Exhibit 99.2


MANAGEMENT’S DISCUSSION AND ANALYSIS


For the year ended December 31, 2010





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 Energy Trust (“Penn West”, “We” or “Our”) for the years ended December 31, 2010 and 2009. The date of this MD&A is March 17, 2011.





For additional information, including Penn West’s audited consolidated financial statements and Annual Information Form, please go to our website at www.pennwest.com, in Canada at www.sedar.com or in the United States 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, Penn West Petroleum Ltd. (the “Company”), which is operating under the trade name of Penn West Exploration. These consolidated financial results are presented under Penn West’s former structure, as an income trust, as at and for the years ended December 31, 2010 and 2009.





All dollar amounts contained in this MD&A are expressed in millions of Canadian dollars unless noted otherwise.





Please refer to our disclaimer on forward-looking statements at the end of the 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.




Measures including funds flow, funds flow per unit-basic, funds flow per unit-diluted, netback, net debt, payout ratio, return on equity and return on capital included in this MD&A are not defined in generally accepted accounting principles (“GAAP”) and do not have a standardized meaning prescribed by 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 asset retirement expenditures. Funds flow is used to assess our ability to fund dividend and planned capital programs. See below for reconciliations of funds flow to its nearest measure prescribed by GAAP. Netback is a per-unit-of-production measure of operating margin used in capital allocation decisions and to economically rank projects. Operating margin is calculated as revenue less royalties, operating costs and transportation costs and is used for similar purposes to netback.Net debt is the sum of long-term debt, convertible debentures and working capital (excluding risk management and future income taxes) and is used to assess our leverage levels and hence the continuing appropriateness of our dividend and capital investment levels. Payout ratio is calculated as distributions paid divided by funds flow and is used to assess the adequacy of funds flow retained to finance capital programs. Return on equity is the rate of return calculated by comparing net income to unitholders equity. Return on capital is calculated using net income and financing charges compared to unitholder equity and long-term debt and is used to assess how effectively Penn West utilizes capital.




Calculation of Funds Flow


Year ended December 31(millions, except per unit amounts)

2010


2009Cash flow from operating activities

$
1,217


$
1,401Increase (decrease) in non-cash working capital


(85
)


27Asset retirement expenditures


53



65Funds flow

$
1,185


$
1,493Basic per unit

$
2.68


$
3.62Diluted per unit

$
2.65


$
3.60




2010 ANNUAL MD&A 1


Annual Financial Summary




Year ended December 31(millions, except per unit amounts)

2010


2009


2008Gross revenues (1)

$
3,034


$
3,203


$
4,651Funds flow


1,185



1,493



2,537Basic per unit


2.68



3.62



6.75Diluted per unit


2.65



3.60



6.66Net income (loss)


226



(144
)


1,221Basic per unit


0.51



(0.35
)


3.25Diluted per unit


0.50



(0.35
)


3.22Capital expenditures, net (2)


1,187



688



1,095Long-term debt at year-end


2,496



3,219



3,854Convertible debentures


255



273



296Distributions paid (3)


708



910



1,500Total assets

$
13,368


$
13,876


$
15,412


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


(2)   Excludes business combinations and net proceeds on property acquisitions and dispositions.


(3)   Includes distributions paid and reinvested in trust units under the distribution reinvestment plan.




2010 Highlights





·
Production averaged 164,633 boe per day and was weighted 60 percent to liquids and 40 percent to natural gas.


·
Net debt was reduced by approximately $536 million during 2010.


·
Capital expenditures for 2010, net, totalled $1,187 million including $102 million of strategic land acquisitions to further strengthen our position in key resource plays and excluding $17 million of joint venture carried capital.Net property dispositions were $1,306 million in 2010 compared to $369 million in 2009.


·
Funds flow for 2010 was $1,185 million compared to $1,493 million in 2009. The decrease was primarily due to lower realized risk management gains.


·
Net income was $226 million compared to a net loss of $144 million for 2009. The increase was primarily due to higher oil and natural gas revenues and lower unrealized risk management losses.


·
Netback was $25.07 per boe compared to $26.32 per boe in 2009.





Quarterly Financial Summary


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





Three months ended

Dec. 31

2010


Sep. 30

2010


June 30

2010


Mar. 31

2010


Dec. 31

2009


Sep. 30

2009


June 30

2009


Mar. 31

2009Gross revenues (1)

$
782


$
728


$
718


$
806


$
831


$
800


$
791


$
781Funds flow


305



267



269



344



366



349



430



348Basic per unit


0.67



0.59



0.62



0.81



0.87



0.84



1.05



0.87Diluted per unit


0.66



0.58



0.61



0.80



0.86



0.83



1.05



0.87Net income (loss)


(21
)


(25
)


195



77



(12
)


7



(41
)


(98
)Basic per unit


(0.05
)


(0.06
)


0.45



0.18



(0.03
)


0.02



(0.10
)


(0.25
)Diluted per unit


(0.05
)


(0.06
)


0.44



0.18



(0.03
)


0.02



(0.10
)


(0.25
)Distributions declared


123



177



196



190



189



188



188



276Per unit

$
0.27


$
0.39


$
0.45


$
0.45


$
0.45


$
0.45


$
0.45


$
0.69ProductionLiquids (bbls/d) (2)


105,296



98,380



95,777



96,317



101,636



104,583



104,070



105,643Natural gas (mmcf/d)


365



394



408



410



411



441



459



447Total (boe/d)


166,148



164,087



163,700



164,587



170,164



178,124



180,601



180,096





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


(2)
Includes crude oil and natural gas liquids.




2010 ANNUAL MD&A 2




Financial Markets





Throughout 2010, the global financial markets experienced signs of recovery but remain volatile due to a slower than expected U.S. economic recovery and ongoing concerns about the sovereign debt of several European countries. This led to financial assistance and fiscal easing measures in the U.S. and Europe in an effort to promote economic growth and job creation. In contrast, Asia and many of the world’s developing economies have returned to growth levels similar to those experienced before the recent economic crisis prompting China, in particular, to begin fiscal tightening measures.





In early 2011, political tension in some North African and Middle Eastern countries resulted in upward pressure on crude oil prices with WTI trading over US$100.00 and Brent trading over US$115.00. Protests and similar activities in these regions have led to concerns regarding the possibility of supply disruptions of crude oil.





The March 11, 2011 earthquake and subsequent tsunami in Japan could impact energy markets. In the near term, demand for LNG and refined products such as heating oil and diesel are expected to increase, while demand for crude oil is expected to decline as significant refining capacity will likely for a time be offline in Japan. Over the longer term, demand for all energy products is expected to increase once the rebuilding process begins.





Commodity Markets





Global demand growth for crude oil exceeded increases in non-OPEC supply in 2010. The high demand from Asia and the developing economies of the world reduced OPEC’s spare capacity resulting in price levels which support capital investment in oil development. This is evidenced by a year-over-year doubling of active rigs targeting oil in the United States. Demand growth for energy in North America and Europe remains weaker than in Asia and the developing economies.





Natural gas demand remained high in Asia and Europe over the past year resulting in premium prices in these markets compared to North America. North American natural gas markets continue to be oversupplied as lower prices have not led to a large enough reduction in drilling activity. Many producers continue to drill to retain their lease rights.





Crude Oil





In 2010, WTI crude oil prices averaged US$79.55 per barrel compared to US$61.93 per barrel in 2009. Canadian producers experienced delays in the second half of 2010 delivering their production to market due to certain pipeline failures that occurred on the Enbridge system. Crude supply continues to be apportioned as Enbridge works to return its pipelines to full operation and reduce high inventory levels resulting from these service interruptions. As a result, it has been challenging for some producers to deliver their production to market and in some situations has resulted in discounting certain Canadian streams and shut-ins of production. It is anticipated that these pipeline capacity issues will be resolved in the upcoming months.





Our average liquids price before the impact of the realized portion of risk management for 2010 was $67.68 per barrel. Currently, we have risk management contracts of 41,000 barrels per day for the remainder of our 2011 crude oil production at average prices between US$79.98 per barrel and US$96.39 per barrel and 25,000 barrels per day of our forecasted 2012 crude oil production between US$84.40 per barrel and US$104.01 per barrel.




2010 ANNUAL MD&A 3





Natural Gas





In 2010, the AECO Monthly Index averaged $4.12 per mcf compared to $4.13 per mcf in 2009. Natural gas prices remained weak throughout 2010 and drilling activity for shale gas, primarily in the U.S., continued notwithstanding the low prices. This drilling activity persisted for several reasons, most notably, producers drilling to retain leases, producers receiving enhanced value from the high natural gas liquids content of some shale gas plays and the infusion of joint venture capital from foreign partners. This led to production rates increasing year-over-year without a significant increase in demand resulting in inventory levels at or near record highs throughout most of 2010. Recent cold weather has contributed to storage levels near the five-year average levels.




Our corporate average natural gas price before the impact of the realized portion of risk management was $4.20 per mcf for 2010. We currently have no natural gas risk management contracts for 2011 or beyond.




Business Strategy




On January 1, 2011, we converted to an exploration and production (“E&P”) company. Moving forward we anticipate a level of return for our shareholders to include an element of both growth and yield.




Over the past few years we have been building towards our corporate conversion and have executed a number of strategies in advance of our conversion date. These strategies include a thorough evaluation of our asset base including our resource plays, acquisition and divestiture activity in order to focus our asset base and to create efficiencies, a build-up of our drilling locations inventory which is now over 8,000 including approximately 3,800 specific locations, the strengthening of our balance sheet through debt reduction, debt diversification and distribution reductions and the enhancement of our staff and technical expertise including exploration, to enable a significant increase to our operating activities.





Throughout 2010, we were active in strengthening our balance sheet and diversifying our debt portfolio along with accessing capital through the close of two strategic joint ventures. We completed transactions to this end including the following:




·
In January, we closed an asset swap (the “January 2010 asset swap”) that increased our position in our Pembina and Dodsland light-oil plays in exchange for certain interests in the Leitchville area. We also received net cash consideration of $434 million, prior to closing adjustments.


·
In March, we completed a private placement of senior unsecured notes with an aggregate principal amount of approximately US$250 million and CAD$50 million.


·
In April, we closed the renewal of our unsecured, revolving syndicated bank facility for three years with an aggregate borrowing amount of $2.25 billion.


·
In June, we formed a joint venture partnership (the “Peace River Oil Partnership”) to develop oil resources in the Peace River area in northern Alberta. As a result of the arrangement, we contributed assets to the partnership for a 55 percent interest and received $817 million which included cash of $312 million and a commitment of $505 million to fund our future capital and operating expenses. In addition, we closed a private placement issuing 23.5 million trust units for gross proceeds of $435 million ($424 million net).


·
In September, we formed a joint venture (the “Cordova Joint Venture”) to develop our unconventional natural gas assets located in northeastern British Columbia. As a result of the arrangement, we sold a 50 percent interest in this property in exchange for approximately $250 million of cash and a commitment from our partner to fund $600 million of the first $800 million of capital expenditures.


·
In December, we closed the first tranche of a private placement of senior unsecured notes with an aggregate principal amount of US$95 million and CAD$60 million. In January 2011, we closed the second tranche of the private placement for US$75 million. The aggregate principal amount of both tranches is approximately US$170 million and CAD$60 million.





In 2011 we plan to allocate approximately 90 percent of our capital program to our significant inventory of light-oil projects. We will continuously evaluate the results of our 2011 capital program and assess areas where the rate of development may be economically increased.




2010 ANNUAL MD&A 4




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 economic viability and the stage of development of our resource plays.


·
Base operations – This includes our production performance and execution of our operational, health, safety, environmental and regulatory programs.


·
Shareholder value measures – This includes key metrics such as funds flow per share and dividends or distributions per share.


·
Financial, business and strategic considerations – This includes the management of our asset base, balance sheet stewardship, execution of financial transactions and the overall goal of creating shareholder value (return on investment).




Finding and Development Costs




Year ended December 312010


2009


2008


3-Year averageAdjusted FD&A including future development costs (“FDC”) (1)FD&A costs per boe – proved plus probable

$
18.12


$
23.77


$
23.38


$
22.81FD&A costs per boe – proved


16.64



15.11



30.78



26.93Excluding FDC (2)F&D costs per boe – proved plus probable


18.90



13.75



18.94



17.40F&D costs per boe – proved


21.50



16.10



27.17



21.49Including FDC (3)F&D costs per boe – proved plus probable


26.73



16.12



24.57



22.90F&D costs per boe – proved

$
28.01


$
16.19


$
31.94


$
25.51





(1)
The calculation of FD&A includes the change in FDC, excluding the effect of economic revisions related to downward revisions of natural gas prices and land acquisition costs.


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


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





Our exploration and development capital program increased during 2010 as we transitioned to an E&P company. We added approximately 72 million boe of proved plus probable reserves (excluding acquisitions and dispositions) as a result of our successful drilling program focused on our light-oil projects.





Thefuture benefit of approximately $640 million raised from joint venture activities, in the form of carried capital, was not included in the Adjusted FD&A calculation, nor was this benefit included in FDC. Capital expenditures for 2010 have been reduced by $17 million related to joint venture carried capital (2009 – nil). We use Adjusted FD&A to assess the economic viability and the stage of development of our resource plays. F&D costs are calculated in accordance with National Instrument 51-101, which include the change in FDC, on a proved and proved plus probable basis. For comparative purposes we also disclose F&D costs excluding FDC.





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


2010 ANNUAL MD&A 5




Base Operations




Throughout 2010, our drilling results were generally consistent with our expectations as we increased our capital plan recognizing our continuing successful results at our light-oil resource plays and in anticipation of our conversion to an E&P company. During the year, we closed two strategic joint venture arrangements, the Peace River Oil Partnership and Cordova Joint Venture, which provide us with significant capital commitments from our partners and allow us to assess the resource potential and move into full-scale development in a shorter time-frame than we previously anticipated.




Shareholder Value Measures




Year ended December 312010


2009


2008Funds flow per unit

$
2.68


$
3.62


$
6.75Distributions paid per unit

$
1.62


$
2.23


$
4.08Ratio of year-end total long-term debt to annual funds flow

2.1:1


2.2:1


1.5:1





To implement our corporate strategy of providing shareholders with a return including both growth and yield, the distribution level was decreased to $0.09 per unit per month effective with the September 2010 distribution paid in October 2010. The funds not distributed will be redeployed to advance the development of our resource plays.





The total long-term debt to annual funds flow ratio decreased in 2010 due to a decline in our long-term debt balance. This was partially offset by a reduction in annual funds flow due to lower production volumes resulting from net dispositions.




Financial, Business and Strategic Considerations




Year ended December 312010


2009


2008Return on capital (1)


3
%


-



15
%Return on equity (2)


3
%


(2
)%


19
%Total assets (millions)

$
13,368


$
13,876


$
15,412





(1) Net income before financing charges divided by average unitholders’ equity and average total debt.


(2) Net income divided by average unitholders’ equity.




The return on capital and return on equity ratios in 2010 increased primarily due to higher net income in 2010 and a reduction in our total debt. During 2010, we significantly reduced the outstanding balance on our syndicated bank facility by executing the January 2010 asset swap, the Peace River Oil Partnership transaction, the Cordova Joint Venture, an equity offering completed in June 2010 to a private investor and by the issuance of senior, unsecured notes. Refer to the Business Strategy section above for more details.




2010 ANNUAL MD&A 6




RESULTS OF OPERATIONS




Production




Year ended December 31Daily production

2010


2009


% changeLight oil and NGL (bbls/d)


80,706



78,011



3Heavy oil (bbls/d)


18,260



25,962



(30
)Natural gas (mmcf/d)


394



440



(10
)Total production (boe/d)


164,633



177,221



(7
)




Our production results for 2010 were strengthened by our successful drilling program. Our focus in 2010 was continuing the development of our key light-oil plays which led to higher light-oil production than the prior year. We drilled 319 net wells in 2010 primarily using horizontal multi-stage fracture technology, compared to 94 net wells in 2009.




The decrease in production volumes from 2009 was mainly due to net property dispositions that included the Lloydminster property disposition completed in November 2009 of approximately 6,000 boe per day, predominantly of heavy oil, the January 2010 asset swap of approximately 2,900 boe per day and the contribution of assets to the Peace River Oil Partnership and Cordova Joint Venture in 2010.




When economic to do so, we strive to maintain a strategic mix of liquids and natural gas production in order to reduce exposure to price volatility that can affect a single commodity. In 2010, crude oil and NGL production averaged 98,966 barrels per day (60 percent of production) and natural gas production averaged 394 mmcf per day (40 percent of production).




Average Sales Prices


Year ended December 312010


2009


% changeLight oil and liquids (per bbl)

$
69.29


$
59.07



17Risk management gain (loss) (per bbl)(1)


(2.72
)


8.19



(100
)Light oil and liquids net (per bbl)


66.57



67.26



(1
)Heavy oil (per bbl)


60.55



53.75



13Natural gas (per mcf)


4.20



4.13



2Risk management gain (per mcf)(1)


0.42



0.69



(39
)Natural gas net (per mcf)


4.62



4.82



(4
)Weighted average (per boe)


50.74



44.11



15Risk management gain (loss) (per boe)(1)


(0.34
)


5.32



(100
)Weighted average net (per boe)

$
50.40


$
49.43



2





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




2010 ANNUAL MD&A 7





Netbacks




Year ended December 312010


2009


% changeLight oil and NGL(1)Production (bbls/day)


80,706



78,011



3Operating netback (per bbl):Sales price

$
69.29


$
59.07



17Risk management gain (loss) (2)


(2.72
)


8.19



(100
)Royalties


(13.73
)


(10.78
)


27Operating costs


(19.83
)


(19.93
)


(1
)Netback

$
33.01


$
36.55



(10
)Heavy oilProduction (bbls/day)


18,260



25,962



(30
)Operating netback (per bbl):Sales price

$
60.55


$
53.75



13Royalties


(8.73
)


(7.26
)


20Operating costs


(17.14
)


(15.54
)


10Transportation


(0.09
)


(0.06
)


50Netback

$
34.59


$
30.89



12Total liquidsProduction (bbls/day)


98,966



103,973



(5
)Operating netback (per bbl):Sales price

$
67.68


$
57.74



17Risk management gain (loss) (2)


(2.22
)


6.14



(100
)Royalties


(12.81
)


(9.90
)


29Operating costs


(19.33
)


(18.83
)


3Transportation


(0.02
)


(0.01
)


100Netback

$
33.30


$
35.14



(5
)Natural gasProduction (mmcf/day)


394



440



(10
)Operating netback (per mcf):Sales price

$
4.20


$
4.13



2Risk management gain (2)


0.42



0.69



(39
)Royalties


(0.58
)


(0.75
)


(23
)Operating costs


(1.71
)


(1.57
)


9Transportation


(0.22
)


(0.21
)


5Netback

$
2.11


$
2.29



(8
)Combined totalsProduction (boe/day)


164,633



177,221



(7
)Operating netback (per boe):Sales price

$
50.74


$
44.11



15Risk management gain (loss) (2)


(0.34
)


5.32



(100
)Royalties


(9.07
)


(7.66
)


18Operating costs


(15.71
)


(14.93
)


5Transportation


(0.55
)


(0.52
)


6Netback

$
25.07


$
26.32



(5
)





(1)
Excluded from the netback calculation is $5 million of realized risk management gains related to our foreign exchange contracts which swap US dollar revenue at a fixed Canadian dollar rate.


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





2010 ANNUAL MD&A 8





Production Revenues




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


Year ended December 31(millions)

2010


2009


2008Light oil and NGL

$
1,965


$
1,920


$
2,465Heavy oil


405



509



747Natural gas


664



774



1,439Gross revenues(1)

$
3,034


$
3,203


$
4,651





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




The decrease in revenue for 2010 from 2009 was mainly the result of lower realized risk management gains and the impact of net property dispositions which reduced production of heavy oil and natural gas. Light oil and NGL production increased, notwithstanding the January 2010 asset swap, as we focused our 2010 capital program on light-oil resource plays. For 2010, heavy oil production was 30 percent lower and natural gas production was 10 percent lower than 2009.




The decrease in gross revenues for 2009 from the comparative period in 2008 was mainly the result of lower commodity prices coupled with lower production volumes as we concentrated our asset base.




Reconciliation of decrease in Production Revenues





(millions)Gross revenues – January 1 – December 31, 2009

$
3,203Increase in light oil and NGL production


66Decrease in light oil and NGL prices (including realized risk management)


(21
)Decrease in heavy oil production


(151
)Increase in heavy oil prices


47Decrease in natural gas production


(80
)Decrease in natural gas prices (including realized risk management)


(30
)Gross revenues – January 1 – December 31, 2010

$
3,034





Royalties




Year ended December 312010


2009


2008Royalties (millions)

$
545


$
495


$
898Average royalty rate (1)


18
%


17
%


18
%$/boe

$
9.07


$
7.66


$
12.95





(1)
Excludes effects of risk management activities.





In 2010, royalty rates and per boe amounts increased as a result of higher crude oil prices. Our royalty rate trended downward throughout 2010 due to new wells coming on production at a lower royalty rate under the new provincial royalty programs.





Royalty rates decreased in 2009 compared to 2008 due to the effect of the new Alberta royalty programs that became effective for part of 2009. The royalties per boe amount decreased as a result of lower royalty payments due to lower commodity prices.




2010 ANNUAL MD&A 9




Expenses





Year ended December 31(millions)

2010


2009


2008Operating

$
944


$
966


$
854Transportation


33



34



34Financing


174



161



204Unit-based compensation

$
55


$
52


$
45





Year ended December 31(per boe)

2010


2009


2008Operating

$
15.71


$
14.93


$
12.31Transportation


0.55



0.52



0.49Financing


2.89



2.49



2.94Unit-based compensation

$
0.92


$
0.81


$
0.65




Operating




In 2010, acquisition and divestiture activity contributed to an increase in the operating costs per boe.  Operating costs for 2010 include a realized loss on electricity contracts of $14 million (2009 - $16 million loss and 2008 - $6 million gain).We have contracts in place that fix the price on approximately 90 percent of our electricity consumption for 2011 at US$63.16 per MWH.




The rise in operating costs in 2009 compared to 2008 was due to greater 2009 emphasis on production maintenance activities to maintain production volumes. Due to the weak commodity price environment early in 2009, we reduced our capital program during that year and focused on highly efficient methods of maintaining production.




Financing




The Company has a three-year, unsecured, revolving syndicated bank facility with an aggregate borrowing limit of $2.25 billion. The facility expires on April 30, 2013 and is extendible. The credit facility contains provisions for stamping fees on bankers’ acceptances and LIBOR loans and standby fees on unutilized credit lines that vary depending on certain consolidated financial ratios. As at December 31, 2010, approximately $0.8 billion was drawn under this facility.




As at December 31, 2010, the Company had $1.7 billion of senior unsecured notes outstanding as follows:





Issue date

Amount (millions)

Term
Average

interest rate
Weighted average

remaining term2007 Notes
May 31, 2007

US$475

8 – 15 years
5.80 percent
6.5 years2008 Notes
May 29, 2008

US$480, CAD$30

8 – 12 years
6.25 percent
7.0 yearsUK Notes
July 31, 2008

£57

10 years
6.95 percent (1)
7.6 years2009 Notes
May 5, 2009

US$154, £20,€10, CAD$5

5 – 10 years
8.85 percent (2)
6.0 years2010Q1 Notes
March 16, 2010

US$250, CAD$50

5 – 15 years
5.47 percent
7.8 years2010Q4 Notes(3)
December 2, 2010

US$95, CAD$60

5 – 15 years
4.96 percent
9.8 years





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


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


(3)
An additional US$75 million of proceeds were received in January 2011 which completed the private placement closing.





2010 ANNUAL MD&A 10





On March 16, 2010, the Company closed the private placement of the 2010 Q1 Notes with an aggregate principal amount of approximately US$250 million and CAD$50 million. The 2010 Q1 Notes had an original weighted average term of 8.6 years and bear a weighted average fixed interest rate of approximately 5.47 percent. The Company used the proceeds of the issue to repay advances on its syndicated bank facility.





In January 2011, the Company completed a closing of a private placement, the 2010 Q4 Notes, with an aggregate principal amount of approximately US$230 million. The 2010 Q4 Notes had an original weighted average term of 10.8 years and bear a weighted average fixed interest rate of approximately 5.00 percent. The Company used the proceeds of the issue to repay advances on its syndicated bank facility.





At December 31, 2010, the Company had the following interest rate swaps outstanding:




Effective date
Termination date
Initial term

Nominal amount

(millions)


Fixed rate

(percent)December 2008
December 2011
3 years

$
500



1.61January 2009
January 2014
5 years

$
600



2.71June 2010
January 2014
3.5 years

$
50



1.94





The interest rates on any non-hedged portion of the Company’s bank debt are subject to fluctuations in short-term money market rates as advances on the bank facility are generally made under short-term instruments. As at December 31, 2010, none (2009 – 14 percent) of our long-term debt instruments were exposed to changes in short-term interest rates. On December 31, 2010, our fixed interest rate debt (including the effects of interest rate swaps) had a weighted average rate of approximately 5.70 percent (2009 – 4.57 percent).





Financing charges for 2010 are higher year-over-year due to a higher percentage of our debt capital being held in senior unsecured notes compared to the prior period as well as the increased cost of borrowing with the new bank facility. The Company’s senior unsecured notes contain higher interest rates than the syndicated bank facilities held in short-term money market instruments. Notwithstanding the current interest rate differentials, we believe the long-term and fixed interest rates inherent in the senior notes is favourable for a portion of our debt capital structure.





Realized gains and losses on the interest rate swaps are recorded as financing costs. For 2010 an expense of $21 million (2009 – $21 million and 2008 – nil) was recognized in financing expense to reflect that the floating interest rate was lower than the fixed interest rate transacted under our financial instruments.





Unit-Based Compensation





Unit-based compensation expense is related to our Trust Unit Rights Incentive Plan (“TURIP”) and our Long-Term Retention and Incentive Plan (“LTRIP”) as described in Note 13 to our audited consolidated financial statements. The LTRIP was implemented in the first quarter of 2010. Compensation expense related to the TURIP is based on the fair value of trust unit rights issued, determined using a Binomial Lattice option-pricing model. The fair value of TURIP rights issued is amortized over the remaining vesting periods on a straight-line basis and is allocated to operating and general and administrative expense as applicable. The intrinsic cost of the LTRIP is charged to income based on our unit price at the end of each reporting period plus accumulated dividends or distributions multiplied by the number of LTRIP awards outstanding. The LTRIP obligation is accrued over the vesting period as service is completed by employees and is allocated to operating and general and administrative expense as applicable based on a graded vesting schedule. Subsequent increases and decreases in the underlying unit price will result in increases and decreases, respectively, to the underlying LTRIP obligation until settlement.




2010 ANNUAL MD&A 11





Year ended December 31(millions)

2010


2009


2008TURIPOperating expense

$
11


$
13


$
11General and administrative expense


36



39



34LTRIPOperating expense


4



-



-General and administrative expense


4



-



-Unit-based compensation expense

$
55


$
52


$
45




The unit price used in the LTRIP intrinsic cost calculation at December 31, 2010 was $23.84 (2009 and 2008 – N/A).




General and Administrative Expenses (“G&A”)




Year ended December 31(millions, except per boe amounts)

2010


2009


2008Gross

$
203


$
189


$
195Per boe


3.38



2.93



2.81Net (including unit-based compensation)


181



168



158Per boe


3.00



2.59



2.29Net (excluding unit-based compensation)


141



129



124Per boe

$
2.34


$
1.99


$
1.80





We increased our complement of technical staff and consolidated our employees into one building prior to our conversion to an E&P company which led to higher staff and building occupancy costs in 2010 compared to 2009. The increase in the cost per boe in 2010 was due to higher costs and lower production volumes during the year from net property dispositions.





For 2009, the increase in the net cost per boe compared to 2008 was primarily due to lower overhead recoveries from the reduced capital expenditure program during 2009 and lower production volumes.





Depletion, Depreciation and Accretion (“DD&A”)




Year ended December 31(millions, except per boe amounts)

2010


2009


2008Depletion of oil and natural gas assets

$
1,293


$
1,514


$
1,556Accretion of asset retirement obligation


45



42



38Total DD&A

$
1,338


$
1,556


$
1,594DD&A expense per boe

$
22.27


$
24.04


$
22.98





DD&A for 2010 decreased compared to the prior year as a result of the contribution of assets into the Peace River Oil Partnership and Cordova Joint Venture and lower production volumes due to net property dispositions.





During 2009, Penn West had F&D costs which were lower than the historical DD&A rate, however, property dispositions that were completed in 2009 led to an increase in the rate compared to 2008.




2010 ANNUAL MD&A 12




Taxes




Year ended December 31(millions)

2010


2009


2008Future income tax (recovery) expense

$
(319
)

$
(378
)

$
135





The 2010 amount included a $177 million recovery related to corporate restructuring. The comparative figure in 2009 included a $168 million recovery related to unrealized risk management losses and a $65 million recovery related to income tax legislation enacted by the Government of Canada which reduced the provincial component of the Specified Investment Flow-Through (“SIFT”) tax rate from 13 percent to 10 percent. The expense in 2008 included a tax charge of $198 million related to unrealized risk management gains in 2008.





Under the income trust structure which we operated in until December 31, 2010, the operating entities made interest and royalty payments to the Trust, which transferred taxable income to the Trust level, eliminating income subject to corporate income taxes in the operating entities. The Trust eliminated its taxable income, in part, by deducting distributions paid to its unitholders. Under the SIFT legislation, enacted in June 2007, and which became effective on January 1, 2011 distributions are no longer tax deductible by certain income trusts.





On January 1, 2011, we converted into a publicly-traded corporation. In 2011 and beyond, we are now subject to current and future income taxes at Canadian corporate rates. As the currently legislated SIFT rates are comparable to corporate tax rates, we do not anticipate our conversion to an E&P company to result in a significant adjustment to our existing future tax liability under Canadian GAAP.





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





Tax Pools





As at December 31(millions)

2010


2009


2008Undepreciated capital cost (UCC)

$
1,122


$
1,379


$
1,394Canadian oil and gas property expense (COGPE)


1,564



1,912



2,496Canadian development expense (CDE)


1,494



1,141



1,243Canadian exploration expense (CEE)


305



280



60Non-capital losses


2,481



2,139



1,646Other


31



16



18Total

$
6,997


$
6,867


$
6,857




Tax pool amounts exclude income deferred in operating partnerships of $920 million in 2010 (2009 - $931 million and 2008 - $885 million).




Foreign Exchange




Year ended December 31(millions)

2010


2009


2008Unrealized foreign exchange (gain) loss

$
(82
)

$
(186
)

$
203





We record unrealized foreign exchange gains or losses to translate the U.S., UK and Euro notes and the related accrued interest to Canadian dollars using the exchange rates in effect on the balance sheet date. The gains during 2010 and 2009 were primarily due to the strengthening of the Canadian dollar relative to the US dollar. The loss in 2008 was due to a stronger US dollar compared to the prior year.




2010 ANNUAL MD&A 13




Funds Flow and Net Income (Loss)




Year ended December 312010


2009


2008Funds flow (1)(millions)

$
1,185


$
1,493


$
$2,537Basic per unit


2.68



3.62



6.75Diluted per unit


2.65



3.60



6.66Net income (loss) (millions)


226



(144
)


1,221Basic per unit


0.51



(0.35
)


3.25Diluted per unit

$
0.50


$
(0.35
)

$
3.22





(1)
Funds flow is a non-GAAP measure. See “Calculation of Funds Flow”.





Funds flow in 2010 was lower than 2009 primarily as a result of net property dispositions and lower realized risk management gains. The 2009 comparative figure also includes the monetization of foreign exchange contracts for a gain of $75 million. Net income for 2010 was higher than 2009 primarily due to higher oil and natural gas revenues and lower unrealized risk management losses.





The decline in funds flow realized in 2009 compared to 2008 was primarily the result of lower revenue due to lower commodity prices. The reduction in net income during 2009 from 2008 was the result of lower revenues resulting from lower commodity prices and unrealized risk management losses.





Year ended December 312010


2009


2008per boe


%


per boe


%


per boe


%Oil and natural gas revenues (1)

$
50.46



100


$
50.67



100


$
67.06



100Royalties


(9.07
)


(18
)


(7.66
)


(15
)


(12.95
)


(19
)Operating expenses (2)


(15.71
)


(31
)


(14.93
)


(30
)


(12.31
)


(18
)Transportation


(0.55
)


(1
)


(0.52
)


(1
)


(0.49
)


(1
)Net operating income


25.13



50



27.56



54



41.31



62General and administrative expenses


(2.34
)


(5
)


(1.99
)


(4
)


(1.80
)


(3
)Financing (3)


(2.89
)


(6
)


(2.49
)


(5
)


(2.94
)


(4
)Funds flow


19.90



39



23.08



45



36.57



55Unrealized foreign exchange gain (loss)


1.36



3



2.88



6



(2.92
)


(5
)Unit-based compensation


(0.92
)


(2
)


(0.81
)


(2
)


(0.65
)


(1
)Risk management activities (4)


0.40



1



(9.17
)


(18
)


9.53



14Depletion, depreciation and accretion


(22.27
)


(44
)


(24.04
)


(47
)


(22.98
)


(34
)Future income tax recovery (expense)


5.30



10



5.84



12



(1.95
)


(3
)Net income (loss)

$
3.77



7


$
(2.22
)


(4
)

$
17.60



26





(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.




2010 ANNUAL MD&A 14




Capital Expenditures





Year ended December 31(millions)

2010


2009


2008Land acquisition and retention

$
102


$
19


$
128Drilling and completions


800



286



529Facilities and well equipping


281



336



407Geological and geophysical


10



9



13Corporate


11



38



18Capital expenditures


1,204



688



1,095Joint venture, carried capital


(17
)


-



-Capital expenditures, net

$
1,187


$
688


$
1,095





Total expenditures


Year ended December 31(millions)

2010


2009


2008Capital expenditures

$
1,204


$
688


$
1,095Property dispositions, net


(1,306
)


(369
)


(50
)Business combinations


139



116



5,525Total expenditures

$
37


$
435


$
6,570





During 2010, we increased our capital spending compared to 2009 to take advantage of success at our light-oil resource plays and in preparation for our conversion to an E&P company. This resulted in an increase in drilling and completions expenditures year-over-year. Our focus throughout 2010 was to continue to advance the appraisal of our key light-oil plays in the Cardium, the Colorado, the Carbonates and Waskada.




For 2010, $89 million was capitalized (2009 - $26 million disposed and 2008 - $25 million capitalized) for additions to asset retirement obligations from our capital program and property acquisitions, net of property dispositions, and changes to our future cost estimates.





Drilling





Year ended December 312010


2009Gross


Net


Gross


NetOil


351



245



102



68Natural gas


53



38



40



17Dry


3



2



2



2407



285



144



87Stratigraphic and service


54



34



11



7Total


461



319



155



94Success rate(1)






99
%






98
%





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




2010 ANNUAL MD&A 15




January 2010 Asset Swap





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





Peace River Oil Partnership





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





Cordova Joint Venture





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





Sifton Energy Inc. (“Sifton”) acquisition





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





Reece Energy Exploration Corp (“Reece”) Acquisition





On April 30, 2009, we closed the acquisition of Reece, an oil and gas exploration company. The acquisition was completed through a Plan of Arrangement wherein Reece shareholders received 0.125 of a Penn West trust unit for each Reece share. The total acquisition cost was approximately $101 million, which included the assumption of approximately $42 million of debt and working capital. The transaction added production of approximately 1,900 boe per day and 67,000 net acres of undeveloped land, the majority of which complements our Dodsland light-oil resource play in Southern Saskatchewan.





Goodwill





Year ended December 31(millions)
2010

2009

2008Balance, beginning of year

$
2,020


$
2,020


$
652Acquisitions


-



-



1,368Balance, end of year

$
2,020


$
2,020


$
2,020





We recorded goodwill on our acquisitions of Petrofund Energy Trust, Canetic Resources Trust and Vault Energy Trust. We determined there was no goodwill impairment at December 31, 2010.





2010 ANNUAL MD&A 16





Business Risks





The disclosures under this heading (excluding the information under environmental and climate change risk), in conjunction with Note 10 to the audited consolidated financial statements, are incorporated into and are an integral part of the audited consolidated financial statements.





We are exposed to normal market risks inherent in the oil and natural gas business, including, but not limited to, commodity price risk, foreign currency risk, credit risk, interest rate risk, liquidity risk and environmental and climate change risk. We seek to mitigate these risks through various business processes and management controls and from time to time by using financial instruments.





For a summary of outstanding financial instruments, please refer to “Financial Instruments” later in this MD&A and to Note 10 to our audited consolidated financial statements.





Commodity Price Risk





Commodity price fluctuations are among our most significant exposures. Crude oil prices are influenced by worldwide factors such as OPEC actions, world supply and demand fundamentals, and geopolitical events. Natural gas prices are influenced by the price of alternative fuel sources such as oil or coal and by North American natural gas supply and demand fundamentals including the levels of industrial activity, weather, storage levels and liquefied natural gas activity. In accordance with policies approved by our Board of Directors, we may, from time to time, manage these risks through the use of swaps, collars or other financial instruments up to a maximum of 50 percent of forecast sales volumes, net of royalties, for the balance of any current year plus one additional year forward and up to a maximum of 25 percent, net of royalties, for one additional year thereafter.





Foreign Currency Rate Risk





Prices received for crude oil are referenced to or denominated directly in US dollars, thus our realized oil prices are impacted by Canadian dollar to US dollar exchange rates. A portion of our debt capital is denominated in US dollars, thus the principal and interest payments in Canadian dollars are also impacted by exchange rates. When we consider it appropriate, we may use financial instruments to fix or collar future exchange rates to fix the Canadian dollar equivalent of crude oil revenues or to fix US denominated long-term debt principal repayments. At December 31, 2010, we had the following foreign currency forward contracts outstanding:





Initial Term
Nominal Amount

(millions)
Termination date
Exchange rate19-month term
Sell US$378
December 2011
1.06085 CAD/USD8-year term
Buy US$80
May 2015
1.01027 CAD/USD10-year term
Buy US$80
May 2017
1.00016 CAD/USD12-year term
Buy US$70
May 2019
0.99124 CAD/USD15-year term
Buy US$20
May 2022
0.98740 CAD/USD




At December 31, 2010, we had US dollar denominated debt with a face value of US$1.2 billion (2009 - US$0.9 billion) on which the repayment of the principal amount in Canadian dollars was not fixed.




2010 ANNUAL MD&A 17





Credit Risk




Credit risk is the risk of loss if purchasers or counterparties do not fulfill their contractual obligations. Our accounts receivable are principally with customers in the oil and natural gas industry and are generally subject to normal industry credit risk, which includes the ability to recover unpaid receivables by retaining the partner’s share of production when we are the operator. For oil and natural gas sales and financial derivatives, we follow a counterparty risk procedure whereby each counterparty is reviewed on a regular basis for the purpose of assigning a credit limit and may be requested to provide security if determined to be prudent. For financial derivatives, we normally transact with counterparties who are members of our banking syndicate or other counterparties that have investment grade bond ratings. We monitor credit events related to all counterparties and reassess credit exposures on a regular basis. As necessary, provisions for potential credit related losses are recognized.





As at December 31, 2010, the maximum exposure to credit risk was $386 million (2009 - $371 million) being the carrying value of the accounts receivable.




Interest Rate Risk




We currently maintain a portion of our debt capital in floating-rate bank facilities which results in exposure to fluctuations in short-term interest rates which remain at lower levels than longer-term rates. From time to time, we may increase the certainty of our future interest rates by entering fixed interest rate debt instruments or by using financial instruments to swap floating interest rates for fixed rates or to collar interest rates.  As at December 31, 2010, none of our long-term debt instruments were exposed to changes in short-term interest rates (2009 – 14 percent).





As at December 31, 2010, we had a total of $1.7 billion of fixed interest rate debt instruments and $0.3 billion of convertible debentures outstanding. On the fixed interest rate debt the average remaining term was 7.2 years (2009 – 7.7 years) with an average interest rate of 5.7 percent (2009 – 4.6 percent), including the effects of interest rate swaps. For further details on these instruments, refer to the “Financing” and “Convertible Debentures” sections in this MD&A.





Liquidity Risk





Liquidity risk is the risk that we will be unable to meet our financial liabilities as they come due. Management utilizes short and long-term financial and capital forecasting programs to ensure credit facilities are sufficient relative to forecast debt levels, dividend and capital program levels are appropriate, and that financial covenants will be met. Management also regularly reviews capital markets to identify opportunities to optimize the debt capital structure on a cost effective basis. In the short term, liquidity is managed through daily cash management activities, short-term financing strategies and the use of collars and other financial instruments to increase the predictability of cash flow from operating activities. Additional information on specific instruments is discussed in Notes 7 and 8 to the audited consolidated financial statements.





The following table outlines estimated future contractual obligations for non-derivative financial liabilities as at December 31, 2010:





(millions)

2011


2012


2013


2014


2015


ThereafterBank debt

$
-


$
-


$
773


$
-


$
-


$
-Senior unsecured notes


-



-



5



60



251



1,407Convertible debentures


255



-



-



-



-



-Accounts payable


743



-



-



-



-



-Distributions payable


41



-



-



-



-



-Total

$
1,039


$
-


$
778


$
60


$
251


$
1,407




2010 ANNUAL MD&A 18




Environmental and Climate Change Risk




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





We are dedicated to reducing the environmental impact from our operations through our environmental programs which include resource conservation, stakeholder communication, CO2 sequestration, water management and site abandonment/reclamation. We continuously monitor our operations to minimize the environmental impact from our operations, allocate sufficient capital to reclamation and other activities and are committed to mitigating the impact in the areas in which we operate.




Liquidity and Capital Resources




Capitalization




As at December 312010


2009


2008(millions)

%


%


%Trust units issued, at market (1)

$
10,959



78


$
7,821



69


$
5,245



54Long-term debt


2,496



18



3,219



28



3,854



40Convertible debentures – long term


255



2



255



2



289



3Working capital deficiency(2)


311



2



106



1



270



3Total enterprise value

$
14,021



100


$
11,401



100


$
9,658



100





(1)
The unit price at December 31, 2010 was $23.84 (2009 - $18.55 and 2008 - $13.57).


(2)
Excludes the current portion of risk management, future income taxes and convertible debentures.





During 2010, we paid total distributions of $708 million (2009 – $910 million and 2008 – $1,500 million) including amounts funded by the distribution reinvestment plan. In preparation for our conversion to an E&P company, we reduced our distribution level to $0.09 per unit, per month during 2010.





The decline in long-term debt in 2010 was mainly due to repayments made on our syndicated bank facility using proceeds received from the January 2010 asset swap, cash received upon closing of the Peace River Oil Partnership transaction and the Cordova Joint Venture and an equity offering completed in June 2010 to a private investor. On April 30, 2010, the Company closed the renewal of its unsecured, revolving, syndicated bank facilities with an aggregate borrowing limit of $2.25 billion and as of December 31, 2010 had approximately $1.5 billion of unused credit capacity available. For further details on these debt instruments, please refer to the “Financing” and “Convertible Debentures” sections of this MD&A.





We actively manage our debt portfolio and consider opportunities to reduce or diversify our debt structure. We have an active risk management program to limit our exposure to certain risks and maintain close relationships with our lenders and agents to monitor credit market developments. These actions 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 the longer-term execution of our business strategies.




2010 ANNUAL MD&A 19





The Company has a number of covenants related to its syndicated bank facility and senior, unsecured notes. On December 31, 2010, the Company was in compliance with all of these financial covenants which comprise the following:


Limit

December 31, 2010Senior debt to EBITDA
Less than 3:1


1.84Total debt to EBITDA
Less than 4:1


1.86Senior debt to capitalization
Less than 50 percent


23
%Total debt(1)to capitalization
Less than 55 percent


23-25
%





(1)
The definitions of Total debt differ slightly among the agreements in relation to convertible debentures.





As at December 31, 2010, all senior, unsecured notes, except for the 2007 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. Our conversion to a corporation did not trigger a change in control under the note agreements. As of January 1, 2011, upon completion of our corporate conversion, all note agreements now have change of control provisions.





As an income trust, we paid distributions in cash as the Trust was required to make distributions to unitholders in amounts at least equal to its taxable income; however, the amount of taxable income allocated to the Trust from the operating entities was subject to management’s discretion. Beginning on January 1, 2011, under our new corporate structure,the amount of future cash dividends may vary depending on a variety of factors and conditions which can include fluctuations in commodity markets, production levels and capital expenditure requirements. Our dividend level could change based on these and other factors and is subject to the discretion of our Board of Directors.





Due to the extent of our environmental programs, we believe no benefit would arise from the initiation of a reclamation fund. We believe our program will be sufficient to meet or exceed existing environmental regulations and best industry practices. In the event of significant changes to the environmental regulations or the cost of environmental activities, a higher portion of funds flow would be required to fund our environmental obligations.





Convertible Debentures





During 2010, $18 million of convertible debentures matured and were settled in units (2009 – $7 million), none were redeemed and settled in units (2009 – $12 million) and none were redeemed and settled in cash (2009 – $4 million).





We have the option of settling the convertible debentures in cash or equity. At December 31, 2010, the balance of our unsecured, subordinated convertible debentures outstanding was as follows:


Description of security

Outstanding

(millions)

Maturity

date

Conversion

price

(per unit)

Redemption prices

(per $1,000 face value)PWT.DB.E

7.2% Convertible

$
26

May 31,

2011

$
75.00

$1,025 May 31, 2010 to maturityPWT.DB.F

6.5% Convertible extendible


229

Dec. 31,

2011

$
51.55

$1,025 Dec. 31, 2010 to maturityTotal

$
255




2010 ANNUAL MD&A 20




Standardized Distributable Cash




Year ended December 31(millions, except per unit amounts)

2010


2009


2008Cash flow from operating activities

$
1,217


$
1,401


$
2,256Productive capacity maintenance(1)


(1,187
)


(688
)


(1,095
)Standardized distributable cash


30



713



1,161Proceeds from the issue of trust units (2)


676



393



246Debt and working capital changes


(20
)


(265
)


143Cash distributions declared

$
686


$
841


$
1,550Accumulated cash distributions, beginning


4,501



3,660



2,110Accumulated cash distributions, ending

$
5,187


$
4,501


$
3,660Standardized distributable cash per unit, basic


0.07



1.73



3.09Standardized distributable cash per unit, diluted


0.07



1.72



3.03Standardized distributable cash payout ratio(3)


22.87



1.18



1.34Distributions declared per unit

$
1.56


$
2.04


$
4.08Net income as a percentage of cash distributions declared


33
%


N/A



79
%Cash flows from operating activities as a percentage of cash distributions declared


177
%


167
%


146
%





(1)
Please refer to our discussion of productive capacity maintenance below.


(2)
Consists of proceeds from the Distribution Reinvestment and Optional Purchase Plan, the Trust Unit Rights Incentive Plan, the Employee Retirement Savings Plan and equity issuances completed in February 2009 and June 2010.


(3)
Represents cash distributions declared divided by standardized distributable cash.





(millions, except ratios)

To December 31, 2010Cumulative standardized distributable cash from operations (1)

$
3,467Issue of trust units


1,605Debt and working capital changes


115Cumulative cash distributions declared(1)

$
5,187Standardized distributable cash payout ratio(2)


1.50





(1)
Subsequent to the trust conversion on May 31, 2005.


(2)
Represents cumulative cash distributions declared divided by cumulative standardized distributable cash.





Productive capacity maintenance is the estimated amount of capital funds required in a period for an enterprise to maintain future cash flows from operating activities at a constant level. As commodity prices can be volatile and short-term variations in production levels are often experienced in our industry, we define our productive capacity as production on a barrel of oil equivalent basis. A quantifiable measure for these short-term variations is not objectively determinable or verifiable due to various factors including the inability to distinguish natural production declines from the effect of production additions resulting from capital and optimization programs, and the effect of temporary production interruptions. As a result, the adjustment for productive capacity maintenance in our calculation of standardized distributable cash is our capital expenditures during the period excluding the cost of any asset acquisitions or proceeds of any asset dispositions.





Our calculation of standardized distributable cash has no adjustment for long-term unfunded contractual obligations. We believe our only significant long-term unfunded contractual obligation at this time is for asset retirement obligations. Cash flow from operating activities, used in our standardized distributable cash calculation, includes a reduction for abandonment expenditures incurred during each period. We believe that our current environmental programs will be sufficient to fund our asset retirement obligations over the life of our reserves. We currently have no financing restrictions caused by our debt covenants. We regularly monitor our current and forecast debt levels to ensure debt covenants are not exceeded.




2010 ANNUAL MD&A 21




Financial Instruments





We had the following financial instruments outstanding as at December 31, 2010. Fair values are determined using external counterparty information which is compared to observable market data. We limit our credit risk by executing counterparty risk procedures which include transacting only with institutions within our credit facility or with high credit ratings and by obtaining financial security in certain circumstances.





Notional

volume


Remaining

term


Pricing


Fair valueCrude oilWTI Collars

35,000 bbls/d


Jan/11 – Dec/11


US$80.06 to $91.98/bbl


$
(70
)WTI Collars

15,000 bbls/d


Jan/12 – Dec/12


US$83.67 to $96.32/bbl



(17
)Electricity swapsAlberta Power Pool

90 MW


Jan/11 – Dec/11


$63.16/MWh



(10
)Alberta Power Pool

45 MW


Jan/12 – Dec/12


$53.02/MWh



(2
)Alberta Power Pool

30 MW


Jan/12 – Dec/13


$54.60/MWh



(1
)Alberta Power Pool

20 MW


Jan/13 – Dec/13


$56.10/MWh



-Alberta Power Pool

50 MW


Jan/14 – Dec/14


$58.50/MWh



(2
)Interest rate swaps$500


Jan/11 – Dec/11



1.61%



(1
)$600


Jan/11 – Jan/14



2.71%



(13
)$50


Jan/11 – Jan/14



1.94%



-Foreign exchange forwards19-month term

US$378


Jan/11 – Dec/11


1.06085 CAD/USD



238-year term

US$80



2015


1.01027 CAD/USD



110-year term

US$80



2017


1.00016 CAD/USD



112-year term

US$70



2019


0.99124 CAD/USD



115-year term

US$20



2022


0.98740 CAD/USD



-Cross currency swaps10-year term

£57



2018


2.0075 CAD/GBP, 6.95%



(28
)10-year term

£20



2019


1.8051 CAD/GBP, 9.15%



(6
)10-year term

€10



2019


1.5870 CAD/EUR, 9.22%



(2
)Total













$
(126
)





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





In 2011, we entered into crude oil collars for 6,000 barrels per day for the period of March 2011 to December 2011 at US$79.50 per barrel to US$122.13 per barrel and on 10,000 barrels per day for 2012 at US$85.50 per barrel to US$115.56 per barrel. Additionally in 2011, Penn West entered into foreign exchange forward contracts to fix approximately $128 million of future US denominated senior, unsecured note repayments at an exchange rate of 1.0150 CAD/USD.




2010 ANNUAL MD&A 22





Outlook




This outlook section is included to provide shareholders with information about our expectations as at March 17, 2011 for production and capital expenditures for 2011 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 disclaimers under "Forward-Looking Statements".




Based on an average crude oil price of WTI US$80.00 per barrel and an average natural gas price of $4.70 per mcf, we expect our 2011 exploration and development capital program to be in the range of approximately $1.1-$1.2 billion. We are focusing our 2011 capital program on our suite of large-scale light-oil plays including the Cardium, the Colorado, the Carbonates and Waskada. Based on this level of capital expenditures, we continue to forecast 2011 average production to be approximately 172,000 to 177,000 boe per day.




There have been no changes from our prior forecast for 2011 released on February 17, 2011 with our 2010 fourth quarter results and filed on SEDAR at www.sedar.com.




Sensitivity Analysis




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


Impact on funds flowChange of:

Change


$ millions


$/sharePrice per barrel of liquids

$
1.00



19



0.04Liquids production

1,000 bbls/day



17



0.04Price per mcf of natural gas

$
0.10



12



0.03Natural gas production

10 mmcf/day



7



0.01Effective interest rate


1
%


4



0.01Exchange rate ($US per $CAD)

$
0.01



21



0.05




2010 ANNUAL MD&A 23




Contractual Obligations and Commitments




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





(millions)

2011


2012


2013


2014


2015


ThereafterLong-term debt

$
-


$
-


$
778


$
60


$
251


$
1,407Transportation


26



15



14



9



5



-Transportation ($US)


4



4



4



4



4



-Power infrastructure


30



10



10



10



10



14Drilling rigs


9



5



3



1



-



-Purchase obligations (1)


13



13



13



11



10



8Interest obligations


154



138



119



106



96



270Office lease (2)


71



68



66



61



60



539Asset retirement obligations(3)

$
65


$
62


$
59


$
57


$
54


$
356





(1)
These amounts represent estimated commitments of $51 million for CO2 purchases and $17 million for processing fees related to interests in the Weyburn Unit.


(2)
Future office lease commitments will be reduced by sublease recoveries totalling $413 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 April 30, 2013. If we are not successful in renewing or replacing the facility, we could be required to repay all amounts then outstanding on the facility or enter other loans including term bank loans. In addition, we have an aggregate of $1.7 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.





Convertible debentures with an aggregate principal amount of $255 million were outstanding on December 31, 2010 (2009 - $273 million). A significant portion of the interest payable on convertible debentures may, at our option, be settled by the issuance of shares. As at March 17, 2011, convertible debentures with an aggregate principal amount of $249 million were outstanding. For a schedule of convertible debenture maturities, please refer to the “Convertible Debentures” section of this MD&A or Note 8 to the audited consolidated financial statements.




2010 ANNUAL MD&A 24





Equity Instruments


Trust units issued:Trust units as at December 31, 2010


459,682,249Trust units cancelled on January 1, 2011


(459,682,249
)As at January 1, 2011


-Common shares issued:Issuance of common shares on January 1, 2011


459,682,249Issued on exercise of options


3,114,236Issued on exercise of common share rights


330,920Issued on settlement of restricted rights


8,848Issued pursuant to dividend reinvestment plan


299,097As at March 17, 2011


463,435,350Trust unit rights outstanding:Trust unit rights outstanding as at December 31, 2010


31,365,478Trust unit rights cancelled on January 1, 2011


(31,365,478
)As at January 1, 2011


-Options outstanding:Issuance on January 1, 2011


27,586,712Granted


6,587,773Exercised


(3,114,236
)Forfeited


(187,245
)As at March 17, 2011


30,873,004Common share rights outstanding:Issuance on January 1, 2011


3,778,766Exercised


(330,920
)Forfeited


(50,851
)As at March 17, 2011


3,396,995





On January 1, 2011, we completed the previously announced Plan of Arrangement which resulted in our conversion to a publicly traded E&P company.Based on the Plan of Arrangement trust units were exchanged for common shares on a one-to-one basis. Additionally, as a result of the conversion the TURIP was amended and electing holders of trust unit rights received an option and a restricted right; those not electing received a common share right. These instruments were issued under our Stock Option Plan and our Common Share Rights Incentive Plan; please refer to our Information Circular and Proxy Statement dated November 10, 2010 related to our corporate conversion for more information.




2010 ANNUAL MD&A 25




Fourth Quarter 2010 Highlights




Key financial and operational results for the fourth quarter 2010 were as follows:




Three months ended December 312010


2009


% changeFinancial

(millions, except per unit amounts)Gross revenues (1)

$
782


$
831



(6
)Funds flow


305



366



(17
)Basic per unit


0.67



0.87



(23
)Diluted per unit


0.66



0.86



(23
)Net loss


(21
)


(12
)


75Basic per unit


(0.05
)


(0.03
)


67Diluted per unit


(0.05
)


(0.03
)


67Distributions paid (2)


123



189



(35
)Capital expenditures, net

$
400


$
196



100OperationsDaily productionLight oil and NGL (bbls/d)


88,447



77,627



14Heavy oil (bbls/d)


16,849



24,009



(30
)Natural gas (mmcf/d)


365



411



(11
)Total production (boe/d)


166,148



170,164



(2
)Average sales priceLight oil and NGL (per bbl)

$
71.05


$
69.49



2Heavy oil (per bbl)


61.87



62.97



(2
)Natural gas (per mcf)

$
3.79


$
4.39



(14
)Netback per boeSales price

$
52.43


$
51.19



2Risk management gain (loss)


(1.51
)


1.89



(100
)Net sales price


50.92



53.08



(4
)Royalties


(9.14
)


(9.35
)


(2
)Operating expenses


(15.92
)


(15.10
)


5Transportation


(0.52
)


(0.52
)


-Netback

$
25.34


$
28.11



(10
)





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


(2)
Includes distributions paid that were subsequently reinvested in trust units under the distribution reinvestment plan.





Financial





Gross revenues were lower in the fourth quarter of 2010 compared to 2009 primarily due to lower realized risk management gains in the period. This also resulted in a reduction of funds flow in the fourth quarter of 2010 compared to 2009.





The increase in net loss from the prior period was primarily due to a lower future income tax recovery in 2010 in comparison to 2009.





During the fourth quarter of 2010, we increased our capital spending recognizing successful results to-date at our light-oil resource plays and in advance of our conversion to an E&P company. For the fourth quarter of 2010, we drilled 116 net wells (2009 – 25) which included 93 net oil wells, 13 net natural gas wells and 10 net stratigraphic and service wells. The majority of these wells drilled in 2010 were horizontal multi-stage fracture wells located in our key light-oil resource plays.




2010 ANNUAL MD&A 26




Operations





Production was 166,148 boe per day in the fourth quarter of 2010. Our light-oil production volumes increased in the fourth quarter of 2010 compared to 2009, due to our concentrated capital program on our key light-oil resource plays. Exit production at December 31, 2010 was approximately 167,100 boe per day. Apportionment issues on certain Enbridge pipelines reduced year-end exit production by approximately 1,900 boe per day.





WTI crude oil prices averaged US$85.18 per barrel in the fourth quarter of 2010, an increase from WTI US$76.21 per barrel in the third quarter of 2010 and WTI US$76.17 per barrel in the fourth quarter of 2009. During the fourth quarter of 2010, the AECO Monthly Index averaged $3.58 per mcf compared to $3.72 per mcf in the third quarter of 2010 and $4.23 per mcf in the fourth quarter of 2009.





Netbacks were $25.34 per boe compared to $28.11 per boe in the fourth quarter of 2009. The decline was primarily due to realized risk management losses.





Disclosure Controls and Procedures





As of December 31, 2010, an internal evaluation was carried out under the supervision of our 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. Based on that evaluation, the CEO and the CFO concluded that as of December 31, 2010 the disclosure controls and procedures were effective to provide reasonable assurance that the information required to be disclosed in the reports that Penn West files or submits under the Exchange Act or under Canadian securities legislation is recorded, processed, summarized and reported, within the time periods specified in the rules and forms therein. Disclosure controls and procedures include, without limitation, controls and procedures designed to ensure that the information required to be disclosed by Penn West in the reports that it files or submits under the Exchange Act or under Canadian securities legislation is accumulated and communicated to the Trust’s management, including the senior executive and financial officers, as appropriate to allow timely decisions regarding the required disclosure.





Internal Control over Financial Reporting (“ICOFR”)





We have a team of qualified and experienced staff who continue to maintain our compliance with the applicable regulations regarding internal control over financial reporting (“ICOFR”). We became a registrant under the U.S. Securities Exchange Act of 1934 and listed our trust units on the New York Stock Exchange in June 2006. As of December 31, 2010, 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 US Securities Exchange Act of 1934 and as defined in Canada by National Instrument 52-109, Certification of Disclosure in Issuers’ Annual and Interim Filings. 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, 2010 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 2010 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, 2010 that have materially affected, or are reasonably likely to materially affect, our ICOFR.




2010 ANNUAL MD&A 27





Future Accounting Pronouncements




Implementation of International Financial Reporting Standards




In January 2006, the Canadian Accounting Standards Board (the “AcSB”) announced its decision to replace Canadian GAAP with International Financial Reporting Standards (“IFRS”) for all Canadian Publicly Accountable Enterprises (“PAEs”), including Penn West. On February 13, 2008, the AcSB confirmed January 1, 2011 as the changeover date for PAEs to commence reporting under IFRS. Although IFRS is principles-based and uses a conceptual framework similar to Canadian GAAP, there are significant differences and choices in accounting policies, as well as increased disclosure requirements under IFRS.




IFRS 1 – Oil and Gas Exemption





In July 2009, the International Accounting Standards Board (“IASB”) issued amendments to IFRS 1 “First-time adoption of IFRS” allowing additional exemptions for first-time adopters. Under these amendments, full cost oil and natural gas companies can elect to use the recorded amount under a previous GAAP as the deemed cost for oil and gas assets on the transition date to IFRS. We have elected to utilize this exemption.




Project Status





In 2008, we began our IFRS conversion project and assembled a project team and steering committee to ensure successful implementation within the required timeframe. Members selected for this team have expertise in a number of areas including; accounting, financial reporting, information technology, internal controls, investor relations, project management, taxation and treasury. These members and other finance and operational staff and members of our Board of Directors have received ongoing training related to IFRS. The project team and steering committee provide updates to senior management and the Audit Committee on a regular basis. Our changeover project consists of three main phases:





Diagnostic phase – This phase involved the identification of key differences between Canadian GAAP and IFRS. This phase began in 2008 and was completed in 2009.





Design and implementation phase – This phase has focused on accounting policy decisions and modifications to IT systems and accounting processes. As decisions are made during this phase we have and will continue to review our internal controls over financial reporting and disclosure controls and procedures and make modifications as required. We started this phase in 2009 and are currently close to completion.





Completion phase – This phase involves the final review of accounting policy choices, internal control changes, full implementation of IT processes and the conversion of financial statement balances and comparative figures to IFRS. We began this phase in early 2010 with the implementation of our IT process. Additionally, we advanced work on our January 1, 2010 transition date balance sheet during the fourth quarter of 2010. We will be continuing to work through this phase into 2011 prior to filing our first set of quarterly financial statements under IFRS being the first quarter of 2011, expected in early May 2011.





Fourth quarter of 2010 update – Throughout the fourth quarter we focused on advancing our work on our transition date balance sheet under IFRS. Any amendments to existing IFRS standards or implementation of new IFRS standards could lead to additional changes as we progress into 2011.




2010 ANNUAL MD&A 28





Significant Accounting Differences and Expected Accounting Policies





Component accounting – Under IFRS, depletion and depreciation of property, plant and equipment (“PP&E”) will be based on significant components.We currently expect these components to consist of oil and natural gas assets, facilities, turnarounds and corporate assets.





Depletion and depreciation – Under Canadian GAAP, PP&E is generally depleted based on aggregations at the country level using the full cost method of accounting for oil and natural gas activities. Depletion of resource properties and facilities will generally continue to be calculated using the unit-of-production method; however, under IFRS there is an option to use production volumes before royalties on total proved reserves or total proved plus probable reserves. Depreciation of other assets can be calculated on a straight-line basis over their estimated useful life, rather than on a unit-of-production basis. We anticipate depleting our resource properties on a proved plus probable reserve basis using forecast prices.





Exploration and evaluation (“E&E”) assets – Oil and natural gas properties will be classified as either PP&E or E&E. Under Canadian GAAP, oil and gas assets are only classified as PP&E.E&E assets will consist of capital costs related to prospective assets for which the technical and commercial viability of extracting oil and natural gas has not yet been ascertained. These assets will initially be measured at cost and classified according to the nature of the associated expenditures.





E&E cost transfers – E&E costs will be reclassified to PP&E when proved reserves have been assigned to the asset, to the extent they are not impaired. If proved reserves will not be established through the completion of E&E activities and there are no future plans for development activity, then the E&E expenditures will be assessed for impairment. Any impairments will be charged to income.





Impairment of oil and natural gas properties – Under IFRS, impairment testing will be performed at a lower level than under current Canadian GAAP.  As a consequence, impairment provisions are more likely to occur as properties will no longer be tested only at the country level. Under IFRS, impairments other than goodwill impairments may be reversed in the event future conditions change.





Trust unit rights classification – Under Canadian GAAP, trust unit rights are classified as equity instruments. Under IFRS, trust units carry a number of features that could result in either equity or liability treatment. Under IFRS “puttable financial instruments” with characteristics similar to ordinary shares are treated as equity instruments. We completed an analysis and concluded that our trust units receive equity classification.





Share-based payments – Under Canadian GAAP, share-based payments are classified as equity awards and are accordingly expensed using the straight-line method. Under IFRS, our equity awards meet the definition of a puttable financial instrument, thus the awards are considered a liability and expensed on a graded vesting schedule.





Asset retirement obligations (“ARO”) or decommissioning provisions – Under Canadian GAAP, ARO is recorded if there is a legal obligation to abandon. Under IFRS, ARO is recorded if there is either a legal or constructive obligation to abandon.





ARO discounting – Discount rates used to calculate ARO are under review by our project team as there is currently diversity in practice when selecting a rate. As a result of using the deemed cost exemption, we are required to offset any changes to our ARO through retained earnings on the transition date. Under Canadian GAAP, we use a credit adjusted discount rate to calculate the obligation.





Future (deferred) income tax – Under Canadian GAAP, the rate used to calculate future income tax is based on a corporate average rate. Under IFRS, as a result of receiving a deduction for our distribution payments, the rate used in the future income tax calculation is based on the undistributed rate which is higher than the corporate rate.




2010 ANNUAL MD&A 29




January 1, 2010 Opening Balance Sheet Adjustments





E&E assets – We anticipate the reclassification of approximately $130 million of PP&E into E&E. Additionally, we anticipate recording approximately $50 million related to land currently considered non-prospective as a charge to retained earnings on January 1, 2010.





Impairment of oil and natural gas properties – On January 1, 2010, we expect no impairments to be recorded.





Share-based payments – In order to remove the equity treatment under Canadian GAAP and set-up the liability treatment under IFRS, we anticipate the removal of contributed surplus amounts related to stock-based compensation under Canadian GAAP of $123 million and the recognition of a unit rights liability under IFRS of approximately $70 million.





ARO –In our transition date balance sheet, we expect to record an additional provision as a result of the constructive obligations related to our pipelines. This additional provision will vary depending on the discount rate used. Additionally, a reduction from the credit-adjusted discount rate used to calculate ARO could lead to a material increase in the recorded asset retirement obligation in our transition date balance sheet.





Future (deferred) income tax – On January 1, 2010, we anticipate an increase in our future income tax liability by approximately $410 million with an offsetting charge to retained earnings due to the requirement to record future income taxes at the rate applicable to undistributed income on future income tax assets and liabilities at the income trust level. As we paid distributions throughout 2010 and upon conversion to a corporation on January 1, 2011, we expect that thischarge will be reversed. Future income taxes under IFRS will also be adjusted for any changes to the recorded ARO, and other changes to the January 1, 2010 Opening Balance Sheet.





Current IASB Projects





The IASB currently has two projects in exposure draft form which could affect our reported financial position. The first relates to “Joint Arrangements” which outlines the appropriate accounting for joint operations, joint assets and joint ventures. Depending on the criteria, joint arrangements could be subject to either proportionate consolidation or equity accounting. This could affect the accounting for our interest in the Peace River Oil Partnership which is currently proportionately consolidated under Canadian GAAP. The standard is expected to be finalized in 2011. Additionally, in August 2010 the IASB and FASB issued an exposure draft related to “Leases” which eliminates the concept of operating leases, thereby classifying many leases as finance leases. This would require a lessee to record both a “right-of-use” asset and an obligation based on the present value of future lease payments along with increased disclosure requirements. Currently, the target date for this standard is mid-2011 with the effective date to follow. We are currently determining the effect of these exposure drafts.





IFRS impacts related to our corporate conversion





Future Income Tax





Under Canadian GAAP, there are no material changes to our future income tax balances as a result of our conversion to a corporation.





Effective January 1, 2010, as an income trust under IFRS, we are required to measure future income tax assets and liabilities at the Trust level at a tax rate of 39 percent, representing the tax rate applicable to undistributed profits of the Trust in the Province of Alberta. Future income tax will be recorded on this basis from January 1, 2010 until our conversion to a corporation on January 1, 2011. Under IFRS, upon conversion to a corporation, the future income tax assets and liabilities will be re-measured at the applicable corporate income tax rate of approximately 25 percent. We anticipate this re-measurement will result in a reduction of recorded future income taxes of approximately $300 - $350 million during the first quarter of 2011.




2010 ANNUAL MD&A 30




Stock-Based Compensation





Under IFRS, the exchange of trust units for common shares generally results in a shift from the liability treatment of a stock-based compensation award to equity treatment as the common shares are not considered puttable financial instruments. The recorded liability for equity awards will be reclassified to equity.





Effective January 1, 2011, we amended our TURIP and implemented a Stock Option Plan whereby TURIP holders could have elected to receive an option (a “Restricted Option”) and a right (a “Restricted Right”) for outstanding “in-the-money” TURIP rights. TURIP right holders who made the election have the choice to settle the Restricted Right in cash or shares upon exercise. For those TURIP holders who chose not to make the election or for TURIP rights that were “out-of-the money” on January 1, 2011, holders received a common share right under the Common Share Rights Incentive Plan (the “CSRIP”), which replaced the TURIP.





Under IFRS, Restricted Options and options issued under the CSRIP will be measured at fair value on January 1, 2011, the date of issuance, and will receive equity treatment. The fair value will be amortized as compensation expense over the expected vesting period of the award based on a graded vesting schedule.





The Restricted Right will be accounted for as a liability as holders may elect to settle the right in cash. Compensation expense will be based on the fair value method. The Restricted Rights will be expensed over the remaining life based on a graded vesting schedule.





Related-Party Transactions





During 2010, we incurred $2 million (2009 – $2 million) of legal fees from a law firm of which a partner is also a director of Penn West.





Off-Balance-Sheet Financing





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





Critical Accounting Estimates





Our significant accounting policies are detailed in Note 2 to the audited consolidated financial statements under Canadian GAAP. In the determination of financial results, we must make certain critical accounting estimates as follows:





Full Cost Accounting





We use the full cost method of accounting for oil and natural gas properties. All costs of exploring for and 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 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 engineering firms. Our reserves are determined in compliance with National Instrument 51-101. The evaluation of oil and natural gas reserves is, by its nature, based on complex extrapolations and models as well as other significant engineering, reservoir, capital, pricing and cost assumptions. Reserve estimates are a key component in the calculation of depletion and are a key component of value in the ceiling test. To the extent that the ceiling amount, based in part on our reserves, is less than the carrying amount of property, plant and equipment, a write-down against income must be made. We determined there was no ceiling test write-down required at December 31, 2010.




2010 ANNUAL MD&A 31




Asset Retirement Obligations





The discounted expected future cost of statutory, contractual or legal obligations to retire long-lived assets is recorded as an asset retirement liability with a corresponding increase to the carrying amount of the related asset. The recorded liability increases over time to its future liability amount through accretion charges to income, included in DD&A. Revisions to the estimated amount or timing of the obligations are reflected as increases or decreases to the recorded asset retirement obligation. Actual asset retirement 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 9 to the audited consolidated financial statements details the impact of these accounting standards.




Financial Instruments





Financial instruments included in the balance sheets consist of accounts receivable, fair values of derivative financial instruments, current liabilities, convertible debentures and long-term debt. Except for the senior notes and the convertible debentures, 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 and the convertible debentures is disclosed in Notes 7 and 8 to the audited consolidated financial statements.





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





Substantially all of our accounts receivable are with customers in the oil and natural gas industry and are subject to normal industry credit risk. We may, from time to time, use various types of financial instruments to reduce our exposure to fluctuating oil and natural gas prices, electricity costs, exchange rates and interest rates. The use of these financial instruments exposes us to credit risks associated with the possible non-performance of counterparties to the derivative contracts. We limit this risk by executing counterparty risk procedures which include transacting only with financial institutions who are members of our credit facility or those with high bond 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. The goodwill impairment test consists of two parts. Under part 1, if the fair value of the reporting entity is less than its book value, part 2 of the test must be performed. The part 2 test compares the implied fair value of the goodwill to its carrying amount; if the carrying amount of goodwill exceeds the implied fair value an impairment loss is recorded. Penn West determined there was no goodwill impairment at December 31, 2010.





Future Income Tax





Future income taxes are recorded based on the asset and liability method of accounting whereby temporary differences are calculated assuming financial assets and liabilities will be settled at their carrying amount. Future income 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.




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Forward-Looking Statements





In the interest of providing our securityholders and potential investors with information regarding the Company, 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: our belief that the earthquake and subsequent tsunami in Japan could impact energy markets, including a near term increase in demand for LNG and refined products, a near term decrease in demand for crude oil, and a long term increase in demand for all energy products; our belief that the delays that certain Canadian producers (including us) experienced in the second half of 2010 delivering certain of their production to market due to pipeline failures that occurred on the Enbridge system and resulting pipeline capacity issues will be resolved in the upcoming months; our anticipation that moving forward our shareholders will experience a level of return that includes an element of both growth and yield; the identification of over 8,000 drilling locations on our existing lands, including approximately 3,800 specific locations; the ability of our business strategies to enable a significant increase in our operating activities; our intention to allocate approximately 90 percent of our 2011 capital program to our light-oil projects; our intention to continuously evaluate the results of our 2011 capital program and assess areas where the rate of development may be economically increased; the ability of the Peace River Oil Partnership and the Cordova Joint Venture to allow us to assess the resource potential of the relevant assets and move into full-scale development of such assets in a shorter time-frame than we previously anticipated; our ability to execute on our corporate strategy of providing shareholders with a return including both growth and yield; our intention to redeploy funds not distributed to shareholders as a result of our most recent distribution decrease to advance the development of our resource plays;our objective to maintain a strategic mix of liquids and natural gas production in order to reduce exposure to price volatility that can effect a single commodity; our forecast that based on current commodity prices and capital spending plans, we could use our tax pools to shelter our taxable income for an extended period; the identity of our primary business risks going forward and the nature and effectiveness of our risk management strategies relating thereto, as more particularly described under "Business Risks"; the ability of our debt portfolio management program and our risk management program to increase the likelihood that we can maintain our financial flexibility to capture opportunities available in the markets in addition to the continuation of our capital and dividend programs and the longer-term execution of our business strategies; the factors that may affect the amount of future cash dividends that we pay; our belief that our environmental programs will be sufficient to meet or exceed existing environmental regulations and best industry practices; our belief that our only significant long-term unfunded contractual obligation at this time is for asset retirement obligations; our belief that our current environmental programs will be sufficient to fund our asset retirement obligations over the life of our reserves; the disclosure set out under the heading "Outlook", which sets forth management's expectations as to our exploration and development capital expenditure levels for 2011, the identity of the light-oil plays on which the 2011 capital program will focus, and our forecast average daily production for 2011; the disclosure contained under the heading "Sensitivity Analysis" relating to the estimated sensitivity to selected key assumptions of our reported financial results during 2011; and our identification of the significant accounting differences between our current accounting policies under Canadian GAAP and our expected accounting policies under IFRS and our expectations regarding the impact of those changes on our historical and future financial results and financial statements (including in relation to our corporate conversion).





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




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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, including the completed acquisitions discussed herein; geological, technical, drilling and processing problems; general economic conditions in Canada, the U.S. and globally; industry conditions, including fluctuations in the price of oil and natural gas; royalties payable in respect of our oil and natural gas production and changes thereto; changes in government regulation of the oil and natural gas industry, including environmental regulation; fluctuations in foreign exchange or interest rates; unanticipated operating events that can reduce production or cause production to be shut-in or delayed; failure to obtain industry partner and other third-party consents and approvals when required; stock market volatility and market valuations; OPEC's ability to control production and balance global supply and demand of crude oil at desired price levels; political uncertainty, including the risks of hostilities, in the petroleum producing regions of the world; the need to obtain required approvals from regulatory authorities from time to time; failure to realize the anticipated benefits of dispositions, acquisitions, joint ventures and partnerships, including the completed dispositions, acquisitions, joint ventures and partnerships discussed herein; changes in tax and other laws that affect us and our securityholders; changes in government royalty frameworks; uncertainty of obtaining required approvals for acquisitions and mergers; the potential failure of counterparties to honour their contractual obligations; and the other factors described under "Business Risks" in this document and in our public filings (including our Annual Information Form) available in Canada at www.sedar.com and in the United States at www.sec.gov. Readers are cautioned that this list of risk factors should not be construed as exhaustive.





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





Additional Information





Additional information relating to Penn West including Penn West’s Annual Information Form, is available on SEDAR at www.sedar.com.




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