CALGARY, ALBERTA — (Marketwire) — 08/10/11 — Peyto Exploration & Development Corp. (TSX: PEY) (“Peyto”) is pleased to present its operating and financial results for the second quarter of the 2011 fiscal year. Production growth of 42% per share was achieved over Q2 2010, while at the same time operating margins of 75%(1) and profit margins of 32%(2) were generated. Second quarter 2011 highlights include:
Second Quarter 2011 in Review
Peyto successfully executed on its plan to “drill through break-up” in the second quarter, taking advantage of multi-well drill pads to eliminate rig moves as the melting frost caused roads to be too soft for travel. As a result, the company continued to grow its production and funds from operations during a challenging period that saw much of the industry shut down activity and even shut in production. To the end of the second quarter, Peyto had developed over 65 MMcfe/d or 11,000 boe/d of new 2011 production at capital efficiencies similar to 2010. The completion of the Wildhay plant expansion increased the company–s 100% owned and operated gas plant capacity to 285 MMcf/d. An intense focus on cost control resulted in further reduction of Peyto–s already industry leading operating costs and contributed to maintaining a 75% operating margin with all-in cash costs of $1.40/Mcfe. Peyto–s balance sheet continued to strengthen with the debt to annualized FFO ratio dropping from 2.0 to 1.5. The strong financial and operating performance resulted in an annualized 15% Return on Equity (ROE) and 13% Return on Capital Employed (ROCE).
Exploration & Development
Peyto has now drilled over 85 horizontal multi-stage fractured gas wells in the Deep Basin. Overall, production results for the 2011 wells continue to meet or exceed company expectations with initial, 3 month, and 6 month sustained production rates exhibiting similar averages to the 2010 group of wells. In total, Peyto has 17 horizontal producers that now have over 12 months of production history. At the end of their first year, six were Cardium wells still producing an average of 190 boe/d (1.1 MMcfe/d), seven were Wilrich wells at an average of 280 boe/d (1.7 MMcfe/d) and four were Notikewin wells at an average of 285 boe/d (1.7 MMcfe/d). Some of Peyto–s first multi-stage fractured horizontal wells are now approaching two years of producing life and are showing strong continued performance in support of their assigned ultimate recoveries.
In addition to the ongoing refinement of the horizontal multi-stage fractured well design, Peyto is proceeding with a unique enhanced liquids extraction project at its Oldman gas plant in the Sundance area. This facility addition will effectively lower the temperature of the refrigeration process from -35 C to -75 C which is expected to result in the recovery of an additional 15 barrels of natural gas liquids per MMcf of natural gas sales while only reducing the heat content of the sales gas stream by 3%. The Oldman plant is currently delivering just over 100 MMcf/d of sales gas. This project is estimated to cost less than $20 million and is expected to be operational by Q3 2012.
Capital Expenditures
In the second quarter, Peyto executed its plan to maintain a high level of drilling activity, through the traditional spring thaw period, by utilizing multi-well drilling pads to minimize rig movement when roads are too soft to travel. As a result 12 gross (10.6 net) wells were drilled, 16 gross (12.4 net) zones completed and 14 gross (11.5 net) zones brought on stream. Capital expenditures for the quarter totaled $69 million (net of $2.6 million in Drilling Royalty Credit adjustments), up 84% from Q2 2010, with drilling, completions and wellsite connections accounting for $32.2 million, $17.5 million and $4.7 million, respectively. In addition, Peyto continued to increase its facility capacity with expansions at Wildhay and Nosehill gas plants totaling $15.8 million in capital investment. Investments in new undeveloped land and seismic totaled $1.4 million.
All of the wells drilled in the second quarter were horizontal wells as Peyto continued to use this technique to develop the multiple prospective formations in its extensive Deep Basin inventory. Of the 12 wells drilled, 5 were in the Notikewin formation, 4 in the Wilrich, and 3 in the Cardium. With each successful well drilled, future inventory was further proven and expanded.
As of the end of Q2 2011, a total of 31 gross (26.7 net) wells have been brought on stream. Total capital invested in the first half of 2011 was $172.8 million which has resulted in 11,000 boe/d of new production at a cost of $15,700/boe/d. This level of capital efficiency compares favorably to the efficiency realized in 2010. This new production is comprised of 16% from the Cardium formation, 32% from the Notikewin, 14% from the Falher and 38% from the Wilrich.
Financial Results
A natural gas price of $4.43/Mcf and a liquids price of $84.06/bbl were realized in the second quarter which combined for a net effective sales price of $5.50/Mcfe. Cash costs of $0.64/Mcfe for royalties, $0.32/Mcfe for operating, $0.13/Mcfe for transportation, $0.07/Mcfe for G&A and $0.24/Mcfe for interest reduced this sales price to a cash netback of $4.10/Mcfe or $24.60/boe. This netback divided by the effective sales price equated to a 75% operating margin, consistent with the previous quarter but improved from the 70% margin of a year ago.
DD&A costs of $1.64/Mcfe and a provision for deferred income tax and performance based compensation reduced the cash netback of $4.10/Mcfe to earnings of $1.74/Mcfe or a 32% profit margin, consistent with both the previous quarter and previous year.
Marketing
Second quarter Alberta daily natural gas prices averaged the same as a year ago but improved slightly from the previous quarter, increasing from $3.56/GJ to $3.67/GJ. This slight improvement was driven by the onset of warmer than normal US summer weather and the expectation of less domestic production growth. Average liquids price was up 28% to $84.06/bbl as a rise in crude oil prices saw par crude postings at Edmonton average $103.60/bbl. Peyto realized gains from its previous forward sales of natural gas of $6.6 million or $0.40/Mcf in Q2 2011 versus $11.4 million or $1.11/Mcf in Q2 2010.
As at June 30, 2011, Peyto had committed to the future sale of 38,770,000 gigajoules (GJ) of natural gas at an average price of $4.31 per GJ or $5.05 per mcf (based on Peyto–s historical heat content premium). Had these contracts been closed on June 30, 2011, Peyto would have realized a gain in the amount of $18.6 million. The average future sales price of $4.31/GJ is 22% lower than last year–s price of $5.52/GJ.
Activity Update
Post break-up activity has resumed to a high level despite some weather related delays experienced through late June and early July. Daily production has recently reached the 37,000 boe/d targeted exit rate for 2011. Wells drilled in 2011 have contributed over 13,000 boe/d of this amount, up from the Q2 exit level of 11,000 boe/d.
To date, 42 gross (36.1 net) wells have been spud this year and 38 gross (32.4 net) new wells have been brought onstream. Peyto has five rigs currently drilling, four in the greater Sundance area and one in the company–s northern Cardium lands.
Outlook
Peyto continues to deliver substantial, profitable growth in production and cashflow in 2011. With a rich and deep inventory of proven opportunities, greater than at any other time in the company–s twelve year history, Peyto is well positioned to continue this trend into the future. These opportunities, coupled with a strict focus on cost control, mean Peyto is uniquely capable of not only surviving a prolonged period of depressed natural gas prices, but of generating significant and profitable growth in such an environment.
As a result of the continued high returns generated in the first half of 2011, Peyto–s Board of Directors has approved the expansion of the 2011 capital program to be between $350 and $375 million, assuming market conditions remain favourable. Based on Peyto–s internal forecasts and current strip pricing, funds from operations are expected to continue to grow faster than debt. The larger capital program results in a year-end debt to FFO ratio that is expected to remain at current levels.
The strength of Peyto–s assets and its balance sheet continue to allow the company to be opportunistic in today–s volatile business climate. Management believes the “economic moat” that surrounds Peyto–s business “fortress” is wider and deeper than ever.
Shareholders are encouraged to visit the Peyto website at where there is a wealth of information designed to inform and educate investors. A monthly President–s Report can also be found on the website which follows the progress of the capital program and the ensuing production growth.
Conference Call and Webcast
A conference call will be held with the senior management of Peyto to answer questions with respect to the 2011 second quarter on Thursday, August 11th, 2011, at 9:00 a.m. Mountain Daylight Time (MDT), or 11:00 a.m. Eastern Daylight Time (EDT). To participate, please call 1-416-695-7848 (Toronto area) or 1-800-952-6845 for all other participants. The conference call will also be available on replay by calling 1-905-694-9451 (Toronto area) or 1-800-408-3053 for all other parties, using passcode 5210084. The replay will be available at 11:00 a.m. MDT, 1:00 p.m. EDT Thursday, August 11th, 2011 until midnight EDT on Thursday, August 18th, 2011. The conference call can also be accessed through the internet at . After this time the conference call will be archived on the Peyto Exploration & Development website at .
Management–s Discussion and Analysis
Management–s Discussion and Analysis of this second quarter report is available on the Peyto website at . A complete copy of the second quarter report to Shareholders, including the Management–s Discussion and Analysis, and financial statements and related notes is also available at and will be filed at SEDAR, , at a later date.
Darren Gee, President and CEO
August 10, 2011
Certain information set forth in this document and Management–s Discussion and Analysis, including management–s assessment of Peyto–s future plans and operations, contains forward-looking statements. By their nature, forward-looking statements are subject to numerous risks and uncertainties, some of which are beyond these parties– control, including the impact of general economic conditions, industry conditions, volatility of commodity prices, currency fluctuations, imprecision of reserve estimates, environmental risks, competition from other industry participants, the lack of availability of qualified personnel or management, stock market volatility and ability to access sufficient capital from internal and external sources. Readers are cautioned that the assumptions used in the preparation of such information, although considered reasonable at the time of preparation, may prove to be imprecise and, as such, undue reliance should not be placed on forward-looking statements. Peyto–s actual results, performance or achievement could differ materially from those expressed in, or implied by, these forward-looking statements and, accordingly, no assurance can be given that any of the events anticipated by the forward-looking statements will transpire or occur, or if any of them do so, what benefits Peyto will derive therefrom.
Peyto Exploration & Development Corp.
Notes to Condensed Financial Statements (unaudited)
As at June 30, 2011 and 2010
(Amount in $ thousands, except as otherwise noted)
1. Nature of operations
Peyto Exploration & Development Corp. (“Peyto” or the “Company”) is a Calgary based oil and natural gas company. The Company conducts exploration, development and production activities in Canada. Peyto is incorporated and domiciled in the Province of Alberta, Canada. The address of its registered office is 1500, 250 – 2nd Street SW, Calgary, Alberta, Canada, T2P 0C1.
On December 31, 2010, Peyto completed the conversion from an income trust to a corporation pursuant to an arrangement under the Business Corporations Act (Alberta); the (“2010 Arrangement”). As a result of this conversion, units of Peyto Energy Trust (the “Trust”) were exchanged for common shares of Peyto on a one-for-one basis (see Note 7).
The conversion has been accounted for as a continuity of interests and all comparative information presented for the pre-conversion period is that of the Trust. All transaction costs associated with the conversion were expensed as incurred as general and administration expense.
There were no changes in Peyto–s underlying operations associated with the 2010 Arrangement. The condensed financial statements and related financial information have been prepared on a continuity of interest basis, which recognizes Peyto as the successor entity and accordingly all comparative information presented for the preconversion period is that of the Trust. For the convenience of the reader, when discussing prior periods, the condensed financial statements refer to common shares, shareholders and dividends although for the pre-conversion period such items were trust units, unitholders– and distributions, respectively.
Following the completion of the 2010 Arrangement, Peyto does not have any subsidiaries.
These condensed financial statements were approved and authorized for issuance by the Audit Committee of the Board of Directors of Peyto on August 9, 2011.
2. Basis of presentation
These unaudited condensed financial statements (“financial statements”) for the three and six months ended June 30, 2011 have been prepared in accordance with International Accounting Standard (“IAS”) 34 Interim Financial Reporting. These condensed interim financial statements do not include all of the information required for annual financial statements. Amounts relating to the three and six months ended June 30, 2010 and as at December 31, 2010 were previously presented in accordance with Canadian generally accepted accounting principles (“Canadian GAAP”). These amounts have been restated as necessary to be compliant with our accounting policies under International Financial Reporting Standards (“IFRS”), which are included below. Reconciliations and descriptions relating to the transition from Canadian GAAP to IFRS are included in Note 17.
a) Summary of significant accounting policies
The precise determination of many assets and liabilities is dependent upon future events, the preparation of periodic financial statements necessarily involves the use of estimates and approximations. Accordingly, actual results could differ from those estimates. The financial statements have, in management–s opinion, been properly prepared within reasonable limits of materiality and within the framework of the Company–s basis of presentation as disclosed.
The following significant accounting policies have been adopted in the preparation and presentation of the financial report:
b) Significant accounting estimates and judgements
The timely preparation of the unaudited condensed financial statements in conformity with International Financial Reporting Standards (“IFRS”) requires that management make estimates and assumptions and use judgment regarding the reported amounts of assets and liabilities and disclosures of contingent assets and liabilities at the date of the unaudited condensed financial statements and the reported amounts of revenues and expenses during the period. Such estimates primarily relate to unsettled transactions and events as of the date of the condensed financial statements. Accordingly, actual results may differ from estimated amounts as future confirming events occur.
Amounts recorded for depreciation, depletion and amortization, decommissioning costs and obligations and amounts used for impairment calculations are based on estimates of gross proved reserves and future costs required to develop those reserves. By their nature, these estimates of reserves, including the estimates of future prices and costs, and the related future cash flows are subject to measurement uncertainty, and the impact in the condensed financial statements of future periods could be material.
The amount of compensation expense accrued for future performance based compensation arrangements are subject to management–s best estimate of whether or not the performance criteria will be met and what the ultimate payout will be.
Tax interpretations, regulations and legislation in the various jurisdictions in which the Company and its subsidiaries operate are subject to change. As such, income taxes are subject to measurement uncertainty.
c) Presentation currency
All amounts in these financial statements are expressed in Canadian dollars, as this is the functional and presentation currency of the Company.
d) Jointly controlled assets
A jointly controlled asset involves joint control and offers joint ownership by the Company and other partners of assets contributed to or acquired for the purpose of the jointly controlled assets, without the formation of a corporation, partnership or other entity.
The Company accounts for its share of the jointly controlled assets, any liabilities it has incurred, its share of any liabilities jointly incurred with its partners, income from the sale or use of its share of the joint venture–s output, together with its share of the expenses incurred by the jointly controlled asset and any expenses it incurs in relation to its interest in the jointly controlled asset.
e) Exploration and evaluation assets
Pre-license costs
Costs incurred prior to obtaining the legal right to explore for hydrocarbon resources are expensed in the period in which they are incurred. The Company has no pre-license costs.
Exploration and evaluation costs
Once the legal right to explore has been acquired, costs directly associated with an exploration well are capitalized as exploration and evaluation intangible assets until the drilling of the well is complete and the results have been evaluated. All such costs are subject to technical feasibility, commercial viability and management review as well as review for impairment at least once a year to confirm the continued intent to develop or otherwise extract value from the discovery. The Company has no exploration or evaluation costs.
f) Property, plant and equipment, net
Oil and gas properties and other property, plant and equipment is stated at cost, less accumulated depreciation and accumulated impairment losses.
The initial cost of an asset comprises its purchase price or construction cost, any costs directly attributable to bringing the asset into operation, the initial estimate of the decommissioning provision and borrowing costs for qualifying assets. The purchase price or construction cost is the aggregate amount paid and the fair value of any other consideration given to acquire the asset. Costs include expenditures on the construction, installation or completion of infrastructure such well sites, pipelines and facilities including activities such as drilling, completion and tie-in costs, equipment and installation costs, associated geological and human resource costs, including unsuccessful development or delineation wells.
Oil and natural gas asset swaps
For exchanges or parts of exchanges that involve assets, the exchange is accounted for at fair value. Assets are then de-recognized at their current carrying value.
Depletion and Depreciation
Oil and natural gas properties are depleted on a unit-of-production basis over the proved plus probable reserves. All costs related to oil and natural gas properties (net of salvage value) and estimated costs of future development of proved plus probable undeveloped reserves are depleted and depreciated using the unit-of-production method based on estimated gross proved plus probable reserves as determined by independent engineers. For purposes of the depletion and depreciation calculation, relative volumes of petroleum and natural gas production and reserves are converted at the energy equivalent conversion rate of six thousand cubic feet of natural gas to one barrel of crude oil.
Other property, plant and equipment are depreciated using a declining balance method over remaining useful life.
g) Corporate Assets
Corporate assets not related to oil and natural gas exploration and development activities are recorded at historical costs and depreciated over their useful life. These assets are not significant or material in nature.
h) Impairment of non-financial assets
The Company assesses at each reporting date whether there is an indication that an asset may be impaired. If any indication exists, or when annual impairment testing for an asset is required, the Company estimates the asset–s recoverable amount. An asset–s recoverable amount is the higher of fair value less costs to sell or value-in-use and is determined for an individual asset, unless the asset does not generate cash inflows that are largely independent of those from other assets or groups of assets, in which case the recoverable amount is assessed as part of a cash generating unit (“CGU”). If the carrying amount of an asset or CGU exceeds its recoverable amount, the CGU is considered impaired and is written down to its recoverable amount. In assessing value-in-use, the estimated future cash flows are discounted to their present value using a pre-tax discount rate that reflects current market assessments of the time value of money and the risks specific to the asset. In determining fair value less costs to sell, recent market transactions are taken into account, if available. If no such transactions can be identified, an appropriate valuation model is used. These calculations are corroborated by valuation multiples, quoted share prices for publicly traded subsidiaries or other available fair value indicators.
Impairment losses of continuing operations are recognized in the income statement.
An assessment is made at each reporting date as to whether there is any indication that previously recognized impairment losses may no longer exist or may have decreased. If such indication exists, the Company estimates the asset–s or cash-generating unit–s recoverable amount. A previously recognized impairment loss is reversed only if there has been a change in the assumptions used to determine the asset–s recoverable amount since the last impairment loss was recognized. The reversal is limited so that the carrying amount of the asset does not exceed its recoverable amount, nor exceed the carrying amount that would have been determined, net of depreciation, had no impairment loss been recognized for the asset in prior years.
i) Leases
Leases or other arrangements entered into for the use of an asset are classified as either finance or operating leases. Finance leases transfer to the Company substantially all of the risks and benefits incidental to ownership of the leased asset. Assets under finance lease are amortized over the shorter of the estimated useful life of the assets and the lease term. All other leases are classified as operating leases and the payments are amortized on a straight-line basis over the lease term.
j) Financial instruments
Financial instruments within the scope of IAS 39 Financial Instruments: Recognition and Measurement (“IAS 39”) are initially recognized at fair value on the condensed balance sheet. The Company has classified each financial instrument into the following categories: “fair value through profit or loss”; “loans & receivables”; and “other liabilities”. Subsequent measurement of the financial instruments is based on their classification. Unrealized gains and losses on held for trading financial instruments are recognized in earnings. The other categories of financial instruments are recognized at amortized cost using the effective interest rate method. The Company has made the following classifications:
Derivative Instruments and Risk Management
Derivative instruments are utilized by the Company to manage market risk against volatility in commodity prices. The Company–s policy is not to utilize derivative instruments for speculative purposes. The Company has chosen to designate its existing derivative instruments as cash flow hedges. The Company assesses, on an ongoing basis, whether the derivatives that are used as cash flow hedges are highly effective in offsetting changes in cash flows of hedged items. All derivative instruments are recorded on the balance sheet at their fair value. The effective portion of the gains and losses is recorded in other comprehensive income until the hedged transaction is recognized in earnings. When the earnings impact of the underlying hedged transaction is recognized in the condensed income statement, the fair value of the associated cash flow hedge is reclassified from other comprehensive income into earnings. Any hedge ineffectiveness is immediately recognized in earnings. The fair values of forward contracts are based on forward market prices.
Embedded Derivatives
An embedded derivative is a component of a contract that causes some of the cash flows of the combined instrument to vary in a way similar to a stand-alone derivative. This causes some or all of the cash flows that otherwise would be required by the contract to be modified according to a specified variable, such as interest rate, financial instrument price, commodity price, foreign exchange rate, a credit rating or credit index, or other variables to be treated as a financial derivative. The Company has no contracts containing embedded derivatives.
Normal purchase or sale exemption
Contracts that were entered into and continue to be held for the purpose of the receipt or delivery of a non-financial item in accordance with the Company–s expected purchase, sale or usage requirements fall within the exemption from IAS 32 Financial Instruments: Presentation (“IAS 32”) and IAS 39, which is known as the –normal purchase or sale exemption–. The Company recognizes such contracts in its balance sheet only when one of the parties meets its obligation under the contract to deliver either cash or a non-financial asset.
k) Hedging
The Company uses derivative financial instruments from time to time to hedge its exposure to commodity price fluctuations. All derivative financial instruments are initiated within the guidelines of the Company–s risk management policy. This includes linking all derivatives to specific assets and liabilities on the balance sheet or to specific firm commitments or forecasted transactions. The Company enters into hedges of its exposure to petroleum and natural gas commodity prices by entering into natural gas fixed price contracts, when it is deemed appropriate. These derivative contracts, accounted for as hedges, are recognized on the balance sheet. Realized gains and losses on these contracts are recognized in oil and natural gas revenue and cash flows in the same period in which the revenues associated with the hedged transaction are recognized. For financial derivative contracts settling in future periods, a financial asset or liability is recognized in the balance sheet and measured at fair value, with changes in fair value recognized in other comprehensive income.
l) Inventories
Inventories are stated at the lower of cost and net realizable value. Cost of producing oil and natural gas is accounted on a weighted average basis. This cost includes all costs incurred in the normal course of business in bringing each product to its present location and condition.
m) Provisions
General
Provisions are recognized when the Company has a present obligation (legal or constructive) as a result of a past event, it is probable that an outflow of resources embodying economic benefits will be required to settle the obligation and a reliable estimate can be made of the amount of the obligation. Where the Company expects some or all of a provision to be reimbursed, the reimbursement is recognized as a separate asset but only when the reimbursement is virtually certain. The expense relating to any provision is presented in the income statement net of any reimbursement. If the effect of the time value of money is material, provisions are discounted using a current pre-tax rate that reflects, where appropriate, the risks specific to the liability. Where discounting is used, the increase in the provision due to the passage of time is recognized as a finance cost.
Decommissioning provision
Decommissioning provision is recognized when the Company has a present legal or constructive obligation as a result of past events, and it is probable that an outflow of resources will be required to settle the obligation, and a reliable estimate of the amount of obligation can be made. A corresponding amount equivalent to the provision is also recognized as part of the cost of the related property, plant and equipment. The amount recognized is the estimated cost of decommissioning, discounted to its present value using a risk-free rate. Changes in the estimated timing of decommissioning or decommissioning cost estimates are dealt with prospectively by recording an adjustment to the provision, and a corresponding adjustment to property, plant and equipment. The accretion of the discount on the decommissioning provision is included as a finance cost.
n) Taxes
Current income tax
Current income tax assets and liabilities for the current and prior periods are measured at the amount expected to be recovered from or paid to the taxation authorities. The tax rates and tax laws used to compute the amount are those that are enacted or substantively enacted, at the reporting date, in Canada.
Current income tax relating to items recognized directly in equity is recognized in equity and not in the income statement. Management periodically evaluates positions taken in the tax returns with respect to situations in which applicable tax regulations are subject to interpretation and establishes provisions where appropriate.
Deferred tax
The Company follows the liability method of accounting for income taxes. Under this method, income tax assets and liabilities are recognized for the estimated tax consequences attributable to differences between the amounts reported in the financial statements and their respective tax bases, using enacted or substantively enacted tax rates expected to apply when the asset is realized or the liability settled. Deferred tax assets are only recognized to the extent it is probable that sufficient future taxable income will be available to allow the future income tax asset to be realized. Accumulated deferred tax balances are adjusted to reflect changes in income tax rates that are substantively enacted with the adjustment being recognized in earnings in the period that the change occurs, except for items recognized in shareholders– equity.
o) Revenue recognition
Revenue from the sale of oil, natural gas and natural gas liquids is recognized when the significant risks and rewards of ownership have been transferred, which is when title passes to the purchaser. This generally occurs when product is physically transferred into a pipe or other delivery system.
Gains and Losses on Disposition
For all dispositions, either through sale or exchange, gains and losses are calculated as the difference between the sale or exchange value in the transaction and the carrying value of the disposed assets disposed. Gains and losses on disposition are recognized in earnings in the same period as the transaction date.
p) Borrowing costs
Borrowing costs directly relating to the acquisition, construction or production of a qualifying capital project under construction are capitalized and added to the project cost during construction until such time the assets are substantially ready for their intended use, which is, when they are capable of commercial production. Where the funds used to finance a project form part of general borrowings, the amount capitalized is calculated using a weighted average of rates applicable to relevant general borrowings of the Company during the period. All other borrowing costs are recognized in the income statement in the period in which they are incurred.
q) Share-based payments
Liability-settled share-based payments to employees are measured at the fair value of the liability award at the grant date. A liability equal to fair value of the payments is accrued over the vesting period measured at fair value using the Black-Scholes option pricing model.
The fair value determined at the grant date of the liability-settled share-based payments is expensed on a graded basis over the vesting period, based on the Company–s estimate of liability instruments that will eventually vest. At the end of each reporting period, the Company revises its estimate of the number of liability instruments expected to vest. The impact of the revision of the original estimates, if any, is recognized in the income statement such that the cumulative expense reflects the revised estimate, with a corresponding adjustment to related liability on the balance sheet.
r) Earnings per share
Basic and diluted earnings per share is computed by dividing the net earnings available to common shareholders by the weighted average number of shares outstanding during the reporting period. The Company has no dilutive instrument outstanding which would cause a difference between the basic and diluted earnings per share.
s) Share capital
Common shares are classified within shareholders– equity. Incremental costs directly attributable to the issuance of shares are recognized as a deduction from shareholders– capital.
t) Standards issued but not yet effective
Presentation of Financial Statements
As of January 1, 2012, the Company will be required to adopt IAS 1, “Presentation of Items of OCI: Amendments to IAS 1 Presentation of Financial Statements.” The amendments stipulate the presentation of net earnings and OCI and also require the Company to group items within OCI based on whether the items may be subsequently reclassified to profit or loss. The adoption of the amendments to this standard is not expected to have a material impact on the Company–s financial position or results.
Financial Instruments
As of January 1, 2013, the Company will be required to adopt IFRS 9 “Financial Instruments” which covers the classification and measurement of financial assets as part of its project to replace IAS 39 “Financial Instruments: Recognition and Measurement.” This standard replaces the current models for financial assets and liabilities with a single model. Under this guidance, entities have the option to recognize financial liabilities at fair value through profit or loss. If this option is elected, entities would be required to reverse the portion of the fair value change due to its own credit risk out of profit or loss and recognize the change in other comprehensive income. The implementation of the issued standard is not expected to have a material impact on the Company–s financial position or results.
Consolidated Financial Statements
As of January 1, 2013, the Company will be required to adopt IFRS 10, “Consolidated Financial Statements,” which provides a single control model to be applied in the assessment of control for all entities in which the Company has an investment, including special purpose entities currently in the scope of Standing Interpretations Committee (“SIC”) 12. Under the new control model, the Company has control over an investment if the Company has the ability to direct the activities of the investment, is exposed to the variability of returns from the investment and there is a linkage between the ability to direct activities and the variability of returns. The Company does not expect IFRS 10 to have a material impact on its financial position or results.
Joint Arrangements
As of January 1, 2013, the Company will be required to adopt IFRS 11, “Joint Arrangements,” which specifies that joint arrangements are classified as either joint operations or joint ventures. Parties to a joint operation retain the rights and obligations to individual assets and liabilities of the operation, while parties to a joint venture have rights to the net assets of the venture. Any arrangement which is not structured through a separate entity or is structured through a separate entity but such separation is ineffective such that the parties to the arrangement have rights to the assets and obligations for the liabilities will be classified as a joint operation. Joint operations shall be accounted for in a manner consistent with jointly controlled assets and operations whereby the Company–s contractual share of the arrangement–s assets, liabilities, revenues and expenses are included in the consolidated financial statements. Any arrangement structured through a separate vehicle that does effectively result in separation between the Company and the arrangement shall be classified as a joint venture and accounted for using the equity method of accounting. Under the existing IFRS standard, the Company has the option to account for any interests it has in joint ventures using proportionate consolidation or equity accounting. The Company does not expect IFRS 11 to have a material impact on its financial position or results.
Disclosure of Interests in Other Entities
As of January 1, 2013, the Company will be required to adopt IFRS 12, “Disclosure of Interests in Other Entities,” which contains new disclosure requirements for interests the Company has in subsidiaries, joint arrangements, associates and unconsolidated structured entities. Required disclosures aim to provide readers of the financial statements with information to evaluate the nature of and risks associated with the Company–s interests in other entities and the effects of those interests on the Company–s financial statements. The Company intends to adopt IFRS 12 in its financial statements for the annual period beginning on January 1, 2013. The Company does not expect IFRS 12 to have a material impact on its financial position or results.
Investments in Associates and Joint Ventures
As of January 1, 2013, the Company will be required to adopt amendments to IAS 28, “Investments in Associates and Joint Ventures,” which provide additional guidance applicable to accounting for interests in joint ventures or associates when a portion of an interest is classified as held for sale or when the Company ceases to have joint control or significant influence over an associate or joint venture. When joint control or significant influence over an associate or joint venture ceases, the Company will no longer be required to re-measure the investment at that date. When a portion of an interest in a joint venture or associate is classified as held for sale, the portion not classified as held for sale shall be accounted for using the equity method of accounting until the sale is completed at which time the interest is reassessed for prospective accounting treatment. The Company does not expect the amendments to IAS 28 to have a material impact on the financial position or results.
Fair Value Measurement
As of January 1, 2013, the Company will be required to adopt IFRS 13, “Fair Value Measurement,” which replaces fair value measurement guidance contained in individual IFRSs, providing a single source of fair value measurement guidance. The standard provides a framework for measuring fair value and establishes new disclosure requirements to enable readers to assess the methods and inputs used to develop fair value measurements and for recurring valuations that are subject to measurement uncertainty, the effect of those measurements on the financial statements. The Company intends to adopt IFRS 13 prospectively in its financial statements for the annual period beginning on January 1, 2013. The extent of the impact of adoption of IFRS 13 has not yet been determined.
Employee Benefits
As of January 1, 2013, the Company will be required to adopt IAS 19, “Employee Benefits” which eliminates the corridor method that permits the deferral of actuarial gains and losses, to revise the presentation requirements for changes in defined benefit plan assets and liabilities and to enhance the required disclosures for defined benefit plans. The Company does not expect the amendments to IAS 19 to have a material impact on the financial position or results.
Canada Revenue Agency (“CRA”) conducted an audit of Peyto–s restructuring costs incurred in the 2003 trust conversion. On September 25, 2008, the CRA reassessed on the basis that $41 million of these costs were not deductible and treated them as an eligible capital amount. Peyto filed a notice of objection and the CRA confirmed the reassessment. Examinations for discovery have been completed. A trial date has not been set. The Tax Court of Canada has agreed to both parties– request to hold Peyto–s appeal in abeyance pending a decision of the Federal Court of Appeal in another taxpayer–s appeal. The other appeal raises issues that are similar in principle to those raised in Peyto–s appeal. Based upon consultation with legal counsel, Management–s view is that it is likely that Peyto–s appeal will succeed.
During the three and six month period ended June 30, the Company capitalized $1.0 million and $2.3 million (2010 – $0.9 and $1.7 million) of general and administrative and share based payments directly attributable to production and development activities.
The Company performs an impairment test calculation when indicators are present which negatively affect the value of the Company–s individual assets or its total asset base. Assets which have indicators of impairment are then aggregated to its cash-generating units at which point the measurement of impairment is calculated.
The Company did not have any indicators of impairment in the current period.
5. Long-term debt
The Company has a syndicated $625 million extendible revolving credit facility with a stated term date of April 29, 2012. The facility is made up of a $20 million working capital sub-tranche and a $605 million production line. The facilities are available on a revolving basis for a period of at least 364 days and upon the term out date may be extended for a further 364 day period at the request of the Company, subject to approval by the lenders. In the event that the revolving period is not extended, the facility is available on a non-revolving basis for a further one year term, at the end of which time the facility would be due and payable. Outstanding amounts on this facility bear interest at rates determined by the Company–s debt to cash flow ratio that range from prime to prime plus 1.25% to 2.75% for debt to earnings before interest, taxes, depreciation, depletion and amortization (EBITDA) ratios ranging from less than 1:1 to greater than 2.5:1. A General Security Agreement with a floating charge on land registered in Alberta is held as collateral by the bank.
Total cash interest expense for the three months ended was $4.5 million (2010 – $5.0 million) and the average borrowing rate for the period was 4.1% (2010 – 4.9%). Total cash interest expense for the six months ended was $9.1 million (2010 – $9.4 million) and the average borrowing rate for the period was 4.4% (2010 – 4.4%).
6. Decommissioning provision
The Company makes provision for the future cost of decommissioning wells, pipelines and facilities on a discounted basis based on the commissioning of these assets.
The decommissioning provision represents the present value of the decommissioning costs related to the above infrastructure, which are expected to be incurred over the economic life of the assets. The provisions have been based on the Company–s internal estimates on the cost of decommissioning, the discount rate, the inflation rate and the economic life of the infrastructure. Assumptions, based on the current economic environment, have been made which management believes are a reasonable basis upon which to estimate the future liability. These estimates are reviewed regularly to take into account any material changes to the assumptions. However, actual decommissioning costs will ultimately depend upon the future market prices for the necessary decommissioning work required which will reflect market conditions at the relevant time. Furthermore, the timing of the decommissioning is likely to depend on when production activities ceases to be economically viable. This in turn will depend and be directly related to the current and future commodity prices, which are inherently uncertain.
Units Issued
On November 30, 2010, Peyto closed an offering of 8,314,500 trust units at a price of $17.30 per trust unit, receiving proceeds of $138.8 million (net of issuance costs).
On April 27, 2010, Peyto closed an offering of 5,566,000 trust units at a price of $13.45 per trust unit, receiving proceeds of $71.7 million (net of issuance costs).
Peyto reinstated its amended distribution reinvestment and optional trust unit purchase plan (the “Amended DRIP Plan”) effective with the January 2010 distribution whereby eligible Unitholders may elect to reinvest their monthly cash distributions in additional trust units at a 5% discount to market price. The Distribution Reinvestment Plan (“DRIP”) incorporates an Optional Trust Unit Purchase Plan (“OTUPP”) which provides unitholders enrolled in the DRIP with the opportunity to purchase additional trust units from treasury using the same pricing as the DRIP.
Common Shares Issued
On December 31, 2010, Peyto converted all outstanding trust units into common shares on a one share per trust unit basis. At December 31, 2010 there were 131,875,382 shares outstanding. The DRIP and the OTUPP plans were cancelled December 31, 2010.
On December 31, 2010, the Company completed a private placement of 655,581 common shares to employees and consultants for net proceeds of $12.4 million ($18.95 per share). These common shares were issued on January 6, 2011.
On January 14, 2011, 279,723 common shares (113,527 pursuant to the DRIP and 166,196 pursuant to the OTUPP) were issued for net proceeds of $4.9 million.
On March 25, 2011, Peyto completed a private placement of 250,615 common shares to employees and consultants for net proceeds of $4.6 million ($18.86 per share). Subsequent to the issuance of these shares, 133,061,301 common shares were outstanding.
Per Share or Per Units Amounts
Earnings per share or unit have been calculated based upon the weighted average number of common shares outstanding for the three month and six month period ended of 133,061,301 and 132,900,079 (2010 – 119,419,799 and 117,298,518), respectively. There are no dilutive instruments outstanding.
Dividends
During the three and six months ended June 30, 2011, Peyto declared and paid dividends of $0.18 and $0.36 per common share, respectively or $0.06 per common share per month, totaling $24.0 million and $47.9 million (2010 – $0.36 and $0.72 per share, respectively or $0.12 per share per month, $43.6 million and $85.1 million), respectively.
Comprehensive Income
Comprehensive income consists of earnings and other comprehensive income (“OCI”). OCI comprises the change in the fair value of the effective portion of the derivatives used as hedging items in a cash flow hedge. “Accumulated other comprehensive income” is an equity category comprised of the cumulative amounts of OCI.
Gains and losses from cash flow hedges are accumulated until settled. These outstanding hedging contracts are recognized in earnings on settlement with gains and losses being recognized as a component of net revenue. Further information on these contracts is set out in Note 13.
8. Operating expenses
The Company–s operating expenses include all costs with respect to day-to-day well and facility operations. Processing and gathering recoveries related to jointly controlled assets and third party natural gas reduces operating expenses.
11. Future Performance based compensation
The Company awards performance based compensation to employees annually. The performance based compensation is comprised of reserve and market value based components.
Reserve Based Component
The reserves value based component is 4% of the incremental increase in value, if any, as adjusted to reflect changes in debt, equity, distributions, general and administrative costs and interest, of proved producing reserves calculated using a constant price at December 31 of the current year and a discount rate of 8%.
Market Based Component
Under the market based component, rights with a three year vesting period are allocated to employees. The number of rights outstanding at any time is not to exceed 6% of the total number of common shares outstanding. At December 31 of each year, all vested rights are automatically cancelled and, if applicable, paid out in cash. Compensation is calculated as the number of vested rights multiplied by the total of the market appreciation (over the price at the date of grant) and associated dividends of a common share for that period.
The fair values were calculated using a Black-Scholes valuation model. The principal inputs to the option valuation model were:
12. Financial instruments
Financial Instrument Classification and Measurement
Financial instruments of the Company carried on the balance sheet are carried at amortized cost with the exception of cash and financial derivative instruments, specifically fixed price contracts, which are carried at fair value. There are no significant differences between the carrying value of financial instruments and their estimated fair values as at June 30, 2011.
The fair value of the Company–s cash and financial derivative instruments are quoted in active markets. The Company classifies the fair value of these transactions according to the following hierarchy.
– Level 1 – quoted prices in active markets for identical financial instruments.
– Level 2 – quoted prices for similar instruments in active markets; quoted prices for identical or similar instruments in markets that are not active; and model-derived valuations in which all significant inputs and significant and significant value drivers are observable in active markets.
– Level 3 – valuations derived from valuation techniques in which one or more significant inputs or significant value drivers are unobservable.
The Company–s cash and financial derivative instruments have been assessed on the fair value hierarchy described above and classified as Level 1.
Fair Values of Financial Assets and Liabilities
The Company–s financial instruments include cash, accounts receivable, financial derivative instruments, due from private placement, current liabilities, provision for future performance based compensation and long term debt. At June 30, 2011, the carrying value of cash and financial derivative instruments are carried at fair value. Accounts receivable, due from private placement, current liabilities and provision for future performance based compensation approximate their fair value due to their short term nature. The carrying value of the long term debt approximates its fair value due to the floating rate of interest charged under the credit facility.
Market Risk
Market risk is the risk that changes in market prices will affect the Company–s earnings or the value of its financial instruments. Market risk is comprised of commodity price risk and interest rate risk. The objective of market risk management is to manage and control exposures within acceptable limits, while maximizing returns. The Company–s objectives, processes and policies for managing market risks have not changed from the previous year.
Commodity Price Risk Management
The Company is a party to certain derivative financial instruments, including fixed price contracts. The Company enters into these contracts with well established counterparties for the purpose of protecting a portion of its future earnings and cash flows from operations from the volatility of petroleum and natural gas prices. The Company believes the derivative financial instruments are effective as hedges, both at inception and over the term of the instrument, as the term and notional amount do not exceed the Company–s firm commitment or forecasted transactions and the underlying basis of the instruments correlate highly with the Company–s exposure.
As at June 30, 2011, the Company had committed to the future sale of 38,770,000 gigajoules (GJ) of natural gas at an average price of $4.31 per GJ or $5.05 per mcf based on the historical heating value of Peyto–s natural gas. Had these contracts been closed on June 30, 2011, the Company would have realized a gain in the amount of $18.6 million. If the AECO gas price on June 30, 2011 were to increase by $1/GJ, the unrealized gain would decrease by approximately $38.8 million. An opposite change in commodity prices rates would result in an opposite impact on earnings which would have been reflected in other comprehensive income.
Interest rate risk
The Company is exposed to interest rate risk in relation to interest expense on its revolving credit facility. Currently, the Company has not entered into any agreements to manage this risk. If interest rates applicable to floating rate debt were to have increased by 100 bps (1%) it is estimated that the Company–s earnings for the three month and six month period ended June 30, 2011 would decrease by $1.1 million and $2.1 million, respectively. An opposite change in interest rates will result in an opposite impact on earnings.
Credit Risk
A substantial portion of the Company–s accounts receivable is with petroleum and natural gas marketing entities. Industry standard dictates that commodity sales are settled on the 25th day of the month following the month of production. The Company generally extends unsecured credit to purchasers, and therefore, the collection of accounts receivable may be affected by changes in economic or other conditions and may accordingly impact the Company–s overall credit risk. Management believes the risk is mitigated by the size, reputation and diversified nature of the companies to which they extend credit. The Company has not previously experienced any material credit losses on the collection of accounts receivable. Of the Company–s revenue for the three months ended June 30, 2011, approximately 82% was received from seven companies (16%, 12%, 12%, 11%, 11%, 10% and 10%) (June 30, 2010 – 87%, five companies (25%, 19%, 16%, 14% and 13%)). Of the Company–s revenue for the six months ended June 30, 2011, approximately 76% was received from five companies (21%, 15%, 14%, 13% and 13%) (June 30, 2010 – 97%, six companies (25%, 19%, 16%, 13%, 13% and 11%)). Of the Company–s accounts receivable for the period ended June 30, 2011, approximately 13% was receivable from a single company (Year ended December 31, 2010 – 31%, three companies (11%, 10% and 10%)). The maximum exposure to credit risk is represented by the carrying amount on the consolidated balance sheet. There are no material financial assets that the Company considers past due and no accounts have been written off.
The Company may be exposed to certain losses in the event of non-performance by counterparties to commodity price contracts. The Company mitigates this risk by entering into transactions with counterparties that have investment grade credit ratings.
Counterparties to financial instruments expose the Company to credit losses in the event of non-performance. Counterparties for derivative instrument transactions are limited to high credit-quality financial institutions, which are all members of our syndicated credit facility.
The Company assesses quarterly if there should be any impairment of financial assets. At June 30, 2011, there was no impairment of any of the financial assets of the Company.
Liquidity Risk
Liquidity risk includes the risk that, as a result of 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 financial 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 our existing capital expenditure program, are continuously monitored and adjusted as input variables change. These variables include, but are not limited to, available bank lines, oil and natural gas production from existing wells, results from new wells drilled, commodity prices, cost overruns on capital projects and changes to government regulations relating to prices, taxes, royalties, land tenure, allowable production and availability of markets. As these variables change, liquidity risks may necessitate the need for 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 certain losses.
13. Capital disclosures
The Company–s objectives when managing capital are: (i) to maintain a flexible capital structure, which optimizes the cost of capital at acceptable risk; and (ii) to maintain investor, creditor and market confidence to sustain the future development of the business.
The Company manages its capital structure and makes adjustments to it in light of changes in economic conditions and the risk characteristics of its underlying assets. The Company considers its capital structure to include Shareholders– equity, debt and working capital. To maintain or adjust the capital structure, the Company may from time to time, issue common shares, raise debt, adjust its capital spending or change dividends paid to manage its current and projected debt levels. The Company monitors capital based on the following non-IFRS measures: current and projected debt to earnings before interest, taxes, depreciation, depletion and amortization (“EBITDA”) ratios, payout ratios and net debt levels. To facilitate the management of these ratios, the Company prepares annual budgets, which are updated depending on varying factors such as general market conditions and successful capital deployment. Currently, all ratios are within acceptable parameters. The annual budget is approved by the Board of Directors. The Company is not subject to any external financial covenants.
The Company has no other contractual obligations or commitments as at June 30, 2011.
Contingent Liability
From time to time, Peyto is the subject of litigation arising out of its day-to-day operations. Damages claimed pursuant to such litigation, including the litigation discussed below may be material or may be indeterminate and the outcome of such litigation may materially impact Peyto–s financial position or results of operations in the period of settlement. While Peyto assesses the merits of each lawsuit and defends itself accordingly, Peyto may be required to incur significant expenses or devote significant resources to defending itself against such litigation. These claims are not currently expected to have a material impact on Peyto–s financial position or results of operations.
17. 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 Canadian GAAP. The Company has prepared financial statements which comply with IFRS–s applicable for periods beginning on or after the transition date of January 1, 2010 and the significant accounting policies meeting those requirements are described in Note 2.
The effect of the Company–s transition to IFRS is summarized in this note as follows:
(i) Transition elections
(ii) Reconciliation of the Balance Sheets, Income Statements and Comprehensive Income as previously reported under Canadian GAAP to IFRS
(iii) IFRS adjustments
(i) Transition elections
IFRS 1 allows first-time adopters certain exemptions from the general requirement to apply IFRS as effective for December 2011 year ends retrospectively. The Company has taken the following exemptions:
(a) IFRS 3 Business Combinations has not been applied to acquisitions of subsidiaries or of interests in associates and joint ventures that occurred before January 1, 2010, the Company–s date of transition.
(b) IFRS 2 Share-based Payment has not been applied to any equity instruments that were granted on or before November 7, 2002, nor has it been applied to equity instruments granted after November 7, 2002 that vested before January 1, 2009.
(c) The Company has elected under IFRS 1 First-time Adoption of IFRS to measure oil and gas assets at the date of transition at a deemed cost under Canadian GAAP.
(d) The Company has elected to apply the exemption from full retrospective application of decommissioning provisions as allowed under IFRS 1 First Time Adoption of IFRS. As such the Company has re-measured the provisions as at January 1, 2010 under IAS 37 Provisions, Contingent Liabilities and Contingent Assets, and estimated the amount to be included in the retained earnings on transition to IFRS.
(iii) Notes to the reconciliation of balance sheet, income statement and comprehensive income from Canadian GAAP to IFRS
(a) The Company has elected under IFRS 1 First-time Adoption of IFRS to measure oil and gas assets at the date of transition to IFRS on a deemed cost basis. The Canadian GAAP full cost pool was measured upon transition to IFRS as follows:
(i) No exploration or evaluation assets were reclassified from the full cost pool to exploration and evaluation assets; and
(ii) All costs recognized under Canadian GAAP under the full cost pool were allocated to the producing assets and undeveloped proved properties on a pro rata basis using reserve volumes.
(b) The recognition and measurement of impairment differs under IFRS from Canadian GAAP. In accordance with IFRS 1 the Company performed an assessment of impairment for all property, plant and equipment and other corporate assets at the date of transition. The testing on transition to IFRS did not result in impairment.
(c) Under Canadian GAAP asset retirement obligations were discounted at a credit adjusted risk free rate. Under IFRS the estimated cash flow to abandon and remediate the wells and facilities has been risk adjusted and the provision is discounted at a risk free rate. Upon transition to IFRS this resulted in a $7.0 million increase in the decommissioning provision with a corresponding decrease in retained earnings.
As a result of the change in the decommissioning provision, accretion expense for the three and six month periods ended June 30, 2010 and for the year ended December 31, 2010 was $0.2 million, $0.5 million and $0.7 million, respectively. In addition, under Canadian GAAP accretion of the discount was included in depletion and depreciation. Under IFRS it is i