Exhibit
99.2





MANAGEMENT’S
DISCUSSION AND ANALYSIS


For the
year ended December 31, 2009
 
 
 
 This
management’s discussion and analysis (“MD&A”) of financial conditions and
results of operations should be read in conjunction with the audited
consolidated financial statements and accompanying notes of Penn West Energy
Trust (“Penn West”, “We” or “Our”) for the years ended December 31, 2009 and
2008. The date of this MD&A is March 18, 2010.
 
 For
additional information, including Penn West’s audited consolidated financial
statements and Annual Information Form, please go to our website at www.pennwest.com, in
Canada at www.sedar.com or in
the United States at www.sec.gov.
 
 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, particularly if used in isolation as it is
based on an energy equivalency conversion method primarily applicable at the
burner tip and does not represent a value equivalency at the wellhead. The aggregate of the
exploration and development costs incurred in the most recent financial year and
the change during that year in estimated future development costs generally will
not reflect total finding and development costs related to reserves additions
for that year.
 
 Measures
including funds flow, funds flow per unit-basic, funds flow per unit-diluted,
netback, payout ratio, recycle ratio, net debt, return on equity and return on
capital included in this MD&A are not defined in generally accepted
accounting principles (“GAAP”) and do not have a standardized meaning prescribed
by GAAP; accordingly, they may not be comparable to similar measures provided by
other issuers. Penn West utilizes funds flow and netbacks to assess financial
performance, to allocate its capital among alternative projects, to economically
rank projects and to assess its capacity to fund distributions and future
capital programs. Refer to “Netbacks” below. Payout ratio is calculated as
distributions paid divided by funds flow which is used to assess the adequacy of
retained funds flow to finance capital programs. Recycle ratio is calculated as
netback divided by the capital cost of reserve replacements which is one of our
measures to ensure our capital programs are adding reserves at an economic cost.
Net debt is the sum of long-term debt, convertible debentures and working
capital (excluding risk management and future income taxes) and is used to
assess our leverage levels and hence the continuing appropriateness of our
distribution and capital investment levels. Return on equity is the rate of
return calculated by comparing net income to unitholders equity. Return on
capital is calculated using net income and financing charges compared to
unitholder equity and long-term debt and is used to assess how economically Penn
West is utilizing its capital. Reconciliations of funds flow to its nearest
measure prescribed by GAAP are provided below. See “Performance Indicators”
below.
 
 Calculation
of Funds Flow
 
 Year
      ended December 31(millions,
      except per unit amounts)
              
              2009
              
              
              2008Cash
      flow from operating activities
              
              $
              1,401
              
              
              $
              2,256Increase
      in non-cash working capital
              
              
              27
              
              
              
              196Asset
      retirement expenditures
              
              
              65
              
              
              
              85Funds
      flow
              
              $
              1,493
              
              
              $
              2,537Basic
      per unit
              
              $
              3.62
              
              
              $
              6.75Diluted
      per unit
              
              $
              3.60
              
              
              $
              6.66
 
 Funds
flow for the year ended December 31, 2009 includes realized gains of $75 million
(2008 - $nil) on foreign exchange forward contracts related to oil collars
recorded in the second quarter of 2009.
  1
  Annual
Financial Summary
 
 Year
      ended December 31(millions,
      except per unit amounts)
              
              2009
              
              
              2008
              
              
              2007Gross
      revenues (1)
              
              $
              3,203
              
              
              $
              4,651
              
              
              $
              2,462Funds
      flow
              
              
              1,493
              
              
              
              2,537
              
              
              
              1,332Basic
      per unit
              
              
              3.62
              
              
              
              6.75
              
              
              
              5.56Diluted
      per unit
              
              
              3.60
              
              
              
              6.66
              
              
              
              5.51Net
      income (loss)
              
              
              (144
              )
              
              
              1,221
              
              
              
              175Basic
      per unit
              
              
              (0.35
              )
              
              
              3.25
              
              
              
              0.73Diluted
      per unit
              
              
              (0.35
              )
              
              
              3.22
              
              
              
              0.73Capital
      expenditures (2)
              
              
              319
              
              
              
              1,045
              
              
              
              1,119Long-term
      debt at year-end
              
              
              3,219
              
              
              
              3,854
              
              
              
              1,943Convertible
      debentures
              
              
              273
              
              
              
              296
              
              
              
              -Distributions
      paid (3)
              
              
              910
              
              
              
              1,500
              
              
              
              976Total
      assets
              
              $
              13,876
              
              
              $
              15,412
              
              
              $
              8,433
 
 (1)
              Gross
      revenues include realized gains and losses on commodity
      contracts.
 (2)
              Excludes
      business combinations and includes net proceeds on property acquisitions
      and dispositions.
 (3)
              Includes
      distributions paid and reinvested in trust units under the distribution
      reinvestment plan.
 
 Annual
2009 Highlights
 
 Key
financial and operational results for the year ended 2009 were as
follows:
 
 ·
              Production
      for 2009 averaged 177,221 boe per day which exceeded our guidance of
      approximately 171,500 to 176,500 boe per day, both net of property
      dispositions which averaged approximately 3,500 boe per
      day.
 ·
              For
      2009 proved plus probable finding and development costs, excluding future
      development capital, were $13.75 per boe (2008 - $18.94, 2007 - $29.43)
      with a recycle ratio of 1.9 (2008 - 2.1, 2007 - 1.1). Over ninety percent
      of proved plus probable reserve additions from development activities were
      oil.
 ·
              Net debt was reduced
      by approximately $822 million in 2009. In the first quarter of
      2010, net debt was reduced by a further $434 million from the net cash
      proceeds received in the previously announced property swap, bringing the
      total reduction to $1.3 billion since January 1,
  2009.
 ·
              Unused
      credit capacity on our bank facility at December 31, 2009 was $1.4
      billion.
 ·
              Development
      capital expenditures for 2009, excluding net asset dispositions, totalled
      $688 million compared to $1,095 million in 2008. Additionally in 2009, we
      had $369 million of net property dispositions (2008 - $50 million, 2007 -
      $422 million acquisitions) and $116 million of business combinations (2008
      - $5,525 million, 2007 - $21 million) for total expenditures of $435
      million (2008 - $6,570 million, 2007 - $1,140 million). The reduction to
      our 2009 capital program compared to 2008 was primarily in response to
      lower commodity prices in 2009.
 ·
              Funds
      flow in 2009 was $1,493 million compared to $2,537 million in 2008 and
      $1,332 million in 2007. The decrease in 2009 was primarily due to lower
      commodity prices in 2009 compared to the prior
  year.
 ·
              Net
      loss for 2009 totalled $144 million compared to net income of $1,221
      million in 2008 and net income of $175 million in 2007. The decline in
      2009 was primarily due to lower revenues as a result of weaker commodity
      prices and an increase in unrealized risk management
    losses.
 ·
              Netbacks
      for 2009 were $26.32 per boe compared to $39.85 per boe in 2008 and $31.51
      per boe in 2007. The decline resulted from lower commodity prices for most
      of 2009.
 ·
              Distribution levels
      are currently set at $0.15 per unit, per monthfor each of March
      and April 2010 subject to maintenance of current forecasts of commodity
      prices, production levels and capital
budget.
  2
  Quarterly
Financial Summary
 (millions,
except per unit and production amounts)
 
 Three
      months ended
              
              Dec 31
      2009
              
              
              Sept 30
      2009
              
              
              June 30
      2009
              
              
              Mar 31
      2009
              
              
              Dec 31
      2008
              
              
              Sept 30
      2008
              
              
              June 30
      2008
              
              
              Mar 31
      2008Gross
      revenues (1)
              
              $
              831
              
              
              $
              800
              
              
              $
              791
              
              
              $
              781
              
              
              $
              968
              
              
              $
              1,235
              
              
              $
              1,312
              
              
              $
              1,136Funds
      flow
              
              
              366
              
              
              
              349
              
              
              
              430
              
              
              
              348
              
              
              
              490
              
              
              
              662
              
              
              
              753
              
              
              
              632Basic
      per unit
              
              
              0.87
              
              
              
              0.84
              
              
              
              1.05
              
              
              
              0.87
              
              
              
              1.27
              
              
              
              1.73
              
              
              
              2.00
              
              
              
              1.76Diluted
      per unit
              
              
              0.86
              
              
              
              0.83
              
              
              
              1.05
              
              
              
              0.87
              
              
              
              1.26
              
              
              
              1.71
              
              
              
              1.98
              
              
              
              1.75Net
      income (loss)
              
              
              (12
              )
              
              
              7
              
              
              
              (41
              )
              
              
              (98
              )
              
              
              404
              
              
              
              1,062
              
              
              
              (323
              )
              
              
              78Basic
      per unit
              
              
              (0.03
              )
              
              
              0.02
              
              
              
              (0.10
              )
              
              
              (0.25
              )
              
              
              1.05
              
              
              
              2.78
              
              
              
              (0.86
              )
              
              
              0.22Diluted
      per unit
              
              
              (0.03
              )
              
              
              0.02
              
              
              
              (0.10
              )
              
              
              (0.25
              )
              
              
              1.04
              
              
              
              2.73
              
              
              
              (0.86
              )
              
              
              0.22Distributions
      declared
              
              
              189
              
              
              
              188
              
              
              
              188
              
              
              
              276
              
              
              
              393
              
              
              
              391
              
              
              
              384
              
              
              
              382Per
      unit
              
              $
              0.45
              
              
              $
              0.45
              
              
              $
              0.45
              
              
              $
              0.69
              
              
              $
              1.02
              
              
              $
              1.02
              
              
              $
              1.02
              
              
              $
              1.02ProductionLiquids
      (bbls/d) (2)
              
              
              101,636
              
              
              
              104,583
              
              
              
              104,070
              
              
              
              105,643
              
              
              
              105,644
              
              
              
              106,898
              
              
              
              109,417
              
              
              
              109,016Natural
      gas (mmcf/d)
              
              
              411
              
              
              
              441
              
              
              
              459
              
              
              
              447
              
              
              
              476
              
              
              
              500
              
              
              
              487
              
              
              
              500Total
      (boe/d)
              
              
              170,164
              
              
              
              178,124
              
              
              
              180,601
              
              
              
              180,096
              
              
              
              184,908
              
              
              
              190,177
              
              
              
              190,515
              
              
              
              192,291
 
 (1)
              Gross
      revenues include realized gains and losses on commodity
      contracts.
 (2)
              Includes
      crude oil and natural gas liquids.
 
 Financial
Markets
 
 Recovery
in the financial, credit and commodity markets began in mid-2009 as the
financial crisis started to subside. Activity in the equity and debt capital
markets increased throughout the year and into 2010 as investors became more
optimistic about the economy and eager to invest low yielding cash investments
into higher return prospects. Crude oil markets steadily improved after the
spring of 2009 as WTI reached highs over US$80.00 per barrel while the spot
price of natural gas fell throughout the year before rising again to reach close
to AECO $5.70 per GJ during the month of December. The outlook for commodity
markets in 2010 and the continued success in applying horizontal multi-fracture
technology contributed to the increase to Penn West’s capital budget for 2010 to
$700 million to $850 million. Penn West will invest approximately 75 percent of
this capital on further development on certain of its key resource
properties.
 
 Penn West
continued to improve its financial flexibility throughout 2009 to enable higher
levels of capital investment in 2010 and to capitalize on weaker market
conditions. Penn West believes these actions further support its strategy to
convert to an exploration and development corporation, with a growth and yield
component for its equity holders, by mid-2011. During 2009 and into early 2010,
we completed the following significant transactions aimed at consolidating our
core areas and strengthening our balance sheet:
 
 -
              In
      March 2010, Penn West closed a private placement of senior unsecured notes
      with an aggregate principal amount of approximately US$250 million and
      CAD$50 million.
 -
              In
      December 2009, Penn West announced an asset swap that increased its
      position in its Pembina and Dodsland light-oil plays in exchange for
      certain interests in the Leitchville area. The transaction closed in
      January 2010 and included net proceeds of $434 million which were used to
      reduce bank debt.
 -
              In
      November 2009, Penn West closed a property sale of approximately 6,000 boe
      per day in the Lloydminster area. The proceeds of this transaction were
      used to reduce bank debt.
 -
              In
      May 2009, Penn West further diversified its debt structure by completing a
      private placement of senior unsecured notes with an aggregate principal
      amount of approximately $238
million.
 -
              In
      February 2009, Penn West completed a bought-deal equity issue for total
      proceeds of approximately $250 million ($238 million net) which were
      applied to reduce bank debt.
 -
              The
      distribution level was reduced to $0.23 per unit effective with the
      January 2009 distribution paid in February 2009 and reduced further to
      $0.15 per unit for the April 2009 distribution paid in May
      2009.
  3
  These
transactions have strengthened our balance sheet and diversified our debt
capital portfolio. Since the close of the acquisition of Canetic Resources Trust
(“Canetic”) in January 2008, net debt inclusive of the above noted asset swap
has been reduced by more than $1.4 billion. This enables us to again consider
potential attractive growth opportunities as they become available and to
allocate more dollars to our capital program in order to increase reserves and
production from the application of new completions technologies to our asset
base.
 
 Commodity
Markets
 
 Business
Environment
 
 The
global recession had a significant impact on crude oil demand in 2009. Oil
prices started 2009 near their 2008 lows and then steadily improved. The
recession resulted in the second consecutive year of declining demand for crude
oil. Some economists believe the recession has ended in North America; however,
others believe the economic recovery is still fragile. In contrast, China and
other Asian economies appear to be moving out of the recession at a faster pace
than developed countries and many forecast this will result in an increase in
global oil demand during 2010. Constraints on capital spending by Non-OPEC oil
producers will likely keep supply from increasing which could cause OPEC’s spare
capacity to diminish over the foreseeable future thereby providing support for
prices to remain at least at current levels.
 
 In
contrast to crude oil, natural gas prices generally declined over most of 2009
before recovering somewhat in the fourth quarter. The demand for natural gas in
North America was negatively impacted by the global recession, most specifically
by lower demand from the U.S. industrial sector. This was partially offset by
higher gas demand for power generation as low gas prices resulted in natural gas
gaining market share from coal. The expected decline in natural gas supply, as a
result of capital constraints and lower drilling activity, did not take effect
as quickly as some forecasters anticipated. This resulted in natural gas
inventory levels reaching an all time high prior to commencement of this year’s
winter heating season. Cold North American weather near the end of 2009
increased the demand for natural gas and drew storage levels down to more normal
levels which resulted in higher prices late in the year.
 
 Crude
Oil
 
 In 2009,
WTI crude oil prices averaged US$61.93 per barrel compared to US$99.66 per
barrel in 2008. Penn West’s corporate average price benefitted throughout the
year from historically tight quality and transportation differentials for
Canadian heavy and sour crudes compared to WTI. Recent growth in complex
refining capabilities in the U.S. along with declining supplies of heavy and
sour crudes from other suppliers such as Mexico and Venezuela are expected to
keep quality differentials at narrow levels for the foreseeable future. Penn
West’s average crude oil and liquids price for 2009 before the impact of the
realized portion of risk management was $57.74 per barrel.
 
 Currently,
Penn West has approximately 35 percent of its crude oil production hedged
between US$60.11 per barrel and US$75.72 per barrel for 2010.
 
 Natural
Gas
 
 In 2009,
the AECO Monthly Index averaged $3.91 per GJ compared to $7.71 per GJ in 2008.
Extremely cold North American weather in December 2009 and early January 2010
resulted in a decline in natural gas inventory levels from record highs in 2009
to more normal levels. Supply also appears to be down year over year due to
restricted capital programs and lower drilling activity. Currently, demand for
2010 is forecasted to be relatively flat compared to 2009. Penn West’s corporate
average gas price for 2009 before the impact of the realized portion of risk
management was $4.13 per mcf.
 
 For 2010,
Penn West has approximately 17 percent of its natural gas production hedged
between $6.01 per GJ and $8.29 per GJ.
  4
  Performance
Indicators
 
 Penn
West’s management and Board of Directors assess our performance based upon a
number of qualitative and quantitative factors including:
 
 -
              Recycle
      ratio – This is calculated based on our netback divided by finding and
      development (“F&D”) costs.
 -
              Base
      operations – This includes our production performance and execution of our
      operational, health, safety, environmental and regulatory
      programs.
 -
              Unitholder
      value measures – This includes key metrics such as funds flow per unit and
      distributions per unit.
 -
              Financial,
      business and strategic considerations – This includes the management of
      our asset base, balance sheet stewardship, execution of financial
      transactions and the overall goal of creating unitholder value (return on
      investment).
 
 Recycle
Ratio and Finding and Development costs
 
 Year
      ended December 312009
              
              
              2008
              
              
              2007
              
              
              3-Year
      averageExcluding
      future development costs (“FDC”) (1)Recycle
      ratio (2)
              
              
              1.9
              
              
              
              2.1
              
              
              
              1.1F&D
      costs per boe – proved plus probable
              
              $
              13.75
              
              
              $
              18.94
              
              
              $
              29.43
              
              
              $
              18.84F&D
      costs per boe – proved
              
              $
              16.10
              
              
              $
              27.17
              
              
              $
              33.09
              
              
              $
              23.80Including
      future development costs (3)Recycle
      ratio (2)
              
              
              1.6
              
              
              
              1.6
              
              
              
              1.1F&D
      costs per boe – proved plus probable
              
              $
              16.12
              
              
              $
              24.57
              
              
              $
              28.81
              
              
              $
              24.99F&D
      costs per boe – proved
              
              $
              16.19
              
              
              $
              31.94
              
              
              $
              31.83
              
              
              $
              27.70
 
 (1)
              The
      calculation of F&D excludes the change in FDC and the effects of
      acquisitions and dispositions.
 (2)
              Recycle
      ratio includes the realized portion of risk management impacts and uses
      F&D costs based on a proved plus
  probable basis.
 (3)
              The
      calculation of F&D includes the change in FDC and excludes the
      effects of acquisitions and
dispositions.
 
 Penn
West’s capital program was scaled back in 2009 due to the weak commodity price
environment experienced in late 2008 and early 2009. We added a total of
approximately 50 million boe of proved plus probable reserves (excluding
corporate acquisitions) with a successful drilling program, executed strong
production performance and increased capital allocations to our key projects.
These factors combined with focusing our capital program on the application of
horizontal multi-fracture completions technology contributed to strong F&D
cost performance on both a proved and proved plus probable basis. During 2009,
over ninety percent of our proved plus probable reserve additions from
development activities were oil. The recycle ratio was consistent with our
expectations as we anticipated a decline in 2009 as a result of a weaker netback
primarily from lower commodity prices. Finding and development costs are
calculated in accordance with NI 51-101, which include the change in FDC, on a
proved and proved plus probable basis. We also disclose for comparative
purposes, F&D costs excluding FDC.
  5
  Base
Operations
 
 Penn
West’s production levels exceeded our guidance throughout 2009. We focused on
large resource plays utilizing horizontal multi-stage fracture applications
which enhanced capital efficiencies. In the fourth quarter of 2009, Penn West
announced a property sale and a property swap as we continue to consolidate
operations in our core areas and strengthen our balance sheet. We will continue
to review strategic acquisitions and dispositions as we prepare Penn West for a
conversion from a trust to a corporation. Refer to the “Update on SIFT Tax and
Corporate Conversion” later in this MD&A for further discussion on our
corporate conversion.
 
 Health
and safety remains a top priority at Penn West. In 2009, our recordable injury
rate improved by 23 percent for employees and 36 percent for contractors
compared to 2008. Our ERCB regulatory compliance record in Alberta in 2009 was
85 percent, 5 percent better than the Industry average. Penn West maintains a
Certificate of Recognition (“COR”), issued by Alberta Employment and
Immigration, which is awarded to employers who develop and maintain health and
safety programs that meet established standards. Additionally, Penn West
continued our Platinum level of Performance in the Canadian Association of
Petroleum Producers Stewardship program. For the third consecutive year Penn
West was one of the top 15 companies in Canada being recognized as a 2009
Climate Disclosure Leader as part of the global Carbon Disclosure Project. Penn
West is a leader in carbon capture, and storage and currently has ownership in
three commercially operated CO2-Enhanced
Oil Recovery (“EOR”) projects and two CO2-EOR pilot
projects.
 
 Unitholder
Value Measures
 
 Year
      ended December 312009
              
              
              2008
              
              
              2007Funds
      flow per unit
              
              $
              3.62
              
              
              $
              6.75
              
              
              $
              5.56Distributions
      paid per unit
              
              $
              2.23
              
              
              $
              4.08
              
              
              $
              4.08Ratio
      of year-end total long-term debt to annual funds flow
              
              
              2.2
              
              
              
              1.5
              
              
              
              1.5
 
 In 2009,
the distribution level was decreased to $0.23 per unit per month effective with
the January 2009 distribution paid in February and then to $0.15 per unit per
month effective with the April 2009 distribution paid in May 2009. This was the
result of depressed commodity prices due to the financial crisis and a strategic
shift to allocate a greater portion of funds flow to the re-development of
certain of our large oil fields with horizontal multi-fracture
technology.
 
 The total
long-term debt to annual funds flow ratio increased in 2009 due to a reduction
in funds flow related to weaker commodity prices compared to 2008 and 2007. The
reduction of long-term debt by approximately 16 percent from 2008 partially
offset the decline in funds flow.
 
 Financial,
Business and Strategic Considerations
 
 Year
      ended December 312009
              
              
              2008
              
              
              2007Return
      on capital (1)
              
              
              -
              
              
              
              15
              %
              
              
              4
              %Return
      on equity (2)
              
              
              (2
              )%
              
              
              19
              %
              
              
              4
              %Total
      assets (millions)
              
              $
              13,876
              
              
              $
              15,412
              
              
              $
              8,433
 
 (1)
              Net
      income before financing charges divided by average unitholders’ equity and
      average total debt.
 (2)
              Net
      income divided by average unitholders’
equity.
 
 The
return on capital and return on equity ratios in 2009 were significantly
affected by the decline in net income which was primarily due to weaker
commodity prices and the recording of an unrealized risk management loss during
the year. This was partially offset by a significant decline in our total debt
compared to 2008.
  6
  As noted
in the Financial Markets section of this MD&A, we executed a number of
transactions during 2009 to further strengthen our balance sheet as we prepare
for the transition to a corporate structure. These transactions included an
equity issue of $250 million ($238 million net) in February, the private
placement of $238 million of senior, unsecured long-term notes in May and the
Lloydminster property disposition in November. In addition during the first
quarter of 2010, Penn West closed a property swap transaction that generated
proceeds of $434 million that were allocated to debt reduction and we also
closed an additional issue of approximately US$250 million and CAD$50 million of
senior, unsecured notes.
 
 RESULTS
OF OPERATIONS
 
 Production
 
 Year
      ended December 31Daily
      production
              
              2009
              
              
              2008
              
              
              %
      changeLight
      oil and NGL (bbls/d)
              
              
              78,011
              
              
              
              80,370
              
              
              
              (3
              )Heavy
      oil (bbls/d)
              
              
              25,962
              
              
              
              27,366
              
              
              
              (5
              )Natural
      gas (mmcf/d)
              
              
              440
              
              
              
              490
              
              
              
              (10
              )Total
      production (boe/d)
              
              
              177,221
              
              
              
              189,462
              
              
              
              (6
              )
 
 Production
for 2009 exceeded our guidance range of 171,500 to 176,500 boe per day, net of
property dispositions with average production of approximately 3,500 boe per
day. Our production results throughout 2009 were relatively consistent quarter
over quarter as a result of successful horizontal drilling in our large light
oil-in-place areas.
 
 We strive
to maintain an appropriate mix of liquids and natural gas production in order to
reduce exposure to price volatility that can affect a single commodity. In 2009,
crude oil and NGL production averaged 103,973 barrels per day (59 percent of
production) and natural gas production averaged 440 mmcf per day (41 percent of
production).
 
 Average
Sales Prices
 Year
      ended December 312009
              
              
              2008
              
              
              %
      changeLight
      oil and liquids (per bbl)
              
              $
              59.07
              
              
              $
              91.30
              
              
              
              (35
              )Risk
      management gain (loss) (per bbl)(1)
              
              
              8.19
              
              
              
              (11.89
              )
              
              
              100Light
      oil and liquids net (per bbl)
              
              
              67.26
              
              
              
              79.41
              
              
              
              (15
              )Heavy
      oil (per bbl)
              
              
              53.75
              
              
              
              74.55
              
              
              
              (28
              )Natural
      gas (per mcf)
              
              $
              4.13
              
              
              $
              8.43
              
              
              
              (51
              )Risk
      management gain (per mcf)(1)
              
              
              0.69
              
              
              
              (0.39
              )
              
              
              100Natural
      gas net (per mcf)
              
              
              4.82
              
              
              
              8.04
              
              
              
              (40
              )Weighted
      average (per boe)
              
              
              44.11
              
              
              
              71.65
              
              
              
              (38
              )Risk
      management gain (loss) (per boe)(1)
              
              
              5.32
              
              
              
              (6.05
              )
              
              
              100Weighted
      average net (per boe)
              
              $
              49.43
              
              
              $
              65.60
              
              
              
              (25
              )
 
 (1)  Gross
revenues include realized gains and losses on commodity
contracts.
  7
  Netbacks
 
 Year
      ended December 312009
              
              
              2008
              
              
              %
      changeLight oil and NGL(1)Production
      (bbls/day)
              
              
              78,011
              
              
              
              80,370
              
              
              
              (3
              )Operating
      netback (per bbl):Sales
      price
              
              $
              59.07
              
              
              $
              91.30
              
              
              
              (35
              )Risk
      management gain (loss) (2)
              
              
              8.19
              
              
              
              (11.89
              )
              
              
              100Royalties
              
              
              (10.78
              )
              
              
              (15.46
              )
              
              
              (30
              )Operating
      costs
              
              
              (19.93
              )
              
              
              (16.94
              )
              
              
              18Netback
              
              $
              36.55
              
              
              $
              47.01
              
              
              
              (22
              )Heavy
      oilProduction
      (bbls/day)
              
              
              25,962
              
              
              
              27,366
              
              
              
              (5
              )Operating
      netback (per bbl):Sales
      price
              
              $
              53.75
              
              
              $
              74.55
              
              
              
              (28
              )Royalties
              
              
              (7.26
              )
              
              
              (11.09
              )
              
              
              (35
              )Operating
      costs
              
              
              (15.54
              )
              
              
              (13.37
              )
              
              
              16Transportation
              
              
              (0.06
              )
              
              
              (0.06
              )
              
              
              -Netback
              
              $
              30.89
              
              
              $
              50.03
              
              
              
              (38
              )Total
      liquidsProduction
      (bbls/day)
              
              
              103,973
              
              
              
              107,736
              
              
              
              (3
              )Operating
      netback (per bbl):Sales
      price
              
              $
              57.74
              
              
              $
              87.04
              
              
              
              (34
              )Risk
      management gain (loss) (2)
              
              
              6.14
              
              
              
              (8.87
              )
              
              
              100Royalties
              
              
              (9.90
              )
              
              
              (14.35
              )
              
              
              (31
              )Operating
      costs
              
              
              (18.83
              )
              
              
              (16.03
              )
              
              
              17Transportation
              
              
              (0.01
              )
              
              
              (0.01
              )
              
              
              -Netback
              
              $
              35.14
              
              
              $
              47.78
              
              
              
              (26
              )Natural
      gasProduction
      (mmcf/day)
              
              
              440
              
              
              
              490
              
              
              
              (10
              )Operating
      netback (per mcf):Sales
      price
              
              $
              4.13
              
              
              $
              8.43
              
              
              
              (51
              )Risk
      management gain (2)
              
              
              0.69
              
              
              
              (0.39
              )
              
              
              100Royalties
              
              
              (0.75
              )
              
              
              (1.84
              )
              
              
              (59
              )Operating
      costs
              
              
              (1.57
              )
              
              
              (1.23
              )
              
              
              28Transportation
              
              
              (0.21
              )
              
              
              (0.19
              )
              
              
              11Netback
              
              $
              2.29
              
              
              $
              4.78
              
              
              
              (52
              )Combined
      totalsProduction
      (boe/day)
              
              
              177,221
              
              
              
              189,462
              
              
              
              (6
              )Operating
      netback (per boe):Sales
      price
              
              $
              44.11
              
              
              $
              71.65
              
              
              
              (38
              )Risk
      management gain (loss) (2)
              
              
              5.32
              
              
              
              (6.05
              )
              
              
              100Royalties
              
              
              (7.66
              )
              
              
              (12.95
              )
              
              
              (41
              )Operating
      costs
              
              
              (14.93
              )
              
              
              (12.31
              )
              
              
              21Transportation
              
              
              (0.52
              )
              
              
              (0.49
              )
              
              
              6Netback
              
              $
              26.32
              
              
              $
              39.85
              
              
              
              (34
              )
 
 (1)
              Light
      oil and NGL revenues for the year ended December 31, 2009 include $5
      million of other revenue not included in the netback
      calculation.
 (2)
              Gross
      revenues include realized gains and losses on commodity
      contracts.
  8
  Production
Revenues
 
 Revenues
from the sale of oil, NGL and natural gas consisted of the
following:
 
 Year
      ended December 31(millions)
              
              2009
              
              
              2008
              
              
              2007Light
      oil and NGL (1)
              
              $
              1,920
              
              
              $
              2,465
              
              
              $
              1,241Heavy
      oil
              
              
              509
              
              
              
              747
              
              
              
              364Natural
      gas
              
              
              774
              
              
              
              1,439
              
              
              
              857Gross
      revenues (2)
              
              $
              3,203
              
              
              $
              4,651
              
              
              $
              2,462
 
 (1)
                Light
      oil and NGL revenues for the year ended December 31, 2009 include $5
      million of other revenue not included in the netback
      calculation.
 (2)
              Gross
      revenues include realized gains and losses on commodity
      contracts.
 
 The
decrease in gross revenue for 2009 from the comparative period in 2008 was
mainly the result of lower commodity prices coupled with lower production
volumes. For 2009, light oil and liquid prices were 35 percent lower, natural
gas prices were 51 percent lower and heavy oil prices were 28 percent lower than
2008. Additionally, as the WTI benchmark price is denominated in US Dollars, the
weakening of the US Dollar has contributed to lower revenues.
 
 The
increase in revenue for 2008 over 2007 was the result of higher production
volumes from the Canetic and Vault Energy Trust (“Vault”) acquisitions and
higher commodity prices.
 
 Reconciliation
of decreases in Production Revenues
 
 (millions)Gross
      revenues – January 1 – December 31, 2008
              
              $
              4,651Decrease
      in light oil and NGL production
              
              
              (79
              )Decrease
      in light oil and NGL prices (including realized risk
      management)
              
              
              (466
              )Decrease
      in heavy oil production
              
              
              (40
              )Decrease
      in heavy oil prices
              
              
              (198
              )Decrease
      in natural gas production
              
              
              (153
              )Decrease
      in natural gas prices (including realized risk management)
              
              
              (512
              )Gross
      revenues – January 1 – December 31, 2009
              
              $
              3,203
 
 Royalties
 
 Year
      ended December 312009
              
              2008
              
              2007Royalties
      (millions)
              
              $
              495
              
              
              $
              898
              
              
              $
              451Average
      royalty rate (1)
              
              
              17
              %
              
              
              18
              %
              
              
              18
              %$/boe
              
              $
              7.66
              
              
              $
              12.95
              
              
              $
              9.72
 
 (1)
              Excludes
      effects of risk management
activities.
 
 For 2009,
royalty rates decreased due to the effect of the new Alberta royalty programs, a
part of which became effective in 2009. The royalties per boe amount decreased
as a result of lower royalty payments due to lower commodity
prices.
 
 Royalties
increased in 2008 compared to 2007 as a result of higher revenues from increased
commodity prices and increased production volumes.
  9
  Alberta
Royalty Modifications
 
 On March
11, 2010, the Government of Alberta, announced changes to its royalty structure
which will become effective January 1, 2011. These modifications include a
reduction in the maximum royalty rate from current levels of 50 percent to 40
percent for conventional oil and from 50 percent to 36 percent for natural gas.
Furthermore, the current incentive allowing a maximum 5 percent royalty rate on
the first year of production from new conventional oil and natural gas wells
will remain in effect under the modified framework. Additionally, the royalty
curves will be reviewed which may lead to modifications for all production
types. Changes to the royalty curves, if any, will be announced prior to May 31,
2010, therefore, Penn West cannot estimate the full impact of the modifications
until that time.
 
 Expenses
 
 Year
      ended December 31(millions)
              
              2009
              
              
              2008
              
              
              2007Operating
              
              $
              966
              
              
              $
              854
              
              
              $
              512Transportation
              
              
              34
              
              
              
              34
              
              
              
              24Financing
              
              
              161
              
              
              
              204
              
              
              
              93Unit-based
      compensation
              
              $
              52
              
              
              $
              45
              
              
              $
              21
 
 Year
      ended December 31(per
      boe)
              
              2009
              
              
              2008
              
              
              2007Operating
              
              $
              14.93
              
              
              $
              12.31
              
              
              $
              11.04Transportation
              
              
              0.52
              
              
              
              0.49
              
              
              
              0.52Financing
              
              
              2.49
              
              
              
              2.94
              
              
              
              2.00Unit-based
      compensation
              
              $
              0.81
              
              
              $
              0.65
              
              
              $
              0.44
 
 Operating
 
 The
increase in 2009 operating costs compared to 2008 was due to greater emphasis on
production maintenance activities to maintain production volumes in 2009. Due to
the weak commodity price environment early in 2009, Penn West reduced its
capital program and focused on highly efficient methods of maintaining
production.
 
 During
2008, upward pressure was placed on operating costs as a result of the high
industry activity levels driven by the high commodity price environment
experienced throughout the first nine months of the year, leading to an increase
over 2007.
 
 A
realized loss of $16 million (2008 - $6 million gain, 2007 - $11 million gain)
or $0.25 per boe (2008 - $0.09, 2007 - $0.24) on electricity contracts was
included in operating costs for the year ended December 31, 2009.
 
 Financing
 
 Penn West
Petroleum Ltd. (“the Company”) has an unsecured, revolving, three-year
syndicated bank facility with an aggregate borrowing limit of $3.25 billion. The
facility is extendible and expires in January 2011. In November 2009, after
significantly reducing the drawings on its bank facilities since early 2008, the
Company cancelled its $750 million tranche of the facility which also was
scheduled to expire in January 2011. 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. We are currently in the process of renewing our credit facility with our
bank syndicate and believe we will be successful in renewing the credit facility
on acceptable terms prior to the date of expiry.
  10
  As at
December 31, 2009, the Company had $1.3 billion of senior unsecured notes
outstanding as follows:
 
 Issue
      date
              
              Amount
      (millions)
              
              Term
              
              Average
      interest rate2007
      Notes
              
              May 31,
      2007
              
              US$475
              
              8 –
      15 years
              
              5.80
      percent2008
      Notes
              
              May 29,
      2008
              
              US$480,
      CAD$30
              
              8 –
      12 years
              
              6.25
      percentUK
      Notes
              
              July 31,
      2008
              
              £57
              
              10
      years
              
              6.95
      percent (1)2009
      Notes
              
              May 5,
      2009
              
              US$154,
      £20,
              
              5 –
      10 years
              
              8.85
      percent (2)€10,
      CAD$5
 
 (1)
              These
      notes bear interest at 7.78 percent in Pounds Sterling, however, contracts
      were entered to fix the interest rate at 6.95 percent in Canadian dollars
      and to fix the exchange rate on the
repayment.
 (2)
              The
      Company entered into contracts to fix the interest rate on the Pounds
      Sterling and Euro tranches, initially at 9.49 percent and 9.52 percent, to
      9.15 percent and 9.22 percent,
respectively.
 
 On March
16, 2010, the Company closed a private placement of senior unsecured notes (the
“2010 Notes”) with an aggregate principal amount of approximately US$250 million
and CAD$50 million. The 2010 Notes have an average term of 8.6 years and bear an
average fixed interest rate of approximately 5.5 percent. The Company used the
proceeds of the issue to repay advances on its syndicated bank
facility.
 
 On May 5,
2009, the Company closed the private placement of senior unsecured notes (the
“2009 Notes”) with an aggregate principal amount of approximately $238 million
on closing. The 2009 Notes have an average term of 7.6 years and bear an average
fixed interest rate of approximately 8.85 percent. The Company used the proceeds
of the issue to repay advances on its syndicated bank facility.
 
 On
February 5, 2009, Penn West closed the issuance of 17,731,000 trust units on a
bought-deal basis with a syndicate of underwriters at $14.10 per trust unit. The
total gross proceeds raised of approximately $250 million ($238 million net)
were used to repay a portion of our syndicated bank facility.
 
 On July
31, 2008, the Company issued £57 million of senior unsecured notes (the “UK
Notes”) through a private placement in the United Kingdom maturing in 2018 and
bearing interest at 7.78 percent. In conjunction with the issue of these notes,
the Company entered into contracts to fix the principal and interest payments at
approximately $114 million bearing interest in Canadian dollars at 6.95 percent.
The Company used the proceeds to repay advances on its syndicated bank
facility.
 
 On May
29, 2008, the Company issued senior unsecured notes (the “2008 Notes”) with an
aggregate principal amount of US$480 million plus CAD$30 million through a
private placement. The 2008 Notes have an average term of 9.6 years and bear an
average fixed interest rate of approximately 6.25 percent. The Company used the
proceeds of the issue to repay advances on its syndicated bank
facility.
 
 In June
2008, the Company completed all requirements to enable the sale of trust units
by way of “at-the-market distributions” on both the TSX and the NYSE. Penn West
may issue and sell up to 20,000,000 trust units from time to time at its
discretion during a period of up to 25 months. The trust units will be
distributed at the current market price at the time of sale. To date, no trust
units have been issued under this facility.
 
 At
December 31, 2009, the Company had the following interest rate swaps
outstanding:
 Effective
      date
              
              Termination
      date
              
              Initial
      term
              
              Nominal
      amount (millions)
              
              
              Fixed
      rate
                (percent)June
      2008
              
              June
      2010
              
              2 –
      years
              
              $
              50
              
              
              
              3.68November
      2008
              
              November
      2010
              
              2 –
      years
              
              $
              250
              
              
              
              2.27December
      2008
              
              December
      2011
              
              3 –
      years
              
              $
              500
              
              
              
              1.61January
      2009
              
              January
      2014
              
              5 –
      years
              
              $
              600
              
              
              
              2.71June
      2010
              
              January
      2014
              
              3.5
      – years
              
              $
              50
              
              
              
              1.94
  11
  The
interest rates on the balance of the Company’s bank debt are subject to
fluctuations in the short-term money market rates as bank debt is generally held
in short-term money market instruments. As at December 31, 2009, 14 percent
(2008 – 28 percent) of our long-term debt instruments were exposed to changes in
short-term interest rates and 86 percent (2008 – 72 percent) of our long-term
debt instruments contained fixed interest rates (including the effects of
interest rate swaps) at an average rate of approximately 4.57 percent (2008 –
4.38 percent).
 
 Financing
charges have declined primarily due to a lower average balance outstanding under
our syndicated bank facility and lower interest rates on short-term money market
instruments. This was partially offset by a higher percentage of our debt
capital being held in senior unsecured notes compared to the prior period. The
Company’s senior unsecured notes contain higher fixed interest rates than the
syndicated bank facilities. Notwithstanding the current interest rate
differentials, we believe the long-term nature of the senior notes is favourable
for a portion of our debt capital structure.
 
 Unit-Based
Compensation
 
 Unit-based
compensation expense related to Penn West’s Trust Unit Rights Incentive Plan is
based on the fair value of trust unit rights issued, determined using a Binomial
Lattice option-pricing model. The fair value of rights issued is amortized over
the remaining vesting periods on a straight-line basis. The amounts were
allocated to operating expense and general and administrative expense as
follows:
 
 Year
      ended December 31(millions)
              
              
              2009
              
              
              
              2008
              
              
              
              2007Operating
      expense
              
              $
              13
              
              
              $
              11
              
              
              $
              6General
      and administrative expense
              
              
              39
              
              
              
              34
              
              
              
              15Unit-based
      compensation expense
              
              $
              52
              
              
              $
              45
              
              
              $
              21
 
 Unit-based
compensation expense increased in 2009 compared to 2008 due to additional trust
unit rights granted in the period.
 
 The
charge increased in 2008 compared to 2007 due to the trust unit rights granted
to employees retained from the Canetic and Vault acquisitions in January
2008.
 
 General
and Administrative Expenses (“G&A”)
 
 Year
      ended December 312009
              
              
              2008
              
              
              2007Gross
              
              $
              189
              
              
              $
              195
              
              
              $
              83Per
      boe
              
              
              2.93
              
              
              
              2.81
              
              
              
              1.80Net
      (including unit-based compensation)
              
              
              168
              
              
              
              158
              
              
              
              65Per
      boe
              
              
              2.59
              
              
              
              2.29
              
              
              
              1.40Net
      (excluding unit-based compensation)
              
              
              129
              
              
              
              124
              
              
              
              50Per
      boe
              
              $
              1.99
              
              
              $
              1.80
              
              
              $
              1.10
 
 For 2009,
the increase in the net cost per boe compared to 2008 was primarily due to lower
overhead recoveries from the reduced capital expenditure program during 2009 and
lower production volumes.
 
 Increases
in 2008 compared to 2007 were primarily related to additional staffing levels
and activities as a result of the Canetic and Vault acquisitions completed in
January.
  12
  Depletion,
Depreciation and Accretion (“DD&A”)
 
 Year
      ended December 31(millions,
      except per boe amounts)
              
              2009
              
              
              2008
              
              
              2007Depletion
      of oil and natural gas assets
              
              $
              1,514
              
              
              $
              1,556
              
              
              $
              868Accretion
      of asset retirement obligation
              
              
              42
              
              
              
              38
              
              
              
              29Total
      DD&A
              
              $
              1,556
              
              
              $
              1,594
              
              
              $
              897DD&A
      expense per boe
              
              $
              24.04
              
              
              $
              22.98
              
              
              $
              19.33
 
 During
2009, Penn West had F&D costs which were lower than the historical DD&A
rate, however, the property dispositions that were completed in 2009 led to an
increase in the rate year over year.
 
 The
Canetic and Vault purchase price allocations to oil and natural gas assets, at
fair value, increased our consolidated depletion base per boe during 2008
compared to 2007.
 
 Taxes
 
 Year
      ended December 31(millions)
              
              2009
              
              
              2008
              
              
              2007Future
      income tax (recovery) expense
              
              $
              (378
              )
              
              $
              135
              
              
              $
              75
 
 Under our
current structure, the operating entities make interest and royalty payments to
the Trust, which transfers taxable income to the Trust level, eliminating income
subject to corporate income taxes in the operating entities. The Trust
eliminates its taxable income, in part, by deducting distributions paid to its
unitholders. Under the Specified Investment Flow-Through (“SIFT”) legislation,
which was enacted in June 2007 and is effective January 1, 2011, distributions
will no longer be tax deductible by the Trust. As a result, the Trust will be
taxed on its income similar to corporations after the effective date; however,
the amount of taxable income transferred to the Trust level and taxed as such is
for the most part discretionary.
 
 Future
income taxes arise from differences between the accounting and tax basis of
assets and liabilities. The estimate of future income taxes is based on the
current tax status of the Trust, enacted legislation and management’s best
estimates of future events. Certain events that could materially affect future
income taxes, such as acquisitions and dispositions and modifications to the
distribution policy, are not reflected under Canadian GAAP until the events
occur and the related legal requirements have been fulfilled.
 
 The
future income tax recovery through income in 2009 was $378 million compared to a
future income tax expense of $135 million for 2008. The difference was primarily
due to a tax benefit of $168 million related to unrealized risk management
losses recognized during 2009 compared to a tax charge of $198 million related
to unrealized risk management gains in 2008. The difference was also
attributable to income tax regulations enacted in March 2009 which modified the
provincial component of the future SIFT Tax rate. The net effect of these rules
on the Trust is to reduce the Provincial SIFT Tax rate from 13 percent to 10
percent, resulting in the recognition of a future income tax recovery of $65
million in 2009.
 
 During
2007, the future income tax expense included a $326 million charge due to
substantive enactment of the SIFT tax legislation during that
period.
  13
  Tax
Pools
 As
      at December 31(millions)
              
              2009
              
              
              2008
              
              
              2007Undepreciated
      capital cost (UCC)
              
              $
              1,379
              
              
              $
              1,394
              
              
              $
              826Canadian
      oil and gas property expense (COGPE)
              
              
              1,928
              
              
              
              2,514
              
              
              
              1,365Canadian
      development expense (CDE)
              
              
              1,141
              
              
              
              1,243
              
              
              
              591Canadian
      exploration expense (CEE)
              
              
              280
              
              
              
              60
              
              
              
              171Non-capital
      losses
              
              
              2,139
              
              
              
              1,646
              
              
              
              746Total
              
              $
              6,867
              
              
              $
              6,857
              
              
              $
              3,699
 
 Tax pool
figures exclude income deferred in operating partnerships of $931 million in
2009 (2008 - $885 million and 2007- $453 million).
 
 The
significant increase in the 2008 tax pools compared to 2007 was primarily the
result of corporate acquisitions which closed in the period.
 
 Update
on SIFT Tax and Corporate Conversion
 
 On June
12, 2007, the Government of Canada enacted legislation implementing a new tax
(the “SIFT Tax”) on certain publicly traded income trusts and limited
partnerships, referred to as SIFT entities. The purpose of the SIFT Tax was to
impose a tax structure on SIFT entities similar to that of public corporations.
Provided SIFT entities adhere to guidelines with respect to limitations on the
amount of new equity issued, the SIFT Tax becomes effective on January 1, 2011.
Currently, Penn West can issue approximately $14 billion of equity anytime
between now and 2011 without prematurely triggering the SIFT Tax.
 
 On March
12, 2009, federal legislation was enacted which provided that the provincial
component of the SIFT tax would be based on provincial corporate income tax
rates where the SIFT has a permanent establishment rather than using a flat 13.0
percent rate which was equally applicable to all SIFT entities under the
original rules. Under the new rules, Penn West currently has its only permanent
establishment in the Province of Alberta thus the combined SIFT tax rate
applicable to Penn West will now be 26.5 percent in 2011 and 25.0 percent in
2012 and thereafter.
 
 Also
included in the March 12, 2009 legislation were detailed rules providing for the
tax-free conversion of SIFT entities into public corporations (the “SIFT
Conversion Rules”). These rules enable the conversion of a SIFT entity into a
corporation without undue tax consequences for the SIFT entity or its investors.
The opportunity for a SIFT entity to apply these relieving provisions is
available until the end of 2012.
 
 Penn West
currently plans to convert to a corporate structure by mid-2011. The timing of
such conversion is dependent on the strength of commodity prices and equity
markets, operating performance and the extent of Penn West’s success in
developing its inventory of prospects. After conversion, total shareholder
return is expected to be a combination of growth and yield. Management will
continue to monitor changes to relevant tax legislation and work with our
advisors to determine the optimal future corporate structure.
 
 Penn West
currently has a significant tax pool base, estimated at $6.9 billion on December
31, 2009. Based on current commodity prices, Penn West forecasts it could use
these pools, as a trust or corporation, to shelter its taxable income for an
extended period after the effective date of the SIFT Tax. Distributions prior to
conversion to a corporation which are sheltered by tax pools are not immediately
taxable to the Trust or to unitholders. To the extent tax pools are insufficient
to shelter distributions after 2010 (and prior to corporate conversion), the
SIFT Tax would be payable and distributions of this income would generally be
considered taxable dividends to unitholders taxed at a lower rate than current
distributions of income as they will generally be eligible for the dividend tax
credit. As a result, the SIFT Tax should not adversely affect Canadian investors
who hold Penn West units in a taxable account. Subsequent to a corporate
conversion, shareholders will generally receive taxable dividends eligible for
the dividend tax credit.
  14
  Foreign
Exchange
 
 Year
      ended December 31(millions)
              
              2009
              
              
              2008
              
              
              2007Unrealized
      foreign exchange (gain) loss
              
              $
              (186
              )
              
              $
              203
              
              
              $
              (38
              )
 
 Penn West
records unrealized foreign exchange gains or losses to translate the U.S., UK
and Euro notes to Canadian dollars using the exchange rates in effect on the
balance sheet date. The gain during 2009 was primarily due to the weakening of
the US dollar relative to the Canadian dollar. The loss in 2008 was due to a
stronger US dollar compared to 2007.
 
 Funds
Flow and Net Income (Loss)
 
 Year
      ended December 312009
              
              
              2008
              
              
              2007Funds
      flow (1)(millions)
              
              $
              1,493
              
              
              $
              2,537
              
              
              $
              $1,332Basic
      per unit
              
              
              3.62
              
              
              
              6.75
              
              
              
              5.56Diluted
      per unit
              
              
              3.60
              
              
              
              6.66
              
              
              
              5.51Net
      income (loss) (millions)
              
              
              (144
              )
              
              
              1,221
              
              
              
              175Basic
      per unit
              
              
              (0.35
              )
              
              
              3.25
              
              
              
              0.73Diluted
      per unit
              
              $
              (0.35
              )
              
              $
              3.22
              
              
              $
              0.73
 
 (1)
              Funds
      flow is a non-GAAP measure. See “Calculation of Funds
    Flow”.
 
 The
decline in funds flow realized in 2009 was primarily the result of lower revenue
due to weaker commodity prices. The reduction in net income from the prior
periods was primarily due to lower revenues as a result of weaker commodity
prices and unrealized risk management losses in 2009 compared to unrealized risk
management gains in 2008.
 
 Funds
flow realized in 2008 increased to record levels from 2007 due to increased
product prices and higher production volumes partially offset by higher
operating and financing costs. The significant increase in net income in 2008
compared to 2007 was due to stronger commodity prices, increased production and
the SIFT tax charge recorded in the second quarter of 2007. This was partially
offset by higher depletion, operating and financing costs.
 
 Year
      ended December 312009
              
              
              2008
              
              
              2007per
      boe
              
              
              %
              
              
              per
      boe
              
              
              %
              
              
              per
      boe
              
              
              %Oil
      and natural gas revenues (1)
              
              $
              50.67
              
              
              
              100
              
              
              $
              67.06
              
              
              
              100
              
              
              $
              53.08
              
              
              
              100Royalties
              
              
              (7.66
              )
              
              
              (15
              )
              
              
              (12.95
              )
              
              
              (19
              )
              
              
              (9.72
              )
              
              
              (18
              )Operating
      expenses (2)
              
              
              (14.93
              )
              
              
              (30
              )
              
              
              (12.31
              )
              
              
              (18
              )
              
              
              (11.04
              )
              
              
              (21
              )Transportation
              
              
              (0.52
              )
              
              
              (1
              )
              
              
              (0.49
              )
              
              
              (1
              )
              
              
              (0.52
              )
              
              
              (1
              )Net
      operating income
              
              
              27.56
              
              
              
              54
              
              
              
              41.31
              
              
              
              62
              
              
              
              31.80
              
              
              
              60General
      and administrative expenses
              
              
              (1.99
              )
              
              
              (4
              )
              
              
              (1.80
              )
              
              
              (3
              )
              
              
              (1.10
              )
              
              
              (2
              )Financing
      (3)
              
              
              (2.49
              )
              
              
              (5
              )
              
              
              (2.94
              )
              
              
              (4
              )
              
              
              (2.00
              )
              
              
              (4
              )Funds
      flow
              
              
              23.08
              
              
              
              45
              
              
              
              36.57
              
              
              
              55
              
              
              
              28.70
              
              
              
              54Unrealized
      foreign exchange gain (loss)
              
              
              2.88
              
              
              
              6
              
              
              
              (2.92
              )
              
              
              (5
              )
              
              
              0.82
              
              
              
              1Unit-based
      compensation
              
              
              (0.81
              )
              
              
              (2
              )
              
              
              (0.65
              )
              
              
              (1
              )
              
              
              (0.44
              )
              
              
              (1
              )Risk
      management activities (4)
              
              
              (9.17
              )
              
              
              (18
              )
              
              
              9.53
              
              
              
              14
              
              
              
              (4.35
              )
              
              
              (8
              )Depletion,
      depreciation and accretion
              
              
              (24.04
              )
              
              
              (47
              )
              
              
              (22.98
              )
              
              
              (34
              )
              
              
              (19.33
              )
              
              
              (36
              )Future
      income tax recovery (expense)
              
              
              5.84
              
              
              
              12
              
              
              
              (1.95
              )
              
              
              (3
              )
              
              
              (1.63
              )
              
              
              (3
              )Net
      income (loss)
              
              $
              (2.22
              )
              
              
              (4
              )
              
              $
              17.60
              
              
              
              26
              
              
              $
              3.77
              
              
              
              7
 
 (1)
              Gross
      revenues include realized gains and losses on commodity
      contracts.
 (2)
              Operating
      expenses include realized gains/ losses on electricity
    swaps.
 (3)
              Financing
      expenses include realized losses on interest rate
  swaps.
 (4)
              Risk
      management activities relate to the unrealized gain and losses on
      derivative instruments.
  15
  Goodwill
 
 As
      at December 312009
              
              
              
              2008
              
              
              
              2007Balance,
      beginning of period
              
              $
              2,020
              
              
              $
              652
              
              
              $
              652Acquisitions
              
              
              -
              
              
              
              1,368
              
              
              
              -Balance,
      end of period
              
              $
              2,020
              
              
              $
              2,020
              
              
              $
              652
 
 Penn West
recorded goodwill on its acquisitions of Petrofund Energy Trust, Canetic and
Vault. Goodwill is subject to impairment testing which consists of two parts.
Under part 1, the fair value of the reporting entity, in our case the market
value of our equity, is compared to the book value. If the fair value of the
reporting entity is less than its book value, part 2 of the test must be
performed. As at December 31, 2009, our market capitalization, plus a 20 percent
equity control premium, exceeded the book value of Penn West. As a result, Penn
West determined there was no goodwill impairment at December 31,
2009.
 
 Capital
Expenditures
 
 Year
      ended December 31(millions)
              
              2009
              
              
              2008
              
              
              2007Land
      acquisition and retention
              
              $
              19
              
              
              $
              128
              
              
              $
              30Drilling
      and completions
              
              
              280
              
              
              
              509
              
              
              
              367Facilities
      and well equipping
              
              
              336
              
              
              
              398
              
              
              
              254Geological
      and geophysical
              
              
              9
              
              
              
              13
              
              
              
              10CO2
      pilot costs
              
              
              6
              
              
              
              29
              
              
              
              20Corporate
              
              
              38
              
              
              
              18
              
              
              
              16Development
      capital expenditures
              
              
              688
              
              
              
              1,095
              
              
              
              697Property
      (dispositions) acquisitions, net
              
              
              (369
              )
              
              
              (50
              )
              
              
              422Capital
      expenditures
              
              
              319
              
              
              
              1,045
              
              
              
              1,119Business
      combinations
              
              
              116
              
              
              
              5,525
              
              
              
              21Total
      expenditures
              
              $
              435
              
              
              $
              6,570
              
              
              $
              1,140
 
 In 2009,
Penn West reduced its capital spending compared to 2008 as a result of a weak
commodity price environment. The 2009 capital program included increased
production maintenance activities to maintain production volumes and as a result
capital expenditures for facilities and well equipping are proportionally higher
in 2009 compared to 2008.
 
 For the
year ended December 31, 2009, asset retirement obligations were reduced by $26
million (2008 - $25 million capitalized, 2007- $97 million capitalized)
reflecting net property dispositions.
 
 CO2 pilot
costs represent capital expenditures related to the Pembina and South Swan Hills
CO2
pilot projects, including the cost of injectants, for which no incremental
reserves have been booked.
  16
  Drilling
 
 Year
      ended December 312009
              
              
              2008Gross
              
              
              Net
              
              
              Gross
              
              
              NetOil
              
              
              102
              
              
              
              68
              
              
              
              279
              
              
              
              136Natural
      gas
              
              
              40
              
              
              
              17
              
              
              
              224
              
              
              
              103Dry
              
              
              2
              
              
              
              2
              
              
              
              14
              
              
              
              11144
              
              
              
              87
              
              
              
              517
              
              
              
              250Stratigraphic
      and service
              
              
              11
              
              
              
              7
              
              
              
              40
              
              
              
              38Total
              
              
              155
              
              
              
              94
              
              
              
              557
              
              
              
              288Success
      rate (1)
              
              
              
              
              
              
              98
              %
              
              
              
              
              
              
              96
              %
 
 (1)
              Success
      rate is calculated excluding stratigraphic and service
    wells.
 
 Penn West
reduced its capital expenditure program in 2009, compared to 2008, in response
to the decline in commodity prices resulting from the financial crisis. Our 2009
capital spending was focused on large resource plays utilizing horizontal
multi-stage fracture applications to enhance capital efficiency. Our 2010
capital budget has been increased compared to 2009 due to the partial recovery
in commodity prices and our strategy to accelerate the development of certain of
our large scale light-oil properties.
 
 Canetic
Acquisition
 
 On
January 11, 2008, Penn West closed its acquisition of Canetic for a total
acquisition cost of approximately $3.6 billion, funded through the issuance of
approximately 124.3 million trust units, calculated based on the volume weighted
average trading price of the units around the date of the announcement,
discounted by five percent to reflect normal equity issuance costs. The
acquisition by Penn West was accounted for using the purchase method. The
allocation of the consideration paid to the fair value of the identifiable
assets and liabilities was as follows:
 
 Purchase
      price
              
              (millions)124.3
      million Penn West trust units issued
              
              $
              3,573Transaction
      costs
              
              
              22$
              3,595Allocation
      of purchase priceProperty,
      plant and equipment
              
              $
              4,979Goodwill
              
              
              1,348Working
      capital deficiency
              
              
              (274
              )Bank
      debt
              
              
              (1,443
              )Convertible
      debentures
              
              
              (261
              )Risk
      management liability
              
              
              (65
              )Future
      income taxes
              
              
              (511
              )Asset
      retirement obligations
              
              
              (178
              )$
              3,595
 
 Vault
Acquisition
 
 On
January 10, 2008, Penn West closed its acquisition of Vault for a total
acquisition cost of approximately $164 million funded through the issuance of
approximately 5.6 million trust units. The trust unit value was calculated based
on the volume weighted average trading price of the units around the date of the
announcement, discounted by five percent to reflect normal equity issuance
costs. The acquisition by Penn West was accounted for using the purchase method.
The allocation of the consideration paid to the fair value of the identifiable
assets and liabilities was as follows:
  17
 
 Purchase
      price
              
              (millions)5.6
      million Penn West trust units issued
              
              $
              158Transaction
      costs
              
              
              6$
              164Allocation
      of purchase priceProperty,
      plant and equipment
              
              $
              346Goodwill
              
              
              20Working
      capital
              
              
              2Future
      income taxes
              
              
              47Bank
      debt
              
              
              (114
              )Convertible
      debentures
              
              
              (99
              )Risk
      management liability
              
              
              (2
              )Asset
      retirement obligations
              
              
              (36
              )$
              164
 
 Endev Energy Inc. (“Endev”)
Acquisition
 
 On July
22, 2008, the acquisition of Endev was successfully completed. Penn West issued
approximately 3.6 million trust units for total consideration of $115 million
and assumed approximately $45 million of debt and working capital. The
acquisition was accomplished through a Plan of Arrangement wherein Endev
shareholders received 0.041 of a Penn West trust unit for each Endev
share.
 
 Reece
Energy Exploration Corp (“Reece”) Acquisition
 
 On April
30, 2009, Penn West closed the acquisition of Reece, an oil and gas exploration
company. The acquisition was completed through a Plan of Arrangement wherein
Reece shareholders received 0.125 of a Penn West trust unit for each Reece
share. The total acquisition cost was approximately $101 million, which included
the assumption of approximately $42 million of debt and working capital. The
transaction added current production of approximately 1,900 boe per day and
67,000 net acres of undeveloped land, the majority of which complements Penn
West’s Dodsland light-oil resource play in Southern Saskatchewan.
 
 Business
Risks
 
 The
disclosures under this heading (excluding the information under environmental
and climate change risk), in conjunction with Note 8 to the audited consolidated
financial statements, are incorporated into and are an integral part of, the
audited consolidated financial statements.
 
 We are
exposed to normal market risks inherent in the oil and natural gas business,
including, but not limited to, commodity price risk, credit risk, interest rate
risk, foreign currency risk and environmental and climate change risk. We seek
to mitigate these risks through various business processes and management
controls and from time to time by using financial instruments.
 
 For a
summary of outstanding financial instruments, please refer to “Financial
Instruments” later in this MD&A and to Note 8 to our audited consolidated
financial statements.
  18
  Commodity
Price Risk
 
 Commodity
price fluctuations are among Penn West’s most significant exposures. Crude oil
prices are influenced by worldwide factors such as OPEC actions, supply and
demand fundamentals, and geopolitical events. Natural gas prices are influenced
by the price of alternative fuel sources such as oil or coal, and by North
American natural gas supply and demand fundamentals including the levels of
industrial activity, weather, storage levels and liquefied natural gas imports.
In accordance with policies approved by our Board of Directors, we may, from
time to time, manage these risks through the use of swaps, collars or other
financial instruments up to a maximum of 50 percent of forecast sales volumes,
net of royalties, for the balance of any current year plus one additional year
forward and up to a maximum of 25 percent for one additional year
thereafter.
 
 Foreign
Currency Rate Risk
 
 Prices
received for crude oil are referenced to or denominated directly in US dollars,
thus our realized oil prices are impacted by Canadian dollar to US dollar
exchange rates. When we consider it appropriate, we may use financial
instruments to fix or collar future exchange rates in addition to the use of US
dollar denominated borrowings and related interest expense. At December 31,
2009, Penn West had the following foreign currency forward contracts
outstanding:
 
 Initial
      term
              Nominal
      amount (millions)
              Termination
      date
              Exchange
      rate8-year
      term
              Buy
      US$80
              May
      2015
              1.01027
      CAD/USD10-year
      term
              Buy
      US$80
              May
      2017
              1.00016
      CAD/USD12-year
      term
              Buy
      US$70
              May
      2019
              0.99124
      CAD/USD15-year
      term
              Buy
      US$20
              May
      2022
              0.98740
      CAD/USD
 
 At
December 31, 2009, we had US dollar denominated debt with a face value of US$859
million outstanding on which the repayment of the principal amount in Canadian
dollars is not fixed.
 
 Credit
Risk
 
 Credit
risk is the risk of loss if purchasers or counterparties do not fulfill their
contractual obligations. Our receivables are principally with customers in the
oil and natural gas industry and are generally subject to normal industry credit
risk including the right to recover unpaid receivables by receiving the
partner’s share of production where Penn West is the operator. For oil and
natural gas sales and financial derivatives, Penn West follows a counterparty
risk procedure whereby each counterparty is reviewed on a regular basis for the
purpose of assigning a credit limit and is requested to provide security if
deemed necessary. For financial derivatives, Penn West normally transacts with
counterparties who are members of our banking syndicate or other counterparties
that have investment grade credit ratings. Penn West monitors credit events
related to all counterparties and reassesses credit exposures on a regular
basis. As necessary, provisions for potential credit related losses are
recorded.
 
 As at
December 31, 2009, the maximum exposure to credit risk was $371 million
(December 31, 2008 - $834 million) being the carrying value of the accounts
receivable and risk management assets. The balance consisted of $371 million of
trade accounts receivable at December 31, 2009 compared to $386 million of trade
accounts receivable and $448 million of risk management assets at December 31,
2008. Management continuously monitors credit risk and credit policies to ensure
exposures to customers are controlled.
 
 Interest
Rate Risk
 
 We
currently maintain a portion of our debt capital in floating-rate bank
facilities which results in exposure to fluctuations in short-term interest
rates which remain at lower levels than longer-term rates. From time to time, we
may increase the certainty of our future interest rates by entering fixed
interest rate debt instruments or by using financial instruments to swap
floating interest rates for fixed rates or to collar interest
rates.
  19
  As at
December 31, 2009, we had a total of $1.3 billion of fixed interest rate debt
instruments and $0.3 billion of convertible debentures outstanding as
follows:
 
 ·
              The
      2007 Notes, totalling US$475 million, bear fixed interest rates at an
      average rate of approximately 5.80 percent with an average original term
      of 10.1 years.
 ·
              The
      2008 Notes, which total US$480 million plus CAD$30 million, bear fixed
      interest rates at an average of approximately 6.25 percent with an average
      original term of 9.6 years.
 ·
              The
      UK Notes, totalling £57 million, have a fixed interest rate of
      approximately 7.78 percent for an original term of 10 years. The Company
      entered into contracts to fix the principal of the UK Notes at
      approximately $114 million bearing interest in Canadian dollars at 6.95
      percent.
 ·
              The
      2009 Notes, which total US$154 million, £20 million, €10 million and CAD$5
      million, bear fixed interest rates at an average rate of 8.85 percent with
      an average original term of 7.6 years. The Company entered into contracts
      to fix the principal of the Pounds Sterling and Euro tranches, at $36
      million and $16 million bearing interest in Canadian dollars at 9.15
      percent and 9.22 percent,
respectively.
 ·
              We
      have unsecured, subordinated convertible debentures outstanding with
      maturity dates until the end of 2011. For further details on these
      instruments, refer to the “Convertible Debenture” section below in this
      MD&A.
 
 Liquidity
Risk
 
 Liquidity
risk is the risk that Penn West will be unable to meet its financial liabilities
as they come due. Management utilizes short and long-term financial and capital
forecasting programs that include a continuous review of debt forecasts to
ensure credit facilities are sufficient relative to forecast debt levels,
distribution and capital program levels are appropriate, and that financial
covenants will be met. Management also regularly reviews capital markets to
identify opportunities to optimize the debt capital structure on a cost
effective basis. In the short term, liquidity is managed through daily cash
management activities, short-term financing strategies and the use of collars
and other financial instruments to increase the predictability of cash flow from
operating activities. Additional information on specific instruments is
discussed in Notes 6 and 7 to the audited consolidated financial
statements.
 
 The
following table outlines estimated future contractual obligations for
non-derivative financial liabilities as at December 31, 2009:
 
 (millions)
              
              2010
              
              
              2011
              
              
              2012
              
              
              2013
              
              
              2014
              
              
              ThereafterBank
      debt
              
              $
              -
              
              
              $
              1,874
              
              
              $
              -
              
              
              $
              -
              
              
              $
              -
              
              
              $
              -Senior
      unsecured notes
              
              
              -
              
              
              
              -
              
              
              
              -
              
              
              
              5
              
              
              
              62
              
              
              
              1,278Convertible
      debentures
              
              
              18
              
              
              
              255
              
              
              
              -
              
              
              
              -
              
              
              
              -
              
              
              
              -Accounts
      payable
              
              
              515
              
              
              
              -
              
              
              
              -
              
              
              
              -
              
              
              
              -
              
              
              
              -Distributions
      payable
              
              
              63
              
              
              
              -
              
              
              
              -
              
              
              
              -
              
              
              
              -
              
              
              
              -Total
              
              $
              596
              
              
              $
              2,129
              
              
              $
              -
              
              
              $
              5
              
              
              $
              62
              
              
              $
              1,278
 
 Environmental
and Climate Change Risk
 
 The oil
and gas industry has a number of environmental risks and hazards and is subject
to regulation by all levels of government. Environmental legislation includes,
but is not limited to, operational controls, reporting requirements, site
restoration requirements and restrictions on emissions of various substances
produced in association with oil and natural gas operations. Compliance with
such legislation could require additional expenditures and a failure to comply
may result in fines and penalties which could, in the aggregate and under
unlikely assumptions, become material.
 
 Penn West
is dedicated to reducing the environmental impact from our operations through
our environmental programs which include resource conservation, stakeholder
communication, CO2
sequestration, water management and site abandonment/reclamation. We
continuously monitor our responsibilities to minimize the environmental impact
from our operations, allocate sufficient capital to reclamation and other
activities and are committed to mitigating the impact on the areas in which we
operate.
  20
  Liquidity
and Capital Resources
 
 Capitalization
 
 As
      at December 312009
                          
                          
                          2008
                          
                          
                          2007(millions)
                          
                          
                          
                          
                          %
                          
                          
                          
                          
                          
                          %
                          
                          
                          
                          
                          
                          %Trust
      units issued, at market
                          
                          $
                          7,821
                          
                          
                          
                          69
                          
                          
                          $
                          5,245
                          
                          
                          
                          54
                          
                          
                          $
                          6,270
                          
                          
                          
                          75Long-term
      debt
                          
                          
                          3,219
                          
                          
                          
                          28
                          
                          
                          
                          3,854
                          
                          
                          
                          40
                          
                          
                          
                          1,943
                          
                          
                          
                          23Convertible
      debentures – long term
                          
                          
                          255
                          
                          
                          
                          2
                          
                          
                          
                          289
                          
                          
                          
                          3
                          
                          
                          
                          -
                          
                          
                          
                          -Working
      capital deficiency (1)
                          
                          
                          106
                          
                          
                          
                          1
                          
                          
                          
                          270
                          
                          
                          
                          3
                          
                          
                          
                          118
                          
                          
                          
                          2Total
      enterprise value
                          
                          $
                          11,401
                          
                          
                          
                          100
                          
                          
                          $
                          9,658
                          
                          
                          
                          100
                          
                          
                          $
                          8,331
                          
                          
                          
                          100
 
 (1)
              Excludes
      the current portion of risk management, future income taxes and
      convertible debentures.
 
 During
2009, we paid total distributions, including those funded by the distribution
reinvestment plan, of $910 million compared to distributions of $1,500 million
for 2008 and $976 million for 2007. The monthly distribution was reduced from
$0.34 per unit, per month to $0.23 per unit, per month effective with the
monthly distribution paid in February 2009. As forward commodity prices fell
further, the monthly distribution was further reduced to $0.15 per unit, per
month commencing with the distribution paid in May 2009.
 
 The
decline in long-term debt in 2009 compared to 2008 was mainly due to repayments
made on our syndicated bank facility and the appreciation of the Canadian dollar
against the US dollar. The working capital deficiency has decreased from
December 31, 2008, primarily due to a decline in our accounts payable
balance.
 
 For 2008,
the increase in long-term debt compared to 2007 was mainly due to debt of $1,443
million assumed in the Canetic acquisition and $114 million assumed in the Vault
acquisition.
 
 The
Company has unsecured, revolving, syndicated bank facilities totalling $3.25
billion with $1.9 billion drawn at December 31, 2009, senior unsecured notes of
$1.3 billion and convertible debentures of $0.3 billion. For further details on
these debt instruments, please refer to the “Financing” and “Convertible
Debentures” sections of this MD&A.
 
 In 2009,
Penn West completed a number of transactions to actively manage its debt
portfolio, including: the completion of an equity offering in February, the
closing of $369 million in net asset dispositions, the reduction of our
distribution levels, the reduction of our capital programs compared to 2008 and
the issuance of additional long-term private notes in May. Additionally, we have
an active risk management program to limit our exposure to credit risk and
maintain close relationships with our bank syndicate members to monitor credit
market developments. These actions aim to increase the likelihood of maintaining
our financial flexibility to capture opportunities availed by the current market
in addition to the continuation of our capital and distribution programs and the
longer-term execution of our business strategies.
 
 The
Company has a number of covenants related to its syndicated bank facility and
senior, unsecured notes. On December 31, 2009, the Company was in compliance
with all of these financial covenants which comprise the following:
 Limit
              
              December 31,
      2009Senior
      debt to pro forma EBITDA (1)
              Less
      than 3:1
              
              
              2.0Total
      debt to pro forma EBITDA (1)
              Less
      than 4:1
              
              
              2.0Senior
      debt to capitalization
              Less
      than 50 percent
              
              
              28
              %Total
      debt to capitalization (2)
              Less
      than 55 percent
              
              
              28
      - 31
              %
 
 (1)
              Pro
      forma EBITDA includes Penn West and Reece and certain property
      transactions closing in the pro forma
period.
 (2)
              The
      definitions of Total debt differ slightly among the agreements in relation
      to convertible debentures.
 
 The 2008
Notes, the UK Notes and the 2009 Notes contain change of control provisions
requiring that if a change in control occurs, the Company may be required to
offer to prepay the 2008 Notes, the UK Notes and the 2009 Notes at par, which
the holders of these notes have the right to refuse.
  21
  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. 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; however, the amount
of taxable income allocated to the trust from the operating entities is subject
to management’s discretion. In the event a special distribution is required in
order to distribute taxable income from the Trust, such a distribution would
generally be in trust units and 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 be reset to the number
outstanding immediately prior to the special distribution, plus 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. Penn West has
never declared such a distribution and, at the current time, forecasts that such
a special distribution will not be required for 2010.
 
 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 will be 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 funds flow would be
required to fund our environmental expenditures.
 
 Convertible
Debentures
 
 During
2009, convertible debentures with a face value of $12 million (2008 – $nil) were
redeemed and settled in units, $4 million (2008 - $56 million) were redeemed and
settled in cash, no amounts (2008 - $3 million) were converted and $7 million
matured and were settled in units (2008 – $5 million settled in
cash).
 
 At
December 31, 2009, the balance of our unsecured, subordinated convertible
debentures outstanding was as follows:
  Description
      of security
                  
                  Outstanding
                    (millions)
                  
                  
                  Maturity
      date
                  
                  
                  Conversion
      price
                    (per
      unit)
                  
                  
                  Redemption
      prices
                    (per
      $1,000 face value)PWT.DB.C
                  
                  $
                  -
                  
                  
                  June
      30,
                  
                  
                  $
                  82.14
                  
                  
                  $1,025
      July 1, 2009 to maturity8.0%
      Convertible (1)
                  
                  
                  
                  
                  
                  2010PWT.DB.D
                  
                  
                  18
                  
                  
                  July
      31,
                  
                  
                  $
                  36.82
                  
                  
                  $1,025
      July 31, 2009 to maturity6.5%
      Convertible extendible
                  
                  
                  
                  
                  
                  2010PWT.DB.E
                  
                  
                  26
                  
                  
                  May
      31,
                  
                  
                  $
                  75.00
                  
                  
                  $1,050
      May 31, 2009 – May 30, 20107.2%
      Convertible
                  
                  
                  
                  
                  
                  2011
                  
                  
                  
                  
                  
                  
                  $1,025
      May 31, 2010 to maturityPWT.DB.F
                  
                  
                  229
                  
                  
                  Dec.
      31,
                  
                  
                  $
                  51.55
                  
                  
                  $1,050
      Dec. 31, 2009 – Dec. 30, 20106.5%
      Convertible extendible
                  
                  
                  
                  
                  
                  2011
                  
                  
                  
                  
                  
                  
                  $1,025
      Dec. 31, 2010 to maturityTotal
                  
                  $
                  273
 
 (1)
              Series
      redeemable at the debenture holder’s
option.
  22
  Standardized
Distributable Cash
 
 Year
      ended December 31(millions,
      except per unit amounts)
              
              2009
              
              
              2008
              
              
              2007Cash
      flow from operating activities
              
              $
              1,401
              
              
              $
              2,256
              
              
              $
              1,242Productive
      capacity maintenance (1)
              
              
              (688
              )
              
              
              (1,095
              )
              
              
              (697
              )Standardized
      distributable cash
              
              
              713
              
              
              
              1,161
              
              
              
              545Proceeds
      from the issue of trust units (2)
              
              
              393
              
              
              
              246
              
              
              
              163Debt
      and working capital changes
              
              
              (265
              )
              
              
              143
              
              
              
              269Cash
      distributions declared
              
              $
              841
              
              
              $
              1,550
              
              
              $
              977Accumulated
      cash distributions, beginning
              
              
              3,660
              
              
              
              2,110
              
              
              
              1,133Accumulated
      cash distributions, ending
              
              $
              4,501
              
              
              $
              3,660
              
              
              $
              2,110Standardized
      distributable cash per unit, basic
              
              
              1.73
              
              
              
              3.09
              
              
              
              2.27Standardized
      distributable cash per unit, diluted
              
              
              1.72
              
              
              
              3.03
              
              
              
              2.25Standardized
      distributable cash payout ratio (3)
              
              
              1.18
              
              
              
              1.34
              
              
              
              1.80Distributions
      declared per unit
              
              $
              2.04
              
              
              $
              4.08
              
              
              $
              4.08Net
      income as a percentage of cash distributions declared
              
              
              N/A
              
              
              
              79
              %
              
              
              18
              %Cash
      flows from operating activities as a percentage of cash distributions
      declared
              
              
              167
              %
              
              
              146
              %
              
              
              127
              %
 
 (1)
              Please
      refer to our discussion of productive capacity maintenance
      below.
 (2)
              Consists
      of proceeds from the Distribution Reinvestment and Optional Purchase Plan,
      the Trust Unit Rights Incentive Plan, the Employee Retirement Savings Plan
      and the equity issuance that was completed in February
    2009.
 (3)
              Represents
      cash distributions declared divided by standardized distributable
      cash.
 
 (millions,
      except ratios)
              
              To
      December 31, 2009Cumulative
      standardized distributable cash from operations (1)
              
              $
              3,437Issue
      of trust units
              
              
              929Debt
      and working capital changes
              
              
              135Cumulative
      cash distributions declared (1)
              
              $
              4,501Standardized
      distributable cash payout ratio (2)
              
              
              1.31
 
 (1)
              Subsequent
      to the trust conversion on May 31,
2005.
 (2)
              Represents
      cumulative cash distributions declared divided by cumulative standardized
      distributable cash.
 
 We strive
to fund both distributions and maintenance capital programs primarily from funds
flow. We currently budget our capital programs at approximately 50-60 percent of
annual forecast funds flow. Looking forward, given our business strategy to
convert to an exploration and production corporation by mid-2011, our mix of
capital and distributions is likely to favour increasing capital allocations to
provide our unitholders with returns from growth in our productive capacity.
Additional borrowings and equity issues may be required from time to time to
fund a portion of our distributions, decrease our debt capital or to maintain or
increase our productive capacity. Adjustments to the level of distributions
and/or capital expenditures to maintain or increase our productive capacity may
be required or desirable based on forecast levels of funds flow, expected
capital efficiency and debt levels. In 2009, we reduced our distribution levels
and our capital programs due to market conditions and a low commodity price
environment. We closed an issuance of equity in February 2009.
  23
  Productive
capacity maintenance is the estimated amount of capital funds required in a
period for an enterprise to maintain future cash flows from operating activities
at a constant level. As commodity prices can be volatile and short-term
variations in production levels are often experienced in our industry, we define
our productive capacity as production on a barrel of oil equivalent basis. A
quantifiable measure for these short-term variations is not objectively
determinable or verifiable due to various factors including the inability to
distinguish natural production declines from the effect of production additions
resulting 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 standardized distributable cash is our capital
expenditures during the period excluding the cost of any asset acquisitions or
proceeds of any asset dispositions. We believe that our current capital
programs, based on investing 50-60 percent of forecast annual funds flow and our
current view of our assets and opportunities, including particularly our
resource play assets, our proposed enhanced oil recovery projects, and our
outlook for commodity prices and industry conditions, should be sufficient to
maintain our productive capacity over the medium term. We set our internal
hurdle rates for evaluating potential development and optimization projects
according to these parameters. Due to the risks inherent in the oil and natural
gas industry, particularly our exploration and development activities and
variations in commodity prices, there can be no assurance that capital programs,
whether limited to the excess of funds flow over distributions or not, will be
sufficient to maintain or increase our production levels or cash flow from
operating activities. Penn West historically incurred a larger proportion of its
development expenditures in the first quarter of each calendar year to exploit
winter-only access properties. Due to a high allocation to our oil resource
plays in our 2010 capital budget we do not expect our capital expenditures to be
disproportionally high in the first quarter of 2010. As we strive to maintain
sufficient credit facilities and appropriate levels of debt, any seasonality is
not currently expected to influence our distribution policies.
 
 Our
calculation of standardized distributable cash 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 standardized
distributable cash calculation, includes a reduction for abandonment
expenditures incurred during each period. We believe that our current
environmental programs will be sufficient to fund our asset retirement
obligations over the life of our reserves. Our Board of Directors sets our
distribution policies based on forecast funds flow and debt levels. Accordingly,
distributions in excess of net income may include an economic return of capital
to unitholders.
 
 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.
  24
  Financial
Instruments
 
 Penn West
had the following financial instruments outstanding as at December 31, 2009.
Fair values are determined using external counterparty information which is
compared to observable market data. We limit our credit risk by executing
counterparty risk procedures which include transacting only with financial
institutions with high credit ratings, obtaining security in certain
circumstances and by completing substantially all such transactions with members
of our banking syndicate.
 
 Notionalvolume
              
              
              Remainingterm
              
              
              Pricing
              
              
              Fair
      valueCrude
      oilWTI
      Collars
              
              35,000
      bbls/d
              
              
              Jan/10
      – Dec/10
              
              
              US$60.11
      to $75.72/bbl
              
              
              $
              (139
              )Natural
      gasAECO
      Collars (1)
              
              63,000
      GJ/d
              
              
              Jan/10
      – Oct/10
              
              
              $6.50
      to $9.50/GJ
              
              
              
              29Electricity
      swapsAlberta
      Power Pool Swaps
              
              50
      MW
              
              
              Jan/10
      – Dec/10
              
              
              $77.82/MWh
              
              
              
              (10
              )Alberta
      Power Pool Swaps
              
              25
      MW
              
              
              Jan/10
      – Dec/11
              
              
              $66.70/MWh
              
              
              
              (6
              )Alberta
      Power Pool Swaps
              
              50
      MW
              
              
              Jan/11
      – Dec/11
              
              
              $66.23/MWh
              
              
              
              (7
              )Interest
      rate swaps$50
              
              
              Jan/10 –
      June/10
              
              
              
              3.68
              %
              
              
              (1
              )$250
              
              
              Jan/10
      – Nov/10
              
              
              
              2.27
              %
              
              
              (4
              )$500
              
              
              Jan/10
      – Dec/11
              
              
              
              1.61
              %
              
              
              (2
              )$600
              
              
              Jan/10
      – Jan/14
              
              
              
              2.71
              %
              
              
              (5
              )$50
              
              
              June/10
      – Jan/14
              
              
              
              1.94
              %
              
              
              1Foreign
      exchange forwards8-year
      term
              
              US$80
              
              
              
              2015
              
              
              1.01027
      CAD/USD
              
              
              
              310-year
      term
              
              US$80
              
              
              
              2017
              
              
              1.00016
      CAD/USD
              
              
              
              312-year
      term
              
              US$70
              
              
              
              2019
              
              
              0.99124
      CAD/USD
              
              
              
              315-year
      term
              
              US$20
              
              
              
              2022
              
              
              0.98740
      CAD/USD
              
              
              
              1Cross
      currency10-year
      term
              
              
              £57
              
              
              
              2018
              
              
              2.0075
      CAD/GBP, 6.95%
              
              
              
              (15
              )10-year
      term
              
              
              £20
              
              
              
              2019
              
              
              1.8051
      CAD/GBP, 9.15%
              
              
              
              (2
              )10-year
      term
              
              
              €10
              
              
              
              2019
              
              
              1.5870
      CAD/EUR, 9.22%
              
              
              
              -Total
              
              
              
              
              
              
              
              
              
              
              
              
              
              $
              (151
              )
 
 (1)  The
collars total approximately 59,700 mcf per day between prices of $6.85 and
$10.02 per mcf.
 
 Please
refer to Penn West’s website at www.pennwest.com for details of all financial
instruments currently outstanding.
 
 Realized
gains and losses on the interest rate swaps are recorded as financing costs. In
2009, an expense of $21 million (2008 and 2007 – $nil) was recorded to recognize
the reduction in short-term floating interest rates compared to the fixed
interest rates and terms transacted under our financial
instruments.
 
 In the
first quarter of 2010, Penn West entered into additional natural gas collars for
March 2010 to December 2010 on 30,000 GJ per day at $5.00 per GJ to $5.75 per
GJ. We also entered into crude oil collars on 5,000 barrels per day for 2011 at
US$80.00 to US$90.66 per barrel. Additionally, Penn West entered into
electricity swaps for the remainder of 2010 on 15 MW at $50.00 per MWh, 2011 on
15 MW at $47.00 per MWh, 2012 on 75 MW at $53.65 per MWh, 2013 on 50MW at $55.20
per MWh and in 2014 on 10MW at $59.50.
  25
  Outlook
 
 This
outlook section is included to provide unitholders with information as to our
expectations as at March 18, 2010 for production and capital expenditures for
2010 and readers are cautioned that the information may not be appropriate for
any other purpose. This information constitutes forward-looking information.
Readers should note the assumptions, risks and disclaimers under
"Forward-Looking Statements".
 
 Based
upon our current outlook on commodity prices, our 2010 development capital
expenditures are expected to be in the range of $700 million to $850 million.
Penn West will focus its 2010 capital program on its suite of large-scale
light-oil plays including Waskada, Dodsland, Pembina and Swan Hills. The
application of horizontal multi-fracture completions technology will be an
important factor in the exploitation and development of these opportunities.
Based on this level of capital expenditures, our forecast 2010 average
production is expected to be approximately 165,000 to 173,000 boe per
day.
 
 There
have been no changes from our prior forecast, released on February 18, 2010,
with our 2009 fourth quarter results and filed on SEDAR at
www.sedar.com.
 
 Sensitivity
Analysis
 
 Estimated
sensitivities to selected key assumptions on reported financial results for the
12 months subsequent to this reporting period, including risk management
contracts entered to date, are based on forecasted results as discussed in our
Outlook.
 
 Impact
      on funds flowChange
      of:
              
              Change
              
              
              $
      millions
              
              
              $/unitPrice
      per barrel of liquids
              
              $
              1.00
              
              
              
              17
              
              
              
              0.04Liquids
      production
              
              1,000
      bbls/day
              
              
              
              17
              
              
              
              0.04Price
      per mcf of natural gas
              
              $
              0.10
              
              
              
              10
              
              
              
              0.02Natural
      gas production
              
              10
      mmcf/day
              
              
              
              11
              
              
              
              0.02Effective
      interest rate
              
              
              1
              %
              
              
              2
              
              
              
              -Exchange
      rate ($US per $CAD)
              
              $
              0.01
              
              
              
              21
              
              
              
              0.05
 
 Based on
December 31, 2009 pricing, a $1.00 change in the price per barrel of liquids
would change the pre-tax unrealized risk management loss by $11 million and a
$0.10 change in the price per mcf of natural gas would change the pre-tax
unrealized risk management loss by $2 million.
  26
  Contractual
Obligations and Commitments
 
 We are
committed to certain payments over the next five calendar years as
follows:
 
 (millions)
              
              2010
              
              
              2011
              
              
              2012
              
              
              2013
              
              
              2014
              
              
              ThereafterLong-term
      debt
              
              $
              -
              
              
              $
              1,874
              
              
              $
              -
              
              
              $
              5
              
              
              $
              62
              
              
              $
              1,278Transportation
              
              
              21
              
              
              
              13
              
              
              
              3
              
              
              
              -
              
              
              
              -
              
              
              
              -Transportation
      ($US)
              
              
              3
              
              
              
              3
              
              
              
              3
              
              
              
              3
              
              
              
              3
              
              
              
              3Power
      infrastructure
              
              
              21
              
              
              
              7
              
              
              
              7
              
              
              
              7
              
              
              
              7
              
              
              
              4Drilling
      rigs
              
              
              12
              
              
              
              3
              
              
              
              -
              
              
              
              -
              
              
              
              -
              
              
              
              -Purchase
      obligations (1)
              
              
              13
              
              
              
              13
              
              
              
              13
              
              
              
              12
              
              
              
              11
              
              
              
              19Interest
      obligations
              
              
              124
              
              
              
              105
              
              
              
              89
              
              
              
              89
              
              
              
              85
              
              
              
              247Office
      lease (2)
              
              $
              56
              
              
              $
              72
              
              
              $
              69
              
              
              $
              67
              
              
              $
              61
              
              
              $
              605
 
 (1)
              These
      amounts represent estimated commitments of $62 million for CO2
      purchases and $19 million for processing fees related to interests in the
      Weyburn Unit.
 (2)
              Future
      office lease commitments will be reduced by sublease recoveries totalling
      $397 million.
 
 Our
syndicated credit facility is due for renewal on January 11, 2011. If we are not
successful in renewing or replacing the facility, we could be required to repay
all amounts then outstanding on the facility or enter other loans including term
bank loans. In addition, we have an aggregate of $1.3 billion in senior notes
maturing between 2014 and 2022. We maintain positive working relationships and
are in continuous contact with members in our banking syndicate. Our discussions
with our syndicate banks regarding the renewal of our banking syndicate are
proceeding as expected and we anticipate we will be successful in renewing our
credit facilities on acceptable terms prior to the date of expiry.
 
 Convertible
debentures with an aggregate principal amount of $273 million outstanding on
December 31, 2009 (2008 - $296 million), and a significant portion of the
interest payable on convertible debentures may, at the option of Penn West, be
settled by the issuance of trust units. As at March 18, 2010, convertible
debentures with an aggregate principal amount of $273 million were outstanding.
For a schedule of convertible debenture maturities, please refer to the
“Liquidity and Capital Resources” section of this MD&A or Note 7 to the
audited consolidated financial statements.
 
 Equity
      InstrumentsTrust
      units issued:As
      at December 31, 2009
              
              
              421,638,737Issued
      on exercise of trust unit rights
              
              
              557,677Issued
      to employee savings plan
              
              
              340,956Issued
      pursuant to distribution reinvestment plan
              
              
              1,504,297As
      at March 18, 2010
              
              
              424,041,667Trust
      unit rights outstanding:As
      at December 31, 2009
              
              
              31,816,158Granted
              
              
              3,899,000Exercised
              
              
              (557,677
              )Forfeited
              
              
              (900,799
              )As
      at March 18, 2010
              
              
              34,256,682
  27
  Fourth
Quarter 2009 Highlights
 
 Key
financial and operational results for the fourth quarter 2009 were as
follows:
 
 Three
      months ended December 312009
              
              
              2008
              
              
              %
      changeFinancial(millions,
      except per unit amounts)Gross
      revenues (1)
              
              $
              831
              
              
              $
              968
              
              
              
              (14
              )Funds
      flow
              
              
              366
              
              
              
              490
              
              
              
              (25
              )Basic
      per unit
              
              
              0.87
              
              
              
              1.27
              
              
              
              (32
              )Diluted
      per unit
              
              
              0.86
              
              
              
              1.26
              
              
              
              (32
              )Net
      income (loss)
              
              
              (12
              )
              
              
              404
              
              
              
              (100
              )Basic
      per unit
              
              
              (0.03
              )
              
              
              1.05
              
              
              
              (100
              )Diluted
      per unit
              
              
              (0.03
              )
              
              
              1.04
              
              
              
              (100
              )Distributions
      paid (2)
              
              $
              189
              
              
              $
              392
              
              
              
              (52
              )Capital
      expendituresDevelopment
      capital expenditures
              
              $
              196
              
              
              $
              344
              
              
              
              (43
              )Property
      (dispositions) acquisitions, net
              
              
              (196
              )
              
              
              (56
              )
              
              
              100Capital
      expenditures, net
              
              $
              -
              
              
              $
              288
              
              
              
              (100
              )OperationsDaily
      productionLight
      oil and NGL (bbls/d)
              
              
              77,627
              
              
              
              79,115
              
              
              
              (2
              )Heavy
      oil (bbls/d)
              
              
              24,009
              
              
              
              26,529
              
              
              
              (10
              )Natural
      gas (mmcf/d)
              
              
              411
              
              
              
              476
              
              
              
              (14
              )Total
      production (boe/d)
              
              
              170,164
              
              
              
              184,908
              
              
              
              (8
              )Average
      sales priceLight
      oil and NGL (per bbl)
              
              $
              69.49
              
              
              $
              53.72
              
              
              
              29Heavy
      oil (per bbl)
              
              
              62.97
              
              
              
              38.67
              
              
              
              63Natural
      gas (per mcf)
              
              
              4.39
              
              
              
              7.03
              
              
              
              (38
              )Netback
      per boeSales
      price
              
              $
              51.19
              
              
              $
              46.79
              
              
              
              9Risk
      management gain (loss)
              
              
              1.89
              
              
              
              3.12
              
              
              
              (39
              )Net
      sales price
              
              
              53.08
              
              
              
              49.91
              
              
              
              6Royalties
              
              
              (9.35
              )
              
              
              (8.89
              )
              
              
              5Operating
      expenses
              
              
              (15.10
              )
              
              
              (13.22
              )
              
              
              14Transportation
              
              
              (0.52
              )
              
              
              (0.49
              )
              
              
              6Netback
              
              $
              28.11
              
              
              $
              27.31
              
              
              
              3
 
 (1)
              Gross
      revenues include realized gains and losses on commodity
      contracts.
 (2)
              Includes
      distributions paid prior to those reinvested in trust units under the
      distribution reinvestment plan.
 
 Financial
 
 During
the fourth quarter of 2009, gross revenues were lower compared to 2008 due to
lower realized hedging gains in the period. This also contributed to the decline
in funds flow in the fourth quarter of 2009.
 
 The
reduction in net income from the prior period was primarily due to unrealized
risk management losses in 2009 and unrealized risk management gains in
2008.
 
 During
the fourth quarter of 2009 we closed net property dispositions of $196 million.
These divestitures of non-core assets allowed us to reduce debt while at the
same time focusing future development into areas which provide the best full
cycle economics and value-creation opportunities.
  We
drilled 25 net wells with a success rate of 96 percent in the fourth quarter of
2009 compared to 52 net wells at a success rate of 94 percent in the same period
of 2008. The majority of these wells drilled in 2009 were horizontal multi-stage
fracture wells located in our key light oil resource plays.
  28
  Net debt
was reduced by approximately $222 million in the fourth quarter of 2009 due
primarily to the disposition of non-core assets.
 
 Operations
 
 Quarterly
average production, after the effect of non-core property dispositions, was
170,164 boe per day with a weighting of 60 percent to oil and 40 percent to
natural gas. In
November 2009, Penn West closed the sale of certain non-core heavy oil
properties in the Lloydminster area with production of approximately 6,000 boe
per day.
 
 Oil
prices in the fourth quarter of 2009 averaged WTI US$76.17 per barrel and
appreciated from an average of WTI $68.29 per barrel in the third quarter of
2009 and WTI US$58.76 per barrel in the fourth quarter of 2008. The price of
crude oil increased throughout 2009 consistent with general economic
conditions.
 
 The AECO
Monthly Index averaged $4.01 per GJ in the fourth quarter of 2009 compared to
$2.87 per GJ for the third quarter of 2009 and $6.43 per GJ for the fourth
quarter of 2008. In the fourth quarter of 2009, the price of natural gas started
to improve as storage levels began to normalize due to increased demand from
colder than normal North American weather.
 
 Fourth
quarter netbacks increased in 2009 as a result of stronger liquids
prices.
 
 Disclosure
Controls and Procedures
 
 As of December 31, 2009, an internal
evaluation was carried out under the supervision of our Chief Executive Officer
(the "CEO") and Executive Vice President and Chief Financial Officer (the "CFO")
of the effectiveness of Penn West’s disclosure controls and procedures as
defined in Rule 13a-15 under the US Securities Exchange Act of 1934 and as
defined in Canada by National Instrument 52-109, Certification of Disclosure in
Issuers’ Annual and Interim Filings. Based on that evaluation, the CEO and the
CFO concluded that as of December 31, 2009 the disclosure controls and
procedures were effective to provide reasonable assurance that the information
required to be disclosed in the reports that Penn West files or submits under
the Exchange Act or under Canadian Securities legislation is recorded,
processed, summarized and reported, within the time periods specified in the
rules and forms therein. Disclosure controls and procedures include, without
limitation, controls and procedures designed to ensure that the information
required to be disclosed by Penn West in the reports that it files or submits
under the Exchange Act or under Canadian Securities Legislation is accumulated
and communicated to the Trust’s management, including the senior executive and
financial officers, as appropriate to allow timely decisions regarding the
required disclosure.
  29
  Internal
Control over Financial Reporting
 
 We have a
team of qualified and experienced staff who continue to maintain our compliance
with the applicable regulations regarding internal control over financial
reporting (“ICOFR”). We became a registrant under the U.S. Securities Exchange
Act of 1934 and listed our trust units on the New York Stock Exchange in June
2006. As of December 31, 2009, an internal evaluation was carried out under the
supervision of our CEO and CFO of the effectiveness of our ICOFR as defined in
Rule 13a-15 under the US Securities Exchange Act of 1934 and as defined in
Canada by National Instrument 52-109, Certification of Disclosure in Issuers’
Annual and Interim Filings. The assessment was based
on the framework in Internal Control – Integrated Framework issued by the
Committee of Sponsoring Organizations of the Treadway Commission.Based
on that evaluation, the CEO and the CFO concluded that as of December 31, 2009
our ICOFR was effective.We have
certified our ICOFR and obtained auditor attestation of the operating
effectiveness of our internal control over financial reporting in conjunction
with our 2009 year-end audited financial statements. All significant financial
reporting processes have been documented, assessed, and tested. During the
fourth quarter ended December 31, 2009, Penn West implemented changes to its
internal control over financial reporting, providing an additional
reconciliation related to the ceiling test calculation under US GAAP. Our
reconciliation to US GAAP is available on SEDAR at www.sedar.com and on EDGAR at
www.sec.gov. There were no other changes in Penn West’s internal control over
financial reporting that occurred during the three month period ended December
31, 2009 that have materially affected, or are reasonably likely to materially
affect, Penn West’s internal control over financial reporting.
 
 Accounting
Changes and Pronouncements
 
 In
February 2008, the CICA issued Handbook Section 3064 – “Goodwill and Intangible
Assets”. This standard outlines guidelines for the recognition, measurement,
presentation and disclosure of goodwill and intangible assets subsequent to
their initial recognition. This new standard became effective January 1, 2009
and the adoption had no material impact on Penn West’s financial
statements.
 
 In
December 2008, the CICA issued Handbook Section 1582 – “Business Combinations”.
This standard outlines new guidance which states that the purchase price is to
be based on trading data at the closing date of the acquisition, not the
announcement date of the acquisition, and that most acquisition costs are to be
expensed as incurred. The new standard becomes effective on January 1, 2011 and
early adoption is permitted. Penn West early adopted this standard in the second
quarter of 2009 as it substantially aligns U.S. GAAP and International Financial
Reporting Standards (“IFRS”). The adoption of this standard had no material
impact on Penn West’s financial statements.
 
 In
December 2008, the CICA issued Handbook Section 1601 – “Consolidated Financial
Statements” and Section 1602 – “Non-Controlling Interest”. These sections
outline standards for preparing consolidated financial statements and the
treatment of non-controlling interests in a business combination. Penn West
early adopted these standards in the second quarter of 2009. The adoption of
these standards had no material impact on Penn West’s financial
statements.
 
 In May
2009, the CICA issued amendments to Handbook Section 3862 – “Financial
Instruments – Disclosures”. These amendments outline a hierarchy of methods used
to determine the fair value of financial instruments at a balance sheet date.
Level 1 inputs are based on quoted prices in active markets that Penn West has
the ability to access at the measurement date. Level 2 inputs are based on
quoted prices in markets that are not active or based on prices that are
observable for the asset or liability. Level 3 inputs are based on unobservable
inputs for the asset or liability. These additional disclosures are effective
December 31, 2009 and had no material effect on Penn West’s financial
statements.
 
 Future
Accounting Pronouncements
 
 In
January 2006, the Canadian Accounting Standards Board (the “AcSB”) announced its
decision to replace Canadian GAAP with IFRS for all Canadian Publicly
Accountable Enterprises (“PAEs”), including Penn West. On February 13, 2008, the
AcSB confirmed January 1, 2011 as the transition date for PAEs to commence
reporting under IFRS. Although IFRS is principles-based and uses a conceptual
framework similar to Canadian GAAP, there are significant differences and
choices in accounting policies, as well as increased disclosure requirements
under IFRS.
  30
  In July
2009, the International Accounting Standards Board (“IASB”) issued amendments to
IFRS 1 “First-time adoption of IFRS” allowing additional exemptions for
first-time adopters. Under these amendments, full cost oil and gas companies can
elect to use the recorded amount under a previous GAAP as the deemed cost for
oil and gas assets on the transition date to IFRS. Penn West is currently
planning to adopt this exemption.
 
 In 2009,
our project team completed the diagnostic phase of our project and identified
the key differences between Canadian GAAP and IFRS. We then moved into the
implementation phase which focused on accounting policy decisions, modifications
to IT systems and accounting processes as well as reviewing our internal
controls over financial reporting. During the fourth quarter of 2009, our work
focused on completing integration testing on our IT systems, conducting a pilot
of our newly designed systems and processes and determining IFRS disclosure
requirements. The implementation phase will continue into 2010.
 
 The
project team and steering committee continue to provide updates to senior
management and the Audit Committee. We will provide the key elements of our plan
and progress on the project as information becomes available during the
transition period.
 
 We
currently expect that the significant differences between our existing
accounting policies under Canadian GAAP and those under IFRS will include the
following:
 
 -
              Depletion
      and depreciation of property, plant and equipment (“PP&E”) will be
      based on significant components. Depletion of resource properties will
      generally continue to be calculated using the unit-of-production method;
      however under IFRS there is an option to base depletion on production
      volumes before royalties as a proportion of total proved reserves or total
      proved plus probable reserves. Depreciation of all other assets will be
      calculated on a straight-line basis over their estimated useful
      life.
 -
              Oil and gas
      properties will be classified as either PP&E or Exploration and
      Evaluation assets (“E&E”).E&E assets will be measured at
      cost and are classified according to the nature of the expenditures and
      whether or not technical feasibility and commercial viability of
      extracting oil and gas from the property under consideration has been
      demonstrated.
 -
              E&E
      costs will be reclassified to PP&E, to the extent they are not
      impaired, when proved reserves have been assigned to the asset. If proved
      reserves will not be established through the completion of E&E
      activities and there are no future plans for development activity, then
      the E&E expenditures will be reviewed for impairment. Any impairments
      would be charged to income.
 -
              Impairment
      testing on oil and gas properties will be performed at a lower level than
      under current Canadian GAAP.
 -
              Share-based
      payments are expensed based on a graded vesting
  schedule.
 -
              Discount
      rates used in calculating the asset retirement obligation are currently
      under review by the IASB as there is diversity in practice when selecting
      a rate. Future changes to the standards and further interpretations of the
      guidance could lead to a material change in this provision upon adoption
      of IFRS.
 
 We are
currently in the process of evaluating the impact of the above noted accounting
policy choices and the effect they will have on our financial statements. We
will disclose additional information on the impact of the changes throughout
2010. Any amendments to existing IFRS standards or implementation of new IFRS
standards could lead to additional changes.
 
 Related-Party
Transactions
 
 During
2009, Penn West paid $2 million (2008 – $5 million) of legal fees to a law firm
of which a partner is also a director of Penn West.
 
 Off-Balance-Sheet
Financing
 
 We have
off-balance-sheet financing arrangements consisting of operating leases. Future
operating lease payments are summarized in the Contractual Obligations and
Commitments section.
  31
  Critical
Accounting Estimates
 
 Our
significant accounting policies are detailed in Note 2 to the audited
consolidated financial statements. 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.
 
 All of
our reserves were evaluated or audited by GLJ Petroleum Consultants Ltd. (”GLJ”)
and Sproule Associates Limited (“SAL”), both independent engineering firms. Our
reserves are 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 “ceiling test”
write-down against income must be made. We determined there was no ceiling test
write-down required at December 31, 2009, for Canadian GAAP.
 
 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 income, included in DD&A. Revisions to the estimated amount or
timing of the obligations are reflected as increases or decreases to the
recorded 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 9 to the audited
consolidated financial statements details the impact of these accounting
recommendations.
 
 Financial
Instruments
 
 Financial
instruments included in the balance sheets consist of accounts receivable, fair
values of derivative financial instruments, current liabilities (excluding
future income tax liability), convertible debentures and long-term debt. Except
for the senior notes and the convertible debentures, 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 applicable to the bank
debt. The estimated fair value of the senior notes and the convertible
debentures is disclosed in Notes 6 and 7 to the audited consolidated financial
statements.
 
 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
funds flows are sufficient to fund planned capital programs and distributions,
collars or other financial instruments may be utilized from time to time.
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.
 
 Substantially
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 executing counterparty risk
procedures which include transacting only with financial institutions who are
members of our credit facility or those with high credit ratings as well as
obtaining security in certain circumstances.
  32
  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. The goodwill impairment test consists
of two parts. Under part 1, if the fair value of the reporting entity is less
than its book value, part 2 of the test must be performed. As at December 31, 2009,
our market capitalization, plus a 20 percent equity control premium, exceeded
the book value of Penn West. As a result, Penn West determined there was no
goodwill impairment at December 31, 2009.
 
 Future
Income Tax
 
 Future
income taxes are recorded based on the asset and liability method of accounting
whereby temporary differences are calculated assuming financial assets and
liabilities will be settled at their carrying amount. Future income taxes are
computed on temporary differences using substantively enacted income tax rates
expected to apply when future income tax assets and liabilities are realized or
settled.
 
 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: our anticipated monthly per unit distribution
level and the factors that may affect such distribution level; our intention to
accelerate the development of certain of our large scale light oil properties;
our future prospects and the factors that will affect those prospects; our
intention and ability to focus future development into assets which provide the
best economics and value-creation opportunities for our unitholders; our
intention and ability to increase our reserve and production by applying new
completions technologies to our assets; our expectations regarding North
American and global supply and demand factors for crude oil and natural gas in
2010 and beyond; our expectations regarding differentials between light, medium
and heavy oil prices in 2010; our intention to continue to review strategic
acquisitions and dispositions; our belief that we will be successful in renewing
our credit facility on acceptable terms prior to its expiry; the disclosure
contained under the heading "Update on SIFT Tax and Corporate Conversion", which
among other things identifies our intention to convert to a corporate structure
by mid-2011 and the factors affecting the timing of such conversion, our
expectation that total shareholder return following conversion will be a
combination of growth and yield, our potential ability to shield our taxable
income from income tax using our tax pools for an extended period of time
following the implementation of the SIFT Tax, and the impact the SIFT Tax may
have on our distributions and our unitholders; the identity of our primary
business risks going forward and the nature and effectiveness of our risk
management strategies; the ability of our strategies to increase the likelihood
that we will be able to maintain our financial flexibility to capture
opportunities availed by the current market, continue our capital and
distribution programs, and execute our business strategies; funding sources for
distributions and distribution levels and whether a special distribution will be
made in 2010; our belief that our current capital programs should be sufficient
to maintain our productive capacity over the medium term; our belief that our
current environmental programs will be sufficient to fund our asset retirement
obligations over the life of our reserves; the disclosure contained under the
heading "Outlook", which sets forth management's expectations as to our capital
expenditure levels for 2010, the nature of our 2010 capital expenditures, and
our forecast average daily production for 2010; the disclosure contained under
the heading "Sensitivity Analysis" relating to the estimated sensitivity of our
reported financial results for the next 12 months in respect of funds flow and
pre-tax unrealized risk management loss to changes in certain operational and
financial metric assumptions; and our expectations regarding the impact that new
and pending accounting changes may have on us, including the adoption of
IFRS.
  33
  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 capital
expenditure levels; future oil and natural gas production levels; future
exchange rates and interest rates; the amount of future cash distributions that
we intend to pay; 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; and our ability to add
production and reserves through our development and exploitation activities. In
addition, many of the forward-looking statements contained in this document are
located proximate to assumptions that are specific to those forward-looking
statements, and such assumptions should be taken into account when reading such
forward-looking statements: see in particular the assumptions identified under
the headings "Update on SIFT Tax and Corporate Conversion", "Standardized
Distributable Cash", "Outlook" and "Sensitivity Analysis".
 
 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: the impact of weather
conditions on seasonal demand and ability to execute capital programs; risks
inherent in oil and natural gas operations; uncertainties associated with
estimating reserves and resources; competition for, among other things, capital,
acquisitions of reserves, resources, undeveloped lands and skilled personnel;
incorrect assessments of the value of acquisitions, including the completed
acquisitions discussed herein; geological, technical, drilling and processing
problems; general economic conditions in Canada, the U.S. and globally; industry
conditions, including fluctuations in the price of oil and natural gas;
royalties payable in respect of our oil and natural gas production and changes
thereto; changes in government regulation of the oil and natural gas industry,
including environmental regulation; fluctuations in foreign exchange or interest
rates; unanticipated operating events 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 completed acquisitions discussed herein; changes in tax laws that
affect us and our securityholders; changes in government royalty frameworks;
uncertainty of obtaining required approvals for acquisitions and mergers; 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 Penn West’s Annual Information Form,
is available on SEDAR at www.sedar.com.


2009 ANNUAL MD&A
33