Exhibit 99.2

MANAGEMENTS DISCUSSION AND ANALYSIS

For the year ended
December 31, 2012

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, 2012 and 2011. The date of this MD&A is March 13, 2013. All dollar amounts contained in this MD&A are expressed in millions of Canadian dollars unless noted otherwise.

For additional information, including our 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.

Please refer to our advisory 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.

Certain 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 within, 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 IFRS. Netback is the per unit of production amount of revenue less royalties, operating costs, transportation and realized risk management and
is used in capital allocation decisions and to economically rank projects. Return on equity is calculated by comparing net income to shareholders equity and is used to measure a rate of return on shareholders equity. Return on capital is
calculated using net income excluding financing charges compared to shareholders equity and long-term debt and is used as a measure to assess how well we employ the capital invested into the company.

Calculation of Funds Flow



|                                                |  |                        |       |   |      |   |       | 
|----------------------------------------------- |  | ---------------------- | ----- | - | ---- | - | ----- | 
|                                                |  | Year ended December 31 |      
|(millions, except per share amounts)            |  | 2012                   |       |   | 2011 |  
|Cash flow from operating activities             |  | $                      | 1,193 |   |      | $ | 1,407 | 
|Increase (decrease) in non-cash working capital |  |                        | (37   | ) |      |   | 49    | 
|Decommissioning expenditures                    |  |                        | 92    |   |      |   | 81    | 
|                                                |  |                        |       |   |      |   |       | 
|Funds flow                                      |  | $                      | 1,248 |   |      | $ | 1,537 | 
|                                                |  |                        |       |   |      |   |       | 
|Basic per share                                 |  | $                      | 2.62  |   |      | $ | 3.29  | 
|Diluted per share                               |  | $                      | 2.62  |   |      | $ | 3.29  | 
|                                                |  |                        |       |   |      |   |       | 



2012
MANAGEMENTS DISCUSSION & ANALYSIS 1



---

Annual Financial Summary



|                                     |  |                        |        |  |      |   |        |      |  |   |        |  
|------------------------------------ |  | ---------------------- | ------ |  | ---- | - | ------ | ---- |  | - | ------ | -
|                                     |  | Year ended December 31 |       
|(millions, except per share amounts) |  | 2012                   |        |  | 2011 |   |        | 2010 | 
|Gross revenues(1)                    |  | $                      | 3,283  |  |      | $ | 3,604  |      |  | $ | 3,034  |  
|Funds flow                           |  |                        | 1,248  |  |      |   | 1,537  |      |  |   | 1,185  |  
|Basic per share                      |  |                        | 2.62   |  |      |   | 3.29   |      |  |   | 2.68   |  
|Diluted per share                    |  |                        | 2.62   |  |      |   | 3.29   |      |  |   | 2.65   |  
|Net income                           |  |                        | 174    |  |      |   | 638    |      |  |   | 1,110  |  
|Basic per share                      |  |                        | 0.37   |  |      |   | 1.37   |      |  |   | 2.51   |  
|Diluted per share                    |  |                        | 0.37   |  |      |   | 1.36   |      |  |   | 2.48   |  
|Capital expenditures, net(2)         |  |                        | 137    |  |      |   | 1,580  |      |  |   | (119   | )
|Long-term debt at year-end           |  |                        | 2,690  |  |      |   | 3,219  |      |  |   | 2,496  |  
|Convertible debentures               |  |                        |       |  |      |   |       |      |  |   | 255    |  
|Dividends/ distributions paid(3)     |  |                        | 512    |  |      |   | 420    |      |  |   | 708    |  
|Total assets                         |  | $                      | 14,491 |  |      | $ | 15,584 |      |  | $ | 14,543 |  



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

|(2) | Excludes business combinations.
|--- | -------------------------------

|(3) | Includes dividends paid and reinvested in shares under the dividend reinvestment plan.
|--- | --------------------------------------------------------------------------------------

2012 Highlights



| |  |  | Funds flow for 2012 was $1,248 million ($2.62 per share  basic) compared to $1,537 million ($3.29 per share  basic) in 2011. The decline in
funds flow was primarily attributed to lower commodity price realizations from wider Canadian crude oil differentials and lower natural gas prices.
| | - |  | -------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



| |  |  | Net income for 2012 was $174 million ($0.37 per share  basic); a decrease from the $638 million ($1.37 per share  basic) in 2011. Net
income was lower in 2012 primarily due to lower revenues related to lower commodity price realizations, an impairment charge on certain of our natural gas assets as a result of lower natural gas prices, partially offset by gains on asset
dispositions, and gains from risk management items. Results for 2011 included a one-time deferred tax recovery of $304 million as a result of our conversion to a corporation.
| | - |  | --------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



| |  |  | Annual 2012 production of 161,195 boe per day was within our previous guidance, compared to 163,094 boe per day for 2011. Production in 2012 was
weighted approximately 65 percent to oil and liquids compared to 63 percent in 2011.
| | - |  | -------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



| |  |  | Total net capital expenditures in 2012 of $137 million compared to $1,866 million in 2011 were within our previous guidance of $1.3 to $1.4 billion net
of divestments closed to the end of the third quarter.
| | - |  | --------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



| |  |  | In 2012, we closed net dispositions of $1,615 million with average production of approximately 16,500 boe per day.
| | - |  | ------------------------------------------------------------------------------------------------------------------



| |  |  | Netback was $26.58 per boe compared to $30.95 per boe in 2011, due primarily to a decline in commodity price realizations.
| | - |  | --------------------------------------------------------------------------------------------------------------------------



2012
MANAGEMENTS DISCUSSION & ANALYSIS 2



---

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   |  | 2012    |         |   | 2012    |   |         | 2012    |  |   | 2012    |  |  | 2011    |         |  | 2011    |   |         | 2011    |  |   | 2011    | 
|Gross revenues(1)    |  | $       | 799     |   |         | $ | 840     |         |  | $ | 774     |  |  | $       | 870     |  |         | $ | 979     |         |  | $ | 861     |  |  | $ | 920     |  |  | $ | 844     | 
|Funds flow           |  |         | 295     |   |         |   | 344     |         |  |   | 272     |  |  |         | 337     |  |         |   | 437     |         |  |   | 348     |  |  |   | 396     |  |  |   | 356     | 
|Basic per share      |  |         | 0.62    |   |         |   | 0.72    |         |  |   | 0.57    |  |  |         | 0.71    |  |         |   | 0.93    |         |  |   | 0.74    |  |  |   | 0.85    |  |  |   | 0.77    | 
|Diluted per share    |  |         | 0.62    |   |         |   | 0.72    |         |  |   | 0.57    |  |  |         | 0.71    |  |         |   | 0.93    |         |  |   | 0.74    |  |  |   | 0.85    |  |  |   | 0.77    | 
|Net income (loss)    |  |         | (53     | ) |         |   | (67     | )       |  |   | 235     |  |  |         | 59      |  |         |   | (62     | )       |  |   | 138     |  |  |   | 271     |  |  |   | 291     | 
|Basic per share      |  |         | (0.11   | ) |         |   | (0.14   | )       |  |   | 0.50    |  |  |         | 0.12    |  |         |   | (0.13   | )       |  |   | 0.29    |  |  |   | 0.58    |  |  |   | 0.63    | 
|Diluted per share    |  |         | (0.11   | ) |         |   | (0.14   | )       |  |   | 0.50    |  |  |         | 0.12    |  |         |   | (0.13   | )       |  |   | 0.29    |  |  |   | 0.58    |  |  |   | 0.63    | 
|Dividends declared   |  |         | 129     |   |         |   | 129     |         |  |   | 128     |  |  |         | 128     |  |         |   | 127     |         |  |   | 127     |  |  |   | 127     |  |  |   | 125     | 
|Per share            |  | $       | 0.27    |   |         | $ | 0.27    |         |  | $ | 0.27    |  |  | $       | 0.27    |  |         | $ | 0.27    |         |  | $ | 0.27    |  |  | $ | 0.27    |  |  | $ | 0.27    | 
|Production           |  |         |         |   |         |   |         |         |  |   |         |  |  |         |         |  |         |   |         |         |  |   |         |  |  |   |         |  |  |   |         | 
|Liquids (bbls/d)(2)  |  |         | 99,071  |   |         |   | 105,588 |         |  |   | 104,758 |  |  |         | 107,199 |  |         |   | 108,071 |         |  |   | 101,392 |  |  |   | 98,998  |  |  |   | 104,349 | 
|Natural gas (mmcf/d) |  |         | 329     |   |         |   | 329     |         |  |   | 351     |  |  |         | 361     |  |         |   | 364     |         |  |   | 360     |  |  |   | 343     |  |  |   | 371     | 
|                     |  |         |         |   |         |   |         |         |  |   |         |  |  |         |         |  |         |   |         |         |  |   |         |  |  |   |         |  |  |   |         | 
|Total (boe/d)        |  |         | 153,931 |   |         |   | 160,339 |         |  |   | 163,181 |  |  |         | 167,420 |  |         |   | 168,801 |         |  |   | 161,323 |  |  |   | 156,107 |  |  |   | 166,135 | 
|                     |  |         |         |   |         |   |         |         |  |   |         |  |  |         |         |  |         |   |         |         |  |   |         |  |  |   |         |  |  |   |         | 



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

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

Business Strategy

Over the past several
years, we have focused our capital activities to appraise the application of horizontal multi-stage fracture technology across our light-oil plays in Western Canada. These efforts have resulted in a significant inventory of light-oil targets. We
completed these appraisal activities while providing a meaningful dividend to our shareholders. As we enter 2013, we remain committed to providing a dividend as we shift our focus to improving capital efficiencies and production reliability. Our
2013 capital budget is set at $900 million with the possibility of an additional $300 million depending on external market factors and internal performance. Our business strategy remains centered on realizing the value inherent in our extensive
light-oil weighted asset base for the benefit of our shareholders.

Business Environment

Average 2012 benchmark crude oil prices remained range bound with WTI averaging US$94.17 per barrel compared to US$95.14 per barrel in 2011 and Brent
averaging US$111.64 per barrel compared to US$111.11 per barrel in 2011. Ongoing issues in the Middle East and Africa, notably in Syria, Libya and Iran, led to future supply concerns and supported an upward movement in crude oil prices. These
geopolitical issues were more than offset by Europes sovereign debt concerns, U.S. fiscal cliff risks and uncertainty regarding Chinas economic growth rate.

Canadian oil price realizations were more volatile in 2012 than in recent history. Extended refinery turnarounds combined with North American production increases from plays such as the Canadian oil sands
and the U.S. Bakken and Eagle Ford shale plays put pressure on North American oil infrastructure. The delay in the U.S. approval of the Keystone XL pipeline in January 2012 contributed to a risk averse tone in crude oil markets. In 2012, Edmonton
light sweet crude averaged, on a monthly basis, between a US$20.02 discount per barrel and a US$3.61 premium per barrel compared to WTI, reaching its widest discount in March 2012. The benchmark Canadian heavy oil stream, Western Canadian Select
(WCS), traded in the range of US$9.74 to US$32.98 per barrel less than WTI in 2012.



2012
MANAGEMENTS DISCUSSION & ANALYSIS 3



---

To date in 2013, the economic climate in Europe and Asia has shown signs of improvement and the U.S. has
taken steps toward resolving its fiscal and budgetary problems. Geo-political concerns related to Syria and Iran persist and are expected to provide support to world oil prices in 2013. The Seaway project, which added 400,000 barrels per day of oil
pipeline capacity from Cushing, Oklahoma to the U.S. Gulf Coast, came on stream in early 2013. Numerous other North American pipeline additions and expansions have been proposed to debottleneck North American oil. Many of these projects could be
subject to environmental or other regulatory delays. The use of rail to deliver crude oil to markets has grown considerably, particularly in the U.S. Bakken play. In the first two months of 2013, WTI averaged approximately US$95.07 per barrel and
Edmonton light sweet averaged $87.92 per barrel.

Despite lower drilling activity directed towards natural gas, production levels in the U.S.
remained flat in 2012. This was attributed to associated gas production from high drilling levels for oil and natural gas liquids. On the demand side, last winter was one of the warmest on record which resulted in the highest end of the season
natural gas inventory levels in history. This combination of high production and high inventory levels drove AECO day prices to an average low of $1.64 per mcf for the month of May. U.S. natural gas prices similarly declined to levels below coal on
a BTU equivalent basis prompting some conversion in the power generation sector from coal to natural gas. The summer of 2012 was significantly warmer than average, further increasing natural gas demand for power generation which lowered inventory
levels by the end of the summer compared to 2011. In late 2012, natural gas and coal equivalent prices were similar and the natural gas share of the power generation market ended close to pre-2012 levels. The AECO monthly price ended 2012 well off
its lows for the year at $3.43 per mcf.

Crude Oil

Our average crude oil and liquids price for 2012, before the impact of the realized portion of risk management, was $74.91 per barrel (2011  $83.22 per barrel). Currently, we have WTI collars on
55,000 barrels per day of our 2013 crude oil production between US$91.55 and US$104.42 per barrel.

Natural Gas

In 2012, the AECO Monthly Index averaged $2.40 per mcf compared to $3.67 per mcf in 2011. AECO monthly gas prices hit a low of $1.64 per mcf in May as
inventory levels in North America reached historical highs.

Our corporate average natural gas price for 2012 before the impact of the
realized portion of risk management was $2.45 per mcf (2011  $3.78 per mcf). Currently, we have 125,000 mcf per day of natural gas production hedged for 2013 at an average price of $3.34 per mcf at AECO. We also have 25,000 mcf of natural gas
production hedged for 2014 at an average price of $3.85 per mcf and an additional 50,000 mcf per day hedged through the use of collars with a floor of $3.41 per mcf and a ceiling of $4.18 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, financial stewardship and the overall goal
of creating competitive return on investment for our shareholders.
| | - |  | ---------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



2012
MANAGEMENTS DISCUSSION & ANALYSIS 4



---

Finding and Development costs



|                                                                 |  |                        |       |  |      |   |       |      |  |   |               |  |  |   |       | 
|---------------------------------------------------------------- |  | ---------------------- | ----- |  | ---- | - | ----- | ---- |  | - | ------------- |  |  | - | ----- | 
|                                                                 |  | Year ended December 31 |      
|                                                                 |  | 2012                   |       |  | 2011 |   |       | 2010 |  |   | 3-Yearaverage | 
|Adjusted F&D costs including future development costs (FDC)(1) |  |                        |       |  |      |   |       |      |  |   |               |  |  |   |       | 
|F&D costs per boe  proved plus probable                         |  | $                      | 23.12 |  |      | $ | 23.96 |      |  | $ | 23.39         |  |  | $ | 23.54 | 
|F&D costs per boe  proved                                       |  | $                      | 26.91 |  |      | $ | 31.69 |      |  | $ | 25.25         |  |  | $ | 28.43 | 
|Excluding FDC(2)                                                 |  |                        |       |  |      |   |       |      |  |   |               |  |  |   |       | 
|F&D costs per boe  proved plus probable                         |  | $                      | 17.48 |  |      | $ | 15.07 |      |  | $ | 18.90         |  |  | $ | 16.76 | 
|F&D costs per boe  proved                                       |  | $                      | 26.69 |  |      | $ | 23.55 |      |  | $ | 21.50         |  |  | $ | 24.02 | 
|Including FDC(3)                                                 |  |                        |       |  |      |   |       |      |  |   |               |  |  |   |       | 
|F&D costs per boe  proved plus probable                         |  | $                      | 25.50 |  |      | $ | 26.79 |      |  | $ | 26.73         |  |  | $ | 26.32 | 
|F&D costs per boe  proved                                       |  | $                      | 30.96 |  |      | $ | 37.05 |      |  | $ | 28.01         |  |  | $ | 32.60 | 



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

|(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.
|--- | ------------------------------------------------------------------------------------------------------------

Our proved reserves continue to reflect a high percentage of developed reserves. Of total proved reserves, 78 percent were developed at December 31,
2012 (2011  80 percent). At December 31, 2012, total proved reserves as a percentage of proved plus probable reserves were 66 percent (2011  69 percent). On a proved plus probable basis our reserves continued to be weighted 71
percent to crude oil and liquids (2011  71 percent) and 29 percent to natural gas (2011  29 percent). Our successful tight-oil development activities and the application of techniques including waterflood and Enhanced Oil Recovery offset
2012 reserve dispositions which were predominately weighted towards oil. Economic revisions were primarily due to lower natural gas prices on base assets.

Capital expenditures for 2012 have been reduced by $137 million related to joint venture carried capital (2011  $107 million). We use Adjusted F&D to assess the economic viability of our oil
development programs. F&D costs are calculated in accordance with NI 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

During 2012, we continued to consolidate our asset base and complete infrastructure development as we move through the development phase on
many of our key light-oil plays. Our appraisal activities over the past few years have provided us with a significant inventory of light-oil targets. Our 2013 capital program is focused on improving capital efficiencies by allocating capital to
areas we have significantly de-risked, where we have realized cost reductions and where we have infrastructure capacity.



2012
MANAGEMENTS DISCUSSION & ANALYSIS 5



---

Shareholder Value Measures



|                                                       |  |                        |       |  |      |   |       |      |  |   |       | 
|------------------------------------------------------ |  | ---------------------- | ----- |  | ---- | - | ----- | ---- |  | - | ----- | 
|                                                       |  | Year ended December 31 |      
|                                                       |  | 2012                   |       |  | 2011 |   |       | 2010 | 
|Funds flow per share                                   |  | $                      | 2.62  |  |      | $ | 3.29  |      |  | $ | 2.68  | 
|Dividends/ distributions paid per share                |  | $                      | 1.08  |  |      | $ | 0.90  |      |  | $ | 1.62  | 
|Ratio of year-end total long-term debt to annual funds |  |                        | 2.2:1 |  |      |   | 2.1:1 |      |  |   | 2.1:1 | 

In April 2011, subsequent to converting to a corporation in January 2011, we began paying a quarterly dividend of $0.27
per share, which continued throughout 2012. Our last monthly distribution payment of $0.09 per unit as a trust was declared in December 2010 and paid in January 2011. In 2013, we plan to continue the rotation of our asset portfolio through the
disposition of non-core properties and investment in our light-oil resources. We believe these strategies achieve a balance that provides our shareholders with a meaningful dividend as we continue to concentrate our asset base for oil growth.

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



|                        |  |                        |        |   |      |   |        |      |  |   |        |  
|----------------------- |  | ---------------------- | ------ | - | ---- | - | ------ | ---- |  | - | ------ | -
|                        |  | Year ended December 31 |       
|                        |  | 2012                   |        |   | 2011 |   |        | 2010 | 
|Return on capital(1)    |  |                        | 3      | % |      |   | 7      | %    |  |   | 11     | %
|Return on equity(2)     |  |                        | 2      | % |      |   | 7      | %    |  |   | 13     | %
|Total assets (millions) |  | $                      | 14,491 |   |      | $ | 15,584 |      |  | $ | 14,543 |  



|(1) | Net income before financing charges divided by average shareholders equity and average total debt.
|--- | ---------------------------------------------------------------------------------------------------

|(2) | Net income divided by average shareholders equity.
|--- | ---------------------------------------------------

The return on capital and return on equity ratios in 2012 and 2011 decreased as a result of lower net income. Net income was lower in 2012 primarily due to lower revenues related to lower commodity price
realizations, an impairment charge on certain of our natural gas assets as a result of lower natural gas prices, partially offset by gains on asset dispositions, and gains from risk management items. Results for 2011 included a one-time income tax
recovery of $304 million as a result of our conversion to a corporation. In 2010, we recorded significant gains on the formation of the Peace River Oil Partnership and the Cordova Joint Venture.



2012
MANAGEMENTS DISCUSSION & ANALYSIS 6



---

RESULTS OF OPERATIONS

Production



|                           |  |                        |         |  |      |  |         |          |  |  |    |  
|-------------------------- |  | ---------------------- | ------- |  | ---- |  | ------- | -------- |  |  | -- | -
|                           |  | Year ended December 31 |        
|Daily production           |  | 2012                   |         |  | 2011 |  |         | % change | 
|Light oil and NGL (bbls/d) |  |                        | 86,783  |  |      |  | 85,316  |          |  |  | 2  |  
|Heavy oil (bbls/d)         |  |                        | 17,361  |  |      |  | 17,892  |          |  |  | (3 | )
|Natural gas (mmcf/d)       |  |                        | 342     |  |      |  | 359     |          |  |  | (5 | )
|                           |  |                        |         |  |      |  |         |          |  |  |    |  
|Total production (boe/d)   |  |                        | 161,195 |  |      |  | 163,094 |          |  |  | (1 | )
|                           |  |                        |         |  |      |  |         |          |  |  |    |  

In 2012, we completed net property dispositions with combined production of approximately 16,500 boe per day, primarily
weighted to oil. Our increase in light-oil production is the result of focusing our activities on light-oil plays, while our natural gas production declined in 2012 as a result of this strategy.

After the disposition of properties producing approximately 13,000 boe per day for approximately $1.3 billion during the fourth quarter of 2012, liquids
production was approximately 62 percent of our production base exiting 2012. In 2013, we will continue to focus our capital activity on light-oil which should increase our weighting to liquids. Excluding the impact of net property dispositions,
liquids production increased by approximately five percent from 2011.

When economic to do so, we strive to maintain an appropriate 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 and our significant inventory of light-oil locations, we currently plan to continue
allocating substantially all of our capital investments to oil-weighted projects.

Average Sales Prices



|                                         |  |                        |       |  |      |   |       |          |  |  |     |  
|---------------------------------------- |  | ---------------------- | ----- |  | ---- | - | ----- | -------- |  |  | --- | -
|                                         |  | Year ended December 31 |      
|                                         |  | 2012                   |       |  | 2011 |   |       | % change | 
|Light oil and liquids (per bbl)          |  | $                      | 77.16 |  |      | $ | 86.19 |          |  |  | (10 | )
|Risk management gain (loss) (per bbl)(1) |  |                        | 0.17  |  |      |   | (2.03 | )        |  |  | 100 |  
|                                         |  |                        |       |  |      |   |       |          |  |  |     |  
|Light oil and liquids net (per bbl)      |  |                        | 77.33 |  |      |   | 84.16 |          |  |  | (8  | )
|                                         |  |                        |       |  |      |   |       |          |  |  |     |  
|                                         |  |                        |      
|Heavy oil (per bbl)                      |  |                        | 63.67 |  |      |   | 69.07 |          |  |  | (8  | )
|                                         |  |                        |      
|Natural gas (per mcf)                    |  |                        | 2.45  |  |      |   | 3.78  |          |  |  | (35 | )
|Risk management gain (per mcf)(1)        |  |                        | 0.34  |  |      |   |      |          |  |  | 100 |  
|                                         |  |                        |       |  |      |   |       |          |  |  |     |  
|Natural gas net (per mcf)                |  |                        | 2.79  |  |      |   | 3.78  |          |  |  | (26 | )
|                                         |  |                        |       |  |      |   |       |          |  |  |     |  
|                                         |  |                        |      
|Weighted average (per boe)               |  |                        | 53.60 |  |      |   | 60.99 |          |  |  | (12 | )
|Risk management gain (loss) (per boe)(1) |  |                        | 0.81  |  |      |   | (1.06 | )        |  |  | 100 |  
|                                         |  |                        |       |  |      |   |       |          |  |  |     |  
|Weighted average net (per boe)           |  | $                      | 54.41 |  |      | $ | 59.93 |          |  |  | (9  | )
|                                         |  |                        |       |  |      |   |       |          |  |  |     |  



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



2012
MANAGEMENTS DISCUSSION & ANALYSIS 7



---

Netbacks



|                               |  |                        |         |   |      |   |         |          |  |  |     |  
|------------------------------ |  | ---------------------- | ------- | - | ---- | - | ------- | -------- |  |  | --- | -
|                               |  | Year ended December 31 |        
|                               |  | 2012                   |         |   | 2011 |   |         | % change | 
|Light oil and NGL (1, 2)       |  |                        |         |   |      |   |         |          |  |  |     |  
|Production (bbls/day)          |  |                        | 86,783  |   |      |   | 85,316  |          |  |  | 2   |  
|Operating netback (per bbl):   |  |                        |         |   |      |   |         |          |  |  |     |  
|Sales price                    |  | $                      | 77.16   |   |      | $ | 86.19   |          |  |  | (10 | )
|Risk management gain (loss)(3) |  |                        | 0.17    |   |      |   | (2.03   | )        |  |  | 100 |  
|Royalties                      |  |                        | (15.57  | ) |      |   | (16.83  | )        |  |  | (8  | )
|Operating costs                |  |                        | (19.86  | ) |      |   | (21.05  | )        |  |  | (6  | )
|                               |  |                        |         |   |      |   |         |          |  |  |     |  
|Netback                        |  | $                      | 41.90   |   |      | $ | 46.28   |          |  |  | (10 | )
|                               |  |                        |         |   |      |   |         |          |  |  |     |  
|Heavy oil                      |  |                        |         |   |      |   |         |          |  |  |     |  
|Production (bbls/day)          |  |                        | 17,361  |   |      |   | 17,892  |          |  |  | (3  | )
|Operating netback (per bbl):   |  |                        |         |   |      |   |         |          |  |  |     |  
|Sales price                    |  | $                      | 63.67   |   |      | $ | 69.07   |          |  |  | (8  | )
|Royalties                      |  |                        | (9.01   | ) |      |   | (10.01  | )        |  |  | (10 | )
|Operating costs                |  |                        | (19.32  | ) |      |   | (17.53  | )        |  |  | 10  |  
|Transportation                 |  |                        | (0.07   | ) |      |   | (0.08   | )        |  |  | (13 | )
|                               |  |                        |         |   |      |   |         |          |  |  |     |  
|Netback                        |  | $                      | 35.27   |   |      | $ | 41.45   |          |  |  | (15 | )
|                               |  |                        |         |   |      |   |         |          |  |  |     |  
|Total liquids                  |  |                        |         |   |      |   |         |          |  |  |     |  
|Production (bbls/day)          |  |                        | 104,144 |   |      |   | 103,208 |          |  |  | 1   |  
|Operating netback (per bbl):   |  |                        |         |   |      |   |         |          |  |  |     |  
|Sales price                    |  | $                      | 74.91   |   |      | $ | 83.22   |          |  |  | (10 | )
|Risk management gain (loss)(3) |  |                        | 0.14    |   |      |   | (1.68   | )        |  |  | 100 |  
|Royalties                      |  |                        | (14.48  | ) |      |   | (15.64  | )        |  |  | (7  | )
|Operating costs                |  |                        | (19.77  | ) |      |   | (20.44  | )        |  |  | (3  | )
|Transportation                 |  |                        | (0.01   | ) |      |   | (0.01   | )        |  |  |    |  
|                               |  |                        |         |   |      |   |         |          |  |  |     |  
|Netback                        |  | $                      | 40.79   |   |      | $ | 45.45   |          |  |  | (10 | )
|                               |  |                        |         |   |      |   |         |          |  |  |     |  
|Natural gas                    |  |                        |         |   |      |   |         |          |  |  |     |  
|Production (mmcf/day)          |  |                        | 342     |   |      |   | 359     |          |  |  | (5  | )
|Operating netback (per mcf):   |  |                        |         |   |      |   |         |          |  |  |     |  
|Sales price                    |  | $                      | 2.45    |   |      | $ | 3.78    |          |  |  | (35 | )
|Risk management gain(3)        |  |                        | 0.34    |   |      |   |        |          |  |  | 100 |  
|Royalties                      |  |                        | (0.34   | ) |      |   | (0.54   | )        |  |  | (37 | )
|Operating costs                |  |                        | (2.11   | ) |      |   | (2.03   | )        |  |  | 4   |  
|Transportation                 |  |                        | (0.23   | ) |      |   | (0.22   | )        |  |  | 5   |  
|                               |  |                        |         |   |      |   |         |          |  |  |     |  
|Netback                        |  | $                      | 0.11    |   |      | $ | 0.99    |          |  |  | (89 | )
|                               |  |                        |         |   |      |   |         |          |  |  |     |  
|Combined totals                |  |                        |         |   |      |   |         |          |  |  |     |  
|Production (boe/day)           |  |                        | 161,195 |   |      |   | 163,094 |          |  |  | (1  | )
|Operating netback (per boe):   |  |                        |         |   |      |   |         |          |  |  |     |  
|Sales price                    |  | $                      | 53.60   |   |      | $ | 60.99   |          |  |  | (12 | )
|Risk management gain (loss)(3) |  |                        | 0.81    |   |      |   | (1.06   | )        |  |  | 100 |  
|Royalties                      |  |                        | (10.07  | ) |      |   | (11.09  | )        |  |  | (9  | )
|Operating costs                |  |                        | (17.26  | ) |      |   | (17.40  | )        |  |  | (1  | )
|Transportation                 |  |                        | (0.50   | ) |      |   | (0.49   | )        |  |  | 2   |  
|                               |  |                        |         |   |      |   |         |          |  |  |     |  
|Netback                        |  | $                      | 26.58   |   |      | $ | 30.95   |          |  |  | (14 | )
|                               |  |                        |         |   |      |   |         |          |  |  |     |  



|(1) | Excluded from the netback calculation is $72 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) | Included in the netback calculation is $48 million realized on the rearrangement of our 2013 oil collars which closed in the third quarter of 2012.
|--- | ---------------------------------------------------------------------------------------------------------------------------------------------------

|(3) | Gross revenues include realized gains and losses on commodity contracts.
|--- | ------------------------------------------------------------------------



2012
MANAGEMENTS DISCUSSION & ANALYSIS 8



---

Production Revenues

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



|                  |  |                        |       |  |      |   |       |      |  |   |       | 
|----------------- |  | ---------------------- | ----- |  | ---- | - | ----- | ---- |  | - | ----- | 
|                  |  | Year ended December 31 |      
|(millions)        |  | 2012                   |       |  | 2011 |   |       | 2010 | 
|Light oil and NGL |  | $                      | 2,529 |  |      | $ | 2,657 |      |  | $ | 1,965 | 
|Heavy oil         |  |                        | 405   |  |      |   | 452   |      |  |   | 405   | 
|Natural gas       |  |                        | 349   |  |      |   | 495   |      |  |   | 664   | 
|                  |  |                        |       |  |      |   |       |      |  |   |       | 
|Gross revenues(1) |  | $                      | 3,283 |  |      | $ | 3,604 |      |  | $ | 3,034 | 
|                  |  |                        |       |  |      |   |       |      |  |   |       | 



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

Lower commodity price realizations in 2012, partially offset by an increase in liquids production, resulted in a decline in liquids revenue from 2011. Natural gas revenues were affected by lower
production, due to our focus on light oil, and a significant decline in natural gas prices.

Crude oil prices increased in 2011 from 2010
which led to increases in both light and heavy-oil revenues. Also, contributing to the increase in light-oil revenues was higher light-oil production. 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.

Reconciliation of Decrease in Production Revenues



|                                                                          |  |   |       |  
|------------------------------------------------------------------------- |  | - | ----- | -
|(millions)                                                                |  |   |      
|Gross revenues  January 1  December 31, 2011                            |  | $ | 3,604 |  
|Increase in light oil and NGL production                                  |  |   | 53    |  
|Decrease in light oil and NGL prices (including realized risk management) |  |   | (181  | )
|Decrease in heavy oil production                                          |  |   | (12   | )
|Decrease in heavy oil prices                                              |  |   | (35   | )
|Decrease in natural gas production                                        |  |   | (23   | )
|Decrease in natural gas prices                                            |  |   | (123  | )
|                                                                          |  |   |       |  
|Gross revenues  January 1  December 31, 2012                            |  | $ | 3,283 |  
|                                                                          |  |   |       |  

Royalties



|                        |  |                        |       |   |      |   |       |      |  |   |      |  
|----------------------- |  | ---------------------- | ----- | - | ---- | - | ----- | ---- |  | - | ---- | -
|                        |  | Year ended December 31 |      
|                        |  | 2012                   |       |   | 2011 |   |       | 2010 | 
|Royalties (millions)    |  | $                      | 595   |   |      | $ | 661   |      |  | $ | 545  |  
|Average royalty rate(1) |  |                        | 18    | % |      |   | 18    | %    |  |   | 18   | %
|$/boe                   |  | $                      | 10.07 |   |      | $ | 11.09 |      |  | $ | 9.07 |  



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

Lower commodity prices in 2012, partially offset by the impact of wider Canadian crude oil differentials to WTI, resulted in lower royalties compared to
2011. Royalty rates remained consistent between 2012 and 2011.

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



2012
MANAGEMENTS DISCUSSION & ANALYSIS 9



---

Expenses



|                         |  |                        |       |   |      |   |       |      |  |   |       | 
|------------------------ |  | ---------------------- | ----- | - | ---- | - | ----- | ---- |  | - | ----- | 
|                         |  | Year ended December 31 |      
|(millions)               |  | 2012                   |       |   | 2011 |   |       | 2010 | 
|Operating                |  | $                      | 1,019 |   |      | $ | 1,036 |      |  | $ | 944   | 
|Transportation           |  |                        | 29    |   |      |   | 29    |      |  |   | 33    | 
|Financing                |  |                        | 199   |   |      |   | 190   |      |  |   | 174   | 
|Share-based compensation |  | $                      | (10   | ) |      | $ | 84    |      |  | $ | 159   | 
|                         | 
|                         |  | Year ended December 31 |      
|(per boe)                |  | 2012                   |       |   | 2011 |   |       | 2010 | 
|Operating                |  | $                      | 17.26 |   |      | $ | 17.40 |      |  | $ | 15.71 | 
|Transportation           |  |                        | 0.50  |   |      |   | 0.49  |      |  |   | 0.55  | 
|Financing                |  |                        | 3.37  |   |      |   | 3.20  |      |  |   | 2.89  | 
|Share-based compensation |  | $                      | (0.17 | ) |      | $ | 1.41  |      |  | $ | 2.65  | 

Operating

Operating costs were lower in 2012 than 2011 due to our focus on cost savings, lower electricity costs and acquisition and disposition activity. 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 2011.

Operating costs for 2012 include a realized gain on electricity contracts of $7 million (2011  $11 million gain and 2010  $14 million loss).
The average Alberta electricity pool price for 2012 was $64.31 per MWh compared to $76.21 per MWh in 2011 and $50.88 per MWh in 2010. We currently have the following contracts in place that fix the price of our electricity consumption; in 2013
approximately 50 MW fixed at $55.20 per MWh, in 2014 approximately 80 MW fixed at $58.50 per MWh, in 2015 approximately 55 MW fixed at $58.32 per MWh and in 2016 approximately 25 MW fixed at $49.90 per MWh.

Financing

The Company has an unsecured,
revolving syndicated bank facility with an aggregate borrowing limit of $3.0 billion. The facility expires on June 30, 2016 and is extendible. The credit facility contains provisions for standby fees on unutilized credit lines and stamping fees
on bankers acceptances and LIBOR loans that vary depending on certain consolidated financial ratios. At December 31, 2012, approximately $2.2 billion was undrawn under this facility.



2012
MANAGEMENTS DISCUSSION & ANALYSIS 10



---

As at December 31, 2012, the Company had $1.9 billion (2011  $2.0 billion) of senior unsecured
notes outstanding with a weighted average interest rate, including the effects of cross currency swaps, of approximately 6.1 percent (2011  6.1 percent) and a weighted average remaining term of 5.5 years (2011  6.5 years). At
December 31, 2012, 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. These swaps fix a portion of the interest rates under our bank facility.

At December 31, 2012, we had the following senior unsecured notes outstanding:



|              |  |                                   |  |                            |  |            |  |                     |      |      |                              |  |           | 
|------------- |  | --------------------------------- |  | -------------------------- |  | ---------- |  | ------------------- | ---- | ---- | ---------------------------- |  | --------- | 
|              |  | Issue date                        |  | Amount (millions)          |  | Term       |  | Averageinterestrate |      |      | Weightedaverageremainingterm | 
|2007 Notes    |  | May 31, 2007                      |  | US$475                     |  | 815 years |  |                     | 5.80 | %    |                              |  | 4.5 years | 
|2008 Notes    |  | May 29, 2008                      |  | US$480,CAD$30              |  | 812 years |  |                     | 6.25 | %    |                              |  | 5.0 years | 
|UK Notes      |  | July 31, 2008                     |  | £57                        |  | 10 years   |  |                     | 6.95 | %(1) |                              |  | 5.6 years | 
|2009 Notes    |  | May 5, 2009                       |  | US$154(2), £20,
10, CAD$5 |  | 510 years |  |                     | 8.85 | %(3) |                              |  | 4.0 years | 
|2010 Q1 Notes |  | March 16, 2010                    |  | US$250,CAD$50              |  | 515 years |  |                     | 5.47 | %    |                              |  | 5.8 years | 
|2010 Q4 Notes |  | December 2, 2010, January 4, 2011 |  | US$170,CAD$60              |  | 515 years |  |                     | 5.00 | %    |                              |  | 8.7 years | 
|2011 Notes    |  | November 30, 2011                 |  | US$105,CAD$30              |  | 510 years |  |                     | 4.49 | %    |                              |  | 7.1 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) | A portion of the 2009 Notes have equal repayments, beginning in 2013, over the remaining seven years.
|--- | -----------------------------------------------------------------------------------------------------

|(3) | 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.
|--- | --------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------

Financing charges in 2012 were slightly higher than in
2011 and 2010. In 2011, we repaid all outstanding convertible debentures and entered into additional fixed-rate, senior unsecured notes. While the Companys senior unsecured notes currently contain higher interest rates than drawings under our
syndicated bank facilities held in short-term money market instruments, we believe the long-term nature inherent in the senior notes is favourable for a portion of our debt capital structure.

The interest rates on any non-hedged portion of the Companys credit facility are subject to fluctuations in short-term money market rates as advances on the credit facility are generally made under
short-term instruments. As at December 31, 2012, four percent (December 31, 2011  19 percent) of our long-term debt instruments were exposed to changes in short-term interest rates.

Realized gains and losses on the interest rate swaps are recorded as financing costs. For 2012 an expense of $9 million (2011  $12 million) was
recorded in financing to reflect that the floating interest rate was lower than the fixed interest rate transacted under our interest rate swaps.



2012
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).

Effective January 1, 2011, we implemented the Option
Plan and amended our Trust Unit Rights Incentive Plan (TURIP) to become the CSRIP. Pursuant to our conversion from a trust to a corporation, TURIP 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. TURIP 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) with the same terms under the CSRIP for each trust unit right. Subsequent to January 1, 2011, all grants are under the Option Plan.

Following the conversion to a corporation, the TURIP 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 Restricted
Options, Share Rights and subsequent grants under the Option Plan receive equity treatment for accounting purposes 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 option grants are calculated using a Black-Scholes option-pricing model and the fair value of the Share Rights was calculated using a Binomial Lattice option-pricing model. The Restricted Rights are accounted for as a
liability as holders may elect to settle in cash or common shares.

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:



|                                            |  |                        |     |   |      |   |      |      |  |   |     | 
|------------------------------------------- |  | ---------------------- | --- | - | ---- | - | ---- | ---- |  | - | --- | 
|                                            |  | Year ended December 31 |    
|(millions)                                  |  | 2012                   |     |   | 2011 |   |      | 2010 | 
|Options                                     |  | $                      | 21  |   |      | $ | 18   |      |  | $ |    | 
|Restricted Options                          |  |                        | 6   |   |      |   | 22   |      |  |   |    | 
|Restricted Rights                           |  |                        | (45 | ) |      |   | (29  | )    |  |   |    | 
|Share Rights                                |  |                        |    |   |      |   | 1    |      |  |   |    | 
|LTRIP                                       |  |                        | 8   |   |      |   | 14   |      |  |   | 8   | 
|TURIP                                       |  |                        |    |   |      |   |     |      |  |   | 151 | 
|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                    |  | $                      | (10 | ) |      | $ | 84   |      |  | $ | 159 | 
|                                            |  |                        |     |   |      |   |      |      |  |   |     | 

The share price used in the fair value calculation of the LTRIP liability and Restricted Rights obligation at
December 31, 2012 was $10.80 per share (2011  $20.19 and 2010  $23.84).



2012
MANAGEMENTS DISCUSSION & ANALYSIS 12



---

General and Administrative Expenses (G&A)



|                                   |  |                        |      |  |      |   |      |      |  |   |      | 
|---------------------------------- |  | ---------------------- | ---- |  | ---- | - | ---- | ---- |  | - | ---- | 
|                                   |  | Year ended December 31 |     
|(millions, except per boe amounts) |  | 2012                   |      |  | 2011 |   |      | 2010 | 
|Gross                              |  | $                      | 254  |  |      | $ | 222  |      |  | $ | 207  | 
|Per boe                            |  |                        | 4.31 |  |      |   | 3.72 |      |  |   | 3.45 | 
|Net                                |  |                        | 172  |  |      |   | 142  |      |  |   | 145  | 
|Per boe                            |  | $                      | 2.91 |  |      | $ | 2.38 |      |  | $ | 2.41 | 

In 2012, staff costs increased compared to the prior periods due to increasing activity levels consistent with our
exploration & production company mandate.

In the fourth quarter of 2012, we incurred $13 million of restructuring charges related to
an internal reorganization of departments which resulted in termination payouts for certain employees.

During 2012, we incurred a negligible
amount (2011  $1 million) of legal fees from a law firm of which a partner is also a director of Penn West.

Depletion, Depreciation,
Impairment and Accretion



|                                       |  |                        |       |  |      |   |       |      |  |   |       | 
|-------------------------------------- |  | ---------------------- | ----- |  | ---- | - | ----- | ---- |  | - | ----- | 
|                                       |  | Year ended December 31 |      
|(millions, except per boe amounts)     |  | 2012                   |       |  | 2011 |   |       | 2010 | 
|Depletion and depreciation (D&D)     |  | $                      | 1,248 |  |      | $ | 1,168 |      |  | $ | 1,169 | 
|D&D expense per boe                    |  |                        | 21.17 |  |      |   | 19.62 |      |  |   | 19.44 | 
|                                       |  |                        |      
|Impairment (recovery)                  |  |                        | 277   |  |      |   | (10   | )    |  |   |      | 
|Impairment (recovery) per boe          |  |                        | 4.69  |  |      |   | (0.17 | )    |  |   |      | 
|                                       |  |                        |      
|Accretion of decommissioning liability |  |                        | 54    |  |      |   | 45    |      |  |   | 44    | 
|Accretion expense per boe              |  | $                      | 0.90  |  |      | $ | 0.76  |      |  | $ | 0.73  | 

Our D&D rate has increased due to our capital spending substantially weighted to light-oil development and the
divestment of non-core properties. D&D and accretion rates were comparable in 2011 and 2010.

We recorded an impairment charge during the
fourth quarter of 2012 related to legacy, base natural gas assets in northern British Columbia as a result of lower natural gas prices.

In
2011, we recorded an impairment reversal of $10 million to reflect stronger commodity prices resulting in higher forecast cash flows relating to properties in central Alberta.

Taxes



|                                |  |                        |    |  |      |   |      |      |  |   |      |  
|------------------------------- |  | ---------------------- | -- |  | ---- | - | ---- | ---- |  | - | ---- | -
|                                |  | Year ended December 31 |   
|(millions)                      |  | 2012                   |    |  | 2011 |   |      | 2010 | 
|Deferred tax expense (recovery) |  | $                      | 63 |  |      | $ | (227 | )    |  | $ | (101 | )

In 2012, we recorded a deferred tax expense primarily due to gains on property dispositions and from unrealized risk
management gains.

The deferred tax recovery for the year ended December 31, 2011 includes a $304 million recovery related to the tax
rate differential on our conversion from a trust to an E&P company on January 1, 2011. As a corporation, we are subject to income taxes at Canadian corporate tax rates. Under the former trust structure, IFRS required us 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.



2012
MANAGEMENTS DISCUSSION & ANALYSIS 13



---

Tax Pools



|                                              |  |                   |       |  |      |   |       |      |  |   |       | 
|--------------------------------------------- |  | ----------------- | ----- |  | ---- | - | ----- | ---- |  | - | ----- | 
|                                              |  | As at December 31 |      
|(millions)                                    |  | 2012              |       |  | 2011 |   |       | 2010 | 
|Undepreciated capital cost (UCC)              |  | $                 | 1,155 |  |      | $ | 1,085 |      |  | $ | 1,122 | 
|Canadian oil and gas property expense (COGPE) |  |                   | 24    |  |      |   | 1,395 |      |  |   | 1,562 | 
|Canadian development expense (CDE)            |  |                   | 2,713 |  |      |   | 2,104 |      |  |   | 1,494 | 
|Canadian exploration expense (CEE)            |  |                   | 348   |  |      |   | 294   |      |  |   | 305   | 
|Non-capital losses                            |  |                   | 1,963 |  |      |   | 2,966 |      |  |   | 2,481 | 
|Other                                         |  |                   | 21    |  |      |   | 31    |      |  |   | 31    | 
|                                              |  |                   |       |  |      |   |       |      |  |   |       | 
|Total                                         |  | $                 | 6,224 |  |      | $ | 7,875 |      |  | $ | 6,995 | 
|                                              |  |                   |       |  |      |   |       |      |  |   |       | 

Tax pool amounts exclude income deferred in operating partnerships of $616 million in 2012 (2011  $1,654 million
and 2010  $920 million).

Foreign Exchange



|                                        |  |                        |     |   |      |   |    |      |  |   |     |  
|--------------------------------------- |  | ---------------------- | --- | - | ---- | - | -- | ---- |  | - | --- | -
|                                        |  | Year ended December 31 |    
|(millions)                              |  | 2012                   |     |   | 2011 |   |    | 2010 | 
|Unrealized foreign exchange loss (gain) |  | $                      | (32 | ) |      | $ | 38 |      |  | $ | (82 | )

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 gains during 2012 and 2010 were primarily due to the strengthening of the Canadian dollar relative to the US dollar and the
losses during 2011 were primarily due to the weakening of the Canadian dollar relative to the US dollar.

Funds Flow and Net Income



|                        |  |                        |       |  |      |   |       |      |  |   |       | 
|----------------------- |  | ---------------------- | ----- |  | ---- | - | ----- | ---- |  | - | ----- | 
|                        |  | Year ended December 31 |      
|                        |  | 2012                   |       |  | 2011 |   |       | 2010 | 
|Funds flow(1)(millions) |  | $                      | 1,248 |  |      | $ | 1,537 |      |  | $ | 1,185 | 
|Basic per share         |  |                        | 2.62  |  |      |   | 3.29  |      |  |   | 2.68  | 
|Diluted per share       |  |                        | 2.62  |  |      |   | 3.29  |      |  |   | 2.65  | 
|                        |  |                        |      
|Net income (millions)   |  |                        | 174   |  |      |   | 638   |      |  |   | 1,110 | 
|Basic per share         |  |                        | 0.37  |  |      |   | 1.37  |      |  |   | 2.51  | 
|Diluted per share       |  | $                      | 0.37  |  |      | $ | 1.36  |      |  | $ | 2.48  | 



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

Funds flow in 2012 decreased from 2011 as a result of lower commodity price realizations and disposition activity. 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 2012, net income decreased as lower revenues from the decline in commodity
prices and an impairment charge on legacy natural gas properties were partially offset by gains from property dispositions and risk management gains.

For 2011, net income decreased compared to 2010 as significant gains on asset dispositions were recorded in 2010 on the formation of the Cordova Joint Venture and the Peace River Oil Partnership. Net
income in 2011 included a $304 million deferred tax recovery related to our conversion from an income trust to a corporate structure.



2012
MANAGEMENTS DISCUSSION & ANALYSIS 14



---

|                                        |  |                        |        |   |      |  |     |         |  |   |        |   |  |         |     |   |   |   |        |   |  |  |     |  
|--------------------------------------- |  | ---------------------- | ------ | - | ---- |  | --- | ------- |  | - | ------ | - |  | ------- | --- | - | - | - | ------ | - |  |  | --- | -
|                                        |  | Year ended December 31 |       
|                                        |  | 2012                   |        |   | 2011 |  |     | 2010    | 
|                                        |  | per boe                |        |   | %    |  |     | per boe |  |   | %      |   |  | per boe |     |   | % |  
|Oil and natural gas revenues(1)         |  | $                      | 55.63  |   |      |  | 100 |         |  | $ | 60.54  |   |  |         | 100 |   |   | $ | 50.46  |   |  |  | 100 |  
|Royalties                               |  |                        | (10.07 | ) |      |  | (18 | )       |  |   | (11.09 | ) |  |         | (18 | ) |   |   | (9.07  | ) |  |  | (18 | )
|Operating expenses(2)                   |  |                        | (17.26 | ) |      |  | (31 | )       |  |   | (17.40 | ) |  |         | (29 | ) |   |   | (15.71 | ) |  |  | (31 | )
|Transportation                          |  |                        | (0.50  | ) |      |  | (1  | )       |  |   | (0.49  | ) |  |         | (1  | ) |   |   | (0.55  | ) |  |  | (1  | )
|                                        |  |                        |        |   |      |  |     |         |  |   |        |   |  |         |     |   |   |   |        |   |  |  |     |  
|Net operating income                    |  |                        | 27.80  |   |      |  | 50  |         |  |   | 31.56  |   |  |         | 52  |   |   |   | 25.13  |   |  |  | 50  |  
|General and administrative expenses     |  |                        | (2.91  | ) |      |  | (6  | )       |  |   | (2.38  | ) |  |         | (4  | ) |   |   | (2.41  | ) |  |  | (5  | )
|Restructuring                           |  |                        | (0.23  | ) |      |  |    |         |  |   |       |   |  |         |    |   |   |   |       |   |  |  |    |  
|Share-based compensation  cash         |  |                        | (0.14  | ) |      |  |    |         |  |   | (0.15  | ) |  |         |    |   |   |   | (0.14  | ) |  |  |    |  
|Financing(3)                            |  |                        | (3.37  | ) |      |  | (6  | )       |  |   | (3.20  | ) |  |         | (5  | ) |   |   | (2.89  | ) |  |  | (6  | )
|                                        |  |                        |        |   |      |  |     |         |  |   |        |   |  |         |     |   |   |   |        |   |  |  |     |  
|Funds flow                              |  |                        | 21.15  |   |      |  | 38  |         |  |   | 25.83  |   |  |         | 43  |   |   |   | 19.69  |   |  |  | 39  |  
|Unrealized foreign exchange gain (loss) |  |                        | 0.54   |   |      |  | 1   |         |  |   | (0.64  | ) |  |         | (1  | ) |   |   | 1.36   |   |  |  | 3   |  
|Share-based compensation                |  |                        | 0.31   |   |      |  |    |         |  |   | (1.26  | ) |  |         | (2  | ) |   |   | (2.51  | ) |  |  | (5  | )
|Risk management activities(4)           |  |                        | 2.55   |   |      |  | 5   |         |  |   | 0.55   |   |  |         | 1   |   |   |   | 0.40   |   |  |  | 1   |  
|Depletion and depreciation              |  |                        | (25.86 | ) |      |  | (46 | )       |  |   | (19.45 | ) |  |         | (32 | ) |   |   | (19.44 | ) |  |  | (39 | )
|Accretion                               |  |                        | (0.90  | ) |      |  | (2  | )       |  |   | (0.76  | ) |  |         | (1  | ) |   |   | (0.73  | ) |  |  | (1  | )
|Gain on dispositions                    |  |                        | 6.51   |   |      |  | 12  |         |  |   | 2.89   |   |  |         | 5   |   |   |   | 18.02  |   |  |  | 36  |  
|Exploration and evaluation              |  |                        | (0.29  | ) |      |  | (1  | )       |  |   | (0.25  | ) |  |         | (1  | ) |   |   | (0.02  | ) |  |  |    |  
|Deferred tax recovery (expense)         |  |                        | (1.07  | ) |      |  | (2  | )       |  |   | 3.80   |   |  |         | 6   |   |   |   | 1.70   |   |  |  | 3   |  
|                                        |  |                        |        |   |      |  |     |         |  |   |        |   |  |         |     |   |   |   |        |   |  |  |     |  
|Net income                              |  | $                      | 2.94   |   |      |  | 5   |         |  | $ | 10.71  |   |  |         | 18  |   |   | $ | 18.47  |   |  |  | 37  |  
|                                        |  |                        |        |   |      |  |     |         |  |   |        |   |  |         |     |   |   |   |        |   |  |  |     |  



|(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.
|--- | -------------------------------------------------------------------------------------------

Drilling



|                          |  |                        |     |  |      |  |     |       |  |  |     |  |  |  |     |  
|------------------------- |  | ---------------------- | --- |  | ---- |  | --- | ----- |  |  | --- |  |  |  | --- | -
|                          |  | Year ended December 31 |    
|                          |  | 2012                   |     |  | 2011 | 
|                          |  | Gross                  |     |  | Net  |  |     | Gross |  |  | Net | 
|Oil                       |  |                        | 349 |  |      |  | 263 |       |  |  | 457 |  |  |  | 353 |  
|Natural gas               |  |                        | 23  |  |      |  | 19  |       |  |  | 53  |  |  |  | 36  |  
|                          |  |                        |     |  |      |  |     |       |  |  |     |  |  |  |     |  
|                          |  |                        | 372 |  |      |  | 282 |       |  |  | 510 |  |  |  | 389 |  
|Stratigraphic and service |  |                        | 72  |  |      |  | 32  |       |  |  | 89  |  |  |  | 37  |  
|                          |  |                        |     |  |      |  |     |       |  |  |     |  |  |  |     |  
|Total                     |  |                        | 444 |  |      |  | 314 |       |  |  | 599 |  |  |  | 426 |  
|                          |  |                        |     |  |      |  |     |       |  |  |     |  |  |  |     |  
|Success rate(1)           |  |                        |     |  |      |  | 100 | %     |  |  |     |  |  |  | 100 | %
|                          |  |                        |     |  |      |  |     |       |  |  |     |  |  |  |     |  



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



2012
MANAGEMENTS DISCUSSION & ANALYSIS 15



---

Capital Expenditures



|                               |  |                        |        |   |      |   |       |      |  |   |        |  
|------------------------------ |  | ---------------------- | ------ | - | ---- | - | ----- | ---- |  | - | ------ | -
|                               |  | Year ended December 31 |       
|(millions)                     |  | 2012                   |        |   | 2011 |   |       | 2010 | 
|Land acquisition and retention |  | $                      | 37     |   |      | $ | 181   |      |  | $ | 102    |  
|Drilling and completions       |  |                        | 1,148  |   |      |   | 1,217 |      |  |   | 800    |  
|Facilities and well equipping  |  |                        | 675    |   |      |   | 521   |      |  |   | 281    |  
|Geological and geophysical     |  |                        | 13     |   |      |   | 9     |      |  |   | 10     |  
|Corporate                      |  |                        | 16     |   |      |   | 25    |      |  |   | 11     |  
|                               |  |                        |        |   |      |   |       |      |  |   |        |  
|Capital expenditures(1)        |  |                        | 1,889  |   |      |   | 1,953 |      |  |   | 1,204  |  
|Joint venture, carried capital |  |                        | (137   | ) |      |   | (107  | )    |  |   | (17    | )
|Property dispositions, net     |  |                        | (1,615 | ) |      |   | (266  | )    |  |   | (1,306 | )
|Business combinations          |  |                        |       |   |      |   | 286   |      |  |   | 139    |  
|                               |  |                        |        |   |      |   |       |      |  |   |        |  
|Total expenditures             |  | $                      | 137    |   |      | $ | 1,866 |      |  | $ | 20     |  
|                               |  |                        |        |   |      |   |       |      |  |   |        |  



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

Our 2012 and 2011 capital programs continued to be directed towards our key light-oil projects, focusing on the Carbonates, Cardium, Spearfish and
Viking. During 2012, we completed net property dispositions of non-core properties with combined production of approximately 16,500 barrels of oil equivalent per day. In 2011, we were successful at land sales and acquired strategic lands to
complement our existing asset base.

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



|                         |  |                        |     |  |      |   |     |      |  |   |    | 
|------------------------ |  | ---------------------- | --- |  | ---- | - | --- | ---- |  | - | -- | 
|                         |  | Year ended December 31 |    
|(millions)               |  | 2012                   |     |  | 2011 |   |     | 2010 | 
|E&E capital expenditures |  | $                      | 228 |  |      | $ | 321 |      |  | $ | 58 | 

E&E expenditures include land acquisitions, appraisal activities at our Cordova and Peace River joint ventures and
other exploration costs. For 2012, we had a non-cash E&E expense of $17 million (2011  $15 million and 2010  $1 million) primarily related to land expiries and minor properties not expected to be continued to the development phase.
We also had transfers into Property, Plant and Equipment totalling $16 million (2011  $14 million and 2010  nil) and dispositions of $4 million (2011  $2 million and 2010  $61 million).

Gain on asset dispositions



|                           |  |                        |     |  |      |   |     |      |  |   |       | 
|-------------------------- |  | ---------------------- | --- |  | ---- | - | --- | ---- |  | - | ----- | 
|                           |  | Year ended December 31 |    
|(millions)                 |  | 2012                   |     |  | 2011 |   |     | 2010 | 
|Gain on asset dispositions |  | $                      | 384 |  |      | $ | 172 |      |  | $ | 1,082 | 

The gains recognized in income during 2012 and 2011 related to property dispositions of non-core assets. We recorded
significant gains in 2010 as a result of forming the Peace River Oil Partnership in June 2010 and entering the Cordova Joint Venture in September 2010.

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.



2012
MANAGEMENTS DISCUSSION & ANALYSIS 16



---

Goodwill



|                                   |  |                        |       |  |      |   |       |      |  |   |       | 
|---------------------------------- |  | ---------------------- | ----- |  | ---- | - | ----- | ---- |  | - | ----- | 
|                                   |  | Year ended December 31 |      
|(millions)                         |  | 2012                   |       |  | 2011 |   |       | 2010 | 
|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 in
previous years. We determined there was no goodwill impairment at December 31, 2012 or 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 unlikely assumptions, become material.

We are dedicated to reducing the environmental impact from our operations through our environmental programs which include resource conservation, water
management, site abandonment/reclamation and CO2 sequestration. Operations are continuously monitored to minimize the environmental impact and capital is allocated to reclamation and other activities to mitigate the impact on the areas in which we
operate.

Liquidity and Capital Resources

Capitalization



|                                   |  |                   |       |  |      |  |     |      |  |   |        |  |  |  |     |  |  |   |        |  |  |  |     | 
|---------------------------------- |  | ----------------- | ----- |  | ---- |  | --- | ---- |  | - | ------ |  |  |  | --- |  |  | - | ------ |  |  |  | --- | 
|                                   |  | As at December 31 |      
|                                   |  | 2012              |       |  | 2011 |  |     | 2010 | 
|(millions)                         |  | %                 |       |  | %    |  |     | %    | 
|Common shares issued, at market(1) |  | $                 | 5,176 |  |      |  | 64  |      |  | $ | 9,517  |  |  |  | 72  |  |  | $ | 10,959 |  |  |  | 78  | 
|Bank loans and long-term notes     |  |                   | 2,690 |  |      |  | 33  |      |  |   | 3,219  |  |  |  | 24  |  |  |   | 2,496  |  |  |  | 18  | 
|Convertible debentures             |  |                   |      |  |      |  |    |      |  |   |       |  |  |  |    |  |  |   | 255    |  |  |  | 2   | 
|Working capital deficiency(2)      |  |                   | 239   |  |      |  | 3   |      |  |   | 554    |  |  |  | 4   |  |  |   | 303    |  |  |  | 2   | 
|                                   |  |                   |       |  |      |  |     |      |  |   |        |  |  |  |     |  |  |   |        |  |  |  |     | 
|Total enterprise value             |  | $                 | 8,105 |  |      |  | 100 |      |  | $ | 13,290 |  |  |  | 100 |  |  | $ | 14,013 |  |  |  | 100 | 
|                                   |  |                   |       |  |      |  |     |      |  |   |        |  |  |  |     |  |  |   |        |  |  |  |     | 



|(1) | The share price at December 31, 2012 was $10.80 (2011$20.19 and 2010$23.84).
|--- | ------------------------------------------------------------------------------

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

Dividends



|                   |  |                        |      |  |      |   |      |      |  |   |      | 
|------------------ |  | ---------------------- | ---- |  | ---- | - | ---- | ---- |  | - | ---- | 
|                   |  | Year ended December 31 |     
|(millions)         |  | 2012                   |      |  | 2011 |   |      | 2010 | 
|Dividends declared |  | $                      | 514  |  |      | $ | 506  |      |  | $ | 686  | 
|Per share          |  |                        | 1.08 |  |      |   | 1.08 |      |  |   | 1.56 | 
|Dividends paid(1)  |  | $                      | 512  |  |      | $ | 420  |      |  | $ | 708  | 



|(1) | Includes amounts funded by the dividend reinvestment plan.
|--- | ----------------------------------------------------------

On February 13, 2013, our Board of Directors declared a first quarter 2013 dividend of $0.27 per share to be paid on April 15, 2013 to shareholders of record at the close of business on
March 28, 2013. Shareholders who are residents of Canada are advised that this dividend is designated as an eligible dividend for Canadian income tax purposes.



2012
MANAGEMENTS DISCUSSION & ANALYSIS 17



---

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 investment plans. Our dividend level could change based on these and other factors and is subject to the approval of our Board of Directors. For
further information regarding our dividend policy, including the factors that could affect the amount of quarterly dividend that we pay and the risks relating thereto, see Dividends and Dividend Policy  Dividend Policy in our
Annual Information Form, which is available on our website at www.pennwest.com, on the SEDAR website at www.sedar.com, and on the SEC website at www.sec.gov.

Liquidity

The Company currently has an unsecured, revolving, syndicated bank facility with an
aggregate borrowing limit of $3.0 billion expiring on June 30, 2016. For further details on our debt instruments, please refer to the Financing section of this MD&A.

We actively manage our debt capital and consider opportunities to reduce or diversify our debt structure. We contemplate 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. Strategies 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, 2012, the Company was in compliance with all of these financial covenants which consist of the following:



|                              |  |               |  |                   |     |  
|----------------------------- |  | ------------- |  | ----------------- | --- | -
|                              |  | Limit         |  | December 31, 2012 |    
|Senior debt to EBITDA(1)      |  | Less than 3:1 |  |                   | 2.1 |  
|Total debt to EBITDA(1)       |  | Less than 4:1 |  |                   | 2.1 |  
|Senior debt to capitalization |  | Less than 50% |  |                   | 23  | %
|Total debt to capitalization  |  | Less than 55% |  |                   | 23  | %



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

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.

Convertible Debentures

We had no convertible debentures outstanding at December 31, 2012 or 2011. 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.



2012
MANAGEMENTS DISCUSSION & ANALYSIS 18



---

Financial Instruments

We had the following financial instruments outstanding as at December 31, 2012. 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.



|                                          |  |                |               |  |               |  |               |         |  |  |                         |   |  |  |     |  
|----------------------------------------- |  | -------------- | ------------- |  | ------------- |  | ------------- | ------- |  |  | ----------------------- | - |  |  | --- | -
|                                          |  | Notionalvolume |               |  | Remainingterm |  |               | Pricing |  |  | Fair value(millions)    |  
|Crude oil                                 |  |                |               |  |               |  |               |         |  |  |                         |   |  |  |     |  
|WTI Collars                               |  |                | 55,000 bbls/d |  |               |  | Jan/13Dec/13 |         |  |  | US$91.55 to $104.42/bbl |   |  |  | $66 |  
|Natural gas                               |  |                |               |  |               |  |               |         |  |  |                         |   |  |  |     |  
|AECO Forwards                             |  |                | 125,000 mcf/d |  |               |  | Jan/13Dec/13 |         |  |  | $3.34/mcf               |   |  |  | 9   |  
|AECO Forwards                             |  |                | 25,000 mcf/d  |  |               |  | Jan/14Dec/14 |         |  |  | $3.85/mcf               |   |  |  | 2   |  
|AECO Collars                              |  |                | 25,000 mcf/d  |  |               |  | Jan/14Dec/14 |         |  |  | $3.25 to $4.35/mcf      |   |  |  |    |  
|Electricity swaps                         |  |                |               |  |               |  |               |         |  |  |                         |   |  |  |     |  
|Alberta Power Pool                        |  |                | 30 MW         |  |               |  | Jan/13Dec/13 |         |  |  | $54.60/MWh              |   |  |  | 1   |  
|Alberta Power Pool                        |  |                | 20 MW         |  |               |  | Jan/13Dec/13 |         |  |  | $56.10/MWh              |   |  |  | 1   |  
|Alberta Power Pool                        |  |                | 70 MW         |  |               |  | Jan/14Dec/14 |         |  |  | $58.50/MWh              |   |  |  | (5  | )
|Alberta Power Pool                        |  |                | 10 MW         |  |               |  | Jan/14Dec/15 |         |  |  | $58.50/MWh              |   |  |  | (1  | )
|Alberta Power Pool                        |  |                | 45 MW         |  |               |  | Jan/15Dec/15 |         |  |  | $58.28/MWh              |   |  |  | (4  | )
|Alberta Power Pool                        |  |                | 25 MW         |  |               |  | Jan/16Dec/16 |         |  |  | $49.90/MWh              |   |  |  |    |  
|Interest rate swaps                       |  |                | $650          |  |               |  | Jan/13Jan/14 |         |  |  | 2.65                    | % |  |  | (10 | )
|Foreign exchange forwards on senior notes |  |                |               |  |               |  |               |         |  |  |                         |   |  |  |     |  
|3 to 15-year initial term                 |  |                | US$641        |  |               |  | 20142022     |         |  |  | 1.000 CAD/USD           |   |  |  | 23  |  
|Cross currency swaps                      |  |                |               |  |               |  |               |         |  |  |                         |   |  |  |     |  
|10-year initial term                      |  |                | £57           |  |               |  | 2018          |         |  |  | 2.0075 CAD/GBP, 6.95    | % |  |  | (19 | )
|10-year initial term                      |  |                | £20           |  |               |  | 2019          |         |  |  | 1.8051 CAD/GBP, 9.15    | % |  |  | (3  | )
|10-year initial term                      |  |                | 10           |  |               |  | 2019          |         |  |  | 1.5870 CAD/EUR, 9.22    | % |  |  | (2  | )
|Total                                     |  |                |               |  |               |  |               |         |  |  |                         |   |  |  | $58 |  

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

Subsequent to December 31, 2012, we entered into foreign exchange forward contracts on revenue from March 2013 to December 2013 on $153
million per month at an average foreign exchange rate of 1.022 CAD/USD. We also entered into additional natural gas collars on 25,000 mcf per day in 2014 between $3.57 per mcf and $4.00 per mcf.

Additionally, we have subsequently entered into oil differential contracts from March to June 2013 on 4,000 barrels per day. These contracts fix the
price of MSW (mixed sweet crudes at Edmonton) at a discount of USD $8.00 per barrel to WTI.



2012
MANAGEMENTS DISCUSSION & ANALYSIS 19



---

Outlook

This outlook section is included to provide shareholders with information about our expectations as at March 13, 2013 for production and capital expenditures in 2013 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 and are cautioned that
numerous factors could potentially impact our capital expenditure levels and production performance for 2013, including our current disposition program.

Our 2013 forecast exploration and development capital is $900 million with an option to layer in up to $300 million of incremental capital later in 2013, subject to external market factors and internal
performance. After the divestment activity in 2012, we forecast 2013 average production of between 135,000 and 145,000 boe per day.

There
have been no changes to our guidance from our prior forecast, released on February 14, 2013 with our fourth quarter results and filed on SEDAR at www.sedar.com.

Our 2012 annual capital expenditure and production guidance released on November 2, 2012 with our third quarter results were met.

Sensitivity Analysis

Estimated sensitivities to selected key assumptions on funds flow 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           |   |            |  | 24 |         |  |  | 0.05 | 
|Liquids production           |  |                      | 1,000 bbls/day |   |            |  | 20 |         |  |  | 0.04 | 
|Price per mcf of natural gas |  | $                    | 0.10           |   |            |  | 5  |         |  |  | 0.01 | 
|Natural gas production       |  |                      | 10 mmcf/day    |   |            |  | 2  |         |  |  |     | 
|Effective interest rate      |  |                      | 1              | % |            |  | 6  |         |  |  | 0.01 | 
|Exchange rate ($US per $CAD) |  | $                    | 0.01           |   |            |  | 12 |         |  |  | 0.02 | 



2012
MANAGEMENTS DISCUSSION & ANALYSIS 20



---

Contractual Obligations and Commitments

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



|                             |  |      |     |  |      |   |     |      |  |   |      |  |  |      |     |  |            |   |     |  |  |   |       | 
|---------------------------- |  | ---- | --- |  | ---- | - | --- | ---- |  | - | ---- |  |  | ---- | --- |  | ---------- | - | --- |  |  | - | ----- | 
|(millions)                   |  | 2013 |     |  | 2014 |   |     | 2015 |  |   | 2016 |  |  | 2017 |     |  | Thereafter |  
|Long-term debt               |  | $    | 5   |  |      | $ | 60  |      |  | $ | 251  |  |  | $    | 968 |  |            | $ | 242 |  |  | $ | 1,164 | 
|Transportation               |  |      | 24  |  |      |   | 17  |      |  |   | 10   |  |  |      | 4   |  |            |   | 1   |  |  |   |      | 
|Transportation ($US)         |  |      | 4   |  |      |   | 37  |      |  |   | 37   |  |  |      | 33  |  |            |   | 33  |  |  |   | 198   | 
|Power infrastructure         |  |      | 29  |  |      |   | 14  |      |  |   | 14   |  |  |      | 14  |  |            |   | 14  |  |  |   | 12    | 
|Drilling rigs                |  |      | 23  |  |      |   | 21  |      |  |   | 17   |  |  |      | 11  |  |            |   | 6   |  |  |   |      | 
|Purchase obligations(1)      |  |      | 6   |  |      |   | 5   |      |  |   | 5    |  |  |      | 1   |  |            |   | 1   |  |  |   | 1     | 
|Interest obligations         |  |      | 146 |  |      |   | 142 |      |  |   | 132  |  |  |      | 105 |  |            |   | 77  |  |  |   | 136   | 
|Office lease(2)              |  |      | 62  |  |      |   | 56  |      |  |   | 55   |  |  |      | 54  |  |            |   | 52  |  |  |   | 384   | 
|Decommissioning liability(3) |  | $    | 100 |  |      | $ | 95  |      |  | $ | 91   |  |  | $    | 87  |  |            | $ | 82  |  |  | $ | 180   | 



|(1) | These amounts represent estimated commitments of $13 million for CO2 purchases and $6 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 $335 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 30, 2016. If we are not successful in renewing or replacing the
facility, we could be required to obtain other facilities including term bank loans. In addition, we have an aggregate of $1.9 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.

We are involved in various claims and litigation in the normal course of
business and record provisions for claims as required.

Equity Instruments



|                                              |  |  |             |  
|--------------------------------------------- |  |  | ----------- | -
|Common shares issued:                         |  |  |             |  
|As at December 31, 2012                       |  |  | 479,258,670 |  
|Issued on exercise of share rights            |  |  | 139,158     |  
|Issued pursuant to dividend reinvestment plan |  |  | 2,807,458   |  
|                                              |  |  |             |  
|As at March 13, 2013                          |  |  | 482,205,286 |  
|                                              |  |  |             |  
|Options outstanding:                          |  |  |             |  
|As at December 31, 2012                       |  |  | 15,737,400  |  
|Granted                                       |  |  | 8,248,100   |  
|Forfeited                                     |  |  | (1,614,185  | )
|                                              |  |  |             |  
|As at March 13, 2013                          |  |  | 22,371,315  |  
|                                              |  |  |             |  
|Share Rights outstanding:                     |  |  |             |  
|As at December 31, 2012                       |  |  | 291,638     |  
|Exercised                                     |  |  | (79,518     | )
|Forfeited                                     |  |  | (28,059     | )
|                                              |  |  |             |  
|As at March 13, 2013                          |  |  | 184,061     |  
|                                              |  |  |             |  
|Restricted Options outstanding(1):            |  |  |             |  
|As at December 31, 2012                       |  |  | 10,535,361  |  
|Forfeited                                     |  |  | (2,361,394  | )
|                                              |  |  |             |  
|As at March 13, 2013                          |  |  | 8,173,967   |  
|                                              |  |  |             |  



|(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.
|--- | ------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



2012
MANAGEMENTS DISCUSSION & ANALYSIS 21



---

Fourth Quarter 2012 Highlights

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



|                                     |  |                                |         |   |      |   |         |          |  |  |      |  
|------------------------------------ |  | ------------------------------ | ------- | - | ---- | - | ------- | -------- |  |  | ---- | -
|                                     |  | Three months ended December 31 |        
|                                     |  | 2012                           |         |   | 2011 |   |         | % change | 
|Financial                            |  |                                |         |   |      |   |         |          |  |  |      |  
|(millions, except per share amounts) |  |                                |         |   |      |   |         |          |  |  |      |  
|Gross revenues(1)                    |  | $                              | 799     |   |      | $ | 979     |          |  |  | (18  | )
|Funds flow                           |  |                                | 295     |   |      |   | 437     |          |  |  | (33  | )
|Basic per share                      |  |                                | 0.62    |   |      |   | 0.93    |          |  |  | (33  | )
|Diluted per share                    |  |                                | 0.62    |   |      |   | 0.93    |          |  |  | (33  | )
|Net loss                             |  |                                | (53     | ) |      |   | (62     | )        |  |  | (15  | )
|Basic per share                      |  |                                | (0.11   | ) |      |   | (0.13   | )        |  |  | (15  | )
|Diluted per share                    |  |                                | (0.11   | ) |      |   | (0.13   | )        |  |  | (15  | )
|Capital expenditures, net(2)         |  |                                | (916    | ) |      |   | 583     |          |  |  | (100 | )
|Dividends                            |  |                                |         |   |      |   |         |          |  |  |      |  
|(millions)                           |  |                                |         |   |      |   |         |          |  |  |      |  
|Dividends paid(3)                    |  | $                              | 129     |   |      | $ | 127     |          |  |  | 2    |  
|DRIP                                 |  |                                | (31     | ) |      |   | (26     | )        |  |  | 19   |  
|                                     |  |                                |         |   |      |   |         |          |  |  |      |  
|Dividends paid in cash               |  | $                              | 98      |   |      | $ | 101     |          |  |  | (3   | )
|Operations                           |  |                                |         |   |      |   |         |          |  |  |      |  
|Daily production                     |  |                                |         |   |      |   |         |          |  |  |      |  
|Light oil and NGL (bbls/d)           |  |                                | 82,224  |   |      |   | 90,185  |          |  |  | (9   | )
|Heavy oil (bbls/d)                   |  |                                | 16,847  |   |      |   | 17,886  |          |  |  | (6   | )
|Natural gas (mmcf/d)                 |  |                                | 329     |   |      |   | 364     |          |  |  | (10  | )
|                                     |  |                                |         |   |      |   |         |          |  |  |      |  
|Total production (boe/d)             |  |                                | 153,931 |   |      |   | 168,801 |          |  |  | (9   | )
|                                     |  |                                |         |   |      |   |         |          |  |  |      |  
|Average sales price                  |  |                                |         |   |      |   |         |          |  |  |      |  
|Light oil and NGL (per bbl)          |  | $                              | 75.91   |   |      | $ | 88.76   |          |  |  | (15  | )
|Heavy oil (per bbl)                  |  |                                | 59.85   |   |      |   | 76.88   |          |  |  | (22  | )
|Natural gas (per mcf)                |  | $                              | 3.28    |   |      | $ | 3.47    |          |  |  | (5   | )
|Netback per boe                      |  |                                |         |   |      |   |         |          |  |  |      |  
|Sales price                          |  | $                              | 54.10   |   |      | $ | 63.05   |          |  |  | (14  | )
|Risk management gain (loss)          |  |                                | 0.51    |   |      |   | (0.84   | )        |  |  | 100  |  
|                                     |  |                                |         |   |      |   |         |          |  |  |      |  
|Net sales price                      |  |                                | 54.61   |   |      |   | 62.21   |          |  |  | (12  | )
|Royalties                            |  |                                | (10.10  | ) |      |   | (11.47  | )        |  |  | (12  | )
|Operating expenses                   |  |                                | (17.16  | ) |      |   | (17.48  | )        |  |  | (2   | )
|Transportation                       |  |                                | (0.51   | ) |      |   | (0.48   | )        |  |  | 6    |  
|                                     |  |                                |         |   |      |   |         |          |  |  |      |  
|Netback                              |  | $                              | 26.84   |   |      | $ | 32.78   |          |  |  | (18  | )
|                                     |  |                                |         |   |      |   |         |          |  |  |      |  



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

|(2) | Includes net asset acquisitions/dispositions and excludes business combinations. There are no business combinations in the 2012 period.
|--- | ---------------------------------------------------------------------------------------------------------------------------------------

|(3) | 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.
|--- | ----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



2012
MANAGEMENTS DISCUSSION & ANALYSIS 22



---

Financial

Gross revenues and funds flow decreased in the fourth quarter of 2012 compared to 2011 primarily due to lower commodity price realizations and asset dispositions.

Net loss was comparable between the fourth quarter of 2012 and 2011 as a decline in revenues from lower commodity prices was offset by unrealized risk
management gains in 2012. We recorded an impairment charge during the fourth quarter of 2012 related to legacy, base natural gas assets in northern British Columbia as a result of decreased natural gas prices.

We closed non-core asset dispositions during the fourth quarter for proceeds of approximately $1.3 billion. The proceeds were applied to reduce bank
debt.

Our capital activity continued to be focused on our light-oil targets with 31 net oil wells drilled during the fourth quarter of 2012.

Operations

Average production in
the fourth quarter of 2012 was 153,931 boe per day after the impact of net asset dispositions and weighted approximately 64 percent to oil and liquids. During the fourth quarter of 2012, we completed net asset dispositions with combined production
of approximately 13,000 boe per day.

In the fourth quarter of 2012, WTI crude oil prices averaged US$88.20 per barrel compared to US$92.19
per barrel in the third quarter of 2012 and US$94.02 per barrel for the fourth quarter of 2011. Edmonton light sweet oil traded at a discount of $3.46 per barrel to WTI during the fourth quarter of 2012 (2011  premium of $1.44 per barrel)
compared to a discount of $7.40 per barrel during the third quarter of 2012. In the fourth quarter of 2012, the AECO Monthly Index averaged $3.06 per mcf compared to $2.19 per mcf in the third quarter of 2012 and $3.47 per mcf for the fourth quarter
of 2011.

Netbacks were $26.84 per boe compared to $32.78 per boe in the fourth quarter of 2011. The decrease was primarily attributed to
lower commodity prices.

Disclosure Controls and Procedures

As of December 31, 2012, 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, 2012 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.



2012
MANAGEMENTS DISCUSSION & ANALYSIS 23



---

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). As of December 31, 2012, 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, 2012 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 2012 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, 2012 that have materially affected, or are
reasonably likely to materially affect, our ICOFR.

Future Accounting Pronouncements

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

IFRS 9 Financial Instruments outlines a new methodology for the recognition and measurement requirements for financial instruments. This new
standard will eventually replace IAS 39 Financial Instruments: Recognition and Measurement. The standard becomes effective for annual periods beginning on or after, January 1, 2015. This standard is still in development; therefore,
we cannot assess the impact of this standard at this time.

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. We believe the adoption of this standard will have no material impact on our 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 our interest in the Peace
River Oil Partnership. We currently believe that our interest in the Peace River Oil Partnership is appropriately classified as a joint operation; therefore we will continue to proportionately consolidate our 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. We are currently assessing the impact of this standard.

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. We are currently assessing the impact of this standard.



2012
MANAGEMENTS DISCUSSION & ANALYSIS 24



---

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 our audited consolidated financial statements. In the determination of financial results, we must make certain critical accounting estimates as follows:

Depletion and Impairments

Costs of 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.

All of our reserves were evaluated or audited by GLJ Petroleum Consultants Ltd. (GLJ) and Sproule Associates Limited (SAL), both
independent, qualified reserve evaluation 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 an important 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 recorded a $277 million impairment related
to certain properties in northern British Columbia, primarily due to weak natural gas forward prices on December 31, 2012. No impairment existed at December 31, 2011.

Decommissioning Liability

The decommissioning liability is the present value of our future
statutory, contractual, legal or constructive obligations to retire long-lived assets. The liability is recorded on the balance sheet 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 10 to our 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 9 to our audited consolidated financial statements.



2012
MANAGEMENTS DISCUSSION & ANALYSIS 25



---

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, financial instruments including collars may be utilized from time to time. Collars ensure that commodity prices
realized will fall into a contracted range for a contracted sales volume.

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. We determined there was no goodwill
impairment at December 31, 2012 and 2011.

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: under the heading Business Strategy, among other things, our intent to continue to provide our shareholders a meaningful dividend while focusing on improving capital efficiencies and production reliability, that in 2013
exploration and development capital will be $900 million with an option to layer in up to $300 million of incremental capital later in 2013 subject to external market factors, and our intent to keep our business strategy centered on realizing the
value inherent in our extensive light-oil weighted asset base for the benefit of our shareholders; under the heading Business Environment, that geopolitical concerns related to Syria and Iran will persist and are expected to provide
support to world oil prices in 2013; under the heading Performance Indicators, among other things, the focus of our 2013 capital program on improving capital efficiencies by allocating capital to areas we have significantly de-risked,
where we have realized cost reductions, and where we have infrastructure capacity, our plan in 2013 to continue the rotation of our asset portfolio through the disposition of non-core properties and investment in our light-oil resources, and our
belief that our strategies will achieve a balance that provides our shareholders with a meaningful dividend as we continue to concentrate our asset base for oil growth; under Results of Operations, among other things, our intent to
continue to focus our capital activity in 2013 on light-oil and our expectation that this should increase our weighting to liquids; under the heading Environmental and Climate Change, among other things, our intent to reduce the
environmental impact from our operations through our environmental programs; under Liquidity and Capital Resources, our expectation that our strategies will 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; under the heading Outlook, among other things, our expectation
that in 2013 exploration and development capital will be $900 million with an option to layer in up to $300 million of incremental capital later in 2013 subject to external market factors and internal performance and our forecast 2013 average
production of between 135,000 and 145,000 boe per day; and certain disclosures contained under the heading Sensitivity Analysis relating to our estimated sensitivities to certain key assumptions on our future funds flow.





2012
MANAGEMENTS DISCUSSION & ANALYSIS 26



---

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 and Canadian, WTI and world oil prices; future capital expenditure levels; future crude oil, natural gas
liquids and natural gas production levels; that we will be able to successfully dispose of certain non-core assets as expected; drilling results; future exchange rates and interest rates; the amount of future cash dividends that we intend to pay and
the level of participation in our dividend reinvestment plan; 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, 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; geological, technical, drilling and processing problems; general economic and political
conditions in Canada, the U.S. and globally; industry conditions, including fluctuations in the price of oil and natural gas, price differentials for crude oil produced in Canada as compared to other markets and transportation restrictions;
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; failure to complete disposition of non-core assets as
expected; uncertainty of obtaining required approvals for acquisitions, dispositions 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.



2012
MANAGEMENTS DISCUSSION & ANALYSIS 27



---

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.



2012
MANAGEMENTS DISCUSSION & ANALYSIS 28