**Exhibit99.2**

**Management’s Discussion &Analysis and Audited Consolidated Financial Statements**

For the year ended December 31, 2006

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**CONTENTS**
| Management’s Discussion and  Analysis      |   | 1      |
|-------------------------------------------------|--------|--------|
|                                            |   |   |
| Management’s Report                        |   | 23     |
|                                            |   |   |
| Auditors’ Report  to the Unitholders       |   | 24     |
|                                            |   |   |
| Consolidated  Financial Statements              |   | 25     |
|                                            |   |   |
| Notes to the  Consolidated Financial Statements |   | 28     |
|                                            |   |   |
| Investor  Information                           |   | 43-44  |

 

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**MANAGEMENT’S DISCUSSION AND ANALYSIS**

This management’s discussion and analysis (“MD&A”)of financial conditions and results of operations should be read in conjunctionwith the audited consolidated financial statements and accompanying notes ofPenn West Energy Trust (“Penn West”, “the Trust”, “We” or “Our”) for the yearsended December 31, 2006 and 2005. The date of this MD&A is February 28,2007.

For additional information, including the Trust’saudited financial statements and Annual Information Form (when filed), go tothe Trust’s website at www.pennwest.com, in Canada at www.sedar.com or in theUnited States at www.sec.gov.

All dollar amounts contained in this MD&A areexpressed in millions of Canadian dollars unless noted otherwise.

Please refer to our disclaimer on forward-lookingstatements at the end of this MD&A. The calculations of barrels of oilequivalent (“boe”) are based on a conversion ratio of six thousand cubic feetof natural gas to one barrel of crude oil. This could be misleading if used inisolation as it is based on an energy equivalency conversion method at theburner tip and does not necessarily represent a value equivalency at thewellhead.

Measures including cash flow, cash flow perunit-basic, cash flow per unit-diluted, netbacks and distributable cash fromoperations included in this MD&A are not defined in generally acceptedaccounting principles (“GAAP”); accordingly, they may not be comparable tosimilar measures provided by other issuers. Management utilizes cash flow, andnetbacks to assess financial performance, to allocate its capital amongalternative projects and to assess our capacity to fund distributions andfuture capital programs.

**Calculation of Cash Flow**
| ** **                                                         | ** ** | **Three months ended December 31** | ** ** | **Year ended December 31** | ** ** |
|--------------------------------------------------------------------|------------|--------------------------------------------------------|------------|-------------------------------------------|------------|
| **($ millions, except per unit amounts)** | ** ** | **2006**                                               | ** ** | **2005**                                  | ** ** | **2006** | ** ** | **2005** | ** ** |
| Cash flow from  operating activities                               | ** ** | **$**                                                  | **261.1**  |                                      | $          | 368.7 | ** ** | **$** | **1,106.3** |   | $ | 932.8 |   |
| Increase (decrease) in  non-cash working capital                   | ** ** | **32.9**                                               |       | (42.4                                     | )          | **43.6** |   | 1.8 |   |
| Payments for  surrendered options                                  | ** ** | **—**                                             |       | —                                    | ** ** | **—** |   | 141.6 |   |
| Asset retirement  expenditures                                     | ** ** | **9.3**                                                |       | 6.3                                       | ** ** | **26.9** |   | 22.6 |   |
| Realized foreign  exchange gain                                    | ** ** | **—**                                             |       | —                                    | ** ** | **—** |   | 85.8 |   |
| Cash flow                                                          | ** ** | **$**                                                  | **303.3**  |                                      | $          | 332.6 | ** ** | **$** | **1,176.8** |   | $ | 1,184.6 |   |
| Basic per unit                                                     | ** ** | **$**                                                  | **1.23**   |                                      | $          | 2.03 | ** ** | **$** | **5.86** |   | $ | 7.28 |   |
| Diluted per unit                                                   | ** ** | **$**                                                  | **1.22**   |                                      | $          | 2.03 | ** ** | **$** | **5.78** |   | $ | 7.14 |   |

 

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**QuarterlyFinancial Summary**

($ millions, except per unit and production amounts)
| ** **                       | ** ** | ** **                                | ** ** | ** **        | ** ** | ** **       | ** ** | ** **       | ** ** | ** **       | ** ** | ** **        | ** ** | ** **       | ** ** | **Penn West** | ** ** |
|----------------------------------|------------|-------------------------------------------|------------|-------------------|------------|------------------|------------|------------------|------------|------------------|------------|-------------------|------------|------------------|------------|--------------------|------------|
| ** **                       | ** ** | ** **                                | ** ** | ** **        | ** ** | ** **       | ** ** | ** **       | ** ** | ** **       | ** ** | ** **        | ** ** | ** **       | ** ** | **Petroleum**      | ** ** |
| ** **                       | ** ** | **Penn West Energy Trust** | ** ** | **Ltd.**          | ** ** |
| ** **                       | ** ** | **Dec. 31**                          | ** ** | **Sept. 30** | ** ** | **June 30** | ** ** | **Mar. 31** | ** ** | **Dec. 31** | ** ** | **Sept. 30** | ** ** | **June 30** | ** ** | **Mar. 31**   | ** ** |
| **Three months ended** | ** ** | **2006**                                  | ** ** | **2006**          | ** ** | **2006**         | ** ** | **2006**         | ** ** | **2005**         | ** ** | **2005**          | ** ** | **2005**         | ** ** | **2005**           | ** ** |
| Gross revenues                   | ** ** | **$**                                     | **578.5**  |              | $          | 636.0            |       | $                | 452.5      |             | $          | 433.9             |       | $                | 554.5      |               | $          | 535.0 |   | $ | 424.2 |   | $ | 405.3 |   |
| Cash flow                        | ** ** | **303.3**                                 |       | 365.6             |       | 264.7            |       | 243.2            |       | 332.6            |       | 334.9             |       | 257.0            |       | 260.1              |       |
| Basic per unit(1)                | ** ** | **1.23**                                  |       | 1.55              |       | 1.59             |       | 1.49             |       | 2.03             |       | 2.06              |       | 1.58             |       | 1.61               |       |
| Diluted per unit(1)              |       | **1.22**                                  |       | 1.53              |       | 1.56             |       | 1.47             |       | 2.03             |       | 2.04              |       | 1.49             |       | 1.58               |       |
| Net income                       | ** ** | **122.9**                                 |       | 177.8             |       | 220.5            |       | 144.4            |       | 241.1            |       | 209.5             |       | 59.7             |       | 66.9               |       |
| Basic per unit(1)                | ** ** | **0.44**                                  |       | 0.66              |       | 1.34             |       | 0.88             |       | 1.48             |       | 1.29              |       | 0.37             |       | 0.41               |       |
| Diluted per unit (1)             | ** ** | **0.44**                                  |       | 0.65              |       | 1.31             |       | 0.87             |       | 1.46             |       | 1.27              |       | 0.34             |       | 0.41               |       |
| Distributions  declared          | ** ** | **241.5**                                 |       | 240.7             |       | 167.6            |       | 162.0            |       | 151.8            |       | 127.3             |       | 42.4             |       | —             |       |
| Per unit                         | ** ** | **1.02**                                  |       | 1.02              |       | 1.02             |       | 0.99             |       | 0.93             |       | 0.78              |       | 0.26             |       | —             |       |
| Dividends  declared              | ** ** | —                                    |       | —            |       | —           |       | —           |       | —           |       | —            |       | —           |       | 10.8               |       |
| Per unit (1)                     | ** ** | **$**                                     | **—** |              | $          | —           |       | $                | —     |             | $          | —            |       | $                | —     |               | $          | — |   | $ | — |   | $ | 0.07 |   |
| Production                       |       |                                      |       |              |       |             |       |             |       |             |       |              |       |             |       |               |       |
| Liquids (2) (bbls/day)           | ** ** | **70,819**                                |       | 69,215            |       | 48,599           |       | 52,226           |       | 51,953           |       | 51,634            |       | 50,633           |       | 53,162             |       |
| Natural gas (mmcf/day)           | ** ** | **354.6**                                 |       | 359.1             |       | 267.9            |       | 266.9            |       | 277.5            |       | 289.0             |       | 295.7            |       | 289.1              |       |
| Total (boe/day)                  | ** ** | **129,915**                               |       | 129,059           |       | 93,242           |       | 96,713           |       | 98,205           |       | 99,802            |       | 99,910           |       | 101,343            |       |

 

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(1)  Per unit figures for the periods priorto June 30, 2005 have been restated to reflect the conversion of Penn Westcommon shares to trust units using an exchange ratio of three trust units pershare in accordance with the plan of arrangement dated May 31, 2005 related tothe trust conversion.

(2)  Includescrude oil and natural gas liquids.

**Petrofund Merger**

As of June 30, 2006, all approvals required to closethe merger of Penn West and Petrofund Energy Trust (“Petrofund”) had beenreceived and the merger was completed effective June 30, 2006. Petrofundunitholders received 0.6 of a Penn West unit for each Petrofund unit exchangedand also received a special distribution of $1.00 per unit plus an adjustmentof $0.10 per unit required to align the distribution dates of the trusts.

Penn West accounted for the Petrofund merger as a purchase ofPetrofund. The consolidated financial statements of Penn West include theresults of operations and cash flows of Petrofund from July 1, 2006 forward. Ifthe merger had occurred on January 1, 2006, Penn West would have realized thefollowing pro forma results for the year ended December 31, 2006:
| **($ millions, except per unit amounts)** | ** ** | ** ** | ** ** |
|--------------------------------------------------------------------|------------|------------|------------|
| Revenue                                                            |       | $          | 2,496.5    |   |
| Net income                                                         |       | 722.9      |       |
| Basic per unit                                                     |       | 3.07       |       |
| Diluted per unit                                                   |       | $          | 3.03       |   |
| Production (boe/day)                                               |       | 132,373    |       |

 

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**Business Environment**

The current business environment has moderatecommodity prices, accessible capital markets, low interest rates by historicalstandards and a relatively stable regulatory environment other than the October31, 2006 Government of Canada announcement of proposed changes to the taxationof income trusts.

Continuing demand for crude oil from growing economiessuch as China and India, along with political instability in parts of theworld, resulted in stronger oil prices in 2006. The price of West TexasIntermediate (“WTI”), the primary benchmark for light crude oil prices,averaged US$66.22 per barrel in 2006, up by 17 percent from 2005.

Heavy oil differentials narrowed in 2006 as asphaltand residual fuel markets’ demand exceeded the normal seasonal demand early in2006. The price was also supported by industry initiatives to improve accessinto U.S. heavy oil markets. The Canadian Bow River differential to WTInarrowed by 10 percent from 2005.

AECO natural gas prices weakened in 2006, decreasingby 26 percent to $6.53 per mcf from $8.81 per mcf in 2005. Warm 2005 and early2006 winters in North America resulted in lower demand and higher storagelevels that lead to lower prices.

Lower natural gas prices and a strengthening of theCanadian dollar relative to the U.S. dollar more than offset the benefit ofstronger oil prices. Oil sales contracts are generally based on WTI pricesdenominated in U.S. dollars; therefore the strengthening Canadian dollarreduces Canadian dollar realization. The average exchange rate increased fromCAD$1.00 equals USD$0.825 in 2005 to CAD$1.00 equals USD$0.882 in 2006. Inearly 2007, the Canadian dollar has weakened to approximately CAD$1.00 equalsUSD$0.85.

Regulations and incentive programs governing thecalculation of royalties have been stable in recent years; however, there canbe no assurance they will not change in the future.

High levels of industry activity increased operatingcosts in 2006 due to increases in the demand for energy, steel, services andother costs over 2005. However, Penn West is encouraged that its fourth quarter2006 operating costs per barrel of oil equivalent remained approximately levelwith the third quarter of 2006. The flat operating cost per barrel of oilequivalent was achieved by our initiatives to contain operating cost increasesand by realizing approximately $17 million in gains on electricity hedges.

We have a proven management team, dedicated employeesand a business plan appropriate for an energy trust. Over the last 15 years, weprogressed from a small explorer and producer to the top ranks of independentoil and natural gas producers in Western Canada. In 2005, we converted into thelargest conventional oil and natural gas trust by production in Canada andadded to production and reserves through the Petrofund merger in 2006. We havea disciplined approach to business that stresses cost control and productbalance. Using this discipline, we have shown that we can explore for anddevelop grassroots reserves, and also successfully acquire and optimizeproducing fields. We have a diverse asset base in the Western CanadaSedimentary Basin divided into three core areas ranging from southern Manitobato regions bordering the Northwest Territories.

Our goal is to create and protect unitholder value by:

·                  Pursuing an active program ofinternal development, focusing on low-risk opportunities to maintain productionor reduce operating costs, and on resource plays such as the Peace River OilSands project and our portfolio of CO2 enhanced oil recovery projects;

·                  Participating in exploration, withoutthe requirement to fund capital expenditures, through the farm-out ofundeveloped lands;

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·                  Rationalizing our asset base with theaim of maintaining distributions over the long-term, including assetacquisitions and dispositions that are accretive or strategic; and

·                  Maintaining a strong balance sheet.

**Proposed Tax on Income Trusts**

On October 31, 2006, the Government of Canadaannounced proposed changes to the taxation of publicly traded income trusts.Commencing in 2011, taxes at estimated corporate tax rates were proposed ondistributions that represent a return on capital by disallowing thesedistributions as a deduction in the calculation of the trust’s taxable income.Subsequent to the October 31 announcement, the Government of Canada tableddraft legislation and clarified the rules related to “undue expansion”.Recently, hearings of the House of Commons’ finance committee have been held;however, it is not yet clear what impact, if any, the hearings will have on theproposed tax. If the tax proposals are enacted into law as proposed on October31, 2006, they could have some or all of the following impacts, and Penn Westcould take some or all of the following actions:

·                  If structural or other similarchanges are not made, the after-tax distribution yield in 2011 to taxableCanadian investors will remain approximately the same, however, thedistribution yield in 2011 to tax- deferred Canadian investors (RRSPs, RRIFs,pension plans, etc.) and foreign investors will fall by an estimated 31.5percent and 26.5 percent, respectively;

·                  A portion of Penn West’s cash flowcould be allocated to the payment of cash distribution taxes, or other forms oftax, and will not be available for distribution or re-investment;

·                  It could be determined that it ismore economic for Penn West to change its corporate structure to facilitateinvesting a higher proportion or all of its cash flow in exploration anddevelopment projects. Such a conversion and change to capital programs wouldresult in a significant reduction or elimination of distributions and/ordividends;

·                  It could be determined that it ismore economic to remain in the trust structure and pay corporate income taxesrather than the proposed distribution tax and pay all or a portion of ourdistributions on a return of capital basis at a potentially significantly lowerpayout ratio;

·                  Other strategic alternatives could bedetermined to be more economic than any of the above; and/or

·                  If income trusts are subsequentlydetermined to be taxable entities for future income tax accounting purposes,the recording of an additional future income tax liability would be requiredand the change in the future income tax liability could be material.

The table below, provided by the Government of Canadain a backgrounder accompanying its October 31, 2006 announcement, shows asimplified comparison of the effects of the proposed changes to investor taxrates in 2011:
| ** **                        | ** ** | **Current System**              | ** ** | **Proposed System**   | ** ** |
|-----------------------------------|------------|--------------------------------------|------------|----------------------------|------------|
| ** **                        | ** ** | **Income Portion**              | ** ** | **Large Corporation** | ** ** | **Income Portion** | ** ** | **Large Corporation** | ** ** |
| **Investor**                      | ** ** | **of Trust Distributions** | ** ** | **(dividend)**             | ** ** | **of Trust Distributions** | ** ** | **(dividend)** | ** ** |
| Taxable Canadian  individuals (1) |       | 46                                   | %          | 46                         | %          | 45.5 | % | 45.5 | % |
| Canadian tax-exempt  investors    |       | 0                                    | %          | 32                         | %          | 31.5 | % | 31.5 | % |
| Taxable U.S. investors (2)        |       | 15                                   | %          | 42                         | %          | 41.5 | % | 41.5 | % |

 

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(1)  All rates in the table are as of 2011,and include both entity- and investor-level tax (as applicable). Rates for “taxableCanadian individuals” assume that top personal income tax rates apply and thatprovincial governments increase their dividend tax credit for dividends oflarge corporations.

(2)  Canadiantaxes only. U.S. tax will also apply in most cases, net of any foreign taxcredits.

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Our Board of Directors and management team arereviewing the impact, if any, of the proposals on our business strategy.

**Unitholder Value Measures**
| ** **                                       | ** ** | **Year ended December 31** | ** ** |
|--------------------------------------------------|------------|-------------------------------------------|------------|
| ** **                                       | ** ** | **2006**                                  | ** ** | **2005** | ** ** | **2004** | ** ** |
| Cash flow per  unit ($)                          | ** ** | **5.86**                                  |       | 7.28 |   | 5.37 |   |
| Distributions  per unit ($)                      | ** ** | **4.05**                                  |       | 1.97 |   | — |   |
| Dividends per  unit ($)                          | ** ** | **—**                                |       | 0.07 |   | 0.16 |   |
| Ratio of year-end bank  debt to annual cash flow | ** ** | **1.1**                                   |       | 0.5 |   | 0.6 |   |

 

We have a strong in-house professional and technicalstaff, an extensive base of undeveloped land (3.7 million net acres) and astrong balance sheet. These attributes provide us the ability to pursuestrategies of organic growth through development and optimization, growththrough strategic or accretive acquisitions and the farm-out of undevelopedland. We believe in the application of financial discipline in all areas ofoperations as a key factor in achieving superior returns on investment for ourunitholders.

**Performance Indicators**
| ** **                      | ** ** | **Year ended December 31** | ** ** |
|---------------------------------|------------|-------------------------------------------|------------|
| ** **                      | ** ** | **2006**                                  | ** ** | **2005** | ** ** | **2004** | ** ** |
| Return on  capital employed (1) | ** ** | **12.8**                                  | **%**      | 17.0 | % | 9.0 | % |
| Total assets ($ millions)  | ** ** | **8,070**                                 |       | 3,967 |   | 3,867 |   |
| Return on equity (2)            | ** ** | **18.1**                                  | **%**      | 28.3 | % | 15.3 | % |

 

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(1)          Netincome before financing charges divided by average total liabilities lesscurrent assets.

(2)          Net income divided byaverage unitholders’ equity.

**Results of Operations**

Production
| ** **                         | ** ** | **Three months ended December 31** | ** ** | **Year ended December 31** | ** ** |
|------------------------------------|------------|--------------------------------------------------------|------------|-------------------------------------------|------------|
| **Daily Production**          | ** ** | **2006**                                               | ** ** | **2005**                                  | ** ** | **% change** | ** ** | **2006** | ** ** | **2005** | ** ** | **% change** | ** ** |
| Natural gas  (mmcf/day)            | ** ** | **354.6**                                              |       | 277.5                                     |       | 28 | ** ** | **312.5** |   | 287.8 |   | 9 |   |
| Light oil and  NGL (bbls/day)      | ** ** | **48,233**                                             |       | 33,227                                    |       | 45 | ** ** | **39,514** |   | 33,137 |   | 19 |   |
| Conventional  heavy oil (bbls/day) | ** ** | **22,586**                                             |       | 18,726                                    |       | 21 | ** ** | **20,776** |   | 18,705 |   | 11 |   |
| Total production  (boe/day) (1)    |       | **129,915**                                            |       | 98,205                                    |       | 32 | ** ** | **112,369** |   | 99,807 |   | 13 |   |

 

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(1)          Barrels of oilequivalent (boe) are based on six mcf of natural gas being equal to one barrelof oil (6:1).

The increase in production was generally due to thePetrofund merger closing at the end of June 2006, and to our development andoptimization programs.

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We strive to maintain an approximately balancedportfolio of liquids and natural gas production provided it is economic to doso. We believe a balance by product helps to reduce exposure to pricevolatility that can affect a single commodity. Crude oil and NGL production averaged70,819 barrels per day (55 percent of production) in the fourth quarter of 2006and natural gas production averaged 354.6 mmcf per day (45 percent of production)in the same quarter.

We invested $159.4 million on capital expenditures anddrilled 52 net wells in the fourth quarter of 2006. Drilling activity wasfocused in the Central and Plains areas.

**Commodity Markets**

Natural Gas

Natural gas prices declined throughout 2006, fromclose to record highs at the end of the prior year, due to a warm winter in2005-2006 that weakened demand and resulted in higher than normal storagelevels. Spot natural gas prices at AECO in the fourth quarter of 2006 increasedby $1.18 per mcf or 21 percent from the prior quarter to average $6.91 per mcfwhile decreasing by $4.70 per mcf or 40 percent from the fourth quarter of2005. AECO gas prices of $6.53 per mcf in 2006 decreased by 26 percent from$8.81 per mcf for the prior year.

Crude Oil

International crude oil prices remained strong withthe benchmark West Texas Intermediate price averaging US$59.96 per barrel inthe fourth quarter of 2006. However, this was a decrease of US$10.52 per barrelfrom the prior quarter. Oil prices had reached near-record highs in 2006 withcontinued high demand for crude oil and refined products and politicalinstability in the Middle East. The Edmonton par price for light sweet crudeoil remained strong year-over-year, slightly under performing WTI, due to awell-supplied crude oil market in Canada and the strengthening of the Canadiandollar relative to the U.S. dollar.

**Average Sales Prices Received**
| ** **                         | ** ** | **Three months ended December 31** | ** ** | **Year ended December 31** | ** ** |
|------------------------------------|------------|--------------------------------------------------------|------------|-------------------------------------------|------------|
| ** **                         | ** ** | **2006**                                               | ** ** | **2005**                                  | ** ** | **% change** | ** ** | **2006** | ** ** | **2005** | ** ** | **% change** | ** ** |
| Natural gas  ($/mcf)               | ** ** | **$**                                                  | **6.97**   |                                      | $          | 11.66 |   | (40 | ) | **$** | **6.75** |   | $ | 8.68 |   | (22 | ) |
| Risk management  $mcf              | ** ** | **0.56**                                               |       | —                                    |       | — | ** ** | **0.72** |   | 0.06 |   | 1,100 |   |
| Natural gas net  ($/mcf)           | ** ** | **7.53**                                               |       | 11.66                                     |       | (35 | ) | **7.47** |   | 8.74 |   | (15 | ) |
|                               | ** ** | ** **                                             |       |                                      |       |   |   | ** ** |   |   |   |   |   |
| Light oil and  liquids ($/bbl)     | ** ** | **57.43**                                              |       | 64.28                                     |       | (11 | ) | **65.02** |   | 62.59 |   | 4 |   |
| Risk management  ($/bbl)           | ** ** | **0.01**                                               |       | —                                    |       | — | ** ** | **(1.00** | **)** | — |   | — |   |
| Light oil and  liquids net ($/bbl) | ** ** | **57.44**                                              |       | 64.28                                     |       | (11 | ) | **64.02** |   | 62.59 |   | 2 |   |
|                               | ** ** | ** **                                             |       |                                      |       |   |   | ** ** |   |   |   |   |   |
| Conventional  heavy oil ($/bbl)    | ** ** | **37.57**                                              |       | 34.95                                     |       | 7 | ** ** | **43.07** |   | 35.71 |   | 21 |   |
|                               | ** ** | ** **                                             |       |                                      |       |   | ** ** | ** ** |   |   |   |   |   |
| Weighted average  ($/boe)          | ** ** | **46.88**                                              |       | 61.38                                     |       | (24 | ) | **49.58** |   | 52.50 |   | (6 | ) |
| Risk management  ($/boe)           | ** ** | **1.53**                                               |       | —                                    |       | — | ** ** | **1.64** |   | 0.18 |   | 811 |   |
| Weighted average net ($/boe)       | ** ** | **$**                                                  | **48.41**  |                                      | $          | 61.38 |   | (21 | ) | **$** | **51.22** |   | $ | 52.68 |   | (3 | ) |

 

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**Operating Netbacks**
| ** **                  | ** ** | **Three months ended December 31** | ** ** | **Year ended December 31** | ** ** |
|-----------------------------|------------|--------------------------------------------------------|------------|-------------------------------------------|------------|
| ** **                  | ** ** | **2006**                                               | ** ** | **2005**                                  | ** ** | **% change** | ** ** | **2006** | ** ** | **2005** | ** ** | **% change** | ** ** |
| **Natural  gas**            | ** ** | ** **                                             | ** ** | ** **                                | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** |
| Production (mmcf/day)       | ** ** | **354.6**                                              |       | 277.5                                     |       | 28 | ** ** | **312.5** |   | 287.8 |   | 9 |   |
| Operating netback ($/mcf):  |       |                                                   |       |                                      |       |   |   |   |   |   |   |   |   |
| Sales price                 | ** ** | **$**                                                  | **6.97**   |                                      | $          | 11.66 |   | (40 | ) | **$** | **6.75** |   | $ | 8.68 |   | (22 | ) |
| Hedging gain                | ** ** | **0.56**                                               |       | —                                    |       | — | ** ** | **0.72** |   | 0.06 |   | 1,100 |   |
| Royalties                   | ** ** | **1.61**                                               |       | 2.67                                      |       | (40 | ) | **1.51** |   | 1.86 |   | (19 | ) |
| Operating costs             | ** ** | **1.04**                                               |       | 0.87                                      |       | 20 | ** ** | **0.99** |   | 0.85 |   | 16 |   |
| Transportation              | ** ** | **0.18**                                               |       | 0.22                                      |       | (18 | ) | **0.21** |   | 0.21 |   | — |   |
| Netback                     | ** ** | **$**                                                  | **4.70**   |                                      | $          | 7.90 |   | (41 | ) | **$** | **4.76** |   | $ | 5.82 |   | (18 | ) |
| **Light  oil and NGL**      | ** ** | ** **                                             | ** ** | ** **                                | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** |
| Production  (bbls/day)      | ** ** | **48,233**                                             |       | 33,227                                    |       | 45 | ** ** | **39,514** |   | 33,137 |   | 19 |   |
| Operating netback ($/bbl):  |       |                                                   |       |                                      |       |   |   |   |   |   |   |   |   |
| Sales price                 | ** ** | **$**                                                  | **57.43**  |                                      | $          | 64.28 |   | (11 | ) | **$** | **65.02** |   | $ | 62.59 |   | 4 |   |
| Hedging gain / (loss)       | ** ** | **0.01**                                               |       | —                                    |       | — | ** ** | **(1.00** | **)** | — |   | — |   |
| Royalties                   | ** ** | **10.21**                                              |       | 11.46                                     |       | (11 | ) | **10.51** |   | 10.17 |   | 3 |   |
| Operating costs             | ** ** | **15.36**                                              |       | 15.17                                     |       | 1 | ** ** | **15.80** |   | 14.43 |   | 9 |   |
| Netback                     | ** ** | **$**                                                  | **31.87**  |                                      | $          | 37.65 |   | (15 | ) | **$** | **37.71** |   | $ | 37.99 |   | (1 | ) |
| **Conventional  heavy oil** | ** ** | ** **                                             | ** ** | ** **                                | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** |
| Production  (bbls/day)      | ** ** | **22,586**                                             |       | 18,726                                    |       | 21 | ** ** | **20,776** |   | 18,705 |   | 11 |   |
| Operating netback ($/bbl):  |       |                                                   |       |                                      |       |   |   |   |   |   |   |   |   |
| Sales price                 | ** ** | **$**                                                  | **37.57**  |                                      | $          | 34.95 |   | 7 | ** ** | **$** | **43.07** |   | $ | 35.71 |   | 21 |   |
| Royalties                   | ** ** | **5.44**                                               |       | 5.67                                      |       | (4 | ) | **6.51** |   | 5.41 |   | 20 |   |
| Operating costs             | ** ** | **11.88**                                              |       | 9.64                                      |       | 23 | ** ** | **11.22** |   | 9.30 |   | 21 |   |
| Transportation              | ** ** | **0.07**                                               |       | 0.10                                      |       | (30 | ) | **0.07** |   | 0.09 |   | (22 | ) |
| Netback                     | ** ** | **$**                                                  | **20.18**  |                                      | $          | 19.54 |   | 3 | ** ** | **$** | **25.27** |   | $ | 20.91 |   | 21 |   |
| **Total  liquids**          | ** ** | ** **                                             | ** ** | ** **                                | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** |
| Production  (bbls/day)      | ** ** | **70,819**                                             |       | 51,953                                    |       | 36 | ** ** | **60,290** |   | 51,842 |   | 16 |   |
| Operating netback ($/bbl):  |       |                                                   |       |                                      |       |   |   |   |   |   |   |   |   |
| Sales price                 | ** ** | **$**                                                  | **51.09**  |                                      | $          | 53.71 |   | (5 | ) | **$** | **57.46** |   | $ | 52.89 |   | 9 |   |
| Hedging gain / (loss)       | ** ** | **0.01**                                               |       | —                                    |       | — | ** ** | **(0.66** | **)** | — |   | — |   |
| Royalties                   | ** ** | **8.69**                                               |       | 9.38                                      |       | (7 | ) | **9.13** |   | 8.45 |   | 8 |   |
| Operating costs             | ** ** | **14.25**                                              |       | 13.18                                     |       | 8 | ** ** | **14.22** |   | 12.58 |   | 13 |   |
| Transportation              | ** ** | **0.02**                                               |       | 0.04                                      |       | (50 | ) | **0.03** |   | 0.03 |   | — |   |
| Netback                     | ** ** | **$**                                                  | **28.14**  |                                      | $          | 31.11 |   | (10 | ) | **$** | **33.42** |   | $ | 31.83 |   | 5 |   |
| **Combined  totals**        | ** ** | ** **                                             | ** ** | ** **                                | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** |
| Production (1)  (boe/day)   | ** ** | **129,915**                                            |       | 98,205                                    |       | 32 | ** ** | **112,369** |   | 99,807 |   | 13 |   |
| Operating netback ($/boe):  |       |                                                   |       |                                      |       |   |   |   |   |   |   |   |   |
| Sales price                 | ** ** | **$**                                                  | **46.88**  |                                      | $          | 61.38 |   | (24 | ) | **$** | **49.58** |   | $ | 52.50 |   | (6 | ) |
| Hedging gain                | ** ** | **1.53**                                               |       | —                                    |       | — | ** ** | **1.64** |   | 0.18 |   | 811 |   |
| Royalties                   | ** ** | **9.12**                                               |       | 12.52                                     |       | (27 | ) | **9.10** |   | 9.74 |   | (7 | ) |
| Operating costs             | ** ** | **10.61**                                              |       | 9.44                                      |       | 12 | ** ** | **10.39** |   | 8.99 |   | 16 |   |
| Transportation              | ** ** | **0.51**                                               |       | 0.64                                      |       | (20 | ) | **0.60** |   | 0.62 |   | (3 | ) |
| Netback                     | ** ** | **$**                                                  | **28.17**  |                                      | $          | 38.78 |   | (27 | ) | **$** | **31.13** |   | $ | 33.33 |   | (7 | ) |

 

----

(1)          Boe or barrels of oilequivalent are based on six mcf of natural gas being equal to one barrel of oil(6:1).

7

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**Production Revenues**

Revenues from the sale of crude oil, NGL and naturalgas consisted of the following:
| ** **              | ** ** | **Year ended December 31** | ** **  |
|-------------------------|------------|-------------------------------------------|-------------|
| **($ millions)**   | ** ** | **2006**                                  | ** **  | **2005** | ** ** | **2004** | ** ** |
| Natural gas             | ** ** | **$**                                     | **850.9**   |   | $ | 918.2 |   | $ | 773.0 |   |
| Light oil and  NGL      | ** ** | **923.4**                                 |        | 757.0 |   | 537.7 |   |
| Conventional  heavy oil | ** ** | **326.6**                                 |        | 243.8 |   | 210.6 |   |
| Total                   | ** ** | **$**                                     | **2,100.9** |   | $ | 1,919.0 |   | $ | 1,521.3 |   |

 

The increase in revenue resulted from higher volumesdue to the Petrofund merger and higher oil prices, partially offset by lowernatural gas prices.

**Increases (Decreases) in Production Revenues**
| **($ millions)**                                                         | ** ** | ** ** | ** ** |
|-------------------------------------------------------------------------------|------------|------------|------------|
| Gross revenues –  2005                                                   |       | $          | 1,919.0    |   |
| Increase in  light oil and NGL production                                     |       | 145.7      |       |
| Increase in  light oil and NGL prices (including realized hedging activities) |       | 20.7       |       |
| Increase in  conventional heavy oil production                                |       | 27.0       |       |
| Increase in  conventional heavy oil prices                                    |       | 55.8       |       |
| Increase in  natural gas production                                           |       | 78.8       |       |
| Decrease in  natural gas prices (including realized hedging activities)       |       | (146.1     | )          |
| Gross revenues – 2006                                                    |       | $          | 2,100.9    |   |

 

**Royalties**
| ** **                  | ** ** | **Year ended December 31** | ** ** |
|-----------------------------|------------|-------------------------------------------|------------|
| ** **                  | ** ** | **2006**                                  | ** ** | **2005** | ** ** | **2004** | ** ** |
| Royalties ($ millions) | ** ** | **$**                                     | **373.3**  |   | $ | 355.0 |   | $ | 296.1 |   |
| Average royalty  rate (%)   | ** ** | **18**                                    | **%**      | 19 | % | 20 | % |
| $/boe                       | ** ** | **$**                                     | **9.10**   |   | $ | 9.74 |   | $ | 7.65 |   |

 

Royalties, as a percentage of revenue, decreased inthe quarter due to realized hedging gains. The Petrofund properties have higheraverage royalty rates than the Penn West properties, however, realized hedginggains reduced 2006 royalty rates compared to 2005.

8

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**Expenses**
| ** **                 | ** ** | **Year ended December 31** | ** ** |
|----------------------------|------------|-------------------------------------------|------------|
| **($ millions)**      | ** ** | **2006**                                  | ** ** | **2005** | ** ** | **2004** | ** ** |
| Operating                  | ** ** | **$**                                     | **426.3**  |   | $ | 327.4 |   | $ | 300.4 |   |
| Transportation             | ** ** | **24.5**                                  |       | 22.7 |   | 25.6 |   |
| Financing                  | ** ** | **49.3**                                  |       | 23.2 |   | 17.0 |   |
| Equity-based  compensation | ** ** | **$**                                     | **11.3**   |   | $ | 77.2 |   | $ | 84.1 |   |

 
| ** **                 | ** ** | **Year ended December 31** | ** ** |
|----------------------------|------------|-------------------------------------------|------------|
| **($/boe)**                | ** ** | **2006**                                  | ** ** | **2005** | ** ** | **2004** | ** ** |
| Operating                  | ** ** | **$**                                     | **10.39**  |   | $ | 8.99 |   | $ | 7.75 |   |
| Transportation             | ** ** | **0.60**                                  |       | 0.62 |   | 0.66 |   |
| Financing                  | ** ** | **1.20**                                  |       | 0.63 |   | 0.45 |   |
| Equity-based  compensation | ** ** | **$**                                     | **0.27**   |   | $ | 2.12 |   | $ | 2.17 |   |

 

**Operating**

High levels of industry activity, in response torelatively high commodity prices, resulted in strong demand for oilfieldservices and labour that continued to put upward pressure on operating costs in2006. In addition, higher energy costs translated into higher utility, chemicaland trucking costs. A higher proportion of liquids production, combined withbase production declines and interruptions, also contributed to higher per unitoperating costs in 2006 than in 2005. The addition of the Petrofund assets withhigher operating costs than Penn West’s properties also contributed to theincrease.

During 2006, as natural gas prices fell from theirclose to record highs, some significant oil and natural gas companies cut theircapital programs, helping to reduce demand for oilfield services. This,combined with internal initiatives targeted at reducing operating costs,resulted in the operating cost per barrel of oil equivalent in the fourthquarter of 2006 being approximately equal to the rate for the third quarter of2006.

**Financing**

We use short-term money market instruments to realizelower interest rates at the shorter end of the yield curve. The short end ofthe yield curve has increased due to rate increases by the central banks inCanada and the United States. The 2006 increase in interest expense was due toboth an increase in the average outstanding debt balance and the increases inshort-term interest rates over 2005. The average prime interest rate increasedto 6.0 percent in the fourth quarter of 2006 from an average of 4.8 percent inthe same quarter of 2005.

Interest and other financing costs for the year endedDecember 31, 2006 increased to $49.3 million from $23.2 million in 2005. Theincreased average loan balance was principally due to the $610 million of debtassumed with the Petrofund merger.

**Equity-Based Compensation**

On the close of the trust conversion on May 31, 2005,Penn West implemented a trust unit rights incentive plan. Compensation expenserelated to this plan is based on the fair value of trust unit rights issued,determined using the Binomial Lattice option-pricing model. The fair value ofrights issued is expensed on a straight-line basis over the vesting periods ofthe rights. Prior to the trust conversion, the Trust’s predecessor company, PennWest Petroleum Ltd. (“the Company”), had a stock option plan with a cashsettlement alternative; as a result, equity-based compensation was recordedbased on changes in the intrinsic value of stock options.

9

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**General and Administrative Expenses**
| ** **                                                        | ** ** | **Year ended December 31** | ** ** |
|-------------------------------------------------------------------|------------|-------------------------------------------|------------|
| **($ millions, except per boe amounts)** | ** ** | **2006**                                  | ** ** | **2005** | ** ** | **2004** | ** ** |
| Gross                                                             | ** ** | **$**                                     | **62.0**   |   | $ | 45.0 |   | $ | 41.3 |   |
| Per boe                                                           | ** ** | **1.51**                                  |       | 1.24 |   | 1.07 |   |
| Net                                                               | ** ** | **36.0**                                  |       | 23.1 |   | 16.1 |   |
| Per boe                                                           | ** ** | **$**                                     | **0.88**   |   | $ | 0.64 |   | $ | 0.42 |   |

 

Increases in total and per boe general andadministrative costs in 2006 were due to higher staff levels following thePetrofund merger and higher compensation costs. The cost of hiring,compensating and retaining employees and consultants remains high due to strongdemand for staff, particularly those with specialized training and experience.Increasing costs related to regulatory compliance also contributed to theincrease.

**Taxes**
| ** **                | ** ** | **Year ended December 31** | ** ** |
|---------------------------|------------|-------------------------------------------|------------|
| **($ millions)**     | ** ** | **2006**                                  | ** ** | **2005** | ** ** | **2004** | ** ** |
| Capital                   | ** ** | **$**                                     | **14.7**   |   | $ | 14.7 |   | $ | 10.1 |   |
| Current income            | ** ** | **—**                                |       | 54.1 |   | 17.8 |   |
| Future income  (recovery) | ** ** | **(106.2**                                | **)**      | (1.1 | ) | 109.6 |   |
| ** **                | ** ** | **$**                                     | **(91.5**  | **)** | $ | 67.7 |   | $ | 137.5 |   |

 

Capital taxes recorded in 2006 were consistent with2005 as higher revenues subject to the Saskatchewan resource surcharge, wereoffset by the enactment of the elimination of the Canadian federal largecorporations tax and reductions to the rate of the Saskatchewan resourcesurcharge.

In the second quarter of 2006, Penn West recorded a$74 million future income tax recovery to reflect corporate tax rate reductionssubstantively enacted by the federal, Alberta and Saskatchewan governments.

Under our current structure, the operating entitiesmake interest and royalty payments to the Trust, which transfers taxable incometo the Trust to eliminate income subject to corporate and other income taxes inthe operating entities. Under the terms of its trust indenture, the Trust isrequired to distribute amounts equal to at least its taxable income. In theevent that the Trust has undistributed taxable income in a taxation year, anadditional special taxable distribution, subject to certain withholding taxes,would be required by the terms of its trust indenture.

If the proposed distribution tax is enacted and PennWest’s structure is not changed, Penn West will become a taxable entity, andfrom 2011 and subsequent future income tax recoveries will likely not berecorded for income transfers to the trust.

10

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**Tax Pools**
| ** **                                     | ** ** | **As at December 31** | ** **  |
|------------------------------------------------|------------|--------------------------------------|-------------|
| **($ millions)**                          | ** ** | **2006**                             | ** **  | **2005** | ** ** | **2004** | ** ** |
| Undepreciated capital  cost (UCC)              | ** ** | **$**                                | **788.3**   |   | $ | 519.0 |   | $ | 276.4 |   |
| Canadian oil and gas  property expense (COGPE) | ** ** | **1,091.0**                          |        | 707.6 |   | 611.5 |   |
| Canadian development  expense (CDE)            | ** ** | **428.8**                            |        | 329.8 |   | 95.4 |   |
| Canadian exploration  expense (CEE)            | ** ** | **—**                           |        | — |   | — |   |
| Non-capital losses                             | ** ** | **106.1**                            |        | — |   | — |   |
| Total tax pools                                | ** ** | **$**                                | **2,414.2** |   | $ | 1,556.4 |   | $ | 983.3 |   |

 

The significant increase inthe 2006 tax pools reflects the merger with Petrofund. The tax pool figures arenet of income deferred in operating partnerships.

**Depletion, Depreciation andAccretion (“DD&A”)**
| ** **                                                        | ** ** | **Year ended December 31** | ** ** |
|-------------------------------------------------------------------|------------|-------------------------------------------|------------|
| **($ millions, except per boe amounts)** | ** ** | **2006**                                  | ** ** | **2005** | ** ** | **2004** | ** ** |
| Depletion of oil and  natural gas assets(1)                       | ** ** | **$**                                     | **623.7**  |   | $ | 406.1 |   | $ | 383.7 |   |
| Gas plant depreciation                                            | ** ** | **11.3**                                  |       | 10.4 |   | 10.6 |   |
| Accretion of asset  retirement obligation (2)                     | ** ** | **19.7**                                  |       | 21.1 |   | 18.8 |   |
| Total DD&A                                                    | ** ** | **654.7**                                 |       | 437.6 |   | 413.1 |   |
| DD&A expense per boe                                          | ** ** | **$**                                     | **15.96**  |   | $ | 12.01 |   | $ | 10.67 |   |

 

----

(1) Includes depletion of the capitalized portion of the assetretirement obligation.

(2) Represents the accretionexpense on the asset retirement obligation during the period.

Higher DD&A expense in2006 versus 2005 was due to the Petrofund merger. The merger was accounted foras a purchase with the purchase price allocated to the net assets acquired. Thepurchase allocation to oil and natural gas assets significantly increased ourconsolidated depletion base and therefore increased our DD&A rate.

**Foreign Exchange**

In 2006, we had noU.S.-dollar-denominated debt. In 2005, the Company realized a foreign exchangegain of $85.8 million on the conversion of U.S.-dollar-denominated debt toCanadian-dollar debt.

**Cash Flow and Net Income**
| ** **                   | ** ** | **Three months ended December 31** | ** ** | **Year ended December 31** | ** ** |
|------------------------------|------------|--------------------------------------------------------|------------|-------------------------------------------|------------|
| ** **                   | ** ** | **2006**                                               | ** ** | **2005**                                  | ** ** | **% change** | ** ** | **2006** | ** ** | **2005** | ** ** | **% change** | ** ** |
| Cash flow ($ millions)  | ** ** | **$**                                                  | **303.3**  |                                      | $          | 332.6 |   | (9 | ) | **$** | **1,176.8** |   | $ | 1,184.6 |   | (1 | ) |
| Basic per unit               | ** ** | **1.23**                                               |       | 2.03                                      |       | (39 | ) | **5.86** |   | 7.28 |   | (20 | ) |
| Diluted per unit             | ** ** | **1.22**                                               |       | 2.03                                      |       | (40 | ) | **5.78** |   | 7.14 |   | (19 | ) |
|                         | ** ** | ** **                                             |       |                                      |       |   |   | ** ** |   |   |   |   |   |
| Net income ($ millions) | ** ** | **122.9**                                              |       | 241.1                                     |       | (49 | ) | **665.6** |   | 577.2 |   | 15 |   |
| Basic per unit               | ** ** | **0.44**                                               |       | 1.48                                      |       | (70 | ) | **3.32** |   | 3.55 |   | (6 | ) |
| Diluted per unit             | ** ** | **$**                                                  | **0.44**   |                                      | $          | 1.46 |   | (70 | ) | **$** | **3.27** |   | $ | 3.48 |   | (6 | ) |

 

11

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Cash flow realized in 2006decreased from 2005 due to lower natural gas prices offset by higher productionand higher oil prices.

Net income increased from2005 levels due to higher production following the Petrofund merger and futureincome tax recoveries offset by lower natural gas prices. The lower fourthquarter 2006 net income reflects higher depletion, depreciation and accretioncharges following the Petrofund merger.
| ** **                               | ** ** | **Year ended December 31** | ** ** |
|------------------------------------------|------------|-------------------------------------------|------------|
| ** **                               | ** ** | **2006**                                  | ** ** | **2005** | ** ** | **2004** | ** ** |
| ** **                               | ** ** | **$/boe**                                 | ** ** | **%** | ** ** | **$/boe** | ** ** | **%** | ** ** | **$/boe** | ** ** | **%** | ** ** |
| Oil and natural  gas revenues            | ** ** | **$**                                     | **51.22**  | ** ** | **100.0** |   | $ | 52.68 |   | 100.0 |   | $ | 39.29 |   | 100.0 |   |
| Net royalties                            | ** ** | **(9.10**                                 | **)**      | **(17.8** | **)** | (9.74 | ) | (18.5 | ) | (7.65 | ) | (19.5 | ) |
| Operating  expenses                      | ** ** | **(10.39**                                | **)**      | **(20.3** | **)** | (8.99 | ) | (17.1 | ) | (7.75 | ) | (19.7 | ) |
| Transportation                           | ** ** | **(0.60**                                 | **)**      | **(1.2** | **)** | (0.62 | ) | (1.1 | ) | (0.66 | ) | (1.7 | ) |
| Net operating  income                    | ** ** | **31.13**                                 | ** ** | **60.7** |   | 33.33 |   | 63.3 |   | 23.23 |   | 59.1 |   |
| General and  administrative expenses     | ** ** | **(0.88**                                 | **)**      | **(1.7** | **)** | (0.64 | ) | (1.2 | ) | (0.42 | ) | (1.1 | ) |
| Interest                                 | ** ** | **(1.20**                                 | **)**      | **(2.3** | **)** | (0.63 | ) | (1.2 | ) | (0.45 | ) | (1.1 | ) |
| Realized foreign  exchange gain          | ** ** | **—**                                | ** ** | **—** |   | 2.35 |   | 4.4 |   | 0.74 |   | 1.9 |   |
| Current and  capital taxes               | ** ** | **(0.36**                                 | **)**      | **(0.7** | **)** | (1.89 | ) | (3.6 | ) | (0.71 | ) | (1.8 | ) |
| Cash flow                                | ** ** | **28.69**                                 | ** ** | **56.0** |   | 32.52 |   | 61.7 |   | 22.39 |   | 57.0 |   |
| Unrealized  foreign exchange gain (loss) | ** ** | **—**                                | ** ** | **—** |   | (2.48 | ) | (4.7 | ) | 0.30 |   | 0.8 |   |
| Equity-based  compensation               | ** ** | **(0.27**                                 | **)**      | **(0.5** | **)** | (2.12 | ) | (4.0 | ) | (2.17 | ) | (5.5 | ) |
| Risk management  activities              | ** ** | **1.18**                                  | ** ** | **2.3** |   | (0.09 | ) | (0.2 | ) | — |   | — |   |
| Depletion,  depreciation and accretion   | ** ** | **(15.96**                                | **)**      | **(31.2** | **)** | (12.01 | ) | (22.8 | ) | (10.67 | ) | (27.2 | ) |
| Future income  taxes                     | ** ** | **2.59**                                  | ** ** | **5.1** |   | 0.03 |   | — |   | (2.83 | ) | (7.2 | ) |
| Net income                               | ** ** | **$**                                     | **16.23**  | ** ** | **31.7** |   | $ | 15.85 |   | 30.0 |   | $ | 7.02 |   | 17.9 |   |

 

**Capital Expenditures**
| ** **                                 | ** ** | **Three months ended December 31** | ** ** | **Year ended December 31** | ** ** |
|--------------------------------------------|------------|--------------------------------------------------------|------------|-------------------------------------------|------------|
| **($ millions)**                      | ** ** | **2006**                                               | ** ** | **2005**                                  | ** ** | **2006** | ** ** | **2005** | ** ** |
| Property  acquisitions (dispositions), net | ** ** | **$**                                                  | **10.9**   |                                      | $          | (91.3 | ) | **$** | **5.6** |   | $ | (5.8 | ) |
| Land acquisition  and retention            | ** ** | **0.8**                                                |       | 3.7                                       | ** ** | **19.8** |   | 13.5 |   |
| Drilling and  completions                  | ** ** | **86.1**                                               |       | 61.0                                      | ** ** | **317.4** |   | 277.1 |   |
| Facilities and  well equipping             | ** ** | **57.9**                                               |       | 30.0                                      | ** ** | **224.6** |   | 155.2 |   |
| Geological and  geophysical                | ** ** | **1.0**                                                |       | 0.8                                       | ** ** | **3.6** |   | 7.4 |   |
| CO2 pilot costs                       | ** ** | **1.1**                                                |       | 1.9                                       | ** ** | **3.7** |   | 8.1 |   |
| Administrative                             | ** ** | **1.6**                                                |       | 0.2                                       | ** ** | **3.2** |   | 1.2 |   |
| Capital  expenditures                      | ** ** | **159.4**                                              |       | 6.3                                       | ** ** | **577.9** |   | 456.7 |   |
| Petrofund merger                           | ** ** | **—**                                             |       | —                                    | ** ** | **3,323.3** |   | — |   |
| Total expenditures                         | ** ** | **$**                                                  | **159.4**  |                                      | $          | 6.3 | ** ** | **$** | **3,901.2** |   | $ | 456.7 |   |

 

We drilled 52 net wells inthe fourth quarter of 2006, resulting in 12 net natural gas wells and 38 netoil wells with a success rate of 96 percent. Our drilling activities werefocused in the Central and Plains areas. For 2006 we drilled 270 net wells, 105net natural gas and 149 net oil wells with a success rate of 94 percent.

12

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CO2 pilot costs represent capital expendituresrelated to the Pembina CO2 pilot project, including the cost ofinjectants, for which no reserves have been booked.

On June 30, 2006, we mergedwith Petrofund. The fair value of the oil and gas properties acquired of $3.3billion was added to property, plant and equipment and the remaining $0.7billion of the purchase price was attributed to goodwill. Goodwill was recordedto reflect that we increased our production capacity to levels which made usthe largest conventional oil and gas royalty trust in North America, weincreased our exposure to light oil giving us a better future product balanceas we increase our future production from the Peace River Oil Sands, weincreased our reserve life index and technological access to, and staff withexperience in, resource plays including the Weyburn CO2 projectand coalbed methane.

Our farm-out program isongoing; since 2005, 272 wells have been drilled on Penn West’s lands,including re-completions and re-entries, by independent operators that incurdrilling, completions and other capital costs on these properties. In thefourth quarter of 2006, 57 wells were drilled on our lands, bringing the totalto 169 wells for 2006.

In addition to the abovecapital expenditures, $1.7 million was capitalized in relation to future incometaxes on minor acquisitions in the Swan Hills area, with less tax basis thanthe purchase price, and $55.9 million was capitalized from additions to andrevisions of asset retirement obligations.

**Business Risks**

**Market Risk Management**

We are exposed to normalmarket risks inherent in the oil and natural gas business, including commodityprice risk, credit risk, interest rate risk and foreign currency risk. Fromtime to time, we attempt to minimize exposure to a portion of these risks usingfinancial instruments.

**Commodity Price Risk**

We have substantial exposureto commodity price fluctuations. Crude oil prices are influenced by worldwidefactors such as OPEC actions, supply and demand fundamentals, and politicalevents. Oil prices, North American natural gas supply and demand factors andstorage levels influence natural gas prices. Pursuant to our policies, we may,from time to time, manage these risks through the use of costless collars orother financial instruments up to a maximum of 50 percent of forecast salesvolumes, net of royalties, for a two-year period or up to 75 percent offorecast sales volumes, net of royalties, for a one-year period.

For a current summary ofoutstanding oil and natural gas hedging contracts, please refer to our websiteat www.pennwest.com.

**Credit Risk**

Credit risk is the risk ofloss if purchasers or counterparties do not fulfill their contractualobligations. All of our receivables are with customers in the oil and naturalgas industry and are subject to normal industry credit risk. In order to limitthe risk of non-performance of counterparties to derivative instruments, wecontract only with organizations with high credit ratings or by obtainingsecurity in certain circumstances.

**Interest Rate Risk**

We maintain our debt infloating-rate bank facilities, resulting in exposure to fluctuations inshort-term interest rates. From time to time, we may increase the certainty offuture interest rates using financial instruments to swap floating interest ratesfor fixed rates or to collar interest rates. In 2006, we entered into interestrate swaps that fix the interest rate for two years at 4.36 percent on $100million of bank debt.

13

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**Foreign Currency Rate Risk**

Prices received for sales ofcrude oil are referenced to, or denominated in, U.S. dollars, and thus realizedoil prices may be impacted by Canadian to United States exchange rates. When weconsider it appropriate, we may use financial instruments to fix or collarfuture exchange rates. At December 31, 2006, we had no financial instrumentsoutstanding related to foreign exchange rates.

**Liquidity and Capital Resources**

**Capitalization**
| ** **                      | ** ** | **Year ended December 31** | ** ** |
|---------------------------------|------------|-------------------------------------------|------------|
| ** **                      | ** ** | **2006**                                  | ** ** | **2005** | ** ** | **2004** | ** ** |
| ** **                      | ** ** | **($ millions)**                     | ** ** | **%** | ** ** | **($ millions)** | ** ** | **%** | ** ** | **($ millions)** | ** ** | **%** | ** ** |
| Trust units  issued, at market  | ** ** | **$**                                     | **8,435**  | ** ** | **86.0** |   | $ | 6,203 |   | 90.5 |   | $ | 4,269 |   | 86.0 |   |
| Bank loan –  long-term     | ** ** | **1,285**                                 | ** ** | **13.1** |   | 542 |   | 7.9 |   | 503 |   | 10.2 |   |
| Working capital  deficiency (1) | ** ** | **86**                                    | ** ** | **0.9** |   | 127 |   | 1.6 |   | 190 |   | 3.8 |   |
| Total enterprise value          | ** ** | **$**                                     | **9,806**  | ** ** | **100.0** |   | $ | 6,872 |   | 100.0 |   | $ | 4,962 |   | 100.0 |   |

 

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(1) Current assets minuscurrent liabilities.

OnJune 30, 2006, we issued approximately 70.7 million trust units on the close ofthe Petrofund merger. During 2006, 2.5 million units were issued in lieu ofcash under the Distribution Re-investment and Optional Purchase Plan, 0.4million units were issued on the exercise of rights under the Trust Unit RightsIncentive Plan and 0.3 million units were issued to match employeecontributions under the Trust Unit Savings Plan.

During2006, we paid distributions of $781.8 million compared to distributions of$270.9 million and dividends of $17.5 million in 2005. This reflects that wewere a trust for the full year in 2006, we paid higher per unit distributionsin 2006 and we issued additional units on the Petrofund merger.

Underthe terms of its current trust indenture, the Trust is required to makedistributions to unitholders in amounts at least equal to its taxable income.Distributions may be monthly or special and in cash or in trust units at thediscretion of our Board of Directors. To the extent that additional cashdistributions are paid and capital programs are not adjusted, debt levels mayincrease. In the event that a special distribution in the form of trust unitsis declared, the terms of the trust indenture require that the outstandingunits be consolidated immediately subsequent to the distribution. The number ofoutstanding trust units would remain at the number outstanding immediatelyprior to the unit distribution, less those sold to fund the payment ofwithholding taxes, and an amount equal to the distribution would be allocatedto the unitholders as a taxable distribution.

Ourphilosophy is to retire approximately 10 percent of our opening assetretirement obligation annually, using our cash flow. Due to the extent of ourenvironmental programs, we believe no benefit would arise from the initiationof a reclamation fund. We believe our program is sufficient to meet or exceedexisting environmental regulations and best industry practices. In the event ofsignificant changes to the environmental regulations or the cost ofenvironmental activities, a higher portion of cash flow would be required tofund our environmental expenditures.

Bankdebt at December 31, 2006 was $1,285 million compared to $542 million atDecember 31, 2005. In the third quarter of 2006, our wholly owned subsidiary,Penn West Petroleum Ltd., amended its unsecured, extendible, three-yearrevolving syndicated credit facility. The amended credit facility has anaggregate borrowing limit of $1.8 billion plus a $100 million swing linefacility with stamping fees ranging from 60-115 basis points and standby feesranging from 12.5-22.5 basis points depending on our ratio of consolidated bankdebt to earnings before interest, taxes and depreciation and depletion (“EBITDA”).During 2006, the Company extended the facility termination date to August 25,2009. As at December 31, 2006, there was $515 million (2005 – $628 million)available under the syndicated credit facility to finance future activities.

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During2006, the Company secured a $650 million bridge facility and utilized it toretire Petrofund’s bank debt of $610 million on the close of the merger. Thebridge facility was re-paid from the proceeds of the re-syndication of thecredit facility on August 25, 2006. On December 31, 2006, the Company was incompliance with all of the financial covenants under the credit facility. Thefinancial covenants under the new syndicated credit facility are as follows:

·  Consolidated bank debt to EBITDAshall be less than 3:1 except in certain circumstances and shall not exceed3.5:1;

·  Consolidated total debt to EBITDAshall be less than 4:1; and

·  Consolidated bank debt to totaltrust capitalization shall not exceed 50 percent except in certaincircumstances and shall not exceed 55 percent.

**Reconciliationof Cash Flow from Operating Activities to Distributable Cash from Operations**

PennWest has elected to voluntarily present the following reconciliation ofdistributable cash from operations based on guidance contained in the CanadianInstitute of Chartered Accountants’ related November 2006 draft interpretive release.In the draft release, sustainability concepts are discussed and distributablecash from operations is defined as cash flow from operating activities lessadjustments for productive capacity maintenance, long-term unfunded contractualobligations and the effect of any foreseeable financing matters, related todebt covenants, which could impair our ability to pay distributions.
| ** **                                                         | ** ** | **Three months ended December 31** | ** **  | **Year ended December 31** | ** ** |
|--------------------------------------------------------------------|------------|--------------------------------------------------------|-------------|-------------------------------------------|------------|
| **($ millions, except per unit amounts)** | ** ** | **2006**                                               | ** **  | **2005**                                  | ** ** | **2006** | ** ** | **2005 **(1) | ** ** |
| Cash flow from  operating activities                               | ** ** | **$**                                                  | **261.1**   |                                      | $          | 368.7 | ** ** | **$** | **1,106.3** |   | $ | 696.5 |   |
| Productive  capacity maintenance (2)                               | ** ** | **(148.5**                                             | **)**       | (97.6                                     | )          | **(572.3** | **)** | (212.1 | ) |
| Distributable  cash from operations                                | ** ** | **112.6**                                              |        | 271.1                                     | ** ** | **534.0** |   | 484.4 |   |
| Proceeds from  the issue of trust units (3)                        | ** ** | **31.3**                                               |        | 2.4                                       | ** ** | **118.6** |   | 8.3 |   |
| Bank borrowings  and working capital changes                       | ** ** | **97.6**                                               |        | (121.7                                    | )          | **159.2** |   | (171.2 | ) |
| Cash  distributions declared                                       | ** ** | **$**                                                  | **241.5**   |                                      | $          | 151.8 | ** ** | **$** | **811.8** |   | $ | 321.5 |   |
| Accumulated cash  distributions, beginning                         | ** ** | **891.8**                                              |        | 169.7                                     | ** ** | **321.5** |   | — |   |
| Accumulated cash  distributions, ending                            | ** ** | **$**                                                  | **1,133.3** |                                      | $          | 321.5 | ** ** | **$** | **1,133.3** |   | $ | 321.5 |   |
|                                                               | ** ** | ** **                                             |        |                                      | ** ** | ** ** |   |   |   |
| Distributable  cash from operations per unit, basic                | ** ** | **0.48**                                               |        | 1.66                                      | ** ** | **2.66** |   | 2.98 |   |
| Distributable  cash from operations per unit, diluted              | ** ** | **0.47**                                               |        | 1.63                                      | ** ** | **2.62** |   | 2.92 |   |
| Distributable  cash payout ratio (4)                               | ** ** | **2.14**                                               |        | 0.56                                      | ** ** | **1.52** |   | 0.66 |   |
|                                                               | ** ** | ** **                                             |        |                                      | ** ** | ** ** |   |   |   |
| Distributions  declared per unit                                   | ** ** | **$**                                                  | **1.02**    |                                      | $          | 0.93 | ** ** | **$** | **4.05** |   | $ | 1.97 |   |
| Distributions  declared as a percentage of net income              | ** ** | **197**                                                | **%**       | 63                                        | %          | **122** | **%** | 56 | % |
| Distributions declared  as a percentage of cash flow               | ** ** | **80**                                                 | **%**       | 46                                        | %          | **69** | **%** | 43 | % |

 

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(1) Includesthe operations of Penn West subsequent to the effective date of the Trustconversion, May 31, 2005.

(2) Pleaserefer to our discussion of productive capacity maintenance below.

(3) Consists of proceeds from the DistributionReinvestment and Optional Purchase Plan, the Trust Unit Rights Incentive Planand the Trust Unit Savings Plan.

(4) Representscash distributions declared divided by distributable cash from operations.

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Westrive to fund both distributions and capital programs from cash flow. We budgetour capital programs at approximately 40-50 percent of forecast cash flow. Webelieve that proceeds from the Distribution Re-investment and Optional PurchasePlan should be used to fund capital expenditures of a longer-term nature. Overthe medium term, additional borrowings and equity issues may be required fromtime to time to fund a portion of our distributions or maintain or increase ourproductive capacity. On a longer-term basis, adjustments to the level ofdistributions and/or capital expenditures to maintain or increase ourproductive capacity may be required based on forecast levels of distributablecash from operations and capital efficiency. 

Productivecapacity maintenance is generally the amount required in a period for anenterprise to maintain its ability to generate future cash flow from operatingactivities at a constant level. As commodity prices can be volatile, we defineour productive capacity as production on a barrel of oil equivalent basis.Short-term variations in production levels are often experienced in ourbusiness. A quantifiable measure for these short-term variations is notobjectively quantifiable or verifiable due to various factors including theinability to distinguish natural production declines from the effect of productionadditions from capital and optimization programs, and the effect of temporaryproduction interruptions. As a result, the adjustment for productive capacitymaintenance in our calculation of distributable cash from operations is ouractual capital expenditures during the period excluding the cost of anyacquisitions or proceeds of any dispositions. We believe that our currentcapital programs will be sufficient to maintain our productive capacity in themedium-term and set our hurdle rates for evaluating potential development andoptimization projects accordingly.

Ourcalculation of distributable cash from operations has no adjustment forlong-term unfunded contractual obligations. We believe our only significantlong-term unfunded contractual obligation at this time is for asset retirementobligations. Cash flow from operating activities, used in our distributablecash from operations calculation, includes a deduction for actual abandonmentexpenditures during the period. We believe that our philosophy, to retireapproximately 10 percent of our opening asset retirement obligation on anannual basis, is sufficient to fund our asset retirement obligations over thelife of our reserves.

Wecurrently have no financing restrictions caused by our debt covenants. Weregularly monitor our current and forecast debt levels to ensure debt covenantsare not exceeded.
| **($ millions, except indicators)** | ** ** | **As at December 31, 2006** | ** ** |
|----------------------------------------------------|------------|-------------------------------------------------|------------|
| Cumulative  distributable cash from operations (1) |       | $                                               | 1,018.4    |   |
| Issue of trust units                               |       | 126.9                                           |       |
| Bank borrowing and  working capital change         |       | (12.0                                           | )          |
| Cumulative cash  distributions declared (1)        |       | $                                               | 1,133.3    |   |
|                                               |       |                                            |       |
| Distributable cash payout ratio (2)                |       | 1.11                                            |       |

 

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(1) Subsequent to the trust conversion on May 31, 2005.

(2) Represents cumulativecash distributions paid divided by cumulative distributable cash fromoperations.

**FinancialInstruments**

Wecurrently have WTI crude oil collars on approximately 26,000 barrels per dayfrom January 1 to December 31, 2007 and 10,000 barrels per day from January2008 to June 2008. The collars on the 26,000 barrels per day to December 2007have an average floor price of US$56.12 per barrel and an average ceiling priceof US$83.50 per barrel. The 2008 WTI crude oil collars have an average floorprice of US$60.00 per barrel and an average ceiling price of US$94.55 perbarrel. In addition, Penn West has AECO natural gas collars on approximately 76mmcf per day from January 1 to October 31, 2007 with an average floor price of$7.69 per mcf and an average ceiling price of $9.79 per mcf.

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Inthe second quarter of 2006, we entered into interest rate swaps that fix theinterest rate for two years at approximately 4.36 percent on $100 million ofbank debt.

Otherfinancial instruments outstanding at December 31, 2006 are Alberta electricitycontracts, which fix electricity costs on 67 megawatts at $49.55 per megawatthour and 2 megawatts at $57.00 per megawatt hour.

Markto market amounts on all financial instruments outstanding on December 31, 2006are summarized in note 12 to the audited consolidated financial statements.Please refer to Penn West’s website at www.pennwest.com for details offinancial instruments currently outstanding.

**Outlook**

Theoutlook for oil and natural gas prices remains strong compared to historicallevels. For 2007, we initially budgeted net capital expenditures of $550million to $650 million, to fund the drilling of 220-250 net wells. Estimatedaverage 2007 production was forecast between 130,000 boe per day and 132,000boe per day. Based on a forecast WTI oil price of US$59.00 per barrel, a $7.25per mcf natural gas price at AECO and an exchange rate of CAD$1.00 equalsUSD$0.86 for 2007, cash flow for 2007 was forecast to be between $1.1 billionand $1.4 billion.

Subsequentto the completion of our 2007 budget, our board of directors approved the $339million property acquisition announced in February 2007 and an increase to thebudgeted capital program in the Peace River Oil Sands project to $175 millionfrom $100 million.

**SensitivityAnalysis**

Estimatedsensitivities to selected key assumptions on 2007 financial results beforeconsidering hedging impacts, the property acquisition announced on February 9,2007 and the expanded capital program in the Peace River Oil Sands, areoutlined in the table below.
| **($ millions, except per unit amounts)** | ** ** | ** **     | ** ** | **Impact on Cash Flow**(1) | ** ** | **Impact on Net Income**(1) | ** ** |
|--------------------------------------------------------------------|------------|----------------|------------|-------------------------------------------|------------|--------------------------------------------|------------|
| **Change of**                                                 | ** ** | **Change**     | ** ** | **$ millions**                       | ** ** | **$/unit**                                 | ** ** | **$ millions** | ** ** | **$/unit** | ** ** |
| Price per barrel  of liquids                                       |       | $              | 1.00       |                                      | 22.8       |                                       | 0.10       |   | 15.7 |   | 0.07 |   |
| Liquids  production                                                |       | 1,000 bbls/day |       | 16.9                                      |       | 0.07                                       |       | 9.3 |   | 0.04 |   |
| Price per mcf of  natural gas                                      |       | $              | 0.10       |                                      | 9.7        |                                       | 0.04       |   | 6.7 |   | 0.03 |   |
| Natural gas  production                                            |       | 10 mmcf/day    |       | 23.1                                      |       | 0.10                                       |       | 12.0 |   | 0.05 |   |
| Effective  interest rate                                           |       | 1              | %          | 13.5                                      |       | 0.06                                       |       | 9.3 |   | 0.04 |   |
| Exchange rate ($USD per  $CAD)                                     |       | $              | 0.01       |                                      | 29.4       |                                       | 0.12       |   | 20.3 |   | 0.09 |   |

 

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(1)  The impacton cash flow and net income is computed based on 2007 forecast commodity pricesand production volumes. The impact on net income assumes that the distributionlevels are not adjusted for changes in cash flow thus changing the incrementaltax rate.

**Contractual Obligations andCommitments**

We are committed to certainpayments over the next five calendar years as follows:
| **($ millions)**     | ** ** | **2007** | ** ** | **2008** | ** ** | **2009** | ** ** | **2010** | ** ** | **2011** | ** ** | **Thereafter** | ** ** |
|---------------------------|------------|----------|------------|----------|------------|----------|------------|----------|------------|----------|------------|----------------|------------|
| Transportation            | ** ** | **$**    | **20.0**   |     | $          | 9.2      |       | $        | 4.7        |     | $          | 1.9            |       | $ | — |   | $ | — |   |
| Transportation ($USD)     | ** ** | **2.5**  |       | 2.3      |       | 2.3      |       | 2.3      |       | 2.3      |       | 8.6            |       |
| Power  infrastructure     | ** ** | **4.6**  |       | 3.7      |       | 3.7      |       | 3.7      |       | 3.7      |       | 7.6            |       |
| Drilling rigs             | ** ** | **6.9**  |       | 7.7      |       | 2.4      |       | 1.2      |       | —   |       | —         |       |
| Purchase  obligations (1) | ** ** | **13.2** |       | 13.3     |       | 13.3     |       | 13.3     |       | 13.3     |       | 54.3           |       |
| Office lease              | ** ** | **$**    | **12.0**   |     | $          | 17.9     |       | $        | 17.5       |     | $          | 15.1           |       | $ | 14.3 |   | $ | 117.5 |   |

 

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(1)  Theseamounts represent estimated commitments of $95.5 million for CO2 purchases and $25.2 million for processing fees related to interests inthe Weyburn Unit.

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OnFebruary 9, 2007, Penn West announced we had entered into an agreement to acquireconventional oil and natural gas assets. The transaction is expected to closein March 2007 subject to the satisfaction of certain conditions, including therights of first refusal held on certain assets by working interest parties andthe receipt of regulatory approvals. The purchase price of the asset package,prior to any reductions due to rights of first refusal, totals approximately$339 million before closing adjustments of an estimated $12 million, which willreduce the cash outlays on closing.

Ourcredit facility expires in approximately three years, and if we were notsuccessful in renewing it or replacing it, we would be required to repay allamounts then outstanding on the facilities in August 2009. As we maintain ourleverage ratios at relatively modest levels, we believe we will be successfulin renewing or replacing our credit facilities on acceptable terms.

**Equity Instruments**
| Trust units  issued:                               |   |        |   |
|----------------------------------------------------|--------|-------------|--------|
| As at December 31, 2006                            |   | 237,126,219 |   |
| Issued on exercise of trust unit rights            |   | 9,590       |   |
| Issued to employee savings plan                    |   | 74,770      |   |
| Issued pursuant to distribution re-investment plan |   | 450,095     |   |
| As at February 28, 2007                            |   | 237,660,674 |   |
|                                               |   |        |   |
| Trust unit  rights outstanding:                    |   |        |   |
| As at December 31, 2006                            |   | 11,284,872  |   |
| Granted                                            |   | 3,713,469   |   |
| Exercised                                          |   | (9,590      | )      |
| Forfeited                                          |   | (218,100    | )      |
| As at February  28, 2007                           |   | 14,770,651  |   |

 

**Disclosure Controls andProcedures**

Wehave established a Disclosure Committee that is responsible for ensuring thatour disclosure controls and procedures are designed to provide reasonable assurancethat information required to be disclosed by us is recorded, processed,summarized and reported within the time periods specified under Canadiansecurities laws, and that our controls and procedures are designed to ensurethat information is accumulated and communicated to management, including thePresident and Chief Executive Officer and the Chief Financial Officer, to allowtimely decisions regarding required disclosure. Our Disclosure Committeeincludes selected members of senior management, including the Chief ExecutiveOfficer, the Chief Operating Officer and the Chief Financial Officer.

Asat December 31, 2006, an evaluation was carried out, under the supervision ofthe Disclosure Committee and with the participation of management, of the effectivenessof our disclosure controls and procedures as defined under the MultilateralInstrument 52-109. As at December 31, 2006, the design and operatingeffectiveness of our disclosure controls and procedures were assessed by ourChief Executive Officer and Chief Financial Officer to be operatingeffectively.

**InternalControls Over Financial Reporting**

Wehave assembled a team of qualified and experienced staff and consultants whohave been working on compliance with the applicable regulations regarding internalcontrols over financial reporting. As we are listed in both Canada and theUnited States, the recent changes in Canada to remove the requirement forauditor attestation and to extend the timing of CEO/CFO certification of theeffective operation of internal controls over financial reporting to 2008 willnot affect us.

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Webecame a registrant of the U.S. Securities and Exchange Commission and listedon the New York Stock Exchange in June 2006. As a 2006 applicant, we are notrequired to certify or obtain auditor attestation of the operatingeffectiveness of our internal controls over financial reporting until we fileour 2007 year-end audited financial statements. To date, all significantfinancial reporting processes have been documented and the resulting changes ininternal control over financial reporting are substantially completed. Based onthis work to date, no changes were made to our internal controls over financialreporting during the quarter ended December 31, 2006 that materially affected,or would be reasonably likely to materially affect, our internal controls overfinancial reporting.

**AccountingChanges and Pronouncements**

**FinancialInstruments, Other Comprehensive Income**

Thispronouncement, effective for fiscal year-ends on or after October 1, 2006,addresses when to recognize, and how to measure, a financial instrument on thebalance sheet and how gains and losses are to be presented. An additionalfinancial statement, other comprehensive income, is required in certaincircumstances. We currently have no items that would create other comprehensiveincome. The fair value of financial instruments, which are designated ashedges, are to be included on the balance sheet as a financial asset orliability with the related mark-to-market gain or loss recognized in othercomprehensive income.

Financialinstruments, not designated as hedges, will be valued at market with anyrelated gains and losses recognized in income of the period. As we elected toaccount for all of our derivative financial instruments using the fair valuemethod on July 1, 2005, this required change will have no effect on ourreported financial position or net income or loss.

**Non-Monetary Transactions**

EffectiveJanuary 1, 2006, this accounting pronouncement requires that non-monetarytransactions be measured at fair value unless certain conditions apply. Thispronouncement did not impact our reported results.

**Related-PartyTransactions**

In2006, we paid $4.1 million (2005 – $2.1 million) of legal fees to a law firm ofwhich a partner is also one of our directors. 

**Off-Balance-SheetFinancing**

Wehave off-balance-sheet financing arrangements consisting of operating leases.The details of the operating lease payments are summarized in the ContractualObligations and Commitments section.

**CriticalAccounting Estimates**

Oursignificant accounting policies are detailed in note 2 to the auditedconsolidated financial statements. In the determination of financial results,we must make certain significant accounting estimates as follows:

**FullCost Accounting**

We use the full costmethod of accounting for oil and natural gas properties. All costs of exploringfor and developing oil and natural gas reserves are capitalized and depletedagainst associated oil and natural gas production using the unit-of productionmethod based on the estimated proved reserves with forecast commodity pricing.

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Ourreserves were evaluated by GLJ Petroleum Consultants Ltd., an independentengineering firm. In both 2006 and 2005, our reserves were determined incompliance with National Instrument 51-101. The evaluation of oil and naturalgas reserves is, by its nature, based on complex extrapolations and models aswell as other significant engineering, capital, pricing and cost assumptions.Reserve estimates are a key component in the calculation of depletion and are akey component of value in the ceiling test. To the extent that the ceilingamount, based in part on our reserves, is less than the carrying amount ofproperty, plant and equipment, a write-down against income must be made. Wedetermined there was no ceiling test write-down required at December 31, 2006.

**AssetRetirement Obligations**

Thediscounted, expected future cost of statutory, contractual or legal obligationsto retire long-lived assets is recorded as an asset retirement liability with acorresponding increase to the carrying amount of the related asset. Therecorded liability increases over time to its future liability amount throughaccretion charges to earnings, included in DD&A. Revisions to the estimatedamount or timing of the obligations are reflected as increases or decreases toour asset retirement obligation. Actual asset retirement expenditures arecharged to the liability to the extent of the then – recorded liability.Amounts capitalized to the related assets are amortized to income consistentwith the depletion or depreciation of the underlying asset. Note 7 to theaudited consolidated financial statements details the impact of theseaccounting recommendations.

**FinancialInstruments**

Financialinstruments, included in the balance sheets, consist of accounts and taxesreceivable, the fair value of the derivative financial instruments, currentliabilities and the bank loan. The fair values of these financial instruments approximatetheir carrying amounts due to the short-term maturity of the instruments, themark to market values recorded for the financial instruments and the marketrate of interest applied to the bank loan.

Allof our accounts receivable are with customers in the oil and natural gasindustry and are subject to normal industry credit risk. We may, from time totime, use various types of financial instruments to reduce our exposure to fluctuatingoil and natural gas prices, electricity costs, exchange rates and interestrates. The use of these financial instruments exposes us to credit risksassociated with the possible non-performance of counterparties to thederivative contracts. We limit this risk by transacting only with financialinstitutions with high credit ratings and by obtaining security in certaincircumstances.

Ourrevenues from the sale of crude oil, natural gas liquids and natural gas aredirectly impacted by changes to the underlying commodity prices. To ensure thatcash flows are sufficient to fund planned capital programs and distributions, costlesscollars or other financial instruments may be utilized. Collars ensure thatcommodity prices realized will fall into a contracted range for a contractedsales volume. Forward power contracts fix a portion of future electricity costsat levels determined to be economic by management.

**Goodwill**

Goodwillmust be recorded on a business combination when the total purchaseconsideration exceeds the fair value of the net identifiable assets andliabilities of the acquired entity. The goodwill balance is not amortized,however, it must be assessed for impairment at least annually. Impairment isinitially determined based on the fair value of the reporting entity comparedto its book value. Any impairment must be charged to income or loss in theperiod the impairment occurs. We determined there was no goodwill impairment asat December 31, 2006.

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**Forward-Looking Statements**

Inthe interest of providing Penn West’s unitholders and potential investors withinformation regarding Penn West, including management’s assessment of Penn West’sfuture plans and operations, certain statements contained in this document constituteforward-looking statements or information (collectively “forward-lookingstatements”) within the meaning of the “safe harbour” provisions of applicablesecurities legislation. Forward-looking statements are typically identified by wordssuch 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 beforward-looking statements as they involve the implied assessment, based oncertain estimates and assumptions, that the reserves and resources describedexist in the quantities predicted or estimated and can be profitably producedin the future. In particular, this document contains forward-looking statementspertaining to, without limitation, the following: the nature of the proposedchanges to the taxation of income trusts in Canada, the effects of the proposedchanges to investor tax rates in 2011, the impact on our business of theproposed tax changes and the different actions that we might take in responseto the proposed tax changes; the stability and growth potential of our assetbase; our intention to focus our efforts on our Peace River Oil Sands projectand expand the project more rapidly in the future, including the estimatednumber of wells to be drilled in 2007, estimated 2007 capital expenditureslevels and the anticipated nature of those expenditures, our intention to completethe installation of pipeline infrastructure to the main project developmentarea, the daily production target by the end of 2007 and within four years forthis project, and the recovery methods anticipated to be employed to attain thesetargets; our current estimate of the amount of heavy oil resources in place inour Peace River Oil Sands project area and our belief that the potentialproduction and reserve additions for this project could be very significant;the timing for beginning carbon dioxide injection at the Joffre Viking Unit;our intention to continue to add oil, natural gas and electricity hedges; theestimated amount of light oil resources in place in the Pembina field, theamount of such resources that have been recovered to date and the potential torecover additional significant light oil reserves; our intention to expand our Pembinacarbon dioxide pilot project to apply horizontal well technology in order toaccelerate the production response and thus improve the capital payouttimelines; the anticipated timing for the commercial start-up of the Pembina CO2 project;our belief that we can demonstrate an economic, environmentally proactiveapproach to enhancing recovery from mature, light conventional oil fields anddeveloping our non-conventional oil resources; the amount anticipated to bespent on environmental programs in 2007 and the long-term benefits to bederived therefrom by unitholders; our near-term and long-term businessstrategies (including risk management strategies) and plans of management,including our intention in 2007 to maintain production volumes, improve capitalefficiencies, and continue our efforts toward the realization of thesignificant and long-term benefits the Peace River Oil Sands project and the CO2 EnhancedRecovery projects could provide; our ability to explore for and developgrassroots reserves, and also successfully acquire and optimize producingfields; our intention to create and protect unitholder value by (i) pursuing anactive program of internal development (and the focus of such development),(ii) participating in exploration through the farm-out of undeveloped lands,(iii) rationalizing our asset base, and (iv) maintaining a strong balancesheet; our ability to pursue strategies of organic growth through developmentand optimization, growth through strategic or accretive acquisitions and thefarmout of undeveloped land; our desire to maintain an approximately balancedportfolio of liquids and natural gas production; the existence, operation andstrategy of our risk management program, including methods of managing marketrisks, commodity price risks, credit risks, interest rate risks and foreigncurrency risks; our intention to retire approximately 10 percent of our openingasset retirement obligation annually using our cash flow; the intended use ofproceeds received under the Distribution Reinvestment and Optional PurchasePlan; the methods of funding distributions and maintaining or increasing ourproductive capacity over the medium and long-term; our belief that our currentcapital programs will be sufficient to maintain our barrel of oil equivalentproductive capacity in the medium-term; our belief that our philosophy to retireapproximately 10 percent of our opening asset retirement obligation on anannual basis is sufficient to fund our asset retirement obligations over thelife of our reserves; our belief that our only significant long-term unfundedcontractual obligation is for asset retirement obligations; our outlook for oiland natural gas prices; our forecast 2007 net capital expenditures and thenumber of wells to be drilled; our estimated average 2007 production forecast;our budget for oil prices, natural gas prices and the USD/CAD exchange rate for2007; our forecast cash flow for 2007; the timing for closing

21

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theacquisition announced on February 9, 2007 and the purchase price therefor; ourbelief that we will be successful in renewing or replacing our creditfacilities on acceptable terms when it expires; and the quantity andrecoverability of our oil and natural gas reserves and resources.

Withrespect to forward-looking statements contained in this document, we have madeassumptions regarding, among other things: future oil and natural gas pricesand differentials between light, medium and heavy oil prices; future oil and naturalgas production levels; future exchange rates; the amount of future cashdistributions that we intend to pay; the cost of expanding our property holdings;our ability to obtain equipment in a timely manner to carry out development activities;our ability to market our oil and natural gas successfully to current and newcustomers; the impact of increasing competition; our ability to obtainfinancing on acceptable terms; our ability to obtain all necessary approvalsrequired to complete the acquisition announced on February 9, 2007 and tocomplete the acquisition when expected; and our ability to add production andreserves through our development and exploitation activities.

AlthoughPenn West believes that the expectations reflected in the forward-lookingstatements contained in this document, and the assumptions on which suchforward-looking statements are made, are reasonable, there can be no assurance thatsuch expectations will prove to be correct. Readers are cautioned not to placeundue reliance on forward-looking statements included in this document, asthere can be no assurance that the plans, intentions or expectations upon whichthe forward-looking statements are based will occur. By their nature,forward-looking statements involve numerous assumptions, known and unknownrisks and uncertainties that contribute to the possibility that thepredictions, forecasts, projections and other forward-looking statements willnot occur, which may cause Penn West’s actual performance and financial resultsin future periods to differ materially from any estimates or projections offuture performance or results expressed or implied by such forward-lookingstatements. These risks and uncertainties include, among other things: volatilityin market prices for oil and natural gas; the impact of weather conditions onseasonal demand and ability to execute capital programs; risks inherent in oiland 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 ofthe value of acquisitions; geological, technical, drilling and processingproblems; general economic conditions in Canada, the U.S. and globally;industry conditions, including fluctuations in the price of oil and naturalgas; royalties payable in respect of our oil and natural gas production;changes in government regulation of the oil and natural gas industry, includingenvironmental regulation; fluctuations in foreign exchange or interest rates; unanticipatedoperating events that can reduce production or cause production to be shut-inor delayed; failure to obtain industry partner and other third-party consentsand approvals when required; stock market volatility and market valuations;OPEC’s ability to control production and balance global supply and demand ofcrude oil at desired price levels; political uncertainty, including the risksof hostilities, in the petroleum producing regions of the world; the need toobtain required approvals from regulatory authorities from time to time;failure to realize the anticipated benefits of acquisitions, including themerger with Petrofund Energy Trust; failure to obtain required approvals orotherwise complete the acquisition announced on February 9, 2007 on theexpected timeline or at all; and the other factors described under “BusinessRisks” in this document and in Penn West’s public filings (including our AnnualInformation Form) available in Canada at www.sedar.com and in the United Statesat www.sec.gov. Readers are cautioned that this list of risk factors should notbe construed as exhaustive.

Theforward-looking statements contained in this document speak only as of the dateof this document. Except as expressly required by applicable securities laws,Penn West does not undertake any obligation to publicly update or revise anyforward-looking statements, whether as a result of new information, futureevents or otherwise. The forward-looking statements contained in this documentare expressly qualified by this cautionary statement.

**AdditionalInformation**

Additionalinformation relating to Penn West, including its Annual Information Form (whenfiled), is available on SEDAR at www.sedar.com.

 

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