pennwest-corr_101513.htm

We note that you report under this heading Gross Revenues which include realized gains and losses on commodity contracts. However, in your Consolidated Statements of Income, you include both realized and unrealized gains and losses as part of your total revenues. Tell us why you believe inclusion of both realized and unrealized gains and losses in your total revenues in your financial statements is appropriate, while excluding unrealized amounts from your measure of revenues under this heading. Given your disclosure in Note 11, indicating that you have not designated any derivative contracts as hedges for accounting purposes, please also explain why you believe the effects of your derivative activities are fairly presented as revenues, along with your oil and gas sales.

Cash flow from operating activities and funds flow (a non-GAAP measure), which is reconciled to cash flow from operating activities in our Management Discussion and Analysis (“MD&A”), are key metrics in determining our sustainability and are used to assess our ability to fund planned capital programs and anticipated dividend levels. These two metrics are a focus for both the Company and our investors.

We use derivative instruments to manage our exposures to commodity price fluctuations and these derivative instruments give rise to realized and unrealized gains and losses. As further explained below, we believe that disclosure of both realized and unrealized gains and losses in our MD&A and financial statements helps users to understand the impact of risk management activities by distinguishing between realized/settled amounts (which impact cash flow from operating activities and funds flow in the current period) and unrealized amounts (which do not impact cash flow from operating activities or funds flow in the current period and are subject to considerable fluctuation in carrying amounts subsequent to the end of the reporting date as the fair value of the derivative instruments for future periods fluctuates with commodity prices). We believe that our current disclosure practices provide transparency for the users of our disclosure documents and demonstrate the effects of risk management activities on these two key cash generation metrics.

In our MD&A, under the “Production Revenue” heading, we include oil and natural gas sales and only the realized portion of risk management gains and losses which we then total to Gross Revenue. We believe it is appropriate to segregate the realized portion of the risk management gain (loss) in this discussion, as it provides the reader with the components of the realized price and therefore the funds to be received from the sale of production in the current period inclusive of our risk management activities. We separately disclose our revenue and realized risk management gains or losses on a per barrel of oil equivalent (“boe”) basis in our netback table in the MD&A, which is also a focus of management, investors and analysts. As unrealized risk management gains and losses represent the fair value change of all financial commodity contracts related to periods beyond the current reporting period, we believe our presentation enables users to better assess current period cash realizations from commodity sales. The change in carrying amount of derivative contracts related to future periods will impact funds generated in future periods and is therefore excluded from the current period Gross Revenue portion of the discussion. Our MD&A includes a detailed summary of our outstanding derivative contracts, including the contract terms and the related fair values as at each balance sheet date.

In our Consolidated Statements of Income we include separate disclosures of oil and natural gas sales, royalties and both realized and unrealized risk management gains and losses. As our commodity sale price derivative instruments are not designated as hedges for accounting purposes by management, we determined that it was not appropriate under International Financial Reporting Standards (“IFRS”) to include only the realized risk management gains and losses within the related oil and natural gas revenues sub-heading. Accordingly, realized and unrealized risk management gains and losses are included in our Consolidated Statement of Income, above the expenses category, as the risk management activities relate to the underlying economic exposure of oil and gas revenue to commodity price risk.

We respectfully submit that our disclosure practices (in both the MD&A and Consolidated Statements of Income) are consistent with many oil and natural gas producers in Canada who prepare financial statements in accordance with IFRS. To provide additional clarity and transparency to the users of our financial statements, in future filings of our MD&A we will define Gross Revenues as a non-GAAP measure and will include appropriate non-GAAP measures disclosure.

Additionally, please explain to us how you calculated realized and unrealized gains and losses on your derivatives. Since you report derivative assets and liabilities at fair value and the changes in fair value as gain or loss each period, tell us why you believe differentiating between the realized and unrealized portions is meaningful, understanding that realized amounts should not reflect the overall impact of the underlying instruments because these do not include previously recognized unrealized gain or loss.

Unrealized risk management gains and losses represent the change in fair value of the derivative instruments during the reporting period which relate to future periods. As derivative instruments settle, we reclassify the realized (settled) portions of gains and losses from the unrealized risk management gains and losses line to the realized risk management gains and losses line but all within the total risk management gains and losses heading. The amount of realized risk management gains and losses may or may not have been included in a previous accounting period as the unrealized amount is dependent on the timing of the change in commodity price futures and the terms of each applicable derivative instrument. The changes in fair value of the derivative instruments applicable to future periods are calculated using fair value support provided by our external counterparties, which is based upon forward prices relative to the terms of the underlying derivative instrument. We verify the counterparty values by completing our own fair value assessment using various techniques, such as the use of a Black Scholes model, and conducting comparisons to observable market data.

For the reasons noted in our response above, we believe differentiating between the unrealized and realized portions of risk management gains and losses provides meaningful and transparent disclosure to readers as realized gains and losses impact cash flow from operating activities and funds flow for the current period, whereas unrealized gains and losses do not and are subject to significant fluctuations as commodity prices change for the future periods of the derivative instruments. We note that we have applied this practice consistently, even during periods when we experienced significant fluctuations in unrealized gains and losses. For example, in the second quarter of 2008 we recorded a loss in excess of $800 million and then in the following quarter (third quarter of 2008) we recorded a gain of approximately $1.1 billion when both the unrealized loss and gain were related to changes in the fair value of the derivative instruments for future periods.

We note that you completed property dispositions of $1.6 billion during 2012 and recorded related gains of $384 million. Please tell us how the cost basis of the underlying properties was determined and provide the related calculations; describe any allocation methods utilized to determine the cost basis. In addition, please clarify how you have considered the guidance in paragraph 86 of IAS 36, regarding goodwill associated with operations that were disposed. If no goodwill was allocated to the related cash-generating unit, explain why.

Based on the derecognition guidance in paragraphs 67 to 72 of IAS 16, Property, Plant and Equipment, we determined the carrying amount of the PP&E associated to the disposed operation by prorating the total carrying amount of PP&E of the applicable amortizable PP&E components by the portion of the PP&E disposed. We also referred to Section 7.3, Partial disposals and undivided interest, of Chapter 20, Property, Plant and Equipment, of Ernst & Young’s International GAAP Online which states “The entity needs to identify the cost of the part disposed of by allocating the carrying value on a systematic and appropriate basis.” We determined the carrying amount of the portion of PP&E disposed by obtaining the proved plus probable reserves (“2P”), discounted at 10 percent (“2P PV 10 percent”), for the portion of the PP&E disposed, divided by the 2P PV 10 percent value for the applicable amortizable PP&E components. This allocation method is consistent with how we allocated our development and production asset cost basis under the full cost method of accounting to our Canadian cost centre’s underlying assets (i.e. components) upon adoption of IFRS as one method permitted by IFRS 1.D8A and, accordingly, we also viewed it to be a systematic and appropriate basis for the purpose of derecognition of PP&E. This portion was multiplied by the carrying amount of PP&E of the applicable amortizable PP&E components to determine the carrying amount of the PP&E associated with disposed operations. The carrying amount of the disposed operation also includes an estimate of the depletion charge from the last reporting date to the date the disposition closed and an estimate of the decommissioning liability disposed based on the assets sold in the transaction.

Our practice for associating the carrying amount of goodwill (which was allocated to our sole operating segment comprising all of the Company’s cash generating units (“CGUs”)) with a disposed operation was first a qualitative determination of whether the disposed operation originally gave rise to goodwill. If, in our view, the disposed operation did not give rise to goodwill, we did not associate any carrying amount of goodwill to the carrying amount of the disposed operation when determining the gain or loss on disposal. We determined this was appropriate on the basis that IAS 36.86 permits an entity to apply some other method when it better reflects the goodwill associated with any disposed operation (in our case oil and natural gas properties). Applying this practice, we did not associate goodwill with any disposed properties since the adoption of IFRS on January 1, 2010 on the basis that these operations were non-core properties, which we determined did not give rise to goodwill at the date of acquisition.

In preparing our response to this comment and comment 3 below (relating to the operating segment level at which we test for goodwill impairment), we acknowledge that this practice of asserting that we have the ability to identify whether disposed operations originally gave rise to goodwill may be an indication that we should have allocated goodwill on a different basis to an individual or group of CGUs below our sole operating segment when we adopted IFRS. Please refer to our response in comment 3 where we discuss our re-evaluation of our methodology for allocating goodwill to CGUs. In that re-evaluation, we conclude that our goodwill is associated with a group of CGUs below the operating segment level consistent with the strategic rationale of the acquisitions giving rise to the goodwill. From our current research, we acknowledge that our practice arguably might not have met the spirit in IAS 36.86 (“a better method”) on the basis that our practice was based on a qualitative assessment rather than a reliably determinable computation.

As a result, we have re-performed our computations for associating the carrying amount of goodwill to the carrying amount of disposed operations when determining the gain or loss on disposals of properties since IFRS adoption. For disposal of operations from the revised group of CGUs to which goodwill has been allocated, we applied IAS 36.86 in measuring the carrying amount of goodwill associated with the disposed operation based on the relative values of the disposed operations (i.e., proceeds on disposals) and the portion of the group of CGUs retained (i.e., estimated recoverable amount). The gain on disposals for each of the years ended December 31, 2012, 2011 and 2010 decreased as a result of associating the carrying amount of goodwill to the carrying amount of the disposed operations. We performed a materiality assessment of uncorrected misstatements for each of 2012, 2011 and 2010 and concluded that the uncorrected misstatements, individually and in the aggregate, were quantitatively and qualitatively immaterial to the respective year’s previously-issued financial statements. A further discussion of our materiality assessment has been provided supplementally to the Staff.

The Company’s goodwill balance of $2,020 million on the date of IFRS adoption of January 1, 2010 arose from three business combinations completed prior to IFRS adoption (all in the form of a share-for-share exchange). The Company elected not to adopt IFRS 3 (“Business Combinations”), to acquisitions prior to the adoption of IFRS and, accordingly, our goodwill measurement remained unchanged upon IFRS adoption. The goodwill balance consists of $1,348 million that resulted from the acquisition of Canetic Resources Trust (“Canetic”), which closed in January 2008, $652 million from the acquisition of Petrofund Energy Trust (“Petrofund”) which closed in June 2006, and $20 million from the acquisition of Vault Energy Trust (“Vault”) which closed in January 2008.

The Western Canadian Sedimentary Basin (“WCSB”) contains significant crude oil and natural gas deposits, with relatively low recovery factors to-date using vertical drilling technologies. In the period leading up to the Petrofund and Canetic acquisitions, there was a belief by our CEO that technology would be developed that would permit the production of additional light oil from these reservoirs, increasing recovery factors from the previously discovered and developed oil reservoirs. Prior to the Canetic and Petrofund acquisitions, the Company had significant holdings

in the Cardium, Carbonates and Viking light-oil areas of the WCSB. The strategy of the Company at that time was to further increase its positions in these reservoirs and then apply the latest technologies to increase recovery factors and extract additional production. It was believed that the technology to unlock these resources was the use of Carbon Dioxide (“CO2”) miscible flooding. This strategy of accumulating these positions continued in the period following the acquisitions. With the benefit of hindsight, different technologies were developed which supplanted CO2 flooding; however, regardless of the technology applied, the strategy was to increase recovery factors. Horizontal drilling and the application of multi-stage fracturing have increased the amount of economically recoverable oil in these reservoirs. CO2 flooding, water flooding applications and other enhanced oil recovery methods continue to be explored and implemented by market participants, in tandem with horizontal multi-stage fracture technology. Despite the different technologies ultimately applied to these reservoirs, the corporate strategy was and continues to this day, to maximize resource recoveries.

While there were 2P reserves associated with these large resource play areas from historical vertical development, a significant portion of the perceived value was in the future value that would be generated from increasing light oil recoveries. To effect these acquisitions, it was necessary to also acquire many properties that were ancillary or not contained in large light-oil areas, and thus not core to the future strategic direction of the Company as they contained limited upside potential (i.e. goodwill). A portion of the acquired ancillary properties has been monetized to date.

We considered the guidance in IAS 36.80-83 at the time of adoption of IFRS effective January 1, 2010. On the basis that the acquisitions created a larger enterprise with significant exposure to light-oil resources (with low recovery factors that we believed could be increased using technological advances), and the additional benefit of increased liquidity in our common stock, including access to US markets, our view at the time of adoption of IFRS was that the Company’s sole operating segment (a group containing all of our CGUs) in aggregate, was expected to benefit from the synergies of the acquisitions. Furthermore, other than for financial reporting purposes (i.e. goodwill impairment testing), goodwill was not specifically monitored by management (i) directly at individual CGUs or groups of CGUs, or (ii) indirectly through higher targeted rates of return to cover the cost of the goodwill at any level within the Company. Accordingly, we concluded at the date of adoption of IFRS that the goodwill arising from the pre-IFRS acquisitions could not be allocated on a non-arbitrary basis to individual CGUs below the Company’s sole operating segment for the purposes of goodwill impairment testing.

In preparing our response to this comment and comment 2 above, we acknowledge that this practice of asserting that we have the ability to identify whether disposed operations originally gave rise to goodwill may be an indication that we should have allocated goodwill on a different basis to an individual or group of CGUs below our sole operating segment when we adopted IFRS. As a result, we re-evaluated our methodology for associating goodwill to CGUs.

We have re-examined various documentation generated in connection with the acquisitions including internal presentations, meeting minutes, due diligence materials, financial statements, management discussion and analysis, annual information form, press releases, investor presentations and analyst reports with the objective of gaining further insight as to what the goodwill represented at the time the acquisitions were completed and which CGU or groups of CGUs benefited from the acquisitions. This review confirmed that the predominant reason for the goodwill arising from the acquisitions was the value that came from the future application of technology to enhance recovery factors in the Cardium, Carbonates and Viking resource plays. Upon the adoption of IFRS, these resource plays resided in a group of CGUs, not all of the

Company’s CGUs. While we believe that there were ancillary benefits to the entire Company from the business combinations, we are not certain how a portion of the goodwill could be reliably attributed to our other CGUs. Accordingly, we believe it is reasonable to associate the goodwill to the group of CGUs in which the Cardium, Carbonates and Viking resource plays reside.

As a result of our revised conclusion, we have re-performed our annual goodwill impairment testing at the effective IFRS transition date of January 1, 2010, and at December 31, 2012, 2011 and 2010 for the group of CGUs in which the Cardium, Carbonates and Viking resource plays reside and determined there were no goodwill impairments. Please refer to our response in comment 4.

We note your disclosure under Note 8: Goodwill that the recoverable amount under the goodwill impairment test was determined based on the fair value less costs to sell method. You also identify certain of the key assumptions that underlie your determination of fair value less costs to sell. Please explain to us how your methodology is in compliance with paragraph 27 of IAS 36, and provide us a copy of your recoverability analysis. As part of your response, please tell us how you have considered the outcome of any recent transactions for similar assets, including your recent dispositions, and the stock market capitalization of your company. In addition, we note the disclosure in your prior year Form 40-F that one of your key assumptions included the future cash flows using proved plus probable reserves discounted at 10%, and that the current year’s disclosure does not include this key assumption. Please describe any significant change in this key assumption from the prior year to the current year.

In preparing our annual goodwill impairment test at December 31, 2012, we considered that the carrying amount of the Company’s net assets of $8.9 billion exceeded the Company’s stock market capitalization of $5.2 billion. Management viewed this gap to be indicative of the Company operational performance and temporary market factors rather than an indication of impairment of the Company’s underlying assets. In light of the December 31, 2012 market capitalization, management determined the recoverable amount, being the higher of fair value less cost to sell (“FVLCS”) and value-in-use (“VIU”) of the Company’s net assets using a detailed asset buildup approach on a CGU-by-CGU basis. The components of this asset build-up considered:

We followed the guidance outlined in IAS 36.27 for determining the FVLCS of the Company’s assets as described above based on “the best information available to reflect the amount that an entity could obtain, at the end of the reporting period, from the disposal of the asset in an arm's length transaction between knowledgeable, willing parties…” Further, the Company reviewed its own recent dispositions activity as well as publically available transaction metrics for similar assets within a reasonable period of time of the measurement date of December 31, 2012.

In preparing our 2012 annual financial statements, we prepared the goodwill impairment test at the Company’s single operating segment (i.e., at the consolidated level). However, as discussed in our response to comment 3, we have determined that goodwill should be allocated to a group of CGUs below the operating segment level. The discussion of the revised goodwill impairment test is provided further below.

Our estimation of recoverable amount of 2P reserves is based on 2P PV 10 percent value from the reserve reports as evaluated or audited by our independent reserve evaluators. Our use of a 10 percent discount rate is unchanged from prior years (see further discussion of the discount rate in our response to comment 5). We made reference to the use of this method in our disclosure “the future cash flows using reserve forecasts, the forecasted commodity prices, future development costs”. This is a typical practice in our industry as it is reflects the present value of future cash flows from our current operations plus additional amounts which are likely to result from our near-term development programs. Many purchase and sale transactions of oil and natural gas properties in the WCSB use 2P PV 10 percent as a starting point in the determination of an appropriate transaction value.

We then determined the recoverable amount of our incremental development drilling locations not included in our 2P PV 10 percent values, but would be considered in an arm’s length transaction if the asset(s) were disposed. On October 17, 2012, we disclosed the results of our Cardium contingent resource study. This contingent resource study was completed by an independent, qualified, engineering firm. The results of our Cardium contingent resource study concluded that we have a number of incremental development drilling locations in the area, which we included in our calculation of recoverable amount. We made reference to this study in our disclosure by stating that we included “the value of resources estimated by independent reserve engineers”. We have also completed an internal assessment in our other core light-oil areas (Carbonates and Viking), which also identified incremental development drilling locations. These incremental locations were not included in the recoverable amount of our 2P PV 10 percent value at December 31, 2012, thus we added the Carbonates and Viking incremental locations to the recoverable amount. Subsequent to December 31, 2012, these incremental development drilling locations were further supported by the Contingent Resource Studies completed in the Carbonates and Viking areas, by an independent external resource evaluator. We issued a press release related to these studies on August 7, 2013 titled “Penn West Exploration Announces Results of Contingent Resources Studies”.

As noted in our response to comment 3, the operating segment level at which we tested our goodwill for impairment was inconsistent with our practice for associating the carrying amount of goodwill with a disposed operation. Our revised conclusion in comment 3 is that our goodwill is associated with a group of CGUs which include the Cardium, Carbonates and Viking resource plays (i.e., below the operating segment level). Accordingly, we re-performed our goodwill impairment test at January 1, 2010 (the effective date of adoption of IFRS), December 31, 2010, December 31, 2011 and December 31, 2012. These calculations included the 2P PV 10 percent reserve values for the CGUs which include the Cardium, Carbonates and Viking resource plays. We then reviewed incremental development drilling locations not included in our 2P PV 10 percent value, but would have value associated with them in an arm’s length transaction if asset(s) were disposed in these specific areas, or realized through the continued development of the area. Upon completion of this analysis, we concluded that the recoverable amount of this group of CGUs is higher than its carrying value, including the associated goodwill, and accordingly, no goodwill impairment was required. Related 2012 calculations and details of this approach have been provided supplementally to the Staff.

We completed a number of non-core asset dispositions during 2012, notably in the fourth quarter of 2012, which attracted high valuations. In 2012, the oil and natural gas industry in western Canada continued to have an active acquisition and divestiture market, primarily for oil weighted properties. For purposes of our goodwill impairment testing, we reviewed not only our own asset transactions but other publically available transaction metrics for similar assets within a reasonable period of time of the measurement date of December 31, 2012 in determining the recoverable amount of net assets.

We revised our disclosures in 2012 to state that estimates of future cash flows include not only the use of 2P PV 10 percent as set forth in our independent reserve report, but also use estimated cash flows in addition to those included in the reserve report, such as estimated cash flows associated with contingent resources and incremental development drilling locations not currently recorded in the 2P reserve value. For these reasons, we revised the disclosures in 2012.

Goodwill is not amortized and the carrying amount is assessed for impairment on an annual basis on December 31, or more frequently if circumstances arise that indicate impairment may have occurred. To test for impairment, the carrying amount of goodwill is compared to the excess of the recoverable amount of our PP&E over the carrying amount of our PP&E to which the goodwill is associated. If the carrying amount of the goodwill is greater than this excess, an impairment loss is recorded. The determination of the recoverable amount of our PP&E involves estimating the higher of an asset’s fair value less costs to sell and its value-in-use. Goodwill impairment losses are not reversed in subsequent periods.”

The guidance in paragraph 12(d) of IAS 36 requires consideration of indicators that an asset may be impaired, circumstances when the carrying amount of the net assets of an entity is more than its market capitalisation. We note that your market capitalization as of the end of 2012 was approximately $5 billion and the carrying amount of your net assets at the same time was $8.9 billion. This difference appears to indicate that you should have estimated the recoverable amount of each of your cash-generating units. As disclosed in Note 7: Property, Plant and Equipment, we note that you recorded a $277 million impairment related to certain properties in northern British Columbia, although it is not clear whether you have estimated recoverability for other properties or how you determined additional impairments for these other properties were not required.

As SEC staff note below, at December 31, 2012, our 2P PV 10 percent future cash flow value was $9,130 million compared to $12,042 million at December 31, 2011. The decline between the periods was primarily due to dispositions closed during 2012, which in itself would not be an indicator of impairment. Also contributing to the decline were lower forward natural gas prices. We concluded the decreasing natural gas prices were an indicator that our gas weighted CGUs could be impaired. We also concluded that there were no indicators of impairment in our oil-weighted CGUs, as forward prices included in the 2P PV 10 percent figures in our reserve report were consistent with previous years. In addition, during 2012 we published the results of our contingent resource studies, and our development and engineering teams continued to develop listings and analyses of incremental development drilling locations in our core resource plays, all of which indicated significant value existed in excess of 2P PV 10 percent related to these areas.

During 2012, there were no significant changes, other than natural gas prices, which adversely affected us related to the factors listed under this paragraph. Technology related to secondary recovery methods continues to evolve and results from our horizontal waterflooding projects have been promising to date, which could lead to additional recoveries from our existing pools and an increase in our reserve value. Thus we concluded that this was not an indicator of impairment.

As SEC staff noted, the net assets of our Company was higher than our market capitalization at December 31, 2012, and thus was an indicator of possible impairment. As we have discussed under our response to comment 4, our development and engineering teams have developed listings and analysis of incremental development drilling locations in our core resource plays, indicating significant value in excess of 2P PV 10 percent values related to these areas. We performed a detailed asset build-up test at December 31, 2012 to support our goodwill balance.

significant changes with an adverse effect on the entity have taken place during the period, or are expected to take place in the near future, in the extent to which, or manner in which, an asset is used or is expected to be used. These changes include the asset becoming idle, plans to discontinue or restructure the operation to which an asset belongs, plans to dispose of an asset before the previously expected date, and reassessing the useful life of an asset as finite rather than indefinite.

In 2012, there were no significant changes related to the use or expected future use of our assets. Our strategy remained focused on development of our light-oil properties and our current plan is to continue this strategy into 2013. Our current business plans include the continued monetization of non-core properties in order to concentrate our activity on our key resource plays.

From our 2012 results, our netbacks, a non-GAAP measure as disclosed in our MD&A, for natural gas were considerably lower than the previous year due to declining natural gas prices. Oil and natural gas liquids netbacks were also modestly lower than in the prior year. Lower netbacks are not necessarily an indicator of impairment, as the recoverable amount of our PP&E is based on estimated future commodity prices, as disclosed in our independently evaluated and audited reserve report, which estimated prices were higher than prices received in 2012.

As there were indicators of impairment of our gas weighted CGUs per (a), (d) and (g) above, we estimated the recoverable amounts of each of these specific CGUs to determine if there were impairments. As SEC staff noted, we recorded an impairment loss in one of our gas weighted CGUs. Further discussion of our impairment assessment is provided in the second part of this comment below.

We also note that the net present value of future net revenue as of December 31, 2012, discounted at 10%, (page A3-4 of Exhibit 99.1), was $9.1 billion, while the net book value of your property, plant and equipment is $10.9 billion. Accordingly, if you have estimated the recoverability for each of your cash-generating units, please provide us these recoverability analyses and explain how the analyses conform to paragraphs 30 and 33 of IAS 36. If you have not estimated the recoverability of each of your cash-generating units, please explain to us the basis for your accounting.

For purposes of calculating recoverable amount of our CGUs, the 2P PV 10 percent reserve value was used as an estimate of the value of 2P reserves associated with each CGU. For our annual reserve report in 2012, all of our reserves were evaluated or audited by independent, qualified engineering firms GLJ Petroleum Consultants Ltd. and Sproule Associates Limited. This report includes estimated 2P reserves. Proved reserves are the estimated quantities of crude oil, natural gas and natural gas liquids determined to be economically recoverable under existing economic and operating conditions with a high degree of certainty (at least 90 percent) those quantities will be exceeded. Probable reserves are the estimated quantities of crude oil, natural gas and natural gas liquids determined to be economically recoverable under existing economic and operating conditions with a 50 percent certainty those quantities will or will not be exceeded. We report production and reserve quantities in accordance with Canadian practices and specifically in accordance with National Instrument 51-101 - Standards of Disclosure for Oil and Gas Activities (“NI 51-101”).

The reserve evaluation and audit includes the resulting cash flows expected from the assets based on forecast prices, royalties, operating and capital costs. This report is prepared externally on an annual basis (IAS 36.30a, b). The report also includes present value calculations of these cash flows based upon a number of alternative discount rates (IAS 36.30c). In determining the appropriate discount rate to apply to these cash flows, we considered multiple sources. Many industry participants utilize a 10 percent discount rate, and include 2P PV 10 percent figures in their public disclosures. We also considered our weighted average cost of capital as a discount factor to apply to the resulting cash flows. A third consideration was to assign specific discount factors to the specific reserve classifications; a lower rate to proved reserves, given the 90 percent likelihood of exceeding the expected production quantity, and a higher discount rate to probable reserves, given the 50 percent likelihood of exceeding these expected production quantities. Each of these methods resulted in a discount factor of approximately 10 percent. We therefore concluded a discount factor of 10 percent was appropriate in accordance with IAS 36.30 (c).

We also review market transaction metrics for similar properties and the application of these metrics to our properties. The two common metrics utilized in the valuation of oil and gas assets include reserve ($ per 2P reserve barrel of oil equivalent) and flowing barrel ($ per barrel of oil equivalent production per day) measures. Our estimates of recoverable amount, when appropriate, utilize both metrics.

Our CGU impairment indicator analysis, described earlier in our response to this comment, concluded that only our gas weighted CGUs had indicators present. As discussed in our response to comment 4, due to the significant gap between the carrying amount of the Company’s net assets and its stock market capitalization, we determined the recoverable amount of the Company’s sole operating segment using a detailed asset buildup approach on a CGU-by-CGU basis. In light of having access to the recoverable amounts of CGUs, we considered the consistency of this information with the results of our CGU impairment indicator analysis. The CGU recoverable amounts supported the conclusion that only our gas weighted CGUs had indicators present.

On an annual basis, the CODM reviews our consolidated annual budget which is a key tool in determining the amount of our annual capital expenditures. The CODM determines capital available for expenditure (i.e. allocation) based on the consolidated annual budget. Key items reviewed include forecast commodity prices, production, funds flow and anticipated dividend levels. From this review, the CODM determines capital allocations to individual projects based on multiple factors, including internal rates of return and other economic indicators including capital costs, capital efficiencies, production and performance expectations, reserve considerations, competitor activity in specific areas, and current and past performance of our drilling programs. Once these resource allocation decisions are finalized, capital is allocated to specific projects within the Company’s plays based upon the above analysis. Capital allocation is a company-wide process focused on identifying the best projects for development with no specific consideration given solely to the geographic location of the project.

The CODM reviews our monthly consolidated financial package prior to distribution to our Board of Directors. This package includes a summary of our consolidated financial results to evaluate business performance including production, funds flow (a non-GAAP measure), capital expenditures, commodity prices, and netbacks (a non-GAAP measure), all of which management believes are also important to external stakeholders. Corporate performance is evaluated by the CODM by reviewing and evaluating a number of the factors mentioned above. With the release of our quarterly results, these metrics are also reviewed and analyzed by external parties, including investors and analysts that report on our performance and prospects. Other corporate level metrics reviewed and evaluated by the CODM, our senior management team, Board of Directors and external parties, on a quarterly or annual basis, for the purpose of assessing the Company’s

Additionally, on a monthly basis, the CODM reviews our annual forecast and compares the forecast to our consolidated annual budget in order to assess our actual results to date and our expectations for the remainder of the year against our initial budget. Based upon this review, capital allocations may change. This continuous performance assessment and capital allocation process is completed from a company-wide perspective.

Capital allocation decisions are monitored by project on a consolidated level based upon a number of internal and external operational factors, including, but not limited to; individual well economics, production expectations, reserve additions, corporate cash flow estimates, estimated forward commodity prices, competitor activity in specific areas, current and past performance of our drilling programs and operational results and capital budgets.

With respect to point 3, discrete financial information is available below the consolidated Company level for other personnel to monitor the efficiency within our business. We do not prepare discrete financial reporting below that of the enterprise level on a regular basis for review by the CODM. As such, it is not used by the CODM for purposes of resource allocation or performance assessment of the Company.

As SEC staff notes, in our Form 40-F, we describe our principal resource plays and expected activity levels. This information is a required disclosure under current Canadian securities laws (Form 51-101F1 “Statement of Reserves Data and Other Oil and Gas Information” under NI 51-101 and Form 51-102F1 “Management’s Discussion & Analysis” and 51-102F2 “Annual Information Form” under National Instrument 51-102 "Continuous Disclosure Obligations"). Pursuant to Form 51-101F1 Item 6.1, we are required to identify and describe generally our important properties, plants, facilities and installations; however, these important properties and related plants, facilities and installations do not constitute operating segments.

We have re-reviewed the disclosures required by paragraphs 20 through 22 of IFRS 8 and in an effort to provide further clarity that we have only one operating segment, in future filings we will include additional disclosures in our Accounting Policy note (Note 3 per our December 31, 2012 Financial Statements) in our Consolidated Financial Statements which will read substantively as follows:

“The Company operates in one segment, to explore for, develop and hold interests in oil and natural gas properties and related production infrastructure in the Western Canadian Sedimentary Basin directly and through investments in securities of subsidiaries holding such interests. Penn West’s portfolio of assets is managed at an enterprise level, rather than by separate operating segments or business units. The Company assesses its financial performance at the enterprise level and resource allocation decisions are made on a project basis across Penn West’s portfolio of assets, without regard to the geographic location of projects.”