HOUSTON, TEXAS — (Marketwire) — 03/30/12 — Caza Oil & Gas, Inc. (“Caza” or “the Company”) (TSX: CAZ)(AIM: CAZA), the exploration, appraisal, development and production company, is pleased to announce the Company–s final results for the year ended December 31, 2011.
2011 highlights include:
W. Michael Ford, Chief Executive Officer commented:
“We are pleased with our progress in 2011. The latter portion of the year was particularly positive with material increases in both production and revenues. Caza increased its production volumes by 38% and revenues by 63% in Q4 2011, as compared to Q4 2010, with an annual increase in revenues on the prior year of 83% in 2011. Our proven reserves also increased materially during the course of 2011. These increases were the direct result of Caza–s successful drilling operations during the year and highlight the value creating activities that remain the focus of the operations we undertake on behalf of our shareholders. Our cash and cash equivalents at December 31, 2011, are US$10.2MM, and our net working capital at December 31, 2011, is US$8.84MM.”
About Caza
Caza is engaged in the acquisition, exploration, development and production of hydrocarbons in the following regions of the United States of America through its subsidiary, Caza Petroleum, Inc.: Texas and Louisiana Gulf Coast (on-shore), and the Permian Basin (West Texas and Southeast New Mexico).
In accordance with AIM Rules – Guidance Note for Mining, Oil and Gas Companies, the information contained in this announcement has been reviewed and approved by Anthony B. Sam, Vice President Operations of Caza who is a Petroleum Engineer and a member of The Society of Petroleum Engineers.
Copies of the Company–s financial statements for the year ended December 31, 2011, the accompanying management–s discussion and analysis and the Company–s Annual Information Form for the year ended December 31, 2011 (which contains further information about the Company, its principal properties and its crude oil and natural gas reserves), will be available on SEDAR at and the Company–s website at . The Company–s financial statements have been in accordance with Canadian generally acceptable accounting principles applicable to publicly accountable enterprises. All dollar amounts disclosed in this press release are disclosed in United States dollars.
Chief Executive–s Statement
“We are pleased with our progress in 2011. The latter portion of the year was particularly positive with material increases in both production and revenues. These increases were the direct result of Caza–s successful drilling operations during the year and clearly highlight the value creating activities that remain the focus of the operations we undertake on behalf of our shareholders.
“We were successful in the Permian Basin at our San Jacinto Wolfberry property in Midland County, Texas. Caza, as operator, successfully engineered the stimulation, completion and commingling of multiple pay zones and currently has two wells on production averaging gross volumes of 170 boe/d with up to seven additional proven undeveloped locations still to be drilled on this property. This has added real value in the form of cash flows and proven reserves. Notwithstanding this, more favorable investment opportunities and attractive recent Wolfberry properties– sale prices have caused management to explore the possibility of divesting the San Jacinto Wolfberry property. If this property is ultimately sold, Caza intends to use the proceeds to further existing assets and to pursue new opportunities in order to add additional shareholder value through continued investment in suitable properties.
“We are also pleased to disclose that Caza is steadily building a position in the very active Bone Spring horizontal play in Southeast New Mexico. As previously announced, Caza conducted extensive production tests in the Bone Spring formation at our Lynch Property on the Mud Slide Slim Fed Com 15-1 well, which led to our heightened interest in this play. The Bone Spring formation in Lea and Eddy Counties, New Mexico, contains multiple potential pay zones for oil and liquids-rich natural gas, which include the Avalon Shale and First, Second and Third Bone Spring Sands. Caza–s current prospects in the Bone Spring play are Lynch, Forehand Ranch, Lennox, Copperline and Mad River. We have acquired approximately 4,000 acres in the play to date. The NSAI Report has assigned 100 viable Bone Spring horizontal drilling locations to our current leasehold position with total proved plus probable plus possible net reserves to the Company of 16.7 MMboe. In addition to Bone Spring potential, our leases also have shallow Delaware potential for oil, which could be developed independently of the Bone Spring. Caza intends to sell down to industry partners in these prospects and participate with a manageable 25-50% interest in the wells.
“Also in Southeast New Mexico, CML, as operator, commenced drilling operations earlier this month on the WC 35 State No. 1 well on Caza–s Sombrero property in Lea County, New Mexico. This property is targeting the Cisco formation for oil and liquids-rich natural gas. We will update the market regarding the well in due course.
“We continue to evaluate our 3-D seismic databases in south Texas and south Louisiana. Caza is currently evaluating the Lewis prospect against our current prospect inventory and looking for an operating partner to drill our Consilience Cib Op prospect in Atchafalaya Bay later in 2012. These are high impact prospects that carry slightly more risk than the Permian Basin oil prospects mentioned previously, but with higher upside potential. We recognize the value in generating and drilling high impact prospects. Our extensive 3-D seismic data base allows us to achieve this while giving us a competitive advantage over oil and gas exploration and production companies of similar size and value.
“The Company had development and production impairments of $10.8MM and exploration and evaluation impairments of $6.3MM in 2011. The impairments are largely due to low North American natural gas prices and write downs associated with the Company–s Cook Mountain leases in Wharton County, Texas, and the Arran/Marian Baker #1 well in Acadia Parish, Louisiana.
“At Caza we are pleased with progress made in 2011, and after laying the groundwork for continued success, we look forward to advancing the Company–s prospects and properties during the course of 2012.”
Reserve Figures by Category:
Caza reported an increase in proved (1P) reserves at year end 2011 to 2.35 MMboe or an increase of 36%; proved plus probable (2P) reserves increased at year end 2011 to 12.12 MMboe or an increase of 150%; proved plus probable plus possible (3P) reserves increased at year end 2011 to 22.26 MMboe or an increase of 143% (as depicted in the table below).
Present value cash flows of Caza–s estimated net proved and probable reserves as at December 31, 2011 were:
The reserves data set out in this announcement (including in the above tables) have been extracted from the NSAI Report and are disclosed, together with additional information relating to the Company–s reserves and properties, in the Company–s Annual Information Form for the year ending December 31, 2011 (filed on SEDAR at ). The evaluation of the reserves data included in the Annual Information Form and in the NSAI Report complies with standards set out in the Canadian Oil and Gas Evaluation Handbook prepared jointly by the Society of Petroleum Evaluation Engineers (Calgary Chapter) and the Canadian Institute of Mining, Metallurgy & Petroleum (Petroleum Society). References to the NSAI Report are to the report prepared on the Company–s reserves by Netherland, Sewell & Associates, Inc. as of December 31, 2011, and entitled “Estimates of Reserves and Future Revenue to the Caza Petroleum, Inc. Interest in Certain Oil and Gas Properties Located in Louisiana, New Mexico, and Texas as of December 31, 2011”.
ADVISORY STATEMENT
Information in this news release that is not current or historical factual information may constitute forward-looking statements within the meaning of securities laws. Such information is often, but not always, identified by the use of words such as “seek”, “anticipate”, “plan”, “continue”, “estimate”, “expect”, “may”, “will”, “project”, “predict”, “potential”, “targeting”, “intend”, “could”, “might”, “should”, “believe” and similar expressions. Information regarding future exploration, development and drilling activities (including the timing and scope thereof), drilling programs, geologic and seismic interpretation, joint venture relationships, ability to generate projects, strategic acquisitions and Caza–s ability to execute its strategic plan contained in this news release constitutes forward-looking information within the meaning of securities laws. Statements relating to “reserves” are deemed to be forward-looking statements, as they involve the implied assessment, based on certain estimates and assumptions, that the resources and reserves described can be profitably produced in the future.
Implicit in this information, particularly in respect of production are assumptions regarding projected revenue and expenses, the performance of wells, drilling and operating results, availability of funds, asset dispositions and the ability to secure joint venture partners and internally generate projects. These assumptions, although considered reasonable by the Company at the time of preparation, may prove to be incorrect. Readers are cautioned that actual future operating results and economic performance of the Company are subject to a number of risks and uncertainties, including general mechanical, economic, market and business conditions and could differ materially from what is currently expected as set out above. Production disclosed in this press release is at December 31, 2011. Future production may vary, perhaps materially.
For more exhaustive information on these risks and uncertainties you should refer to the Company–s most recently filed Annual Information Form filed on SEDAR at . You should not place undue importance on forward-looking information and should not rely upon this information as of any other date. While we may elect to, we are under no obligation and do not undertake to update this information at any particular time, except as required by applicable securities laws.
The estimates of reserves and future net revenue for individual properties may not reflect the same confidence level as estimates of reserves and future net revenue for all properties, due to the effects of aggregation.
The term boe may be misleading, particularly if used in isolation. A boe conversion of six thousand cubic feet per one barrel is based on an energy equivalency conversion method primarily applicable at the burner tip and does not represent a value equivalency at the well head.
Statements in this news release relating to net present value or future net revenue do not represent fair market value.
Management–s Report to Shareholders
Management has prepared the accompanying consolidated financial statements of Caza Oil & Gas, Inc. in accordance with International Financial Reporting Standards.
Management is responsible for the integrity and objectivity of the financial statements. Where necessary, the financial statements include estimates, which are based on management–s informed judgments. Management has established systems of internal control that are designed to provide reasonable assurance that assets are safeguarded from loss or unauthorized use and to produce reliable accounting records for financial reporting purposes.
The Board of Directors is responsible for ensuring that management fulfills its responsibilities for financial reporting and internal control. It exercises its responsibilities primarily through the Audit Committee. The Audit Committee meets periodically with management and the external auditors to satisfy itself that management–s responsibilities are properly discharged, to review the consolidated financial statements and to recommend that the consolidated financial statements be presented to the Board of Directors for approval.
Deloitte & Touche LLP has audited the consolidated financial statements in accordance with Canadian generally accepted auditing standards to enable them to express an opinion on the fairness of the consolidated financial statements.
William M. Ford, Chief Executive Officer and Director
March 29, 2012
James M. Markgraf, Chief Financial Officer
March 29, 2012
Independent Auditor–s Report
To the Shareholders of Caza Oil & Gas, Inc.
We have audited the accompanying consolidated financial statements of Caza Oil & Gas Inc. which comprise the consolidated statements of financial position as at December 31, 2011, December 31, 2010 and January 1, 2010, and the consolidated statements of net loss, comprehensive loss and deficit, consolidated statements of cash flows and the consolidated statements of changes in equity for the years ended December 31, 2011 and December 31, 2010, and the notes to the consolidated financial statements.
Management–s Responsibility for the Consolidated Financial Statements
Management is responsible for the preparation and fair presentation of these consolidated 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.
Auditor–s Responsibility
Our responsibility is to express an opinion on these consolidated 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 consolidated financial statements are free from material misstatement.
An audit involves performing procedures to obtain audit evidence about the amounts and disclosures in the consolidated financial statements. The procedures selected depend on the auditor–s judgment, including the assessment of the risks of material misstatement of the consolidated financial statements, whether due to fraud or error. In making those risk assessments, the auditor considers internal control relevant to the entity–s preparation and fair presentation of the consolidated 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 consolidated 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.
Opinion
In our opinion, the consolidated financial statements present fairly, in all material respects, the financial position of Caza Oil & Gas Inc. and subsidiaries as at December 31, 2011, December 31, 2010 and January 1, 2010, and its financial performance and its cash flows for the years ended December 31, 2011 and December 31, 2010 in accordance with International Financial Reporting Standards.
Deloitte & Touche LLP, Chartered Accountants
Calgary, Alberta
March 29, 2012
On behalf of the Board:
J. Russell Porter, Director
William M. Ford, Director
1. Basis of Presentation
Caza Oil & Gas, Inc. (“Caza” or the “Company”) was incorporated under the laws of British Columbia on June 9, 2006 for the purposes of acquiring shares of Caza Petroleum, Inc. (“Caza Petroleum”). The Company and its subsidiaries are engaged in the exploration for and the development, production and acquisition of, petroleum and natural gas reserves. The Company–s common shares are listed for trading on the TSX (symbol “CAZ”) and AIM stock exchanges (symbol “CAZA”). The corporate headquarters of the Company is located at 10077 Grogan–s Mill Road, Suite 200, The Woodlands, Texas 77380 and the registered office of the Company is located at Suite 1700, Park Place, 666 Burrard Street Vancouver, British Columbia, V6C 2X8.
The consolidated financial statements have been prepared in accordance with International Financial Reporting Standards (“IFRS”). Canadian generally accepted accounting principles (“Canadian GAAP”) were revised to incorporate IFRS and publicly accountable enterprises are required to apply such standards for years beginning on or after January 1, 2011. Accordingly, these consolidated financial statements were prepared in accordance with IFRS 1, First-time Adoption of IFRS. The significant accounting policies set out below were consistently applied to all the periods presented.
Canadian GAAP differs in some areas from IFRS. In preparing these consolidated financial statements, management has amended certain accounting, valuation and consolidation methods applied in the Canadian GAAP financial statements to comply with IFRS. The date of transition to IFRS was January 1, 2010 and the comparative figures for 2010 were restated to reflect these adjustments. Reconciliations and descriptions of the effect of the transition from Canadian GAAP to IFRS on equity, net loss and comprehensive loss are included in note 14.
The consolidated financial statements were approved and authorized by the Board of Directors on March 29, 2012.
Caza–s reporting currency is the United States (“U.S.”) dollar as the majority of its transactions are denominated in the currency.
2. Significant Accounting Policies
The accounting policies set out below have been applied consistently to all years presented in these consolidated financial statements, and have been applied consistently by the Company and its subsidiaries.
(a) Basis of consolidation:
Subsidiaries:
Subsidiaries are entities controlled by the Company. Control exists when the Company has the power to govern the financial and operating policies of an entity so as to obtain benefits from its activities. In assessing control, potential voting rights that currently are exercisable are taken into account. The financial statements of subsidiaries are included in the consolidated financial statements from the date that control commences until the date that control ceases.
Details of the Company–s subsidiaries at the end of the reporting year are as follows.
The proportion not owned by the Company is shown as non-controlling interests in these financial statements and relates to exchangeable rights in Caza Petroleum Inc. which are held by management and which are exchangeable into the Company–s shares (see Note 7 e).
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 a proportionate share of the relevant revenue and related costs.
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) Foreign currency:
The Company and its subsidiary companies each determines their functional currency of the primary economic environment in which they operate. The Company–s (and its subsidiaries) functional currency is the U.S. Dollar. Transactions denominated in a currency other than the functional currency of the entity are translated at the exchange rate in effect on the transaction date.
(c) Financial instruments:
Non-derivative financial instruments:
Non-derivative financial instruments comprise accounts receivable, cash and cash equivalents, accounts payable and accrued liabilities. Non-derivative financial instruments are recognized initially at fair. 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 held with banks, other short-term highly liquid investments (including money market instruments) with original maturities of three months or less.
Financial assets at fair value through profit or loss:
An instrument is classified at fair value through profit or loss if it is held for trading or is designated as such upon initial recognition. Upon initial recognition attributable transaction costs are recognized in profit or loss when incurred. Financial instruments at fair value through profit or loss are measured at fair value, and changes therein are recognized in profit or loss. The Company has designated cash and cash equivalents as fair value through profit and loss.
Loans and receivables:
Non-derivative financial instruments classed as loans and receivables, such as accounts receivable and accounts payable and accrued liabilities, are measured at amortized cost using the effective interest method, less any impairment losses.
(d) Evaluation and exploration assets:
Pre-license costs are expensed in the statement of operations as incurred.
Exploration and evaluation (“E&E”) costs, including the costs of acquiring licenses and directly attributable general and administrative costs, initially are capitalized as either tangible or intangible exploration and evaluation assets according to the nature of the assets acquired. The costs are accumulated in cost centers by well, field or exploration area pending determination of technical feasibility and commercial viability.
Assets classified as E&E are not amortized, but are assessed for impairment if (i) sufficient data exists to determine technical feasibility and commercial viability, and (ii) facts and circumstances suggest that the carrying amount exceeds the recoverable amount. For purposes of impairment testing, exploration and evaluation assets are allocated to cash-generating units (“CGU”).
The technical feasibility and commercial viability of extracting a mineral resource is considered to be determinable when proven reserves are determined to exist. A review of each exploration license or field is carried out, at least annually, to ascertain whether proven reserves have been discovered. Upon determination of proven reserves, exploration and evaluation assets attributable to those reserves are first tested for impairment and then reclassified from exploration and evaluation assets to a separate category within tangible assets referred to as petroleum and natural gas interests.
(e) Development and production costs:
Items of property, plant and equipment (“PPE”), which include oil and gas development and production assets, are measured at cost less accumulated depletion and depreciation and accumulated impairment losses. Development and production assets are grouped into CGU–s for impairment testing.
Development costs that may be capitalized as PPE include land acquisition costs, geological and geophysical expenses, the costs of drilling productive wells, the cost of petroleum and natural gas production equipment, directly attributable and incremental general overhead and estimated abandonment costs. 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.
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 within “other expenses (income)” in profit or loss. The carrying amount of any replaced or sold component is derecognized.
Maintenance:
The costs of the day-to-day servicing of property, plant and equipment are recognized in profit or loss as incurred.
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 year to the related proven reserves, taking into account estimated future development costs necessary to bring those proved reserves into production. Future development costs are estimated taking into account the level of development required to produce the reserves. These estimates are reviewed by independent reserve engineers at least annually.
Other Property and Equipment:
For other assets, depreciation is recognized in profit or loss on a straight-line basis over the estimated useful lives of each part of an item of property, plant and equipment. 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. Land is not depreciated.
The estimated useful lives for other assets for the current and comparative years are as follows:
Depreciation methods, useful lives and residual values are reviewed at each reporting date.
(f) Impairment:
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.
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.
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 any indication of impairment. If any such indication exists, then the asset–s recoverable amount is estimated. An impairment test is completed each year for other intangible assets that have indefinite lives or that are not yet available for use. E&E assets are also assessed for impairment if facts and circumstances suggest that the carrying amount exceeds the recoverable amount and before they are reclassified to property and equipment, as oil and natural gas interests.
For the purpose of impairment testing, assets are grouped together into CGUs. A CGU is a grouping of assets that generate cash flows independently of other assets held by the Company. 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.
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 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 or amortization, if no impairment loss had been recognized.
(g) Decommissioning liabilities:
The Company recognizes a decommissioning liability in the period in which it has a present legal or constructive liability and a reasonable estimate of the amount can be made. Liabilities are measured based on current requirements, technology and price levels and the present value is calculated using amounts discounted over the useful economic life of the assets. Amounts are discounted using the risk-free rate. On a periodic basis, management reviews these estimates and changes, if any, will be applied prospectively. The fair value of the estimated decommissioning liability is recorded as a long-term liability, with a corresponding increase in the carrying amount of the related asset. The capitalized amount is depleted on a unit-of-production basis over the life of the proved reserves. The liability amount is increased each reporting period due to the passage of time and the amount of accretion is charged to finance expense. Periodic revisions to the estimated timing of cash flows or to the original estimated undiscounted cost can also result in an increase or decrease to the decommissioning liability. Actual costs incurred upon settlement of the obligation are recorded against the decommissioning liability to the extent of the liability recorded.
(h) Share capital:
Common shares are classified as equity. Incremental costs directly attributable to the issue of common shares and share options are recognized as a deduction from equity, net of any tax effects.
(i) Share based payments:
Equity-settled share-based payments to employees and others providing similar services are measured at the fair value of the equity instruments at the grant date.
The grant date fair value of options granted to employees is recognized as compensation expense on a graded basis over the vesting period, within general and administrative expenses, with a corresponding increase in contributed surplus. A forfeiture rate is estimated on the grant date; however, at the end of each reporting period, the Company revises its estimate of the number of equity instruments expected to vest. The impact of the revision of the original estimates, if any, is recognized on a prospective basis.
(j) 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. This is generally at the time product enters the pipeline or any other means of transportation. Revenue is measured net of royalties.
(k) Finance income and expenses:
Finance expense comprises interest expense on borrowings, if any, and the unwinding of the discount on decommissioning liabilities.
Borrowing costs incurred for the construction of qualifying assets are capitalized during the period of time that is required to complete and prepare the assets for their intended use or sale. All other borrowing costs are recognized in profit or loss using the effective interest method. The capitalization rate used to determine the amount of borrowing costs to be capitalized is the weighted average interest rate applicable to the Company–s outstanding borrowings during the period.
Interest income is recognized as it accrues in profit or loss, using the effective interest method.
(l) Earnings per share:
Basic earnings per share is calculated by dividing the profit or loss attributable to common shareholders by the weighted average number of common shares outstanding during the year. 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. Diluted per share calculations reflect the exercise or conversion of potentially dilutive securities or other contracts to issue shares at the later of the date of grant of such securities or the beginning of the year. The Company computes diluted earnings per share using the treasury stock method to determine the dilutive effect of securities or other contracts. Under this method, the diluted weighted average number of shares is calculated assuming the proceeds that arise from the exercise of outstanding, in-the-money options are used to purchase common shares of the Company at their average market price for the year. No adjustment to diluted earnings per share or diluted shares outstanding is made if the result of the calculations is anti-dilutive.
(m) Application of new and revised International Financial Reporting Standards (IFRSs) issued but not yet effective.
The Company has not applied the following new and revised IFRSs that have been issued but are not yet effective.
As of January 1, 2012, the Company will be required to adopt amendments to IAS 1 “Presentation of Financial Statements” which will require companies to group together items within other comprehensive income that may be reclassified to the net earnings section of the comprehensive income statement. The Company does not expect a material impact as a result of the amendment.
Each of the additional new standards outlined below is effective for annual periods beginning on or after January 1, 2013, or 2015, with early adoption permitted. The Company has not yet assessed the impact, if any, that the new amended standards will have on its financial statements or whether to early adopt any of the new requirements.
IFRS 9 (revised) “Financial Instruments: Classification and Measurement”
The result of the first phase of the IASB–s project to replace IAS 39, “Financial Instruments: Recognition and Measurement”. The new standard replaces the current multiple classification and measurement models for financial assets and liabilities with a single model that has only two classification categories: amortized cost and fair value.
IFRS 10 (new) “Consolidated Financial Statements”
Replaces Standing Interpretations Committee 12, “Consolidation – Special Purpose Entities” and the consolidation requirements of IAS 27 “Consolidated and Separate Financial Statements”. The new standard replaces the existing risk and rewards based approaches and establish control as the determining factor when determining whether an interest in another entity should be included in the consolidated financial statements.
IFRS 11 (new) “Joint Arrangements”
Replaces IAS 31 “Interests in Joint Ventures” along with amending IAS 28 “Investment in Associates”. The new standard focuses on the rights and obligations of an arrangement, rather than its legal form. The standard redefines joint operations and joint ventures and requires joint operations to be proportionately consolidated and joint ventures to be equity accounted.
IFRS 12 (new) “Disclosure of Interests in Other Entities”
Provides comprehensive disclosure requirements on interests in other entities, including joint arrangements, associates, and special purpose vehicles. The new disclosure requires information that will assist financial statement users in evaluating the nature, risks and financial effects of an entity–s interest in subsidiaries and joint arrangements.
IFRS 13 (new) “Fair Value Measurement”
Provides a common definition of fair value within IFRS. The new standard provides measurement and disclosure guidance and applies when IFRS requires or permits the item to be measured at fair value, with limited exceptions. This standard does not determine when an item is measured at fair value and as such does not require new fair value measurements.
(n) Critical accounting judgments and key sources of estimation uncertainty
The preparation of financial statements in conformity with IFRS requires management to make estimates and assumptions that affect the amounts reported in the consolidated financial statements and accompanying notes. Actual results could differ from those estimates. The consolidated financial statements have, in management–s opinion, been properly prepared using careful judgment with reasonable limits of materiality.
The estimates and underlying assumptions are reviewed on an ongoing basis. Revisions to accounting estimates are recognized in the period in which the estimate is revised if the revision affects only that period or in the period of the revision and future periods if the revision affects both current and future periods.
Critical judgements in applying accounting policies
The following are the critical judgments, apart from those involving estimations (see below), that management has made in the process of applying the Company–s accounting policies and that have the most significant effect on the amounts recognized in the consolidated financial statements include:
a) Estimation of reserves
Estimates of recoverable quantities of proved and probable reserves include judgmental assumptions and require interpretation of complex geological and geophysical models in order to make an assessment of the size, shape, depth and quality of reservoirs, and their anticipated recoveries. The economic, geological and technical factors used to estimate reserves may change from period to period. Reserve estimates are prepared in accordance with the Canadian Oil and Gas Evaluation Handbook and are reviewed by third party reservoir engineers.
Estimates of oil and gas reserves are inherently imprecise, require the application of judgment and are subject to regular revision, either upward or downward, based on new information such as from the drilling of additional wells, observation of long-term reservoir performance under producing conditions and changes in economic factors, including product prices, contract terms or development plans
Changes in reported reserves can impact property, plant and equipment impairment calculations, estimates of depletion and the provision for decommissioning obligations due to changes in expected future cash flows based on estimates of proved and probable reserves, production rates, future petroleum and natural gas prices, future costs and the remaining lives and period of future benefit of the related assets.
b) Identification of cash-generating units
Management reviews the CGU determination on a periodic basis. The recoverability of property, plant and equipment carrying values are assessed at the CGU level. Determination of what constitutes a CGU is subject to management judgments. The asset composition of a CGU can directly impact the recoverability of the related assets.
c) Estimation of fair value of stock options
The Black-Scholes option pricing model was developed for use in estimating the fair value of traded options which have no vesting restrictions and are fully transferable. In addition, option pricing models require the input of highly subjective assumptions including the expected stock price volatility. Because the Company–s employee–s stock options have characteristics significantly different from those of traded options, and because changes in the subjective input assumptions can materially affect the fair value estimate, in management–s opinion, the existing models do not necessarily provide a reliable single measure of the fair value of its employee stock options. By their nature, these estimates are subject to measurement uncertainty and the effect on the consolidated financial statements of changes of estimates in future periods could be significant.
Key sources of estimation uncertainty
The following are the key assumptions concerning the key sources of estimation uncertainty at the end of the reporting period, that have a significant risk of causing adjustments to the carrying amounts of assets and liabilities within the next financial year.
The above judgments, estimates and assumptions relate primarily to unsettled transactions and events as of the date of the consolidated financial statements. Actual results could differ from these estimates and the differences could be material.
3. Exploration and evaluation assets
During the year ended December 31, 2011, the Company expensed $6,339,995 of exploration and evaluation costs of which $2,594,801 related to the Marian Baker et al, No 1 drilled during the three months ended March 31, 2011 that did not encounter hydrocarbons as well as an impairment to the valuation of the Las Animas prospect in the amount of $1,146,226. The balance of the costs expensed related to other leasehold and prospect expenditures that have expired or no longer prospective for the Company.
4. Petroleum and natural gas properties and equipment
Future development costs of proved undeveloped reserves of $30,722,900 were included in the depletion calculation at December 31, 2011 and $9,292,700 for the year ended December 31, 2010.
During the year ended December 31, 2011 the Company did not capitalize general and administrative expenses (2010 – $219,790) directly relating to exploration and development activities, of which $nil in 2011 that (2010 – $29,681) related to stock based compensation.
The Company performed an impairment test at December 31, 2011 to assess whether the carrying value of its petroleum and natural gas properties exceeds fair value. Impairment in the amount of $10,842,437 was required to be recorded as at December 31, 2011 primarily due to changes in Company estimates of reserves in the Cook Mountain formation in the SE Texas CGU. The December 31, 2011 impairment was recognized using a 16% discounted cash flow (December 31, 2010 – 13%, January 1, 2010 – 15%). The petroleum and natural gas future prices (adjusted for quality differentials) are based on commodity price forecasts of the Company–s independent reserve evaluators for 2011 as follows:
5. Decommissioning Liabilities
The following table presents the reconciliation of the beginning and ending aggregate carrying amount of the obligation associated with the retirement of oil and gas properties:
The undiscounted amount of cash flows, required over the estimated reserve life of the underlying assets, to settle the obligation, adjusted for inflation, is estimated at $1,533,283 (December 31, 2010 – $1,032,726). The obligation was calculated using a risk free discount rate of 2.5 percent (December 31, 2010 – 4.19%) and an inflation rate of 3 percent. It is expected that this obligation will be funded from general Company resources at the time the costs are incurred with the majority of costs expected to occur between 2012 and 2030.
6. Income Taxes
The following is a reconciliation of income taxes, calculated at the combined statutory federal and provincial income tax rates, to the income tax recovery included in the consolidated statements of net loss.
Deferred income taxes reflect the net tax effects of temporary differences between the carrying amounts of assets and liabilities for financial reporting purposes and the amounts for income tax purposes. The components of the Company–s deferred income tax assets and liabilities are as follows:
The Company has the following net operating losses available to be carried forward to offset future operating income for Caza–s US and Canadian entities:
7. Share Capital
(a) Authorized
Unlimited number of voting common shares.
(b) Issued
(c) Stock options
The maximum number of common shares for which options may be granted, together with shares issuable under any other share compensation arrangement of the Company, is limited to 10% of the total number of outstanding common shares (plus common shares that would be outstanding upon the exercise of all exchangeable rights) at the time of grant of any option. The exercise price of each option may not be less than the fair market value of the Company–s common shares on the date of grant. Except as otherwise determined by the Board and subject to the limitation that the stock options may not be exercised later than the expiry date provided in the relevant option agreement but in no event later than 10 years (or such shorter period required by a stock exchange) from their date of grant, options cease to be exercisable: (i) immediately upon a participant–s termination by the Company for cause, (ii) 90 days (30 days in the case of a participant engaged in investor relations activities) after a participant–s termination from the Company for any other reason except death and (iii) one year after a participant–s death. Subject to the Board–s sole discretion in modifying the vesting of stock options, stock options will vest, and become exercisable, as to 33 1/3% on the first anniversary of the date of grant and 33 1/3% on each of the following two anniversaries of the date of grant. All options granted to a participant but not yet vested will vest immediately upon a change of control or upon the Company–s termination of a participant–s employment without cause. A summary of the Company–s stock option plan as at December 31, 2011 and changes during the year ended on those dates is presented below.
During the year ended December 31, 2010, 7,950,000 options were granted at a fair value of $0.05 per option and 20,000 options were granted at a fair value of $0.24 per option. Options in the amount of 1,500,000 were granted at a fair value of $0.13 per option during the year ended December 31, 2011. The fair value of these options was determined using the Black-Sholes model with the following assumptions:
(d) Shared base compensation reserve
The following table presents the changes in the share based compensation reserve:
(e) Non-controlling interest
During 2010, the non-controlling interest percentages decreased as a result of additional issuances of shares of the subsidiary to Caza. This resulted in an increase in Caza–s deficit of $4,044,319. In 2011, issuances had a negligible effect.
8. Related Party Transactions
The aggregate amount of expenditures made to related parties:
During the years 2010 and 2011, Singular Oil & Gas Sands, LLC (“Singular”) agreed to participate in the drilling of the Matthys McMillan Gas Unit #2 and the O B Ranch #1 and 2 wells located in Wharton County, Texas. Under the terms of that agreement, Singular paid 14.01% of the drilling costs through completion to earn a 10.23% net revenue interest on the Matthys McMillan Gas Unit #2 well and paid 12.5% of the drilling costs to earn a 6.94% net revenue interest on the O B Ranch #1 well. Under the terms of the agreement of the O B Ranch #2 Singular paid 9.375% of the drilling costs to earn approximately 6.8% net revenue interest. This participation was in the normal course of Caza–s business and on the same terms and conditions to those of other joint venture partners. Singular owes the Company $492,240 in joint venture partner receivables as at December 31, 2011 (December 31, 2010 – $19,968; January 1, 2010 – $7,819). Singular is a related party as it is a company under common control with Zoneplan Limited, which is a significant shareholder of Caza.
All related party transactions are in the normal course of operations and have been measured at the agreed to exchange amounts, which is the amount of consideration established and agreed to by the related parties and which is comparable to those negotiated with third parties.
Remuneration of key management personnel of the Company, which includes directors, officers and other key personnel, is set out below in aggregate:
9. Commitments and Contingencies
As of December 31, 2010, the Company is committed under operating leases for its offices and corporate apartment in the following aggregate minimum lease payments which are shown below:
10. Supplementary Information
(a) net change in non-cash working capital
(b) supplementary cash flow information
(c) cash and cash equivalents
The money market instruments bear interest at a rate of 0.033% as at December 31, 2011
(December 31, 2010 – 0.136%).
11. Capital Risk Management
The Company–s objectives when managing capital is to safeguard the entity–s ability to continue as a going concern, so that it can continue to provide returns for shareholders and benefits for other stakeholders. The Company defines capital as shareholder–s equity, working capital and credit facilities when available. The Company manages the capital structure in light of changes in economic conditions and the risk characteristics of the underlying assets. The Company–s objective is met by retaining adequate equity and working capital to provide for the possibility that cash flows from assets will not be sufficient to meet future cash flow requirements. The Board of Directors does not establish quantitative return on capital criteria for management; but rather promotes year over year sustainable profitable growth.
The Company has evaluated its net working capital balance as at December 31, 2011. Due to long lead times on several of the Company–s exploration and development projects, from time to time the Company secures capital to fund its investments in petroleum and natural gas exploration projects in advance which has resulted in a net working capital balance. As exploration and development projects progress the Company expects the net working capital balance to significantly decrease from current levels, and additional capital may be required to fund additional projects. If the Company is unsuccessful in raising additional capital, the Company may have to sell or farm out certain properties. If the Company cannot sell or farm out certain properties, it will be unable to participate with joint venture partners and may forfeit rights to some of its properties.
12. Financial Instruments
The Company holds various forms of financial instruments. The nature of these instruments and the Company–s operations expose the Company to commodity price, credit, and foreign exchange risks. The Company manages its exposure to these risks by operating in a manner that minimizes its exposure to the extent practical.
(a) Commodity Price Risk
The Company is subject to commodity price risk for the sale of natural gas. The Company may enter into contracts for risk management purposes only, in order to protect a portion of its future cash flow from the volatility of natural gas and natural gas liquids commodity prices. To date the Company has not entered into any forward commodity contracts.
(b) Credit Risk
Credit risk arises when a failure by counter parties to discharge their obligations could reduce the amount of future cash inflows from financial assets on hand at the consolidated statement of financial position date. A majority of the Company–s financial assets at the consolidated statement of financial position date arise from natural gas liquids and natural gas sales and the Company–s accounts receivable that are with these customers and joint venture participants in the oil & natural gas industry. Industry standard dictates that commodity sales are settled on the 25th day of the month following the month of production. The Company–s natural gas and condensate production is sold to large marketing companies. Typically, the Company–s maximum credit exposure to customers is revenue from two months of sales. During the year ended December 31, 2011, the Company sold 68.96% (December 31, 2010 – 58.31%) of its natural gas and condensates to a single purchaser. These sales were conducted on transaction terms that are typical for the sale of natural gas and condensates in the United States. In addition, when joint operations are conducted on behalf of a joint venture partner relating to capital expenditures, costs of such operations are paid for in advance to the Company by way of a cash call to the partner of the operation being conducted.
Caza management assesses quarterly whether there should be any impairment of the financial assets of the Company. At December 31, 2011, the Company had overdue accounts receivable from certain joint interest partners of $135,835 which were outstanding for greater than 60 days and $443,466 that were outstanding for greater than 90 days. At December 31, 2011, the Company–s two largest joint venture partners represented approximately 13% and 13% of the Company–s receivable balance (December 31, 2010 25% and 15% respectively). The maximum exposure to credit risk is represented by the carrying amount on the consolidated statement of financial position of cash and cash equivalents, accounts receivable and deposits.
(c) Foreign Currency Exchange Risk
The Company is exposed to foreign currency exchange fluctuations, as certain general and administrative expenses are or will be denominated in Canadian dollars and United Kingdom pounds sterling. The Company–s sales of oil and natural gas are all transacted in US dollars. At December 31, 2011, the Company considers this risk to be relatively limited and not material and therefore does not hedge its foreign exchange risk.
(d) Fair Value of Financial Instruments
The Company has determined that the fair values of the financial instruments consisting of cash and cash equivalents, accounts receivable and accounts payable are not materially different from the carrying values of such instruments reported on the consolidated statement of financial position due to their short-term nature.
IFRS establishes a fair value hierarchy that prioritizes the inputs to valuation techniques used to measure fair value. The three levels of the fair value hierarchy are described below:
The Company–s cash and cash equivalents, which are classified as fair value through profit or loss, are categorized as Level 1 financial instruments.
All other financial assets are classified as loans or receivables and are accounted for on an amortized cost basis. All financial liabilities are classified as other liabilities. There are no financial assets on the consolidated statement of financial position that have been designated as available-for-sale. There have been no changes to the aforementioned classifications during the years presented.
(e) Liquidity Risk
Liquidity risk includes the risk that, as a result of our operational liquidity requirements:
The Company–s operating cash requirements including amounts projected to complete the Company–s existing capital expenditure program are continuously monitored and adjusted as input variables change. These variables include but are not limited to, available bank lines, natural gas production from existing wells, results from new wells drilled, commodity prices, cost overruns on capital projects and regulations relating to prices, taxes, royalties, land tenure, allowable production and availability of markets. As these variables change, liquidity risks may necessitate the Company to conduct equity issues or obtain project debt financing. The Company also mitigates liquidity risk by maintaining an insurance program to minimize exposure to insurable losses. The financial liabilities as at December 31, 2011 that subject the Company to liquidity risk are accounts payable and accrued liabilities. The contractual maturity of these financial liabilities is generally the following sixty days from the receipt of the invoices for goods of services and can be up to the following next six months. Management believes that current working capital will be adequate to meet these financial liabilities as they become due.
13. General and Administrative
During the year ended December 31, 2011 the Company incurred general and administrative expenses in the amount of $5,911,834 (December 31, 2010 – $3,574,453). Consulting and professional expenses in the amount $2,369,637 for the year ended December 31, 2011 (December 31, 2010 – $1,596,737) made up the largest expenditure for the year. Salaries in the amount of $2,136,490 as compared to $1,651,938 for the comparative period were incurred during the year ended December 31, 2010. Reimbursements of general and administrative expenses were received during the year ended December 31, 2010 in the amount of $725,720 as a result of certain joint venture agreements that were not in effect during 2011.
14. Transition to IFRS
For all periods up to and including the year ended December 31, 2010, the Company prepared its financial statements in accordance with previous GAAP. The Accounting Standards Board confirmed that IFRS will replace previous GAAP for financial periods beginning January 1, 2011 with restatement required for comparative purposes of amounts reported for year ended December 31, 2010, including the opening statement of financial position as at January 1, 2010.
The Company has adopted IFRS effective January 1, 2010 (the “transition date”) and has prepared its opening IFRS consolidated statement of financial position as at that date. IFRS 1 requires the presentation of comparative information as at the January 1, 2010 transition date and subsequent comparative periods as well as the consistent and retrospective application of IFRS accounting policies. To assist with the transition, the provisions of IFRS 1 allow for certain mandatory and optional exemptions for first-time adopters to alleviate the retrospective application of all IFRSs.
Elected exemptions from full retrospective application
In preparing these consolidated financial statements in accordance with IFRS 1, “First-time Adoption of International Financial Reporting Standards” (“IFRS 1”), the Company has applied certain of the optional exemptions from full retrospective application of IFRS. The optional exemptions applied are described below.
a) Deemed cost for oil and gas assets
The Company has elected to measure oil and gas assets previously recorded in the full cost pool under Accounting Guidelines 16, “Oil and Gas Accounting – Full Cost” (“AcG 16”) of Canadian GAAP at the transition date as follows:
(i) the full cost pool was allocated to development and production assets pro rata using proved plus probable reserve values.
b) Decommissioning liabilities included in the cost of property and equipment
The Company has elected to measure decommissioning liabilities as at the transition date in accordance with IAS 37, “Provisions, Contingent Liabilities and Contingent Assets” (“IAS 37”) and recognize directly in deficit the difference between that amount and the carrying amount of those liabilities at the date of transition determined under Canadian GAAP.
c) Business combinations
The Company has applied the business combinations exemption in IFRS 1 to not apply IFRS 3, “Business Combinations” (“IFRS 3”) retrospectively to past business combinations. Accordingly, the Company has not restated business combinations that took place prior to the transition date.
d) Share-based payment transactions
The Company has elected not to apply IFRS 2, “Share-based Payments” (“IFRS 2”) to equity instruments granted after November 7, 2002 that have not vested by the transition date.
e) Borrowing costs
The Company has applied the borrowing costs exemption in IFRS to not apply IAS 23, “Borrowing Costs” (“IAS 23”) retrospectively to past borrowing costs related to transactions that took place prior to the transition date.
Mandatory exceptions to retrospective application
a) Estimates
Hindsight was not used to create or revise estimates and accordingly the estimates previously made by the Company under Canadian GAAP are consistent with their application under IFRS.
The remaining IFRS 1 exemptions were not applicable or material to the preparation of Caza–s consolidated statement of financial position at the date of transition on January 1, 2010.
The following reconciliations present the adjustments made to the Company–s Canadian GAAP financial results of operations and financial position to comply with IFRS. A summary of the significant accounting policy changes and applicable exemptions are discussed following the reconciliations. Reconciliations include the Company–s Consolidated Equity and Statement of Financial Positions as at January 1, 2010 and December 31, 2010, and the Consolidated Statement of Comprehensive Loss for the year ended December 31, 2010.
The following discussion explains the significant differences between Caza–s previous GAAP accounting policies and those applied by the Company under IFRS. IFRS policies have been retrospectively and consistently applied except where specific IFRS 1 optional and mandatory exemptions permitted an alternative treatment upon transition to IFRS for first-time adopters. The descriptive note captions below correspond to the adjustments presented in the preceding reconciliations.
Exploration and Evaluation Assets (“E&E”)
Under Canadian GAAP, Caza followed AcG-16 under which all costs directly associated with the acquisition of, the exploration for, and the development of natural gas and liquids reserves were capitalized on a prospect cost basis. Costs accumulated within each prospect were depleted using the unit-of-production method based on proved reserves determined using estimated future prices and costs. Upon transition to IFRS, the Company was required to adopt new accounting policies for exploration and development activities.
Under IFRS, exploration and evaluation costs are those expenditures for an area where technical feasibility and commercial viability has not yet been determined. Development costs include those expenditures for areas where technical feasibility and commercial viability has been determined. Caza adopted the IFRS 1 exemption whereby the Company deemed its January 1, 2010 IFRS asset costs to be equal to its previous GAAP historical property, plant and equipment net book value. Accordingly, exploration and evaluation costs were deemed equal to the unproved properties balance and the development costs were deemed equal to the full cost pool balance.
Under IFRS, exploration and evaluation costs are presented on separate line items on the consolidated statement of financial position. Under Canadian GAAP these assets are included in the general balance of property and natural gas properties and equipment.
Exploration and evaluation assets at January 1, 2010 were determined to be $11,662,047, representing the unproved properties balance under Canadian GAAP. This resulted in a reclassification of $11,662,047 from petroleum and natural gas properties to exploration and evaluation assets on Caza–s consolidated statement of financial position as at January 1, 2010 (December 31, 2010 – $7,371,582). As at the date of transition, the Company tested all of its exploration and evaluation assets for impairment and determined no impairment charges were necessary.
Under Canadian GAAP, exploration and evaluation costs were capitalized as property and equipment in accordance with the CICA–s full cost accounting guidelines. Under IFRS, Caza capitalizes these costs initially as exploration and evaluation assets. Once technical feasibility and commercial viability of the area has been determined, the costs are transferred from exploration and evaluation assets to property, plant and equipment. Under IFRS, unrecoverable exploration and evaluation costs associated with an area and costs incurred prior to obtaining the legal rights to explore are expensed.
During the year ended December 31, 2010, Caza transferr