ANDERSON ENERGY LTD.
See accompanying notes to the consolidated financial statements.
See accompanying notes to the consolidated financial statements.
See accompanying notes to the consolidated financial statements.
ANDERSON ENERGY LTD.
See accompanying notes to the consolidated financial statements.
ANDERSON ENERGY LTD.
Notes to the Consolidated Financial Statements
DECEMBER 31, 2011 AND DECEMBER 31, 2010
(Tabular amounts in thousands of dollars, unless otherwise stated)
1. REPORTING ENTITY
Anderson Energy Ltd. and its wholly-owned subsidiaries (collectively “Anderson” or the “Company”) are engaged in the acquisition, exploration and development of oil and gas properties in western Canada. Anderson is a public company incorporated and domiciled in Canada. Anderson’s common shares and convertible debentures are listed on the Toronto Stock Exchange. The Company’s registered office and principal place of business is 700, 555 – 4th Avenue SW, Calgary, Alberta, Canada, T2P 3E7.
2. BASIS OF PREPARATION
(a) Statement of compliance. These consolidated financial statements comply with International Financial Reporting Standards (“IFRS”) as issued by the International Accounting Standards Board (“IASB”).
These are the Company’s first consolidated annual financial statements prepared in accordance with IFRS and IFRS 1 First-time Adoption of International Financial Reporting Standards has been applied. In previous years, the Company prepared its consolidated financial statements in accordance with Canadian Generally Accepted Accounting Principles in effect prior to January 1, 2011 (“Canadian GAAP”). See note 23 for details on the impact of the transition from Canadian GAAP to IFRS.
The consolidated financial statements were approved and authorized for issuance by the Board of Directors on March 16, 2012.
(b) Basis of measurement. The consolidated financial statements have been prepared on the historical cost basis except for derivative financial instruments, which are measured at fair value. The methods used to measure fair values are discussed in note 5.
(c) Functional and presentation currency. These consolidated financial statements are presented in Canadian dollars, which is the Company’s functional currency.
(d) Function and nature of expenses. Expenses in the consolidated statements of operations and comprehensive loss are presented as a combination of function and nature in conformity with industry practice. Transportation expenses, depletion and depreciation, and impairment of property, plant and equipment are presented in separate lines by their nature, while operating expenses and general and administrative expenses are presented on a functional basis. Significant operating and general and administrative expenses are presented by their nature in note 15.
3. SIGNIFICANT ACCOUNTING POLICIES
The accounting policies set out below have been applied consistently to all periods presented in these consolidated financial statements except for the opening IFRS consolidated statement of financial position, which has utilized certain exemptions available under IFRS 1 as described in note 23.
(a) Basis of consolidation:
(i) Subsidiaries. Subsidiaries are entities controlled by the Company. The financial statements of subsidiaries are included in the consolidated financial statements from the date that control commences until the date that control ceases.
| 7 | 2011 FINANCIAL STATEMENTS |
3. SIGNIFICANT ACCOUNTING POLICIES (Continued)
(ii) Jointly controlled operations and jointly controlled assets. Many of the Company’s oil and natural gas activities involve jointly controlled assets. The consolidated financial statements include the Company’s share of these jointly controlled assets and the proportionate share of the relevant revenue and related costs.
(iii) Transactions eliminated on consolidation. Intercompany balances and transactions, and any unrealized income and expenses arising from intercompany transactions, are eliminated in preparing the consolidated financial statements.
(b) Financial instruments:
(i) Non-derivative financial instruments. Non-derivative financial instruments comprise cash and cash equivalents, accounts receivable and accruals, accounts payables and accruals, bank loans and convertible debentures. Non-derivative financial instruments are recognized initially at fair value, plus, for instruments not classified as “fair value through profit or loss”, any directly attributable transaction costs. Subsequent to initial recognition, non-derivative financial instruments are measured as described below.
Cash and cash equivalents. Cash and cash equivalents comprise cash on hand, term deposits and other short-term highly liquid investments with original maturities of three months or less and is measured similar to other non-derivative financial instruments.
Other. Other non-derivative financial instruments, comprising accounts receivable and accruals, accounts payable and accruals, bank loans and convertible debentures, are measured at amortized cost using the effective interest method, less any impairment losses. The Company nets all transaction costs incurred in relation to the acquisition of a financial asset or liability, against the related financial asset or liability. Bank loans and convertible debentures are recorded net of issue costs and are presented net of deferred interest payments, with interest recognized in earnings on an effective interest basis.
(ii) Derivative financial instruments. The Company has entered into certain financial derivative contracts in order to manage the exposure to market risks from fluctuations in commodity prices. These instruments are not used for trading or speculative purposes. The Company has not designated its financial derivative contracts as effective accounting hedges, and thus has not applied hedge accounting, even though the Company considers all commodities contracts to be economic hedges. As a result, all financial derivative contracts are classified as “fair value through profit or loss” and are recorded on the statement of financial position at fair value. Transaction costs are recognized in profit or loss when incurred.
The Company accounts for forward physical delivery sales contracts, which are entered into and held for the purpose of delivery or receipt of non-financial items in accordance with expected sale or usage requirements as executory contracts. As such, these contracts are not considered to be derivative financial instruments and have not been recorded at fair value on the statement of financial position. Settlements on these physical sales contracts are recognized in oil and natural gas revenue.
Embedded derivatives are separated from the host contract and accounted for separately if the economic characteristics and risks of the host contract and the embedded derivative are not closely related. A separate instrument with the same terms as the embedded derivative would meet the definition of a derivative, and the combined instrument is not measured at “fair value through profit or loss”. Changes in the fair value of separable embedded derivatives are recognized immediately in profit or loss.
(iii) Share capital. Common shares are classified as equity. Incremental costs directly attributable to the issue of common shares and stock options are recognized as a deduction from equity, net of any tax effects.
3. SIGNIFICANT ACCOUNTING POLICIES (Continued)
(c) Property, plant and equipment:
(i) Exploration and evaluation expenditures. Pre-licence costs are recognized in the statement of operations and comprehensive loss as incurred. Generally, costs designated as exploration and evaluation assets are initially capitalized, and are assessed for impairment when there are indicators of impairment present and when technical feasibility and commercial viability are established and the assets are transferred to development and production assets. Exploration and evaluation assets that are determined not to be technically feasible or commercially viable are charged to net income. As of December 31, 2011, the Company has not identified any costs as exploration and evaluation assets (December 31, 2010 – $Nil, January 1, 2010 - $Nil).
(ii) Development and production costs. Items of property, plant and equipment, which include oil and gas development and production assets, are measured at cost less accumulated depletion and depreciation and accumulated impairment losses. All costs directly associated with the development of oil and natural gas reserves are recognized as oil and natural gas interests if they extend or enhance the recoverable reserves of the underlying assets. Such costs include property acquisitions, drilling and completion costs, gathering and processing infrastructure, capitalized decommissioning obligations, directly attributable internal costs and major overhaul and turnaround activities that maintain property, plant and equipment. Repairs and maintenance and operational costs that do not extend or enhance the recoverable reserves are charged to profit or loss when incurred.
Oil and natural gas assets are grouped into cash generating units (“CGUs”) for impairment testing. The Company has grouped its development and production assets into the following CGUs: Horizontal Oil, Deep Gas, Shallow Gas and Non-Core. When significant parts of an item of property, plant and equipment, including oil and natural gas interests, have different useful lives, they are accounted for as separate items (components).
Gains and losses on disposal of an item of property, plant and equipment, including oil and natural gas interests, are determined by comparing the proceeds from disposal with the carrying amount of property, plant and equipment and are recognized as separate line items in profit or loss.
(d) Depletion and depreciation. The net carrying value of development or production assets is depleted using the unit of production method by reference to the ratio of production in the quarter to the related proved and probable reserves, taking into account estimated future development and decommissioning costs necessary to bring those reserves into production. For other assets, depreciation is recognized in profit or loss over the estimated useful lives of each part of an item of property, plant and equipment using the declining balance method at rates between 20% and 30% per annum. Leased assets are depreciated over the shorter of the lease term and their useful lives unless it is reasonably certain that the Company will obtain ownership by the end of the lease term. The costs of major overhaul and turnaround activities that are capitalized are depreciated on a straight-line basis over the period to the next recurrence of that set of activities, which varies from two to five years.
Depreciation methods, useful lives and residual values are reviewed at each reporting date.
(e) Leased assets. Operating leases are not recognized on the Company’s statement of financial position.
Payments made under operating leases are recognized in profit or loss on a straight-line basis over the term of the lease. Lease incentives received are recognized as an integral part of the total lease expense, over the term of the lease.
| 9 | 2011 FINANCIAL STATEMENTS |
3. SIGNIFICANT ACCOUNTING POLICIES (Continued)
(f) Impairment:
(i) Financial assets. A financial asset is assessed at each reporting date to determine whether there is any objective evidence that it is impaired. A financial asset is considered to be impaired if objective evidence indicates that one or more events have had a negative effect on the estimated future cash flows of that asset.
An impairment loss in respect of a financial asset measured at amortized cost is calculated as the difference between its carrying amount and the present value of the estimated future cash flows discounted at the original effective interest rate.
Individually significant financial assets are tested for impairment on an individual basis. The remaining financial assets are assessed collectively in groups that share similar credit risk characteristics.
All impairment losses are recognized in profit or loss.
An impairment loss is reversed if the reversal can be related objectively to an event occurring after the impairment loss was recognized. For financial assets measured at amortized cost the reversal is recognized in profit or loss.
(ii) Non-financial assets. The carrying amounts of the Company’s non-financial assets net of decommissioning liabilities, other than deferred tax assets are reviewed at each reporting date to determine whether there is any indication of impairment. If any such indication exists, then the asset’s recoverable amount is estimated.
For the purpose of impairment testing, assets are grouped together into CGUs; the smallest group of assets that generates cash inflows from continuing use that are largely independent of the cash inflows of other assets or groups of assets. The recoverable amount of an asset or a CGU is the greater of its value in use (“VIU”) and its fair value less costs to sell (“FVLCTS”).
An impairment loss is recognized if the carrying amount of an asset or its CGU exceeds its estimated recoverable amount. Impairment losses are recognized in profit or loss. Impairment losses recognized in respect of CGUs are allocated first to reduce the carrying amount of any goodwill allocated to the units and then to reduce the carrying amounts of the other assets in the unit on a pro rata basis.
Impairment losses recognized in prior years are assessed at each reporting date for any indications that the loss has decreased or no longer exists. An impairment loss is reversed if there has been a change in the estimates used to determine the recoverable amount. An impairment loss is reversed only to the extent that the asset’s carrying amount does not exceed the carrying amount that would have been determined, net of depletion and depreciation, if no impairment loss had been recognized.
(g) Share-based payments. The grant date fair value of equity-settled options granted to employees is recognized as stock-based compensation expense, within general and administrative expenses, with a corresponding increase in contributed surplus over the vesting period. A forfeiture rate is estimated on the grant date and is adjusted to reflect the actual number of options that vest.
(h) Provisions. A provision is recognized if, as a result of a past event, the Company has a present legal or constructive obligation that can be estimated reliably, and it is probable that an outflow of economic benefits will be required to settle the obligation. Provisions are determined by discounting the expected future cash flows at a pre-tax rate that reflects current market assessments of the time value of money and the risks specific to the liability. Provisions are not recognized for future operating losses.
3. SIGNIFICANT ACCOUNTING POLICIES (Continued)
Decommissioning obligations. The Company’s activities give rise to dismantling, decommissioning and site disturbance remediation activities. Provision is made for the estimated cost of site restoration and capitalized in the relevant asset category.
Decommissioning obligations are measured at the present value of management’s expectation of the expenditures required to settle the present obligation at the reporting date. Subsequent to the initial measurement, the obligation is adjusted at the end of each period to reflect the passage of time and changes in the estimated future cash flows underlying the obligation, including changes in the discount rate used to calculate the obligation. The increase in the provision due to the passage of time is recognized as finance costs whereas increases/decreases due to changes in the estimated future cash flows are capitalized. Actual costs incurred upon settlement of the decommissioning obligations are charged against the provision to the extent the provision was established, with any difference being recognized in profit or loss under gain or loss on sale of property, plant and equipment.
(i) Revenue. Revenue from the sale of oil and natural gas is recorded when the significant risks and rewards of ownership of the product is transferred to the buyer, which is usually when legal title passes to the external party. Oil and gas sales are presented before royalty obligations, whereas revenue is presented net of royalties.
Royalty income is recognized as it accrues in accordance with the terms of the overriding royalty agreements.
Fees charged to other entities for the use of pipelines, compressors and facilities owned by the Company are recognized as operating expense recoveries for use of transportation and processing assets when the usage is incurred.
Fees charged to other entities to recover overhead costs pursuant to capital and operating agreements are recognized as a reduction of general and administrative expenses in accordance with the terms of the capital and operating agreements.
(j) Transportation expenses. Transportation expenses include third-party pipeline and trucking costs incurred to transport oil, natural gas and natural gas liquids from processing and treating facilities to the point of sale
(k) Finance income and expenses. Finance expense comprises interest expense on borrowings, accretion of the discount on decommissioning obligations and accretion on convertible debentures recognized as financial liabilities.
Interest income is recognized as it accrues in profit or loss, using the effective interest method.
(l) Income tax. Income tax expense comprises current and deferred tax. Income tax expense is recognized in profit or loss except to the extent that it relates to items recognized directly in equity, in which case it is recognized in equity.
Current tax is the expected tax payable on the taxable income for the year, using tax rates enacted or substantively enacted at the reporting date, and any adjustment to tax payable in respect of previous years.
Deferred tax is recognized using the balance sheet method, providing for temporary differences between the carrying amounts of assets and liabilities for financial reporting purposes and the amounts used for taxation purposes. Deferred tax is not recognized on the initial recognition of assets or liabilities in a transaction that is not a business combination. In addition, deferred tax is not recognized for taxable temporary differences arising on the initial recognition of goodwill. Deferred tax is measured at the tax rates that are expected to be applied to temporary differences when they reverse, based on the laws that have been enacted or substantively enacted by the reporting date. Deferred tax assets and liabilities are offset if there is a legally enforceable right to offset, and they
| 11 | 2011 FINANCIAL STATEMENTS |
3. SIGNIFICANT ACCOUNTING POLICIES (Continued)
relate to income taxes levied by the same tax authority on the same taxable entity, or on different tax entities, but they intend to settle current tax liabilities and assets on a net basis or their tax assets and liabilities will be realized simultaneously.
A deferred tax asset is recognized to the extent that it is probable that future taxable profits will be available against which the temporary difference can be utilized. Deferred tax assets are reviewed at each reporting date and are reduced to the extent that it is no longer probable that the related tax benefit will be realized.
(m) Earnings per share. Basic earnings per share is calculated by dividing the profit or loss attributable to common shareholders of the Company by the weighted average number of common shares outstanding during the period. Diluted earnings per share is determined by adjusting the profit or loss attributable to common shareholders and the weighted average number of common shares outstanding for the effects of dilutive instruments such as options granted to employees.
(n) New standards and interpretations not yet adopted:
The IASB has issued the following new standards and amendments, all of which are effective for annual periods beginning on or after January 1, 2013. Although early adoption is permitted, the Company has not done so as of December 31, 2011
IFRS 9 – Financial Instruments. In November 2009, the IASB published IFRS 9 “Financial Instruments" which covers the classification and measurement of financial assets as part of its project to replace IAS 39 “Financial Instruments: Recognition and Measurement.” IFRS 9 uses a single approach to determine whether a financial asset is measured at amortized cost or fair value, replacing the multiple rules in IAS 39. The approach in IFRS 9 is based on how an entity managed its financial instruments in the context of its business model and the contractual cash flow characteristics of the financial assets. The new standard also requires a single impairment method to be used, replacing the multiple impairment methods in IAS 39.
In October 2010, additional requirements for classifying and measuring financial liabilities were added to IFRS 9. Under this guidance, entities have the option to recognize financial liabilities at fair value through profit or loss. If this option is elected, entities would be required to reverse the portion of the fair value change due to own credit risk out of profit or loss and recognize the change in other comprehensive income.
On August 4, 2011, the IASB issued an exposure draft proposing to change the mandatory effective date of IFRS 9 to annual periods beginning on or after January 1, 2015 from the original effective date of January 1, 2013. Early adoption is permitted and the standard is required to be applied retrospectively. The comment period for this exposure draft closed on October 21, 2011. The implementation of the issued standard is not expected to have a significant impact on the Company’s financial position or results.
Reporting Entity. In May 2011, the IASB issued IFRS 10 Consolidated Financial Statement, IFRS 11 Joint Arrangements, IFRS 12 Disclosures of Interests in Other Entities, and amendments to IAS 27 Separate Financial Statements and IAS 28 Investments in Associates and Joint Ventures.
IFRS 10 creates a single consolidation model by revising the definition of control in order to apply the same control criteria to all types of entities, including joint arrangements, associates and special purpose vehicles. IFRS 11 establishes a principle-based approach to the accounting for joint arrangements by focusing on the rights and obligations of the arrangement and limits the application of proportionate consolidation accounting to arrangements that meet the definition of a joint operation. IFRS 12 is a comprehensive disclosure standard for all forms of interests in other entities, including joint arrangements, associates and special purpose vehicles.
3. SIGNIFICANT ACCOUNTING POLICIES (Continued)
Retrospective application of these standards with relief for certain transactions is effective for fiscal years beginning on or after January 1, 2013, with earlier application permitted if all five standards are collectively adopted. The implementation of the issued standard is not expected to have a significant impact on the Company’s financial position or results.
IAS 12 – Income Taxes. IAS 12 “Income Taxes” was amended on December 20, 2010 to remove subjectivity in determining on which basis an entity measures the deferred tax relating to an asset. The amendment introduces a presumption that an entity will assess whether the carrying value of an asset will be recovered through the sale of the asset. The amendment to IAS 12 is effective for reporting periods beginning on or after January 1, 2012. The implementation of the issued standard is not expected to have a significant impact on the Company’s financial position or results.
IFRS 13 – Fair Value Measurement. In May 2011, the IASB issued IFRS 13 Fair Value Measurement, which establishes a single source of guidance for all fair value measurements; clarifies the definition of fair value; and enhances the disclosures on fair value measurement. Prospective application of this standard is effective for fiscal years beginning on or after January 1, 2013, with early application permitted. The implementation of the issued standard is not expected to have a significant impact on the Company’s financial position or results.
4. MANAGEMENT JUDGEMENTS AND ESTIMATES
The preparation of the consolidated financial statements in accordance with IFRS requires management to make judgements, estimates and assumptions that affect the application of accounting policies and the reported amounts of assets, liabilities, income and expenses. Actual results ultimately may differ from these estimates.
(a) Judgements. The key judgements made in applying accounting policies that have the most significant effect on the amounts recognized in these consolidated financial statements are as follows:
| (i) | Identification of cash generating units. Cash generating units are defined as the lowest grouping of integrated assets that generate identifiable cash inflows that are largely independent of the cash inflows of other assets or groups of assets. The classification of assets into cash generating units requires significant judgement and interpretations with respect to shared infrastructure, geographical proximity, petroleum type and similar exposure to market risk and materiality. See note 7. |
| (ii) | Fair value of derivatives. The fair value of financial instruments that are not traded in an active market is determined using valuation techniques. The Company uses its judgement to select a variety of methods and makes assumptions that are primarily based on market conditions existing at the end of each reporting period. The Company uses directly and indirectly observable inputs in measuring the value of financial instruments that are not traded in active markets, including quoted commodity prices and volatility. See note 19(d). |
(b) Use of estimates. Information about assumptions and estimation uncertainties that have a significant risk of resulting in a material adjustment within the next financial year are as follows:
| (i) | Estimates of oil and natural gas reserves. Depletion and depreciation as well as the amounts used in impairment calculations are based on estimates of oil and natural gas reserves. Reserves estimates are based on engineering data, estimated future prices, expected future rates of production and the timing of future capital expenditures, all of which are subject to many uncertainties and interpretations. At least once per year, a reserves estimate is prepared by independent qualified reserves evaluators. The Company expects that, over time, its reserves estimates will be revised upward or downward based on updated information such as the results |
| 13 | 2011 FINANCIAL STATEMENTS |
4. MANAGEMENT JUDGEMENTS AND ESTIMATES (Continued)
of future drilling, testing and production levels, and may be affected by changes in commodity prices. See notes 6 and 7.
| (ii) | Recoverable amounts of CGUs. The recoverable amount of a CGU used in the assessment of impairment is the greater of its VIU and its FVLCTS. |
VIU is determined by estimating the present value of the future net cash flows from the continued use of the CGU, and is subject to the risks associated with estimating the value of reserves.
FVLCTS refers to the amount obtainable from the sale of a CGU in an arm’s length transaction between knowledgeable, willing parties, less costs of disposal. The criteria used in the estimation of this amount are discussed in note 5.
At December 31, 2011 the recoverable amounts of the Company’s CGUs were based on their estimated FVLCTS. Note 5 outlines the factors considered in estimating these amounts. The key assumptions and estimates of the value of oil and gas reserves and the existing and potential markets for the Company’s oil and gas assets are valid at the time of reserves estimation and market assessment and are subject to change as new information becomes available. Changes in international and regional factors including supply and demand of commodities, inventory levels, drilling activity, currency exchange rates, weather, geopolitical and general economic environment factors may result in significant changes to the estimated recoverable amounts of CGUs. See notes 6 and 7.
| (iii) | Decommissioning obligations. The total decommissioning obligation is estimated based on the Company’s net ownership interest in all wells and facilities, estimated costs to reclaim and abandon these wells and facilities and the estimated timing of the costs to be incurred in future years, based on current legal and constructive requirements and technology. The estimated obligations and actual costs may change significantly due to changes in and regulations, technology, timing of the expenditure, and the discount rates used to determine the net present value of the obligations. See note 10. |
| (iv) | Deferred taxes. Deferred tax assets and liabilities are measured using enacted or substantively enacted tax rates at the reporting date in effect for the period in which the temporary differences are expected to be recovered or settled. The effect on deferred tax assets and liabilities of a change in tax rates is recognized as part of the provision for income taxes in the period that includes the enactment date. The recognition of deferred tax assets is based on the assumption that it is probable that taxable profit will be available against which the deductible temporary differences can be utilized. |
| (v) | Allowance for doubtful accounts. The Company maintains an allowance for doubtful accounts to provide for receivables which may ultimately be uncollectible. The allowance is determined in light of a number of factors including company specific conditions, economic events and the Company’s historical loss experience. The allowance is assessed quarterly by a detailed formal review of accounts receivable balances. See note 19(b). |
| (vi) | Stock-based compensation. The Company uses the Black-Scholes option pricing model in determining stock-based compensation expense, which requires a number of assumptions to be made, including the risk-free interest rate, expected option life, forfeiture rate, and expected share price volatility. Consequently, the actual stock based compensation expense may vary from the amount estimated. See note 12. |
Estimates and underlying assumptions are reviewed on an ongoing basis. Revisions to accounting estimates are recognized in the year in which the estimates are revised and in any future years affected.
5. DETERMINATION OF FAIR VALUE
A number of the Company’s accounting policies and disclosures require the determination of fair value, for both financial and non-financial assets and liabilities. Fair values have been determined for measurement and/or disclosure purposes based on the following methods. When applicable, further information about the assumptions made in determining fair values is disclosed in the notes specific to that asset or liability.
(a) Property, plant and equipment. Property, plant and equipment is recognized at fair value in a business combination. The fair value of property, plant and equipment is the estimated amount for which property, plant and equipment could be exchanged on the acquisition date between a willing buyer and a willing seller in an arm’s length transaction after proper marketing wherein the parties had each acted knowledgeably, prudently and without compulsion.
The Company estimated the FVLCTS to determine the recoverable amounts of the Company’s CGUs for impairment testing. The FVLCTS of each CGU were estimated based on consideration of the following:
| | (i) | net present value of proved plus probable reserves using a pre-tax discount rate of 10% as determined by independent qualified reserves evaluators; |
| | (ii) | management’s estimate of the fair value of undeveloped land; and |
| | (iii) | a review of the values indicated by the metrics of recent market transactions of similar assets within the oil and gas industry. |
The market value of other items of property, plant and equipment is based on the quoted market prices for similar items.
(b) Cash and cash equivalents, accounts receivable and accruals and accounts payable and accruals. The fair value of cash and cash equivalents, accounts receivable and accruals and accounts payable and accruals is estimated as the present value of future cash flows, discounted at the market rate of interest at the reporting date. At December 31, 2011, December 31, 2010 and January 1, 2010, the fair value of these balances approximated their carrying value due to their short term to maturity.
(c) Bank loans. The fair value of bank loans approximates their carrying value, as they bear interest at floating rates and the premium charged at December 31, 2011, December 31, 2010 and January 1, 2010 was indicative by the Company’s current credit spreads.
(d) Derivatives. The fair value of forward contracts and swaps is derived from quoted prices received from financial institutions and is based on published forward price curves as at the measurement date, using the remaining contracted oil and natural gas volumes.
(e) Stock options. The fair value of employee stock options is measured using a Black-Scholes option pricing model. Measurement inputs include share price on measurement date, exercise price of the instrument, expected volatility (based on weighted average historic volatility adjusted for changes expected due to publicly available information), weighted average expected life of the instruments and forfeiture rate (both based on historical experience and general option holder behaviour), expected dividends, and the risk-free interest rate (based on government bonds).
The Company classified the fair value of its financial instruments measured at fair value according to the following hierarchy based on the amount of observable inputs used to value the instrument:
| ● | Level 1 – observable inputs such as quoted prices in active markets; |
| ● | Level 2 – inputs, other than the quoted market prices in active markets, which are observable, either directly and/or indirectly; and |
| ● | Level 3 – unobservable inputs for the asset or liability in which little or no market data exists, therefore requiring an entity to develop its own assumptions. |
| 15 | 2011 FINANCIAL STATEMENTS |
5. DETERMINATION OF FAIR VALUE (Continued)
The fair value of the derivative contracts used for risk management as shown in the consolidated statements of financial position as at December 31, 2011 and December 2010 is measured using level 2. There were no derivative contracts outstanding at January 1, 2010.
During the years ended December 31, 2011 and 2010, there were no transfers between level 1, level 2 and level 3 classified assets and liabilities.
6. PROPERTY, PLANT AND EQUIPMENT
Cost or deemed cost
| | | Oil and natural gas assets | | | Other equipment | | | Total | |
| Balance at January 1, 2010 | | $ | 469,762 | | | $ | 1,713 | | | $ | 471,475 | |
| Additions | | | 118,140 | | | | 66 | | | | 118,206 | |
| Disposals | | | (2,407 | ) | | | - | | | | (2,407 | ) |
| Balance at December 31, 2010 | | | 585,495 | | | | 1,779 | | | | 587,274 | |
| Additions | | | 183,182 | | | | 84 | | | | 183,266 | |
| Disposals | | | (14,802 | ) | | | - | | | | (14,802 | ) |
| Balance at December 31, 2011 | | $ | 753,875 | | | $ | 1,863 | | | $ | 755,738 | |
Accumulated depletion, depreciation and impairment losses
| | | Oil and natural gas assets | | | Other equipment | | | Total | |
| Opening balance at January 1, 2010 | | $ | - | | | $ | 1,075 | | | $ | 1,075 | |
Impairment loss at January 1, 2010 (note 7) | | | 67,193 | | | | - | | | | 67,193 | |
| Balance at January 1, 2010 | | | 67,193 | | | | 1,075 | | | | 68,268 | |
| Depletion and depreciation for the year | | | 45,484 | | | | 168 | | | | 45,652 | |
Impairment loss (note 7) | | | 153,165 | | | | - | | | | 153,165 | |
| Disposals | | | (484 | ) | | | - | | | | (484 | ) |
| Balance at December 31, 2010 | | $ | 265,358 | | | $ | 1,243 | | | $ | 266,601 | |
| Depletion and depreciation for the year | | | 52,794 | | | | 135 | | | | 52,929 | |
Impairment loss (note 7) | | | 35,230 | | | | - | | | | 35,230 | |
| Disposals | | | (5,969 | ) | | | - | | | | (5,969 | ) |
| Balance at December 31, 2011 | | $ | 347,413 | | | $ | 1,378 | | | $ | 348,791 | |
Carrying amounts
| | | Oil and natural gas assets | | | Other equipment | | | Total | |
| At January 1, 2010 | | $ | 402,569 | | | $ | 638 | | | $ | 403,207 | |
| At December 31, 2010 | | $ | 320,137 | | | $ | 536 | | | $ | 320,673 | |
| At December 31, 2011 | | $ | 406,462 | | | $ | 485 | | | $ | 406,947 | |
Capitalized overhead. For the year ended December 31, 2011, additions to property plant and equipment included internal overhead costs of $4.6 million (December 31, 2010 – $4.9 million).
Depletion, depreciation and impairment charges. Depletion and depreciation, impairment of property, plant and equipment, and any reversal thereof, are recognized as separate line items in the consolidated statements of operations (see note 7).
7. IMPAIRMENT LOSS AND IMPAIRMENT REVERSAL
In 2011, there were indicators of impairment and reversal of impairment for certain CGUs due to changes in forecasted commodity prices used by the Company’s independent qualified reserves evaluators when compared to December 31, 2010. Accordingly, the Company tested certain CGUs for impairment or reversal and determined that the aggregate carrying value of these CGUs was $35.2 million (net of impairment reversals of $9.7 million recorded at September 30, 2011) higher than the recoverable amount and impairments were recorded.
The recoverable amounts of the CGUs were estimated based on the fair value less costs to sell (see notes 4 and 5). Carrying amounts are calculated as the net book value of property, plant and equipment less decommissioning obligations.
The impairment losses and reversals since January 1, 2010 recognized in each CGU were as follows:
| | | Horizontal
Oil CGU | | | Deep Gas CGU | | | Shallow
Gas CGU | | | Non-Core
CGU | | | Total (1) | |
| Impairment loss at January 1, 2010 | | $ | - | | | $ | - | | | $ | 67,193 | | | $ | - | | | $ | 67,193 | |
Impairment loss for the quarter ended
March 31, 2010 | | | - | | | | 6,587 | | | | 52,827 | | | | 126 | | | | 59,540 | |
Impairment loss for the quarter ended
June 30, 2010 | | | - | | | | 3,112 | | | | - | | | | - | | | | 3,112 | |
Impairment loss for the quarter ended
September 30, 2010 | | | - | | | | 15,996 | | | | 28,286 | | | | 4,035 | | | | 48,317 | |
Impairment loss for the quarter ended
December 31, 2010 | | | - | | | | 5,384 | | | | 35,033 | | | | 1,779 | | | | 42,196 | |
Cumulative impairment loss at
December 31, 2010 | | $ | - | | | $ | 31,079 | | | $ | 183,339 | | | $ | 5,940 | | | $ | 220,358 | |
Impairment loss (reversal) for the
quarter ended September 30, 2011 | | | - | | | | (9,725 | ) | | | 3,207 | | | | 5,444 | | | | (1,074 | ) |
Impairment loss for the quarter ended
December 31, 2011 | | | - | | | | 12,328 | | | | 22,582 | | | | 1,394 | | | | 36,304 | |
Cumulative impairment loss at
December 31, 2011 | | $ | - | | | $ | 33,682 | | | $ | 209,128 | | | $ | 12,778 | | | $ | 255,588 | |
| | | | | | | | | | | | | | | | | | | | | |
| Carrying amount, January 1, 2010 | | $ | 5,750 | | | $ | 116,993 | | | $ | 233,237 | | | $ | 44,795 | | | $ | 400,775 | |
| Carrying amount, December 31, 2010 | | $ | 63,687 | | | $ | 94,091 | | | $ | 124,836 | | | $ | 36,764 | | | $ | 319,378 | |
| Carrying amount, December 31, 2011 | | $ | 215,556 | | | $ | 82,090 | | | $ | 83,216 | | | $ | 24,608 | | | $ | 405,470 | |
| (1) | Carrying amounts exclude inventory and corporate assets of $2.4 million at January 1, 2010, $1.3 million at December 31, 2010 and $1.5 million at December 31, 2011. |
At December 31, 2011, if the discount rate had been two percent higher or two percent lower, the impairment losses recognized would have been revised as follows:
| | | Horizontal Oil CGU | | | Deep Gas CGU | | | Shallow Gas CGU | | | Non-Core CGU | | | Total | |
Reduction of impairment using an 8
percent discount rate | | $ | - | | | $ | (6,345 | ) | | $ | (6,281 | ) | | $ | (1,891 | ) | | $ | (14,517 | ) |
Additional impairment using a 12
percent discount rate | | $ | - | | | $ | 5,408 | | | $ | 5,342 | | | $ | 1,558 | | | $ | 12,308 | |
| 17 | 2011 FINANCIAL STATEMENTS |
7. IMPAIRMENT LOSS AND IMPAIRMENT REVERSAL (Continued)
The following table shows the differences in the future commodity prices used by the Company’s independent qualified reserves evaluators at December 31, 2011 compared to December 31, 2010 for certain commodities:
| | | Light, Sweet Crude Edmonton ($Cdn/bbl) | | | AECO Gas Price ($Cdn/MMBTU) | |
| Year | | December 31, 2011 | | | December 31, 2010 | | | Difference | | | December 31, 2011 | | | December 31, 2010 | | | Difference | |
| 2012 | | | 97.96 | | | | 89.29 | | | | 8.67 | | | | 3.49 | | | | 4.74 | | | | (1.25 | ) |
| 2013 | | | 101.02 | | | | 90.92 | | | | 10.10 | | | | 4.13 | | | | 5.31 | | | | (1.18 | ) |
| 2014 | | | 101.02 | | | | 92.96 | | | | 8.06 | | | | 4.59 | | | | 5.77 | | | | (1.18 | ) |
| 2015 | | | 101.02 | | | | 96.19 | | | | 4.83 | | | | 5.05 | | | | 6.22 | | | | (1.17 | ) |
| 2016 | | | 101.02 | | | | 98.62 | | | | 2.40 | | | | 5.51 | | | | 6.53 | | | | (1.02 | ) |
| 2017 | | | 101.02 | | | | 101.39 | | | | (0.37 | ) | | | 5.97 | | | | 6.76 | | | | (0.79 | ) |
| 2018 | | | 102.40 | | | | 103.92 | | | | (1.52 | ) | | | 6.21 | | | | 6.90 | | | | (0.69 | ) |
| 2019 | | | 104.47 | | | | 106.68 | | | | (2.21 | ) | | | 6.33 | | | | 7.06 | | | | (0.73 | ) |
| 2020 | | | 106.58 | | | | 108.84 | | | | (2.26 | ) | | | 6.46 | | | | 7.21 | | | | (0.75 | ) |
8. BANK LOANS
At December 31, 2011, total bank facilities were $135 million consisting of a $110 million extendible revolving term credit facility, a $10 million working capital credit facility and a $15 million supplemental credit facility, with a syndicate of Canadian banks. The extendible revolving term credit facility and the working capital credit facility have a revolving period ending on July 11, 2012. If not extended, the extendible revolving term credit facility and working capital credit facility cease to revolve and all outstanding advances thereunder become repayable one year from the term date of July 11, 2012. The supplemental facility expires on July 11, 2012, with any outstanding amounts due in full at that time. At December 31, 2011, there were no amounts drawn under the supplemental facility.
The average effective interest rate on advances under the facilities in 2011 was 5.3% (December 31, 2010 – 4.9%). The Company had $133,500 in letters of credit outstanding at December 31, 2011 that reduce the amount of credit available to the Company.
Advances under the facilities can be drawn in either Canadian or U.S. funds and bear interest at the bank’s prime lending rate, bankers’ acceptance or LIBOR loan rates plus applicable margins. These margins vary from 1.50% to 6.00% depending on the borrowing option used and the Company’s financial ratios.
Loans are secured by a floating charge debenture over all assets and guarantees by material subsidiaries.
The available lending limits of the facilities are reviewed semi-annually and are based on the bank syndicate’s interpretations of the Company’s reserves and future commodity prices. There can be no assurance that the amount of the available facilities or the applicable margins will not be adjusted at the next scheduled review on or before July 11, 2012.
9. CONVERTIBLE DEBENTURES
On June 8, 2011, the Company issued $46 million of convertible unsecured subordinated debentures (the “Series B Debentures”) on a bought deal basis. The Series B Debentures have a face value of $1,000, bear interest at the rate of 7.25% per annum payable semi-annually in arrears on the last day of June and December of each year commencing on December 31, 2011 and mature on June 30, 2017 (“Maturity Date”). The Series B Debentures are convertible at the holder’s option at a conversion price of $1.70 per common share (the “Conversion Price”), subject to adjustment in certain events. The Series B Debentures are not redeemable by the Company before June 30, 2014. On and after June 30, 2014 and prior to June 30, 2016, the Series B Debentures are redeemable at the Company’s option, in whole or in part, at a price equal to their principal amount plus accrued and unpaid interest if the weighted average trading price of the common shares on the Toronto Stock Exchange for the 20 consecutive trading days preceding the date on which the notice of redemption is given is not less than 125% of the Conversion Price. On or after June 30, 2016 and prior to the Maturity Date, the Series B Debentures may be redeemed in whole or in part at the option of the Company on not more than 60 days and not less than 30 days prior notice at a price equal to their principal amount plus accrued and unpaid interest. The Series B Debentures are listed and posted for trading on the TSX under the symbol “AXL.DB.B”.
On December 31, 2010, the Company issued $50 million of convertible unsecured subordinated debentures (the “Series A Debentures”) on a bought deal basis. The Series A Debentures have a face value of $1,000, bear interest at the rate of 7.5% per annum payable semi-annually in arrears on the last day of January and July of each year commencing on July 31, 2011 and mature on January 31, 2016 (the “Maturity Date”). The Series A Debentures are convertible at the holder’s option at a conversion price of $1.55 per common share (the “Conversion Price”), subject to adjustment in certain events. The Series A Debentures are not redeemable by the Company before January 31, 2014. On or after January 31, 2014 and prior to the Maturity Date, the Series A Debentures are redeemable at the Company’s option, in whole or in part, at a price equal to their principal amount plus accrued and unpaid interest if the weighted average trading price of the common shares on the Toronto Stock Exchange for the 20 consecutive trading days preceding the date on which the notice of redemption is given is not less than 125% of the Conversion Price. The Series A Debentures are listed and posted for trading on the TSX under the symbol “AXL.DB”.
Both the Series A and the Series B Debentures were determined to be compound instruments. As the Series A and Series B Debentures are convertible into common shares, the liability and equity components are presented separately. The initial carrying amount of the financial liability is determined by discounting the stream of future payments of interest and principal. Using the residual method, the carrying amount of the conversion feature is the difference between the principal amount and the carrying value of the financial liability. The Series A and Series B Debentures, net of the equity component and issue costs are accreted using the effective interest rate method over the term of the Series A and Series B Debentures, such that the carrying amount of the financial liability will equal the $50 million and $46 million principal balance at maturity respectively.
| 19 | 2011 FINANCIAL STATEMENTS |
9. CONVERTIBLE DEBENTURES (Continued)
The following table indicates the convertible debenture activities:
| | | Proceeds | | | Debt component | | | Equity component | |
| | | | | | | | | | |
| Balance, January 1, 2010 | | $ | - | | | $ | - | | | $ | - | |
Series A Debentures issued pursuant to prospectus,
7.5% interest rate, due January 31, 2016(1) | | | 50,000 | | | | 45,553 | | | | 4,447 | |
| Issue costs | | | (2,300 | ) | | | (2,095 | ) | | | (205 | ) |
| Deferred tax | | | - | | | | - | | | | (1,650 | ) |
| Accretion expense | | | - | | | | 2 | | | | - | |
| Balance, December 31, 2010 | | $ | 47,700 | | | $ | 43,460 | | | $ | 2,592 | |
Series B Debentures issued pursuant to prospectus,
7.25% interest rate, due June 30, 2017(2) | | | 46,000 | | | | 41,849 | | | | 4,151 | |
| Issue costs | | | (2,140 | ) | | | (1,947 | ) | | | (193 | ) |
| Deferred tax | | | - | | | | - | | | | (1,531 | ) |
| Accretion expense | | | - | | | | 1,434 | | | | - | |
| Balance, December 31, 2011 | | $ | 91,560 | | | $ | 84,796 | | | $ | 5,019 | |
(1) Includes 1,000 Series A Debentures issued to directors for total gross proceeds of $1.0 million.
(2) Includes 1,575 Series B Debentures issued to management and directors for total gross proceeds of $1.6 million.
10. DECOMMISSIONING OBLIGATIONS
| | | December 31, 2011 | | | December 31, 2010 | |
| Balance at January 1 | | $ | 51,550 | | | $ | 47,657 | |
| Provisions incurred | | | 4,878 | | | | 2,945 | |
| Total abandonment expenditures | | | (249 | ) | | | (1,549 | ) |
| Provisions disposed | | | (1,316 | ) | | | (75 | ) |
| Change in estimates | | | 6,355 | | | | 918 | |
| Accretion expense | | | 1,630 | | | | 1,654 | |
| Ending balance | | $ | 62,848 | | | $ | 51,550 | |
The Company’s decommissioning obligations result from its ownership interest in oil and natural gas assets including well sites and gathering systems. The Company has estimated the net present value of the decommissioning obligations to be $62.8 million as at December 31, 2011 (December 31, 2010 – $51.6 million) based on an undiscounted inflation-adjusted total future liability of $80.8 million (December 31, 2010 – $72.9 million). These payments are expected to be made over the next 25 years with the majority of costs to be incurred between 2012 and 2030. At December 31, 2011 the liability has been calculated using an inflation rate of 2.0% (December 31, 2010 – 2.0%) and discounted using a risk-free rate of 0.9% to 3.1% (December 31, 2010 – 0.8% to 4.4%) depending on the estimated timing of the future obligation.
11. TAXES
The temporary differences that gave rise to the Company’s deferred income tax liabilities (assets) at December 31, 2011, December 31, 2010 and January 1, 2010 were as follows:
| | | December 31, 2011 | | | December 31, 2010 | | | January 1, 2010 | |
| Deferred income tax liabilities (assets): | | | | | | | | | |
| Property, plant and equipment | | $ | 1,395 | | | $ | (275 | ) | | $ | 33,296 | |
| Decommissioning obligations | | | (15,712 | ) | | | (12,888 | ) | | | (11,914 | ) |
| Derivative contracts | | | 346 | | | | (508 | ) | | | - | |
| Convertible debentures | | | 2,820 | | | | 1,650 | | | | - | |
| Share issue costs | | | (1,909 | ) | | | (2,229 | ) | | | (1,985 | ) |
| Non-capital losses | | | (29,843 | ) | | | (18,004 | ) | | | (9,289 | ) |
| Current income deferred | | | 7,514 | | | | 2,597 | | | | 812 | |
| Ending balance | | $ | (35,389 | ) | | $ | (29,657 | ) | | $ | 10,920 | |
The Company has recognized a net deferred tax asset based on the independently evaluated reserves report as cash flows are expected to be sufficient to realize the deferred tax asset.
The provision for income taxes differs from the result that would have been obtained by applying the combined federal and provincial tax rates to the loss before income taxes. The difference results from the following items:
| | | December 31, 2011 | | | December 31, 2010 | |
| Loss before taxes | | $ | (29,707 | ) | | $ | (166,506 | ) |
| Combined federal and provincial tax rates | | | 26.5 | % | | | 28.0 | % |
| Expected deferred income tax benefit | | | (7,872 | ) | | | (46,622 | ) |
| Increase in income taxes resulting from: | | | | | | | | |
| Changes in expected deferred tax rates | | | 365 | | | | 4,624 | |
| Non-deductible stock-based compensation and other | | | 244 | | | | 279 | |
| Deferred income tax benefit | | $ | (7,263 | ) | | $ | (41,719 | ) |
At December 31, 2011, the Company has loss carryforwards of approximately $119 million that will expire between 2025 and 2030. The Company expects to be able to fully utilize these losses. The statutory tax rate decreased to 26.5% in 2011 from 28% in 2010 as a result of tax legislation enacted in 2007.
A continuity of the net deferred income tax (asset) liability is detailed in the following tables:
| (in thousands of dollars) | | Balance January 1, 2010 | | | Recognized in profit or loss | | | Recognized in equity | | | Balance December 31, 2010 | |
| Property, plant and equipment | | $ | 33,296 | | | $ | (33,570 | ) | | $ | - | | | $ | (275 | ) |
| Decommissioning obligations | | | (11,914 | ) | | | (974 | ) | | | - | | | | (12,888 | ) |
| Derivative contracts | | | - | | | | (508 | ) | | | - | | | | (508 | ) |
Convertible debentures (note 9) | | | - | | | | - | | | | 1,650 | | | | 1,650 | |
Share issue costs (note 12) | | | (1,985 | ) | | | 263 | | | | (507 | ) | | | (2,229 | ) |
| Non-capital losses | | | (9,289 | ) | | | (8,715 | ) | | | - | | | | (18,004 | ) |
| Current income deferred | | | 812 | | | | 1,785 | | | | - | | | | 2,597 | |
| | | $ | 10,920 | | | $ | (41,719 | ) | | $ | 1,143 | | | $ | (29,657 | ) |
| 21 | 2011 FINANCIAL STATEMENTS |
11. TAXES (Continued)
| (in thousands of dollars) | | Balance January 1, 2011 | | | Recognized in profit or loss | | | Recognized in equity | | | Balance December 31, 2011 | |
| Property, plant and equipment | | $ | (275 | ) | | $ | 1,670 | | | $ | - | | | $ | 1,395 | |
| Decommissioning obligations | | | (12,888 | ) | | | (2,824 | ) | | | - | | | | (15,712 | ) |
| Derivative contracts | | | (508 | ) | | | 854 | | | | - | | | | 346 | |
Convertible debentures (note 9) | | | 1,650 | | | | (361 | ) | | | 1,531 | | | | 2,820 | |
| Share issue costs | | | (2,229 | ) | | | 320 | | | | - | | | | (1,909 | ) |
| Non-capital losses | | | (18,004 | ) | | | (11,839 | ) | | | - | | | | (29,843 | ) |
| Current income deferred | | | 2,597 | | | | 4,917 | | | | - | | | | 7,514 | |
| | | $ | (29,657 | ) | | $ | (7,263 | ) | | $ | 1,531 | | | $ | (35,389 | ) |
12. SHARE CAPITAL
Authorized share capital. The Company is authorized to issue an unlimited number of common and preferred shares. The preferred shares may be issued in one or more series.
Issued share capital.
| | | Number of Common Shares | | | Amount | |
| Balance at January 1, 2010 | | | 150,500,401 | | | $ | 396,524 | |
Issued pursuant to prospectus(1) | | | 21,900,000 | | | | 31,755 | |
| Share issue costs | | | - | | | | (1,963 | ) |
| Tax effect of share issue costs | | | - | | | | 507 | |
| Stock options exercised | | | 84,900 | | | | 67 | |
| Transferred from contributed surplus on stock option exercise | | | - | | | | 35 | |
| Balance at December 31, 2010 | | | 172,485,301 | | | $ | 426,925 | |
| | | | | | | | | |
| Elimination of deficit | | | - | | | | (255,543 | ) |
| Stock options exercised | | | 64,400 | | | | 51 | |
| Transferred from contributed surplus on stock option exercise | | | - | | | | 27 | |
| Balance at December 31, 2011 | | | 172,549,701 | | | $ | 171,460 | |
(1) Includes 352,466 common shares issued to directors for total gross proceeds of $0.5 million.
Elimination of deficit. On May 16, 2011, the Company’s shareholders approved the elimination of the Company’s consolidated deficit as at January 1, 2011, without reduction to the Company’s stated capital or paid up capital.
Stock options. The Company has an employee stock option plan under which employees, directors and consultants are eligible to purchase common shares of the Company. Options are granted using an exercise price of stock options equal to the weighted average trading price of the Company’s common shares for the five trading days prior to the date of the grant. Options have terms of either five or ten years and vest equally over a three year period starting on the first anniversary date of the grant. Changes in the number of options outstanding during the years ended December 31, 2011 and 2010 are as follows:
12. SHARE CAPITAL (Continued)
| | | December 31, 2011 | | | December 31, 2010 | |
| | | Number of options | | | Weighted average exercise price | | | Number of options | | | Weighted average exercise price | |
| Outstanding at January 1 | | | 12,006,232 | | | $ | 2.32 | | | | 10,258,756 | | | $ | 3.22 | |
| Granted during the year | | | 4,484,800 | | | | 0.74 | | | | 3,950,250 | | | | 1.06 | |
| Exercised during the year | | | (64,400 | ) | | | 0.79 | | | | (84,900 | ) | | | 0.79 | |
| Expired during the year | | | (1,564,150 | ) | | | 4.27 | | | | (1,430,124 | ) | | | 5.78 | |
| Forfeited during the year | | | (848,300 | ) | | | 1.01 | | | | (687,750 | ) | | | 1.44 | |
| Ending balance | | | 14,014,182 | | | $ | 1.69 | | | | 12,006,232 | | | $ | 2.32 | |
| | | | | | | | | | | | | | | | | |
| Exercisable, end of year | | | 6,764,582 | | | $ | 2.60 | | | | 6,111,399 | | | $ | 3.53 | |
The range of exercise prices of the outstanding options is as follows:
| Range of exercise prices | | Number of options | | | Weighted average exercise price | | | Weighted average remaining life (years) | |
| | | | | | | | | | |
| $0.45 to $0.67 | | | 172,500 | | | $ | 0.48 | | | | 4.9 | |
| $0.68 to $1.02 | | | 6,255,100 | | | | 0.74 | | | | 3.8 | |
| $1.03 to $1.54 | | | 3,620,950 | | | | 1.08 | | | | 3.6 | |
| $2.33 to $3.50 | | | 625,950 | | | | 2.68 | | | | 1.6 | |
| $3.51 to $4.90 | | | 3,339,682 | | | | 4.00 | | | | 0.6 | |
| Total at December 31, 2011 | | | 14,014,182 | | | $ | 1.69 | | | | 2.9 | |
The weighted average common share price at the date of exercise for stock options exercised in 2011 was $1.20 (December 31, 2010 – $1.02).
The fair value of the options was estimated using the Black-Scholes model with the following weighted average inputs:
| | | December 31, 2011 | | | December 31, 2010 | |
| Fair value at grant date | | $ | 0.38 | | | $ | 0.55 | |
| Common share price | | $ | 0.74 | | | $ | 1.06 | |
| Exercise price | | $ | 0.74 | | | $ | 1.06 | |
| Volatility | | | 59% | | | | 58% | |
| Option life | | 5 years | | | 5 years | |
| Dividends | | | 0% | | | | 0% | |
| Risk-free interest rate | | | 1.7% | | | | 2.3% | |
| Forfeiture rate | | | 15% | | | | 15% | |
This estimated forfeiture rate is adjusted to the actual forfeiture rate when each tranche vests. Stock-based compensation cost of $1.0 million (December 31, 2010 – $1.0 million) was expensed during the year ended December 31, 2011. In addition, stock-based compensation expense of $0.5 million (December 31, 2010 – $0.6 million) was capitalized during the year ended December 31, 2011.
| 23 | 2011 FINANCIAL STATEMENTS |
13. LOSS PER SHARE
Basic and diluted loss per share were calculated as follows:
| | | December 31, 2011 | | | December 31, 2010 | |
| Loss for the year | | $ | (22,444 | ) | | $ | (124,787 | ) |
Weighted average number of common shares (basic) (in thousands of shares) | | | | | | | | |
| Common shares outstanding at January 1 | | | 172,485 | | | | 150,500 | |
| Effect of stock options exercised | | | 53 | | | | 17 | |
| Effect of other shares issued | | | - | | | | 19,782 | |
| Weighted average number of common shares (basic) | | | 172,538 | | | | 170,299 | |
Basic and diluted loss per share | | $ | (0.13 | ) | | $ | (0.73 | ) |
The average market value of the Company’s common shares for purposes of calculating the dilutive effect of stock options was based on quoted market prices for the period that the options were outstanding. For the year ended December 31, 2011, 14,014,182 options (December 31, 2010 – 12,006,232 options) and 59,316,889 common shares reserved for convertible debentures (December 31, 2010 – 32,258,065) were excluded from calculating dilutive earnings as they were anti-dilutive.
14. SUPPLEMENTAL REVENUE AND EXPENSE RECOVERY INFORMATION
Revenues for all product sales and services and expense recoveries are as follows:
| | | December 31, 2011 | | | December 31, 2010 | |
| Revenue from oil and gas sales, net of royalties | | $ | 104,486 | | | $ | 77,446 | |
| | | | | | | | | |
| Other income (expense): | | | | | | | | |
| Realized loss on derivative contracts | | $ | (624 | ) | | $ | (131 | ) |
| Unrealized gain (loss) on derivative contracts | | | 3,302 | | | | (1,918 | ) |
| Gain on sale of property, plant and equipment | | | 4,710 | | | | 389 | |
| | | $ | 7,388 | | | $ | (1,660 | ) |
| | | | | | | | |
| Expenses recovered from third parties: | | | | | | | | |
Operating expense recoveries for use of transportation
and processing assets | | $ | 2,864 | | | $ | 2,860 | |
General and administrative overhead expense recoveries | | | 568 | | | | 540 | |
| | | $ | 3,432 | | | $ | 3,400 | |
Major customers. For the year ended December 31, 2011, revenues of $33.9 million (December 31, 2010 – $43.2 million), $30.8 million (December 31, 2010 – $2.2 million) and $28.6 million (December 31, 2010 – $16.0 million) were derived from the external customers who individually amounted to 10 percent or more of the Company’s revenues.
15. EXPENSES BY NATURE
| | | December 31, 2011 | | | December 31, 2010 | |
External services(1) | | $ | 9,970 | | | $ | 8,093 | |
| Third-party gathering, processing and treating services | | | 8,790 | | | | 9,508 | |
Employee benefit expenses (note 16) | | | 7,229 | | | | 6,640 | |
Operating leases and equipment rents(2) | | | 3,893 | | | | 3,781 | |
| Repairs and maintenance | | | 3,494 | | | | 2,680 | |
| Materials and supplies | | | 2,313 | | | | 1,456 | |
| Other expenses | | | 4,249 | | | | 5,796 | |
| Expenses by nature | | $ | 39,938 | | | $ | 37,954 | |
| | | | | | | | | |
Above costs allocated to the following functions: | | | | | | | | |
| Operating | | $ | 29,533 | | | $ | 28,537 | |
| General and administrative | | | 10,405 | | | | 9,417 | |
| Total operating and general and administrative expenses | | $ | 39,938 | | | $ | 37,954 | |
| | (1) | External services include professional fees, contract operators, consulting fees, design fees and other operating and administrative services. |
| | (2) | Operating leases and equipment rents include office leases, surface leases, and equipment rents. |
16. EMPLOYEE BENEFIT EXPENSES
General and administrative expenses include employee benefit expense as follows:
| | | December 31, 2011 | | | December 31, 2010 | |
| Short-term employee benefits | | $ | 9,726 | | | $ | 9,190 | |
| Share-based payments | | | 1,491 | | | | 1,619 | |
| Total employee remuneration | | | 11,217 | | | | 10,809 | |
| Capitalized portion of employee remuneration | | | (3,988 | ) | | | (4,169 | ) |
| | | $ | 7,229 | | | $ | 6,640 | |
Employees include all staff and directors of the Company. Personnel expenses directly attributed to capital activities have been capitalized and included in property, plant and equipment.
17. FINANCE INCOME AND EXPENSES
| | | December 31, 2011 | | | December 31, 2010 | |
| Income: | | | | | | |
| Interest income on cash equivalents | | $ | 6 | | | $ | - | |
| Other | | | 78 | | | | 96 | |
| Expenses: | | | | | | | | |
| Interest and financing costs on bank loans | | | (3,201 | ) | | | (3,306 | ) |
| Interest on convertible debentures | | | (5,631 | ) | | | (11 | ) |
| Accretion on convertible debentures | | | (1,434 | ) | | | (2 | ) |
| Accretion on decommissioning obligations | | | (1,630 | ) | | | (1,654 | ) |
| Other | | | (46 | ) | | | (33 | ) |
| Net finance expenses | | $ | (11,858 | ) | | $ | (4,910 | ) |
| 25 | 2011 FINANCIAL STATEMENTS |
18. SUPPLEMENTAL CASH FLOW INFORMATION
Changes in non-cash working capital is comprised of:
| | | December 31, 2011 | | | December 31, 2010 | |
| Source (use) of cash | | | | | | |
| Accounts receivable and accruals | | $ | 6,726 | | | $ | 1,992 | |
| Prepaid expenses and deposits | | | 726 | | | | 726 | |
| Accounts payable and accruals | | | 13,711 | | | | 9,973 | |
| | | $ | 21,163 | | | $ | 12,691 | |
Related to operating activities | | $ | 94 | | | $ | 5,365 | |
| Related to financing activities | | $ | (324 | ) | | $ | 384 | |
| Related to investing activities | | $ | 21,393 | | | $ | 6,942 | |
19. FINANCIAL RISK MANAGEMENT
(a) Overview. The Company’s activities expose it to a variety of financial risks that arise as a result of its exploration, development, production, and financing activities such as:
This note presents information about the Company’s exposure to each of the above risks, the Company’s objectives, policies and processes for measuring and managing risk, and the Company’s management of capital. Further quantitative disclosures are included throughout these consolidated financial statements.
The Board of Directors oversees management’s establishment and execution of the Company’s risk management framework. Management has implemented and monitors compliance with risk management policies. The Company’s risk management policies are established to identify and analyze the risks faced by the Company, to set appropriate risk limits and controls, and to monitor risks and adherence to market conditions and the Company’s activities.
(b) Credit risk. Credit risk is the risk of financial loss to the Company if a customer or counterparty to a financial instrument fails to meet its contractual obligations, and arises principally from the Company’s receivables from joint venture partners and oil and natural gas customers. The maximum exposure to credit risk is as follows:
| | | December 31, 2011 | | | December 31, 2010 | | | January 1, 2010 | |
| Cash and cash equivalents | | $ | 1 | | | $ | 4,024 | | | $ | 1 | |
| Accounts receivable and accruals | | | 14,272 | | | | 20,998 | | | | 22,990 | |
| | | $ | 14,273 | | | $ | 25,022 | | | $ | 22,991 | |
Accounts receivable and accruals. All of the Company’s operations are conducted in Canada. The Company’s exposure to credit risk is influenced mainly by the individual characteristics of each customer or joint venture partner.
A substantial portion of the Company’s accounts receivable are with customers in the oil and gas industry and are subject to normal industry credit risks. Receivables from oil and natural gas customers are normally collected on the 25th day of the month following the related sale of oil and gas production. The Company’s policy to mitigate credit risk associated with these balances is to establish commercial relationships with large customers. The Company historically has not experienced any collection issues with its oil and natural gas customers. Receivables from joint venture partners are typically collected within ninety days.
19. FINANCIAL RISK MANAGEMENT (Continued)
The Company attempts to mitigate the risk from joint venture receivables by obtaining venturer pre-approval of significant capital expenditures. However, the receivables are from participants in the oil and natural gas sector, and collection of the outstanding balances is dependent on industry factors such as commodity price fluctuations, escalating costs and the risk of unsuccessful drilling. In addition, further risk exists with joint venturers as disagreements occasionally arise that increase the potential for non-collection.
The Company does not typically obtain collateral from oil and natural gas customers or joint venturers; however, the Company does have the ability to withhold production from joint venturers in the event of non-payment.
The Company’s allowance for doubtful accounts as at December 31, 2011 was $0.9 million (December 31, 2010 – $1.0 million, January 1, 2010 - $1.6 million). This allowance was mostly created in prior years and is associated with prior corporate acquisitions and potential joint venture billing disputes. The Company wrote-off $0.1 million in receivables during the year ended December 31, 2011 (December 31, 2010 – $0.6 million). The Company would only choose to write-off a receivable balance (as opposed to providing an allowance) after all reasonable avenues of collection had been exhausted.
The maximum exposure to credit risk for accounts receivable and accruals, net of allowance for doubtful accounts at the reporting date by type of customer was:
| | | Carrying Amount | |
| | | December 31, 2011 | | | December 31, 2010 | | | January 1, 2010 | |
| Oil and natural gas customers | | $ | 10,307 | | | $ | 9,286 | | | $ | 8,213 | |
| Joint venture partners | | | 2,335 | | | | 7,989 | | | | 7,790 | |
| Other | | | 1,630 | | | | 3,723 | | | | 6,987 | |
| | | $ | 14,272 | | | $ | 20,998 | | | $ | 22,990 | |
As at December 31, 2011, December 31, 2010 and January 1, 2010, the Company’s accounts receivable and accruals, net of allowance for doubtful accounts was aged as follows:
| Aging | | December 31, 2011 | | | December 31, 2010 | | | January 1, 2010 | |
| Not past due | | $ | 13,608 | | | $ | 18,960 | | | $ | 22,402 | |
| Past due by less than 120 days | | | 163 | | | | 1,706 | | | | 537 | |
| Past due by more than 120 days | | | 501 | | | | 332 | | | | 51 | |
| Total | | $ | 14,272 | | | $ | 20,998 | | | $ | 22,990 | |
These amounts exclude offsetting amounts owing to joint venture partners that are included in accounts payable and accruals.
(c) Liquidity risk. Liquidity risk is the risk that the Company will not be able to meet its financial obligations as they fall due. The Company’s objective is to ensure, as far as possible, that it will always have sufficient liquidity to meet its liabilities when due, under both normal and stressed conditions, without incurring unacceptable losses or risking damage to the Company’s reputation.
To achieve this objective, the Company prepares annual capital expenditure budgets, which are regularly monitored and updated as considered necessary. The Company uses authorizations for expenditures on both operated and non operated projects to further manage capital expenditures. To provide capital when needed, the Company has revolving reserves-based credit facilities which are reviewed semi-annually by its lenders. These facilities are described in note 8. The Company also attempts to match its payment cycle with collection of oil and natural gas revenue on the 25th of each month.
| 27 | 2011 FINANCIAL STATEMENTS |
19. FINANCIAL RISK MANAGEMENT (Continued)
The following are the contractual maturities of financial liabilities, including associated interest payments on convertible debentures and excluding the impact of netting agreements at December 31, 2011:
| Financial Liabilities | | Less than one year | | | One to two years | | | Two to three years | | | Three to four years | | | Four to five years | | | Five to six years | |
| Non-derivative financial liabilities | | | | | | | | | | | | | | | | | | |
Accounts payable and accruals (1) | | $ | 60,573 | | | $ | - | | | $ | - | | | $ | - | | | $ | - | | | $ | - | |
Bank loans – principal (2) | | | - | | | | 88,682 | | | | - | | | | - | | | | - | | | | - | |
| Convertible debentures | | | | | | | | | | | | | | | | | | | | | | | | |
- Interest (1) | | | 5,523 | | | | 7,085 | | | | 7,085 | | | | 7,085 | | | | 5,210 | | | | 1,667 | |
| - Principal | | | - | | | | - | | | | - | | | | - | | | | 50,000 | | | | 46,000 | |
| Total | | $ | 66,096 | | | $ | 95,767 | | | $ | 7,085 | | | $ | 7,085 | | | $ | 55,210 | | | $ | 47,667 | |
| | (1) | Accounts payable and accruals includes $3.4 million of interest relating to convertible debentures. The total cash interest payable in less than one year on the convertible debentures is $9.0 million. |
| | (2) | Assumes the credit facilities are not renewed on July 11, 2012. |
The following table shows the Company’s accounts payable and accruals:
| | | Carrying Amount | |
| | | December 31, 2011 | | | December 31, 2010 | | | January 1, 2010 | |
| Trade payables | | $ | 24,188 | | | $ | 19,550 | | | $ | 19,443 | |
Accruals (1) | | | 36,385 | | | | 27,312 | | | | 17,446 | |
| | | $ | 60,573 | | | $ | 46,862 | | | $ | 36,889 | |
(1) Accruals include amounts for goods and services that have been received or supplied but have not been paid, invoiced or formally agreed with the supplier as of the reporting date. These accruals relate to both operating and capital activities.
(d) Market risk. Market risk is the risk that changes in market prices, such as commodity prices, foreign exchange rates and interest rates will affect the Company’s income or the value of the financial instruments. The objective of market risk management is to manage and control market risk exposures within acceptable parameters, while optimizing the return.
The Company may use both financial derivatives and physical delivery sales contracts to manage market risks. All such transactions are conducted within risk management tolerances that are reviewed by the Board of Directors.
Currency risk. Prices for oil are determined in global markets and generally denominated in United States dollars. Natural gas prices obtained by the Company are influenced by both U.S. and Canadian demand and the corresponding North American supply, and recently, by imports of liquefied natural gas. The exchange rate effect cannot be quantified but generally an increase in the value of the Canadian dollar as compared to the U.S. dollar will reduce the prices received by the Company for its petroleum and natural gas sales.
There were no financial instruments denominated in U.S. dollars at December 31, 2011 or December 31, 2010.
Interest rate risk. Interest rate risk is the risk that future cash flows will fluctuate as a result of changes in market interest rates. The interest charged on the outstanding bank loans fluctuates with the interest rates posted by the lenders. The Company has not entered into any mitigating interest rate hedges or swaps, however the Company has $50 million and $46 million of convertible debentures with fixed interest rates of 7.5% and 7.25% respectively, maturing January 31, 2016 and June 30, 2017 (see note 9). Had the borrowing rate on bank loans been 100 basis points higher (or lower) throughout the year ended December 31, 2011, earnings would have been affected by $0.4 million (December 31, 2010 – $0.3 million) based on the average bank debt balance outstanding during the year.
19. FINANCIAL RISK MANAGEMENT (Continued)
Commodity price risk. Commodity price risk is the risk that the fair value or future cash flows will fluctuate as a result of changes in commodity prices. Commodity prices for oil and natural gas are impacted by both the relationship between the Canadian and U.S. dollar and world economic events that dictate the levels of supply and demand.
It is the Company’s policy to economically hedge some oil and natural gas sales through the use of various financial derivative forward sales contracts and physical sales contracts. The Company does not apply hedge accounting for these contracts. The Company’s production is usually sold using “spot” or near term contracts, with prices fixed at the time of transfer of custody or on the basis of a monthly average market price. The Company, however, may give consideration in certain circumstances to the appropriateness of entering into long term, fixed price sales contracts. The Company does not enter into commodity contracts other than to meet the Company’s expected sale requirements.
At December 31, 2011 the following derivative contracts were outstanding and recorded at estimated fair value:
Type of Contract(1) | Commodity | Volume | Weighted Average Fixed Price (NYMEX Canadian $) | Remaining Period |
| Financial swap | Crude oil | 500 bbls/day | $106.04/bbl | Jan 1, 2012 to Mar 31, 2012 |
| Financial swap | Crude oil | 1,000 bbls/day | $103.93/bbl | Jan 1, 2012 to Dec 31, 2012 |
| (1) | Swap indicates fixed price payable to Anderson in exchange for floating price payable to counterparty. |
The estimated fair value of the financial oil contracts has been determined on the amounts the Company would receive or pay to terminate the oil contracts. At December 31, 2011, the Company estimates that it would receive $1.4 million to terminate these contracts.
There were no derivative contracts outstanding at January 1, 2010. The fair value of the financial commodity risk management contracts have been allocated to current and non-current liabilities on a contract by contract basis as follows:
| | | December 31, 2011 | | | December 31, 2010 | |
| Current asset | | $ | 1,384 | | | $ | - | |
| Current liability | | | - | | | | (1,918 | ) |
| Net asset (liability) position | | $ | 1,384 | | | $ | (1,918 | ) |
The fair value of derivative contracts at December 31, 2011 would have been impacted as follows had the oil prices used to estimate the fair value changed by:
| | | Effect of an increase in price on after-tax earnings | | Effect of a decrease in price on after-tax earnings |
| Canadian $1.00 per barrel change in the oil prices | $ | (412) | $ | 412 |
In January 2012, the Company entered into fixed price swap contracts for an average of 500 barrels per day of crude oil for February to December 2012 at a weighted average NYMEX crude oil price of Canadian $103.75 per barrel.
In June 2011, the Company entered into physical sales contracts to sell 15,000 GJ per day of natural gas between July 1, 2011 and October 31, 2011 at a weighted average AECO price of $4.06 per GJ. The Company realized $1.2 million of gains associated with these contracts.
| 29 | 2011 FINANCIAL STATEMENTS |
19. FINANCIAL RISK MANAGEMENT (Continued)
(e) Capital management. Anderson’s capital management policy is to maintain a strong, but flexible capital structure that optimizes the cost of capital and maintains investor, creditor and market confidence while sustaining the future development of the business.
The Company manages its capital structure and makes adjustments to it in the light of changes in economic conditions and the risk characteristics of the underlying petroleum and natural gas assets. The Company’s capital structure includes shareholders’ equity of $163.4 million, bank loans of $88.7 million, convertible debentures with a face value of $96.0 million and the cash working capital deficiency of $44.0 million, which excludes the current portion of unrealized gains on derivative contracts. In order to maintain or adjust the capital structure, the Company may from time to time issue shares, seek additional debt financing and adjust its capital spending to manage current and projected debt levels.
Consistent with other companies in the oil and gas sector, Anderson monitors capital based on the ratio of total debt to funds from operations. This ratio is calculated by dividing total debt at the end of the period (comprised of the cash working capital deficiency, the liability component of convertible debentures and outstanding bank loans) by the annualized current quarter funds from operations (cash flow from operating activities before changes in non-cash working capital including decommissioning expenditures). This ratio may increase at certain times as a result of acquisitions, the timing of capital expenditures and market conditions. In order to facilitate the management of this ratio, the Company prepares annual capital expenditure budgets, which are updated as necessary depending on varying factors including current and forecast crude oil and natural gas prices, capital deployment and general industry conditions. The annual and updated budgets are approved by the Board of Directors. Funds from operations in the quarter, annualized current quarter funds from operations and total net debt to funds from operations are not defined by IFRS and therefore are referred to as non-GAAP measures.
| | | December 31, 2011 | | | December 31, 2010 | |
| Bank loans | | $ | 88,682 | | | $ | 52,719 | |
Current liabilities(1) | | | 60,573 | | | | 46,862 | |
Current assets(1) | | | (16,599 | ) | | | (28,074 | ) |
| Net debt before convertible debentures | | $ | 132,656 | | | $ | 71,507 | |
| Convertible debentures (liability component) | | | 84,796 | | | | 43,460 | |
| Total net debt | | $ | 217,452 | | | $ | 114,967 | |
| | | | | | | | | |
| Cash from operating activities in the quarter | | $ | 16,462 | | | $ | 10,488 | |
| Decommissioning expenditures in the quarter | | | 146 | | | | 118 | |
| Changes in non-cash working capital in the quarter | | | 389 | | | | (1,324 | ) |
| Funds from operations in the quarter | | $ | 16,997 | | | $ | 9,282 | |
| Annualized current quarter funds from operations | | $ | 67,988 | | | $ | 37,128 | |
| | | | | | | | | |
| Net debt before convertible debentures to funds from operations | | | 2.0 | | | | 1.9 | |
| Total net debt to funds from operations | | | 3.2 | | | | 3.1 | |
(1) Excludes unrealized gains (losses) on derivative contracts.
There were no changes in the Company’s approach to capital management during the year.
19. FINANCIAL RISK MANAGEMENT (Continued)
As at December 31, 2011, the Company’s ratio of net debt before convertible debentures to annualized funds from operations was 2.0 to 1 (December 31, 2010 – 1.9 to 1). As at December 31, 2011, the Company’s ratio of total net debt to annualized funds from operations was 3.2 to 1 (December 31, 2010 – 3.1 to 1). The high ratios reflect the capital expenditures required to make the transition from a gas weighted company to an oil weighted company. The increase in the ratio from December 31, 2010 is the result higher capital spending in 2011, partially offset by higher funds from operations as a result of the transition to an oil weighted company. As new crude oil production is brought on-stream at higher expected operating margins, the debt to funds from operations ratio is expected to decrease.
Neither the Company nor any of its subsidiaries are subject to externally imposed capital requirements. The credit facilities are subject to a semi-annual review of the borrowing base which is directly impacted by the value of the oil and natural gas reserves.
20. RELATED PARTY TRANSACTIONS
Key management personnel are comprised of all officers and directors of the Company.
On June 8, 2011, the Company issued 1,575 Series B Convertible Debentures to key management personnel at a price of $1,000 per convertible debenture for total gross proceeds of $1.6 million as part of a $46.0 million bought deal offering of convertible debentures.
On December 31, 2010, the Company issued 1,000 Series A Convertible Debentures to directors at a price of $1,000 per convertible debenture for total gross proceeds of $1.0 million as part of a $50.0 million bought deal offering of convertible debentures.
In February 2010, the Company issued 352,466 common shares to directors at a price of $1.45 per share for total gross proceeds of $0.5 million as part of a $31.8 million bought deal offering of common shares before commissions and expenses.
Compensation of key management personnel was as follows:
| | | December 31, 2011 | | | December 31, 2010 | |
| Salaries and other short-term employee benefits | | $ | 2,469 | | | $ | 2,058 | |
| Share-based payments | | | 902 | | | | 820 | |
| | | $ | 3,371 | | | $ | 2,878 | |
| Capitalized portion of key management personnel compensation | | | (1,552 | ) | | | (1,285 | ) |
| | | $ | 1,819 | | | $ | 1,593 | |
21. COMMITMENTS AND CONTINGENCIES
(a) Capital commitments. As at December 31, 2011 the Company had commitments for future capital expenditures in the amount of $0.5 million that are expected to be incurred during the first quarter of 2012. In addition to these capital commitments, the Company has entered into “farm-in” agreements whereby the Company may earn working interests in oil and gas properties in exchange for undertaking capital spending programs to develop the properties. In certain farm-in agreements, the Company is subject to non-performance fees if it does not fulfill its capital spending obligations. As at December 31, 2011 the Company is committed to fulfilling the following farm-in obligations.
Cardium Horizontal Well Program - Oil. The Company has farm-in obligations to drill six gross (4.5 net capital) horizontal wells in the Cardium geological formation prior to dates ranging from August 1, 2012 to September 30, 2012. One agreement has a $100,000 non-performance fee clause should the Company fail to drill the well. Another agreement pertains to two wells; there is a $100,000 non-performance fee should the Company fail to drill both wells, and if only one well is drilled, the Company would also forfeit fifty per cent of the interest in the first well drilled under the agreement.
| 31 | 2011 FINANCIAL STATEMENTS |
21. COMMITMENTS AND CONTINGENCIES (Continued)
Edmonton Sands Well Program – Natural Gas. In 2009, the Company committed to a 200 well drilling and completion program in the Edmonton Sands geological formation (the “Program”) under a farm-in agreement with a large international oil and gas company (the “Farmor”) from which the Company will earn an interest in up to 120 sections of land. The Company is obligated to complete the Program or before March 31, 2013 and has an option to continue the farm-in transaction until March 1, 2014 by committing to drill a minimum of 100 additional wells under similar terms as in the commitment phase to earn a minimum of 50 sections of land. Following the commitment and/or option phases, the Company and the Farmor can then jointly develop the lands on denser drilling spacing under terms of an operating agreement.
As of December 31, 2011, the Company had drilled 126 wells under the farm-in agreement and deferred the drilling of the remaining 74 gross (53.5 net capital) wells until 2013 due to depressed natural gas prices. A $550,000 penalty is payable for each well not drilled under the commitment as of March 31, 2013, subject to certain reductions due to unavoidable events beyond the Company’s control and rights of first refusal. The Company estimates that its minimum commitment to drill the remaining 74 wells is approximately $10 million.
(b) Operating lease commitments. The Company leases various plant and equipment, vehicles, and surface land locations under cancellable operating lease agreements. Surface lease arrangements may be cancelled at any time following reclamation of any site used in the Company’s operations. For plant and equipment and vehicle leases, the Company may terminate the leases at any time, subject to certain immaterial conditions and guarantees.
The Company leases various offices and computer software under non-cancellable operating lease agreements. The head office lease terminates on November 30, 2012, while other lease terms are between one and three years, and the majority of lease agreements are renewable at the end of the lease period at the prevailing market rate.
The minimum future payments under non-cancellable operating leases are as follows:
| | | December 31, 2011 |
| Less than one year | $ | 1,952 |
| Between one year and five years | | 467 |
| More than five years | | - |
| | $ | 2,419 |
The total operating lease expenditure charged to the income statement during the year is disclosed in note 15.
(c) Other commitments and contingencies. The Company has entered into firm service gas transportation agreements in which the Company guarantees certain minimum volumes of natural gas will be shipped on various gas transportation systems. The terms of the various agreements expire in one to eight years. If no volumes were shipped pursuant to the agreements, the maximum amounts payable under the guarantees based on current tariff rates are as follows:
| | | 2012 | | | 2013 | | | 2014 | | | 2015 | | | 2016 | | | Thereafter | |
| Firm service commitment | | $ | 1,255 | | | $ | 871 | | | $ | 679 | | | $ | 608 | | | $ | 95 | | | $ | 299 | |
Firm service committed volumes (MMcfd) | | | 19 | | | | 10 | | | | 5 | | | | 4 | | | | 3 | | | | 9 | |
The Company entered into an agreement for gas gathering services with a minimum fee payable of approximately $244,000 per year until November 30, 2018. To date, the gathering fees paid by the Company for gas volumes transported on the gathering system have exceeded the minimum requirements.
21. COMMITMENTS AND CONTINGENCIES (Continued)
The Company entered into a facilities construction and operation agreement pursuant to which it has guaranteed a minimum revenue to the crude oil pipeline operator related to minimum volumes of crude oil shipments through the new facilities and pipeline. The minimum revenue guaranteed is approximately $257,000 per contract year for the first five years commencing with the in-service date of the facilities and pipeline, which occurred in October 2011. If the Company exceeds the minimum volume requirement in a single year, the excess is carried forward as a credit to the minimum revenue guarantee in the subsequent year. If no volumes were shipped, the annual payment under the guarantee would be approximately $257,000 each year for five years. To date, no payments have been required under this guarantee.
22. SUBSEQUENT EVENTS
On February 21, 2012 the Company issued a news release to announce the Board of Directors’ decision to initiate a process to identify, examine and consider a range of strategic alternatives available to the Company with a view to enhancing shareholder value. Strategic alternatives may include, but are not limited to, a sale of all or a material portion of the assets of Anderson, either in one transaction or in a series of transactions, the outright sale of the Company, or a merger or other strategic transaction involving Anderson and a third party. There are no guarantees or assurances that the process will result in a transaction or a series of transactions or, if a transaction or a series of transactions are undertaken, the terms or timing of any such transaction or series of transactions.
Subsequent to December 31, 2011, the Company sold or has entered into agreements to sell minor properties for $6.3 million in gross proceeds (subject to adjustments).
| 33 | 2011 FINANCIAL STATEMENTS |
23. RECONCILIATION FROM CANADIAN GAAP TO IFRS
These are the Company’s first annual consolidated financial statements prepared in accordance with IFRS.
The accounting policies in note 3 have been applied in preparing the consolidated financial statements for the year ended December 31, 2011, the comparative information presented in these consolidated financials statements for the year ended December 31, 2010 and in the preparation of the opening IFRS statement of financial position at January 1, 2010.
Statement of financial position at the date of IFRS transition – January 1, 2010:
| (in thousands of dollars) | | Canadian GAAP | | | Impairment (note 23b) | | | Decommi- ssioning (note 23d) | | | Share-based payments (note 23e) | | | Flow through shares (note 23f) | | | Deferred taxes (note 23h) | | | IFRS | |
| ASSETS | | | | | | | | | | | | | | | | | | | | | |
| Current assets: | | | | | | | | | | | | | | | | | | | | | |
| Cash | | $ | 1 | | | $ | - | | | $ | - | | | $ | - | | | $ | - | | | $ | - | | | $ | 1 | |
Accounts receivable
and accruals | | | 22,990 | | | | | | | | | | | | | | | | | | | | | | | | 22,990 | |
Prepaid expenses and
deposits | | | 3,778 | | | | | | | | | | | | | | | | | | | | | | | | 3,778 | |
| | | | 26,769 | | | | - | | | | - | | | | - | | | | - | | | | - | | | | 26,769 | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
Property, plant and equipment
(note 23a) | | | 470,400 | | | | (67,193 | ) | | | | | | | | | | | | | | | | | | | 403,207 | |
| | | $ | 497,169 | | | $ | (67,193 | ) | | $ | - | | | $ | - | | | $ | - | | | $ | - | | | $ | 429,976 | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| LIABILITIES AND EQUITY | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Current liabilities: | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Accounts payable and accruals | | $ | 36,889 | | | $ | - | | | $ | - | | | $ | - | | | $ | - | | | $ | - | | | $ | 36,889 | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Bank loans | | | 62,404 | | | | | | | | | | | | | | | | | | | | | | | | 62,404 | |
| Decommissioning obligations | | | 33,879 | | | | | | | | 13,778 | | | | | | | | | | | | | | | | 47,657 | |
Deferred tax liability (note 23h) | | | 31,278 | | | | (16,914 | ) | | | (3,444 | ) | | | | | | | | | | | - | | | | 10,920 | |
| | | | 164,450 | | | | (16,914 | ) | | | 10,334 | | | | - | | | | - | | | | - | | | | 157,870 | |
| Shareholders’ equity: | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Share capital | | | 391,637 | | | | | | | | | | | | - | | | | 5,336 | | | | (449 | ) | | | 396,524 | |
| Contributed surplus | | | 6,104 | | | | | | | | | | | | 234 | | | | | | | | | | | | 6,338 | |
Deficit (note 23i) | | | (65,022 | ) | | | (50,279 | ) | | | (10,334 | ) | | | (234 | ) | | | (5,336 | ) | | | 449 | | | | (130,756 | ) |
| | | | 332,719 | | | | (50,279 | ) | | | (10,334 | ) | | | - | | | | - | | | | - | | | | 272,106 | |
| | | $ | 497,169 | | | $ | (67,193 | ) | | $ | - | | | $ | - | | | $ | - | | | $ | - | | | $ | 429,976 | |
23. RECONCILIATION FROM CANADIAN GAAP TO IFRS (Continued)
Statement of financial position at December 31, 2010:
| (in thousands of dollars) | | Canadian GAAP | | | Impairment (note 23b) | | | Decommi-ssioning (note 23d) | | | Share-based payments (note 23e) | | | Depletion and depreciation (note 23c) | | | Other PP&E adjs (note 23c) | | | Flow through shares (note 23f) | | | Convertible debentures (note 23g) | | | Deferred taxes (note 23h) | | | IFRS | |
| ASSETS | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Current assets: | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Cash and cash equivalents | | $ | 4,024 | | | $ | - | | | $ | - | | | $ | - | | | $ | - | | | $ | - | | | $ | - | | | $ | - | | | $ | - | | | $ | 4,024 | |
| Accounts receivable and accruals | | | 20,998 | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | 20,998 | |
| Prepaid expenses and deposits | | | 3,052 | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | 3,052 | |
| Deferred tax asset | | | 508 | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | (508 | ) | | | - | |
| | | | 28,582 | | | | - | | | | - | | | | - | | | | - | | | | - | | | | - | | | | - | | | | (508 | ) | | | 28,074 | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
Property, plant and
equipment (note 23a) | | | 506,533 | | | | (220,358 | ) | | | 2,185 | | | | (322 | ) | | | 33,071 | | | | (436 | ) | | | | | | | | | | | | | | | 320,673 | |
| | | $ | 535,115 | | | $ | (220,358 | ) | | $ | 2,185 | | | $ | (322 | ) | | $ | 33,071 | | | $ | (436 | ) | | $ | - | | | $ | - | | | $ | (508 | ) | | $ | 348,747 | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| LIABILITIES AND EQUITY | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Current liabilities: | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
Accounts payable and
accruals | | $ | 46,862 | | | $ | - | | | $ | - | | | $ | - | | | $ | - | | | $ | - | | | $ | - | | | $ | - | | | $ | - | | | $ | 46,862 | |
Unrealized loss on
derivative contracts | | | 1,918 | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | 1,918 | |
| | | | 48,780 | | | | - | | | | - | | | | - | | | | - | | | | - | | | | - | | | | - | | | | - | | | | 48,780 | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Bank loans | | | 52,719 | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | 52,719 | |
| Convertible debentures | | | 43,460 | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | 43,460 | |
| Decommissioning obligations | | | 36,320 | | | | | | | | 15,075 | | | | | | | | | | | | 155 | | | | | | | | | | | | | | | | 51,550 | |
Deferred tax liability (asset)
(note 23h) | | | 20,045 | | | | (55,407 | ) | | | (3,222 | ) | | | | | | | 8,268 | | | | (483 | ) | | | | | | | 1,650 | | | | (508 | ) | | | (29,657 | ) |
| | | | 201,324 | | | | (55,407 | ) | | | 11,853 | | | | - | | | | 8,268 | | | | (328 | ) | | | - | | | | 1,650 | | | | (508 | ) | | | 166,852 | |
| Shareholders’ equity: | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Share capital | | | 422,038 | | | | | | | | | | | | | | | | | | | | | | | | 5,336 | | | | | | | | (449 | ) | | | 426,925 | |
Equity component of
convertible debentures | | | 4,242 | | | | | | | | | | | | | | | | | | | | | | | | | | | | (1,650 | ) | | | | | | | 2,592 | |
| Contributed surplus | | | 8,164 | | | | | | | | | | | | (243 | ) | | | | | | | | | | | | | | | | | | | | | | | 7,921 | |
Deficit (note 23i) | | | (100,653 | ) | | | (164,951 | ) | | | (9,668 | ) | | | (79 | ) | | | 24,803 | | | | (108 | ) | | | (5,336 | ) | | | | | | | 449 | | | | (255,543 | ) |
| | | | 333,791 | | | | (164,951 | ) | | | (9,668 | ) | | | (322 | ) | | | 24,803 | | | | (108 | ) | | | - | | | | (1,650 | ) | | | - | | | | 181,895 | |
| | | $ | 535,115 | | | $ | (220,358 | ) | | $ | 2,185 | | | $ | (322 | ) | | $ | 33,071 | | | $ | (436 | ) | | $ | - | | | $ | - | | | $ | (508 | ) | | $ | 348,747 | |
| 35 | 2011 FINANCIAL STATEMENTS |
| 23. | RECONCILIATION FROM CANADIAN GAAP TO IFRS (Continued) |
Reconciliation of consolidated statement of operations and comprehensive loss for the year ended December 31, 2010:
| | | | | | | | | | | | | | | | | | | | | | |
| (in thousands of dollars) | | Canadian GAAP | | | Impairment (note 23b) | | | Decommi- ssioning (note 23d) | | | Share-based payments (note 23e) | | | Depletion and depreciation (note 23c) | | | Other PP&E adjs (note 23c) | | | IFRS | |
| | | | | | | | | | | | | | | | | | | | | | |
| Oil and gas sales | | $ | 86,457 | | | $ | - | | | $ | - | | | $ | - | | | $ | - | | | $ | - | | | $ | 86,457 | |
| Royalties | | | (9,011 | ) | | | | | | | | | | | | | | | | | | | | | | | (9,011 | ) |
| Revenue | | | 77,446 | | | | - | | | | - | | | | - | | | | - | | | | - | | | | 77,446 | |
| Realized loss on derivative contracts | | | (131 | ) | | | | | | | | | | | | | | | | | | | | | | | (131 | ) |
| Unrealized loss on derivative contracts | | | (1,918 | ) | | | | | | | | | | | | | | | | | | | | | | | (1,918 | ) |
| Gain on sale of property, plant and equipment | | | - | | | | | | | | | | | | | | | | | | | | 389 | | | | 389 | |
| | | | 75,397 | | | | - | | | | - | | | | - | | | | - | | | | 389 | | | | 75,786 | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Operating expenses | | | 28,537 | | | | | | | | | | | | | | | | | | | | | | | | 28,537 | |
| Transportation expenses | | | 611 | | | | | | | | | | | | | | | | | | | | | | | | 611 | |
| Depletion and depreciation | | | 78,723 | | | | | | | | | | | | | | | | (33,071 | ) | | | | | | | 45,652 | |
| Impairment of property, plant and equipment | | | - | | | | 153,165 | | | | | | | | | | | | | | | | | | | | 153,165 | |
General and administrative expenses, including stock-based compensation | | | 8,908 | | | | | | | | | | | | (155 | ) | | | | | | | 664 | | | | 9,417 | |
| Loss from operating activiites | | | (41,382 | ) | | | (153,165 | ) | | | - | | | | 155 | | | | 33,071 | | | | (275 | ) | | | (161,596 | ) |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Finance income | | | 96 | | | | | | | | | | | | | | | | | | | | | | | | 96 | |
| Finance expenses, including accretion | | | (5,894 | ) | | | | | | | 888 | | | | | | | | | | | | | | | | (5,006 | ) |
| Net finance expenses | | | (5,798 | ) | | | - | | | | 888 | | | | - | | | | - | | | | - | | | | (4,910 | ) |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Loss before taxes | | | (47,180 | ) | | | (153,165 | ) | | | 888 | | | | 155 | | | | 33,071 | | | | (275 | ) | | | (166,506 | ) |
| Deferred income tax reduction | | | (11,549 | ) | | | (38,493 | ) | | | 222 | | | | - | | | | 8,268 | | | | (167 | ) | | | (41,719 | ) |
| Loss and comprehensive loss for the year | | $ | (35,631 | ) | | $ | (114,672 | ) | | $ | 666 | | | $ | 155 | | | $ | 24,803 | | | $ | (108 | ) | | $ | (124,787 | ) |
| 23. | RECONCILIATION FROM CANADIAN GAAP TO IFRS (Continued) |
Notes to reconciliations
(a) IFRS 1 Exemptions:
Deemed Cost. The Company applied the IFRS 1 exemption whereby the value of its opening plant, property and equipment at January 1, 2010 was deemed to be equal to the net book value as determined under Canadian GAAP and the corresponding CGUs were tested for impairment. The Company chose to allocate its costs to its CGUs based on proved plus probable reserves volumes.
Business Combinations. The Company applied the IFRS 1 exemption and did not retrospectively revalue business combinations that occurred before January 1, 2010 in accordance with IFRS 3, Business Combinations. Accordingly, there were no adjustments made to the Company’s January 1, 2010 financial statements as a result of this exemption.
Borrowing Costs. The Company also applied the IFRS 1 exemption which allowed first-time adopters to use the transitional provisions set out in IAS 23, Borrowing Costs and set the effective date of the standard as January 1, 2010, which is the date of the Company’s transition to IFRS. Accordingly, there were no adjustments made to the Company’s January 1, 2010 financial statements as a result of this exemption.
Refer to notes 23(d) and 23(e) for further discussion on IFRS 1 exemptions taken for decommissioning obligations and share-based payments.
(b) IAS 36 Adjustments – Impairment of Assets. Under Canadian GAAP, impairment of non-financial assets is assessed on the basis of an asset’s estimated undiscounted future cash flows compared with the asset’s carrying amount and if impairment is indicated, discounted cash flows are prepared to quantify the amount of the impairment. Under IFRS, impairment is assessed based on the recoverable amount (greater of value in use or fair value less costs to sell) compared with the asset’s carrying amount to measure the amount of the impairment. In addition, under IFRS, where a non-financial asset does not generate largely independent cash inflows, the Company is required to perform its test at a cash generating unit level, which is the smallest identifiable grouping of assets that generates largely independent cash inflows. Canadian GAAP impairment was based on undiscounted cash flows using asset groupings with both independent cash inflows and cash outflows.
As a result of applying the deemed cost exemption at January 1, 2010, the Company recorded an impairment of $67.2 million with a corresponding reduction in property, plant and equipment. For the year ended December 31, 2010 the Company recognized additional impairments of $153.2 million respectively with a corresponding reduction in property, plant and equipment as a result of declines in the forward natural gas price curves.
(c) IAS 16 Adjustments – Property, Plant and Equipment.
Depletion and depreciation. Upon transition to IFRS, the Company adopted a policy of depleting and depreciating oil and natural gas interests on a unit of production basis over proved plus probable reserves. The depletion and depreciation policy under Canadian GAAP was based on unit of production over proved reserves. In addition, depletion and depreciation was calculated on the Canadian full cost pool under Canadian GAAP. IFRS requires depletion and depreciation to be calculated based on individual components.
At January 1, 2010, there were no amounts recorded as a result of the policy differences as discussed above. For the year ended December 31, 2010, the use of proved plus probable reserves in conjunction with lower net book values due to impairments in the Company’s Shallow Gas, Deep Gas and Non-core CGUs resulted in a decrease to depletion and depreciation of $33.1 million with a corresponding increase to property, plant and equipment.
| 37 | 2011 FINANCIAL STATEMENTS |
23. RECONCILIATION FROM CANADIAN GAAP TO IFRS (Continued)
Other adjustments. IFRS requires that gains or losses be reported on the disposition of property, plant and equipment. Under Canadian GAAP, gains or losses on disposition of property, plant and equipment were only reported when the disposition resulted in more than a 20 percent change in the depletion rate. As a result of this requirement, the Company reported a gain of $0.4 million during the year ended December 31, 2010 with an increase in property, plant and equipment where the proceeds were originally recorded under Canadian GAAP and a net increase to decommissioning obligations that were assumed as part of an asset exchange of $0.2 million.
IFRS also requires that the capitalization of general and administrative costs be limited to directly attributable costs. Under Canadian GAAP, a reasonable allocation of general and administrative costs to property, plant and equipment was acceptable. As a result of the change in the capitalization criteria, the Company increased its general and administrative expense by $0.7 million during the year ended December 31, 2010 with a corresponding decrease in property, plant and equipment.
Under Canadian GAAP, a deferred tax adjustment was recorded related to stock-based compensation costs capitalized. No such adjustment is made under IFRS. As a result of this change, property, plant and equipment was reduced by $0.3 million at December 31, 2010 with a corresponding decrease to the deferred tax liability.
(d) IAS 37 Adjustments – Provisions, Contingent Liabilities and Contingent Assets. Consistent with IFRS, decommissioning obligations (asset retirement obligations under Canadian GAAP) were measured under Canadian GAAP based on the estimated cost of decommissioning, discounted to their net present value upon initial recognition. Under Canadian GAAP, asset retirement obligations were discounted at a credit adjusted risk fee rate of eight to 10 percent. Under IFRS, the estimated cash flows to abandon and remediate the Company’s wells and facilities has been risk adjusted, therefore the provision is discounted at a risk free rate of one to four percent depending upon the estimated timelines to reclamation. Under IFRS, decommissioning obligations are also required to be re-measured at each reporting period to incorporate changes in future cash flow estimates, timelines to reclamation as well as discount rates used in present valuing the obligations.
The IFRS 1 exemption was utilized for asset retirement obligations associated with oil and gas properties and the Company re-measured asset retirement obligations as at January 1, 2010 under IAS 37 with a corresponding adjustment to opening retained earnings. Upon transition to IFRS this resulted in a $13.8 million increase in the decommissioning obligations with a corresponding decrease in retained earnings.
At December 31, 2010, using risk-free rates of one to four percent, depending on the estimated timing of the future obligation, the Company increased its decommissioning obligations by $15.1 million from Canadian GAAP. The Company also increased the value of its plant, property and equipment for December 31, 2010 by $2.2 million for new obligations incurred during 2010.
For the year ended December 31, 2011, accretion expense decreased by $0.9 million under IFRS compared to Canadian GAAP as a result of higher initial decommissioning obligations being recognized under IFRS and lower discount rates being used. Under IFRS, accretion on decommissioning obligations is included in finance expenses as opposed to Canadian GAAP where these amounts were included in depletion, depreciation and accretion.
(e) IFRS 2 Adjustments – Share-based Payments. Under Canadian GAAP, the Company recognized stock-based compensation expense on a straight-line basis through the date of full vesting and incorporated a forfeiture rate, which was optional under Canadian GAAP. Under IFRS, the Company is required to recognize the expense over the individual vesting periods for the graded vesting awards and estimating a forfeiture rate is no longer optional.
23. RECONCILIATION FROM CANADIAN GAAP TO IFRS (Continued)
The Company applied the IFRS 1 exemption for equity instruments which vested before the transition date and did not retroactively restate them. All unvested options at transition date were retroactively restated in accordance with IFRS 2 with the adjustment going through opening retained earnings. As a result, the Company recorded an additional $0.2 million in contributed surplus at January 1, 2010 for unvested options with the offset going to opening retained earnings.
For the year ended December 31, 2010, the Company reduced contributed surplus by $0.5 million and reduced the amount of stock-based compensation capitalized by $0.3 million for a net reduction in stock-based compensation expense of $0.2 million. Under Canadian GAAP, stock-based compensation expense was disclosed separately on the consolidated statement of operations and comprehensive loss. Under IFRS, stock-based compensation expense is included in general and administrative expenses.
(f) Flow Through Shares. Under Canadian GAAP, the Company recorded the deferred tax impact on renouncement of flow through shares against share capital. Under IFRS, the Company is required to record a premium liability when the flow through shares are issued, which is relieved upon renouncement, with the difference going to deferred tax expense. As a result of this change in the treatment of deferred taxes, at January 1, 2010, the Company recorded an additional $5.3 million to share capital with a corresponding reduction in retained earnings for flow through shares that had been previously issued and fully renounced at transition.
(g) Convertible Debentures. Under Canadian GAAP, the Company did not record a deferred tax difference on its convertible debentures. Under IFRS, the Company is required to record the deferred tax difference between the fair value of the liability component of the convertible debentures and the tax value of the convertible debentures with the difference being booked against the equity component of convertible debentures. As a result, the Company recorded $1.7 million in deferred tax against the equity component of convertible debentures at December 31, 2010.
(h) IAS 12 Adjustments – Income Taxes. The aforementioned changes increased (decreased) the net deferred tax liability as follows based on a tax rate of 25 percent:
| | | December 31, 2010 | | | January 1, 2010 | |
Impairment of plant, property and equipment (note 23b) | | | (55,407 | ) | | | (16,914 | ) |
Depletion and depreciation (note 23c) | | | 8,268 | | | | - | |
Decommissioning obligation (note 23d) | | | (3,222 | ) | | | (3,444 | ) |
Convertible debentures (note 23g) | | | 1,650 | | | | - | |
Other adjustments (note 23c) | | | (483 | ) | | | - | |
| Decrease in deferred tax liability | | $ | (49,194 | ) | | $ | (20,358 | ) |
IFRS requires that adjustments to the future tax rates used to calculate deferred taxes be traced and recorded against the original source of the timing difference as opposed to through earnings as was done under Canadian GAAP. As a result of this change at January 1, 2010, the Company reclassified $0.5 million in deferred taxes previously recorded in income against share issue costs.
Under Canadian GAAP, the Company was required to disclose future income taxes in the same current or long-term classification from which the timing differences arose. As such at December 31, 2010, the Company reported $0.5 million as a current asset related to timing differences that would reverse in one year. There is no such requirement under IFRS, therefore the Company removed the separate disclosure of current deferred taxes.
The effect on the consolidated statements of operations and comprehensive loss for the year ended December 31, 2010 was to decrease the previously reported tax charge by $30.2 million.
| 39 | 2011 FINANCIAL STATEMENTS |
23. RECONCILIATION FROM CANADIAN GAAP TO IFRS (Continued)
(i) Retained Earnings Adjustments. The aforementioned changes increased (decreased) retained earnings as follows on an after-tax basis:
| | | December 31, 2010 | | | January 1, 2010 | |
Impairment of plant, property and equipment (note 23b) | | $ | (164,951 | ) | | $ | (50,279 | ) |
Decommissioning obligations (note 23d) | | | (9,668 | ) | | | (10,334 | ) |
Flow through shares (note 23f) | | | (5,336 | ) | | | (5,336 | ) |
Depletion and depreciation (note 23c) | | | 24,803 | | | | - | |
General and administrative expenses (note 23c) | | | (497 | ) | | | - | |
Gain on sale of plant, property and equipment (note 23c) | | | 389 | | | | - | |
Deferred taxes on share issue costs (note 23h) | | | 449 | | | | 449 | |
Stock-based compensation (note 23e) | | | (79 | ) | | | (234 | ) |
| Decrease in retained earnings | | $ | (154,890 | ) | | $ | (65,734 | ) |
(j) Adjustments to the Company’s Statements of Cash Flows under IFRS. The reconciling items discussed above between Canadian GAAP and IFRS policies have no material impact on the cash flows generated by the Company. As a result of the change in capitalized general and administrative expenses, there was a reduction of $0.7 million to operating cash flows, with and equal and opposite effect on investing cash flows for the year ended December 31, 2010.
