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Penn West Announces Its Results for the Fourth Quarter Ended December 31, 2010

Feb 17, 2011

CALGARY, ALBERTA--(Feb. 17, 2011) - PENN WEST EXPLORATION (TSX:PWT) (NYSE:PWE) is pleased to announce its results for the fourth quarter ended December 31, 2010

As we move forward as an exploration and production ("E&P") company, our objective is to deliver both growth and dividends to our shareholders. To this end, our aim in 2010 was to appraise the potential of our light-oil resource plays and to position other significant Penn West resources for future large-scale development using joint ventures. We believe we are well positioned as we increase our capital focus on the key strengths of our asset base.

Financial Results

- Funds flow (1) of $305 million in the fourth quarter of 2010 increased 14 percent from the $267 million realized in the third quarter of 2010. Basic funds flow increased to $0.67 per unit (1) in the fourth quarter of 2010 from $0.59 per unit in the third quarter of 2010, primarily from higher production and crude oil prices.

- Funds flow for 2010 totalled $1,185 million compared to $1,493 million in 2009 reflecting the sale of properties and lower realized risk management gains.

- Net income for 2010 totalled $226 million ($0.51 per unit-basic) compared to a net loss of $144 million ($0.35 per unit-basic) in 2009 as a result of higher oil and natural gas revenues and lower unrealized risk management losses.

- Net debt (1) was reduced by approximately $536 million (2) during 2010 to $3.1 billion at December 31, 2010 due to the proceeds received from an asset exchange, an equity issue, the Peace River Oil Partnership transaction and the Cordova Joint Venture.

- The netback (1) of $25.34 per boe in the fourth quarter of 2010 was 10 percent higher than the third quarter of 2010 mainly due to stronger crude oil prices.

Operations

- Our results to date from appraising our large, light-oil resource plays are generally on-track with our expectations and led us to increase our activity levels as we move into 2011.

- In 2010, we drilled 319 net wells, including 245 net oil wells, 38 net natural gas wells and 34 net stratigraphic and service wells.

- Fourth quarter 2010 production increased to 166,148 boe (3) per day from 164,087 boe per day in the third quarter of 2010 reflecting drilling success. Production for the fourth quarter included 88,447 barrels per day of light oil and NGLs, 16,849 barrels per day of heavy oil and 365 mmcf per day of natural gas.

- Production for 2010 averaged 164,633 boe per day. 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.

- Capital expenditures, net, for 2010 totalled $1,187 million including $102 million of strategic land acquisitions. Capital expenditures, net, were $400 million in the fourth quarter of 2010 compared to $196 million in the fourth quarter of 2009. We began escalating drilling levels in the fall of 2010 and have further increased activity during the first quarter of 2011.

(1) The terms "funds flow", "funds flow per unit-basic", "netback" and "net debt" are non-GAAP measures. Please refer to the "Calculation of Funds Flow", "Highlights - Netback per boe", "Results of Operations - Netbacks" and "Non-GAAP Measures Advisory" sections below.

(2) Consists of the change in long-term debt, convertible debentures and working capital (excluding future income taxes and risk management). Please refer to the Consolidated Balance Sheets below.

(3) Please refer to the "Oil and Gas Information Advisory" section below for information regarding the term "boe".

- We continue to appraise the resource potential of our extensive portfolio. We are the most active driller in the Western Canadian Sedimentary Basin with 31 rigs currently running.

- The Enbridge apportionment issues continue to the present. In early January 2011, issues at a partner operated gas facility in the Swan Hills area resulted in the loss of approximately 3,500 boe per day. We are optimistic our production will be restored in the near future. Penn West is maintaining original guidance in the range of 172,000 - 177,000 boe per day as we are confident that we can overcome the shortfalls that have been beyond our control.

Reserves Highlights

- Total working interest proved reserves were 481 mmboe and total working interest proved plus probable reserves were 661 mmboe at December 31, 2010, weighted approximately 70 percent to crude oil and liquids and 30 percent to natural gas.

- Adjusted finding, development and acquisition costs ("FD&A") (1) on a proved plus probable basis, including the change in future development capital were $18.12 per boe for 2010 (2009 - $23.77 per boe).

- In 2010, we added approximately 72 million boe of reserves on a proved plus probable basis with approximately 68 percent related to crude oil and liquids.

2011 Capital Strategy

- As we move into 2011, we will continue our focus on light-oil appraisal and full-scale development. Our exploration and development capital program for 2011 will be approximately 90 percent focused on light-oil projects using horizontal multi-stage fracture technology. We will continue to evaluate ongoing drilling results with a concentration on projects with the size and potential to drive growth in both production and reserves.

- The 2011 capital program will focus on our large resource plays in the Cardium in Alberta, the Colorado Viking in Alberta and Saskatchewan, Waskada in Manitoba and the Carbonates in northern Alberta. The 2011 plan also includes accelerating the appraisal of our heavy oil interests in the Peace River Oil Partnership and our unconventional natural gas assets located in the Cordova Embayment.

Risk Management Activity

- Since September 30, 2010, we entered into additional crude oil collars on 20,000 barrels per day for 2012 at US$84.25 per barrel to US$98.45 per barrel.

Dividends

- We have adopted a dividend policy with an expected initial quarterly dividend of $0.27 per share. The dividend is subject to the approval of our Board of Directors based on the outlook for commodity prices, production levels and planned capital programs. We anticipate the first quarterly dividend to be declared payable on April 15, 2011 to shareholders of record on March 31, 2011.

Corporate Update

- On January 1, 2011, we converted to a growth oriented, dividend paying, E&P company. We now operate under the trade name Penn West Exploration.

- On January 4, 2011, we completed the closing of a private placement of notes for a principal amount of approximately US$230 million with an average term of 10.8 years and an average interest rate of 5.00 percent.

- On January 26, 2011, due to our corporate conversion, we announced our offer to repurchase all of our outstanding convertible debentures. Debenture holders are entitled to receive cash consideration based on the offer prices with the offer closing on March 3, 2011. At January 26, 2011, we had approximately $255 million of convertible debentures outstanding.

(1) Refer to "finding and development costs" table below for discussion on Adjusted FD&A.



HIGHLIGHTS
Three months ended Year ended
December 31 December 31
----------------------------------------------------
% %
2010 2009 change 2010 2009 change
----------------------------------------------------------------------------
Financial
(millions, except
per unit amounts)
Gross revenues
(1) $ 782 $ 831 (6) $ 3,034 $ 3,203 (5)
Funds flow 305 366 (17) 1,185 1,493 (21)
Basic per unit 0.67 0.87 (23) 2.68 3.62 (26)
Diluted per unit 0.66 0.86 (23) 2.65 3.60 (26)
Net income (loss) (21) (12) 75 226 (144) 100
Basic per unit (0.05) (0.03) 67 0.51 (0.35) 100
Diluted per unit (0.05) (0.03) 67 0.50 (0.35) 100
Capital
expenditures, net
(2) 400 196 100 1,187 688 73
Long-term debt at
period-end 2,496 3,219 (22) 2,496 3,219 (22)
Convertible
debentures 255 273 (7) 255 273 (7)
Distributions
paid (3) $ 123 $ 189 (35) $ 708 $ 910 (22)

Payout ratio (4) 40% 52% (12) 60% 61% (1)
Operations
Daily average
production
Light oil and NGL
(bbls/d) 88,447 77,627 14 80,706 78,011 3
Heavy oil
(bbls/d) 16,849 24,009 (30) 18,260 25,962 (30)
Natural gas
(mmcf/d) 365 411 (11) 394 440 (10)
----------------------------------------------------------------------------
Total production
(boe/d) 166,148 170,164 (2) 164,633 177,221 (7)
----------------------------------------------------------------------------
Average sales
price
Light oil and NGL
(per bbl) $ 71.05 $ 69.49 2 $ 69.29 $ 59.07 17
Heavy oil (per
bbl) 61.87 62.97 (2) 60.55 53.75 13
Natural gas (per
mcf) 3.79 4.39 (14) 4.20 4.13 2
Netback per boe
Sales price $ 52.43 $ 51.19 2 $ 50.74 $ 44.11 15
Risk management
gain (loss) (1.51) 1.89 (100) (0.34) 5.32 (100)
----------------------------------------------------------------------------
Net sales price 50.92 53.08 (4) 50.40 49.43 2
Royalties (9.14) (9.35) (2) (9.07) (7.66) 18
Operating
expenses (15.92) (15.10) 5 (15.71) (14.93) 5
Transportation (0.52) (0.52) - (0.55) (0.52) 6
----------------------------------------------------------------------------
Netback $ 25.34 $ 28.11 (10) $ 25.07 $ 26.32 (5)
----------------------------------------------------------------------------

(1) Gross revenues include realized gains and losses on commodity contracts.
(2) Excludes net proceeds on property acquisitions and dispositions and
business combinations.
(3) Includes distributions paid prior to those reinvested in trust units
under the distribution reinvestment plan.
(4) Payout ratio is calculated as distributions paid divided by funds flow.
The term "payout ratio" is a non-GAAP measure. See "Non-GAAP Measures
Advisory" section below.


DRILLING PROGRAM
Three months ended Year ended
December 31 December 31
---------------------------------------------------
2010 2009 2010 2009
---------------------------------------------------
Gross Net Gross Net Gross Net Gross Net
----------------------------------------------------------------------------
Oil 134 93 33 19 351 245 102 68
Natural gas 15 13 8 5 53 38 40 17
Dry 1 - 1 1 3 2 2 2
----------------------------------------------------------------------------
150 106 42 25 407 285 144 87
Stratigraphic and service 16 10 3 - 54 34 11 7
----------------------------------------------------------------------------
Total 166 116 45 25 461 319 155 94
----------------------------------------------------------------------------
Success rate (1) 100% 96% 99% 98%
----------------------------------------------------------------------------

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

 



Our 2010 drilling program focused on our large, light-oil resource plays throughout western Canada. We significantly increased our 2010 drilling activity in anticipation of our conversion to a corporation and drilled 319 net wells compared to 94 net wells in 2009. We utilized horizontal multi-stage fracture technology on substantially all of our wells drilled during 2010, excluding stratigraphic and service wells.



LAND
As at December 31
-------------------------------------------------------
Producing Non-producing
-------------------------------------------------------
% %
2010 2009 change 2010 2009 change
----------------------------------------------------------------------------
Gross acres (000s) 6,354 6,016 6 3,012 3,106 (3)
Net acres (000s) 4,185 4,047 3 2,093 2,425 (14)
Average working
interest 66% 67% (1) 69% 78% (9)
----------------------------------------------------------------------------

 



The decline in net acres of non-producing land compared to 2009 was primarily the result of the contribution of assets into the Peace River Oil Partnership, the Cordova Joint Venture and land lease expiries.



CORE AREA ACTIVITY
Net wells drilled Total land
for the year ended as at December 31, 2010
Core Area December 31, 2010 (thousands of net acres)
----------------------------------------------------------------------------
Central 54 1,578
Eastern 94 604
Northern 8 779
North West Alberta 34 1,281
Southern 129 2,036
----------------------------------------------------------------------------
319 6,278
----------------------------------------------------------------------------


TRUST UNIT DATA
Three months ended Year ended
December 31 December 31
------------------------------------------------------
% %
(millions of units) 2010 2009 change 2010 2009 change
----------------------------------------------------------------------------
Weighted average
Basic 457.0 420.7 9 441.8 412.9 7
Diluted 457.0 420.7 9 447.6 412.9 8
Outstanding as at
December 31 459.7 421.6 9
----------------------------------------------------------------------------

 



During the second quarter of 2010, we completed a private placement issuing 23.5 million trust units to our partner in the Peace River Oil Partnership.

RESERVE DATA

a) Working Interest Reserves using forecast prices and costs



----------------------------------------------------------------------------
Penn West as at
December 31, 2010
Natural
Reserve Light & Gas Barrels of
Estimates Medium Oil Heavy Oil Natural Gas Liquids Oil Equivalent
Category (1)(2) (mmbbl) (mmbbl) (bcf) (mmbbl) (mmboe)
----------------------------------------------------------------------------
Proved
Developed producing 203 51 735 21 398
Developed
non-producing 5 2 47 1 16
Undeveloped 51 1 83 2 68
----------------------------------------------------------------------------
Total proved 259 54 865 24 481
Probable 94 14 370 9 180
----------------------------------------------------------------------------
Total proved
plus probable 353 68 1,235 33 661
----------------------------------------------------------------------------

(1) Working interest reserves are before royalty burdens and exclude royalty
interests.
(2) Columns may not add due to rounding.

b) Net after Royalty Interest Reserves using forecast prices and costs

----------------------------------------------------------------------------
Penn West as at
December 31, 2010
Natural
Reserve Light & Gas Barrels of
Estimates Medium Oil Heavy Oil Natural Gas Liquids Oil Equivalent
Category (1)(2) (mmbbl) (mmbbl) (bcf) (mmbbl) (mmboe)
----------------------------------------------------------------------------

Proved
Developed
producing 175 45 646 15 343
Developed
non-producing 4 1 39 1 13
Undeveloped 44 1 73 2 58
----------------------------------------------------------------------------
Total proved 223 47 758 17 414
Probable 79 13 320 7 151
----------------------------------------------------------------------------
Total proved
plus probable 302 60 1,078 24 565
----------------------------------------------------------------------------

(1) Net after royalty reserves are working interest reserves including
royalty interests and deducting royalty burdens.
(2) Columns may not add due to rounding.

 



Our proved reserves continue to reflect a high percentage of developed reserves. Of total proved reserves, 86 percent were developed at December 31, 2010 compared to 88 percent at December 31, 2009. At December 31, 2010 total proved reserves as a percentage of proved plus probable reserves were 73 percent consistent with the prior year. In 2010, all of our reserves were evaluated or audited by independent engineering firms GLJ Petroleum Consultants Ltd. ("GLJ") or Sproule Associates Limited ("SAL"). Approximately 10 percent of total proved plus probable reserves were internally evaluated and audited by our independent qualified reserve evaluators.

GLJ and SAL are our independent qualified reserves evaluators. The reserves estimates have been calculated in compliance with the National Instrument 51-101 Standards of Disclosure for Oil and Gas Activities ("NI 51-101"). Under NI 51-101, proved reserves estimates are defined as having a high degree of certainty with a targeted 90 percent probability in aggregate that actual reserves recovered over time will equal or exceed proved reserve estimates. For proved plus probable reserves under NI 51-101, the targeted probability is an equal (50 percent) likelihood that the actual reserves to be recovered will be equal to or greater than the proved plus probable reserves estimate. The reserves estimates set forth above are estimates only and there is no guarantee that the estimated reserves will be recovered. Actual reserves may be greater than or less than the estimates provided herein.

Additional reserve disclosures, as required under NI 51-101, will be contained in our Annual Information Form that will be filed on SEDAR at www.sedar.com.

c) Reconciliation of Working Interest Reserves using forecast prices and costs



Light and Medium Oil and
Natural Gas Liquids Heavy Oil
(mmbbl) (mmbbl)
-------------------------------------------------------------
Proved Proved
Reconciliation plus plus
Items (1) Proved Probable probable Proved Probable probable
----------------------------------------------------------------------------
December 31,
2009 285 116 401 56 15 71
Extensions 15 6 21 - - -
Improved
Recovery 2 (1) 1 1 - 1
Infill Drilling 9 5 14 1 - 1
Technical
Revisions 10 (3) 7 2 - 2
Discoveries - - - - - -
Acquisitions 10 4 13 3 2 5
Dispositions (18) (22) (41) (3) (2) (4)
Economic Factors (1) - (1) (1) (1) (2)
Production (29) - (29) (7) - (7)
----------------------------------------------------------------------------
December 31,
2010 283 103 387 54 14 68
----------------------------------------------------------------------------

Natural Gas Barrels of Oil Equivalent
(bcf) (mmboe)
-------------------------------------------------------------
Proved Proved
Reconciliation plus plus
Items (1) Proved Probable probable Proved Probable probable
----------------------------------------------------------------------------
December 31,
2009 938 354 1,292 497 190 687
Extensions 46 49 95 23 14 38
Improved
Recovery 3 - 3 4 (1) 3
Infill Drilling 9 3 12 12 5 17
Technical
Revisions 59 (30) 29 22 (8) 14
Discoveries - - - - - -
Acquisitions 27 12 39 17 8 25
Dispositions (48) (9) (58) (29) (26) (55)
Economic Factors (27) (9) (36) (6) (3) (9)
Production (141) - (141) (59) - (59)
----------------------------------------------------------------------------
December 31,
2010 865 370 1,235 481 179 661
----------------------------------------------------------------------------

(1) Columns may not add due to rounding.

 



We increased our capital program during 2010 in preparation for our change to a growth oriented E&P company. Throughout 2010, we were active in consolidating our resource base through a number of acquisition, divestiture and land transactions. We closed three significant transactions, an asset exchange in the first quarter, the Peace River Oil Partnership in the second quarter and the Cordova Joint Venture in the third quarter. The asset exchange was consistent with our strategy of moving our assets from the early assessment stage through the development stage while considering our asset portfolio balance. The latter two transactions involved us contributing assets and retaining an ownership interest and operatorship. The resultant structures enable us to develop these large-scale and capital-intensive projects at a significantly faster pace. Numerous minor transactions were also completed to ready ourselves for our new mandate.

d) Net present value of future net revenue using forecast prices and costs (millions) at December 31, 2010



Net present value of future net revenue
before income taxes
(discounted @)
-----------------------------------------------
Reserve Category (1) 0% 5% 10% 15% 20%
----------------------------------------------------------------------------

Proved
Developed producing $ 12,873 $ 9,126 $ 7,202 $ 6,017 $ 5,206
Developed non-producing 448 333 261 214 182
Undeveloped 2,464 1,401 881 585 400
----------------------------------------------------------------------------
Total proved $ 15,784 $ 10,860 $ 8,344 $ 6,817 $ 5,788
Probable 7,266 3,848 2,427 1,693 1,260
----------------------------------------------------------------------------
Total proved plus probable $ 23,051 $ 14,708 $ 10,771 $ 8,510 $ 7,048
----------------------------------------------------------------------------

 



(1) Columns may not add due to rounding.

Net present values take into account wellbore abandonment liabilities and are based on the price assumptions that are contained in the following table. It should not be assumed that the estimated future net revenues represent fair market value of the reserves. There is no assurance that the forecast price and cost assumptions will be attained and variances could be material.

e) Summary of pricing and inflation rate assumptions as of December 31, 2010 using forecast prices and costs



Oil
---------------------------------------------------
Edmonton Lloydminster Cromer
WTI Par Blend Medium
Cushing, 40 degrees 21 degrees 29 degrees
Oklahoma API API API
Year ($US/bbl) ($CAD/bbl) ($CAD/bbl) ($CAD/bbl)
----------------------------------------------------------------------------
Historical
2006 66.22 73.16 50.36 62.24
2007 72.24 77.02 52.03 66.30
2008 98.05 101.82 82.59 93.40
2009 61.60 66.32 58.39 62.98
2010 79.42 78.02 66.79 73.81
Forecast
2011 88.20 89.65 77.31 84.20
2012 89.07 91.57 77.63 84.69
2013 89.38 92.17 76.11 84.33
2014 90.44 93.25 75.76 84.39
2015 92.69 95.57 77.65 86.50
2016 94.56 97.50 79.21 88.25
2017 96.60 99.61 80.92 90.16
2018 98.54 101.62 82.54 91.98
2019 100.60 103.75 84.27 93.91
2020 102.37 105.59 85.76 95.57
----------------------------------------------------------------------------
Thereafter
escalating at 1.8% 1.8% 1.8% 1.8%
----------------------------------------------------------------------------


-------------------------------------------------------
Natural gas Exchange
AECO Edmonton Inflation rate
gas price propane rate (US$ equals
Year ($CAD/mcf) ($CAD/bbl) (%) $1 CAD)
----------------------------------------------------------------------------
Historical
2006 7.02 43.97 2.1 0.88
2007 6.65 46.85 2.1 0.94
2008 8.16 58.31 1.7 0.94
2009 4.20 37.99 0.3 0.88
2010 4.17 46.87 1.8 0.97
Forecast
2011 4.10 54.76 1.8 0.96
2012 4.70 55.95 1.8 0.96
2013 5.15 56.35 1.8 0.96
2014 6.17 57.02 1.8 0.96
2015 6.45 58.46 1.8 0.96
2016 6.66 59.65 1.8 0.96
2017 6.83 60.95 1.8 0.96
2018 6.96 62.19 1.8 0.96
2019 7.10 63.50 1.8 0.96
2020 7.23 64.63 1.8 0.96
----------------------------------------------------------------------------
Thereafter
escalating at 1.8% 1.8% 1.8 -
----------------------------------------------------------------------------

f) Finding and development costs ("F&D costs")

Year ended December 31
------------------------------------------
3-Year
2010 2009 2008 average
----------------------------------------------------------------------------

Adjusted FD&A including Future
Development
Costs ("FDC") (1)
FD&A costs per boe - proved plus
probable $ 18.12 $ 23.77 $ 23.38 $ 22.81
FD&A costs per boe - proved $ 16.64 $ 15.11 $ 30.78 $ 26.93

Excluding FDC (2)
F&D costs per boe - proved plus
probable $ 18.90 $ 13.75 $ 18.94 $ 17.40
F&D costs per boe - proved $ 21.50 $ 16.10 $ 27.17 $ 21.49

Including FDC (3)
F&D costs per boe - proved plus
probable $ 26.73 $ 16.12 $ 24.57 $ 22.90
F&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.

 



The future 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 NI 51-101, which include the change in FDC, on a proved and proved plus probable basis. For comparative purposes we also disclose F&D costs excluding FDC.

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



g) Future development costs using forecast prices and costs (millions)

Proved Future Proved plus Probable
Year Development Costs Future Development Costs
----------------------------------------------------------------------------
2011 $ 662 $ 928
2012 213 349
2013 117 188
2014 104 141
2015 60 93
2016 and subsequent 233 386
----------------------------------------------------------------------------
Undiscounted total $ 1,389 $ 2,085
----------------------------------------------------------------------------
Discounted @ 10%/yr $ 1,103 $ 1,635
----------------------------------------------------------------------------

 



Letter to our Shareholders

Penn West Exploration began operating as a conventional exploration and development corporation on January 1, 2011. In 2010, during the ramp up to conversion, we focused on appraising the resource potential of our extensive portfolio of light-oil weighted assets and on positioning the company as the dominant operator in the development of conventional oil in western Canada.

This appraisal work sets up a capital intensive development stage that we believe will deliver with it better capital efficiencies and improved project returns.

Penn West ramped up drilling in the fourth quarter of 2010 on four major tight oil plays. The plays are performing as we had anticipated with production in line with our established production type-curves. Throughout the fourth quarter we continued to build operational capacity. We achieved a 2010 exit rate in-line with previous guidance at just over 167,000 boe per day despite the impact of approximately 1,900 boe per day of production lost due to pipeline apportionment.

The 2011 capital program will increase our activity level on the Cardium and Carbonates light-oil projects. These longer lead-time, higher reserves projects complement our shallower, light-oil plays in the Colorado and at Waskada.

We are now the most active driller in western Canada. We anticipate 2011 to be a year marked by ongoing resource appraisal and a move toward full scale project development as the year progresses. We are targeting five percent growth in 2011 via a capital program dominated by light-oil development. Cost reduction through efficiency and technology continues to be a priority in all project areas. We are also actively identifying those areas where both near-term and long-term strategic consolidation opportunities are present. Areas currently being assessed are both in active resource play areas as well as early-stage exploration plays.

Our basket of large scale resource opportunities provided us the ability to execute on two significant joint venture agreements in 2010. These agreements, one partnership to develop bitumen resources in the Peace River oilsands block and a joint venture to develop shale gas assets in the Cordova Embayment of northeastern British Columbia, further evidence the size and potential of our portfolio. In the case of both transactions, partial cash consideration was paid upfront which was used to strengthen our balance sheet and provide ongoing financial flexibility to the Company. A carry on future capital associated with these joint ventures means that of a projected $1.85 billion in capital spending over the next 4-5 years, our partners will contribute approximately $1.6 billion. Appraisal work has begun on these assets and we believe the ultimate resource potential of these significant plays will provide attractive returns to Penn West shareholders.

On converting the Trust to a conventional corporation, the Board of Directors, acting on management's recommendation, adopted a business model that will balance growth with income. We anticipate our initial quarterly dividend as a conventional corporation to be declared payable on April 15, 2011 to shareholders of record on March 31, 2011.

Penn West is eagerly looking forward to increasing shareholder value based on a platform of growth and income.

On behalf of the Board of Directors,


William E. Andrew, Chief Executive Officer

Murray R. Nunns, President and Chief Operating Officer

Calgary, Alberta

February 16, 2011

Outlook

This outlook section is included to provide shareholders with information about our expectations as at February 16, 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.

To date in the first quarter of 2011, we continue to experience production losses from Enbridge pipeline apportionments as well as issues at a partner operated gas facility in the Swan Hills area which resulted in the approximate loss of an additional 3,500 boe per day. We are optimistic that our partner operated gas facility in the Swan Hills area will return to full production in the near future. We do not anticipate a complete resolution to the current apportionment issues prior to the end of the first quarter. Penn West is maintaining its original guidance in the range of 172,000 - 177,000 boe per day as we are confident that we can overcome these production losses which were beyond our control.

There have been no changes from our prior forecast for 2011 released on November 5, 2010, with our 2010 third quarter results and filed on SEDAR at www.sedar.com. Our actual 2010 exploration and development capital was slightly higher than our forecast of approximately $1.0 billion mainly due to our success at land sales and the advancement of our key light-oil properties which led to additional spending in late 2010.

Non-GAAP Measures Advisory

The above information includes non-GAAP measures not defined under generally accepted accounting principles ("GAAP"), including funds flow, funds flow per unit-basic, netback, payout ratio and net debt. Non-GAAP measures do not have any standardized meaning prescribed by GAAP and therefore may not be comparable to similar measures presented 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 dividends and planned capital programs. See "Calculation of Funds Flow" below. 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 and is used for similar purposes to netback. Payout ratio is calculated as distributions or dividends paid divided by funds flow. We use payout ratio to assess the adequacy of retained funds flow to finance capital programs. Net debt is calculated as 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.

Oil and Gas Information Advisory

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.

Forward- Looking Statements

This press release contains forward-looking statements. Please refer to our disclaimer on forward-looking statements set forth at the end of the management commentary attached below.



Penn West Energy Trust
Consolidated Balance Sheets

(CAD millions, unaudited) December 31, 2010 December 31, 2009
----------------------------------------------------------------------------

Assets
Current
Accounts receivable $ 386 $ 371
Future income taxes 17 37
Other 87 101
----------------------------------------------------------------------------
490 509
----------------------------------------------------------------------------

Deferred funding obligation 678 -
Property, plant and equipment 10,180 11,347
Goodwill 2,020 2,020
----------------------------------------------------------------------------
12,878 13,367
----------------------------------------------------------------------------
$ 13,368 $ 13,876
----------------------------------------------------------------------------

Liabilities and unitholders' equity
Current
Accounts payable and accrued
liabilities $ 743 $ 515
Distributions payable 41 63
Risk management 62 130
----------------------------------------------------------------------------
846 708
Long-term debt 2,496 3,219
Convertible debentures 255 273
Asset retirement obligations 653 568
Risk management 64 21
Future income taxes 855 1,169
----------------------------------------------------------------------------
5,169 5,958
----------------------------------------------------------------------------
Unitholders' equity
Unitholders' capital 9,177 8,451
Contributed surplus 138 123
Deficit (1,116) (656)
----------------------------------------------------------------------------
8,199 7,918
----------------------------------------------------------------------------
$ 13,368 $ 13,876
----------------------------------------------------------------------------


Penn West Energy Trust
Consolidated Statements of Operations and Retained Earnings
(Deficit)
Three months ended Year ended
December 31 December 31
(CAD millions, except per unit ----------------------------------------
amounts, unaudited) 2010 2009 2010 2009
----------------------------------------------------------------------------

Revenues
Oil and natural gas $ 805 $ 801 $ 3,054 $ 2,859
Royalties (139) (146) (545) (495)
----------------------------------------------------------------------------
666 655 2,509 2,364
Risk management gain (loss)
Realized (23) 30 (20) 344
Unrealized (87) (107) 23 (554)
----------------------------------------------------------------------------
556 578 2,512 2,154
----------------------------------------------------------------------------

Expenses
Operating 246 240 959 979
Transportation 8 8 33 34
General and administrative 48 43 181 168
Financing 43 41 174 161
Depletion, depreciation and
accretion 345 367 1,338 1,556
Unrealized risk management (gain)
loss (12) (2) (2) 39
Unrealized foreign exchange gain (55) (25) (82) (186)
Transaction costs 4 - 4 -
Gain on currency contracts - - - (75)
----------------------------------------------------------------------------
627 672 2,605 2,676
----------------------------------------------------------------------------
Loss before taxes (71) (94) (93) (522)
----------------------------------------------------------------------------

Taxes
Future income tax recovery (50) (82) (319) (378)
----------------------------------------------------------------------------

Net and comprehensive income (loss) $ (21) $ (12) $ 226 $ (144)

Retained earnings (deficit),
beginning of period $ (972) $ (455) $ (656) $ 329
Distributions declared (123) (189) (686) (841)
----------------------------------------------------------------------------
Deficit, end of period $(1,116) $ (656) $(1,116) $ (656)
----------------------------------------------------------------------------

Net income (loss) per unit
Basic $ (0.05) $ (0.03) $ 0.51 $ (0.35)
Diluted $ (0.05) $ (0.03) $ 0.50 $ (0.35)
Weighted average units outstanding
(millions)
Basic 457.0 420.7 441.8 412.9
Diluted 457.0 420.7 447.6 412.9


Penn West Energy Trust
Consolidated Statements of Cash Flows

Three months ended Year ended
December 31 December 31
----------------------------------------
(CAD millions, unaudited) 2010 2009 2010 2009
----------------------------------------------------------------------------

Operating activities
Net income (loss) $ (21) $ (12) $ 226 $ (144)
Depletion, depreciation and accretion 345 367 1,338 1,556
Future income tax recovery (50) (82) (319) (378)
Unit-based compensation 11 13 47 52
Unrealized risk management loss (gain) 75 105 (25) 593
Unrealized foreign exchange gain (55) (25) (82) (186)
Asset retirement expenditures (15) (16) (53) (65)
Change in non-cash working capital 13 88 85 (27)
----------------------------------------------------------------------------
303 438 1,217 1,401
----------------------------------------------------------------------------

Investing activities
Additions to property, plant and
equipment (400) (196) (1,187) (688)
Acquisition of property, plant and
equipment (158) (1) (637) (32)
Disposition of property, plant and
equipment 4 197 1,148 401
Change in non-cash working capital 9 30 155 (79)
----------------------------------------------------------------------------
(545) 30 (521) (398)
----------------------------------------------------------------------------

Financing activities
Increase (decrease) in bank loan 134 (315) (1,101) (687)
Proceeds from issuance of notes 156 - 460 238
Issue of equity 73 10 557 280
Distributions paid (100) (163) (591) (799)
Redemption of convertible debentures - - - (4)
Repayment of acquired credit
facilities (21) - (21) (31)
----------------------------------------------------------------------------
242 (468) (696) (1,003)
----------------------------------------------------------------------------

Change in cash - - - -
Cash, beginning of period - - - -
----------------------------------------------------------------------------
Cash, end of period $ - $ - $ - $ -
----------------------------------------------------------------------------

Interest paid $ 56 $ 56 $ 147 $ 147
Income taxes recovered $ - $ - $ (1) $ (3)
----------------------------------------------------------------------------

 



MANAGEMENT COMMENTARY

For the three months and year ended December 31, 2010

All dollar amounts contained in this Management Commentary are expressed in millions of Canadian dollars unless noted otherwise.

Please refer to our disclaimer on forward-looking statements at the end of the Management Commentary. 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, return on equity and return on capital included in this Management Commentary 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 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. 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 well Penn West utilizes the capital invested into the company.



Calculation of Funds Flow
Three months ended Year ended
December 31 December 31
----------------------------------------
(millions, except per unit amounts) 2010 2009 2010 2009
----------------------------------------------------------------------------
Cash flow from operating activities $ 303 $ 438 $ 1,217 $ 1,401
Increase (decrease) in non-cash
working capital (13) (88) (85) 27
Asset retirement expenditures 15 16 53 65
----------------------------------------------------------------------------
Funds flow $ 305 $ 366 $ 1,185 $ 1,493
----------------------------------------------------------------------------

Basic per unit $ 0.67 $ 0.87 $ 2.68 $ 3.62
Diluted per unit $ 0.66 $ 0.86 $ 2.65 $ 3.60
----------------------------------------------------------------------------


Annual Financial Summary
Year ended December 31
---------------------------------------
(millions, except per unit amounts) 2010 2009 2008
----------------------------------------------------------------------------
Gross revenues (1) $ 3,034 $ 3,203 $ 4,651
Funds flow 1,185 1,493 2,537
Basic per unit 2.68 3.62 6.75
Diluted per unit 2.65 3.60 6.66
Net income (loss) 226 (144) 1,221
Basic per unit 0.51 (0.35) 3.25
Diluted per unit 0.50 (0.35) 3.22
Capital expenditures, net (2) 1,187 688 1,095
Long-term debt at year-end 2,496 3,219 3,854
Convertible debentures 255 273 296
Distributions paid (3) 708 910 1,500
Total 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 Year-to-date 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, net, for 2010 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 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 decline 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.

Fourth Quarter 2010 Highlights

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

- Production averaged 166,148 boe per day and was weighted 63 percent to liquids and 37 percent to natural gas.

- Capital expenditures, net, totalled $400 million compared to $196 million in the fourth quarter of 2009. During the fourth quarter of 2010, we closed net property acquisitions of $69 million (2009 - $196 million net dispositions).

- Funds flow in the quarter was $305 million compared to $366 million in the fourth quarter of 2009. The decline was primarily due to realized risk management losses.

- Net loss was $21 million compared to a net loss of $12 million in the fourth quarter of 2009.

- Netback was $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.

- In January 2011, we completed the closing of a private placement of notes (the "2010 Q4 Notes") totalling approximately US$230 million.



Quarterly Financial Summary

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

Three Dec. Sep. June Mar. Dec. Sep. June Mar.
months 31 30 30 31 31 30 30 31
ended 2010 2010 2010 2010 2009 2009 2009 2009
----------------------------------------------------------------------------
Gross
revenues
(1) $ 782 $ 728 $ 718 $ 806 $ 831 $ 800 $ 791 $ 781
Funds flow 305 267 269 344 366 349 430 348
Basic per
unit 0.67 0.59 0.62 0.81 0.87 0.84 1.05 0.87
Diluted per
unit 0.66 0.58 0.61 0.80 0.86 0.83 1.05 0.87
Net 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 123 177 196 190 189 188 188 276
Per unit $ 0.27 $ 0.39 $ 0.45 $ 0.45 $ 0.45 $ 0.45 $ 0.45 $ 0.69
Production
Liquids
(bbls/d)
(2) 105,296 98,380 95,777 96,317 101,636 104,583 104,070 105,643
Natural gas
(mmcf/d) 365 394 408 410 411 441 459 447
----------------------------------------------------------------------------
Total
(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.

 



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$90.00 and Brent trading over US$100.00. Protests and similar activities in these regions led to concerns regarding the possibility of disruptions of crude oil shipments through the Suez Canal and other routes important to future crude oil supply.

Commodity Markets

Global demand growth for crude oil exceeded increases in non-OPEC supply over the past year. 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 over the past year resulting in premium prices in international 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. During the fourth quarter of 2010, crude oil prices averaged WTI US$85.18 per barrel, 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. 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 discounts on certain Canadian streams and shut-ins of certain production occurred. 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 and for the fourth quarter of 2010 was $69.58 per barrel. Currently, we have risk management contracts of 35,000 barrels per day of our 2011 crude oil production at prices between US$80.06 per barrel and US$91.98 per barrel and 20,000 barrels per day of our forecasted 2012 crude oil production between US$84.25 per barrel and US$98.45 per barrel.

Natural Gas

In 2010, the AECO Monthly Index averaged $4.12 per mcf compared to $4.13 per mcf in 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. 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 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.

Our corporate average natural gas price before the impact of the realized portion of risk management was $4.20 per mcf for 2010 and $3.79 per mcf for the fourth quarter of 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. Our transition to an E&P was seamless and 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 on a number of strategies in advance of our conversion date. These strategies include a thorough evaluation of our resource plays, acquisition and divestiture activity in order to focus our asset base and 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 examination of our staff and technical expertise including exploration, to significantly increase and maintain 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 for a 55 percent interest in the partnership 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 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 increased.

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 development stage 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 31
-----------------------------------------
3-Year
2010 2009 2008 average
----------------------------------------------------------------------------
Adjusted FD&A including future
development costs ("FDC") (1)
FD&A costs per boe - proved plus
probable $ 18.12 $ 23.77 $ 23.38 $ 22.81
FD&A costs per boe - proved $ 16.64 $ 15.11 $ 30.78 $ 26.93

Excluding FDC (2)
F&D costs per boe - proved plus
probable $ 18.90 $ 13.75 $ 18.94 $ 17.40
F&D costs per boe - proved $ 21.50 $ 16.10 $ 27.17 $ 21.49

Including FDC (3)
F&D costs per boe - proved plus
probable $ 26.73 $ 16.12 $ 24.57 $ 22.90
F&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 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.

The future 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 NI 51-101, which include the change in FDC, on a proved and proved plus probable basis. For comparative purposes we also disclose F&D costs excluding FDC.

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

Base operations

Throughout 2010, our drilling results were generally consistent with our expectations as we increased our capital plan in anticipation of our conversion to an E&P company and due to our successful results at our light-oil resource plays. Weather issues in the summer and winter months resulted in interruptions in tying in wells and led to production delays. During the year, we closed two strategic joint venture arrangements, the Peace River Oil Partnership and Cordova Joint Venture, which provide us with a significant capital commitment 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 31
---------------------------------------
2010 2009 2008
----------------------------------------------------------------------------
Funds flow per unit $ 2.68 $ 3.62 $ 6.75
Distributions paid per unit $ 1.62 $ 2.23 $ 4.08
Ratio 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 in the near term the distribution level was decreased to $0.09 per unit per month effective with the September 2010 distribution paid in October 2010. These funds will be used to expand our capital program.

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 31
---------------------------------------
2010 2009 2008
----------------------------------------------------------------------------
Return 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.



RESULTS OF OPERATIONS

Production
Three months ended Year ended
December 31 December 31
-----------------------------------------------------
Daily production % %
2010 2009 change 2010 2009 change
----------------------------------------------------------------------------
Light oil and NGL
(bbls/d) 88,447 77,627 14 80,706 78,011 3
Heavy oil (bbls/d) 16,849 24,009 (30) 18,260 25,962 (30)
Natural gas
(mmcf/d) 365 411 (11) 394 440 (10)
----------------------------------------------------------------------------
Total production
(boe/d) 166,148 170,164 (2) 164,633 177,221 (7)
----------------------------------------------------------------------------

 



Our production results for 2010 were strong primarily due to 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. During 2010, we experienced some unplanned interruptions due to poor weather which resulted in delays in tying in new wells and therefore delays in production coming on-stream. We drilled 319 net wells in 2010 primarily using horizontal multi-stage fracture technology, compared to 94 net wells in 2009.

Production increased to 166,148 boe per day in the fourth quarter of 2010 from 164,087 boe per day in the third quarter of 2010. Our light-oil production volumes increased due to our concentrated capital program on our key light-oil resource plays. During the fourth quarter of 2010 extremely cold weather throughout western Canada led to some unanticipated interruptions resulting in production delays. We drilled 116 net wells during the fourth quarter primarily throughout our light-oil plays compared to 25 net wells in 2009.

The decrease from the comparable periods in 2009 was mainly due to property dispositions including the Lloydminster property disposition completed in November 2009 of approximately 6,000 boe per day, predominantly of heavy oil, and the January 2010 asset swap of approximately 2,800 boe per day.

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 the fourth quarter of 2010, crude oil and NGL production averaged 105,296 barrels per day (63 percent of production) and natural gas production averaged 365 mmcf per day (37 percent of production).



Average Sales Prices

Three months ended Year ended
December 31 December 31
----------------------------------------------------------------------------
% %
2010 2009 change 2010 2009 change
----------------------------------------------------------------------------

Light oil and NGL
(per bbl) $ 71.05 $ 69.49 2 $ 69.29 $ 59.07 17
Risk management
gain (loss) (per
bbl) (1) (4.12) 1.55 (100) (2.72) 8.19 (100)
----------------------------------------------------------------------------
Light oil and NGL
net (per bbl) 66.93 71.04 (6) 66.57 67.26 (1)
----------------------------------------------------------------------------

Heavy oil (per bbl) 61.87 62.97 (2) 60.55 53.75 13
----------------------------------------------------------------------------

Natural gas (per
mcf) 3.79 4.39 (14) 4.20 4.13 2
Risk management
gain (per mcf) (1) 0.31 0.49 (37) 0.42 0.69 (39)
----------------------------------------------------------------------------
Natural gas net
(per mcf) 4.10 4.88 (16) 4.62 4.82 (4)
----------------------------------------------------------------------------
Weighted average
(per boe) 52.43 51.19 2 50.74 44.11 15
Risk management
gain (loss) (per
boe) (1) (1.51) 1.89 (100) (0.34) 5.32 (100)
----------------------------------------------------------------------------
Weighted average
net (per boe) $ 50.92 $ 53.08 (4) $ 50.40 $ 49.43 2
----------------------------------------------------------------------------

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


Netbacks

Three months ended Year ended
December 31 December 31
----------------------------------------------------------
% %
2010 2009 change 2010 2009 change
----------------------------------------------------------------------------
Light oil and NGL
(1)
Production
(bbls/day) 88,447 77,627 14 80,706 78,011 3
Operating netback
($/bbl):
Sales price $ 71.05 $ 69.49 2 $ 69.29 $ 59.07 17
Risk management
gain (loss) (2) (4.12) 1.55 (100) (2.72) 8.19 (100)
Royalties (13.79) (13.89) (1) (13.73) (10.78) 27
Operating costs (18.83) (19.74) (5) (19.83) (19.93) (1)
----------------------------------------------------------------------------
Netback $ 34.31 $ 37.41 (8) $ 33.01 $ 36.55 (10)
----------------------------------------------------------------------------
Conventional
heavy oil
Production
(bbls/day) 16,849 24,009 (30) 18,260 25,962 (30)
Operating netback
($/bbl):
Sales price $ 61.87 $ 62.97 (2) $ 60.55 $ 53.75 13
Royalties (8.61) (9.52) (10) (8.73) (7.26) 20
Operating costs (17.28) (15.37) 12 (17.14) (15.54) 10
Transportation (0.11) (0.07) 57 (0.09) (0.06) 50
----------------------------------------------------------------------------
Netback $ 35.87 $ 38.01 (6) $ 34.59 $ 30.89 12
----------------------------------------------------------------------------
Total liquids
Production
(bbls/day) 105,296 101,636 4 98,966 103,973 (5)
Operating netback
($/bbl):
Sales price $ 69.58 $ 67.95 2 $ 67.68 $ 57.74 17
Risk management
gain (loss) (2) (3.46) 1.18 (100) (2.22) 6.14 (100)
Royalties (12.96) (12.86) 1 (12.81) (9.90) 29
Operating costs (18.58) (18.71) (1) (19.33) (18.83) 3
Transportation (0.02) (0.02) - (0.02) (0.01) 100
----------------------------------------------------------------------------
Netback $ 34.56 $ 37.54 (8) $ 33.30 $ 35.14 (5)
----------------------------------------------------------------------------
Natural gas
Production
(mmcf/day) 365 411 (11) 394 440 (10)
Operating netback
($/mcf):
Sales price $ 3.79 $ 4.39 (14) $ 4.20 $ 4.13 2
Risk management
gain (2) 0.31 0.49 (37) 0.42 0.69 (39)
Royalties (0.42) (0.69) (39) (0.58) (0.75) (23)
Operating costs (1.88) (1.63) 15 (1.71) (1.57) 9
Transportation (0.23) (0.21) 10 (0.22) (0.21) 5
----------------------------------------------------------------------------
Netback $ 1.57 $ 2.35 (33) $ 2.11 $ 2.29 (8)
----------------------------------------------------------------------------
Combined totals
Production
(boe/day) 166,148 170,164 (2) 164,633 177,221 (7)
Operating netback
($/boe):
Sales price $ 52.43 $ 51.19 2 $ 50.74 $ 44.11 15
Risk management
gain (loss) (2) (1.51) 1.89 (100) (0.34) 5.32 (100)
Royalties (9.14) (9.35) (2) (9.07) (7.66) 18
Operating costs (15.92) (15.10) 5 (15.71) (14.93) 5
Transportation (0.52) (0.52) - (0.55) (0.52) 6
----------------------------------------------------------------------------
Netback $ 25.34 $ 28.11 (10) $ 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.

Production Revenues

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

Three months ended Year ended
December 31 December 31
-------------------------------------------------------
% %
(millions) 2010 2009 change 2010 2009 change
----------------------------------------------------------------------------
Light oil and NGL $ 548 $ 507 8 $ 1,965 $ 1,920 2
Heavy oil 96 139 (31) 405 509 (20)
Natural gas 138 185 (25) 664 774 (14)
----------------------------------------------------------------------------
Gross revenues (1) $ 782 $ 831 (6) $ 3,034 $ 3,203 (5)
----------------------------------------------------------------------------

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

 



The decrease in revenue for 2010 from the comparative period in 2009 was mainly the result of lower realized risk management gains and the impact of 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.



Reconciliation of decrease in Production Revenues

(millions)
----------------------------------------------------------------------------
Gross revenues - January 1 - December 31, 2009 $ 3,203
Increase in light oil and NGL production 66
Decrease in light oil and NGL prices (including realized risk
management) (21)
Decrease in heavy oil production (151)
Increase in heavy oil prices 47
Decrease 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
Three months ended Year ended
December 31 December 31
-----------------------------------------------------
% %
2010 2009 change 2010 2009 change
----------------------------------------------------------------------------
Royalties (millions) $ 139 $ 146 (5) $ 545 $ 495 10
Average royalty rate
(1) 17% 18% (1) 18% 17% 1
$/boe $ 9.14 $ 9.35 (2) $ 9.07 $ 7.66 18
----------------------------------------------------------------------------

(1) Excludes effects of risk management activities.

 



In 2010, royalty rates and per boe amounts increased as a result of higher crude oil prices. During the fourth quarter of 2010, our royalty rate decreased due to new wells coming on production at a lower royalty rate under the new provincial royalty programs.



Expenses
Three months ended Year ended
December 31 December 31
---------------------------------------------------------
% %
(millions) 2010 2009 change 2010 2009 change
----------------------------------------------------------------------------
Operating $ 243 $ 237 3 $ 944 $ 966 (2)
Transportation 8 8 - 33 34 (3)
Financing 43 41 5 174 161 8
Unit-based
compensation $ 14 $ 13 8 $ 55 $ 52 6
----------------------------------------------------------------------------

Three months ended Year ended
December 31 December 31
---------------------------------------------------------
% %
(per boe) 2010 2009 change 2010 2009 change
----------------------------------------------------------------------------
Operating $ 15.92 $ 15.10 5 $ 15.71 $ 14.93 5
Transportation 0.52 0.52 - 0.55 0.52 6
Financing 2.78 2.57 8 2.89 2.49 16
Unit-based
compensation $ 0.92 $ 0.86 7 $ 0.92 $ 0.81 14
----------------------------------------------------------------------------

 



Operating

During the fourth quarter of 2010, we incurred approximately $5 million of realized losses (2009 - $5 million) on our electricity contracts which had a $0.31 per boe effect (2009 - $0.29) on our results. In 2010, acquisition and divestiture activity also 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).

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.

Financing

Penn West Petroleum Ltd. (the "Company") has a three-year, unsecured, revolving syndicated bank facility with an aggregate borrowing limit of $2.25 billion. The facility is extendible and expires on April 30, 2013. 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:




Weighted
Average average
Amount interest remaining
Issue date (millions) Term rate term
----------------------------------------------------------------------------

2007 Notes May 31, 2007 US$475 8-15 years 5.80 percent 6.5 years

US$480,
2008 Notes May 29, 2008 CAD$30 8-12 years 6.25 percent 7.0 years

Pounds
Sterling 6.95 percent
UK Notes July 31, 2008 57 10 years (1) 7.6 years

US$154,
Pounds
Sterling
May 5, 2009 20,
EUR 10, 8.85 percent
2009 Notes CAD$5 5-10 years (2) 6.0 years

US$250,
2010 Q1 March 16, 2010 CAD$50 5-15 years 5.47 percent 7.8 years
Notes

2010 Q4 December 2, 2010 US$95, 5-15 years 4.96 percent 9.8 years
Notes (3) CAD$60
----------------------------------------------------------------------------
(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.

 



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 have a 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 have a 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 from the issue received on that date to repay advances on its syndicated bank facility.



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

Nominal amount Fixed rate
Effective date Termination date Initial term (millions) (percent)
----------------------------------------------------------------------------
December 2008 December 2011 3 years $ 500 1.61
January 2009 January 2014 5 years $ 600 2.71
June 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 both the fourth quarter and 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 the fourth quarter of 2010 an expense of $4 million (2009 - $8 million) and for 2010 an expense of $21 million (2009 - $21 million) 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"). 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.



Three months ended Year ended
December 31 December 31
--------------------------------------------------------
% %
(millions) 2010 2009 change 2010 2009 change
----------------------------------------------------------------------------
TURIP
Operating expense $ 2 $ 3 (33) $ 11 $ 13 (15)
General and
administrative
expense 9 10 (10) 36 39 (8)
LTRIP
Operating expense 1 - 100 4 - 100
General and
administrative
expense 2 - 100 4 - 100
----------------------------------------------------------------------------
Unit-based
compensation
expense $ 14 $ 13 8 $ 55 $ 52 6
----------------------------------------------------------------------------

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

General and Administrative Expenses ("G&A")

Three months ended Year ended
December 31 December 31
-------------------------------------------------------
(millions, except % %
per boe amounts) 2010 2009 change 2010 2009 change
----------------------------------------------------------------------------
Gross $ 58 $ 47 23 $ 203 $ 189 7
Per boe 3.78 3.03 25 3.38 2.93 15
Net (including
unit-based
compensation) 48 43 12 181 168 8
Per boe 3.08 2.76 12 3.00 2.59 16
Net (excluding
unit-based
compensation) 37 33 12 141 129 9
Per boe $ 2.36 $ 2.12 11 $ 2.34 $ 1.99 18
----------------------------------------------------------------------------

 



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 in comparison to 2009.

During the fourth quarter of 2010, gross costs increased as a result of higher staff costs which were partially offset on a net basis by recoveries from higher capital activity levels. The increase in the cost per boe in 2010 was due to higher costs and lower production volumes during the year from property dispositions.



Depletion, Depreciation and Accretion ("DD&A")

Three months ended Year ended
December 31 December 31
-------------------------------------------------------
(millions, except % %
per boe amounts) 2010 2009 change 2010 2009 change
----------------------------------------------------------------------------
Depletion of oil
and natural gas
assets $ 331 $ 357 (7) $ 1,293 $ 1,514 (15)
Accretion of asset
retirement
obligations 14 10 40 45 42 7
----------------------------------------------------------------------------
Total DD&A $ 345 $ 367 (6) $ 1,338 $ 1,556 (14)
----------------------------------------------------------------------------
DD&A expense per
boe $ 22.56 $ 23.41 (4) $ 22.27 $ 24.04 (7)
----------------------------------------------------------------------------

 



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 property dispositions.



Taxes
Three months ended Year ended
December 31 December 31
-------------------------------------------------------
% %
(millions) 2010 2009 change 2010 2009 change
----------------------------------------------------------------------------
Future income tax
recovery $ (50) $ (82) (39) $ (319) $ (378) (16)
----------------------------------------------------------------------------

 



The 2010 recovery included $177 million 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 SIFT tax rate from 13 percent to 10 percent.

Under the income trust structure, which we operated in 2010, the operating entities make interest and royalty payments to the Trust, which transfers 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 Specified Investment Flow-Through ("SIFT") legislation, which was enacted in June 2007 and was effective on January 1, 2011, distributions are no longer tax deductible by trusts.

On January 1, 2011, we converted into a publicly-traded corporation. In 2011 and beyond, we are now subject to current and future taxes at normal 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 after 2010.



Tax Pools
As at
December 31
-------------------------
(millions) 2010 2009
----------------------------------------------------------------------------
Undepreciated capital cost (UCC) $ 1,122 $ 1,379
Canadian oil and gas property expense
(COGPE) 1,564 1,912
Canadian development expense (CDE) 1,494 1,141
Canadian exploration expense (CEE) 305 280
Non-capital losses 2,481 2,139
Other 31 16
----------------------------------------------------------------------------
Total $ 6,997 $ 6,867
----------------------------------------------------------------------------

 



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



Foreign Exchange
Three months ended Year ended
December 31 December 31
-------------------------------------------------------
% %
(millions) 2010 2009 change 2010 2009 change
----------------------------------------------------------------------------
Unrealized foreign
exchange gain $ (55) $ (25) 100 $ (82) $ (186) (56)
----------------------------------------------------------------------------

 



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 $82 million gain during 2010 was primarily due to the strengthening of the Canadian dollar relative to the US dollar.



Funds Flow and Net Income (Loss)
Three months ended Year ended
December 31 December 31
-------------------------------------------------------
% %
2010 2009 change 2010 2009 change
----------------------------------------------------------------------------
Funds flow (1)
(millions) $ 305 $ 366 (17) $ 1,185 $ 1,493 (21)
Basic per unit 0.67 0.87 (23) 2.68 3.62 (26)
Diluted per unit 0.66 0.86 (23) 2.65 3.60 (26)

Net income (loss)
(millions) (21) (12) (75) 226 (144) 100
Basic per unit (0.05) (0.03) (67) 0.51 (0.35) 100
Diluted per unit $ (0.05) $ (0.03) (67) $ 0.50 $ (0.35) 100
----------------------------------------------------------------------------

(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 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. For the fourth quarter of 2010, the net loss was mainly due to lower realized risk management gains compared to the fourth quarter of 2009.



Capital Expenditures
Three months ended Year ended
December 31 December 31
----------------------------------------
(millions) 2010 2009 2010 2009
----------------------------------------------------------------------------
Land acquisition and retention $ 10 $ 3 $ 102 $ 19
Drilling and completions 263 89 800 286
Facilities and well equipping 140 86 281 336
Geological and geophysical - 3 10 9
Corporate 4 15 11 38
----------------------------------------------------------------------------
Capital expenditures 417 196 1,204 688
Joint venture, carried capital (17) - (17) -
----------------------------------------------------------------------------
Capital expenditures, net $ 400 $ 196 $ 1,187 $ 688
----------------------------------------------------------------------------

Total expenditures
Three months ended Year ended
December 31 December 31
----------------------------------------
(millions) 2010 2009 2010 2009
----------------------------------------------------------------------------
Capital expenditures $ 417 $ 196 $ 1,204 $ 688
Property acquisitions (dispositions),
net 69 (196) (1,306) (369)
Business combinations 139 - 139 116
----------------------------------------------------------------------------
Total expenditures $ 625 $ - $ 37 $ 435
----------------------------------------------------------------------------

 



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

During 2010, we drilled 319 net wells (2009 - 94) resulting in 245 net oil wells, 38 net natural gas wells and 34 stratigraphic and service wells with a success rate of 99 percent (2009 - 98 percent). 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. Throughout 2010, we utilized horizontal multi-stage fracture technology on most of our wells drilled, excluding stratigraphic and service wells.

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

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 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 $450 million consisting of $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.



Goodwill

(millions) December 31, 2010 December 31, 2009
----------------------------------------------------------------------------
Balance, beginning and end of period $ 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.

Business Risks

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 Management Commentary.

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 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:



Nominal Amount
Initial Term (millions) Termination date Exchange rate
----------------------------------------------------------------------------
19-month term Sell US$378 December 2011 1.06085 CAD/USD
8-year term Buy US$80 May 2015 1.01027 CAD/USD
10-year term Buy US$80 May 2017 1.00016 CAD/USD
12-year term Buy US$70 May 2019 0.99124 CAD/USD
15-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 is not fixed.

Credit Risk

Credit risk is the risk of loss if purchasers or counterparties do not fulfill their contractual obligations. Our receivables are principally with customers in the oil and natural gas industry and are generally subject to normal industry credit risk, which includes the right to recover unpaid receivables by receiving 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 5.70 percent (2009 - 4.57 percent), including the effects of interest rate swaps. For further details on these instruments, refer to the "Financing" and "Convertible Debentures" sections in this Management Commentary.

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, distribution 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.

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



(millions) 2011 2012 2013 2014 2015 Thereafter
----------------------------------------------------------------------------
Bank debt $ - $ - $ 773 $ - $ - $ -
Senior unsecured notes - - 5 60 251 1,407
Convertible debentures 255 - - - - -
Accounts payable 743 - - - - -
Distributions payable 41 - - - - -
----------------------------------------------------------------------------
Total $ 1,039 $ - $ 778 $ 60 $ 251 $ 1,407
----------------------------------------------------------------------------

 



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 31
------------------------------------------
2010 2009
----------------------------------------------------------------------------
(millions) % %
----------------------------------------------------------------------------
Trust units issued, at market (1) $ 10,959 78 $ 7,821 69
Bank loans and long-term notes 2,496 18 3,219 28
Convertible debentures 255 2 273 2
Working capital deficiency (2) 311 2 106 1
----------------------------------------------------------------------------
Total enterprise value $ 14,021 100 $ 11,419 100
----------------------------------------------------------------------------

(1) The unit price at December 31, 2010 was $23.84 (2009 - $18.55).
(2) Excludes the current portion of risk management, future income taxes
and convertible debentures.

 



For 2010, we paid total distributions, including those funded by the distribution reinvestment plan, of $708 million (2009 - $910 million).

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 Management Commentary.

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.

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, 2010
----------------------------------------------------------------------------
Senior debt to EBITDA Less than 3:1 1.84
Total debt to EBITDA Less than 4:1 1.86
Senior debt to capitalization Less than 50 percent 23%
Total debt to capitalization (1) 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 policies are subject to 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). There was no change in the convertible debenture balances in the fourth quarter of 2010 or in the comparable period in 2009.

On January 26, 2011, due to our conversion to a corporation and in accordance with the debenture indentures, we announced our offer to repurchase all of our outstanding convertible debentures. Debenture holders are entitled to receive cash consideration in the amount of the offer price equal to 101 percent of the outstanding principal amounts plus accrued interest with the offer closing on March 3, 2011. At the time of the announcement we had approximately $255 million of convertible debentures outstanding.

At December 31, 2010, the balance of our unsecured, subordinated convertible debentures outstanding was as follows:



Conversion Redemption
Description of Outstanding Maturity price prices (per
security (millions) date (per unit) $1,000 face value)
----------------------------------------------------------------------------
PWT.DB.E $1,025 May 31, 2010
7.2% Convertible $ 26 May 31, 2011 $75.00 to maturity
PWT.DB.F
6.5% Convertible $1,025 Dec. 31, 2010
extendible 229 Dec. 31, 2011 $51.55 to maturity
----------------------------------------------------------------------------
Total $ 255
----------------------------------------------------------------------------

 



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.



Fair
Notional volume Remaining term Pricing value
----------------------------------------------------------------------------
Crude oil
US$80.06 to
WTI Collars 35,000 bbls/d Jan/11 - Dec/11 $91.98/bbl $ (70)
US$83.67 to
WTI Collars 15,000 bbls/d Jan/12 - Dec/12 $96.32/bbl (17)

Electricity swaps
Alberta 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 forwards
19-month term US$378 Jan/11 - Dec/11 1.06085 CAD/USD 23
8-year term US$80 2015 1.01027 CAD/USD 1
10-year term US$80 2017 1.00016 CAD/USD 1
12-year term US$70 2019 0.99124 CAD/USD 1
15-year term US$20 2022 0.98740 CAD/USD -

Cross currency swaps
Pounds 2.0075 CAD/GBP,
10-year term Sterling 57 2018 6.95% (28)
Pounds 1.8051 CAD/GBP,
10-year term Sterling 20 2019 9.15% (6)
1.5870 CAD/EUR,
10-year term EUR 10 2019 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 additional crude oil collars on 5,000 barrels per day for 2012 at US$86.00 per barrel to US$104.84 per barrel.

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 section of this release.



Impact on funds flow
----------------------------------------------------------------------------
Change of: Change $ millions $/unit
----------------------------------------------------------------------------
Price per barrel of liquids $1.00 19 0.04
Liquids production 1,000 bbls/day 17 0.04
Price per mcf of natural gas $0.10 12 0.03
Natural gas production 10 mmcf/day 7 0.01
Effective interest rate 1% 4 0.01
Exchange rate ($US per $CAD) $0.01 21 0.05
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Contractual Obligations and Commitments

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

(millions) 2011 2012 2013 2014 2015 Thereafter
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Long-term debt $ - $ - $ 778 $ 60 $ 251 $ 1,407
Transportation 26 15 14 9 5 -
Transportation ($US) 4 4 4 4 4 -
Power infrastructure 30 10 10 10 10 14
Drilling rigs 9 5 3 1 - -
Purchase obligations (1) 13 13 13 11 10 8
Interest obligations 154 138 119 106 96 270
Office lease (2) $ 71 $ 68 $ 66 $ 61 $ 60 $ 539
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(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.

 



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 February 16, 2011, convertible debentures with an aggregate principal amount of $255 million were outstanding. For a schedule of convertible debenture maturities, please refer to the "Convertible Debentures" section of this Management Commentary.



Equity Instruments

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Trust units issued:
Trust units as at December 31, 2010 459,682,249
Trust units cancelled on January 1, 2011 (459,682,249)
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As at January 1, 2011 -
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Common shares issued:
Issuance of common shares on January 1, 2011 459,682,249
Issued on exercise of options 1,211,795
Issued on exercise of common share rights 225,478
Issued on settlement of restricted rights 3,433
Issued pursuant to dividend reinvestment plan 299,097
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As at February 16, 2011 461,422,052
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Trust unit rights outstanding:
Trust unit rights outstanding as at December 31, 2010 31,365,478
Trust unit rights cancelled on January 1, 2011 (31,365,478)
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As at January 1, 2011 -
----------------------------------------------------------------------------
Options outstanding:
Issuance on January 1, 2011 27,586,712
Granted 78,130
Exercised (1,211,795)
Forfeited (152,083)
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As at February 16, 2011 26,300,964
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Common share rights outstanding:
Issuance on January 1, 2011 3,778,766
Exercised (225,478)
Forfeited (43,701)
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As at February 16, 2011 3,509,587
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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 conversion for more information.

Internal Control over Financial Reporting

No changes in our internal control over financial reporting ("ICOFR") were made during the quarter ended December 31, 2010 that have materially affected, or are reasonably likely to materially affect, our ICOFR.

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.

Forward-Looking Statements

In the interest of providing Penn West's securityholders and potential investors with information regarding Penn West, including management's assessment of Penn West's 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 objective to deliver a return to our shareholders comprised of both growth and dividends in the near term; our intention and ability to declare a dividend anticipated to be payable on April 15, 2011 to shareholders of record on March 31, 2011; our intention to position our significant resources for future large scale development using joint ventures; our intention to increase our capital focus on the key strengths of our asset base and increase our activity levels in 2011; our intention to continue to appraise the resource potential of our extensive portfolio; our belief that the production losses that we have experienced as a result of pipeline apportionment issues and issues at a partner operated gas facility will be resolved, our expectations for the timing of the resolution of such issues, and our belief that we can overcome these production losses and therefore attain our forecast average daily production for 2011; our forecast average daily production range for 2011; our intention to continue our focus on light-oil appraisal and full-scale development and the portion of our 2011 exploration and development capital program that will focus on light-oil projects using horizontal multi-stage fracture technology; our intention to continue to evaluate ongoing drilling results with a concentration on projects with a size and potential to drive growth in both production and reserves; the identity of the resources plays on which we will focus our 2011 capital budget; our intention to use our 2011 capital budget to accelerate the appraisal of our heavy oil interests in the Peace River Oil Partnership and our unconventional natural gas assets located in the Cordova Embayment; the ability of the Peace River Oil Partnership and the Cordova Joint Venture to enable us to develop these projects in a shorter time-frame than previously anticipated; our belief that we will be the dominant operator in the development of conventional oil in western Canada; the ability of our development stage to deliver better capital efficiencies and improved project returns; the intention for our 2011 capital program to increase our activity level on the Cardium and Carbonates light-oil projects; our ability to remain the most active driller in western Canada; our intention in 2011 to continue ongoing resource appraisal and to move toward full scale project development;
our target for five percent growth in 2011 via a capital program dominated by light-oil development.

Our ability to achieve cost reductions through efficiency and technology; our ability to identifying and seize near-term and long-term strategic consolidation opportunities and the types of opportunities being assessed; our belief that the ultimate resource potential of the Peace River oilsands block and the Cordova Embayment will provide extremely attractive returns to our shareholders; the timing for the payment of our first dividend; our ability to increase shareholder value based on a platform of growth and income; the disclosure contained 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 capital program will focus, and our forecast average daily production for 2011; the identification of over 8,000 drilling locations on existing Penn West lands, including approximately 3,800 specific locations; our intention and ability to leverage off of our business strategies to significantly increase and maintain our operating activities; our intention to allocate 90 percent of our 2011 capital program to our light-oil projects; 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 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; the ability of our debt and risk management programs to increase the likelihood that we can maintain our financial flexibility to capture opportunities available in the markets in addition to the continuation of our capital and dividend programs and the longer-term execution of our business strategies; the factors that may affect the amount of dividends that we pay; our belief that our environmental programs will be sufficient to meet or exceed existing environmental regulations; and the disclosure contained under the heading "Sensitivity Analysis" relating to the estimated sensitivity to selected key assumptions of our reported financial results during 2011.

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".

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.

Investor Information

Penn West shares and debentures are listed on the Toronto Stock Exchange under the symbols PWT, PWT.DB.E and PWT.DB.F and Penn West shares are listed on the New York Stock Exchange under the symbol PWE.

A conference call will be held to discuss Penn West's results at 10:00 a.m. Mountain Time (12:00 p.m. Eastern Time) on February 17, 2011.

To listen to the conference call, please call 416-695-6616 or 800-952-4972 (North American toll-free).

This call will be broadcast live on the Internet and may be accessed directly on the Penn West website at www.pennwest.com or at the following URL:

http://events.digitalmedia.telus.com/pennwest/021711/index.php

A taped recording will be available until March 3, 2011 by dialing 800-408-3053 (North American toll-free) and entering pass code 3676641.

FOR FURTHER INFORMATION PLEASE CONTACT:

Penn West Exploration
Suite 200, 207 - 9th Avenue SW
Calgary, Alberta T2P 1K3
403-777-2500 or Toll Free: 1-866-693-2707
403-777-2699 (FAX)
www.pennwest.com

or

Investor Relations:
Toll Free: 1-888-770-2633
investor_relations@pennwest.com

or

William Andrew
CEO
403-777-2502
bill.andrew@pennwest.com

or

Jason Fleury
Manager, Investor Relations
403-539-6343
jason.fleury@pennwest.com

 
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