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



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

  PR Newswire

  CALGARY, February 14, 2013

CALGARY, February 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 31       Year ended December 31
                                                       %                            %
                                  2012       2011 change       2012       2011 change
    Financial
    (millions, except
    per share amounts)
    Gross revenues (1)       $     799  $     979   (18)  $   3,283  $   3,604    (9)
    Funds flow                     295        437   (33)      1,248      1,537   (19)
            Basic per
            share                 0.62       0.93   (33)       2.62       3.29   (20)
            Diluted per
            share                 0.62       0.93   (33)       2.62       3.29   (20)
    Net income (loss)             (53)       (62)   (15)        174        638   (73)
            Basic per
            share               (0.11)     (0.13)   (15)       0.37       1.37   (73)
            Diluted per
            share               (0.11)     (0.13)   (15)       0.37       1.36   (73)
    Capital expenditures,
    net (2)                      (916)        583  (100)        137      1,580   (91)
    Debt at period-end       $   2,690  $   3,219   (16)  $   2,690  $   3,219   (16)

    Dividends
    (millions)
    Dividends paid (3)       $     129  $     127      2  $     512  $     420     22
    DRIP                          (31)       (26)     19      (117)       (92)     27
    Dividends paid in
    cash                     $      98  $     101    (3)  $     395  $     328     20

    Operations
    Daily production
            Light oil and
            NGL (bbls/d)        82,224     90,185    (9)     86,783     85,316      2
            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)
    Average sales price
            Light oil and
            NGL (per bbl)    $   75.91  $   88.76   (15)  $   77.16  $   86.19   (10)
            Heavy oil (per
            bbl)                 59.85      76.88   (22)      63.67      69.07    (8)
            Natural gas
            (per mcf)        $    3.28  $    3.47    (5)  $    2.45  $    3.78   (35)
    Netback per boe
            Sales price      $   54.10  $   63.05   (14)  $   53.60  $   60.99   (12)
            Risk
            management
            gain (loss)           0.51     (0.84)    100       0.81     (1.06)    100
            Net sales
            price                54.61      62.21   (12)      54.41      59.93    (9)
            Royalties          (10.10)    (11.47)   (12)    (10.07)    (11.09)    (9)
            Operating
            expenses           (17.16)    (17.48)    (2)    (17.26)    (17.40)    (1)
            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.
        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).
    (3) Our first quarterly dividend ($0.27 per share) as a corporation was
        paid in April 2011.

DRILLING STATISTICS

                                                                    Year ended
                          Three months ended December 31           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 service             9        1       12        3    72   32    89   37
    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

    (millions)         Three months ended December 31       Year ended December 31
                               2012              2011           2012          2011
    Land
    acquisition
    and retention        $        1        $        9      $      37      $    181
    Drilling and
    completions                 160               410          1,148         1,217
    Facilities
    and well
    equipping                   205               197            675           521
    Geological
    and
    geophysical                   3                 -             13             9
    Corporate                     3                 8             16            25
    Capital
    expenditures
    (1)                         372               624          1,889         1,953
    Joint
    venture,
    carried
    capital                    (24)              (30)          (137)         (107)
    Property
    dispositions,
    net                     (1,264)              (11)        (1,615)         (266)
    Business
    combinations                  -                 -              -           286
    Total
    expenditures         $    (916)        $      583      $     137      $  1,866

    (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

                                                                             Year ended
                                      Three months ended December 31        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 December 31                                    479.3 471.4      2

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 at
    December 31, 2012

    Reserve
    Estimates
    Category          Light &                       Natural Gas     Barrels of
    (1)(2)         Medium Oil Heavy Oil Natural Gas     Liquids Oil Equivalent
                      (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 at
    December 31, 2012

    Reserve
    Estimates
    Category          Light &                       Natural Gas     Barrels of
    (1)(2)         Medium Oil Heavy Oil Natural Gas     Liquids Oil Equivalent
                      (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
http://www.sedar.com .

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


    Reconciliation Items (1)  Light and Medium Oil (mmbbl)   Heavy Oil (mmbbl)
                                                  Proved                   Proved
                                                    plus                     plus
                                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

    Reconciliation Items (1)  Natural Gas Liquids (mmbbl)   Natural Gas (bcf)

                                                  Proved                   Proved
                                                    plus                     plus
                              Proved  Probable  probable Proved Probable probable

    December 31, 2011             28        12        39    783      452    1,235
    Extensions                     1         1         1     17       43       60
    Improved Recovery              1         -         1      2        1        3
    Infill Drilling                -         -         1     10        9       18
    Technical Revisions            2        (1)        1    138      (86)      51
    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, 2012             27        11        38    773      413    1,186


    Reconciliation Items (1)      Barrels of Oil Equivalent (mmboe)

                                                       Proved plus
                                  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
    (1)                           0%            5%           10%           15%           20%

    Proved
         Developed
         producing          $ 10,179      $  7,151      $  5,603      $  4,659      $  4,017
         Developed
         non-producing           312           220           167           134           112
         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
    probable                $ 21,419      $ 13,023      $  9,130      $  6,937      $  5,546

    (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
                                      Lloyd-            Natural                    Exchange
                    WTI  Edmonton   minster    Cromer       gas                       rate
                Cushing,      Par     Blend    Medium  AECO gas  Edmonton Inflation   (US$
               Oklahoma   40o API   21o API   29o API     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
    escalating at  1.8%      1.8%      1.8%      1.8%      1.8%      1.8%        -       -

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
                  - proved plus
                  probable           $ 23.12  $ 23.96  $ 23.39       $   23.54
                  F&D costs per boe
                  - proved           $ 26.91  $ 31.69  $ 25.25       $   28.43

    F&D costs excluding FDC (2)
                  F&D costs per boe
                  - proved plus
                  probable           $ 17.48  $ 15.07  $ 18.90       $   16.76
                  F&D costs per boe
                  - proved           $ 26.69  $ 23.55  $ 21.50       $   24.02

    F&D costs including FDC (3)
                  F&D costs per boe
                  - proved plus
                  probable           $ 25.50  $ 26.79  $ 26.73       $   26.32
                  F&D costs per boe
                  - proved           $ 30.96  $ 37.05  $ 28.01       $   32.60

    (1) The calculation of adjusted F&D includes the change in FDC, 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, AlbertaFebruary 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
http://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 assets           609       418
                     Property, plant and equipment            10,892    11,893
                     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 accrued
                     liabilities                            $    764  $  1,108
                     Dividends payable                           129       127
                     Current portion of long-term debt             5         -
                     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 liabilities                 5         9
                                                               5,617     6,517
    Shareholders' equity
                     Shareholders' capital                     8,985     8,840
                     Other reserves                               97        95
                     Retained earnings (deficit)               (208)       132
                                                               8,874     9,067
    Total liabilities and shareholders' equity              $ 14,491  $ 15,584

                            Penn West Petroleum Ltd.
                       Consolidated Statements of Income

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

        Oil and natural gas sales               $    791  $    992   $ 3,235  $ 3,667
        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 administrative                    46        30       172      142
        Restructuring                                 13         -        13        -
        Share-based compensation                     (12)       68       (10)      84
        Depletion, depreciation and impairment       598       308     1,525    1,158
        Gain on dispositions                        (279)      (21)     (384)    (172)
        Exploration and evaluation                    15        10        17       15
        Unrealized risk management (gain) loss         6       (23)        5      (25)
        Unrealized foreign exchange (gain) loss       22       (53)      (32)      38
        Financing                                     52        48       199      190
        Accretion                                     22        12        54       45
                                                     733       657     2,607    2,540
    Income (loss) before taxes                       (68)     (110)      237      411

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

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

    Net income (loss) per share
        Basic                                    $ (0.11)  $ (0.13)  $  0.37  $  1.37
        Diluted                                  $ (0.11)  $ (0.13)  $  0.37  $  1.36

    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, unaudited)                        2012     2011       2012       2011

    Operating activities
        Net income (loss)                         $   (53)  $  (62)  $    174  $     638
        Depletion, depreciation and impairment        598      308      1,525      1,158
        Gain on dispositions                         (279)     (21)      (384)      (172)
        Exploration and evaluation                     15       10         17         15
        Accretion                                      22       12         54         45
        Deferred tax expense (recovery)               (15)     (48)        63       (227)
        Share-based compensation                      (11)      61        (18)        75
        Unrealized risk management loss (gain)         (4)     230       (151)       (33)
        Unrealized foreign exchange loss (gain)        22      (53)       (32)        38
        Decommissioning expenditures                  (32)     (36)       (92)       (81)
        Change in non-cash working capital            178       83         37        (49)
                                                      441      484      1,193      1,407
    Investing activities
        Capital expenditures                         (348)    (594)    (1,752)    (1,846)
        Property dispositions (acquisitions), net   1,264       11      1,615        266
        Business combinations                           -        -          -       (166)
        Change in non-cash working capital              8       56       (168)       113
                                                      924     (527)      (305)    (1,633)
    Financing activities
        Increase (decrease) in bank debt           (1,267)     230       (496)       475
        Proceeds from issuance of notes                 -      137          -        212
        Repayment of acquired credit facilities         -        -          -        (39)
        Issue of equity                                 -        1          3        161
        Dividends paid                                (98)    (101)      (395)      (328)
        Settlement of convertible debentures            -     (224)         -       (255)
                                                   (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, unaudited)
                                               Shareholders'    Other
                                                    Capital  Reserves    Deficit     Total

    Balance at January 1, 2012                    $   8,840    $   95    $   132   $ 9,067
    Net and comprehensive income                          -         -        174       174
    Share-based compensation                              -        27          -        27
    Issued on exercise of options and share rights       28       (25)         -         3
    Issued to dividend reinvestment plan                117         -          -       117
    Dividends declared                                    -         -       (514)     (514)
    Balance at December 31, 2012                  $   8,985    $   97    $  (208)  $ 8,874

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

    Balance at January 1, 2011                    $   9,170    $    -    $  (610)  $ 8,560
    Elimination of deficit                             (610)        -        610         -
    Net and comprehensive income                          -         -        638       638
    Implementation of Option Plan and CSRIP               -        81          -        81
    Share-based compensation                              -        41          -        41
    Issued on exercise of options and share rights      188       (27)         -       161
    Issued to dividend reinvestment plan                 92         -          -        92
    Dividends declared                                    -         -       (506)     (506)
    Balance at December 31, 2011                  $   8,840    $   95    $   132   $ 9,067

                            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

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

    Cash flow from operating activities             $   441   $   484   $ 1,193   $ 1,407
    Increase (decrease) in non-cash working capital    (178)      (83)      (37)       49
    Decommissioning expenditures                         32        36        92        81
    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 months ended      2012    2012    2012    2012    2011    2011    2011     2011

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

    (1) Gross revenues include realized gains and losses on commodity contracts.
    (2) Includes crude oil and natural gas liquids.

Business Strategy

Over the past several years, we have focused our capital activities 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 (bbls/d)  82,224  90,185    (9)  86,783  85,316      2
    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 and liquids (per bbl)    $ 75.91  $  88.76    (15)  $ 77.16  $  86.19    (10)
    Risk management gain (loss)
    (per bbl) (1)                         0.20     (1.58)   100      0.17     (2.03)   100
    Light oil and liquids net (per bbl)  76.11     87.18    (13)    77.33     84.16     (8)

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

    Natural gas (per mcf)                 3.28      3.47     (5)     2.45      3.78    (35)
    Risk management gain (per mcf) (1)    0.19         -    100      0.34         -    100
    Natural gas net (per mcf)             3.47      3.47      -      2.79      3.78    (26)

    Weighted average (per boe)           54.10     63.05    (14)    53.60     60.99    (12)
    Risk management gain (loss)
    (per boe) (1)                         0.51     (0.84)   100      0.81     (1.06)   100
    Weighted average net (per boe)     $ 54.61  $  62.21    (12)  $ 54.41  $  59.93     (9)

    (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 (bbls/day)      82,224     90,185     (9)     86,783     85,316      2
      Operating netback
      ($/bbl):
        Sales price         $   75.91  $   88.76    (15)  $   77.16  $   86.19    (10)
        Risk management
        gain (loss) (3)          0.20      (1.58)   100        0.17      (2.03)   100
        Royalties              (14.38)    (16.94)   (15)     (15.57)    (16.83)    (8)
        Operating costs        (19.84)    (20.75)    (4)     (19.86)    (21.05)    (6)
        Netback             $   41.89  $   49.49    (15)  $   41.90  $   46.28    (10)
    Conventional heavy oil
    Production (bbls/day)      16,847     17,886     (6)     17,361     17,892     (3)
      Operating netback
      ($/bbl):
        Sales price         $   59.85  $   76.88    (22)  $   63.67  $   69.07     (8)
        Royalties               (8.63)    (10.82)   (20)      (9.01)    (10.01)   (10)
        Operating costs        (19.22)    (17.42)    10      (19.32)    (17.53)    10
        Transportation          (0.03)     (0.07)   (57)      (0.07)     (0.08)   (13)
        Netback             $   31.97  $   48.57    (34)  $   35.27  $   41.45    (15)
    Total liquids
    Production (bbls/day)      99,071    108,071     (8)    104,144    103,208      1
      Operating netback
      ($/bbl):
        Sales price         $   73.18  $   86.80    (16)  $   74.91  $   83.22    (10)
        Risk management
        gain (loss) (3)          0.17      (1.32)   100        0.14      (1.68)   100
        Royalties              (13.40)    (15.93)   (16)     (14.48)    (15.64)    (7)
        Operating costs        (19.73)    (20.20)    (2)     (19.77)    (20.44)    (3)
        Transportation              -      (0.01)  (100)      (0.01)     (0.01)     -
        Netback             $   40.22  $   49.34    (19)  $   40.79  $   45.45    (10)
    Natural gas
    Production (mmcf/day)         329        364    (10)        342        359     (5)
      Operating netback
      ($/mcf):
        Sales price         $    3.28  $    3.47     (5)  $    2.45  $    3.78    (35)
        Risk management
        gain (3)                 0.19          -    100        0.34          -    100
        Royalties               (0.69)     (0.59)    17       (0.34)     (0.54)   (37)
        Operating costs         (2.09)     (2.11)    (1)      (2.11)     (2.03)     4
        Transportation          (0.24)     (0.22)     9       (0.23)     (0.22)     5
        Netback             $    0.45  $    0.55    (18)  $    0.11  $    0.99    (89)
    Combined totals
    Production (boe/day)      153,931    168,801     (9)    161,195    163,094     (1)
      Operating netback
      ($/boe):
        Sales price         $   54.10  $   63.05    (14)  $   53.60  $   60.99    (12)
        Risk management
        gain (loss) (3)          0.51      (0.84)   100        0.81      (1.06)   100
        Royalties              (10.10)    (11.47)   (12)     (10.07)    (11.09)    (9)
        Operating costs        (17.16)    (17.48)    (2)     (17.26)    (17.40)    (1)
        Transportation          (0.51)     (0.48)     6       (0.50)     (0.49)     2
        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 management)        (181)
    Decrease in heavy oil production                                                  (12)
    Decrease in heavy oil prices                                                      (35)
    Decrease in natural gas production                                                (23)
    Decrease in natural gas prices                                                   (123)
    Gross revenues - January 1 - December 31, 2012                                $ 3,283

Royalties

                                     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 compensation  $   (12)  $    68   (100)  $    (10)  $    84   (100)

                                     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 compensation  $ (0.82)  $  4.32   (100)  $  (0.17)  $  1.41   (100)

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, CAD$30     8-12 years   6.25%      5.0 years


    UK Notes       July 31, 2008      GBP57              10 years     6.95%(1)   5.6 years



    2009 Notes     May 5, 2009        US$154(2), GBP20,  5-10 years   8.85%(3)   4.0 years
                                      EUR10, CAD$5


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


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


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

    (1) These notes bear interest at 7.78 percent in Pounds Sterling, however,
        contracts were entered to fix the interest rate at 6.95 percent in
        Canadian dollars and to fix the exchange rate on the repayment.
    (2) A portion of the 2009 Notes have equal repayments, beginning in 2013,
        over the remaining seven years.
    (3) The Company entered into contracts to fix the interest rate on the
        Pounds Sterling and Euro tranches, initially at 9.49 percent and 9.52
        percent, to 9.15 percent and 9.22 percent, respectively, and to fix
        the exchange rate on repayment.

Financing charges in 2012 were slightly higher than 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
    depreciation ("D&D")        $   321  $   308      4  $ 1,248  $  1,168      7
    D&D expense per boe           22.75    19.84     15    21.17     19.62      8

    Impairment                      277        -    100      277       (10)   100
    Impairment per boe            19.53        -    100     4.69     (0.17)   100

    Accretion of decommissioning
    liability                        22       12     83       54        45     20
    Accretion expense per boe   $  1.51  $  0.76     99  $  0.90  $   0.76     18

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
    (recovery)                     $ (15)  $ (48)   (69)  $ 63  $ (227)    100


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


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)
    (millions)              $    295   $    437    (33)  $ 1,248  $ 1,537    (19)
      Basic per share           0.62       0.93    (33)     2.62     3.29    (20)
      Diluted per share         0.62       0.93    (33)     2.62     3.29    (20)

    Net income (loss)
    (millions)                   (53)      (62)    (15)      174      638    (73)
      Basic per share          (0.11)    (0.13)    (15)     0.37     1.37    (73)
      Diluted per share     $  (0.11)  $ (0.13)    (15)  $  0.37  $  1.36    (73)

    (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 dispositions    $ 279  $ 21     100  $ 384  $ 172    100


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).
        Excludes the current portion of risk management and share-based
    (2) 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 - Dec/13  US$91.55 to $104.42/bbl  $  66
    Natural gas
      AECO Forwards (1)   131,800 GJ/d  Jan/13 - Dec/13         $3.17/GJ              9
      AECO Forwards (2)    26,400 GJ/d  Jan/14 - Dec/14         $3.65/GJ              2
      AECO Collars (3)     26,400 GJ/d  Jan/14 - Dec/14     $3.08 to $4.13/GJ         -
    Electricity swaps
      Alberta Power Pool      30 MW     Jan/13 - Dec/13        $54.60/MWh             1
      Alberta Power Pool      20 MW     Jan/13 - Dec/13        $56.10/MWh             1
      Alberta Power Pool      70 MW     Jan/14 - Dec/14        $58.50/MWh            (5)
      Alberta Power Pool      10 MW     Jan/14 - Dec/15        $58.50/MWh            (1)
      Alberta Power Pool      45 MW     Jan/15 - Dec/15        $58.28/MWh            (4)
      Alberta Power Pool      25 MW     Jan/16 - Dec/16        $49.90/MWh             -

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

    Foreign exchange forwards on senior notes
      3 to 15-year initial
      term                    US$641      2014 - 2022         1.000 CAD/USD          23
    Cross currency swaps

      10-year initial term    GBP57           2018         2.0075 CAD/GBP, 6.95%    (19)

      10-year initial term    GBP20           2019         1.8051 CAD/GBP, 9.15%     (3)

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

    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 http://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              1,000
    production        bbls/day         20       0.04
    Price per mcf of
    natural gas          $0.10          5       0.01
    Natural gas             10
    production        mmcf/day          2          -
    Effective
    interest rate           1%          6       0.01
    Exchange rate
    ($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 http://www.sedar.com and
in the United States at http://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 http://www.sedar.com and on EDGAR
at http://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
http://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, 201321:59 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. 

For further information:

PENNWEST EXPLORATION Penn West Plaza Suite 200, 207 - 9 ^th Avenue SWCalgary,
Alberta  T2P 1K3 Phone: +1-403-777-2500 Fax: +1-403-777-2699Toll Free:
1-866-693-2707 Website:  http://www.pennwest.com

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

Murray Nunns, President & Chief Executive Officer Phone:  +1-403-218-8939
E-mail:  murray.nunns@pennwest.com

Clayton Paradis, Manager, Investor Relations Phone:  +1-403-539-6343 E-mail: 
clayton.paradis@pennwest.com
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