Exhibit 99.2

MANAGEMENTS DISCUSSION AND ANALYSIS

For the year ended
December 31, 2011

This managements discussion and analysis (MD&A) of financial conditions and results of
operations should be read in conjunction with the audited consolidated financial statements and accompanying notes of Penn West Petroleum Ltd. (Penn West, We, Our, the Company) for the years ended
December 31, 2011 and 2010. The date of this MD&A is March 15, 2012. All dollar amounts contained in this MD&A are expressed in millions of Canadian dollars unless noted otherwise.

For additional information, including Penn Wests audited consolidated financial statements and Annual Information Form, please go to our website at
www.pennwest.com, in Canada to the SEDAR website at www.sedar.com or in the United States to the SEC website at www.sec.gov.

On January 1, 2011, we completed our plan of arrangement under which Penn West converted from an income trust to a corporation, operating under the trade name of Penn West Exploration. Prior to this
date, our consolidated financial results were presented as an income trust, Penn Wests former legal structure, as at and for the year ended December 31, 2010.

In the first quarter of 2011, we completed our change to International Financial Reporting Standards (IFRS) from Canadian Generally Accepted Accounting Principles (previous GAAP).
Our previously reported consolidated financial statements were adjusted to be in compliance with IFRS on January 1, 2010 (the date of transition). Previously reported results and balances subsequent to the date of transition have
been revised to comply with IFRS. All 2009 balances remain in accordance with previous GAAP.

Please refer to our disclaimer on
forward-looking statements at the end of this MD&A. Barrels of oil equivalent (boe) may be misleading, particularly if used in isolation. A boe conversion ratio of six thousand cubic feet of natural gas to one barrel of crude oil is
based on an energy equivalency conversion method primarily applicable at the burner tip and does not represent a value equivalency at the wellhead. Given that the value ratio based on the current price of crude oil as compared to natural gas is
significantly different from the energy equivalency conversion ratio of 6:1, utilizing a conversion on a 6:1 basis is misleading as an indication of value.

Non-GAAP measures including funds flow, funds flow per share-basic, funds flow per share-diluted, netback, return on equity and return on capital included in this MD&A are not defined nor have a
standardized meaning prescribed by IFRS or previous GAAP; accordingly, they may not be comparable to similar measures provided by other issuers. Funds flow is cash flow from operating activities before changes in non-cash working capital and
decommissioning expenditures. Funds flow is used to assess our ability to fund dividend and planned capital programs. See below for reconciliations of funds flow to its nearest measure prescribed by GAAP. Netback is the per unit of production amount
of revenue less royalties, operating costs, transportation and realized risk management used in capital allocation decisions and to economically rank projects. Return on equity is the rate of return calculated by comparing net income to
shareholders equity. Return on capital is calculated using net income excluding financing charges compared to shareholders equity and long-term debt and is used to assess how well Penn West utilizes the capital invested into the company.

Calculation of Funds Flow



|                                                |      |                        |       |      |  |   |       |  
|----------------------------------------------- | ---- | ---------------------- | ----- | ---- |  | - | ----- | -
|(millions, except per share amounts)            |      | Year ended December 31 |      
|                                                | 2011 |                        |       | 2010 | 
|Cash flow from operating activities             |      | $                      | 1,407 |      |  | $ | 1,217 |  
|Increase (decrease) in non-cash working capital |      |                        | 49    |      |  |   | (85   | )
|Decommissioning expenditures                    |      |                        | 81    |      |  |   | 53    |  
|                                                |      |                        |       |      |  |   |       |  
|Funds flow                                      |      | $                      | 1,537 |      |  | $ | 1,185 |  
|                                                |      |                        |       |      |  |   |       |  
|                                                |      |                       
|Basic per share                                 |      | $                      | 3.29  |      |  | $ | 2.68  |  
|Diluted per share                               |      | $                      | 3.29  |      |  | $ | 2.65  |  



2011 ANNUAL
MANAGEMENTS DISCUSSION & ANALYSIS 1



---

Annual Financial Summary



|                                     |  |                        |        |  |          |   |        |          |  |   |        |  
|------------------------------------ |  | ---------------------- | ------ |  | -------- | - | ------ | -------- |  | - | ------ | -
|                                     |  | Year ended December 31 |       
|(millions, except per share amounts) |  | 2011                   |        |  | 2010 (1) |   |        | 2009 (1) | 
|Gross revenues(2)                    |  | $                      | 3,604  |  |          | $ | 3,034  |          |  | $ | 3,203  |  
|Funds flow                           |  |                        | 1,537  |  |          |   | 1,185  |          |  |   | 1,493  |  
|Basic per share                      |  |                        | 3.29   |  |          |   | 2.68   |          |  |   | 3.62   |  
|Diluted per share                    |  |                        | 3.29   |  |          |   | 2.65   |          |  |   | 3.60   |  
|Net income (loss)                    |  |                        | 638    |  |          |   | 1,110  |          |  |   | (144   | )
|Basic per share                      |  |                        | 1.37   |  |          |   | 2.51   |          |  |   | (0.35  | )
|Diluted per share                    |  |                        | 1.36   |  |          |   | 2.48   |          |  |   | (0.35  | )
|Capital expenditures, net(3)         |  |                        | 1,580  |  |          |   | (119   | )        |  |   | 319    |  
|Long-term debt at year-end           |  |                        | 3,219  |  |          |   | 2,496  |          |  |   | 3,219  |  
|Convertible debentures               |  |                        |       |  |          |   | 255    |          |  |   | 273    |  
|Dividends/ distributions paid(4)     |  |                        | 420    |  |          |   | 708    |          |  |   | 910    |  
|Total assets                         |  | $                      | 15,584 |  |          | $ | 14,543 |          |  | $ | 13,876 |  



|(1) | Comparative 2010 figures are presented under IFRS. Comparative 2009 figures are presented under previous GAAP.
|--- | --------------------------------------------------------------------------------------------------------------

|(2) | Gross revenues include realized gains and losses on commodity contracts.
|--- | ------------------------------------------------------------------------

|(3) | Excludes business combinations.
|--- | -------------------------------

|(4) | Includes dividends paid and reinvested in shares under the dividend reinvestment plan.
|--- | --------------------------------------------------------------------------------------

2011 Highlights



| |  |  | Funds flow for 2011 increased 30 percent to $1,537 million compared to $1,185 million in 2010. The increase was due to higher revenues as a result of
higher liquids production and stronger crude oil prices.
| | - |  | --------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



| |  |  | Net income was $638 million in 2011 compared to $1,110 million in 2010. Prior year figures include a $572 million after-tax gain on the formation of
the Peace River Oil Partnership and a $368 million gain on the formation of the Cordova Joint Venture.
| | - |  | -----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



| |  |  | Annual 2011 production averaged 163,094 boe per day, in line with our previous annual guidance of 162,000 to 164,000 boe per day.
| | - |  | ---------------------------------------------------------------------------------------------------------------------------------



| |  |  | Capital expenditures totalled $1,580 million net of joint venture carried capital and proceeds on net asset dispositions of $266 million. To date in
2012, Penn West has closed net dispositions of approximately $340 million.
| | - |  | -------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



| |  |  | Netbacks were $30.95 per boe compared to $25.07 per boe in 2010, due primarily to higher liquid prices.
| | - |  | -------------------------------------------------------------------------------------------------------

Quarterly Financial Summary

(millions,
except per share and production amounts) (unaudited)



|                     |  |         |         |   |         |   |         |         |  |   |         |  |  |         |         |  |         |   |         |         |  |   |         |  |  |   |         |  |  |   |         | 
|-------------------- |  | ------- | ------- | - | ------- | - | ------- | ------- |  | - | ------- |  |  | ------- | ------- |  | ------- | - | ------- | ------- |  | - | ------- |  |  | - | ------- |  |  | - | ------- | 
|                     |  | Dec. 31 |         |   | Sep. 30 |   |         | June 30 |  |   | Mar. 31 |  |  | Dec. 31 |         |  | Sep. 30 |   |         | June 30 |  |   | Mar. 31 | 
|Three months ended   |  | 2011    |         |   | 2011    |   |         | 2011    |  |   | 2011    |  |  | 2010    |         |  | 2010    |   |         | 2010    |  |   | 2010    | 
|Gross revenues(1)    |  | $       | 979     |   |         | $ | 861     |         |  | $ | 920     |  |  | $       | 844     |  |         | $ | 782     |         |  | $ | 728     |  |  | $ | 718     |  |  | $ | 806     | 
|Funds flow           |  |         | 437     |   |         |   | 348     |         |  |   | 396     |  |  |         | 356     |  |         |   | 305     |         |  |   | 267     |  |  |   | 269     |  |  |   | 344     | 
|Basic per share      |  |         | 0.93    |   |         |   | 0.74    |         |  |   | 0.85    |  |  |         | 0.77    |  |         |   | 0.67    |         |  |   | 0.59    |  |  |   | 0.62    |  |  |   | 0.81    | 
|Diluted per share    |  |         | 0.93    |   |         |   | 0.74    |         |  |   | 0.85    |  |  |         | 0.77    |  |         |   | 0.66    |         |  |   | 0.58    |  |  |   | 0.61    |  |  |   | 0.81    | 
|Net income (loss)    |  |         | (62     | ) |         |   | 138     |         |  |   | 271     |  |  |         | 291     |  |         |   | (37     | )       |  |   | 304     |  |  |   | 745     |  |  |   | 98      | 
|Basic per share      |  |         | (0.13   | ) |         |   | 0.29    |         |  |   | 0.58    |  |  |         | 0.63    |  |         |   | (0.08   | )       |  |   | 0.67    |  |  |   | 1.72    |  |  |   | 0.23    | 
|Diluted per share    |  |         | (0.13   | ) |         |   | 0.29    |         |  |   | 0.58    |  |  |         | 0.63    |  |         |   | (0.08   | )       |  |   | 0.66    |  |  |   | 1.69    |  |  |   | 0.23    | 
|Dividends declared   |  |         | 127     |   |         |   | 127     |         |  |   | 127     |  |  |         | 125     |  |         |   | 123     |         |  |   | 177     |  |  |   | 196     |  |  |   | 190     | 
|Per share            |  | $       | 0.27    |   |         | $ | 0.27    |         |  | $ | 0.27    |  |  | $       | 0.27    |  |         | $ | 0.27    |         |  | $ | 0.39    |  |  | $ | 0.45    |  |  | $ | 0.45    | 
|Production           |  |         |         |   |         |   |         |         |  |   |         |  |  |         |         |  |         |   |         |         |  |   |         |  |  |   |         |  |  |   |         | 
|Liquids (bbls/d)(2)  |  |         | 108,071 |   |         |   | 101,392 |         |  |   | 98,998  |  |  |         | 104,349 |  |         |   | 105,296 |         |  |   | 98,380  |  |  |   | 95,777  |  |  |   | 96,317  | 
|Natural gas (mmcf/d) |  |         | 364     |   |         |   | 360     |         |  |   | 343     |  |  |         | 371     |  |         |   | 365     |         |  |   | 394     |  |  |   | 408     |  |  |   | 410     | 
|                     |  |         |         |   |         |   |         |         |  |   |         |  |  |         |         |  |         |   |         |         |  |   |         |  |  |   |         |  |  |   |         | 
|Total (boe/d)        |  |         | 168,801 |   |         |   | 161,323 |         |  |   | 156,107 |  |  |         | 166,135 |  |         |   | 166,148 |         |  |   | 164,087 |  |  |   | 163,700 |  |  |   | 164,587 | 
|                     |  |         |         |   |         |   |         |         |  |   |         |  |  |         |         |  |         |   |         |         |  |   |         |  |  |   |         |  |  |   |         | 



|(1) | Gross revenues include realized gains and losses on commodity contracts.
|--- | ------------------------------------------------------------------------

|(2) | Includes crude oil and natural gas liquids.
|--- | -------------------------------------------



2011 ANNUAL
MANAGEMENTS DISCUSSION & ANALYSIS 2



---

Business Strategy

Over the past several years, we have focused our capital program on appraisal activities across our light-oil plays in the Cardium, Carbonates, Spearfish and Viking where we have significant legacy
production, land and infrastructure positions. In 2011, we concentrated on moving these projects from the resource appraisal phase into full-scale development. In 2012, our focus remains on these key light-oil projects with a further shift toward
full-scale development across portions of these plays. The application of horizontal multi-stage drilling technologies continues to be a key component of our success along with continuous operations and the use of pad drilling techniques to drive
improved capital efficiencies. In 2012, we plan to continue the appraisal activities within the Peace River Oil Partnership and the Cordova Joint Venture with our partners. Further appraisal of our extended portfolio of light-oil and liquids-rich
gas plays will continue at a less aggressive pace than in 2010 and 2011. Our unique ownership of light-oil and liquids-rich resources combined with successful resource appraisal over the past several years and our increasing expertise in new
drilling and completions technologies provides us significant opportunities for large-scale oil development in a politically stable environment.

Business Environment

Crude oil markets were volatile in 2011 due to a number of factors.
Supply concerns resulting from social unrest in the Middle East and North Africa led to a rise in crude oil prices in the first half of the year. The loss of crude oil exports from Libya led to prices peaking early in the second quarter. In the
second half of 2011, exports resumed from Libya at a faster than expected rate resulting in lower crude oil prices. European sovereign debt concerns reduced confidence in the outlook for global economic growth which also exerted downward pressure on
crude oil prices. Since the latter part of 2011, crude oil prices have recovered to above US$100 WTI as the market fundamentals re-balanced. As we enter 2012, the European Union continues to address its debt issues; however, it is not clear when
these issues will be resolved. Analysts are currently forecasting a modest level of global GDP growth in 2012 which is expected to result in incremental demand for crude oil. Crude oil prices have also strengthened to date in 2012 due to tightening
unutilized OPEC capacity and geo-political tensions in certain parts of the world, including Iran, where economic sanctions on Irans oil trade could result in future oil supply volatility.

Historically, WTI has traded at a premium to Brent however in 2011 WTI traded at a significant discount to Brent and other world benchmark crudes. This
spread peaked at US$27 per barrel during 2011, but has recently settled at approximately US$20 per barrel. A number of factors contributed to this spread, notably: WTI is priced at Cushing, Oklahoma and thus is a land-locked crude that
does not fully participate in price increases in comparison to crude oil that has ocean access; the loss of Libyan exports earlier in 2011 caused European buyers to place a premium on other streams such as Brent; inventory levels at Cushing rose to
high levels; and, North Sea production problems further contributed to premium Brent pricing. In order for this price differential to fully reverse, additional transportation between Cushing and the Gulf Coast is believed to be required. Currently,
both TransCanada and Enbridge have pipeline projects that, if approved and completed, will enable Canadian crudes to be transported to the Gulf Coast where they will have greater access to world prices. In January 2012, the US government rejected
TransCanadas permit for the Keystone XL pipeline project, however, TransCanada has the option to reapply for a permit in the future. In February 2012, TransCanada announced plans to begin building the south leg of the Keystone XL pipeline
which will connect Cushing, Oklahoma to the Texas Gulf Coast. We have made commitments that will allow us to participate in one of these development projects and we continue to monitor the progress and assess the merits of other projects.

In February 2012, differentials for Canadian oil to WTI widened compared to historical levels. Lower refinery runs due to earlier than normal
turnarounds and the need to work down high gasoline inventory levels have recently softened demand for Canadian crudes. We expect these differentials will normalize as refineries come back on-line and as inventory levels re-balance.



2011 ANNUAL
MANAGEMENTS DISCUSSION & ANALYSIS 3



---

Despite 2011 increases in demand in the industrial and power generation sectors, North America natural gas
markets continue to be over-supplied. The drilling activities in liquids-rich shale gas plays remain robust resulting in increasing natural gas production despite weak natural gas pricing. The combination of increased supply and a mild 2011 winter
have led to lower heating demand and record levels of inventory. Over the next several years, North American access to international gas markets through the development of LNG infrastructure appears to be an important part of rebalancing North
American supply and demand.

Crude Oil

In 2011, WTI crude oil prices averaged US$95.14 per barrel compared to US$79.55 per barrel in 2010. Over the past year, Canadian producers experienced delays delivering their production to market due to
increasing supply and a number of pipeline interruptions. Some transportation issues continue in 2012 due to increased repair and maintenance programs and reduced capacity on some lines which have encountered operational issues. As an alternative,
the use of rail transportation has increased to address congestion. In the future, the benefits of increased reliability due to recent maintenance programs and various expansion projects are expected to reduce disruptions.

Penn Wests average crude oil price for 2011 before the impact of the realized portion of risk management was $83.22 per barrel. Currently Penn West
has 60,000 barrels per day of its 2012 crude oil production hedged between US$85.53 and US$101.16 per barrel and 35,000 barrels per day of its forecast 2013 production hedged between US$93.57 and US$107.91 per barrel.

Natural Gas

In 2011, the AECO Monthly
Index averaged $3.67 per mcf compared to $4.12 per mcf in 2010. The continued drilling activity in liquids-rich shale gas plays in the U.S. is reducing the demand for Canadian gas exports. Currently, Western Canadian gas producers face two specific
challenges compared to their U.S. competitors. Firstly, certain Western Canadian gas streams are drier than many of the U.S. shale gas plays thus price realizations are lower due to lower liquids content, and secondly, the longer distance to end
markets means that Western Canadian gas producers incur higher transportation costs. Current forecasts, at current drilling activity levels, project natural gas liquids production to eventually over supply North American markets resulting in
downward pressure on prices, reducing the value discrepancy between wet and dry gas plays. Many analysts believe the solution for Western Canadian gas is to build the infrastructure capable of providing access to higher netback markets outside of
North America, such as Asia.

Penn Wests corporate average natural gas price for 2011 before the impact of the realized portion of risk
management was $3.78 per mcf. Penn West currently has 50,000 mcf per day of natural gas production hedged for 2012 at an average price of $4.30 per mcf.

Performance Indicators

Our management and Board of Directors monitor our performance based
upon a number of qualitative and quantitative factors including:



| |  |  | Finding and development (F&D) costs  We use these metrics to assess the continuing economic viability and the relative
development stage of our resource plays.
| | - |  | ------------------------------------------------------------------------------------------------------------------------------------------------------------------



| |  |  | Base operations  Includes our production performance and execution of our operational, health, safety, environmental and regulatory programs.
| | - |  | ----------------------------------------------------------------------------------------------------------------------------------------------



| |  |  | Shareholder value measures  These include key enterprise value metrics such as funds flow per share and dividends per share.
| | - |  | -----------------------------------------------------------------------------------------------------------------------------



| |  |  | Financial, business and strategic considerations  These include the management of our asset portfolio, balance sheet stewardship, financial
stewardship and the overall goal of creating competitive return on investment for our shareholders.
| | - |  | ------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



2011 ANNUAL
MANAGEMENTS DISCUSSION & ANALYSIS 4



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Finding and Development costs



|                                                                 |  |                        | $00,000 |  |      |   | $00,000 |      |  |   | $00,000        |  |  |   | $00,000 | 
|---------------------------------------------------------------- |  | ---------------------- | ------- |  | ---- | - | ------- | ---- |  | - | -------------- |  |  | - | ------- | 
|                                                                 |  | Year ended December 31 |        
|                                                                 |  | 2011                   |         |  | 2010 |   |         | 2009 |  |   | 3-Year average | 
|Adjusted F&D costs including future development costs (FDC)(1) |  |                        |         |  |      |   |         |      |  |   |                |  |  |   |         | 
|F&D costs per boeproved plus probable                           |  | $                      | 22.64   |  |      | $ | 21.97   |      |  | $ | 15.18          |  |  | $ | 20.97   | 
|F&D costs per boeproved                                         |  | $                      | 29.71   |  |      | $ | 23.56   |      |  | $ | 15.63          |  |  | $ | 24.70   | 
|                                                                 |  |                        |         | 
|Excluding FDC(2)                                                 |  |                        |         |  |      |   |         |      |  |   |                |  |  |   |         | 
|F&D costs per boeproved plus probable                           |  | $                      | 15.07   |  |      | $ | 18.90   |      |  | $ | 13.75          |  |  | $ | 15.81   | 
|F&D costs per boeproved                                         |  | $                      | 23.55   |  |      | $ | 21.50   |      |  | $ | 16.10          |  |  | $ | 21.11   | 
|                                                                 |  |                        |         | 
|Including FDC(3)                                                 |  |                        |         |  |      |   |         |      |  |   |                |  |  |   |         | 
|F&D costs per boeproved plus probable                           |  | $                      | 26.79   |  |      | $ | 26.73   |      |  | $ | 16.12          |  |  | $ | 24.51   | 
|F&D costs per boeproved                                         |  | $                      | 37.05   |  |      | $ | 28.01   |      |  | $ | 16.19          |  |  | $ | 29.17   | 



|(1) | The calculation of adjusted F&D includes the change in FDC, excludes the effect of economic revisions related to downward revisions of natural gas prices and
excludes land acquisition costs.
|--- | ----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------

|(2) | The calculation of F&D excludes the change in FDC and excludes the effects of acquisitions and dispositions.
|--- | ------------------------------------------------------------------------------------------------------------

|(3) | The calculation of F&D includes the change in FDC and excludes the effects of acquisitions and dispositions.
|--- | ------------------------------------------------------------------------------------------------------------

In 2011, we increased our capital program as we completed our transition to an E&P corporation and continued to focus on our portfolio of light-oil
plays. Our successful drilling program in 2011 resulted in an increase in liquids reserves which led to an increase in total reserves. On a proved basis, our reserves are weighted 74 percent to crude oil and liquids (2010  70 percent). On a
proved plus probable basis our reserves are weighted 71 percent to crude oil and liquids (2010  69 percent) and 29 percent to natural gas (2010  31 percent).

Capital expenditures for 2011 are net of $107 million related to joint venture carried capital (2010  $17 million). We use Adjusted F&D to assess the economic viability and the stage of
development of our resource plays. F&D costs are calculated in accordance with National Instrument 51-101, which include the change in FDC, on a proved and proved plus probable basis. For comparative purposes we also disclose F&D costs
excluding FDC.

The aggregate of the exploration and development costs incurred in the most recent financial year and the change during that
year in estimated future development costs generally will not reflect total finding and development costs related to reserves additions for that year.

Base operations

In 2011, we moved toward full-scale development on many of our light-oil plays.
During the second quarter of 2011, severe flooding in Saskatchewan and Manitoba and wild fires in Alberta caused temporary operating interruptions which we overcame during the third quarter. We ended 2011 with significant operational momentum and
have continued to build on this early in 2012.

Shareholder Value Measures



|                                                            |  |                        | $00,000 |  |          |   | $00,000 |          |  |   | $00,000 | 
|----------------------------------------------------------- |  | ---------------------- | ------- |  | -------- | - | ------- | -------- |  | - | ------- | 
|                                                            |  | Year ended December 31 |        
|                                                            |  | 2011                   |         |  | 2010 (1) |   |         | 2009 (1) | 
|Funds flow per share                                        |  | $                      | 3.29    |  |          | $ | 2.68    |          |  | $ | 3.62    | 
|Dividends/ distributions paid per share                     |  | $                      | 0.90    |  |          | $ | 1.62    |          |  | $ | 2.23    | 
|Ratio of year-end total long-term debt to annual funds flow |  |                        | 2.1:1   |  |          |   | 2.1:1   |          |  |   | 2.2:1   | 



|(1) | Comparative 2010 figures are presented under IFRS. Comparative 2009 figures are presented under previous GAAP.
|--- | --------------------------------------------------------------------------------------------------------------



2011 ANNUAL
MANAGEMENTS DISCUSSION & ANALYSIS 5



---

In April 2011, we began paying a quarterly dividend of $0.27 per share as a corporation. Our last monthly
distribution payment of $0.09 per unit as a trust was declared in December 2010 and paid in January 2011. Currently, our business strategy is to provide shareholder return through a combination of oil-oriented growth and yield.

Our total long-term debt to annual funds flow ratio has remained consistent over the last three years. As we look forward, we aim to grow our funds flow
by oil and liquids production growth relative to both our long-term debt and dividend payout levels.

Financial, business and strategic
considerations



|                        |  |                        | $00,000 |   |          |   | $00,000 |          |  |   | $00,000 |   
|----------------------- |  | ---------------------- | ------- | - | -------- | - | ------- | -------- |  | - | ------- | --
|                        |  | Year ended December 31 |        
|                        |  | 2011                   |         |   | 2010 (1) |   |         | 2009 (1) | 
|Return on capital(2)    |  |                        | 7       | % |          |   | 11      | %        |  |   |        |   
|Return on equity(3)     |  |                        | 7       | % |          |   | 13      | %        |  |   | (2      | )%
|Total assets (millions) |  | $                      | 15,584  |   |          | $ | 14,543  |          |  | $ | 13,876  |   



|(1) | Comparative 2010 figures are presented under IFRS. Comparative 2009 figures are presented under previous GAAP.
|--- | --------------------------------------------------------------------------------------------------------------

|(2) | Net income before financing charges divided by average shareholders equity and average total debt.
|--- | ---------------------------------------------------------------------------------------------------

|(3) | Net income divided by average shareholders equity.
|--- | ---------------------------------------------------

The return on capital and return on equity ratios in 2011 decreased in comparison to 2010 as a result of lower net income mainly due to an increase in unrealized risk management losses and a decline in
gains on dispositions, both non-cash items. In 2010, we recorded significant gains on dispositions as a result of forming the Peace River Oil Partnership and the Cordova Joint Venture.

RESULTS OF OPERATIONS

Production



|                           |  |                        |         |  |      |  |         |          |  |  |    |  
|-------------------------- |  | ---------------------- | ------- |  | ---- |  | ------- | -------- |  |  | -- | -
|                           |  | Year ended December 31 |        
|Daily production           |  | 2011                   |         |  | 2010 |  |         | % change | 
|Light oil and NGL (bbls/d) |  |                        | 85,316  |  |      |  | 80,706  |          |  |  | 6  |  
|Heavy oil (bbls/d)         |  |                        | 17,892  |  |      |  | 18,260  |          |  |  | (2 | )
|Natural gas (mmcf/d)       |  |                        | 359     |  |      |  | 394     |          |  |  | (9 | )
|                           |  |                        |         |  |      |  |         |          |  |  |    |  
|Total production (boe/d)   |  |                        | 163,094 |  |      |  | 164,633 |          |  |  | (1 | )
|                           |  |                        |         |  |      |  |         |          |  |  |    |  

In 2011, production was disrupted in the second quarter and into the third quarter as a result of extreme flooding in
southern Saskatchewan and Manitoba, wild fires in the Slave Lake region in northern Alberta and third party facility outages. As we moved through the third quarter of 2011, activities were concentrated on restoring production and resuming full
operations. In the fourth quarter of 2011, we reached full operating capacity and continued to build on a successful capital program. To date in 2012, we have closed property dispositions for proceeds of approximately $340 million.

When economic to do so, we strive to maintain a strategic mix of liquids and natural gas production in order to reduce exposure to price volatility that
can affect a single commodity. Given the weak outlook for natural gas prices in the medium term and our significant inventory of light-oil locations, we plan to continue allocating substantially all of our capital investments to oil projects.



2011 ANNUAL
MANAGEMENTS DISCUSSION & ANALYSIS 6



---

Average Sales Prices



|                                    |  |                        | $00,000 |   |      |   | $00,000 |          |  |  | $00,000 |  
|----------------------------------- |  | ---------------------- | ------- | - | ---- | - | ------- | -------- |  |  | ------- | -
|                                    |  | Year ended December 31 |        
|                                    |  | 2011                   |         |   | 2010 |   |         | % change | 
|Light oil and liquids (per bbl)     |  | $                      | 86.19   |   |      | $ | 69.29   |          |  |  | 24      |  
|Risk management loss (per bbl)(1)   |  |                        | (2.03   | ) |      |   | (2.72   | )        |  |  | (25     | )
|                                    |  |                        |         |   |      |   |         |          |  |  |         |  
|Light oil and liquids net (per bbl) |  |                        | 84.16   |   |      |   | 66.57   |          |  |  | 26      |  
|                                    |  |                        |         |   |      |   |         |          |  |  |         |  
|                                    |  |                        |        
|Heavy oil (per bbl)                 |  |                        | 69.07   |   |      |   | 60.55   |          |  |  | 14      |  
|                                    |  |                        |         |   |      |   |         |          |  |  |         |  
|                                    |  |                        |        
|Natural gas (per mcf)               |  |                        | 3.78    |   |      |   | 4.20    |          |  |  | (10     | )
|Risk management gain (per mcf)(1)   |  |                        |        |   |      |   | 0.42    |          |  |  | (100    | )
|                                    |  |                        |         |   |      |   |         |          |  |  |         |  
|Natural gas net (per mcf)           |  |                        | 3.78    |   |      |   | 4.62    |          |  |  | (18     | )
|                                    |  |                        |         |   |      |   |         |          |  |  |         |  
|                                    |  |                        |        
|Weighted average (per boe)          |  |                        | 60.99   |   |      |   | 50.74   |          |  |  | 20      |  
|Risk management loss (per boe)(1)   |  |                        | (1.06   | ) |      |   | (0.34   | )        |  |  | 100     |  
|                                    |  |                        |         |   |      |   |         |          |  |  |         |  
|Weighted average net (per boe)      |  | $                      | 59.93   |   |      | $ | 50.40   |          |  |  | 19      |  
|                                    |  |                        |         |   |      |   |         |          |  |  |         |  



|(1) | Gross revenues include realized gains and losses on commodity contracts.
|--- | ------------------------------------------------------------------------



2011 ANNUAL
MANAGEMENTS DISCUSSION & ANALYSIS 7



---

Netbacks



|                             |      |                        |         |      |  |   |          |   |  |  |      |  
|---------------------------- | ---- | ---------------------- | ------- | ---- |  | - | -------- | - |  |  | ---- | -
|                             |      | Year ended December 31 |        
|                             | 2011 |                        |         | 2010 |  |   | % change |  
|Light oil and NGL(1)         |      |                        |         |      |  |   |          |   |  |  |      |  
|Production (bbls/day)        |      |                        | 85,316  |      |  |   | 80,706   |   |  |  | 6    |  
|Operating netback (per bbl): |      |                        |         |      |  |   |          |   |  |  |      |  
|Sales price                  |      | $                      | 86.19   |      |  | $ | 69.29    |   |  |  | 24   |  
|Risk management loss(2)      |      |                        | (2.03   | )    |  |   | (2.72    | ) |  |  | (25  | )
|Royalties                    |      |                        | (16.83  | )    |  |   | (13.73   | ) |  |  | 23   |  
|Operating costs              |      |                        | (21.05  | )    |  |   | (19.83   | ) |  |  | 6    |  
|                             |      |                        |         |      |  |   |          |   |  |  |      |  
|Netback                      |      | $                      | 46.28   |      |  | $ | 33.01    |   |  |  | 40   |  
|                             |      |                        |         |      |  |   |          |   |  |  |      |  
|Heavy oil                    |      |                        |         |      |  |   |          |   |  |  |      |  
|Production (bbls/day)        |      |                        | 17,892  |      |  |   | 18,260   |   |  |  | (2   | )
|Operating netback (per bbl): |      |                        |         |      |  |   |          |   |  |  |      |  
|Sales price                  |      | $                      | 69.07   |      |  | $ | 60.55    |   |  |  | 14   |  
|Royalties                    |      |                        | (10.01  | )    |  |   | (8.73    | ) |  |  | 15   |  
|Operating costs              |      |                        | (17.53  | )    |  |   | (17.14   | ) |  |  | 2    |  
|Transportation               |      |                        | (0.08   | )    |  |   | (0.09    | ) |  |  | (11  | )
|                             |      |                        |         |      |  |   |          |   |  |  |      |  
|Netback                      |      | $                      | 41.45   |      |  | $ | 34.59    |   |  |  | 20   |  
|                             |      |                        |         |      |  |   |          |   |  |  |      |  
|Total liquids                |      |                        |         |      |  |   |          |   |  |  |      |  
|Production (bbls/day)        |      |                        | 103,208 |      |  |   | 98,966   |   |  |  | 4    |  
|Operating netback (per bbl): |      |                        |         |      |  |   |          |   |  |  |      |  
|Sales price                  |      | $                      | 83.22   |      |  | $ | 67.68    |   |  |  | 23   |  
|Risk management loss(2)      |      |                        | (1.68   | )    |  |   | (2.22    | ) |  |  | (24  | )
|Royalties                    |      |                        | (15.64  | )    |  |   | (12.81   | ) |  |  | 22   |  
|Operating costs              |      |                        | (20.44  | )    |  |   | (19.33   | ) |  |  | 6    |  
|Transportation               |      |                        | (0.01   | )    |  |   | (0.02    | ) |  |  | (50  | )
|                             |      |                        |         |      |  |   |          |   |  |  |      |  
|Netback                      |      | $                      | 45.45   |      |  | $ | 33.30    |   |  |  | 36   |  
|                             |      |                        |         |      |  |   |          |   |  |  |      |  
|Natural gas                  |      |                        |         |      |  |   |          |   |  |  |      |  
|Production (mmcf/day)        |      |                        | 359     |      |  |   | 394      |   |  |  | (9   | )
|Operating netback (per mcf): |      |                        |         |      |  |   |          |   |  |  |      |  
|Sales price                  |      | $                      | 3.78    |      |  | $ | 4.20     |   |  |  | (10  | )
|Risk management gain(2)      |      |                        |        |      |  |   | 0.42     |   |  |  | (100 | )
|Royalties                    |      |                        | (0.54   | )    |  |   | (0.58    | ) |  |  | (7   | )
|Operating costs              |      |                        | (2.03   | )    |  |   | (1.71    | ) |  |  | 19   |  
|Transportation               |      |                        | (0.22   | )    |  |   | (0.22    | ) |  |  |     |  
|                             |      |                        |         |      |  |   |          |   |  |  |      |  
|Netback                      |      | $                      | 0.99    |      |  | $ | 2.11     |   |  |  | (53  | )
|                             |      |                        |         |      |  |   |          |   |  |  |      |  
|Combined totals              |      |                        |         |      |  |   |          |   |  |  |      |  
|Production (boe/day)         |      |                        | 163,094 |      |  |   | 164,633  |   |  |  | (1   | )
|Operating netback (per boe): |      |                        |         |      |  |   |          |   |  |  |      |  
|Sales price                  |      | $                      | 60.99   |      |  | $ | 50.74    |   |  |  | 20   |  
|Risk management loss(2)      |      |                        | (1.06   | )    |  |   | (0.34    | ) |  |  | 100  |  
|Royalties                    |      |                        | (11.09  | )    |  |   | (9.07    | ) |  |  | 22   |  
|Operating costs              |      |                        | (17.40  | )    |  |   | (15.71   | ) |  |  | 11   |  
|Transportation               |      |                        | (0.49   | )    |  |   | (0.55    | ) |  |  | (11  | )
|                             |      |                        |         |      |  |   |          |   |  |  |      |  
|Netback                      |      | $                      | 30.95   |      |  | $ | 25.07    |   |  |  | 23   |  
|                             |      |                        |         |      |  |   |          |   |  |  |      |  



|(1) | Excluded from the netback calculation is $37 million primarily related to realized risk management gains on our foreign exchange contracts which swap US dollar revenue
at a fixed Canadian dollar rate.
|--- | --------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------

|(2) | Gross revenues include realized gains and losses on commodity contracts.
|--- | ------------------------------------------------------------------------



2011 ANNUAL
MANAGEMENTS DISCUSSION & ANALYSIS 8



---

Production Revenues

Revenues from the sale of oil, NGL and natural gas consisted of the following:



|                  |  |                        | $00,000 |  |      |   | $00,000 |      |  |   | $00,000 | 
|----------------- |  | ---------------------- | ------- |  | ---- | - | ------- | ---- |  | - | ------- | 
|                  |  | Year ended December 31 |        
|(millions)        |  | 2011                   |         |  | 2010 |   |         | 2009 | 
|Light oil and NGL |  | $                      | 2,657   |  |      | $ | 1,965   |      |  | $ | 1,920   | 
|Heavy oil         |  |                        | 452     |  |      |   | 405     |      |  |   | 509     | 
|Natural gas       |  |                        | 495     |  |      |   | 664     |      |  |   | 774     | 
|                  |  |                        |         |  |      |   |         |      |  |   |         | 
|Gross revenues(1) |  | $                      | 3,604   |  |      | $ | 3,034   |      |  | $ | 3,203   | 
|                  |  |                        |         |  |      |   |         |      |  |   |         | 



|(1) | Gross revenues include realized gains and losses on commodity contracts.
|--- | ------------------------------------------------------------------------

Our successful drilling program has resulted in additional light-oil production and an increase in light-oil revenue. Crude oil prices increased in 2011 from 2010 which led to increases in both light and
heavy-oil revenues. Natural gas prices were lower in 2011 compared to 2010 resulting in a decline in natural gas revenues. Asset dispositions and a capital program concentrated on our light-oil properties led to the decline in natural gas
production.

The decrease in revenue for 2010 from 2009 was mainly the result of lower realized risk management gains and the impact of net
property dispositions which reduced production of heavy oil and natural gas. Light-oil and NGL production increased, notwithstanding the January 2010 asset swap, as we focused our 2010 capital program on light-oil resource plays.

Reconciliation of Increase in Production Revenues



|                                                                          |  |   | $00,000 |  
|------------------------------------------------------------------------- |  | - | ------- | -
|(millions)                                                                |  |   |        
|Gross revenuesJanuary 1December 31, 2010                                |  | $ | 3,034   |  
|Increase in light oil and NGL production                                  |  |   | 112     |  
|Increase in light oil and NGL prices (including realized risk management) |  |   | 580     |  
|Decrease in heavy oil production                                          |  |   | (8      | )
|Increase in heavy oil prices                                              |  |   | 55      |  
|Decrease in natural gas production                                        |  |   | (58     | )
|Decrease in natural gas prices                                            |  |   | (111    | )
|                                                                          |  |   |         |  
|Gross revenuesJanuary 1December 31, 2011                                |  | $ | 3,604   |  
|                                                                          |  |   |         |  

Royalties



|                        |  |                        |       |   |      |   |      |      |  |   |      |  
|----------------------- |  | ---------------------- | ----- | - | ---- | - | ---- | ---- |  | - | ---- | -
|                        |  | Year ended December 31 |      
|                        |  | 2011                   |       |   | 2010 |   |      | 2009 | 
|Royalties (millions)    |  | $                      | 661   |   |      | $ | 545  |      |  | $ | 495  |  
|Average royalty rate(1) |  |                        | 18    | % |      |   | 18   | %    |  |   | 17   | %
|$/boe                   |  | $                      | 11.09 |   |      | $ | 9.07 |      |  | $ | 7.66 |  
|                        |  |                        |       |   |      |   |      |      |  |   |      |  



|(1) | Excludes effects of risk management activities.
|--- | -----------------------------------------------

An increase in crude oil prices has led to an increase in royalties; however, royalty rates have remained comparable in both 2011 and 2010 as lower
royalty rates on new wells under the various royalty incentive programs have partially offset higher royalty rates on base production.

Royalty rates were lower in 2009 due to the effect of the new Alberta royalty programs that became effective for part of 2009. The royalties per boe
amount was lower as a result of lower royalty payments due to lower commodity prices.



2011 ANNUAL
MANAGEMENTS DISCUSSION & ANALYSIS 9



---

Expenses



|                         |  |                        | $00,000 |  |      |   | $00,000 |      |  |   | $00,000 | 
|------------------------ |  | ---------------------- | ------- |  | ---- | - | ------- | ---- |  | - | ------- | 
|                         |  | Year ended December 31 |        
|(millions)               |  | 2011                   |         |  | 2010 |   |         | 2009 | 
|Operating                |  | $                      | 1,036   |  |      | $ | 944     |      |  | $ | 966     | 
|Transportation           |  |                        | 29      |  |      |   | 33      |      |  |   | 34      | 
|Financing                |  |                        | 190     |  |      |   | 174     |      |  |   | 161     | 
|Share-based compensation |  | $                      | 84      |  |      | $ | 159     |      |  | $ | 52      | 
|                         |  |                        |         |  |      |   |         |      |  |   |         | 



|                         |  |                        | $00,000 |  |      |   | $00,000 |      |  |   | $00,000 | 
|------------------------ |  | ---------------------- | ------- |  | ---- | - | ------- | ---- |  | - | ------- | 
|                         |  | Year ended December 31 |        
|(per boe)                |  | 2011                   |         |  | 2010 |   |         | 2009 | 
|Operating                |  | $                      | 17.40   |  |      | $ | 15.71   |      |  | $ | 14.93   | 
|Transportation           |  |                        | 0.49    |  |      |   | 0.55    |      |  |   | 0.52    | 
|Financing                |  |                        | 3.20    |  |      |   | 2.89    |      |  |   | 2.49    | 
|Share-based compensation |  | $                      | 1.41    |  |      | $ | 2.65    |      |  | $ | 0.81    | 
|                         |  |                        |         |  |      |   |         |      |  |   |         | 

Operating

In
2011, the temporary interruptions experienced in the second quarter of 2011 from the wild fires in Slave Lake and flooding in Manitoba and Saskatchewan led to increased workover and maintenance activity in the second half of 2011. These events also
contributed to lower average production volumes which led to an increase in operating costs on a per boe basis. Operating costs for 2011 include a realized gain on electricity contracts of $11 million (2010  $14 million loss and 2009 
$16 million loss). For 2011 the average Alberta pool price was $76.21 per MWh. We have contracts in place that fix the price on approximately 75 percent of our Alberta electricity consumption for 2012 at $53.65 per MWh and additionally in 2013 and
2014 we have approximately 50 percent of our Alberta electricity consumption fixed at $55.20 per MWh and $58.50 per MWh, respectively.

In
2010, acquisition and divestiture activity contributed to an increase in the operating costs per boe. In 2009, there was a greater emphasis on production maintenance activities to maintain production volumes as a weaker commodity price environment
in the early part of the year led to us focusing on efficient methods of maintaining production in the short-term.

Financing

The Company has an unsecured, revolving syndicated bank facility with an aggregate borrowing limit of $2.75 billion. The facility expires on June 26,
2015 and is extendible. The credit facility contains provisions for stamping fees on bankers acceptances and LIBOR loans and standby fees on unutilized credit lines that vary depending on certain consolidated financial ratios. At
December 31, 2011, approximately $1.2 billion was drawn under this facility.



2011 ANNUAL
MANAGEMENTS DISCUSSION & ANALYSIS 10



---

As at December 31, 2011, the Company had $2.0 billion (2010  $1.7 billion) of senior unsecured
notes outstanding with a weighted average interest rate, including the effects of interest rate swaps, of approximately 5.9 percent (2010  5.7 percent) and a weighted average remaining term of 6.5 years (2010  7.2 years), as follows:



|              |  |                                  |  |                        |  |              |  |                      |      |      |                                |          
|------------- |  | -------------------------------- |  | ---------------------- |  | ------------ |  | -------------------- | ---- | ---- | ------------------------------ | ---------
|              |  | Issue date                       |  | Amount (millions)      |  | Term         |  | Averageinterest rate |      |      | Weighted averageremaining term
|2007 Notes    |  | May 31, 2007                     |  | US$475                 |  | 8 15 years  |  |                      | 5.80 | %    |                                | 5.5 years
|2008 Notes    |  | May 29, 2008                     |  | US$480, CAD$30         |  | 8 12 years  |  |                      | 6.25 | %    |                                | 6.0 years
|UK Notes      |  | July 31, 2008                    |  | £57                    |  | 10 years     |  |                      | 6.95 | %(1) |                                | 6.6 years
|2009 Notes    |  | May 5, 2009                      |  | US$154, £20,10, CAD$5 |  | 5  10 years |  |                      | 8.85 | %(2) |                                | 5.0 years
|2010 Q1 Notes |  | March 16, 2010                   |  | US$250, CAD$50         |  | 5  15 years |  |                      | 5.47 | %    |                                | 6.8 years
|2010 Q4 Notes |  | December 2, 2010,January 4, 2011 |  | US$170, CAD$60         |  | 5  15 years |  |                      | 5.00 | %    |                                | 9.7 years
|2011 Notes    |  | November 30, 2011                |  | US$105, CAD$30         |  | 5  10 years |  |                      | 4.49 | %    |                                | 8.1 years



|(1) | These notes bear interest at 7.78 percent in Pounds Sterling, however, contracts were entered to fix the interest rate at 6.95 percent in Canadian dollars and to fix
the exchange rate on the repayment.
|--- | ---------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------

|(2) | The Company entered into contracts to fix the interest rate on the Pounds Sterling and Euro tranches, initially at 9.49 percent and 9.52 percent, to 9.15 percent and
9.22 percent, respectively, and to fix the exchange rate on repayment.
|--- | --------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------

In November 2011, we closed a private placement of
senior unsecured notes (the 2011 Notes) with aggregate principal amounts of approximately $135 million. The 2011 Notes had an original weighted average term of approximately 8.1 years and an average fixed interest rate of approximately
4.49 percent. The Company used the proceeds of the issue to repay advances on its syndicated bank facility.

In January 2011, we completed the
closing of a private placement of senior unsecured notes, (the 2010 Q4 Notes), with an aggregate principal amount of approximately US$230 million. The 2010 Q4 Notes had an original weighted average term of 10.8 years and bear a weighted
average fixed interest rate of approximately 5.0 percent. The Company used the proceeds of the issue to repay advances on its syndicated bank facility.

Financing charges in 2011 were higher than in 2010 since a higher percentage of our debt capital was held in longer-term, fixed rate, senior unsecured notes. The cost of borrowing under the current bank
facility increased compared to the facility in place during 2009 and the first quarter of 2010 due to increased rates in the bank market. While the Companys senior unsecured notes contain higher interest rates than the syndicated bank
facilities held in short-term money market instruments, we believe the long-term and fixed interest rates inherent in the senior notes are favourable for a portion of our debt capital structure.

The interest rates on any non-hedged portion of the Companys bank debt are subject to fluctuations in short-term money market rates as advances on
the bank facility are generally made under short-term instruments. As at December 31, 2011, 19 percent (2010  none and 2009  14 percent) of our long-term debt instruments were exposed to changes in short-term interest rates.

At December 31, 2011, the Company had $650 million of interest rate swaps outstanding at a weighted average fixed rate of 2.65 percent
and an expiry date of January 2014.

Realized gains and losses on the interest rate swaps are recorded as financing costs. For 2011 an expense
of $12 million (2010 and 2009  $21 million) was recognized in financing to reflect that the floating interest rate was lower than the fixed interest rate transacted under our interest rate swaps.



2011 ANNUAL
MANAGEMENTS DISCUSSION & ANALYSIS 11



---

Share-Based Compensation

Share-based compensation expense is related to our Stock Option Plan (the Option Plan), our Common Share Rights Incentive Plan (the CSRIP), our Long-Term Retention and Incentive
Plan (LTRIP), and our Deferred Share Unit Plan (the DSU) as described in Note 15 to our audited consolidated financial statements.

Effective January 1, 2011, we implemented the Option Plan and amended our Trust Unit Rights Incentive Plan (TURIP) which became the CSRIP. Pursuant to our plan to convert from a trust to
a corporation, trust unit right holders had the choice to receive one restricted option (a Restricted Option) and one restricted right (a Restricted Right) for each outstanding in-the-money trust unit right. Those
trust unit right holders who chose not to make the election or held trust unit rights that were out-of-the-money on January 1, 2011, received one common share right (Share Rights) issued under the CSRIP for each trust
unit right. After January 1, 2011, all grants are under the Option Plan.

Trust unit rights issued under the former TURIP received
liability treatment for accounting purposes throughout 2010 as we operated in an income trust structure. The Restricted Options, Share Rights and subsequent grants under the Option Plan receive equity treatment for accounting purposes subsequent to
our conversion to a corporation with the fair value of each instrument expensed over the expected vesting period based on a graded vesting schedule. The fair values of the Restricted Options and new option grants are calculated using a Black-Scholes
option-pricing model and a Binomial Lattice option-pricing model continues to be used to value the Share Rights. The Restricted Rights are accounted for as a liability as holders may elect to settle in cash or common shares.

On January 1, 2011, the previously recognized trust unit rights liability was removed and a share-based compensation liability was recorded for the
Restricted Rights with the fair value charged to income. The fair values of the Restricted Options and Share Rights were also charged to income as at January 1, 2011, with an offset to other reserves. The elimination of the TURIP and subsequent
implementation of the Option Plan and CSRIP resulted in a net $58 million charge to income during the first quarter of 2011.

The change in
the fair value of outstanding LTRIP awards is charged to income based on the common share price at the end of each reporting period plus accumulated dividends. The LTRIP obligation is accrued over the vesting period as service is completed by
employees and expensed based on a graded vesting schedule. Subsequent increases and decreases in the underlying common share price will result in increases and decreases charged to income to adjust the LTRIP obligation to fair value until
settlement.

Share-based compensation consisted of the following:



|                                            |  |                        | $00,000 |   |      |   | $00,000 |      |  |   | $00,000 | 
|------------------------------------------- |  | ---------------------- | ------- | - | ---- | - | ------- | ---- |  | - | ------- | 
|                                            |  | Year ended December 31 |        
|(millions)                                  |  | 2011                   |         |   | 2010 |   |         | 2009 | 
|Options                                     |  | $                      | 18      |   |      | $ |        |      |  | $ |        | 
|Restricted Options                          |  |                        | 22      |   |      |   |        |      |  |   |        | 
|Restricted Rights                           |  |                        | (29     | ) |      |   |        |      |  |   |        | 
|Share Rights                                |  |                        | 1       |   |      |   |        |      |  |   |        | 
|LTRIP                                       |  |                        | 14      |   |      |   | 8       |      |  |   |        | 
|TURIP                                       |  |                        |        |   |      |   | 151     |      |  |   | 52      | 
|Expiry of TURIP at Jan. 1, 2011             |  |                        | (196    | ) |      |   |        |      |  |   |        | 
|Share Rights at Jan. 1, 2011                |  |                        | 16      |   |      |   |        |      |  |   |        | 
|Restricted Options at Jan. 1, 2011          |  |                        | 65      |   |      |   |        |      |  |   |        | 
|Restricted Rights liability at Jan. 1, 2011 |  |                        | 173     |   |      |   |        |      |  |   |        | 
|                                            |  |                        |         |   |      |   |         |      |  |   |         | 
|Share-based compensation                    |  | $                      | 84      |   |      | $ | 159     |      |  | $ | 52      | 
|                                            |  |                        |         |   |      |   |         |      |  |   |         | 

The share price used in the fair value calculation of the LTRIP liability and Restricted Rights obligation at
December 31, 2011 was $20.19 (2010  $23.84 and 2009  N/A).



2011 ANNUAL
MANAGEMENTS DISCUSSION & ANALYSIS 12



---

General and Administrative Expenses (G&A)



|                                   |  |                        | $00,000 |  |      |   | $00,000 |      |  |   | $00,000 | 
|---------------------------------- |  | ---------------------- | ------- |  | ---- | - | ------- | ---- |  | - | ------- | 
|                                   |  | Year ended December 31 |        
|(millions, except per boe amounts) |  | 2011                   |         |  | 2010 |   |         | 2009 | 
|Gross                              |  | $                      | 222     |  |      | $ | 207     |      |  | $ | 189     | 
|Per boe                            |  |                        | 3.72    |  |      |   | 3.45    |      |  |   | 2.93    | 
|Net                                |  |                        | 142     |  |      |   | 145     |      |  |   | 129     | 
|Per boe                            |  | $                      | 2.38    |  |      | $ | 2.41    |      |  | $ | 1.99    | 
|                                   |  |                        |         |  |      |   |         |      |  |   |         | 

For 2011, our staff levels continued to increase compared to 2010 as we transitioned to an E&P production company
resulting in higher gross costs.

In 2010 we began increasing our complement of technical staff and consolidated our employees into one
building prior to our conversion to an E&P company which led to higher staff and building occupancy costs in 2010 compared to 2009.

Depletion, Depreciation and Accretion



|                                       |  |                        | $00,000 |  |      |   | $00,000 |      |  |   | $00,000 | 
|-------------------------------------- |  | ---------------------- | ------- |  | ---- | - | ------- | ---- |  | - | ------- | 
|                                       |  | Year ended December 31 |        
|(millions, except per boe amounts)     |  | 2011                   |         |  | 2010 |   |         | 2009 | 
|Depletion and depreciation (D&D)     |  | $                      | 1,158   |  |      | $ | 1,169   |      |  | $ | 1,514   | 
|D&D expense per boe                    |  |                        | 19.45   |  |      |   | 19.44   |      |  |   | 23.39   | 
|Accretion of decommissioning liability |  |                        | 45      |  |      |   | 44      |      |  |   | 42      | 
|Accretion expense per boe              |  | $                      | 0.76    |  |      | $ | 0.73    |      |  | $ | 0.65    | 
|                                       |  |                        |         |  |      |   |         |      |  |   |         | 

D&D and accretion rates were comparable in 2011 and 2010. In 2009, under previous GAAP, depletion was based on proved
reserves which resulted in a higher rate.

During the first quarter of 2011, we recorded an impairment reversal of $39 million (2010 
none) to reflect stronger commodity prices resulting in higher forecast cash flows relating to properties in central Alberta. In the second quarter of 2011, we recorded a $29 million impairment (2010  $80 million) on certain properties in
central Alberta due to weaker forward commodity prices.

Taxes



|                      |  |                        | $00,000 |   |      |   | $00,000 |      |  |   | $00,000 |  
|--------------------- |  | ---------------------- | ------- | - | ---- | - | ------- | ---- |  | - | ------- | -
|                      |  | Year ended December 31 |        
|(millions)            |  | 2011                   |         |   | 2010 |   |         | 2009 | 
|Deferred tax recovery |  | $                      | (227    | ) |      | $ | (101    | )    |  | $ | (378    | )
|                      |  |                        |         |   |      |   |         |      |  |   |         |  

The 2011 deferred tax recovery includes a $304 million recovery related to the tax rate differential on our conversion
from a trust to an E&P company. As a corporation, we are subject to income taxes at Canadian corporate tax rates. In the trust structure, under IFRS we were required to tax-effect timing differences in our trust entities at rates applicable to
undistributed earnings of a trust being the maximum marginal income tax rate for individuals in the Province of Alberta.

The 2010 amount
included a $177 million recovery related to corporate restructuring. The comparative figure in 2009 included a $168 million recovery related to unrealized risk management losses and a $65 million recovery related to income tax legislation enacted by
the Government of Canada which reduced the provincial component of the Specified Investment Flow-Through (SIFT) tax rate from 13 percent to 10 percent.

We currently have a significant tax pool base. Based on current commodity prices and capital spending plans, we forecast these pools will shelter our taxable income for an extended period.



2011 ANNUAL
MANAGEMENTS DISCUSSION & ANALYSIS 13



---

Tax Pools



|                                              |  |                   | $00,000 |  |      |   | $00,000 |      |  |   | $00,000 | 
|--------------------------------------------- |  | ----------------- | ------- |  | ---- | - | ------- | ---- |  | - | ------- | 
|                                              |  | As at December 31 |        
|(millions)                                    |  | 2011              |         |  | 2010 |   |         | 2009 | 
|Undepreciated capital cost (UCC)              |  | $                 | 1,085   |  |      | $ | 1,122   |      |  | $ | 1,379   | 
|Canadian oil and gas property expense (COGPE) |  |                   | 1,395   |  |      |   | 1,562   |      |  |   | 1,912   | 
|Canadian development expense (CDE)            |  |                   | 2,104   |  |      |   | 1,494   |      |  |   | 1,141   | 
|Canadian exploration expense (CEE)            |  |                   | 294     |  |      |   | 305     |      |  |   | 280     | 
|Non-capital losses                            |  |                   | 2,966   |  |      |   | 2,481   |      |  |   | 2,139   | 
|Other                                         |  |                   | 31      |  |      |   | 31      |      |  |   | 16      | 
|                                              |  |                   |         |  |      |   |         |      |  |   |         | 
|Total                                         |  | $                 | 7,875   |  |      | $ | 6,995   |      |  | $ | 6,867   | 
|                                              |  |                   |         |  |      |   |         |      |  |   |         | 

Tax pool amounts exclude income deferred in operating partnerships of $1,654 million in 2011 (2010  $920 million
and 2009  $931 million).

Foreign Exchange



|                                        |  |                        | $00,000 |  |      |   | $00,000 |      |  |   | $00,000 |  
|--------------------------------------- |  | ---------------------- | ------- |  | ---- | - | ------- | ---- |  | - | ------- | -
|                                        |  | Year ended December 31 |        
|(millions)                              |  | 2011                   |         |  | 2010 |   |         | 2009 | 
|Unrealized foreign exchange loss (gain) |  | $                      | 38      |  |      | $ | (82     | )    |  | $ | (186    | )
|                                        |  |                        |         |  |      |   |         |      |  |   |         |  

We record unrealized foreign exchange gains or losses to translate the U.S., UK and Euro denominated notes and the
related accrued interest to Canadian dollars using the exchange rates in effect on the balance sheet date. The unrealized losses during 2011 were primarily due to the weakening of the Canadian dollar relative to the US dollar and the gains during
2010 and 2009 were primarily due to the strengthening of the Canadian dollar relative to the US dollar.

Funds Flow and Net Income (Loss)



|                             |  |                        | $00,000 |  |      |   | $00,000 |      |  |   | $00,000 |  
|---------------------------- |  | ---------------------- | ------- |  | ---- | - | ------- | ---- |  | - | ------- | -
|                             |  | Year ended December 31 |        
|                             |  | 2011                   |         |  | 2010 |   |         | 2009 | 
|Funds flow(1)(millions)      |  | $                      | 1,537   |  |      | $ | 1,185   |      |  | $ | 1,493   |  
|Basic per share              |  |                        | 3.29    |  |      |   | 2.68    |      |  |   | 3.62    |  
|Diluted per share            |  |                        | 3.29    |  |      |   | 2.65    |      |  |   | 3.60    |  
|                             |  |                        |        
|Net income (loss) (millions) |  |                        | 638     |  |      |   | 1,110   |      |  |   | (144    | )
|Basic per share              |  |                        | 1.37    |  |      |   | 2.51    |      |  |   | (0.35   | )
|Diluted per share            |  | $                      | 1.36    |  |      | $ | 2.48    |      |  | $ | (0.35   | )
|                             |  |                        |         |  |      |   |         |      |  |   |         |  



|(1) | Funds flow is a non-GAAP measure. See Calculation of Funds Flow.
|--- | ------------------------------------------------------------------

Funds flow for 2011 increased from 2010 primarily due to an increase in our weighting of light-oil production and an increase in crude oil prices. In 2010, funds flow was lower than 2009 primarily as a
result of net property dispositions and lower realized risk management gains.

For 2011, net income decreased compared to 2010 as significant
gains on asset dispositions were recorded in 2010, which included a $368 million gain on the formation of the Cordova Joint Venture and a $572 million after-tax gain on the formation of the Peace River Oil Partnership. This was partially offset by a
$304 million deferred tax recovery related to our conversion from an income trust to a corporate structure. The increase in net income in 2010 from 2009 was due to the gains on asset dispositions in 2010.



2011 ANNUAL
MANAGEMENTS DISCUSSION & ANALYSIS 14



---

|                                        |  |                        | $0,00000 |   |      |  | $0,00000 |   |  |   | $0,00000 |   |  |  | $0,00000 |   |      |   | $0,00000 |   |  |  | $0,00000 |  
|--------------------------------------- |  | ---------------------- | -------- | - | ---- |  | -------- | - |  | - | -------- | - |  |  | -------- | - | ---- | - | -------- | - |  |  | -------- | -
|                                        |  | Year ended December 31 |         
|                                        |  |                        |          |   | 2011 |  |          |   |  |   | 2010     |   |  |  |          |   | 2009 |  
|                                        |  |                        |          |   |      |  |          |   |  |   |          |   |  |  |          |   |      |   |          |   |  |  |         
|                                        |  |                        | per boe  |   |      |  | %        |   |  |   | per boe  |   |  |  | %        |   |      |   | per boe  |   |  |  | %        |  
|                                        |  |                        |          |   |      |  |          |   |  |   |          |   |  |  |          |   |      |   |          |   |  |  |          |  
|Oil and natural gas revenues(1)         |  | $                      | 60.54    |   |      |  | 100      |   |  | $ | 50.46    |   |  |  | 100      |   |      | $ | 50.67    |   |  |  | 100      |  
|Royalties                               |  |                        | (11.09   | ) |      |  | (18      | ) |  |   | (9.07    | ) |  |  | (18      | ) |      |   | (7.66    | ) |  |  | (15      | )
|Operating expenses(2)                   |  |                        | (17.40   | ) |      |  | (29      | ) |  |   | (15.71   | ) |  |  | (31      | ) |      |   | (14.93   | ) |  |  | (30      | )
|Transportation                          |  |                        | (0.49    | ) |      |  | (1       | ) |  |   | (0.55    | ) |  |  | (1       | ) |      |   | (0.52    | ) |  |  | (1       | )
|                                        |  |                        |          |   |      |  |          |   |  |   |          |   |  |  |          |   |      |   |          |   |  |  |          |  
|Net operating income                    |  |                        | 31.56    |   |      |  | 52       |   |  |   | 25.13    |   |  |  | 50       |   |      |   | 27.56    |   |  |  | 54       |  
|General and administrative expenses     |  |                        | (2.38    | ) |      |  | (4       | ) |  |   | (2.41    | ) |  |  | (5       | ) |      |   | (1.99    | ) |  |  | (4       | )
|Share-based compensation  cash         |  |                        | (0.15    | ) |      |  |         |   |  |   | (0.14    | ) |  |  |         |   |      |   |         |   |  |  |         |  
|Financing(3)                            |  |                        | (3.20    | ) |      |  | (5       | ) |  |   | (2.89    | ) |  |  | (6       | ) |      |   | (2.49    | ) |  |  | (5       | )
|                                        |  |                        |          |   |      |  |          |   |  |   |          |   |  |  |          |   |      |   |          |   |  |  |          |  
|Funds flow                              |  |                        | 25.83    |   |      |  | 43       |   |  |   | 19.69    |   |  |  | 39       |   |      |   | 23.08    |   |  |  | 45       |  
|Unrealized foreign exchange gain (loss) |  |                        | (0.64    | ) |      |  | (1       | ) |  |   | 1.36     |   |  |  | 3        |   |      |   | 2.88     |   |  |  | 6        |  
|Share-based compensation                |  |                        | (1.26    | ) |      |  | (2       | ) |  |   | (2.51    | ) |  |  | (5       | ) |      |   | (0.81    | ) |  |  | (2       | )
|Risk management activities(4)           |  |                        | 0.55     |   |      |  | 1        |   |  |   | 0.40     |   |  |  | 1        |   |      |   | (9.17    | ) |  |  | (18      | )
|Depletion and depreciation              |  |                        | (19.45   | ) |      |  | (32      | ) |  |   | (19.44   | ) |  |  | (39      | ) |      |   | (23.39   | ) |  |  | (46      | )
|Accretion                               |  |                        | (0.76    | ) |      |  | (1       | ) |  |   | (0.73    | ) |  |  | (1       | ) |      |   | (0.65    | ) |  |  | (1       | )
|Gain on dispositions                    |  |                        | 2.89     |   |      |  | 5        |   |  |   | 18.02    |   |  |  | 36       |   |      |   |         |   |  |  |         |  
|Exploration and evaluation              |  |                        | (0.25    | ) |      |  | (1       | ) |  |   | (0.02    | ) |  |  |         |   |      |   |         |   |  |  |         |  
|Deferred tax recovery                   |  |                        | 3.80     |   |      |  | 6        |   |  |   | 1.70     |   |  |  | 3        |   |      |   | 5.84     |   |  |  | 12       |  
|                                        |  |                        |          |   |      |  |          |   |  |   |          |   |  |  |          |   |      |   |          |   |  |  |          |  
|Net income (loss)                       |  | $                      | 10.71    |   |      |  | 18       |   |  | $ | 18.47    |   |  |  | 37       |   |      | $ | (2.22    | ) |  |  | (4       | )
|                                        |  |                        |          |   |      |  |          |   |  |   |          |   |  |  |          |   |      |   |          |   |  |  |          |  



|(1) | Gross revenues include realized gains and losses on commodity contracts.
|--- | ------------------------------------------------------------------------

|(2) | Operating expenses include realized gains/ losses on electricity swaps.
|--- | -----------------------------------------------------------------------

|(3) | Financing expenses include realized losses on interest rate swaps.
|--- | ------------------------------------------------------------------

|(4) | Risk management activities relate to unrealized gains and losses on derivative instruments.
|--- | -------------------------------------------------------------------------------------------

Capital Expenditures



|                               |  |                        | $00,000 |   |      |   | $00,000 |      |  |   | $00,000 |  
|------------------------------ |  | ---------------------- | ------- | - | ---- | - | ------- | ---- |  | - | ------- | -
|                               |  | Year ended December 31 |        
|(millions)                     |  | 2011                   |         |   | 2010 |   |         | 2009 | 
|Land acquisition and retention |  | $                      | 181     |   |      | $ | 102     |      |  | $ | 19      |  
|Drilling and completions       |  |                        | 1,217   |   |      |   | 800     |      |  |   | 286     |  
|Facilities and well equipping  |  |                        | 521     |   |      |   | 281     |      |  |   | 336     |  
|Geological and geophysical     |  |                        | 9       |   |      |   | 10      |      |  |   | 9       |  
|Corporate                      |  |                        | 25      |   |      |   | 11      |      |  |   | 38      |  
|                               |  |                        |         |   |      |   |         |      |  |   |         |  
|Capital expenditures(1)        |  |                        | 1,953   |   |      |   | 1,204   |      |  |   | 688     |  
|Joint venture, carried capital |  |                        | (107    | ) |      |   | (17     | )    |  |   |        |  
|Property dispositions, net     |  |                        | (266    | ) |      |   | (1,306  | )    |  |   | (369    | )
|                               |  |                        |         |   |      |   |         |      |  |   |         |  
|Capital expenditures, net      |  |                        | 1,580   |   |      |   | (119    | )    |  |   | 319     |  
|Business combinations          |  |                        | 286     |   |      |   | 139     |      |  |   | 116     |  
|                               |  |                        |         |   |      |   |         |      |  |   |         |  
|Total expenditures             |  | $                      | 1,866   |   |      | $ | 20      |      |  | $ | 435     |  
|                               |  |                        |         |   |      |   |         |      |  |   |         |  



|(1) | Capital expenditures include costs related to development capital and Exploration and Evaluation activities.
|--- | ------------------------------------------------------------------------------------------------------------

In 2011, we increased our capital program as we transitioned some of our light-oil plays from the appraisal phase into full-scale development which led
to an increase in drilling and completions, facilities and well equipping capital costs. We were also successful at land sales and acquired strategic lands to complement our existing asset base.

During 2010, we increased our capital spending compared to 2009 to take advantage of success at our light-oil resource plays and in preparation for our
conversion to an E&P company. This resulted in an increase in drilling and completions expenditures year-over-year.



2011 ANNUAL
MANAGEMENTS DISCUSSION & ANALYSIS 15



---

Drilling



|                          |  |                        |     |      |     |  |     |       |  |      |     |  |  |  |     |  
|------------------------- |  | ---------------------- | --- | ---- | --- |  | --- | ----- |  | ---- | --- |  |  |  | --- | -
|                          |  | Year ended December 31 |    
|                          |  |                        |     | 2011 |     |  |     |       |  | 2010 |    
|                          |  | Gross                  |     |      | Net |  |     | Gross |  |      | Net | 
|Oil                       |  |                        | 457 |      |     |  | 353 |       |  |      | 351 |  |  |  | 245 |  
|Natural gas               |  |                        | 53  |      |     |  | 36  |       |  |      | 53  |  |  |  | 38  |  
|Dry                       |  |                        |    |      |     |  |    |       |  |      | 3   |  |  |  | 2   |  
|                          |  |                        |     |      |     |  |     |       |  |      |     |  |  |  |     |  
|                          |  |                        | 510 |      |     |  | 389 |       |  |      | 407 |  |  |  | 285 |  
|Stratigraphic and service |  |                        | 89  |      |     |  | 37  |       |  |      | 54  |  |  |  | 34  |  
|                          |  |                        |     |      |     |  |     |       |  |      |     |  |  |  |     |  
|Total                     |  |                        | 599 |      |     |  | 426 |       |  |      | 461 |  |  |  | 319 |  
|                          |  |                        |     |      |     |  |     |       |  |      |     |  |  |  |     |  
|Success rate(1)           |  |                        |     |      |     |  | 100 | %     |  |      |     |  |  |  | 99  | %
|                          |  |                        |     |      |     |  |     |       |  |      |     |  |  |  |     |  



|(1) | Success rate is calculated excluding stratigraphic and service wells.
|--- | ---------------------------------------------------------------------

Gain on asset dispositions



|                           |  |                        |     |  |      |   |       |      |  |   |   | 
|-------------------------- |  | ---------------------- | --- |  | ---- | - | ----- | ---- |  | - | - | 
|                           |  | Year ended December 31 |    
|(millions)                 |  | 2011                   |     |  | 2010 |   |       | 2009 | 
|Gain on asset dispositions |  | $                      | 172 |  |      | $ | 1,082 |      |  | $ |  | 
|                           |  |                        |     |  |      |   |       |      |  |   |   | 

During 2011, we closed property dispositions which resulted in gains of $172 million recognized in income (2010 
$1,082 million). In June 2010, as a result of forming the Peace River Oil Partnership, we recognized a pre-tax gain of $749 million in income and in September 2010, due to entering the Cordova Joint Venture, we recognized a $368 million gain.

Exploration and evaluation (E&E) capital expenditures



|                         |  |                        | $00,000 |  |      |   | $00,000 |      |  |   | $00,000 | 
|------------------------ |  | ---------------------- | ------- |  | ---- | - | ------- | ---- |  | - | ------- | 
|                         |  | Year ended December 31 |        
|(millions)               |  | 2011                   |         |  | 2010 |   |         | 2009 | 
|E&E capital expenditures |  | $                      | 321     |  |      | $ | 58      |      |  | $ |        | 
|                         |  |                        |         |  |      |   |         |      |  |   |         | 

Our E&E capital expenditures increased due to strategic land purchases and exploration and evaluation activities
since our conversion to an E&P company. Included in E&E capital expenditures is the benefit of $92 million of joint venture carried capital in 2011 (2010  nil). During 2011, we transferred $14 million from E&E into PP&E and we
had a non-cash E&E expense of $15 million (2010  $1 million) related to land expiries and unsuccessful exploration activities.

In
2011, we disposed of E&E assets valued at $2 million (2010  $61 million) in connection with property dispositions.

Spartan
Exploration Ltd. (Spartan) business combination

On June 1, 2011, we closed the acquisition of Spartan, a publicly traded
oil and gas exploration company with assets primarily located in the Cardium light-oil resource play in central Alberta. The total cost was $166 million, including the assumption of approximately $39 million of debt, with $286 million recorded to
property, plant and equipment.

Sifton Energy Inc. (Sifton) business combination

On December 22, 2010, we closed the acquisition of Sifton, a private oil and gas exploration company with assets primarily located in the Cardium
light-oil resource play in central Alberta. The total acquisition cost was approximately $108 million, which included the assumption of approximately $23 million of debt and working capital.



2011 ANNUAL
MANAGEMENTS DISCUSSION & ANALYSIS 16



---

Cordova Joint Venture

In the third quarter of 2010, we closed a joint venture agreement with a subsidiary of Mitsubishi Corporation (Mitsubishi) to develop our shale gas assets in the Cordova Embayment and certain
conventional gas assets at our Wildboy property in northeastern British Columbia. As part of the arrangement, we sold a 50 percent interest in these assets to Mitsubishi in exchange for approximately $250 million of cash and approximately $205
million of future commitments. Mitsubishi will fund $600 million of the first $800 million of capital expenditures in this joint venture and we will continue to serve as the operator of the assets.

Peace River Oil Partnership

In the
second quarter of 2010, we closed the transaction creating the Peace River Oil Partnership to develop oil resources in the Peace River area of northern Alberta. We contributed assets valued at $1.8 billion, retained a 55 percent interest in the
partnership and received approximately $817 million which included $312 million cash paid upon closing and $505 million committed to us to fund our share of future capital and operating expenses for the Peace River Oil Partnership. As a result, on
the first $1.0 billion of capital and operating costs to be incurred by the partnership, we will contribute approximately $56 million while maintaining our 55 percent interest in the partnership. In addition, we closed a private placement issuing
approximately 23.5 million trust units to our partner for gross proceeds of $435 million ($424 million net).

January 2010 Asset Swap

In the first quarter of 2010, we closed an Asset Exchange Agreement increasing our position in our light-oil resource plays at Pembina and
Dodsland with total production of approximately 560 boe per day in exchange for certain interests in the Leitchville area with total production of approximately 3,500 boe per day. Additionally, we received net cash proceeds of approximately $434
million which were applied to our bank facility.

Goodwill



|                                   |  |                        | $00,000 |  |      |   | $00,000 |      |  |   | $00,000 | 
|---------------------------------- |  | ---------------------- | ------- |  | ---- | - | ------- | ---- |  | - | ------- | 
|                                   |  | Year ended December 31 |        
|(millions)                         |  | 2011                   |         |  | 2010 |   |         | 2009 | 
|Balance, beginning and end of year |  | $                      | 2,020   |  |      | $ | 2,020   |      |  | $ | 2,020   | 
|                                   |  |                        |         |  |      |   |         |      |  |   |         | 

We recorded goodwill on our acquisitions of Petrofund Energy Trust, Canetic Resources Trust and Vault Energy Trust. We
determined there was no goodwill impairment at December 31, 2011.

Environmental and Climate Change

The oil and gas industry has a number of environmental risks and hazards and is subject to regulation by all levels of government. Environmental
legislation includes, but is not limited to, operational controls, site restoration requirements and restrictions on emissions of various substances produced in association with oil and natural gas operations. Compliance with such legislation could
require additional expenditures and a failure to comply may result in fines and penalties which could, in the aggregate and under certain assumptions, become material.

We are dedicated to reducing the environmental impact from our operations through our environmental programs which include resource conservation,
CO2sequestration, water management and site
abandonment/reclamation. Operations are continuously monitored to minimize the environmental impact and sufficient capital is allocated to reclamation and other activities to mitigate the impact on the areas in which we operate.



2011 ANNUAL
MANAGEMENTS DISCUSSION & ANALYSIS 17



---

Liquidity and Capital Resources

Capitalization



|                                   |  |                   | $00,000 |   |      |  | $00,000 |  |  |   | $00,000 |  |  |  | $00,000 |   |      |   | $00,000 |  |  |  | $00,000 | 
|---------------------------------- |  | ----------------- | ------- | - | ---- |  | ------- |  |  | - | ------- |  |  |  | ------- | - | ---- | - | ------- |  |  |  | ------- | 
|                                   |  | As at December 31 |        
|(millions)                         |  |                   |         |   | 2011 |  |         |  |  |   | 2010    |  |  |  |         |   | 2009 |  
|                                   |  |                   |         | % |      |  |         |  |  | % |         |  |  |  |         | % |     
|Common shares issued, at market(1) |  | $                 | 9,517   |   |      |  | 72      |  |  | $ | 10,959  |  |  |  | 78      |   |      | $ | 7,821   |  |  |  | 69      | 
|Bank loans and long-term notes     |  |                   | 3,219   |   |      |  | 24      |  |  |   | 2,496   |  |  |  | 18      |   |      |   | 3,219   |  |  |  | 28      | 
|Convertible debentures             |  |                   |        |   |      |  |        |  |  |   | 255     |  |  |  | 2       |   |      |   | 255     |  |  |  | 2       | 
|Working capital deficiency(2)      |  |                   | 554     |   |      |  | 4       |  |  |   | 303     |  |  |  | 2       |   |      |   | 106     |  |  |  | 1       | 
|                                   |  |                   |         |   |      |  |         |  |  |   |         |  |  |  |         |   |      |   |         |  |  |  |         | 
|Total enterprise value             |  | $                 | 13,290  |   |      |  | 100     |  |  | $ | 14,013  |  |  |  | 100     |   |      | $ | 11,401  |  |  |  | 100     | 
|                                   |  |                   |         |   |      |  |         |  |  |   |         |  |  |  |         |   |      |   |         |  |  |  |         | 



|(1) | The share price at December 31, 2011 was $20.19 (2010$23.84 and 2009$18.55).
|--- | ------------------------------------------------------------------------------

|(2) | Excludes the current portion of risk management, convertible debentures and share-based compensation liability.
|--- | ---------------------------------------------------------------------------------------------------------------

For 2011, we declared total dividends of $506 million or $1.08 per share (2010  trust distributions of $686 million or $1.56 per unit and 2009
 $841 million or $2.04 per unit) and paid total dividends, including amounts funded by the dividend reinvestment plan, of $420 million (2010  trust distributions of $708 million and 2009  $910 million). On February 15, 2012,
our Board of Directors declared a 2012 first quarter dividend of $0.27 per share to be paid on April 13, 2012 to shareholders of record on March 30, 2012. Shareholders are advised that this dividend is designated as an eligible
dividend for Canadian income tax purposes.

On June 27, 2011, the Company closed the extension of its unsecured, revolving,
syndicated bank facility with an aggregate borrowing limit of $2.25 billion and a four-year term. On October 27, 2011, the Company increased the aggregate borrowing limit by $500 million to $2.75 billion using the accordion feature
in the facility. For further details on its debt instruments, please refer to the Financing and Convertible Debentures sections of this MD&A.

We actively manage our debt portfolio and consider opportunities to reduce or diversify our debt structure. We actively consider operating and financial risks and take actions as appropriate to limit our
exposure to certain risks. We maintain close relationships with our lenders and agents to monitor credit market developments. These actions and plans aim to increase the likelihood of maintaining our financial flexibility to capture opportunities
available in the markets in addition to the continuation of our capital and dividend programs and hence the longer-term execution of our business strategies.

The Company has a number of covenants related to its syndicated bank facility and senior, unsecured notes. On December 31, 2011, the Company was in compliance with all of these financial covenants
which comprise the following:



|                              |  |               |  |                   |      |  
|----------------------------- |  | ------------- |  | ----------------- | ---- | -
|                              |  | Limit         |  | December 31, 2011 |     
|Senior debt to EBITDA(1)      |  | Less than 3:1 |  |                   | 1.86 |  
|Total debt to EBITDA(1)       |  | Less than 4:1 |  |                   | 1.86 |  
|Senior debt to capitalization |  | Less than 50% |  |                   | 26   | %
|Total debt to capitalization  |  | Less than 55% |  |                   | 26   | %



|(1) | EBITDA is calculated in accordance with Penn Wests lending agreements wherein unrealized risk management gains and losses and impairment provisions are excluded.
|--- | ------------------------------------------------------------------------------------------------------------------------------------------------------------------

As at December 31, 2011, all senior, unsecured notes contain change of control provisions whereby if a change of control
occurs, the Company may be required to offer to prepay the notes, which the holders have the right to refuse.

The amount of future cash
dividends may vary depending on a variety of factors and conditions which can include, but are not limited to, fluctuations in commodity markets, production levels and capital expenditure requirements. Our dividend level could change based on these
and other factors and is subject to the approval of our Board of Directors.



2011 ANNUAL
MANAGEMENTS DISCUSSION & ANALYSIS 18



---

Convertible Debentures

During 2011, $248 million of convertible debentures matured and were settled in cash (2010  nil), $7 million were redeemed and settled in cash (2010  nil) and none matured and were settled in
shares (2010  $18 million). Of the $255 million of convertible debentures settled in cash during 2011, $224 million were the series F debentures which matured in the fourth quarter of 2011. We now have no convertible debentures
outstanding.

Financial Instruments

We had the following financial instruments outstanding as at December 31, 2011. Fair values are determined using external counterparty information which is compared to observable market data. We
limit our credit risk by executing counterparty risk procedures which include transacting only with institutions within our credit facility or with high credit ratings and by obtaining financial security in certain circumstances.



|                                          |  |                 |  |                 |  |                         |  |                      |      |  
|----------------------------------------- |  | --------------- |  | --------------- |  | ----------------------- |  | -------------------- | ---- | -
|                                          |  | Notional volume |  | Remaining
term  |  | Pricing                 |  | Fair value(millions) |     
|Crude oil                                 |  |                 |  |                 |  |                         |  |                      |      |  
|WTI Collars                               |  | 60,000 bbls/d   |  | Jan/12  Dec/12 |  | US$85.53 to $101.16/bbl |  | $                    | (103 | )
|WTI Collars                               |  | 5,000 bbls/d    |  | Jan/13  Dec/13 |  | US$90.00 to $100.00/bbl |  |                      | (1   | )
|                                          |  |                 |  |                
|Natural gas                               |  |                 |  |                 |  |                         |  |                      |      |  
|AECO Forwards(1)                          |  | 52,730 GJ/d     |  | Jan/12  Dec/12 |  | $4.08/GJ                |  |                      | 25   |  
|                                          |  |                 |  |                
|Electricity swaps                         |  |                 |  |                 |  |                         |  |                      |      |  
|Alberta Power Pool                        |  | 45 MW           |  | Jan/12  Dec/12 |  | $53.02/MWh              |  |                      | 7    |  
|Alberta Power Pool                        |  | 30 MW           |  | Jan/12  Dec/13 |  | $54.60/MWh              |  |                      | 10   |  
|Alberta Power Pool                        |  | 20 MW           |  | Jan/13  Dec/13 |  | $56.10/MWh              |  |                      | 2    |  
|Alberta Power Pool                        |  | 50 MW           |  | Jan/14  Dec/14 |  | $58.50/MWh              |  |                      | 1    |  
|                                          |  |                 |  |                
|Interest rate swaps                       |  | $650            |  | Jan/12  Jan/14 |  | 2.65%                   |  |                      | (22  | )
|                                          |  |                 |  |                
|Foreign exchange forwards on revenues     |  |                 |  |                 |  |                         |  |                      |      |  
|12-month initial term                     |  | US$1,872        |  | Jan/12  Dec/12 |  | 1.022 CAD/USD           |  |                      | 2    |  
|                                          |  |                 |  |                
|Foreign exchange forwards on senior notes |  |                 |  |                 |  |                         |  |                      |      |  
|3 to 15-year initial term                 |  | US$641          |  | 2014  2022     |  | 1.000 CAD/USD           |  |                      | 20   |  
|                                          |  |                 |  |                
|Cross currency swaps                      |  |                 |  |                 |  |                         |  |                      |      |  
|10-year initial term                      |  | £57             |  | 2018            |  | 2.0075 CAD/GBP, 6.95%   |  |                      | (26  | )
|10-year initial term                      |  | £20             |  | 2019            |  | 1.8051 CAD/GBP, 9.15%   |  |                      | (5   | )
|10-year initial term                      |  | 10             |  | 2019            |  | 1.5870 CAD/EUR, 9.22%   |  |                      | (3   | )
|                                          |  |                 |  |                 |  |                         |  |                      |      |  
|Total                                     |  |                 |  |                 |  |                         |  | $                    | (93  | )
|                                          |  |                 |  |                 |  |                         |  |                      |      |  



|(1) | The forward contracts total approximately 50,000 mcf per day with an average price of $4.30 per mcf.
|--- | ----------------------------------------------------------------------------------------------------

Subsequent to December 31, 2011, we entered into additional crude oil collars on 30,000 barrels per day in 2013 between US$94.17 and US$109.23 per
barrel.

Please refer to our website at www.pennwest.com for details of all financial instruments currently outstanding.



2011 ANNUAL
MANAGEMENTS DISCUSSION & ANALYSIS 19



---

Outlook

This outlook section is included to provide shareholders with information about our expectations as at March 15, 2012 for production and capital expenditures for 2012 and readers are cautioned that
the information may not be appropriate for any other purpose. This information constitutes forward-looking information. Readers should note the assumptions, risks and discussion under Forward-Looking Statements.

Our production and capital guidance for 2012 remains unchanged. Taking into account net acquisition and disposition activity to date in 2012, our
forecast average production for 2012 is between 168,500 and 172,500 boe per day and our exploration and development capital, net of acquisition and disposition activity, is forecasted to be in the range of $1.3 billion to $1.4 billion. These ranges
are consistent with our prior forecasts for 2012 released with our third and fourth quarter 2011 results, reflecting acquisition and disposition activity to date in 2012, and filed on SEDAR at www.sedar.com.

Sensitivity Analysis

Estimated sensitivities
to selected key assumptions on reported financial results for the 12 months subsequent to this reporting period, including risk management contracts entered to date, are based on forecasted results as discussed in the Outlook above.



|                             |  |                      |  |            |    |  |         |  |      | 
|---------------------------- |  | -------------------- |  | ---------- | -- |  | ------- |  | ---- | 
|                             |  | Impact on funds flow | 
|Change of:                   |  | Change               |  | $ millions |    |  | $/share | 
|Price per barrel of liquids  |  | $1.00                |  |            | 32 |  |         |  | 0.07 | 
|Liquids production           |  | 1,000 bbls/day       |  |            | 22 |  |         |  | 0.05 | 
|Price per mcf of natural gas |  | $0.10                |  |            | 9  |  |         |  | 0.02 | 
|Natural gas production       |  | 10 mmcf/day          |  |            |   |  |         |  |     | 
|Effective interest rate      |  | 1%                   |  |            | 7  |  |         |  | 0.01 | 
|Exchange rate ($US per $CAD) |  | $0.01                |  |            | 19 |  |         |  | 0.04 | 
|                             |  |                      |  |            |    |  |         |  |      | 

Contractual Obligations and Commitments

We are committed to certain payments over the next five calendar years as follows:



|                             |  |      | $00,000 |  |      |   | $00,000 |      |  |   | $00,000 |  |  |      | $00,000 |  |            |   | $00,000 |  |  |   | $00,000 | 
|---------------------------- |  | ---- | ------- |  | ---- | - | ------- | ---- |  | - | ------- |  |  | ---- | ------- |  | ---------- | - | ------- |  |  | - | ------- | 
|(millions)                   |  | 2012 |         |  | 2013 |   |         | 2014 |  |   | 2015    |  |  | 2016 |         |  | Thereafter |  
|Long-term debt               |  | $    |        |  |      | $ | 5       |      |  | $ | 61      |  |  | $    | 1,504   |  |            | $ | 221     |  |  | $ | 1,428   | 
|Transportation               |  |      | 23      |  |      |   | 19      |      |  |   | 12      |  |  |      | 8       |  |            |   | 3       |  |  |   |        | 
|Transportation ($US)         |  |      | 4       |  |      |   | 4       |      |  |   | 37      |  |  |      | 37      |  |            |   | 33      |  |  |   | 231     | 
|Power infrastructure         |  |      | 32      |  |      |   | 15      |      |  |   | 15      |  |  |      | 15      |  |            |   | 15      |  |  |   | 14      | 
|Drilling rigs                |  |      | 26      |  |      |   | 26      |      |  |   | 22      |  |  |      | 16      |  |            |   | 10      |  |  |   | 2       | 
|Purchase obligations(1)      |  |      | 13      |  |      |   | 13      |      |  |   | 11      |  |  |      | 10      |  |            |   | 2       |  |  |   | 5       | 
|Interest obligations         |  |      | 161     |  |      |   | 161     |      |  |   | 158     |  |  |      | 127     |  |            |   | 93      |  |  |   | 216     | 
|Office lease(2)              |  |      | 68      |  |      |   | 66      |      |  |   | 60      |  |  |      | 60      |  |            |   | 59      |  |  |   | 479     | 
|Decommissioning liability(3) |  | $    | 70      |  |      | $ | 67      |      |  | $ | 64      |  |  | $    | 61      |  |            | $ | 58      |  |  | $ | 287     | 
|                             |  |      |         |  |      |   |         |      |  |   |         |  |  |      |         |  |            |   |         |  |  |   |         | 



|(1) | These amounts represent estimated commitments of $40 million for CO2purchases and $14 million for processing fees related to our interests in the Weyburn Unit.
|--- | ---------------------------------------------------------------------------------------------------------------------------------------------------------------

|(2) | The future office lease commitments above will be reduced by sublease recoveries totalling $434 million.
|--- | --------------------------------------------------------------------------------------------------------

|(3) | These amounts represent the inflated, discounted future reclamation and abandonment costs that are expected to be incurred over the life of the properties.
|--- | -----------------------------------------------------------------------------------------------------------------------------------------------------------

Our syndicated credit facility is due for renewal on June 26, 2015. If we are not successful in renewing or replacing the
facility, we could enter other loans including term bank loans or be required to repay all amounts then outstanding on the facility. In addition, we have an aggregate of $2.0 billion in senior notes maturing between 2014 and 2025. We continuously
monitor our credit metrics and maintain positive working relationships with our lenders, investors and agents.

Penn West is involved in
various litigation and claims in the normal course of business and records provisions for claims as required.



2011 ANNUAL
MANAGEMENTS DISCUSSION & ANALYSIS 20



---

Equity Instruments



|                                              |  |  |             |  
|--------------------------------------------- |  |  | ----------- | -
|Common shares issued:                         |  |  |             |  
|As at December 31, 2011                       |  |  | 471,372,730 |  
|Issued on exercise of share rights            |  |  | 162,988     |  
|Issued pursuant to dividend reinvestment plan |  |  | 1,364,540   |  
|                                              |  |  |             |  
|As at March 15, 2012                          |  |  | 472,900,258 |  
|                                              |  |  |             |  
|Options outstanding:                          |  |  |             |  
|As at December 31, 2011                       |  |  | 7,919,600   |  
|Granted                                       |  |  | 7,548,200   |  
|Forfeited                                     |  |  | (112,541    | )
|                                              |  |  |             |  
|As at March 15, 2012                          |  |  | 15,355,259  |  
|                                              |  |  |             |  
|Share Rights outstanding:                     |  |  |             |  
|As at December 31, 2011                       |  |  | 2,549,112   |  
|Exercised                                     |  |  | (155,841    | )
|Forfeited                                     |  |  | (104,283    | )
|                                              |  |  |             |  
|As at March 15, 2012                          |  |  | 2,288,988   |  
|                                              |  |  |             |  
|Restricted Options outstanding(1):            |  |  |             |  
|As at December 31, 2011                       |  |  | 17,110,193  |  
|Forfeited                                     |  |  | (3,916,374  | )
|                                              |  |  |             |  
|As at March 15, 2012                          |  |  | 13,193,819  |  
|                                              |  |  |             |  



|(1) | Each holder of a Restricted Option holds a Restricted Right and has the option to settle the Restricted Right in cash or common shares upon exercise. Refer to the
ExpensesShare-Based Compensation section of this MD&A for further details.
|--- | ------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



2011 ANNUAL
MANAGEMENTS DISCUSSION & ANALYSIS 21



---

Fourth Quarter 2011 Highlights

Key financial and operational results for the fourth quarter 2011 were as follows:



|                                               |  |                                |         |   |      |   |         |          |  |  |     |  
|---------------------------------------------- |  | ------------------------------ | ------- | - | ---- | - | ------- | -------- |  |  | --- | -
|                                               |  | Three months ended December 31 |        
|                                               |  | 2011                           |         |   | 2010 |   |         | % change | 
|Financial
(millions, except per share amounts) |  |                                |         |   |      |   |         |          |  |  |     |  
|Gross revenues(1)                              |  | $                              | 979     |   |      | $ | 782     |          |  |  | 25  |  
|Funds flow                                     |  |                                | 437     |   |      |   | 305     |          |  |  | 43  |  
|Basic per share                                |  |                                | 0.93    |   |      |   | 0.67    |          |  |  | 39  |  
|Diluted per share(2)                           |  |                                | 0.93    |   |      |   | 0.66    |          |  |  | 41  |  
|Net loss(2)                                    |  |                                | (62     | ) |      |   | (37     | )        |  |  | 68  |  
|Basic per share(2)                             |  |                                | (0.13   | ) |      |   | (0.08   | )        |  |  | 63  |  
|Diluted per share(2)                           |  |                                | (0.13   | ) |      |   | (0.08   | )        |  |  | 63  |  
|Capital expenditures, net(3)                   |  |                                | 583     |   |      |   | 469     |          |  |  | 24  |  
|Dividends paid(4)                              |  | $                              | 127     |   |      | $ | 123     |          |  |  | 3   |  
|                                               |  |                                |        
|Operations                                     |  |                                |         |   |      |   |         |          |  |  |     |  
|                                               |  |                                |        
|Daily production                               |  |                                |         |   |      |   |         |          |  |  |     |  
|Light oil and NGL (bbls/d)                     |  |                                | 90,185  |   |      |   | 88,447  |          |  |  | 2   |  
|Heavy oil (bbls/d)                             |  |                                | 17,886  |   |      |   | 16,849  |          |  |  | 6   |  
|Natural gas (mmcf/d)                           |  |                                | 364     |   |      |   | 365     |          |  |  |    |  
|                                               |  |                                |         |   |      |   |         |          |  |  |     |  
|Total production (boe/d)                       |  |                                | 168,801 |   |      |   | 166,148 |          |  |  | 2   |  
|                                               |  |                                |         |   |      |   |         |          |  |  |     |  
|                                               |  |                                |        
|Average sales price                            |  |                                |         |   |      |   |         |          |  |  |     |  
|Light oil and NGL (per bbl)                    |  | $                              | 88.76   |   |      | $ | 71.05   |          |  |  | 25  |  
|Heavy oil (per bbl)                            |  |                                | 76.88   |   |      |   | 61.87   |          |  |  | 24  |  
|Natural gas (per mcf)                          |  | $                              | 3.47    |   |      | $ | 3.79    |          |  |  | (8  | )
|                                               |  |                                |        
|Netback per boe                                |  |                                |         |   |      |   |         |          |  |  |     |  
|Sales price                                    |  | $                              | 63.05   |   |      | $ | 52.43   |          |  |  | 20  |  
|Risk management loss                           |  |                                | (0.84   | ) |      |   | (1.51   | )        |  |  | (44 | )
|                                               |  |                                |         |   |      |   |         |          |  |  |     |  
|Net sales price                                |  |                                | 62.21   |   |      |   | 50.92   |          |  |  | 22  |  
|Royalties                                      |  |                                | (11.47  | ) |      |   | (9.14   | )        |  |  | 25  |  
|Operating expenses                             |  |                                | (17.48  | ) |      |   | (15.92  | )        |  |  | 10  |  
|Transportation                                 |  |                                | (0.48   | ) |      |   | (0.52   | )        |  |  | (8  | )
|                                               |  |                                |         |   |      |   |         |          |  |  |     |  
|Netback                                        |  | $                              | 32.78   |   |      | $ | 25.34   |          |  |  | 29  |  
|                                               |  |                                |         |   |      |   |         |          |  |  |     |  



|(1) | Gross revenues include realized gains and losses on commodity contracts.
|--- | ------------------------------------------------------------------------

|(2) | Comparative figures have been revised to comply with IFRS.
|--- | ----------------------------------------------------------

|(3) | Excludes business combinations.
|--- | -------------------------------

|(4) | Includes dividends paid prior to those reinvested in shares under the dividend reinvestment plan. In 2011, we began paying dividends on a quarterly basis. The last
monthly distribution payment as a trust was declared in December 2010 and paid in January 2011 ($0.09 per unit). Our first quarterly dividend ($0.27 per share) as a corporation was paid in April 2011.
|--- | ----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------

Financial

Gross revenues increased in the
fourth quarter of 2011 compared to 2010 primarily due to an increase in our light-oil production and higher crude oil prices. This also contributed to an increase in funds flow in 2011 compared to 2010.

The increase in net loss in 2011 from the prior period was primarily due to unrealized risk management losses.

We continued our oil focused capital program during the fourth quarter of 2011 and drilled 108 net wells.



2011 ANNUAL
MANAGEMENTS DISCUSSION & ANALYSIS 22



---

Operations

Production in the fourth quarter of 2011 was 168,801 boe per day. We completed a successful capital program in the second half of 2011. We gained momentum in the third quarter after the fires and floods
reaching our full operating capacity in the fourth quarter. Average oil and liquids production was approximately 108,000 barrels per day in the fourth quarter of 2011, an increase of seven percent over the third quarter of 2011. To date in 2012, we
have closed property dispositions for proceeds of approximately $340 million.

During the fourth quarter of 2011, crude oil prices averaged
WTI US$94.02 per barrel compared to WTI US$89.81 per barrel in the third quarter of 2011 and WTI US$85.18 per barrel in the fourth quarter of 2010. In the fourth quarter of 2011, the AECO Monthly Index averaged $3.47 per mcf compared to $3.72 per
mcf in the third quarter of 2011 and $3.58 per mcf in the fourth quarter of 2010.

Netbacks were $32.78 per boe compared to $25.34 per boe in
the fourth quarter of 2010. The increase was primarily due to higher crude oil prices.

Disclosure Controls and Procedures

As of December 31, 2011, an internal evaluation was carried out under the supervision of our President and Chief Executive Officer (the
CEO) and Executive Vice President and Chief Financial Officer (the CFO) of the effectiveness of Penn Wests disclosure controls and procedures as defined in Rule 13a-15 under the US Securities Exchange Act of 1934 (the
Exchange Act) and as defined in Canada by National Instrument 52-109, Certification of Disclosure in Issuers Annual and Interim Filings (NI 52-109). Based on that evaluation, the CEO and the CFO concluded that as of
December 31, 2011 the disclosure controls and procedures were effective to provide reasonable assurance that the information required to be disclosed in the reports that Penn West files or submits under the Exchange Act or under Canadian
securities legislation is recorded, processed, summarized and reported, within the time periods specified in the rules and forms therein. Disclosure controls and procedures include, without limitation, controls and procedures designed to ensure that
the information required to be disclosed by Penn West in the reports that it files or submits under the Exchange Act or under Canadian securities legislation is accumulated and communicated to the Companys management, including the senior
executive and financial officers, as appropriate to allow timely decisions regarding the required disclosure.

Internal Control over
Financial Reporting (ICOFR)

We have a team of qualified and experienced staff who continue to maintain our compliance with the
applicable regulations regarding internal control over financial reporting (ICOFR). We became a registrant under the U.S. Securities Exchange Act of 1934 and listed our trust units on the New York Stock Exchange in June 2006. As of
December 31, 2011, an internal evaluation was carried out under the supervision of our CEO and CFO of the effectiveness of our ICOFR as defined in Rule 13a-15 under the Exchange Act and as defined in Canada by NI 52-109. The assessment was
based on the framework in Internal Control  Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission. Based on that evaluation, the CEO and the CFO concluded that as of December 31, 2011 our
ICOFR was effective. We have certified our ICOFR and obtained auditor attestation of the operating effectiveness of our internal control over financial reporting in conjunction with our 2011 year-end audited consolidated financial statements. All
significant financial reporting processes have been documented, assessed, and tested. No changes in our ICOFR were made during the quarter ended December 31, 2011 that have materially affected, or are reasonably likely to materially affect, our
ICOFR.



2011 ANNUAL
MANAGEMENTS DISCUSSION & ANALYSIS 23



---

Changes in accounting policies

Transition to IFRS

On January 1, 2011, we completed our changeover to IFRS, with a
transition date of January 1, 2010. On the transition date, we adjusted our account balances to IFRS and our financial reporting was changed to be in accordance with IFRS thereafter. A full description of our new accounting policies is outlined
in Note 3 to our audited consolidated financial statements. Additionally, transition date information and reconciliations between IFRS and previous GAAP for comparative periods in 2010 are described in Note 24 to our audited consolidated financial
statements. The transition to IFRS has not led to any changes in the business operations, capital strategies or funds flow of the Company.

Significant Accounting Differences and Accounting Policies

The following outlines significant accounting policy choices and differences between IFRS and previous GAAP applicable from the date of transition to IFRS on January 1, 2010. We operated in an income
trust structure from the date of transition until our conversion to a corporation on January 1, 2011.

Component accounting

Under IFRS, depletion and depreciation of property, plant and equipment (PP&E) is based on significant components. These
components consist of oil and natural gas assets, facilities, turnarounds and corporate assets.

Depletion and depreciation

Under previous GAAP, PP&E was generally depleted based on aggregations at the country level using the full cost method of accounting for oil and
natural gas activities. Depletion of resource properties and facilities will continue to be calculated using the unit-of-production method; however, under IFRS there is an option to use reserves volumes on a total proved or total proved plus
probable basis. We have elected to deplete resource properties using total proved plus probable reserves. Other assets, consisting of computer hardware and software, office furniture, buildings and leasehold improvements, will be depreciated on a
straight-line basis over their estimated useful lives.

E&E assets

Oil and natural gas properties are classified as either PP&E or E&E under IFRS. Under previous GAAP, oil and gas assets were classified only as PP&E. E&E assets consist of capital costs
related to prospective assets for which the technical and commercial viability of extracting oil and natural gas has not yet been ascertained. These assets are initially measured at cost and classified according to the nature of the associated
expenditures.

E&E costs are transferred to PP&E, to the extent they are not impaired, once their technical and commercial viability
is established which will generally be when proved reserves have been assigned to the asset. If proved reserves will not be established through the completion of E&E activities and there are no future plans for development activity, E&E
assets are assessed for impairment. Any impairment will be charged to income as E&E expense.

Impairment of oil and natural gas
properties

Under IFRS, impairment testing is performed at a lower level than under previous GAAP. As a consequence, impairment provisions
are more likely to occur as properties will no longer be tested at the country level. Under IFRS, unlike previous GAAP, impairments other than goodwill impairments may be reversed in the event future conditions change.



2011 ANNUAL
MANAGEMENTS DISCUSSION & ANALYSIS 24



---

Classification of trust units

Under previous GAAP, trust units were classified as equity instruments. Under IFRS, trust units carried a number of features that could result in either equity or liability treatment. Under IFRS
puttable financial instruments with characteristics similar to ordinary shares are treated as equity instruments. We concluded that the appropriate classification of our trust units was equity.

Share-based payments

Under previous
GAAP, share-based payments were classified as equity awards and were expensed using the straight-line method. Under IFRS, as an income trust, our equity awards met the definition of a puttable financial instrument, thus the awards were considered a
liability in 2010 and expensed on a graded vesting schedule.

Asset retirement obligations (ARO) or decommissioning liability

Under previous GAAP, ARO was recorded when there was a legal obligation to abandon an asset. Under IFRS, a decommissioning liability is
recorded when there is either a legal or constructive obligation to abandon an asset.

Future (deferred) income tax

While operating as an income trust subsequent to 2006, Penn West was considered a Specified Investment Flow-Through entity (a SIFT entity).
Under previous GAAP, income tax assets and liabilities at the trust level were measured at the enacted tax rate for SIFT entities of approximately 25 percent. Under IFRS, in the 2010 period preceding our conversion to a corporation we were required
to apply a tax rate of 39 percent, representing the rate applicable to undistributed profits of the Trust in the Province of Alberta.

IFRS
1Oil and Gas Exemption

In July 2009, the International Accounting Standards Board (IASB) issued amendments to IFRS 1
First-time adoption of IFRS allowing additional exemptions for first-time adopters. Under these amendments, oil and natural gas companies previously following the full cost method of accounting could elect to use the recorded amount
under a previous GAAP as the deemed cost for oil and gas assets on the transition date to IFRS. We elected to apply this exemption. For a further discussion on IFRS 1 exemptions, refer to Note 24 of our audited consolidated financial statements.

Future Accounting Pronouncements

In May 2011, the International Accounting Standards Board issued the following standards which are not yet effective:

IFRS 10 Consolidated Financial Statements outlines a new methodology to determine whether to consolidate an investee. This new standard becomes effective for annual periods beginning on or
after January 1, 2013. Penn West believes the adoption of this standard will have no material impact on its financial statements.

IFRS
11 Joint Arrangements outlines the accounting treatment for joint arrangements, notably joint operations which will follow the proportionate consolidation method and joint ventures which will follow the equity accounting method. This new
standard becomes effective for annual periods beginning on or after January 1, 2013 and will apply to Penn Wests interest in the Peace River Oil Partnership. Penn West currently believes that its interest in the Peace River Oil
Partnership is appropriately classified as a joint operation; therefore, it will continue to proportionately consolidate its interest in the Partnership upon adoption of this standard.

IFRS 12 Disclosure of Interests in Other Entities outlines disclosure requirements for interests in subsidiaries, joint arrangements, associates and unconsolidated structured entities. These
disclosure requirements are required for annual periods beginning on or after January 1, 2013. Penn West is currently assessing the impact of this standard.



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IFRS 13 Fair Value Measurement defines fair value, provides guidance on measuring fair value and
outlines disclosure requirements for fair value measurement. This standard applies when another IFRS standard requires fair value measurements or disclosures, with some exceptions including IFRS 2 Share based payments and IAS 17
Leases. This new standard is applicable for annual periods beginning on or after January 1, 2013. Penn West is currently assessing the impact of this standard.

IFRS impacts subsequent to our corporate conversion

Shareholders capital

Following the one-to-one exchange of trust units for common shares on January 1, 2011, Unitholders Capital was re-classified to
Shareholders Capital.

Elimination of the consolidated deficit

Upon commencement of operations as a corporation, pursuant to the Plan of Arrangement and a resolution of the Board of Directors, Penn Wests recorded deficit of $610 million was eliminated against
share capital on January 1, 2011.

Deferred Tax

Effective January 1, 2010, as an income trust, we were required to measure deferred income tax assets and liabilities at the trust level at a tax rate of 39 percent, representing the tax rate
applicable to undistributed profits of the trust in the Province of Alberta. Deferred income tax was recorded on this basis from January 1, 2010 until our conversion to a corporation on January 1, 2011. Under IFRS, upon conversion to a
corporation, the deferred income tax assets and liabilities were re-measured at the applicable corporate income tax rate of approximately 26 percent and the company recognized a $304 million deferred income tax recovery during the first quarter of
2011.

Share-based Compensation

Effective January 1, 2011, we implemented an Option Plan and amended our TURIP to become the CSRIP. Trust unit right holders had the choice to receive both a Restricted Option and a Restricted Right
for outstanding in-the-money trust unit rights or receive a Share Right under the CSRIP if they chose not to elect or had out-of-the-money trust unit rights. The elimination of the TURIP and subsequent implementation of the
Option Plan and CSRIP resulted in a $58 million net charge to income during the first quarter of 2011.

Related-Party Transactions

During 2011, we incurred $1 million (2010  $2 million) of legal fees from a law firm of which a partner is also a director of Penn
West.

Off-Balance-Sheet Financing

We have off-balance-sheet financing arrangements consisting of operating leases. The operating lease payments are summarized in the Contractual Obligations and Commitments section.

Critical Accounting Estimates

Our
significant accounting policies are detailed in Note 3 to the audited consolidated financial statements under IFRS. In the determination of financial results, we must make certain critical accounting estimates as follows:

Depletion and Impairments

Costs for
developing oil and natural gas reserves are capitalized and depleted against associated oil and natural gas production using the unit-of-production method based on the estimated proved plus probable reserves with forecast commodity pricing.



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All of our reserves were evaluated or audited by GLJ Petroleum Consultants Ltd. (GLJ) and
Sproule Associates Limited (SAL), both independent engineering firms. Our reserves are determined in compliance with National Instrument 51-101. The evaluation of oil and natural gas reserves is, by its nature, based on complex
extrapolations and models as well as other significant engineering, reservoir, capital, pricing and cost assumptions. Reserve estimates are a key component in the calculation of depletion and are a key component in determining the recoverable amount
in the impairment test. The determination of the recoverable amount involves estimating the higher of an assets fair value less costs to sell or its value-in-use, the latter of which is based on its discounted future cash flows using an
applicable discount rate. To the extent that the recoverable amount, which could be based in part on our reserves, is less than the carrying amount of property, plant and equipment, a write-down against income must be made. We determined there was
no impairment at December 31, 2011.

Decommissioning Liability

The discounted expected future cost of statutory, contractual, legal or constructive obligations to retire long-lived assets is recorded as a decommissioning liability with a corresponding increase to the
carrying amount of the related asset. The recorded liability increases over time to its future liability amount through accretion charges to income. Revisions to the estimated amount or timing of the obligations are reflected as increases or
decreases to the recorded decommissioning liability. Actual decommissioning expenditures are charged to the liability to the extent of the then-recorded liability. Amounts capitalized to the related assets are amortized to income consistent with the
depletion or depreciation of the underlying asset. Note 11 to the audited consolidated financial statements details the impact of these accounting standards.

Financial Instruments

Financial instruments included in the balance sheets consist of accounts
receivable, fair values of derivative financial instruments, current liabilities and long-term debt. Except for the senior notes, the fair values of these financial instruments approximate their carrying amounts due to the short-term maturity of the
instruments, the mark-to-market values recorded for the financial instruments and the market rate of interest applicable to the bank debt. The estimated fair value of the senior notes is disclosed in Note 10 to the audited consolidated financial
statements.

Our revenues from the sale of crude oil, natural gas liquids and natural gas are directly impacted by changes to the underlying
commodity prices. To ensure that funds flows are sufficient to fund planned capital programs and dividends, collars or other financial instruments may be utilized from time to time. Collars ensure that commodity prices realized will fall into a
contracted range for a contracted sales volume. Forward power contracts fix a portion of future electricity costs at levels determined to be economic by management.

Substantially all of our accounts receivable are with customers in the oil and natural gas industry and are subject to normal industry credit risk. We may, from time to time, use various types of
financial instruments to reduce our exposure to fluctuating oil and natural gas prices, electricity costs, exchange rates and interest rates. The use of these financial instruments exposes us to credit risks associated with the possible
non-performance of counterparties to the derivative contracts. We limit this risk by executing counterparty risk procedures which include transacting only with financial institutions who are members of our credit facility or those with high credit
ratings as well as obtaining security in certain circumstances.

Goodwill

Goodwill must be recorded on a business combination when the total purchase consideration exceeds the fair value of the net identifiable assets and liabilities of the acquired entity. The goodwill balance
is not amortized; however, it must be assessed for impairment at least annually. Penn West determined there was no goodwill impairment at December 31, 2011.



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Deferred Tax

Deferred taxes are recorded based on the liability method of accounting whereby temporary differences are calculated assuming financial assets and liabilities will be settled at their carrying amount.
Deferred taxes are computed on temporary differences using substantively enacted income tax rates expected to apply when future income tax assets and liabilities are realized or settled.

Forward-Looking Statements

In the interest of providing our securityholders and potential
investors with information regarding Penn West, including managements assessment of our future plans and operations, certain statements contained in this document constitute forward-looking statements or information (collectively
forward-looking statements) within the meaning of the safe harbour provisions of applicable securities legislation. Forward-looking statements are typically identified by words such as anticipate,
continue, estimate, expect, forecast, may, will, project, could, plan, intend, should, believe,
outlook, objective, aim, potential, target and similar words suggesting future events or future performance. In addition, statements relating to reserves or
resources are deemed to be forward-looking statements as they involve the implied assessment, based on certain estimates and assumptions, that the reserves and resources described exist in the quantities predicted or estimated and can be
profitably produced in the future.

In particular, this document contains forward-looking statements pertaining to, without limitation, the
following: certain disclosures contained under the headings Business Strategy and Outlook relating to, among other things, our continued focus in 2012 on light-oil plays and our further shift toward full-scale development
across portions of these plays; certain disclosures contained under the heading Business Strategy relating to, among other things, our continued application of horizontal multi-stage drilling technologies and pad drilling techniques, our
continued appraisal activities under the Peace River Oil Partnership and the Cordova Joint Venture, our intention to appraise and extend our portfolio of light-oil and liquids-rich gas plays at a less aggressive pace than in 2010 and 2011; forecasts
for modest global GDP growth in 2012 and the expected incremental demand for crude oil as a result thereof; our intention to continually allocate substantially all of our capital investments to oil projects; certain disclosures contained under the
heading Outlook relating to our estimated 2012 exploration and development capital program and our resulting production estimates for 2012; certain disclosures contained under the heading Natural Gas relating to, among other
things, our view of the outlook for natural gas prices and supply-demand fundamentals for such commodity; our forecast under the heading Taxes that, based on current commodity prices and capital spending plans, our tax pool base will
shelter our taxable income for an extended period; all matters relating to our dividend policy, including the factors that may affect the amount of dividends that we pay in the future (if any); the ability of our debt and risk management programs to
increase the likelihood that we can maintain our financial flexibility to capture opportunities available in the markets in addition to the continuation of our capital and dividend programs and the longer-term execution of our business strategies;
and certain disclosures contained under the heading Sensitivity Analysis relating to our estimated sensitivities to certain key assumptions on funds flow.

With respect to forward-looking statements contained in this document, we have made assumptions regarding, among other things: future crude oil, natural gas liquids and natural gas prices and
differentials between light, medium and heavy oil prices; future capital expenditure levels; future crude oil, natural gas liquids and natural gas production levels; drilling results; future exchange rates and interest rates; the amount of future
cash dividends that we intend to pay; our ability to obtain equipment in a timely manner to carry out development activities and the costs thereof; our ability to market our oil and natural gas successfully to current and new customers; the impact
of increasing competition; our ability to obtain financing on acceptable terms; and our ability to add production and reserves through our development and exploitation activities. In addition, many of the forward-looking statements contained in this
document are located proximate to assumptions that are specific to those forward-looking statements, and such assumptions should be taken into account when reading such forward-looking statements: see in particular the assumptions identified under
the headings Outlook and Sensitivity Analysis.

Although we believe that the expectations reflected in the
forward-looking statements contained in this document, and the assumptions on which such forward-looking statements are made, are reasonable,



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there can be no assurance that such expectations will prove to be correct. Readers are cautioned not to place undue reliance on forward-looking statements included in this document, as there can
be no assurance that the plans, intentions or expectations upon which the forward-looking statements are based will occur. By their nature, forward-looking statements involve numerous assumptions, known and unknown risks and uncertainties that
contribute to the possibility that the predictions, forecasts, projections and other forward-looking statements will not occur, which may cause our actual performance and financial results in future periods to differ materially from any estimates or
projections of future performance or results expressed or implied by such forward-looking statements. These risks and uncertainties include, among other things: the impact of weather conditions on seasonal demand and ability to execute capital
programs; risks inherent in oil and natural gas operations; uncertainties associated with estimating reserves and resources; competition for, among other things, capital, acquisitions of reserves, resources, undeveloped lands and skilled personnel;
incorrect assessments of the value of acquisitions, including the completed acquisitions discussed herein; geological, technical, drilling and processing problems; general economic conditions in Canada, the U.S. and globally; industry conditions,
including fluctuations in the price of oil and natural gas; royalties payable in respect of our oil and natural gas production and changes thereto; changes in government regulation of the oil and natural gas industry, including environmental
regulation; fluctuations in foreign exchange or interest rates; unanticipated operating events or environmental events that can reduce production or cause production to be shut-in or delayed, including wild fires and flooding; failure to obtain
industry partner and other third-party consents and approvals when required; stock market volatility and market valuations; OPECs ability to control production and balance global supply and demand of crude oil at desired price levels;
political uncertainty, including the risks of hostilities, in the petroleum producing regions of the world; the need to obtain required approvals from regulatory authorities from time to time; failure to realize the anticipated benefits of
dispositions, acquisitions, joint ventures and partnerships, including the completed dispositions, acquisitions, joint ventures and partnerships discussed herein; changes in tax and other laws that affect us and our securityholders; changes in
government royalty frameworks; uncertainty of obtaining required approvals for acquisitions and mergers; the potential failure of counterparties to honour their contractual obligations; and the other factors described in our public filings
(including our Annual Information Form) available in Canada at www.sedar.com and in the United States at www.sec.gov. Readers are cautioned that this list of risk factors should not be construed as exhaustive.

The forward-looking statements contained in this document speak only as of the date of this document. Except as expressly required by applicable
securities laws, we do not undertake any obligation to publicly update or revise any forward-looking statements, whether as a result of new information, future events or otherwise. The forward-looking statements contained in this document are
expressly qualified by this cautionary statement.

Additional Information

Additional information relating to Penn West including Penn Wests Annual Information Form, is available on SEDAR at www.sedar.com and on EDGAR at www.sec.gov.



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