Exhibit 99.30

NEWS RELEASE

PENN WEST ENERGY TRUST ANNOUNCES RECORD 2005 FOURTH QUARTER AND YEAR END RESULTS

FOR IMMEDIATE RELEASE, Monday, February 27, 2006

PENN WEST ENERGY TRUST (TSX – PWT.UN) is pleased to announce record results for the fourth quarter and year ended December 31, 2005.

Financial Results

•The Trust generated record cash flow(1) of $1.2 billion ($7.28 per unit, basic) in 2005, up 37 percent from $867 million ($5.37 per unit, basic) in 2004. Cash flow of $333 million ($2.03 per unit, basic) in the fourth quarter of 2005 was consistent with the third quarter of 2005 cash flow of $335 million ($2.06 per unit, basic), and 40 percent higher than the cash flow of $238 million ($1.47 per unit, basic) realized in the fourth quarter of 2004. These cash flow increases were due to higher crude oil and natural gas prices.

•Net income increased 15 percent to $241 million ($1.48 per unit, basic) in the fourth quarter of 2005 compared to $210 million ($1.29 per unit, basic) in the third quarter of 2005 mainly due to a future income tax recovery in the fourth quarter compared to a charge in Q3 partially offset by mark-to-market losses of $24 million on risk management activities in the fourth quarter compared to $20 million of gains in the previous quarter.

•Record net income for the year ended December 31, 2005 of $577 million ($3.55 per unit, basic) was 112 percent higher than the $272 million ($1.68 per unit, basic) in 2004. Net income in the fourth quarter of 2005 was 251 percent higher than the $69 million ($0.42 per unit, basic) for the same period of 2004. The increases in both periods were mainly due to higher commodity prices, and reduced future income tax provisions due to income allocations to the Trust subsequent to the conversion and a lower future tax rate.

Operations

•During the fourth quarter of 2005, Penn West focused its activities on development drilling in the Central and Plains areas. A total of 51 net wells were drilled at a 92 percent rate of success.

•Production averaged 98,200 boe per day in the fourth quarter of 2005 representing a two percent decrease from the third quarter of 2005 due to the sale of properties for $94 million that produced approximately 1,500 boe per day of production in total.

•Crude oil and liquids production averaged 52,000 barrels per day for the quarter and was consistent with the third quarter of 2005.

•Natural gas production averaged 278 mmcf per day for the quarter. This represents a four percent decrease from the third quarter of 2005.

•During 2005, the Trust farmed out almost 600,000 net acres of undeveloped land and had 103 wells drilled on farmout lands. The majority of the transactions were completed in exchange for non-convertible gross overriding royalties with no deductions.

Distributions

•Our first monthly cash distribution of $0.26 per trust unit was paid in July 2005 to unitholders of record on June 30, 2005. In October 2005, the Trust announced a 19 percent distribution increase to $0.31 per unit. On February 2, 2006, the Trust announced a further 10 percent distribution increase to $0.34 per unit payable on March 15, 2006 to unitholders of record on February 28, 2006. This represents a 31 percent increase in distributions over the eight-month period since converting to a trust.

•The Trust initially planned to distribute approximately 60 percent of its cash flow with the remaining 40 percent reinvested in exploitation and development. Distributions in 2005 represented approximately 43 percent of cash flow and 66 percent of net income since becoming a trust. The balance of 2005 cash flow, after capital expenditures, was used to reduce bank debt. After the payment of income taxes and stock options required to effect the trust conversion, debt plus working capital deficiency was $25 million lower than at the end of 2004.

(1)Cash flow is a non-generally accepted accounting principles (“GAAP”) measure and consists of cash flow from operating activities before changes in non-cash working capital, cash option payments and environmental expenditures plus realized foreign exchange gains.

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1.FINANCIAL HIGHLIGHTS  ($ millions, except per unit and production amounts)

	Q4		Q3		Q4		Year ended December 31
	2005		2005		2004		2005		2004
Gross revenues	$	554.5	$	535.0	$	400.5	$	1,919.0	$	1,521.3
Cash flow	$	332.6	$	334.9	$	237.8	$	1,184.6	$	866.7
Per unit (1)	2.03		2.06		1.47		7.28		5.37
Diluted per unit (1)	2.03		2.04		1.44		7.14		5.28
Net income	$	241.1	$	209.5	$	68.6	$	577.2	$	271.8
Per unit (1)	1.48		1.29		0.42		3.55		1.68
Diluted per unit (1)	1.46		1.27		0.42		3.48		1.65
Capital expenditures, net	$	6.3	$	149.3	$	229.0	$	456.7	$	865.6
Daily production (boe/d) (2)	98,205		99,802		105,007		99,807		105,788
Distributions paid	$	143.6	$	127.3	$	—	$	270.9	$	—
Dividends paid	$	—	$	—	$	6.7	$	17.5	$	107.6

(1)The 2004 comparative figures have been restated to reflect the conversion ratio of three trust units issued for each Penn West common share pursuant to the plan of arrangement.

(2)Barrels of oil equivalent (boe) are based on six mcf of natural gas equals one barrel of oil (6:1). This could be misleading if used in isolation as it is based on energy equivalency at the burner tip and might not represent a value equivalency at the wellhead.

2.ADJUSTED INCOME FROM OPERATIONS

The following table provides a reconciliation of the after-tax effects of certain items of a non-operational nature that are included in the reported financial results.

		Three months ended December 31						Year ended December 31
($ millions, except per unit amounts)		2005			2004			2005			2004
Net income as reported		$	241.1		$	68.6		$	577.2		$	271.8
Unrealized foreign exchange (gain) loss (1)		—			(14.1		)	3.8			(9.8		)
Risk management activities (1)		15.3			—			2.2			—
Effect of statutory tax rate changes on  future income tax liabilities (2)		(28.3		)	—			(31.1		)	(20.3		)
Stock-based compensation expense (3)		—			14.5			46.7			54.6
Unit-based compensation expense (4)		3.4			—			5.5			—
Adjusted income from operations (5)		$	231.5		$	69.0		$	604.3		$	296.3
Per unit	- basic	$	1.43		$	0.43		$	3.72		$	1.84
	- diluted	$	1.41		$	0.42		$	3.64		$	1.80

(1)Mark-to-market gains and losses on commodity prices and power costs since July 1, 2005 and translation of US denominated debt.

(2)In the fourth quarter of 2005, a $28 million general rate reduction was recorded to reflect the revised future tax rate. In the third quarter of 2005, the British Columbia government substantively enacted a 1.5 percent general tax rate reduction. During the first quarter of 2004, the Alberta Government substantively enacted rate reductions applicable to the resource industry. The impact of such changes on future income tax assets and liabilities is included in net income during the period that the legislation is substantively enacted.

(3)The Penn West stock option plan provided employees and directors the choice of a cash payment in return for surrendering vested options. The plan was cancelled upon conversion to Penn West Energy Trust on May 31, 2005 with amounts paid in excess of the previously recorded liability expensed as stock-based compensation in the period.

(4)The Trust provides for unit-based compensation utilizing the fair market value method.

(5)Adjusted income from operations is a non-GAAP measure that the Trust utilizes to evaluate its financial performance.

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3.UNDEVELOPED LAND

	As at December 31
	2005		2004		% Change
Gross acres (000s)	4,390		6,058		(28	)
Net acres (000s)	4,142		5,767		(28	)
Average working interest	94	%	95	%	(1	)

4.DRILLING PROGRAM

	Three months ended December 31						Year ended December 31
	2005			2004			2005			2004
	Gross	Net		Gross	Net		Gross	Net		Gross	Net
Natural gas	13	13		29	27		150	148		209	197
Oil	37	34		40	38		119	110		195	188
Dry	4	4		5	5		18	18		35	32
Total wells	54	51		74	70		287	276		439	417
Success Rate		92	%		93	%		93	%		92	%

5.FARMOUT ACTIVITY

	Year ended December 31
	2005	2004
Wells drilled on farmout lands*	103	34

* Wells drilled on Penn West lands, including recompletions and re-entries, by independent operators pursuant to farmout agreements.

6.ACTIVITIES BY CORE AREA

Core Area	Undeveloped land as at December 31, 2005 (thousands of net acres)	Net wells drilled for the year ended December 31, 2005
Northern	1,814	27
Peace River Arch	74	17
Central	848	50
Plains	994	172
Southern Saskatchewan/Other	412	10
	4,142	276

7.TRUST UNIT DATA (millions of units)

	2005	2004	% Change
Weighted average:
(Year ended December 31)
Basic	162.6	161.4	1
Diluted	165.9	164.4	1
Outstanding: (as at December 31)
Basic	163.3	161.6	1
Basic plus trust unit rights	172.7	172.8	—

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8.RESERVE ESTIMATES

a)Reserve category splits under forecast prices and costs

	Light & Medium Oil	Heavy Oil	Natural Gas	Natural Gas Liquids
Reserve Estimates Category (1)	(MMbbl)	(MMbbl)	(Bcf)	(MMbbl)
Proved
Developed producing	105	46	486	12
Developed non-producing	3	2	35	1
Undeveloped	21	5	44	1
Total proved	129	53	565	14
Probable	28	14	133	3
Total proved plus probable	157	67	698	17

(1)Working interest reserves before royalty burdens and excluding royalty interests.

GLJ Petroleum Consultants Ltd. evaluated Penn West’s reserves for all properties. The reserve estimates have been calculated in compliance with the National Instrument 51-101 Standards of Disclosure (“NI 51-101”). Under NI 51-101, proved reserve estimates are defined as having a high degree of certainty with a targeted 90 percent probability that actual reserves recovered over time will equal or exceed proved reserve estimates. For proved plus probable reserves under NI 51-101, the targeted probability is an equal (50 percent) likelihood that the actual reserves to be recovered will be less than or greater than the proved plus probable reserves estimate.

Proved undeveloped reserves are mainly associated with planned infill drilling in existing pools. No reserves have been booked for coalbed methane or for CO₂ miscible flooding in the Pembina area.

Additional reserve disclosure tables, as required under NI 51-101, will be contained in the Trust’s Annual Information Form that will be filed on SEDAR at www.sedar.com.

b)Reconciliation of Gross Interest Reserves (Working Interest before Royalty Burdens) using forecast prices and costs

	Oil and Liquids						Natural Gas						Barrels of Oil Equivalent
	Proved		Probable		Proved Plus Probable		Proved		Probable		Proved Plus Probable		Proved		Probable		Proved Plus Probable
Reconciliation Items (1)	(MMbbl)		(MMbbl)		(MMbbl)		(Bcf)		(Bcf)		(Bcf)		(MMboe)		(MMboe)		(MMboe)
December 31, 2004	202.3		37.4		239.7		637.0		123.7		760.7		308.5		57.9		366.4
Extensions	3.8		1.1		4.8		31.4		11.2		42.6		9.0		2.9		11.9
Improved recovery	4.3		1.6		5.9		7.5		0.3		7.9		5.5		1.7		7.2
Technical and economic factors	1.0		2.3		3.3		(11.4	)	(4.4	)	(15.8	)	(0.9	)	1.6		0.7
Discoveries	0.1		—		0.1		10.9		3.1		14.0		1.9		0.6		2.4
Acquisitions	4.0		2.1		6.1		6.3		2.0		8.3		5.0		2.4		7.5
Dispositions	(0.4	)	(0.1	)	(0.4	)	(13.4	)	(2.7	)	(16.1	)	(2.6	)	(0.5	)	(3.1	)
Production	(18.7	)	—		(18.7	)	(103.3	)	—		(103.3	)	(35.9	)	—		(35.9	)
December 31, 2005	196.3		44.4		240.7		565.1		133.2		698.4		290.5		66.7		357.1

(1)Columns may not add due to rounding. Gross interest reserves exclude royalty interests.

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Reconciliation of Net Interest Reserves (Working Interest after Royalty Burdens and including Royalty Interests) using forecast prices and costs

	Oil and Liquids					Natural Gas						Barrels of Oil Equivalent
	Proved		Probable	Proved Plus Probable		Proved		Probable		Proved Plus Probable		Proved		Probable		Proved Plus Probable
Reconciliation Items (1)	(MMbbl)		(MMbbl)	(MMbbl)		(Bcf)		(Bcf)		(Bcf)		(MMboe)		(MMboe)		(MMboe)
December 31, 2004	182.1		32.8	214.9		520.2		101.1		621.3		268.8		49.7		318.5
Extensions	3.3		0.9	4.2		24.7		9.1		33.8		7.4		2.5		9.9
Improved recovery	4.0		1.6	5.6		5.8		0.3		6.2		4.9		1.7		6.6
Technical and economic factors	0.5		2.2	2.7		(11.9	)	(2.7	)	(14.6	)	(1.5	)	1.8		0.3
Discoveries	—		—	—		9.3		2.5		11.9		1.6		0.4		2.0
Acquisitions	3.5		1.8	5.4		5.0		1.5		6.5		4.4		2.1		6.5
Dispositions	(0.3	)	—	(0.4	)	(10.2	)	(2.1	)	(12.3	)	(2.0	)	(0.4	)	(2.4	)
Production	(16.0	)	—	(16.0	)	(80.1	)	—		(80.1	)	(29.4	)	—		(29.4	)
December 31, 2005	177.1		39.4	216.5		462.8		109.8		572.6		254.2		57.7		312.0

(1)Columns may not add due to rounding.

Proved plus probable reserves of 357 mmboe at the end of 2005, were three

percent lower than proved plus probable reserves of 366 mmboe at the end of 2004. Total Trust interest proved plus probable reserves, which include royalty interests, was 360 mmboe as at December 31, 2005 (2004 – 370 mmboe).

c)Net present value of future net revenue under forecast prices and costs ($ millions)

	Net Present Value of Future Net Revenue Before Income Taxes (Discounted)
Reserve Category	5%		10%		15%
Proved
Developed producing	$	4,614	$	3,702	$	3,164
Developed non-producing	205		161		133
Undeveloped	454		276		180
Total proved	$	5,273	$	4,139	$	3,477
Probable	994		645		473
Total proved plus probable	$	6,267	$	4,784	$	3,950

Net present values are net of producing wellbore abandonment liabilities and are based on the price assumptions that are contained in the following table. The estimated future net revenues do not represent fair market value.

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d)Summary of pricing and inflation rate assumptions as of December 31, 2005 under forecast prices and costs

	Oil
	WTI Cushing Oklahoma		Edmonton Par Price 40o API		Hardisty Heavy 12o API		Cromer Medium 29o API		Natural Gas AECO Gas Price		Edmonton Propane		Inflation Rates	Exchange Rate
Year	($ US/bbl)		($ CAD/bbl)		($ CAD/bbl)		($ CAD/bbl)		($ CAD/mcf)		($ CAD/bbl)		(%)	(CAD/USD)
Historical
2001	25.97		39.40		16.94		31.56		6.21		31.85		2.6	0.646
2002	26.08		40.33		26.57		35.48		4.04		21.39		2.2	0.637
2003	31.07		43.66		26.26		37.55		6.66		32.14		2.8	0.721
2004	41.38		52.96		29.11		45.75		6.88		34.70		1.8	0.768
2005	56.60		69.11		34.14		57.07		8.58		42.55		2.2	0.825
Forecast
2006	57.00		66.25		33.25		55.75		10.60		42.50		2.0	0.850
2007	55.00		64.00		32.75		55.25		9.25		41.00		2.0	0.850
2008	51.00		59.25		32.50		51.25		8.00		38.00		2.0	0.850
2009	48.00		55.75		32.00		48.25		7.50		35.75		2.0	0.850
2010	46.50		54.00		32.00		46.75		7.20		34.50		2.0	0.850
2011	45.00		52.25		33.50		45.25		6.90		33.50		2.0	0.850
2012	45.00		52.25		33.50		45.25		6.90		33.50		2.0	0.850
2013	46.00		53.25		34.00		46.00		7.05		34.00		2.0	0.850
2014	46.75		54.25		34.75		47.00		7.20		34.75		2.0	0.850
2015	47.75		55.50		35.25		48.00		7.40		35.50		2.0	0.850
2016	48.75		56.50		36.00		48.75		7.55		36.25		2.0	0.850
Thereafter	2	%	2	%	2	%	2	%	2	%	2	%	2.0	0.850

e)Future development costs under forecast prices and costs ($ millions)

Year	Proved Future Development Costs
2006	$	140
2007	59
2008	57
2009	38
2010	29
2011 and subsequent	90
Undiscounted total	$	413
Discounted @ 10%/yr	$	307

CHARTING OUR PERFORMANCE

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LETTER TO OUR UNITHOLDERS

Penn West Energy Trust entered its first full fiscal year of operations in 2006 as Canada’s largest producing energy trust. We intend to build on our progress over the second half of 2005 as we establish operating and financial benchmarks that will measure our success relative to our peers.

Looking back over the past six months, and particularly the past quarter, we are encouraged by improvements shown in capital efficiency and finding costs. We have reduced total debt from $890.4 million, on conversion, to $668.5 million by year-end 2005. Most notably, we have increased monthly distributions to our unitholders from the initial $0.26 per unit up to $0.34 per unit effective with our distribution to be paid on March 15, 2006.

In the fourth quarter of 2005, cash flow from operations was $332.6 million ($2.03 per unit basic) resulting in net income of $241.1 million ($1.48 per unit basic). Production for the quarter averaged 98,205 barrels of oil equivalent per day including 51,953 barrels per day of crude oil and natural gas liquids and 277.5 million cubic feet per day of natural gas. As a result of increasing our weighting to oil, from 51.7 percent in the third quarter of 2005 to 52.9 percent in the fourth quarter, our operating costs per barrel of oil equivalent increased from $9.11 in the third quarter to $9.44 in the fourth quarter of 2005. Royalties on a per barrel of oil equivalent basis increased from $10.36 to $12.52. These factors partially offset strong product prices. Our operating netback per barrel of oil equivalent of $39.42 in the fourth quarter compares to $38.80 received in the third quarter of 2005.

At year-end 2005, Penn West Energy Trust’s reserves of crude oil, natural gas and natural gas liquids, as calculated by GLJ Petroleum Consultants, totaled 359.7 million barrels of oil equivalent (proven plus probable) of which 292.5 million barrels of oil equivalent (81 percent) was proven. Our finding, development and acquisition cost per barrel of oil equivalent in 2005 was $17.17 on a proven plus probable basis. In terms of capital efficiency, we estimate that our capital efficiency as a trust over the last seven months of 2005 was approximately $25,000 per barrel of oil equivalent per day of production added. During 2005, we continued to monetize our inventory of undeveloped lands, increasing our level of farmouts to almost 600,000 net acres. Successful wells drilled on these lands will provide a stream of future cash flow to the trust reducing the amount of capital required to replace our production volumes.

As we move into 2006 and towards the future, we do so with a sense of optimism based on our recent performance and on our future plans. In the years to come, we will use a mix of conventional oil and gas, enhanced recovery and oil sands projects to secure our production and cash flow. Our conventional oil and gas opportunities include field development through infill and horizontal drilling, improving recovery through conventional pressure maintenance schemes and production enhancement by optimizing, recompleting and stimulating our inventory of wells.

We have identified enhanced recovery projects at Pembina, Swan Hills and other smaller oil pools that have the potential to replace our existing reserves base over the next 10 to 15 years. The projects will involve injecting greenhouse gas (CO₂) into mature reservoirs to markedly improve recovery and to extend productive life. Work on our Pembina Pilot CO₂ Project, that includes two separate patterns, has been ongoing for one year and we are very encouraged by results obtained to date. We are working with our supplier of CO₂ on the planning of a large scale commercial project that will see CO₂ captured and transported to Pembina. The initial phase of the commercial project is expected to add significant production by 2010. Additional phases are anticipated for the 2010 to 2020 period.

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Our Peace River Oil Sands project at Seal has the potential to redefine our business by 2020. The bitumen at Seal is unique in that it can be developed and produced using conventional drilling and production technology. This dramatically reduces the time from discovery to the initial on-production date and, importantly, provides for low operating costs. The bitumen deposit at Peace River is very large, with an average depth of burial of 2,000 feet. Penn West Energy Trust’s oil sands leases in the area encompass approximately 200,000 net acres. We have started the first stage pilot work at Seal, and plan to increase production from current levels of 900 barrels of oil per day to 4,000 to 5,000 barrels of oil per day by year end 2006. We will continue to increase the base of primary cold bitumen production through to 2012. Following the primary recovery phases, we expect to increase production several fold through enhanced thermal recovery techniques.

Looking to the short term, we expect to spend $400-$500 million in 2006 on a wide variety of projects. We are targeting average daily production for 2006 of between 94,000 and 98,000 barrels of oil equivalent that should yield cash flow of $1.0 billion to $1.1 billion. We base our projections on product prices of WTI $US 58.00 per barrel of oil and AECO $CAD 8.75 per thousand cubic feet of gas.

On behalf of the Board of Directors,

William E. Andrew

President and CEO

Calgary, Alberta

February 27, 2006

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MANAGEMENT’S DISCUSSION AND ANALYSIS

Management’s discussion and analysis (“MD&A”) of financial conditions and results of operations should be read in conjunction with the unaudited interim consolidated financial statements of Penn West Energy Trust (the “Trust”) for the three months ended December 31, 2005 and the audited consolidated financial statements and MD&A of Penn West Petroleum Ltd. (“Penn West”) for the year ended December 31, 2004. Penn West converted to an income trust on May 31, 2005, and to facilitate meaningful comparisons, the financial results of the Trust are presented on a continuity of interest basis as if it historically carried on the business of Penn West. The date of this MD&A is February 27, 2006. For additional information, including the Trust’s audited financial statements and Annual Information Form (when filed), go to the Trust’s website at www.pennwest.com or SEDAR at www.sedar.com.

References to cash flow, cash flow per unit-basic, cash flow per unit-diluted, and netbacks included in this MD&A are considered non-GAAP measures and may not be comparable to similar measures provided by other issuers. Management utilizes cash flow and netbacks to assess financial performance and the capacity of the Trust to fund distributions to unitholders and future capital projects. The reconciliation of cash flow to cash flow from operating activities is as follows:

Calculation of Cash Flow ($ millions, except per unit amounts)

	Three months ended December 31					Year ended December 31
	2005			2004		2005		2004
Cash flow from operating activities	$	368.7		$	206.2	$	932.8	$	816.8
(Decrease) increase in non-cash working capital	(42.4		)	10.0		1.8		(23.7		)
Payments for surrendered options	—			5.2		141.6		15.6
Environmental expenditures	6.3			16.4		22.6		29.5
Realized foreign exchange gains	—			—		85.8		28.5
Cash flow	$	332.6		$	237.8	$	1,184.6	$	866.7
Basic, per unit	$	2.03		$	1.47	$	7.28	$	5.37
Diluted, per unit	$	2.03		$	1.44	$	7.14	$	5.28

Notes to Reader

This document contains forward-looking statements (forecasts) under applicable securities laws. Forward-looking statements are necessarily based upon assumptions and judgements with respect to the future including, but not limited to, the outlook for commodity prices and capital markets, the performance of producing wells and reservoirs, and the regulatory and legal environment. For a discussion of other factors, please refer to “Notice Regarding Forward-Looking Statements” later in this MD&A. Many of these factors can be difficult to predict. As a result, the forward-looking statements are subject to known or unknown risks and uncertainties that could cause actual results to differ materially from those anticipated or implied in the forward-looking statements. The Trust assumes no responsibility to publicly update or revise any forward-looking statements.

All dollar amounts contained in this document are expressed in millions of Canadian dollars unless noted otherwise.

The calculations of barrels of oil equivalent (“boe”) are based on a conversion ratio of six thousand cubic feet of natural gas to one barrel of crude oil. This could be misleading if used in isolation as it is based on energy equivalency at the burner tip and might not represent a value equivalency at the wellhead.

9

Quarterly Financial Summary ($ millions, except per unit and production amounts, unaudited)

	2005								2004
Three months ended	Dec 31		Sept 30		Jun 30		Mar 31		Dec 31		Sept 30		Jun 30		Mar 31
Gross revenues	$	554.5	$	535.0	$	424.2	$	405.3	$	400.5	$	384.3	$	390.4	$	346.1
Cash flow	$	332.6	$	334.9	$	257.0	$	260.1	$	237.8	$	236.5	$	211.2	$	181.2
Basic per unit (1)	2.03		2.06		1.58		1.61		1.47		1.46		1.31		1.13
Diluted per unit (1)	2.03		2.04		1.49		1.58		1.44		1.44		1.29		1.11
Net income	$	241.1	$	209.5	$	59.7	$	66.9	$	68.6	$	76.7	$	65.5	$	61.0
Basic per unit (1)	1.48		1.29		0.37		0.41		0.42		0.48		0.41		0.38
Diluted per unit (1)	1.46		1.27		0.34		0.41		0.42		0.47		0.40		0.37
Distributions declared	$	151.8	$	127.3	$	42.4	$	—	$	—	$	—	$	—	$	—
Distributions per unit(1)	0.93		0.78		0.26		—		—		—		—		—
Dividends declared	$	—	$	—	$	—	$	10.8	$	6.7	$	6.7	$	6.7	$	6.7
Dividends per unit(1)	—		—		—		0.07		0.04		0.04		0.04		0.04
Production
Liquids (bbls/d)	51,953		51,634		50,633		53,162		53,781		52,966		54,316		51,245
Natural gas (mmcf/d)	277.5		289.0		295.7		289.1		307.4		316.0		329.8		312.0
Total (boe/d)	98,205		99,802		99,910		101,343		105,007		105,639		109,280		103,237

(1)Per unit figures for the periods prior to June 30, 2005 have been restated to reflect the conversion of Penn West common shares to trust units using an exchange ratio of three trust units per share pursuant to the plan of arrangement.

Net income in the second quarter of 2005 contained stock-based compensation charges related to the trust conversion and current income tax provisions related to the pre-conversion period. Higher commodity prices and lower tax provisions, due to income allocations to the trust, are reflected in the third and fourth quarter of 2005 net income amounts.

Business Environment

Increased demand for commodities from growing economies such as China, political instability in parts of the world and the occurrence of natural disasters, resulted in strong energy prices in 2005. The price of West Texas Intermediate (“WTI”), the benchmark for light crude oil, averaged US$56.70 per barrel in 2005 up 37 percent compared to 2004.

Heavy oil differentials increased in 2005 as a significant portion of 2005 incremental supply, especially from the Organization of Petroleum Exporting Countries, was heavy oil and there was a continuing shortage of upgrading capacity. The average 2005 heavy/light crude oil differential was $24.16 per barrel, an increase of 58 percent from $15.32 per barrel in 2004.

AECO natural gas prices continued to be strong in 2005 increasing 34 percent to $8.81 per mcf compared to $6.59 per mcf in 2004. Concerns about overall North American supply/demand balance and interruptions in supply from the Gulf of Mexico were the main contributors to this price level.

The benefit of the strength in commodity prices was partially offset by the strength of the Canadian dollar relative to the U.S. dollar and wider heavy oil differentials. Oil marketing contracts are generally based on WTI prices denominated in U.S. dollars; therefore the strengthening Canadian dollar reduces Canadian dollar prices. The average exchange rate increased from $0.769 CAD/USD in 2004 to $0.825 CAD/USD in 2005. Strong commodity prices increased operating costs due to increases in the demand for energy, steel, services and other costs.

10

Penn West has proven management, dedicated employees and a business plan appropriate for an energy trust. In terms of production, cash flow, reserves and market capitalization, Penn West progressed from a very small explorer and producer in 1992 to the top ranks of independent oil and natural gas producers in Western Canada. This year, Penn West converted into the largest conventional oil and natural gas trust by production in Canada. We believe we have a disciplined approach to business that stresses cost control and product balance. Using this discipline, we have shown the ability not only to explore for and develop reserves, but also to acquire and optimize producing fields. We have a diverse asset base in the Western Canada Sedimentary Basin divided into five core areas ranging from southern Saskatchewan to regions bordering the Northwest Territories. Our goal is to create and protect unitholder value by:

•Pursuing an active program of internal development, focusing on low-risk opportunities to maintain production or reduce operating costs and resource plays such as our CO₂  enhanced oil recovery project at Pembina and our Seal conventional oil sands project;

•Participating in exploration, without the requirement to fund capital expenditures, through the farmout of undeveloped lands.

•Rationalizing our asset base with the aim of maintaining distributions over the long-term, including asset acquisitions and dispositions that are accretive or strategic; and

•Maintaining a strong balance sheet.

Using our established business plan, we achieved record cash flow and net income in 2005.

Unitholder Value Measures

Years ended December 31	2005	2004	2003
Cash flow per unit ($)	7.28	5.37	5.04
Distributions per unit ($)	1.97	—	—
Dividends per unit ($)	0.07	0.16	0.54
Ratio of year end bank debt to annual cash flow	0.5	0.6	0.5

We have an extensive base of undeveloped land (4.1 million net acres at December 31, 2005) and a strong balance sheet. These attributes, plus strong in-house professional and technical staff, give us the ability to pursue a strategy of both organic growth and optimization through acquisitions, dispositions and farmout of undeveloped land. We believe that the application of financial discipline is also a key factor in achieving superior returns on investment for our unitholders.

Performance Indicators

Years ended December 31	2005		2004		2003
Return on capital employed	36.2	%	8.4	%	15.9	%
Total assets ($ millions)	3,967		3,867		3,310
Return on equity	28.3	%	15.3	%	30.1	%

Cash Flow and Net Income

A 57 percent increase in Q4 2005 operating netbacks resulted in a 40 percent increase in cash flow and a 251 percent increase in net income compared to Q4 2004. Operating netbacks were higher mainly due to increased prices received for crude oil and natural gas. Prices received for crude oil and NGLs are related to world markets and the quality of crude oil produced. The Trust’s liquid production is 64 percent light oil and NGLs that receives prices close to Edmonton par price. This benchmark price increased over 24 percent in Q4 2005 compared to Q4 2004. Natural gas prices in North America are more significantly impacted by regional supply and demand factors. The geographic constraints can result in volatility due to the supply and demand imbalances that occur from time to time. Benchmark AECO prices for natural gas were 73 percent higher in the current quarter than Q4 2004.

Cash flow and net income before taxes in 2005 increased mainly due to the increases in the sales prices of crude oil and natural gas. The impact of higher prices during 2005 was partially offset by a reduction in pre-tax income of $53 million to reflect the payout of outstanding stock options in accordance with the plan of arrangement in respect of the trust conversion and the terms of the stock option plan. After-tax net income was further impacted by future income tax recoveries in the period since converting to a Trust.

11

Production and Netbacks

	Three months ended December 31								Years ended December 31
	2005			2004			% Change		2005			2004			% Change
Natural gas:
MMcf per day	277.5			307.4			(10	)	287.8			316.3			(9	)
Operating netback ($ per mcf):
Sales price	$	11.66		$	6.81		71		$	8.68		$	6.68		30
Hedging gain	—			0.02			—		0.06			—			—
Royalties	(2.67		)	(1.51		)	77		(1.86		)	(1.43		)	30
Operating costs	(0.87		)	(0.71		)	23		(0.85		)	(0.69		)	23
Netback	$	8.12		$	4.61		76		$	6.03		$	4.56		32
Light oil and NGLs:
Barrels per day	33,227			34,524			(4	)	33,137			34,943			(5	)
Operating netback ($ per bbl):
Sales price	$	64.28		$	52.67		22		$	62.59		$	48.09		30
Hedging loss	—			(4.10		)	—		—			(6.05		)	—
Royalties	(11.46		)	(9.47		)	21		(10.17		)	(7.86		)	29
Operating costs	(15.17		)	(13.14		)	15		(14.43		)	(12.80		)	13
Netback	$	37.65		$	25.96		45		$	37.99		$	21.38		78
Conventional heavy oil:
Barrels per day	18,726			19,257			(3	)	18,705			18,136			3
Operating netback ($ per bbl):
Sales price	$	34.95		$	29.89		17		$	35.71		$	31.73		13
Royalties	(5.67		)	(4.42		)	28		(5.41		)	(4.62		)	17
Operating costs	(9.64		)	(8.32		)	16		(9.30		)	(8.49		)	10
Netback	$	19.64		$	17.15		15		$	21.00		$	18.62		13
Total Liquids:
Barrels per day	51,953			53,781			(3	)	51,842			53,079			(2	)
Operating netback ($ per bbl):
Sales price	$	53.71		$	44.51		21		$	52.89		$	42.50		24
Hedging loss	—			(2.63		)	—		—			(3.98		)	—
Royalties	(9.38		)	(7.67		)	22		(8.45		)	(6.75		)	25
Operating costs	(13.18		)	(11.41		)	16		(12.58		)	(11.33		)	11
Netback	$	31.15		$	22.80		37		$	31.86		$	20.44		56
Combined totals:
Barrels of oil equivalent (1)
Daily production	98,205			105,007			(6	)	99,807			105,788			(6	)
Operating netback ($ per boe):
Sales price	$	61.38		$	42.73		44		$	52.50		$	41.27		27
Hedging gain (loss)	—			(1.28		)	—		0.18			(1.98		)	—
Royalties	(12.52		)	(8.33		)	50		(9.74		)	(7.65		)	27
Operating costs	(9.44		)	(7.94		)	19		(8.99		)	(7.75		)	16
Netback	$	39.42		$	25.18		57		$	33.95		$	23.89		42

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

Production of 98,205 boe per day in the fourth quarter of 2005 was down slightly compared to the third quarter of 2005 due to minor asset dispositions. Production levels in 2005 were impacted by wet weather that limited access and product hauling. Unanticipated production interruptions, normal production declines and a 47 percent reduction in capital spending also impacted 2005 production levels compared to 2004.

12

For the year ended December 31, 2005, the Trust received an average light oil and liquids netback of $37.99 per barrel, an average conventional heavy oil netback of $21.00 per barrel, and a natural gas netback of $6.03 per mcf. The light oil and liquids netback was up 78 percent from $21.38 per barrel for the year ended December 31, 2004 due to higher average commodity prices in 2005 and a 2004 hedging loss of $6.05 per barrel compared to no realized gain or loss in 2005. The increase was partially offset by higher royalties and operating expenses experienced in 2005. The heavy oil netback was up 13 percent from $18.62 per barrel in 2004 mainly due to higher benchmark oil prices, partially offset by the larger light/heavy oil price differential and higher royalties and operating costs. The natural gas netback was up 32 percent from $4.56 per mcf in 2004 due to higher prices, partially offset by higher royalties and operating expenses in 2005.

In Q4 2005, the Trust achieved an overall netback of $39.42 per boe consisting of a light oil and liquids netback of $37.65 per barrel, a conventional heavy oil netback of $19.64 per barrel, and a natural gas netback of $8.12 per mcf. All products contributed to the 57 percent overall increase from $25.18 per boe in 2004. The Q4 2005 light oil and liquids netback increased 45 percent from $25.96 per barrel in Q4 2004, the netback for conventional heavy oil increased 15 percent from $17.15 per barrel in Q4 2004, and the natural gas netback increased 76 percent from $4.61 per mcf in Q4 2004. The increased netbacks in the quarter were the result of higher commodity prices in Q4 2005 and hedging losses in the 2004 period partially offset by increased royalties and increased operating expenses.

Oil and Natural Gas Revenues

	Years ended December 31
($millions)	2005			2004		2003
Light oil and natural gas liquids	$	757.0		$	537.7	$	497.3
Conventional heavy oil	243.8			210.6		113.7
Total liquids	1,000.8			748.3		611.0
Natural gas	918.2			773.0		783.2
Total	$		1,919.0	$	1,521.3	$	1,394.2

Increases (Decreases) in Gross Revenues, before royalties, for the year ended December 31, 2005 ($ millions)

Gross revenues – 2004	$	1,521.3
Decrease in light oil and NGL production	(29.2		)
Increase in light oil and NGL prices	248.5
Increase in conventional heavy oil production	6.0
Increase in conventional heavy oil prices	27.2
Decrease in natural gas production	(71.5		)
Increase in natural gas prices	216.7
Gross revenues – 2005	$	1,919.0

Oil Revenues and Marketing

The Trust’s overall quality of crude oil remains high, averaging 28 degrees API in 2005. Light and medium oil and NGLs made up 33 percent of the Trust’s total production, with an average quality of 37 degrees API. Conventional heavy oil, at an average of 15 degrees API, accounted for 19 percent of the Trust’s production. The Trust’s light and heavy oil netbacks remained strong throughout 2005 despite larger differentials between light/heavy oil prices. Most of the Trust’s production is sold at the field level to various refiners and marketing companies.

Revenues from light oil and liquids increased 41 percent to $757 million for the year ended December 31, 2005 from $538 million in 2004. This increase was attributable to higher average prices in 2005. The Trust’s average light oil and liquids price increased 30 percent to $62.59 per barrel for the year ended December 31, 2005 from $48.09 per barrel in 2004. The average daily production of light oil and liquids decreased five percent to 33,137 barrels per day in 2005 from 34,943 barrels per day in 2004. Hedging reduced the net price received in 2004 by $6.05 to $42.04 per barrel. At December 31, 2005, the Trust had hedged 20,000 bbls per day for 2006 using collars with a floor price of US$ 47.50 and a ceiling price of US$ 67.86. The Trust maintains an active hedging program.

13

Light oil and liquids revenues in the fourth quarter of 2005 were $197 million, an increase of 28 percent over Q4 2004 revenues of $154 million. This increase was due to significantly higher average prices in the 2005 quarter. The Trust’s average light oil and liquids price for Q4 2005 was $64.28 per barrel, an increase of 22 percent over the Q4 2004 average price of $52.67 per barrel. Hedging reduced the net price received in Q4 2004 by $4.10 to $48.57 per barrel. Production of 33,227 barrels per day of light oil and liquids was down four percent compared to production of 34,524 in Q4 of 2004.

Revenues from conventional heavy oil for the year ended December 31, 2005 increased 16 percent to $244 million from $211 million in the same period of 2004. This increase was attributable to higher average prices in the year. The Trust’s average conventional heavy oil price increased 13 percent to $35.71 per barrel in 2005 from $31.73 in 2004, and the average production of conventional heavy oil increased three percent to 18,705 barrels per day in 2005 from 18,136 barrels per day in 2004.

In the fourth quarter of 2005, conventional heavy oil revenues increased 13 percent to $60 million compared to $53 million in Q4 2004. This increase was also due to higher average prices in the quarter. Conventional heavy oil prices were $34.95 per barrel in Q4 2005, an increase of 17 percent over Q4 2004 prices of $29.89 per barrel. Production in Q4 was down three percent to 18,726 barrels per day in 2005 compared to 19,257 barrels per day in 2004.

Natural Gas Revenues and Marketing

The Trust maintained significant weighting to the Alberta natural gas market in 2005, as this market continued to offer a premium netback relative to other indices. At December 31, 2005, the Trust marketed approximately 89 percent of its natural gas sales directly, with the remaining 11 percent marketed by aggregators.

For the year ended December 31, 2005, Penn West received an average natural gas sales price of $8.68 per mcf, an increase of 30 percent from $6.68 per mcf in 2004. Revenues from natural gas increased 19 percent in the year ended December 31, 2005 to $918 million from $773 million in 2004. The increased revenue in 2005 over 2004 was due to pricing, as natural gas production of 288 mmcf per day in 2005 was nine percent less than production of 316 mmcf per day in 2004. The decrease in natural gas production in 2005 was attributable to minor asset dispositions, natural reservoir declines and a reduced capital program.

Natural gas revenues in the fourth quarter of 2005 increased 54 percent to $298 million from $193 million in the same period in 2004. This was the result of higher natural gas prices in Q4 2005 partially offset by lower production volumes. Q4 2005 natural gas prices of $11.66 per mcf were 71 percent higher than Q4 2004 prices of $6.81 per mcf, and natural gas production of 278 mmcf per day in Q4 2005 was 10 percent lower than the 307 mmcf per day in Q4 2004.

The Trust makes use of financial instruments at various times in the commodity price cycle to manage downside risk. On average, the Trust hedged approximately 20 percent of its natural gas production in 2005. For the year ended December 31, 2005, natural gas hedging increased the sales price received by $0.06 per mcf and had no impact in 2004. The Trust currently has a number of AECO collars in place for 2006. For details on financial instruments outstanding at December 31, 2005 see note 8 to the unaudited interim consolidated financial statements.

Royalty Expenses

Years ended December 31	2005			2004			2003
Royalties, net of Alberta Royalty Credit ($millions)	$	355.0		$	296.1		$	265.1
Average rate ($/boe)	$	9.74		$	7.65		$	7.15
Percentage of gross revenues	19		%	20		%	19		%

The average royalty rate incurred was 19 percent for the year ended December 31, 2005 compared to 20 percent for the same period in 2004. The royalty rate comprises an oil and liquids royalty rate of 16 percent compared to 18 percent in 2004 and a natural gas royalty rate of 21 percent in both 2005 and 2004. The decrease in the oil and liquids royalty rate was mainly attributable to hedging losses in 2004. The year-to-year royalty rates also vary with commodity prices and the proportion of oil production relative to natural gas production.

For the fourth quarters of 2005 and 2004, the average royalty rate incurred was 20 percent. The oil and liquids royalty component was 18 percent in Q4 of both 2005 and 2004. The natural gas royalty was 23 percent in Q4 2005 compared to 22 percent in Q4 2004.

14

Operating Expenses

Years ended December 31	2005			2004			2003
Operating expenses ($ millions)	$	327.4		$	300.4		$	245.6
Average cost ($/boe)	$	8.99		$	7.75		$	6.63
Percentage of gross revenues	17		%	20		%	18		%

For the year ended December 31, 2005, operating costs averaged $8.99 per boe, a 16 percent increase from the average cost of $7.75 per boe achieved in 2004. The average production decline between 2004 and 2005 accounted for 10 percent of the increase in unit operating costs. In addition, operating costs are higher for oil properties, and in 2005 liquids production increased to 52 percent of total production compared to 50 percent in 2004. A significant portion of the Trust’s liquid production is light oil that commands a premium price, therefore, the Trust is well positioned to absorb operating cost increases and still maintain economic operating netbacks. Operating costs were impacted by higher energy and fuel costs, planned facility maintenance projects, increased natural gas compression costs and lower natural gas production. Higher industry activity and commodity prices also impacted operating costs by increasing the demand for services, thus increasing input costs resulting in higher rates charged by our service providers.

Light oil and liquids operating costs increased 13 percent to $14.43 per barrel in the year ended December 31, 2005 from $12.80 per barrel in the same period of 2004. Operating costs for conventional heavy oil increased 10 percent to $9.30 per barrel during 2005 from $8.49 per barrel in 2004. Operating costs for natural gas in 2005 were $0.85 per mcf, an increase of 23 percent from $0.69 per mcf in 2004.

Q4 2005 operating costs were $9.44 per boe, 19 percent higher than Q4 2004 operating costs of $7.94 per boe. This increase was the result of the higher liquids production as a percentage of total production, higher energy and fuel costs, increased industry demand for oilfield services, and lower total production in the 2005 quarter. The overall production decline between Q4 2005 and Q4 2004 accounted for 13 percent of the increase in unit operating costs.

Light oil and liquids operating costs in Q4 2005 increased 15 percent to $15.17 per barrel from $13.14 per barrel in Q4 2004 and natural gas operating costs increased 23 percent to $0.87 per mcf in Q4 2005 from $0.71 per mcf in Q4 2004.

General and Administrative Expenses

Years ended December 31 ($ millions)	2005			2004			2003
Gross expenses	$	45.0		$	41.3		$	34.0
Operator recoveries	(21.9		)	(25.2		)	(21.5		)
Net expenses	$	23.1		$	16.1		$	12.5
Gross general and administrative expenses – average cost ($/boe)	$	1.24		$	1.07		$	0.92
Percentage of gross revenues	2		%	3		%	2		%
Net general and administrative expenses – average cost ($/boe)	$	0.64		$	0.42		$	0.34
Percentage of gross revenues	1		%	1		%	1		%

Gross general and administrative expenses increased due to higher compensation costs to retain staff. On a unit of production basis, the gross general and administrative costs increased 16 percent to $1.24 per boe for the year ended December 31, 2005 from $1.07 per boe in 2004. Net general and administrative expenses on a per unit basis increased 52 percent to $0.64 per boe in 2005 from $0.42 per boe in 2004. The Trust does not capitalize any general and administrative expenses. The reduction in operator recoveries resulted from the planned reduction in capital spending due to the trust conversion. Q4 2005 net general and administrative expenses were up 36 percent on a per unit basis to $0.75 per boe from $0.55 per boe in Q4 2004.

15

Unit-Based Compensation Provision

Years ended December 31	2005			2004			2003
Unit-based compensation ($ millions)	$	77.2		$	84.1		$	48.0
Average cost ($/boe)	$	2.12		$	2.17		$	1.30
Percentage of gross revenues	4		%	6		%	3		%

Upon conversion to a Trust, unvested stock options were vested in accordance with the terms of the stock option plan and the plan of arrangement. Option holders had several alternatives including a cash payment, purchasing Penn West shares at the option exercise price or carrying the option forward. Of the total unit-based compensation charge of $77 million in 2005, $53 million represented the cash paid to option holders in the second quarter of 2005 in excess of the previously recorded stock-based compensation liability. Penn West paid $81 million at the end of May 2005 to option holders who elected to receive cash for surrendering stock options that were outstanding at the time of the trust conversion. The impact of these payments was expensed in Q2 2005.

In May 2005, the Trust implemented a unit rights incentive plan. Compensation expense related to this plan is based on the fair value of trust unit rights granted and determined using the Black-Scholes option pricing model. The resulting expense is amortized over the remaining vesting periods on a straight-line basis. Compensation expense of $6 million relating to the unit rights incentive plan was expensed in the year ended December 31, 2005.

Financing Expenses

Years ended December 31	2005			2004			2003
Interest ($ millions)	$	23.2		$	17.0		$	11.9
Cash flow times interest coverage	52.1			51.9			69.5
Average cost ($/boe)	$	0.63		$	0.45		$	0.32
Percentage of gross revenues	1		%	1		%	1		%

Interest expense for the year ended December 31, 2005 amounted to $23 million, an increase of 35 percent from $17 million in 2004. This increase was due to higher 2005 short-term interest rates and average debt levels that resulted from the payment of over $200 million in income taxes and $142 million for the surrender of stock options. With 2005 cash flows and the planned capital program reductions, the Trust repaid the majority of this debt prior to the end of 2005.

Q4 2005 interest expense of $7 million is 75 percent higher than Q4 2004 interest expense of $4 million as a result of higher average debt levels in the 2005 quarter and higher short-term interest rates.

Capital Expenditures ($ millions)

	Three months ended December 31					Year ended December 31
	2005			2004		2005			2004		2003
Property (dispositions) acquisitions, net	$	(91.3	)	$	101.4	$	(5.8	)	$	332.3	$	0.3
Land acquisition and retention	3.7			3.9		13.5			18.4		47.4
Drilling and completions	61.0			89.4		277.1			301.5		349.6
Facilities and well equipping	30.0			27.1		155.2			191.3		191.4
Geological and geophysical	0.8			4.6		7.4			16.3		18.1
Research and development	1.9			2.3		8.1			4.9		—
Administrative	0.2			0.3		1.2			0.9		1.3
Capital expenditures	$	6.3		$	229.0	$	456.7		$	865.6	$	608.1

The decrease in 2005 capital expenditures compared to 2004 reflects planned reductions due to the trust conversion, the February 2004 acquisition of oil and natural gas assets and undeveloped land in southwest Saskatchewan for $234 million, and $91 million of net property dispositions in Q4 2005 versus the $101 million in net acquisitions in Q4 2004.

Research and development represents capital expenditures related to the Pembina CO₂ pilot project, including injectants, for which no reserves have been booked. Capital expenditures exclude the impact of property, plant and equipment adjustments for asset retirement obligations and future income taxes. For details of these adjustments, see notes 3 and 5 to the unaudited interim consolidated financial statements.

16

Depletion, Depreciation and Accretion

Years ended December 31	2005			2004			2003
Depletion and depreciation ($ millions)	$	416.5		$	394.3		$	291.9
Accretion ($ millions)	21.1			18.8			11.8
	$	437.6		$	413.1		$	303.7
Average rate ($/boe)	$	12.01		$	10.67		$	8.19
Percentage of gross revenues	23		%	27		%	22		%

The increase in the 2005 depletion, depreciation and accretion provision compared to 2004 reflects a rate increase of 13 percent that was partially offset by lower production. The rate increase was due to a higher portion of the capital program being allocated to infill drilling and other production optimization activities consistent with the trust mandate that focuses on capital efficiency. Generally, a lower amount of reserve additions are assigned to these activities than conventional exploration and development company activities, however production is added or maintained at a lower capital cost per flowing barrel of production.

Foreign Exchange

Years ended December 31 ($ millions)	2005		2004			2003
Foreign exchange loss (gain)	$	4.5	$	(27.7	)	$	(95.6	)
(Gain) loss from written Canadian dollar calls	—		(12.7		)	12.7
Net foreign exchange loss (gain)	$	4.5	$	(40.4	)	$	(82.9	)
Average loss (gain) ($/boe)	$	0.12	$	(1.04	)	$	(2.24	)
Percentage of gross revenues	—		3		%	6		%

During Q1 2005, the Trust converted US $205 million of its US denominated borrowings to Canadian dollars at an average exchange rate of $0.829 CAD/USD resulting in a realized foreign exchange gain of $63 million. In May 2005, the Trust converted its remaining US $85 million of US denominated borrowings to Canadian dollars at an average exchange rate of $0.803 CAD/USD and realized an additional $23 million foreign exchange gain. As at December 31, 2005, the Trust had no foreign currency denominated debt versus the $290 million of US denominated debt outstanding at December 31, 2004.

Taxes

Years ended December 31	2005			2004			2003
Current income taxes ($ millions)	$	54.1		$	17.8		$	9.9
Future income taxes (recovery) ($ millions)	(1.1		)	109.6			97.3
	$	53.0		$	127.4		$	107.2
Effective tax rate	8		%	31		%	19		%
Capital taxes ($ millions)	$	14.7		$	10.1		$	10.1

In Q4 2005, no current income tax provision was required compared to a recovery of $13 million in the same period of 2004. The cash income tax provision for 2005 was $54.1 million compared to $18 million in the 2004 period due to higher cash flow in 2005. The trust conversion on May 31, 2005 resulted in a short income tax year that accelerated $214 million of cash income taxes as a significant amount of Penn West’s taxable income was earned in a partnership. Of this amount, $54 million was expensed as current income taxes to May 31, 2005, $146 million was reflected as a reduction to the future income tax liability and $13 million, being the tax rate differential, was recorded as a restructuring charge.

The trust conversion also impacted capital taxes in Q2 2005. Part of the plan of arrangement consisted of the conveyance of properties from a partnership to a corporation. This transaction increased taxable capital for large corporations tax in the corporation for tax year ended December 31, 2005; however, this increase will not apply in subsequent taxation years.

In Q4 2005, a $51 million future tax recovery was recorded compared to a $48 million provision in Q4 2004. There was a future income tax recovery in 2005 of $1 million compared to a future income tax provision of $110 million in 2004. The 2005 future income tax provisions reflect future tax reductions related to 2005 income allocations to the trust and lower tax rates. Interest and royalty payments, by the operating corporation to the Trust, are accounted for as a reduction of accumulated timing differences and accordingly lowers the future income tax provision.

17

In the fourth quarter of 2005, a $28 million general future tax rate reduction was recorded to reflect lower scheduled future tax rates resulting from timing differences reversing in later taxation years under current legislation. In the third quarter of 2005, a $3 million tax rate reduction was recorded to reflect British Columbia’s 1.5 percent general tax rate reduction. In the first quarter of 2004, a $20 million future income tax recovery was recorded to reflect the 2004 tax rate reduction enacted by the Government of Alberta.

Tax Pools

As at December 31 ($ millions)	2005		2004		2003
Undepreciated capital cost (UCC)	$	519.0	$	276.4	$	270.1
Cumulative Canadian oil and gas property expense (COGPE)	707.6		611.5		679.2
Cumulative Canadian development expense (CDE)	329.8		95.4		136.6
Cumulative Canadian exploration expense (CEE)	—		—		—
Total tax pools	$	1,556.4	$	983.3	$	1,085.9

The increase in the 2005 tax pools reflects the May 31, 2005 tax year-ends, due to the trust conversion, that advanced taxable income in a partnership previously accounted for as tax pool reductions.

Items Affecting Cash Flow and Net Income

	2005					2004					2003
Years ended December 31	$/boe			%		$/boe			%		$/boe			%
Oil and natural gas revenues	$	52.68		100.0		$	39.29		100.0		$	37.62		100.0
Net royalties	(9.74		)	(18.5	)	(7.65		)	(19.5	)	(7.15		)	(19.0	)
Operating expenses	(8.99		)	(17.1	)	(7.75		)	(19.7	)	(6.63		)	(17.6	)
Transportation	(0.62		)	(1.1	)	(0.66		)	(1.7	)	(0.71		)	(1.9	)
Net operating income	33.33			63.3		23.23			59.1		23.13			61.5
General and administrative expenses	(0.64		)	(1.2	)	(0.42		)	(1.1	)	(0.34		)	(0.9	)
Interest	(0.63		)	(1.2	)	(0.45		)	(1.1	)	(0.32		)	(0.9	)
Realized foreign exchange gain	2.35			4.4		0.74			1.9		—			—
Current and capital taxes	(1.89		)	(3.6	)	(0.71		)	(1.8	)	(0.54		)	(1.4	)
Cash flow	32.52			61.7		22.39			57.0		21.93			58.3
Unrealized foreign exchange gain (loss)	(2.48		)	(4.7	)	0.30			0.8		2.24			6.0
Unit-based compensation	(2.12		)	(4.0	)	(2.17		)	(5.5	)	(1.30		)	(3.5	)
Risk management activities	(0.09		)	(0.2	)	—			—		—			—
Depletion, depreciation and accretion	(12.01		)	(22.8	)	(10.67		)	(27.2	)	(8.19		)	(21.8	)
Future income taxes	0.03			—		(2.83		)	(7.2	)	(2.63		)	(7.0	)
Net income	$	15.85		30.0		$	7.02		17.9		$	12.05		32.0

Cash flow increased by 37 percent to $1.2 billion for the year ended December 31, 2005 from $867 million in the same period of 2004. Basic cash flow per unit rose by 36 percent to $7.28 per unit in 2005, compared to $5.37 per unit in 2004.

Q4 2005 cash flow was $333 million, an increase of 40 percent from $238 million in Q4 2004. Basic cash flow per unit increased 38 percent to $2.03 per unit in Q4 2005 compared to $1.47 per unit in Q4 2004.

Net income for the year ended December 31, 2005 increased by 112 percent to $577 million from $272 million in 2004. Basic net income per unit increased by 111 percent in 2005 to $3.55 per unit from $1.68 per unit in 2004.

Net income in Q4 2005 increased 251 percent to $241 million from $69 million in Q4 2004. Basic net income per unit increased 252 percent to $1.48 per unit in Q4 2005 from $0.42 per unit in Q4 2004.

Market Risk Management

The Trust is exposed to normal market risks inherent in the oil and natural gas business, including credit risk, commodity price risk, interest rate risk and foreign currency risk. The Trust, from time to time, attempts to minimize exposure to these risks using financial instruments.

18

Credit Risk

Credit risk is the risk of loss if purchasers or counterparties do not fulfill their contractual obligations. All of the Trust’s receivables are with customers in the oil and natural gas industry and are subject to normal industry credit risk. In order to limit the risk of non-performance of counterparties to derivative instruments, the Trust transacts only with financial institutions with high credit ratings and by obtaining security in certain circumstances.

Commodity Price Risk

Commodity price risk is the Trust’s most significant exposure. Crude oil prices are influenced by worldwide factors such as OPEC actions, supply and demand fundamentals, and political events. Natural gas prices are generally influenced by oil prices and North American natural gas supply and demand factors. Pursuant to policy, the Trust may, from time to time, manage these risks through the use of costless collars or other financial instruments up to a maximum of 50 percent of sales volumes.

The Trust maintains an active hedging program. Other financial instruments include Alberta electricity contracts, with positive mark-to-market values. For details of the financial instruments outstanding on December 31, 2005, see note 8 to the unaudited interim consolidated financial statements.

Interest Rate Risk

The Trust maintains its debt in floating-rate bank facilities resulting in exposure to fluctuations in short term interest rates. From time to time, the Trust may increase the certainty of future interest rates using financial instruments to swap floating interest rates for fixed rates or to collar interest rates. The Trust had no financial instruments in place at December 31, 2005 that affected its future interest rate exposure.

Foreign Currency Rate Risk

Prices received for sales of crude oil and certain bank loans are referenced to, or denominated in, US dollars. Accordingly, realized oil prices, interest costs and debt levels may be impacted by CAD/USD exchange rates. When considered appropriate, the Trust may use financial instruments to fix or collar future exchange rate. At December 31, 2005 the Trust had no financial instruments outstanding related to foreign exchange rates.

Liquidity and Capital Resources

Capitalization

As at December 31	2005			2004			2003
	$ millions		%	$ millions		%	$ millions		%
Trust unit equity, at market	$	6,203	90.5	$	4,269	86.0	$	2,586	81.0
Bank loan	542		7.9	503		10.2	442		13.8
Working capital deficiency (1)	127		1.6	190		3.8	165		5.2
Total enterprise value	$	6,872	100.0	$	4,962	100.0	$	3,193	100.0

(1) Current assets less current liabilities.

Penn West’s closing market price on the Toronto Stock Exchange was $37.99 per unit in 2005. The closing market price in the prior years, after accounting for the conversion ratio of three trust units issued for each common share, was $26.42 per unit in 2004 and $16.05 per unit in 2003. Total enterprise value was $6.9 billion at December 31, 2005 compared to $5.0 billion at year end 2004.

Dividends paid to shareholders prior to the trust conversion of $17 million, distributions paid to unitholders after the conversion of $271 million, and the 2005 capital program was funded using a portion of internally generated 2005 cash flow. Distributions declared subsequent to the trust conversion represented 43 percent of cash flow and 66 percent of net income. The remaining cash flow was used to repay bank debt which, at December 31, 2005, was $542 million compared with $503 million at December 31, 2004 after the payment of cash taxes and stock options related to the trust conversion in 2005.

In the second quarter of 2005, the Trust entered into an unsecured, extendible, three year revolving syndicated credit facility with an aggregate borrowing limit of $1,170 million plus a $50 million operating facility. The credit facility contains provision for stamping fees on Bankers’ Acceptances and LIBOR loans, and standby fees on lines not drawn depending on certain consolidated bank debt to earnings before interest, taxes and depreciation and depletion (“EBITDA”) ratios. The Trust is in compliance with all financial covenants relating to the facility.

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Under the terms of its trust indenture, the Trust is required to distribute all of its taxable income to unitholders. Distributions may be monthly or special and in cash or in trust units at the discretion of the Board of Directors. To the extent that additional cash distributions are paid and capital programs are not adjusted, debt levels will be affected. Under the Distribution Reinvestment and Optional Trust Unit Purchase Plan (the “DRIP”), announced on December 8, 2005, unitholders may elect to reinvest distributions for the purchase of units. Trust units issued under the DRIP increase the number of trust units outstanding. In the event that a special distribution in the form of trust units is declared, the terms of the Trust Indenture require that the outstanding units be consolidated immediately subsequent to the distribution. The number of outstanding trust units would remain at the number outstanding immediately prior to the distribution of trust units and that portion of the Trust’s taxable income would be allocated to the unitholders.

The philosophy of the Trust is to retire approximately 10 percent to 15 percent of its opening asset retirement obligations (“ARO”), as contained in the unaudited interim consolidated financial statements, annually from cash flow. Due to the extent of its environmental programs, the Trust believes little or no benefit would result from the initiation of a reclamation fund. The Trust believes its program is sufficient to meet or exceed existing environmental regulations and best industry practices. In the event of significant changes to the environmental regulations or the cost of environmental activities, a higher portion of cash flow will be required to fund these expenditures.

Reconciliation of Cash Flow to Distributions

($ millions, except indicators and per unit amounts)

	Three months ended December 31, 2005			Seven months ended December 31, 2005 *
Cash flow from operating activities	$	368.7		$	696.5
(Decrease) increase in non-cash working capital	(42.4		)	34.6
Payments for surrendered options	—			0.6
Environmental expenditures	6.3			12.6
Cash flow	$	332.6		$	744.3
Funding of capital expenditures	(6.3		)	(203.3		)
Expenditures on abandonments	(6.3		)	(12.6		)
Debt repayments	(168.2		)	(206.9		)
Cash distributions	$	151.8		$	321.5
Accumulated cash distributions, beginning of period	169.7			—
Accumulated cash distributions, end of period	$	321.5		$	321.5
Net income	$	241.1		$	485.6
Cash distributions as a percentage of net income	63		%	66		%
Cash distributions as a percentage of cash flow	46		%	43		%
Cash distributions per unit	$	0.93		$	1.97

* Includes the operations of the Trust subsequent to the effective date of the trust conversion, May 31, 2005.

During 2005, Penn West paid dividends of $18 million (2004 - $108 million) and distributions of $270 million. The first monthly cash distribution of the Trust, in the amount of $42 million or $0.26 per trust unit, was paid on July 15, 2005 to unitholders of record on June 30, 2005. On October 17, 2005, the Trust announced an increased monthly distribution of $0.31 per trust unit, a 19 percent increase, that was payable on November 15, 2005 to unitholders of record on October 31, 2005. On February 2, 2006, a further 10 percent or $0.03 per trust unit distribution increase was announced effective for the February distribution payable March 15, 2006. The distribution increases were made considering expected commodity prices that exceed those initially forecasted, hedging contracts put in place to increase the likelihood of achieving price expectations, strong industry interest in the Trust’s undeveloped land base, and the level of projected capital requirements for 2006 and beyond.

The Trust’s 2005 distributions, for both Canadian and U.S. unitholders, were 100 percent taxable with no return of capital.

20

Plan of Arrangement

On May 27, 2005, the shareholders approved the proposed reorganization of Penn West into an income trust as described in the plan of arrangement dated April 22, 2005. Court approval was obtained on the effective date of the conversion, May 31, 2005. Penn West shareholders received three units of the Trust for each Penn West share. The Trust commenced operations on May 31, 2005 with a new business mandate and legal structure pursuant to the trust indenture dated April 22, 2005. The Trust assumed all assets and liabilities previously held by Penn West.

Prior to the trust conversion, the unaudited interim consolidated financial statements included the accounts of the Trust and its subsidiaries and partnerships. The unaudited interim consolidated financial statements of the Trust have been prepared on a continuity of interest basis, as if the Trust historically carried on the business of Penn West, and include the financial results of Penn West to May 31, 2005 and the Trust for the subsequent months. Per unit figures of comparative periods have been restated to reflect the conversion ratio of three units of the Trust for each share of Penn West.

Reorganization costs of $36 million, pre-tax, relating to financial advisors, legal fees, short year tax rate differences and additional capital taxes associated with the plan of arrangement were charged to accumulated earnings in the second quarter of 2005. In addition, as Penn West’s stock option plan contained a cash payment alternative, $53 million related to canceling outstanding options was expensed in the second quarter of 2005. At the end of May 2005, Penn West made cash payments of $81 million for the surrender of the remaining vested and unvested stock options pursuant to the plan of arrangement and the terms of the stock option plan.

Business Risks

The Trust’s exploration, development, production and asset acquisition/disposition activities are conducted in the Western Canada Sedimentary Basin and involve a number of business risks. These risks include the uncertainty of replacing annual production and finding new reserves on an economic basis, the potential instability of commodity prices, exchange rates and interest rates, and other factors discussed under “Notice Regarding Forward-Looking Statements.”

To the extent practical, the Trust mitigates these risks by employing highly trained and competent management and staff who mitigate these risks by:

•Balancing the production portfolio between oil and natural gas;

•Pursuing low risk development and production optimization projects and implementing a phased approach to significant projects such as the Pembina/Swan Hills CO2 enhanced oil recovery project and the Seal oilsands project;

•Pursuing strategic acquisitions, dispositions and the farmout of undeveloped land; and,

•Maintaining high average capital efficiency and low operating and general and administrative costs.

The Trust’s management team believes that these principles, validated through Penn West’s thirteen-year track record of growth and profitability, will continue to apply under the trust business model.

The oil and natural gas industry is subject to extensive government influence through taxation policies and environmental legislation. While taxation policy has remained relatively stable, there is always the potential for change.

The industry is also subject to extensive regulations imposed by governments related to the protection of the environment. Environmental legislation in Western Canada has undergone major revisions that have resulted in environmental standards and compliance becoming more stringent. The Trust is committed to meeting its responsibilities to minimize its impact on the environment wherever it operates, and has instituted a series of controls and procedures with respect to environmental protection that meet the standards of the Environmental Code of Practice published by the Canadian Association of Petroleum Producers. The Trust’s plan is to retire approximately 10 percent to 15 percent of its opening ARO annually from cash flow. All activities that have or could have an environmental impact and all environmental regulations are regularly monitored by the Trust.

21

Outlook

The outlook for oil and natural gas prices remains strong. For 2006, we are forecasting net capital expenditures of $400 to $500 million which will fund 250 to 300 net wells. Estimated average 2006 production is forecast between 94,000 and 98,000 boe per day. Based on a forecast WTI oil price of US$58.00 per barrel and an $8.75 per mcf natural gas price with an exchange rate of $0.850 CAD/USD for 2006 forecast after-tax cash flow for 2006 is between $1.0 billion and $1.1 billion.

Sensitivity Analysis

This news release includes forward-looking statements (forecasts) under applicable securities laws. These statements are based on assumptions related to, but not limited to, commodity prices, the capital markets, the performance of producing wells and reservoirs, and the regulatory and legal environment. Forward-looking statements are subject to known or unknown risks and uncertainties that could cause actual results to differ materially from those anticipated or implied in the forward-looking statements. The Trust assumes no responsibility to publicly update or revise any forward-looking statements. Sensitivities to selected key assumptions, excluding hedging impacts, are outlined in the table below.

Change of:	Impact on cash flow*	Impact on net income*
$ 1.00 per barrel of liquids price	16.0	10.4
Per trust unit, basic	0.10	0.06
1,000 barrels per day in liquids production	16.1	7.3
Per trust unit, basic	0.10	0.04
$ 0.10 per mcf of natural gas price	7.5	4.9
Per trust unit, basic	0.05	0.03
10 mmcf per day in natural gas production	24.7	10.7
Per trust unit, basic	0.15	0.07
$ 0.01 in $CAD/$US exchange rate	15.4	10.0
Per trust unit, basic	0.09	0.06

* $ millions, except per unit amounts. Cash flow and net income impacts are computed based on 2006 forecast commodity prices and production volumes. The net income impact further assumes that income allocations to the trust are not adjusted for changes in cash flow thus impacting the incremental tax rate.

Commitments

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

($ millions)	2006	2007	2008	2009	2010	Thereafter
Transportation	15.4	8.3	6.4	4.4	1.3	—
Transportation ($US)	3.4	1.7	1.6	1.6	1.6	7.7
Electricity	3.9	3.9	3.9	3.9	3.9	6.5
Office lease	5.4	4.5	4.2	4.2	2.1	1.4

Equity Instruments

Trust units issued
As at December 31, 2005 ***	163,290,013
Issued to distribution reinvestment plan	222,037
Issued to employee savings plan	43,742
As at February 27, 2006	163,555,792
Trust unit rights outstanding
As at December 31, 2005 ***	9,447,625
Granted	154,250
Forfeited	(24,000	)
As at February 27, 2006	9,577,875

*** See notes 6 and 7 to the unaudited interim consolidated financial statements

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Evaluation of Disclosure Controls

The Trust maintains a Disclosure Committee (the “Committee”) that is responsible for ensuring that all public and regulatory disclosures are sufficient, timely and appropriate, and that disclosure controls and procedures are operating effectively. The Committee includes select members of senior management, including the Chief Executive Officer, the Chief Operating Officer and the Vice-President, Finance. As at the end of the period covered by this report, under the supervision of the Committee, the design and operating effectiveness of the Trust’s disclosure controls were evaluated. According to this evaluation, the Trust’s disclosure controls and procedures are effective to ensure that any material, or potentially material, information is made known to a member of the Committee and is appropriately included in this report.

Critical Accounting Estimates

The Trust’s significant accounting policies are detailed in note 1 to the unaudited interim consolidated financial statements. In the determination of financial results, the Trust must make certain significant accounting estimates as follows:

Full Cost Accounting

The Trust uses the full cost method of accounting for oil and natural gas properties. Generally, all costs of exploring and developing oil and natural gas reserves are capitalized and depleted against associated oil and natural gas production using the unit-of-production method based on the estimated proved reserves using forecast pricing.

All Trust reserves were evaluated by GLJ Petroleum Consultants Ltd., an independent engineering firm. In both 2005 and 2004, reserves were determined in compliance with National Instrument 51-101. The evaluation of oil and natural gas reserves are, by their nature, based on complex extrapolations and models as well as other significant engineering, capital, pricing and cost assumptions. Reserve estimates are a key component in the calculation of depletion. In addition, reserves are a key component of value in the ceiling test. To the extent that the ceiling amount is less than the carrying amount of property, plant and equipment, a write down against income must be made.

Asset Retirement Obligations

The Trust applies the “Asset Retirement Obligations” (“ARO”) accounting recommendations. The discounted, expected future cost of statutory, contractual or legal obligations to retire long-lived assets are recorded as an ARO liability with a corresponding increase to the carrying amount of the related asset. The recorded ARO liability increases over time to its future amount through accretion charges to earnings. Revisions to the estimated amount or timing of the obligations are reflected as increases or decreases to the ARO liability. Actual asset retirement expenditures are charged to the ARO liability to the extent of the then recorded liability. Amounts capitalized to the related assets are amortized to income consistent with the depletion or depreciation of the underlying asset. Note 5 to the unaudited interim consolidated financial statements details the impact these accounting recommendations had on the unaudited interim consolidated financial statements.

Financial Instruments

Financial instruments contracted by the Trust and determined to be hedges were accounted for as a component of the hedged item such as oil prices, natural gas prices, electricity costs or interest costs. The change in market value of a financial instrument accounted for as a hedge was not recognized in the financial statements until the underlying oil or natural gas production, power or interest was realized. Changes in market value of financial instruments determined not to be hedges, not qualifying as a hedge, or no longer effective as a hedge were fully recognized in the financial statements.

The Trust elected to discontinue hedge accounting effective July 1, 2005. All financial instruments are now accounted for using the fair value method where changes in the mark-to-market value of all financial instruments are recognized in net income.

23

Accounting Changes

Earnings Per Share

Effective January 1, 2005, this accounting pronouncement requires the number of incremental shares included in year-to-date diluted earnings per share calculations be computed using the average market price of shares for the year-to-date period. It also stipulates that contracts that could be settled in cash or shares be assumed settled in shares if share settlement is more dilutive. Shares to be issued upon conversion of convertible instruments with mandatory conversion features would be included in the basic weighted average earnings per share calculation from the date of mandatory conversion. These changes did not materially impact the Trust’s reported diluted earnings per share amounts.

Financial Instruments

Future changes in the fair value of derivative financial instruments will be recorded on the balance sheet with a corresponding unrealized gain or loss in income. For a summary of financial instruments outstanding on December 31, 2005 see note 8 to the unaudited interim consolidated financial statements.

Stock-based Compensation

Costs associated with the cancellation of outstanding stock options, due to the trust conversion, were expensed during the second quarter of 2005 as the stock option plan contained a cash settlement alternative.

Consolidation of Variable Interest Entities

Effective January 1, 2005, this accounting guideline addresses the circumstances where an entity has control of another entity through arrangements other than share ownership. The accounting guideline requires an enterprise to consolidate the entity when that enterprise has a variable interest that will absorb a majority of the entity’s returns or losses. The Trust does not currently have any such arrangements.

Notice Regarding Forward-Looking Statements

This document contains certain forward-looking statements that can generally be identified as such because of the context of the statements. Forward-looking statements may contain words such as forecasts, expects, anticipates, plans, intends, projects, estimates, or words of a similar nature. Results may differ materially from those expressed or implied by the forward-looking statements as a result of known and unknown risks, uncertainties and other factors.

Such factors include, but are not limited to, the following:

•Changes in general economic, market and business conditions which will impact demand for and market prices of the Trust’s products;

•The ability of the Trust to implement its business strategy;

•Availability and cost of borrowing;

•The ability of the Trust to complete its capital programs;

•The ability of the Trust to transport its products to market;

•Potential delays or changes in plans with respect to exploration or development projects;

•The success of exploration and development activities;

•The accuracy of reserve estimates;

•Actions by governmental authorities, government regulations and the expenditures required to comply with them (especially safety and environmental laws and regulations);

•Competitive actions of other entities, including increased competition from other oil and gas companies or from companies that provide alternative sources of energy; and,

•The occurrence of unexpected events such as fires, blowouts, freeze-ups, equipment failures and other similar events directly affecting assets, and/or daily operations.

Readers are cautioned that the foregoing list of important factors is not exhaustive. Although the Trust believes that the expectations conveyed by the forward-looking statements are reasonable based on information available on the date the statements are made, events or circumstances could cause actual results to differ materially from those estimated or projected and expressed in, or implied by, these forward-looking statements. The Trust assumes no responsibility to publicly update or revise any forward-looking statements.

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Accounting Pronouncements

Financial Instruments, Other Comprehensive Income:

This pronouncement, effective for fiscal year ends beginning on or after October 1, 2006, addresses when to recognize, and how to measure, a financial instrument on the balance sheet and how gains and losses are to be presented. An additional financial statement, other comprehensive income, will be required. Once implemented, the fair value of financial instruments, designated as hedges, will be included on the balance sheet as an equity item with the related mark-to-market gain or loss recognized in other comprehensive income. Consistent with current practice, financial instruments not designated as hedges will be valued at market with any related gains and losses recognized in net income of the period. As the Trust no longer designates financial instruments as hedges, and immediately recognizes changes in their fair value in net income, this pronouncement is not expected to impact reported results.

Non-Monetary transactions:

Effective January 1, 2006, this accounting pronouncement requires that non-monetary transactions be measured at fair value unless certain conditions apply and is not expected to affect the Trust’s reported results.

25

Penn West Energy Trust

Consolidated Balance Sheets

($millions, unaudited)	As at December 31, 2005			As at December 31, 2004
Assets
Current
Accounts receivable	$	214.4		$	160.5
Future income taxes	—			25.3
Risk management (note 8)	8.5			—
Other	29.0			19.8
	251.9			205.6
Property, plant and equipment (note 3)	3,715.2			3,661.8
	$	3,967.1		$	3,867.4
Liabilities and unitholders’ equity
Current
Accounts payable and accrued liabilities	$	304.1		$	306.6
Taxes payable	11.8			11.2
Distributions/dividends payable	50.6			6.7
Stock-based compensation (note 6)	—			71.0
Deferred gain on financial instruments (note 8)	11.9			—
	378.4			395.5
Bank loan (note 4)	542.0			503.1
Asset retirement obligations (note 5)	192.4			180.7
Stock-based compensation (note 6)	—			20.9
Future income taxes	682.1			858.2
	1,416.5			1,562.9
Unitholders’ equity
Unitholders’ capital (note 7)	561.0			515.3
Contributed surplus (note 7)	5.5			—
Accumulated earnings	1,927.2			1,393.7
Accumulated cash distributions	(321.5		)	—
	2,172.2			1,909.0
	$	3,967.1		$	3,867.4

See accompanying notes to the unaudited interim consolidated financial statements.

26

Penn West Energy Trust

Consolidated Statements of Income and Accumulated Earnings

($ millions, except per unit amounts, unaudited)	Three months ended December 31						Year ended December 31
	2005			2004			2005			2004
Revenues
Oil and natural gas	$	554.5		$	400.5		$	1,919.0		$	1,521.3
Royalties	(113.1		)	(80.5		)	(355.0		)	(296.1		)
	441.4			320.0			1,564.0			1,225.2
Expenses
Operating	85.3			76.8			327.4			300.4
Transportation	5.7			6.3			22.7			25.6
General and administrative	6.7			5.4			23.1			16.1
Interest on long term debt	6.9			4.3			23.2			17.0
Depletion, depreciation and accretion (note 5)	115.0			116.2			437.6			413.1
Unit-based compensation (note 6)	3.4			22.1			77.2			84.1
Foreign exchange (gain) loss	—			(17.2		)	4.5			(40.4		)
Risk management activities (note 8)	23.7			—			3.4			—
	246.7			213.9			919.1			815.9
Income before taxes	194.7			106.1			644.9			409.3
Taxes
Capital	4.2			2.5			14.7			10.1
Current income (recovery)	—			(13.1		)	54.1			17.8
Future income (recovery)	(50.6		)	48.1			(1.1		)	109.6
	(46.4		)	37.5			67.7			137.5
Net income	$	241.1		$	68.6		$	577.2		$	271.8
Net income per unit (1)
Basic	$	1.48		$	0.42		$	3.55		$	1.68
Diluted	$	1.46		$	0.42		$	3.48		$	1.65
Accumulated earnings, beginning of period	$	1,686.1		$	1,331.8		$	1,393.7		$	1,148.7
Net income	241.1			68.6			577.2			271.8
Plan of arrangement (note 10)	—			—			(32.9		)	—
Dividends	—			(6.7		)	(10.8		)	(26.8		)
Accumulated earnings, end of period	$	1,927.2		$	1,393.7		$	1,927.2		$	1,393.7

See accompanying notes to the unaudited interim consolidated financial statements.

(1)The 2004 comparative figures have been restated to reflect the conversion ratio of three trust units issued for each Penn West common share pursuant to the plan of arrangement.

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Penn West Energy Trust

Consolidated Statements of Cash Flow

	Three months ended December 31						Year ended December 31
($ millions, unaudited)	2005			2004			2005			2004
Operating activities
Net income	$	241.1		$	68.6		$	577.2		$	271.8
Depletion, depreciation and accretion (note 5)	115.0			116.2			437.6			413.1
Future income taxes (recovery)	(50.6		)	48.1			(1.1		)	109.6
Foreign exchange (gain) loss	—			(17.2		)	4.5			(40.4		)
Unit-based compensation (note 6)	3.4			22.1			77.2			84.1
Risk management activities (note 8)	23.7			—			3.4			—
Payments for surrendered options	—			(5.2		)	(141.6		)	(15.6		)
Environmental expenditures	(6.3		)	(16.4		)	(22.6		)	(29.5		)
Decrease (increase) in non-cash working capital	42.4			(10.0		)	(1.8		)	23.7
	368.7			206.2			932.8			816.8
Investing activities
Additions to property, plant and equipment, net	(6.3		)	(229.0		)	(456.7		)	(865.6		)
Decrease (increase) in non-cash working capital	15.0			81.4			(63.2		)	50.0
	8.7			(147.6		)	(519.9		)	(815.6		)
Financing activities
(Decrease) increase in bank loan	(236.2		)	(52.5		)	(51.4		)	72.6
Issue of equity	2.4			0.6			23.7			5.2
Realized foreign exchange gain	—			—			85.8			28.5
Distributions/dividends paid	(143.6		)	(6.7		)	(288.4		)	(107.6		)
Plan of arrangement costs	—			—			(36.3		)	—
Settlement of future income tax liabilities	—			—			(146.3		)	—
Decrease in non-cash working capital	—			—			—			0.1
	(377.4		)	(58.6		)	(412.9		)	(1.2		)
Change in cash	—			—			—			—
Cash, beginning of period	—			—			—			—
Cash, end of period	$	—		$	—		$	—		$	—
Interest paid	$	6.3		$	4.3		$	22.9		$	17.0
Income and capital taxes paid (recovered)	$	15.4		$	2.4		$	241.2		$	(9.5	)

See accompanying notes to the unaudited interim consolidated financial statements.

Notes to the Unaudited Interim Consolidated Financial Statements ($ millions, except per unit amounts):

1. SIGNIFICANT ACCOUNTING POLICIES AND BASIS OF PRESENTATION

On May 31, 2005, Penn West Petroleum Ltd. (the “Company”) was reorganized into Penn West Energy Trust (the “Trust”) under a plan of arrangement (the “Plan”) entered into by the Trust and the Company and its shareholders. Shareholders received three trust units for each common share held. On June 2, 2005, the trust units commenced trading on the TSX under the symbol “PWT.UN”. The Trust was created pursuant to a trust indenture dated April 22, 2005 with CIBC Mellon Trust Company appointed trustee.

The Trust is an open-ended, unincorporated investment trust governed by the laws of the Province of Alberta. The purpose of the Trust is to indirectly explore for, develop and hold interests in petroleum and natural gas properties through investments in securities of subsidiaries and royalty interests in oil and natural gas properties. The Trust owns 100% of the common shares of the Company that carries on the business of the Trust. The activities of the Company are financed through interest bearing notes from the Trust and third party debt as described in the notes to the financial statements.

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Pursuant to the terms of an NPI agreement (the “NPI”), the Trust is entitled to a payment from the Company equal to essentially all of the proceeds of the sale of production less certain specified deductions. Under the terms of the NPI, the deductions are discretionary and include the requirement to fund capital expenditures.

The Trust is required to make distributions to Unitholders in amounts equal to the income of the Trust earned from interest on certain notes, the NPI, and any dividends paid on the common shares of the Company, less any expenses of the Trust.

These unaudited interim consolidated financial statements have been prepared on a continuity of interest basis as if the Trust historically carried on the business of the Company. Prior to the Plan on May 31, 2005, the consolidated financial statements included the accounts of the Company and its subsidiaries. After giving effect to the Plan, the unaudited interim consolidated financial statements include the accounts of the Trust, its subsidiaries and partnerships. The unaudited interim consolidated financial statements have been prepared in accordance with Canadian generally accepted accounting principles and, except as detailed in note 2, are consistent with the accounting policies described in the notes to the audited consolidated financial statements of the Company for the year ended December 31, 2004.

2. CHANGE IN ACCOUNTING POLICIES

Earnings Per Share

The Trust adopted the new earnings per share (“EPS”) accounting recommendations effective January 1, 2005. The number of incremental shares included in diluted EPS is computed using the average market price of common shares for the year-to-date period. In addition, contracts that could be settled in cash or common shares are assumed settled in common shares if share settlement is more dilutive. Shares to be issued upon conversion of convertible instruments with a mandatory conversion feature would be included in the basic weighted average EPS calculation from the date when conversion becomes mandatory. These changes did not materially impact the Trust’s reported diluted EPS amounts.

Financial Instruments

Effective July 1, 2005, the Trust elected to discontinue the designation of commodity and power financial instruments as hedges, thus accounting for these instruments using the fair value method. In accordance with the accounting recommendations, the fair value of power contracts at July 1, 2005 in the amount of $16.7 million was recorded as a deferred gain and will be recognized into net income over the remaining life of the contracts. Future changes in the fair value of commodity and power contracts are reflected on the balance sheet with a corresponding unrealized gain or loss in income. See note 8 to the unaudited interim consolidated financial statements.

Stock-based Compensation

During the second quarter of 2005, pursuant to the plan of arrangement, the stock option plan was cancelled. Costs associated with the cancellation of outstanding stock options on conversion were charged to income as the stock option plan contained a cash settlement alternative. The Trust initiated a new trust unit rights incentive plan that is accounted for using the fair value based method. See note 6 to the unaudited interim consolidated financial statements.

3. PROPERTY ACQUISITION

In February 2004, the Company acquired producing properties in southwest Saskatchewan. Results of operations from these properties were included in the Trust’s results from February 1, 2004. The allocation of the purchase price to assets acquired and liabilities assumed was as follows:

Purchase price
Cash consideration	$	233.7
Working capital	9.8
	$	243.5
Net assets acquired
Property, plant and equipment	$	318.7
Future income tax liability	(54.8		)
Asset retirement obligations	(20.4		)
	$	243.5

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4. BANK LOAN

	As at December 31, 2005		As at December 31, 2004
Bankers’ acceptances	$	542.0	$	154.1
LIBOR advances (2004 US $290 million)	—		349.0
	$	542.0	$	503.1

As at December 31, 2005, the Trust had unsecured bank credit facilities of $1,220 million consisting of a $1,170 million credit facility and a $50 million operating loan facility, and had outstanding letters of credit totalling $9 million (2004 - $9 million) that reduced the amount otherwise available to be drawn on the operating facility. In Q1 2005, the Company converted US $205 million of its US denominated borrowings to Canadian dollars at an average exchange rate of $0.829 CAD/USD resulting in a realized foreign exchange gain of $63 million. In May 2005, the Company converted its remaining US $85 million of US denominated borrowings to Canadian dollars realizing an additional foreign exchange gain of $23 million.

5. ASSET RETIREMENT OBLIGATIONS

The total undiscounted, uninflated amount required to settle the asset retirement obligations at December 31, 2005 was $777 million (2004 - $737 million). The liability was determined by applying an inflation factor of 1.7 percent (2004 – 1.5 percent) and discounting the inflated amount using a credit adjusted rate of 7.5 percent (2004 – 7.5 percent) over the expected useful life of the underlying assets, which currently extends up to 50 years into the future with an average life of 22 years.

Changes to asset retirement obligations were as follows:

	2005			2004
Asset retirement obligations at January 1	$	180.7		$	172.8
Liabilities incurred during the period	9.8			18.6
Liabilities settled during the period	(22.6		)	(29.5		)
Increase in liability due to change in estimates	3.4			—
Accretion	21.1			18.8
Asset retirement obligations at December 31	$	192.4		$	180.7

6. UNIT AND STOCK-BASED COMPENSATION

Stock option plan

The stock option plan included a cash payment alternative and stock-based compensation costs were recorded based on changes to the share price at the end of each quarter and any changes to the number of outstanding options. Pursuant to the plan of arrangement, all stock options outstanding on the date of conversion were settled for cash of $84.77 per share or by issuing shares. The continuity of the compensation liability and outstanding options to the date of cancellation was as follows:

	2005			2004
Liability, January 1	$	91.9		$	27.9
Compensation expense provision	71.7			84.1
Cash payments on exercise of stock options	(141.6		)	(15.6		)
Liability settlements on stock options exercised for shares	(22.0		)	(4.5		)
Liability, December 31	—			91.9
Current portion	—			71.0
Long term portion	—			20.9
	$	—		$	91.9

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Penn West stock options	Number of stock options		Weighted average exercise price
Outstanding, January 1, 2005	3,728,980		$	39.00
Granted	82,600		79.51
Exercised for common shares	(488,399	)	34.72
Settled for cash	(3,212,931	)	40.51
Forfeited	(110,250	)	44.26
Outstanding, May 31, 2005	—		$	—

Trust unit rights incentive plan

In May 2005, the Trust implemented a unit rights incentive plan (the “TURIP”) that allows the Trust to issue rights to acquire trust units to directors, officers, employees and service providers. The number of trust units reserved for issuance shall not at any time exceed ten percent of the aggregate number of issued and outstanding trust units of the Trust. Unit right exercise prices are equal to the market price for the trust units based on the five-day weighted average market price prior to the date the unit rights are granted. If certain conditions are met, the exercise price per unit may be reduced by deducting from the grant price the aggregate of all distributions, on a per unit basis, paid by the Trust after the grant date. Rights granted under the plan vest over a five-year period and expire six years after the date of the grant.

Trust unit rights	Number of unit rights		Weighted average exercise price
Granted	10,045,325		$	29.73
Forfeited	(597,700	)	28.46
Balance before reduction of exercise price	9,447,625		$	29.81
Reduction of exercise price for distributions paid	—		(1.36		)
Outstanding, December 31, 2005	9,447,625		$	28.45
Exercisable, December 31, 2005	—		$	—

The Trust recorded compensation expense of $5.5 million from implementation of the TURIP to December 31, 2005. The compensation expense is based on the fair value of rights issued and is amortized over the remaining vesting periods on a straight-line basis. The Black-Scholes option pricing model was used to determine the fair value of trust unit rights granted with the following weighted average assumptions:

Seven months ended December 31	2005
Average fair value of trust unit rights granted (per unit)
Directors and officers	$	6.50
Other employees	$	6.13
Expected life of trust unit rights (years)
Directors and officers	5.0
Other employees	4.5
Expected volatility (average)	16		%
Risk free rate of return (average)	3.4		%
Expected distribution rate	Nil		*

* The expected distribution rate is assumed to be nil as it is expected that future distributions result in a reduction to the exercise price of trust unit rights.

Trust unit savings plan

The Trust has an employee trust unit savings plan for the benefit of all employees. Under the plan, employees may elect to contribute up to 10 percent of their salary. Pursuant to the plan, contributions are used to fund the acquisition of trust units. The Trust matches employee contributions at a rate of $1.50 for each $1.00 contributed. Trust units may be issued from treasury at the five-day weighted average month end market price or purchased in the open market.

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7.UNITHOLDERS’ CAPITAL

a.Authorized

i) An unlimited number of voting Trust Units, which are redeemable at the option of the unitholder at 95% of the lesser of the ten trading day average market price, and the closing market price on the day of redemption.

ii) An unlimited number of Special Voting Units, which enable the Trust to provide voting rights to holders of any exchangeable shares that may be issued by any direct or indirect subsidiaries of the Trust. Except for the right to vote, the Special Voting Units do not confer any other rights.

The Trust has a Distribution Reinvestment and Optional Trust Unit Purchase Plan (the “DRIP”) that provides eligible unitholders the opportunity to reinvest monthly cash distributions into additional units at a potential discount. Units are issued from treasury at 95 percent of the average market price when available. When units are not available from treasury they are acquired in the open market at prevailing market prices.

Unitholders who participate in the DRIP may also purchase additional units subject to a monthly maximum of $5,000 and a minimum of $500. Optional cash purchase units are acquired, without a discount, in the open market at prevailing market prices or issued from treasury at the average market price.

b.Issued

Penn West shareholders received three trust units for each common share held resulting in the issuance of 163,137,018 trust units in exchange for the common shares of Penn West pursuant to the plan of arrangement.

No special voting units were issued or are outstanding.

Common shares of Penn West	Shares		Amount
Balance, January 1, 2005	53,868,745		$	515.3
Issued on exercise of stock options	488,399		17.0
Issued to employee stock savings plan	21,905		1.8
Cancellation of certificates	(43	)	—
Liability settlements on stock options exercised for shares	—		22.0
Balance, May 31, 2005 prior to plan of arrangement	54,379,006		$	556.1
Exchanged for Trust units	(54,379,006	)	(556.1		)
Balance as at May 31, 2005	—		$	—

Trust units of Penn West Energy Trust	Units	Amount
Issued to settlor for cash, April 22, 2005	1,250	$	—
Exchanged for Penn West shares, May 31, 2005	163,137,018	556.1
Issued to employee trust unit savings plan	151,745	4.9
Balance as at December 31, 2005	163,290,013	$	561.0

c.Contributed Surplus

	2005		2004
Balance, January 1	$	—	$	—
Unit-based compensation expense	5.5		—
Balance as at December 31	$	5.5	$	—

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8.FINANCIAL INSTRUMENTS

The Trust had the following financial instruments outstanding as at December 31, 2005:

	Notional Volume	Remaining Term	Pricing	Market Value ($ millions)
Crude Oil
WTI Costless Collars	20,000 Bbls/d	Jan/06 - Dec/06	$US 47.50 to $67.86/Bbl	$	(22.1	)
Natural Gas
AECO Costless Collars	46,300 mcf/d	Jan/06 - Mar/06	$8.64 to $16.69/mcf	0.2
AECO Costless Collars	46,300 mcf/d	Jan/06 - Oct/06	$8.64 to $16.25/mcf	2.1
AECO Costless Collars	18,500 mcf/d	Jan/06 - Oct/06	$9.72 to $17.28/mcf	3.3
AECO Costless Collars	23,100 mcf/d	Apr/06 - Sept/06	$9.07 to $15.12/mcf	0.7
AECO Costless Collars	9,300 mcf/d	Apr/06 - Sept/06	$9.18 to $15.39/mcf	0.8
AECO Costless Collars	13,400 mcf/d	Oct/06 - Dec/06	$9.18 to $17.39/mcf	0.2
Electricity
Alberta Power Pool Swaps	60 MW	2006	$42.25 to $43.15/MWh	16.6
Alberta Power Pool Swaps	35 MW	2007	$46.00/MWh	$	6.7

Effective July 1, 2005, the Trust elected to discontinue the designation of commodity and power financial instruments as hedges, choosing to account for these instruments using the fair value method. In accordance with the accounting recommendations, the fair value of power contracts at July 1, 2005 in the amount of $16.7 million was recorded as a deferred gain and will be recognized into net income over the life of the contracts. Future changes in the fair value of commodity and power contracts will be recorded on the balance sheet with a corresponding unrealized gain or loss in income.

The following table reconciles the changes in the fair value of financial instruments no longer designated as effective accounting hedges:

Risk management:	2005
Balance June 30,	$	—
Deferred gain at June 30	16.7
Unrealized gain on financial instruments	(8.2		)
Fair value, December 31	$	8.5
Deferred gain on financial instruments:
Balance June 30	$	—
Deferred gain at June 30	(16.7		)
Amortization	4.8
Balance, December 31	$	(11.9	)

9. INCOME TAXES

Prior to the income trust conversion, a significant portion of the Trust’s taxable income was incurred in a partnership. This resulted in a significant portion of current income taxes being incurred on the partnership’s taxable income in the year following the year of inclusion in the Trust’s consolidated net income. Subsequent to the income trust conversion, a lower percentage of the Trust’s taxable income will be incurred in a partnership. It is expected that future income allocations to the Trust will compensate for future taxable income to be incurred in the Trust’s subsidiaries.

In the fourth quarter of 2005, a $28 million general future tax rate reduction was recorded. In the third quarter of 2005, a $3 million tax rate reduction was recorded to reflect British Columbia’s 1.5 percent general tax rate reduction. In the first quarter of 2004, a $20 million future income tax recovery was recorded to reflect the 2004 tax rate reduction enacted by the Government of Alberta.

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10. PLAN OF ARRANGEMENT COSTS

Effective May 31, 2005, Penn West commenced operations as an oil and gas income trust pursuant to a plan of arrangement approved by the shareholders on May 27, 2005. Certain amounts, related to the plan of arrangement, were charged to accumulated earnings as follows:

	Amount
Tax rate difference on current income taxes	$	13.3
Incremental capital taxes	13.4
Financial advisor fees	5.6
Filing fees, communication, professional fees and other	4.0
Future income taxes	(3.4		)
	$	32.9

11. RELATED PARTY TRANSACTIONS

The Trust incurred $2.1 million (2004 - $0.8 million) of legal expenses with a law firm, at which one of its directors is a partner.

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Investor Information

Penn West Energy Trust is a senior oil and natural gas income trust based in Calgary, Alberta that trades on the Toronto Stock Exchange under the symbol PWT.UN.

A conference call will be held to discuss Penn West’s results at 9:00 a.m. Mountain Time, 11:00 a.m. Eastern Time on Tuesday, February 28, 2006. The North American conference call number is 1-800-814-4861 and the local conference call number for Toronto is 416-644-3423. A taped recording will be available until Tuesday, March 7, 2006 by dialing 1-877-289-8525 or 416-640-1917 and entering pass code 21172569#. This call will be broadcast live on the internet and may be accessed directly on the Penn West website www.pennwest.com or at the following URL: http://www.newswire.ca/en/webcast/viewEvent.cgi?eventID=1343980

Notes to Reader

1.This document contains forward-looking statements (forecasts) under applicable securities laws. Forward—looking statements are necessarily based upon assumptions and judgements with respect to the future including, but not limited to, the outlook for commodity markets and capital markets, the performance of producing wells and reservoirs, and the regulatory and legal environment. Many of these factors can be difficult to predict. As a result, the forward-looking statements are subject to known or unknown risks and uncertainties that could cause actual results to differ materially from those anticipated or implied in the forward-looking statements.

2.All dollar amounts contained in this document are expressed in millions of Canadian dollars unless noted otherwise.

3.Where applicable, natural gas has been converted to barrels of oil equivalent (boe) using a conversion rate of 6 mcf of natural gas equals 1 boe, however, this could be misleading if used in isolation. A boe conversion ratio of 6 mcf to1 bbl is based on an energy equivalency conversion method primarily applicable at the burner tip and does not represent a value equivalency at the wellhead.

For further information, please contact:

PENN WEST ENERGY TRUST

Suite 2200, 425 - First Street S.W.

Calgary, Alberta  T2P 3L8

Phone: 403-777-2500

Fax: 403-777-2699

Toll Free: 1-866-693-2707

Website: www.pennwest.com

E-mail: investor_relations@pennwest.com

William Andrew, President and CEO

Phone:  (403) 777-2502

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