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

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


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

2012 HIGHLIGHTS

  • Driven primarily by oil and natural gas liquids, the company generated funds flow of $1.25 billion;
  • Average production of 161,195 boe (1) per day was within the guidance range of 161,000 - 163,000 boe per day and weighted approximately 65 percent to oil and liquids;
  • Completed net dispositions of approximately 16,500 boe per day for proceeds of approximately $1.6 billion;
  • Total debt at year-end was approximately $2.7 billion and resulted in a debt-to-EBITDA (2) ratio of 2.1 times;
  • On a proved plus probable basis, we replaced 190 percent (3) of 2012 production, excluding economic revisions and acquisition and disposition activity through the addition of approximiately 110 million boe of reserves of which approximately 80 percent were crude oil and liquids;
  • Proved plus probable finding and development costs including future development capital improved approximately five percent year-over-year to $25.50 per boe or $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.
(3) Includes dividends paid prior to those reinvested in shares under the dividend reinvestment plan. In 2011, we began paying dividends on a quarterly basis. The last monthly distribution payment as a Trust was declared in December 2010 and paid in January 2011 ($0.09 per unit). Our first quarterly dividend ($0.27 per share) as a corporation was paid in April 2011.

DRILLING STATISTICS

  Three months ended December 31 Year ended December 31
2012 2011 2012 2011
  Gross Net Gross Net Gross Net Gross Net
Oil 55 31 135 101 349 263 457 353
Natural gas - - 7 4 23 19 53 36
  55 31 142 105 372 282 510 389
Stratigraphic and 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

  Three months ended December 31 Year ended December 31
(millions of shares) 2012 2011 %
change
2012 2011 %
change
Weighted average            
  Basic 478.9 471.1 2 475.6 467.2 2
  Diluted 478.9 471.2 2 475.8 467.4 2
Outstanding as at 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 (1)(2)
Light &
Medium Oil
Heavy Oil Natural Gas Natural Gas
Liquids
Barrels of
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 (1)(2)
Light &
Medium Oil
Heavy Oil Natural Gas Natural Gas
Liquids
Barrels of
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 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 Probable Proved
plus
probable
  Proved Probable Proved
plus
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 Probable Proved
plus
probable
  Proved Probable Proved
plus
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 Probable Proved
plus
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    
  WTI
Cushing,
Oklahoma
Edmonton
Par
40o API
Lloydminster
Blend
21o API
Cromer
Medium
29o API
  Natural gas
AECO
gas price
Edmonton
propane
Inflation
rate
Exchange rate
(US$ 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)

Year Proved Future
Development Costs
Proved plus Probable
Future Development Costs
2013 $ 994 $ 1,233
2014   787   1,291
2015   519   997
2016   98   254
2017   19   35
2018 and subsequent   146   308
Undiscounted total $ 2,563 $ 4,118
Discounted @ 10%/yr $ 2,175 $ 3,411

Letter to our Shareholders


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

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

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

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

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

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

(signed)

Murray R. Nunns
President and Chief Executive Officer  

Calgary, Alberta
February 13, 2013

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

Outlook

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

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

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

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

Non-GAAP Measures Advisory

This news release includes non-GAAP measures not defined under International Financial Reporting Standards ("IFRS") including funds flow, funds flow per share-basic, funds flow per share-diluted, netback and debt to EBITDA ratio. Non-GAAP measures do not have any standardized meaning prescribed by GAAP and therefore may not be comparable to similar measures presented by other issuers. Funds flow is cash flow from operating activities before changes in non-cash working capital and decommissioning expenditures. Funds flow is used to assess our ability to fund dividends and planned capital programs. See "Calculation of Funds Flow" below. Netback is a per-unit-of-production measure of operating margin used in capital allocation decisions, to economically rank projects and is the per unit of production amount of revenue less royalties, operating costs, transportation and realized risk management gains and losses. Debt to EBITDA is a financial covenant for Penn West in the agreements governing our credit facility and our senior unsecured notes and compares our current and long-term debt balance to our earnings before interest, taxes, depreciation and amortization.

Oil and Gas Information Advisory

Barrels of oil equivalent ("boe") may be misleading, particularly if used in isolation. A boe conversion ratio of six thousand cubic feet of natural gas to one barrel of crude oil is based on an energy equivalency conversion method primarily applicable at the burner tip and does not represent a value equivalency at the wellhead. Given that the value ratio based on the current price of crude oil as compared to natural gas is significantly different from the energy equivalency conversion ratio of 6:1, utilizing a conversion on a 6:1 basis is misleading as an indication of value.

Contingent Resource Disclosures

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

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

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

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

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

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

Forward-Looking Statements

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

Penn West Petroleum Ltd.
Consolidated Balance Sheets
  As at December 31
(CAD millions, unaudited)                          2012 2011
         
Assets        
Current        
  Accounts receivable $ 364 $ 486
  Other                       79   104
  Deferred funding assets   187   236
  Risk management   76   39
    706   865
Non-current        
   Deferred funding assets   238   360
   Exploration and evaluation 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
December 31
Year ended
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
December 31
Year ended
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'
Capital
Other
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'
Capital
Other
Reserves
Retained 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
December 31
Year ended
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
December 31
Year ended
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
December 31
Year ended
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
December 31
Year ended
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
            December 31
Year ended
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
December 31
Year ended
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
December 31
Year ended
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:

  Issue date Amount (millions) Term Average
interest
rate
Weighted
average
remaining 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 £57 10 years 6.95% (1) 5.6 years
2009 Notes May 5, 2009 US$154 (2), £20,
€10, CAD$5
5 - 10 years 8.85% (3) 4.0 years
2010 Q1 Notes March 16, 2010 US$250, CAD$50 5 - 15 years 5.47% 5.8 years
2010 Q4 Notes December 2, 2010,
January 4, 2011
US$170, CAD$60 5 - 15 years 5.00% 8.7 years
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
December 31
Year ended
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
December 31
Year ended
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
December 31
Year ended
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
December 31
Year ended
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
December 31
Year ended
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
December 31
Year ended
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
December 31
Year ended
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
December 31
Year ended
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).
(2)      Excludes the current portion of risk management and share-based compensation liability.

Dividends

  Three months ended
December 31
Year ended
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
volume
Remaining
term
Pricing Fair value
(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 £57 2018 2.0075 CAD/GBP, 6.95%   (19)
   10-year initial term £20 2019 1.8051 CAD/GBP, 9.15%   (3)
   10-year initial term €10 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 www.pennwest.com for details of all financial instruments currently outstanding.

Sensitivity Analysis

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

  Impact on funds flow
Change of: Change $ millions $/share
Price per barrel of liquids $1.00 24 0.05
Liquids production 1,000 bbls/day 20 0.04
Price per mcf of natural gas $0.10 5 0.01
Natural gas production 10 mmcf/day 2 -
Effective interest rate 1% 6 0.01
Exchange rate ($US per $CAD) $0.01 27 0.06

Contractual Obligations and Commitments

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

(millions) 2013 2014 2015 2016 2017 Thereafter
Long-term debt $ 5 $ 60 $ 251 $ 968 $ 242 $ 1,164
Transportation   24   17   10   4   1   -
Transportation ($US)   4   37   37   33   33   198
Power infrastructure   29   14   14   14   14   12
Drilling rigs   23   21   17   11   6   -
Purchase obligations (1)   6   5   5   1   1   1
Interest obligations   146   142   132   105   77   136
Office lease (2)   62   56   55   54   52   384
Decommissioning liability (3) $ 100 $ 95 $ 91 $ 87 $ 82 $ 180
(1)      These amounts represent estimated commitments of $13 million for CO2 purchases and $6 million for processing fees related to our interests in the Weyburn Unit.
(2)      The future office lease commitments above are contracted to be reduced by sublease recoveries totalling $335 million.
(3)      These amounts represent the inflated, discounted future reclamation and abandonment costs that are expected to be incurred over the life of the properties.

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

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

Equity Instruments

   
Common shares issued:  
   As at December 31, 2012 479,258,670
   Issued on exercise of share rights 82,242
   Issued pursuant to dividend reinvestment plan 2,807,458
   As at February 13, 2013 482,148,370
   
Options outstanding:  
   As at December 31, 2012 15,737,400
   Granted 35,100
   Forfeited (1,266,271)
   As at February 13, 2013 14,506,229
Share Rights outstanding:  
   As at December 31, 2012 291,638
   Exercised (37,821)
   Forfeited (21,590)
   As at February 13, 2013 232,227
Restricted Options outstanding (1):  
   As at December 31, 2012 10,535,361
   Forfeited (1,282,715)
   As at February 13, 2013 9,252,646
(1)      Each holder of a Restricted Option holds a Restricted Right and has the option to settle the Restricted Right in cash or common shares upon exercise. Refer to the "Expenses - Share-Based Compensation" section of this Management Commentary for further details.

Forward-Looking Statements

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

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

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

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

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

Additional Information

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

Investor Information


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

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

To listen to the conference call, please call 647-427-7450 or 1-888-231-8191 (North America toll-free). This call will be broadcast live on the Internet and may be accessed directly on the Penn West website at www.pennwest.com or at the following URL:
http://event.on24.com/r.htm?e=582804&s=1&k=042420A83CA78A991EE4C87CAB9D5901

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

 

 

 

 

 

SOURCE Penn West Exploration




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