(CAZA) Caza Oil & Gas

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 and AIM stock exchanges.

In conjunction with the Company's annual audited Consolidated Financial Statements to be issued under International Financial Reporting Standards ("IFRS") for the year ended December 31, 2011, these interim Condensed Consolidated Financial Statements present Caza's financial results of operations and financial position under IFRS as at and for the three and nine months ended September 30, 2011, including 2010 comparative periods.  As a result, they have been prepared in accordance with IFRS 1, "First-time Adoption of International Reporting Standards" and with International Accounting Standards ("IAS") 34, "Interim Financial Reporting", as issued by the International Accounting Standards Board ("IASB") using the accounting policies the Company expects to adopt in its consolidated financial statements for the year ending December 31, 2011.

These interim Condensed Consolidated Financial Statements do not include all the necessary annual disclosures in accordance with IFRS.  Prior to 2011 reporting, the Company prepared its interim and annual consolidated financial statements in accordance with Canadian general accepted accounting principles ("Canadian GAAP"). 

The preparation of these interim Condensed Consolidated Financial Statements resulted in selected changes to Caza's accounting policies as compared to those disclosed in the Company's annual audited Financial Statements for the period ended December 31, 2010 issued under GAAP.  A summary of the significant changes to Caza's accounting policies is disclosed in Note 11 along with reconciliations presenting the impact of the transition to IFRS for the comparative periods as at January 1, 2010, as and for the nine months ended September 30, 2010, and as at for the twelve months ended December 31, 2010.      

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 condensed 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 condensed 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 period 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 6 (e)).

         Jointly controlled operations and jointly controlled assets:

Many of the Company's oil and natural gas activities involve jointly controlled assets. The condensed 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 condensed consolidated financial statements.

(b)  Foreign currency:

The Company, 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 value plus any directly attributable transaction costs. Subsequent to initial recognition, non-derivative financial instruments are measured as described below.

Cash and cash equivalents:

Cash and cash equivalents comprise cash on hand, term deposits 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.

         Other:

Other non-derivative financial instruments, 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.

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 cash-generating units ("CGU")'s for impairment testing. 

The cost of property, plant and equipment at January 1, 2010, the date of transition to IFRS, was determined by allocating the net costs in the full cost pool to the areas within the CGU's according to the proven and probable reserves of each area. 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:

Office equipment                                                                                         5 - 7 years

Fixtures and fittings                                                                                    5 - 7 years

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 in the period.  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, unwinding of the discount on decommissioning liabilities and impairment losses recognized on financial assets.

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 period. Diluted earnings per share is determined by adjusting the profit or loss attributable to common shareholders and the weighted average number of common shares outstanding for the effects of dilutive instruments such as options granted to employees.  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 period.  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 period. 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.

IFRS 7 (revised)    "Financial Instruments: Disclosures"

IFRS 9 (revised)    "Financial Instruments: Classification and Measurement"

IAS 12 (revised)    "Income Taxes"

IFRS 10 (new)       "Consolidated Financial Statements"

IFRS 11 (new)       "Joint Arrangements"

IFRS 12 (new)       "Disclosure of Interests in Other Entities"

IAS 27 (revised)    "Separate Financial Statements"

IAS 28 (revised)    "Investments in Associates and Joint Ventures"

IFRS 13 (new)       "Fair Value Measurement"

IAS 1 (revised)      "Presentation of Financial Statements"

(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 interim condensed consolidated financial statements and accompanying notes.  Actual results could differ from those estimates. The interim condensed 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.

·      Estimates of recoverable quantities of proved and probable reserves include judgmental assumptions and the economic, geological and technical factors used to estimate reserves may change from period to period

·      Forward price estimates of the oil and natural gas prices are used in the impairment model.    Commodity prices have fluctuated widely in recent years due to global and regional factors including supply and demand fundamentals, inventory levels, weather, economic and geopolitical factors.

·      The impairment model uses discount rate to calculate the net present value of cash flows based on weighted average cost of capital estimates.  Changes in the general economic environment could result in significant changes in this estimate.

·      Amounts recorded from joint venture partners are based on the Company's interpretation of underlying agreements and may be subject to joint approval. The Company has recorded balances due from its joint venture partners based on costs incurred and its interpretation of allowable expenditures. Any adjustment required as a result of joint venture audits are recorded in the period of the determination with joint venture partners.

·      The provision for site restoration and abandonment is based on current legal and constructive requirements, technology, price levels and expected plans for remediation.  Actual costs and cash outflows can differ from estimates because of changes in laws and regulations, public expectations, prices and discovery and analysis of site conditions and changes in clean-up technology.

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 nine month period ended September 30, 2011, the Company expensed $3,872,640 of exploration and evaluation costs of which $2,915,699 related to the Marian Baker et al, No 1 drilled during the period ended March 31, 2011 that did not encounter hydrocarbons as well as an adjustment to the valuation of the Las Animas prospect.  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 $15,028,250 were included in the depletion calculation at September 30, 2011 and $9,292,700 for the period ended December 31, 2010.

During the three and nine months ended September 30, 2011 the Company did not capitalize general and administrative expenses (September 30, 2010 - $74,026 and $264,095) directly relating to exploration and development activities of which $9,937 and $160,202 related to stock based compensation for the three and nine months ended September 30, 2010.

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 $1,680,023 (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.         Share Capital

(a)  Authorized

 Unlimited number of voting common shares.

 Issued 

(i)  The Company issued 158,000 common shares as a result of exercised stock options

(ii) The Company issued 45,000,000 common shares in a private placement at approximately $0.67 (United Kingdom 42 pence per common share). Pursuant to this private placement, the Company incurred $1,545,896 of share issuance costs.

(iii) 18,000,000 warrants for the purchase of 19,800,000 common shares have expired as at December 31, 2010

   (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 33⅓% on the first anniversary of the date of grant and 33⅓% 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 September 30, 2011 and December 31, 2010 and changes during the respective period and year ended on those dates is presented below.

No options were granted during the nine months period ended September 30, 2011.  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.  The fair value of these options was determined using the Black-Sholes model with the following assumptions:

(d) Contributed surplus

The following table presents the changes in contributed surplus: 

(i)  During the period ended December 31, 2010 19,800,000 warrants expired with a value of $3,870,000. 

(e) Non-controlling interest

(i)    Management has a non-controlling interest in the Company which allows shares of Caza Petroleum, Inc. to be exchanged into the Company's shares at an exchange rate of 2800 to 1.

7.     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 $232,153 in joint venture partner receivables as at September 30, 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.

Cash remuneration of key management personnel of the Company, which includes directors, officers and other key personnel, is set out below in aggregate:

8.     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 0.057% as at September 30, 2011

(December 31, 2010 - 0.136%). Cash on deposit is held with Wells Fargo Bank Texas and the money market account is a fund managed by Wells Fargo Brokerage Services, LLC investing in U.S. Treasury Bill securities.

9.     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, 2010. 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.

10.   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 condensed consolidated statement of financial position date. A majority of the Company's financial assets at the condensed 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 three and nine month ended period September 30, 2011, the Company sold 63.30% and 66.22% respectively (three and nine months ended September 30, 2010 - 66.12% and 52.03% respectively) 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 September 30, 2011, the Company had overdue accounts receivable from certain joint interest partners of $17,623 which were outstanding for greater than 60 days and $610,172 that were outstanding for greater than 90 days. At September 30, 2011, the Company's two largest joint venture partners represented approximately 20% and 11% 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 condensed consolidated statement of financial position of cash and cash equivalents, accounts receivable and deposits.  The Company has their checking and money markets accounts with Wells Fargo Bank Texas, N.A.   The money market is backed by United States treasury bills.

(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 September 30, 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 condensed 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:

·    Level 1: Values based on unadjusted quoted prices in active markets that are accessible at the measurement date for identical assets or liabilities.

·    Level 2: Values based on quoted prices in markets that are not active or model inputs that are observable either directly or indirectly for substantially the full term of the asset or liability.

·    Level 3: Values based on prices or valuation techniques that require inputs that are both unobservable and significant to the overall fair value measurement.

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 condensed consolidated statement of financial position that have been designated as available-for-sale. There have been no changes to the aforementioned classifications during the periods presented. 

(e)  Liquidity Risk

Liquidity risk includes the risk that, as a result of our operational liquidity requirements:

·      The Company will not have sufficient funds to settle a transaction on the due date;

·      The Company will be forced to sell assets at a value which is less than what they are worth; or

·      The Company may be unable to settle or recover a financial asset at all.

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 September 30, 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.

11.   Transition to IFRS

The Company has adopted IFRS effective January 1, 2010 (the "transition date") and has prepared its opening IFRS condensed consolidated statement of financial position as at that date. Prior to the adoption of IFRS the Company prepared its financial statements in accordance with Canadian generally accepted accounting principles ("Canadian GAAP"). The Company's consolidated financial statements for the year ending December 31, 2011 will be the first annual financial statements that comply with IFRS. The Company will ultimately prepare its opening IFRS condensed consolidated statement of financial position by applying existing IFRS with an effective date of December 31, 2011 or prior. Accordingly, the opening IFRS condensed consolidated statement of financial position and the December 31, 2010 comparative condensed consolidated statement of financial position presented in the consolidated financial statements for the year ending December 31, 2011 may differ from those presented at this time.

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 Condensed 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 Condensed consolidated statement of financial positions as at January 1, 2010, September 30, 2010 and December 31, 2010, and Condensed Consolidated Statement of Comprehensive Loss for the three and nine months ended September 30, 2010 and the year ended December 31, 2010.

Condensed Consolidated Statement of Financial Position

As at January 1, 2010

Condensed Consolidated Statement of Financial Position

As at September 30, 2010

Condensed Consolidated Statement of Financial Position

As at December 31, 2010