Premier Oil Granted Drilling Permit in North Sea

- Premier Oil Granted Drilling Permit in North Sea

Wednesday, September 07, 2011
Norwegian Petroleum Directorate

The Norwegian Petroleum Directorate has granted Premier Oil Norge AS a drilling permit for well 9/1-1 S.

Well 9/1-1 S will be drilled from the Bredford Dolphin drilling facility in position 57°35'37.02"N and 4°00'56.05"E.

The drilling program for well 9/1-1 S concerns the drilling of a wildcat well in production license 406. Premier Oil Norge AS is the operator with a 40 percent ownership interest. The other licensees are Skeie Energy AS with 40 percent and Spring Energy Exploration AS with 20 percent. Production license 406 was awarded in APA 2006.

The area in this production license is located in the southeastern part of the North Sea. It consists of parts of blocks 8/3, 9/1, 17/12, 18/10 and 18/11. Well 9/1-1 S is the first exploration well to be drilled in this production license.

The drilling permit is contingent upon the operator securing all permits and consents required by other authorities before commencing the drilling activity.

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Premier Oil Sees 60,000 Boepd Production in Second Half

- Premier Oil Sees 60,000 Boepd Production in Second Half

Thursday, August 25, 2011
Dow Jones Newswires
LONDON
by Iain Packham

Independent oil and gas company Premier Oil expects production to increase to around 60,000 barrels of oil equivalent a day in the second half of the year as its Chim Sao and Gajah Baru projects come on line in the next few weeks, Chief Executive Simon Lockett told Dow Jones Newswires Thursday.

First-half production averaged 36,900 barrels of oil equivalent a day, down from 46,600 in the first half of 2010 as unplanned maintenance work sapped production. Full-year production is estimated to be between 40,000 and 45,000, similar to levels in 2010.

Premier has put in place a $40 million investment program to minimize future disruptions and some of the work undertaken will actually boost production, Lockett said.

Premier said it expects second-half production to be higher than the first half as the Chim Sao project in Vietnam, which it operates, starts oil production in the next few weeks. This will be supplemented by the start of gas production at the Premier-operated Gajah Baru project in Indonesia.

Lockett said he expects production from Gajah Baru and Chim Sao will "push our production numbers up from the low end that we had in the first half of this year up to 60,0000 barrels [of oil equivalent] a day towards the back end of this year."

"That will keep us on track to deliver 75,000 barrels [of oil equivalent] a day back-end of next year and on to 100,000 barrels a day in the medium term, which is the stated target."

The company is also stepping up its exploration activities and estimates up to 20 exploration and appraisal wells will be drilled in the next 12 months, targeting around 300 million barrels of oil equivalent. It expects to drill 10 exploration wells in the second half of 2011 in Indonesia, Vietnam, Norway and the U.K.

Finance Director Tony Durrant told Dow Jones Newswires that Premier's exploration activities will cost around $250 million over 2011 and estimated that $150 million of that will be spent in the second half.

Premier said it has set itself an exploration target of achieving 200 million barrels of oil equivalent of reserve additions by 2015, of which around 75 million barrels have already been achieved.


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

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Premier Sets Sights on Oil at Chim Sao Field

- Premier Sets Sights on Oil at Chim Sao Field

Friday, August 12, 2011
Premier Oil plc

Premier reported an exploration drilling update on its Indonesia and Vietnam operations.

Belut Laut-1 (Tuna Block, Indonesia, Premier 65% equity)

The Belut Laut-1 exploration well has reached the planned total depth of 4,948 meters. Oil shows with high gas readings were reported from a depth of 4,740 meters throughout a gross 155 meter Oligocene sandstone interval. However, logs indicated that the sandstones at this depth were of poor porosity. The well will therefore be plugged and abandoned with oil and gas shows.

Belut Laut, along with Gajah Laut Utara-1 and the successful appraisal of the Ca Rong Do discovery (CRD-2x) in Vietnam earlier this year, has confirmed the potential for hydrocarbons within the Oligocene section in the Nam Con Son basin. The ongoing sub-surface interpretation will now be focused to prospects at shallower depths where good reservoir properties are preserved up dip from proven source rocks. At least five such prospects have been identified in the Tuna acreage and also in the neighboring Block 07/03 in Vietnam. Premier plans to drill the first of these in the second half of 2012.

CS-N2P (Block 12W, Vietnam, Premier 53.125%)

The CS-N2P well, a development production well for the Chim Sáo project, has intersected the shallow part of a previously undrilled fault terrace to the north west of the Chim Sáo field. Based on Logging While Drilling data, the well encountered a 20 meter oil column in an independent closure within good quality Upper Dua Sandstones. The plan is to appraise this new accumulation as a near-field tie-back opportunity via the CS-N1P development well, through which wire-line logs and fluid samples will be acquired. The results of this well are expected in October.

Simon Lockett, Chief Executive Officer, commented, "We have learned from the wells drilled on the Tuna acreage and will now target lookalike prospects in the Nam Con Son basin where the Oligocene reservoirs are at shallower depths and are therefore of better quality.

The discovery of new resources close to the Chim Sáo development is very encouraging and we look forward to the appraisal results later this year."

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Chim Sao Set to Premier

- Chim Sao Set to Premier

Friday, July 15, 2011
Rigzone Staff
by Jaime Kammerzell

Premier Oil Vietnam BV is set to bring the Chim Sao field online in September 2011.

Premier Oil drilled the Blackbird 2E-CS-1X discovery well (now known as Chim Sao) in 115 m of water in November 2006. Premier found more than 70 m of net pay in four oil-bearing intervals in the Middle Dua target, 4,058 m below sea level. The well is in a tilted fault block in the Nam Con Son Basin, 21 km southwest of Premier Oil's Dua field.

In May 2008, the partners drilled the (renamed) Chim Sao North appraisal well. They performed a drill stem test and the well flowed oil at 1,650 b/d and 1.4 MMcf/d on a 40/64-in. choke. The second zone test showed a rate of 2,680 b/d and 2.1 MMscf/d on a 48/64th in. choke. The well was sidetracked down-dip to delineate the oil/water contact and the extent of the hydrocorabon-bearing reservoir.

Premier's partners in the field currently include Santos with 31.857% interest and PVEP with 15% interest. Santos estimates the field contains 48 MMboe of proved and probable reserves and expects 25,000 b/d plateau production from the field.

Santos became a partner in Block 12E in April 2006 when Premier split its 75% share in the block along with partner Delek Energy, which held 25% interest at the time. Premier became operator of Blocks 12E and 12W in September 2004 when it purchased 75% of the block from Delek Energy.

Premier Oil then acquired additional equity in Block 12 in July 2009 when it purchased Delek's 25% interest for $72 million in cash. Separately PetroVietnam Exploration and Production exercised its back-in right to acquire a 15% interest in the PSC.

Shortly after becoming operator, Premier launched a 2D and 3D seismic acquisition, processing and interpretation program, which identified the Dua and Blackbird prospects. The operator then drilled the Blackbird well using Diamond Offshore's Ocean General semisubmersible in May 2006.

Diamond Offshore's Ocean General semisubmersible

Field Development

The Vietnamese authorities approved Premier Oil's Draft Reserves Assessment Report and Field Development Plan in April 2008.

The partners then contracted the Wilboss jackup for a three- to four-well exploration campaign in the first half of 2009 to further appraise the area and to see if there are additional oil discoveries that could be tied-back to the Chim Sao development.

The WilBoss is an independent leg cantilever jackup rig. Keppel Fels built the Awilco rig in Singapore in 2007. It can drill in up to 400 ft of water and down to 30,000 ft.

The first phase of development planned to produce oil and associated gas through two unmanned, minimum facility wellhead platforms tied back to the Nexus 1 FPSO. The FPSO was built to process 25,000-30,000 b/d and offload to shuttle tankers. Gas would be exported via spur and then through PetroVietnam's Nam Con gas pipeline.

BW Offshore submitted a bid to provide both the FPSO and the EPCI contract for the surface facilities. On March 28, 2009, BW Offshore reported it was working on a private placement for the Nexus 1 FPSO. The lease agreement and the EPCI contract were dependent on BW securing funding for the vessel.

In late 2009, however, FPSO lease arrangements were made with a joint venture of Ezra Holdings, EOC, PetroVietnam, PV Keez, and KSI Production. This JV was the first oversees company to secure an offshore Vietnam loan to finance an FPSOs conversion.

The field partners agreed to contract the Lewek EMAS, a 168,000 deadweight ton Suemax oil tanker from EOC Ltd. in late 2009. The FPSO Lewek EMAS is one of Vietnam's largest FPSOs. Keppel Shipyard converted the tanker on behalf of owner PV Keez Pte. Ltd. EMAS Production will manage and operate the FPSO, which Premier Oil charted for the development of the Chim Sáo field off southern Vietnam for six years, with a further option to extend the charter by another six years. The FPSO charter contract is worth approximately $1 billion.

In January 2010, PetroVietnam Transportation (PVTrans) and EOCP then agreed to form a JV to provide operations and maintenance services for the FPSO for 12 years. And in February 2010, EOCP, Ezra Holdings, Keppel and PVTrans agreed to co-own the FPSO.

The FPSO was christened at Singapore's Keppel shipyard on April 15, 2011. EOC said the FPSO can produce up to 50,000 b/d, store up to 680,000 bbl of oil and process around 89 MMsfc/d of gas. EOC and Petrovietnam Transportation Corp. will operate and maintain the vessel under a 50/50 joint venture.

Other contracts the Chim Sao partners awarded include the engineering, procurement, construction and installation (EPCI) contract for the wellhead platform, infield flowlines, and gas export pipelines to PetroVietnam Technical Services (PTSC) in 2008. The platform jacket was installed in March 2010.

In December 2009, the partners awarded a contract to Saipem to install the wellhead platform. Saipem also provided engineering for infield pipelines and the installation of subsea pipelines, umbilicals, and PLEMs. Also in December 2009, EOCP awarded a contract to DPS Bristol to provide detailed design engineering services for CSU, water injection, and flare knock-out drum modules for the FPSO.

Viet Nam Rigs

Premier currently has the ENSCO 107 jackup contracted to drill wells on the Chim Sao field through May 15, 2012, at $110,000/day.

ENSCO 107

Of the 14 other rigs off Vietnam, one is under construction, two are ready stacked, and 11 are drilling.

PV Drilling, Seadrill, and VietSovPetro each have three jackups, Vantage Energy has two rigs, and ENSCO (previously mentioned), Maersk, Petrovietnam, and Transocean each have one rig contracted off Vietnam.

Operator VietSovPetro has six rigs drilling. Aside from Premier, other operators present off Vietnam include Hoang Long, BHP Billiton, Cuu Long JOC, Salamander Energy, and Phu Quy.

Vantage Energy's Aquamarine Driller jackup is currently the highest contracted rig off Vietnam. The jackup is contracted to Salamander Energy to drill block 101/100-04 CB-1X on the Cat Ba field through Aug. 15, 2011 at a rate of $135,000/day.

Vantage Energy's Aquamarine Driller

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Premier Looks Ahead to Next Stage of Growth

- Premier Looks Ahead to Next Stage of Growth

Tuesday, July 12, 2011
Premier Oil plc

Premier provided a trading and operations update ahead of its 2011 Interim Results.

Simon Lockett, Chief Executive, commented, "With continuing good progress on our Asian development projects we expect to see a significant increase in production to around 60 kboepd by year end. Our development teams in the North Sea and Asia are already focused on delivering the next stage of Premier's growth. Our exploration program of around 20 wells over the next 12 months targets around 300 mmboe of unrisked prospective potential."

Production outlook

2011 to date has seen continuing good production performance from the Anoa field in Indonesia, while Pakistan's production has remained steady. This was offset by increased maintenance activity in the UK and a recent unplanned shutdown at Balmoral. As a result, estimated average group production for the first half of 2011 was 36.6 thousand barrels of oil equivalent (kboepd) (2010: 42.8 kboepd) and forecast full year production is now estimated at between 40 kboepd and 45 kboepd.

Near term developments in Asia (Chim Sao and Gajah Baru) are progressing well and 2011 year end run rate is expected to be around 60 kboepd as these projects ramp up. With the UK Huntington and Rochelle projects due on-stream next year, Premier is on target to reach a run rate of 75 kboepd in 2012. Our medium term target of 100 kboepd remains unchanged.

Singapore gas demand continues to grow for our gas exports from the Natuna Sea, with average gas sales under the West Natuna gas contract of 373 bbtud in the first half of 2011 compared to 357 bbtud in the second half of 2010. Block A's share of the contract amounted to 41 percent in the period (against a contractual share of 37 percent), though with a recovery in output from the other two PSC's participating in the contract, actual levels of production reduced from the prior period. Premier's production levels will rise in the second half of the year as the Gajah Baru development contributes from October.

In the UK, production was below expectations due to maintenance related downtime earlier in the year at the Balmoral and Wytch Farm facilities and a recent unplanned shutdown at Balmoral due to a subsea hydraulic leak. Production resumed at Balmoral on 4 July after a three week outage. Scott and Telford production has remained steady since April following earlier disruptions for gas compression maintenance.

As announced in June, Premier increased its stake in the Wytch Farm Assets by 17.715 percent. This is expected to add around 2.5 kboepd to Premier's UK production from year end 2011 when the transaction is targeted for completion. Following the shutdown in the first quarter, production at the Wytch Farm facilities has been rising in recent weeks to around 14 kboepd (gross).

Pakistan production is stable, with the natural decline in the fields offset by infill drilling and the completion of ongoing front-end compression projects. The successful K-18 sidetrack well on Kadanwari, which came on-stream in February 2011, continues to perform favorably. Delays in the front-end compression project at Zamzama are being resolved and increased production is anticipated imminently.

Current and future developments

Asia

In Vietnam, the Chim Sao project remains on schedule with first oil expected in August. On July 1, the FPSO moved from the Keppel yard to its offshore anchorage where deep water commissioning and trials were completed. The FPSO is now on tow to the Chim Sao field for the installation of the umbilicals that will connect it to the production wells.

The Gajah Baru project in Indonesia is progressing ahead of schedule. The Central Processing Platform topsides were installed on the jacket on July 6 and the bridge linking this to the wellhead platform was installed on July 7. Elsewhere on Block A, EPCI technical bids have been received and are under evaluation for the Anoa Phase 4 Development which will add additional compression capacity on the Anoa platform. In addition, the Front End Engineering and Design has been completed for the facilities and pipelines for the Pelikan and Naga fields. These projects are on target for sanction in the fourth quarter of 2011.

In North Sumatra, discussions with the shortlisted facilities EPCI bidders are under way. Technical bids are due in by September and final contract award is expected by year end. First gas on Block A Aceh remains on target for late 2013.

North Sea

The Huntington development in the UK is progressing, with work continuing on the Sevan Voyager FPSO upgrade project and sub-contracted modules. Timing for sail away (and therefore first oil) is likely to be impacted by the current financial situation of the FPSO supplier. Any material delay in the Huntington project will impact the average production for 2012 and the date at which a run-rate of 75 kboepd is achieved. In the meantime, key subsea equipment is on order and an installation contract has been signed. Development drilling commenced in April and is proceeding well.

An agreement for the Rochelle area has been executed with Premier acquiring a 15 percent equity in the unitised East and West Rochelle projects. First gas is anticipated for the fourth quarter of 2012. As previously announced, a Sale and Purchase Agreement for the Solan field was signed in May and Premier will become the development operator of the field at sanction with a 60 percent equity interest. Pre-sanction activities are progressing with final project approval targeted for later this year.

Development concept selection for Fyne is expected by year end, after the East Fyne appraisal well has been drilled. Discussions are ongoing with partners regarding potential development solutions for the Catcher Area. In Norway, development plans for the Froy field received Premier support for moving to the next phase. However, the operator has indicated that, due to limited resources and commitments elsewhere, they will not be proceeding with the project at this time. As a result, discussions with third party new entrants to the Froy project are underway. Dialogue also continues with the preferred contractor for the Bream field development regarding the timing of the FPSO availability.

Exploration and appraisal

Around 20 exploration and appraisal wells are planned during the next 12 months, with unrisked net prospective resource potential, on a P50 basis, of around 300 mmboe. Several of the planned wells for the first half of 2012 remain subject to partner approvals and government consents.

North Sea

As previously announced, the Grosbeak well in Norway was spudded in April 2011 and has now been sidetracked. The results of the sidetrack, which reached target depth on July 7, are anticipated later in July. Premier plans to drill its first operated well in Norway, the Gardrofa exploration well, in the third quarter of 2011.

Premier has signed a Heads of Agreement (HOA) with Antrim Energy to gain additional acreage in the Greater Fyne Area. Under the HOA, Premier will earn a 50 percent working interest in the acreage in return for funding a promoted share of the costs to drill a well on the Erne Prospect, which is planned for the third quarter. The Erne well will target an Eocene Tay Formation oil prospect located between the Fyne and Guillemot NW fields in the UK Central North Sea. A successful Erne exploration well will be taken into account for the Fyne development concept selection targeted for year end.

Separately the East Fyne appraisal well is now planned for the fourth quarter, using the Sedco 704 semi-submersible rig, the results of which - along with the results of the Erne exploration well - will feed into the Fyne development concept process. The Sedco 704 will then move to spud the Bluebell well, a prospect near to the Premier-operated Caledonia field and the Balmoral facility.

The Stingray well (Premier interest, 50 percent), which is scheduled for the first half of 2012, is targeting a Jurassic sandstone reservoir in UK Block 15/13b. In UK Block 28/9, the Joint Venture partners have decided to acquire 3D seismic data over the block in the second half of 2011. As a result, the Carnaby well will now be drilled in the first half of 2012.

Asia

In Indonesia, on the Tuna Block, Gajah Laut Utara was plugged and abandoned in June with oil and gas shows. The Ocean General Rig has now moved to Belut Laut, which spudded on 4 July. The Belut Laut prospect is in a separate sub-basin to that of Gajah Laut Utara and is an independent test of the petroleum system on the Tuna acreage. The results of Belut Laut are expected in August.

Elsewhere in Indonesia the Benteng-1 well on the Buton licence is expected to be drilled in the first quarter of 2012. The Matang-1 well on Block A Aceh is also scheduled to be drilled in the first quarter of 2012. The Antareja Resources land rig, Antareja-8, has been contracted for Matang-1.

Pakistan

As previously announced, the K-27 exploration well was successful and will be tied back to the production facility by the end of the third quarter, delivering around 30 MMscfd (gross). The K-29 and K-30 exploration wells, together with Badhra-6 Parh, are planned for late 2011.

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Premier IDs O&G Shows at Indonesia's Tuna Block

- Premier IDs O&G Shows at Indonesia's Tuna Block

Monday, June 27, 2011
Premier Oil plc

Premier updated its exploration and appraisal operations in Norway, Indonesia and Pakistan.

Grosbeak, Norway (Premier 20%)

The Grosbeak well 35/12-4 S, which spudded on April 24, 2011, has completed the drilling and testing of the primary well bore and will now be sidetracked to further delineate the extent of the Jurassic oil accumulation. The sidetrack is expected to be completed by the end of July.

Gajah Laut Utara, Indonesia (Premier 65%)

In Indonesia on the Tuna block, the Gajah Laut Utara-1 exploration well has reached a total depth of 4,688 meters in pre-Tertiary basement and is being plugged and abandoned with oil and gas shows. Oil shows were reported throughout a 350 meter thick succession of interbedded sandstones and shales in the Oligocene. However, logs suggest that the majority of these Oligocene sandstones are tight. One zone was sampled and gas was recovered. The well also encountered good quality water wet reservoir rocks within the Miocene sequence and source rocks within the Oligocene. A working oil and gas petroleum system has therefore been established on the Tuna block. The Ocean General rig will now move to drill the Belut prospect. Belut Laut is located approximately 10 kilometers north-west of Gajah Laut Utara, in a separate sub-basin and is an independent test of the petroleum system on the Tuna acreage. The results of the Belut well are expected in early August.

K-27, Pakistan (Premier 15.79%)

The K-27 exploration well, which spudded on April 4, 2011 in the Kadanwari block, has been successful, testing gas with a flow rate of 51.3 MMscfd through a 56/64 inch choke. The operator (ENI) plans to tie the well to the production facility by the end of the third quarter, delivering around 30 MMscfd.

Simon Lockett, Chief Executive Officer, commented, "The Grosbeak appraisal has provided valuable information and we look forward to the results of the sidetrack confirming the size of the oil reserves in the field.

"The Gajah Laut Utara well is the first exploration well drilled by Premier in the Tuna acreage and established the presence of a working petroleum system. We look forward to the results of drilling the Belut Laut prospect.

"In Pakistan, the K-27 test results are extremely positive providing additional resources and near term production to the Kadanwari asset."

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Premier Snatches Stake in Wytch Farm

- Premier Snatches Stake in Wytch Farm

Monday, June 20, 2011
Premier Oil plc

Premier has agreed to acquire an interest of 17.715 percent in Wytch Farm (the "Wytch Farm Assets") for an initial cash consideration of $96 million. This follows a pre-emption notice received from BP on May 18, 2011. Premier intends to finance the acquisition from available cash resources.

The proposed transaction will increase Premier's interest in the Wytch Farm Assets from 12.38 percent to an aggregate 30.1 percent, adding approximately 12.5 mmboe of 2P and 2C reserves and resources as at 1 January 2011. The field is currently producing approximately 13,000 boepd (gross). Premier will support the transition of operatorship to Perenco UK Limited ("Perenco"), which will on completion of the transaction hold a 50.1 percent interest in the Wytch Farm Assets.

The acquisition is in line with Premier's stated strategy of acquiring high-quality assets in existing core areas and utilises its strong balance sheet. It provides an attractive opportunity to increase Premier's existing interests in a material package of producing oil assets with significant upside potential.

Background

On May 17, 2011, BP announced that it had reached an agreement with Perenco to dispose of its approximately 68 percent interest in a portfolio of onshore and offshore assets in Dorset, including licenses PL089 and P534 and associated tax allowances relating to Wytch Farm for a consideration of up to $610 million. Under the terms of the operating agreements over the Wytch Farm Assets (the "JOAs"), Premier has certain pre-emption rights in the event of a sale to a third party.

Premier has notified BP that it wishes to acquire an interest of 17.715 percent in the Wytch Farm Assets. Premier has also entered into an agreement with Perenco setting out the basis on which the acquisition of the Wytch Farm Assets will be carried out as between Premier and Perenco, including the basis on which tax allowances will be allocated.

Principal terms of the arrangements

Under the arrangements, Premier will pay an initial consideration of $96 million to acquire a 17.715 percent interest in the Wytch Farm Assets. Further payments of up to approximately $14.4 million in aggregate will be payable if the Secretary of State for Energy and Climate Change approves a field development in respect of the Beacon discovery located within block 98/7a and/or in accordance with an agreed methodology relating to the average oil price between 2011 and 2013. Premier will pay a deposit of approximately $86.5 million.

The acquisition is conditional upon satisfaction of certain customary conditions, which include: (a) various third party consents being obtained; (b) the consent of the Secretary of State for Energy and Climate Change to the assignment of the licences and to the appointment of the new operator of the assets; and (c) the amendment of certain planning consents relating to the Wytch Farm Assets.

Subject to JOA partner approval, Perenco will operate the Wytch Farm Assets from completion of the acquisition.

Premier is being advised by Deutsche Bank AG.

Simon Lockett, Chief Executive, commented, "We are pleased to have this opportunity to increase our equity stake in one of our quality core producing assets to over 30 percent. In addition, it allows us to make efficient use of Premier's large existing pool of tax allowances. We look forward to working with Perenco to deliver maximum value from Wytch Farm."

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Premier Signs SPA for Solan Field Development

- Premier Signs SPA for Solan Field Development

Tuesday, May 31, 2011
Premier Oil plc

Premier has signed the sale and purchase agreement (SPA) with Chrysaor to acquire equity in License P164 in order to participate in the development of the Solan field in the UK for an upfront consideration of US $10 million, with US $10 million to follow upon sanction as well as a partial development carry. Premier will hold 60% equity and become Development Operator.

Premier will provide a loan to fund Chrysaor's remaining share of the project costs, which will then be repaid by a cash sweep from a share of their revenue.

Project sanction is targeted for later this year.

Simon Lockett, Chief Executive, commented, "We look forward to adding Premier's project management skills to the significant work already put in by the Chrysaor team and together taking the Solan field through the development process."

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Premier to Plug, Abandon Well at Vietnam Block

Premier to Plug, Abandon Well at Vietnam Block

Thursday, April 28, 2011
Pan Pacific Petroleum NL

Premier Oil Vietnam South B.V. ("Premier"), the operator of the Block 07/03 Production Sharing Contract, has advised that the CRD-2X-ST appraisal well operations have been successfully completed and that the CRD-2X well will now be plugged and abandoned as planned.

The CRD-2X appraisal well was spudded by the semi-submersible drilling rig the Ocean General on Thursday, February 10. The well was planned to evaluate the oil and gas discovered in multiple stacked Miocene and Oligocene reservoir sands by CRD-1X in 2009 with the aim of reducing uncertainty in whether the CRD (Cá Rong Ðo) structure contains sufficient volumes to support a potential development. CRD-1X tested two zones in the Miocene sands which flowed oil at a combined rate of 3,265.4 BOPD plus 8.1 MMSCFD, through a 48/64" choke, with no water. However, it was not possible to flow test the Oligocene sands at that time.

CRD-2X reached a total depth of 3,785 m BRT on March 10, and following evaluation of the section by logging, drill stem tests of two
reservoir zones in the Oligocene section were conducted. The first zone tested flowed gas and condensate at rates of 9.7 MMSCFD and 870 BOPD respectively through a 40/64" choke. The second zone tested flowed gas and condensate at rates of 17 MMSCFD and 1730 BOPD respectively through a 56/64" choke. The total net condensate/gas pay in this well was 72m, a significant increase compared with the 17 m of net pay penetrated in the Oligocene section in the up dip CRD-1X well.

CRD-2X was subsequently sidetracked to further evaluate the distribution of hydrocarbons in the Miocene sands. This sidetrack well CRD-2X-ST reached its planned total depth of 3,340 m BRT in the Miocene section and intersected 18.3m of net oil pay in the Miocene sands. This compares with 34.4m of net oil pay intersected in the Miocene section in the up dip CRD-1X well, and 3.8m in the down dip CRD-2X well.

These well results, including strong flows from the Oligocene sands have provided important information that will assist in the assessment of the resource potential of the CRD structure. The Operator will now undertake further studies to determine the feasibility of a commercial development.

Partners in the Vietnam Block 07/03 are:

• Pan Pacific Petroleum (Vietnam) Pty Ltd 5% (a wholly owned subsidiary of Pan Pacific Petroleum NL)
• Premier Oil Vietnam South B.V. (Operator) 30%
• Vietnam American Exploration Company, LLC. 40% (a wholly owned subsidiary of Pitkin Petroleum Plc)
• PearlOil (Ophiolite) Ltd. 15%
• PetroVietnam Exploration and Production Corporation Ltd 10%

TD Reached at Premier's Ca Rong Do Appraisal

TD Reached at Premier's Ca Rong Do Appraisal

Monday, April 11, 2011
Premier Oil plc

Premier announced that the CRD-2X appraisal well in block 07/03 Vietnam has been drilled to a TD of 3785 meters MDRT, appraising the Miocene sands discovered in 2009 with the CRD-1X well.

The well was deepened from the preliminary TD of 3109 meters MDRT to evaluate the Oligocene which was not tested by the CRD-1X well. Two drill stem tests of the hydrocarbon bearing sands in the Oligocene section have been conducted. The first zone tested flowed gas and condensate at rates of 9.7 mmscfd and 870 bopd respectively through a 40/64 inch choke. The second zone tested flowed gas and condensate at rates of 17 mmscfd and 1730 bopd respectively through a 56/64 inch choke.

The well will now be sidetracked to further evaluate the distribution of hydrocarbons in the Miocene sands.

Simon Lockett, Chief Executive Officer, commented, "We are encouraged by the hydrocarbon flow rates from the Oligocene section in Ca Rong Do, which in addition to the previously proven Miocene reservoirs, provide further exploration upside across the area. We look forward to the result of the sidetrack well which will provide additional data to determine the hydrocarbon distribution in this part of the Ca Rong Do structure."

Premier to Steer North Sea Fyne Block

Premier to Steer North Sea Fyne Block

Monday, April 04, 2011

Antrim Energy Inc.

Antrim announced that Premier has provided notice that it has elected to drill the East Fyne well under the Joint Venture and Earn-In Agreement with Antrim, previously announced October 6, 2010.

The East Fyne well is an appraisal well designed to de-risk the eastern extent of the Fyne Field in Block 21/28a UK Central North Sea, and is expected to be drilled before the end of 2011. Under the conditions of the previously announced transaction, the well will be drilled at no cost to Antrim and the cost of drilling, completion and/or abandonment deducted from Premier's carried contribution of up to $50 million assigned to offset all or a portion of Antrim's development expenses to bring the Fyne Field to production.

This election by Premier results in the transfer of a 39.9% working interest and operatorship of the Fyne Block 21/28a from Antrim to Premier. Antrim retains a 35.1% working interest in the block, with First Oil Expro Limited holding the remaining 25% working interest. The license assignment and transfer of operatorship under the Agreement is subject to partner approval and to the usual UK government approvals.

The Fyne Block 21/28a was assigned gross proved plus probable reserves of 23.3 million barrels of oil by independent engineering consultants McDaniel & Associates Consultants Ltd. as at Dec. 31, 2010. The Fyne Field is situated immediately west-southwest of the Guillemot group of oil fields, which have produced in excess of 70 million barrels of oil to date. Fyne is also located approximately 35 kilometres north of the recently announced Catcher and Burgman oil discoveries in Block 21/9, both of which have reservoirs of comparable age with those in the Fyne Field.

Drilling of the East Fyne well will be in addition to Antrim's recently announced drilling plans for two exploration wells in the Greater Fyne Area, the West Teal and Carra wells (Antrim 100%). Premier retains a right to participate up to 50% in the Greater Fyne Area exploration program, which is due to commence mid-year 2011.

Premier Oil Sees Tax Allowance Offsetting UK North Sea Tax Hike

Premier Oil Sees Tax Allowance Offsetting UK North Sea Tax Hike

Thursday, March 24, 2011
by  Alexis Flynn

U.K. government plans to raise taxation on North Sea oil and gas production are unlikely to have a significant impact on Premier's earnings for at least the next four years, as its effects will be mitigated by $1.1 billion in tax allowances from a 2009 acquisition, Premier Oil Chief Executive Simon Lockett said Thursday.

"We're not immune, but we are mitigated from the effects of this kind of situation," said Lockett.

The Chancellor of the Exchequer of the U.K. Wednesday announced plans to raise the supplementary charge levied on profits from oil and gas produced in the U.K. to 32% from the previous 20% level. Premier said it is insulated against the effects of the levee because of a tax allowance the company received when it bought explorer Oilexco's North Sea operations in 2009,

Shares in several small-and mid-cap producers with significant assets in the North Sea were sharply lower in the wake of yesterday's news. U.K. continental shelf-focused EnQuest's stock fell 12% Wednesday, while peer Nautical lost 9%. Although Premier Oil shares fell 4.6% on the news, they have since recovered much of the lost ground. At 1248 GMT, Premier Oil shares were up 0.6 pence, or 3.2%, at 1973p amid a broadly higher London market and after reporting earnings Thursday that beat forecasts.

Premier Oil's 2009 deal to buy Oilexco's North Sea assets included it assuming $1 billion of losses that can be written off against the tax, of which it can use about 25% -- around $250 million -- a year.

Deutsche Bank said in a note that these allowances could shelter Premier from the U.K. cash tax until at least 2014, adding that it sees "these tax increases as presenting Premier with growth opportunities, not just value risk." It recommends the stock as 'buy' with a 2275 pence price target.

The oil and gas producer, which also has significant interests in Vietnam and the Middle East, Thursday reported record net profits of $130 million, 15% higher than consensus analyst estimates. The company also said it was on track to reach production of 75,000 barrels of oil equivalent per day and expects to spend $500 million a day on acquisitions this year.

Lockett said a positive consequence of yesterday's budget announcement was that it could provide buying opportunities as peers come under further cost pressure as a result of the tax rise.

"If I can take one minor positive out of it, it means that if we were looking for acquisitions in the North Sea then they are now slightly cheaper than yesterday," said Lockett.

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