Penn West Exploration Announces its Financial Results for the Fourth Quarter Ended December 31, 2011
CALGARY, Alberta, February 16, 2012 /PRNewswire/ --
PENN WEST PETROLEUM LTD. (TSX: PWT) (NYSE: PWE)("PENN WEST") is pleased to announce its results for the fourth quarter ended December 31, 2011
Penn West has the largest light-oil asset base in Canada with the greatest leverage to the application of horizontal multi-frac technology. After several years of significant appraisal activity, we have moved into large-scale development. We believe our recent results are reflecting the potential of our company.
Highlights
- Production for the fourth quarter was 168,801 boe (1) per day, an increase of more than 7,000 boe per day over our third quarter production. We met the mid-point of both our 2011 annual and second half average production guidance. Exit production, before the impact of asset dispositions, was approximately 172,000 boe per day. Cardium production originally planned for exit 2011 is now on-stream.
- Reserve replacement (2) exceeded 230 percent, prior to the impact of economic natural gas price revisions and asset dispositions. Greater than 70 percent of added reserves were light oil and liquids contributing $2.70 per share to our net asset value (3), after the effect of downward revisions of future natural gas prices.
- Funds flow (4) was $437 million ($0.93 per share-basic (4)) in the fourth quarter of 2011, a 43 percent increase from the $305 million ($0.67 per share-basic) reported in the fourth quarter of 2010. Stronger funds flow was driven by greater oil and liquids weighting, an increase in production and strengthening crude oil prices.
- Our portfolio management program is on-track with net realized proceeds of approximately $440 million in 2011 and 2012 to-date from the sale of approximately 5,500 boe per day. These dispositions support our strategy of prudent balance sheet management while facilitating our shift from light-oil appraisal to development.
- Penn West entered 2012 with significant operating momentum launched by strong fourth quarter execution. We ramped up development activity across our light-oil projects with 108 net wells drilled in the fourth quarter of 2011. We advanced some of our 2012 drilling and facilities projects to the fourth quarter of 2011 to provide greater certainty of first quarter 2012 production additions.
Production
- Average production increased to 168,801 boe per day for the fourth quarter of 2011 from 161,323 boe per day in the third quarter of 2011.
- Penn West's exit production was weighted approximately 65 percent to oil and liquids.
- Average oil and liquids production was approximately 108,000 barrels per day in the fourth quarter of 2011, an increase of seven percent over the third quarter of 2011.
- Our second half 2011 production averaged 165,062 boe per day, meeting our second-half guidance.
- Annual 2011 production averaged 163,094 boe per day, in line with guidance.
(1) Please refer to the "Oil and Gas Information Advisory" section below
for information regarding the term "boe".
(2) Reserve replacement is calculated by dividing reserve additions by
production on a proved plus probable reserve basis.
(3) Net asset value per share contribution is calculated as the change in
the net present value of future net revenue before income taxes
discounted at 10 percent on a proved plus probable reserves basis from
the prior year over the total outstanding shares at December 31, 2011.
(4) The terms "funds flow" and "funds flow per share-basic" are non-GAAP
measures. Please refer to the "Calculation of Funds Flow" and
"Non-GAAP Measures Advisory" sections below.
Reserves
- In 2011, Penn West added approximately 138 million boe of reserves on a proved plus probable basis (2010 - 72 million boe), a reserve replacement ratio of 234 percent (2010 - 122 percent), excluding the effect of acquisitions and dispositions and economic factors, with approximately 73 percent of the additions being crude oil and liquids (2010 - 65 percent).
- Total working interest proved plus probable reserves were 719 mmboe at December 31, 2011 (2010 - 661 mmboe), weighted approximately 71 percent to crude oil and liquids (2010 - 69 percent).
- Proved plus probable oil and liquids reserves of approximately 513 million barrels represents a 13 percent increase over 2010.
- Adjusted finding and development costs ("F&D")(1) on a proved plus probable basis, including the change in future development capital were $22.64 per boe for 2011 (2010 - $21.97 per boe).
- The net present value of proved plus probable reserves at a 10 percent discount rate increased 12 percent over 2010, after the effect of downward revisions of future natural gas prices.
Financial
- Funds flow was $437 million in the fourth quarter of 2011, a 43 percent increase from the $305 million reported in the fourth quarter of 2010 and a 26 percent increase from the $348 million reported in the third quarter of 2011. The increase was attributed to stronger crude oil prices and our increased oil and liquids production. Funds flow was $0.93 per share-basicin the fourth quarter of 2011 compared to $0.67 per share-basic in the fourth quarter of 2010 and $0.74 per share-basic in the third quarter of 2011.
- Funds flow for 2011 totalled $1,537 million compared to $1,185 million in 2010 as a result of stronger commodity prices and a year-over-year increase in our light-oil production.
- Net income for 2011 totalled $638 million compared to $1,110 million in 2010. The prior period included significant gains on asset dispositions including a $572 million after-tax gain recorded on the formation of the Peace River Oil Partnership and a $368 million gain on the formation of our joint venture in the Cordova Embayment.
- Net loss for the fourth quarter of 2011 was $62 million ($0.13 per share-basic) compared to a net loss of $37 million ($0.08 per share-basic) in the fourth quarter of 2010 and net income of $138 million ($0.29 per share-basic) in the third quarter of 2011. The net loss in the fourth quarter of 2011 was primarily due to unrealized risk management losses.
- Capital expenditures for the fourth quarter of 2011, including net property dispositions, totalled $583 million compared to $469 million for the fourth quarter of 2010.
- Our 2011 net capital expenditures of $1,580 million were substantially in line with our previous forecast of $1.4 billion - $1.5 billion, net of asset dispositions. We advanced certain projects in our 2012 capital program into late 2011.
- On December 31, 2011 the PWT.DB.F convertible debentures matured and were settled in cash totalling $224 million. We now have no convertible debentures outstanding.
Dividend
- On February 15, 2012, our Board of Directors declared a first quarter 2012 dividend of $0.27 per share to be paid on April 13, 2012 to shareholders of record on March 30, 2012. Shareholders are advised that this dividend is designated as an "eligible dividend" for Canadian income tax purposes.
(1) Refer to "finding and development costs" table below for a discussion on Adjusted F&D.
Risk Management
- For 2012, we have 60,000 barrels per day of our liquids production hedged between US$85.53 per barrel and US$101.16 per barrel and 20,000 barrels per day of our liquids production for 2013 hedged between US$90.00 per barrel and US$106.31 per barrel.
- In 2012, we have 50,000 mcf per day of our natural gas production hedged at an average price of $4.30 per mcf.
- We have foreign exchange contracts to swap US$156 million per month of US dollar revenue for 2012 to Canadian dollars at an average rate of 1.02 Canadian dollars per US dollar.
2011 OPERATIONS
Penn West continued its oil focused capital program during the fourth quarter of 2011 with 20-25 rigs deployed throughout this period. Production results in the second half of 2011 have met our expectations as we resolved the operational issues resulting from severe flooding and wild fires in the second quarter of 2011. In 2011, capital expenditures including net property dispositions totalled $1,580 million including land expenditures of $181 million. We moved to large-scale development in our key light-oil resource plays. We acquired significant land positions based on proprietary knowledge to expand key resource plays as well as to gain strategic holdings in emerging plays.
Drilling Statistics
Three months ended Year ended
December 31 December 31
2011 2010 2011 2010
Gross Net Gross Net Gross Net Gross Net
Oil 135 101 134 93 457 353 351 245
Natural gas 7 4 15 13 53 36 53 38
Dry - - 1 - - - 3 2
142 105 150 106 510 389 407 285
Stratigraphic and service 12 3 16 10 89 37 54 34
Total 154 108 166 116 599 426 461 319
Success rate (1) 100% 100% 100% 99%
(1) Success rate is calculated excluding stratigraphic and service wells.
Oil Development
- Carbonates - We added key strategic infrastructure and significantly grew our land position. Drilling activity evolved from appraisal to focused development in the Slave Point and Swan Hills trends with over 40 net wells drilled.
- Cardium - Penn West has the largest position in the industry on the Cardium oil trend. We moved to full-scale development in portions of this play with approximately 100 net wells drilled with focus at Alder Flats, Willesden Green and West Pembina.
- Viking - Through our legacy land positions and Crown land sale acquisitions over the past three years, Penn West has a significant land position with over 750,000 net acres on the trend. Our Viking capital program included both tight-oil development and exploration drilling. We believe the potential exists to meaningfully expand our oil resource on this play.
- Spearfish - We drilled approximately 95 net wells in 2011. We began facility expansion and accelerated drilling activity in the fourth quarter to provide greater certainty for future production additions.
2012 OPERATIONS
In 2012, we continue to focus on light-oil plays and the strong returns that these development areas are providing. The results of our drilling and completion activities remain positive and our production rates and capital costs are consistent with our expectations. The size and scale of our program helps provide certainty of supply for our drilling, completions, and facilities requirements.
Oil Development
- Carbonates - With seven active drilling rigs, we anticipate spending between $300 million and $350 million. The focus of our program will continue to be on the Slave Point to take advantage of the predictability of this play and our pre-built infrastructure.
- Cardium - 2012 development capital for the Cardium is expected to be $225 million to $275 million. Five drilling rigs continue to focus on the Willesden Green, Alder Flats and West Pembina areas where results have consistently exceeded industry averages.
- Spearfish - We have five active rigs drilling and expansion of our Waskada oil battery is scheduled for completion in the first quarter of 2012. This will increase production capacity to 13,500 barrels of oil per day. We have planned a capital program of between $200 million and $250 million.
- Viking - Our 2012 capital plan is to spend between $125 million and $175 million, with development on the Saskatchewan side of the play and further appraisal of the oil potential in Alberta.
Resource Appraisal
We have established four major resource appraisal initiatives. Each component has significant value-creation potential and optionality for Penn West beyond our substantial primary light-oil development.
- Enhanced Oil Recovery ("EOR") - The combination of proven EOR techniques, including waterfloods and horizontal multi-frac technology, has opened an avenue for a material increase in oil recovery from our legacy fields.
- Exploration - We have used our knowledge in tight oil, information from major source rock developments around the world, and the leverage of our existing infrastructure, to establish significant land positions on several trends for future development.
- Peace River Oil Partnership - We continue to appraise the parameters for commercial thermal development in this oil sands resource. Initial testing of the thermal application was very positive and we are committed to moving this project ahead.
- Cordova Joint Venture - Appraisal of this shale-gas resource and productivity testing continues, including the drilling of additional multi-well pads.
HIGHLIGHTS
Three months ended Year ended
December 31 December 31
%
2011 2010 change 2011 2010 % change
Financial
(millions, except per share
amounts)
Gross revenues (1) $ 979 $ 782 25 $ 3,604 $ 3,034 19
Funds flow 437 305 43 1,537 1,185 30
Basic per
share 0.93 0.67 39 3.29 2.68 23
Diluted per
share (2) 0.93 0.66 41 3.29 2.65 24
Net income (loss) (2) (62) (37) 68 638 1,110 (43)
Basic per
share (2) (0.13) (0.08) 63 1.37 2.51 (45)
Diluted per
share (2) (0.13) (0.08) 63 1.36 2.48 (45)
Capital expenditures,
net (3) 583 469 24 1,580 (119) 100
Long-term debt at
period-end 3,219 2,496 29 3,219 2,496 29
Convertible
debentures - 255 (100) - 255 (100)
Dividends paid (4) $ 127 $ 123 3 $ 420 $ 708 (41)
Payout ratio (5) 29% 40% (11) 27% 60% (33)
Operations
Daily production
Light oil and
NGL (bbls/d) 90,185 88,447 2 85,316 80,706 6
Heavy oil
(bbls/d) 17,886 16,849 6 17,892 18,260 (2)
Natural gas
(mmcf/d) 364 365 - 359 394 (9)
Total production
(boe/d) 168,801 166,148 2 163,094 164,633 (1)
Average sales price
Light oil and
NGL (per bbl) $ 88.76 $ 71.05 25 $ 86.19 $ 69.29 24
Heavy oil (per
bbl) 76.88 61.87 24 69.07 60.55 14
Natural gas
(per mcf) $ 3.47 $ 3.79 (8) $ 3.78 $ 4.20 (10)
Netback per boe
Sales price $ 63.05 $ 52.43 20 $ 60.99 $ 50.74 20
Risk
management
loss (0.84) (1.51) (44) (1.06) (0.34) 100
Net sales
price 62.21 50.92 22 59.93 50.40 19
Royalties (11.47) (9.14) 25 (11.09) (9.07) 22
Operating
expenses (17.48) (15.92) 10 (17.40) (15.71) 11
Transportation (0.48) (0.52) (8) (0.49) (0.55) (11)
Netback $ 32.78 $ 25.34 29 $ 30.95 $ 25.07 23
(1) Gross revenues include realized gains and losses on commodity
contracts.
(2) Comparative figures have been revised to comply with IFRS.
(3) Excludes business combinations.
(4) 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.
(5) Payout ratio is calculated as dividends paid divided by funds flow.
The term "payout ratio" is a non-GAAP measure. See "Non-GAAP Measures
Advisory" section below.
LAND
As at December 31
Producing Non-producing
% %
2011 2010 change 2011 2010 change
Gross acres (000s) 6,144 6,354 (3) 2,980 3,012 (1)
Net acres (000s) 4,093 4,185 (2) 2,105 2,093 1
Average working interest 67% 66% 1 71% 69% 2
Acreage figures are comparable year-over-year as strategic land acquisitions have offset land lease expiries in non-core areas and net asset dispositions.
COMMON SHARES DATA
Three months
ended Year ended
December 31 December 31
% %
(millions of shares) 2011 2010 change 2011 2010 change
Weighted average
Basic 471.1 457.0 3 467.2 441.8 6
Diluted 471.2 463.8 2 467.4 451.6 4
Outstanding as at December 31 471.4 459.7 3
RESERVES DATA
a) Working Interest Reserves using forecast prices and costs
Penn West as
at
December 31,
2011
Reserve
Estimates
Category Light & Natural Gas Barrels of
(1)(2) Medium Oil Heavy Oil Natural Gas Liquids Oil Equivalent
(mmbbl) (mmbbl) (bcf) (mmbbl) (mmboe)
Proved
Developed
producing 205 48 661 23 385
Developed
non-producing 6 1 35 1 13
Undeveloped 78 2 88 4 99
Total Proved 288 51 783 28 498
Probable 113 22 452 12 222
Total Proved
plus Probable 401 73 1,235 39 719
(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, 2011
Reserve
Estimates
Category Light & Natural Gas Barrels of
(1)(2) Medium Oil Heavy Oil Natural Gas Liquids Oil Equivalent
(mmbbl) (mmbbl) (bcf) (mmbbl) (mmboe)
Proved
Developed
producing 176 44 582 17 334
Developed
non-producing 5 1 29 1 11
Undeveloped 67 2 78 3 86
Total Proved 248 47 689 21 430
Probable 93 19 383 9 186
Total Proved
plus Probable 342 66 1,073 30 616
(1) Net after royalty reserves are working interest reserves including
royalty interests and deducting royalty burdens.
(2) Columns may not add due to rounding.
Our proved reserves continue to reflect a high percentage of developed reserves. Of total proved reserves, 80 percent were developed at December 31, 2011 (2010 - 86 percent). At December 31, 2011, total proved reserves as a percentage of proved plus probable reserves were 69 percent (2010 - 73 percent). In 2011, all of our reserves were evaluated or audited by independent, qualified engineering firms GLJ Petroleum Consultants Ltd. ("GLJ") or Sproule Associates Limited ("SAL"). Approximately 16 percent of total proved plus probable reserves were internally evaluated and 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 above are estimates only and there is no guarantee that the estimated reserves will be recovered. Actual reserves may be greater than or less than the estimates provided herein.
Additional reserve disclosures, as required under NI 51-101, will be contained in our Annual Information Form that will be filed on SEDAR at http://www.sedar.com .
c) Reconciliation of Working Interest Reserves using forecast prices and costs
Light and Medium Oil and Heavy
Reconciliation Items Natural Gas Liquids Oil
(1) (mmbbl) (mmbbl)
Proved Proved
plus plus
Proved Probable probable Proved Probable probable
December 31, 2010 283 103 387 54 14 68
Extensions 20 13 33 1 1 2
Improved Recovery 2 - 3 1 5 6
Infill Drilling 33 11 44 1 2 3
Technical Revisions 11 (2) 9 1 - 1
Discoveries - - - - - -
Acquisitions 6 2 7 - - -
Dispositions (6) (3) (9) - - (1)
Economic Factors (2) - (2) - - 1
Production (31) - (31) (7) - (7)
December 31, 2011 316 124 440 51 22 73
Barrels of Oil
Reconciliation Items Natural Gas Equivalent
(1) (bcf) (mmboe)
Proved Proved
plus plus
Proved Probable probable Proved Probable probable
December 31, 2010 865 370 1,235 481 179 661
Extensions 41 109 150 28 32 60
Improved Recovery 2 - 2 4 5 9
Infill Drilling 41 15 56 41 15 57
Technical Revisions 40 (29) 11 19 (7) 12
Discoveries - - - - - -
Acquisitions 13 4 16 8 2 10
Dispositions (22) (7) (30) (11) (4) (15)
Economic Factors (68) (10) (79) (13) (1) (14)
Production (128) - (128) (59) - (59)
December 31, 2011 783 452 1,235 498 222 719
(1) Columns may not add due to rounding.
On a proved plus probable basis our reserves are weighted 71 percent to crude oil and liquids (2010 - 69 percent) and 29 percent to natural gas (2010 - 31 percent).
d) Net present value of future net revenue using forecast prices and costs (millions) at December 31, 2011
Net present value of future net revenue before income taxes
(discounted @)
Reserve Category
(1) 0% 5% 10% 15% 20%
Proved
Developed
producing $ 13,556 $ 9,464 $ 7,417 $ 6,177 $ 5,337
Developed
non-producing 418 298 232 191 163
Undeveloped 3,870 2,242 1,406 916 603
Total proved $ 17,844 $ 12,004 $ 9,055 $ 7,283 $ 6,103
Probable 9,218 4,785 2,988 2,070 1,530
Total proved plus
probable $ 27,063 $ 16,790 $ 12,042 $ 9,354 $ 7,633
(1) Columns may not add due to rounding.
Net present values take into account wellbore abandonment liabilities and are based on the price assumptions that are contained in the following table. It should not be assumed that the estimated future net revenues represent fair market value of the reserves. There is no assurance that the forecast price and cost assumptions will be attained and variances could be material.
e) Summary of pricing and inflation rate assumptions as of December 31, 2011 using forecast prices and costs
Oil
WTI Lloydminster Cromer
Cushing, Edmonton Par Blend Medium
Oklahoma 40o API 21o API 29o API
Year ($US/bbl) ($CAD/bbl) ($CAD/bbl) ($CAD/bbl)
Historical
2007 72.24 77.02 52.03 66.30
2008 98.05 101.82 82.59 93.40
2009 61.60 66.32 58.39 62.98
2010 79.42 78.02 66.79 73.81
2011 94.83 95.15 76.37 87.57
Forecast
2012 97.53 97.42 81.83 90.11
2013 97.45 97.38 81.01 90.06
2014 96.00 95.95 79.79 88.23
2015 98.71 98.63 82.06 90.71
2016 99.68 99.59 82.88 91.61
2017 100.68 100.57 83.72 92.52
2018 102.37 102.26 85.13 94.08
2019 104.41 104.32 86.84 95.97
2020 106.50 106.42 88.59 97.90
2021 108.63 108.55 90.37 99.87
Thereafter
escalating at 2% 2% 2% 2%
Table Continued Below
Natural gas
AECO Edmonton Inflation Exchange rate
gas price propane rate (US$ equals
Year ($CAD/mcf) ($CAD/bbl) (%) $1 CAD)
Historical
2007 6.65 46.85 2.1 0.94
2008 8.16 58.31 1.7 0.94
2009 4.20 37.99 0.3 0.88
2010 4.17 46.87 1.8 0.97
2011 3.68 53.47 3.0 1.01
Forecast
2012 3.32 56.15 2.0 1.00
2013 3.95 56.45 2.0 1.00
2014 4.36 55.80 2.0 1.00
2015 5.29 57.69 2.0 1.00
2016 5.58 58.20 2.0 1.00
2017 5.87 58.72 2.0 1.00
2018 6.05 59.67 2.0 1.00
2019 6.17 60.83 2.0 1.00
2020 6.30 62.01 2.0 1.00
2021 6.43 63.22 2.0 1.00
Thereafter
escalating at 2% 2% 2.0 -
f) Finding and development costs ("F&D costs")
Year ended December 31
2011 2010 2009 3-Year average
Adjusted F&D costs
including Future
Development Costs ("FDC")
(1)
F&D costs per boe - proved
plus probable $ 22.64 $ 21.97 $ 15.18 $ 20.97
F&D costs per boe - proved $ 29.71 $ 23.56 $ 15.63 $ 24.70
Excluding FDC (2)
F&D costs per boe - proved
plus probable $ 15.07 $ 18.90 $ 13.75 $ 15.81
F&D costs per boe - proved $ 23.55 $ 21.50 $ 16.10 $ 21.11
Including FDC (3)
F&D costs per boe - proved
plus probable $ 26.79 $ 26.73 $ 16.12 $ 24.51
F&D costs per boe - proved $ 37.05 $ 28.01 $ 16.19 $ 29.17
(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 and excludes land acquisition costs.
(2) The calculation of F&D excludes the change in FDC and excludes the
effects of acquisitions and dispositions.
(3) The calculation of F&D includes the change in FDC and excludes the
effects of acquisitions and dispositions.
Capital expenditures for 2011 have been reduced by $107 million related to joint venture carried capital (2010 -$17 million). We use Adjusted F&D to assess the economic viability and the stage of development of our resource plays. F&D costs are calculated in accordance with NI 51-101, which include the change in FDC, on a proved and proved plus probable basis. For comparative purposes we also disclose F&D costs excluding FDC.
The aggregate of the exploration and development costs incurred in the most recent financial year and the change during that year in estimated future development costs generally will not reflect total finding and development costs related to reserves additions for that year.
g) Future development costs using forecast prices and costs (millions)
Proved Future Proved plus Probable
Year Development Costs Future Development Costs
2012 $ 972 $ 1,382
2013 736 1,001
2014 424 631
2015 81 142
2016 53 80
2017 and subsequent 193 286
Undiscounted total $ 2,459 $ 3,522
Discounted @ 10%/yr $ 2,063 $ 2,952
Letter to our Shareholders
The world energy complex is forever evolving. Changes in supply, demand, infrastructure, and technology all contribute to the market balances for energy products. Some of these changes are subtle and take place over extended periods of time while others are more immediate in nature and occur rapidly. Anticipating, recognizing and proactively adjusting to these market forces have become increasingly important as the rate of change accelerates. No business will ever get all of the required adjustments perfect, however millions of years of paleontology reminds us that failure to adapt to the environment will result in extinction. Penn West's response to these market pressures has been a combination of long-term strategic evolutions coupled with short-term tactical adjustments.
As Penn West began moving back to the E&P model, we recognized significant shifts in the energy complex. It was becoming apparent that the Asian market was of increasing importance with respect to oil consumption. The requirements for capital to develop oil resources continue to exceed current capital capabilities within Canada. Asia provided an emerging source of capital. The creation of the Peace River Oil Partnership was a response by Penn West to these market factors. This positioned Penn West for the appraisal of significant oil resources and supported building long-term relationships in Asia.
The technology changes to both drilling and completion techniques have led to a reinvention of the conventional oil and gas business in North America. The application of this technology to natural gas resources has led to a structural change to the cost base of North American natural gas. The combination of new technology and strong capitalization led to significant natural gas supply additions over the past several years. These supply additions in the land-locked market of North America and flat domestic demand led to the current state of oversupply of natural gas. North America has limited ability to ship natural gas to world markets. This led to a significant weakening of natural gas prices. We believe in the long term there will be a demand-side response through transportation, electrical generation and off-take initiatives which will result in a return to a balanced natural gas market. Reacting to these conditions, we formed a joint venture relationship in 2010 with Mitsubishi Corporation, one of the world's largest LNG developers, to participate in the export of North American natural gas.
In 2009, our concern over the low-cost shale gas supply in the US, combined with the potential to apply new technologies to our vast legacy oil assets prompted us to focus an increasing amount of our time and attention on light oil. Since that time, we have allocated an increasing portion of our annual capital spending program into these assets. As we enter 2012, our capital budget is focused on large scale, light-oil development projects.
We anticipate liquids production will grow in a meaningful way in North America over the next few years. The differential that developed between oil benchmarked off WTI, the former gold-standard in oil pricing, and Brent crude highlights the importance of the oil transportation balance in North America. We believe we must be well-positioned to gain access to world markets and pricing. We have begun committing volumes to pipeline projects that provide access to the Gulf Coast, and other intra-North American refineries.
As the economic events of the last five years have unfolded, oil prices have moved from below $40 per barrel to prices in excess of $100 per barrel. We actively hedge our oil program with collars to limit our exposure to the downside while still providing our shareholders with participation in the upside. We have a significant portion of our 2012 program hedged at attractive prices and we are actively increasing our 2013 oil hedges.
The longevity of Penn West and the shareholder value created over the past two decades is a reflection of our ability to adapt to a changing energy, technology and capital markets landscape. The lessons learned and the wisdom accumulated over this time is ingrained within the Penn West corporate DNA.
(signed "Murray R. Nunns") Murray R. Nunns President and Chief Executive Officer Calgary, Alberta February 15, 2012
Outlook
This outlook section is included to provide shareholders with information about our expectations as at February 15, 2012 for production and capital expenditures for 2012 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".
Our prior forecast was released on November 2, 2011 with our third quarter results and filed on SEDAR at http://www.sedar.com . Production was in-line with previous guidance for 2011 annual and 2011 second half production. Cardium production originally planned for exit 2011 came on-stream in early 2012. Capital expenditures guidance of $1.4 billion to $1.5 billion, net of asset dispositions, was slightly exceeded as we shifted the timing on some of our 2012 projects into the fourth quarter of 2011 to partially mitigate the possibility of an early spring break-up due to unseasonably warm weather.
Our estimated 2012 exploration and development capital program is expected to be in the range of $1.6 billion to $1.7 billion prior to asset dispositions. Our 2012 plan is to continue to focus on light-oil plays and continue to move toward full-scale development at the Cardium, Carbonates, Spearfish and Viking. Based on this level of capital expenditures, we estimate average production to be approximately 174,000 to 178,000 boe per day, prior to the effect of asset dispositions.
Assuming there is no further significant acquisition or disposition activity in 2012, our forecast average production for 2012 is between 168,500 and 172,500 boe per day and our estimated exploration and development capital would be in the range of $1.3 billion to $1.4 billion, in each case after reflecting the impact of net asset dispositions of $340 million to-date in 2012.
Non-GAAP Measures Advisory
This news release includes non-GAAP measures not defined under IFRS or previous generally accepted accounting principles ("GAAP"), including funds flow, funds flow per share-basic, funds flow per share-diluted, netback and payout 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. Payout ratio is calculated as dividends paid divided by funds flow. We use payout ratio to assess the adequacy of retained funds flow to finance capital programs.
Oil and Gas Information Advisory
Barrels of oil equivalent ("boe") may be misleading, particularly if used in isolation. A boe conversion ratio of six thousand cubic feet of natural gas to one barrel of crude oil is based on an energy equivalency conversion method primarily applicable at the burner tip and does not represent a value equivalency at the wellhead. Given that the value ratio based on the current price of crude oil as compared to natural gas is significantly different from the energy equivalency conversion ratio of 6:1, utilizing a conversion on a 6:1 basis is misleading as an indication of value.
Forward-Looking Statements
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
(CAD millions, unaudited) December 31, 2011 December 31, 2010
Assets
Current
Accounts receivable $ 486 $ 386
Other 104 87
Risk management 39 23
629 496
Non-current
Deferred funding assets 596 678
Exploration and evaluation
assets 418 128
Property, plant and equipment 11,893 11,218
Goodwill 2,020 2,020
Risk management 28 3
14,955 14,047
Total assets $ 15,584 $ 14,543
Liabilities and Shareholders' Equity
Current
Accounts payable and accrued
liabilities $ 1,108 $ 910
Dividends payable 127 41
Convertible debentures - 255
Risk management 114 85
1,349 1,291
Non-current
Long-term debt 3,219 2,496
Decommissioning liability 607 648
Risk management 46 67
Deferred tax liability 1,287 1,452
Other non-current liabilities 9 29
6,517 5,983
Shareholders' equity
Shareholders' capital 8,840 -
Unitholders' capital - 9,170
Other reserves 95 -
Retained earnings (deficit) 132 (610)
9,067 8,560
Total liabilities and shareholders'
equity $ 15,584 $ 14,543
Penn West Petroleum Ltd.
Consolidated Statements of Income
Three months ended Year ended
December 31 December 31
(CAD millions, except per
share amounts, unaudited) 2011 2010 2011 2010
Oil and natural
gas sales $ 992 $ 805 $ 3,667 $ 3,054
Royalties (179) (139) (661) (545)
813 666 3,006 2,509
Risk management
gain (loss)
Realized (13) (23) (63) (20)
Unrealized (253) (87) 8 23
547 556 2,951 2,512
Expenses
Operating 271 243 1,036 944
Transportation 7 8 29 33
General and
administrative 30 41 142 145
Share-based
compensation
expense 68 82 84 159
Depletion and
depreciation 308 294 1,158 1,169
Gain on
dispositions (21) - (172) (1,082)
Exploration and
evaluation expense 10 - 15 1
Unrealized risk
management gain (23) (12) (25) (2)
Unrealized foreign
exchange loss
(gain) (53) (55) 38 (82)
Financing 48 43 190 174
Accretion 12 14 45 44
657 658 2,540 1,503
Income (loss) before
taxes (110) (102) 411 1,009
Deferred tax recovery (48) (65) (227) (101)
Net and comprehensive
income (loss) $ (62) $ (37) $ 638 $ 1,110
Net income (loss) per
share
Basic $ (0.13) $ (0.08) $ 1.37 $ 2.51
Diluted $ (0.13) $ (0.08) $ 1.36 $ 2.48
Weighted average shares
outstanding (millions)
Basic 471.1 457.0 467.2 441.8
Diluted 471.2 463.8 467.4 451.6
Penn West Petroleum Ltd.
Consolidated Statements of Cash Flows
Three months ended Year ended
December 31 December 31
(CAD millions,
unaudited) 2011 2010 2011 2010
Operating activities
Net income (loss) $ (62) $ (37) $ 638 $ 1,110
Depletion and
depreciation 308 294 1,158 1,169
Gain on
dispositions (21) - (172) (1,082)
Exploration and
evaluation
expense 10 - 15 1
Accretion 12 14 45 44
Deferred tax
recovery (48) (65) (227) (101)
Share-based
compensation
expense 61 79 75 151
Unrealized risk
management loss
(gain) 230 75 (33) (25)
Unrealized
foreign exchange
loss (gain) (53) (55) 38 (82)
Decommissioning
expenditures (36) (15) (81) (53)
Change in
non-cash working
capital 83 13 (49) 85
484 303 1,407 1,217
Investing activities
Capital
expenditures (594) (400) (1,846) (1,187)
Acquisitions (66) (73) (138) (552)
Proceeds from
dispositions 77 4 404 1,148
Business
combinations - (85) (166) (85)
Change in
non-cash working
capital 56 9 113 155
(527) (545) (1,633) (521)
Financing activities
Increase
(decrease) in
bank loan 230 134 475 (1,101)
Proceeds from
issuance of notes 137 156 212 460
Repayment of
acquired credit
facilities - (21) (39) (21)
Issue of equity 1 73 161 557
Dividends and
distributions
paid (101) (100) (328) (591)
Settlement of
convertible
debentures (224) - (255) -
43 242 226 (696)
Change in cash - - - -
Cash, beginning of
period - - - -
Cash, end of period $ - $ - $ - $ -
Penn West Petroleum Ltd.
Statements of Changes in Shareholders' Equity
(CAD millions, Shareholders' Other Retained
unaudited) Capital Reserves Earnings Total
Balance at January
1, 2011 $ 9,170 $ - $ (610) $ 8,560
Elimination of
deficit (610) - 610 -
Net and
comprehensive
income - - 638 638
Implementation of
Option Plan and
CSRIP - 81 - 81
Share-based
compensation
expense - 41 - 41
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
Unitholders' Other
(CAD millions, unaudited) Capital Reserves Deficit Total
Balance at January 1, 2010 $ 8,451 $ - $ (1,034) $ 7,417
Net and comprehensive
income - - 1,110 1,110
Exercise of trust unit
rights 114 - - 114
Issued to employee trust
unit savings plan 42 - - 42
Issued to distribution
reinvestment plan 117 - - 117
Issued to settle
convertible debentures 18 - - 18
Issued on trust unit
placement 428 - - 428
Distributions declared - - (686) (686)
Balance at December 31,
2010 $ 9,170 $ - $ (610) $ 8,560
MANAGEMENT COMMENTARY
For the three months and year ended December 31, 2011
All dollar amounts contained in this Management Commentary are expressed in millions of Canadian dollars unless noted otherwise.
Please refer to our disclaimer on forward-looking statements at the end of 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.
On January 1, 2011, we completed our plan of arrangement under which Penn West Petroleum Ltd. ("Penn West", "We", "Us", "Our" or the "Company") converted from an income trust to a corporation, operating under the trade name of Penn West Exploration. Prior to this date, our consolidated financial results were presented as an income trust, Penn West's former legal structure, as at and for the year ended December 31, 2010.
In the first quarter of 2011, we completed our change to International Financial Reporting Standards ("IFRS") from Canadian Generally Accepted Accounting Principles ("previous GAAP"). Our previously reported consolidated financial statements were adjusted to be in compliance with IFRS on January 1, 2010 (the "date of transition"). Previously reported results and balances subsequent to the date of transition have been revised to comply with IFRS.
Non-GAAP measures including funds flow, funds flow per share-basic, funds flow per share-diluted, netback, return on equity and return on capital included in this Management Commentary are not defined nor have a standardized meaning prescribed by IFRS or previous GAAP; accordingly, they may not be comparable to similar measures provided by other issuers. Funds flow is cash flow from operating activities before changes in non-cash working capital and 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 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. Return on equity is the rate of return calculated by comparing net income to shareholders' equity. Return on capital is calculated using net income and financing charges compared to shareholders' equity and long-term debt and is used to assess how well Penn West utilizes the capital invested into the company.
Calculation of Funds Flow
Three months ended Year ended
December 31 December 31
(millions, except per share
amounts) 2011 2010 2011 2010
Cash flow from operating
activities $ 484 $ 303 $ 1,407 $ 1,217
Increase (decrease) in
non-cash working capital (83) (13) 49 (85)
Decommissioning expenditures 36 15 81 53
Funds flow $ 437 $ 305 $ 1,537 $ 1,185
Basic per share $ 0.93 $ 0.67 $ 3.29 $ 2.68
Diluted per share $ 0.93 $ 0.66 $ 3.29 $ 2.65
Annual Financial Summary
Year ended December 31
(millions, except per share amounts) 2011 2010 (1) 2009 (1)
Gross revenues (2) $ 3,604 $ 3,034 $ 3,203
Funds flow 1,537 1,185 1,493
Basic per share 3.29 2.68 3.62
Diluted per share 3.29 2.65 3.60
Net income (loss) 638 1,110 (144)
Basic per share 1.37 2.51 (0.35)
Diluted per share 1.36 2.48 (0.35)
Capital expenditures, net (3) 1,580 (119) 319
Long-term debt at year-end 3,219 2,496 3,219
Convertible debentures - 255 273
Dividends/ distributions paid (4) 420 708 910
Total assets $ 15,584 $ 14,543 $ 13,876
(1) Comparative 2010 figures are presented under IFRS. Comparative 2009 figures are presented under previous GAAP.
(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.
2011 Highlights
- Funds flow for 2011 increased 30 percent to $1,537 million compared to $1,185 million for 2010. The increase was due to higher revenues as a result of higher liquids production as a percentage of total production and stronger crude oil prices.
- Net income was $638 million in 2011 compared to $1,110 million in 2010. Prior year figures include a $572 million after-tax gain on the formation of the Peace River Oil Partnership and a $368 million gain on the formation of the Cordova Joint Venture.
- Annual 2011 production averaged 163,094 boe per day, in line with our previous annual guidance of 162,000 to 164,000 boe per day.
- Capital expenditures totalled $1,580 million, net of joint venture carried capital and proceeds on net asset dispositions of $266 million. To-date in 2012, Penn West has closed net dispositions of approximately $340 million.
- Netbacks were $30.95 per boe compared to $25.07 per boe in 2010, due primarily to higher liquid prices.
Fourth Quarter 2011 Highlights
- Funds flow for the fourth quarter increased by 43 percent to $437 million ($0.93 per share-basic) compared to $305 million ($0.67 per share-basic) in the fourth quarter of 2010. The increase was mainly due to a higher weighting of our light-oil production and higher crude oil prices.
- Net loss was $62 million compared to a net loss of $37 million in the fourth quarter of 2010. The change was primarily due to unrealized risk management losses.
- Production averaged 168,801 boe per day and was weighted 64 percent to liquids and 36 percent to natural gas compared to 166,148 boe per day with 63 percent liquids and 37 percent natural gas in the fourth quarter of 2010.
- Average oil and liquids production was approximately 108,000 barrels per day in the fourth quarter of 2011, an increase of seven percent over the third quarter of 2011.
- Capital expenditures, net of joint venture carried capital and including net property dispositions, totalled $583 million compared to $469 million in the fourth quarter of 2010.
- Netbacks were $32.78 per boe in the fourth quarter of 2011 compared to $25.34 per boe in the fourth quarter of 2010. The increase resulted primarily from higher oil prices.
Quarterly Financial Summary
(millions, except per share and production amounts) (unaudited)
Dec. 31 Sep. 30 June 30 Mar. 31 Dec. 31
Three months ended 2011 2011 2011 2011 2010
Gross revenues (1) $ 979 $ 861 $ 920 $ 844 $ 782
Funds flow 437 348 396 356 305
Basic per
share 0.93 0.74 0.85 0.77 0.67
Diluted
per share 0.93 0.74 0.85 0.77 0.66
Net income (loss) (62) 138 271 291 (37)
Basic per
share (0.13) 0.29 0.58 0.63 (0.08)
Diluted
per share (0.13) 0.29 0.58 0.63 (0.08)
Dividends declared 127 127 127 125 123
Per share $ 0.27 $ 0.27 $ 0.27 $ 0.27 $ 0.27 $
Production
Liquids (bbls/d)
(2) 108,071 101,392 98,998 104,349 105,296
Natural gas
(mmcf/d) 364 360 343 371 365
Total (boe/d) 168,801 161,323 156,107 166,135 166,148
Table continued below
Sep. 30 June 30 Mar. 31
Three months ended 2010 2010 2010
Gross revenues (1) $ 728 $ 718 $ 806
Funds flow 267 269 344
Basic per
share 0.59 0.62 0.81
Diluted
per share 0.58 0.61 0.81
Net income (loss) 304 745 98
Basic per
share 0.67 1.72 0.23
Diluted
per share 0.66 1.69 0.23
Dividends declared 177 196 190
Per share $ 0.39 $ 0.45 $ 0.45
Production
Liquids (bbls/d)
(2) 98,380 95,777 96,317
Natural gas
(mmcf/d) 394 408 410
Total (boe/d) 164,087 163,700 164,587
(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 program on appraisal activities across our light-oil plays in the Cardium, Carbonates, Spearfish and Viking where we have significant land and infrastructure positions. In 2011, we concentrated on moving these projects from the resource appraisal phase into full-scale development. In 2012, our focus remains on these key light-oil projects with a further shift toward full-scale development across portions of our positions. The application of horizontal multi-stage drilling technologies continues to be a key component of our success along with continuous operations and the use of pad drilling techniques to drive improved capital efficiencies. In 2012, we plan to continue the appraisal activities within the Peace River Oil Partnership and the Cordova Joint Venture with our partners. Further appraisal of our extended portfolio of light-oil and liquids-rich gas plays will continue at a less aggressive pace than in 2010 and 2011. Our unique ownership of light-oil and liquids-rich resources combined with successful resource appraisal over the past several years and our increasing expertise in new drilling and completions technologies provides us significant opportunities for large-scale oil development in a politically stable environment.
Business Environment
Crude oil markets were volatile in 2011 due to a number of factors. Supply concerns resulting from social unrest in the Middle East and North Africa led to a rise in crude oil prices in the first half of the year. The loss of crude oil exports from Libya led to prices peaking early in the second quarter. In the second half of 2011, exports resumed from Libya at a faster than expected rate resulting in lower crude oil prices. European sovereign debt concerns reduced confidence in the outlook for global economic growth thus also exerted downward pressure on crude oil prices. Since the latter part of 2011, crude oil prices have recovered to above US$95 WTI as the market fundamentals re-balanced. As we enter 2012, the European Union continues to address its debt issues; however, it is not clear when significant issues will be resolved. Analysts are currently forecasting a modest level of global GDP growth in 2012 which is expected to result in incremental demand for crude oil. Crude oil prices have also strengthened to date in 2012 due to tightening unutilized OPEC capacity and geo-political tensions in certain parts of the world including in Iran where economic sanctions on Iran's oil trade could result in future oil supply volatility.
Historically, WTI has traded at a premium to Brent however in 2011 WTI traded at a significant discount to Brent and other world benchmark crudes. This spread peaked at US$27 per barrel during 2011, but has recently settled at approximately US$20 per barrel. A number of factors contributed to this spread, notably; WTI is priced at Cushing, Oklahoma thus is a "land-locked" crude that does not fully participate in price increases in comparison to crude oil that has ocean access; the loss of Libyan exports earlier in 2011 caused European buyers to place a premium on other streams such as Brent; inventory levels at Cushing rose to high levels; and, North Sea production problems further contributed to premium Brent pricing. In order for this price differential to fully reverse, additional transportation between Cushing and the Gulf Coast is believed to be required. Currently, both TransCanada and Enbridge have pipeline projects that if approved, will enable Canadian crudes to be transported to the Gulf Coast where they will have greater access to world prices. In January 2012, the US government rejected TransCanada's permit for the Keystone XL pipeline project, however, TransCanada has the option to reapply for a permit in the future. We have made commitments that will allow us to participate in one of these development projects and we continue to monitor the progress and assess the merits of other projects.
In February 2012, differentials for Canadian oil to WTI have widened compared to historical levels. Lower refinery runs due to earlier than normal turnarounds and the need to work down high gasoline inventory levels have recently softened demand for Canadian crudes. We expect these differentials will normalize as refineries come back on-line and as inventory levels re-balance.
Despite 2011 increases in demand in the industrial and power generation sectors, North America natural gas markets continue to be over-supplied. The drilling activities in "liquids-rich" shale gas plays remain robust resulting in increasing natural gas production despite weak natural gas pricing. The combination of increased supply and a mild 2011 winter to date has led to lower heating demand and record levels of inventory. Over the next several years, North American access to international gas markets through the development of LNG infrastructure appears to be an important part of rebalancing North American supply and demand.
Crude Oil
In 2011, WTI crude oil prices averaged US$95.14 per barrel compared to US$79.55 per barrel in 2010. During the fourth quarter of 2011, crude oil prices averaged WTI US$94.02 per barrel compared to WTI US$89.81 per barrel in the third quarter of 2011 and WTI US$85.18 per barrel in the fourth quarter of 2010. Over the past year, Canadian producers experienced delays delivering their production to market due to increasing supply and a number of pipeline interruptions. Some transportation issues continue in 2012 due to increased repair and maintenance programs and reduced capacity on some lines which have encountered operational issues. As an alternative, the use of rail transportation has increased to address congestion. In the future, the benefits of increased maintenance schedules and various expansion projects are expected to minimize disruptions.
Penn West's average crude oil price for 2011 before the impact of the realized portion of risk management was $83.22 per barrel. Currently Penn West has 60,000 barrels per day of its 2012 crude oil production hedged between US$85.53 and US$101.16 per barrel and 20,000 barrels per day of its forecast 2013 production hedged between US$90.00 and US$106.31 per barrel.
Natural Gas
In 2011, the AECO Monthly Index averaged $3.67 per mcf compared to $4.12 per mcf in 2010. During the fourth quarter of 2011, the AECO Monthly Index averaged $3.47 per mcf compared to $3.72 per mcf in the third quarter of 2011 and $3.58 per mcf in the fourth quarter of 2010. The continued drilling activity in liquids-rich shale gas plays in the U.S. is reducing the demand for Canadian gas exports. Currently, Western Canadian gas producers face two specific challenges compared to their U.S. competitors. Firstly, certain Western Canadian gas streams are drier than many of the U.S. shale gas plays thus price realizations are lower due to lower liquids content, and secondly, the longer distance to end markets means that Western Canadian gas producers incur higher transportation costs. Current forecasts are that at current drilling activity levels, natural gas liquids production will eventually over supply North American markets resulting in downward pressure on prices and will suppress the value discrepancy between wet and dry gas plays. Many analysts believe the solution for Western Canadian gas is to build the infrastructure capable of providing access to higher netback markets outside of North America, such as Asia.
Penn West's corporate average natural gas price for 2011 before the impact of the realized portion of risk management was $3.78 per mcf. Penn West currently has 50,000 mcf per day of natural gas production hedged for 2012 at an average price of $4.30 per mcf.
Performance Indicators
Our management and Board of Directors monitor our performance based upon a number of qualitative and quantitative factors including:
- Finding and development ("F&D") costs - We use these metrics to assess the continuing economic viability and the relative development stage of our resource plays.
- Base operations - This includes our production performance and execution of our operational, health, safety, environmental and regulatory programs.
- Shareholder value measures - This includes key enterprise value metrics such as funds flow per share and dividends per share.
- Financial, business and strategic considerations - This includes the management of our asset portfolio, balance sheet stewardship, financial stewardship and the overall goal of creating competitive return on investment for our shareholders.
Finding and Development costs
Year ended December 31
2011 2010 2009 3-Year average
Adjusted F&D
costs including
future
development
costs ("FDC")
(1)
F&D costs
per boe -
proved
plus
probable $ 22.64 $ 21.97 $ 15.18 $ 20.97
F&D costs
per boe -
proved $ 29.71 $ 23.56 $ 15.63 $ 24.70
Excluding FDC
(2)
F&D costs
per boe -
proved
plus
probable $ 15.07 $ 18.90 $ 13.75 $ 15.81
F&D costs
per boe -
proved $ 23.55 $ 21.50 $ 16.10 $ 21.11
Including FDC
(3)
F&D costs
per boe -
proved
plus
probable $ 26.79 $ 26.73 $ 16.12 $ 24.51
F&D costs
per boe -
proved $ 37.05 $ 28.01 $ 16.19 $ 29.17
(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 and excludes land acquisition costs.
(2) The calculation of F&D excludes the change in FDC and excludes the
effects of acquisitions and dispositions.
(3) The calculation of F&D includes the change in FDC and excludes the
effects of acquisitions and dispositions.
In 2011, we increased our capital program as we completed our transition to an E&P corporation and continued to focus on our portfolio of light-oil plays. Our successful drilling program in 2011 resulted in an increase in liquids reserves which led to an increase in total reserves. On a proved basis, our reserves are weighted 74 percent to crude oil and liquids (2010 - 70 percent). On a proved plus probable basis our reserves are weighted 71 percent to crude oil and liquids (2010 - 69 percent) and 29 percent to natural gas (2010 - 31 percent).
Capital expenditures for 2011 have been reduced by $107 million related to joint venture carried capital (2010 -$17 million). We use Adjusted F&D to assess the economic viability and the stage of development of our resource plays. F&D costs are calculated in accordance with NI 51-101, which include the change in FDC, on a proved and proved plus probable basis. For comparative purposes we also disclose F&D costs excluding FDC.
The aggregate of the exploration and development costs incurred in the most recent financial year and the change during that year in estimated future development costs generally will not reflect total finding and development costs related to reserves additions for that year.
Base operations
In 2011, we moved toward full-scale development on many of our light-oil plays. During the second quarter of 2011, severe flooding in Saskatchewan and Manitoba and wild fires in Alberta caused temporary operating interruptions which we overcame during the third quarter. We ended 2011 with significant operational momentum and have continued to build on this early in 2012.
Shareholder Value Measures
Year ended December 31
2011 2010 (1) 2009 (1)
Funds flow per share $ 3.29 $ 2.68 $ 3.62
Dividends/ distributions paid
per share $ 0.90 $ 1.62 $ 2.23
Ratio of year-end total
long-term debt to annual funds
flow 2.1:1 2.1:1 2.2:1
(1) Comparative 2010 figures are presented under IFRS. Comparative 2009 figures are presented under previous GAAP.
In April 2011, we began paying a quarterly dividend of $0.27 per share as a corporation. Our last monthly distribution payment of $0.09 per unit as a Trust was declared in December 2010 and paid in January 2011. Currently, our business strategy is to provide shareholder return through a combination of oil oriented growth and yield.
Our total long-term debt to annual funds flow ratio has remained consistent over the last three years. As we look forward, we aim to grow our funds flow by oil and liquids growth relative to both our long-term debt and dividend payout levels.
Financial, business and strategic considerations
Year ended December 31
2011 2010 (1) 2009 (1)
Return on capital (2) 7% 11% -
Return on equity (3) 7% 13% (2)%
Total assets (millions) $ 15,584 $ 14,543 $ 13,876
(1) Comparative 2010 figures are presented under IFRS. Comparative 2009 figures are presented under previous GAAP.
(2) Net income before financing charges divided by average shareholders' equity and average total debt.
(3) Net income divided by average shareholders' equity.
The return on capital and return on equity ratios in 2011 decreased in comparison to 2010 as a result of lower net income mainly due to an increase in unrealized risk management losses and a decline in gains on dispositions, both non-cash items. In 2010, we recorded significant gains on dispositions as a result of entering the Peace River Oil Partnership transaction and the Cordova Joint Venture.
RESULTS OF OPERATIONS
Production
Three months ended Year ended
December 31 December 31
% %
Daily production 2011 2010 change 2011 2010 change
Light oil and NGL (bbls/d) 90,185 88,447 2 85,316 80,706 6
Heavy oil (bbls/d) 17,886 16,849 6 17,892 18,260 (2)
Natural gas (mmcf/d) 364 365 - 359 394 (9)
Total production (boe/d) 168,801 166,148 2 163,094 164,633 (1)
We completed a successful capital program in the second half of 2011. We gained momentum in the third quarter after the fires and floods reaching our full operating capacity in the fourth quarter. Average oil and liquids production was approximately 108,000 barrels per day in the fourth quarter of 2011, an increase of seven percent over the third quarter of 2011. To date in 2012, we have closed property dispositions for proceeds of approximately $340 million.
When economic to do so, we strive to maintain a strategic mix of liquids and natural gas production in order to reduce exposure to price volatility that can affect a single commodity. 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 toward oil projects.
Average Sales Prices
Three months ended Year ended
December 31 December 31
% %
2011 2010 change 2011 2010 change
Light oil and
liquids (per bbl) $ 88.76 $ 71.05 25 $ 86.19 $ 69.29 24
Risk management loss
(per bbl) (1) (1.58) (4.12) (62) (2.03) (2.72) (25)
Light oil and
liquids net (per
bbl) 87.18 66.93 30 84.16 66.57 26
Heavy oil (per bbl) 76.88 61.87 24 69.07 60.55 14
Natural gas (per
mcf) 3.47 3.79 (8) 3.78 4.20 (10)
Risk management gain
(per mcf) (1) - 0.31 (100) - 0.42 (100)
Natural gas net (per
mcf) 3.47 4.10 (15) 3.78 4.62 (18)
Weighted average
(per boe) 63.05 52.43 20 60.99 50.74 20
Risk management loss
(per boe) (1) (0.84) (1.51) (44) (1.06) (0.34) 100
Weighted average net
(per boe) $ 62.21 $ 50.92 22 $ 59.93 $ 50.40 19
(1) Gross revenues include realized gains and losses on commodity
contracts.
Netbacks
Three months ended Year ended
December 31 December 31
% %
2011 2010 change 2011 2010 change
Light oil and NGL (1)
Production (bbls/day) 90,185 88,447 2 85,316 80,706 6
Operating netback ($/bbl):
Sales price $ 88.76 $ 71.05 25 $ 86.19 $ 69.29 24
Risk management loss (2) (1.58) (4.12) (62) (2.03) (2.72) (25)
Royalties (16.94) (13.79) 23 (16.83) (13.73) 23
Operating costs (20.75) (18.83) 10 (21.05) (19.83) 6
Netback $ 49.49 $ 34.31 44 $ 46.28 $ 33.01 40
Conventional heavy oil
Production (bbls/day) 17,886 16,849 6 17,892 18,260 (2)
Operating netback ($/bbl):
Sales price $ 76.88 $ 61.87 24 $ 69.07 $ 60.55 14
Royalties (10.82) (8.61) 26 (10.01) (8.73) 15
Operating costs (17.42) (17.28) 1 (17.53) (17.14) 2
Transportation (0.07) (0.11) (36) (0.08) (0.09) (11)
Netback $ 48.57 $ 35.87 35 $ 41.45 $ 34.59 20
Total liquids
Production (bbls/day) 108,071 105,296 3 103,208 98,966 4
Operating netback ($/bbl):
Sales price $ 86.80 $ 69.58 25 $ 83.22 $ 67.68 23
Risk management loss (2) (1.32) (3.46) (62) (1.68) (2.22) (24)
Royalties (15.93) (12.96) 23 (15.64) (12.81) 22
Operating costs (20.20) (18.58) 9 (20.44) (19.33) 6
Transportation (0.01) (0.02) (50) (0.01) (0.02) (50)
Netback $ 49.34 $ 34.56 43 $ 45.45 $ 33.30 36
Natural gas
Production (mmcf/day) 364 365 - 359 394 (9)
Operating netback ($/mcf):
Sales price $ 3.47 $ 3.79 (8) $ 3.78 $ 4.20 (10)
Risk management gain (2) - 0.31 (100) - 0.42 (100)
Royalties (0.59) (0.42) 40 (0.54) (0.58) (7)
Operating costs (2.11) (1.88) 12 (2.03) (1.71) 19
Transportation (0.22) (0.23) (4) (0.22) (0.22) -
Netback $ 0.55 $ 1.57 (65) $ 0.99 $ 2.11 (53)
Combined totals
Production (boe/day) 168,801 166,148 2 163,094 164,633 (1)
Operating netback ($/boe):
Sales price $ 63.05 $ 52.43 20 $ 60.99 $ 50.74 20
Risk management loss (2) (0.84) (1.51) (44) (1.06) (0.34) 100
Royalties (11.47) (9.14) 25 (11.09) (9.07) 22
Operating costs (17.48) (15.92) 10 (17.40) (15.71) 11
Transportation (0.48) (0.52) (8) (0.49) (0.55) (11)
Netback $ 32.78 $ 25.34 29 $ 30.95 $ 25.07 23
(1) Excluded from the netback calculation is $37 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) Gross revenues include realized gains and losses on commodity
contracts.
Production Revenues
Revenues from the sale of oil, NGL and natural gas consisted of the following:
Three months ended Year ended
December 31 December 31
% %
(millions) 2011 2010 change 2011 2010 change
Light oil and NGL $ 736 $ 548 34 $ 2,657 $ 1,965 35
Heavy oil 127 96 32 452 405 12
Natural gas 116 138 (16) 495 664 (25)
Gross revenues (1) $ 979 $ 782 25 $ 3,604 $ 3,034 19
(1) Gross revenues include realized gains and losses on commodity
contracts.
Our successful drilling program has resulted in additional light-oil production and an increase in light-oil revenue. Crude oil prices have increased on a year-over-year basis which has led to increases in both light and heavy oil revenues. Natural gas prices were lower in 2011 compared to 2010 resulting in a decline in revenues. Asset dispositions and a capital program concentrated on our light-oil properties led to the decline in natural gas production.
Reconciliation of Increase in Production Revenues
(millions)
Gross revenues - January 1 - December 31, 2010 $ 3,034
Increase in light oil and NGL production 112
Increase in light oil and NGL prices (including realized risk
management) 580
Decrease in heavy oil production (8)
Increase in heavy oil prices 55
Decrease in natural gas production (58)
Decrease in natural gas prices (111)
Gross revenues - January 1 - December 31, 2011 $ 3,604
Royalties
Three months ended Year ended
December 31 December 31
% %
2011 2010 change 2011 2010 change
Royalties (millions) $ 179 $ 139 29 $ 661 $ 545 21
Average royalty rate (1) 18% 17% 1 18% 18% -
$/boe $ 11.47 $ 9.14 25 $ 11.09 $ 9.07 22
(1) Excludes effects of risk management activities.
An increase in crude oil prices has led to an increase in royalties; however, royalty rates have remained comparable year-over-year as lower royalty rates on new wells under the various royalty incentive programs have partially offset higher royalty rates on base production.
Expenses
Three months ended Year ended
December 31 December 31
% %
(millions) 2011 2010 change 2011 2010 change
Operating $ 271 $ 243 12 $ 1,036 $ 944 10
Transportation 7 8 (13) 29 33 (12)
Financing 48 43 12 190 174 9
Share-based compensation $ 68 $ 82 (17) $ 84 $ 159 (47)
Three months ended Year ended
December 31 December 31
% %
(per boe) 2011 2010 change 2011 2010 change
Operating $ 17.48 $ 15.92 10 $ 17.40 $ 15.71 11
Transportation 0.48 0.52 (8) 0.49 0.55 (11)
Financing 3.16 2.78 14 3.20 2.89 11
Share-based compensation $ 4.32 $ 5.38 (20) $ 1.41 $ 2.65 (47)
Operating
During the fourth quarter of 2011, operating costs were affected by higher power costs and increased trucking and fuel costs. On a year-to-date basis, the temporary interruptions experienced in the second quarter of 2011 from the wild fires in Slave Lake and flooding in Manitoba and Saskatchewan led to increased workover and maintenance activity in the second half of 2011. These events also contributed to lower average production volumes which led to an increase on a per boe basis.
Operating costs in the fourth quarter of 2011 include a realized gain on electricity contracts of $3 million (2010 - $5 million loss) and for 2011 include a realized gain on electricity contracts of $11 million (2010 - $14 million loss). For 2011 the average Alberta pool price was $76.21 per MWh. We have contracts in place that fix the price on approximately 75 percent of our Alberta electricity consumption for 2012 at $53.65 per MWh and additionally in 2013 and 2014 we have approximately 50 percent of our Alberta electricity consumption at $55.20 per MWh and $58.50 per MWh, respectively.
Financing
The Company has an unsecured, revolving syndicated bank facility with an aggregate borrowing limit of $2.75 billion. The facility expires on June 26, 2015 and is extendible. The credit facility contains provisions for stamping fees on bankers' acceptances and LIBOR loans and standby fees on unutilized credit lines that vary depending on certain consolidated financial ratios. At December 31, 2011, approximately $1.2 billion was drawn under this facility.
As at December 31, 2011, the Company had $2.0 billion (2010 - $1.7 billion) of senior unsecured notes outstanding with a weighted average interest rate, including the effects of interest rate swaps, of approximately 5.9 percent (2010 - 5.7 percent) and a weighted average remaining term of 6.5 years (2010 - 7.2 years), as follows:
Weighted
Average average
interest remaining
Issue date Amount (millions) Term rate term
May 31,
2007 Notes 2007 US$475 8 - 15 years 5.80% 5.5 years
May 29,
2008 Notes 2008 US$480, CAD$30 8 - 12 years 6.25% 6.0 years
July 31, 6.95%
UK Notes 2008 GBP57 10 years (1) 6.6 years
May 5, US$154, GBP20, 8.85%
2009 Notes 2009 EUR10, CAD$5 5 - 10 years (2) 5.0 years
March 16,
2010 Q1 Notes 2010 US$250, CAD$50 5 - 15 years 5.47% 6.8 years
December
2, 2010,
January 4,
2010 Q4 Notes 2011 US$170, CAD$60 5 - 15 years 5.00% 9.7 years
November
2011 Notes 30, 2011 US$105, CAD$30 5 - 10 years 4.49% 8.1 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) 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.
In November 2011, we closed a private placement of senior unsecured notes (the "2011 Notes") with aggregate principal amounts of approximately $135 million. The 2011 Notes had an original weighted average term of approximately 8.1 years and an average fixed interest rate of approximately 4.49 percent. The Company used the proceeds of the issue to repay advances on its syndicated bank facility.
In January 2011, the Company completed the closing of a private placement of senior unsecured notes, (the "2010 Q4 Notes"), with an aggregate principal amount of approximately US$230 million. The 2010 Q4 Notes had an original weighted average term of 10.8 years and bear a weighted average fixed interest rate of approximately 5.0 percent. The Company used the proceeds of the issue to repay advances on its syndicated bank facility.
Financing charges in 2011 are higher than in 2010 since a higher percentage of our debt capital is held in longer-term, fixed rate, senior unsecured notes. The cost of borrowing under the current and previous bank facility increased compared to the facility in place during the first quarter of 2010 due to increased rates in the bank market. While the Company's senior unsecured notes contain higher interest rates than the syndicated bank facilities held in short-term money market instruments, we believe the long-term 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 bank debt are subject to fluctuations in short-term money market rates as advances on the bank facility are generally made under short-term instruments. As at December 31, 2011, 19 percent (2010 - none) of our long-term debt instruments were exposed to changes in short-term interest rates.
At December 31, 2011, 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.
Realized gains and losses on the interest rate swaps are recorded as financing costs. For the fourth quarter of 2011 an expense of $3 million (2010 - $4 million) and for 2011 an expense of $12 million (2010 - $21 million) were recognized in financing to reflect that the floating interest rate was lower than the fixed interest rate transacted under our financial instruments.
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") and our Long-Term Retention and Incentive Plan ("LTRIP").
Effective January 1, 2011, we implemented the Option Plan and amended our Trust Unit Rights Incentive Plan ("TURIP") which became the CSRIP. Pursuant to our plan to convert from a trust to a corporation, trust unit right 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. Those trust unit right 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" issued under the CSRIP) for each trust unit right. Trust unit rights issued under the former TURIP received liability treatment for accounting purposes throughout 2010 as we operated in an income trust structure. After January 1, 2011, all grants will be under the Option Plan.
The Restricted Options, Share Rights and subsequent grants under the Option Plan receive equity treatment for accounting purposes subsequent to our conversion to a corporation 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 new option grants are calculated using a Black-Scholes option-pricing model and a Binomial Lattice option-pricing model continues to be used to value the Share Rights. 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 trust unit rights 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.
Share-based compensation consisted of the following:
Three months
ended Year ended
December 31 December 31
% %
(millions) 2011 2010 change 2011 2010 change
Options $ 5 $ - 100 $ 18 $ - 100
Restricted Options 5 - 100 22 - 100
Restricted Rights 51 - 100 (29) - (100)
Share Rights - - - 1 - 100
LTRIP 7 3 100 14 8 75
TURIP - 79 (100) - 151 (100)
Expiry of TURIP at Jan. 1,
2011 - - - (196) - (100)
Share Rights at Jan. 1, 2011 - - - 16 - 100
Restricted Options at Jan. 1,
2011 - - - 65 - 100
Restricted Rights liability
at Jan. 1, 2011 - - - 173 - 100
Share-based compensation $ 68 $ 82 (17) $ 84 $ 159 (47)
The share price used in the fair value calculation of the LTRIP liability and Restricted Rights obligation at December 31, 2011 was $20.19 (2010 - $23.84).
General and Administrative Expenses ("G&A")
Three months ended Year ended
December 31 December 31
% %
(millions, except per boe amounts) 2011 2010 change 2011 2010 change
Gross $ 54 $ 62 (13) $ 222 $ 207 7
Per boe 3.47 4.05 (14) 3.72 3.45 8
Net 30 41 (27) 142 145 (2)
Per boe $ 1.88 $ 2.62 (28) $ 2.38 $ 2.41 (1)
Our fourth quarter 2011 net G&A amounts have decreased compared to the prior year primarily due to increased recoveries from our capital program and an increase in office lease recoveries.
For 2011, our staff levels have increased compared to 2010 as a result of our transition to an exploration and production company resulting in higher gross costs.
Depletion, Depreciation and Accretion
Three months ended Year ended
December 31 December 31
(millions, except per % %
boe amounts) 2011 2010 change 2011 2010 change
Depletion and
depreciation ("D&D") $ 308 $ 294 5 $ 1,158 $ 1,169 (1)
D&D expense per boe 19.84 19.17 3 19.45 19.44 -
Accretion of
decommissioning
liability 12 14 (14) 45 44 2
Accretion expense per
boe $ 0.76 $ 0.91 (16) $ 0.76 $ 0.73 4
During the first quarter of 2011, we recorded an impairment reversal of $39 million (2010 - none) to reflect stronger commodity prices resulting in higher forecast cash flows relating to properties in Central Alberta. In the second quarter of 2011, we recorded a $29 million impairment (2010 - $80 million) on certain properties in Central Alberta due to weaker forward commodity prices.
Taxes
Three months ended Year ended
December 31 December 31
(millions) 2011 2010 % change 2011 2010 % change
Deferred tax recovery $ (48) $ (65) (26) $ (227) $ (101) 100
In the fourth quarter of 2011, we recorded a deferred tax recovery primarily due to unrealized risk management losses.
The 2011 deferred tax recovery includes a $304 million recovery related to the tax rate differential on our conversion from a trust to an E&P company. As a corporation, we are subject to income taxes at Canadian corporate tax rates. In the trust structure, under IFRS we were required 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.
We currently have a significant tax pool base. Based on current commodity prices and capital spending plans, we forecast these pools will shelter our taxable income for an extended period.
Tax Pools
As at December 31
(millions) 2011 2010
Undepreciated capital cost (UCC) $ 1,085 $ 1,122
Canadian oil and gas property expense (COGPE) 1,395 1,562
Canadian development expense (CDE) 2,104 1,494
Canadian exploration expense (CEE) 294 305
Non-capital losses 2,966 2,481
Other 31 31
Total $ 7,875 $ 6,995
Tax pool amounts exclude income deferred in operating partnerships of $1,654 million in 2011 (2010 - $920 million).
Foreign Exchange
Three months ended Year ended
December 31 December 31
% %
(millions) 2011 2010 change 2011 2010 change
Unrealized foreign
exchange (gain) loss $ (53) $ (55) (4) $ 38 $ (82) (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 during 2011 were primarily due to the weakening of the Canadian dollar relative to the US dollar.
Funds Flow and Net Income (Loss)
Three months ended Year ended
December 31 December 31
% %
2011 2010 change 2011 2010 change
Funds flow (1)
(millions) $ 437 $ 305 43 $ 1,537 $ 1,185 30
Basic per
share 0.93 0.67 39 3.29 2.68 23
Diluted per
share 0.93 0.66 41 3.29 2.65 24
Net income (loss)
(millions) (62) (37) 68 638 1,110 (43)
Basic per
share (0.13) (0.08) 63 1.37 2.51 (45)
Diluted per
share $ (0.13) $ (0.08) 63 $ 1.36 $ 2.48 (45)
(1) Funds flow is a non-GAAP measure. See "Calculation of Funds Flow" and
"Non-GAAP Measure Advisory".
Funds flow in the fourth quarter of 2011 and for 2011 increased from 2010 primarily due to an increase in our weighting of light-oil production and an increase in crude oil prices.
On a quarterly basis, the increase in net loss in the fourth quarter of 2011 compared to 2010 was primarily due to unrealized risk management losses. For 2011, net income decreased due to significant gains on asset dispositions in 2010, including a $368 million gain on the formation of the Cordova Joint Venture and a $572 million after-tax gain on the formation of the Peace River Oil Partnership.
Capital Expenditures
Three months ended Year ended
(millions) December 31 December 31
2011 2010 2011 2010
Land acquisition and retention $ 9 $ 10 $ 181 $ 102
Drilling and completions 410 263 1,217 800
Facilities and well equipping 197 140 521 281
Geological and geophysical - - 9 10
Corporate 8 4 25 11
Capital expenditures (1) 624 417 1,953 1,204
Joint venture, carried capital (30) (17) (107) (17)
Property acquisitions
(dispositions), net (11) 69 (266) (1,306)
Capital expenditures, net 583 469 1,580 (119)
Business combinations - 139 286 139
Total expenditures $ 583 $ 608 $ 1,866 $ 20
Capital expenditures include costs related to development capital and
(1) Exploration and Evaluation activities.
In 2011, we increased our capital program as we transitioned some of our light-oil plays from the appraisal phase into full-scale development which led to an increase in drilling and completions, facilities and well equipping capital costs.
For the three months ended December 31, 2011, decommissioning liabilities increased $5 million (2010 - $63 million) and for 2011, decreased by $7 million (2010 - $91 million capitalized additions) to reflect net acquisitions and dispositions activity.
Gain on asset dispositions
Three months ended Year ended
December 31 December 31
(millions) 2011 2010 % change 2011 2010 % change
Gain on asset dispositions $ 21 $ - 100 $ 172 $ 1,082 (84)
During 2011, we closed property dispositions which resulted in gains of $172 million recognized in income (2010 - $1,082 million). In June 2010, as a result of forming the Peace River Oil Partnership, we recognized a pre-tax gain of $749 million in income and in September 2010, due to entering the Cordova Joint Venture, we recognized a $368 million gain.
Exploration and evaluation ("E&E") capital expenditures
Three months ended Year ended
December 31 December 31
(millions) 2011 2010 % change 2011 2010 % change
E&E capital
expenditures $ 167 $ 32 100 $ 321 $ 58 100
Included in E&E capital expenditures is the benefit of $92 million of joint venture carried capital in 2011 (2010 - nil). Our E&E capital expenditures increased due to strategic land purchases and exploration and evaluation activities since our conversion to an E&P company. During 2011, we transferred $14 million from E&E into PP&E and we had a non-cash E&E expense of $15 million (2010 - $1 million) related to land expiries and unsuccessful exploration activities.
In 2011, we disposed of E&E assets valued at $2 million (2010 - $61 million) in connection with property dispositions.
Spartan Exploration Ltd. ("Spartan") Business Combination
On June 1, 2011, we closed the corporate acquisition of Spartan, a publicly traded oil and gas exploration company with assets primarily located in the Cardium light-oil resource play in central Alberta. The total cost was $166 million with $286 million recorded to property, plant and equipment.
Goodwill
As at December 31
(millions) 2011 2010
Balance, beginning and end of period $ 2,020 $ 2,020
We recorded goodwill on our acquisitions of Petrofund Energy Trust, Canetic Resources Trust and Vault Energy Trust. We determined there was no goodwill impairment at December 31, 2011.
Environmental and Climate Change
The oil and gas industry has a number of environmental risks and hazards and is subject to regulation by all levels of government. Environmental legislation includes, but is not limited to, operational controls, site restoration requirements and restrictions on emissions of various substances produced in association with oil and natural gas operations. Compliance with such legislation could require additional expenditures and a failure to comply may result in fines and penalties which could, in the aggregate and under certain assumptions, become material.
We are dedicated to reducing the environmental impact from our operations through our environmental programs which include resource conservation, CO2 sequestration, water management and site abandonment/reclamation. Operations are continuously monitored to minimize the environmental impact and sufficient capital is allocated to reclamation and other activities to mitigate the impact on the areas in which we operate.
Liquidity and Capital Resources
Capitalization
As at December 31
2011 2010
(millions) % %
Common shares issued, at market (1) $ 9,517 72 $ 10,959 78
Bank loans and long-term notes 3,219 24 2,496 18
Convertible debentures - - 255 2
Working capital deficiency (2) 554 4 303 2
Total enterprise value $ 13,290 100 $ 14,013 100
The share price at December 31, 2011 was $20.19 (December 31, 2010 -
(1) $23.84).
Excludes the current portion of risk management, convertible
(2) debentures and share-based compensation liability.
For 2011, we declared total dividends of $506 million (2010 - $686 million) and paid total dividends, including amounts funded by the dividend reinvestment plan, of $420 million (2010 - $708 million). We anticipate dividends will continue to be paid on a quarterly basis. On February 15, 2012, our Board of Directors declared a 2012 first quarter dividend of $0.27 per share to be paid on April 13, 2012 to shareholders of record on March 30, 2012. Shareholders are advised that this dividend is designated as an "eligible dividend" for Canadian income tax purposes.
On June 27, 2011, the Company closed the extension of its unsecured, revolving, syndicated bank facility with an aggregate borrowing limit of $2.25 billion and a four-year term. On October 27, 2011, the Company increased the aggregate borrowing limit by $500 million to $2.75 billion using the "accordion" feature in the facility. For further details on our debt instruments, please refer to the "Financing" and "Convertible Debentures" sections of this Management Commentary.
We actively manage our debt portfolio and consider opportunities to reduce or diversify our debt structure. We actively consider 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. These actions and plans 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, 2011, the Company was in compliance with all of these financial covenants which comprise the following:
Limit December 31, 2011
Senior debt to EBITDA Less than 3:1 1.86
Total debt to EBITDA Less than 4:1 1.86
Senior debt to capitalization Less than 50% 26%
Total debt to capitalization Less than 55% 26%
As at December 31, 2011, 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.
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 expenditure requirements. Our dividend level could change based on these and other factors and is subject to the approval of our Board of Directors.
Convertible Debentures
During 2011, $248 million of convertible debentures matured and were settled in cash (2010 - nil), $7 million were redeemed and settled in cash (2010 - nil) and none matured and were settled in shares (2010 - $18 million). Of the $255 million of convertible debentures settled in cash during 2011, $224 million were the series "F" debentures which matured in the fourth quarter of 2011. We now have no convertible debentures outstanding.
Financial Instruments
We had the following financial instruments outstanding as at December 31, 2011. Fair values are determined using external counterparty information which is compared to observable market data. We limit our credit risk by executing counterparty risk procedures which include transacting only with institutions within our credit facility or with high credit ratings and by obtaining financial security in certain circumstances.
Notional Remaining Fair value
volume term Pricing (millions)
Crude oil
US$85.53 to
WTI Collars 60,000 bbls/d Jan/12 - Dec/12 $101.16/bbl $ (103)
US$90.00 to
WTI Collars 5,000 bbls/d Jan/13 - Dec/13 $100.00/bbl (1)
Natural gas
AECO Forwards (1) 52,730 GJ/d Jan/12 - Dec/12 $4.08/GJ 25
Electricity swaps
Alberta Power Pool 45 MW Jan/12 - Dec/12 $53.02/MWh 7
Alberta Power Pool 30 MW Jan/12 - Dec/13 $54.60/MWh 10
Alberta Power Pool 20 MW Jan/13 - Dec/13 $56.10/MWh 2
Alberta Power Pool 50 MW Jan/14 - Dec/14 $58.50/MWh 1
Interest rate swaps
$650 Jan/12 - Jan/14 2.65% (22)
Foreign exchange forwards on revenues
12-month initial 1.022
term US$1,872 Jan/12 - Dec/12 CAD/USD 2
Foreign exchange forwards on senior notes
3 to 15-year initial 1.000
term US$641 2014 - 2022 CAD/USD 20
Cross currency swaps
2.0075
CAD/GBP,
10-year term GBP57 2018 6.95% (26)
1.8051
CAD/GBP,
10-year term GBP20 2019 9.15% (5)
1.5870
CAD/EUR,
10-year term EUR10 2019 9.22% (3)
Total $ (93)
The forward contracts total approximately 50,000 mcf per day with an
(1) average price of $4.30 per mcf.
Subsequent to December 31, 2011, we entered into additional crude oil collars on 15,000 barrels per day in 2013 between US$90.00 and US$108.41 per barrel.
Please refer to our website at http://www.pennwest.com for details of all financial instruments currently outstanding.
Outlook
This outlook section is included to provide shareholders with information about our expectations as at February 15, 2012 for production and capital expenditures for 2012 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".
Our prior forecast was released on November 2, 2011 with our third quarter results and filed on SEDAR at http://www.sedar.com. Production was in-line with previous guidance for 2011 annual and 2011 second half production. Cardium production originally planned for exit 2011 came on-stream in early 2012. Capital expenditures guidance of $1.4 billion to $1.5 billion, net of asset dispositions, was slightly exceeded as we shifted the timing on some of our 2012 projects into the fourth quarter of 2011 to partially mitigate the possibility of an early spring break-up due to unseasonably warm weather.
Our estimated 2012 exploration and development capital program is expected to be in the range of $1.6 billion to $1.7 billion prior to asset dispositions. Our 2012 plan is to continue to focus on light-oil plays and continue to move toward full-scale development at the Cardium, Carbonates, Spearfish and Viking. Based on this level of capital expenditures, we estimate average production to be approximately 174,000 to 178,000 boe per day, prior to the effect of asset dispositions.
Assuming there is no further significant acquisition or disposition activity in 2012, our forecast average production for 2012 is between 168,500 and 172,500 boe per day and our estimated exploration and development capital would be in the range of $1.3 billion to $1.4 billion, in each case after reflecting the impact of net asset dispositions of $340 million to-date in 2012.
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 32 0.07
Liquids production 1,000 bbls/day 22 0.05
Price per mcf of natural gas $0.10 9 0.02
Natural gas production 10 mmcf/day - -
Effective interest rate 1% 7 0.01
Exchange rate ($US per $CAD) $0.01 19 0.04
Contractual Obligations and Commitments
We are committed to certain payments over the next five calendar years as follows:
(millions) 2012 2013 2014 2015 2016 Thereafter
Long-term debt $ - $ 5 $ 61 $ 1,504 $ 221 $ 1,428
Transportation 23 19 12 8 3 -
Transportation ($US) 4 4 37 37 33 231
Power infrastructure 32 15 15 15 15 14
Drilling rigs 26 26 22 16 10 2
Purchase obligations (1) 13 13 11 10 2 5
Interest obligations 161 161 158 127 93 216
Office lease (2) 68 66 60 60 59 479
Decommissioning liability
(3) $ 70 $ 67 $ 64 $ 61 $ 58 $ 287
These amounts represent estimated commitments of $40 million for CO2
purchases and $14 million for processing fees related to our interests
(1) in the Weyburn Unit.
The future office lease commitments above will be reduced by sublease
(2) recoveries totalling $434 million.
These amounts represent the inflated, discounted future reclamation
and abandonment costs that are expected to be incurred over the life
(3) of the properties.
Our syndicated credit facility is due for renewal on June 26, 2015. If we are not successful in renewing or replacing the facility, we could enter other loans including term bank loans or be required to repay all amounts then outstanding on the facility. In addition, we have an aggregate of $2.0 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.
Equity Instruments
Common shares issued:
As at December 31, 2011 471,372,730
Issued on exercise of share rights 143,898
Issued on settlement of restricted rights 6,413
Issued pursuant to dividend reinvestment plan 1,364,540
As at February 15, 2012 472,887,581
Options outstanding:
As at December 31, 2011 7,919,600
Granted 253,600
Forfeited (81,906)
As at February 15, 2012 8,091,294
Share Rights outstanding:
As at December 31, 2011 2,549,112
Exercised (143,898)
Forfeited (42,533)
As at February 15, 2012 2,362,681
Restricted Options outstanding (1):
As at December 31, 2011 17,110,193
Forfeited (3,645,855)
As at February 15, 2012 13,464,338
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"
(1) section of this Management Commentary for further details.
Related-Party Transactions
During 2011, we incurred $1 million (2010 - $2 million) of legal fees from a law firm of which a partner is also a director of Penn West.
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 under the headings "2012 Operations - Oil Development" and "Business Strategy" relating to, among other things, our capital expenditure plans for, and our focus on, our Carbonates, Cardium, Spearfish and Viking light-oil plays; certain disclosures contained under the headings "2012 Operations - Resource Appraisal" and "Business Strategy" relating to, among other things, our continued resource appraisal activities under the Peace River Oil Partnership and the Cordova Joint Venture; certain disclosures contained in the "Letter to our Shareholders" relating to, among other things, long-term natural gas prices, the focus of our 2012 capital budget on light-oil development projects and our belief that liquids production will grow in a meaningful way in North America over the next few years; certain disclosures contained under the heading "Outlook" relating to our estimated 2012 exploration and development capital program, its continued focus on light-oil plays (specifically the Cardium, Carbonates, Spearfish and Viking) and our resulting production estimates for 2012; certain disclosures contained under the headings "Business Environment", "Crude Oil" and "Natural Gas" relating to, among other things, our view of the outlook for crude oil, natural gas liquid and natural gas prices and supply-demand fundamentals for such commodities; our forecast under the heading "Taxes" that, based on current commodity prices and capital spending plans, our tax pool base will shelter our taxable income for an extended period; all matters relating to our dividend policy, including our intention to continue to pay dividends on a quarterly basis, the details of our first quarter dividend payment, and the factors that may affect the amount of dividends that we pay in the future (if any); the ability of our debt and risk management programs to increase the likelihood that we can maintain our financial flexibility to capture opportunities available in the markets in addition to the continuation of our capital and dividend programs and the longer-term execution of our business strategies; and certain disclosures contained under the heading "Sensitivity Analysis" relating to our estimated sensitivities to certain key assumptions on 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; future capital expenditure levels; future crude oil, natural gas liquids and natural gas production levels; drilling results; future exchange rates and interest rates; the amount of future cash dividends that we intend to pay; our ability to obtain equipment in a timely manner to carry out development activities and the costs thereof; our ability to market our oil and natural gas successfully to current and new customers; the impact of increasing competition; our ability to obtain financing on acceptable terms; and our ability to add production and reserves through our development and exploitation activities. In addition, many of the forward-looking statements contained in this document are located proximate to assumptions that are specific to those forward-looking statements, and such assumptions should be taken into account when reading such forward-looking statements: see in particular the assumptions identified under the headings "Outlook" and "Sensitivity Analysis".
Although we believe that the expectations reflected in the forward-looking statements contained in this document, and the assumptions on which such forward-looking statements are made, are reasonable, there can be no assurance that such expectations will prove to be correct. Readers are cautioned not to place undue reliance on forward-looking statements included in this document, as there can be no assurance that the plans, intentions or expectations upon which the forward-looking statements are based will occur. By their nature, forward-looking statements involve numerous assumptions, known and unknown risks and uncertainties that contribute to the possibility that the predictions, forecasts, projections and other forward-looking statements will not occur, which may cause our actual performance and financial results in future periods to differ materially from any estimates or projections of future performance or results expressed or implied by such forward-looking statements. These risks and uncertainties include, among other things: the impact of weather conditions on seasonal demand and ability to execute capital programs; risks inherent in oil and natural gas operations; uncertainties associated with estimating reserves and resources; competition for, among other things, capital, acquisitions of reserves, resources, undeveloped lands and skilled personnel; incorrect assessments of the value of acquisitions, including the completed acquisitions discussed herein; geological, technical, drilling and processing problems; general economic conditions in Canada, the U.S. and globally; industry conditions, including fluctuations in the price of oil and natural gas; royalties payable in respect of our oil and natural gas production and changes thereto; changes in government regulation of the oil and natural gas industry, including environmental regulation; fluctuations in foreign exchange or interest rates; unanticipated operating events 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; uncertainty of obtaining required approvals for acquisitions and mergers; the potential failure of counterparties to honour their contractual obligations; and the other factors described in our public filings (including our Annual Information Form) available in Canada at http://www.sedar.com and in the United States at http://www.sec.gov. Readers are cautioned that this list of risk factors should not be construed as exhaustive.
The forward-looking statements contained in this document speak only as of the date of this document. Except as expressly required by applicable securities laws, we do not undertake any obligation to publicly update or revise any forward-looking statements, whether as a result of new information, future events or otherwise. The forward-looking statements contained in this document are expressly qualified by this cautionary statement.
Additional Information
Additional information relating to Penn West including Penn West's Annual Information Form, is available on SEDAR at http://www.sedar.com.
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 16, 2012.
To listen to the conference call, please call 647-427-7450 or 1-888-231-8191 (North America toll-free). This call will be broadcast live on the Internet and may be accessed directly on the Penn West website at http://www.pennwest.com or at the following URL:
http://event.on24.com/r.htm?e=403564&s=1&k=D7B86CF84A0746967693F547B7A4747C
A digital recording will be available for replay two hours after the call's completion, and will remain available until March 1, 2012 21:59 Mountain Time (23:59 Eastern Time). To listen to the replay, please dial +1-416-849-0833 or 1-855-859-2056 (North America toll-free) and entering Conference ID 50696892, followed by the pound (#) key.
For further information:
PENN WEST EXPLORATION
Penn West Plaza
Suite 200, 207 - 9th Avenue SW
Calgary, Alberta T2P 1K3
Phone: +1-403-777-2500
Fax: +1-403-777-2699
Toll Free: 1-866-693-2707
Website: http://www.pennwest.com
Investor Relations:
Toll Free: 1-888-770-2633
E-mail: investor_relations@pennwest.com
Murray Nunns, President & Chief Executive Officer
Phone: +1-403-218-8939
E-mail: murray.nunns@pennwest.com
Jason Fleury, Senior Manager, Investor Relations
Phone: +1-403-539-6343
E-mail: jason.fleury@pennwest.com
Share this article