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Oil and Gas Energy News Update

Monday, August 15, 2011

Oil & Gas Post - All News Report for Monday, August 15, 2011

Monday, August 15, 2011

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Commodity Corner: Crude Rallies Along with Equities

- Commodity Corner: Crude Rallies Along with Equities

Monday, August 15, 2011
Rigzone Staff
by Matthew V. Veazey

Light sweet crude oil for September delivery gained $2.50 Monday to settle at $87.88 a barrel.

Rallies in equities markets worldwide, coupled with a weaker dollar, propelled oil futures forward. Major merger announcements Monday by heavyweights such as Google and Transocean helped the Dow Jones Industrial Average and S&P 500 to finish the day 1.9 percent and 2.18 percent higher, respectively.

The U.S. Dollar, meanwhile, weakened against other major currencies after a monthly Federal Reserve Bank of New York report showed worsening business conditions in the Empire State. A weaker greenback makes dollar-denominated crude oil a better buy for investors holding other currencies. The New York Fed's survey revealed falling orders, decreasing prices, plunging capital expenditures, and a future general business conditions index hitting its lowest point since February 2009.

The WTI peaked at $88.05 and bottomed out at $84.40. Brent futures settled at $109.91 a barrel, a $1.88 day-on-day gain and four cents shy of Monday's intraday high. The September Brent contract fell to $108.20 earlier in the session.

Thanks in part to milder temperatures in much of the U.S., August natural gas futures lost four cents to settle at $4.02 per thousand cubic feet. The front-month contract price fluctuated from $3.95 to $4.06.

The price of a gallon of reformulated gasoline gained a nickel to end the day at $2.87. August gasoline traded within a range from $2.81 to $2.88.

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Evergreen Solar Files For Chapter 11

- Evergreen Solar Files For Chapter 11

Aug 15, 2011

Evergreen Solar (NASDAQ:ESLR) announced that it voluntarily filed a petition for a relief under Chapter 11 of the U.S. Bankruptcy Code. The petition was filed in the U.S. Bankruptcy Court for the District of Delaware.

As part of the restructuring, an entity formed by the supporting noteholders, ES Purchaser, entered into an asset purchase agreement with the company.

If higher or better offers for assets are not obtained, it is expected that ES Purchaser will acquire most of the company's assets pursuant to the asset purchase agreement. As part of Evergreen Solar's reorganization activities, the company will reduce its U.S. and European workforce by about 65 people, including suspension of operations at its Midland, Michigan filament facility.

Evergreen Solar should find initial resistance at its 50-day moving average (MA) of $0.48 and further resistance at its 200-day MA of $2.14.

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Leighton Olmos Flows O&G at Peeler Well

- Leighton Olmos Flows O&G at Peeler Well

Monday, August 15, 2011
Global Petroleum Ltd.

Texon has advised that the latest Leighton Olmos vertical production well, Peeler #3, has begun to flow oil and gas at the combined rate of 370 boepd from the Olmos reservoir (comprising 325 bopd and 268 mcfgpd). This is the ninth well targeting the Olmos reservoir in which Global has a 15% working interest (11.25% net revenue interest).

This is a good result as the closest three Olmos production wells, Peelers #1 and #2 and Tyler Ranch #5 tested at initial rates of 170 to 445 boepd.

The well will be connected for production to oil tanks and the gas pipeline in the next two weeks.

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Tethys Highlights 2Q11 Production

- Tethys Highlights 2Q11 Production

Monday, August 15, 2011
Tethys Petroleum Ltd.

Tethys provided an operational update in conjunction with its financial results for the quarter ended June 30, 2011.

Operational Update - Recent Highlights

  • AKD05 appraisal well flowed at over 1,500 bopd of good quality oil.
  • KBD01 (Kalypso) exploration well close to total depth.
  • Drilling operations commenced on AKD06, an appraisal well of the Doris oil discovery targeting the Cretaceous sand.
  • Stage 2 oil production facilities installed.

  • East Olimtoi exploration well EOL09 has reached total depth and electric logs are currently being run.
  • New exploration well "Persea 1" spudded with total depth expected to be 2,700 meters.
  • Aero magnetics and gravity gradiometry survey underway.

  • Initial jet pump trial on the North Urtabulak oilfield successful.
  • Negotiations continue on new production and exploration contracts.


The appraisal program on the Doris oil discovery and further exploration on the Akkulka and Kul-Bas block is continuing.

The Kalypso (KBD01) wildcat exploration well which, is targeting primarily a large potential structural closure at Permo-Carboniferous level, is currently at a depth of 4,128 meters in what is interpreted to be Carboniferous limestones. Some oil and gas indications have been observed but the significance of these cannot be ascertained until electric logs have been run and further evaluation carried out. The planned total depth of this well is approximately 4,300 meters.

The Doris (AKD06) appraisal well, which is targeting primarily the Cretaceous sandstone interval, which flowed at over 5,400 barrels of oil per day ("bopd") in the AKD01 Doris discovery well, is currently at a depth of 641 meters. This well is located on an amplitude anomaly derived from detailed spectral analysis of the new 3D seismic dataset and is aimed at establishing a stratigraphic component to the Doris oil accumulation. The planned total depth of this well is 2,400 meters and it is estimated to be completed by October 2011.


The East Olimtoi (EOL09) exploration well has just reached its total depth of 3,765 meters in the Akdzhar formation. Electric logs are currently being run in the Bukhara and Akdzhar sections as well as the lower part of the overlying Alai formation. The initial results from the raw logs indicate some zones of interest in the Bukhara limestone sequence but further data gathering and analysis is required. The Alai formation showed both good oil and gas shows while drilling (with oil and gas to surface) and the electric logs through this interval indicate several hydrocarbon bearing zones with no evidence of any oil-water contact. Following a full analysis of the Bukhara interval, a testing program will commence. The well is exploring an attractive salt induced structure located in the south-east of the PSC area, south of the town of Kulob and only some 10 kilometres north-west of the Afghan border. The nearest oilfield in that region is the Beshtentak field some 75 km to the north-west.

The Persea 1 exploration well is primarily targeting the Bukhara limestone formation in a four-way dip closed structure with the overlying Alai formation forming a potential secondary target. The well is currently at a depth of 606 meters where casing has been run. The planned total depth of this well is 2,700 meters and it is expected that this will be reached by October. The well is located near the town of Kurgon-Teppa in the south-west part of the PSC area with the nearest field in the same Bukhara horizon being Kyzyltumshuk to the immediate south and south-east of the prospect.

The Company has commenced the gravity, gradiometry and magnetic aerial survey. The survey will cover the entire area of the 35,000 km2 Bokhtar Production Sharing Contract Area and will provide additional and more aerially extensive data to complement the existing seismic acquisition. Over 34% of the survey data has now been acquired and the final processed data and results are expected in 4Q 2011. The Company has previously stated that it is seeking a suitable farm-in partner for its exploration program in Tajikistan and these geophysical data are an important part of the information relating to such a potential farm-in. Discussions with several parties are ongoing.


The initial results of the recent jet pump trial on the North Urtabulak oilfield appear successful with oil rates on the two test wells increasing by some 20%. Further work is now underway to ascertain the economics of extending the use of jet pumps on the field (and potentially on any new fields the Company is successful in contracting) which, together with the likely effects of the water injection reconfiguration carried out earlier this year, should have a positive impact on oil production levels from the field in the latter half of 2011.

Negotiations continue with the Uzbek authorities on production enhancement contracts for two further oilfields in the Bukhara area, and work continues on the joint exploration study agreement carried out with the Institute of Geology and Prospecting for Oil and Gas Department of the State Holding Company NHC Uzbekneftegas. This study is now almost complete. Tethys hopes this study will lead onto contracts over these exploration areas.

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Whiting Declares Dividend

- Whiting Declares Dividend

Monday, August 15, 2011
Whiting Petroleum Corp.

Whiting declared a dividend of $1.5625 per share on its 6.25% convertible perpetual preferred stock. The dividend is payable on September 15, 2011 to holders of record on September 1, 2011.

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Halliburton Unveils Latest Advancement in Horizontal Completions

- Halliburton Unveils Latest Advancement in Horizontal Completions

Monday, August 15, 2011
Halliburton Co.

Halliburton has deployed the most recent addition to its horizontal completion portfolio. The new RapidFrac™ completion system allows operators to set new standards for fracture completion efficiency and post-fracture production.

This innovative horizontal sliding sleeve completion system is a differentiating technology that allows for enhanced reservoir contact. In a changing landscape where operators are drilling longer laterals that require increasingly complex completions, the RapidFrac system delivers several unique differences from the "plug and perforate" system and other similar techniques.

The RapidFrac system uses a metering process that enables a single ball to open multiple sleeves isolated within an interval by swellable packers. Each RapidFrac sleeve can be tailored to specific fracture requirements along a horizontal wellbore so as to enhance post-frack production. Up to 90 sleeves can be incorporated into any one horizontal completion, ensuring maximized stimulated reservoir volume. By facilitating continuous pumping, the RapidFrac system reduces stimulation cycle time from days to hours and reduces the volume of water consumed.

"The RapidFrac system allows operators to optimize completion design, reduce operational risk, and materially reduce the time to first hydrocarbons," said Marc Edwards, senior vice president, Halliburton Completion and Production Division. "This technology also enables Halliburton to increase the utilization of its unconventional asset fleet."

Although initial system deployments have occurred in the Bakken Shale with Brigham Exploration and Williams Production Company, this technology has application for shale developments on a global basis.

"Brigham's success in the Bakken has been driven by its early adoption of game-changing technologies," said Lance Langford, executive vice president, Brigham Exploration. "We believe our industry is in the very early stage of developing tools and techniques to optimally exploit the Bakken and working with Halliburton to successfully launch its RapidFrac system is an example of what can be done in this world class resource."

In order to prove this technology with Halliburton, Williams drilled two comparable offset wells. The first was completed with the traditional "plug and perforate" method and the second utilized the RapidFrac system.

"The new RapidFrac completion system delivered significant performance benefits," said William Stenzel, vice president, Williams Williston. "(The) RapidFrac (system) enabled us to complete the well in less than half the time of a "plug and perforate" system, while delivering a stronger early time production performance. This is a major step forward in completion efficiency."

Halliburton continues to develop technical innovations designed to address the efficiency and effectiveness of unconventional hydrocarbon development, while meeting the highest environmental and safety standards.

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Swire Oilfield Service Names New Sales Director

- Swire Oilfield Service Names New Sales Director

Monday, August 15, 2011
Swire Group

Swire Oilfield Service has appointed David Rae as sales director in line with its significant investment plans.

Mr. Rae brings a wealth of knowledge and experience to the company gained from holding a variety of senior commercial and finance roles in a career spent working in both the oil and gas and manufacturing industries. He was most recently business development director at helicopter operators CHC.

His role at Swire will see him plan and implement sales and marketing activities as well as contributing to the executive management of the company.

"I am delighted to join Swire at this dynamic time of investment and growth in the company and look forward to working with the sales and operations teams to ensure we continue to deliver a first class service to our clients," said Mr. Rae. "Our global offering is competitive with bespoke services in high demand and I look forward to the challenge of driving sales onwards and upwards with the support of my team."

Mr. Rae's appointment comes shortly after Swire's announcement of its £50 million investment in services with £20 million being injected in to its North Sea operations including the construction of new global headquarters in Aberdeen.

Roy Burrell, director and general manager for Swire Oilfield Services said, "We welcome David at an exciting time in Swire's progression. We strongly believe that the experience and knowledge that he brings to the team will enable us to continue our fast growth and success in the industry."

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OTG Starts Up New Production Line at Tx. Facility

- OTG Starts Up New Production Line at Tx. Facility

Monday, August 15, 2011
Momentive Specialty Chemicals Inc.

The Oilfield Technology Group (OTG) of Momentive Specialty Chemicals Inc., announced the startup of a new manufacturing production line at its Brady, Texas, facility to provide additional resin coated proppants to fracturing service companies and operators in the oil & gas industry.

"Industry demand continues to grow as more operators come to realize the correlation between curable resin coated proppants and enhanced post-frac well production. This expansion of our Brady resin coating plant allows us to provide our customers with the additional resin coated proppant supply they are requesting for their hydraulic fracturing treatments," said Jerry Borges, Vice President, Oilfield Technology Group.

The Brady plant expansion is the third addition to the OTG manufacturing grid in 2011. The new production line manufactures Momentive's field-proven curable resin coated proppants such as Prime PlusTM, SiberPropTM, and SB ExcelTM which are available in large grain sizes. These products and the plant's geographic location are especially suited to serve the nearby Eagle Ford and Permian Basin oil markets.

"The value of our high strength proppants is seen from the increased well production they consistently provide. By leveraging Momentive's technology from other industries, combined with our own internal resin manufacturing facilities, we will continue to bring innovative proppant technology to our customers," Borges said.

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Bristow Appoints North Sea Development Manager

- Bristow Appoints North Sea Development Manager

Monday, August 15, 2011
Bristow Helicopters Ltd.

Bristow has appointed David Laskowski to oversee its operations in the busy northern North Sea energy sector. Based in Aberdeen, Scotland, Laskowski will serve as Development Manager responsible for day-to-day management of up to 250,000 passenger movements annually through the Integrated Aviation Consortium (IAC) contract. He will play a key role in ensuring delivery of Bristow's Target Zero program to achieve zero accidents, complaints and downtime.

Laskowski's experience includes management roles in safety, commercial and helicopter operations. He began his aviation career in his native Louisiana, obtaining his pilot's licence while at university pursuing a Bachelors of Science degree in Professional Aviation and Aviation Management. He joined Bristow in 2001 as a Facilities and Special Projects Officer in the Gulf of Mexico. He served as Base Manager of Bristow's airfield at Patterson, Louisiana before becoming a Safety Case Manager, travelling to Bristow operations in Alaska, Aberdeen in Scotland, Trinidad and Mexico. Most recently he served as Regional Sales Manager for Bristow's North American Business Unit.

Fiona MacLeod, Commercial Manager – Europe, who previously held responsibility for the northern North Sea sector, will continue to oversee existing client activity in central North Sea and expand to the Baltic region.

Mike Imlach, Bristow's European Operations Director said, "David's appointment means that we now have an executive dedicated solely to the management and development of our Northern North Sea business and in the Shetland Basin.

"Not only will this enhance our service to our IAC partners; it also will allow us to grow our business in the expanding markets in Denmark and the Baltic regions."

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Judge Strikes Down US Policy on O&G Permits

- Judge Strikes Down US Policy on O&G Permits

Monday, August 15, 2011
Dow Jones Newswires
by Ryan Tracy

A federal judge has struck down an Obama administration policy related to drilling permits on public lands, leading oil and gas companies to hope more permits in the western U.S. will be forthcoming.

But it wasn't clear Monday how the Interior Department, which processes the permits, would respond. The ruling, issued Friday by the U.S. District Court in Wyoming, rejected a policy that had required more extensive environmental review of some drilling permits.

Interior "had no authority" to adopt the policy last year "without public notice and an opportunity for comment," Judge Nancy D. Freudenthal wrote. She ruled in favor of an industry group and vacated the policy nationwide.

An Interior Department spokesman said the agency was reviewing the ruling and declined to comment further.

The ruling "holds the promise of new jobs and economic growth," said Kathleen Sgamma, director of government and public affairs for the Western Energy Alliance, which filed the suit and represents Devon and Anadarko, among others.

Permitting on U.S. land quickened under the Bush administration and hit a peak during the 2007 fiscal year, when Interior approved 7,124 permits to drill for oil and gas on federal lands. The Obama administration, by contrast, approved 4,487 such permits in 2009 and 4,090 in 2010, according to data from Interior's Bureau of Land Management, or BLM.

Some of that drop can be attributed to lower demand as a result of the economic downturn, but the industry says permits are also taking longer to obtain.

For its part, BLM has argued that its new permitting policies are more efficient because a stronger up-front review will lead to fewer lawsuits and delays down the road.

At issue in Friday's court ruling was a provision in the 2005 Energy Policy Act that allowed oil and gas companies to skip federal environmental reviews under certain circumstances -- for example, if a well was being drilled from an existing site where drilling had occurred within the previous five years.

In May 2010, Interior instructed its staff to allow such exceptions under "extraordinary circumstances." Freudenthal said that decision amounted to an "about-face" from past practice, so the agency must formally propose the change and solicit public input.

Sgamma said she hoped Interior would rescind the current policy for now. The department might also keep it in place and appeal the ruling.

"It's not like we'll start to get permits quicker here on out in the short term," Sgamma said. "We'll have to wait to see what the government does."

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

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Devon Energy's Barnett Shale Bet Pays Off

- Devon Energy's Barnett Shale Bet Pays Off

Monday, August 15, 2011
Fort Worth Star-Telegram, Texas
by Jack Z. Smith

Ten years ago Sunday, Devon Energy made a multibillion-dollar bet on the Barnett Shale.

On Aug. 14, 2001, the Oklahoma City-based oil and gas company announced a deal to acquire Mitchell Energy & Development of Houston for $3.5 billion.

Mitchell Energy, led by legendary oilman George Mitchell, was the pioneering company that cracked the code of the Barnett's dense shale rock by using new hydraulic fracturing techniques and experimenting with horizontal drilling. At the time, it had drilled about 400 wells in the Barnett, and executives saw the potential for 1,200.

But over the decade, Devon would advance the ball significantly with improved horizontal drilling and an expansion of drilling far beyond areas north of Fort Worth where Mitchell Energy had focused. The result would be a drilling boom that by 2008 would draw numerous rivals into the field and make the Barnett the biggest gas-producing area in the U.S. Tarrant and Johnson counties would emerge as the top two gas-producing counties in Texas.

Today, Devon has drilled more than 4,700 wells in the Barnett. The field now accounts for 39 percent of the company's total production, which includes operations that stretch to the Rocky Mountains and into Canada.

In the Barnett, "our drilling costs are down, our production is up and our efficiencies are increasing," said Brad Foster, senior vice president of Devon's Central Division, which includes Barnett operations.

Devon has achieved, or is on the verge of, several Barnett milestones:

It posted record production in this year's second quarter, averaging the equivalent of 1.28 billion cubic feet of gas per day, even while keeping only 12 drilling rigs busy. That's less than a third as many as it ran in 2008, before gas prices cratered.

Devon's total Barnett production since the Mitchell acquisition is expected to hit the equivalent of 3 trillion cubic feet by year's end, spokesman Chip Minty said. It's at 2.8 trillion now.

Despite weak gas prices, now about $4 per 1,000 cubic feet, Devon is realizing solid returns from the Barnett because "our ability to drill wells economically just gets better every year," said Chairman Larry Nichols, who was CEO during the Mitchell acquisition.

A 35-well pad site

Devon's advances in the Barnett are exemplified at a rural 12-acre drilling site in far southwest Tarrant County. The 31st well there was drilled last week by contractor Patterson-UTI Drilling Co.

Devon expects to have 35 producing wells at the site by March, said Jay Ewing, its manager of Barnett well completions.

That will be the most wells ever on a single Barnett Shale pad site, but the project development has "been pretty routine. ... It's been pretty close to plan," Ewing said. Horizontal legs of the wells, called "laterals," will be steered thousands of feet under Benbrook Lake.

Devon estimates that the 350 Barnett wells it drills this year will yield, on average, the equivalent of 3.2 billion cubic feet of gas apiece over their producing lifetimes. By that measure, the 35 at the southwest Tarrant pad site cumulatively would produce 112 billion cubic feet.

That's enough fuel for gas heating and cooking at more than 1.5 million homes for a year, based on American Gas Association data.

If Devon maintains its current drilling pace, it will drill its 5,000th well next year. Less than 1 percent of Devon's Barnett wells have been dry or otherwise not worth putting into production.

Devon, which has more than 600 Barnett employees and an office in downtown Fort Worth, has boosted its Barnett reserves for seven straight years. Proven reserves are now the equivalent of 6.7 trillion cubic feet.

Drilling time slashed

When Devon began drilling in the Barnett in 2002, it took three to six weeks to drill a single horizontal well, said David Fortenberry, Devon vice president of technology.

"The rigs we used were really too small and underpowered for horizontal wells," he said.

Now, with higher-efficiency rigs and much more experience, Devon averages only about 12 days to drill a Barnett well, and "we've actually drilled some wells down in southwest Johnson County in about six days," Foster said.

Drilling-rig design "has improved dramatically in the past 10 years," with rigs now "ideally suited to drill these horizontal wells," Nichols said.

Devon uses a "walking rig" device to scoot a 156-foot-high rig between surface well bores at its southwest Tarrant pad site. If well bores are 20 feet apart, the rig can move that far in just an hour. Without the walking device, it could take two days to disassemble a rig and set it up 20 feet away.

The Barnett wells that Devon has drilled this year have provided "some of the best results we've ever gotten," Nichols said.

Supply rises, prices fall

Ample supplies from dramatic increases in U.S. shale-gas production have kept prices low, as the industry has become "in part ... a victim of our own success," Nichols said.

Devon has dropped to 12 drilling rigs because it can keep production at least flat at that level of activity and because "at this time, the country just doesn't need any more natural gas," Nichols said.

Production declines have been lower than expected in Barnett wells, he said. There will be "steep declines in the first year, but it flattens out a lot sooner than we originally thought" -- often after 12 to 18 months of production, he said.

The Barnett may soon lose its spot as the top gas-producing area, if it hasn't been already, to the Haynesville Shale in northwest Louisiana and East Texas. But Devon has lots more drilling to do in the Barnett.

7,500 drill sites left

Foster said Devon still has "7,500 potential drilling locations," which represent "probably over 20 years of inventory" for future drilling.

About 2,500 are in "the liquids-rich portion of the play," Foster said. Natural gas liquids such as ethane, propane and butane generate higher profit margins.

Future gas prices will determine how many of the 7,500 locations are eventually drilled, he said.

On average, drilling and completing a Barnett well costs Devon $2.8 million. Wells are 6,500 to 9,200 feet deep, and the average lateral length is more than 4,000 feet.

Devon's Barnett production is 78 percent natural gas, 21 percent natural gas liquids, and 1 percent oil.

In announcing Devon's purchase of Mitchell Energy 10 years ago, Nichols said the Mitchell properties "fit perfectly with our long-term objectives."

That appears perhaps even more so now, as Devon has sold international and Gulf of Mexico properties in the last two years as it embraces a new focus on onshore production in North America.

Copyright (c) 2011, Fort Worth Star-Telegram, Texas

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State: Additional Cook Inlet Investments Could Find New Gas

- State: Additional Cook Inlet Investments Could Find New Gas

Monday, August 15, 2011
Alaska Journal of Commerce
by Tim Bradner

An investment of $1 billion to $2 billion by natural gas producers in additional drilling in gas fields in Southcentral Alaska could meet projected gas supply shortages in the region until 2018 or 2020, possibly eliminating the need for local utilities to import liquefied natural gas.

A recent study by the state Division of Oil and Gas shows that if producers drill eight new production wells per year in the four largest gas fields in Cook Inlet Basin, the fields will produce sufficient new gas to meet the current 90 million cubic feet per day demand in the region at a cost of $10 million to $20 million per well with an additional $100 million investment in compression.

"This study considers what we think it will take, in terms of revenue, to get producers to produce additional gas we believe is in these fields, although we can't say the price that the field operators will feel is acceptable to make the investment," said Joe Balash, deputy commissioner in the state Department of Natural Resources, in the briefing.

ConocoPhillips, Marathon Oil Co. and Chevron Corp. are operators at the four fields included in the study.

The region's utilities, however, are skeptical that investments by producers will actually be made, and are proceeding with plans to have imported LNG available in Cook Inlet within three years.

"We can't take a chance. Our estimates show a supply gas in the region as early as 2014," said Jim Posey, general manager of Anchorage's city-owned Municipal Power & Light, one of several utilities in negotiations with potential LNG suppliers.

Despite what the state study said, Cook Inlet producers are actually drilling about half the new wells needed to sustain current production levels, Posey said. Four new development wells are planned for 2011.

The study by the Division of Oil and Gas examines gas reserves the state believes remain in the four largest gas fields, which include the Beluga, Ninilchik, North Cook Inlet and the McArthur River Grayling gas sands based on data that is public and some that is confidential, and relies on known costs for drilling and compression.

Balash said the state study included only the large producing fields and did not include new gas found though exploration, such as a recent 10 billion-cubic-foot gas discovery made by Buccaneer Energy LLC, an independent, on the Kenai Peninsula.

The study indicates that producers could earn a 20 percent internal rate of return in 2018 at a gas price below $6 per thousand cubic feet (mcf), a price that is about what producers are selling most gas produced in Cook Inlet, and a 15 percent rate of return on a gas price below $5 per mcf.

However, another assessment made in the study is that the net present value of many of the investments in wells will be modest, which could discourage some companies, particularly larger companies, from exploring, Balash said.

"It's quite possible that smaller projects could have quite good rates of return and yet have small net present values. This kind of investment might be very attractive for a small independent and less attractive for a larger company," said Jeff Dykstra, a commercial analyst in the state oil and gas division and one of the authors of the gas study.

Independent companies are in fact showing much more interest in Cook Inlet than are large companies such as the current producers.

"Most companies use several financial indicators in assessing possible investments including rate or return and net present value as well as their cash-flow needs," Bill Barron, director of the state oil and gas division, said in the briefing. Whether an investment will be made depends on a company's internal investment threshold, Barron said.

Information in the study will be used by state legislators next year as they consider additional funds needed for planning a possible $7.9 billion, 24-inch gas pipeline that could be built by the state from the North Slope. The 24-inch pipeline, which could bring gas from the slope to southern Alaska by 2019, is being considered as an alternative if a large 48-inch Alaska gas pipeline is seriously delayed.

Balash said the division will do a second increment to its Cook Inlet gas study taking into consideration a new estimate of technically-recoverable gas resources released by the U.S. Geological Survey. The USGS estimated that Cook Inlet could hold as much as 19 trillion cubic feet of conventional and unconventional gas resources, more than twice the amount of conventional gas discovered so far.

"We will try to determine a minimum economic field size that would allow some of these new resources to be developed," Balash said.

Copyright (c) 2011, Alaska Journal of Commerce, Anchorage

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Escopeta's Jackup Arrives in Cook Inlet, Set to Drill

- Escopeta's Jackup Arrives in Cook Inlet, Set to Drill

Monday, August 15, 2011
Alaska Journal of Commerce
by Tim Bradner

Spartan Drilling Co.'s Blake 151 jackup rig arrived Aug. 7 in Cook Inlet and cleared U.S. Customs before proceeding to an exploration location in upper Cook Inlet Aug. 10, a spokesman for Escopeta Oil and Gas Co. said.

The rig waited briefly in Kachemak Bay near Homer, Escopeta spokesman Steve Sutherland said in an interview.

"We [held] in Kachemak Bay until we clear customs and finalize some matters with the state Department of Natural Resources. We expect to be moving the rig to the drilling location in the Kitchen Light Unit," Sutherland said.

Escopeta has most of the permits it needs from the state. "Escopeta has an approved plan of operations from Department of Natural Resources," agency spokeswoman Elizebeth Bluemink said. "We plan an informal inspection after they arrive at the drill site but we don't have any pending DNR permits. What's still pending will come from other agencies, the AOGCC (Alaska Oil and Gas Conservation Commission) drilling permit, for example."

"We approved the plan of operations in July. The plan covers drilling related activities and not the transit period to get to the drill site," Bluemink said.

Escopeta is the main leaseholder in the Kitchen Lights Unit and will be operator of the exploration well.

If the rig moves to the location and successfully spuds the well it will qualify for a special state exploration incentive that will pay up to 100 percent of the first $25 million of costs of the first exploration well drilled with a jackup rig in Cook Inlet. Wells drilled by the same rig are eligible for follow-on incentives for the second and third exploration wells, of 90 percent of costs up to $22.5 million on the second well and 80 percent f the first $20 million for the third well.

However, the wells must be drilled for different companies.

The Blake 151 was towed from Vancouver, B.C. To Cook Inlet by three Foss Maritime Co. tugs. The rig was in Vancouver for several weeks undergoing modifications after being moved to the west Canadian city from the U.S. Gulf of Mexico by a Chinese heavy-left vessel.

The rig movement from the gulf was controversial because Escopeta's original plan was to move it directly to Cook Inlet after obtaining a waiver of the U.S. Jones Act from the Department of Homeland Security.

The rig was diverted to Canada after Homeland Security Secretary Janet Napolitano turned down the waiver request. U.S. Shipping interests who work to protect the Jones Act had urged Napolitano to turn down the waiver.

The Jones Act requires shipments of cargo between U.S. Ports to be made with American-built ships. Escoptea hired the Chinese heavy-lift ship because no U.S. Vessels were capable of moving the rig safely around the tip of South America, where there are rough seas, company president Danny Davis said earlier.

U.S. shipping groups are pushing for a penalty to be imposed on Escopta for a Jones Act violation.

"We expect the customs to issue a significant fine once the rig has completed its transit and positioned for duty in Cook Inlet," said Richard Berkowitz, Director of the Transportation Institute, a Seattle-based maritime industry association.

Even with the rig's voyage on a Chinese heavy-lift vessel terminated in Vancouver, B.C., a Jones Act violation has occurred, Berkowitz said.

Meanwhile, a second jackup rig may soon be headed to Cook Inlet. Buccaneer Energy, an Australian company, is purchasing a heavy jackup rig in Asia for drilling in Cook Inlet waters and elsewhere in coastal Alaska. That rig may be moved to Alaska this winter or by early spring.

Copyright (c) 2011, Alaska Journal of Commerce, Anchorage

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Doyon Plans New Interior Gas Exploration Effort in Nenana Basin

- Doyon Plans New Interior Gas Exploration Effort in Nenana Basin

Monday, August 15, 2011
Alaska Journal of Commerce
by Tim Bradner

Doyon Ltd., the Interior Alaska Native regional corporation, is planning new seismic work this winter in the northern part of the Nenana Basin, an Interior Alaska basin about 60 miles west of Fairbanks that is considered gas prone but also has oil potential.

About 120 miles of two-dimensional seismic is planned for this winter, according to Jim Mery, Doyon's vice president for lands. The seismic will set the stage for a possible exploration well drilled in the area, he said. It would be the second test well drilled in the Nenana Basin in recent years.

Doyon is an Alaska Native development corporation with about 11 million acres of surface and subsurface land holdings in Interior Alaska. The Nenana Basin project is on state-owned lands held under an exploration license, a form of state lease. The license area includes 483,000 acres of general state lands and an additional 9,500 acres of lands owned by the Alaska Mental Health Trust Authority, a state agency that leases its lands to support mental health programs.

Mery said Doyon plans to press ahead with exploration in spite of an announcement by Golden Valley Electric Association, the regional electric utility, and Flint Hills Resources, operator of a refinery near Fairbanks, that they will pursue a project to truck liquefied natural gas from the North Slope.

The Fairbanks area is a near-term market for any gas discovered in the Nenana Basin, although a 60-mile pipeline would be needed to bring the gas to the Interior city.

On the other hand, a plan by the state of Alaska to pursue a 24-inch pipeline built from the North Slope to Southcentral Alaska would have its line pass through the Nenana Basin near where Doyon plans exploration. If gas is discovered, and if the pipeline is built, Doyon could ship its gas to Southcentral Alaska through the pipeline.

"There are a lot of moving parts to the pipeline and natural gas picture, and our decision is to move ahead with our plans," Mery said.

Doyon and three partners drilled a well two years ago in the southern part of the basin with mixed results. No gas was found but there were indications that hydrocarbons were present in the region. Doyon's partners in the Nenana Basin exploration have been Arctic Slope Regional Corp., another Native development corporation with holdings on the North Slope, and Usibelli Energy LLC, an affiliate of Usibelli Mines, which operates a coalmine near Healy, also in Interior Alaska.

Mery said this winter's program will involve the first seismic done in the northern part of the Nenana Basin, which is believed to hold the deepest part of the basin, with sedimentary rocks possibly as deep as 16,000 feet.

State geologists have said the basin exhibits somewhat similar geology to the prolific Cook Inlet basin in southern Alaska and is generally considered prospective for natural gas. A geologic assessment of the basin indicated the possibility of 3 trillion cubic feet of technically recoverable thermogenic gas in the basin, with the possibility of additional biogenic gas. There were two earlier exploration wells drilled, by Unocal in 1962 and ARCO in 1984, but the wells were drilled at the far southern, and shallowest, part of the basin and were unsuccessful.

A key advantage of Nenana Basin gas for the state's 24-inch pipeline is that a 500 million cubic feet per day limit that applies to the state project because of its contract with TransCanada Corp. does not apply to gas found in Interior Alaska and shipped through the pipeline, said Dan Fauske, president of the Alaska Gasline Development Corp., the state corporation planning the 24-inch pipeline.

The state's 24-inch pipeline could move 500 million cubic feet per day from the North Slope to comply with the TransCanada contract and any gas from the Nenana Basin could be above that amount, Fauske told legislators in recent briefing.

TransCanada and ExxonMobil Corp. are planning a 48-inch pipeline built from the North Slope to Canada and are working with incentives offered by the state. As a part of the agreement the state is limited in helping a competing pipeline that would ship more than 500 million cubic feet per day from the slope.

The 500 million cubic feet per day limit is a source of frustration to many state legislators because it limits the development of industrial customers who would need more than the gas that could be delivered under the limit. Industrial customers are needed for the 24-inch pipeline build to Southcentral Alaska to be economically viable.

Copyright (c) 2011, Alaska Journal of Commerce, Anchorage

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Shell: Gannet Oil Leak Under Control

- Shell: Gannet Oil Leak Under Control

Monday, August 15, 2011
Rigzone Staff
by Karen Boman

The oil leak on a flowline system that serves the Shell-operated Gannet Alpha platform in the North Sea has spilled an estimated 1,300 barrels, or 216 tonnes, a Shell spokesperson said. The spill remains under control, with the well shut in on Wednesday, Aug. 10 and work underway to completely halt any further oil leakage.

"This is a significant spill in the context of annual amounts of oil spilled in the North Sea. We care about the environment and we regret that the spill happened. We have taken it very seriously and responded promptly to it," said Glen Cayley, technical director of Shell's exploration and production activities in Europe, in a statement today.

Cayley estimates that the current rate of leaking is less than five b/d. The sheen, which also changes from day to day, is 0.5 square kilometres in size. The spill is a light crude oil with a low wax content (API-36). There is also some hydraulic fluid in present.

Cayley added, "The high winds and waves over the weekend have led to a substantial reduction in the size of the oil sheen as can be seen from the current levels on the water. We continue to expect that the oil sheen will disperse naturally due to wave action and that it will not reach the shore."

Personnel on the platform are safe and the platform continues to operate. A standby vessel, Grampian Prince, remains on station monitoring the area, with oil spill response equipment and dispersant available if required. Shell's emergency response team remains in place and is working with the relevant authorities (DECC, MCA, Marine Scotland, Scottish Government) to manage the incident and minimize its environmental impact.

"We are also in contact with RSPB and other environmental agencies. We will be sharing our latest estimates with them as well as what we know about the nature of the oil, and the monitoring of wildlife," said Cayley.

The UK Department of Energy and Climate Change (DECC) said its environmental inspectors will continue to monitor the situation and have been working closely with the company and counterparts from the Health and Safety Executive, Maritime and Coastguard Agency and Marine Scotland since the spill was reported last week.

"Although small in comparison to the Macondo, Gulf of Mexico, incident, in the context of the UK Continental Shelf the spill is substantial – but it is not anticipated that oil will reach the shore and indeed it is expected that it will be dispersed naturally.

"The UK Continental Shelf oil spill record is strong which is why it is disappointing that this spill has happened. We take any spill very seriously and we will be investigating the causes of the spill and learning any lessons from the response to it."

The Gannet field is in the Central North Sea around 112 miles (180 km) east of Aberdeen. It is operated by Shell U.K. Limited on behalf of itself and Esso Exploration and Production UK Limited.

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56,600 Gallons of Oil Spilled in North Sea

- 56,600 Gallons of Oil Spilled in North Sea

Aug 15, 2011

Royal Dutch Shell (NYSE:RDS.A) estimated Monday that 54,600 gallons of oil have spilled into the North Sea from an oil rig off eastern coast of Scotland.

The Gannet Alpha oil rig, located 112 miles east of the city of Aberdeen, is operated by shell and Eddo, a subsidiary of Exxon Mobil (NYSE:XOM).

According to the technical director of Shell's European exploration and production activities, "We care about the environment and we regret that the spill happened."

It was not clear when the leak began last week. Shell announced it Friday and said it was under control on Saturday.

Exxon Mobil (NYSE:XOM) has a potential upside of 25.7% based on a current price of $73.9 and an average consensus analyst price target of $92.88.

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NOV Pens $1.5B Deal for 7 Drillship Equipment Packages

- NOV Pens $1.5B Deal for 7 Drillship Equipment Packages

Monday, August 15, 2011
National Oilwell Varco Inc.

National Oilwell Varco has signed contracts to supply drilling equipment packages for seven drillships to Estaleiro Atlantico Sul ("EAS"), including drilling riser and pressure control equipment. The value, over the term of the deliveries, is approximately $1.5 billion.

Pete Miller, Chairman, President and CEO of National Oilwell Varco, stated "We are pleased to have been selected as the drilling equipment supplier for this prominent project, and excited to work with one of Brazil's premier shipyard companies, EAS. Brazil's extraordinary deepwater discoveries of the past several years have transformed it into one of the most significant offshore markets we serve, and one we expect to continue to grow. We are investing heavily in Brazil to manufacture more of the products and technologies National Oilwell Varco provides to our oil and gas customers, and to service the rapidly growing installed base of NOV drilling equipment in the region.

"Congratulations to our Rig Technology team in securing the largest single order in our company's 150 year history."

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Indonesia After OPEC

- Indonesia After OPEC

Monday, August 15, 2011
Rigzone Staff
by Barbara Saunders

Back in 1990, former Indonesian OPEC minister Ginandjar made a jarring statement: his country would become a net oil importer and "have to drop out of OPEC" and also, that the large, multi-island Southeast Asian nation would have to diversify its energy sources to fuel its growing and modernizing population.

A few years ago, in 2008, Ginandjar's prediction came true as Indonesia pulled out of OPEC. Now, Indonesia's petro-regulatory agency BPMigas has confirmed that oil production is declining – but announced 10 new projects heavily tilted toward natural gas that should help with the energy diversification goal and Indonesia's continuation as a major LNG exporter.

The announced projects represent a total investment of $4.725 billion and are slated to come onstream between this year and 2014, the agency reported. Anticipated output is 1.750 million cubic feet of gas per day (MMcfd); 20,000 barrels oil per day (bpd); and 26,000 bpd of oil condensate, BPMigas spokesman Gde Pradnyana said in a statement.

"This reflects that the future of Indonesia's oil and gas industry will be dominated by gas," Pradnyana added. He emphasized that domestic markets, which are burgeoning with demand for gas, will get priority but did not rule out the possibility of exports.

The 10 projects are as follows:
    Slated for First Production 2011 –
  • Pengembangan Lapangan Jambi Merang, Pertamina-Talisman, Gas 155 MMcfd, Condensate: 12.50 bpd , 2Q 2011
  • Ujungh Pangkah, Hess Indonesia & Pangkah, Oil 20,000 bpd, Gas 150 MMcfd 3Q 2011
  • Gajah Baru, Premier Oil, Gas 210 MMcfd , 4Q 2011;
    Slated for First Production 2012 –
  • Terang Sirasun Batur, Kangean Energy Indonesia, Gas: 300 MMcfd 2Q 2012
  • South Mahakam Phase 1 & 2, Total E&P Gas: 128 MMcfd; 5,900 bpd condensate, 3Q 2012
    Slated for First Production 2013 -
  • Ruby Gas Field Development, Pearl Oil and Sebuku, Gas 100 MMcfd, 3Q 2013
  • South Belut, ConocoPhillips Indonesia, Gas 120 MMcfd, 1,000 bpd condensate, 4Q 2013
  • Naga-Pelican, Premier Oil Natuna, Gas 130 MMcfd, 4Q 2013
  • Sisi Nubi 2B, Total E&P Indonesia, Gas 350 MMcfd, 2Q 2013
    Slated for First Production 2014 –
  • Madura BD Deveopment, Husky Oil Madura, Gas Production 100MMcfd, Condensate 6,600 bpd, 4Q 2014

Meanwhile, the government reported recently that state revenues from the oil and natural gas sector, as of May 2011, has reached nearly US $14 billion, exceeding the state budget target by 39 percent or US $10.062 billion.

BPMIGAS chairman R. Priyono stated that as of July 2011, oil and condensate this year is estimated at 920 thousand bpd, while natural gas lifting is projected to reach 7.769 trillion Btu per day. Total lifting is proposed at 2.259 million barrels oil equivalent per day (boepd), changing from 2.31 million boepd.

"Average optimum production potentials as much as 920 thousand bpd may be achieved with fulfilled conditions, which are all new projects [being] completed on time," he said.

The Global Business Guide Indonesia commented, "The state oil and gas company Pertamina is targeting 1 million bpd by 2015 to once again make the country a net oil exporter; but this will be no easy task. The energy sector faces the challenge of meeting its export commitments, satisfying domestic demand and effectively leveraging its resources for economic growth."

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Shell: 1,300 Barrels of Oil Spilled from North Sea Leak

- Shell: 1,300 Barrels of Oil Spilled from North Sea Leak

Monday, August 15, 2011
Dow Jones Newswires
by Alexis Flynn

Around 1,300 barrels of oil are estimated to have spilled into the U.K. North Sea from a leaking pipeline at a Shell platform since last Wednesday, the Anglo-Dutch major said Monday.

"It isn't easy to quantify the total volume spilled but we estimate so far that it is around 216 tons [1,300 barrels]," said Glen Cayley, technical director of Shell's exploration and production activities in Europe.

The current rate of leaking is less than five barrels a day, Shell said.

Shell said the volume of oil at the sea surface is estimated at around one ton, or around six barrels. Wave action and high winds over the weekend have led to a "substantial" reduction in the size of the visible oil sheen, Cayley said.

"This is a significant spill in the context of annual amounts of oil spilled in the North Sea," said Cayley. "We care about the environment and we regret that the spill happened. We have taken it very seriously and responded promptly to it."

An undersea pipe at the Gannet Alpha platform has been leaking oil into the ocean since last Wednesday. Shell said the leak is "under control" and that the well that feeds the pipeline, shut in since Wednesday, remains closed.

The Department of Energy and Climate Change said that while the spill was small in comparison with BP's Gulf of Mexico accident last year, it was "substantial" in the context of the U.K. continental shelf. DECC said its environmental inspectors will continue to monitor the situation and are working closely with the company and counterparts from the Health and Safety Executive, Maritime and Coastguard Agency and Marine Scotland.

The size of the sea surface affected is estimated to be some 31 kilometers by 4.3 kilometers at its widest point. A sheen, estimated at 0.5 kilometers in size, is currently moving west from the field.

The platform is located 180 kilometers east of Aberdeen, Scotland. Shell operates the platform along with partner ExxonMobil's U.K. unit Esso.

Oil from the Gannet system is taken to Teesside, U.K., through the Fulmar pipeline as part of Ekofisk blend. Production at the facility is estimated to be around 6,000 barrels a day, according to a trader.

The platform had 10 leak incidents in 2009 and 2010, according to an HSE document showing voluntarily declared spills. Only one of the incidents was described as "significant" while the others were logged as "minor."

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

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Beach Strikes Oil at Elliston-1 Well

- Beach Strikes Oil at Elliston-1 Well

Monday, August 15, 2011
Beach Energy Ltd.

Beach Energy has made a new field oil discovery at Elliston-1, the second successful exploration well from three drilled in PEL 92 (Beach 75%) for the financial year to date.

The Elliston-1 well, located in the Western Flank of the Cooper Basin, encountered an oil column with net pay of three meters in the Namur Sandstone section of the well. Preliminary volumetric assessment indicates a discovery in the order of one hundred thousand barrels of recoverable oil (gross).

The Elliston-1 reservoir appears to be of high quality with the potential to deliver strong flow rates. As it is near infrastructure, the tie-in of the well should be relatively quick, with the well expected to be on-line in the fourth quarter.

Following the completion of the evaluation program, the Ensign #30 rig will be moved to the Perlubie-2 appraisal well which is located about four kilometers to the south of Elliston-1.

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SacOil: Work Program to Commence at Congo Block III

- SacOil: Work Program to Commence at Congo Block III

Monday, August 15, 2011
SacOil Holdings Ltd.

SacOil provided an operational update on the Block III oil concession ("Block III"), Albertine Graben in the Democratic Republic of Congo ('DRC'), in which SacOil has an effective 12.5 percent interest.

As announced on March 4, 2011, Semliki Energy SPRL ("Semliki"), a 50 percent owned subsidiary of SacOil, successfully concluded a farm-in agreement in March 2011 with Total E&P RDC ("Total") pursuant to which Total acquired an effective 60 percent undivided interest in, and became the operator of, Block III. The Government of DRC holds an effective 15 percent interest and DIG Oil holds an effective 12.5 percent interest respectively in Block III.

Work Program

SacOil announced the establishment of the Block III Operations Committee ("Committee") for the management of Block III joint venture operations. The Committee consists of members from SacOil, Total, DIG and a representative of the Government. The first meeting took place in Kinshasa in June 2011 and further meetings are scheduled to take place on a bi-annual basis to monitor and report back on the execution of the work program.

The work planned and agreed on Block III includes an airborne gravity and magnetic survey over the license area, the results of which are expected in 4Q of 2011. This will form the basis for the next stage of the program which will include the acquisition of a targeted 2D seismic survey. The performance of the work program is subject to first obtaining the relevant ministerial authorization.

Bradley Cerff, Vice President Commercial of SacOil commented, "I am pleased with the progress we are making at Block III with our partners Total. Work will shortly commence on carrying out the preliminary aeromagnetic surveys which is the precursor to targeted seismic surveys. The Block III project in the DRC has an exceptional postcode in terms of recent neighboring discoveries in Uganda. We look forward to updating shareholders on further work programs as we move towards drilling a maiden well on Block III during the first phase of the exploration period."

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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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Nostra Terra Reaches Total Vertical Depth at Verde Prospect

- Nostra Terra Reaches Total Vertical Depth at Verde Prospect

Monday, August 15, 2011
Nostra Terra O&G Co. plc

Nostra Terra announced that the initial well in the Verde Prospect in south-eastern Colorado, has been drilled ahead of schedule to a total vertical depth of 5,300 feet.

Indications of productivity in drilling samples and electric logs were positive and the well has been recommended for completion.

Production casing will be run to total depth, followed by completion in the most optimal zone(s). NTOG will provide the first 30-day production figures as soon as these are available.

NTOG has a 16.25% working interest (WI) in the Verde prospect. Following evaluation of testing and potential production of the initial well, two or three further development wells (PUDs) could be drilled, in which Nostra Terra also has the right to participate.

Matt Lofgran, Chief Executive Officer of Nostra Terra, commented, "We're pleased with the progress made on this well ahead of schedule and hope to see further positive results on this prospect. As a company, our current prospects are fully-funded, with additional cash on hand for further acquisitions, allowing us to continue to grow, regardless of the state of the global economy or markets."

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Caza Spotlights Operational, Financial Results for 2Q11

- Caza Spotlights Operational, Financial Results for 2Q11

Monday, August 15, 2011
Caza O&G Inc.

Caza O&G provided its unaudited financial and operational results for the six months ended June 30, 2011.

Second Quarter Financial Highlights
  • Caza's production increased 32% to 18,130 Boe for the three-month period ended June 30, 2011, from 13,712 Boe for the comparative period in 2010. This represents an average daily production rate increase of 48 Boe/d for the three month period ended June 30, 2011, 199 Boe/d as compared to 151 Boe/d for the comparative period. As anticipated, Q2 2011 production was slightly lower than Q1 2011 (which was 23,974 Boe) due to standard production curve declines in certain wells. Recently drilled wells that are in various stages of completion are expected to more than make up for the decline (see "Second Quarter Operational Highlights" below).
  • Caza had a cash balance of $24,533,451 as of June 30, 2011, as compared to $9,375,345 at June 30, 2010 and $33,885,900 at December 31, 2010. The increase is attributable to the placing announced on Nov 15 2010. Caza's working capital balance at June 30, 2011, was $20,870,708 as compared to $26,612,514 at March 31, 2011. The decrease in Caza's working capital balance primarily represents the investments made to drill the O.B. Ranch #2 development well in Wharton County, Texas, the Caza Elkins 3401 & 3402 wells in Midland County, Texas, and the Caza 158 #3 in Upton County, Texas.
  • Revenues from oil and gas sales increased 112% to $843,836 for the three-month period ended June 30, 2011, up from $398,883 for the comparative period in 2010. The increase in revenues was primarily due to the additional wells brought on since the comparative period. The average combined price received by Caza increased 60% to $46.54 per Boe during the three-month period ended June 30, 2011, from $29.09 per Boe during the comparative period in 2010.
  • General and Administrative expenses were $1,435,156 ($1,403,088 net of reimbursements) for the three-month period ended June 30, 2011, as compared to $1,188,962 ($1,078,739 net of reimbursements) for the comparative period in 2010. The change in General and Administrative costs are a result of additional costs incurred and changes in reporting requirements as a result of converting to the International Financial Reporting Standards. During the three month period ended June 30, 2010, the Company received reimbursements that resulted from certain joint venture agreements that provided reductions in overhead costs that expired April 8, 2010.

Second Quarter Operational Highlights
  • Drilling commenced on the O.B. Ranch #2 development well in Wharton County, Texas in May 2011. The well reached its target depth of 13,210 feet in June 2011, and electric logs were obtained through the target depth indicating potential pay in the Frio and targeted Cook Mountain formations. The well was fracture stimulated at the end of July 2011, and is currently being flowed back in order to clean up the fracture fluids. The well has been placed on an extended well test, and the market will be updated once stabilized flow rates have been achieved.
  • The Caza Elkins 3401 well in Midland County, Texas, reached a total depth of 11,854 feet in June 2011. The rig was immediately moved to the Caza Elkins 3402 location, which reached a total depth of 11,852 feet in July 2011. Log data from both wells indicated multiple potential pay sands for both oil and gas in the Spraberry, Wolfcamp, Strawn, Atoka and Mississippian/Devonian formations. The fracture stimulation program for the Caza Elkins 3401 well began on July 28, 2011. The fracture stimulation program for the Caza Elkins 3402 well began earlier than anticipated on August 12, 2011. Both wells are currently being flowed back in order to clean up the fracture fluids. Caza will update the market once initial flow rates have been established for each well.
  • The Caza 158 #3 well on the Windham property reached its target depth of 9,824 feet in June 2011, and Caza elected to participate in the operator's proposal to complete the well. The well has been fracture stimulated across all potentially productive intervals seen on the logs, which include the Spraberry/Wolfcamp, Penn and Strawn formations. The Caza 158 #3 was the fourth well drilled and completed on this property. The Caza 158 #1, 158 #2 and 162 #1 wells are currently at various stages in their respective fracture stimulation programs, but are all producing oil and natural gas.

W. Michael Ford, Chief Executive Officer commented, "I am very pleased with the progress that we have made in 2011, both operationally and from a financial perspective. In the three months to June 30, 2011, Caza has continued to progress a busy work program, which should add further production, reserves and cash flow to the solid platform that we have created through our endeavors to date.

"Revenues have materially risen due to increased oil and gas production levels and a supportive price environment. As we add production through our exploration and development campaign, the Company and the shareholders should continue to benefit.

"I look forward to updating the market on future exploration activities and established flow rates associated with wells that are currently in various stages of completion operations."

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Rockhopper Boosts Estimates at Sea Lion Play

- Rockhopper Boosts Estimates at Sea Lion Play

Monday, August 15, 2011
Rockhopper Exploration plc

Rockhopper provided the following update on the interpretation of the fast track seismic data over acreage on licenses PL032 and PL033:
  • Initial interpretation of fast track new seismic data in PL032 and PL033 completed
  • Seismic shows Sea Lion Main Complex ("SLMC") to extend to the south and new high case area to extend over 90km2
  • Two new fan prospects identified within new seismic, Casper and Kermit
  • Management interpretation for SLMC potential size: 
    • Low Case: 608 MMbbls STOIIP
    • Mid Case: 1,086 MMbbls STOIIP
    • High Case: 1,279 MMbbls STOIIP

Volumes listed above are within Rockhopper's 100% owned acreage. Not included in the high case listed above, based upon the current interpretation, the Company believes that up to approximately 10% additional volume could be contained within license PL004, in which Rockhopper has a non-operated 7.5% working interest.

During 2011 the Company acquired a total of over 4000km2 of 3D seismic data in conjunction with other operators in the area. Data over the southern portion of licenses PL032 and PL033 has been fast track processed and an initial interpretation has now been completed. This initial interpretation, combined with well data from 14/10-2, 14/10-3, 14/10-4, 14/10-5 and 14/10-6, indicates that the SLMC comprises two fan lobes sourced from the same main feeder channel just to the east of the 14/10-5 and 14/10-2 wells.

The two lobes, represented as sand packages within the wells, are identified as the SL20 and SL10 units, and, from the formation pressure data acquired in the wells, are shown to be in pressure communication. The two packages together comprise the SLMC and are interpreted to comprise of mass flow turbidite sand sequences prograding from the sand input point to the east and extending beyond the southern boundary of license PL032 into license PL004, where Rockhopper has a non-operated 7.5% working interest.

The Company believes that recovery rates of 30% to 40% could be achievable using industry standard production techniques including water injection, artificial lift, deviated or horizontal wells and /or other enhanced oil recovery techniques.

Should a recovery factor of 30% be achieved, based upon the Company's mid case area, the SLMC would contain approximately 325mmbbls recoverable oil. Should a recovery factor of 40% be achieved, the mid case number would increase to 434mmbbls recoverable oil.

The fast track seismic interpretation has enabled the identification of two new feeders into the basin and the mapping of two new prospects, Casper and Kermit. Both of these comprise similar fan systems fed from eastern basin margin feeder channels and exhibit similar seismic character to the SLMC. Casper is stratigraphically shallower than the SLMC while Kermit is stratigraphically deeper than the SLMC.

Following well 14/10-6 the Company believes that the B15 sand, which forms part of the lower fan complex, has the potential to contain up to 161 mmbbls STOIIP on a high case basis. Formation pressure testing indicates that B15 is also in communication with the SLMC.

Fan prospects currently mapped on the Company's acreage are now SLMC, Lower Fan (B sands), Chatham, Casper and Kermit.

In addition to the SLMC, management interpretation of potential in place resources across the other fan prospects within the licence is set out below (All mmbbls STOIIP):

Low Mid High
Lower Fan (B15) 100 130 161
Casper 135 163 194
Kermit 39 47 55
Chatham 28 93 318

The balance of the newly acquired 3D seismic data is still being processed and the Company expects it will be available for interpretation before the end of 2011.

Future Drilling Plans

Following completion of drilling operations on well 14/10-6, the Company is currently committed to drill three further wells using the Ocean Guardian drilling unit. The Company is discussing the possibility of drilling additional wells under an assignment agreement.

The Company intends to drill the next well 3.3km north west of the 14/10-2 discovery well. The second well in the sequence is currently planned to be located approximately 4.1 km to the south south east of the 14/10-2 discovery well. The third well in the sequence is currently planned to be located approximately 5.5km south west of the 14/10-2 discovery well. The second and third locations are subject to change depending upon drilling results and technical work and are subject to gaining the relevant regulatory consents. The Company currently intends to wait for the result of well 14/10-7 before deciding whether to take any additional drilling slots. Estimates of in place and prospective resource information are based upon wells drilled to date and could alter with future well results. Once the Company completes its current drilling campaign, all estimated potential in place resource estimates will be further refined.

Operations continue at the 14/10-6 location and a further announcement will be made once 14/10-7 has been spudded.

Sam Moody, Chief Executive, commented, "We are highly encouraged by the interpretation of new seismic data which identifies both significant reservoir extension and the existence of two additional fan prospects above and beneath the Sea Lion Main Complex. We look forward to continuing our drilling program as we seek to further refine our understanding of Sea Lion and the other prospects on our licenses."

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