### ADVANCED RESOURCES INTERNATIONAL, INC.

4501 Fairfax Dr, Suite 910, Arlington, Virginia 222 03 Phone: (703) 528-8420 Fax: (703) 528-0439 

# Memorandum

To: James Covington; U.S. Environmental Protection Agency

From: Michael Godec; Advanced Resources International, Inc.

Date: 11/10/2010

Re: Review of prospective but non-producing coalbed met hane basins

The purpose of this memo is to describe possible new coal bed methane (CBM) basins with a potential for strong development or pilot large scale w ork, but where current activity is limited.
The Environmental Protection Agency (EPA) survey of CBM e xtraction operations is, of course, focusing on basins with current CBM development and prod uction operations. EPA will use the responses collected in this detailed questionnaire to info rm its decision on whether to initiate a rulemaking to potentially revise the effluent guidelin es for the Oil and Gas Extraction Point Source Category (40 CFR 435) to include limits for pol lutants discharged in CBM produced water. Operators in the following CBM basins are expecte d to respond to the EPA survey (see Figure 1):

• Alabama/Florida/Mississippi Salt Dome Basin

• Anadarko Basin

• Appalachian Basin (Northern and Central)

• Arkla Basin

• Arkoma Basin

• Big Horn Basin

• Black Warrior Basin

• Cahaba Basin

• Cherokee/Forest City Basin

• Ft. Worth Basin

• Green River Basin

• Illinois Basin

• Permian Basin

• Powder River Basin

• Raton Basin

• Salina Basin

• San Juan Basin

• Gulf Coast Tertiary Coal Basin

• Uinta-Piceance Basin

• Wind River Basin

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Figure 1 U.S. Environmental Protection Agency 2007 Coalbed Methane Industry Screener

While much of the higher quality, easier to produce C BM resource plays have been found, and are the primary focus of the EPA survey, additional CBM prospects exist in deeper coals and lower rank coals, as well as in other areas. Resources in these basins will not be targeted by the EPA survey of operators, because, in general, they have not yet undergone much development. The primary resources in this category include:

• Deep coals of the Greater Green River and Piceance Basi ns

• Undeveloped CBM plays in Alaska

• Resources in the Pacific Northwest coal region

• The Black Mesa Basin in Arizona

• Low rank coals in the Gulf Coast
Each of these prospective areas is summarized below.

1. Green River and Piceance Basin CBM. The coalbed methane in the Green River and Piceance basins has long been noted for two things -- th e vast in-place resource and their considerable depth. Estimates put the in-place coalbed methane resource of the Green River Basin at 314 trillion cubic feet (Tcf), and of the Pi ceance Basin at 84 Tcf.

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In the Piceance Basin, the Cameo coal (in the “Paludal ” zone located below the Williams Fork (Mesaverde) tight gas sands) contains about 80% of the ba sin’s CBM resource. During the 1980s and early 1990s, producers experimented with commin gling production from these deep tight gas sands and coals, motivated, in part, by Section 29 tax credits. However, the high reservoir pressure and the increase in water production fr om completing the coals eventually discouraged this practice. More recently, EnCana has repo rted completing the entire Williams Fork (Mesaverde) interval, including the lower “Paludal coal zone”, using vertical wells and multiple fracs.

In the Green River Basin, 85% of the 314 Tcf of coalb ed methane resource occurs below 6,000 feet. Since the early 1990s, operators have attempted to tap into these deep coals through completions into multiple seams or through commingled completions of coals and overlying Mesaverde tight gas sands, all with limited success. Toda y, drilling for these coals is underway in the Atlantic and Pacific Rim projects, along the shal lower flanks of the Washakie Basin.
However, these deeper plays are geographically coincide nt with the shallower CBM plays under development in the Piceance and Unita Basins, so existi ng operations in these geographic areas, while perhaps not in pursuing development in t hese specific, deeper geologic formations, are addressed in the survey.
2. Undeveloped CBM plays in Alaska. Alaska has major CBM resources estimated at 776 Tcf of gas in place, slightly larger than the CBM resource ba se in the entire Lower-48 states. None of Alaska’s CBM potential has been commercially develope d, due to its remoteness from markets, and (until perhaps recently) insufficient natura l gas prices for economic viability. Most of the CBM resource (621 Tcf) is located in bituminous -rank coals of the North Slope region. Prospective but still untested, the North Slope CBM r esources lack markets and development must await construction of natural gas pipeline from t he Alaska North Slope to viable markets.
However, CBM resources in the onshore Cook Inlet region in southern Alaska (136 Tcf) are more conveniently located, close to the Kenai liquefied natural gas (LNG) facility, and thus have brighter market prospects. Reservoir characteristics appea r favorable (thick, sub-bituminous coal with 100-200 standard cubic feet per ton (scf/ton) gas content). The Pioneer/Evergreen pilot -- though not commercially successful (gas prices were $1.80/Mcf at the time) – is the only CBM test and provided useful data. Cook Inlet CBM could replace dwindling conventional gas supplies for Kenai at attractive prices (~$6 to 9/Mcf). Recent efforts in Australia to develop CBM for LNG exports have sparked renewed interest in Cook In let’s CBM potential.
A more detailed characterization of the undeveloped CB M plays in Alaska is provided in Appendix A.
3. Pacific Northwest Coal Region, Washington and Or egon. The structurally complex Pacific Northwest Coal Region (PNCR) in Washington and Orego n contains significant (~10 Tcf) undeveloped coalbed methane resources in place. CBM t esting since 1987 by Texaco, El Paso, and smaller operators has not been commercially succe ssful but did measure encouraging gas content (up to 500 scf/ton), permeabi lity (up to 300 millidarcies (md)), and short-term gas flow rates up to 500,000 cubic feet per day (Mcfd). Produced water in some pilots was fresh, enabling surface discharge under state p ermits.
The main challenges in the PNCR have been relatively co mplex structural conditions, including faulting, steep dips, and unstable coals. In additio n, vertical well fracturing and completion have not been effective to date. Horizontal drilling has no t yet been attempted. Geologically, PNCR is one of the most challenging undeveloped CBM areas i n the US, though the lack of conventional gas production in the region is a positive m arket factor. Higher gas prices likely

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would stimulate further exploration in this region, pe rhaps introducing advanced horizontal drilling.
A more detailed characterization of the undeveloped CB M plays in Pacific Northwest Coal Region is provided in Appendix B.
4. Black Mesa Basin, Arizona. The 2,500 square mile Black Mesa Basin in northeastern Arizona contains extensive coal resources that have not been tested for CBM but could have significant potential (1-10 Tcf). The northern part of the basin has experienced large-scale surface coal mining since the 1960s, but conflicting own ership claims on Hopi and Navajo lands further south in the basin have discouraged CBM testing to date. Black Mesa is perhaps the last significant untested CBM basin in the US Rocky Mount ain region.
Based on outcrop studies and data from sparse oil and ga s wells drilled in the 1950s through the 1970s, CBM reservoir conditions in Black Mesa appear prospective and might even approach those of the commercially developed San Juan a nd Raton Basins nearby. In certain respects, Black Mesa resembles the undeveloped Raton ba sin of 20 years ago (though it is 50% larger than the Raton). Cretaceous Wepo Formatio n coals total up to 60 feet thick and dip south from outcrop to a depth of approximately 3,000 f eet in the basin’s center. Coal rank ranges from sub-bituminous to high-volatile bituminous A . Thinner coals occur in the underlying Cretaceous Toreva and Dakota Formations. Market access cou ld be via the recently constructed Questar Southern Trails gas pipeline, which cr osses the northern edge of the basin, or the El Paso Lincoln pipeline, which crosses just south of the basin.
A more detailed characterization of the undeveloped CB M plays in the Black Mesa Basin is provided in Appendix C.

5. Low Rank Coals in the Gulf Coast A large in-place coalbed methane resource exists in Gulf work by the U.S. Geological Survey (USGS) estimates tota l undiscovered technically recoverable resources in the Cretaceous-Tertiary Coal be ds of the Gulf Coast Region to range from 1.7 to 7.9 Tcf, with a mean estimate of 4.1 Tc f. 1 Prospective coals occur at depths of 1,500 to 5,000 foot depths with more mature, gas ri ch coals existing below 3,000 feet. Drilling has been limited to individual test pilots and significan t production has yet to be established. However, leasing has been active, with over 400,000 acres leased to date.
A more detailed characterization of the undeveloped CB M plays in the Black Mesa Basin is provided in Appendix D.

6. Other Low Rank Coals in the U.S. Conventional wisdom assumes that lignite is of too low a grade to be a commercially viable source of methane. How ever, ongoing activities in the Texas Gulf Coast are challenging this assumption. A number o f other areas in the U.S. have low rank coals. In addition to the Gulf Coast and Alaska, low ra nk coals exist throughout much of the west, including North Dakota, Northern Montana, and M ichigan. Little work has been done to assess the coalbed methane potential of these coals, an d development activity regarding this resource is minimal.

Nonetheless, there is some anecdotal evidence from ranche rs and water well drillers, for example, suggesting that coalbed methane may indeed occu r in some of the lignites of North Dakota. The occurrence of coalbed methane appears to b e related to the thickness of a coal seam, the thickness of the overburden, and the hydrostati c pressure of water within the seam. Detailed knowledge of the nature of target coals is critical to the evaluation of its potential as a coalbed methane resource.

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## Appendix A Preliminary Evaluation of Alaska’s Undeveloped CBM Resource Potential 1. Summary
Alaska has major CBM resources estimated at 776 Tcf of gas in place, slightly larger than the CBM resource base in the Lower-48 states. None of Alask a’s CBM potential has been commercially developed, due to its remoteness from markets and (until recently) low gas prices. Most of the CBM resource (621 Tcf) is located in bitum inous-rank coals of the North Slope region. Prospective but still untested, the North Slo pe CBM resources lack markets and development must await construction of the planned N orth Slope gas pipeline.
However, CBM resources in the onshore Cook Inlet region in southern Alaska (136 Tcf) are more conveniently located close to the Kenai LNG facilit y and thus have brighter market prospects. Reservoir characteristics appear favorable (thi ck, sub-bituminous coal with 100-200 scf/ton gas content). The Pioneer/Evergreen pilot -- though not commercially successful (gas prices were $1.80/Mcf at the time) – is the only CBM test and provided useful data. Cook Inlet CBM could replace dwindling conventional gas supplies for Kenai at attractive prices (~$6- 9/Mcf). The Australian CBM-to-LNG paradigm has sparked renewed interest in Cook Inlet’s CBM potential.

2. Resource Potential
Though mining has been limited, Alaska contains major coa l deposits that range from shallow outcrop to over 2,000 meters deep. Three major geolo gic provinces account for nearly 90% of Alaska’s coal resources: 1) Northern Alaska - North Slope Region; 2) Central Alaska – Nenana Region; and 3) Southern Alaska – Cook Inlet Region.

CBM Resources

in Alaska were initially estimated by the Alaska DNR to be around 1,000 Tcf of gas in place, including 245 Tcf in the Cook Inlet. 2 In 2004, the USGS coal resource evaluation examined CBM in Alaska, characterizing it as “exceedingly large,” but did not actually quantify CBM resources. 3 In 2006 the USGS assessed North Slope CBM resources, esti mating a total of 19 Tcf in place, 4 which would imply an average gas content of only 6 s cf/ton. This seems “exceedingly low,” much lower than the 100-200 scf/ton t ested in the Cook Inlet basin.
Advanced Resources has recently developed an independent , preliminary estimate of Alaska CBM resources ( Table A-1 ). Gas content was assumed to range from 100 scf/ton i n the relatively low-rank and shallow Nenana region, to 150 scf/ton in the deeper but still subbituminous Cook Inlet area, to 200 scf/ton in the hig her-rank and deeper North Slope region. Using this methodology, we estimate CBM resources in Alask a to be approximately 758 Tcf. Onshore Cook Inlet has about 136 Tcf of accessible CBM reso urces in place, similar to a published estimate (using similar methodology) of 140 Tc f. 5

North Slope. The North Slope region has coals in the Lower Creta ceous Nanushuk and Upper Cretaceous Colville Groups as well as in the Tertiary Sa gavanirktok Group. Coal underlies an area of approximately 83,000 km 2 . Coal rank ranges from lignite A to high-volatile A bituminous, with a mean rank of high-volatile C bituminous. Ident ified resources are 120 billion short tons, with a further 3,870 billion tons of undiscovered but likely coal resources. ARI estimates there are approximately 621 Tcf of coalbed methane resources in the North Slope. However, these resources are located far from gas markets, have never b een tested, and thus remain poorly characterized.

Central Alaska. The Central Alaska – Nenana region has Tertiary coal s estimated at 6.4 to 7.7 billion tons of identified resources, with an additio nal 10 billion tons of undiscovered resources. 6

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The region is not continuously underlain by coal, but i nstead comprises numerous small structural basins (synclines) that are separated by anticlin al highs. Coal occurs in the Tertiary Usibelli Group. Coal thickness is approximately 50 to 66 f eet and occurs at depths ranging from surface to around 3,000 feet. Coal rank ranges from lignite to sub-bituminous, mainly subbituminous C. Although smaller than the North Slope and Cook Inlet, the Nenana basin is the only coal province in Alaska that is currently being mined . ARI estimates CBM resources in Central Alaska at about 1 Tcf.

Cook Inlet. The Cook Inlet region has the most prospective CBM reso urces in the state. Major coal deposits occur in the Miocene Tyonek Formation. Dem onstrated coal resources are estimated at 2.9 to 12 billion tons, with another 970 to 1,600 billion tons of undiscovered resources. The coals can total up to 1,000 feet or mo re in places. They often occur at optimal depths of 1,000 to 4,000 feet. Coal rank is sub-bitu minous to high-volatile bituminous C. These coals sourced most of Cook Inlet’s conventional natural g as reserves. CBM Testing. To date, the only Alaska CBM area to experience sign ificant well testing has been the onshore Cook Inlet. Projects have included a state DNR gas content core hole and Pioneer’s 4-well production pilot.

• Alaska DNR. In 1994 the Alaska Department of Natural Resources dr illed Alaska’s first gas content core hole about 50 km northeast of Anchorage. Approximately 40 feet of coal was cored and desorbed. Gas content was encouragingly high and increased regularly with depth, from 63 scf/ton (d.a.f.) at 500-foot depth (R o =0.47%), to 245 scf/ton at a depth of 1,300 feet (R o =0.58%). Gas composition was mainly methane (98-99%), with minor CO 2 and N 2

.

• Evergreen. During 2002-2004, Evergreen Resources (now Pioneer) t ested a 300,000-acre lease. Oligocene-Miocene Tyonek Formation coals total 8 0-150 ft thick, are high-volatile bituminous in rank (R o =0.6%), and occur at depths of 2,600 to 3,700 feet. Evergreen drilled two separate 4-well CBM pilot production patterns (t otal 8 vertical ells) and hydraulically stimulated all four wells of the first pilot and one w ell of the second pilot. Drilling permits were granted for two water-disposal wells. However, E vergreen abandoned the project in 2004 following long-term production testing, saying it was “probably not capable of commercial production.” Note that the $1.80/Mcf wellhe ad gas price was among the lowest in the USA at the time.

3. Market Potential. While much of Alaska’s CBM potential is remote from existing pipeline and gas market infrastructure, several potential marketi ng opportunities have emerged in recent
years:

• Anchorage. The city of Anchorage is served by conventional natur al gas fields that are in long-term decline. Pioneer Resources’ initial CBM pil ot in the onshore Cook Inlet basin was intended to serve the Anchorage market initially. The local utility Enstar paid an average $8.75/Mcf for natural gas supplies in 2008, up from $1 .80/Mcf ten years ago.

• Kenai LNG. A much larger and longer-term potential market for Alaska CBM would be to develop the vast resources present in the Cook Inlet re gion to replace rapidly declining conventional gas supplies for the Kenai LNG facility. Al ready, concerned Japanese LNG companies have begun to look into Cook Inlet’s CBM pote ntial as they seek reliable supplies for future decades from this key facility. And given the new Australian paradigm of developing CBM for LNG, industry has taken renewed int erest in Cook Inlet’s CBM

resources. Operated by ConocoPhillips (70%) and Marathon (30%), t he Kenai-Nikiski plant has annual production of about 1.2 million tons. Most of Kenai’ s production is exported to Japan. Kenai

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is the oldest LNG plant, having started production in 1 969. Current estimates of the conventional gas reserves remaining in the Cook Inlet Ba sin vary from 1 to 2 Tcf, insufficient for long-term LNG exports. Furthermore, the conven tional gas produced for Kenai requires compression, placing CBM resources on a more equal footing

.

• Alaska Gas Pipeline. In the more distant future, there is likely to be a n atural gas pipeline constructed to transport stranded conventional gas reserves i n the North Slope to southern markets. If cost-competitive, the North Slope CBM resou rces could be developed and marketed via this planned pipeline. ExxonMobil and Tra nsCanada recently announced a joint-venture to bid on the pipeline project.



### Figure A-1: Coal Basins and CBM Resources In Alaska

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Table A-1: CBM Resources in Alaska

Identified & Identified & HighUndiscovered Mean Mean Undiscovered Mean Total Graded

Coal Ash Moisture Coal Volatile Methane CBM CBM

Resources Content Content Resources Matter Content Resour ces Resources

Region (Btons) (%) (%) (Btons, daf) (%) (scf/ton, daf) (Tcf) (Tcf)

North Slope 4,020 10.3 12.5 3,103 30.1 USGS 6 18

North Slope 4,020 10.3 12.5 3,103 30.1 ARI 200 621

Nenana 17 9.9 24.7 11 35.9 ARI 100 1

Cook Inlet 1,292 10.0 20.0 905 35.0 ARI 150 136 27.1

ARI Total 5,329 4,019 ARI 758

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## Appendix B Pacific Northwest Coal Region, Washington and Orego n

1. Summary
The structurally complex Pacific Northwest Coal Region (PNCR) in Washington and Oregon contains significant (~10 Tcf) undeveloped coalbed metha ne resources in place. CBM testing since 1987 by Texaco, El Paso, and smaller operators has n ot been commercially successful but did measure encouraging gas content (up to 500 scf/ ton), permeability (up to 300 md), and short-term gas flow rates (up to 500 Mcfd). Produced wa ter in some pilots was fresh, enabling surface discharge under state permits.
The main challenges in the PNCR have been relatively co mplex structural conditions, including faulting, steep dips, and unstable coals. In additio n, vertical well fracturing and completion have not been effective to date. Horizontal drilling has no t yet been attempted. Geologically, PNCR is one of the most challenging undeveloped CBM areas i n the USA, though the lack of conventional gas production in the region is a positive m arket factor. Higher gas prices likely would stimulate further exploration in this region, pe rhaps introducing advanced horizontal drilling.

2. Resource Potential
The Pacific Northwest Coal Region (PNCR) comprises a ser ies of discrete fault-bounded coal fields that stretch from southwestern Oregon, through ce ntral Washington, and into western British Columbia (Figure B-1). CBM resources in this re gion have not been rigorously assessed, although early scoping-level estimates have range d from 0.3 to 24 Tcf. 7,8,9

Eocene-age coal-bearing formations include the Cowli tz, Skookumchuck, Carbonado, Spiketon, Tiger Mountain, and Renton Formations, as well as the undivided Puget Group (Figure B-2). These units were deposited in a variety of deltaic, fl uvial, brackish, and shallow-marine environments. Coal rank is mainly bituminous, with some sub-bituminous coals. Gas contents are fairly high, up to 500 scf/ton. Although not ide al due to their structural complexity, CBM deposits in the PNCR do benefit from a lack of conventi onal gas production in the region.
3. Exploration Testing
The Pacific Northwest underwent an initial phase of CB M exploration activity took place during 1982-93, including the Amoco, Texaco, and Carbon River Energy pilots. Early wells qualified for Section 29 non-conventional gas tax credits, which expi red at the end of 1992. However, the initial projects were unsuccessful due to structural compl exity, faulting, steep dips, and poor well completion practices, as well as relatively low prevailin g wellhead gas prices (~$2/Mcf).
Texaco, Palo Petroleum, and Boeing teamed up in 1992 to drill three wells near Black Diamond, WA. One well was hydraulically fractured with nitrogen foam and sand, while the other two wells were completed by open-hole cavitation . The best well tested 30-200 Mcfd from Eocene coal seams at depths of 2,500-3,300 feet. Howe ver, steep dips in this area led to severe borehole deviation during drilling, and caused hole collapse during the cavitation operations. Although these wells penetrated over 30 m eters of coal, production results were disappointing.
A second CBM testing phase started about 2000, stimulat ed by higher gas prices (>$5/Mcf), new exploration concepts, and improved well completion technology. These more recent projects, though still not economically successful, have t ested encouraging levels of coal seam

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gas content and permeability in the region. Recent o perators have included El Paso Corporation, Duncan Oil, Torrent Energy, and Comet Ridge Ltd.

Partners El Paso Corp. and Duncan Oil tested the Northwest’s largest CBM pilot. 10 The Carbonado CBM project covered 264,014 acres in King an d Pearce Counties located 30 miles SE of Tacoma. A total of 14 CBM production wells an d 4 core holes were drilled, targeting more than two dozen coal seams in the Puget Group tot aling nearly 80 feet thick at depths of approximately 3,000 feet. Individual coal beds were th in (3 feet) with high ash content (average 60%), usually separated by 150 feet of sandstone and sh ale. Intrusive dikes and sills occur sporadically. Coal rank was high-medium volatile bitum inous. Gas content varied with depth and location, with highest values in the southern part of the prospect. Using a minimum 2,000- foot depth cutoff, the average in-situ gas content was reported to be about 500 scf/ton.
All 14 production wells were hydraulically stimulated, u sing a variety of fluids. Eight of the wells used nitrogen foam with 90 tons of sand proppant per zone. Four wells were used slickwater KCl fluid, with about 23 tons of sand per zone. Two of the wells utilized polymer fluid with 42 tons of sand proppant per zone. El Paso did not rele ase detailed production data. Some wells reportedly produced at high water rates, sometimes exce eding the 1000 barrels per day installed pump capacity. Based on injection/falloff test ing and production analysis, the company estimated coal seam permeability to range from 1 to 300 md, with a regional average 1 to 7 md. (This is lower permeability than found in the San Juan and Powder River basins, but similar to the levels encountered in the Warrior basin of Alabama .)
Produced water at El Paso’s pilot was quite fresh and disposed by surface discharge into local streams under permit from the State of Washington, al though capacity constraints required some of the water to be trucked to a local water utili ty. Despite operating in what some consider to be an environmentally restrictive part of the countr y, El Paso had no issues obtaining drilling permits, mainly because the locations were situated on private timberlands that were scheduled for clear cutting. Had the project proceeded, access to N orthwest Pipeline’s trunk line would have required construction of a 10-mile connecting pi peline. El Paso eventually abandoned the project due to high water and low gas production.
Comet Ridge Limited (based in Sydney, Australia) currently is conducting a CBM and conventional gas exploration program in the Grays Harbo r area southwest of Seattle. 11 Comet Ridge’s subsidiary St. Helens Energy LLC holds mineral rig hts to 50,000 acres and has a lease option for an additional 420,000 acres at low bonus cost s (<$0.50/acre). The company has completed a 3-D seismic survey in the block and is nearing co mpletion of a 2-D seismic shoot. After processing and interpreting the seismic data, Come t Ridge plans its first test well later during 2009.
Torrent Energy (based in Coos Bay Basin, Oregon) conducted extensive CBM testing at its Coos Bay block further south in southwestern Oregon. 12 The Coos Bay basin is the southernmost of a series of coal-bearing Tertiary sedime ntary basins (the Puget-Willamette Trough) that stretch from southern Oregon to northern Washington. Coal seams occur in the Lower and Upper Members of the Middle Eocene Coaledo Formation. Net coal thickness totals up to 60 feet and 30 feet, respectively, in the Lower and Upper Coaledo units. The coal rank ranges from sub-bituminous to high-volatile bituminous. Approximately 20 conventional oil and gas exploration wells were drilled in the Coos Bay basin between 1914 and 1993, many of which encountered gas kicks in the coal seams penetrated dur ing drilling. An independent engineering study estimated total gas in place on Torren t’s acreage at approximately 1.2 Tcf.
Torrent commenced an initial multi-hole CBM coring pro gram at Coos Bay in October 2004. The company drilled and tested a total of 12 explor ation wells in three pilot areas: Beaver Hill (5 wells), Radio Hill (2), and Westport (5). In May 200 8, Torrent completed initial fracture

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stimulation of 5 CBM wells at Beaver Hill and started p roduction testing. Torrent claims the coal seams were saturated with pipeline-quality natural gas , but the project did not book proved reserves and has been placed on hold due to the compan y’s financial difficulties.
Core samples from 11 coal seams at the three test sites were desorbed at the well site. Based on initial results, the Beaver Hill core hole site was selected for a 5-well production pilot. Its original core hole was cased and converted to a product ion well. Four new wells were directionally drilled around it in a pattern from the same drilling location. All five wells penetrated multiple Lower Coaledo coal seams at depths of about 4,000 feet. The 5-m thick “D” seam in each well was stimulated with a nitrogen frac. Short-term rates of 200-500 Mcfd were reported.
Torrent tested one well at its Radio Hill site, comp leting 10 Lower Coaledo coal seams at depths of 2500-3000 feet and with a cumulative net coal thi ckness of 33 feet. The coals were stimulated with nitrogen fracs. Reported gas rate was much lower than at the Beaver Hill pilot, about 30 Mcfd with about 6 bwpd.
Produced water chemistry was not reported but appears t oo saline for surface discharge. The produced water from the Torrent pilots was trucked to a dilution facility adjacent to the municipal water-treatment plant at Coos Bay. Torrent had plan ned to evaluate fractured basalts beneath the Coaledo Formation at its Westport project site as a possible injection zone for produced water. The Oregon Department of Environmental Quali ty would require an approved water disposal/containment plan for any commercial-scale CBM p roduction; they have ruled out surface discharge.

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Figure B-1: CBM Deposits and Testing, Pacific North west Coal Region

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Figure B-2: Coal and CBM Stratigraphy, Pacific Nort hwest Coal Region

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## Appendix C Black Mesa Basin, Arizona 1. Summary
The 2,500 square mile Black Mesa Basin in northeastern Ar izona contains extensive coal resources that have not been tested for CBM but could h ave significant potential (1-10 Tcf). 13 The northern part of the basin has experienced large-sca le surface coal mining since the 1960s, but conflicting ownership claims on Hopi and Navajo lan ds further south in the basin have discouraged CBM testing to date. Black Mesa is perhaps t he last significant untested CBM basin in the US Rocky Mountain region.
Based on outcrop studies and data from sparse oil and ga s wells drilled in the 1950s through the 1970s, CBM reservoir conditions in Black Mesa appear prospective and might even approach those of the commercially developed San Juan a nd Raton Basins nearby. In certain respects, Black Mesa resembles the undeveloped Raton ba sin of 20 years ago (though it is 50% larger than the Raton). Cretaceous Wepo Formatio n coals total up to 60 feet thick and dip south from outcrop to a depth of approximately 3,000 f eet in the basin’s center. Coal rank ranges from sub-bituminous to high-volatile bituminous A . Thinner coals occur in the underlying Cretaceous Toreva and Dakota Formations. Market access cou ld be via the recently constructed Questar Southern Trails gas pipeline, which cr osses the northern edge of the basin, or the El Paso Lincoln pipeline, which crosses just south of the basin.

2. Resource Potential
The Cretaceous Mesaverde Group offers three potential CBM targets ( Figure C-1 ). The thickest is the Wepo Formation, with up to 60 feet of coal, while the underlying Toreva and Dakota formations contain an additional 10 to 50 feet

. 14 Wepo coals are high-volatile bituminous (12,400 Btu/lb; dry basis). Toreva and Dakot a coals are lower in rank at outcrop, but may increase to bituminous levels below 2,000-foot depth s. Structure is favorably simple, with gently dipping strata interrupted by broad Laramide-ag e folds that were formed over Laramide or reactivated Precambrian basement faults.
CBM development in the Black Mesa Basin faces several chall enges. The thickest coals are mapped in the northern shallow part of the basin, wh ere gas content is low ( Figure C-2 ). Deeper areas (2,000 to 3,000 feet) in the center of the basin have better CBM potential but are mapped as having thin coal. However, this may be more due to lack of reliable log data than actual coal thickness trends. Erosion has cut deep canyons acr oss the recently uplifted basin, locally exposing and possibly degassing the Wepo and Toreva coals. However, the lowermost Dakota coals are not exposed and, as in the Raton Basin, the Black Mesa has extensive uneroded plateaus where coals remain buried and may b e gas saturated.

3. Market Potential. Black Mesa has never been a gas-productive basin, thus the re is no gas pipeline infrastructure within the basin’s interior. However, the perimeter of the basin is served by two interstate gas pipelines that transport gas from the San Juan basin to southern California markets. Questar’s 16-inch diameter, 80-MMcfd capacity S outhern Trails gas pipeline, converted from an existing disused oil pipeline in 2002 , crosses the northwestern edge of the Black Mesa basin. El Paso’s Lincoln pipeline crosses just s outh of the basin and has 600 MMcfd capacity.

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Figure C-1: Coal and CBM Stratigraphy, Black Mesa B asin

Primary CBM Target

Secondary CBM Targets Modified from Nations, 2002

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Figure C-2: Coal Thickness Distribution Map, Black Mesa Basin

Modified from Nations, 2002

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## Appendix D Coalbed Methane Potential of Low Rank Coals in the Gulf Coast

1. Summary

A large in-place coalbed methane resource exists in Gulf Coast Tertiary coals, stretching from the Florida panhandle to the Texas Gulf Coast, Figu re 1. Recent work by the U.S. Geological Survey (USGS) estimates total undiscovered technica lly recoverable resources in the Cretaceous-Tertiary Coal beds of the Gulf Coast Reg ion to range from 1.7 to 7.9 Tcf, with a mean estimate of 4.1 Tcf. 15 Prospective coals occur at depths of 1,500 to 5,0 00 foot depths with more mature, gas rich coals existing below 3,0 00 feet. Drilling has been limited to individual test pilots and significant production h as yet to be established. However, leasing has been active, with over 400,000 acres leased to date

.



### Figure 1. Gulf Coast Tertiary Coal Belt (Louisiana to Florida)

1 , 0 0 0

5

, 0 0 0

1 0

, 0 0 0 2

, 0 0 0

1 0
, 0 0 0

0 70 140 210 280 Miles N Legend

Wilcox Depth Contour ft

1000 2000 5000 10000 States

Source: based on data from http://pubs.usgs.gov/of/2000/ofr-00-0113/wlcxmaps.h tm#1 

### JO

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2. Resource Potential

Recent investigations suggest that significant coal bed gas resources may exist in the lower Trinity Group and Hosston Formation (both Lower Cre taceous), Midway Group (Paleocene), and Wilcox Group (Paleocene-Eocene) of the Gulf of Mexico Coastal Plain. At outcrop, these coals are generally classified as lignites. However , thermal maturity increases with depth in these formations, and although comprehensive data a re lacking, coal rank is most likely subbituminous at depth. Drill records from Arkansas and Louisiana indicate that there are Cretaceous coal beds greater than 10 feet thick at depths of 1,500- 6,000 feet suitable for coalbed gas development. Available data from conven tional oil and gas wells in Louisiana indicate that upper, middle, and lower Wilcox Group coal zones have potential for coalbed gas accumulations and similar data from Texas, Arkansas , Mississippi, and Alabama indicate that gas may be present in coal beds of the lower and mi ddle sections of the Wilcox. In addition, gas accumulations may occur in the coal beds of the upp er part of the Midway Group in Mississippi and Alabama.
Public data from several wells completed in Wilcox Group coal zones in north-central Louisiana indicate that initial production ranges from 7 to 1 22 thousand cubic feet (Mcf) of gas per day. In Louisiana, the depth to the targeted Wilcox coal be ds ranges from 1,500 to 5,000 feet, and individual coal beds have a maximum thickness of ab out 20 feet. The thickest coal beds tend to be in the lower Wilcox coal zone and cumulative coa l thickness can exceed 100 feet.
Much of the early work characterizing the coalbed m ethane resource in Louisiana was done by John Echols, then with the Louisiana Geological Sur vey. 16 , The U.S. Geological Survey (USGS) also has looked into the resource potential of Gulf Coast coal seams. 17

More data are needed to better characterize and ass ess the coalbed gas potential for the Cretaceous coal beds in this region. Regional studi es by the Louisiana Geological Survey and the Texas Bureau of Economic Geology are ongoing to better determine the extent and characteristics of coalbed methane resources in the Gulf Coast.
Nonetheless, the USGS recently completed an assessm ent of the undiscovered continuous gas potential of Cretaceous-Tertiary coal beds of the o nshore areas and State waters of the Gulf Coast. They estimate that total undiscovered techni cally recoverable resources in the Gulf Coast Region to range from 1.7 to 7.9 Tcf, with a m ean estimate of 4.06 Tcf in the geologic provinces they assessed. Nearly all of the undiscov ered gas resource is assessed within the Wilcox Coalbed Gas assessment unit. .The unconventi onal gas resources were estimated to reside in coalbed reservoirs and in adjacent and in terfingered sandstones deposited in fluvial and deltaic depositional environments. The assessme nt results reflect estimates based on vertical drilling technology.
Similarly, the Potential Gas Committee, in their 20 06 assessment, estimated that undiscovered (speculative) coalbed methane resources in their Gu lf Coast region ranged from 1.5 to 6.75 Tcf, with a most likely estimate of 3.4 Tcf. 18


### 3. Development History

Louisiana
Devon Energy Co. drilled the first pilot program in Caldwell Parish, where Devon and Donner Properties share a common interest in the minerals over a large area. The first coalbed well was drilled in Caldwell Parish in 1989, but was plugged and abandoned in the same year. 19 Nonetheless, this test proved that the so-called li gnite was actually subbituminous, with good gas content, at the depths targeted.

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After John Echols left Louisiana State University B asin Research Institute for private industry, he also drilled a test in Caldwell Parish. King Dri lling drilled a coal seam well in LaSalle Parish. Other players include GeoMet, Inc., Mark V Petroleu m Co., Harvest Gas Management, Vintage Petroleum Inc., EnerVest Operating Co., Samson Reso urces and other companies are acquiring leases. Southwestern Energy Co. had the m ost producing wells, 29, as of the first of May 2008. Most of these companies are keeping what they know to themselves. 20

In Louisiana, exploration is underway in the north central portion of the state; in particular Caldwell and LaSalle parishes and those surrounding them. Sixteen CBM wells were drilled in 2006, and 26 wells have been spudded in 2007 as of October 1. As of August, 2008, there were 44 producing wells that have produced from 10 to 25 0 Mcf per day, according to some sources and 9 in various stages of dewatering. The companie s drilling the wells have not divulged much information about the production or drilling detail s publicly. 21

Prior to 2005, Louisiana did not have law appropria te for coalbed methane wells. Government and industry worked together to successfully educat e the legislature regarding the need for larger units and state regulations were changed. Th e horizontal wells these plays demand are expensive, but can effectively cover large areas, s o up to 5,000 acre units were created to maximize the potential of each location.



### Texas
The most advanced exploration for coalbed methane i n Texas is in the bituminous coals of the Olmos Formation in Maverick County, where two compa nies have leased more than 250,000 acres and permitted more than 60 wells. These compa nies have drilled and/or recompleted more than 30 wells, which they are testing. One com pany began limited commercial gas production from Olmos coals in early 2001, but earl y production rates are low and have not yet established commerciality of the project. Reportedl y, operators are evaluating Wilcox coalbed methane in Zavala County, South Texas, and in East- Central Texas. Operators have not reported results or commercial gas production. 22



### 4. Market Potential
The major coal seams of interest in the Gulf Coast are at depths of 2,800 to 3,400 feet, so the average cost to drill and complete a well is only a bout $250,000 to $300,000 per well and early test data has established the gas content in the co als as economical. This could make the development of Gulf Coast coalbed methane economica lly competitive with other supplies producing in this region, which is served by a plet hora of natural gas pipelines.

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## References

1 U.S. Geological Survey, Assessment of Undiscovered Oil and Gas Resources in Cretaceou s-Tertiary Coal Beds of the Gulf Coast Region , Fact Sheet 2007-3039, 2007

2 Smith, T.N., 1995. “Coalbed Methane Potential for Alaska and Drilling Results for the Upper Cook Inlet .” Intergas Conference, May 15-19, Tuscaloosa, Alabama, p . 1-21.

3 Flores, R., Stricker, G., and Kinney, S., “Alaska Coa l Geology, Resources, and Coalbed Methane Potential.” US Geological Survey, DDS 77, 2004.

4 Roberts, S. et al., 2006. “Assessment of Coalbed G as Resources in Cretaceous and Tertiary Rocks on the North Slope, Alaska, 2006.” Preliminary 2-page r eport.
5 Montgomery, S.L. and Barker, C.E., “Coalbed Methane, Cook Inlet, South-Central Alaska: A Potential Giant Gas Resource.” AAPG Bulletin, v. 87, p. 1-13, January 2003.

6 Tyler, R., Scott, A., and Clough, J., 1998. “Coalbe d Methane Potential and Exploration Targets for Rur al Alaskan Communities.” Alaska Division of Geological a nd Geophysical Surveys Final Report, 169 p.

7 Choate, R., Johnson, C.A., and McCord, J.P., 1984. “Geologic Overview, Coal and Coalbed Methane Resources of the Western Washington Coal Region.” In Rightmire, C.T. et al., eds., Coalbed Methane Resources of the United States, AAPG Studies in Geol ogy, Series 17, p. 353-372.

8 Stevens, S.H., 1993. “Pacific Coal Region.” In Co albed Methane – State of the Industry, Gas Research Institute, Quarterly Review of Methane from Coal Sea ms Technology, v. 11, no. 1 (August), p. 21-23.

9 Johnson, S.Y. and Rice, D.D., 1995. “Region 2, Paci fic Coast – Western Washington.” In Gautier et al., eds., 1995 National Assessment of United States Oil and Gas Resources. U.S. Geological Survey Digital Data Series 30, p. 6-12.

10 McHenry, J., Bazinski, P., and Lentz, R. “Another Chan ce for CBM in Mt. Rainier Coal Fields, Washington.” 4th 2003 RMAG Coalbed Methane Symposiu m Proceedings, Rocky Mountain Association of Geologists, Denver, CO, June 10, 2003.

11 Comet Ridge Limited. Presentation to CSG Summit, Christchurch, New Zealand, June 30, 2009.

12 Torrent Energy Corporation. Press Releases, January 17, March 20, and May 8, 2007.

13 Stevens, S.H., Nations, J.D., and Rauzi, S.L., 2002. “Black Mesa Coal Basin, Northeastern Arizona : An Overlooked Rocky Mountain Coalbed Methane Play.” Am erican Association of Petroleum Geologists, Annual Meeting, Houston, Texas, March 10 -13.

14 Nations, J.D., Swift, R.L., and Haven, H.W., Jr., 20 02. “Summary of Cretaceous Stratigraphy and Coal Distribution: Black Mesa Basin, Arizona.” in: Nation al Coal Resource Assessment: Geologic Assessment of Coal in the Colorado Plateau: Arizona, C olorado, New Mexico, and Utah, U.S. Geological Survey.

15 U.S. Geological Survey, Assessment of Undiscovered Oil and Gas Resources in Cretaceou s-Tertiary Coal Beds of the Gulf Coast Region , Fact Sheet 2007-3039, 2007

16 John B. Echols, “Coalbed Methane: Louisiana's Undere xploited Energy Resource,” Basin Research Institute Bulletin, a publication of the Louisiana G eological Survey, Volume 9, pages 18-27 (June, 2000) ( www.lgs.lsu.edu )

17 Breland, F.C., Jr., 2004, Coalbed methane potential in Louisiana, in Warwick, P.D., ed., Selected presentations on coal-bed gas in the eastern United States, U.S. Geological Survey Open-File Report 2004-1273, p. 27-35.
18 Potential Gas Committee, Potential Supply of Natural Gas in the United States, Report of the Potential Gas Committee (December 31, 2006) , November 2007

19 Durham, Louise S., “From the ‘Seam”, Not the “Bed” : Coal Gas Tapped in Louisiana,” AAPG Explorer

, May 2006

20 Chance, Diana L., “Louisiana CBM on the Cusp?” Oil and Gas Investor, Special Report on Shale and Coalbed Methane , January 2008

21 McGee, David, “Haynesville Shale Gas Play and Louisia na Coal Seam Natural Gas,” Louisiana Department of Natural Resources, Technology Assessment D ivision, August 2008

22 Garduno, Jorge Luis, et al., “CO 2 Sequestration Potential in Texas Low Rank Coals, SP E Paper No. 84154 presented at the SPE Annual Technical Conference and Exhibition, Denver, CO, October 508, 2003