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Oil and Gas Energy News Update

Monday, May 9, 2011

Commodity Corner: Oil Bounces Back

Commodity Corner: Oil Bounces Back

Monday, May 09, 2011
Rigzone Staff
by Matthew Veazey

Crude oil for June delivery settled above $100 Monday—$102.55 a barrel, to be exact.

Sensing a buying opportunity after last week's 14.7-percent decline in oil futures, investors helped to give oil a $5.37 day-on-day bounce. Monday's rally stems in part from expectations that the overall supply and demand fundamentals for oil will become less elastic by early 2012.

Oil peaked at $103.40 and bottomed out at $97.42 Monday.

Also surging Monday was the front-month price for gasoline, which gained 17 cents to settle at $3.28 a gallon. Propelling gasoline were fears that an increasingly swollen Mississippi River will curb production from refineries along the waterway. Widespread, potentially record-breaking spring flooding is threatening cities and towns along the river from the Midwest to the Deep South.

June gasoline traded within a range from $3.10 to $3.31.

Natural gas for June delivery lost 8.5 cents to end the day at $4.15 per thousand cubic feet. Gas, which has fallen as temperatures moderate in the Midwest and Northeast, fluctuated from $4.15 to $4.30 Monday.

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India Revives Energy Ties with Iran

India Revives Energy Ties with Iran

Monday, May 09, 2011
Knight Ridder/Tribune Business News
by Utpal Bhaskar & Elizabeth Roche, Mint, New Delhi

In a visible attempt to re-engage with Iran's energy sector, India has submitted a reworked master development plan for Iran's Farsi natural gas block.

A consortium led by ONGC Videsh Ltd (OVL), the overseas arm of state-owned Oil and Natural Gas Corp. Ltd, won the bid in 2002, but is yet to develop the gas block.

While OVL is the operator of the Farsi block, in which it holds a 40% stake, Indian Oil Corp. Ltd has an equal stake and the balance 20% is held by Oil India Ltd. The block cannot be developed without a master plan.

The plan, submitted last month, could reduce the country's energy risks by diversifying its supplies, but could also cause tension in India-US ties.

India had recently preferred two European companies over US ones in the shortlist for the $10 billion ('44,600 crore today) jet procurement deal for the Indian Air Force, billed as India's biggest defence contract yet. Seattle-based Boeing Co. and the Bethesda, Maryland-based Lockheed Martin Corp., also contenders for the deal, were not among the finalists.

Indian government officials, underlining the country's reliance on Iran as an energy partner, have been seeking a more flexible approach from the US and other members of the international community on sanctions against Iran.

India's action comes against the backdrop of two sets of sanctions imposed in June by the US and United Nations that included strictures against Iran's energy and banking sectors, which could also hurt firms from other countries doing business with Tehran.

"India can't find alternative sources of energy overnight," said a government official, who did not want to be named.

The development plan was prepared with the help of Sydney-headquartered WorleyParsons Ltd. The consortium had earlier submitted a feasibility report to National Iranian Oil Co. (NIOC) in November 2008. The Iranian firm then accepted the commercial viability of gas production at Farsi block, after which the first plan was submitted in April 2009.

"We submitted the (revised) MDP (master development plan) last month. We had earlier submitted it but the Iranians had sought some modifications to it," said the chief executive of one of the consortium partners, who did not want to be named. "We haven't given up on Iran."

Mint reported on 12 January about legal advice sought by OVL cautioning it against proceeding with the Iran projects, providing a test case of how far India is willing to go to accommodate US sensitivities at the cost of its energy security.

"In its quest for energy security, India has been engaging a host of countries, including Iran, which is an important source of hydrocarbon products for us," Vishnu Prakash, spokesperson for the Indian foreign ministry, said in an emailed response. "India's outlook remains unchanged."

The investment for exploration and production work will amount to around $5 billion. While the Indian consortium doesn't have ownership rights, its members will be paid a 15% return on investment they make once they are awarded development rights.

The Farsi block is estimated to have reserves of up to 21.68 trillion cu. ft (tcf), with recoverable reserves of around 12.8 tcf.

"There has been suspended animation on Iran projects. While on the one side, there have been various sanctions in place, on the other, several projects are active, including the ones being undertaken by the Chinese," the chief executive quoted above said. "We don't want to disengage."

NIOC could not be contacted. While Iran embassy officials in New Delhi did not respond to phone calls on Friday, the US embassy did not respond to an email query at the time of going to press.

Iran has the world's second largest oil and natural gas reserves. After India and the US signed a civilian nuclear deal in 2008, several Iran-related Indian projects have either been put on hold or dropped.

India and Iran are also trying to resolve an impasse over the method of settlement for bilateral oil trade, after India decided to discontinue payment through the 35-year-old Asian Clearing Union system.

"We seem to have no consistent policy, especially when it comes to Iran (in these matters)," said Lydia Powell, head at Centre for Resources Management, at New Delhi-based Observer Research Foundation, a think tank.

Kalim Bahadur, former international studies professor at Jawaharlal Nehru University, sees it as a move by India to diversify its energy sources, given the unrest in West Asia.

"I think India is looking for newer energy sources, given that there is so much uncertainty in the Middle East, which has been its traditional source of oil," he said. "If uncertainty persists, oil prices will be affected and could hurt our economy and cause problems. The government seems to be weighing its options."


Copyright (c) 2011, Mint, New Delhi. Distributed by McClatchy-Tribune Information Services.

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Unclear Ownership of Mineral Rights May Hurt Ohio's Revenue Hopes

Unclear Ownership of Mineral Rights May Hurt Ohio's Revenue Hopes

Monday, May 09, 2011
The Columbus Dispatch, Ohio
by Spencer Hunt

Plans to make millions of dollars by opening up state parks to drilling could be limited by the relatively small amount of natural-gas rights Ohio actually owns.

Of the 115,300 acres of state parks, the Ohio Department of Natural Resources estimates that it owns the gas rights for 34,590 acres. That's less than one-third of the state park land that could be opened to drilling if lawmakers approve one of several proposals.

In many cases, the state doesn't know who owns the natural-gas rights, said Gene Wells, real-estate administrator for the Ohio Department of Natural Resources. Access to natural gas is covered by mineral rights.

"Some of these lands were purchased in the 1920s," Wells said. "It was not an issue back then to clearly identify what our mineral interests were."

It's definitely an issue now.

Eager to tap natural gas in the deeply buried Marcellus and Utica shale deposits in Ohio, energy companies are offering landowners as much as $1,500 an acre for the mineral rights. Gov. John Kasich and Natural Resources officials say that the proceeds from drilling would help whittle down a $560 million maintenance backlog at state parks.

Landowners lease access to the mineral rights and collect royalty payments from any gas the wells produce.

But if the state doesn't own the rights, it can't make any money.

In many cases, there are old leases that give companies "surface access." This could force the state to allow drilling despite having no mineral rights or chance of royalties.

Wells and Thomas Stewart, executive vice president of the Ohio Oil and Gas Association, said leaseholders could argue that they have the legal rights to drill in some of the state's parks right now.

"It's always been the case that that possibility existed," Stewart said.

Environmental advocates who oppose such drilling say that fact raises a red flag.

"Drilling in state parks is going to make more headaches than money for the state," said Jennifer Miller, spokeswoman for the Ohio chapter of the Sierra Club. "It's just a plain bad idea."

Some of the mineral-rights owners are well-known. Wells said the Army Corps of Engineers holds the rights to thousands of acres, mostly for parks centered on reservoirs, including Alum Creek State Park in central Ohio.

Wells said the federal agency has told him it will not allow drilling. Corps officials did not return calls for comment.

Columbia Gas Transmission Corp. holds leases on much of the mineral rights beneath Mohican, Malabar Farm and Hocking Hills state parks. The company currently uses old wells in the parks as storage sites for natural gas, Wells said.

In an email, the company said it has not subleased rights to drill into the Utica shale beneath any of its storage sites at state parks. The company wrote that it has subleased mineral rights beneath natural-gas storage areas across the United States to oil and gas companies.

In many cases, Wells said, Natural Resources doesn't know who holds the mineral rights or what lease agreements might still apply to sites. To find out, the state would have to perform title searches in county recorder offices statewide.

For example, the state owns the surface rights to 627.5 acres in Tar Hollow State Park, but it has no idea who holds the mineral rights.

"On a case-by-case basis, we'd have to look at the (ownership) history and go from there on what we would allow," Wells said.

Most of the mineral rights that state parks officials have confirmed are concentrated in Salt Fork State Park in Guernsey County. The 20,756-acre state park is surrounded by oil and gas wells.

It's unclear how much money the state could make if it opened state parks to drilling, but Stewart said the income would be substantial.

"It is 34,000 acres," he said. "That's a lot of acreage."

Sen. Keith Faber, a Celina Republican who co-sponsored one of the bills that would allow drilling on public lands, said he would support drilling no matter how much the state stands to make.

"Just because the state doesn't get the money, you shouldn't limit the drilling," said Faber, the second-highest-ranking Republican in the state Senate. "Ohio still benefits from a vibrant oil and gas industry and from the jobs that are created."

Jack Shaner, a lobbyist with the Ohio Environmental Council, said the risks of pollution and ecological harm outweigh the potential economic benefits.

"I think most Ohioans would be outraged to learn that the state may not be able to control what goes on in our parks," Shaner said.

"Instead of figuring ways to allow the industry to scheme their way into our parks, the door should be firmly closed."

Copyright (c) 2011, The Columbus Dispatch, Ohio. Distributed by McClatchy-Tribune Information Services.

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Cook Inlet Drilling Still Lags Pace Needed to Sustain Gas Supply

Cook Inlet Drilling Still Lags Pace Needed to Sustain Gas Supply

Monday, May 09, 2011
Alaska Journal of Commerce
by Tim Bradner

More drilling is under way in Cook Inlet natural gas fields, but the pace is still short of the number estimated to needed to forestall shortages of gas in the region.

Still, there are glimmers of hope. Although the quantities are still small, new gas is coming into Enstar Natural Gas Co.'s pipeline system from a new producer, Armstrong Oil and Gas.

Also, explorers drilling for gas in Southcentral appear to be finding some, although it is too early to know whether the wells can be commercially produced.

The overall pace still falls short of what is needed.

Firms operating producing fields in Southcentral Alaska this year plan four new production wells. Independent companies also have drilled three exploration wells this winter. The last one, being drilled near the city if Kenai, is now being completed.

However, seven new gas wells in total drilled this year are less than half the 18 new wells estimated to be needed each year if the region's gas reserves are to be sustained.

The estimate was done for the regional utilities in 2010 by Petrotechnical Resource Alaska, an Alaska-based petroleum-consulting firm.

Meanwhile, Southcentral electric utilities have kicked off construction of a number of new gas-fueled power generation facilities, but there are questions about where the gas for these new plants will come from.

Chugach Electric Association and Municipal Light and Power have the new $369 million Southcentral Power Project plan underway in south Anchorage.

Matanuska Electric Association's new $250 million gas-fired generation plant in Eklutna is in the early stages of permitting.

Homer Electric Association also has two new, smaller power generation projects, one that has started construction.

The Regulatory Commission of Alaska has approved Chugach's request to pass its share of the Southcentral power plant costs, about $200 million, on to its customers. A similar request is anticipated from ML&P for its one-third share, RCA chairman Bob Pickett said.

Although the turbines in the new facilities will be more efficient, typically using a third less gas to generate power than older equipment now used, the net result may still be an increase in total gas use.

It isn't clear where the gas will come from. A gas pipeline from the North Slope is years away, if it can even be built. Several utilities, including the regional gas utility, Enstar Natural Gas Co., are working on possible imports of liquefied natural gas.

"There's not much we can say about it right now," Enstar spokesman John Sims said.

Jim Posey, ML&P's general manager, said about the same.

"I'm much more encouraged about this than I was three months or six months ago," Posey said. He said he hopes to be able to talk in more detail sometime in the summer.

Pickett, at the RCA, said the regulatory commission wants to know about this, however.

The commission will ask the utilities to tell it where things stand on possible LNG imports in a meeting in late May or early June, Pickett said.

Although the pace of drilling isn't enough, there are some positive developments for the regional gas supply pictures.

Enstar is now taking delivery of gas from the small North Fork gas field on the Kenai Peninsula near Homer, Enstar said.

Armstrong Oil and Gas, a Denver-based independent company that owns the North Fork field, began deliveries in early April, Enstar spokesman Sims said.

The utility is taking about 15 million to 25 million cubic feet of gas daily, although this is expected to increase. Enstar's contract with Armstrong calls for the company to deliver 1 billion cubic feet of gas per year.

Enstar built a $21 million, 21-mile, eight-inch pipeline from an existing pipeline from Ninilchik to Anchor Point, where it has linked with two four-inch pipelines built by Armstrong from the North Fork field.

Armstrong is now producing from two wells at North Fork and has drilled two more wells, Sims said.

Companies operating producing fields in the region have four new production wells planned. Marathon Oil Co. plans one well in the Ninilchik gas field on the Kenai Peninsula. Marathon also plans two new production wells on the Steelhead platform in Cook Inlet. Marathon owns the platform, which produces gas, although Chevron Corp. manages production operations.

One new production well is planned for the Beluga gas field, according to Municipal Light & Power, which owns a third of the field.

Exploration wells drilled this winter meanwhile have found some gas, although it is too early to know if they can be produced.

Linc Energy, an Australian independent, reported finding gas at its test well drilled in the Matanuska Susitna Borough late last fall, although testing is now under way on possible production.

Nordaq Energy completed an exploration well on the Kenai Peninsula in April, and although results weren't announced the company said it is working on permits for surface facilities, a good sign.

Buccaneer Energy Ltd. is now completing its exploration well, also on the Kenai Peninsula. The well has encountered gas shows but whether these can be produced remains to be seen.

There are also plans for two jack-up rigs to be operating in deeper waters of Cook Inlet this summer. One rig is now being transported to the Inlet by Escopeta Oil and Gas, another independent.

Buccaneer Energy plans to bring a second, larger jack-up rig to the Inlet this summer.

Both companies own leases with prospects that will be tested by the two jack-up rigs.

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Reliance Debunks Claims on KG-D6 Output Decline

Reliance Debunks Claims on KG-D6 Output Decline

Monday, May 09, 2011
Asia Pulse Pte Ltd

India's Reliance Industries has debunked charges that KG-D6 gas field output fell due to non-drilling of an adequate number of wells, saying the phenomenon was a result of reservoir complexity and indiscriminate drilling would have lead to infructous capital expenditure.

The drop in production from over 61 million cubic meters per day achieved in March, 2010, to under 50 mmcmd was a result of the main reservoir channels not behaving in the manner predicted in 2006.

"Reliance has told us that pressure in wells has fallen rapidly and some wells haven shown early water ingress," an Oil Ministry official said. "They made a detailed presentation on the problems being faced at the field on May 2 and by the look of it, we feel there are some genuine reservoir issues."

More wells on the main channel area of the Dhirubhai-1 and 3 fields, the largest of the 18 gas finds in the block that were put into production in 2009, is unlikely to either raise production rate or recovery as they will drain the same resource, he said.

Reliance will identify disconnected gas volumes and drill wells on them, an exercise that will take 3-4 years.

It has drilled 20 out of the 22 wells committed in the field development plan (FDP) as it now feels that drilling of additional wells unmindful of the reservoir behavior would have resulted in huge capital expenditure which would have been difficult to justify later.

Oil regulator DGH is pushing for drilling of 11 committed wells by April 1, 2012, to raise output. Reliance wants UK's BP Plc to come on board first.

BP is buying 30 percent interest in KG-D6 and 22 other blocks for US$7.2 billion.

Once the government approves the stake buy, Reliance plans to sit with BP to come up with most optimal solution to the reservoir problem including drilling of additional wells.

Reliance is allowed to recover every penny spent on the field from sale of gas before profits are split with the government. Investment in injudicious additional wells would have led to a reduction in the government's petroleum profit.

Sitting in water depths of up to 1.2 kilometers, the KG-D6 is the first deepsea field in South Asia to go on production and there are no deepwater analogs available for reference on how the reservoir will behave.

As a result, Reliance had to depend on its own resources and some global industry consultants for the characterization, modelling and development of this complex deepwater reservoir system.

Current wells have no contribution from the areas outside the main channel area, contrary to what was predicted at the time of FDP in 2006.

(C) 2011 Asia Pulse Pte Ltd.

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BP Kicks Off Ugnu Test on North Slope

BP Kicks Off Ugnu Test on North Slope

Monday, May 09, 2011
Alaska Journal of Commerce
by Tim Bradner

BP has started up the first of four North Slope wells in a $100 million project to test heavy oil production technologies in the Ugnu formation.

The Ugnu is a large accumulation of heavy oil, with about 23 billion barrels of oil-in-place estimated, that overlies existing conventional oil fields on the North Slope. Ugnu oil was produced in am experimental test well drilled by BP two years ago, BP spokesman Steve Rinehart said.

The oil is thick and flows with difficulty. It measured 12 degrees API in the test well done by BP previously, Rinehart said.

API is an American Petroleum Institute index for oil quality.

Heavy oil from Ugnu is seen by BP and others as one of three unconventional sources of oil production that could supplement declining conventional oil production on the North Slope.

The others are production of viscous oil, also a lower quality oil that is about 19 degrees API and which lies in deeper formations than the shallow Ugnu accumulation. Viscous oil is being produced now.

A third potential type of unconventional oil that could be produced is shale oil production from the large layers of shale on the North Slope that are the source rocks for the conventional oil fields now producing. Independent oil and gas company Great Bear Petroleum will drill a well in 2012 to test whether shale can be produced from North Slope shale rock.

The major challenge in producing oil from Ugnu is the thickness of the oil and its temperature, which is about 70 degrees Fahrenheit in the shallow formation. The oil lies just below the permafrost that under the North Slope -- the wells will produce from depths of about 3,800 feet to 4,400 feet -- and the oil, thick and cool, will have be made to flow upward through the 2,000 feet of frozen permafrost to the surface.

Rinehart said BP will test two production procedures in its project. One is a technique called cold heavy oil production with sand, or CHOPS, that is now being used in Alberta to produce from oil sands. A second method involves producing the oil from horizontal production wells drilled laterally through the oil-bearing rock, a technique now common on the North Slope.

The first well, now producing about 350 barrels per day, is a horizontal well that was drilled 3,800 feet vertically and 3,500 horizontally, with 1,500 feet "perforated" for production, Rinehart said.

The second well is planned to begin production in May, he said. It will be a CHOPS well, Rinehart said, where a progressive cavity pump, an auger device, is installed in the well to create enough pressure to draw sand out of the formation to create fissures allowing the heavy oil to flow.

A progressive cavity pump also is installed in the horizontal well now producing to aid production, he said.

One of the problems in producing heavy oil, and also the somewhat higher-quality viscous oil, is sand that is produced up the well along with the crude oil. As oil is withdrawn from the weak rock that holds the heavy and viscous oil, sand is broken loose and flows with the oil into the well, where it can cause damage to the wells and the surface facilities that process the oil.

Companies producing viscous oil, including BP, have found ways to allow the sand to flow without causing damage, and to separate it from the oil at the surface.

In the heavy oil project a specially built processing facility separates and stores the sand until it can be trucked to an underground disposal well to inject the sand back underground.

Rinehart said the heavy oil also must be heated before it is pumped on by pipeline to Pump Station 1 of the Trans-Alaska Pipeline System, where it is mixed with other, conventional crude oil for shipment south.

"Our goal here is data collection, but we are also processing and selling the oil we produce," Rinehart said. The test production project is on S Pad in the Milne Point field.

"The project is going well so far. There is a lot of oil in place but there are a lot of production challenges. We need to ensure we can produce it on a sustainable basis. Once we understand the engineering and physics, we can have a conversation about the economics," Rinehart said.

BP's plan is for the test production program to be run for three to five years, Rinehart said. By then enough data will be in-hand to make a judgment on possible commercial production.

Copyright (c) 2011, Alaska Journal of Commerce, Anchorage. Distributed by McClatchy-Tribune Information Services.

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JX Nippon, Qatar Sign Gas Exploration Deal - Reports

JX Nippon, Qatar Sign Gas Exploration Deal - Reports

Monday, May 09, 2011
Deutsche Presse-Agentur (dpa)

Japan's JX Nippon Oil & Gas Exploration Corp. and state-operated Qatar Petroleum signed a 100-million-dollar exploration and production sharing agreement for a natural gas field off the emirate, news reports said Monday.

JX Nippon, a unit of JX Holdings Inc, reached the 30-year agreement Sunday with Qatar for production sharing at Block A, a 6,173-square-kilometer area near North Field, the world's biggest gas field, Jiji Press reported.

The field is estimated to have significantly large reserves, an unnamed official of Japan's Agency for Natural Resources and Energy was quoted by Jiji as saying. Production is expected to start around 2020 after five years of exploration and test drilling.

Industry Minister Banri Kaieda said in a statement that the latest deal would help Japan bolster its bilateral relations with Qatar and secure energy needed for its recovery from the March earthquake disaster, Jiji reported.

Demand for liquefied natural gas has risen in Japan following the March 11 earthquake and tsunami, which forced providers to take a number of nuclear power stations offline. The disaster crippled the Fukushima Daiichi nuclear plant and it has leaked radiation into the air and sea ever since.

Amid growing public concern about another nuclear accident and demands to review the country's nuclear energy policy, Prime Minister Naoto Kan urged utility provider Chubu Electric Power Co Friday to shut down all reactors at its Hamaoka nuclear station located near a geological fault line.

Copyright 2011 dpa Deutsche Presse-Agentur GmbH

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Study More Than Doubles B.C. Gas Resources Estimate

Study More Than Doubles B.C. Gas Resources Estimate

Monday, May 09, 2011
B.C. Ministry of Energy & Mines; NEB

A new joint report on the shale-gas potential of Northeastern B.C.'s Horn River Basin more than doubles a previous assessment of gas resources within the province.

The report released by the National Energy Board (NEB) and British Columbia Ministry of Energy and Mines (BC MEM) titled "Ultimate Potential for Unconventional Natural Gas in Northeastern British Columbia's Horn River Basin" is the first publicly released probability-based resource assessment of a Canadian shale basin.

The report says the ultimate potential for marketable unconventional shale gas in the Horn River Basin is 78 trillion cubic feet (Tcf), including three Tcf of discovered resources and 75 Tcf of undiscovered resources. The Horn River Basin is part of the larger Western Canada Sedimentary Basin.

"This innovative report on shale-gas resources provides Canadians with valuable information about our energy future, particularly as it relates to the Western Canada Sedimentary Basin," said Gaetan Caron, chair of the National Energy Board.

Energy and Mines Minister Rich Coleman said, "This report should provide residents of our province with a sense of optimism about the future. B.C. is recognized for its significant shale gas reservoirs as well as for having world-class regulations."

Placing the Horn River numbers in context, the NEB currently estimates that there is 197 Tcf of conventional and unconventional natural gas remaining in the WCSB -- although this number does not take into account known but as-yet-unassessed unconventional gas resources.

The estimate of total remaining conventional and unconventional natural gas in Northeast B.C available for future demand is 109 Tcf. That includes 78 Tcf of shale gas as well as 31 Tcf of remaining natural gas resources identified in a joint assessment of conventional natural gas resources in Northeast B.C. The conventional gas assessment was released by the NEB and B.C. Ministry of Energy and Mines in 2006.

According to the new report on unconventional gas resources, the medium-case estimate of 78 Tcf for Horn River shale gas is the most realistic scenario. However, the study produced a range of numbers for shale gas potential in the Horn River Basin with the low estimate being 61 Tcf and the high being 96 Tcf.


Remaining Ultimate Potential by Province (Tcf)

The NEB is an independent federal agency that regulates several parts of Canada's energy industry. Its purpose is to promote safety and security, environmental protection, and efficient energy infrastructure and markets in the Canadian public interest, within the mandate set by Parliament in the regulation of pipelines, energy development and trade.

The B.C. Ministry of Energy and Mines manages the responsible exploration and development of British Columbia's energy sector.

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Apache Keeps Blake Platform Rigs Busy

Apache Keeps Blake Platform Rigs Busy

Monday, May 09, 2011
Blake International

Blake International reports that the Blake Rig 210 has signed a contract with Apache Corporation for a two-well program with a one-well option. The work will take place on Apache's East Cameron 278 "B" platform. The rig is scheduled to load out on May 8th. Blake International's Rig 14 has also signed an extension with Apache Corporation, a two-platform, three-well program with work commencing at South Pass 62C and continuing at South Pass 62D.

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AGR Announces Two-year Contract with Statoil

AGR Announces Two-year Contract with Statoil

Monday, May 09, 2011
AGR Drilling Services

International energy company Statoil has signed a two year, NOK66m contract for the Riserless Mud Recovery system (RMR) from AGR Drilling Services.

Statoil is one of AGR's top customers and technology partners. AGR, which has its head office in Straume, Norway, has performed 33 RMR well installations since 2004 for Statoil.

RMR has been an industry changer since it was introduced. It enables engineered mud to be used in the top-hole section of a well, with all mud and cuttings being returned to the rig with zero discharge. The top-hole section can be drilled more safely, quickly and with far less impact on the environment.

This latest contract with Statoil also includes the continuation of CTS (Cutting Transportation System) operations on two rigs, with provision for AGR to be optional CTS supplier on a number of others. Statoil has used CTS, which takes cuttings up to 2km away from the well area, on 209 wells since 1998.

Johan Moller Warmedal, Executive Vice President of AGR Drilling Services, said: "It gives particular pleasure to land this agreement with such an important customer. I am delighted that Statoil has once again seen fit to use our innovative technology. The reputation of RMR continues to grow ever stronger globally and this latest show of confidence from Statoil is a credit to our dedicated, highly experienced team."

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Samson Issues Update on N.D. Wells

Samson Issues Update on N.D. Wells

Monday, May 09, 2011
Samson Oil & Gas Limited

Samson Oil & Gas Limited on Sunday advised that operations on the Earl #1-13H progressed to drilling out plugs 19 to plug 11. At this point the tubing string being used to drill the plugs parted at around 4,400 feet.

The top part of the tubing string was subsequently recovered and an operation to recover the balance of the tubing is underway. This has taken longer than anticipated because the drill pad had to be reinforced with gravel as a consequence of the spring thaw. In addition, unseasonal blizzard conditions have been experienced in North Dakota which shut down operations for a 48 hour period.

A rotating snubbing unit was mobilized to the well site the morning of Friday May 6th. This equipment will enable the parted tubing string to be rotated and pulled such that the drill string is successfully recovered. The rupture in the drill string is thought to have been caused by frac sand forming a bridge behind the drill bit. Once the string is rotated and fluid circulated, the string will be recovered.

Whilst these operations have been undertaken, the well continued to flow hydrocarbons and the rate in the 24 hours ending 0500 hours on May 6th was 749 BOPD, with rates observed up to 1296 BOPD.

EVERETT #1-15H (SSN Working Interest 31%)

The Everett #1-15H spudded on May 7th, and on May 8th was at a depth of 2,214 feet. The Everett well is designed as a 5,000 ft horizontal well in the Middle Bakken. It is to be completed using external casing packers and fracture stimulated in 20 stages.

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Petroamerica Confirms Significance of Balay-2 Well

Petroamerica Confirms Significance of Balay-2 Well

Monday, May 09, 2011
Petroamerica Oil Corp.

Petroamerica Oil Corp. is pleased to announce that the Balay-2 ST1 appraisal well flowed from two perforated intervals in the Upper Mirador, 2,620 barrels of 26 degree API oil per day with 9.3% bulk sediment and water ("BS&W") that is probably mainly completion fluid, under electro-submersible pump. The Balay-2 ST1 well also defined a deeper oil-down-to in the Upper Mirador reservoir. Additionally, 145 barrels of heavy oil (13 degree API, waiting on laboratory confirmation) and water (10-16% BS&W) was recovered from the Barco Formation. No hydrocarbons were recovered from tests carried out in the Une and Gacheta reservoirs.

Nelson Navarrete, President and CEO, commented on the Balay-2 ST1 drilling result, "this is significant in terms of proving up recoverable oil volumes in the Balay structure, and more importantly, moving the project one step closer towards a commercial development."

The Balay discovery was announced on March 11, 2010 and the Balay-1 discovery well has been on long-term production test since July 14, 2010, producing more than 285,000 barrels of 28 degree API oil from the Upper Mirador Formation, with no measurable water (0.22% BS&W). The forward plan is to put the Balay-2 ST1 well on long-term test together with the Balay-1 well. A third well, Balay-3, is planned for the fourth quarter 2011 to appraise the northern extent of the Balay discovery.

Petroamerica Oil Corp., through its wholly owned subsidiary, Petroamerica International Corp., holds a 15% participating interest in the Balay block for which it received its approval from the ANH (Colombian National Hydrocarbon Agency) earlier this year. Petrobras is the operator with a 45% participating interest and the other partners are CEPSA COLOMBIA S.A. and Sorgenia, each holding a 30% and 10% participating interest, respectively.

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EFC Reports US Order Growth

EFC Reports US Order Growth

Monday, May 09, 2011
EFC Group

Headquartered in Aberdeen, Scotland, EFC Group announced significant order growth for its Houston office and US-based manufacturing capabilities.

The Americas region of EFC Group, a leading designer and manufacturer of Handling, Control, Instrumentation, and Monitoring Systems for the global oil and gas industry, also announced several major new US contracts, taking its Hydraulic Controls Division over the $1 million USD [approx GBP600,000] mark in 2011 to date.

EFC Group general manager Americas, Mike Coady said: "Our Houston-based staff and contractor numbers have doubled in the last six months to meet local manufacturing demand.

"With the launch of EFC Group Hydraulic Control and Test Panel product line, the Americas team has recently secured contracts totaling over $1million USD. Most notably a contract award for six trailer mounted systems for a global pressure control company."

Ocean Rig has placed a further significant contract for its four ultra-deep waters high-specification drill ships, 12 hotline test panels have been procured, the first three have been delivered onboard the Ocean Corcovado.

Terry Wise, Ocean Rig Subsea Project Engineer commented "EFC quickly customized a neat solution providing the exact regulated lines for our testing needs. We will continue to work with EFC for future control and instrumentation systems."

EFC is predicting 60% international growth over the next two years, with a strong focus on the US market.

EFC showcased its latest hydraulic product launch, the high pressure 15Kpsi BOP Test unit during its OTC Open House. The BOP Test Unit answers the increasing industry need for frequent testing whilst reducing operational downtime.

Mike continues: "With North and South America and Gulf of Mexico sectors accounting for more than 30% of our international business, the US market is extremely important to us and is supported by our growing Houston team. We are continuing to develop our reputation as a specialist supplier of tailored mechnanical handling, well control, BOP control and marine instrumentation system solutions to the global oil and gas industry."

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Minor to Lead Ops at Far East Energy

Minor to Lead Ops at Far East Energy

Monday, May 09, 2011
Far East Energy Corp.

Far East Energy Corp. announced Monday that the Company welcomes David J. Minor as Executive Director of Operations reporting directly to Michael R. McElwrath, CEO and President.

"We are very pleased to have Dave Minor join our team," said Michael McElwrath. He continued, "With his excellent credentials, Dave brings extensive coalbed methane experience to the table, with direct and comprehensive involvement in Alabama's Black Warrior Basin. As we move into the development stage of our operations at Shouyang, it is appropriate that we add advanced skill sets to our management capacity and Dave certainly advances our collective competencies for our CBM projects in China."

In his role as Executive Director of Operations for the Company, Minor will utilize his expertise to provide guidance and advice on all operational aspects of its Coalbed Methane Projects in China. His near term goals are to implement a series of operations objectives aimed at increasing the CBM production for currently existing wells and maximizing production for newly drilled wells.

With over thirty years of engineering and management experience, including project planning, drilling, completion and production, Minor has spent the majority of his career in management and technical supervisory roles; and most recently, a transition role as President and General Manager of Walter Black Warrior Basin LLC, a Walter Energy subsidiary, operator of approximately 1,400 coalbed methane wells in Alabama's Black Warrior Basin.

Minor served as Chairman of the Coalbed Methane Association of Alabama (CMAA) from 1996-1997 and again from 1999-2002. He has also served on the Environmental, Tax and Safety Committees. Minor is a member of the Society of Petroleum Engineers and served on numerous Committees. Other professional affiliations include the National Society of Professional Engineers, The University of Alabama Capstone Engineering Society, and The Order of the Engineer. He is a Registered Professional Engineer in Alabama, Mississippi, Oklahoma, Arkansas and Texas. Minor graduated from the University of Alabama with a BS Biology; a BS Civil Engineering; and, a MS Mineral Engineering (Petroleum).

"We look forward to the technical focus that Dave will bring to Far East," said Donald A. Juckett, Chairman of Far East. "We anticipate excellent results from his tenure at Far East as he brings a wide range of technical experience to bear on the exciting Shouyang Block."

Based in Houston, Texas, with offices in Beijing, Kunming, and Taiyuan City, China, Far East Energy Corp. is focused on coalbed methane exploration and development in China.

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Tethys Petroleum: Kazakhstan Operations Update

Tethys Petroleum: Kazakhstan Operations Update

Monday, May 09, 2011
Tethys Petroleum Limited

Tethys Petroleum Limited today provided an update on the progress in its Kazakhstan oil appraisal and exploration activities.

The AKD04 (Dero) appraisal well has now reached total depth of 2,566 metres and electric logging has been carried out. This well is located on the separate Dero part of the structure to the east of the AKD01 Doris oil discovery and was designed to ascertain the potential in the Upper Jurassic carbonate zone and the edge of the Lower Cretaceous (Aptian) sandstone in this area. Interpretation of the well data shows both the Jurassic carbonate and the Aptian sand to be present in the well with both showing indications of hydrocarbons. These two horizons were the zones that tested oil in the AKD01 well. Preparations are currently being made to run casing which will be followed by an appropriate testing programme - following receipt of the usual consents from Kazakh authorities.

In the AKD05 Doris appraisal well, the 9 5/8" casing has been set and it is drilling ahead. This well is currently on prognosis and should reach planned total depth of 2,500 metres by the end of this month.

Further evaluation of the recently acquired 3D seismic dataset using state of the art processing and interpretation techniques is revealing the probable presence of sand fans in the Cretaceous sandstone sequence and these data are being integrated with the results of the well data to plan future appraisal well locations in the greater Doris area.

Testing of the AKD03 (Dione) exploration well continues after the successful test of a new sandstone zone in the Upper Jurassic, which flowed dry oil at over 400 barrels per day. The company believes that a significantly higher flow rate may be achieved with a horizontal or high angle completion, and will determine optimised well designs as part of the overall development plan following completion of the appraisal and exploration programme. The overlying Upper Jurassic carbonate has now been tested but no commercial oil flow was obtained. Testing will now be undertaken on the good quality potentially oil-bearing Cretaceous sandstone interval (which is similar to the main reservoir zone in the AKD01 well) and which shows the best reservoir properties of the zones being tested. The extent and potential of this Dione flank structure is currently being evaluated using the new 3D seismic dataset.

The KBD01 (Kalypso) wildcat exploration well is currently drilling at a depth of 2,498 metres. This well is being drilled on a large structure some 50 km to the north west of the Doris discovery with its primary target being at approximately 4,000 metres and with secondary targets above this. Seismic shows this prospect to have up to 400 metres of potential vertical closure. Hydrocarbon shows have been observed in the drilled section. It is expected that this well will reach total depth in July 2011.

Tethys is focused on oil and gas exploration and production activities in Central Asia with activities currently in the Republics of Tajikistan, Kazakhstan and Uzbekistan. This highly prolific oil and gas area is rapidly developing and Tethys believes that significant potential exists in both exploration and in discovered deposits.

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McDermott Board Appoints Johnson Chairman

McDermott Board Appoints Johnson Chairman

Monday, May 09, 2011
McDermott International, Inc.

McDermott International, Inc. announced Monday the results of its 2011 Annual Meeting of Stockholders, held Friday afternoon, May 6, 2011 in Panama City, Panama.

Based on the voting results from the meeting, shareholders re-elected Messrs. John F. Bookout, III, Roger A. Brown, Stephen G. Hanks, D. Bradley McWilliams, Thomas C. Schievelbein and David A. Trice, and elected Stephen M. Johnson and Mary L. Shafer-Malicki to our Board of Directors, all for one-year terms. In addition, shareholders approved the advisory vote on executive compensation, voted on an advisory basis for the Company to hold the advisory vote on the frequency of executive compensation annually, approved the Company's Executive Incentive Compensation Plan for tax deductibility reasons and ratified the appointment of Deloitte & Touche LLP as our independent registered public accounting firm for the year ending December 31, 2011.

As previously disclosed and pursuant to the Company's By-Law requirements, Ronald C. Cambre retired from McDermott's Board of Directors after 11 years of service to the Company, including the last three years as non-executive Chairman. His retirement was effective coincident with the adjournment of the Board of Directors meeting held in connection with the Annual Meeting. Additionally, McDermott announced that the Board of Directors has appointed Stephen M. Johnson as Chairman of the Board and D. Bradley McWilliams as Lead Director of the Board effective coincident with the adjournment of the Board of Directors meeting held in connection with the Annual Meeting.

"On behalf of the Board of Directors, our shareholders and the management team, I want to express our deep gratitude to Ron for his dedicated service to McDermott," said Stephen M. Johnson, McDermott's Chairman of the Board of Directors, President and Chief Executive Officer. "As Chairman, Ron has served the McDermott shareholders in an exemplary fashion and he has selflessly served as a skilled mentor for me. Additionally, I am honored and humbled from the confidence the Board has placed in me as Chairman and I look forward to working closely with the Board and with Brad McWilliams as Lead Director as we prepare McDermott for our next phase of growth."

McDermott is a leading engineering, procurement, construction and installation ("EPCI") company focused on executing complex offshore oil and gas projects worldwide. Providing fully integrated EPCI services for upstream field developments, the Company delivers fixed and floating production facilities, pipelines and subsea systems from concept to commissioning. McDermott's customers include national and major energy companies. Operating in approximately 20 countries across the Atlantic, Middle East and Asia Pacific, the Company's integrated resources include more than 15,000 employees and a diversified fleet of marine vessels, fabrication facilities and engineering offices. McDermott has served the energy industry since 1923.

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Petrobras Contracts Deepsea Metro II

Petrobras Contracts Deepsea Metro II

Monday, May 09, 2011
Odfjell Offshore Ltd.

Deep Sea Metro Ltd. has secured a contract with Petrobras for its second drillship; the Deepsea Metro II.

The contract with Petrobras has a firm duration of 3 years and the value, including part of potential bonus and mobilization fee, is approximately USD 531 million.

Deepsea Metro II will be operating in ultra deep waters offshore Brazil from the end of Q4 2011.

Deepsea Metro II is the second of two ultra deepwater drillships under construction by Deep Sea Metro Ltd., and is scheduled for delivery from Hyundai Heavy Industries (HHI) ultimo November 2011. The Deepsea Metro I has recently secured a deepwater drilling contract with the BG Group and is expected to be delivered from HHI on 31 May 2011.

The Metrostar Group retains 60 percent ownership in Deepsea Metro I & II and Odfjell Drilling Ltd has a 40 percent ownership, which is in the process of being transferred from Odfjell Drilling Ltd to Odfjell Offshore Ltd.

Odfjell Drilling Ltd is responsible for the construction follow-up, management and operation of the vessels.

Chairman of the Board in Odfjell Offshore Ltd., Simen Lieungh, says:

"To enter the deepwater market offshore Brazil has always been part of our long term strategy with Deep Sea Metro Ltd., and with the award of this contract to Deepsea Metro II, we have achieved it. We have now secured contracts for all our deepwater newbuild units and we look forward to the operations ahead."

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Quicksilver Resources Reported Mixed Q1 Results, Top Line Down 4.5%

Quicksilver Resources Reported Mixed Q1 Results, Top Line Down 4.5%



May 9, 2011

Quicksilver Resources (NYSE:KWK) reported Q1 EPS of $0.02, ex-items, missing consensus estimates of $0.03 per share. Revenues for the quarter fell 4.5% year-over-year to $212.2 million, topping consensus estimates of $193.9 million.

Glenn Darden, Quicksilver president and chief executive officer said, "Our base operations continued to improve as production volumes once again set new records while we remained focused on our all-in unit cost structure, which declined 2% versus the prior year. Concurrently, we built the largest inventory of new projects in our company's history. Quicksilver has assembled meaningful acreage positions in four developing oil plays and three natural gas plays, where Quicksilver can use its expertise in unconventional resource development to cost-effectively grow our reserve base and production. We are actively pursuing these new projects, with initial results expected later this year."

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Atwood Clutches BHP Contract

Atwood Clutches BHP Contract

Monday, May 09, 2011
Atwood Oceanics, Inc.

Atwood Oceanics, Inc., a Houston-based international offshore drilling contractor, announced that one of its subsidiaries has been awarded a one well contract by BHP Billiton Petroleum PTY LTD, with an estimated duration of 45 days in a water depth of 600 feet.

The day rate for this contract for the first 40 days will be approximately $376,000; thereafter the day rate will increase to approximately $399,000 (both day rates subject to change due to currency exchange provisions in the contract).

With this contract, the firm contractual commitments for the Atwood Eagle will extend through approximately January 2012.

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FX, American Eagle to Explore Alberta Bakken in NW Montana

FX, American Eagle to Explore Alberta Bakken in NW Montana

Monday, May 09, 2011
FX Energy, Inc.

FX Energy, Inc. on Monday announced the signing of an agreement with American Eagle Energy, Inc., and Big Sky Operating LLC, to jointly explore approximately 75,000 acres in the Alberta Bakken in Northwest Montana. FX Energy's 10,000 acre field in the Southwest Cut Bank Sand Unit will be included in the joint exploration program and the Company will own a one-third interest in the overall project.

The companies plan to drill a minimum of three vertical wells to evaluate the potential of the acreage over the next several months. If the tests confirm the potential that the companies believe exists in the project area, the wells will be drilled horizontally and fracked. The drilling contractor for the wells will be the Company's wholly owned subsidiary FX Drilling Company.

"Since our partners were among the first movers in the Williston Basin Bakken play, their technical expertise is a valuable addition to the joint venture. We expect to drill and test several wells this year and if successful, our acreage position is sufficiently large to accommodate a continuous drilling program for years to come," said Andy Pierce VP of Operations for FX Energy.

FX Energy is an independent oil and gas exploration and production company with production in the US and Poland. The Company's main exploration activity is focused on Poland's Permian Basin where the gas-bearing Rotliegend sandstone is a direct analog to the Southern Gas Basin offshore England.

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Technip Wins Vigdis NE Subsea Contract

Technip Wins Vigdis NE Subsea Contract

Monday, May 09, 2011
Technip

Technip has been awarded by Statoil a contract, worth approximately EUR55 million, for the Vigdis NE field development located in the Norwegian Sea at a water depth of 220 - 310 meters.

This contract covers:
  • welding and installation of flowlines, including a 1.5 kilometer pipe-in-pipe production flowline and a 9 kilometer plastic-lined water injection flowline,
  • supply of flexible tails for the flowlines,
  • subsea equipment installation,
  • installation and tie-ins of flowlines flexible tails, jumpers and umbilicals.

Technip's operating center in Oslo, Norway will execute the contract. Flowline welding will take place in the Group's spoolbase in Orkanger, Norway, while flowline installation will be performed with the Apache II, a pipelay vessel from Technip fleet, in mid-2012.

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Linn to Acquire Texas Panhandle, Okla. Properties for $220M

Linn to Acquire Texas Panhandle, Okla. Properties for $220M

Monday, May 09, 2011
LINN Energy, LLC

LINN Energy, LLC announced Monday that it signed a definitive purchase agreement with Panther Energy Company, LLC and Red Willow Mid-Continent, LLC to acquire 40 percent of their oil and natural gas properties located in Ochiltree and Lipscomb counties, Texas and Ellis County, Oklahoma for a contract price of $220 million, subject to closing conditions. The Company anticipates the acquisition will close on or before June 1, 2011, and will be financed with net proceeds from the recently announced senior notes offering.

"The acquisition of these properties enhances LINN's overall position in the Texas Panhandle area, and marks our entry into the liquids-rich window of the horizontal Cleveland play in the Anadarko Basin," said Mark E. Ellis, President and Chief Executive Officer of LINN Energy. "Partnering with Panther will align us with an experienced and efficient operator that has been active and successful in this area for several years. This acquisition provides high rate-of-return projects and we expect it to be immediately accretive to our unitholders."

Bob Zahradnik, Chairman of Panther Energy, added, "We have created significant value in the Anadarko Basin, and we look forward to developing this area with a solid partner like LINN Energy. This divestiture is a tactical transaction to fund the substantial capital demands of our successful programs in the deepwater Gulf of Mexico and West Texas."

Significant characteristics of the assets are:
  • Net production of approximately 2,700 barrels of oil equivalent per day from approximately 170 producing wells;
  • Proved reserves of approximately 10 million barrels of oil equivalent (45 percent oil, 37 percent proved developed);
  • Total acreage position of 140,000 gross (44,000 net) acres; and
  • More than 165 proved low-risk infill drilling locations.

LINN Energy's mission is to acquire, develop and maximize cash flow from a growing portfolio of long-life oil and natural gas assets. LINN Energy is a top-20 U.S. independent oil and natural gas development company, with approximately 2.8 Tcfe of proved reserves in producing U.S. basins as of Dec. 31, 2010 (pro forma for pending and closed 2011 acquisitions).

The Southern Ute Growth Fund is the majority owner and funding partner of Panther Energy, LLC and the parent company of Red Willow. Panther and Red Willow have E&P and midstream operations throughout the Rockies, Mid-Continent, Permian Basin, West Texas and the Gulf of Mexico. The Growth Fund oversees the business of the Southern Ute Indian Tribe.

Scotia Waterous (USA) acted as financial advisor to Panther Energy Company, LLC and Red Willow Mid-Continent, LLC in this transaction.

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