Caledonian Royalty Corporation Financial Statements As at and for the years ended 2016 and 2015
KPMG LLP 205 5th Avenue SW Suite 3100 Calgary AB T2P 4B9 Telephone (403) 691-8000 Fax (403) 691-8008 www.kpmg.ca INDEPENDENT AUDITORS REPORT To the Shareholders of Caledonian Royalty Corporation We have audited the accompanying financial statements of Caledonian Royalty Corporation, which comprise the statements of financial position as at 2016 and 2015, the statements of loss and comprehensive loss, changes in shareholder s equity and cash flows for the years then ended, and notes, comprising a summary of significant accounting policies and other explanatory information. Management s Responsibility for the Financial Statements Management is responsible for the preparation and fair presentation of these financial statements in accordance with International Financial Reporting Standards, and for such internal control as management determines is necessary to enable the preparation of financial statements that are free from material misstatement, whether due to fraud or error. Auditors Responsibility Our responsibility is to express an opinion on these financial statements based on our audits. We conducted our audits in accordance with Canadian generally accepted auditing standards. Those standards require that we comply with ethical requirements and plan and perform the audit to obtain reasonable assurance about whether the financial statements are free from material misstatement. An audit involves performing procedures to obtain audit evidence about the amounts and disclosures in the financial statements. The procedures selected depend on our judgment, including the assessment of the risks of material misstatement of the financial statements, whether due to fraud or error. In making those risk assessments, we consider internal control relevant to the entity s preparation and fair presentation of the financial statements in order to design audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the entity s internal control. An audit also includes evaluating the appropriateness of accounting policies used and the reasonableness of accounting estimates made by management, as well as evaluating the overall presentation of the financial statements. We believe that the audit evidence we have obtained in our audits is sufficient and appropriate to provide a basis for our audit opinion. KPMG LLP is a Canadian limited liability partnership and a member firm of the KPMG network of independent member firms affiliated with KPMG International Cooperative ( KPMG International ), a Swiss entity. KPMG Canada provides services to KPMG LLP.
Opinion In our opinion, the financial statements present fairly, in all material respects, the financial position of Caledonian Royalty Corporation as at 2016 and 2015, and its financial performance and its cash flows for the years then ended in accordance with International Financial Reporting Standards. Chartered Professional Accountants April 13, 2017 Calgary, Canada 2
CALEDONIAN ROYALTY CORPORATION Statements of Financial Position (Expressed in CDN dollars) Notes 2016 2015 Assets Current assets Cash $ 345,355 $ 171,251 Accounts receivable 16,19 1,848,570 1,175,139 Prepaid expenses and deposits 122,877 171,450 Financial asset 4 3,167,581 2,573,991 5,484,383 4,091,831 Property, plant and equipment 5 33,691,337 41,577,256 Financial asset 4 5,146,998 7,781,504 $ 44,322,718 $ 53,450,591 Liabilities and Shareholders' Equity Current liabilities Notes payable 7 $ - $ 48,062,020 Accounts payable and accrued liabilities 16,19 3,732,572 1,887,593 Preferred shares 8 3,350,000 - Deferred lease incentives 16,724 16,724 Decommissioning liability 9 369,068 223,624 7,468,364 50,189,961 Notes payable 7 $ 40,949,225 - Deferred lease incentives 29,266 45,989 Decommissioning liability 9 3,433,793 3,517,967 51,880,648 53,753,917 Shareholders' equity Share capital 12 50,011,554 43,704,497 Deficit (57,569,484) (44,007,823) (7,557,930) (303,326) $ 44,322,718 $ 53,450,591 Related party transactions (note 16) Contingencies (note 21) See accompanying notes to the financial statements. Approved on behalf of the Board of Directors: (signed) James S. Kinnear James S. Kinnear (signed) Charles V. Selby Charles V. Selby
CALEDONIAN ROYALTY CORPORATION Statements of Loss and Comprehensive Loss For the year ended (Expressed in CDN dollars) Notes 2016 2015 Revenue Oil and natural gas revenues $ 2,426,556 $ 2,858,072 Royalties (169,803) (251,239) Oil and natural gas revenues, net of royalties 2,256,753 2,606,833 Royalty revenue 2,615,172 4,907,815 4,871,925 7,514,648 Expenses Management fee 16-462,005 Production and operating 1,379,298 1,880,960 General and administrative 2,352,926 3,544,252 Reorganization costs - 369,982 Financing fees 8 1,300,000 - (Gain) loss on financial asset 4 (122,962) 920,413 Depletion and depreciation 5 3,700,694 8,024,860 Finance expense 10 5,687,872 9,462,093 Impairment 6 4,135,758 33,118,081 18,433,586 57,782,646 Net loss and comprehensive loss $ (13,561,661) $ (50,267,998) Net loss per share Basic and diluted 14 $ (0.83) $ (3.30) See accompanying notes to the financial statements.
CALEDONIAN ROYALTY CORPORATION Statements of Changes in Shareholder's Equity (Expressed in CDN dollars) Notes Share Capital Retained Earnings (Deficit) Total Shareholders' Equity Balance at 2014 $ 100 $ 9,001,703 $ 9,001,803 Issued on exchange of royalty units 12 29,003,082-29,003,082 Tax effect of reorganization 12 14,701,315-14,701,315 Net loss for the year - (50,267,998) (50,267,998) Dividends - (2,741,528) (2,741,528) Balance at 2015 $ 43,704,497 $ (44,007,823) $ (303,326) Notes Share Capital Retained Earnings (Deficit) Total Shareholders' Equity Balance at 2015 $ 43,704,497 $ (44,007,823) $ (303,326) Issue of common shares 12 6,665,490-6,665,490 Common share issue costs 12 (358,433) - (358,433) Net loss for the year - (13,561,661) (13,561,661) Balance at 2016 $ 50,011,554 $ (57,569,484) $ (7,557,930) See accompanying notes to the financial statements.
CALEDONIAN ROYALTY CORPORATION Statements of Cash Flows For the year ended (Expressed in CDN dollars) Notes 2016 2015 Cash provided by (used in): Operating activities Net loss for the year $ (13,561,661) $ (50,267,998) Non-cash items: Amortization of finance charges 10 1,887,980 2,850,370 Amortization of royalty unit issue costs 10-2,664,971 (Gain) loss on financial asset 4 (122,962) 920,413 Depletion and depreciation 5 3,700,694 8,024,860 Accretion of decommissioning liabilities 9 277,959 204,440 Impairment 6 4,135,758 33,118,081 Decommissioning expenditures 9 (161,682) (134,320) (3,843,914) (2,619,183) Change in non-cash working capital 20 1,203,398 552,001 (2,640,516) (2,067,182) Investing activities Capital expenditures 5 (5,540) (68,554) (5,540) (68,554) Financing activities Issue of notes payable, net of fees 7 - (17,127) Repayment of notes payable 7 (9,000,775) - Issue of common shares 12 6,665,490 - Common share issue costs 12 (358,433) - Issue of convertible preferred shares 8 3,350,000 - Return of capital on royalty units 15 - (507,000) Repayments of financial asset 4 2,163,878 3,703,522 Dividends paid - (2,741,528) Change in non-cash working capital 20 - (400,031) 2,820,160 37,836 Increase (decrease) in cash 174,104 (2,097,900) Cash - beginning of year 171,251 2,269,151 Cash - end of year $ 345,355 $ 171,251 See accompanying notes to the financial statements.
CALEDONIAN ROYALTY CORPORATION Notes to the Financial Statements for the Years Ended 2016 and 2015 1. General information Caledonian Royalty Corporation ( Caledonian or the Company ) was incorporated under the laws of the Province of Alberta on September 24, 2009. The address of Caledonian s registered office is Suite 2200, 300 5 th Avenue S.W., Calgary, Alberta, Canada, T2P 3C4. The Company is engaged in the business of purchasing royalty and non-operated interests in oil and gas properties and providing investment opportunities through the issuance of common shares. 2. Basis of Presentation Statement of compliance The financial statements have been prepared in accordance with International Financial Reporting Standards ( IFRS ) as issued by the International Accounting Standards Board ( IASB ) The financial statements were authorized for issuance by the Board of Directors on April 13, 2017. Basis of measurement The financial statements have been prepared on the historical cost basis, except for certain financial and non-financial assets and liabilities which have been measured at fair value. Jointly-controlled assets and operations A significant portion of the Company s oil and natural gas activities include jointly controlled assets and any liabilities incurred. The financial statements include the Company s share of these jointly controlled assets and liabilities and a proportionate share of the relevant revenues and related costs. Functional and presentation currency The financial statements are presented in Canadian dollars which is the Company s functional currency. Use of estimates and judgements The preparation of financial statements in conformity with IFRS requires management to make judgements, estimates and assumptions that affect the application of accounting policies and reported amount of assets, liabilities, income and expenses. Actual results may differ materially from these estimates. Estimates and their underlying assumptions are reviewed on an ongoing basis and are based on managements experience and other factors, including expectations of future events that are believed to be reasonable under the circumstances. Revisions to accounting estimates are recognized in the year in which the estimates are revised and for any future years affected. Critical Judgements in Applying Accounting Policies The following are critical judgements that management has made in the process of applying accounting policies and that have the most significant effect on the amounts recognized in these financial statements. i) Identification of cash-generating units The Company s assets are aggregated into cash generating units for the purpose of calculating impairment. Cash generating units ( CGU or CGUs ) are based on an assessment of the unit s ability to generate independent cash inflows. The determination of these CGUs was based on management s judgment in regards to geographical proximity, geology, production profile, shared infrastructure and similar exposure to market risk and materiality. Based on this assessment, the Company s CGUs are generally composed of significant development areas. The Company reviews the
composition of its CGUs at each reporting date to assess whether any changes are required in light of new facts and circumstances. Judgements are required to assess when impairment indicators exist and impairment testing is required. ii) Deferred income taxes Judgment is made by management to determine the likelihood of whether deferred tax assets at the end of the reporting period will be realized from future taxable earnings. iii) Preferred shares Judgement was made by management in determining whether preferred shares issued should be classified as liabilities or equity. The Company specifically considered if there was a contractual obligation to deliver cash to the preferred share holder. Key Sources of Estimation Uncertainty The following are key estimates and their assumptions made by management affecting the measurement of balances and transactions in these financial statements. i) Impairment of petroleum and natural gas assets Estimation of recoverable quantities of proven and probable reserves include estimates and assumptions regarding future commodity prices, exchange rates, discount rates and production and transportation costs for future cash flows as well as the interpretation of complex geological and geophysical models and data. Changes in reported reserves can affect the impairment of assets, the decommissioning liabilities and the amounts reported for depletion, depreciation and amortization of property, plant and equipment. These reserve estimates are verified by third party professional engineers, who work with information provided by the Company to establish reserve determination in accordance with National Instrument 51-101 Standards of Disclosure for Oil and Gas Activities. ii) Financial asset The financial asset is measured at fair value at each reporting date. The fair value is estimated by discounting the future cash receipts based on the forecasted Alberta gas reference price multiplied by the contracted deemed volume. Changes in the market pricing between period end and the settlement of the financial asset could have a material impact on the financial results related to the financial asset. iii) Decommissioning obligations The Company estimates the decommissioning liabilities for oil and gas wells and their associated production facilities and pipelines. In most instances, removal of assets and remediation occurs many years into the future. Amounts recorded for the decommissioning liabilities and related accretion expense require assumptions regarding removal date, future environmental legislation, the extent of reclamation activities required, the engineering methodology for estimating cost, inflation estimates, future removal technologies in determining the removal cost, and the estimate of the liability specific discount rates to determine present value of these cash flows. iv) Royalty Units The amortized cost of the Company s royalty units was determined by discounting future cash flows to present value at various discount rates. These future cash flows were sourced from cash flow estimates provided by third party engineers and management s estimates of future costs related to the financing and administration of the Company. v) Business combinations In a business combination, management makes estimates of the fair value of assets acquired and liabilities assumed which includes the value of oil and gas properties based upon the estimation of recoverable quantities of proven and probable reserves being acquired.
vi) Preferred shares The fair value of the preferred share liability was determined by using a market rate of interest for a liability with the same term without a conversion feature or detachable warrants. 3. Significant Accounting Policies The accounting policies set out below have been applied consistently to all periods presented in these financial statements, and have been applied consistently by the Company. (a) Exploration and Evaluation Assets Costs incurred prior to obtaining the right to explore a mineral resource are recognized as an expense in the period incurred. All costs incurred after the rights to explore an area have been obtained, such as geological and geophysical costs, exploration costs, appraisal costs and directly attributable general and administrative costs, are accumulated as exploration and evaluation assets. Exploration and evaluation costs are not amortized prior to the conclusion of appraisal activities. At the completion of appraisal activities, if technical feasibility is demonstrated and commercial reserves are discovered, then, the carrying value of the relevant exploration and evaluation asset will be reclassified as a petroleum and natural gas asset. This occurs only after the carrying value of the relevant exploration and evaluation asset has been assessed for impairment and, where appropriate, its carrying value adjusted. Technical feasibility and commercial viability are considered to be demonstrable when proved or probable reserves are determined to exist. If it is determined that the technical feasibility and commercial viability have not been achieved in relation to the exploration and evaluation assets appraised, all other costs are written down to the recoverable amount in net income. Expired land leases included in the undeveloped land are recognized in net income upon expiry. If there are circumstances that indicate that the carrying value of an exploration and evaluation asset may exceed its recoverable amount, an impairment test is carried out by grouping the exploration and evaluation assets with property, plant and equipment CGU s to which they belong for impairment testing. The equivalent combined carrying value of the CGU s is compared against the recoverable amount of the CGU s and resulting impairment loss is recognized in profit or loss. The recoverable amount is the greater of fair value, less costs to sell, or value-in-use. Impairments of exploration and evaluation assets are only reversed when there is significant evidence that the impairment has been reversed, but only to the extent of what the carrying amount would have been had no impairment been recognized. (b) Property, plant and equipment Property, plant and equipment includes the costs associated with the acquisition of and development of petroleum and natural gas reserves and maintaining or enhancing production from such reserves. Such costs include lease acquisition costs, geological and geophysical costs, carrying charges of non-producing properties, costs of drilling both productive and non-productive wells and tangible production equipment costs. Property, plant and equipment is carried at cost, less accumulated depletion and accumulated impairment losses. Gains and losses on disposal of an item of property, plant and equipment are determined by comparing the proceeds from disposal with the net carrying amount of property, plant and equipment and are recognized net in profit or loss. (c) Depletion and depreciation The net carrying value of development or production assets is depleted using the unit of production method, based upon estimated proved oil and gas reserves, before royalties, as determined by independent reservoir engineers. Proved reserve and production volumes are converted to equivalent units on the basis of relative energy content using a ratio of six mcf of natural gas to one barrel of crude oil. Costs subject to depletion include the estimated costs to be incurred in developing and retiring proved reserves. Depreciation of leasehold improvements and computer hardware is calculated on a straight-line basis over three to five years. Depreciation methods, useful lives and residual values are reviewed at each reporting date.
(d) Impairment Financial assets Financial assets, other than those classified as fair value through profit or loss, are assessed for indicators of impairment at the end of each reporting period. Financial assets are considered to be impaired when there is objective evidence that, as a result of one or more events that occurred after the initial recognition of the financial asset, the estimated future cash flows of the investment have been negatively affected. For financial assets carried at amortized cost, the amount of the impairment loss recognized in net income is the difference between the asset s carrying amount and the present value of the estimated future cash flows, discounted at the financial asset s original effective interest rate. The carrying amount of the financial asset is reduced by the impairment loss directly for all financial assets with the exception of trade receivables, where the carrying amount is reduced through the use of an allowance account. When a trade receivable is considered uncollectible, it is written off against the allowance account. Subsequent recoveries of amounts previously written off are credited against the allowance account. Changes in the carrying amount of the allowance accounts are recognized in the statement of income. Non-financial assets The carrying amounts of the Company s non-financial assets, other than E&E assets and deferred tax assets, are reviewed at each reporting date to determine whether there is indication of impairment. If any such indication exists, then the asset s recoverable amount is estimated. The carrying amounts of property, plant and equipment are reviewed at each reporting date to determine whether there is any indication of impairment. If any such indication exists, the estimated recoverable amount is calculated. For the purpose of impairment testing, assets are grouped together into the smallest group of assets that generates cash inflows from continuing use that are largely independent of the cash inflows of other assets or group of assets ( cash-generating unit or CGU ). The recoverable amount of an asset or a CGU is the greater of its value in use and its fair value less costs to sell. In assessing value in use, the estimated future cash flows are discounted to their present value using a pre-tax discount rate that reflects current market assessments of the time value of money. Value in use is generally computed by reference to the present value of the future cash flows expected to be derived from production of proved and probable reserves. Fair value less costs to sell is determined as the amount that would be obtained from the sale of a CGU in an arm s length transaction between knowledgeable and willing parties. The fair value less cost to sell of oil and natural gas assets is generally determined as the net present value of the estimated future cash flows expected to arise from the continued use of the CGU, including any expansion projects, and its eventual disposal, using assumptions that an independent market participant may take into account. These cash flows are discounted by an appropriate discount rate which would be applied by such a market participant to arrive at a net present value of the CGU. Consideration is given to acquisition metrics of recent transactions completed on similar assets to those contained within the relevant CGU. 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 CGU s are allocated to reduce the carrying amounts of these assets in the CGU on a pro rata basis. Impairment losses previously recognized 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 only to the extent that the asset s carrying amount does not exceed the carrying amount that would have been determined, net of accumulated depletion, if no impairment loss had been recognized. (e) Business Combinations Business combinations are accounted for using the acquisition method. Identifiable assets acquired and liabilities assumed in a business combination are measured at their fair values at the acquisition date. The cost of an acquisition is measured as the fair value of the assets given, equity instruments issued and liabilities incurred or assumed at the acquisition date. The excess of the cost of the acquisition over the fair values of the identifiable assets acquired and liabilities assumed are recorded as goodwill. If the cost of the acquisition is less than the fair values, the difference is
recognized immediately in net income. Transaction costs associated with a business combination are expensed as incurred. (f) Decommissioning Liabilities The Company recognizes the present value of the decommissioning liability in the period in which it is incurred. The obligation is recorded as a liability on a discounted basis using a credit-adjusted risk-free rate, with a corresponding increase to the carrying amount of the related asset. Over time, the liabilities are accreted for the change in present value and the capitalized costs are depleted on a unit-of production basis over the life of the underlying total proved reserves. Revisions to the discount rate, estimated timing or amount of future cash flows would also result in an increase or decrease in the decommissioning liability and related asset. (g) Royalty units Royalty units were recorded as a liability due to the requirement of the Company to pay out cash flows to the royalty unitholders. The royalty units were accounted for at fair value upon issuance and subsequently measured at amortized cost using the effective interest rate method as a fixed rate financial instrument. Additions to the royalty unit liability were added to the cost of the carrying amount of the modified liability and amortized over the remaining expected life. Royalty units converted to common shares were reclassified to equity at the previously recognized amortized cost since the royalty unitholders approved the conversion in their capacity as unitholders. (h) Preferred shares Preferred shares are recorded as a liability due to the requirement of the Company to pay finance fees to the holders of the preferred shares in cash or common shares at the option of the preferred share holder. The preferred shares are accounted for at fair value upon issuance. (i) Revenue recognition Royalty revenue is recorded in accordance with royalty rates as stated in the contract terms when title passes to the customer and collection is reasonably assured. Revenue from the sale of petroleum and natural gas is recognized when the significant risks and rewards of ownership of the product are transferred to the customer or buyer, based on volumes delivered to customers or buyers at contractual delivery points and rates and when collection is reasonably assured. The costs associated with the delivery, including operating and maintenance costs, transportation and production-based royalty expenses are recognized in the same period in which the related revenue is earned and recorded. (j) Net income per share Basic per share amounts are computed by dividing the income or loss attributable to common shareholders of the Company by the weighted average number of common shares outstanding during the period. Diluted per share amounts are determined by adjusting the income attributable to common shareholders and the weighted average number of common shares outstanding for the effects of dilutive instruments. (k) Income taxes Income tax expense is comprised of current and deferred tax. Income tax expense is recognized in profit or loss except to the extent that it related 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 providing for temporary differences between the carrying amount 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 and 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 largely enforceable right to offset, and they 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. (l) Financial instruments A financial instrument is any contract that gives rise to a financial asset of one entity and a financial liability or equity instrument to another entity. Upon initial recognition all financial instruments are recognized on the Statement of Financial Position at fair value. Subsequent measurement is then based on the financial instruments being classified into one of five categories: held for trading, held to maturity, loans and receivables, available for sale and other liabilities. The Company s cash and accounts receivable are classified as loans and receivables which are measured at amortized cost. Accounts payable and accrued liabilities, notes payable, royalty units and preferred share liabilities are classified as other liabilities which are measured at amortized cost. The Company s financial asset is classified as held for trading and is measured at fair value through profit or loss. Transaction costs related to financial instruments classified as fair value through profit or loss are expensed as incurred. All other transaction costs related to financial instruments are recorded as part of the instrument and are amortized using the effective interest rate method. (m) Share capital Incremental costs directly attributable to the issue of common shares are recognized as a deduction from equity, net of any tax effects. (n) Foreign Currency Translation The functional and reporting currency of the Company is the Canadian dollar. Transactions in currencies other than the functional currency are recorded at the rate of exchange prevailing on the date of the transaction. Monetary assets and liabilities that are denominated in foreign currencies are retranslated to the functional currency at the exchange rate at the period end date. Non-monetary items that are measured at historical cost in a foreign currency are translated at the exchange rate on the date of the transaction. Foreign currency translation differences are recognized in income (loss). (o) New standards and interpretations not yet adopted IFRS 15: Revenue from Contracts with Customers was issued in May 2014 and replaced IAS 18: Revenue, IAS 11: Construction Contracts, and related interpretations. IFRS 15 is effective for the years beginning on or after January 1, 2018. The Company is currently evaluating the impact of the standard on the financial statements. IFRS 9: Financial Instruments was issued in July 2014 and replaced IAS 39: Financial Instruments: Revenue Recognition and Measurement. IFRS 9 is effective for years beginning on or after January 1, 2018. Early adoption is permitted if IFRS 9 is adopted in its entirety at the beginning of a fiscal period. The Company is currently evaluating the impact of adopting IFRS 9 on the financial statements. IFRS 16: Leases requires the recognition of most leases on the balance sheet, and effectively removes the classification of leases as either finance or operating leases and treats all leases as finance leases for lessees with exceptions for short term leases where the lease term is twelve months or less and for leases of low value items. IFRS 16 accounting treatment for lessors is unchanged, which provides the choice of classifying a lease as either a finance or operating lease. The new standard is effective for annual periods beginning on or after January 1, 2019. The Company is currently evaluating the impact of adopting IFRS 16 on the financial statements.
4. Financial Asset 2016 2015 Balance, beginning of year $ 10,355,495 $ 14,979,430 Repayments (2,163,878) (3,703,522) Fair value adjustment 122,962 (920,413) Balance, end of year $ 8,314,579 $ 10,355,495 Current 3,167,581 2,573,991 Non-current 5,146,998 7,781,504 $ 8,314,579 $ 10,355,495 On June 26, 2014, the Company entered into an agreement with an industry partner whereby the Company paid $18.5 million in exchange for a monthly cash flow from oil and gas properties which expires June 2021. On August 27, 2014 the Company paid $2.8 million for additional monthly cash flows from oil and gas properties. The agreements set out future receipts using the same formula as the industry partner s monthly GOB Royalty Adjustment entitlements under the Alberta Natural Gas Royalty Regulation based on a January 1, 2014 forecast for the Alberta gas reference price. If the actual Alberta gas reference price for a month differs from the January 1, 2014 forecast, the Company s receipt is (a) reduced by 100% for any decline in price or (b) increased 65% for any increase in price. The security for the asset is over certain lands and future GOB Royalty Adjustments. The Company has accounted for this financial asset as a hybrid financial instrument comprising of a host contract and an embedded derivative. The embedded derivative is driven by changes in the future Alberta gas reference price and the impact of these changes on future cash receipts. The Company measures the financial asset at fair value through profit and loss. For the year ended 2016, an unrealized gain of $122,962 (2015: $920,413 loss) has been recognized related to the change in fair value of the financial asset. As at 2016, if future natural gas prices changed by $0.25/GJ, the fair market value of the financial asset would change by $855,470. 5. Property, plant and equipment Cost 2016 2015 Balance, beginning of year $ 151,312,234 $ 152,009,360 Additions 5,540 68,554 Change in decommissioning liabilities (55,007) (765,680) Balance, end of year $ 151,262,767 $ 151,312,234 Accumulated depletion and depreciation Balance, beginning of year Impairment Depletion and depreciation Balance, end of year $ (109,734,978) $ (68,592,037) (4,135,758) (33,118,081) (3,700,694) (8,024,860) $ (117,571,430) $ (109,734,978) Net book value, end of year $ 33,691,337 $ 41,577,256 Included in the net amount of property, plant and equipment at 2016 is leasehold improvements and computer hardware of $47,462 less accumulated depreciation of $21,889. The calculation of depletion included future development costs of $nil ( 2015: $700,000) associated with the development of the Company s proved crude oil and natural gas reserves.
6. Impairment Years ended 2016 2015 Impairment Expense $ 4,135,758 $ 33,118,081 For the year ended 2016, the Company conducted an assessment of indicators for the Company s CGUs. In performing the review, management determined that the shut-in of production in both the Royalty and Northern CGUs justified a review for impairment. In the Medicine River CGU, the additions of reserves due to technical revisions justified a review for impairment reversal. The recoverable amounts of the Company s CGUs were estimated as the fair value less costs to sell based on the net present value of before tax cash flows from oil and gas proved plus probable reserves estimated by the Company s third party reserve evaluators at rates ranging from ten to fifteen percent. In determining the appropriate discount rates, the Company referenced recent market transactions completed on assets similar to those in the CGU. At 2016, the Company recorded a net impairment of $4,135,758 which was comprised of the following: The Company determined that the carrying amount of the Royalty CGU exceeded the recoverable amount of $26,514,000. Accordingly, an impairment charge of $4,549,936 was included in net income. The Company determined that the carrying amount of the Northern CGU exceeded the recoverable amount of $nil. Accordingly, an impairment charge of $535,004 was included in net income. The Company determined that the recoverable amount of the Medicine River CGU of $2,236,368 exceeded its carrying amount. Accordingly, an impairment reversal of $949,182 was included in net income. The following table outlines forecasted commodity prices and exchange rates used in the Company s impairment test as at 2016. The forecasted commodity prices are consistent with those used by the Company s external reserve evaluators and are a key assumption in assessing recoverable amount. The reserve evaluators also include financial assumptions regarding royalty rates, operating costs, and future development capital that can significantly impact the recoverable amount which is assigned based on historical rates and future anticipated activities by management. WTI Price - Oil (US$/bbl) Edmonton Price- Oil ($/bbl) AECO Gas Price ($MMBtu) Exchange Rate ($Cdn/$US) 2017 55.00 69.33 3.20 0.750 2018 57.84 72.26 2.79 0.775 2019 61.51 75.00 2.91 0.800 2020 63.14 76.36 3.05 0.825 2021 65.59 78.82 3.15 0.850 2022 67.02 82.35 3.26 0.850 2023 68.37 85.88 3.37 0.850 2024 69.64 89.41 3.39 0.850 2025 70.84 92.94 3.39 0.850 2026 72.00 95.61 3.40 0.850 Escalation rate of 2% per year thereafter At 2015, due to the decline in forward commodity prices, the Company tested its CGUs for impairment. The recoverable amounts of the Company s CGUs were estimated as the fair value less costs to sell based on the net present value of before tax cash flows from oil and gas proved plus probable reserves estimated by the Company s third party reserve engineers ranging from ten to fifteen percent. In determining the appropriate discount rate, the Company referenced recent market transactions completed on assets similar to those in the CGU. The fair value less costs to sell for undeveloped land was estimated based on recent market transactions in the respective areas. At 2015, it was determined that the net present value of all of the CGUs exceeded the recoverable amount and the Company recorded a $33.1 million impairment charge.
7. Notes Payable 2016 2015 Senior secured first lien notes $ 49,950,000 $ 50,000,000 Converted to royalty units - (50,000) Settled (9,000,775) - Transaction costs (6,787,993) (6,787,993) Amortization of transaction costs 6,787,993 4,900,013 $ 40,949,225 $ 48,062,020 The Company issued $50,000,000 of notes payable in two tranches in 2013; $48,000,000 on September 9, 2013 and $2,000,000 on November 1, 2013. The notes bear interest at 7.5% payable monthly and had an August 31, 2016 maturity. The first interest payment on the first tranche was made on September 30, 2013 and the first interest payment on the second tranche was made on November 30, 2013. The notes are secured by first liens on the Company s assets and have certain financial covenants restricting the payment of management fees and dividends including: i) Fixed charge coverage ratio calculated as consolidated EBITDA (as defined in the trust indenture) divided by interest expense (as defined in the trust indenture) must be at least 3.0:1.0; and Distributions or dividends and management fees paid since the issuance of the notes must be less than or equal to the aggregate of: 50% of consolidated net income (as defined in the trust indenture) beginning April 1, 2013 and ending on the date of the last completed financial quarter (provided that if consolidated net income (as defined in the trust indenture) for such period is a loss, less 100% of such loss); plus the aggregate net cash proceeds received since April 1, 2013 as a contribution to common equity capital (as defined in the trust indenture); plus the aggregate amount of indebtedness reduced by the conversion of indebtedness to equity. ii) If the company does not meet the covenants in (i) above then to pay distributions (or dividends) and management fees it must: Maintain a fixed charge coverage ratio of 2.0:1.0 or greater; and Cannot pay distributions to holders of royalty units (or dividends to shareholders) and pay management fees that in aggregate are in excess of 95% of excess cash (as defined in the trust indenture) for the previous four quarters. On October 30, 2014, amendments to the Trust Indenture were approved through the execution of the first Supplemental Trust Indenture and waivers were approved for previous breaches to the covenants. The amendments to the Trust Indenture included changes to the definitions of Consolidated EBITDA, Consolidated Net Income, Excess Cash and Fixed Charge Coverage Ratio for the purposes of the covenants described above. The amendments also permitted the conversion of Caledonian to a dividend paying Corporation and gave the Noteholders an option to convert notes into royalty units or common shares. In consideration for the approval of the amendments and waivers, Caledonian issued 221,780 royalty units at $7.00 per unit to the Noteholders. The Company also incurred expenses consisting of a $393,560 soliciting dealer s fee, a $200,000 consent solicitation fee, $4,500 for expenses to the solicitation agent and $507,661 of professional fees. On August 31, 2016, the Company repaid $9 million of the notes. On September 1, 2016, amendments to the Trust Indenture were approved through the execution of the Second Supplemental Trust Indenture and waivers were approved for previous breaches to the covenants. The amendments to the Trust Indenture include: The maturity date of the notes is extended from August 31, 2016 to August 31, 2018; The redemption price is amended from 105% to 100% of the principal amount of the notes being redeemed;
The definition of the Fixed Charge Coverage Ratio is amended so the calculation does not include any fiscal quarters prior to September 30, 2016; The addition of a mandatory amortization whereby noteholders are to be paid 50% of the Available Cash Flow for such quarter. Available Cash Flow is defined as: the sum of: i. the consolidated revenue from operations of the Issuer; and ii. amounts received by the Issuer pursuant to the Amended and Restated Royalty and Revenue Sharing Agreement between the Issuer and Perpetual Operating Trust dated August 27, 2014; less: i. royalty expenses paid or payable to the provincial government or freehold land owners and gross overriding royalties paid to arm s length third parties; ii. iii. iv. reasonable general and administrative and marketing, transportation, reorganization, transaction costs approved by the Holders holding a majority of the principal amount of the Notes, bad debts and other ordinary course operating expenses, including interest on the Notes and hedging expenses; cash taxes; capital expenditures for non-operated working interests, including abandonment and reclamation costs; v. maintenance capital expenditures and abandonment and reclamation costs for operated working interests and, with the consent of the Holders, development capital expenditures for operated working interests (and, in respect of each of the foregoing items, excluding any amount previously deducted pursuant to (vi) below); vi. any reserve reasonably required for authorization for expenditure costs over $25,000; vii. viii. the net change in non-cash working capital for such quarter; and the lesser of (x) $250,000 and (y) the amount which is the difference between $1,000,000 and the cash on hand and cash equivalents on the last day of the quarter; provided that if the issuer has $1,000,000 or more of cash on hand and cash equivalents, there shall be no deduction under this subparagraph (viii). There will be no payments of management fees and/or dividends unless a payment has been made first to the holders of the notes and is made from the Company s 50% share of Available Cash Flow for such quarter; The Company is restricted from selling, leasing, transferring, assigning or conveying property or assets with a value greater than $100,000 without the prior written consent of the noteholders; The Company is not permitted to directly or indirectly create, incur, assume, guarantee or otherwise become directly or indirectly liable with respect to any indebtedness without the prior written consent of the noteholders. As at 2016, Caledonian was in compliance with the covenants on the notes payable. 8. Preferred Shares On August 24, 2016, the Company issued 1,675,000 units at $2.00 per unit for total cash consideration of $3.35 million. Each unit was comprised of one redeemable convertible preferred share and one common share purchase warrant. The preferred shares have no fixed maturity date and can be redeemed at the option of the Company at $2.00 per share. The preferred shares are convertible at the option of the holder on the following terms: (i) (ii) (iii) prior to March 31, 2017, one common share for each preferred share; on or after March 31, 2017 and prior to January 1, 2018, two common shares for each preferred share; on or after January 1, 2018, two hundred common shares for each preferred share
The preferred shares are subject to financing fees triggered as noted below, payable at the option of the holder in whole or in part, in cash or common shares at a deemed price of $2.00 per common share. (i) On September 30, 2016, a fee in the amount of $900,000; (ii) If any of the preferred shares have not been redeemed prior to October 31, 2016, a fee in the amount of $150,000; (iii) If any of the preferred shares have not been redeemed prior to 2016, a fee in the amount of $250,000; (iv) If any of the preferred shares have not been redeemed prior to March 31, 2017, a fee in the amount of $500,000. The following table summarizes the change in preferred shares issued and outstanding for the year ended 2016: 2016 2015 Number of Shares Amount Number of Shares Amount Balance, beginning of year - $ - - $ - Issued in the year 1,675,000 3,350,000 - - Balance, end of year 1,675,000 $ 3,350,000 - $ - The preferred share liability were initially recognized at fair value based on similar debt securities without the conversion or warrant feature and are subsequently carried at amortized cost. The entire value of the issuance has been recognized as the liability with $nil allocated to the equity components of the preferred shares. 9. Decommissioning Liability The decommissioning liability results from the net ownership interests in petroleum and natural gas assets including well sites, gathering systems and processing facilities. The Company estimates the total undiscounted amount of cash flows required to settle its decommissioning liability at 2016, to be approximately $12.1 million ( 2015: $11.5 million) including expected annual inflation of 2.0 percent (2015: 2.0 percent). A credit-adjusted risk-free rate of 10.0 percent (2015: 10.0 percent) was used to calculate the fair value of the liability. These obligations are expected to be incurred from the current year through 2071 and are expected to be funded through general corporate funds at the time of settlement. The following table outlines a reconciliation of the decommissioning liability: 2016 2015 Balance, beginning of year $ 3,741,591 $ 4,437,151 Change in estimate (55,007) (765,680) Accretion 277,959 204,440 Decommissioning expenditures (161,682) (134,320) Balance, end of year $ 3,802,861 $ 3,741,591 Current 369,068 223,624 Non-current 3,433,793 3,517,967 $ 3,802,861 $ 3,741,591 10. Finance Expense Years ended 2016 2015 Interest $ 3,520,843 $ 3,751,043 Amortization of transaction costs - notes payable 1,887,980 2,850,370 Amortization of royalty unit issue costs - 2,664,971 Foreign exchange loss (gain) 1,090 (8,731) Accretion on decommissioning liability 277,959 204,440 $ 5,687,872 $ 9,462,093
11. Income Taxes (a) Income tax expense The provision for income tax expense in the financial statements differs from the result in which would have been obtained by applying the combined federal and provincial tax rate to the Company s income before taxes. The difference results in the following items: 2016 2015 Net income before tax $ (13,561,661) $ (50,267,998) Tax rate 27.00% 26.00% Expected tax recovery (3,661,648) (13,069,679) Non-deductible expenses 356,916 9,526 Change in rate - 670,627 Other (5,645) 1,228 Change in unrecognized deferred tax asset 3,310,377 12,388,298 Subtotal 3,661,648 13,069,679 Income tax recovery $ - $ - The income tax rate change is due to an increase in the Alberta provincial corporate tax rate from 10% to 12% effective July 1, 2015. (b) Deferred income tax liability Deferred tax assets have not been recognized in respect of the following temporary differences: 2016 2015 Petroleum and natural gas interests $ 26,982,952 $ 24,764,488 Decommissioning liability 3,802,861 3,741,591 Notes payable issue costs 1,890,685 1,365,704 Share issue costs and other 767,182 777,645 Non-capital losses 26,536,895 16,712,059 Capital losses 185,644 185,644 $ 60,166,219 $ 47,547,131 The Company has non-capital losses of approximately $26,536,895 which will expire from 2030 to 2036. 12. Share Capital a) Authorized The Company is authorized to issue an unlimited number of common shares. b) Issued and Outstanding Common Shares On August 24, 2016, the Company issued 3,332,745 units for cash consideration of $6.67 million less $0.36 million of issue costs. Each unit was comprised of one common share and one half transferable common share purchase warrant. The following table summarizes the change in common shares issued and outstanding for the year ended 2016:
2016 2015 Number of Shares Amount Number of Shares Amount Balance, beginning of year 15,230,712 $ 43,704,497 - $ 100 Issued in exchange for royalty units - - 15,230,712 29,003,082 Tax effect of reorganization - - - 14,701,315 Issued in the period 3,332,745 6,665,490 - - Common share issue costs - (358,433) - - Balance, end of year 18,563,457 $ 50,011,554 15,230,712 $ 43,704,497 13. Warrants (a) On August 24, 2016, the Company issued 3,332,745 units for cash consideration of $6.67 million. Each unit was comprised of one common share and one half transferable common share purchase warrant. Each full warrant shall be exercisable into one common share for a period of three years from the closing date at an exercise price of $3.50 per common share. A valuation of the warrants was performed at the time of issuance and it was determined that the value of the warrant was nil due to the provisions of the convertible preferred shares. (b) On August 24, 2016, The Company issued 19,614 warrants to the agent of the private placement. Each warrant shall be exercisable into one common share for a period of two years from the closing date at an exercise price of $2.00 per common shares. A valuation of the warrants was performed at the time of issuance and it was determined that the value of the warrant was nil due to the provisions of the convertible preferred shares. (c) On August 24, 2016, the Company issued 1,675,000 units for cash consideration of $3.35 million. Each unit was comprised of one redeemable convertible preferred share and one common share purchase warrant. Each warrant shall be exercisable into one common share for a period of five years from the closing date at an exercise price of $2.00 per common share. A valuation of the warrants was performed at the time of issuance and it was determined that the value of the warrant was nil due to the provisions of the convertible preferred shares. No warrants were exercised or forfeited during the year. Outstanding warrants as at 2016 were 3,360,987. 14. Net Loss per Common Share The following table shows the calculation of net loss per common share: Years ended 2016 2015 Net loss $ (13,561,661) $ (50,267,998) Number of common shares: Weighted average common shares outstanding - basic and dilutive 16,414,474 15,230,712 Net loss per common share: Basic and diluted $ (0.83) $ (3.30) Excluded from the diluted per share calculation are 3.4 million warrants and 1.675 million preferred shares convertible into a maximum 335 million common shares, as they would be anti-dilutive. 15. Royalty Units On March 6, 2015, the Company reorganized its capital structure through the redemption of all of the outstanding Royalty Units for Common Shares on a one-for-one basis. The reorganization was approved via an extraordinary resolution at the January 21, 2015 special meeting of the holders of Caledonian. The amortized cost balance recognized as royalty unit liability was reclassified to equity on the effective date of the conversion.