Antrim Reports Financial, Operational Results for 1Q11

Antrim reported its financial and operational results for the three month period ended March 31, 2011.

All financial figures are unaudited and in US dollars unless otherwise noted

HIGHLIGHTS:

  • Antrim to drill three wells in the UK North Sea
  • Joint venture with Premier Oil on the Fyne Field proceeding
  • Heads of Terms export agreement signed for Causeway oil production
  • Average gas price in Argentina increased 12% to $2.08 per mcf
  • Antrim raised Cdn $48.5 million from equity financing
  • Current cash position of $76 million and no bank debt

In the first quarter 2011, average production in Argentina was 1,640 barrels of oil equivalent per day ("boepd") compared to 1,835 boepd in the first quarter 2010. The decline in production is attributable to the sale of the Puesto Guardian property in February 2010, as well as scheduled gas plant maintenance and service rig repairs in Tierra del Fuego.

Oil and gas revenue, net of royalties, was $2.4 million for the three months ended March 31, 2011 compared to $2.7 million for the same period in 2010. Net revenue decreased as a result of lower oil and gas sales partially offset by higher oil and gas prices received. Antrim generated cash flow from operations of $0.6 million for the three months ended March 31, 2011 compared to a cash flow deficiency of $0.2 million for the same period in 2010.

Antrim's average gas price for the first quarter of 2011 was $2.08 per mcf compared to $1.85 per mcf for the same period in 2010, a 12% increase. For the first quarter, oil prices averaged $55.00 per barrel compared to $46.54 per barrel for the same period in 2010, an 18% increase.

On April 5, 2011, Antrim announced that a Heads of Terms agreement had been signed for the export of Causeway crude oil to the Cormorant North production platform. The Cormorant North platform is operated by TAQA Bratani Limited and is located approximately 15 km west of the Causeway Field.

On April 4, 2011, Antrim announced that Premier Oil UK Limited ("Premier") had elected to drill the East Fyne well under the Earn-In Agreement ("EIA") previously announced on October 6, 2010. The well is an appraisal well designed to de-risk the eastern extent of the Fyne Field and is expected to be drilled before the end of 2011. Under the terms of the EIA, Antrim will be carried for all development expenses, including the East Fyne drilling costs, up to $50 million.

On March 28, 2011, Antrim announced that it had signed a Letter of Award ("LOA") to provide well project management and drilling services for two wells commencing in the third quarter of 2011.

On March 17, 2011, Antrim issued 48,191,700 common shares at a price of Cdn $1.07 per common share for gross proceeds of Cdn $51.6 million (net proceeds Cdn $48.5 million) which included 6,191,700 common shares issued to the underwriters pursuant to the 98.3% exercise of the over-allotment option. Net proceeds from the equity financing will be used for exploration of the Greater Fyne Area including the West Teal Prospect and either the Carra or Erne Prospects.

OVERVIEW OF OPERATIONS

United Kingdom

Fyne Field

On April 4, 2011, Antrim announced that Premier had elected to drill the East Fyne well in the Fyne Field in P077 Block 21/28a (the "Fyne License") under the EIA signed in October 2010. The appraisal well is designed to de-risk the eastern extent of the Fyne Field and is expected to be drilled in the third quarter of 2011. The well will be drilled at no cost to Antrim and the cost of drilling, completion and/or abandonment will be deducted from Premier's $50 million carried contribution.

The election by Premier resulted in the transfer of a 39.9% working interest and operatorship of the Fyne License from Antrim to Premier, with Antrim retaining a 35.1% working interest.

The Fyne License expires on November 25, 2011. The UK Department of Energy and Climate Change ("DECC") has agreed to a three year extension on the condition that a Field Development Plan ("FDP") is submitted by December 25, 2011 or by June 25, 2012 if the East Fyne appraisal well is drilled on the license prior to expiry in November 2011.

Antrim is continuing to work with Premier on the identification of alternative export routes. The preferred production system will handle up to 20,000 barrels of oil per day ("bopd") directly from the Fyne Field, with potential capacity add-ons to handle additional volume from satellite fields. First production is anticipated in the middle of 2013.

The EIA also provides Premier with the option to participate at a "promoted" 20% to 50% working interest alongside Antrim in a planned drilling program on Antrim's 100% licenses surrounding the Fyne Field (the "Greater Fyne Area").

Greater Fyne Area

In addition to the Fyne development, Antrim has identified several high priority drilling prospects on Antrim licenses surrounding the Greater Fyne Area. Initial drilling targets are expected to be the West Teal Upper Jurassic Fulmar Prospect, at 10,400 feet true vertical depth, in P1625 Block 21/24b, the Carra Eocene Tay Prospect in P1563 Block 21/28b at 5,000 feet drilling depth, and the Erne Tay Prospect in P1875 Block 21/29d at 5,600 feet drilling depth. The West Teal Prospect contains a discovery well drilled by a previous operator in 1991 that was subsequently abandoned after encountering mechanical problems.

Antrim signed a LOA for project management and drilling services for two wells commencing in the third quarter of 2011. The estimated duration for the drilling of the two wells is 50 days, not including testing. Antrim completed the site survey work over the West Teal, Carra and Erne Prospects in April 2011. Premier retains a right to participate up to 50% in the Greater Fyne Area exploration program.

Antrim announced on October 28, 2010 that two new licenses were offered to Antrim by DECC in the UK 26th Seaward Licensing Round. License documents were executed, effective January 10, 2011, for P1875 Block 21/29d (Antrim 100%) located in the Greater Fyne Area, and P1784 Block 21/7b (Premier 70%, Antrim 30%) located north of the Greater Fyne Area. Both blocks contain additional drilling prospects, which are currently being evaluated.

Causeway Field

In March 2010, Antrim signed a Conditional Letter Agreement ("CLA") with Valiant Petroleum plc ("Valiant") to sell a 30% interest in P201 Block 211/22a South East Area and P1383 Block 211/23d (the "Causeway Licenses"). In return, Antrim will receive up to $21.75 million towards its remaining working interest share of development costs of the Causeway Field. Completion of the transaction is subject to several conditions, including sanction of a FDP and the consent of DECC.

As part of the transaction, Antrim transferred operatorship of the licences to Valiant. Following completion of the transaction, Antrim will retain a 35.5% working interest in the Causeway Licenses.

On April 5, 2011, Antrim announced that a non-binding Heads of Terms agreement had been signed for the export route of Causeway crude oil to the Cormorant North production platform. The Cormorant North platform is operated by TAQA Bratani Limited and is located approximately 15 km west of the Causeway Field.

Antrim and Valiant are currently discussing the FDP to be submitted to DECC with respect to the Causeway Field. Among the items being discussed is Valiant's estimate of reserves associated with Phase II and later production phases of the field, which may be lower than that of Antrim and its independent reserve evaluator McDaniel & Associates Consultants Ltd. Such discussions are at a preliminary stage and subject to finalization as the process of preparing the FDP evolves. Antrim expects that a finalized FDP will be submitted to DECC with a target of achieving first production in the middle of 2012.

Argentina

Antrim completed a ten (net 2.5) well drilling program on its Tierra del Fuego Concessions in southern Argentina in 2010. The program targeted the liquid-rich gas bearing sandstone reservoirs of the Springhill Formation in the Los Flamencos Field. Of the ten wells drilled, eight were cased for production and two were plugged and abandoned. Three cased wells were completed and tied-in in 2010. Of the remaining five wells, four have recently been fracture stimulated. Three wells flowed gas and are currently going through a cleanup period before final testing. The fourth well tested oil and has been put on pump for cleanup and test. The remaining cased well will be fracture stimulated later in 2011. With the stimulation and tie-in of the four wells, Antrim's daily production is expected to average approximately 1,750 boepd in 2011.

Antrim's average gas price for the first quarter of 2011 was $2.08 per mcf compared to $1.85 per mcf for the same period in 2010, a 12% increase. In the first quarter of 2011, oil prices averaged $55.00 per barrel compared to $46.54 per barrel for the same period in 2010, an 18% increase.

Antrim sells all of its oil production and approximately 81% of its natural gas production from Tierra del Fuego to the Argentine mainland. These sales generate value-added tax ("VAT") of 21%, which is retained by Antrim due to favourable tax laws pertaining to Tierra del Fuego. VAT of $0.5 million (2010 - $0.4 million) is reported as other income and is not included in Antrim's per unit sales prices.

Antrim's field netbacks in Argentina, based on sales, were $8.96 (2010 - $7.86) per boe for the three month periods ended March 31, 2011. The increase in the 2011 field netbacks, as compared to 2010, was due to the lower operating costs partially offset by a higher proportion of gas to oil sales.

The Company applied for "Gas Plus" pricing incentives for new gas that will be produced from the wells drilled in 2010. The submission has received a favorable technical review and Antrim is now awaiting final government approval. If approved by the federal authorities, this will permit Antrim to sell a portion of its gas in the higher-priced industrial market on the mainland.

In December 2010 Antrim entered into an agreement to acquire a 50.1% interest in and operatorship of the 307,215 acre Cerro de Los Leones Exploration Concession, located in Argentina's Neuquén Basin. Cerro de Los Leones is situated in the northern portion of the Neuquén Basin in the Province of Mendoza. The existing 2-D seismic coverage of 700 km provides regional control and has identified numerous lower Tertiary and Cretaceous structural and stratigraphic leads at drilling depths of between 5,000 and 8,200 feet. Antrim continues to work on obtaining the necessary environmental approvals to shoot a 3-D seismic program in the second half of 2011. At least one exploration well is planned for the latter part of 2011.

Antrim's Argentine operations are self-sustaining thereby enabling the Company to evaluate other opportunities in Argentina using the cash flow generated from the Tierra del Fuego properties.

Tanzania

In December 2010, two agreements were signed in Tanzania which are expected to lead to the resumption of exploration activities on the production sharing agreement for the Pemba-Zanzibar exploration license offshore and onshore Tanzania (the "P-Z PSA"). Antrim holds an option for a 20% carried interest in the P-Z PSA through the pre-drilling phase and an additional 10% option to be exercised up to 180 days following receipt of the initial drilling results. The carried interests would be repaid from future production. The P-Z PSA has been in a state of effective force majeure for several years due to a dispute between the federal government of Tanzania and the provincial government of Zanzibar regarding revenue sharing, and access to the license area for petroleum exploration activities has been blocked. RAK Gas, the operator, is currently drafting a revised work program for the P-Z PSA for submission to the government of Tanzania.

Outlook

Antrim expects to have a FDP for the Causeway Field submitted and approved in 2011 for an anticipated production startup in the middle of 2012. Production startup from the Fyne Field is anticipated in the middle of 2013.

In 2011, Antrim will use its strong financial position to take a leading role in the exploration of the Greater Fyne Area. The drilling program is scheduled to begin in the third quarter with a well drilled to test a Jurassic Fulmar oil prospect. The well is expected to take 55 days to drill and test and cost approximately $30 million.

An additional exploration well in the Greater Fyne Area is expected to be drilled to test an Eocene Tay oil target. The well is expected to take 19 days to drill, at an estimated cost of $12 million.

An East Fyne appraisal well is also scheduled to be drilled on the Fyne Field in the third quarter 2011. This well is intended to de-risk the eastern extent of the Fyne Field and will extend the submission deadline of the FDP for Fyne to June 25, 2012. Antrim together with its partners, continues to work towards identifying the most attractive export route for future oil production from the Fyne Field. Under the terms of the EIA, Antrim's costs up to $50 million are paid by Premier.

In Argentina, Antrim's focus will be on the recently acquired Cerro de Los Leones Exploration Concession (Antrim 50.1% and operator) in the Neuquén Basin. A 3-D seismic program will be shot to support the drilling of at least one exploration well on the license in 2011. Cash flow from Antrim's expected 1,750 boepd from Tierra del Fuego will be used to support this exploration program.

In East Africa, Antrim holds an option to participate up to 30% working interest in an exploration program on the Tanzanian P-Z PSA. This region has recently experienced a significant increase in exploration activity, with several major discoveries announced by Anadarko and British Gas. The P-Z PSA has been in an effective force majeure for several years. Antrim expects this impasse could be resolved with the recently announced agreement signed with RAK Gas LLC, a UAE–based exploration and production company with interests elsewhere in Tanzania.

Antrim also considers other global exploration opportunities and views its bilateral strategy of balancing longer term and capital-intensive investments in the UK North Sea with shorter investment cycle on-shore exploration and production opportunities as central to its corporate development.

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