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Oil and Gas Energy News Update

Tuesday, July 19, 2011

Oil & Gas Post - All News Report for Tuesday, July 19, 2011

Tuesday, July 19, 2011

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Commodity Corner: Oil Gains on Positive Economy Outlook

- Commodity Corner: Oil Gains on Positive Economy Outlook

Tuesday, July 19, 2011
Rigzone Staff
by Saaniya Bangee

Light, sweet crude soared Tuesday on positive U.S. housing data and hope that the European debt crisis may soon be resolved.

Oil futures gained $1.57 Tuesday after the U.S. Commerce Department reported a surge in housing starts. According to data, June housing starts jumped 14.6 percent to a five-month high. An increase in housing starts represents an improvement in the economy.

However, analysts anticipate markets to remain restless until a Thursday meeting, during which European officials will discuss an additional bailout for Greece.

President Barack Obama released a statement Tuesday indicating some progress on U.S. debt-ceiling talks. Consequently, the euro rose higher against the greenback. Measuring the dollar against major foreign currencies, the dollar index edged lower Tuesday.

After fluctuating between $95.93 and $98.65, crude for August delivery settled at $97.50 a barrel, up $1.57. Likewise, its European counterpart gained $1.01 to settle at $117.06 a barrel. The intraday range for September Brent crude was $116.09 to $118.45 a barrel.

In other NYMEX trading, August natural gas lost 2 cents to end Tuesday's trading session at $4.511 per gallon. Meanwhile, front-month reformulated gasoline blendstock (RBOB) rose 0.6 percent, settling at $3.11 a gallon. Prices traded between $3.10 and $3.15 Tuesday.

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Doxa Brings Tx. Well Online

- Doxa Brings Tx. Well Online

Tuesday, July 19, 2011

Doxa announced the successful completion and commencement of production from its Martin-State Gas Unit No. 1 well, a high rate, Wilcox formation gas condensate well in McMullen County, Texas. The Company expects that production from this well will add substantially to its monthly net cash flow, and will achieve payout within one year.

This is the Company's first of 2-3 wells planned on its 623 gross acre County Line Prospect, in which Doxa owns a 14.0625% working interest and a respective 10.4867% net revenue interest. Hurd Enterprises, Ltd. of San Antonio, Texas, is the designated Operator of this prospect.

After drilling the well to a total depth of 11,800', the well was initially completed in the lowermost pay interval from 10,466-10,482'. During the 4-point production test, the well flowed naturally at the high rate of 4,297 MCFPD and 101 BCPD on a 12/64" choke with 5,945 psi tubing pressure. The well was placed on-line last month flowing at a restricted rate of approximately 3,200 MCFPD, 60 BCPD and 5 BWPD. As stated, additional wells are expected to be drilled on the project, and Doxa will maintain its 14.0625% working interest in any such subsequent operations or wells.

"The success of the Martin State No. 1 is meaningful not only for the immediate impact on our sales and profitability but also for the increased potential in the balance of our County Line Prospect along with our other Wilcox prospect holdings," stated John D. Harvison, President and CEO of Doxa. In addition, he stated, "The performance of this well validates our team's analysis of this area for prolific Wilcox hydrocarbon potential."

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Flexlife Opens New Base in UK

- Flexlife Opens New Base in UK

Tuesday, July 19, 2011

Flexlife has opened a new base in Newcastle and plans to recruit 25 staff by the end of this year, rising to 50 within 18 months.

The award-winning company has appointed Andrew Lake as Director of Operations in Newcastle. He is a Chartered Engineer with more than 30 years experience, including senior roles at Soil Machine Dynamics, BPP Technical Services and Wellstream International. He holds a 1st class Mechanical Engineering degree and is a Member of both the Institute of Mechanical Engineers and the Association for Project Management.

As well as attracting new recruits into the industry, Flexlife believes the location will be a draw to many workers who commute weekly to Aberdeen and other energy hubs at present. The office is at the newly developed Baltic Place on the quayside near to the Millenium Bridge.

Chief Operating Officer John Marsden said, "We know from our experience that there is a talented pool of highly-skilled staff in the Newcastle area and we are hoping to tap into that. We have the best team in the industry and are confident we will quickly attract the same caliber of staff for our Newcastle office. We are already off to a great start with Andy taking charge of our operations in Newcastle."

Mr. Lake said, "Flexlife is experiencing a period of significant growth and the new office will expand our capability to offer specialized support to our clients. The choice of Newcastle for this latest expansion recognizes the skills in the region and will be a new addition to the growing subsea sector in the North East of England."

Mr. Marsden added, "Flexlife has continued to build on its reputation for offering a full subsea integrity and project management package, assisting clients to cost-effectively manage all of their subsea assets and infrastructure. Looking ahead, the Newcastle office will provide us with the capability to expand our range of services to include front end engineering design to support the ongoing work for our clients."

Flexlife reported an increase in turnover of more than 50% for year ending 2010/11, with a rise from £4.8million to £7.5million. A further rise to £17.8million is predicted for 2011/12.

As well as the new office in Newcastle, Flexlife has moved into premises in Brazil and taken on a new global HQ in Aberdeen. The company also operates in Africa, the Far East and Mediterranean and staff numbers globally are expected to reach 120 by the end of this year.

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Baker Supports Marcellus Initiative with New Office

- Baker Supports Marcellus Initiative with New Office

Tuesday, July 19, 2011
Michael Baker Corp.

Michael Baker has established a new office in Towanda, Bradford County, Pa., in support of its Marcellus Shale initiative and growing client base across the Marcellus Shale region from Pittsburgh to north central Pennsylvania to south central New York.

Baker's Matthew Natale, P.E., assistant vice president, said, "Opening the Towanda office allows Baker to provide both staff and services more efficiently to current Marcellus Shale clients in northern Pennsylvania. It will also accommodate growth of shale service areas currently provided out of other Baker offices in Pennsylvania and West Virginia."

"With nearly 1,000 professionals based in offices across the entire Marcellus Shale region, Baker is well-positioned to provide a considerable range of services including surveying and geospatial, well pad design and permitting, pipeline and facilities design, roadway rehabilitation support, and construction management/construction inspection services," added Christine S. Mayernik, P.E., PMP, vice president and coordinator of Baker's Marcellus Shale services. "The new Towanda office further demonstrates our commitment to the region and support of our membership in the Marcellus Shale Coalition."

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Nighthawk Welcomes COO

- Nighthawk Welcomes COO

Tuesday, July 19, 2011
Nighthawk Energy plc

Nighthawk announced the appointment of Mr. Charles (Chuck) H. Wilson to the Executive Management team as Chief Operating Officer. Chuck will commence his role on August 1, 2011.

Chuck brings over 30 years of drilling and completions experience, most recently as VP Operations and Engineering at Gasco Energy and holds a degree in Petroleum Engineering from the University of Wyoming.

Chuck has extensive knowledge of developing and undertaking vertical and horizontal drilling and completion programs within the United States and internationally. He has held operational and senior management positions with organizations such as Maxus Energy and Forest Oil Corporation.

Tim Heeley, Chief Executive of Nighthawk, commented, "We are delighted that Chuck has joined Nighthawk at an exciting juncture in our redevelopment. Chuck brings extensive experience of operating in the Denver basin plus a proven track record in optimizing production and driving cost savings in drilling and completion programs. His particular expertise of designing and implementing technical solutions for completion operations will be of real benefit as the Company focuses on becoming more engaged in the operational aspects of developing the Jolly Ranch Shale Project."

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Energy Transfer, Southern Union Reach $5.7B Deal

- Energy Transfer, Southern Union Reach $5.7B Deal

Tuesday, July 19, 2011
Dow Jones Newswires
by Ben Lefebvre

Southern Union agreed to a sweetened $5.7 billion cash-and-stock buyout offer from Energy Transfer Equity, spurning a bid from rival suitor Williams Cos.

The agreement is the latest maneuver in a bidding war that has added more than a billion dollars to Energy Transfer's opening $4.2 billion bid for Southern in mid-June. Energy Transfer and Williams have competed to merge their pipeline assets with those of Southern, with the winner expected to become the largest natural gas pipeline operator in the country.

Williams, whose most recent bid was for $5.6 billion on July 14, said it was "evaluating its options."

Enterprise and Williams have hoped that combining their position in prolific natural gas production areas with Southern's access to markets will make them better able to transport natural gas through what is becoming an increasingly congested system. The glut has been brought about by new drilling technology, which in the past decade has unlocked an unprecedented natural gas bounty from shale formations across the U.S.

The combined company will have capacity to move more than 30 billion cubic feet a day of natural gas--nearly half of the natural gas produced in the U.S.--along nearly 45,000 miles of pipeline.

Southern shareholders may have been swayed by Energy Transfer's use of stock in the deal, which would offer tax benefits and dividends, analysts have said. Energy Transfer's assets in Texas might also fit easier with Southern's position in markets in the Midwest and Florida, said Morningstar analyst Avi Feinberg.

"I think Energy Transfer has the best natural fit with Southern Union," Feinberg said in an interview.

Under Energy Transfer's latest offer, Southern Union holders can elect to receive $44.25 in cash or one Energy Transfer Equity common unit, worth $44.03 as of Monday's close. The total value of the deal, including debt assumption, is about $9.4 billion.

Williams may find going above $44 a share problematic, as the amount could be more than Southern might be worth to shareholders, BMO Capital Markets analysts have said.

Energy Transfer on Tuesday also reached an amended agreement to sell Southern Union's 50% interest in Citrus Corp., owner of the Florida Gas Transmission pipeline system, to Energy Transfer Partners LP for $2 billion. Regulators are requiring Energy Transfer Equity to sell the stake when the Southern Union acquisition closes.

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

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Niobrara's Slow Start Not Cause for Worry

- Niobrara's Slow Start Not Cause for Worry

Tuesday, July 19, 2011
Knight Ridder/Tribune Business News
by Trevor Brown, Wyoming Tribune-Eagle, Cheyenne

The Niobrara oil play is off to a slow start, but state and industry officials say that is not unexpected or a reason for concern.

No oil rigs were operating in southeast Wyoming as of last Wednesday. This is down from about six in the area two months ago.

Wyoming Oil and Gas Conservation Commission Supervisor Tom Doll said many oil companies are waiting for updated seismic maps that show the underground Niobrara formation before they commit to expensive drilling operations.

"You want to get as much data as possible so you don't drill a $3 million to $4 million dry hole," he said. "My expectation is (the companies) want to have another tool of using that additional science to have a better opportunity to drill a productive well."

Texas-based Global Geophysical Services spent much of the spring using trucks and other seismic equipment to map areas beneath the surface of 831 square miles of land in Laramie County.

John Robitaille, vice president of the Petroleum Association of Wyoming, said it can take some time before the 3-D seismic maps are analyzed and sold to the oil companies.

"I can tell you it is some pretty technical data that they receive back," he said. "It then needs to be plotted and made into a format that is readable for the various geologists so they can get their plans made and know where they want to drill.

"And, of course, getting everything in place and lining up a rig takes all sorts of time as well."

Robitaille said he expects the activity to pick up in the fourth quarter of this year. In addition, up to three rigs are expected to return to Laramie County later this month.

According to the Oil and Gas Conservation Commission, 21 wells have been drilled to date in southeast Wyoming for the oil play -- 18 in Laramie County, two in Goshen County and one in Platte County.

Doll said although the companies are currently hesitant to drill, they are moving forward with other preparations, including obtaining drilling permits.

The Oil and Gas Conservation Commission issued 73 permits for drilling in Laramie County for the first quarter of 2011 and 60 in the second quarter.

In the second, third and fourth quarters of 2010, a combined 64 permits were issued here. Data from the first quarter of 2010 are not available.

Laramie County planner Gary Kranse said he estimates 1,500 drilling permits will be issued during the next five years here.

Both Doll and Robitaille said the relatively low number of wells that have been drilled so far is not a sign the oil play is a bust -- at least not yet.

"I wouldn't be too concerned because this is a slow-moving play," Robitaille said. "It is still very much in the exploratory phase of knowing where to drill."

A representative for Chesapeake Energy, which has announced a large stake in the oil play, would not comment on the specifics of why there has not been more drilling.

But John Dill, director of corporate development and government affairs for the company, agreed this exploratory phase can take some time before increased activity begins.

"It is also a very complex geology, and Chesapeake is only just beginning the process of exploring this vast, complicated play," Dill said in an email. "What may appear to be slow development of this extraordinary resource is primarily due to its size, complexity and the early stages of this effort."

Doll said there is too little information yet to determine how successful the play will be in the end.

This is because of the low number of commercial wells and rules that allow companies to keep their results confidential for up to six months.

"We just haven't seen enough drilling rigs and enough activity to really know if there is a play yet," he said.

Another reason for the oil play's slowdown could be because of increased activity in North Dakota, Doll said.

He said the Bakken oil play is gearing up to have 170 active drilling rigs and up to 290 by the end of the year. That could leave a shortage of equipment and workers for activity here.

"They claim that they are using many new rigs, so that may not be a problem," Doll said. "But my concern is: Where are you going to get the drillers, roughnecks and (fracking) crews who are trained to do the sophisticated work?"

Kranse added that companies could be taking time to develop the right formula for fracking the Niobrara shale.

Hydraulic fracturing, known as fracking, involves injecting a mixture chemicals and water into the earth to extract oil.

Copyright (c) 2011, Wyoming Tribune-Eagle, Cheyenne

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Western N.D. Oil Boom Offers Beacon to Unemployed

- Western N.D. Oil Boom Offers Beacon to Unemployed

Tuesday, July 19, 2011
Knight Ridder/Tribune Business News
by Lisa Miller, The Dickinson Press, N.D.

The diversity of Dickinson continues to grow as more and more people from all parts of the country and walks of life move to western North Dakota for employment.

A recent energy boom including the discovery of oil and gas in the area, have many people seeing dollar signs.

Lexi Sebastian, the executive director of the Dickinson Area Chamber of Commerce , said since the beginning of the year the Chamber has received approximately 500 phone calls and 225 walk-ins requesting information about the community.

She added the chamber receives about 40 contacts a day from people looking to relocate and mails about that many relocation information packets a month.

Steve Kass of Hayward, Wis., is one of those relocators.

He moved to Dickinson after work in Wisconsin slowed.

"I used to work construction, panelizing and building walls," Kass said. "In the summer of 2006 I was working on a big commercial project in Illinois when day after day union carpenters began coming in looking for work. I thought to myself if they are slow what's coming next?"

And he was right.

"By the fall I had to let between 15 and 20 guys go because there was just no business," Kass said. "It was a very difficult thing to do."

Kass then did remodeling on his own until that "petered out" too.

"My family, (wife Amy and kids Tyler and Jordan) were barely getting by and this spring I decided I had to do something," Kass said.

He added a few people in his community were moving to North Dakota because they had heard a lot of places were hiring.

"So I decided to check it out," Kass said. He and a friend packed-up one weekend and attended a job fair.

But on the way one of the tires on the camper the pair was toting blew out near Richardton.

"We went into town for help and a young man offered so we went and got the tire fixed and then he offered to let us park the camper on his dad's farm," Kass said. "One thing that really surprised me was how nice everyone in North Dakota is."

He added other things that surprised him were the lack of trees, general landscape and the amount of wind.

"Everyday there is wind," Kass said laughing.

Two days after the job fair both men were hired.

"It was such a relief," Kass said.

He now works for Steier Oil Field Service as a roustabout.

"Its kind of like being a mechanic. We fix things on location," Kass said.

He added one nice thing about Steier Oil Field Service is that they are big on safety.

"I had no experience," Kass said. "I did not even know what an oil field looked like, but they trained me and things are going well."

Kass said sometimes he feels like a fish out of water yet because of his lack of experience and because most of his coworkers are younger than him.

"My boss is 21, I'm 42," Kass said. "I never thought I'd have to start over again."

Kass said what he misses most is his family.

"I talk to them every day and always get the same question 'Dad when are you coming home?'" Kass said. "It's tough, its really tough to be away from family and missing out on all their big adventures. It's also tough because I have always been the protector and made sure everyone was safe, happy and healthy and I can't do that from here."

He added he really wants to move his family here but can't find affordable housing nor can he sell his home back in Wisconsin because they are having housing problems of the opposite kind.

"My wife is an accountant, so we both have good jobs but in today's economy and cost of living things are tight," Kass said.

Right now Kass and his friend are living in their camper.

"I have to find something before the winter," Kass said. "But if housing stays this way it's almost not worth staying. It's cheaper to buy another house, but then my wife and I will be paying for two houses."

Kass said on a typical day he starts at 6:30 a.m. He heads out to get job orders then goes from location to location and returns to the camper between 7 p.m. and 8 p.m.

"I work as many hours and weekends as I can because I am trying to earn money for my family and because there is nothing to do," Kass said. "Actually I shouldn't say there is nothing to do because that's not true, I just don't feel like going out without my family."

He added once in a while he goes golfing with some friends but many nights he sits at home watches TV, eats a microwave meal, showers and goes to bed.

"It's just so different than what I have done in the past," Kass said. "It's a different way of life."

He added another nice thing is that Steier Oil Field Service doesn't have a problem with employees going home, they are very family friendly.

"The problem for me is home is hundreds of miles away," Kass said. "It's expensive both to fly and drive and it's almost a 10 hour drive. I go home for two days. The time just seems so short but it is worth it."

Kass added the economy everywhere else in the country is crud.

"You hear and learn about the great depression, I never thought I'd live it," Kass said. "No one is hiring back home, people in North Dakota should feel very blessed because it's not like this everywhere else, you really don't know unless you've seen it."

Kass said he wishes he had this kind of work at home not only for himself but his neighbors as well.

Copyright (c) 2011, The Dickinson Press, N.D.

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Aztec's Nine Month Results Exceed Projections

- Aztec's Nine Month Results Exceed Projections

Tuesday, July 19, 2011
Aztec O&G Inc.

Aztec O&G announced the filing of its financial results for the quarter and nine months ending May 31, 2011. Aztec has continued to achieve significant improvement over the reporting period ending August 31, 2010, which 2010 reporting period in turn was significantly higher than Aztec's corresponding 2009 results.

A limited summary of the current filing shows that Aztec's Total Assets increased from $11,433,893 on August 31, 2010 to $24,590,266 for the nine month period ending May 31, 2011, or by approximately 115%. Total Current Assets, including cash of $5,253,905, increased from $5,271,927 on August 31, 2010 to $5,822,822 for the current period. For the same period, Total Liabilities decreased by $296,601, or approximately 10%, Total Equity increased from $8,318,708 to $21,771,682, or by approximately 162%. (All of the foregoing amounts are compared to the period for the fiscal year ending August 31, 2010 and are rounded.)

Oil and natural gas sales increased from $164,110 for the nine months ending May 31, 2010 to $621,649 for the nine months ending May 31, 2011, or approximately 280%. Net Loss for the three months ending May 31, 2010 was ($739,579) and for the current three month period ending May 31, 2011 was ($516,333), a reduction of loss by approximately 30%.

"Aztec is having a very good year and is looking forward to much more of the same, regardless of oil pricing levels. Many years of hard work by some very talented people are definitely resulting in substantial gains for Aztec, which just happens to coincide with some currently high levels of oil pricing. As oil is, and has been since 2008, our focused commodity, that all works out quite well for Aztec," stated Waylan R. Johnson, President of Aztec Oil & Gas, Inc. Mr. Johnson went on to say, "Separately our sponsored drilling programs are doing well and continue to gain more acceptance with the national broker dealer community; plus Aztec's separate, corporate investment projects are also doing quite well. Aztec has interests in over 200 wells, and is active in approximately 14 counties in Texas, plus the states of Missouri and West Virginia."

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Entek Launches Green River Basin Work Program

- Entek Launches Green River Basin Work Program

Tuesday, July 19, 2011
Entek Energy Ltd.

Entek announced the commencement of its Green River Basin work program for 2011.

DHS Rig-18 has spudded the Battle Mountain 14-10L well, which is the first of a minimum 3 well Niobrara Shale Oil appraisal drilling program in 2011. Battle Mountain 14-10L was selected from 7 currently permitted well locations based on close proximity to the Battle Mountain 14-15 well which flowed oil last year against all odds from a severely damage well bore (drilled by the previous operator). Subsequent wells in the program will be located based on drilling results, local operating season constraints and field operational considerations.

Entek holds a 55% interest in the Green River Basin Joint Venture (GRBJV) with Emerald Oil & Gas NL holding 45%. Entek is the Operator of the GRBJV. As a result of continued leasing activity and ongoing lease maintenance the GRBJV now controls close to 80,000 gross acres, approximately 60,000 net acres, covering the Niobrara Shale Oil Play.

The wells planned in the 2011 appraisal program will be drilled vertically to intersect the oilprone Niobrara Shale which can be up to 1,100 ft thick in the area. The wells are expected to penetrate the brittle naturally fractured bench intervals within the Niobrara section that have been proven as porous and permeable reservoirs in offset wells. As an example the Sierra Madre 12-20 well owned by Anadarko which is approximately 8 miles from the 14-10 well, had initial production of around 550 BOPD, has recovered in excess of 355,000 BO and is still on production. In addition, the fractured igneous intrusive reservoirs that are present in this area will be further
evaluated. The Company's Focus Ranch 12-1 well (which was tested in 2009 at a cumulative rate of 240 BOPD and 2.75 MMCFD) has already indicated the potential of the igneous intrusive reservoirs in the area.

The primary objectives of the 2011 vertical well appraisal program are to:
  • establish deliverability and commercial production of the oil prone Niobrara Shale;
  • identify the most prospective Niobrara intervals;
  • gather technical information necessary to design and execute effective fracture stimulation treatments; and
  • select which intervals to target with both vertical and horizontal wells in 2012 as part of the continued appraisal and development program.

The Company is working closely with Halliburton to design fracture stimulation treatments for at least one interval in each well this year with scheduled slots available from August. Initial flow test results from these wells are not expected to be available immediately after reaching total depth and logging. Rather, weekly announcements will be made each Thursday morning where drilling progress, fracture stimulation, testing and completion operations for each well will be updated as these operations will be occurring concurrently across all wells in the work program.

Interested parties are directed to review the Investor Presentation (to be presented to institutional investors from July) that was released to the ASX on July 14, 2011 for further information on the Niobrara Shale Oil Project in the Green River Basin as well as the Company's
update on its recent successful oil discovery in the Gulf of Mexico.

CEO and Managing Director Trent Spry commented, "It is exciting to have commenced our 2011 Green River Basin appraisal program. I am certain that our appraisal efforts in 2011 will provide the Company with the information and confidence it needs to accelerate appraisal and development in 2012. We are seeing increased industry activity across leasing, well permitting (both vertical and horizontal), and acreage acquisitions and transactions in the area as the attention shifts from the DJ Basin to the Green River Basin this
year. Industry activity and success will provide valuable information on the Niobrara in the GRB and is expected to have a significant impact on acreage value. I look forward to providing further updates from now until the end of the year on what is an exciting time for the Company."

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Bow Boosts 2P Certified Reserves by 60%

- Bow Boosts 2P Certified Reserves by 60%

Tuesday, July 19, 2011
Bow Energy Ltd.

Bow has obtained further 2P certified reserves in the Blackwater CSG Field (ATP 1025P) increasing Bow's total certified reserves to 238 PJ of 2P and 2,752 PJ of 3P reserves.

As previously announced Bow has reached an agreement to share exploration and production data with a number of CSG companies operating in the Bowen Basin. This has allowed data on adjacent Exploration Permits and Petroleum Leases to be extrapolated across permit and or lease boundaries. Based on the data from pilot production wells adjacent to Bow's Blackwater CSG field, along with Bow's previous core hole data, MHA Petroleum Consultants, Inc (MHA) have certified within the Rangal coal measures of Bow's Blackwater field (ATP 1025P) a further 89 PJ of 2P and 13 PJ of 3P. Several pilot production programs are in progress at Blackwater with 10 wells in various stages of dewatering. The aim of these programs is to test different well design and completion techniques to determine the optimal commercial production methods.

CEO, John De Stefani commented, "the new gas reserves at Blackwater follow on from our previous announcement regarding the recognition of the initial reserves at Norwich Park and are a further step towards achieving our goal from the current funded work programs of 1,250PJ 2P and 6,200PJ 3P reserves. Pilot programs are continuing on the Blackwater CSG Field with a series of pilot wells aimed at obtaining further reserve upgrades."

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ConOps Service Launched to Reduce Integrated Control System Risk

- ConOps Service Launched to Reduce Integrated Control System Risk

Tuesday, July 19, 2011
Rigzone Staff

Houston-based Athens Group, a provider of risk reduction services for control systems software on high-specification offshore assets, today unveiled its new Concept of Operations (ConOps) service.

Output from this service, a ConOps document, helps reduce integrated control system-related risks, such as non-productive time (NPT), health, safety and environmental incidents, from the very beginning of newbuild and refurbishment projects.

A ConOps document, or text document, defines from the owner's perspective performance, quality, health, safety and environmental (PQHSE) expectations; validation and verification requirements by project phase; and contractual requirements for the owner to sign by project phase.

Most offshore assets are now built or refurbished through turnkey, builder furnished equipment contracts. This procurement model makes it challenging for the asset owner to exercise the level of oversight and control needed to hold their vendors accountable for delivering a safe, reliable, and fit-for-purpose asset, the company said.

In Athens Group's recent industry survey, The State of NPT on High-Specification Offshore Assets: Third Annual Benchmarking Report, 89 percent of drilling contractors and operators identified the development of a software-specific risk mitigation plan as an opportunity the reduce NPT. Implementing a ConOps phase is the critical first step in mitigating software risk throughout the offset asset life-cycle, Athens Group said in a statement.

"Many of the project delays and much of the NPT we've seen could have been prevented if risk reduction planning had started earlier in the project life-cycle," said Athens Group CEO Mike Haney, noting that other industries that rely on large, one-of-a-kind systems integration projects have significantly reduced risk by starting each project with a Concept of Operations document.

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Energy Transfer Equity, Southern Union Announce Amended Merger Agreement

-  Energy Transfer Equity, Southern Union Announce Amended Merger Agreement

Jul 19, 2011

Energy Transfer Equity (NYSE:ETE) and Southern Union (NYSE:SUG) announced that they have entered into an amended and restated merger agreement under which Energy Transfer Equity will acquire Southern Union for $9.4B, including $5.7B in cash and Energy Transfer Equity common units. Under the terms of the revised agreement, which has been unanimously approved by the boards of directors of both companies, Southern Union shareholders can elect to exchange their common shares for $44.25 of cash or one Energy Transfer Equity common unit.

Shares of Southern Union are trading up over 2% to $44.23 on the news.

Energy Transfer Equity has a potential upside of 16.7% based on a current price of $43.86 and an average consensus analyst price target of $51.17.

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Growing Population, Economies Fuel Asian LNG Demand

- Growing Population, Economies Fuel Asian LNG Demand

Tuesday, July 19, 2011
Rigzone Staff
by Karen Boman

Southeast Asian demand for liquefied natural gas (LNG) will play a significant role in the global LNG trade as forecasts call for growing populations and economies in the region and demand for cleaner-burning natural gas.

According to the U.S. Energy Information Administration, Asia is expected to account for 48 percent of the world's population growth, 52 percent of global gross domestic product growth, and 64 percent of growth in primary energy consumption. Demand for LNG is expected to grow in China, India, Malaysia and Indonesia in the coming years, and Japan, which was devastated by an earthquake and tsunami in March, has boosted its LNG imports as nuclear power plants in the country remain offline.

Southeast Asian gas markets are often overlooked, but Thailand, Singapore, Indonesia, Malaysia, Vietnam and Bangladesh are expected to become LNG importers by 2017, Flex LNG reported in June. Regasification terminals are under construction in Indonesia, Malaysia, Singapore and Thailand, which previously did not have regasification capacity.

Thailand's first LNG receiving terminal is expected to begin operations this year.

Flex LNG is developing a floating LNG project in Papua New Guinea (PNG) with a proposed operations start-up date in 2014, which the company said is "perfect timing" for the anticipated wave of Asian LNG demand. Northeast Asia remains the dominant LNG market and is still experiencing solid growth, and the Fukushima disaster is greatly enhancing this growth, Flex LNG noted. "China and India are the new 'growth engines' in Asian LNG demand and strong growth is expected going forward," Flex LNG said.

According to a report by the International Gas Union, 60 percent, or 135.1 million tones/annum, of the world's LNG was consumed by the Asia-Pacific region in 2010. Sixty percent of that LNG was sourced from within the region; the remaining 40 percent was imported from other regions.

At the end of 2010, China and traditional LNG importers Japan, Taiwan and Korea had 280 million tones/annum, or 51 percent, of the world's regasification capacity. East Asia had accounted for between 75 percent and 80 percent through of the 1990s and early 2000s of the world's regasification capacity, but that share has declined since the mid-2000s due to new capacity in North America, Europe, and the emergence of LNG importing markets in South Asia, South America, and the Middle East.

Asian LNG markets represent three distinct demand groups, said Peter Cleary, VP of Corporate Strategy and Development of Santos Ltd., at the Asian Oil and Gas Conference on June 7. The first group, comprised of established LNG markets of Japan, South Korea, and Taiwan, are countries seeking supply security and diversification by fuel type. These countries have effectively locked in LNG demand, growing at steady incremental rates of between one percent and three percent of year.

The second group represents the growing mega-markets of China and India, which started to develop less than a decade ago but is expected to grow at 10 percent per year, and could be as significant as established markets.

Last month, Black & Veatch and Chemtex unveiled plans to design and build two new LNG facilities in Shaanxi Province, China. The facilities, located in Jingbian City and Yulin City, will be used to liquefy gas for vehicle fuel in the region, offsetting the use of diesel and gasoline. The Black & Veatch-Chemtex team has won five LNG projects in China since the beginning of 2011, and 13 since 2006.

The third group represents the emerging markets of Southeast Asia, including Singapore, Thailand, Malaysia, Indonesia, Vietnam and the Philippines. This group of emerging buyers includes some of Asia's "bedrock" producers who are now becoming importers, as is the case with Petronas purchasing 3.5 mtpa from the Gladstone LNG project in which Santos, Petronas, Total and Kogas are partners.

While future U.S. LNG exports will impact trade flows, Cleary said he believes Asia's demand for securing supplies from neighboring sources will preserve oil-linked prices for the foreseeable future. "Oil-linked pricing of LNG has been the commercial driver required to build real scale and tackle challenging gas developments. Oil-linked pricing has worked in Asia because buyers are comfortable that oil is an established, well understood and globally traded commodity," Cleary said.

With limited conventional gas resource, industrialized Asia and the emerging economies in that region are almost totally dependent on imported LNG from Southeast Asia, Australia and the Middle East. "This dependence places a high premium on security of supply, which is reflected in the region's dependence on long-term relatively high-priced contracts indexed to oil," according to a study by the Massachusetts Institute of Technology, The Future of Natural Gas.

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Infamous Oil Forecasts that Failed & What Makes a More Solid Forecast

- Infamous Oil Forecasts that Failed & What Makes a More Solid Forecast

Tuesday, July 19, 2011
Rigzone Staff
by Barbara Saunders

Even before Colonel Edwin Drake confirmed a way to drill for crude oil in 1859, pundits were already active in predicting the future of oil. Some called it "Drake's Folly" and forecast that drilling was not the way to reach oh well.

Drake's Folly
Skeptics called America's first drilled oil well "Drake's Folly" and insisted that drilling was no way to reach . . . Oh well.

But oil prices are what draw the primary predictions nowadays, even though $100 per barrel oil is really nothing new. During the Civil War, for instance, the price of oil soared to about $115 per barrel when adjusted for inflation in 2010 dollars. In fact, until an extended period after World War II through about 1970, oil prices were anything but stable and were often above levels seen in the 1980s and 1990's even without inflation taken into account.

Historical Oil Prices in Today's Dollars
In real terms, or adjusted for inflation, oil prices hit the equivalent of $100 per barrel or more in 1861 and again in 1980.

This underscores how poorly oil prices tracked inflation in modern history and the importance of technology in keeping pace with supply, regardless of price. In fact, according to the Society of Petroleum Engineers (SPE,) during the extended periods of low prices after the price crash of 1986, a number of technological advances occurred that lowered finding and lifting costs. These included the polycrystalline carbon drill bit and the expanded use of horizontal drilling.

In terms of price predictions, one of the biggest boners occurred only a few years ago, when forecasters during the summer of 2008 were predicting that oil prices would remain at levels of $150 or higher for the foreseeable future. Then came the global financial meltdown and took oil prices along with it, with an oil price plunge to the $30's by the following winter ooops!

A similar prediction occurred during the 1980's. Following the supply panics of the late 1970's, many were predicting that oil would reach $100 per barrel in nominal, or pre-inflation terms, by or before mid-decade. However, no such thing happened. Consumers, in part, had responded by purchasing much smaller cars than in the past and prices ultimately cratered by mid-decade, into the single digits for some crude grades.

"Beware all forecasts that do not have a strong basis in quantifiable supply/demand trends.

The problem with these particular forecasts was that some were predicated on wishful thinking, primarily by traders, not sound market fundamentals. Beware all forecasts that do not have a strong basis in quantifiable supply/demand trends. Just because renewed tensions have erupted in the Middle East, for instance, does not mean that oil prices are destined to fly up. Some of what is touted as "forecasts" in news bulletins is really the hype of traders hoping to make headlines that will push prices up on the commodity futures markets. Such hype may work briefly, but invariably, when there's nothing backing a prediction, prices will drop back in short order.

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American Standard Begins Tx. Drilling Program

- American Standard Begins Tx. Drilling Program

Tuesday, July 19, 2011
American Standard Energy Corp.

American Standard announced initial spud for its 10 net well drilling program in Andrews County, Texas.

ASEN intends to drill the University Andrews 42 #2 well to the Devonian and then subsequent wells will be drilled to the Strawn and completed in the Strawn, Wolfcamp, Spraberry and Lower Clearfork formations. The Company will own 100% working interests in all 10 wells.

The Viking Rig #20 has arrived on location, is rigging up, and is expected to spud the University 42 #2 well in Andrews County within the next 24 hours.

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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.

  • 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."


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.


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.


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.


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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Harley-Davidson Beats EPS Estimates, Sees Growth in 2011

- Harley-Davidson Beats EPS Estimates, Sees Growth in 2011

Jul 19, 2011

Harley Davidson (NYSE:HOG) reported quarter results of $0.81 per share above consensus estimates of $0.71. Revenue for the quarter rose 18% year-over-year to $1.34 billion ahead of consensus estimates of $1.26 billion.

The Company raised shipment guidance for 2011 and now expects to ship 228,000 to 235,000 Harley-Davidson motorcycles to dealers and distributors worldwide, compared to guidance provided April 19, 2011 of 215,000 to 228,000 motorcycles. In the third quarter of 2011, the Company expects to ship 60,000 to 65,000 motorcycles. For all of 2010, the Company shipped 210,494 motorcycles.

Harley-Davidson is currently above its 50-day moving average (MA) of $38.24 and above its 200-day of $36.91.

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Injuries, Spills in UK Offshore Oil Fall - HSE

- Injuries, Spills in UK Offshore Oil Fall - HSE

Tuesday, July 19, 2011
Dow Jones Newswires
by James Herron & Alexis Flynn

There were less potentially hazardous oil and gas leaks from offshore installations operating in the U.K. North Sea than in the corresponding period a year earlier, although the industry has yet to improve on the record low number of incidents recorded two years ago, data from the Health and Safety Executive showed Tuesday.

There were 73 major or significant hydrocarbon releases offshore in 2010-2011, down from 85 the previous year, the HSE said in its annual statistical report. Few of these releases could be considered as oil spills, it said. However, this was still significantly more than the record low of 61 incidents in 2008-2009. There were only seven incidents where a quantity of hydrocarbon liquid was released to the sea, with the amounts ranging from minimal to 500 kilograms, it said.

No workers were killed and there were 42 major injuries reported in the period, down 16% from 50 reports the prior year, the HSE said. The combined fatal and major injury rate fell to 151.84 per 100,000 workers in 2010-2011 compared with 187.9 in 2009-2010, the third lowest rate over the last 10 years, it said.

There were 432 dangerous occurrences reported in 2010-2011, down 2.5% from 443 in the preceding year, the HSE said.

The backlog of maintenance work on safety critical systems continue to decline, according to data gathered by the industry, the HSE said.

"This year's statistics are a step in the right direction," said Steve Walker, HSE's head of offshore safety. "But there is still much work to be done. Hydrocarbon releases are a key indicator of how well the offshore industry is managing its major accident risks, and the industry still hasn't matched or exceeded the record lows of two years ago," he added.

Walker said companies need to pick up the pace of improvement and that he expects all operators to be drawing up and implementing plans to meet that end.

Robert Paterson, industry body Oil & Gas U.K.'s health and safety director, said the statistics reflect the "significant effort made in the last 12 months to get back on track after last year's disappointing performance."

Paterson said the maintenance of safety critical systems remains of paramount importance for all members of Oil & Gas U.K. but acknowledged "there were still areas for us to improve upon."

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

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PA Resources Hits Gas Pay in Danish North Sea

- PA Resources Hits Gas Pay in Danish North Sea

Tuesday, July 19, 2011
PA Resources AB

PA Resources' subsidiary PA Resources UK Limited announced initial results of the Broder Tuck exploration well (5504/20-4), located approximately 10 kilometers south of Gorm Field in the Danish part of the North Sea.

Following some initial drilling problems, the well was drilled as a vertical well to a total depth of 3,658 meters below mean sea level in layers of Lower Jurassic/Triassic age.

The well encountered approximately 17 meters of net pay in high quality sandstones in the primary Middle Jurassic target. The reservoir was cored and an extensive wireline log, pressure and sample suite has been taken for future evaluation, with well site sample analysis showing the reservoir fluid to be gas with some condensate.

The Broder Tuck well has established a gross hydrocarbon column of at least 230 meters from the crest of the structure down to the base of the column encountered in the well. A sidetrack will now be drilled to assess the potential for additional gas volumes down-dip.

The following companies participate in Lenience 12/06: PA Resources UK Limited (64%), Nordsøfonden (Danish North Sea Fund) (20%), Danoil Exploration A/S (8%) and Spyker Energy APS (a wholly-owned subsidiary of Spyker Energy Plc) (8%).

Bo Askvik, President and CEO at PA Resources, commented, "We are delighted to have made this exciting discovery with our first operated well in the North Sea. I would like to congratulate our exploration/operations team on this outcome and to thank our partners for their continued support. We now look forward to the results of the sidetrack."

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IGas Begins Drilling 3rd Doe Green Well

- IGas Begins Drilling 3rd Doe Green Well

Tuesday, July 19, 2011
IGas Energy plc

IGas Energy has spud its third well at Doe Green (DG-3). This well is being drilled with the BDF Rig 28.

The Doe Green site located between Warrington and Widnes has steadily produced gas and generated electricity for over two years from a pilot well, DG-2.

DG-3 will be the first well drilled under the Company's accelerated drilling program. The company will update the market on the results of drilling and other activity under the program over the coming weeks and months.

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Victoria O&G Ups Stake in Cameroon Field

- Victoria O&G Ups Stake in Cameroon Field

Tuesday, July 19, 2011
Victoria O&G plc

Victoria O&G has increased its effective working interest in the Logbaba gas and gas condensate field in Douala, Cameroon ("Logbaba Concession") to 95% following the serving of a Notice of Forfeiture on July 18, 2011 on RSM Production Corporation ("RSM") which previously had a 38% interest in the Logbaba Concession.

The activities at the Logbaba Concession are regulated by a number of legal agreements between VOG's 100% subsidiary Rodeo Developments Limited ("RDL") and RSM which cover various operating and legal matters including the obligation for RSM to meet appropriately evidenced cash calls raised by RDL for the costs of development and operation at the Logbaba Concession.

RSM failed to make payment under a cash call made on June 15, 2011, and a notice of default was served on July 2, 2011. As RSM failed to rectify the default, RDL has served Notice of Forfeiture in accordance with the Operating Agreement ("Agreement") between RDL and RSM. The effect of this is to require RSM to withdraw from the Agreement and transfer RSM's former interest to RDL.

As announced on 6 May 2011 Societé National des Hydrocarbures, ("SNH") has indicated that it intends to exercise its right to take a 5% participation in the Logbaba Concession, and will pay its share of development costs. Following the forfeiture VOG, through RDL, will have a 95% interest and SNH will have the remaining 5% interest.

Kevin Foo, Chairman of VOG commented, "We are disappointed to be in the position where we have had to take this step, but it is important for all participants to meet their obligations at Logbaba, not just VOG. We look forward to working with SNH to drive this project forward to first gas later this year."

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