Ithaca Energy Inc.
TSX VENTURE : IAE
AIM : IAE

Ithaca Energy Inc.

August 26, 2011 02:01 ET

Ithaca Energy Inc.: Second Quarter and Half Yearly 2011 Financial Results

LONDON, UNITED KINGDOM and CALGARY, ALBERTA--(Marketwire - Aug. 26, 2011) -

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

Ithaca Energy Inc. (TSX VENTURE:IAE)(AIM:IAE) announces its quarterly financial results for the three months ended June 30, 2011 and half yearly financial results for the six months ended June 30, 2011.

HIGHLIGHTS

Financial

  • Q2 Earnings of US$2.9 million (Q2 2010: US$14.1 million) resulting in Half Yearly Earnings of US$9.5 million (1H 2010: US$26.2 million)
  • Q2 Cashflow from Operations of US$3.7 million (Q2 2010: US$22.8 million) resulting in Half Yearly Cashflow from Operations of US$25.8 million (1H 2010: US$42.3 million)
  • Cash US$176.6 million, inclusive of US$7.6 million restricted cash (Q1 2011: US$198.9 million inclusive of restricted cash)
  • Undrawn US$140 million senior debt facility
  • Tax losses of US$265 million (Q1 2011 $221 million)
  • Further Oil Put Option taken out ensuring 2nd half 2011 Oil price floor of $115/barrel for 300,000 barrels (in addition to the previous Oil Put Option ensuring 10 months 2011 Oil price floor of $105/barrel for 804,500 barrels)
  • Results and comparatives are now reported under International Financial Reporting Standards ("IFRS")

Operations

  • Production averaged 2,040 barrels of oil equivalent per day ("boepd") net to Ithaca over the 3 months period to June 30 with sales averaging 1,950 boepd after accounting for increased pipeline stock. Q2 production was lower than anticipated mainly as a result of the failure of the Electrical Submersible Pumps ("ESP") in the Jacky J01 production well as well as unscheduled interruptions during the drilling of the Jacky J03 well. The pumps were replaced during June 2011 and Jacky production was fully restored at the start of July 2011.
  • The well workover campaign on Beatrice Alpha was completed in July, when the 'A21' well was returned to production following the re-completion of the well and deployment of a new ESP.
  • The modification works being performed in Dubai to extend the 'BW Athena' FPSO vessel by 65 feet and install a turret mooring system were completed on schedule in June 2011. The vessel was subsequently re-floated ready for installation of the new power generation and water injection modules.
  • The Sedco 704 drilling rig successfully concluded drilling operations on the Athena field in June 2011. The rig subsequently commenced the completion programme for the five development wells (four productions and one water injection), with operations on the 'A2', 'A3' and 'A4' wells having now been completed. The rig is currently undertaking completion operations on the fourth of the five well programme.
  • The Athena Field Subsea Installation campaign began in early August with loadout and transport to the field of the submerged buoy mooring system. Other subsea equipment including risers and flowlines has been delivered to quayside and is ready for installation. More details and images of the Athena project are provided on the Company's website: http://www.ithacaenergy.com/Athena-Area.asp
  • The first of the major contracts on the Stella project was awarded to GE Oil & Gas for the manufacture of the subsea trees and control systems. The Company has also completed an offshore geotechnical programme to determine the suitability of certain jackup drilling units at potential development drilling locations on the Stella and Harrier fields. The programme also included a borehole survey in advance of the planned Hurricane appraisal well.

Corporate

  • The Company 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 was completed on August 25, 2011 with an effective date of January 1, 2011 and an adjusted consideration of $57 million. The adjusted consideration does not reflect current oil inventory of approximately 185,000 barrels which will be part of the next Ithaca cargo lifting (of approximately 300,000 barrels) anticipated in Q4 2011.

    Cook production post completion shall be included in the Company's 2011 production figures. The field is currently producing approximately 7,000 boepd (1,992 boepd net to Ithaca).

    With the conclusion of the Cook acquisition, the Company now has three producing centres in Cook, Jacky & Beatrice and Anglia & Topaz. The commencement of production from Athena will further widen the Company's production base.
  • The Company signed an earn in agreement with Challenger Minerals (North Sea) Limited 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.

Notes:

Further details on the above are provided in the Interim Consolidated Financial Statements and Management's Discussion and Analysis for the three and six months ended June 30, 2011 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 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 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 Q2 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 JUNE 30, 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 and six months ended June 30, 2011. The information is provided as of August 25, 2011. The second 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 June 30, 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

'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 SECOND QUARTER 2011

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

Financial

  • Q2 Profit after tax of $2.9 million (Q2 2010: $14.1 million) resulting in Half yearly Profit after tax of $9.5 million (Q2 2010 YTD: $26.2 million)
  • Q2 Cashflow from operations of $3.7 million (Q2 2010: $22.8 million) resulting in Half yearly cashflow from operations of $25.8 million (Q2 2010 YTD: $42.3 million)
  • Cash $176.6 million, inclusive of $7.6 million restricted cash (Q1 2011: $198.9 million)
  • Undrawn $140 million senior debt facility
  • Tax losses of $265 million (Q1 2011 $221 million)
  • Further oil put option taken out ensuring 2nd half 2011 oil price floor of $115/barrel for 300,000 barrels (in addition to the previous oil put option ensuring 10 months 2011 Oil price floor of $105/barrel for 804,500 barrels)

Operational

Production

Production averaged 2,040 barrels of oil equivalent per day ("boepd") net to Ithaca over the 3 months period to June 30 with sales averaging 1,950 boepd. Production dipped in Q2 mainly as a result of the failure of the Electrical Submersible Pumps ("ESP") in the Jacky J01 production well and interruption to production caused by the drilling of the Jacky J03 well. The pumps were replaced during June 2011 and Jacky production was fully restored at the start of July 2011.

Athena

In June, 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.

Also in June, the modification and recertification work on the Floating Production Storage and Offload vessel ("FPSO") the 'BW Athena' was significantly progressed. The vessel was successfully separated for installation of a turret docking section welded into the structure amidships.

Following the end of the quarter, in July, the engineering and modifications associated with the dry dock works in Dubai to extend the vessel by 65 feet and install a turret docking system were completed. The vessel was re-floated ready for installation of the new power generation and water injection modules.

In July operations to prepare the Athena field development well 14/18b-A2Z for production were successfully concluded. A 7" production liner and a dual electrical submersible pump system were successfully installed above the horizontal section of the well and the subsea xmas tree and flowbase are now ready for hook-up of flowlines by the subsea installation contractor. The Sedco 704 drilling unit has stayed on location to undertake further completion work and has completed the 14/18b-16 and 14/18b-18 wells. It is now working on 14/18b-A1, the fourth well of a five well program of completions (four productions and one water injection) to be carried out before hook-up to the 'BW Athena'.

In August the Athena Field Subsea Installation campaign began with loadout and transport to the field of the submerged buoy mooring system. Other subsea equipment including risers and flowlines has been delivered to quayside and is ready for installation.

Jacky

In April 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 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). The J01 production well continued to free flow until the Jacky J03 well reached the target reservoir formation, in May. The Northern Enhancer rig was utilised to undertake a workover operation to replace the failed ESPs, reperforate the well and reinstate J01 production. The operation was completed in June. In July, following the end of the quarter, stable production from the Jacky field was restored at approximately 3,120 bopd (1,482 bopd net to Ithaca).

The Jacky J03 well noted above was 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.

Following an announcement in December 2010 that North Sea Energy was seeking to withdraw from participating in the drilling of 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.

Beatrice

Production from the Beatrice field wells has continued throughout the quarter. In April the workover of well A28 was partially completed and it is now free flowing at approximately 130 bopd gross (65 bopd net to Ithaca). Operations then transferred to the workover of the A21 well.

In July, the workover campaign on Beatrice Alpha was completed with the final workover well, A21, returned to ESP production. The workover unit was demobilised from Beatrice Alpha in July.

Beatrice production and water injection uptimes have remained excellent throughout the quarter with no significant process failures.

Stella

In July the development of the Stella field moved ahead with the placement of a contract with GE Oil & Gas to manufacture and supply subsea trees and controls systems. The initial phase of detailed engineering work commenced and is focusing on the procurement of forgings and materials for the systems. The systems will be delivered as an integrated package and are designed for installation using a heavy duty jackup drilling unit. A geotechnical program has also been successfully completed to determine the suitability of certain jackup drilling units at four potential development drilling locations on the Stella and Harrier fields. The program incorporated test boreholes in advance of the planned Hurricane appraisal well. Two drill centres will be selected. Final development concept selection will be made in the second half of 2011 with Field Development Plan ("FDP") submission expected by the end of the year.

Corporate

Cook Acquisition

The Company 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 transaction was completed on August 25, with an effective date of January 1, 2011 and an adjusted consideration of $57 million. The adjusted consideration does not reflect current oil inventory of approximately 185,000 barrels which will be part of the next Ithaca cargo lifting (of approximately 300,000 barrels) anticipated in Q4 2011.

The Maclure field, originally included in the agreement was subject to pre-emption, the right of which was exercised by one of the existing Maclure co-venturers. The interest in the Maclure field was therefore removed from the acquisition and the consideration was adjusted such that Ithaca acquired a 28.46% non-operated interest in the Cook field only.

The Reserves Audit Opinion on the Cook field issued by Sproule in the quarter confirmed management's view that the acquisition would increase the Corporation's remaining Proved plus Probable reserves by 5.75 million barrels of oil equivalent ("mmboe") net to Ithaca as at January 1, 2011 as reasonable.

Hurricane

In April 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.

Other

In April the Corporation purchased a further put option with a floor price of $115 per barrel for 300,000 barrels of oil. This put option 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.

Following the end of the quarter, in July, the Corporation announced that from January 2012 Mr. Mike Travis would be appointed as Chief Production Officer. He has over 28 years of diverse offshore and onshore experience in the oil industry and has held key leadership positions throughout his career in all aspects of production and development projects including asset management, drilling and operations.

In July the Corporation established a Share Incentive Plan ("SIP") effective as of July 19, 2011. The purpose of the SIP is to provide UK based officers and employees with the opportunity to acquire common shares in the Company in a tax-effective way. Approval for the SIP was obtained from HM Revenue & Customs under Schedule 2 to the Income Tax (Earnings and Pensions) Act 2003.

RESULTS OF OPERATIONS

Revenue

Three months ended June 30, 2011

Sales revenue has decreased in Q2 2011 to $16.7 million (Q2 2010 $34.1 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 4,914 bopd in Q2 2010 to 1,248 bopd for Q2 2011 predominantly due to the ESP failures on Jacky, noted above. The Corporation has benefited from an increase in average realized oil prices from $73.98 / bbl in Q2 2010 to $116.59/ bbl in Q2 2011.
The addition of gas production also contributed to revenue in Q2 2011 (no gas production in Q2 2010). The combined production from the Anglia and Topaz fields contributed over $3 million to revenue.

Six months ended June 30, 2011

Sales revenue has decreased in 1H 2011 to $47.8 million (1H 2010 $64.9 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 4,552 bopd in 1H 2010 to 1,876 bopd for 1H 2011. The Corporation has benefited from an increase in average realized oil prices from $76.70 / bbl in 1H 2010 to $112.98/ bbl in 1H 2011.
The addition of gas production noted above contributed over $7 million to revenue.

Cost of Sales

Three months ended June 30, 2011

Cost of sales has increased in Q2 2011 to $15.7 million (Q2 2010 $14.8 million) due to an increase in operating costs offset by a decrease in DD&A expense.
Operating costs have increased in Q2 2011 to $11.5 million (Q2 2010 $9.5 million) primarily due to the addition of Anglia and Topaz operating costs. Operating costs for the Great Beatrice Area have remained consistent in the period.
DD&A expense for the quarter has decreased in Q2 2011 to $4.2 million (Q2 2010 $5.3 million) due to the decrease in production noted above, partially offset by an increase in the DD&A rate due to the addition of the Anglia and Topaz gas assets and capital expenditure in the period.

Six months ended June 30, 2011

Cost of sales has increased in 1H 2011 to $32.9 million (1H 2010 $27.9 million) due to an increase in operating costs and DD&A expense.

Operating costs have increased in 1H 2011 to $21.8 million (1H 2010 $18.1 million) primarily due to the addition of Anglia and Topaz assets noted above.
DD&A expense for the six months ended June 30 has increased in 1H 2011 to $11.2 million (1H 2010 $9.7 million) due to the addition of the Anglia and Topaz assets and the significant capital expenditure in the period.

Administrative expenses and Exploration & Evaluation expenses

Three months ended June 30, 2011

Administrative expenses have increased in Q2 2011 to $2.5 million (Q2 2010 $0.2 million). The main reason for the increase was the continued growth of the corporation as the Athena project progresses to first oil and the Greater Stella Area moves towards FDP approval together with an increase in stock based compensation. A year-to-date stock based compensation reclassification to credit costs in Q2 2010 also contributed to the movement in costs from 2010.

Exploration and evaluation expenses of less than $0.2 million (Q2 2010 $Nil) were recorded for the three months ended June 30, 2011 due to the expensing of previously capitalized costs relating to areas where the Corporation has decided to cease exploration and evaluation activities.

Six months ended June 30, 2011

Administrative expenses have increased in 1H 2011 to $3.5 million (1H 2010 $2.1 million). The main reason for the increase was the continued growth of the corporation noted above together with an increase in stock based compensation.

A credit of $0.3 million has been recorded in the income statement for exploration and evaluation expenses for the six months ended June 30, 2011 (1H 2010 $Nil). The credit relates to the expensing of certain prospects declared non-commercial and areas where exploration and evaluation activities has ceased 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.

Foreign exchange and Financial Instruments

Three months ended June 30, 2011

Foreign exchange movements increased $0.8 million to an overall gain of $0.4 million in the three months ended June 30, 2011 (Q2 2010 $0.4 million loss). The gain in Q2 2011 was caused by increases in the USD : GBP exchange rate experienced 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 June 30, 2010.

The Corporation recorded a $0.3 million loss on financial instruments for the three months ended June 30, 2011 (Q2 2010: $4.6 million loss). The loss was primarily due to a $1.5 million loss recorded from the revaluation of the oil 'put options' caused by the high Brent oil price per barrel of $113.20 as at June 30, and movements in forecast oil prices for the option life partially offset by a $1.2 million gain on the revaluation of the embedded derivative within the Anglia gas sales contract. The remaining movement was made up of revaluations of other financial instruments.

Six months ended June 30, 2011

Foreign exchange gains / losses increased $4.5 million to an overall gain of $2.6 million in the six months ended June 30, 2011 (1H 2010 $1.9 million loss). The gain in Q2 2011 was again caused by increases in the USD : GBP exchange rate experienced in the 6 months ended 30 June 2011, 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 six months ended June 30, 2010.

The Corporation recorded a $2.6 million loss on financial instruments for the six months ended June 30, 2011 (1H 2010: $6.6 million loss). The loss was primarily due to a $3.6 million loss recorded from the revaluation of the oil 'Put Options' held, partially offset by a $1.0 million gain on the revaluation of the embedded derivative within the Anglia gas sales contract. The remaining movement was made up of revaluations of other financial instruments.

Taxation

Three months ended June 30, 2011

A deferred tax credit of $4.7 million was recognized in the three months ended June 30, 2011 (Q2 2010: $Nil) due to adjustments relating to the tax impact of derivative financial instruments and the UK Ring Fence Expenditure Supplement in the quarter.

Six months ended June 30, 2011

A deferred tax charge of $1.7 million was recognized in the six months ended June 30, 2011 (1H 2010: $Nil) representing an effective tax rate of 16%. This rate is a product of adjustments to taxable income due to adjustments relating to the tax impact of derivative financial instruments and the UK Ring Fence Expenditure Supplement in the quarter and the changes in UK Corporation Tax rates for upstream and non-upstream oil and gas activities.

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 after tax for the three months ended June 30 decreased to $2.9 million (Q2 2010 $14.1 million) and for the six months ended June 30 decreased to $9.5 million (1H 2010 $26.2 million).

SUMMARY OF QUARTERLY RESULTS

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

31/06/2011 31/03/201131/12/201030/09/201030/06/201031/03/201031/12/2009*30/09/2009*
$'000 $'000$'000$'000$'000$'000$'000$'000
Revenue16,724 31,05034,26035,96534,12930,76739,67637,395
Profit after tax2,860 6,59317,92218,07314,09812,10817,488(1,145)
Earnings per share
Basic0.01 0.030.070.080.090.070.11(0.01)
Diluted0.01 0.030.070.080.090.070.11(0.01)
Selected other information
(Loss) / Profit
before tax(1,827)13,03714,25718,15414,09812,10817,488(1,145)
* Comparative figures for 2009 have been reported under Canadian GAAP

The most significant factors to have affected the Corporation's results during the above quarters are fluctuation in underlying commodity prices and movement in production volumes in the current period. 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 USD : GBP exchange rate.

LIQUIDITY AND CAPITAL RESOURCES

As at June 30, 2011, Ithaca had working capital of $197.2 million including a free cash balance of $169.0 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 June 30, 2011 there was a cash outflow from operating, investing and financing activities of $22.4 million (Q2 2010 inflow of $30.9 million). The net outflow was due to cash inflows from operating activities of $5.5 million; cash outflows from investing activities of $25.6 million due to investment in fixed assets and movements in working capital, and cash outflows from financing activities of $2.4 million. The remainder of the movement was due to foreign exchange on non US Dollar denominated cash deposits. The fixed asset investment in the quarter predominantly related to capital expenditure on the development of Athena, J03 well drilling costs and J01 well ESP replacement operations on Jacky, the purchase of long lead items for the Greater Stella Area and the hydraulic workover program on Beatrice Alpha.

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:

Year ended2011201220132014Subsequent
to 2014
US$'000US$'000US$'000US$'000US$'000
Office lease128256256256833
Exploration license fees8751,2481,602--
Engineering14,36220,07911,67911,679-
Total15,36521,58313,53711,935833

OUTSTANDING SHARE INFORMATION

As at June 30, 2011, Ithaca had 258,535,295 common shares outstanding along with 19,398,505 options to employees and directors to acquire common shares.

As at August 25, 2011, Ithaca had 259,105,295 common shares outstanding along with 18,351,005 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. Leases are treated as either operating leases or finance leases based on the extent to which risks and rewards incidental to ownership lie with the lessor or the lessee under IAS 17. No asset or liability value has been assigned to any leases on the balance sheet as at June 30, 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 Q2 2011 was $0.1 million (Q2 2010 - $0.1 million). 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 currently 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 June 30, 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 IFRS using a transition date of January 1, 2010. The financial statements for the three months ended June 30, 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 June 30, 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;
  • 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.

Q2 2011 CONSOLIDATED FINANCIAL STATEMENTS

Consolidated Statement of Income
For the three and six months ended June 30, 2011 and 2010
(unaudited) Three months
ended June 30
Six months
ended June 30
2011 2010 2011 2010
NoteUS$'000 US$'000 US$'000 US$'000
Revenue416,724 34,129 47,774 64,896
Cost of sales5(15,714)(14,806)(32,932)(27,884)
Gross Profit 1,010 19,323 14,842 37,012
Exploration and evaluation expenses8(175)- 344 -
Administrative expenses6(2,454)(160)(3,514)(2,117)
Operating (Loss) / Profit (1,619)19,163 11,672 34,895
Foreign exchange 428 (362)2,562 (1,938)
Loss on financial instruments19(263)(4,631)(2,550)(6,604)
(Loss) / Profit Before Interest and Tax (1,454)14,170 11,684 26,353
Finance costs (489)(75)(749)(151)
Interest income 116 3 275 5
(Loss) / Profit Before Tax (1,827)14,098 11,210 26,207
Taxation - Deferred tax174,687 - (1,740)-
Profit After Tax 2,860 14,098 9,470 26,207
Earnings per share
Basic160.01 0.09 0.04 0.16
Diluted160.01 0.09 0.04 0.16

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

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

Consolidated Statement of Financial Position
(unaudited)
June 30December 31January 1
201120102010
NoteUS$'000US$'000US$'000
ASSETS
Current assets
Cash and cash equivalents 168,970195,58129,886
Restricted cash77,5966,3085,224
Accounts receivable 100,16893,43467,166
Deposits, prepaid expenses and other 17,27012,341352
Inventory 1,202--
Derivative financial instruments202,932-685
Deferred tax asset 2,0063,745-
300,144311,409103,313
Non current assets
Restricted cash7--352
Exploration and evaluation assets817,62417,52215,500
Property, plant & equipment9305,903249,968189,975
323,527267,490205,827
Total assets 623,671578,899309,140
LIABILITIES AND EQUITY
Current Liabilities
Trade and other payables 102,95975,56443,613
Commodity hedge -349397
102,95975,91344,010
Non current liabilities
Decommissioning liabilities1125,65323,6528,751
Other long term liabilities122,7262,8722,718
Contingent consideration1310,97612,9766,933
Derivative financial instruments203,5094,378-
42,86443,87818,402
Net Assets 477,848459,108246,728
Equity attributable to equity holders
Share capital14428,819422,373277,075
Contributed surplus1514,56211,4276,860
Warrants issued14-311-
Retained earnings / (deficit) 34,46724,997(37,207)
Shareholders' Equity 477,848459,108246,728


Jay Zammit, Director

John Summers, Director

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

Consolidated Statement of Changes in Equity
(unaudited)
Share
Capital
Contributed
Surplus
Warrants
Issued
Retained
E'ings/
(Deficit)
Total
US$'000US$'000 US$'000 US$'000 US$'000
Balance, Jan 1 2010277,0756,860 - (37,207)246,728
Net income for the period-- - 12,108 12,108
Total comprehensive income277,0756,860 - (25,099)258,836
Transactions with owners
Stock based compensation-1,181 - - 1,181
Options exercised99(47)- - 52
Balance, June 30 2010277,1747,994 - (25,099)260,069
Balance, Jan 1 2011422,37311,427 311 24,997 459,108
Net income for the period-- - 9,470 9,470
Total comprehensive income422,37311,427 311 34,467 468,578
Transactions with owners
Stock based compensation-3,283 - - 3,283
Options exercised349(148)- - 201
Warrants exercised6,097- (311)- 5,786
Balance, June 30 2011428,81914,562 - 34,467 477,848
The accompanying notes are an integral part of the financial statements.
Consolidated Statement of Cash Flow
For the six months ended June 30, 2011 and 2010
(unaudited)
Three months
ended June 30
Six months
ended June 30
2011 2010 2011 2010
US$'000 US$'000 US$'000 US$'000
CASH PROVIDED BY (USED IN):
Operating activities
(Loss) / Profit Before Tax(1,827)14,098 11,210 26,207
Adjustments for:
Depletion, depreciation and amortization4,200 5,346 11,172 9,735
Exploration and evaluation expenses175 - 1,656 -
Stock based compensation643 (581)1,235 601
Loan fee amortization78 - 154 -
Unrealized (gain) / loss on financial instruments263 (225)2,057 1,583
Revaluation of contingent consideration- 4,044 (2,000)4,044
Accretion175 71 353 143
Cashflow from operations3,707 22,753 25,837 42,313
Movement in working capital1,751 15,589 7,378 729
Net cash from operating activities5,458 38,342 33,215 43,042
Investing activities
Capital expenditure
Oil and gas assets(42,169)(13,794)(65,950)(28,360)
Non oil and gas assets(90)(46)(472)(145)
Movement in working capital16,643 6,385 7,470 2,529
Net cash used in investing activities(25,616)(7,455)(58,952)(25,976)
Financing activities
Proceeds from issuance of shares- 69 5,986 121
(Increase) / decrease in restricted cash(1)- (1,288)5,241
Derivatives(2,445)- (6,508)-
Net cash from financing activities(2,446)69 (1,810)5,362
Currency translation differences relating to cash240 (30)936 (1,304)
(Decrease) / increase in cash & cash equiv.(22,364)30,926 (26,611)21,124
Cash and cash equivalents, beginning of period191,334 20,084 195,581 29,886
Cash and cash equivalents, end of period168,970 51,010 168,970 51,010

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 24, 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 24 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 August 25, 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 is 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, contingent consideration 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 June 30
Six months
ended June 30
2011 2010 2011 2010
US$'000 US$'000 US$'000 US$'000
Oil sales 13,246 33,094 38,379 63,196
Gas sales2,841 - 6,763 -
Condensate sales255 - 576 -
Other income382 1,035 2,056 1,700
Total 16,724 34,129 47,774 64,896
5. COST OF SALES
Three months
ended June 30
Six months
ended June 30
2011 2010 2011 2010
US$'000 US$'000 US$'000 US$'000
Operating costs(11,514)(9,460)(21,760)(18,149)
Depletion, depreciation and amortisation(4,200)(5,346)(11,172)(9,735)
(15,714)(14,806)(32,932)(27,884)
6. ADMINISTRATIVE EXPENSES
Three months
ended June 30
Six months
ended June 30
2011 2010 2011 2010
US$'000 US$'000 US$'000 US$'000
General & administrative(1,811)(741)(2,279)(1,516)
Stock based compensation(643)581 (1,235)(601)
(2,454)(160)(3,514)(2,117)
7. RESTRICTED CASH
June 30Dec 31Jan 1
201120102010
US$'000US$'000US$'000
Decommissioning security7,2405,956-
Cash security - Crown estate356352352
Cash security - Foreign exchange contract--5,224
7,5966,3085,576

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 field.

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
At January 1, 201015,500
Additions3,141
Write offs/relinquishments(1,119)
At December 31, 201017,522
Additions1,758
Write offs/relinquishments(1,656)
At June 30, 201117,624

Following completion of geotechnical evaluation activity, certain licences were declared unsuccessful and certain prospects were declared non-commercial and therefore the related expenditures of $0.2 million and $1.7 million were expensed in the three and six months to June 30, 2011 respectively. $2 million of associated contingent consideration relating to those licences and prospects was also released to the consolidated statement of income in Q1 to give a total credit of $0.3 million for the six months ended June 30, 2011. See note 13 for details.

9. PROPERTY, PLANT AND EQUIPMENT
Development &
Production
Oil and
Gas assets
Other
fixed
assets
Total
US$'000 US$'000 US$'000
Cost
At January 1, 2010189,458 1,274 190,732
Additions82,879 313 83,192
At December 31, 2010272,337 1,587 273,924
Additions66,634 473 67,107
At June 30, 2011338,971 2,060 341,031
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 period(10,978)(194)(11,172)
At June 30, 2011(33,830)(1,298)(35,128)
NBV at January 1, 2010189,458 517 189,975
NBV at January 1, 2011249,485 483 249,968
NBV at June 30, 2011305,141 762 305,903

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 were 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 six months ended June 30, 2011).

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
June 30 Dec 31
2011 2010
US$'000 US$'000
Balance, beginning of period23,652 8,751
Additions1,921 12,772
Accretion353 283
Revision to estimates(273)1,846
Balance, end of period25,653 23,652

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 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.

12. OTHER LONG TERM LIABILITIES
June 30 Dec 31
2011 2010
US$'000 US$'000
Balance, beginning of period2,872 2,718
Revaluation in the period(146)154
Balance, end of period2,726 2,872

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
June 30 Dec 31
2011 2010
US$'000 US$'000
Balance, beginning of period12,976 6,933
Additions- 2,000
Revision to estimates(2,000)4,043
Balance, end of period10,976 12,976

The contingent consideration at the end of the period relates to the acquisition of the Stella field and is payable once Field Development Plan approval is received.

The revision 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
shares
Amount
US$'000
Balance January 1, 2010162,361,975277,075
Issued for cash - options exercised765,205305
Transfer from Contributed Surplus on options exercised 273
Issued for cash - prospectus92,662,284153,248
Share issue costs (8,528)
Balance December 31, 2010255,789,464422,373
Issued for cash - options exercised245,831201
Issued for cash - warrants exercised2,500,0005,786
Transfer from Contributed Surplus on options exercised 148
Transfer from Warrants issued on warrants exercised 311
Balance June 30, 2011258,535,295428,819

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 June 30, 2011, 19,398,505 stock options to purchase common shares were outstanding, having an exercise price range of $0.20 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:

June 30, 2011December 31, 2010
Wt. Avg Wt. Avg
No. of Options Exercise Price *No. of Options Exercise Price *
Balance, beginning of period20,146,003 $1.6111,042,875 $1.48
Granted260,000 $1.9910,100,000 $1.88
Forfeited / expired(761,667)$2.15(231,667)$1.28
Exercised(245,831)$0.77(765,205)$0.33
Options19,398,505 $1.6520,146,003 $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 June 30, 2011
Options
Outstanding
Options
Exercisable
Range of
Exercise
Price
No. of
Options
Wt.
Avg.
Life
(Ye-
ars)
Wt.
Avg.
Exer-
cise
Price
*
Range of
Exercise
Price
No. of
Options
Wt.
Avg.
Life
(Ye-
ars)
Wt.
Avg.
Exer-
cise
Price
*
$3.65 (C$3.65)2,365,0000.6$3.65 $3.65 (C$3.65)2,365,0000.6$3.65
$2.22-$2.86 (C$2.25-C$3.00)5,935,0003.0$2.24 $2.22-$2.86 (C$2.25-C$3.00)818,3330.2$2.35
$1.49-$1.76 (C$1.54-C$1.85)5,411,6672.5$1.55 $1.49-$1.68 (C$1.54-C$1.80)1,711,6642.3$1.53
$0.20-$0.81 (C$0.25-C$0.87)5,686,8382.3$0.55 $0.20-$0.81 (C$0.25-C$0.87)2,622,7532.3$0.45
19,398,5052.4$1.73 7,517,7501.6$1.91
The following is a summary of stock options as at December 31, 2010
Options
Outstanding
Options Exercisable
Range of
Exercise
Price
No. of
Options
Wt.
Avg.
Life
(Ye-
ars)
Wt.
Avg.
Exer-
cise
Price
*
Range of
Exercise
Price
No. of
Options
Wt.
Avg.
Life
(Ye-
ars)
Wt.
Avg.
Exer-
cise
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 (C$2.25-C$3.00)6,375,0002.40$2.25 $2.29-$2.86 (C$2.51-C$3.00)1,285,0000.3$2.38
$1.49-$1.76 (C$1.54-C$1.85)5,345,0003.01$1.54 $1.49-$1.68 (C$1.54-C$1.80)300,0001.7$1.68
$0.20-$0.81 (C$0.25-C$0.87)5,991,0032.77$0.55 $0.20-$0.81 (C$0.25-C$0.87)2,591,0842.8$0.45
20,146,0032.50$1.61 5,799,4181.3$1.44

(c) Stock based compensation

Options granted are accounted for using the fair value method. The compensation cost during the three months and six months ended June 30, 2011 for total stock options granted was $1.7 million and $3.3 million respectively (Q2 2010: $1.2 million, Q2 YTD: $2.3 million). $0.6 million and $1.2 million were charged through the income statement for stock based compensation for the three and six months ended June 31, 2011 respectively, 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 six
months ended
June 30, 2011
For the
year ended
December 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
June 30 Dec 31
2011 2010
US$'000 US$'000
Balance, beginning of period11,427 6,860
Stock based compensation cost3,283 4,840
Transfer to share capital on exercise of options(148)(273)
Balance, end of period14,562 11,427

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 June 30
Six months
ended June 30
201120102011 2010
Wtd av. number of common shares (basic)258,535,295162,555,640257,691,879 162,555,640
Wtd av. number of common shares (diluted)263,211,406165,518,118262,979,178 165,518,118
17.TAXATION
Three months
ended June 30
Six months
ended June 30
201120102011 2010
US$000US$000US$000 US$000
Deferred tax4,687-(1,740)-

Current corporation tax payable of $23k 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 ended
2011201220132014Subsequent
to
2014
US$'000US$'000US$'000US$'000US$'000
Office lease128256256256833
Exploration8751,2481,602--
Engineering14,36220,07911,67911,679-
Total 15,36521,58313,53711,935833

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 June 30, 2011:

Total Fair
Level 1Level 2 Level 3 Value
US$'000US$'000 US$'000 US$'000
Derivative financial instrument assets-2,932 - 2,932
Long term liability on Beatrice acquisition-- (2,726)(2,726)
Contingent consideration-(10,976)- (10,976)
Derivative financial instrument liability-(3,509)- (3,509)

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 June 30
Six months
ended June 30
2011 2010 2011 2010
US$'000 US$'000 US$'000 US$'000
Unrealized gain/(loss) on forex forward contracts- 229 - (2,159)
Realized (loss)/gain on forex forward contracts- (811)- (1,062)
Revaluation of gas contract1,221 - 1,024 -
Revaluation of other long term liability32 (5)146 179
Contingent consideration- (4,044)- (4,044)
Unrealized (loss)/gain on commodity hedges(1,516)- (3,227)86
Realized (loss)/gain on commodity hedges- - (493)396
Total (loss) on financial instruments(263)(4,631)(2,550)(6,604)

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 6 months ended June 30, 2011.

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 in the three months ended June 30, 2011 resulted in an unrealized loss of $1.4 million.

In Q2 2011 the Corporation purchased a put option with a floor price of $115 / barrel for 300,000 barrels of 2011 production. The option delivers a minimum price on the specified volume of oil and allows the Corporation to benefit from any upside above $115 / barrel. Due to movements in forecast oil prices the revaluation of this instrument in the three months ended June 30, 2011 resulted in an unrealized loss of $0.1 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 currently 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 June 30, 2011 all of accounts receivables are current, being defined as less than 90 days. The Corporation has no allowance for doubtful accounts as at June 30, 2011 (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 June 30, 2011, exposure is $2.9 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 June 30, 2011, substantially all accounts payable are current.

The following table shows the timing of cash outflows relating to trade and other payables.

Within
1 year
1 to 5
years
US$'000 US$'000
Accounts payable and accrued liabilities 102,959 -
Other long term liabilities - 2,726
102,959 2,726
20.DERIVATIVE FINANCIAL INSTRUMENTS
June 30 December 31 January 1
2011 2010 2010
US$'000 US$'000 US$'000
Oil put premiums2,932 - -
Embedded derivative(3,509)(4,378)-
Foreign exchange forward contract- - 685
(577)(4,378)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 June 30, 2011.

In Q2 2011 the Corporation entered into a further 'put' option to sell 300,000 barrels of the Corporation's 2011 forecast production at $115 / bbl. This is recognized at its fair value in the financial statements. Fair value represents the market price for the instrument, measured as at June 30, 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 June 30, 2010, the classification of financial instruments and the carrying amounts reported on the balance sheet and their estimated fair values are as follows:

June 30, 2011December 31, 2010
US$'000US$'000
ClassificationCarrying
Amount
Fair
Value
Carrying
Amount
Fair
Value
Cash and cash equivalents (Held for trading)168,970168,970195,581195,581
Restricted cash7,5967,5966,3086,308
Derivative financial instruments (Held for trading)2,9322,932--
Accounts receivable (Loans and Receivables)100,168100,16893,43493,434
Deposits256256248248
Loan fees - current261261286286
Loan fees - non-current391391521521
Commodity hedge (Held for trading)--349349
Contingent consideration10,97610,97612,97612,976
Derivative financial instruments (Held for trading)3,5093,5094,3784,378
Other long term liabilities2,7262,7262,8722,872
Accounts payable (Other financial liabilities)102,959102,95975,56475,564

22. RELATED PARTY TRANSACTIONS

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 three and six months ended June 30, 2011 was $0.1 million (June 30, 2010 - $0.1 million June 30, 2010 YTD - $0.1 million). The balance outstanding at June 30, 2011 was $Nil (June 30, 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 second 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 three and six months ended June 30, 2011, the comparative information for the three and six months ended June 30, 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)

CGAAP IFRS Adj IFRS
US$'000 US$'000 US$'000
ASSETS
Current assets
Cash and cash equivalents29,886 - 29,886
Restricted cash5,224 - 5,224
Accounts receivable67,166 - 67,166
Deposits, prepaid expenses and other352 - 352
Foreign exchange forward contract685 - 685
103,313 - 103,313
Non current assets
Restricted cash352 - 352
Exploration and evaluation assets (note a)- 15,500 15,500
Property, plant & equipment (notes a, b, c)205,475 (15,500)189,975
205,827 - 205,827
Total assets309,140 - 309,140
LIABILITIES AND EQUITY
Current Liabilities
Trade and other payables43,613 - 43,613
Commodity hedge397 - 397
44,010 - 44,010
Non current liabilities
Long term liability2,718 - 2,718
Decommissioning liabilities (note d)7,956 795 8,751
Contingent consideration (note e)- 6,933 6,933
10,674 7,728 18,402
Net Assets254,456 (7,728)246,728
Equity attributable to equity holders
Share capital277,075 - 277,075
Contributed surplus (note f)7,812 (952)6,860
Retained earnings / (deficit) (notes d and e)(30,431)(6,776)(37,207)
Shareholders' Equity254,456 (7,728)246,728
Reconciliation of equity as at June 30, 2010
CGAAP IFRS Adj IFRS
US$'000 US$'000 US$'000
ASSETS
Current assets
Cash and cash equivalents51,010 - 51,010
Accounts receivable79,560 - 79,560
Deposits, prepaid expenses and other506 - 506
131,076 - 131,076
Non current assets
Restricted cash335 - 335
Exploration and evaluation assets (note a)- 17,624 17,624
Property, plant & equipment (notes a, b, c)208,570 (1,564)207,006
208,905 16,060 224,965
Total assets339,981 16,060 356,041
LIABILITIES AND EQUITY
Current Liabilities
Trade and other payables58,589 - 58,589
58,589 - 58,589
Non current liabilities
Long term liability2,539 - 2,539
Decommissioning liabilities (note d)6,098 2,380 8,478
Contingent consideration (note e)- 10,976 10,976
Derivative financial instruments- - -
8,637 13,356 21,993
Net Assets272,755 2,704 275,459
Equity attributable to equity holders
Share capital277,307 - 277,307
Contributed surplus (note f)10,012 (862)9,150
Retained earnings / (deficit) (notes b, d, e and f)(14,564)3,566 (10,998)
Shareholders' Equity272,755 2,704 275,459
Reconciliation of equity as at December 31, 2010
CGAAPIFRS Adj IFRS
US$'000US$'000 US$'000
ASSETS
Current assets
Cash and cash equivalents195,581- 195,581
Restricted cash6,308- 6,308
Accounts receivable93,434- 93,434
Deposits, prepaid expenses and other12,341- 12,341
Deferred tax asset (note g)16,074(12,329)3,745
323,738(12,329)311,409
Non current assets
Exploration and evaluation assets (note a)-17,522 17,522
Property, plant & equipment (notes a, b, c)238,11311,855 249,968
238,11329,377 267,490
-
Total assets561,85117,048 578,899
LIABILITIES AND EQUITY
Current Liabilities
Trade and other payables75,564- 75,564
Commodity hedge349 349
75,913- 75,913
Non current liabilities
Long term liability2,872- 2,872
Decommissioning liabilities (note d)20,8682,784 23,652
Contingent consideration (e)-12,976 12,976
Derivative financial instruments4,378- 4,378
28,11815,760 43,878
Net Assets457,8201,288 459,108
Equity attributable to equity holders
Share capital422,373- 422,373
Contributed surplus (note f)11,530(103)11,427
Warrants issued311- 311
Retained earnings (notes b, d, e and f)23,6061,391 24,997
Shareholders' Equity457,8201,288 459,108
Reconciliation of total comprehensive income for the six months ended June 30, 2010
CGAAP IFRS Adj IFRS
US$'000 US$'000 US$'000
Revenue64,896 - 64,896
Cost of sales (note b)(42,236)14,352 (27,884)
Gross Profit22,660 14,352 37,012
Admin expenses (note f)(2,028)(89)(2,117)
Operating Profit20,632 14,263 34,895
Foreign exchange(1,938)- (1,938)
Gain / (loss) on financial instruments (note e)(2,560)(4,044)(6,604)
Profit on ordinary activities Before Interest and Tax16,134 10,219 26,353
Finance costs (note d)(272)121 (152)
Interest income5 - 5
Profit Before Tax15,867 10,340 26,206
Taxation- - -
Profit After Tax15,867 10,340 26,206
Reconciliation of total comprehensive income for the three months ended June 30, 2010
CGAAP IFRS Adj IFRS
US$'000 US$'000 US$'000
Revenue34,129 - 34,129
Cost of sales (note b)(22,453)7,647 (14,806)
Gross Profit11,676 7,647 19,323
Admin expenses (note f)(100)(60)(160)
Operating Profit11,576 7,587 19,163
Foreign exchange(362)- (362)
Gain / (loss) on financial instruments (note e)(587)(4,044)(4,631)
Profit on ordinary activities Before Interest and Tax10,627 3,543 14,170
Finance costs (note d)(114)39 (75)
Interest income3 - 3
Profit Before Tax10,516 3,582 14,098
Taxation- - -
Profit After Tax10,516 3,582 14,098
Reconciliation of total comprehensive income for the year ended December 31, 2010
CGAAP IFRS Adj IFRS
US$'000 US$'000 US$'000
Revenue135,121 - 135,121
Cost of sales (note b)(87,307)26,257 (61,050)
Gross Profit47,814 26,257 74,071
Exploration and evaluation (note a)- (1,119)(1,119)
Admin expenses (note f)(4,620)(848)(5,468)
Operating Profit43,194 24,290 67,484
Foreign exchange818 - 818
Revaluation of financial instruments (note e)(5,268)(4,044)(9,312)
Profit on ordinary activities Before Interest and Tax38,744 20,246 58,990
Finance costs (note d)(814)249 (565)
Interest income113 113
Profit Before Tax38,043 20,495 58,538
Taxation (note g)15,994 (12,329)3,665
Profit After Tax54,037 8,166 62,203

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 cash flows 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 six months ended June 30, 2010, the Corporation has recognized depletion, depreciation and amortization expense of $9.7 million under IFRS when compared to $24.1 million under Canadian GAAP. For the three months ended June 30, 2010, the Corporation has recognized depletion, depreciation and amortization expense of $5.3 million under IFRS when compared to $13.0 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 $189.5 million, 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 six months ended June 30, 2010, the Corporation recorded accretion of $0.4 million compared to $0.5 million under CGAAP. For the three months ended June 30, 2010, the Corporation recorded accretion of $0.2 million compared to $0.3 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 a decrease in retained earnings relating to a contingent consideration on the Stella acquisition.

For the six months ended June 30, 2010, the Corporation recognized a further $4 million of contingent consideration, being $4m adjustment to the Stella acquisition (opposite side recognised in the income statement).

For the year ended December 31, 2010, the Corporation recognized a further $2 million of 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 a decrease in contributed surplus with an offsetting 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

On August 25, 2011, the Company completed the acquisition of a 28.46% non-operated interest in the Cook oil field from Hess Limited ("Hess") for an adjusted consideration of $57 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.

Neither the TSX Venture Exchange 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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