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Canadian Energy Research Institute

North American Market Dynamics: Gas Plays in North America – A Review

Paul Kralovic

Study No. 123 – Section I

February 2011

Relevant • Independent • Objective

NORTH AMERICAN NATURAL GAS MARKET DYNAMICS: PLAYS IN NORTH AMERICA – A REVIEW

North American Natural Gas Market Dynamics: Shale Gas Plays in North America – A Review

Copyright © Canadian Energy Research Institute, 2011 Sections of this study may be reproduced in magazines and newspapers with acknowledgement to the Canadian Energy Research Institute

Study No. 123 ISBN 1-896091-97-0

Author: Paul Kralovic*

*Paul Kralovic is an external consultant and is the Director of Calgary-based Kralovic Economics Inc.

Acknowledgements: The author of this report would like to extend his thanks and gratitude to everyone involved in the production and editing of the material, including, but not limited to George Eynon, Megan Murphy and Peter Howard

CANADIAN ENERGY RESEARCH INSITTUTE 150, 3512 – 33 Street NW Calgary, T2L 2A6 www.ceri.ca

February 2011 Printed in Canada North American Natural Gas Market Dynamics: iii Shale Gas Plays in North America – A Review Table of Contents

LIST OF FIGURES ...... v LIST OF TABLES ...... vii CHAPTER 1 INTRODUCTION AND REPORT STRUCTURE ...... 1 Background...... 1 Regulatory and Environmental Issues ...... 7 Report Structure ...... 22 CHAPTER 2 ESTABLISHED SHALE PLAYS ...... 23 The , Michigan ...... 23 The , ...... 29 The , Appalachian Basin, //West Virginia ...... 35 The , ...... 42 The , /Texas ...... 48 The Marcellus Shale, /West Virginia/Ohio/ ...... 55 The , Basin, Illinois//Kentucky ...... 62 The Woodford Shale, Oklahoma ...... 68 CHAPTER 3 EMERGING/EXPLORATORY SHALE PLAYS ...... 75 The Eagle Ford Shale and Pearsall Shale, Maverick Basin, Texas ...... 75 The Floyd-Neal Shale, Black Warrior Basin, /Mississippi ...... 81 The Hilliard-Baxter Shale, Greater Green River Basin, Wyoming/Colorado ...... 87 The Montney Shale, ...... 94 The Muskwa/Ootla Shale, Basin, British Columbia ...... 103 The , Québec ...... 114 Other Shale Gas Plays ...... 119 APPENDIX A A LIST OF FRAC FLUID ADDITIVES ...... 133 APPENDIX B A COMPLETE LIST OF SHALE GAS PLAYS IN NORTH AMERICA ...... 135

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February 2011 North American Natural Gas Market Dynamics: v Shale Gas Plays in North America – A Review List of Figures

Figure 1.1 Major Shale Gas Basins in North America ...... 2 Figure 1.2 Schematic Geology of Natural Gas Resources ...... 4 Figure 1.3 Horizontal versus Vertical Multi-stage Fracture Stimulation ...... 5 Figure 1.4 Natural Gas Production by Source, 1990-2035 ...... 7 Figure 1.5 Composition of a Frac Fluid ...... 11 Figure 1.6 Groundwater Protection and Drilling and Completions ...... 15 Figure 1.7 A Typical Horizontal Well and Multi-stage Frac ...... 17 Figure 1.8 A Typical Frac’ing Operation in ...... 19 Figure 1.9 Multiple Horizontal Wells Drilled from a Single Well Pad ...... 20 Figure 1.10 Vertical Drilling versus Multiple Horizontal Wells Drilled from a Single Well Pad ...... 21 Figure 2.1 Antrim Shale Map ...... 23 Figure 2.2 Map of Michigan’s Drilling Activity ...... 26 Figure 2.3 Barnett Shale Map ...... 29 Figure 2.4 Drilling Forecast for the Barnett Shale ...... 35 Figure 2.5 Map of the Devonian & Marcellus Shales ...... 36 Figure 2.6 Map of the Lower Huron & Marcellus Fairways ...... 39 Figure 2.7 Virginia’s Nora-Haysi Field ...... 40 Figure 2.8 Fayetteville Shale Map ...... 42 Figure 2.9 Drilling Forecast for the Fayetteville Shale ...... 48 Figure 2.10 Haynesville Shale Map ...... 49 Figure 2.11 Drilling Forecast for the Haynesville Shale ...... 54 Figure 2.12 Marcellus Shale Map ...... 56 Figure 2.13 Hydraulic Frac’ing Job Size for Range Resources ...... 60 Figure 2.14 Drilling Forecast for the Marcellus Shale ...... 61 Figure 2.15 New Albany Shale Map ...... 63 Figure 2.16 Map of the and the New Albany Shale ...... 65 Figure 2.17 Woodford Shale Map ...... 69 Figure 2.18 Drilling Forecast for the Woodford Shale ...... 73 Figure 3.1 Eagle Ford Shale Map ...... 75 Figure 3.2 Schematic Geology of the Eagle Ford Shale ...... 76 Figure 3.3 Eagle Ford Shale Activity ...... 79 Figure 3.4 Floyd-Neal Shale Map ...... 82 Figure 3.5 Map of the Floyd-Neal Drilling Activity ...... 84 Figure 3.6 Hilliard-Baxter Shale Map ...... 87 Figure 3.7 Greater Green River Basin Map ...... 88 Figure 3.8 Map of Existing and Planned Pipelines in the Rock Mountains ...... 93 Figure 3.9 Montney/Doig Basin Shale Region ...... 95 Figure 3.10 Upper and Lower Montney Horizontal Type Curves ...... 98 Figure 3.11 Horn River Shale Region ...... 104 Figure 3.12 Landholdings Within the Horn River Basin ...... 106 Figure 3.13 LNG Terminal Project ...... 109 Figure 3.14 Drilling Forecast for the Horn River Basin Shale ...... 111 Figure 3.15 Location of Utica Shale ...... 115 Figure 3.16 The Barnett-Woodford Shale ...... 120 Figure 3.17 ...... 122 Figure 3.18 Shale Gas Development in Alabama ...... 123 Figure 3.19 The Paradox Basin ...... 125 Figure 3.20 Uinta and Piceance Basins Map ...... 127 Figure 3.21 GGRB and the Uinta and Piceance Basins Map ...... 127

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Figure 3.22 The Pierre (Raton Basin) Shale Map ...... 129 Figure 3.23 The Pierre Shale (Raton Basin) and Area Map ...... 130

February 2011 North American Natural Gas Market Dynamics: vii Shale Gas Plays in North America – A Review List of Tables

Table 1.1 Water Requirements for Various Shale Gas Plays ...... 13 Table 2.1 Antrim Geological Characteristics ...... 24 Table 2.2 Basin Metrics for the Antrim Shale ...... 25 Table 2.3 Barnett Shale Geological Characteristics ...... 30 Table 2.4 Basin Metrics for the Barnett Shale ...... 31 Table 2.5 Top Ten Producers in the Barnett Shale ...... 32 Table 2.6 Devonian Shales Geological Characteristics ...... 37 Table 2.7 Basin Metrics for the Devonian Shales ...... 38 Table 2.8 Fayetteville Shale Geological Characteristics ...... 43 Table 2.9 Basin Metrics for the Fayetteville Shale ...... 44 Table 2.10 Haynesville Shale Geological Characteristics ...... 50 Table 2.11 Basin Metrics for the Haynesville Shale ...... 51 Table 2.12 Marcellus Shale Geological Characteristics ...... 57 Table 2.13 Basin Metrics for the Marcellus Shale...... 58 Table 2.14 New Albany Geological Characteristics ...... 64 Table 2.15 Basin Metrics for the New Albany Shale ...... 65 Table 2.16 Woodford Shale Geological Characteristics ...... 70 Table 2.17 Basin Metrics for the Woodford Shale ...... 70 Table 3.1 Eagle Ford & Pearsall Shale Geological Characteristics...... 78 Table 3.2 Floyd-Neal Shale Geological Characteristics ...... 83 Table 3.3 Basin Metrics for the Floyd-Neal Shale ...... 84 Table 3.4 Hilliard-Baxter Shale Geological Characteristics ...... 90 Table 3.5 Basin Metrics for the Hilliard-Baxter Shale ...... 90 Table 3.6 Montney Basin Shale Geological Characteristics ...... 96 Table 3.7 Basin Metrics for the Montney Shale...... 97 Table 3.8 Horn River Basin Shale Geological Characteristics ...... 105 Table 3.9 Basin Metrics for the Horn River Basin Shale ...... 106 Table 3.10 Utica Shale Geological Characteristics ...... 116 Table 3.11 Basin Metrics for the Utica Shale ...... 116 Table 3.12 Comparing Geological Features ...... 117 Table 3.13 Barnett-Woodford Shale Geological Characteristics...... 122 Table 3.14 Chattanooga Shale Geological Characteristics ...... 124 Table 3.15 Gothic Shale Geological Characteristics ...... 126 Table 3.16 Mancos Shale Geological Characteristics ...... 128 Table 3.17 Basin Metrics for the Mancos Shale ...... 129 Table 3.18 Pierre Shale Geological Characteristics ...... 131 Table A.1 Frac’ing Fluid Additives, Main Compounds and Common Uses ...... 133

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February 2011 North American Natural Gas Dynamics: 1 Shale Gas Plays in North America – A Review Chapter 1 Introduction and Report Structure

Background If the recent boom is any indication, the future potential of shale gas is nothing short of dramatic.

Representing an increasingly large and growing share of the recoverable resource base, shale gas is garnering a lot of interest, not only in North America, but around the world. As of November 2008, FERC estimates approximately 742 Tcf of technically recoverable shale gas resources in the .1 This is more than triple what the agency had estimated only two years earlier. Much of this is attributable to rapid technological advancements in drilling and the ability to economically recover natural gas from shale rock.2 And while there is currently no large- scale commercial shale production yet in Canada, the Gas Technology Institute (GTI) estimates over 850 Tcf of gas in place in just the Western Canadian Sedimentary Basin (WCSB).3

The Barnett Shale in East Texas—the most prolific gas shale play in the US—accounts for 8.5 percent of the Lower- 48’s total gas production.4 In fact, shale gas production in the US accounts for 17 percent of total natural gas production in 2008. Amidst conventional natural gas production declines, the success of Barnett has created a sense of excitement for E&Ps and the energy sector as a whole. While shale formations have unique properties and characteristics, depending on porosity, thickness, brittleness and permeability, many E&P companies in basins across North America are relying on improved drilling efficiencies and advances in fracturing (frac’ing) and other forms of stimulation to release shale gas that were learned from the Barnett Shale play—this is particularly true in a lower natural gas price environment, as has been the case in the past several years.

It is, however, important to mention that producing shale gas is by no means a new concept. The first commercial natural gas well in the US tapped into the Devonian-aged shale in Fredonia, New York in 1821—albeit in small quantities. The ’s Big Sandy Field, the first large-scale commercial field in the US, was first developed in the 1880s and to a greater extent in the 1920s. Michigan’s Antrim Shale was being produced as early as the 1940s.5 The technology, however, to make shale gas economically feasible on a large-scale simply did not exist. Currently, the Antrim Shale (Northern Michigan), the Barnett Shale (Fort Worth Basin, North Texas), the Devonian/Ohio Shales (Appalachia), the Fayetteville Shale (Arkansas), the Haynesville Shale (Louisiana), the Marcellus Shale (Appalachia), the New Albany (Illinois/Indiana) and the Woodford Shale (Oklahoma) are all established and commercially-producing plays. There are, however, currently two dozen of additional shale plays across over 20 states and provinces that are being categorized as major and are being developed or in the

1 http://www.naturalgas.org/overview/unconvent_ng_resource.asp (November 17, 2010) 2 http://www.naturalgas.org/shale/growingshare.asp (November 17, 2010) 3 NRCAN website, http://nrcan.gc.ca/eneene/sources/natnat/shocou-eng.php (November 17, 2010) 4 Modern Shale Gas Development in the United States: A Primer, US Department of Energy, Office of Fossil Energy and the National Energy Technology Laboratory, April 2009, pp. 8. 5 Indiana Geological Survey, Antrim Shale, http://igs.indiana.edu/Geology/structure/compendium/ html/comp3n6s.cfm (accessed on September 23, 2010)

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exploratory phase of development. While production volumes from shale gas resources in Canada are currently insignificant compared to United States, there is substantial potential for future growth in Canada. Energy companies, spurred by shale gas discoveries, added C$220 million to British Columbia’s land sale coffers in the September 2008 auction. According to the Ministry of Energy, Mines and Resources, British Columbia closed out the 2008-09 fiscal year with an all-time high of C$2.4 billion sold—more than doubling the previous record set in 2007.6

Figure 1.1 illustrates major shale gas basins in North America. There are dozens more that are considered minor and are only now being studied for their gas potential.

Figure 1.1 Major Shale Gas Basins in North America

Source: NEB7

6 Marketwire, Press Release, “Government of British Columbia: Oil and Gas Produce Record-Breaking Fiscal Year”. http://www.marketwire.com/press-release/Government-Of-British-Columbia-966555.html, (accessed on March 26, 2009) 7 NEB website, http://www.neb.gc.ca/clf-nsi/rnrgynfmtn/nrgyrprt/nrgyvrvw/cndnnrgyvrvw2009/mg/fg5_5-eng.jpg (accessed on November 23, 2010)

February 2011 North American Natural Gas Dynamics: 3 Shale Gas Plays in North America – A Review

Given the sheer magnitude of the resource potential of shale gas, it essential to understand—or at least to appreciate—the quite different characteristics of the shales in different basins, and their lack of homogeneity even in the same trend. For the investor, it is important to understand the various players and the various shale gas plays. And for anyone involved in the energy industry, or interested about energy, it is essential to be aware of this unconventional source of natural gas.

This purpose of this study is to review shale gas plays in North America, their geological differences, the players involved and their potential. It is important to review the geological characteristics of the various shale plays. However, this study explores the questions of where, who and when versus the what, how and why. In other words, this study will examine several of the major shale plays in North America and will not delve into the chemistry and geology of shale gas or to debate the complex drilling technologies available. Many people are familiar with several, if not all, the big five shale plays in North America–the Barnett, Fayetteville, Haynesville, Marcellus and Woodford Shales. While these plays are the hottest ones, basking in the media, there are many other plays that are far less known—and may end up being more productive than the aforementioned. This study will explore other less well-known but potentially prolific shale gas plays in North America. plays are beyond the scope of this study, as are other unconventional natural gas resources such as and coalbed methane (CBM).

The definition of what constitutes conventional and unconventional sources of natural gas is blurred and changes with advances in technology and science. Essentially, unconventional gas is natural gas that cannot be produced at economic flow rates or in economic volumes unless the reservoir is stimulated by hydraulic fracture treatments, a horizontal wellbore, multilateral wellbores, or some other technique to access more of the reservoir.

In this dynamic environment, the Canadian Association of Petroleum Producers (CAPP) suggests that the two categories are defined by the ease, manner of development and costs associated with extraction and development of the resource.8 Currently, unconventional natural gas is frequently divided into three parts: shale gas, tight gas and CBM. Other industry pundits suggest that deep gas, geopressured zones and gas hydrates should be added to the constantly evolving definition.

Shale gas is natural gas generated from and contained within dark-coloured, organic rich rocks. Shales can act as the source, reservoir, and seal for natural gas. According to the Centre for Energy, the natural gas molecules are generally stored in three ways: adsorbed into the organic matter in the shales, trapped in the pore spaces of the fine-grained sediments interbedded with the shale, or trapped in fractures within the shale itself.9 The exploitable occurrences are low permeability, with low production rates from the natural fracture system.

Shale gas should not be confused with tight gas, another form of unconventional natural gas. Tight gas is natural gas trapped, by a variety of mechanisms, in unusually impermeable reservoir rocks—usually , but sometimes as well.

8 CAPP website, http://www.capp.ca/canadaIndustry/naturalGas/Conventional- Unconventional/Pages/default.aspx#DiyHNz4iXNrv (accessed on November 15, 2010) 9 Centre For Energy website, http://www.centreforenergy.com/AboutEnergy/ONG/ShaleGas/Overview.asp?page=1 (accessed on November 15, 2010)

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The third form of unconventional natural gas is CBM, where most, if not all, the natural gas contained in a coal seam is adsorbed in a non-gaseous state in the matrix of the coal. The hydrostatic pressure in the coal seam is all that is necessary to contain the adsorbed natural gas within the coal structure in this non-gaseous state. Once the pressure in the coal is lowered, the gas is desorbed from the coal matrix and recovered.

A schematic of the geology of natural gas resources is illustrated in Figure 1.2, including conventional non- associated gas, shale gas, tight gas, CBM and conventional associated gas.

Figure 1.2 Schematic Geology of Natural Gas Resources

Source: http://eaglefordshaleblog.com/2010/03/03/what-is-a-shale-gas-play. Accessed on December 15, 2010.

While shale formations have unique properties and characteristics, most shale plays are characterized by low permeability. E&P companies in basins across North America are relying on advances in horizontal drilling and frac’ing. Shale gas generally utilizes horizontal drilling and frac’ing to improve the low permeability of shale reservoirs.

While vertical drilling is more prevalent when developing relatively more porous and permeable wells, this is not typically the case with shale gas, where a lack of permeability is an issue. The above graphic illustrates a horizontal well, in which the wellbore is drilled vertically and then angled horizontally through the target formation.10 Drilling horizontally exposes the wellbore to more of the reservoir, thereby increasing recovery rates for gas shale.11 The

10 Modern Shale Gas Development in the United States: A Primer, US Department of Energy, Office of Fossil Energy and the National Energy Technology Laboratory, April 2009, pp. 82. 11 Centre for Energy website, http://www.centreforenergy.com/AboutEnergy/ONG/ShaleGas/Overview.asp?page=2 (accessed on January 12, 2011)

February 2011 North American Natural Gas Dynamics: 5 Shale Gas Plays in North America – A Review

direction of the drill path follows the known natural fractures in the shale.12 It is important to note that the cost of horizontal drilling is higher cost than its vertical counterpart, although advances in technology are reducing the cost.

The second integral process to improve low permeability reservoirs is frac’ing. While frac’ing has been around since the 1940s, it was fracs by Mitchell Energy in the 1990s that changed the outlook and the role of shale gas in North America.13 The company began utilizing frac’ing in the Barnett Shale that changed the outlook and role of the shale gas in North America. For shale gas and CBM, frac’ing is without doubt a game-changer.

Due to low permeability, most shale plays require fracture stimulation. This is done by pumping frac fluids down into a well until the pressure cracks the subsurface rock, increasing recovery rates dramatically for shale gas.14 To increase the efficiency of the process further, multi-stage frac’ing technique isolates segments of the wellbore to frac them one at a time.15 This process allows the geologists and drillers to determine what direction the shale is cracking from the increases in pressure.16 As such, advances in microseismic imaging also play an important role in the success of developing shale gas. Figure 1.3 illustrates horizontal and vertical multi-stage frac’ing.

Figure 1.3 Horizontal versus Vertical Multi-stage Fracture Stimulation

Source: NEB17

12 National Energy Board, “A Primer for Understanding Canadian Shale Gas - Energy Briefing Note”, http://www.neb-one.gc.ca/clf-nsi/rnrgynfmtn/nrgyrprt/ntrlgs/prmrndrstndngshlgs2009/prmrndrstndngshlgs2009- eng.html#s7 (accessed on January 12, 2011) 13 http://geology.com/articles/hydraulic-fracturing/ (accessed on January 11, 2011) 14 ibid 15 National Energy Board, “A Primer for Understanding Canadian Shale Gas - Energy Briefing Note”, http://www.neb-one.gc.ca/clf-nsi/rnrgynfmtn/nrgyrprt/ntrlgs/prmrndrstndngshlgs2009/prmrndrstndngshlgs2009- eng.html#s7 (accessed on January 12, 2011) 16 ibid 17 ibid

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Frac fluids differ depending on the geology of the shale. For example, the presence of hard minerals such as silica and may determine the chemical composition of the frac fluids used.18 While clay absorbs the frac fluids, silica-rich shales are excellent candidates for frac’ing.19 Another factor is the internal pressure of the shale. Over- pressured shales are better candidates for frac’ing.20 The composition of frac fluids also depends on company preference. With that being said, frac fluids typically contain approximately 99 percent water and sand but may also contain other materials, such as gelling agents to make the fluid more viscous.21 The water fractures the shale while the sand acts a proppant, keeping the fractures open when the frac fluid is recovered when the well is brought into production.22

While advances in horizontal drilling and hydraulic frac’ing have played very important roles in the evolution and development of shale gas, completing the trifecta of important factors in the advancement of shale gas economic viability was the rapid increases in the price of natural gas several years before the current recession.23 The increase in prices was due to supply and demand pressures, particularly true in the past decade.

With natural gas being the choice of fuel across various sectors, demand continues to increase. Declines in conventional gas production in both Canada and the US have fuelled various unconventional natural gas resources to attracting attention, particularly shale gas. The Energy Information Agency (EIA) suggests that the gap between surging demand for natural gas and US domestic supply will grow to 9 Tcf by 2025.24 Unconventional natural gas resources, like shale gas, tight gas and CBM, can significantly change that balance. Unconventional production already accounts for nearly half of total US production and this number is expected to increase. According to the EIA’s Annual Energy Outlook 2010, by 2035, 35 percent of domestic gas production will come from shale gas.

Figure 1.4 demonstrates expected natural gas production by source over the next quarter of a century.

18 ibid 19 ibid 20 http://geology.com/articles/hydraulic-fracturing/ (accessed on January 14, 2011) 21 API, at a Glance, 2008. 22 ibid 23 Modern Shale Gas Development in the United States: A Primer, US Department of Energy, Office of Fossil Energy and the National Energy Technology Laboratory, April 2009, pp. 8. 24 Modern Shale Gas Development in the United States: A Primer, US Department of Energy, Office of Fossil Energy and the National Energy Technology Laboratory, April 2009, pp. 4.

February 2011 North American Natural Gas Dynamics: 7 Shale Gas Plays in North America – A Review

Figure 1.4 Natural Gas Production by Source, 1990-2035

Source: EIA25

Canada shares this sentiment. Production from British Columbia’s shale and tight gas will likely play a large role in mitigating the effects of declining conventional production on total production in Canada. In its report, Short-term Natural Gas Deliverability 2008-2010, the National Energy Board (NEB) suggests that production is expected to decrease by 7 percent by 2010 and that the Horn River and Montney plays could alter the projections of decline in the future.

This study explores the major and several less known, but potentially prolific, shale gas plays that could play a large role in North America’s energy future.

Regulatory and Environmental Issues This section explores the various regulatory and environmental issues regarding shale gas in North America. It is important to note that this section only briefly discusses regulatory and environmental issues. While small, this section provides vital information regarding shale gas development in North America.

While frac’ing is a very important activity in the process of developing shale gas, it is also at the heart of making shale gas a politically-charged topic. Shale gas is often perceived as an unknown entity, as are the technologies used to produce the vast resource. Nothing, however, can be further from the truth.

The following discusses briefly regulatory issues, frac fluids composition and chemicals, water usage and management, groundwater protection and surface land use and impacts.

25 EIA website, http://www.eia.gov/oiaf/aeo/gas.html (accessed on November 24, 2010)

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Regulatory Issues Oil and gas—including shale gas—development and production is regulated by a complex and extensive set of regulations at the federal, state/provincial and local levels. It is not realistic to analyze each of the state/provincial structures and implementation in this study, let alone the plethora of local regulations from various counties, municipalities, First Nation groups and regional water authorities. It is, however, useful to outline briefly the existing regulatory framework and accompanying issues for the shale gas industry.

While it is not difficult to paint a picture of the complexity of the regulatory environment, it must be said that the industry, regulators and public continue to collaborate successfully.

In the US, the Environmental Protection Agency (EPA) administers federal environmental laws, the exception being if development occurs on federal land.26 In this case the land is managed by the Bureau of Land Management (BLM) and the US Forest Service.27 The former is a part of the Department of the Interior while the latter is a part of the Department of Agriculture.28 The EPA is charged with protecting human health and the health of the environment. Amidst existing legislation, the federal laws governing shale gas development include the Clean Water Act (CWA), the Safe Drinking Water Act (SDWA), the Clean Air Act (CAA) and the National Environmental Policy Act (NERA).29 The EPA administers laws, either directly or by authorizing states to administer on their behalf. In spite of the fact that the EPA employs approximately 17,000 people and has an annual budget of US$10.5 billion, the federal agency simply do not have the resources to administer and implement legislation.30 In addition, the EPA determined that a ‘one size fits all’ solution may not be appropriate as jurisdictions are affected by different geology, population, topography etc. As a result, states implement the aforementioned federal programs, with federal oversight and federal approval.31

States agencies, however, may adopt their own environmental standards, as long as they meet the minimum requirements set at the federal level.32 As a result, regulations across states are not standard, but must meet at least the federal standard. In other words, the Texas Railroad Commission—the nation’s largest oil and gas producing state—and Ohio’s Department of Natural Resources must monitor and enforce oil and gas activities to meet a federal standard. That being said, the two organizations are organized differently and implement slightly different standards to reflect specific state environmental concerns.

Like their federal counterparts, state agencies, however, often suffer from a lack of resources as well. It is important to note that each oil and gas producing state regulates every element of the process, from exploration to operations. Well permits, location, spacing, operation and abandonment are all administered at the state level. Environmental activities, such as water management and disposal, air emission, underground injection, surface

26 Modern Shale Gas Development in the United States: A Primer, US Department of Energy, Office of Fossil Energy and the National Energy Technology Laboratory, April 2009, pp. 25. 27 ibid 28 ibid 29 ibid 30 EPA website, www.epa.gov (accessed on January 18, 2011) 31 Modern Shale Gas Development in the United States: A Primer, US Department of Energy, Office of Fossil Energy and the National Energy Technology Laboratory, April 2009, pp. 25. 32 ibid

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disturbance and worker health and safety are implemented at the state level, but must at least follow the guidelines provided by federal laws.33

In addition to lack of resources, in the case for some states, they lack experience as well. Of the 38 oil and gas producing states, several which are attracting attention from shale gas are not traditionally producing states. While traditional producing jurisdictions such as Texas, Wyoming and Oklahoma have well laid out laws that govern the oil and gas industry, shale gas is shining a spotlight on jurisdictions that have never been producers of oil or gas or have not produced for quite some time. To complicate matters further for the oil and gas industry, some shale plays stretch across several states which may have different regulations. The Marcellus Shale in the northeast US stretch across several states, each of which may have varying legislation.

The oil and gas regulatory environment is further complicated by local regulations. Counties, municipalities, First Nations or regional water authorities may set operational requirements. Examples of the latter are the Delaware River Basin Commission (DRBC), the Susquehanna River Basin Commission (SRBC) and the Great Lakes-St. Lawrence River Basin Commission. For instance, any water withdrawn for consumption from the Delaware River Basin, located in New York, Pennsylvania, New Jersey and Delaware, must first receive a permit. In addition to water management requirement issues, local regulations often target noise and traffic issues.

The federal-state-local dynamic, however, continues to change, directly affecting the development of shale gas, and frac’ing in particular. For example, on the local or regional level, the DRBC and SRBC released new regulations on drilling in their region in the Fall of 2010, with regard to water usage in the particular river basins.34 On the federal level, Democratic members of the US Congress introduced two bills dubbed the Fracturing Responsibility and Awareness of Chemicals (FRAC) Act on June 9, 2009.35 The FRAC Act amends the previously mentioned SDWA—the federal law intended to ensure safe drinking water for the public—and gives the EPA authority of frac’ing.36 This bill adds another layer of regulation that the industry does not believe is necessary. In addition, various states challenge the need for the FRAC Act, seeing it as the latest round of federal versus state jurisdiction. The Interstate Oil and Gas Compact Commission (IOGCC), comprised of 38 oil and gas producing states and used by the state regulatory bodies to unify their voice with the federal government, is partnering with the Ground Water Protection Council (GWPC) to establish a national registry of chemicals that are used in the process of frac’ing.37

Frac’ing was made exempt from the SDWA with the ratification of the Energy Policy Act of 2005. Political pressure, however, is placing frac’ing—an integral part of shale gas development—under a microscope. Frac fluids and groundwater protection are discussed in subsequent sections.

33 ibid 34 Kelly Carmichael, “Shale Gas Environmental & Regulatory Issues”, Presentation at the Ohio Gas Association, July 27, 2010, pp. 18. 35 Open Congress for the 112th Congress website, http://www.opencongress.org/bill/111-s1215/show (accessed on January 21, 2011) 36 Modern Shale Gas Development in the United States: A Primer, US Department of Energy, Office of Fossil Energy and the National Energy Technology Laboratory, April 2009, pp. 25., 2011) 37 IOGCC website, IOGCC/GWPC to Coordinate Hydraulic Fracturing Chemical Registry, http://groundwork.iogcc.org/news/iogccgwpc-to-coordinate-hydraulic-fracturing-chemical-registry (accessed on January 21, 2011)

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In Canada the federal government has input into resource developments as it relates to interprovincial and export trade, and regulates the construction and operation of interprovincial and international pipelines, including their tolls and tariffs.38 The NEB is the main regulatory body in the Territories and offshore areas.39 The provinces, however, manage the mechanics of resource developments. This includes land use (with the exception of First Nation, defense and federal lands), drilling, pipelines (with the exception of interprovincial or export) and industrial complexes. Frac’ing is also a provincial matter, although former federal Environment Minister Jim Prentice was suggesting that environmental regulations are being drawn up, potentially affecting shale gas development.40 To date, however, there is no further news to report. Each of the provinces regulates the oil and gas industry, from exploration to abandonment. And with the exception of Prince Edward Island, the oil and gas industry is active in the remaining provinces—albeit at different levels.

Alberta is the leading oil and gas producer in Canada and has an extensive set of regulations that the industry must follow. Alberta is governed by the Alberta Oil and Gas Act which establishes the royalty structure and set up the Energy Resources Conservation Board (ERCB) as the provincial regulator to deal with ethical exploitation of hydrocarbons. The ERCB and Alberta Environment jointly manage environmental matters.41 The ERCB is an independent, quasi-judicial agency of the Government of Alberta and establishes directives and guides the regulation of Alberta’s energy resources: oil, natural gas, , coal and pipelines.42 Included in their mandate are the rules that must be adhered to with respect to drilling, completions, gas plants, provincial pipelines. Specific directives regulating production and processing, such as surface casing, production casing, wellhead requirements, as well as environmental standards with regard to produced water and the handling of non-saline water, are discussed in addressing various environmental concerns. The ERCB is in the process of creating a new unconventional gas regulatory framework by 2Q2011.

With the Horn River Basin, the Montney Shale and the Utica Shale attracting a great deal of attention, shale gas development in Canada affects the provinces of British Columbia and Québec. The main regulatory body in British Columbia is the British Columbia Oil and Gas Commission (BCOGC). The bulk of the regulations are modeled after the ERCB regulations. Québec’s Ministère des Resources Naturelles et de la Faune oversees oil and gas activities within the province, from exploration and development to drilling and decommissioning.43 In addition, the large department also regulates the development and use of land, energy, forestry and mineral resources in Québec.44 While oil and gas played a small role in the organization’s mandate, the sheer potential of the Utica has changed things. On August 31, 2010, ’s Cabinet mandated the Bureau d’Audiences Publiques sur l’Environnement (BAPE – Public Hearings on the Environment Board) to propose a framework for shale gas exploration and

38 NEB website, Canada’s National Energy Regulator, http://www.neb-one.gc.ca/clf- nsi/rthnb/whwrndrgvrnnc/cndntnlnrgrgltr-eng.html (accessed on January 18, 2011) 39 ibid 40 The Globe and Mail website October 15, 2010, http://www.theglobeandmail.com/report-on-business/industry- news/energy-and-resources/shale-gas-rules-still-being-crafted-prentice/article1758796/ (accessed on January 18, 2011) 41 Centre for Energy website, http://www.centreforenergy.com/AboutEnergy/ONG/NaturalGas/Overview.asp?page=5 (accessed on January 18, 2011) 42 43 http://www.ogc.gov.bc.ca/documents/annualreports/Oil_and_Gas_Water_Use_in_BC.pdf, pp. 4. 44 Ministère des Ressources Naturelles et de la Faune website, http://www.mrnf.gouv.qc.ca/english/department/index.jsp (accessed on September 14, 2010)

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development in the province.45 Public hearings began September 14, 2010 and ministers have encountered loud opposition from environmentalists and residents.46 A similar response has been encountered in the northeastern part of the US where regulators are also either establishing or tweaking their regulatory frameworks.

Frac Fluids Composition & Chemicals It is important to note that because each shales is unique, frac fluid composition and quantity of frac fluids vary depending on the geology of the shale. Frac fluids also differ depending on the preference of the company. That being said, the majority of the frac fluids are water and sand. The latter is used as a proppant to keep the fractures open when the frac fluids are withdrawn, or when the well is produced.

Figure 1.5 illustrates the frac fluids in the Fayetteville Shale in Arkansas. Water and sand account for 99.51 percent of frac fluid. The remaining 0.49 percent includes other chemicals such as friction reducers, corrosion inhibitors, gelling agents and scale inhibitors.

Figure 1.5 Composition of a Frac Fluid

Source: ALL Consulting47

Water in a “slickwater” frac typically accounts for between 98 and 99.5 percent of the fluid.48 Likewise, additives generally account for between 0.5 and 2 percent. While the additives vary, the reality is that most frac fluid chemicals are materials normal households use. For example, iron control is used as a food additive to flavour food and beverages. Gel, used to thicken water in fracs, is used in the cosmetic industry, as well as an ingredient of

45 “Shale Gas: Anticipated Changes to Quebec’s Regulatory Framework”, Blakes website, http://www.blakes.com/english/view.asp?ID=4214 (accessed on September 14, 2010) 46 “Quebec shale gas debate heats up”, CBC website, http://www.cbc.ca/canada/montreal/story/2010/08/29/que- shale-gas.html (accessed on September 14, 2010) 47 Arthur, J. Daniel and Jon W. Seekins, “Water and Shale Gas Development”, ALL Consulting, Presentation at the National Association of Royalty Owners, Pittsburgh, October 7, 2010, pp. 20. 48 Modern Shale Gas Development in the United States: A Primer, US Department of Energy, Office of Fossil Energy and the National Energy Technology Laboratory, April 2009, pp. 25.

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toothpaste. Friction reducers are used in makeup remover, laxatives and candy. There are, however, a number of chemical additives that could be hazardous, if not handled properly. Diluted Acid (15 percent) is primarily comprised of hydrochloric acid (HCL). This product is commonly used to clean swimming pools and must be handled carefully in large quantities. The natural gas industry, however, has long-standing industry standards regarding the handling of chemicals. Appendix A illustrates the complete list of the additives in Figure 1.5 and various roles in frac’ing, as well as their common uses. It is important to note that regulations regarding fluid handling and spills are discussed in the groundwater protection and contamination section.

While most of the chemicals used in frac’ing have practical every day uses, some in the food and beverage industry, the trend in the industry seems to be towards reducing the number of chemicals used.49 And in some cases, non-chemical treatments or “green” chemicals are being researched.50 For example, instead of using biocides to inhibit development of bacteria that can lead to corrosive by-products in the frac water, the service industry is exploring the use of UV light treatment.51 Biocides are primarily used as a disinfectant of medical and dental equipment and account for approximately 0.001 percent of the frac fluids in Figure 1.5. Chesapeake’s Green Frac™ program, founded in October 2009, has resulted in the elimination of 25 percent of the additives used in frac fluids in its shale plays.52

The proposed FRAC Act suggests that frac fluids be fully disclosed. This act also, as mentioned, proposes to give the EPA authority over the process of frac’ing. It is important to note that several state regulatory agencies are pressing for disclosure as well: including Arkansas, New York, Pennsylvania, Texas and Wyoming.53 This is in addition to state regulatory agencies’ efforts, via the IOGCC and the GWPC, to establish a national registry of chemicals used in the process of frac’ing.

Two important programs in Canada, managed by the Government of Canada, are the Chemical Management Plan and New Substances Program.54 Lubricants, drilling fluids, corrosion inhibitors, frac’ing fluids and biocides are subject to the aforementioned programs.55

Water Usage and Management With the bulk of frac fluid being comprised of water, ranging between 98 and 99.5 percent of the fluid,56 water is critical to developing shale gas. For this reason, water usage and management issues, from managing withdrawals, to transporting large volumes, to disposal issues, are important to regulators, whether they are at the federal, state/provincial or regional level.

49 Arthur, J. Daniel and Jon W. Seekins, “Water and Shale Gas Development”, ALL Consulting, Presentation at the National Association of Royalty Owners, Pittsburgh, October 7, 2010, pp. 21. 50 Ian Duncan, “Shale Gas: Energy and Environmental Issues”, Gulf Coast Carbon Center, Bureau of Economic Geology, pp. 13. 51 Arthur, J. Daniel and Jon W. Seekins, “Water and Shale Gas Development”, ALL Consulting, Presentation at the National Association of Royalty Owners, Pittsburgh, October 7, 2010, pp. 21. 52 http://www.hydraulicfracturing.com/Green-Frac/Pages/information.aspx (accessed on January 21, 2011) 53 Arthur, J. Daniel and Jon W. Seekins, “Water and Shale Gas Development”, ALL Consulting, Presentation at the National Association of Royalty Owners, Pittsburgh, October 7, 2010, pp. 21. 54 “Understanding Hydraulic Fracturing”, Canadian Society for Unconventional Gas (CSUG), January 2011, pp. 6. 55 ibid 56 Modern Shale Gas Development in the United States: A Primer, US Department of Energy, Office of Fossil Energy and the National Energy Technology Laboratory, April 2009, pp. 25.

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Thus far, most of the water used in shale development is fresh surface water or groundwater.57 On occasion, water is trucked or piped to the well site, where it is stored in large tanks or large ponds.58 In areas where water demands are high or supply is limited, such as in arid regions or during times of low precipitation, operators are utilizing alternative sources, including recycling recovered water and non-potable brackish water.59

The volume of frac fluid and water depends on the unique geological qualities of the particular shale and the size and number of stages of the frac operations.60 It is common to use between approximately 925,000 and 4,000,000 gallons of water in a deep, multi-stage horizontal frac, whereas a shallow single zone may only require approximately 5,300 to 26,500 gallons of water.61 Table 1.1 illustrates the volume of frac’ing water per well in various shale gas producing plays in the United States. It is important to note that volumes are approximate and vary substantially between wells. It is also important to note that while water volumes may be large, they represent a small percentage of overall usage, from less than 0.1 percent to 0.8 percent.62 While the Marcellus may use nearly 4 million gallons, nearly 150 million gallons per day are consumed for electrical generation in the Susquehanna River Basin.63 Other sources of water usage include public supply, industrial and mining, irrigation and livestock.

Table 1.1 Water Requirements for Various Shale Gas Plays Volume of Frac’ing Water per Shale Gas Play Well (gal) Barnett Shale 2,300,000 Fayetteville Shale 2,900,000 Haynesville Shale 2,700,000 Marcellus Shale 3,800,000 Source: ALL Consulting64

Water usage and management fall under the jurisdiction of the state and regional river basin commissions. For example, in the case of the aforementioned Marcellus Shale, depending on the location of the well, operators fall under the jurisdiction of Pennsylvania, West Virginia, Ohio or New York. Permitting and reporting of volumes withdrawn and passby flow, however, fall under the Susquehanna River Basin Commission, the Delaware River Basin Commission or another particular river basin, depending on the location of the well.

Like water sourcing, water disposal is an issue that regulators and river authorities are managing carefully to protect surface and groundwater resources. Several options for managing produced water include underground injection (discussed in the subsequent groundwater protection section), water treatment and reuse or recycle.

57 “Understanding Hydraulic Fracturing”, Canadian Society for Unconventional Gas (CSUG), January 2011, pp. 18. 58 ibid 59 ibid 60 “Understanding Hydraulic Fracturing”, Canadian Society for Unconventional Gas (CSUG), January 2011, pp. 18. 61 ibid 62 Modern Shale Gas Development in the United States: A Primer, US Department of Energy, Office of Fossil Energy and the National Energy Technology Laboratory, April 2009, pp. 65. 63 ibid 64 Kelly Carmichael, “Shale Gas Environmental & Regulatory Issues”, Presentation at the Ohio Gas Association, July 27, 2010, pp. 13.

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While underground injection is commonly employed in the oil and gas industry, produced water may also be managed effectively by water treatment or reuse/recycling.65 The best disposal option depends on the shale play and the location of well site. For example, while the operators in the Barnett Shale reuses/recycles produced water or practices underground water injection, operators in the Marcellus Shale treat produced water and are in the process of evaluating the idea of reuse and recycling.66 Options for underground water injection are limited in the Marcellus Shale.67

Water treatment is particularly valuable where municipal or commercial treatment facilities are available. Likewise, operators are strongly considering water treatment and reuse/recycle options, but are often limited by frac fluid requirements and scale producing sulfates.68

Groundwater Protection Arguably, frac’ing’s most controversial issue is whether potable water aquifers are at risk of being contaminated. This issue is echoed in town hall meetings and the media alike. This section discusses groundwater protection and contamination from the perspective of the drilling itself and the process of frac’ing.

As defined by Alberta Environment, groundwater is water that is beneath the surface, its upper limit defined by the water table.69 Currently, water is considered too saline, and unsuitable for human consumption, if the total dissolved solids (TDS) exceeds 4,000 mg/L.70 It is important to note that surface water is different than groundwater, and is primarily comprised of water in rivers, streams and lakes. In the United States and Canada, federal and state/provincial regulators place great emphasis on protecting surface water and groundwater—not only in regard to shale gas development and production but to the oil and gas industry as a whole.

While well construction practices across North America, in every state or provincial jurisdiction, are not standardized, all wells in North America have strict guidelines that protect groundwater and potable water sources.71 Differences in standards often reflect differences in geology and topography. Multiple layers of protective steel casing and cementing are an important part of well construction, whether to produce oil or gas, whether vertical or horizontal. They are specifically designed to protect fresh water aquifers and to isolate the producing zone from overlying formations. Shale gas wells are fundamentally no different from their conventional counterparts.

Figure 1.6 illustrates groundwater protection regulations regarding drilling and completion activities.

65 Modern Shale Gas Development in the United States: A Primer, US Department of Energy, Office of Fossil Energy and the National Energy Technology Laboratory, April 2009, pp. 68. 66 Arthur, J. Daniel and Jon W. Seekins, “Water and Shale Gas Development”, ALL Consulting, Presentation at the National Association of Royalty Owners, Pittsburgh, October 7, 2010, pp. 30. 67 ibid 68 Arthur, J. Daniel and Jon W. Seekins, “Water and Shale Gas Development”, ALL Consulting, Presentation at the National Association of Royalty Owners, Pittsburgh, October 7, 2010, pp. 33. 69 http://environment.alberta.ca/03137.html (accessed on January 21, 2011) 70 Michael Bevan, “ERCB and Groundwater Protection”, Presentation at SEAWA – Below you Watershed: Understanding the Groundwater Connection Conference, March 12, 2010, pp. 4. 71 API, Hydraulic Fracturing at a Glance, 2008.

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Figure 1.6 Groundwater Protection and Drilling and Completions

Conductor Pipe

Surface Casing

Cement

BGWP

Production Casing

Cement

Perforations

Source: ERCB72

Base of Groundwater Protection (BGWP) refers to the approximate depth at which groundwater changes from non-saline to saline.73 The BGWP is managed by the ERCB. Requirements for any work above the BGWP are more demanding. As Figure 1.6 illustrates, to protect the groundwater, multiple layers of protective steel casing and cementing are required by strict regulation. Along with the production casing, surface casing is required.

In Canada and the US the surface casing must extend 25 meters below the lowest water well or groundwater level with a minimum depth of 100 meters. The casing must be cemented into place by pushing cement from the bottom to the top to eliminate the possibility of contamination of groundwater. In addition, the well production casing, which extends from the surface to the bottom of the well, must also be cemented into place. Canada requires the total length of the casing to be cemented, greatly reducing the risk of groundwater contamination.

The following are two ERCB directives that address groundwater protection during drilling and completion:

• Directive 036 states that oil-based drilling fluids, or any other toxic additive, are prohibited when drilling above the BGWP.74

72 Michael Bevan, “ERCB and Groundwater Protection”, Presentation at SEAWA – Below you Watershed: Understanding the Groundwater Connection Conference, March 12, 2010, pp. 7. 73 Michael Bevan, “ERCB and Groundwater Protection”, Presentation at SEAWA – Below you Watershed: Understanding the Groundwater Connection Conference, March 12, 2010, pp. 3. 74 Michael Bevan, “ERCB and Groundwater Protection”, Presentation at SEAWA – Below you Watershed: Understanding the Groundwater Connection Conference, March 12, 2010, pp. 9.

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• Directive 009 states that surface casing must be cemented to surface (as illustrated in Figure 1.6).75 In addition if the surface casing does not extend below the BGWP, the next casing string must be cemented to surface.76

British Columbia’s Water Act includes stringent regulations regarding the protection of groundwater, from surface sealing, to abandonment and to the flood proofing of wells.77

In Texas, the area is cemented from the hole depth to 600 feet above the production zone–with part of the well filled with drilling fluid or diesel. Within the production casing a separate production string is used to produce fluids. This string extends from the surface to the production zone and passes through rubber isolation plugs that seal the zone from contaminating other zones. Deep wells sometimes have intermediate casing as well as a production casing, and some wells do not have a production string (shallow wells). However, in all cases the well design fits the depth and risk associated with the well drilling.

While frac’ing is a new term to many, the reality is that it is not a new technology. It was first used by Stanolind Oil in 1949 and it is estimated that 2.5 million frac operations have been completed globally since.78 Historically, however, frac fluids were intended to break open channels in the rock and flush out or dissolve the broken rock so as to leave an open fracture for the gas to flow to the well bore. In some cases, sand (or other propping agents) are injected into the formation to hold open the channels. The technology has evolved dramatically and frac’ing now plays a major role in the development of unconventional oil and gas resources.79

Figure 1.7 illustrates a typical horizontal and multi-stage frac well. The graphic illustrates how the steel casing and cement protects the groundwater from contamination. It is important to note the depth involved, in addition to the fact that the process of frac’ing is occurring within multiple layers of casing and cement. Most fracs are performed at depths greater than 7,000 ft., which is nearly 6 Empire State buildings end over end, and 6,000-7,000 feet below fresh water aquifers.80

75 Michael Bevan, “ERCB and Groundwater Protection”, Presentation at SEAWA – Below you Watershed: Understanding the Groundwater Connection Conference, March 12, 2010, pp. 10. 76 ibid 77 http://www.bclaws.ca/EPLibraries/bclaws_new/document/ID/freeside/11_299_2004#part2 (accessed on January 20, 2011) 78 Montgomery, Carl T. and Michael B. Smith, Hydraulic Fracturing: History of an Enduring Technology, JPT, December 2010, pp. 27. 79 IOGCC website, http://www.iogcc.state.ok.us/hydraulic-fracturing (accessed on January 20, 2011) 80 http://www.hydraulicfracturing.com/Process/Pages/information.aspx (accessed on January 21, 2011)

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Figure 1.7 A Typical Horizontal Well and Multi-stage Frac

Source: http://www.hydraulicfracturing.com/Process/Pages/information.aspx

A joint American Petroleum Institute (API) and Department of Energy (DOE) study in the 1980s determined that the likelihood of corrosion or an injectate polluting an underground source of drinking water (USDW) ranged from 2x10-5 to 2x10-8.81 In 2004 the EPA conducted a similar study of the environmental risks of frac’ing in CBM wells. 82 In fact, of the thousands of wells frac’ed annually, not a single case of drinking water contamination occurred;83 results were verified by the IOGCC member states.84

The SDWA also established a framework for the Underground Injection Control (UIC) program.85 The EPA and the states regulate the UIC, which started in 1974. The UIC regulates injection wells and manages liquid wastes.86 The oil and gas industry is a part of the regulatory framework. It is important to note that there are different types, or classifications, of injection wells: industrial and municipal waste disposal wells (Class I), oil and gas related wells (Class II), mining wells (Class III), shallow hazardous and radioactive injection wells (Class IV), shallow non-

81 Modern Shale Gas Development in the United States: A Primer, US Department of Energy, Office of Fossil Energy and the National Energy Technology Laboratory, April 2009, pp. 53. 82 http://www.iogcc.state.ok.us/hydraulic-fracturing (accessed on January 21, 2011) 83 ibid 84 ibid 85 Regulatory Framework Fact Sheet, July 2010. http://www.chk.com/Media/CorpMediaKits/Regulatory_Framework_Fact_Sheet.pdf 86 API, Hydraulic Fracturing at a Glance, 2008.

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hazardous injection wells (Class V) and geologic sequestration wells (Class VI).87 Frac’ing, however, is exempt from the SDWA with the ratification of the Energy Policy Act of 2005.

The FRAC Act, introduced by Democratic members of the US Congress, amends the SDWA. The legislation would force companies to disclose frac fluids used in particular frac’ing operations. In addition, the EPA is studying frac’ing and its potential impacts on drinking water and the environment;88 the study is scheduled to be completed by late 2012.89

Another environmental concern regarding frac’ing is the possibility of accidental spills when the frac fluids are recovered from the well. There is, however, an extensive set of regulations at the federal and state/provincial levels in North America. In Alberta, there are five ERCB directives that address groundwater protection during production, fluid handling and waste disposal.

• Directive 044 requires surveillance, sampling and analysis of water produced in oil and gas wells completed above the BGWP.90

• Directive 027 requires that frac’ing above the BGWP must use non-toxic frac fluids; in addition frac’ing is not permitted within 200m of a water well.91

• Directive 036 requires that all fluids used or generated must be properly contained, and any spill over 2m3 must be reported immediately to the ERCB.92 The latter is part of the release notification requirements (IL 98-1).93 It is also important to note that Alberta Transportation is responsible for the transport of chemicals into the wells sites.

• Directive 050 governs the handling of drilling waste.

• Directive 051 provides guidelines regarding injection and disposal wells.94 It requires annual testing to illustrate well integrity and that fluids be injected through tubing to provide another layer of protection for groundwater.95

87EPA website, http://water.epa.gov/type/groundwater/uic/index.cfm (accessed on January 23, 2010) 88 EPA website, http://water.epa.gov/type/groundwater/uic/class2/hydraulicfracturing/index.cfm (accessed on January 23, 2010) 89 ibid 90 ERCB, Directive 044, Requirements for the Surveillance, Sampling, and Analysis of Water Production in Oil and Gas Wells Completed Above the Base of Groundwater Protection (BGWP), October 31, 2006. 91 Michael Bevan, “ERCB and Groundwater Protection”, Presentation at SEAWA – Below you Watershed: Understanding the Groundwater Connection Conference, March 12, 2010, pp. 11. 92 Michael Bevan, “ERCB and Groundwater Protection”, Presentation at SEAWA – Below you Watershed: Understanding the Groundwater Connection Conference, March 12, 2010, pp. 18. 93 Michael Bevan, “ERCB and Groundwater Protection”, Presentation at SEAWA – Below you Watershed: Understanding the Groundwater Connection Conference, March 12, 2010, pp. 20. 94 Michael Bevan, “ERCB and Groundwater Protection”, Presentation at SEAWA – Below you Watershed: Understanding the Groundwater Connection Conference, March 12, 2010, pp. 22. 95 ibid

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In the US, there is an extensive set of regulations at the federal and state levels regarding frac’ing and the possibility of accidental spills when the frac fluids are recovered from the well and could contaminate surface water. The CWA regulates surface discharge of water associated with the oil and gas industry.96 This is done through the National Pollutant Discharge Elimination System (NPDES) permitting process, which sets limits on what material is being discharged, as well as providing monitoring and reporting.97 The program is authorized by the CWA and the EPA, but can be altered at state and local levels.98 In addition, the oil and gas industry must comply with the Resource Conservation and Recovery Act (RCRA). The RCRA regulates the impacts to land from shale gas development, including solid waste disposal and surface disturbance.99 As a result there are specific guidelines that must be adhered to with regard to produced frac fluids and other wastes. States administer the RCRA and have jurisdiction for treatment and disposal issues.100

Figure 1.8 illustrates a typical frac’ing operation in the Barnett Shale in Texas. Frac tanks filled with stimulation fluid and sand circle the project. Within the enclosed area are the wellhead, frac pumps and frac blenders. The process is well developed and closely monitored.

Figure 1.8 A Typical Frac’ing Operation in East Texas

Source: Bureau of Economic Geology101

96 Modern Shale Gas Development in the United States: A Primer, US Department of Energy, Office of Fossil Energy and the National Energy Technology Laboratory, April 2009, pp. 29. 97 http://cfpub.epa.gov/npdes/writermanual.cfm?program_id=45 (accessed on January 23, 2011) 98 Modern Shale Gas Development in the United States: A Primer, US Department of Energy, Office of Fossil Energy and the National Energy Technology Laboratory, April 2009, pp. 29. 99 Modern Shale Gas Development in the United States: A Primer, US Department of Energy, Office of Fossil Energy and the National Energy Technology Laboratory, April 2009, pp. 37. 100 “US Shale Gas Regulatory Overview Focus: Marcellus and Haynesville”, SPE S&E Luncheon, May 18, 2010, http://www.spegcs.org/attachments/studygroups/12/SPE%20Fracking%20Challenges%20%5BRead-Only%5D.pdf (accessed on January 26, 2011) 101 Ian Duncan, “Shale Gas: Energy and Environmental Issues”, Gulf Coast Carbon Center, Bureau of Economic Geology, pp. 7.

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Surface Land Use & Impacts Surface land use and impacts are obviously the most visible of the environmental concerns. As previously mentioned, both vertical and horizontal drilling are used to develop shale gas; the latter is far more common.

Horizontal drilling, which has been around since the 1930s, lowers the surface disturbance and land use dramatically.102 While horizontal wells expose the wellbore to a greater part of the reservoir, they also reduce surface disturbance. Development of a section (one square mile) could require 16 vertical wells, each situated on their own well pad.103 However, as many as 20 horizontal wells could be drilled from a single well pad using horizontal drilling.104 In the Barnett Shale, drillers are planning to drill up to 24 wells from a single well pad.

Figure 1.9 illustrates eight horizontal wells drilled from a single pad.

Figure 1.9 Multiple Horizontal Wells Drilled from a Single Well Pad

Source: NEB105

In addition to greatly reducing surface disturbance, the reduction of the number of well pads will certainly result in the overall number of access roads, pipeline routes and production facilities.106 The smaller environmental

102 Modern Shale Gas Development in the United States: A Primer, US Department of Energy, Office of Fossil Energy and the National Energy Technology Laboratory, April 2009, pp. 46. 103 Modern Shale Gas Development in the United States: A Primer, US Department of Energy, Office of Fossil Energy and the National Energy Technology Laboratory, April 2009, pp. 47. 104 ibid 105 “Shale Gas 101: The rocks and their potential impact on Canadian natural gas delivery”, pp. 11.

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footprint will also result in the reduction of wildlife, and community impacts greatly reduce the surface area in more densely populated areas.107 This is certainly the case of the development of the Barnett Shale near the Dallas-Ft. Worth International Airport where horizontal drilling helps overcome the challenges of drilling in the highly-sensitive, densely-populated urban area.108 The pad can also be serviced by a single access road and pipeline.109

Figure 1.10 illustrates the potential land use impact of drilling vertical wells versus multiple horizontal wells from a single well pad. The following demonstrates a vertical well development with 32 wells on a two-square-mile area illustrated on the left) and utilizing horizontal wells drilled from a single well pad, also on a two-square-mile area.110 While the single well pad is larger in size compared to its vertical counterpart, Chesapeake estimates up to a 90 percent reduction in overall surface presence.111

Figure 1.10 Vertical Drilling Versus Multiple Horizontal Wells Drilled from a Single Well Pad

Source: Chesapeake Energy112

106 Modern Shale Gas Development in the United States: A Primer, US Department of Energy, Office of Fossil Energy and the National Energy Technology Laboratory, April 2009, pp. 47. 107 ibid 108 Modern Shale Gas Development in the United States: A Primer, US Department of Energy, Office of Fossil Energy and the National Energy Technology Laboratory, April 2009, pp. 49. 109 http://www.askchesapeake.com/MARCELLUS-SHALE/NY/DRILLING/Pages/information.aspx (accessed on January 27, 2011) 110 ibid 111 ibid 112 ibid

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Report Structure There are nearly 60 shale gas plays that have spurred interest in North America. While it is not realistic to review every play, this study will review as many as possible. This report is divided into three chapters, and will divide all the shale plays into two categories: established and emerging/exploratory.

Chapter 1 discusses the purpose and provides a background for the study, as well as provides a structure of the report.

Chapter 2 discusses established shale plays in North America. All shale plays are commercially producing and are, or have been, at various stages of production. This chapter is divided into eight sections: the Antrim Shale, the Barnett Shale, the Devonian/Ohio Shales, the Fayetteville Shale, the Haynesville Shale, the Marcellus Shale, the New Albany Shale and the Woodford Shale. Each shale play is divided into four sections: geology and basin metrics, E&P players and recent M&A activity, development outlook and drilling forecasts (where available), and additional information. It is important to note that the Barnett Shale, the Fayetteville Shale, the Haynesville Shale, the Marcellus Shale and the Woodford Shale are often regarded as the big five shale plays in terms of prospects, and are periodically referred to as the big five in this study.

Chapter 3 discusses emerging and exploratory shale plays in North America. All shale plays are considered developing or emerging and exploratory. This chapter is divided into seven sections: the Eagle Ford (inc. Pearsall) Shale, the Floyd-Neal Shale, the Hilliard-Baxter Shale, the Montney Shale and the Muskwa/Ootla (Horn River Basin) Shale, the Utica Shale and Other Shale Plays. Each shale play is divided into four sections: geology and basin metrics, E&P players and recent M&A activity, development outlook and drilling forecasts (where available), and additional information. Unlike the previous sections that are divided into four sections, the other shale gas plays section only discusses the geology and basin metrics of the particular shale gas play. The five shale gas plays discussed in this section are the Barnett-Woodford Shale, the Chattanooga Shale, the Gothic-Hovenweep Shales, the Mancos Shale and the Pierre Shale.

Appendix A illustrates a list of the frac fluid additives and their various roles in frac’ing, as well as their common uses.

Appendix B provides a complete list of all shale gas plays in North America, their geological age and their locations. It is important to note that several of the listed shale plays are better known for their oil shale potential. They are divided into Canadian shales and US shales, and are listed alphabetically.

February 2011 North American Natural Gas Dynamics: 23 Shale Gas Plays in North America – A Review Chapter 2 Established Shale Plays

This chapter discusses established shale plays in North America. All shale plays are commercially producing and are considered established. This chapter is divided into eight sections: the Antrim Shale, the Barnett Shale, the Devonian/Ohio Shales, the Fayetteville Shale, the Haynesville Shale, the Marcellus Shale, the New Albany Shale and the Woodford Shale. Each shale play is divided into four sections: geology and basin metrics, E&P players and recent M&A activity, development outlook and drilling forecasts, and additional information. They are listed in alphabetical order.

The Antrim Shale, Michigan

Geology and Basin Metrics The vast majority of the Antrim Shale is located in the state of Michigan, however, the southern portion stems into neighbouring Indiana and Ohio. The Antrim Shale is roughly 39,000 square miles.113 The Upper Devonian-aged shale is situated within the . Both the Michigan Basin and the Antrim—which derives its name from a producing country in Michigan—are nearly circular in shape. Figure 2.1 illustrates the Antrim Shale. Currently, most of the drilling activity is in the northern rim of the Antrim, towards the Great Lakes. The Antrim Shale is in large part correlative with the New Albany Shale, discussed later in this chapter, located in Illinois, southern Indiana and western Kentucky.114 Figure 2.1 Antrim Shale Map

Source: http://www.haynesvilleplay.com

113 oilshalegas.com/antrimshale.html (accessed on September 23, 2010) 114 Indiana Geological Survey, Antrim Shale, http://igs.indiana.edu/geology/structure/compendium/ html/comp82hw.cfm (accessed on September 23, 2010)

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While not categorized as one of the US’s big five—Woodford, Haynesville, Fayetteville, Marcellus and Barnett—the Antrim is a commercially producing shale.115 In fact, the play was identified in 1901 and began producing in the early 1940s.116 However, it was not until the 1980s when the play gained widespread attention. Advancements in drilling technology in the 1970s and 1980s made the Antrim an attractive drilling destination and by the 1990s, the Antrim Shale was the most active shale play in the US, with thousands of wells drilled. By 2006 the Antrim produced more than 2.5 Tcf from more than 9,000 wells.117 The depths of the wells are generally 150 to 1,500 ft. 118 In 2007, the Antrim gas field produced 136 Bcf of gas.119 It is important to note that the gas is biogenic in nature, meaning that it was generated by bacteria in the organic-rich rock.

The US’s Geological Survey National Assessment estimates that approximately 7 Tcf is technically recoverable in the Antrim Shale. This is considerably less than other shale plays, such as the New Albany Shale, which ranges between 86-160 Tcf.120 However, more recent estimates of the Antrim, provided by the GTI, suggests that possible gas reserves range between 35 to 76 Tcf.121

The New Albany Shale is a brown to black, organically-rich shale similar to the Marcellus and the New Albany, but may also contain pyrite, as well as thin limestones and sandstones in places.122

Table 2.1 provides a summary of Antrim’s key geological characteristics.

Table 2.1 Antrim Geological Characteristics Parameter Antrim Shale Geological age Upper Devonian Depth range (ft) 600-2,200 Shale thickness (ft), gross 160 GIP/sq mi (Bcf) 6-15 Porosity (%) 9 Total organic carbon (%) 1.0-20.0 Thermal maturity (Ro) 0.4-0.6 Silica content (%) n/a Pressure gradient (psi/ft) 0.35 Source: Deutsche Bank, 2008.123

The Antrim Shale lies at depths of 600-2,200 ft., comparable to the New Albany Shale at depths range of 1,000- 4,500 ft. In terms of thickness and porosity, the Antrim Shale averages 160 ft. and 9 percent, respectively. The

115 “From Shale to Shining Shale”, Deutsche Bank, July 22, 2008, pp. 9. 116 Indiana Geological Survey, Antrim Shale, http://igs.indiana.edu/Geology/structure/compendium/ html/comp3n6s.cfm (accessed on September 23, 2010) 117 “Michigan’s Antrim Gas Shale Play – A Two-Decade Template for Successful Devonian Gas Shale Development”, Wayne Goodman and Timothy Maness, September 25, 2008, pp.1. 118 oilshalegas.com/antrimshale.html (accessed on September 24, 2010) 119 ibid 120 oilshalegas.com/antrimshale.html (accessed on September 24, 2010) 121 http://www.energyindustryphotos.com/new_albany_shale.htm (accessed on September 24, 2010) 122 ibid 123 “From Shale to Shining Shale”, Deutsche Bank, July 22, 2008, pp. 30.

February 2011 North American Natural Gas Dynamics: 25 Shale Gas Plays in North America – A Review

Antrim Shale has a total organic carbon (TOC) content of 1 to 20 percent and has a thermal maturity of 0.4 to 0.6. The pressure gradient for the Antrim Shale is 0.35 psi/ft. Several similarities exist with the New Albany Shale, especially in terms of thickness (100-300 ft.), porosity (9 percent), total organic content (1.0-25.0), thermal maturity (0.4-1.0) and pressure gradient (0.35).

Table 2.2 provides the basin metrics for the Antrim Shale.

Table 2.2 Basin Metrics for the Antrim Shale Parameter Antrim Shale Well Cost ($MM) 0.3-0.5 Depth (ft) 600-2,200 IP Rate (MMCFPD) 0.04-0.3 EUR/Well (BCFE) 0.2-1.2 Threshold Price ($/MCFE) n/a F&D Cost ($/MCFE) 0.70 Expected Recovery Factor (%) 20-60 Lateral lengths (ft) n/a Fracturing stages n/a Typical Well Spacing (acres/well) 40-60 Source: Simmons & Co., Various company Reports.124

E&P Players and Recent M&A Activity As mentioned previously, most of the drilling activity is occurring in northern Michigan. This is illustrated in Figure 2.2; drilling activity is indicated by the blue colour. More specifically, Antrim, Ostego and Montmorency are attracting attention.125 Kalkaska, Crawford and Oscoda Counties are attracting attention as well, albeit to a lesser extent.126

124 ibid 125 oilshalegas.com/antrimshale.html (accessed on September 24, 2010) 126 ibid

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Figure 2.2 Map of Michigan’s Drilling Activity

Source: www.energyindustryphotos.com

At the beginning of 2008, the Antrim had over 700 active projects and over thirty operators in the play.127 However, the top five operators produce over 50 percent of the gas.128

There are three major players in the Antrim Shale: Atlas Energy, Whiting Petroleum Corp. and BreitBurn Energy Partners (BBEP). The following will discuss these players. Interestingly, two of the three are also heavily involved in the New Albany Shale, discussed later in this chapter.

Atlas is the largest oil and gas producer in the Antrim Shale. Daily net production at 4Q2009 was 57 MMcfpd. Most of Atlas Energy’s 270,000 net acres of land holdings within the Antrim are in the heart of the drilling core, in northern Michigan.129 The company is utilizing horizontal drilling on their acreage, which has resulted in the company opening up new areas to development. They operate over 2,400 producing wells.130 The company suggests that it has another 700 future drilling locations planned.131 In addition, Atlas estimates that their costs of production are approximately 30 percent lower than their nearest rivals in the Antrim Shale.132

Atlas is also an active producer in the Marcellus Shale of western Pennsylvania, the Chattanooga Shale of northeastern and the New Albany Shale.133

127 “Michigan’s Antrim Gas Shale Play – A Two-Decade Template for Successful Devonian Gas Shale Development”, Wayne Goodman and Timothy Maness, September 25, 2008, pp. 41. 128 ibid 129 Atlas Energy website, http://www.atlasenergyresources.com/operations/michigan.aspx (accessed on September 24, 2010) 130 ibid 131 ibid 132 oilshalegas.com/antrimshale.html (accessed on September 24, 2010) 133 http://www.energyindustryphotos.com/new_albany_shale.htm (accessed on September 24, 2010)

February 2011 North American Natural Gas Dynamics: 27 Shale Gas Plays in North America – A Review

The second major player in the Antrim is Whiting Petroleum. Their Michigan assets produced 2.4 millions of barrels of oil (MMbbl) and 30.0 Bcf of gas at the end of 4Q2009.134 Total MMBoe at the end of 4Q2009 was 7.4; by 2Q2010, 2.8 MMBoe was produced in the Antrim Shale.135 As of 4Q2009, the company estimates proved reserves of 7.4 MMBoe on their acreage in the Antrim Shale. The company holds 14,700 net acres in the Antrim, mostly in the Missauke, Clare and Oceola Counties.136

Whiting plans to invest US$35 million into E&P activities in the Antrim in 2010.137

The Denver-based oil and gas producer also has major operations in the Williston Basin (North Dakota Bakken), Basin (West Texas), Rocky Mountains (Colorado) and the Mid-Continent (Oklahoma Panhandle). At 123.3 MMBoe, the Permian Basin is their most productive asset.138

BBEP is quickly becoming a major player in the Antrim and the New Albany Shales. The company’s New Albany and Antrim properties stem from an acquisition with Quicksilver Resources, which included natural gas and midstream assets located in Michigan, Indiana and Kentucky. The deal, completed on November 2007, was financed with US$750 million cash and 21.348 million BreitBurn Common Units.139 In addition, BBEP acquired integrated midstream assets in the New Albany and Antrim shales.140

Of the total estimated 548 Bcfe of proved reserves in the two shale plays, 523 Bcfe are estimated in the Antrim Shale.141 BBEP currently holds over 268,000 net acres in the Antrim Shale, with an estimated proved reserves of 23 Bcfe. Net daily production in 3Q2007 was approximately 68 MMcfpd with over 5,000 gross producing wells.142 The company also cites a potential for over 800 recompletions and over 2,000 potential drilling locations.143 Net daily average production in 4Q2009 was 10,414 Boepd and reserves are estimated to be 76.2 MMBoe according to a company presentation in September 2010.144

Development Outlook & Drilling Forecasts Recall that in the 1990s, the Antrim Shale was the most actively drilled shale play in the US. That prestige now goes to East Texas’s Barnett Shale. Production peaked in the Antrim Shale in 1998 at 546 MMcfpd.145 And while the most attractive area in the northern Michigan is either largely developed or being developed, the shale play still has a lot to offer.

134 ibid 135 ibid 136 oilshalegas.com/antrimshale.html (accessed on September 24, 2010) 137 Whiting Petroleum website, http://www.whiting.com/download/GENERAL_CORPORATE_INFORMATION.pdf (accessed on September 24, 2010) 138 Whiting Petroleum website, http://www.whiting.com/corporate/reserves.asp (accessed on September 24, 2010) 139 BreitBurn Energy Partners, Credit Suisse Energy Summit, February 2008, pp. 9. 140 ibid 141 BreitBurn Energy Partners, Credit Suisse Energy Summit, February 2008, pp. 10. 142 ibid 143 ibid 144 BreitBurn Energy Partners, UBS MLP, One-on-One Conference, Las Vegas, September 2010, pp. 3. 145 “Michigan’s Antrim Gas Shale Play – A Two-Decade Template for Successful Devonian Gas Shale Development”, Wayne Goodman and Timothy Maness, September 25, 2008, pp. 42.

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Technological advances and increasing drilling efficiencies appear to be offsetting lower gas prices, and will likely factor in the future development of the Antrim Shale. Industry pundits suggest that there is potential in optimizing existing wells, including re-fracs, minimizing back pressure, high angle and HD wells and utilizing twin wells in the Upper Antrim.146 In addition, the southwestern and southeastern parts of the Antrim have been largely untapped, as well as the Deep Basin Antrim.147 The latter is anticipated to have a high potential TOC.148

According to a Penn Energy study, the North American natural gas industry is expected to grow steadily, with an AAGR of 1.2 percent, during the 2008-20 period.149 The unconventional natural gas will play an increasingly important role, increasing from 6 Bcfpd in 2008 to 19.3 Bcfpd in 2020 (shale gas is estimated to account for approximately 52 percent of the total production by 2020).150 The study suggests that activity in the following plays will surge: Barnett, Antrim, Haynesville, Fayetteville, Woodford and Marcellus.151

In addition to the expected increase in drilling activity and production in the Antrim Shale, Michigan’s Collingwood- Utica Shale is also attracting a lot of attention. While the economic feasibility is not yet known, the new and deeper shale play attracted US$178 million in a land sale on May 4, 2010.152 EnCana’s pioneer well in Missaukee County had an initial production of approximately 2.5 MMcfpd.153

Additional Information Until January 2011, Michigan’s Department of Natural Resources and Environment (DNRE) regulated the development and use of land, energy, forestry and mineral resources in the state.154 Within its oil and gas division, the DNRE regulated drilling, completion, production, pipeline transport and all environmental aspects. With Executive Order 20110-01, Governor Snyder, however, eliminated the DNRE and replaced it with the Department of Natural Resources and the Department of Environmental Quality.155

146 “Michigan’s Antrim Gas Shale Play – A Two-Decade Template for Successful Devonian Gas Shale Development”, Wayne Goodman and Timothy Maness, September 25, 2008, pp. 65. 147 “Michigan’s Antrim Gas Shale Play – A Two-Decade Template for Successful Devonian Gas Shale Development”, Wayne Goodman and Timothy Maness, September 25, 2008, pp. 66. 148 ibid 149 North America Unconventional Gas Industry - Set to Regain Momentum Post Current Crisis - new market report published, May 14, 2010, http://www.pr-inside.com/north-america-unconventional-gas-industry-r1892947.htm (accessed on September 24, 2010) 150 ibid 151 ibid 152 “Say Hello To The Collingwood Shale”, May 18, 2010, http://stocks.investopedia.com/stock-analysis/2010/say- hello-to-the-collingwood-shale-atls-eca-bbep-kwk0518.aspx (accessed on September 24, 2010) 153 ibid 154 Michigan’s Department of Natural Resources and Environment website, http://www.michigan.gov/dnre (accessed on September 24, 2010) 155 Department of Natural Resources and Environmental website, http://www.michigan.gov/deq#blank (accessed on January 30, 2011)

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The Barnett Shale, Texas

Geology and Basin Metrics The Barnett Shale is located in East Texas and predominantly underlies the city of Dallas-Fort Worth and the surrounding two dozen counties. While not the oldest shale play in the US, it is certainly the most prolific and well known. The success of the Barnett spurred E&Ps across North America to explore other shale plays on the continent. With 13,740 gas wells, the Barnett Shale is the largest gas field in Texas.156 While gas is being produced in 23 counties, much of the drilling activity is occurring in 15 counties consisting of Newark East Field, Core, Tier 1 and Tier 2.157 Figure 2.3 illustrates these areas of the Barnett Shale. The figure also illustrates areas that produce oil, condensate gas and dry gas.

Figure 2.3 Barnett Shale Map

Source: http://www.shalewiki.org158

While oil and gas was first produced in 1910 in the area, it was only in 1981 that gas was produced with significant volume.159 With the technological advances in drilling, such as hydraulic frac’ing and horizontal drilling, it was twenty years later that shale gas production really began to increase.160 This ushered a new era for the Barnett Shale and for shale gas plays in North America. The Newark Gas Field is the heart of the Barnett and marks the

156 “Gas Shale Market Report and Five-Year Forecast 2010”, Warlick International, pp. 28. 157 ibid 158 http://www.shalewiki.org/index.php?n=BarnettShale.OtherShales. 159 “Gas Shale Market Report and Five-Year Forecast 2010”, Warlick International, pp. 28. 160 ibid

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location of where the first drilling took place. The Core area is located in the counties of Denton, Tarrant and Wise. Tier 1 includes three counties while Tier 2 includes nine counties.

The Barnett holds an estimated 2.5 Tcf of recoverable gas.161 Some geologists, however, estimate that the technically recoverable gas could be much larger, between about 7 and 20 Tcf—possibly higher by other estimates.162 This is similar to the Fayetteville Shale, which is estimated to contain 20 Tcf of recoverable gas. 163 Recall the GIP estimates for the Marcellus and Haynesville Shales, the latter also in Texas, are potentially much higher.

Table 2.3 provides a summary of Barnett’s key geological characteristics. It is divided into two profiles to better illustrate the different geological characteristics between the Core/Tier 1 (including Johnson City) and the South/Western Counties.

Table 2.3 Barnett Shale Geological Characteristics Parameter Core/Tier 1 South/Western Geological age Mississippian Depth range (ft) 6,500-9,000 6,500-9,000 Shale thickness (ft), gross 200-1000 100-250 GIP/sq mi (Bcf) 100-500 50-125 Porosity (%) 4.0-6.0 3.0-4.8 Total organic carbon (%) 3.5-8.0 3.5-5.0 Thermal maturity (Ro) 2.2 2.2 Silica content (%) 40-60 n/a Pressure gradient (psi/ft) 0.46-0.52 0.46-0.52 Source: Deutsche Bank, 2008.164

The Barnett Shale is black, organic-rich shale located in the Bend Arch-Fort Worth Basin.165 The late Mississippian- aged Barnett Shale lies at a depth range of 6,500-9,000 ft., which is shallow compared to the 10,500-13,500 ft. of the Haynesville Shale or 7,800-13,300 ft. of British Columbia’s Horn River Shale. The thick shale has an attractive permeability and porosity.166 In terms of thickness and porosity, the Barnett Shale (Core/Tier 1) is 200-1,000 ft. and 4.0-6.0 percent, respectively. This part of the Barnett Shale is moderate in silica content (40-60 percent) and has a TOC content of 3.5-8.0 percent. The pressure gradient is between 0.46 and 0.52 psi/ft. In terms of thickness and porosity, the Barnett Shale (South/Western) is 100-250 ft. and 3.0-4.8 percent, respectively. This part of the Barnett Shale has a TOC content of 3.5-5.0 percent. The pressure gradient and thermal maturity are identical between the two profiles.

161 Bowker, K.A., 2003, Recent developments of the Barnett Shale play, Fort Worth Basin: West Texas Geological Society Bulletin, v. 42, no. 6, pp. 4-11. 162 Kuskraa, V.A., Koperna, G., Schmoker, J.W., and Quinn, J.C., 1998, Barnett Shale rising star in Fort Worth Basin: Oil and Gas Journal, v. 96, no. 21, p. 71-76. 163 Edt Peggy Williams, “The Arkoma Shales”, UGcenter Arkoma Playbook, April 2009, pp 5. 164 “From Shale to Shining Shale”, Deutsche Bank, July 22, 2008, pp. 30. 165 http://www.oilshalegas.com/barnettshale.html (accessed on August 30, 2010) 166 “Gas Shale Market Report and Five-Year Forecast 2010”, Warlick International, pp. 29.

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Table 2.4 provides the basin metrics for the Barnett Shale. The Core, the most attractive profile, is illustrated below. It is important to note that of the big five US shale plays, the current metrics indicate that the Barnett Shale tends to be relatively shallow depth (7,500 ft.), have relatively high royalty rates at 25 percent and have a threshold gas price at US$4.10 per Mcfe. The latter combined with the lowest well cost (US$2.8) and the lowest F&D cost (US$1.23) makes the economics of the Barnett attractive.

Table 2.4 Basin Metrics for the Barnett Shale Parameter Barnett Shale Well Cost ($MM) 2.8 Depth (ft) 7,500 IP Rate (MMCFD) 2.5 EUR/Well (BCFE) 2.8 Threshold Price ($/MCFE) 4.10 F&D Cost ($/MCFE) 1.23 LOE ($/MCFE) 0.90 Royalty (%) 25 Production Tax (%) 8 Decline – Yr. 1 (%) -65 Decline – Yr. 2 (%) -34 Decline – Yr. 3 (%) -19 Decline – Out Yrs. (%) -6 Source: Simmons & Co., various company reports.

E&P Players and Recent M&A Activity Currently, there are over 246 E&P companies active in the Barnett, including many considered world-class. As previously mentioned the busiest part of the Barnett is the Core, Tier 1 and Tier 2 areas.

Table 2.5 illustrates the top ten producers in the Barnett Shale.167 These ten producers account for approximately 92 percent of total gas production and the top five operators account for 78 percent of total gas production.

167 “Gas Shale Market Report and Five-Year Forecast 2010”, Warlick International, pp. 33.

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Table 2.5 Top Ten Producers in the Barnett Shale Rank Operator Production, Bcf 1 Devon Energy 458.9 2 Chesapeake Energy 334.0 3 XTO Energy Inc. 285.5 4 EOG Resources Inc. 196.9 5 Quicksilver Resources Inc. 102.0 6 EnCana Oil & Gas USA 70.3 7 Range Resources 55.5 8 Burlington Resources Oil & Gas Company 39.1 9 Williams Exploration 39.0 10 Carrizo Oil & Gas Inc. 34.2 Source: Simmons & Co., various company reports.

While not realistic in this study to discuss all ten producers, the following will review briefly the top five operators in the Barnett Shale and their various mergers and acquisitions in the play.

Devon Energy is the most significant player in the Barnett Shale. Devon has history in the Barnett, acquiring the shale gas development pioneer, Mitchell Energy, for US$3.5 billion in 2001. And Devon has not looked back since.

Devon drilled 336 wells in 2009, down considerably from 2008.168 At year end 2009 Devon’s net production exceeded 1.25 Bcfpd while their 1Q2010 net production was 1.1 Bcfpd.169 The Dallas-based Devon, however, expects their 3Q2010 production to break their 4Q2009 record. Devon operated 4,200 wells in the aforementioned quarter and plans to drill 370 wells in 2010.170

Chesapeake, the most important player in the Haynesville Shale and a major player in the Marcellus Shale, is the second largest producer in the Barnett Shale. The organization holds 225,000 net acres in the relatively small Barnett play, mostly located in the Dallas, Ellis, Hill, Johnson, Parker and Tarrant Counties.171 The latter two are considered Barnett’s sweet spot. Before Total E&P USA acquired a 25 percent share of Chesapeake’s holding in the Barnett, the company owned 300,000 net acres in the play.172 In the joint venture, Total E&P USA paid US$800 million cash and an additional US$1.65 billion in drilling carry, or 60 percent carry of future Chesapeake capex for drilling and completion.173 Carrying the existing capacity rights in the Sabine Pass LNG, Total E&P USA enhances its gas value chain position in the US.174

168 “Gas Shale Market Report and Five-Year Forecast 2010”, Warlick International, pp. 34. 169 http://www.oilshalegas.com/barnettshale.html (accessed on August 30, 2010) 170 “Gas Shale Market Report and Five-Year Forecast 2010”, Warlick International, pp. 34. 171 “Gas Shale Market Report and Five-Year Forecast 2010”, Warlick International, pp. 35. 172 “Gas Shale Market Report and Five-Year Forecast 2010”, Warlick International, pp. 31. 173 “Gas Shale Market Report and Five-Year Forecast 2010”, Warlick International, pp. 34. 174 ibid

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Chesapeake currently is the second largest producer in the Barnett, producing 535 MMcfpd in 2Q2010.175 The company’s average daily net production in 4Q2009 was 700 MMcfpd.176 Total E&P’s acquisition accounts for the difference in total gas production. Chesapeake is currently operating 22 rigs, up from 18 rigs in 2Q2009.177

Similar to Total E&P teaming up with Chesapeake, ExxonMobil decided that XTO Energy provided a great position to get into the shale gas game. ExxonMobil is now a significant player in several shale plays, including the Barnett, Fayetteville and Woodford Shales. In December 2009, ExxonMobil announced its intent to acquire XTO Energy. In the US$41 billion deal, ExxonMobil significantly enhanced its natural gas position—XTO was a significant player in various unconventional plays in the US and was the third largest producer in the Barnett at the end of 2009.178 This section only discusses the impacts of the US$41 billion deal on the Barnett.

As illustrated in Table 2.5, gas production at end-2009 was 285.5 Bcf. Currently ExxonMobil/XTO are operating 13 rigs, 11 of which are in the Tier 1.179 This is up from 10 rigs the end of 3Q2009 XTO.180 The company holds approximately 280,000 net acres in the Barnett, including 155,000 net acres in the core area of the Barnett.181

At 400 Bcf, the fourth largest producer in the Barnett is EOG Resources. While ranking fourth in production, EOG ranks first in net acreage. They hold 900,000 net acres, exceeding Devon’s 713,000 net acres.182 EOG is active in the Erath, Hill, Wood and Wise Counties.183 Company forecasts suggest that gas production should be steady at 400 MMcfpd through 2012.184 EOG is also adding to its crude oil production with the Barnett Shale Combo—this is particularly the case in Montague County which is an oily play with sizeable gas potential.185

EOG is reporting an increase in drilling efficiencies. The average drilling costs decreased from US$3.05 million at end-2008 to US$2.34 million in 2010.186 Finding costs have also decreased from US$1.53 per Mcfe to US$1.35 per Mcfe over the same time period.187

EOG is planning to drill over 200 wells during 2010, expanding from 9 rigs at 4Q2009 to 14 rigs by 4Q2010.188

The fifth largest gas producer is Quicksilver Resources. Quicksilver has acreage in Bosque, Denton, Hill, Johnson and Tarrant Counties. The company’s attractive position in the Barnett drew attention from Italian-based Eni. In May of 2009, Eni bought 27.5 percent of Quicksilver’s Alliance Barnett Shale leasehold, which includes 13,000 net

175 http://www.oilshalegas.com/barnettshale.html (accessed on August 30, 2010) 176 “Gas Shale Market Report and Five-Year Forecast 2010”, Warlick International, pp. 31. 177 “Gas Shale Market Report and Five-Year Forecast 2010”, Warlick International, pp. 34. 178 “Gas Shale Market Report and Five-Year Forecast 2010”, Warlick International, pp. 32. 179 http://www.oilshalegas.com/barnettshale.html (accessed on August 30, 2010) 180 “Gas Shale Market Report and Five-Year Forecast 2010”, Warlick International, pp. 35. 181 http://www.oilshalegas.com/barnettshale.html (accessed on August 30, 2010) 182 “Gas Shale Market Report and Five-Year Forecast 2010”, Warlick International, pp. 36. 183 ibid 184 ibid 185 http://www.oilshalegas.com/barnettshale.html (accessed on August 30, 2010) 186 “Gas Shale Market Report and Five-Year Forecast 2010”, Warlick International, pp. 37. 187 ibid 188 ibid

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acres in the heart of the Barnett (Tarrant and Denton Counties).189 The strategic alliance includes only acreage, not Quicksilver’s midstream infrastructure.190 The deal is worth US$280 million.

Quicksilver plans to increase production at least 25 percent in 2010 and to drill in excess of 150 wells.191 And like EOG, Quicksilver is interested in the Barnet Combo play.192 The company also has exploratory interest in British Columbia’s Horn River Basin and Alberta’s Horseshoe Canyon CBM play.

Development Outlook & Drilling Forecasts More than 2,600 wells were drilled in 2008; however, this number plummeted down to 1,550 wells in 2009.193 In spite of lower gas prices, improvements in technology and the use of micro-seismic technology have made the economics of the Barnett attractive for E&P companies. 3D Seismic allows operators to identify and avoid hazards, such as faults and karst features (sinkholes).194 Momentum suggests that operators will ramp up their drilling efforts over the next several years.

As suggested previously, there are five major players that most affect the Barnett Shale. As indicated by various highlights below, all five appear to sustaining or ramping up drilling activity.

• Devon operated 4,200 wells in the aforementioned quarter and plans to drill 370 wells in 2010195

• Chesapeake plans to employ an average of 20 rigs for the remainder of 2010 (drilling 300 net wells)

• EOG forecasts suggest that gas production should be steady at 400 MMcfpd through 2012; company plans to drill over 200 net wells during 2010196

• Quicksilver plans to increase production at least 25 percent in 2010 and to drill in excess of 150 wells197

Figure 2.4 is a drilling forecast for the Barnett Shale for the period 2009-14. The figure illustrates two cases: the high case and low case. Drilling estimates are provided by Warlick International, May 2010.198

189 “Gas Shale Market Report and Five-Year Forecast 2010”, Warlick International, pp. 32. 190 ibid 191 “Gas Shale Market Report and Five-Year Forecast 2010”, Warlick International, pp. 38. 192 ibid 193 “Gas Shale Market Report and Five-Year Forecast 2010”, Warlick International, pp. 29. 194 “Gas Shale Market Report and Five-Year Forecast 2010”, Warlick International, pp. 44. 195 “Gas Shale Market Report and Five-Year Forecast 2010”, Warlick International, pp. 34. 196 ibid 197 “Gas Shale Market Report and Five-Year Forecast 2010”, Warlick International, pp. 38. 198 “Gas Shale Market Report and Five-Year Forecast 2010”, Warlick International, pp. 47.

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Figure 2.4 Drilling Forecast for the Barnett Shale

1800

1700

1600

1500

1400 2009 2010 2011 2012 2013 2014

High Case Low Case

Source: Warlick International, May 2010

Additional Information The Texas Natural Resources Conservation Commission, via the Texas Railroad Commission (TRC), oversees all regulatory and environmental issues with regards to the oil and gas industry.

While the Barnett is a successful play and the largest shale gas field in the US, the Barnett is not without controversy. Much of it is to do with environmental and safety issues of frac’ing and horizontal drilling. Regarding horizontal drilling, as much of the Barnett Shale lies underneath the City of Fort Worth, producers are currently drilling beneath neighborhoods. This is a concern for citizens of the Dallas-Fort Worth Metroplex.

As for hydraulic frac’ing, opponents suggest that the process created water and air quality issues. Wells in the Barnett can require up to 4,000,000 gallons of frac water.199 The water issue is not only the volume of water needed but also for the treatment and disposition of the flowback water.200

The Devonian Shales, Appalachian Basin, Ohio/Kentucky/West Virginia

Geology and Basin Metrics The Devonian Shales are spread across several states, including West Virginia, Kentucky and Ohio. There are various shales in the area that are considered the Devonian Shale and the definition often various across research. In this study the Devonian-aged Shales in the Appalachian Basin include the Rhinestreet Shale, the and the Huron Shale. The Cleveland and the Huron are members of the Ohio Shale and, thus, the Devonian Shales

199 “Gas Shale Market Report and Five-Year Forecast 2010”, Warlick International, pp. 43. 200 ibid

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are also sometimes labeled Devonian (Ohio) Shales or Devonian/Ohio Shales.201 Also located in the enormous Appalachian Basin is the Marcellus Shale and the Utica Shale. The Utica is the deepest and oldest of the three shale plays, while the Devonian/Ohio shales are the shallowest and youngest. The Marcellus Shale is the largest subset of the Appalachian Basin, which is the largest hydrocarbon-bearing basin in the Lower-48. While the Marcellus Shale is discussed later in this chapter, the Utica Shale is discussed in subsequent chapter.

Figure 2.5 illustrates the Devonian Shales and the Marcellus Shale.

Figure 2.5 Map of the Devonian & Marcellus Shales

Source: http://geopetesview.blogspot.com/2009_02_21_archive.html

This section will only discuss the Devonian Shales (Rhinestreet, Cleveland and Huron Shales) located in Ohio, Kentucky and West Virginia. Of these the most active is the Huron Shale. As such this section will focus on the black shales of the basal Huron.202

The Figure above illustrates the Devonian Shales extending as far south as Tennessee and Alabama. However, the Devonian-aged Chattanooga Shale is discussed separately in the subsequent chapter. Like the Marcellus Shale, it is often discussed separately.

While the Barnett Shale is the prolific shale today, the Devonian Shales played a significant role in the early years of US gas production. The first commercial natural gas well in the US tapped into the Devonian-aged shale in Fredonia, New York in 1821—albeit in small quantities. Also located in the Devonian Shales is Huron Shale’s Big

201 Lazar, Remus and Juergen Schieber, “New Albany and Ohio Shales: An Introduction, http://www.indiana.edu/~sepm04/PDF/JS-G4-SEPM%20Guidebook-strat-overview.pdf 202 Ohio Shale, September 2008, http://www1.newark.ohio-state.edu/Professional/OSU/Faculty/jstjohn/ Ohio%20Shale/Ohio%20Shale.htm (December 8, 2010)

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Sandy Field, the first large-scale commercial field in the US. This field was first developed in the 1880s and to a greater extent in the 1920s.203 Recall the Huron is a member of the Ohio Shale.204

The area has long been famous for its shale gas and coal-bearing qualities.

The USGS estimates that the Devonian Shales contain 31.4 Tcf of gas, 562 million barrels of gas liquids and 7.5 million barrels of oil.205 This is comparable to the Fayetteville Shale which is estimated to contain 20 Tcf of recoverable gas.206 The Devonian is, however, dwarfed by the estimates of the Marcellus, which is estimated to contain 516 Tcf, of which the same geologists estimate that 49 TCF is recoverable with current technology.207

Table 2.6 provides a summary of the Devonian Shales key geological characteristics.

Table 2.6 Devonian Shales Geological Characteristics Parameter Devonian Shales Geological age Devonian Depth range (ft) 1,600-6,000 Shale thickness (ft), gross 50-300 GIP/sq mi (Bcf) 5 Porosity (%) 6.0-14.0 Total organic carbon (%) 1.0-6.5 Thermal maturity (Ro) 0.6-2.0 Silica content (%) n/a Expected Recovery Factor (%) 20.0-50.0 Source: Deutsche Bank, 2008.208

The Devonian Shales are black organic-rich shales. It commonly contains beds, as well as iron, uranium and pyrite.209 Iron ore was mined and played an important role in the economic development of the region.210 The Devonian-aged Devonian Shales lie at a depth range of 1,600-6,000 ft., which is shallow compared to the 10,500- 13,500 ft. of the Haynesville Shale but comparable to the 5,000-8,500 ft. of the neighbouring Marcellus Shale. The Appalachian Basin is generally shallower in the western part of the shale, predominantly in Ohio. In terms of thickness and porosity, the Devonian Shales are 50-300 ft. and 6.0-14.0 percent, respectively. This is comparable to the Marcellus in terms of thickness and porosity, 50-200 ft. and 6.0 percent, respectively. The Devonian Shales are has a TOC content of 1.0-6.5 percent and a thermal maturity of 0.6-2.0 Ro.

203 Gas Shale Market Report and Five-Year Forecast 2010”, Warlick International, pp. 73. 204 Emerging Shale Gas Plays in the Appalachian Basin, January 2007, http://www.papgrocks.org/JAN%2007%20PAPG%20%20Flyer.pdf 205 US Shale Gas Brief, Phasis.ca, http://www.phasis.ca/files/pdf/Phasis_Shale_Gas_Study_Web.pdf 206 Edt Peggy Williams, “The Arkoma Shales”, UGcenter Arkoma Playbook, April 2009, pp 5. 207 Congressional Research Services, “Marcellus Shale CRS Report”, October 14, 2008, CRS-4. 208208 “From Shale to Shining Shale”, Deutsche Bank, July 22, 2008, pp. 31. 209 “Gas Shale Market Report and Five-Year Forecast 2010”, Warlick International, pp. 141. 210 ibid

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Table 2.7 provides the basin metrics for the Devonian Shales. It is important to note that of the big five US shale plays, the current metrics indicate that the Marcellus Shale tends to be relatively shallow depth at 6,000 ft., the Devonian Shales are even shallower. The relatively low well cost (US$0.5-3.0), the lower F&D (US$1.30 per Mcf), combined with the large estimated reserves make the Devonian Shales attractive. The proximity to the East Coast markets and low transportation costs are also very attractive. There are, however, operational challenges. These include rough topography for moving rigs and building infrastructure, difficulties with permitting and severe transportation bottlenecks.211 Another challenge in the play is that the play is spread out and has attracted smaller E&P’s with limited resources.212

Table 2.7 Basin Metrics for the Devonian Shales Parameter Devonian Shales Well Cost ($MM) 0.5-3.0 Depth (ft) 1,600-6,000 IP Rate (MMCFD) 0.6-2.0 EUR/Well (BCFE) 1.0-2.2 F&D Cost ($/MCFE) 1.30 Lateral Lengths (ft) 3,500 Typical Well Spacing (acres/well) 80 Typical Frac Foam Source: Simmons & Co., various company reports.

E&P Players and Recent M&A Activity Currently over 80 percent of gas production in the Devonian Shales comes from the Big Sandy Field in eastern Kentucky.213 With more than 10,000 wells, Big Sandy has produced over 2.5 Tcf since the 1920s.214 The historic Big Sandy Field, renewed by advances in technology and high gas prices several years ago, is a part of the Lower Huron Shale, or usually simply referred to as the Huron Shale.

Figure 2.6 illustrates the Lower Huron and Marcellus Fairways. The heart of the Marcellus lies in Pennsylvania while its equivalent for the Lower Huron Shale lies in West Virginia and the eastern edge of Kentucky. The shale in Ohio, north of the Lower Huron Fairway, is regarded as shallow, lower pressure and oily. This is especially the case when compared to Barnett Shale, Woodford Shale and its Appalachian Counterpart, the Marcellus Shale.215

211 From Shale to Shining Shale”, Deutsche Bank, July 22, 2008, pp. 31. 212 US Shale Gas Brief, Phasis.ca, http://www.phasis.ca/files/pdf/Phasis_Shale_Gas_Study_Web.pdf 213 http://www.onepetro.org/mslib/servlet/onepetropreview?id=SPE-139101-MS&soc=SPE (December 17, 2010) 214 Range Resources document, January 15, 2008, http://www.rseg.com/development/drupal/sites/default/files/samples/Experts%20View.pdf, pp. 8. 215 Range Resources document, January 15, 2008, http://www.rseg.com/development/drupal/sites/default/files/samples/Experts%20View.pdf, pp. 8.

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Figure 2.6 Map of the Lower Huron & Marcellus Fairways

Source: http://www.oilshalegas.com216

Key players in the Devonian-aged Huron Shale include Range Resources, Chesapeake Energy, EOG Resources and Equitable Resources.217 While there are larger companies involved in the Huron, this section will discuss the more active players—Equitable Resources and Range Resources.

Even though geologists have known about the Huron Shale for a long time, the recent developments are attributed to Equitable Resources.218 Armed with multi-stage frac’ing techniques, using sand or vapour at high temperatures, Equitable began to explore the Huron shale deposit.219 The company is focusing on the Huron/Burea area of the play, where it currently holds approximately 2.7 million net acres.220 The 120-year old company estimates 2.0 Tcf of proved reserves on their acreage, and 6.7 Tcf of proved plus probable plus probable (3P) reserves.221 The Pittsburgh-based Equitable drilled 356 horizontal wells in the Huron in 2009.222 It is important to note that Equitable and DCP Midstream Partners agreed to create a midstream joint venture, and will focus on gas processing and NGL infrastructure.223 The agreement was announced on May 27, 2010.

216 http://www.oilshalegas.com/sitebuildercontent/sitebuilderpictures/HuronShale.jpg (December 17, 2010) 217 ibid 218 http://oilshalegas.com/huronshale.html (December 17, 2010) 219 ibid 220 http://www.eqt.com/production/reservoirs.aspx (December 17, 2010) 221 ibid 222 ibid 223 Steel Path, Investor Commentary, May 28, 2010, http://www.steelpath.com/wp-content/uploads/Investor- Commentary-5.30.10.pdf

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Equitable is also a very active player in the Marcellus where it holds 500,000 net acres.224 The company is also a leading CBM producer in the Appalachian Basin.225

Range Resources is a large player in the Huron Shale. Like Equitable, Range is a significant player in the Marcellus Shale—they hold approximately 1.3 million net acres in the Marcellus, of which 900,000 net acres are in the Marcellus Fairway (located in Pennsylvania).226 While Range is focusing its efforts on the Marcellus, and its higher EURs compared to the Huron, the company suggests that the Huron and its rate-of-return potential should not be overlooked.227

Range is focusing on the plays tight gas, CBM and shale gas potential in the Huron. More specifically, Range is active in the large Nora-Haysi Fields in Dickenson County, Virginia.228 Both fields have more than 1,000 producing CBM wells and 500 tight sand gas wells.229

Figure 2.7 Virginia’s Nora-Haysi Field

Source: Range Resources230

In addition to the aforementioned, there are over 90 vertical wells producing from the Devonian shale on the Nora-Haysi acreage.231 They are commingled with tight sand production.232

During 3Q2009, Range drilled 5 horizontal Huron Shale wells, 2 horizontal Big Lime wells and 1 horizontal Berea wells.233 During the 3Q2010 Range drilled a total of 61 wells, 29 net wells, in the Nora field. Wells are combinations of tight gas sand, CBM and horizontal drilling.234

224 http://www.eqt.com/production/reservoirs.aspx (December 17, 2010) 225 ibid 226 “Gas Shale Market Report and Five-Year Forecast 2010”, Warlick International, pp. 163. 227 Range Resources, The Experts’ View, January 15, 2008, pp. 1. 228 Range Resources, The Experts’ View, January 15, 2008, pp. 3. 229 ibid 230 ibid 231 Range Resources, The Experts’ View, January 15, 2008, pp. 8. 232 ibid

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Development Outlook & Drilling Forecasts The current metrics indicate that the Marcellus Shale tends to be relatively shallow depth at 6,000 ft. and the Devonian Shales are even shallower. This may be a problem, in the sense that the shales may be under-pressured, but also that they may be on the radar for various environmental groups opposing frac’ing. Shallower shales tend to draw more ire. As previously mentioned, there are other operational challenges as well. These include rough topography for moving rigs and building infrastructure, difficulties with permitting and severe transportation bottlenecks.235 Another challenge in the play is that while larger companies are involved, the more active players are smaller E&P’s with limited resources.236 The larger companies tend to be more active in the neighbouring Marcellus Shale in Pennsylvania.

There are however, positive attribute to the Devonian Shales. The relatively low well cost (US$0.5-3.0), the lower F&D (US$1.30 per Mcf), combined with the large estimated reserves make the Devonian Shales attractive. The proximity to the East Coast markets and low transportation costs are also very attractive.

This shale will certainly grow in the future, but currently seems to be overshadowed by the Marcellus Shale.

Additional Information As previously mentioned the Devonian Shales straddle several states: Kentucky, West Virginia and Ohio.

The Division of Oil and Gas regulates the oil and gas industry in the Commonwealth of Kentucky.237 This includes drilling, completion, production, pipeline transport and all environmental aspects. While the first well was drilled in 1818, the Division of Oil and Gas was created in 1960.238 The oil and gas division lies within the Department for Energy Development and Independence.

On the West Virginia side of the Devonian Shales, the Oil & Gas Conservation Commission (OGCC) and the Department of Environmental Protection oversees all regulatory and environmental issues with regard to the oil and gas industry.

On the Ohio side of the Devonian Shales, the Ohio Department of Natural Resources (DNR) oversees all field, be it oil or gas, operations. This includes drilling, completion, production, pipeline transport and all environmental of all of the aforementioned. The DNR operates through the Division of Mineral Resources Management.

233 http://www.b2i.us/profiles/investor/ResLibraryView.asp?BzID=790&ResLibraryID=33084&Category=1640 (December 17, 2010) 234 ibid 235 From Shale to Shining Shale”, Deutsche Bank, July 22, 2008, pp. 31. 236 US Shale Gas Brief, Phasis.ca, http://www.phasis.ca/files/pdf/Phasis_Shale_Gas_Study_Web.pdf 237 Energy and Environment Cabinet; Department of Natural Resources, Commonwealth of Kentucky, http://oilandgas.ky.gov/Pages/Welcome.aspx (accessed on September 23, 2010) 238 ibid

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The Fayetteville Shale, Arkansas

Geology and Basin Metrics The Fayetteville Shale is located in north central Arkansas, stretching from western Conway County to eastern White County.239 It is part of the Arkoma Basin which, as the name suggests, crosses into Oklahoma. The Arkoma Basin contains three shale plays, the Fayetteville, Woodford and the Caney. The Caney Shale will not be discussed in this report while the Woodford Shale is discussed later in this chapter.

Figure 2.8 illustrates the core drilling area of the Fayetteville Shale, lying in the central part of the state. Much of the gas delivery takes place in five counties: Van Buren, Cleburne, Conway, Faulkner and White.240

Figure 2.8 Fayetteville Shale Map

Source: http://www.shalewiki.org241

According to UGcenter, with recoverable reserves in the region at 20 Tcf, the Fayetteville Shale is often considered the equivalent of the Barnett Shale.242 The Fayetteville Shale is currently the second most productive shale play in the US and one of the nation’s 10 largest fields of any type.243 Houston-based Corp., the largest leaseholder in the core of the Fayetteville Shale, suggests that their position alone may yield ultimate gross recoverable reserves of over 11 Tcf.244 While less than Southwestern Energy’s estimates for their holdings, the Oklahoma City-based Chesapeake Energy estimates that their holdings could yield 7 Tcf in ultimate recoverable gas

239 Fayetteville Shale Arkansas, Oil & Gas Mineral Services, http://www.mineralweb.com/fayetteville-shale- arkansas-a-290.html (accessed on October 19, 2010) 240 “Gas Shale Market Report and Five-Year Forecast 2010”, Warlick International, pp. 73. 241 http://www.shalewiki.org/index.php?n=BarnettShale.OtherShales. (accessed on August 14,2010) 242 Edt Peggy Williams, “The Arkoma Shales”, UGcenter Arkoma Playbook, April 2009, pp 5. 243 Chesapeake Fayetteville Shale, http://www.askchesapeake.com/Fayetteville-Shale/Pages/ information.aspx (accessed on August 14,2010)

244 Riestenberg, David, Robert Ferguson and Vellow Kuuskraa, New and Emerging Unconventional Gas Plays and Prospects”, Advanced Resources International, Arlington, Virginia, August 3, 2007.

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reserves.245 In spite of US gas drilling decreasing in 2009, drilling in the Fayetteville increased and is widely regarded as a shale gas success story. The shale play produces more than 1.5 Bcfpd.246

The Fayetteville Shale is black, fissile clay shale that is commonly interbedded with dark-gray, fine-grained limestone.247 The Mississippian-aged Fayetteville Shale lies at a depth range of 1,500-6,000 ft., which is shallow compared to the 7,800-13,300 ft. of the Horn River Basin, located predominantly in northeast British Columbia. Arkansas’s Fayetteville Shale is generally deeper in the eastern part of the state, near Little Rock. Many of these prospects, however, have been downgraded and are less economically viable in a lower price environment.248 Much of the drilling activity occurs in the central part of Arkansas, where the shale is shallower. In terms of thickness and porosity, the Fayetteville Shale is 50-325 ft. and between 2.0 to 8.0 percent, respectively. The Fayetteville Shale is moderate in silica content (20-60 percent) and has a TOC content of 4.0-9.5 percent. The pressure gradient for the Fayetteville Shale is 0.44 psi/ft. and has a thermal maturity of 1.5-4.5 Ro.

Table 2.8 provides a summary of Fayetteville’s key geological characteristics.

Table 2.8 Fayetteville Shale Geological Characteristics Parameter Fayetteville Shale Geological age Mississippian Depth range (ft) 1,500-6,000 Shale thickness (ft), gross 50-325 GIP/sq mi (Bcf) 25-65 Porosity (%) 2.0-8.0 Total organic carbon (%) 4.0-9.5 Thermal maturity (Ro) 1.5-4.5 Silica content (%) 20-60 Pressure gradient (psi/ft) 0.44 Source: Deutsche Bank, 2008.249

Table 2.9 provides the basin metrics for the Fayetteville Shale.

245 Edt Peggy Williams, “The Arkoma Shales”, UGcenter Arkoma Playbook, April 2009, pp 5. 246 “Gas Shale Market Report and Five-Year Forecast 2010”, Warlick International, pp. 72. 247 “Gas Shale Market Report and Five-Year Forecast 2010”, Warlick International, pp. 87. 248 Drake Steven, “Unconventional Gas Plays SPEE”, Marsh Operating Company, December 2007. 249 “From Shale to Shining Shale”, Deutsche Bank, July 22, 2008, pp. 32.

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Table 2.9 Basin Metrics for the Fayetteville Shale Parameter Fayetteville Shale Well Cost ($MM) 3.0 Depth (ft) 5,000 IP Rate (MMCFD) 2.8 EUR/Well (BCFE) 2.6 Threshold Price ($/MCFE) 3.95 F&D Cost ($/MCFE) 1.48 LOE ($/MCFE) 0.70 Royalty (%) 20 Production Tax (%) 5 Decline – Yr. 1 (%) -64 Decline – Yr. 2 (%) -35 Decline – Yr. 3 (%) -21 Decline – Out Yrs. (%) -5 Source: Simmons & Co., Various company Reports.

In terms of IP, EUR, well costs and overall decline rates, the metrics for the Fayetteville Shale are similar to those of the Barnett Shale.

E&P Players and Recent M&A Activity The vast potential of the Fayetteville Shale is attracting large independent producers, as well as several mid-sized E&P companies. Currently, the more significant producers, in alphabetical order, include BP America, Chesapeake Energy, ExxonMobil/XTO Energy, Petrohawk Operating Company, PetroQuest Energy and Southwestern Energy Co. (via wholly-owned SEECO Inc., an Arkansas subsidiary of Southwestern).250 Together these companies hold exploration rights to approximately two million net acres of land. Other producers include Edge Petroleum Corp., Hallwood Petroleum LLC, KCS Resources Inc., and One TEC Operating LLC. This list is not exhaustive and does not include smaller operators.

The following will discuss the top five players and review various mergers and acquisitions: Southwestern, Chesapeake, BP North America, ExxonMobil/XTO Energy and Petrohawk Operating Company.

It was SEECO and Southwestern that discovered the modern play in 2002.251 In short, Southwestern is to the Fayetteville Shale as to what Devon Energy is to the Barnett Shale. While all dark, organic-rich eyes were on Barnett, Southwestern and its Arkansas-based subsidiary focused on the Arkansas portion of the Arkoma Basin. As a result Southwestern, the largest leaseholder in the Fayetteville Shale, began purchasing land when prices were low in 2002. Currently Southwestern holds 889,000 net acres in the play.252 Southwestern also is the basin leader in drilling and production. The company realized that the new frac techniques, used in the Barnett Shale, could be applied in the Fayetteville Shale.

250 “Gas Shale Market Report and Five-Year Forecast 2010”, Warlick International, pp. 77-82. 251 http://www.oilshalegas.com/fayettevilleshale.html (accessed on October 22, 2009) 252 “Gas Shale Market Report and Five-Year Forecast 2010”, Warlick International, pp. 81.

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They drilled their first well in 1Q2004, and first horizontal well one year later in 1Q2005.253 In the first half of 2009, the company reported a total of 231 operated wells on production, all of which were horizontal wells fracture stimulated using slickwater.254 Southwestern first used slickwater frac treatment in 3Q2005.255 By the end of 2009, Southwestern drilled and placed in service approximately 500 wells, most of which are horizontal and completed with slickwater.256 The organization placed in service 106 wells in 1Q2010, 26 fewer than planned.257

According to oilgasshale.com, as of July 30, 2010 Southwestern’s gross production rate was approximately 1,447 MMcfpd, up from 1,330 MMcfpd in 1Q2010 and up from approximately 850 MMcfpd from 2009.258 This is also up from approximately 500 MMcfpd from the previous year. According to same source, during the 1Q2010, the company’s horizontal wells had an average horizontal lateral length of 4,348 feet, compared to 4,123 feet in 2Q2009.259 In addition, over the same period, costs per well have decreased from US$2.9 million to US$2.8 million.260

Southwestern’s success is due in large part to improvements in technology and efficiency. Completions feature longer horizontal fractures using slickwater treatments. In addition, improved 3-D seismic information increases well efficiencies. The average time to drill, from re-entry to re-entry, is only 12 days.261 This is down from 14 days in 2008.

Chesapeake Energy is the second largest leasehold owner in the Fayetteville Shale, holding 455,000 net acres.262 The company’s acreage position, however, decreased from 540,000 net acres as Chesapeake sold 25 percent of its holdings (135,000 net acres) to BP North America.263 Of the nearly US$1.9 billion, US$1.1 was in cash and the remainder is to be paid in the form of drilling on joint venture properties.264 The latter US$800 was paid in full by end-of-year 2009.265

According to oilgasshale.com, during the 1Q2010 Chesapeake’s average daily net production rate was 345 MMcfpd, up from 202 MMcfpd in 1Q2009.266 Reports from Chesapeake indicate that they are currently producing approximately 365 MMcfpd.267

While BP North America is late in arriving to the shale game in the US, the major energy company, however, made a big splash. Understanding the importance of shale gas in North America, it felt the pull of Fayetteville’s massive potential upside. Siding with some of the most knowledgeable in the shale industry, BP bought, as mentioned

253 “Key Players”, UGcenter Arkoma Playbook, April 2009, pp 31. 254 ibid 255 ibid 256 “Gas Shale Market Report and Five-Year Forecast 2010”, Warlick International, pp. 81. 257 http://www.oilshalegas.com/fayettevilleshale.html (accessed on August 14, 2010) 258 http://www.oilshalegas.com/fayettevilleshale.html (accessed on October 19, 2010) 259 http://www.oilshalegas.com/fayettevilleshale.html (accessed on August 14, 2010) 260 ibid 261 “Gas Shale Market Report and Five-Year Forecast 2010”, Warlick International, pp. 81. 262 “Gas Shale Market Report and Five-Year Forecast 2010”, Warlick International, pp. 78. 263 “Key Players”, UGcenter Arkoma Playbook, April 2009, pp 27. 264 “Key Players”, UGcenter Arkoma Playbook, April 2009, pp 19. 265 “Gas Shale Market Report and Five-Year Forecast 2010”, Warlick International, pp. 76. 266 http://www.oilshalegas.com/fayettevilleshale.html (accessed on August 14, 2010) 267 “Gas Shale Market Report and Five-Year Forecast 2010”, Warlick International, pp. 78.

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previously, 25 percent of Chesapeake’s holding in the Fayetteville Shale. After the deal, BP controlled 135,000 net acres and 45 MMcfpd of natural gas gross production in the heart of the Fayetteville Shale.268 In addition, BP possesses the right to participate in future acquisitions by Chesapeake.269 In this joint venture, BP paid approximately US$1.1 million per 80-acre drilling location—a very steep price indeed.270 At the time the joint venture agreement was executed the price of gas was approximately US$8 MCF.

Similar to BP teaming up with Chesapeake, ExxonMobil decided that XTO provided a great position to get into the shale gas game. In December 2009, ExxonMobil announced its intent to acquire XTO Energy, an important player in the Barnett and Fayetteville Shales.271 In the US$41 billion deal, ExxonMobil significantly enhanced its natural gas position—XTO was a significant player in various unconventional plays in the US.272

ExxonMobil/XTO has 380,000 net acres in the Fayetteville Shale.273 Before XTO’s acquisition, it was expanding its shale gas portfolio, not only in the Fayetteville but also the Barnett. Following several purchases, including 55,631 net acres from Chesapeake Energy, XTO Energy expanded its net acreage to 380,000.274 XTO paid Chesapeake approximately US$520 million for land in Cleburne County.275

ExxonMobil/XTO has an attractive position in both the Fayetteville and Barnett Shales for future development. Gas production grew from 40 MMcfpd at the beginning of 2009 to more than 100 MMcfpd in 4Q2009.276 The latter is using seven operated rigs. According to UGcenter, in 2008 XTO produced 30 MMcfpd gross.277 With ExxonMobil/XTO’s land holdings, significant other potential wells exist: Johnson for 3.5 MMcfpd, the McFalls for 3 MMcfpd and the Thomas for 2.7 MMcfpd.278 All potential is gross production.

Petrohawk Energy’s position in the Fayetteville is significant. The organization has 157,000 net acres in the Fayetteville Shale.279 With an estimated resource potential of 1.5 Tcf, there are approximately 2,500 drilling locations.280 In 4Q2009 Petrohawk’s production was 79 MMcfpd, up dramatically from 18 MMcfpd at the beginning of 2009.281 According to oilshalegas.com, during 2Q2009 the company’s horizontal wells had an average horizontal lateral length of 3,170 feet, with an average of 9.7 frac stages.282 This is compared to 3,080 feet and 7.9

268 Edt Peggy Williams, “The Arkoma Shales”, UGcenter Arkoma Playbook, April 2009. 269 “Gas Shale Market Report and Five-Year Forecast 2010”, Warlick International, pp. 77. 270 ibid 271 “Gas Shale Market Report and Five-Year Forecast 2010”, Warlick International, pp. 79. 272 “Gas Shale Market Report and Five-Year Forecast 2010”, Warlick International, pp. 32. 273 “Gas Shale Market Report and Five-Year Forecast 2010”, Warlick International, pp. 79. 274 “Gas Shale Market Report and Five-Year Forecast 2010”, Warlick International, pp. 32. 275 ibid 276 “Gas Shale Market Report and Five-Year Forecast 2010”, Warlick International, pp. 79. 277 “Key Players”, UGcenter Arkoma Playbook, April 2009, pp 27. 278 ibid 279 “Gas Shale Market Report and Five-Year Forecast 2010”, Warlick International, pp. 74. 280 “Gas Shale Market Report and Five-Year Forecast 2010”, Warlick International, pp. 79. 281 “Gas Shale Market Report and Five-Year Forecast 2010”, Warlick International, pp. 80. 282 http://www.oilshalegas.com/fayettevilleshale.html (accessed on August 14,2010)

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frac stages in 4Q2008.283 In addition, the company reported a significant improvement in drilling efficiency— reducing spud to rig release from 15 days to an average of 11 days between late 2009 and early 2010.284

Development Outlook & Drilling Forecasts While the top five players have a large impact on the development of the Fayetteville Shale, it is Southwestern that is unquestionably the major driving force within the play. The good news for Fayetteville is that even within the low-gas price environment Southwestern, plans to ramp up drilling. Their capital expenditure in the near future is US$1.2 billion in the Fayetteville Shale, with 650-680 gross wells to be drilled.285 Southwestern’s success is due in large part to improvements in technology and efficiency.

Like Southwestern, Chesapeake’s drilling results continue to improve—drilling longer laterals and better geo- steering. While the company’s horizontal wells have increased their average horizontal lateral length, costs per well have decreased. The company cites that its 30 most recent operated wells are 30 percent more productive than previous estimates. Perhaps this is due to drilling longer laterals, better geo-steering and enhanced completion techniques. The company is currently drilling with 12 operated rigs and plans to drill 90 net wells with 10 rigs throughout the 2010.286

As previously mentioned, with ExxonMobil/XTO’s land holdings, significant other potential wells exist: Johnson for 3.5 MMcfpd, the McFalls for 3 MMcfpd and the Thomas for 2.7 MMcfpd. The organization’s position includes an estimated 2.5 Tcf and between 1,600-1,800 potential drilling locations.287 They are expected to ramp up activity.

Petrohawk and BP North America future activities are more uncertain—especially in BP. While Petrohawk are focusing their efforts on their holdings in the very productive Haynesville Shale, the organization plans to drill 15 wells in 2010.288 In light of their poor economics, partially stemming from their high-priced merger in the Fayetteville Shale and the Gulf of Mexico spill, BP’s future plans are unknown.

Figure 2.9 is a drilling forecast for the Fayetteville Shale for the period 2009-14. The Figure illustrates two cases: the high case and low case. Drilling estimates are provided by Warlick International, May 2010.289

283 ibid 284 “Gas Shale Market Report and Five-Year Forecast 2010”, Warlick International, pp. 80. 285 “Gas Shale Market Report and Five-Year Forecast 2010”, Warlick International, pp. 82. 286 “Gas Shale Market Report and Five-Year Forecast 2010”, Warlick International, pp. 78. 287 ibid 288 “Gas Shale Market Report and Five-Year Forecast 2010”, Warlick International, pp. 80. 289 “Gas Shale Market Report and Five-Year Forecast 2010”, Warlick International, pp. 92.

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Figure 2.9 Drilling Forecast for the Fayetteville Shale

1000

800

600

400

200

0 2009 2010 2011 2012 2013 2014

High Case Low Case

Source: Warlick International, May 2010

Additional Information The Arkansas Oil and Gas Commission (AOGC) oversees all oil and gas operations in the state, including drilling, production, handling of produced liquids, use of water for drilling and pressure pumping. Environmental and transportation issues fall under the AOGC as well.

The Haynesville Shale, Louisiana/Texas

Geology and Basin Metrics The Haynesville Shale is located in northwestern Louisiana and extends into southwestern Arkansas and eastern Texas. The southern portions of the shale are called the Bossier Shale, but the Bossier is in fact a geologically separate entity, located just south of the Haynesville. Figure 2.10 illustrates the core drilling area of the Haynesville Shale. Drilling is primarily located in the following counties: Caddo, Bienville, Bossier, DeSoto, Red River and Webster Parishes of northwestern Louisiana.290

290 http://geology.com/articles/haynesville-shale.shtml (accessed August 16, 2010)

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Figure 2.10 Haynesville Shale Map

Source: UGcenter291

While geologists have long known about the Haynesville, it was not until 2008—with the developments at Red Deer and DeSoto Parishes—that the Haynesville emerged as a major gas resource.292 Interestingly, because of its low permeability the Haynesville was originally considered to be a gas rather than a gas reservoir.293

The Haynesville Shale has recently been estimated by the USGS to be the largest natural gas field in the 48 states with an estimated 250 Tcf of recoverable gas.294 Chesapeake Energy, the plays largest leaseholder and player, estimates it has approximately 24 Tcf of risked unproved resources and 39 Tcf of unrisked, unproved resources.295 Petrohawk estimates a resource potential of 15.7 Tcfe on their Haynesville properties.296 While the field is yet to be fully defined, other estimates suggest that the Haynesville Shale could be the fourth largest gas field in the world, behind South Pars/North Dome (Qater and Iran), Urengoy (Russia) and the Yamburg (Russia).297 It is easy to understand the attention that the Haynesville is receiving from industry pundits and E&Ps alike.

The Haynesville Shale is an organic-rich black shale, deposited between the Cotton Valley and Smackover Formations.298 The Upper -era shale underlies much of the Gulf Coast area of the US and was deposited about 150 million years ago.299 The Haynesville Shale lies at a depth range of 10,500-13,500 ft., which is deep compared to the Fayetteville Shale, Woodford Shale and Barnett Shale. It is, however, comparable to the 7,800- 13,300 ft. of the Horn River Basin located predominantly in northeast British Columbia. In terms of shale thickness and porosity, the Haynesville Shale is 200-240 ft. and 8.0-12.0 percent, respectively. This is comparable to the

291 http://www.ugcenter.com/Shales/US/Haynesville/ (accessed August 16, 2010) 292 “Gas Shale Market Report and Five-Year Forecast 2010”, Warlick International, pp. 96. 293 http://geology.com/articles/haynesville-shale.shtml (accessed August 16, 2010) 294 Shale Gas Reservoirs, http://www.transformsw.com/resources/studies.html (accessed August 16, 2010) 295 http://www.oilshalegas.com/haynesvilleshale.html (accessed on August 15, 2010) 296 “Gas Shale Market Report and Five-Year Forecast 2010”, Warlick International, pp. 113. 297 http://myhaynesvilleshale.com (access August 16, 2010) 298 “Gas Shale Market Report and Five-Year Forecast 2010”, Warlick International, pp. 96. 299 http://geology.com/articles/haynesville-shale.shtml (accessed August 16, 2010)

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Barnett Shale. The Haynesville Shale’s pressure gradient is 0.7-0.9 psi/ft. while its TOC content is 3.0-5.0 percent. It is characterized by high porosity compared to other shales. The silica content and thermal maturity are not available.

Table 2.10 provides a summary of key geological characteristics of the Haynesville Shale.

Table 2.10 Haynesville Shale Geological Characteristics Parameter Haynesville Shale Geological age Upper Jurassic Depth range (ft) 10,500-13,500 Shale thickness (ft), gross 200-240 GIP/sq mi (Bcf) 150-250 Porosity (%) 8.0-12.0 Total organic carbon (%) 3.0-5.0 Thermal maturity (Ro) n/a Silica content (%) n/a Pressure gradient (psi/ft) 0.7-0.9 Source: Deutsche Bank, 2008.300

Table 2.11 provides the basin metrics for the Haynesville Shale. Recall that the Woodford Shale has the second highest well cost among the top five shale plays in the US, with the Haynesville Shale being the highest. It is also important to note that current metrics indicate that the Haynesville Shale lead major US plays in average depth (11,500 ft.), most sizable EUR/well (6.5 Bcfe) and highest IP rate (14 MMcfpd).301

300 “From Shale to Shining Shale”, Deutsche Bank, July 22, 2008, pp. 34. 301 “Gas Shale Market Report and Five-Year Forecast 2010”, Warlick International, pp. 96.

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Table 2.11 Basin Metrics for the Haynesville Shale Parameter Haynesville Shale Well Cost ($MM) 7.5 Depth (ft) 11,500 IP Rate (MMCFD) 14 EUR/Well (BCFE) 6.5 Threshold Price ($/MCFE) 4.40 F&D Cost ($/MCFE) 1.54 LOE ($/MCFE) 0.85 Royalty (%) 25 Production Tax (%) 8 Decline – Yr. 1 (%) -85 Decline – Yr. 2 (%) -41 Decline – Yr. 3 (%) -26 Decline – Out Yrs. (%) -5 Source: Simmons & Co., various company reports.

E&P Players and Recent M&A Activity Currently, there are over 20 E&P companies active in the Haynesville, including the following: BG Group, Cabot Oil & Gas, Chesapeake Energy, Comstock Resources, Cubic Energy, Devon Energy, El Paso E&P, EnCana Corp., EOG Resources, EXCO Resources, ExxonMobil/XTO, Forest Oil Corp., GMX Resources Corp., Goodrich Petroleum Corp., Penn Virginia Corp., Petrohawk Energy, Plains E&P, Questar E&P, Shell Western E&P, St. Mary Land & Exploration and Southwestern Energy.302 There are, however, only four entities that are considered significant: Chesapeake, Petrohawk, EnCana and EXCO/BG. These companies account for more than 60 percent of wells drilled in 2010.303

While it is not realistic to discuss all these aforementioned companies, it is useful to review the four major players and their various mergers and acquisitions in the play.

It was Dallas-based Cubic Energy who initially, and successfully, tested the Haynesville Shale. It was followed quickly by Chesapeake. And the organization has not looked back since. Chesapeake is the largest leaseholder at 535,000 net acres and most active driller in the Haynesville.304 With their 20 percent joint venture partner, Plains E&P, they have drilled and completed 150 horizontal wells in the Haynesville.305 Daily net production averaged 510 MMcfpd in 2Q2010, up from 425 MMcfpd in 1Q2010 and 365 MMcfpd in 4Q2009.306 In addition to the Haynesville, Chesapeake owns approximately 185,000 net acres in the Bossier Shale.307 Chesapeake’s total average net daily production from the Haynesville and Bossier Shales is approximately 510 MMcfpd in 2Q2010.308

302 “Gas Shale Market Report and Five-Year Forecast 2010”, Warlick International, pp. 101-118. 303 “Gas Shale Market Report and Five-Year Forecast 2010”, Warlick International, pp. 119. 304 “Gas Shale Market Report and Five-Year Forecast 2010”, Warlick International, pp. 102. 305 ibid 306 “Gas Shale Market Report and Five-Year Forecast 2010”, Warlick International, pp. 103. 307 http://www.oilshalegas.com/haynesvilleshale.html (accessed on August 19, 2010) 308 http://www.oilshalegas.com/haynesvilleshale.html (accessed on August 19, 2010)

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Currently, the company is operating 36 rigs in the Haynesville and is anticipating operating 35 rigs by end-2010. 309 With expanding operations in the Haynesville and advances in technology, Chesapeake anticipates reaching 640 MMcfpd by end-2010.310 Several notable wells recently completed yield very interesting results: three wells in the DeSoto Parish in Louisiana are averaging 21.5 MMcfpd.311

Chesapeake formed two significant joint ventures in the Haynesville, the first with Plains E&P and the second with Goodrich Petroleum. Both occurred in July 2008. Plains acquired a 20 percent interest in Chesapeake’s Haynesville 535,000 net acreage leasehold.312 The cost was US$1.65 billion. About US$390 million of Chesapeake’s drilling and completion costs were paid for by Plains during 2009.313 The remainder of the acquisition was paid by Plains to Chesapeake in the form of cash in 4Q2009. In the second deal, Plains/Chesapeake paid $178 million to form a joint venture with Goodrich Petroleum.314 At the center of the joint venture is a 20 percent working interest in 25,000 net acres in the Bethany-Longstreet field and 50 percent working interest in 10,500 net acres in the Longwood field.315

The second major player in the Haynesville is Petrohawk Energy. The company appears to be solidifying its position as a gas shale developer. As previously mentioned, the organization’s 157,000 net acres and 4Q2009 production of 79 MMcfpd is an excellent position in the Fayetteville Shale. Their position in the Haynesville is also quickly on the rise. With 348,000 net acres and a daily net production of 326 MMcfpd, Petrohawk is the third largest leaseholder and second largest producer in the Haynesville Shale.316 With an estimated resource potential of 15.7 Tcf, there are approximately 4,200 drilling locations on their holdings. The company’s properties are largely located in Caddo, Bossier, Webster, Bienville, DeSoto and Red River Parishes.317 In addition, Petrohawk owns 122,000 net acres and 1,500 drilling locations in the Bossier Shale.318

In 2009 Petrohawk drilled 73 operated wells and 111 non-operated wells. In 2010 the company plans to drill 110 operated wells and 165 non-operated wells.319

It is important to note that in April 2010 Kinder Morgan Energy Partners (KMEP) entered a joint venture with Petrohawk. Kinder purchased 50 percent interest in Petrohawk’s gathering and treating business in the Haynesville Shale.320 The cost of US$875 million creates the largest gathering and midstream business in the Haynesville.321

Calgary-based EnCana is a significant player in the Haynesville. With their recent purchases of land, they now have approximately 400,000 net acres in the play, plus another 63,000 net acres of mineral rights.322 The company first

309 “Gas Shale Market Report and Five-Year Forecast 2010”, Warlick International, pp. 103. 310 ibid 311 http://www.oilshalegas.com/haynesvilleshale.html (accessed on August 19, 2010) 312 “Gas Shale Market Report and Five-Year Forecast 2010”, Warlick International, pp. 103. 313 ibid 314 ibid 315 ibid 316 “Gas Shale Market Report and Five-Year Forecast 2010”, Warlick International, pp. 113. 317 ibid 318 “Gas Shale Market Report and Five-Year Forecast 2010”, Warlick International, pp. 114. 319 ibid 320 “Gas Shale Market Report and Five-Year Forecast 2010”, Warlick International, pp. 97. 321 ibid

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entered Haynesville in 2005 and drilled several vertical wells. Their position has increased rapidly since. In 2007, EnCana signed a joint venture exploration agreement with Shell E&P. The joint venture agreement is 50-50 and involved 134,000 net acres of land.323 In June 2008, EnCana acquired acreage from Indigo Mineral LLC, in which EnCana paid US$457 million cash for 89,500 net acres.324

Daily net production was 71 MMcfpd by end-2009, up from 10 MMcfpd in end-2008.325 Current estimates indicate that production at end-2010 could exceed 300 MMcfpd.326 2Q2010 production is approximately 270 MMcfpd, indicating that the company could in fact exceed 500 MMcfpd and is well on its way to averaging over 300 MMcfpd over the entire year.327

EnCana currently has a half a dozen operating rigs in the Haynesville and have drilled 41 net wells in the first half of 2010.328 This number is expected to increase. The company’s 2010 budget involves drilling 110 net wells with 20- 25 operated rigs.329 Currently all of EnCana’s drilling activity is in the state of Louisiana.

The fourth significant player in the Haynesville Shale is EXCO/BG. Through various joint ventures, this company currently holds 107,800 net acres and is increasing its presence in the Haynesville.330 This figure increased by 22,800 net acres in the joint venture between EXCO and BG Group in August 2009.331 BG acquired a 50 percent interest in 120,000 net acres in EXCO’s leases.332 The deal will add approximately 2.6 Tcf of gas resources and 90 MMcfpd of production to BG while EXCO secures monetary resources to develop the Haynesville.333 The total cost was US$1.396 billion, including US$727 million cash plus US$400 million to be paid as a carry of EXCO’s future drilling costs plus US$269 million to be paid for the midstream portion of the alliance (TGGT Holdings).334

Gas production at the beginning of 2010 increased to 112 MMcfpd from 51 operated and 49 non-operated horizontal wells.335 EXCO/BG are currently running a 13-rig program and plan to drill between 20 to 30 wells per quarter for the remainder of 2010.336

Development Outlook & Drilling Forecasts At approximately 11,500 ft., the Haynesville is the deepest of the big five shales. This is one of the reasons that well costs, also the highest of the big five shales, are US$7.5 million. With technology advances and drilling efficiencies increasing, the price of natural gas appears to be less of a factor compared to other plays. Between the

322 http://www.oilshalegas.com/haynesvilleshale.html (accessed on August 19, 2010) 323 “Gas Shale Market Report and Five-Year Forecast 2010”, Warlick International, pp. 107. 324 ibid 325 “Gas Shale Market Report and Five-Year Forecast 2010”, Warlick International, pp. 107. 326 ibid 327 http://www.oilshalegas.com/haynesvilleshale.html (accessed on August 19, 2010) 328 ibid 329 ibid 330 “Gas Shale Market Report and Five-Year Forecast 2010”, Warlick International, pp. 109. 331 ibid 332 “Gas Shale Market Report and Five-Year Forecast 2010”, Warlick International, pp. 99. 333 ibid 334 ibid 335 “Gas Shale Market Report and Five-Year Forecast 2010”, Warlick International, pp. 109. 336 ibid

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positive economics and the plays incredible gas-in-place potential, drilling activity in the Haynesville is expected to increase.

Figure 2.11 is a drilling forecast for the Haynesville Shale for the period 2009-14. The Figure illustrates two cases: the high case and low case. Drilling estimates are provided by Warlick International, May 2010.337

Figure 2.11 Drilling Forecast for the Haynesville Shale

1200

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200

0 2009 2010 2011 2012 2013 2014

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Source: Warlick International, May 2010

As suggested previously, there are four major players that can affect the Haynesville Shale. And all four appear to be sustaining or ramping up drilling activity. Currently, Chesapeake is operating 36 rigs in the Haynesville and is anticipating operating 35 rigs by end-2010.338 With expanding operations in the Haynesville and advances in technology, Chesapeake anticipates reaching 640 MMcfpd by end-2010.339

Petrohawk’s position in the Haynesville is also quickly on the rise. With 348,000 net acres and a daily net production of 326 MMcfpd, Petrohawk is the third largest leaseholder and second largest producer in the Haynesville Shale.340 On their current lease holdings there are approximately 4,200 drilling locations. This does not even include their 122,000 net acres and 1,500 drilling locations in the Bossier Shale. In 2010 the company plans to drill 110 operated wells and 165 non-operated wells, up from 73 operated wells and 111 non-operated wells in 2009.341

337 “Gas Shale Market Report and Five-Year Forecast 2010”, Warlick International, pp. 137. 338 “Gas Shale Market Report and Five-Year Forecast 2010”, Warlick International, pp. 103. 339 ibid 340 “Gas Shale Market Report and Five-Year Forecast 2010”, Warlick International, pp. 113. 341 “Gas Shale Market Report and Five-Year Forecast 2010”, Warlick International, pp. 114.

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EnCana currently has 6 operating rigs in the Haynesville and have drilled 41 net wells in the first half of 2010. 342 This number is expected to increase. The company’s 2010 budget involves drilling 110 net wells with 20-25 operated rigs.343

EXCO/BG are currently running a 13-rig program and plan to drill between 20 to 30 wells per quarter for the remainder of 2010.344

Additional Information The Haynesville Shale straddles two states, Louisiana and Texas. On the Louisiana side of the Haynesville, the Louisiana Department of Natural Resources (DNR) oversees all field, be it oil or gas, operations. This includes drilling, completion, production, pipeline transport and all environmental of all of the aforementioned. This also includes the handling of produced liquids (including water), the use of drilling fluids and frac fluids. The DNR operates through the Office of Conservation and the Office of Mineral Resources.

The DNR generally supports this sector, in terms of generating jobs and positive economic impacts. In spite of this generally positive stance, the DNR is particularly careful regarding the environmental impacts—especially considering how quickly the industry is ramping up activity in the Haynesville Shale. One of the environmental issues that the DNR is paying attention to is the Wilcox Aquifer.345 The organization is particularly careful that drilling and production does not impact this important source of water.

On the Texas side of the Haynesville, the Texas Natural Resources Conservation Commission, via the Texas Railroad Commission (TRC), oversees the all regulatory and environmental issues with regards to the oil and gas industry.

The Marcellus Shale, Pennsylvania/West Virginia/Ohio/New York

Geology and Basin Metrics While much of the drilling activity is occurring in Pennsylvania, the Marcellus Shale spreads across several states, including West Virginia, Ohio and New York. Sometimes the shale adopts the name of the particular state: Pennsylvania Shale, New York Shale, Ohio Shale and West Virginia Shale.346 The Marcellus is the largest subset of the Appalachian Basin, which is the largest hydrocarbon-bearing basin in the Lower-48. Other shales in the northeastern states are the Utica Shale and the Devonian Shale—both are discussed in subsequent sections. The Utica is the deepest and oldest of the three shale plays, while the Devonian/Ohio shales are the shallowest and youngest.

Figure 2.12 illustrates the Marcellus Shale, including the Ohio Shale’s Big Sandy Fields which has been producing since the 1880s in minor quantities and in larger-scale since the 1920s.347 The figure also illustrates portions of the

342 ibid 343 ibid 344 “Gas Shale Market Report and Five-Year Forecast 2010”, Warlick International, pp. 114. 345 Louisiana Oil & Gas Association, http://loga.la/haynesville-shale-news/?m=2009&w=21 (accessed on October 19, 2010) 346http://www.oilshalegas.com/marcellusshale.html (accessed on August 27, 2010) 347 Gas Shale Market Report and Five-Year Forecast 2010”, Warlick International, pp. 73.

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Basin that are categorized as either over- or under-pressured. Much of the gas delivery takes place in the over- pressured part of the Marcellus. The figure also illustrates the comparative size of the shale to the core drilling area of the prolific Barnett Shale (approximately 63 million acres, vs. Barnett at 2.7 million acres).

Figure 2.12 Marcellus Shale Map

Source: http://www.shalewiki.org348

What makes the Marcellus extremely attractive to E&P companies is the estimated gas-in-place. The US Department of Energy estimates the play to contain 262 Tcf of recoverable gas.349 The Fayetteville is estimated to contain 20 Tcf of recoverable gas.350 University of New York and Pennsylvania State University geologists estimate the Marcellus to contain 516 Tcf, of which the same geologists estimate that 49 TCF is recoverable with current technology.351 Estimates such as these have led many E&Ps to expand their acreages in the hope of future development.

Chesapeake Energy Co., the largest leaseholder in the core of the Marcellus Shale, suggests that their position alone may yield ultimate gross recoverable reserves of approximately 460 Bcf and 34.1 Tcf of risked unproved resources.352 CNX Gas Corporation, another significant player, estimates that their reserve base is 13.7 Tcf (1.4 Tcf in proved reserves, 1.3 Tcf of unproved reserves and 11 Tcf in net resource potential).353 Range Resources, the

348 http://www.shalewiki.org/index.php?n=BarnettShale.OtherShales. 349 US Department of Energy, “Modern shale gas development in the United States: a primer”, p. 17, April 2009. 350 Edt Peggy Williams, “The Arkoma Shales”, UGcenter Arkoma Playbook, April 2009, pp 5. 351 Congressional Research Services, “Marcellus Shale CRS Report”, October 14, 2008, CRS-4. 352 http://www.oilshalegas.com/marcellusshale.html (accessed on August 27, 2010) 353 “Gas Shale Market Report and Five-Year Forecast 2010”, Warlick International, pp. 158.

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company that discovered the Marcellus and completed the first commercial well in 2004, estimates approximately 20-27 Tcf potential in their vast holdings.354

Table 2.12 provides a summary of Marcellus’s key geological characteristics.

Table 2.12 Marcellus Shale Geological Characteristics Parameter Marcellus Shale Geological age Devonian Depth range (ft) 5,000-8,500 Shale thickness (ft), gross 50-200 GIP/sq mi (Bcf) 70-150 Porosity (%) 6.0 Total organic carbon (%) 2.0-10.0 Thermal maturity (Ro) 1.0-2.5 Silica content (%) 40-60 Pressure gradient (psi/ft) 0.4-0.7 Source: Deutsche Bank, 2008.355

The Marcellus Shale is black, low-density, organic-rich shale. It commonly contains limestone beds, as well as iron, uranium and pyrite.356 Iron ore was mined and played an important role in the economic development of the region.357 The Devonian-aged Marcellus Shale lies at a depth range of 5,000-8,500 ft., which is shallow compared to the 10,500-13,500 ft. of the Haynesville Shale. The Marcellus is generally shallower in the western part of the shale, predominantly in Ohio. Many of these prospects, however, appear to have been downgraded and are less economically viable due to lower pressure, oily nature and a lower price environment.358 In terms of thickness and porosity, the Marcellus Shale is 50-200 ft. and 6.0 percent, respectively. The Marcellus Shale is moderate in silica content (40-60 percent) and has a TOC content of 2.0-10.0 percent. The pressure gradient for the Marcellus Shale is between 0.4 and 0.7 psi/ft.

Table 2.13 provides the basin metrics for the Marcellus Shale. It is important to note that of the big five US shale plays, the current metrics indicate that the Marcellus Shale tends to be relatively shallow depth (6,000 ft.), have low royalty rates at 15 percent and have the lowest threshold gas price at US$3.30 per Mcfe. The latter combined with a relatively low well cost (US$3.7), average IP rates of 3.5 MMcfpd and EURs of approximately 3.5 MMcfpd makes the economics of the Marcellus very attractive.

354 “Gas Shale Market Report and Five-Year Forecast 2010”, Warlick International, pp. 163. 355 “From Shale to Shining Shale”, Deutsche Bank, July 22, 2008, pp. 35. 356 “Gas Shale Market Report and Five-Year Forecast 2010”, Warlick International, pp. 141. 357 ibid 358 Drake Steven, “Unconventional Gas Plays SPEE”, Marsh Operating Company, December 2007.

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Table 2.13 Basin Metrics for the Marcellus Shale Parameter Marcellus Shale Well Cost ($MM) 3.7 Depth (ft) 6,000 IP Rate (MMCFD) 3.5 EUR/Well (BCFE) 3.5 Threshold Price ($/MCFE) 3.30 F&D Cost ($/MCFE) 1.24 LOE ($/MCFE) 0.90 Royalty (%) 15 Production Tax (%) 5 Decline – Yr. 1 (%) -62 Decline – Yr. 2 (%) -35 Decline – Yr. 3 (%) -21 Decline – Out Yrs. (%) -5 Source: Simmons & Co., various company reports.

E&P Players and Recent M&A Activity Currently, there are over 20 E&P companies active in the Marcellus, including the following: Anadarko Petroleum, Antero Resources, Atlas Energy, BG Group, Cabot Oil & Gas, Carrizo Oil & Gas, Chief Oil & Gas, Chesapeake Energy/Statoil, CNX Gas Corporation, EOG Resources, EXCO Resources, ExxonMobil/XTO, PostRock Exploration, Range Resources, Rex Energy, Seneca Resources, Southwestern Energy, Ultra Petroleum and Williams E&P.359 There are, however, only three entities that are considered significant: Range, Chesapeake/Statoil and CNX. However, companies such as Atlas/Reliance, EXCO/BG and Cabot are becoming increasingly important players, either through M&A’s or aggressive drilling programs.

While it is not realistic to discuss all these aforementioned companies, it is useful to review the three major players and their various mergers and acquisitions in the play.

Chesapeake, the most important player in the Haynesville Shale, is also a major player in the Marcellus Shale. Chesapeake is the largest leaseholder in the Marcellus, with approximately 1.6 million net acres in the play.360 Their joint venture partner, Statoil, owns 590,000 net acres.361 The Chesapeake/Statoil partnership creates a formidable entity to develop the huge up-and-coming play. The companies executed two deals, one in November 2008 and the other in March 2010. The deals were significant for both entities and for the development of the Marcellus Shale play. In the first deal, Norway’s Statoil (previously known as StatoilHydro), paid Chesapeake US$3.375 billion for a 32.5 percent interest in their Marcellus Shale assets.362 Chesapeake received US$1.25 billion cash and received a further US$2.125 billion in the form of drilling and completion expenditure through 2012.363 In exchange, Statoil expects a future recovery of between 2.5 and 3.0 billion Boe and equity up to 200,000 Boepd by

359 “Gas Shale Market Report and Five-Year Forecast 2010”, Warlick International, pp. 151-168. 360 “Gas Shale Market Report and Five-Year Forecast 2010”, Warlick International, pp. 150. 361 “Gas Shale Market Report and Five-Year Forecast 2010”, Warlick International, pp. 148. 362 “Gas Shale Market Report and Five-Year Forecast 2010”, Warlick International, pp. 150. 363 ibid

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2020.364 Chesapeake and Statoil signed a second transaction that added approximately 59,000 net acres to Statoil’s 600,000 net acre positions.365 The cost of the net acreage was US$253 million.366 Industry pundits expect Statoil to increase its net acreage in the Marcellus.

Chesapeake currently is the second largest producer in the Marcellus. 2Q2010 average daily net production is 105 MMcfpd, up approximately 250 percent year-over-year.367 Average daily net production is expected to near 270 MMcfpd by end-2010.368 The company anticipates production to top 450 MMcfpd by end-2011.369 Chesapeake is currently operating 24 rigs, making it the most active driller in the Marcellus, and is anticipating this number to increase to approximately 32 rigs by the end of 2010.370 The bulk of current production comes from net acreages in Pennsylvania and West Virginia.

Not surprisingly, the company is reporting increases in efficiencies. Notably, three wells in Pennsylvania recently completed averaged 9.5 MMcfpd.371

The second major player is CNX Gas Resources, which is 83.3 percent owned by CONSOL Energy.372 The latter is the second largest coal producer in the US. CNX holds approximately 2.6 million net acres of CBM leases and 1.1 million net acres of gas shale leases.373 Recall that like shale gas, CBM is also considered unconventional natural gas. With 210 MMcfpd of gas produced in 2009, it is the largest producer in the Marcellus Shale.374

In addition, CNX is reporting increased drilling efficiencies. Their reserves per well have increased from 3.0 Bcf/well at end-2009 to 3.5 Bcf at 2Q2010.375 The companies well costs have also been decreasing, from US$5.2 million per well at end-2008 to less than US$3.5 at the end of 2Q2010.376

The third significant player in the Marcellus is the company that started it all in the Marcellus—Range Resources. Range has an attractive position in the Marcellus Shale—they hold approximately 1.3 million net acres in the Marcellus, of which 900,000 net acres are in the Marcellus Fairway (located in Pennsylvania).377 Range’s 2Q2010 net gas production is approximately 160 MMcfpd, well ahead of its mid-year targets.378 Much of this can be attributed to increases in drilling efficiencies. This has allowed the organization to invest an additional US$210

364 ibid 365 “Gas Shale Market Report and Five-Year Forecast 2010”, Warlick International, pp. 148. 366 ibid 367 http://www.oilshalegas.com/marcellusshale.html (accessed on August 27, 2010) 368 “Gas Shale Market Report and Five-Year Forecast 2010”, Warlick International, pp. 157. 369 ibid 370 ibid 371 http://www.oilshalegas.com/haynesvilleshale.html (accessed on August 15, 2010) 372 “Gas Shale Market Report and Five-Year Forecast 2010”, Warlick International, pp. 158. 373 ibid 374 ibid 375 “Gas Shale Market Report and Five-Year Forecast 2010”, Warlick International, pp. 163. 376 ibid 377 ibid 378 http://www.oilshalegas.com/marcellusshale.html (accessed on August 27, 2010)

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million of capital into the Marcellus project.379 The company estimates a year-end production of between 180 and 200 MMcfpd and production to increase to between 360 and 400 MMcfpd by end-2011.380

Figure 2.13 illustrates the increases in drilling efficiency for Range in the Marcellus Shale. Lateral lengths have increased from 1,800 ft. in 2006 to 3,100 ft. in 2009. Similarly frac stages over the same time period increased from three to ten.

Figure 2.13 Hydraulic Frac’ing Job Size for Range Resources

12 10 10 8 8 7

6 5.1

4 3 2.7 2.5 3.1 3.1 1.8 2.2 2.2 2

0 2006 2007 2008 2009

Lateral Length (M ft.) Fluid (MM Gal.) Frac Stages (#)

Source: Range Resources – April 2010 & Gas Shale Market Report 2010381

Range signed an agreement with MarkWest in 2008 to increase its gathering, treatment and transportation infrastructure.382 2Q2010 capacity is 155 MMcfpd with another 30 MMcfpd added by end-2010.383 An additional 150 MMcfpd is scheduled to be added by 1Q2011.384

Other large players with large leaseholds are EXCO/BG (186,000 net acres), EOG Resources (230,000 net acres), Chief Oil & Gas (500,000 net acres), Atlas/Reliance (519,000 net acres). Most of these companies are ramping up drilling efforts as well.

Development Outlook & Drilling Forecasts Like the Haynesville, the Marcellus is one of the most attractive plays in the US. With technology advances and drilling efficiencies increasing, the price of natural gas appears to be less of a factor compared to other plays.

379 ibid 380 “Gas Shale Market Report and Five-Year Forecast 2010”, Warlick International, pp. 163. 381 “Gas Shale Market Report and Five-Year Forecast 2010”, Warlick International, pp. 177. 382 ibid 383 ibid 384 http://www.oilshalegas.com/marcellusshale.html (accessed on August 27, 2010)

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Between the positive economics and the plays incredible gas-in-place potential, drilling activity in the Marcellus is expected to increase. The plays low threshold price is certainly a distinct advantage.

Figure 2.14 is a drilling forecast for the Haynesville Shale for the period 2009-14. The Figure illustrates two cases: the high case and low case. Drilling estimates are provided by Warlick International, May 2010.385

Figure 2.14 Drilling Forecast for the Marcellus Shale

1750

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0 2009 2010 2011 2012 2013 2014

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Source: Warlick International, May 2010

As suggested previously, there are three major players that most affect the Marcellus Shale. All three appear to be sustaining or ramping up drilling activity. Other E&Ps are following their lead.

Chesapeake, also a leader in the growing Haynesville, is currently operating 24 rigs, making it the most active driller in the Marcellus. The company is anticipating this number to increase to approximately 32 rigs by the end of 2010.386 CNX’s position in the Marcellus is also quickly on the rise. The company expects to increase its net acreage.387 For the remainder of 2010 CNX intends to drill approximately two dozen wells with a drilling budget of US$ 110 million.388 Range is currently running a 13-rig program and is planning to operate a 50-rig program in the near future.389

385 “Gas Shale Market Report and Five-Year Forecast 2010”, Warlick International, pp. 193. 386 ibid 387 http://www.oilshalegas.com/marcellusshale.html (accessed on August 27, 2010) 388 ibid 389 “Gas Shale Market Report and Five-Year Forecast 2010”, Warlick International, pp. 164.

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Additional Information As previously mentioned the Marcellus Shale straddles several states, Pennsylvania, West Virginia, New York and Ohio. The majority of drilling is taking place in Pennsylvania and West Virginia. The latter being a distant second. As such New York and Ohio are not discussed in this study.

On the Pennsylvania side of the Marcellus, the Department of Environmental Protection (DEP) is a very large agency and includes 16 bureaus, including the Bureau of Oil & Gas Management.390 The latter oversees all field, be it oil or gas, operations in the State (Commonwealth) of Pennsylvania. This includes drilling, completion, production, pipeline transport and all environmental such as the Clean Streams Law, Solid Waste Management Act and the Water Resources Planning Act.391 The Bureau’s Field Operations inspects well sites according to applicable laws.

While the GIP is enormous and the economics are favourable, the complex topography often complicates building infrastructure and moving rigs in the Marcellus.392 In addition, fragmented land ownership complicates matters, creating severe transportation bottlenecks.393 Needless to say the Bureau is very busy.

In spite of this generally positive stance, the Bureau of Oil & Gas Management is particularly careful regarding the environmental impacts. Especially considering how quickly the industry is ramping up activity in the Marcellus. Other issues that are high profile are frac’ing and the regulation of water and fluids. Frac’ing is a major concern in Pennsylvania and has led to the Fracturing Responsibility & Awareness of Chemicals (FRAC) Act.394 The legislation was introduced by Pennsylvania Senator Casey in June 2009.395 Thus far, the oil and gas industry has been granted exemption from disclosing chemicals used in hydraulic frac’ing.396 Water regulation is a hot topic in the Marcellus Shale play. Regulatory authorities have been increasingly committed to testing, overseeing and evaluating fluids used and produced by the oil and gas industry.397

On the West Virginia side of the Marcellus, the Oil & Gas Conservation Commission (OGCC) and the Department of Environmental Protection oversees all regulatory and environmental issues with regard to the oil and gas industry.

The New Albany Shale, Illinois Basin, Illinois/Indiana/Kentucky

Geology and Basin Metrics The New Albany Shale is situated in the states of Illinois, Indiana and Kentucky. The Devonian and Mississippian- aged shale is located in the vast Illinois Basin and derives its name from New Albany, Indiana.

Figure 2.15 illustrates the New Albany Shale. As illustrated by the cluster of purple on the map, while most of the New Albany lies in the state of Illinois, most drilling activity is occurring in the south of Indiana and western

390 “Gas Shale Market Report and Five-Year Forecast 2010”, Warlick International, pp. 187. 391 ibid 392 “From Shale to Shining Shale”, Deutsche Bank, July 22, 2008, pp. 35. 393 ibid 394 ibid 395 ibid 396 ibid 397 ibid

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Kentucky. As previously mentioned, the New Albany Shale is in large part correlative with the Antrim Shale, located in the northern part of Indiana and Michigan.398 The New Albany is a part of the Illinois Basin.

Figure 2.15 New Albany Shale Map

Source: http://www.shalewiki.org399

Like the Antrim Shale, it is not categorized as one of the US’s big five shale—Woodford, Haynesville, Fayetteville, Marcellus and the Barnett. The New Albany, however, is a commercially-producing shale.400 In fact, the play has been producing as early as 1858 and over 600 wells prior to 1994 have been drilled.401 While the area has produced gas in small quantities for well over a hundred years, it is not until recent times that the organic-rich black New Albany shale is attracting attention. Much of this is attributed to advancements in drilling technology.

Technically recoverable estimates in the New Albany Shale range between 1.9 Tcf and 19.2 Tcf of natural gas.402 This makes it one of the larger shale plays in North America. According to the GTI, gas resource estimates for the New Albany Shale range from 86 to 160 Tcf;403 this certainly places the shale play in the top five shale plays in the US. In addition to gas resources, the New Albany is also a deposit of oil shale and is estimated to hold up to 189,000 106 barrels of oil.404 These estimates, in combination with improved drilling technology, have

398 Indiana Geological Survey website, New Albany Shale, http://igs.indiana.edu/geology/structure/compendium/html/comp82hw.cfm (accessed on September 23, 2010) 399 http://www.shalewiki.org/index.php?n=BarnettShale.OtherShales. (accessed on September 23, 2010) 400 “From Shale to Shining Shale”, Deutsche Bank, July 22, 2008, pp. 9. 401 http://www.energyindustryphotos.com/new_albany_shale.htm (accessed on September 20, 2010) 402 “Shale Gas Exciting Again”, AAPG, http://www.aapg.org/explorer/2001/03mar/gas_shales.cfm (accessed on September 20, 2010) 403 New Albany Shale Gas Research Project, GTI Presentation, Kent F. Perry, October 2009, pp. 8. 404 Dyni, J.R.,2006 Geology and resources of some world oil-shale deposits: U.S. Geological Survey Scientific Investigations Report 2005-5294.

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attracted the attention of various E&Ps. The New Albany, however, still lags behind the better known shale gas plays.

The New Albany Shale has black, brown and greenish organically-rich shale. It commonly contains minor beds of dolomite and .405 Similar to the Marcellus, the New Albany also contains pyrite and uranium.406 The New Albany Shale lies at a depth range of 1,000-4,500 ft., which is considered quite shallow. The Fayetteville Shale, which is the shallowest range of the leading five shales in the US, lies between 1,500 and 6,000 ft. In terms of thickness and porosity, the New Albany Shale is 100-300 ft. and 10.0-14.0 percent, respectively. The New Albany Shale has a TOC content of 1.0-25.0 percent and has a thermal maturity of 0.4-1.0 Ro. The pressure gradient for the New Albany Shale is 0.43 psi/ft.

Table 2.14 provides a summary of Fayetteville’s key geological characteristics.

Table 2.14 New Albany Geological Characteristics Parameter New Albany Shale Geological age Devonian Depth range (ft) 1,000-4,500 Shale thickness (ft), gross 100-300 GIP/sq mi (Bcf) 8.0-20.0 Porosity (%) 10.0-14.0 Total organic carbon (%) 1.0-25.0 Thermal maturity (Ro) 0.4-1.0 Silica content (%) n/a Pressure gradient (psi/ft) 0.43 Source: Deutsche Bank, 2008.407

While compared to the five leading US shale plays, the New Albany Shale is the shallowest (1,000-4,500 ft.) and is relatively thick. Along with a similar thermal maturity in parts (0.4-1.0 Ro) and total organic content (1.0-25.0 percent), this has led several industry pundits to compare the New Albany with the Barnett Shale. There are, however, several differences as well. The geology in the New Albany is regarded as complex and the shale is considered both low permeability and low in silica content.408 In addition, due to the shallowness of the shale, the New Albany is considered normal pressure. Generally speaking, producers target areas that are over-pressured, not normal. This can make extraction more complicated. While the GIP is attractive, there are several factors that can make developing the New Albany challenging.

Table 2.15 provides the basin metrics for the New Albany Shale.

Table 2.15 Basin Metrics for the New Albany Shale Parameter New Albany Shale

405 Lazar, Remus and Juergen Schieber, “New Albany and Ohio Shales: An Introduction”, pp.2 406 Lazar, Remus and Juergen Schieber, “New Albany and Ohio Shales: An Introduction”, pp.4 407 “From Shale to Shining Shale”, Deutsche Bank, July 22, 2008, pp. 32. 408 New Albany Shale Gas Research Project, GTI Presentation, Kent F. Perry, October 2009, pp. 21.

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Well Cost ($MM) 0.8-1.0 Depth (ft) 1,000-4,500 IP Rate (MMCFPD) 2.0 EUR/Well (BCFE) 1.0-1.1 Threshold Price ($/MCFE) n/a F&D Cost ($/MCFE) 1.00 Expected Recovery Factor (%) 10-20 Lateral lengths (ft) 3,000-4,000 Fracturing stages None - unstimulated Typical Well Spacing (acres/well) 320 Source: Simmons & Co., various company reports.409

E&P Players and Recent M&A Activity As mentioned previously, most of the drilling activity is occurring in western Kentucky and southwestern Indiana. More specifically, Rough Creek Graben and the Fairfield Subbasin are attracting attention.410 This is illustrated in Figure 2.16.

Figure 2.16 Map of the Illinois Basin and the New Albany Shale

Source: www.energyindustryphotos.com

It is also interesting to note that while the majority of the Illinois Basin lies in the state of Illinois, not a lot of drilling occurs in Illinois.411 Small tracts of land, complicated titles and high brokerage costs may be several of the

409 “From Shale to Shining Shale”, Deutsche Bank, July 22, 2008, pp. 32. 410 http://www.energyindustryphotos.com/new_albany_shale.htm (accessed on September 20, 2010) 411 “The New Albany Shale Update, The Discovery Group, Bob Cluff, 2006 IOGA Shale Presentation, pp. 26.

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reasons.412 As previously mentioned, this acreage is old oil and coal country, and may not have the infrastructure to accommodate gas producers.

Currently, the active operators are Atlas America, Aurora Oil & Gas, BreitBurn Energy Partners, Carrizo Oil & Gas, CNX Gas, Continental Resources, Deka Exploration, Diversified Operating, El Paso, Forest Oil, NGAS Resources, Noble Energy, Trendwell Energy and Rex Energy.

The following will discuss the several players in the New Albany Shale: Atlas Energy, CNX Gas and BreitBurn Energy Partners (BBEP).

Atlas Energy is an independent gas developer and producer, with operations in Appalachian Basin, the Michigan Basin and the Illinois Basin.413 More specifically, and previously mentioned, the company is an active producer in the Marcellus Shale of western Pennsylvania, the Antrim Shale, the Chattanooga Shale of northeastern Tennessee and the Antrim Shale.414

Most of their 270,000 net acres of land holdings within the New Albany are in west central Indiana, in the counties of Sullivan, Knox, Greene, Owen, Clay and Lawrence.415 The company planned to drill over one hundred wells on its land holdings by the end of 2009. A farmout agreement, signed with Aurora Oil & Gas in 2008, requires that Atlas drill a minimum of 20 wells annually and grants Aurora the right to participate for 25 percent.416

The second major player is CNX Gas Resources in the New Albany Shale. While the company holds 486,000 net acres in the Appalachian Basin, including 161,000 in the heart of the Marcellus, the company holds 300,000 net acres in the New Albany.417 Of their 300,000 net acres in the New Albany, approximately 70,000 net acres are leased from Atmos Energy and Teal Royalties LLC and are oil and gas potentials; they are located in western Kentucky.418 Their acreage in the New Albany is estimated to hold 300 Bcf of gas, in addition to having potential for conventional oil production as well.419 CNX also holds 573,000 net acres in Illinois for CBM potential.420 It is important to note that CONSOL Energy, the second largest coal producer in the US, owns 83.3 percent of CNX.

CNX is reporting drilling efficiencies in the Marcellus and hope to translate that advantage in their various shale holdings, including the New Albany. Recall that CNX is a major player in the Marcellus Shale, holding approximately 2.6 million net acres of CBM leases and 1.1 million net acres of gas shale leases. The company is not only focusing on the Marcellus in the Appalachian Basin but also the Huron Shale and Chattanooga Shale. The latter two are also located in the enormous Appalachian Basin.

412 ibid 413 Atlas Energy website, http://www.atlasenergy.com/operations/indiana.aspx (accessed on September 20, 2010) 414 http://www.energyindustryphotos.com/new_albany_shale.htm (accessed on September 20, 2010) 415 Atlas Energy website, http://www.atlasenergy.com/operations/indiana.aspx(accessed on September 20, 2010) 416 “Atlas Energy Enters the New Albany Shale and Plans to Drill Over 100 Horizontal Wells Before the End of 2009”, October 28, 2008, http://www.istockanalyst.com/article/viewiStockNews/articleid/2752881 (accessed on September 20, 2010) 417 Consol Energy website, http://www.cnxgas.com/newsitem.aspx?nid=13 (accessed on October 24, 2010) 418 “CNX Gas Leases New Albany Shale Acreage from Atmos Energy and Teal Royalties LLC”, May 29, 2007, http://www.highbeam.com/doc/1G1-164143911.html (accessed on October 24, 2010) 419 Consol Energy website, http://www.cnxgas.com/newsitem.aspx?nid=13 (accessed on October 24, 2010) 420 ibid

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BBEP is quickly becoming a major player in the New Albany Shale. The California-based independent oil and gas producer includes the following assets in their drilling portfolio: Los Angeles Basin (California), Wind River and Big Horn Basins (Wyoming), Permian Basin (Texas), Sunniland Trend (Florida), Antrim Shale (Northern Michigan) and the New Albany Shale (Indiana/Kentucky).421

BBEP’s New Albany and Antrim properties stem from an acquisition with Quicksilver Resources. The deal includes natural gas and midstream assets located in Michigan, Indiana and Kentucky. Completed in November 2007, the acquisition was financed with US$750 million cash and 21.348 million BreitBurn Common Units.422 BBEP acquired integrated midstream assets in the New Albany and Antrim shales, as well as an estimated 548 Bcfe of proved reserves in the two shale plays.423

BBEP currently holds over 260,000 net acres in the New Albany Shale, with estimated proved reserves of 23 Bcfe.424 Net daily production in 3Q2007 was approximately 4 MMcfpd with 212 gross producing wells; the company also cites a potential for 475 recompletions.425 Net daily average production in 2009 was 582 Boepd and reserves are estimated to be 1.2 MMBoe according to a company presentation in September 2010.426

Similar to Atlas, BBEP cites their ownership of regional infrastructure in the GTG/Cardinal pipeline system as a key to future development.

Development Outlook & Drilling Forecasts Technological advances and increasing drilling efficiencies appear to be offsetting lower gas prices. And while there are attractive geological attributes in the New Albany Shale, there are also potential challenges427—low permeability, low silica content and unpredictable geology are several. The New Albany’s excellent GIP potential and proximity to the market and pipeline infrastructure are also positive. Its proximity to other attractive shales, such as the Marcellus Shale, the Chattanooga Shale and the Antrim Shale may be stealing some of the spotlight of the potential in the New Albany Shale.

All things considered, drilling activity is expected to increase—albeit moderately—in the New Albany Shale.

Additional Information The Division of Oil and Gas oversees oil and gas activities within Indiana, from exploration and development to drilling and decommissioning.428 This increasingly busy department is under the Indiana Department of Natural Resources. This enormous department is divided into the following divisions, of which the Oil and Gas division is a part of: Communications, Engineering, Entomology and Plant Pathology, Fish and Wildlife, Forestry, Heritage Trust,

421 BreitBurn energy Partners, Credit Suisse Energy Summit, February 2008, pp. 3. 422 BreitBurn energy Partners, Credit Suisse Energy Summit, February 2008, pp. 9. 423 ibid 424 BreitBurn Energy Partners, Credit Suisse Energy Summit, February 2008, pp. 11. 425 ibid 426 BreitBurn Energy Partners, UBS MLP One-on-One Conference, Las Vegas, September 2010, pp. 3. 427 New Albany Shale Gas Research Project, GTI Presentation, Kent F. Perry, October 2009, pp. 21. 428 Indiana Department of Natural Resources website, http://www.in.gov/dnr/dnroil/ (accessed on September 23, 2010)

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Historic Preservation and Archaeology, Law Enforcement, Natural Preserves, Out Recreation, Reclamation, State Museum and Historic Sites, State Parks and Reservoirs and Water.429

The Division of Oil and Gas regulates the oil and gas industry in the Commonwealth of Kentucky.430 This includes drilling, completion, production, pipeline transport and all environmental aspects. While the first well was drilled in 1818, the Division of Oil and Gas was created in 1960.431 The oil and gas division lies within the Department for Energy Development and Independence.

The Illinois Department of Natural Resources regulates the development and use of land, energy, forestry and mineral resources in the state.432 The organization’s mandate also currently includes public safety and environmental issues. The Oil and Gas Division is one of four divisions within the Illinois DNR.433

The Woodford Shale, Oklahoma

Geology and Basin Metrics The Woodford Shale is located in southeastern Oklahoma and makes up the western portion of the Arkoma Basin. It is primarily located in the following counties: Hughes, Coal, Pittsburg, McIntosh, Carter, Johnston, Marshall, Bryan, Canadian, Garvin, Wagoner and Mayes.434 Figure 2.17 illustrates the Woodford Shale. The red circled areas indicate regions of special interest, including the McIntosh, Hughes, Coal, and Pittsburg counties. Hughes and Coal counties have the largest share of production.435

The Woodford Shale extends beyond Arkoma Basin, into the further south located Ardmore Basin and the Anadarko Basin, located in central Oklahoma. However, only the Woodford Shale in the Arkoma is discussed in this study. Oklahoma is home to another shale play—the Caney Shale. The Mississippian-aged shale is located in the westernmost part of the Arkoma Basin. The latter is clay rich and is often referred to as the Cana Woodford, or simply the Caney Shale.436 This play is also not discussed in this study.

429 Indiana Department of Natural Resources website, http://www.in.gov/dnr/ (accessed on September 23, 2010) 430 Energy and Environment Cabinet; Department of Natural Resources, Commonwealth of Kentucky, http://oilandgas.ky.gov/Pages/Welcome.aspx (accessed on September 23, 2010) 431 ibid 432 http://www.dnr.illinois.gov/Pages/default.aspx (accessed on October 24, 2010) 433 http://dnr.state.il.us/mines/ (accessed on September 23, 2010) 434 Fayetteville Shale Arkansas, Oil & Gas Mineral Services, http://www.mineralweb.com/fayetteville-shale- arkansas-a-290.html (accessed on October 22, 2009) 435 “Gas Shale Market Report and Five-Year Forecast 2010”, Warlick International, pp. 52. 436 AAPG website, http://www.aapg.org/explorer/2006/11nov/shale_play.cfm (accessed on November 7, 2010)

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Figure 2.17 Woodford Shale Map

Source: http://www.shalewiki.org/index.php?n=BarnettShale.OtherShales.

According to Oil & Gas Investor, the Woodford Shale is estimated to be more than 10 Tcf.437 Other estimates suggest that the original gas-in-place is 23 Tcf, with technically recoverable resources estimated at 11.4 Tcf. 438 While smaller geographically than other shale plays in the US, it is drawing a lot of attention from E&P companies. Although geologists have known about the Upper Devonian/Lower Mississippian-aged shale for many years, it was largely ignored until recently. As with other shale plays, like the neighbouring Fayetteville Shale, advancements in technology have encouraged exploration and development in the shale play.

The Woodford Shale is a dark-gray to black shale and is predominantly an Upper Devonian-era shale.439 The Woodford Shale lies at a depth range of 6,000-13,000 ft., which is deep compared to the Fayetteville Shale and Barnett Shale. It is, however, comparable to the 7,800-13,300 ft. of the Horn River Basin located predominantly in northeast British Columbia. Most drilling in the Woodford occurs in a 6,000-8,000 ft. range.440 In terms of shale thickness and porosity, the Woodford Shale is 150-300 ft. and 6.0-8.0 percent, respectively. This is comparable to the Fayetteville Shale. The Woodford Shale is high in silica content (60-80 percent) and has a TOC content of 3.0- 10.0 percent. The pressure gradient for the Woodford Shale is 0.44 psi/ft., identical to the Fayetteville Shale.

Table 2.16 provides a summary of key geological characteristics of Oklahoma’s Woodford Shale.

437 A&D Trends, Oil & Gas Investor, August 2009, pp 15. 438 http://shale.typepad.com/woodfordshale/arkoma-basin/page/2/ (accessed on October 19,2010) 439 “Gas Shale Market Report and Five-Year Forecast 2010”, Warlick International, pp. 63. 440 “Gas Shale Market Report and Five-Year Forecast 2010”, Warlick International, pp. 50.

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Table 2.16 Woodford Shale Geological Characteristics Parameter Woodford Shale Geological age Upper Devonian Depth range (ft) 6000-13,000 Shale thickness (ft), gross 150-300 GIP/sq mi (Bcf) 25-65 Porosity (%) 6.0-8.0 Total organic carbon (%) 3.0-10.0 Thermal maturity (Ro) 1.1-3.0 Silica content (%) 60-80 Pressure gradient (psi/ft) 0.52 Source: Deutsche Bank, 2008.441

Table 2.17 provides the basin metrics for the Woodford Shale. It is important to note that the Woodford Shale has the second highest well cost among the top five shale plays in the US and has a threshold price that lies in the upper end of the spectrum; Haynesville Shale has the highest well cost.442 However, like the Marcellus Shale it has the royalty percent of the top five shale plays.

Table 2.17 Basin Metrics for the Woodford Shale Parameter Woodford Shale Well Cost ($MM) 5-6 Depth (ft) 7,500 IP Rate (MMCFD) 3.6 EUR/Well (BCFE) 4.0 Threshold Price ($/MCFE) 4.50-5.00 F&D Cost ($/MCFE) 1.48 LOE ($/MCFE) 0.80 Royalty (%) 15 Production Tax (%) 7 Decline – Yr. 1 (%) -59 Decline – Yr. 2 (%) -43 Decline – Yr. 3 (%) -32 Decline – Out Yrs. (%) -5 Source: Simmons & Co., various company reports.

E&P Players and Recent M&A Activity Currently, the more significant operators include Antero Resources, BP America, Continental Resources, Devon Energy, Newfield Exploration, St. Mary Land & Exploration, PetroQuest Energy and ExxonMobil/XTO Energy. 443 Together these companies hold exploration rights to approximately 3,885 square kilometers, or 1,500 sq. miles, of

441 “From Shale to Shining Shale”, Deutsche Bank, July 22, 2008, pp. 33. 442 “Gas Shale Market Report and Five-Year Forecast 2010”, Warlick International, pp. 62. 443 Fayetteville Shale Arkansas, Oil & Gas Mineral Services, http://www.mineralweb.com/fayetteville-shale- arkansas-a-290.html (accessed on October 22, 2009)

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land.444 While it is not realistic to discuss all these companies, it is useful to review the four major players: Newfield Exploration, ExxonMobil/XTO Energy, Devon Energy and BP America.

Like its counterpart Southwestern on the Arkansas side of the Arkoma Basin, Newfield Exploration is the key player on the Oklahoma side of the Arkoma Basin. In fact, the Woodford Shale was rediscovered by the company in 2003.445 Newfield is the largest leaseholder in the Woodford Shale, with 172,000 net acres in the play.446 Nearly 90 percent of their land holdings were held by production, up from 85 percent at the end of 2009.447

While Newfield has been the leader in the Woodford since 2003, it does not appear to relinquishing that fact anytime soon. The company has been increasing its percentage of capital spending in the play from 33 percent in 2008 to 45 percent by the end of 2009.448 Newfield currently operates approximately a third of active rigs, horizontal wells and total production in the play. In other words, they operate approximately 380 of the 1,000 horizontal completions in the Woodford.449

The higher costs of drilling in the Woodford Shale combined with weaker natural gas prices have resulted in Newfield electing to decrease gas drilling in the play.450 The company reduced their gas directed rigs from 9 in early 2010 to only 4 rigs by mid-year 2010.451 Their peak drilling year was 2008. By year end-2008 their gross production totaled 265 MMcfpd, up from 200 MMcfpd at the end of 2Q2007. In addition, by the end of 2008 Newfield operated 13 of the 45 rigs in the Woodford and owned 225 horizontal wells of the 750 horizontal wells operating in the Woodford.452 It is interesting to note that while their peak drilling year was 2008, their record production is 2Q2010. Newfield’s gross production in 2Q2010 is 370 MMcfpd, or 220 MMcfpd net.453 According to company sources, production by end-2010 is expected to be 20 percent higher than end-2009 levels.454

The company, not surprisingly, is reporting increases in efficiencies. During 2010, Newfield’s horizontal wells will be an average horizontal lateral length of approximately 6,000-7,000 feet, compared to 4,000 feet in 2009.455 This is primarily due to utilizing their new Super Extended Lateral (SXL) program.456 Their Madison1H-15W well had a reported lateral length of 9,983 feet and was completed with 20 frac stages.457

The second major player in the Woodford Shale is ExxonMobil/XTO. Prior to its acquisition by ExxonMobil, XTO Energy amassed 120,000 net acres.458 This makes it the second largest leasehold owner in the Woodford Shale. Industry pundits suggest that its 120,000 net acres will increase to accommodate for future development. In

444 ibid 445 “Gas Shale Market Report and Five-Year Forecast 2010”, Warlick International, pp. 56. 446 ibid 447 “Arkoma: Key Players”, UGcenter Arkoma Playbook, April 2009, pp 26. 448 “Arkoma: Key Players”, UGcenter Arkoma Playbook, April 2009, pp 26. 449 A&D Trends, Oil & Gas Investor, August 2009, pp 15. 450 http://www.oilshalegas.com/woodfordshale.html (accessed on August 13, 2010) 451 ibid 452 Arkoma: Key Players”, UGcenter Arkoma Playbook, April 2009, pp 26. 453 http://www.oilshalegas.com/woodfordshale.html (accessed on August 13, 2010) 454 ibid 455 ibid 456 ibid 457 “Gas Shale Market Report and Five-Year Forecast 2010”, Warlick International, pp. 56. 458 “Gas Shale Market Report and Five-Year Forecast 2010”, Warlick International, pp. 57

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addition to the Woodford and Fayetteville Shales, XTO is an important player in Marcellus Shale (280,000 net acres), Bakken Shale (450,000 net acres) and the prolific Barnett Shale (288,000 net acres). It is important to note that the Bakken is oil shale rather than gas shale. The company’s excellent position in various plays made it an excellent target for ExxonMobil to get its foot in the growing unconventional gas market game in North America. As mentioned in the previous Fayetteville Shale section, ExxonMobil announced its intent to acquire XTO Energy in December 2009.459 In the US$41 billion deal, ExxonMobil significantly enhanced its natural gas position.460

Their net gas production grew from 40 MMcfpd at the beginning of 2009 to more than 100 MMcfpd in 4Q2009.461 The latter is using seven operated rigs. According to UGcenter, in 2008, XTO produced 30 MMcfpd gross.462 ExxonMobil/XTO currently has five operating rigs in the Woodford.463 According to UGcenter, by year-end 2008, XTO produced 40 MMcfpd gross from wells ranging from 2.6 Bcf to 5 Bcf in reserves per well.464

As with the Fayetteville Shale, BP America entered the game late but made a big splash in the Woodford Shale. BP entered the play in mid-2008 by purchasing 90,000 net acres from Chesapeake Energy.465 The properties were located in Atoka, Coal, Hughes and Pittsburg counties and produced approximately 50 MMcfpd.466 The purchase represented an exit from the Woodford Shale for Chesapeake Energy, currently holding no leases in the Oklahoma side of the Arkoma Basin. The Woodford purchase was worth US$1.75 billion.467 Recall that BP bought 25 percent of Chesapeake’s holding in the Fayetteville Shale, now controlling 135,000 net acres and 45 MMcfpd of natural gas gross production in the heart of the Fayetteville Shale.468 The latter was worth nearly US$1.9 billion.

Currently, BP has approximately 182,000 net acres in the Woodford Shale with its production reported to be approximately 200 MMcfpd.469

The fourth major player in the Woodford Shale is Devon Energy. The organization drilled 131 wells in 2008 and operated 25 wells in 2009 in the Woodford Shale.470 The company is also a major player in the Cana-Woodford, where it holds 180,000 net acres.471 Recall the Cana-Woodford is located west of Oklahoma City and is the western extension of the Arkoma Basin. They drilled 41 wells in 2009 in the Cana-Woodford and plan approximately 80 wells in 2010.472

459 “Gas Shale Market Report and Five-Year Forecast 2010”, Warlick International, pp. 32. 460 “Gas Shale Market Report and Five-Year Forecast 2010”, Warlick International, pp. 32. 461 “Gas Shale Market Report and Five-Year Forecast 2010”, Warlick International, pp. 79. 462 “Key Players”, UGcenter Arkoma Playbook, April 2009, pp 27. 463 http://www.oilshalegas.com/fayettevilleshale.html (accessed on August 13, 2010) 464 Arkoma: Key Players”, UGcenter Arkoma Playbook, April 2009, pp 37. 465 “Gas Shale Market Report and Five-Year Forecast 2010”, Warlick International, pp. 54. 466 Arkoma: Key Players”, UGcenter Arkoma Playbook, April 2009, pp 17. 467 “Gas Shale Market Report and Five-Year Forecast 2010”, Warlick International, pp. 54. 468 Edt Peggy Williams, “The Arkoma Shales”, UGcenter Arkoma Playbook, April 2009. 469 “Gas Shale Market Report and Five-Year Forecast 2010”, Warlick International, pp. 54. 470 “Gas Shale Market Report and Five-Year Forecast 2010”, Warlick International, pp. 55 471 ibid 472 “Gas Shale Market Report and Five-Year Forecast 2010”, Warlick International, pp. 54.

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Development Outlook & Drilling Forecasts Figure 2.18 is a drilling forecast for the Woodford Shale for the period 2009-14. The Figure illustrates two cases: the high case and low case. Drilling estimates are provided by Warlick International, May 2010.473

Figure 2.18 Drilling Forecast for the Woodford Shale

300

250

200

150

100

50

0 2009 2010 2011 2012 2013 2014

High Case Low Case

Source: Warlick International, May 2010

Recall that the Woodford is relatively deep at approximately 7,500 ft., one of the reasons that well costs range from US$5-6 million. While technology advances and drilling efficiencies are increasing, the price of natural gas appears to be a factor. As suggested previously, there are four major players that can affect the Woodford Shale. With BP America’s plans unidentified and Devon appearing to be focusing on the Cana Woodford, this only leaves Newfield and ExxonMobil/XTO as major players that can really influence the play.

Newfield appears to be resigned to operate four rigs for the remainder of the year, down from nine at the beginning of 2010.474 The company is expanding operations and investments to their oil plays.475 While having success in the Woodford, it seems that the price of natural gas and the shear economics of oil is simply too attractive. On the other hand, while ExxonMobil/XTO has significant other potential wells, their activity for the remainder of 2010 will most likely depend on integrating plans between ExxonMobil and XTO.

The activities of smaller operators could have a cumulative impact, but the two markers for the Woodford Shale are Newfield and ExxonMobil/XTO.

473 “Gas Shale Market Report and Five-Year Forecast 2010”, Warlick International, pp. 70. 474 “Gas Shale Market Report and Five-Year Forecast 2010”, Warlick International, pp. 56. 475 http://www.oilshalegas.com/woodfordshale.html (accessed on October 19, 2010)

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Additional Information The Oil and Gas Conservation Division, a part of the Oklahoma Corporation Commission (OGC), oversees all field operations. This includes drilling, completion, production, pipeline transport and all environmental aspects of all of the aforementioned.

It is important to note that Oklahoma is third largest gas producer in the US, behind Texas and Wyoming.

February 2011 North American Natural Gas Dynamics: 75 Shale Gas Plays in North America – A Review Chapter 3 Emerging/Exploratory Shale Plays

Chapter 3 discusses emerging and exploratory shale plays in North America. This chapter is divided into seven sections: the Eagle Ford and Pearsall Shale, the Floyd-Neal Shale, the Hilliard-Baxter Shale, the Montney Shale and the Muskwa/Ootla (Horn River Basin) Shale, the Utica Shale and Other Shale Plays. Each shale play is divided into four sections: geology and basin metrics, E&P players and recent M&A activity, development outlook and drilling forecasts, and additional information.

Unlike the previous sections that are divided into four sections, the other shale gas plays section only discusses the geology and basin metrics of the particular shale gas play. The five shale gas plays discussed in this section are the Barnett-Woodford Shale, the Chattanooga Shale, the Gothic-Hovenweep Shales, the Mancos Shale and the Pierre Shale.

The Eagle Ford Shale and Pearsall Shale, Maverick Basin, Texas

Geology and Basin Metrics The Eagle Ford Shale is situated in the state of Texas, south of Houston and adjacent to the Gulf of Mexico. The play is located in the Maverick Basin and extends to the Mexican border. The -aged Eagle Ford takes its name from the town of Eagle Ford where the outcrops peak through to the surface. The town is now a suburb of Dallas. The play is roughly 80 kilometers wide and nearly 650 kilometers long.476

Figure 3.1 illustrates the Eagle Ford Shale. Figure 3.1 Eagle Ford Shale Map

Source: http://info.p2es.com/Portals/60430/images//Eagle-Ford-Shale-Counties.jpg

476 Railroad Commission of Texas website, http://www.rrc.state.tx.us/eagleford/index.php

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The highlighted blue areas identify various counties where the emerging shale is primarily located. Natural gas can be found in the counties of Atascosa, Wilson, Gonzales, Karnes, De Witt, McMullen, Live Oak, Frio, La Salle, Duval, Zavala, Maverick, Dimmit, Webb and Zapata.477 The heart of Eagle Ford activities occur in the blue-shaded counties above, with McMullen County being the center.

While not categorized as one of the US’s big five shale—Woodford, Haynesville, Fayetteville, Marcellus and the Barnett—the Eagle Ford, while not commercially producing shale is quickly becoming a very significant shale play.478 This is especially true considering the sheer activity in 2010. In fact, the play is often used in the same sentence as the potentially prolific Haynesville Shale.

The area is best known for its gas, gas-carbonates and oil production, but the shale element is growing dramatically. It is not until the last couple of years, particularly 2010, that the organic-rich black Eagle Ford Shale is attracting attention. Much of this is attributed to advancements in drilling technology.

Figure 3.2 illustrates the geology of the Eagle Ford Shale. The Eagle Ford lies below the Cretaceous-aged Austin Chalk, which stretches across Texas, Louisiana and Mississippi. The Austin Chalk, drilled since the 1920s, is currently producing natural gas and oil.479 The advent of horizontal drilling is enhancing productivity of the Austin Chalk reservoirs.480

Figure 3.2 Schematic Geology of the Eagle Ford Shale

Source: http://reference.findtarget.com/search/Eagle%20Ford%20Formation/

477 http://oilshalegas.com/eaglefordshale.html (November 24, 2010) 478 http://info.p2es.com/blog/?Tag=eagle%20ford%20shale%20play 479 http://www.oilshalegas.com/austinchalk.html (November 28, 2010) 480 ibid

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There is another important, but lesser known shale in the Maverick Basin. The Pearsall Shale is located in southwest Texas. The Pearsall Shale is located on the Rio Grande River in the counties of Maverick, Dimmit and Webb, located adjacent to the Mexican border.481 The Jurassic to Cretaceous-aged shale has both oil and gas reserves. While smaller than its Eagle Ford counterpart, the Pearsall has attracted several large and experienced companies—including TXCO Resources, Anadarko and EnCana.482 The CBM and shale gas potential is raising eyebrows in the Pearsall Shale.483

While the estimates of the Eagle Ford and Pearsall Shale are unknown, the resource potential is thought to be significant for both oil and gas.484 EOG Resources, on their 505,000 acreage alone, estimates over 900,000 barrels of recoverable oil and calls it the largest oil discovery in the last four decades.485 This has led industry pundits to speculate that the Eagle Ford may hold billions of recoverable barrels of oil and trillions of cubic feet of gas.486 This sentiment is shared by Haliburton. The company suggests that early core analysis show that the Eagle Ford Shale may be have the potential to be one of the highest quality shale reservoirs in the US.487 ConocoPhillips suggests that the Eagle Ford formation could be as big as the Haynesville.488

The Eagle Ford and Pearsall Shale lies at a depth range of 6,000-11,500 ft., which is comparable to the Barnett Shale which is at 6,500-9,000 ft. This depth is considered ideal in that the shale is more likely to be over pressured and easier to extract, rather than at normal pressure. In terms of thickness, the Eagle Ford and Pearsall Shale is 600-750 ft.; this is comparable to the Barnett Shale. The Barnett Shale’s thickness is 200-1,000 ft. in the Core/Tier 1 and 100-250 ft. in the South/Western. The Eagle Ford and Pearsall Shales have a GIP/sq mi of 100-300 Bcf and an IP rate of 1.0 MMcfpd. While it is too early to tell, initial testing from Petrohawk Energy is very encouraging; indicating that gas in place is 180-210 Bcf/sq mi, porosity of 9.4-10.7 percent and has TOC content of 4.4-4.7 percent.489

Table 3.1 provides a summary of Eagle Ford & Pearsall’s key geological characteristics.

481 http://capitalsolutionsbancorp.com/blog/us-shale-plays-marcellus-pearsall-new-albany-and-woodford (November 28, 2010) 482 Maverick Basin, Robert Clarke, Oil & Gas Investor, August, 2007. 483 ibid 484 http://stocks.investopedia.com/stock-analysis/2010/foreigners-agree-eagle-ford-shale-the-place-to-be-ceo- chk-sto-tlm-pxd-pxp-mhr1012.aspx (November 28, 2010) 485 http://www.oilshalegas.com/eaglefordshale.html (November 29, 2010) 486 http://eaglefordshaleblog.com (November 29, 2010) 487 http://www.halliburton.com/ps/default.aspx?navid=1614&pageid=3027 (November 29, 2010) 488 http://oilshalegas.com/eaglefordshale.html (November 29, 2010) 489 “The Eagle Ford Shale: A Major New Gas Play?”, April 23, 2009, http://geopetesview.blogspot.com/2009/04/eagle-ford-shale-major-new-gas-play.html (November 29, 2010)

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Table 3.1 Eagle Ford & Pearsall Shale Geological Characteristics Eagle Ford & Parameter Pearsall Shale Geological age Upper Mississippian Depth range (ft) 6,000-11,500 Shale thickness (ft), gross 600-750 GIP/sq mi (Bcf) 100-300 IP Rate (MMCFPD) 1.0 Pressure gradient (psi/ft) n/a Source: Deutsche Bank, 2008.490

E&P Players and Recent M&A Activity E&Ps have been active in the Eagle Ford Shale in 2010, making it one of the hottest shale plays in the US. The Eagle Ford illustrates the dynamic and ever changing world of shale gas. Several years ago many maps indicating major shale plays in the US did not even show the Eagle Ford, and only a few showed the Pearsall Shale in southwestern Texas.

Today, the Eagle Ford and Pearsall Shales have attracted some of the energy industries largest and most experienced players. And the activity is not only centered in shale, but in oil and conventional gas as well. This is especially true after EOG Resources announced its major oil discovery in its South Texas Eagle Ford wells earlier in 2010.491

Chesapeake Energy, Apache Corporation, ConocoPhillips, ExxonMobil, , Cabot Oil & Gas, Pioneer Natural Resources, Petrohawk Energy, Anadarko Petroleum and SM Energy are just several of the most active shale gas players in the Eagle Ford. On the oil side of things the most active players are , Penn Virginia, Comstock Resources, Petrohawk and Carrizo Oil & Gas. Figure 3.3 illustrates the areas of recent activity in the Eagle Ford Shale, as well as the companies involved and their current projects. Wells in the deeper portion of the shale produce dry gas whereas wells in the northeastwardly direction produce more liquids.492 As of November 8, 2010, the Texas Railroad Commission permitted 851 wells, of which 252 were completed in the Eagle Ford Shale.493 Most of the wells permitted are in Webb, McMullen, Karmes and La Salle counties.

490 “From Shale to Shining Shale”, Deutsche Bank, July 22, 2008, pp. 39. 491 http://oilshalegas.com/eaglefordshale.html (November 29, 2010) 492 http://www.rrc.state.tx.us/eagleford/index.php (November 29, 2010) 493 http://www.rrc.state.tx.us/eagleford/images/EagleFordShalePlay201011_large.jpg (December 11, 2010)

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Figure 3.3 Eagle Ford Shale Activity

Source: http://www.doxaenergy.com/_resources/DoxaEagleFordShaleTrend.jpg

The following will discuss Chesapeake, Petrohawk and ConocoPhillips in greater detail.

Petrohawk is neither the largest company nor the largest player in the Eagle Ford but it drilled the first well in the play in 2008.494 In doing so, it discovered the Hawkville Field in Las Salle County. The well flowed at a rate 7.6 MMcfpd and was drilled to a total vertical depth of 11,141 ft. and 3,200 ft. laterally.495 And they haven’t turned back. As of 3Q2010, the total number of wells operated by Petrohawk is 75, 52 of which are located in Hawkville Field and 21 located in Black Hawk.496 The remaining two are located in nearby Red Hawk.497 After its initial success, Petrohawk began to acquire land. Currently, the company controls over 280,000 net acres in the aforementioned regions. In Hawkville Field, the ten most recent wells completed average 6.2 MMcfpd and 240 Bcfpd.

Interestingly, Petrohawk was also one of the first to discover parts of the potentially massive Haynesville Shale.498

494 ibid 495 ibid 496 http://oilshalegas.com/eaglefordshale.html (November 29, 2010) 497 ibid 498 http://oilshalegas.com/eaglefordshale.html (November 29, 2010)

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Soon after Petrohawk’s results were revealed, other companies began to acquire land in the shale, the largest being Chesapeake. The company holds approximately 550,000 net acres in the Eagle Ford Shale, of which approximately 150,000 net acres were acquired in 1Q2010.499 Chesapeake has drilled and completed seven wells to date (3Q2010) and anticipates operating five rigs by end-2010.500 Chesapeake’s most notable wells completed yielded the following results:

• PGE Browne 1-H in Webb County, 24-hour rate of 11.2 MMcfpd

• Lazy A Cotulla 1H in Dimmit County, 24-hour rate of 5.9 MMcfpd

• Traylor North 1H in Zavala County, 24-hour rate of 5.9 MMcfpd

It is important to note that China National Offshore Oil Corporation (CNOOC) is in negotiations with Chesapeake over acquiring one-third of their stake in the Eagle Ford.501 As of October 12, 2010, CNOOC is planning on paying Chesapeake US$2.2 billion over two stages.502 The first being US1.1 billion and then funding 75 percent of Chesapeake’s drilling costs for up to a second US$1.1 billion.503 The deal is sure to raise controversy. Recall that it was CNOOC that attempted to purchase US-based Unocal several years ago—rather unsuccessfully. Chesapeake had also been in negotiating with India-based Reliance Industries over a similar deal.

ConocoPhillips is the largest company that is active in the Eagle Ford Shale. It currently holds 300,000 net acres. The company is operating nine rigs active, with fifteen wells successfully drilled and completed during the 3Q2010. According to the company’s website, well costs are in the US$8-9 million per well range and the wells are averaging 1,500 Boepd (over a 30-day rate).

Development Outlook & Drilling Forecasts As previously mentioned, 2010 has been a very active year for the Eagle Ford and Pearsall Shales. This is especially true for the former. The Eagle Ford Shale is drawing some of the biggest players in the gas shale and oil shale game. EOG Resources is leading the way for oil shale development in the Eagle Ford, escalating their drilling and completions. They are currently operating rigs and plan to expand to 14 rigs by the end of 2011.504

On the gas side, Chesapeake Energy, the most active shale gas player, is expected to increase its drilling activity from averaging 5 rigs in 2010 to averaging 16 and 27 rigs in 2011 and 2012, respectively.505 Petrohawk, ConocoPhillips and Pioneer Natural Resources regard the Eagle Ford as highly prospective and appear to be

499 ibid 500 ibid 501 Foreigners Agree: Eagle Ford Shale the Place to be”, October 12, 2010, http://stocks.investopedia.com/stock- analysis/2010/foreigners-agree-eagle-ford-shale-the-place-to-be-ceo-chk-sto-tlm-pxd-pxp-mhr1012.aspx (November 29, 2010) 502 ibid 503 ibid 504 http://oilshalegas.com/eaglefordshale.html (December 9, 2010) 505 ibid

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ramping up their drilling programs in the future. Pioneer, for example, is planning to increase from 7 rigs in 2010 to drilling 70 wells in 2011, 120 wells in 2012 and 140 wells in 2013.506

The future of the Eagle Ford is bright. And while 2010 was a year of land acquisition, 2011 may be a year of M&A’s for the shale play.

In the Pearsall Shale, TXCO Resources and EnCana’s joint-venture agreement promises to be lucrative. TXCO plans to increase from three wells drilled to up to 27 more in the next year.507 Newfield Exploration is planning a multi- rig program to fully assess the oil and gas potential in the Pearsall and Eagle Ford Shales.508 The company plans to invest US$100 to drill approximately 25 wells in 2010.509

Additional Information The Texas Natural Resources conservation commission, via the Texas Railroad Commission (TRC), oversees all regulatory and environmental issues with regard to the oil and gas industry.

The Floyd-Neal Shale, Black Warrior Basin, Alabama/Mississippi

Geology and Basin Metrics The is located mostly in Alabama while the Neal Shale is located mostly in Mississippi. As the two are stratigraphically very similar, they are referred to as the Floyd-Neal Shale. The Upper Mississippian-era Floyd-Neal is located in the Black Warrior Basin Province (BWB), along the Ouachita Fold Belt.510 Also situated near the Quachita belt, to the east, is the Fayetteville Shale (Arkoma Basin, Arkansas/Oklahoma) and the prolific Barnett Shale (Fort Worth Basin, East Texas).511

Figure 3.4 illustrates the Floyd-Neal Shale and the BWB. The latter covers an area of 23,000 square miles.512

506 ibid 507 “US Shale Plays: Marcellus, Pearsall, New Albany and Woodford”, October 15, 2010, http://capitalsolutionsbancorp.com/blog/us-shale-plays-marcellus-pearsall-new-albany-and-woodford (December 8, 2010) 508Pearsall Shale, April 30, 2010, http://shale.typepad.com/eaglefordshale/pearsall-shale/ (December 7, 2010) 509 ibid 510 Bowker, Kent, Bowker Petroleum, “Recent Activity in the Floyd, Neal, and Chattanooga Shale Plays, Black Warrior Basin, Alabama and Mississippi”, 2008, pp. 8. 511 ibid 512 Ryder, R.T., Black Warrior Basin Province, USGC, pp. 1.

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Figure 3.4 Floyd-Neal Shale Map

Source: http://content.edgar-online.com/edgar_conv_img/2007/10/12/0001193125-07-217884_ G12650G64G34.JPG

There are several other shales in the region that are attracting attention. The Chattanooga Shale underlies the Floyd-Neal Shale and is separated by a band of sandstone.513 The Devonian-era Chattanooga is located in eastern Tennessee, northern Alabama, southern Kentucky and northeastern Georgia. The other shale that is garnering a fair amount of interest and excitement is the . It is located entirely in Alabama, east of the BWB, in the counties of St. Claire, Jefferson, Blount, Etowah, Calhoun and Cherokee.514 This section will discuss only the Floyd-Neal Shale.

The Floyd-Neal Shale is not commercially producing. There are, however, many operators in the play. It is categorized as an emerging play that is still being explored and developed. The geology, however, is attractive. As they were deposited at the same time, the black organic-rich Floyd-Neal Shale is geologically very similar to the Fayetteville Shale and the Barnett Shale.515

513 Geological Survey of Alabama, “An Overview of the Floyd Shale & Chattanooga Shale Gas Play In Alabama” (July 2009), pp. 4. 514 oishalegas.com/alabamashale.html (accessed October 1, 2010) 515 Bowker, Kent, Bowker Petroleum, “Recent Activity in the Floyd, Neal, and Chattanooga Shale Plays, Black Warrior Basin, Alabama and Mississippi”, 2008, pp. 1.

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While promising, the shale play still needs more capital to truly determine the plays potential and is its infancy.516 Several industry pundits suggest that the recent economic slowdown forced E&Ps to reallocate their investments into plays with better payoffs.517

The US’s Geological Survey National Assessment estimates that approximately 8.5 Tcf of gas is technically recoverable in the BWB.518 The same organization estimates 7 Tcf of technically recoverable gas in the Antrim Shale. The BWB also is estimated to contain 5.9 MMBO of oil and 7.6 MMBNGL of total natural gas liquids.519

The Floyd-Neal Shale, as previously mentioned, is similar to the Barnett and Fayetteville Shales. This will be reflected in the similar geological characteristics. The Floyd-Neal Shale lies at a depth range of 6,000-10,000 ft., which is comparable to the Barnett Shale which is at 6,500-9,000 ft. This depth is considered ideal in that the shale is more likely to be over pressured and easier to extract, rather than at normal pressure. In terms of thickness and porosity, the Floyd-Neal Shale is 80-180 ft. and 1.6 percent, respectively. The Barnett Shale’s thickness is 200-1,000 ft. in the Core/Tier 1 and 100-250 ft. in the South/Western. The Floyd-Neal Shale has a TOC content of 1.6 percent. The thermal maturity, pressure gradient and GIP/sq mi is not yet known. Recall that the Floyd-Neal is still in the exploration and production phase.

Table 3.2 provides a summary of Floyd-Neal’s key geological characteristics.

Table 3.2 Floyd-Neal Shale Geological Characteristics Parameter Floyd-Neal Shale Geological age Upper Mississippian Depth range (ft) 6,000-10,000 Shale thickness (ft), gross 80-180 GIP/sq mi (Bcf) n/a Porosity (%) 1.6 Total organic carbon (%) 1.8 Thermal maturity (Ro) n/a Silica content (%) n/a Pressure gradient (psi/ft) n/a Source: Deutsche Bank, 2008.520

Table 3.3 provides the basin metrics for the Floyd-Neal Shale.

516 “Still Waiting For The Floyd Shale”, June 3, 2009, http://stocks.investopedia.com/stock-analysis/2009/Still- Waiting-For-The-Floyd-Shale-DNR-MUR-RRC-COG-CRZO0603.aspx (accessed October 1, 2010) 517 ibid 518 “Assessment of Undiscovered Oil and Gas Resources of the Black Warrior Basin Province of Alabama and Mississippi”, U.S. Geological Survey Black Warrior Basin Province Assessment Team, pp. 3. 519 ibid 520 “From Shale to Shining Shale”, Deutsche Bank, July 22, 2008, pp. 39.

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Table 3.3 Basin Metrics for the Floyd-Neal Shale Parameter Floyd-Neal Shale Well Cost ($MM) 3.0 Depth (ft) 6,000-10,000 IP Rate (MMCFPD) <1 EUR/Well (BCFE) <1 Threshold Price ($/MCFE) n/a F&D Cost ($/MCFE) 3.50 Expected Recovery Factor (%) n/a Lateral lengths (ft) n/a Fracturing stages n/a Typical Well Spacing (acres/well) 320 Source: Simmons & Co., various company reports.521

E&P Players and Recent M&A Activity While there is no commercial production within the Floyd-Neal Shale, there are numerous operators currently active within the area. Most of the drilling activity, illustrated in Figure 3.5, is occurring north of the Quachita Belt and the Appalachian Thrust.

Figure 3.5 Map of the Floyd-Neal Drilling Activity

Source: Bowker Petroleum522

521 ibid 522 Bowker, Kent, Bowker Petroleum, “Recent Activity in the Floyd, Neal, and Chattanooga Shale Plays, Black Warrior Basin, Alabama and Mississippi”, 2008, pp. 10.

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Denbury Resources, David Arrington, Murphy Oil, Noble Energy, Bankers Petroleum, Wagner and Brown (W&B), Marlin, Cabot, Carrizo Oil and Gas, Range Resources, Resolute, Anadarko and Chesapeake are active operators or leaseholders in the Floyd-Neal. However, unlike any other play discussed thus far, there is not a single company that is taking on a lead role in developing the Floyd-Neal.523

That being said, there are several operators that bring deep pockets and experience in developing unconventional gas resources. Unfortunately for the Floyd-Neal, many of these operators were forced to divert finances and investments when commodity prices plummeted and the economy slowed down.524 As a result, E&P activities in this play slowed down. The Floyd-Neal now lags behind other plays that have surged ahead with capital investments. The Floyd-Neal will have to wait a little longer before its true potential is known.525

Carrizo Oil and Gas, Cabot Oil and Gas and Murphy Oil are excellent examples of companies with experience in other shale plays that were active in the Floyd-Neal, but have decided to focus on other more certain and lucrative plays. Carrizo currently holds 71,000 net acres in the Floyd-Neal and drilled a well before the fall in commodity prices, but has decided to concentrate its efforts on its activities in the Barnett Shale and the Marcellus Shale.526 Carrizo allocated no capital towards the Floyd-Neal in 2009 and the company’s website does not even list the Floyd-Neal in its operations.527 Cabot Oil and Gas drilled a well in the Floyd-Neal in October 2007 but have redirected their attention to the Haynesville Shale and Marcellus Shale. Cabot holds 644,015 net acres in the Floyd- Neal, making it the largest leaseholder in the play.528 The Floyd-Neal, however, does not even show on the company’s website, but Cabot did release a statement that they were encouraged by their well drilled in the BWB.529 Murphy Oil was testing the Floyd-Neal back in 2005 with three wells.530 While active in other burgeoning plays, such as the Montney Shale in British Columbia, Murphy’s activities in the Floyd-Neal are limited.

Other potential leaders in the Floyd-Neal are Denbury Resources, Range Resources and Chesapeake Oil. The organizations, as of late 2008, hold 50,000 net acres, 200,000 net acres and 565,000 net acres in the Floyd-Neal Shale, respectively.531 Denbury and Range drilled test wells in 2006 and 2007, with mixed results.532 Oklahoma City-based Chesapeake purchased half of the interest in Energen Resources, a pioneer of CBM in the BWB in the mid-1980s.533 Chesapeake is a major player in several shale plays in the US, including the Haynesville Shale, the Woodford Shale, the Fayetteville Shale, the Barnett Shale and the Marcellus Shale. The company currently owns approximately 2.8 million net acres in our natural gas shale resource plays in the US in which they have identified

523 Bowker, Kent, Bowker Petroleum, “Recent Activity in the Floyd, Neal, and Chattanooga Shale Plays, Black Warrior Basin, Alabama and Mississippi”, 2008, pp. 20. 524 “Still Waiting For The Floyd Shale”, June 3, 2009, http://stocks.investopedia.com/stock-analysis/2009/Still- Waiting-For-The-Floyd-Shale-DNR-MUR-RRC-COG-CRZO0603.aspx (accessed October 4, 2010) 525 ibid 526 ibid 527 ibid 528 ibid 529 Cabot Oil & Gas website, http://www.cabotog.com/ops_south.html (accessed October 5, 2010) 530 ibid 531 Bowker, Kent, Bowker Petroleum, “Recent Activity in the Floyd, Neal, and Chattanooga Shale Plays, Black Warrior Basin, Alabama and Mississippi”, 2008, pp. 9. 532 “Still Waiting For The Floyd Shale”, June 3, 2009, http://stocks.investopedia.com/stock-analysis/2009/Still- Waiting-For-The-Floyd-Shale-DNR-MUR-RRC-COG-CRZO0603.aspx (accessed October 1, 2010) 533 “Conasauga Saga”, Oil and Gas Investor, September 2007, pp. 2.

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approximately 19,300 net drilling locations to develop 8.7 Tcfe of total proved reserves and approximately 69 Tcfe of risked unproven reserves.534 Chesapeake is well positioned in the aforementioned major plays, which has attracted several joint ventures. In this case, however, Birmingham-based Energen’s excellent position in the Floyd-Neal Shale attracted Chesapeake, which paid US$75 million for their acreage.535 As previously mentioned, the partnership currently holds over 550,000 net acres.

Development Outlook & Drilling Forecasts Technological advances and increasing drilling efficiencies appear to be offsetting lower gas prices, and will likely factor in the future development of the Floyd-Neal Shale. Industry pundits suggest that there is potential in the shale play. However, unlike other—and better known plays—the Floyd-Neal’s potential needs more time to be realized. While there are several operators in the shale play, as previously mentioned, there is no single company is leading the charge to develop the shale play.

There are also other factors that indicate the Floyd-Neal will require more time. The geology is uncertain as it is highly folded and faulted—may lead to issues regarding well control and lost circulation issues.536

As suggested by the previously discussed Penn Energy study, the North American natural gas industry is expected to grow steadily and shale is expected to play an increasingly important role, increasing from 6 Bcfpd in 2008 to 19.3 Bcfpd in 2020 (shale gas is estimated to account for approximately 52 percent of the total production by 2020).537

With that being said, drilling activity and production in the Floyd-Neal Shale is expected to increase. However, the shale play will require more time to develop and realize its potential, as it is lagging behind its previously discussed counterparts.

Additional Information The Floyd-Neal Shale, and the BWB, is located in Alabama and Mississippi. As such this section will discuss the regulatory structure in both states.

The State Oil and Gas Board of Alabama is the regulatory agency for the oil and gas industry. It regulates drilling, completion, production, pipeline transport and all environmental aspects.538 The State Oil and Gas Board operates within the Geological Survey of Alabama. The western portion of the BWB lies under the jurisdiction of the Mississippi Oil and Gas Board (MSOGB). The MSOGB regulates oil and gas drilling in that state, enforcing rules of

534 Chesapeake Energy website, http://www.chk.com/Operations/Unconventional/Pages/Default.aspx (accessed October 2, 2010) 535 Conasauga Saga”, Oil and Gas Investor, September 2007, pp. 3. 536 “From Shale to Shining Shale”, Deutsche Bank, July 22, 2008, pp. 39. 537 North America Unconventional Gas Industry - Set to Regain Momentum Post Current Crisis - new market report published, May 14, 2010, http://www.pr-inside.com/north-america-unconventional-gas-industry-r1892947.htm (accessed on September 24, 2010) 538 State Oil and Gas Board of Alabama website, http://www.gsa.state.al.us/ogb/ogb.html (accessed on October 4, 2010)

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drilling, production, storage and disposal of wastes.539 As such, all environmental aspects of the oil and industry lie within the jurisdiction of the MSOGB as well.540

The Hilliard-Baxter Shale, Greater Green River Basin, Wyoming/Colorado

Geology and Basin Metrics The Hilliard-Baxter is located primarily in Wyoming and Colorado, and edges into Utah. The large play is sometimes referred to as the Hilliard-Baxter-Mancos or the Hilliard-Baxter-Mancos Interval, but is more commonly known as the Hilliard-Baxter Shale. Perhaps this is to reduce the confusion with the separate Mancos Shale which is located in the nearby Uinta Basin in Utah and the Piceance Basin in western Colorado. In any case, this study will refer to the shale play as the Hilliard-Baxter. Figure 3.6 illustrates the Late-Cretaceous Hilliard-Baxter Shale and the area of the Greater Green River Basin (GGRB) that it is located in. The boundary of the latter mirrors roughly the USGC’s Wyoming Landscape Conservation Initiative boundary.

Figure 3.6 Hilliard-Baxter Shale Map

Source: USGC541

539 Mississippi Oil and Gas Board website, http://www.ogb.state.ms.us/ (accessed on October 4, 2010) 540 ibid 541 Biewick, Laura R.H., “Oil and Gas Development in Southwestern Wyoming—Energy Data and Services for the Wyoming Landscape Conservation Initiative (WLCI)”, May 2009, pp. 29.

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The GGRB is a large area comprised of four large basins: the Green River Basin, the Red Desert Basin (or the Great Divide Basin), the Washakie Basin and the Sand Wash Basin.542 The latter includes the Vermillion Sub-Basin, which is home to the Baxter Shale that is attracting the attention of various E&P’s.543 The GGRB and its regional basins are best illustrated in Figure 3.7. The Sand Wash Basin is located in the northern part of Colorado, just south of the Washakie Basin. Given the various basins, the area, as anticipated, is complex geologically.

Figure 3.7 Greater Green River Basin Map

Source: http://oilshalegas.com544

There are several other shales in the Rocky Mountains that are attracting attention, however, it is pertinent to only discuss several which are in the vicinity. The Uinta Basin and the Piceance Basin are located in Utah and Colorado, respectively. Both of these basins are illustrated in Figure 3.7. The Mancos Shale is prevalent in these basins. Located south of the Piceance Basin is the Paradox Basin, in the southwestern corner of Colorado and the southeastern corner of Utah. Various E&P’s are taking notice of the Paradox Basin’s Gothic Shale and Hovenweep Shale. The other shale that is garnering interest and excitement is the Mowry Shale, located entirely in northern Wyoming, extending to the Montana Border. It is located north of the GGRB, in the Big Horn Basin. This section, however, will discuss only the Hilliard-Baxter Shale in the GGRB.

It is important to note that the Green River Basin Formation area is not only known for gas shale but oil shale as well. The Green River Basin Formation (or the Green River Shale) area includes the Greater Green River Basin with Uinta and Piceance, illustrated in Figure 3.7. While beyond the scope of this study, the Green River Basin

542 Gibson Consulting, GGRB, http://www.gravmag.com/grnriv.shtml (accessed on October 6, 2010) 543 Dolan, Michael et al., “Maturity Determinations in the Vermillion Basin-Baxter Shale: Fluid Maturity Parameters Help Interpret Charge and Migration (Abstract)”, AAPG Rocky Mountain Section, http://www.searchanddiscovery.net/abstracts/html/2008/rms/abstracts/dolan02.htm?q=%2Btext%3Avermillion (accessed on October 6, 2010) 544 http://oilshalegas.com/greenriveroilshale.html (accessed on October 6, 2010)

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Formation area is estimated to hold between 1.2 and 1.8 trillion barrels of oil.545 Even with a modest recoverable estimate, this is nearly three times greater than the proven oil reserves of Saudi Arabia.546 Nearly 80 percent of the land that contains the oil shale is owned by the US federal government, understanding the vast potential back in 1930.547 It is, however, important to note that there are various factors affecting oil shale development, including the price of oil. Various companies have federal contracts to do exploratory work in the region: Chevron, Shell Oil, IDT Corporation and OSEC.548

With the first gas field discovered in the Baxter in 1922, the play has significant history.549 The GGRB has excellent existing gas production, including the Pinedale field.550 While at home to one of the top three producing gas fields in the US, the unconventional gas resource in the GGRB is categorized as an emerging play that is being explored and developed.551

The US’s Geological Survey National Assessment estimates that approximately 11.8 Tcf of gas is technically recoverable in the Hilliard-Baxter-Mancos total Petroleum System.552 The GGRB is also estimated to contain 752.2 million barrels of total natural gas liquids.553 The EIA suggests that the GGRB contains 281 fields and estimates the basin to contain: Total Number Liquid Reserves of 177,362 Mbbl, Total Gas Reserves of 12.7 Tcf and Total BOE Reserves of 2,294,535 Mbbl.554

With an enormous potential, the Hilliard-Baxter is certainly drawing attention from operators in the industry.

While the Barnett Shale lies at a depth range of 6,500-9,000 ft., the Hilliard-Baxter lies at a depth of 10,000-19,500 ft. While the former is considered an ideal depth, in that the shale is more likely to be over pressured and easier to extract, the Hilliard-Baxter is considered very deep and over pressured. It is important to note that the Hilliard Shale and the Baxter Shales are separate but, like the Floyd Shale and Neal Shale in Alabama and Mississippi, they are stratigraphically very similar. As such they are referred to as the Hilliard-Baxter Shale. One difference, however, is that the Hilliard Shale is located deeper than the Baxter Shale. In terms of thickness and porosity, the Hilliard- Baxter Shale is 2,850-3,300 ft. and 3.0-5.5 percent, respectively. What it loses in depth, the Hilliard-Baxter Shale makes up in its remarkable thickness. The Barnet Shale’s thickness is 200-1,000 ft. in the Core/Tier 1 and 100-250 ft. in the South/Western. The Hilliard-Baxter Shale has a TOC content of 1.6 percent and has a GIP/sq mi of 440 Bcf,

545 Oil Shale and Tar Sands Programmatic EIS Information Center website, http://ostseis.anl.gov/guide/oilshale/index.cfm (accessed on October 6, 2010) 546 ibid 547 http://oilshalegas.com/greenriveroilshale.html (accessed on October 6, 2010) 548 ibid 549 ibid 550 “Shales Add to Wyoming Portfolio:, AAPG Explorer, David Brown, http://www.aapg.org/explorer/2007/05may/wyoming.cfm (accessed on October 7, 2010) 551 ibid 552 Finn, Thomas and Ronald Johnson, “Chapter 7: The Hilliard-Baxter-Mancos Total Petroleum System, Southwestern Wyoming Province”, USGC Data Series DDS-69-D, 2005, pp. 13. 553 ibid 554 EIA website, http://www.eia.doe.gov/pub/oil_gas/natural_gas/analysis_publications/ maps/GGR_LIQ.pdf (accessed on October 7, 2010)

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one of the highest of any gas shale play in the US. The thermal maturity, silica content and pressure gradient is not yet known.

Table 3.4 provides a summary of Hilliard-Baxter’s key geological characteristics.

Table 3.4 Hilliard-Baxter Shale Geological Characteristics Parameter Hilliard-Baxter Shale Geological age Late Cretaceous Depth range (ft) 10,000-19,500 Shale thickness (ft), gross 2,850-3,300 GIP/sq mi (Bcf) 440 Porosity (%) 3.0-5.5 Total organic carbon (%) 1.0-2.5 Thermal maturity (Ro) n/a Silica content (%) n/a Pressure gradient (psi/ft) n/a Source: Deutsche Bank, 2008.555

Table 3.5 provides the basin metrics for the Hilliard-Baxter Shale.

Table 3.5 Basin Metrics for the Hilliard-Baxter Shale Parameter Hilliard-Baxter Shale Well Cost ($MM) 20.0 Depth (ft) 10,000-19,500 IP Rate (MMCFPD) +10 EUR/Well (BCFE) 20 Threshold Price ($/MCFE) n/a F&D Cost ($/MCFE) 3.50 Expected Recovery Factor (%) 10 Lateral lengths (ft) 3,000-4,000 Fracturing stages n/a Typical Well Spacing (acres/well) 40-160 Source: Simmons & Co., various company reports.556

While some of the geology is attractive the high well cost (US$20 million) is most likely related to the great depth and complex geological conditions of the shale play. The gray-coloured organic-rich shale has high pressure completions and uneven results, which has led some geologists to question reservoir quality and permeability of

555 “From Shale to Shining Shale”, Deutsche Bank, July 22, 2008, pp. 37. 556 ibid

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the Hilliard-Baxter Shale.557 In addition, another factor in high drilling costs may be the fact that the GGRB is considered an environmentally sensitive region.558

The economic slowdown along with the plummeting gas prices has not helped the Hilliard-Baxter Shale.

E&P Players and Recent M&A Activity The most active operators in the Hilliard-Baxter are Devon Energy, Kodiak Oil & Gas, Samson Oil & Gas and Questar Corporation. In 2007 and 2008 several of these companies were drilling testing wells in the Hilliard-Baxter Shale. However, high costs and low IP rates, combined with the economic recession which forced companies to reallocate assets to more certain and profitable ventures, led to activities in the Hilliard-Baxter to taper.559 However, there has been more activity in the GGRB in 2010.

The following section will discuss several companies which are active in the emerging shale play, and the various M&A activity which has shaped the Hilliard-Baxter Shale thus far.

Devon Energy is the largest active and most experienced company in shale gas in the Hilliard-Baxter Shale. One of the largest independent oil and gas producers in the US, Devon is an active and well-positioned company in several major shale plays in the US and Canada. It is the most significant player in the Barnett Shale, the most prolific shale play in the US. Devon drilled 336 wells in 2009, down considerably from 2008.560 End-2009 Devon’s net production exceeded 1.25 Bcfpd while their 1Q2010 net production was 1.1 Bcfpd.561 The Dallas-based Devon is also a major player in Oklahoma’s Woodford Shale, where they drilled 131 wells in 2008 and operated 25 wells in 2009. The company is a significant player in the Horn River Basin in Northeastern British Columbia and the Cana-Woodford, where it holds 180,000 net acres.

Devon is very active in Wyoming, operating in four different areas in the state: Washakie Basin, Wind River Basin, Powder River Basin and the Big Horn Basin.562 The company produced an average of 3,000 bbl of oil per day and 244 MMcfpd.563

In the Washakie Basin, within the GGRB, Devon holds 157,000 net acres and operates more than 600 active wells in the basin.564 The company drilled 100 wells in 2009 and plans to drill an additional 115 in 2010.565 The unconventional gas side of things is, however, firmly entrenched in the back seat.

557 ibid 558 ibid 559 “Shales Gone Wild Part 2—Go West To Find Little-Known Shale Plays In The Rockies”, Oil & Gas Investor.com, http://blogs.oilandgasinvestor.com/steve/2008/07/31/shales-gone-wild-part-2-go-west-to-find-little-known-shale- plays-in-the-rockies/ (accessed on October 24, 2010) 560 “Gas Shale Market Report and Five-Year Forecast 2010”, Warlick International, pp 34. 561 http://www.oilshalegas.com/barnettshale.html (accessed on August 30, 2010) 562 Devon Energy website, Wyoming Fact Sheet, http://www.devonenergy.com/AboutDevon/Documents/Fact%20Sheets/2010%20WyomingFactSheet.pdf 563 ibid 564 ibid 565 ibid

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Devon is, however, well positioned in the Hilliard-Baxter Shale. This has likely led to two interesting M&A’s with smaller operators. The first agreement is with Denver-based Kodiak Oil & Gas, an independent energy exploration and development company whose primary focus is the Williston Basin (North Dakota, Montana and ) and Green River Basin.566 In 2007, Kodiak completed drilling operations on the Horseshoe Basin #5-3 well.567 The vertical well is located in the Baxter Shale and was drilled vertically to a depth of 13,500 ft.568 The initial 24-hour production rate was estimated at 3.0 MMcfpd and stabilized down to approximately 2.0 MMcfpd.569 Devon now operates the well after its 1Q2008 Vermillion Basin Exploration Agreement. As part of the agreement, Devon commenced drilling of 3 additional test wells with Kodiak having 50 percent working interest in each of the three wells.570 As a result of the agreement Kodiak’s interest will total 16,000 net acres in the GGRB’s Vermillion Sub- Basin.571 The agreement between the two companies was amended on August 1, 2009, and gives Kodiak access to the enormous potential of the Hilliard-Baxter Shale while allowing it to focus its efforts on the Bakken oil shale projects in the Williston Basin.572

Involved in a second exploration agreement in the Hilliard-Baxter Shale, Devon entered a joint-venture arrangement with Samson Oil & Gas. The latter is a Perth, Australia-based oil and gas producer that is getting into the unconventional oil and gas game. The company has interests in the Williston Basin, the GGRB, as well as interests in the Anadarko Basin, West Permian Basin (New Mexico/Texas) and the Gulf Coast Basin (onshore Texas).573

Samson has joined the Rubicon Unit, in the southern part of the GGRB, near Sweetwater County, Wyoming.574 The area is approximately 40,000 acres, of which Samson currently holds 6,400 net acres.575 The agreement included the Rubicon 3D seismic data, acquired by Samson.576 Samson retains 25 percent of its equity in the Rubicon in the no-cost farm-in arrangement with Devon.577 The data was delivered to Samson in September 2009 and the

566 Kodiak Oil & Gas Corp. website, http://www.kodiakog.com/operations/operations.html (accessed October 15, 2010) 567 “Vermillion Basin Deep - Baxter Shale and Frontier and Dakota Sandstone”, May 9, 2008, http://www.wikinvest.com/stock/Kodiak_Oil_%28KOG%29/Vermillion_Basin_Deep_Baxter_Shale_Frontier_Dakot a_Sandstone (accessed on October 24, 2010) 568 ibid 569 ibid 570 “Kodiak Oil & Gas Announces Definitive Vermillion Basin Exploration Agreement”, January 31, 2008, http://www.streetinsider.com/Corporate+News/Kodiak+Oil+&+Gas+%28KOG%29+Announces+Definitive+Vermilli on+Basin+Exploration+Agreement/3308268.html (accessed on October 24, 2010) 571 “Kodiak Roars Ahead with Vermillion Basin Exploration Agreement”, January 31, 2008, http://www.rigzone.com/news/article.asp?a_id=56063 (accessed on October 24, 2010) 572 Kodiak Oil & Gas Corp. website, “Kodiak Oil & Gas Corp. Reports Second Quarter 2009 Results”, http://kodiakog.investorroom.com/index.php?s=43&item=90 (accessed on October 24, 2010) 573 Samson Oil & Gas Quarterly Report, for the period ended 31 December 2009, http://samsonoilandgas.com/IRM/Company/ShowPage.aspx?CPID=1091&EID=84674454&PageName=Quarterly% 20Activities%20report , pp. 2-3. (accessed on October 24, 2010) 574 ibid 575 Samson Oil & Gas Quarterly Report for the period ended 30 June 2010, http://www.samsonoilandgas.com/IRM/Company/ShowPage.aspx?CPID=1171&EID=87936038&PageName=June% 202010%20Quarterly%20Report%20and%20Appendix%205B, pp. 4 (accessed on October 24, 2010) 576 ibid 577 ibid

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company has completed the interpretation of the data supplied.578 Samson’s 6,400 net acres includes a 3,500 ft. section of the Baxter Shale that was successfully drilled in the 1970s, recovering a significant flow of gas.579

Development Outlook & Drilling Forecasts Technological advances and increasing drilling efficiencies are offsetting lower gas prices only to an extent. And while the potential of the Hilliard-Baxter Shale is enormous, drilling costs are still too high. Several companies have drilled test wells, which will provide useful geological information for future drilling. Like the Floyd-Neal in Alabama and Mississippi, drilling activity and production in the Hilliard-Baxter Shale is expected to increase. However, the shale play will require more time to develop and realize its potential. With the highest estimated threshold price of any shale play in the US (US7.50 per MMBtu), a higher natural gas price would not harm the play either.580

That being said, the Hilliard-Baxter Shale has one of the highest GIP sq mi of any shale play in the US. Another positive for the shale play, and other shale plays in the area, is its extensive infrastructure in the region. Unlike other shale plays such as the remote Horn River Basin in northeastern British Columbia, the existing pipeline infrastructure is excellent. Figure 3.8 illustrates existing and planned pipelines in the Rocky Mountain region.

Figure 3.8 Map of Existing and Planned Pipelines in the Rock Mountains

Source: Bill Barrett Corporation

As suggested by the previously discussed Penn Energy study, the North American natural gas industry is expected to grow steadily and shale is expected to play an increasingly important role, increasing from 6 Bcfpd in 2008 to

578 Samson Oil & Gas Quarterly Report for the period ended 30 June 2010, http://www.samsonoilandgas.com/IRM/Company/ShowPage.aspx?CPID=1171&EID=87936038&PageName=June% 202010%20Quarterly%20Report%20and%20Appendix%205B (accessed on October 24, 2010) 579 ibid 580 Medlock, Kenneth B, North American Shale Gas, Russia and Europe: An Unexpected Intersection, Rice University, Presentation to the NE BC Natural Gas Summit, September, 2009, pp. 30.

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19.3 Bcfpd in 2020 (shale gas is estimated to account for approximately 52 percent of the total production by 2020).581

This play will increase but it will take time and a greater understanding of the unique challenges involved.

Additional Information The Wyoming Oil & Gas Conservation regulates the oil and gas industry in the state, regulating drilling, completion, production, pipeline transport and all environmental aspects.582 In the state of Colorado, the Colorado Oil & Gas Conservation Commission regulates the oil and gas industry, promoting responsible development of its natural resources.583 The Colorado Oil & Gas Conservation Commission operates under the jurisdiction of Colorado’s Department of Natural Resources.

The Montney Shale, British Columbia

Geology and Basin Metrics The is a mature shale and tight gas play in British Columbia, extending into Alberta. The British Columbia portion of the Montney is located south of the Horn River Basin, near , while the Alberta portion is located in the northwestern part of Alberta, near . The Montney underlies the which leads the Basin to periodically be referred to as the Montney/Doig. For the purpose of this study the play is simply referred to as the Montney.

Figure 3.9 illustrates the location of the Montney and its proximity to the Horn River Basin and the vast Colorado Group in Alberta. The latter will not be discussed in this study.

581 “North America Unconventional Gas Industry - Set to Regain Momentum Post Current Crisis”, May 14, 2010, http://www.pr-inside.com/north-america-unconventional-gas-industry-r1892947.htm (accessed on September 24, 2010) 582 Wyoming Oil & Gas Conservation Commission website, http://wogcc.state.wy.us/ (accessed on October 24, 2010) 583 Colorado Oil & Gas Conservation Commission website, http://cogcc.state.co.us/General/ MissionPage.htm (accessed on October 24, 2010)

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Figure 3.9 Montney/Doig Basin Shale Region

Source: CSUG584

The Montney is divided into four distinct intervals: Upper, Middle, Middle-Lower and Lower.585 The Upper, with nearly 90 percent of the drill activity, and Lower Montney are considered the most prolific.586 Consisting of a blend of low-permeability sandstone, siltstone, and shale, the Montney is not a pure shale gas play. It is sometimes also referred to as a tight shale play or tight gas play. The shale/sand ratios increase towards the western part of the play, as it evolves from tight gas in the east to more shale in the west.587 While most of the development to date is occurring on the eastern side of the Montney, it is the western side of the play that is attracting interest from E&P’s.588 In addition, the Montney Basin also produces oil in Sturgeon Lake and the Saddle Hills area.589

Although geologists have known about the -aged Montney formation for many years, it was largely ignored until recent years. As with other shale plays, advancements in technology and a high market price for natural gas several years ago, have encouraged exploration and development in the Montney Shale play.

Like the Horn River Basin to the north, the Montney holds substantial resource potential and opportunities for future growth. And also like the Horn River Basin, the land sale coffers are setting records. At a mid-July 2008 British Columbia Oil and Gas rights auction, records were broken when buyers paid C$610 million for rights to drill

584 http://www.gasnet.com.br/conteudos.asp?cod=8333&tipo=Artigos&categoria=11 (accessed on September 19, 2010) 585 The Full Montney, (March 2009), http://www.investingdaily.com/ce/17164/the-full-montney.html (accessed on September 19, 2010) 586 ibid 587 “Gas Potential of Selected Shale Formations in the Western Canadian Sedimentary Basin”, 2004, http://media.godashboard.com/gti/4ReportsPubs/4_7GasTips/Winter04/GasPotentialOfSeclectedShaleFormations InTheWesternCanadianSedimentaryBasin.pdf, pp. 24. 588 Assessing the Supply and Regulatory Environment for Northern Gas Development, National Energy Board, Presentation, March 2009, http://www.neb.gc.ca/clf-nsi/rpblctn/spchsndprsnttn/2009/ nrthrngsdvlpmnt/nrthrngsdvlpmnt-eng.html 589 http://chinookconsulting.ca/News/Montney.html

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in the Montney Shale area, including a whopping C$157 million for a single parcel in the heart of the Montney, just outside of Dawson Creek.590 The GIP potential of the Montney Shale is certainly attracting attention.

In 2008, the Canadian Society for Unconventional Gas (CSUG) estimated that the Montney Shale’s OGIP could be as high as 250 Tcf.591 The Gas Technology Institute (GTI) estimates that the Montney and neighbouring Doig/Doig Phosphate formations may hold over 86 Tcf.592 British Columbia provincial studies suggest that its provincial shale gas resources could be somewhere in the range of 250 Tcf to 1,000 Tcf.593 Recoverable gas volumes from shale are typically low – in the 20 percent range. However, analysts believe that the recovery factor in British Columbia’s Montney Shale could be much higher, at up to 50 percent.594 EnCana, one the major players in the play, estimates that it has 60 Tcf of original GIP on its Montney lands alone.595

The Montney Shale lies in at a depth range of 6,600-8,200 ft., which is shallower than the Horn River Basin at 7,800-13,300 ft. It is very comparable to the other shales such as the Fayetteville Shale, Woodford Shale and the prolific Barnett Shale. The Montney shale thickness and porosity average over 950 ft. and 6.0, respectively. This is considerably thicker that the Horn River Basin at 360-580 Ft. and 4.0 percent, respectively. The Barnett shale’s thickness is 150-700 ft. The Horn River Basin Shale’s thermal maturity is 1.4-2.5 Ro and has a TOC content of 2.5- 6.0 percent.

Table 3.6 provides a summary of key geological characteristics of the Montney Shale.

Table 3.6 Montney Basin Shale Geological Characteristics Parameter Montney Basin Shale Geological age Triassic Depth range (ft) 6,600-8,200 Shale thickness (ft), gross +950 GIP/sq mi (Bcf) 75-100 Porosity (%) 6.0 Total organic carbon (%) 2.5-6.0 Thermal maturity (Ro) 1.4-2.5 Silica content (%) n/a Pressure gradient (psi/ft) n/a Source: Deutsche Bank, 2008596 and Talisman, 2009.

590 oilshalegas.com/montneyshale.html (accessed on September 19, 2010) 591 F.M., Dawson, “Shale Gas in North America: Emerging Supply Opportunities”, Canadian Society for Unconventional Gas, October, 2008. 592 “Gas Potential of Selected Shale Formations in the Western Canadian Sedimentary Basin”, 2004, http://media.godashboard.com/gti/4ReportsPubs/4_7GasTips/Winter04/GasPotentialOfSeclectedShaleFormations InTheWesternCanadianSedimentaryBasin.pdf, pp. 24. 593 The Full Montney, (March 2009), http://www.investingdaily.com/ce/17164/the-full-montney.html (accessed on September 19, 2010) 594 “From Shale to Shining Shale”, Deutsche Bank, July 22, 2008, pp. 35. 595 The Full Montney, (March 2009), http://www.investingdaily.com/ce/17164/the-full-montney.html (accessed on September 19, 2010) 596 “From Shale to Shining Shale”, Deutsche Bank, July 22, 2008, pp. 35.

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Table 3.7 provides the basin metrics for the Montney Basin Shale. The geology of the Montney Basin Shale is attractive. While it is a deep play, it is also a thick shale play (360-580 ft.) with an excellent one-year decline rate (50 percent).597 The Barnett Shale is 65 percent, while many other shale plays hover between 80 and 90 percent.

Table 3.7 Basin Metrics for the Montney Shale Parameter Montney Basin Average Well Cost ($MM) 4.0-6.0 Depth range (ft) 6,800-8,200 IP Rate (MMCFPD) 5.0-10.0 Expected EUR/Well (BCFE) 2.5 Threshold Price ($/MCFE) n/a Expected F&D Cost ($/MCFE) 2.0-2.5 Expected Recovery Factor (%) Up to 50 Lateral lengths (ft) 5000 Fracturing stages 8-11 Typical Well Spacing (acres/well) 80-160 Source: Deutsche Bank, 2008598.

Production in the Montney formation is characterized by high initial flow rates, followed by steep declines and low, but stable, long-term output. Figure 3.10 displays horizontal type curves for Upper Montney and Lower Montney plays. Upper Montney is the shale located near Dawson Creek, British Columbia.

Wells generally produce between 3 to 5 MMcfpd on startup, but are followed by rapid declines to long-lived lower production rates.599

597 “Encana says Horn River ranks high as shale-gas find”, September 9, 2009, http://www.reuters.com/article/idUSN0933344420090909 (accessed on September 8, 2010) 598 “From Shale to Shining Shale”, Deutsche Bank, July 22, 2008, pp. 35. 599 “A Primer for Understanding Canadian Shale Gas”, National Energy Board, November 2009, pp. 9-10.

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Figure 3.10 Upper and Lower Montney Horizontal Type Curves

Source: Talisman Energy, Investor Presentation – NAO, May 2008.

E&P Players and Recent M&A Activity The Montney Shale has attracted a great deal of attention from major oil and gas companies in recent years and the situation, like the Horn River Basin, is dynamic. Currently, the top producers and landholders are EnCana, ARC Energy, Shell Oil, Murphy Oil Corporation and Talisman Energy Inc. Other Montney players include Advantage Oil & Gas Ltd., Approach Resources, Progress Energy Ltd., Monterey Exploration Ltd. Ensign Energy Services Inc. and Sabretooth Energy Ltd.

The following will discuss briefly the five top producers and acreage holders in the Montney: EnCana, ARC Energy, Murphy Oil Corporation, Shell Oil and Talisman Energy Inc.

Since 2005, production of natural gas from horizontal shale gas wells drilled in the Montney has risen from zero to 376 MMcfpd, and as of July 2009, 234 horizontal wells were producing from Montney shale.600

Of this EnCana is the most active operator in the Montney. Since 2005 they have had 482 rigs released, followed by Shell Canada and ConocoPhillips at 174 and 172, respectively.601

Interestingly there is only one company that is a major player in both the Horn River Basin and the Montney Shale Basin plays. That company is Calgary-based EnCana. While EnCana began purchasing land in the Horn River Basin as early as 2003, EnCana also saw the vast potential of the Montney early in the game as well. EnCana began purchasing acreage in the Montney roughly the same time they entered the Horn River Basin and now has a very

600 “A Primer for Understanding Canadian Shale Gas”, National Energy Board, November 2009, pp. 16. 601 Shale Gas Activity in British Columbia, Ministry of Energy, Mines and Petroleum Resources, April 8, 2010, pp.17.

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strong position in the emerging play.602 Their net acreage has expanded to approximately 730,000 acres, including part of the Cutbank Ridge play, making it the largest leaseholder in the Montney.603

The Montney is an excellent performing asset with their Canadian division. In 2008, EnCana drilled 82 net wells, and produced 296 MMcfpd (after royalties) from their net acreage in the Cutbank Ridge resource play.604 They have significantly ramped up their operations further, with another 60 wells drilled in 2009.605 The primary target for its operations is the Swan Lake area in the Montney play. EnCana suggests that their rate of return is quickly approaching 50 percent and a supply cost that is close to US$3.00 per Mcf.606

Net daily production in the Montney in 2009 was 4.7 MMcfpd, up from 3.7 MMcfpd in 2008.607 The company forecasts production to increase to 5.3 MMcfpd in 2010. With an estimated 60 Tcf GIP in their net acreage, EnCana has an excellent position for future development.608 They suggest that they can sustain drilling 8 to 10 wells per section to develop their Upper and Lower Montney potential.609

Fueling their increases in rates of return, as with their Horn River operations, EnCana is reporting increases in drilling efficiencies. Typical horizontal wells were up to 14,500 ft. total depth, with 10 frac stages per well and have increased to 19,500 ft. total measured depth with 14 frac stages per well.610 In fact, the company can now complete as many as eight staged fracture stimulations along the horizontal leg of a well in just four days.611

Recall that EnCana also entered a three-year agreement with Kogas Canada Ltd. (KOGAS), a subsidiary of Korea Gas Corporation. In that agreement KOGAS plans to invest C$565 million to earn a 50 percent interest in 154,000 net acres, 25,000 net acres are located in the Horn River while 129,000 net acres are in the Montney play.612 The 25,000 net acres in the Horn River Basin is in the Greater Sierra field while the 154,000 net acres in the Montney are located in the Cutbank Ridge play. It is important to note that the Montney play, along with the Horn River Basin, is part of the discussions with the China National Petroleum Corporation (CNPC) regarding a potential joint venture.

ARC Energy Trust is a dominant producer in the Montney Basin, particularly in the Upper Montney shale. Like EnCana, ARC Energy entered the unconventional gas game in 2003. The Calgary-based ARC solidified its position in the Montney with its acquisition of Storm Exploration for C$680 million.613 Storm Exploration’s leaseholds included

602 oilgshalegas.com/montneyshale.html (accessed on September 19, 2010) 603 ibid 604 EnCana Corp, News Release, February 12, 2009. 605 Shale Gas Activity in British Columbia, Ministry of Energy, Mines and Petroleum Resources, April 8, 2010, pp. 17 606 ibid 607 EnCana, Division Overview Presentation, Calgary, March 16, 2010, pp. 5. 608 Shale Gas Activity in British Columbia Ministry of Energy, Mines and Petroleum Resources, April 18, 2010, pp. 39. 609 ibid 610 oilgshalegas.com/montneyshale.html (accessed on September 19, 2010) 611 Shale Gas Activity in British Columbia Ministry of Energy, Mines and Petroleum Resources April 18, 2010, pp. 38. 612 EnCana website, http://www.encana.com/news/topics/kogas/ (accessed on August 15, 2010)

613 Oilweek website, “ARC expanding presence in promising B.C. shale play with Storm acquisition”, June 10, 2010, http://www.oilweek.com/news.asp?ID=28312 (accessed on October 21, 2010)

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The heart of ARC’s Montney operation is centered in the Dawson Creek area. Within this Upper Montney shale, the company estimated a total GIP of 8.1 Tcf.616 Utilizing horizontal drilling technology and advanced completion techniques, it produced a record daily net 52 MMcfpd in 4Q2008.617 ARC’s production increased to nearly 60 MMcfpd after it drilled an additional 22 wells in 2009, this is up from 2 wells drilled and another 9 wells completed in 2008.618 ARC is planning to drill another 30 horizontal wells and 3 vertical wells in the Montney by the end of 2010.619

ARC is positioned well for future development—ARC’s 2009 proved plus probable reserves for Upper Montney at Dawson and West Montney areas increased to 784 Bcf.620

Murphy Oil holds 126,000 net acres in the Montney Shale, including the Tupper Main and Tupper West areas.621 The company began Tupper Main in 2007, and is currently producing 94 MMcfpd. This is up from about 30 MMcfpd from Tupper at 4Q2008. Gas production from Tupper West and Tupper Main started in December 2008 with volumes reaching 80 MMcfpd in late 2009. IP rates on the wells were 7 MMcfpd and Murphy is expecting an ultimate recovery of 3.7 Bcfpd per well.622

Murphy is ramping up Tupper West, which is expected to be better than Tupper Main. Tupper West will consist of 275 wells in the first phase of development. Phase two is expected to consist of 244 wells.623 Production is estimated to reach 425 MMcfpd by 2015.624

Shell Canada is a major player in the Montney Basin. In August 2008, Duvernay Oil Corp., a junior Alberta-based E&P company which owned 450,000 net acres of Montney land, was acquired by Shell Canada for US$5.9 billion.625 In this deal Shell acquired net acreage in northeastern British Columbia, extending into Alberta’s Deep Basin. In addition to land, Shell acquired processing facilities in the aforementioned districts. It is important to mention that much of Duvernay’s prospects were categorized as tight gas.

614 ibid 615 ibid 616 Shale Gas Activity in British Columbia Ministry of Energy, Mines and Petroleum Resources April 18, 2010, pp. 38. 617 ibid 618 ibid 619 ibid 620 Shale Gas Activity in British Columbia Ministry of Energy, Mines and Petroleum Resources April 8, 2010, pp. 39. 621 “Murphy Oil's North American Portfolio”, May 19, 2010, http://stocks.investopedia.com/stock- analysis/2010/Murphy-Oils-North-American-Portfolio-MUR0519.aspx (accessed on October 21, 2010) 622 ibid 623 ibid 624 ibid 625 “Duvernay Oil acquired by Shell Canada”, July 14, 2008, http://www.stockhouse.com/Community- News/2008/July/14/Duvernay-Oil-acquired-by-Shell-Canada (accessed on October 21, 2010)

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Talisman is active in the Montney Basin, owning 830,000 net (590,000 gross) acres of Montney land in British Columbia and Alberta.626 However, less than 200,000 net acres are located on the British Columbia-side of the Montney. Talisman holds 32,500 net hectares of land in the high-potential Groundbirch area.627 The company’s 2009 Montney plans include the completion of 2 pilot projects (Legacy in British Columbia, and Cabin Creek in Alberta), and drilling 49 gross wells.628 Talisman is also developing the Farrell Creek area, drilling three horizontal wells in March 2010. Production was 22 MMcfpd in those wells. According to its website, Talisman is moving the Farrell Creek area into commercial development, drilling approximately 25 horizontal development wells for the remainder of 2010.629 In addition, Talisman expects to increase its number of rigs in the Montney Shale in 2010, spending approximately C$550 million.630

The company is also active in another shale in Canada—the Utica Shale in Québec. This play is discussed in the subsequent shale play section. Development Outlook & Drilling Forecasts While the price of natural gas appears to be a factor, technological advances and increasing drilling efficiencies appear to be offsetting lower gas prices. Between the positive economics and geology and the Horn River’s incredible GIP potential, drilling activity in northeastern British Columbia is expected to increase.

In the NEB’s Short-term Natural Gas Deliverability 2010-2012 study, they anticipate shale gas development to grow over the next several years, from 387 MMcfpd to 1.5 Bcfpd by 2012.631 The NEB anticipates drilling activity in the Montney and Horn River Basin Shales to increase to between 500 and 900 wells by 2020.632 Recall that in July 2009, 234 horizontal wells were producing from Montney shale.633

The Triassic-aged Montney has a very attractive geology. It is relatively shallow at 6,600-8,200 ft., certainly shallower than the Horn River Basin at 7,800-13,300 ft. At over 950 ft., it also has an excellent thickness and good porosity. The thickness of the shale is being compared to the Barnett shale. Also comparable to the Barnett is the Montney’s excellent one-year decline rate (50 percent).634 The Barnett Shale is 65 percent, while many other shale plays hover between 80-90 percent.

Drilling activity is expected to increase in the Montney Shale. This is indicated by the major players that most affect the Montney Shale. This is indicated various highlights below.

626 Talisman Energy, “A Clear Strategy to Unlock Value”, Corporate Presentation February 2009. 627 Shale Gas Activity in British Columbia Ministry of Energy, Mines and Petroleum Resources April 18, 2010, pp. 43. 628 Talisman Energy, Investor Presentation – NAO, May 2008 629 Talisman Energy website, “Outlook for 2010”, http://ar.talisman-energy.com/2009/managements-discussion- and-analysis/outlook-for-2010.html (accessed on October 21, 2010) 630 Talisman Energy website, “Outlook for 2010”, http://ar.talisman-energy.com/2009/managements-discussion- and-analysis/outlook-for-2010.html (accessed on October 21, 2010) 631 “Short-term Canadian Natural Gas Deliverability 2010-2012”, National Energy Board, March 2010, pp. 5 632 ibid 633 “A Primer for Understanding Canadian Shale Gas”, National Energy Board, November 2009, pp. 16. 634 Encana says Horn River ranks high as shale-gas find”, September 9, 2009, http://www.reuters.com/article/idUSN0933344420090909 (accessed on September 10, 2010)

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• ARC expects to have another 60 million a day of production on the operated lands at Sunrise in early 2012635; ARC is planning to drill another 30 horizontal wells and three vertical wells in the Montney by the end of 2010.636

• Murphy Oil plans to develop the Tupper West area which will consist of 275 wells in the first phase of development and another 244 wells in the second phase; production of this area alone is estimated to reach 425 MMcfpd by 2015.637

Talisman is moving the Farrell Creek area into commercial development, drilling approximately 25 horizontal development wells for the remainder of 2010 and plans to spend approximately C$550 million.638

Additional Information As in all provinces and territories, the National Energy Board (NEB) regulates aspects of the energy industry in Canada. This includes the construction and operation of inter-provincial and international pipelines; pipeline traffic, tolls and tariffs; the construction and operation of international and designated inter-provincial power lines; the export and import of natural gas; the export of oil and electricity; and Frontier oil and gas activities.639

The British Columbia Oil and Gas Commission (OGC) oversee oil and gas activities within the province, from exploration and development to drilling and decommissioning.640 Public safety and environmental issues are also a part of the OGC’s mandate.

Constraints in the Montney Basin are similar to the constraints discussed in the aforementioned Horn River Basin, including low gas prices, the short drilling season, the lack of existing infrastructure (pipelines and roadways), 641 produced carbon dioxide (CO2) and emerging water issues.

While further south and closer to a larger oil and gas infrastructure of Alberta, producers in the Montney still face a lack of infrastructure, whether roadways or pipelines. Access to northeastern British Columbia’s hydrocarbon resources is primarily limited to the winter months (December to March), when the land is in a deep freeze. As the ground thaws, it is unable to sustain the weight of the drilling equipment. As such, both workers and production equipment must be removed before the spring break-up commences. A short drilling season, in turn, places limitations on the amount of natural gas that can be produced in the area. As suggested previously, improvements in technology will effectively extend the drilling season in northern climates.

635 http://www.worldfuels.com/wfExtract/exports/Content/b72d058c-b7f7-4ba1-a322-1e7e739e1ebe.html (accessed on September 8, 2010) 636 Shale Gas Activity in British Columbia Ministry of Energy, Mines and Petroleum Resources April 8, 2010, pp. 38. 637 http://www.worldfuels.com/wfExtract/exports/Content/b72d058c-b7f7-4ba1-a322-1e7e739e1ebe.html (accessed on September 8, 2010) 638 http Talisman Energy website, “Outlook for 2010”, http://ar.talisman-energy.com/2009/managements- discussion-and-analysis/outlook-for-2010.html (accessed on October 21, 2010) 639 Memorandum of Understanding between the National Energy Board and the Oil & Gas Commission, http://www.neb.gc.ca/clf-nsi/rpblctn/ctsndrgltn/mmrndmndrstndng/lgscmmssn2007-eng.html (accessed on September 10, 2010) 640 http://www.ogc.gov.bc.ca/documents/annualreports/Oil_and_Gas_Water_Use_in_BC.pdf, pp. 4. 641 “From Shale to Shining Shale”, Deutsche Bank, July 22, 2008, pp. 35.

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The lack of existing infrastructure, whether it is pipelines or roadways, is also a limiting factor. Without sufficient pipeline capacity to move gas to markets, much of British Columbia’s resources could remain shut-in. As previously mentioned, TransCanada recently completed two binding open seasons for pipeline capacity from the Horn River and Montney areas to its existing Alberta pipeline network. TransCanada’s Groundbirch Pipeline is expected to cost C$340 million.642 By the end of 2010, the pipeline will begin transporting up to 1 Bcfpd of gas from the Montney region (northwest of Dawson Creek) to the Alberta system near the Gordondale meter station.643

As mentioned previously in the Horn River Basin section, another noteworthy investment in British Columbia’s pipeline infrastructure is the approved C$1 billion proposal by Pacific Trail Pipelines to construct a pipeline from the Sempra Energy Transmission system at Summit Lake to the proposed Kitimat LNG terminal and its natural gas liquefaction site. The Kitimat to Summit Lake Pipeline Looping Project will be approximately 462 kilometers (287 miles) in length, and have a capacity of 1 Bcfpd.644

As production of gas from shale, tight sands, and CBM increases, the strain on existing water resources will become more apparent. The availability of large volumes of water is crucial to northeastern British Columbia’s shale development. In neighbouring Alberta, where fresh water concerns are mounting, new technologies and policies are being explored to increase the productivity of fresh water resources. While water is more abundant in British Columbia than in Alberta, the successful deployment of new water saving technologies will be crucial to the future development of the province’s gas resources.

The Muskwa/Ootla Shale, Horn River Basin, British Columbia

Geology and Basin Metrics The Horn River Basin is located in northeastern British Columbia and stretches north up to Fort Liard, southern . The Horn River Basin area encompasses approximately 1.28 million hectares within the Fort Nelson/Northern Plains region of British Columbia.645 Figure 3.11 illustrates the Horn River Basin and the accompanying Cordova Embayment, which straddles the northeastern corner of British Columbia and the Northwest Territories. Drilling is primarily located northeast of the remote Snake River, shown by the cluster of red squares. Due to the small amount of shale gas targets, this study does not include a discussion of the gas- producing Cordova Embayment, in the northeastern corner of British Columbia.

642 oilshalegas.com/hornriverbasin.html (accessed on September 26, 2010) 643 ibid 644 Pacific Trail Pipelines website, http://www.pacifictrailpipelines.com/page131.htm (accessed on September 10, 2010) 645 Summary of Shale Gas Activity in Northeast British Columbia 2007, pp. 4.

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Figure 3.11 Horn River Shale Region

Source: National Energy Board646

While production volumes from shale gas resources in Canada are currently insignificant, compared to that in the United States, there is substantial potential for future growth. Shale gas and tight gas hold enormous supply potential in British Columbia. Energy companies, led by shale gas discoveries, have added $220 million to British Columbia’s land sale coffers in the September 2008 auction alone. According to the Ministry of Energy, Mines and Petroleum Resources, British Columbia closed out the 2008-09 fiscal year with an all-time high of $2.4 billion sold—more than doubling the previous record set in 2007.647 The shale gas potential is in rocks from several parts of the province, ranging from the prolific WCSB to the Bowser Basin in the north central part of the province.

According to Platts, in early May 2008 the Scotland-based Wood Mackenzie stated that the Horn River Basin could rival the Barnett Shale, with recoverable reserves in the region at 37 Tcf and easily rising to 50 Tcf or greater as drilling activity increases.648 The Horn River Basin, according to CSUG, may contain over 500 Tcf of original gas in place (OGIP).649 This makes it the third largest North American natural gas accumulation discovered prior to 2010, ranking behind the Marcellus and the Haynesville Shales. The Horn River Basin has certainly garnered attention for E&Ps across North America and Asia.

646 “A Primer for Understanding Canadian Shale Gas”, National Energy Board, November 2009, pp. 18. 647 Marketwire, Press Release, “Government of British Columbia: Oil and Gas Produce Record-Breaking Fiscal Year”. http://www.marketwire.com/press-release/Government-Of-British-Columbia-966555.html (accessed on September 8, 2010) 648 http://oilshalegas.com/hornrivershalebasin.html (accessed on September 8, 2010) 649 F.M., Dawson, “Shale Gas in North America: Emerging Supply Opportunities”, Canadian Society for Unconventional Gas, October, 2008.

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The Horn River Basin is named for the geological formation, of which the Muskwa Member, Otter Park Member and Evie Member are subunits. This explains why the Devonian-aged shale is, on occasion, referred to as the Ootla/Muskwa shale. It lies in at a depth range of 7,800-13,300 ft. and is located predominantly in northeast British Columbia. It is very comparable to the Haynesville Shale which lies at a depth of 10,500-13,500 ft., and is deeper than other shales such as the Fayetteville Shale, Woodford Shale and Barnett Shale. In terms of thickness and porosity, the Ootla/Muskwa shale is 360-580 ft. and 4.0 percent, respectively. The former is comparable to the Barnett shale, which ranges in thickness from 150 ft. to 700 ft. The Horn River Basin Shale’s thermal maturity is 2.2-3.8 Ro and has a TOC content of 3.0 percent. The silica content is 45-68 percent.

Table 3.8 provides a summary of key geological characteristics of the Horn River Basin Shale.

Table 3.8 Horn River Basin Shale Geological Characteristics Parameter Horn River Basin Shale Geological age Devonian Depth range (ft) 7,800-13,300 Shale thickness (ft), gross 360-580 GIP/sq mi (Bcf) 180-320 Porosity (%) 4.0 Total organic carbon (%) 3.0 Thermal maturity (Ro) 2.2-3.8* Silica content (%) 45-68* Pressure gradient (psi/ft) n/a Source: Deutsche Bank, 2008650 and *Vero Energy, New Prospect Shale Gas, August 2010651.

Table 3.9 provides the basin metrics for the Horn River Basin Shale. The geology of the Horn River Basin Shale is attractive. While it is a deep play, it is also a thick shale play (360-580 ft.) with an exceptional one-year decline rate (50 percent).652 The Barnett Shale is considered low at 65 percent; many other shale plays hover between 80-90 percent.

650 “From Shale to Shining Shale”, Deutsche Bank, July 22, 2008, pp. 38. 651 “New Prospect Cordova Embayment Shale Gas”, Vero Energy (presentation), August 2010. 652 “Encana says Horn River ranks high as shale-gas find”, September 9, 2009, http://www.reuters.com/article/idUSN0933344420090909 (accessed on September 8, 2010)

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Table 3.9 Basin Metrics for the Horn River Basin Shale Parameter Horn River Basin Average Well Cost ($MM) 7.0-10.0 Depth range (ft) 7,800-13,300 IP Rate (MMCFPD) 5.0-12.0 Expected EUR/Well (BCFE) 4.0-6.0 Threshold Price ($/MCFE) n/a Expected F&D Cost ($/MCFE) 2.0 Expected Recovery Factor (%) 20-30 Decline – Yr. 1 (%) -50 Lateral lengths (ft) 4,600-8,200 Fracturing stages 6-12 Typical Well Spacing (acres/well) 40 Source: Deutsche Bank, 2008653.

E&P Players and Recent M&A Activity The enormous potential of the Horn River Basin is attracting large independent producers, as well as several mid- sized E&P companies. As much of the Horn River land has been tenured in the past five years, the situation is quite dynamic. Currently the top landholders in the region are EnCana Corp., Apache Corp., EOG Resources and Nexen Inc., together holding exploration rights to over 760,000 net acres of Horn River land. With ExxonMobil/Imperial’s large purchase in early 2010, there are now five major operators on the list—at least in terms of net acreage.

Figure 3.12 illustrates the landholdings within the Horn River Basin area.

Figure 3.12 Landholdings Within the Horn River Basin

Source: UGcenter654

653 “From Shale to Shining Shale”, Deutsche Bank, July 22, 2008, pp. 38. 654 http://www.ugcenter.com/Shales/Canadian/HornRiverMuskwa (accessed on September 8, 2010)

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Other companies involved in the extraction of natural gas from the Horn River Shale include Stone Mountain/Ramshorn Resources, Quicksilver Resources and Devon Energy. It is important to note that together the aforementioned eight companies plus ConocoPhillips, Suncor Energy and Pengrowth Energy Trust, form the Horn River Basin Shale Producers Group. The groups mandate is to minimize the environmental footprint of the remote wilderness area and to facilitate cooperation between companies and First Nations and other key stakeholders.655

While it is not realistic to discuss all these aforementioned companies, it is useful to review quickly the following major players and their various mergers and acquisitions in the play: EnCana, Apache, EOG Resources, and Nexen. ExxonMobil/Imperial will not be discussed in greater detail as they are evaluating their large net acreage (now 305,000 acres) and have only drilled one horizontal well thus far.656

EnCana began purchasing land in the Horn River Basin in 2003, and now holds 260,000 net acres in the region.657 In 2008, the company drilled 4 horizontal wells using techniques similar to those used in the Texas Barnett. 658 Calgary-based EnCana entered a 50/50 joint venture with Apache in the Horn River in the summer of 2006.659 Together EnCana and Apache hold more than 400,000 net acres in the Horn River Basin.

EnCana’s daily net production averaged 24 MMcfpd in 2Q2010 in the Horn River.660 Currently, the company is operating 10 rigs. Initial production rates for the first 30 days of production are reported to reach 8 MMcfpd, declining to 4 MMcfpd after a year.661 Utilizing Debolt water processing for use in their frac’ing, EnCana is reporting increases in drilling efficiencies.662 This initiative, introduced in May 2010, is expected to lead to drilling longer laterals and increased recovery and production.663 In their 2Q2010 corporate update, EnCana suggested one well drilled in the Horn River to a total measured depth of just over 19,000 feet, and is expected to have 28 fracture intervals when completed.664

In addition to a joint venture with Apache, EnCana also entered a three-year agreement with Kogas Canada Ltd. (KOGAS).665 The latter is a subsidiary of Korea Gas Corporation, the world’s largest importer of liquefied natural gas (LNG), operating three LNG regasification terminals in South Korea. KOGAS plans to invest C$565 million to earn a 50 percent interest in 154,000 net acres, 25,000 net acres are located in the Horn River while 129,000 net acres are

655 http://www.capp.ca/energySupply/innovationStories/RelationshipsPartners/Pages/Collaboration- HornRiverProducersGroup.aspx#PtlEZnoTUTt7 (accessed on September 8, 2010) 656 oilshalegas.com/hornriverbasin.html (accessed on September 8, 2010) 657 EnCana News Release, June 16, 2008, http://www.encana.com/news/newsreleases/2008/ P1213590054715.html (accessed on October, 22, 2010) 658 ibid 659 Apache Corporation website, “Apache Canada takes the lead in shale gas production” (May 2008) http://www.apachecorp.com/explore/Browse_Archives/View_Article.aspx?Article.ItemID=595 (accessed on September 8, 2010) 660 “EnCana Q2 2010 Earnings Call Transcript” (July 27, 2010), http://seekingalpha.com/article/216690-encana-q2- 2010-earnings-call-transcript (accessed on September 8, 2010) 661 Oil Voice, “EnCana Generates Third Quarter Cash Flow of US$2.8 billion” October 23, 2008, http://www.oilvoice.com/n/EnCana_Generates_Third_Quarter_Cash_Flow_of_US28_billion/0fce3636.aspx, (accessed on August 15, 2010) 662 oilshalegas.com/hornriverbasin.html (accessed on August 15, 2010) 663 ibid 664 ibid 665 http://www.encana.com/news/topics/kogas/ (accessed on August 15, 2010)

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108 Canadian Energy Research Institute in the Montney play.666 This agreement will facilitate EnCana to accelerate E&P in the two highly prospective unconventional gas plays.667 In June 2009 KOGAS committed US$20 billion to Kitimat LNG, a planned LNG export facility located in Kitimat, British Columbia.668

It is also important to note that EnCana is currently in discussions with the China National Petroleum Corporation (CNPC) for a joint venture on its acreage in the Horn River Basin, as well as other areas of Canada.669 Recall that EnCana is a significant player in another growing and potentially prolific shale gas play—the Haynesville in Louisiana and East Texas. With their recent purchases of land, they now have approximately 400,000 net acres in the Haynesville play, plus another 63,000 net acres of mineral rights.670

Apache holds approximately 207,000 net acres in the Horn River Basin area (and over 400,000 net acres total with EnCana). In a press release in April 2008, the company suggests that net gas resources on their acreage alone are between 9 and 16 Tcf.671 Apache’s 2009 objective was to drill 25 wells and install a 24-inch pipeline.672

In April 2010, Apache completed frac’ing operations on the first well pad in the Horn River Basin.673 This undertaking was nearly a decade in the making, after their first E&P activities commenced in the Ootla area of the Horn River Basin in 2001. Unlike the players in the Horn River play, Apache had no experience in the shale gas game. Partnering up with EnCana gave Apache access to knowledge and experience on unconventional gas development.674 Apache was the first company to produce gas in the Horn River Basin.675

Apache has ambitious goals for the remainder of 2010 and into 2011, expecting to complete two more pads with 25 to 28 wells.676 The Houston-based company also expects to bring an additional 42 to 45 wells to production by end-2010.677 While a very active driller in the Horn River Basin, Apache is also active in LNG, purchasing 51 percent of the stake in Kitimat LNG.678 Apache announced the agreement on January 13, 2010. The design and front-end engineering activities are expected to commence in 2010, potentially leading for exporting natural gas as early as

666 ibid 667 ibid 668 http://hornrivernews.com/tag/encana-corp/ 669 http://www.encana.com/news/newsreleases/2010/0624-china-national-petroleum-corporation.html (accessed October, 21, 2010) 670 http://www.oilshalegas.com/haynesvilleshale.html (accessed on August 15, 2010) 671 Apache Corporation website, “Apache Canada takes the lead in shale gas production” (May 2008) http://www.apachecorp.com/explore/Browse_Archives/View_Article.aspx?Article.ItemID=595 (accessed on September 8, 2010) 672 Roger Plank, CFO Apache Corporation, Presentation at the Credit Suisse Annual Energy Conference, February 5, 2009. 673 Apache Corporation website, “The Horn River Project” (July 2010), http://www.apachecorp.com/explore/Browse_Archives/View_Article.aspx?Article.ItemID=1130 (accessed on October 21, 2010) 674 ibid 675 ibid 676 ibid 677 ibid 678 Apache Corporation website, “LNG is Key” (March 2010), http://www.apachecorp.com/explore/Browse_Archives/View_Article.aspx?Article.ItemID=985 (accessed on October 21, 2010)

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2014.679 Apache anticipates that enormous potential of the Horn River Basin may be large enough to market to the emerging Asian economies, such as Japan, South Korea and China. Recall interest from KOGAS and CNPC in the Horn River Basin and the Kitimat facility.

Figure 3.13 illustrates the Kitimat LNG terminal—the only export LNG facility planned in North America. The planned capacity of the proposed facility is approximately 700 MMcfpd and will cost about C$3 billion.680

Figure 3.13 Kitimat LNG Terminal Project

Source: Apache Corporation681

Nexen is an active player in the Horn River Basin and its position in the play is improving. Landholdings in the Horn River area expanded to over 300,000 net acres, up from 123,000 net acres, following a land sale in June 2010.682 The company announced the potential for a net 3 to 6 Tcf of recoverable reserves in the Horn River Basin on just its 123,000 net acres in the play.683 Of this net acreage, 90,000 net acres are in the highly-touted Dilly Creek area.684 The company suggests that between 500 and 700 wells could be drilled in their land positions.685 Nexen is assuming a 20 percent recovery of the resources.

679 ibid 680 Kitimat LNG website, http://www.kitimatlng.com/code/navigate.asp?Id=32 (accessed on October 21, 2010) 681 Apache Corporation website, “LNG is Key” (March 2010), http://www.apachecorp.com/explore/Browse_Archives/View_Article.aspx?Article.ItemID=985 (accessed on October 21, 2010) 682 Nexen website, http://www.nexeninc.com/en/Operations/UnconventionalGas/ShaleGas.aspx (accessed on October 21, 2010) 683 Nexen Q12009 Earning Report, http://www.slideshare.net/earningreport/q1-2009-earning-report-of-nexen-inc (accessed on September 10, 2010) 684 http://oilshalegas.com/hornrivershalebasin.html (accessed on September 10, 2010) 685Nexen website, http://www.nexeninc.com/en/Operations/UnconventionalGas/ShaleGas.aspx (accessed on October 21, 2010)

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Nexen’s 2009 capital budget plans included the drilling of seven test wells in the Horn River Basin.686 A total of C$160 million of Nexen’s C$690 million 2009 exploration program were allocated to Horn River developments.687 The aforementioned seems to be paying off, as Nexen reported progress at the 2Q2010. Currently, Nexen has drilled eight horizontal wells with six completions to date. Currently Nexen is producing approximately 15 MMcfpd, and plans to increase production to 150 to 200 MMcfpd by September of 2011.688 The company is very active in the area with 18 wells planned in the winter 2010-11. Nexen suggests that the eight wells can earn a 10 percent rate of return, even at a C$4.00 natural gas price.689

EOG Resources holds 157,500 net acres of Horn River land.690 In an EOG investor presentation in March 2009, EOG suggests that net gas resources on their acreage are approximately 6 Tcf, assuming a 25 percent recovery rate. However, due to the regions limited pipeline infrastructure, EOG does not believe full scale production will be possible until 2012.691 EOG is currently working on completing 11 wells drilled in the winter 2009-10. EOG planned to drill seven horizontal wells in the in 2009.692 In an early 2010 update the company will operate an active drilling program for the first half of 2010 and will complete wells during the second half of 2010.693

EOG acquired 49 percent of the aforementioned proposed Kitimat LNG facility, located at Bish Cove, near the Port of Kitimat.694 EOG announced the acquisition of Calgary-based Galveston LNG, the founder of Kitimat LNG in 2004, in mid-May 2010. Sharing the rationale of their new partner Apache, EOG suspects enormous potential in exporting the natural gas to international markets.

Development Outlook & Drilling Forecasts In its report, Short-term Natural Gas Deliverability 2008-2010, the NEB warned that high costs of production and soft natural gas prices, could be constraining factors for the development of . Early in September 2008, Devon Canada estimated that its acreage in the Horn River Shale holds as much as 8 Tcf of gas reserves, but also warned that high development costs could inhibit efforts to extract it. Apache’s President, John Crum, shares this sentiment. In early September Mr. Crum stated that costs, combined with decreasing natural gas prices, could be an issue in the remote shale play.

While the price of natural gas appears to be a factor, technological advances and increasing drilling efficiencies appear to be offsetting lower gas prices. Between the positive economics and geology and the Horn River’s

686 Nexen News Release, http://www.nexeninc.com/Newsroom/News_Releases/attachments/928578.pdf (accessed on December 9, 2008). 687 ibid 688 Nexen website, http://www.nexeninc.com/en/Operations/UnconventionalGas/ShaleGas.aspx (accessed on October 21, 2010) 689 “Horn River Basin Second-Quarter Update”, Aug 19, 2010 , http://stocks.investopedia.com/stock- analysis/2010/Horn-River-Basin-Second-Quarter-Update-KWK-EOG-NXY-ECA-DVN0819.aspx (accessed on September 10, 2010) 690 http://oilshalegas.com/hornrivershalebasin.html (accessed on October 21, 2010) 691 oilshalegas.com/hornriverbasin.html (accessed on September 10, 2010) 692 Patrick Johnston and Shannon Nome, Deutsche Bank: Global Market Research, EOG Resources. February 5, 2009. 693 oilshalegas.com/hornriverbasin.html (accessed on September 10, 2010) 694 Kitimat LNG website, http://www.kitimatlng.com/code/navigate.asp?Id=32 (accessed on October 21, 2010)

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incredible GIP potential, drilling activity in the northeastern British Columbia is expected to increase. In the NEB’s Short-term Natural Gas Deliverability 2010-2012 study, they anticipated that shale gas development will grow over the next several years, from 41 MMcfpd in 2010 to 462 MMcfpd by 2012.695 BMO Capital Markets estimates that Horn River production alone could exceed 4 Bcfpd by 2015.696

Figure 3.14 is a drilling forecast for the Horn River Basin Shale for the period 2009-28, provided by the British Columbia Ministry of Energy, Mines and Petroleum Resources. The Figure illustrates two cases: the optimistic case and pessimistic case. The Pessimistic Outlook is based on limited accessibility, 20 percent recovery and 4.1 Bcf/well production while the Optimistic Outlook is based on good accessibility, 30 percent recovery and 5.5 Bcf/well productions.697

Figure 3.14 Drilling Forecast for the Horn River Basin Shale

5000

4000

3000

2000

1000

0 2009 2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028

Pessimistic Optimistic

Source: BC Ministry of Energy, Mines and Petroleum Resources, 2009698

As suggested previously, there are four major players that most affect the Horn River Basin Shale. As indicated by various highlights below, all four appear to sustaining or ramping up drilling activity.

• Apache has ambitious goals over the remainder of 2010-2011, expecting to complete two more pads with 25 to 28 wells;699 Apache also expects to bring an additional 42 to 45 wells to production by end-2010.700

695 “Short-term Canadian Natural Gas Deliverability 2010-2012”, National Energy Board, March 2010, pp. 5 696 Pipeline & Gas Journal, “Gas Revolution No. 2: Canadian Shale”, Gary Park, May 2010 Vol. 237 No. 5, http://pipelineandgasjournal.com/gas-revolution-no-2-canadian-shale?page=show (accessed on October 21, 2010) 697 Kerr, B., “Looking to the Future: Development in the Horn River Basin”, BC Ministry of Energy, Mines and Petroleum Resources, 2008. 698 ibid

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• Nexen plans to increase production to 150 to 200 MMcfpd by September of 2011; company is very active in the area with 18 wells planned in winter 2010-11.701

• EOG will operate an active drilling program for the first half of 2010 and will complete wells during the second half of 2010.702

Additional Information Limitations in the Horn River Basin are similar with its relatively close counterpart Montney Shale. The latter is discussed in a subsequent section.

The British Columbia Oil and Gas Commission (OGC) oversee oil and gas activities within the province, from exploration and development to drilling and decommissioning.703 Public safety and environmental issues are also a part of the OGC’s mandate.

With the hydrocarbon resources in the Horn River Basin believed to be quite substantial, the OGC is getting busy. That being said, operators in these resource plays face several constraints. The key constraints faced by producers include, but are not limited to, low gas prices, the short drilling season, the lack of existing infrastructure (pipelines 704 and roadways), produced carbon dioxide (CO2), and emerging water issues.

Access to much of northeastern British Columbia’s hydrocarbon resources is limited to the winter months (December to March). As the ground thaws, it is unable to sustain the weight of the drilling equipment. As such, both workers and production equipment must be removed before the spring break-up commences. A short drilling season, in turn, places limitations on the amount of natural gas that can be produced in the area.

As suggested previously, improvements in technology will effectively extend the drilling season in northern climates. The ability to drill multiple horizontal wells (8-20 wells) from a single pad can increase production during a given drilling season, and improve the project economics for companies operating in the region. Nexen is among the companies that utilized multi-well pads in 2009. EnCana utilized wooden mats to allow the completion of multi-well programs during the summer months.705

The lack of existing infrastructure, whether it is pipelines or roadways, is also a limiting factor. Without sufficient pipeline capacity to move gas to markets, much of British Columbia’s resources could remain shut-in. Existing

699 Apache Corporation website, “The Horn River Project” (July 2010), http://www.apachecorp.com/explore/Browse_Archives/View_Article.aspx?Article.ItemID=1130 (accessed on October 21, 2010) 700 Apache Corporation website, “The Horn River Project” (July 2010), http://www.apachecorp.com/explore/Browse_Archives/View_Article.aspx?Article.ItemID=1130 (accessed on October 21, 2010) 701 Nexen website, http://www.nexeninc.com/en/Operations/UnconventionalGas/ShaleGas.aspx (accessed on October 21, 2010) 702 oilshalegas.com/hornriverbasin.html (accessed on September 10, 2010) 703 http://www.ogc.gov.bc.ca/documents/annualreports/Oil_and_Gas_Water_Use_in_BC.pdf, pp. 4. 704 “From Shale to Shining Shale”, Deutsche Bank, July 22, 2008, pp. 38. 705 EnCana website, http://www.encana.com/operations/canada/greatersierra (accessed on October 21, 2010)

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pipeline takeaway capacity is likely to be adequate initially, however, as the area develops, additional pipe will be required to tie into major export trunk lines.

TransCanada recently completed two binding open seasons for pipeline capacity from the Horn River and Montney areas to its existing Alberta pipeline network. Shipping contracts have been secured to move 378 MMcfpd of gas on the proposed C$340 million Horn River pipeline.706 The Horn River pipeline is expected to commence operations in the middle of 2011.707 By the end of 2010, TransCanada’s C$340 million Groundbirch Pipeline will begin transporting up to 1 Bcfpd of gas from the Montney region (northwest of Dawson Creek) to the Alberta system near the Gordondale meter station.708 Another noteworthy investment in British Columbia’s pipeline infrastructure is the approved C$1 billion proposal by Pacific Trail Pipelines to construct a pipeline from the Sempra Energy Transmission system at Summit Lake to the proposed Kitimat LNG terminal and its natural gas liquefaction site.709 The Kitimat to Summit Lake Pipeline Looping Project will be approximately 462 kilometers (287 miles) in length, and have a capacity of 1 Bcfpd. Pipeline construction is slated to be completed by 2013. The Kitimat LNG terminal, of which Apache and EOG are partners, is expected to commence operations in 2013. In addition, Spectra Energy Corp. announced in mid-July 2010 that it is building a new gas processing plant scheduled to begin operations in 2011.710

The lack of available roadways in northeastern British Columbia makes accessing remote shale areas extremely difficult. Fort Nelson is the largest city center within a relatively close proximity to the Horn River Basin. Before the Horn River Basin gas can be fully commercialized, government and industry will have to improve the infrastructure in the region. The Infrastructure Royalty Credit Program, the Heartland Oil and Gas Road Rehabilitation Strategy, and the Public-Private Partnership (P3) for the Sierra-Yoyo-Desan Road, are ways in which the provincial government is attempting to promote improvements in regional infrastructure.711 Announced in March 2009, the British Columbia government planned to spend C$187 million over 4 years to upgrade the aforementioned road into the Horn River basin.712

In addition to the aforementioned issues, there are several environmental and public safety issues regarding shale gas production in the Horn River Basin. Natural gas produced in the Horn River basin consists of 10 percent CO2 or 713 more in some cases. In order for the natural gas to meet pipeline specifications, the CO2 must be removed. Once the CO2 is separated out from the natural gas, it can be disposed of in two ways: injecting it into a suitable

706 oilshalegas.com/hornriverbasin.html (accessed on September 10, 2010) 707 “TransCanada secures support for shale gas line”, February 26, 2009, http://uk.reuters.com/article/oilRpt/ idUKN2622905120090226 (accessed on September 12, 2010) 708 oilshalegas.com/hornriverbasin.html (accessed on September 10, 2010) 709 Pacific Trail Pipelines website, http://www.pacifictrailpipelines.com/page131.htm (accessed on September 10, 2010) 710 David Ebner, “B.C. shale gas gets jump-start with $404-million land auction“ June 24, 2010, http://www.theglobeandmail.com/report-on-business/industry-news/energy-and-resources/bc-pulls-in-404- million-for-gas-rights/article1616371/ (accessed on September 10, 2010) 711BC Ministry of Energy, Mines and Petroleum Resources, 2009, http://www.empr.gov.bc.ca/OG/oilandgas/infrastructure/Pages/default.aspx (accessed on September 10, 2010) 712 http://www.ogj.com/display_article/357276/120/ARTCL/none/ExplD/1/British-Columbia/ (accessed on March 31, 2009) 713 Carol McGowen, “Horn River Basin Keeping Canada Hot”, AAPG, http://www.aapg.org/explorer/2010/10oct/regsec1010.cfm (accessed on September 14, 2010)

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114 Canadian Energy Research Institute reservoir or shipping it through pipelines to be used in Enhanced Oil Recovery (EOR). While both options could prove to be quite costly, utilizing the CO2 in EOR (in either British Columbia or Alberta) may be the more preferred choice, as it will generate an income stream, which would offset some portion of the infrastructure costs. Spectra Energy, in partnership with the British Columbia government, is currently evaluating the technological, geological and economic feasibility of a large-scale Carbon Capture and Storage (CCS) project to be located near the company’s existing Fort Nelson gas processing plant.714

As production of gas from shale (and other unconventional gas development such as tight sands and CBM) increases, the strain on existing water resources will become more apparent. Due to the low permeability inherent in gas shales, sub-surface stimulation, or frac’ing, is almost always required to splinter the rocks. Using substantial amounts of water and sand, hydraulically fracturing the shale allows the gas to flow to the wellbore. The availability of large volumes of water is crucial to northeastern British Columbia’s shale development. In 2008, Apache reported using 280,000 barrels of water in 18 fracture stimulations for 3 horizontal Horn River wells.715

The Utica Shale, Québec

Geology and Basin Metrics The Utica Shale is among the oldest and most widespread of black shales in North America, stretching from Pennsylvania and New York to Québec. The -aged shale is located in the enormous Appalachian Basin and derives its name from Utica, New York. The shale play is, however, characterized as Utica deep and Utica shallow. The Utica deep extends from northern New York State down to Pennsylvania. Recall another large potential shale play in New York, Pennsylvania, West Virginia and eastern Ohio—the Marcellus Shale. While the Marcellus is garnering more attention the deep Utica is slowly gaining steam. The shallow Utica, on the other hand, is located in Québec, with the best prospects lying within a corridor that runs parallel with the St. Lawrence River southeast of Montréal up to Québec City.

This is illustrated in Figure 3.15. This study only the shallow Utica is discussed.

714 Spectra Energy website, http://www.spectraenergy.com/our_responsibility/climate/carbon_capture/ (accessed on March 4, 2009) 715 Apache Corporation, “Apache Announces Three Successful Horizontal Wells at Ootla Shale Gas Play in Northeast British Columbia Release”, April 8, 2008. http://investor.apachecorp.com/releasedetail.cfm?ReleaseID=303676 (accessed on September 14, 2010)

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Figure 3.15 Location of Utica Shale

Source: Forest Oil 2008 Analyst Conference, April 1, 2008.

While there is currently no commercial production, Québec’s Utica Shale is attracting a lot of attention from North American E&P companies. Many industry pundits draw comparisons between Utica and Barnett shale in Texas, the most prolific shale formation in North America. Given its proximity to US Northeast markets, the gas could well command a premium to NYMEX, whereas the more developed shale plays in British Columbia are located further from consuming markets.

Estimates in the Utica Shale ranges between 2 Tcf up to 69 Tcf of natural gas.716 This would make it one of the largest in North America. Wellington West Capital Markets suggest that initial estimates of the resource potential play could be 25 Tcf of recoverable resources, with the best prospects lying within a corridor that runs parallel with the St. Lawrence River southeast of Montreal up to Québec City.717 Total estimated OGIP volumes for Questerre's gross acreage are between 82.7 Tcf to 180.5 Tcf, while recoverable estimates range from 2.2 Tcf to 8.0 Tcf.718

The Ordovician-aged Utica lies in at a depth range of 2,300-6,000 ft., which is shallower than the Montney at 6,600-8,200 ft. and the Barnett Shale which is at 4,500-9,000 ft. The Utica deep, on the other hand, lies at a depth range of 12,000 to 15,000 ft. In terms of thickness and porosity, the Utica Shale averages 500 ft. and 3.5, respectively. This is shallower and thicker than the Montney at 950 ft., but is comparable to the Horn River Basin which ranges between 360 ft. and 580 ft. The Barnett Shale ranges in thickness from 150 ft. to 700 ft. Both of these shales have excellent thickness. The Utica Shale’s thermal maturity is 1.0-3.0 Ro and has a TOC content of 2.5-6.0. The latter is identical to the Horn River Basin Shale’s TOC content (2.5-6.0 percent).

716 “Utica Shale Gas Players – Needing News to Move”, http://www.jimletourneau.com/2009/01/utica-shale-gas- players-needing-news-to-move/#ixzz13EQiylfy (accessed on September 14, 2010) 717 Energy Strategy – The Utica Shale Gas Play, Part II, May 28, 2008. 718 ibid

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Table 3.10 provides a summary of key geological characteristics of the Utica Shale.

Table 3.10 Utica Shale Geological Characteristics Parameter Utica Shale Geological age Ordovician Depth range (ft) 2,300-6,000 Shale thickness (ft), gross 500 GIP/sq mi (Bcf) 93 Porosity (%) 3.5 Total organic carbon (%) 2.5-6.0 Thermal maturity (Ro) 1.0-3.0 Silica content (%) 5-25* Pressure gradient (psi/ft) 0.45-0.60 Source: Deutsche Bank, 2008719 and *NEB720.

Table 3.11 provides the basin metrics for the Utica Shale. The geology of the Utica Shale is both attractive, drawing comparisons with the Barnett Shale, and unique which brings potential challenges. While it is a thick shale play (500 ft.), it is also a shallow play. In addition, what makes the Utica Shale unique among its shale peers is that it has an unusually high calcite or dolomite, approximately 30-70 percent.721 These unique attributes bring potential unique challenges.

Table 3.11 Basin Metrics for the Utica Shale Parameter Utica Shale Average Well Cost ($MM) 2.5-4.0 Depth range (ft) 2,300-6,000 IP Rate (MMCFPD) n/a Expected EUR/Well (BCFE) 2.5 Threshold Price ($/MCFE) n/a Expected F&D Cost ($/MCFE) 2.00-2.10 Expected Recovery Factor (%) 20 Lateral lengths (ft) 2000 Fracturing stages 4 Typical Well Spacing (acres/well) 100 Source: Deutsche Bank, 2008.722

Québec’s Utica play is shallower than some of the other shales (such as the Barnett) and has pipeline infrastructure available. This is a drawback for more remote shale plays such as the Horn River basin in northeastern British Columbia. Table 3.12 illustrates the similar geological features between the Utica and Barnett Shales, including depth, thickness, clay content, pressure gradient and gas-filled porosity.

719 “From Shale to Shining Shale”, Deutsche Bank, July 22, 2008, pp. 42. 720 “A Primer for Understanding Canadian Shale Gas”, National Energy Board, November 2009, pp. 15. 721 ibid 722 “From Shale to Shining Shale”, Deutsche Bank, July 22, 2008, pp. 42.

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Table 3.12 Comparing Geological Features Utica Barnett

Depth (ft) 2,300-6,000 4,500-9,000 Thickness (ft) 500 150-700 Clay Content (%) 15-26 15-30 Gas-filled Porosity (%) 3.2-3.7 3.0-4.8 Pressure Gradient (psi/ft) 0.45-0.60 0.46-0.50 Source: Forest Oil 2008 Analyst Conference, April 1, 2008.723

E&P Players and Recent M&A Activity While the play is still in the exploratory and development stage, as initial testing is still underway, the Utica Shale has attracted attention from major oil and gas companies in recent years. Currently, the top two players are Forest Oil and Talisman Energy Inc. Other Utica players include Questerre Energy, Canadian Quantum, Equitable Resources, Gastem, Range Resources, Altai Resources, Junex and Greencastle Resources.

The following will discuss the two main players in the Utica Shale: Forest Oil and Talisman.

Forest Oil was the first E&P in the Utica. In fact, early in April 2008, Forest Oil actually announced the discovery of a new gas play in the Utica Shale in the St. Lawrence basin.724 The company spent the previous several years defining the play and acquiring acreage. Two joint partners early in the process were two Quebec-based companies, Junex Inc. and Gastem.725 Forest Oil drilled three vertical wells in 2006 and 2007, including the Bécancour #8 (with Junex), Saint François du Lac #1 (with is Gastem) and Gastem Saint Louis #1 (with is Gastem).726 The Bécancour #8 and the Saint François du Lac #1 were fracture stimulated.

Forest Oil has close to 270,000 net lease acres over the 100 kilometers of the St. Lawrence River between Montréal and Québec City.727 The company believes the play has the potential to deliver as much as 4 Tcf into the area, based on two vertical wells drilled in 2007 (tested rates up to 1,000 Mcfpd).728 Forest Oil drilled three horizontal wells and was scheduled to begin frac’ing wells in the 4Q2008. Initial production rates were reported as being between 100 and 800 Mcfpd.729 This is lower than the initial production rates in other major shale plays. Each well, targeting a different section of the Utica, were facture stimulated in four stages. 730 Recall that due to the low permeability inherent in gas shales, stimulation is almost always required. This process requires substantial amounts of water and sand to allow the gas to flow to the wellbore.

In 2008 Forest Oil expected full-scale development to occur in 2010, in spite of limited drilling and production history in the area. This, however, has not occurred. In 2Q2010 the company has been collecting seismic data and

723 Utica Shale Play in Quebec –Forest Oil Announced New Trend, Canaccord-Adams, April 2008, pp. 6. 724 Utica Shale Play in Quebec –Forest Oil Announced New Trend, Canaccord-Adams, April 2008, pp.2. 725 Utica Shale Play in Quebec –Forest Oil Announced New Trend, Canaccord-Adams, April 2008, pp.3. 726 ibid 727 Utica Shale Play in Quebec –Forest Oil Announced New Trend, Canaccord-Adams, April 2008, pp.2. 728 “From Shale to Shining Shale”, Deutsche Bank, July 22, 2008, pp. 42. 729 “It's Too Soon To Play The Utica Shale”, April 7, 2009, http://stocks.investopedia.com/stock-analysis/2009/its- too-soon-to-play-the-utica-shale-fst-tlm-rrc-eqt0407.aspx (accessed on September 12, 2010) 730 oilshalegas.com/uticashale.html (accessed on September 14, 2010)

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118 Canadian Energy Research Institute conducting rock analysis.731 The company is still very active in other plays in the US, including the Eagle Ford Shale in Texas and Nikanassin, near Brule, Alberta.732

Talisman is very active in the Utica, and other shales including the Horn River Basin and the Montney Shale. Talisman Energy has 760,000 net acres in the St. Lawrence lowlands and is now the largest active operator in the shale play, surpassing Forest Oil.733 According to Talisman, the Gentilly well in the Utica shale was successful in September 2008. The well, located about 100 kilometers south of Québec City, flowed at 800 Mcfpd.734 Following success, the Calgary-based company has three more wells planned for 2008.735 Production tests ranged from 200 to 900 MMcfpd in Talisman’s wells.736

By 2Q2010, Talisman drilled four horizontal wells, with a fifth in early August 2010.737 The company expects to have three producing wells by the end of 3Q2010 and five by the end of 2010.738

Development Outlook & Drilling Forecasts Technological advances and increasing drilling efficiencies appear to be offsetting lower gas prices. Between the geology, proximity to the market and the Utica’s excellent GIP potential, drilling activity in Québec is expected to increase.

In the NEB’s Short-term Natural Gas Deliverability 2010-2012, the study suggested that within the timeframe of their analysis, commercial volumes within the Utica are unlikely to be substantial.739 Drilling activity is, however, expected to increase—albeit moderately—in the Utica Shale.

Various corporate highlights are illustrated below.

• Talisman plans to have three producing wells by the end of 3Q2010 and five by the end of 2010.740

• Montreal-based Gastem is moving forward with pilot projects in 2010, including one with Talisman as a partner. The company has 486,000 gross acres in the Utica and Lorraine Shale and has 35,000 gross acres in the deeper Utica in New York.741

• Forest and Junex have plans to drill a vertical pilot hole well in winter 2010, followed by drilling and completion of a horizontal wellbore.

731 ibid 732 http://drippingoil.blogspot.com/2010/09/forest-oil-nysefst-upgraded-by-barclays.html (accessed on September 12, 2010) 733 oilshalegas.com/uticashale.html (accessed on September 14, 2010) 734 ibid 735 ibid 736 “The Utica Shale Gains Ground”, September 7, 2010, http://stocks.investopedia.com/stock-analysis/2010/The- Utica-Shale-Gains-Ground-TLM-FST-RRC-ATLS0907.aspx (accessed on September 12, 2010) 737 ibid 738 ibid 739 “Short-term Canadian Natural Gas Deliverability 2010-2012”, National Energy Board, March 2010, pp. 2 740 ibid 741 oilshalegas.com/uticashale.html (accessed on September 14, 2010)

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Additional Information As previously discussed in Chapter 1, Québec’s Ministère des Resources Naturelles et de la Faune oversees oil and gas activities within the province, from exploration and development to drilling and decommissioning.742 The large department also regulates the development and use of land, energy, forestry and mineral resources in Québec.743 The organization’s mandate also currently includes public safety and environmental issues. While oil and gas played a small role, the potential of the Utica has changed a few things, including creating a new oil and gas regulatory framework.

On August 31, 2010, Quebec’s Cabinet mandated the Bureau d’Audiences Publiques sur l’Environnement (BAPE – Public Hearings on the Environment Board) to propose a framework for shale gas exploration and development in the province.744 Public hearings began September 14, 2010 and ministers have encountered loud opposition from environmentalists and residents in the area.745

Other Shale Gas Plays As previously mentioned, the following section discusses five other shales that are emerging and have potential. Unlike the previous sections that are divided into four sections—geology and basin metrics, E&P players and recent M&A activity, development outlook and drilling forecasts, and additional information—this section only discusses the geology and basin metrics of the particular shale gas play.

The five shale gas plays discussed in this section are the Barnett-Woodford Shale, the Chattanooga Shale, the Gothic-Hovenweep Shales, the Mancos Shale and the Pierre Shale. For shale plays not discussed in this study, please refer to the complete list of shales in Appendix B.

The Barnett-Woodford Shale, Delaware & Marfa Basins, West Texas While Texas is home to the most prolific shale play in the US—the Barnett Shale—the state is also home to the Delaware and Marfa Basin’s, located in West Texas. The Delaware Basin, a part of the Permian Basin, is in particular drawing attention from E&Ps for prolific potential. The Delaware and Marfa basins are home to the Barnett-Woodford Shale, not to be confused with the East Texas’s Barnett Shale. That being said, the Barnett- Woodford Shale, as the name suggests, is the equivalent to the Barnett Shale located in the Fort Worth Basin and the Woodford Shale in Oklahoma. The shale play is sometimes referred to as the Barnett Shale-Woodford Shale. The Devonian-aged Woodford underlies the Mississippian-aged Barnett shales.746 The two shales are separated by a dense Mississippian Limestone interval.747

742 http://www.ogc.gov.bc.ca/documents/annualreports/Oil_and_Gas_Water_Use_in_BC.pdf, pp. 4. 743 Ministère des Ressources Naturelles et de la Faune website, http://www.mrnf.gouv.qc.ca/english/department/index.jsp (accessed on September 14, 2010) 744 “Shale Gas: Anticipated Changes to Quebec’s Regulatory Framework”, Blakes website, http://www.blakes.com/english/view.asp?ID=4214 (accessed on September 14, 2010) 745 “Quebec shale gas debate heats up”, CBC website, http://www.cbc.ca/canada/montreal/story/2010/08/29/que-shale-gas.html (accessed on September 14, 2010) 746 Cluff, Bob, Barnett Shale-Woodford Shale play of the Delaware basin, The Discovery Group Inc., pp. 2. 747 ibid

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The Barnett-Woodford Shale is located primarily in eastern Texas but does extend into New Mexico. Figure 3.16 illustrates the location of the Barnett-Woodford Shale. It is important to note that the larger yellow area illustrates roughly the location of the Maverick Basin while the smaller yellow circle, north of Big Bend National Park, illustrates the Marfa Basin. It is very important to note that the Barnett-Woodford and the Barnett Shale are situated along the Ouachita Fold Belt. Also situated near the Quachita belt, to the east, is the Fayetteville Shale (Arkoma Basin, Arkansas), Woodford Shale (Oklahoma) and the Floyd-Neal, located in the Black Warrior Basin (BWB) in Mississippi and Alabama.748

Figure 3.16 The Barnett-Woodford Shale

Source: www.bjservices.com749

The Barnett-Woodford Shale is attracting a lot of attention for its gas shale potential, especially considering the play has similar geology to its neighbour to the east. While the Permian Basin is best known for producing billions of barrels of oil, the area is raising eyebrows for its vast potential of natural gas. The US’s Geological Survey National Assessment estimates a mean of 41 Tcf of undiscovered gas is in the Delaware Basin.750 This is in addition to 1.3 billion barrels of undiscovered oil.751 The numbers, however, could be much higher. The Denver-based Discovery Group suggests that while the question of whether or not the area is commercial is still too early to tell, the organization believes the Barnett-Woodford Shale may contain over 800 Tcf of gas.752 The organization

748 Bowker, Kent, Bowker Petroleum, “Recent Activity in the Floyd, Neal, and Chattanooga Shale Plays, Black Warrior Basin, Alabama and Mississippi”, 2008, pp. 8. 749 BJ Services website, http://www.bjservices.com/website/index.nsf/webpages/Shale-West-Texas-Barnett- Woodford-Page?OpenDocument (accessed on November, 7, 2010) 750 “Delaware Basin gas reserves prove tough to coax from ground”, Mella McEwen, http://www.mywesttexas.com/business/oil/top_stories/article_97011f25-1322-59e5-ae4e-a1706c70a252.html (November 8, 2010) 751 ibid 752 Cluff, Bob, Barnett Shale-Woodford Shale play of the Delaware basin, The Discovery Group Inc., pp. 31.

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suggests that much of the gas may be too deep to be commercial.753 The sweet spot in the Delaware Basin is in Reeves, Culberson and Jeff Davis counties.754

The vast potential is attracting some of the largest and most experienced players in the shale gas industry, including EnCana, Chesapeake Energy, Quicksilver, EOG Resources, ConocoPhillips, Southwestern Energy, Carrizo Oil & Gas, Devon Energy, Forest Oil and others.755 The largest landholders in the Delaware Basin are EnCana (560,000 to 850,000 net acres), Chesapeake (385,000 net acres) and Quicksilver (310,000 net acres).756 Given the technological challenges involved in developing the deep shale gas and the steep learning curve, thus far it appears that companies are keeping their information to themselves.757

The smaller Marfa Basin is attracting attention as well—albeit to a smaller scale. The Marfa’s shale is tectonically more complicated and deeper than the shale targets in the Delaware Basin.758 TXCO Resources, Continental Resources, Quicksilver Resources, Carrizo Oil & Gas and Ascent Energy are companies that have been active in the Marfa Basin.759 TXCO and Continental have a 50 percent working interest in leases totaling 135,000 net acres. 760 Most activity is occurring in the counties of Presido and Brewster.761

While the Hilliard-Baxter lies at a depth of 10,000-19,500 ft., the Barnett-Woodford Shale lies at a depth range of 5,100-15,300 ft. The Mississippian-aged Barnett is the shallower of the two in the range, and comparable to the Barnett Shale of the Fort Worth Basin, which lies at a depth range of 6,500-9,000 ft. In terms of thickness, the Barnett-Woodford is 125-800 ft., between the two shales. More specifically, the Woodford shale thickness is 125- 350 ft. while the thicker Barnett shale is 400-800 ft. This is comparable to the Barnett Shale’s thickness, which is 200-1,000 ft. in the Core/Tier 1 and 100-250 ft. in the South/Western. The Barnett-Woodford has a TOC content of 4-7 percent and its GIP/sq mi is 50-300 Bcf. While lagging behind the Hilliard-Baxter’s GIP/sq mi of 440 Bcf, the Barnett-Woodford’s GIP is considered quite high. It is interesting to note the high well cost in the Barnett- Woodford. Much of this can be attributed to the complicated geology and the depth of some of the shale, more specifically the Woodford shales.

Table 3.13 provides a summary of the Barnett-Woodford’s key geological characteristics and metrics. It is important to note that the following includes the Marfa Basin.

753 ibid 754 Permian Basin Petroleum Association, Unconventional Shale Gas Plays, http://www.pbog.com/index.php?page=article&article=8luff (accessed on November 7, 2010) 755 Cluff, Bob, Barnett Shale-Woodford Shale play of the Delaware basin, The Discovery Group Inc., pp. 4. 756 ibid 757 Permian Basin Petroleum Association, Unconventional Shale Gas Plays, http://www.pbog.com/index.php?page=article&article=8luff (accessed on November 7, 2010) 758 “Marfa Basin”, Peggy Williams, Oil and Gas Investor, October 2006, pp. 1. 759 “Marfa Basin”, Peggy Williams, Oil and Gas Investor, October 2006, pp. 3. 760 “Woodford Shale Exploration in Marfa Basin”, April 17, 2010, http://www.theinfomine.com/2010/04/17/woodford-shale-exploration-in-marfa-basin/ (accessed on November 8, 2010) 761 “Marfa Basin”, Peggy Williams, Oil and Gas Investor, October 2006, pp. 3.

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Table 3.13 Barnett-Woodford Shale Geological Characteristics Parameter Barnett-Woodford Shale Devonian (Woodford) & Geological age Mississippian (Barnett) Depth range (ft) 5,100-15,300 Barnett shale thickness (ft), gross 400-800 Woodford shale thickness (ft), gross 125-350 GIP/sq mi (BCF) 50-300 Total organic carbon (%) 4.0-7.0 EUR/Well (BCFE) 3.0 F&D Cost ($/MCFE) 2.50 Typical well spacing (acres/well) 160 Well Cost ($MM) 6.50 Source: Deutsche Bank, 2008.762

The Chattanooga Shale, Alabama/Tennessee The Chattanooga Shale is located mostly in Alabama and Tennessee, but does extend into southern Kentucky and northeastern Georgia. This is illustrated roughly with the grey area in Figure 3.17.

Figure 3.17 Chattanooga Shale

Source: http://geopetesview.blogspot.com/2009_02_21_archive.html

The Chattanooga Shale underlies the Floyd-Neal Shale, more specifically the Floyd Shale in Alabama, and is separated by a band of sandstone.763 The Upper Mississippian-era Floyd-Neal is located in the Black Warrior Basin Province (BWB), along the Ouachita Fold Belt.764 The other shale that is in the area and garnering a fair amount of interest and excitement is the Conasauga Shale. It is located entirely in Alabama, east of the BWB, in the counties

762 “From Shale to Shining Shale”, Deutsche Bank, July 22, 2008, pp. 38. 763 Geological Survey of Alabama, “An Overview of the Floyd Shale & Chattanooga Shale Gas Play in Alabama” (July 2009), pp. 4. 764 Bowker, Kent, Bowker Petroleum, “Recent Activity in the Floyd, Neal, and Chattanooga Shale Plays, Black Warrior Basin, Alabama and Mississippi”, 2008, pp. 8.

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of St. Claire, Jefferson, Blount, Etowah, Calhoun and Cherokee.765 Figure 3.18 shows the various shale plays in Alabama.

Figure 3.18 Shale Gas Development in Alabama

Source: http://www.gsa.state.al.us/gsa/shalegas.html

The Devonian-aged Chattanooga Shale is the equivalent to the Marcellus Shale which lies to the northeast of the Chattanooga, along the Appalachian Thrust Belt.766 In fact, the Chattanooga Shale is an extension of the Appalachian Basin Devonian Shale, or the Marcellus Shale.767 The Chattanooga Shale is also equivalent to the Woodford Shale in Oklahoma.768 Recall that both the Marcellus and the Woodford are Devonian formations.

While in its infancy, the organic, hydrocarbon rich shale is attracting several companies: Atlas Energy, CNX Gas Company and GeoMet (GMET).769 Atlas is the largest leaseholder with 105,000 net acres in eastern Tennessee; the company also suggests that its acreage may contain nearly 500 potential drilling locations.770 According to a company news release, Atlas plans to drill up to 50 horizontal wells in the next 18 months.771 CNX is planning to drill 25 well in the Chattanooga Shale in 2010.772

While the Barnett Shale lies at a depth range of 6,500-9,000 ft., the Chattanooga Shale lies at a range of 1,600- 4,000 ft. In terms of thickness, the Devonian-aged Chattanooga is 35-200 ft. has a TOC content of 4.0-6.0 percent

765 oishalegas.com/alabamashale.html (accessed November 7, 2010) 766 Jack Pashin, “Gas Shale Potential of Alabama”, Geological Survey of Alabama, pp. 3. 767 http://oilshalegas.com/chattanoogashale.html (accessed November 12, 2010) 768 http://geopetesview.blogspot.com/2009_02_21_archive.html (accessed November 12, 2010) 769 http://oilshalegas.com/chattanoogashale.html (accessed November 12, 2010) 770 ibid 771 Atlas Energy Resources website, http://phx.corporate-ir.net/phoenix.zhtml?c=202140&p=irol- newsArticle&ID=1168269&highlight= (November 14, 2010) 772 http://oilshalegas.com/chattanoogashale.html (accessed November 12, 2010)

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Table 3.14 provides a summary of the Chattanooga’s key geological characteristics and metrics. It is important to note that the following includes the Marfa Basin.

Table 3.14 Chattanooga Shale Geological Characteristics Parameter Chattanooga Shale Geological age Late Devonian Depth range (ft) 1,600-4,000 Shale thickness (ft), gross 35-200 Total organic carbon (%) 4.0-6.0 Lateral lengths (ft) 3,000 IP rates (MMCFPD) 0.3-0.5 Well Cost ($MM) 1.1 Source: Deutsche Bank, 2008.773

The Gothic & Hovenweep Shales, Paradox Basin, Colorado/New Mexico The Gothic Shale of the Paradox Basin is gaining attention. Also located in the Paradox Basin is the Hovenweep Shale. Both -aged shales are black, organic-rich marine shale.774 The Hovenweep Shale overlies the deeper and older Gothic Shale. The former covers roughly 1,300 square miles while the latter is nearly 1,850 square miles in size.775

The Paradox Basin is located in southeastern Utah and southwestern Colorado. The basin is south of the Uinta Basin in Utah and the Piceance Basin in Colorado. Colorado counties include Montezuma, Dolores, La Plata, and San Miguel, while counties in Utah include San Juan, Garfield and Wayne.776 Figure 3.19 illustrates the location of the Paradox Basin. At times this shale is known as the Hermosa, named after the Hermosa Formation.777

773 “From Shale to Shining Shale”, Deutsche Bank, July 22, 2008, pp. 38. 774 http://www.rpsea.org/attachments/contentmanagers/3328/Coalbed_and_Shale_Gas_Symposium-Forum- Potential_Paleozic_Shale_Gas_in_Utah-Tom_Chidsey_5-19-10.pdf (accessed on October 28, 2010) 775 http://www.billbarrettcorp.com/pdf/2008/July%2010%202008%20COGA.pdf (pp. 29) 776 http://buffaloroyalties.com/SWColorado.aspx (accessed on October 27, 2010) 777 http://www.searchanddiscovery.net/abstracts/html/2009/annual/abstracts/moreland.htm (accessed on October 28, 2010)

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Figure 3.19 The Paradox Basin

Source: http://buffaloroyalties.com/SWColorado.aspx

The Paradox Basin is rich in various natural resources, including oil, gas, uranium, potash and copper. The Greater Aneth oil field and Utah’s largest oil producer is located in the Paradox Basin.778 Discovered in 1956, the Greater Aneth has produced over 450 million barrels of oil.779 The Cane Creek Shale and the Chimney Rock Shale are located in the Paradox Basin but are not discussed in this study.

And while the extent of the gas potential is not yet determined, test wells thus far indicate the potential may be world-class.780 With a 397,000 gross acreage position, the largest shale gas player is Bill Barrett Corporation.781 The company has drilled and completed several gas wells in the Gothic shale, most notably in Montezuma County, Colorado.782 Bill Barrett reports flow rates between 3.1 MMcfpd and 5.7 MMcfpd on several horizontal test wells in the Gothic Shale.783 The test wells are a part of the Yellow Jacket Shale Gas Prospect.

778 http://geology.utah.gov/blog/?tag=gothic-shale 779 abid 780 “A Grand Opportunity”, Tidewater Oil & Gas Company, LLC, Presentation, pp. 2. 781 http://www.marketwire.com/press-release/Bill-Barrett-Corporation-Reports-Gothic-Shale-Gas-Discovery-Third- Quarter-2008-Results-NYSE-BBG-916977.htm 782 http://www.marketwire.com/press-release/Bill-Barrett-Corporation-Reports-Gothic-Shale-Gas-Discovery-Third- Quarter-2008-Results-NYSE-BBG-916977.htm 783 http://www.marketwire.com/press-release/Bill-Barrett-Corporation-Reports-Gothic-Shale-Gas-Discovery-Third- Quarter-2008-Results-NYSE-BBG-916977.htm

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While the Pierre Shale lies at a depth of 4,000-6,000 ft., the Gothic lies at a depth range of 5,500-7,500 ft. Both of these shales are comparable to the Barnett Shale which lies at a depth range of 6,500-9,000 ft. In terms of thickness, the Gothic is 80-150 ft. This is considerably thinner than the Pierre, in which the thickness of the shale ranges between 2,200 and 2,800 ft. The Mancos Shale averages 3,000 ft. The Gothic is, however, comparable to the Barnett Shale’s thickness, which is 200-1,000 ft. in the Core/Tier 1 and 100-250 ft. in the South/Western. It is important to note that the Hovenweep Shale’s shale thickness ranges between 20 and 140 ft.784 The Gothic’s TOC content, porosity and GIP/sq mi are undetermined in the emerging shale. Test wells have indicated that lateral lengths will be in the 1,500 and 3,500 ft. range, while well cost is expected to be between US$3.8 to US$5.0 million per well.

Table 3.15 provides a summary of the Gothic’s key geological characteristics and metrics. It is important to note that the following includes the Hovenweep Shale.

Table 3.15 Gothic Shale Geological Characteristics Parameter Gothic Shale Geological age Pennsylvanian Depth range (ft) 5,500-7,500 Shale thickness (ft), gross 80-150 GIP/sq mi (BCF) n/a Porosity (%) n/a Total organic carbon (%) n/a Lateral lengths (ft) 1,500-3,500 Well Cost ($MM) 3.8-5.0 Source: Deutsche Bank, 2008.785

The Mancos Shale, Utah/Colorado The Mancos Shale is an Upper Cretaceous geologic formation in the Western US. The shale is widespread and occurs in the following basins: Green River, Paradox, Piceance, San Juan, Uinta, Black Mesa, Estancia and the Orogrande.786 As such, the enormous Mancos Shale is spread across Wyoming, Utah, Colorado, New Mexico and Arizona. Recall the discussion about the Hilliard-Baxter Shale and the fact that it is sometimes known as the Hilliard-Baxter-Mancos or the Hilliard-Baxter-Mancos Interval. Because of its range, Haliburton has labeled the Mancos Shale as “the single most significant shale deposit in the western US.”787

The Mancos Shale is often used to describe the shale play located in the Uinta Basin and the Piceance Basin.788 The former is located in Utah while the latter is located in western Colorado. The two basins, illustrated in Figure 3.20, are separated by the Douglas Creek Arch. In addition both basins are located south of the GGRB, in which the

784 http://www.billbarrettcorp.com/pdf/2008/July%2010%202008%20COGA.pdf 785 “From Shale to Shining Shale”, Deutsche Bank, July 22, 2008, pp. 41. 786 USGS website, Mancos Shale, http://3dparks.wr.usgs.gov/coloradoplateau/lexicon/mancos.htm (accessed on October 21, 2010) 787“The Mancos Shale”, Haliburton, http://www.halliburton.com/public/solutions/contents/Shale/related_docs/Mancos.pdf, pp. 2 (accessed on October 21, 2010) 788 EIA website, http://www.eia.doe.gov/oil_gas/rpd/shale_gas.pdf (accessed on October 21, 2010)

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Hilliard-Baxter Shale is located. It is also important to note that the Uinta and Piceance Basins, like the GGRB, also contain coal and massive amounts of oil shale, in addition to conventional natural gas and gas shale.

Figure 3.20 Uinta and Piceance Basins Map

Source: USGC789

Figure 3.21 illustrates the Mancos Shale’s proximity to the GGRB. The Figure is identical to Figure 3.7 illustrating the GGRB and the location of the Hilliard-Baxter Shale.

Figure 3.21 GGRB and the Uinta and Piceance Basins Map

Source: http://oilshalegas.com790

789 USGC website, http://pubs.usgs.gov/dds/dds-069/dds-069-b/fig1.gif (accessed on October 6, 2010)

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The US’s Geological Survey National Assessment estimates that approximately 11.8 Tcf of gas is technically recoverable in the Mancos-Mowry Total Petroleum System.791 The same organization estimates the entire Uinta- Piceance Province to contain a total of 21 Tcf of technically recoverable gas.792 The Mesaverde Total Petroleum System is estimated to contain 13 Tcf of technically recoverable gas.

While the Hilliard-Baxter lies at a depth of 10,000-19,500 ft., the Mancos Shale lies at a depth range of 13,000- 17,500 ft. The Barnett Shale lies at a depth range of 6,500-9,000 ft. While the Barnett is considered an ideal depth, in that the shale is more likely to be over pressured and easier to extract, the Mancos Shale, like the Hilliard- Baxter, is considered very deep and over pressured. In terms of thickness and porosity, the Mancos Shale averages 3,000 ft. and 2.0-5.0 percent, respectively. The Barnett Shale’s thickness is 200-1,000 ft. in the Core/Tier 1 and 100- 250 ft. in the South/Western. The Mancos Shale has a TOC of 1.4 percent while its GIP/sq mi is 280-350 Bcf. While lagging behind the Hilliard-Baxter’s GIP/sq mi of 440 Bcf, the Mancos is still one of the highest GIP/sq mi of any gas shale play in the US.

Table 3.16 provides a summary of the Mancos’s key geological characteristics.

Table 3.16 Mancos Shale Geological Characteristics Parameter Mancos Shale Geological age Upper Cretaceous Depth range (ft) 13,000-17,500 Shale thickness (ft), gross 3,000 GIP/sq mi (BCF) 280-350 Porosity (%) 2.0-5.0 Total organic carbon (%) 1.4 Thermal maturity (Ro) n/a Silica content (%) n/a Pressure gradient (psi/ft) 0.66 Source: Deutsche Bank, 2008.793

Table 3.17 provides the basin metrics for the Mancos Shale.

790 http://oilshalegas.com/greenriveroilshale.html (accessed on October 6, 2010) 791 USGS Uinta-Piceance Assessment Team, “Chapter 1: Executive Summary – Assessment of Undiscovered Oil and Gas Resources of the Uinta-Piceance Province of Utah and Colorado, 2001”, USGC Data Series DDS-69-B, 2005, pp. 3. 792 ibid 793 “From Shale to Shining Shale”, Deutsche Bank, July 22, 2008, pp. 40.

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Table 3.17 Basin Metrics for the Mancos Shale Parameter Mancos Shale Well Cost ($MM) 4.0-8.0 Depth (ft) 13,000-17,500 IP Rate (MMCFPD) 1-2 EUR/Well (BCFE) ~1 Threshold Price ($/MCFE) n/a F&D Cost ($/MCFE) 2.00 Expected Recovery Factor (%) 5-15 Lateral lengths (ft) n/a Fracturing stages n/a Typical Well Spacing (acres/well) 40-80 Source: Simmons & Co., various company reports.794

The Pierre Shale, Raton Basin, Colorado/New Mexico It is, however, important to note that like the Mancos Shale which is widespread, so too is the Pierre Shale. The Upper Cretaceous-aged shale occurs east of the Rocky Mountains in the Great Plains, extending from North Dakota to New Mexico. The portion of the Pierre Shale that is of interest is located in the Raton Basin, in the states of Colorado and New Mexico. The Pierre Shale in the Raton Basin is illustrated in Figure 3.22.

Figure 3.22 The Pierre (Raton Basin) Shale Map

Source: USGC795

794 ibid

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The shale is sometimes referred to as the Pierre/Niobrara Shale, named after the Niobrara Formation which overlies the Pierre Shale. This can, however, sometimes be confusing, as the Niobrara Shale is a separate shale located in Wyoming, Colorado and Nebraska. The Niobrara Shale is also attracting a lot of attention for its oil shale potential, leading some industry pundits to compare it to the enormous Bakken Oil Shale located in Montana, North Dakota and Saskatchewan. For the context of this study it is simply referred to as the Pierre Shale, as is the case of the EIA labeling the shale gas play in Colorado and New Mexico.

The location of the shale is illustrated in Figure 3.23. The Pierre is located near the bottom of the map and is labeled Raton Basin.

Figure 3.23 The Pierre Shale (Raton Basin) and Area Map

Source: UGcenter796

The US’s Geological Survey National Assessment estimates a mean of 2.35 Tcf of undiscovered and a mean of 28.1 million of undiscovered natural gas liquids in the Raton Basin-Sierra Grande Uplift Provence.797 The numbers, however, could be much higher. Pioneer Natural Gas is a large player in the Pierre shale play, holding 134,000 net acres.798 The company suggests that under its own acreage the OGIP could be as high as 21 Tcf.

While the Hilliard-Baxter lies at a depth of 10,000-19,500 ft., the Pierre Shale lies at a depth range of 4,000-6,000 ft. This is comparable to the Barnett Shale which lies at a depth range of 6,500-9,000 ft. In terms of thickness and porosity, the Pierre is 2,200-2,800 ft. and 2.0-6.0 percent, respectively. Recall, the Mancos Shale averages 3,000 ft.

795 USGC website, http://pubs.usgs.gov/fs/2005/3027/images/AllCellsRatonNoFlt_opt.jpg (accessed on October, 27, 2010) 796 UGcenter website, http://www.ugcenter.com/resources/images/niobrara_shale.gif 797 USGS Uinta-Piceance Assessment Team, “Assessment of Undiscoverd Oil and Gas Resources of the Raton Baton- Sierra Grande Uplift Provence of New Mexico and Colorado, 2004”, Fact Sheet 2005-3027, April 2005, pp. 1. 798 Williams, Peggy, “Raton Basin home of Pierre shale play”, April 28, 2008, Oil & Gas Investor, http://blogs.oilandgasinvestor.com/peggy/2008/04/12/raton-basin-home-of-pierre-shale-play/ (accessed on October, 27, 2010)

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and is 2.0-5.0 percent, respectively. This is considerably thicker than the Barnett Shale’s thickness, which is 200- 1,000 ft. in the Core/Tier 1 and 100-250 ft. in the South/Western. The Pierre Shale has a TOC content of 1.6-2.6 percent. This is comparable to the Hilliard-Baxter Shale. The GIP/sq mi is approximately 100 Bcf.

Table 3.18 provides a summary of the Pierre’s key geological characteristics and metrics.

Table 3.18 Pierre Shale Geological Characteristics Parameter Pierre Shale Geological age Upper Cretaceous Depth range (ft) 4,000-6,000 Shale thickness (ft), gross 2,200-2,800 GIP/sq mi (BCF) 100 Porosity (%) 2.0-6.0 Total organic carbon (%) 1.6-2.6 Thermal maturity (Ro) 2.0-2.8 F&D Cost ($/MCFE) 1.65-2.00 Expected Recovery Factor (%) 16 Typical Well Spacing (acres/well) 80 Pressure gradient (psi/ft) 0.66 Source: Deutsche Bank, 2008.799

799 “From Shale to Shining Shale”, Deutsche Bank, July 22, 2008, pp. 41.

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February 2011 North American Natural Gas Dynamics: 133 Shale Gas Plays in North America – A Review Appendix A A List of Frac Fluid Additives

Table A.1 Frac’ing Fluid Additives, Main Compounds and Common Uses800 Common Use of Main Additive Type Main Compound Purpose Compound Hydrochloric acid or Helps dissolve mineral and Swimming pool cleaner and Diluted Acid (15%) muriatic acid initiate cracks in the rock cleaner Eliminates bacteria in the water Disinfectant; sterilize medical and that produce corrosive by- dental equipment Biocide Glutaraldehyde products Bleaching agent in detergent and Allows a delayed break down of hair cosmetics, manufacture of the gel polymer chains Breaker Ammonium persulfate household plastics Prevents the corrosion of the Used in pharmaceuticals, Corrosion Inhibitor N,n-dimethyl formamide pipe acrylic fibers, plastics Maintains fluid viscosity as Laundry detergents, hand Crosslinker Borate salts temperature increases soaps, and cosmetics Water treatment, soil Polyacrylamide Minimizes friction between the conditioner Friction Reduce fluid and the pipe Make-up remover, laxatives, Mineral oil and candy Guar gum or hydroxyethyl Thickens the water in order to Cosmetics, toothpaste, sauces, Gel cellulose suspend the sand baked goods, ice cream Food additive, flavouring in Prevents precipitation of metal food and beverages; Lemon oxides Iron Control Citric acid Juice ~7% Citric Acid Low sodium table salt Creates a brine carrier fluid KCl Potassium chloride substitute Removes oxygen from the water Cosmetics, food and beverage to protect the pipe from processing, water treatment Oxygen Scavenger Ammonium bisulfite corrosion Maintains the effectiveness of Washing soda, detergents, Sodium or potassium other components, such as soap, water softener, glass and pH Adjusting Agent carbonate crosslinkers ceramics Allows the fractures to remain Drinking water filtration, play Proppant Silica, quartz sand open so the gas can escape sand, concrete, brick mortar Automotive antifreeze, Prevents scale deposits in the household cleansers, and deicing pipe Scale Inhibitor Ethylene glycol agent Used to increase the viscosity of Glass cleaner, antiperspirant, Surfactant Isopropanol the fracture fluid and hair color Note: The specific compounds used in a given fracturing operation will vary depending on company preference, source water quality and site-specific characteristics of the target formation. The compounds shown above are representative of the major compounds used in hydraulic fracturing of gas shales.

800 Modern Shale Gas Development in the United States: A Primer, US Department of Energy, Office of Fossil Energy and the National Energy Technology Laboratory, April 2009, pp. 63.

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February 2011 North American Natural Gas Dynamics: 135 Shale Gas Plays in North America – A Review Appendix B A Complete List of Shale Gas Plays in North America

The following section lists all known shale plays in North America, many of which have been discussed in the study. The list of other shales is divided into Canadian and US shales. The list contains the name of the shale, geological period and the location of the particular shale. Shale plays are listed in alphabetical order and are in various degrees of exploratory development. While all remaining shales contain gas, some are better known for their oil shale or CBM potential.

The following is a list of Canadian shale plays801:

• Colorado Shale, Cretaceous, and Saskatchewan

• Duvernay Shale, Late Devonian, west central Alberta

• Exshaw Shale, Devonian-Mississippian, Alberta and northeast British Columbia

• Fernie Shale, Jurassic, west central Alberta and northeast British Columbia

• Frederick Brook Shale, Mississippian, New Brunswick and

• Gordondale Shale, , northeast British Columbia

• Horn River Shale, Middle Devonian, northeast British Columbia

• Horton Bluff Shale, Early Mississippian, Nova Scotia

• Klua/Evie Shale, Middle Devonian, northeast British Columbia

• Montney-Doig Shale, Triassic Alberta, northeast British Columbia

• Muskwa Shale, Late Devonian, northeast British Columbia

• Nordegg/Gordondale Shale, , Alberta and northeast British Columbia

• Poker Chip Shale, Jurassic, west central Alberta and northeast British Columbia

• Second White Speckled Shale, Late Cretaceous,

• Wilrich/Buckinghorse/Garbutt/Moosebar Shale, Early Cretaceous, west central Alberta and northeast British Columbia

801 Shale Gas Plays in the US and Canada, http://www.marcellus-shale.us/gas-shale_plays.htm (November 24, 2010)

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The following is a list of shale plays in the US802:

• Antrim Shale, Late Devonian, Michigan Basin, Michigan

• Baxter Shale, Late Cretaceous, Vermillion Basin, Colorado and Wyoming

• Barnett Shale, Mississippian, Fort Worth and Permian basins, Texas

• Bend Shale, Pennsylvanian, Palo Duro Basin, Texas

• Cane Creek Shale, Pennsylvanian, Paradox Basin, Utah

• Caney Shale, Mississippian, Arkoma Basin, Oklahoma

• Chattanooga Shale, Late Devonian, Alabama, Arkansas, Kentucky and Tennessee

• Chimney Rock Shale, Pennsylvanian Paradox Basin, Colorado and, Utah

• Cleveland Shale, Devonian, eastern Kentucky

• Clinton Shale, Early , eastern Kentucky

• Cody Shale, Cretaceous, Montana

• Conasauga Shale, Middle , Black Warrior Basin, Alabama

• Dunkirk Shale, Upper Devonian, western New York

• Eagle Ford Shale, Late Cretaceous, Maverick Basin, Texas

• , Late Devonian, Michigan Basin, Michigan

• Excello Shale, Pennsylvanian, Kansas and Oklahoma

• Fayetteville Shale, Mississippian, Arkoma Basin, Arkansas

• Floyd/Neal Shale, Late Mississippian, Black Warrior Basin, Alabama and Mississippi

• Gammon Shale, Late Cretaceous, Williston Basin, Montana

• Gothic Shale Pennsylvanian Paradox Basin, Colorado and Utah

• Green River Shale, Eocene, Colorado and Utah

• Haynesville/Bossier Shale, Late Jurassic, Louisiana and east Texas

• Hovenweep Shale, Pennsylvanian, Paradox Basin, Colorado and Utah

• Huron Shale, Devonian, Part of Ohio Shale

• Lewis Shale, Late Cretaceous Colorado, New Mexico

• Mancos Shale, Cretaceous, San Juan Basin, New Mexico, Uinta Basin, Utah

• Manning Canyon Shale, Mississippian, Central Utah

• Marcellus Shale, Devonian, New York, Ohio, Pennsylvania and West Virginia

802 ibid

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• McClure Shale, Miocene, San Joaquin Basin, California

• Monterey Shale, Miocene, Santa Maria Basin, California

• Moorefield Shale, Mississippian, Arkoma Basin, Arkansas

• Mowry Shale, Cretaceous, Bighorn and Powder River basins, Wyoming

• New Albany Shale, Devonian-Mississippian, Illinois Basin, Illinois and Indiana

• Niobrara Shale, Late Cretaceous, Denver Basin, Colorado

• Ohio Shale, Devonian East Kentucky, Ohio, West Virginia

• Pearsall Shale, Cretaceous, Maverick Basin, Texas

• Percha Shale, Devonian-Mississippian, West Texas

• Pierre Shale, Cretaceous Raton Basin, Colorado

• Queenston Shale, Ordovician, New York

• Rhinestreet Shale, Devonian, Appalachian Basin

• Utica Shale, Ordovician, New York, Quebec

• Woodford Shale, Late Devonian-Early Mississippian, Oklahoma and Texas

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