Ithaca Energy Inc.
AIM : IAE
TSX VENTURE : IAE

Ithaca Energy Inc.

June 27, 2011 02:12 ET

Ithaca Energy Inc.: Q1 2011 Financial Results, Jacky (J01) Well Update and Production Guidance Q2 2011 and Full Year 2011

Profit before tax US$13 million

LONDON, UNITED KINGDOM and CALGARY, ALBERTA--(Marketwire - June 27, 2011) -

NOT FOR DISTRIBUTION TO U.S. NEWSWIRE SERVICES OR FOR DISSEMINATION IN THE UNITED STATES

Ithaca Energy Inc. ("Ithaca" or "the Company")(AIM:IAE)(TSX VENTURE:IAE) announces its financial results for the three months ended March 31, 2011.

HIGHLIGHTS - For the three months ended March 31, 2011

Financial

  • Profit before tax US$13.0 million (Q1 2010: US$12.1 million)
  • Cashflow from Operations of US$22.1 million (Q1 2010: US$19.6 million)
  • Cash US$198.9 million, inclusive of US$7.6 million restricted cash (Q4 2010: US$201.9 million)
  • Undrawn US$140 million senior debt facility
  • Tax losses of US$221 million (Q4 2010 $216 million)
  • Results and comparatives are now reported under International Financial Reporting Standards ("IFRS")

Operational

  • Sales averaged 3,493 barrels of oil equivalent per day ("boepd") net to Ithaca over the period to March 31.
  • Successfully completed the drilling of the water injection well for the Athena field and commenced drilling of the final production well (drilling was successfully concluded post period end)
  • Significant progress made on modification and recertification works of the Athena FPSO vessel "BW Athena" following arrival in a Dubai shipyard. The works are on schedule and anticipated to be completed in Q3 2011 ahead of first production in Q4 2011.

Corporate

  • Lawrie Payne, Non-Executive Chairman of the Board, retired from the Board of Directors. Jack C. Lee assumed the position of Non-Executive Chairman of the Board.

SIGNIFICANT POST Q1 EVENTS

  • Entered into an agreement to acquire a 28.46% non-operated interest in the Cook oil field from Hess Limited ("Hess") for a consideration of $62.5 million and the transfer from Ithaca to Hess of a 10% interest in each of exploration blocks 42/25b, 43/16a and 43/21c in the Southern North Sea (the "Cook Acquisition"). The transaction is expected to complete in Q3 2011 with an effective date of January 1, 2011. Sproule International Limited subsequently confirmed management's estimate of Cook Proved plus Probable ("2P") reserves of 5.75 mmboe.
  • Signed an earn in agreement with Challenger Minerals (North Sea) Limited ("CMI") to drill an appraisal well on the Hurricane discovery. Subject to agreeing 'turnkey' terms for the provision of a drilling rig and well management services, CMI will pay 40% of gross Hurricane initial appraisal well costs in exchange for a 31% equity interest in Block 29/10b. In addition, upon successful appraisal, CMI will pay 40% of gross costs of a drill stem well test of any sidetrack.
  • The Electrical Submersible Pump ("ESP") units in the Jacky production well, J01, encountered faults, requiring the ESP units to be replaced. A rig based workover ESP replacement and reperforation operation was undertaken which has recently been completed and J01 production, under ESP support, has been reinstated. The Company will report J01 production rates once production is fully stabilized and the well flow has completely cleaned up.
  • Drilling of the Jacky J03 well was suspended due to the well encountering a smaller than anticipated oil column in the Beatrice 'A' Sand reservoir. Technical work is ongoing to determine whether to re-enter the well and complete it as a water injector to maximise oil recovery from the Jacky field.
  • Development drilling on the Athena field was completed with the conclusion of drilling on the final production well. The rig is currently in the process of batch completing all five development wells. First oil is on schedule for Q4 2011 at 22,000 bopd (gross) and the project remains on budget. The FPSO is in dry dock with modification and recertification works well advanced. The vessel has been successfully separated for installation of a turret docking section which has been welded into the structure amidships.

PRODUCTION UPDATE

As a result of the Jacky well issues highlighted above, average daily production from existing assets in Q2 2011 is expected to be approximately 2,100 boepd. With less than 4 days remaining in the quarter no further production update will be announced ahead of the Q2 Financial Results which are expected to breakeven or possibly show a small loss for the quarter.

Although Ithaca benefits from the production associated with the Cook Acquisition from January 1, 2011, the production reported for Q1-2011 and the forecast for Q2-2011 highlighted above exclude such volumes. Adding anticipated Cook volumes from January 1, 2011 to that of the existing assets, full year production is forecast to be approximately 5,000 boepd, with a forecast 2011 exit rate of around 10,000 boepd following first oil from the Athena field.

Looking ahead, the Company expects to update its longer range production profiles once it has first production from the Athena field, closed the Cook Acquisition, and submitted its FDP on the Stella development.

Iain McKendrick, CEO, commented,

"Despite the short term set-backs that caused production shortfalls on Jacky in the first half of the year, Q1 has delivered a strong set of results. With completion of the Cook acquisition and Athena first oil in the second half of 2011 the vulnerability of the company's production to single well upsets has been addressed. This reduction of risk concentration will continue as we look to add further quality production acquisitions. With J01 production now restored, we look forward with confidence to first oil on Athena following the successful drilling program and the excellent progress being made elsewhere on the project."

Notes:

Further details on the above are provided in the Interim Consolidated Financial Statements and Management's Discussion and Analysis for the three months ended March 31, 2011, below which have been filed with securities regulatory authorities in Canada. These documents are also available on the System for Electronic Document Analysis and Retrieval at www.sedar.com and on the Company's website: www.ithacaenergy.com.

Notes to oil and gas disclosure:

In accordance with AIM Guidelines, Hugh Morel, BSc Physics and Geology (Durham), PhD Hydrogeology (London) and senior petroleum engineer at Ithaca Energy is the qualified person that has reviewed the technical information contained in this press release. Dr Morel has 30 years operating experience in the upstream oil industry.

About Ithaca Energy:

Ithaca Energy Inc. and its wholly owned subsidiary Ithaca Energy (UK) Limited ("Ithaca" or "the Company"), is an oil and gas exploration, development and production company active in the United Kingdom's Continental Shelf ("UKCS"). The goal of Ithaca, in the near term, is to maximize production and achieve early production from the development of existing discoveries on properties held by Ithaca, to originate and participate in exploration and appraisal on properties held by Ithaca when capital permits, and to consider other opportunities for growth as they are identified from time to time by Ithaca.

NOT FOR DISTRIBUTION TO U.S. NEWSWIRE SERVICES OR FOR DISSEMINATION IN THE UNITED STATES

Forward-looking statements

Some of the statements in this announcement are forward-looking. Forward-looking statements include statements regarding the intent, belief and current expectations of Ithaca Energy Inc. or its officers with respect to various matters including, but not limited to future production levels and the benefits of the Cook Acquisition. When used in this announcement, the words "anticipate", "continue", "estimate", "expect", "may", "will", "project", "plan", "should", "believe", "could", "target" and similar expressions, and the negatives thereof, are intended to identify forward-looking statements. Such statements are not promises or guarantees, and are subject to known and unknown risks and uncertainties and other factors that may cause actual results or events to differ materially from those anticipated in such forward-looking statements or information. Please refer to the risk factors affecting Ithaca as set out in the Company's Annual Information Form and the Company's Q1 MD&A filed on SEDAR at www.sedar.com. These forward-looking statements speak only as of the date of this announcement. Ithaca Energy Inc. expressly disclaims any obligation or undertaking to release publicly any updates or revisions to any forward-looking statement contained herein to reflect any change in its expectations with regard thereto or any change in events, conditions or circumstances on which any forward-looking statement is based except as required by applicable securities laws.

The term "boe" may be misleading, particularly if used in isolation. A boe conversion of 6 Mcf: 1 bbl is based on an energy equivalency conversion method primarily applicable at the burner tip and does not represent a value equivalency at the wellhead.

ITHACA ENERGY INC.

MANAGEMENT'S DISCUSSION AND ANALYSIS

FOR THE QUARTER ENDED MARCH 31, 2011

The following is management's discussion and analysis ("MD&A") of the operating and financial results of Ithaca Energy Inc. (the "Corporation" or "Ithaca" or the "Company") for the three months ended March 31, 2011. The information is provided as of June 27, 2011. The first quarter 2011 results have been compared to the results of the comparative period in 2010. This discussion and analysis should be read in conjunction with the Corporation's unaudited consolidated financial statements as at March 31, 2011 and with the Corporation's audited consolidated financial statements as at December 31, 2010 together with the accompanying notes, MD&A and Annual Information Form ("AIF") for the 2010 fiscal year. These documents and additional information about Ithaca are available on SEDAR at www.sedar.com.

Certain statements contained in this MD&A, including estimates of reserves, estimates of future cash flows and estimates of future production as well as other statements about future events or anticipated results, are forward-looking statements. The forward-looking statements contained herein are based on assumptions and are subject to known and unknown risks, uncertainties and other factors. Should the underlying assumptions prove incorrect or should one or more of these risks, uncertainties or factors materialize, actual results may vary significantly from those expected. See "Forward-Looking Information", below.

All financial data contained herein is presented in accordance with International Financial Reporting Standards ("IFRS") and is expressed in United States dollars ("$"), unless otherwise stated. All comparative figures for 2010 have been restated to be in accordance with IFRS.

BUSINESS OF THE CORPORATION

Ithaca is an oil and gas exploration, development and production company active in the United Kingdom's Continental Shelf ("UKCS"). The goal of Ithaca, in the near term, is to maximize production and achieve early production from the development of existing discoveries on properties held by Ithaca, to originate and participate in exploration and appraisal on properties held by Ithaca when capital permits, and to consider other opportunities for growth as they are identified from time to time by Ithaca.

The Corporation's common shares are listed for trading on the TSX Venture Exchange and the Alternative Investment Market of the London Stock Exchange under the symbol "IAE".

NON-GAAP MEASURES

'Operating costs per boe' referred to in this MD&A are not prescribed by IFRS. This non-GAAP financial measure does not have any standardized meaning and therefore is unlikely to be comparable to similar measures presented by other companies. Ithaca includes operating costs per barrel data because investors may use this information to analyze operating performance. The additional information should not be considered in isolation or as a substitute for measures of performance prepared in accordance with GAAP. See "Results of Operations" section for details.

'Cashflow from operations' referred to in this MD&A is not prescribed by IFRS. This non-GAAP financial measure does not have any standardized meaning and therefore is unlikely to be comparable to similar measures presented by other companies. The Corporation uses this measure to help evaluate its performance. As an indicator of the Corporation's performance, cashflow from operations should not be considered as an alternative to, or more meaningful than, net cash from operating activities as determined in accordance with IFRS. The Corporation's determination of cashflow from operations does not have any standardized meaning and therefore may not be comparable to similar measures presented by other companies. The Corporation considers cashflow from operations to be a key measure as it demonstrates the Corporation's ability to generate the cash necessary to fund operations and support activities related to its major assets. Cashflow from operations is determined by adding back changes in non-cash operating working capital to cash provided by operating activities.

BOE PRESENTATION

The calculation of barrels of oil equivalent ("boe") is based on a conversion rate of six thousand cubic feet of natural gas ("mcf") to one barrel of crude oil ("bbl"). The term boe may be misleading, particularly if used in isolation. A boe conversion ratio of 6 mcf: 1 bbl is based on an energy equivalency conversion method primarily applicable at the burner tip and does not represent a value equivalency at the wellhead.

HIGHLIGHTS FIRST QUARTER 2011

Ithaca achieved the following highlights during the first three months of 2011.

Financial

  • Profit before tax of $13.0 million (Q1 2010 $12.1 million)
  • Cashflow from operations of $22.1 million (Q1 2010 $19.6 million)
  • Cash of $198.9 million, inclusive of $7.6 million restricted cash (Q4 2010 $201.9 million)
  • Tax losses attributable to upstream oil and gas activities of $221 million (Q4 2010 $216 million)

Profit before tax in Q1 2011 rose compared to the prior year, despite it being a period of significant issues. This was driven by rising realized average oil price of $111.19 / bbl ($79.95 / bbl in Q1 2010), income from the Anglia and Topaz gas fields acquired in December 2010, and foreign exchange gains on Sterling bank deposits.

The significant capital expenditure program, in combination with the strong operating cashflow resulted in a cash balance of $198.9 million at March 31, 2011.

Operational

Production

  • Average net sales were 3,493 boe per day (4,193boepd in Q1 2010). Net sales in the Greater Beatrice Area for Q1 were affected by mechanical issues with the drilling mud handling system on the Energy Enhancer, positioning of the Energy Enhancer over the J03 well and the requirement to retrofit an ESP in the Beatrice Alpha A28 workover well (see below for further discussion).

Athena

  • In January 2011, the Sedco 704 drilling unit anchored on location over the Athena field ready to commence campaign to drill a fourth production well, a water injector well and complete the three existing wells on the field as producers. Modification and recertification of the FPSO vessel "BW Athena" continued in a Dubai shipyard with works to re-certify existing equipment and install new equipment on the FPSO. All work is anticipated to be completed in Q3 2011 allowing the vessel to return to UK waters and arrive on location at Athena.
  • In February 2011, the Corporation successfully completed the drilling of the water injection well. The well exceeded the net reservoir requirements for water injection to support initial gross production, showed excellent average porosity across the reservoir section and tests indicated good fluid mobility in all selected sandstone units tested. The well was drilled down flank from three successful appraisal wells and was the first well of the campaign.
  • In March 2011 the Sedco 704 semi submersible drilling unit commenced the drilling of the final production well. The well was drilled from the Athena drill centre and was the final well to be drilled. The well was directionally drilled in the north west of the field and intersected the top reservoir (Top Scapa A sands). These drilling operations precede subsea equipment installation and hook-up of the BW Athena FPSO later in the year.

Jacky

  • In March 2011, the Energy Enhancer jack-up drilling unit commenced drilling on the second production well, J03. The well was drilled to access additional reserves and increase production as part of a field management strategy. The drilling unit was positioned over the Jacky platform to drill from an existing spare wellbay.
  • Mechanical issues were experienced on the drilling unit causing the suspension of drilling on the J03 well and an extension to the suspension of production from the J01 well that was necessary to complete the 'top hole section' of the J03 well (as is normal practice). Following successful repair to the drilling mud handling system onboard the rig and completion of the top hole section, production from the J01 well was reinstated by March 22, with the recommencement of drilling on the J03 well on the Jacky field on March 29.

Beatrice

  • In April 2011 the workover well A28 was partially completed and was free flowing at approximately 130 bopd gross (65 bopd net to Ithaca). Operations have transferred to the workover of the A21 well. On completion of the A21 well operations will transfer back to A28 to retrofit a downhole electric submersible pump ("ESP") to support production.

Corporate

  • In February 2011, Lawrie Payne, Non-Executive Chairman of the Board, notified the Corporation of his intention to retire from service of the Corporation and resigned from the Board of Directors effective February 22, 2011. Jack C. Lee succeeded Lawrie Payne as Non-Executive Chairman effective as of the same date.
  • In March 2011 Gemini Oil & Gas Fund II, L.P. ("Gemini") exercised all warrants granted by the Corporation in Q3 2010 to acquire 2,500,000 common shares of the Corporation at C$2.25 per share.
  • In March 2011, in order to benefit from the recent rise in oil price, Ithaca purchased a 'put option' with a floor price of $105 per barrel for 804,500 barrels of oil for the period March to December 2011. The put option delivers a minimum price on the specified volume of oil and leaves the Corporation to benefit from any oil price upside above $105 per barrel.

HIGHLIGHTS SUBSEQUENT TO QUARTER END:

  • In April 2011 the Corporation entered into an agreement to acquire a 28.46% non-operated interest in the Cook oil field and a 7.41% non-operated interest in the Maclure oil field from Hess Limited ("Hess") for a consideration of $74.5 million and the transfer from Ithaca to Hess of a 10% interest in each of exploration Blocks 42/25b, 43/16a and 43/21c in the Southern North Sea. The acquisition of Maclure was subject to pre-emption within 30 days of notification to other parties in the Maclure field. The Corporation commissioned Sproule International Ltd ("Sproule") to provide a Reserves Audit Opinion on Cook and Maclure. The transaction is expected to complete in Q3 2011 with an effective date of January 1, 2011.
  • In April 2011 the Corporation signed an earn in agreement with Challenger Minerals (North Sea) Limited ("CMI") on the Hurricane discovery. Under the terms of the agreement CMI has agreed to pay a share of the initial well costs in return for an option, exercisable within 90 days of abandonment or suspension of the initial appraisal and any sidetrack well, to acquire an interest in Block 29/10b. CMI will pay 40% of gross Hurricane appraisal well costs in exchange for a 31% equity interest in Block 29/10b, thereby carrying a part of Ithaca's share of all costs of drilling an initial appraisal well. In addition, upon successful appraisal, CMI will pay 40% of gross costs of a drill stem well test of any sidetrack. All additional costs, including those for planned sidetrack drilling, will be apportioned such that CMI will pay its 31% pro rata share. The transaction is subject to agreed 'turnkey' terms with ADTI for the provision of a suitable drilling unit and well management services.
  • In April 2011 both ESPs in the Jacky production well, J01, developed faults under routine operations, requiring the ESPs to be replaced. As a result the well was free flowing and gross production from the J01 well reduced to approximately 700 barrels of oil per day ("bopd") (approximately 335 bopd net to Ithaca); prior to this, under ESP support gross production was approximately 2,800 bopd (1,330 bopd net to Ithaca) as measured at the Nigg storage facility. The Corporation continued to free flow the J01 production well until the J03 well reached the target reservoir formation, the Beatrice "A" Sand. The Northern Enhancer rig was then utilised to undertake a workover operation to replace the failed ESPs in the J01 production well.
  • In April 2011, the Corporation purchased a further put option with a floor price of $115 per barrel for 300,000 barrels of oil. This put option also delivers a minimum price on the specified volume of oil and leaves the Corporation to benefit from any oil price upside above $115 per barrel.
  • In May 2011, the Corporation was notified that an exercising notice had been received in relation to the right of pre-emption held by each of the existing Maclure co-venturers. Subject to completed documentation being executed by Hess and any pre-empting parties, the interest in the Maclure field will be removed from the acquisition and the consideration will be adjusted to $62.5 million such that Ithaca shall acquire a 28.46% non-operated interest in the Cook field only.
  • In May 2011 Sproule completed its Reserves Audit Opinion on the Cook field. Management's view that the acquisition will increase the Corporation's remaining Proved plus Probable ("2P") reserves by 5.75 million barrels of oil equivalent ("mmboe") net to Ithaca as at January 1, 2011 was confirmed by Sproule as reasonable. Based on 5.75 mmboe of 2P reserves, the acquisition is priced at $10.87 per boe.
  • In May, 2011 the Corporation announced that the Jacky J03 well has been suspended having encountered a smaller than anticipated oil column in the Beatrice 'A' Sand reservoir. Technical work is ongoing to determine whether to re-enter the well and complete it as a water injector to maximise oil recovery from the Jacky field.
  • In May 2011, capital expenditure plans for 2011 were revised showing an increase from $120 million to $136 million mainly to cover the re-phasing of long lead items for the Stella project.
  • Following an announcement in December 2010 that North Sea Energy ("NSE") was seeking to withdraw from investing in the Jacky J03 well, Ithaca commenced proceedings in the High Court of Justice in London for a declaration that the Jacky J03 well is a joint operation. A court date for the proceedings has been set for April 19, 2012.
  • In June 2011, the final Athena production well completed drilling and was fully cased. The well encountered a considerable section of oil saturated net reservoir, with good porosities. Development drilling has now successfully concluded and the project remains on schedule for production start up in Q4 2011 at approximately 22,000 barrels of oil per day ("bopd") (gross), ~5,000 bopd (net to Ithaca). The drilling rig, Sedco 704, is now proceeding to run completion equipment and perforate the well, the three existing suspended production wells and the water injection well.
  • In June 2011, ongoing modification and recertification work on the FPSO BW Athena is well advanced. The vessel has been successfully separated for installation of a turret docking section which is currently being welded into the structure amidships. The vessel will be extended by approximately 65 feet. The FPSO will return to UK waters for 'hook up' to the turret mooring buoy by the end of Q3 2011.
  • In June 2011, the rig based workover ESP replacement and reperforation operation was successfully completed and J01 production, under ESP support, has been reinstated. The Company will report J01 production rates once production is fully stabilized and the well flow has completely cleaned up.

RESULTS OF OPERATIONS

Sales revenue has increased in Q1 2011 to $31.1 million (Q1 2010 $30.8 million). This movement comprises a decrease in total net oil production, an increase in average realized prices, and the addition of gas sales from the Anglia and Topaz fields from December 17, 2010.

Oil production decreased from 4,193 bopd in Q1 2010 to 2,511 bopd for Q1 2011 predominantly due to the workover and drilling activities experienced on Beatrice and Jacky noted above. The Corporation has benefited from an increase in average realized oil prices from $79.95 / bbl in Q1 2010 to $111.19 / bbl, due to an increase in the 'spot' Brent oil price in the year.

The addition of gas production due to the acquisition of producing gas assets from GDF SUEZ E&P UK Ltd in December 2010 ("GdF Acquisition") also contributed to increased revenue in Q1 2011 (no gas production in Q1 2010). The combined production from the Anglia and Topaz fields contributed over $4.2 million to revenue through 981 boepd of allocated gas.

Cost of Sales has increased in Q1 2011 to $17.2 million (Q1 2010 $13.1 million) due to an increase in both operating costs and DD&A expense.

Operating costs have increased in Q1 2011 to $10.2 million (Q1 2010 $8.7 million) due to the addition of Anglia and Topaz operating costs acquired in December 2010. Operating costs for the Great Beatrice Area have remained consistent in the period.

DD&A expense for the quarter has increased in Q1 2011 to $7.0 million (Q1 2010 $4.4 million). Although oil production has decreased year on year, an increase in expense has been recorded due to the increase in the depletion rate per barrel partly due to the addition of higher DD&A from the Anglia and Topaz gas assets.

A credit of $0.5 million has been recorded in the income statement relating to Exploration and Evaluation expenses for the three months ended March 31, 2011 (Q1 2010 $Nil). The credit relates to the expensing of certain prospects declared non-commercial of $1.5 million and the offsetting release of $2 million of associated contingent consideration relating to those licences and prospects. The Opal and Garnet prospects, acquired as part of the GdF Acquisition, were included within this write-off.

Administrative expenses have decreased in Q1 2011 to $1.0 million (Q1 2010 $2.0 million). Tight cost control combined with increased capitalization of general & administrative expenses and stock based compensation costs associated with higher levels of project work has delivered the reduction in costs charged to the income statement.

Foreign exchange gains / losses increased $3.7 million to an overall gain of $2.1 million in the three months ended March 31, 2011 (Q1 2010 $1.6 million loss). The gain in Q1 2011 was caused by a increase in the average USD : GBP exchange rate in the quarter, causing an increase in the value of GBP cash held on deposit. This compares to a decrease in the average USD : GBP exchange rate for the three months ended March 31, 2010.

The Corporation recorded a $2.3 million loss on financial instruments for the three months ended March 31, 2011 (Q1 2010: $2.0 million loss). $2.1 million of the loss resulted from the revaluation of the oil 'Put Option' that was purchased in the period due to movements in forecast oil prices. The remainder of the movement was made up of a $0.1 million loss on the oil hedges taken out at the end of 2010 and $0.1 million of revaluations of other financial instruments.

A deferred tax charge of $6.4 million was recognized in the three months ended March 31, 2011 (Q1 2010: $Nil) representing a tax rate of 49%. This rate is a product of the movements in UK Corporation Tax rates to 62% and 26% for upstream oil and gas and non-upstream oil and gas activities respectively. Although the Corporation has now recorded a deferred tax charge for the first reporting period, no tax is expected to be paid in the mid-term future relating to upstream oil and gas activities.

As a result of the above factors, Profit before tax increased to $13.0 million (Q1 2010 $12.1 million), and Profit after tax has decreased to $6.6 million for the quarter ended March 31, 2011 (Q1 2010 $12.1 million).

SUMMARY OF QUARTERLY RESULTS

The following table provides a summary of quarterly results of the Corporation for its eight most recently completed quarters:

31/03/201131/12/201030/09/201030/06/201031/03/201031/12/2009*30/09/2009*30/06/2009*
$'000$'000$'000$'000$'000$'000$'000$'000
Revenue31,05034,26035,96534,12930,76739,67637,39529,903
Profit after tax6,59317,92218,07314,01012,10817,488(1,145)3,780
Earnings per share
Basic0.030.070.080.090.070.11(0.01)0.02
Diluted0.030.070.080.080.070.11(0.01)0.02
Selected other information
Profit before tax13,03714,25718,15414,01012,10817,488(1,145)3,780
* Comparative figures for 2009 have been reported under Canadian GAAP

The most significant factor to have affected the Corporation's results during the above periods is fluctuation in underlying commodity prices. Commodity prices have generally risen through the periods in which the Corporation had production. The Corporation has utilized forward sales contracts and foreign exchange contracts to take advantage of higher commodity prices while reducing the exposure to price volatility. These contracts can cause volatility in Profit after tax as a result of unrealized gains and losses due to movements in the oil price and US Dollar: British Pounds Sterling exchange rate.

LIQUIDITY AND CAPITAL RESOURCES

As at March 31, 2011, Ithaca had working capital of $234.7 million including a free cash balance of $191.3 million. Available cash has been, and is currently, invested in money market deposit accounts with the Bank of Scotland. Management has received confirmation from the financial institution that these funds are available on demand. The restricted cash of $7.6 million comprises $7.2 million currently held by the Bank of Scotland as decommissioning security provided as part of the acquisition of gas interests from GDF SUEZ E&P UK Ltd and $0.4 million held by the Bank of Scotland as cash security for a bank guarantee that Ithaca Energy (UK) Limited ("Ithaca UK") provided to the Crown Estate when it was granted Field Development Plan approval for the Jacky Field.

During the three months ended March 31, 2011 there was a cash outflow from operating, investing and financing activities of $4.2 million (Q1 2010 outflow of $9.8 million). The net outflow was due to positive cash flows from operating activities of $27.8 million; a decrease in cashflows from investing activities of $33.3 million due to investment in fixed assets and movements in working capital, and positive cash flows from financing activities of $0.6 million, due to the proceeds from the exercise of the Gemini warrants and share options, offset by movements in restricted cash and the purchase of the put option for 804,500 barrels at $105 / barrel. The fixed asset investment in the quarter predominantly related to capital expenditure on the development of Athena, the continuing hydraulic workover program on Beatrice Alpha, and drilling costs on the Jacky J03 well.

All of the Corporation's current projects are anticipated to be fully funded through to first production.

COMMITMENTS

The Corporation has the following financial commitments of which the largest component relates to the Engineering (Athena and Stella projects):

Year ended2011201220132014Subsequent to 2014
US$'000US$'000US$'000US$'000US$'000
Office lease192257257257834
Exploration license fees8761,2491,603--
Engineering17,04612,26620,66612,266-
Total18,11413,77222,52612,523834

OUTSTANDING SHARE INFORMATION

As at March 31, 2011, Ithaca had 258,535,295 common shares outstanding along with 19,798,505 options to employees and directors to acquire common shares.

The total number of options outstanding is inclusive of 260,000 options granted to employees in the quarter in accordance with the Corporation's stock option plan. The options were approved by the Board of Directors at a range of prices from C$1.80 to C$2.69. 200,000 of these options were reserved for issue in Q3 2010 in contemplation of hiring. Each of the options granted may be exercised for a period of four years from the grant date. One third of the options will vest at the end of each of the first, second and third years from the effective date of grant.

As discussed above, on March 3, 2011, Gemini exercised the 2,500,000 warrants to purchase common shares of the Corporation that were granted in Q3 2010.

As at June 9, 2011, Ithaca had 258,535,295 common shares outstanding along with 19,798,505 options to employees and directors to acquire common shares.

CRITICAL ACCOUNTING ESTIMATES

Certain accounting policies require that management make appropriate decisions with respect to the formulation of estimates and assumptions that affect the reported amounts of assets, liabilities, revenues and expenses. These accounting policies are discussed below and are included to aid the reader in assessing the critical accounting policies and practices of the Corporation and the likelihood of materially different results being reported. Ithaca's management reviews these estimates regularly. The emergence of new information and changed circumstances may result in actual results or changes to estimated amounts that differ materially from current estimates.

The following assessment of significant accounting policies and associated estimates is not meant to be exhaustive. The Corporation might realize different results from the application of new accounting standards promulgated, from time to time, by various rule-making bodies.

Capitalized costs relating to the exploration and development of oil and gas reserves, along with estimated future capital expenditures required in order to develop proved and probable reserves are depreciated on a unit-of-production basis, by asset, using estimated proved and probable reserves as adjusted for production.

A review is carried out each reporting date for any indication that the carrying value of the Corporation's Development & Production ("D&P") assets may be impaired. For D&P assets where there are such indications, an impairment test is carried out on the Cash Generating Unit ("CGU"). Each CGU is identified in accordance with IAS 36. The Corporation's CGUs are those assets which generate largely independent cash flows and are normally, but not always, single developments or production areas. The impairment test involves comparing the carrying value with the recoverable value of an asset. The recoverable amount of an asset is determined as the higher of its fair value less costs to sell and value in use, where the value in use is determined from estimated future net cash flows. Any additional depreciation resulting from the impairment testing is charged to the Income Statement.

Recognition of decommissioning liabilities associated with oil and gas wells are determined using estimated costs discounted based on the estimated life of the asset. In periods following recognition, the liability and associated asset are adjusted for any changes in the estimated amount or timing of the settlement of the obligations. The liability is accreted up to the actual expected cash outlay to perform the abandonment and reclamation. The carrying amounts of the associated assets are depleted using the unit of production method, in accordance with the depreciation policy for development and production assets. Actual costs to retire tangible assets are deducted from the liability as incurred.

All financial instruments (including derivatives, financial assets and liabilities) are initially recognized at fair value on the balance sheet. The Corporation's financial instruments consist of cash, restricted cash, accounts receivable, deposits, derivatives, loan fees, accounts payable, accrued liabilities and the long term liability on the Beatrice acquisition. Measurement in subsequent periods is dependent on the classification of the respective financial instrument.

In order to recognize stock based compensation expense, the Corporation estimates the fair value of stock options granted using assumptions related to interest rates, expected life of the option, volatility of the underlying security and expected dividend yields. These assumptions may vary over time.

The determination of the Corporation's income and other tax liabilities / assets requires interpretation of complex laws and regulations. Tax filings are subject to audit and potential reassessment after the lapse of considerable time. Accordingly, the actual income tax liability may differ significantly from that estimated and recorded on the financial statements.

The accrual method of accounting will require management to incorporate certain estimates of revenues, production costs and other costs as at a specific reporting date. In addition, the Corporation must estimate capital expenditures on capital projects that are in progress or recently completed where actual costs have not been received as of the reporting date.

OFF-BALANCE SHEET ARRANGEMENTS

The Corporation has certain lease agreements which were entered into in the normal course of operations, all of which are disclosed under the heading "Commitments", above. All leases have been treated as operating leases whereby the lease payments are included in cost of sales or administrative expenses depending on the nature of the lease. No asset or liability value has been assigned to these leases on the balance sheet as at March 31, 2011.

RELATED PARTY TRANSACTIONS

A director of the Corporation is a partner of Burstall Winger LLP who acts as counsel for the Corporation. The amount of fees paid to Burstall Winger LLP in Q1 2011 was $0.1 million (Q1 2010 - $Nil). All related party transactions are in the normal course of business and are conducted on normal commercial terms with consideration comparable to those charged by third parties.

RISKS AND UNCERTAINTIES

The business of exploring for, developing and producing oil and natural gas reserves is inherently risky. There is substantial risk that the manpower and capital employed will not result in the finding of new reserves in economic quantities. There is a risk that the sale of reserves may be delayed due to processing constraints, lack of pipeline capacity or lack of markets.

The Corporation is dependent upon the production rates and oil price to fund the current development program. In order to mitigate the Corporation's risk to fluctuations in oil price, the Corporation has taken out a number of commodity derivatives. In March 2011, a put option to sell 804,500 bbls of the Corporation's 2011 forecast production at $105 / bbl was entered into. In April 2011 a further put option to sell an additional 300,000 bbls of the Corporation's forecast 2011 production at $115 / bbl was entered into. These options deliver a minimum price on the specified volumes of oil and leave the Corporation to benefit from any oil price upside above $105 and $115 per barrel respectively.

The Corporation is exposed to financial risks including financial market volatility, fluctuation in interest rates and various foreign exchange rates. Given the increasing development expenditure and operating costs in currencies other than the United States dollar, the Board of Directors of the Corporation has a hedging policy to mitigate foreign exchange rate risk on committed expenditure. In 2011 in order to protect against movements in USD/£ exchange rates, the Corporation holds GBP denominated cash on deposit in order to match the forecast 2011 GBP denominated expenditure.

A further risk relates to the Corporation's ability to meet the conditions precedent for a full drawdown on the Corporation's credit facility with the Bank of Scotland (the "Credit Facility"). Ability to drawdown the Credit Facility is based on the Corporation meeting certain tests including coverage ratio tests, liquidity tests and development funding tests which are determined by a detailed economic model of the Corporation. There can be no assurance that the Corporation will satisfy such tests in order to have access to the full amount of the Credit Facility, however at present the Corporation believes that there are no circumstances present that would lead to failure to meet those tests.

In addition, the Credit Facility contains covenants that require the Corporation to meet certain financial tests and that restrict, among other things, the ability of Ithaca to incur additional debt or dispose of assets. To the extent the cash flow from operations is not adequate to fund Ithaca's cash requirements, external financing may be required. Lack of timely access to such additional financing, or which may not be on favorable terms, could limit the future growth of the business of Ithaca. To the extent that external sources of capital, including public and private markets, become limited or unavailable, Ithaca's ability to make the necessary capital investments to maintain or expand its current business and to make necessary principal payments under the Credit Facility may be impaired. At present the Corporation believes that there are no circumstances present that would lead to failure to meet those certain financial tests.

A failure to access adequate capital to continue its expenditure program may require that the Corporation meet any liquidity shortfalls through the selected divestment of its portfolio or delays to existing development programs. As is standard to a Credit facility, the Corporation's and Ithaca UK assets have been pledged as collateral and are subject to foreclosure in the event the Corporation or Ithaca UK defaults. At present the Corporation believes that there are no circumstances present that would lead to selected divestment, delays to existing programs or a default relating to the Credit Facility.

The Corporation is and may in the future be exposed to third-party credit risk through its contractual arrangements with its current and future joint venture partners, marketers of its petroleum production and other parties. The Corporation extends unsecured credit to these parties, and therefore, the collection of any receivables may be affected by changes in the economic environment or other conditions. Management believes the risk is mitigated by the financial position of the parties. The Corporation has entered in to a five year marketing agreement with BP Oil International Limited to sell all of its North Sea oil production. All gas production, acquired through the purchase of the Anglia and Topaz fields from GDF SUEZ E&P UK Ltd, is sold through three contracts on a monthly basis to RWE NPower PLC and Hess Energy Gas Power (UK) Ltd. The Corporation has not experienced any material credit loss in the collection of accounts receivable to date.

The Corporation's properties will be generally held in the form of licenses, concessions, permits and regulatory consents ("Authorizations"). The Corporation's activities are dependent upon the grant and maintenance of appropriate Authorizations, which may not be granted; may be made subject to limitations which, if not met, will result in the termination or withdrawal of the Authorization; or may be otherwise withdrawn. Also, in the majority of its licenses, the Corporation is often a joint interest-holder with another third party over which it has no control. An Authorization may be revoked by the relevant regulatory authority if the other interest-holder is no longer deemed to be financially credible. There can be no assurance that any of the obligations required to maintain each Authorization will be met. Although the Corporation believes that the Authorizations will be renewed following expiry or granted (as the case may be), there can be no assurance that such Authorizations will be renewed or granted or as to the terms of such renewals or grants. The termination or expiration of the Corporation's Authorizations may have a material adverse effect on the Corporation's results of operations and business.

In addition, the areas covered by the Authorizations are or may be subject to agreements with the proprietors of the land. If such agreements are terminated, found void or otherwise challenged, the Corporation may suffer significant damage through the loss of opportunity to identify and extract oil or gas.

The Corporation is also subject to the risks associated with owning oil and natural gas properties, including environmental risks associated with air, land and water. The Corporation takes out market insurance to mitigate many of these operational, construction and environmental risks. In all areas of the Corporation's business there is competition with entities that may have greater technical and financial resources. There are numerous uncertainties in estimating the Corporation's reserve base due to the complexities in estimating the magnitude and timing of future production, revenue, expenses and capital. All of the Corporation's operations are conducted offshore in the UKCS; as such Ithaca is exposed to operational risk associated with weather delays that can result in a material delay in project execution. Third parties operate some of the assets in which the Corporation has interests. As a result, the Corporation may have limited ability to exercise influence over the operations of these assets and their associated costs. The success and timing of these activities may be outside the Corporation's control.

It should be noted that the Corporation is not required to certify the design and evaluation of the Corporation's disclosure controls and procedures and internal control over financial reporting and it has not completed such an evaluation. Furthermore, given the size of the Corporation there are inherent limitations on the certifying officers to design and implement on a cost effective basis disclosure controls and procedures and internal control over financial reporting that may result in additional risks to the quality, reliability, transparency, and timeliness of annual filings.

For additional detail regarding the Corporation's risks and uncertainties, refer to the Corporation's most recent AIF filed on SEDAR at www.sedar.com.

CONTROL ENVIRONMENT

As of March 31, 2011, there were no changes in our internal control over financial reporting that occurred during 2011 that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

Based on their inherent limitations, disclosure controls and procedures and internal controls over financial reporting may not prevent or detect misstatements and even those options determined to be effective can provide only reasonable assurance with respect to financial statement preparation and presentation.

CHANGES IN ACCOUNTING POLICIES

On January 1, 2011, the Corporation adopted International Financial Reporting Standards ("IFRS") using a transition date of January 1, 2010. The financial statements for the three months ended March 31, 2011, including required comparative information, have been prepared in accordance with International Financial Reporting Standards 1, First-time Adoption of International Financial Reporting Standards, and with International Accounting Standard ("IAS") 34, Interim Financial Reporting, as issued by the International Accounting Standards Board ("IASB"). Previously, the Corporation prepared its Interim and Annual Consolidated Financial Statements in accordance with Canadian GAAP. Refer to Note 24 of the Interim Consolidated Financial Statements for the Corporation's assessment of impacts of the transition to IFRS.

IMPACT OF FUTURE ACCOUNTING CHANGES

In May 2011, the IASB issued the following standards: IFRS 10, Consolidated Financial Statements ("IFRS 10"), IFRS 11, Joint Arrangements ("IFRS 11"), IFRS 12, Disclosure of Interests in Other Entities ("IFRS 12"), IAS 27, Separate Financial Statements ("IAS 27"), IFRS 13, Fair Value Measurement ("IFRS 13") and amended IAS 28, Investments in Associates and Joint Ventures ("IAS 28"). Each of the new standards is effective for annual periods beginning on or after January 1, 2013 with early adoption permitted. The Corporation has not yet assessed the impact that the new and amended standards will have on its financial statements or whether to early adopt any of the new requirements.

FINANCIAL INSTRUMENTS AND OTHER INSTRUMENTS

All financial instruments are initially measured in the balance sheet at fair value. Subsequent measurement of the financial instruments is based on their classification. The Corporation has classified each financial instrument into one of these categories: held-for-trading, held-to-maturity investments, loans and receivables, or other financial liabilities. Loans and receivables, held-to-maturity investments and other financial liabilities are measured at amortized cost using the effective interest rate method. For all financial assets and financial liabilities that are not classified as held-for-trading, the transaction costs that are directly attributable to the acquisition or issue of a financial asset or financial liability are adjusted to the fair value initially recognized for that financial instrument. These costs are expensed using the effective interest rate method and are recorded within interest expense. Held-for-trading financial assets are measured at fair value and changes in fair value are recognized in net income.

All derivative instruments are recorded in the balance sheet at fair value unless they qualify for the expected purchase, sale and usage exemption. All changes in their fair value are recorded in income unless cash flow hedge accounting is used, in which case changes in fair value are recorded in other comprehensive income.

The Corporation has classified its cash and cash equivalents, restricted cash, derivatives, commodity hedge and long term liability as held-for-trading, which are measured at fair value with changes being recognized in net income. Accounts receivable are classified as loans and receivables; operating bank loans, accounts payable and accrued liabilities are classified as other liabilities, all of which are measured at amortized cost. The classification of all financial instruments is the same at inception and at March 31, 2011.

FORWARD-LOOKING INFORMATION

This MD&A and any documents incorporated by reference herein contain certain forward-looking statements and forward-looking information which are based on the Corporation's internal expectations, estimates, projections, assumptions and beliefs as at the date of such statements or information, including, among other things, assumptions with respect to production, future capital expenditures and cash flow. The reader is cautioned that assumptions used in the preparation of such information may prove to be incorrect. The use of any of the words "anticipate", "continue", "estimate", "expect", "may", "will", "project", "plan", "should", "believe", "could", "scheduled", "targeted" and similar expressions are intended to identify forward-looking statements and forward-looking information. These statements are not guarantees of future performance and involve known and unknown risks, uncertainties and other factors that may cause actual results or events to differ materially from those anticipated in such forward-looking statements or information. The Corporation believes that the expectations reflected in those forward-looking statements and information are reasonable but no assurance can be given that these expectations, or the assumptions underlying these expectations, will prove to be correct and such forward-looking statements and information included in this MD&A and any documents incorporated by reference herein should not be unduly relied upon. Such forward-looking statements and information speak only as of the date of this MD&A and any documents incorporated by reference herein and the Corporation does not undertake any obligation to publicly update or revise any forward-looking statements or information, except as required by applicable laws.

In particular, this MD&A and any documents incorporated by reference herein, contains specific forward-looking statements and information pertaining to the following:

  • the quality of and future net revenues from the Corporation's reserves;
  • oil, natural gas liquids ("NGLs") and natural gas production levels;
  • commodity prices, foreign currency exchange rates and interest rates;
  • capital expenditure programs and other expenditures;
  • the sale, farming in, farming out or development of certain exploration properties using third party resources;
  • supply and demand for oil, NGLs and natural gas;
  • the Corporation's ability to raise capital;
  • the Corporation's acquisition strategy, the criteria to be considered in connection therewith and the benefits to be derived therefrom;
  • the Corporation's ability to continually add to reserves;
  • schedules and timing of certain projects and the Corporation's strategy for growth;
  • the Corporation's future operating and financial results;
  • the ability of the Corporation to optimize operations and reduce operational expenditures;
  • treatment under governmental and other regulatory regimes and tax, environmental and other laws;
  • production rates, including production rates in respect to the workover operation to replace the failed ESPs in the J01 production well at the Corporation's Jacky well;
  • targeted production levels;
  • timing and cost of the development of the Corporation's reserves; and
  • estimates of production volumes and reserves in connection with the acquisition of Cook.

With respect to forward-looking statements contained in this MD&A and any documents incorporated by reference herein, the Corporation has made assumptions regarding, among other things:

  • Ithaca's ability to obtain additional drilling rigs and other equipment in a timely manner, as required;
  • Access to third party hosts and associated pipelines can be negotiated and accessed within the expected timeframe;
  • Field development plan approval and operational construction and development is obtained within expected timeframes;
  • The Corporation's development plan for the Stella and Harrier discoveries will be implemented as planned;
  • Reserves volumes assigned to Ithaca's properties;
  • Ability to recover reserves volumes assigned to Ithaca's properties;
  • Revenues do not decrease below anticipated levels and operating costs do not increase significantly above anticipated levels;
  • future oil, NGLs and natural gas production levels from Ithaca's properties and the prices obtained from the sales of such production;
  • the level of future capital expenditure required to exploit and develop reserves;
  • Ithaca's ability to obtain financing on acceptable terms, in particular, the Corporation's ability to access the Credit Facility;
  • Ithaca's reliance on partners and their ability to meet commitments under relevant agreements; and
  • the state of the debt and equity markets in the current economic environment.

The Corporation's actual results could differ materially from those anticipated in these forward-looking statements and information as a result of assumptions proving inaccurate and of both known and unknown risks, including the risk factors set forth in this MD&A and under the heading "Risk Factors" in the AIF and the documents incorporated by reference herein, and those set forth below:

  • risks associated with the exploration for and development of oil and natural gas reserves in the North Sea;
  • risks associated with offshore development and production including transport facilities;
  • operational risks and liabilities that are not covered by insurance;
  • volatility in market prices for oil, NGLs and natural gas;
  • the ability of the Corporation to fund its substantial capital requirements and operations;
  • risks associated with ensuring title to the Corporation's properties;
  • changes in environmental, health and safety or other legislation applicable to the Corporation's operations, and the Corporation's ability to comply with current and future environmental, health and safety and other laws;
  • the accuracy of oil and gas reserve estimates and estimated production levels as they are affected by the Corporation's exploration and development drilling and estimated decline rates;
  • the Corporation's success at acquisition, exploration, exploitation and development of reserves;
  • the Corporation's reliance on key operational and management personnel;
  • the ability of the Corporation to obtain and maintain all of its required permits and licenses;
  • competition for, among other things, capital, drilling equipment, acquisitions of reserves, undeveloped lands and skilled personnel;
  • changes in general economic, market and business conditions in Canada, North America, the United Kingdom, Europe and worldwide, specifically being the unavailability of the debt and equity markets to the Corporation during the current economic crisis;
  • actions by governmental or regulatory authorities including changes in income tax laws or changes in tax laws, royalty rates and incentive programs relating to the oil and gas industry including the recent increase in UK taxes;
  • adverse regulatory rulings, orders and decisions;
  • risks associated with the nature of the common shares; and
  • the impact of adoption of IFRS as opposed to GAAP from January 1, 2011.

Statements relating to reserves are deemed to be forward-looking statements, as they involve the implied assessment, based on certain estimates and assumptions, that the reserves described can be profitably produced in the future. Many of these risk factors, other specific risks, uncertainties and material assumptions are discussed in further detail throughout the AIF and in the MD&A. Readers are specifically referred to the risk factors described in the AIF under "Risk Factors" and in other documents the Corporation files from time to time with securities regulatory authorities. Copies of these documents are available without charge from Ithaca or electronically on the internet on Ithaca's SEDAR profile at www.sedar.com.

The estimates of reserves and future net revenue for individual properties may not reflect the same confidence level as estimates of reserves and future net revenue for all properties, due to the effects of aggregation.

Ithaca Energy Inc. Q1 2011 Financial Statements

Q1 2011 CONSOLIDATED FINANCIAL STATEMENTS

Consolidated Statement of Income
For the three months ended March 31, 2011 and 2010
(unaudited)
20112010
Note US$'000US$'000
Revenue 431,05030,767
Cost of Sales 6(17,218)(13,078)
Gross Profit13,83217,689
Exploration and evaluation expenses 8519-
Administrative expenses 5(1,060)(1,957)
Operating Profit13,29115,732
Foreign exchange 2,135(1,576)
Gain / (Loss) on financial instruments 19(2,287)(1,974)
Profit on ordinary activities Before Interest and Tax13,13912,182
Finance costs (259)(76)
Interest income 1572
Profit Before Tax13,03712,108
Taxation - Deferred tax 17(6,426)-
Profit After Tax6,61112,108
Earnings per share
Basic 160.030.07
Diluted 160.030.07

No separate statement of comprehensive income has been prepared as all such gains and losses have been incorporated in the income statement above.

The accompanying notes are an integral part of the financial statements.

Consolidated Balance Statement of Financial Position
(unaudited)
March 31December 31 January 1
20112010 2010
Note US$'000US$'000 US$'000
ASSETS
Current assets
Cash and cash equivalents 191,334195,581 29,886
Restricted Cash 77,5956,308 5,224
Accounts receivable 90,15993,434 67,166
Deposits, prepaid expenses and other 17,71512,341 352
Inventory 1,192- -
Derivative Financial Instruments 202,003- 685
Deferred Tax Asset - 3,745 -
309,998311,409 103,313
Non current assets
Restricted Cash 7-- 352
Exploration and evaluation assets 817,25417,522 15,500
Property, Plant & Equipment 9266,055249,968 189,975
283,309267,490 205,827
Total assets593,307578,899 309,140
LIABILITIES AND EQUITY
Current Liabilities
Trade and other payables 75,31275,564 43,613
Commodity hedge -349 397
75,31275,913 44,010
Non current liabilities
Decommissioning liabilities 1123,55623,652 8,751
Other long term liabilities 122,7582,872 2,718
Contingent consideration 1310,97612,976 6,933
Derivative financial instruments 204,7354,378 -
Deferred Tax Liability 2,681--
44,70643,878 18,402
Net assets473,289459,108 246,728
Equity attributable to equity holders
Share Capital 14428,817422,373 277,075
Contributed surplus 1512,86411,427 6,860
Warrants issued 14-311 -
Retained Earnings / (Deficit) 31,60824,997 (37,207)
Shareholders' Equity473,289459,108 246,728

"John Summers", Director

"Jay Zammit", Director

The accompanying notes are an integral part of the financial statements.

Consolidated Statement of Changes in Equity
(unaudited)
lContributedWarrantsRetainedl
Share CapitalSurplusIssuedE'ings/(Deficit) Total
US$'000US$'000US$'000US$'000US$'000
Balance, Jan 1 2010277,0756,860-(37,207)246,728
Stock based compensation-1,181--1,181
Options exercised99(47)--52
Net income for the period---12,10812,108
Balance, March 31 2010277,1747,994-(25,099)260,069
Balance, Jan 1 2011422,37311,42731124,997459,108
Stock based compensation-1,585--1,585
Options exercised347(148)--199
Warrants exercised6,097-(311)-5,786
Net income for the year---6,6116,611
Balance, March 31 2011428,81712,864-31,608473,289
The accompanying notes are an integral part of the financial statements
Consolidated Statement of Cash Flow
For the three months ended March 31, 2011 and 2010
(unaudited)
20112010
US$'000US$'000
CASH PROVIDED BY (USED IN):
Operating activities
Profit Before Tax13,03712,108
Adjustments for:
Depletion, Depreciation and Amortization 6,9724,389
Exploration and evaluation expenses 1,481-
Stock based compensation 5911,181
Loan Fee amortization 78-
Unrealized (gain) / loss on financial instruments 1,7941,808
Revaluation of contingent consideration (2,000)-
Accretion 17772
Cashflow from operations22,13019,558
Movement in working capital 5,629(14,858)
Net cash from operating activities27,7594,700
Investing activities
Capital expenditure
Oil and gas assets (23,781)(14,566)
Non oil and gas assets (382)(99)
Movement in working capital (9,173)(3,856)
Net cash used in investing activities(33,336)(18,521)
Financing activities
Proceeds from issuance of shares 5,98652
(Increase) / Decrease in Restricted Cash (1,287)5,241
Derivatives (4,063)-
Net cash from financing activities6365,293
Currency translation differences relating to cash and cash equivalents 694(1,274)
Increase / (decrease) in cash and cash equivalents(4,247)(9,802)
Cash and cash equivalents, beginning of period 195,58129,886
Cash and cash equivalents, end of period191,33420,084
The accompanying notes are an integral part of the financial statements

1. NATURE OF OPERATIONS

Ithaca Energy Inc. (the "Corporation" or "Ithaca"), incorporated and domiciled in Alberta, Canada on April 27, 2004, is a publicly traded company involved in the exploration, development and production of oil and gas in the North Sea. The Corporation's registered office is 1600, 333 - 7th Avenue S.W., Calgary, Alberta, Canada, T2P 2Z1. The Corporation's shares are listed on the TSX Venture Exchange in Canada and the London Stock Exchange's Alternative Investment Market in the United Kingdom under the symbol "IAE". Ithaca has a wholly-owned subsidiary Ithaca Energy (UK) Limited ("Ithaca UK"), incorporated in Scotland.

2. BASIS OF PREPARATION AND ADOPTION OF IFRS

The Corporation prepares its financial statements in accordance with Canadian generally accepted accounting principles as set out in the Handbook of the Canadian Institute of Chartered Accountants ("CICA Handbook"). In 2010, the CICA Handbook was revised to incorporate International Financial Reporting Standards ("IFRS"), and require publicly accountable enterprises to apply such standards effective for years beginning on or after January 1, 2011. Accordingly, the Corporation has commenced reporting on this basis in these interim consolidated financial statements. In the financial statements, the term "Canadian GAAP" refers to Canadian GAAP before the adoption of IFRS.

These interim consolidated financial statements have been prepared in accordance with IFRS applicable to the preparation of interim financial statements, including IAS 34 Interim Financial Reporting and IFRS 1 First Time Adoption of IFRS. These interim consolidated financial statements do not include all the necessary annual disclosures in accordance with IFRS. Subject to certain transition elections disclosed in note 22, the Corporation has consistently applied the same accounting policies in its opening IFRS statement of financial position at January 1, 2010 and throughout all periods presented, as if these policies had always been in effect. Note 22 discloses the impact of the transition to IFRS on the Corporation's reported financial position, financial performance and cash flows, including the nature and effect of significant changes in accounting policies from those used in the Corporation's consolidated financial statements for the year ended December 31, 2010.

The policies applied in these condensed interim consolidated financial statements are based on IFRS issued and outstanding as of June 23, 2011, the date the Board of Directors approved the statements. Any subsequent changes to IFRS that are given effect in the Corporation's annual consolidated financial statements for the year ending December 31, 2011 could result in restatement of these interim consolidated financial statements, including the transition adjustments recognized on change-over to IFRS.

The condensed interim consolidated financial statements should be read in conjunction with the Corporation's Canadian GAAP annual financial statements for the year ended December 31, 2010. Note 24 discloses IFRS information for the year ended December 31, 2010 not provided in the 2010 annual financial statements.

3. SIGNIFICANT ACCOUNTING POLICIES, JUDGEMENTS AND ESTIMATION UNCERTAINTY

Basis of measurement

The consolidated financial statements have been prepared under the historical cost convention, except for the revaluation of certain financial assets and financial liabilities to fair value, including derivative instruments.

Principles of consolidation

The consolidated financial statements of the Corporation include the accounts of Ithaca Inc. and its wholly-owned subsidiary Ithaca Energy (UK) Ltd. All inter-company transactions and balances have been eliminated on consolidation.

A subsidiary is an entity (including special purpose entities) which the Corporation controls by having the power to govern the financial and operating policies. The existence and effect of potential voting rights that are currently exercisable or convertible are considered when assessing whether Ithaca controls another entity. A subsidiary is fully consolidated from the date on which control is obtained by Ithaca and are de-consolidated from the date that control ceases.

Foreign Currency Translation

Items included in the financial statements are measured using the currency of the primary economic environment in which the Corporation and its subsidiary operate (the 'functional currency'). The consolidated financial statements are presented in United States Dollars, which is the Corporation's and Ithaca UK's functional and presentation currency.

Foreign currency transactions are translated into the functional currency using the exchange rates prevailing at the dates of the transactions. Foreign exchange gains and losses resulting from the settlement of such transactions and from the translation at year end exchange rates of monetary assets and liabilities denominated in foreign currencies are recognized in the statement of income.

Share based payments

The Corporation has a stock based compensation plan as described in note 14 (b). The Corporation's proportionate share of expense is recorded in the statement of income or capitalized for all options granted in the year, with the gross increase recorded as contributed surplus. Compensation costs are based on the estimated fair values at the time of the grant and the expense or capitalized amount is recognized over the vesting period of the options. Upon the exercise of the stock options, consideration paid together with the amount previously recognized in contributed surplus is recorded as an increase in share capital. In the event that vested options expire unexercised, previously recognized compensation expense associated with such stock options is not reversed. In the event that unvested options are forfeited or expired, previously recognized compensation expense associated with the unvested portion of such stock options is reversed.

Cash and Cash Equivalents

For the purpose of cash flow statements, cash and cash equivalents include investments with an original maturity of three months or less.

Restricted Cash

Cash that is held for security for bank guarantees is reported in the balance sheet and cash flow statements separately. If the expected duration of the restriction is less than twelve months then it is shown in current assets.

Financial Instruments

All financial instruments are initially recognized at fair value on the balance sheet. The Corporation's financial instruments consist of cash, restricted cash, accounts receivable, deposits, derivatives, loan fees, accounts payable, accrued liabilities and the long term liability on the Beatrice acquisition. The Corporation classifies its financial instruments into one of the following categories: held-for-trading financial assets and financial liabilities; held-to- maturity investments; loans and receivables; and other financial liabilities. All financial instruments are required to be measured at fair value on initial recognition. Measurement in subsequent periods is dependent on the classification of the respective financial instrument.

Held-for-trading financial instruments are subsequently measured at fair value with changes in fair value recognized in net earnings. All other categories of financial instruments are measured at amortized cost using the effective interest method. Cash and cash equivalents are classified as held-for-trading and are measured at fair value. Accounts receivable are classified as loans and receivables. Accounts payable, accrued liabilities, certain other long-term liabilities, and long-term debt are classified as other financial liabilities. Although the Corporation does not intend to trade its derivative financial instruments, they are classified as held-for-trading for accounting purposes.

Transaction costs that are directly attributable to the acquisition or issue of a financial asset or liability and original issue discounts on long-term debt have been included in the carrying value of the related financial asset or liability and are amortized to consolidated net earnings over the life of the financial instrument using the effective interest method.

Analysis of the fair values of financial instruments and further details as to how they are measured are provided in notes 19 to 21.

Inventory

Inventories of materials and product inventory supplies, other than oil and gas inventories, are stated at the lower of cost and net realizable value. Cost is determined on the first-in, first-out method. Oil and gas inventories are stated at fair value less cost to sell.

Property, Plant and Equipment

Oil and gas expenditure – exploration and evaluation assets

Capitalisation

Pre-acquisition costs on oil and gas assets are recognised in the Income Statement when incurred. Costs incurred after rights to explore have been obtained, such as geological and geophysical surveys, drilling and commercial appraisal costs and other directly attributable costs of exploration and evaluation including technical and administrative costs are capitalised as intangible exploration and evaluation ("E&E") assets.

E&E costs are not amortised prior to the conclusion of evaluation activities. At completion of evaluation activities, if technical feasibility is demonstrated and commercial reserves are discovered then, following development sanction, the carrying value of the E&E asset is reclassified as a development and production ("D&P") asset, but only after the carrying value is assessed for impairment and where appropriate its carrying value adjusted. If after completion of evaluation activities in an area, it is not possible to determine technical feasibility and commercial viability or if the legal right to explore expires or if the Corporation decides not to continue exploration and evaluation activity, then the costs of such unsuccessful exploration and evaluation is written off to the Income Statement in the period the relevant events occur.

Impairment

The Corporation's oil and gas assets are analysed into cash generating units ("CGU") for impairment review purposes, with E&E asset impairment testing being performed at a grouped CGU level. The current E&E CGU consists of the Corporation's whole E&E portfolio. E&E assets are reviewed for impairment when circumstances arise which indicate that the carrying value of an E&E asset exceeds the recoverable amount. When reviewing E&E assets for impairment, the combined carrying value of the grouped CGU is compared with the grouped CGU's recoverable amount. The recoverable amount of a grouped CGU is determined as the higher of its fair value less costs to sell and value in use. Impairment losses resulting from an impairment review are written off to the Income Statement.

Oil and gas expenditure – development and production assets

Capitalisation

Costs of bringing a field into production, including the cost of facilities, wells and sub-sea equipment together with E&E assets reclassified in accordance with the above policy, are capitalised as a D&P asset. Normally each individual field development will form an individual D&P asset but there may be cases, such as phased developments, or multiple fields around a single production facility when fields are grouped together to form a single D&P asset.

Depreciation

All costs relating to a development are accumulated and not depreciated until the commencement of production. Depreciation is calculated on a unit of production basis based on the proved and probable reserves of the asset. Any re-assessment of reserves affects the depreciation rate prospectively. Significant items of plant and equipment will normally be fully depreciated over the life of the field. However, these items are assessed to consider if their useful lives differ from the expected life of the D&P asset and should this occur a different depreciation rate would be charged.

Impairment

A review is carried out each reporting date for any indication that the carrying value of the Corporation's D&P assets may be impaired. For D&P assets where there are such indications, an impairment test is carried out on the CGU. Each CGU is identified in accordance with IAS 36. The Corporation's CGUs are those assets which generate largely independent cash flows and are normally, but not always, single developments or production areas. The impairment test involves comparing the carrying value with the recoverable value of an asset. The recoverable amount of an asset is determined as the higher of its fair value less costs to sell and value in use, where the value in use is determined from estimated future net cash flows. Any additional depreciation resulting from the impairment testing is charged to the Income Statement.

(b) Non Oil and Natural Gas Operations

Computer and office equipment is recorded at cost and depreciated over its estimated useful life on a straight-line basis over three years. Furniture and fixtures are recorded at cost and depreciated over their estimated useful lives on a straight-line basis over five years.

Decommissioning liabilities

The Corporation records the present value of legal obligations associated with the retirement of long term tangible assets, such as producing well sites and processing plants, in the period in which they are incurred with a corresponding increase in the carrying amount of the related long term asset. In subsequent periods, the asset is adjusted for any changes in the estimated amount or timing of the settlement of the obligations. The carrying amounts of the associated assets are depleted using the unit of production method, in accordance with the depreciation policy for development and production assets. Actual costs to retire tangible assets are deducted from the liability as incurred.

Contingent consideration

Contingent consideration is accounted for as a financial liability and measured at fair value at the date of acquisition with any subsequent remeasurements recognised either in profit or loss or in other comprehensive income in accordance with IAS 39.

Taxation

Deferred tax is recognized for all deductible temporary differences and the carry-forward of unused tax losses. Deferred tax assets and liabilities are measured using enacted or substantively enacted income tax rates expected to apply to taxable income in the years in which temporary differences are expected to be recovered or settled. The effect on deferred tax assets and liabilities of a change in rates is included in earnings in the period of the enactment date. Deferred tax assets are recorded in the consolidated financial statements if realization is considered more likely than not.

Recent accounting pronouncements

In May 2011, the IASB issued the following standards: IFRS 10, Consolidated Financial Statements ("IFRS 10"), IFRS 11, Joint Arrangements ("IFRS 11"), IFRS 12, Disclosure of Interests in Other Entities ("IFRS 12"), IAS 27, Separate Financial Statements ("IAS 27"), IFRS 13, Fair Value Measurement ("IFRS 13") and amended IAS 28, Investments in Associates and Joint Ventures ("IAS 28"). Each of the new standards is effective for annual periods beginning on or after January 1, 2013 with early adoption permitted. The Corporation has not yet assessed the impact that the new and amended standards will have on its financial statements or whether to early adopt any of the new requirements.

Significant accounting judgements and estimation uncertainties

The preparation of financial statements in conformity with IFRS requires management to make estimates and assumptions regarding certain assets, liabilities, revenues and expenses. Such estimates must often be made based on unsettled transactions and other events and a precise determination of many assets and liabilities is dependent upon future events. Actual results may differ from estimated amounts.

The amounts recorded for depletion, depreciation of property and equipment, long-term liability, stock-based compensation, contingent consideration, decommissioning liabilities, derivatives, warrants, and deferred taxes are based on estimates. The depreciation charge and any impairment tests are based on estimates of proved and probable reserves, production rates, prices, future costs and other relevant assumptions. By their nature, these estimates are subject to measurement uncertainty and the effect on the financial statements of changes in such estimates in future periods could be material.

4.REVENUE
Three months ended March 31
20112010
US$'000US$'000
Oil Sales25,13330,102
Gas Sales3,922-
Condensate Sales321-
Other Income1,674665
Total31,05030,767
5.ADMINISTRATIVE EXPENSES
Three months ended March 31
20112010
US$'000US$'000
General & administrative469776
Stock based compensation5911,181
1,0601,957
6.COST OF SALES
Three months ended March 31
20112010
US$'000US$'000
Operating costs10,2468,689
Depletion, Depreciation and Amortisation6,9724,389
17,21813,078
7. RESTRICTED CASH
March 31Dec 31 Jan 1
20112010 2010
US$'000US$'000 US$'000
Decommissioning security 7,2395,956 -
Cash security - Crown Estate 356352 352
Cash security - Foreign exchange contract -- 5,224
7,5956,308 5,576

Restricted cash of $7.2 million is held by the Bank of Scotland as decommissioning security in respect of the Corporation's interests in the Anglia and Topaz fields.

Further restricted cash of $0.4 million is held by the Bank of Scotland as cash security for a Bank Guarantee that Ithaca Energy (UK) Limited provided to the Crown Estate when it was granted Field Development Plan approval for the Jacky Field.

$5.2 million of restricted cash held by the Bank of Scotland in 2009 as cash security for the 2010 foreign exchange forward contract was released in January 2010.

8. EXPLORATION AND EVALUATION ASSETS
US$'000
Cost
At January 1, 201015,500
Additions3,141
Write offs/relinquishments
(1,119)
At December 31, 201017,522
Additions1,213
Write offs/relinquishments
(1,481)
At March 31, 201117,254

Following completion of geotechnical evaluation activity, certain licences were declared unsuccessful and certain prospects were declared non-commercial and therefore the related expenditures of $1.5 million were expensed in the three months to March 31, 2011. $2 million of associated contingent consideration relating to those licences and prospects was also released to the consolidated statement of income to give a total credit of $0.5 million. See note 13 for details.

9. PROPERTY, PLANT AND EQUIPMENT
Development & Production
Oil and Gas AssetsOther fixed assetsTotal
US$'000US$'000US$'000
Cost
At January 1, 2010189,4581,274190,732
Additions82,87931383,192
Disposals---
Write offs/relinquishments---
At December 31, 2010272,3371,587273,924
Additions22,67738223,059
Disposals---
Write offs/relinquishments---
At March 31, 2011295,0141,969296,983
DD&A
At January 1, 2010-(757)(757)
Charge for the period(22,852)(347)(23,199)
At December 31, 2010(22,852)(1,104)(23,956)
Charge for the Quarter(6,885)(87)(6,972)
At March 31, 2011(29,737)(1,191)(30,928)
NBV at January 1, 2010189,458517189,975
NBV at January 1, 2011249,485483249,968
NBV at March 31, 2011265,277778266,055

10. LOAN FACILITY

On July 12, 2010, the Corporation signed and completed a Senior Secured Borrowing Base Facility agreement (the "Facility") for up to US$140 million with the Bank of Scotland Plc. The loan term is up to five years and will attract interest at LIBOR plus 3-4.5%. Loan issue costs of $0.9 million have been incurred in the year ended December 31, 2010 and are being amortized over the period of the loan (approx $0.2 million amortized in the year ended December 31, 2010).

The Corporation is subject to financial and operating covenants related to the Facility. Failure to meet the terms of one or more of these covenants may constitute an event of default as defined in the Facility agreement, potentially resulting in accelerated repayment of the debt obligations.

The Corporation is in compliance with its financial and operating covenants.

No funds are currently drawn down under the Facility.

11.DECOMMISSIONING LIABILITIES
March 31Dec 31
20112010
US$'000US$'000
Balance, beginning of period23,6528,751
Additions-12,772
Accretion177283
Revision to estimates(273)1,846
Balance, end of period23,55623,652

The total future decommissioning liability was calculated by management based on its net ownership interest in all wells and facilities, estimated costs to reclaim and abandon wells and facilities and the estimated timing of the costs to be incurred in future periods. The Corporation uses a risk free rate of 3.3 percent and an inflation rate of 2 percent over the varying lives of the assets to calculate the present value of the decommissioning liabilities. These costs are expected to be incurred at various intervals over the next 9 years. The economic life and the timing of the obligations are dependent on Government legislation, commodity price and the future production profiles of the respective production and development facilities. Note that upon the acquisition of the Beatrice Field in November 2008, the Corporation did not assume the decommissioning liabilities.

The addition to the liability in 2010 was due to the liabilities assumed as part of the GDF acquisition.

12.OTHER LONG TERM LIABILITIESMarch 31Dec 31
20112010
US$'000US$'000
Balance, beginning of period2,8722,718
Revaluation in the period(114)154
Balance, end of period2,7582,872

On completion of the acquisition of the Beatrice Facilities on November 10, 2008 there were 75,000 barrels of oil in an oil storage tank at the Nigg Terminal. This volume of oil is required to be in the storage tank when the Beatrice Facilities are re-transferred. This volume of oil is valued at the price on the forward oil price curve at the expected date of re-transfer and discounted. The liability is subject to revaluation at each financial period end. The expected date of re-transfer is likely to be more than three years in the future.

13. CONTINGENT CONSIDERATION
March 31Dec 31
20112010
US$'000US$'000
Balance, beginning of period 12,9766,933
Additions -2,000
Revision to estimates (2,000)4,043
Balance, end of period 10,97612,976

The contingent consideration at the end of the period relates to the acquisition of the Stella field.

The revaluation in the period relates to the reassessment of the Opal and Garnet prospects which have been determined uncommercial, resulting in a release of the associated contingent consideration.

14.SHARE CAPITAL
(a)Issued
The issued share capital is as follows:
Issued
Number of common sharesAmount US$'000
Balance January 1, 2010162,361,975277,075
Issued for cash - options exercised765,205305
Transfer from Contributed Surplus on options exercised273
Issued for cash - prospectus92,662,284153,248
Share issue costs(8,528)
Balance December 31, 2010255,789,464422,373
Issued for cash - options exercised245,831199
Issued for cash - warrants exercised2,500,0005,786
Transfer from Contributed Surplus on options exercised148
Transfer from Warrants issued on warrants exercised311
Balance March 31, 2011258,535,295428,817

On July 28 2010, the Corporation successfully closed a Canadian bought deal and UK private placement. Gross proceeds were $78.3 million (C$80.9 million) through the issue of 47.6 million shares at a price of C$1.70 per share and $74.9 million (£48.2 million) through the issue of 45.1 million shares at £1.07 per common share.

(b) Stock options

In the quarter ended March 31, 2011, the Corporation's Board of Directors granted 260,000 options at a weighted average exercise price of $1.99 (C$2.01). 200,000 of these options were reserved for issue in Q3 2010 in contemplation of hiring.

The Corporation's stock options and exercise prices are denominated in Canadian Dollars when granted. As at March 31, 2011, 19,798,505 stock options to purchase common shares were outstanding, having an exercise price range of $0.23 to $3.65 (C$0.25 to C$3.65) per share and a vesting period of up to 3 years in the future.

Changes to the Corporation's stock options are summarized as follows:
March 31, 2011 December 31, 2010
Wt. Avg Wt. Avg
No. of Options Exercise Price * No. of Options Exercise Price *
Balance, beginning of period 20,146,003 $1.61 11,042,875 $1.48
Granted 260,000 $1.99 10,100,000 $1.88
Forfeited / expired (361,667) $2.00 (231,667) $1.28
Exercised (245,831) $0.77 (765,205) $0.33
Options 19,798,505 $1.74 20,146,003 $1.61
* The weighted average exercise price has been converted into U.S. dollars based on the foreign exchange rate in effect at the date of issuance.
The following is a summary of stock options as at March 31, 2011
Options OutstandingOptions Exercisable
Range ofWt. Avg. LifeWt. Avg. ExerciseRange ofWt. Avg. LifeWt. Avg. Exercise
Exercise PriceNo. of Options(Years)Price *Exercise PriceNo. of Options(Years)Price *
$3.65 (C$3.65)2,365,0000.9$3.65$3.65 (C$3.65)2,331,6670.9$3.65
$2.22-$2.86$2.22-$2.86 (C$2.25-
(C$2.25-C$3.00)6,335,0003.1$2.25C$3.00)1,185,0000.2$2.33
$1.49-$1.76$1.49-$1.68 (C$1.54-
(C$1.54-C$1.85)5,411,6672.6$1.55C$1.80)1,711,6642.6$1.53
$0.23-$0.80$0.20-$0.81 (C$0.25-
(C$0.25-C$0.87)5,686,8382.5$0.55C$0.87)2,411,9192.6$0.45
19,798,5052.6$1.747,640,2501.7$1.96
The following is a summary of stock options as at December 31, 2010
Options OutstandingOptions Exercisable
Range of Wt. Avg. LifeWt. Avg. ExerciseRange ofWt. Avg. LifeWt. Avg. Exercise
Exercise PriceNo. of Options(Years)Price *Exercise PriceNo. of Options(Years)Price *
$3.65 (C$3.65)2,435,0001.14$3.65$3.65 (C$3.65)1,623,3341.1$3.65
$2.22-$2.86$2.29-$2.86 (C$2.51-
(C$2.25-C$3.00)6,375,0002.40$2.25C$3.00)1,285,0000.3$2.38
$1.49-$1.76$1.49-$1.68 (C$1.54-
(C$1.54-C$1.85)5,345,0003.01$1.54C$1.80)300,0001.7$1.68
$0.20-$0.80$0.20-$0.81 (C$0.25-
(C$0.25-C$0.87)5,991,0032.77$0.55C$0.87)2,591,0842.8$0.45
20,146,0032.50$1.615,799,4181.3$1.44

(d) Stock based compensation

Options granted are accounted for using the fair value method. The compensation cost during the three months ended March 31, 2011 for total stock options granted was $1.6 million (Q1 2010: $1.2 million). $0.6 million was charged through the income statement for stock based compensation for the three months ended March 31, 2011, being the Corporation's share of stock based compensation chargeable through the income statement. The remainder of the Corporation's share of stock based compensation has been capitalized. The fair value of each stock option granted was estimated at the date of grant, using the Black-Scholes option pricing model with the following assumptions:

For the three months endedFor the year ended
March 31, 2011December 31, 2010
Risk free interest rate1.20%1.20%
Expected stock volatility97%104%
Expected life of options3 years3 years
Weighted Average Fair Value$1.64$1.14

(d) Gemini Agreement

In September 2006 Gemini Oil & Gas Fund 11 L.P. ("Gemini") provided non–recourse funding of $6 million. Further to a supplemental agreement entered into in August 2008, the loan was fully repaid. Under the supplemental agreement Gemini retained rights, under certain circumstances relating to the Athena Field, to elect to receive warrants to acquire up to 3,000,000 common shares at $3.00 per share and to receive payments connected to asset sales of interests in Athena.

On September 20, 2010, a further agreement was entered into with Gemini whereby in exchange for and in consideration of Gemini's waiver of any right to proceeds from the disposal of equity interest in the Athena discovery and in substitution for any previously awarded or agreed warrants, Ithaca Energy Inc. granted Gemini warrants to acquire up to 2,500,000 common shares in Ithaca Energy Inc. The warrants were exercised at C$2.25 per share on March 3, 2011. The agreement terminates all rights that Gemini has in respect of the Corporation's interests. The total fair value attributed to warrants issued in 2010 was $0.3 million.

15. CONTRIBUTED SURPLUS
March 31,Dec 31, 2010
US$'000US$'000
Balance, beginning of period11,4276,860
Stock based compensation cost1,5854,840
Transfer to share capital on exercise of options(148)(273)
Balance, end of period12,86411,427

16. EARNINGS PER SHARE

The calculation of basic earnings per share is based on the profit after tax and the weighted average number of common shares in issue during the period. The calculation of diluted earnings per share is based on the profit after tax and the weighted average number of potential common shares in issue during the period.

Three months ended March 31,
20112010
Weighted average number of common shares (basic)256,839,092162,555,640
Weighted average number of common shares (diluted)262,744,370165,518,118
17. TAXATION
Three months ended March 31,
20112010
US$000US$000
Deferred tax6,426-

Current corporation tax payable of $18k is related to tax on interest income from cash held on deposit. No corporation tax is payable in relation to upstream oil and gas activities.

18. COMMITMENTS
Year endedSubsequent to
20112012201320142014
US$'000US$'000US$'000US$'000US$'000
Office lease 192 257 257 257 834
Exploration 876 1,249 1,603 - -
Engineering 19,149 12,266 20,666 12,266 -
Total 20,218 13,772 22,526 12,523 834

19. FINANCIAL INSTRUMENTS

To estimate fair value of financial instruments, the Corporation uses quoted market prices when available, or industry accepted third-party models and valuation methodologies that utilize observable market data. In addition to market information, the Corporation incorporates transaction specific details that market participants would utilize in a fair value measurement, including the impact of non-performance risk. The Corporation characterizes inputs used in determining fair value using a hierarchy that prioritizes inputs depending on the degree to which they are observable. However, these fair value estimates may not necessarily be indicative of the amounts that could be realized or settled in a current market transaction. The three levels of the fair value hierarchy are as follows:

  • Level 1 – inputs represent quoted prices in active markets for identical assets or liabilities (for example, exchange- traded commodity derivatives). Active markets are those in which transactions occur in sufficient frequency and volume to provide pricing information on an ongoing basis.
  • Level 2 – inputs other than quoted prices included within Level 1 that are observable, either directly or indirectly, as of the reporting date. Level 2 valuations are based on inputs, including quoted forward prices for commodities, market interest rates, and volatility factors, which can be observed or corroborated in the marketplace. The Corporation obtains information from sources such as the New York Mercantile Exchange and independent price publications.
  • Level 3 – inputs that are less observable, unavailable or where the observable data does not support the majority of the instrument's fair value.

In forming estimates, the Corporation utilizes the most observable inputs available for valuation purposes. If a fair value measurement reflects inputs of different levels within the hierarchy, the measurement is categorized based upon the lowest level of input that is significant to the fair value measurement. The valuation of over-the-counter financial swaps and collars is based on similar transactions observable in active markets or industry standard models that primarily rely on market observable inputs. Substantially all of the assumptions for industry standard models are observable in active markets throughout the full term of the instrument. These are categorized as Level 2.

The following table presents the Corporation's material financial instruments measured at fair value for each hierarchy level as of March 31, 2011:

Total Fair
Level 1Level 2Level 3Value
US$'000US$'000US$'000US$'000
Derivative financial instrument asset-2,003-2,003
Long term liability on Beatrice acquisition--(2,758)(2,758)
Contingent Consideration-(10,976)-(10,976)
Derivative financial instrument liability-(4,735)-(4,735)

The table below presents the total gain / (loss) on financial instruments that has been disclosed through the statement of net and comprehensive income / (loss):

Three months ended March 31,
20112010
US$'000US$'000
Unrealized (loss) / gain on foreign exchange forward contracts -(2,389)
Realized (loss) / gain on foreign exchange forward contracts -(251)
Revaluation of gas contract (197)-
Revaluation of other long term liability 114184
Unrealized gain / (loss) on commodity hedges (1,711)86
Realized (loss) / gain on commodity hedges (493)396
Total (loss) / gain on derivatives(2,287)(1,974)

The Corporation has identified that it is exposed principally to these areas of market risk.

i) Commodity Risk

Commodity price risk related to crude oil prices is the Corporation's most significant market risk exposure. Crude oil prices and quality differentials are influenced by worldwide factors such as OPEC actions, political events and supply and demand fundamentals. The Corporation is also exposed to natural gas price movements on uncontracted gas sales. Natural gas prices, in addition to the worldwide factors noted above, can also be influenced by local market conditions. The Corporation's expenditures are subject to the effects of inflation, and prices received for the product sold are not readily adjustable to cover any increase in expenses from inflation. The Corporation may periodically use different types of derivative instruments to manage its exposure to price volatility, thus mitigating fluctuations in commodity-related cash flows.

In Q4 2009 the Corporation entered into a forward swap for 51,000 barrels per month over November, December, January and February 2010 production fixing the price at $77/barrel. In Q4 2010, the Corporation entered into another forward swap for 108,668 and 80,600 barrels per month over December and January respectively to hedge a proportion of November and December production. The combination of these forward swaps resulted in a realized loss of $0.5 million and an unrealized gain of $0.3 million in the three months ended March 31, 2011. If the oil price had been lower by $1 per barrel in 2011 then the profit for the three months to March 31, 2011 would have been lower by $0.3 million.

In Q1 2011 the Corporation purchased a put option with a floor price of $105 / barrel for 804,500 barrels of oil for the period March to December 2011. The option delivers a minimum price on the specified volume of oil and allows the Corporation to benefit from any upside above $105 / barrel. Due to movements in forecast oil prices the revaluation of this instrument as at March 31, 2011 resulted in an unrealized loss of $2.1 million.

ii) Interest Risk

Calculation of interest payments for the Senior Secured Borrowing Base Facility agreement with the Bank of Scotland that was signed on July 12, 2010 incorporates LIBOR. The Corporation will therefore be exposed to interest rate risk to the extent that LIBOR may fluctuate. The Corporation will evaluate its annual forward cash flow requirements on a rolling monthly basis. No funds are currently drawn down under the facility.

iii) Foreign Exchange Rate Risk

The Corporation is exposed to foreign exchange risks to the extent it transacts in various currencies, while measuring and reporting its results in US Dollars. Since time passes between the recording of a receivable or payable transaction and its collection or payment, the Corporation is exposed to gains or losses on non USD amounts and on balance sheet translation of monetary accounts denominated in non USD amounts upon spot rate fluctuations from quarter to quarter.

On July 7, 2010, in order to protect against the strengthening of the US Dollar and secure the net proceeds from the equity raise of $150 million the Corporation entered into a foreign exchange forward contract to swap the Canadian Dollars and Pounds Sterling proceeds of the Canadian bought deal and UK Private placement in exchange for US Dollars when the proceeds were estimated to be received at contracted rates of $1.00 / C$1.0489 and $1.00 / £0.6592. During the period the US Dollar weakened with the result that the forex instruments prevented an exchange gain being realized. Forex losses of $3.1 million were recorded which offset the natural gain reflected in equity.

On October 12, 2009, the Corporation entered in to a Window Forward Plus contract with the Bank of Scotland to hedge its forecast British Pounds Sterling 2010 operating costs, including general and administrative expenses. The hedge amounts to $4 million per month (total $48 million) at a US$/£ rate of no worse than USD1.60/1.0 and a Trigger rate of USD1.4975/£1.00. A realized loss of $1.3 million has been recognized on the contract for the year ended December 31, 2010. This contract expired in December 2010, and the resulting unwinding of unrealized gains and losses on the contracts resulted in an unrealized loss of $0.7 million for the year ended December 31, 2010.

iv) Credit Risk

The Corporation's accounts receivable with customers in the oil and gas industry are subject to normal industry credit risks and are unsecured. It should be noted that the Corporation has entered in to a five year marketing agreement with BP Oil International Limited to sell all of its North Sea oil production. All gas production, acquired through the purchase of the Anglia and Topaz fields from GDF SUEZ E&P UK Ltd, is sold through three contracts on a monthly basis to RWE NPower PLC and Hess Energy Gas Power (UK) Ltd.

The Corporation assesses partners' credit worthiness before entering into farm-in or joint venture agreements. In the past, the Corporation has not experienced credit loss in the collection of accounts receivable. As the Corporation's exploration, drilling and development activities expand with existing and new joint venture partners, the Corporation will assess and continuously update its management of associated credit risk and related procedures.

The Corporation regularly monitors all customer receivable balances outstanding in excess of 90 days. As at March 31, 2011 over 99% of accounts receivables are current, being defined as less than 90 days. The Corporation has no allowance for doubtful accounts as at March 31, 2010 (December 31, 2010 $Nil).

The Corporation may be exposed to certain losses in the event that counterparties to derivative financial instruments are unable to meet the terms of the contracts. The Corporation's exposure is limited to those counterparties holding derivative contracts with positive fair values at the reporting date. As at March 31, 2011, exposure is $2 million (December 31, 2010: $Nil).

The Corporation also has credit risk arising from cash and cash equivalents held with banks and financial institutions. The maximum credit exposure associated with financial assets is the carrying values.

v) Liquidity Risk

Liquidity risk includes the risk that as a result of its operational liquidity requirements the Corporation will not have sufficient funds to settle a transaction on the due date. The Corporation manages liquidity risk by maintaining adequate cash reserves, banking facilities, and by considering medium and future requirements by continuously monitoring forecast and actual cash flows. The Corporation considers the maturity profiles of its financial assets and liabilities. As at March 31, 2011, substantially all accounts payable are current.

The following table shows the timing of cash outflows relating to trade and other payables.
Within 1 year1 to 5 years
US$'000US$'000
Accounts payable and accrued liabilities75,312-
Other long term liabilities-2,758
Total75,3122,758
20.DERIVATIVE FINANCIAL INSTRUMENTS
March 31December 31January 1
201120102010
US$'000US$'000US$'000
Oil put premium2,003--
Embedded Derivative(4,735)(4,378)-
Foreign exchange forward contract--685

In Q1 2011 the Corporation entered into a 'put' option to sell 804,500 barrels of the Corporation's 2011 forecast production at $105 / bbl. This is recognized at its fair value in the financial statements. Fair value represents the market price for the instrument, measured as at March 31, 2011.

In Q4 2010, the Corporation acquired an embedded derivative within an Anglia gas sales contract. This is recognized at its fair value in the financial statements. Fair value represents the difference between the contract price and the period end market price for the contracted volumes.

21. FAIR VALUES OF FINANCIAL ASSETS AND LIABILITIES

Financial instruments of the Corporation consist mainly of cash and cash equivalents, receivables, payables, loans and financial derivative contracts, all of which are included in these financial statements. At December 31, 2010, the classification of financial instruments and the carrying amounts reported on the balance sheet and their estimated fair values are as follows:

March 31, 2011December 31, 2010
US$'000US$'000
ClassificationCarryingCarrying
AmountFair ValueAmountFair Value
Cash and cash equivalents (Held for trading)191,334191,334195,581195,581
Restricted cash7,5957,5956,3086,308
Derivative financial instruments (Held for trading)2,0032,003--
Accounts receivable (Loans and Receivables)90,15990,15993,43493,434
Deposits257257248248
Loan fees - current273273286286
Loan fees - non-current456456521521
Commodity hedge (Held for trading)--397397
Contingent consideration10,97610,97612,97612,976
Derivative financial instruments (Held for trading)4,7354,7354,3784,378
Other long term liabilities2,7582,7582,8722,872
Accounts payable (Other financial liabilities)75,31275,31275,56475,564

22. RELATED PARTY TRANSACTIONS

A Director of the Corporation is a partner of Burstall Winger LLP who acts as counsel for the Corporation. The amount of fees paid to Burstall Winger LLP in the quarter ended March 31, 2011 was $0.1 million (March 31, 2010 - $Nil). The balance outstanding at March 31, 2011 was $Nil (March 31, 2010 - $Nil).

23. SEASONALITY

The effect of seasonality on the Corporation's financial results for any individual quarter is not material.

24. TRANSITION TO IFRS

These are the Corporation's first condensed interim consolidated financial statements to be prepared in accordance with IFRS.

The accounting policies in Note 3 have been applied in preparing the condensed interim consolidated financial statements for the first three months ended March 31, 2011, the comparative information for the three months ended March 31, 2010, the balance sheet for the year ended December 31, 2010 and the preparation of an opening IFRS balance sheet on the transition date, January 1, 2010.

An explanation of how the transition from Canadian GAAP to IFRS has affected the Corporation's financial position, financial performance and cash flows is set out below.

IFRS 1 Exemptions

IFRS 1 First-Time Adoption of International Financial Reporting Standards allows first-time adopters certain exemptions from retrospective application of certain IFRS.

The Corporation has applied the following exemptions:

Oil and gas assets in property, plant and equipment were recognized and measured on a full cost basis in accordance with Canadian GAAP. The Corporation has elected to measure its properties at the amount determined under Canadian GAAP as at January 1, 2010. Costs included in the full cost pool on January 1, 2010 were allocated on a pro rata basis to the underlying assets on the basis of pre-tax net present values using proved and probable reserves as at January 1, 2010.

Associated decommissioning assets were also measured at their carrying value under Canadian GAAP while all decommissioning liabilities were measured using a risk free rate, with a corresponding adjustment recorded to opening retained earnings.

IFRS 3 Business Combinations has not been applied to acquisitions of subsidiaries or interests in joint ventures that occurred before January 1, 2010.

IFRS 2 Share-Based Payments has not been applied to equity awards that were granted prior to November 7, 2002, nor those that were granted after November 7, 2002 and vested prior to January 1, 2010.

The Corporation has elected to apply IAS 23 Borrowing Costs with an effective date of January 1, 2010 which requires mandatory capitalization of borrowing costs directly attributable to the acquisition, construction or production of qualifying assets. No borrowing costs previously capitalized in accordance with Canadian GAAP have been derecognized.

Reconciliations from Canadian GAAP to IFRS

In preparing the interim condensed Consolidated Financial Statements, the Corporation has adjusted amounts reported previously in its Consolidated Financial Statements prepared under Canadian GAAP. The following reconciliations present the adjustments made to the Corporation's financial position, financial performance and cashflow (as required by IFRS 1), along with explanatory notes.

Reconciliation of equity as at January 1, 2010 (date of transition to IFRS)

CGAAPIFRS AdjIFRS
US$'000US$'000US$'000
ASSETS
Current assets
Cash and cash equivalents29,886-29,886
Restricted Cash5,224-5,224
Accounts receivable67,166-67,166
Deposits, prepaid expenses and other352-352
Foreign exchange forward contract685-685
103,313-103,313
Non current assets
Restricted cash352-352
Exploration and evaluation assets (note a)-15,50015,500
Property, Plant & Equipment (notes a, b, c)205,475(15,500)189,975
205,827-205,827
Total assets309,140-309,140
LIABILITIES AND EQUITY
Current Liabilities
Trade and other payables43,613-43,613
Commodity hedge397-397
44,010-44,010
Non current liabilities
Long term liability2,718-2,718
Decommissioning liabilities (note d)7,9567958,751
Contingent consideration (note e)-6,9336,933
10,6747,72818,402
Net assets254,456(7,728)246,728
Equity attributable to equity holders
Share Capital277,075-277,075
Contributed surplus (note f)7,812(952)6,860
Retained Earnings / (Deficit) (notes d and e)(30,431)(6,776)(37,207)
Shareholders' Equity254,456(7,728)246,728
Reconciliation of equity as at March 31, 2010
CGAAPIFRS AdjIFRS
US$'000US$'000US$'000
ASSETS
Current assets
Cash and cash equivalents20,084-20,084
Accounts receivable81,194-81,194
Deposits, prepaid expenses and other4,589-4,589
105,867-105,867
Non current assets
Restricted cash335-335
Exploration and evaluation assets (note a)-16,08716,087
Property, Plant & Equipment (notes a, b, c)208,616(9,382)199,234
208,9516,705215,656
Total assets314,8186,705321,523
LIABILITIES AND EQUITY
Current Liabilities
Trade and other payables43,164-43,164
43,164-43,164
Non current liabilities
Long term liability2,534-2,534
Decommissioning liabilities (note d)8,1107138,823
Contingent consideration (e)-6,9336,933
Derivative financial instruments---
10,6447,64618,290
Net assets261,010(941)260,069
Equity attributable to equity holders
Share Capital277,174-277,174
Contributed surplus (note f)8,916(922)7,993
Retained earnings (notes b, d, e and f)(25,080)(19)(25,099)
Shareholders' Equity261,010(941)260,069
Reconciliation of equity as at December 31, 2010
CGAAPIFRS AdjIFRS
US$'000US$'000US$'000
ASSETS
Current assets
Cash and cash equivalents195,581-195,581
Restricted Cash6,308-6,308
Accounts receivable93,434-93,434
Deposits, prepaid expenses and other12,341-12,341
Deferred Tax Asset (note g)16,074(12,329)3,745
323,738(12,329)311,409
Non current assets
Exploration and evaluation assets (note a)-17,52217,522
Property, Plant & Equipment (notes a, b, c)238,11311,855249,968
238,11329,377267,490
-
Total assets561,85117,048578,899
LIABILITIES AND EQUITY
Current Liabilities
Trade and other payables75,564-75,564
Commodity hedge349349
75,913-75,913
Non current liabilities
Long term liability2,872-2,872
Decommissioning liabilities (note d)20,8682,78423,652
Contingent consideration (e)-12,97612,976
Derivative financial instruments4,378-4,378
28,11815,76043,878
Net assets457,8201,288459,108
Equity attributable to equity holders
Share Capital422,373-422,373
Contributed surplus (note f)11,530(103)11,427
Warrants issued311-311
Brought Forward Deficit (notes b, d, e and f)23,6061,39124,997
Shareholders' Equity457,8201,288459,107
Reconciliation of total comprehensive income for the three months ended March 31, 2010
CGAAPIFRS AdjIFRS
US$'000US$'000US$'000
Revenue30,767-30,767
Cost of Sales (note b)(19,783)6,705(13,078)
Gross Profit10,9846,70517,689
Admin expenses (note f)(1,927)(30)(1,956)
Operating Profit9,0576,67515,733
Foreign exchange(1,576)-(1,576)
Gain / (Loss) on financial instruments(1,974)-(1,974)
Profit on ordinary activities Before Interest and Tax5,5076,67512,182
Finance costs (note d)(158)82(76)
Interest Income2-2
Profit Before Tax5,3516,75712,108
Taxation---
Profit After Tax5,3516,75712,108
Reconciliation of total comprehensive income for the year ended December 31, 2010
CGAAPIFRS AdjIFRS
US$'000US$'000US$'000
Revenue135,121-135,121
Cost of Sales (note b)(87,307)26,257(61,050)
Gross Profit47,81426,25774,071
Exploration and evaluation (note a)-(1,119)(1,119)
Admin expenses (note f)(4,620)(848)(5,468)
Operating Profit43,19424,29067,484
Foreign exchange818-818
Revaluation of financial instruments (note e)(5,268)(4,044)(9,312)
Profit on ordinary activities Before Interest and Tax38,74420,24658,990
Finance costs (note d)(814)249(565)
Interest Income113113
Profit Before Tax38,04320,49558,538
Taxation (note g)15,994(12,329)3,665
Profit After Tax54,0378,16662,203

Adjustments to the statement of cash flows

All IFRS transition adjustments were non-cash items therefore the transition from Canadian GAAP to IFRS had no impact on cash flows generated by the Corporation, nor on the categorisation cashflows between operating activities, investing activities or financing activities.

Notes to the reconciliations of equity and total comprehensive income from Canadian GAAP to IFRS

(a) Exploration and evaluation assets

Under IFRS 6, as at January 1, 2010, management has deemed exploration and evaluation assets to be $15.5 million, representing the unproved properties balance under previous GAAP. This resulted in reclassification of $15.5 million from property, plant and equipment to exploration and evaluation assets.

(b) Depletion, Depreciation and Amortization

Under Canadian GAAP, development costs were depleted on a unit of production basis based on the proved reserves of the cost pool. Under IFRS, the Corporation depletes development costs at a field level on a unit of production basis, and has elected to deplete these over the proved and probable reserves of the assets. For the three months ended March 31, 2010, the Corporation has recognized depletion, depreciation and amortization expense of $4.4 million under IFRS when compared to $11.1 million under Canadian GAAP. For the year ended December 31, 2010, the Corporation has recognized depletion, depreciation and amortization expense of $23.2 million under IFRS when compared to $49.5 million under Canadian GAAP.

(c) Deemed cost allocation

The most significant changes to the Corporation's accounting policies relate to the accounting for upstream costs. Under Canadian GAAP, the Corporation followed the full cost method of accounting for oil and gas assets whereby all costs of acquisition, exploration for and development of oil and gas reserves were capitalized and accumulated within one cost centre (UK North Sea). Costs accumulated were depleted using the unit-of-production method based on proved reserves determined using estimated future prices and costs.

The Corporation has elected to apply the IFRS 1 exemption for its Canadian oil and gas assets whereby development costs as at January 1, 2010 were deemed to be $189.5m, being the full cost proved PP&E net book value. As stated above exploration and evaluation costs as at January 1, 2010 were deemed to be $15.5m, being the unproved properties balance under Canadian GAAP.

(d) Decommissioning Liabilities

Under Canadian GAAP, similar to IFRS, decommissioning liabilities were calculated based on the Corporation's best estimate of the expenditure required to settle the present obligation at the end of the reporting period or to transfer it to a third party at that time. The liability is however required to be remeasured at the end of each period including changes in discount rates. As stated above, the Corporation utilized an exemption under IFRS for measurement of oil and gas assets. This exemption has a consequential impact to the measurement of the oil and gas assets' decommissioning liabilities upon transition to IFRS, whereby the differences arising from the remeasurement of the decommissioning liabilities are taken directly to retained earnings rather than adjusting the carrying amount of the underlying oil and gas assets. This resulted in an increase in decommissioning liabilities and a decrease to retained earnings of $0.8 million as at January 1, 2010.

Subsequent remeasurements and differences in accretion were recorded in property, plant and equipment and finance costs respectively. For the three months ended March 31, 2010, the Corporation recorded accretion of less than $0.1 million compared to $0.2 million under CGAAP. As at December 31, 2010, the Corporation remeasured the decommissioning liabilities resulting in an increase to decommissioning liabilities of $2.7 million. For the 12 months ended December 31, 2010, the Corporation reduced recorded accretion by $0.2 million.

Associated decommissioning assets were measured at their carrying value under Canadian GAAP while all decommissioning liabilities were measured using a risk free rate, with a corresponding adjustment recorded to opening retained earnings.

(e) Contingent consideration

Under IFRS, contingent consideration is required to be accounted for as a financial liability and measured at fair value at the date of acquisition with any subsequent remeasurements recognised either in profit or loss or in other comprehensive income in accordance with IAS 39.

On transition, as at January 1, 2010, the Corporation recognized a liability of $6.9 million and an decrease in retained earnings relating to a contingent consideration on the Stella acquisition.

As at December 31, 2010, the Corporation recognized a further $6 million of contingent consideration, being $4m adjustment to the Stella acquisition (opposite side recognised in the income statement) and the recognition of $2 million liability relating to the GDF assets acquisition (opposite side recognised in PP&E).

(f) Share based payments

Under Canadian GAAP, similar to IFRS, the expense relating to the Corporation's equity-settled stock based compensation plans was recorded at fair value using the Black-Scholes option pricing model.

Some of the required valuation inputs however differ according to each GAAP. As stated above, on transition, as at January 1, 2010, the Corporation recognized an decrease in contributed surplus with an offset in an increase in retained earnings of $1 million.

(g) Deferred tax

Deferred tax has been adjusted to reflect the tax effect arising from the differences between IFRS and Canadian GAAP. Upon transition to IFRS, similar to Canadian GAAP, no deferred tax asset was recognized as realization of the asset was not considered to be more likely than not. For the twelve months ended December 31, 2010, the application of the IFRS adjustments as discussed in a) to f) above resulted in the recognition of a reduced deferred tax asset of $3.7 million and a $12.3 million decrease to the Company's deferred tax credit.

25. SUBSEQUENT EVENTS

In April 2011 the Corporation entered into an agreement to acquire a 28.46% non-operated interest in the Cook oil field and a 7.41% non-operated interest in the Maclure oil field from Hess Limited ("Hess") for a consideration of $74.5 million and the transfer from Ithaca to Hess of a 10% interest in each of exploration Blocks 42/25b, 43/16a and 43/21c in the Southern North Sea. The acquisition of Maclure was subject to pre-emption within 30 days of notification to other parties in the Maclure field. In May 2011, the Corporation was notified an exercising notice had been received in relation to the right of pre-emption. Subject to completed documentation being executed by Hess and any pre-empting parties, the interest in the Maclure field will be removed from the acquisition and the consideration will be adjusted to $62.5 million. The transaction is expected to complete in Q3 2011 with an effective date of January 1, 2011.

In April 2011 the Corporation signed an earn in agreement with Challenger Minerals (North Sea) Limited ("CMI") on the Hurricane discovery. Under the terms of the agreement CMI has agreed to pay a share of the initial well costs in return for an option, exercisable within 90 days of abandonment or suspension of the initial appraisal and any sidetrack well, to acquire an interest in Block 29/10b. CMI will pay 40% of gross Hurricane appraisal well costs in exchange for a 31% equity interest in Block 29/10b, thereby carrying a part of Ithaca's share of all costs of drilling an initial appraisal well. In addition, upon successful appraisal, CMI will pay 40% of gross costs of a drill stem well test of any sidetrack. All additional costs, including those for planned sidetrack drilling, will be apportioned such that CMI will pay its 31% pro rata share. The transaction is subject to agreed 'turnkey' terms with ADTI for the provision of a suitable drilling unit and well management services.

Neither TSX Venture nor its Regulation Services Provider (as that term is defined in the policies of the TSX Venture Exchange) accepts responsibility for the adequacy or accuracy of this release.

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