Quantcast

Penn West Announces its Financial Results for the Fourth Quarter and Year Ended December 31, 2013 and 2013 Reserve Results

March 7, 2014

CALGARY, March 7, 2014 /PRNewswire/ – PENN WEST PETROLEUM LTD. (TSX – PWT) (NYSE – PWE) (“PENN WEST” or the “COMPANY”) is pleased to announce its results for the fourth quarter and year
ended December 31, 2013. All figures are in Canadian dollars unless
otherwise stated.


                       Three months ended December       Year ended December 31
                                                31

                             2013      2012      %        2013      2012      %
                                            change                       change

    Financial
    (millions, except
    per share
    amounts)                                                                   

    Gross revenues
    (1,2)               $     613 $     799   (23)   $   2,835 $   3,283   (14)

    Funds flow (2)            216       295   (27)       1,054     1,248   (16)

       Basic per
       share (2)             0.44      0.62   (29)        2.17      2.62   (17)

       Diluted per
       share (2)             0.44      0.62   (29)        2.17      2.62   (17)

    Net income (loss)       (728)      (78)  (100)       (838)       149  (100)

       Basic per
       share               (1.49)    (0.16)  (100)      (1.72)      0.31  (100)

       Diluted per
       share               (1.49)    (0.16)  (100)      (1.72)      0.31  (100)

    Development
    capital
    expenditures (3)          208       348   (40)         816     1,752   (53)

    Long-term debt at
    period-end          $   2,458 $   2,690    (9)   $   2,458 $   2,690    (9)

    Dividends
    (millions)                                                                 

    Dividends paid
    (4)                 $      68 $     129   (47)   $     458 $     512   (11)

    DRIP                     (14)      (31)   (55)        (95)     (117)   (19)

    Dividends paid in
    cash                $      54 $      98   (45)   $     363 $     395    (8)

    Operations                                                                 

    Daily production
    (average)                                                                  

       Light oil and
       NGL (bbls/d)        64,056    82,224   (22)      69,587    86,783   (20)

       Heavy oil
       (bbls/d)            14,601    16,847   (13)      15,511    17,361   (11)

       Natural gas
       (mmcf/d)               272       329   (17)         300       342   (12)

    Total production
    (boe/d)(5)            123,995   153,931   (19)     135,093   161,195   (16)

    Average sales
    price                                                                      

       Light oil and
       NGL (per bbl)    $   77.43 $   75.91      2   $   83.25 $   77.16      8

       Heavy oil (per
       bbl)                 58.66     59.85    (2)       65.12     63.67      2

       Natural gas
       (per mcf)        $    3.53 $    3.28      8   $    3.31 $    2.45     35

    Netback per boe                                                            

       Sales price      $   54.65 $   54.10      1   $   57.71 $   53.60      8

       Risk
       management
       gain                  0.62      0.51     22        0.16      0.81   (80)

       Net sales
       price                55.27     54.61      1       57.87     54.41      6

       Royalties
                          (10.13)   (10.10)      -     (10.29)   (10.07)      2

       Operating
       expenses           (17.86)   (17.16)      4     (17.30)   (17.26)      -

       Transportation
                           (0.62)    (0.51)     22      (0.59)    (0.50)     18

       Netback (2)      $   26.66 $   26.84    (1)   $   29.69 $   26.58     12

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

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

    (3)  Includes the effect of capital carried by partners.

    (4)  Includes dividends paid prior to amounts reinvested in shares
         under the dividend reinvestment plan.

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

PRESIDENT’S MESSAGE

Four months ago, we began discussing a new vision for Penn West. We
promised focus on the Company’s industry leading light-oil positions in
the Western Canada Sedimentary Basin; application of best-in-class
operating practices; relentless cost control; and to de-lever the
balance sheet to deliver shareholder value. We are pleased to say we
are on plan.

We have instilled a value-first culture at Penn West in which we
challenge the cost/benefit of every activity we engage in and question
the profitability of every barrel we produce. We are ahead of our asset
disposition plans to date, achieving better than planned realizations
from a net operating income multiple perspective, and our organization
is 35 percent smaller than the beginning of 2013. Our capital
efficiency improvements continue as we realize game changing capital
cost reductions across our key plays.

Our 2013 development capital totaled $816 million compared to a $900
million budget with more activity completed than planned. We are
already at or within reach of our per well capital cost targets
outlined in our long-term plan and will continue to drive efficiencies
to further enhance returns and extend the economic longevity of our
plays. These improvements were also a component of our strong finding
and development (“F&D”) cost performance in 2013. Inclusive of the
change in future development costs, our proved plus probable F&D costs
were $9.47 per boe ((1)) in 2013 with 76 percent of additions comprising oil and natural gas
liquids. This compares to $25.50 per boe in 2012, a 63 percent
improvement to an important capital investment indicator. Excluding the
change in future development costs, the proved plus probable F&D cost
was $17.17 per boe and is in line with our operated development capital
cost target of $15 – $20 per boe in our long-term plan.

Another cornerstone of our business plan is to operate in a continuous
and deliberate manner to drive cost efficiencies and predictable
production performance. Our teams are already operating under these
principles with the expectation that our production profile will shift
as the effects of the front-end loaded programs of the past dissipate.
In the Cardium, we have been running ahead of cost, time and
performance expectations – including best-in-play drilling performance
– and anticipate being able to advance drilling activities above our
stated business plan in 2014 and future years within the planned
capital allocations. With the testing of drilling and completion
techniques to significantly reduce costs in the Slave Point and
industry leading cost and well performance in the Viking, our
organizational energy is being fueled by success. Waterflood programs
across these assets, pivotal to sustainable performance, are proceeding
as planned.

To date in 2014, we have benefited from stronger than planned commodity
prices and a favorable currency climate; however, we remain
conservative in our commodity outlook for the remainder of the year.
Operating excellence and investment discipline will continue to be key
organic levers while we progress through phase two of our asset
divestiture strategy and deliver a laser focused portfolio and improve
our balance sheet.

FOURTH QUARTER KEY POINTS

        --  Non-core asset dispositions totalling approximately $486
            million with associated production of 10,800 boe per day were
            closed in the fourth quarter of 2013. Asset dispositions in
            2013 resulted in an approximate $90 million reduction to our
            decommissioning liability.
        --  As a result of our focus on cost reductions, our recycle ratio
            (2), on a proved plus probable basis and including the change
            in future development costs ("FDC"), improved to 3.1 in 2013
            compared to 1.0 in 2012.
        --  Development capital was $208 million for the fourth quarter of
            2013 and $816 million for 2013. For 2013, our development
            capital came in below our budget of $900 million primarily due
            to the cost reductions we realized across our plays.
        --  Further operational improvements were experienced during the
            fourth quarter with continued reduction in drilling and
            completion costs and cycle times, notably in the Lodgepole and
            Crimson Lake areas of the Cardium and the Dodsland area of the
            Viking.

    (1)  For detailed calculations and disclaimers, see "Finding and
         Development costs" below.

    (2)  Recycle ratio is a non-GAAP measure. Please refer to our "Non-GAAP
         Measures Advisory" section below.

RESERVE HIGHLIGHTS

        --  Proved plus probable finding and development cost ("F&D")
            including the change in FDC for 2013 was $9.47 per boe (2012 -
            $25.50 per boe). The improvement includes the effects of
            reductions in FDC due to significant declines in our drilling
            and completion costs and removal of certain capital costs
            associated with properties no longer carrying reserves, and
            technical revisions to our current reserve base.
        --  Excluding the impact of dispositions, our reserve replacement
            ratio (1) was 97 percent in 2013.
        --  Total working interest (gross) proved plus probable reserves
            were 625 mmboe at December 31, 2013 (2012 - 676 mmboe),
            weighted approximately 70 percent to liquids (2012 - 71
            percent), and including the effect of 50 mmboe of oil weighted
            asset dispositions completed in 2013.
        --  Proved plus probable net present value discounted at 10 percent
            (before income taxes) remained relatively consistent
            year-over-year with December 31, 2013 at $8.9 billion (2012 -
            $9.1 billion) which included a reduction of approximately $450
            million related to asset dispositions completed in 2013.
        --  Reserve additions for 2013 were weighted 76 percent to oil,
            excluding technical revisions.
        --  During 2013, we completed or updated contingent resource
            studies covering our interests in the Cardium, Viking, Slave
            Point and Swan Hills areas substantiating our appraisal
            activities and confirming significant recoverable oil resources
            in these areas.

FINANCIAL HIGHLIGHTS

        --  Funds flow for the fourth quarter of 2013 was $216 million
            ($0.44 per share - basic), a decrease from $293 million ($0.60
            per share - basic) in the third quarter of 2013, mainly due to
            lower crude oil prices and lower production volumes as a result
            of asset dispositions in the fourth quarter of 2013.
        --  For the fourth quarter of 2013, we recorded a net loss of $728
            million ($1.49 per share - basic). The net loss was primarily
            due to non-cash PP&E impairment charges and unrealized foreign
            exchange losses on the translation of our US denominated
            senior, unsecured notes.
        --  Disposition proceeds received during 2013 were applied toour
            credit facilities with a net reduction in long-term debt of
            $356 million during the year, prior to foreign currency
            translations.

ASSET IMPAIRMENTS

        --  During the fourth quarter of 2013, we recorded non-cash
            impairment charges of $742 million related to PP&E. These
            impairment charges were the result of limited planned
            development capital in certain non-core natural gas assets and
            lower estimated reserve recoveries at our Manitoba properties.
            Our five-year plan is focused on the integrated development of
            our large light-oil areas in the Cardium, Slave Point and
            Viking.

DIVIDENDS

On March 6, 2014, our Board of Directors declared a first quarter 2014
dividend of $0.14 per share to be paid on April 15, 2014 to
shareholders of record at the close of business on March 31, 2014.
Shareholders are advised that this dividend is designated as an
“eligible dividend” for Canadian income tax purposes.


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

PLAY UPDATES

Cardium

During 2013, significant cost reductions and cycle time improvements
were realized with a continued focus on further reductions as we move
through 2014. Compared to 2012, drilling and completion (“D&C”) costs
decreased by approximately 35 – 40 percent, notably in the Lodgepole
and Crimson Lake areas. In the fourth quarter of 2013, development
activities were concentrated in these two areas and we maintained
momentum as we moved into the first quarter of 2014 with a four-rig
program. Also in the fourth quarter, horizontal waterflood development
began in the Willesden Green area with the initiation of one pilot
project and the construction of another which began water injection in
early 2014.

For 2014, we have allocated $270 million of development capital to the
Cardium with further expansion of our planned EOR pilot work along with
a focused development drilling program (67 net wells) as we continue to
methodically increase our activity in the area, consistent with our
five-year plan.

Viking

During 2013, we became an industry leader in the area due to significant
D&C cost reductions and superior well performance. These cost savings
were experienced in a short time frame with average D&C costs per well
during the first half of the year of $1.2 million compared to
approximately $850,000 per well in the second half; close to a 30
percent reduction. The results from our development programs, primarily
in the Dodsland area, consistently exceeded both our own and
competitors’ type curves. We plan to continue to build on these
successes in 2014, with $150 million budgeted for the area (104 net
wells) as we leverage our existing infrastructure and complete a
down-spaced development program. In 2014, we have plans to initiate the
first and second phases of a waterflood pilot in the Avon Hills area
with the third phase beginning in 2015.

Slave Point

In the Slave Point, our fourth quarter activities were focused on a
selective drilling program in the Red Earth area and the initiation of
a waterflood pilot in the Otter area. For 2014 we allocated $145
million to the Slave Point with a focus on completing a low-risk
development drilling program in Sawn, Otter and Red Earth (21 net
wells), continued expansion of the Otter waterflood pilot and the
initiation of a waterflood pilot in Sawn.

DISPOSITION UPDATE

On January 21, 2014 we announced a non-core asset disposition for
expected proceeds of $175 million, expected to close in mid-March 2014.
The assets to be disposed are primarily located in the central and
southwestern parts of Alberta with associated production of
approximately 6,700 boe per day weighted 58 percent to natural gas and
1,800 currently producing or suspended wellbores.

DRILLING STATISTICS


                                Three months ended           Year ended
                                       December 31          December 31

                                   2013       2012      2013       2012

                              Gross Net Gross  Net Gross Net Gross  Net

    Oil                          67  53    55   31   274 201   349  263

    Natural gas                   3   2     -    -     6   4    23   19

    Dry                           1   1     -    -     1   1     -    -

                                 71  56    55   31   281 206   372  282

    Stratigraphic and service     5   1     9    1    41  18    72   32

    Total                        76  57    64   32   322 224   444  314

    Success rate (1)                98%       100%       99%       100%

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




CAPITAL EXPENDITURES


                               Three months ended                Year ended
                                      December 31               December 31

    (millions)                 2013          2012         2013         2012

    Land
    acquisition and
    retention         $           - $           1 $          4 $         37

    Drilling and
    completions                 118           160          543        1,148

    Facilities and
    well equipping              102           205          332          675

    Geological and
    geophysical                   1             3           10           13

    Corporate                     3             3           10           16

    Capital carried
    by partners                (16)          (24)         (83)        (137)

    Development
    capital
    expenditures
    (1)                         208           348          816        1,752

    Property
    acquisitions
    (dispositions),
    net                       (473)       (1,264)        (525)      (1,615)

    Total
    expenditures      $       (265) $       (916) $        291 $        137

    (1) Development capital includes costs related to Property, Plant and
        Equipment and Exploration and Evaluation activities.

In the fourth quarter of 2013, we increased our development activity
levels in the Cardium and Viking areas by reallocating capital to these
plays. Cost reductions realized during 2013 on drilling and completion
activities enabled us to expand our program.

LAND


                                                              As at December 31

                                       Producing              Non-producing

                                                   %                          %
                               2013    2012   change      2013    2012   change

    Gross acres (000s)        4,836   5,733     (16)     2,842   2,680        6

    Net acres (000s)          3,308   3,841     (14)     1,957   1,896        3

    Average working
    interest                    68%     67%        1       69%     71%      (2)

COMMON SHARE DATA


                              Three months ended                 Year ended
                                     December 31                December 31

    (millions of                               %                          %
    shares)                2013    2012   change      2013    2012   change

    Weighted average                                                       

      Basic               489.5   478.9        2     485.8   475.6        2

      Diluted             489.5   478.9        2     485.8   475.8        2

      Outstanding as at                              489.1   479.3        2
      December 31

RESERVES DATA

Our reserves continue to reflect a high percentage of oil and liquids at
70 percent (2012 – 71 percent) and proved reserves continue to reflect
a high percentage of developed reserves. Of total proved reserves, 75
percent were developed at December 31, 2013 (2012 – 78 percent). At
December 31, 2013, total proved reserves as a percentage of proved plus
probable reserves were 67 percent (2012 – 66 percent). In 2013, all of
our reserves were evaluated or audited by Sproule Associates Limited
(“SAL”), an independent, qualified engineering firm. Approximately 25
percent of total proved plus probable reserves were internally
evaluated and then audited by SAL.

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 to be recoverable 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 (Gross) Reserves using forecast prices and costs


    Penn West as
    at
    December 31,
    2013

                                                     Natural   Barrels of
                     Light &               Natural       Gas          Oil
    Reserve       Medium Oil   Heavy Oil       Gas   Liquids   Equivalent

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

    Proved                                                               

    Developed            141          38       585        22          299
    producing

    Developed              5           -        30         1           11
    non-producing

    Undeveloped           72           4       142         7          106

    Total Proved         218          42       757        30          415

    Probable              96          40       366        13          209

    Total Proved         314          82     1,123        42          625
    plus Probable

    (1) Working interest (gross) 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,
    2013                                                                 

                                                     Natural   Barrels of
                     Light &               Natural       Gas          Oil
    Reserve       Medium Oil   Heavy Oil       Gas   Liquids   Equivalent

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

    Proved                                                               

    Developed
    producing            122          34       517        16          259

    Developed
    non-producing          4           -        25         1            9

    Undeveloped           61           3       123         5           90

    Total Proved         187          38       664        22          358

    Probable              80          35       316         9          176

    Total Proved
    plus Probable        267          73       980        31          534

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

    (2) Columns may not add due to rounding.

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

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


                        Light and Medium Oil                  Heavy Oil
                               (mmbbl)                         (mmbbl)

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

    December 31,        243      108       351         46       44       90
    2012

    Extensions            -        1         1          1        -        1

    Infill Drilling      14        7        21          2        -        2

    Improved              -        5         6          -        -        1
    Recovery

    Technical           (9)     (17)      (26)          4      (2)        2
    Revisions

    Acquisitions          -        -         -          -        -        -

    Dispositions       (11)      (8)      (19)        (7)      (3)      (9)

    Economic Factors      1        -         2          -        -        1

    Production         (22)        -      (22)        (6)        -      (6)

    December 31,        218       96       314         41       40       82
    2013

                         Natural Gas Liquids                Natural Gas
                               (mmbbl)                         (bcf)

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

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

    Extensions            -        -         -         13       28       41

    Infill Drilling       1        -         1         12        6       18

    Improved              -        -         -          -        2        2
    Recovery

    Technical             6        2         8        121      (8)      113
    Revisions

    Acquisitions          -        -         -          1        -        1

    Dispositions        (1)      (1)       (1)       (46)     (76)    (121)

    Economic Factors      -        -         -        (8)        1      (7)

    Production          (4)        -       (4)      (109)        -    (109)

    December 31,         30       13        42        757      366    1,123
    2013

                     Barrels of Oil Equivalent
                              (mmboe)

                                        Proved
    Reconciliation                        plus
    Items (1)        Proved Probable  probable

    December 31,        445      231       676
    2012

    Extensions            3        5         9                             

    Infill Drilling      18        9        27                             

    Improved              1        6         7
    Recovery

    Technical            22     (19)         4
    Revisions

    Acquisitions          -        -         -                             

    Dispositions       (26)     (24)      (50)                             

    Economic Factors      -        -         1                             

    Production         (49)        -      (49)                             

    December 31,        415      209       625
    2013

    (1)  Columns may not add due to rounding.

Our focused drilling program during the year highlighted by the
realization of significant drilling and completions cost reductions and
the potential of our waterflood programs partially offset oil weighted
dispositions that occurred primarily in the fourth quarter of 2013. The
dispositions noted in our reserve numbers are primarily attributable to
the dispositions we closed during the fourth quarter of 2013.

d) Net present value of future net revenue using forecast prices and
costs (millions) at December 31, 2013


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

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

    Proved                                                                 

      Developed         $  9,826 $  6,927 $ 5,412 $ 4,487 $           3,864
      producing

      Developed              279      202     156     127               107
      non-producing

      Undeveloped          3,465    1,923   1,157     714               432

      Total proved      $ 13,570 $  9,052 $ 6,726 $ 5,329 $           4,403

    Probable               7,991    3,785   2,153   1,353               899

    Total proved plus   $ 21,561 $ 12,836 $ 8,879 $ 6,682 $           5,302
    probable

    (1)  Columns may not add due to rounding.

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

e) Summary of pricing and inflation rate assumptions using forecast
prices and costs as of December 31, 2013


                                            Oil                                                     

                                     Western                                                Exchange
                  WTI     Edmonton    Canada     Cromer   Natural gas                         rate
               Cushing,     Par       Select      LSB         AECO      Edmonton  Inflation   (US$
               Oklahoma   40o API   20.5o API   35o API    gas price    propane     rate     equals
    Year       ($US/bbl) ($CAD/bbl) ($CAD/bbl) ($CAD/bbl) ($CAD/MMbtu) ($CAD/bbl)    (%)    $1 CAD)

    Historical                                                                                      

    2009           61.60      66.32      58.66      63.86         4.20      38.30       0.3     0.88

    2010           79.42      78.02      67.21      76.57         4.17      44.36       1.8     0.97

    2011           94.83      95.15      77.09      89.68         3.68      50.17       3.0     1.01

    2012           94.15      86.70      73.08      84.42         2.44      47.20       1.5     1.00

    2013           97.98      93.24      74.20      91.59         3.13      38.62       0.8     0.97

    Forecast                                                                                        

    2014           94.65      92.64      77.81      90.64         4.00      45.78       1.5     0.94

    2015           88.37      89.31      75.02      87.31         3.99      44.14       1.5     0.94

    2016           84.25      89.63      75.29      87.63         4.00      44.30       1.5     0.94

    2017           95.52     101.62      85.36      99.62         4.93      50.22       1.5     0.94

    2018           96.96     103.14      86.64     101.14         5.01      50.98       1.5     0.94

    2019           98.41     104.69      87.94     102.69         5.09      51.74       1.5     0.94

    2020           99.89     106.26      89.26     104.26         5.18      52.52       1.5     0.94

    2021          101.38     107.86      90.60     105.86         5.26      53.30       1.5     0.94

    2022          102.91     109.47      91.96     107.47         5.35      54.10       1.5     0.94

    2023          104.45     111.12      93.34     109.12         5.43      54.92       1.5     0.94

    Thereafter
    escalating
    at              1.5%       1.5%       1.5%       1.5%         1.5%       1.5%         -        -

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


                                                     Year ended December 31

                                  2013      2012      2011   3-Year average

    F&D costs including FDC
    (1)

      F&D costs per boe -      $  9.47   $ 25.50   $ 26.79   $        22.49
      proved plus probable

      F&D costs per boe -      $ 16.51   $ 30.96   $ 37.05   $        31.02
      proved

    F&D costs excluding FDC
    (2)

      F&D costs per boe -      $ 17.17   $ 17.48   $ 15.07   $        16.33
      proved plus probable

      F&D costs per boe -      $ 18.00   $ 26.69   $ 23.55   $        23.31
      proved

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

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

Capital expenditures for 2013 have been reduced by $83 million related
to joint venture carried capital (2012 – $137 million). 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)


                                                      At December 31, 2013

                                Proved Future         Proved plus Probable
    Year                    Development Costs     Future Development Costs

    2014                    $             704     $                    840

    2015                                  973                        1,533

    2016                                  419                          726

    2017                                   58                          149

    2018                                   35                           92

    2019 and subsequent                    60                          166

    Undiscounted total      $           2,249     $                  3,506

    Discounted @ 10%/yr     $           1,941     $                  2,958

                                                      At December 31, 2012

    Undiscounted total      $           2,563     $                  4,118

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

Outlook

This outlook section is included to provide shareholders with
information about our expectations as at March 6, 2014 for production
and capital expenditures in 2014 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
2014, including our non-core asset disposition program.

For 2014, our development capital expenditures budget is $900 million.
Our forecast 2014 average production is 101,000 boe per day to 106,000
boe per day.

For the first quarter of 2014, our development capital budget is
approximately $230 million.

There have been no changes to our guidance from our 2014 forecast
average production outlined in our January 21, 2014 press release “Penn
West Provides Fourth Quarter 2013 Operational Update and Announces
Additional Non-Core Asset Dispositions for Expected Proceeds of
Approximately $175 Million” and our 2014 development capital
expenditures budget outlined in our November 6, 2013 press release
“Penn West Announces its Financial Results for the Third Quarter Ended
September 30, 2013″ released and filed on SEDAR at www.sedar.com and on EDGAR at www.sec.gov.

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, gross revenues and recycle 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. Gross revenue is total revenues
including realized risk management gains and losses and is used to
assess the cash realizations on commodity sales. Recycle ratio is a
comparison of our netback to our finding and development costs and is
used to assess the cost of finding reserves compared to the cash
received.

Calculation of Funds Flow


                                  Three months ended          Year ended
                                         December 31         December 31
    (millions, except per share
    amounts)                          2013      2012      2013      2012

    Cash flow from operating       $   329   $   441   $ 1,039   $ 1,193
    activities

    Change in non-cash working       (129)     (178)      (51)      (37)
    capital

    Decommissioning expenditures        16        32        66        92

    Funds flow                     $   216   $   295   $ 1,054   $ 1,248

    Basic per share                $  0.44   $  0.62   $  2.17   $  2.62

    Diluted per share              $  0.44   $  0.62   $  2.17   $  2.62

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.

Forward-Looking Statements

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”, “budget”, “may”, “will”, “project”, “could”,
“plan”, “intend”, “should”, “believe”, “outlook”, “objective”, “aim”,
“potential”, “target” and similar words suggesting future events or
future performance. In addition, statements relating to “reserves” or
“resources” are deemed to be forward-looking statements as they involve
the implied assessment, based on certain estimates and assumptions,
that the reserves and resources described exist in the quantities
predicted or estimated and can be profitably produced in the future.
In particular, this document contains forward-looking statements
pertaining to, without limitation, the following: under “President’s
Message” – our intention to focus on our industry leading light-oil
positions in the Western Canada Sedimentary Basin, the application of
best-in-class operating practices, relentless cost control and to
de-lever the balance sheet to deliver shareholder value; our belief
that our capital efficiency improvements will continue as we realize
game changing capital cost reductions across our key plays; our
intention to continue to drive efficiencies to further enhance returns
and extend the economic longevity of our plays; our operated
development capital cost targets in our long-term plan; our intention
to operate in a continuous and deliberate manner to drive cost
efficiencies and predictable production performance; our expectation
that our production profile will shift as the effects of the front-end
loaded programs of the past dissipate; our expectation that we will be
able to advance drilling activities in the Cardium above our stated
business plan in 2014 and future years within the planned capital
allocations; our intention that operating excellence and investment
discipline will continue to be key organic levers while we progress
through phase two of our asset divestiture strategy and deliver a laser
focused portfolio and improve our balance sheet; under “Dividends” -
the details of our first quarter 2014 dividend payment; under “Play
Updates” – the details of our exploration and development programs in
2014 and beyond on our Cardium, Viking and Slave Point plays, including
the amount of capital budgeted for each play in 2014, the number of net
wells we plan to drill on each play in 2014, the EOR and waterflood
projects we intend to undertake, our continued focus on further cost
reductions and cycle time improvements, and our plans for down-spacing;
under “Disposition Update” – the details of our pending non-core asset
disposition; under “Reserves Data” – the estimated future development
costs of our reserves; and under “Outlook” – our forecast 2014 annual
and first quarter development capital expenditures budget and forecast
2014 average daily production.

With respect to forward-looking statements contained in this document,
we have made assumptions regarding, among other things: the terms and
timing of asset sales completed under our ongoing program to sell
between $1.5 billion and $2.0 billion of non-core assets, including the
asset sale anticipated to close in the first quarter of 2014; our
ability to execute or long-term plan as described herein and the impact
that the successful execution of such plan will have on our Company and
our shareholders; the economic returns anticipated from expenditures
on our assets; 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 and natural gas prices; future capital
expenditure levels; future crude oil, natural gas liquids and natural
gas production levels; 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 execute our capital programs as planned without
significant adverse impacts from various factors beyond our control,
including weather, infrastructure access and delays in obtaining
regulatory approvals and third party consents; 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; 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
heading “Outlook”.

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 possibility that we are
unable to execute some or all of our ongoing non-core asset disposition
program on favourable terms or at all, including the disposition
discussed herein that is scheduled to close in the first quarter of
2014, whether due to the failure to receive requisite regulatory
approvals or satisfy applicable closing conditions or for other reasons
that we cannot anticipate; the possibility that we will not be able to
successfully execute our long-term plan in part or in full, and the
possibility that some or all of the benefits that we anticipate will
accrue to our Company and our securityholders as a result of the
successful execution of such plan do not materialize; the impact of
weather conditions on seasonal demand; the impact of weather conditions
on our ability to execute capital programs; the risk that we will be
unable to execute our capital programs as planned without significant
adverse impacts from various factors beyond our control, including
weather, infrastructure access and delays in obtaining regulatory
approvals and third party consents; 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 and natural gas produced in Canada as
compared to other markets, and transportation restrictions, including
pipeline and railway capacity constraints; royalties payable in respect
of our oil and natural gas production and changes to government royalty
frameworks; 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 extreme cold during winter months,
wild fires and flooding; failure to obtain regulatory, industry partner
and other third-party consents and approvals when required, including
for acquisitions, dispositions and mergers; failure to realize the
anticipated benefits of dispositions, acquisitions, joint ventures and
partnerships, including those discussed herein; changes in tax and
other laws that affect us and our securityholders; the potential
failure of counterparties to honour their contractual obligations;
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; and the
other factors described in our public filings (including our Annual
Information Form) available in Canada at www.sedar.com and in the United States at www.sec.gov. Readers are cautioned that this list of risk factors should not be
construed as exhaustive.

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


                                   Penn West Petroleum Ltd.

                                 Consolidated Balance Sheets

                                                     As at December 31

    (CAD millions, unaudited)                          2013       2012

    Assets                                                            

    Current                                                           

       Accounts receivable                        $     263   $    364

       Other                                             57         79

       Deferred funding assets                          139        187

       Risk management                                    2         76

                                                        461        706

    Non-current                                                       

       Deferred funding assets                          184        238

       Exploration and evaluation assets                645        609

       Property, plant and equipment                  9,392     10,892

       Goodwill                                       1,912      1,966

       Risk management                                   50         26

                                                     12,183     13,731

    Total assets                                  $  12,644   $ 14,437

    Liabilities and Shareholders' Equity                              

    Current                                                           

       Accounts payable and accrued liabilities   $     654   $    764

       Dividends payable                                 68        129

       Current portion of long-term debt                 64          5

       Risk management                                   24          9

                                                        810        907

    Non-current                                                       

       Long-term debt                                 2,394      2,685

       Decommissioning liability                        603        635

       Risk management                                   16         35

       Deferred tax liability                         1,102      1,350

       Other non-current liabilities                      9          5

                                                      4,934      5,617

    Shareholders' equity                                              

       Shareholders' capital                          9,124      8,985

       Other reserves                                    80         97

       Deficit                                      (1,494)      (262)

                                                      7,710      8,820

    Total liabilities and shareholders' equity    $  12,644   $ 14,437


                                       Penn West Petroleum Ltd.

                           Consolidated Statements of Income (Loss)

                                   Three months ended            Year ended
                                          December 31           December 31

    (CAD millions, except per         2013       2012        2013      2012
    share amounts, unaudited)

        Oil and natural gas      $     606   $    791   $   2,827   $ 3,235
        sales

        Royalties                    (115)      (144)       (507)     (595)

                                       491        647       2,320     2,640

        Risk management gain
        (loss)

          Realized                       7          8           8        48

          Unrealized                  (13)         10        (94)       156

                                       485        665       2,234     2,844

    Expenses                                                               

        Operating                      204        243         853     1,019

        Transportation                   7          7          29        29

        General and                     34         46         160       172
        administrative

        Restructuring                    -         13          38        13

        Share-based                      2       (12)          32      (10)
        compensation

        Depletion,                     980        598       1,792     1,525
        depreciation and
        impairment

        Impairment of goodwill          48          -          48         -

        Loss (gain) on                  19      (254)          14     (359)
        dispositions

        Exploration and                 44         15          44        17
        evaluation

        Unrealized risk               (21)          6        (48)         5
        management loss (gain)

        Unrealized foreign              63         22         126      (32)
        exchange loss (gain)

        Financing                       45         52         184       199

        Accretion                       10         22          43        54

                                     1,435        758       3,315     2,632

    Income (loss) before taxes       (950)       (93)     (1,081)       212

        Deferred tax expense         (222)       (15)       (243)        63
        (recovery)

    Net and comprehensive        $   (728)   $   (78)   $   (838)   $   149
    income (loss)

    Net income (loss) per
    share

        Basic                    $  (1.49)   $ (0.16)   $  (1.72)   $  0.31

        Diluted                  $  (1.49)   $ (0.16)   $  (1.72)   $  0.31

    Weighted average shares
    outstanding (millions)

        Basic                        489.5      478.9       485.8     475.6

        Diluted                      489.5      478.9       485.8     475.8


                                       Penn West Petroleum Ltd.

                             Consolidated Statements of Cash Flows

                                   Three months ended            Year ended
                                          December 31           December 31

    (CAD millions, unaudited)        2013        2012      2013        2012

    Operating activities                                                   

      Net income (loss)           $ (728)   $    (78)   $ (838)   $     149

      Depletion, depreciation         980         598     1,792       1,525
      and impairment

      Impairment of goodwill           48           -        48           -

      Loss (gain) on                   19       (254)        14       (359)
      dispositions

      Exploration and                  44          15        44          17
      evaluation

      Accretion                        10          22        43          54

      Deferred tax expense          (215)        (15)     (236)          63
      (recovery)

      Share-based compensation          3        (11)        15        (18)

      Unrealized risk                 (8)         (4)        46       (151)
      management loss (gain)

      Unrealized foreign               63          22       126        (32)
      exchange loss (gain)

      Decommissioning                (16)        (32)      (66)        (92)
      expenditures

      Change in non-cash              129         178        51          37
      working capital

                                      329         441     1,039       1,193

    Investing activities                                                   

      Capital expenditures          (208)       (348)     (816)     (1,752)

      Property dispositions           473       1,264       525       1,615
      (acquisitions), net

      Change in non-cash               61           8      (44)       (168)
      working capital

                                      326         924     (335)       (305)

    Financing activities                                                   

      Decrease in long-term         (608)     (1,267)     (356)       (496)
      debt

      Issue of equity                   4           -        12           3

      Dividends paid                 (51)        (98)     (360)       (395)

                                    (655)     (1,365)     (704)       (888)

    Change in cash                      -           -         -           -

    Cash, beginning of period           -           -         -           -

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


                                      Penn West Petroleum Ltd.

                      Statements of Changes in Shareholders' Equity

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

    Balance at                                97   $   (262)   $     8,820
    January 1,
    2013            $       8,985   $

    Net and                                    -       (838)         (838)
    comprehensive
    loss                        -    

    Share-based                               15           -            15
    compensation                -    

    Issued on                               (32)           -            12
    exercise of
    options and
    share rights               44    

    Issued to                                  -           -            95
    dividend
    reinvestment
    plan                       95    

    Dividends                                  -       (394)         (394)
    declared                    -    

    Balance at                                80   $ (1,494)   $     7,710
    December 31,
    2013            $       9,124   $

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

    Balance at                                95   $     103   $     9,038
    January 1,
    2012            $       8,840   $

    Net and                                    -         149           149
    comprehensive
    income                      -    

    Share-based                               27           -            27
    compensation                -    

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

    Issued to                                  -           -           117
    dividend
    reinvestment
    plan                      117    

    Dividends                                  -                     (514)
    declared                    -                      (514)

    Balance at                                97   $           $     8,820
    December 31,                                       (262)
    2012            $       8,985   $

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 and webcast presentation will be held to discuss the
matters noted above at 9:00am Mountain Time (11:00am Eastern Time) on
Friday, March 7, 2014. The duration of the conference call is expected
to be approximately 30 minutes.

To listen to the conference call, please call 647-427-7450 or
1-888-231-8191 (toll-free). This call will be broadcast live on the
Internet and may be accessed directly at the following URL: http://event.on24.com/r.htm?e=754668&s=1&k=EBF7E3EFF18CA391A6490D4CEB866F66

A digital recording will be available for replay two hours after the
call’s completion, and will remain available until March 21, 2014 21:59
Mountain Time (23:59 Eastern Time). To listen to the replay, please
dial 416-849-0833 or 1-855-859-2056 (toll-free) and enter Conference ID
2959082, followed by the pound (#) key.

We expect to file our annual Management’s Discussion and Analysis and
audited annual consolidated financial statements on SEDAR and EDGAR
shortly.

SOURCE Penn West


Source: PR Newswire



comments powered by Disqus