Williams CEO Says Future of Natural Gas Looks Good

- Williams CEO Says Future of Natural Gas Looks Good

Wednesday, August 31, 2011
Tulsa World, Okla.
by Rod Walton

Falling natural gas prices can benefit the country and smart companies if they're willing to take advantage by getting bigger, Williams Cos. Inc. CEO and Chairman Alan Armstrong said Tuesday.

"Production companies are going to have to operate on a large scale," Armstrong said during the inaugural lecture of this academic year's Friends of Finance series on the University of Tulsa campus. "You better be a big player."

Williams knows something about size within the industry -- 14 percent of daily U.S. natural gas consumption moves on the company's interstate pipelines, while Williams' exploration and production side produces 1.2 billion cubic feet per day, according to the most recent data.

More efficient drilling techniques and shale gas discoveries have driven down natural gas prices from an average $7.91 per thousand cubic feet midway through the last decade to $4.37 in the past year. Crude oil now trades at 3.5 times the price of natural gas on an energy-equivalent basis.

And that's not such a bad thing, Armstrong told a capacity audience in the Great Hall of the Allen Chapman Activity Center. Cheaper natural gas pushes up demand, including the fuel's use as a petrochemical feedstock that is more cost-effective than plastic and petchem products made abroad.

In fact, the U.S. now enjoys a $16.4 billion trade surplus in basic chemical and plastics products, Armstrong said. Power generation companies also are replacing coal-fired units with gas-fired operations.

"We really do embrace the concept of low natural gas prices," Armstrong said. "We feel that growth is coming."

Change is certainly almost routine at Williams since Armstrong took over for Steve Malcolm in January. The Tulsa-based company announced the partial IPO and eventual spinoff of its exploration and production side into WPX Energy Inc., and it's also pursuing Houston-based pipeline and utility supplier Southern Union Co. for a possible merger.

Armstrong would not detail the offer for Southern Union since Williams is still in a bidding war with Energy Transfer Equity LP. But he did note that Southern Union's pipeline network and gas utility connections are attractive as power generation shifts toward natural gas.

"We really do believe that power generation markets will continue to expand," Armstrong said.

Energy Transfer Equity currently holds the higher offer at $44.25 per share in stock and cash. Williams, however, has argued that its all-cash bid, at $44 per share, is a better value for Southern Union because of stock market volatility.

The WPX Energy spinoff and IPO offers more immediate benefits locally. Few investors view Williams as a producer despite its top-10 domestic status, so WPX will give a strong, focused option to long-term investors who are not interested in the quarterly distributions promised by fee-based master limited partnerships.

"There really is a revolution going on before us," Armstrong said of the production and processing opportunities awaiting growth-oriented natural gas players.

Williams still would own 80 percent of WPX after the partial IPO, using the maximum $750 million in equity raised to pay down debt and shore up the company's investment-grade status. Williams shareholders would receive the remaining stake in a tax-free spinoff next year.

The final result would be that two of the nation's largest independent pure-play energy companies would both based in Tulsa.

Williams currently employs about 1,300 people in the city. The companywide workforce, including operations in offshore drilling and Canadian off-gas processing and olefins production, stands at about 5,000. Williams Cos. Inc. by the numbers

• 103 years old
• 1,300 employees in Tulsa; 5,000 companywide
• 14 percent of U.S. natural gas consumption moves on its pipelines
• 1.2 billion cubic feet in natural gas produced per day

Copyright (c) 2011 Tulsa World (Tulsa, Okla.)

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Abraxas Looks Ahead to 'Active' 2011 Drilling Program

- Abraxas Looks Ahead to 'Active' 2011 Drilling Program

Tuesday, August 09, 2011
Abraxas Petroleum Corp.

Abraxas provided an operational update and issued production guidance for 2011.

Rocky Mountain – North Dakota / Montana

In McKenzie County, North Dakota, Abraxas drilled the Stenehjem 27-34 1H to a total measured depth of 16,504 feet, including a 5,965 foot lateral in the middle Bakken formation, and completed the well with a 17-stage fracture stimulation. The well was placed on production in late June and in 44 days the well has produced (on a restricted choke) 20,000 barrels of oil, 32.2 MMcf of wellhead gas which yields 2,700 barrels of natural gas liquids and 23.3 MMcf of residue gas for a total of 26,500 barrels of oil equivalent, or an average of 600 barrels of oil equivalent per day. For the past three days, the well averaged 615 barrels of oil equivalent per day on a 21/64-inch choke with 750 psi of flowing pressure. Abraxas owns a 79% working interest in this well.

In various counties in North Dakota and Montana, fourteen non-operated horizontal wells, targeting the Bakken or Three Forks formation, in which Abraxas owns a working interest are currently in progress or recently placed on-line. Seven gross (0.35 net) wells went on production in June or July, three gross (0.08 net) wells have been fracture stimulated and are currently cleaning up, one gross (0.36 net) well is waiting on completion, one gross (0.01 net) well is currently drilling and two gross (0.05 net) wells are waiting on a drilling rig. Since January 2010, Abraxas has elected to participate in 19 gross (1.00 net) non-operated wells in the Bakken / Three Forks play.

In McKenzie County, North Dakota, two gross (0.11 net) non-operated horizontal wells targeting the Mission Canyon have been drilled, completed and are currently waiting on production facilities. Early production testing of these wells has yielded flow rates in excess of 1,000 barrels of oil per day each.

In early July, Abraxas announced the purchase of a drilling rig that is in the process of being refurbished. After completion, the rig will be mobilized to McKenzie County, North Dakota and it is anticipated that the rig will begin drilling on the first pad site in October.

Rocky Mountain - Wyoming

In Campbell and Niobrara Counties, Wyoming, a two well oil development program is scheduled to begin this fall. One of these horizontal wells will target the Niobrara formation and one will target the Turner formation. Abraxas owns a 100% working interest in each of these wells.

South Texas – Eagle Ford

Abraxas currently owns a 41% equity interest in Blue Eagle, a joint venture between Abraxas and Rock Oil Company, LLC. On June 29, 2011, Rock Oil contributed an additional $11 million to the joint venture and Blue Eagle purchased approximately 2,487 net acres in McMullen County, Texas in the oil window of the play.

In DeWitt County, Texas, Blue Eagle's first well, the T-Bird 1H, continues to outperform expectations and is currently producing 930 barrels of oil equivalent per day, which is comprised of 185 barrels of condensate, 300 barrels of natural gas liquids and 2.7 MMcf of residue gas. The well has produced approximately 230,000 barrels of oil equivalent during its first 180 days on production. Blue Eagle owns a 100% working interest in this well.

In DeWitt County, Texas, Blue Eagle participated in a non-operated horizontal well with its 43.9% working interest. The Matejek Gas Unit 1 was drilled to a total measured depth of 17,865 feet, including a 3,600 foot lateral, and completed with a 14-stage fracture stimulation. The well is currently shut-in waiting on pipeline hookup which is expected to be completed later this month.

In Atascosa County, Texas, the Grass Farms 1H is currently drilling the lateral at a total measured depth of 13,150 feet towards a total measured depth of 13,380 feet, including a 6,000 foot lateral. A fracture stimulation date has been secured for this well in September, a month later than originally anticipated. Blue Eagle owns a 100% working interest in this well.

West Texas

In Nolan County, Texas, the Spires 126 2H was drilled to a total measured depth of 9,000 feet, including a 2,000 foot lateral, and completed open hole and un-stimulated. The well was recently placed on-line and during the first 20 days of production, the well averaged 125 barrels of oil equivalent per day, which was comprised of 47 barrels of oil, 46 barrels of natural gas liquids and 210 Mcf of residue gas. Abraxas owns a 100% working interest in this well.

In Coke County, Texas, the Sadie #2A was drilled to a total vertical depth of 6,425 feet and is waiting on completion and the Sadie #1B is currently drilling below 4,600 feet towards a total vertical depth of 6,500 feet. These two delineation wells are targeting the Canyon Sands. Abraxas owns a 100% working interest in these wells.

In Reeves County, Texas, Abraxas previously announced that it acquired an additional 640 net acres, for a total of approximately 3,000 net acres, in the emerging Wolfbone play. Two wells directly adjacent to our acreage are currently being drilled by the industry.

Canada - Pekisko

In Alberta, Canada, the Twining 6-11 was drilled to a total measured depth of 8,900 feet, including a 3,025 foot lateral, and is waiting on completion and the Twining 6-12 recently reached total measured depth of 9,150 feet, including a 3,380 foot lateral. These two wells are targeting the Pekisko formation. Canadian Abraxas owns a 100% working interest in each of these wells.

Guidance

For July, Abraxas produced approximately 4,160 barrels of oil equivalent per day up from an average of 3,845 barrels of oil equivalent per day for the second quarter. Abraxas expects production for 2011 to average 4,000 – 4,200 barrels of oil equivalent per day, including its equity interest share of Blue Eagle's production, which would generate an exit rate for 2011 between 4,700 and 4,900 barrels of oil equivalent per day.

Comments

"We've been busy! It is a refreshing change to get back to a very active drilling program. So far, we are quite pleased with the results of our operated (and non-operated) wells and we hope to continue this success throughout the year. The purchase of the drilling rig will enable us to be quite active in the Williston Basin on an operated basis and in an efficient manner for years to come," commented Bob Watson, Abraxas' President and CEO.

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Egdon Looks Ahead to Markwells Wood-1 Well Test

- Egdon Looks Ahead to Markwells Wood-1 Well Test

Wednesday, August 03, 2011
Egdon Resources plc

Egdon provided an update on its UK operations and production at its year end of July 31, 2011.

Egdon's production during July 2011 from the Keddington, Kirkleatham and Avington fields was 420 barrels of oil equivalent per day ("boepd").

Keddington

At the Keddington Oil Field in Lincolnshire, license PEDL005(remainder) (Egdon 75% interest) the Keddington-4 (K4) well was drilled as a re-entry and horizontal sidetrack from the Keddington-1Z "donor" well during April 2011, and a total of 120 meters of the primary reservoir Unit 1 sandstone was encountered along with 65 meters of Unit 2.

As reported in May the K4 well initially free-flowed oil and gas at maximum rates in excess of 200 barrels of oil per day ("bopd") and 518,000 cubic feet of gas per day with no associated formation water. Following "bleeding- off" of the gas pressure the well was put on pumped production using a down-hole sucker-rod pump and stabilized rates of around 75 bopd along with 200,000 cubic feet of gas per day were achieved by the end of June. Indications are that the pump is operating at low efficiency due to the high gas levels in the produced fluids and that the well is capable of delivering higher oil rates with greater drawdown. Options to resolve this are being investigated.

The Keddington-3z well (K3Z), which had been shut-in since March 2011, was put back on free-flow production, along with continued production from K4, from the beginning of July and total oil rates have steadily increased during the month from 120 to 180 bopd (Net Egdon 135 bopd) as the gas pressure in the well has gradually been "bled-off" in a controlled manner and has been constrained by flaring capacity. Average daily production during July was 158 bopd (Net Egdon 118.5 bopd) and 850,000 cubic feet of gas per day (Net Egdon 106 boepd currently being flared).

To date no formation water has been produced from either K3Z or K4 resulting in a decrease in project operating costs.

We continue to pursue the best options for export of electricity from the site to minimize constraints on oil production and are integrating the results of the K4 well into a field model to enable a reassessment of the ultimate reserves for the field.

Kirkleatham

As previously reported the Kirkleatham gas field in PEDL068 (Egdon 40% interest) achieved first production on April 19, 2011. Following the resolution of a number of residual mechanical and control issues the field has been capable of 24 hour production since mid-May. Availability of the end-user power plant restricted production during June. However, production uptime during July has been high with production averaging 4.24 million cubic feet of gas per day ("mmcfg/d") (Net Egdon 1.7 mmcfg/d or 282 boepd). Levels of H2S have stabilized at 60 parts per million, well below design limitations.

The power plant was shut-in for 7 days for routine maintenance on 30 July during which time down-hole pressure data will be retrieved from the Kirkleatham-4 well for analysis.

It is planned to produce the well at between 3 and 3.5 mmcfg/d (Net Egdon 1.2 to 1.4 mmcfg/d or 200 to 233 boepd) on resumption of production to match expected power output and manage reservoir pressure.

Ceres

The Ceres field in block 47/9c (Egdon 10% interest) is now in a position to produce following completion of repair work on the damaged Eris umbilical and resolution of hydrate issues in the flow lines. The Ceres field was brought back on stream on June 13, 2011 and was produced with some interruptions until June 26, 2011 when the field was shut-in due to annual maintenance at the Cleeton platform. Egdon have been advised that this shut-down is likely to last for a period of around sixty days with the expectation of a restart of sustained production during September 2011. Production occurred over seven days during June 2011 and average net Egdon gas production for the period was 1.6 mmscfg/d (c. 260 boepd).

Waddock Cross

At the Waddock Cross oil discovery in Dorset license PL090 (Egdon 45%), the site is in the final stages of preparation for commencement of an Extended Well Test. Test operations are expected to start within the next two weeks and to continue for a period of up to six months. The intention is to trial a number of techniques aimed at increasing oil production in this high water cut reservoir to enable a decision to be made over a future development of this field which contains significant in place oil reserves.

Markwells Wood

In West Sussex license PEDL126 (Egdon 10%) we have been advised that well test operations at the Markwells Wood-1 oil discovery are due to commence at the end of August, subject to final DECC approval. The test is planned to last a maximum of 40 days and will include acid stimulation of the reservoir. The outcome of the testing will help in determining the commerciality of the well.

Avington

The Avington oil field in Hampshire license PEDL070 (Egdon 26.67% interest following the recently announced sale of 10% interest in the field) continues to produce from the Avington-2z and Avington-3z wells. Net Egdon production for July was 20 bopd.

Dukes Wood/Kirklington

In Nottinghamshire license PEDL118 (Egdon 65% interest) planning consent has been received for oil production at the Dukes Wood-1 well. Egdon are now in the process of securing the environmental permit and DECC field development approval prior to restarting the combined production from Dukes Wood-1 and Kirklington-3Z later in 2011.

PEDL201 Seismic Program

In Leicestershire/Nottinghamshire license PEDL201 (Egdon 50%) Tessla-IMC completed a 19 kilometer 2D seismic program during May 2011 over the Burton on the Wolds Prospect which is located to the south-east of the Rempstone oil field. The processed data is currently being evaluated with a view to a drilling decision during 2012.

PEDL180/182 3D Seismic Program

A contract has recently been signed with Tessla-IMC for the acquisition of a 45 square kilometer 3D seismic survey over the prospective Broughton-Wressle trend in Lincolnshire licenses PEDL180 & PEDL182. On current timing the survey is expected to be completed by the year end.

Commenting on the recent developments, Egdon's Managing Director Mark Abbott said, "We have made further good progress towards our long stated target of 500 boepd and achieved net Egdon production of 420 boepd during July 2011. The resumption of production at Ceres which is currently expected on conclusion of the maintenance shut-down of the Cleeton platform during September, along with the EWT at Waddock Cross should enable us to exceed our production target at this time.

"We also look forward to the commencement of the Markwells Wood-1 well test which will determine if the discovery is commercial."

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McMoran Looks Ahead at Reserve, Production Profile

- McMoran Looks Ahead at Reserve, Production Profile

Tuesday, July 19, 2011
McMoRan Exploration Co.

McMoRan reported a net loss applicable to common stock of $50.2 million, $0.32 per share, for the second quarter of 2011 compared with a net loss of $21.7 million, $0.23 per share, for the second quarter of 2010.

HIGHLIGHTS

• Shallow Water, Ultra-Deep Exploration & Development Activities:
  • Davy Jones No. 2
    • In June 2011, results from wireline logs of the Cretaceous section indicated that the Davy Jones No. 2 well encountered 192 net feet of potential hydrocarbons in the Tuscaloosa and Lower Cretaceous carbonate sections. Flow testing will be required to confirm the potential hydrocarbons and flow rates from these sandstones and limestones.
    • Completion for flow testing expected to commence in the second quarter of 2012.
    • Previous wireline logs confirmed hydrocarbon bearing Wilcox sands seen in the Davy Jones No. 1 discovery well.
  • Blackbeard East
    • Exploration results to date indicate updip potential in the Miocene (178 net feet of hydrocarbons) above 25,000 feet and downdip potential in the Oligocene (Frio) below 30,000 feet.
    • In July 2011, commenced operations to drill a by-pass well at approximately 30,700 feet to evaluate targets in the Eocene.
  • Lafitte
    • Commenced drilling on October 3, 2010, currently below 24,200 feet with a proposed total depth of 29,950 feet. Targeting Miocene and Oligocene objectives.
• Shallow Water, Deep Gas Exploration & Development Activities:
  • Laphroaig No. 2
    • Production commenced in April 2011 and averaged a gross rate of approximately 50 million cubic feet of natural gas equivalents per day (MMcfe/d) (15 MMcfe/d net to McMoRan) in May and June of 2011.
• Boudin
  • Exploratory well commenced drilling on February 27, 2011 and is drilling below 19,350 feet towards a proposed total depth of 23,100 feet.
• Second-quarter 2011 production averaged 197 MMcfe/d net to McMoRan, compared with 165 MMcfe/d in the second quarter of 2010.
• Average daily production for 2011 is expected to approximate 185 MMcfe/d net to McMoRan, including 180 MMcfe/d in third quarter 2011.
• Operating cash flows totaled $102.6 million for the second quarter of 2011, including working capital sources of $28.4 million and $20.0 million in abandonment expenditures.
• Capital expenditures totaled $162.4 million in the second quarter of 2011 and $258.9 million for the six months ended June 30, 2011.
• Cash at June 30, 2011 totaled $765.3 million.

James R. Moffett and Richard Adkerson, McMoRan's Co-Chairmen, said, "The data gained to date from our ultra-deep drilling program in the shallow waters of the Gulf of Mexico add to our enthusiasm for the resource potential of this important new geologic trend. Through our drilling activities, we have confirmed the potential for large hydrocarbon bearing structures below salt in the Miocene, Wilcox, Frio, Tuscaloosa and Cretaceous Carbonate formations. Our ongoing exploration drilling and flow testing of the Davy Jones wells in the coming months have the potential to enhance our reserve and production profile meaningfully."

PRODUCTION AND DEVELOPMENT ACTIVITIES

Second-quarter 2011 production averaged 197 MMcfe/d net to McMoRan, compared with 165 MMcfe/d in the second quarter of 2010. Production in the second quarter of 2011 was higher than McMoRan's previously reported estimates of 190 MMcfe/d in April 2011 because of favorable production performance. Production is expected to average approximately 180 MMcfe/d in the third quarter of 2011 and 185 MMcfe/d for the year, higher than the previous 2011 annual estimate of 175 MMcfe/d. McMoRan's estimated production rates are dependent on the timing of planned recompletions, production performance, weather and other factors.

Production from the Flatrock field averaged a gross rate of approximately 172 MMcfe/d (70 MMcfe/d net to McMoRan) in the second quarter of 2011. McMoRan owns a 55.0 percent working interest and a 41.3 percent net revenue interest in the Flatrock field.

As previously reported, McMoRan successfully commenced production from the Laphroaig No. 2 well in St. Mary Parish, Louisiana in late April 2011. Production from the Laphroaig No. 2 well averaged a gross rate of approximately 50 MMcfe/d (15 MMcfe/d net to McMoRan) in May and June of 2011. McMoRan owns a 38.4 percent working interest and a 29.5 percent net revenue interest in the Laphroaig No. 2 well. Energy XXI (NASDAQ:EXXI - News) holds an 18.8 percent working interest.

As previously reported, the Brazos A-23 development well commenced drilling on February 13, 2011, and was drilled to a total depth of 15,946 feet. This traditional Shelf well targeted proved undeveloped reserves updip from logged pay zones. Log evaluation indicated that the well encountered 30 net feet of hydrocarbon bearing sands and a protective liner has been set. The well has been temporarily abandoned while future plans are developed. McMoRan owns a 100.0 percent working interest and an 81.25 percent net revenue interest in the well. McMoRan recorded a $23.8 million impairment charge in the second quarter to reduce the carrying value of the Brazos A-23 well to $17.4 million.

EXPLORATION ACTIVITIES

McMoRan's exploration strategy is focused in the shallow waters of the Gulf of Mexico (GOM) and Gulf Coast area on the "ultra-deep gas play" and on the "deep gas play."

Shallow Water, Ultra-Deep Exploration Update

Since 2008, McMoRan has actively pursued large ultra-deep targets located in the shallow waters of the GOM below the salt weld (i.e. listric fault) at depths generally below 25,000 feet. The data gained to date from four wells confirm McMoRan's geologic model and the highly prospective nature of this emerging geologic trend. Prior to McMoRan's involvement in the ultra-deep, there had been only two wells drilled on the Shelf targeting these objectives; one did not reach its targeted depth and the other was outside McMoRan's focus area. McMoRan's results to date have indicated the potential for large accumulations of hydrocarbons at these deeper depths in the shallow waters of the GOM.

McMoRan's activities to date have confirmed that drilling below the salt weld on the Shelf of the GOM can be achieved safely. In addition, the data indicate the presence below the salt weld of geologic formations including Middle/Lower Miocene, Wilcox, Frio, Tuscaloosa and Cretaceous carbonate. These formations have been prolific onshore, in the deepwater GOM and in international locations. McMoRan is encouraged by the results which indicate the potential for prospects with high quality reservoirs on large structures with multi-Tcfe of gross unrisked potential. McMoRan intends to conduct further drilling and flow testing to determine the ultimate potential of this emerging geologic trend.

The Davy Jones offset appraisal well (Davy Jones No. 2), located on South Marsh Island Block 234 two and a half miles southwest of the Davy Jones No. 1 discovery well, was drilled to a total depth of 30,546 feet. Log results above 27,300 feet confirmed 120 net feet of hydrocarbon bearing Wilcox sands, indicating continuity across the major structural features of the Davy Jones prospect.

In June 2011, results from wireline logs of the Cretaceous section below 27,300 feet indicated that the Davy Jones No. 2 well encountered 192 net feet of potential hydrocarbons in the Tuscaloosa and Lower Cretaceous carbonate sections. Flow testing will be required to confirm the potential hydrocarbons and flow rates. A 6 5/8 inch production liner has been set to 30,511 feet and the well has been temporarily abandoned. McMoRan is evaluating development options and expects to commence completion of the No. 2 well for flow testing in the second quarter of 2012. McMoRan is also considering updip locations in a subsequent well to the north to evaluate the Tuscaloosa sands and Lower Cretaceous carbonates higher on the Davy Jones structure.

The Tuscaloosa sands are correlative with the prolific Tuscaloosa trend onshore South Louisiana and the carbonate section may be analogous to productive fields located offshore and onshore Mexico in the southern GOM. These potential hydrocarbon bearing zones are the first Cretaceous sandstones and limestones encountered offshore Central Louisiana on the GOM Shelf. McMoRan believes the combination of productive Wilcox and Cretaceous intervals on the same structure could enhance the value of Davy Jones and the prospectivity of McMoRan's other ultra-deep prospects on its acreage position within the Davy Jones trend.

As previously reported, in January 2010 McMoRan logged 200 net feet of pay in multiple Wilcox sands in the Davy Jones No. 1 well on South Marsh Island Block 230. In March 2010, a production liner was set and the well was temporarily abandoned to prepare for completion. McMoRan is preparing to complete and flow test the No. 1 well in late 2011.

Davy Jones involves a large ultra-deep structure encompassing four OCS lease blocks (20,000 acres). McMoRan holds a 60.4 percent working interest and a 47.9 percent net revenue interest in Davy Jones. Other working interest owners in Davy Jones include: Energy XXI (15.8%), JX Nippon Oil Exploration (U.S.A.) Limited (12%), Moncrief Offshore LLC (8.8%) and a private investor (3%). McMoRan's total investment in Davy Jones, a substantial majority of which is associated with allocated costs associated with the PXP property acquisition, totaled $619.4 million at June 30, 2011.

In July 2011, McMoRan commenced operations to drill a by-pass of the Blackbeard East ultra-deep exploration well at approximately 30,700 feet to evaluate targets in the Eocene. The well is permitted to 34,000 feet. Based on interpretations of drilling data obtained in the first quarter of 2011 prior to the mechanical issue, McMoRan believes the well encountered Sparta sands in the Eocene, which are younger than the Wilcox. Sparta sands are productive onshore in South Louisiana. Wireline logs will be required to evaluate this interval.

As reported in January 2011, wireline logs indicated that Blackbeard East encountered hydrocarbon bearing sands in the Oligocene (Frio) with good porosity below 30,000 feet. McMoRan is considering down dip drilling opportunities on the flanks of the structure to evaluate this section further. This is the first hydrocarbon bearing Frio sand encountered either on the GOM Shelf or in the deepwater offshore Louisiana. The Frio sand section below 30,000 feet is in addition to the 178 net feet of hydrocarbons in the Miocene sands above 25,000 feet announced in December 2010 at Blackbeard East. Pressure and temperature data below the salt weld between 19,500 feet and 24,600 feet at Blackbeard East indicate that a completion at these depths could utilize conventional equipment and technologies.

Blackbeard East is located in 80 feet of water on South Timbalier Block 144. McMoRan holds a 70.0 percent working interest and a 56.2 percent net revenue interest in the well. Other working interest owners in Blackbeard East include: EXXI (18.0%), Moncrief Offshore LLC (10.0%) and a private investor (2.0%). McMoRan's total investment in Blackbeard East, which includes allocated costs associated with the PXP property acquisition, totaled $216.1 million at June 30, 2011.

The Lafitte ultra-deep exploration well commenced drilling on October 3, 2010 and is currently drilling below 24,200 feet towards a proposed total depth of 29,950 feet. Lafitte is located on Eugene Island Block 223 in 140 feet of water. The well is targeting Miocene objectives and possibly Oligocene (Frio) sections below the salt weld. McMoRan holds a 72.0 percent working interest and 58.3 percent net revenue interest in Lafitte. Other working interest owners in Lafitte include: EXXI (18.0%), and Moncrief Offshore LLC (10.0%). McMoRan's total investment in Lafitte, which includes allocated costs associated with the PXP property acquisition, totaled $100.2 million at June 30, 2011.

Information gained from the Blackbeard East and Lafitte wells is expected to assist McMoRan in developing plans for future operations at Blackbeard West. As previously reported, the Blackbeard West ultra-deep exploratory well on South Timbalier Block 168 was drilled to 32,997 feet in 2008. Logs indicated four potential hydrocarbon bearing zones that require further evaluation and the well was temporarily abandoned. McMoRan is evaluating whether to drill deeper at Blackbeard West, drill an offset location or complete the well to test the existing zones.

McMoRan has also identified a new location within the Blackbeard West unit on Ship Shoal Block 188 to evaluate the Miocene age sands seen in Blackbeard East above 25,000 feet. McMoRan is developing plans to commence drilling this ultra-deep well, which has a proposed total depth of 26,000 feet, in the second half of 2011. The Ship Shoal Block 188 location is approximately 4 miles west of the Blackbeard West #1 well on South Timbalier Block 168. McMoRan holds a 67.3 percent working interest and 51.5 percent net revenue interest in the Blackbeard West well on Ship Shoal Block 188. McMoRan's total investment in Blackbeard West, which includes allocated costs associated with the PXP property acquisition, totaled $58.9 million at June 30, 2011.

Shallow Water, Deep Gas Exploration Update

In addition to the ultra-deep play on the Shelf of the GOM, McMoRan's exploration strategy is also focused on the "deep gas play." Deep gas prospects target large Miocene age deposits above the salt weld (i.e. listric fault) at depths typically between 15,000 to 25,000 feet.

The Boudin deep gas exploration well commenced drilling on February 27, 2011 and is drilling below 19,350 feet. Boudin, which is located in 20 feet of water on Eugene Island Block 26, has a proposed total depth of 23,100 feet and will test Miocene objectives. McMoRan holds a 53.5 percent working interest and a 42.4 percent net revenue interest in Boudin. EXXI holds a 20.6 percent working interest. McMoRan's total investment in Boudin, which includes allocated costs associated with the PXP property acquisition, totaled $49.1 million at June 30, 2011.

The Hurricane Deep well, which is located in 12 feet of water on South Marsh Island Block 217, was drilled to a true vertical depth of 21,378 feet in July 2011. Log results indicated the presence of Operc and Gyro sands that McMoRan determined could be pursued in an updip location. The well is being temporarily abandoned to preserve the wellbore and McMoRan is evaluating opportunities to sidetrack or deepen. McMoRan's total investment in Hurricane Deep, which includes allocated costs associated with the PXP property acquisition, totaled $54.5 million at June 30, 2011. McMoRan's investment is expected to be reduced by approximately $11 million for reimbursable costs associated with its insurance programs.

Second-quarter 2011 exploration expense includes $36.8 million in costs for the previously reported noncommercial well at Blueberry Hill.

REVENUES

McMoRan's second-quarter 2011 oil and gas revenues totaled $155.5 million, compared to $104.1 million during the second quarter of 2010. During the second quarter of 2011, McMoRan's sales volumes totaled 11.6 Bcf of gas, 778,400 barrels of oil and condensate and 1.6 Bcfe of plant products, compared to 9.8 Bcf of gas, 626,400 barrels of oil and condensate and 1.4 Bcfe of plant products in the second quarter of 2010. McMoRan's second-quarter comparable average realizations for gas were $4.71 per thousand cubic feet (Mcf) in 2011 and $4.66 per Mcf in 2010; for oil and condensate McMoRan received an average of $109.08 per barrel in second-quarter 2011 compared to $76.20 per barrel in second-quarter 2010.

CASH, LIQUIDITY AND CAPITAL EXPENDITURES

At June 30, 2011, McMoRan had $765.3 million in cash. Total debt was $561.0 million at June 30, 2011, including $74.7 million in Convertible Senior Notes due in October 2011 with a conversion price of $16.575 per share and $186.3 million in Convertible Senior Notes due in December 2017 with a conversion price of $16.00 per share. On June 30, 2011, McMoRan entered into a new five-year, $150 million senior secured revolving credit facility, which replaced the revolving credit facility that was scheduled to mature in August 2012. McMoRan had no borrowings and $100 million of letters of credit issued under its revolving credit facility resulting in total availability of $50 million at June 30, 2011.

Capital expenditures totaled $162.4 million for the second quarter of 2011 and $258.9 million for the six-months ended June 30, 2011. McMoRan expects 2011 capital expenditures to approximate $500 million, including $300 million for exploration and $200 million for development. Capital spending will continue to be driven by opportunities, drilling results and follow-on development activities.

Net abandonment expenditures, which include scheduled conventional and hurricane-related work, totaled $20.0 million for the second quarter of 2011 and $42.2 million for the six-months ended June 30, 2011. Abandonment expenditures are expected to approximate $160 million in 2011.

In the second quarter of 2011, McMoRan recorded $12.9 million in gains for reimbursable costs associated with its insurance programs. Since 2009, McMoRan has recorded $92.9 million in gains associated with the 2008 hurricane events in the GOM and continues to pursue reimbursement of certain hurricane-related abandonment costs under its insurance programs.

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Premier Looks Ahead to Next Stage of Growth

- Premier Looks Ahead to Next Stage of Growth

Tuesday, July 12, 2011
Premier Oil plc

Premier provided a trading and operations update ahead of its 2011 Interim Results.

Simon Lockett, Chief Executive, commented, "With continuing good progress on our Asian development projects we expect to see a significant increase in production to around 60 kboepd by year end. Our development teams in the North Sea and Asia are already focused on delivering the next stage of Premier's growth. Our exploration program of around 20 wells over the next 12 months targets around 300 mmboe of unrisked prospective potential."

Production outlook

2011 to date has seen continuing good production performance from the Anoa field in Indonesia, while Pakistan's production has remained steady. This was offset by increased maintenance activity in the UK and a recent unplanned shutdown at Balmoral. As a result, estimated average group production for the first half of 2011 was 36.6 thousand barrels of oil equivalent (kboepd) (2010: 42.8 kboepd) and forecast full year production is now estimated at between 40 kboepd and 45 kboepd.

Near term developments in Asia (Chim Sao and Gajah Baru) are progressing well and 2011 year end run rate is expected to be around 60 kboepd as these projects ramp up. With the UK Huntington and Rochelle projects due on-stream next year, Premier is on target to reach a run rate of 75 kboepd in 2012. Our medium term target of 100 kboepd remains unchanged.

Singapore gas demand continues to grow for our gas exports from the Natuna Sea, with average gas sales under the West Natuna gas contract of 373 bbtud in the first half of 2011 compared to 357 bbtud in the second half of 2010. Block A's share of the contract amounted to 41 percent in the period (against a contractual share of 37 percent), though with a recovery in output from the other two PSC's participating in the contract, actual levels of production reduced from the prior period. Premier's production levels will rise in the second half of the year as the Gajah Baru development contributes from October.

In the UK, production was below expectations due to maintenance related downtime earlier in the year at the Balmoral and Wytch Farm facilities and a recent unplanned shutdown at Balmoral due to a subsea hydraulic leak. Production resumed at Balmoral on 4 July after a three week outage. Scott and Telford production has remained steady since April following earlier disruptions for gas compression maintenance.

As announced in June, Premier increased its stake in the Wytch Farm Assets by 17.715 percent. This is expected to add around 2.5 kboepd to Premier's UK production from year end 2011 when the transaction is targeted for completion. Following the shutdown in the first quarter, production at the Wytch Farm facilities has been rising in recent weeks to around 14 kboepd (gross).

Pakistan production is stable, with the natural decline in the fields offset by infill drilling and the completion of ongoing front-end compression projects. The successful K-18 sidetrack well on Kadanwari, which came on-stream in February 2011, continues to perform favorably. Delays in the front-end compression project at Zamzama are being resolved and increased production is anticipated imminently.

Current and future developments

Asia

In Vietnam, the Chim Sao project remains on schedule with first oil expected in August. On July 1, the FPSO moved from the Keppel yard to its offshore anchorage where deep water commissioning and trials were completed. The FPSO is now on tow to the Chim Sao field for the installation of the umbilicals that will connect it to the production wells.

The Gajah Baru project in Indonesia is progressing ahead of schedule. The Central Processing Platform topsides were installed on the jacket on July 6 and the bridge linking this to the wellhead platform was installed on July 7. Elsewhere on Block A, EPCI technical bids have been received and are under evaluation for the Anoa Phase 4 Development which will add additional compression capacity on the Anoa platform. In addition, the Front End Engineering and Design has been completed for the facilities and pipelines for the Pelikan and Naga fields. These projects are on target for sanction in the fourth quarter of 2011.

In North Sumatra, discussions with the shortlisted facilities EPCI bidders are under way. Technical bids are due in by September and final contract award is expected by year end. First gas on Block A Aceh remains on target for late 2013.

North Sea

The Huntington development in the UK is progressing, with work continuing on the Sevan Voyager FPSO upgrade project and sub-contracted modules. Timing for sail away (and therefore first oil) is likely to be impacted by the current financial situation of the FPSO supplier. Any material delay in the Huntington project will impact the average production for 2012 and the date at which a run-rate of 75 kboepd is achieved. In the meantime, key subsea equipment is on order and an installation contract has been signed. Development drilling commenced in April and is proceeding well.

An agreement for the Rochelle area has been executed with Premier acquiring a 15 percent equity in the unitised East and West Rochelle projects. First gas is anticipated for the fourth quarter of 2012. As previously announced, a Sale and Purchase Agreement for the Solan field was signed in May and Premier will become the development operator of the field at sanction with a 60 percent equity interest. Pre-sanction activities are progressing with final project approval targeted for later this year.

Development concept selection for Fyne is expected by year end, after the East Fyne appraisal well has been drilled. Discussions are ongoing with partners regarding potential development solutions for the Catcher Area. In Norway, development plans for the Froy field received Premier support for moving to the next phase. However, the operator has indicated that, due to limited resources and commitments elsewhere, they will not be proceeding with the project at this time. As a result, discussions with third party new entrants to the Froy project are underway. Dialogue also continues with the preferred contractor for the Bream field development regarding the timing of the FPSO availability.

Exploration and appraisal

Around 20 exploration and appraisal wells are planned during the next 12 months, with unrisked net prospective resource potential, on a P50 basis, of around 300 mmboe. Several of the planned wells for the first half of 2012 remain subject to partner approvals and government consents.

North Sea

As previously announced, the Grosbeak well in Norway was spudded in April 2011 and has now been sidetracked. The results of the sidetrack, which reached target depth on July 7, are anticipated later in July. Premier plans to drill its first operated well in Norway, the Gardrofa exploration well, in the third quarter of 2011.

Premier has signed a Heads of Agreement (HOA) with Antrim Energy to gain additional acreage in the Greater Fyne Area. Under the HOA, Premier will earn a 50 percent working interest in the acreage in return for funding a promoted share of the costs to drill a well on the Erne Prospect, which is planned for the third quarter. The Erne well will target an Eocene Tay Formation oil prospect located between the Fyne and Guillemot NW fields in the UK Central North Sea. A successful Erne exploration well will be taken into account for the Fyne development concept selection targeted for year end.

Separately the East Fyne appraisal well is now planned for the fourth quarter, using the Sedco 704 semi-submersible rig, the results of which - along with the results of the Erne exploration well - will feed into the Fyne development concept process. The Sedco 704 will then move to spud the Bluebell well, a prospect near to the Premier-operated Caledonia field and the Balmoral facility.

The Stingray well (Premier interest, 50 percent), which is scheduled for the first half of 2012, is targeting a Jurassic sandstone reservoir in UK Block 15/13b. In UK Block 28/9, the Joint Venture partners have decided to acquire 3D seismic data over the block in the second half of 2011. As a result, the Carnaby well will now be drilled in the first half of 2012.

Asia

In Indonesia, on the Tuna Block, Gajah Laut Utara was plugged and abandoned in June with oil and gas shows. The Ocean General Rig has now moved to Belut Laut, which spudded on 4 July. The Belut Laut prospect is in a separate sub-basin to that of Gajah Laut Utara and is an independent test of the petroleum system on the Tuna acreage. The results of Belut Laut are expected in August.

Elsewhere in Indonesia the Benteng-1 well on the Buton licence is expected to be drilled in the first quarter of 2012. The Matang-1 well on Block A Aceh is also scheduled to be drilled in the first quarter of 2012. The Antareja Resources land rig, Antareja-8, has been contracted for Matang-1.

Pakistan

As previously announced, the K-27 exploration well was successful and will be tied back to the production facility by the end of the third quarter, delivering around 30 MMscfd (gross). The K-29 and K-30 exploration wells, together with Badhra-6 Parh, are planned for late 2011.

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San Leon Looks Ahead to Polish Drilling Programs

- San Leon Looks Ahead to Polish Drilling Programs

Thursday, June 23, 2011
San Leon Energy plc

San Leon provided the following Operational Update.

Poland - Exploration program continues as planned

• Interpretation and prospect evaluation is ongoing in Szczecinek Block 106 (San leon 50%). San Leon and its partner, Gas Plus, are looking at further studies including a regional core study to evaluate the paleogeography and continued evaluation of the newly acquired 3D survey. Gas Plus, the operator of the license, are likely to delay drilling until 2012 (from 3Q 2011) due to internal planning considerations.
• The Baltic Basic 2D seismic program, over the Gdansk W, Braniewo and Szczawno Concessions, was completed in June 2011. The Company successfully acquired 480 km of 2D data. The program was completed with a perfect HSE (Health, Safety and Environment) performance. A drilling rig has been booked for August 1, 2011, which will be used to drill three back-to-back wells.
• Geofizyka Krakow completed 120 km of high quality 2D seismic over the Company's 100% owned Nida Concession in May 2011. The data has been interpreted and confirmed three high potential structures on trend with the prolific Grobla and Plowice oil fields. A San Leon subsidiary, Vabush Energy, plans to drill two of these prospects commencing in July/August 2011.
• Acoustic Geophysical has started the acquisition of 165 km2 of 3D seismic on the Company's 100% owned Nowa Sol Concession. The survey is currently c.20% complete and is seeking to delineate numerous prospects and leads along the southern Fore Sudetic Monocline of the Permian Basin. This survey is designed to support an upcoming drilling campaign in the Nowa Sol Concession which is currently planned to start in 4Q 2011.
• Work is ongoing in the Carboniferous shale play across the Wschowa, Gora, Winsko and Rawicz Concessions (San Leon 100%). The Company continues to evaluate the existing core and well data in preparation for the first exploration well in the area which is planned for 4Q 2011. Core analysis is being performed by TerraTek (Schlumberger) and the Polish Oil & Gas Institute in Krakow. Petrophysics on the existing well logs has been performed by NuTech.

Morocco

• The Tarfaya Oil Shale pilot project is well advanced.
• The base camp has been constructed and all operational personnel are on site with all communications systems in place.
• The pilot plant site construction and the assembly of the process equipment has been completed.
• Two wells have been drilled at a distance of 10 meters apart confirming the presence of 30 meters of prospective oil shale at a depth of 195 meters. This is slightly thicker than the original prognosis. The initial model provided by ONHYM (Morocco National Office of Hydrocarbons and Mines) has also been confirmed by the well logs.
• A pre frac injection test with water was applied to collect data concerning the natural connectivity between the two wells and was followed by a mini hydro frac. This was unable to establish connectivity between the wells.
• Initial analysis of these tests has suggested the presence of natural fractures in the shale. San Leon is encouraged by the possibility of these natural fractures which could enhance the propagation of heated gas throughout the prospective intervals.
• The Company is re-evaluating the technical program to incorporate the new data gained from these tests into its model for commercial extraction of oil from the Tarfaya Shale.
• The Company plans to drill a third test well using the same rig in August 2011. Core data will be collected, from this well, in order to evaluate the local geologic parameters of the prospective shale interval as well as the presence and orientation of any natural fractures at the pilot location. Following the drilling of the third well, San Leon will again perform a small frac on the shale to establish connectivity between the wells. Based upon these results injection tests will be designed to take advantage of the fractures.
• Upon successful flow testing with water, followed by nitrogen, propane will subsequently be brought to the pilot plant to test the process of heating the shale with natural gas.
• San Leon's new seismic acquisition subsidiary, NovaSeis, is up and running in Morocco. NovaSeis plans to start the acquisition of 1,200 km of 2D seismic in its Tarfaya and Zag Licenses by July 1, 2011.
• Full re-interpretation of the seismic data on the offshore Foum Draa and Sidi Moussa Licenses is near completion. Once this is successful, the Company is likely to seek farm-in partners for drilling.

Ireland

• Following the Company's acquisition of Island Oil & Gas plc, San Leon continues to appraise its high impact Atlantic Margin assets and is seeking farm-in partners.
• San Leon completed a 250 km2 3D seismic survey on the North Porcupine License (FEL 1/04) in May 2011. The offshore survey was designed to evaluate the highly prospective C1 Lead. PGS Exploration UK Limited was contracted to carry out the survey using the M/V Ramform Vanguard. San Leon has a seismic services agreement with PGS Ventures AS, who is providing a US $50m facility for seismic services, part of which was used for this survey. We expect to finalize the data processing contractor(s) in the coming weeks. Seismic processing is expected to be complete in early 4Q 2011.
• The Company continues to interpret the 300 km2 Slyne License (FEL 4/06) 3D survey. Delays in processing and interpretations are the result of very complex structural issues and significant surface volcanics which have made imaging some areas of the survey very difficult. The initial interpretation is encouraging and the Company plans to open a data room in August/September 2011.
• Following the completion of the assignment of OMV's 50% interest in Rockall License (FEL 3/05) to San Leon in March 2011, the Company had insufficient time to secure a seismic survey vessel for the license in Summer 2011. San Leon expects to apply to the Irish Government for a license extension.
• The company is also considering several options for data acquisition/analysis of the South Porcupine License (FEL 3/08) including 2D/3D seismic and controlled source electro magnetic data acquisition with a view to seeking a farm-in partner to the license.
• 3D seismic acquisition operations have commenced on Barryroe Licensing Option (08/01) in the north Celtic Sea, offshore Ireland. Polarcus has been contracted to carry out a 220 km2 survey, which is expected to be completed by the end of June.

Albania

• The 840 km2 Durresi Block 3D seismic acquisition survey was completed in April 2011. The data is currently being processed by Western Geophysical in London, who are expected to deliver the final processed data in early 4Q 2011. Parallel interpretation and prospect generation will continue in the interim.
• The 3D seismic program will evaluate a number of highly prospective structures in the Block, including the A4-1X discovery, in preparation for a planned 2012 exploration and appraisal drilling program.

Netherlands

• GDF Suez E&P Nederland B.V, the new 50% owner in the Amstel Field, offshore Netherlands, has successfully completed the drilling of an appraisal well on March 29, 2011. The partners are currently evaluating a development plan for the oil field, in which San Leon Energy holds a 2.5% royalty.

Italy

• San Leon has notified the Italian authorities that it is relinquishing two offshore Sicily permits. The Company has made the decision following the publication of a new Italian Environmental Law in June 2010 which placed tighter restrictions on oil and gas exploration within five nautical miles of the coast and twelve nautical miles of any protected environmental area. In effect, San Leon would not have gained an environmental authorization to drill exploration or appraisal wells in two permit areas, D.352 CR-SL (Narciso) and D.354 CR-SL (Sciacca). The relinquishment will become effective upon publication of a notice in the official Italian Ministerial Gazette, B.U.I.G.. San Leon will continue to retain D.353 CR-SL (Narciso South) and its two onshore Po Valley assets Sorbolo and Sospiro.

Oisin Fanning, Chairman of San Leon Energy commented, "We continue to make steady progress and meet our objectives as we move from seismic acquisition to drilling on many of our licenses. The completion of three seismic acquisition programs in Poland, particularly the 2D seismic acquisition in the Baltic Basin, and the start of another program on our Nowa Sol Concession mean our shareholders can now look forward to drilling these prospects over the coming months.

Furthermore, our new seismic acquisition company, Novaseis, is about to begin the first of two seismic acquisition programs in Morocco and this follows the successful completion of our offshore Albania and Atlantic Margin Ireland surveys.

The Company's operational and technical capacity continues to grow in line with our increasing activity, particularly in Poland, where our knowledge base and expertise is geared towards delivering near term value for our shareholders."

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Europa O&G Looks Ahead at 2011 Exploration

- Europa O&G Looks Ahead at 2011 Exploration

Friday, June 10, 2011
Europa O&G Holdings plc

Europa provided an Operational Update outlining activity planned for the remainder of 2011 and into 2012.

Production

Since the operational and weather related issues reported in early March, group production has increased some 100% to a current average of 260 bopd. Gross revenues are currently running at $750,000 per month.

West Firsby-9 is currently on jet pump production from Zone 1 and is producing an estimated 50 bopd. Previously, Zone 2 produced at an estimated average of 50 bopd. West Firsby-7 Zone 1 has been producing approximately 90 bopd for the last 2 weeks with an estimated water cut of 75%, a strong improvement on previous performance before re-perforation.

There is significant potential for additional production from Crosby Warren by repeating the highly successful 1987 stimulation of Crosby Warren-1. This is planned for August and is anticipated to provide incremental production of between 50 and 150 bopd.

Appraisal

The Romanian appraisal well Voitinel-2, anticipated to be spudded in September, is to be a relatively conservative appraisal stepout to prove up to 35 bcf of gas-in-place which would allow for the initiation of a pilot production project for the northern part of Voitinel.

A second appraisal-exploration well, likely to be on the Solca Prospect, situated between the Voitinel and Paltinu gas discoveries and designed to test the upside in the Voitinel trend play, is expected to be drilled in early 2012.

On Europa's flagship appraisal project, Berenx, work has been underway for several weeks on the engineering design for a Berenx-3 appraisal well in late 2012/early 2013. In the meantime, the highly encouraging results from the recent CGGV processing of the Lacq Ouest 3D volume has given sufficient encouragement to acquire additional 3D data over the western part of the Berenx structure. It is anticipated this survey will be acquired in 4Q 2011 with a view to maturing contingent resource numbers and choosing a firm well location by 2Q 2012.

Exploration

With regard to UK exploration, Europa, Egdon Resources and Celtique Energie have agreed, subject to DECC approval, to equalize working interests across contiguous licenses PEDL180 and PEDL182, situated to the south and east of Crosby Warren. This will increase Europa's overall exposure to the play, including the Broughton oil discovery and a joint 3D seismic survey planned for later in 2011 will firm up drilling plans for the licenses.

Following the decision by the Surrey Planning Committee to overturn the County Planning Officer's recommendation to allow exploration drilling at Holmwood, the Company has consulted counsel and in the light of their comments and partners' support to appeal the decision, the intention is to move forward with this process. Further updates will be provided in due course.

In Romania, the Company has lodged the required documentation with the government agency to appraise the Barchiz-1 oil discovery well by deepening it to up to 2,500m in order to penetrate the anticipated repeat section of the Oligocene Sandstone reservoir encountered in nearby wells. The Barchiz Prospect therefore remains only partially tested due to the premature cessation of drilling operations at 1,450m following technical problems. It is hoped that approval will be given shortly and that the well can be deepened in October.

A program of 2D seismic acquisition is planned for the coming months in the Brodina and Cuejdiu licenses in the East Carpathian oil play. It is hoped that these additional surveys, totaling approximately 200km, will provide a well location for 2012.

Paul Barrett, Managing Director of Europa, said, "This update demonstrates our strong conveyor belt of appraisal and exploration projects for the remainder of 2011 and beyond. The plan for the next 18 months is shaping up to see the Company firstly drill up to 3 exploration wells with net resource potential of up to 48 MMbo, secondly to appraise up to 80 bcf net contingent resource and thirdly to be in a position to drill a well on a 1.7TCF potential net resource onshore France."

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Bucks County Republican Looks for Sponsor on Shale Fee

- Bucks County Republican Looks for Sponsor on Shale Fee

Thursday, June 09, 2011
Knight Ridder/Tribune Business News
by Brad Bumsted, The Pittsburgh Tribune-Review

A Bucks County Republican is asking legislators to co-sponsor her shale impact fee which she says is designed to try to win GOP Gov. Tom Corbett's approval.

Corbett has said any measure must be a fee and not a tax and the main purpose must be to help compensate municipalities for damages gas drilling causes. He has said revenue from a fee should not go into the state's General Fund.

For starters, Rep. Marguerite Quinn says her proposal is a fee. It is not based on gas well production nor is it tied to the price of natural gas like a half-dozen or so tax proposals pending in the House and Senate, she said. It's a flat rate on a declining scale, starting at $50,000 per well.

While the state Department of Revenue would collect the fee, the revenue would not go into the General Fund, Quinn told colleagues in a memo seeking co-sponsorship.

"I've been working on it -- something that does meet the governor's criteria," Quinn said today. "I tried to respect the governor's call for no tax. I made it a simple impact fee."

Asked about Quinn's proposal, Kevin Harley, Corbett's spokesman was non-committal. "Gov. Corbett has said he is open to an impact fee. But he wants to wait until his Marcellus Shale Advisory Commission issues a report."

The commission, headed by Lt. Gov. Jim Cawley, is attempting to quantify local drilling costs. The report will be issued July 22 while lawmakers are likely on summer recess after adopting a state budget by June 30.

Quinn said she plans to meet with Cawley to outline her proposal.

Under Quinn's proposal, half of the revenue would be deposited into an "impact mitigation fund" for use by counties and municipalities hosting drilling. That would cover fire, police and emergency service costs, as well local water issues, and repairing roads and bridges.

Twenty-five percent of money would go for statewide environmental projects and hazardous waste cleanup. The money would go to a state fund for environmental use called Growing Greener. It would be used for projects such as watershed protection, acid mine drainage abatement and cleanup and plugging of wells.

And 20 percent of the revenue would go to the state Motor License fund for road and bridge repairs. Five percent would go to local conservation districts.

Quinn says she is calling her plan a fee on shale, not Marcellus shale. The point is to cover drilling in deeper layers beneath the Marcellus shale formation such as the Utica formation.

"We don't want to be shortsighted in structuring this and have to re-invent the wheel later," she said.

Copyright (c) 2011, The Pittsburgh Tribune-Review

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Greece Looks to Open South Gas Corridor Via ITGO Project

- Greece Looks to Open South Gas Corridor Via ITGO Project

Thursday, June 02, 2011
Knight Ridder/Tribune Business News
by A. Badalova, Trend News Agency, Baku, Azerbaijan

The Turkey-Greece-Italy gas pipeline must act as the starting point for the South Gas Corridor for gas supplies from the Caspian region to Europe, Greek Environment Minister Tina Birbili said at a meeting with BP senior representatives, Athens News reported.

Birbili later said after there are additional volumes of gas, other pipelines will be connected.

This position was voiced by the Greek environment minister during a meeting with BP Vice President Alasdair Cook.

Gas produced within the second stage of Shah Deniz's development is regarded as the main source, not only for ITGI project.

The peak production is forecasted at over 9 billion cubic meters and 50,000 barrels of condensate. According to the forecasts, gas production can be brought up to 24 billion cubic meters a year within the second stage of field development.

Shah Deniz reserves are estimated at approximately 1.2 trillion cubic meters of gas.

First gas is expected to be received within the second stage of field development in 2017.

ITGI Transport Corridor includes the renovated Turkish pipeline infrastructure, as well as ITG projects and IGI. Edison (Italy) and Depa (Greece) established IGI Poseidon SA for the design and construction of IGI pipeline, known as Poseidon.

Copyright (c) 2011, Trend News Agency, Baku, Azerbaijan

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California Oil Industry Looks to Replenish Ranks

California Oil Industry Looks to Replenish Ranks

Wednesday, April 06, 2011
The Bakersfield Californian

by  John Cox

The upturn in oil prices has worsened a shortage of experienced engineers and other science professionals ready to work in Kern's suddenly bustling petroleum industry.

People in the industry say large local producers are scrambling to recruit and train young people to replace engineers and geologists nearing retirement age.

The effort is hampered by the industry's notoriously unsteady employment pattern: Many young oil engineers were let go about a decade ago when crude prices languished and drilling work tapered off. Many entered different fields and never looked back.

Local factors have made the situation particularly acute. Cal State Bakersfield has an industry-oriented geology department, but the university produces no engineers. Also, attracting fresh graduates from outside the area can be difficult because of Bakersfield's reputation as a sleepy ag town.

"I'd like to hire an engineer myself and I don't really know where to look," Bakersfield oil producer Chad Hathaway said, adding that he'd be in high demand now if he had stayed in engineering school.

The severity of the shortage tracks closely with gasoline prices, said Jackie Flesher, co-owner of ProSearch Associates, an executive technical recruitment service in Bakersfield. Two years ago, she said, nobody needed an oil engineer; now she has 25 such positions to fill.

"It's very cyclical," she said. "They do get laid off and they do get hired back."

One of the largest producers operating locally, Occidental Petroleum Corp., is looking to fill more than 50 positions in Bakersfield ranging from engineering to safety jobs. It hasn't been easy.

"We acknowledge there is a shortage of qualified technical professionals available to work within the oil and gas industry," Oxy spokeswoman Susie Geiger wrote in an email. "In light of that, we want to bring our new employees up to speed faster than before." To that end, she wrote, the company is developing a two- to five-year program intended to accelerate new employee training.

That's a key challenge facing not only oil producers but utilities and others in the local energy industry, said Robin Fleming, senior manager of business development at the Kern Economic Development Corp., which helps grow and retain local businesses. She said all the large producers operating here are investing in recruitment and building up work experience.

"There is a ramp-up to try and get those people in for training," she said.

Some of that is happening at a very early stage. A local initiative headed by KEDC's nonprofit foundation promotes energy professions among high school girls who have expressed an interest in math, science and engineering. Called the Alliance for Women in Energy, it arranges for local energy professionals to mentor these students and show them the benefits of working in oil, wind energy and utilities.

While these students could go on to pre-engineering programs at Bakersfield College and CSUB, there is no way for them to earn an oil engineering degree in Kern County -- yet.

Last fall CSUB won a $3.7 million U.S. Department of Education grant for the creation of a computer engineering degree that university spokesman Robert Meszaros said will serve as a stepping stone for future engineering programs.

Such graduate engineering programs do not exist locally partly because of a lack of money but also because of engineering programs at Fresno State and Cal Poly San Luis Obispo, Meszaros said.

But CSUB does offer undergraduate and post-graduate geology degrees -- and the local oil industry makes good use of them.

"We get inquiries weekly from people who have jobs they're looking to fill," said Robert Horton, chairman of CSUB's department of geological sciences. He added that most of the inquiries come from the oil industry.

Something that makes the program of particular value to the local industry, Horton said, is the fact that the graduates are accustomed to the Kern County lifestyle. He said that's important to Bakersfield-area employers, who otherwise must convince job candidates of the high quality of life here.

But perhaps the bigger challenge goes back to the cyclical nature of the industry. Times may be good now, but projects will eventually dry up if prices hit the dirt again, as happened in the late 1990s.

Les Clark, executive vice president of Bakersfield's Independent Oil Producers Agency, said the industry lost a lot of good people back then.

"Right now I think the oil industry is a good place to go get yourself a job," he said. "It's the ups and downs that really get us." 

PetroNeft Looks Ahead to 2011 Exploration

PetroNeft Looks Ahead to 2011 Exploration

Monday, April 04, 2011

PetroNeft Resources plc

PetroNeft, owner and operator of Licenses 61 and 67, Tomsk Oblast, Russian Federation, is pleased to provide an update on its operations.

Highlights:

• Hydraulic fracturing program completed successfully
• Target production now estimated to be between 7,000 and 8,000 bopd at end of Q1 2012
• First and second production wells in 2011 development program successfully drilled - first well encounters thickest net pay interval to date
• Five well exploration drilling program targeting 120 mmbbls to commence in April

License 61 Hydraulic fracturing program

  The hydraulic fracturing of nine wells at Pad 1 at the Lineynoye oil field was completed successfully in February 2011. All of the fracture stimulated wells have been returned to production and cleaned-up. Current production from the nine wells is approximately 3,000 bopd; this does not include the Lineynoye No. 1 or No. 6 wells which are currently offline for operational reasons.

In the Lineynoye No.1 well, which was drilled in 1972, the diameter of the well casing is too small to accommodate an Electrical Submersible Pump (ESP) and a special order screw pump was purchased for the well. This pump is currently being installed.

The well produced around 275 bopd on natural flow during pilot production in 2009, but production from the well has been minimal this past year because it could not flow naturally against the back pressure of the process system caused by the ESPs in the other wells. The screw pump should remedy this issue.

Repair of a casing hole in Lineynoye No.6 well has just been completed and an ESP is currently being re-installed. This well had previously produced around 200 bopd.

Both Lineynoye No. 1 and No. 6 are anticipated to be back on line within the month.
We are satisfied with the results of the fracture stimulation program and the performance of the fracture stimulated wells to date and remain highly confident with regard to our understanding of both geology and reservoir quality in License 61. The results of this program will enable us to refine our plans for future activities, especially with regard to the size of the frac and the time required to return wells to production following the fracture stimulation. Current plans are to fracture stimulate up to 8 of the 17 new development wells being drilled in 2011 this summer using a heli-frac crew. To this end we have purchased the necessary proppant and frac tubing and already moved these items to the field by winter road. In addition, we have also recently purchased a new workover rig, which will be staffed with our own crew, and speed up workovers and their quality in the future.

Given our recent experience, we have felt it prudent to take a more conservative view regarding the future production profile taking into account of the attendant variables for the timing of bringing wells online and the timing of the hydraulic fracturing of new wells. Therefore the Company is now targeting a range of between 7,000 and 8,000 bopd by the end of Q1 2012 when all of the 17 new wells being drilled in the 2011 campaign, together with the 11 existing wells, will have been fracture stimulated and returned to production.

2011 License 61 Development program - Lineynoye oil field

Production drilling at Pad 2 has commenced and the 201 and 202 wells successfully drilled and cased. Preliminary log and survey data indicate that well 201 encountered the thickest net pay interval to date in the drilling program.

The rig for Pad 3 and all materials have been mobilized to site and rig-up is about 25% complete. The first well should spud in late April.

Works to tie-in Pads 2 and 3 to the existing central processing facility are ongoing and it is expected that this work will be completed in May 2011 thereby allowing new wells to be brought swiftly into production. All of the major equipment and materials necessary to expand the central processing facility from 7,400 bpd to 14,800 bpd have been delivered to site and this work is proceeding to schedule and is expected to be completed by July 2011.

2011 License 61 Exploration program

PetroNeft's high impact 2011 exploration program, which has the potential to more than double our reserves this year, will target over 60 million barrels across three prospects in License 61. The first of these, Kondrashevskoye No. 2 well, should spud in late April; site preparation is complete, the rig has been mobilized to location and rig-up is underway.

The second well in the schedule at Sibkrayevskaya No. 372 will target the largest prospect in the program at over 40 million barrels. At present, site preparation and mobilization of the rig and materials is complete and rig-up operations are planned to start in late April for a June spud. The site for the North Varyakhskaya No. 1 well has also been prepared and the rig and materials are being moved to the site. This well will be the last exploration well drilled at License 61 in 2011 with a planned spud in July.

2011 License 67 Exploration program

The drilling tender for the two exploration wells to be drilled in 2011 in License 67 is currently underway. This program will also target over 60 million barrels. The two wells, Cheremshanskaya No. 3 and Ledovoye No. 2a, are located close to existing all weather roads and will be drilled in the second half of the year following the License 61 exploration wells.

Mobilization of equipment for the construction of the Cheremshanskaya site has commenced.
Dennis Francis, Chief Executive Officer of PetroNeft, commented, "We are pleased with the results of our nine well fracture stimulation program but we have learned from the program and feel we can improve on both the design and efficiency in our future drilling and frac programs.

Based on these results we have taken a more conservative approach to our production profile and are targeting a range from 7,000 to 8,000 bopd by the end of Q1 2012. The Company has a very significant reserve base which we are only just starting to develop and the key for sustained production growth in the coming years will be to continue to build the stock of producing wells, in the most cost efficient manner.

Part of the process is implementing our Lessons Learned and continuous review of the development sequence based on new discoveries. Provided we do these tasks well the future of the Company looks very good and we will build significant production and cash flow profiles over the next 5 years."

Marcellus Panel Looks for Common Ground at First Meeting

Marcellus Panel Looks for Common Ground at First Meeting

Monday, March 28, 2011
Pittsburgh Post-Gazette
by  Laura Olson

The public comments at the end of Friday's inaugural meeting of the state Marcellus Shale Advisory Commission showed part of the challenge facing that panel during the next four months.

One county commissioner stood up to laud the number of jobs that gas drilling has brought to his community. He was followed by a northeastern resident who said her property value has plummeted because of the surrounding well pads, and another woman citing concerns about water quality.

"I moved up here to be at peace with nature," Wyoming County resident Joanne Fiorito told the panel. "You have now ripped my American dream apart, and I am appalled and outraged."

The 30-member panel has 120 days to assess how the state is managing natural gas drilling, as well as find some policy agreement between those skeptical of the booming business and those benefiting from it.

The group will report back to Gov. Tom Corbett in mid-July on what changes they recommend to balance job growth and environmental protection.

Their first task during the meeting, which lasted for more than four hours, was dividing the topics to be tackled among four work groups -- health, safety and environmental protection; economic and workforce development; infrastructure; and local impacts and emergency response.

Those groups will begin their work shortly, and give an update of their progress at the commission's next meeting on April 27.

A locally assessed impact fee on gas drillers will be part of those talks, said Lt. Gov. Jim Cawley, the commission's chairman. But a statewide severance tax, which the Corbett administration opposes, is "off the table," he added.

Several of the commission members -- who represent state government, local communities, environmental advocates, industry leaders and academia -- noted a need for some form of levy or fee to help local governments with rising costs.

Mr. Cawley said he'd like to see figures on what the drilling industry is costing municipalities and counties in additional road construction, staffing, emergency response calls and other growing demands.

Several on the panel talked about using a "fact-based" process to figure out how to responsibly grow the drilling industry, and to present Pennsylvania as the best place for drilling companies to invest.

"We have to win," said Nicholas Haden, vice president of Reserved Environmental Services, a wastewater treatment facility in New Stanton, Westmoreland County. "The Marcellus Shale is not the only shale play in the world."

Presenters giving a snapshot of the industry's activities relayed data on how much interest the Marcellus, and the state's other shale formations, already have garnered.

Southwestern Pennsylvania is near the forefront of activity, with Washington and Greene among the top five counties for number of wells. Department of Environmental Protection statistics show Washington with 305 wells drilled since 2007 and 179 in Greene, which puts them third and fourth behind Bradford and Tioga.

Those wells, and others in the works, are expected to bring more than 10,000 industry jobs to the state's southwest by 2014, said Tom Murphy, of Penn State's Marcellus Center for Outreach and Research.

But amid the presentations came questions to be discussed in the coming months: How should the state help non-drilling businesses, which are losing workers to higher-paying gas companies and having trouble filling the resulting openings?

And how many hotel rooms and apartment buildings should towns add to accommodate an industry that tends to move money and manpower quickly if markets shift?

Some lessons may be found in looking at the southern shale gas-producing states, said Teri Ooms, of the Institute for Public Policy and Economic Development.

A major complaint in Arkansas, and in some parts of Pennsylvania already, is road damage and congestion, said Ms. Ooms. She said one strategy that helped ease tensions was posting truck routes and advertising when those roads would have heavy traffic.

Other problems and solutions will be the source of much-welcomed debate by the commission and members of the public, said Mr. Cawley.

"We want to hear it from all sectors, because we want to provide a blueprint to Gov. Corbett in the middle of July that truly outlines all of the benefits as well as any potential impacts so that he can make an informed decision," he said.