Exhibit 99.1

Quarterly Report

For the three and six months ended June 30, 2007

Operations

· Production averaged 126,599 boe per day in the second quarter of 2007 compared to 93,242 boe per day in the same period of 2006. The previously announced fire at our Wildboy tank farm reduced reported second quarter 2007 gas production by approximately 20 mmcf per day (approximately 3,300 barrels of oil equivalent).

· Crude oil and NGL production averaged 70,923 barrels per day and natural gas production averaged 334 mmcf per day in the second quarter of 2007.

· Penn West invested $484 million on capital development that included $351 million of net property acquisitions and drilled 13 net wells in the second quarter with a success rate of 92 percent.

Financial

· Cash flow of $326 million ($1.37 per unit, basic) in the second quarter of 2007 was 23 percent higher than cash flow of $265 million ($1.59 per unit, basic) realized in the second quarter of 2006, mainly due to higher production as a result of the Petrofund merger reflected from July 1, 2006 forward.

· The net loss in the second quarter of 2007 was $185 million ($0.77 per unit, basic) compared to net income of $221 million ($1.34 per unit, basic) in the second quarter of 2006, mainly due to a $326 million future income tax charge taken to reflect the enactment of the tax on income trusts (the “SIFT tax”).

· In the absence of the charge to reflect the SIFT tax enactment, net income for the second quarter and first half of 2007 would have been $140 million ($0.59 basic per unit) and $237 million ($0.99 basic per unit), respectively.

· After the acquisition of approximately 80 percent of the shares of C1 Energy Ltd. by July 23, 2007, a notice of extension was subsequently mailed extending the offer to August 3, 2007.

· On May 31, 2007, Penn West Petroleum Ltd. issued US$475 million of unsecured notes maturing in eight to 15 years on a private placement basis in the United States. The Company used the proceeds of the notes to repay a portion of the outstanding bank debt under its credit facilities.

Distributions

· Penn West’s Board of Directors recently resolved to keep our distribution level at $0.34 per unit, per month, for the next three months subject to current forecasts of commodity prices, production and planned capital expenditures.

Distribution Tax

· In June 2007, the Government of Canada enacted the previously announced tax on publicly traded income trusts. This resulted in the accounting recognition of an additional $326 million future income tax liability and a non-cash future income tax expense in the second quarter of 2007. The tax enactment and the related charge against income did not affect cash flow or distributions in the quarter and is not expected to affect our distribution policies until 2011 at the earliest. Penn West will remain active with various parties pursuing a re-evaluation of the tax legislation and continues to review various tax efficient structural alternatives.

Long-term Project Updates

· In the second half of 2007, in addition to ongoing geological and engineering studies and pilot tests, Penn West plans to drill an additional 19 horizontal wells and 14 stratigraphic test wells in its Peace River Oil Sands project. We expect to complete the tie-in of 41 producing wells to recently constructed production facilities by August 2007, to significantly increase netbacks by reducing trucking costs. The previously announced acquisition of producing light oil and natural gas properties, undeveloped lands, additional infrastructure and all-weather roads in the project area will be important in the development of the project area.

· During the second quarter, we continued to evaluate an integrated approach to enhancing our light oil recovery rates from large, legacy oil pools using miscible flooding with CO2 captured from heavy industry gasification processes while at the same time helping to sequester greenhouse gases. At our Pembina CO2 pilot project, we plan to drill four horizontal wells in the third quarter which we expect to be on-stream by the first quarter of 2008. We are de-watering our four wells drilled to date at our South Swan Hills coalbed methane pilot project and are assessing potential future coalbed methane development programs in the area.

HIGHLIGHTS

	Three months ended June 30							Six months ended June 30
($ millions, except per unit						%							%
and production amounts)	2007			2006		change		2007			2006		change
Financial

Gross revenues (1)	$	608.3		$	452.5	34		$	1,190.7		$	886.4	34
Cash flow	326.2			264.7		23		637.5			507.9		26
Basic per unit	1.37			1.59		(14	)	2.68			3.08		(13	)
Diluted per unit	1.35			1.56		(13	)	2.65			3.03		(13	)
Net (loss) income	(185.2		)	220.5		(184	)	(88.9		)	364.9		(124	)
Basic per unit	(0.77		)	1.34		(157	)	(0.37		)	2.22		(117	)
Diluted per unit	(0.77		)	1.31		(159	)	(0.37		)	2.18		(117	)
Capital expenditures, net	483.6			105.8		357		699.5			263.8		165
Long-term debt at period-end	1,822.5			1,369.7		33		1,822.5			1,369.7		33
Distributions paid (2)	$	243.1		$	167.4	45		$	485.2		$	324.3	50

Operations

Daily production
Natural gas (mmcf/d)	334.1			267.9		25		337.2			267.4		26
Light oil and NGL (bbls/d)	49,635			29,974		66		49,372			30,755		61
Conventional heavy oil (bbls/d)	21,288			18,625		14		21,945			19,648		12
Total production (boe/d)	126,599			93,242		36		127,518			94,968		34

Average sales price
Natural gas ($/mcf)	$	7.55		$	6.14	23		$	7.57		$	7.12	6
Light oil and NGL ($/bbl)	65.24			71.96		(9	)	62.39			66.93		(7	)
Conventional heavy oil ($/bbl)	$	42.45		$	52.85	(20	)	$	41.73		$	41.29	1
Netback per boe
Sales price	$	52.63		$	51.33	3		$	51.35		$	50.26	2
Risk management	0.03			2.00		(99	)	0.16			1.30		(88	)
Net sales price	52.66			53.33		(1	)	51.51			51.56		—
Royalties	9.82			9.45		4		9.72			9.59		1
Operating expenses	10.94			10.26		7		10.82			10.07		7
Transportation	0.52			0.60		(13	)	0.53			0.64		(17	)
Netback	$	31.38		$	33.02	(5	)	$	30.44		$	31.26	(3	)

The above information includes non-GAAP measures not defined under generally accepted accounting principles, including cash flow and netback. Cash flow is cash flow from operating activities before changes in non-cash working capital, and asset retirement expenditures. Please refer to the calculation of cash flow table on the first page of the Management’s Discussion and Analysis for a reconciliation of cash flow from operating activities to cash flow. Barrels of oil equivalent (boe) are based on six mcf of natural gas equalling one barrel of oil (6:1). Netback is a per unit of production measure of operating margin used in capital allocation decisions.

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

(2) Includes distributions paid in trust units under the distribution reinvestment plan.

drilling program

	Three months ended June 30						Six months ended June 30
	2007			2006			2007			2006
	Gross	Net		Gross	Net		Gross	Net		Gross	Net
Natural gas	5	3		12	5		54	25		80	64
Oil	24	8		23	21		77	44		64	55
Dry	1	1		1	1		5	4		11	11
	30	12		36	27		136	73		155	130
Stratigraphic and service	4	1		1	1		19	15		9	6
Total	34	13		37	28		155	88		164	136
Success Rate (1)		92	%		96	%		95	%		92	%

(1) Success rate is calculated excluding stratigraphic and service wells.

UNDEVELOPED LANDS

	As at June 30
	2007		2006		% change
Gross acres (000s)	3,969		4,825		(18	)
Net acres (000s)	3,470		4,305		(19	)
Average working interest	87	%	89	%	(2	)

FARM-OUT ACTIVITY

	Three months ended June 30		Six months ended June 30
	2007	2006	2007	2006
Wells drilled on farm-out lands (1)	16	26	106	54

(1) Wells drilled on Penn West lands, including re-completions and re-entries, by independent operators pursuant to farm-out agreements.

CORE AREA ACTIVITY

	Net wells drilled for the six	Undeveloped land as at June 30, 2007
Core Area	months ended June 30, 2007	(thousands of net acres)
Central	51	1,308
Plains	35	1,006
Northern	2	1,156
	88	3,470

TRUST UNIT DATA

Three months ended June 30

Six months ended June 30

(millions of units)

2007

2006

% change

2007

2006

% change

Weighted average

Basic

239.0

165.8

238.0

164.6

Diluted

241.5

168.7

240.3

167.6

Outstanding as at June 30

Basic

239.2

235.3

Basic plus trust unit rights

253.7

246.0

Charting our Performance

Letter to our Unitholders

During the second quarter of 2007, Penn West continued to advance all of its significant initiatives. These included the continuing execution of our conventional asset development and optimization plans, the evaluation of our Peace River Oil Sands project, the advancement of our Pembina CO2 pilot, and continuing engineering, planning and pilot testing to set up commercial CO2 enhanced oil recovery programs on some of the largest legacy light oil pools in Western Canada. We continue to focus our efforts on controlling our lifting costs and capital efficiencies while enhancing our health, safety and environmental stewardship programs.

In April 2007, we closed the acquisition of light oil and natural gas assets and infrastructure that includes important processing infrastructure and all-weather roads in our Peace River Oil Sands project area. In May 2007, we announced a take-over bid for the shares of C1 Energy Ltd. (“C1”) for $0.20 per share, or a total acquisition cost of approximately $23 million, which we closed in late July 2007. We also closed the issuance of US$475 million of unsecured notes with fixed terms ranging from eight to 15 years. The proceeds from the notes were used to repay a portion of our bank credit facilities. In June 2007, Shirley McClellan was elected as a director of Penn West. Mrs. McClellan will bolster our Board using her experience gained during her distinguished career with the Government of Alberta, which included the offices of Minister of Finance and Deputy Premier.

Cash flow in the second quarter of 2007 was $326 million or $1.37 per unit basic compared to $311 million or $1.31 per unit basic in the first quarter of 2007 and $265 million or $1.59 per unit basic in the second quarter of 2006. For 2007, we expect to generate cash flow between $1.3 billion and $1.4 billion from forecast production of between 129,000 and 132,000 barrels of oil equivalent per day. Subject to this forecast cash flow and capital expenditures, our Board of Directors recently resolved to maintain our distributions at $0.34 per unit per month for the next three months. Production averaged 126,600 barrels of oil equivalent in the second quarter of 2007 compared to 128,447 and 93,242 barrels of oil equivalent in first quarter of 2007 and second quarter of 2006 respectively. The increases in the 2007 production and cash flow over the second quarter of 2006 primarily reflects the Petrofund merger we closed on June 30, 2006 partially offset by the stronger Canadian dollar. The tank farm fire at our Wildboy gas plant reduced our reported natural gas production in the second quarter of 2007 by approximately 20 mmcf per day (approximately 3,300 barrels of oil equivalent per day). We have since restored production at Wildboy to approximately 50 percent of the pre-fire level and expect to have production fully restored by October 2007. We expect that our property insurance will cover the majority of the capital costs to replace the damaged equipment and that our business interruption insurance will cover a significant portion of the lost cash flow.

Operationally, at our Peace River Oil Sands project, we elected to increase our focus on delineating the resources contained in our 300,000 net acres of oil sands leases in the area by scaling back the pace of our development drilling. In addition to the 19 horizontal wells planned to be drilled before year-end, we are also planning a total of 38 stratigraphic test wells, 3-D seismic programs and area mapping over the next six to nine months. To increase our netbacks from the area, we are currently connecting 41 producing wells to our central oil processing battery, thereby eliminating all associated trucking costs. By year-end, we expect to have completed the drilling and facility construction related to a six-well water flood pilot project in our Seal Main area.

On the CO2 enhanced oil recovery side, we are expanding our Pembina CO2 pilot project to include four new horizontal wells and one new vertical well, and plan to commence injecting CO2 by the first quarter of 2008. At South Swan Hills, we expect our eight-well vertical CO2 pilot will be operational by January 2008 and are continuing to de-water our four horizontal wells at our Mannville coalbed methane pilot project.

The proposed tax on income trusts (the “trust tax”) received Royal Assent in the House of Commons on June 22. Currently, Penn West will be subject to the new tax under this legislation effective in 2011 and may increase its equity by approximately $10 billion over the period to 2011 without pre-maturely triggering the trust tax. As a result of the tax enactment in the second quarter, Penn West recorded a $326 million non-cash future income tax charge against income, which led to our first reported quarterly loss since 1992. The charge has no impact on our cash flow and hence has no effect on our distributions. Excluding the charge, second quarter 2007 net income would have been $140 million ($0.59 per unit, basic) compared to $96 million ($0.41 per unit, basic) in the first quarter of 2007. Based on our current forecasts, little or no trust or corporate income tax will be paid until approximately 2014. Our efforts to obtain a re-evaluation of the trust tax are continuing in collaboration with other parties.

Over the remainder of 2007, we will work diligently to restore production at Wildboy and advance all of our conventional and non-conventional projects. On behalf of our Board of Directors, I wish to thank Jeffery Errico for his counsel as a Director of Penn West since the merger with Petrofund in June 2006. Mr. Errico did not stand for re-election to our Board due to personal reasons.

On behalf of the Board of Directors,

William E. Andrew

President and CEO

Calgary, Alberta

August 1, 2007

MANAGEMENT’S DISCUSSION AND ANALYSIS

For the six months ended June 30, 2007

This management’s discussion and analysis (“MD&A”) of financial conditions and results of operations should be read in conjunction with the unaudited interim consolidated financial statements of Penn West Energy Trust (“Penn West”, “the Trust”, “we” or “our”) for the three and six months ended June 30, 2007 and the audited consolidated financial statements and MD&A for the year ended December 31, 2006. The date of this MD&A is August 1, 2007.

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

Please refer to our disclaimer on forward-looking statements at the end of this MD&A. The calculations of barrels of oil equivalent (“boe”) are based on a conversion ratio of six thousand cubic feet of natural gas to one barrel of crude oil. This could be misleading if used in isolation as it is based on an energy equivalency conversion method primarily applicable at the burner tip and does not represent a value equivalency at the wellhead.

Measures including cash flow, cash flow per unit-basic, cash flow per unit-diluted and netbacks included in this MD&A are not defined in generally accepted accounting principles (“GAAP”) and do not have a standardized meaning prescribed by GAAP; accordingly, they may not be comparable to similar measures provided by other issuers. Management utilizes cash flow and netbacks to assess financial performance, to allocate its capital among alternative projects and to assess our capacity to fund distributions and future capital programs. Reconciliations of non-GAAP measures to their nearest measure prescribed by GAAP are provided below.

Calculation of Cash Flow

	Three months ended June 30				Six months ended June 30
($ millions, except per unit amounts)	2007		2006		2007		2006
Cash flow from operating activities	$	316.5	$	218.7	$	613.3	$	426.4
Increase in non-cash working capital	0.9		43.4		5.7		72.0
Asset retirement expenditures	8.8		2.6		18.5		9.5
Cash flow	$	326.2	$	264.7	$	637.5	$	507.9

Basic per unit	$	1.37	$	1.59	$	2.68	$	3.08
Diluted per unit	$	1.35	$	1.56	$	2.65	$	3.03

Quarterly Financial Summary

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

	Penn West Energy Trust
	June 30			Mar. 31		Dec. 31		Sept. 30		June 30		Mar. 31		Dec. 31		Sept. 30
Three months ended	2007			2007		2006		2006		2006		2006		2005		2005
Gross revenues (1)	$	608.3		$	582.4	$	578.5	$	636.0	$	452.5	$	433.9	$	554.5	$	535.0
Cash flow	326.2			311.3		303.3		365.6		264.7		243.2		332.6		334.9
Basic per unit	1.37			1.31		1.23		1.55		1.59		1.49		2.03		2.06
Diluted per unit	1.35			1.30		1.22		1.53		1.56		1.47		2.03		2.04
Net (loss) income	(185.2		)	96.3		122.9		177.8		220.5		144.4		241.1		209.5
Basic per unit	(0.77		)	0.41		0.44		0.66		1.34		0.88		1.48		1.29
Diluted per unit	(0.77		)	0.40		0.44		0.65		1.31		0.87		1.46		1.27
Distributions declared	243.5			242.4		241.5		240.7		167.6		162.0		151.8		127.3
Per unit	1.02			1.02		1.02		1.02		1.02		0.99		0.93		0.78
Production
Liquids (2) (bbls/d)	70,923			71,716		70,819		69,215		48,599		52,226		51,953		51,634
Natural gas (mmcf/d)	334.1			340.4		354.6		359.1		267.9		266.9		277.5		289.0
Total (boe/d)	126,599			128,447		129,915		129,059		93,242		96,713		98,205		99,802

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

(2) Includes crude oil and natural gas liquids.

Enactment of the Tax on Income Trusts

On June 12, 2007, the legislation implementing the new tax on publicly traded income trusts and limited partnerships (the “SIFT tax”), referred to as “Specified investment flow-through” (“SIFT”) entities (Bill C-52) received third reading in the House of Commons and on June 22, 2007, the Bill received Royal Assent. As a result, the tax was considered to be enacted for accounting purposes in June 2007.

SIFTs are certain publicly traded income and royalty trusts and limited partnerships including Penn West. For SIFTs in existence on October 31, 2006, the SIFT tax will be effective in 2011 unless certain rules related to “undue expansion” are not adhered to. Under the guidance provided, we can increase our equity by approximately $10 billion between now and 2011 without prematurely triggering the SIFT tax.

Under the SIFT tax, distributions will not be deductible for income tax purposes by SIFTs in 2011 and thereafter and any trust level taxable income will be taxed at an approximate of the corporate income tax rate currently estimated to be 31.5 percent. The resultant distributions will be considered taxable dividends to unitholders, generally eligible for the dividend tax credit. Distributions representing a return of capital for income tax purposes will continue to be an adjustment to a unitholder’s adjusted cost base of trust units.

For accounting purposes, as the SIFT tax was enacted in the second quarter of 2007, Penn West recorded a non-cash charge of $326 million to future income taxes to reflect the current temporary differences between the book and tax basis of assets and liabilities expected to be remaining in the Trust in 2011. The majority of the temporary differences at the Trust level arose on the merger with Petrofund on June 30, 2006.

Our Board of Directors and Management continue to review the impact of this tax on our business strategy. We expect future technical interpretations and details will further clarify the legislation. At the present time, Penn West believes some or all of the following actions will or could result due to the enactment of the SIFT tax:

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

· A portion of Penn West’s cash flow could be allocated to the payment of the SIFT tax, or other forms of tax, and would not be available for distribution or re-investment;

· Penn West could convert to a corporate structure to facilitate investing a higher proportion or all of its cash flow in exploration and development projects. Such a conversion and change to capital programs could result in a significant reduction to, or elimination of, distributions and/or dividends;

· Penn West might determine that it is more economic to remain in the trust structure, at least for a period of time, and shelter its taxable income using tax pools and pay all or a portion of its distributions on a return of capital basis, likely at a lower payout ratio. Further, as the SIFT tax rate exceeds the corporate income tax rate that would be applicable to Penn West, some corporate tax might be paid resulting in all or a portion of distributions being paid on a return of capital basis at a lower payout ratio;

The Trust is reviewing all organizational structures and alternatives to minimize the impact of the SIFT tax on our unitholders. While there can be no assurance that the negative effect of the tax can be minimized or eliminated, Penn West and its advisors will continue to work diligently on these issues.

The table below, provided by the Government of Canada in a backgrounder accompanying its October 31, 2006 announcement, shows a simplified comparison of the effects of the changes to investor tax rates in 2011;

	Current System				Proposed System
	Income portion		Large		Income portion
	of trust		corporation		of trust		Large corporation
Investor	distributions		(dividend)		distributions		(dividend)
Taxable Canadian individuals (1)	46	%	46	%	45.5	%	45.5	%
Canadian tax-exempt investors	0	%	32	%	31.5	%	31.5	%
Taxable U.S. investors (2)	15	%	42	%	41.5	%	41.5	%

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

(2) Canadian taxes only. U.S. tax will also apply in most cases, net of any foreign tax credits.

RESULTS OF OPERATIONS

Production

	Three months ended June 30			Six months ended June 30
Daily production	2007	2006	% change	2007	2006	% change
Natural gas (mmcf/d)	334.1	267.9	25	337.2	267.4	26
Light oil and NGL (bbls/d)	49,635	29,974	66	49,372	30,755	61
Conventional heavy oil (bbls/d)	21,288	18,625	14	21,945	19,648	12
Total production (boe/d) (1)	126,599	93,242	36	127,518	94,968	34

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

The increase in production was due to the Petrofund merger closing at the end of June 2006, and to our development and optimization programs. Production in the second quarter of 2007 was slightly below the 128,447 boe per day produced in the first quarter of 2007 due to a fire at our 100% owned Wildboy natural gas plant during mid-May reducing production by approximately 3,300 boe per day for the quarter. Partial production was restored at the property in June 2007.

We strive to maintain an approximately balanced portfolio of liquids and natural gas production provided it is economic to do so. We believe a balance by product helps to reduce exposure to price volatility that can affect a single commodity. In the second quarter of 2007, crude oil and NGL production averaged 70,923 barrels per day (56 percent of production) and natural gas production averaged 334.1 mmcf per day (44 percent of production).

We drilled 13 net wells in the second quarter of 2007, mainly in the Central and Plains areas, compared to 28 in the same period of 2006.

Commodity Markets

Natural Gas

Following exceptional volatility through the winter, natural gas price movements have been relatively muted through the spring, with mild weather providing little incentive to move prices in either direction. Lower natural gas storage levels were offset by weaker demand due to the milder weather. Spot natural gas prices at AECO in the second quarter of 2007 decreased by $0.09 per mcf or one percent from the prior quarter to average $7.37 per mcf. Penn West’s average natural gas price in the second quarter of 2007 exceeded AECO spot prices due to the use of fixed price, short-term, physical natural gas contracts. Spot natural gas prices were $1.07 per mcf or 18 percent higher than the second quarter of 2006.

Crude Oil

Due to concerns related to crude oil inventory levels resulting from mild winter weather in the first quarter of 2007, crude oil prices were relatively weak early in the first quarter of 2007 but subsequently recovered in the second quarter of 2007. OPEC production cuts combined with strong North American demand resulted in continued high prices. The Edmonton par price for light, sweet crude oil weakened relative to WTI in the quarter as the Canadian dollar strengthened relative to the US dollar. Heavy oil differentials widened relative to Edmonton par, with Bow River differentials averaging $22.31 per barrel in the second quarter of 2007 compared to $18.86 per barrel in the same quarter of 2006.

Average Sales Prices Received

	Three months ended June 30							Six months ended June 30
	2007		2006			% change		2007		2006			% change

Natural gas ($/mcf)	$	7.55	$	6.14		23		$	7.57	$	7.12		6
Risk management ($/mcf)	0.01		0.93			(99	)	0.04		0.58			(93	)
Natural gas net ($/mcf)	7.56		7.07			7		7.61		7.70			(1	)

Light oil and liquids ($/bbl)	65.24		71.96			(9	)	62.39		66.93			(7	)
Risk management ($/bbl)	—		(2.11		)	(100	)	0.18		(1.04		)	(117	)
Light oil and liquids net ($/bbl)	65.24		69.85			(7	)	62.57		65.89			(5	)

Conventional heavy oil ($/bbl)	42.45		52.85			(20	)	41.73		41.29			1

Weighted average ($/boe)	52.63		51.33			3		51.35		50.26			2
Risk management ($/boe)	0.03		2.00			(99	)	0.16		1.30			(88	)
Weighted average net ($/boe)	$	52.66	$	53.33		(1	)	$	51.51	$	51.56		—

Netbacks

	Three months ended June 30							Six months ended June 30
	2007		2006			% change		2007		2006			% change
Natural gas
Production (mmcf/day)	334.1		267.9			25		337.2		267.4			26
Operating netback ($/mcf):
Sales price	$	7.55	$	6.14		23		$	7.57	$	7.12		6
Risk management (2)	0.01		0.93			(99	)	0.04		0.58			(93	)
Royalties	1.64		1.45			13		1.65		1.63			1
Operating costs	1.10		0.97			13		1.08		0.96			13
Transportation	0.20		0.21			(5	)	0.20		0.22			(9	)
Netback	$	4.62	$	4.44		4		$	4.68	$	4.89		(4	)
Light oil and NGL
Production (bbls/day)	49,635		29,974			66		49,372		30,755			61
Operating netback ($/bbl):
Sales price	$	65.24	$	71.96		(9	)	$	62.39	$	66.93		(7	)
Risk management (2)	—		(2.11		)	(100	)	0.18		(1.04		)	(117	)
Royalties	11.29		10.57			7		11.02		10.69			3
Operating costs	15.28		16.10			(5	)	15.21		15.75			(3	)
Netback	$	38.67	$	43.18		(10	)	$	36.34	$	39.45		(8	)
Conventional heavy oil
Production (bbls/day)	21,288		18,625			14		21,945		19,648			12
Operating netback ($/bbl):
Sales price	$	42.45	$	52.85		(20	)	$	41.73	$	41.29		1
Royalties	6.38		9.39			(32	)	6.33		7.45			(15	)
Operating costs	12.15		11.49			6		12.12		11.00			10
Transportation	0.03		—			—		0.05		0.08			(38	)
Netback	$	23.89	$	31.97		(25	)	$	23.23	$	22.76		2
Total liquids
Production (bbls/day)	70,923		48,599			46		71,317		50,403			41
Operating netback ($/bbl):
Sales price	$	58.40	$	64.64		(10	)	$	56.03	$	56.93		(2	)
Risk management (2)	—		(1.30		)	(100	)	0.12		(0.63		)	(119	)
Royalties	9.82		10.12			(3	)	9.58		9.43			2
Operating costs	14.34		14.33			—		14.26		13.90			3
Transportation	0.01		—			—		0.02		0.03			(33	)
Netback	$	34.23	$	38.89		(12	)	$	32.29	$	32.94		(2	)
Combined totals
Production (boe/day)(1)	126,599		93,242			36		127,518		94,968			34
Operating netback ($/boe):
Sales price	$	52.63	$	51.33		3		$	51.35	$	50.26		2
Risk management (2)	0.03		2.00			(99	)	0.16		1.30			(88	)
Royalties	9.82		9.45			4		9.72		9.59			1
Operating costs	10.94		10.26			7		10.82		10.07			7
Transportation	0.52		0.60			(13	)	0.53		0.64			(17	)
Netback	$	31.38	$	33.02		(5	)	$	30.44	$	31.26		(3	)

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

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

Production Revenues

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

	Three months ended June 30						Six months ended June 30
($ millions)	2007		2006		% change		2007		2006		% change
Natural gas	$	231.4	$	172.4	34		$	465.8	$	372.7	25
Light oil and NGL	294.7		190.5		55		559.2		366.8		52
Conventional heavy oil	82.2		89.6		(8	)	165.7		146.9		13
Gross revenues (1)	$	608.3	$	452.5	34		$	1,190.7	$	886.4	34

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

Increases (Decreases) in Production Revenues

($ millions)
Gross revenues – January 1 – June 30, 2006	$	886.4
Increase in light oil and NGL production	222.0
Decrease in light oil and NGL prices (including realized risk management)	(29.6		)
Increase in conventional heavy oil production	17.2
Increase in conventional heavy oil prices	1.7
Increase in natural gas production	97.3
Decrease in natural gas prices (including realized risk management)	(4.3		)
Gross revenues – January 1 – June 30, 2007	$	1,190.7

Royalties

	Three months ended June 30					Six months ended June 30
	2007		2006		% change	2007		2006		% change
Royalties ($ millions)	$	113.1	$	80.1	41	$	224.4	$	165.7	35
Average royalty rate (%)	19		18		6	19		19		—
$/boe	$	9.82	$	9.45	4	$	9.72	$	9.59	1

Expenses

	Three months ended June 30					Six months ended June 30
($ millions)	2007		2006		% change	2007		2006		% change
Operating	$	126.0	$	87.2	45	$	249.7	$	173.1	44
Transportation	6.0		5.0		20	12.1		10.8		12
Financing	24.3		8.4		189	40.5		14.8		174
Unit-based compensation	$	5.0	$	2.4	108	$	9.8	$	5.4	81

	Three months ended June 30						Six months ended June 30
($/boe)	2007		2006		% change		2007		2006		% change
Operating	$	10.94	$	10.26	7		$	10.82	$	10.07	7
Transportation	0.52		0.60		(13	)	0.53		0.64		(17	)
Financing	2.12		1.00		112		1.76		0.87		102
Unit-based compensation	$	0.44	$	0.29	52		$	0.42	$	0.32	31

Operating

With the continued strong draw on skilled labour and services by the large oil sands projects in Northern Alberta, oil and natural gas producers in the Western Canada Sedimentary Basin continued to experience inflationary, albeit moderating, pressure on operating costs in the second quarter of 2007. A higher proportion of liquids production, combined with production interruptions, also contributed to higher per unit operating costs in 2007 than the comparative second quarter 2006 period. The addition of the Petrofund assets, effective July 1, 2006 with higher operating costs, also contributed to the increase.

In 2006, as natural gas prices fell from close to record highs, some significant oil and natural gas companies cut their capital programs related to natural gas helping to reduce demand for oilfield services, particularly drilling and service rigs. The effect of lower activity, combined with internal Penn West initiatives specifically targeted at reducing operating costs, resulted in the operating cost per barrel of oil equivalent in the second quarter of 2007 being approximately equal to the first quarter of 2007 and fourth quarter of 2006.

A realized gain of $2.0 million (2006 - $2.2 million) on our electricity contracts has been included in the operating costs for the first half of the year.

Financing

The 2007 increase in interest expense was due to both an increase in the average outstanding debt balance and increases in short-term interest rates over 2006. The short end of the yield curve has increased due to rate increases by the central bank in Canada. The increased average loan balance was principally due to the $610 million of debt assumed with the Petrofund merger on June 30, 2006 and the $330 million property acquisition that closed in April 2007.

Penn West Petroleum Ltd. (“the Company”) closed the placement of US$475 million of notes on May 31, 2007. The interest rates on the notes are fixed at 5.68 to 6.05 percent for fixed terms of eight to 15 years. In addition, the Company has swaps on $100 million of bank debt that fix the interest rate at approximately 4.36 percent until March 2008. The interest rate on the balance of the Company’s long-term debt is currently issued to short-term, floating interest rate debt instruments.

Unit-Based Compensation

Unit-based compensation expense related to Penn West’s Trust Unit Rights Incentive Plan is based on the fair value of trust unit rights issued, determined using the Binomial Lattice option-pricing model. The unit-based compensation expense was $5.0 million for the three months ended June 30, 2007, of which $1.3 million was charged to operating expense and $3.7 million was charged to general and administrative expense (2006 - $2.4 million, $0.6 million and $1.8 million respectively). Unit-based compensation expense is based on the fair value of rights issued and is amortized over the remaining vesting periods on a straight-line basis.

General and Administrative Expenses

	Three months ended June 30					Six months ended June 30
($ millions, except per boe amounts)	2007		2006		% change	2007		2006		% change
Gross	$	20.9	$	13.4	56	$	41.9	$	25.5	64
Per boe	1.81		1.58		15	1.81		1.48		22
Net	12.7		7.1		79	26.5		14.1		88
Per boe	$	1.10	$	0.83	33	$	1.15	$	0.82	40

Increases in total and per boe general and administrative costs in 2007 were due to higher staff levels following the Petrofund merger and higher compensation costs. The cost of hiring, compensating and retaining employees and consultants, including the recruitment of professional staff dedicated to optimizing and controlling field operating costs, remains high due to strong demand for staff, particularly those with specialized training and experience. More onerous regulatory compliance activities also contributed to the increase.

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

	Three months ended June 30					Six months ended June 30
($ millions, except per boe amounts)	2007		2006		% change	2007		2006		% change
Depletion of oil and natural gas assets (1)	$	212.2	$	104.1	104	$	421.2	$	210.9	100
Accretion of asset retirement obligation (2)	6.2		5.8		7	12.1		11.5		5
Total DD&A	218.4		109.9		99	433.3		222.4		95
DD&A expense per boe	$	18.95	$	12.96	46	$	18.77	$	12.94	45

(1) Includes depletion of the capitalized portion of the asset retirement obligation.

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

Higher DD&A expense in 2007 versus 2006 was due to the Petrofund merger in 2006. The merger was accounted for as a purchase with the purchase price allocated to the net assets acquired. The purchase price allocation to oil and natural gas assets, at their estimated fair value, significantly increased our consolidated depletion base per unit and hence our depletion rate.

Taxes

	Three months ended June 30							Six months ended June 30
($ millions)	2007		2006			% change		2007		2006			% change
Future income expense (reduction)	$	299.0	$	(94.8	)	(415	)	$	254.6	$	(104.7	)	(343	)

The second quarter of 2007 future income tax expense, compared to the reduction in the first quarter of 2007, reflects a $325.5 million charge due to the enactment of the SIFT tax legislation during the period. Temporary differences at the Trust level, or differences between book and tax basis of assets and liabilities, were previously not recognized as prescribed under Canadian GAAP since the Trust was required to distribute all of its taxable income. Under the new legislation, in 2011 and beyond, as distributions will no longer be tax deductible, the Trust will not be able to make distributions to reduce its taxable income and thus is no longer considered to be exempt from income taxes for accounting purposes. Accordingly, the future income tax liability was increased to reflect the current temporary differences expected to be remaining at the Trust level in 2011 using the SIFT tax rate of 31.5 percent.

Under our current structure, the operating entities make interest and royalty payments to the Trust, which transfers taxable income to the Trust to eliminate income subject to corporate and other income taxes in the operating entities. With the new legislation, such amounts transferred to the Trust could be taxable beginning in 2011 as distributions will no longer be deductible for income tax purposes. At that time, Penn West could claim tax pools in its operating companies, reduce the income transferred to the Trust, and pay all or a portion of its distributions on a return of capital basis. Until 2011, under the terms of its trust indenture, the Trust is required to distribute amounts equal to at least its taxable income. In the event that the Trust has undistributed taxable income in a taxation year (prior to 2011), an additional special taxable distribution, subject to certain withholding taxes, would be required by the terms of its trust indenture.

The estimate of future income taxes is based on the current tax status of the Trust. Future events, which could materially affect future income taxes such as acquisitions and dispositions and modifications to the distribution policy, are not reflected under Canadian GAAP until the events occur and the related legal requirements have been fulfilled. As a result, future changes to the tax legislation could lead to a material change in the recorded amount of future income taxes.

The new legislation is not expected to directly affect our cash flow levels and distribution policies until 2011 at the earliest.

Cash Flow and Net (Loss) Income

	Three months ended June 30							Six months ended June 30
	2007			2006		% change		2007			2006		% change
Cash flow (1)($ millions)	$	326.2		$	264.7	23		$	637.5		$	507.9	26
Basic per unit	1.37			1.59		(14	)	2.68			3.08		(13	)
Diluted per unit	1.35			1.56		(13	)	2.65			3.03		(13	)

Net (loss) income ($ millions)	(185.2		)	220.5		(184	)	(88.9		)	364.9		(124	)
Basic per unit	(0.77		)	1.34		(157	)	(0.37		)	2.22		(117	)
Diluted per unit	$	(0.77	)	$	1.31	(159	)	$	(0.37	)	$	2.18	(117	)

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

Cash flow realized in the first six months of 2007 increased from the comparable 2006 period due to higher production volumes resulting from the Petrofund merger and higher conventional heavy oil prices partially offset by higher operating and financing costs.

In the absence of the $325.5 million non-cash charge taken to reflect the enactment of the SIFT tax, net income for the second quarter and first half of 2007 would have been $140.3 million and $236.6 million, respectively. The remainder of the decrease was due to increased depletion and financing charges following the Petrofund merger that closed on June 30, 2006.

Goodwill

The goodwill balance of $652.0 million resulted from the merger with Petrofund in June 2006. The Trust has determined that there was no goodwill impairment as of June 30, 2007.

Capital Expenditures

	Three months ended June 30					Six months ended June 30
($ millions)	2007		2006			2007		2006
Property acquisitions (dispositions), net	$	351.0	$	(3.4	)	$	368.1	$	(5.5	)
Land acquisition and retention	1.6		5.1			4.5		18.5
Drilling and completions	44.1		54.1			165.6		151.0
Facilities and well equipping	80.2		47.7			147.6		94.7
Geological and geophysical	4.3		0.9			8.0		2.2
CO2 pilot costs	1.6		0.8			3.1		1.9
Administrative	0.8		0.6			2.6		1.0
Capital expenditures	483.6		105.8			699.5		263.8

Business combination	—		3,361.3			—		3,361.3

Total expenditures	$	483.6	$	3,467.1		$	699.5	$	3,625.1

We drilled 13 net wells in the second quarter of 2007, resulting in eight net oil wells, three net natural gas wells and one stratigraphic well with a success rate of 92 percent. Our drilling activities were focused in the Central and Plains areas.

CO2 pilot costs represent capital expenditures related to the Pembina CO2 pilot project, including the cost of injectants, for which no reserves have been booked.

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

On May 31, 2007, we entered into an agreement with C1 Energy Ltd (“C1”) to make an offer to its shareholders to acquire all of the issued and outstanding shares of the company for an estimated cash purchase price of $23 million. After the acquisition of approximately 80 percent of C1 by July 23, 2007, we extended the offer to August 3, 2007. Certain assets of C1 are located in the Peace River Arch area of Alberta further strengthening our position near our Peace River Oil Sands project. The acquisition is expected to close in August 2007.

Our farm-out program is ongoing; since 2005, 378 wells have been drilled on Penn West’s lands, including re-completions and re-entries, by independent operators who incur drilling, completions and other capital costs on these plays to earn an interest in the lands. In the second quarter of 2007, 16 wells were drilled on our farm-out lands.

In addition to the above capital expenditures, $8.4 million was capitalized in relation to future income taxes on minor acquisitions in the Swan Hills area, to reflect the acquisition of assets with less tax basis than the purchase price, and $17.1 million was capitalized for additions to asset retirement obligations.

Business Risks

Market Risk Management

We are exposed to normal market risks inherent in the oil and natural gas business, including commodity price risk, credit risk, interest rate risk, foreign currency and environmental risk. From time to time, we attempt to minimize exposure to a portion of these risks by using financial instruments and by other means.

Commodity Price Risk

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

For a current summary of outstanding oil and natural gas hedging contracts, please refer to “Financial Instruments” later in this MD&A or our website at www.pennwest.com.

Foreign Currency Rate Risk

Prices received for sales of crude oil are referenced to, or denominated in, US dollars, and thus realized oil prices are generally impacted by Canadian to United States exchange rates. When we consider it appropriate, we may use financial instruments to fix or collar future exchange rates. At June 30, 2007, we had US dollar denominated debt with a face value of US$475 million outstanding on which the repayment of principal amount in Canadian dollars is not fixed.

Credit Risk

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

Interest Rate Risk

We currently maintain our debt in floating-rate bank facilities, resulting in exposure to fluctuations in short-term interest rates. From time to time, we may increase the certainty of future interest rates using financial instruments to swap floating interest rates for fixed rates or to collar interest rates. In 2006, we entered into interest rate swaps that fix the interest rate for two years at 4.36 percent on $100 million of bank debt. We also closed the placement of notes totaling US$475 million on May 31, 2007 which bear fixed interest rates at an average rate of 5.8 percent for an average term of 10.1 years.

Greenhouse Gas and Air Emissions Legislation

The Alberta Government has introduced legislation that will enable the province to regulate emissions of Greenhouse Gases. The regulations require facilities that emit over 100,000 tonnes of CO2E/yr (total Greenhouse Gases in terms of CO2 equivalent) to reduce their emissions intensity (quantity of gases released per unit of production) by 12 percent starting July 1, 2007 or pay a fee based on emissions in excess of the targeted reductions. Penn West currently does not operate any facilities that are over the current threshold but it does have a working interest in some facilities that do exceed the threshold. We have been in contact with the operators of these facilities to evaluate the impact of the regulations on our working interest.

The Federal Government has also released its regulatory framework to reduce emissions of both Greenhouse Gases and four smog-forming pollutants with targets coming into force in 2010 and 2015, respectively. Clarification surrounding the regulations is expected in the next year with the regulations to be finalized by 2010.

There are multiple compliance mechanisms under both the Alberta and Federal plans including making contributions to technology funds, emissions trading, and offset credits.

Penn West is in the process of fully evaluating the impact of these regulations. There will be a cost associated with complying with these regulations, but we believe that the cost will be minor. We believe that these new regulations may result in increased interest in CO2 capture, transportation and storage technologies and infrastructure and may assist in the development of our CO2 enhanced oil recovery projects in our light oil pools in Alberta. In the meantime, we will continue our current activities to reduce our emissions intensity, improve our energy efficiency and develop CO2 injection and sequestration infrastructure.

Liquidity and Capital Resources

Capitalization

	June 30, 2007			December 31, 2006
($ millions)			%			%
Trust units issued, at market	$	8,521	81.8	$	8,435	86.0
Long-term debt	1,823		17.5	1,285		13.1
Working capital deficiency (1)	77		0.7	86		0.9
Total enterprise value	$	10,421	100.0	$	9,806	100.0

(1) Current assets minus current liabilities.

During the first six months of 2007, we paid total distributions, including those funded by the distribution reinvestment plan, of $485.2 million compared to distributions of $324.3 million in the same period of 2006. This increase was due to the increase in the distribution rate from $0.31 per unit, per month in March 2006, to the rate of $0.34, and the additional units issued as consideration for Petrofund in 2006.

Long-term debt at June 30, 2007 was $1,823 million compared to $1,285 million at December 31, 2006. Penn West Petroleum Ltd.’s unsecured, extendible, three-year revolving syndicated credit facility has an aggregate borrowing limit of $1.9 billion with stamping fees ranging from 60 - 115 basis points and standby fees ranging from 12.5 - 22.5 basis points depending on our ratio of consolidated bank debt to income before interest, taxes and depreciation and depletion (“EBITDA”). The syndicated facility expires on August 25, 2009.

On April 18, 2007, the Company entered into an additional $250 million unsecured, demand credit facility. This demand credit facility is priced at the same rates as the Company’s existing syndicated credit facility and expires on December 31, 2008.

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

On June 30, 2007, the Company was in compliance with the financial covenant pursuant to the notes, which is that consolidated total debt to consolidated total capitalization is not to exceed 55 percent except in the event of a material acquisition where it is not to exceed 60 percent. The ratio at June 30, 2007 was 28 percent.

On June 30, 2007, the Company was in compliance with all of the financial covenants under its syndicated credit facility. The financial covenants under the syndicated credit facility are as follows:

· Consolidated bank debt to EBITDA shall be less than 3:1 except in certain circumstances and shall not exceed 3.5:1;

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

· Consolidated bank debt to total trust capitalization shall not exceed 50 percent except in certain circumstances and shall not exceed 55 percent.

The consolidated senior, and total debt, to EBITDA and the consolidated senior debt to capitalization ratios at June 30, 2007 were 1.27 and 28 percent respectively.

Under the terms of its current trust indenture, the Trust is required to make distributions to unitholders in amounts at least equal to its taxable income. Distributions may be monthly or special and in cash or in trust units at the discretion of our Board of Directors. To the extent that additional cash distributions are paid and capital programs are not adjusted, debt levels may increase. In the event that a special distribution in the form of trust units is declared, the terms of the current trust indenture requires that the outstanding units be consolidated immediately subsequent to the distribution. The number of outstanding trust units would remain at the number outstanding immediately prior to the unit distribution, plus those sold to fund the payment of withholding taxes, and an amount equal to the distribution would be allocated to the unitholders as a taxable distribution.

Our philosophy is to retire approximately 10 percent of our opening asset retirement obligation annually, using our cash flow. Due to the extent of our environmental programs, we believe no benefit would arise from the initiation of a reclamation fund. We believe our program is sufficient to meet or exceed existing environmental regulations and best industry practices. In the event of significant changes to the environmental regulations or the cost of environmental activities, a higher portion of cash flow would be required to fund our environmental expenditures.

Standardized Distributable Cash

Prior to recent guidance from accounting and regulatory standard setters on the disclosure of distributable cash, Penn West believed it was inappropriate to provide disclosures regarding distributable cash to its investors and opted to provide statistics including a reconciliation of cash flow from operating activities to distributions declared and distributions declared as a percentage cash flow from operating activities and net income. In the fourth quarter of 2006, Penn West early adopted the draft guidance on the disclosure of distributable cash released in November 2006. The Canadian Institute of Chartered Accountants issued the Interpretive Release “Standardized Distributable Cash in Income Trusts and Other Flow-Through Entities” in July 2007, which is required for the third quarter of 2007. The interpretive release was early adopted by Penn West in this MD&A. In the new guidance, sustainability concepts are discussed and standardized distributable cash is defined as cash flow from operating activities less adjustments for productive capacity maintenance, long-term unfunded contractual obligations and the effect of any foreseeable financing matters, related to debt covenants, which could impair our ability to pay distributions or maintain productive capacity.

	Three months ended June 30						Six months ended June 30
($ millions, except per unit amounts)	2007			2006			2007			2006
Cash flow from operating activities	$	316.5		$	218.7		$	613.3		$	426.4
Productive capacity maintenance (1)	(132.6		)	(109.2		)	(331.4		)	(269.3		)
Standardized distributable cash	183.9			109.5			281.9			157.1
Proceeds from the issue of trust units (2)	37.4			31.8			65.9			51.4
Bank borrowings and working capital changes	22.2			26.3			138.1			121.1
Cash distributions declared	$	243.5		$	167.6		$	485.9		$	329.6
Accumulated cash distributions, beginning	1,375.7			483.5			1,133.3			321.5
Accumulated cash distributions, ending	$	1,619.2		$	651.1		$	1,619.2		$	651.1

Standardized distributable cash per unit, basic	0.77			0.66			1.18			0.95
Standardized distributable cash per unit, diluted	0.76			0.65			1.15			0.94
Standardized distributable cash payout ratio (3)	1.32			1.53			1.72			2.10

Distributions declared per unit	$	1.02		$	1.02		$	2.04		$	2.01
Net income in excess of cash distributions declared	N/A			132		%	N/A			111		%
Cash flows from operating activities in excess of cash distributions declared	130		%	130		%	126		%	129		%

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

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

(3) Represents cash distributions declared divided by standardized distributable cash.

We strive to fund both distributions and maintenance capital programs primarily from cash flow. We initially budget our capital programs at approximately 40-50 percent of annual cash flow. We believe that proceeds from the Distribution Re-investment and Optional Purchase Plan should be used to fund capital expenditures of a longer-term nature. Over the medium term, additional borrowings and equity issues may be required from time to time to fund a portion of our distributions or maintain or increase our productive capacity. On a longer-term basis, adjustments to the level of distributions and/or capital expenditures to maintain or increase our productive capacity may be required based on forecast levels of cash flow, capital efficiency and debt levels.

Productive capacity maintenance is the amount of capital funds required in a period for an enterprise to maintain its ability to generate future cash flow from operating activities at a constant level. As commodity prices can be volatile and short-term variations in production levels are often experienced in our industry, we define our productive capacity as production on a barrel of oil equivalent basis. A quantifiable measure for these short-term variations is not objectively determinable or verifiable due to various factors including the inability to distinguish natural production declines from the effect of production additions resulting from capital and optimization programs, and the effect of temporary production interruptions. As a result, the adjustment for productive capacity maintenance in our calculation of standardized distributable cash is our capital expenditures during the period excluding the cost of any asset acquisitions or proceeds of any asset dispositions. We believe that our current capital programs, based on 40-50 percent of forecast annual cash flow and our current view of our assets and opportunities, including particularly our oil sands projects and proposed enhanced oil recovery projects, and our outlook for commodity prices and industry conditions in the medium term, should be sufficient to maintain our productive capacity in the medium term. We set our hurdle rates for evaluating potential development and optimization projects according to these parameters. Due to the risks inherent in the oil and natural gas industry, particularly our exploration and development activities and inherent variations in commodity prices, there can be no assurance that capital programs, whether limited to the excess of cash flow over distributions or not, will be sufficient to maintain or increase our production levels or cash flow from operating activities. Penn West generally incurs a large proportion of its development expenditures in the first quarter of each calendar year to exploit winter-only access properties. As we strive to maintain sufficient credit facilities and appropriate levels of bank debt, this seasonality is not expected to influence our distribution policies.

Our calculation of standardized distributable cash has no adjustment for long-term unfunded contractual obligations. We believe our only significant long-term unfunded contractual obligation at this time is for asset retirement obligations. Cash flow from operating activities, used in our standardized distributable cash calculation, includes a deduction for abandonment expenditures incurred during the period. We believe that our philosophy to retire approximately 10 percent of our opening asset retirement obligation on an annual basis is sufficient to fund our asset retirement obligations over the life of our reserves.

We currently have no financing restrictions caused by our debt covenants. We regularly monitor our current and forecast debt levels to ensure debt covenants are not exceeded.

($ millions, except indicators)	To June 30, 2007
Cumulative distributable cash from operations (1)	$	1,300.3
Issue of trust units	192.8
Bank borrowing and working capital change	126.1
Cumulative cash distributions declared (1)	$	1,619.2

Standardized distributable cash payout ratio (2)	1.25

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

(2) Represents cumulative cash distributions declared divided by cumulative standardized distributable cash.

Financial Instruments

We currently have WTI crude oil collars on approximately 25,000 barrels per day from July 1 to December 31, 2007 and 17,500 barrels per day from January 2008 to December 2008. The collars on the 25,000 barrels per day to December 2007 have an average floor price of US$56.00 per barrel and an average ceiling price of US$83.80 per barrel. The 2008 WTI crude oil collars have an average floor price of US$64.25 per barrel and an average ceiling price of US$81.06 per barrel. In addition, Penn West has AECO natural gas collars on approximately 52 mmcf per day from July 1 to December 31, 2007 with an average floor price of $7.81 per mcf and an average ceiling price of $10.50 per mcf and approximately nine mmcf per day for the first quarter of 2008 with an average floor price of $8.18 per mcf and an average ceiling price of $12.15 per mcf.

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

Other financial instruments outstanding at June 30, 2007 are Alberta electricity contracts, which fix 2007 electricity costs on 67 megawatts at $49.55 per megawatt hour and for 2008 on 2 megawatts at $57.00 per megawatt hour.

Mark to market amounts on all financial instruments outstanding on June 30, 2007 are summarized in note 8 to the unaudited interim consolidated financial statements. Please refer to Penn West’s website at www.pennwest.com for details of financial instruments currently outstanding.

Outlook

The outlook for oil prices remains strong however the outlook for natural gas prices has weakened and the Canadian dollar has reached three decade high levels against the US dollar. We are currently forecasting capital expenditures of $850 million to $950 million in 2007, including net property acquisitions. Estimated average 2007 production is currently forecast between 129,000 and 132,000 boe per day after the estimated reduction due to the Wildboy fire. Using a forward strip, 2007 average WTI oil price of US$69.00, an average $6.60 per mcf AECO natural gas price and an average exchange rate of CAD$1.00 equals US$0.92, 2007 cash flow is currently forecast to be between $1.3 billion and $1.4 billion.

Sensitivity Analysis

Estimated sensitivities to selected key assumptions on 2007 financial results before considering hedging impacts are outlined in the table below.

($ millions, except per unit amounts)				Impact on cash flow (1)		Impact on net income (1)
Change of:	Change			$ millions	$/unit	$ millions	$/unit
Price per barrel of liquids	$	1.00		21.5	0.09	15.1	0.06
Liquids production	1,000 bbls/day			14.6	0.06	5.4	0.02
Price per mcf of natural gas	$	0.10		9.5	0.04	6.7	0.03
Natural gas production	10 mmcf/day			13.5	0.06	1.4	0.01
Effective interest rate	1		%	14.1	0.06	8.3	0.03
Exchange rate ($US per $CAD)	$	0.01		21.3	0.09	15.0	0.06

(1) The impact on cash flow and net income is computed based on 2007 forecast commodity prices and production volumes. The impact on net income assumes that the distribution levels are not adjusted for changes in cash flow thus changing the incremental future income tax rate.

Contractual Obligations and Commitments

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

($ millions)	2007		2008		2009		2010		2011		Thereafter
Transportation	$	8.0	$	9.7	$	5.1	$	3.2	$	0.1	$	—
Transportation ($US)	1.1		2.3		2.3		2.3		2.3		8.6
Power infrastructure	4.8		3.9		3.9		3.9		3.9		7.6
Drilling rigs	3.5		7.7		2.4		1.2		—		—
Purchase obligations (1)	6.6		13.3		13.3		13.3		13.3		54.3
Office lease	$	5.1	$	17.9	$	17.5	$	15.1	$	14.3	$	117.5

(1) These amounts represent estimated commitments of $90.0 million for CO2 purchases and $24.1 million for processing fees related to interests in the Weyburn Unit.

Our syndicated credit facility expires on August 25, 2009 and our demand credit facility expires on December 31, 2008. If we were not successful in renewing or replacing them, we would be required to repay all amounts then outstanding on the facilities. In addition, we have US$475 million of fixed-term notes expiring between 2015 and 2022. As we maintain our leverage ratios at relatively modest levels, we believe we will be successful in renewing or replacing our credit facilities on acceptable terms.

Equity Instruments

Trust units issued:
As at June 30, 2007	239,227,937
Issued on exercise of trust unit rights	32,960
Issued to employee savings plan	42,455
Issued pursuant to distribution re-investment plan	347,755
As at August 1, 2007	239,651,107

Trust unit rights outstanding:
As at June 30, 2007	14,465,432
Granted	91,120
Exercised	(32,960	)
Forfeited	(239,648	)
As at August 1, 2007	14,283,944

Disclosure Controls and Procedures

We have established a Disclosure Committee that is responsible for ensuring that our disclosure controls and procedures are designed to provide reasonable assurance that information required to be disclosed by us is recorded, processed, summarized and reported within the time periods specified under Canadian securities laws. The committee is also responsible to ensure that our internal controls and procedures are designed to ensure that information is accumulated and communicated to management, including the President and Chief Executive Officer and the Chief Financial Officer, to allow timely decisions regarding required disclosure. Our Disclosure Committee includes selected members of senior management, including the Chief Executive Officer, the Chief Operating Officer and the Chief Financial Officer.

As at June 30, 2007, an evaluation of the effectiveness of our disclosure controls and procedures, as defined under Multilateral Instrument 52-109, was completed. The evaluation was completed under the supervision of the Disclosure Committee and with the participation of management. As at June 30, 2007, the design and operating effectiveness of our disclosure controls and procedures were assessed by our Chief Executive Officer and Chief Financial Officer to be operating effectively.

Internal Controls over Financial Reporting

We have assembled a team of qualified and experienced staff and consultants who have been working on compliance with the applicable regulations regarding internal control over financial reporting. As we are listed in both Canada and the United States, the recent changes in Canada to remove the requirement for auditor attestation and to extend the timing of CEO/CFO certification of the effective operation of internal control over financial reporting to 2008 will not affect us. We became a registrant under the U.S. Securities Act of 1934 and listed our trust units on the New York Stock Exchange in June 2006. We are not required to certify or obtain auditor attestation of the operating effectiveness of our internal control over financial reporting until we file our 2007 year-end audited financial statements. To date, all significant financial reporting processes have been documented, assessed, and the resulting modifications to our systems of internal control over financial reporting have been substantially completed. Based on this work to date, no changes were made during the quarter ended June 30, 2007 that materially affected, or would be reasonably likely to materially affect, our internal control over financial reporting.

Accounting Changes and Pronouncements

Effective January 1, 2007, the Trust adopted new Canadian accounting standards being “Comprehensive Income”, “Financial Instruments - Disclosure and Presentation”, “Hedges”, “Financial Instruments - Recognition and Measurement”, and “Equity”. The adoption of these standards has had no material impact on the Trust’s net income or cash flows.

Financial Instruments

Financial instruments are required to be measured at fair value on the balance sheet upon initial recognition of the instrument. Measurement in subsequent periods depends on whether the financial instrument has been classified in one of the following categories: held-for-trading, available-for-sale, held-to-maturity, loans and receivables, or other financial liabilities as defined under CICA Handbook Section 3855.

Subsequent measurement and changes in fair value will depend on initial classification, as follows: held-for-trading financial assets are measured at fair value and changes in fair value are recognized in net income; available-for-sale financial instruments are measured at fair value with changes in fair value recorded in Other Comprehensive Income (“OCI”) until the instrument or a portion thereof is derecognized or impaired at which time the amounts would be recorded in net income.

As the Trust previously elected to discontinue hedge accounting, the adoption of these standards did not change the Trust’s accounting for financial instruments. Cash and cash equivalents are designated as held-for-trading and are measured at carrying value, which approximates fair value due to the short-term nature of these instruments. Accounts receivable and accrued revenues are designated as loans and receivables. Accounts payable and accrued liabilities and long-term debt are designated as other liabilities. Risk management assets and liabilities are derivative financial instruments classified as held-for-trading.

Embedded Derivatives

An embedded derivative is a component of a contract that affects the contract terms in relation to another factor, for example rent costs that fluctuate with oil prices. These “hybrid” contracts are considered to consist of a “host” contract plus an embedded derivative. The embedded derivative is separated from the host contract and accounted for as a derivative if certain conditions are met. These include:

· the economic characteristics and risks of the embedded derivative are not closely related to the economic characteristics and risks of the host contract,

· if the embedded derivative separated meets the definition of a derivative,

· the hybrid contract is not measured at fair value or classified as held for trading.

The Trust currently has no material embedded derivatives.

Comprehensive Income

Comprehensive income is defined as the change in equity from transactions and other events from non-owner sources. It consists of net income and OCI. OCI refers to items recognized in comprehensive income that are excluded from net income calculated in accordance with generally accepted accounting principles. The Trust currently has no items requiring separate disclosure as OCI on a statement of Comprehensive Income.

Two new Canadian accounting standards have been issued, “Financial Instruments-Disclosure” and “Capital Disclosure”, which will require additional disclosure in the Trust’s financial statements commencing January 1, 2008 about the Trust’s financial instruments as well as its capital and how it is managed.

Related-Party Transactions

During the first six months of 2007, Penn West paid $0.8 million (2006 – $2.3 million) of legal fees to a law firm of which a partner is also a director of Penn West.

Off-Balance-Sheet Financing

We have off-balance-sheet financing arrangements consisting of operating leases. The operating lease payments are summarized in the Contractual Obligations and Commitments section.

Forward-Looking Statements

In the interest of providing Penn West’s unitholders and potential investors with information regarding Penn West, including management’s assessment of Penn West’s future plans and operations, certain statements contained in this document constitute forward-looking statements or information (collectively “forward-looking statements”) within the meaning of the “safe harbour” provisions of applicable securities legislation. Forward-looking statements are typically identified by words such as “anticipate”, “continue”, “estimate”, “expect”, “forecast”, “may”, “will”, “project”, “could”, “plan”, “intend”, “should”, “believe”, “outlook”, “potential”, “target” and similar words suggesting future events or future performance. In addition, statements relating to “reserves” or “resources” are deemed to be forward-looking statements as they involve the implied assessment, based on certain estimates and assumptions, that the reserves and resources described exist in the quantities predicted or estimated and can be profitably produced in the future. In particular, this document contains forward-looking statements pertaining to, without limitation, the following: the impact on our business and unitholders of the SIFT tax and the different actions that we might take in response to the SIFT tax; drilling plans; sufficiency of insurance related to Wildboy costs and losses; timing for production restoration at Wildboy; tie-in of wells; environmental regulation compliance costs and strategy; production estimates; netback estimates; our business strategy, including our strategy in respect of our Peace River Oil Sands project and enhanced oil recovery projects; product balance; the sufficiency of our environmental program; funding sources for distributions and distribution levels; the funding of our asset retirement obligations; our beliefs and outlook for the maintenance of productive capacity; our outlook for oil and natural gas prices; our forecast 2007 net capital expenditures and the allocation and funding thereof; currency exchange rates; our forecast cash flow; our belief that we will be successful in renewing or replacing our credit facilities on acceptable terms when they expire; and the quantity and recoverability of our oil and natural gas reserves and resources.

With respect to forward-looking statements contained in this document, we have made assumptions regarding, among other things: future oil and natural gas prices and differentials between light, medium and heavy oil prices; future oil and natural gas production levels; future exchange rates; the amount of future cash distributions that we intend to pay; the cost of expanding our property holdings; our ability to obtain equipment in a timely manner to carry out development activities; our ability to restore production at Wildboy and the costs thereof; our ability to market our oil and natural gas successfully to current and new customers; the impact of increasing competition; our ability to obtain financing on acceptable terms; and our ability to add production and reserves through our development and exploitation activities.

Although Penn West believes that the expectations reflected in the forward-looking statements contained in this document, and the assumptions on which such forward-looking statements are made, are reasonable, there can be no assurance that such expectations will prove to be correct. Readers are cautioned not to place undue reliance on forward-looking statements included in this document, as there can be no assurance that the plans, intentions or expectations upon which the forward-looking statements are based will occur. By their nature, forward-looking statements involve numerous assumptions, known and unknown risks and uncertainties that contribute to the possibility that the predictions, forecasts, projections and other forward-looking statements will not occur, which may cause Penn West’s actual performance and financial results in future periods to differ materially from any estimates or projections of future performance or results expressed or implied by such forward-looking statements. These risks and uncertainties include, among other things: volatility in market prices for oil and natural gas; the impact of weather conditions on seasonal demand and ability to execute capital programs; risks inherent in oil and gas operations; uncertainties associated with estimating reserves and resources; competition for, among other things, capital, acquisitions of reserves, resources, undeveloped lands and skilled personnel; incorrect assessments of the value of acquisitions; geological, technical, drilling and processing problems; general economic conditions in Canada, the U.S. and globally; industry conditions, including fluctuations in the price of oil and natural gas; royalties payable in respect of our oil and natural gas production; changes in government regulation of the oil and natural gas industry, including environmental regulation; fluctuations in foreign exchange or interest rates; unanticipated operating events that can reduce production or cause production to be shut-in or delayed; failure to obtain industry partner and other third-party consents and approvals when required; stock market volatility and market valuations; OPEC’s ability to control production and balance global supply and demand of crude oil at desired price levels; political uncertainty, including the risks of hostilities, in the petroleum producing regions of the world; the need to obtain required approvals from regulatory authorities from time to time; failure to realize the anticipated benefits of acquisitions, including the merger with Petrofund Energy Trust; changes in tax law; and the other factors described under “Business Risks” in this document and in Penn West’s public filings (including our Annual Information Form) available in Canada at www.sedar.com and in the United States at www.sec.gov. Readers are cautioned that this list of risk factors should not be construed as exhaustive.

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

Additional Information

Additional information relating to Penn West including Penn West’s Annual Information Form is available on SEDAR at www.sedar.com.

Penn West Energy Trust

Consolidated Balance Sheets

($ millions, unaudited)	June 30, 2007		December 31, 2006

Assets
Current
Accounts receivable	$	247.9	$	268.7
Risk management (note 8)	21.3		54.0
Other	46.9		56.0
	316.1		378.7
Property, plant and equipment (note 3)	7,342.8		7,039.0
Goodwill	652.0		652.0
	7,994.8		7,691.0
	$	8,310.9	$	8,069.7

Liabilities and unitholders’ equity
Current
Accounts payable and accrued liabilities	$	312.5	$	384.1
Distributions payable	81.3		80.6
	393.8		464.7
Long-term debt (note 4)	1,822.5		1,285.0
Asset retirement obligations (note 5)	349.8		339.1
Future income taxes	1,055.6		792.6
	3,621.7		2,881.4
Unitholders’ equity
Unitholders’ capital (note 6)	3,779.1		3,712.4
Contributed surplus (note 6)	25.4		16.4
Retained earnings	884.7		1,459.5
	4,689.2		5,188.3
	$	8,310.9	$	8,069.7

See accompanying notes to the unaudited interim consolidated financial statements.

Penn West Energy Trust

Consolidated Statements of Income and Retained Earnings

	Three months ended June 30						Six months ended June 30
($ millions, except per unit amounts, unaudited)	2007			2006			2007			2006

Revenues
Oil and natural gas	$	608.0		$	435.5		$	1,187.0		$	864.0
Royalties	(113.1		)	(80.1		)	(224.4		)	(165.7		)
	494.9			355.4			962.6			698.3

Risk management gain (loss) (note 8)
Realized	0.3			17.0			3.7			22.4
Unrealized	5.8			(27.4		)	(29.2		)	(14.1		)
	501.0			345.0			937.1			706.6

Expenses
Operating (note 7)	127.3			87.8			252.3			174.5
Transportation	6.0			5.0			12.1			10.8
General and administrative (note 7)	16.4			8.9			33.7			18.1
Financing (note 4)	24.3			8.4			40.5			14.8
Depletion, depreciation and accretion (note 3)	218.4			109.9			433.3			222.4
Risk management (gain) loss – unrealized (note 8)	(1.2		)	(0.7		)	3.5			5.8
Unrealized foreign exchange gain	(4.0		)	—			(4.0		)	—
	387.2			219.3			771.4			446.4
Income before taxes	113.8			125.7			165.7			260.2

Taxes
Future income expense (reduction)	299.0			(94.8		)	254.6			(104.7		)

Net (loss) income	(185.2		)	220.5			(88.9		)	364.9

Retained earnings, beginning of period	1,313.4			1,588.1			1,459.5			1,605.7
Distributions declared	(243.5		)	(167.6		)	(485.9		)	(329.6		)
Retained earnings, end of period	$	884.7		$	1,641.0		$	884.7		$	1,641.0

Net (loss) income per unit
Basic	$	(0.77	)	$	1.34		$	(0.37	)	$	2.22
Diluted	$	(0.77	)	$	1.31		$	(0.37	)	$	2.18

See accompanying notes to the unaudited interim consolidated financial statements.

Penn West Energy Trust

Consolidated Statements of Cash Flows

	Three months ended June 30						Six months ended June 30
($ millions, unaudited)	2007			2006			2007			2006

Operating activities
Net (loss) income	$	(185.2	)	$	220.5		$	(88.9	)	$	364.9
Depletion, depreciation and accretion (note 3)	218.4			109.9			433.3			222.4
Future income tax expense (reduction)	299.0			(94.8		)	254.6			(104.7		)
Unit-based compensation (note 7)	5.0			2.4			9.8			5.4
Risk management (gain) loss (note 8)	(7.0		)	26.7			32.7			19.9
Asset retirement expenditures	(8.8		)	(2.6		)	(18.5		)	(9.5		)
Unrealized foreign exchange gain	(4.0		)	—			(4.0		)	—
Change in non-cash working capital	(0.9		)	(43.4		)	(5.7		)	(72.0		)
	316.5			218.7			613.3			426.4

Investing activities
Acquisition of property, plant and equipment	(351.0		)	3.4			(368.1		)	5.5
Additions to property, plant and equipment	(132.6		)	(109.2		)	(331.4		)	(269.3		)
Petrofund merger costs	—			(32.7		)	—			(32.7		)
Change in non-cash working capital	(51.5		)	(16.2		)	(36.0		)	3.0
	(535.1		)	(154.7		)	(735.5		)	(293.5		)

Financing activities
Proceeds from issuance of notes (note 4)	509.1			—			509.1			—
(Decrease) increase in bank loan	(84.8		)	56.1			32.4			124.5
Issue of equity	12.5			6.4			18.2			9.1
Distributions paid	(218.2		)	(142.0		)	(437.5		)	(282.0		)
Settlement of future income tax liabilities on trust conversion	—			15.5			—			15.5
	218.6			(64.0		)	122.2			(132.9		)

Change in cash	—			—			—			—
Cash, beginning of period	—			—			—			—
Cash, end of period	$	—		$	—		$	—		$	—

Interest paid	$	24.9		$	8.2		$	38.3		$	14.0
Income taxes paid	$	4.5		$	—		$	4.5		$	—

See accompanying notes to the unaudited interim consolidated financial statements.

Notes to the Unaudited Interim Consolidated Financial Statements

(All tabular amounts are in $ millions except numbers of units, per unit amounts, percentages and various figures in Note 8)

1. Structure of Penn West

Penn West is an open-ended, unincorporated investment trust governed by the laws of the Province of Alberta. The purpose of Penn West is to indirectly explore for, develop and hold interests in petroleum and natural gas properties through investments in securities of subsidiaries and royalty interests in oil and natural gas properties. Penn West owns 100 percent of the common shares, directly or indirectly, of the entities that carry on the oil and natural gas business of Penn West. The activities of these entities are financed through interest-bearing notes from Penn West and third-party debt as described in the notes to the unaudited interim consolidated financial statements.

Pursuant to the terms of net profit interest agreements (the “NPIs”), Penn West is entitled to payments from certain subsidiary entities equal to essentially all of the proceeds of the sale of oil and natural gas production less certain specified deductions. Under the terms of the NPIs, the deductions are in part discretionary, include the requirement to fund capital expenditures and asset acquisitions, and are subject to certain adjustments for asset dispositions.

Under the terms of its trust indenture, Penn West is required to make distributions to unitholders in amounts at least equal to its taxable income consisting of interest on notes, the NPIs, and any inter-corporate distributions and dividends received, less certain expenses and deductions.

2. Significant accounting policies and basis of presentation

These unaudited interim consolidated financial statements have been prepared in accordance with Canadian generally accepted accounting principles and are consistent with the accounting policies described in the notes to the audited consolidated financial statements of Penn West for the year ended December 31, 2006. These financial statements should accordingly be read in conjunction with Penn West’s audited consolidated financial statements and notes thereto for the year ended December 31, 2006.

Financial Instruments

Subsequent measurement and changes in fair value will depend on the classification of the instrument: held-for-trading financial assets are measured at fair value and changes in fair value are recognized in net income; available-for-sale financial instruments are measured at fair value with changes in fair value recorded in Other Comprehensive Income (“OCI”) until the instrument or a portion thereof is derecognized or impaired at which time the amounts would be recorded in net income.

As the Trust previously elected to discontinue hedge accounting, the adoption of these standards did not change the Trust’s accounting for financial instruments. Cash and cash equivalents are designated as held-for-trading and are measured at carrying value, which approximates fair value due to the short-term nature of these instruments. Accounts receivable and accrued revenues are designated as loans and receivables. Accounts payable and accrued liabilities and long-term debt are designated as other financial liabilities. All risk management assets and liabilities are derivative financial instruments classified as held-for-trading.

Embedded Derivatives

An embedded derivative is a component of a contract, that affects the terms in relation to another factor, for example rent costs that fluctuate with oil prices. These “hybrid” contracts are considered to consist of a “host” contract plus an embedded derivative. The embedded derivative is separated from the host contract and accounted for as a derivative only if certain conditions are met. These include:

· the economic characteristics and risks of the embedded derivative are not closely related to the economic characteristics and risks of the host contract,

· if the embedded derivative separated meets the definition of a derivative,

· the hybrid contract is not measured at fair value or classified as held for trading.

The Trust currently has no material embedded derivatives.

Comprehensive Income

3. Property, plant and equipment

	June 30, 2007			December 31, 2006
Oil and natural gas properties, including production and processing equipment	$	10,388.4		$	9,666.0
Other	19.8			17.2
	10,408.2			9,683.2
Accumulated depletion and depreciation	(3,065.4		)	(2,644.2		)
Net book value	$	7,342.8		$	7,039.0

Other than Penn West’s net share of capital overhead recoveries, no general and administrative expenses are capitalized. In 2007, additions to property, plant and equipment included a $17.1 million increase related to additions to asset retirement obligations and an $8.4 million addition for future income taxes recorded on minor property acquisitions.

An impairment test was performed on the costs capitalized to oil and natural gas properties at June 30, 2007. The estimated undiscounted future net cash flows from proved reserves, using forecast prices, exceeded the carrying amount of the oil and natural gas property interests and the cost of unproved properties.

4. Long-term debt

	June 30, 2007		December 31, 2006
Bankers’ acceptances and prime rate loans	$	1,317.4	$	1,285.0

US Senior unsecured notes
5.68%, US$160 million, maturing May 31, 2015	170.1		—
5.80%, US$155 million, maturing May 31, 2017	164.8		—
5.90%, US$140 million, maturing May 31, 2019	148.9		—
6.05%, US$20 million, maturing May 31, 2022	21.3		—
Total long-term debt	$	1,822.5	$	1,285.0

As at June 30, 2007, the Company had an unsecured, extendible, three-year revolving syndicated credit facility with an aggregate borrowing limit of $1.9 billion, which expires on August 25, 2009. The credit facility contains provisions for stamping fees on bankers’ acceptances and LIBOR loans and standby fees on unutilized credit lines that vary depending on certain consolidated financial ratios.

Interest expense on long-term debt for the six months ended June 30, 2007 was $38.4 million (2006 - $13.8 million).

Letters of credit totaling $0.2 million (December 31, 2006 - $0.4 million) were outstanding on June 30, 2007 that reduced the amount otherwise available to be drawn on the swing line facility.

On April 18, 2007, the Company entered into a $250 million unsecured, demand credit facility. This demand credit facility is priced at the same rates as the Company’s existing syndicated credit facility and expires on December 31, 2008.

On May 31, 2007, the Company issued US$475 million of unsecured notes maturing in eight to 15 years, and bear interest at 5.68 to 6.05 percent, on a private placement basis in the United States. The notes are subject to the financial covenant that consolidated debt to consolidated capitalization shall not exceed 55 percent except in the event of a material acquisition where it is not to exceed 60 percent. The estimated fair value of the principal and interest obligations under the notes at June 30, 2007 was $490.6 million.

5. Asset retirement obligations

The total inflated and undiscounted amount to settle Penn West’s asset retirement obligations at June 30, 2007 was $2.3 billion (December 31, 2006 - $2.2 billion). The asset retirement obligation was determined by applying an inflation factor of 2.0 percent (2006 - 2.0 percent) and the inflated amount was discounted using a credit-adjusted rate of 7.0 percent (2006 - 7.0 percent) over the expected useful life of the underlying assets, currently extending up to 50 years into the future with an average life of 23 years. Future cash flows from operating activities are expected to fund the obligations.

Changes to asset retirement obligations were as follows:

	2007			2006
Balance, beginning of period	$	339.1		$	192.4
Liabilities incurred during the period	17.1			30.2
Petrofund liabilities assumed on acquisition	—			98.0
Increase in liability due to change in estimate	—			25.7
Liabilities settled during the period	(18.5		)	(26.9		)
Accretion charges	12.1			19.7
Balance, end of period	$	349.8		$	339.1

6. Unitholders’ equity

Unitholders’ capital	Units	Amount
Balance, December 31, 2005	163,290,013	$	561.0
Issued on exercise of trust unit rights (1)	407,750	10.6
Issued to employee trust unit savings plan	295,449	12.3
Issued to distribution reinvestment plan	2,459,870	96.1
Issued on Petrofund merger	70,673,137	3,032.4
Balance, December 31, 2006	237,126,219	3,712.4
Issued on exercise of trust unit rights (1)	419,600	10.5
Issued to employee trust unit savings plan	236,754	8.5
Issued to distribution reinvestment plan	1,445,364	47.7
Balance, June 30, 2007	239,227,937	$	3,779.1

Contributed surplus	2007			2006
Balance, beginning of period	$	16.4		$	5.5
Unit-based compensation expense	9.8			11.3
Net benefit on rights exercised (1)	(0.8		)	(0.4		)
Balance, end of period	$	25.4		$	16.4

(1) Upon exercise of trust unit rights, the net benefit is reflected as a reduction of contributed surplus and an increase to unitholders’ capital.

	Three months ended June 30		Six months ended June 30
(millions of units)	2007	2006	2007	2006
Weighted average
Basic	239.0	165.8	238.0	164.6
Diluted	239.0	168.7	238.0	167.6
Outstanding as at June 30
Basic			239.2	235.3
Basic plus trust unit rights			253.7	246.0

In 2007, due to the reported net loss arising as a result of the future income tax charge taken to reflect the enactment of the “Specified Investment Flow-Through” (“SIFT”) tax, all trust unit rights (2006 - 1.0 million) were excluded in calculating the weighted average number of diluted trust units as they were considered anti-dilutive.

7. Unit-based compensation

Trust unit rights incentive plan

Penn West has a unit rights incentive plan that allows Penn West to issue rights to acquire trust units to directors, officers, employees and other service providers. Under the terms of the plan, the number of trust units reserved for issuance shall not exceed 10 percent of the aggregate number of issued and outstanding trust units of Penn West. Unit right exercise prices are administrated to be equal to the volume-weighted average trading price of the trust units on the Toronto Stock Exchange for the five trading days immediately prior to the date upon which the unit rights are granted. If certain conditions are met, the exercise price per unit may be reduced by deducting from the grant price the aggregate of all distributions, on a per unit basis, paid by Penn West after the grant date. Rights granted under the plan prior to November 13, 2006 vest over a five-year period and expire six years after the date of the grant. Rights granted subsequent to this date generally vest over a three-year period and expire four years after the date of the grant.

	Six months ended June 30, 2007					Year ended December 31, 2006
Trust unit rights	Number of unit rights		Weighted average exercise price			Number of unit rights		Weighted average exercise price
Outstanding, beginning of period	11,284,872		$	27.76		9,447,625		$	28.45
Granted	4,246,476		33.90			3,257,622		39.77
Exercised	(419,600	)	22.98			(407,750	)	24.65
Forfeited	(646,316	)	31.83			(1,012,625	)	33.38
Balance before reduction of exercise price	14,465,432		29.52			11,284,872		30.89
Reduction of exercise price for distributions paid	—		(2.04		)	—		(3.13		)
Outstanding, end of period	14,465,432		$	27.48		11,284,872		$	27.76
Exercisable, end of period	2,608,730		$	23.14		1,125,300		$	23.16

Penn West recorded unit-based compensation expense of $9.8 million for the six months ended June 30, 2007, of which $2.6 million was charged to operating expense and $7.2 million was charged to general and administrative expense (2006 - $5.4 million, $1.4 million and $4.0 million respectively). Unit-based 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 Binomial Lattice option-pricing model was used to determine the fair value of trust unit rights granted with the following weighted average assumptions:

	2007			2006
Six months ended June 30	Three-year vesting period			Five-year vesting period
Average fair value of trust unit rights granted (per unit)	$	6.68		$	8.16
Expected life of trust unit rights (years)	3.0			4.5
Expected volatility (average)	24.6		%	22.4		%
Risk-free rate of return (average)	4.2		%	4.2		%
Distribution yield (1)	11.8		%	9.0		%

(1) Represents distributions declared as a percentage of the market price of trust units and does not account for any portion of distributions that represent a return of capital.

Trust unit savings plan

Penn West has an employee trust unit savings plan for the benefit of all employees. Under the savings plan, employees may elect to contribute up to 10 percent of their salary. Penn West matches employee contributions at a rate of $1.50 for each $1.00. Both the employee’s and Penn West’s contribution are used to acquire Penn West trust units. These trust units may be issued from treasury at the five-day volume weighted average month-end trading price on the Toronto Stock Exchange or purchased in the open market at prevailing market prices.

8. Financial instruments

Changes in the fair value of all outstanding financial commodity, power and interest rate contracts are reflected on the balance sheet with a corresponding unrealized gain or loss in income.

The following table reconciles the changes in the fair value of financial instruments outstanding on June 30, 2007:

Risk management	June 30, 2007
Balance, December 31, 2006	$	54.0
Unrealized gain (loss) on financial instruments:
Commodities	(29.2		)
Electricity contracts	(4.0		)
Interest rate swaps	0.5
Fair value, end of period	$	21.3

Penn West had the following financial instruments outstanding as at June 30, 2007:

	Notional volume		Remaining term	Pricing		Market value
Crude oil
WTI Costless Collars	25,000 bbls/d		Jul/07 - Dec/07	US$ 56.00 to $83.80/bbl		$	(3.1	)
WTI Costless Collars	10,000 bbls/d		Jan/08 - Jun/08	US$ 60.00 to $94.55/bbl		2.1
WTI Costless Collars	10,000 bbls/d		Jan/08 - Dec/08	US$ 65.00 to $76.00/bbl		(4.5		)
WTI Costless Collars	5,000 bbls/d		Jul/08 - Dec/08	US$ 67.00 to $77.70/bbl		0.2
Natural gas
AECO Costless Collars	73,400 mcf/d		Jul/07 - Oct/07	$7.63 to $9.68/mcf		11.6
AECO Costless Collars	9,200 mcf/d		Nov/07 - Mar/08	$8.18 to $12.15/mcf		1.1
Electricity
Alberta Power Pool Swaps	67 MW		2007	$49.55/MWh		13.1
Alberta Power Pool Swaps	2 MW		2008	$57.00/MWh		0.5

Interest rate swaps	$	100.0	Jul/07 - Mar/08	4.356	%	0.3

Total						$	21.3

A realized gain of $2.0 million (2006 - $2.2 million) on the electricity contracts has been included in the operating costs.

Realized gains and losses on the interest rate swaps are charged to interest expense. In the period the fixed rate and the floating rate were approximately equal resulting in no reportable gain or loss being charged to interest rate expense in relation to the interest rate swaps.

9. Income taxes

On June 12, 2007, the Government of Canada enacted new tax legislation on publicly traded income trusts. Under the new rules, effective for the 2011 tax year, distributions representing return on capital will no longer be deductible for income tax purposes by certain SIFT entities, including Penn West, and will be taxed at an approximate of the corporate tax rate, currently expected to be 31.5 percent. As a result of the enactment, an additional $325.5 million future income tax liability and future income tax expense was recorded in the second quarter of 2007 to reflect the Trust’s current temporary differences between the accounting and tax values of assets and liabilities expected to be remaining in 2011. In accordance with GAAP, prior to the enactment, the Trust’s temporary differences were not recorded as future income taxes. The Trust’s temporary differences relate primarily to the net book value of oil and natural gas properties in excess of tax pools recorded on the Petrofund merger closing June 30, 2006.

10. Related-party transactions

During the first six months of 2007, Penn West paid $0.8 million (2006 – $2.3 million) of legal fees to a law firm of which a partner is also a director of Penn West.

Investor Information

Officers

William Andrew

President and CEO

David Middleton

Executive Vice President and COO

Thane Jensen

Senior Vice President, Exploration and Development

William Tang Kong

Senior Vice President, Corporate Development

Todd Takeyasu

Senior Vice President, and CFO

Gregg Gegunde

Vice President, Development

Eric Obreiter

Vice President, Production

Kristian Tange

Vice President, Business Development

Anne Thomson

Vice President, Exploration

Lucas Law

Vice President, Asset Management

Keith Luft

Vice President, Land and Legal

Directors

John A. Brussa

Chairman

Calgary, Alberta

William E. Andrew

Calgary, Alberta

Thomas E. Phillips (1)(2)(3)(4)(5)

Calgary, Alberta

James C. Smith (1)(3)(4)(5)

Calgary, Alberta

Murray R. Nunns (1)(2)(3)(5)

Calgary, Alberta

George H. Brookman (1)(4)(5)

Calgary, Alberta

James E. Allard (1)

Calgary, Alberta

Frank Potter (2)(4)

Toronto, Ontario

Shirley A. McClellan (4)(5)

Hanna, Alberta

Legal Counsel

Burnet, Duckworth & Palmer LLP

Calgary, Alberta

Dorsey & Whitney LLP

Vancouver, B.C.

Enerlaw LLP

Calgary, Alberta

Bankers

Canadian Imperial Bank of Commerce

Royal Bank of Canada

The Bank of Nova Scotia

Bank of Montreal

Bank of Tokyo-Mitsubishi (Canada)

Alberta Treasury Branches

Sumitomo Mitsui Banking Corporation of Canada

BNP Paribas (Canada)

Societe Generale

HSBC Bank Canada

The Toronto Dominion Bank

Citibank, N.A.

National Bank of Canada

Fortis Capital (Canada) Ltd.

Union Bank of California, N.A.

Transfer Agent

CIBC Mellon Trust Company

Calgary, Alberta

Investors are encouraged to contact CIBC Mellon Trust Company for information regarding their security holdings. They can be reached at:

CIBC Mellon Trust Company:

(416) 643-5000 or toll-free throughout North America at

1-800-387-0825

e-mail: inquiries@cibcmellon.ca

Web site: www.cibcmellon.ca

Independent Reserve Evaluator

GLJ Petroleum Consultants Ltd.

Calgary, Alberta

Auditors

KPMG LLP

Calgary, Alberta

Stock Exchange Listing

The Toronto Stock Exchange

Trading Symbol: PWT.UN

The New York Stock Exchange

Trading Symbol: PWE

Head Office

Suite 2200, 425 - First Street S.W.

Calgary, Alberta T2P 3L8

Telephone: (403) 777-2500

Toll Free: 1-866-693-2707

Fax: (403) 777-2699

Website: www.pennwest.com

For further information contact:

Investor Relations

Toll Free: 1-888-770-2633

E-mail: investor_relations@pennwest.com

William Andrew

President and CEO

Phone: (403) 777-2502

E-mail: bill.andrew@pennwest.com

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 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.

Refer to our MD&A for a more detailed discussion of forward-looking statements.

Notes:

(1) Member of the Audit Committee

(2) Member of the Human Resources and Compensation Committee

(3) Member of the Reserves Committee

(4) Member of the Governance Committee

(5) Member of the Health, Safety and Environment Committee