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Antrim Energy Inc. (TSX:AEN) (AIM:AEY) MANAGEMENT'S DISCUSSION AND ANALYSIS This management's discussion and analysis ("MD&A") provides a detailed explanation of Antrim Energy Inc.'s (the "Company" or "Antrim") operating results for the fourth quarter and year ended December 31, 2012 compared to the fourth quarter and year ended December 31, 2011 and should be read in conjunction with the audited consolidated financial statements of Antrim. This MD&A has been prepared using information available up to March 26, 2013. The audited consolidated financial statements of the Company have been prepared in accordance with International Financial Reporting Standards ("IFRS"). Unless otherwise noted all amounts are reported in United States dollars. Non-IFRS Measures Cash flow from operations, cash flow from operations per share and netback do not have standard meanings under IFRS and may not be comparable to those reported by other companies. Antrim utilizes cash flow from operations and netback to assess operational and financial performance to allocate capital among alternative projects and to assess the Company's capacity to fund future capital programs. Cash flow from operations is defined as cash flow from operating activities before changes in working capital. Cash flow from operations per share is calculated as cash flow from operations divided by the weighted-average number of outstanding shares. Reconciliation of cash flow from operations to its nearest measure prescribed by IFRS is provided below. Calculation of Cash Flow from Operations Three Months Ended Year Ended December 31 December 31 2012 2011 2012 2011 ---------------------------------------------------------------------------- ---------------------------------------------------------------------------- ($000's) Cash flow provided by (used in) 3,495 10,843 (8,671) 8,941 operating activities Less: change in non-cash working 11,633 11,676 4,717 12,688 capital ---------------------------------------------------------------------------- Cash deficiency from operations (8,138) (833) (13,388) (3,747) ---------------------------------------------------------------------------- ---------------------------------------------------------------------------- Overview During 2012, Antrim completed the sale of its Argentina operations and focused solely on its UK North Sea and Irish assets. In November 2012, Antrim achieved a significant milestone when the Causeway Field commenced production. Following first production from the Causeway Field, the Company achieved first production from the Cormorant East Field in January 2013 from the discovery of oil at well 211/21-N94 (the "Contender Well") drilled in October 2012. On March 26, 2013, planning was discontinued for the development of the Fyne Field following a significant escalation of expected future development costs. Overview of Continuing Operations Causeway Licences Licence P201 Block 211/22a South East Area and P1383 Block 211/23d, Antrim 35.5% The Causeway Licences include the Causeway Field, the Fionn Field and the West Causeway area. The Causeway Licences total gross proved plus probable reserves decreased by 4% from 12.5 million barrels (4.4 million net to Antrim) to 12.0 million barrels (4.3 million net to Antrim) as at December 31, 2012 due to 2012 production and technical revisions following initial field performance data. Subsequent to December 31, 2012, with an early indication of significant cost increases, Antrim elected to opt out of the Fionn Field development, which will result in a decrease of total gross proved plus probable reserves of 4.9 million barrels (1.7 million net to Antrim). Production from the Causeway Field averaged 4,081 gross barrels of oil per day ("bopd") (Antrim net 1,194 bopd) from November to December 31, 2012 compared to nil in 2011. Oil production is transported by pipeline to the North Cormorant production platform where it is processed before being exported to the Sullom Voe terminal via the Brent Pipeline System for sale. Under a contract with the purchaser, Antrim invoices and receives payment for its oil in the month after production; however, the purchaser retains certain rights impacting the timing of liftings which may result in no sales in a particular month resulting in deferred revenue. During 2012, no oil revenue was recorded ($nil - 2011) as there were no oil liftings. Deferred revenue of $1.1 million ($nil - 2011) was recognized in 2012 relating to oil produced and collected but not lifted from the terminal. Rig operations commenced in January 2013 to complete the water injector for the Causeway Field and were completed in February 2013. Anticipated startup of the downhole electrical submersible pump ("ESP") will follow completion of topside modifications on the North Cormorant production platform, and is scheduled for the second half of 2013. The recently completed water injection well is expected to commence operation in 2014, with a possibility of it being accelerated to the second half of 2013. As part of the sale of a 30% working interest in the Causeway Licences to Valiant Petroleum plc ("Valiant") in October 2011, Antrim entered into a Differential Lifting Agreement ("DLA") giving Valiant the right to 6.25% of Antrim's share of produced oil. Antrim's share of oil produced will be reduced to 29.25% until a cumulative value of $8.9 million after-tax is received by Valiant. Once satisfied, Antrim's working interest in production will revert back from 29.25% to 35.5%. Under the terms of the Fionn Field Supplementary Agreement with Valiant, Antrim had an option for three months following first oil production from the Causeway Field to opt out of participating in the Fionn Field development and sell its 35.5% working interest share to Valiant for the cost of its 35.5% working share of the Fionn Field pre-investment costs, or to confirm its continued participation by repaying its share of the Fionn pre-investment costs plus interest. In February 2013, Antrim announced that it had elected to opt out of participating in further development of the Fionn Field. The projected costs associated with the development of Fionn had increased to the extent that the project no longer met Antrim's economic criteria. Subject to all necessary approvals from the UK Department of Energy and Climate Change ("DECC"), Antrim intends to withdraw from the Fionn Field subarea and will not incur any further liabilities. As a result, an impairment charge of $50.4 million was recorded in the fourth quarter of 2012 representing the full carrying value relating to the Fionn Field. Contender Licence P201 Block 211/22a Contender Area, Antrim 8.4% The Contender Licence contains the Cormorant East Field. Cormorant East Field total gross proved plus probable reserves increased from nil to 7.3 million barrels (0.6 million net to Antrim) as at December 31, 2012 due to the successful drilling of exploration well 211/21-N94 (the "Contender Well") as announced on October 22, 2012. On January 14, 2013, Antrim announced that first oil production had been achieved from the Cormorant East Field after 85 days following discovery of the field. Production is processed through the North Cormorant platform before being exported to the Sullom Voe terminal. The Cormorant East Field is initially being produced under primary depletion with a single production well, with the potential to install a water injection scheme and/or additional production wells at a later date. Future drilling locations are being considered by the partners. Under the terms of the farm-out agreement with the operator, 100% of the drilling, completion and tie in costs of the Contender Well were funded by the operator. Antrim will receive its share of production after Antrim's working interest share of the completion and tie in costs is recovered from production revenue. Kerloch Licence P201 Block 211/22a Kerloch Area, Antrim 13.65% The Kerloch Licence includes the Kerloch discovery made in 2007. With the successful drilling of the Contender Well, TAQA also earned a 35% working interest in the adjacent Licence P201 Block 211/22a Kerloch Area, reducing Antrim's working interest from 21% to 13.65%. Fyne Licence P077 Block 21/28a - Fyne, Dandy and Crinan, Antrim 100% The Fyne Licence includes the Fyne Field, the Dandy Field and the Crinan Field (formerly referred to as "Area 4"). Total proved plus probable reserves at December 31, 2012 decreased by 50% to 11.8 million barrels from 23.3 million barrels (gross) in 2011. The change was due to the results of well 21/28a-11 drilled in the East Fyne area, a decrease in reserves attributed to the Dandy Field due to no further development currently being planned, and the upgrade in reserve category in the Crinan Field due to it being cited as part of a potential phase 2 development of the Fyne Licence. Antrim's net reserves in the Fyne Licence increased by 44% from 8.2 million barrels to 11.8 million barrels as the decrease in gross reserves was offset by an increase in working interest from 35.1% to 100%. On March 26, 2013 the Company discontinued development of the Fyne Field. Until very recently, estimated costs indicated that the planned Fyne development satisfied the Company's economic threshold and contingent on timing of the redeployment of the FPSO from its current location was on track for a late 2014 start-up. However, projected capital costs have recently increased substantially, and in the Company's view now make the project uneconomic. The majority of costs associated with the Fyne Field were written off in March 2012. No further material write downs associated with the Fyne Field are anticipated as recent work has been confined to front end engineering design work for the subsea facilities and modification to the FPSO. Erne P1875 21/29d, Antrim 50% Licence P1875 contains the Erne discovery drilled in 2011 and the Corrib prospect. The Erne sidetrack well 21/29d-11Z well is suspended for possible future incorporation into neighbouring infrastructure A separate prospect has been identified to the southwest, named Corrib, which may also be assessed for possible future incorporation into neighbouring infrastructure. Carra P1563 Blocks 21/28b and 21/29c, Antrim 100% Licence P1563 contains the Carra Prospect, the Riddon and Scavaig discoveries and several other prospects. In October 2012, DECC agreed to waive the contingent well obligation on Licence P1563 Blocks 21/28b & 21/29c as it was determined by Antrim that there was insufficient potential to proceed with drilling. The licence was relinquished in February 2013. Cyclone and Typhoon Licence P1784 Block 21/7b, Antrim 30% Licence P1784 Block 21/7b is located in the Central North Sea, north of the Greater Fyne Area and contains the "Cyclone" and "Typhoon" Tertiary Cromarty prospects. The licence was acquired jointly with Premier (70%, Operator) with a firm well commitment. In November 2012, Cyclone well 21/7b-4 was drilled and encountered 105 feet of very porous and permeable Tertiary Cromarty sands. Well logs identified only residual oil, suggesting that the trap was breached and the well was plugged and abandoned. As a result, an impairment charge of $5.9 million was recorded in the fourth quarter of 2012, representing the full carrying value relating to Block 21/7b. Ireland Licensing Option 11/5 Blocks 44/4, 44/5 (part), 44/9, 44/10, 44/14, 44/15, Antrim 100% Antrim holds a Frontier Licence Option (the "Skellig Block") in the Porcupine Basin approximately 110 km off the southwest coast of Ireland. Antrim has licenced, reprocessed and interpreted 2D seismic data and has identified the "Dunree Prospect". Antrim is currently planning a 3D seismic programme and is seeking partners to joint venture on the block. Participation in the block has received strong interest from industry. Tanzania Production Sharing Agreement - Pemba and Zanzibar Antrim holds an option to acquire a 20% interest in the production sharing agreement for the Pemba-Zanzibar exploration licence offshore and onshore Tanzania (the "P-Z PSA") following the pre-drilling (seismic) phase and an additional 10% interest to be exercised up to 180 days following receipt of the initial drilling results. Should Antrim exercise the initial option, costs for the seismic phase associated with Antrim's acquired interests would be repaid from future production. RAK Gas, the Operator, has submitted a proposal for a revised work programme to the federal government of Tanzania. Environmental impact assessment work has commenced, with seismic operations expected to proceed in the near future. On October 29, 2012, an agreement between the federal government of Tanzania and the government of Zanzibar on the sharing of any future hydrocarbon revenues was announced, potentially ending a moratorium which has delayed exploration of the licence. The agreement has still to be ratified and final details are still to be agreed. It is not yet known what, if any, impact this agreement will have on the P-Z PSA. Reserves Update In February 2013 Antrim elected out of participating further in the Fionn Field development and on March 26, 2013 the Company discontinued development of the Fyne and Crinan Fields following a significant escalation of expected future development costs. The impact on Antrim's reserves is as follows: Net UK proved plus probable reserves (Mbbls) ---------------------------------------------------------------------------- At December 31, 2012 16,626 Less: Fionn Field (1,727) Fyne and Crinan Fields (11,758) ---------------------------------------------------------------------------- Revised proved plus probable reserves 3,141 ---------------------------------------------------------------------------- The updated present value cash flow after tax using a 10% discount rate is $144,775,000. Corporate On January 23, 2013, Antrim announced that it entered into a $30 million Payment Swap transaction with a major financial institution. The Payment Swap provided Antrim with sufficient funding to meet its commitments for cost overruns on the completion of the production well in the Causeway Field, future costs related to the Causeway water injection well and initial FEED work associated with the Fyne Field. Under the terms of the Payment Swap, $30 million is repayable in 29 instalments commencing September 2013 and concluding January 2016. The interest rate under the Payment Swap is fixed at 5.1%. To enable Antrim to pay amounts under the Payment Swap, Antrim also entered into a Brent Oil Price Commodity Swap for a forward sale of 657,350 barrels of Brent crude oil at a fixed price of $89.37 covering the period from February 2013 to December 2015. Financial Discussion of Continuing Operations All amounts reported in this MD&A related to the three month periods ended December 31, 2012 and 2011 are unaudited. Three Months Ended Year Ended December 31 December 31 2012 2011 2012 2011 ---------------------------------------------------------------------------- Financial Results ($000's except per share amounts) ------------------------------------ Cash deficiency from operations (1) - continuing operations 8,138 833 13,388 3,747 Cash deficiency from operations per share (1) 0.04 0.00 0.07 0.02 Net loss - continuing operations 67,155 15,975 134,859 55,110 Net loss 67,155 14,951 134,544 52,970 Net loss per share - basic, continuing operations 0.37 0.09 0.73 0.32 Total assets 96,520 239,177 96,520 239,177 Working capital (deficiency) (10,734) 52,674 (10,734) 52,674 Capital expenditures 26,771 10,634 63,034 14,702 Bank debt - - - - Common shares outstanding (000's) ------------------------------------ End of period 184,731 184,116 184,731 184,116 Weighted average - basic 184,848 184,108 184,388 173,997 Weighted average - diluted 185,681 185,530 185,528 175,412 (1) Cash flow from operations and cash flow from operations per share are Non-IFRS Measures. Refer to "Non-IFRS Measures" in Management's Discussion and Analysis. Production From early November to December 31, 2012, gross daily oil production from the Causeway Field averaged gross 4,081 bopd (Antrim net 1,194 bopd). The following table provides oil production and sales from the Causeway Field for the year ended December 31, 2012. (barrels) 2012 2011 ---------------------------------------------------------------------------- Gross production (1) 146,870 - Net production (2) 42,950 - Ending inventory (3) 42,950 - Sales - - (1) Gross production is after linefill and deadstock of 106,153 barrels (2) Per the DLA, Antrim's share of oil produced is reduced to 29.25% until a cumulative value of $8.9 million after tax is received by Valiant (3) Ending oil inventory is net of process and shrinkage Revenue Revenue is recognized when title and risk transfer to the purchaser, which occurs at the time of lifting into a tanker at the Sullom Voe terminal. All sales from Causeway are made under contract to one UK customer. Under the contract with the purchaser, Antrim invoices and receives payment for its oil in the month after production; however, the purchaser retains certain rights impacting the timing of liftings which may result in no sales in a particular month resulting in deferred revenue. The Company did not record any revenue in 2012 (2011 - nil) as there was no oil lifted from the terminal in 2012. General and Administrative General and administrative ("G&A") costs increased to $5.8 million for the year ended December 31, 2012 compared to $5.0 million in 2011. The increase in G&A costs was primarily due to employee compensation. During 2012, Antrim capitalized $0.6 million (2011 - $0.6 million) of G&A costs related to exploration and development activity. Exploration & Evaluation Expenditures Exploration and evaluation ("E&E") expenditures increased to $7.6 million for the year ended December 31, 2012 compared to $0.3 million for the same period in 2011. E&E expenditures increased to $6.3 million for the three month period ended December 31, 2012 compared to $0.03 million for the same period in 2011. The increase in E&E expenditures is primarily related to work on the development plan for the Fyne Licence. Impairment In January 2013, the Company elected not to participate in further development work on the Fionn Field. As a result, an impairment charge of $50.4 million was recognized in the fourth quarter of 2012, representing the full carrying value relating to the Fionn Field. Antrim retains a 35.5% interest in the remainder of Licence P201 Block 211/22a South East Area. In December 2012, the Company announced that the Cyclone exploration well in UK Block 21/7b was plugged and abandoned. As a result, an impairment charge of $5.9 million was recognized in the fourth quarter of 2012 representing the full carrying value of the licence. Licence P1625 Block 21/24b ("West Teal") is nearing the end of its initial exploration term and based on an evaluation performed by management the licence is not considered economically viable. As a result, the Company recognized an impairment charge of $1.8 million in the fourth quarter of 2012, representing the full carrying value of the licence. In October 2012, DECC agreed to waive the seismic and contingent well obligations on Licence P1563 Blocks 21/28b & 21/29c ("Carra") and allowed the Company to relinquish the licence in its entirety. The Company recognized a $2.3 million impairment charge in the third quarter of 2012 representing the full carrying value of the licence. In addition the Company recorded impairment charges consisting of $60.1 million for the Fyne Licence and $2.1 million on the drilling of the Erne discovery well and the Erne sidetrack well in the first and second quarters of 2012. The impaired costs relating to the Erne discovery well and the Erne sidetrack well are in addition to a $10.3 million impairment charge recorded in 2011. Discontinued Operations On May 28, 2012, Antrim completed the sale of Antrim Argentina S.A. to Crown Point Energy Inc. ("Crown Point") (formerly known as Crown Point Ventures Ltd.) by way of a plan of arrangement effected under the Business Corporation Act (Alberta) (the "Arrangement"). Under the terms of the Arrangement, the Company received a cash payment of $9.9 million (net of adjustments of $1.0 million) and 35,761,290 common shares of Crown Point ("Crown Point Shares"). The Crown Point Shares were distributed to Antrim's shareholders in accordance with the terms of the Arrangement on June 7, 2012 (the "Distribution Date"). As a result of the sale, the Company recognized a gain on the disposal of the Argentina assets of $5.9 million and income from discontinued operations for the year ended December 31, 2012 of $0.3 million (2011 - $2.1 million). The financial and operating results for discontinued operations for the year ended December 31, 2012 include only the results up to May 28, 2012, the date of sale of the Argentina operations, and are no longer comparable with the 2011 results. Reduction in the Fair Value of Financial Assets On the Distribution Date, the closing price of the Crown Point Shares on the TSX Venture Exchange was Cdn $0.51 which had decreased from the May 28, 2012 closing share price of Cdn $0.80. This reduction in the share price of the Crown Point Shares resulted in the Company recognizing a capital loss on the Crown Point Shares of $10.0 million. This amount has been recognized in the 2012 consolidated statement of comprehensive loss as a reduction in the fair value of financial assets. Finance Income Finance income relates to interest income on short-term deposits and was $0.3 million (2011 - $0.7 million) for the year ended December 31, 2012. Finance Costs Finance costs were $0.2 million for the year ended December 31, 2012 (2011 - $0.6 million) and relate to accretion of decommissioning obligations, interest expense and bank charges. Income Taxes Current income tax assets and liabilities are measured at the amount expected to be recovered from or paid to the taxation authorities. The Company did not pay or recover any taxes during the year ended December 31, 2012. The Company follows the liability method of accounting for income taxes. As at December 31, 2012, no deferred income tax assets were recorded due to uncertainty with respect to the ability of Antrim to generate sufficient taxable income to utilize the unrecognized losses. Cash Flow and Net Loss In the three month period ended December 31, 2012, Antrim had a cash deficiency from operations of $8.1 million ($0.04 per share) compared to cash deficiency from operations of $0.8 million ($0.00 per share) in the same period in 2011. For the year ended December 31, 2012, Antrim incurred a cash deficiency from operations of $13.4 million ($0.07 per share) in 2012 compared to a cash deficiency from operations of $3.7 million ($0.02 per share) in 2011. The cash deficiency from operations increased in 2012 primarily due to higher exploration and evaluation expenditures. In the fourth quarter of 2012 and 2011, Antrim incurred net losses of $67.2 million and $15 million respectively. For the year ended December 31, 2012, the Company incurred a net loss of $134.5 million compared to $53 million in 2011. The increase in the net loss was due to impairment charges for the Fionn Field, the Fyne Licence, West Teal Licence and the Cyclone - Typhoon licence and E&E expenditures on the Fyne Licence. Capital Expenditures Antrim incurred capital expenditures in 2012 related to petroleum and natural gas properties of $63 million (2011 - $14.7 million). Capital expenditures in 2012 consisted of $54.5 million for the ongoing development costs of the Causeway Licence, $5.5 million in exploration costs related to the Cyclone well, and $1.6 million for the drilling of the Erne discovery well. Foreign Exchange Loss and Comprehensive Income (Loss) The measurement currency of the Company is the Canadian dollar, while its reporting currency is the US dollar. A significant portion of the Company's activities are transacted in or referenced to US dollars, Canadian dollars and British pounds sterling. The Company's operating costs and certain of the Company's payments in order to maintain property interest are made in the local currency of the jurisdiction where the applicable property is located. As a result of these factors, fluctuations in the Canadian dollar, British pounds sterling and US dollar could result in unanticipated fluctuations in the Company's financial results. The Company incurred a foreign exchange loss of $0.5 million from continuing operations for the year ended December 31, 2012 compared to a loss of $0.7 million in 2011. The Company realized a gain of $3.2 million in accumulated other comprehensive income related to discontinued operations for the year ended December 31, 2012. Financial Resources and Liquidity In the fourth quarter of 2012, the Company incurred unexpected cost overruns on the development of the Causeway Field, resulting in a working capital deficiency of $10.7 million as at December 31, 2012. In January 2013, Antrim entered into the $30 million Payment Swap transaction which provides Antrim with sufficient funding to meet its commitments. Accounts payable and accrued liabilities were $18.1 million at December 31, 2012 primarily related to costs for the development of the Causeway and Fyne Fields and the Cyclone drilling program in November, compared to $17.2 million as at December 31, 2011. Antrim invests unrestricted cash not required for immediate operational needs in short-term bankers' acceptances and money market instruments. Although there have been improvements in the global economy and financial markets, restrictions on availability of credit remain and may limit Antrim's ability to access debt or equity financing for its development projects. Antrim forecasts cash flows against a range of macroeconomic and financing market scenarios in an effort to identify future commitments and arrange financing, if necessary. Antrim's planned capital program for 2013 includes ongoing development of the Causeway Field, the Cormorant East Field and new ventures. Contractual Obligations, Commitments and Contingencies Antrim has several commitments in respect of its petroleum and natural gas properties and operating leases as at December 31, 2012 as follows: ($000's) 2013 2014 2015 2016 2017 Thereafter ---------------------------------------------------------------------------- United Kingdom Causeway (1) 16,079 7,073 27 29 31 31 Cormorant East 654 8 8 8 8 8 Fyne and Dandy (2) 2,913 33 33 33 33 33 Cyclone-Typhoon (3) 13 12 - - - - West Teal (4) - - - - - - Carra (5) - - - - - - Erne 13 13 - - - - Ireland 69 - - - - - Office leases 358 359 372 372 350 10 ---------------------------------------------------------------------------- Total 20,099 7,498 440 442 422 82 ---------------------------------------------------------------------------- (1) Relates to Antrim's 35.5% interest in the Causeway Licences. (2) In 2012, Antrim signed a Heads of Term's agreement for an option to lease an FPSO for use in the development of the Fyne Field. As the Company decided not to proceed with the development of the Fyne Field., there is a $2.8 million obligation related to front end engineering design work. This obligation is included in the consolidated balance sheet as at December 31, 2012 under accounts payable and accrued liabilities. (3) The Company has a $6.2 million contingent drilling commitment on this licence for the Typhoon prospect in 2014. Due to the results of the Cyclone well, the Company has asked DECC to accept this well as a fulfillment of the drilling obligation. Contingent on DECC acceptance, there are no remaining obligations for the initial term of the licence. (4) The Company has a $24.0 million contingent drilling commitment on this licence for the West Teal prospect in 2013. Due to the Company being unable to identify a commercially viable export route a request was made to DECC to waive the contingent well requirement and, with DECC's consent, allow the licence to be relinquished. (5) In October 2012, DECC waived all commitments related to the Licence P1563 Blocks 21/28b & 21/29c. In February 2013 the licence and all commitments were officially relinquished. In 2011, the Company entered into a variation to an existing contract for drilling management services in the UK North Sea which required the drilling of two wells, estimated to take 50 days in a letter of intent preceding the contract variation. The Company contends that it met its contractual obligations under this variation through the drilling of the Erne discovery well (21/29d-11) and the Erne sidetrack well (21/29d-11Z). The drilling of these two wells took place over a period of 58 days. Subsequent to releasing the rig, the Company received an invoice from the drilling management services contractor charging the Company for approximately $5 million in additional costs as the contractor claims all conditions of the contract had not yet been satisfied. In July 2012, the drilling management services contractor filed a claim against the Company for the additional invoice costs plus interest and lost management time, in the High Court of England and Wales. In August 2012, the Company filed a defence against this claim in the High Court of England and Wales. A case management conference where the Court will set the timetable for the claim going forward has been listed for April 12, 2013. The Company is disputing the additional costs and believes it is more likely than not that it will not have to pay. As a result, a contingent liability has not been recorded. In January 2013 the Company elected not to participate in further development work on the Fionn Field. Subject to all necessary approvals from DECC, Antrim intends to withdraw from the Fionn Field subarea and will not incur any further liabilities. In accordance with the Fionn Field Supplemental Agreement signed in January 2012, the Company is of the position that there are no further obligations with respect to the decommissioning or well abandonment liabilities of the three currently suspended wells in the Fionn Field subarea. The operator contends this position in regards to two of the three currently suspended wells. The Company is disputing the operator's position and believes it is more likely than not that Antrim will be released of these obligations. Accordingly, no amounts have been recorded in decommissioning obligation in relation to the Fionn Field. Risks and Uncertainties The oil and gas industry involves a wide range of risks which include but are not limited to the uncertainty of finding new commercial fields, securing markets for existing reserves, commodity price fluctuations, exchange and interest rate costs and changes to government regulations, including regulations relating to prices, taxes, royalties, land tenure, allowable production and environmental protection and access to off-shore production facilities in the UK. The oil and natural gas industry is intensely competitive and the Company competes with a large number of companies that have greater resources. Substantial Capital Requirements The Company's ability to increase reserves in the future will depend not only on its ability to develop its present properties but also on its ability to select and acquire suitable exploration or producing properties or prospects. The acquisition and development of properties also requires that sufficient funds, including funds from outside sources, will be available in a timely manner. The availability of equity or debt financing is affected by many factors, many of which are outside the control of the Company. Recent world financial market events and the resultant negative impact on economic conditions have increased the risk and uncertainty of the availability of equity or debt financing. In January 2013, Antrim entered into a payment swap for $30 million and a forward sale of 657,350 barrels of Brent crude oil. The Company's anticipated revenue for 2013, as well as the Company's ability to repay the payment swap, is dependent upon the future production rates from the Causeway and Cormorant East fields as well as oil prices. Foreign Operations A number of risks are associated with conducting foreign operations over which the Company has no control, including currency instability, potential and actual civil disturbances, restriction of funds movement outside of these countries, the ability of joint venture partners to fund their obligations, changes of laws affecting foreign ownership and existing contracts, environmental requirements, crude oil and natural gas price and production regulation, royalty rates, OPEC quotas, potential expropriation of property without fair compensation, retroactive tax changes and possible interruption of oil deliveries. Further discussions regarding the Company's risks and uncertainties, can be found in the Company's Annual Information Form dated March 26, 2013 which is filed on SEDAR at www.sedar.com. Outlook Antrim expects to see increased production from the Causeway Field following deployment of the ESP in the second half of 2013, and the implementation of the water injection scheme scheduled to commence operation in 2014, with a possibility of it being accelerated to the second half of 2013. Following the discovery of the Cormorant East Field by the Contender Well, Antrim anticipates planning at least one appraisal well, downdip of the discovery well and a plan to explore the adjacent fault compartments. Recent seismic studies on the Skellig block in the Porcupine Basin offshore Southwest Ireland has high graded the Dunree Prospect, adjacent to the licence holding the Dunquin Propsect, which is expected to be drilled by its operator and joint venture partners in the second quarter of 2013. Antrim is currently seeking partners to joint venture on the block and has received strong interest from the industry. Summary of Quarterly Results Oil, Natural Gas and NGL Cash Flow Net Revenue, from Loss Per ($000, except per share Net of Operations Net Share - amounts) Royalties (Deficiency) Loss Basic ---------------------------------------------------------------------------- 2012 Fourth quarter(1) - (8,138) 67,155 0.37 Third quarter (1) - (472) 5,240 0.03 Second quarter (1) - (3,177) 6,373 0.03 First quarter (1) - (1,601) 56,091 0.30 ---------------------------------------------------------------------------- - (13,388) 134,859 0.73 ---------------------------------------------------------------------------- 2011 Fourth quarter (1) - (833) 15,362 0.10 Third quarter (1) - (894) 36,800 0.20 Second quarter (1) - (1,215) 1,503 0.01 First quarter (1) - (805) 1,445 0.01 ---------------------------------------------------------------------------- - (3,747) 55,110 0.32 ---------------------------------------------------------------------------- (1) Quarterly results reflect continuing operations only Key factors relating to the comparison of net loss for the last eight quarters are as follows: -- In the fourth quarter of 2012, the Company recognized a $50.4 million impairment charge related to the decision not to participate in further development of its 35.5% working interest in the Fionn Field, a $5.9 million impairment charge related to the abandonment of the Cyclone well 21/7b-4 and a $1.8 million impairment charge related to the West Teal Licence; -- In the third quarter of 2012, the Company recognized a $2.3 million impairment charge related to the planned relinquishment of Carra Licence P1563 Blocks 21/28b & 21/29c; -- The second quarter 2012 net loss was impacted by a $10 million reduction in the fair value of the Crown Point shares partially offset by a $5.9 million gain on the disposal of the Argentina assets; -- During the first quarter of 2012, net loss was negatively impacted by $54.7 million in impairment costs related to the Fyne Licence and the Erne discovery well and Erne sidetrack well; -- In the fourth quarter of 2011, the Company recognized an impairment charge of $10.3 million related to the Erne discovery well 21/29d-11 and Erne sidetrack well 21/29d-11Z; -- During the third quarter of 2011, the Company recognized an impairment charge of $35.6 million due to the sale of the 30% interest in the Causeway Licences. Critical Accounting Estimates Our significant accounting policies are detailed in Note 3 to the audited consolidated financial statements. In determination of financial results, Antrim makes certain critical accounting estimates described as follows: Estimation of reserve quantities Depletion, impairment and asset retirement charges are measured based on the Company's estimate of oil and gas reserves. The estimation of reserves is an inherently complex process and involves the exercise of professional judgment. Reserves have been evaluated at the balance sheet date by an independent qualified reserve evaluator in accordance with National Instrument 51-101 Standards of Disclosure for Oil and Gas Activities and are based on the definitions and guidelines contained in the Canadian Oil and Gas Evaluation Handbook. Oil and gas reserve estimates are based on a range of geological, technical and economic factors including projected future rates of production, estimated commodity prices, engineering data, reserve type and timing and amount of future expenditures, all of which are subject to uncertainty. Assumptions reflect market and regulatory conditions existing at the balance sheet date, which could differ significantly from other points in time throughout the year, or future periods. Changes in market and regulatory conditions and assumptions can materially impact the estimation of net reserves. Recoverability of exploration and evaluation costs Exploration and evaluation costs are initially capitalized with the intent to establish commercially viable reserves. The Company is required to make estimates and judgments about future events and circumstances regarding the economic viability of extracting the underlying resources. The costs are subject to technical, commercial and management review to confirm the continued intent to develop and extract the underlying resources. Fluctuations in future commodity prices, resource quantities, expected production techniques, drilling results, production costs and required capital expenditures are important factors when making this determination. If a judgment is made that extraction of the reserves is not viable, the exploration and evaluation costs will be written off to net earnings. Decommissioning obligations The Company recognizes liabilities for the future decommissioning and restoration of property, plant and equipment. These provisions are based on estimated costs, which take into account the anticipated method and extent of restoration consistent with legal requirements, technological advances and the possible use of the site. Actual costs are uncertain and estimates can vary as a result of changes to relevant laws and regulations, the emergence of new technology, operating experience and prices. The actual timing of future decommissioning and restoration is not known and may change due to certain factors, including reserve life. Changes to assumptions made about future expected costs, discount rates, inflation and timing may have a material impact on the amounts presented. The Company has chosen to measure decommissioning obligations using a risk-free discount rate. Impairment of property, plant and equipment The recoverable amounts of cash-generating units ("CGUs") and individual assets have been determined based on greater of value-in-use or fair value less costs to sell calculations. The key assumptions the Company uses in estimating future cash flows for purposes of calculating value-in use or fair value less costs to sell are future oil prices, expected production volumes, future development costs, operating costs and the discount rate applied to reflect the time value of money. Changes to these assumptions will affect the recoverable amounts of CGUs and individual assets and may then require a material adjustment to their related carrying value. The determination of CGUs requires judgement in defining a group of assets that generate cash inflows that are largely independent of the cash inflows from other assets or groups of assets. CGUs are determined by similar geological structure, shared infrastructure, geographical proximity, commodity type, similar exposure to market risks and materiality. Fair value of share-based compensation The fair value of share-based compensation is calculated using a Black-Scholes option-pricing model. There are a number of estimates used in the calculation such as future forfeiture rate, expected option life and the future price volatility of the underlying security which can vary from actual future events. The factors applied in the calculation are management's best estimates based on historical information and future forecasts. Fair value of contingent consideration When consideration transferred relating to an acquisition includes consideration contingent on future events, the Company is required to estimate the fair value of the contingent consideration and record a contingent consideration liability. The fair value of such consideration is based on assumptions and judgements regarding the likelihood of future events. Deferred income taxes Deferred tax assets are recognized when it is considered probable that deductible temporary differences will be recovered in the foreseeable future. To the extent that future taxable income and the application of existing tax laws in each jurisdiction differ significantly from the Company's estimate, the ability of the Company to realize the deferred tax assets could be impacted. New Accounting Pronouncements The following pronouncements and amendments are effective for annual periods beginning on or after January 1, 2013 unless otherwise stated. Adopting these standards is expected to have minimal or no impact on the consolidated financial statements. IFRS 10 - Consolidation replaces SIC-12 Consolidation - Special Purpose Entities and parts of IAS 27 Consolidated and Separate Financial Statements and requires an entity to consolidate an investee when it is exposed, or has rights, to variable returns from its involvement with the investee and has the ability to affect those returns through its power over the investee. IFRS 11 - Joint Arrangements requires a venturer to classify its interest in a joint arrangement as a joint venture or joint operation. Joint ventures will be accounted for using the equity method of accounting whereas joint operations, the venturer will recognize its share of the assets, liabilities, revenue and expenses of the joint operation. IFRS 11 supersedes IAS 31 Interests in Joint Ventures, and SIC-13 Jointly Controlled Entities - Non-monetary Contributions by Venturers. IFRS 12 - Disclosure of Interest in Other Entities establishes disclosure requirements for interests in other entities, such as joint arrangements, associates, and special purpose vehicles and off balance sheet vehicles. The standard carries forward existing disclosures and also introduces additional disclosures addressing the nature of, and risks associated with, an entity's interests in other entities. IFRS 13 - Fair Value Measurement is a comprehensive standard that defines fair value, requires disclosure about fair value measurement and provides a framework for measuring fair value when it is required or permitted within the IFRS standards. IAS 27 - Separate Financial Statement addresses accounting for subsidiaries, jointly controlled entities and associates in non-consolidated financial statements. IAS 28 - Investments in Associates and Joint Ventures has been amended to include joint ventures in its scope and to address the changes in IFRS 10 - 13. IAS 1 - Presentation of Financial Statements amendment requires components of other comprehensive income to be separately presented between those that may be reclassified to income and those that will not. The amendments are effective for annual periods beginning on or after July 1, 2012. IAS 32 - Financial Instruments: Presentation amendment provides clarification on the application of offsetting rules. The amendments are effective for annual periods beginning on or after July 1, 2012. Disclosure Controls and Procedures and Internal Controls Over Financial Reporting Antrim has established disclosure controls, procedures and corporate policies so that its consolidated financial results are presented accurately, fairly and on a timely basis. The Chief Executive Officer and Chief Financial Officer have designed or have caused such internal controls over financial reporting to be designed under their supervision to provide reasonable assurance regarding the reliability of financial reporting and preparation of the Company's financial statements in accordance with IFRS. The Company tested and evaluated the effectiveness of its disclosure controls and procedures and internal controls over financial reporting as at December 31, 2012. During this evaluation the Corporation identified a weakness due to the limited number of finance and accounting personnel at the Corporation dealing with complex and non-routine accounting transactions that may arise. There were no changes in the Company's internal controls over financial reporting that occurred during 2012 that have materially affected, or are reasonably likely to materially affect, the Company's internal controls over financial reporting. All internal control systems, no matter how well designed, have inherent limitations. Therefore, these systems provide reasonable but not absolute assurance that financial information is accurate and complete. Related Party and Off-Balance Sheet Transactions Antrim may from time to time enter into arrangements with related parties. In 2012, Antrim incurred fees of $421,607 (2011 - $266,741) payable to Burstall Winger LLP, a law firm in which a director of the Company is a partner. The Company had no off-balance sheet transactions in the year ended December 31, 2012. Forward-Looking Statements This MD&A and any documents incorporated by reference herein contain certain forward-looking statements and forward-looking information which are based on Antrim's internal reasonable expectations, estimates, projections, assumptions and beliefs as at the date of such statements or information. Forward-looking statements often, but not always, are identified by the use of words such as "seek", "anticipate", "believe", "plan", "estimate", "expect", "targeting", "forecast", "achieve" and "intend" and statements that an event or result "may", "will", "should", "could" or "might" occur or be achieved and other similar expressions. These statements are not guarantees of future performance and involve known and unknown risks, uncertainties, assumptions and other factors that may cause actual results or events to differ materially from those anticipated in such forward-looking statements and information. Antrim believes that the expectations reflected in those forward-looking statements and information are reasonable but no assurance can be given that 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 or the particular document incorporated by reference herein and Antrim 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, contain specific forward-looking statements and information pertaining to the quantity of and future net revenues from Antrim's reserves of oil, natural gas liquids ("NGL") and natural gas production levels. This MD&A may also contain specific forward-looking statements and information pertaining to Antrim's plans for developing its licences, expected production rates and future development plans with respect to Cormorant East and future development plans for the Causeway Field, commodity prices, foreign currency exchange rates and interest rates, capital expenditure programs and other expenditures, supply and demand for oil, NGL's and natural gas, expectations regarding Antrim's ability to raise capital, to continually add to reserves through acquisitions and development, the schedules and timing of certain projects, Antrim's strategy for growth, Antrim's future operating and financial results, treatment under governmental and other regulatory regimes and tax, environmental and other laws. With respect to forward-looking statements contained in this MD&A and any documents incorporated by reference herein, Antrim has made assumptions regarding Antrim's ability to obtain additional drilling rigs and other equipment in a timely manner, obtain regulatory approvals, future oil and natural gas production levels from Antrim's properties and the price obtained from the sales of such production, the level of future capital expenditure required to exploit and develop reserves, the ability of Antrim's partners to meet their commitments as they relate to the Company and Antrim's reliance on industry partners for the development of some of its properties, Antrim's ability to obtain financing for future Fyne development on acceptable terms, the general stability of the economic and political environment in which Antrim operates and the future of oil and natural gas pricing. In respect to these assumptions, the reader is cautioned that assumptions used in the preparation of such information may prove to be incorrect. Antrim'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 risks associated with the exploration for and development of oil and natural gas reserves such as the risk that drilling operations may not be successful, unanticipated delays with respect to the development of Antrim's properties, operational risks and liabilities that are not covered by insurance, volatility in market prices for oil, NGLs and natural gas, changes or fluctuations in oil, NGLs and natural gas production levels, changes in foreign currency exchange rates and interest rates, the ability of Antrim to fund its substantial capital requirements and operations and to repay its obligations under the Payment Swap and Brent Oil Price Commodity Swap. Antrim's reliance on industry partners for the development of some of its properties, risks associated with ensuring title to the Company's properties, liabilities and unexpected events inherent in oil and gas operations, including geological, technical, drilling and processing problems the risk of adverse results from litigation, the accuracy of oil and gas reserve estimates and estimated production levels as they are affected by the Antrim's exploration and development drilling and estimated decline rates, in particular the future production rates at the Causeway and Cormorant East Fields in the UK North Sea. Additional risks include the ability to effectively compete for, among other things, capital, acquisitions of reserves, undeveloped lands and skilled personnel, incorrect assessments of the value of acquisitions, Antrim's success at acquisition, exploitation and development of reserves, changes in general economic, market and business conditions in Canada, North America, the United Kingdom, Europe and worldwide, 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 and more specifically, changes in environmental or other legislation applicable to Antrim's operations, and Antrim's ability to comply with current and future environmental and other laws, adverse regulatory rulings, order and decisions and risks associated with the nature of the Common Shares. Many of these risk factors, other specific risks, uncertainties and material assumptions are discussed in further detail throughout this MD&A and in Antrim's annual information form for the year ended December 31, 2012. Readers are specifically referred to the risk factors described in this MD&A under "Risk Factors" and in other documents Antrim files from time to time with securities regulatory authorities. Copies of these documents are available without charge from Antrim or electronically on the internet on Antrim's SEDAR profile at www.sedar.com. Readers are cautioned that this list of risk factors should not be construed as exhaustive. 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"). Boe's 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. In accordance with AIM guidelines, Mr. Kerry Fulton, P. Eng and Vice President, Operations for Antrim, is the qualified person that has reviewed the technical information contained in this MD&A. Mr. Fulton has over 30 years operating experience in the upstream oil and gas industry. MANAGEMENT'S RESPONSIBILITY FOR FINANCIAL REPORTING The accompanying consolidated financial statements are the responsibility of management. The consolidated financial statements have been prepared by management in accordance with International Financial Reporting Standards outlined in the notes to the consolidated financial statements. The consolidated financial statements include certain estimates that reflect the management's best judgments. Management has determined such amounts on a reasonable basis in order to ensure that the consolidated financial statements are presented fairly, in all material respects. In the opinion of management, the consolidated financial statements have been prepared within acceptable limits of materiality and are in accordance with International Financial Reporting Standards. The financial information contained in the annual report is consistent with that in the consolidated financial statements. Management is also responsible for establishing and maintaining appropriate systems of internal control over the company's financial reporting. The internal control system was designed to provide reasonable assurance to management regarding the preparation and presentation of the consolidated financial statements. Management tested and evaluated the effectiveness of its disclosure controls and procedures and internal controls over financial reporting as at December 31, 2012. During this evaluation Management identified a weakness due to the limited number of finance and accounting personnel at the Corporation dealing with complex and non-routine accounting transactions that may arise. All internal control systems, no matter how well designed, have inherent limitations. Therefore, these systems provide reasonable but not absolute assurance that financial information is accurate and complete. PricewaterhouseCoopers LLP, an independent firm of Chartered Accountants, has been engaged, as approved by a vote of the shareholders at the Company's most recent annual general meeting, to examine the consolidated financial statements in accordance with Canadian generally accepted auditing standards and provide an independent professional opinion. The audit committee of the Board of Directors with all of its members being independent directors, have reviewed the consolidated financial statements including notes thereto, with management and PricewaterhouseCoopers LLP. The consolidated financial statements have been approved by the Board of Directors on the recommendation of the audit committee. Stephen Greer, President & Chief Executive Officer Anthony Potter, Chief Financial Officer To view the Independent Auditor's Report, please visit the following link: http://media3.marketwire.com/docs/auditor.pdf. Antrim Energy Inc. Consolidated Balance Sheets As at December 31, 2012 and 2011 (Amounts in US$ thousands) ---------------------------------------------------------------------------- December 31 December 31 Note 2012 2011 ------------------------ Assets Current assets Cash and cash equivalents 1,503 47,105 Restricted cash 5 808 17,249 Accounts receivable 332 5,294 Inventory and prepaid expenses 6 5,877 240 Assets held for sale 4 - 31,651 ------------------------ 8,520 101,539 Property, plant and equipment 7 81,069 15,207 Exploration and evaluation assets 8 6,931 122,431 ------------------------ 96,520 239,177 ------------------------ ------------------------ Liabilities Current liabilities Accounts payable and accrued liabilities 18,165 17,214 Deferred revenue 9 1,089 - Liabilities held for sale 4 - 4,180 ------------------------ 19,254 21,394 ------------------------ Decommissioning obligations 10 10,270 3,595 Contingent consideration 11 - 7,000 ------------------------ 29,524 31,989 ------------------------ Commitments and contingencies 21 Subsequent events 24 Shareholders' equity Share capital 12 361,922 361,587 Contributed surplus 20,626 19,579 Accumulated other comprehensive income (loss) 4,656 (5,971) Deficit (320,208) (168,007) ------------------------ 66,996 207,188 ------------------------ 96,520 239,177 ------------------------ ------------------------ The accompanying notes are an integral part of the consolidated financial statements. Approved on behalf of the Board of Directors of Antrim Energy Inc.: Gerry Orbell, Director James Smith, Director Antrim Energy Inc. Consolidated Statements of Comprehensive Loss For the years ended December 31, 2012 and 2011 (Amounts in US$ thousands, except per share data) ---------------------------------------------------------------------------- Note 2012 2011 ------------------------ Revenue 15 - - Expenses General and administrative expenses 16 5,843 5,004 Depreciation 7 94 191 Share-based compensation 13 998 883 Exploration and evaluation expenditures 7,640 273 Impairment 7, 8 122,698 49,101 Change in fair value of contingent consideration 11 (7,000) (1,000) Reduction in the fair value of financial assets 4 10,040 - Gain on disposal of Argentina assets 4 (5,894) - Loss on disposal - 70 ------------------------ 134,419 54,522 Financial items Finance income 17 (276) (706) Finance costs 18 213 586 Foreign exchange loss 503 708 ------------------------ Loss from continuing operations before income taxes 134,859 55,110 Income tax expense 20 - - ------------------------ Loss from continuing operations after income taxes 134,859 55,110 Income from discontinued operations 4 (315) (2,140) ------------------------ Net loss for the year 134,544 52,970 ------------------------ Other comprehensive (income) loss Foreign currency translation adjustment (7,414) 4,123 Foreign currency translation adjustment - disposal of assets 4 (3,213) (2,271) ------------------------ Other comprehensive (income) loss for the year (10,627) 1,852 ------------------------ Comprehensive loss for the year 123,917 54,822 ------------------------ ------------------------ Net loss (income) per common share Basic & diluted - continuing operations 14 0.73 0.32 Basic & diluted - discontinued operations 14 (0.00) (0.01) The accompanying notes are an integral part of the consolidated financial statements. Antrim Energy Inc. Consolidated Statements of Cash Flows For the years ended December 31, 2012 and 2011 (Amounts in US$ thousands) ---------------------------------------------------------------------------- Note 2012 2011 ------------------------ Operating Activities Loss from continuing operations after income taxes (134,859) (55,110) Items not involving cash: Depreciation 7 94 191 Share-based compensation 13 998 883 Accretion of decommissioning obligations 10 145 209 Foreign exchange loss 390 1,909 Impairment 7, 8 122,698 49,101 Change in the fair value of contingent consideration 11 (7,000) (1,000) Reduction in the fair value of financial assets 4 10,040 - Gain on disposal of Argentina assets 4 (5,894) - Loss on disposal - 70 Changes in non-cash working capital items - continuing operations 19 4,717 12,688 ------------------------ Cash (used in) provided by operating activities - continuing operations (8,671) 8,941 Cash used in operating activities - discontinued operations 4 (365) (1,204) ------------------------ Cash (used in) provided by operating activities (9,036) 7,737 ------------------------ Financing Activities Issue of common shares 12 186 52,431 Share issue expenses 12 - (2,998) ------------------------ Cash provided by financing activities 186 49,433 ------------------------ Investing Activities Capital expenditures (63,034) (14,702) Restricted cash 5 16,441 (17,249) Cash proceeds from the disposal of Argentina assets 4 9,976 - ------------------------ Cash used in investing activities - continuing operations (36,617) (31,951) Cash used in investing activities - discontinued operations 4 (1,121) (2,372) ------------------------ Cash used in investing activities (37,738) (34,323) ------------------------ Effect of foreign exchange on cash and cash equivalents 986 (1,392) Net (decrease) increase in cash and cash equivalents (45,602) 21,455 Cash and cash equivalents - beginning of year 47,105 25,650 ------------------------ Cash and cash equivalents - end of year 19 1,503 47,105 ------------------------ ------------------------ The accompanying notes are an integral part of the consolidated financial statements. Antrim Energy Inc. Consolidated Statements of Changes in Equity For the years ended December 31, 2012 and 2011 (Amounts in US$ thousands) ---------------------------------------------------------------------------- Share capital --------------------------- Number of Contributed Note common shares Amount surplus --------------------------------------- Balance, December 31, 2010 135,571,542 312,062 18,377 Net loss for the year - - - Other comprehensive loss - - - Issuance of common shares 12 48,191,700 52,297 - Share issuance costs 12 - (2,998) - Share-based compensation 13 - - 1,294 Stock options exercised 352,836 226 (92) --------------------------------------- Balance, December 31, 2011 184,116,078 361,587 19,579 --------------------------------------- --------------------------------------- Balance, December 31, 2011 184,116,078 361,587 19,579 Net loss for the year - - - Capital distribution 4 - - - Other comprehensive income - - - Share-based compensation 13 - - 1,196 Stock options exercised 614,998 335 (149) --------------------------------------- Balance, December 31, 2012 184,731,076 361,922 20,626 --------------------------------------- --------------------------------------- Antrim Energy Inc. Consolidated Statements of Changes in Equity For the years ended December 31, 2012 and 2011 (Amounts in US$ thousands) ----------------------------------------------------------------------- Accumulated other comprehensive income (loss) Deficit Total --------------------------------------- Balance, December 31, 2010 (4,119) (115,037) 211,283 Net loss for the year - (52,970) (52,970) Other comprehensive loss (1,852) - (1,852) Issuance of common shares - - 52,297 Share issuance costs - - (2,998) Share-based compensation - - 1,294 Stock options exercised - - 134 --------------------------------------- Balance, December 31, 2011 (5,971) (168,007) 207,188 --------------------------------------- --------------------------------------- Balance, December 31, 2011 (5,971) (168,007) 207,188 Net loss for the year - (134,544) (134,544) Capital distribution - (17,657) (17,657) Other comprehensive income 10,627 - 10,627 Share-based compensation - - 1,196 Stock options exercised - - 186 --------------------------------------- Balance, December 31, 2012 4,656 (320,208) 66,996 --------------------------------------- --------------------------------------- The accompanying notes are an integral part of the consolidated financial statements. Notes to Consolidated Financial Statements For the years ended December 31, 2012 and 2011 (Amounts in US$ thousands, except as otherwise noted) 1) Nature of Operations Antrim Energy Inc. ("Antrim" or the "Company") is a Calgary based oil and natural gas company. Through subsidiaries, the Company conducts exploration activities in the United Kingdom and Ireland. Antrim Energy Inc. is incorporated and domiciled in Canada. The Company's common shares are listed on the Toronto Stock Exchange ("TSX") and the London Alternative Investment Market ("AIM") under the symbols "AEN" and "AEY", respectively. The address of its registered office is 1600, 333 - 7th Avenue S.W, Calgary, Alberta, Canada. 2) Basis of Presentation a) Statement of compliance The consolidated financial statements have been prepared in accordance with International Financial Reporting Standards ("IFRS") as issued by the International Accounting Standards Board ("IASB"). The policies applied in these consolidated financial statements are based on IFRS issued and outstanding as at March 26, 2013, the date the Board of Directors approved the year ended consolidated financial statements. The consolidated financial statements have been prepared on the historical cost basis, except as explained in Note 3, Summary of Significant Accounting Policies. The accounting policies described in Note 3 have been applied consistently to all periods presented in these financial statements. Historical cost is generally based on the fair value of the consideration given in exchange for the assets. b) Presentation currency In these consolidated financial statements, unless otherwise indicated, all dollar amounts are expressed in United States ("US") dollars. Antrim's functional currency is Canadian dollars; however, the Company has adopted the US dollar as its presentation currency to facilitate a more direct comparison to North American oil and gas companies with international operations. c) Critical accounting judgments and key sources of estimation uncertainty In the application of the Company's accounting policies, management is required to make judgments, estimates and assumptions about carrying values of assets and liabilities that are not readily apparent from other sources. The estimates and underlying assumptions are reviewed on an ongoing basis. The estimates and associated assumptions are based on historical experience and other factors, including expectations of future events that are believed to be reasonable under the circumstances. Actual results may differ from these estimates. The following are the critical judgments and estimates that management has made in the process of applying the Company's accounting policies and that have the most significant effect on the amounts recognized in the financial statements: Estimation of reserve quantities Depletion, impairment and decommissioning charges are dependent on the Company's estimate of oil and gas reserves. The estimation of reserves is an inherently complex process and involves the exercise of professional judgment. Reserves have been evaluated at the balance sheet date by an independent qualified reserve evaluator in accordance with National Instrument 51-101 Standards of Disclosure for Oil and Gas Activities and are based on the definitions and guidelines contained in the Canadian Oil and Gas Evaluation Handbook. Oil and gas reserve estimates are based on a range of geological, technical and economic factors including projected future rates of production, estimated commodity prices, engineering data, reserve type and timing and amount of future expenditures, all of which are subject to uncertainty. Assumptions reflect market and regulatory conditions existing at the balance sheet date, which could differ significantly from other points in time throughout the year, or future periods. Changes in market and regulatory conditions and assumptions can materially impact the estimation of net reserves. Recoverability of exploration and evaluation costs Exploration and evaluation costs are initially capitalized with the intent to establish commercially viable reserves. The Company is required to make estimates and judgments about future events and circumstances regarding the economic viability of extracting the underlying resources. The costs are subject to technical, commercial and management review to confirm the continued intent to develop and extract the underlying resources. Fluctuations in future commodity prices, resource quantities, expected production techniques, drilling results, production costs and required capital expenditures are important factors when making this determination. If a judgment is made that extraction of the reserves is not viable, the exploration and evaluation costs will be written off to net earnings. Decommissioning obligations The Company recognizes liabilities for the future decommissioning and restoration of property, plant and equipment. These provisions are based on estimated costs, which take into account the anticipated method and extent of restoration consistent with legal requirements, technological advances and the possible use of the site. Actual costs are uncertain and estimates can vary as a result of changes to relevant laws and regulations, the emergence of new technology, operating experience and prices. The actual timing of future decommissioning and restoration is not known and may change due to certain factors, including reserve life. Changes to assumptions made about future expected costs, discount rates, inflation and timing may have a material impact on the amounts presented. The Company has chosen to measure decommissioning obligations using a risk-free discount rate. Impairment of property, plant and equipment The recoverable amounts of cash-generating units ("CGUs") and individual assets have been determined based on greater of value-in-use or fair value less costs to sell calculations. The key assumptions the Company uses in estimating future cash flows for purposes of calculating value-in use or fair value less costs to sell are future oil prices, expected production volumes, future development costs, operating costs and the discount rate applied to reflect the time value of money. Changes to these assumptions will affect the recoverable amounts of cash-generating units and individual assets and may then require a material adjustment to their related carrying value. The determination of CGUs requires judgement in defining a group of assets that generate cash inflows that are largely independent of the cash inflows from other assets or groups of assets. CGUs are determined by similar geological structure, shared infrastructure, geographical proximity, commodity type, similar exposure to market risks and materiality. Fair value of share-based compensation The fair value of share-based compensation is calculated using a Black-Scholes option-pricing model. There are a number of estimates used in the calculation such as future forfeiture rate, expected option life and the future price volatility of the underlying security which can vary from actual future events. The factors applied in the calculation are management's best estimates based on historical information and future forecasts. Fair value of contingent consideration When consideration transferred relating to an acquisition includes consideration contingent on future events, the Company is required to estimate the fair value of the contingent consideration and records a contingent consideration liability. The fair value of such consideration is based on assumptions and judgements regarding the likelihood of future events. Deferred income taxes Deferred tax assets are recognized when it is considered probable that deductible temporary differences will be recovered in the foreseeable future. To the extent that future taxable income and the application of existing tax laws in each jurisdiction differ significantly from the Company's estimate, the ability of the Company to realize the deferred tax assets could be impacted. 3) Summary of Significant Accounting Policies The following significant accounting policies have been adopted in the preparation and presentation of the consolidated financial statements: a) Basis of consolidation These consolidated financial statements incorporate the financial statements of the Company and entities controlled by the Company. Control is achieved where the Company has the power to govern the financial and operating policies of the entity so as to obtain benefits from its activities. The financial statements of subsidiaries are included in the consolidated financial statements from the date that control commences until the date that control ceases. All intra-company transactions, balances, income and expenses are eliminated on consolidation. b) Foreign currency translation In preparing the financial statements of the Company's subsidiaries, transactions in currencies other than the entity's functional currency are recorded at the rates of exchange prevailing on the date of the transaction. Monetary assets and liabilities denominated in foreign currencies are translated to the appropriate functional currency at foreign exchange rates at the balance sheet date. Foreign exchange differences arising on translation are recognized in earnings. Non-monetary assets that are measured at historical cost in a foreign currency are translated using the exchange rate at the date of the transactions. In preparing the Company's consolidated financial statements, the financial statements of each entity are first translated into Canadian dollars, the functional currency of the Company. The consolidated financial statements of the Company are then translated into U.S. dollars, the Company's presentation currency. The assets and liabilities of foreign operations are translated into Canadian dollars at exchange rates at the balance sheet date. Revenues and expenses of foreign operations are translated into Canadian dollars using foreign exchange rates that approximate those on the date of the underlying transaction. Foreign exchange differences are recognized in other comprehensive income and reclassified to net earnings upon disposal of the foreign operation. c) Jointly controlled operations and jointly controlled assets A significant portion of the Company's operations are conducted with others and involve jointly controlled assets. The consolidated financial statements reflect only the Company's interest in such activities and assets. d) Oil and natural gas exploration and evaluation expenditures Pre-licence costs Costs incurred prior to obtaining the legal right to explore for hydrocarbon resources are expensed in the period in which they are incurred. Exploration and evaluation costs Exploration and evaluation assets are stated at cost, less accumulated impairment losses. Once the legal right to explore has been acquired, costs directly associated with an exploration well are capitalized as exploration and evaluation assets until the drilling of the well is complete and the results have been evaluated. These costs include licence costs, geological and geophysical costs, employee remuneration, materials and fuel used, rig costs and payments made to contractors. If no reserves are found, the exploration asset is tested for impairment. If extractable hydrocarbons are found and, subject to further appraisal activity (e.g. by drilling further wells), are likely to be developed commercially, the costs continue to be carried as exploration and evaluation assets while sufficient and continued progress is made in assessing the commerciality of the hydrocarbons. All such costs are subject to technical, commercial and management review as well as review for impairment indicators at each period end to confirm the continued intent to develop or otherwise extract value from the discovery. When this is no longer the case, the costs are written off. When proved and probable reserves of oil are determined and development is sanctioned, the relevant expenditure is transferred to oil and gas properties after impairment is assessed and any resulting impairment loss is recognized. e) Property, plant and equipment Property, plant and equipment are stated at cost, less accumulated depreciation and accumulated impairment losses. The initial cost of an asset comprises its purchase price or construction cost, any costs directly attributable to bringing the asset into operation, the initial estimate of the decommissioning obligations and borrowing costs for qualifying assets. Expenditures on the construction, installation or completion of infrastructure facilities such as platforms, pipelines and the drilling and completion of development wells, including unsuccessful development or delineation wells, is capitalized within property, plant and equipment. The purchase price or construction cost is the aggregate amount paid and the fair value of any other consideration given to acquire the asset. The capitalized value of a finance lease is also included within property, plant and equipment. Depletion and depreciation Oil and gas assets within property, plant and equipment are depleted on a unit-of-production basis over the proved and probable reserves of the field concerned. The unit-of-production rate for the amortization of field development costs takes into account expenditures incurred to date, together with sanctioned future development expenditure. Other property, plant and equipment are generally depreciated on a straight-line basis over its estimated useful lives, as follows: Office equipment 5 years Computer hardware and software 3 years f) Impairment of non-financial assets The Company assesses at each reporting date whether there is an indication that an asset may be impaired. If any indication exists the Company estimates the asset's recoverable amount. An asset's recoverable amount is the higher of an asset's or CGU's fair value less costs to sell and its value-in-use and is determined for an individual asset, unless the asset does not generate cash inflows that are largely independent of those from other assets or groups of assets. If the carrying amount of an asset or CGU exceeds its recoverable amount, the asset or CGU is considered impaired and is written down to its recoverable amount. In assessing value-in-use, the estimated future cash flows are discounted to their present value using a pre-tax discount rate that reflects current market assessments of the time value of money and the risks specific to the asset. In determining fair value less costs to sell, recent market transactions are taken into account, if available. If no such transactions can be identified, an appropriate valuation model is used. These calculations are corroborated by valuation multiples or other available fair value indicators. Impairment losses are recognized in the consolidated statement of loss and comprehensive loss. An assessment is made at each reporting date as to whether there is any indication that previously recognized impairment losses may no longer exist or may have decreased. If such indication exists, the Company estimates the asset's or cash-generating unit's recoverable amount. A previously recognized impairment loss is reversed only if there has been a change in the assumptions used to determine the asset's recoverable amount since the last impairment loss was recognized. The reversal is limited so that the carrying amount of the asset does not exceed its recoverable amount, nor exceed the carrying amount that would have been determined, net of depreciation, had no impairment loss been recognized for the asset in prior years. g) Financial assets Financial assets are measured at fair value on the balance sheet upon initial recognition of the instrument. Subsequent measurement and changes in fair value will depend on initial classification, as follows: i. fair value through profit or loss financial assets and liabilities, classified as held for trading or designated as fair value through profit or loss, are measured at fair value and subsequent changes in fair value are recognized in income; ii. loans and receivables are non-derivative financial assets with fixed or determinable payments that are not quoted in an active market; iii.available-for-sale financial instruments are measured at fair value with changes in fair value recorded in equity until the instrument or a portion thereof is derecognized or impaired at which time the amounts would be recognized in income; and iv. held to maturity financial assets and loans and receivables are initially measured at fair value with subsequent measurement at amortized cost using the effective interest rate method. The effective interest rate method calculates the amortized cost of a financial asset and allocates interest income or expense over the applicable period. The rate used discounts the estimated future cash flows over either the expected life of the financial asset or liability or a shorter time- frame if it's deemed appropriate. Antrim's current classifications are as follows: i. cash and cash equivalents are designated as loans and receivables, ii. restricted cash is designated as loans and receivables; and iii.accounts receivable are designated as loans and receivables. h) Financial liabilities Financial liabilities within the scope of IAS 39 Financial Instruments: Recognition and Measurement ("IAS 39") are classified as financial liabilities at fair value through profit or loss or as other financial liabilities at amortized cost, as appropriate. The Company determines the classification of its financial liabilities at initial recognition. All financial liabilities are recognized initially at fair value and in the case of loans and borrowings, plus directly attributable transaction costs. The Company's financial liabilities include accounts payables and contingent consideration. Derecognition A financial liability is derecognized when the obligation under the liability is discharged, cancelled or expires. i) Cash and cash equivalents Cash and cash equivalents include cash on hand, deposits held with banks, and other short-term highly liquid investments with original maturities of three months or less. j) Inventories Inventories are stated at the lower of cost and net realizable value. The cost of crude oil is the cost to produce, including the appropriate proportion of depletion and depreciation and overheads, including all costs incurred in the normal course of business in bringing each product to its present location and condition, and is accounted on a weighted average basis. Net realizable value of crude oil and refined products is based on estimated selling price in the ordinary course of business less any expected selling costs. k) Assets held for sale Non-current assets, or disposal groups consisting of assets and liabilities, are classified as held for sale if their carrying amounts will be recovered through a sale transaction rather than through continuing use. This condition is met when the sale is highly probably and the asset is available for immediate sale in its present condition. Non-current assets classified as held for sale are measured at the lower of the carrying amount and fair value less costs to sell, with impairments recognized in net earnings in the period measured. Non-current assets and disposal groups held for sale are presented in current assets and liabilities within the consolidated balance sheet. Assets held for sale are not depreciated, depleted or amortized. l) Provisions General Provisions are recognized when the Company has a present obligation (legal or constructive) as a result of a past event, it is probable that an outflow of resources embodying economic benefits will be required to settle the obligation and a reliable estimate can be made of the amount of the obligation. Where the Company expects some or all of a provision to be reimbursed, for example, under an insurance contract, the reimbursement is recognized as a separate asset but only when the reimbursement is virtually certain. The expense relating to any provision is presented in the income statement net of any reimbursement. If the effect of the time value of money is material, provisions are discounted using a current pre-tax rate that reflects, where appropriate, the risks specific to the liability. Where discounting is used, the increase in the provision due to the passage of time is recognized as a finance cost. Decommissioning obligations Decommissioning obligations are recognized when the Company has a present legal or constructive obligation as a result of past events, it is probable that an outflow of resources will be required to settle the obligation and a reliable estimate of the amount of obligation can be made. A corresponding amount equivalent to the provision is also recognized as part of the cost of the relevant asset category to which they relate. The amount recognized is the estimated cost of decommissioning, discounted to its present value using a risk-free interest rate. Changes in the estimated timing or cost of decommissioning are dealt with prospectively by recording an adjustment to the provision, and a corresponding adjustment to the relevant asset category. The unwinding of the discount on the decommissioning obligations is included as a finance cost. m) Taxes Current income tax Current income tax assets and liabilities are measured at the amount expected to be recovered from or paid to the taxation authorities. The tax rates and tax laws used to compute the amount are those that are enacted or substantively enacted, by the reporting date, in the countries where the Company operates and generates taxable income. Current income tax relating to items recognized directly in equity is recognized in equity and not in the income statement. Management periodically evaluates positions taken in the tax returns with respect to situations in which applicable tax regulations are subject to interpretation and establishes provisions where appropriate. Deferred tax The Company follows the liability method of accounting for income taxes. Under this method, income tax assets and liabilities are recognized for the estimated tax consequences attributable to differences between the amounts reported in the financial statements and their respective tax bases, using enacted or substantially enacted tax rates expected to apply when the asset is realized or the liability settled. Deferred tax assets are only recognized to the extent it is more likely than not that sufficient future taxable income will be available to allow the future income tax asset to be realized. n) Revenue recognition Revenue is recognized when it is probable that the economic benefits associated with a transaction will flow to the Company and the amount of the revenue can be measured reliably and collectability is reasonably assured. In particular, revenue from the production and sale of crude oil is recognized when the title has been transferred to customers, which is when risk and rewards pass to the customer. This occurs when product is physically transferred into a shipping vessel. Deferred revenue is recognized when cash is received and no crude oil has been lifted from the terminal therefore title and risk has not been transferred to the buyer. For all financial instruments measured at amortized cost and interest bearing financial assets classified as available-for-sale, interest income or expense is recorded using the effective interest rate, which is the rate that exactly discounts the estimated future cash payments or receipts through the expected life of the financial instrument or a shorter period, where appropriate, to the net carrying amount of the financial asset or liability. Interest income is included in finance income in the income statement. o) Share-based compensation Equity-settled share-based compensation to directors, employees and others providing similar services are measured at the fair value of the equity instruments at the grant date. The fair value determined at the grant date of the equity-settled share-based compensation is expensed on a graded basis over the vesting period, based on the Company's estimate of equity instruments that will eventually vest. At the end of each reporting period, the Company revises its estimate of the number of equity instruments expected to vest. The impact of the revision of the original estimates, if any, is recognized in profit or loss such that the cumulative expense reflects the revised estimate, with a corresponding adjustment to contributed surplus. p) Earnings (loss) per share Basic earnings (loss) per share is computed by dividing the net earnings (loss) available to common shareholders by the weighted average number of shares outstanding during the reporting year. Diluted earnings (loss) per share is computed in a similar way to basic earnings (loss) per share except that the weighted average shares outstanding are increased to include additional shares for the assumed exercise of stock options and warrants, if dilutive. The number of additional shares is calculated by assuming that outstanding stock options were exercised and that the proceeds from such exercises were used to acquire common stock at the average market price during the reporting periods. q) Share capital Common shares are classified as equity. Incremental costs directly attributable to the issuance of shares are recognized as a deduction from equity. r) Standards issued but not yet effective The following pronouncements and amendments are effective for annual periods beginning on or after January 1, 2013 unless otherwise stated. Adopting these standards is expected to have minimal or no impact on the consolidated financial statements. IFRS 10 - Consolidation replaces SIC-12 Consolidation - Special Purpose Entities and parts of IAS 27 Consolidated and Separate Financial Statements and requires an entity to consolidate an investee when it is exposed, or has rights, to variable returns from its involvement with the investee and has the ability to affect those returns through its power over the investee. IFRS 11 - Joint Arrangements requires a venturer to classify its interest in a joint arrangement as a joint venture or joint operation. Joint ventures will be accounted for using the equity method of accounting whereas joint operations, the venturer will recognize its share of the assets, liabilities, revenue and expenses of the joint operation. IFRS 11 supersedes IAS 31 Interests in Joint Ventures, and SIC-13 Jointly Controlled Entities - Non-monetary Contributions by Venturers. IFRS 12 - Disclosure of Interest in Other Entities establishes disclosure requirements for interests in other entities, such as joint arrangements, associates, and special purpose vehicles and off balance sheet vehicles. The standard carries forward existing disclosures and also introduces additional disclosures addressing the nature of, and risks associated with, an entity's interests in other entities. IFRS 13 - Fair Value Measurement is a comprehensive standard that defines fair value, requires disclosure about fair value measurement and provides a framework for measuring fair value when it is required or permitted within the IFRS standards. IAS 27 - Separate Financial Statement addresses accounting for subsidiaries, jointly controlled entities and associates in non-consolidated financial statements. IAS 28 - Investments in Associates and Joint Ventures has been amended to include joint ventures in its scope and to address the changes in IFRS 10 - 13. IAS 1 - Presentation of Financial Statements amendment requires components of other comprehensive income to be separately presented between those that may be reclassified to income and those that will not. The amendments are effective for annual periods beginning on or after July 1, 2012. IAS 32 - Financial Instruments: Presentation amendment provides clarification on the application of offsetting rules. The amendments are effective for annual periods beginning on or after January 1, 2014. 4) Discontinued operations The Company entered into an agreement on March 23, 2012 to sell all of its interest in its wholly owned subsidiary Antrim Argentina S.A. to Crown Point Energy Inc. ("Crown Point") (formerly known as Crown Point Ventures Ltd.) by way of a plan of arrangement (the "Arrangement"). The consideration consisted of Cdn $10,262 in cash (subject to certain adjustments) and 35,761,290 common shares of Crown Point ("Crown Point Shares"). Pursuant to the Arrangement, Antrim would distribute the Crown Point Shares to its shareholders. On May 28, 2012, Antrim completed the sale of Antrim Argentina S.A. to Crown Point. Under the terms of the Arrangement, the Company received a cash payment of $9,976 (Cdn $10,262) and 35,761,290 Crown Point Shares. The actual cash payment received was netted against adjustments of $1,015 (Cdn $1,016) which have been recognized as sale transaction costs. These sale transaction costs, along with costs of $1,886 incurred by the Company, have been offset against income from discontinued operations. Details of the disposition are as follows: 2012 -------- Consideration received: Cash 9,976 Crown Point Shares (based on a May 28, 2012 share price of Cdn $0.80) 27,811 -------- 37,787 Carrying value of assets and liabilities disposed: Working capital 9,388 Property, plant and equipment 19,886 Exploration and evaluation assets 719 Other non-current assets 1,189 Decommissioning obligations (2,502) -------- Total carrying value of assets and liabilities disposed 28,680 -------- Gain on disposal excluding foreign currency translation adjustment 9,107 Foreign currency translation adjustment relating to disposal (3,213) -------- Gain on disposal after foreign currency translation adjustment 5,894 -------- -------- Antrim distributed the Crown Point Shares to its shareholders on June 7, 2012 (the "Distribution Date"). On the Distribution Date, Crown Point's closing share price on the TSX Venture Exchange was Cdn $0.51 which had decreased from the May 28, 2012 closing share price of Cdn $0.80. This reduction in Crown Point's share price resulted in the Company recognizing a capital loss on the Crown Point Shares of $10,040. This amount has been recognized on the consolidated statement of comprehensive loss as a reduction in the fair value of financial assets. A capital distribution of $17,657 has been recorded in deficit on the statement of changes in equity. The combined results of the discontinued operations have been included in the consolidated statement of comprehensive loss. The comparative period income and cash flows from discontinued operations have been reclassified to include those operations classified as discontinued in the current year. The year ended December 31, 2012 discontinued financial and operating results include only those results up to May 28, 2012 (the date of sale of the Argentina operations). December 31 December 31 2012 2011 ------------------------------ Discontinued operations Revenue, net of royalties 4,764 10,197 Direct production and operating expenditures (1,906) (4,710) Depletion and depreciation (147) (4,004) General and administrative expenses (768) (1,292) Sale transaction costs (1,886) - Exploration and evaluation expenditures (26) (45) Other income 935 2,183 Export taxes (88) (247) Write down of non-current assets (568) - Finance income 88 311 Finance costs (130) (272) Foreign exchange gain 47 19 ------------------------------ Income from discontinued operations 315 2,140 ------------------------------ ------------------------------ December 31 December 31 2012 2011 ------------------------------ Cash flow from discontinued operations Net cash flow used in operating activities (365) (1,204) Net cash flow used in investing activities (1,121) (2,372) ------------------------------ Net cash flow used in discontinued operations (1,486) (3,576) ------------------------------ ------------------------------ 5) Restricted cash December 31 December 31 2012 2011 ------------------------------ Restricted cash 808 17,249 ------------------------------ 808 17,249 ------------------------------ ------------------------------ Restricted cash of $808 at December 31, 2012 relates to a British pounds sterling standby letter of credit issued to the Sullom Voe Terminal as part of the operations of Causeway. Restricted cash of $17,249 at December 31, 2011 relates to US dollar and British pounds sterling standby letters of credit issued with respect to the Company's drilling program in the UK North Sea. 6) Inventory and prepaid expenses December 31 December 31 2012 2011 ------------------------------ Crude oil inventory 4,498 - Prepaids 1,379 240 ------------------------------ 5,877 240 ------------------------------ ------------------------------ Inventory with a carrying amount of $4,498 (2011 - nil) represents linefill and oil stocks available for sale as at December 31, 2012. Included within this balance is depletion of $3,372. 7) Property, plant and equipment December 31 December 31 2012 2011 ------------------------------ Opening balance 15,207 26,129 Additions 58,250 2,161 Depletion and depreciation (3,466) (191) Depletion and depreciation relating to assets held for sale - (4,004) Changes in decommissioning estimate 158 370 Impairment - (3,184) Transferred from exploration and evaluation assets 9,347 15,005 Reclassified to assets held for sale - (19,536) Foreign currency translation 1,573 (1,543) ------------------------------ Ending balance 81,069 15,207 ------------------------------ ------------------------------ In November 2012, the Field Development Plan ("FDP") for the Cormorant East Field was approved by the Department of Energy and Climate Change ("DECC"). As a result, $9,347 of accumulated exploration and evaluation costs were transferred to property, plant and equipment. During the year, the Company capitalized $152 (2011 - $23) of general and administrative and $61 (2011 - $20) of share-based compensation related to development activity. At December 31, 2012, the Company assessed the carrying amount of its property, plant and equipment assets for indicators of impairment such as changes in reserves and lower production rates. Impairment tests were completed using an after-tax discount rate of 10 percent. The following table outlines benchmark prices at December 31, 2012 used in the impairment test: Brent crude oil Exchange rate Exchange rate (US$/barrel) (US$/C$) (US$/GBPGBP ) --------------------------------------------- 2013 107.50 1.00 1.60 2014 102.50 1.00 1.60 2015 101.40 1.00 1.60 2016 100.80 1.00 1.60 2017 100.10 1.00 1.60 Thereafter +2.0% 1.00 1.60 --------------------------------------------- No impairment existed at December 31, 2012 relating to the capitalized costs of property, plant and equipment assets. 8) Exploration and evaluation assets December 31 December 31 2012 2011 ------------------------------ Opening balance 122,431 171,850 Additions 9,219 38,494 Changes in decommissioning estimate(1) 1,850 (288) Disposals - (22,035) Impairment (122,698) (45,917) Transferred to property, plant and equipment (9,347) (15,005) Reclassified to assets held for sale - (608) Foreign currency translation 5,476 (4,060) ------------------------------ Ending balance 6,931 122,431 ------------------------------ ------------------------------ (1) Changes in decommissioning obligation estimate are offset by decommissioning obligation dispositions of $1,362 During the year, the Company capitalized $425 (2011 - $558) of general and administrative costs and $137 (2011 - $391) of share-based compensation related to exploration and evaluation activity. In January 2013, the Company elected not to participate in further development work on the Fionn Field. As a result, an impairment charge of $50,358 in 2012 was recognized, representing the full carrying value relating to the Fionn Field CGU. Antrim retains a 35.5% interest in the remainder of Licence P201 Block 211/22a South East Area. Licence P1625 Block 21/24b ("West Teal") is nearing the end of its initial exploration term and based on an evaluation performed by management the licence is not considered economically viable to continue with. As a result the Company recognized an impairment charge of $1,841 million in 2012, relating to the full carrying value of this licence. In December 2012, the Company announced that the Cyclone exploration well in UK Block 21/7b was plugged and abandoned. As a result, an impairment charge of $5,939 was recognized in 2012 representing the full carrying value relating to this licence. In October 2012, DECC agreed to waive the seismic and contingent well obligations on Licence P1563 Blocks 21/28b & 21/29c ("Carra") which allowed the Company to relinquish the licence in its entirety. The Company recognized an impairment charge of $2,304 in 2012 representing the full carrying value of this licence. As at March 31, 2012, in accordance with IFRS, management performed an impairment assessment on the carrying value of the Fyne Licence CGU as there were indications that the recoverable value may be impaired. The facts and circumstances considered included the abandonment of the East Fyne appraisal well, the expectation that the gross Fyne Field reserves would likely decline by approximately 36%, the withdrawal of Premier Oil UK Limited ("Premier") and First Oil Expro Limited ("First Oil") from the Joint Operating Agreement ("JOA"), the risk that Antrim may not obtain approval of an FDP from DECC, the risk of Antrim not finding partners and the challenge in securing funding for the project in a difficult market. In light of these events management determined that the carrying value of the Fyne Licence CGU was impaired. The carrying value of the Fyne Licence was written down to a $nil value with the Company incurring a $60,112 impairment charge in the first quarter of 2012. Costs incurred subsequent to March 31, 2012 of $7,343 relating to this licence have been expensed as exploration and evaluation expenditures on the statement of comprehensive loss. The Company recognized an impairment charge in 2012 of $2,144 relating to the Erne discovery well 21/29d-11 and the sidetrack well 21/29d-11Z. Post-well analysis of these two wells by the Company's independent reserve evaluation engineers did not result in any reserves being assigned at this time. The impairment charge is in addition to an impairment charge of $10,312 recognized in the fourth quarter of 2011. With the sale of the Company's subsidiary Antrim Causeway (N.I.) Limited ("Antrim Causeway") to Valiant Petroleum plc ("Valiant") in October 2011, an impairment charge of $35,605 to exploration and evaluation assets was recognized in 2011. 9) Deferred revenue December 31 December 31 2012 2011 ------------------------------ Deferred revenue 1,089 - ------------------------------ ------------------------------ Deferred revenue of $1,089 (2011 - $nil) relates to oil sales which have been invoiced during the year but have not been lifted from the terminal therefore title and risk has not been transferred to the buyer (see Note 15). 10) Decommissioning obligations December 31 December 31 2012 2011 ------------------------------ Opening balance 3,595 7,380 Additions 4,259 579 Accretion 145 209 Accretion relating to asset held for sale - 30 Change in estimate 3,370 82 Dispositions (1,362) (1,561) Reclassified to liabilities held for sale - (2,529) Foreign currency translation 263 (595) ------------------------------ Ending balance 10,270 3,595 ------------------------------ ------------------------------ At December 31, 2012, the estimated undiscounted decommissioning obligations are $11,218 (2011 - $5,794). The Company expects the undiscounted obligations to be payable between 2016 and 2020. In January 2013, the Company elected not to participate in further development work on the Fionn Field. As a result of Antrim's withdrawal of its 35.5% working interest, $1,362 of abandonment liability was disposed of. The change in estimate in 2012 is primarily related to increased costs estimates for the reclamation of suspended wells, changes in working interest and revision to the timing of future decommissioning obligation cash flows. The present value of the decommissioning obligations has been calculated using a risk-free interest rate of 1.6% (2011 - 3.8%) and an inflation rate of 2.0% (2011 - 2.0%). 11) Contingent consideration December 31 December 31 2012 2011 ------------------------------ Opening balance 7,000 8,000 Revision to estimate (7,000) (1,000) ------------------------------ Ending balance - 7,000 ------------------------------ ------------------------------ Contingent consideration of $10,000 on the acquisition of the Fyne Field is payable to the seller upon approval of an FDP by DECC. As at March 31, 2012, a fair value of $nil for the contingent consideration was determined based on the impairment assessment performed with respect to the Fyne Licence (See Note 8). 12) Share capital Authorized Unlimited number of common voting shares Common shares issued Number of Amount Shares $ ------------------------------ Balance, December 31, 2010 135,571,542 312,062 Issuance of common shares 48,191,700 52,297 Exercise of stock options 352,836 134 Transfer from contributed surplus - 92 Share issuance costs - (2,998) ------------------------------ Balance, December 31, 2011 184,116,078 361,587 Exercise of stock options 614,998 186 Transfer from contributed surplus - 149 ------------------------------ Balance, December 31, 2012 184,731,076 361,922 ------------------------------ ------------------------------ 13) Share-based compensation The Company has a program whereby it may grant options to its directors, officers and employees to purchase up to 10% of the issued and outstanding number of common shares. The exercise price of each option is no less than the market price of the Company's stock on the date of grant. Stock option terms are determined by the Company's Board of Directors but options typically vest evenly over a period of three years from the date of grant and expire five years after the date of grant. Share-based compensation for the year was $1,196 (2011 - $1,294) of which $998 (2011 - $883) was expensed and $198 (2011 - $411) was capitalized. The following table illustrates the number and weighted average exercise prices of and movements in share options under the option program during the year. 2012 2011 -------------------------------------------------- Weighted Weighted average average exercise exercise price price # of Options Cdn $ # of Options Cdn $ -------------------------------------------------- Outstanding at January 1 9,168,063 2.12 13,247,898 2.20 Granted 6,985,000 0.60 - - Forfeited/expired (3,188,000) 3.45 (3,726,999) 2.59 Exercised (614,998) 0.30 (352,836) 0.37 -------------------------------------------------- Outstanding at December 31 12,350,065 0.98 9,168,063 2.12 -------------------------------------------------- -------------------------------------------------- Exercisable at December 31 4,581,742 1.56 6,858,083 2.49 -------------------------------------------------- -------------------------------------------------- The weighted average share price on the exercise date for share options exercised in 2012 was $0.77 (2011 - $1.19). The range of exercise prices of the outstanding options is as follows: Options outstanding ---------------------------------------------------------------------------- Weighted- Weighted- Number average Range average outstanding years of exercise exercise at remaining prices price December contractual Cdn $ Cdn $ 31, 2012 life ---------------------------------------------------------------------------- 0.27 - 1.00 0.55 8,485,065 3.91 1.01 - 2.00 1.02 2,340,000 2.72 2.01 - 3.00 2.49 600,000 0.60 3.01 - 3.92 3.87 925,000 0.37 -------------------- 12,350,065 -------------------- -------------------- Options Options exercisable outstanding ---------------------------------------------------------------------------- Weighted- Weighted- Number average Range average outstanding years of exercise exercise at remaining prices price December contractual Cdn $ Cdn $ 31, 2012 life ---------------------------------------------------------------------------- 0.27 - 1.00 0.31 1,470,066 1.08 1.01 - 2.00 1.02 1,586,676 2.71 2.01 - 3.00 2.49 600,000 0.60 3.01 - 3.92 3.87 925,000 0.37 -------------------- 4,581,742 -------------------- -------------------- The fair values of options granted during the year were calculated using a Black Scholes valuation model. The principal inputs to the option valuation model were: 2012 2011 -------------------- Weighted average share price 0.60 - Weighted average exercise price 0.60 - Weighted average expected volatility 80.54% - Option life 4.5 years - Dividend yield Nil - Weighted average risk-free interest rate 1.19% - Forfeiture rate 10% - Expected volatility was determined by calculating the historical volatility of the Company's share price over a period commensurate with the expected lifetime of the options. On July 26, 2012, as a result of the completion of the Arrangement for the sale of Antrim Argentina S.A. and in accordance with the terms of the Company's stock option plan, the Company received all necessary approvals to make a four cent reduction to the exercise price of the Antrim options outstanding at the time of the Arrangement, so that Antrim option plan participants were neither favoured nor penalized by the impact of the reduction of stated capital of Antrim's common shares. The modification of the exercise price resulted in an increase of $51 on the fair value of the stock options outstanding. This incremental fair value has been recognized in share-based compensation. 14) Earnings per share 2012 2011 ------------------------------ Loss used in the calculation from continuing operations 134,859 55,110 Income used in the calculation from discontinued operations (315) (2,140) ------------------------------ Net loss for the year 134,544 52,970 ------------------------------ ------------------------------ Basic earnings per share was calculated as follows: 2012 2011 ------------------------------ Weighted average number of common shares: Issued common shares 184,116,078 135,571,542 Effects of share options exercised 272,074 268,446 Effects of shares issued - 38,157,264 ------------------------------ Weighted average number of common shares - basic 184,388,152 173,997,252 ------------------------------ ------------------------------ Diluted earnings per share was calculated as follows: 2012 2011 ------------------------------ Weighted average number of common shares: Weighted average number of common shares - basic 184,388,152 173,997,252 Effect of outstanding options 1,140,005 1,415,216 ------------------------------ Weighted average number of common shares - diluted 185,528,157 175,412,468 ------------------------------ ------------------------------ There have been no other transactions involving ordinary shares or potential ordinary shares between the reporting date and the date of completion of these financial statements. 2012 2011 -------------------- Basic and diluted loss (earnings) per common share From continuing operations 0.73 0.32 From discontinued operations (0.00) (0.01) -------------------- Total basic and diluted loss per share 0.73 0.31 -------------------- -------------------- For the years ended December 31, 2012 and 2011, all stock options were anti-dilutive and were not included in the diluted common share calculation. 15) Revenue 2012 2011 -------------------- Sales invoiced 1,089 - Deferred revenue at the end of the year (1,089) - -------------------- Sales recognized as revenue - - -------------------- -------------------- Revenue is recognized when title and risk transfer to the purchaser, which is at the time of lifting of the oil into the tanker at the Sullom Voe terminal. All sales are made under contract to one UK customer. Under the contract with the purchaser, Antrim invoices and receives payment for its oil in the month after production; however, the purchaser retains certain rights impacting the timing of liftings which may result in no sales in a particular month resulting in deferred revenue. 16) General and administrative expenses 2012 2011 -------------------- Wages and salaries 3,770 3,338 Occupancy 467 468 Administrative 2,253 1,699 Travel 315 370 Overhead recovery (962) (871) -------------------- 5,843 5,004 -------------------- -------------------- Total employee benefits expenses, including share-based compensation for the year ended December 31, 2012 were $4,966 (2011 - $4,632). 17) Finance income 2012 2011 -------------------- Interest income 276 706 -------------------- -------------------- 18) Finance costs 2012 2011 -------------------- Accretion of decommissioning obligations 145 209 Interest expense - 172 Bank charges 68 205 -------------------- 213 586 -------------------- -------------------- 19) Supplemental cash flow information 2012 2011 -------------------- (Increase) / decrease of assets: Trade and other receivables 4,962 (1,764) Inventory and prepaid expenses (2,284) 487 Increase / (decrease) of liabilities: Trade and other payables 950 13,965 Deferred revenue 1,089 - -------------------- 4,717 12,688 -------------------- -------------------- Cash and cash equivalents are comprised of: 2012 2011 -------------------- Cash in bank 1,503 19,921 Short-term deposits - 27,184 -------------------- 1,503 47,105 -------------------- -------------------- 20) Income taxes The differences between the expected income tax provision and the reported income tax provision are summarized as follows: 2012 2011 -------------------- Loss from continuing operations before income taxes 134,859 55,110 Statutory income tax rate 25% 26.5% -------------------- Expected recovery 33,715 14,604 Increase (decrease) in taxes resulting from: Non-deductible expenses (16,692) (9,575) Effect of different tax rates in foreign jurisdictions (10,767) 2,635 Changes in statutory rate changes in the year 412 104 Benefit of tax losses not recognized (6,668) (7,768) -------------------- - - -------------------- -------------------- The statutory tax rate was 25% in 2012 (2011 - 26.5%). The decrease from 2011 to 2012 was as a result of previously enacted reductions in the federal corporate income tax rates. There was no income tax expense relating to discontinued operations. Deferred income tax The deferred income tax assets are comprised of the following: December 31 December 31 2012 2011 ------------------------------ Property, plant and equipment (25,083) (39,139) Decommissioning obligations 3,081 1,078 Non-capital losses 94,165 63,995 Capital losses 1,447 - Share issuance and financing costs 1,103 755 Other 249 149 Unrecognized deferred tax asset (74,962) (26,838) ------------------------------ - - ------------------------------ ------------------------------ The Company has unused non-capital tax losses of $310,676 (2011 - $220,754) to carry forward against future taxable income of subsidiaries in which the losses arose. Some of these deferred tax assets were recognized in the current period as the Company anticipates being able to use them to offset taxable profits in its operations in the United Kingdom. At December 31, 2012, the Company had the following available tax loss carryforwards: Expiry Dates $ ------------------------ Loss carryforwards attributable to continuing operations: Canada 2014-2031 26,809 United Kingdom No Expiry 283,841 Ireland No Expiry 26 ---------- 310,676 ---------- ---------- 21) Commitments and contingencies The Company has commitments in respect of its petroleum and natural gas properties and operating leases as follows: 2013 2014 2015 2016 2017 Thereafter ---------------------------------------------------------------------------- United Kingdom Causeway(1) 16,079 7,073 27 29 31 31 Cormorant East 654 8 8 8 8 8 Fyne and Dandy(2) 2,913 33 33 33 33 33 Cyclone - Typhoon(3) 13 12 - - - - West Teal(4) - - - - - - Carra(5) - - - - - - Erne 13 13 - - - - Ireland 69 - - - - - Office leases 358 359 372 372 350 10 ---------------------------------------------------------------------------- Total 20,099 7,498 440 442 422 82 ---------------------------------------------------------------------------- (1) Relates to Antrim's 35.5% interest in the Causeway Licences. (2) In 2012, Antrim signed a Heads of Term's Agreement for an option to lease an FPSO for use in the development of the Fyne Field. As the Company decided not to proceed with the development of the Fyne Field, there is a $2.8 million obligation related to front end engineering design work. This obligation is included on the consolidated balance sheet as at December 31, 2012 under accounts payables and accrued liabilities. (3) The Company has a $6.2 million contingent drilling commitment on this licence for the Typhoon prospect in 2014. Due to the results of the Cyclone well, the Company has asked DECC to accept this well as a fulfillment of the drilling obligation. Contingent on DECC acceptance, there are no remaining obligations for the initial term of the licence. (4) The Company has a $24.0 million contingent drilling commitment on this licence for the West Teal prospect in 2013. Due to the Company being unable to identify a commercially viable export route a request was made to DECC to waive the contingent well requirement and, with DECC's consent, allow the licence to be relinquished (see Note 8). (5) In October 2012, DECC waived all commitments related to the Licence P1563 Blocks 21/28b & 21/29c. In February 2013, the licence and all commitments were officially relinquished. Contingencies In 2011, the Company entered into a variation to an existing contract for drilling management services in the UK North Sea which required the drilling of two wells, estimated to take 50 days in a letter of intent preceding the contract variation. The Company contends that it met its contractual obligations under this variation through the drilling of the Erne pilot well (21/29d-11) and the Erne sidetrack well (21/29d-11Z). The drilling of these two wells took place over a period of 58 days. Subsequent to releasing the rig, the Company received an invoice from the drilling management services contractor charging the Company for approximately $5 million in additional costs as the contractor claims all conditions of the contract had not yet been satisfied. In July 2012, the drilling management services contractor filed a claim against the Company for the additional invoice costs plus interest and lost management time, in the High Court of England and Wales. In August 2012, the Company filed a defence against this claim in the High Court of England and Wales. A case management conference where the Court will set the timetable for the claim going forward has been listed for April 12, 2013. The Company is disputing the additional costs and believes it is more likely than not that it will not have to pay. As a result, a contingent liability has not been recorded. In January 2013, the Company elected not to participate in further development work on the Fionn Field. Subject to all necessary approvals from DECC, Antrim intends to withdraw from the Fionn Field subarea and will not incur any further liabilities. In accordance with the Fionn Field Supplemental Agreement, signed in January 2012, the Company is of the position that there are no further obligations with respect to the decommissioning or well abandonment liabilities of the three currently suspended wells in the Fionn Field subarea. The operator contends this position in regards to two of the three currently suspended wells. The Company believes it is more likely than not that Antrim will be released of these obligations. Accordingly, no amounts have been recorded in decommissioning obligations in relation to the Fionn Field (see Note 10). Operating lease arrangements 2012 2011 -------------------- Minimum lease payments under operating leases recognized as an expense in the year 470 - -------------------- -------------------- At the balance sheet date, the Company had outstanding commitments for future minimum lease payments under non-cancellable operating leases, which fall due as follows: 2012 2011 -------------------- Within one year 358 - In the second to fifth years inclusive 1,464 - -------------------- 1,822 - -------------------- -------------------- Operating lease payments represent net rentals payable by the Company for its office properties. Current lease arrangements expire at the end of December 2017. 22) Financial instruments and financial risks Financial instruments Financial assets and financial liabilities are initially recognized at fair value and are subsequently accounted for based on their classification. The classification categories, which depend on the purpose for which the financial instruments were acquired and their characteristics, include held-for-trading, available-for-sale, held-to-maturity, loans and receivables, investments, and other liabilities. Except in very limited circumstances, the classification is not changed subsequent to initial recognition. The Company's financial instruments consist of cash, cash equivalents, restricted cash, accounts receivable, other non-current assets, accounts payable and contingent consideration. Cash and cash equivalents, restricted cash, and accounts receivable are classified as loans and receivables and are accounted for at amortized cost. Accounts payable are classified as other liabilities and are accounted for at amortized cost. Due to the short-term maturity of the Company's financial instruments, fair values approximate carrying amounts. Financial risks The Company is exposed to financial risks encountered during the normal course of its business. These financial risks are composed of credit risk, liquidity risk and market risk including commodity price and foreign currency exchange risks. a) Credit risk The Company is exposed to the risk that its counterparties will fail to discharge their obligations to the Company on its cash, cash equivalents, accounts receivable and certain non-current assets. Cash and cash equivalents and restricted cash are on deposit with reputable Canadian and international banks, and therefore the Company does not believe these financial instruments are subject to material credit risk. The Company sells all of its production to one oil and natural gas marketer and therefore is subject to concentration risk. Management does not believe that this concentration of credit risk will result in any loss to the Company based on past payment experience and its investment grade credit rating as established by independent credit rating agencies. The Company's sales from discontinued operations are approximately 40% to a single customer and three customers who each have sales of greater than 10%. Factors included in the assessment of accounts receivable for impairment are the relationship between the purchaser and the Company and the age of the receivable. As at December 31, 2012, the Company has provided for an allowance for doubtful accounts of $nil (2011 - $nil). The extent of the Company's credit risk exposure is identified in the following table: December 31 December 31 2012 2011 ------------------------------ Current Cash and cash equivalents 1,503 47,105 Restricted cash 808 17,249 Accounts receivable 332 5,294 Assets held for sale(1) - 8,200 ------------------------------ 2,643 77,848 ------------------------------ ------------------------------ (1) Relates to cash and cash equivalents classified as assets held for sale as at December 31, 2011 and the non-interest bearing promissory note and interest bearing bond which were classified as non-current as at December 31, 2011. (b) Liquidity risk The Company is exposed to liquidity risk from the possibility that it will encounter difficulty meeting its financial obligations. The Company manages this risk by forecasting cash flows in an effort to identify future liabilities and arrange financing, if necessary. It may take many years and substantial cash expenditures to pursue exploration and development activities on all of the Company's existing undeveloped properties. Accordingly, the Company will need to raise additional funds from outside sources in order to explore and develop its properties. There is no assurance that adequate funds from debt and equity markets will be available to the Company in a timely manner. At December 31, 2012, the Company had a working capital deficiency of $10,734, compared to working capital of $52,674 at December 31, 2011. In January 2013 the Company entered into a $30 million Payment Swap transaction described in Note 24. The Payment Swap provides the Company with sufficient funding to meet its commitments for cost overruns on the completion of the production well in the Causeway Field and future costs related to the Causeway development program. The contractual maturities of the Company's financial liabilities at December 31, 2012 are all less than one year. (c) Market risk Market risk consists of commodity price risk and foreign currency exchange risk. Commodity price risk Currently all of the Company's production is from one property in the UK. Commodity price risk related to crude oil production represents a significant market risk exposure. Crude oil prices and quality differentials can be influenced by global supply and demand factors as well as political events, quotas imposed on members of the Organization of Petroleum Exporting Countries (OPEC) and weather. In January 2013, Antrim entered into a Brent Oil Price Commodity Swap which reduced its exposure to commodity price risk (see Note 24). Foreign currency exchange risk The Company is exposed to fluctuations in foreign currency exchange rates as many of the Company's financial instruments are denominated in United States dollars and British pounds sterling ("GBP "). As a result, fluctuations in the United States dollar and British pounds sterling against the Canadian dollar could result in unanticipated fluctuations in the Company's financial results. The Company seeks to minimize foreign exchange risk by holding cash and cash equivalents in Canadian dollars when not required in support of current operations. A 1% change in the Cdn$/US$ and Cdn$/GBP exchange rate at December 31, 2012 would impact comprehensive income by approximately $1,123 and $739, respectively. Capital management The Company's objective when managing its capital is to maintain adequate levels of funding to support its exploration and development program and provide flexibility in the future development of its business. Historically the Company raised all of its capital requirements from internally generated cash flow and the issuance of common shares and securities exchangeable for common shares. In the fourth quarter of 2012, the Company incurred unexpected cost overruns on the development of Causeway resulting in a working capital deficiency as at December 31, 2012. The Company's capital structure at December 31, 2012 consisted of cash and cash equivalents and shareholders' equity. Shareholders' equity includes shareholders' capital, contributed surplus, and accumulated other comprehensive loss and deficit. The Company had no bank debt at December 31, 2012; however, it assumed debt obligations in January 2013 when it entered into a Payment Swap transaction (see Note 24). The capital structure of the Company consists of: December 31 December 31 2012 2011 ------------------------------ Cash and cash equivalents 1,503 47,105 Shareholders' equity (66,996) (207,188) ------------------------------ (65,493) (160,083) ------------------------------ ------------------------------ Current restrictions on the availability of credit may limit the Company's ability to access debt or equity financing for its development projects. The Company forecasts cash flows against a range of macroeconomic and financing market scenarios in an effort to identify future liabilities and arrange financing, if necessary. Although the Company may need to raise additional funds from outside sources, if available, in order to develop its oil and gas properties, the Company maintains flexibility to manage financial commitments on these assets. Methods employed to adjust the Company's capital structure could include any, all or a combination of the following activities: i. Issue new shares through a public offering or private placement; ii. Issue equity linked or convertible debt; iii.Raise fixed or floating rate debt; iv. Sell or farmout existing exploration, development and producing assets. 23) Related party transactions The financial statements include the financial statements of Antrim and the subsidiaries listed in the following table: Equity interest in % Country of Subsidiary Incorporation 2012 2011 ---------------------------------------------------------------------------- Antrim Argentina S.A. Argentina - 100 Antrim Energy Ltd. Bahamas 100 100 Antrim Exploration (Ireland) Limited Ireland 100 100 Antrim Resources (N.I.) Limited United Kingdom 100 100 Netherfield Corporation(1) British Virgin - 100 Islands (1) - This entity was amalgamated with Antrim Energy Inc. as part of the plan of arrangement discussed in Note 4. Compensation of key management personnel of the Company Key management personnel include directors and executives of the Company. The compensation paid or payable to key management personnel is as follows: 2012 2011 -------------------- Short-term employee benefits 2,190 1,643 Share-based compensation 792 753 -------------------- Total compensation paid to key management personnel 2,982 2,396 -------------------- -------------------- Other related party transactions The Company may from time to time enter into arrangements with related parties which are accounted for at the exchange amount. In 2012, the Company incurred fees of $422 (2011 - $267) payable to Burstall Winger LLP, a law firm in which a director of the Company is a partner. 24) Subsequent events In January 2013, the Company elected not to participate in further development work on the Fionn Field. Subject to all necessary approvals from DECC, Antrim intends to withdraw from the Fionn Field subarea and will not incur any further liabilities, including remaining decommissioning or well abandonment liabilities. As a result of its withdrawal, the Company recorded a $50,358 impairment charge as at December 31, 2012. On January 23, 2013, Antrim announced that it entered into a $30 million Payment Swap transaction with a major financial institution. Under the terms of the Payment Swap, the Company received $30 million which is repayable in 29 instalments commencing September 2013 and concluding January 2016. The interest rate under the Payment Swap is fixed at 5.1%. Antrim also entered into a Brent Oil Price Commodity Swap to forward sell 657,350 barrels of Brent crude oil at a fixed price of $89.37 covering the period from February 2013 to December 2015. On March 26, 2013 the Company discontinued development of the Fyne Field. Until very recently, estimated costs indicated that the planned Fyne development satisfied the Company's economic threshold and contingent on timing of the redeployment of the FPSO from its current location was on track for a late 2014 start-up. However, projected capital costs have recently increased substantially, and in the Company's view now make the project uneconomic. DIRECTORS Stephen Greer President and Chief Executive Officer, Antrim Energy Inc. Colin Maclean (2) (3) (4) (5) Independent Director Dr. Gerry Orbell (1) (3) (4) (5) Chairman, Antrim Energy Inc. Erik Mielke Independent Director Jim Perry (1) (3) (4) (5) President and CEO, Alternative Fuel Systems (2004) Inc. Jim Smith (1) (2) (5) Independent Director Jay Zammit (2) (5) Partner, Burstall Winger LLP 1. Member of the Audit Committee 2. Member of the Compensation Committee 3. Member of the Reserves Committee 4. Member of the Exploration Committee 5. Member of the Corporate Governance Committee OFFICERS Stephen Greer President and Chief Executive Officer Anthony Potter Chief Financial Officer Kerry Fulton Vice President, Operations Terry Lederhouse Vice President, Commercial Martin Dashwood Vice President, Exploration Adrian Harvey Corporate Secretary STOCK EXCHANGE LISTINGS Toronto Stock Exchange: Trading Symbol "AEN" London Stock Exchange (AIM): Trading Symbol "AEY" HEAD OFFICE 610, 301 8th Avenue SW Calgary, Alberta Canada T2P 1C5 Main: +1 403 264 5111 Fax: + 1 403 264 5113 info@antrimenergy.com http://www.antrimenergy.com/ The Company's website is not incorporated by reference in and does not form a part of this annual report. LONDON OFFICE Ashbourne House, The Guildway Old Portsmouth Road, Artington Guildford, Surrey United Kingdom GU3 1LR Main: +44 (0) 1483-307 530 Fax: +44 (0) 1483-307 531 INTERNATIONAL SUBSIDIARIES Antrim Energy Ltd. Antrim Exploration (Ireland) Limited Antrim Resources (N.I.) Limited LEGAL COUNSEL Burstall Winger LLP Calgary, Alberta BANKERS Toronto-Dominion Bank of Canada AUDITORS PricewaterhouseCoopers LLP Calgary, Alberta INDEPENDENT ENGINEERS McDaniel & Associates Consultants Ltd. REGISTRAR AND TRANSFER AGENT Inquiries regarding change of address, registered shareholdings, stock transfers or lost certificates should be direct to: CIBC Mellon Trust Company Calgary, Alberta FOR FURTHER INFORMATION PLEASE CONTACT: Antrim Energy Inc. Stephen Greer President & CEO 403-264-5111 403-264-5113 (FAX) greer@antrimenergy.com Antrim Energy Inc. Anthony Potter Chief Financial Officer 403-264-5111 403-264-5113 (FAX) potter@antrimenergy.com www.antrimenergy.com Nominated Advisor Royal Bank of Canada Europe Limited Martin Eales +44 20 7029 7881
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