Russia Can Double Oil Reserves By Tapping Arctic Potential -Lukoil Exec.

- Russia Can Double Oil Reserves By Tapping Arctic Potential -Lukoil Exec.

Wednesday, September 07, 2011
Dow Jones Newswires
SINGAPORE
by Max Lin

Russia can double its oil reserves if the government is determined to exploit the potential in the Arctic, a senior Lukoil Holdings executive said Wednesday.

"The development of Arctic fields needs political will and support from the government," Sergey Chaplygin, chief executive of Lukoil International Trading and Supply Co. said, but didn't elaborate. Lukoil is the country's biggest private oil producer.

Russia, the world's top oil and gas producer, has proven oil reserves of around 60 billion barrels, Energy Information Administration data showed.

Lukoil plans to explore oil production in the Russian Arctic with state oil company Rosneft under a new long-term cooperation agreement that takes effect this month.

Rosneft will also explore in the Arctic area with U.S. energy giant ExxonMobil, in a separate deal.

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

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BP Unleashes Additional Reserves at Mad Dog Field

- BP Unleashes Additional Reserves at Mad Dog Field

Wednesday, September 07, 2011
BP plc

BP announced the drilling of a successful appraisal well in a previously untested northern segment of the Mad Dog field in the US Gulf of Mexico.

The well results confirm a significant resource extension for the Mad Dog Field complex, which includes the existing field, in production since 2005, and appraisal drilling of the Mad Dog South field in 2008 and 2009. Pending confirmation through future appraisal drilling, the total hydrocarbons initially in place in the Mad Dog field complex are now estimated to be up to four billion barrels of oil equivalent.

The well, drilled by BHP Billiton on behalf of the unit operator BP, is located on Gulf of Mexico Green Canyon block 738 approximately 140 miles (225 kilometers) south of Grand Isle, LA., in about 4,500 feet (1,371 meters) of water. The well encountered about 166 net feet (50 meters) of hydrocarbons in the objective Miocene hydrocarbon-bearing sands and discovered an oil column of more than 300 feet (91 meters). Transocean's semisub GSF Development Driller I was used to drill the Mad Dog well.

"With these additional hydrocarbon resources north of the main field, Mad Dog has been firmly established as a giant field in BP's Gulf of Mexico portfolio, rivaling Thunder Horse in size of resource," said Bob Dudley, BP group chief executive. "Working with the industry and regulators, we will apply our enhanced standards of safety, reliability and compliance to all of our Gulf activities as we continue to provide important jobs and energy to the nation."

BP maintains a 60.5 percent working interest in Mad Dog. BHP Billiton has a 23.9 percent interest, Chevron Corporation, through its subsidiary Union Oil Company of California, has a 15.6 percent interest.

Due to the materiality of the Mad Dog South finds in 2009, BP has been advancing development options to increase production from Mad Dog by adding another spar production facility with a production capacity of 120,000–140,000 barrels of oil equivalent per day (boed).

"Coupled with the recent exploration success at the discovery at the Moccasin prospect, located in Keathley Canyon, the Mad Dog result re-emphasizes the exploration and development potential of the Gulf of Mexico and the region’s ability to continue to deliver material projects for BP," Dudley added.

On Sept. 6, 2011 Chevron Corporation announced the Moccasin discovery in the Lower Tertiary play on Keathley Canyon block 736. BP has a 43.75 percent working interest in the Moccasin prospect. The prospect is operated by Chevron U.S.A. Inc., also with a 43.75 percent interest, and the co-owner is Samson Offshore Company with 12.5 percent interest.

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Legacy Reserves Enters Equity Distribution Agreement for Up to $60 Million In Units

- Legacy Reserves Enters Equity Distribution Agreement for Up to $60 Million In Units



Aug 25, 2011

Legacy Reserves (NASDAQ:LGCY) entered into an Equity Distribution Agreement with Knight Capital Americas. Pursuant to the terms of the Agreement, the Partnership may sell from time to time through Knight, as the Partnership's sales agent, the Partnership's common units representing limited partner interests having an aggregate offering of up to $60 million.

Sales of the units, if any, will be made by means of ordinary brokers' transactions on the Nasdaq Global Select Market at market prices, in block transactions or as otherwise agreed by the Partnership and Knight.

Legacy Reserves (NASDAQ:LGCY) has a potential upside of 27.5% based on a current price of $26.68 and an average consensus analyst price target of $34.

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Brazil's Pre-Salt Reserves to Boost Latin American Oil Production Growth

- Brazil's Pre-Salt Reserves to Boost Latin American Oil Production Growth

Friday, August 19, 2011
Rigzone Staff
by Karen Boman

Brazilian state energy company Petrobras' plans to develop its offshore pre-salt oil reserves will contribute in part to what Barclays Capital calls a "sizable upward shift" in hydrocarbons production through 2011 through 2020, according to Barclays' Global Energy Outlook. Brazil and Colombia are expected to experience increases hydrocarbons production during that time period, most concentrated in oil versus natural gas, Barclays noted.

Petrobras has unveiled plans to spend US $127.5 billion, or 57 percent of the resources under Petrobras' 2011-2015 Business Plan of US $224.7 billion, on exploration and production efforts. The company plans to increase total oil and gas output from 2.7 million boe/d in Brazil and abroad to 4 million in 2015 and 6.4 million in 2020.

Pre-salt output alone will add up to nearly 2 million boe/d in 2020, pushing the pre-salt's contribution to production from two percent today to 18 percent in 2015 and 40.5 percent by 2020. Petrobras will achieve this growth by setting up 30 extended well tests over the next five years, including 20 in the pre-salt cluster, and 10 in the post-salt area. Additionally, the company will spend US $1.3 billion per year on technology, which will include funding for efforts explore new frontiers, oil recovery and develop a new generation of offshore and undersea production systems.

Petrobras last month also confirmed the commercial potential of its Lula discovery in the pre-salt Santos Basin in water depths ranging from 6,890 feet to 7, 218 feet. Lula produced 28,436 b/d, according to Subsea IQ, and is the first well to produce from Brazil's high touted pre-salt offshore reserves. The well is interconnected to Cidade de Angra dos Reis FPSO and is the first of six production wells to be connected to the FPSO. Petrobras expects for the FPSO to produce around 100,000 b/d d throughout 2012.

Other companies are seeing significant potential in Brazil's pre-salt area. BG Group in June upgraded its estimate of its pre-salt Santos Basin interests to some 6 billion Boe net to BG Group with an upside potential of 8 billion BOE net. The new estimates results from the company's internal analysis of data gathered from drilling, appraisal and other data, including data collected from 29 wells drilled in BG's existing discoveries.

"Robust economics and solid progress with the fast-track development program will see gross installed production capacity rising steadily to reach more than 2.3 million boe per day by 2017," said BG Group Chief Executive Sir Frank Chapman.

Other companies active offshore Brazil include OGX, which has identified the presence of hydrocarbons in the Santonian section of well 1-OGX-47-RJS in the BM-S-59 block in the shallow waters of the Santos Basin, according to Subsea IQ. The operator found a hydrocarbon column of about 430 feet in sandstone reservoirs of the Santonian section with about 167 feet of net pay. The OGX-47 well, named Maceio, lies about 68 miles off the coast of Rio de Janeiro in a water depth of 607 feet. The Ocean Quest semisub drilled the well.

Chevron reported last month that it plans to drill a well later this year in the pre-salt section beneath its Frade field offshore Brazil. The company will drill the well using Transocean semisubmersible Sedco 706, according to RigLogix. "If successful, we'll be in a great position to take advantage of our existing production facilities," said George Kirkland, vice chairman and EVP of Global Upstream and Gas at Chevron.

Petrobras' ambitious drilling plans include constructing newbuild rigs within Brazil; these plans make it likely that service companies will beef up investments in Brazil to meet their customers' needs. National Oilwell Varco (NOV) this week signed contracts to supply drilling equipment packages for seven drillships to Estaleiro Atlantico Sul, 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, said the company is investing heavily in Brazil to manufacture more of the products and technologies National Oilwell Varco provides to its oil and gas customers, and to service the rapidly growing installed base of NOV drilling equipment in the region.

Sedco 706

The significant distance at which pre-salt reserves lie offshore Brazil means that operators will likely continue to favor floating production systems as field development solutions. Brazilian waters will be the most active region for future floating production projects, with 50 potential floater projects in the planning cycle, according to a recent report by International Maritime Associates Inc. Of the 50 potential projects, 26 are planned for ultra-deepwater, or water depths greater than 4,921 feet; five are planned for deepwater, or water depths between 3,280 feet and 4,921 feet, and 19 for water depths less than 3,280 feet.

Keppel Shipyard is on track to complete the modification and upgrade of FPSO OSX-1, the first floating production storage and offloading FPSO unit for OSX Brazil S.A. Chartered to OGX Petroleo e Gas Participacoes S.A., the FPSO will be deployed in the Waimea field in the Campos Basin offshore Brazil. The FPSO is expected to leave Keppel in this year's third quarter; production is expected to begin in this year's last quarter at a rate of up to 20,000 b/d from the OGX-26 well.

OGX in June unveiled its business plan related to discoveries in the Campos and Parnaibas basins. Waimea and the Waikiki production is expected to begin in the fourth quarter of 2013. In 2013, the company expects to have three Floating Production Storage Offloading FPSOs (OSX-1, OSX-2 and OSX-3) and two Wellhead Platforms "WHPs" (WHP-1 and WHP-2) in place with a total of ten horizontal production wells onstream in these two projects. OGX expects to achieve 150,000 b/d of production from the Campos Basin in 2013 in these two production complexes from 10 horizontal wells producing an average of 15,000 b/d each.

The gas production ramp-up in the Parnaíba Basin is expected to begin in the second half of 2012. OGX has one project covering two accumulations in the PN-T-68 block, which is 46.7% owned by OGX, and is expected to achieve gross production of 5.7 million m3 of natural gas per day (approximately 200 MMcf/d), or approximately 36,000 BOE/d in 2013 (approximately 15,000 BOE/d net to OGX).

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Origin Boosts Total 2P Reserves by 13%

- Origin Boosts Total 2P Reserves by 13%

Friday, July 29, 2011
Origin Energy Ltd.

Origin announced record annual production and sales revenues for its Exploration and Production business, released in the company's Production Report for the quarter to June 30, 2011.

This follows the release yesterday of Origin's 2011 Annual Reserves Report, in which the company announced a 13 percent annual increase in total Proved plus Probable (2P) reserves.

Origin Executive Director, Finance and Strategy, Ms. Karen Moses, said, "The Exploration and Production business has delivered record annual production of 135 Petajoules equivalent (PJe), up 30 percent on the prior year. Sales revenues also increased to a record $835 million, an increase of 32 percent on the prior year.

"The strong performance was driven by a 36 percent increase in production from Australia Pacific LNG as gas was supplied into major new contracts, higher production from Origin's increased share of Otway, a full year's contribution from Kupe and higher production from BassGas after an extended shutdown in 2009/2010.

"Notably, the record increases were achieved amid a challenging operating environment with extreme weather conditions impacting a number of our assets.

"Origin also reported a 13 percent annual increase in 2P reserves to 7,041 PJe, driven by increases in our CSG reserves held through Australia Pacific LNG and in the Ironbark area," Ms. Moses said.

During the year, Australia Pacific LNG made significant progress on its CSG to LNG project, culminating with a Final Investment Decision announced on July 28, 2011. The decision initiates development of the first LNG train and infrastructure to support a second train, and is underpinned by a sale and purchase agreement with Sinopec for the supply of 4.3 million tonnes per annum of LNG. Sinopec has also subscribed for a 15% equity interest in Australia Pacific LNG1.

"The Final Investment Decision on the first phase of the Australia Pacific LNG project marks the commencement of one of Australia’s largest LNG export projects," Ms. Moses said.

"Australia Pacific LNG holds Australia's largest 2P CSG reserves, including extensive acreage within the premier production fairways providing high quality gas resources with high deliverability," Ms. Moses said.

Production for the quarter to 30 June 2011 was 37 PJe, or 23 percent, higher than the June Quarter in 2010, with all asset areas either increasing production or maintaining production at comparable levels. Most notably, Otway increased production by 49 percent. Total sales volumes and revenues increased by 8 percent and 11 percent respectively.

Compared with the March Quarter 2011, production was 28 percent higher, as Otway returned to higher production levels and CSG and Cooper Basin production increased after the floods experienced earlier in the year. Sales volumes and revenues were 19 percent and 14 percent higher respectively, reflecting the increased production.

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Northern Notes Reserves at Southern Adriatic Permits

- Northern Notes Reserves at Southern Adriatic Permits

Thursday, July 28, 2011
Northern Petroleum plc

Northern announced an update on its Southern Adriatic permits containing the Rovesti and Giove oil discoveries, which hold a combined 53.2 million barrels of 2P reserves.

Highlights:

• Approval of increase in work program on each of Southern Adriatic permits F.R39 .NPand F.R40.NP to include 3D seismic of up to a maximum of 600 sqkm by Ministry of Economic Development;
• Contract signed for a 2D seismic survey over permits F.R39.NP and F.R40.NP, with survey scheduled to commence in late Q3 / early 4Q 2011 to assist with de-risking of significant exploration prospects; and
• Planning for two 3D seismic surveys scheduled for 4Q 2011 will now intensify, targeting the Rovesti and Giove oil discoveries and a significant exploration prospect within theF.R39.NP and F.R40.NP permits.

Northern has been advised by the Ministry of Economic Development (the "Ministry") that it has approved an increase in the work programs for permits F.R39.NP and F.R40.NP from 300km of 2D seismic to include in addition up to a maximum of 600 sqkm of 3D seismic acquisition on each permit.

The first operation to be conducted under this enhanced work program will be the acquisition of 2D seismic, which Northern has just contracted CGG Veritas Service SA ("CGG Veritas") to undertake. This survey is planned to enable the de-risking of several exploration prospects within the two permits, and compliment the planned 3D seismic acquisition focused on the Rovesti and Giove oil discoveries. Subject to receipt of necessary approvals, the CGG Veritas 2D survey is scheduled to commence in late 3Q/early 4Q 2011.

The Ministry approval allows us to now intensify our planning of the next phase of work on these permits. A 3D seismic survey is scheduled, subject to receipt of necessary approvals, for 4Q 2011 to cover the Rovesti and Giove oil discoveries and is also aimed at the de-risking of one significant prospect within the F.R39.NP and F.R40.NP permits. This 3D seismic acquisition, and the processing of the resultant data, will be the first activity funded entirely by Azimuth Limited ("Azimuth"), a specialist global E&P business, under the terms of the agreement first announced on March 25, 2011.

The Giove and Rovesti oil fields have previously been independently assessed by Blackwatch Petroleum Services to have 53.2 million barrels of 2P oil reserves. In addition, as a result of work undertaken to date, Northern recognizes the potential both for oil prospects with a mean of over 3 billion barrels of oil in place and gas prospects with a mean of over 2 Tcf of gas in place, which is over 1 billion barrels oil equivalent of prospective resource in the two permits, split approximately equally between oil and gas prospects.

Derek Musgrove, Managing Director of Northern, commented, "Exploration of the Southern Adriatic area is a major priority for Northern, so I am delighted to be able to report greater visibility on our forward plans as a consequence of the approval of our enhanced work programs for the F.R39.NP and F.R40.NP permits. CGG Veritas should be commencing a 2D surveying late 3Q/ early 4Q, and we look forward to also firming up the 3D surveys, the first activities with our new partner, Azimuth, within our 2011 program.

"I further note the recent offshore permit award announced by ADX Energy, which after a twelve month hiatus I am hopeful is a positive sign of the start of the award of new offshore permits to both Northern and other applicants."

Aaron D'Este, CEO of Azimuth, commented, "Receiving Ministry approval for the enhanced work program is excellent news. We already know that there is an active petroleum system in the Adriatic basin and 3D seismic is the natural next step to highlight commercial accumulations. Working closely with our partner, we will complete the planned surveys as quickly and safely as possible, and then move on to defining drillable targets early in the New Year."

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AWE Updates 2P Reserves at Tui Area Oil Fields

- AWE Updates 2P Reserves at Tui Area Oil Fields

Monday, July 25, 2011
New Zealand O&G Ltd.

AWE, as Operator of the Tui Joint Venture, has advised that preliminary work completed on the Tui Area Oil Fields indicates that the gross initial developed 2P reserves recoverable from the existing four well development of the fields will be reduced from the previously reported 50.5 million barrels to between 40 and 42 million barrels. This would leave gross remaining developed 2P reserves as at June 30, 2011 of between 9 and 11 million barrels and would represent a reduction of between 1.1 to 1.3 million barrels net to NZOG. An independent review of the reserves estimate is being undertaken by RPS Energy Pty Ltd (RPS). The RPS review is anticipated by AWE to be completed in early August 2011. A finalized 2P reserves estimate will be advised after the Joint Venture and RPS review has been completed.

AWE's evaluation has also identified possible additional volumes of oil not accessed by the current production wells in the Tui fields. To recover this oil additional wells or side tracks of existing wells will be required. Further work is being progressed that may mature these opportunities into a firm project that would add back a portion of the reserves reduction.

The revised 2P reserves estimate indicates an economic cut‐off for production in the 2019 to 2020 period based on operating costs for the FPSO Umuroa, the oil price forecast at that time, and no future infill drilling or exploration drilling success.

Concurrently, reprocessing and reinterpretation of the Tui 3D seismic undertaken by AWE has identified exploration prospects adjacent to the Tui fields which are under ongoing evaluation.

Participating interests in the Tui Joint Venture are:

• AWE Limited (Operator) 42.5%
• Mitsui E&P Australia Pty Limited 35.0%
• Stewart Petroleum Co Limited (NZOG) 12.5%
• WM Petroleum Limited (PPP) 10.0%

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Buccaneer's Kenai Loop Reserves Exceed Expectations

- Buccaneer's Kenai Loop Reserves Exceed Expectations

Wednesday, July 20, 2011
Buccaneer Energy Ltd.

Buccaneer announced an initial Proven and Probable Reserve of 38.3 BCF (4.8 MMBOE) at 100% owned Kenai Loop. These booked Reserves substantially exceed the Company's pre drill assessment of approximately 5.0 – 10.0 BCF.

Ralph E. Davis completed an independent reserve assessment of the Kenai Loop project. Ralph E. Davis is a respected consulting firm providing independent reservoir engineering, geological, technical and financial services to the domestic and international energy industry since 1924.

	Proven (1P)	Proven & Probable (2P)	Proven & Probable & Possible (3P)
Gas - BCF	31.5	38.3	51.6
Oil Equivalent- MMBOE	3.9	4.8	6.5

The above Reserves were calculated using subsurface mapping, pressure and flow rates data attained from KL #1 well. The current Reserves include only two sand packages at 9,700 feet and 10,000 feet. An average drainage area of 340 acres was used to calculate the Reserves and the Company expects that a second well will be required to drain the entire 340 acres. The Company's mapping indicates the two sand packages have a total closure area of 1,600-2,000 acres.

The Proven Reserves have a Future Net Income of US $127.9 million and a Net Present Value (NPV) of US $73.6 million. Assumptions used in the NPV calculation include:

• Two wells producing at 5.0 mmcfd;
• A gas price of US $5.71 / mcf;
• A pipeline tariff of $0.21 / mcf;
• Operating Costs of US $15,000 per month; and
• A discount rate of 10%.

The KL # 1 well was drilled to a depth of 10,680 feet and intersected 26 separate gas zones totaling 645 feet of gross pay. The Company elected to perforate and test only the 9,700 and 10,000 feet sands (which totaled 87 feet of gross pay) due to rig availability constraints. The remaining 24 zones totaling 558 feet of gross pay are yet to be tested and do not form part of the Reserves assessment.

Kenai Loop is 100% owned by Buccaneer with total acreage under lease of 8,988 acres.

Near Term Work Plan

The Company expects to spud the second well at Kenai Loop this quarter. The second well will be drilled from the same location as KL # 1 and will have two primary objectives:

• a step out well to test and possibly extend the known aerial extent of both the 9,700 and 10,000 feet sands. If successful this will effect an increase in the current Proven and Probable Reserves; and
• to test the sands below 10,000 feet and specifically those at approximately 10,600 feet intersected in KL # 1. These sands appear similar to the 9,700 and 10,000 sands. If this or other objectives are successful then it is expected Proven and Probable Reserves will be increased.

Further details on the commencement date of this well will be made once rig contracts have been executed.

Commentary

Director of Buccaneer Energy, Dean Gallegos said, "This is a very significant result. We expect that further drilling at Kenai Loop will yield additional increases to booked Reserves. These increases would be based on both the current two pay zones and zones below10,000 feet.

"Clearly, there is substantial upside from the remaining 24 zones (totaling 558 feet of gross pay), which are yet to be tested.”

"As part of the Buccaneer's 3 prong strategy, the Company has planned an aggressively drilling program for the development of the Kenai Loop field and expects to drill additional wells in the next 12 months.

"We anticipate placing the Kenai Loop field into production by the end of 2011."

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Bow Boosts 2P Certified Reserves by 60%

- Bow Boosts 2P Certified Reserves by 60%

Tuesday, July 19, 2011
Bow Energy Ltd.

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

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

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

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Venezuela Oil Reserves Surpassed Saudis In 2010 - OPEC

- Venezuela Oil Reserves Surpassed Saudis In 2010 - OPEC

Monday, July 18, 2011
Dow Jones Newswires
LONDON
by Benoit Faucon

Venezuela's crude proven reserves surpassed those of Saudi Arabia in 2010, making it the world's largest oil reserves holder, the Organization of Petroleum Exporting Countries said in its annual statistical bulletin.

Venezuela's proven crude oil reserves reached 296.5 billion barrels in 2010, up 40.4% on the year and higher than Saudi Arabia's 264.5 billion barrels, OPEC said.

In the long run the boost in reserves, which comes alongside increases from Iran and Iraq, may empower members of OPEC who favor a defense of high prices. However, there are doubts over whether all of Venezuela's heavy oil discoveries are economically viable.

The data broadly confirm Venezuela's statements that it had reached this level of reserves in January. OPEC normally relies on its members' assessments for statistical data.

Iraq's and Iran's proven reserves were also respectively upgraded by 24.4% to 143.1 billion barrels and by 10.3% to 151.2 billion barrels respectively, roughly in line with the countries' earlier disclosures.

Venezuela, Iran and Iraq were part of a group that refused to endorse a Saudi-led push to hike output at an acrimonious OPEC meeting June 8.

Analysts have questioned how economic Venezuelan reserves additions could be, as most come from the heavy and extra-heavy oil in the Orinoco Belt, which is difficult and expensive to extract.

Venezuela's statistics have long been a controversial topic in oil circles, though disagreements on the matter have recently eased. The International Energy Agency last month said it revised the method used to calculate the country's oil-production figures, bringing its estimates closer to those of Caracas.

The set of statistics may also vindicate Iran's claims that sanctions aren't crippling the development of its oil and gas industry. For instance, crude oil exports from the Islamic Republic to Europe in 2010 rose 34.5% to 764,000 barrels a day on average.

Overall, Iranian oil exports rose by 0.7% as exports to Asia and the Pacific fell by 11%. Iranian natural gas reserves and exports rose by 11.8% and 48.7% respectively.

Last year, the European Union implemented stringent sanctions on Iran which, without banning crude purchases, complicate them by putting restrictions on insurance, financial services and energy sectors.

The numbers also underscore the recovery of the Nigerian oil industry with 17 more rigs active in the West African nation and 437 additional producing wells, following a successful amnesty for militants in 2009.

Overall, the numbers show OPEC members strongly benefited from higher oil prices in 2010, with the total value of their petroleum exports up 27.2% at $745.1 billion and their overall gross domestic product rising 11.2% to $2,325 billion.

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

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Magnum Hunter Sees 133% Increase in Reserves

- Magnum Hunter Sees 133% Increase in Reserves

Thursday, July 14, 2011
Magnum Hunter Resources Corp.

Magnum Hunter announced a 133% increase in the quantity of the Company's estimated total proved reserves at June 30, 2011 as compared to December 31, 2010. The present value of estimated future cash flows, before income taxes, of the Company's estimated total proved reserves as of mid-year 2011, discounted at 10% ("PV-10"), also increased 141% as compared to six months ago at year-end 2010.

Magnum Hunter's total proved reserves increased by 17.8 million barrels of oil equivalent (Boe) to 31.2 million Boe (55% crude oil & ngl; 50% proved developed producing) as of June 30, 2011 as compared to 13.4 million Boe (51% crude oil & ngl; 44% proved developed producing) at December 31, 2010. The Company's reserve life (R/P ratio) was approximately 17.3 years as of June 30, 2011.

The Company's PV-10 at June 30, 2011 increased by $250 million or 141% to $428 million from $178 million at December 31, 2010. Under new SEC guidelines, the commodity prices used in the December 31, 2010 and June 30, 2011 PV-10 estimates were based on the 12-month unweighted arithmetic average of the first day of the month price for the periods January 1, 2010 through December 31, 2010, and July 1, 2010 through June 30, 2011, respectively, adjusted by lease for transportation fees and regional price differentials. For crude oil and ngl volumes, the average West Texas Intermediate posted price of $89.96 per barrel at June 30, 2011, was up 13% from the average price of $79.43 per barrel at December 31, 2010. For natural gas volumes, the average price of the Henry Hub spot price of $4.20 per million British thermal units ("MMBTU") at June 30, 2011 was down (4%) from the $4.37 per MMBTU at December 31, 2010. All prices were held constant throughout the estimated economic life of the properties.

Note: PV-10 is a non-GAAP financial measure and should not be considered as an alternative to the standardized measure of discounted future net cash flows as defined under GAAP; see "Non-GAAP Measures: Reconciliation to Standardized Measure" below for the Company's definition of PV-10 and a reconciliation to the standardized measure.

The Company's June 30, 2011 total proved reserves of 31.2 million Boe reflect an organic growth of 6% from the Company's pro forma proved reserves of 29.4 million Boe as of December 31, 2010, when including the proved reserves related to the Company's acquisition of the assets of NGAS Resources, Inc. and NuLoch Resources, Inc., which occurred on April 13, 2011 and May 3, 2011, respectively. Magnum Hunter's first half of fiscal year 2011 organic extensions and discoveries from drilling activities replaced the Company's estimated production through June 30, 2011 by a factor of four times. When including the first six months of fiscal year 2011's property acquisition activities, the replacement of production factor for the first six months of fiscal year 2011 increased by approximately 20 times.

The estimates of Magnum Hunter's total proved reserves as of December 31, 2010 and June 30, 2011 were prepared by the Company's third-party engineering consultants.

Resource Potential

The Company's internal engineering team has evaluated the resource potential of Magnum Hunter's existing undeveloped lease acreage position in our three unconventional shale plays. The undeveloped acreage evaluated includes 652,419 gross acres and 347,547 net acres to Magnum Hunter's ownership interest.

The current number of total new drilling locations in Magnum Hunter's inventory today is approximately 4,000 of which 1,350 are identified drilling locations in these three unconventional resource plays, net to the Company's interest. The net unrisked resource potential of 462 million barrels of oil equivalent is approximately 48% crude oil and natural gas liquids

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Namibia Sees 11 Billion Barrels In Offshore Oil Reserves

- Namibia Sees 11 Billion Barrels In Offshore Oil Reserves

Wednesday, July 06, 2011
Dow Jones Newswires
WINDHOEK

An estimated 11 billion barrels in oil reserves have been found off Namibia's coast, with the first production planned within four years, mines and energy minister Isak Katali announced Wednesday.

The finding could put Namibia on par with neighboring Angola, whose reserves are estimated at around 13 billion barrels and whose production rivals Africa's top producer, Nigeria.

Katali said that Enigma Oil & Gas, owned by London-listed Chariot Oil & Gas, has identified 11 prospects along the southern coast.

"The largest of these, the Nimrod Prospect in 350 meters (1,150 feet) depth, and most likely reserves in the event of success are estimated to be greater than four billion barrels," he told parliament.

"Enigma expects to find oil rather than gas," Katali said, adding that first production could begin as early as 2015.

Enigma holds a 50% equity in the offshore Southern Block together with Brazil's Petrobras.

According to Katali, another Brazilian company, HRT Oil & Gas Ltd, has raised $1.3 billion on the Brazilian stock market, with $300 million earmarked for oil and gas exploration in Namibia.

He said that HRT has certified about 5.2 billion barrels of potential reserves.

"This finding could turn offshore Namibia into a great producer of oil and gas in a short time," Katali said.

In his statement to Parliament, Katali added that HRT would drill three to four wells in that area as early as next year.

Another find off Namibia's central coast called Delta Prospect contained recoverable resources of up to two billion barrels of oil, by Arcadia Expro Namibia and British firm Tower Resources, he said.

"We expect that six to eight wells to be drilled in Namibia's waters in the next 18 months, the highest number in Namibia's exploration history," he said.

Namibia has long been seen as a potential new source of oil, hampered by a lack of exploration to determine the extent of its reserves. Its offshore geology is similar to Brazil, which is seeing a boom in oil.

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

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PetroNeft Confirms 2P Reserves in Western Siberia

- PetroNeft Confirms 2P Reserves in Western Siberi

Wednesday, July 06, 2011
PetroNeft Resources plc

PetroNeft, owner and operator of Licenses 61 and 67, Tomsk Oblast, Russian Federation, provide an update on its operations.

Highlights

• Kondrashevskoye No. 2 sidetrack well confirms 2P reserves
• Lineynoye 206 contains thickest oil pay encountered to date
• Lineynoye/West Lineynoye has materially thicker pay and extends significantly further north than originally anticipated
• Several new oil bearing structures are now likely to the north of Lineynoye/West Lineynoye

License 61 Exploration/Delineation program

The Kondrashevskoye No. 2 sidetrack has been drilled down dip from the Kondrashevskoye No. 2 well and penetrated the oil water contact in the objective J1-1 sandstone interval at -2,465 m true vertical depth ("TVD"). The reservoir interval of 3 meters in the sidetrack section was slightly thicker than in the vertical well with the top meter of the reservoir oil bearing.

Based on the results, the well has most likely confirmed the existing independent Ryder Scott 2P reserves of 8.1 mmbo attributed to the field and we will now update the reserves with the Russian State Reserve committee in preparation for field development. The exact timing of development will depend upon how the economics of this field compares with other nearby fields, most notably Arbuzovskoye.

Production casing has been run and cemented in the well so it can be used when the field is developed. The drilling crew is in the process of moving to the potentially high impact Sibkrayevskaya exploration prospect which will commence drilling shortly.

License 61 Development program

The Lineynoye 206 development well drilled from Pad 2 to the north contained 21.9 meters of gross sandstone with 18.5 meters of net pay which is the thickest net pay interval encountered to date in the drilling program. The reservoir interval was completely saturated with oil and confirmed an oil-down-to of -2,437.5 m TVD, some 15 meters deeper than the previously mapped structural spill point of the field to the north.

The results of this and other recent Pad 2 wells have shown that the northern part of the Lineynoye field has materially thicker pay and extends significantly further north than originally anticipated. This has positive implications for reserves and productivity in this region of the field and for the likelihood of several new structures north of Lineynoye/West Lineynoye to be oil bearing.

Dennis Francis, Chief Executive Officer of PetroNeft Resources plc, commented, "We are pleased to have proved reserves for economic development at Kondrashevskoye and will incorporate this discovery along with Arbuzovskoye in our 2012 development planning. Pad 2 drilling continues to be very encouraging with the thickest oil pay encountered yet indicating an increased probability that oil has migrated north from the Lineynoye/West Lineynoye field into the various structures contained in the undeveloped Emtorskaya High area."

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Maverick Boosts Reserves at Blue Ridge Dome

- Maverick Boosts Reserves at Blue Ridge Dome

Wednesday, June 29, 2011
Maverick Drilling & Exploration Ltd.

Maverick Drilling & Exploration announced a significant upgrade to Maverick's 2P reserves on its flagship asset, Blue Ridge Dome, by approximately 26.8 million net oil barrels for Maverick's share of its leases. The reserves reflect no barrels equivalent in natural gas and are all true liquid oil barrels.

The reserve upgrade is a result of a combination of new lease acquisitions on Blue Ridge Dome and further analysis of results of Maverick's ongoing drilling program. A comparison to previously disclosed reserves is set out below:

Net Maverick Reserves

	Proved 1P (million bbls)	Proved + Probable 2P (million bbls)
ISO prospectus	7.8	25.6
Today	12.4	52.4
9 month increase (%)	59%	104%

Approximately 7.6 million net 2P barrels of the increase are the result of the company's improvements on those Blue Ridge Dome leases held at the time of listing (in September 2010). The remaining 19.2 million 2P barrels relate to acquisitions and expansion of holdings in the field.

Commenting on the upgrade, Maverick's executive chairman, Mr. Don Henrich said, "This is a superb outcome in Maverick's first nine months as a listed company. The substantial upgrade highlights the vale of Blue Ridge Dome, and the inherent potential of Boiling Dome, a piercement type salt dome with similar characteristics. The reserve upgrade underpins our aggressive acquisitions and in-field drilling and completion program which is achieving record production month over month for the past several months."

As previously announced, the company holds considerably larger net acreage on Boiling Dome than on Blue Ridge Dome. The Directors expect to announce maiden reserves for Boiling Dome later this calendar year, after commencement of the pilot drilling program.

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Analysis: Shale Boom, Independents Drive U.S. Reserves, Capital Spending

- Analysis: Shale Boom, Independents Drive U.S. Reserves, Capital Spending

Wednesday, June 15, 2011
Rigzone Staff
by Karen Boman

The U.S. shale oil and gas drilling boom boosted U.S. oil and gas reserve growth to a five-year high in 2010, while upstream spending more than doubled from 2009 to 2010 largely due to producers' acquisitions of shale properties, according to Ernst & Young's fourth annual U.S. E&P Benchmark Study.

The survey of the 50 largest oil and gas companies by end-of-year reserves found that end-of-year oil reserves grew 11 percent from 16.1 billion barrels in 2009 to 17.8 billion barrels in 2010, and natural gas reserve grew 12 percent from 156.2 Tcf in 2009 to 174.3 Tcf in 2010, the strongest combined annual growth posted from 2006 to 2010.

Shale Rock

The oil production replacement rate for U.S. oil reserves from all sources, including extensions and discoveries, improved recovery, revisions, purchases and sales of proved reserves, was 234 percent in 2010, compared with a 158 percent replacement rate in 2009. The U.S. natural gas production replacement rate from all sources was 252 percent last year, compared with 156 percent in 2009.

Production replacement rates for 2010 that excluded purchases and sales were 205 percent for oil, 249 percent for gas, and 232 percent on a combined BOE basis.

The study found that independent oil and gas producers led in terms of oil production replacement rates for 2010, with independents replacing 601 percent of oil production from all sources last year and, excluding purchases and sales, replacing 433 percent of oil production.

Large independents replaced 241 percent of production from all sources, and 290 percent of production from sources other than purchases and sales. Meanwhile, integrated oil and gas companies replaced 141 percent of oil production from all sources, and 111 percent of production from sources excluding purchases and sales.

Integrated companies had a gas production replacement rate of 436 percent from all sources; however, this replacement rate reflects ExxonMobil's acquisition of XTO Energy, which was completed in June 2010. When purchases and sales were excluded, integrated companies had a gas production replacement rate of 111 percent.

Independents replaced 408 percent of gas production from all sources in 2010, or 375 percent when purchases and sales were excluded. Large independents recorded a negative gas production replacement rate of 34 percent, largely due to the ExxonMobil/XTO transaction, as XTO is classified as a large independent. Excluding purchases and sales, large independents had a gas production replacement rate of 263 percent in 2010.

Reserve replacement costs on a total basis, including proved property acquisitions, were up once again, increasing to $15.26 per BOE in 2010 from $12.78 per BOE in 2009. Reserve replacement costs on a finding and development basis, excluding proved property acquisitions, increased to $17.84 per BOE, up from $13.01 per BOE in 2009.

Upstream spending more than doubled from $72.8 billion in 2009 to $177.9 billion in 2010. ExxonMobil's acquisition of XTO Energy accounted for 51 percent of proved property acquisition costs of $42.2 billion and 40 percent of unproved property acquisition costs of $59.3 billion in 2010. Apache Corp.'s acquisition of Mariner Energy and assets from Devon Energy and BP contributed significantly to proved and unproved property acquisition costs, as did acquisitions by Chesapeake Energy and Denbury Resources.

Exploration costs increased eight percent from $14.3 billion in 2009 to $15.5 billion in 2010, while development spending increased 36 percent from $44.8 billion in 2009 to $60.8 billion in 2010, primarily due to shale oil and gas development. The increase in exploration and development spending was primarily driven by ExxonMobil, Chesapeake Energy and EOG Resources. Of the 50 companies surveyed, only four decreased their exploration and development spending in 2010 – BP, ConocoPhillips, Loews and Plains Exploration & Production.

The companies' plowback percentage, or total upstream spending as a percentage of netback, increased to 170 percent in 2010, the highest of the five-year period from 2006 to 2010, as companies reinvest in shale activity. In 2006, the plowback percentage reached 121 percent as a result of an increase in investment activity driven by a relatively high priced commodity environment.

ExxonMobil's acquisition of XTO and similar deals are part of the trend of major oil and gas companies following the lead of independent oil and gas companies, who were first movers in North American shale plays. This trend is occurring as integrated majors are finding it difficult to replace reserves organically. The rise of national oil companies overseas has made it more difficult for the companies to access foreign reserves, as have restrictions placed U.S. offshore drilling. U.S. independents and oil service companies have been at leading edge of technology, including developments in horizontal drilling, which have changed the oil and gas industry.

Horizontal drilling

Strong oil prices and weak, but stable, gas prices in 2010 encouraged investment in shale exploration efforts and production technology. The shift from gas to oil-focused drilling has created a drilling renaissance in the Permian Basin that has operators looking at plays nobody thought was possible.

However, consistency in commodity prices, as well as companies' abilities to find enough skilled employees and addressing issues surrounding hydraulic fracturing, are needed to allow companies to capitalize on shale properties. Despite controversy over hydraulic fracturing, the practice will likely continue, said Marcela Donadio, Americas Oil & Gas Leader for Ernst & Young, noting that companies are taking efforts to conduce fracing responsibly.

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PetroNeft's 2011 Exploration Program to Double Reserves in Russia

- PetroNeft's 2011 Exploration Program to Double Reserves in Russia

Tuesday, June 07, 2011
PetroNeft Resources plc

PetroNeft, owner and operator of Licenses 61 and 67, Tomsk Oblast, Russian Federation, provided an update on its operations.
Highlights:

• Kondrashevskoye No. 2 well successfully tests oil
• Four additional wells completed in the Lineynoye Development Drilling Program
• Drilling establishes interconnection between Lineynoye and West Lineynoye fields
• New structural interpretation of Lineynoye shows thicker pays extend significantly further north
• Facilities construction to expand capacity from 7,400 bopd to 14,800 bopd is on schedule for completion in July

License 61 Exploration / Delineation Program

PetroNeft's high impact 2011 exploration program, which has the potential to more than double our reserves, is targeting over 60 million barrels on three prospects in License 61.

The first well in the program, the Kondrashevskoye No. 2 delineation well, has been drilled and has confirmed 2.3 m of net pay in the J1 interval. This is consistent with the No. 1 well which discovered the oil field in 2008. The well tested high quality 41° API gravity crude oil at a prorated inflow rate of 32 bopd on a short open hole test (without stimulation). The well was then drilled to basement and a core taken to meet government regulations.

Neither Kondrashevskoye well has encountered the oil water contact for the field so we will now sidetrack the No. 2 well down-dip to locate the oil water contact and determine the full reserve potential of the field. This process in now underway and is expected to be completed by the end of June.

The second 2011 exploration well will be at Sibkrayevskaya, the largest prospect in the program at over 40 million barrels. Site preparation and mobilization of the rig and materials is complete and rig-up operations are well advanced. Drilling should start in late June, following completion of the Kondrashevskoye No. 2 sidetrack.

The site for the third exploration well, North Varyakhskaya No. 1, has also been prepared and the rig and materials have been moved to the site for a planned spud in August 2011 following Sibkrayevskaya.

2011 License 61 Development program - Lineynoye oil field

Production drilling continues with three additional wells successfully drilled from Pad 2, making a total of 5 thus far and the first well from Pad 3. Preliminary log and survey data for the development wells on Pads 2 and 3 are shown below, with Well 204 having the largest gross sand interval in the J1 section to date.

The primary objective for Well 203 was encountered deeper than anticipated and close to the oil-water contact for the field. The well was then side-tracked up-dip to the planned 204 location. The sidetrack well (203s) contained 2.0m of oil in the J1-1 interval with good oil saturation (65%), but the J1-2 sandstone interval was not developed in this location.

As a result of the information learned from Wells 203 and 203s, we have re-evaluated the seismic data for the Lineynoye Field. The resulting new interpretation clearly connects Pads 1 and 2 to the West Lineynoye field to the north where previously it had been thought they were separate structures. While this has positive implications for reserve and production performance from these areas of the field, the data also suggests that net pay in the planned Pad 3 wells is likely to be thinner than previously anticipated. Wells 204 and 205, which were drilled after the new structural interpretation have confirmed the revised mapping and shown that the area of thicker pays extends significantly further north than originally thought. This, together with the results of Well 334, will likely add extra wells to the Pad 2 program and reduce the number of wells to be located at Pad 3.

Due to the poor condition of the well bore in the original Lineynoye No. 1 discovery well (drilled in 1972) and the high quality reservoir characteristics at this location we have decided to drill a new production well adjacent to the L-1 location from Pad 2 at the end of the Pad 2 program. A modern well will allow effective production and drainage of this portion of the field through the use of a modern electric submersible pump and the application of hydraulic fracturing.

Production is currently about 2,500 bopd with the primary contribution coming from 7 of the 9 wells drilled last year with workovers to be carried out on the two poorest performing wells later in the year. New wells will now be tied-in but we do not anticipate significant production increases until some of the new wells can be fracture stimulated later this summer by a heli-frac crew.

License 61 Facilities Construction and Tie-in

The connection of Pads 2 and 3 to the existing central processing facility is complete and new wells being prepared for tie-in to the process facilities. Work to expand the central processing facility from 7,400 bfpd to 14,800 bfpd is expected to be completed on schedule by mid July.

2011 License 67 Exploration program

The drilling tender for the two exploration wells to be drilled in 2011 in License 67 has been completed and the contract was awarded to LLC "Tomskburneftegaz" (TBNG). In accordance with AIM Rule 13 and ESM Rule 13, the drilling contracts are deemed to be a related party transaction as Vakha Sobraliev, a Non-Executive director of the Company, is principal owner of TBNG.

The Board of Directors, with the exception of Vakha Sobraliev who is involved in the transaction as a related party, having consulted with Davy, the Company's Nominated Adviser and ESM adviser, have determined that the terms of the drilling contracts are fair and reasonable insofar as shareholders are concerned.

The two exploration wells, Cheremshanskaya No. 3 and Ledovoye No. 2a, are located close to existing all year round roads and will be drilled in the second half of the year following the License 61 exploration wells, utilizing the same drilling crew. We have already mobilized equipment and completed construction of the Cheremshanskaya site and the rig is now being mobilized by barge to a nearby river port. Construction of the site for the Ledovoye No 2a well will begin shortly and drilling will commence following completion of Cheremshanskaya No. 3.

Dennis Francis, Chief Executive Officer of PetroNeft Resources plc, commented, "We are delighted that the Kondrashevskoye No. 2 well has further proved up the Kondrashevskoye oil field and look forward to the additional data that the deviated portion of the well will provide. This oil field is one of the candidates for production drilling and tie-in during 2012.

"The development program is well underway and we have learned a lot from the drilling to date. The Lineynoye oil field extends further north and has thicker oil pays than previously thought whereas the Pad 3 area has some thinner pays. We will continue to dynamically adjust the drilling and completion program to ensure the optimum long term reserve and production outcome for Lineynoye and the surrounding discoveries."

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Thailand's Natural Gas Reserves to Run Out in 18 Years

- Thailand's Natural Gas Reserves to Run Out in 18 Years

Wednesday, June 01, 2011
Knight Ridder/Tribune Business News
by Watcharapong Thongrung, The Nation, Bangkok, Thailand

Thailand's natural-gas reserves are estimated to be enough for only 18 more years if no new reserves are found, said Kurujit Nakornthap, deputy permanent secretary of the Energy Ministry.

He made the remark yesterday (May 31) at a seminar on Thailand's energy outlook. He said the current natural-gas reserves, both proven and probable, stand at 23 trillion cubic feet. If production is maintained at the rate of 3,747 million cubic feet per day (MMcfd) and no new reserves are found, the current reserves will run out in 18 years.

He added that the ministry had given priority to seeking new resources to ensure national energy stability.

He added that of the country's proven petroleum reserves as of 2009, natural gas stood at 11.026 trillion cubic feet, condensate at 255 million barrels, and crude oil at 180 million barrels. Of total probable reserves, the natural-gas amount stood at 6.170 trillion cubic feet, condensate at 86 million barrels, and crude oil at 170 million barrels.

This year natural-gas production in Thailand in many fields is expected to reach a combined 3,717MMcfd, up from 3,511MMcfd, while the demand from many industrial sectors is estimated at a combined 4,006MMcfd, down from 4,039MMcfd last year.

The high demand for natural gas means Thailand is expected to import 702MMcfd from Burma this year.

Kurujit said one threat to the country's energy security was its over-dependence on natural gas for generating electricity. It is estimated that natural gas this year will account for 71 percent of all energy sources used for electricity generation. Coal-fired power plants and proposed nuclear plants face opposition from communities.

Department of mineral fuels director-general Songpop Polachan said it would rapidly seek additional domestic petroleum sources through the planned granting of new concessions, the promotion of production in small petroleum fields, and a feasibility study on the production of natural gas from high-carbon-dioxide fields.

Copyright (c) 2011, The Nation, Bangkok, Thailand / Asia News Network

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Pegasi Ramps Reserves in Tx.

- Pegasi Ramps Reserves in Tx.

Thursday, May 26, 2011
Pegasi Energy Resources Corp.

Pegasi released net oil and gas reserves as of December 31, 2010.

The Company is reporting total net proved reserves of 3,024,333 Barrels of Oil Equivalent (BOE), net probable reserves of 610,339 BOE and net possible reserves of 10,620,722 BOE as of 12/31/2010. A 6,000 CUFT ratio to one barrel of oil is used to equate BCF to BOE. In addition, Pegasi has internally estimated its unrisked total Contingent Resource potential of 77,130,240 BOE bringing the total unrisked plus risked reserve to 91,461,463 BOE. The contingent resource evaluation was performed by utilizing the data presented in the Engineering Study and Economic Analysis for the Cass and Marion Development Program prepared by James E. Smith and Associates.

All of the reported oil and gas reserves are from the Company's Cornerstone project located in Marion and Cass counties in northeast Texas and are based on independent engineering by James E. Smith and Associates. The Company has a 40% to 80% working interest in the project.

The area of the Cornerstone Project has produced over 400 million barrels of oil and more than 2.3 trillion cubic feet of gas. Pegasi is focused on applying new horizontal drilling and multistage frac technology to recover substantial additional oil and gas reserves which remain in place.

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TAG Sees 221% Increase in Taranaki Reserves

- TAG Sees 221% Increase in Taranaki Reserves

Monday, May 23, 2011
TAG Oil Ltd.

TAG Oil reported that an independent assessment of reserves has been completed as of March 31, 2011 on TAG Oil's 100%-owned Cheal Mining Permit (PMP 38156) and Sidewinder Exploration Permit (PEP 38748), located in the Taranaki Basin, New Zealand. Sproule International Limited, one of Canada's largest petroleum engineering consulting companies prepared the report in accordance with definitions, standards and procedures contained in the Canadian Oil and Gas Evaluation Handbook (COGE Handbook) and National Instrument 51-101, Standards of Disclosure for Oil and Gas Activities.

The reserves reported for the 2011 fiscal year relate primarily to the Cheal oil and gas field due to fiscal year-end 2011 cut-offs required under NI-51-101. Due to the timing of operations occurring after March 31, 2011, the Sidewinder reserve assessment was completed with information related only to the Sidewinder-1 well and does not include the now-completed Sidewinder-2, Sidewinder-3 and Sidewinder-4 wells.

The assessment of reserves has assigned net proved and probable reserves ("2P") remaining of 1,360,000 barrels of oil (2010 = 651,000 bbls) and 1,864 million cubic feet ("mmcf") of associated gas (2010 = 258 mmcf). This reserves report, on a 2P basis, amounts to 1,677,000 barrels of oil equivalent ("BOE") assessed within a reserves area covering just 475 acres of the 7,487-acre Cheal permit and just 107 acres of the 7,910-acre Sidewinder permit.

After considering production during the 2011 fiscal year, the 1,677,000 BOE in proved and probable reserves represents a 221% increase over the March 31, 2010 year-end independent reserve assessment. The key factors for the increase in reserves for fiscal 2011 are as follows:

• One new well drilled and completed
• Establishment of commercial production from a bypassed discovery
• Increased recovery factors
• Upward revision to projected future well performance

During the 2011 fiscal year, TAG focused primarily on optimizing the production from the producing Cheal wells. This resulted in an increase in the recovery factors being assigned to the Mt. Messenger Formation. In addition, TAG was successful in establishing the first-ever commercial production from the bypassed Urenui Formation oil discovery, using two historical wells drilled at Cheal by the previous operator. Having successfully completed these operations, Cheal now produces from both the Urenui and Mt. Messenger Formations at approximate depths of 1400m (~4600 feet) and 1800m (~5900 feet), respectively.

TAG Oil's Chief Executive Officer, Garth Johnson, commented, "We are very pleased to follow fiscal 2010's reserve increase with another large increase in fiscal 2011, even after having produced ~160,000 barrels of oil during the year. This report has established initial reserves within the Sidewinder discovery area, where the majority of our operations occurred after year-end and could not be considered for fiscal 2011 reserves. The commercialization of the Urenui oil discovery has also allowed us to book initial reserves and is another low-risk opportunity to build reserves in Taranaki from this widespread formation identified at Cheal."

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SSGC: Pakistan's Estimated Gas Reserves Higher Than Expected

- SSGC: Pakistan's Estimated Gas Reserves Higher Than Expected

Monday, May 23, 2011
Asia Pulse Pte Ltd.

Pakistan holds an estimated 33 trillion cubic feet (tcf) of tight-gas reserves, higher than the existing estimated 27 tcf in the country, said the deputy managing director of operations of Sui Southern Gas Company (SSGC) Syed Hassan Nawab.

Nawab made the comment addressing the 7th International POGEE Conference 2011 for Oil and Gas and Energy Industry at the Karachi Expo Center on Wednesday. Joint Secretary Ministry of Petroleum and Natural Resources Raashid Bashir Maser was the chairman of the session.

Referring to a report of Pakistan Petroleum Exploration and Production Companies Association (PPEPCA), Nawab said the country will have sufficient natural gas if tight gas is explored with the help of advanced technology. He pointed out that the government has prepared the draft policy for tight gas and it is currently with the Council of Common Interest (CCI) and this will be approved soon.

Quoting some of the incentives in the draft tight gas policy, he said that investors will be offered 40 percent premium on the current gas price for exploring tight gas. Similarly, 50 percent premium will be offered on current gas price to investors if they commission their project by December 2011.

Hassan Nawab said that Pakistan can also produce gas from Thar coal with the help of underground coal gasification (UCG) technology. There is a potential to produce 35 tcf of coalbed methane from Thar coal, he noted.

He said that the availability of natural gas can be enhanced through import of liquefied natural gas (LNG) from neighboring countries like Qatar and Iran-through 3rd party arrangements. He said the country has a very large network of pipelines and the importer of LNG can pump this gas to their buyers in upcountry destinations.

(C) 2011 Asia Pulse Pte Ltd.

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