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Copyright 2013 Union Square Research Group, LLC 1 www.unionsquareresearch.com (646) 706-7633 Copyright 2013 Union Square Research Group, LLC www.unionsquareresearch.com

Getting Ahead by Drilling Down Valuing Oil & Gas Shale Assets to Exploit Market Inefficiency

Because sector experience and reporting are not the same thing as sector expertise and analysis

Independent Buyside Insights

Copyright 2013 Union Square Research Group, LLC 2 www.unionsquareresearch.com (646) 706-7633 Copyright 2013 Union Square Research Group, LLC 2 www.unionsquareresearch.com (646) 706-7633

Nicholas Snyder has been investing in the oil and gas space for over seven years and has spent the last four of those developing an expertise in the valuation of shale assets. During this period, he has made many industry contacts through his study of geology and petroleum engineering. Prior to co-founding Union Square Research Group, Mr. Snyder headed up the research effort at a family office, where he evaluated private oil and gas opportunities among other responsibilities. He has been directly involved in the evaluation and leasing of natural resources and was interviewed in the May, 2012 issue of Outstanding Investor Digest for his work in the shale space. Mr. Snyder has been a Chartered Financial Analyst (CFA) charterholder since 2010.

Union Square Research Group is pleased to be working with Wall Street Access, an independent firm with a 32-year track record of providing research and execution services to its clients. If you are interested in obtaining our research through an execution services firm, please contact Matt Treacy at (212) 232-5690.

About the Author


Executive Summary

Contents

• Overview

• Basic shale play evaluation

• Evaluating leasehold

• Case study

• Conclusions

An opportunity currently exists to buy hundred-million to multi-billion dollar assets for a fraction of what they are worth. For the first time, the value of oil and gas shale assets can be calculated on an NPV basis due to an increase in publicly available data and improved disclosures.

As these assets reach the tipping point in development, when there is visibility into future free cash flow and an NPV can be calculated, the market will adjust and this opportunity will disappear.

*See End Notes for sources


Before the real estate crash, real estate assets were valued based on a multiple of expected future income at full occupancy.

After the crash, gun-shy analysts focused solely on current cash flow.

Sophisticated investors, who could value properties under development, bought the best ones and made a killing. A similar opportunity exists today for investors who can value shale assets.

Opportunity


Imagine two brand new Miami apartment buildings that come up for sale after the real estate crash. Both buildings are 90% vacant.

One building is selling for a price based on the NPV of reaching full occupancy over the next few years, while the other is selling for a multiple of current income that is similar to fully-occupied peers.

Current Cash Flow ≠ Value

This is how the market is currently valuing shale E&Ps, due to sell-side limitations


Sell-Side Limitations

• Reports are limited in length and scope by their audience and business model – For the same reason the sell-side doesn’t value every building in a REIT, it

doesn’t accurately value shale assets within small E&Ps or large diversified E&Ps

• The sell-side still has a black eye from predicting huge per-acre values for gas shale assets before the commodity itself collapsed – Analysts don’t want to take the career risk of making a big call before the

development picture and road to FCF is crystal clear

• The exception is large “single shale” E&P companies – Once there is a clear path to FCF, the sell-side is willing to build DCF models;

consequently, “single shale” companies like RRC and COG trade at huge premiums to their peers


Skate To Where The Puck Is Going

The sell-side doesn’t currently value many shale assets properly for structural reasons.

It will.

Analysts now have enough primary source data to accurately value these assets and capitalize before the sell-side catches up.


Solutions for Analysts

• Understand the science and technology behind these emerging resource plays

• Talk to geologists, engineers, service firms and other “boots on the ground”

• Gather primary source data: Subsurface maps Leasing rates Permits Midstream development plans Infrastructure construction Well IP rates Leasehold development (HBP) status

Company production data State production data Drilling unit permits and spacing Severance tax and royalty info Regional basis differentials Completion technique and cost trends Development plans and resources

EARLY STAGE DATA DCF MODEL DATA


Basic Shale Play Evaluation: Understanding an Asset


Three Levels of Analysis

Level One: geologic models, leasing data, and initial well results provide a roadmap to large area valuation

Level Two: Initial type-curves, reservoir studies, larger leasehold transaction, and other scuttlebutt create a more refined understanding of core areas

Level Three: larger data set of localized well results combined with study of leasehold allow for discounted cash flow (DCF) valuation of specific assets within a shale play

E&P companies follow a similar process when they are acquiring leasehold in a new play


GROSS THICKNESS THERMAL MATURITY FORMATION DEPTH ORGANIC THICKNESS

Level One: Geophysical Predictors

• Total organic content (TOC), porosity, and the depth/temperature at which a shale has been “cooked” in the earth’s crust are the major indicators of oil and gas in place

• Depth and thickness are indicative of pressure and the size of the localized reservoir

that can be accessed by a horizontal well

• Reservoirs are complex and the ultimate economics of an area will depend on natural permeability and the ability to which it can be increased through fracturing


Level One: Initial Well Results

• Analysts should look for clusters of good wells in areas that make sense within the framework of the geologic model

• It is important to make sure that big production figures are

indicative of good economics and not the result of an operator drilling a huge lateral and running a well flat-out in order to report a big initial production (IP) figure to Wall Street


Level Two: Core Area Delineation

Big production numbers (from State rather than operator data) and a high ratio of oil/gas indicates best part of the field


Valuation requires an understanding of the long-run economics of a play, which change quickly during the early stage of development as drilling and completion techniques become more efficient. As a play matures, operator efficiency and “pad” vs. “HBP” drilling drive gains.

Level Two: Trends in Well Economics


Good well results and increased development budgets can have predictive value

In many resource plays, good well results and large investment plans have been predictive of an upward re-rating of acreage values by the industry, private, and public markets

Initial investments in a resource play can carry the same price-tag and level of risk as a deep water “wildcat” well

Even multi-hundred million dollar investments may not have good information value – caveat emptor

Conservatism is paramount Negative scuttlebutt should be used to inform when a valuation is not conservative enough rather than using positive data points to increase a valuation; announcement of large initial production figures may not be indicative of good economics

Level Two: Scuttlebutt


($0.75) ($0.50) ($0.25) $0.00 $0.25 $0.50 $0.75

16.0% $198.1 $214.7 $231.2 $247.8 $264.4 $280.9 $297.5

Cost 14.0% $231.9 $250.0 $268.1 $286.2 $304.3 $322.4 $340.5

of 12.0% $273.8 $293.8 $313.7 $333.6 $353.5 $373.5 $393.4

Capital 10.0% $326.6 $348.8 $371.0 $393.1 $415.3 $437.5 $459.7

8.0% $394.7 $419.6 $444.6 $469.6 $494.6 $519.6 $544.5

Uniform Change in Natural Gas Futures Curve

Sensitivities of "Super Rich" Marcellus Valuation

($ millions)

$1.25 20.0% 12.0%

$ Thousands Year 1 2 3 4 5 6 7 8 9 10 11-40

Gross MMcfe Produced: 1,228.7 619.5 452.7 366.7 312.6 275.8 249.0 228.2 211.2 196.4 2,430.4

Gross Revenue Based on NYMEX: $6,943 $3,754 $2,822 $2,329 $1,975 $1,743 $1,573 $1,442 $1,335 $1,241 $15,690

Processing and Differentials: ($1,536) ($774) ($566) ($458) ($391) ($345) ($311) ($285) ($264) ($245) ($3,103)

Severance Taxes and Royalties: ($1,298) ($715) ($541) ($449) ($380) ($336) ($303) ($278) ($257) ($239) ($3,021)

Net Undiscounted Revenue: $4,109 $2,265 $1,714 $1,422 $1,204 $1,062 $959 $879 $814 $756 $9,361

PV of Future Net Revenue $3,877 $1,907 $1,289 $955 $722 $569 $458 $375 $310 $257 $1,279

$11,998 $7,000 $4,998 IRR: 36.5%

Gastar Exploration "Super Rich" Marcellus Well Model

Present Value of Future Cash Flow: Cost per Well: NPV per Well:

Processing and Differential Cost per Mcfe: Royalty Rate: Cost of Capital:

30.0 MMcfe/Day

($ Millions) Year 2013 2014 2015 2016 2017 PV in 2018

Net Wells Per Year Value of Current Production $39,119 $26,295 $20,849 $17,386 $15,516 $78,441

9 Value of 2013 Drilling Program: $44,981




Present Value: $79,339 $72,667 $68,302 $62,015 $9,303 $41,990

$333,615Present Value of Current Production and Future Wells:

Existing Production at Year End 2012:Number of Gross Future Well Sites: 100 (50% GST W.I.)

Valuation of Gastar's "Super Rich" Marcellus Play in Marshall and Wetzel Counties

Once an analyst has collected enough information to get a clear picture of the economics of individual wells, the number of wells that will be drilled, and the timeframe over which this resource will be developed, an NPV can be calculated just like any other project.

Level Three: Development Model DCF


Evaluating Leasehold: The Overlooked Variable


Importance of Leasehold Analysis

• Non-core assets with lease expiration issues fetch terrible prices in the market, because the seller has few options.

• Large HBP leases are hugely valuable on the market, as they are essentially perpetual call options on the commodity.

• The future economics of an area under development are vastly different if leases are small and fragmented (like some old coal leases) vs. large “blocked up” drilling units from recently leased farms/ranches.

Analysts often focus on an operator’s development plan to ascertain the value of a shale asset. This is a mistake. The quality of leasehold is more important than the development plan because of its implications for divestitures and future development costs.


Leasehold Quality is Often Ignored

There are three key variables to take into account when valuing shale assets:

1) Well Economics

2) Leasehold Quality

3) Development Plan

• Optimistic analysts often focus primarily on well economics, but apply it to too wide an area.

• Pessimistic analysts often focus only on the area under development, rather than the entire position.

• Understanding the nature and quality of leasehold is the key to bridging the gap between these other two variables.


Leases must be drilled before their term expires to be “held by production” (HBP)

Leasehold that will not be drilled before expiration has little value to the owner unless there is high demand from buyers

Large “blocked-up” groups of leases allow for more efficient “pad drilling” and are significantly more valuable

“Retail” leasehold < “blocked-up” drilling units < large groups of drilling units

Availability of local infrastructure and regional “take away” capacity significantly affect timing and thus economics of drilling leasehold

Royalty rates, state tax regimes, and environmental issues also affect the ultimate value of a leasehold position

Components of Leasehold Value


Cost of drilling and completion ($6,700,000)

Cost of 1/8th of wellpad and gathering ($187,500)

Cost of SG&A ($333,333)

Cost of capital for above (@10%) ($722,083)

PV of one well $11,434,600

NPV of one well $3,491,683

Acres per well 80

Value per acre if drilled today: $43,646

Years until well comes online 5

Additional cost of capital for up-front infrastructure ($114,471)

Time discount to single well NPV (5 years @ 10%): ($1,323,623)

Discounted NPV of one well: $2,053,590

Acres per well 80

Value per acre if drilled in five years: $25,670

Theoretical value of a 8.5 BCF EUR NE Marcellus Well

Theoretical per Acre Value

In a perfect world: one acre of leasehold would translate into a fraction of the NPV of a well dependent only on timing and well spacing


4 years left on lease



1 year left on lease

Contigous lease that will

allow for pad drilling

Efficient operator with

large holdings in the area

Theoretical value per

acre of a lease in a

homogenous play with

NPV per acre of $43,646

and a ten year inventory

$25,000

$20,000

$15,000

$10,000

$6,000

$1,000

Lease held by production

(HBP)

Take-away capacity exists

or will soon be built by

others

Actual per Acre Value

In the real world: resource play development is a manufacturing business, which means that cost control and efficiency are the ultimate arbiters of returns


Glossary

A method for estimating reserves and predicting production in oil reservoirs and oil fields. The decline curve shows how oil and gas production rates decrease over time. The difference between the Henry Hub spot price and the corresponding cash spot price for natural gas in a specified location. 640 acre area in which leases are combined into a single unit and are considered proportional pieces of a large “unitized” lease for purposes of revenue sharing, and converting leases to HBP status. Abbreviation for “estimated ultimate recovery”; the amount of oil and gas expected to be economically recovered from a reservoir or field by the end of its producing life. The general limitation on E&P companies booking reserves that will not be developed within five years. Abbreviation for “held by production”; a provision in an oil or gas lease that perpetuates a company’s right to operate a property or concession as long as the property or concession produces a minimum paying quantity of oil or gas. Initial production rate of an oil or gas well, generally measured over a 24 hour period The amount of acreage owned after adjusting for minority working interest owners (i.e. 70% interest in 100 gross acres = 70 net acres). The amount of interest owned in a well after adjusting for minority working interest owners (i.e. 70% interest in 10 gross wells = 7 net wells). The ability to drill multiple horizontal wells from a single well pad, saving on infrastructure costs. A geologically homogenous, area of unconventional reservoir in which well performance is generally repeatable and can be predicted by linear relationships between geophysical factors A representative decline curve for a homogenous area of a resource play, which can be used to accurately predict the initial production, EUR, and production decline of producing well and well yet to be drilled.

Decline Curve:

Differential:

Drilling Unity:

EUR:

Five Year Rule:

HBP:

IP Rate:

Net Acre:

Net Well:

Pad Drilling:

Resource Play:

Type Curve:


Case Study: The Steps to Valuing a Shale Asset


Four Steps to Valuation

1) Perform due diligence on leasehold, current production levels, company and competitor claims regarding the reservoir, State production data, regional infrastructure developments, etc.

2) Delineate core areas and quantify acreage into buckets 3) Model well economics 4) Create a development model and find the NPV of the

asset based on conservative assumptions

• The majority of the work is in Step 1 • Steps 2-4 are relatively straightforward and could be accomplished by

most financial analysts who understand the key concepts • A good result from Step 4 is dependent on making the right conclusions

about data uncovered in step 1


Total Leasehold of 1.4 Million Net Acres

(Net addition by this operator of 400k Marcellus acres during 2009-2012 has increased proportion of “core” acreage within this leasehold position)

1) Basic Due Diligence


Analysts must use a mosaic of publicly available information to determine both the boundaries of core areas and “sweet spots” as well as determine as best as possible the quality of a company’s leasehold within these areas

1) Define the Core Area(s)

Utilize disclosures from multiple companies, including smaller competitors that may provide additional details


Disclosures suggest the company holds 100k net acres in the “core of the core” (10 BCF EUR) and an additional ~300k net acres in the “core” area (8.5 BCF EUR)

1) Quantify Acreage by Tier

A portion of this county is a “sweet spot” or “super core” area, with some of the best economics in the country


There may be regional “sweet spots”, where over-pressured areas have tremendous economics. It is important to ensure that well results in these areas are not over-represented in the “average well” type-curve for a larger area.

1) Potential Pitfalls to Area Valuations

Wells in this area have double the initial production of those in neighboring counties, which can skew “average” well production figures


Insufficient pipeline capacity to move supply out of a producing region will drive down “basis differentials” to the NYMEX commodity price. The regional price for marginal supply can reach zero in some cases, so this is an important risk to assess.

1) Examine Regional Infrastructure

Almost 2 Bcf/day of new pipeline capacity is being added to this area within the next year, which will ease congestion


Examination of actual leasehold, drilling units, well results and state production data on the county level is imperative to understanding the quality and value of a leasehold position

1) Perform Leasehold Analysis

State records, online landowner groups, permit data, smaller competitor disclosures, trade periodicals and even “fractivist” groups can be excellent sources for detailed information on leasehold positions down to the drilling unit level


Location of all permitted drilling units shown, with state production data for the last 6-month reporting period superimposed on individual well-pads (shown by size of circle)

1) County Level Leasehold Analysis

The majority of the acreage in yellow appears to be in large efficient drilling units, which can drill many wells from the same pad. This makes sense for a rural area without previous production


State production figures show consistent good results within the boundaries the company claims. Major pipelines in the area provide a ready market for future production.

1) Examining Key Claims

“Core” and “core of the core” area (as defined by the company) super-imposed. Un-leased State forest explains lack of activity in Western edge of the “core of the core”


It is crucial to examine the actual operations of a company on the Township level. At this level, an analyst gets a view of the actual operations and the future trajectory of development costs.

1) Operations on the Township Level

Comparison of wells in these counties to “core of the core” type-curve will show if wells are below average as they get farther West from acreage in the “super core” sweet spot to the East of this County


Large “blocked up” landholdings allow for numerous efficiencies in the building of roads, pads, and gathering pipelines, as well as ongoing operating efficiencies for years to come. Bringing new production online from these drilling units may be twice as profitable as developing smaller leases a few miles away.

(Gathering pipeline placement is illustrative)

1) Development Efficiency

Leases are usually pooled together into 640 acre “drilling units”


Generally, an operator must drill one well in each 640 acre drilling unit in order to hold by production (HBP) all of the leases within the unit. In farm areas like this, operators may be able get large leases that span multiple drilling units. Smaller operators who do not operate on this scale have much higher all-in costs.

1) Pad Drilling = Lower Future Costs


1,147 acre “double” drilling unit will accommodate ~16 wells

The operator has drilled two wells from this pad, one north and one south

Initial wells were drilled to maximize play knowledge and hold acreage by production, not maximize IRR

Future wells from this pad will cost less and produce more

1) Initial Construction vs. Development


Drilled Southeast from the pad and came online in August, 2011

Lateral is only 3,475 feet

Despite the short lateral, this well has outperformed the operator’s “core of the core” type-curve by 14%

This well was likely drilled short to cheaply establish production in order to HBP the leases in this drilling unit

1) Examining Individual Wells

Actual Well Permit


Future wells from this pad will produce $400 million in revenue and have an NPV of $98 million (if drilled today).

All infrastructure is in-place and has been paid for.

1) Future Well Pad Economics

Twelve additional wells to be drilled from this pad


Within the “Core” and “Core of Core”, this company’s leasehold is highly contiguous and most acreage looks to be already held by production (HBP)

2) Quantifying Acreage into “Buckets”

Acreage "Buckets" Net Acres HBP Status Confidence Level

Pennsylvania "Core of Core" 100,000 85% High

Pennsylvania "Core" 300,000 70% High

Pennsylvania "Tier 1" 200,000 20% Medium

Pennsylvania "Tier 2" 350,000 5% Low

New York "Core" 50,000 0% Low

New York "Tier 1" 50,000 0% Low

New York "Tier 2" 350,000 0% Low

Total: 1,400,000 25%


3) Understanding Well Economics

• Average EUR across 139 wells is 10.4 Bcf, which is better than the “core of the core” type-curve

• Decline curve is consistent with competitors and state production data

• We model production at 90% of the disclosed type-curve


Discount Rate for Well IRRs: 10%

Royalty Rate 17%

Severence Tax 5%

Operating Expense ($/Mcf) $0.60

-16.3%

Well Spacing (acres): 80

Days to drill (spud to spud): 21

0.0%

Discount to HH (%):

Income Tax (%)

Month: 1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24

USRG NE "Core of Core" Wells: 328.5 301.1 275.1 251.9 228.6 209.9 192.1 177.1 164.6 155.1 147.0 138.2 131.6 124.9 118.3 112.1 106.6 102.3 98.5 94.6 90.6 86.9 83.3 79.9

Henry Hub Futures Price $4.22 $4.26 $4.31 $4.33 $4.32 $4.33 $4.39 $4.54 $4.64 $4.60 $4.49 $4.08 $4.07 $4.09 $4.12 $4.13 $4.13 $4.15 $4.23 $4.42 $4.50 $4.48 $4.41 $4.11

Net Monthly Revenue: $760.5 $704.9 $652.5 $601.5 $544.3 $500.3 $466.1 $447.6 $426.8 $397.4 $366.3 $306.6 $291.5 $278.5 $266.1 $253.0 $240.1 $232.1 $228.2 $231.1 $226.4 $216.1 $202.9 $178.7

Month Specific Discount Factor: 1.008 1.016 1.024 1.032 1.041 1.049 1.057 1.066 1.074 1.083 1.091 1.100 1.109 1.118 1.127 1.136 1.145 1.154 1.163 1.172 1.182 1.191 1.200 1.210

Discounted Mthly Net Revs: $754.5 $693.7 $637.2 $582.7 $523.1 $477.0 $440.9 $420.1 $397.4 $367.1 $335.6 $278.7 $262.9 $249.2 $236.2 $222.8 $209.8 $201.2 $196.2 $197.2 $191.6 $181.4 $169.0 $147.7

Wells per year per rig: 17 21,651 21,087 11,793

Year: 1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24

USRG NE "Core of Core" Wells: 2,569.1 1,229.5 778.1 558.4 433.6 351.3 291.5 247.8 214.4 188.6 168.8 152.8 139.4 128.3 118.6 110.3 103.2 97.0 91.2 85.7 80.5 75.7 71.2 66.9

Henry Hub Futures Price: $4.37 $4.28 $4.28 $4.37 $4.50 $4.66 $4.86 $5.10 $5.41 $5.50 $5.50 $5.50 $5.50 $5.50 $5.50 $5.50 $5.50 $5.50 $5.50 $5.50 $5.50 $5.50 $5.50 $5.50

Net Revenues by Year 6,174.6 2,844.6 1,835.5 1,355.0 1,091.0 $913.8 $797.3 $717.1 $664.9 $595.9 $533.3 $482.6 $440.4 $405.2 $374.8 $348.6 $325.9 $306.3 $288.0 $270.7 $254.4 $239.2 $224.8 $211.3

Year Specific Discount Factor: 1.050 1.155 1.271 1.398 1.537 1.691 1.860 2.046 2.251 2.476 2.723 2.996 3.295 3.625 3.987 4.386 4.825 5.307 5.838 6.422 7.064 7.770 8.547 9.402

Discounted Annual Net Rev: $5,880.6 $2,462.9 $1,444.7 $969.5 $709.7 $540.4 $428.6 $350.5 $295.4 $240.7 $195.8 $161.1 $133.6 $111.8 $94.0 $79.5 $67.5 $57.7 $49.3 $42.2 $36.0 $30.8 $26.3 $22.5

Present Value of Discounted Net Revenue: $14,552.5

USRG "Core of Core" 9 Bcf EUR wellsGross Production (MMcf) and Net Revenue ($1,000s) by Month

Gross Production by Year (MMcf)

first year net production for one rig: 2nd year net production for one rig: 3rd year net production for one rig: 4th year net production for one rig:

Single well NPV = $7.825 million

3) Creation of Conservative Type Curve


Net Undrilled Acres 90,000

% Drillable 100%

Royalty Rate 17.0%

Severence Tax 5%

Operating Expense ($/Mcf) $0.60

Discount rate for Drilling program: 10.0%

$6.7

-16.3%

Well Spacing (acres): 80

Days to drill (spud to spud): 21

0.0%

Discount to HH (%):

Income Tax (%)

Well Cost ($MMs)

2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030 2031 2032 2033 2034 2035 2036 2037 2038 2039 2040 2041 2042

5 6 6 6 6 6 6 6 6 6 6

$4.37 $4.28 $4.28 $4.37 $4.50 $4.66 $4.86 $5.10 $5.41 $5.50 $5.50 $5.50 $5.50 $5.50 $5.50 $5.50 $5.50 $5.50 $5.50 $5.50 $5.50 $5.50 $5.50 $5.50 $5.50 $5.50 $5.50 $5.50 $5.50 $5.50

Commulative net wells drilled: 86.9 191.2 295.5 399.8 504.0 608.3 712.6 816.9 921.2 1,025.5 1,129.8

7.0 15.3 23.6 32.0 40.3 48.7 57.0 65.4 73.7 82.0 90.4

Net Production (MMcf) for vintage: 2013 108.3 105.4 59.0 39.9 29.8 23.6 19.4 16.3 13.9 12.2 10.8 9.7 8.8 8.1 7.5 6.9 6.5 6.1 5.7 5.3 5.0 4.7 4.4 4.2 3.9 3.7 3.5 3.3 3.1 2.9

Net Production (MMcf) for vintage: 2014 129.9 126.5 70.8 47.9 35.7 28.3 23.2 19.5 16.7 14.6 13.0 11.7 10.6 9.7 9.0 8.3 7.7 7.3 6.8 6.4 6.0 5.7 5.3 5.0 4.7 4.4 4.2 3.9 3.7

Net Production (MMcf) for vintage: 2015 129.9 126.5 70.8 47.9 35.7 28.3 23.2 19.5 16.7 14.6 13.0 11.7 10.6 9.7 9.0 8.3 7.7 7.3 6.8 6.4 6.0 5.7 5.3 5.0 4.7 4.4 4.2 3.9

Net Production (MMcf) for vintage: 2016 129.9 126.5 70.8 47.9 35.7 28.3 23.2 19.5 16.7 14.6 13.0 11.7 10.6 9.7 9.0 8.3 7.7 7.3 6.8 6.4 6.0 5.7 5.3 5.0 4.7 4.4 4.2

Net Production (MMcf) for vintage: 2017 129.9 126.5 70.8 47.9 35.7 28.3 23.2 19.5 16.7 14.6 13.0 11.7 10.6 9.7 9.0 8.3 7.7 7.3 6.8 6.4 6.0 5.7 5.3 5.0 4.7 4.4

Net Production (MMcf) for vintage: 2018 129.9 126.5 70.8 47.9 35.7 28.3 23.2 19.5 16.7 14.6 13.0 11.7 10.6 9.7 9.0 8.3 7.7 7.3 6.8 6.4 6.0 5.7 5.3 5.0 4.7

Net Production (MMcf) for vintage: 2019 129.9 126.5 70.8 47.9 35.7 28.3 23.2 19.5 16.7 14.6 13.0 11.7 10.6 9.7 9.0 8.3 7.7 7.3 6.8 6.4 6.0 5.7 5.3 5.0

Net Production (MMcf) for vintage: 2020 129.9 126.5 70.8 47.9 35.7 28.3 23.2 19.5 16.7 14.6 13.0 11.7 10.6 9.7 9.0 8.3 7.7 7.3 6.8 6.4 6.0 5.7 5.3

Net Production (MMcf) for vintage: 2021 129.9 126.5 70.8 47.9 35.7 28.3 23.2 19.5 16.7 14.6 13.0 11.7 10.6 9.7 9.0 8.3 7.7 7.3 6.8 6.4 6.0 5.7

Net Production (MMcf) for vintage: 2022 129.9 126.5 70.8 47.9 35.7 28.3 23.2 19.5 16.7 14.6 13.0 11.7 10.6 9.7 9.0 8.3 7.7 7.3 6.8 6.4 6.0

Net Production (MMcf) for vintage: 2023 129.9 126.5 70.8 47.9 35.7 28.3 23.2 19.5 16.7 14.6 13.0 11.7 10.6 9.7 9.0 8.3 7.7 7.3 6.8 6.4

108.3 235.3 315.4 367.1 404.9 434.4 458.5 478.7 495.9 510.8 524.0 406.0 290.3 229.4 190.5 163.2 142.8 126.9 114.2 104.0 95.5 88.3 82.0 76.5 71.5 67.0 62.9 59.1 55.6 52.2

-$582.3 -$698.7 -$698.7 -$698.7 -$698.7 -$698.7 -$698.7 -$698.7 -$698.7 -$698.7 -$698.7 $0.0

$331.4 $702.7 $941.7 $1,123.9 $1,282.3 $1,433.4 $1,590.3 $1,756.6 $1,950.7 $2,046.4 $2,099.5 $1,626.6 $1,162.9 $918.9 $763.4 $654.0 $571.9 $508.2 $457.7 $416.6 $382.6 $353.6 $328.5 $306.3 $286.5 $268.5 $252.1 $236.9 $222.6 $209.3

-$250.8 $4.0 $243.0 $425.2 $583.6 $734.7 $891.6 $1,057.9 $1,251.9 $1,347.7 $1,400.7 $1,626.6 $1,162.9 $918.9 $763.4 $654.0 $571.9 $508.2 $457.7 $416.6 $382.6 $353.6 $328.5 $306.3 $286.5 $268.5 $252.1 $236.9 $222.6 $209.3

($238.9) $3.4 $191.3 $304.2 $379.6 $434.5 $479.3 $517.0 $556.2 $544.3 $514.3 $543.0 $352.9 $253.5 $191.5 $149.1 $118.5 $95.8 $78.4 $64.9 $54.2 $45.5 $38.4 $32.6 $27.7 $23.6 $20.1 $17.2 $14.7 $12.6

HH gas prices:

Net Gas Production (Bcf/year)

Operated Rig Count:

Drilling and completion cost:

Total net acreage drilled (1,000s):

Net Gas Production (Bcf):

Net production revenue:

Net cash produce by (used in) drilling program:

Discounted Net Cash Production:

NPV of all wells in this area, under current

development plan = $5.84 billion

4) Model Multi-Year Development


• Fully-load with $150MM in annual SG&A, increasing at 3% annually (~50% more than is currently being spent)

• Assume no increase in rig-count until the “core of the core” area is developed

• Only 324,000 net acres out of 1.4 million will be developed under this model

• No value is ascribed to 75% of the acreage

4) Make Conservative Assumptions

We model this company’s Northeast Marcellus asset as if it were a stand-alone company to be conservative:


4) Create Development DCF Model

Net present value = $8.0 billion

• This is a conservative approximation of how this asset would be valued if it was spun-off as a public company or sold

2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030 2031 2032 2033 2034 2035 2036 2037 2038 2039 2040 2041 2042 2043 2044 2045 2046 2047 2048 2049 2050 2051 2052

5 6 6 6 6 6 6 6 6 6 6

12 12 12 12 12 12 12 12 12 12 12 12 12 12 0 0

$4.37 $4.28 $4.28 $4.37 $4.50 $4.66 $4.86 $5.10 $5.41 $5.50 $5.50 $5.50 $5.50 $5.50 $5.50 $5.50 $5.50 $5.50 $5.50 $5.50 $5.50 $5.50 $5.50 $5.50 $5.50 $5.50 $5.50 $5.50 $5.50 $5.50 $5.50 $5.50 $5.67 $5.83 $6.01 $6.19 $6.38 $6.57 $6.76 $6.97

Commulative " Core of Core" net wells drilled: 86.9 191.2 295.5 399.8 504.0 608.3 712.6 816.9 921.2 1,025.5 1,129.8

7.0 15.3 23.6 32.0 40.3 48.7 57.0 65.4 73.7 82.0 90.4

Commulative " CORE" net wells drilled: 208.6 417.1 625.7 834.3 1,042.9 1,251.4 1,460.0 1,668.6 1,877.1 2,085.7 2,294.3 2,502.9 2,711.4 2,920.0

16.7 33.4 50.1 66.7 83.4 100.1 116.8 133.5 150.2 166.9 183.5 200.2 216.9 233.6

194.4 131.6 98.1 77.8 63.8 53.6 46.0 40.1 35.6 32.0 29.1 26.7 24.6 22.8 21.3 20.0 18.8 17.6 16.6 15.6 14.6 13.8 12.9 12.2 11.4 10.7 10.1 9.5 8.9 8.4 7.9 7.4 7.0 6.6 6.2 5.8 5.4 5.1 4.8 4.5

Net Production (MMcf) for vintage: 2013 108.3 105.4 59.0 39.9 29.8 23.6 19.4 16.3 13.9 12.2 10.8 9.7 8.8 8.1 7.5 6.9 6.5 6.1 5.7 5.3 5.0 4.7 4.4 4.2 3.9 3.7 3.5 3.3 3.1 2.9 2.7 2.5 2.4 2.2 2.1 2.0 1.9 1.8 1.7 1.6

Net Production (MMcf) for vintage: 2014 129.9 126.5 70.8 47.9 35.7 28.3 23.2 19.5 16.7 14.6 13.0 11.7 10.6 9.7 9.0 8.3 7.7 7.3 6.8 6.4 6.0 5.7 5.3 5.0 4.7 4.4 4.2 3.9 3.7 3.5 3.2 3.1 2.9 2.7 2.5 2.4 2.2 2.1 2.0

Net Production (MMcf) for vintage: 2015 129.9 126.5 70.8 47.9 35.7 28.3 23.2 19.5 16.7 14.6 13.0 11.7 10.6 9.7 9.0 8.3 7.7 7.3 6.8 6.4 6.0 5.7 5.3 5.0 4.7 4.4 4.2 3.9 3.7 3.5 3.2 3.1 2.9 2.7 2.5 2.4 2.2 2.1

Net Production (MMcf) for vintage: 2016 129.9 126.5 70.8 47.9 35.7 28.3 23.2 19.5 16.7 14.6 13.0 11.7 10.6 9.7 9.0 8.3 7.7 7.3 6.8 6.4 6.0 5.7 5.3 5.0 4.7 4.4 4.2 3.9 3.7 3.5 3.2 3.1 2.9 2.7 2.5 2.4 2.2

Net Production (MMcf) for vintage: 2017 129.9 126.5 70.8 47.9 35.7 28.3 23.2 19.5 16.7 14.6 13.0 11.7 10.6 9.7 9.0 8.3 7.7 7.3 6.8 6.4 6.0 5.7 5.3 5.0 4.7 4.4 4.2 3.9 3.7 3.5 3.2 3.1 2.9 2.7 2.5 2.4

Net Production (MMcf) for vintage: 2018 129.9 126.5 70.8 47.9 35.7 28.3 23.2 19.5 16.7 14.6 13.0 11.7 10.6 9.7 9.0 8.3 7.7 7.3 6.8 6.4 6.0 5.7 5.3 5.0 4.7 4.4 4.2 3.9 3.7 3.5 3.2 3.1 2.9 2.7 2.5

Net Production (MMcf) for vintage: 2019 129.9 126.5 70.8 47.9 35.7 28.3 23.2 19.5 16.7 14.6 13.0 11.7 10.6 9.7 9.0 8.3 7.7 7.3 6.8 6.4 6.0 5.7 5.3 5.0 4.7 4.4 4.2 3.9 3.7 3.5 3.2 3.1 2.9 2.7

Net Production (MMcf) for vintage: 2020 129.9 126.5 70.8 47.9 35.7 28.3 23.2 19.5 16.7 14.6 13.0 11.7 10.6 9.7 9.0 8.3 7.7 7.3 6.8 6.4 6.0 5.7 5.3 5.0 4.7 4.4 4.2 3.9 3.7 3.5 3.2 3.1 2.9

Net Production (MMcf) for vintage: 2021 129.9 126.5 70.8 47.9 35.7 28.3 23.2 19.5 16.7 14.6 13.0 11.7 10.6 9.7 9.0 8.3 7.7 7.3 6.8 6.4 6.0 5.7 5.3 5.0 4.7 4.4 4.2 3.9 3.7 3.5 3.2 3.1

Net Production (MMcf) for vintage: 2022 129.9 126.5 70.8 47.9 35.7 28.3 23.2 19.5 16.7 14.6 13.0 11.7 10.6 9.7 9.0 8.3 7.7 7.3 6.8 6.4 6.0 5.7 5.3 5.0 4.7 4.4 4.2 3.9 3.7 3.5 3.2

Net Production (MMcf) for vintage: 2023 129.9 126.5 70.8 47.9 35.7 28.3 23.2 19.5 16.7 14.6 13.0 11.7 10.6 9.7 9.0 8.3 7.7 7.3 6.8 6.4 6.0 5.7 5.3 5.0 4.7 4.4 4.2 3.9 3.7 3.5

Net Production (MMcf) for vintage: 2024 120.8 120.0 77.5 58.4 48.0 43.3 39.8 37.0 34.5 32.3 30.4 28.5 26.8 25.2 23.7 22.3 20.9 19.7 18.5 17.4 16.4 15.4 14.4 13.6 12.8 12.0 11.3 10.6 10.0

Net Production (MMcf) for vintage: 2025 120.8 120.0 77.5 58.4 48.0 43.3 39.8 37.0 34.5 32.3 30.4 28.5 26.8 25.2 23.7 22.3 20.9 19.7 18.5 17.4 16.4 15.4 14.4 13.6 12.8 12.0 11.3 10.6

Net Production (MMcf) for vintage: 2026 120.8 120.0 77.5 58.4 48.0 43.3 39.8 37.0 34.5 32.3 30.4 28.5 26.8 25.2 23.7 22.3 20.9 19.7 18.5 17.4 16.4 15.4 14.4 13.6 12.8 12.0 11.3

Net Production (MMcf) for vintage: 2027 120.8 120.0 77.5 58.4 48.0 43.3 39.8 37.0 34.5 32.3 30.4 28.5 26.8 25.2 23.7 22.3 20.9 19.7 18.5 17.4 16.4 15.4 14.4 13.6 12.8 12.0

Net Production (MMcf) for vintage: 2028 120.8 120.0 77.5 58.4 48.0 43.3 39.8 37.0 34.5 32.3 30.4 28.5 26.8 25.2 23.7 22.3 20.9 19.7 18.5 17.4 16.4 15.4 14.4 13.6 12.8

Net Production (MMcf) for vintage: 2029 120.8 120.0 77.5 58.4 48.0 43.3 39.8 37.0 34.5 32.3 30.4 28.5 26.8 25.2 23.7 22.3 20.9 19.7 18.5 17.4 16.4 15.4 14.4 13.6

Net Production (MMcf) for vintage: 2030 120.8 120.0 77.5 58.4 48.0 43.3 39.8 37.0 34.5 32.3 30.4 28.5 26.8 25.2 23.7 22.3 20.9 19.7 18.5 17.4 16.4 15.4 14.4

Net Production (MMcf) for vintage: 2031 120.8 120.0 77.5 58.4 48.0 43.3 39.8 37.0 34.5 32.3 30.4 28.5 26.8 25.2 23.7 22.3 20.9 19.7 18.5 17.4 16.4 15.4

Net Production (MMcf) for vintage: 2032 120.8 120.0 77.5 58.4 48.0 43.3 39.8 37.0 34.5 32.3 30.4 28.5 26.8 25.2 23.7 22.3 20.9 19.7 18.5 17.4 16.4

Net Production (MMcf) for vintage: 2033 120.8 120.0 77.5 58.4 48.0 43.3 39.8 37.0 34.5 32.3 30.4 28.5 26.8 25.2 23.7 22.3 20.9 19.7 18.5 17.4

Net Production (MMcf) for vintage: 2034 120.8 120.0 77.5 58.4 48.0 43.3 39.8 37.0 34.5 32.3 30.4 28.5 26.8 25.2 23.7 22.3 20.9 19.7 18.5

Net Production (MMcf) for vintage: 2035 120.8 120.0 77.5 58.4 48.0 43.3 39.8 37.0 34.5 32.3 30.4 28.5 26.8 25.2 23.7 22.3 20.9 19.7

Net Production (MMcf) for vintage: 2036 120.8 120.0 77.5 58.4 48.0 43.3 39.8 37.0 34.5 32.3 30.4 28.5 26.8 25.2 23.7 22.3 20.9

120.8 120.0 77.5 58.4 48.0 43.3 39.8 37.0 34.5 32.3 30.4 28.5 26.8 25.2 23.7 22.3

302.6 366.9 413.5 444.9 468.7 488.0 504.5 518.8 531.4 542.8 553.2 553.5 555.7 570.6 588.6 607.9 629.5 652.4 675.7 699.0 721.9 744.1 765.6 786.1 805.6 703.3 600.9 539.9 497.0 463.7 434.2 407.3 382.4 359.3 337.7 317.5 298.4 280.5 263.7 247.9

($582.3) ($698.7) ($698.7) ($698.7) ($698.7) ($698.7) ($698.7) ($698.7) ($698.7) ($698.7) ($698.7) ($1,397.4) ($1,397.4) ($1,397.4) ($1,397.4) ($1,397.4) ($1,397.4) ($1,397.4) ($1,397.4) ($1,397.4) ($1,397.4) ($1,397.4) ($1,397.4) ($1,397.4) ($1,397.4) $0.0 $0.0 $0.0 $0.0 $0.0 $0.0 $0.0 $0.0 $0.0 $0.0 $0.0 $0.0 $0.0 $0.0 $0.0

$926.5 $1,095.6 $1,234.7 $1,362.2 $1,484.4 $1,610.3 $1,749.7 $1,903.8 $2,090.7 $2,174.8 $2,216.1 $2,217.5 $2,226.3 $2,285.8 $2,358.0 $2,435.5 $2,522.1 $2,613.5 $2,706.9 $2,800.3 $2,892.0 $2,981.2 $3,067.1 $3,149.3 $3,227.5 $2,817.7 $2,407.2 $2,162.9 $1,991.3 $1,857.7 $1,739.4 $1,631.6 $1,585.0 $1,540.3 $1,497.2 $1,455.3 $1,414.4 $1,374.5 $1,335.5 $1,297.5

$344.3 $396.9 $535.9 $663.4 $785.7 $911.6 $1,051.0 $1,205.1 $1,392.0 $1,476.1 $1,517.4 $820.1 $828.9 $888.4 $960.6 $1,038.1 $1,124.7 $1,216.1 $1,309.5 $1,402.8 $1,494.6 $1,583.8 $1,669.6 $1,751.8 $1,830.1 $2,817.7 $2,407.2 $2,162.9 $1,991.3 $1,857.7 $1,739.4 $1,631.6 $1,585.0 $1,540.3 $1,497.2 $1,455.3 $1,414.4 $1,374.5 $1,335.5 $1,297.5

($150.0) ($154.5) ($159.1) ($163.9) ($168.8) ($173.9) ($179.1) ($184.5) ($190.0) ($195.7) ($201.6) ($207.6) ($213.9) ($220.3) ($226.9) ($233.7) ($240.7) ($247.9) ($255.4) ($263.0) ($270.9) ($279.0) ($287.4) ($296.0) ($304.9) ($314.1) ($323.5) ($333.2) ($343.2) ($353.5) ($364.1) ($375.0) ($386.3) ($397.9) ($409.8) ($422.1) ($434.7) ($447.8) ($461.2) ($475.1)

$185.0 $209.9 $296.6 $357.4 $401.3 $436.2 $468.7 $498.8 $534.0 $517.1 $483.1 $204.4 $186.6 $184.3 $184.0 $183.4 $183.2 $182.4 $180.6 $177.5 $173.2 $167.9 $161.7 $154.8 $147.5 $220.1 $166.5 $132.9 $108.8 $90.3 $75.1 $62.4 $54.1 $46.8 $40.5 $35.0 $30.2 $26.0 $22.3 $19.0

Net Gas Production (Bcf/year)

"Core of Core" Operated Rig Count:

Discounted Net Income:

"Core" Operated Rig Count:

Total "CORE" net acreage drilled (1,000s):

SG&A per year:

Current Production:

Total "C of C" net acreage drilled (1,000s):

Net Gas Production (Bcf):

Drilling and completion cost:

Net production revenue:

Net cash produce by (used in) drilling program:

HH gas prices:


4) Create Development DCF Model

Stand-alone entity is FCF positive in every year • This would provide flexibility in development plan

• Upside to valuation if development is accelerated or the 1.1 million net acres not included in the development plan are monetized


SEC Reserve Value of Case Study

SEC PV10 value is only $1 billion • Due to “trailing 12-month” pricing regime

• Even if SEC PV10 is adjusted for strip pricing, it captures less than $4 billion in present value

No value ascribed to these reserves


Sell-Side Valuation of Case Study

While neither company breaks it out specifically, this asset appears to be valued by GS at ~$8.5 billion and by JPM at less than $4 billion. This is a huge disparity for a single asset.

• Goldman uses a sum-of-parts valuation

• JPM uses a limited DCF methodology similar to SEC PV10

• Neither analyst wants to stick their neck out: • Goldman analyst subtracts ~$9 billion in phantom liabilities at the parent

level to justify a “neutral” • JP Morgan uses a clearly broken SEC methodology to justify a “neutral”

• How will the market value assets like this when they are producing free cash flow (if not sold or spun-off)?

Copyright 2013 Union Square Research Group, LLC 49 www.unionsquareresearch.com (646) 706-7633

Diversified shale E&P “A”

• ~70% of assets are shale

• 10+ years of drilling inventory

• Enterprise value >$10 billion

• EV/EBITDA ≈ 6

• Valued by the sell-side on a peer EV/EBITDA ratio or on an SEC proved reserve value

Single shale E&P “B”

• ~90% of assets are shale

• 10+ years of drilling inventory

• Enterprise value >$10 billion

• EV/EBITDA ≈ 14

• Valued by the sell-side under a multi-year development model DCF

“Pure Play” Valuation Disparity


Conclusions

• There are huge valuation disparities in the public market for shale assets, both high and low

• Investors willing to perform substantial due diligence can arrive at firm and robust valuations

• There are tremendous opportunities due to the current dislocations in the public market:

• Cheap shale assets within smaller under-analyzed E&P companies • Cheap shale assets within larger diversified E&P companies • Expensive “pure play” shale companies, which can be used to set up

long-short trades or express a view on the underlying commodity


About USRG

Union Square Research is a group of buy side analysts working on both a consulting and subscription/commission basis for institutional investors of all sizes. In an industry where reporting often passes for analysis and sector experience passes for sector expertise, we differentiate everything ourselves through real industry expertise learned through operational

experience and a rigorous research process, which is second to none. We are able to make actionable non-consensus calls through a combination of our expertise, our no-stone-uncovered process, and most importantly, our patience. Our clients know that our research track record is our most important asset; our clients say we've earned their trust. Contact us to learn about our services.

We are pleased to be working with Wall Street Access, an independent firm with a 32-year track record of providing research and execution services to its clients. If you are interested in obtaining our research through an execution services firm, please contact Matt Treacy at (212) 232-5690.


Disclaimer

The information herein reflects the opinions and projections of Union Square Research Group, LLC (collectively “USRG”) and its affiliates as of the date of publication, which is subject to change without notice at any time subsequent to the date of issue, and serves as a limited supplement to a verbal presentation. While the information presented herein is believed to be reliable, no representation or warranty is made concerning the accuracy of any data presented. USRG is not a tax expert and nothing within this presentation should be construed as tax advice. All information provided in this presentation is for informational purposes only and should not be deemed as investment advice or a recommendation to purchase or sell any specific security. Any logos, graphics, presentation materials or photos included in this presentation are the express property of their owners. USRG as well as funds and clients advised by USRG may have an economic interest in the price movement of securities mentioned in this presentation, but this economic interest is subject to change without notice. This presentation my not be reproduced without prior written permission from USRG.


End Notes Slide 4: Picture Source: http://llenrock.com/blog/tag/stuyvesant-town/

Slide 5: Picture Source: http://www.miamicondoinvestments.com/condo/one-thousand-museum-condos/

Slide 7: Picture Source: http://www.whatsupyasieve.com/2013/01/26/birthday-boy-wayne-gretzky-2/

Slide 9: Picture Source: http://content.cdlib.org/ark:/13030/kt838nd424/

Slide 11: Picture Source: searchanddiscovery.org, American Oil and Gas Reporter, American Association of Petroleum Geologists (aapg.org)

Slide 12: Picture Source: modified from IEA report; http://www.eia.gov/todayinenergy/detail.cfm?id=3750

Slide 13: Picture Source: modified from IEA report; http://www.eia.gov/todayinenergy/detail.cfm?id=3750

Slide 14: Sources: Tudor Pickering & Holt presentation and Southwestern Energy company presentation

Slide 16: Sources: Gastar Exploration corporate presentation and USRG proprietary valuation model

Slide 17: Picture Source: http://www.paranet.com/Portals/107491/images/it%20due%20diligence.jpg

Slide 23: Source: definitions adapted from Schlumberger’s Oilfield Glossary, Investopedia, and SEC.gov

Slide 24: Picture Source: Modified from an image at: http://www.n2ndochina.org/wp-content/uploads/2013/03/Puzzle-pieces5132.jpg

Slide 26: Sources: Chesapeake Energy November 2012 and June 2013 corporate presentations; Southwestern Energy 4/29/13 press release

Slide 28: Sources: CHK disclosed with their Q1, 2013 report that they held ~100k net acres in the “core of core” and “multiples of that” in the “core”

Slide 30: Source: www.eia.gov/naturalgas/pipelines/EIA-NaturalGasPipelineProjects.xls‎

Slide 32: Source: Adapted from a graphic in Northeast Driller Vol. 4 No. 3 April 2013

Slide 33: Source: Adapted from a graphic in Northeast Driller Vol. 4 No. 3 April 2013, Chesapeake Energy May, 2013 corporate presentation, and state records



Slide 36: Source: Adapted from a graphic in Northeast Driller Vol. 4 No. 3 April 2013, Chesapeake Energy May, 2013 corporate presentation, state permit data and Google maps satellite image

Slide 37: Source: Google satellite maps and state permit data

Slide 38: Source: Google satellite maps and state permit data

Slide 39: Source: Google satellite maps and state permit data and Zimbio.com

Slide 41: Source: Chesapeake Energy May 2013 corporate presentation

Slide 48: Sources: Goldman Sachs May 30, 2013 research note; JPM May 15, 2013 research note

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