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Penn West Exploration Announces its Financial Results for the Fourth Quarter Ended December 31, 2012 and 2012 Year-end Reserve Results

February 14, 2013

CALGARY, Feb. 14, 2013 /PRNewswire/ – PENN WEST PETROLEUM LTD. (TSX – PWT; NYSE – PWE) (“PENN WEST”) is pleased to announce its results for the fourth quarter ended
December 31, 2012 and year-end reserve results. All figures are in
Canadian dollars unless otherwise stated.

——————————

We are committed to maximizing the efficiency of our capital programs
and the reliability of our production base while continuing to improve
the company’s balance sheet. We have actively changed the balance of
our asset portfolio through the disposition of non-core properties and
investment in our light-oil resources, a theme that will continue in
2013. These strategies achieve a balance that provides our shareholders
with a meaningful dividend as we demonstrate the value inherent in Penn
West.

2012 HIGHLIGHTS

        --  Driven primarily by oil and natural gas liquids, the company
            generated funds flow of $1.25 billion;
        --  Average production of 161,195 boe (1) per day was within the
            guidance range of 161,000 - 163,000 boe per day and weighted
            approximately 65 percent to oil and liquids;
        --  Completed net dispositions of approximately 16,500 boe per day
            for proceeds of approximately $1.6 billion;
        --  Total debt at year-end was approximately $2.7 billion and
            resulted in a debt-to-EBITDA (2) ratio of 2.1 times;
        --  On a proved plus probable basis, we replaced 190 percent (3)of
            2012 production, excluding economic revisions and acquisition
            and disposition activity through the addition of approximiately
            110 million boe of reserves of which approximately 80 percent
            were crude oil and liquids;
        --  Proved plus probable finding and development costs including
            future development capital improved approximately five percent
            year-over-year to $25.50 per boeor $23.12 per boe (4)excluding
            economic revisions.

FOURTH QUARTER FINANCIAL AND PRODUCTION RESULTS

        --  Funds flow (2) was $295 million ($0.62 per share - basic (2))
            in the fourth quarter of 2012 compared to $437 million ($0.93
            per share - basic) in the fourth quarter of 2011. Funds flow
            was lower in 2012 as a result of lower commodity price
            realizations and disposition activity;
        --  Exploration and development capital expenditures in the fourth
            quarter of 2012 totalled $348 million compared to $594 million
            in the fourth quarter in 2011. Capital activity late in 2012
            included the drilling of 31 net oil wells;
        --  Average production in the fourth quarter of 2012 was 153,931
            boe per day after the impact of net asset dispositions and
            weighted approximately 64 percent to oil and liquids;
        --  We closed non-core asset dispositions during the fourth quarter
            for proceeds of approximately $1.3 billion. The proceeds were
            applied to reduce bank debt which strengthened our balance
            sheet;
        --  During the fourth quarter of 2012, we recorded a net loss of
            $53 million ($0.11 per share - basic) compared to a net loss of
            $62 million ($0.13 per share - basic) in the fourth quarter of
            2011.

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

    (2) The terms "funds flow", "funds flow per share-basic" and "debt to
        EBITDA" are non-GAAP measures. Please refer to the "Calculation of
        Funds Flow" and "Non-GAAP Measures Advisory" sections below.

    (3) Reserve replacement ratio is calculated by dividing reserve
        additions by production on a proved plus probable basis.

    (4) Refer to "finding and development costs" table below for a
        discussion on Adjusted F&D.

ANNUAL FINANCIAL AND PRODUCTION RESULTS

        --  Funds flow for 2012 was approximately $1.25 billion ($2.62 per
            share - basic) compared to $1.54 billion ($3.29 per share -
            basic) in 2011. The decline in funds flow was primarily
            attributed to lower commodity price realizations from wider
            Canadian crude oil differentials and lower natural gas prices;
        --  Total capital expenditures in 2012 of approximately $137
            million compared to $1,866 million in 2011 and were within
            previous guidance of $1.3 to $1.4 billion net of divestments
            closed to the end of the third quarter;
        --  Average production for 2012 was 161,195 boe per day, compared
            to 163,094 boe per day for 2011, and was within our guidance of
            161,000 to 163,000 boe per day, provided prior to the fourth
            quarter divestitures. Production in 2012 was weighted
            approximately 65 percent to oil and liquids compared to 63
            percent in 2011;
        --  For 2012, we recorded net income of $174 million ($0.37 per
            share - basic); a decrease from the $638 million ($1.37 per
            share - basic) recorded in 2011. Net income was lower in 2012
            primarily due to lower revenues related to lower commodity
            price realizations, an impairment charge on certain of our
            natural gas assets as a result of lower natural gas prices,
            partially offset by gains on asset dispositions, and gains from
            risk management items. Results for 2011 included a one-time
            income tax recovery of $304 million as a result of our
            conversion to a corporation.

RESERVES

        --  We increased bookings in all key resource plays in 2012 and
            added approximately 110 million boe of reserves on a proved
            plus probable basis (2011 - 138 million boe) of which
            approximately 80 percent were crude oil and liquids (2011 - 73
            percent).
        --  Our 2012 reserve replacement ratio was 190 percent (2011 - 234
            percent), excluding the effect of acquisitions and dispositions
            and economic factors.
        --  Total working interest proved plus probable reserves were 676
            mmboe at December 31, 2012 (2011 - 719 mmboe), weighted
            approximately 71 percent to crude oil and liquids (2011 - 71
            percent) after the effect of 87 mmboe of oil weighted base
            asset dispositions. In 2012, we recorded gains on these net
            asset dispositions of $384 million (2011 - $172 million).
        --  Adjusted finding and development ("F&D") (1) costs in 2012 of
            $23.12 per boe on a proved plus probable basis, excluding
            economic revisions, represents in excess of a two times initial
            recycle ratio (2) on new light-oil development.
        --  Including the impact of future development capital and after
            the effect of economic revisions, finding and development costs
            on a proved plus probable basis improved to $25.50 per boe in
            2012 compared to $26.79 per boe in 2011. Economic revisions of
            approximately 10 mmboe were primarily related to base natural
            gas assets.
        --  Our three-year average finding and development cost performance
            continues to support in excess of a two times initial recycle
            ratio on new light-oil development.
        --  During 2012, contingent resource studies were completed by
            independent reserves evaluators on our interests in the Cardium
            and within the Peace River Oil Partnership which confirmed our
            internal estimates of significant recoverable resources in
            these areas.

    (1) Refer to "finding and development costs" table below for a
        discussion on Adjusted F&D.

    (2) Recycle ratio is calculated by dividing the initial netback on
        liquids production by finding and development costs.

COMMODITY ENVIRONMENT

        --  For 2013, we currently have 55,000 barrels per day of our crude
            oil production hedged between US$91.55 and US$104.42 per barrel
            and 125,000 mcf per day of our natural gas production hedged at
            $3.34 per mcf. Additionally, we have 50 MW of Alberta
            electricity consumption fixed at $55.20 per MWh.
        --  In 2012, WTI crude oil prices averaged US$94.17 per barrel
            compared to US$95.14 per barrel in 2011 and Brent averaged
            US$111.64 per barrel compared to US$111.11 per barrel in 2011.
            For 2012, Edmonton light sweet traded at an average discount of
            $7.97 per barrel compared to WTI (2011 - premium of $1.22 per
            barrel).
        --  In the fourth quarter of 2012, WTI crude oil prices averaged
            US$88.20 per barrel compared to US$92.19 per barrel in the
            third quarter of 2012 and US$94.02 per barrel for the fourth
            quarter of 2011. Edmonton light sweet oil traded at a discount
            of $3.46 per barrel compared to WTI during the fourth quarter
            of 2012 (2011 - premium of $1.44 per barrel) compared to a
            discount of $7.40 per barrel during the third quarter of 2012.
        --  In 2012, the AECO Monthly Index averaged $2.40 per mcf compared
            to $3.67 per mcf in 2011.
        --  In the fourth quarter of 2012, the AECO Monthly Index averaged
            $3.06 per mcf compared to $2.19 per mcf in the third quarter of
            2012 and $3.47 per mcf for the fourth quarter of 2011.

DIVIDEND

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

OPERATIONS UPDATE

Our successful appraisal activities, our ongoing efforts to consolidate
our asset base and infrastructure development during 2010 to 2012
support our shift to a capital efficient light-oil development program
in 2013. Our 2013 capital program is focused on improving capital
efficiencies by allocating capital to areas we have significantly
de-risked from a development perspective, where we have, and expect to
continue to successfully drive down costs, and where we have
infrastructure capacity. We plan to reach our peak operating activity
at lower levels than in 2012, enabling the utilization of optimal
equipment allocations in all aspects of our development programs. This
year, 150 to 210 development wells are planned primarily targeting
light oil. We are also increasing focus on the reliability of base
production and working to reduce our cash costs in 2013.

The incremental capital added in late 2012 provided momentum as we
entered 2013, which should enable us to bring more production on-stream
prior to reducing operations at break-up this coming spring. To date in
2013, development costs, production deliverables and base production
reliability are all on or ahead of plan.

Oil Development

Spearfish 

        --  Over the past few years, we have increased the predictability
            from this play, successfully reduced cycle times to lower costs
            and increased our oil processing infrastructure. Our Waskada
            play is a key focus in 2013 due to its attractive economics,
            predictable type curve and short cycle times. We plan to drill
            90 to 130 wells in the area in 2013.
        --  In 2013, drill times have been further reduced from eight to
            four days. We currently have five rigs operating in the area.
        --  Our natural gas liquids extraction plant remains on plan for
            start-up during the second quarter of 2013.

Carbonates

        --  We have a significant land position of approximately 500,000
            net acres within the Carbonates. Our drilling inventory
            continues to expand, targeting the large and economic
            accumulations of light oil. Well results have been encouraging,
            particularly in the Sawn Lake area, where early results
            continue to exceed expectations.
        --  In 2013, we have a focused development program in the Slave
            Point, notably in the Sawn Lake and Swan Hills areas. During
            the first quarter of 2013, completion activity has continued on
            wells drilled and carried over from 2012.
        --  We continue improving efficiencies in these plays. Over the
            past few months reduced drilling times in the Sawn Lake area
            have resulted in significant cost savings of between $500,000
            and $900,000 per well compared to 2012.
        --  The completion of our Sawn Lake battery expansion in late 2012,
            and the expansion of our gas handling capacity in the Slave
            Point area, should provide infrastructure capacity for several
            years of development activity.
        --  In addition, we continue to advance our Enhanced Oil Recovery
            ("EOR") strategy in the Slave Point in 2013 with the initiation
            of horizontal waterflood pilots at Sawn Lake and Otter.

Cardium

        --  We are the largest landholder in the Cardium with over 600,000
            net acres and have a dominant infrastructure position across
            the play.
        --  The Cardium is a significant accumulation of light oil which
            will drive long-term growth and value creation for us due to
            the areal extent of the light-oil in place combined with the
            potential for significant recoveries using a combination of
            horizontal development and EOR techniques.
        --  In 2013, our capital budget includes selective drilling in the
            Alder Flats and West Pembina areas and further progression on
            our enhanced oil recovery strategy within the trend which
            includes plans for two horizontal waterflood pilots in
            Willesden Green.
        --  Results at our initial horizontal waterflood pilot in Pembina
            remain very promising, with production of 150 barrels of oil
            per day from three previously shut in legacy vertical wells.

Viking

        --  Over the past few years, we have consolidated our position in
            the area and have experienced repeatable and predictable well
            results. We plan to continue to high grade this asset
            going-forward.
        --  During 2013, we plan to drill 25 to 30 wells primarily in the
            Dodsland area and expand the infrastructure to support ongoing
            development programs into 2014 and beyond.

Exploration and Joint Ventures 

        --  We have a material Duvernay position in the liquids-rich
            fairway of the Willesden Green area. Our initial stratigraphic
            assessment well was consistent with our geological studies, and
            industry activities continue to support our assessment of the
            significant potential in this play. We plan a further
            stratigraphic test in 2013.
        --  In the Peace River Oil Partnership, 2013 capital plans include
            continued primary recovery and thermal appraisal, additional
            engineering work at our Seal Main thermal pilot and Seal Main
            commercial project and further assessment of our Harmon Valley
            South thermal pilot. Our industry leading steam oil ratios
            continue at our Seal Main thermal pilot as it approaches the
            end of its second steam cycle.
        --  In the Cordova Joint Venture, assessment and appraisal work
            will continue in 2013.

HIGHLIGHTS


                        Three months ended December                Year ended December 31
                                                 31

                                                  %                                     %
                           2012         2011 change            2012         2011   change

    Financial
    (millions, except per share
    amounts)

    Gross revenues    $     799    $     979   (18)       $   3,283    $   3,604      (9)
    (1)

    Funds flow              295          437   (33)           1,248        1,537     (19)

       Basic per           0.62         0.93   (33)            2.62         3.29     (20)
       share

       Diluted per         0.62         0.93   (33)            2.62         3.29     (20)
       share

    Net income (loss)      (53)         (62)   (15)             174          638     (73)

       Basic per                      (0.13)   (15)            0.37         1.37     (73)
       share             (0.11)

       Diluted per                    (0.13)   (15)            0.37         1.36     (73)
       share             (0.11)

    Capital               (916)          583  (100)             137        1,580     (91)
    expenditures, net
    (2)

    Debt at           $   2,690    $   3,219   (16)       $   2,690    $   3,219     (16)
    period-end

    Dividends
    (millions)

    Dividends paid    $     129    $     127      2       $     512    $     420       22
    (3)

    DRIP                   (31)         (26)     19           (117)         (92)       27

    Dividends paid in $      98    $     101    (3)       $     395    $     328       20
    cash

    Operations                                                                           

    Daily production                                                                     

       Light oil and     82,224       90,185    (9)          86,783       85,316        2
       NGL (bbls/d)

       Heavy oil         16,847       17,886    (6)          17,361       17,892
       (bbls/d)                                                                       (3)

       Natural gas          329          364   (10)             342          359
       (mmcf/d)                                                                       (5)

    Total production    153,931      168,801    (9)         161,195      163,094
    (boe/d)                                                                           (1)

    Average sales
    price

       Light oil and  $   75.91    $   88.76   (15)       $   77.16    $   86.19
       NGL (per bbl)                                                                 (10)

       Heavy oil (per     59.85        76.88   (22)           63.67        69.07
       bbl)                                                                           (8)

       Natural gas    $    3.28    $    3.47    (5)       $    2.45    $    3.78
       (per mcf)                                                                     (35)

    Netback per boe                                                                      

       Sales price    $   54.10    $   63.05   (14)       $   53.60    $   60.99
                                                                                     (12)

       Risk                0.51       (0.84)    100            0.81       (1.06)      100
       management
       gain (loss)

       Net sales          54.61        62.21   (12)           54.41        59.93      (9)
       price

       Royalties        (10.10)      (11.47)   (12)         (10.07)      (11.09)      (9)

       Operating        (17.16)      (17.48)    (2)         (17.26)      (17.40)      (1)
       expenses

       Transportation    (0.51)       (0.48)      6          (0.50)       (0.49)        2

       Netback        $   26.84    $   32.78   (18)       $   26.58    $   30.95     (14)

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

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

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

DRILLING STATISTICS


                      Three months ended December 31 Year ended December 31

                            2012                2011       2012        2011

                      Gross  Net Gross           Net Gross  Net Gross   Net

    Oil                  55   31   135           101   349  263   457   353

    Natural gas           -    -     7             4    23   19    53    36

                         55   31   142           105   372  282   510   389

    Stratigraphic and     9    1    12             3    72   32    89    37
    service

    Total                64   32   154           108   444  314   599   426

    Success rate (1)        100%                100%       100%        100%

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

CAPITAL EXPENDITURES


                     Three months ended December 31 Year ended December 31

    (millions)            2012                 2011      2012         2011

    Land acquisition $       1 $                  9 $      37 $        181
    and retention

    Drilling and           160                  410     1,148        1,217
    completions

    Facilities and         205                  197       675          521
    well equipping

    Geological and           3                    -        13            9
    geophysical

    Corporate                3                    8        16           25

    Capital                372                  624     1,889        1,953
    expenditures (1)

    Joint venture,        (24)                 (30)     (137)        (107)
    carried capital

    Property           (1,264)                 (11)   (1,615)        (266)
    dispositions, net

    Business                 -                    -         -          286
    combinations

    Total            $   (916) $                583 $     137 $      1,866
    expenditures

    (1) Capital expenditures include costs related to Property, Plant and
        Equipment and Exploration and Evaluation activities.

Our 2012 capital program continued to be directed towards our key
light-oil projects, focusing on the Carbonates, Cardium, Spearfish and
Viking. During 2012, we completed net property dispositions of non-core
properties with combined production of approximately 16,500 barrels of
oil equivalent per day.

LAND


                                                 As at December 31

                                   Producing       Non-producing

                                              %                  %
                              2012  2011 change  2012  2011 change

    Gross acres (000s)       5,733 6,144    (7) 2,680 2,980   (10)

    Net acres (000s)         3,841 4,093    (6) 1,896 2,105   (10)

    Average working interest   67%   67%      -   71%   71%      -

COMMON SHARES DATA


                      Three months ended December 31 Year ended December 31

    (millions of                                   %                      %
    shares)            2012  2011             change  2012  2011     change

    Weighted average                                                       

      Basic           478.9 471.1                  2 475.6 467.2          2

      Diluted         478.9 471.2                  2 475.8 467.4          2

    Outstanding as at                                479.3 471.4          2
    December 31

RESERVES DATA

Our proved reserves continue to reflect a high percentage of developed
reserves. Of total proved reserves, 78 percent were developed at
December 31, 2012 (2011 – 80 percent). At December 31, 2012, total
proved reserves as a percentage of proved plus probable reserves were
66 percent (2011 – 69 percent). In 2012, all of our reserves were
evaluated or audited by independent, qualified engineering firms GLJ
Petroleum Consultants Ltd. (“GLJ”) and Sproule Associates Limited
(“SAL”). Approximately 18 percent of total proved plus probable
reserves were internally evaluated and then audited by our independent
qualified reserve evaluators.

The reserves estimates have been calculated in compliance with 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 below 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.

a)  Working Interest Reserves using forecast prices and costs


    Penn West as                                               Barrels of
    at               Light &                       Natural Gas        Oil
    December 31,  Medium Oil Heavy Oil Natural Gas     Liquids Equivalent
    2012

    Reserve
    Estimates
    Category (1)
    (2)              (mmbbl)   (mmbbl)       (bcf)     (mmbbl)    (mmboe)

    Proved                                                               

    Developed
    producing            163        44         641          21        334

    Developed
    non-producing          4         1          32           1         11

    Undeveloped           76         2         100           5         99

    Total Proved         243        46         773          27        445

    Probable             108        44         413          11        231

     Total Proved
    plus Probable        351        90       1,186          38        676

    (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                                               Barrels of
    at               Light &                       Natural Gas        Oil
    December 31,  Medium Oil Heavy Oil Natural Gas     Liquids Equivalent
    2012

    Reserve
    Estimates
    Category (1)
    (2)              (mmbbl)   (mmbbl)       (bcf)     (mmbbl)    (mmboe)

    Proved                                                               

    Developed
    producing            140        40         564          15        290

    Developed
    non-producing          4         1          27           1          9

    Undeveloped           65         2          89           4         86

    Total Proved         209        42         680          20        384

    Probable              89        38         349           8        194

    Total Proved
    plus Probable        298        81       1,029          28        578

    (1) Net after royalty reserves are working interest reserves including
        royalty interests and deducting royalty burdens.

    (2) Columns may not add due to rounding.

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               Heavy Oil
                                 (mmbbl)                       (mmbbl)

                                          Proved                     Proved
    Reconciliation                          plus                       plus
    Items (1)           Proved Probable probable   Proved Probable probable

    December 31, 2011      288      113      401       51       22       73

    Extensions               5        9       14        -        -        -

    Improved Recovery        1        5        7        2       22       24

    Infill Drilling         23       14       37        2        2        3

    Technical Revisions      7     (11)      (4)        3      (1)        3

    Discoveries              -        -        -        -        -        -

    Acquisitions             -        -        -        -        -        -

    Dispositions          (54)     (22)     (75)      (5)      (2)      (6)

    Economic Factors       (1)        -      (2)        -        -        -

    Production            (28)        -     (28)      (6)        -      (6)

    December 31, 2012      243      108      351       46       44       90

                                                            Natural Gas
                     Natural Gas Liquids (mmbbl)               (bcf)

                                          Proved                     Proved
    Reconciliation                          plus                       plus
    Items (1)        Proved Probable    probable   Proved Probable probable

    December 31,         28       12          39      783      452    1,235
    2011

    Extensions            1        1           1       17       43       60

    Improved              1        -           1        2        1        3
    Recovery

    Infill Drilling       -        -           1       10        9       18

    Technical             2      (1)           1      138     (86)       51
    Revisions

    Discoveries           -        -           -        -        -        -

    Acquisitions          -        -           -        4        1        6

    Dispositions        (1)      (1)         (2)     (12)      (5)     (18)

    Economic Factors    (1)        -         (1)     (46)        -     (47)

    Production          (4)        -         (4)    (123)        -    (123)

    December 31,         27       11          38      773      413    1,186
    2012

                             Barrels of Oil Equivalent
                                      (mmboe)

                                                Proved
                                                  plus
    Reconciliation Items (1) Proved Probable  probable

    December 31, 2011           498      222       719

    Extensions                    9       17        25

    Improved Recovery             5       28        33

    Infill Drilling              27       17        44

    Technical Revisions          35     (27)         8

    Discoveries                   -        -         -

    Acquisitions                  1        -         1

    Dispositions               (61)     (25)      (87)

    Economic Factors           (10)        -      (10)

    Production                 (58)        -      (58)

    December 31, 2012           445      231       676

    (1) Columns may not add due to rounding.

On a proved plus probable basis our reserves continued to be weighted 71
percent to crude oil and liquids (2011 – 71 percent) and 29 percent to
natural gas (2011 – 29 percent). Our successful tight-oil development
activities and the application of techniques including waterflood and
EOR offset 2012 reserve dispositions which were predominately weighted
towards oil. Economic revisions were primarily due to lower natural gas
prices on base assets.

d)  Net present value of future net revenue using forecast prices and
costs (millions) at December 31, 2012


                      Net present value of future net revenue before income
                                              taxes
                                         (discounted @)

    Reserve Category        0%       5%     10%     15%                 20%
    (1)

    Proved                                                                 

      Developed       $ 10,179 $  7,151 $ 5,603 $ 4,659 $             4,017
      producing

      Developed            312      220     167     134                 112
      non-producing

      Undeveloped        2,896    1,620     942     541                 284

      Total proved    $ 13,387 $  8,990 $ 6,713 $ 5,334 $             4,413

    Probable             8,031    4,033   2,417   1,604               1,133

    Total proved plus $ 21,419 $ 13,023 $ 9,130 $ 6,937 $             5,546
    probable

    (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 using forecast
prices and costs as of December 31, 2012

 


                                            Oil                                                     

                                                             Natural                        Exchange
                 WTI    Edmonton  Lloydminster    Cromer       gas                            rate
               Cushing,   Par        Blend        Medium       AECO     Edmonton  Inflation   (US$
               Oklahoma 40o API     21o API      29o API    gas price   propane     rate     equals

    Year       ($US/bbl($CAD/bbl)  ($CAD/bbl)  ($CAD/bbl)   ($CAD/mcf) ($CAD/bbl)     (%)   $1 CAD)

    Historical                                                                                      

    2008         98.05     101.82        82.59      93.40         8.16      58.31       1.7     0.94

    2009         61.60      66.32        58.39      62.98         4.20      37.99       0.3     0.88

    2010         79.42      78.02        66.79      73.81         4.17      46.87       1.8     0.97

    2011         94.83      95.15        76.37      87.57         3.68      53.47       3.0     1.01

    2012         94.15      86.70        73.05      81.26         2.44      38.18       1.5     1.00

    Forecast                                                                                        

    2013         89.82      84.78        69.63      78.84         3.35      40.61       1.8     1.00

    2014         91.21      90.67        75.26      83.42         3.78      47.98       1.8     1.00

    2015         91.64      91.10        75.62      83.81         4.09      52.93       1.8     1.00

    2016         96.51      95.97        80.13      88.77         4.71      55.86       1.8     1.00

    2017         97.23      96.68        80.73      89.43         5.13      56.43       1.8     1.00

    2018         97.95      97.41        81.34      90.11         5.31      56.82       1.8     1.00

    2019         99.21      98.67        82.39      91.27         5.40      57.52       1.8     1.00

    2020        100.95     100.40        83.84      92.88         5.50      58.51       1.8     1.00

    2021        102.71     102.17        85.31      94.51         5.60      59.51       1.8     1.00

    2022        104.51     103.96        86.81      96.16         5.70      60.54       1.8     1.00

    Thereafter    1.8%       1.8%         1.8%       1.8%         1.8%       1.8%         -        -
    escalating
    at

f) Finding and development costs (“F&D costs”)


                                                     Year ended December 31

                                  2012       2011       2010 3-Year average

    Adjusted F&D costs
    including Future
    Development Costs ("FDC")
    (1)

      F&D costs per boe -      $ 23.12    $ 23.96    $ 23.39 $        23.54
      proved plus probable

      F&D costs per boe -      $ 26.91    $ 31.69    $ 25.25 $        28.43
      proved

    F&D costs excluding FDC(2)                                             

      F&D costs per boe -      $ 17.48    $ 15.07    $ 18.90 $        16.76
      proved plus probable

      F&D costs per boe -      $ 26.69    $ 23.55    $ 21.50 $        24.02
      proved

    F&D costs including FDC
    (3)

      F&D costs per boe -      $ 25.50    $ 26.79    $ 26.73 $        26.32
      proved plus probable

      F&D costs per boe -      $ 30.96    $ 37.05    $ 28.01 $        32.60
      proved

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

    (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.

Capital expenditures for 2012 have been reduced by $137 million related
to joint venture carried capital (2011 – $107 million). We use Adjusted
F&D to assess the economic viability of our oil development programs.
F&D costs are calculated in accordance with NI 51-101, which include
the change in FDC, on a proved and proved plus probable basis. For
comparative purposes we also disclose F&D costs excluding FDC.

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

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


                            Proved Future     Proved plus Probable
    Year                Development Costs Future Development Costs

    2013                $             994 $                  1,233

    2014                              787                    1,291

    2015                              519                      997

    2016                               98                      254

    2017                               19                       35

    2018 and subsequent               146                      308

    Undiscounted total  $           2,563 $                  4,118

    Discounted @ 10%/yr $           2,175 $                  3,411

Letter to our Shareholders

——————————

This past year proved to be challenging and directionally important for
both Penn West and the Canadian energy industry. Our activities of the
past several years have created a platform that includes thousands of
economic oil locations, greater play concentration, exploration
opportunities and core areas with significant oil handling facilities.
Penn West has stated two clear goals for 2013: improving capital
efficiencies and production reliability. We have implemented
organizational changes to attain these objectives. The transition from
resource growth and delineation to our focus on maximizing capital
efficiency is necessary, attainable and important for capital markets
to provide greater recognition of the value of Penn West.

The most important factor affecting oil producers in Canada during 2012
was price differentials between Canadian and US benchmark oil prices
due to North American pipeline bottlenecks. This volatility led to
equity capital markets diversifying away from the Canadian upstream
energy sector. We are focused on mitigating the impact of oil price differential
volatility and potential weakness in crude oil pricing. Penn West has
contracted 35,000 barrels per day of pipeline capacity to the Gulf
coast, which is currently expected to be on-stream mid-2014. This will
provide access to significant US markets which should enable us to
realize higher oil netbacks. We are evolving our crude oil marketing
strategies toward direct sales to refiners and are actively hedging our
crude oil production. We have an average floor price of US$91.55 per
barrel on over 80 percent of our forecast 2013 oil and liquids
production, net of royalties.

We completed two significant external contingent resource studies in
2012. We believe the Cardium is the most significant asset in the
company from a growth and long-term value perspective. The
independently substantiated 533 million barrels of light-oil contingent
resources ((1)) in our Cardium assets confirms our appraisal activities. Notably,
potential recoveries from horizontal multi-fracture water flooding are
not reflected in the study. In the Cardium, 2013 activity is directed
to primary development wells as we continue to develop a longer-term
integrated strategy of primary development with enhanced oil recovery
schemes. Our horizontal waterflood pilot in Pembina provides evidence
of the potential of this strategy.

In the Peace River Oil Partnership, the economic contingent resource ((1)) of 473 million barrels assigned by independent reserves auditors
provided us further validation of our resource base. In 2013, the focus
will be on primary development and continuing engineering and
regulatory applications for the commercial cyclic steam project at Seal
Main. To date, results of the cyclic steam pilot at Seal Main remain
attractive with industry leading steam-oil ratios below 1.5 times and
over 150,000 barrels of oil recovered from the first two steam cycles
from a single well.

As we exited 2012, our reserves book reflected approximately 15 percent
of our identified potential oil drilling locations which we calculate
from a combination of the contingent resource studies and internal
estimates. We are aiming to complete further resource studies on select
plays in our portfolio as we drive further conversions from resource to
reserves. Our proved plus probable finding and development cost was
$25.50 per boe including future development capital, a five percent
improvement over 2011, and approximately 80 percent of these additions
were crude oil and liquids. At year-end 2012, our reserves book was 71
percent oil and natural gas liquids on a proved plus probable basis.

We look forward to sharing results with our shareholders as we deliver
on our 2013 plan.

(signed)

Murray R. Nunns
President and Chief Executive Officer  

Calgary, Alberta
February 13, 2013


    (1)  Contingent resources are net best estimate figures.  See
        "Contingent Resource Disclosures" below.

Outlook

This outlook section is included to provide shareholders with
information about our expectations as at February 13, 2013 for
production and capital expenditures in 2013 and readers are cautioned
that the information may not be appropriate for any other purpose. This
information constitutes forward-looking information. Readers should
note the assumptions, risks and discussion under “Forward-Looking
Statements” and are cautioned that numerous factors could potentially
impact our capital expenditure levels and production performance for
2013, including our current disposition program.

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

There have been no changes to our guidance from our prior forecast,
released on January 9, 2013 with our “2013 Budget” release and filed on
SEDAR at www.sedar.com.

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

Non-GAAP Measures Advisory

This news release includes non-GAAP measures not defined under
International Financial Reporting Standards (“IFRS”) including funds
flow, funds flow per share-basic, funds flow per share-diluted, netback
and debt to EBITDA ratio. 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 decommissioning 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, to
economically rank projects and is the per unit of production amount of
revenue less royalties, operating costs, transportation and realized
risk management gains and losses. Debt to EBITDA is a financial
covenant for Penn West in the agreements governing our credit facility
and our senior unsecured notes and compares our current and long-term
debt balance to our earnings before interest, taxes, depreciation and
amortization.

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. Given that
the value ratio based on the current price of crude oil as compared to
natural gas is significantly different from the energy equivalency
conversion ratio of 6:1, utilizing a conversion on a 6:1 basis is
misleading as an indication of value.

Contingent Resource Disclosures

In this press release, Penn West discusses the results of two recently
completed independent resource evaluation studies which include an AJM
Deloitte (“AJM”) contingent resource evaluation effective July 31,
2012, for Penn West’s Cardium properties and a Sproule Unconventional
Limited (“Sproule”) contingent resource evaluation report effective
September 30, 2012 for Penn West’s interest in the Peace River Oil
Partnership (the “PROP”). Penn West holds a 55 percent interest in PROP
and all figures presented in this release in respect of PROP assets
reflect Penn West’s 55 percent interest. This release contains certain
information reproduced from both the AJM Report and the Sproule Report,
but does not contain either report in its entirety.

AJM has assigned contingent resources of 533 million barrels of oil in
the best estimate case for Penn West’s Cardium properties. Sproule has
assigned contingent resources of 473 million barrels of bitumen in the
best estimate case for Penn West’s interest in the PROP assets.

The contingent resource assessments prepared by AJM and Sproule were
prepared in accordance with the definitions, standards and procedures
contained in the Canadian Oil and Gas Evaluation Handbook (the “COGE
Handbook”) and NI 51-101. Contingent resource is defined in the COGE
Handbook as those quantities of petroleum estimated to be potentially
recoverable from known accumulations using established technology or
technology under development, but which do not currently qualify as
reserves or commercially recoverable due to one or more contingencies.
Contingencies may include factors such as economic, legal,
environmental, political and regulatory matters or a lack of markets.
There is no certainty that it will be commercially viable to produce
any portion of the contingent resources.

The economic viability of Penn West’s Cardium contingent resources is
undetermined, as economic studies have not yet been completed. All of
PROP’s contingent resources are considered economic using Sproule’s
September 30, 2012 forecast prices.

Under the COGE Handbook and NI 51-101, naturally occurring hydrocarbons
with a viscosity greater than 10,000 centipoise are classed as bitumen.
The majority of the contingent resource at PROP will be recovered by
thermal processes.

Please refer to our press release dated October 17, 2012 “Penn West
Updates Asset Dispositions and Results of the Contingent Resources
Studies” for further information.

Forward-Looking Statements

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


                                      Penn West Petroleum Ltd.
                                     Consolidated Balance Sheets

                                                          As at December 31

    (CAD millions, unaudited)                              2012        2011

    Assets                                                                 

    Current                                                                

       Accounts receivable        $                         364    $    486

       Other                                                 79         104

       Deferred funding assets                              187         236

       Risk management                                       76          39

                                                            706         865

    Non-current                                                            

       Deferred funding assets                              238         360

       Exploration and evaluation                           609         418
       assets

       Property, plant and                               10,892      11,893
       equipment

       Goodwill                                           2,020       2,020

       Risk management                                       26          28

                                                         13,785      14,719

    Total assets                  $                      14,491    $ 15,584

    Liabilities and Shareholders'
    Equity

    Current                                                                

       Accounts payable and       $                         764    $  1,108
       accrued liabilities

       Dividends payable                                    129         127

       Current portion of                                     5           -
       long-term debt

       Risk management                                        9         114

                                                            907       1,349

    Non-current                                                            

       Long-term debt                                     2,685       3,219

       Decommissioning liability                            635         607

       Risk management                                       35          46

       Deferred tax liability                             1,350       1,287

       Other non-current                                      5           9
       liabilities

                                                          5,617       6,517

    Shareholders' equity                                                   

       Shareholders' capital                              8,985       8,840

       Other reserves                                        97          95

       Retained earnings                                  (208)         132
       (deficit)

                                                          8,874       9,067

    Total liabilities and         $                      14,491    $ 15,584
    shareholders' equity


                                    Penn West Petroleum Ltd.
                               Consolidated Statements of Income

                                 Three months ended             Year ended
                                        December 31            December 31

    (CAD millions, except per      2012        2011       2012        2011
    share amounts, unaudited)

              Oil and          $    791    $    992    $ 3,235    $  3,667
              natural gas
              sales

              Royalties           (144)       (179)      (595)       (661)

                                    647         813      2,640       3,006

              Risk
              management
              gain (loss)

                Realized              8        (13)         48        (63)

                Unrealized           10       (253)        156           8

                                    665         547      2,844       2,951

    Expenses                                                              

              Operating             243         271      1,019       1,036

              Transportation          7           7         29          29

              General and            46          30        172         142
              administrative

              Restructuring          13           -         13           -

              Share-based          (12)          68       (10)          84
              compensation

              Depletion,            598         308      1,525       1,158
              depreciation
              and impairment

              Gain on             (279)        (21)      (384)       (172)
              dispositions

              Exploration            15          10         17          15
              and evaluation

              Unrealized              6        (23)          5        (25)
              risk
              management
              (gain) loss

              Unrealized             22        (53)       (32)          38
              foreign
              exchange
              (gain) loss

              Financing              52          48        199         190

              Accretion              22          12         54          45

                                    733         657      2,607       2,540

    Income (loss) before           (68)       (110)        237         411
    taxes

              Deferred tax         (15)        (48)         63       (227)
              expense
              (recovery)

    Net and comprehensive      $   (53)    $   (62)    $   174    $    638
    income (loss)

    Net income (loss) per
    share

              Basic            $           $ (0.13)    $  0.37    $   1.37
                                 (0.11)

              Diluted          $           $ (0.13)    $  0.37    $   1.36
                                 (0.11)

    Weighted average shares
    outstanding (millions)

              Basic               478.9       471.1      475.6       467.2

              Diluted             478.9       471.2      475.8       467.4

                                   Penn West Petroleum Ltd.
                             Consolidated Statements of Cash Flows

                               Three months ended                Year ended
                                      December 31               December 31

    (CAD millions,                2012       2011         2012         2011
    unaudited)

    Operating activities                                                   

      Net income (loss)      $    (53)    $  (62)    $     174    $     638

      Depletion,                   598        308        1,525        1,158
      depreciation and
      impairment

      Gain on dispositions       (279)       (21)        (384)        (172)

      Exploration and               15         10           17           15
      evaluation

      Accretion                     22         12           54           45

      Deferred tax expense        (15)       (48)           63        (227)
      (recovery)

      Share-based                 (11)         61         (18)           75
      compensation

      Unrealized risk              (4)        230        (151)         (33)
      management loss
      (gain)

      Unrealized foreign            22       (53)         (32)           38
      exchange loss (gain)

      Decommissioning             (32)       (36)         (92)         (81)
      expenditures

      Change in non-cash           178         83           37         (49)
      working capital

                                   441        484        1,193        1,407

    Investing activities                                                   

      Capital expenditures       (348)      (594)      (1,752)      (1,846)

      Property                   1,264         11        1,615          266
      dispositions
      (acquisitions), net

      Business                       -          -            -        (166)
      combinations

      Change in non-cash             8         56        (168)          113
      working capital

                                   924      (527)        (305)      (1,633)

    Financing activities                                                   

      Increase (decrease)      (1,267)        230        (496)          475
      in bank debt

      Proceeds from                  -        137            -          212
      issuance of notes

      Repayment of                   -          -            -         (39)
      acquired credit
      facilities

      Issue of equity                -          1            3          161

      Dividends paid              (98)      (101)        (395)        (328)

      Settlement of                  -      (224)            -        (255)
      convertible
      debentures

                               (1,365)         43        (888)          226

    Change in cash                   -          -            -            -

    Cash, beginning of               -          -            -            -
    period

    Cash, end of period      $       -    $     -    $       -    $       -

                                 Penn West Petroleum Ltd.
                       Statements of Changes in Shareholders' Equity

    (CAD millions,   Shareholders'           Other
    unaudited)             Capital        Reserves   Deficit          Total

    Balance at       $       8,840    $         95 $     132    $     9,067
    January 1,
    2012

    Net and                      -               -       174            174
    comprehensive
    income

    Share-based                  -              27         -             27
    compensation

    Issued on                   28                         -              3
    exercise of                               (25)
    options and
    share rights

    Issued to                  117               -         -            117
    dividend
    reinvestment
    plan

    Dividends                    -               -                    (514)
    declared                                           (514)

    Balance at       $       8,985    $         97 $            $     8,874
    December 31,                                       (208)
    2012

    (CAD millions,   Shareholders'           Other  Retained
    unaudited)             Capital        Reserves  Earnings          Total

    Balance at       $       9,170    $          - $            $     8,560
    January 1,                                         (610)
    2011

    Elimination of                               -       610              -
    deficit                  (610)

    Net and                      -               -       638            638
    comprehensive
    income

    Implementation               -              81         -             81
    of Option Plan
    and CSRIP

    Share-based                  -              41         -             41
    compensation

    Issued on                  188                         -            161
    exercise of                               (27)
    options and
    share rights

    Issued to                   92               -         -             92
    dividend
    reinvestment
    plan

    Dividends                    -               -                    (506)
    declared                                           (506)

    Balance at       $       8,840    $         95 $     132    $     9,067
    December 31,
    2011

MANAGEMENT COMMENTARY

For the three months and year ended December 31, 2012

——————————

All dollar amounts contained in this Management Commentary are expressed
in millions of Canadian dollars unless noted otherwise. We follow
International Financial Reporting Standards (“IFRS”) in the preparation
of the amounts reported in our financial statements.

Please refer to our cautionary notes relating to forward-looking
statements at the end of this 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. Given that the value
ratio based on the current price of crude oil as compared to natural
gas is significantly different from the energy equivalency conversion
ratio of 6:1, utilizing a conversion on a 6:1 basis is misleading as an
indication of value.

Certain financial measures including funds flow, funds flow per
share-basic, funds flow per share-diluted and netback included in this
Management Commentary do not have a standardized meaning prescribed by
IFRS and therefore are considered non-GAAP measures; accordingly, they
may not be comparable to similar measures provided by other issuers.
Funds flow is cash flow from operating activities before changes in
non-cash working capital and decommissioning expenditures. Funds flow
is used to assess our ability to fund dividend and planned capital
programs. See below for reconciliations of funds flow to its nearest
measure prescribed by GAAP. Netback is the per unit of production
amount of revenue less royalties, operating costs, transportation and
realized risk management gains and losses and is used in capital
allocation decisions and to economically rank projects.

Calculation of Funds Flow


                                 Three months ended            Year ended
                                        December 31           December 31
    (millions, except per
    share amounts)              2012           2011       2012       2011

    Cash flow from operating $   441    $       484    $ 1,193    $ 1,407
    activities

    Increase (decrease) in     (178)           (83)       (37)         49
    non-cash working capital

    Decommissioning               32             36         92         81
    expenditures

    Funds flow               $   295    $       437    $ 1,248    $ 1,537

    Basic per share          $  0.62    $      0.93    $  2.62    $  3.29

    Diluted per share        $  0.62    $      0.93    $  2.62    $  3.29

Annual Financial Summary


                                                     Year ended December 31

    (millions, except per share
    amounts)                              2012       2011         2010 (1)

    Gross revenues (2)                $  3,283   $  3,604   $        3,034

    Funds flow                           1,248      1,537            1,185

       Basic per share                    2.62       3.29             2.68

       Diluted per share                  2.62       3.29             2.65

    Net income                             174        638            1,110

       Basic per share                    0.37       1.37             2.51

       Diluted per share                  0.37       1.36             2.48

    Capital expenditures, net (3)          137      1,580            (119)

    Debt at year-end                     2,690      3,219            2,496

    Convertible debentures                   -          -              255

    Dividends/ distributions paid (4)      512        420              708

    Total assets                      $ 14,491   $ 15,584   $       14,543

    (1) Comparative 2010 figures are presented under IFRS.

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

    (3) Excludes business combinations.

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

Quarterly Financial Summary

(millions, except per share and production amounts)


                   Dec. 31     Sep. 30     June 30     Mar. 31     Dec. 31     Sep. 30     June 30      Mar.
                                                                                                          31

    Three             2012        2012        2012        2012        2011        2011        2011      2011
    months
    ended

    Gross        $     799   $     840   $     774   $     870   $     979   $     861   $     920   $   844
    revenues
    (1)

    Funds flow         295         344         272         337         437         348         396       356

       Basic          0.62        0.72        0.57        0.71        0.93        0.74        0.85      0.77
       per
       share

       Diluted        0.62        0.72        0.57        0.71        0.93        0.74        0.85      0.77
       per
       share

    Net income                                 235          59                     138         271       291
    (loss)            (53)        (67)                                (62)

       Basic                                  0.50        0.12                    0.29        0.58      0.63
       per          (0.11)      (0.14)                              (0.13)
       share

       Diluted                                0.50        0.12                    0.29        0.58      0.63
       per          (0.11)      (0.14)                              (0.13)
       share

    Dividends          129         129         128         128         127         127         127       125
    declared

       Per       $    0.27   $    0.27   $    0.27   $    0.27   $    0.27   $    0.27   $    0.27   $
       share                                                                                           0.27

    Production                                                                                              

    Liquids         99,071     105,588     104,758     107,199     108,071     101,392      98,998     104,349
    (bbls/d)
    (2)

    Natural            329         329         351         361         364         360         343       371
    gas
    (mmcf/d)

    Total          153,931     160,339     163,181     167,420     168,801     161,323     156,107     166,135
    (boe/d)

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

    (2) Includes crude oil and natural gas liquids.

Business Strategy

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

Business Environment

Average 2012 benchmark crude oil prices remained range bound with WTI
averaging US$94.17 per barrel compared to US$95.14 per barrel in 2011
and Brent averaging US$111.64 per barrel compared to US$111.11 per
barrel in 2011. In the fourth quarter of 2012, WTI averaged US$88.20
per barrel compared to US$92.19 per barrel in the third quarter of 2012
and US$94.02 per barrel in the fourth quarter of 2011. Ongoing issues
in the Middle East and Africa, notably in Syria, Libya and Iran, led to
future supply concerns and supported an upward movement in crude oil
prices. These geopolitical issues were more than offset by Europe’s
sovereign debt concerns, U.S. fiscal cliff risks and uncertainty
regarding China’s economic growth rate.

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

In 2013 to date, the economic climate in Europe and Asia has shown signs
of improvement and the U.S. has taken steps toward resolving its fiscal
and budgetary problems. Geo-political concerns related to Syria and
Iran persist and are expected to provide support to crude prices in
2013. The Seaway project, which added 400,000 barrels per day of oil
pipeline capacity from Cushing, Oklahoma to the U.S. Gulf Coast, came
on stream in early 2013. Numerous other North American pipeline
additions and expansions have been proposed to debottleneck North
American oil. Many of these projects could be subject to environmental
or regulatory delays. The use of rail to deliver crude oil to markets
has grown considerably, particularly in the U.S. Bakken play. In
January 2013, WTI averaged approximately US$94.83 per barrel and
Edmonton light sweet averaged $87.27 per barrel.

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

Crude Oil

Penn West’s average crude oil price for 2012, before the impact of the
realized portion of risk management, was $74.91 per barrel (2011 -
$83.22 per barrel). Currently Penn West has 55,000 barrels per day of
its 2013 crude oil production hedged between US$91.55 and US$104.42 per
barrel.

Natural Gas

In 2012, the AECO Monthly Index averaged $2.40 per mcf compared to $3.67
per mcf in 2011. During the fourth quarter of 2012, the AECO Monthly
Index averaged $3.06 per mcf compared to $2.19 per mcf during the third
quarter of 2012 and $3.47 per mcf during the fourth quarter of 2011.
AECO monthly gas prices hit a low of $1.64 per mcf in May as inventory
levels in North America reached historical highs.

Penn West’s corporate average natural gas price for 2012 before the
impact of the realized portion of risk management was $2.45 per mcf
(2011 – $3.78 per mcf). Penn West currently has 125,000 mcf per day of
natural gas production hedged for 2013 at an average price of $3.34 per
mcf. Penn West also has 25,000 mcf of natural gas production hedged for
2014 at an average price of $3.85 per mcf and an additional 25,000 mcf
per day hedged through the use of collars with a floor of $3.25 per mcf
and a cap of $4.35 per mcf.

RESULTS OF OPERATIONS

Production


                                 Three months ended             Year ended
                                        December 31            December 31

                                                  %                      %
    Daily production            2012    2011 change    2012    2011 change

    Light oil and NGL         82,224  90,185    (9)  86,783  85,316      2
    (bbls/d)

    Heavy oil (bbls/d)        16,847  17,886    (6)  17,361  17,892    (3)

    Natural gas (mmcf/d)         329     364   (10)     342     359    (5)

    Total production (boe/d) 153,931 168,801    (9) 161,195 163,094    (1)

During the fourth quarter of 2012, we completed net asset dispositions
with combined production of approximately 13,000 boe per day. After the
close of the property dispositions during the fourth quarter of 2012,
liquids production was approximately 62 percent of our production base
exiting 2012. In 2013, we will continue to focus our capital activity
on light-oil which should increase our weighting to liquids. Our
natural gas production has declined in 2012 as we focused our
activities on light-oil plays.

For 2012, we completed net property dispositions with combined
production of approximately 16,500 boe per day, primarily weighted to
oil. Our increase in light-oil production is the result of focusing our
activities on light-oil plays.

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

Average Sales Prices


                         Three months ended                      Year ended
                                December 31                     December 31

                                          %                               %
                    2012        2011 change       2012          2011 change

    Light oil    $ 75.91    $  88.76   (15)    $ 77.16    $    86.19   (10)
    and liquids
    (per bbl)

    Risk            0.20      (1.58)    100       0.17        (2.03)    100
    management
    gain (loss)
    (per bbl)(1)

    Light oil      76.11       87.18   (13)      77.33         84.16    (8)
    and liquids
    net (per
    bbl)

    Heavy oil      59.85       76.88   (22)      63.67         69.07    (8)
    (per bbl)

    Natural gas     3.28        3.47    (5)       2.45          3.78   (35)
    (per mcf)

    Risk            0.19           -    100       0.34             -    100
    management
    gain (per
    mcf)(1)

    Natural gas     3.47        3.47      -       2.79          3.78   (26)
    net (per
    mcf)

    Weighted       54.10       63.05   (14)      53.60         60.99   (12)
    average (per
    boe)

    Risk            0.51      (0.84)    100       0.81        (1.06)    100
    management
    gain (loss)
    (per boe)(1)

    Weighted     $ 54.61    $  62.21   (12)    $ 54.41    $    59.93    (9)
    average net
    (per boe)

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

Netbacks


                               Three months ended                 Year ended

                                      December 31                December 31

                                                %                          %

                            2012     2011  change     2012      2011  change

    Light oil and NGL
    (1, 2)

    Production            82,224    90,185    (9)    86,783    85,316      2
    (bbls/day)

      Operating
      netback ($/bbl):

        Sales price    $   75.91 $   88.76   (15) $   77.16 $   86.19   (10)

        Risk                0.20              100      0.17              100
        management                  (1.58)                     (2.03)
        gain (loss)(3)

        Royalties        (14.38)             (15)                        (8)
                                   (16.94)          (15.57)   (16.83)

        Operating        (19.84)              (4)                        (6)
        costs                      (20.75)          (19.86)   (21.05)

        Netback        $   41.89 $   49.49   (15) $   41.90 $   46.28   (10)

    Conventional heavy
    oil

    Production            16,847    17,886    (6)    17,361    17,892    (3)
    (bbls/day)

      Operating
      netback ($/bbl):

        Sales price    $   59.85 $   76.88   (22) $   63.67 $   69.07    (8)

        Royalties         (8.63)             (20)                       (10)
                                   (10.82)           (9.01)   (10.01)

        Operating        (19.22)               10                         10
        costs                      (17.42)          (19.32)   (17.53)

        Transportation    (0.03)             (57)                       (13)
                                    (0.07)           (0.07)    (0.08)

        Netback        $   31.97 $   48.57   (34) $   35.27 $   41.45   (15)

    Total liquids                                                           

    Production            99,071   108,071    (8)   104,144   103,208      1
    (bbls/day)

      Operating
      netback ($/bbl):

        Sales price    $   73.18 $   86.80   (16) $   74.91 $   83.22   (10)

        Risk                0.17              100      0.14              100
        management                  (1.32)                     (1.68)
        gain (loss)(3)

        Royalties        (13.40)             (16)                        (7)
                                   (15.93)          (14.48)   (15.64)

        Operating        (19.73)              (2)                        (3)
        costs                      (20.20)          (19.77)   (20.44)

        Transportation         -            (100)                          -
                                    (0.01)           (0.01)    (0.01)

        Netback        $   40.22 $   49.34   (19) $   40.79 $   45.45   (10)

    Natural gas                                                             

    Production               329       364   (10)       342       359    (5)
    (mmcf/day)

      Operating
      netback ($/mcf):

        Sales price    $    3.28 $    3.47    (5) $    2.45 $    3.78   (35)

        Risk                0.19         -    100      0.34         -    100
        management
        gain (3)

        Royalties         (0.69)               17                       (37)
                                    (0.59)           (0.34)    (0.54)

        Operating         (2.09)              (1)                          4
        costs                       (2.11)           (2.11)    (2.03)

        Transportation    (0.24)                9                          5
                                    (0.22)           (0.23)    (0.22)

        Netback        $    0.45 $    0.55   (18) $    0.11 $    0.99   (89)

    Combined totals                                                         

    Production           153,931   168,801    (9)   161,195   163,094    (1)
    (boe/day)

      Operating
      netback ($/boe):

        Sales price    $   54.10 $   63.05   (14) $   53.60 $   60.99   (12)

        Risk                0.51              100      0.81              100
        management                  (0.84)                     (1.06)
        gain (loss)(3)

        Royalties        (10.10)             (12)   (10.07)              (9)
                                   (11.47)                    (11.09)

        Operating        (17.16)              (2)   (17.26)              (1)
        costs                      (17.48)                    (17.40)

        Transportation    (0.51)                6    (0.50)                2
                                    (0.48)                     (0.49)

        Netback        $   26.84 $   32.78   (18) $   26.58 $   30.95   (14)

    (1)      Excluded from the netback calculation is $72 million primarily
             related to realized risk management gains on our foreign
             exchange contracts which swap US dollar revenue at a fixed
             Canadian dollar rate.

    (2)      Included in the netback calculation is $48 million realized on
             the rearrangement of our 2013 oil collars which closed in the
             third quarter of 2012.

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

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)          2012      2011      change    2012    2011 change

    Light oil and NGL  $ 601     $ 736        (18) $ 2,529 $ 2,657    (5)

    Heavy oil             93       127        (27)     405     452   (10)

    Natural gas          105       116        (10)     349     495   (30)

    Gross revenues (1) $ 799     $ 979        (18) $ 3,283 $ 3,604    (9)

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

Lower commodity price realizations in 2012 resulted in a decline in
liquids revenue from the comparative periods. Also, net disposition
activity which was liquids weighted, occurring primarily in the fourth
quarter of 2012 contributed to a decline in revenues for that period.
Natural gas revenues were affected by lower production and a
significant decline in natural gas prices.

Reconciliation of Decrease in Production Revenues


    (millions)                                                       

    Gross revenues - January 1 - December 31, 2011                $ 3,604

    Increase in light oil and NGL production                           53

    Decrease in light oil and NGL prices (including realized risk   (181)
    management)

    Decrease in heavy oil production                                 (12)

    Decrease in heavy oil prices                                     (35)

    Decrease in natural gas production                               (23)

    Decrease in natural gas prices                                  (123)

    Gross revenues - January 1 - December 31, 2012                $ 3,283

Royalties


                                  Three months ended             Year ended
                                         December 31            December 31

                                                   %                      %
                                2012    2011  change    2012    2011 change

    Royalties (millions)     $   144 $   179    (20) $   595 $   661   (10)

    Average royalty rate (1)     18%     18%       -     18%     18%      -

    $/boe                    $ 10.10 $ 11.47    (12) $ 10.07 $ 11.09    (9)

    (1)      Excludes effects of risk management activities.

Royalties in the fourth quarter of 2012 declined from the comparative
period in 2011 due to lower commodity price realizations and net
dispositions activity. On an annual basis, in 2012 lower commodity
prices and the impact of wider Canadian crude oil differentials to WTI
resulted in lower royalties which was partially offset by a higher
weighting of liquids production. Royalty rates remained consistent
between comparative periods.

Expenses


                        Three months ended                 Year ended
                               December 31                December 31

                                         %                          %
    (millions)         2012    2011 change        2012    2011 change

    Operating      $    243 $   271   (10) $     1,019 $ 1,036    (2)

    Transportation        7       7      -          29      29      -

    Financing            52      48      8         199     190      5

    Share-based    $   (12) $    68  (100) $      (10) $    84  (100)
    compensation

                        Three months ended                 Year ended
                               December 31                December 31

                                         %                          %
    (per boe)          2012    2011 change        2012    2011 change

    Operating      $  17.16 $ 17.48    (2) $     17.26 $ 17.40    (1)

    Transportation     0.51    0.48      6        0.50    0.49      2

    Financing          3.65    3.16     16        3.37    3.20      5

    Share-based    $ (0.82) $  4.32  (100) $    (0.17) $  1.41  (100)
    compensation

Operating

For the fourth quarter of 2012 and on an annual basis in 2012, operating
costs were lower than the comparative periods in 2011 due to our focus
on cost savings, lower electricity costs and acquisition and
disposition activity. The average Alberta electric pool price for 2012
was $64.31 per MWh compared to $76.21 per MWh in 2011.

Operating costs for the fourth quarter of 2012 include a realized gain
on electricity contracts of $4 million (2011 – $3 million) and for 2012
a realized gain of $7 million (2011 – $11 million). We currently have
the following contracts in place that fix the price on our electricity
consumption; in 2013 approximately 50 MW fixed at $55.20 per MWh, in
2014 approximately 80 MW fixed at $58.50 per MWh, in 2015 approximately
55 MW fixed at $58.32 per MWh and in 2016 approximately 25 MW fixed at
$49.90 per MWh.

Financing

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

As at December 31, 2012, the Company had $1.9 billion (2011 – $2.0
billion) of senior unsecured notes outstanding with a weighted average
interest rate, including the effects of cross currency swaps, of
approximately 6.1 percent (2011 – 6.1 percent) and a weighted average
remaining term of 5.5 years (2011 – 6.5 years). At December 31, 2012,
the Company had $650 million of interest rate swaps outstanding at a
weighted average fixed rate of 2.65 percent and an expiry date of
January 2014. These swaps fix a portion of the interest rates under our
bank facility.

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


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

    2007 Notes May 31, 2007  US$475      8 - 15 years 5.80%     4.5 years

    2008 Notes May 29, 2008  US$480,     8 - 12 years 6.25%     5.0 years
                             CAD$30

    UK Notes   July 31, 2008 £57         10 years     6.95% (1) 5.6 years

    2009 Notes May 5, 2009   US$154 (2), 5 - 10 years 8.85% (3) 4.0 years
                             £20,
                             EUR10,
                             CAD$5

    2010 Q1    March 16,     US$250,     5 - 15 years 5.47%     5.8 years
    Notes      2010          CAD$50

    2010 Q4    December 2,   US$170,     5 - 15 years 5.00%     8.7 years
    Notes      2010,         CAD$60
               January 4,
               2011

    2011 Notes November 30,  US$105,     5 - 10 years 4.49%     7.1 years
               2011          CAD$30

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

    (2)      A portion of the 2009 Notes have equal repayments, beginning
             in 2013, over the remaining seven years.

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

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

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

Realized gains and losses on the interest rate swaps are recorded as
financing costs. For the fourth quarter of 2012 an expense of $2
million (2011 – $3 million) was incurred and for 2012 an expense of $9
million (2011 – $12 million) was recorded in financing to reflect that
the floating interest rate was lower than the fixed interest rate
transacted under our interest rate swaps.

Share-Based Compensation

Share-based compensation expense is related to our Stock Option Plan
(the “Option Plan”), our Common Share Rights Incentive Plan (the
“CSRIP”), our Long-Term Retention and Incentive Plan (“LTRIP”), and our
Deferred Share Unit Plan (the “DSU”).

Effective January 1, 2011, we implemented the Option Plan and amended
our Trust Unit Rights Incentive Plan (“TURIP”) to become the CSRIP.
Pursuant to our conversion from a trust to a corporation, TURIP holders
had the choice to receive one restricted option (a “Restricted Option”)
and one restricted right (a “Restricted Right”) for each outstanding
“in-the-money” trust unit right. TURIP holders who chose not to make
the election or held trust unit rights that were “out-of-the-money” on
January 1, 2011, received one common share right (“Share Rights”) with
the same terms under the CSRIP for each trust unit right. Subsequent to
January 1, 2011, all grants are under the Option Plan.

The Restricted Options, Share Rights and subsequent grants under the
Option Plan receive equity treatment for accounting purposes with the
fair value of each instrument expensed over the expected vesting period
based on a graded vesting schedule. The fair values of the Restricted
Options and option grants are calculated using a Black-Scholes
option-pricing model and the fair value of the Share Rights were
calculated using a Binomial Lattice option-pricing model. The
Restricted Rights are accounted for as a liability as holders may elect
to settle in cash or common shares.

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

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

Total share-based compensation was as follows:


                                 Three months ended         Year ended
                                        December 31        December 31

                                                  %                  %
    (millions)                 2012     2011 change   2012 2011 change

    Share-based compensation $ (12) $     68  (100) $ (10) $ 84  (100)

The share price used in the fair value calculation of the LTRIP
liability and Restricted Rights obligation at December 31, 2012 was
$10.80 per share compared to $20.19 per share at December 31, 2011. The
change in the share price has contributed to the share-based
compensation recovery in 2012.

General and Administrative Expenses (“G&A”)


                                Three months ended           Year ended
                                       December 31          December 31

    (millions, except per boe                    %                    %
    amounts)                    2012   2011 change   2012   2011 change

    Gross                     $   65 $   54     20 $  254 $  222     14

      Per boe                   4.61   3.47     33   4.31   3.72     16

    Net                           46     30     53    172    142     21

      Per boe                 $ 3.28 $ 1.88     75 $ 2.91 $ 2.38     22

The increase in G&A in the fourth quarter of 2012 compared to 2011 is
primarily related to higher staff costs, an increase in community
investment activities and lower recoveries during the period as capital
expenditures were lower in 2012. On an annual basis, the increase in
2012 was also attributed to a rise in staff costs.

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

Depletion, Depreciation, Impairment and Accretion


                             Three months ended                  Year ended
                                    December 31                 December 31

    (millions, except                         %                           %
    per boe amounts)      2012    2011   change    2012       2011   change

    Depletion and      $   321 $   308        4 $ 1,248 $    1,168        7
    depreciation
    ("D&D")

    D&D expense per      22.75   19.84       15   21.17      19.62        8
    boe

    Impairment             277       -      100     277       (10)      100

    Impairment per boe   19.53       -      100    4.69     (0.17)      100

    Accretion of            22      12       83      54         45       20
    decommissioning
    liability

    Accretion expense  $  1.51 $  0.76       99 $  0.90 $     0.76       18
    per boe

Our D&D rate has increased due to our capital spending substantially
weighted to light-oil development and the divestment of non-core
properties.

The impairment charge during the fourth quarter of 2012 related to
legacy, base natural gas assets as a result of decreased natural gas
prices.

Taxes 


                                   Three months ended            Year ended
                                          December 31           December 31

                                                    %                     %
    (millions)                2012        2011 change 2012      2011 change

    Deferred tax expense  $   (15) $      (48)   (69) $ 63 $   (227)    100
    (recovery)

The deferred income tax recovery decreased in the fourth quarter of 2012
compared to the fourth quarter of 2011 due to provisions recorded on
gains from property divestitures. In 2012, we recorded a deferred tax
expense due to gains on property dispositions and from unrealized risk
management gains.

The deferred tax recovery for the year ended December 31, 2011 includes
a $304 million recovery related to the tax rate differential on our
conversion from a trust to an E&P company on January 1, 2011. As a
corporation, we are subject to income taxes at Canadian corporate tax
rates. Under the former trust structure, IFRS required us to tax-effect
timing differences in our trust entities at rates applicable to
undistributed earnings of a trust being the maximum marginal income tax
rate for individuals in the Province of Alberta.

Tax Pools


                                                  As at December 31

    (millions)                                       2012      2011

    Undepreciated capital cost (UCC)              $ 1,155 $   1,085

    Canadian oil and gas property expense (COGPE)      24     1,395

    Canadian development expense (CDE)              2,713     2,104

    Canadian exploration expense (CEE)                348       294

    Non-capital losses                              1,963     2,966

    Other                                              21        31

    Total                                         $ 6,224 $   7,875

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

Foreign Exchange


                              Three months ended              Year ended
                                     December 31             December 31

                                               %                       %
    (millions)           2012        2011 change   2012      2011 change

    Unrealized foreign   $ 22 $      (53)    100 $ (32) $      38  (100)
    exchange loss (gain)

We record unrealized foreign exchange gains or losses to translate the
U.S., UK and Euro denominated notes and the related accrued interest to
Canadian dollars using the exchange rates in effect on the balance
sheet date. The unrealized losses in the fourth quarter of 2012 were
largely due to the weakening of the Canadian dollar relative to the US
dollar and unrealized gains on an annual basis in 2012 were primarily
due to the strengthening of the Canadian dollar relative to the US
dollar over that period.

Funds Flow and Net Income (Loss)


                                Three months ended               Year ended
                                       December 31              December 31

    (millions, except
    per share                                    %                        %
    amounts)               2012        2011 change    2012      2011 change

    Funds flow (1)    $     295 $       437   (33) $ 1,248 $   1,537   (19)
    (millions)

       Basic per           0.62        0.93   (33)    2.62      3.29   (20)
       share

       Diluted per         0.62        0.93   (33)    2.62      3.29   (20)
       share

    Net income (loss)      (53)        (62)   (15)     174       638   (73)
    (millions)

       Basic per         (0.11)      (0.13)   (15)    0.37      1.37   (73)
       share

       Diluted per    $  (0.11) $    (0.13)   (15) $  0.37 $    1.36   (73)
       share

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

Funds flow in the fourth quarter of 2012 and for the year ended 2012
decreased from their comparable periods as a result of lower commodity
price realizations and disposition activity.

For the fourth quarter of 2012, the net loss was comparable quarter over
quarter as lower commodity price realizations were offset by gains on
asset dispositions. On an annual basis in 2012, net income decreased as
lower revenues from the decline in commodity prices and an impairment
charge on legacy natural gas properties were partially offset by gains
from property dispositions and unrealized risk management items. Also,
in 2011 we recorded a one-time $304 million deferred income tax
recovery related to our conversion to an E&P company from an income
trust.

Exploration and Evaluation (“E&E”) Capital Expenditures


                                  Three months ended             Year ended
                                         December 31            December 31

                                                   %                      %
    (millions)               2012        2011 change  2012      2011 change

    E&E capital expenditures $ 20 $       167   (88) $ 228 $     321   (29)

E&E expenditures include land acquisitions, appraisal activities at our
Cordova and Peace River joint ventures and other exploration costs. For
2012, we had a non-cash E&E expense of $17 million (2011 – $15 million)
primarily related to land expiries and unsuccessful exploration
activities, transfers into Property, Plant and Equipment totalling $16
million (2011 – $14 million) and dispositions of $4 million (2011 -
nil).

Gain on Asset Dispositions


                        Three months ended             Year ended
                               December 31            December 31

                                         %                      %
    (millions)     2012        2011 change  2012      2011 change

    Gain on asset $ 279 $        21    100 $ 384 $     172    100
    dispositions

The gains recognized in income during 2012 and 2011 related to property
dispositions of non-core assets.

Goodwill


                                         As at December 31

    (millions)                              2012      2011

    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 in prior years.

Liquidity and Capital Resources

Capitalization


                                               As at December 31

                                               2012         2011

    (millions)                                    %            %

    Common shares issued, at market (1) $ 5,176  64 $  9,517  73

    Bank loans and long-term notes        2,690  33    3,219  25

    Working capital deficiency (2)          239   3      309   2

                                        $ 8,105 100 $ 13,045 100

    (1)      The share price at December 31, 2012 was $10.80 (2011 -
             $20.19).

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

Dividends


                                 Three months ended              Year ended
                                        December 31             December 31

    (millions, except per                         %                       %
    share amounts)          2012        2011 change   2012      2011 change

    Dividends declared    $  129 $       127      2 $  514 $     506      2

    Per share               0.27        0.27      -   1.08      1.08      -

    Dividends paid (1)    $  129 $       127      2 $  512 $     420     22

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

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

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

Liquidity

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

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

The Company has a number of covenants related to its syndicated bank
facility and senior, unsecured notes. On December 31, 2012, the Company
was in compliance with all of these financial covenants which consist
of the following:


                                        Limit   December 31, 2012

    Senior debt to EBITDA (1)     Less than 3:1               2.1

    Total debt to EBITDA (1)      Less than 4:1               2.1

    Senior debt to capitalization Less than 50%               23%

    Total debt to capitalization  Less than 55%               23%

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

All senior, unsecured notes contain change of control provisions whereby
if a change of control occurs; the Company may be required to offer to
prepay the notes, which the holders have the right to refuse.

Financial Instruments

We had the following financial instruments outstanding as at December
31, 2012. Fair values are determined using observable market data which
is compared to external counterparty information. We take steps to
limit our credit risk by executing counterparty risk procedures which
include transacting only with institutions within our credit facility
or with high credit ratings and by obtaining financial security in
certain circumstances.


                          Notional      Remaining                Fair value
                            volume           term        Pricing (millions)

    Crude oil                                                              

       WTI Collars   55,000 bbls/d       Jan/13 -    US$91.55 to $       66
                                           Dec/13    $104.42/bbl

    Natural gas                                                            

       AECO Forwards  131,800 GJ/d       Jan/13 -       $3.17/GJ          9
       (1)                                 Dec/13

       AECO Forwards   26,400 GJ/d       Jan/14 -       $3.65/GJ          2
       (2)                                 Dec/14

       AECO Collars    26,400 GJ/d       Jan/14 -       $3.08 to          -
       (3)                                 Dec/14       $4.13/GJ

    Electricity
    swaps

       Alberta Power         30 MW       Jan/13 -     $54.60/MWh          1
       Pool                                Dec/13

       Alberta Power         20 MW       Jan/13 -     $56.10/MWh          1
       Pool                                Dec/13

       Alberta Power         70 MW       Jan/14 -     $58.50/MWh        (5)
       Pool                                Dec/14

       Alberta Power         10 MW       Jan/14 -     $58.50/MWh        (1)
       Pool                                Dec/15

       Alberta Power         45 MW       Jan/15 -     $58.28/MWh        (4)
       Pool                                Dec/15

       Alberta Power         25 MW       Jan/16 -     $49.90/MWh          -
       Pool                                Dec/16

    Interest rate             $650       Jan/13 -          2.65%       (10)
    swaps                                  Jan/14

    Foreign exchange forwards on senior notes                              

       3 to 15-year         US$641    2014 - 2022  1.000 CAD/USD         23
       initial term

    Cross currency swaps                                                   

       10-year                 £57           2018         2.0075       (19)
       initial term                               CAD/GBP, 6.95%

       10-year                 £20           2019         1.8051        (3)
       initial term                               CAD/GBP, 9.15%

       10-year           EUR10           2019         1.5870        (2)
       initial term                               CAD/EUR, 9.22%

    Total                                                        $       58

    (1)      The forward contracts total approximately 125,000 mcf per day
             with an average price of $3.34 per mcf.

    (2)      The forward contracts total approximately 25,000 mcf per day
             with an average price of $3.85 per mcf.

    (3)      The collars total approximately 25,000 mcf per day with a
             range of $3.25 to $4.35 per mcf.

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

Sensitivity Analysis

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


                                                Impact on funds flow

    Change of:                           Change $ millions   $/share

    Price per barrel of liquids           $1.00         24      0.05

    Liquids production           1,000 bbls/day         20      0.04

    Price per mcf of natural gas          $0.10          5      0.01

    Natural gas production          10 mmcf/day          2         -

    Effective interest rate                  1%          6      0.01

    Exchange rate ($US per $CAD)          $0.01         27      0.06

Contractual Obligations and Commitments

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


    (millions)                     2013  2014  2015  2016  2017 Thereafter

    Long-term debt                $   5 $  60 $ 251 $ 968 $ 242 $    1,164

    Transportation                   24    17    10     4     1          -

    Transportation ($US)              4    37    37    33    33        198

    Power infrastructure             29    14    14    14    14         12

    Drilling rigs                    23    21    17    11     6          -

    Purchase obligations (1)          6     5     5     1     1          1

    Interest obligations            146   142   132   105    77        136

    Office lease (2)                 62    56    55    54    52        384

    Decommissioning liability (3) $ 100 $  95 $  91 $  87 $  82 $      180

    (1)      These amounts represent estimated commitments of $13 million
             for CO2 purchases and $6 million for processing fees related
             to our interests in the Weyburn Unit.

    (2)      The future office lease commitments above are contracted to be
             reduced by sublease recoveries totalling $335 million.

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

Our syndicated credit facility is due for renewal on June 30, 2016. If
we are not successful in renewing or replacing the facility, we could
be required to obtain other loans including term bank loans. In
addition, we have an aggregate of $1.9 billion in senior notes maturing
between 2014 and 2025. We continuously monitor our credit metrics and
maintain positive working relationships with our lenders, investors and
agents.

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

Equity Instruments


    Common shares issued:                                       

       As at December 31, 2012                       479,258,670

       Issued on exercise of share rights                 82,242

       Issued pursuant to dividend reinvestment plan   2,807,458

       As at February 13, 2013                       482,148,370

    Options outstanding:                                        

       As at December 31, 2012                        15,737,400

       Granted                                            35,100

       Forfeited                                     (1,266,271)

       As at February 13, 2013                        14,506,229

    Share Rights outstanding:                                   

       As at December 31, 2012                           291,638

       Exercised                                        (37,821)

       Forfeited                                        (21,590)

       As at February 13, 2013                           232,227

    Restricted Options outstanding (1):                         

       As at December 31, 2012                        10,535,361

       Forfeited                                     (1,282,715)

       As at February 13, 2013                         9,252,646

    (1)      Each holder of a Restricted Option holds a Restricted Right
             and has the option to settle the Restricted Right in cash or
             common shares upon exercise. Refer to the "Expenses -
             Share-Based Compensation" section of this Management
             Commentary for further details.

Forward-Looking Statements

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

In particular, this document contains forward-looking statements
pertaining to, without limitation, the following: certain disclosures
contained in the introduction relating to our intention to continue our
strategy of changing our balance of our asset portfolio through the
disposition of non-core assets and redeployment of investment into the
light -oil focused resources portfolio and our belief that this
strategy will accelerate improvements in the Company’s balance sheet,
achieves a strategic balance that rewards our shareholders in the
near-term with a meaningful dividend and enables us to maximize the
intrinsic value of our assets in the long term; under the heading
“Operations Update”, among other things: the focus of our 2013 capital
program on improving capital efficiencies by allocating capital to
areas we have significantly de-risked from a development perspective,
where we have, and expect to continue to successfully drive down costs,
and where we have infrastructure capacity, our plan to reach our peak
operating activity at lower levels than in 2012, enabling the
utilization of optimal equipment allocations in all aspects of our
development programs, our plans to drill 150 to 210 development wells
in 2013 primarily targeting light oil, our plan to increase the focus
on the reliability of base production and working to reduce our cash
costs in 2013, our intent that the Waskada play will be a key focus in
2013 due to its attractive economics, predictable type curve and short
cycle times, our belief that the incremental capital added in late 2012
should enable us to bring more production on-stream prior to reducing
operations at break-up this coming spring, our plan to drill 90 to 130
wells in the Spearfish area in 2013, our expectation that our natural
gas liquids extraction plant in the Spearfish area will start-up during
the second quarter of 2013, our plans to have a focused development
program in the Slave Point area, our expectation that the completion of
the Sawn Lake battery expansion and the expansion of our gas handling
capacity in the Slave Point area should provide infrastructure capacity
for several years of development activity, our plans to continue to
advance our EOR strategy in the Slave Point area in 2013 with the
initiation of horizontal waterflood pilots at Sawn Lake and Otter, our
belief that our significant accumulation of light oil in the Cardium
will drive long-term growth and value creation for us due to the areal
extent of the light-oil in place combined with the potential for
significant recoveries using a combination of horizontal development
and EOR techniques, our plans that our 2013 capital budget will include
selective drilling in the Alder Flats and West Pembina areas and
further progression on our EOR strategy within the Cardium trend which
includes plans for two horizontal waterflood pilots in Willesden Green,
our plan to continue to high grade our Viking assets, our plans to
drill 25 to 30 wells primarily in the Dodsland area and expand the
infrastructure to support ongoing development programs of our Viking
assets into 2014 and beyond, our plans for a stratigraphic test with
respect to our Duvernay position in 2013, our intent that our capital
plans in 2013 include continued primary recovery and thermal appraisal,
additional engineering work at our Seal Main thermal pilot and Seal
Main commercial project and further assessment of our Harmon Valley
South thermal pilot in the Peace River Oil Partnership and our plans
that assessment and appraisal work will continue in 2013 on the Cordova
Joint Venture; in the “Letter to our Shareholders”, among other things:
our transition from a focus on oil resource growth and appraisal to
maximizing the efficiency of our operations and our belief that this
will allow us to realize the value inherent in our resources, our
intent that our business strategy will remain centered on realizing the
value inherent in our extensive light-oil weighted asset base for the
benefit of our shareholders, our intent on improving capital
efficiencies and production reliability, our belief that macro-economic
issues will continue to cast uncertainty over economic growth outlooks,
our intent to continue to focus on mitigating the impact of oil
differential volatility and potential crude oil pricing, expectations
of timing for bringing pipeline capacity to the Gulf coast on stream
and our belief that this will allow us to realize higher netbacks,
expectations that asset portfolio activity will continue and our belief
that this will help unlock value in our asset base, our belief that our
independent qualified reserve evaluators’ recently completed contingent
resource studies for our interests in the Cardium and Peace River areas
have substantiated the oil potential contained in our asset base and
have confirmed the extent of oil in place in these areas, our belief
that the Cardium is the most significant asset from a growth and long
term value perspective, our expectation that 2013 Cardium activity will
focus on development wells, our intent to develop a longer-term
integrated strategy of primary development with EOR schemes in the
Cardium, our intent with respect to the Peace River Oil Partnership to
focus on primary development and continuing engineering and regulatory
applications for the commercial cyclic steam project at Seal Main, our
belief that our reserves as at December 31, 2012 reflected only
approximately 15 percent of our identified potential oil locations, our
intent to transition to focused development with a strong emphasis on
capital efficiency, our belief that the organizational change that has
been implemented will result in improved efficiency and our intent to
provide our shareholders a meaningful dividend and to maximize the
long-term value of our asset base; under “Outlook”, among, other
things: our expectation that in 2013 exploration and development
capital will be $900 million with an option to layer in up to $300
million of incremental capital later in 2013 subject to external market
factors and internal performance and our forecast 2013 average
production of between 135,000 and 145,000 boe per day; under “Business
Strategy”, among, other things: our intent to continue to provide our
shareholders a meaningful dividend while focusing on improving capital
efficiencies and production reliability, that in 2013 exploration and
development capital will be $900 million with an option to layer in up
to $300 million of incremental capital later in 2013 subject to
external market factors; and our intent to keep our business strategy
centered on realizing the value inherent in our extensive light-oil
weighted asset base for the benefit of our shareholders; under “Results
of Operations”, among other things: our intent to continue to focus our
capital activity in 2013 on light-oil and our expectation that this
should increase our weighting to liquids; under “Liquidity and Capital
Resources”: our expectation that our strategies will increase the
likelihood of maintaining our financial flexibility to capture
opportunities available in the markets in addition to the continuation
of our capital and dividend programs and hence the longer-term
execution of our business strategies; and certain disclosures contained
under the heading “Sensitivity Analysis” relating to our estimated
sensitivities to certain key assumptions on our future funds flow.

With respect to forward-looking statements contained in this document,
we have made assumptions regarding, among other things: future crude
oil, natural gas liquids and natural gas prices and differentials
between light, medium and heavy oil prices and Canadian, WTI and world
oil prices; future capital expenditure levels; future crude oil,
natural gas liquids and natural gas production levels; that we will be
able to successfully dispose of certain non-core assets as expected;
drilling results; future exchange rates and interest rates; the amount
of future cash dividends that we intend to pay and the level of
participation in our dividend reinvestment plan; our ability to obtain
equipment in a timely manner to carry out development activities and
the costs thereof; our ability to market our oil and natural gas
successfully to current and new customers; the impact of increasing
competition; our ability to obtain financing on acceptable terms,
including our ability to renew or replace our credit facility and our
ability to finance the repayment of our senior unsecured notes on
maturity; and our ability to add production and reserves through our
development and exploitation activities. In addition, many of the
forward-looking statements contained in this document are located
proximate to assumptions that are specific to those forward-looking
statements, and such assumptions should be taken into account when
reading such forward-looking statements: see in particular the
assumptions identified under the headings “Outlook” and “Sensitivity
Analysis”.

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

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

Additional Information

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

Investor Information

——————————

Penn West shares are listed on the Toronto Stock Exchange under the
symbol PWT and on the New York Stock Exchange under the symbol PWE.

A conference call will be held to discuss Penn West’s results at 10:00am
Mountain Time (12:00pm Eastern Time) on February 14, 2013.

To listen to the conference call, please call 647-427-7450 or
1-888-231-8191 (North America 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://event.on24.com/r.htm?e=582804&s=1&k=042420A83CA78A991EE4C87CAB9D5901

A digital recording will be available for replay two hours after the
call’s completion, and will remain available until February 28, 2013
21:59 Mountain Time (23:59 Eastern Time). To listen to the replay,
please dial 416-849-0833 or 1-855-859-2056 (North America toll-free)
and enter Conference ID 97265797, followed by the pound (#) key. 

 

 

 

 

 

SOURCE Penn West Exploration


Source: PR Newswire