## Discussion of North American Natural Gas Development

and Documentation of the Gas Resource Base Included in ICF Modeling Work for EPA

ICF International

August 31, 2010

The objectives of this paper are to present recent trends in North American gas resource development, to document the development of the ICF North American gas resource base used in the recent EPA modeling and forecasting.



### Unconventional Gas Development in the U.S.

Unconventional (low permeability) reservoi rs now account for about one-half of U.S. gas production. For decades, conventional high permeability gas reservoirs were developed in regions such as the Gulf Coast, Gulf of Mexico, and the Mid-Continent. However, recent decades saw a sharp decline in onshore new field discoveries, and well recoveries were declining. The deepwater Gulf of Mexico was the only bright spot in the Lower-48 for new conventional

discoveries.

However, North America has vast deposit s of in-place unconventional natural gas resources in the form of tight (low permeability) gas, coalbed methane (coals

where the coalbed is both the source and reservoir for gas), and shale gas (organic shale formations where the shale is both the source and reservoir for gas). These resources are now bei ng extensively developed and U.S. production is increasing. Shale gas has now emerged as a major, long-term energy resource due to the widespread o ccurrence of high quality organic shales

in the U.S. and Canada.

Shale gas production in the U.S. dates to the 1800s wit h the early development of the Appalachian Devonian Shale in We st Virginia, Kentucky, Pennsylvania, and New York. This eventually involved t he drilling of thousands of shallow low productivity vertical wells where producti on in many cases was unrecorded. The wells were often stimulated with explosives.

The 1980s saw the development of the Mich igan Basin Antrim Shale. This was

also the time of the initia l development of t he Barnett Shale in the Fort Worth Basin of North Texas – a play that was to expand into, by most definitions, the largest and most prolific natural gas play in U.S. history.

Tight gas sandstone production in the U.S. dates to the 1940s with the development of the San Juan Basin in northwestern New Mexico and2 southwestern Colorado. Tight gas reserv oirs were also developed starting in the 1950s and 1960s in Appalachia.

Coalbed methane production in the U.S. began in a significant way in the 1980s

with the Fruitland coalbeds of the San Juan Basin in New Mexico and Colorado. Coalbed methane production in the San Juan increased rapidly in subsequent years, reaching 2 Bcf per day (Bcfd) by 1995. The Alabama Warrior Basin coalbed methane production also start ed in the 1980s and saw more modest growth to about 300 million cubic feet per day (MMcfd). Then came the development of the Powder River Basin in eastern Wyoming. Production from that play started in the mid-1990s and achieved one Bcfd by 2003. Coalbed methane production also started in Alber ta several years ago and production now

exceeds 650 MMcfd.



### Recent Trends in Gas Production

Figure 1 summarizes the recent trends in Lower-48 unconventional gas production. The production rate has increas ed from 1,000 Bcf per year to almost 10,000 Bcf per year since 1970. Overall, most of the growth has been in tight gas. However, shale gas has accounted for much of the recent growth.

Figure 1: Lower-48 Unc onventional Gas Production

0 2,000 4,000 6,000 8,000 10,000 12,00019701972197419761978198019821984198619881990199219941996199820002002200420062008Bcf Per Year

Coalbed

Shale
Tight3 The U.S. currently has five large-scale, active shale gas plays. These are the Barnett Shale of North Texas, the Faye tteville Shale in Arkansas, the Woodford Shale in eastern Oklahoma, the Hayne sville Shale of northern Louisiana and East Texas, and the Marcellus Shale in Appalachia.

Other Lower-48 shale plays with increasing activity include the Eagle Ford shale along the Texas Gulf Coast, the Woodfor d Shale in western Oklahoma, the Bossier in Louisiana, and several Rocky Mountain formations including the Gothic Shale in the Paradox Basin. The Bakken oil shale play in North Dakota is experiencing rapid development. A portion of the Fort Worth Barnett play is being developed for crude oil as well.

In Canada, active shale plays include the Horn River Basin, the Cordova Embayment, and the Montney siltstone/shale in BC. Eastern Canada has seen exploration activity in shale formati ons in New Brunswick and Nova Scotia.

Figure 2 focuses on U.S. shale gas production. This chart illustrates the tremendous growth in gas production from th e Fort Worth Barnett Shale. While production growth from the Barnett is slo wing, other shale gas plays such as the Fayetteville, Haynesville, and Marcellus are growing rapidly.

Figure 2: Lower-48 Shale Gas Production

0 500 1,000 1,500 2,000 2,500 3,0002000200120022003200420052006200720082009Bcf per Year N. LA and E. TX

Mid-Continent

Fort Worth Basin
Michigan-IL
Appalachia4 

### Recent Trends in Drilling Activity

Over the past decade, gas well completion ac tivity in the U.S. has shifted heavily toward unconventional gas development. Th e initial surge was in the Fort Worth Basin Barnett Shale and in tight gas dev elopment in the Rockies and Texas. Within the past few years, operators have been able to use the technology developed for the Barnett Shale to open new shale plays around the country. Activity has surged, particularly in North and East Texas, Oklahoma, Pennsylvania, and Arkansas.

Recent activity peaked in 2008 but decli ned greatly in late 2008 and 2009, with the onset of the recession. In 2010, acti vity has rebounded, but overall rig counts at a level of about 1,500 rigs are only about two-thirds of prior levels.

Perhaps the most significant aspect of ri g activity has been the shift away from vertical drilling to horizontal and directi onal drilling. This trend is illustrated in Figure 3 . Currently, over two-thirds of rig activity is directed toward either

horizontal or directional drill ing, while only one-third is ve rtical drilling. Horizontal wells are mostly shale gas wells and direct ional wells are mostly tight gas wells.

Figure 3: Recent Rig Activity Trends

U.S. Rig Activity by Type - Vertical vs. Horizontal (Baker-Hughes)

0 200 400 600 800 1,000 1,2001/4/20083/4/20085/4/20087/4/20089/4/200811/4/20081/4/20093/4/20095/4/20097/4/20099/4/200911/4/20091/4/20103/4/20105/4/20107/4/2010Rigs 

### Vertical

Directional

Horizontal

Also, a recent trend that has emerged in 2010 is a greatly increased emphasis on crude and natural gas liquids production fr om several unconventional plays.

These include the Bakken oil shale in No rth Dakota, the Eagle Ford shale in south Texas, the oil portion of the Barnett, and the Granite Wash tight sand play.5 

### ICF Gas Resource Base Analysis

ICF has been involved in North American gas and oil resource base studies for over 20 years. The work has included resource assessment, characterization, and economic analysis, and has included bo th conventional and unconventional resources and modeling. In the early years, unconventional gas assessments relied heavily upon published information from the U.S. Geological Survey, which has assessed many tight gas and coalbed methane plays, and some shale plays and this effort is onging. 1 ICF developed a map-based cell structure to compile information on depth, well recovery, pr oduction parameters, drilling costs, and operating costs.

Starting about 2005, ICF began st udying several of the major U.S. shale gas plays in detail. This included geologi c mapping of play area, depth, organics maturity, and thickness. We determined bas ic shale volumetrics, and by using relationships derived in part from the Fort Worth Basin Barnett Shale, ICF developed estimates of gas in place and re covery for the major plays. This

information was collected on the basis of 36 square mile units or “townships.”

Within the past two years, ICF has empl oyed more sophisticated approaches to shale and tight gas assessment. Thes e involve geographic information systems and detailed mapping. In addition, new models have been developed to approach the resource assessment us ing reservoir engineering methods and accounting for recovery as a function of well spacing. With shale and tight gas plays in particular, any comprehensive analysis must account for infill drilling potential and the characteristics of the re servoir that control well recovery as a function of well spacing. Over 30 plays have been evaluated by using this approach. The resource base assum ed for the EPA modeling is a modified version of that developed in this recent ICF work.

Figure 4 shows the supply regions for this study. Table 1 summarizes the resource base assumptions used in t he model. The Lower-48 conventional resource is 313 Tcf, the recoverable s hale gas resource base is 921 Tcf, tight gas is 321 Tcf and coalbed methane is 74 Tcf. Canadian shale gas is assessed

at 509 Tcf.

It should be noted that ICF’s assessment of Marcellus Shale potential has been reduced as applied in the EPA modeling fr om the original geologically-based analysis because of the potential for reduc ed access due to state regulations. In general, ICF believes that industry will experience more difficulty in accessing portions of the Marcellus than has been the case with plays such as the Barnett and Fayetteville.

1 U.S. Geological Survey Nationa l Oil and Gas Assessment, 2010 http://energy.cr.usgs.gov/oilgas/noga/6 Table 2 compares the shale gas resource base assumptions for the EPA work to other significant assessments in recent y ears. The first co lumn of the table documents the ICF shale gas resource. While the individual play assessments are not shown here, the regi onal comparisons are shown. All of the plays listed

in the table are included in the current ICF assessment.

An important observation from this table is that with the past few years, many new shale plays have been added to the as sessment. Thus, the changes from older assessments involve both changes within plays and the addition of new plays. To a large extent, the num ber of successful new plays being announced has declined over the past year, al though recently Encana announced a new shale play in the Michigan Basin - t he Collingwood Shale. In the Rockies, technologies are currently being developed that will likely unlock a number of shale plays. The Colingwood and these potential new plays from the Rockies

have not been included in the ICF resour ce assessment because they are so

recent.

Figure 4: ICF Supply Regions Map7 Table 1: ICF Resource Base Assumptions for EPA Modeling

Lower 48 Resources

Total

Offshore Conventional Conventional Shale Tight Coalbed Total Non-Associated associated

Northeast 15.4 254.8 33.7 9.5 313.4

Gulf Coast 133.9 433.1 59.6 4.3 630.9

Midcontinent 54.4 133.9 4.6 9.6 202.5

Southwest /1 19.2 61.3 6.1 0.0 86.6

Rockies/Williston 84.0 37.9 205.1 49.8 376.8

West Coast 6.4 0.3 11.5 0.7 18.9
L-48 Total 313.3 921.3 320.6 73.9 1,629.1 137.1 145.1 1,911.3

Alaska Resources 153.6

Total U.S. 2,064.9

Canada Resources

Western 121.4 508.8 10.3 27.4 667.9

Eastern Offshore 71.8

Mackenzie Delta 32.9

Total Canada 154.3 508.8 10.3 27.4 71.8 8.1 780.7 Onshore Non-associated Other8Table 2: ICF Gas Resource Base Assumptions for EPA ModelingTcf recoverable2010 2009 2008 ICF INGAA 2008 2008 2008ICF Assessment ICF Foundation PGC 2009 2002-08 2010 Clean Skies Clean SkiesRegion Basin for EPA Assessment Assessment Assessment EIA USGS ARI Mean MaximumUnited StatesAppalachiaAppalachian Vertical Low Pressure17.0 30.6 (with Marcell.) 13.1 12.2 35.4 49.8Appalachian Marcellus289.7 63.0 228.0 38.3 not assessed 200.0 34.2 262.0Appalachian Huron20.0 20.0 (with Marcell.) not assessed not assessed not assessed with vertical? with vertical?NY Uticanot assessed not assessed (with Marcell.) not assessed not assessed not assessed not assessed not assessedtotal 245.3 326.7 113.6 228.0 51.4 12.2 200.0 69.6 311.8Texas and LAHaynesville Shale102.2 31.0 112.3 71.6 not assessed 130.0 34.0 251.0Gulf CoastBossier Shalenot assessed not assessed (with Haynes.) not assessed not assessed not assessedEagle Ford Shalenot assessed not assessed 24.5 not assessed not assessed not assessedPearsall Shalenot assessed not assessed not assessed not assessed not assessed not assessedTotal 433.1 102.2 31.0 136.8 71.6 0.0 130.0 34.0 251.0Warrior BasinFloyd and Conasauga Shales not assessed not assessed not assessed not assessed not assessed not assessed 2.1 4.5Michigan-MIchigan Antrim 4.0 4.0 5.9 10.0 7.5 not assessed 13.2 20.0IllinoisIllinois New Albany 3.2 3.2 5.4 3.1 3.8 not assessed 3.8 19.2Cincinnati Arch 2.3 2.3 not assessed 1.1 0.0 not assessedtotal 9.5 9.5 9.5 11.3 14.2 11.3 17.0 39.2North TexasFort Worth Barnett46.3 107.4 107.0 59.3 59.7 26.2 39.0 26.2 44.0Mid-ContinentArkoma - Arkansas Fayetteville86.3 58.0 110.5 29.2 not assessed 50.0 26.0 41.6Arkoma - Oklahoma Woodford61.9 53.0 (with Fayette.) 19.7 not assessed 34.0 12.2 17.4Arkoma Moorefield (AR)not assessed not assessed (with Fayette.) not assessed not assessed not assessed not assessed not assessedArkoma Caney (OK)not assessed not assessed (with Fayette.) not assessed not assessed not assessed not assessed not assessedAnadarko Woodfordnot assessed not assessed 2.1 not assessed not assessed not assessed not assessed not assessedCentral OK Fold Belt Woodford not assessed not assessed not assessed 7.1 not assessed not assessed not assessed not assessedtotal 133.9 148.2 111.0 112.6 56.0 84.0 38.2 59.0Permian BasinBarnett Shale10.0 10.0 3.9 not assessed 35.1 not assessed 35.4 53.0Woodford Shalewith Barnett with Barnett with Barnett not assessed not assessed not assessedtotal 15.0 10.0 10.0 3.9 0.0 35.1 35.4 53.0WillistonWilliston Niobrara with tight with tight not assessed 3.9 not assessed not assessed 0.0 not assessedWilliston Bakken Oil Playnot assessed not assessed not assessed not assessed not assessed not assessed 1.8 3.0total 1.9 0.0 0.0 0.0 3.9 0.0 1.8 3.0RockiesGreen River Vermillion Baxter Shalenot assessed not assessed not assessed not assessed not assessed not assessedGreen River Hilliard Shalenot assessed not assessed not assessed not assessed not assessed not assessedGreen River Lewis and Mowrywith tight with tight not assessed not assessed not assessed not assessed 33.8 53.0Paradox Gothic Shale1.0 1.0 not assessed not assessed not assessed not assessed not assessed not assessedParadox Cane Creek Shalenot assessed not assessed not assessed not assessed not assessed not assessedUinta Mancos Shalenot assessed not assessed 60.2 not assessed not assessed not assessedSan Juan Lewis with tight with tight 4.5 10.5 not assessed not assessed 10.2 12.3Denver Niobrara with tight with tight not assessed not assessed not assessed not assessed 1.3 2.7Raton Basin Pierre 2.0 2.0 not assessed not assessed not assessed not assessed not assessed not assessedtotal 36.0 3.0 3.0 64.7 10.5 0.0 45.3 68.0Pacific OnshoreSan Joaquin Basin McClure 0.3 0.3 0.3 not assessed not assessed not assessed not assessed not assessed not assessedOther0.0 0.0 0.0 0.0 0.0 4.7 8.3Lower 48 total921.3 707.3 385.4 616.6 267.2 84.8 453.0 274.3 841.8Alaskanot assessed not assessed not assessed not assessed not assessed not assessed not assessed not assessedU.S. total707.3 385.4 616.6 267.2 84.8 453.0 274.3 841.89 Another aspect of the ICF resource a ssessment work involves crude oil and natural gas liquids. The volume of natur al gas liquids that is produced with the gas can have a major impact on economics. This is evidenced by the shift toward liquids-rich plays this year. The ICF analysis has included a map-based analysis of gas “wetness” in major shale plays that is a function of shale gas “maturity.” Interestingly, the analysis shows that the U.S. has a very large volume of undeveloped crude oil and NG Ls that are associated with unconventional shale and tight gas plays.



### Producer Expenditure Trends

While the total number of gas wells current ly being completed is much lower than it was in 2007 and 2008, industry outlays ar e very high because of the increased capital cost per well. Each horizontal s hale well may range in cost from $2 to $10 million or more, depending on the location and well configuration. This well cost is many times that of a conventional vertical gas well along the Gulf Coast or in the Mid-Continent. The higher cost is due to several factors, including the drilling of the horizontal la teral and the cost of stim ulating the well, which may require up to ten or more fracture stages.

The annual Oil and Gas Journal survey of upstream industry expenditures has documented a huge increase in outlays in recent years. 2 For example, upstream U.S. expenditures were approximately $292 bi llion in 2008. This compares to only $84 billion in 2004. Most of the increase was due to higher drilling and completion outlays. Much of the increased activity in shale well development has been undertaken by the Top 20 E&P operators in the U.S. since significant capital outlays are required for shale well development. Many of those operators

have continued to increase t heir expenditures for shal e well development despite significant downturn in the prices for nat ural gas during the past couple years.

2 Oil and Gas Journal, March 1, 2010.