**Exhibit 99.2**

 

**MANAGEMENT’S DISCUSSION AND ANALYSIS**

 

Thismanagement’s discussion and analysis (“MD&A”) of financial conditions andresults of operations should be read in conjunction with the auditedconsolidated financial statements and accompanying notes of Penn West EnergyTrust (“Penn West”, “the Trust”, “We” or “Our”) for the years ended December 31,2007 and 2006. The date of this MD&A is March 6, 2008.

 

Foradditional information, including the Trust’s audited financial statements andAnnual Information Form, go to the Trust’s website at www.pennwest.com, inCanada at www.sedar.com or in the United States at www.sec.gov.

 

Alldollar amounts contained in this MD&A are expressed in millions of Canadiandollars unless noted otherwise.

 

Pleaserefer to our disclaimer on forward-looking statements at the end of thisMD&A. The calculations of barrels of oil equivalent (“boe”) are based on aconversion ratio of six thousand cubic feet of natural gas to one barrel ofcrude oil. This could be misleading if used in isolation as it is based on anenergy equivalency conversion method primarily applicable at the burner tip andmay not represent a value equivalency at the wellhead.

 

Measuresincluding funds flow, funds flow per unit-basic, funds flow per unit-dilutedand netbacks included in this MD&A are not defined in generally acceptedaccounting principles (“GAAP”) and do not have a standardized meaningprescribed by GAAP; accordingly, they may not be comparable to similar measuresprovided by other issuers. Management utilizes funds flow and netbacks toassess financial performance, to allocate its capital among alternativeprojects and to assess its capacity to fund distributions and future capitalprograms. Reconciliations of non-GAAP measures to their nearest measureprescribed by GAAP are provided below.

 

**Calculation of Funds Flow**

 
| ** **                                                  | ** ** | **Three months ended December 31** | ** ** | **Year ended December 31** | ** ** |
|-------------------------------------------------------------|------------|--------------------------------------------------------|------------|-------------------------------------------|------------|
| **(millions, except per unit amounts)** | ** ** | **2007**                                               | ** ** | **2006**                                  | ** ** | **2007** | ** ** | **2006** | ** ** |
| Cash flow from operating activities                         | ** ** | **$**                                                  | **311.7**  |                                      | $          | 261.1 | ** ** | **$** | **1,241.8** |   | $ | 1,106.3 |   |
| Increase in non-cash working capital                        | ** ** | **20.7**                                               |       | 32.9                                      | ** ** | **38.2** |   | 43.6 |   |
| Asset retirement expenditures                               | ** ** | **14.8**                                               |       | 9.3                                       | ** ** | **51.5** |   | 26.9 |   |
| Funds flow                                                  | ** ** | **$**                                                  | **347.2**  |                                      | $          | 303.3 | ** ** | **$** | **1,331.5** |   | $ | 1,176.8 |   |
| Basic per unit                                              | ** ** | **$**                                                  | **1.44**   |                                      | $          | 1.23 | ** ** | **$** | **5.56** |   | $ | 5.86 |   |
| Diluted per unit                                            | ** ** | **$**                                                  | **1.43**   |                                      | $          | 1.22 | ** ** | **$** | **5.51** |   | $ | 5.78 |   |

 

1

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**Annual Financial Summary**

 
| ** **                                                  | ** ** | **Year ended December 31** | ** **  |
|-------------------------------------------------------------|------------|-------------------------------------------|-------------|
| **(millions, except per unit amounts)** | ** ** | **2007**                                  | ** **  | **2006** | ** ** | **2005** | ** ** |
| Gross revenues (1)                                          | ** ** | **$**                                     | **2,461.8** |   | $ | 2,100.9 |   | $ | 1,919.0 |   |
| Funds flow                                                  | ** ** | **1,331.5**                               |        | 1,176.8 |   | 1,184.6 |   |
| Basic per unit                                              | ** ** | **5.56**                                  |        | 5.86 |   | 7.28 |   |
| Diluted per unit                                            | ** ** | **5.51**                                  |        | 5.78 |   | 7.14 |   |
| Net income                                                  | ** ** | **175.5**                                 |        | 665.6 |   | 577.2 |   |
| Basic per unit                                              | ** ** | **0.73**                                  |        | 3.32 |   | 3.55 |   |
| Diluted per unit                                            | ** ** | **0.73**                                  |        | 3.27 |   | 3.48 |   |
| Total expenditures, net                                     | ** ** | **1,140.2**                               |        | 577.9 |   | 456.7 |   |
| Long-term debt at period-end                                | ** ** | **1,943.2**                               |        | 1,285.0 |   | 542.0 |   |
| Distributions paid (2)                                      | ** ** | **976.0**                                 |        | 781.8 |   | 270.9 |   |
| Dividends paid                                              | ** ** | **—**                                |        | — |   | 17.5 |   |
| Total assets                                                | ** ** | **$**                                     | **8,433.0** |   | $ | 8,069.7 |   | $ | 3,967.1 |   |

 

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(1)  Gross revenuesinclude realized gains and losses on commodity contracts.

(2)  Includesdistributions paid and reinvested in trust units under the distributionreinvestment plan.

 

**QuarterlyFinancial Summary**

(millions, except per unit and production amounts)

 
| ** **                       | ** ** | **Dec. 31** | ** ** | **Sept. 30** | ** ** | **June 30** | ** ** | **Mar. 31** | ** ** | **Dec. 31** | ** ** | **Sept. 30** | ** ** | **June 30** | ** ** | **Mar. 31** | ** ** |
|----------------------------------|------------|------------------|------------|-------------------|------------|------------------|------------|------------------|------------|------------------|------------|-------------------|------------|------------------|------------|------------------|------------|
| **Three months ended** | ** ** | **2007**         | ** ** | **2007**          | ** ** | **2007**         | ** ** | **2007**         | ** ** | **2006**         | ** ** | **2006**          | ** ** | **2006**         | ** ** | **2006**         | ** ** |
| Gross revenues (1)               | ** ** | **$**            | **644.0**  |              | $          | 627.1            |       | $                | 608.3      |             | $          | 582.4             |       | $                | 578.5      |             | $          | 636.0 |   | $ | 452.5 |   | $ | 433.9 |   |
| Funds flow                       | ** ** | **347.2**        |       | 346.8             |       | 326.2            |       | 311.3            |       | 303.3            |       | 365.6             |       | 264.7            |       | 243.2            |       |
| Basic per unit                   | ** ** | **1.44**         |       | 1.44              |       | 1.37             |       | 1.31             |       | 1.23             |       | 1.55              |       | 1.59             |       | 1.49             |       |
| Diluted per unit                 | ** ** | **1.43**         |       | 1.43              |       | 1.35             |       | 1.30             |       | 1.22             |       | 1.53              |       | 1.56             |       | 1.47             |       |
| Net income (loss)                | ** ** | **127.0**        |       | 137.4             |       | (185.2           | )          | 96.3             |       | 122.9            |       | 177.8             |       | 220.5            |       | 144.4            |       |
| Basic per unit                   | ** ** | **0.53**         |       | 0.57              |       | (0.77            | )          | 0.41             |       | 0.44             |       | 0.66              |       | 1.34             |       | 0.88             |       |
| Diluted per unit                 | ** ** | **0.52**         |       | 0.57              |       | (0.77            | )          | 0.40             |       | 0.44             |       | 0.65              |       | 1.31             |       | 0.87             |       |
| Distributions declared           | ** ** | **247.0**        |       | 245.0             |       | 243.5            |       | 242.4            |       | 241.5            |       | 240.7             |       | 167.6            |       | 162.0            |       |
| Per unit                         | ** ** | **$**            | **1.02**   |              | $          | 1.02             |       | $                | 1.02       |             | $          | 1.02              |       | $                | 1.02       |             | $          | 1.02 |   | $ | 1.02 |   | $ | 0.99 |   |
| Production                       |       |             |       |              |       |             |       |             |       |             |       |              |       |             |       |             |       |
| Liquids (bbls/d) (2)             | ** ** | **73,332**       |       | 72,783            |       | 70,923           |       | 71,716           |       | 70,819           |       | 69,215            |       | 48,599           |       | 52,226           |       |
| Natural gas (mmcf/d)             | ** ** | **328.1**        |       | 315.4             |       | 334.1            |       | 340.6            |       | 354.6            |       | 359.1             |       | 267.9            |       | 266.9            |       |
| Total (boe/d)                    | ** ** | **128,024**      |       | 125,345           |       | 126,599          |       | 128,447          |       | 129,915          |       | 129,059           |       | 93,242           |       | 96,713           |       |

 

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(1)  Gross revenues include realized gains and losses on commoditycontracts.

(2)  Includes crude oil and natural gas liquids.

 

Themajor trend changes above are largely due to the acquisition of PetrofundEnergy Trust (“Petrofund”) on June 30, 2006 and the enactment of theSpecified Investment Flow-Through tax legislation in the second quarter of2007.

 

**Canetic Acquisition**

 

OnJanuary 11, 2008, the close of the acquisition of Canetic Resources Trust(“Canetic”) was successfully completed. Canetic unitholders received 0.515 of aPenn West unit for each Canetic unit on a tax-deferred basis for Canadian andU.S. tax purposes plus a one-time special distribution of $0.09 per unit underthe terms of the Combination Agreement.

 

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| **Estimated Total Consideration** | ** ** | **(millions)** | ** **  |
|---------------------------------------------|------------|----------------|-------------|
| 124.3 million Penn West trust units issued  |       | $              | 3,572.5     |   |
| Transaction costs                           |       | 17.0           |        |
| Bank debt                                   |       | 1,467.0        |        |
| Convertible debentures                      |       | 260.0          |        |
| Working capital deficiency                  |       | 153.0          |        |
| **Total**                                   | ** ** | **$**          | **5,469.5** | ** ** |

 

**Vault Acquisition**

 

OnJanuary 10, 2008 the close of the acquisition of Vault Energy Trust (“Vault”)was successfully completed. The acquisition was accomplished through a Plan ofArrangement wherein Vault unitholders received 0.14 of a Penn West trust unitfor each Vault unit and all Vault exchangeable shares were exchanged for PennWest trust units based on the exchange ratio for Vault units at the effectivedate of the Plan of Arrangement. Subsequent to the close of the Vaultacquisition, Penn West made its compulsory offer to redeem the Vaultconvertible debentures for cash at 101 percent of the principle amounts. On March 5,2008, Penn West retired $23.8 million of the principle amount of the debenturesfor $24.5 million including the premium and accrued interest.

 
| **Estimated Total Consideration** | ** ** | **(millions)** | ** ** |
|---------------------------------------------|------------|----------------|------------|
| 5.6 million Penn West trust units issued    |       | $              | 157.9      |   |
| Transaction costs                           |       | 5.0            |       |
| Bank debt                                   |       | 88.8           |       |
| Convertible debentures                      |       | 100.9          |       |
| Working capital deficiency                  |       | 33.4           |       |
| **Total**                                   | ** ** | **$**          | **386.0**  | ** ** |

 

**The New Alberta Royalty Framework**

 

OnOctober 25, 2007, the Government of Alberta (the “Government”) releasedits new royalty framework which is to become effective January 1, 2009.The new framework maintains or continues certain programs that are important toPenn West:

 

·                  Conventional production from oil sands leaseswill maintain oil sands administrative status which benefits our Peace RiverOil Sands project due to the reduced royalty rates;

 

·                  Enhanced Oil Recovery (“EOR”) and InnovativeEnergy Technology incentive programs will continue. Penn West has significantinventories of legacy light oil interests amenable to EOR and interests in CO2 EOR producingand other CO2pilot projects; and

 

·                  Otherwise Flared Solution Gas Waiver Programwill continue, which supports our long-standing environmental operating and assetoptimization objectives.

 

Onconventional production, the Government confirmed that its new royaltyframework will be sensitive to well productivity and commodity prices atslightly higher thresholds than the September 18, 2007 proposals of theAlberta Royalty Review Panel. Penn West, as the largest energy trust in NorthAmerica, has a diversity of play types across the Western Canada SedimentaryBasin. Approximately 60 percent of our production is from Alberta Crown leasesand our historical asset strategies have favoured mature assets. We are currentlyassessing the impact that the new royalty framework will have on ourconventional capital allocations for 2008 and beyond. We currently expect thatour conventional producing oil and natural gas strategies and business planswill only be minimally affected at current commodity prices and at our currentasset mix.

 

InJanuary 2008, ministers of the Government of Alberta publically statedthat a possible re-review of the new Alberta Royalty Framework could occur,with the objective of avoiding “unintended consequences” such as disincentivesto drill certain types of wells; however, no details have been formallyannounced.

 

3

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**Enactment of the Tax on Income Trusts**

 

OnJune 12, 2007, the federal legislation (Bill C-52) implementing the newtax on publicly traded income trusts and limited partnerships (the “SIFT tax”),referred to as “Specified Investment Flow-Through” (“SIFT”) entities receivedthird reading in the House of Commons and on June 22, 2007, the Billreceived Royal Assent.

 

ForSIFTs in existence on October 31, 2006 including Penn West, the SIFT taxwill be effective in 2011 unless certain rules related to “undue expansion”are not adhered to. Under the guidance provided, with the recent close of Vaultand Canetic and along with other transactions, we can increase our equity byapproximately $15 billion between now and 2011 without prematurely triggeringthe SIFT tax.

 

Underthe SIFT tax, distributions from certain types of income will not be deductiblefor income tax purposes by SIFTs in 2011, and thereafter, and any resultanttrust level taxable income will be taxed at approximately the corporate incometax rate. The SIFT rate was initially proposed at 31.5 percent; however, on October 30,2007, the Government of Canada, in its Mini-Budget (Bill C-28),proposed reductions to the general corporate tax rate, thereby reducing theSIFT rate to 29.5 percent in 2011 and 28.0 percent in 2012 and later. On December 14,2007 Bill C-28 received Royal Assent, resulting in a reduction to the SIFT taxrate as it becomes effective in 2011, and lowering the rate at which anycorporate income taxes will be paid in Penn West’s operating entities. As theTrust currently has a significant tax pool base and expects to increase its taxpool base until 2011, it is expected that the Trust could shelter its taxableincome for a period after the effective date of the SIFT tax. Distributions ofthis nature would not be currently taxable to unitholders as they would representa return of capital that would continue to be an adjustment to a unitholder’sadjusted cost base of trust units. Distributions from income subject to theSIFT tax will be considered taxable dividends to unitholders and will generallybe eligible for the dividend tax credit. The SIFT tax was not intended toadversely affect the after-tax yield of Canadian investors who hold Penn Westunits in a non-tax deferred account.

 

Foraccounting purposes, the SIFT tax charge during the second quarter of 2007 was$325.5 million reflecting the current estimate of the temporary differencesbetween the book and tax basis of assets and liabilities expected to beremaining in the Trust in 2011. The majority of the temporary differences atthe Penn West Trust level resulted from the acquisition of Petrofund on June 30,2006.

 

PennWest Petroleum Ltd.’s Board of Directors and management are continuouslymonitoring the impact of this tax on our business strategies. We expect futuretechnical interpretations and details will further clarify the legislation. Atthe present time, Penn West believes some or all of the following actions willor could result in the future due to the SIFT tax:

 

·                  If structural or other similar changes are notmade, the distribution yield net of the SIFT tax in 2011 and beyond to taxableCanadian investors will remain approximately the same; however, thedistribution yield to tax-deferred Canadian investors (RRSPs, RRIFs,pension plans, etc.) would fall by an estimated 29.5 percent in 2011 and 28.0percent in 2012 and beyond. For U.S. investors, the distribution yield net ofthe SIFT and withholding taxes would fall by an estimated 25.1 percent in 2011 and 23.8percent in 2012 and beyond;

 

·                  A portion of Penn West’s funds flow could berequired for the payment of the SIFT tax, or other forms of tax, and would notbe available for distribution or reinvestment;

 

·                  Penn West could convert to a corporatestructure with yield in the form of dividends to facilitate investing a higher proportion orall of its funds flow in exploration and development projects. Such aconversion could result in the reduction, or the elimination, of the currentdistribution program in favour of higher capital investment and/or a dividendpayment program; and

 

·                  Penn West might determine that it is moreeconomic to remain in the trust structure, at least for a period of time, and shelter itstaxable income using tax pools and pay all or a portion of its distributions ona return of capital basis, likely at a lower payout ratio. Further, as the SIFTtax rate exceeds the corporate income tax rate that would be applicable to PennWest, the tax strategy might involve paying some corporate tax resulting in allor a portion of those distributions being paid on a return of capital basis ata lower payout ratio.

 

4

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TheTrust continues to review all organizational structures and alternatives tominimize the impact of the SIFT tax on its unitholders. While there can be noassurance that the negative effect of the tax can be minimized or eliminated,Penn West and its advisors will continue to work diligently on these issues.

 

OnFebruary 26, 2008, the Government of Canada, in its Federal Budget,announced changes to the SIFT tax rules. The provincial component of the SIFTtax will be based on the provincial rates where the SIFT has a permanentestablishment rather than using a 13 percent flat rate. As Penn West currentlyhas its permanent establishment in the Province of Alberta, its combined SIFTtax rate applicable in 2012 is expected to fall from 28 percent to 25 percent.

 

**Business Environment**

 

Thecurrent business environment reflects high oil prices offset by weak naturalgas prices, a strong Canadian dollar relative to the U.S. dollar, volatilecapital markets due to turmoil in debt capital markets caused by asset-backedcommercial paper and sub-prime mortgage issues and low interest rates byhistorical standards, offset by significantly higher credit spreads oncorporate debt.

 

Continuingdemand for commodities including crude oil from growing economies such as Chinaand India, increasing oil consumption in many of the oil exporting countriesand continuing political instability in parts of the world resulted in oilprices remaining strong in 2007. The price of West Texas Intermediate (“WTI”),the primary benchmark for light crude oil prices, averaged US$72.34 per barrelin 2007, up by approximately nine percent from 2006.

 

Heavyoil differentials widened slightly in 2007, a result of continued refineryupsets throughout the year. The Canadian Bow River differential to WTI widenedby eight percent from 2006.

 

AECOnatural gas prices weakened in 2007, decreasing by five percent to $6.60 permcf from $6.98 per mcf in 2006. Weak natural gas prices reflected record NorthAmerican storage levels resulting from warmer than average North Americantemperatures coupled with record liquefied natural gas (“LNG”) imports drivenby warmer than average weather in other parts of the world. Recently, theoutlook for natural gas prices has begun to improve as global demand fornatural gas has continued to outpace supply due to colder weather resulting inlower North American LNG deliveries and leading to more balanced supply/demandfundamentals.

 

Lowernatural gas prices and a strengthening of the Canadian dollar relative to theU.S. dollar continued to partially offset the benefit of stronger oilprices. Oil sales contracts are generally based on WTI prices denominated inU.S. dollars; therefore the strengthening Canadian dollar reducedCanadian dollar-denominated oil prices. The average exchange rate increasedfrom CAD$1.00 equals US$0.8882 in 2006 to CAD$1.00 equals US$0.9300 in 2007 andis currently approximately at parity.

 

Royaltiescame under scrutiny by the Alberta government in 2007 leading to theannouncement of the new royalty rate framework for the province with aneffective date of January 1, 2009. Other provinces have maintained currentroyalty structures; however, future changes, both positive and/or negative innature, may occur.

 

Operatingcost initiatives continue to be a focus of Penn West. During 2007, the industryencountered a slow-down in drilling activity primarily due to low natural gasprices and uncertainties resulting from the Alberta royalty review. Penn Westexperienced only modest increases in operating costs as a result of thesefactors.

 

Wehave an experienced management team and strong technical staff who arecommitted to exploiting our assets along with realizing operationalefficiencies from our economies of scale. Over the past two years, we havecompleted significant acquisitions including Canetic, Petrofund and Vault, alladding production and reserves throughout the Western Canada Sedimentary Basinand elsewhere. We are now the largest conventional oil and natural gas trust inNorth America, with a dominant position in Canada’s legacy light oil pools.These conventional opportunities combined with our unconventional resourceplays including our Peace River Oil Sands project, coal bed methane, shale gasand enhanced oil recovery opportunities create the diversity and theflexibility that will help us to adjust to changing economic, political andenvironmental conditions.

 

5

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PennWest strives to generate and preserve unitholder value by:

 

·                  Continuing the development of our high-qualityassets, with a balance between low-risk, cost efficient resource plays and furtherdevelopment of our unconventional opportunities such as our Peace River OilSands project and CO2 enhanced oil recoveryprojects;

 

·                  Maintaining a stable distribution profilethrough active risk management activities, maintaining and optimizing our productioninfrastructure, further consolidating our core asset areas and exploitingopportunities availed by our undeveloped land position;

 

·                  Pursuing strategic or accretive acquisitionsboth domestically and internationally to further expand our already significantinventory of assets; and

 

·                  Maintaining our strong financial position andbalance sheet and operating with financial discipline.

 

**Unitholder Value Measures**

 
| ** **                                       | ** ** | **Year ended December 31** | ** ** |
|--------------------------------------------------|------------|-------------------------------------------|------------|
| ** **                                       | ** ** | **2007**                                  | ** ** | **2006** | ** ** | **2005** | ** ** |
| Funds flow per unit                              | ** ** | **$**                                     | **5.56**   |   | $ | 5.86 |   | $ | 7.28 |   |
| Distributions per unit                           | ** ** | **$**                                     | **4.08**   |   | $ | 4.05 |   | $ | 1.97 |   |
| Dividends per unit                               | ** ** | **$**                                     | **—** |   | $ | — |   | $ | 0.07 |   |
| Ratio of year-end bank debt to annual funds flow | ** ** | **1.5**                                   |       | 1.1 |   | 0.5 |   |

 

PennWest maintained a distribution of $0.34 per unit per month throughout 2007 andhad continued that level since the rate was increased in February 2006.Increases in the bank debt to funds flow ratio were primarily due to propertyacquisitions during 2007 that led to increased debt levels.

 

**Performance Indicators**

 
| ** **                     | ** ** | **Year ended December 31** | ** ** |
|--------------------------------|------------|-------------------------------------------|------------|
| ** **                     | ** ** | **2007**                                  | ** ** | **2006** | ** ** | **2005** | ** ** |
| Return on capital employed (1) | ** ** | **8.9**                                   | **%**      | 12.8 | % | 17.0 | % |
| Total assets (millions)        | ** ** | **$**                                     | **8,433**  |   | $ | 8,070 |   | $ | 3,967 |   |
| Return on equity (2)           | ** ** | **3.6**                                   | **%**      | 18.1 | % | 28.3 | % |
|                                |            |                                           |            |  |  |  |  |  |  |  |

 

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(1)  Net income before financing charges divided byaverage total liabilities less current assets.

(2)  Net income divided by average unitholders’equity.

 

During2007, pre-tax net income was affected by the $201.6 million unrealized loss onrisk management activities in 2007. Further, in the second quarter of 2007, theenactment of the SIFT tax led to a $325.5 million non-cash, future income taxcharge during the period. During the fourth quarter of 2007, the Government ofCanada announced rate reductions that led to a $106.4 million reduction in theperiod. If neither the SIFT tax nor the tax rate reductions had been enacted in2007, return on capital employed and return on equity would have been 13.1 percentand 8.1 percent respectively.

 

**Results Of Operations**

 

**Production**

 
| ** **                      | ** ** | **Three months ended December 31** | ** ** | **Year ended December 31** | ** ** |
|---------------------------------|------------|--------------------------------------------------------|------------|-------------------------------------------|------------|
| **Daily production**       | ** ** | **2007**                                               | ** ** | **2006**                                  | ** ** | **% change** | ** ** | **2007** | ** ** | **2006** | ** ** | **% change** | ** ** |
| Natural gas (mmcf/d)            | ** ** | **328.1**                                              |       | 354.6                                     |       | (7 | ) | **329.4** |   | 312.5 |   | 5 |   |
| Light oil and NGL (bbls/d)      | ** ** | **51,070**                                             |       | 48,233                                    |       | 6 | ** ** | **50,175** |   | 39,514 |   | 27 |   |
| Conventional heavy oil (bbls/d) | ** ** | **22,262**                                             |       | 22,586                                    |       | (1 | ) | **22,019** |   | 20,776 |   | 6 |   |
| Total production (boe/d) (1)    | ** ** | **128,024**                                            |       | 129,915                                   |       | (1 | ) | **127,098** |   | 112,369 |   | 13 |   |

 

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

 

6

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Productionin the fourth quarter of 2007 exceeded the 125,345 boe per day produced in thethird quarter of 2007 due primarily to the resumption of production at our 100percent owned Wildboy natural gas plant in November 2007. The plant wasrunning at only partial capacity after a fire at the adjoining tank farm inmid-May of 2007. We expect that our business interruption insurance willcover the majority of the lost funds flow, excluding the deductible portion.

 

Westrive to maintain an approximately balanced portfolio of liquids and naturalgas production provided it is economic to do so. We believe a balance byproduct helps to reduce exposure to price volatility that can affect a singlecommodity. In the fourth quarter of 2007, crude oil and NGL production averaged73,332 barrels per day (57 percent of production) and natural gas productionaveraged 328.1 mmcf per day (43 percent of production).

 

Wedrilled 43 net wells in the fourth quarter of 2007, mainly in the Central andPlains areas, compared to 52 in the same period of 2006.

 

**CommodityMarkets**

 

**NaturalGas**

 

NorthAmerican natural gas prices remained weak in the fourth quarter of 2007,particularly compared to oil prices. Natural gas storage levels continued togrow throughout the fall reaching record levels to offset the increased demanddue to the onset of winter. Spot natural gas prices at AECO in the fourthquarter increased to $6.00 per mcf or approximately seven percent over theprior quarter. Penn West’s realized price averaged $6.54 per mcf, includinggains from commodity contracts.

 

**CrudeOil**

 

WTIoil prices strengthened in the fourth quarter of 2007, with continued concernover supply and inventory levels coupled with ongoing geo-political concerns.The crude oil market has been extremely volatile in recent months as demandappeared to remain impervious to price. As the Canadian dollar strengthened relativeto the U.S. dollar, Edmonton par oil prices traded lower relative to WTI pricesthrough the quarter. Both heavy and sour Canadian oil differentials to theEdmonton par light oil price widened over the third quarter of 2007. Bow Riverdifferential to Edmonton averaged $29.50 per barrel compared to $24.60 in theprevious quarter due primarily to lower seasonal demand and scheduled refineryturnarounds in the quarter. Penn West’s average price for liquids, includingrealized losses from commodity contracts, was $65.71 per barrel.

 

**Average Sales Prices Received**

 
| ** **                       | ** ** | **Three months ended December 31** |       | **Year ended December 31** | ** ** |
|----------------------------------|------------|--------------------------------------------------------|------------|-------------------------------------------|------------|
| ** **                       | ** ** | **2007**                                               | ** ** | **2006**                                  | ** ** | **% change** |   | **2007** | ** ** | **2006** | ** ** | **% change** | ** ** |
| Natural gas (per mcf)            | ** ** | **$**                                                  | **6.34**   |                                      | $          | 6.97 |   | (9 | ) | **$** | **6.85** |   | $ | 6.75 |   | 1 |   |
| Risk management (per mcf)        | ** ** | **0.20**                                               |       | 0.56                                      |       | (64 | ) | **0.17** |   | 0.72 |   | (76 | ) |
| Natural gas net (per mcf)        | ** ** | **6.54**                                               |       | 7.53                                      |       | (13 | ) | **7.02** |   | 7.47 |   | (6 | ) |
|                             | ** ** | ** **                                             |       |                                      |       |   |   | ** ** |   |   |   |   |   |
| Light oil and NGL (per bbl)      | ** ** | **76.99**                                              |       | 57.43                                     |       | 34 |   | **68.75** |   | 65.02 |   | 6 |   |
| Risk management (per bbl)        | ** ** | **(3.87**                                              | **)**      | 0.01                                      |       | — |   | **(0.97** | **)** | (1.00 | ) | (3 | ) |
| Light oil and NGL (per bbl)      | ** ** | **73.12**                                              |       | 57.44                                     |       | 27 |   | **67.78** |   | 64.02 |   | 6 |   |
|                             | ** ** | ** **                                             |       |                                      |       |   |   | ** ** |   |   |   |   |   |
| Conventional heavy oil (per bbl) | ** ** | **48.69**                                              |       | 37.57                                     |       | 30 |   | **45.26** |   | 43.07 |   | 5 |   |
|                             | ** ** | ** **                                             |       |                                      |       |   |   | ** ** |   |   |   |   |   |
| Weighted average (per boe)       | ** ** | **55.44**                                              |       | 46.88                                     |       | 18 |   | **52.73** |   | 49.58 |   | 6 |   |
| Risk management (per boe)        | ** ** | **(1.02**                                              | **)**      | 1.53                                      |       | (167 | ) | **0.06** |   | 1.64 |   | (96 | ) |
| Weighted average net (per boe)   | ** ** | **$**                                                  | **54.42**  |                                      | $          | 48.41 |   | 12 |   | **$** | **52.79** |   | $ | 51.22 |   | 3 |   |

 

7

----

 

**Netbacks**

 
| ** **                      | ** ** | **Three months ended December 31** |       | **Year ended December 31** | ** ** |
|---------------------------------|------------|--------------------------------------------------------|------------|-------------------------------------------|------------|
| ** **                      | ** ** | **2007**                                               | ** ** | **2006**                                  | ** ** | **% change** |   | **2007** | ** ** | **2006** | ** ** | **% change** | ** ** |
| **Natural gas**                 |       |                                                   |       |                                      |       |   |   |   |   |   |   |   |   |
| Production (mmcf/day)           | ** ** | **328.1**                                              |       | 354.6                                     |       | (7 | ) | **329.4** |   | 312.5 |   | 5 |   |
| Operating netback (per mcf):    |       |                                                   |       |                                      |       |   |   |   |   |   |   |   |   |
| Sales price                     | ** ** | **$**                                                  | **6.34**   |                                      | $          | 6.97 |   | (9 | ) | **$** | **6.85** |   | $ | 6.75 |   | 1 |   |
| Risk management (gain) (2)      | ** ** | **(0.20**                                              | **)**      | (0.56                                     | )          | (64 | ) | **(0.17** | **)** | (0.72 | ) | (76 | ) |
| Royalties                       | ** ** | **1.34**                                               |       | 1.63                                      |       | (18 | ) | **1.48** |   | 1.53 |   | (3 | ) |
| Operating costs                 | ** ** | **1.17**                                               |       | 1.04                                      |       | 13 |   | **1.12** |   | 0.99 |   | 13 |   |
| Transportation                  | ** ** | **0.21**                                               |       | 0.18                                      |       | 17 |   | **0.20** |   | 0.21 |   | (5 | ) |
| Netback                         | ** ** | **$**                                                  | **3.82**   |                                      | $          | 4.68 |   | (18 | ) | **$** | **4.22** |   | $ | 4.74 |   | (11 | ) |
| **Light oil and NGL**           |       |                                                   |       |                                      |       |   |   |   |   |   |   |   |   |
| Production (bbls/day)           | ** ** | **51,070**                                             |       | 48,233                                    |       | 6 |   | **50,175** |   | 39,514 |   | 27 |   |
| Operating netback (per bbl):    |       |                                                   |       |                                      |       |   |   |   |   |   |   |   |   |
| Sales price                     | ** ** | **$**                                                  | **76.99**  |                                      | $          | 57.43 |   | 34 |   | **$** | **68.75** |   | $ | 65.02 |   | 6 |   |
| Risk management loss (gain) (2) | ** ** | **3.87**                                               |       | (0.01                                     | )          | — |   | **0.97** |   | 1.00 |   | (3 | ) |
| Royalties                       | ** ** | **13.24**                                              |       | 10.55                                     |       | 26 |   | **11.94** |   | 10.87 |   | 10 |   |
| Operating costs                 | ** ** | **15.55**                                              |       | 15.36                                     |       | 1 |   | **15.29** |   | 15.80 |   | (3 | ) |
| Netback                         | ** ** | **$**                                                  | **44.33**  |                                      | $          | 31.53 |   | 41 |   | **$** | **40.55** |   | $ | 37.35 |   | 9 |   |
| **Conventional heavy oil**      |       |                                                   |       |                                      |       |   |   |   |   |   |   |   |   |
| Production (bbls/day)           | ** ** | **22,262**                                             |       | 22,586                                    |       | (1 | ) | **22,019** |   | 20,776 |   | 6 |   |
| Operating netback (per bbl):    |       |                                                   |       |                                      |       |   |   |   |   |   |   |   |   |
| Sales price                     | ** ** | **$**                                                  | **48.69**  |                                      | $          | 37.57 |   | 30 |   | **$** | **45.26** |   | $ | 43.07 |   | 5 |   |
| Royalties                       | ** ** | **7.18**                                               |       | 6.46                                      |       | 11 |   | **6.79** |   | 7.47 |   | (9 | ) |
| Operating costs                 | ** ** | **12.32**                                              |       | 11.88                                     |       | 4 |   | **12.18** |   | 11.22 |   | 9 |   |
| Transportation                  | ** ** | **0.06**                                               |       | 0.07                                      |       | (14 | ) | **0.07** |   | 0.07 |   | — |   |
| Netback                         | ** ** | **$**                                                  | **29.13**  |                                      | $          | 19.16 |   | 52 |   | **$** | **26.22** |   | $ | 24.31 |   | 8 |   |
| **Total liquids**               |       |                                                   |       |                                      |       |   |   |   |   |   |   |   |   |
| Production (bbls/day)           | ** ** | **73,332**                                             |       | 70,819                                    |       | 4 |   | **72,194** |   | 60,290 |   | 20 |   |
| Operating netback (per bbl):    |       |                                                   |       |                                      |       |   |   |   |   |   |   |   |   |
| Sales price                     | ** ** | **$**                                                  | **68.40**  |                                      | $          | 51.09 |   | 34 |   | **$** | **61.59** |   | $ | 57.46 |   | 7 |   |
| Risk management loss (gain) (2) | ** ** | **2.69**                                               |       | (0.01                                     | )          | — |   | **0.67** |   | 0.66 |   | 2 |   |
| Royalties                       | ** ** | **11.40**                                              |       | 9.24                                      |       | 23 |   | **10.37** |   | 9.69 |   | 7 |   |
| Operating costs                 | ** ** | **14.57**                                              |       | 14.25                                     |       | 2 |   | **14.34** |   | 14.22 |   | 1 |   |
| Transportation                  | ** ** | **0.02**                                               |       | 0.02                                      |       | — |   | **0.02** |   | 0.03 |   | (33 | ) |
| Netback                         | ** ** | **$**                                                  | **39.72**  |                                      | $          | 27.59 |   | 44 |   | **$** | **36.19** |   | $ | 32.86 |   | 10 |   |
| **Combined totals**             |       |                                                   |       |                                      |       |   |   |   |   |   |   |   |   |
| Production (boe/day) (1)        | ** ** | **128,024**                                            |       | 129,915                                   |       | (1 | ) | **127,098** |   | 112,369 |   | 13 |   |
| Operating netback (per boe):    |       |                                                   |       |                                      |       |   |   |   |   |   |   |   |   |
| Sales price                     | ** ** | **$**                                                  | **55.44**  |                                      | $          | 46.88 |   | 18 |   | **$** | **52.73** |   | $ | 49.58 |   | 6 |   |
| Risk management loss (gain) (2) | ** ** | **1.02**                                               |       | (1.53                                     | )          | (167 | ) | **(0.06** | **)** | (1.64 | ) | (96 | ) |
| Royalties                       | ** ** | **9.97**                                               |       | 9.48                                      |       | 5 |   | **9.72** |   | 9.46 |   | 3 |   |
| Operating costs                 | ** ** | **11.35**                                              |       | 10.61                                     |       | 7 |   | **11.04** |   | 10.39 |   | 6 |   |
| Transportation                  | ** ** | **0.56**                                               |       | 0.51                                      |       | 10 |   | **0.52** |   | 0.60 |   | (13 | ) |
| Netback                         | ** ** | **$**                                                  | **32.54**  |                                      | $          | 27.81 |   | 17 |   | **$** | **31.51** |   | $ | 30.77 |   | 2 |   |

 

----

(1)  Barrels of oil equivalent (boe) are based onsix mcf of natural gas being equal to one barrel of oil (6:1).

(2)  Realized component of risk managementactivities related to oil and natural gas prices.

 

8

----

 

**Production Revenues**

 

Revenuesfrom the sale of oil, NGL and natural gas consisted of the following:

 
| ** **              | ** ** | **Year ended December 31** | ** **  |
|-------------------------|------------|-------------------------------------------|-------------|
| **(millions)**          | ** ** | **2007**                                  | ** **  | **2006** | ** ** | **2005** | ** ** |
| Natural gas             | ** ** | **$**                                     | **856.6**   |   | $ | 850.9 |   | $ | 918.2 |   |
| Light oil and  NGL      | ** ** | **1,241.4**                               |        | 923.4 |   | 757.0 |   |
| Conventional  heavy oil | ** ** | **363.8**                                 |        | 326.6 |   | 243.8 |   |
| Gross revenues (1)      | ** ** | **$**                                     | **2,461.8** |   | $ | 2,100.9 |   | $ | 1,919.0 |   |

 

----

(1)  Gross revenues include realized gains and losses on commodity contracts.

 

**Increases (Decreases) in Production Revenues**

 
| **(millions)**                                                             | ** ** | ** ** | ** ** |
|----------------------------------------------------------------------------|------------|------------|------------|
| Gross revenues –  2006                                                |       | $          | 2,100.9    |   |
| Increase in  light oil and NGL production                                  |       | 249.2      |       |
| Increase in  light oil and NGL prices (including realized risk management) |       | 68.9       |       |
| Increase in  conventional heavy oil production                             |       | 19.5       |       |
| Increase in  conventional heavy oil prices                                 |       | 17.6       |       |
| Increase in  natural gas production                                        |       | 46.1       |       |
| Decrease in  natural gas prices (including realized risk management)       |       | (40.4      | )          |
| Gross revenues –  2007                                                |       | $          | 2,461.8    |   |

 

Inthe fourth quarter of 2007 gross revenues increased by 11 percent to $644.0million from $578.5 million in 2006. This was primarily due to a 34 percentincrease in light oil and NGL sales prices to $76.99 per bbl in 2007 from$57.43 per bbl in 2006 and a 30 percent increase in conventional heavy oilsales price to $48.69 per bbl in 2007 from $37.57 per bbl in 2006.

 

**Royalties**

 
| ** **                | ** ** | **Year ended December 31** | ** ** |
|---------------------------|------------|-------------------------------------------|------------|
| ** **                | ** ** | **2007**                                  | ** ** | **2006** | ** ** | **2005** | ** ** |
| Royalties  (millions)     | ** ** | **$**                                     | **450.8**  |   | $ | 388.0 |   | $ | 369.7 |   |
| Average royalty  rate (%) | ** ** | **18**                                    | **%**      | 18 | % | 19 | % |
| Per boe                   | ** ** | **$**                                     | **9.72**   |   | $ | 9.46 |   | $ | 10.15 |   |

 

**Expenses**

 
| ** **               | ** ** | **Year ended December 31** | ** ** |
|--------------------------|------------|-------------------------------------------|------------|
| **(millions)**           | ** ** | **2007**                                  | ** ** | **2006** | ** ** | **2005** | ** ** |
| Operating                | ** ** | **$**                                     | **512.2**  |   | $ | 426.3 |   | $ | 327.4 |   |
| Transportation           | ** ** | **24.1**                                  |       | 24.5 |   | 22.7 |   |
| Financing                | ** ** | **92.4**                                  |       | 49.3 |   | 23.2 |   |
| Unit-based  compensation | ** ** | **$**                                     | **20.5**   |   | $ | 11.3 |   | $ | 77.2 |   |

 
| ** **               | ** ** | **Year ended December 31** | ** ** |
|--------------------------|------------|-------------------------------------------|------------|
| **(per boe)**       | ** ** | **2007**                                  | ** ** | **2006** | ** ** | **2005** | ** ** |
| Operating                | ** ** | **$**                                     | **11.04**  |   | $ | 10.39 |   | $ | 8.99 |   |
| Transportation           | ** ** | **0.52**                                  |       | 0.60 |   | 0.62 |   |
| Financing                | ** ** | **2.00**                                  |       | 1.20 |   | 0.63 |   |
| Unit-based  compensation | ** ** | **$**                                     | **0.44**   |   | $ | 0.27 |   | $ | 2.12 |   |

 

9

----

 

**Operating**

 

PennWest continued all of its initiatives to limit increases to operating costs.Over the past two years, operating cost escalation occurred industry-wide dueto strong demand for skilled labour and oilfield services, particularlydrilling and oilfield service rigs. Penn West’s modest increases in operatingcosts per barrel of oil equivalent were generally due to a higher proportion ofliquids production in 2007 than in the comparative 2006 periods. Currently,with the low natural gas price and the recent Alberta royalty recommendations,we are experiencing a slow-down in industry activity that is expected toalleviate some of the high demand for oilfield services in the near future. Theaddition of the Petrofund assets effective July 1, 2006, with higheroperating costs than the Penn West assets, also contributed to the increase.

 

Duringthe fourth quarter of 2007, operating costs increased by six percent to $135.1million from $127.7 million in the same period of 2006, due to industry-widecost escalations.

 

Arealized gain of $11.0 million (2006 – $17.3 million) on our electricitycontracts was included in operating costs for the year.

 

**Financing**

 

PennWest Petroleum Ltd. (“the Company”) closed the placement of US$475 million ofnotes on May 31, 2007. The interest rates on the notes are fixed at 5.68to 6.05 percent for terms of 8 to 15 years and average 5.8 percent. During September 2007,the Company entered into foreign exchange contracts to fix the repayment (inCanadian dollars) on US$250 million at an exchange rate of approximately oneCanadian dollar at par with one U.S. dollar. In addition, the Company has swapson $100 million of bank debt that fix the interest rate at approximately 4.36percent until March 2008 and on $100 million of bank debt that fix theinterest rate at approximately 4.26 percent until November 2010. Theinterest rate on the balance of the Company’s long-term debt is currently basedon short-term, floating interest rate debt instruments.

 

Inthe fourth quarter of 2007, Penn West incurred $27.2 million of financingcharges compared to $17.8 million in the same period of 2006 due to increaseddebt levels.

 

The2007 increase in interest expense resulted from both an increase in the averageoutstanding debt balance and increases in interest rates over 2006. The U.S.notes contain slightly higher fixed interest rates than the Company was subjectto under its syndicated credit facility using short-term money marketinstruments. Penn West believes the long-term nature and the fixed interestrates inherent in the notes are beneficial for a portion of its capitalstructure. The increased average loan balance was principally due to propertyacquisitions in 2007.

 

**Unit-BasedCompensation**

 

Unit-basedcompensation expense related to Penn West’s Trust Unit Rights Incentive Plan isbased on the fair value of trust unit rights issued, determined using theBinomial Lattice option-pricing model. The fair value of rights issued isamortized over the remaining vesting periods on a straight-line basis. Theunit-based compensation expense was $5.5 million for the three months ended December 31,2007, of which $1.5 million was charged to operating expense and $4.0 millionwas charged to general and administrative expense (2006 – $3.1 million, $0.8million and $2.3 million, respectively). The amount per boe increased in 2007due to additional options granted in the period.

 

10

----

 

**General and Administrative Expenses**

 
| ** **       | ** ** | **Year ended December 31** | ** ** |
|------------------|------------|-------------------------------------------|------------|
| ** **       | ** ** | **2007**                                  | ** ** | **2006** | ** ** | **2005** | ** ** |
| Gross (millions) | ** ** | **$**                                     | **83.3**   |   | $ | 62.0 |   | $ | 45.0 |   |
| Per boe          | ** ** | **1.80**                                  |       | 1.51 |   | 1.24 |   |
| Net (millions)   | ** ** | **50.8**                                  |       | 36.0 |   | 23.1 |   |
| Per boe          | ** ** | **$**                                     | **1.10**   |   | $ | 0.88 |   | $ | 0.64 |   |

 

Theworkplace environment continues to be highly competitive in hiring,compensating and retaining employees and consultants. Professional staff,particularly those with experience and strong technical skills, continue to bein high demand, leading to increased compensation costs. Additional regulatorycompliance activities have also contributed to increased costs.

** **

**Depletion, Depreciation and Accretion (“DD&A”)**

** **
| ** **                                                 | ** ** | **Year ended December 31** | ** ** |
|------------------------------------------------------------|------------|-------------------------------------------|------------|
| **(millions, except per boe amounts)** | ** ** | **2007**                                  | ** ** | **2006** | ** ** | **2005** | ** ** |
| Depletion of oil  and natural gas assets                   | ** ** | **$**                                     | **867.4**  |   | $ | 635.0 |   | $ | 416.5 |   |
| Accretion of  asset retirement obligation (1)              | ** ** | **29.3**                                  |       | 19.7 |   | 21.1 |   |
| Total DD&A                                             | ** ** | **$**                                     | **896.7**  |   | $ | 654.7 |   | $ | 437.6 |   |
| DD&A expense  per boe                                  | ** ** | **$**                                     | **19.33**  |   | $ | 15.96 |   | $ | 12.01 |   |

 

----

(1) Represents the accretion expense on the asset retirement obligation during theperiod.

 

DD&Aexpense in 2007 was higher than in 2006 due to a full year of production fromthe Petrofund assets and a higher depletion rate as a result of the Petrofundacquisition, which closed in June 30, 2006. Penn West accounted for theacquisition as a purchase of Petrofund with the purchase price allocated to thefair value of net identifiable assets acquired. The purchase price allocationto oil and natural gas assets at fair value significantly increased ourconsolidated depletion base per unit. Preliminary estimates for 2008 indicatethe 2008 DD&A rate will further increase due to the Vault and Caneticacquisitions.

** **

**Taxes**

** **
| ** **                         | ** ** | **Year ended December 31** | ** ** |
|------------------------------------|------------|-------------------------------------------|------------|
| **(millions)**                     | ** ** | **2007**                                  | ** ** | **2006** | ** ** | **2005** | ** ** |
| Current income                     | ** ** | **$**                                     | **—** |   | $ | — |   | $ | 54.1 |   |
| Future income  expense (reduction) | ** ** | **75.4**                                  |       | (106.2 | ) | (1.1 | ) |
| ** **                         |       | **$**                                     | **75.4**   |   | $ | (106.2 | ) | $ | 53.0 |   |

 

Temporarydifferences at the Trust level, or differences between book and tax basis ofthe assets and liabilities, were previously not recognized under GAAP as futureincome taxes because the Trust was required to distribute all of its taxableincome under the terms of its Trust Indenture. Under the SIFT legislation, in2011 and beyond, as distributions will no longer be tax deductible, the Trustwill not be able to make distributions to reduce its taxable income and thus isno longer considered to be exempt from income taxes for accounting purposes.

 

11

----

 

Duringthe second quarter of 2007, a $325.5 million charge was recorded due to theenactment of the SIFT tax legislation during the period. The future income taxliability was increased to reflect the current temporary differences expectedto be remaining at the Trust level in 2011 using the then effective SIFT taxrate of 31.5 percent. On October 30, 2007, the Government of Canadaproposed rate reductions which were enacted in Bill C-28 on December 14,2007 lowering the SIFT tax rate to 29.5 percent in 2011 and to 28.0 percent for2012 and beyond and reducing future corporate income tax rates by an additional3.5 percent. During the fourth quarter of 2007, a $106.4 million future incometax reduction was recorded to reflect these substantively enacted tax rates.

 

OnFebruary 26, 2008, the Government of Canada, in its Federal Budget,announced changes to the SIFT tax rules. The provincial component of the SIFTtax will be based on the provincial rates where the SIFT has a permanentestablishment rather than using a 13 percent flat rate. For Penn West, the SIFTtax rate applicable in 2012 is expected to fall from 28 percent to 25 percent.As the tax rate change has not been substantively enacted, no future income taxrate benefit has been recorded in the financial statements.

 

Underour current structure, the operating entities make interest and royaltypayments to the Trust, which transfers taxable income to the Trust to eliminateincome subject to corporate income taxes in the operating entities. With thenew legislation, such amounts transferred to the Trust could be taxablebeginning in 2011 as distributions will no longer be deductible by the Trustfor income tax purposes. At that time, Penn West could claim on its tax poolsand pay all or a portionof its distributions on a return of capital basis. Such distributions would notbe immediately taxable to investors; they would generally reduce the adjusted cost base of units held byinvestors, however such distributions would potentially be at a lower payoutratio.

 

Thenew legislation is not currently expected to directly affect our funds flowlevels and distribution policies until 2011 at the earliest.

 

Theestimate of future income taxes is based on the current tax status of theTrust. Future events, which could materially affect future income taxes such asacquisitions and dispositions and modifications to the distribution policy, arenot reflected under Canadian GAAP until the events occur and the related legalrequirements have been fulfilled. As a result, future changes to the taxlegislation could lead to a material change in the recorded amount of futureincome taxes.

** **

**Tax Pools**

** **
| ** **                                     | ** ** | **As at December 31** | ** **  |
|------------------------------------------------|------------|--------------------------------------|-------------|
| **(millions)**                                 | ** ** | **2007**                             | ** **  | **2006** | ** ** | **2005** | ** ** |
| Undepreciated  capital cost (UCC)              | ** ** | **$**                                | **826.2**   |   | $ | 788.3 |   | $ | 519.0 |   |
| Canadian oil and  gas property expense (COGPE) | ** ** | **1,308.6**                          |        | 1,091.0 |   | 707.6 |   |
| Canadian  development expense (CDE)            | ** ** | **413.7**                            |        | 428.8 |   | 329.8 |   |
| Non-capital  losses                            | ** ** | **697.4**                            |        | 106.1 |   | — |   |
| Total tax pools                                | ** ** | **$**                                | **3,245.9** |   | $ | 2,414.2 |   | $ | 1,556.4 |   |

 

Theincrease in the 2007 tax pools reflects capital spending and income transfersto the Trust throughout the year. The tax pool figures are net of incomedeferred in operating partnerships.

 

**ForeignExchange**

 

In2007, the Trust had U.S.-dollar-denominated debt totalling $475 millioncompared to nil in 2006. The Trust recorded unrealized foreign exchange gainsof $38.2 million in 2007 related to the outstanding U.S. notes. No gains wererealized on these contracts in 2007 as no amounts were settled or converted toCanadian dollars during the year.

 

12

----

 

**Funds Flow and Net Income**

 
| ** **                    | ** ** | **Three months ended December 31** | ** ** | **Year ended December 31** | ** ** |
|-------------------------------|------------|--------------------------------------------------------|------------|-------------------------------------------|------------|
| ** **                    | ** ** | **2007**                                               | ** ** | **2006**                                  | ** ** | **% change** | ** ** | **2007** | ** ** | **2006** | ** ** | **% change** | ** ** |
| Funds flow(1) (millions) | ** ** | **$**                                                  | **347.2**  |                                      | $          | 303.3 |   | 14 | ** ** | **$** | **1,331.5** |   | $ | 1,176.8 |   | 13 |   |
| Basic per unit                | ** ** | **1.44**                                               |       | 1.23                                      |       | 17 | ** ** | **5.56** |   | 5.86 |   | (5 | ) |
| Diluted per unit              | ** ** | **1.43**                                               |       | 1.22                                      |       | 17 | ** ** | **5.51** |   | 5.78 |   | (5 | ) |
|                          | ** ** | ** **                                             |       |                                      |       |   | ** ** | ** ** |   |   |   |   |   |
| Net income  (millions)        | ** ** | **127.0**                                              |       | 122.9                                     |       | 3 | ** ** | **175.5** |   | 665.6 |   | (74 | ) |
| Basic per unit                | ** ** | **0.53**                                               |       | 0.44                                      |       | 20 | ** ** | **0.73** |   | 3.32 |   | (78 | ) |
| Diluted per unit              | ** ** | **$**                                                  | **0.52**   |                                      | $          | 0.44 |   | 18 | ** ** | **$** | **0.73** |   | $ | 3.27 |   | (78 | ) |

 

----

(1)  Fundsflow is a non-GAAP measure. See “Calculation of Funds Flow”.

 

Fundsflow realized in 2007 increased from the comparable 2006 period due to higherproduction volumes resulting from the Petrofund acquisition, partially offsetby higher operating and financing costs.

 

Inthe absence of the $325.5 million non-cash charge taken in the second quarterof 2007 to reflect the enactment of the SIFT tax and the $106.4 million raterecovery received in the fourth quarter of 2007, net income for 2007 would havebeen $394.6 million.

 
| ** **                               | ** ** | **Year ended December 31** | ** ** |
|------------------------------------------|------------|-------------------------------------------|------------|
| ** **                               | ** ** | **2007**                                  | ** ** | **2006** | ** ** | **2005** | ** ** |
| ** **                               | ** ** | **$/boe**                                 | ** ** | **%** | ** ** | **$/boe** | ** ** | **%** | ** ** | **$/boe** | ** ** | **%** | ** ** |
| Oil and natural  gas revenues (1)        | ** ** | **$**                                     | **53.08**  | ** ** | **100.0** | ** ** | $ | 51.22 |   | 100.0 |   | $ | 52.68 |   | 100.0 |   |
| Net royalties                            | ** ** | **(9.72**                                 | **)**      | **(18.3** | **)** | (9.46 | ) | (18.4 | ) | (10.15 | ) | (19.3 | ) |
| Operating  expenses (2)                  | ** ** | **(11.04**                                | **)**      | **(20.8** | **)** | (10.39 | ) | (20.3 | ) | (8.99 | ) | (17.1 | ) |
| Transportation                           | ** ** | **(0.52**                                 | **)**      | **(1.0** | **)** | (0.60 | ) | (1.2 | ) | (0.62 | ) | (1.1 | ) |
| Net operating  income                    | ** ** | **31.80**                                 | ** ** | **59.9** | ** ** | 30.77 |   | 60.1 |   | 32.92 |   | 62.5 |   |
| General and  administrative expenses     | ** ** | **(1.10**                                 | **)**      | **(2.0** | **)** | (0.88 | ) | (1.7 | ) | (0.64 | ) | (1.2 | ) |
| Interest                                 | ** ** | **(2.00**                                 | **)**      | **(3.8** | **)** | (1.20 | ) | (2.3 | ) | (0.63 | ) | (1.2 | ) |
| Realized foreign  exchange gain          | ** ** | **—**                                | ** ** | **—** | ** ** | — |   | — |   | 2.35 |   | 4.4 |   |
| Current taxes                            | ** ** | **—**                                | ** ** | **—** | ** ** | — |   | — |   | (1.48 | ) | (2.8 | ) |
| Funds flow                               | ** ** | **28.70**                                 | ** ** | **54.1** | ** ** | 28.69 |   | 56.0 |   | 32.52 |   | 61.7 |   |
| Unrealized  foreign exchange gain (loss) | ** ** | **0.82**                                  | ** ** | **1.5** | ** ** | — |   | — |   | (2.48 | ) | (4.7 | ) |
| Unit-based  compensation                 | ** ** | **(0.44**                                 | **)**      | **(0.8** | **)** | (0.27 | ) | (0.5 | ) | (2.12 | ) | (4.0 | ) |
| Risk management  activities (3)          | ** ** | **(4.35**                                 | **)**      | **(8.2** | **)** | 1.18 |   | 2.3 |   | (0.09 | ) | (0.2 | ) |
| Depletion,  depreciation and accretion   | ** ** | **(19.33**                                | **)**      | **(36.4** | **)** | (15.96 | ) | (31.2 | ) | (12.01 | ) | (22.8 | ) |
| Future income  taxes                     | ** ** | **(1.63**                                 | **)**      | **(3.0** | **)** | 2.59 |   | 5.1 |   | 0.03 |   | — |   |
| Net income                               | ** ** | **$**                                     | **3.77**   | ** ** | **(7.2** | **)** | $ | 16.23 |   | 31.7 |   | $ | 15.85 |   | 30.0 |   |

 

 

----

(1)   Gross revenues includerealized gains and losses on commodity contracts.

(2)   Operating expenses includerealized gains on electricity swaps.

(3)   Risk management activitiesrelate to the unrealized gain and losses on derivative instruments.

 

13

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**Goodwill**

 

Thegoodwill balance of $652.0 million resulted from the acquisition of Petrofundin June 2006. The Trust has determined that there was no goodwillimpairment as of December 31, 2007.

 

**Capital Expenditures**

** **
| ** **                                 | ** ** | **Three months ended December 31** | ** ** | **Year ended December 31** | ** ** |
|--------------------------------------------|------------|--------------------------------------------------------|------------|-------------------------------------------|------------|
| **(millions)**                             | ** ** | **2007**                                               | ** ** | **2006**                                  | ** ** | **2007** | ** ** | **2006** | ** ** |
| Property  acquisitions (dispositions), net | ** ** | **$**                                                  | **19.7**   |                                      | $          | 10.9 | ** ** | **$** | **421.7** |   | $ | 5.6 |   |
| Land acquisition  and retention            | ** ** | **0.8**                                                |       | 0.8                                       | ** ** | **30.2** |   | 19.8 |   |
| Drilling and  completions                  | ** ** | **96.1**                                               |       | 86.1                                      | ** ** | **367.2** |   | 317.4 |   |
| Facilities and  well equipping             | ** ** | **73.0**                                               |       | 57.9                                      | ** ** | **254.1** |   | 224.6 |   |
| Geological and  geophysical                | ** ** | **0.5**                                                |       | 1.0                                       | ** ** | **10.2** |   | 3.6 |   |
| CO2 pilot costs                       | ** ** | **9.8**                                                |       | 1.1                                       | ** ** | **19.8** |   | 3.7 |   |
| Administrative                             | ** ** | **10.8**                                               |       | 1.6                                       | ** ** | **15.8** |   | 3.2 |   |
| Capital  expenditures                      | ** ** | **210.7**                                              |       | 159.4                                     | ** ** | **1,119.0** |   | 577.9 |   |
| Business  combination                      | ** ** | **—**                                             |       | —                                    | ** ** | **21.2** |   | 3,323.3 |   |
| Total  expenditures                        | ** ** | **$**                                                  | **210.7**  |                                      | $          | 159.4 | ** ** | **$** | **1,140.2** |   | $ | 3,901.2 |   |

 

Wedrilled 43 net wells in the fourth quarter of 2007, resulting in 25 net oilwells, nine net natural gas wells and nine stratigraphic wells with a successrate of 99 percent. Our drilling activities were focused primarily in theCentral and Plains areas.

 

OnJune 30, 2006, we closed the acquisition of Petrofund. The fair value ofthe oil and natural gas properties acquired of $3.3 billion was added toproperty, plant and equipment and the remaining $0.7 billion of the purchaseprice was attributed to goodwill.

 

Theacquisition of C1 Energy Ltd (“C1”) for a total cost of approximately $21.2million closed during the third quarter of 2007 and was accounted for as apurchase. Also, during 2007, we completed a number of other minor propertyacquisitions.

 

Inaddition to the above noted capital expenditures, for the year ended December 31,2007, $5.1 million was capitalized for future income taxes on acquisitions toreflect the acquisitions with a different tax basis than the purchase pricesand $96.6 million was capitalized for additions to asset retirement obligationsto reflect the additional retirement obligations from both capital programs andnet acquisitions.

 

CO2 pilot costs represent capital expendituresrelated to the Pembina CO2 pilotproject, including the cost of injectants, for which no reserves have beenbooked.

** **

**Business Risks**

 

**MarketRisk Management**

 

Weare exposed to normal market risks inherent in the oil and natural gasbusiness, including commodity price risk, credit risk, interest rate risk, foreigncurrency and environmental risk. From time to time, we attempt to minimizeexposure to a portion of these risks by using financial instruments and byother means.

 

14

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**CommodityPrice Risk**

 

Commodityprice fluctuations are among the Trust’s most significant exposures. Crude oilprices are influenced by worldwide factors such as OPEC actions, supply anddemand fundamentals, and political events. Oil prices, North American naturalgas supply and demand factors including weather, storage levels and LNGimports, influence natural gas prices. In accordance with policies approved byour Board of Directors, we may, from time to time, manage these risks throughthe use of costless collars or other financial instruments up to a maximum of50 percent of forecast sales volumes, net of royalties, for a two-year periodor up to 75 percent of forecast sales volumes, net of royalties, for a one-yearperiod.

 

Fora current summary of outstanding oil and natural gas contracts, please refer to“Financial Instruments” later in this MD&A or our website atwww.pennwest.com which includes all current contracts including those assumedin the Canetic and Vault acquisitions which closed in January 2008.

 

**ForeignCurrency Rate Risk**

 

Pricesreceived for sales of crude oil are referenced to, or denominated in, U.S.dollars, and thus realized oil prices are impacted by Canadian to United Statesexchange rates. When we consider it appropriate, we may use financialinstruments to fix or collar future exchange rates.

 

InSeptember 2007, we entered into foreign exchange contracts to fix theforeign exchange rate on the future repayment of US$250 million ofU.S.-dollar-denominated private notes at an exchange rate of approximately oneCanadian dollar equalling one U.S. dollar. At December 31, 2007, we hadU.S.-dollar-denominated debt with a face value of US$225 million outstanding onwhich the repayment of principal amount in Canadian dollars is not fixed.

 

**CreditRisk**

 

Creditrisk is the risk of loss if purchasers or counterparties do not fulfill theircontractual obligations. All of our receivables are with customers in the oiland natural gas industry and are subject to normal industry credit risk. Inorder to limit the risk of non-performance of counterparties to derivativeinstruments, we contract only with organizations with high credit ratings or byobtaining security in certain circumstances.

 

**InterestRate Risk**

 

Wecurrently maintain a portion of our debt in floating-rate bank facilities,which results in exposure to fluctuations in short-term interest rates thathave for a number of years been lower than longer-term rates. From time totime, we may increase the certainty of our future interest rates by enteringfixed interest rate debt instruments or by using financial instruments to swapfloating interest rates for fixed rates or to collar interest rates.

 

InApril 2006, we entered into interest rate swaps for two years at 4.36percent on $100 million of bank debt and in November 2007 we entered intointerest rate swaps for three years at 4.26 percent on $100 million of bankdebt, both of which fixed the interest rates for the stated period of time. Weclosed the placement of notes totalling US$475 million on May 31, 2007that bear fixed interest rates at an average rate of 5.8 percent for an averageterm of 10.1 years.

 

15

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**Liquidity and Capital Resources**

 

**Capitalization**

 
| ** **                     | ** ** | **Year ended December 31** | ** ** |
|--------------------------------|------------|-------------------------------------------|------------|
| **(millions)**                 | ** ** | **2007**                                  | ** ** | **2006** | ** ** | **2005** | ** ** |
| Trust units issued, at market  | ** ** | **$**                                     | **6,270**  | ** ** | **74.0** |   | $ | 8,435 |   | 86.0 |   | $ | 6,203 |   | 90.5 |   |
| Bank loans and notes           | ** ** | **1,943**                                 | ** ** | **22.9** |   | 1,285 |   | 13.1 |   | 542 |   | 7.9 |   |
| Working capital deficiency (1) | ** ** | **266**                                   | ** ** | **3.1** |   | 86 |   | 0.9 |   | 127 |   | 1.6 |   |
| Total enterprise value         | ** ** | **$**                                     | **8,479**  | ** ** | **100.0** |   | $ | 9,806 |   | 100.0 |   | $ | 6,872 |   | 100.0 |   |

 

----

(1)  Current assets minus current liabilities.

 

During2007, we paid total distributions, including those funded by the distributionreinvestment plan, of $976.0 million, compared to distributions of $781.8million in 2006. This increase was due to the increase in the distribution ratefrom $0.31 per unit, per month in February 2006, to the rate since thattime of $0.34 per unit, per month, and the 70.7 million additional units issuedas consideration for Petrofund in June 2006.

 

Long-termdebt at December 31, 2007 was $1,943.2 million compared to $1,285.0million at December 31, 2006. In January 2008, our wholly ownedsubsidiary, Penn West Petroleum Ltd., amended its unsecured, revolvingsyndicated credit facility to an aggregate borrowing limit of $4.0 billionexpiring on January 11, 2011, to enable the cancellation of the credit facilities of Canetic and Vault. The facilityis made up of two revolving tranches; tranche one of the facility is $3.25billion and extendible, andtranche two is $750 million and non-extendible. Stamping fees range from 55 -110 basis points and standby fees range from 11.0 - 22.5 basis points dependingon our ratio of bank debt to income before interest, taxes and depreciation anddepletion (“EBITDA”). The syndicated facility expiry date on both tranches is January 11,2011.

 

OnMay 31, 2007, the Company closed an offering of notes issued on a privateplacement basis in the United States, with an aggregate principal amount ofUS$475 million. The Company used the proceeds of the notes to repay a portionof its outstanding bank debt under its credit facilities. The notes mature in 8to 15 years and bear interest at rates between 5.68 and 6.05 percent.

 

OnDecember 31, 2007, the Company was in compliance with all of the financialcovenants under its syndicated credit facility that closed on January 10,2008. The financial covenants under the syndicated credit facility, whichinclude the unaudited pro forma Canetic, Vault and Titan Exploration Ltd. (“Titan”)historical results, are as follows:

 

·    Consolidated senior debt to EBITDA shall beless than 3:1 except in certain circumstances and shall not exceed 3.5:1;

 

·    Consolidated total debt to EBITDA shall beless than 4:1; and

 

·             Consolidatedsenior debt to total trust capitalization shall not exceed 50 percent except incertain circumstances and shall notexceed 55 percent.

 

AtDecember 31, 2007, the pro forma consolidated senior and total debt toEBITDA ratios were 1.5:1 and 1.6:1 respectively, and the consolidated seniordebt to capitalization ratio was 29.5 percent.

 

OnDecember 31, 2007, the Company was in compliance with the financialcovenant pursuant to the notes, which is that consolidated total debt toconsolidated total capitalization is not to exceed 55 percent except in certaincircumstances where it is not to exceed 60 percent.

 

16

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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 current Trust Indenture require that theoutstanding units be consolidated immediately subsequent to the distribution.The number of outstanding trust units would remain at the number outstandingimmediately prior to the unit distribution, plus those sold to fund the paymentof withholding taxes, and an amount equal to the distribution would beallocated to the unitholders as a taxable distribution. Penn West has neverdeclared such a distribution and, at the current time, it forecasts that such aspecial distribution will not be required in 2008.

 

Dueto the extent of our environmental programs, we believe no benefit would arisefrom the initiation of a reclamation fund. We believe our program will besufficient to meet or exceed existing environmental regulations and bestindustry practices. In the event of significant changes to the environmentalregulations or the cost of environmental activities, a higher portion of funds flowwould be required to fund our environmental expenditures.

 

**Standardized Distributable Cash**

 

Priorto the recent guidance from accounting and regulatory standard setters on thedisclosure of distributable cash, Penn West’s disclosures regarding distributablecash to its investors focused on statistics including a reconciliation of cashflow from operating activities to distributions declared and distributionsdeclared as a percentage of cash flow from operating activities and net income.The Canadian Institute of Chartered Accountants (“CICA”) issued theInterpretive Release “Standardized Distributable Cash in Income Trusts andOther Flow-Through Entities” in July 2007, which provided furtherguidance. In the guidance, sustainability concepts are discussed andstandardized distributable cash is defined as cash flow from operatingactivities less adjustments for productive capacity maintenance, long-termunfunded contractual obligations and the effect of any foreseeable financingmatters, related to debt covenants, which could impair an entity’s ability topay distributions or maintain productive capacity.

 
| ** **                                                                                         | ** ** | **Three months ended December 31** | ** **  | **Year ended December 31** | ** ** |
|----------------------------------------------------------------------------------------------------|------------|--------------------------------------------------------|-------------|-------------------------------------------|------------|
| **(millions, except per unit amounts, ratios and percentages)** | ** ** | **2007**                                               | ** **  | **2006**                                  | ** ** | **2007** | ** ** | **2006** | ** ** |
| Cash flow from operating activities                                                                | ** ** | **$**                                                  | **311.7**   | ** **                                | $          | 261.1 | ** ** | **$** | **1,241.8** | ** ** | $ | 1,106.3 |   |
| Productive capacity maintenance (1)                                                                | ** ** | **(191.0**                                             | **)**       | (148.5                                    | )          | **(697.3** | **)** | (572.3 | ) |
| Standardized distributable cash                                                                    | ** ** | **120.7**                                              | ** **  | 112.6                                     | ** ** | **544.5** | ** ** | 534.0 |   |
| Proceeds from the issue of trust units (2)                                                         | ** ** | **50.2**                                               | ** **  | 31.3                                      | ** ** | **163.1** | ** ** | 118.6 |   |
| Debt and working capital changes                                                                   | ** ** | **76.1**                                               | ** **  | 97.6                                      | ** ** | **270.3** | ** ** | 159.2 |   |
| Cash distributions declared                                                                        | ** ** | **$**                                                  | **247.0**   | ** **                                | $          | 241.5 | ** ** | **$** | **977.9** | ** ** | $ | 811.8 |   |
| Accumulated cash distributions, beginning                                                          | ** ** | **1,864.2**                                            | ** **  | 891.8                                     | ** ** | **1,133.3** | ** ** | 321.5 |   |
| Accumulated cash distributions, ending                                                             | ** ** | **$**                                                  | **2,111.2** | ** **                                | $          | 1,133.3 | ** ** | **$** | **2,111.2** | ** ** | $ | 1,133.3 |   |
|                                                                                               | ** ** | ** **                                             | ** **  |                                      | ** ** | ** ** | ** ** |   |   |
| Standardized distributable cash per unit,  basic                                                   | ** ** | **$**                                                  | **0.50**    | ** **                                | $          | 0.48 | ** ** | **$** | **2.27** | ** ** | $ | 2.66 |   |
| Standardized distributable cash per unit,  diluted                                                 | ** ** | **$**                                                  | **0.50**    | ** **                                | $          | 0.47 | ** ** | **$** | **2.25** | ** ** | $ | 2.62 |   |
| Standardized distributable cash payout  ratio (3)                                                  | ** ** | **2.05**                                               | ** **  | 2.14                                      | ** ** | **1.80** | ** ** | 1.52 |   |
|                                                                                               | ** ** | ** **                                             | ** **  |                                      | ** ** | ** ** | ** ** |   |   |
| Distributions declared per unit                                                                    | ** ** | **$**                                                  | **1.02**    | ** **                                | $          | 1.02 | ** ** | **$** | **4.08** | ** ** | $ | 4.05 |   |
| Net income as a percentage of cash  distributions declared                                         | ** ** | **51**                                                 | **%**       | 51                                        | %          | **18** | **%** | 82 | % |
| Cash flow from operating activities as a  percentage of cash distributions declared                | ** ** | **126**                                                | **%**       | 108                                       | %          | **127** | **%** | 136 | % |

 

----

(1)        Please refer to our discussion of productive capacity maintenance below.

(2)        Consists of proceeds from the Distribution Reinvestment and Optional PurchasePlan, the Trust Unit Rights Incentive Plan and the Trust Unit Savings Plan.

(3)        Represents cash distributions declared divided by standardizeddistributable cash.

 

17

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Westrive to fund both distributions and maintenance capital programs primarilyfrom funds flow. We initially budget our capital programs at approximately40-50 percent of annual funds flow. We believe that proceeds from theDistribution Reinvestment and Optional Purchase Plan should be used to fundcapital expenditures of a longer-term nature. Over the medium term, additionalborrowings and equity issues may be required from time to time to fund aportion of our distributions or maintain or increase our productive capacity.On a longer-term basis, adjustments to the level of distributions and/orcapital expenditures to maintain or increase our productive capacity may berequired based on forecast levels of funds flow, capital efficiency and debtlevels.

 

Productivecapacity maintenance is the amount of capital funds required in a period for anenterprise to maintain its future cash flow from operating activities at aconstant level. As commodity prices can be volatile and short-term variationsin production levels are often experienced in our industry, we define ourproductive capacity as production on a barrel of oil equivalent basis. Aquantifiable measure for these short-term variations is not objectivelydeterminable or verifiable due to various factors including the inability todistinguish natural production declines from the effect of production additionsresulting from capital and optimization programs, and the effect of temporaryproduction interruptions. As a result, the adjustment for productive capacitymaintenance in our calculation of standardized distributable cash is ourcapital expenditures during the period excluding the cost of any assetacquisitions or proceeds of any asset dispositions. We believe that our currentcapital programs, based on 40-50 percent of forecast annual funds flow and ourcurrent view of our assets and opportunities, including particularly our oilsands project, and our proposed enhanced oil recovery projects, and our outlookfor commodity prices and industry conditions, should be sufficient to maintainour productive capacity in the medium-term. We set our hurdle rates forevaluating potential development and optimization projects according to theseparameters. Due to the risks inherent in the oil and natural gas industry,particularly our exploration and development activities and variations incommodity prices, there can be no assurance that capital programs, whetherlimited to the excess of funds flow over distributions or not, will besufficient to maintain or increase our production levels or cash flow fromoperating activities. Penn West historically incurred a larger proportion ofits development expenditures in the first quarter of each calendar year toexploit winter-only access properties. As we strive to maintain sufficientcredit facilities and appropriate levels of debt, this seasonality is notcurrently expected to influence our distribution policies.

 

Ourcalculation of standardized distributable cash has no adjustment for long-termunfunded contractual obligations. We believe our only significant long-termunfunded contractual obligation at this time is for asset retirementobligations. Cash flow from operating activities, used in our standardizeddistributable cash calculation, includes a deduction for abandonmentexpenditures incurred during each period. We believe that our currentenvironmental programs will be sufficient to fund our asset retirementobligations over the life of our reserves. Distribution policies are set by ourBoard of Directors based on funds flow. Distributions in excess of net incomemay include an economic return of capital to unitholders.

 

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 ratios)**                         | ** ** | **To December 31, 2007** | ** ** |
|-----------------------------------------------------------------|------------|-----------------------------------------|------------|
| Cumulative standardized distributable cash  from operations (1) |       | $                                       | 1,562.9    |   |
| Issue of trust units                                            |       | 290.0                                   |       |
| Bank borrowing and working capital change                       |       | 258.3                                   |       |
| Cumulative cash distributions declared (1)                      |       | $                                       | 2,111.2    |   |
|                                                            |       |                                    |       |
| Standardized distributable cash payout  ratio (2)               |       | 1.35                                    |       |

 

----

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

(2)   Represents cumulative cash distributionsdeclared divided by cumulative standardized distributable cash.

 

18

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**Financial Instruments**

 

During2007, Penn West had $201.6 million of unrealized losses on risk managementactivities compared to a $48.6 million gain in 2006. The losses in 2007 wereprimarily due to record oil prices experienced in the latter part of the year.

 

Asat December 31, 2007 we had WTI crude oil collars on approximately 30,000barrels per day for 2008 with an average floor price of US$66.17 per barrel andan average ceiling price of US$81.75 per barrel. In addition, Penn West hasAECO natural gas collars on approximately 67.5 mmcf per day for 2008 with anaverage floor price of $6.68 per mcf and an average ceiling price of $7.70 permcf.

 

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 offloating interest rate debt. Further to this, in the fourth quarter of 2007, weentered into additional interest swaps that fix the interest rate for threeyears at 4.26 percent on $100 million of floating interest rate debt.

 

Inthe third quarter of 2007, we entered into foreign exchange forward contractsto fix the principal repayment on debt amounts totalling US$250 million at anexchange rate of approximately par.

 

InJanuary 2008, we entered into 10-year U.S. Treasury forward contracts on anotional principal amount of $250 million at an average fixed treasury rate of3.6778 percent until June 30, 2008.

 

Otherfinancial instruments outstanding at December 31, 2007 were Albertaelectricity contracts, which fix 2008 electricity costs on 32 megawatts at$75.02 per megawatt-hour and in both 2009 and 2010 fix electricity costs on 30megawatts at $76.23 per megawatt-hour.

 

Markto market amounts on all financial instruments outstanding at December 31,2007 are summarized in note 11 to the audited consolidated financialstatements. Canetic and Vault had entered into a number of financialinstruments that were assumed upon closing of these deals. Please refer to PennWest’s website at www.pennwest.com for details of all financial instrumentscurrently outstanding.

 

**Outlook**

 

Thisoutlook section is included to provide unitholders with information as tomanagement’s expectations as at March 6, 2008 for production, revenues andnet capital expenditures for 2008 and readers are cautioned that theinformation may not be appropriate for any other purpose. This informationconstitutes forward-looking information. Readers should note the assumptions,risks and disclaimers under “Forward-Looking Statements”.

 

Theoutlook for oil prices remains strong, while the outlook for natural gas pricesremains relatively weak and the Canadian dollar remains strong compared to theU.S. dollar. Including the Canetic and Vault acquisitions, Penn West forecasts2008 production of between 195,000 boe per day and 205,000 boe per day. Basedon a forecast WTI oil price of US$80.00 per barrel, a $6.75 per GJ natural gasprice at AECO and a CAD/USD exchange rate of par for 2008, funds flow for 2008is forecast to be between $2.0 billion and $2.1 billion. Based on this level offunds flow and other factors, we estimate 2008 net capital expenditures ofapproximately $960 million.

 

19

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**Sensitivity Analysis**

 

Estimated sensitivities toselected key assumptions on 2008 financial results, including the impact of theCanetic and Vault acquisitions, and before considering hedging impacts, areoutlined in the table below.

 
| ** **                   | ** ** | ** **     | ** ** | **Impact on Funds Flow**** (1)** | ** ** | **Impact on Net Income ****(1)** | ** ** |
|------------------------------|------------|----------------|------------|------------------------------------------------------|------------|------------------------------------------------------|------------|
| **Change of**           | ** ** | **Change**     | ** ** | **$ millions**                                  | ** ** | **$/unit**                                           | ** ** | **$ millions** | ** ** | **$/unit** | ** ** |
| Price per barrel of liquids  |       | $              | 1.00       |                                                 | 30.3       |                                                 | 0.08       |   | 21.2 |   | 0.06 |   |
| Liquids production           |       | 1,000 bbls/day |       | 14.7                                                 |       | 0.04                                                 |       | 4.8 |   | 0.01 |   |
| Price per mcf of natural gas |       | $              | 0.10       |                                                 | 17.2       |                                                 | 0.05       |   | 12.0 |   | 0.03 |   |
| Natural gas production       |       | 10 mmcf/day    |       | 14.2                                                 |       | 0.04                                                 |       | 0.8 |   | — |   |
| Effective interest rate      |       | 1              | %          | 31.4                                                 |       | 0.08                                                 |       | 22.0 |   | 0.06 |   |
| Exchange rate ($US per $CAD) |       | $              | 0.01       |                                                 | 23.9       |                                                 | 0.06       |   | 16.8 |   | 0.04 |   |

 

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(1)  The impact on funds flow and net income is computed based on 2008forecast commodity prices and production volumes. The impact on net incomeassumes that the distribution levels are not adjusted for changes in funds flowthus changing the incremental future income tax rate.

 

**Contractual Obligations and Commitments**

 

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

 
| **(millions)**           | ** ** | **2008** | ** ** | **2009** | ** ** | **2010** | ** ** | **2011** | ** ** | **2012** | ** ** | **Thereafter** | ** ** |
|--------------------------|------------|----------|------------|----------|------------|----------|------------|----------|------------|----------|------------|----------------|------------|
| Long-term debt           |       | $        | —     |     | $          | —   |       | $        | 1,485.4    |     | $          | —         |       | $ | — |   | $ | 457.8 |   |
| Transportation           |       | 13.9     |       | 5.8      |       | 2.2      |       | 0.1      |       | —   |       | —         |       |
| Transportation ($US)     |       | 2.3      |       | 2.3      |       | 2.3      |       | 2.3      |       | 2.3      |       | 6.4            |       |
| Power infrastructure     |       | 6.2      |       | 4.2      |       | 4.2      |       | 4.2      |       | 4.2      |       | 7.6            |       |
| Drilling rigs            |       | 7.7      |       | 2.4      |       | 1.2      |       | —   |       | —   |       | —         |       |
| Purchase obligations (1) |       | 13.3     |       | 13.3     |       | 13.3     |       | 13.3     |       | 13.2     |       | 41.1           |       |
| Office lease             |       | $        | 19.4       |     | $          | 19.6     |       | $        | 17.3       |     | $          | 16.5           |       | $ | 16.2 |   | $ | 104.3 |   |

 

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(1)  These amounts represent estimated commitments of $84.4 million forCO2 purchases and $23.1 million for processingfees related to interests in the Weyburn Unit.

 

The$4.0 billion syndicated credit facility expires on January 11, 2011. If wewere not successful in renewing or replacing the facility, we could be requiredto repay all amounts then outstanding on the facility or enter term bank loans.As we strive to maintain our leverage ratios at relatively modest levels, webelieve we will be successful in renewing or replacing our credit facility onacceptable terms.

 

20

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**Equity Instruments**

 
| Trust units issued:                                |   |        |   |
|----------------------------------------------------|--------|-------------|--------|
| As at December 31, 2007                       |   | 242,663,164 |   |
| Issued on exercise of trust unit rights            |   | 330,370     |   |
| Issued to employee savings plan                    |   | 217,988     |   |
| Issued pursuant to distribution  reinvestment plan |   | 1,116,862   |   |
| Issued on Canetic acquisition                      |   | 124,348,739 |   |
| Issued on Vault acquisition                        |   | 5,550,923   |   |
| As at March 6, 2008                           |   | 374,228,046 |   |
|                                               |   |        |   |
| Trust unit rights outstanding:                     |   |        |   |
| As at December 31, 2007                       |   | 14,486,084  |   |
| Granted                                            |   | 11,296,752  |   |
| Exercised                                          |   | (330,370    | )      |
| Forfeited                                          |   | (162,244    | )      |
| As at March 6, 2008                           |   | 25,290,222  |   |

 

**Disclosure Controls and Procedures and Internal Controls overFinancial Reporting**

 

PennWest maintains disclosure controls and procedures designed to providereasonable assurance that information required to be disclosed by Penn West inits annual filings, interim filings (as these terms are defined in MultilateralInstrument 52-109 Certification of Disclosure in Issuers’ Annual and InterimFilings) and other reports filed or submitted by it under provincial andterritorial securities legislation is recorded, processed, summarized andreported within the required time periods. Our Chief Executive Officer andChief Financial Officer, after evaluating the effectiveness of our disclosurecontrols and procedures as of the end of the period covered by the annualfilings, being December 31, 2007, have concluded that, as of such date,our disclosure controls and procedures were effective to provide reasonableassurance that information required to be disclosed by Penn West in reportsthat it files or submits is (i) recorded, processed, summarized andreported within the time periods as required, and (ii) accumulated andmade known to management, including the Chief Executive Officer and ChiefFinancial Officer, to allow timely decisions regarding required disclosure.

 

Ourdisclosure controls and procedures are designed to provide reasonable assuranceof achieving their objectives and, as indicated in the preceding paragraph, theChief Executive Officer and Chief Financial Officer believe that our disclosurecontrols and procedures are effective at that reasonable assurance level,although the Chief Executive Officer and Chief Financial Officer do not expectthat the disclosure controls and procedures will prevent all errors and fraud.A control system, no matter how well conceived or operated, can provide only reasonable,not absolute, assurance that the objectives of the control system are met.

 

Managementis responsible for establishing and maintaining adequate internal controls overfinancial reporting, as defined in Rules 13a-15(f) and 15d-15(f) underthe Securities Exchange Act of 1934, as amended. Internal controls overfinancial reporting are designed to provide reasonable assurance regarding thereliability of financial reporting and preparation of financial statements forexternal purposes in accordance with generally accepted accounting principles.

 

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Underthe supervision and with the participation of our management, including ourChief Executive Officer and Chief Financial Officer, we conducted an evaluationof the design and effectiveness of our internal control over financialreporting as of the end of the fiscal year covered by this report based on theframework issued by the Committee of Sponsoring Organizations of the TreadwayCommission (“COSO”) in Internal Control — Integrated Framework. Based on thisevaluation, management concluded that as of December 31, 2007, Penn Westdid maintain effective internal control over financial reporting. There havebeen no changes in Penn West’s internal control over financial reporting duringboth 2007 and the most recent interim period that have materially affected, orare reasonably likely to materially affect, its internal control over financialreporting.

 

Management’sassessment of the effectiveness of internal control over financial reporting asof December 31, 2007 was audited by KPMG LLP, an independent registeredpublic accounting firm, as stated in their report.

 

**Accounting Changes and Pronouncements**

 

EffectiveJanuary 1, 2007, the Trust adopted new Canadian accounting standardsissued by the CICA, these being “Comprehensive Income”, “Financial Instruments –Disclosure and Presentation”, “Hedges”, “Financial Instruments – Recognitionand Measurement”, and “Equity”. The adoption of these standards has had no materialimpact on the Trust’s net income or funds flows.

 

FinancialInstruments

 

Financialinstruments are measured at fair value on the balance sheet upon initialrecognition of the instrument. Measurement in subsequent periods depends onwhether the financial instrument has been classified in one of the followingcategories: held-for-trading, available-for-sale, held-to-maturity, loans andreceivables, or other financial liabilities as defined under CICA Handbook Section 3855.

 

Subsequentmeasurement and changes in fair value will depend on initial classification, asfollows: held-for-trading financial assets are measured at fair value and changes in fair value arerecognized in net income; and available-for-sale financial instruments are measured at fair value withchanges in fair value recorded in Other Comprehensive Income (“OCI”) until theinstrument or a portion thereof is derecognized or impaired, at which time theamounts would be recorded in net income.

 

Asthe Trust elected to discontinue hedge accounting in 2005, the adoption ofthese standards did not change the Trust’s accounting for financialinstruments. Cash and cash equivalents are designated as held-for-trading andare measured at carrying value, which approximates fair value due to the short-termnature of these instruments. Accounts receivable and accrued revenues aredesignated as loans and receivables. Accounts payable and accrued liabilitiesand long-term debt are designated as other liabilities. Risk management assetsand liabilities are derivative financial instruments classified asheld-for-trading.

 

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EmbeddedDerivatives

 

Anembedded derivative is a component of a contract that affects the contractterms in relation to another factor, for example rent costs that fluctuate withoil prices. These “hybrid” contracts are considered to consist of a “host”contract plus an “embedded derivative”. The embedded derivative is separatedfrom the host contract and accounted for as a derivative if certain conditionsare met. These include:

 

·                  Theeconomic characteristics and risks of the embedded derivative are not closelyrelated to the economic characteristics and risks of the host contract;

 

·                  Ifthe embedded derivative separated meets the definition of a derivative; and

 

·                  Thehybrid contract is not measured at fair value or classified asheld-for-trading.

 

TheTrust currently has no material embedded derivatives.

 

ComprehensiveIncome

 

Comprehensiveincome is defined as the change in equity from transactions and other eventsfrom non-owner sources. It consists of net income and OCI. OCI refers to itemsrecognized in comprehensive income that are excluded from net income calculatedin accordance with GAAP. The Trust currently has no items requiring separatedisclosure as OCI on a Statement of Comprehensive Income.

 

FutureAccounting Pronouncements

 

Threenew Canadian accounting standards have been issued: “Financial Instruments –Disclosure”, “Capital Disclosure” and “Goodwill and Intangible Assets”. Thesewill require additional disclosure in the Trust’s financial statementscommencing January 1, 2008 related to the Trust’s financial instruments aswell as the management of capital. The goodwill and intangible assets sectionis effective January 1, 2009.

 

Related-Party Transactions

 

During2007, Penn West paid $1.3 million (2006 – $4.1 million) of legal fees to a lawfirm of which a partner is also a director of Penn West.

 

Off-Balance-Sheet Financing

 

Wehave off-balance-sheet financing arrangements consisting of operating leases.The operating lease payments are summarized in the Contractual Obligations andCommitments section.

 

Critical Accounting 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

 

Weuse the full cost method of accounting for oil and natural gas properties. Allcosts of exploring for and developing oil and natural gas reserves arecapitalized and depleted against associated oil and natural gas productionusing the unit-of-production method based on the estimated proved reserves withforecast commodity pricing.

 

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Ourreserves were evaluated by GLJ Petroleum Consultants Ltd., an independentengineering firm. In 2007 and 2006, our reserves were determined in compliancewith National Instrument 51-101. The evaluation of oil and natural gas reservesis, by its nature, based on complex extrapolations and models as well as othersignificant engineering, capital, pricing and cost assumptions. Reserveestimates are a key component in the calculation of depletion and are a keycomponent of value in the ceiling test. To the extent that the ceiling amount,based in part on our reserves, is less than the carrying amount of property,plant and equipment, a write-down against income must be made. We determinedthere was no ceiling test write-down required at December 31, 2007.

 

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. Amountscapitalized to the related assets are amortized to income consistent with thedepletion or depreciation of the underlying asset. Note 6 to the auditedconsolidated financial statements details the impact of these accountingrecommendations.

 

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 instrumentsapproximate their carrying amounts due to the short-term maturity of theinstruments, the mark to market values recorded for the financial instrumentsand the market rate 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 tofluctuating oil and natural gas prices, electricity costs, exchange rates andinterest rates. The use of these financial instruments exposes us to creditrisks associated 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 thatfunds flows are sufficient to fund planned capital programs and distributions,costless collars or other financial instruments may be utilized. Collars ensurethat commodity prices realized will fall into a contracted range for acontracted sales volume. Forward power contracts fix a portion of futureelectricity costs at 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 and liabilities of the acquired entity. Thegoodwill balance is not amortized; however, it must be assessed for impairment at least annually.Impairment is initially determined based on the fair value of the reportingentity compared to its book value. Any impairment must be charged to income orloss in the period the impairment occurs. We determined there was no goodwillimpairment as at December 31, 2007.

 

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**Forward-LookingStatements**

 

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 documentconstitute forward-looking statements or information (collectively “forward-lookingstatements”) within the meaning of the “safe harbour” provisions of applicablesecurities legislation. Forward-looking statements are typically identified bywords such as “anticipate”, “continue”, “estimate”, “expect”, “forecast”, “may”,“will”, “project”, “could”, “plan”, “intend”, “should”, “believe”, “outlook”, “potential”,“target” and similar words suggesting future events or future performance. Inaddition, 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 impact on our business, distributionpolicies and unitholdersof the SIFT tax and the different actions that we might take in response to theSIFT tax; the impact on our reserves and business of the new Alberta royaltyframework drilling plans; sufficiency of insurance related to Wildboy costs andlosses; tie-in of wells; environmental regulation compliance costs andstrategy; production estimates; netback estimates; our business strategy,including our strategy in respect of our Peace River Oil Sands project, and ourcoal bed methane, shale gas and enhanced oil recovery projects; productbalance; the sufficiency of our environmental program; funding sources fordistributions, distribution levels and whether a special distribution will bemade in 2007; the funding of our asset retirement obligations; our beliefs andoutlook for the maintenance of productive capacity; our outlook for oil andnatural gas prices; our forecast 2008 net capital expenditures and theallocation and funding thereof; the section on “Outlook” which sets forth management’s expectations as toproduction, revenues and net capital expenditures for 2008; the sensitivity of our assumptionsregarding 2008 funds flow and net income to changes in certain operational andfinancial metrics; currency exchange rates; our forecast funds flow; the natureand effectiveness of our risk management strategies; our belief that we will besuccessful in renewing or replacing our credit facilities on acceptable termswhen they expire; the quantity and recoverability of our oil and natural gasreserves and resources, including the quantity of discovered heavy oilresources in place at the Peace River Oil Sands Project; and the ability ofPenn West to economically developits contingent resources at its Peace River Oil Sands Project and convert theseresources into reserves.

 

Withrespect to forward-looking statements contained in this document, we have madeassumptions regarding, among other things: future oil and natural gas prices and differentialsbetween light, medium and heavy oil prices; future capital expenditure levels;future oil and natural gas production levels; future exchange rates; the amountof future cash distributions that we intend to pay; the cost of expanding ourproperty holdings; our ability to obtain equipment in a timely manner to carryout development activities; the ability of insurance to offset the financialimpact of the fire-related outage at the Wildboy natural gas plant; our abilityto market our oil and natural gas successfully to current and new customers; theimpact of increasing competition; our ability to obtain financing on acceptableterms; and our ability to addproduction and reserves through our development and exploitation activities. Inaddition, the “Outlook” section is based on specific assumptions as tocommodity prices and exchange rates, planned capital expenditures and oursuccess in maintaining production and adding new production through ourexploitation activities.

 

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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 assurancethat such expectations will prove to be correct. Readers are cautioned not toplace undue reliance on forward-looking statements included in this document,as there can be no assurance that the plans, intentions or expectations uponwhich the 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: volatility in market prices for oil andnatural gas; the impact of weather conditions on seasonal demand and ability toexecute capital programs; risks inherent in oil and natural gas operations;uncertainties associated with estimating reserves and resources; competitionfor, among other things, capital, acquisitions of reserves, resources,undeveloped lands and skilled personnel; incorrect assessments of the value ofacquisitions; geological, technical, drilling and processing problems; generaleconomic conditions in Canada, the U.S. and globally; industry conditions,including fluctuations in the price of oil and natural gas; royalties payablein respect of our oil and natural gas production; changes in governmentregulation of the oil and natural gas industry, including environmentalregulation; 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 the acquisition of Petrofund Energy Trust, theacquisition of C1 Energy Ltd. and Vault Energy Trust and the acquisition of Canetic Resources Trust; changes in tax law;changes in the Alberta royalty framework; uncertainty of obtaining requiredapprovals for acquisitions and mergers; and the other factors described under “BusinessRisks” in this document and in PennWest’s public filings (including our Annual Information Form) available inCanada at www.sedar.com and in the United States at www.sec.gov. Readers arecautioned that this list of risk factors should not be 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.

 

**Additional Information**

 

Additionalinformation relating to Penn West including Penn West’s Annual Information Form isavailable on SEDAR at www.sedar.com.

 

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