Ithaca Energy Inc.
TSX : IAE
AIM : IAE

Ithaca Energy Inc.

November 14, 2011 02:00 ET

Ithaca Energy Inc.: Third Quarter 2011 Financial Results

LONDON, UNITED KINGDOM and CALGARY, ALBERTA--(Marketwire - Nov. 14, 2011) -

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

Ithaca Energy Inc. (TSX:IAE)(AIM:IAE) announces its quarterly financial results for the three and nine months ended September 30, 2011.

HIGHLIGHTS

Financial

Q3 Profit before Tax of US$10.8 million (Q3 2010: US$18.1 million)
Q3 Cashflow from Operations of US$18.1 million (Q3 2010: US$23.0 million)
Average realised oil price of $111.24 / bbl (Q3 2010: $79.06 / bbl)
Cash US$115.3 million, inclusive of US$16.7 million restricted cash (Q2 2011: US$176.6 million inclusive of restricted cash)
Undrawn senior debt facility
Crude oil inventory of US$29.4 million
Tax losses available for utilisation of US$289 million (Q2 2011 $265 million)

Operations

Export production averaged 3,602 barrels of oil equivalent per day ("boepd") net to Ithaca over the 3 month period to September 30 through the restoration of production in the Jacky J01 well, replacement of an Electric Submersible Pump on Beatrice Alpha A21 and the introduction of Cook production from August 25, offset by a 7 day shutdown on Beatrice Alpha.
September average export production was 4,719 boepd.
Significant progress was made in the Corporation's key developments with the completion of major milestones on Athena and the conclusion of the Greater Stella Area ('GSA') concept select process and related transactions. Further details are provided in Management's Discussion and Analysis below. The highlights of the GSA concept select process are:
Creation of a production hub - through deployment of a floating production unit in an area with many undeveloped discoveries.
Higher production rates than previously advised - at an expected initial annualised average rate of 30,000 boepd (gross).
Strategically aligned partnership - through transactions between co-venturers.
Development de-risking - through the introduction to the GSA of Petrofac, a FTSE 100 listed worldwide, full cycle oil and gas service company.

Corporate

The Corporation completed a transaction to acquire a 28.46% non-operated interest in the Cook oil field from Hess Limited ("Hess") for an adjusted cash 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. Included in the asset acquisition was an oil inventory of approximately 190,000 the asset acquisition was an oil inventory of approximately 190,000 barrels.
On November 1, the Company commenced trading on the Toronto Stock Exchange ("TSX") graduating from the TSX Venture Exchange. The common shares continue to trade on AIM, a market operated by London Stock Exchange plc.

Notes:

Further details on the above are provided in the Interim Consolidated Financial Statements and Management's Discussion and Analysis for the three and nine months ended September 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 GSA concept select process. 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 Q3 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.

MANAGEMENT'S DISCUSSION AND ANALYSIS
FOR THE QUARTER ENDED SEPTEMBER 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 nine months ended September 30, 2011. The information is provided as of November 11, 2011. The third quarter 2011 results have been compared to the results of the comparative period in 2010. This MD&A should be read in conjunction with the Corporation's unaudited consolidated financial statements as at September 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 Toronto Stock 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 THIRD QUARTER 2011

Financial

  • Q3 Profit before tax of $10.8 million (Q3 2010: $18.1 million) resulting in YTD Profit before tax of $22.0 million (Q3 2010 YTD: $44.3 million)
  • Q3 Cashflow from operations of $18.1 million (Q3 2010: $23.0 million) resulting in YTD cashflow from operations of $43.9 million (Q3 2010 YTD: $65.3 million)
  • Average realized oil price of $111.24 / bbl (Q3 2010: $79.06 / bbl)
  • Cash $115.3 million, inclusive of $16.7 million restricted cash (Q2 2011: $176.6 million)
  • Undrawn senior debt facility
  • Crude oil inventory of $29.4 million
  • Tax losses available for utilization of $289 million (Q2 2011 $265 million)

Operational

Production

Export production averaged 3,602 barrels of oil equivalent per day ("boepd") net to Ithaca over the 3 month period to September 30 through the restoration of production in the Jacky J01 well, replacement of an ESP on Beatrice Alpha A21, the introduction of Cook production from August 25, offset by a 7 day shutdown on Beatrice.

September average export production was 4,719 boepd.

Athena

In July, the engineering and modifications associated with the dry dock works in Dubai to extend the FPSO 'BW Athena' by 65 feet and install a turret docking system were completed. The FPSO was subsequently re-floated.

Also in July, operations to prepare the development well 14/18b-A2Z for production were successfully concluded. The Sedco 704 drilling unit stayed on location to undertake further completion work and is expected to complete the final well of the five well drilling program imminently.

In August the subsea installation campaign began with loadout and transport to the field of the submerged buoy mooring system.

Following the end of the quarter some major scheduled milestones for the project were achieved with the installation of the FPSO mooring system, riser base and subsea manifold, the installation of all topsides equipment on the FPSO. Installation of the subsea flowlines and umbilicals is ongoing.

The FPSO is planned to leave Dubai in mid November / early December to arrive in the field in December. The transit will take approximately 20 days and involves passage through the Suez Canal. The start up procedure in the field will then take approximately 14 days to complete, involving securing the vessel over the STP buoy, final hook up and commissioning of all surface and subsea systems.

The Athena project remains within budget.

Jacky

Strong production from the Jacky field was restored in July at approximately 3,120 bopd (1,482 bopd net to Ithaca) through the replacement of a dual ESP system with slightly larger pumps that will provide greater operational flexibility and prolonged run life.

Beatrice

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

Beatrice production was shut in for 7 days in September to allow maintenance of the produced water treatment system. Jacky production was not restricted during the Beatrice shut-in.

Greater Stella Area

Significant progress was made on the development of the Greater Stella Area ("GSA").

In July a contract was placed with GE Oil & Gas to manufacture and supply subsea trees and controls systems as an integrated package which are designed for installation using a heavy duty jackup drilling unit.

A geotechnical program was also 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.

In October the Corporation concluded its development concept select process for the GSA fields with the decision to create a production hub based on a floating production unit located over the Stella field. The development concept involves the introduction of Petrofac, a global integrated energy services company listed on the FTSE 100 in London as a new strategic partner through the granting of the right to earn a 20% interest in Stella / Harrier and the transfer of interests in the Hurricane and Helios fields. In addition Petrofac transferred ownership interests in the floating production unit to the existing co-venturers of Stella. This created a fully integrated partnership for the GSA hub and the ability to increase the recovery of hydrocarbons from the fields. The Company will submit a Stella / Harrier Field Development Plan to the Department of Energy and Climate Change ("DECC") at the end of 2011.

Management forecast that first hydrocarbons will be in H2-2013 at an initial annualised average rate of approximately 30,000 boepd (gross). This represents a higher rate than previously advised by the Company, driven by optimisation of the reservoir management strategy and the ability of the FPF-1 to handle higher oil and gas rates than those of other development solutions. Management forecasts that gas production from Stella / Harrier should remain on plateau at the gas processing limit of the FPF-1 for nearly three years.

The Corporation also completed the acquisition of Challenger Minerals (North Sea) Ltd ("CMNSL"), subsequently renamed Ithaca Minerals (North Sea) Ltd, from Transocean Drilling U.K. Limited for a consideration of US$35 million; US$25 million payable immediately and US$10 million upon approval of the Stella / Harrier Field Development Plan by the DECC. This transaction increases the Corporation's interests in the Stella / Harrier fields, gives the Corporation a non-operated interest in the producing Broom field and gains the Corporation access to additional undeveloped North Sea discoveries and exploration prospects.

The Corporation also signed an agreement to divest a 25.34% interest in Block 29/10b, which contains the Hurricane field, to Dyas UK Limited ("Dyas"). The agreement has an effective date of January 1, 2011. In consideration for the interest, Dyas will pay its pro-rata share of costs incurred since the effective date. The transaction is subject to the submission for approval of a Stella / Harrier Field Development Plan to the DECC.

As a result of the transfer of interests in the various GSA fields to Petrofac, the acquisition of CMNSL, and the divestment of an interest in Hurricane to Dyas, the Company and its GSA co-venturers now have full field interest alignment across Stella / Harrier, Hurricane and Helios as follows:

Field Block Ithaca(i) Dyas Petrofac
Stella / Harrier 30/6a 54.66 % 25.34 % 20 %
Hurricane 29/10b 54.66 % 25.34 % 20 %
Helios 29/10d 54.66 % 25.34 % 20 %
(i)post acquisition of CMNSL

A contract letter of intent was also signed with Awilco Drilling plc to provide a semi-submersible drilling unit for the drilling of Hurricane appraisal well and performance of a well test commencing in Q1 2012.

In November the Corporation signed an a Letter of Award with Ensco Offshore UK Limited to provide the jack up drilling unit 'Ensco 100' for development drilling on the Stella and Harrier fields. The campaign, which will include the drilling of 5 firm wells and up to 3 options for additional wells, will commence on Stella in H2 2012.

Corporate

In July, the Corporation appointed Mr. Mike Travis as Chief Production Officer effective as of January 2012. Mr. Travis 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.

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.

On August 25, the Corporation completed a transaction to acquire a 28.46% non-operated interest in the Cook oil field from Hess Limited ("Hess") for a cash 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. Included in the cash consideration was the purchase of oil inventory of approximately 190,000 barrels which will be part of the next Ithaca cargo lifting (of approximately 300,000 barrels) now anticipated in Q4 2011 / Q1 2012.

On November 1, the common shares of the Company commenced trading on the Toronto Stock Exchange. As of the same date, the common shares were delisted from the TSX Venture Exchange. The common shares will continue to trade on the Alternative Investments Market (AIM), a market operated by London Stock Exchange plc under the symbol "IAE". Ithaca's graduation to the TSX marks another progressive stage in the Company's continued growth profile. The listing of the common shares on the TSX will provide the Company with access to Canada's largest stock exchange and is expected to enhance Ithaca's trading liquidity and visibility within North American capital markets.

RESULTS OF OPERATIONS

Revenue

Three months ended September 30, 2011

Sales revenue decreased in Q3 2011 to $26.4 million (Q3 2010 $36.0 million). This movement comprises a decrease in oil sales volumes, partially offset by an increase in average realized oil prices and the addition of gas sales from the Anglia, Topaz and Cook fields (Anglia & Topaz acquired December 17, 2010; Cook acquired August 25,2011). Cook oil production is recorded as a credit to cost of sales until oil has been lifted.

Oil sales volumes decreased from 4,862 bopd in Q3 2010 to 2,248 bopd for Q3 2011 due to the combination of the expected natural decline in year on year production from the Jacky field and the operational issues experienced on the Jacky J01 well from Q2 through to the beginning of Q3. The Corporation benefited from an increase in average realized oil prices from $79.06 / bbl in Q3 2010 to $111.24/ bbl in Q3 2011.

The addition of gas production also contributed to revenue in Q3 2011 (no gas production in Q3 2010). The combined production from the Anglia, Topaz and Cook fields contributed over $3 million to revenue.

Nine months ended September 30, 2011

Sales revenue decreased in the period to $74.2 million (Q3 YTD 2010 $100.9 million). This movement comprises a decrease in oil sales volumes, partially offset by an increase in average realized prices and the addition of gas sales from the Anglia and Topaz fields (acquired December 17, 2010).

Oil sales volumes decreased from 4,657 bopd in Q3 YTD 2010 to 2,002 bopd for Q3 YTD 2011. This again was due to the combination of the expected natural decline in year on year production from the Jacky field and the operational issues experienced on the Jacky J01 well from Q2 2011 through to the beginning of Q3 2011. The Corporation benefited from an increase in average realized oil prices from $77.58 / bbl in Q3 YTD 2010 to $112.33 / bbl in Q3 YTD 2011.

The addition of gas production noted above contributed over $10.3 million to revenue.

Cost of Sales

Three months ended September 30, 2011

Cost of sales decreased in Q3 2011 to $11.4 million (Q3 2010 $15.8 million) due to the recording of oil inventory volumes (volumes produced but not yet sold) from the Cook field partially offset by increases in operating costs and DD&A arising from increased activity.

Inventory volumes of $7.2 million were credited to cost of sales in Q3 2011 (Q3 2010 $nil) arising from Cook oil produced into the host FPSO 'Anasuria' since the acquisition date but not yet sold. The balance of Cook inventory of $25.9 million (from a total $29.4 million oil inventory) is held on the balance sheet with a corresponding reduction in the asset acquisition value.

Operating costs increased in Q3 2011 to $11.9 million (Q3 2010 $10.2 million) primarily due to the addition of Anglia, Topaz and Cook operating costs in 2011. Operating costs for the Great Beatrice Area have remained consistent in the period.

DD&A expense for the quarter also increased in Q3 2011 to $6.7 million (Q3 2010 $5.6 million) due to an increase in the DD&A rate due to the addition of the Anglia and Topaz gas assets and capital expenditure in the period.

Nine months ended September 30, 2011

Cost of sales increased in the period to $44.3 million (Q3 YTD 2010 $43.7 million) due to increases in both operating costs and DD&A, partially offset by the recording oil inventory volumes from the Cook field.

Operating costs increased in the period to $33.7 million (Q3 YTD 2010 $28.4 million) primarily due to the addition of Anglia, Topaz and Cook operating costs in 2011.

DD&A expense for the nine months ended September 30 increased to $17.8 million (Q3 YTD 2010 $15.3 million) due to the addition of the Anglia, Topaz and Cook assets and the significant capital expenditure in the period.

Oil inventory volumes of $7.2 million were credited to cost of sales in Q3 2011 (Q3 2010 $nil) arising from barrels produced but not yet sold from the Cook field (acquired August 25, 2011). The balance of Cook inventory of $25.9 million (from a total $29.4 million oil inventory) is held on the balance sheet with a corresponding reduction in the asset acquisition value.

Administrative expenses and Exploration & Evaluation expenses

Three months ended September 30, 2011

Administrative expenses remained constant in Q3 2011 at $1.6 million (Q3 2010 $1.6 million) comprising a marginal decrease in general and administrative costs offset by a marginal increase in stock based compensation.

Exploration and evaluation expenses of $0.2 million (Q3 2010 $nil) were recorded for the three months ended September 30, 2011 due to the expensing of previously capitalized costs relating to areas where the Corporation has decided to cease exploration and evaluation activities.

Nine months ended September 30, 2011

Administrative expenses increased in the period to $5.1 million (Q3 YTD 2010 $3.7 million). The continued growth of the corporation has caused an increase in both general & administrative and stock based compensation costs.

Exploration and evaluation expenses of $1.8 million (Q3 YTD 2010 $nil) were recorded for the nine months ended Sept 30, 2011 due to the expensing of previously capitalized costs relating to areas where exploration and evaluation activities have ceased.

Foreign exchange and Financial Instruments

Three months ended September 30, 2011

A foreign exchange loss of $2.4 million was recorded in the three months ended September 30, 2011 (Q3 2010 $1.8 million gain). The loss in Q3 2011 was caused by a combination of general volatility in exchange rates and a dip in the USD : GBP exchange rate at the end of the quarter, causing an decrease in the value of GBP cash held on deposit. This compares to a increase in the average USD : GBP exchange rate for the three months ended September 30, 2010.

The Corporation recorded a $0.4 million gain on financial instruments for the three months ended September 30, 2011 (Q3 2010: $2.1 million loss). The gain was due to a combination of a $2.3 million gain on the revaluation of the embedded derivative within the Anglia gas sales contract and a $0.4 gain on the revaluation of the Nigg storage tank liability, offset by a $2.3 million expense on the revaluation of the oil 'put options' caused by the high Brent oil price per barrel in the quarter and movements in forecast oil prices for the remainder of the option lives.

Nine months ended September 30, 2011

A foreign exchange gain of $0.1 million was recorded in the nine months ended September 30, 2011 (Q3 YTD 2010 $0.2 million loss). The gain in Q3 2011 was again caused by general volatility in the USD : GBP exchange rate.

The Corporation recorded a $2.2 million loss on financial instruments for the nine months ended September 30, 2011 (Q3 YTD 2010: $8.7 million loss). The loss was due to a combination of a $5.8 million loss recorded from the revaluation of oil 'put options' held, partially offset by a $3.3 million gain on the revaluation of the Anglia gas sales contract embedded derivative. The remaining movement was made up of revaluations of other financial instruments.

Taxation

Three months ended September 30, 2011

A deferred tax charge of $0.7 million was recognized in the three months ended September 30, 2011 (Q3 2010: $Nil) representing an tax rate of 7%. This rate is a product of adjustments to taxable income relating to derivative financial instruments, stock based compensation and the UK Ring Fence Expenditure Supplement in the quarter.

Nine months ended September 30, 2011

A deferred tax charge of $2.5 million was recognized in the nine months ended September 30, 2011 (Q3 YTD 2010: $Nil) representing an effective tax rate of 11%. This rate is a product of adjustments to taxable income relating to derivative financial instruments, stock based compensation, the UK Ring Fence Expenditure Supplement, 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 September 30 decreased to $10.0 million (Q3 2010 $18.1 million) and for the nine months ended September 30 decreased to $19.5 million (Q3 YTD 2010 $44.3 million).

SUMMARY OF QUARTERLY RESULTS

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

30/09
2011
30/06
2011
31/03
2011
31/12
2010
30/09
2010
30/06
2010
31/03
2010
31/12/
2009*
$'000 $'000 $'000 $'000 $'000 $'000 $'000 $'000
Revenue 26,415 16,724 31,050 34,260 35,965 34,129 30,767 39,676
Profit after tax 10,013 2,860 6,593 17,922 18,073 14,098 12,108 17,488
Earnings per share
Basic 0.04 0.01 0.03 0.07 0.08 0.09 0.07 0.11
Diluted 0.04 0.01 0.03 0.07 0.08 0.09 0.07 0.11
Selected other information
Profit/(Loss) before tax 10,753 (1,827 ) 13,037 14,257 18,154 14,098 12,108 17,488
* 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. 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 September 30, 2011, Ithaca had working capital of $144.7 million including a free cash balance of $98.7 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 $16.7 million comprises $16.3 million currently held by the Bank of Scotland as decommissioning security provided as part of the acquisitions of the Anglia and Cook fields and $0.4 million also held by the Bank of Scotland as cash security for a bank guarantee provided to the Crown Estate as part of the Field Development Plan approval for the Jacky Field.

During the three months ended September 30, 2011 there was a cash outflow from operating, investing and financing activities of $70.3 million (Q3 2010 inflow of $142.8 million). The net outflow was due to a cash inflow from operating activities of $11.4 million offset by a cash outflow from investing activities of $71.3 million, and a cash outflow from financing activities of $8.7 million. The remainder of the movement was due to foreign exchange on non US Dollar denominated cash deposits. This overall free cash outflow is the product of the acquisition of the Cook field (including cash paid for the purchase of oil inventory, currently valued at over $25.9 million, due to be received in December 2011 / January 2012), significant capital expenditure on the Athena development and the purchase of long lead items for the Greater Stella Area, offset by cash generated from Beatrice, Jacky, Anglia, Topaz and Cook operations.

The Company continues to be fully funded, with more than sufficient financial resources to cover the anticipated level of development capital expenditure commitments and continue the pursuit of additional asset acquisition opportunities through its existing cash balance, forecast cashflow from operations and its undrawn debt facility.

COMMITMENTS

The Corporation has the following financial commitments:

Year ended 2011 2012 2013 2014 Subsequent
to 2014
US$'000 US$'000 US$'000 US$'000 US$'000
Office lease 63 250 250 250 813
Exploration license fees 176 918 1,140 - -
Engineering 6,562 33,503 11,393 11,393 -
Total 6,801 34,672 12,783 11,643 813

OUTSTANDING SHARE INFORMATION

As at September 30 and November 14, 2011, Ithaca had 259,164,461 common shares outstanding along with 17,506,839 options outstanding 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 September 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 Q3 2011 was $0.1 million (Q3 2010 - $0.5 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 results in 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 results in failure to meet those certain financial tests. Access to the full Credit Facility will probably require syndication of the debt, the success of which at the current Credit Facility pricing levels will be influenced by the volatility in European bank liquidity.

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 oil production from the Beatrice, Jacky, and Athena fields. Oil production from Cook is sold to Shell Trading International Ltd. Anglia and Topaz gas production is currently sold through three contracts to RWE NPower PLC and Hess Energy Gas Power (UK) Ltd. Cook gas is sold to Shell UK Ltd and Esso Exploration & Production 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.

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 September 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 September 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 September 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 acquisitions of the Cook field and CMNSL.

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.

Consolidated Statement of Income
For the three and nine months ended September 30, 2011 and 2010
(unaudited)
Three months ended September 30 Nine months ended September 30
2011 2010 2011 2010
NoteUS$'000 US$'000 US$'000 US$'000
Revenue426,415 35,965 74,189 100,861
Cost of sales5(11,408)(15,810)(44,339)(43,694)
Gross Profit 15,007 20,155 29,850 57,167
Exploration and evaluation expenses9(174)- 170 -
Administrative expenses6(1,625)(1,624)(5,138)(3,741)
Operating Profit 13,208 18,531 24,882 53,426
Foreign exchange (2,415)1,766 147 (172)
Gain / (loss) on financial instruments20397 (2,127)(2,153)(8,730)
Profit Before Interest and Tax 11,190 18,170 22,876 44,524
Finance costs (526)(147)(1,275)(298)
Interest income 89 50 362 56
Profit Before Tax 10,753 18,073 21,963 44,282
Taxation - Deferred tax18(740)- (2,479)-
Profit After Tax 10,013 18,073 19,484 44,282
Earnings per share
Basic170.04 0.08 0.08 0.24
Diluted170.04 0.08 0.07 0.24
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)
Sept 30December 31January 1
201120102010
NoteUS$'000US$'000US$'000
ASSETS
Current assets
Cash and cash equivalents 98,668195,58129,886
Restricted cash716,6796,3085,224
Accounts receivable 120,53093,43467,166
Deposits, prepaid expenses and other 14,05512,341352
Inventory829,431--
Derivative financial instruments21682-685
Deferred tax asset 1,2653,745-
281,310311,409103,313
Non current assets
Restricted cash7--352
Exploration and evaluation assets919,11617,52215,500
Property, plant & equipment10375,976249,968189,975
395,092267,490205,827
Total assets 676,402578,899309,140
LIABILITIES AND EQUITY
Current Liabilities
Trade and other payables 136,59375,56443,613
Commodity hedge -349397
136,59375,91344,010
Non current liabilities
Decommissioning liabilities1235,54823,6528,751
Other long term liabilities132,3942,8722,718
Contingent consideration1410,97612,9766,933
Derivative financial instruments211,1084,378-
50,02643,87818,402
Net Assets 489,783459,108246,728
Equity attributable to equity holders
Share capital15429,502422,373277,075
Contributed surplus1615,80011,4276,860
Warrants issued15-311-
Retained earnings / (deficit) 44,48124,997(37,207)
Shareholders' Equity 489,783459,108246,728
"John Summers"
Director
"Jay Zammit"
Director
The accompanying notes are an integral part of the financial statements.
Consolidated Statement of Changes in Equity
(unaudited)
Share
Capital
Contributed
Surplus
Warrants
Issued
Retained
E'ings/
(Deficit)
Total
US$'000 US$'000 US$'000 US$'000 US$'000
Balance, Jan 1 2010277,075 6,860 - (37,207)246,728
Net income for the period- - - 44,282 44,282
Total comprehensive income277,075 6,860 - 7,075 291,010
Transactions with owners
Stock based compensation- 3,602 - - 3,602
Options exercised540 (254)- - 286
Issued for cash153,104 - - - 153,104
Share issue costs(8,521)- - - (8,521)
Warrants issued- - 311 - 311
Balance, Sept 30 2010422,198 10,208 311 7,075 439,792
Balance, Jan 1 2011422,373 11,427 311 24,997 459,108
Net income for the period- - - 19,484 19,484
Total comprehensive income422,373 11,427 311 44,481 478,592
Transactions with owners
Stock based compensation- 4,833 - - 4,833
Options exercised1,032 (460)- - 572
Warrants exercised6,097 - (311)- 5,786
Balance, Sept 30 2011429,502 15,800 - 44,481 489,783
The accompanying notes are an integral part of the financial statements.
Consolidated Statement of Cash Flow
For the three and nine months ended Sept 30, 2011 and 2010
(unaudited)
Three months ended
Sept 30
Nine months ended
Sept 30
2011 2010 2011 2010
US$'000 US$'000 US$'000 US$'000
CASH PROVIDED BY (USED IN):
Operating activities
Profit Before Tax10,753 18,073 21,963 44,282
Adjustments for:
Depletion, depreciation and amortization6,666 5,569 17,838 15,304
Exploration and evaluation expenses174 - 1,830 -
Stock based compensation603 458 1,837 1,059
Loan fee amortization78 72 233 72
Unrealized (gain) / loss on financial instruments(397)(1,253)1,660 330
Revaluation of contingent consideration- - (2,000)4,044
Accretion217 70 571 213
Cashflow from operations18,094 22,989 43,932 65,304
Movement in working capital(6,709)(4,366)669 (3,637)
Net cash from operating activities11,385 18,623 44,601 61,667
Investing activities
Capital expenditure
Oil and gas assets(88,266)(10,515)(154,216)(38,875)
Non oil and gas assets(226)(40)(698)(185)
Decommissioning(358)- (358)-
Movement in working capital17,580 (10,276)25,050 (7,747)
Net cash used in investing activities(71,270)(20,831)(130,222)(46,807)
Financing activities
Proceeds from issuance of shares371 153,269 6,357 153,390
Share issue costs- (8,522)- (8,522)
(Increase) / decrease in restricted cash(9,082)(17)(10,370)5,224
Loan issue costs- (887)- (887)
Derivatives- - (6,508)-
Net cash from financing activities(8,711)143,843 (10,521)149,205
Currency translation differences relating to cash(1,706)1,167 (771)(140)
(Decrease) / increase in cash & cash equiv.(70,302)142,802 (96,913)163,925
Cash and cash equivalents, beginning of period168,970 51,010 195,581 29,886
Cash and cash equivalents, end of period98,668 193,812 98,668 193,812
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. As of November 1, 2011 the Corporation's shares have traded on the Toronto Stock Exchange in Canada (previously the TSX Venture Exchange). The Corporation's shares continue to trade on the London Stock Exchange's Alternative Investment Market in the United Kingdom under the symbol "IAE". Ithaca has two wholly-owned subsidiaries, Ithaca Energy (UK) Limited ("Ithaca UK") and Ithaca Minerals (North Sea) Ltd ("Ithaca Minerals"), which was acquired post quarter end on October 19, 2011, both incorporated in Scotland. See note 26 for further details of the acquisition.

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 25, 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 25 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 November 11, 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 25 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 the 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 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 15 (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 acquired as part of the Beatrice field 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 20 to 22.

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 Sept 30 Nine months ended Sept 30
2011 2010 2011 2010
US$'000 US$'000 US$'000 US$'000
Oil Sales 23,006 35,434 61,385 98,630
Gas sales 2,780 - 9,543 -
Condensate sales 223 - 798 -
Other income 406 531 2,463 2,231
Total 26,415 35,965 74,189 100,861

5. COST OF SALES

Three months ended Sept 30 Nine months ended Sept 30
2011 2010 2011 2010
US$'000 US$'000 US$'000 US$'000
Operating costs (11,926 ) (10,241 ) (33,723 ) (28,390 )
Movement in oil and gas inventory 7,184 - 7,222 -
Depletion, depreciation and amortisation (6,666 ) (5,569 ) (17,838 ) (15,304 )
(11,408 ) (15,810 ) (44,339 ) (43,694 )

6. ADMINISTRATIVE EXPENSES

Three months ended Sept 30 Nine months ended Sept 30
2011 2010 2011 2010
US$'000 US$'000 US$'000 US$'000
General & administrative (1,022 ) (1,166 ) (3,301 ) (2,683 )
Stock based compensation (603 ) (458 ) (1,837 ) (1,058 )
(1,625 ) (1,624 ) (5,138 ) (3,741 )

7. RESTRICTED CASH

Sept 30 Dec 31 Jan 1
2011 2010 2010
US$'000 US$'000 US$'000
Decommissioning security 16,336 5,956 -
Cash security - Crown estate 343 352 352
Cash security - Foreign exchange contract - - 5,224
16,679 6,308 5,576

Restricted cash of $16.3 million is held by the Bank of Scotland as decommissioning security in respect of the Corporation's interests in the Anglia and Cook fields.

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

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

8. INVENTORY

Sept 30 Dec 31 Jan 1
2011 2010 2010
US$'000 US$'000 US$'000
Crude oil inventory 29,386 - -
Materials inventory 45 - -
29,431 - -

Approximately 190,000 barrels of crude oil inventory were purchased as part of the acquisition of the Cook field on August 25, 2011. This inventory, combined with Cook oil produced post acquisition, is expected to be sold in December 2011 / January 2012.

9. EXPLORATION AND EVALUATION ASSETS

US$'000
At January 1, 2010 15,500
Additions 3,141
Write offs/relinquishments (1,119 )
At December 31, 2010 17,522
Additions 3,528
Write offs/relinquishments (1,830 )
Disposals (104 )
At September 30, 2011 19,116

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 $1.8 million were written off in the three and nine months to Sept 30, 2011 respectively.

$2 million of associated contingent consideration relating to the licences and prospects relinquished was also released to the consolidated statement of income in Q1 2011 to give a total credit of $0.2 million for the nine months ended Sept 30, 2011. See note 14 for details.

10. PROPERTY, PLANT AND EQUIPMENT

Development & Production Other fixed
Oil and Gas assets assets Total
US$'000 US$'000 US$'000
Cost
At January 1, 2010 189,458 1,274 190,732
Additions 82,879 313 83,192
At December 31, 2010 272,337 1,587 273,924
Additions 143,148 698 143,846
At September 30, 2011 415,485 2,285 417,770
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 (17,542 ) (296 ) (17,838 )
At September 30, 2011 (40,394 ) (1,400 ) (41,794 )
NBV at January 1, 2010 189,458 517 189,975
NBV at January 1, 2011 249,485 483 249,968
NBV at September 30, 2011 375,091 885 375,976

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 a cash 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.

11. 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 nine months ended Sept 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.

12. DECOMMISSIONING LIABILITIES

Sept 30 Dec 31
2011 2010
US$'000 US$'000
Balance, beginning of period 23,652 8,751
Additions 11,956 12,772
Accretion 571 283
Revision to estimates (273 ) 1,846
Utilisation (358 ) -
Balance, end of period 35,548 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. $12.0 million of additional liability was recorded in the nine months ended Sept 30, 2011 due to decommissioning liabilities assumed on the acquisition of the Cook field and liabilities from the drilling of development wells in 2011. Note that upon the acquisition of the Beatrice Field in November 2008, the Corporation did not assume the decommissioning liabilities.

13. OTHER LONG TERM LIABILITIES

Sept 30 Dec 31
2011 2010
US$'000 US$'000
Balance, beginning of period 2,872 2,718
Revaluation in the period (478 ) 154
Balance, end of period 2,394 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.

14. CONTINGENT CONSIDERATION

Sept 30 Dec 31
2011 2010
US$'000 US$'000
Balance, beginning of period 12,976 6,933
Additions - 2,000
Revision to estimates (2,000 ) 4,043
Balance, end of period 10,976 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 nine months to September 30, 2011 relates to the reassessment of the Opal and Garnet prospects which have been determined uncommercial, resulting in a release of the associated contingent consideration.

15. SHARE CAPITAL

(a) Issued

The issued share capital is as follows:

Issued Number of
common shares
Amount
US$'000
Balance January 1, 2010 162,361,975 277,075
Issued for cash - options exercised 765,205 305
Transfer from Contributed Surplus on options exercised 273
Issued for cash - prospectus 92,662,284 153,248
Share issue costs (8,528 )
Balance December 31, 2010 255,789,464 422,373
Issued for cash - options exercised 874,997 572
Issued for cash - warrants exercised 2,500,000 5,786
Transfer from Contributed Surplus on options exercised 460
Transfer from Warrants issued on warrants exercised 311
Balance Sept 30, 2011 259,164,461 429,502

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.

In the quarter ended September 30, 2011, 400,000 options were reserved for issue for a future employee. These options have not yet been granted, therefore they have not been included in the table below and no expense has been incurred in relation to the options.

The Corporation's stock options and exercise prices are denominated in Canadian Dollars when granted. As at Sept 30, 2011, 17,506,839 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:

September 30, 2011 December 31, 2010
No. of Options Wt. Avg
Exercise Price *
No. of Options Wt. Avg
Exercise Price *
Balance, beginning of period 20,146,003 $ 1.61 11,042,875 $ 1.48
Granted 260,000 $ 1.99 10,100,000 $ 1.88
Forfeited / expired (2,024,167 ) $ 2.29 (231,667 ) $ 1.28
Exercised (874,997 ) $ 0.61 (765,205 ) $ 0.33
Options 17,506,839 $ 1.66 20,146,003 $ 1.61
* The weighted average exercise price has been converted into U.S. dollars based on the foreign exchange rate in effect at the date of issuance.

The following is a summary of stock options as at September 30, 2011

Options Outstanding Options Exercisable
Wt.
Avg.
Life
Wt. Avg.
Exercise
Wt.
Avg.
Life
Wt. Avg.
Exercise
Range of
Exercise
Price
No. of
Options
(Years) Price * Range of
Exercise
Price
No. of
Options
(Years) Price *
$3.65
(C$3.65)
2,165,000 0.4 $3.65 $3.65
(C$3.65)
2,165,000 0.4 $3.65
$2.22-
$2.70
(C$2.25-
C$2.69)
5,050,000 3.2 $2.23 $2.22-
$2.86
(C$2.25-
C$2.70)
- - -
$1.49-
$1.76
(C$1.54-
C$1.85)
5,311,667 2.3 $1.55 $1.49-
$1.76
(C$1.54-
C$1.85)
1,948,330 2.0 $1.56
$0.20-
$0.81
(C$0.25-
C$0.87)
4,980,172 2.0 $0.56 $0.20-
$0.81
(C$0.25-
C$0.87)
3,032,547 2.0 $0.56
17,506,839 2.2 $1.72 7,145,877 1.5 $1.77

The following is a summary of stock options as at December 31, 2010

Options Outstanding Options Exercisable
Wt.
Avg.
Life
Wt. Avg.
Exercise
Wt.
Avg.
Life
Wt. Avg.
Exercise
Range of
Exercise
Price
No. of
Options
(Years) Price * Range of
Exercise
Price
No. of
Options
(Years) Price *
$3.65
(C$3.65)
2,435,000 1.14 $3.65 $3.65
(C$3.65)
1,623,334 1.1 $3.65
$2.22-
$2.86
(C$2.25-
C$3.00)
6,375,000 2.40 $2.25 $2.29-
$2.86
(C$2.51-
C$3.00)
1,285,000 0.3 $2.38
$1.49-
$1.76
(C$1.54-
C$1.85)
5,345,000 3.01 $1.54 $1.49-
$1.68
(C$1.54-
C$1.80)
300,000 1.7 $1.68
$0.20-
$0.81
(C$0.25-
C$0.87)
5,991,003 2.77 $0.55 $0.20-
$0.81
(C$0.25-
C$0.87)
2,591,084 2.8 $0.45
20,146,003 2.50 $1.61 5,799,418 1.3 $1.44

(c) Stock based compensation

Options granted are accounted for using the fair value method. The compensation cost during the three and nine months ended Sept 30, 2011 for total stock options granted was $1.6 million and $4.8 million respectively (Q3 2010: $0.8 million, Q3 YTD: $4.8 million). $0.6 million and $1.8 million were charged through the income statement for stock based compensation for the three and nine months ended Sept 30, 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 nine months ended For the year ended
September 30, 2011 December 31, 2010
Risk free interest rate 1.20% 1.20%
Expected stock volatility 97% 104%
Expected life of options 3 years 3 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.

16. CONTRIBUTED SURPLUS

Sept 30 Dec 31
2011 2010
US$'000 US$'000
Balance, beginning of period 11,427 6,860
Stock based compensation cost 4,833 4,840
Transfer to share capital on exercise of options (460 ) (273 )
Balance, end of period 15,800 11,427

17. 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 Sept 30 Nine months ended Sept 30
2011 2010 2011 2010
Wtd av. number of common shares (basic) 258,833,547 228,371,351 258,076,617 184,811,251
Wtd av. number of common shares (diluted) 262,850,930 231,748,163 262,935,959 188,385,443

18. TAXATION

Three months ended Sept 30 Nine months ended Sept 30
2011 2010 2011 2010
US$000 US$000 US$000 US$000
Deferred tax (740 ) - (2,479 ) -

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.

19. COMMITMENTS

Year ended Subsequent to
2011 2012 2013 2014 2014
US$'000 US$'000 US$'000 US$'000 US$'000
Office lease 63 250 250 250 813
Exploration 176 918 1,140 - -
Engineering 6,562 33,503 11,393 11,393 -
Total 6,801 34,671 12,783 11,643 813

20. 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 Sept 30, 2011:

Level 1 Level 2 Level 3 Total Fair Value
US$'000 US$'000 US$'000 US$'000
Derivative financial instrument assets - 682 - 682
Long term liability on Beatrice acquisition - - (2,394 ) (2,394 )
Contingent consideration - (10,976 ) - (10,976 )
Derivative financial instrument liability - (1,108 ) - (1,108 )

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 Sept 30 Nine months ended Sept 30
2011 2010 2011 2010
US$'000 US$'000 US$'000 US$'000
Unrealized gain/(loss) on forex forward contracts - 1,444 - (715 )
Realized (loss)/gain on forex forward contracts - (3,380 ) - (4,441 )
Revaluation of gas contract 2,315 - 3,339 -
Revaluation of other long term liability 332 (191 ) 478 (12 )
Contingent consideration - - - (4,044 )
Unrealized (loss)/gain on commodity hedges (2,250 ) - (5,477 ) 396
Realized (loss)/gain on commodity hedges - - (493 ) 86
Total gain / (loss) on financial instruments 397 (2,127 ) (2,153 ) (8,730 )

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 9 months ended Sept 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 Sept 30, 2011 resulted in an unrealized loss of $0.5 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 Sept 30, 2011 resulted in an unrealized loss of $1.7 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 oil production from the Beatrice, Jacky, and Athena fields. Oil production from Cook is sold to Shell Trading International Ltd. Anglia and Topaz gas production is currently sold through three contracts to RWE NPower PLC and Hess Energy Gas Power (UK) Ltd. Cook gas is sold to Shell UK Ltd and Esso Exploration & Production 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 Sept 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 Sept 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 Sept 30, 2011, exposure is $0.7 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 Sept 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 136,593 -
Other long term liabilities - 2,394
136,593 2,394

21. DERIVATIVE FINANCIAL INSTRUMENTS

Sept 30 Dec 31 Jan 1
2011 2010 2010
US$'000 US$'000 US$'000
Oil put premiums 682 - -
Embedded derivative (1,108 ) (4,378 ) -
Foreign exchange forward contract - - 685
(426 ) (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 Sept 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 Sept 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.

22. 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 Sept 30, 2010, the classification of financial instruments and the carrying amounts reported on the balance sheet and their estimated fair values are as follows:

Sept 30, 2011 December 31, 2010
US$'000 US$'000
Classification Carrying Fair Carrying Fair
Amount Value Amount Value
Cash and cash equivalents (Held for trading) 98,668 98,668 195,581 195,581
Restricted cash 16,679 16,679 6,308 6,308
Derivative financial instruments (Held for trading) 682 682 - -
Accounts receivable (Loans and Receivables) 120,530 120,530 93,434 93,434
Deposits 250 250 248 248
Loan fees - current 261 261 286 286
Loan fees - non-current 313 313 521 521
Commodity hedge (Held for trading) - - (349 ) (349 )
Contingent consideration (10,976 ) (10,976 ) (12,976 ) (12,976 )
Derivative financial instruments (Held for trading) (1,108 ) (1,108 ) (4,378 ) (4,378 )
Other long term liabilities (2,394 ) (2,394 ) (2,872 ) (2,872 )
Accounts payable (Other financial liabilities) (136,593 ) (136,593 ) (75,564 ) (75,564 )

23. RELATED PARTY TRANSACTIONS

A Director of the Corporation is a partner of Burstall Winger LLP who acts as counsel for the Corporation. The amount of fees paid to Burstall Winger LLP in the three and nine months ended Sept 30, 2011 was $0.1 million and $0.2 million respectively (Sept 30, 2010 - $0.5 million Sept 30, 2010 YTD - $0.6 million). The balance outstanding at Sept 30, 2011 was $Nil (Sept 30, 2010 - $Nil).

24. SEASONALITY

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

25. TRANSITION TO IFRS

These are the Corporation's third 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 nine months ended September 30, 2011, the comparative information for the three and nine months ended September 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 equivalents 29,886 - 29,886
Restricted cash 5,224 - 5,224
Accounts receivable 67,166 - 67,166
Deposits, prepaid expenses and other 352 - 352
Foreign exchange forward contract 685 - 685
103,313 - 103,313
Non current assets
Restricted cash 352 - 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 assets 309,140 - 309,140
LIABILITIES AND EQUITY
Current Liabilities
Trade and other payables 43,613 - 43,613
Commodity hedge 397 - 397
44,010 - 44,010
Non current liabilities
Long term liability 2,718 - 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 Assets 254,456 (7,728 ) 246,728
Equity attributable to equity holders
Share capital 277,075 - (952 ) 277,075
Contributed surplus (note f) 7,812 (6,776 ) 6,860
Retained (deficit) (notes d and e) (30,431 ) (37,207 )
Shareholders' Equity 254,456 (7,728 ) 246,728

Reconciliation of equity as at Sept 30, 2010

CGAAP IFRS Adj IFRS
US$'000 US$'000 US$'000
ASSETS
Current assets
Cash and cash equivalents 193,812 - 193,812
Accounts receivable 92,775 - 92,775
Deposits, prepaid expenses and other 6,763 - 6,763
293,350 - 293,350
Non current assets
Restricted cash 352 - 352
Exploration and evaluation assets (note a) - 17,892 17,892
Property, plant & equipment (notes a, b, c) 206,600 5,764 212,364
206,952 23,656 230,608
Total assets 500,302 23,656 523,958
LIABILITIES AND EQUITY
Current Liabilities
Trade and other payables 61,912 - 61,912
61,912 - 61,912
Non current liabilities
Long term liability 2,730 - 2,730
Decommissioning liabilities (note d) 6,219 2,329 8,548
Contingent consideration (note e) - 10,976 10,976
Derivative financial instruments - - -
8,949 13,305 22,254
Net Assets 429,441 10,351 439,792
Equity attributable to equity holders
Share capital 422,198 - 422,198
Contributed surplus (note f) 11,046 (838 ) 10,208
Warrants issued 311 - 311
Retained earnings / (deficit) (notes b, d, e and f) (4,114 ) 11,189 7,075
Shareholders' Equity 429,441 10,351 439,792

Reconciliation of equity as at December 31, 2010

CGAAP IFRS Adj IFRS
US$'000 US$'000 US$'000
ASSETS
Current assets
Cash and cash equivalents 195,581 - 195,581
Restricted cash 6,308 - 6,308
Accounts receivable 93,434 - 93,434
Deposits, prepaid expenses and other 12,341 - 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) 238,113 11,855 249,968
238,113 29,377 267,490
-
Total assets 561,851 17,048 578,899
LIABILITIES AND EQUITY
Current Liabilities
Trade and other payables 75,564 - 75,564
Commodity hedge 349 349
75,913 - 75,913
Non current liabilities
Long term liability 2,872 - 2,872
Decommissioning liabilities (note d) 20,868 2,784 23,652
Contingent consideration (e) - 12,976 12,976
Derivative financial instruments 4,378 - 4,378
28,118 15,760 43,878
Net Assets 457,820 1,288 459,108
Equity attributable to equity holders
Share capital 422,373 - 422,373
Contributed surplus (note f) 11,530 (103 ) 11,427
Warrants issued 311 - 311
Retained earnings (notes b, d, e and f) 23,606 1,391 24,997
Shareholders' Equity 457,820 1,288 459,108

Reconciliation of total comprehensive income for the nine months ended Sept 30, 2010

CGAAP IFRS Adj IFRS
US$'000 US$'000 US$'000
Revenue 100,861 - 100,861
Cost of sales (note b) (65,643 ) 21,949 (43,694 )
Gross Profit 35,218 21,949 57,167
Admin expenses (note f) (3,627 ) (114 ) (3,741 )
Operating Profit 31,591 21,835 53,426
Foreign exchange (172 ) - (172 )
Gain / (loss) on financial instruments (note e) (4,686 ) (4,044 ) (8,730 )
Profit on ordinary activities Before Interest and Tax 26,733 17,791 44,524
Finance costs (note d) (471 ) 173 (298 )
Interest income 56 - 56
Profit Before Tax 26,318 17,964 44,282
Taxation - - -
Profit After Tax 26,318 17,964 44,282

Reconciliation of total comprehensive income for the three months ended Sept 30, 2010

CGAAP IFRS Adj IFRS
US$'000 US$'000 US$'000
Revenue 35,965 - 35,965
Cost of sales (note b) (23,406 ) 7,596 (15,810 )
Gross Profit 12,559 7,596 20,155
Admin expenses (note f) (1,599 ) (25 ) (1,624 )
Operating Profit 10,960 7,571 18,531
Foreign exchange 1,766 - 1,766
Gain / (loss) on financial instruments (note e) (2,127 ) - (2,127 )
Profit on ordinary activities Before Interest and Tax 10,599 7,571 18,170
Finance costs (note d) (199 ) 52 (147 )
Interest income 50 - 50
Profit Before Tax 10,450 7,623 18,073
Taxation - - -
Profit After Tax 10,450 7,623 18,073

Reconciliation of total comprehensive income for the year ended December 31, 2010

CGAAP IFRS Adj IFRS
US$'000 US$'000 US$'000
Revenue 135,121 - 135,121
Cost of sales (note b) (87,307 ) 26,257 (61,050 )
Gross Profit 47,814 26,257 74,071
Exploration and evaluation (note a) - (1,119 ) (1,119 )
Admin expenses (note f) (4,620 ) (848 ) (5,468 )
Operating Profit 43,194 24,290 67,484
Foreign exchange 818 - 818
(Loss) on financial instruments (note e) (5,268 ) (4,044 ) (9,312 )
Profit on ordinary activities Before Interest and Tax 38,744 20,246 58,990
Finance costs (note d) (814 ) 249 (565 )
Interest income 113 - 113
Profit Before Tax 38,043 20,495 58,538
Taxation (note g) 15,994 (12,329 ) 3,665
Profit After Tax 54,037 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 nine months ended Sept 30, 2010, the Corporation has recognized depletion, depreciation and amortization expense of $15.3 million under IFRS when compared to $37.3 million under Canadian GAAP. For the three months ended Sept 30, 2010, the Corporation has recognized depletion, depreciation and amortization expense of $5.6 million under IFRS when compared to $13.2 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 nine months ended Sept 30, 2010, the Corporation recorded accretion of $0.2 million compared to $0.4 million under CGAAP. For the three months ended Sept 30, 2010, the Corporation recorded accretion of under $0.1 million compared to $0.1 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 nine months ended Sept 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.

26. SUBSEQUENT EVENTS

On October 19, 2011 the Company completed the acquisition of Challenger Minerals (North Sea) Limited, ("CMNSL") subsequently renamed Ithaca Minerals (North Sea) Ltd from Transocean Drilling U.K. Limited for a consideration of US$35 million; US$25 million payable immediately and US$10 million upon approval of the Stella / Harrier Field Development Plan by the Department of Energy and Climate Change, thereby increasing its interests in the Stella / Harrier fields, obtaining a non-operated interest in the producing Broom field and gaining access to additional undeveloped North Sea discoveries.

On October 19, 2011 the Company, Dyas UK Limited and CMNSL, now a subsidiary of Ithaca, entered into various agreements with the Petrofac group ("Petrofac"), effective from 1 October 2011, for the transfer by Petrofac of a majority ownership interest in a company that owns the floating production vessel 'FPF-1' and the provision of certain services. Petrofac was also granted the right to earn an interest in Stella / Harrier (Blocks 30/6a and 29/10a) and the transfer of an interest in Hurricane (Block 29/10b) and Helios (Block 29/10d).

On October 19, 2011 the Company agreed to divest a 25.34% interest in the Hurricane field to Dyas UK Limited with an effective date of 1 January 2011.

On November 1, 2011, the common shares of the Company commenced trading on the Toronto Stock Exchange under the Company's existing trading symbol "IAE". The common shares were delisted from the TSX Venture Exchange on the same day.

Contact Information