EMD Annual Leadership Meeting June 6, 2009

Gas Shale Committee Report Brian Cardott, Chairman

1. Active Gas-Shale Plays

In April 2009, the U.S. Department of Energy published the report “Modern shale gas development in the United States: a primer”, available at http://www.fossil.energy.gov/programs/oilgas/publications/naturalgas_general/Shale_Gas_Primer_2009.pdf. The EIA Active U.S. Gas Shale Plays map is available at http://www.eia.doe.gov/pub/oil_gas/natural_gas/analysis_publications/maps/maps.htm. An alphabetical list of 57 gas-shale plays across the United States and Canada was published in the November 2008 Explorer EMD column (http://www.aapg.org/explorer/divisions/2008/11emd.cfm). There are too many potential gas shales to describe each in detail. Below are a few highlights. (a) Fort Worth Basin, Texas: Barnett Shale (Mississippian). The Barnett

Shale is still the most active gas-shale play in the United States. The EIA Barnett Shale map is available at http://www.eia.doe.gov/pub/oil_gas/natural_gas/analysis_publications/maps/maps.htm. According to the Texas Railroad Commission web site (http://www.rrc.state.tx.us/data/fielddata/barnettshale.pdf) as of March 3, 2009 there were a total of 10, 539 Barnett Shale gas wells and 5,037 permitted locations in the Newark East Field (discovery date, October 15, 1981) of the Fort Worth Basin. The field produces in 19 counties. During calendar year 2008 (January through December), 1,396 billion cubic feet (Bcf) gas was produced from the field (representing peak annual production), accounting for 21% of Texas gas production. Of a total of 229 operators in the Newark East Field, the top 10 operators are:

(1) Devon Energy Production Co., L.P. (2) XTO Energy Inc. (3) Chesapeake Operating, Inc. (4) EOG Resources, Inc. (5) Encana Oil and Gas (USA) Inc. (6) Quicksilver Resources Inc. (7) Range Production Co. (8) Burlington Resources O&G Co. LP (9) Denbury Onshore, LLC (10) Williams Production Gulf Coast, L.P.

(Barnett Shale statistics charts are from http://www.rrc.state.tx.us/barnettshale/index.php)

(b) Arkoma Basin, Arkansas: Fayetteville Shale (Mississippian): by Peng Li (Arkansas Geological Survey). The EIA Fayetteville Shale map is available at http://www.eia.doe.gov/pub/oil_gas/natural_gas/analysis_publications/maps/maps.htm. A map of Fayetteville Shale wells is available at http://www.geostor.arkansas.gov/apps/aogc/index.htm. The top seven operators of the Fayetteville gas shale play based on numbers of producing wells are:

(1) Seeco Inc. (638 wells) (2) Chesapeake Operating Inc. (191 wells) (3) One TEC Operating, LLC (37 wells) (4) KCS Resources Inc. (36 wells) (5) Petrohawk Operating Co. (15 wells) (6) Hallwood Petroleum LLC (11 wells) (6) XTO Energy, Inc. (11 wells)

The Upper Mississippian Fayetteville Shale play is the current focus of a regional shale-gas exploration and development program within the central and eastern Arkoma Basin of Arkansas. Approximately 2.5 million acres have been leased in the Fayetteville Shale gas play. Early estimates have indicated that there are over 40 Tcf of gas reserves in the Fayetteville Shale. Estimated ultimate recovery (EUR) for a horizontal well is 2.9 Bcf/well. At the end of 2008, cumulative production of Fayetteville has totaled 380 Bcf and initial production rates of horizontal wells average about 2,000 Mcf/day. Fayetteville Shale reports from the Arkansas Oil and Gas Commission have noted well increases from 24 in 2004, 33 in 2005, 129 in 2006, 428 in 2007 and 587 in 2008. As of March 31, 2009, a total of 1,674 wells have been drilled and completed in the Fayetteville Shale play, of which 1,414 wells are currently producing gas. Fayetteville Shale wells generally range over a vertical depth between 1,500 to 6,500 feet. The thickness of Fayetteville Shale varies from 50 feet in the western portion of the Arkoma Basin of Arkansas (fairway area) to 550 feet in the central and eastern regions (primary producing area). Most Fayetteville Shale wells are horizontal wells and have been fracture stimulated using slickwater or cross-linked gel fluids. Horizontal lateral lengths are continually increasing in Fayetteville Shale wells. Horizontal wells drilled in 2008 averaged 3,500 feet in lateral length with some wells up to 7,000 feet. Southwestern Energy has been a major player since 2004 when production started. Chesapeake Energy and BP are also active in the Fayetteville play. BP acquired approximately a 25% interest in

Chesapeake’s Fayetteville assets for $1.9 billion in late 2008. Southwestern holds approximately 875,000 net acres in the play area and Chesapeake about 600,000 acres. Other operators involved with Fayetteville Shale exploration and development ventures include: XTO, One Tec, Petrohawk, KCS Resources, Hallwood Energy, Storm Cat Energy (USA) Operating, Edge Petroleum, Alta Operating and twelve other companies. Additional information is available at the Arkansas Geological Survey web site (http://www.state.ar.us/agc/agc.htm).

(c) Arkoma Basin, Oklahoma: Woodford Shale (Late Devonian-Early

Mississippian). According to the Oklahoma Geological Survey, as of April 20, 2009, there were a total of 1,047 Woodford Shale gas-well completions since 2004 (first application of advanced completion technology), primarily in the western part of the Arkoma Basin in eastern Oklahoma. Of a total of 764 horizontal Woodford Shale gas wells from 2005-2009, initial potential gas rates ranged from 3 to 11,875 thousand cubic feet of gas per day (Mcfg/d). Excluding 33 old well workover completions, cumulative production from 808 Woodford Shale-only wells drilled from 2004-2009 is 283,672,521 Mcf gas and 597,527 BBLs oil/condensate. A gas shale completions database, lists of references, maps, and several presentations are available on the OGS web site (http://www.ogs.ou.edu/oilgas.php). The latest Woodford Gas Shale Plays presentation is available at http://www.ogs.ou.edu/oilgaspres.php. Of 37 operators active in calendar year 2008, the top ten operators (for number of wells drilled during 2008):

(1) Newfield Exploration Mid-Continent Inc. (2) Coronado Great Plains (3) Devon Energy Production Co. LP (4) Continental Resources (5) WCT Operating (6) Antero Resources Corporation (7) Chesapeake Operating Inc. (8) XTO Energy (9) Pablo Energy II LLC

(10) Petroquest Energy Caney Shale (Mississippian) only-gas-well completions dropped from 24 in 2004 to 1 Caney-only in 2008 due to problems completing the clay-rich shale. Several companies are looking at less damaging completion fluids for Caney Shale wells. A number of wells completed both Caney and Woodford Shale (see chart below). New Woodford gas-shale plays are in the Ardmore Basin in southern Oklahoma, Anadarko Basin shelf in western Oklahoma, and northeast Oklahoma shelf. Presentations from the October 2008 Oklahoma Gas Shales Conference are available at http://www.ogs.ou.edu/highlights.php.

[Hart Unconventional Natural Gas Report, February 2009 feature]

(d) Michigan Basin, Michigan: Antrim Shale (Devonian): by Dr. William B. Harrison, III (Western Michigan University) The Michigan Basin Antrim Shale play is about 22 years old, having begun the modern phase of development in 1987. The total number of producing wells drilled in the play through 2008 is approximately 10,987 with about 9,668 still online. Total cumulative gas production reached 2.722 TCF through 2008. Michigan Antrim production is reported by project rather than by individual well or lease. Projects may be only a few wells or more than 70 wells. There were 766 separate projects at the end of 2008. Cumulative production for 2008 was 131,041,202 Mcf of gas. That was a 3.7% decline from 2007. There were 32 operators with production at the end of 2008. There were 9,668 wells online at the end of 2008. There were 385 new wells drilled in 2008. That is a 3.0% increase in wells from 2007. Most of the production comes from a few operators. The top 10 operators produced 79.7% of the total Antrim gas in 2008.

Although some wells can initially produce up to 500 Mcf/day, generally wells settle at less than 100 Mcf/day. Play wide average production at the end of 2008 was 37 Mcf/day per well. Many Michigan Antrim wells begin with high water production and begin to increase gas production as the water is pumped off. Water production generally continues throughout the project life, although it usually declines through time. Play wide gas to water production ratio reached almost 3 Mcf/bbl in 1998, 2008 ratio is 1.47 Mcf/bbl. CO2 is also an issue in the produced Antrim gas that is mostly of biogenic origin. Most wells begin with very low amounts of CO2 in the produced gas; however, the percentage of CO2 increases through time. Some projects that have a long production history may now exceed 30% CO2 in the produced gas. The play wide average was just over 12.4% CO2 in 2008. Wells produce from depths as shallow as 350 feet to just over 3,000 feet, although the vast majority of wells are completed from 1,000 to 2,500 feet deep. Wells are typically drilled with water and an attempt is made to keep the well in balance or slightly under-balanced. Wells are fraced with water and sand. Some wells are fraced using nitrogen or foam. Production and well data is available online at the Michigan Public Service Commission at http://www.cis.state.mi.us/mpsc/gas/prodrpts.htm Various kinds of oil and gas information is also available at the Michigan Office of Geological Survey site at http://www.michigan.gov/deq/0,1607,7-135-3311_4111_4231---,00.html Cores, samples and other kinds of data are available at the Michigan Geological Repository for Research and Education at Western Michigan University. That website is http://wst023.west.wmich.edu/MGRRE%20Website/mgrre.html

2008 Annual Summary Table of Michigan Antrim Shale Gas Production

Total number of wells drilled – 10,987 Total currently producing – 9,668 2008 Completions – 385 Total Horizontal wells – 426 2008 Horizontal wells – 80 Range in horizontal length – 42 ft. to 5,033 ft – Average length 1,973 ft IP range of all wells – 10 to 2,000 Mcf/day – average 80 Mcf/day Depth range of all wells – 361 ft to 2248 ft

Depth range of 2008 wells – 489 ft to 1,906 ft Average Thickness of Shales – 75 ft for Lachine Member, 20 ft for the Norwood Member 2008 Production – 131,041,202 Mcf gas and 88,931,392 bbls water 2008 Daily average per well – 37 Mcf Cumulative Production – 2,721,271 Mcf Number of Operators – 32 Top 10 Operators – ATLAS GAS & OIL COMPANY LLC HIGHMOUNT MIDWEST ENERGY LLC BREITBURN OPERATING LIMITED PARTNERSHIP BELDEN & BLAKE CORP DBA WARD LAKE ENERGY TERRA ENERGY LTD MUSKEGON DEVELOPMENT CO TRENDWELL ENERGY CORP JORDAN DEVELOPMENT CO LLC DELTA OIL CO INC O I L ENERGY CORP

Significant Trends – Production continues to decline at >3% per year even though the total number of wells added is increasing. Daily production per well also is still dropping, but not as fast as in previous years. The number of horizontal completions is increasing, but still represents less than 4% of total wells. Issues – None Legislation – None

(e) Appalachian Basin, multi-state: Marcellus Shale (Devonian): by Katharine Lee Avary (West Virginia Geological and Economic Survey, WVGES) New York: There are 45 wells with Marcellus listed as producing formation; 14 in 2007 with production of 28,200 Mcf and 333 barrels of water. These wells were on line from 1 to 12 months. Pennsylvania: There have been 1,452 Marcellus wells permitted since 2003. Records have been received for 311 wells (97 horizontals and 214

verticals). According to John Harper, average production ranges from 80 to 100 Mcf/day, with horizontals having higher averages than verticals for the first two years. West Virginia: For 2006 and 2007, there were almost 1,500 wells permitted which may be Marcellus; WVGES has records for 648 of these wells and are compiling production data. Very preliminary production looks like about 2.8 Bcf for 2006 and 9.86 Bcf for 2007. For 2008 (in progress), production was 4.93 Bcf with many more production records which need to be added. During 2008, there were 1,040 wells permitted which may be Marcellus. Evaluation of the records and production data are pending. All of the WV data is preliminary and subject to revision as this is on-going work. Visit the following web sites for more information on the Marcellus. http://www.wvgs.wvnet.edu/www/datastat/devshales.htm http://www.wvgs.wvnet.edu/www/datastat/WVGES_GeologyMarcellusShale.pdf http://www.mgs.md.gov/geo/marcellus.html http://www.dec.ny.gov/energy/46288.html http://www.dcnr.state.pa.us/topogeo/pub/pageolmag/pdfs/v38n1.pdf http://www.dcnr.state.pa.us/topogeo/oilandgas/index.aspx http://www.pamarcellus.com/ http://www.dec.ny.gov/docs/materials_minerals_pdf/GWPCMarcellus.pdf

(f) Haynesville Shale (Jurassic), Louisiana and Texas: by Creties Jenkins (Degolyer and Macnaughton) [Unconventional Natural Gas Report feature for September 2008] The Haynesville Shale is located in northern Louisiana and eastern Texas at depths ranging from 10,500 to 13,500 feet. It is an overpressured (0.7-0.9 psi/ft) Upper Jurassic-age shale bounded by the Cotton Valley Group sandstones above and Smackover limestones below. The Haynesville covers an area of approximately 9,000 square miles with an average thickness of 200 to 300 feet. The thickness and areal extent of the Haynesville has allowed operators to evaluate a wide variety of spacing intervals ranging from 40 to 560 acres per well. Original gas-in-place in the Haynesville is estimated to be 717 TCF and technically recoverable resources are estimated at 251 TCF. A comparison of the Haynesville to other shale gas plays is shown in the table below (Reference: Modern Shale Gas Development in the United States: A Primer; U.S. Dept. of Energy; April 2009).

Initial production rates range from less than 3 to more than 24 MMcf/d. Declines are very steep, exceeding 80% in the first year with estimated ultimate recoveries ranging from 3 to 10 BCF per well. The breakeven gas price for these wells is less than $3.50 per MMBtu (Reference: Examining the True Economic Cost of Shales; Credit Suisse Equity Research Report, April 8, 2009), which makes it the most attractive shale gas play in North America. Drilling and completion costs average 9-10 MM$ per well assuming lateral lengths of 4,300 to 4,600 feet with 12-15 fracture stimulation stages per well. Each stage contains four perforation clusters, two feet in length, and spaced approximately 80 to 85 feet apart. Light sand fracture stimulations are used containing either ceramic or resin-coated proppant. The biggest operators in the Haynesville, based on acreage position, are Chesapeake, Devon, EnCana, EOG Resources, Exco Resources, Forest Oil, Petrohawk, XTO Energy, and Plains Exploration and Production. Over 400 wells have been drilled thus far with approximately 80 rigs running as of April, 2009. Petrohawk drilled an additional 31 wells during the first quarter of 2009. The joint venture between Chesapeake and Plains is expected to average 26 rigs this year, which amounts to more than 150 new wells based on an average drilling time of two months per well. The increased drilling in the Haynesville is also causing a rapid expansion in infrastructure for compression equipment and pipelines to move the gas out of the area and to market. Based on the accelerating growth of the Haynesville, it is projected to become America’s largest gas field within five years (Reference: From Shale to Shining Shale, A Primer on North American Shale Gas Plays; Deutsche Bank; July 22, 2008.) Additional information on the Haynesville can be found at these websites: http://www.haynesvilleplay.com/ http://geology.com/articles/haynesville-shale.shtml http://oilshalegas.com/haynesvilleshale.html

(g) Black Warrior Basin, Alabama and Mississippi: Neal/Floyd Shale (Mississippian): by Kent A. Bowker (Bowker Petroleum, LLC) There continues to be little activity in the Neal/Floyd (hereafter termed Neal) Shale of the Black Warrior Basin of Alabama and Mississippi. (The organic-rich portion of the Floyd is termed the Neal in Mississippi, and that term more properly reflects the objective of operators in the play.) The first sale of Neal gas occurred in 2008: the Jim Walter Resources, JWR

#28-05-02 in Tuscaloosa County is the first productive Neal well in Alabama. The well averaged 98 MCF/D and 780 BW/D over 39-day production test in the spring of 2008. The well is currently selling gas at a rate of 50 MCF/D. In Mississippi, Anadarko placed their Saxophone #22-1 (Clay County), originally a vertical Neal test, on line in May 2008; the well is currently producing about 600 MCF/D, but from a shallower sandstone interval. The most active operator this past year in the play has been St. Mary Land & Exploration. They have drilled a total of four vertical Neal wells in Mississippi: two wells in Calhoun County and one each in Chickasaw and Pontotoc counties. There are no completion attempts filed for these wells to date. In addition to placing the Saxophone #22-1 on line, Anadarko resumed drilling activity in Mississippi. Their St. Paul #8-1 in Clay County was drilled to 11,134 ft and 4 ½” casing was set to 11,108 ft; this is a vertical well. This is one of the deepest wells drilled in the basin. No completion attempts have been filed with the state. Cabot Oil & Gas drilled one Neal test in mid-2008. The Williamson #33-11 1 was drilled in Yalobusha County, Mississippi to a depth of 7803 ft. 5 ½” casing was set to TD but no production information is filed for this well. In Greene County, Alabama, Huber took over operations from BWNR on the Weyerhauser #2-23-2402. This is a vertical Neal and Chattanooga well; in late 2008, Huber completed the well in the Chattanooga Shale and flowed 456 MCFG during the initial test. The well is currently shut in. In November, 2007, the Geological Survey of Alabama published an overview of Floyd Shale drilling activity in the state (http://www.ogb.state.al.us/documents/misc_ogb/Floyd%20Shale.pdf).

(h) Chattanooga Shale: Black Warrior Basin, Alabama and Mississippi

[Hart Unconventional Natural Gas Report, March 2009 feature]

(i) Devonian Shale: Kentucky. According to the Kentucky Geological Survey web site (http://www.uky.edu/KGS/emsweb/oginfo/resource.html, http://www.uky.edu/KGS/emsweb/oginfo/devsh_reserves.pdf), the estimated proven reserves in the Ohio/New Albany/Chattanooga black shale of Kentucky (Illinois and Appalachian basins) is 12 Tcf gas. “Gas reservoir character of Devonian shales of Kentucky” (http://www.uky.edu/KGS/emsweb/devsh/dvnnsh.html)

“Predicting cumulative production of Devonian shale gas wells from early well performance data, Appalachian Basin of eastern Kentucky” (http://www.uky.edu/KGS/emsweb/devsh/production/) Well activity and production data are not available.

(j) Illinois Basin, Indiana: New Albany Shale (Devonian)

According to the well record tables of the “Petroleum Database Management System” on the Interactive Maps portion of the Indiana Geological Survey web site (http://www.igs.indiana.edu/pdms/index.cfm), there are a total of 706 New Albany Shale gas wells completed since 1885 (as of April 20, 2009). Most of the wells, drilled since the mid 1990s, are in Harrison Co. at depths of 500-1,100 ft and production rates of 20-450 Mcfg/d. Recent exploration is in Daviess Co. Gas production is thermogenic and mixed thermogenic/biogenic primarily from the organic-rich Clegg Creek Member. Source: Comer, J.B., N.R. Hasenmueller, M.D. Mastalerz, J.A. Rupp, N.R. Shaffer, and C.W. Zuppann, 2006, The New Albany Shale gas play in southern Indiana (abstract): 2006 AAPG Eastern Section meeting, Program with Abstracts, p. 17.https://scholarworks.iu.edu/dspace/handle/2022/712 [Hart Unconventional Natural Gas Report, December 2008 feature]

(k) Maverick Basin, Texas: Pearsall Shale (Cretaceous)

[Hart Unconventional Natural Gas Report, November 2008 feature]

(l) Powder River Basin, Montana and Wyoming: Mowry Shale (Upper Cretaceous) Anna, L.O., and T.A. Cook, 2008, Assessment of the Mowry Shale and Niobrara Formation as continuous hydrocarbon systems, Powder River Basin, Montana and Wyoming: USGS Open-File Report 2008-1367. http://pubs.usgs.gov/of/2008/1367/

(m) Utah Shale Gas Activity Update 2008-2009: by Thomas C. Chidsey, Jr., (Utah Geological Survey)

Uinta Basin Mancos Shale Play Overview The Upper Cretaceous Mancos Shale Mancos consists of interbedded claystone, siltstone, and very fine grained sandstone. It is up to 3,500 ft (1,100 m) thick and overpressured in some areas. The thickness of potential shale-gas members (Prairie Canyon and Tununk Shale) of the Mancos ranges up to 1,500 ft. (450 m) with 2-5% porosity. Vitrinite reflectance at the top of the Mancos ranges from 0.65% to 1.50%; total organic carbon (TOC) is 1% to 2% with type II to mixed type II-III kerogen. Estimated in-place gas is reportedly between 280 and 350 Bcf per square mile (3 and 3.8 billion m3/km2), with a projected estimated ultimate

recovery (EUR) of 5-15% of in-place gas. Initial flow rates range from 1,000 to 2,000 Mcf/day (28,320-56,630 m3/day). The exact extent of the play has not been defined.

Activity East of the San Rafael Swell in the southwestern Uinta Basin, Bill Barrett Corporation drilled two 3,900 ft (1,200 m) vertical evaluation wells (100% working interest) in the shallow, fractured Juana Lopez Shale Member of the Mancos. The company plans to finish the testing and completion process of these wells in 2010. Barrett has 35,000 acres (14,000 hectares) in this area they call “Shallow Hook.” To the north at the West Tavaputs field Barrett is evaluating the Mancos potential at West Tavaputs field. As already announced, the Record of Decision on the Environmental Impact Statement for full-field development at West Tavaputs has been deferred to President Obama's administration. Due to the pending transition of certain positions within the Bureau of Land Management and Department of Interior, the Company believes it will be months before the Record of Decision is obtained. At year-end 2008, the company had an approximate 96% working interest in production from 130 gross wells in its West Tavaputs shallow and deep programs. In 2008, Petro-Canada staked the 12-14 Twin Hollow-Federal, a 14,300 ft (4,360 m) well (section 12, T. 13 S., R. 15 E., Carbon County) south of the West Tavaputs area designed to test the Mancos and shallower formations. The company has plans for 14 more exploratory tests in the region. The Bureau of Land Management’s (BLM) Price Field Office prepared an Environmental Assessment (EA) for the Twin Hollow drilling program. In the extreme west-southwest part of the Uinta Basin, north of the town of Price, Williams Production RMT Company, staked the 23-16 Reservation State, a 13,000 ft (3,960 m) wildcat (section 16, T. 11 S., R. 11 E., Duchesne County) to potential gas zones in the Mancos Shale. This well is 3.5 mi (5.6 km) southwest of the company’s 2007 42-2 Reservation State well; no details have been release on this 12,000 ft (3,660 m) test of the Mancos. In 2008, GASCO Energy explored and developed deep gas in the Mancos Shale at River Bend project area, Wilken Ridge Unit, and Gate Canyon Unit/area in the central Uinta Basin where the company has 26,442 net acres (10,700 hectares), 35,424 net acres (14,336 hectares), and 22,273 net acres (9,014 hectares), respectively. In the River Bend area the company completed 18 Mancos wells, two completions are pending, and three wells are proposed. Ten Mancos wells are planned for both the Wilken Ridge and Gate Canyon areas. In the Gate Canyon area, tests continue on the Gate Canyon State No. 23-16 well (section 16, T. 11 S., R. 15 E., Duchesne County) which flowed at an initial rate of 5.7 MMcf/day

(0.16 million m3/day) from fractured-stimulated intervals in the Mancos Shale and Blackhawk Formation. GASCO estimates gas recovery between 1.0 and 3.0 Bcf (0.03-0.8 billion m3) per well from overpressured Mancos zones at depths of 13,000 to 16,500 ft (3,900-5,000 m). Within the Monument Butte field, producing from the Tertiary Green River Formation, west of the River Bend area, Newfield Production Company staked a deeper pool wildcat, the 15,900 ft (4,850 m) 14-16T-9-17 (section 16, T. 9 S., R. 17 E., Duchesne County) targeting the Mancos Shale. In the southeastern part of the Uinta Basin along the northwest-trending Uncompahgre uplift, National Fuel Corporation staked an 8,096-ft wildcat to delineate the 2006 EOG Resources Inc. Lindisfarne 1-26 (section 26, T. 15 S., R. 23 E., Uintah County) discovery. That well initially flowed gas at 535 Mcf/day (15.2 m3/day) and 32 bbls (5.1 m3) of condensate from the Mancos Shale and deeper formations; the Mancos intervals were fractured stimulated. In 2008, Royale Energy Inc. staked a deep offset test targeting the Mancos Shale and other formations in the southeastern part of the Uinta Basin along the Uncompahgre uplift, offsetting its 2007 20-1 V Canyon discovery (section 20, T. 15 S., R. 21 E., Uintah County) that encountered gas in the Mancos and numerous deeper and shallower formations. In 2009, Questar Exploration & Production Company staked an 11,364 ft (3,464 m) wildcat, the 8D-21-15-19 Wolf Flat (section 21, T. 15 S., R. 19 E., Uintah County) to the west and southwest of Flat Rock field. It offsets the company’s 2008 Wolf Flat discovery 1 mi (1.6 km) to the north-northwest which tested gas from the Mancos and deeper Cretaceous formations. Wind River Corp. and Questar, continue targeting the Mancos and other formations in the Flat Rock field area in the southern Uinta Basin. In Natural Buttes field in the eastern Uinta Basin, Utah’s largest gas field, Questar Exploration & Production Company continues to evaluate deep, tight gas sand/shale gas play potential including the Mancos Shale. Over 30 wells were drilled by the company in 2008 for the Mancos and other deep formations. XTO Energy separately tested the Mancos and tight sands potential of their Natural Buttes acreage in 2008. Drilling operations may be curtailed in 2009 due to the economic downturn and depressed gases.

WasatchPlateauBlueGateandTununkShaleMembers,CretaceousMancosShale Overview On the Wasatch Plateau in central Utah, potential shale gas reservoirs include the Blue Gate and Tununk Shale Members of the Mancos Shale. The Blue Gate contains an upper high-TOC interval with dense, non-fissile, dark gray claystone and scattered, light gray silt laminae and

bivalve fragments. The Tununk consists of dark gray calcareous mudstone with interbeds of silt to very fine sand laminae containing silt–filled burrows. The extent and resource potential of this frontier play are unknown. Activity In the fall of 2008, Pioneer Natural Resources USA Inc. staked the 11C-34-11-9 Jenson State (section 34, T. 11 S., R. 9 E., Carbon County), a 7,575 ft (2.309 m) test of the Mancos Shale on the northeastern Wasatch Plateau. Ten miles (16 km) to the west, EOG Resources Inc. has staked the 1-11 Wing Spring (section 11, T. 11 S., R. 7 E., Carbon County) and 1-11 Wing Spring (section 14, T. 11 S., R. 7 E., Carbon County) projected to 9,000 and 10,000 ft (2,700 and 3,000 m), respectively, to presumably to also test the Mancos. XTO continued evaluating, completing or has staked several wells targeting the Tununk Shale Member of the Mancos. XTO took over the prospects from Dominion E&D in 2007. Central Utah Mississippian Shale Gas Play Overview Paleozoic shales in the Colorado Plateau and eastern Basin and Range Provinces have long been known for their potential as source rocks for hydrocarbons that have migrated into other formations but have not been considered as in-situ gas reservoirs. These include the Mississippian Manning Canyon and Delle Phosphatic Shales of central Utah. The Manning Canyon Shale is mainly claystone with interbeds of limestone, sandstone, siltstone, and mudstone, and has a maximum thickness of 2,000 ft (600 m). TOC varies from 1% to greater than 8% with type III (?) kerogen. In north-central Utah, the Manning Canyon was deeply buried by sediments in the Pennsylvanian-Permian-aged Oquirrh basin and is therefore likely very thermally mature. The Delle Phosphatic Shale is a member of the Chainman Shale, Deseret Limestone, and Little Flat Formation. The Delle is composed of interbedded organic-rich phosphatic shale, siltstone, and limestone deposited in a starved basin at the foot of the Paleozoic carbonate ramp. The member is typically 100 to 200 ft (30-60 m) thick. Although the organic content of some of these shales is partially known, the reservoir quality and the basic rock mechanic data so important to successful completions are virtually unknown. In addition, the distribution and thickness of these rocks are poorly mapped and the vertical succession and regional correlation of the Manning Canyon and Delle Phosphatic has not been interpreted in a sequence stratigraphic framework. The burial history of the Manning Canyon and Delle Phosphatic appears complex and probably varies widely from deep burial in the Permian Oquirrh basin (>10,000 ft [3,000 m] of overlying Pennsylvanian and Permian strata) to shallower burial along the Paleozoic

shelf of central Utah. There are no published studies of the best completion practices for the Manning Canyon and Delle Phosphatic shales. Exploratory efforts are just beginning to target this frontier gas shale play. Activity In 2008, Bill Barrett Corporation and its partner ConocoPhillips continued to acquire leasehold acreage in an area named “Hook” targeting the Manning Canyon Shale. Barrett (50% working interest with ConocoPhillips) drilled the 15-32-15-12 State well (section 32, T. 15 S., R. 12 E., Carbon County) to a total depth 7,585 ft (2312 m) in the Hook prospect targeting the Manning Canyon Shale. The Manning Canyon consisted of 589 ft (180 m) of shale over a total formation thickness of 816 ft (249 m), 422 ft (129 m) of which was cored. The well analysis indicated good gas shows and high gas contents from core samples. In 2009, the Company plans to drill a horizontal well with a 3,700-foot (1,130 m) horizontal lateral offsetting the vertical well in the same section. Barrett has locations staked for three additional Manning Canyon wells in Carbon and Emery Counties within its Hook prospect area. The company also plans to conduct a 3-D seismic program in the area covering 142 mi2 (368 km2). West of the Hook area, Shell Western Exploration & Production, Inc. drilled and cored the Manning Canyon Shale in the 5-12 Carbon Canal well (section 12, T. 16 S., R. 10 E., Emery County). No results have been released. Shell has staked two additional 9,400 ft (2,900 m) wells to test potential Paleozoic shale gas reservoirs 3.5 mi (5.6 km) southwest and 6 mi west-northwest (9.7 km) in Emery and Carbon Counties, respectively. Within the same area as Barrett is exploring, Chief Oil & Gas International Petroleum LLC has announced plans to drill a 7,287 ft (2,221 m) test of the Mississippian (section 3, T. 16 S., R. 12 E., Emery County) 1.5 mi (2.4 km) southwest of a Barrett location. The drill site is just west of Grassy Trail Creek oil field, which produces from the Triassic Moenkpoi Formation. On March 24, 2009, oil and gas lease sales were held by the Utah State Office of the BLM in Salt Lake City. The sale’s top per acre bid was $190 made by Salt Lake City-based International Petroleum for an 80-acre (32 hectares) parcel 5 mi (8 km) north of the Barrett well. In June 2008, the company also was the top bidder paying $2100 per acre for a 160-acre (64 hectares) parcel 5 mi (8 km) southwest of the Barrett well. The BLM’s Price Field Office is preparing an EA to determine whether or not to offer for competitive leasing about 332,000 acres (134,000 hectares) in the region.

Paradox Basin Pennsylvanian Shale Gas Play Overview Cyclic shale units in the Pennsylvanian Paradox Formation (Gothic, Chimney Rock, and Hovenweep, for example), consist of thinly interbedded, black, organic-rich marine shale; dolomitic siltstone; dolomite; and anhydrite. They generally range in thickness between 25 and 50 ft (8-15 m). These units contain TOC as high as 15% with type III and mixed type II-III kerogen, are naturally fractured (usually on the crest of anticlinal closures), and are typically often overpressured. In the Utah part of the Paradox Basin, exploratory efforts are just beginning to target this play; many in environmentally sensitive areas. The Colorado part of the basin has seen considerable success, particularly for the Gothic using horizontal drilling. Activity CrownQuest Operating LLC continues to evaluate the drilling results and conduct workovers in former dry holes on the Hovenweep, Gothic, and Chimney Rock shale zones of the Pennsylvanian Paradox Formation. They continue to develop an ambitious exploration program; nine wells have been staked. Cabot Oil & Gas, Baytex, Fidelity E&P, and Babcock & Brown have also staked wells targeting Paradox shales or are evaluating drilling results. Little information is available on these activities. In the Colorado side of the Paradox Basin, Bill Barrett Corporation is conducting an extensive, successful horizontal drilling exploration and development program for the Gothic and Hovenweep shales in what the company has named the “Yellow Jacket” and “Green Jacket” areas, respectively. The estimated Gothic and Hovenweep shale thickness in these areas ranges from 80 to 150 ft ( 24-46 m) at depths between 5,500 and 7,500 ft ( 1,700 and 2,300 m). The shale zones are composed of 36% quartz, 44% carbonate, and 15% clay. They are over pressured at 0.52 to 0.59 psi/ft. Barrett estimates gross in-place reserves are 50 Bcf/section (1.4 billion m3/section). The Yellow Jacket area covers 1,850 mi2 (4,800 km2), where the company has about 140,000 net undeveloped acres (57,000 hectares). Barrett has drilled eight horizontal wells in the Gothic shale (55% working interest); 10 wells are planned to be drilled in 2009. Three wells are on production totaling 3.0 MMcf/day (85,000 m3/day). In an effort to alleviate slat migration into the wellbores, the company continues to modify completion and pumping techniques including employing cemented casing and micro-seismic monitoring during fracturing. Davis Petroleum Corporation is also planning two Gothic wells in the Yellow Jacket area. The Green Jacket area, which extends into Utah, covers 1,300 mi2 (3,400 km2), where the company has about 150,000 net undeveloped acres (61,000 hectares). Barrett is evaluating the results of their first horizontal well (100% working interest).

In the northwestern part of the Paradox Basin, Delta Petroleum continues to evaluate clastic zones in the Paradox Formation, which likely include shale. Delta’s 28-11 Samson Federal discovery (section 28, T. 22 S., R. 17 E., Grand County) is flowing at a rate of 1.7 MMcf/day (48,000 m3/day) from the “O” zone clastic interval within the Paradox cyclic salt section into the new 49.6- (80 km) Greentown pipeline beginning June 30, 2008. The pipeline if sized to move up to 150 MMcf (4.2 MMm3/day) daily and varies in diameter from 16 to 20 inches (6.3-7.9 cm). Delta estimates that their wells in the area will recover approximate 2.0 Bcf (56.6 million m3) where they have three discoveries. The company is now developing Greentown field, 2 miles (3 km) south of the town of Green River, through horizontal drilling. Delta has approximately 46,000 gross acres (19,000 hectares) and plans to maintain a continuous drilling program. Research In August 2008, the Utah Geological Survey (UGS) began a three-year project to characterize Mississippian shale gas reservoirs (Manning Canyon) in central Utah, and Pennsylvanian shale gas reservoirs (Gothic, Chimney Rock, and other shales in the Paradox Formation) in the Paradox Basin of southeast Utah, funded by the Research Partnership to Secure Energy for America (RPSEA). Halliburton Energy Services, the UGS’s industry partner, will assist with the project by designing best completion practices based on the reservoir characteristics determined by the UGS, and project team members Bereskin and Associates, Inc. and GeoX, Inc. Additional information is available at the UGS project Web site: http://geology.utah.gov/emp/shalegas/index.htm. Presentations Potential Shale Gas Resources in Utah by Michael D. Laine, Thomas C.

Chidsey, Jr., and Craig D. Morgan, presented at the American Association of Petroleum Geologists Annual Convention, in San Antonio, Texas, April 21, 2008.

Potential Shale Gas Resources in Utah by Michael D. Laine, Thomas C. Chidsey, Jr., and Craig D. Morgan, Utah Geological Survey, presented at the American Association of Petroleum Geologists Rocky Mountain Section Meeting, in Denver, Colorado, poster July 9-11, 2008.

Shale Gas Potential of the Paradox Basin, Colorado and Utah by Steven C. Schamel, GeoX Consulting, Inc., presented at the American Association of Petroleum Geologists Rocky Mountain Section Meeting, in Denver, Colorado, July 11, 2008.

“Shale” Gas – Some Views Concerning Geologic Controls on “Shale” Gas Production by S. Robert Bereskin, Bereskin and Associates, Inc., presented at the Utah Geological Association monthly meeting, Salt Lake City, Utah, February 9, 2009.

Publications Bereskin, S.R., and McLennan, J., 2008, Hydrocarbon potential of

Pennsylvanian black shale reservoirs, Paradox Basin, southeastern Utah: Utah Geological Survey Open-file Report 534, 53 p.

Hill, D.G., Curtis, J.B., and Lillis, P.G., 2008, Update on North America shale-gas exploration and development, in Hill, D.G., Lillis, P.G., and Curtis, J.B., editors, Gas shale in the Rocky Mountains and beyond: Rocky Mountain Association of Geologists Guidebook, p. 11-42.

Schamel, S.C., 2008, Potential shale gas resources in Utah, in Hill, D.G., Lillis, P.G., and Curtis, J.B., editors, Gas shale in the Rocky Mountains and beyond: Rocky Mountain Association of Geologists Guidebook, p. 119-161.

Trudgill, D., and Arbuckle, W.C., 2009, Reservoir characterization of the clastic cycle sequences in the Paradox Formation of the Hermosa Group, Paradox Basin, Utah: Utah Geological Survey Open-file Report 543, 145 p.

(n) Canada: by Jock McCracken (Petro-Canada)

Shale gas production in Canada is less than a year old after the initial announcements of new discoveries at the beginning of 2008. Therefore the state of development for the shale plays range from speculative to exploratory to emerging with only one being considered developing. In most cases the majority of wells are still confidential so production numbers are limited. Information gathered in this report comes from some provincial government reports and the key operators. NORTHEAST BRITISH COLUMBIA Devonian Muskwa Shale Horn River Basin, Cordova Embayment and the Liard Basin - The Devonian Shales are the targets in these basins. Depending on the locality these shales can be called Muskwa, Otter Park, Horn River, Klua/Evie, Besa River and Fort Simpson. The Mississippian Exshaw and Banff can potentially be a target. These Horn River shales, with approximately 1.5 million acres in the core area, has been receiving a lot of press lately that this play may exceed the Barnett, although the remote drilling location in N.E. B.C. increases the operating costs and hence decreases the economics. This area in N.E. British Columbia within the Cretaceous to Devonian shales have the potential capacity to hold 250 to 1,000 Tcf of gas in place. These Devonian shales have been estimated to hold 21 to 110 Tcf of marketable gas. This productive shale interval with up to 10% TOC is about 160 to 450 ft thick at a depth of 8,000 to 13,000 ft. Operators, with lessons from the Barnett, are going directly to horizontals with laterals of up to 5,000 ft and up to 16 stages of fracturing. IP’s are ranging from 5 to 10 MMcf/d

with highs as much as16 MMcf/d. Some operators are giving the gas in place numbers as 150 Bcf/section upward to 318 Bcf/section. In total about 125 wells will be drilled by the end of 2009, many from multi-well pads (16 wells) to reduce the footprint and environmental impact in this remote area of British Columbia. http://www.oilandgasinquirer.com/article.asp?article=magazine%2F081014%2FMAG2008_OE0001.html Building of construction camps, roads and pipelines (Spectra and TransCanada) are priorities. Pipeline capacity is being ramped up with increasing production from this area to be significant by 2012. http://www.spectraenergy.com/what_we_do/projects/#westcan , http://www.transcanada.com/news/2009_news/20090226.html Currently there are 15 rigs drilling in the area. The BC government is encouraging development by creative royalty structures, increasing subsidies to drill in this remote basin as well as upgrading the road system. http://www.empr.gov.bc.ca/MACR/EnergyAndMiningOpportunities/Documents/BC%20Y2E%202009.pdf Success in this play was first announced by EOG in February 2008 with Apache and partner Encana following in April 2008. The main players initially formed an eight company Horn River Basin Producers Group which included the following companies: Apache Canada Ltd., Devon Canada Corp., Encana, EOG Resources Canada, Imperial Oil Resources/ExxonMobil Canada, Nexen Inc, Quicksilver, and Stone Mountain Resources. More companies joined, recently adding ConocoPhillips, Pengrowth, Petro-Canada, PetroBank, Crew and Result Energy Inc. This group’s purpose is to facilitate cooperation and communication between major industry players, key stakeholders and First Nations in the area. They have also partnered up with Geoscience B.C. which is funded through the B.C. government with a 5.7 million dollar grant to conduct collaborative geoscience projects including a joint aquifer study of the area. http://www.geosciencebc.com/s/NewsReleases.asp?ReportID=343070&_Type=News&_Title=Collaborative-Horn-River-Basin-Aquifer-Study-Phase-1 Here are some of the most recent activities. The EnCana and Apache partnership now plan to drill 24 gross wells in 2009 rather than 40 initially scheduled. The number of well fractures along these long horizontal wells will be increased to about 14 from the original planned 8. They have three rigs drilling. They are hoping the well costs will come down to $8 million per well. Some of the wells have produced at an average of 5 MMcf/d. EOG plans to drill seven horizontals compared to six last year. They now

have six months of sustained production from several of their wells. Devon has drilled two horizontal wells so far this year. Quicksilver is currently drilling two horizontal wells which will be tested later this year. Nexen just completed and tied-in two wells drilled last summer and also drilled three wells earlier this year with plans to complete and tie-in these wells before year end. They expect to have six wells on production in 2009. There are a few other players in this area including SMR Oil and Gas, Paramount, Storm, Ramshorn and a few others. The B.C government closed out their fiscal year this March with announcements of record land bonus bids of $2.66 Billion of which 41% was attributed to the Horn River http://www.empr.gov.bc.ca/OG/oilandgas/petroleumgeology/UnconventionalOilAndGas/Pages/Shale.aspx The Liard Basin, northwest of the Horn River, has recently been evaluated by re-entering old wells by Questerre and Transeuro. This well is currently producing at 5 MMcf/d from a carbonate-rich sequence within the shale/siltstone Mississippian Mattson/Besa River at Beaver River. http://www.questerre.com/assets/files/090430_QEC_Presentation.pdf The Cordova Embayment, to the east of the Horn River, had a large land sale bonus of $44 million the year before in 2007. Virtually most of the prospective land was leased with little leasing activity this year, perhaps because of no drilling announcements. Triassic Montney Dawson Creek Area, Northeast British Columbia The Montney is another hot play in N.E. B.C, covering about 2.5 million acres, that is gaining a lot of attention. The reservoir intervals are the Upper and Lower Montney, Doig and Doig Phosphate. This interval is a thick (up to 500 m) mixture of organic-rich phosphatic shales, siltstones and tight sands within the gas window. The depths range from 1,312 to 14,400 ft. Very large gas-in-place numbers have been quoted, up to 400 Tcf OGIP. As of February 2009, there were 320 wells producing 340 MMcf/d from the Montney. Cumulative gas production to that date was 195 Bcf, 150Bcf of which was produced in the last 3 years. The Upper Montney has seen exceptional growth from 4 producing areas including Swan, Dawson, Saturn and Monias. The dominate players are Arc Energy Trust, Encana, Murphy, Storm, Duvernay which was acquired by Shell, Talisman with Canadian Spirit,

Crew, Galleon, Birtchcliff, Penn West, Crescent Point, and Devon amongst the many others. Some operator highlights are as follows: Encana drilled a total of 15.5 net horizontal wells in the first quarter. The 30 day initial production rates in each well averaging more than 4 MMcf/d or 0.5 MMcf/d on a fracture interval basis. Talisman plans to drill 49 wells during the year. They have seen horizontal wells flowing around 4 MMcf/d on extended tests. Within their large acreage base they have about 450 well locations picked. ARC Energy Trust has quoted 30 day IP rates of close to 9 MMcf/d. There has been some activity in this play to the east in Alberta. The B.C government closed out their fiscal year this March with announcements of record land bonus bids of $2.66 Billion of which 49% was attributed to the Montney play. British Columbia Government Shale Information The Government of British Columbia, Ministry of Mines, Minerals and Petroleum website is a good source for industry updates, activity maps and reports on the Devonian, Triassic and Cretaceous shales. http://www.empr.gov.bc.ca/OG/oilandgas/petroleumgeology/UnconventionalOilAndGas/Pages/Shale.aspx ALBERTA Cretaceous Colorado Group Eastern Alberta There is limited shale gas activity and production reported in Alberta even though potentially large resources exist within various formations. Stealth Ventures announced their shale-gas project in the Wildmere region of eastern Alberta as commercial within the Colorado Group which is a mixture of biogenic gas-charged shales with silts and sand laminae. A typical well will IP at over 150 Mcf/d and reduce to 40 Mcf/d after 1.5 years. They drilled 81 wells last year and increased average shale gas production to 1.54 MMcf/d, a 233% increase compared to 2007. Current production is 2.4 MMcf/d. Other operators are also targeting this section. The Alberta ERCB is not reporting any shale gas reserves at this time. There were 32 shale gas reported wells in 2007 increasing to 100 in 2008. Muskwa Shales Western Alberta Mooncor (http://www.mooncor.com/) is exploring for an Alberta S.E. extension of the Muskwa play of the Horn River Basin in N.E. B.C. They have re-entered a well and tested about one MMcf/d from a thinner 12-25 metre thick shale. They plan to test this with a horizontal next.

The Alberta Geological Survey has made these reports available with the Montney and Duvernay/Muskwa being available later in the year. Rokosh, C.D., J.G. Pawlowicz, H. Berhane, S.D.A. Anderson and A.P.

Beaton, 2009, Geochemical and sedimentological investigation of the Banff and Exshaw Formations for shale gas potential: initial results: Energy Resources Conservation Board, Alberta Geological Survey.

Rokosh, C.D., J.G. Pawlowicz, H. Berhane, S.D.A. Anderson and A.P. Beaton, 2009, Geochemical and sedimentological investigation of the Colorado Group for shale gas potential: Initial results: Energy Resources Conservation Board, Alberta Geological Survey, http://www.ags.gov.ab.ca/publications/newreports.html

SASKATCHEWAN Cretaceous Colorado Group Central Saskatchewan In the past four years, more than 50 test wells have been drilled for shale gas in all areas in the province, including Watrous, Moose Jaw, Strasbourg, Foam Lake, Smeaton, Shell Lake and Big River but no commercial discoveries have been announced. http://www2.canada.com/reginaleaderpost/news/business_agriculture/story.html?id=c41a6b5b-b892-40cc-8cb4-902156681111&k=18412 PanTerra Resource Corp. and other companies continue shale gas exploration in Saskatchewan. Thirty-six wells have been drilled and cased to date by PanTerra within their more than one million acres of land. They have been coring, logging and fracture stimulating but no rates have been announced to date. http://www.panterraresource.com/ Mooncor (http://www.mooncor.com/) also has interests in 7,200 net acres of a Colorado shale gas ct at White Hill Lakes, Saskatchewan. There has also been some activity in the Pasquia Hillsin central east Saskatchewan. There have been about 23 wells drilled by various operators with gas shows and some limited gas tests. MANITOBA Cretaceous Colorado Group There is the potential of shale gas in Manitoba, but no activity. Nicholas and Bamburak, 2009. http://www.geoconvention.org/2009abstracts/014.pdf ONTARIO Upper Devonian Kettle Point Shale (Antrim Shale Equivalent) Middle Devonian Marcellus Shale

Upper Ordovician Blue Mountain and Collingwood Shale (Utica Equivalent) These above shales have been described by Hamblin (2006) and Carter et al (2008). http://www.ogsrlibrary.com/news?article=shale-gas-in-ontario Exploitation of these shales has been very quiet with only a few operators discussing the evaluation of these shale targets. These shales are mostly considered secondary targets but no wells have been drilled to test these zones to date. Mooncor (http://www.mooncor.com/) are in southwestern Ontario targeting the Kettle Point Formation (Antrim style shale gas zones) and the Collingwood/Blue Mountain Formation (Utica shale gas zones). Plans to drill the first well of a potential 5 well program through the Kettle Point Formation to test an identified Silurian Pinnacle Reef in Lambton County is planned for late Q3 or Q4. Greentree recently announced that sidewall coring of the Blue Mountain shale has taken place. http://www.greentreegas.on.ca/news/greentree_july_23_2008.pdf QUEBEC – ST. LAWRENCE LOWLANDS Ordovician Lorraine and Utica Shale The other bright light in Canadian shale exploration in 2008 was in Quebec within a 300 km by 100 km fairway between Montreal and Quebec. Both Forest Oil Corporation and their partners and Talisman and their partners have drilled about 11 wells to evaluate both the Lorraine, up to 6,500 ft thick and the Utica, 300 to 1000 ft thick. Forest Oil (http://www.forestoil.com/) announced on April 1, 2008 a significant gas discovery in the Ordovician Utica Shale in Quebec. Two vertical wells were drilled and production rates of up to 1 MMcf/d. They are estimating a 4.1 Tcf resource potential at 20% recovery. These black shales of 1 to 3% TOC are 500 ft thick within the gas window. They followed this up with three horizontals. Rates ranged from 100 to 800 Mcf/d with 4 stage fracs. They plan to go back into the wells and recomplete different zones. Talisman has drilled 6 vertical wells into this play with rates ranging from 300 Mcf/d to almost 1 MMcf/d. They are evaluating the rocks and then will proceed with up to 10 horizontal wells. Canbriam, Gastem, Junex, Questerre and Altai are among the other interest holders in this play. Quebec’s natural gas royalty, which currently is12.5%, has been described as attractive by some of the players. As well, shale gas plays in the province’s St. Lawrence Lowlands enjoy another advantage in being close to the northeast U.S. gas market. NEW BRUNSWICK Lower Mississippian Fredrick Brook Shale Moncton Basin

Corridor Resources (http://www.corridor.ca/investors/documents/AGMCALGARYMAY142009.pdf) has drilled a vertical well with an encouraging 1,000 m of fractured Lower Mississippian Frederick Brook Shale with natural gas shows. They have plans to frac and test this zone this summer. NOVA SCOTIA Upper Devonian/Lower Mississippian Horton Bluff Kennetcook Basin Triangle Petroleum (http://www.trianglepetroleum.com/) acquired significant seismic on the project and drilled five vertical wells. The shale interval in one of the wells is about 1,000 m thick at 3,000 m deep. So far, rates have been small but an upcoming fracture and testing program is being designed. On April 16, 2009, Triangle executed a 10-year production lease on its Windsor Block in Nova Scotia which covers 474,625 gross acres (270,000 net acres). They have agreed to drill at least 7 more wells in this block before 2014. NEWFOUNDLAND Ordovician Green Point Shale Western Newfoundland Shoal Point Energy (http://www.shoalpointenergy.com/) and its partners encountered about 500 m with varying gas readings through the Ordovician Green Point formation west of Stephanville, Newfoundland. This shale has been studied in outcrop by the Canadian Geological Survey and is summarized in Hamblin (2006). The companies are pursuing further testing of the concept. Canadian Society for Unconventional Gas http://www.csug.ca/index.html Key References and Information on Canadian Shales: Carter, T., L. Fortner, and J. Clark, 2008, Ontario Petroleum

Institute/IOGA New York, 2008, Joint Annual Meeting, Niagara Falls, ON

Faraj, B., H. Williams, G. Addison, B. McKinstry, R. Donaleshen, G. Sloan, J. Lee, T. Anderson, R. Leal, C. Anderson, C. Lafleur, and J. Ahlstrom, 2002, Gas shale potential of selected Upper Cretaceous, Jurassic, Triassic and Devonian shale formations in the WCSB of western Canada: implications for shale gas production: Des Plaines, Illinois, Gas Technology Institute, GRI-02/0233, compact disc, 285 p.

Faraj, B., H. Williams, G. Addison, and B. McKinstry, 2004, Gas potential of selected shale formations in the western Canadian sedimentary basin: GasTIPS, v. 10, no. 1, p. 21-25.

Hamblin, A.P., 2006, The “shale gas” concept in Canada: a preliminary inventory of possibilities: Geological Survey of Canada, Open File 5384, 108 p.

Nicolas, M.P.B. and J.D. Bamburak, 2009, Shallow unconventional Cretaceous shale gas in southwestern Manitoba: CSPG, CSEG, CWLS Convention, Calgary

Ross, D., G. Chalmers, and R.M. Bustin, 2005, Reservoir characteristics of potential gas shales in the western Canadian sedimentary basin, in P. Lufholm and D. Cox, eds., 2005 WTGS Fall Symposium: West Texas Geological Society, Publication No. 05-115, p. 41.

Ross, D.J.K., and R.M. Bustin, 2007, Shale gas potential of the Lower Jurassic Gordondale member, northeastern British Columbia, Canada: Bulletin of Canadian Petroleum Geology, v. 55, p. 51-75.

Ross, D.J.K., and R.M. Bustin, 2008, Characterizing the shale gas resource potential of Devonian-Mississippian strata in the western Canada sedimentary basin: Application of an integrated formation evaluation: AAPG Bulletin, v. 92, p. 87-125.

2. Gas Shale research and sources of funding. Gas shale research is being

conducted by private industry, consortia, and government. (1) Private Industry (e.g., Devon Energy): not for public distribution. (2) Consortia:

(a) Core Lab “Reservoir characterization and production properties of gas shales” (http://www.corelab.com/rm/irs/studies/GasShales_Global.aspx);

“Haynesville and Bossier Shale Evaluation” (http://www.corelab.com/rm/irs/studies/Haynesville-Bossier.aspx);

(c) Colorado School of Mines FAST (Fracturing, Acidizing, Stimulation Technology) Consortium Project 9: stimulation of “shale” reservoirs (http://www.mines.edu/fast/).

(d) Humble Geochemical Services (http://www.humble-inc.com/) Geochemical Data and Gas Shale Studies “Shale Gas: Source Rocks as Reservoirs” report http://www.humble-inc.com/shgas.html “Ft. Worth Basin Geochemical Database and Report” “Rocky Mountain Shale Gas Evaluation Project” “Delaware Basin Shale Gas Study” http://www.humble-inc.com/2005%20Shale%20Gas%20Study%20Culberson%20County%20and%20Permian%20Basin.pdf

(e) GeoMark Research Appalachian Basin Shale Gas Study (2005) (http://www.geomarkresearch.com/studies_northamerica.cfm)

(f) Baseline Resolution

Black Warrior Basin Study (http://www.baselinedgsi.com/contents/black_warrior_basin.htm)

(g) GASH (Gas Shales in Europe) (http://www.gfz-potsdam.de/portal/-;jsessionid=7BA522526C3C6B6F7C57E0E6A3579326?$part=binary-content&id=2022464&status=300&language=en)

(h) CSIRO Shale Research Centre (http://www.csiro.au/science/shaleResearchCentre.html)

(3) Government (a) RPSEA (Research Partnership to Secure Energy for America) http://www.rpsea.org/ List of Projects Selected for the Unconventional Resources Program (April 2009) http://www.rpsea.org/en/art/164/ RPSEA Upcoming Forums http://www.rpsea.org/en/cms/?1462 (b) USGS. The U.S. Geological Survey is updating the National Assessment of Oil and Gas Resources, including shale gas in the Arkoma Basin, Oklahoma. http://energy.cr.usgs.gov/oilgas/noga/ http://certmapper.cr.usgs.gov/data/noga95/natl/text/summary.pdf Michigan Basin assessment http://pubs.usgs.gov/fs/2005/3070/2005-3070.pdf Bend Arch/Fort Worth Basin assessment http://pubs.usgs.gov/fs/2004/3022/fs-2004-3022.pdf The USGS Eastern Energy Resources Team has initiated a project that pertains to the organic geochemistry of the Devonian shale formations in the Appalachian Basin. The project is being conducted in cooperation with the State geological surveys of Virginia, Kentucky, Ohio, West Virginia, and Pennsylvania. The State geological surveys are collecting samples of Devonian shale, which they ship to the USGS for analyses. The analyses are, for the most part, being conducted by a commercial laboratory. Newly obtained data will eventually be integrated with previously published analyses to prepare a regional summary of Devonian shale geochemistry.

3. What EMD technical session, publications, workshops, etc. exist or are planned that are relevant to this commodity? 2009 AAPG Annual Convention: Theme IX Unconventional Reservoirs: Gas Shales Reservoirs — Updates and New Insights http://www.aapg.org/denver/ataglance.cfm

4. Sources of Information

(a) References (see gas shale bibliography on Gas Shale Committee web site (http://emd.aapg.org/members_only/gas_shales/gasshalereferences.pdf)

(b) Trade Journals (articles included in bibliography above)

(1) Powell Barnett Shale Newsletter (http://www.barnettshalenews.com/)

(2) American Oil and Gas Reporter (3) Oil and Gas Investor (4) Oil and Gas Journal (5) Hart’s E & P (6) AAPG Explorer (c) Subscription Services

(1) Hart Unconventional Natural Gas Report (http://www.ugcenter.com/; http://www.ugcenter.com/Newsletters/)

(2) IHS Energy (http://energy.ihs.com/) (3) Warlick International Report (http://www.warlick.net/)

5. Calendar

June 4: Mid-Continent Gas Shales Forum/RPSEA Member Meeting, Rosemont, IL http://www.rpsea.org/en/cev/186

June 4-5: The Canadian Institute’s 12th Annual BC Natural Gas Symposium, Calgary, Alberta, Canada http://www.canadianinstitute.com/BCNG.htm

June 5-6, 2009: Platts Shale Gas Developer, Houston, TX. http://www.platts.com/Events/PC623/

June 7-9, 2009: AAPG Annual Convention: Unconventional Reservoirs, Denver, CO. http://www.aapg.org/denver/technicalprogram/sessions.cfm (note: there is an AAPG sponsored multi-disciplinary short course on unconventional shale resource plays scheduled on June 10-11, 2009 in Denver also).

July 23: Shale Gas: New Developments, AAPG Webinar. September 20-22: Shale Resources of the Eastern United States and

Canada, AAPG Eastern Section Meeting, Evansville, IN. http://www.esaapg2009.org/

October 11-13, 2009: sessions on Woodford Formation and Shale & Coalbed Reservoirs in the Mid-Continent, AAPG Mid-Continent Section Meeting, Tulsa, OK. http://www.2009aapgmidcon.com/

November 18-20, 2009: 11th Annual Unconventional Gas Conference, Canadian Society for Unconventional Gas (CSUG), Calgary, Alberta, Canada. http://www.csug.ca/

6. Committee Members (in alphabetical order)

Bill Ambrose, Lee Avary, Kent Bowker, Charles Boyer, Dwight Brown, Marc Bustin, Brian Cardott, John Curtis, Bradley Dean, Wally Dow, Lisa Hunt, Dan Jarvie, Chris Johnson, Doug Kenaley, Jean Kulla, Charlie Landis, Jeff Levine, Peter Lufholm, Jock McCracken, Bob Milici, Mike Party, Doug Patchen, Jeremy Platt, Rick Richardson, Steve Ruhl, Steven Schamel, Loren Schmidt, John Sherborne, Dave Tabet, Bob Timmer, Frank Walles, Peter Warwick, Mark Whitney, Charles Wickstrom