GE Selected for Centrica's Projects in N. Sea, Irish Sea

- GE Selected for Centrica's Projects in N. Sea, Irish Sea

Wednesday, September 07, 2011
GE O&G

GE O&G has signed contracts totaling more than $15 million to provide subsea systems to Centrica Energy Upstream of Aberdeen for use in projects in the North Sea and the Irish Sea.

GE reported at Offshore Europe 2011 that it will supply four shallow water vertical tree (SVXT) subsea tree systems for fields in the U.K. Southern North Sea gas basin and the East Irish Sea, and one MVXT system for use in the U.K. Central North Sea.

"The SVXT systems incorporate GE's latest design for shallow water applications and offer new, innovative features to meet Centrica Energy's specific requirements," said Matt Corbin, regional leader—United Kingdom and continental Europe for GE Oil & Gas. "The SVXT tree system is smaller and lighter than any traditional shallow water systems on the market and also offers the lowest installed cost."

The SVXT subsea tree merges horizontal and vertical tree technology, reducing weight by 20 percent, decreasing height and also delivering essential functionality in a pre-engineered, pre-configured modular style. Low-cost installation is achieved through a design that enables deployment using standard offshore jack-up drilling rigs without the need for major modifications.

The MVXT Tree System will be deployed in the Central North Sea and is a standard structured M-Series Vertical Subsea Tree, Nominal 18-3/4" - 5" x 2" 10K system.

"Centrica is at the forefront of developing marginal fields by using new and innovative approaches. The right technology is key to ensuring the economic viability of these fields so we're delighted to be working with GE on its new subsea tree technology," said Greg McKenna, commercial director for Centrica Energy Upstream.

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BP Gets Govt OK for Kinnoull Field Development

- BP Gets Govt OK for Kinnoull Field Development

Tuesday, September 06, 2011
BP plc

On behalf of its co-venturers BP announced an agreement to invest up to £700 million to progress a project to develop the Kinnoull reservoir in the central North Sea.

Kinnoull is the largest of three reservoirs that are being developed as part of the Andrew Area developments project, and contains 45 million barrels of oil equivalent. The reservoir will be connected to BP's Andrew platform and enable production to be extended to 2020 and beyond.

Production from Kinnoull is forecast to peak at 45,000 barrels per day and be exported via the existing Forties pipeline system to Kinneil and the CATS pipeline system to Teesside.

Trevor Garlick, Regional President for BP's North Sea business said, "The Kinnoull project is a further demonstration of BP's vision to sustain a material and high quality business in the North Sea region. It is also a showcase for the outstanding subsea expertise that exists within the UK. At its peak the project will create employment for over 1,000 people in the UK."

Charles Hendry, Minister of state for Energy and Climate Change said, "I am pleased to see that BP is taking forward the development of the Kinnoull field. With around 90% of the development involving UK firms, this is a real big win for our domestic supply chain and shows that the thriving North Sea oil and gas sector continues to deliver economic benefit. I hope major global players continue to harness the expertise of UK companies as new developments come forward."

In order to access the new reservoir, the project will install a new subsea system and caisson onto the Andrew platform. The backbone of the subsea system will be 4 subsea bundles with a total length of 28 km - the longest bundle system in the world - which will carry the fluids to the Andrew platform for processing. The bundle system is being fabricated by Subsea 7 at its facility in Wick, Scotland.

To accept the new Kinnoull production fluids, and to facilitate the production from the Lower Cretaceous reservoir below the Andrew reservoir, the Andrew platform will undergo major modifications including the addition of a 750 ton process module. Construction will be completed over 2 years, with the flotel Borgholm Dolphin on location throughout. The Andrew platform is expected to be shut down for 18 months during this campaign during which time operational work will also be undertaken to maintain the efficiency and integrity of the existing Andrew platform facilities.

The new facilities are scheduled to commence production in 2013.

BP owns 77.06%, with other interests as follows: Eni (16.67%); Summit (6.27%)


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Petronas to Award Second Deal for Marginal Field Soon

- Petronas to Award Second Deal for Marginal Field Soon

Monday, August 15, 2011
The New Straits Times
by Kamarul Yunus

Petroliam Nasional Bhd (Petronas) is expected to announce the second contract to develop a marginal oil field soon.

"Petronas is currently finalizing the second risk services contract (RSC) and will make an announcement in due time," a Petronas spokesman told Business Times.

The spokesman, however, did not identify the field.

In January this year, Petronas said it will award two marginal oil field contracts by April. The only RSC awarded so far is for the Berantai field to the Petrofac-Kencana Petroleum-SapuraCrest Petroleum partnership early this year.

But in its prospectus for listing on Bursa Malaysia last month, Bumi Armada Bhd said it was awarded a floating, storage and offload (FSO) vessel contract for the Sepat field. It is claimed to be the first under the marginal fields initiative of the government's Economic Transformation Program (ETP).

Responding to Business Times' query, the spokesman clarified that Sepat is a field currently being developed under a production sharing contract operated by Petronas Carigali Sdn Bhd, the exploration and production arm of the national oil company.

In December last year, Petronas Carigali awarded the engineering, procurement, construction, installation and commissioning contract for Sepat to Petrofac, which in turn awarded the FSO vessel contract to Bumi Armada.

The development of the marginal oil and gas fields under the new RSC arrangement is part of the initiatives under the ETP.

Malaysia, according to Petronas, has 106 marginal fields, with 580 million barrels of oil.

(C) 2011 The New Straits Times. via ProQuest Information and Learning Company; All Rights Reserved

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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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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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Beach, Icon Enter Farmin Agreement for ATP 855P

- Beach, Icon Enter Farmin Agreement for ATP 855P

Friday, July 15, 2011
Beach Energy Ltd.

Beach and Icon have resolved their dispute in relation to the prospective ATP 855P tenement, and have agreed to work together under a Farmin Agreement executed today.

Under the terms of their agreement:

• The Federal Court proceedings will be discontinued;
• Icon has now transferred a 40% interest in ATP 855P to Beach (subject to Ministerial approval);
• Beach will drill a horizontal pilot unconventional well into one of the strata comprising the Roseneath, Epsilon & Murteree sequence, then case and suspend the well, suitable for fracture stimulation, which is expected to occur within 30 days of rig release from the well;
• Beach will fund Icon's share of the farmin operations at an estimated cost of $16 million (gross), with the exception of a $1.75 million contribution to be made by Icon;
• the cost of fracture stimulation, completing and flow testing the well will be paid by the Joint Venture parties in proportion to their Participating lnterest shares;
• Beach will be recommended by Icon to be the operator of the ATP 855 permit;
• Icon will be recommended by Beach to undertake the management of coal seam gas operations in both ATP 855P and PEL 218 Post Permian Joint Ventures; and
• Beach will effect the assignment of Icon's Phase 2 Post Permian PEL 218 interest upon Ministerial consent to the transfer of a 40% interest to Beach in ATP 855P, giving Icon a 33.333% interest in the PEL 218 Post Permian Joint Venture.

The interests of the parties in ATP 855P following this agreement are:

• Beach Energy Limited (40%)
• Icon Energy Limited (40%)
• Deka Resources Pty Ltd (10%)
• Well Traced Pty Ltd (10%)

Both Beach and Icon are pleased with this agreement, and look forward to working closely together with each other and the other ATP 855P participants to develop the exciting prospects offered in the emerging shale gas play in the Nappamerri Trough in southwest Queensland.

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CB&I Scores Engineering, Construction Contract for Northeastern Facility

- CB&I Scores Engineering, Construction Contract for Northeastern Facility

Wednesday, July 13, 2011
CB&I

CB&I has been awarded a contract, valued in excess of $300 million, for a new natural gas processing plant in the Northeastern U.S.

CB&I's work scope includes the engineering, procurement and construction of a 200 million cubic foot per day natural gas processing plant, including full fractionation and treatment capabilities, storage tanks and loading systems. In addition, CB&I's Lummus Technology business sector is providing its proprietary NGL-MaxSM recovery technology. The contract is scheduled for completion in 2012.

"This contract is a great example of CB&I's ability to leverage the synergy of our technology, storage and EPC capabilities to provide a single-source solution to natural gas producers," said Philip K. Asherman, President and CEO. "As gas production ramps up in U.S. shale basins, we are well positioned to support the infrastructure development needs of these strategically important projects."

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Gulmar Vessel Sets Sail for Port Gentil

- Gulmar Vessel Sets Sail for Port Gentil

Wednesday, July 13, 2011
Gulmar Offshore Ltd.

DP2 Construction Vessel Gulmar Condor is sailing from the Gulf of Mexico to Port Gentil (Gabon) where she will work for Vaalco under a charter with Dynamic Industries from the US. Vessel Charter is firm till mid December 2011 with potential extensions. Gulmar Condor, equipped with a 120T AHC deep water crane, 1100m2 of deck space and 128 accommodations, will then remain in the West Africa region to work on the subsea spot market.

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BP, Co-Venturers to Redevelop N. Sea Fields for $4.8B

- BP, Co-Venturers to Redevelop N. Sea Fields for $4.8B

Wednesday, July 13, 2011
BP plc

On behalf of its co-venturers BP announced an agreement to progress a major redevelopment of the Schiehallion and Loyal oil fields to the west of the Shetland Islands.

Schiehallion and Loyal have produced nearly 400 million barrels of oil since production started in 1998 and an estimated 450 million barrels of resource is still available. The investment of circa £3 billion in the redevelopment of the fields will take production out to 2035 and possibly beyond.

Trevor Garlick, Regional President for BP's North Sea business, said, "This important milestone is consistent with BP's strategy to sustain a material, high quality business in the North Sea region. The Schiehallion and Loyal oil fields are established assets with a strong future - and we and our co-venturers are taking some significant steps to maximize the greater potential we now see in these fields."

BP has developed a strong track record west of Shetland over the past two decades and will use the latest technology to maximize recovery from these fields.

The Quad 204 project involves replacing the existing Schiehallion Floating, Production, Storage and Offloading (FPSO) vessel with a new FPSO which is scheduled to be installed in 2015. The new vessel will be 270 meters long by 52 meters wide and able to process and export up to 130,000 barrels a day of oil, and store in excess of 1 million barrels.

There will also be a major investment in the upgrading and replacement of the subsea facilities to enable the full development of the reserves.

The new facilities are scheduled to commence production in 2016.

BP will have a 36.3 percent ownership interest in the new FPSO, with other interests as follows: Shell (36.3 percent); Hess Ltd (12.90 percent); Statoil (UK) Ltd (4.84 percent); OMV (UK) Ltd. (4.84 percent) and Murphy Petroleum (4.84 percent).

Commenting on the news, Bob Dudley, group chief executive of BP, said, "This decision is another example of BP's strategy to deliver long-term value growth through investing in the large fields and in key basins where it has extensive knowledge. BP has over 40 years experience in the North Sea, during which time it has developed a strong set of assets. We are committed to growing and maintaining a material, high quality business there for the long term. We are pursuing a number of additional growth opportunities to support this strategy. For us a key to this strategy is the need to maintain the integrity of our existing infrastructure; to look after our reservoirs and maximize recovery; and to deploy and develop the necessary capability."

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EIA: Higher US Gas Production Expected for 2011

- EIA: Higher US Gas Production Expected for 2011

Tuesday, July 12, 2011
Dow Jones Newswires
NEW YORK
by Amy D'Onofrio

The U.S. Energy Information Administration raised its forecast for natural-gas production for 2011, and said inventories are expected to come close to last year's record levels this fall.

The EIA also expects demand for gas to be slightly stronger than previously expected.

U.S. gas production is expected to average 65.4 billion cubic feet a day in 2011, up 5.8% from last year. The forecast was up from last month's prediction of 4.5% growth in output, according to the agency's monthly Short Term Energy Outlook released Tuesday.

"Growing domestic natural gas production has reduced reliance on natural gas imports and contributed to increased exports," the EIA said.

That increase in production is partly due to drilling to access gas in shale rock formations, where output has shot up in recent years.

Pipeline gross exports to Mexico and Canada are expected to average 4.2 Bcf/d in 2011, up from 3.1 Bcf/d in 2010, while liquefied natural gas imports are seen falling to 1 Bcf/d, from 1.2 Bcf/d in 2010, the agency said.

Production continues to grow faster than consumption. Total gas consumption is forecast to increase by 2% in 2011 to 67.4 billion cubic feet a day, on higher demand from industrial and electric power consumers.

Consumption is expected to drop slightly in 2012 to 67.3 billion cubic feet a day. The EIA expects residential and commercial consumption to decline because cooler weather is expected in the Midwest and West, the EIA said.

Natural-gas prices at the benchmark Henry Hub should average $4.26 per million British thermal units over the second half of 2011, "as the inventory deficit relative to last year narrows," the EIA said. In June, prices averaged $4.54, or 34 cents higher than the forecast last month.

Uncertainty over natural gas prices is still lower this year compared with the same time last year, the statistical arm of the Department of Energy said.

Gas prices will likely come under downward pressure as inventories rise during the summer months, but prices are expected to average $4.54 in 2012 as production growth slows.

This year, inventories should remain high, however.

Inventories are forecast to surpass 3.8 trillion cubic feet at the end of October "because of current high production rates and a milder summer relative to last year," according to the report.

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

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Bill Would Clear Path for Oil Project Approvals

- Bill Would Clear Path for Oil Project Approvals

Monday, July 11, 2011
The Bakersfield Californian
by John Cox

A bill advancing through the state Legislature could help Kern County's oil industry by providing a clearer path of approval for certain drilling-related activities.

Senate Bill 682, sponsored by Sen. Michael Rubio, D-Bakersfield, proposes to assign the state Division of Oil, Gas and Geothermal Resources direct responsibility for overseeing underground injection of produced gases, a common if controversial method of disposing of oil field byproducts such as hydrogen sulfide, or sour gas.

DOGGR, as the division is known, has regulated such projects for more than a decade. But since new leadership was installed at the division two years ago, a backlog of underground injection applications has grown to about 200, frustrating oil companies and local politicians who say the delays are stalling investment and potential job growth.

"We want someone to process those applications -- either deny or approve them so we can put people to work across the San Joaquin Valley and, particularly, Kern County," Rubio said in a phone interview.

DOGGR has taken no official position on the bill and therefore declined to comment. But earlier this year the division acknowledged a slowdown in project approvals, a situation it blamed on inadequate staffing and the complexity of engineering and geological issues involved. It has also pointed to a lack of clear legal authority to regulate what it considers an environmentally risky practice that has the potential to contaminate sources of drinking water.

On Thursday, despite opposition by the Sierra Club, the bill cleared the Assembly Environmental Safety & Toxic Materials Committee by a vote of 8-0. It is scheduled for consideration soon by the Assembly Natural Resources Committee.

Representatives of the Sierra Club's California lobbying arm could not be reached for comment Friday.

The head of the California Independent Petroleum Association expressed hope that the bill, if signed into law, would help expedite oil companies' injection applications, some of them as much as two years old.

"This allows (DOGGR) to consider those old permits," CIPA CEO Rock Zierman said.

"We really appreciate Sen. Rubio's leadership on this," he added.

Rubio said the bill represents the "first step" in a longer process of addressing DOGGR's concerns about underground injection projects. Related issues still to be worked out, he said, regard how California oil producers handle toxic waste, water and other environmental issues.

Copyright (c) 2011, The Bakersfield Californian

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3D Training Simulator Delivered for Pazflor FPSO

- 3D Training Simulator Delivered for Pazflor FPSO

Thursday, June 30, 2011
VRcontext International

VRcontext International was recently awarded a milestone contract with TOTAL E&P Angola to deliver a 3D "Immersive Training Simulator" (ITS) for the Pazflor FPSO, to be anchored on one of TOTAL's largest offshore producing assets.

Walkinside allowed the TOTAL Training Room Instructors to create customized collaborative scenarios that were later used to develop improved communication skills of the trainees and to test their execution performance.

Walkinside ITS' Scenario Editor helped TOTAL E&P Angola simulate real-life workflow situations using different training mode options, with diverse immersive scenarios specifically designed for the planning, the scheduling and the execution of Standard Operating Procedures. The implementation of these scenarios can be timed and stored for subsequent operators' assessment, improvement tracking and playback for refresher courses or novice training, making learning more effective, fun and easy!

"The objective for the Field Operators was to associate the Tags of equipment, instruments such as pressure gauges, valves, safety valves on one hand and piping lay out and the main machines such as pumps on the other hand, with their location on site for various scenarios including HSE (Health, Safety Environmental) procedures, Black Start procedures and Routine operations," said Lionel Ramat from the Field Operations group of the Pazflor project for TOTAL E&P Angola.

He added: "Even though it is still early to quantify the return on investment, the ease of the takeover by the trainees and their feedback were very positive. Also the value of the ITS, as a contextual training environment, was confirmed by experienced operational personnel."

Thanks to the Walkinside ITS, TOTAL can now rely on faithful, photo-realistic 3D representations of its new producing assets for the training of all field personnel. The 3D Virtual Reality models can be automatically created from the existing 3D Engineering CAD drawings using the smart Walkinside converter capabilities. The 3D models are subsequently enhanced to include interactive items that can be manually operated during the training sessions, such as valves, pumps, fire-extinguishers, etc. Trainees are therefore able to use these live-action items in training scenarios.

This breakthrough technology helps accelerate both safe start-up operation and time to first oil of all new important assets, significantly improving Return on Investment for major capital projects.

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Niko Updates Financial, Operational Results for Year-End

- Niko Updates Financial, Operational Results for Year-End

Wednesday, June 29, 2011
Niko Resources Ltd.

Niko reported its financial and operating results, including consolidated financial statements and notes thereto, as well as its managements' discussion and analysis, for the year ended March 31, 2011. The operating results are effective June 28, 2011. All amounts are in U.S. dollars unless otherwise indicated.

FINANCIAL HIGHLIGHTS

• There was a year-over-year increase of 32 percent in funds from operations.
• In October 2010, Niko repaid all of its outstanding long-term debt.
• At March 31, 2011, the Company's unrestricted cash totaled $108 million.
• In January 2009, the Company announced that the Canadian authorities were engaged in a formal investigation into allegations of improper payments in Bangladesh. The Company cooperated in the investigation, which was concluded on June 24, 2011. The Company pleaded guilty to one count of bribery under the Corruption of Foreign Public Officials Act, was fined Cdn$9.5 million and is subject to a 3-year Probation Order. In early 2009, the Company adopted a full anti-corruption compliance program.

EXPLORATION HIGHLIGHTS

• Indonesia: Four new offshore exploration blocks were added and the Company farmed out 45 percent of its working interest in the Seram and East Bula blocks and 40 percent of its working interest in the North Makassar Strait, West Papua IV and Halmahera-Kofiau blocks. Seismic acquisition activity continued during the year and the planning of drilling has commenced.
• Trinidad: The Company increased its exploration acreage in Trinidad with three new offshore blocks, all of which are in proximity to producing gas fields, and entered into an agreement, which closed subsequent to year-end, to acquire a 25 percent working interest in Block 5(c), located 94 kilometres off the east coast of Trinidad.
• Madagascar: Seismic acquisition has been completed and processing is underway.
• Kurdistan: Drilling was completed to a depth of 3,908 meters in May and testing is underway and expected to continue into July 2011.

PRESIDENT'S REPORT

The Company's strategy of accumulating a highly prospective exploration portfolio continued.

In Indonesia, four new blocks were added and farm-outs occurred in five blocks. Farm-outs are a part of the Company's exploration strategy. Partners in Indonesia now include Exxon/Mobil, Marathon, Repsol and Statoil.

In Trinidad & Tobago, four new blocks were added. Partners in this country include Centrica and RWE.

From a drilling perspective, in Trinidad and Tobago, the Company has contracted an offshore rig that is expected to spud the Company's first offshore well in the country in October. In Indonesia, Niko has established an extremely strong drilling organization staffed with seasoned professionals that bring extensive deep-water drilling experience.

During the past year, uncertainty regarding D6 production, reserves and gas price has been a concern. This uncertainty has been largely removed by an independent reserve report that shows that the revision to the Company's worldwide net proved plus probable reserves was approximately 6.8 percent. Operationally, the D6 field's gross gas production averaged approximately 2 billion cubic feet per day over the year with no downtime.

Due to a pre-emptive right, Niko expects to have the opportunity to increase its net interest by 30 percent in each or all of the D6, NEC-25 and D4 blocks in India. Niko expects this opportunity would be financed with debt.

Niko has a strong production base and an extensive portfolio of exploration prospects. Two thousand and twelve could prove to be Niko's most exciting year ever.

Production from the D6 Block has increased year-over-year and is the primary reason for total production increases of 25 percent compared to production in the prior year. The D6 Block is also the primary reason for improved operating netbacks as the D6 Block has higher realized prices and lower profit petroleum than the average of the Company's other properties.

Gas sales volumes from the D6 Block for the year averaged approximately 198 MMcf/d versus a budget of 210 MMcf/d due to well performance. Current gas sales volumes from the block are approximately 167 MMcf/d. Production from the D6 Block is expected to decline until additional wells are drilled and tied-in.

The Company is forecasting total production of 236 MMcfe/d for Fiscal 2012, which assumes that no additional wells will be tied in at D6 during the year and is consistent with the estimated production from total proved reserves in the Company's reserve report.

Operating cashflow increased in Fiscal 2011 primarily as a result of increased oil and gas sales from the D6 Block. Forecast operating cashflow for the coming year is expected to decrease with the decrease in production described above. In addition, maintenance of the onshore terminal and subsea systems for the D6 Block are expected to result in a decreased operating netback.

Exploration expenditures for Fiscal 2011 were for drilling activities on three exploration wells in the D6 Block, seismic acquisition in Indonesia and Madagascar, drilling of the first exploration well in Kurdistan and seismic on Block 2AB in Trinidad and carrying costs of the Trinidad blocks. Forecast expenditures for Fiscal 2012 include drilling on the D6 and D4 Blocks in India; seismic activity and preparation for drilling activities in Indonesia; completion of drilling the well in Kurdistan, and seismic activity in Trinidad on all blocks and commencement of drilling on Block 2AB.

Development expenditures forecast for Fiscal 2012 are primarily for workovers, drilling new wells and acquisition of compression equipment for the D6 block.

In addition to exploration and development expenditures, the Company's acquisition of Block 5(c), located 94 kilometres off the east coast of Trinidad closed in June 2011 for a purchase price of $78.1 million.

Funds from operations improvements resulted from improved volumes and operating netbacks partially offset by higher current income taxes, higher interest expense related to the Company's convertible debentures, a Cdn$9.5 million (US$9.7 million) fine described previously herein and lower other income as the prior year periods benefited from a favorable arbitration ruling related to a pipeline dispute.

Net income increased year-over-year as a result of the increase in funds from operations. The benefit from improved funds from operations was offset by higher non-cash charges related primarily to depletion and a loss on short-term investments.

Exploration Acreage

Niko has increased its exploration acreage with the addition of three blocks in Trinidad and four blocks in Indonesia. In addition, Niko farmed out 45 percent of its working interest in two blocks in Indonesia to Repsol and 40 percent of its working interest in three blocks in Indonesia to Statoil.

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KS Energy Secures Contract for Jackup

- KS Energy Secures Contract for Jackup

Tuesday, June 28, 2011
KS Energy Ltd.

KS Energy announced that its wholly-owned subsidiary, Atlantic Rotterdam Limited, has secured a 1 plus 1 year bareboat charter contract worth up to Euro12 million (including the 1 year option) for its Jackup Offshore Accommodation rig Atlantic Rotterdam. The Rig will be deployed for Shell in the UK sector of the North Sea and is expected to commence work on August 1, 2011.

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EMGS Scores Barents Sea Survey for Statoil

- EMGS Scores Barents Sea Survey for Statoil

Monday, June 27, 2011
Electromagnetic Geoservices ASA

Electromagnetic Geoservices (EMGS) has signed a contract with Statoil to acquire high-resolution, full-azimuth 3D electromagnetic (EM) data for continued research purposes in the Barents Sea.

The survey will be performed by the vessel Atlantic Guardian using densely sampled receiver grids, thereby providing high-resolution data.

Following the survey in the Barents Sea, which is expected to take approximately twelve days, the vessel will complete its campaign of back-to-back surveys with a work program in the North Sea before heading to the Americas towards the end of July.

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Ptarmigan Completes Additional Option for Exploration License 1120

- Ptarmigan Completes Additional Option for Exploration License 1120

Tuesday, June 21, 2011
Ptarmigan Energy Inc.

Ptarmigan has completed an option agreement for its Western Newfoundland exploration license with Canadian Independent Oil and Gas Company (CIOGC), a privately held, Calgary based oil and gas exploration company.

President and CEO Craig Boland says that a discovery under this agreement will yield Ptarmigan a gross overriding royalty based upon a percentage of the gross production proceeds without deductions. "We are excited and very pleased that this agreement, coupled with the recent gas-in-shale farm out agreement with Shoal Point Energy (April 2011), has established strong partners to explore both traditional and non-traditional targets within Exploration License 1120, with very favorable terms for our shareholders."

Under the terms of the agreement CIOGC has 90 days to review existing seismic data and decide whether or not to exercise its option to acquire, a minimum of 1000 square kilometers of high definition 3D seismic data within the area of Exploration License 1120; 100% owned by Ptarmigan Energy. Exploration License 1120 is currently undergoing an environmental assessment and permitting process required by the Canada Newfoundland and Labrador Offshore Petroleum Board (C-NLOPB).

Should CIOGC exercise its option to collect additional seismic data, it would be in a position to execute a definitive agreement with a seismic acquisition contractor by October, 2011 with a view to starting that work in September 2012 following completion of the environmental assessment process. CIOGC has until December 2013 to exercise its option to drill a test well to the depth of 3,250 meters or 50 meters into the top of the Labrador Formation; the established marker below all anticipated targets. That well must then be spudded by no later than December 2014.

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Zion O&G Applies for Israel Exploration Permit

- Zion O&G Applies for Israel Exploration Permit

Tuesday, June 14, 2011
Zion O&G Inc.

Zion O&G announced that on June 13, 2011, the Company submitted an application to the Israeli Petroleum Commissioner's Office, requesting the grant of a new petroleum exploration permit area adjacent to Zion's Joseph License area. The new permit application has been named by Zion, the "Asher-Joseph Permit Application".

The Asher-Joseph Permit Application area covers approximately 80,000 acres of land and is to the west and south of Zion's Joseph License area. It is onshore Israel and traverses a section of land, adjacent to the coastline, between Haifa and Tel Aviv. The grant of a permit would allow us to conduct, on an exclusive basis through a specified period, preliminary investigations to ascertain the prospects for discovering petroleum in the area covered by the permit. Unlike a license area, where test drilling may take place, no test drilling is allowed on a permit area.

Zion's Chief Executive Officer, Richard Rinberg, said, "We have three applications for new exploration areas pending before the Israeli Petroleum Commissioner's Office: the Asher-Joseph Permit, the Zebulun Permit and the Dead Sea License.

"We continue to implement our exploration and drilling program and build on our progress to date. If granted the new exploration areas, we intend to acquire additional seismic and other geological and geophysical data, as we work towards refining potential drilling prospects.

"Currently, drilling operations at our Ma'anit-Joseph #3 well continue. We have reached our target depth of approximately 19,357 feet (5,900 meters), in the Permian geologic layer in Northern Israel, and are now preparing for open-hole wireline logging operations, planned to commence this week. Depending on the outcome of our wireline logging and subsequent interpretation, we may determine to drill this well deeper."

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Seadrill Lines Up Semi-Tender for 2013 Delivery

- Seadrill Lines Up Semi-Tender for 2013 Delivery

Thursday, June 09, 2011
Seadrill Ltd.

Seadrill has entered into an agreement with Keppel FELS Limited in Singapore to build a new semi-submersible self-erecting tender rig (semi-tender). Total project price for the rig is estimated at below US $200 million (including the drilling equipment set, project management, spares, capitalized interest and operation preparation).

The new rig is scheduled for delivery in the second quarter 2013 and will be based on a similar design and specification as the semi-tender West Jaya, which was delivered from the Keppel FELS yard in March this year and is contracted for a minimum of two years. Similar to previous semi-tenders, the new unit is suited for harsher environment and deepwater drilling operations in combination with floating wellhead platforms such as Tension Leg Platforms and Spars.

The new unit is based on the KFELS SSDT 3600E design and adds to the seven semi-tenders that Keppel has earlier built for Seadrill since the launch of the design in 1994. The unit will feature a crane capacity of 250 tones, four mud pumps and accommodation for 160 people.

Alf C Thorkildsen, Chief Executive Officer of Seadrill Management AS said, "We are pleased to announce the addition of a new semi-tender to our existing fleet of 19 tender rigs. The tender rig business has delivered excellent operational results as well as outstanding economics over the last decade. Based on the continued strength of the offshore drilling market we continue to see strong growth and earnings potential for our business. The new semi-tender has a favorable construction price and an equipment specification list that will meet our customers' future needs. We have had very good experience with the Keppel FELS yard and this design and we are confident that the new unit will be delivered on time and within budget once again."

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Wood Group Wins Contract for Chevron's Jack/St. Malo Facility

- Wood Group Wins Contract for Chevron's Jack/St. Malo Facility

Thursday, June 02, 2011
Wood Group
by SubseaIQ

Wood Group has been granted a multi-million dollar, 42-month contract by Chevron U.S.A. Inc. for the planning, managing and field execution of commissioning for the Jack/St. Malo semi-submersible hub production facility. Work will be performed by DSI, Wood Group PSN's commissioning services business.

The Jack/St. Malo platform will be installed in 7,000 feet of water in the Walker Ridge section of the US Gulf of Mexico and will have an initial design capacity of 170,000 barrels per day of oil.

DSI's commissioning will be performed at a South Texas fabrication yard where the topsides will be fabricated and integrated with the hull, and offshore, during final installation and start-up

DSI has commissioned four other deepwater Gulf of Mexico semi-submersibles, including two that had designs similar to that of Jack & St. Malo. DSI's work for Chevron has included commissioning of the Tahiti spar in the Gulf of Mexico and the South Nemba Enhanced Recovery Project offshore Angola.

"Project commissioning proves the integrity and reliability of all operating and safety systems on a production facility prior to hydrocarbon start-up. Commissioning must be delivered to the highest quality in the deepwater Gulf of Mexico today," stated Trey Lambert, president of DSI. "We look forward to providing these critical services for Jack/St. Malo and to extending our relationship with Chevron."

Wood Group has supported the Jack & St. Malo project throughout its development. Mustang is conducting detailed design for the Jack/St. Malo topsides facilities and the integrated control and safety systems, and J P Kenny is performing detailed design for the deepwater oil export pipeline.

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Shell, Maersk Offer Bids for Offshore Danish Project

- Shell, Maersk Offer Bids for Offshore Danish Project

Thursday, May 26, 2011
IndigoPool

Shell and Maersk Oil as the operator (the Partners) are jointly offering up to 60% interest in the Elly and Luke development project located near the existing Tyra gathering, treating and transportation infrastructure. The Partners are in the advanced stages of planning for the combined development of the Elly and Luke discoveries that will deliver hydrocarbons into the Danish and Dutch gas transmission systems. The Luke and Elly fields are expected to yield mean recoverable gas resources of 180 BCF, with upside estimated at 430 BCF. In addition, exploration prospects in the licenses have potential mean recoverable gas resources estimated at 140 BCF with an upside of 422 BCF.

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