Oil and Gas News: 08/09/11

Tuesday, August 9, 2011

Oil & Gas Post - All News Report for Tuesday, August 09, 2011

Tuesday, August 09, 2011

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Commodity Corner: Crude Slips Below $80

- Commodity Corner: Crude Slips Below $80

Tuesday, August 09, 2011
Rigzone Staff
by Saaniya Bangee

Crude oil futures extended losses Tuesday after the Federal Reserve said risks to the economic outlook have increased.

Light, sweet crude continued to retreat on the New York Mercantile Exchange Tuesday settling at $79.30 a barrel, down $2.01. For the first time in nearly 10 months, crude prices settled below $80 a barrel.

The Fed failed to ease fears as Chairman Ben S. Bernanke and his colleagues promised to extend the benchmark interest rate for another two years but stopped short of initiating an additional round of economic stimulus.

In separate monthly reports, the U.S. Energy Information Administration (EIA) and OPEC cut demand forecasts for 2011. The EIA cut its 2011 world demand growth forecast by 60,000 barrels per day (bpd). It raised its 2012 projections to 1.64 MMbpd. Meanwhile, OPEC cut oil demand growth for this year by 150,000 bpd and 20,000 bpd for next year.

The intraday range for crude was $75.71 to $83.05 a barrel.

At its lowest close since Feb. 18, Brent futures lost $1.17 to end Tuesday's trading session at $102.57 a barrel. Prices traded as low as $99.06 and as high as $105.81 Tuesday.

Gasoline for September delivery settled 2.4 cents lower at $2.67 a gallon Tuesday. The EIA reported a 2 percent decline in gasoline demand over the summer-driving season, pushing prices as low as $2.59. The intraday high for gasoline was $2.76.

Conversely, natural gas futures gained 5.9 cents, or 1.5 percent, settling at $3.99 per thousand cubic feet. Natural gas futures pushed past the $4-mark Tuesday, peaking at $4.04 and bottoming out just below $3.89. High temperatures continue to support gains.

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SEC Subpoenas Producer for Documents on Shale Gas

- SEC Subpoenas Producer for Documents on Shale Gas

Tuesday, August 09, 2011
Houston Chronicle
by Tom Fowler

Dallas-based Exco Resources is among shale gas producers that have received subpoenas for documents on actual well production and reserve estimates, the company said in a regulatory filing.

Exco Resources said in financial documents filed with the Securities and Exchange Commission that it received a subpoena from the agency Aug. 1.

Exco said the SEC requested "certain information from Jan. 1, 2008, through the present pertaining to our proved developed producing shale gas wells and reserve estimates."

"The SEC stated that this investigation is a fact-finding inquiry. We understand that a number of other shale gas producers have received similar subpoenas from the SEC."

Analysts with Houston-based bank Tudor Pickering & Holt said it polled a number of shale companies to see if they have received subpoenas, but the answer so far has been "not yet."

The Chronicle reported last month on its FuelFix website that some companies were receiving subpoenas for documents relating to the financial viability of shale projects, after the New York Times reported concerns expressed by some in the industry and government that the shale boom has been overstated.

The Times report has prompted industry backlash, and the paper's public editor wrote that the report was short on dissenting views and was misleading in how it described sources -- drawing a rebuttal from editors behind the story.

Copyright (c) 2011, Houston Chronicle

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Gas Driller Opposes Pipeline Rules, Asks Landowners to Raise Concerns

- Gas Driller Opposes Pipeline Rules, Asks Landowners to Raise Concerns

Tuesday, August 09, 2011
Knight Ridder/Tribune Business News
by Laura Legere, The Times-Tribune, Scranton, Pa.

New permitting requirements affecting natural gas pipelines in Pennsylvania have raised the ire of Chesapeake Energy, which is encouraging natural gas leaseholders to join it in protesting the rules.

In a recent letter sent to landowners in the Northern Tier, Chesapeake's vice president for government relations, David J. Spigelmyer, called the updated requirements enacted by the U.S. Army Corps of Engineers on July 1 "unnecessary, time consuming and redundant."

Delays caused by the new permit reviews have stranded 128 of the company's drilled and completed Marcellus Shale wells without pipelines and are "costing Pennsylvanians royalty income," he wrote.

The new rules replace federal regulations that expired in June controlling pipeline construction and other surface-water impacts in Pennsylvania. A change in the regulations requires companies to detail all of the streams and wetlands to be crossed by a pipeline project -- some of which stretch for hundreds of miles -- rather than outlining only the impacts of each stream crossing individually.

The new permits allow regulators to consider the cumulative surface-water impacts of the projects, which are increasingly spiderwebbing the commonwealth to tie new Marcellus Shale wells to interstate pipelines that bring the gas to market.

Army Corps of Engineers spokeswoman Stacy A. Ouellette said the permit "streamlines the process for activities throughout the state of Pennsylvania" and within multiple Army Corps of Engineers boundaries. The permit also allows Pennsylvania "to issue permits for activities having minimal impact to waterways and wetlands, reducing redundancy between the corps and state," she said.

In a description of the regulations published in the Pennsylvania Bulletin in May, Pennsylvania Department of Environmental Protection Secretary Michael Krancer said that the revised permit incorporates federal and state standards in one process and "continues a streamlined process for permit applicants without compromising comprehensive environmental protection."

PennFuture president Jan Jarrett said the cumulative review offered with the new permit is "a good thing." The need for additional regulatory oversight of pipeline construction was highlighted in recent weeks when two failures at a pipeline project in Susquehanna County dumped drilling mud into a high-quality waterway, she said.

"It's unfortunate to see a company coming out opposing updated regulations that address natural gas pipelines," she said. "We would rather see them doubling down and working with the regulations that are clearly aimed at protecting Pennsylvania's water resources rather than stirring up and scaring the landowners who they work with."

Chesapeake said the potential review of all stream and wetland crossings increases the average review time for a project from 45 days to nearly 300 days and unfairly singles out Pennsylvania projects for extra layers of review.

Along with the letter written by Mr. Spigelmyer, Chesapeake provided landowners with a form letter to send to their senators and congressmen that says, "At a time of great economic uncertainty in this country, it seems unproductive that the federal government would take such a drastic step to limit the ability of landowners like me to benefit economically from natural gas production."

In a statement Monday, Mr. Spigelmyer said the Baltimore District of the Army Corps of Engineers began applying aspects of the permit change over the last year and "the delays are already evident."

"This is obviously of great concern to landowners who've had wells drilled on their land and who are wondering why their wells are not yet producing and marketing gas," he said. "It is of equal concern to Chesapeake as each of our wells represents the investment of millions of dollars in capital that can't begin to produce a recovery of investment, let alone a return on investment, if we cannot predictably plan for the development of pipelines necessary to get gas to market."

Copyright (c) 2011, The Times-Tribune, Scranton, Pa.

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Black Elk, ES&G Join Forces to Protect Platforms during Hurricane Season

- Black Elk, ES&G Join Forces to Protect Platforms during Hurricane Season

Tuesday, August 09, 2011
Black Elk Energy, LLC

Black Elk announced a proactive project with ES&H Consulting & Training Group to strategically place waterproof sensors on each platform. The sensors emit a continuous location signal that is used as a tracking device. If the sensor becomes submerged or is damaged, as it might in hurricane conditions, the signal is then lost, suggesting damage to the structure and thus a possible environmental impact. This would alert ES&H Consulting & Training Group and Black Elk Energy to quickly investigate the incident, enabling a more effective management response. Black Elk Energy is currently 50% deployed with the remainder to be installed within the next 45 days.

The units are manufactured by ESSI Corporation and utilize low earth orbit satellites (LEO) and transmit on L-band frequencies, providing excellent rain fade performance. The systems send a small data packet with location information, battery status, etc., every four hours as long as there is a clear line of sight to the sky. If no signal is received, resources can be concentrated within 4 hours’ passage of a storm. The lithium ion batteries last an entire hurricane season and are field serviceable.

"We understand the importance of being prepared for what may come with hurricane season," said John Hoffman, CEO of Black Elk Energy. "This new technical measure will aid in the overall tracking and management of our platforms in the Gulf. Black Elk Energy maintains an intranet site that provides a gulf-wide view of each of our platforms, which indicates a green symbol for every structure that’s operating normally."

"We commend Black Elk Energy for initiating a proactive measure for their platforms in the Gulf of Mexico, just in time for hurricane season," said Kevin Voisin, Vice President/Partner of ES&H Consulting & Training Group. "We believe this project proves Black Elk’s commitment to the environment and certainly demonstrates their efforts in going above and beyond industry standards to diligently monitor the integrity of their platforms."

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First Subsea Names Global Sales, Business Development Manager

- First Subsea Names Global Sales, Business Development Manager

Tuesday, August 09, 2011
First Subsea Ltd.

First Subsea has appointed John Shaw as global sales and business development manager. Formerly head of Engineered Products Group at Trelleborg Offshore, he will be responsible for developing First Subsea's innovative ball and taper connector business worldwide.

In addition to the Ballgrab range of subsea mooring connectors, ball and taper has been successfully used for pipeline recovery and decommissioning tools, ROV and diverless bend stiffener connectors for risers and umbilicals, pipeline repair, hose connectors, heavy lift and buoy mooring and retrieval applications.

A Fellow of the Institute of Mechanical Engineers, Mr. Shaw is no stranger to the connector technology. At Trelleborg Offshore, he worked with First Subsea on the development of the diverless bend stiffener connector. "The simplicity of the ball and taper connection, and its powerful multi-point grip, makes it a very flexible solution to offshore connections in many demanding applications. My role will be to work with clients to develop existing and new applications for the ball and taper connector," he said.

First Subsea has successfully developed the ball and taper connector technology for drilling applications both onshore and offshore. One of this year's OTC Spotlight on Technology Awards included Canrig Drilling Technology's SureGrip Automated Casing Running Tool featuring the ball and taper gripping mechanism for handling drill piping.

"The ease of ball and taper connection makes it suitable for any application involving gripping, pulling and holding connections under load. John Shaw's experience will allow us to consolidate and improve our current product range, as well as developing opportunities for the connector in new markets," commented Brian Green, general manager, First Subsea Ltd.

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PG&E Welcomes New CEO

- PG&E Welcomes New CEO

Tuesday, August 09, 2011
PG&E Corp.

PG&E announced that Anthony F. Earley, Jr., 62, will become the company's new Chairman of the Board, Chief Executive Officer, and President. Earley's appointment – the first in PG&E's history to come from outside the organization – puts the company under the leadership of one of the nation's most experienced energy executives.

As head of Michigan-based DTE Energy for more than a decade, Earley built the company's core businesses – Detroit Edison and Michigan Consolidated Gas Company – into two of the most highly respected electric and natural gas operating companies, with strong performance on many of the industry's key safety and reliability measures.

"Tony is a highly respected and proven CEO who will provide fresh eyes and strong leadership as we focus on public safety and operations excellence," said Lee Cox, interim Chairman, Chief Executive Officer, and President. "We looked across the industry and found the person best qualified to help us win back public confidence."

Earley joined Detroit Edison in 1994 as President and Chief Operating Officer. He became CEO of DTE Energy in 1998 and served in that role through 2010. Most recently, he has been DTE's Executive Chairman. DTE Energy is one of the nation's largest diversified energy companies.

"PG&E has a proud legacy," said Earley. "It's a great privilege to help an iconic company recover from its recent challenges and reclaim its standing as the utility others admire and aspire to follow."

Earley has received accolades for his crisis leadership. In 2003, the largest blackout in U.S. history began at a utility in Ohio and triggered outages in Michigan and six other states. Public officials and customers praised Earley's response to the emergency. Michigan Governor Jennifer Granholm called him a "calming influence" and exactly the person she would want to lead during a crisis.

"Tony Earley proved that he was a leader we could rely on to be open, honest and accountable at a very difficult time," said Granholm. "He stepped up publicly. He made sure we knew what was happening, what we could expect and when we could expect it. And he made sure DTE came through and delivered on what it promised."

In addition to his success establishing DTE as an operational leader, Earley has also been instrumental in forging industry consensus on national energy policy challenges. During his recent tenure as Chairman of the Edison Electric Institute (EEI), the association of investor-owned utilities, he helped the group work constructively in Washington on issues ranging from climate change to energy efficiency and support for electric vehicles.

"Tony pulled the industry together to develop a common proactive position supporting a reasonable and affordable approach to climate change enabling us to be a constructive force in the discussions. He is highly respected across our industry," said Tom Kuhn, President and CEO of EEI. Earley also has served as Chair of the Nuclear Energy Institute.

"The PG&E Board has asked Tony to continue the significant leadership role PG&E has played on climate change issues," said Cox. "Tony understands and admires California's unique role in leading the country on environmental issues, and he is eager to become involved here."

Locally, Earley has dedicated significant time and energy to supporting civic and community initiatives, with a particular focus on driving economic revitalization in Detroit and the surrounding region. He is currently a board member of Business Leaders for Michigan, United Way for Southeastern Michigan and Cornerstone Schools.

"Tony Earley is passionate about investing in the community," said Detroit Mayor David Bing. "He knows that for business to thrive, the community has to thrive – and he leads by example to make that happen."

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Reliance-BP Deal Gets OK from Indian Govt

- Reliance-BP Deal Gets OK from Indian Govt

Tuesday, August 09, 2011
Reliance Industries Ltd.

Reliance Industries Limited has received the Government of India approval for its transformational deal with BP. Reliance Industries is grateful to the Government of India for the approval, which will result in the largest foreign investment in the domestic hydrocarbon sector.

BP will take 30% stake in 21 oil & gas production sharing contracts that Reliance operates in India, including the producing KG D6 block. Following the approval, RIL and BP will work together to conclude the deal expeditiously.

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Sentry Updates Appraisal Work at AU Wells

- Sentry Updates Appraisal Work at AU Wells

Tuesday, August 09, 2011
Sentry Petroleum Ltd.

Sentry provided the following update on its drilling exploration and appraisal work on ATP 862 and ATP 864 in Queensland Australia.

Sentry Petroleum has now completed the drilling of two Coal Seam Gas wells on ATP 862. The wells, Talundilly_CSG1 and Albilbah_CSG1 reached depths of 1,430 feet and 1,555 feet, respectively. In Talundilly_CSG1, 833 feet of core were cut, out of which 51 feet of coal and carbonaceous rock were canistered for gas desorption in 21 samples. Gas desorption is still ongoing as gas was found in all the canistered core samples. The Company expects this process to be completed for the Talundilly_CSG1 during the coming week. The Company further advises that isotherms will be obtained on selected coal and shale samples.

In Albilbah_CSG1, 472 feet of core were cut, out of which 35 feet of gaseous coal and carbonaceous rock were sealed in 20 canisters for desorption measurement. In addition, the lower Winton Sandstones were found to contain free gas and 20 feet of these cores were also canistered and evolved gas is being measured. Once these measurements are completed during the coming weeks the cores will be sealed and sent to a laboratory for routine core analysis to measure porosity, permeability and residual fluid saturation. The wireline logs from the previously drilled Albilbah-1 also indicate the presence of gas in these sands over a 128 feet interval starting beneath the last coal.

The Company's coalbed gas content measurements are using the direct method which is the preferred method in coalbed methane and gas shale resource assessment. The direct method physically measures the volume of gas released over time from a core sample sealed into a desorption canister—termed the measured gas content. Adjustments are made to the measured gas content to account for gas lost prior to the core being placed in the desorption canister and for residual gas remaining in the core at the completion of the desorption period. The process of acquiring the measured gas content generally requires four to five weeks. Upon completion of the gas desorption results will be forwarded for independent certification.

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Samson O&G Begins 4-Well Drilling Program

- Samson O&G Begins 4-Well Drilling Program

Tuesday, August 09, 2011
Samson O&G Ltd.

Samson O&G advised that the Evergreen Rig 22 has been released from its previous well and is being mobilized to the Defender US33 #2-29H location, and will then be deployed at three additional Samson drilling locations. The initial trucks arrived Tuesday and the rig up at Defender US33 #2-29H has commenced, and it is expected that the rig will be ready for its final inspection such that drilling operations should begin late Thursday or Friday this week.

Defender US33 #2-29H, Goshen County, Wyoming, Samson 37.5% working interest

The Defender US33 #2-29H, is the first Niobrara appraisal well in Samson's Hawk Springs project. Initially, a vertical pilot well will be drilled to around 7,450' and a conventional core will be cut from the Niobrara Formation. After the orientation of the fractures has been identified from core and FMI logs, the vertical pilot borehole will be plugged back to a kick-off point above the Niobrara. From the kick-off point, the borehole angle will be built until it is horizontal and the bit is positioned within the Niobrara "B". Then 7-inch intermediate casing will be set through the curve and the lateral will thereafter be drilled for a distance of approximately 4,300' within the Niobrara "B". The well will be completed using a plug and perforation process in 15-stages that is expected to involve the placement of approximately 3,000,000 pounds of proppant into the Niobrara Formation.

Sprit of America US34 #1-29, Goshen County, Wyoming, Samson 100% working interest

The Defender well will be followed by the Spirit of America US34 #1-29. This well is the first Permian and Pennsylvanian appraisal well within the Hawk Springs project. Preparatory operations, including the well site construction and the setting of the 20-inch surface casing, have been accomplished. The Spirit of America US34 #1-29 will be drilled as an 11,000' vertical test to the Precambrian basement to evaluate multiple conventional targets; in particular, two closed structural traps in the Permian and Pennsylvanian sections.

Following the completion of the two Hawk Springs wells, the Evergreen Rig 22 will be mobilised to Montana to drill the initial two wells in the Roosevelt project.

Australia II KA6 #1-29H and Gretel 11 KA12 #1-30H, Roosevelt County, Montana, Samson 100% working interest

These wells will be the first two appraisal wells in the Roosevelt Project. Both wells will be drilled initially as vertical pilot holes to enable cores to be cut in the Bakken Formation, and then completed as a 15,500’ measured depth horizontal wells in the middle member of the Bakken Formation. The wells will then be fracture stimulated. The design of this completion is currently being undertaken but the final design will build on industry results previously achieved in the area.

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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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Gran Tierra Reaches 'Significant Milestones' in 2Q11

- Gran Tierra Reaches 'Significant Milestones' in 2Q11

Tuesday, August 09, 2011
Gran Tierra Energy Inc.

Gran Tierra announced its financial and operating results for the quarter ended June 30, 2011. All dollar amounts are in United States dollars unless otherwise indicated.

Highlights for the quarter include:

Quarterly production of 18,141 barrels of oil equivalent per day ("BOEPD") net after royalty ("NAR"), a 36% increase in average daily production from the same period in 2010 of 13,376 BOEPD due to additional production from existing field developments, new production from recent field discoveries, and production growth from the recently acquired assets of Petrolifera Petroleum Ltd. ("Petrolifera");
Quarterly oil production of 17,525 barrels of oil per day ("BOPD") NAR, a 32% increase in average daily production from the same period in 2010 of 13,234 BOPD NAR;
Quarterly gas production of 3.7 million cubic feet per day ("MMCFD") NAR, a 334% increase in average daily production from the same period in 2010 of 0.8 MMCFD NAR;
Revenue and other income for the quarter of $162.1 million, a 93% increase over the same period in 2010;
Net income of $31.6 million or $0.11 per share basic and diluted compared to net income of $17.4 million or $0.07 per share basic and diluted in the same period in 2010;
Funds flow from operations of $88.6 million compared to $44.3 million for the same period in 2010;
Cash and cash equivalents were $211.4 million at June 30, 2011 compared to $355.4 million at December 31, 2010 and working capital decreased to $215.4 million at June 30, 2011 compared to $265.8 million at December 31, 2010;
Moqueta-5 delineation well testing was initiated from a single zone at production rates of approximately 730 BOPD over 10 days with a jet pump, with additional testing ongoing;
Major infrastructure projects were completed including the construction and commissioning of the Moqueta to Costayaco flow-line with first short-term test production commencing in June, and the connection of the Costayaco field into Colombia's national electrical system;
First production contribution from Gran Tierra Energy's Brazil assets in the Recôncavo Basin was recorded in the quarter;
Continued to mature plans for robust exploration, delineation and development drilling campaigns in Colombia, Brazil, Peru and Argentina through 2011 and into 2012.

"Several significant milestones were achieved in the second quarter of 2011, positioning the Company to achieve continued growth into the future. The completion of the Moqueta to Costayaco flow-line and initiation of production was a major achievement. This is the first time that an oil field in Colombia has been discovered and test production initiated with operations entirely supported by helicopter and without access by road minimizing the environmental footprint of Gran Tierra Energy's operations at this early stage of development," said Dana Coffield, President and Chief Executive Officer of Gran Tierra Energy. "We achieved record production in the quarter due to effective management of existing producing fields in Colombia and Argentina and new production from recent discoveries in Colombia and Brazil. Record cash flow, and progress in permitting and contracting, are supporting the execution of our planned exploration and drilling program scheduled for the balance of 2011 and into 2012," concluded Coffield.

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ATP Sees Revenue Increase in 2Q 2011

- ATP Sees Revenue Increase in 2Q 2011

Tuesday, August 09, 2011
ATP O&G Corp.

ATP announced second quarter 2011 results.

Results of Operations

Revenues from oil and gas production were $172.9 million for the second quarter 2011, compared to $101.1 million for the second quarter 2010. Increased revenues from production were attributable to higher production volumes and higher oil prices. Oil and gas production for the second quarter 2011 was 2.1 MMBoe (23.6 MBoe/d) compared to 1.9 MMBoe (21.3 MBoe/d) for the second quarter 2010, an 11% increase. Average prices were up 68% over the same period a year ago. Oil represented 68% of total production for the second quarter 2011, compared to 48% of total production for the second quarter 2010.

ATP recorded a net loss attributable to common shareholders of $56.9 million or $(1.11) per basic and diluted share for the second quarter 2011, compared to $82.9 million or $(1.63) per basic and diluted share for the same 2010 period. The net loss attributable to common shareholders for the second quarter of 2011 was impacted by several items analysts often exclude from their published estimates. Those items include impairment expense of $45.7 million, workover expenses of $17.3 million and $1.2 million of drilling interruption costs associated with the Gulf of Mexico moratorium. Also, the items include $45.1 million related to the unrealized derivative income for the quarter. As a result of production increases and higher oil prices, ATP reduced its estimate of the time required to repay a dollar-denominated Override at Gomez. This change in estimate resulted in our recognizing $21.9 million in incremental interest expense related to this Override in the second quarter of 2011 compared to the first quarter of 2011.

The impairment expense of $45.7 million during the second quarter of 2011 related primarily to South Timbalier (“ST”) Block 77 (acquired in 2005), due to ATP's decision not to move forward with a capital expenditure on this property in the second half of 2011. The workover expense is related to the Gomez MC 711 #5 well, which was placed back on production late in the second quarter.

Capital Resources and Liquidity

In the second quarter 2011, ATP conveyed dollar-denominated Overrides and NPI's in the Gomez Hub and the Telemark Hub for net proceeds of $70.3 million. These Overrides and NPI's obligate ATP to deliver a percentage of the proceeds from the future sale of hydrocarbons in the specified proved properties until the purchasers achieve a specified return.

In June 2011 ATP closed a perpetual preferred equity offering that provided net proceeds of $123.3 million, net of discount, related option contract costs and issuance costs. Shares of the preferred are convertible into common shares at $22.20 per share.

During July 2011, ATP entered into a crude oil prepaid swap transaction for 274,500 barrels at a net price of $111.84 per barrel. ATP received $30.7 million at closing. A schedule summarizing ATP's outstanding oil and gas derivatives can be found near the end of this press release.

ATP incurred $220.5 million of capital expenditures ($209 million, excluding capitalized interest) on oil and gas properties during the first half of 2011, of which $34.8 million was funded through vendor deferral and net profit interest programs. These capital expenditures were predominantly related to the Gomez and Telemark Hubs, and the Octabuoy production platform. In the remainder of 2011, ATP anticipates incurring $250 million to $300 million in total capital expenditures, excluding capitalized interest, of which $150 million to $200 million will be contributed by vendors through existing NPI programs or deferral programs.

ATP had unrestricted cash of $185.9 million and restricted cash of $47.4 million at June 30, 2011.

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GM Plans To Halve The Number Of Vehicle Frames

- GM Plans To Halve The Number Of Vehicle Frames

Aug 9, 2011

General Motors (NYSE:GM) plans to be leaner in the future by halving the number of car and truck frames its uses worldwide.

The company also says it plans to increase factory capacity 45% in Brazil, Russia, India and China by 2014 to take advantage of growth.

GM made the statements Tuesday in slide presentations for its annual global business conference for industry analysts.

The slides say that GM built cars and trucks on 30 specific frames last year. That number would be cut to 14 by 2018, saving on engineering, design and manufacturing costs.

The company also plans to keep its investment in research and development steady, even when car sales are down. That will save money by terminating the practice of stopping and starting projects.

General Motors has a potential upside of 71.6% based on a current price of $25.21 and an average consensus analyst price target of $43.25.

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Fitch Confirms NRG Rating

- Fitch Confirms NRG Rating

Aug 9, 2011

Fitch Ratings on Tuesday confirmed its noninvestment-grade "B+" overall credit rating for wholesale power company NRG Energy Inc.(NYSE:NRG).

The credit rating agency also gave its "BB+" rating to NRG's new first line facilities and affirmed its "BB" rating on the company's unsecured notes. The outlook is stable.

Fitch pointed to the diversity of NRG's power plants in terms of size, fuel location, along with its improved business risk profile, strong liquidity position and historically conservative hedging strategy, as grounds for the ratings.

Fitch said it expects NRG's credit metrics to bottom out in 2013 and for its solid liquidity profile to allow it to navigate a continued drop in commodity prices.

NRG Energy has a potential upside of 28.7% based on a current price of $21.24 and an average consensus analyst price target of $27.33.

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White House announces oil savings standards for heavy duty trucks, buses

- White House announces oil savings standards for heavy duty trucks, buses

Aug 9, 2011

The Obama administration announced new fuel efficiency and greenhouse gas pollution standards for work trucks, buses, and other heavy duty vehicles that it said will save American businesses who operate and own these commercial vehicles approximately $50B in fuel costs over the life of the program. Under the guidelines, trucks and buses built in 2014 through 2018 will reduce oil consumption by a projected 530M barrels and greenhouse gas pollution by approximately 270M metric tons.

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U.S. Faces Increased Energy Security Risk, Report Shows

- U.S. Faces Increased Energy Security Risk, Report Shows

Tuesday, August 09, 2011
Rigzone Staff
by Barbara Saunders

The U.S. faces heightened threats to its energy security, according to a new report by the U.S Chamber of Commerce that measures risk in four areas—geopolitical, economic, reliability and environmental.

For 2010, the energy security risk index score was 98.0—the fourth highest since 1970 and a 6.5 point increase from the 2009 score of 91.5.

"These are the worst risks we've seen in recent history," said Karen Harbert, president of the Chamber's Institute for 21st Century Energy. "They approach what we saw following the Iranian hostage crisis. . . . Unless we take dramatic action to change the trajectory, America is headed toward an unprecedented level of sustained risk."

The index, updated annually, tracks changes in energy security risk beginning in 1970 and projects future risk through 2035. The 2011 edition of the index incorporates the most current energy data from the U.S. Energy Information Administration (EIA) and other federal agencies.

Of the 37 metrics weighed, 20 showed increased risk in 2010, 11 showed improvement, and six were unchanged. Eight of the top 10 metric with the largest score changes related to energy prices, price volatility and expenditures, the Chamber said, adding that the index projects a sustained period of high risk all the way through 2035. "These risks would be even higher if not for improvements made in energy efficiency, and the potential for shale gas to improve the security of natural gas supplies and lower energy costs," the Chamber added.

"We must maximize all of our domestic energy resources, make clean energy technologies more affordable, and eliminate regulatory barriers that are stalling urgently needed energy projects," Harbert said. "Only by taking these actions will we reduce our energy risks and make the nation and economy more secure."

The 2011 edition includes some adjustments to the index's formula based on feedback from last year's inaugural report. Adjustments also were made to some previous year's scores based on updated data from government sources. Most significantly, the 2009 score was adjusted from 83.7 to 91.5, largely because revised data that showed resurgence in high energy prices occurring more rapidly than originally estimated.

Highlights of the report included:

Geopolitical energy security risks rose to 97, 13.5 points above the 30-year average of 83.5. Most of the increase in risks seen in this sub-index since the early 2000s is linked to higher crude oil prices and volatility and greater import expenditures. The metrics measuring security of global fossil fuel reserves and production were essentially unchanged from 2009.
Economic energy security risks increased by 9.3 points in 2010 to 94.0, offsetting a large portion of the 17.1 point drop experienced in 2009. "This level of risk is well above the 30-year average of 73.7 for this sub-index and has been exceeded only in 1980, 1981, and 2008," the Chamber noted.
Reliability energy security risks increased 5.4 points to 111.0 in 2010, the highest recorded for this sub-index, with crude oil price volatility being responsible for much of the increase. The score for this sub-index has hit 100 points or more every year since 2005, and projections indicate that levels of risk above 95 will be maintained through 2035, even after assuming that crude oil energy price volatility will return to historical averages.

In one bright spot, the Chamber noted that the "potential of shale gas to improve the security of natural gas supplies and lower energy costs and expenditures is beginning to emerge. Recent estimates double the volume of recoverable shale gas resources assumed in past estimates, leading to greater domestic and global supplies and lower gas imports. Increasing shale gas supplies and further improvements in natural gas extraction technologies will further delink the prices of crude oil and natural gas."

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Obama Backs Additional Oil Drilling in Alaska, Salazar Says

- Obama Backs Additional Oil Drilling in Alaska, Salazar Says

Tuesday, August 09, 2011
Knight Ridder/Tribune Business News

Interior Secretary Ken Salazar came to Anchorage on Monday and said the Obama administration supports more oil drilling in Alaska, potentially including offshore Arctic development.

Salazar joined Alaska Sen. Mark Begich and Rhode Island Sen. Jack Reed, both Democrats, for a meeting with Alaska businesspeople and said the president's feeling toward Arctic offshore drilling is "Let's take a look at what's up there and see what it is we can develop." But any Arctic oil development must be done carefully, he said. Salazar said the Arctic lacks needed infrastructure for responding to potential offshore oil spills and cited painful lessons from the Deepwater Horizon spill in the Gulf of Mexico last year.

"Not the mightiest companies with multibillion-dollar pockets were able to do what needed to be done in a timely basis, and the representations of preparation simply turned out not to be true from the oil companies that had a legal obligation to shut down that kind of an oil spill. ...

When you look at the Arctic itself, we recognize that there are different realities - the ocean is a much shallower ocean, conditions are very different than we had in the Gulf of Mexico. (But) there are challenges that are unique to the Arctic," Salazar told Alaska reporters.

Salazar said a step toward a solution is "having an agency within the United States government and Interior, the Bureau of Ocean Energy Management and Regulation, that can in fact do its job." The agency is the successor to the Minerals Management Service, which was discredited after the Gulf spill.

"Secondly, there will be conditions that will be imposed on whatever drilling that does occur in either the Beaufort or the Chukchi on down the road that will incorporate the lessons that have been learned (from the Gulf spill)," he said. "And thirdly, there is also a recognition we have that there is additional work that needs to be done with respect to the understanding of the Arctic, the science and the need for having effective oil spill response," Salazar said.

Begich, said he was encouraged the administration is taking steps toward Arctic development while working out what Coast Guard and other resources would be needed in the area.

Last week the Interior Department's Bureau of Ocean Energy Management, Regulation and Enforcement gave Shell a conditional exploration permit that covers a program that would drill four wells over two years in Camden Bay of the Beaufort Sea, due north of the coastal plain of the Arctic National Wildlife Refuge. But the permit is contingent on many other federal permits and approvals, including oil-spill response plans and marine mammal protection.

Shell is also seeking authorization to drill in the Chukchi Sea.

Shell's Alaska government affairs manager, Cam Toohey, was at Monday's meeting with Salazar and Begich at the Cook Inlet Regional Inc. building in Midtown Anchorage. Toohey said the oil company has seen what it considers an improved attitude among the Interior Department toward providing the certainty needed to invest in projects.

Obama in July signed an executive order to create a new federal working group tasked with having agencies better coordinate Alaska oil and gas permitting and other regulatory oversight. The White House said the working group, which is overseen by Deputy Interior Secretary David Hayes, is designed to simplify oil and gas decision-making in Alaska by bringing together federal agencies to collaborate as they evaluate permits and environmental reviews. Hayes joined Salazar in traveling to Alaska this week.

Salazar said he hoped it would help with instances like the dispute among agencies over a permit for a bridge crossing of the Colville River, which would let companies develop the onshore CD-5 drill site within the National Petroleum Reserve-Alaska.

Salazar on Monday reiterated Obama's support for drilling in the NPR-A.

He said the president wants to increase the domestic energy supply, reduce consumption through measures like greater fuel efficiency, and develop alternative fuels.

Obama does not support drilling in the Arctic National Wildlife Refuge.

Salazar said there are places like NPR-A to focus on drilling "where we don't have to deal with that particular controversy." The Alaskan business people that Salazar, Begich and Reed met with in Anchorage on Monday morning were particularly concerned about what CIRI President Margie Brown described as the "regulatory morass that we find ourselves in." Deputy Interior Secretary Hayes after the meeting went to have a discussion with the governor's office, which has loudly and repeatedly complained about such regulations.

Begich and Salazar also met with the Alaska Federation of Natives on Monday before Salazar, his deputy, Hayes, and Sen. Reed went on to Fairbanks to tour the Bureau of Land Management wildfire-fighting facilities along with Sen. Lisa Murkowski, R-Alaska. Reed is chairman of the Appropriations Subcommittee with jurisdiction over the Interior Department.

The agenda for Salazar's Alaska trip also includes a visit to the Alpine oil field on the North Slope, a flyover of the NPR-A and a meeting with Shell officials in Barrow on offshore exploration. Murkowski, a Republican, will accompany him.

Salazar was in Kodiak over the weekend and will conclude his trip Wednesday with a visit to the Eielson Visitors Center in Denali National Park and Preserve.

(c) 2011, Anchorage Daily News (Anchorage, Alaska). Distributed by Mclatchy-Tribune News Service.

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Australia Pacific LNG Finalizes Subscription Agreement with Sinopec

- Australia Pacific LNG Finalizes Subscription Agreement with Sinopec

Tuesday, August 09, 2011
Origin Energy Ltd.

Origin Energy advised that the Subscription Agreement facilitating the acquisition by Sinopec of a 15% ownership interest in Australia Pacific LNG has been completed.

In addition, all conditions precedent have now been met for the sale of 4.31 million tonnes of LNG per annum by Australia Pacific LNG to Sinopec, commencing in 2015.

Australia Pacific LNG received US $1.765 billion for the 15% ownership interest. As a consequence, ConocoPhillips' and Origin Energy's ownership interest in Australia Pacific LNG has been diluted to 42.5% each.

This investment by Sinopec provides a net reduction in funding requirements of US $750 million to each of Origin and ConocoPhillips (being 42.5% of US $1.765 billion).

Origin Managing Director and Chairman of Australia Pacific LNG, Mr. Grant King said, "We officially welcome Sinopec to Australia Pacific LNG as a shareholder and foundation customer. We look forward to working alongside ConocoPhillips and Sinopec to deliver the Australia Pacific LNG project, drawing on the extensive experience and capabilities within the joint venture in CSG production, development and operation of LNG facilities."

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GTI Boosts Marcellus Presence with Pittsburgh Office

- GTI Boosts Marcellus Presence with Pittsburgh Office

Tuesday, August 09, 2011
Gas Technology Institute

Gas Technology Institute (GTI) on Wednesday announced the opening of the organization's newest office in Pittsburgh, PA. Headquartered in the Chicago suburb of Des Plaines, IL, GTI has field offices across the country, and the new office in Pittsburgh represents GTI's local commitment to the natural gas industry in the Marcellus Shale fairway and the surrounding region.

GTI's continued growth in this region will be achieved by generating effective technology development and services based on customer needs, and through partnering to develop technology, create collaborative opportunities and achieve strategic business results. The efforts led by the Pittsburgh Office will advance the development of innovative solutions to the region's most pressing challenges.

"We're excited about establishing a stronger presence in this important region," says David Carroll, President and CEO of GTI. "We are committed to the future of natural gas and see tremendous opportunity for growth in the shale market where GTI has performed analysis since the 1980s. Our new office location will help us provide the continued high-level customer service and technology developments that will help meet today's complex energy and environmental challenges."

The Director of the Pittsburgh office is Patrick Findle, who has worked for GTI earlier in his career and has returned to help establish a strategic beachhead for business growth. He brings many years of technology business development in the natural gas industry that will help GTI build industry relationships and facilitate new business.

Notes Findle, "Along with growing global demand for natural gas, there is a correlating demand for new technologies to enable and ensure its responsible production, distribution, and use. The opening of the Pittsburgh Office is evidence of GTI's commitment to become a valued resource and partner to the natural gas industry as it transforms this region."

The GTI PA office can be found at 800 Old Pond Road, Suite 706 B, Bridgeville, PA 15017; 412-319-7249.

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ReneSola Reported Q2 Results; Issued Guidance

- ReneSola Reported Q2 Results; Issued Guidance

Aug 9, 2011

ReneSola (NYSE:SOL) reported Q2 EPS of $0.02, missing consensus estimates of $0.16 per share. Revenues fell 1.8% year-over-year to $249.3 million, vs. consensus estimates of $147.6 million.

Mr. Xianshou Li, ReneSola's chief executive officer said, "Both wafer and module prices fell faster than expected in the second quarter as European subsidy cuts weakened demand and led to oversupply in the industry. Although this affected both our top and bottom lines, we were able to maintain a gross margin of 18.4% with our industry-low wafer processing costs and growing in-house polysilicon production. Our new Virtus wafer, a multicrystalline wafer that can achieve cell efficiency rates of up to 18.2%, has an even higher profit margin than our existing wafers and has been well-received by clients with its high efficiency-to-price ratio. We expect Virtus wafers to replace all of ReneSola's existing multicrystalline wafers by the end of 2011. As the solar market matures, we will continue to focus on wafer production to capitalize on our brand name, scale of operations and innovative technologies to lead the industry in cost-competitive solar manufacturing."

The company expects Q3 revenues of $220 to $240 million, vs. consensus estimates of $166.63 million.

Renesola has a potential upside of 132.4% based on a current price of $2.77 and an average consensus analyst price target of $6.43.

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OPEC Shaves Oil Demand Outlook, Sees 'Dark Clouds' over Econ

- OPEC Shaves Oil Demand Outlook, Sees 'Dark Clouds' over Econ

Tuesday, August 09, 2011
Dow Jones Newswires
LONDON
by Benoit Faucon

OPEC Tuesday trimmed its global oil demand growth forecast for 2011 and warned it could cut the outlook further, signaling that mounting economic woes are biting into the world's crude consumption.

In its monthly report, the Organization of Petroleum Exporting Countries reduced the global demand growth forecast for this year by 150,000 barrels of oil a day--the deepest such cut this year--on a downgrade in its U.S. economic growth outlook and weakening Chinese prospects.

"Dark clouds over the economy are already impacting the market's direction," OPEC said. "The potential for consequent deterioration in market stability requires higher vigilance and close monitoring of developments over the coming months."

Global oil demand will still rise by 1.2 million barrels a day, and the downgrade represents only a fraction of the 88.14 million barrels a day OPEC expects to be consumed this year worldwide.

OPEC warned that were higher oil prices to persist or the most industrialized economies to suffer further setbacks, it might trim the forecast by another 200,000 barrels a day. OPEC produces more than one in three barrels consumed worldwide each day.

Coming hard on the heels of a drop in oil prices by over 10% since early August, the downgrade could give ammunition to an Iran-led group that has fought higher oil output. A June OPEC meeting in Vienna ended in acrimony after a Saudi Arabia-led group failed to persuade OPEC that an anticipated surge in oil demand this year merited an output increase.

OPEC Tuesday cut its U.S. economic growth forecast to 1.8% in 2011 from 2.5% previously. U.S. oil consumption data for May showed the largest decline observed since January 2010 and demand contraction in industrialized countries was expected to continue.

OPEC also said demand in China--the engine of oil consumption growth in recent years-has been losing steam. The country's factory sector grew in June at its slowest pace in 28 months, OPEC said.

OPEC estimated demand for its own crude remained unchanged for 2011 and is still up 200,000 barrels compared to last year, as the global demand downgrade is offset by lower-than-expected non-OPEC supply. The OPEC oil demand outlook, however, was cut by 100,000 barrels a day for next year.

But the group's data also still points to a supply gap of 811,000 barrels a day in the second half of this year, according to a Dow Jones calculation of the difference between current oil output and OPEC's demand forecast for the coming period.

But the crystal ball will roll into the consumers' camp with the U.S. Energy Information Administration expected to release its own report later Tuesday, followed by the International Energy Agency Wednesday.

Copyright (c) 2011 Dow Jones & Company, Inc.

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Tethys Opens Doris Facilities in Kazakhstan

- Tethys Opens Doris Facilities in Kazakhstan

Tuesday, August 09, 2011
Tethys Petroleum Ltd.

Tethys announced the opening of its Doris oil production facilities in Kazakhstan.

Oil is currently being trucked from this location at a rate of approximately 1,500 barrels of oil per day ("bopd"), which will increase to 2-2,500 bopd with the new production facilities. With the opening of the new rail-loading facility in 4Q of this year, which will reduce the trucking distance by half, it is planned to increase production to 4,000 bopd. The production facility and terminal are designed for potentially much greater production rates in the future.

Dr. David Robson, Chairman, President and Chief Executive Officer of Tethys, who inaugurated the facilities together with the Deputy Governor of the Shalkar Region and the Governor of Bozoi, said, "This is an important step forward in the development of the Doris oilfield. The increase in production capacity and the ability to produce refinery grade crude oil is crucial to the further development of the Doris oilfield. In addition to the increased sales volumes Tethys will also realise better margins. Our Kazakh team have done a tremendous job in delivering this project on time and on budget, particularly in the remote location of Bozoi and I congratulate them on this important milestone. We would expect to see further production increases as we continue to expand the facilities and drill new wells on the Doris field. This is a great day for Tethys!"

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Carrizo Reports Record Production for 2Q11

- Carrizo Reports Record Production for 2Q11

Tuesday, August 09, 2011
Carrizo O&G Inc.

Carrizo announced financial results for the second quarter of 2011, which included the following highlights:

Results for the Second Quarter of 2011

Record production of 11.2 Bcfe, or 122,788 Mcfe/d
Revenue of $50.7 million or adjusted revenue, of $54.1 million, including the impact of realized hedges
Net Income of $7.7 million, or Adjusted Net Income, as defined below, of $9.5 million
EBITDA, as defined below, of $41.8 million

Production volumes during the three months ended June 30, 2011 were a record 11.2 Bcfe, an increase of 1.9 Bcfe, or 20%, from second quarter 2010 production of 9.3 Bcfe and an increase of 0.5 Bcfe, or 5% from first quarter 2011 production of 10.7 Bcfe. The increase in production from the second quarter of 2010 and the first quarter 2011 to the second quarter of 2011 was primarily due to increased production from new wells in the Barnett Shale, Eagle Ford Shale and Niobrara Formation, partially offset by normal production decline and the sale of substantially all of our non-core area Barnett Shale properties to KKR Natural Resources ("KKR") in May 2011.

Adjusted revenues were $54.1 million for the second quarter of 2011, which includes oil and gas revenues of $50.7 million and realized hedge gains of $3.4 million, compared to $43.5 million for the second quarter of 2010, which includes oil and gas revenues of $32.9 million and realized hedge gains of $10.6 million. The increase in adjusted revenues was primarily driven by increased production, particularly higher oil and condensate production in the Eagle Ford Shale, and higher oil prices partially offset by lower realized hedge gains. Including the impact of realized hedges, the Company's average realized gas price decreased 13% to $3.83 per Mcfe for the second quarter of 2011 compared to $4.40 per Mcfe for the second quarter of 2010 and the average realized oil price increased 1% to $93.90 per barrel for the second quarter of 2011 compared to $93.30 per barrel for the second quarter of 2010. Revenues excluding the impact of realized hedges are presented in the table below.

Adjusted net income, which excludes certain non-cash items described in the statements of operations included below ("Adjusted Net Income"), was $9.5 million, or $0.25 and $0.24 per basic and diluted share, respectively, during the second quarter of 2011, including a $3.3 million benefit of cash distributions received from a joint venture partner as described below, as compared to $11.3 million, or $0.33 per basic and diluted share, during the second quarter of 2010. The Company reported net income of $7.7 million, or $0.20 per basic and diluted share, for the quarter ended June 30, 2011, as compared to net income of $1.8 million, or $0.05 per basic and diluted share, for the same quarter during 2010.

Earnings before interest, income tax, depreciation, depletion and amortization ("EBITDA") as defined in the Company's new U.S. senior secured revolving credit facility ("Credit Facility") and described in the statements of operations included below was $41.8 million, or $1.07 and $1.06 per basic and diluted share, respectively, during the second quarter of 2011, including the $3.3 million benefit of cash distributions received from a joint venture partner as described below, as compared to $31.6 million, or $0.93 and $0.92 per basic and diluted share, respectively, during the second quarter of 2010. During the second quarter of 2011, the Company received cash distributions of $3.3 million on its B Unit investment in ACP II Marcellus, LLC ("ACP II"), a joint venture partner in the Marcellus Shale that is an affiliate of Avista Capital Partners, LP, a private equity fund, as a result of ACP II's distribution to Avista of remaining proceeds from its sale of oil and gas properties to an affiliate of Reliance Industries Limited ("Reliance"). Although such cash distributions are included in EBITDA and Adjusted Net Income, such cash distributions are recognized as a reduction of oil and gas property costs under the full cost method of accounting and accordingly are not included in net income.

Lease operating expenses (including transportation costs of $1.6 million) were $7.4 million (or $0.66 per Mcfe) for the three months ended June 30, 2011 as compared to lease operating expenses (including transportation costs of $1.5 million) of $6.2 million (or $0.66 per Mcfe) for the second quarter of 2010. Lease operating expenses increased due to increased production primarily attributable to new wells in the Barnett Shale, Eagle Ford Shale and Niobrara Formation. Although we continued to experience a decrease in the operating cost per Mcfe of our Barnett Shale production, driven by comparatively less salt water disposal costs in the core area of the Barnett Shale as compared to production from other areas of the Barnett Shale, this decrease was offset by increased operating cost per Mcfe associated with higher cost oil production.

Production taxes were $1.5 million (or 2.89% of revenues) for the three months ended June 30, 2011 as compared to $0.9 million (or 2.69% of revenues) for the three months ended June 30, 2010. The increases in production taxes and the percentage of revenues are due to increased oil production, which has a higher effective production tax rate as compared to natural gas.

Ad valorem taxes increased to $1.0 million (or $0.05 per Mcfe) for the three months ended June 30, 2011 from $0.5 million ($0.09 per Mcfe) for the same period in 2010. The increase in ad valorem taxes is due to new oil and gas wells drilled in 2010 as well as a reduction in ad valorem taxes recorded in the second quarter of 2010 reflecting a true up of our first quarter 2010 estimate. The decrease in the per Mcfe amounts is due primarily to this true up of the first quarter 2010 estimate.

General and administrative expense was $5.7 million during the three months ended June 30, 2011 as compared to $4.3 million during the three months ended June 30, 2010. The increase was primarily due to increased compensation costs related to an increase in the number of employees in the second quarter of 2011.

Depreciation, depletion and amortization ("DD&A") expense for the three months ended June 30, 2011 increased to $20.6 million (or $1.84 per Mcfe) from $11.1 million (or $1.19 per Mcfe) for the same period in 2010. The increases in DD&A and the related per Mcfe amounts were primarily due to increased production during the second quarter of 2011 as compared to the same period in 2010 and increased future development costs associated with crude oil and natural gas liquids reserves in the Eagle Ford which were added during the fourth quarter of 2010 and have a higher future development cost per equivalent unit than the Company's proved gas reserves. The increase in the second quarter 2011 forecasted DD&A of $1.58 per Mcfe to the actual DD&A of $1.84 per Mcfe is largely due to increased production in the second quarter of 2011 as compared to the first quarter of 2011 as well as an increase in prior year's estimated future development costs in the Eagle Ford.

Cash interest expense, net of amounts capitalized, increased to $6.1 million for the second quarter of 2011 compared to $2.9 million for the second quarter of 2010. The increase was primarily attributable to interest on the $400 million aggregate principal amount of Senior Notes issued in the fourth quarter of 2010 partially offset by decreased interest attributable to the $300 million aggregate principal amount of Convertible Senior Notes repurchased in a tender offer during the fourth quarter of 2010.

An unrealized gain on derivatives of $8.1 million was recorded for the second quarter of 2011 compared to an unrealized loss on derivatives of $7.4 million for the second quarter of 2010 due to the change in fair value of our open derivative positions during those periods.

Non-cash, stock-based compensation expense increased to $6.8 million for the three months ended June 30, 2011 from $3.2 million for the same period in 2010. The increase was largely attributable to additional stock appreciation rights as well as stock appreciation rights that increased in fair value.

Non-cash interest expense, net of amounts capitalized, decreased to $0.7 million for the second quarter of 2011 compared to $1.9 million for the second quarter of 2010, primarily due to decreased amortization of the discount as a result of the $300 million aggregate principal amount of the Convertible Senior Notes repurchased in a tender offer during the fourth quarter of 2010.

During the second quarter of 2011, we contributed $1.0 million in common stock to the Carrizo Oil & Gas, Inc. endowed scholarship fund at the University of Texas at Arlington ("UTA") where we are producing natural gas from a number of wells in the Barnett Shale play.

The effective income tax rate was 31.8% for the second quarter of 2011 and 15.0% for the second quarter of 2010. Our estimated annual effective income tax rate for 2011 is approximately 37%, substantially all of which we expect to be deferred. The effective income tax rate for the second quarter of 2011 was lower than 37% primarily due to the true up of prior estimates of the foreign tax benefit associated with the Company's UK Huntington field development. The lower rate in the second quarter of 2010 was due to a true up of prior estimates of state income tax.

Carrizo's President and CEO, S. P. "Chip" Johnson, IV, commented on recent activity, "In late July we initiated sales from a three well pad producing from the Eagle Ford Shale on our Mumme lease in La Salle County, Texas, and from our Orlando Hill well in the Niobrara Formation. These events marked an inflection point in our liquids production growth ramp. We anticipate the oil production from these new wells to be followed by a fairly steady increase for the remainder of the year, with each month's oil production sequentially higher than the last, as a sufficient inventory of drilled wells has been built in the Eagle Ford and Niobrara to allow the execution of a continuous completion program.

"While still flowing back significant quantities of completion fluid, the Mumme 30H, 31H and 32H have each reached rates between 920 BOE per day and 1,184 BOE per day, consisting of 720-984 barrels of oil and approximately 1,200 Mcf of high BTU natural gas which went directly to sales in the existing lease gas gathering system. Following stabilization, we intend to flow these wells at constrained rates to maximize ultimate recoveries. We expect to begin completion of a three well pad on the Glover lease in Atascosa County later this month and anticipate first sales to occur in mid-September. Our recently completed well in the Niobrara Formation, the Orlando Hill 26-44-8-61 in Weld County, Colorado, reached a peak 24 hour production rate of 650 bopd on July 17th and averaged 580 bopd over the following week. The Nelson 17-44-9-60 well has also been completed and is currently flowing back completion fluid with a strong oil cut. An additional Niobrara well, the Wickstrom 7-11-5-60, has been drilled to total depth and is scheduled for completion later this month. We continue to be satisfied with the results of our Niobrara program and expect to be able to average adding a new well to production each month for the rest of 2011.

"The production contribution from our Eagle Ford completion program and our Niobrara activity should allow us to exit the year 2011 at or above our previous guidance of 5,000 net bopd. This growth in liquids production, in addition to the improved well performance from the Barnett Shale, gives us confidence in meeting our 2011 production growth forecast of 32% (after adjustment for the sale of a portion of our Barnett Shale properties to KKR earlier this year)."

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