Shale_Gas_LNG_areas

Study analyzes US, shale gas plays

A recent study has estimated that US shale-gas plays may produce as much as 24 bcfd by 2018.

US gas production Unconventional to soon dominate
Source: http://www.platts.com 17-11-08
Higher gas prices and significant technological advances have led to a dramatic increase in production of unconventional gas resources in recent years, and that trend is expected to continue unabated, according to a study to be released in the US.
By 2020, 69 % of US gas production and 43 % of Canadian gas will come from unconventional plays, said the report prepared by energy consultant ICF International.

To support the production forecast, roughly 300,000 unconventional wells will have to be drilled, representing an outlay of $ 560 bn for unconventional gas drilling and related capital costs.
Previewing the report to the INGAA Foundation, or Interstate Natural Gas Association of America Foundation, at its annual meeting in Palm Coast, Florida, ICF analyst Harry Vidas pronounced it "good news for customers and policy makers," asserting that the findings "show how well the natural gas industry in the US and Canada has done in recent years stemming the decline" of conventional gas production.

The outlook is "very optimistic," he continued. And with the tremendous gains in production from tight gas, coalbed methane and, most significantly, shale gas, this energy supply "is poised to be a very important part of North America's energy future."
IFC noted that research and investment into unconventional gas has increased significantly in recent years due to the higher price environment. In many cases, the technologies for economic production had already been developed, while in other cases resources were still in the research stages.

Unconventional gas had been a significant component of US production for many years, but "its contribution has grown rapidly in recent years," the report said, pointing to notable growth in production from tight gas reservoirs in the Rockies and East Texas, coalbed methane in Wyoming and New Mexico, and shale gas in North Texas and the Mid-Continent.
While tight gas figures to remain the dominant category of unconventional gas through the study period of 2007-2020, the "most significant" trend, said ICF, is the "rapid rise" of gas production from shale formations.
"It appears certain that shale gas production will expand in coming decades, and production will emerge in new regions in the US and Canada."

ICF is forecasting growth in overall North American gas production from last year's 25 tcf to 29 tcf by 2020. That gain will be "driven by onshore unconventional gas," which is expected to grow from 42 % of total production in 2007 to 64 % in 2020 and 72 % in 2030, Vidas told the INGAA Foundation audience.
Total gas resources in North America exceed 2,300 tcf, said the report, adding that shale gas accounts for roughly 500 tcf of recoverable resources within that total. For the Lower-48 states, IFC put tight gas at 174 tcf, coalbed methane at 65 tcf and shale gas at 385 tcf. The consultant sees production from gas shales in the US growing from 1.4 tcf last year to 4.8 tcf in 2020, and tight gas production jumping from 5.8 tcf to 9.2 tcf over the same span.

ICF said its forecast "may prove to be conservative, especially for gas shales." It noted that the size of the recoverable resource base "is large enough to support higher levels of annual production over the long term if such production is demanded by the market." What's more, "it is likely that our forecast of Western Canada is conservative, given the limited available information on shale plays in British Columbia."
Also, several emerging shale plays, such as those in the Southeast US and Rockies, are not included in the report due to scarce data.

The financial crisis and the recent decline in oil and gas prices may stunt drilling programs, and some producers already have announced significant cutbacks.
"However, the longer-term need for energy in the US and Canada should be strong enough to support the future levels of gas production presented here, albeit on a possibly slower pace," said ICF.

The report also cautioned that environmental and regulatory issues may dampen unconventional gas production efforts.
"These include well and environmental permitting and related costs, land access, water use and disposal and surface disturbance."
Water use and disposal for fracturing of shale wells has already emerged as a significant issue, ICF observed, "although, to date, water use has not significantly restricted development in most shale areas."

Pioneer Eagle Ford shale gas production averaging 85 MMcfd
OGJ.com 12/27/08
Pioneer Natural Resources Inc., Dallas, is drilling the horizontal leg in Cretaceous Eagle Ford shale in an exploratory well in DeWitt County, Tex. This is about 90 miles east-northeast of where Petrohawk Energy Corp., Houston, gauged an Eagle Ford gas-condensate discovery in LaSalle County (OGJ Online, Oct. 21, 2008).
Petrohawk is completing its second well in LaSalle and is drilling in McMullen County, Pioneer said.
Pioneer has logs through Eagle Ford from the more than 150 wells it has drilled in the Cretaceous Edwards Trend along its 310,000-acre spread from LaSalle to Lavaca counties and chose to horizontally drill the Eagle Ford where it saw the best porosity Permeability is the question, the company said Dec. 2.
Eagle Ford shale is the source rock for the Cretaceous Austin chalk and Edwards formations, Pioneer noted.
Meanwhile, the company’s Edwards gas production is averaging 85 MMcfd.

Northeast US Millennium pipeline First Delivery 182-Mi.
Millennium Pipeline 12/22/2008

Millennium Pipeline Company, L.L.C. announced that its recently constructed 182-mile natural gas pipeline was placed into complete service today and deliveries of natural gas supplies to its anchor shippers have commenced.

"This is an historic day for New York State and the Northeast," said Millennium President Dick Leehr. "Many years of hard work and planning, permitting and eventual construction have finally come to fruition, enabling Millennium to deliver much-needed natural gas supplies as we enter the peak of the 2008-09 winter heating season. But the real winners are the energy users of today and tomorrow, who now have a reliable new natural gas pipeline system that will meet their growing need for clean-burning natural gas for years to come."

"It is gratifying to see that a major collaborative effort involving skilled union workers from local communities and around the country, government officials at all levels, customers, partners, contractors, vendors and many other organizations came together to achieve this common important goal of meeting the region's growing energy needs," Leehr added.

Millennium Pipeline began construction activities in 2007; however, the majority of the 30-inch-diameter mainline pipeline installation work across New York's Southern Tier and lower Hudson Valley was completed this year. Some land restoration and environmental monitoring work will extend into 2009 and beyond. More than 2,000 workers -- many hired from local communities -- were involved in construction of the pipeline.

More than 90 percent of the Millennium pipeline was installed within or adjacent to existing pipeline rights-of-way. Millennium is the centerpiece of a $1 billion investment in new energy infrastructure that includes new facilities by Empire Pipeline, Algonquin Gas Transmission and the Iroquois Gas Transmission systems.

Millennium Pipeline is anchored by its customers National Grid, Consolidated Edison of New York, Central Hudson Gas and Electric Corporation and Columbia Gas Transmission Corporation. Millennium will serve markets along its route in the Southern Tier and lower Hudson Valley as well as providing essential service to the New York City markets through its pipeline interconnections. Millennium's design will allow it to transport up to 525,400 dekatherms per day, based on market needs. Millennium is jointly owned by affiliates of NiSource Inc., National Grid and DTE Energy.

Williams Completes 1st Phase Pennsylvania New Jersey pipeline
Williams 12/22/2008
Williams has placed the first phase of its Sentinel expansion project on its Transco natural gas pipeline system into service, increasing firm transportation capacity into the northeastern U.S. by 40,000 dekatherms per day.

The Sentinel expansion project is being constructed in two phases. Phase 2 of the expansion will provide an additional 102,000 dekatherms per day and is expected to be placed into service by November 2009. The entire Sentinel expansion project is designed to increase Transco's firm transportation capacity by 142,000 dekatherms per day.

"This is a major milestone and we sincerely appreciate our customers' commitment to this project," said Phil Wright, president of Williams' natural gas pipeline business. "We look forward to placing the remaining portion of this much needed project into service and working with our customers to provide reliable natural gas service for the northeastern United States for years to come."

Phase 1 construction has included the addition of approximately four miles of 42-inch pipe in Northampton and Monroe counties, Pa., in addition to compressor station upgrades at Transco Station 195 in Delta, Pa. Phase 2 will include the addition or replacement of 14 miles of pipeline at various locations in Pennsylvania and New Jersey.

Colorado East -- Nighthawk Energy Shale O/G production
Jolly Ranch Operational Update
The directors of Nighthawk Energy plc (“Nighthawk” or “the Company”) (AIM: HAWK), the US focused hydrocarbon production and development company, are pleased to announce an operational update in respect of the Jolly Ranch Group project, located in Elbert, Lincoln and Washington Counties, Colorado. Nighthawk holds a 50% interest in the project and the operator, Running Foxes Petroleum Inc. (“Running Foxes”), holds the remaining interest.
Highlights
Jolly 10-5 well encounters hydrocarbons in multiple formations and is cased for production. Ten commercial wells drilled at Jolly Ranch – 100% success rate
Craig 15-32 well on three week production test from the Tebo shale bed of the Cherokee formation presently producing 110 to 120 barrels of oil per day
Four well drilling programme to test the prolific Codell and J Sand formations commencing
The Jolly Ranch Group project is a major hydrocarbon production and development venture which includes Jolly Ranch, currently the core area, Middle Mist and Mustang Creek, to the north and west of Jolly Ranch respectively. The current project area comprises 370,578 gross acres (281,069 acres on a net basis).
Drilling results to date have established Jolly Ranch as a significant new oil and natural gas field, particularly in the Atoka and Cherokee shales. These shales are laterally extensive and are believed to be continuous over the entire project area. In addition, several oil bearing conventional zones have been penetrated during drilling, including the Marmaton, Morrow, Spergen, St Louis and Codell formations.

Jolly 10-5 well
The Jolly 10-5 well, the tenth of the drilling programme, has reached Target Depth and encountered several hydrocarbon-bearing formations, both conventional and unconventional. The well has been cased for production and will be put on production in January 2009.

Craig 15-32 well
The Craig 15-32 well commenced production at the start of December from a four foot Tebo shale, a component of the Cherokee shales, the first test applied to this formation on the project. The oil is 38 API gravity, low paraffin sweet crude and has a -10 degree pour point and no sulphur. The well commenced production at 50 to 60 bbls of oil per day and has increased to 110 to 120 bbls of oil per day with less than 10% water.
As a result of this positive result from the Cherokee formation, two previously drilled wells, the Craig 8-1 and Craig 4-4, have been completed in the Tebo shale, are making oil and are presently being swab tested. The wells will then be completed in the V and Excello shales also within the Cherokee formation during the last two weeks of December and then placed on full production in January 2009.
The Cherokee formation comprises four shales varying from three to six feet thick for a net thickness of 15 to 22 feet. These shales contain 40% to 80% quartz and carbonates, which, based on detailed analysis, are heavily fractured and saturated with hydrocarbons. The Tebo B, Tebo, V and Excello shales all have the same reservoir features. In addition, Omnilabs, a division of Weatherford International, has indicated in detailed reports, that both the Atoka and Cherokee shales in the project area are generating and expelling hydrocarbons and showing characteristics typical of a successful shale play.

Codell and J Sand drilling programme
Black Gold Inc., a local drilling company, is commencing a four well drilling programme to test the shallower Codell and J Sand formations, both prolific producing zones in the region. Three wells, the Jolly 9C-1, Jolly 16C-1 and Jolly 7-1 will test the Codell formation and the Fischer 14-20 will test the J Sand formation in the Middle Mist Project.
These formations are of Cretaceous age and are located at depths of between 3,000 and 4,000 feet. The J Sand is a prolific producer in the central part of the Denver Basin.
David Racher B.Sc (Hons) Geology, who is a consultant to Nighthawk and has over 37 years of experience in the hydrocarbons industry and previously managed the Lasmo plc onshore US portfolio in Kansas, Louisiana, South Dakota, Texas and Wyoming, has approved the technical information contained in this announcement.

CNX Gas Marcellus Record rate -- 6.5 MMcf
CNX Gas Corp. 12/15/2008
CNX Gas Corporation reported that its first horizontal Marcellus Shale well is now producing at a rate of 6.5 million cubic feet (MMcf) per day. This is a record daily production rate for any well in the company's history and is believed to be among the highest reported by any Marcellus Shale producer.

The well, located in Greene County, Pa., began flowing into the sales meter on October 2, with an initial production rate of 1.2 MMcf per day and 4,000 pounds of backpressure, as previously reported. The backpressure on the well had been gradually reduced since then, allowing daily production to increase to about 4 MMcf per day until Friday, when the installation of new surface equipment enabled the well to flow at the 6.5 MMcf per day rate, with pressure still being held at 2,640 pounds. Cumulative production from the well prior to last Friday was 106 MMcf.

Nicholas J. DeIuliis, president and chief executive officer, said, "This was a team effort from our engineers, operators, and support personnel, including the directional drillers from Scientific Drilling and the hydraulic fracturing team from BJ Services. I can't speak highly enough of our Marcellus Shale team.

"To achieve this kind of success with our first horizontal Marcellus Shale well," DeIuliis continued, "speaks volumes about the breadth of our horizontal drilling expertise. Many investors may not be aware, but CNX Gas had drilled 160 horizontal coalbed methane wells before drilling its first horizontal Marcellus Shale well."

The well was drilled to a vertical depth of 8,140 feet in the Huntersville Chert, penetrating 83 vertical feet of Marcellus Shale. The well was logged then plugged back and a horizontal section of 3,395 feet was cut for a total measured depth of 10,738 feet. The well was completed with a five-stage slickwater fracture treatment using 3 million pounds of proppant.

CNX Gas has a 100% working interest in the well and a 100% net revenue interest because CNX Gas does not pay a royalty. Because of the gathering infrastructure already in place from its CBM operations, CNX Gas was able to place the well online immediately after retrieving frac fluids. Also, gas from production in southwestern Pennsylvania, as in other areas of Appalachia, typically receives a premium over NYMEX pricing.

CNX Gas is currently drilling its second vertical Marcellus Shale well and will be shortly hydraulically fracturing its second and third horizontal wells. Updates on these wells will be provided during the company's next earnings conference call, now scheduled for January 28, 2009.

CNX Gas is also raising its 2008 production guidance to 75 billion cubic feet (Bcf) from 74 Bcf. The current guidance represents the third time guidance has been raised from the original guidance of 72 Bcf. If the 75 Bcf is attained, it would represent a nearly 29% increase from the 58.2 Bcf produced in 2007. The company attributes the increased guidance to exploration success in both the Marcellus and Chattanooga shales, as well as continued higher-than-expected coalbed methane production.

Baxter shale Wyoming Cretaceous 2.19 MMcfd
Oil & Gas Journal / Dec. 8, 2008

Devon Energy Corp. started production at the 5-3 Horseshoe Basin Unit well in the Vermillion Creek area of the Greater Green River basin in Sweetwater County, Wyo. Output from Cretaceous Baxter shale totaled 21.7 MMcf gas and 3,836 bbl of condensate in the first 6.5 days on line, and the current rate is 2.19 MMcfd and 412 b/d of condensate, said 50% working interest owner Kodiak Oil & Gas Corp., Denver. TD is 13,534 ft. Three wells have been drilled, and Devon is acquiring 25 sq miles of 3D seismic in the area. The outlook for 2009 is for horizontal drilling in the Baxter, said Kodiak.

Jurassic Haynesville/Bossier shale Texas East
December 8, OGJ.com
GMX Resources Inc., Oklahoma City, said its Callison-9H well in Harrison County, Tex., stabilized at 7.7 MMcfd of gas on a 22/64-in. choke with 5,200 psi flowing casing pressure from Jurassic Haynesville/Bossier shale. The company ran an eight-stage frac in the well’s 2,200-ft lateral, its shortest planned lateral in the play. GMX has 100% working interest.
GMX is drilling the Bosh-1l H and Baldwin-I7 H wells and expects to spud a fourth well within 2 weeks. The next 16 wells are expected to average 3,800-ft laterals and 11-12 frac stages. The company plans to drill 45 wells in 2009.

The Belin-1 well in the Hilltop area of the deep Bossier play has the potential to be Gastar Exploration Ltd.’s best well to date in terms of flow rate and reserves, the company said. Logs indicated 150 net ft of pay in the middle and lower Bossier formations. TD is 18,800 ft.
The well’s three Lower Bossier pay zones have the highest measured porosity, up to 25%, of any well drilled by Gastar in the play.
Belin- also encountered two middle Bossier sands, including the Lanier sand, in a downdip location in a new fault block with indicated pay based on log analysis. The well, to be on line within 30 days, is to be completed in the two deepest zones first.
The Lanier sand has been shown to be productive in a downthrown fault block from the Wildman Trust-3 well, where Lanier was recently recompleted at an initial 21 MMcfd.

Marcellus shale Pennsylvania 30 MMcfd -7 wells
December 8, OGJ.com
Range Resources Corp., Fort Worth, said seven wells totaling 30 MMcfd from the Marcellus shale are connected to Pennsylvania’s first large-scale gas processing plant, operated by MarkWest Energy Partners LP. Range plans to begin flowing more wells as two more gas processing plants are completed next year (OGJ Online, Oct. 22, 2008). The company plans to enter 2009 with three horizontal rigs and boost that to six by the end of the year. It expects yearend 2009 production to reach anet 80-100 MMcfed.

Talisman Energy Inc., Calgary, deferred a five-well Marcellus shale pilot in New York pending environmental and regulatory reviews and shifted its focus to Pennsylvania. The company’s Fortuna Energy Inc. unit holds almost 120,000 acres of state controlled land in north-central Pennsylvania and is drilling a pilot in an area where it owns 19,200 net acres prospective for development. It was completing its first operated horizontal well this month. Talisman Energy’s holding totals 640,000 net acres in both states in the emerging overpressured Marcellus play. It estimates gas in place in the Marcellus at 20-100 bcf/sq mile at 2,500-6,000 ft.

Marcellus Shale could hold 1,100 tcf
Source: http://www.platts.com 29-10-08
The gas potential of the Marcellus Shale may be as high as 1,100 tcf, well above the 50 tcf previously forecast, the US's top academic authority on the play said. "There's something really big in the Marcellus," Pennsylvania State University professor Terry Engelder told an audience of oil and gas executives at Platts' Appalachian Gas conference in Pittsburgh. "The Marcellus is much bigger than the Barnett," Engelder said, adding that he based his projection on early reports from Range Resources and Chesapeake Energy's initial wells in the play. Engelder earlier estimated that the shale contained about 50 tcf of recoverable gas.

While he called Chesapeake's numbers "mildly optimistic," Engelder said Range's numbers buttress his new forecast of more than 1 tcf of recoverable gas from the shale play which extends from New York south through Pennsylvania and into West Virginia. "It's bigger than the Barnett, Fayetteville, and Woodford shales combined," he said. Getting that gas to market is another problem, Engelder said. "The cost of land is going to scale to the price of gas," he said.

Already, Pennsylvania landowners are reporting lower priced leasing deals from exploration and production companies as the price of gas has fallen nearly by half since June. Overlapping regulatory agencies present a further problem for E&P companies, Tudor Pickering Holt Managing Director David Pursell said. "There are guys who aren't entering this play because of regulation," he said.

The biggest regulatory uncertainty is the Susquehanna River Basin Commission, a federal agency that controls water use in much of eastern Pennsylvania, Pursell said. The commission only meets quarterly, and Pursell said that isn't often enough to keep pace with the gas rush that's occurring in the state. "Ultimately, the Marcellus will be developed, the economics are just too large to ignore," Pursell said.

He said the cost to buy that gas in the ground was about $ 4/mm cf and with the forward strip calling for gas at $ 10/mm cf, the profit potential of the Marcellus is just too large for E&P companies to ignore.
"The Marcellus has all the economies of shale plays," he added. "Easy to find, hard to produce." He said Tudor Pickering Holt is forecasting 2.6 bn cfpd of production from the play by 2023.

Marcellus Cabot Pennsylvania, 13 MMcf/d
Cabot Oil & Gas Corp. 12/8/2008

Cabot has announced that its Marcellus initiative in northeastern Pennsylvania is gaining momentum and is currently producing over 13 Mmcfe per day. Most recently, Cabot completed its first Marcellus horizontal well with a measured depth of 8,925' and a horizontal leg at 2,000' using a six-stage frac. The result was a 24-hour average initial production rate of 6.4 Mmcf per day.

"Adding this to our series of vertical wells, which have been turned in line over the last five months and have a 30-day average IP of 750 Mcf per day, has allowed Cabot to exceed our original year-end Marcellus production target of six to nine Mmcf per day," said Dan O. Dinges, Chairman, President and Chief Executive Officer. "We expect this to increase considerably over the next few weeks as we have nine additional wells (six vertical and three horizontal) ready to be completed or in the final stages of pipeline hookup."

To date, the Company has drilled 18 total wells in the field, four of these as horizontal tests. Five rigs are currently working with plans to increase to eight rigs in 2009. "Our 2008 program will be 16 vertical wells plus seven horizontal wells," added Dinges. Cabot has four vertical wells and three horizontal wells remaining to be drilled this year and will continue operations seamlessly into 2009. Total well costs range between $1.3 million to $1.5 million for a typical vertical well and $2.6 million to $2.9 million for a horizontal well. The average depth of a vertical well is 7,200'; the average horizontal leg is approximately 2,200'.

In terms of infrastructure, the Company has completed its first phase pipeline build-out totaling 10 miles and has started up its first compressor with a second unit on site and ready to be utilized once production volumes justify the need. "We continue to actively secure rights of way and gain permits to expand our pipeline infrastructure for our 2009 drilling program," commented Dinges.

Other News
In other news, Cabot completed its first horizontal Berea well in southern West Virginia. This well came on line at approximately 900 Mcf per day, from a 1,600' lateral section. Early production rates suggest ultimate recovery between 1.0 - 1.2 Bcfe from this zone at a finding cost of less than $1.50/Mcfe. The Company has identified over 60 additional locations on the current acreage.

East Texas
"We continue to work with vendors to secure the frac sand for our completion operations," stated Dinges. "Currently we expect the horizontal Haynesville/Bossier shale at Minden and the deep vertical test at County Line, both to be fraced in mid-December."
In east Texas, the Company is testing its first horizontal Haynesville lime well. The Pinkerton 12H was drilled to a total depth of 14,407' with a 3,100' horizontal section. It was stimulated with an eight-stage treatment with 1.6 million pounds of proppant. It is too early to tell how this well will perform as the company continues to flow back completion fluid. This completion and others in the company have been delayed due to a lack of proppant which seems to be an industry-wide problem.

Haynesville gas flows as high as 28 MMcfd
By OGJ editors HOUSTON, Dec. 9
Three operators reported new horizontal completions in Jurassic Haynesville shale at rates as high as 28.2 MMcfd of gas.
The three companies, Petrohawk Energy Corp. of Houston and Comstock Resources Inc. and EXCO Resources Inc. of the Dallas area, plan much more activity in the Haynesville in East Texas and Northwest Louisiana.

Petrohawk reported the 28.2 MMcfd rate at its Sample 9-1 in 9-14n-11w, Red River Parish, La., about 12 miles south of Elm Grove gas field. The rate came on a 30/64-in. choke with 7,100 psi flowing casing pressure. Petrohawk's Brown 17-4 in 17-16n-11w, Bossier Parish, gauged 23.4 MMcfd on a 26/64-in. choke with 7,700 psi FCP. And its Goodwin 9-5 in 9-16n-11w, Bossier Parish, made 21.1 MMcfd on a 26/64-in. choke with 6,750 psi FCP. The company plans to complete five more Haynesville shale wells by yearend 2009.

Initial flow rate is 9 MMcfd at Comstock's BSMC LA 7-1H well in Toledo Bend North field, De Soto Parish. The flow came from a 4,300-ft lateral at 11,750 ft true vertical depth after a 10-stage frac. Comstock is running another 10-stage frac at its Collins LA 15-1H well in Logansport field, also in De Soto. It has a 4,200-ft leg at 11,350 ft. The company has a 22% interest in the Gamble 24-1H well at Logansport, drilled to 11,800 ft TVD with a 3,950-ft lateral. Comstock has drilled the vertical portion of two other Haynesville wells. Bogue A-6H in Waskom field in Harrison County is to get a 4,000-ft lateral, and Green 13H in Blocker field in Harrison County is to get a 3,700-ft lateral. Comstock is drilling vertically at Headrick 1H and Hart 1H in Logansport and Moneyham 7H in Longwood field. Each is due a 4,000-ft leg.

EXCO said its first Haynesville horizontal well, Oden 30H6 in De Soto Parish, averaged 22.5 MMcfd on a 26/64-in. choke with 7,800 psi FCP. It has a 4,481-ft lateral at 12,304 ft TVD. EXCO has two operated horizontal wells, one vertical well, and two outside-operated horizontal wells in the play and plans to drill 25 or more horizontal Haynesville wells in 2009.

Petrohawk 3 New Haynesville Shale Wells 73 Mmcfe/d
HOUSTON, Dec. 9 /PRNewswire-FirstCall/
Petrohawk Announces Three New Haynesville Shale Wells Placed on Production at a Combined Rate of 73 Mmcfe/d.
The Company expects to complete five additional Haynesville Shale wells by the end of the year.

-- Petrohawk Energy Corporation ("Petrohawk" or the "Company") (NYSE: HK) has placed three additional Haynesville Shale wells on production at a combined rate of 73 Mmcfe/d, one with the highest reported initial production rate of any well in Petrohawk's history, as follows:

        The Brown 17 #4 (69% W.I.), located in Section 17-T16N-R11W, Bossier
        Parish, Louisiana, was completed on November 18 and produced at a rate
        of 23.4 Mmcfe/d on a 26/64" choke with 7,700# flowing casing pressure.

        The Goodwin 9 #5 (97% W.I.), located in Section 9-T16N-R11W, Bossier
        Parish, Louisiana, was completed on November 25 and produced at a rate
        of 21.1 Mmcfe/d on a 26/64" choke with 6,750# flowing casing pressure.

        The Sample 9 #1 (100% W.I.) is located in Section 9-T14N-R11W, Red
        River Parish, Louisiana, approximately 12 miles south of Elm Grove
        Field. It was completed on November 27 and produced at a rate of 28.2
        Mmcfe/d on a 30/64" choke with 7,100# flowing casing pressure.

Petrohawk Energy Corporation is an independent energy company engaged in the acquisition, production, exploration and development of natural gas and oil with properties concentrated in Northwest Louisiana and East Texas (Haynesville / Bossier Shale and Cotton Valley), Arkansas (Fayetteville Shale), South Texas (Eagle Ford Shale), Oklahoma and the Permian basin.

For more information contact Joan Dunlap, Vice President - Investor Relations, at 832-204-2737 or jdunlap@petrohawk.com. For additional information about Petrohawk, please visit our website at http://www.petrohawk.com.

Range Resources Reaches Production Milestone
Range Resources Corp. 12/2/2008

Range Resources has reached the 400 Mmcfe per day production milestone. The Company currently anticipates that fourth quarter 2008 production will be within its previous guidance of 400 to 405 Mmcfe per day. This represents an 18% increase for the quarter and nearly a 20% increase for the year. This will also represent Range's 24th consecutive quarter of sequential production growth. The rising production is the result of the Company's successful drilling program. All of Range's divisions have increased production for the year through the drill bit.

Commenting on the announcement, John Pinkerton, Range's Chairman and CEO, said, "Reaching 400 Mmcfe per day of production is a terrific milestone for all of us at Range. The drilling program has been the principle driver for our growth as we have focused on lower cost drilling versus higher cost acquisitions. As a result, we have maintained our low cost structure, which is critical in the current environment. Rising production, a low cost structure, hedges in place covering approximately 60% of next year’s production and strong liquidity position us well as we enter 2009."

Haynesville $1.1 B Pipeline Expansion Regency Energy
Pipeline & Gas Journal Nov 2008
Regency Energy Partners LP plans to expand its pipeline system in north Louisiana to bring natural gas from the Haynesville Shale — one of the most active new natural gas plays in the United States. The $1.1 billion expansion of the Regency Intrastate Gas System will provide 1.45 Bcf/d of new capacity to handle expected increases in production from the region. Regency has obtained letters of intent for long-term transportation agreements from anchor shippers covering approximately 76% of the incremental capacity and is also seeing strong demand for the remaining capacity.
The Haynesville expansion project includes looping the existing pipeline, extending the system and adding new compression. Construction of the project will be divided into two phases.
Phase one expects completion first half of 2009, adding 300 MMcf/d of capacity once fully operational. Phase one will comprise $375 million of the total cost of the project.
Phase two will add an incremental 1.15 Bcf/d and is expected to be online by end 2009 and fully operational early 2010. Overall, the project will add 204 miles of pipeline, ranging from 24 to 42 inches, and 49,000 horsepower of compression.

Regency also plans to expand some of its existing interconnections with interstate pipelines and is exploring new intrastate and interstate market options for its shippers. The system reaches across north Louisiana, from Caddo Parish to Franklin Parish and will be expanded to the southwest into Desoto Parish to interconnect with Regency’s Logansport gathering system.
Regency selected Gulf Interstate Engineering Company to provide engineering, design and procurement services for the three compressor stations in northern Louisiana, Cane Hill, Woodardville and Elm Grove. Gulf will also be responsible for providing engineering, design and procurement services for four interstate delivery-interconnects with Texas Gas, Trunkline, ANR and Columbia Gulf and multiple receipt point interconnects with various producers. In addition, Gulf will support Regency with scheduling and project controls services for the project.

In other news, Gulf Interstate was awarded a contract by Consorcio Terminales GMP - Oiltanking to perform a feasibility study and capital cost estimate for the Poliducto Pisco Lima Ventanilla Project (PPLV). Specifically, Gulf’s scope of work on the LPG pipeline and facilities includes the evaluation of the pipeline route, development of preliminary route maps, development of P&IDs, plot plans, one line diagrams, and a SCADA system architecture diagram for five facility sites. The facility sites include pump stations, metering and storage, truck-loading facilities and delivery meter stations.

Marcellus Mid-Stream Pipeline Project by Superior Appalachian
Superior Appalachian To Build Mid-Stream Pipeline Projects
Pipeline & Gas Journal Nov 2008
A division of an Oklahoma company wants to lay natural gas lines in Centre County, PA, partly in anticipation of an untapped supply of gas in the Marcellus Shale region. Superior Appalachian Pipeline has been working to acquire the rights-of-way for a line from property owners in areas including Burnside, Snow Shoe and Curtin townships.
Chuck Davies, vice president of business development, said the company opened an office in Canonsburg to look at places in Pennsylvania where gas is constrained by capacity shortages in existing pipelines. The company is also interested in the increased need for gas lines that could come from the Marcellus Shale.

Fayetteville Express Pipeline JV $1.3 Billion Pipeline
Pipeline & Gas Journal Nov 2008
Kinder Morgan Energy Partners, L.P. and Energy Transfer Partners, L.P. have entered into a 50/50 joint venture, Fayetteville Express Pipeline, LLC (FEP), to develop a new pipeline. The 187-mile pipeline will originate in Conway County. AR, continue eastward through White County, AR, and terminate at an interconnect with Trunkline Gas Company in Quitman County, MS. The pipeline will have an initial capacity of 2 Bcf/d. Pending necessary regulatory approvals, the approximately $1.3 billion pipeline project is expected to be in service by late 2010 or early 2011. FEP has secured binding 10-year commitments of 1.575 MMDth/d including 1.2 MMDth/d from Southwestern Energy Services, a unit of Southwestern Energy Co., and 375,000 Dth/d with an option for an additional 125,000 Dth/d from Chesapeake Energy Marketing, Inc., an affiliate of Chesapeake Energy Corp.
To gauge further shipper interest, FEP began a binding open season on Oct. 8 that ran through Nov 7. Depending on shipper support during the open season, capacity on the proposed pipeline may be increased.

Atlas to pursue New Albany shale in Indiana
Oil& Gas Journal/Nov. 17, 2008
Atlas Energy Resources LLC, Pittsburgh, plans to drill more than 100 horizontal wells to Devonian New Albany shale in southwestern Indiana by the end of 2009. The company has acquired 114,000 net acres and has taken a farmout on 78,000 net acres from Aurora Oil & Gas Corp., Traverse City, Mich. The combined transactions give Atlas rights to 284,000 largely contiguous gross acres in the Illinois basin, mainly in Sullivan, Knox, Greene, Owen, Clay, and Lawrence counties, Indiana.
Drilling is to start in 2008, with Atlas Energy using capital from its syndicated oil and gas investment programs. The total acreage contains about 800 horizontal drilling locations.
The farmout requires that Atlas Energy drill at least 20 wells/year and grants Aurora a right to participate for 25%. Aurora will receive a well site fee for and overriding royalty interest in each well.
The acreage is in the northern “biogenic” part of the New Albany shale play, where several operators have drilled more than 40 successful horizontal wells, said Atlas Energy. “We have been studying the New Albany shale for over 2 years and believe the predictable and statistical nature of its development is a perfect fit for our investment programs,” said Atlas Energy president and chief operating officer Richard D. Weber.

Overseeing Atlas Energy’s New Albany shale development will be the company’s Antrim Shale operating team, led by Dick Redmond, president of Atlas Energy Michigan LLC. The New Albany shale has many similarities to Michigan’s biogenic Antrim shale, in which Atlas Energy is the largest and one of the lowest cost operators.

Atlas Energy noted that New Albany is a blanket formation 100-200 ft thick and 500-3,000 ft deep. Natural fracture patterns are low-angle in the Antrim shale and vertical in the New Albany.
Atlas Energy reviewed more than 30 successful horizontal completions in and near its acreage and observed an average estimated ultimate recovery of 1 .3 bcf/well. Horizontal New Albany wells with 4,000-5,000-ft laterals can be drilled and completed for $1.3 million.

Aurora Oil & Gas, through predecessors, has been working in the New Albany play since 1994. Operator and majority owner until now of its 121,702-gross-acre Wabash project in Clay, Greene, Owen, and Sullivan counties, it has drilled 13 wells. All may be considered productive, but all are shut-in awaiting connection to pipeline and processing facilities.

Albany Shale GTI Partners Recoverable Gas project
Pipeline & Gas Journal Nov 2008
GTI has entered into a multi-year program with the Research Partnership to Secure Energy for America (RPSEA) to lead a field-based research consortium focused on meeting U.S. natural gas demand and lowering costs for consumers. The consortium is comprised of GTI and 14 participants including producing companies Atlas Gas & Oil, Aurora Oil and Gas, BreitBurn Energy, CNX Gas Corp, Inflection Energy, NGAS Resources, Noble Energy and Trendwell Energy Corp.
The principal objective is to develop techniques and methodologies for increasing the success rate and productivity of New Albany shale gas wells to a level at which the otherwise noncommercial wells become commercially viable. The consortium will be conducting joint research targeting the 10.5 Tcf of technically recoverable gas in the New Albany Shale formation, with the overall goal of converting it to an economically recoverable resource.

Anadarko basin Upper Devonian Woodford shale Oklahoma
Oil& Gas Journal/Nov. 17, 2008
A play for gas-condensate and oil in the fractured Upper Devonian Wood-ford shale formation is emerging on the Oklahoma side of the Anadarko basin. The Woodford shale, thought of until relatively recently as a source rock, has developed into a considerable gas producing formation in the Arkoma basin on the opposite side of the Nemaha ridge, and production is also emerging in the Ardmore basin. Cimarex Energy Co., Denver, began assembling acreage about 18 months ago to drill the Woodford as a primary objective in the Anadarko. Cimarex said the play holds potentially 1.5 to 2 tcf recoverable to the company.
Several other operators are believed to be pursuing or evaluating positions as well. Cimarex amassed 50,000 acres in Woodford-prospective areas of central-western Oklahoma and in late October completed the acquisition of a further 38,000 net acres from Chesapeake Energy Corp. for $180 million. The acreage is in Blaine and Canadian counties. Only $5 million of that transaction went for reserves, Cimarex revealed. It was the last large block to be acquired in its core area in the Woodford play, the company said.
Linn Energy LLC, Houston, announced the sale of its deep rights including the Woodford shale interval in certain central Oklahoma acreage to an undisclosed buyer on Oct. 10 for $229 million, subject to closing adjustments. That sale included no producing assets, and Linn Energy retained the shallow rights.
Continental Resources Inc., Enid, said it held 111,000 net acres in early November 2008 in the Anadarko Woodford shale.

Drilling progress
Cimarex, still leasing in the play, participated in 28 wells by late October; 16 completed and 12 still drilling or being completed. Drilling totals 31 wells by all operators, Cimarex said, and the other three wells were still being drilled in late October. Continental Resources said it was drilling two operated wells in the play as of Nov. 6. The company holds a mix of acreage, some held by production from other formations.

Devon Energy Corp. and Western Oil & Gas Development Corp., both of OK City are companies in the emerging play
Other companies appear to have HBP acreage and may be evaluating their positions.

Cimarex looks for the average well to recover nearly 5 bcf on 160-acre spacing with a 4,000-ft lateral. Wells with that lateral length have averaged initial production rates of 5 MMcfd. Cimarex defines the Anadarko Woodford as occurring at 11,000-16,000 ft, where it is 120-280 ft thick, has 3-9% total organic carbon, good porosity and permeability, and gas in place of 145-195 bcf/sq mile. The Woodford represents “a big, multiyear drilling program in a play we like,” said F.H. Merelli, chairman, chief executive officer, and president of Cimarex. The company is already studying the desirability of downspacing to 80 acres. Half of Cimarex's 88,000 net acres is held by production from other formations, so the company is in control of development timing rather than being governed by lease expiration deadlines. Well cost could moderate slightly from the current $8.5 million to $9 million, Cimarex said. The company said it was dropping five rigs in the Texas Panhandle, but it expects to be running 9-11 rigs in the spring of 2009, up from five operated rigs in late October 2008. While climbing learning curves on drilling and completion techniques in the Anadarko Woodford shale, operators will be deciding how far west they will be able to pursue the play given the economics. The formation plunges well below 15,000 ft as it trends westward toward the deep Anadarko basin trough.

Petrohawk Announces New Shale Gas Field Discovery
Eagle Ford Shale Well Placed on Production at 9.1 Mmcfe/d
HOUSTON, Oct. 21 /PRNewswire-FirstCall/
Petrohawk Energy Corporation ("Petrohawk" or the "Company") (NYSE: HK) announced a significant new natural gas field discovery in the Eagle Ford Shale in South Texas. This new field in La Salle County, Texas, was discovered after extensive regional subsurface and seismic mapping, geochemical analysis and petrophysical study. The Company has leased over 100,000 net acres in what it believes to be the most prospective areas for commercial production from the Eagle Ford Shale. The field is located immediately south of the Stuart City Field, which is on the Edwards Reef Trend that extends across South Texas.
"This discovery folds perfectly into our portfolio of unconventional resource assets," said Dick Stoneburner, Chief Operating Officer. "Petrohawk's staff has extensive experience in the acquisition and development of horizontal plays as exhibited by our results in the Haynesville Shale and Fayetteville Shale plays. Leveraging that expertise to uncover new opportunities like the Eagle Ford Shale adds significantly to our playbook."
The discovery well, the STS #241-1H, was drilled to an approximate true vertical depth of 11,300 feet during which extensive coring and open hole logging was performed. An approximate 3,200-foot lateral was drilled and subsequently fracture stimulated with over two million pounds of sand in ten stages. The well was placed on production at a rate of 9.1 million cubic feet of natural gas equivalent per day (7.6 million cubic feet of natural gas per day and 250 barrels of condensate per day). A confirmation well, the second well drilled on the project, the Dora Martin #1H, which is approximately 15 miles from the discovery well, has been drilled, cored and logged. The quality of the Eagle Ford Shale in this well appears to be superior to that found in the STS #241-1H. The Company is currently drilling the lateral on this second well. A third well is expected to spud by mid-November.
Petrohawk expects drilling and completion costs for development wells to range between $5 and $7 million. Development costs, including one rig that will run continuously on the project, have already been included in the Company's published 2008 and 2009 capital plans. The Company plans to access existing gathering and transportation infrastructure, further improving lower overall development costs.

Petrohawk is the operator and owns 90% working interest in the project, with 10% owned by industry partners.

Louisiana-Mississippi Encore and Tuscaloosa marine shale
Oil & Gas journal / Nov. 17, 2008

Encore Acquisition Co., Fort Worth, is exploring for oil in the highly over-pressured Cretaceous Tuscaloosa marine shale and has accumulated 210,000 net acres along the Louisiana-Mississippi line east of the Mississippi River. The company mapped a silt in the shale of sufficient integrity to drill a horizontal wellbore. It drilled and cased to just beyond 17,000 ft measured depth the Weyerhaeuser-1 H, in irregular section 60-ls-4e, in the northwestern corner of St. Helena Parish, La. Encore Acquisition plans to attempt completion in the well’s 4,100-ft lateral, but the attempt delayed 5 weeks due to the short supply of high-strength proppant.
The company, has drilled four horizontal wells in the play in 2008, took a $26.3 million impairment charge on the first two, Richland Plantation-A 1 in East Feliciana Parish and Joe Jackson 4-13H in Amite County, Miss.

Petrohawk’s production grows 25-35% by 2009
Oil & Gas Journal / Oct. 13, 2008
Petrohawk will emphasize development of nonproved locations in its successful Haynesville and Fayetteville shale projects and expects higher overall reserve growth potential. It projects that its production will grow 25-35% through the drill-bit in 2009 from estimated 2008 production of 305 MMcfd. The Haynesville shale sits 11,000 ft underground in East Texas and northwestern Louisiana. The Fayetteville shale play is east of Little Rock, Ark.
Petrohawk sliced its budget to $1 billion for drilling, comp1etions, seismic exploration, and facilities, down from $1.5 billion previously. Officials said the change affirms the company’s strong capitalization. The firm has “no current plans or need to access the equity capital markets,” they said. Petrohawk’s undrawn credit facility was increased to $1.1 billion from $800 million Sept. 10, 2008.
In addition, the company is looking to divest some conventional assets in the Permian basin next year. These properties include interests in Waddell Ranch, Sawyer, Jalmat, and TXL fields of West Texas and southeastern New Mexico. The Permian basin properties currently produce 35 MMcfd of gas equivalent.
Even with the budget reduction, Petrohawk expects a production growth of 25-35% in 2009. It reaffirmed a third quarter guidance of 310-320 MMcfed.

Petrohawk Energy is engaged in the acquisition, production, exploration, and development of natural gas and oil primarily north Louisiana, Arkansas, East Texas, Oklahoma and the Permian Basin.

Haynesville Shale flowing 16 MMcfd @ 6,400 psi
Questar Corp. 11/24/2008

Questar Exploration and Production Company has announced completion of the company's first operated Haynesville Shale horizontal wells in Northwest Louisiana. The Waerstad #3, located in Red River Parish, La. (Sec 1, T14N, R12W) was placed on production on November 13, 2008, at an initial rate of 16 million cubic feet of natural gas per day (MMcfd) on a 23/64 inch choke with 6,400 pounds per square inch flowing casing pressure. Eight fracture stimulation stages were pumped in the 3,234 foot horizontal lateral. Questar E&P has a 100% working interest in the Waerstad #3 well.

The Wiggins 36H- #1, located in Bienville Parish, La. (Sec 36, T15N, R10W) was placed on production on November 16, 2008, at an initial rate of 7.4 MMcfd on a 22/64 inch choke with 5,450 pounds per square inch flowing casing pressure. Nine fracture stimulation stages were pumped in the 3,455 foot horizontal lateral. Questar E&P has a 62% working interest in the Wiggins 36H- #1 well.

Questar E&P is currently drilling two additional company-operated Haynesville horizontal wells and is participating in four outside-operated Haynesville horizontal wells that are in various stages of progress.

Questar E&P has approximately 31,000 net acres of Haynesville Shale leasehold in the Elm Grove, Woodardville and Thorn Lake areas of Northwest Louisiana.

Marcellus New Technique Higher Results-Atlas Energy
PITTSBURGH, Nov 24, 2008 Atlas Energy Resources
LLC (NYSE:ATN) ("Atlas Energy" or "the Company") Over the past several weeks, Atlas Energy has successfully pioneered the use of a two-stage frac design for five of its vertical wells as part of its Marcellus Shale drilling program in southwestern Pennsylvania. Using this frac design, the Company has averaged initial rates of production for 24 hours into a pipeline of 2.1 million cubic feet per day ("Mmcf/d"), more than double the Company's historical average of approximately 1 Mmcf/d over 90 previous vertical completions in its Marcellus program. Further, early results indicate that a well having a two-stage frac exhibits a shallower decline rate than a well with a single stage frac. Assuming these results continue, which are not assured, the Company expects to realize sizable increased reserves and production per vertical well drilled. The incremental cost of the two stage design over a single stage design is approximately $125,000.

Atlas Energy is also pleased to report that it has successfully drilled and cased its second horizontal well to the Marcellus Shale having a lateral length of approximately 3,000 feet. The Company plans to complete this well, located in Washington County, Pennsylvania, with an eight-stage frac. Atlas has spud its third and fourth horizontal wells and is on track with its previously announced plan to drill 12 horizontal wells in the next six months. These horizontal wells are being drilled in an industry joint venture where Atlas Energy will typically have a 50% working interest and is the operator.

"These results clearly demonstrate our growing expertise at Atlas Energy", stated Richard D. Weber, President and Chief Operating Officer. "Using these advanced techniques, we look forward to accelerating our growth in reserves and production."

Atlas Energy Resources, LLC develops and produces domestic natural gas and to a lesser extent, oil. Atlas Energy is one of the largest independent energy producers in the Eastern United States. Atlas Energy sponsors and manages tax-advantaged investment partnerships, in which it co-invests, to finance the development of its acreage. For more information, visit Atlas Energy's website at www.atlasenergyresources.com or contact Investor Relations at bbegley@atlasamerica.com.

XTO $3.3 billion budget shale gas procssing
By OGJ editors HOUSTON, Nov. 21
XTO Energy Inc., Fort Worth, approved a 2009 capital budget for development and exploration expenditures of $3.3 billion.

An additional $500 million has been budgeted for the construction of pipeline, compression, and processing facilities. With these expenditures, it plans to increase 2009 production volumes by 18% over 2008 levels.

"In these challenging times, the strength of our property base allows XTO to continue to create shareholder value through volume growth and strong economic margins," said Keith A. Hutton, XTO president. "With this managed growth strategy, the company expects to average utilizing 90 drilling rigs for 2009. Activities will include drilling 1,250 new wells and conducting 800 workover events," he said.

During the year, the eastern region will be allocated $1 billion. The Barnett shale will utilize about $800 million. The Arkoma basin and Midcontinent properties will be allocated $500 million. The Bakken, Gulf Coast, and Offshore areas will be allocated $350 million.

Programs in the Permian district are expected to utilize another $300 million. The San Juan, Raton, Uinta, and Piceance basins combined will be allocated $250 million. XTO will target $100 million for exploration events.

Regulations could stifle 20 major US shale gas fields
Nick Snow OGJ.com Washington Editor WASHINGTON, DC, Nov. 24
Natural gas production from US shale plays such as the Marcellus shale in New York, Pennsylvania, and West Virginia could double in the next 10 years and provide 25% of the nation's supply, a Natural Gas Supply Association official said Nov. 21.

But NGSA Vice-Chairman Terrence L. Ruder, who also is senior vice-president for Devon Energy Corp.'s marketing and mainstream division, also warned that a windfall profits tax and new restrictive regulations could hurt that effort a time when more gas will be needed to help meet clean air requirements mandated by climate change legislation.

"What we've seen so far from shale fields is just the tip of the iceberg. To facilitate a steady supply growth of gas from shale, we need a stable tax and regulatory environment," Ruder told a Federal Energy Regulatory Commission conference on the US gas infrastructure. He said shale developments provide an estimated 6-8 bcfd of gas, or 10-12% of projected 2008 US demand. Over the next 10 years, US shale gas production could double to 15-20 bcfd, with total reserve estimates at 250-750 tcf of gas, he indicated.

Ruder said Devon has invested more than $10 billion in the Barnett shale play in northern Texas. He estimated that the gas industry as a whole will spend $150 billion to fully develop the Barnett shale play.

Twenty major US fields
Ruder noted that there are about 20 major shale fields across the US that have the potential to or are currently producing gas, including the Bakken play in North and South Dakota, the Woodford in eastern Oklahoma, the Haynesville in East Texas and Louisiana, and the Green River Piceance basin play in Colorado.

"Shale developments are highly capital-intensive and a windfall profit tax assessment now being discussed in Congress would directly and adversely affect production," Ruder warned.

Another NGSA member, Clay Bretches, vice-president, minerals and marketing, at Anadarko Petroleum Corp., expressed similar concerns. "I cannot emphasize enough the importance of a stable regulatory environment. When exploration and production companies expend billions of dollars on capital projects, they can mitigate some of the risks stemming from price fluctuations, resource requirements, and transportation constraints. But in absence of a transparent and consistent regulatory environment, these projects may be delayed or worse yet, never get off the drawing board," he said.

"What we need is regulatory certainty that not only benefits the economics of the projects, but also provides adequate and on-time supply to consumers. Make no mistake about it, regulatory uncertainty strongly impacts price volatility," Bretches said.

Ruder said shale developments have the potential to reshape the traditional domestic gas supply mix and aid in the replacement of declining conventional production. "Industry has proven it can develop shale plays safely. These resources, however, will only partially satisfy the nation's growing demand for natural gas, demand that will increase even more rapidly with any new climate change policies," he said.

U.S. Shale Gas Could Double
United Press International 11/21/2008
An energy association said Friday that production of natural gas from shale deposits in the United States could be doubled over the next decade,

"if there is stable tax and regulatory environment."

The Natural Gas Supply Association said its calculations indicated that 25 percent of U.S. natural gas demand could be satisfied by the exploiting shale beds located in Appalachia, the Barnett Permian Basin of Texas and other areas of the nation. Shale gas is locked in the dense shale rock and is released through a process known as hydraulic fracturing in which water and sand are pumped into a well and build up enough pressure to fracture the rock.

"What we've seen so far from shale fields is just the tip of the iceberg," Terry Ruder, vice chairman of the Natural Gas Supply Association, said in a written statement. Rude said shale accounted for 6-8 billion cubic feet per day of natural gas this year, about 10-12 percent of U.S. gas demand. He estimated that production could reach 20 Bcfd over the next 10 years.

The promise of shale gas will require some help from the federal government, however.

"To facilitate a steady supply growth of natural gas from shale, we need a stable tax and regulatory environment," Ruder said.

Appalachian expansion new processing, CGT, MarkWest
Christopher E. Smith Pipeline Editor HOUSTON, Oct. 24

NiSource Inc. unit Columbia Gas Transmission Corp. and MarkWest Energy Partners LP intend to jointly expand natural gas gathering and processing services to support increased production volumes in the Appalachian basin of central West Virginia.

The two companies also are discussing plans with several gas producers to provide new gathering and processing services near Columbia's Cobb aggregation system in Kanawha, Jackson, and Roane counties, W.Va.

The expansion of services includes MarkWest's previously announced expansion of its Cobb gas processing plant, increasing total capacity to about 70 MMcfd from the current 25 MMcfd by mid-2009. NGLs recovered at Cobb will continue to be fractionated at MarkWest's Siloam fractionation, marketing, and storage complex in South Shore, Ky., currently in the final stages of its own expansion. Siloam can currently fractionate 600,000 gpd of propane, butane, and natural gasoline and has 11 million gal of cavern propane storage.

Columbia will add horsepower to its existing Cobb compressor station and install new field gathering and compression facilities to bring new production to the Cobb processing plant. Further incremental additions of horsepower and capacity remain possible as warranted by production increases.

These expansion plans follow an August 2008 announcement by the two companies to expand similar services near Majorsville, W.Va., serving the northern panhandle area of West Virginia and western Pennsylvania.

StatoilHydro, Chesapeake join in E&P pact

StatoilHydro has ventured into unconventional gas opportunities arid gas shale development under an agreement signed with Chesapeake Energy Corp., the largest US natural gas producer. The companies have committed to jointly look for gas in China, Romania, and Ukraine, said Statoil Executive Vice-Pres. Peter Mellbye in a conference call with analysts and investors.

StatoilHydro has agreed to spend $3.38 billion for a 32.5% in Chesapeake’s gas assets in the Marcellus shale region in Pennsylvania, West Virginia and New York. StatoilHydro said $1.25 billion would be paid in cash, and the outstanding $2.12 5 billion would constitute a 75% carry on drilling and completion of wells during 2009-12.
“In order to earn this carry, Chesapeake is required to maintain a significant level of drilling activity” the Stavanger-based major added.
The acreage covers 7,300 sq km and will add future recoverable equity resources of 2.5-3 billion boe. StatoilHydro’s equity production from the Marcellus shale gas play is expected to increase to a minimum 50,000 boe/d in 2012 and at least 200,000 boe/d after 2020, with net positive cash flow from 2013. Chesapeake plans to build upon its leases in the Marcellus shale play with StatoilHydro having a right to a 32.5% interest in them.
“The agreement we have entered into with Chesapeake provides us with a solid position in an attractive long-term resource base at competitive terms.” said Helge Lund, president and chief executive officer of StatoilHydro. “This is a significant step in strengthening our US gas position, building on our existing capacity rights for the Cove Point LNG terminal, our gas trading and marketing organization, and the gas producing assets in the US Gulf of Mexico.”

The development program could support the drilling of 13,500-17,000 horizontal wells over the next 20 years, using up to 50 drilling rigs. The expected cost is estimated at $3.5 million/well, with an ultimate recovery of 560,000 boe/well.

The transaction is expected to close by yearend, 2008.
This announcement follows other recent deals that Chesapeake has struck with Plains Exploration & Production Co. and BP America to raise funds and develop its natural-gas holdings: Plains bought a 20% working interest in its assets in the Haynesville shale in north Louisiana and East Texas for $3.3 billion, and BP America acquired a 25% stake in its assets in the Fayetteville shale for $1.9 billion.

Range Resources Expands Marcellus Shale Production
Range Resources 11/20/2008
Range Resources Corporation provided an update on its Marcellus Shale play. Last month, Range and MarkWest Energy Partners, L.P. announced completion of the first phase of the Marcellus Shale infrastructure. The initial phase included gas gathering and compression, as well as Pennsylvania's first large-scale gas processing facility. Since then, Range has been completing production facilities and connecting previously drilled wells to the gas gathering system. Currently, seven wells are tied into the gas processing facility and net sales from these wells total 30 Mmcfe per day.
MarkWest is currently undertaking additional infrastructure development which will serve to expand the gathering system and add gas processing capacity. A cryogenic plant is expected to be online by the end of first quarter 2009, increasing gas processing capacity to 60 Mmcf per day. By year-end 2009 or early 2010, processing capacity is anticipated to be 180 Mmcf per day. As additional gas processing capacity is completed, Range will turn on additional wells. Range currently plans to enter 2009 with three horizontal rigs, increasing to six rigs by the end of 2009. By year-end 2009, Range anticipates that production will reach 80 to 100 Mmcfe per day, net to its interest.

John H. Pinkerton, Chairman and CEO of Range Resources, commented, "We continue to make exciting progress in the Marcellus Shale play as production rates are exceeding expectations. Our technical team is making excellent headway in reducing drilling costs which is very important as we ramp up our development activities. Having now transitioned from the testing phase to the development phase, the Marcellus Shale play should greatly enhance our future production, reserves and capital efficiency. Given its proximity to the northeastern gas markets, the Marcellus Shale play is ideally located to provide a new source of domestic, clean-burning natural gas for many years to come. Importantly, during this period of economic uncertainty, the Marcellus Shale play has the potential to add tens of thousands of new jobs and billions of dollars of economic benefit."

"if there is stable tax and regulatory environment."

The promise of shale gas will require some help from the federal government, however.

"To facilitate a steady supply growth of natural gas from shale, we need a stable tax and regulatory environment," Ruder said.

StatoilHydro, Chesapeake join in E&P pact
OGJ.com November 17 2008
StatoilHydro has ventured into unconventional gas opportunities and gas shale development under an agreement signed with Chesapeake Energy Corp., the largest US natural gas producer. The companies have committed to jointly look for gas in China, Romania, and Ukraine, said Statoil Executive Vice-Pres. Peter Mellbye in a conference call with analysts and investors.

“In order to earn this carry, Chesapeake is required to maintain a significant level of drilling activity” the Stavanger-based major added.

The acreage covers 7,300 sq km and will add future recoverable equity resources of 2.5-3 billion boe. StatoilHydro’s equity production from the Marcellus shale gas play is expected to increase to a minimum 50,000 boe/d in 2012 and at least 200,000 boe/d after 2020, with net positive cash flow from 2013. Chesapeake plans to build upon its leases in the Marcellus shale play with StatoilHydro having a right to a 32.5% interest in them.
“The agreement we have entered into with Chesapeake provides us with a solid position in an attractive long-term resource base at competitive terms.” said Helge Lund, president and chief executive officer of StatoilHydro. “This is a significant step in strengthening our US gas position, building on our existing capacity rights for the Cove Point LNG terminal, our gas trading and marketing organization, and the gas producing assets in the US Gulf of Mexico.”

The development program could support the drilling of 13,500-17,000 horizontal wells over the next 20 years, using up to 50 drilling rigs. The expected cost is estimated at $3.5 million/well, with an ultimate recovery of 560,000 boe/well.

The transaction is expected to close by yearend, 2008.
This announcement follows other recent deals that Chesapeake has struck with Plains Exploration & Production Co. and BP America to raise funds and develop its natural-gas holdings: Plains bought a 20% working interest in its assets in the Haynesville shale in north Louisiana and East Texas for $3.3 billion, and BP America acquired a 25% stake in its assets in the Fayetteville shale for $1.9 billion.

Marcellus Gas estimates 20-100 bcf/sq mile Pennsylvania
By OGJ editors
HOUSTON, Nov. 19 -- Talisman Energy Inc., Calgary, deferred a five-well Marcellus shale pilot in New York pending environmental and regulatory reviews and shifted its focus to Pennsylvania.

The company's Fortuna Energy Inc. unit holds almost 120,000 acres of state controlled land in north-central Pennsylvania and is drilling a pilot in an area where it owns 19,200 net acres prospective for development. It was completing its first operated horizontal well this month.

Talisman Energy's holding totals 640,000 net acres in both states in the emerging overpressured Marcellus play. It estimates gas in place in the Marcellus at 20-100 bcf/sq mile at 2,500-6,000 ft.

Pennsylvania Shale; net sales 30 MMcfed from seven wells
By OGJ editors
HOUSTON, Nov. 20 -- Range Resources Corp., Fort Worth, said its net sales from the Marcellus shale in Pennsylvania reached 30 MMcfed from seven wells.
The wells are connected to the state's first large-scale gas processing plant, operated by MarkWest Energy Partners LP.
Range plans to begin flowing more wells as gas processing capacity is completed next year (OGJ Online, Oct. 22, 2008).
The company plans to enter 2009 with three horizontal rigs and boost that to six by the end of the year. It expects yearend 2009 production to reach a net 80-100 MMcfed.

Kentucky Shale Gas Play Reports Development
Gale Force Petroleum Inc. 11/19/2008

Gale Force has announced further interim results from its initial "Phase 1" development program on its Kentucky Appalachian Shale Gas Property. Property will recover capital cost payback in less than 2 years with NYMEX at a constant $7.00 per Mcf, with a prospective internal rate of return greater than 50%.

The Corporation has now completed 5 of the 9 wells on the property that had never been completed, focusing primarily on stimulating the organically rich hydrocarbon-bearing intervals within the Devonian Shale source rock using fracture stimulation. The Corporation has obtained test results from the 5 wells, which demonstrate that an average vertical well drilled on the Kentucky

On September 24, 2008, the Corporation announced that it had re-entered and started natural gas production from 4 of 9 existing wells on the Kentucky Property that had already been completed. The Corporation will now tie-in the remaining 5, newly completed wells.

The recent workover and completion program has proven that there is consistent natural gas potential across the Kentucky Property, confirming that there is low-risk drilling for the Devonian Shale target. There are more than 200 potential drilling locations adjacent to the existing infrastructure, which means that the Kentucky Property is an excellent candidate for a low-cost, multi-well drilling program designed to generate cash early in the project development and increase the net present value of the reserves on the property.

"These are great results, which strongly suggest that the Kentucky Property can create tremendous economical value if developed on a larger scale," said Michael McLellan, President and CEO. "These results are in line with what we told investors they could expect when we acquired the prospect."

The Kentucky Property was acquired by the Corporation on July 27, 2008 and included nine existing wells on the 22,000 acres of leased land with ready access to market via existing pipeline infrastructure. Subject to new financing, the Corporation will also drill and core additional wells on the Kentucky Property and attempt alternative exploitation techniques such as horizontal drilling, underbalanced drilling and open-hole completions, all of which could improve the development template for the Kentucky Property, permitting the Corporation to accelerate recovery of the gas resource and create greater net asset value of reserves.

Atlas Energy’s Marcellus program delivers 60 MMcfd in Pennsylvania Oil & Gas Journal / Oct. 20, 2008

Atlas Energy Resources LLC, Philadelphia, is the largest producer of gas from Devonian Marcellus shale in the Appalachian basin and has drilled more than 80 wells, almost all of them vertical, the company said in a webcast Oct 8.
A sweet spot in the emerging play occurs in the same area as the company’s gas gathering system, and Atlas Energy is moving 60 MMcfd, said Richard D. Weber, president and chief operating officer. The company is expanding the system’s capacity to 150 MMcfd by the end of 2008 and 250 MMcfd by the end of 2009 from the present 120 MMcfd.
Atlas Energy previously said it could ultimately recover 4 to 6 tcf of gas from the Marcellus on its properties mostly in southwestern Pennsylvania (OGI, Mar. 3,2008, p.40).

The play falls in the midst of Atlas Energy’s historic acreage position. It controls 580,000 acres, including 280,000 acres in a sweet spot in the play in southwestern Pennsylvania.
The initial 24-hr flow rate has averaged 1 MMcfd, and the company assigned average reserves of 1 bcf/ well. Initial flows have ranged from 300 Mcfd to 3.6 MMcfd.
Atlas Energy, which claims to be advanced in its understanding of the Marcellus reservoir, said it has lately eliminated many of the low-end wells. It expects the play to be developed with horizontal wells and has drilled one horizontal penetration which was a success although costs were unacceptably high.
The company plans to drill four horizontal wells this fall in a 50-50 joint venture in Washington County, Pa., offsetting acreage held by Range Resources Corp., Fort Worth. The Marcellus in this area is lower pressured and less geologically complex than in the areas Atlas Energy has drilled thus far.
The company plans to have 150 vertical wells on production by mid-2009 and by then expects to be able to assess whether to begin a bias toward horizontal wells, Weber said.
It does not believe the Marcellus play will be productive continuously across its entire extent (see map. OGI, Oct. 6, 2008, p.50). It sees another sweet spot in northeastern Pennsylvania in Sullivan and Lycoming counties, where little infrastructure exists.

Texas shale gas has large reserves
11/19/08 houston.bizjournals.com
Gas shale plays will dominate future investment in oil and gas in Texas, predicts Renato Bertani, president and CEO of Thompson & Knight Global Energy Services LLC.

Since onshore oil and gas production from conventional sources has been declining and will likely continue to decline, gas from unconventional sources such as gas shale, coal bed methane and tight sands will drive supply growth in the future. Of these, gas shale will be the most important source in Texas. “Some companies have been very aggressive in securing acreage,” he noted at a recent seminar for the firm’s clients.

The gas, trapped in micro-fractures in layers of shale, is more difficult and expensive to produce than gas from conventional wells. But better technology and, more importantly, rising prices for natural gas, have made it potentially profitable.
“When gas is at $5 per Mcf (1,000 cubic feet) and above, these plays can work,” says Bertani. Gas is now at $7 per Mcf.

He expects that the price will continue to rise, and that fossil fuels in general will continue as the prevailing source of energy in the foreseeable future.

Natural gas is now about half the price of oil on an energy equivalent basis, in large part because gas is more difficult to move around. Acknowledging that making price projections is very risky, he nonetheless expects that with the growing availability of liquefied natural gas, gas prices will approach oil equivalency, about $14 per Mcf, within four or five years. “This resource will be more valuable over time,” he asserts. “Now is the time to establish a strong acreage position.” Barnett Shale

Texas is blessed with large deposits of gas shale, left behind by vast ancient seas that once covered most of the Central U.S. They laid down sedimentary layers filled with organic material that settled into shales and fractured many times, leaving gas trapped in the fractures. In many places, shales are a caprock. In the case of gas shale they act as a source rock. In some places the gas forms hot spots that can support clusters of producing wells.

Although Texas and Louisiana may seem to have been pored over and drilled for decades, large reserves of gas shale remain to be tapped. Most of the good wells in the state are in the Barnett shale, west of Dallas/Fort Worth. The wells drilled in the rest of the state have mixed results. The Barnett shale field has an estimated 50 trillion cubic feet of remaining reserves. Other areas in Texas also have significant reserves.

Gas shale wells are drilled down to the target formation and then horizontally along the layer of shale. The wells must be stimulated by hydraulic fracturing operations. Fracing forces fluid at high pressure forced out into the formation. The fluid contains spheres of aluminum oxide (or another proppant) which keep the fractures open and allow gas to flow. The process results in wells with high initial production that deplete quickly, usually in the first three years, “maybe 10 years if you are in a hotspot,” says Bertani.

Rule of capture
A major legal issue with respect to fracing operations was recently decided by the Texas Supreme Court, in Coastal Oil & Gas Corp. vs. Garza Energy Trust. Garza sued Coastal for trespass, alleging that Coastal’s fracing of its well on neighboring acreage had caused gas from Garza’s acreage to migrate and be produced from Coastal’s well. At trial, Garza won on all counts and was awarded $15 million in total damages, some of which were reduced by the trial court.

Coastal argued that the rule of capture precluded Garza’s recovery. The rule, which is well-settled law in Texas, gives a mineral rights owner title to the oil and gas produced from a lawful well bottomed on his property, even if the oil and gas flowed to the well from beneath another owner’s tract. Garza claimed that the rule of capture did not apply because fracing was an unnatural means of causing the gas to migrate to the property of another, and claimed there was no difference between producing gas from another’s property by means of fracing and producing gas from a slant well that bottoms under the property of another, which is illegal.

The court affirmed the rule of capture, giving Coastal title to the gas even if it had flowed to Coastal’s well from Garza’s tract, on grounds the drained owner already has full recourse (he can drill his own well or apply for pooling) and because changing the rule would usurp power of the Texas Railroad Commission to regulate oil and gas. The court recognized that fracing operations are essential to development of tight sands and gas shale plays in Texas, specifically referencing the Barnett shale, and that some drainage from fracing is virtually unavoidable.

The Coastal decision was long-awaited, and settled some important issues, but questions remain. The court did not decide the broader issue of whether fracing operations constitute trespass. “It’s not really a great decision for the industry,” says Greg Curry, a litigator in Thompson & Knight LLP’s Dallas office. “Now your lessor can sue you for not preventing drainage.”
Charles Sartain of Looper, Reed & McGraw PC points out that the decision could have a potentially adverse effect both in traditional areas of production and in urban areas that will experience unprecedented mineral development activity. “It is almost certain that this matter will continue as a source of discussion, debate and litigation,” he says.

Unconventional gas spurs EnCana’s output
Oil & Gas journal / Nov. 3, 2008
EnCana Corp. said its company wide natural gas production was up 8% to 3.9 bcfd in the quarter ended Sept.30 on a gain of 16% in its North American unconventional gas plays.
East Texas output averaged 340 MMcfd, up 135% from the same quarter a year ago, due to new wells coming on production and a 2007 acquisition that doubled EnCana’s interest in the Jurassic Deep Bossier play.
EnCana’s US gas production was up 24% on drilling and operational success in the Fort Worth and Piceance basins and Jonah field in Wyoming.
In Canada, coalbed methane, Cutbank Ridge, and Bighorn increased production by 23%, partly offset by natural declines from conventional properties, resulting in an overall 16% gain in the Canadian Foothills division.
EnCana added 25,000 net acres in North Louisiana in the quarter, bringing its Haynesville shale position to 400,000 net acres of land plus 63,000 net acres of mineral rights. EnCana and its partner Shell Exploration & Production Co. have an industry-leading land position in the area, where they are running six rigs and will target drilling and completion of the first well in the mid-Bossier shale in the fourth quarter.
EnCana holds more than 700,000 acres in the Montney play in Northeast British Columbia and northwestern Alberta, and EnCana and Apache Corp. have completed seven wells this year in the Horn River basin shale play One of the most recent wells averaged almost 8 MMcfd in the first 30 days.

WVa. Appalachian Basin gas expansion
Oil & Gas Journal / Nov. 3, 2008
NiSource Inc. unit Columbia Gas Transmission Corp., and Mark-West Energy Partners LP intend to jointly expand natural gas gathering and processing services to support increased production volumes in the Appalachian basin of central West Virginia.
The two companies also are discussing plans with several gas producers to provide new gathering and processing services near Columbia’s Cobb aggregation system in Kanawha, Jackson, and Roane counties, WVa.
The expansion of services includes MarkWest’s previously announced expansion of its Cobb gas processing plant, increasing total capacity to about 70 MMcfd from the current 25 MMCM by mid-2009. NGLs recovered at Cobb will continue to be fractionated at MarkWest’s Siloam fractionation, marketing, and storage complex in South Shore. Ky., currently in the final stages of its own expansion.

Huron shale Virginia horizontal wells: Range Resources
Oil & Gas Journal / Nov. 3, 2008

Range Resources Corp., Fort Worth, completed drilling its fifth horizontal well to Devonian Huron shale in Nora field in southwestern Virginia.

The company, which says Huron produces gas from 107 vertical wells in the field, estimated the formation’s net reserve potential at Nora from horizontal drilling to 8-1.5 tcf.

The four horizontal Huron shale wells averaged initial production of 1.1 MMcfd, averaged $1.7 million/well, and continue to produce in line with expectations, the company said.

The company noted that the Huron is thicker and higher pressured at Nora than in Kentucky.

Range Resourcea plans to drill five more Huron shale wells and two horizontal Berea wells by the end of 2008.

MARCELLUS SHALE GAS parts of three eastern US states, a new opportunity
Atlas Energy Resources, LLC., Nov 10, 2008

The Marcellus shale in the Appalachia basin extends over several states, although most wells drilled to date have been in Pennsylvania.
It says Marcellus production has been minimal to date because of the need to expand the existing infrastructure to accommodate the high-pressure gas that the gas transportation system in Appalachia cannot at this time handle.

Most companies have so far drilled mostly vertical wells to delineate the play, but the study expects horizontal wells to be the primary means for developing the formation.

The Marcellus shale, which extends 575 miles across parts of three eastern US states, is thought to hold as much as 500 tcf of natural gas, about 50 tcf of which is considered recoverable. The area is bringing producers, landowners, and state and local officials to address water use and other questions.

The Marcellus shale deep-gas formation also is bringing the oil and gas industry into parts of Pennsylvania, New York, and West Virginia for the first time. Producers have responded with aggressive outreach efforts.

“We have been meeting with individual groups about the Marcellus play for some time,” said Charlie Burd, executive director of the Independent Oil & Gas Association of West Virginia (IOGA of WV) in Charleston. “We have been to several places in eastern West Virginia where this development will take place because it lies in a formation that hasn’t been produced and a part of the state that hasn’t had a lot of oil and gas exploration, Burd said, adding, “So there’s more concern, both positive and negative, from those constituents. Residents and royalty owners where there has been shallow drilling are more familiar with the process of exploring and producing natural gas and oil.”

State regulators also have responded. “We have experienced here in Pennsylvania what may be a relatively unprecedented land rush,” said J. Scott Roberts, deputy for mineral resources management in Pennsylvania’s Department of Environmental Protection. “There are now several million acres of private land which have been leased for Marcellus shale development, including 78,000 acres of state forest land where bids were put out in September,” Roberts said.
Atlas_Energy_Applachian_Basin.jpg
“Pennsylvania’s traditional oil and gas production has been in the western quarter of the state,” Roberts told OGJ during an Oct. 28 telephone interview. “The Marcellus exists in sort of an arc, starting in the same portions to the south but extending north and east, including all of our northern tier counties to the Delaware River. Those counties haven’t seen any oil and gas production because the opportunities haven’t existed,” he said.

EOG and Seneca Resources Corp Pennsylvania Devonian Marcellus shale trend;
By OGJ editors HOUSTON, Nov. 7
Seneca Resources Corp., Buffalo, NY, bid successfully on 24,000 acres on four large blocks in the Devonian Marcellus shale trend in Pennsylvania. The leases, in Lycoming and Tioga counties, Pa., have 10-year primary terms and are incremental to the 425,000 acres highgraded in this play. Meanwhile, Seneca and EOG Resources Inc. modified the terms of their Marcellus shale joint venture to require EOG to select all prospect acreage by March 2009. The change will more quickly free up the nonselected acreage and allow Seneca further flexibility to evaluate, explore, and develop the remaining lands independently or with other partners.

Atlas Energy Marcellus shale 90 wells = 25 MMcfd into pipeline: Cumulative production exceeds 4 bcf
By OGJ editors HOUSTON, Oct. 31
Atlas Energy Resources LLC, Pittsburgh, said it has 90 wells, some of which have been on line for 2 years, producing a combined 25 MMcfd of gas into a pipeline from Devonian Marcellus shale in Pennsylvania.
Cumulative production exceeds 4 bcf, making Atlas Energy the largest Marcellus producer (OGJ Online, Oct. 8, 2008).
The last 13 vertical Marcellus completions have averaged an initial 1.3 MMcfd, and one vertical well in Fayette County came on at 3.6 MMcfd and has produced 132 MMcf in 60 days.
The company plans to drill 32 vertical wells between next week and Mar. 31, 2009, and 75 more vertical wells the rest of 2009. It is also drilling 12 horizontal wells by next Mar. 31 as operator with 50% working interest and 12 more horizontals with 100% by the end of 2009.

Cabot Oil & Gas Corp., Northeastern Pennsylvania Devonian Marcellus shale averaging 4-5 MMcfd from 5 vertical wells
By OGJ editors HOUSTON, Oct. 30
Cabot Oil & Gas Corp., Houston, is averaging 4-5 MMcfd of gas from five vertical Devonian Marcellus shale producing wells in northeastern Pennsylvania.
The company expects to exceed its goal of producing 6-9 MMcfd by the end of 2008. Cabot completed its first horizontal well, which will be on line shortly, with only three of six planned fracs. The company will run the other three fracs in a few weeks. Two more horizontal wells are cased awaiting completion, and five vertical wells are in various stages of completion, all of which are expected to be flowing to sales by yearend. Cabot Oil & Gas Corp., Houston, set a 2009 capital budget of $450 million, dedicated to its Pennsylvania Marcellus and East Texas Haynesville/Bossier drilling programs.

Chesapeake Energy Corporation Announces Marcellus Shale Joint Venture
International Unconventional Natural Gas Exploration Alliance with StatoilHydro
OKLAHOMA CITY--(BUSINESS WIRE)--Nov. 11, 2008
Chesapeake Energy Corporation (NYSE:CHK) today announced the execution of an agreement for a joint venture with StatoilHydro (NYSE:STO, OSE:STL) whereby StatoilHydro will acquire a 32.5% interest in Chesapeake's Marcellus Shale assets in Appalachia for $3.375 billion, leaving Chesapeake with a 67.5% working interest. The assets include approximately 1.8 million net acres of leasehold, of which StatoilHydro will own approximately 0.6 million net acres and Chesapeake will own approximately 1.2 million net acres.

StatoilHydro will pay $1.25 billion in cash at closing and will pay a further $2.125 billion from 2009 to 2012 by funding 75% of Chesapeake's 67.5% share of drilling and completion expenditures until the $2.125 billion obligation has been funded. Chesapeake plans to continue acquiring leasehold in the Marcellus Shale play and StatoilHydro will have the right to a 32.5% participation in any such additional leasehold.

Additionally, Chesapeake and StatoilHydro have agreed to enter into an international strategic alliance to jointly explore unconventional natural gas opportunities worldwide. Closing of the transaction and strategic alliance is anticipated to occur by year-end 2008.

Helge Lund, President and CEO of StatoilHydro, stated, "I am pleased that we today have made a strategically important move by joining forces with Chesapeake, which is the leading U.S. natural gas player. We are establishing a strong platform for further developing our gas value chain business and growing our position in unconventional gas worldwide. The agreement we have entered into with Chesapeake provides us with a solid position in an attractive long-term resource base under competitive terms. Additionally, this deal adds a major building block to the gas value chain position we have established in the U.S., the world's largest and most liquid gas market. This is a significant step in strengthening our U.S. gas position, building on our existing capacity rights for the Cove Point LNG terminal, our gas trading and marketing organization and the gas producing assets in the Gulf of Mexico."

Aubrey K. McClendon, Chesapeake's Chief Executive Officer, commented, "We are honored to establish a business relationship with StatoilHydro and are excited about the mutually beneficial nature of our transaction with them. We believe this transaction creates substantial value for both companies and unique opportunities for international growth with one of the leading international oil and gas companies. Jointly we can export our world class unconventional natural gas technology for further long-term growth.

"Chesapeake has now completed three shale joint ventures that collectively value Chesapeake's Haynesville, Fayetteville and Marcellus Shale assets (before the joint ventures) at approximately $34 billion. Through these transactions, Chesapeake sold a 20% working interest in its Haynesville Shale assets to Plains Exploration & Production Company (NYSE:PXP) for $3.3 billion (thereby retaining an 80% working interest valued at $13.2 billion), a 25% working interest in its Fayetteville Shale assets to BP America (NYSE:BP) for $1.9 billion (thereby retaining a 75% working interest valued at $5.7 billion) and now has agreed to sell a 32.5% working interest in its Marcellus Shale assets to StatoilHydro for $3.375 billion (thereby retaining a 67.5% working interest valued at $7.0 billion). The total consideration to CHK from these sales has been approximately $8.575 billion, of which approximately $4.0 billion has been (or will be) in cash and approximately $4.575 billion is in drilling and completion cost carries. Furthermore, CHK retains the remaining ownership percentages of the joint ventures that have been valued at approximately $26 billion, or over $40 per share of value from just these three shale joint venture transactions. These joint ventures clearly demonstrate the enormous value of Chesapeake's shale natural gas assets and the unique capability of our organization to develop them."

Chesapeake was advised on the transaction by Jefferies Randall & Dewey of Houston, Texas.

Chesapeake Energy Corporation is the largest producer of natural gas in the U.S. Headquartered in Oklahoma City, the company's operations are focused on exploratory and developmental drilling and corporate and property acquisitions in the Fort Worth Barnett Shale, Fayetteville Shale, Haynesville Shale, Mid-Continent, Appalachian Basin, Permian Basin, Delaware Basin, South Texas, Texas Gulf Coast and Ark-La-Tex regions of the United States. Further information is available at www.chk.com.

Atlas to pursue New Albany shale in Indiana
By OGJ editors HOUSTON, Oct. 30

Atlas Energy Resources LLC, Pittsburgh, plans to drill more than 100 horizontal wells to Devonian New Albany shale in southwestern Indiana by the end of 2009.
The company has acquired 114,000 net acres and has taken a farmout on 78,000 net acres from Aurora Oil & Gas Corp., Traverse City, Mich. The combined transactions give Atlas rights to 284,000 largely contiguous gross acres in the Illinois basin, mainly in Sullivan, Knox, Greene, Owen, Clay, and Lawrence counties, Indiana. Drilling is to start in 2008, with Atlas Energy using capital from its syndicated oil and gas investment programs. The total acreage contains about 800 horizontal drilling locations. The farmout requires that Atlas Energy drill at least 20 wells/year and grants Aurora a right to participate for 25%. Aurora will receive a well site fee for and overriding royalty interest in each well.

The acreage is in the northern "biogenic" part of the New Albany shale play, where several operators have drilled more than 40 successful horizontal wells, said Atlas energy. "We have been studying the New Albany shale for over 2 years and believe the predictable and statistical nature of its development is a perfect fit for our investment programs," said Atlas Energy president and chief operating officer Richard D. Weber.

Overseeing Atlas Energy's New Albany shale development will be the company's Antrim Shale operating team, led by Dick Redmond, president of Atlas Energy Michigan LLC. The New Albany shale has many similarities to Michigan's biogenic Antrim shale, in which Atlas Energy is the largest and one of the lowest cost operators.

Atlas Energy noted that New Albany is a blanket formation 100-200 ft thick and 500-3,000 ft deep. Natural fracture patterns are low-angle in the Antrim shale and vertical in the New Albany. Atlas Energy reviewed more than 30 successful horizontal completions in and close to its acreage and observed an average estimated ultimate recovery of 1.3 bcf/well. Horizontal New Albany wells with 4,000-5,000-ft laterals can be drilled and completed for $1.3 million.

Aurora Oil & Gas New Albany shale in Indiana Aurora Oil & Gas, 13 wells All considered productive, shut-in awaiting connection to pipeline and processing facilities.
, through predecessors, has been working in the New Albany play since 1994. Operator and majority owner until now of its 121,702-gross-acre Wabash project in Clay, Greene, Owen, and Sullivan counties, it has drilled 13 wells. All may be considered productive, but all are shut-in awaiting connection to pipeline and processing facilities.

Barnett Fort Worth basin 8,416 wells 19 counties 3.8 bcfd 1st quarter 2008 from .219 bcfd 2000 6-7 bcfd by 2013.
Development activity continues to evolve with part of the current activity in urban sites such as Fort Worth and the Dallas-Fort Worth airports.
The study notes that as of Aug. 18, 2008, the Barnett had 8,416 gas wells drilled in 19 counties. Production had increased to 3.8 bcfd in first-quarter 2008 from 219 MMcfd in 2000. The study expects the shale to produce 6-7 bcfd in the next 5 years.
Some of the newer techniques in the play noted in the study are: Longer horizontal laterals, up to 3,500 ft, often drilled from pads with multiple wells, especially in the urban areas. Testing of tighter well density with laterals, spaced 250-ft apart (25-30) compared with 500 ft between laterals (50-acre spacing). Simultaneous fracing of wells to increase recovery.

Deep Bossier East Texas six fields 4 counties 65 MMcfd
Wells in Deep Bossier of East Texas reach a 15,000-20,000 ft depth, have pressures of about 15,000 psi, and have tested at 65 MMcfd. The study notes that these wells are expensive, costing $10-20/million for a vertical well.
Currently the play has six main fields in four counties: Robertson, Leon, Freestone, and Limestone.

Fayetteville shale Arkansas: 877 wells, July, 2008 740 MMcfd - 90 MMcfd Dec 2006 expects 3.15 bcfd by 2018.
The Fayetteville shale in Arkansas is the shallower and thinner equivalent of the Barnett shale. The core of the play is in five counties in central Arkansas: Cleburne, Van Buren, Conway, Faulkner, and White. The study says as of May 31, 2008, the play had 877 producing wells, with production in July of 740 MMcfd compared to only 90 MMcfd in December 2006. The study expects the play to produce 3.15 bcfd by 2018.

Fayetteville Shale BP Acquires 25% Interest In Chesapeake’s Assets
Pipeline and Gas Journal, Oct 2008

Chesapeake Energy Corporation and BP America have signed a Letter of Intent for a joint venture whereby BP will acquire a 25% interest in Chesapeake’s Fayetteville Shale assets in Arkansas for $1.9 billion.
The assets have daily net production of 180 MMcf/d of natural gas and include 540,000 net acres of leasehold that the companies believe could support the drilling of up to 6,700 future horizontal wells. BP will own 135,000 net acres of this leasehold and Chesapeake 405,000 net acres.
BP will pay $1.1 billion in cash at closing and $800 million in the remainder of 2008 and in 2009 by funding 100% of Chesapeake’s 75% share of drilling and completion expenditures until the $800 million obligation has been funded.

Haynesville northwestern Louisiana and East Texas: 5-20 MMcfd,
The Haynesville shale is in northwestern Louisiana and East Texas. Wells in the play initially have produced 5-20 MMcfd, the study said. The study expects wells to have ultimate gas recovers of 4-8 bcf. Currently, companies have drilled about 20-25 horizontal wells in the play, and the study expects about 60-80 rigs could be active in the play by yearend 2008, with most of the drilling in Caddo and DeSoto Parishes in Louisiana.

Oklahoma Woodford Arkoma basin of SE 80-acre well 4 bcf of gas.
The Devonian-aged Woodford shale lies at 6,000-14,000 ft depths in the Arkoma basin of southeast Oklahoma. The study notes that the $6 million well cost in the Woodford is more than the $2-3/million/well cost in the Fayetteville and Barnett shales. The study estimates that an 80-acre well in the Woodford will recover about 4 bcf of gas.

Atlas Energy Michigan Antrim Shale: 60 Mmcfe/d
Atlas Energy Michigan, owns interests in approximately 2,400 natural gas wells producing from the Antrim Shale, located in northern Michigan. The Antrim Shale is a mature play characterized by long-lived reserves and predictable production rates and as of June 2008 has 613 Bcfe (billion cubic feet of natural gas equivalents) of proved reserves on DGO’s approximately 273,900 net developed acres and 39,300 net undeveloped acres. Daily production in the Antrim Shale on the date of the transaction was approximately 60 Mmcfe/d (million cubic feet equivalent per day).

Atlas Energy Michigan is the largest operator in Michigan’s Antrim Shale, a biogenic shale found between 500 and 1,500 feet in northern Michigan. Our reserves in this basin are long-lived and have historically stable production rates. One of the first shale plays to evolve and mature, Antrim has been producing since the 1940’s. Although mature, the field continues to expand through development of technology and successful testing of new areas. The natural gas in Antrim exists as adsorbed gas on the surface of the shale and within its natural fractures. The use of horizontal wells has opened up new areas of development resulting in approximately 2,400 producing wells, with more than 750 future drilling locations identified. Our technical team in Michigan has a long operating track record in the Antrim Shale which we believe has resulted in our strong operating discipline and our position as one of the lowest-cost producers in the region. We also believe that we have the most experienced management, technical and operating teams with biogenic shale formations in the country.

Atlas Energy Chattanooga Shale: 4 wells 1/3-1/2mcfgpd
Since the beginning of 2007, Atlas Energy has accumulated 105,000 net acres located in eastern Tennessee. We believe this acreage contains up to 500 potential horizontal drilling locations in the Chattanooga Shale. Today, Atlas Energy operates more than 375 vertical wells producing from conventional zones, as well as the Chattanooga Shale, and is the largest producer of oil and gas in Tennessee.
The Devonian Chattanooga Shale is an organic, hydrocarbon rich shale found throughout eastern Tennessee. This productive horizon is located beneath the Mississippian Fort Payne Limestone at a depth of between 3,000 and 4,000 feet. The shale thickness ranges from 80 to more than 200 feet and is thought to be the source rock for the hydrocarbons produced from many of the conventional reservoirs in Tennessee.
Atlas Energy Tennessee, a subsidiary of Atlas Energy, has drilled or participated in four successful horizontal wells in the Chattanooga Shale of eastern Tennessee. Results have indicated that horizontal Chattanooga Shale wells, with a 3,000 foot lateral, are capable of stabilized production into a pipeline of between 300 and 500 Mcfe per day.
Atlas Energy’s affiliate, Atlas Pipeline Partners, is installing two natural gas processing plants that will be capable of serving a broad area of eastern Tennessee. Atlas Pipeline’s ownership of these facilities, along with the recently acquired intrastate pipeline system, offers Atlas Energy an advantage in acquiring additional leasehold acreage.

December-27-2008 Pioneer Eagle Ford shale gas production averaging 85 MMcfd	December-27-2008 US gas production Unconventional to soon dominate
December-22-2008 Williams Completes 1st Phase Pennsylvania New Jersey pipeline	Northeast US Millennium pipeline First Delivery 182-Mi.
December-17-2008 CNX Gas Marcellus Record rate -- 6.5 MMcf	December-17-2008 Colorado East -- Nighthawk Energy Shale O/G production
December-16-2008 Marcellus shale Pennsylvania 30 MMcfd -7 wells	December-16-2008 Jurassic Haynesville/Bossier shale Texas East
December-10-2008 Marcellus Shale could hold 1,100 tcf	December-16-2008 Baxter shale Wyoming Cretaceous 2.19 MMcfd
December-09-2008 Petrohawk 3 New Haynesville Shale Wells 73 Mmcfe/d	December-09-2008 Haynesville gas flows as high as 28 MMcfd
December 04 2008 Range Resources Reaches Production Milestone	December 08 2008 Marcellus Cabot Pennsylvania, 13 MMcf/d
December 02 2008 Anadarko basin Upper Devonian Woodford shale Oklahoma Cimerex, Devon Energy Corp. and Western Oil & Gas Dev. Corp., Fayetteville Express Pipeline JV $1.3 Billion Pipeline Haynesville $1.1 B Pipeline Expansion Regency Energy	December 02 2008 Indiana Atlas to pursue New Albany shale Louisiana-Mississippi Encore and Tuscaloosa marine shale Marcellus Mid-Stream Pipeline Project by Superior Appalachian
Albany Shale GTI Partners Recoverable Gas project	Petrohawk’s production grows 25-35% by 2009
November-26-2008 Marcellus New Technique Higher Results-Atlas Energy	November-26-2008 Haynesville Shale flowing 16 MMcfd @ 6,400 psi Petrohawk Announces Eagle Ford Shale Gas Field Discovery
November-25-2008 Appalachian expansion new processing, CGT, MarkWest Regulations could stifle 20 major US shale gas fields	November-25-2008 U.S. Shale Gas Could Double XTO $3.3 billion budget shale gas procssing
November-21-2008 StatoilHydro, Chesapeake join in E&P pact U.S. Shale Gas Could Double	November-21-2008 Range Resources Expands Marcellus Shale Production

November-19-2008 Kentucky Shale Gas Play Reports Development	November-19-2008 Pennsylvania Shale; net sales 30 MMcfed from seven wells Marcellus Gas estimates 20-100 bcf/sq mile Pennsylvania
November-19-2008 Texas shale gas has large reserves	November-19-2008 Atlas Energy’s Marcellus program 60 MMcfd in Pennsylvania
November-18-2008 Huron & Berea shale VA horizontal wells: Range Resources	November-18-2008 Unconventional gas spurs EnCana’s output WVa. Appalachian Basin gas expansion
November-11-2008 Atlas Energy Marcellus wells 25 MMcfd pipeline: Cum 4 bcf Atlas to pursue New Albany shale in Indiana Atlas Energy Michigan Antrim Shale: 60 Mmcfe/d Atlas Energy Chattanooga Shale: 4 wells 1/3-1/2mcfgpd Aurora Oil & Gas New Albany shale Indiana 13 wells shut-in Barnett Fort Worth basin 8,416 wells 19 counties 3.8 bcfd 1st Q 2008 from .219 bcfd 2000: 6-7 bcfd by 2013. Cabot Oil averag 4-5 MMcfd from 5 vertical Marcellus wells Chesapeake Energy Corp Marcellus Shale J V StatoilHydro	November-11-2008 Deep Bossier East Texas six fields 4 counties 65 MMcfd EOG and Seneca Resources Pennsylvania Marcellus Fayetteville Shale BP 25% In Chesapeake’s Assets Fayetteville shale Arkansas: 877 wells, July, 2008 740 MMcfd - 90 MMcfd Dec 2006 expects 3.15 bcfd by 2018. Haynesville NW Louisiana East Texas: 5-20 MMcfd, MARCELLUS SHALE GAS parts of 3 eastern US states, Oklahoma SE Woodford Arkoma basin 80-acre well 4 bcf of gas