CALGARY, Feb. 26 /CNW/ - PENN WEST ENERGY TRUST (TSX - PWT.UN; NYSE - PWE) is pleased to announce its results for the fourth quarter and year ended December 31, 2006.
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Financial Results
- The Petrofund operations and cash flows were reflected from
July 1, 2006 forward.
- Penn West mitigated the recent decline in natural gas prices, as its
risk management program realized $18 million in hedging gains in the
fourth quarter of 2006.
- Cash flow of $303 million ($1.23 per unit, basic) in the fourth
quarter of 2006 was 9 percent lower than cash flow of $333 million
($2.03 per unit, basic) realized in the fourth quarter of 2005, for
the most part due to lower natural gas prices.
- Net income decreased to $123 million ($0.44 per unit, basic) in the
fourth quarter of 2006 from $241 million ($1.48 per unit, basic) in
the fourth quarter of 2005, mainly due to lower natural gas prices
and higher depletion charges as a result of the Petrofund merger.
Operations
- Production averaged 129,915 boe per day in the fourth quarter of 2006
compared to 98,205 boe per day in the same period of 2005 and 129,059
boe per day in the third quarter of 2006.
- Crude oil and NGL production averaged 70,819 barrels per day and
natural gas production averaged 355 mmcf per day in the fourth
quarter of 2006.
- Penn West invested $159 million on capital development and drilled
52 net wells in the fourth quarter with a success rate of 96 percent.
Cash Distributions
- Penn West's Board of Directors recently resolved to keep our
distribution level at $0.34 per unit, per month based on current
forecasts of commodity prices and currently planned 2007 capital
expenditures.
Tax Announcement
- On October 31, 2006, the Government of Canada announced proposed
changes to the taxation of income trusts. Effective in 2011, Penn
West could be, in effect, subject to tax on its distributions at
corporate income tax rates. Draft legislation has been distributed
for comment, the rules related to "undue expansion" were clarified
and hearings of the House of Commons' Finance Committee have
commenced. Under the undue expansion rules, Penn West can grow its
equity by approximately $10 billion without prematurely triggering
the proposed tax. The trust is active, and intends to remain active,
with various parties pursuing a re-evaluation of the tax proposals.
We are also reviewing structural alternatives that could limit the
future effects of the tax proposals on Penn West.
Long-term Project Updates
- During the fourth quarter of 2006, Penn West drilled eight horizontal
wells in its Peace River Oil Sands project. In 2007 to date, Penn
West has drilled 11 horizontal wells and 12 exploration wells. As a
result of positive production and exploration results, the capital
budget for the project in 2007 has been increased to $175 million
from $100 million. The additional capital will accelerate our
exploration program in the Peace River Oil Sands and provide
additional capital for research, development drilling and facilities.
Current production is 3,600 barrels per day with target production of
6,000 - 8,000 barrels per day by the end of 2007. The additional
capital should position Penn West for more rapid expansion of the
Peace River Oil Sands project in the future.
- Work continued on our Pembina CO2 pilot project where we have
experienced excellent injection and containment of CO2 into the
Cardium pool. We will be expanding the pilot to evaluate using
horizontal wells to boost production and injection rates from the
Cardium. Currently, we are evaluating moving towards a more
integrated solution to CO2 supply that would tie into our
development of the Peace River Oil Sands.
- During the fourth quarter of 2006, Penn West continued to be active
on its other enhanced oil recovery projects. Work continued on two
additional CO2 patterns at the Joffre Viking Unit with CO2 injection
expected to start during the first quarter of 2007.
- Ongoing development at the Weyburn CO2 enhanced oil recovery project
is continuing with higher than expected response rates to additional
CO2 flooding. Based on these results, and improvements to the CO2
recycling capability, the infill drilling program has been expanded
to 55 wells (12 net) from 40 wells (eight net).
HIGHLIGHTS
Three months ended Year ended
December 31 December 31
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($ millions, except
per unit and % %
production amounts) 2006 2005 change 2006 2005 change
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Financial
Gross revenues $ 578.5 $ 554.5 4 $2,100.9 $1,919.0 9
Cash flow 303.3 332.6 (9) 1,176.8 1,184.6 (1)
Basic per unit 1.23 2.03 (39) 5.86 7.28 (20)
Diluted per unit 1.22 2.03 (40) 5.78 7.14 (19)
Net income 122.9 241.1 (49) 665.6 577.2 15
Basic per unit 0.44 1.48 (70) 3.32 3.55 (6)
Diluted per unit 0.44 1.46 (70) 3.27 3.48 (6)
Capital
expenditures, net 159.4 6.3 2,430 577.9 456.7 27
Total debt at
period-end 1,285.0 542.0 137 1,285.0 542.0 137
Distributions paid 241.3 143.6 68 781.8 270.9 189
Dividends paid $ - $ - - $ - $ 17.5 -
Operations
Daily production
Natural gas
(mmcf/d) 354.6 277.5 28 312.5 287.8 9
Light oil and NGL
(bbls/d) 48,233 33,227 45 39,514 33,137 19
Conventional
heavy oil
(bbls/d) 22,586 18,726 21 20,776 18,705 11
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Total production
(boe/d) 129,915 98,205 32 112,369 99,807 13
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Average sales price
Natural gas
($/mcf) $ 6.97 $ 11.66 (40) $ 6.75 $ 8.68 (22)
Light oil and NGL
($/bbl) 57.43 64.28 (11) 65.02 62.59 4
Conventional
heavy oil ($/bbl) 37.57 34.95 7 43.07 35.71 21
Netback per boe
Sales price $ 46.88 $ 61.38 (24) $ 49.58 $ 52.50 (6)
Risk management 1.53 - - 1.64 0.18 811
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Net sales price 48.41 61.38 (21) 51.22 52.68 (3)
Royalties 9.12 12.52 (27) 9.10 9.74 (7)
Operating expenses 10.61 9.44 12 10.39 8.99 16
Transportation 0.51 0.64 (20) 0.60 0.62 (3)
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Netback $ 28.17 $ 38.78 (27) $ 31.13 $ 33.33 (7)
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The above information includes measures not defined under generally
accepted accounting principles, including cash flow, barrels of oil
equivalent and netback. Cash flow is cash flow from operating activities
before changes in non-cash working capital, cash option payments, and
asset retirement expenditures and includes realized foreign exchange
gains. Please refer to the calculation of cash flow table on the first
page of the Management's Discussion and Analysis for more details.
Barrels of oil equivalent (boe) are based on six mcf of natural gas
equalling one barrel of oil (6:1). Netback is a per unit measure of
operating margin used in capital allocation decisions.
DRILLING PROGRAM
Three months ended Year ended
December 31 December 31
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2006 2005 2006 2005
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Gross Net Gross Net Gross Net Gross Net
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Natural gas 34 12 13 13 181 105 150 148
Oil 50 38 37 34 193 149 119 110
Dry 3 2 4 4 17 16 18 18
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Total wells 87 52 54 51 391 270 287 276
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Success Rate 96% 92% 94% 93%
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UNDEVELOPED LANDS
As at December 31
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2006 2005 % change
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Gross acres (000s) 4,176 4,390 (5)
Net acres (000s) 3,715 4,142 (10)
Average working interest 89% 94% (5)
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FARM-OUT ACTIVITY
Three months ended Year ended
December 31 December 31
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2006 2005 2006 2005
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Wells drilled on
farm-out lands(1) 57 15 169 103
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(1) Wells drilled on Penn West lands, including re-completions and
re-entries, by independent operators pursuant to farm-out agreements.
CORE AREAS
Undeveloped land
as at
Net wells drilled for Net wells drilled December 31, 2006
the three months ended for the year ended (thousands of
Core Area December 31, 2006 December 31, 2006 net acres)
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Central 21 89 1,305
Plains 31 148 1,365
Northern - 33 1,045
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52 270 3,715
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TRUST UNIT DATA
Year ended December 31
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(millions of units) 2006 2005 % change
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Weighted average
Basic 200.8 162.6 23
Diluted 203.5 165.9 23
Outstanding as at December 31
Basic 237.1 163.3 45
Basic plus trust unit rights 248.4 172.7 44
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On June 30, 2006, Penn West issued approximately 70.7 million trust units
on the closing of the Petrofund merger.
a) Reserve category splits under forecast prices and costs
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Natural Barrels of
Light & Natural Gas Oil
Reserve Medium Oil Heavy Oil Gas Liquids Equivalent
Estimates
Category(1)(2) (mmbbl) (mmbbl) (bcf) (mmbbl) (mmboe)
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Proved
Developed
producing 146.9 40.9 667.6 17.1 316.2
Developed
non-producing 6.6 3.1 46.6 1.0 18.5
Undeveloped 33.4 1.8 43.4 1.5 44.0
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Total proved 186.9 45.9 757.6 19.6 378.7
Probable 50.9 14.0 203.2 5.3 104.1
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Total proved
plus probable 237.8 59.9 960.8 24.9 482.8
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(1) Working interest reserves before royalty burdens and excluding
royalty interests.
(2) Columns may not add due to rounding.
Penn West's reserves continue to reflect a high concentration of proved
developed reserves. Of total proved reserves, only 12 percent were undeveloped
at December 31, 2006 and 2005. Of total proved plus probable reserves, only
nine percent were undeveloped at December 31, 2006, compared to 10 percent a
year ago.
Penn West's reserves also contain a high netback product mix. At December
31, 2006, on a proved plus probable basis, reserves other than heavy oil were
88 percent of total reserves on a barrel of oil equivalent basis compared to
82 percent a year ago.
As at December 31, 2006, there were only approximately 7.8 million barrels
of proved plus probable reserves of heavy oil booked for the Peace River Oil
Sands project and no reserves booked for potential future light oil additions
from the Pembina CO2 enhanced recovery projects in the pilot project stage.
Penn West believes these factors speak to the relative quality, stability and
growth potential of our asset base.
GLJ Petroleum Consultants Ltd. evaluated Penn West's reserves for all
properties. The reserve estimates have been calculated in compliance with the
National Instrument 51-101 Standards of Disclosure for Oil and Gas Activities
("NI 51-101"). Under NI 51-101, proved reserve estimates are defined as having
a high degree of certainty with a targeted 90 percent probability 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 less than or greater than the proved plus probable reserves estimate.
Proved undeveloped reserves are mainly associated with planned infill
drilling in existing pools.
Additional reserve disclosure tables, as required under NI 51-101, will be
contained in Penn West's Annual Information Form that will be filed on SEDAR
at www.sedar.com.
b) Reconciliation of Gross Interest Reserves (working interest before
royalty burdens) using forecast prices and costs
Oil and NGLs Natural Gas
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Proved Proved
plus plus
Proved Probable probable Proved Probable probable
Reconciliation
Items(1) (mmbbl) (mmbbl) (mmbbl) (bcf) (bcf) (bcf)
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December 31, 2005 196.3 44.4 240.7 565.1 133.2 698.4
Extensions 2.2 0.3 2.5 18.4 2.6 21.1
Improved recovery 5.6 4.9 10.5 10.4 1.4 11.8
Technical Revisions (3.2) (2.4) (5.6) (4.9) (15.4) (20.3)
Discoveries - - - 2.1 2.6 4.7
Acquisitions 72.8 22.9 95.6 278.3 79.3 357.6
Dispositions (0.4) (0.1) (0.5) (0.7) (0.7) (1.4)
Economic Factors 0.9 0.2 1.1 0.3 0.1 0.3
Production (21.7) - (21.7) (111.3) - (111.3)
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December 31, 2006 252.4 70.2 322.6 757.6 203.2 960.8
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Barrels of Oil Equivalent
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Proved
plus
Proved Probable probable
Reconciliation
Items(1) (mmboe) (mmboe) (mmboe)
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December 31, 2005 290.5 66.7 357.1
Extensions 5.3 0.8 6.0
Improved recovery 7.3 5.1 12.4
Technical Revisions (4.0) (5.0) (9.0)
Discoveries 0.3 0.4 0.8
Acquisitions 119.1 36.1 155.2
Dispositions (0.5) (0.2) (0.7)
Economic Factors 1.0 0.2 1.2
Production (40.3) - (40.3)
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December 31, 2006 378.7 104.1 482.8
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(1) Columns may not add due to rounding. Gross interest reserves exclude
royalty interests.
c) Reconciliation of Net Interest Reserves (working interest after
royalty burdens and including royalty interests) using forecast
prices and costs
Oil and NGLs Natural Gas
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Proved Proved
plus plus
Reconciliation Proved Probable probable Proved Probable probable
Items(1) (mmbbl) (mmbbl) (mmbbl) (bcf) (bcf) (bcf)
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December 31, 2005 177.1 39.4 216.5 462.8 109.8 572.6
Extensions 2.0 0.3 2.2 14.9 2.2 17.1
Improved recovery 3.8 4.5 8.3 8.8 1.5 10.2
Technical revisions (3.0) (2.3) (5.3) (4.9) (12.2) (17.1)
Discoveries - - - 1.6 1.9 3.5
Acquisitions 61.7 19.3 81.0 223.1 64.2 287.3
Dispositions (0.3) (0.1) (0.4) (0.7) (0.3) (1.0)
Economic factors 0.8 0.2 1.0 0.2 0.1 0.3
Production (18.5) - (18.5) (87.8) - (87.8)
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December 31, 2006 223.6 61.2 284.8 618.0 167.2 785.3
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Barrels of Oil Equivalent
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Proved
plus
Reconciliation Proved Probable probable
Items(1) (mmboe) (mmboe) (mmboe)
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December 31, 2005 254.2 57.7 312.0
Extensions 4.5 0.6 5.1
Improved recovery 5.3 4.7 10.0
Technical revisions (3.8) (4.3) (8.1)
Discoveries 0.3 0.3 0.6
Acquisitions 98.8 30.0 128.9
Dispositions (0.5) (0.2) (0.6)
Economic factors 0.9 0.2 1.1
Production (33.1) - (33.1)
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December 31, 2006 326.6 89.1 415.7
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(1) Columns may not add due to rounding.
Total company interest proved plus probable reserves of 486 mmboe at the
end of 2006 were 35 percent higher than proved plus probable reserves of
360 mmboe at the end of 2005.
d) Net present value of future net revenue under forecast prices and
costs ($ millions)
Net present value of future net revenue
before income taxes (discounted @)
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Reserve Category 5% 10% 15%
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Proved
Developed producing $ 6,568 $ 5,174 $ 4,333
Developed non-producing 375 248 186
Undeveloped 784 475 308
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Total proved $ 7,727 $ 5,897 $ 4,826
Probable 1,891 1,152 793
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Total proved plus probable $ 9,618 $ 7,049 $ 5,619
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Net present values are net of producing wellbore abandonment liabilities
and are based on the price assumptions that are contained in the
following table. The estimated future net revenues do not represent fair
market value.
e) Summary of pricing and inflation rate assumptions as of December 31,
2006 under forecast prices and costs
Oil
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Edmonton Hardisty Cromer
WTI Par Heavy Medium
Cushing 40 degrees 12 degrees 29 degrees
Oklahoma API API API
Year ($US/bbl) ($CAD/bbl) ($CAD/bbl) ($CAD/bbl)
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Historical
2002 26.08 40.33 26.57 35.48
2003 31.07 43.66 26.26 37.55
2004 41.38 52.96 29.11 45.75
2005 56.58 69.11 34.07 56.62
2006 66.22 73.16 41.87 62.24
Forecast
2007 62.00 70.25 39.25 61.25
2008 60.00 68.00 40.00 59.25
2009 58.00 65.75 39.75 57.25
2010 57.00 64.50 39.75 56.00
2011 57.00 64.50 40.25 56.00
2012 57.50 65.00 41.50 56.50
2013 58.50 66.25 42.50 57.75
2014 59.75 67.75 43.50 59.00
2015 61.00 69.00 44.25 60.00
2016 62.25 70.50 45.25 61.25
2017 63.50 71.75 46.00 62.50
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Thereafter 2% 2% 2% 2%
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Natural
Gas AECO Edmonton Inflation Exchange
gas price Propane rates Rate
($US equals
Year ($CAD/mcf) ($CAD/bbl) (%) $1 CAD)
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Historical
2002 4.04 21.39 2.2 0.637
2003 6.66 32.14 2.8 0.721
2004 6.88 34.70 1.8 0.768
2005 8.58 43.04 2.2 0.825
2006 7.02 43.97 2.1 0.882
Forecast
2007 7.20 45.00 2.0 0.870
2008 7.45 43.50 2.0 0.870
2009 7.75 42.00 2.0 0.870
2010 7.80 41.25 2.0 0.870
2011 7.85 41.25 2.0 0.870
2012 8.15 41.50 2.0 0.870
2013 8.30 42.50 2.0 0.870
2014 8.50 43.25 2.0 0.870
2015 8.70 44.25 2.0 0.870
2016 8.90 45.00 2.0 0.870
2017 9.10 46.00 2.0 0.870
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Thereafter 2% 2% 2.0 0.870
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f) Future development costs under forecast prices and costs ($ millions)
Proved Future
Development
Year Costs
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2007 $ 148
2008 166
2009 98
2010 73
2011 57
2012 and subsequent 176
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Undiscounted total $ 718
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Discounted at 10%/yr $ 518
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LETTER TO OUR UNITHOLDERS
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Fourth Quarter 2006
The fourth quarter of 2006 was remarkable, with Penn West Energy Trust achieving a record level of quarterly average production. At the same time, our unitholders were left to bear the immediate and harsh impact of the stated intent of the Government of Canada to aggressively tax income trust distributions beginning in 2011.
Following our merger with Petrofund Energy Trust in late June of 2006, we faced the task of integrating the staff and assets of the two entities into a newer, stronger Penn West Energy Trust. The time and extra effort required to effect this merger did impact the timing and execution of our 2006 capital program. In spite of these challenges, by the end of the fourth quarter of 2006, we were able to achieve consistent average daily production levels of approximately 130,000 barrels of oil equivalent per day and formulate a 2007 capital and operating plan to continue moving the trust forward. Our production in the fourth quarter of 2006 was 129,915 boe per day compared to 129,059 in the third quarter of 2006, and 98,205 in the fourth quarter of 2005.
Operating costs for the fourth quarter of 2006 were consistent with the prior quarter reflecting our efforts to control costs in the face of the industry-wide high demand for oilfield services.
Cash flow for the fourth quarter of 2006 was on target at $303 million ($1.23 per unit, basic), resulting in reported cash flow for 2006 of approximately $1.18 billion ($5.86 per unit, basic). If we had owned the Petrofund assets for all of 2006, cash flow would have been approximately $1.37 billion. Compared to 2005, commodity prices were lower in 2006; however, the impact was partially offset by realized oil and natural gas hedging gains of approximately $67 million, or $1.64 per barrel of oil equivalent. Gains realized on electricity hedges of approximately $18 million in 2006 also helped us flatten our operating costs. Our distribution payout ratio in 2006 was 69 percent, toward the upper end of our targeted 60 percent to 70 percent range, largely due to lower natural gas prices resulting from unseasonably warm early winter weather that kept storage levels high. Recent cold weather has helped AECO natural gas prices recover to current, one-year forward, levels of approximately $8.50 per mcf. AECO natural gas prices averaged $8.81 per mcf in 2006 and $8.58 per mcf in 2005. We remain comfortable with the strength of our balance sheet, as we exited 2006 with a bank debt to cash flow ratio of 0.9 to 1 including the Petrofund assets from January 1. As opportunities arise, we plan to continue adding oil, natural gas and electricity hedges. Our Board recently resolved to keep our distribution level at $0.34 per unit, per month, based on current forecasts of commodity prices and currently planned 2007 capital expenditures.
Update on Unconventional Growth Opportunities
We continue to focus our efforts on our Peace River Oil Sands project, where we hold 300,000 acres of 100 percent owned oil sands leases. Penn West currently estimates the project area contains 6.8 billion barrels of heavy oil resources in place(1). As at December 31, 2006, our independent reserves evaluators, GLJ Petroleum Consultants Ltd., assigned approximately 7.8 million barrels of proved plus probable reserves, including 5.2 million barrels of proved developed producing reserves, to our project. As we add production and delineate our project area with exploration wells in the future, we believe that the potential production and reserve additions could be very significant. Our initial 2007 capital budget for this project, developed in the fall of 2006, was $100 million that included the drilling of 60 - 65 net wells, expenditures on production infrastructure, and expenditures on production optimization and engineering research related to water flood and thermal recovery techniques. In 2007 to date, we have drilled 11 horizontal wells and 12 exploration wells and our current production is 3,600 barrels of oil per day. We also plan to complete the installation of pipeline infrastructure from our Seal Main development area to our 13,500 barrel per day oil battery (in which we have a 35 percent interest) that is pipeline connected to Alberta markets. As a result of our continuing success adding production and encouraging results from our ongoing exploratory well program, our Board of Directors recently approved an increase in the 2007 capital program to $175 million for this project, excluding acquisitions. The additional $75 million of capital will be used to accelerate our research, development drilling and to expand our processing capabilities in the project area. Using conventional, non-thermal recovery methods, our target production from the area is 6,000 - 8,000 barrels of oil per day by year-end 2007 and 20,000 barrels of oil per day within four years.
On February 9, 2007, we announced that we signed an agreement to acquire a package of assets for $339 million before closing adjustments and rights of first refusal that will significantly bolster our infrastructure and operating presence in the Peace River Oil Sands. Approximately 80 percent of the acquisition, or 3,000 barrels of light oil per day and 6 mmcf per day of natural gas production, is situated in our Peace River Oil Sands area or adjacent areas, as are 190,000 net acres of undeveloped oil and natural gas leases. The deal also adds important infrastructure including a sales line connected 10,000 barrel per day oil processing facility, a natural gas plant and compression facility with a design capacity of 33 mmcf per day and associated all-weather roads.
Penn West also has an approximate 40 percent interest in the Pembina field estimated to contain light oil resources in place of over 7 billion barrels(2). Of this total, we estimate that only 18 percent(2) has been recovered to date. The potential to recover significant additional light oil reserves keeps us focused on techniques that increase oil recovery rates.
At our Pembina CO2 pilot project, we have injected in excess of a billion cubic feet of CO2 over the last two years. The pilot has exhibited good containment of injected CO2 and excellent ability to accept increasing injection rates. While the pilot oil production using vertical wells continues to increase, we will be expanding our pilot project to apply horizontal well technology to accelerate the production response and thus improve the capital payout timelines. As a result of delays associated with securing an economic supply of CO2, we forecast that the commercial start-up of the project will not occur until 2012. Currently, we are exploring using an approach that will integrate our Peace River Oil Sands and Pembina CO2 projects. If successful, we believe that we can demonstrate an economic, environmentally proactive approach to both enhancing recovery from mature light conventional oil fields and developing non-conventional resources of oil.
Government of Canada Income Trust Tax Proposal
In the fourth quarter of 2006, Penn West remained engaged on various fronts in response to the Government of Canada's October 31, 2006 proposed tax on income trust distributions. We are also looking at structural alternatives to help alleviate part or all of the negative effects of the proposed tax should it be enacted. The rules on undue expansion were clarified and Penn West can grow its equity by approximately $10 billion over the next four years without prematurely triggering the proposed distribution tax. As a result, we have resumed our normal diligence, analyzing all potential strategic or accretive deals to increase the value of our unitholders' investment. We actively supported the formation of the Coalition of Canadian Energy Trusts. This coalition, whose membership actively supported the formation of the Coalition of Canadian Energy Trusts. This coalition, whose membership includes all of the producing energy trusts in Canada, continues to work toward better awareness of the important role that energy trusts play in supporting the continued success of the energy industry in Canada. In addition, we support the efforts of the Canadian Association of Income Funds to mitigate what we believe is an ill-advised proposal by the Department of Finance. We will continue our efforts on behalf of our unitholders to restore investor confidence and move Penn West Energy Trust towards the future. If you have concerns about the tax proposal, we urge you to contact your local Member of Parliament. Additionally, you can join the Canadian Association of Income Trust Investors, a recently formed coalition of investors who are expressing their concerns to the Government of Canada, by visiting their website at www.caiti.info.
Looking Forward
We are continuing to carry out all of our health, safety and environmental programs. We spent $27 million during 2006 on environmental programs and are allocating $40-50 million to this area in 2007. We are committed to proactive health, safety and environmental programs that will benefit our employees, contractors and our communities. Penn West is committed to providing the leadership for a health, safety and environmentally conscious culture at Penn West that will, in the long term, provide direct benefits to all unitholders.
While our near-term focus is on the tax proposal, our long-term focus is on having a strong business plan that incorporates several of the possible outcomes of the proposal. In the interim, we will continue to execute plans for 2007 that will see Penn West Energy Trust work to maintain production volumes, improve capital efficiencies, and continue our efforts toward the realization of the significant and long term benefits the Peace River Oil Sands project and the CO2 Enhanced Recovery projects could provide for the unitholders of Penn West.
On behalf of the board and staff of Penn West Energy Trust, I wish to thank our unitholders for their continuing support of Penn West and for their continuing support against the proposed distribution tax. Your voice is being heard.
On behalf of the Board of Directors,
William E. Andrew
President and CEO
Calgary, Alberta
February 26, 2007
(1) Represents the mid case. Using the definitions set out in the
Canadian Oil and Gas Handbook, these resources are considered
"Discovered Resources". As Penn West is in the early stages of the
project, these resources have not been classified into more specific
categories. There is no certainty that a significant portion of
these resources will be recovered or that a significant portion of
the resources will be economically or technically feasible to produce
in the future. Discovered resources are those quantities of oil and
gas estimated on a given date to be remaining in, plus those
quantities already produced from, known accumulations. Discovered
resources consist of economic and uneconomic resources with the
estimated future recoverable portion classified as reserves or
contingent resources.
(2) Source: Alberta Energy and Utilities Board, "Alberta's Reserves 2004
and Supply/Demand Outlook 2005-2014". In this publication, it was
estimated that 15.8 percent of the Pembina field had been recovered
by the year 2004. This estimate was extrapolated forward to arrive at
Penn West's estimate of 18 percent at December 31, 2006.
MANAGEMENT'S DISCUSSION AND ANALYSIS
For the three months and year ended December 31, 2006
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This management's discussion and analysis ("MD&A") of financial conditions
and results of operations should be read in conjunction with the unaudited
interim consolidated financial information of Penn West Energy Trust ("Penn
West", "the Trust", "We" or "Our") for the three months and year ended
December 31, 2006 included in this press release, and the audited consolidated
financial statements and MD&A for the year ended December 31, 2005. The date
of this MD&A is February 26, 2007.
All dollar amounts contained in this MD&A are expressed in millions of
Canadian dollars unless noted otherwise.
Please refer to our disclaimer on forward-looking statements at the end of
this MD&A. The calculations of barrels of oil equivalent ("boe") are based on
a conversion ratio of six thousand cubic feet of natural gas to one barrel of
crude oil. This could be misleading if used in isolation as it is based on an
energy equivalency conversion method at the burner tip and does not
necessarily represent a value equivalency at the wellhead.
Measures including cash flow, cash flow per unit-basic, cash flow per
unit-diluted, netbacks and distributable cash from operations included in this
MD&A are not defined in generally accepted accounting principles ("GAAP");
accordingly, they may not be comparable to similar measures provided by other
issuers. Management utilizes cash flow, and netbacks to assess financial
performance, to allocate its capital among alternative projects and to assess
our capacity to fund distributions and future capital programs.
Calculation of Cash Flow
Three months ended Year ended
December 31 December 31
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($ millions, except
per unit amounts) 2006 2005 2006 2005
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Cash flow from operating
activities $ 261.1 $ 368.7 $1,106.3 $ 932.8
Increase (decrease) in
non-cash working capital 32.9 (42.4) 43.6 1.8
Payments for surrendered options - - - 141.6
Asset retirement expenditures 9.3 6.3 26.9 22.6
Realized foreign exchange gain - - - 85.8
-------------------------------------------------------------------------
Cash flow $ 303.3 $ 332.6 $1,176.8 $1,184.6
-------------------------------------------------------------------------
Basic per unit $ 1.23 $ 2.03 $ 5.86 $ 7.28
Diluted per unit $ 1.22 $ 2.03 $ 5.78 $ 7.14
-------------------------------------------------------------------------
Quarterly Financial Summary
($ millions, except per unit and production amounts)
Penn West Energy Trust
----------------------------------------
Three months ended Dec. 31 Sept. 30 June 30 Mar. 31
2006 2006 2006 2006
-------------------------------------------------------------------------
Gross revenues $ 578.5 $ 636.0 $ 452.5 $ 433.9
Cash flow 303.3 365.6 264.7 243.2
Basic per unit(1) 1.23 1.55 1.59 1.49
Diluted per unit(1) 1.22 1.53 1.56 1.47
Net income 122.9 177.8 220.5 144.4
Basic per unit(1) 0.44 0.66 1.34 0.88
Diluted per unit(1) 0.44 0.65 1.31 0.87
Distributions declared 241.5 240.7 167.6 162.0
Per unit 1.02 1.02 1.02 0.99
Dividends declared - - - -
Per unit(1) $ - $ - $ - $ -
Production
Liquids(2) (bbls/d) 70,819 69,215 48,599 52,226
Natural gas (mmcf/d) 354.6 359.1 267.9 266.9
Total (boe/d) 129,915 129,059 93,242 96,713
-------------------------------------------------------------------------
Penn West
Petroleum
Ltd.
----------------------------------------
Three months ended Dec. 31 Sept. 30 June 30 Mar. 31
2005 2005 2005 2005
-------------------------------------------------------------------------
Gross revenues $ 554.5 $ 535.0 $ 424.2 $ 405.3
Cash flow 332.6 334.9 257.0 260.1
Basic per unit(1) 2.03 2.06 1.58 1.61
Diluted per unit(1) 2.03 2.04 1.49 1.58
Net income 241.1 209.5 59.7 66.9
Basic per unit(1) 1.48 1.29 0.37 0.41
Diluted per unit(1) 1.46 1.27 0.34 0.41
Distributions declared 151.8 127.3 42.4 -
Per unit 0.93 0.78 0.26 -
Dividends declared - - - 10.8
Per unit(1) $ - $ - $ - $ 0.07
Production
Liquids(2) (bbls/d) 51,953 51,634 50,633 53,162
Natural gas (mmcf/d) 277.5 289.0 295.7 289.1
Total (boe/d) 98,205 99,802 99,910 101,343
-------------------------------------------------------------------------
(1) Per unit figures for the periods prior to June 30, 2005 have been
restated to reflect the conversion of Penn West common shares to
trust units using an exchange ratio of three trust units per share in
accordance with the plan of arrangement dated May 31, 2005 related to
the trust conversion.
(2) Includes crude oil and natural gas liquids.
Petrofund Merger
As of June 30, 2006, all approvals required to close the merger of Penn
West and Petrofund Energy Trust ("Petrofund") had been received and the merger
was completed effective June 30, 2006. Petrofund unitholders received 0.6 of a
Penn West unit for each Petrofund unit exchanged and also received a special
distribution of $1.00 per unit plus an adjustment of $0.10 per unit required
to align the distribution dates of the trusts.
Penn West accounted for the Petrofund merger as a purchase of Petrofund.
The consolidated financial statements of Penn West include the results of
operations and cash flows of Petrofund from July 1, 2006 forward. If the
merger had occurred on January 1, 2006, Penn West would have realized the
following pro forma results for the year ended December 31, 2006:
($ millions, except per unit amounts)
-------------------------------------------------------------------------
Revenue $ 2,496.5
Net income 722.9
Basic per unit 3.07
Diluted per unit $ 3.03
-------------------------------------------------------------------------
Production (boe/d) 132,373
-------------------------------------------------------------------------
Business Environment
The current business environment has moderate commodity prices, accessible capital markets, low interest rates by historical standards and a relatively stable regulatory environment other than the October 31, 2006 Government of Canada announcement of proposed changes to the taxation of income trusts.
Continuing demand for crude oil from growing economies such as China and India, along with political instability in parts of the world, resulted in stronger oil prices in 2006. The price of West Texas Intermediate ("WTI"), the primary benchmark for light crude oil prices, averaged US$66.22 per barrel in 2006, up by 17 percent from 2005.
Heavy oil differentials narrowed in 2006 as asphalt and residual fuel markets' demand exceeded the normal seasonal demand early in 2006. The price was also supported by industry initiatives to improve access into U.S. heavy oil markets. The Canadian Bow River differential to WTI narrowed by 10 percent from 2005.
AECO natural gas prices weakened in 2006, decreasing by 26 percent to $6.53 per mcf from $8.81 per mcf in 2005. Warm 2005 and early 2006 winters in North America resulted in lower demand and higher storage levels that lead to lower prices.
Lower natural gas prices and a strengthening of the Canadian dollar relative to the US dollar more than offset the benefit of stronger oil prices. Oil sales contracts are generally based on WTI prices denominated in US dollars; therefore the strengthening Canadian dollar reduces Canadian dollar realization. The average exchange rate increased from CAD$1.00 equals USD$0.825 in 2005 to CAD$1.00 equals USD$0.882 in 2006. In early 2007, the Canadian dollar has weakened to approximately CAD$1.00 equals USD$0.85
Regulations and incentive programs governing the calculation of royalties have been stable in recent years; however, there can be no assurance they will not change in the future.
High levels of industry activity increased operating costs in 2006 due to increases in the demand for energy, steel, services and other costs over 2005. However, Penn West is encouraged that its fourth quarter 2006 operating costs per barrel of oil equivalent remained approximately level with the third quarter of 2006. The flat operating cost per barrel of oil equivalent was achieved by our initiatives to contain operating cost increases and by realizing approximately $17 million in gains on electricity hedges.
We have a proven management team, dedicated employees and a business plan appropriate for an energy trust. Over the last 15 years, we progressed from a small explorer and producer to the top ranks of independent oil and natural gas producers in Western Canada. In 2005, we converted into the largest conventional oil and natural gas trust by production in Canada and added to production and reserves through the Petrofund merger in 2006. We have a disciplined approach to business that stresses cost control and product balance. Using this discipline, we have shown that we can explore for and develop grassroots reserves, and also successfully acquire and optimize producing fields. We have a diverse asset base in the Western Canada Sedimentary Basin divided into three core areas ranging from southern Manitoba to regions bordering the Northwest Territories.
Our goal is to create and protect unitholder value by:
- Pursuing an active program of internal development, focusing on
low-risk opportunities to maintain production or reduce operating
costs, and on resource plays such as the Peace River Oil Sands
project and our portfolio of CO2 enhanced oil recovery projects;
- Participating in exploration, without the requirement to fund capital
expenditures, through the farm-out of undeveloped lands;
- Rationalizing our asset base with the aim of maintaining
distributions over the long term, including asset acquisitions and
dispositions that are accretive or strategic; and
- Maintaining a strong balance sheet.
Proposed Tax on Income Trusts
On October 31, 2006, the Government of Canada announced proposed changes
to the taxation of publicly traded income trusts. Commencing in 2011, taxes at
estimated corporate tax rates were proposed on distributions that represent a
return on capital by disallowing these distributions as a deduction in the
calculation of the trust's taxable income. Subsequent to the October 31
announcement, the Government of Canada tabled draft legislation and clarified
the rules related to "undue expansion". Recently, hearings of the House of
Commons' finance committee have been held; however, it is not yet clear what
impact, if any, the hearings will have on the proposed tax. If the tax
proposals are enacted into law as proposed on October 31, 2006, they could
have some or all of the following impacts, and Penn West could take some or
all of the following actions:
- If structural or other similar changes are not made, the after-tax
distribution yield in 2011 to taxable Canadian investors will remain
approximately the same, however, the distribution yield in 2011 to
tax-deferred Canadian investors (RRSPs, RRIFs, pension plans, etc.)
and foreign investors will fall by an estimated 31.5 percent and
26.5 percent, respectively;
- A portion of Penn West's cash flow could be allocated to the payment
of cash distribution taxes, or other forms of tax, and will not be
available for distribution or re-investment;
- It could be determined that it is more economic for Penn West to
change its corporate structure to facilitate investing a higher
proportion or all of its cash flow in exploration and development
projects. Such a conversion and change to capital programs would
result in a significant reduction or elimination of distributions
and/or dividends;
- It could be determined that it is more economic to remain in the
trust structure and pay corporate income taxes rather than the
proposed distribution tax and pay all or a portion of our
distributions on a return of capital basis at a potentially
significantly lower payout ratio;
- Other strategic alternatives could be determined to be more economic
than any of the above; and/or
- If income trusts are subsequently determined to be taxable entities
for future income tax accounting purposes, the recording of an
additional future income tax liability would be required and the
change in the future income tax liability could be material.
The table below, provided by the Government of Canada in a backgrounder
accompanying its October 31, 2006 announcement, shows a simplified comparison
of the effects of the proposed changes to investor tax rates in 2011;
Current System Proposed System
-------------------------------------------------------
Income portion Large Income portion Large
of trust corporation of trust corporation
Investor distributions (dividend) distributions (dividend)
-------------------------------------------------------------------------
Taxable Canadian
individuals(1) 46% 46% 45.5% 45.5%
Canadian tax-exempt
investors 0% 32% 31.5% 31.5%
Taxable U.S. investors(2) 15% 42% 41.5% 41.5%
-------------------------------------------------------------------------
(1) All rates in the table are as of 2011, and include both entity- and
investor-level tax (as applicable). Rates for "taxable Canadian
individuals" assume that top personal income tax rates apply and that
provincial governments increase their dividend tax credit for
dividends of large corporations.
(2) Canadian taxes only. U.S. tax will also apply in most cases, net of
any foreign tax credits.
Our Board of Directors and management team are reviewing the impact, if
any, of the proposals on our business strategy.
Unitholder Value Measures
Year ended December 31
------------------------------------
2006 2005 2004
-------------------------------------------------------------------------
Cash flow per unit($) 5.86 7.28 5.37
Distributions per unit($) 4.05 1.97 -
Dividends per unit($) - 0.07 0.16
Ratio of year-end bank debt to annual
cash flow 1.1 0.5 0.6
-------------------------------------------------------------------------
We have a strong in-house professional and technical staff, an extensive
base of undeveloped land (3.7 million net acres) and a strong balance sheet.
These attributes provide us the ability to pursue strategies of organic growth
through development and optimization, growth through strategic or accretive
acquisitions and the farm-out of undeveloped land. We believe in the
application of financial discipline in all areas of operations as a key factor
in achieving superior returns on investment for our unitholders.
Performance Indicators
Year ended December 31
------------------------------------
2006 2005 2004
-------------------------------------------------------------------------
Return on capital employed(1) 12.8% 17.0% 9.0%
Total assets ($ millions) 8,070 3,967 3,867
Return on equity(2) 18.1% 28.3% 15.3%
-------------------------------------------------------------------------
(1) Net income before financing charges divided by average total
liabilities less current assets.
(2) Net income divided by average unitholders' equity.
RESULTS OF OPERATIONS
Production
Three months ended Year ended
December 31 December 31
-----------------------------------------------------
% %
Daily production 2006 2005 change 2006 2005 change
-------------------------------------------------------------------------
Natural gas (mmcf/d) 354.6 277.5 28 312.5 287.8 9
Light oil and NGL
(bbls/d) 48,233 33,227 45 39,514 33,137 19
Conventional heavy
oil (bbls/d) 22,586 18,726 21 20,776 18,705 11
-------------------------------------------------------------------------
Total production
(boe/d)(1) 129,915 98,205 32 112,369 99,807 13
-------------------------------------------------------------------------
(1) Barrels of oil equivalent (boe) are based on six mcf of natural gas
being equal to one barrel of oil (6:1)
The increase in production was generally due to the Petrofund merger closing at the end of June 2006, and to our development and optimization programs.
We strive to maintain an approximately balanced portfolio of liquids and natural gas production provided it is economic to do so. We believe a balance by product helps to reduce exposure to price volatility that can affect a single commodity. Crude oil and NGL production averaged 70,819 barrels per day (55 percent of production) in the fourth quarter of 2006 and natural gas production averaged 354.6 mmcf per day (45 percent of production) in the same quarter.
We invested $159.4 million on capital expenditures and drilled 52 net wells in the fourth quarter of 2006. Drilling activity was focused in the Central and Plains areas.
Commodity Markets
Natural Gas
Natural gas prices declined throughout 2006, from close to record highs at the end of the prior year, due to a warm winter in 2005 - 2006 that weakened demand and resulted in higher than normal storage levels. Spot natural gas prices at AECO in the fourth quarter of 2006 increased by $1.18 per mcf or 21 percent from the prior quarter to average $6.91 per mcf while decreasing by $4.70 per mcf or 40 percent from the fourth quarter of 2005. AECO gas prices of $6.53 per mcf in 2006 decreased by 26 percent from $8.81 per mcf for the prior year.
Crude Oil
International crude oil prices remained strong with the benchmark West Texas Intermediate price averaging US$59.96 per barrel in the fourth quarter of 2006. However, this was a decrease of US$10.52 per barrel from the prior quarter. Oil prices had reached near-record highs in 2006 with continued high demand for crude oil and refined products and political instability in the Middle East. The Edmonton par price for light sweet crude oil remained strong year-over-year, slightly under performing WTI, due to a well-supplied crude oil market in Canada and the strengthening of the Canadian dollar relative to the US dollar.
Average Sales Prices Received
Three months ended Year ended
December 31 December 31
-----------------------------------------------------
% %
2006 2005 change 2006 2005 change
-------------------------------------------------------------------------
Natural gas ($/mcf) $ 6.97 $ 11.66 (40) $ 6.75 $ 8.68 (22)
Risk management
($/mcf) 0.56 - - 0.72 0.06 1,100
-------------------------------------------------------------------------
Natural gas net
($/mcf) 7.53 11.66 (35) 7.47 8.74 (15)
-------------------------------------------------------------------------
Light oil and
liquids ($/bbl) 57.43 64.28 (11) 65.02 62.59 4
Risk management
($/bbl) 0.01 - - (1.00) - -
-------------------------------------------------------------------------
Light oil and
liquids net 57.44 64.28 (11) 64.02 62.59 2
-------------------------------------------------------------------------
Conventional heavy
oil ($/bbl) 37.57 34.95 7 43.07 35.71 21
-------------------------------------------------------------------------
Weighted average
($/boe) 46.88 61.38 (24) 49.58 52.50 (6)
Risk management
($/boe) 1.53 - - 1.64 0.18 811
-------------------------------------------------------------------------
Weighted average net
($/boe) $ 48.41 $ 61.38 (21) $ 51.22 $ 52.68 (3)
-------------------------------------------------------------------------
Operating Netbacks
Three months ended Year ended
December 31 December 31
-----------------------------------------------------
% %
2006 2005 change 2006 2005 change
-------------------------------------------------------------------------
Natural gas
Production (mmcf/day) 354.6 277.5 28 312.5 287.8 9
Operating netback
($/mcf):
Sales price $ 6.97 $ 11.66 (40) $ 6.75 $ 8.68 (22)
Hedging gain 0.56 - - 0.72 0.06 1,100
Royalties 1.61 2.67 (40) 1.51 1.86 (19)
Operating costs 1.04 0.87 20 0.99 0.85 16
Transportation 0.18 0.22 (18) 0.21 0.21 -
-------------------------------------------------------------------------
Netback $ 4.70 $ 7.90 (41) $ 4.76 $ 5.82 (18)
-------------------------------------------------------------------------
Light oil and NGL
Production
(bbls/day) 48,233 33,227 45 39,514 33,137 19
Operating netback
($/bbl):
Sales price $ 57.43 $ 64.28 (11) $ 65.02 $ 62.59 4
Hedging
gain/(loss) 0.01 - - (1.00) - -
Royalties 10.21 11.46 (11) 10.51 10.17 3
Operating costs 15.36 15.17 1 15.80 14.43 9
-------------------------------------------------------------------------
Netback $ 31.87 $ 37.65 (15) $ 37.71 $ 37.99 (1)
-------------------------------------------------------------------------
Conventional
heavy oil
Production
(bbls/day) 22,586 18,726 21 20,776 18,705 11
Operating netback
($/bbl):
Sales price $ 37.57 $ 34.95 7 $ 43.07 $ 35.71 21
Royalties 5.44 5.67 (4) 6.51 5.41 20
Operating costs 11.88 9.64 23 11.22 9.30 21
Transportation 0.07 0.10 (30) 0.07 0.09 (22)
-------------------------------------------------------------------------
Netback $ 20.18 $ 19.54 3 $ 25.27 $ 20.91 21
-------------------------------------------------------------------------
Total liquids
Production
(bbls/day) 70,819 51,953 36 60,290 51,842 16
Operating netback
($/bbl):
Sales price $ 51.09 $ 53.71 (5) $ 57.46 $ 52.89 9
Hedging
gain/(loss) 0.01 - - (0.66) - -
Royalties 8.69 9.38 (7) 9.13 8.45 8
Operating costs 14.25 13.18 8 14.22 12.58 13
Transportation 0.02 0.04 (50) 0.03 0.03 -
-------------------------------------------------------------------------
Netback $ 28.14 $ 31.11 (10) $ 33.42 $ 31.83 5
-------------------------------------------------------------------------
Combined totals
Production(1)
(boe/day) 129,915 98,205 32 112,369 99,807 13
Operating netback
($/boe):
Sales price $ 46.88 $ 61.38 (24) $ 49.58 $ 52.50 (6)
Hedging gain 1.53 - - 1.64 0.18 811
Royalties 9.12 12.52 (27) 9.10 9.74 (7)
Operating costs 10.61 9.44 12 10.39 8.99 16
Transportation 0.51 0.64 (20) 0.60 0.62 (3)
-------------------------------------------------------------------------
Netback $ 28.17 $ 38.78 (27) $ 31.13 $ 33.33 (7)
-------------------------------------------------------------------------
(1) Boe or barrels of oil equivalent are based on six mcf of natural gas
being equal to one barrel of oil (6:1).
Production Revenues
Revenues from the sale of crude oil, NGL and natural gas consisted of the
following:
Year ended December 31
-------------------------------------
($ millions) 2006 2005 2004
-------------------------------------------------------------------------
Natural gas $ 850.9 $ 918.2 $ 773.0
Light oil and NGL 923.4 757.0 537.7
Conventional heavy oil 326.6 243.8 210.6
-------------------------------------------------------------------------
Total $ 2,100.9 $ 1,919.0 $ 1,521.3
-------------------------------------------------------------------------
The increase in revenue resulted from higher volumes due to the Petrofund
merger and higher oil prices, partially offset by lower natural gas prices.
Increases (Decreases) in Production Revenues
($ millions)
-------------------------------------------------------------------------
Gross revenues - 2005 $ 1,919.0
Increase in light oil and NGL production 145.7
Increase in light oil and NGL prices (including realized
hedging activities) 20.7
Increase in conventional heavy oil production 27.0
Increase in conventional heavy oil prices 55.8
Increase in natural gas production 78.8
Decrease in natural gas prices (including realized
hedging activities) (146.1)
-------------------------------------------------------------------------
Gross revenues - 2006 $ 2,100.9
-------------------------------------------------------------------------
Royalties
Year ended December 31
-------------------------------------
2006 2005 2004
-------------------------------------------------------------------------
Royalties ($ millions) $ 373.3 $ 355.0 $ 296.1
Average royalty rate (%) 18% 19% 20%
$/boe $ 9.10 $ 9.74 $ 7.65
-------------------------------------------------------------------------
Royalties, as a percentage of revenue, decreased in the quarter due to
realized hedging gains. The Petrofund properties have higher average royalty
rates than the Penn West properties, however, realized hedging gains reduced
2006 royalty rates compared to 2005.
Expenses
Year ended December 31
-------------------------------------
($ millions) 2006 2005 2004
-------------------------------------------------------------------------
Operating $ 426.3 $ 327.4 $ 300.4
Transportation 24.5 22.7 25.6
Financing 49.3 23.2 17.0
Equity-based compensation $ 11.3 $ 77.2 $ 84.1
-------------------------------------------------------------------------
Year ended December 31
-------------------------------------
($/boe) 2006 2005 2004
-------------------------------------------------------------------------
Operating $ 10.39 $ 8.99 $ 7.75
Transportation 0.60 0.62 0.66
Financing 1.20 0.63 0.45
Equity-based compensation $ 0.27 $ 2.12 $ 2.17
-------------------------------------------------------------------------
Operating
High levels of industry activity, in response to relatively high commodity
prices, resulted in strong demand for oilfield services and labour that
continued to put upward pressure on operating costs in 2006. In addition,
higher energy costs translated into higher utility, chemical and trucking
costs. A higher proportion of liquids production, combined with base
production declines and interruptions, also contributed to higher per unit
operating costs in 2006 than in 2005. The addition of the Petrofund assets
with higher operating costs than Penn West's properties also contributed to
the increase.
During 2006, as natural gas prices fell from their close to record highs,
some significant oil and natural gas companies cut their capital programs,
helping to reduce demand for oilfield services. This, combined with internal
initiatives targeted at reducing operating costs, resulted in the operating
cost per barrel of oil equivalent in the fourth quarter of 2006 being
approximately equal to the rate for the third quarter of 2006.
Financing
We use short-term money market instruments to realize lower interest rates
at the shorter end of the yield curve. The short end of the yield curve has
increased due to rate increases by the central banks in Canada and the United
States. The 2006 increase in interest expense was due to both an increase in
the average outstanding debt balance and the increases in short- term interest
rates over 2005. The average prime interest rate increased to 6.0 percent in
the fourth quarter of 2006 from an average of 4.8 percent in the same quarter
of 2005.
Interest and other financing costs for the year ended December 31, 2006
increased to $49.3 million from $23.2 million in 2005. The increased average
loan balance was principally due to the $610 million of debt assumed with the
Petrofund merger.
Equity-Based Compensation
On the close of the trust conversion on May 31, 2005, Penn West
implemented a trust unit rights incentive plan. Compensation expense related
to this plan is based on the fair value of trust unit rights issued,
determined using the Binomial Lattice option-pricing model. The fair value of
rights issued is expensed on a straight-line basis over the vesting periods of
the rights. Prior to the trust conversion, the Trust's predecessor company,
Penn West Petroleum Ltd. ("the Company"), had a stock option plan with a cash
settlement alternative; as a result, equity-based compensation was recorded
based on changes in the intrinsic value of stock options.
General and Administrative Expenses
Year ended December 31
-------------------------------------
($ millions, except per boe amounts) 2006 2005 2004
-------------------------------------------------------------------------
Gross $ 62.0 $ 45.0 $ 41.3
Per boe 1.51 1.24 1.07
Net 36.0 23.1 16.1
Per boe $ 0.88 $ 0.64 $ 0.42
-------------------------------------------------------------------------
Increases in total and per boe general and administrative costs in 2006
were due to higher staff levels following the Petrofund merger and higher
compensation costs. The cost of hiring, compensating and retaining employees
and consultants remains high due to strong demand for staff, particularly
those with specialized training and experience. Increasing costs related to
regulatory compliance also contributed to the increase.
Taxes
Year ended December 31
-------------------------------------
($ millions) 2006 2005 2004
-------------------------------------------------------------------------
Capital $ 14.7 $ 14.7 $ 10.1
Current income - 54.1 17.8
Future income (recovery) (106.2) (1.1) 109.6
-------------------------------------------------------------------------
$ (91.5) $ 67.7 $ 137.5
-------------------------------------------------------------------------
Capital taxes recorded in 2006 were consistent with 2005 as higher
revenues subject to the Saskatchewan resource surcharge, were offset by the
enactment of the elimination of the Canadian federal large corporations tax
and reductions to the rate of the Saskatchewan resource surcharge.
In the second quarter of 2006, Penn West recorded a $74 million future
income tax recovery to reflect corporate tax rate reductions substantively
enacted by the federal, Alberta and Saskatchewan governments.
Under our current structure, the operating entities make interest and
royalty payments to the Trust, which transfers taxable income to the Trust to
eliminate income subject to corporate and other income taxes in the operating
entities. Under the terms of its trust indenture, the Trust is required to
distribute amounts equal to at least its taxable income. In the event that the
Trust has undistributed taxable income in a taxation year, an additional
special taxable distribution, subject to certain withholding taxes, would be
required by the terms of its trust indenture.
If the proposed distribution tax is enacted and Penn West's structure is
not changed, Penn West will become a taxable entity, and from 2011 and
subsequent future income tax recoveries will likely not be recorded for income
transfers to the trust.
Tax Pools
As at December 31
-------------------------------------
($ millions) 2006 2005 2004
-------------------------------------------------------------------------
Undepreciated capital cost (UCC) $ 788.3 $ 519.0 $ 276.4
Canadian oil and gas property
expense (COGPE) 1,091.0 707.6 611.5
Canadian development expense (CDE) 428.8 329.8 95.4
Canadian exploration expense (CEE) - - -
Non-capital losses 106.1 - -
-------------------------------------------------------------------------
Total tax pools $ 2,414.2 $ 1,556.4 $ 983.3
-------------------------------------------------------------------------
The significant increase in the 2006 tax pools reflects the merger with
Petrofund. The tax pool figures are net of income deferred in operating
partnerships.
Depletion, Depreciation and Accretion ("DD&A")
Year ended December 31
-------------------------------------
($ millions, except per boe amounts) 2006 2005 2004
-------------------------------------------------------------------------
Depletion of oil and natural
gas assets(1) $ 623.7 $ 406.1 $ 383.7
Gas plant depreciation 11.3 10.4 10.6
Accretion of asset retirement
obligation(2) 19.7 21.1 18.8
-------------------------------------------------------------------------
Total DD&A 654.7 437.6 413.1
-------------------------------------------------------------------------
DD&A expense per boe $ 15.96 $ 12.01 $ 10.67
-------------------------------------------------------------------------
(1) Includes depletion of the capitalized portion of the asset retirement
obligation.
(2) Represents the accretion expense on the asset retirement obligation
during the period.
Higher DD&A expense in 2006 versus 2005 was due to the Petrofund merger.
The merger was accounted for as a purchase with the purchase price allocated
to the net assets acquired. The purchase allocation to oil and natural gas
assets significantly increased our consolidated depletion base and therefore
increased our DD&A rate.
Foreign Exchange
In 2006, we had no US-dollar-denominated debt. In 2005, the Company
realized a foreign exchange gain of $85.8 million on the conversion of US-
denominated debt to Canadian dollar debt.
Cash Flow and Net Income
Three months ended Year ended
December 31 December 31
-----------------------------------------------------
% %
2006 2005 change 2006 2005 change
-------------------------------------------------------------------------
Cash flow
($ millions) $ 303.3 $ 332.6 (9) $1,176.8 $1,184.6 (1)
Basic per unit 1.23 2.03 (39) 5.86 7.28 (20)
Diluted per unit 1.22 2.03 (40) 5.78 7.14 (19)
Net income
($ millions) 122.9 241.1 (49) 665.6 577.2 15
Basic per unit 0.44 1.48 (70) 3.32 3.55 (6)
Diluted per unit $ 0.44 $ 1.46 (70) $ 3.27 $ 3.48 (6)
-------------------------------------------------------------------------
Cash flow realized in 2006 decreased from 2005 due to lower natural gas
prices offset by higher production and higher oil prices.
Net income increased from 2005 levels due to higher production following
the Petrofund merger and future income tax recoveries offset by lower natural
gas prices. The lower fourth quarter 2006 net income reflects higher
depletion, depreciation and accretion charges following the Petrofund merger.
Year ended December 31
-----------------------------------------------------
2006 2005 2004
-----------------------------------------------------
$/boe % $/boe % $/boe %
-------------------------------------------------------------------------
Oil and natural gas
revenues $ 51.22 100.0 $ 52.68 100.0 $ 39.29 100.0
Net royalties (9.10) (17.8) (9.74) (18.5) (7.65) (19.5)
Operating expenses 10.39) (20.3) (8.99) (17.1) (7.75) (19.7)
Transportation (0.60) (1.2) (0.62) (1.1) (0.66) (1.7)
-------------------------------------------------------------------------
Net operating income 31.13 60.7 33.33 63.3 23.23 59.1
General and
administrative
expenses (0.88) (1.7) (0.64) (1.2) (0.42) (1.1)
Interest (1.20) (2.3) (0.63) (1.2) (0.45) (1.1)
Realized foreign
exchange gain - - 2.35 4.4 0.74 1.9
Current and capital
taxes (0.36) (0.7) (1.89) (3.6) (0.71) (1.8)
-------------------------------------------------------------------------
Cash flow 28.69 56.0 32.52 61.7 22.39 57.0
Unrealized foreign
exchange gain (loss) - - (2.48) (4.7) 0.30 0.8
Equity-based
compensation (0.27) (0.5) (2.12) (4.0) (2.17) (5.5)
Risk management
activities 1.18 2.3 (0.09) (0.2) - -
Depletion,
depreciation and
accretion (15.96) (31.2) (12.01) (22.8) (10.67) (27.2)
Future income taxes 2.59 5.1 0.03 - (2.83) (7.2)
-------------------------------------------------------------------------
Net income $ 16.23 31.7 $ 15.85 30.0 $ 7.02 17.9
-------------------------------------------------------------------------
Capital Expenditures
Three months ended Year ended
December 31 December 31
--------------------------------------------------
($ millions) 2006 2005 2006 2005
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Property acquisitions
(dispositions), net $ 10.9 $ (91.3) $ 5.6 $ (5.8)
Land acquisition
and retention 0.8 3.7 19.8 13.5
Drilling and
completions 86.1 61.0 317.4 277.1
Facilities and well
equipping 57.9 30.0 224.6 155.2
Geological and
geophysical 1.0 0.8 3.6 7.4
CO2 pilot costs 1.1 1.9 3.7 8.1
Administrative 1.6 0.2 3.2 1.2
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Capital expenditures 159.4 6.3 577.9 456.7
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Petrofund merger - - 3,323.3 -
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Total expenditures $ 159.4 $ 6.3 $ 3,901.2 $ 456.7
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We drilled 52 net wells in the fourth quarter of 2006, resulting in 12 net natural gas wells and 38 net oil wells with a success rate of 96 percent. Our drilling activities were focused in the Central and Plains areas. For 2006 we drilled 270 net wells, 105 net natural gas and 149 net oil wells with a success rate of 94 percent.
CO2 pilot costs represent capital expenditures related to the Pembina CO2 pilot project, including the cost of injectants, for which no reserves have been booked.
On June 30, 2006, we merged with Petrofund. The fair value of the oil and gas properties acquired of $3.3 billion was added to property, plant and equipment and the remaining $0.7 billion of the purchase price was attributed to goodwill. Goodwill was recorded to reflect that we increased our production capacity to levels which made us the largest conventional oil and gas royalty trust in North America, we increased our exposure to light oil giving us a better future product balance as we increase our future production from the Peace River Oil Sands, we increased our reserve life index and technological access to, and staff with experience in, resource plays including the Weyburn CO2 project and coalbed methane.
Our farm-out program is ongoing; since 2005, 272 wells have been drilled on Penn West's lands, including re-completions and re-entries, by independent operators that incur drilling, completions and other capital costs on these properties. In the fourth quarter of 2006, 57 wells were drilled on our lands, bringing the total to 169 wells for 2006.
In addition to the above capital expenditures, $1.7 million was capitalized in relation to future income taxes on minor acquisitions in the Swan Hills area, with less tax basis than the purchase price, and $55.9 million was capitalized from additions to and revisions of asset retirement obligations.
Business Risks
Market Risk Management
We are exposed to normal market risks inherent in the oil and natural gas business, including commodity price risk, credit risk, interest rate risk and foreign currency risk. From time to time, we attempt to minimize exposure to a portion of these risks using financial instruments.
Commodity Price Risk
We have substantial exposure to commodity price fluctuations. Crude oil prices are influenced by worldwide factors such as OPEC actions, supply and demand fundamentals, and political events. Oil prices, North American natural gas supply and demand factors and storage levels influence natural gas prices. Pursuant to our policies, we may, from time to time, manage these risks through the use of costless collars or other financial instruments up to a maximum of 50 percent of forecast sales volumes, net of royalties, for a two- year period or up to 75 percent of forecast sales volumes, net of royalties, for a one-year period.
For a current summary of outstanding oil and natural gas hedging contracts, please refer to our website at www.pennwest.com.
Credit Risk
Credit risk is the risk of loss if purchasers or counterparties do not fulfill their contractual obligations. All of our receivables are with customers in the oil and natural gas industry and are subject to normal industry credit risk. In order to limit the risk of non-performance of counterparties to derivative instruments, we contract only with organizations with high credit ratings or by obtaining security in certain circumstances.
Interest Rate Risk
We maintain our debt in floating-rate bank facilities, resulting in exposure to fluctuations in short-term interest rates. From time to time, we may increase the certainty of future interest rates using financial instruments to swap floating interest rates for fixed rates or to collar interest rates. In 2006, we entered into interest rate swaps that fix the interest rate for two years at 4.36 percent on $100 million of bank debt.
Foreign Currency Rate Risk
Prices received for sales of crude oil are referenced to, or denominated in, US dollars, and thus realized oil prices may be impacted by Canadian to United States exchange rates. When we consider it appropriate, we may use financial instruments to fix or collar future exchange rates. At December 31, 2006, we had no financial instruments outstanding related to foreign exchange rates.
Liquidity and Capital Resources
Capitalization
Year ended December 31
-----------------------------------------------------
2006 2005 2004
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($ millions) % % %
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Trust units issued,
at market $ 8,435 86.0 $ 6,203 90.5 $ 4,269 86.0
Bank loan -
long term 1,285 13.1 542 7.9 503 10.2
Working capital
deficiency(1) 86 0.9 127 1.6 190 3.8
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Total enterprise
value $ 9,806 100.0 $ 6,872 100.0 $ 4,962 100.0
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(1) Current assets minus current liabilities.
On June 30, 2006, we issued approximately 70.7 million trust units on the close of the Petrofund merger. During 2006, 2.5 million units were issued in lieu of cash under the Distribution Re-investment and Optional Purchase Plan, 0.4 million units were issued on the exercise of rights under the Trust Unit Rights Incentive Plan and 0.3 million units were issued to match employee contributions under the Trust Unit Savings Plan.
During 2006, we paid distributions of $781.8 million compared to distributions of $270.9 million and dividends of $17.5 million in 2005. This reflects that we were a trust for the full year in 2006, we paid higher per unit distributions in 2006 and we issued additional units on the Petrofund merger.
Under the terms of its current trust indenture, the Trust is required to make distributions to unitholders in amounts at least equal to its taxable income. Distributions may be monthly or special and in cash or in trust units at the discretion of our Board of Directors. To the extent that additional cash distributions are paid and capital programs are not adjusted, debt levels may increase. In the event that a special distribution in the form of trust units is declared, the terms of the trust indenture require that the outstanding units be consolidated immediately subsequent to the distribution. The number of outstanding trust units would remain at the number outstanding immediately prior to the unit distribution, less those sold to fund the payment of withholding taxes, and an amount equal to the distribution would be allocated to the unitholders as a taxable distribution.
Our philosophy is to retire approximately 10 percent of our opening asset retirement obligation annually, using our cash flow. Due to the extent of our environmental programs, we believe no benefit would arise from the initiation of a reclamation fund. We believe our program is sufficient to meet or exceed existing environmental regulations and best industry practices. In the event of significant changes to the environmental regulations or the cost of environmental activities, a higher portion of cash flow would be required to fund our environmental expenditures.
Bank debt at December 31, 2006 was $1,285 million compared to $542 million at December 31, 2005. In the third quarter of 2006, our wholly owned subsidiary, Penn West Petroleum Ltd., amended its unsecured, extendible, three-year revolving syndicated credit facility. The amended credit facility has an aggregate borrowing limit of $1.8 billion plus a $100 million swing line facility with stamping fees ranging from 60 - 115 basis points and standby fees ranging from 12.5 - 22.5 basis points depending on our ratio of consolidated bank debt to earnings before interest, taxes and depreciation and depletion ("EBITDA"). During 2006, the Company extended the facility termination date to August 25, 2009. As at December 31, 2006, there was $515 million (2005 - $628 million) available under the syndicated credit facility to finance future activities.
During 2006, the Company secured a $650 million bridge facility and utilized it to retire Petrofund's bank debt of $610 million on the close of the merger. The bridge facility was re-paid from the proceeds of the re- syndication of the credit facility on August 25, 2006. On December 31, 2006, the Company was in compliance with all of the financial covenants under the credit facility. The financial covenants under the new syndicated credit facility are as follows:
- Consolidated bank debt to EBITDA shall be less than 3:1 except in
certain circumstances and shall not exceed 3.5:1;
- Consolidated total debt to EBITDA shall be less than 4:1; and
- Consolidated bank debt to total trust capitalization shall not exceed
50 percent except in certain circumstances and shall not exceed
55 percent.
Reconciliation of Cash Flow from Operating Activities to Distributable
Cash from Operations
Penn West has elected to voluntarily present the following reconciliation
of distributable cash from operations based on guidance contained in the
Canadian Institute of Chartered Accountants' related November 2006 draft
interpretive release. In the draft release, sustainability concepts are
discussed and distributable cash from operations is defined as cash flow from
operating activities less adjustments for productive capacity maintenance,
long-term unfunded contractual obligations and the effect of any foreseeable
financing matters, related to debt covenants, which could impair our ability
to pay distributions.
Three months ended Year ended
December 31 December 31
($ millions, except --------------------------------------------------
per unit amounts) 2006 2005 2006 2005(1)
-------------------------------------------------------------------------
Cash flow from
operating activities $ 261.1 $ 368.7 $ 1,106.3 $ 696.5
Productive capacity
maintenance(2) (148.5) (97.6) (572.3) (212.1)
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Distributable cash
from operations 112.6 271.1 534.0 484.4
Proceeds from the
issue of trust units(3) 31.3 2.4 118.6 8.3
Bank borrowings and
working capital changes 97.6 (121.7) 159.2 (171.2)
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Cash distributions
declared $ 241.5 $ 151.8 $ 811.8 $ 321.5
Accumulated cash
distributions,
beginning 891.8 169.7 321.5 -
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Accumulated cash
distributions,
ending $ 1,133.3 $ 321.5 $ 1,133.3 $ 321.5
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Distributable cash
from operations
per unit, basic 0.48 1.66 2.66 2.98
Distributable cash
from operations
per unit, diluted 0.47 1.63 2.62 2.92
Distributable cash
payout ratio(4) 2.14 0.56 1.52 0.66
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Distributions declared
per unit $ 1.02 $ 0.93 $ 4.05 $ 1.97
Distributions declared
as a percentage of
net income 197% 63% 122% 56%
Distributions declared
as a percentage of
cash flow 80% 46% 69% 43%
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(1) Includes the operations of Penn West subsequent to the effective date
of the Trust conversion, May 31, 2005.
(2) Please refer to our discussion of productive capacity maintenance
below.
(3) Consists of proceeds from the Distribution Reinvestment and Optional
Purchase Plan, the Trust Unit Rights Incentive Plan and the Trust
Unit Savings Plan.
(4) Represents cash distributions declared divided by distributable cash
from operations.
We strive to fund both distributions and capital programs from cash flow. We budget our capital programs at approximately 40 - 50 percent of forecast cash flow. We believe that proceeds from the Distribution Re-investment and Optional Purchase Plan should be used to fund capital expenditures of a longer-term nature. Over the medium term, additional borrowings and equity issues may be required from time to time to fund a portion of our distributions or maintain or increase our productive capacity. On a longer-term basis, adjustments to the level of distributions and/or capital expenditures to maintain or increase our productive capacity may be required based on forecast levels of distributable cash from operations and capital efficiency.
Productive capacity maintenance is generally the amount required in a period for an enterprise to maintain its ability to generate future cash flow from operating activities at a constant level. As commodity prices can be volatile, we define our productive capacity as production on a barrel of oil equivalent basis. Short-term variations in production levels are often experienced in our business. A quantifiable measure for these short-term variations is not objectively quantifiable or verifiable due to various factors including the inability to distinguish natural production declines from the effect of production additions from capital and optimization programs, and the effect of temporary production interruptions. As a result, the adjustment for productive capacity maintenance in our calculation of distributable cash from operations is our actual capital expenditures during the period excluding the cost of any acquisitions or proceeds of any dispositions. We believe that our current capital programs will be sufficient to maintain our productive capacity in the medium term and set our hurdle rates for evaluating potential development and optimization projects accordingly.
Our calculation of distributable cash from operations has no adjustment for long-term unfunded contractual obligations. We believe our only significant long-term unfunded contractual obligation at this time is for asset retirement obligations. Cash flow from operating activities, used in our distributable cash from operations calculation, includes a deduction for actual abandonment expenditures during the period. We believe that our philosophy, to retire approximately 10 percent of our opening asset retirement obligation on an annual basis, is sufficient to fund our asset retirement obligations over the life of our reserves.
We currently have no financing restrictions caused by our debt covenants. We regularly monitor our current and forecast debt levels to ensure debt covenants are not exceeded.
($ millions, except indicators) As at December 31, 2006
-------------------------------------------------------------------------
Cumulative distributable cash from operations(1) $ 1,018.4
Issue of trust units 126.9
Bank borrowing and working capital change (12.0)
-------------------------------------------------------------------------
Cumulative cash distributions declared(1) $ 1,133.3
-------------------------------------------------------------------------
Distributable cash payout ratio(2) 1.11
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(1) Subsequent to the trust conversion on May 31, 2005.
(2) Represents cumulative cash distributions paid divided by cumulative
distributable cash from operations.
Financial Instruments
We currently have WTI crude oil collars on approximately 26,000 barrels
per day from January 1 to December 31, 2007 and 10,000 barrels per day from
January 2008 to June 2008. The collars on the 26,000 barrels per day to
December 2007 have an average floor price of US$56.12 per barrel and an
average ceiling price of US$83.50 per barrel. The 2008 WTI crude oil collars
have an average floor price of US$60.00 per barrel and an average ceiling
price of US$94.55 per barrel. In addition, Penn West has AECO natural gas
collars on approximately 76 mmcf per day from January 1 to October 31, 2007
with an average floor price of $7.69 per mcf and an average ceiling price of
$9.79 per mcf.
In the second quarter of 2006, we entered into interest rate swaps that
fix the interest rate for two years at approximately 4.36 percent on
$100 million of bank debt.
Other financial instruments outstanding at December 31, 2006 are Alberta
electricity contracts, which fix electricity costs on 67 megawatts at
$49.55 per megawatt hour and 2 megawatts at $57.00 per megawatt hour.
Mark to market amounts on all financial instruments outstanding on
December 31, 2006 are summarized in note 9 to the unaudited interim
consolidated financial information. Please refer to Penn West's website at
www.pennwest.com for details of financial instruments currently outstanding.
Outlook
The outlook for oil and natural gas prices remains strong compared to
historical levels. For 2007, we initially budgeted net capital expenditures of
$550 million to $650 million, to fund the drilling of 220 - 250 net wells.
Estimated average 2007 production was forecast between 130,000 boe per day and
132,000 boe per day. Based on a forecast WTI oil price of US$59.00 per barrel,
a $7.25 per mcf natural gas price at AECO and an exchange rate of CAD$1.00
equals USD$0.86 for 2007, cash flow for 2007 was forecast to be between $1.1
billion and $1.4 billion.
Subsequent to the completion of our 2007 budget, our board of directors
approved the $339 million property acquisition announced in February 2007 and
an increase to the budgeted capital program in the Peace River Oil Sands
project to $175 million from $100 million.
Sensitivity Analysis
Estimated sensitivities to selected key assumptions on 2007 financial
results before considering hedging impacts, the property acquisition announced
on February 9, 2007 and the expanded capital program in the Peace River Oil
Sands, are outlined in the table below.
Impact on Impact on
cash flow(1) net income(1)
-------------------------------------------------------------------------
($ millions, except
per unit amounts)
Change of: Change $ millions $/unit $ millions $/unit
-------------------------------------------------------------------------
Price per barrel
of liquids $1.00 22.8 0.10 15.7 0.07
Liquids production 1,000 16.9 0.07 9.3 0.04
bbls/day
Price per mcf of
natural gas $0.10 9.7 0.04 6.7 0.03
Natural gas
production 10 23.1 0.10 12.0 0.05
mmcf/day
Effective interest
rate 1% 13.5 0.06 9.3 0.04
Exchange rate
($USD per $CAD) $0.01 29.4 0.12 20.3 0.09
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(1) The impact on cash flow and net income is computed based on 2007
forecast commodity prices and production volumes. The impact on net
income assumes that the distribution levels are not adjusted for
changes in cash flow thus changing the incremental tax rate.
Contractual Obligations and Commitments
We are committed to certain payments over the next five calendar years as
follows:
($ millions) 2007 2008 2009 2010 2011 Thereafter
-------------------------------------------------------------------------
Transportation $ 20.0 $ 9.2 $ 4.7 $ 1.9 $ - $ -
Transportation
($USD) 2.5 2.3 2.3 2.3 2.3 8.6
Power infrastructure 4.6 3.7 3.7 3.7 3.7 7.6
Drilling rigs 6.9 7.7 2.4 1.2 - -
Purchase
obligations(1) 13.2 13.3 13.3 13.3 13.3 54.3
Office lease $ 12.0 $ 17.9 $ 17.5 $ 15.1 $ 14.3 $ 117.5
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(1) These amounts represent estimated commitments of $95.5 million for
CO2 purchases and $25.2 million for processing fees related to
interests in the Weyburn Unit.
On February 9, 2007, Penn West announced we had entered into an agreement
to acquire conventional oil and natural gas assets. The transaction is
expected to close in March 2007 subject to the satisfaction of certain
conditions, including the rights of first refusal held on certain assets by
working interest parties and the receipt of regulatory approvals. The purchase
price of the asset package, prior to any reductions due to rights of first
refusal, totals approximately $339 million before closing adjustments of an
estimated $12 million, which will reduce the cash outlays on closing.
Our credit facility expires in approximately three years, and if we were
not successful in renewing it or replacing it, we would be required to repay
all amounts then outstanding on the facilities in August 2009. As we maintain
our leverage ratios at relatively modest levels, we believe we will be
successful in renewing or replacing our credit facilities on acceptable terms.
Equity Instruments
-------------------------------------------------------------------------
Trust units issued:
As at December 31, 2006 237,126,219
Issued on exercise of trust unit rights 9,590
Issued to employee savings plan 74,770
Issued pursuant to distribution re-investment plan 450,095
-------------------------------------------------------------------------
As at February 26, 2007 237,660,674
-------------------------------------------------------------------------
Trust unit rights outstanding:
As at December 31, 2006 11,284,872
Granted 3,713,469
Exercised (9,590)
Forfeited (218,100)
-------------------------------------------------------------------------
As at February 26, 2007 14,770,651
-------------------------------------------------------------------------
Disclosure Controls and Procedures
We have established a Disclosure Committee that is responsible for ensuring that our disclosure controls and procedures are designed to provide reasonable assurance that information required to be disclosed by us is recorded, processed, summarized and reported within the time periods specified under Canadian securities laws, and that our controls and procedures are designed to ensure that information is accumulated and communicated to management, including the President and Chief Executive Officer and the Chief Financial Officer, to allow timely decisions regarding required disclosure. Our Disclosure Committee includes selected members of senior management, including the Chief Executive Officer, the Chief Operating Officer and the Chief Financial Officer.
As at December 31, 2006, an evaluation was carried out, under the supervision of the Disclosure Committee and with the participation of management, of the effectiveness of our disclosure controls and procedures as defined under the Multilateral Instrument 52-109. As at December 31, 2006, the design and operating effectiveness of our disclosure controls and procedures were assessed by our Chief Executive Officer and Chief Financial Officer to be operating effectively.
Internal Controls Over Financial Reporting
We have assembled a team of qualified and experienced staff and consultants who have been working on compliance with the applicable regulations regarding internal controls over financial reporting. As we are listed in both Canada and the United States, the recent changes in Canada to remove the requirement for auditor attestation and to extend the timing of CEO/CFO certification of the effective operation of internal controls over financial reporting to 2008 will not affect us. We became a registrant of the U.S. Securities and Exchange Commission and listed on the New York Stock Exchange in June 2006. As a 2006 applicant, we are not required to certify or obtain auditor attestation of the operating effectiveness of our internal controls over financial reporting until we file our 2007 year-end audited financial statements. To date, all significant financial reporting processes have been documented and the resulting changes in internal control over financial reporting are substantially completed. Based on this work to date, no changes were made to our internal controls over financial reporting during the quarter ended December 31, 2006 that materially affected, or would be reasonably likely to materially affect, our internal controls over financial reporting.
Accounting Changes and Pronouncements
Financial Instruments, Other Comprehensive Income
This pronouncement, effective for fiscal year-ends on or after October 1, 2006, addresses when to recognize, and how to measure, a financial instrument on the balance sheet and how gains and losses are to be presented. An additional financial statement, other comprehensive income, is required in certain circumstances. We currently have no items that would create other comprehensive income. The fair value of financial instruments, which are designated as hedges, are to be included on the balance sheet as a financial asset or liability with the related mark-to-market gain or loss recognized in other comprehensive income. Financial instruments, not designated as hedges, will be valued at market with any related gains and losses recognized in income of the period. As we elected to account for all of our derivative financial instruments using the fair value method on July 1, 2005, this required change will have no effect on our reported financial position or net income or loss.
Non-Monetary transactions
Effective January 1, 2006, this accounting pronouncement requires that non-monetary transactions be measured at fair value unless certain conditions apply. This pronouncement did not impact our reported results.
Related-Party Transactions
In 2006, we paid $4.1 million (2005 - $2.1 million) of legal fees to a law firm of which a partner is also one of our directors.
Off-Balance-Sheet Financing
We have off-balance-sheet financing arrangements consisting of operating leases. The details of the operating lease payments are summarized in the Contractual Obligations and Commitments section.
Critical Accounting Estimates
Our significant accounting policies are detailed in note 2 to the unaudited interim consolidated financial information. In the determination of financial results, we must make certain significant accounting estimates as follows:
Full Cost Accounting
We use the full cost method of accounting for oil and natural gas properties. All costs of exploring for and developing oil and natural gas reserves are capitalized and depleted against associated oil and natural gas production using the unit-of-production method based on the estimated proved reserves with forecast commodity pricing.
Our reserves were evaluated by GLJ Petroleum Consultants Ltd., an independent engineering firm. In both 2006 and 2005, our reserves were determined in compliance with National Instrument 51-101. The evaluation of oil and natural gas reserves is, by its nature, based on complex extrapolations and models as well as other significant engineering, capital, pricing and cost assumptions. Reserve estimates are a key component in the calculation of depletion and are a key component of value in the ceiling test. To the extent that the ceiling amount, based in part on our reserves, is less than the carrying amount of property, plant and equipment, a write-down against income must be made. We determined there was no ceiling test write- down required at December 31, 2006.
Asset Retirement Obligations
The discounted, expected future cost of statutory, contractual or legal obligations to retire long-lived assets is recorded as an asset retirement liability with a corresponding increase to the carrying amount of the related asset. The recorded liability increases over time to its future liability amount through accretion charges to earnings, included in DD&A. Revisions to the estimated amount or timing of the obligations are reflected as increases or decreases to our asset retirement obligation. Actual asset retirement expenditures are charged to the liability to the extent of the then-recorded liability. Amounts capitalized to the related assets are amortized to income consistent with the depletion or depreciation of the underlying asset. Note 6 to the unaudited interim consolidated financial information details the impact of these accounting recommendations.
Financial Instruments
Financial instruments, included in the balance sheets, consist of accounts and taxes receivable, the fair value of the derivative financial instruments, current liabilities and the bank loan. The fair values of these financial instruments approximate their carrying amounts due to the short-term maturity of the instruments, the mark to market values recorded for the financial instruments and the market rate of interest applied to the bank loan.
All of our accounts receivable are with customers in the oil and natural gas industry and are subject to normal industry credit risk. We may, from time to time, use various types of financial instruments to reduce our exposure to fluctuating oil and natural gas prices, electricity costs, exchange rates and interest rates. The use of these financial instruments exposes us to credit risks associated with the possible non-performance of counterparties to the derivative contracts. We limit this risk by transacting only with financial institutions with high credit ratings and by obtaining security in certain circumstances.
Our revenues from the sale of crude oil, natural gas liquids and natural gas are directly impacted by changes to the underlying commodity prices. To ensure that cash flows are sufficient to fund planned capital programs and distributions, costless collars or other financial instruments may be utilized. Collars ensure that commodity prices realized will fall into a contracted range for a contracted sales volume. Forward power contracts fix a portion of future electricity costs at levels determined to be economic by management.
Goodwill
Goodwill must be recorded on a business combination when the total purchase consideration exceeds the fair value of the net identifiable assets and liabilities of the acquired entity. The goodwill balance is not amortized, however, it must be assessed for impairment at least annually. Impairment is initially determined based on the fair value of the reporting entity compared to its book value. Any impairment must be charged to income or loss in the period the impairment occurs. We determined there was no goodwill impairment as at December 31, 2006.
Forward-Looking Statements
In the interest of providing Penn West's unitholders and potential investors with information regarding Penn West, including management's assessment of Penn West's 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", "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: the nature of the proposed changes to the taxation of income trusts in Canada, the effects of the proposed changes to investor tax rates in 2011, the impact on our business of the proposed tax changes and the different actions that we might take in response to the proposed tax changes; the stability and growth potential of our asset base; our intention to focus our efforts on our Peace River Oil Sands project and expand the project more rapidly in the future, including the estimated number of wells to be drilled in 2007, estimated 2007 capital expenditures levels and the anticipated nature of those expenditures, our intention to complete the installation of pipeline infrastructure to the main project development area, the daily production target by the end of 2007 and within four years for this project, and the recovery methods anticipated to be employed to attain these targets; our current estimate of the amount of heavy oil resources in place in our Peace River Oil Sands project area and our belief that the potential production and reserve additions for this project could be very significant; the timing for beginning carbon dioxide injection at the Joffre Viking Unit; our intention to continue to add oil, natural gas and electricity hedges; the estimated amount of light oil resources in place in the Pembina field, the amount of such resources that have been recovered to date and the potential to recover additional significant light oil reserves; our intention to expand our Pembina carbon dioxide pilot project to apply horizontal well technology in order to accelerate the production response and thus improve the capital payout timelines; the anticipated timing for the commercial start-up of the Pembina CO2 project; our belief that we can demonstrate an economic, environmentally proactive approach to enhancing recovery from mature, light conventional oil fields and developing our non-conventional oil resources; the amount anticipated to be spent on environmental programs in 2007 and the long-term benefits to be derived therefrom by unitholders; our near-term and long-term business strategies (including risk management strategies) and plans of management, including our intention in 2007 to maintain production volumes, improve capital efficiencies, and continue our efforts toward the realization of the significant and long term benefits the Peace River Oil Sands project and the CO2 Enhanced Recovery projects could provide; our ability to explore for and develop grassroots reserves, and also successfully acquire and optimize producing fields; our intention to create and protect unitholder value by (i) pursuing an active program of internal development (and the focus of such development), (ii) participating in exploration through the farm-out of undeveloped lands, (iii) rationalizing our asset base, and (iv) maintaining a strong balance sheet; our ability to pursue strategies of organic growth through development and optimization, growth through strategic or accretive acquisitions and the farm-out of undeveloped land; our desire to maintain an approximately balanced portfolio of liquids and natural gas production; the existence, operation and strategy of our risk management program, including methods of managing market risks, commodity price risks, credit risks, interest rate risks and foreign currency risks; our intention to retire approximately 10 percent of our opening asset retirement obligation annually using our cash flow; the intended use of proceeds received under the Distribution Reinvestment and Optional Purchase Plan; the methods of funding distributions and maintaining or increasing our productive capacity over the medium and long term; our belief that our current capital programs will be sufficient to maintain our barrel of oil equivalent productive capacity in the medium term; our belief that our philosophy to retire approximately 10 percent of our opening asset retirement obligation on an annual basis is sufficient to fund our asset retirement obligations over the life of our reserves; our belief that our only significant long-term unfunded contractual obligation is for asset retirement obligations; our outlook for oil and natural gas prices; our forecast 2007 net capital expenditures and the number of wells to be drilled; our estimated average 2007 production forecast; our budget for oil prices, natural gas prices and the USD/CAD exchange rate for 2007; our forecast cash flow for 2007; the timing for closing the acquisition announced on February 9, 2007 and the purchase price therefor; our belief that we will be successful in renewing or replacing our credit facilities on acceptable terms when it expires; and the quantity and recoverability of our oil and natural gas reserves and resources.
With respect to forward-looking statements contained in this document, we have made assumptions regarding, among other things: future oil and natural gas prices and differentials between light, medium and heavy oil prices; future oil and natural gas production levels; future exchange rates; the amount of future cash distributions that we intend to pay; the cost of expanding our property holdings; our ability to obtain equipment in a timely manner to carry out development activities; 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; our ability to obtain all necessary approvals required to complete the acquisition announced on February 9, 2007 and to complete the acquisition when expected; and our ability to add production and reserves through our development and exploitation activities.
Although Penn West believes 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 Penn West's 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: volatility in market prices for oil and natural gas; the impact of weather conditions on seasonal demand and ability to execute capital programs; risks inherent in oil and gas operations; uncertainties associated with estimating reserves and resources; competition for, among other things, capital, acquisitions of reserves, resources, undeveloped lands and skilled personnel; incorrect assessments of the value of acquisitions; geological, technical, drilling and processing problems; general economic 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; changes in government regulation of the oil and natural gas industry, including environmental regulation; fluctuations in foreign exchange or interest rates; unanticipated operating events that can reduce production or cause production to be shut-in or delayed; 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 acquisitions, including the merger with Petrofund Energy Trust; failure to obtain required approvals or otherwise complete the acquisition announced on February 9, 2007 on the expected timeline or at all; and the other factors described under "Business Risks" in this document and in Penn West's public filings (including our Annual Information Form) available in Canada at www.sedar.com and in the United States at www.sec.gov. Readers are cautioned that this list of risk factors should not be construed as exhaustive.
The forward-looking statements contained in this document speak only as of the date of this document. Except as expressly required by applicable securities laws, Penn West does 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 its Annual Information Form (when filed), is available on SEDAR at www.sedar.com.
Penn West Energy Trust
Consolidated Balance Sheets
As at As at
December December
($ millions, unaudited) 31, 2006 31, 2005
-------------------------------------------------------------------------
Assets
Current
Accounts receivable $ 268.7 $ 214.4
Risk management (note 9) 54.0 8.5
Other 56.0 29.0
-------------------------------------------------------------------------
378.7 251.9
-------------------------------------------------------------------------
Property, plant and equipment (note 4) 7,039.0 3,715.2
Goodwill (note 3) 652.0 -
-------------------------------------------------------------------------
7,691.0 3,715.2
-------------------------------------------------------------------------
$ 8,069.7 $ 3,967.1
-------------------------------------------------------------------------
Liabilities and unitholders' equity
Current
Accounts payable and accrued liabilities $ 382.9 $ 304.1
Taxes payable 1.2 11.8
Distributions payable 80.6 50.6
Deferred gain on financial instruments (note 9) - 11.9
-------------------------------------------------------------------------
464.7 378.4
-------------------------------------------------------------------------
Bank loan (note 5) 1,285.0 542.0
Asset retirement obligations (note 6) 339.1 192.4
Future income taxes 792.6 682.1
-------------------------------------------------------------------------
2,416.7 1,416.5
-------------------------------------------------------------------------
Unitholders' equity
Unitholders' capital (note 7) 3,712.4 561.0
Contributed surplus (note 7) 16.4 5.5
Retained earnings 1,459.5 1,605.7
-------------------------------------------------------------------------
5,188.3 2,172.2
-------------------------------------------------------------------------
$ 8,069.7 $ 3,967.1
-------------------------------------------------------------------------
See accompanying notes to the unaudited interim consolidated financial
information.
Penn West Energy Trust
Consolidated Statements of Income and Retained Earnings
Three months ended Year ended
December 31 December 31
($ millions, except per -----------------------------------------------
unit amounts, unaudited) 2006 2005 2006 2005
-------------------------------------------------------------------------
Revenues
Oil and natural gas $ 578.5 $ 554.5 $ 2,100.9 $ 1,919.0
Royalties (109.0) (113.1) (373.3) (355.0)
Risk management (note 9) 4.8 (14.8) 42.8 (14.8)
-------------------------------------------------------------------------
474.3 426.6 1,770.4 1,549.2
-------------------------------------------------------------------------
Expenses
Operating 126.9 85.3 426.3 327.4
Transportation 6.1 5.7 24.5 22.7
General and administrative 11.4 6.7 36.0 23.1
Financing 17.8 6.9 49.3 23.2
Depletion, depreciation
and accretion (note 4) 214.6 115.0 654.7 437.6
Equity-based compensation
(note 8) 3.1 3.4 11.3 77.2
Foreign exchange loss - - - 4.5
Risk management
activities (note 9) (10.6) 8.9 (5.8) (11.4)
-------------------------------------------------------------------------
369.3 231.9 1,196.3 904.3
-------------------------------------------------------------------------
Income before taxes 105.0 194.7 574.1 644.9
-------------------------------------------------------------------------
Taxes
Capital 4.0 4.2 14.7 14.7
Current income taxes - - - 54.1
Future income tax
recovery (21.9) (50.6) (106.2) (1.1)
-------------------------------------------------------------------------
(17.9) (46.4) (91.5) 67.7
-------------------------------------------------------------------------
Net income $ 122.9 $ 241.1 $ 665.6 $ 577.2
-------------------------------------------------------------------------
Retained earnings,
beginning of period $ 1,578.1 $ 1,516.4 $ 1,605.7 $ 1,393.7
Net income 122.9 241.1 665.6 577.2
Trust conversion costs - - - (32.9)
Distributions declared (241.5) (151.8) (811.8) (321.5)
Dividends declared - - - (10.8)
-------------------------------------------------------------------------
Retained earnings,
end of period $ 1,459.5 $ 1,605.7 $ 1,459.5 $ 1,605.7
-------------------------------------------------------------------------
Net income per unit
Basic $ 0.44 $ 1.48 $ 3.32 $ 3.55
Diluted $ 0.44 $ 1.46 $ 3.27 $ 3.48
-------------------------------------------------------------------------
See accompanying notes to the unaudited interim consolidated financial
information.
Penn West Energy Trust
Consolidated Statements of Cash Flows
Three months ended Year ended
December 31 December 31
-----------------------------------------------
($ millions, unaudited) 2006 2005 2006 2005
-------------------------------------------------------------------------
Operating activities
Net income $ 122.9 $ 241.1 $ 665.6 $ 577.2
Depletion, depreciation
and accretion (note 4) 214.6 115.0 654.7 437.6
Future income tax
recovery (21.9) (50.6) (106.2) (1.1)
Unrealized foreign
exchange loss - - - 4.5
Equity-based
compensation (note 8) 3.1 3.4 11.3 77.2
Risk management (note 9) (15.4) 23.7 (48.6) 3.4
Payments for surrendered
options - - - (141.6)
Asset retirement
expenditures (9.3) (6.3) (26.9) (22.6)
Change in non-cash
working capital (32.9) 42.4 (43.6) (1.8)
-------------------------------------------------------------------------
261.1 368.7 1,106.3 932.8
-------------------------------------------------------------------------
Investing activities
Additions to property,
plant and equipment, net (159.4) (6.3) (577.9) (456.7)
Petrofund merger costs 4.0 - (25.0) -
Change in non-cash
working capital (28.3) 15.0 11.7 (63.2)
-------------------------------------------------------------------------
(183.7) 8.7 (591.2) (519.9)
-------------------------------------------------------------------------
Financing activities
Increase (decrease)
in bank loan 132.6 (236.2) 132.6 (51.4)
Issue of equity 31.3 2.4 118.6 23.7
Distributions/dividends
paid (241.3) (143.6) (781.8) (288.4)
Trust conversion costs - - - (36.3)
Realized foreign
exchange gain - - - 85.8
Settlement of future
income tax liabilities
on trust conversion - - 15.5 (146.3)
-------------------------------------------------------------------------
(77.4) (377.4) (515.1) (412.9)
-------------------------------------------------------------------------
Change in cash - - - -
Cash, beginning of period - - - -
-------------------------------------------------------------------------
Cash, end of period $ - $ - $ - $ -
-------------------------------------------------------------------------
Interest paid $ 14.5 $ 6.3 $ 44.4 $ 22.9
Income and capital
taxes paid $ 0.9 $ 15.4 $ 8.6 $ 241.2
-------------------------------------------------------------------------
See accompanying notes to the unaudited interim consolidated financial
information.
Notes to the Unaudited Interim Consolidated Financial Information
(All tabular amounts are in $ millions except numbers of units, per unit
amounts, percentages and various figures in Note 9.)
1. Structure of Penn West
On May 31, 2005, Penn West Petroleum Ltd. (the "Company") was reorganized
into Penn West Energy Trust ("Penn West" or "the Trust") under a plan of
arrangement entered into by Penn West and the Company and its
shareholders. Shareholders received three trust units for each common
share held. On June 2, 2005, the trust units commenced trading on the TSX
under the symbol "PWT.UN". On June 22, 2006, the trust units commenced
trading on the NYSE under the symbol "PWE".
Penn West is an open-ended, unincorporated investment trust governed by
the laws of the Province of Alberta. The purpose of Penn West is to
indirectly explore for, develop and hold interests in petroleum and
natural gas properties through investments in securities of subsidiaries
and royalty interests in oil and natural gas properties. Penn West owns
100 percent of the common shares, directly or indirectly, of the entities
that carry on the oil and natural gas business of Penn West. The
activities of these entities are financed through interest-bearing notes
from Penn West and third-party debt as described in the notes to the
unaudited interim consolidated financial information.
Pursuant to the terms of net profit interest agreements (the "NPIs"),
Penn West is entitled to payments from certain subsidiary entities equal
to essentially all of the proceeds of the sale of oil and natural gas
production less certain specified deductions. Under the terms of the
NPIs, the deductions are in part discretionary, include the requirement
to fund capital expenditures and asset acquisitions, and are subject to
certain adjustments for asset dispositions.
Under the terms of its trust indenture, Penn West is required to make
distributions to unitholders in amounts at least equal to its taxable
income consisting of interest on notes, the NPIs, and any inter-corporate
distributions and dividends received, less certain expenses.
2. Significant accounting policies and basis of presentation
This unaudited interim consolidated financial information has been
prepared in accordance with Canadian generally accepted accounting
principles and is consistent with the accounting policies described in
the notes to the audited consolidated financial statements of Penn West
for the year ended December 31, 2005. This financial information should
accordingly be read in conjunction with Penn West's audited consolidated
financial statements and notes thereto for the year ended December 31,
2005. This unaudited interim consolidated financial information has been
prepared on a continuity of interests basis as if Penn West historically
carried on the business of the Company prior to the trust conversion. The
consolidated financial statements included the accounts of the Company
and its subsidiaries and partnerships prior to the trust conversion.
After the trust conversion, the consolidated financial statements and
information include the accounts of Penn West, its subsidiaries and
partnerships.
Petrofund Merger
The business combination of Penn West and Petrofund Energy Trust
("Petrofund") was accounted for using the purchase method of accounting
with Penn West acquiring Petrofund effective June 30, 2006.
Goodwill
Goodwill is recorded on a business combination when the total purchase
consideration exceeds the fair value of the net identifiable assets and
liabilities of the acquired entity. Goodwill is not amortized and the
balance is assessed for impairment on an annual basis or more frequently
if circumstances arise that would likely indicate impairment.
The impairment test consists of two steps. First, the fair value of the
reporting entity is compared to its carrying amount, including goodwill,
to identify a potential impairment. If the fair value is greater than the
carrying amount, goodwill is considered not to be impaired and the second
step is not necessary. When the carrying amount exceeds the fair value,
the second step requires the implied fair value of the goodwill to be
compared to its carrying amount. The implied fair value of goodwill is
computed by assigning fair values to the identifiable assets and
liabilities of the reporting entity as if it had been acquired in a
business combination. If the carrying amount of goodwill exceeds its
implied fair value, an impairment loss equal to the excess is recognized
in the period.
3. Merger with Petrofund
Penn West and Petrofund merged effective June 30, 2006 pursuant to a plan
of arrangement (the "Arrangement"). Under the terms of the Arrangement,
Petrofund unitholders received 0.6 Penn West units for each Petrofund
unit exchanged and a special distribution of $1.00 per unit plus
$0.10 per unit to align the distribution dates of the trusts. Penn West
accounted for the merger as an acquisition of Petrofund by Penn West
using the purchase method of accounting. This consolidated financial
information of Penn West includes the results of operations and cash
flows of Petrofund from July 1, 2006 forward. The allocation of the
consideration paid to the fair value of the identifiable assets and
liabilities follows:
Purchase Price
-------------------------------------------------------------------------
70.7 million Penn West trust units issued $ 3,032.4
Transaction costs 25.0
-------------------------------------------------------------------------
$ 3,057.4
-------------------------------------------------------------------------
Allocation of the Purchase Price
-------------------------------------------------------------------------
Property, plant and equipment $ 3,323.3
Working capital (deficiency) (10.0)
Bank loan (610.4)
Future income taxes (199.5)
Asset retirement obligations (98.0)
Goodwill 652.0
-------------------------------------------------------------------------
$ 3,057.4
-------------------------------------------------------------------------
4. Property, plant and equipment
December December
31, 2006 31, 2005
-------------------------------------------------------------------------
Oil and natural gas properties, including
production and processing equipment $ 9,666.0 $ 5,710.4
Other 17.2 14.0
-------------------------------------------------------------------------
9,683.2 5,724.4
-------------------------------------------------------------------------
Accumulated depletion and depreciation (2,549.1) (1,925.4)
Accumulated gas plant depreciation (95.1) (83.8)
-------------------------------------------------------------------------
(2,644.2) (2,009.2)
-------------------------------------------------------------------------
Net book value $ 7,039.0 $ 3,715.2
-------------------------------------------------------------------------
Other than Penn West's net share of capital overhead recoveries, no
general and administrative expenses are capitalized. In 2006, additions
to property, plant and equipment included a $55.9 million increase
related to additions to and changes in estimates related to asset
retirement obligations and a $1.7 million addition for future income
taxes recorded on minor property acquisitions.
An impairment test was performed on the costs capitalized to oil and
natural gas properties at December 31, 2006. The estimated undiscounted
future net cash flows from proved reserves, using forecast prices,
exceeded the carrying amount of the oil and natural gas property
interests and the cost of unproved properties.
5. Bank loan
December December
31, 2006 31, 2005
-------------------------------------------------------------------------
Bankers' acceptances and prime rate loans $ 1,285.0 $ 542.0
-------------------------------------------------------------------------
As at December 31, 2006, the Company had an unsecured, extendible,
three-year revolving syndicated credit facility with an aggregate
borrowing limit of $1.8 billion plus a $100 million swing line facility,
both of which expire on August 25, 2009. 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.
Letters of credit totaling $0.4 million (December 31, 2005 - $9 million)
were outstanding on December 31, 2006 that reduced the amount otherwise
available to be drawn on the swing line facility.
6. Asset retirement obligations
The total uninflated and undiscounted amount to settle Penn West's asset
retirement obligations at December 31, 2006 was $1.3 billion
(December 31, 2005 - $0.8 billion). The asset retirement obligation was
determined by applying an inflation factor of 2.0 percent (2005 -
1.7 percent) and the inflated amount was discounted using a credit-
adjusted rate of 7.0 percent (2005 - 7.5 percent) over the expected
useful life of the underlying assets, currently extending up to 50 years
into the future with an average life of 23 years. Future cash flows from
operating activities are expected to fund the obligations.
Changes to asset retirement obligations were as follows:
2006 2005
-------------------------------------------------------------------------
Balance, beginning of period $ 192.4 $ 180.7
Liabilities incurred during the period 30.2 9.8
Petrofund liabilities assumed on acquisition 98.0 -
Increase in liability due to change in estimates 25.7 3.4
Liabilities settled during the period (26.9) (22.6)
Accretion charges 19.7 21.1
-------------------------------------------------------------------------
Balance, end of period $ 339.1 $ 192.4
-------------------------------------------------------------------------
7. Unitholders' equity
Unitholders' capital Units Amount
-------------------------------------------------------------------------
Issued to settlor for cash, April 22, 2005 1,250 $ -
Exchanged for Penn West shares, May 31, 2005 163,137,018 556.1
Issued to employee trust unit savings plan 151,745 4.9
-------------------------------------------------------------------------
Balance, December 31, 2005 163,290,013 561.0
Issued on exercise of trust unit rights 407,750 10.6
Issued to employee trust unit savings plan 295,449 12.3
Issued to distribution reinvestment plan 2,459,870 96.1
Issued on Petrofund merger 70,673,137 3,032.4
-------------------------------------------------------------------------
Balance, December 31, 2006 237,126,219 $ 3,712.4
-------------------------------------------------------------------------
Contributed surplus 2006 2005
-------------------------------------------------------------------------
Balance, beginning of period $ 5.5 $ -
Equity-based compensation expense 11.3 5.5
Net benefit on rights exercised(1) (0.4) -
-------------------------------------------------------------------------
Balance, end of period $ 16.4 $ 5.5
-------------------------------------------------------------------------
(1) Upon exercise of trust unit rights, the net benefit is reflected as a
reduction of contributed surplus and an increase to unitholders'
capital.
Three months ended Year ended
Units Outstanding December 31 December 31
(millions of units) 2006 2005 2006 2005
-------------------------------------------------------------------------
Weighted average:
Basic 236.7 163.3 200.8 162.6
Diluted 239.5 166.5 203.5 165.9
Outstanding:
(as at December 31)
Basic 237.1 163.3
Basic plus trust unit rights 248.4 172.7
-------------------------------------------------------------------------
8. Equity-based compensation
Trust unit rights incentive plan
On the close of the trust conversion in May 2005, Penn West implemented a
unit rights incentive plan that allows Penn West to issue rights to
acquire trust units to directors, officers, employees and other service
providers. Under the terms of the plan, the number of trust units
reserved for issuance shall not exceed 10 percent of the aggregate number
of issued and outstanding trust units of Penn West. Unit right exercise
prices are administrated to be equal to the volume-weighted average
trading price of the trust units on the Toronto Stock Exchange for the
five trading days immediately prior to the date upon which the unit
rights are granted. If certain conditions are met, the exercise price per
unit may be reduced by deducting from the grant price the aggregate of
all monthly distributions, on a per unit basis, paid by Penn West after
the grant date. Rights granted under the plan prior to November 13, 2006
vest over a five-year period and expire six years after the date of the
grant. Rights granted subsequent to this date vest over a three-year
period and expire four years after the date of the grant.
Year ended Year ended
December 31, 2006 December 31, 2005
-----------------------------------------------
Weighted Weighted
Number average Number average
of unit exercise of unit exercise
Trust unit rights rights price rights price
-------------------------------------------------------------------------
Outstanding, beginning
of period 9,447,625 $ 28.45 - $ -
Granted 3,257,622 39.77 10,045,325 29.73
Exercised (407,750) 24.65 - -
Forfeited (1,012,625) 33.38 (597,700) 28.46
-------------------------------------------------------------------------
Balance before reduction
of exercise price 11,284,872 30.89 9,447,625 29.81
Reduction of exercise
price for distributions
paid - (3.13) - (1.36)
-------------------------------------------------------------------------
Outstanding,
end of period 11,284,872 $ 27.76 9,447,625 $ 28.45
-------------------------------------------------------------------------
Exercisable,
end of period 1,125,300 $ 23.16 - $ -
-------------------------------------------------------------------------
Penn West recorded compensation expense of $11.3 million for the year
ended December 31, 2006 (2005 - $5.5 million). Compensation expense
subsequent to the trust conversion is based on the fair value of rights
issued and is amortized over the remaining vesting periods on a
straight-line basis.
During the year, Penn West adopted the recommendations in Emerging Issues
Committee Abstract 162, "Stock-based compensation for employees eligible
to retire before the vesting date". The recommendation requires early
recognition of compensation expense for employees eligible to retire or
for employees who will become eligible to retire during the vesting
period. The adoption of these recommendations did not affect reported
compensation expense.
The Binomial Lattice option-pricing model was used to determine the fair
value of trust unit rights granted with the following weighted average
assumptions:
Five-year Three-year
vesting vesting
Three months ended December 31, 2006(1) period period
-------------------------------------------------------------------------
Average fair value of trust unit rights
granted (per unit) $ 6.98 $ 7.18
Expected life of trust unit rights (years) 4.5 3.0
Expected volatility (average) 25.5% 25.5%
Risk-free rate of return (average) 3.9% 3.9%
Distribution yield 11.5% 11.5%
-------------------------------------------------------------------------
(1) Rights granted prior to November 13, 2006 vest over a five-year
period. Rights granted subsequent to November 13, 2006 vest over a
three-year period.
Trust unit savings plan
Penn West has an employee trust unit savings plan for the benefit of all
employees. Under the savings plan, employees may elect to contribute up
to 10 percent of their salary. Penn West matches employee contributions
at a rate of $1.50 for each $1.00. Both the employee's and Penn West's
contribution are used to acquire Penn West trust units. These trust units
may be issued from treasury at the five-day volume weighted average
month-end trading price on the Toronto Stock Exchange or purchased in the
open market.
9. Financial instruments
Effective July 1, 2005, Penn West elected to discontinue the designation
of financial instruments as hedges, choosing to account for these
instruments using the fair value method. In accordance with the
transitional accounting recommendations, the fair value of power
contracts at July 1, 2005 in the amount of $16.7 million was recorded as
a deferred gain and was taken into income over the remaining life of the
contracts. Changes in the fair value of all outstanding financial
commodity, power and interest rate contracts are reflected on the balance
sheet with a corresponding unrealized gain or loss in income.
The following table reconciles the changes in the fair value of financial
instruments no longer designated as hedges:
Risk management December 31, 2006
-------------------------------------------------------------------------
Balance, December 31, 2005 $ 8.5
Unrealized gain on financial instruments:
Commodities 51.3
Electricity contracts (5.6)
Interest rate swaps (0.2)
-------------------------------------------------------------------------
Fair value, end of period $ 54.0
-------------------------------------------------------------------------
Deferred gain on financial instruments
Balance, December 31, 2005 $ (11.9)
Amortization 11.9
-------------------------------------------------------------------------
Ending balance $ -
-------------------------------------------------------------------------
Penn West had the following financial instruments outstanding as at
December 31, 2006:
Notional Remaining
volume term Pricing Market value
-------------------------------------------------------------------------
Crude oil
WTI Costless 3,000 Jan/07 US$ 56.67 to
Collars bbls/d - Mar/07 $84.28/bbl $ 0.2
WTI Costless 1,000 Jan/07 US$ 60.00 to
Collars bbls/d - Jun/07 $73.10/bbl 0.2
WTI Costless 1,000 Apr/07 US$ 60.00 to
Collars bbls/d - Jun/07 $80.00/bbl 0.2
WTI Costless 25,000 Jan/07 US$ 56.00 to
Collars bbls/d - Dec/07 $83.80/bbl 7.9
WTI Costless 10,000 Jan/08 US$ 60.00 to
Collars bbls/d - Jun/08 $94.55/bbl 6.2
Natural gas
AECO Costless 9,200 Jan/07 $9.18 to
Collars mcf/d - Mar/07 $12.97/mcf 1.0
AECO Costless 73,400 Jan/07 $7.63 to
Collars mcf/d - Oct/07 $9.68/mcf 20.8
Electricity
Alberta Power
Pool Swaps 67 MW 2007 $49.55/MWh 17.3
Alberta Power
Pool Swaps 2 MW 2008 $57.00/MWh 0.4
Interest rate Jan/07
swaps $100.0 - Mar/08 4.356% (0.2)
-------------------------------------------------------------------------
Total $ 54.0
-------------------------------------------------------------------------
10. Income taxes
In the second quarter of 2006, a $74 million future income tax rate
recovery was recorded to reflect corporate income tax rate reductions
substantively enacted by the federal, Alberta and Saskatchewan
governments.
On October 31, 2006, the Government of Canada announced a proposed new
distribution tax on publicly traded income trusts. Under the proposed
rules, effective for the 2011 tax year, distributions representing return
on capital would no longer be deductible for income tax purposes by
certain publicly traded income trusts, including Penn West, and would be
taxed on the amount of the distribution at an estimated corporate tax
rate. To date, the tax proposals have not been substantively enacted and
the impact on Penn West's organizational structure or current and future
income taxes is not currently determinable.
11. Related-party transactions
During 2006, Penn West paid $4.1 million (2005 - $ 2.1 million) of legal
fees to a law firm of which a partner is also a director of Penn West.
12. Subsequent event
On February 9, 2007, Penn West announced it had entered into an agreement
to acquire conventional oil and natural gas assets. The transaction is
expected to close in March 2007 subject to the satisfaction of certain
conditions, including the rights of first refusal held on certain assets
by working interest parties and the receipt of regulatory approvals. The
purchase price of the asset package, prior to any reductions due to
rights of first refusal, totals approximately $339 million before closing
adjustments of an estimated $12 million, which will reduce the cash
outlays on closing.
Investor Information
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Penn West Energy Trust is a senior oil and natural gas income trust based in Calgary, Alberta that trades on the Toronto Stock Exchange under the symbol PWT.UN and on the New York Stock Exchange under the symbol PWE.
A conference call will be held to discuss Penn West's results at 9:00 a.m. Mountain Standard Time, 11:00 a.m. Eastern Standard Time on Tuesday, February 27, 2007. The North American conference call number is 800-733-7571 toll-free or 416-644-3423 in the Toronto area. A taped recording will be available until March 7, by dialing 877-289-8525 or 416-640-1917 and entering pass code 21216568 followed by the number sign. This call will be broadcast live on the Internet and may be accessed directly on the Penn West website www.pennwest.com or at the following URL: http://www.newswire.ca/en/webcast/viewEvent.cgi?eventID(equal sign)1707200.
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