1

Executive Summary

Company Highlights

EOGs portfolio of assets consists of large holdings in North Americas top unconventional

resource plays: the Eagle Ford Shale, the Bakken/Three Forks Formation, the liquids-rich area of

the Barnett Shale, and the Permian Basin. This has been the reason why EOG has been able to

organically grow their total production at a 5-year CAGR of 9.71% compared to an industry

average of 9.71%. Switching their focus from gas to liquids in 2007 has led their total liquids

production (Oil + NGL) to grow at a 5-year CAGR of 37.63% while their gas production has

decreased at a 3-year CAGR of -3.43%. Their high quality asset base and focus on higher-

valued liquids have allowed them to grow their revenues at a 5-year CAGR of 22.01%, which is

considerably faster than the industry average of 15.46%.

EOG has significant technical and logistical capabilities. EOGs technical team has added value

through the optimization of their well completion techniques. This has resulted in a higher EUR

per well and also lowering well spacing requirements (higher density of wells in a given area).

Their logistics teams ability to think outside of the box has allowed them to reduce costs

through innovative methods. Two examples of this are shipping crude by rail from North Dakota

and mining their own fracking sand. Adding rail capacity allowed EOG save the $25/bbl cost of

shipping by truck and also allowed them to sell their crude at a premium to WTI. Mining their

own fracking sand has allowed them to save approximately $500,000 per well by not having to

buy sand at inflated market prices.

Concerns over EOGs fundamentals arise due to the impairments of natural gas assets and also

their high capex requirements. The main impact of these charges is a reduction in EOGs net

margin and ROE. I dont feel that investors should be worried about these because EOG has

been divesting natural gas assets since 2008 in an effort to focus on the production of liquids.

Their capex has outsized cash flow from operations for the last few years which has led to

increased levels of debt in order to fund this spending. This should also pose little concern to

investors due to EOGs strong CFO that can be used to cover the interest expense.

Valuation To estimate EOGs intrinsic value I used their WACC to discount their projected FCFF. This

resulted in EOG having an estimated value of $179.95 per share. This suggests that EOG might

be slightly undervalued at their current share price of $169.12.

EOGs was compared to its peers using a several multiples to see if they were relatively cheap or

relatively expensive. The results of this analysis are mixed. EOG is more expensive than its

peers based on comparisons of their P/E and EV/EBITDA ratios. EOG is cheaper than its peers

when compared on both price per flowing barrel and price per flowing barrel of liquids.

The results of an analysis of EOGs technicals are also mixed. Analyzing EOGs 50, 100, and 200-

day moving averages suggests slowing momentum. EOGs 50-day MA is fixing to cross their

2

100-day MA which is a bearish indicator. In contrast, EOGs RSI indicator is showing that EOGs

momentum is increasing which is a bullish indicator.

Recommendation-HOLD Even though I feel EOG is a really great company, I dont feel like its that good of a stock right

now. I dont think the 6% discount of market price to intrinsic value is enough to warrant a buy

recommendation. There is just too much variability surrounding EOGs estimate of intrinsic

value. The contradicting technical indicators and the mixed results of my relative valuation also

support the hold recommendation.

In order for me to change recommendation to a buy or sell I would need to see stronger

evidence that EOG is actually mispriced. The difference between EOGs market price and

intrinsic value would have to be upwards of 25-30%. The results of my relative valuation would

also have to support my intrinsic valuation.

Possible Future Catalysts for Divergences from Intrinsic Value When the industry starts to consolidate in the future, EOG is a strong candidate for acquisition

by one of the supermajors. The desirability of EOGs assets should mean that investors would

receive a significant premium over the market value of EOGs shares. News of an acquisition

could cause EOGs share price to diverge from its intrinsic value enough to make a buy or sell

recommendation.

Increased regulation on hydraulic fracturing could have a significant impact on EOGs

operations. The market may over (under)estimate the impact of these regulations on EOGs

value.

3

Table of Contents

INDUSTRY ANALYSIS .............................................................................................................................................. 4

INDUSTRY DEFINITION ..................................................................................................................................................... 4

KEY MACRO FACTORS ..................................................................................................................................................... 4

INDUSTRY TRENDS .......................................................................................................................................................... 7

WHAT DO WE DO NOW?................................................................................................................................................ 31

COMPANY ANALYSIS ........................................................................................................................................... 35

COMPANY OVERVIEW ................................................................................................................................................... 35

FINANCIAL ANALYSIS ..................................................................................................................................................... 39

FINAL THOUGHTS ON EOG ............................................................................................................................................. 44

INTRINSIC VALUATION ......................................................................................................................................... 45

DISCOUNT RATE ........................................................................................................................................................... 45

WACC AND COST OF EQUITY ......................................................................................................................................... 51

VALUING EOG USING FCFF ........................................................................................................................................... 51

CONCLUSIONS REGARDING EOGS INTRINSIC VALUE ........................................................................................................... 54

RELATIVE VALUATION .......................................................................................................................................... 55

PRICE TO EARNINGS RATIO ............................................................................................................................................. 55

EV/EBITDA ............................................................................................................................................................... 56

EV/BOEPD ................................................................................................................................................................ 57

TARGET P/E ................................................................................................................................................................ 57

FINAL THOUGHTS ON RELATIVE VALUATION ...................................................................................................................... 58

TECHNICAL ANALYSIS ........................................................................................................................................... 58

MOVING AVERAGES ..................................................................................................................................................... 59

RSI ............................................................................................................................................................................ 59

FINAL THOUGHTS ON EOGS TECHNICALS ......................................................................................................................... 59

REFERENCES ......................................................................................................................................................... 60

RESEARCH REPORTS ...................................................................................................................................................... 60

BOOKS ....................................................................................................................................................................... 60

WEBSITES ................................................................................................................................................................... 60

DATA ......................................................................................................................................................................... 60

4

Industry Analysis

Industry Definition The industry being analyzed is the North American Exploration and Production industry. The operations

of firms within this industry are focused primarily on the development of oil and gas from onshore

locations in North America. Firms whose production comes primarily from international or offshore

operations are excluded this analysis because their risk characteristics are significantly different than

firms who are focused on the development of onshore, North American assets. Firms with significant

downstream operations are also excluded for the same reasons.

Key Macro Factors The overall health of the exploration and production industry is highly dependent on the market price of

oil and natural gas. Firms in this industry are price takers; they are forced to sell their products for

whatever the prevailing market price is at the time. Because of this, revenues are almost perfectly

correlated with the market price of oil and gas.

Oil Prices The price of oil is a representation of all of the forces that influence its supply and demand around the

world. The highly volatile nature of oil prices stems from the face that prices are highly sensitive to

changes in supply and demand.

Oil Demand

The demand for oil is highly dependent on the overall state of the economy. In addition to being used as

a fuel for transportation, oil is also used in the manufacture of a plethora of other products. The

demand for oil increases during times of economic expansion due to the rise and industrial production.

During times of economic contraction, there is a decline in the demand for oil due to decreasing

industrial production rates.

Chart 1 shows the high degree of positive

correlation between the growth of the

nominal global GDP and the growth in

the global demand for oil. With an R^2

value of 0.953, approximately 95% of the

variability in the demand for oil is

explained by changes in the nominal

global GDP.

Oil Supply

OPEC

OPEC is an organization that attempts to

actively manage the production of its

member countries. According to the

5

Energy Information Administration, approximately 40% of the global production of oil comes from the

twelve OPEC member countries. Due to their large market share, changes in the amount of oil they

supply to the market can have a significant impact on oil prices.

Morgan Downey, author of the book Oil 101, says that OPEC spare production capacity acts as a buffer

against global oil supply shortages. Periods of low spare capacity place upward pressure on oil prices

because a risk premium is built into prices due to the increased probability of supply disruptions. Low

spare capacity also results in more volatile oil prices as shortages cant be compensated for by increased

OPEC production rates.

Chart 2 shows that between 2003 and 2008, low OPEC Spare capacity coincided with extremely high oil

prices. Currently, spare capacity levels are the lowest theyve been since 2008. Downey believes that

increased global demand, maturing fields and few new discoveries will cause OPEC spare capacity to

continue its downward trend. This will likely lead to higher oil prices and increased volatility in the

future.

According to the organizations

website, OPEC member countries

usually meet semi-annually to

decide on their aggregate

production target and to allocate

this target among their individual

member countries. The current

price and volatility of oil is one of

the main factors in deciding on

their aggregate production target.

Although one of OPECs goals is to

reduce unnecessary volatility in

international oil markets, their

chief concern is with the wellbeing

of their member countries. OPEC

will not attempt to reduce

volatility or high prices if it's

detrimental to its member countries.

Chart 2 shows that OPEC tends to increase production targets during times of high prices and decrease

them when prices are low. In the past, OPEC has had to make several adjustments to their targets

before prices started moving in the right direction.

The EIA says that OPEC has no power to enforce the individual country quotas that they set. This means

that the effect of changing their aggregate production target depends on individual member countries

adhering to their quotas. Historically, there has been a significant amount of cheating among OPEC

members.

6

National Inventories

Inventories serve are similar to OPEC spare production capacity in the sense that they act as a buffer

during supply shortages or during times of high demand. An EIA article on national oil storage says that

commercial inventories are usually increased whenever there's excess supply and drawn down

whenever current demand exceeds current supply. Building inventories usually means that the market

expects higher prices in the future.

Geopolitical Events and Natural Disasters

Any event that has the potential to disrupt the supply of oil to consumers can affect prices. When

there's adequate spare capacity, from producers or inventories, to offset the possible loss, the effect of

the event on prices is reduced considerably, says Downey. For example, the release of oil from the US

SPR greatly minimized the effects of Hurricane Katrina on oil prices were minimized due to the release

of oil from the U.S. Strategic Petroleum Reserve (See Chart 2). Low spare capacity or inventories can

magnify the events impact on prices.

Usually, the impact of geopolitical events on the price of oil is only temporary. Prices return to normal

after the event dissipates and supply flows return to normal. However, events that cause long lasting

shifts in the balance between supply and demand can affect prices for indefinite periods of time. For

example, during the Asian Financial Crisis of the late 90s, decreased demand from Asian countries

suppressed oil prices for several years (see Chart 2).Industry Performance

Revenues and Production

An improving global economy has helped drive oil prices higher since the recent depression. The

average realized price of oil that E&P companies received increased from their low of $57.26 in 2009 to

$92.84 in 2011 with a CAGR of 27.33% over the three year period. As a result of the rebound in oil

prices, industry revenues for 2011 were approximately $897 Billion and grew with a three year CAGR of

26.86%. Chart 3 shows how revenue

growth fluctuates with the growth in

global GDP.

In Chart 3, it's visible that between

2001 and 2011, the percentage of

total revenue coming from natural gas

has decreased over the eleven year

period. Natural gas production

accounted for 18.9% of total revenues

in 2011 which is much lower than the

eleven year historical average of

27.4%. In contrast, Chart 4 shows

that both the volume of natural gas

produced (BOE) and its share of total

production volume have increased

over the same eleven year period. A

7

recent IBIS World Industry Report

credits this growth in production

volume to new development

techniques that have allowed E&P

companies to produce deposits of

gas in previously inaccessible shale

formations in the U.S. and Canada.

Excess supply from shale deposits

has suppressed natural gas prices

and has resulted in the decline in

revenues from gas production.

In 2011, E&P companies produced

approximately 19.74 million barrels

of oil per day which accounts for

22.33% of total global production. In Chart 4, it is clear that oil production growth has remained

relatively flat between 2001 and 2011. The CAGR for oil production during this period was only 0.92%.

This stagnant production growth means that increases in revenues from oil production have come

entirely from changes in the price of oil.

Industry Trends

Increasing Consumption from China and other developing economies

The long-term, sustained economic growth of China, India, Brazil and Saudi Arabia has resulted in large

increases in oil consumption. This large increase in demand has placed upward pressure on oil prices.

There is a twofold explanation for the link between increasing economic development of emerging

economies and increasing oil consumption. As economies develop, they gradually become more

industrialized. As a result, demand for oil as an input for industrial processes increases. Secondly, as

countries become wealthier, vehicular transportation begins to become a more feasible option for

people; resulting in the increased

consumption of oil for transportation

purposes.

Chart 5 shows that China, India, Saudi Arabia

and Brazil were responsible for 11.08%, 3.94%,

3.28% and 3.01% of annual global

consumption during the most recent fiscal

year, respectively. Combined, these countries

accounted for approximately 21.3% of global

oil consumption with a combined

6.22%

11.08% 2.95%

3.94%

2.67%

3.01%

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Chart 5: Increasing demand from China and other developing countries, as a result of sustained economic growth, has been a conintuing trend that has placed upword pressure on oil prices

Percentage of global oil consumption(China, Brazil, India, Saudi Arabi

Brazil

India China

SA

Source:BP Statsitcal

8

consumption of 6.84 billion barrels during 2011. This is a 53.12% increase over their combined

percentage of global oil consumption in 2000 of 13.90%.

The aggregate nominal per capita GDP of Brazil, India and Saudi Arabia and the nominal per capita GDP

of China grew with a 5-Year CAGR of 6.30% and 10.87%, respectively. The aggregate combined oil

consumption of India, Saudi Arabia and Brazil along with the oil consumption in China grew with a 5-

Year CAGR of 5.56% and 5.70%, respectively(see Chart 5). Demand growth in these four countries

greatly outpaced the 5-Year CAGR of -0.01% for global growth in oil demand during the same five year

period (2007-2011).

In terms of the year over year change in the actual

number of barrels of oil consumed daily (KBbls/Day),

global growth in oil consumption consists mainly of

growth in these four countries. As seen in Chart 6, a

huge percentage of the growth in global oil demand

is due to the consumption growth in China.

Between 2000 and 2011, China accounted for

43.67% (1.822 billion barrels) of the 4.172 billion

barrel increase in global oil consumption. Chinas

contribution to global consumption growth during

the period was typically around 30%, but has varied

between a minimum of 14.4% to a maximum of

85.2%.

Around May of this year, there was some concern

about slowing oil consumption in China (see Chart

7). Consumption growth began to pick up in August

and has been around 3.75 billion barrels per year.

To help sustain continued economic growth and

shield consumers during times of high oil prices,

many developing countries have initiated oil

consumption subsidies. Oil consumption subsidies

in China, India, and Saudi Arabia have helped to

continue the strong growth in consumption from

these countries during times of high prices.

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Chart 7: Chinese oil demand continuing to grow after slowdown around the middle of the year

Rolling 6mo Average Oil Consumption vs Rolling 6mo CAGR

Chinese Demand Growth

Source: EIA Data

9

A recent S&P Industry Survey says that the

continuance of high oil prices in the future is

heavily dependent on the continued growth in oil

consumption of China as well as other developing

countries. The strong relationship between

Chinese demand and oil prices can be seen in Chart

8. The high R^2 value means that Chinese demand

has a high degree of explanatory power in regards

to predicting oil prices.

To help sustain continued economic growth and

shield consumers during times of high oil prices,

many developing countries have initiated oil

consumption subsidies. Oil consumption subsidies in China, India, and Saudi Arabia have helped to

continue the strong growth in consumption from these countries during times of high prices. I feel this

adds to the power of Chinese demands explanatory power in predicting oil prices.

Growth in global oil demand would be stagnant without the growth in consumption from these

countries, which would eliminate the current upward pressure on oil prices. This means that the future

growth of the exploration and production industry is highly sensitive to changes in the economic

growth of China and other developing countries.

Bottleneck at Cushing is Causing the Price Differential between Brent and WTI

Since 20010, WTI has been trading at a discount to Brent. The spread is currently around $22.00 a

barrel but in the past has widened to as much as $27.31 a barrel in November of last year.

In Chart 09, you can see that Brent-WTI spread

oscillated around parity prior to 2010 Cushing

inventory levels surged during 2010 because of

large production growth from North Dakotas

Bakken field and the Canadian oil sands.

According to a recent S&P Industry Report,

Cushing was designed to get oil from the Gulf

of Mexico and Canada to refineries in the

Midwest. This means that most of the

pipelines connected to Cushing are set up to

flow in the wrong direction to send oil

anywhere except refineries in the Midwest.

Refiners in the Midwest dont have enough

capacity to handle the amount of oil thats

flowing into Cushing each month and there is

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Chart 9: Bottleneck at Cushing is causing WTI to trade at a discount to Brent

WTI differential and Cusing Inventory(Kbbls)

Midwest Field Production-Left AxisCushing Inventory-Left AxisWTI-Brent Differential-Right Axis

Source: EIA Data

Brent-WTI Parity

y = 18.104x + 1545.8 R = 0.7835

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Chart 8: There is a strong relationship between monthly Chinese oil demand and oil prices

Chinese oil demand vs Brent Crude Price

10

not enough pipeline capacity to get the oil to refineries in the gulf.

This bottleneck has caused the Midwest to become greatly over supplied with oil. The substantial

discounts of WTI to Brent have resulted from this oversupply.

In November of 2011, Enbridge announced that they would reverse the flow of their Seaway pipeline

that connects Freeport, TX to the Cushing hub. According to a recent Alliance Bernstein report on oil

prices, the reversal of the pipeline is the first stage in a multi-phase project that will add 150 Kbbls of

pipeline capacity from Cushing to the Gulf Coast. Upon news of the announcement, the spread shrunk

from approximately $23/bbl to around $10/bbl, but rebounded back to $20/bbl a few months later. The

announcement is marked in Chart xx by the yellow shaded circle.

Enbridge completed the first phase of the project in May of 2012 (green circle). This caused the spread

to shrink from $16.50/bbl to a low of $12.86 in July. Since July, the spread began to grow and is

currently around $22.00 a spread.

After the completion of the reversal, inventories at Cushing began to drop until reaching a bottom of

30.4 million billion barrels in October (black arrow). After bottoming out, inventories have shot back up

to almost 40 million barrels of oil.

It is clear that the WTI differential has closely tracked inventory levels since completion of the reversal.

This leads me to believe that the reversal of the Seaway did not add enough capacity to end the bottle

neck at Cushing.

According to Alliance Bernsteins research, the WTI differential should narrow as new pipeline capacity

comes online. This new capacity will come from two possible sources: Additional phases of the Seaway

project and TransCanadas Keystone XL pipeline.

Phases two and three of the Seaway project are scheduled to be completed by the middle of 2014 and

are expected to provide an additional 700,000 BPD of pipeline capacity. TransCanada is planning on re-

applying for a presidential permit to construct their Keystone XL pipeline. If the project is approved,

management expects the project to be completed by 2015 and to add an additional 510,000 BPD of

pipeline capacity.

Light, sweet crude getting more

difficult and expensive to find Chart 10 is a plot of API density and the sulfur

content of crude being used in factories in the

U.S. You can see that as time has passed the

density of the average barrel used in refineries

has increased.

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Chart 10: Oil input at refineries is getting heavier and more sour. This implies that cheap, easy sources of light/sweet crude are likely long

gone. API Density and Sulfur Content(% Weight)

API Density

Sulfur Content

Source: EIA Data

Density Increasing

11

According to Oil 101, heavier oils have higher densities because they're hydrocarbon molecules

contain more molecules than lighter oils. Heavier crudes are more difficult to turn into higher valued

items like gasoline and diesel. This means that heavier crudes trade at a discount to lighter crudes. This

translates into fewer revenues for those companies who have assets producing heavy oil.

Rising sulfur content is also a sign of decreasing oil quality. Oil 101 explains that sulfur molecules take

up space that could be occupied by hydrocarbon molecules and that this decreases the energy content

of the oil. In addition, Environmental regulations force refiners to remove sulfur from many of their

finished products. Both of these things mean that crudes with higher sulfur will trade at a discount to

sweeter crudes.

All of the cheap and easily recoverable sources of light sweet crude have already been recovered. This

means that as time passes, the cost of finding the additional marginal barrel of oil will increase while its

quality will go down.

The mature nature and high degree of competitiveness between participants in this sector means that

it's extremely unlikely that there are any major discoveries just lying out in the open. Companies are

going to have to spend a lot to find new sources of oil and gas in the future.

Chart 11 shows how companies

have had to dig deeper and pay

more to find new sources of

hydrocarbons. With the exception

of the late 70s it appears that well

costs were fairly flat until 1994.

It's at this point that the cost of

drilling wells really started to

increase. Between 1994 and

2007, the average real costs of

drilling wells increased with a

CAGR of 15.93%

Also notice on Chart 11 how much

deeper exploratory wells were

compared to development wells.

This large difference means that

although companies were undoubtedly finding oil this deep, it just wasnt economical to develop these

sources at that period in time. This gap started to decrease after 1994 as companies started to develop

sources that were growing deeper. The combination of increasing well costs and deeper developmental

wells leads me to believe that the early to mid-90s was the end of easy to find oil.

Unconventional Oil and Gas in the US Unconventional resources are one of the biggest things occurring in the industry right now. In a 2011

industry report, Alliance Bernstein analysts compared the importance of unconventional resources to

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Chart 11:Companies are having to look deeper and pay more as the shallower, cheaper and easier plays are all gone

Avg Feet Per Well (Exp. and Dev.) and Avg. Real Cost for Drilling a Well

Avg. Real Dollar Cost per Well

Avg. Ft.-Exp. Well

Avg. Ft-Dev. WellOut of cheap, eassy sources here? Exploratory wells

much deeper

Source: EIA Data

12

the oil and gas industry to that of the power loom and assembly line for the textile and manufacturing

industries. Unconventional resources are the area that holds the most future growth potential for the

industry.

The Basics

A point I would like to make to start off with is that when people talk about shale oil, they're talking

about tight oil. Shale oil is just source rock (kerogen) that hasnt been turned into oil yet.

The book Oil 101 describes tight oil as oil that is trapped inside of a source rock due to the low

porosity and permeability of the source rock. In order for there to be oil or gas present in the source

rock, it has to be at the right temperature and pressure for the right amount of time to be converted

into oil or gas. This optimal set of conditions is known as the oil window for oil and gas window for

natural gasses. Kerogen is source rock that isnt exposed to these optimal conditions.

The low porosity and permeability of the source rock means that if it is drilled into, no resources will be

able to flow. In order to be able to recover oil or gas from the well, it has to be completed with

hydraulic fractures. Fracturing involves pumping water, chemicals and sand down a well bore at

extremely high pressures. This creates fractures throughout the source rock that act as passageways for

oil and gas to flow through.

Pay zones are usually quite thin and require a great deal of precision to be able to hit them. Horizontal

and directional drilling technologies are typically used because they allow you to steer the bit as your

drilling. This gives you the ability to access a tremendous amount of resources by allowing you to drill a

narrow pay zone for very long distance.

Unconventional Trends

Sustained $2-$3 natural gas prices have caused

exploration and production companies to focus on

more liquids rich plays. Alliance Bernstein

researchers say that the Bakken, Niobrara, and Eagle

Ford shale plays are becoming increasingly popular

because they produce a lot more crude oil and

natural gas liquids than dry gas. Chart 12 shows the

increasing number of rigs drilling for oil over gas as

companies make the switch.

Common themes among shale plays North American unconventional resource plays share

several common features. This section contains a detailed analysis of these commonalities using the

Bakken/Three Forks formation located in North Dakota as a case study.

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Chart 12 :Shifting focus from gas to oil due to low natural gas prices

Number of Oil Rigs and Gas Rigs Operating in the US

Oil Rigs in Operation

Gas Rigs in Operation

Shale Oil Boom

Source: EIA Data

13

Sweet Spots

While the actual areal size of a play can be large, analysts at Alliance Bernstein claim that the actual play

is a lot smaller because of core areas (or sweet spots) within the play that produce wells that yield

superior economic returns. To explore the existence of sweet spots within plays, I examined the

production data from wells located in the Bakken/Three Forks formation in North Dakota. My sample

consisted of 1642 wells drilled between 2006 and 2010.

In my analysis of the sweet spots, I first ranked all of the individual wells in the dataset according to their

average daily rate over their first 30 days of production. Ranking was based on initial production rate

because it is commonly used as a metric to gauge the economic potential of new wells. High IP rates are

a strong indicator of high production rates throughout the early stages of development. High early

production rates help wells combat steep decline rates, which results in them producing a higher total

volume of oil than those with lower rates of production. High early production rates also translate into

a faster payback period which reduces risk.

I used ESRIs ArcGIS and data from the states geological website to map the position of all the wells

from my sample. Map 1 shows that the initial production rates are definitely not homogenous

throughout the play. The dark orange and red points represent wells that have IP rates in the top 20th

percentile of the sample. The circled area on the Eastern edge of the play has the densest population of

wells with high IP rates. The area enclosed by the larger polygon is my approximation of the plays

sweet spot. The distribution of wells with higher than average IP rates is extremely scattered outside of

this enclosure.

I used the Average Nearest

Neighbor utility in ArcGIS in order

to test the significance of this

clustering. The ANN utility

calculates average distance from

each feature to its nearest

neighbor and the expected and

compares it to the average

distance in a randomly distributed

population. For an alpha equal to

0.05 (95th Percentile), the critical

Z-Scores were 2.58 and 1.96 while

the resulting Z-Score was -67.98.

This value was way less than the lower critical value which means that the odds of this clustering being

random are extremely low.

14

This sample of data captures the

period before the Bakken/Three

Forks became extremely

popular. Since 2010, the total

number of unconventional wells

in North Dakota has increased

by approximately 3600 wells.

Although well production data in

an easily manipulated format

wasnt available after 2010, I

used ArcGIS to map individual

wells drilled after 2010 in order

to see if drilling was still focused

in the sweet spot after 2010.

Map 2 is a representation of the

density of wells drilled per field during 2011 and 2012. The dark green fields have the lowest well

densities while the dark red fields have the highest. This image shows that drilling is still heavily

focused in the previously defined sweet spot (solid polygon). The dashed line shows how drilling has

been extended outside of the original sweet spot as open acreage becomes scarce.

First Mover Advantage

Analysts at Alliance Bernstein claim that the

first movers within a play have an advantage

over late comers in terms of lease location

and terms. The first companies to explore a

play have the ability to secure the best

acreage for themselves and limit

competitors access to the sweet spot.

Chart 13 uses a companys percentage of the

total number of wells drilled within the

Bakken/Three Forks sweet spot as a proxy for

the amount of acreage they control within

the sweet spot. The more wells a company

has drilled the more acreage it must control.

This chart shows that the 7 companies with

the highest percentage of wells during the

early period of the Bakken development (first

movers) continue to dominate the play.

Very Steep Decline Rates

Wells from the Bakken/Three Forks formation typically have high initial production rates that decline

very quickly. To construct an average Bakken/TF well, I first normalized all the wells by moving the start

18.5% 14.1%

15.7% 10.5%

14.3%

9.1%

9.5%

10.8%

6.8%

5.7%

5.2%

9.2%

4.2%

4.9%

25.8% 35.8%

0.0%

10.0%

20.0%

30.0%

40.0%

50.0%

60.0%

70.0%

80.0%

90.0%

100.0%

First Movers: 2006-2008 Total Wells: 2006-2012

Chart 13: Companies that move first on a play can secure prime acerage and dominate a plays sweet spot.

Companies w/largest percentage of wells in the Bakken/TF sweet spot during early years (2006-2008) and total life (2006-2012)

Others

XTO

Whiting

Burlington

ContinentalMarathon

EOG

Hess Source: ND Geological

15

of each wells production to a unified point in time and then took the simple average of each months

production rate.

One of the techniques the E&P industry uses to make production forecasts is decline curve analysis

(DCA). According to the Petroleum Engineers Handbook, DCA is an empirical technique that matches a

curve to historical production and then extrapolates that curve in order to forecast future production.

Most of my research indicates that Arps Hyperbolic Decline Equation is one of the most widely used

methods of performing DCA within the industry for two main reasons: its relatively simple and doesnt

take that long to do. The method I chose to use is a slightly modified version of this model.

A technical paper written by Fekete Associates, an oil/gas consulting and software company, states that

the most general form of the Arps equation is given by the equation for hyperbolic decline:

(1)

where: qi is the initial production rate and qt is the rate at time t, Di is the decline rate at flow qi, and b represents the curvature of the decline trend

Hyperbolic decline occurs when 0

16

To generate the initial hyperbolic decline curve I used Palisades Evolver (similar to Excels solver but

more powerful and faster) to solve for qi, Di, and b from Equation 1. The goal of this optimization was to

maximize the square of the regression coefficient (r^2):

(

)

(2)

Where: SSE=Sum of Squares Error, SST=Sum of Squares Total q(t)=historical production rate, q(t)=forecasted production rate,

and qavg=average historical production rate

To maximize r^2, must be as close to as possible. To do this, I set up Evolver to maximize r^2 by

changing the variables qi, Di, and b. After 5000 trials Evolver returned a value of 0.9981for r^2. This

value is very close to one which means that the hyperbolic decline curve closely matches the historical

production data. The forecasting of future production is accomplished by inputting the months you

want to predict, along with the optimized values of qi, Di, and b into Equation 1. .

To make the switch from hyperbolic decline to exponential decline, a minimum terminal decline rate

must be selected. I decided to use a range of terminal decline rates instead of just choosing one

because I was unable to find any detailed discussion or method for choosing the minimum decline rate.

In my opinion, using a range of terminal declines and forecasting production as a distribution makes

more sense because there is already a lot of uncertainty built into the forecast. The vast majority of the

terminal decline rates I saw being used ranged between annual effective declines of 6% and 10%, so I

decided to use terminal rates of 7.5% and 10% in my forecast.

From the previously mentioned paper by Fekete Associates, the formula to convert from hyperbolic to

exponential decline is as follows:

(3)

Where: and , are the production rate and time at the terminal decline rate

To find each terminal rates associated or , I first had to convert the terminal rates from an

annual effective rate into a monthly nominal rate. After that, I just had to match up each terminal rate

to the hyperbolic decline rate closest to it. The values of , , and Monthly nominal rate) for

the 7.5% and 10% terminal decline rates are listed in Table 1.

Table 1: Di, tlim, and qlim for the chosen terminal decline rates

10% Terminal Decline 7.5% Terminal Decline

Di 0.0088 0.0065 tlim 214 311 qlim 12.0350503 8.892836538

17

Looking at the values for tlim in the table above, its clear that using a terminal decline of 10% will

forecast less cumulative production than the 7.5% terminal decline rate. The effects of the 10%

terminal decline are stronger and take effect sooner than those of the 7.5% decline. Therefore, the 10%

case will be my low (worst) case, the 7.5% my middle (average) and the straight hyperbolic model will be

my high (best) case. To examine the overall effects of the model and parameter choice, I forecasted the

production of all three cases to 40 years, 480 months, past the start of production.

Chart 14 shows the estimates of cumulative

production from each of the three cases over a

40 year period. The difference between the

high and low estimates was relatively small at

only 11.2%. These results are contrary to my

research as most of it claimed that estimates

from the hyperbolic model were vastly

overinflated. Although skeptical about my

results, I feel that they are sufficient enough to

get across my points later in the paper.

According to the Standard Handbook of

Petroleum and Natural Gas Engineering, the high initial production rate and steep decline from

Bakken/Three Forks wells is because they are drilled horizontally and are completed by using multi-stage

fracing techniques. Multi-stage fracing involves isolating segments of the horizontal well bore and

hydraulically fracturing each segment (stage) before a well is put on production (typically). This process

creates fractures along the length of the lateral that immediately frees a large amount of oil or gas from

the source rock and allows it to flow into the well bore.

The high initial production rates are caused by the fact that there is already a large volume of oil or gas

ready to flow to the surface as soon as soon as production is started. The low permeability of the source

rock prevents the migration of hydrocarbons from areas far outside of the stimulated (fractured) area

into the well bore. This means that oil and gas are flowing out of the well much faster than they are

getting to the bore hole. This causes production rates to drop rapidly.

Chart 15 provides a visual of the extremely fast decline in the rate of production for an average

Bakken/TF well. The average production rate was calculated by taking the simple average of the three

curves at each point in time. Wells are producing at just 25% of their initial production rate by the end

of their first year and by the end of their fourth, theyve already produced half of the oil theyre going to

produce over their lifetime.

276,960.10

297,597.23

307,962.66

260000265000270000275000280000285000290000295000300000305000310000315000

10% Terminal Decline 7.5% Terminal Decline Hyperbolic

Bb

ls

Chart 14: Cumulative oil production over 40 years

18

The Economics of a Single Bakken/TF

Well

In this section, we analyze the economics of

Bakken/TF using the decline curve derived

in the previous section.

Assumptions

The assumptions for the model can be

found in Table 2. Although less than the

18.75% the state of North Dakota is

currently charging to drill, I chose to

implement a royalty of 17% because I feel it

better represents the average royalty paid

by oil and gas producers in the state. The Bakken is not new and much of

the land has already been signed with leases offering lower rates. No other

costs associated with acquiring land are included in this analysis.

Producers in North Dakota are levied a tax of 11.688% on every barrel of oil

that comes out of the ground (not net of royalty payments). After the daily

production rate of a well drops below 30 BOPD it becomes exempt from

the 6.5% extraction tax and all future production from that well is taxed at

5.18%. In the end, producers end up losing between 25% and 30% of their

total production to royalties and taxes.

The upfront capital expenses for drilling and completing (fracing) horizontal wells are massive. Many

plays also require producers to make significant investments to be able to get their production to

market. Bernstein analysts estimate that upfront capital expenses are approximately $10MM with 75%

of that going to drilling and completion while the other 25% goes towards midstream development.

Capital expenses were treated as one-time expense at t=0.

The value of $7/bbl for lease operating expenses was estimated by averaging the LOEs from companies

highly leveraged to the Bakken formation: Kodiak, Oasis, and Northern. I was unable to come up with a

way to separate the fixed and variable cost components from the LOE. This implies that a well

wouldnt be taken off production until it was producing less than $7 in oil, which is a very unrealistic

assumption. To get around this, production is I assume all wells are taken off production in 30 years.

The Economics

A copy of the model I used can be downloaded here. Chart 16 displays the NPV10 values for an average

Bakken well under the four oil price scenarios. Its clear that $85/bbl is slightly above the break-even

point for an average Bakken well. The exact break-even price can be calculated by deriving a line of best

0.E+00

5.E+04

1.E+05

2.E+05

2.E+05

3.E+05

3.E+05

0

50

100

150

200

250

300

350

400

450

500

0 2 4 6 8 10 12 14 16 18 20 22 24 26 28

Bb

ls

BO

PD

Years

Chart 15:Average Bakken/TF Decline Rate and Cumulative Production

(BOPD and Bbl)

BOPD

Price of Oil $65 - $125

Production Tax 5.0000%

Extraction Tax 6.5000%

Conservation Tax 0.1875%

LOE/Month $7.00/bbl

Capital Expenses $10,000,000

Royalty 17%

Discount Rate 10%

Table 2: Assumptions for Well Economics

19

-$5.00E+06

$0.00E+00

$5.00E+06

$1.00E+07

$1.50E+07

$2.00E+07

$2.50E+07

$3.00E+07

$65 $85 $100 $125

Chart 17: NPV is highly dependent on the quality of your holdings.

NPV10 for each group under the four oil price scenarios

Average

60%-75%

75%-90%

Top 10%

fit in Excel and then solving for the price of oil to make NPV=0. The price of for an average Bakken well

to break even is $82.57. Anything below $82.57 and it becomes uneconomic for producers to develop

average quality Bakken/TF acreage. Prices need to be $100+ for producers to earn any kind of

significant return.

Its important to point out that not all of the Bakken

formation will require at least $85/bbl to break-even.

From our previous discussion on sweet spots, we

know that resource plays are composed of zones that

produce wells with similar economic returns. If these

economic returns vary from zone to zone, the break-

even oil prices for zones must vary as well. This

means that in areas with above average economic

returns, the break-even price of oil will be lower than

average.

To analyze the economics of wells in above average

areas, I divided the wells with IP rates in the top 40% of wells into 3 different groups: 60%-75%, 75%-

90% and the top 10%. I then averaged each of the individual wells within the groups to derive an

average set of production data for each group. After that, I used the optimized effective decline rates

(Di) from the average Bakken decline curve to forecast 30 years of production for each group.

The same model and assumptions were used to

analyze each group at the four different oil price

scenarios. Chart 17 displays the NPV10 at each oil

price scenarios for each group. The data from the

average Bakken well is displayed again for visual

comparison. This chart makes it obvious how

important it is to be located in (or very near) the core

areas of resource plays. At $100/bbl, being

positioned on above average acreage can mean having

an NPV 3x to 7x higher than the average. Another way

to examine the differences in quality amongst the

Bakken is by calculating the oil price required to break-

even on the well. The top 10% of Bakken wells only

need oil to be $41.40 to break-even, while the 75%-90% and 60-75% group have break-even prices of

$54.00/bbl and $62.66/ bbl. respectively.

Table 3 gives us some indication as to whats driving the huge differences in NPV. The biggest two

drivers of value are the estimated ultimate recoveries (total lifetime production) and how fast they can

be produced. The top 10% of wells will produce around 140% more oil over their lives than the average.

Using the IP rate as a general indicator of the production rate over a wells life time, we can see that

wells in the top 10% are generally going to have production rates much higher than average. Faster

-$2.16E+06

$2.98E+05

$2.14E+06

$5.21E+06

-$3.00E+06

-$2.00E+06

-$1.00E+06

$0.00E+00

$1.00E+06

$2.00E+06

$3.00E+06

$4.00E+06

$5.00E+06

$6.00E+06

$65.00 $85.00 $100.00 $125.00

Chart 16: Sensitivity of NPV10 to Oil Prices for Average Bakken Well

20

production rates tend to reduce risk because they decrease the payback period for production

companies. Faster payback periods offer companies more flexibility by not tying their cash up for

unnecessarily long periods of time. This also means that a smaller percentage of a companys total cash

flows from a well be effected by the large discount rates in the later lives of a well.

Table 3: IP Rates and EURs for above Bakken Core

Group EUR IP Rate

Top 10% 671434.2 895.8688

75%-90% 482866.9 799.6977

60%-75% 404675.4 636.3036

Average 278793.133 435.67

Its clear that the volatility of a wells NPV is largely due to changing oil prices and the variable EUR

(quality) of wells throughout the play. I used linear regression to create a line of best fit based on the

relationship between EUR and oil prices to NPV. After coming up with a line of best fit for both

variables, I estimated best/worst case scenarios for each along with a base case scenario. All scenarios

are based on the average production curve discussed earlier (280,000 bbl of EUR). Changes in EURs

represent variability in estimation capabilities, and other things that could cause the production of a

well to stop before its economic limit is reached (natural disaster, accidents, etc.).

The best, worst and base cases for oil prices are: $125/bbl, $65.00/bbl and $100.00/bbl. The scenarios

for EUR are 380,000 bbl for the best case and 200,000 bbl for the worst. Chart 18 shows how far each

extreme deviates from the base case. A $1.00/bbl move in oil prices produces $122,827 change in NAV

which is almost equivalent to a change of 1000 bbl of EUR. This makes sense because these are the only

two things that create cash flow. `

Possible Sources of Error

There are several possible sources of error in my analysis of the economics of the Bakken formation.

The largest of these have to do with my well production estimates.

-$959.36

-$2,158.17

-3000 -2000 -1000 0 1000 2000 3000 4000 5000 6000 7000

EUR(Lifetime Production)

Oil Prices

NAV(000's) Chart 18: Sensitivity of NPV to EUR and Oil prices

Worst Case Scenarios: EUR=200,000 and $65.00/BBl

Best Case: EUR=400,000 bbls and $125.00/BBL

Base Case: EUR=280,000 bbls and $100.00/bbl

21

Im not a petroleum engineer and have no formal training in decline curve analysis. There is a plethora

of material explaining the math and theory behind it, but not very many detailed examples that didnt

involve data I had no way of accessing. I feel I firm grasp of the theory and background behind the

models I employed but without any real examples to follow I had to go with what seemed right to me.

As an example: Even though it seemed right to average the three decline curves I created, this may be

totally wrong.

Another source of error could be the production data I was using. The state of ND publishes monthly

production data from all individuals wells monthly. I had to use a set of data that only went up to 2010.

This meant I had relatively little production data to base my curves on, which is a definite source of error

in my model. As operators have gained more technical skill in producing shale oil, the production rates

have tended to increase, my model doesnt account for that.

Another source of error could be the 10% discount rate I used. Even though this is standard in the

industry, it may not be correct. The discount rate should represent the market related risks of the cash

flows its discounting. Production from the Bakken formation could be more or less risky than the 10%

discount rate thats used. NPV will be overestimated (underestimated) depending on how much more

risky (less risky) the cash flows are.

With all that being said, I feel the results of this analysis are definitely reasonable. Although my EURs

are somewhat lower than most estimates, (Alliance Bernstein estimates EUR to be 323 bbl for Bakken

wells), they are definitely in the ball park. My annual decline rates and other derived numbers are fairly

close as well.

Well Spacing

Why is well spacing important? If you have good acreage, the more wells you can drill on your property

the better. Well spacing places a limit on the number of times you can do this and still remain profitable.

If wells are spaced too close together, wells would start cannibalizing the production of other nearby

wells. The optimal well spacing in a play occurs whenever the distance between wells is the smallest it

can possibly be without affecting the performance of nearby wells. In other words, the goal is to pack as

many wells into an area as possible without negatively affecting the production of any other wells.

Brief Discussion on Fracing

According to the Standard Handbook of Petroleum and Natural Gas Engineering, the high initial

production rate and steep decline from Bakken/Three Forks wells is because they are drilled horizontally

and are completed by using multi-stage fracing techniques. Multi-stage fracing involves isolating

segments of the horizontal well bore and hydraulically fracturing each segment (stage) before a well is

put on production (typically). This process creates fractures along the length of the lateral that

immediately frees a large amount of oil or gas from the source rock and allows it to flow into the well

bore.

The high initial production rates are caused by the fact that there is already a large volume of oil or gas

ready to flow to the surface as soon as soon as production is started. The low permeability of the source

rock prevents the migration of hydrocarbons from areas far outside of the stimulated (fractured) area

22

into the well bore. This means that oil and gas are flowing out of a well much faster than they are

getting to the bore hole. This causes production rates to drop rapidly.

The Geometry

The distance that the resulting fractures extend into the rock in one direction is known as the half-width

(xf). Multiplying the half-width by two yields the width of the fracture. Multiplying the fracture width

by the length of the wells lateral yields the surface area of rock thats hydrocarbons can flow through to

reach the well bore. Bernstein research states that the frac half-widths for most unconventional plays

range from 500ft-1500ft (or 1000-3000 feet). The tight oil and gas resources that E&Ps are targeting

exist in intervals that are usually only several hundred feet thick so the fractures extend far enough

along the vertical axis that they entire thickness of the target interval is stimulated.

Land measurements in the oil and gas industry are predominately done in sections. A single section is

equivalent to a square mile or 640 acres. Many contracts stipulate that leases must be held by

production, which means that producers forfeit the lease if they dont start producing from it within a

certain period of time. One well per section is usually the requirement to the retain rights of that

section.

A simple way to think about well spacing is to estimate how many wells could fit into a single section

and then just divide the area of a section by that number. We can keep this analysis 2-dimensional by

assuming the fracture stimulates the entire thickness of the interval. Determining well spacing only

requires calculating the total surface area that the well bore and fractures are in contact with, which is

equal to the length of the wells lateral multiplied by twice the frac half-width:

Eq. 4:

Assuming that well laterals are usually between 5000ft and 10000ft long, along with the frac half-widths

mentioned earlier; we can calculate the typical unconventional resource well has a surface are between

5.00E6ft^2 and 3E7ft^2. A section has a surface are of 2.79E07ft^2. This gives well spacings of 128

acres and around 640 acres.

Similarly, the surface area of a Bakken well is equal to its twice its half-width multiplied by the length of

its lateral (2(750)*9000). By this calculation, the surface area of a horizontal Bakken well is

approximately 13,500,000ft^2. Converting ft^2 to acres, we can see that a slightly over two wells can fit

in a single section (2.06), which means the well spacing for the Bakken formation is 310 acres.

Horizontal vs. Vertical Well Spacing

Fractured vertical wells interact with a much smaller volume of the reservoir than fractured horizontal

wells. Imagine that the square and rectangular figures below represent the top and side view of a tight

oil/gas reservoir. If someone challenged you to pick one of the shapes and put as many of those blue

dots on there as possible, which side would you choose?

23

Its obvious that the square could hold a lot more circles than the rectangle. This is analogous to the

difference in infill spacing between horizontal and vertical wells. You can fit a lot more vertical wells

horizontal wells in the same amount of area. Now imagine the smaller rectangle is a cross section of the

reservoir and the blue circle is a side view of the path that the drill bit took through it. This illustrates

how little of the reservoir is actually contacted by with vertical drilling. Bernstein analysts claim that

vertical wells may only interact with between 0.06 billion cubic feet and 0.6 billion cubic feet reservoir

while a horizontal well contacts between 1 and 3 billion cubic feet of the reservoir. In terms of spacing,

a single section may have enough room for between 10 and 100 vertical wells while the same section

may only room for a single horizontal well.

Analysts say that estimates on infill spacing contain a huge amount of uncertainty and are one of the

most common to be overinflated because they dont occur for many years until after the initial

production of a well.

Stacked Pay Zones

A cross sectional view of tight oil and gas resources would reveal multiple layers of source that vary in

thickness. Multiple layers of source rock can contain the volume of hydrocarbons necessary to make

them economical to drill opportunities. In some cases, these layers maybe stacked in a way that they

can be drilled in the same location. These stacked pay zones can increase the total amount of EUR from

and area by a significant amount.

In addition to the Bakken formation, the Williston Basin also contains the Three Forks (TF) formation.

The US Geological Survey recently released a report that claims that the TF formation has an EUR of

3.73 E9 barrels of oil. This more than doubles the estimate of 3.65 E9 barrels of oil in an earlier release

that only studied the Bakken formation.

Bringing it all Together: Forecasting the production of the entire Bakken formation

Provided in a Bernstein Research report, the total resources can be calculated as follows:

Eq.5

Now that we know the well spacing of the play, the final step in calculating the total resources in the

Bakken is coming up with an estimate of its size. The US Geological survey estimates the Bakken

formation we now only need to estimate the throughout the play, the goal is to try and determine the

areal extent of the plays surface.

Due to the difficulty of deriving a reasonable estimate myself, I chose to use an estimate published in

the 2011 Alliance Bernstein Report North American E&Ps: Aligning the Stars of the North American

Resource Play Constellations. Their research was focused on determining the extent of the Bakken

formation most likely to be developed. Given that companies will almost certainly try to position

themselves in the best land possible, prospective acreage was judged on a variety of factors that

indicate better than average economics. These indicators (metrics) included 30 day IP rates (IP30),

finding & development costs, and average EURs among others. Based on their analysis, there is

approximately 7 million prospective acres within the Bakken formation.

24

Dividing the total acreage of the formation by its well spacing yields the maximum number of wells that

the formation will contain. A total size 7 million acres and well spacing of 310 acres means that the

Bakken will contain a maximum of 22,580.. The amount of time it takes to reach this point is dependent

on the level of drilling activity (rig count) within the play, which is provided on the ND Dept. of Mineral

Resources website. To estimate how long it will take to complete 22,580 wells we need to forecast the

number of rigs

operating in the

Bakken in future

years.

The average number

of rigs operating in

the formation has

grown at a CAGR of

33.69% from 34.67

during 2006, to

197.92 in 2012.

Bernstein analysts

expect rig rates to

stabilize and remain

at 200 until the

Bakken well count

reaches its max. I did

the same in my forecast as well. I also held assumed that the number of wells drilled per rig would

remain at 0.79/month (or 9.45/year). Chart 19 shows a plot of the annual number of wells completed

each year as well as cumulative production. The cumulative number of wells in the play will increase

until there is no more acreage left to drill. My forecast estimates that total remaining undrilled acreage

will be less than 310 acres during the beginning of 2022.

I employed the average Bakken curve derived at the beginning of this section to model production from

the entire field. I felt that this was a reasonable choice because its composed of every well drilled in the

formation weighted by its frequency of occurrence. The production from a formation or field is not

only dependent on its geological properties (represented by the average production profile), but also

on the rate at which its developed (number of well completions each year).

To develop the production curve for the Bakken formation, I set up a matrix with each column

representing one year of production from the formation. Every column was populated with the annual

production volume from the average Bakken well. The first cell in each column to contain data was one

row lower than the previous column. The cells in each column were then multiplied by the number of

wells that were drilled during that particular year. Each cell was then divided by 365 in order to turn

them into daily production rates. The data points of each row were then summed together determine

the formations daily rate of production for a particular year. Table 4 is an example of how I set up the

matrix to make things more clear.

0

5000

10000

15000

20000

25000

0

200

400

600

800

1000

1200

1400

1600

1800

2000

2006 2007 2008 2009 2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022

Cu

mu

lati

ve W

ells

We

lls/Y

ear

Chart 19: The Bakken Formation will run out of acreage to drill by 2022 Annual number of wells completed each year and cumulative number

of wells

Total Wells

Number of WellsDrilled Each Year

Source: Rig Activity info from ND Dept. of Mineral

25

Table 4: Matrix Example

Years of Production 1 2 3 Rates

1 X X

2 X Y XY

3 X Y Z XYZ

Y Z YZ

Z Z

Chart 19 plots the daily rate of production from the Bakken formation as a function of time. Each of the

individual pieces represents the production curve of wells that were completed during a specific year.

Notice how each pieces contribution to the total rate of production is dependent on the number of wells

completed that year. The rate of production increases as long as the quantity of new wells is sufficient

enough to overcome the decline rates of all previously drilled wells. The chart shows that the formation

will reach its peak rate of production of 1.07 million BOPD as soon as the wells completed in 2022 begin

producing. No new wells are drilled after this point because the formation has reached its maximum

carrying capacity of 22,580 wells. After this point, the fast decline rates that are characteristic of tight

oil/gas formations set in and production rates begin to decline rapidly.

0

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2006 2008 2010 2012 2014E 2016E 2018E 2020E 2022E 2024E 2026E 2028E 2030E 2032E 2034E 2036E

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Chart 19: Production Profile from the Bakken Formation Height of curve represents peak bakken production in BOPD and the dotted

line represents the number of wells completed each year

Bakken production rate will rach a maximum of 1.07 MM BOPD

26

Eagle Ford

Bakken Permian

Niobarra Mississippi Lime

Deep Anadarko Basin

Utica

Marcellus

Barnett

Haynesville

Horn River

Woodford

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ate

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First Year Production as a Percent of EUR

Chart 20: IP Rate vs. First Year Production as a Percent of Total EUR for North American Shale Plays

Source: Alliance Bernstein Report

Higher IP rates and faster Decline rates means a faster payback period

Final Thoughts on the Bakken/Three Forks Formation

The production characteristics from the Bakken/TF formation are not homogenous throughout the

surface are of the play. The highest production rates are confined to sweet spots. This means that the

first movers into a play have a significant advantage over late comers in being able to identify and lock

up the best areas.

The main drivers of a plays economics are its EUR and well spacing requirements. Wells with a higher

EUR will produce a higher volume of liquids over its lifetime, which increases its NPV. Lower well

spacing requirements mean you can fit more wells in a given area. More wells equates to higher

revenues for producers.

Sizing Up the Other North American Unconventional Plays

In this section we analyze the characteristics from North Americas other unconventional plays. From

this analysis we are able to rank these plays based on a variety of factors.

Production Characteristics

Shale plays are well known for their high initial

rates of production as well as their fast decline

rates. Chart 20 plots IP rates against first year

production as a percent of total production for

12 North American shale plays. The higher the

percentage of total EUR produced in the first

year, the faster the rate of decline. Although

this may be counterintuitive, faster decline rates

are preferred over slower rates of decline

because they return a larger portion of their

cash flows during the earlier parts of a wells life.

Higher IP rates also increase early cash flows.

Its important to note that that the previous

chart only represents the rate at which cash

flows are returned relative to total cash flows. It

doesnt take into account whether a play is

more weighted towards liquids production (NGL

and oil) or gas production. Plays weighted

towards liquids are preferred over gassier plays

due to extremely low natural gas prices. One

BOE of natural gas is worth only $23.00,

assuming oil prices are $100/bbl and natural gas

prices are $4.00/mcf. Chart 21 shows how much

50%

95%

75%

50% 70%

50% 43%

1% 15% 0% 0% 31%

$0.00

$20.00

$40.00

$60.00

$80.00

$100.00

Chart 21: The $ Value of a BOE Produced from Each of the 12 Plays along with the percentage of liquids per BOE

-Assumes oil is $100/bbl, NGL prices are 40% of oil prices and natural gas is $4.00/mcf

Source: Alliance Bernstein Report

27

1,600,000

1,042,000

660,000

656,000

618,000 467,000

400,000

380,000

320,000 288,000

277,000

224,000

$0.00

$5.00

$10.00

$15.00

$20.00

$25.00

$30.00

$35.00

$40.00

$45.00

$M

M

Chart 22: Cumulative Undiscounted Revenue per Well for each Shale Play

Cumulative Revenue=EUR*$/BOE

Source: Alliance Bernstein Research

a BOE is worth from each of the 12 plays. The value of a BOE ranges from $23.00/bbl for the Haynesville

and Horn River formations to approximately $90.16 for the Bakken formation.

Chart 22 shows the total cumulative revenues

for a single well from each play. The chart is

arranged from left to right in order of

descending EUR value. Its clear that the

value of single well is dependent on its total

cumulative production (EUR) as well as the

value of each BOE it produces. Even though

wells in the Horn River formation out produce

Eagle Ford wells by nearly 1 million BOE over

their lifetime, Eagle Ford wells still have

higher cumulative revenues ($40.66E6 vs.

$37.12E6).

Sweet Spots

The existence of conventional oil and gas fields is contingent on a host of factors lining up just right. In

Oil 101, Downey describes seven steps that must occur in the creation of conventional oil and gas

formations. First, there must be a quality source rock present. Second, this source rock must be

located at the correct depth for the source rock to undergo maturation. This is the process by which

the source rock is broken down by heat and pressure into lighter oil and gas molecules. Third, the

source rock must be in contact with a reservoir rock that is permeable enough to allow the oil and gas

to migrate through it and porous enough to be able to hold oil. Fourth, an impermeable cap rock must

be positioned in a way that traps the oil and gas in the reservoir rock and prevents it from migrating

to the surface. Finding an area with a high probability of meeting all of the required prerequisites is

very difficult and doesnt happen very often. This is why wildcat wells are about four times more likely

to result in a dry hole than a successful one (101).

With tight oil and gas formations only two of the conventional prerequisites are required: source rock

and maturation. Analysts at Alliance Bernstein say that these two factors are usually correlated across

basins. This implies that if something is working in one area, its likely to be successful in other areas of

the play as well. The depth and areal extent of tight oil and gas formations are relatively well known

which means E&Ps dont have much difficulty in hitting it. This means that traditional exploration risk

(probability of a dry hole) is greatly diminished with tight oil and gas plays. Does this mean that tight oil

and gas plays are free from risk free? Not even close.

28

One of the early misconceptions regarding shale formations was that they should have fairly uniform

production characteristics across the play. As previously discussed, we know that well performance is

far from uniform across a play. Localized areas with above average well performance (sweet spots) exist

in all shale formations. Chart 23 shows the variability of the ratio of IP in the top 10% of the population

to those in the 50th percentile from 11 North American shale plays. Assuming that IP rates are

correlated with long term performance; the larger the ratio, the more value there is to being in the

sweet spot (or core area). This chart also shows how production is more homogenous in some plays

than others. This means that being in the sweet spot might not matter as much in plays like the

Haynesville or Horn River formations.

Stacked Pay

Another factor that can be seen

in multiple plays is the presence

of stacked pay zones. Multiple

pay zones provide additional

drilling opportunities from the

same area. This translates into a

higher overall well density (lower

minimum well spacing) and a

higher EUR per well. Compiled

with data from an Alliance

Bernstein report, Table 5 shows

the impact of stacked pay zones

on well density for 7 US shale

plays. The play most impacted by

potential zones is the Deep Anadarko Basin. This formation has a well spacing of 115 acres, which

equates to a well density of 5.6 wells per section. The presence of 12 possible zones increases the

number of wells per section to approximately 66.9.

Table 5: The Impact of Stacked Pay Zones on North American Shale Formations

Formation Well Spacing (Acres)

Wells Per Section Per Zone

Potential Zones Total Wells per Section

Eagle Ford 110 5.8 2 11.6

Deep Anadarko 115 5.6 12 66.9

Marcellus 138 4.6 3 13.9

Haynesville 110 5.8 2 11.6

Barnett Core 207 3.1 2 6.2

Horn River 220 2.9 2 5.8

Bakken 310 2.1 2 4.1

1.69 1.96

2.37 2.38 2.42 2.42 2.75 2.8 2.84

3.03 3.32

0

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Chart 23: Ratio of Wells with IP Rates in the Top 10% vs Average IP Rates

Source: Alliance Bernstein Reportc

29

Ranking North Americas Shale Plays

To briefly summarize, we know that the better quality shale plays have: High IP rates, fast decline rates,

production weighted towards liquids, and high EURs. High IP rates and fast decline rates mean that a

larger percentage of cash flows are returned earlier in the life of a well. This means that companies with

a huge inventory of drilling opportunities can reinvest their cash into the next set of wells more quickly.

The production from liquids rich plays is much more valuable than gassier plays due to the low price of

natural gas. Wells with higher EURs produce more barrels (cash flow) over their lifetime than wells with

lower EURs.

One factor we havent examined yet is the areal extent of each individual play. Its important to

remember that not all areas within a play can be produced economically. This means that its not the

total size of the play that matters. Whats important is the total acreage within a play that can be

produced economically. The total prospective acreage within a play, along with its particular well

spacing requirements, act as constraints on the on the maximum number of wells that can be drilled

within it.

Table 6 lists the total amount of prospective acreage, well spacing, and the maximum number of wells

that the can be drilled in the prospective acreage for the 12 most important shale plays in North

America. Bernstein analysts estimated the total prospective acreage using mapping techniques similar

to those used in the previous section on sweet spots in the Bakken formation. These estimates

represent the total prospective acreage available at the beginning of the plays development. Well

spacing requirements and corresponding well counts were calculated using the same method as before.

Examining the differences in the well counts between the Eagle Ford, Permian, and Bakken formations

highlights the huge effect well spacing has on the development of a play. The Bakken and Eagle Ford are

roughly the same size, but the Eagle Fords tighter well spacing allows it to fit almost twice the number

of wells as the Bakken formation.

Table 6: Total Prospective Acreage in Each Play

Play Prospective

Acreage Well Spacing

Maximum Number of Wells

Eagle Ford 6,547,200 120 54560 Bakken 6,831,642 284 24055 Permian 5,800,000 200 29000 Niobrara 2,240,762 200 11204 Mississippi Lime 3,994,624 240 16644 Deep Anadarko Basin 3,000,000 150 20000 Utica 2,350,367 200 11752 Marcellus 2,952,141 150 19681 Barnett 2,271,552 150 15144 Haynesville 1,600,000 100 16000

Horn River 1,515,238 200 7576

Woodford 9,600,000 200 48000

30

Knowing the maximum number of wells that

can fit within a plays prospective acreage

allows us to estimate the total BOEs a play

will produce over its lifetime. Lifetime

production estimates are illustrated in Chart

25. The Eagle Ford formation is 1st in total

lifetime production. It out produces its

closest competitor (Deep Anadarko) by an

estimated 35% over its lifetime.

Well costs are a major expense for E&Ps

choosing to operate in North Americas

unconventional resources. According to

research from Alliance Bernstein, well costs range from $12.5E6 (Horn River) to $3.15E6 (Barnett) and

average around $7.5E6.

Chart 26 shows the price of a BOE from each individual play based on the following price assumptions:

$100/bbl Oil, $40/bbl NGL, and $4.00/mcf Gas. All production related costs, including those associated

with drilling and completing wells, were converted into $/bbl amounts in order to examine the margin

per barrel for each play. The 3 plays with the highest profit margins are the Eagle Ford, Bakken and

Permian Basin, respectively. The Eagle Ford formation has is on top due to its relatively small

production related costs and its liquids rich production. Even though Bakken formation has the highest

production related costs in the group, its production is the most valuable ($90/BOE) due to its extremely

high liquids content. On the other end of the spectrum, the Haynesville and Woodford plays are not

even breaking even under the current gas price scenario. To break even, the Haynesville and

Woodford plays need gas prices to be $4.40/mcf and $7.14/mcf, respectively.

In my opinion, the best way to rank

these plays would be to use some

NPV based metric. Using NPV

would account for the liquids

content of production, time value

of money, EURs, and the

production profile of a well. Doing

this would require creating a

schedule of cash flows based on

each plays average type curve.

Unfortunately, I dont have access

to the data require