ex991.htm

MANAGEMENT’S DISCUSSION AND ANALYSIS

For the nine months ended September 30, 2010

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”, “We”, “Us” or “Our”) for the nine months ended September 30, 2010 and the audited consolidated financial statements and MD&A for the year ended December 31, 2009. The date of this MD&A is November 4, 2010.

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”) may be misleading, particularly if used in isolation. A boe conversion ratio of six thousand cubic feet of natural gas to one barrel of crude oil 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 funds flow, funds flow per unit-basic, funds flow per unit-diluted, netback, payout ratio and net debt 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. Funds flow is cash flow from operating activities before changes in non-cash working capital and asset retirement expenditures. Funds flow is used to assess our ability to fund distributions and planned capital programs. See below for reconciliations to funds flow to its nearest measure prescribed by GAAP. Netback is a per-unit-of-production measure of operating margin used in capital allocation decisions and to economically rank projects. Operating margin is calculated as revenue less royalties, operating costs and transportation and is used for similar purposes to netback. Payout ratio is calculated as distributions paid divided by funds flow which is used to assess the adequacy of retained funds flow to finance capital programs. Net debt is the sum of long-term debt, convertible debentures and working capital (excluding risk management and future income taxes) and is used to assess our leverage levels and hence the continuing appropriateness of our distribution and capital investment levels.

Calculation of Funds Flow

	Three months ended September 30						Nine months ended September 30
(millions, except per unit amounts)	2010			2009			2010			2009
Cash flow from operating activities	$	333		$	386		$	914		$	963
Increase (decrease) in non-cash working capital		(77	)		(50	)		(72	)		115
Asset retirement expenditures		11			13			38			49
Funds flow	$	267		$	349		$	880		$	1,127

Basic per unit	$	0.59		$	0.84		$	2.02		$	2.75
Diluted per unit	$	0.58		$	0.83		$	1.99		$	2.74

2010 THIRD QUARTER REPORT 1

Third Quarter Highlights

Key financial and operational results for the third quarter 2010 were as follows:

•

Production averaged 164,087 boe per day and was weighted 60 percent to liquids and 40 percent to natural gas.

•

Exploration and development capital expenditures, excluding net asset dispositions, totalled $293 million compared to $171 million in the third quarter of 2009. During the third quarter of 2010, we closed net property dispositions of $332 million (2009 - $29 million). In the quarter, we continued to execute on our resource play strategy by drilling 109 net wells of which 99 percent were drilled using horizontal multi-stage fracture technology.

•

Funds flow in the third quarter was $267 million compared to $349 million in the third quarter of 2009. The decline was primarily due to lower realized risk management gains.

•

Net loss was $25 million compared to a net income of $7 million in the third quarter of 2009. The decrease in net income in 2010 was mainly due to lower realized risk management gains and unrealized foreign exchange gains.

•

Netback was $23.13 per boe compared to $25.91 per boe in the third quarter of 2009. The decline was primarily due to lower realized risk management gains.

•

Distribution levels are currently set at $0.09 per unit, per month, subject to maintenance of current forecasts of commodity prices, production levels and levels of capital investment.

•

On September 23, 2010, we closed a joint venture agreement with a subsidiary of Mitsubishi Corporation (“Mitsubishi”) to develop our shale gas assets in the Cordova Embayment and certain conventional gas assets at our Wildboy property in northeastern British Columbia. As a result of the arrangement, we sold a 50 percent interest in these assets to Mitsubishi in exchange for $250 million of cash and approximately $200 million of future capital commitments. Mitsubishi will fund $600 million of the first $800 million of exploration and development expenditures in this joint venture and we will continue to serve as the operator of the assets.

2010 Year-to-date Highlights

•

Production averaged 164,123 boe per day and was weighted 59 percent to liquids and 41 percent to natural gas.

•

Net debt was reduced by approximately $787 million during the first nine months of 2010.

•

Exploration and development capital expenditures, excluding net asset dispositions, totalled $787 million compared to $492 million for the first nine months 2009. Net dispositions were $1,375 million in 2010 compared to $173 million for the comparable period in 2009.

•

Funds flow for the first nine months of 2010 was $880 million compared to $1,127 million for the comparable period in 2009. The decline was primarily due to lower realized risk management gains and lower production volumes as a result of asset dispositions completed in late 2009 and in 2010.

•

Net income was $247 million compared to a net loss of $132 million for 2009. The increase was primarily due to higher revenues resulting from stronger commodity prices and lower unrealized risk management losses.

•

Netback was $24.99 per boe compared to $25.75 per boe in 2009.

2010 THIRD QUARTER REPORT 2

Quarterly Financial Summary

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

Three months ended	Sep. 30 2010			June 30 2010		Mar. 31 2010		Dec. 31 2009			Sep. 30 2009		June 30 2009			Mar. 31 2009			Dec. 31 2008
Gross revenues (1)	$	728		$	718	$	806	$	831		$	800	$	791		$	781		$	968
Funds flow		267			269		344		366			349		430			348			490
Basic per unit		0.59			0.62		0.81		0.87			0.84		1.05			0.87			1.27
Diluted per unit		0.58			0.61		0.80		0.86			0.83		1.05			0.87			1.26
Net income (loss)		(25	)		195		77		(12	)		7		(41	)		(98	)		404
Basic per unit		(0.06	)		0.45		0.18		(0.03	)		0.02		(0.10	)		(0.25	)		1.05
Diluted per unit		(0.06	)		0.44		0.18		(0.03	)		0.02		(0.10	)		(0.25	)		1.04
Distributions declared		177			196		190		189			188		188			276			393
Per unit	$	0.39		$	0.45	$	0.45	$	0.45		$	0.45	$	0.45		$	0.69		$	1.02
Production
Liquids (bbls/d) (2)		98,380			95,777		96,317		101,636			104,583		104,070			105,643			105,644
Natural gas (mmcf/d)		394			408		410		411			441		459			447			476
Total (boe/d)		164,087			163,700		164,587		170,164			178,124		180,601			180,096			184,908

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

(2)	Includes crude oil and natural gas liquids.

Financial Markets

The global economic recovery previously forecasted by many analysts remains slower than anticipated. Economic growth rates in economies throughout Asia, the Middle East and South America remain higher than rates in developed countries. A number of countries, including the U.S., have implemented easing measures to encourage economic growth. Additionally, interest rates remain very low compared to historical rates in both Canada and the U.S.

Commodity Markets

Business Environment

To date in 2010, crude oil markets have been affected by wider concerns about the state of the economic recovery. Crude oil prices have been influenced by the European sovereign debt issues experienced during the second quarter of 2010 and concerns over the slowing of the economic recovery in the world’s developed economies throughout the third quarter of 2010. Economic growth remains strong in the developing economies of the world, particularly Asia, the Middle East and South America, with the expectation that these regions will lead crude oil demand in the coming quarters resulting in crude oil prices at least at current levels.

Continued economic growth in developing economies and pricing differentials have contributed to the redirection of liquefied natural gas (“LNG”) cargoes away from North America where prices remain influenced by supply and demand fundamentals. Significant shale gas development over the past few years has yielded sizeable supply additions resulting in a weak pricing environment. This has led to several large shale gas producers recently announcing reductions to their capital programs. During the third quarter of 2010, warm weather throughout the Northeastern and Southern U.S. led to increased natural gas demand for power generation which partially offset supply additions and prevented year-over-year increases to inventory levels. As we move into the winter season, some believe increased year-over-year production levels could lead to increased inventory levels and further downward pressure on natural gas prices.

2010 THIRD QUARTER REPORT 3

Crude Oil

WTI averaged US$76.21 per barrel in the third quarter of 2010 compared to US$77.99 per barrel in the second quarter of 2010 and US$68.29 per barrel for the third quarter of 2009. Pipeline constraints from various failures on the Enbridge Pipeline system further discounted prices of certain Canadian crude oil grades. Notably, heavy crudes traded at a much higher discount to the WTI price than in the previous quarter or the prior year with Western Canadian Select crude (“WCS”) trading as high as US$32.00 off WTI. These differentials have improved since the Enbridge pipelines have returned to service with WCS trading at approximately US$20.00 off WTI.

Our corporate average liquids price was $64.44 per barrel in the third quarter compared to $62.75 per barrel for the same period last year. Our higher price in 2010 was attributable to the increase in the benchmark WTI price. This was partially offset by year-over-year appreciation of the Canadian-U.S. dollar exchange rate and slightly higher quality and transportation discounts for Canadian crudes resulting from the Enbridge pipeline issues.

Currently, we have approximately 35 percent of our remaining 2010 crude oil production hedged between US$60.11 per barrel and US$75.72 per barrel and approximately 33 percent of our 2011 crude oil production hedged between US$80.06 per barrel and US$91.98 per barrel. Additionally, we have foreign exchange contracts to swap US$473 million of US dollar revenue for the remainder of 2010 and 2011 to Canadian dollars at an average rate of one US dollar equals 1.06 Canadian dollars to fix the floor price on a portion of our US dollar denominated oil collars in Canadian dollars.

Natural Gas

The AECO Monthly Index averaged $3.72 per mcf in the third quarter of 2010 compared to $3.86 per mcf in the second quarter of 2010 and to $3.03 per mcf for the third quarter of 2009. Shale gas production levels and drilling activity, particularly in the U.S., are significantly higher year-over-year. Thus, although natural gas demand has improved, inventory levels remain high. Demand for natural gas from the industrial sector recovered significantly in the first half of 2010, however, this appears to be flattening as the economic recovery slows. Recent demand increases for natural gas in the power generation sector were largely attributed to short-term demand due to the warm summer weather in certain parts of the U.S. rather than the longer-term capture of market share from other fuels for power generation.

Our corporate average natural gas price averaged $3.68 per mcf in the third quarter of 2010 compared to $3.13 per mcf for the same period last year. For the remainder of 2010, we have approximately 12 percent of our natural gas production hedged between $5.93 per mcf and $7.70 per mcf.

Business Strategy

In September 2010, we announced plans to convert to an exploration and production (“E&P”) company on or about January 1, 2011. Starting in 2008 and continuing into this year, we have executed a number of strategies to prepare for conversion including debt diversification and reduction, evaluation of our resource play potential including the building of large inventories of well locations, distribution reductions and increasing our technical/exploration personnel. Our resource evaluation has identified over 8,000 drilling locations on existing Penn West lands, including 3,800 specific locations and an additional 4,200 potential locations defined by geological mapping. Given the extent of our drilling inventory and our successful drilling results to-date in 2010, we increased our capital budget for 2010 by $150 million the majority of which will be spent in the fourth quarter of 2010.

During the third quarter of 2010, we entered into the Cordova Joint Venture which allows us to increase the pace of development in our conventional and unconventional natural gas assets in northeastern British Columbia. As part of the agreement, our partner will provide a significant financial commitment enabling us to accelerate the development of this large, unconventional play. Funding for the first $800 million of capital expenditures will consist of $600 million from our partner and $200 million from us while we retain a 50 percent interest in the project. This transaction, along with the Peace River Oil Partnership entered into during the second quarter of 2010, allows us to accelerate the development of two of our largest resource plays while maintaining focus on our significant portfolio of light-oil resource plays.

2010 THIRD QUARTER REPORT 4

To date in 2010, we have also executed strategies designed to increase our financial flexibility as an E&P company. Key transactions include the renewal of our unsecured, revolving bank facility for a three-year term with an aggregate borrowing limit of $2.25 billion, the realization of cash proceeds from the exchange of certain assets, completing an equity financing for total proceeds of $435 million ($424 million net) and issuing senior unsecured notes in the amount of US$250 million and CAD$50 million.

As we move into 2011, we will continue to reinvest a significant portion of our capital in our larger light-oil assets allocating capital to projects with higher rates of return and with significant future development potential. In the near term, our corporate strategy is to provide a combination of both growth and yield to our equity holders. As we look beyond 2011, we will continue to evaluate a wide range of properties and drilling results and will then reconsider our pace of development. With our significant land holdings, asset base and strong technical staff, we believe we have the right mix to be a highly successful E&P company.

RESULTS OF OPERATIONS

Production

	Three months ended September 30							Nine months ended September 30
Daily production	2010		2009		% change			2010		2009		% change
Light oil and NGL (bbls/d)		80,614		77,513		4			78,097		78,141		-
Heavy oil (bbls/d)		17,766		27,070		(34	)		18,735		26,621		(30	)
Natural gas (mmcf/d)		394		441		(11	)		404		449		(10	)
Total production (boe/d)		164,087		178,124		(8	)		164,123		179,600		(9	)

Production of 164,087 boe per day in the third quarter of 2010 increased slightly from the 163,700 boe per day produced in the second quarter of 2010. The increase was the result of our successful capital program to date in 2010, however, wet weather throughout Western Canada during the summer months caused delays in bringing a number of our wells on production. As at September 30, 2010, we anticipate the completion and tie-in of approximately 160 wells in the fourth quarter of 2010.

The decrease from the comparable periods in 2009 was mainly due to property dispositions including the Lloydminster property disposition completed in November 2009 of approximately 6,000 boe per day, predominantly of heavy oil and the asset exchange transaction completed in January 2010 (the “January 2010 asset swap”) of approximately 2,800 boe per day.

When economic to do so, we strive to maintain a strategic mix of liquids and natural gas production in order to reduce exposure to price volatility that can affect a single commodity. In the third quarter of 2010, crude oil and NGL production averaged 98,380 barrels per day (60 percent of production) and natural gas production averaged 394 mmcf per day (40 percent of production).

We drilled 109 net wells with a success rate of 98 percent in the third quarter of 2010 compared to 36 net wells at a success rate of 100 percent in the same period of 2009. Excluding stratigraphic and service wells, 99 percent of our drilling activity during the quarter utilized horizontal multi-stage fracture technology.

2010 THIRD QUARTER REPORT 5

Average Sales Prices

	Three months ended September 30								Nine months ended September 30
	2010			2009		% change			2010			2009		% change

Light oil and NGL (per bbl)	$	65.68		$	64.15		2		$	68.62		$	55.58		23
Risk management gain (loss) (per bbl) (1)		(1.69	)		4.90		(100	)		(2.19	)		10.41		(100	)
Light oil and NGL net (per bbl)		63.99			69.05		(7	)		66.43			65.99		1

Heavy oil (per bbl)		58.81			58.72		-			60.15			50.94		18

Natural gas (per mcf)		3.68			3.13		18			4.33			4.05		7
Risk management gain (per mcf) (1)		0.59			0.82		(28	)		0.45			0.75		(40	)
Natural gas net (per mcf)		4.27			3.95		8			4.78			4.80		-

Weighted average (per boe)		47.48			44.58		7			50.16			41.85		20
Risk management gain (per boe) (1)		0.58			4.17		(86	)		0.06			6.41		(99	)
Weighted average net (per boe)	$	48.06		$	48.75		(1	)	$	50.22		$	48.26		4

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

2010 THIRD QUARTER REPORT 6

Netbacks

	Three months ended September 30									Nine months ended September 30
	2010			2009			% change			2010			2009			% change
Light oil and NGL
Production (bbls/day)		80,614			77,513			4			78,097			78,141			-
Operating netback ($/bbl):
Sales price	$	65.68		$	64.15			2		$	68.62		$	55.58			23
Risk management gain (loss) (1)		(1.69	)		4.90			(100	)		(2.19	)		10.41			(100	)
Royalties		(13.37	)		(11.47	)		17			(13.71	)		(9.73	)		41
Operating costs		(19.94	)		(19.97	)		-			(20.21	)		(19.99	)		1
Netback	$	30.68		$	37.61			(18	)	$	32.51		$	36.27			(10	)
Conventional heavy oil
Production (bbls/day)		17,766			27,070			(34	)		18,735			26,621			(30	)
Operating netback ($/bbl):
Sales price	$	58.81		$	58.72			-		$	60.15		$	50.94			18
Royalties		(8.25	)		(8.55	)		(4	)		(8.76	)		(6.57	)		33
Operating costs		(17.32	)		(15.37	)		13			(17.10	)		(15.59	)		10
Transportation		(0.10	)		(0.06	)		67			(0.09	)		(0.06	)		50
Netback	$	33.14		$	34.74			(5	)	$	34.20		$	28.72			19
Total liquids
Production (bbls/day)		98,380			104,583			(6	)		96,832			104,761			(8	)
Operating netback ($/bbl):
Sales price	$	64.44		$	62.75			3		$	66.98		$	54.40			23
Risk management gain (loss) (1)		(1.39	)		3.63			(100	)		(1.77	)		7.77			(100	)
Royalties		(12.45	)		(10.71	)		16			(12.75	)		(8.93	)		43
Operating costs		(19.47	)		(18.78	)		4			(19.61	)		(18.87	)		4
Transportation		(0.02	)		(0.01	)		100			(0.02	)		(0.01	)		100
Netback	$	31.11		$	36.88			(16	)	$	32.83		$	34.36			(4	)
Natural gas
Production (mmcf/day)		394			441			(11	)		404			449			(10	)
Operating netback ($/mcf):
Sales price	$	3.68		$	3.13			18		$	4.33		$	4.05			7
Risk management gain (1)		0.59			0.82			(28	)		0.45			0.75			(40	)
Royalties		(0.48	)		(0.45	)		7			(0.62	)		(0.76	)		(18	)
Operating costs		(1.71	)		(1.56	)		10			(1.65	)		(1.55	)		7
Transportation		(0.22	)		(0.21	)		5			(0.22	)		(0.21	)		5
Netback	$	1.86		$	1.73			8		$	2.29		$	2.28			-
Combined totals
Production (boe/day)		164,087			178,124			(8	)		164,123			179,600			(9	)
Operating netback ($/boe):
Sales price	$	47.48		$	44.58			7		$	50.16		$	41.85			20
Risk management gain (1)		0.58			4.17			(86	)		0.06			6.41			(99	)
Royalties		(8.60	)		(7.41	)		16			(9.05	)		(7.12	)		27
Operating costs		(15.78	)		(14.90	)		6			(15.63	)		(14.87	)		5
Transportation		(0.55	)		(0.53	)		4			(0.55	)		(0.52	)		6
Netback	$	23.13		$	25.91			(11	)	$	24.99		$	25.75			(3	)

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

2010 THIRD QUARTER REPORT 7

Production Revenues

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

	Three months ended September 30							Nine months ended September 30
(millions)	2010		2009		% change			2010		2009		% change
Light oil and NGL	$	476	$	493		(3	)	$	1,417	$	1,413		-
Heavy oil		97		146		(34	)		309		370		(16	)
Natural gas		155		161		(4	)		526		589		(11	)
Gross revenues (1)	$	728	$	800		(9	)	$	2,252	$	2,372		(5	)

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

The decrease in revenue for 2010 from the comparative period in 2009 was mainly the result of lower realized risk management gains and property dispositions which reduced production of heavy oil and natural gas. For the first nine months of 2010, heavy oil production was 30 percent lower and natural gas production was 10 percent lower.

Reconciliation of decrease in Production Revenues

(millions)

Gross revenues - January 1 - September 30, 2009	$$	2,372
Decrease in light oil and NGL production		(1)
Increase in light oil and NGL prices (including realized risk management)		5
Decrease in heavy oil production		(110)
Increase in heavy oil prices		49
Decrease in natural gas production		(59)
Decrease in natural gas prices (including realized risk management)		(4)
Gross revenues - January 1 - September 30, 2010	$$	2,252

Royalties

	Three months ended September 30										Nine months ended September 30
	2010				2009				% change		2010				2009				% change
Royalties (millions)		$	130			$	122			7		$	406			$	349			16
Average royalty rate (1)			18	%			17	%		1			18	%			17	%		1
$/boe		$	8.60			$	7.41			16		$	9.05			$	7.12			27

(1)	Excludes effects of risk management activities.

In 2010, royalty rates and per boe amounts increased as a result of higher crude oil prices. We expect that recently announced provincial royalty programs will have a positive impact on the economics of our resource plays.

2010 THIRD QUARTER REPORT 8

Expenses

	Three months ended September 30							Nine months ended September 30
(millions)	2010		2009		% change			2010		2009		% change
Operating	$	239	$	244		(2	)	$	701	$	729		(4	)
Transportation		8		9		(11	)		25		26		(4	)
Financing		46		43		7			131		120		9
Unit-based compensation	$	14	$	14		-		$	41	$	39		5

	Three months ended September 30						Nine months ended September 30
(per boe)	2010		2009		% change		2010		2009		% change
Operating	$	15.78	$	14.90		6	$	15.63	$	14.87		5
Transportation		0.55		0.53		4		0.55		0.52		6
Financing		3.08		2.65		16		2.93		2.46		19
Unit-based compensation	$	0.92	$	0.82		12	$	0.91	$	0.79		15

Operating

During the third quarter of 2010, we incurred approximately $6 million of realized losses (2009 - $4 million) on our electricity contracts which had a $0.45 per boe effect (2009 - $0.25) on our results. In addition to the power costs, the property dispositions in late 2009 and throughout 2010 led to an increase in the per boe operating costs for both the third quarter and first nine months of 2010.

A realized loss of $10 million (2009 - $12 million) on electricity contracts has been included in operating costs for the first nine months of 2010.

We have approximately 90 percent of our remaining power hedged in 2010 and for 2011 at US$70.09 per MWH and US$63.16 per MWH, respectively.

Financing

Penn West Petroleum Ltd. (the “Company”) has a three-year, unsecured, revolving syndicated bank facility with an aggregate borrowing limit of $2.25 billion. The facility is extendible and expires on April 30, 2013. 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. As at September 30, 2010, approximately $0.6 billion was drawn under this facility.

As at September 30, 2010, the Company had $1.6 billion of senior unsecured notes outstanding as follows:

	Issue date	Amount (millions)	Term	Average interest rate	Weighted average remaining term
2007 Notes	May 31, 2007	US$475	8 - 15 years	5.80 percent	6.8 years
2008 Notes	May 29, 2008	US$480, CAD$30	8 - 12 years	6.25 percent	7.3 years
UK Notes	July 31, 2008	£57	10 years	6.95 percent (1)	7.8 years
2009 Notes	May 5, 2009	US$154, £20, €10, CAD$5	5 - 10 years	8.85 percent (2)	6.2 years
2010 Notes	March 16, 2010	US$250, CAD$50	5 - 15 years	5.50 percent	8.0 years

(1)	These notes bear interest at 7.78 percent in Pounds Sterling, however, contracts were entered to fix the interest rate at 6.95 percent in Canadian dollars and to fix the exchange rate on the repayment.

(2)	The Company entered into contracts to fix the interest rate on the Pounds Sterling and Euro tranches, initially at 9.49 percent and 9.52 percent, to 9.15 percent and 9.22 percent, respectively.

2010 THIRD QUARTER REPORT 9

On March 16, 2010, the Company closed the private placement of the 2010 Notes with an aggregate principal amount of approximately US$250 million and CAD$50 million. The 2010 Notes have a weighted average term of 8.6 years and bear a weighted average fixed interest rate of approximately 5.5 percent. The Company used the proceeds of the issue to repay advances on its syndicated bank facility.

At September 30, 2010, the Company had the following interest rate swaps outstanding:

Effective date	Termination date	Initial term	Nominal amount (millions)		Fixed rate (percent)
November 2008	November 2010	2 years	$	250	2.27
December 2008	December 2011	3 years	$	500	1.61
January 2009	January 2014	5 years	$	600	2.71
June 2010	January 2014	3.5 years	$	50	1.94

The interest rates on any non-hedged portion of the Company’s bank debt are subject to fluctuations in short-term money market rates as advances on the bank facility are generally held in short-term instruments. As at September 30, 2010, none of the balance (2009 - 21 percent) of our long-term debt instruments was exposed to changes in short-term interest rates. On September 30, 2010, our fixed interest rate debt (including the effects of interest rate swaps) had a weighted average rate of approximately 4.60 percent (2009 - 4.58 percent).

Financing charges for the third quarter and first nine months of 2010 are higher year-over-year due to a higher percentage of our debt capital being held in senior unsecured notes compared to the prior period as well as the increased cost of borrowing with the new bank facility. The Company’s senior unsecured notes contain higher interest rates than the syndicated bank facilities held in short-term money market instruments. Notwithstanding the current interest rate differentials, we believe the long term and fixed interest rates inherent in the senior notes is favourable for a portion of our debt capital structure.

Realized gains and losses on the interest rate swaps are recorded as financing costs. For the third quarter of 2010 an expense of $5 million (2009 - $5 million) and for the first nine months of 2010 an expense of $17 million (2009 - $13 million) was recognized to reflect that the floating interest rate decreased compared to the fixed interest rate transacted under our financial instruments.

Unit-Based Compensation

Unit-based compensation expense is related to our Trust Unit Rights Incentive Plan (“TURIP”) and our Long-Term Retention and Incentive Plan (“LTRIP”) as described in Note 9 of our unaudited interim consolidated financial statements. The LTRIP was implemented in the first quarter of 2010. Compensation expense related to the TURIP is based on the fair value of trust unit rights issued, determined using a Binomial Lattice option-pricing model. The fair value of TURIP rights issued is amortized over the remaining vesting periods on a straight-line basis and is allocated to operating and general and administrative expense as applicable. The intrinsic cost of the LTRIP is charged to income based on our unit price at the end of each reporting period plus accumulated distributions multiplied by the number of LTRIP awards outstanding. The LTRIP obligation is accrued over the vesting period as service is completed by employees and is allocated to operating and general and administrative expense as applicable based on a graded vesting schedule. Subsequent increases and decreases in the underlying unit price will result in increases and decreases, respectively, to the underlying LTRIP obligation until settlement.

2010 THIRD QUARTER REPORT 10

	Three months ended September 30							Nine months ended September 30
(millions, except per boe amounts)	2010		2009		% change			2010		2009		% change
TURIP
Operating expense	$	3	$	4		(25	)	$	9	$	10		(10	)
General and administrative expense		9		10		(10	)		27		29		(7	)
LTRIP
Operating expense		1		-		100			3		-		100
General and administrative expense		1		-		100			2		-		100
Unit-based compensation expense	$	14	$	14		-		$	41	$	39		5

The unit price used in the LTRIP intrinsic cost calculation was $20.62 (September 30, 2009 - N/A).

General and Administrative Expenses (“G&A”)

	Three months ended September 30						Nine months ended September 30
(millions, except per boe amounts)	2010		2009		% change		2010		2009		% change
Gross	$	50	$	47		6	$	145	$	142		2
Per boe		3.31		2.86		16		3.24		2.90		12
Net (including unit-based compensation)		46		43		7		133		125		6
Per boe		3.06		2.60		18		2.98		2.54		17
Net (excluding unit-based compensation)		36		33		9		104		96		8
Per boe	$	2.40	$	1.99		21	$	2.33	$	1.95		19

For 2010, gross G&A costs remained consistent compared to 2009 both for the third quarter and the year-to-date results. The increase in the cost per boe in 2010 was primarily due to lower production volumes compared to 2009.

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

	Three months ended September 30							Nine months ended September 30
(millions, except per boe amounts)	2010		2009		% change			2010		2009		% change
Depletion of oil and natural gas assets	$	314	$	393		(20	)	$	963	$	1,157		(17	)
Accretion of asset retirement obligations		10		11		(9	)		30		32		(6	)
Total DD&A	$	324	$	404		(20	)	$	993	$	1,189		(16	)
DD&A expense per boe	$	21.40	$	24.64		(13	)	$	22.17	$	24.25		(9	)

DD&A for 2010 decreased compared to the prior year as a result the contribution of assets into the Peace River Oil Partnership and Cordova Joint Venture and lower production volumes due to property dispositions.

2010 THIRD QUARTER REPORT 11

Taxes

	Three months ended September 30									Nine months ended September 30
(millions)	2010			2009			% change			2010			2009			% change
Future income tax recovery	$	(56	)	$	(61	)		(8	)	$	(269	)	$	(296	)		(9	)

Included in the 2010 recovery was $177 million relating to property dispositions. The comparative figure in 2009 included a $124 million recovery related to unrealized risk management losses and a $65 million recovery related to legislation enacted during the year by the Government of Canada which reduced the provincial component of the SIFT tax rate from 13 percent to 10 percent.

Under our current structure, the operating entities make interest and royalty payments to the Trust, which transfers taxable income to the Trust level, eliminating income subject to corporate income taxes in the operating entities. The Trust eliminates its taxable income, in part, by deducting distributions paid to its unitholders. Under the Specified Investment Flow-Through (“SIFT”) legislation, which was enacted in June 2007 and is effective January 1, 2011, distributions will no longer be tax deductible by the Trust. If the Trust was to continue in its current form, the Trust would be taxed on its income similar to corporations.

Effective on or about January 1, 2011, we expect to convert into a publically-traded corporation. We will then be subject to current and future taxes at normal Canadian corporate rates. As the currently legislated SIFT rate is comparable to corporate tax rates, we do not anticipate corporate conversion to result in a significant adjustment to our existing future tax liability under Canadian GAAP.

We currently have a significant tax pool base. Based on current commodity prices and capital spending plans, we forecast we could use these pools, equally as a trust or corporation, to shelter our taxable income for an extended period after 2010.

Foreign Exchange

	Three months ended September 30									Nine months ended September 30
(millions)	2010			2009			% change			2010			2009			% change
Unrealized foreign exchange gain	$	(46	)	$	(118	)		(61	)	$	(27	)	$	(161	)		(83	)

We record unrealized foreign exchange gains or losses to translate the U.S., UK and Euro notes and the related accrued interest to Canadian dollars using the exchange rates in effect on the balance sheet date. The $27 million gain during 2010 was primarily due to the strengthening of the Canadian dollar relative to the US dollar of which $26 million related to changes to our senior unsecured notes and $1 million related to changes in our working capital balances.

2010 THIRD QUARTER REPORT 12

Funds Flow and Net Income (Loss)

	Three months ended September 30								Nine months ended September 30
	2010			2009		% change			2010		2009			% change
Funds flow (1) (millions)	$	267		$	349		(23	)	$	880	$	1,127			(22	)
Basic per unit		0.59			0.84		(30	)		2.02		2.75			(27	)
Diluted per unit		0.58			0.83		(30	)		1.99		2.74			(27	)

Net income (loss) (millions)		(25	)		7		(100	)		247		(132	)		100
Basic per unit		(0.06	)		0.02		(100	)		0.57		(0.32	)		100
Diluted per unit	$	(0.06	)	$	0.02		(100	)	$	0.56	$	(0.32	)		100

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

Funds flow in the third quarter of 2010 and for the first nine months of 2010 were lower than the comparable periods in 2009 primarily as a result of property dispositions which led to a decline in 2010 production and lower realized risk management gains. The monetization of the foreign exchange contracts completed in the second quarter of 2009 resulting in a gain of $75 million also affected the year-to-date comparison.

Net income for the first nine months of 2010 was higher than 2009 primarily due to higher revenues and lower unrealized risk management losses. For the third quarter of 2010, the net loss was mainly due to lower realized risk management gains in comparison to the third quarter of 2009.

Capital Expenditures

	Three months ended September 30						Nine months ended September 30
(millions)	2010			2009			2010			2009
Land acquisition and retention	$	(12	)	$	4		$	92		$	16
Drilling and completions		247			77			533			192
Facilities and well equipping		51			75			137			250
Geological and geophysical		1			1			10			6
CO2 pilot costs		1			4			8			5
Corporate		5			10			7			23
Exploration and development capital		293			171			787			492
Property dispositions, net		(332	)		(29	)		(1,375	)		(173	)
Capital expenditures (dispositions)		(39	)		142			(588	)		319
Business combinations		-			-			-			116
Total expenditures (dispositions)	$	(39	)	$	142		$	(588	)	$	435

We drilled 109 net wells in the third quarter of 2010 (2009 - 36) resulting in 86 net oil wells, 14 net natural gas wells and seven stratigraphic and service wells with a success rate of 98 percent (2009 - 100 percent). During the quarter, excluding stratigraphic and service wells, 99 percent of our drilling activity utilized horizontal multi-stage fracture technology.

In 2010, we increased our capital spending compared to 2009 due to stronger commodity and other markets and in anticipation of our conversion to an E&P company resulting in an increase in drilling and completions expenditures. The 2010 capital program is weighted towards our large oil resource plays, including the Cardium, the Amaranth and the Carbonates. During the third quarter of 2010, as a result of entering into the Cordova Joint Venture, we sold a portion of land purchased in the second quarter of 2010 to our partner as a part of the transaction.

For the first nine months of 2010, $21 million was capitalized (2009 - $4 million disposed) for additions to asset retirement obligations from our capital program and property acquisitions, net of property dispositions.

2010 THIRD QUARTER REPORT 13

Peace River Oil Partnership

As previously announced on June 1, 2010, we closed the transaction creating the Peace River Oil Partnership to develop oil resources in the Peace River area of northern Alberta. We contributed assets valued at $1.8 billion, retaining a 55 percent interest in the partnership and received approximately $817 million which included $312 million cash paid upon closing and $505 million committed to us to fund our share of future capital and operating expenses for the Peace River Oil Partnership. As a result, on approximately the first $1.0 billion of capital costs, we will contribute approximately $56 million while maintaining a 55 percent interest in the partnership. In addition, we closed a private placement issuing approximately 23.5 million trust units to our partner for gross proceeds of $435 million ($424 million net).

Cordova Joint Venture

On September 23, 2010, we closed a joint venture agreement with a subsidiary of Mitsubishi to develop our shale gas assets in the Cordova Embayment and certain conventional gas assets at our Wildboy property in northeastern British Columbia. As a result of the arrangement, we sold a 50 percent interest in these assets to Mitsubishi in exchange for approximately $450 million consisting of $250 million of cash and approximately $200 million of future capital commitments. Mitsubishi will fund $600 million of the first $800 million of exploration and development expenditures in this joint venture and we will continue to serve as the operator of the assets.

Goodwill

(millions)	September 30, 2010					December 31, 2009
Balance, beginning and end of period		$	2,020			$	2,020

We recorded goodwill on our acquisitions of Petrofund Energy Trust, Canetic Resources Trust and Vault Energy Trust. We determined there was no goodwill impairment at September 30, 2010.

Business Risks

The disclosures under this heading (excluding the information under environmental and climate change risk), in conjunction with Note 10 to the unaudited interim consolidated financial statements, are incorporated into and are an integral part of, the unaudited interim consolidated financial statements.

We are exposed to normal market risks inherent in the oil and natural gas business, including, but not limited to, commodity price risk, foreign currency risk, credit risk, interest rate risk, liquidity risk and environmental and climate change risk. We seek to mitigate these risks through various business processes and management controls and from time to time by using financial instruments.

For a summary of outstanding financial instruments, please refer to “Financial Instruments” later in this MD&A and to Note 10 to our unaudited interim consolidated financial statements.

Commodity Price Risk

Commodity price fluctuations are among our most significant exposures. Crude oil prices are influenced by worldwide factors such as OPEC actions, supply and demand fundamentals, and geopolitical events. Natural gas prices are influenced by the price of alternative fuel sources such as oil or coal and by North American natural gas supply and demand fundamentals including the levels of industrial activity, weather, storage levels and liquefied natural gas imports. In accordance with policies approved by our Board of Directors, we may, from time to time, manage these risks through the use of swaps, collars or other financial instruments up to a maximum of 50 percent of forecast sales volumes, net of royalties, for the balance of any current year plus one additional year forward and up to a maximum of 25 percent for one additional year thereafter.

2010 THIRD QUARTER REPORT 14

Foreign Currency Rate Risk

Prices received for crude oil are referenced to or denominated directly in US dollars, thus our realized oil prices are impacted by Canadian dollar to US dollar exchange rates. A portion of our debt capital is denominated in US dollars, thus the principal and interest payments in Canadian dollars are also impacted by exchange rates. When we consider it appropriate, we may use financial instruments to fix or collar future exchange rates inversely to the effect on crude oil revenues. At September 30, 2010, we had the following foreign currency forward contracts outstanding:

Initial Term	Nominal Amount (millions)	Termination date	Exchange rate
19-month term	Sell US$599	December 2011	1.06085 CAD/USD
8-year term	Buy US$80	May 2015	1.01027 CAD/USD
10-year term	Buy US$80	May 2017	1.00016 CAD/USD
12-year term	Buy US$70	May 2019	0.99124 CAD/USD
15-year term	Buy US$20	May 2022	0.98740 CAD/USD

At September 30, 2010, we had US dollar denominated debt with a face value of US$1.1 billion outstanding (December 31, 2009 - US$0.9 billion) on which the repayment of the principal amount in Canadian dollars is not fixed.

Credit Risk

Credit risk is the risk of loss if purchasers or counterparties do not fulfill their contractual obligations. Our receivables are principally with customers in the oil and natural gas industry and are generally subject to normal industry credit risk, which includes the right to recover unpaid receivables by receiving the partner’s share of production when we are the operator. For oil and natural gas sales and financial derivatives, we follow a counterparty risk procedure whereby each counterparty is reviewed on a regular basis for the purpose of assigning a credit limit and is requested to provide security if deemed necessary. For financial derivatives, we normally transact with counterparties who are members of our banking syndicate or other counterparties that have investment grade bond ratings. We monitor credit events related to all counterparties and reassess credit exposures on a regular basis. As necessary, provisions for potential credit related losses are recognized.

As at September 30, 2010, the maximum exposure to credit risk was $310 million (December 31, 2009 - $371 million) being the carrying value of the accounts receivable.

Interest Rate Risk

We currently maintain a portion of our debt capital in floating-rate bank facilities which results in exposure to fluctuations in short-term interest rates which remain at lower levels than longer-term rates. From time to time, we may increase the certainty of our future interest rates by entering fixed interest rate debt instruments or by using financial instruments to swap floating interest rates for fixed rates or to collar interest rates.

As at September 30, 2010, we had a total of $1.6 billion of fixed interest rate debt instruments and $0.3 billion of convertible debentures outstanding. On the fixed interest rate debt, as at September 30, 2010, the average remaining term was 7.2 years (2009 - 7.9 years) with an average interest rate of 6.34 percent (2009 - 6.54 percent). For further details on these instruments, refer to the “Financing” and “Convertible Debentures” sections in this MD&A.

2010 THIRD QUARTER REPORT 15

Liquidity Risk

Liquidity risk is the risk that we will be unable to meet our financial liabilities as they come due. Management utilizes short and long-term financial and capital forecasting programs to ensure credit facilities are sufficient relative to forecast debt levels, distribution and capital program levels are appropriate, and that financial covenants will be met. Management also regularly reviews capital markets to identify opportunities to optimize the debt capital structure on a cost effective basis. In the short term, liquidity is managed through daily cash management activities, short-term financing strategies and the use of collars and other financial instruments to increase the predictability of cash flow from operating activities. Additional information on specific instruments is discussed in Notes 5 and 6 to the unaudited interim consolidated financial statements.

The following table outlines estimated future contractual obligations for non-derivative financial liabilities as at September 30, 2010:

(millions)	2010		2011		2012		2013		2014		Thereafter
Bank debt	$	-	$	-	$	-	$	639	$	-	$	-
Senior unsecured notes		-		-		-		5		61		1,555
Convertible debentures		-		255		-		-		-		-
Accounts payable		668		-		-		-		-		-
Distributions payable		41		-		-		-		-		-
Total	$	709	$	255	$	-	$	644	$	61	$	1,555

Environmental and Climate Change Risk

The oil and gas industry has a number of environmental risks and hazards and is subject to regulation by all levels of government. Environmental legislation includes, but is not limited to, operational controls, site restoration requirements and restrictions on emissions of various substances produced in association with oil and natural gas operations. Compliance with such legislation could require additional expenditures and a failure to comply may result in fines and penalties which could, in the aggregate and under certain unlikely assumptions, become material.

We are dedicated to reducing the environmental impact from our operations through our environmental programs which include resource conservation, stakeholder communication, CO2 sequestration, water management and site abandonment/reclamation. We continuously monitor our operations to minimize the environmental impact from our operations, allocate sufficient capital to reclamation and other activities and are committed to mitigating the impact in the areas in which we operate.

Liquidity and Capital Resources

Capitalization

	September 30, 2010				December 31, 2009
(millions)			%				%
Trust units issued, at market	$	9,376		77	$	7,821		69
Bank loans and long-term notes		2,260		19		3,219		28
Convertible debentures		255		2		273		2
Working capital deficiency (1)		296		2		106		1
Total enterprise value	$	12,187		100	$	11,419		100

(1)	Excludes the current portion of risk management, future income taxes and convertible debentures.

For the first nine months of 2010, we paid total distributions, including those funded by the distribution reinvestment plan, of $585 million compared to distributions of $721 million for the comparable period of 2009.

2010 THIRD QUARTER REPORT 16

The decline in long-term debt in 2010 was mainly due to repayments made on our syndicated bank facility as a result of proceeds received from the January 2010 asset swap, cash received upon closing of the Peace River Oil Partnership transaction and the Cordova Joint Venture and an equity offering completed in June 2010 to a private investor. On April 30, 2010, the Company closed the renewal of its unsecured, revolving, syndicated bank facilities with an aggregate borrowing limit of $2.25 billion and as of September 30, 2010 has approximately $1.6 billion of unused credit capacity available. For further details on these debt instruments, please refer to the “Financing” and “Convertible Debentures” sections of this MD&A.

We actively manage our debt portfolio and consider opportunities to reduce or diversify our debt structure. We have an active risk management program to limit our exposure to certain risks and maintain close relationships with our lenders and agents to monitor credit market developments. These actions aim to increase the likelihood of maintaining our financial flexibility to capture opportunities availed in the markets in addition to the continuation of our capital and distribution programs and the longer-term execution of our business strategies.

The Company has a number of covenants related to its syndicated bank facility and senior, unsecured notes. On September 30, 2010, the Company was in compliance with all of these financial covenants which comprise the following:

	Limit	September 30, 2010
Senior debt to EBITDA	Less than 3:1	1.60
Total debt to EBITDA	Less than 4:1	1.61
Senior debt to capitalization	Less than 50 percent	21%
Total debt to capitalization (1)	Less than 55 percent	21-23%

(1)	The definitions of Total debt differ slightly among the agreements in relation to convertible debentures.

The 2008 Notes, the UK Notes, the 2009 Notes and the 2010 Notes contain change of control provisions whereby if a change of control occurs, the Company may be required to offer to prepay the notes, which the holders have the right to refuse. Currently, we anticipate our conversion to a corporation will not trigger a change in control under the Note agreements.

Distributions may be in cash or trust units and may be monthly, quarterly or special at the discretion of our Board of Directors. To the extent that additional cash distributions are paid and capital programs are not adjusted, debt levels may increase. Under the terms of its current trust indenture, the Trust is required to make distributions to unitholders in amounts at least equal to its taxable income; however, the amount of taxable income allocated to the Trust from the operating entities is subject to management’s discretion. In the event a special distribution is required in order to distribute all of the Trust’s taxable income, such a distribution would generally be in trust units. The number of outstanding trust units would be reset to 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. We have never declared such a distribution and, at the current time, forecast that such a special distribution will not be required for 2010.

Due to the extent of our environmental programs, we believe no benefit would arise from the initiation of a reclamation fund. We believe our program will be sufficient to meet or exceed existing environmental regulations and best industry practices. In the event of significant changes to the environmental regulations or the cost of environmental activities, a higher portion of funds flow would be required to fund our environmental expenditures.

Convertible Debentures

During the third quarter of 2010, no convertible debentures were redeemed and settled in units (2009 - $1 million) and $18 million (2009 - $7 million) matured and were settled in units. For the first nine months of 2010, an insignificant amount of convertible debentures were redeemed and settled in units (2009 - $12 million), no amounts were redeemed and settled in cash (2009 - $4 million) and $18 million (2009 - $7 million) matured and were settled in units.

2010 THIRD QUARTER REPORT 17

At September 30, 2010, the balance of our unsecured, subordinated convertible debentures outstanding was as follows:

Description of security	Outstanding (millions)		Maturity date	Conversion price (per unit)		Redemption prices (per $1,000 face value)
PWT.DB.E 7.2% Convertible	$	26	May 31, 2011	$	75.00	$1,025 May 31, 2010 to maturity
PWT.DB.F 6.5% Convertible extendible		229	Dec. 31, 2011	$	51.55	$1,050 Dec. 31, 2009 - Dec. 30, 2010 $1,025 Dec. 31, 2010 to maturity
Total	$	255

Standardized Distributable Cash

	Three months ended September 30						Nine months ended September 30
(millions, except per unit amounts)	2010			2009			2010			2009
Cash flow from operating activities	$	333		$	386		$	914		$	963
Productive capacity maintenance (1)		(293	)		(171	)		(787	)		(492	)
Standardized distributable cash		40			215			127			471
Proceeds from the issue of trust units (2)		55			34			580			355
Debt and working capital changes		82			(61	)		(144	)		(174	)
Cash distributions declared	$	177		$	188		$	563		$	652
Accumulated cash distributions, beginning		4,887			4,124			4,501			3,660
Accumulated cash distributions, ending	$	5,064		$	4,312		$	5,064		$	4,312

Standardized distributable cash per unit, basic		0.09			0.51			0.29			1.15
Standardized distributable cash per unit, diluted		0.09			0.51			0.29			1.15
Standardized distributable cash payout ratio (3)		4.43			0.87			4.43			1.38

Distributions declared per unit	$	0.39		$	0.45		$	1.29		$	1.59
Net income as a percentage of cash distributions declared		N/A			4	%		44	%		N/A
Cash flows from operating activities as a percentage of cash distributions declared		188	%		205	%		162	%		148	%

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

(2)	Consists of proceeds from the Distribution Reinvestment and Optional Purchase Plan, the TURIP, the Employee Retirement Savings Plan and the equity issuances that were completed in February 2009 and June 2010.

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

(millions, except ratios)	To September 30, 2010
Cumulative standardized distributable cash from operations (1)	$	3,564
Issue of trust units		1,509
Debt and working capital changes		(9	)
Cumulative cash distributions declared (1)	$	5,064

Standardized distributable cash payout ratio (2)		1.4

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

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

2010 THIRD QUARTER REPORT 18

We strive to fund both distributions and maintenance capital programs primarily from funds flow. As an income trust, we budgeted our capital programs at approximately 50-60 percent of annual forecast funds flow. As we move towards a conventional E&P structure, we are targeting a level of return to our equity holders which will include a combination of organic growth and yield. We believe that proceeds from the Distribution Reinvestment and Optional Purchase Plan should be used to fund capital expenditures of a longer-term nature. Additional borrowings and equity issues may be required from time to time to fund a portion of our distributions, decrease or reallocate our debt capital or to maintain or increase our productive capacity. Adjustments to the level of distributions and/or capital expenditures to maintain or increase our productive capacity may be required or desirable based on forecast levels of funds flow, capital efficiency and debt levels.

Productive capacity maintenance is the estimated amount of capital funds required in a period for an enterprise to maintain future cash flows from operating activities at a constant level. As commodity prices can be volatile and short-term variations in production levels are often experienced in our industry, we define our productive capacity as production on a barrel of oil equivalent basis. A quantifiable measure for these short-term variations is not objectively determinable or verifiable due to various factors including the inability to distinguish natural production declines from the effect of production additions resulting from capital and optimization programs, and the effect of temporary production interruptions. As a result, the adjustment for productive capacity maintenance in our calculation of standardized distributable cash is our capital expenditures during the period excluding the cost of any asset acquisitions or proceeds of any asset dispositions. We believe that our capital programs as an income trust, based on investing 50-60 percent of forecast annual funds flow and our current view of our assets and opportunities, including particularly our resource play assets, our proposed enhanced oil recovery projects, and our outlook for commodity prices and industry conditions, should be sufficient to maintain our productive capacity over the medium term. We set our internal hurdle rates for evaluating potential development and optimization projects according to these parameters. Due to the risks inherent in the oil and natural gas industry, particularly our exploration and development activities and variations in commodity prices, there can be no assurance that capital programs, whether limited to the excess of funds flow over distributions or not, will be sufficient to maintain or increase our production levels or cash flow from operating activities. We historically incur a larger proportion of our exploration and 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 debt, any seasonality is not currently expected to influence our distribution policies.

Our calculation of standardized distributable cash has no adjustment for long-term unfunded contractual obligations. We believe our only significant long-term unfunded contractual obligation at this time is for asset retirement obligations. Cash flow from operating activities, used in our standardized distributable cash calculation, includes a deduction for abandonment expenditures incurred during each period. We believe that our current environmental programs will be sufficient to fund our asset retirement obligations over the life of our reserves. Our Board of Directors sets our distribution policies based on forecast funds flow and debt levels. Accordingly, distributions in excess of net income may include an economic return of capital to unitholders.

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

2010 THIRD QUARTER REPORT 19

Financial Instruments

We had the following financial instruments outstanding as at September 30, 2010. Fair values are determined using external counterparty information which is compared to observable market data. We limit our credit risk by executing counterparty risk procedures which include transacting only with institutions within our credit facility or with high credit ratings and by obtaining financial security in certain circumstances.

	Notional volume	Remaining term		Pricing			Fair value
Crude oil
WTI Collars	35,000 bbls/d	Oct/10 - Dec/10		US$60.11 to $75.72/bbl			$	(29	)
WTI Collars	35,000 bbls/d	Jan/11 - Dec/11		US$80.06 to $91.98/bbl				13
Natural gas
AECO Collars (1)	63,000 GJ/d	Oct/10		$6.50 to $9.50/GJ				10
AECO Collars (2)	30,000 GJ/d	Oct/10 - Dec/10		$5.00 to $5.75/GJ				6
Electricity swaps
Alberta Power	65 MW	Oct/10 - Dec/10		$71.40/MWh				(5	)
Alberta Power	25 MW	Oct/10 - Dec/11		$66.70/MWh				(6	)
Alberta Power	65 MW	Jan/11 - Dec/11		$61.79/MWh				(10	)
Alberta Power	45 MW	Jan/12 - Dec/12		$53.02/MWh				(2	)
Alberta Power	30 MW	Jan/12 - Dec/13		$54.60/MWh				(2	)
Alberta Power	20 MW	Jan/13 - Dec/13		$56.10/MWh				-
Alberta Power	50 MW	Jan/14 - Dec/14		$58.50/MWh				(1	)
Interest rate swaps
	$250	Oct/10 - Nov/10			2.27	%		(1	)
	$500	Oct/10 - Dec/11			1.61	%		(2	)
	$600	Oct/10 - Jan/14			2.71	%		(21	)
	$50	Oct/10 - Jan/14			1.94	%		(1	)
Foreign exchange forwards
19-month term	US$599	Oct/10 - Dec/11		1.06085 CAD/USD				13
8-year term	US$80		2015	1.01027 CAD/USD				4
10-year term	US$80		2017	1.00016 CAD/USD				5
12-year term	US$70		2019	0.99124 CAD/USD				4
15-year term	US$20		2022	0.98740 CAD/USD				1
Cross currency
10-year term	£57		2018	2.0075 CAD/GBP, 6.95%				(21	)
10-year term	£20		2019	1.8051 CAD/GBP, 9.15%				(4	)
10-year term	€10		2019	1.5870 CAD/EUR, 9.22%				(2	)

Total							$	(51	)

(1)	The collars total approximately 59,700 mcf per day between prices of $6.85 and $10.02 per mcf.

(2)	The collars total approximately 28,400 mcf per day between prices of $5.27 and $6.06 per mcf.

Please refer to our website at www.pennwest.com for details of all financial instruments currently outstanding.

Subsequent to the end of the third quarter, Penn West entered into additional crude oil collars on 10,000 barrels per day for 2012 at US$83.00 per barrel to US$94.47 per barrel.

2010 THIRD QUARTER REPORT 20

Outlook

This outlook section is included to provide unitholders with information about our expectations as at November 4, 2010 for production and capital expenditures for 2010 and 2011 and readers are cautioned that the information may not be appropriate for any other purpose. This information constitutes forward-looking information. Readers should note the assumptions, risks and disclaimers under "Forward-Looking Statements".

In September 2010, Penn West added $150 million to its capital program as a result of its successful drilling program and in order to increase its activity levels in anticipation of its conversion to an E&P company. Penn West’s 2010 exploration and development capital expenditures are now expected to be approximately $1.0 billion. Based on this level of capital expenditures Penn West forecasts its 2010 average production to be approximately 165,000 to 167,000 boe per day.

Our prior production forecast, released on August 5, 2010 with our second quarter results and filed on SEDAR at www.sedar.com was based on 2010 average production of 164,000 to 172,000 boe per day. As the end of a reporting period approaches, production guidance ranges are typically narrowed.

Penn West has an exploration and development capital budget for 2011, in the range of approximately $1.0-$1.2 billion. Penn West is focusing its capital program on its suite of large-scale light-oil plays including the Cardium, the Amaranth and the emerging Carbonates play in northwest Alberta. Estimated average production for 2011 ranges from approximately 172,000 to 177,000 boe per day for the year.

Sensitivity Analysis

Estimated sensitivities to selected key assumptions on reported financial results for the 12 months subsequent to this reporting period, including risk management contracts entered to date, are based on forecasted results as discussed in our Outlook.

		Impact on funds flow
Change of:	Change	$ millions	$/unit
Price per barrel of liquids	$1.00	19	0.04
Liquids production	1,000 bbls/day	17	0.04
Price per mcf of natural gas	$0.10	12	0.03
Natural gas production	10 mmcf/day	6	0.01
Effective interest rate	1%	6	0.01
Exchange rate ($US per $CAD)	$0.01	19	0.04

2010 THIRD QUARTER REPORT 21

Contractual Obligations and Commitments

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

(millions)	2010		2011		2012		2013		2014		Thereafter
Long-term debt	$	-	$	-	$	-	$	644	$	61	$	1,555
Transportation		6		26		15		9		3		-
Transportation ($US)		1		4		4		4		4		4
Power infrastructure		7		10		10		10		10		13
Drilling rigs		4		10		7		6		1		-
Purchase obligations (1)		3		13		13		13		11		18
Interest obligations		36		142		127		111		100		308
Office lease (2)	$	18	$	71	$	68	$	66	$	60	$	597

(1)	These amounts represent estimated commitments of $54 million for CO2 purchases and $17 million for processing fees related to interests in the Weyburn Unit.

(2)	Future office lease commitments will be reduced by sublease recoveries totalling $419 million.

Our syndicated credit facility is due for renewal on April 30, 2013. If we are not successful in renewing or replacing the facility, we could be required to repay all amounts then outstanding on the facility or enter other loans including term bank loans. In addition, we have an aggregate of $1.6 billion in senior notes maturing between 2014 and 2025. We continuously monitor our credit metrics and maintain positive working relationships with our lenders and agents.

Convertible debentures with an aggregate principal amount of $255 million were outstanding on September 30, 2010 (December 31, 2009 - $273 million). A significant portion of the interest payable on convertible debentures may, at the option of Penn West, be settled by the issuance of trust units. As at November 4, 2010, convertible debentures with an aggregate principal amount of $255 million were outstanding. For a schedule of convertible debenture maturities, please refer to the “Convertible Debentures” section of this MD&A or Note 6 to the unaudited interim consolidated financial statements.

Equity Instruments

Trust units issued:
As at September 30, 2010	454,711,951
Issued on exercise of trust unit rights	1,057,435
Issued to employee savings plan	161,296
Issued pursuant to distribution reinvestment plan	378,343
As at November 4, 2010	456,309,025

Trust unit rights outstanding:
As at September 30, 2010	34,260,482
Granted	157,100
Exercised	(1,057,435	)
Forfeited	(106,332	)
As at November 4, 2010	33,253,815

Internal Control over Financial Reporting

No changes in our internal control over financial reporting ("ICOFR") were made during the quarter ended September 30, 2010 that have materially affected, or are reasonably likely to materially affect, our ICOFR.

2010 THIRD QUARTER REPORT 22

Accounting Changes and Pronouncements

Future Accounting Pronouncements

Implementation of International Financial Reporting Standards

In January 2006, the Canadian Accounting Standards Board (the “AcSB”) announced its decision to replace Canadian GAAP with International Financial Reporting Standards (“IFRS”) for all Canadian Publicly Accountable Enterprises (“PAEs”), including Penn West. On February 13, 2008, the AcSB confirmed January 1, 2011 as the changeover date for PAEs to commence reporting under IFRS. Although IFRS is principles-based and uses a conceptual framework similar to Canadian GAAP, there are significant differences and choices in accounting policies, as well as increased disclosure requirements under IFRS.

In July 2009, the International Accounting Standards Board (“IASB”) issued amendments to IFRS 1 “First-time adoption of IFRS” allowing additional exemptions for first-time adopters. Under these amendments, full cost oil and natural gas companies can elect to use the recorded amount under a previous GAAP as the deemed cost for oil and gas assets on the transition date to IFRS. We have decided to adopt this exemption.

In 2008, we began our IFRS conversion project and assembled a project team and steering committee to ensure successful implementation within the required timeframe. Members selected for this team have expertise in a number of areas including; accounting, financial reporting, information technology, internal controls, investor relations, project management, taxation and treasury. These members and other finance and operational staff and members of our Board of Directors have received ongoing training related to IFRS. The project team and steering committee provide updates to senior management and the Audit Committee on a regular basis. Our changeover project consists of three main phases:

•

Diagnostic phase - Involved identification of the key differences between Canadian GAAP and IFRS. This phase began in 2008 and was completed in 2009.

•

Design and implementation phase - Focuses on accounting policy decisions and modifications to IT systems and accounting processes. As decisions are made during this phase we will review our internal controls over financial reporting and disclosure controls and procedures and make modifications as required. We started this phase in 2009 and are currently close to completion.

•

Completion phase - Involves the final review of accounting policy choices, internal control changes, the full implementation of IT processes and the conversion of financial statements balances and comparative figures to IFRS. We began this phase in early 2010 with the implementation of our IT process. We will be continuing to work through this phase for the remainder of 2010 and into 2011 prior to filing our first set of quarterly financial statements under IFRS.

During the third quarter of 2010, our work focused on finalizing our accounting policies and analyzing the effects of these policies over our internal controls. We also continued our training throughout the organization and completed education sessions for the Board of Directors, senior management and key finance staff to ensure they are current on IFRS issues. Progress continued on our January 1, 2010 transition date balance sheet which will be finalized during the fourth quarter of 2010 with the significant adjustments disclosed in the fourth quarter 2010 MD&A. Any amendments to existing IFRS standards or implementation of new IFRS standards could lead to additional changes as we progress into 2011.

2010 THIRD QUARTER REPORT 23

Significant accounting differences between our current accounting policies under Canadian GAAP and expected accounting policies under IFRS include the following:

•

Depletion and depreciation of property, plant and equipment (“PP&E”) will be based on significant components. We currently expect these components to consist of Oil and Gas assets, Facilities, Turnarounds and Corporate assets. Under Canadian GAAP, PP&E is generally depleted based on aggregations at the country level using the full cost method of accounting for oil and natural gas activities. Depletion of resource properties and facilities will generally continue to be calculated using the unit-of-production method; however, under IFRS there is an option to base production volumes before royalties on total proved reserves or total proved plus probable reserves. Depreciation of all other assets can be calculated on a straight-line basis over their estimated useful life, rather than on a unit-of-production basis. We anticipate depleting our resource properties on a proved plus probable basis using forecast prices.

•

Oil and natural gas properties will be classified as either PP&E or Exploration and Evaluation assets (“E&E”). Under Canadian GAAP, oil and gas assets are classified as PP&E. E&E assets will consist of capital costs related to prospective assets for which the technical and commercial viability of extracting oil and gas have not yet been determined. These assets will be measured at cost and classified according to the nature of the expenditures.

•

E&E costs will be reclassified to PP&E, to the extent they are not impaired, when proved reserves have been assigned to the asset. If proved reserves will not be established through the completion of E&E activities and there are no future plans for development activity, then the E&E expenditures will be reviewed for impairment. Any impairments will be charged to income.

•

Impairment testing on oil and gas properties will be performed at a lower level than under current Canadian GAAP. As a consequence, impairment provisions are more likely to occur, as properties will no longer be tested at the country level.

•

Trust unit rights are classified as equity instruments under Canadian GAAP. Under IFRS, trust units carry a number of features that could result in either equity or liability treatment. Under IFRS puttable financial instruments with characteristics similar to ordinary shares are treated as equity instruments. We completed an analysis and concluded that our trust units receive equity classification.

•

Share-based payments are classified as equity awards and are expensed based on a straight-line method. Under IFRS, our equity awards are classified as puttable financial instruments resulting in liability treatment of the awards and are expensed based on a graded vesting schedule. We anticipate on our transition date balance sheet under IFRS the following to occur; the removal of the equity amount in contributed surplus under Canadian GAAP, the recognition of a unit rights liability under IFRS and the recalculation of the equity portion related to cumulative exercises to date. Upon conversion to a corporation, we expect the equity awards will revert back to equity classification.

•

Asset retirement obligations are recorded under Canadian GAAP if there is a legal obligation to abandon while under IFRS asset retirement obligations are recorded if there is either a legal or constructive obligation to abandon. In our transition date balance sheet, we expect to record an additional provision as a result of a constructive obligation. This additional provision will vary depending on the discount rate used.

•

Discount rates used to calculate the asset retirement obligation are under review by our project team as there is currently diversity in practice when selecting a rate. As a result of using the deemed cost exemption, we are required to offset any changes to our asset retirement obligation through retained earnings on the transition date. Under Canadian GAAP, we use a credit adjusted discount rate to calculate the obligation. A reduction to the rate used in the calculation could lead to a material increase in the recorded asset retirement obligation in our transition date balance sheet.

•

Future (deferred) income tax is based on a corporate average rate under Canadian GAAP. Under IFRS, as a result of receiving a deduction for our distribution payments, the rate used in the future income tax calculation is based on the undistributed rate which is higher than the corporate rate. Thus, on the transition date balance sheet under IFRS, we anticipate an increase in our future income tax liability with an offsetting charge to retained earnings due to this rate increase. As we pay distributions throughout the year and upon conversion to a corporation, we expect that most of this initial charge will reverse and be recovered through income.

2010 THIRD QUARTER REPORT 24

The IASB currently has two projects in exposure draft form which could affect our reported financial position. The first relates to “Joint Arrangements” which outlines the appropriate accounting for joint operations, joint assets and joint ventures. Depending on the criteria, joint arrangements could follow either proportionate consolidation or equity accounting. This could affect the accounting for our interest in the Peace River Oil Partnership which currently follows proportionate consolidation under Canadian GAAP. The standard is expected to be finalized by the end of 2010. Additionally, in August 2010 the IASB and FASB issued an exposure draft related to “Leases” which eliminates the concept of operating leases, thereby classifying most leases as finance leases. This would require a lessee to record both a “right-of-use” asset and an obligation based on the present value of the lease payments, in addition to increased disclosure requirements. Currently, the target date for this standard is mid-2011 with the effective date to follow. We are currently in the process of determining the effect of these exposure drafts.

Related-Party Transactions

During the first nine months of 2010, we incurred $2 million (2009 - $1 million) of legal fees from 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: our anticipated monthly per unit distribution level and the factors that may affect such distribution level; our expectations regarding North American and global supply and demand factors for crude oil and natural gas for the remainder of 2010 and into 2011; the identification of over 8,000 drilling locations on existing Penn West lands; hedging; effects of the Cordova Joint Venture and the Peace River Oil Partnership on the development of our oil and gas assets; our intention to reinvest a significant portion of our capital in our larger light-oil assets; the anticipated completion and tie-in of certain wells in the fourth quarter of 2010; anticipated effect of provincial royalty programs on project economics; the impact of the SIFT tax, our plans to convert to an E&P company and the timing thereof, and the affect of such conversion on our future tax liability; our potential ability to shield our taxable income from income tax using our tax pools for an extended period of time under either a trust or corporate model; the identity of our primary business risks going forward (commodity price risk, foreign currency rate risk, credit risk, interest rate risk, liquidity risk, and environmental and climate change risk) and the nature and effectiveness of our risk management strategies; the ability of our strategies to increase the likelihood that we will be able to maintain our financial flexibility to capture opportunities availed by the current market, continue our capital and distribution programs, and execute our business strategies; effect of distributions on debt levels; our current belief that a special distribution will not be made in 2010; our belief that our environmental programs eliminate the need for a reclamation fund and are sufficient to meet or exceed existing environmental regulations; the disclosure contained under the heading "Standardized Distributable Cash", which among other things identifies our intention to fund distributions and maintenance capital programs primarily from funds flow, our targeting as we move towards a conventional E&P structure of a level of return to our equity holders which includes a combination of organic growth and yield, our belief that our current capital programs should be sufficient to maintain our productive capacity over the medium term, the impact of seasonality on our distribution policies, and our belief that our current environmental programs will be sufficient to fund our asset retirement obligations over the life of our reserves; the disclosure contained under the heading "Outlook", which sets forth management's expectations as to our capital expenditure levels for 2010 and 2011 and the focus thereof, as well as our forecast average daily production for 2010 and 2011; the disclosure contained under the heading "Sensitivity Analysis" relating to the estimated sensitivity of our reported financial results for the next 12 months in respect of funds flow to certain operational and financial metric assumptions; timing and effect of renewal of our credit facility; and our expectations regarding the impact that the adoption of IFRS may have on us.

2010 THIRD QUARTER REPORT 25

With respect to forward-looking statements contained in this document, we have made assumptions regarding, among other things: future oil and natural gas prices and differentials between light, medium and heavy oil prices; future capital expenditure levels; future oil and natural gas production levels; drilling results; future exchange rates and interest rates; the amount of future cash distributions that we intend to pay; our ability to obtain equipment in a timely manner to carry out development activities 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. In addition, many of the forward-looking statements contained in this document are located proximate to assumptions that are specific to those forward-looking statements, and such assumptions should be taken into account when reading such forward-looking statements: see in particular the assumptions identified under the headings "Standardized Distributable Cash", "Outlook" and "Sensitivity Analysis".

Although Penn West believes that the expectations reflected in the forward-looking statements contained in this document, and the assumptions on which such forward-looking statements are made, are reasonable, there can be no assurance that such expectations will prove to be correct. Readers are cautioned not to place undue reliance on forward-looking statements included in this document, as there can be no assurance that the plans, intentions or expectations upon which the forward-looking statements are based will occur. By their nature, forward-looking statements involve numerous assumptions, known and unknown risks and uncertainties that contribute to the possibility that the predictions, forecasts, projections and other forward-looking statements will not occur, which may cause Penn West's actual performance and financial results in future periods to differ materially from any estimates or projections of future performance or results expressed or implied by such forward-looking statements. These risks and uncertainties include, among other things: the impact of weather conditions on seasonal demand and ability to execute capital programs; risks inherent in oil and natural gas operations; uncertainties associated with estimating reserves and resources; competition for, among other things, capital, acquisitions of reserves, resources, undeveloped lands and skilled personnel; incorrect assessments of the value of acquisitions, including the completed acquisitions discussed herein; geological, technical, drilling and processing problems; general economic conditions in Canada, the U.S. and globally; industry conditions, including fluctuations in the price of oil and natural gas; royalties payable in respect of our oil and natural gas production and changes thereto; changes in government regulation of the oil and natural gas industry, including environmental regulation; fluctuations in foreign exchange or interest rates; unanticipated operating events that can reduce production or cause production to be shut-in or delayed; failure to obtain industry partner and other third-party consents and approvals when required; stock market volatility and market valuations; OPEC's ability to control production and balance global supply and demand of crude oil at desired price levels; political uncertainty, including the risks of hostilities, in the petroleum producing regions of the world; the need to obtain required approvals from regulatory authorities from time to time; failure to realize the anticipated benefits of dispositions, acquisitions, joint ventures and partnerships, including the completed dispositions, acquisitions, joint ventures and partnerships discussed herein; changes in tax and other laws that affect us and our securityholders; changes in government royalty frameworks; uncertainty of obtaining required approvals for acquisitions and mergers including our intended conversion to a corporate structure; 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.

2010 THIRD QUARTER REPORT 26

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.

2010 THIRD QUARTER REPORT 27

Penn West Energy Trust

Consolidated Balance Sheets

(CAD millions, unaudited)	September 30, 2010				December 31, 2009

Assets
Current
Accounts receivable		$	310		$	371
Future income taxes (note 11)			5			37
Other			103			101
			418			509

Deferred funding obligation (note 4)			703			-
Property, plant and equipment (note 3)			9,817			11,347
Goodwill			2,020			2,020
			12,540			13,367
		$	12,958		$	13,876


Liabilities and unitholders’ equity
Current
Accounts payable and accrued liabilities		$	668		$	515
Distributions payable			41			63
Convertible debentures (note 6)			26			18
Risk management (note 10)			20			130
			755			726
Long-term debt (note 5)			2,260			3,219
Convertible debentures (note 6)			229			255
Asset retirement obligations (note 7)			581			568
Risk management (note 10)			31			21
Future income taxes (note 11)			866			1,169
			4,722			5,958
Unitholders’ equity
Unitholders’ capital (note 8)			9,057			8,451
Contributed surplus (note 8)			151			123
Deficit			(972	)		(656	)
			8,236			7,918
		$	12,958		$	13,876

See accompanying notes to the unaudited interim consolidated financial statements.

2010 THIRD QUARTER REPORT 28

Penn West Energy Trust

Consolidated Statements of Operations and Retained Earnings (Deficit)

	Three months ended September 30						Nine months ended September 30
(CAD millions, except per unit amounts, unaudited)	2010			2009			2010			2009

Revenues
Oil and natural gas	$	719		$	732		$	2,249		$	2,058
Royalties		(130	)		(122	)		(406	)		(349	)
		589			610			1,843			1,709

Risk management gain (loss) (note 10)
Realized		9			68			3			314
Unrealized		(45	)		(58	)		110			(447	)
		553			620			1,956			1,576

Expenses
Operating (note 9)		243			248			713			739
Transportation		8			9			25			26
General and administrative (note 9)		46			43			133			125
Financing (notes 5 and 6)		46			43			131			120
Depletion, depreciation and accretion		324			404			993			1,189
Unrealized risk management loss (note 10)		13			45			10			41
Unrealized foreign exchange gain		(46	)		(118	)		(27	)		(161	)
Gain on currency contracts		-			-			-			(75	)
		634			674			1,978			2,004
Loss before taxes		(81	)		(54	)		(22	)		(428	)

Taxes
Future income tax recovery (note 11)		(56	)		(61	)		(269	)		(296	)

Net and comprehensive income (loss)	$	(25	)	$	7		$	247		$	(132	)


Retained earnings (deficit), beginning of period	$	(770	)	$	(274	)	$	(656	)	$	329
Distributions declared		(177	)		(188	)		(563	)		(652	)
Deficit, end of period	$	(972	)	$	(455	)	$	(972	)	$	(455	)

Net income (loss) per unit
Basic	$	(0.06	)	$	0.02		$	0.57		$	(0.32	)
Diluted	$	(0.06	)	$	0.02		$	0.56		$	(0.32	)
Weighted average units outstanding (millions)
Basic		453.0			418.0			436.7			410.3
Diluted		453.0			419.6			442.0			410.3

See accompanying notes to the unaudited interim consolidated financial statements.

2010 THIRD QUARTER REPORT 29

Penn West Energy Trust

Consolidated Statements of Cash Flows

	Three months ended September 30						Nine months ended September 30
(CAD millions, unaudited)	2010			2009			2010			2009

Operating activities
Net income (loss)	$	(25	)	$	7		$	247		$	(132	)
Depletion, depreciation and accretion		324			404			993			1,189
Future income tax recovery		(56	)		(61	)		(269	)		(296	)
Unit-based compensation (note 9)		12			14			36			39
Unrealized risk management loss (gain) (note 10)		58			103			(100	)		488
Unrealized foreign exchange gain		(46	)		(118	)		(27	)		(161	)
Asset retirement expenditures		(11	)		(13	)		(38	)		(49	)
Change in non-cash working capital		77			50			72			(115	)
		333			386			914			963

Investing activities
Additions to property, plant and equipment		(293	)		(171	)		(787	)		(492	)
Acquisition of property, plant and equipment		(151	)		(24	)		(479	)		(31	)
Disposition of property, plant and equipment		278			53			1,144			204
Change in non-cash working capital		152			11			146			(109	)
		(14	)		(131	)		24			(428	)

Financing activities
Decrease in bank loan		(169	)		(101	)		(1,235	)		(372	)
Proceeds from issuance of notes (note 5)		-			-			304			238
Issue of equity		18			12			484			270
Distributions paid		(168	)		(166	)		(491	)		(636	)
Redemption / maturity of convertible debentures		-			-			-			(4	)
Repayment of acquired credit facilities		-			-			-			(31	)
		(319	)		(255	)		(938	)		(535	)

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

Interest paid	$	27		$	34		$	91		$	104
Income taxes recovered	$	-		$	-		$	(1	)	$	(3	)

See accompanying notes to the unaudited interim consolidated financial statements.

2010 THIRD QUARTER REPORT 30

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 10)

1. Structure of Penn West

Penn West Energy Trust (“Penn West”) is an open-ended, unincorporated investment trust governed by the laws of the Province of Alberta, Canada. The business 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 net profit interests in oil and natural gas properties. Penn West owns 100 percent of the equity, directly or indirectly, of the entities that carry on the oil and natural gas business of Penn West, except for an unincorporated joint venture arrangement (the “Peace River Oil Partnership”) in which Penn West wholly owned subsidiaries hold a 55 percent interest. 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 royalty payments from certain subsidiary entities equal to essentially all of the proceeds of the sale of oil and natural gas production less certain 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 current 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 (“GAAP”) 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, 2009, except as described below. These unaudited interim consolidated financial statements do not include all of the disclosures outlined in Penn West’s annual financial statements and should accordingly be read in conjunction with Penn West’s audited consolidated financial statements and notes thereto for the year ended December 31, 2009.

New Accounting Policies

In the first quarter of 2010, Penn West implemented a Long-Term Retention and Incentive Plan as outlined in Note 9. Compensation expense for the plan is based on an intrinsic cost calculation on each reporting date using the awards outstanding and Penn West’s unit price from the Toronto Stock Exchange on each balance sheet date. The awards are expensed over the vesting period based on a graded vesting schedule. Subsequent increases and decreases in the underlying unit price will result in increases and decreases, respectively, to the underlying accrued obligation until settlement.

Partnership accounting

Penn West entered into the Peace River Oil Partnership during the second quarter of 2010. This arrangement is accounted for using the proportionate consolidation method with Penn West receiving its 55 percent share of revenues, expenses, assets and liabilities. Please refer to Note 4 below.

2010 THIRD QUARTER REPORT 31

3. Property, plant and equipment

	September 30, 2010				December 31, 2009
Oil and natural gas properties, including production and processing equipment		$	17,362		$	17,929
Accumulated depletion and depreciation			(7,545	)		(6,582	)
Net book value		$	9,817		$	11,347

In addition to Penn West’s net share of capital overhead recoveries, capital additions included approximately $18 million of staff costs directly attributable to exploration and development activities (2009 - $nil).

An impairment test was performed on the costs capitalized to oil and natural gas properties at September 30, 2010 and December 31, 2009. 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 less the cost of unproved properties.

4. Deferred funding obligation

Peace River Oil Partnership

On June 1, 2010, Penn West entered a partnership agreement to develop oil assets in the Peace River area in Alberta. Pursuant to the agreement, Penn West contributed assets with a fair value of $1.8 billion for a 55 percent interest in the partnership. Penn West received cash consideration of $312 million upon closing and will receive an additional $505 million in funding from Penn West’s partner for its share of future capital and operating expenses in the Peace River Oil Partnership. As at September 30, 2010, approximately $498 million of future funding was remaining.

Cordova Joint Venture

On September 23, 2010, Penn West entered into a joint venture agreement to develop its unconventional natural gas assets located in the Cordova Embayment and certain conventional assets located at its Wildboy play in northeastern British Columbia. Penn West sold a 50 percent interest in the assets for cash consideration of approximately $250 million upon closing and approximately $200 million in future commitments from Penn West’s partner for its share of future capital expenses in the joint venture.

2010 THIRD QUARTER REPORT 32

5. Long-term debt

	September 30, 2010			December 31, 2009
Bankers’ acceptances and prime rate loans		$	639	$	1,874

U.S. Senior unsecured notes - 2007 Notes
5.68%, US$160 million, maturing May 31, 2015			165		168
5.80%, US$155 million, maturing May 31, 2017			159		163
5.90%, US$140 million, maturing May 31, 2019			144		147
6.05%, US$20 million, maturing May 31, 2022			21		21
			489		499
Senior unsecured notes - 2008 Notes
6.12%, US$153 million, maturing May 29, 2016			157		160
6.16%, CAD$30 million, maturing May 29, 2018			30		30
6.30%, US$278 million, maturing May 29, 2018			286		292
6.40%, US$49 million, maturing May 29, 2020			51		52
			524		534
UK Senior unsecured notes - UK Notes
6.95%, £57 million, maturing July 31, 2018 (1)			92		97

Senior unsecured notes - 2009 Notes
8.29%, US$50 million, maturing May 5, 2014			51		52
8.89%, US$35 million, maturing May 5, 2016			36		36
9.32%, US$34 million, maturing May 5, 2019			35		36
8.89%, US$35 million, maturing May 5, 2019 (2)			36		37
9.15%, £20 million, maturing May 5, 2019 (3)			32		34
9.22%, €10 million, maturing May 5, 2019 (4)			14		15
7.58%, CAD$5 million, maturing May 5, 2014			5		5
			209		215
Senior unsecured notes - 2010 Notes
4.53%, US$28 million, maturing March 16, 2015			28		-
4.88%, CAD$50 million, maturing March 16, 2015			50		-
5.29%, US$65 million, maturing March 16, 2017			67		-
5.85%, US$112 million, maturing March 16, 2020			116		-
5.95%, US$25 million, maturing March 16, 2022			25		-
6.10%, US$20 million, maturing March 16, 2025			21		-
			307		-

Total long-term debt		$	2,260	$	3,219

(1)	These notes bear interest at 7.78 percent in Pounds Sterling, however, contracts were entered which fixed the interest rate at 6.95 percent in Canadian dollars.

(2)	This portion of the 2009 Notes has equal repayments, beginning in 2013, over the remaining seven years.

(3)	These notes bear interest at 9.49 percent in Pounds Sterling, however, contracts were entered into which fixed the interest rate at 9.15 percent in Canadian dollars.

(4)	These notes bear interest at 9.52 percent in Euros, however, contracts were entered into which fixed the interest rate at 9.22 percent in Canadian dollars.

Penn West Petroleum Ltd. (the “Company”) has a three-year, unsecured, revolving syndicated bank facility with an aggregate borrowing limit of $2.25 billion. The facility is extendible and expires on April 30, 2013. 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. At September 30, 2010, the Company had approximately $1.6 billion of unused credit capacity available.

2010 THIRD QUARTER REPORT 33

Letters of credit totalling $2 million were outstanding on September 30, 2010 (December 31, 2009 - $2 million) that reduced the amount otherwise available to be drawn on the syndicated facility.

Financing costs, including interest expense on the syndicated credit facility, the senior unsecured notes and convertible debentures, were $46 million in the third quarter of 2010 (2009 - $43 million) and $131 million for the first nine months of 2010 (2009 - $120 million). Also included in financing costs are realized losses on interest rate swaps of $5 million in the third quarter of 2010 (2009 - $5 million) and $17 million for the first nine months of 2010 (2009 - $13 million).

The estimated fair values of the principal and interest obligations of the outstanding unsecured notes were as follows:

	September 30, 2010			December 31, 2009
2007 Notes		$	544	$	508
2008 Notes			602		558
UK Notes			93		99
2009 Notes			253		247
2010 Notes			336		-
Total		$	1,828	$	1,412

6. Convertible debentures

Penn West’s outstanding balances and estimated fair values for the unsecured, subordinated convertible debentures were as follows:

	September 30, 2010			December 31, 2009
Current portion		$	26	$	18
Long-term portion			229		255
Total		$	255	$	273

Total fair value (1)		$	264	$	277

(1)	Based on quoted market value.

At September 30, 2010, Penn West had the following unsecured, subordinated convertible debentures outstanding:

Description of security	Symbol	Maturity date	Conversion price (per unit)		Redemption prices (per $1,000 face value)
7.2% Convertible	PWT.DB.E	May 31, 2011	$	75.00	$1,025 May 31, 2010 to maturity
6.5% Convertible extendible	PWT.DB.F	Dec. 31, 2011	$	51.55	$1,050 Dec. 31, 2009 - Dec. 30, 2010 $1,025 Dec. 31, 2010 to maturity

2010 THIRD QUARTER REPORT 34

	PWT.DB.B			PWT.DB.C			PWT.DB.D			PWT.DB.E		PWT.DB.F
	8.0%			8.0%			6.5%			7.2%		6.5%		Total
Balance, December 31, 2008	$	7		$	16		$	18		$	26	$	229	$	296
Redeemed		-			(16	)		-			-		-		(16	)
Matured		(7	)		-			-			-		-		(7	)
Balance, December 31, 2009		-			-			18			26		229		273
Matured		-			-			(18	)		-		-		(18	)
Balance, September 30, 2010	$	-		$	-		$	-		$	26	$	229	$	255

7. Asset retirement obligations

At September 30, 2010, the total estimated amount to settle Penn West’s asset retirement obligations on an uninflated and undiscounted basis was $2.4 billion (December 31, 2009 - $2.4 billion) and on an inflated and undiscounted basis was $4.2 billion (December 31, 2009 - $4.0 billion). The recorded asset retirement obligations were determined by applying an inflation factor of 2.0 percent (December 31, 2009 - 2.0 percent) and discounting the inflated amount using credit-adjusted rates between 7.0 - 9.0 percent (December 31, 2009 - 7.0 - 9.0 percent) over the expected useful life of the underlying assets, currently extending up to 50 years into the future with an average life of 22 years. Future cash flows from operating activities are expected to fund these obligations.

Changes to asset retirement obligations were as follows:

	Nine months ended September 30, 2010			Year ended December 31, 2009
Balance, beginning of period	$	568		$	614
Net additions (disposals) (1)		21			(26	)
Liabilities settled		(38	)		(65	)
Liabilities acquired		-			3
Accretion charges		30			42
Balance, end of period	$	581		$	568

(1)	Includes additions from drilling activity and facility capital spending and disposals from net property dispositions.

2010 THIRD QUARTER REPORT 35

8. Unitholders’ equity

Unitholders’ capital	Units		Amount
Balance, December 31, 2008		386,504,586	$	7,976
Issued on exercise of trust unit rights (1)		414,745		9
Issued to employee trust unit savings plan		2,579,500		37
Issued to distribution reinvestment plan		8,221,146		111
Issued to settle convertible debentures		1,498,247		19
Issued on trust unit offering (net of issue costs/tax)		17,731,000		240
Issued on Reece acquisition		4,689,513		59
Balance, December 31, 2009		421,638,737	$	8,451
Issued on exercise of trust unit rights (1)		2,273,114		39
Issued to employee trust unit savings plan		1,433,483		29
Issued to distribution reinvestment plan		4,919,828		94
Issued to settle convertible debentures		922,580		18
Issued on trust unit offering (net of issue costs/tax)		23,524,209		426
Balance, September 30, 2010		454,711,951	$	9,057

Contributed surplus	September 30, 2010			December 31, 2009
Balance, beginning of period	$	123		$	75
Unit-based compensation expense		36			52
Net benefit on rights exercised (1)		(8	)		(4	)
Balance, end of period	$	151		$	123

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

Average units outstanding	Three months ended September 30				Nine months ended September 30
(millions of units)	2010		2009		2010		2009
Weighted average
Basic		453.0		418.0		436.7		410.3
Dilutive impact of unit rights and debentures		-		1.6		5.3		-
Diluted		453.0		419.6		442.0		410.3

For the third quarter of 2010, 34.3 million trust units (2009 - 19.3 million) that would be issued under the trust unit rights incentive plan and 4.8 million trust units (2009 - 5.3 million) that would be issued on the conversion of the convertible debentures were excluded in calculating the weighted average number of diluted trust units outstanding as they were considered anti-dilutive due to the net loss in the quarter. For the first nine months of 2010, 20.4 million trust units (2009 - 32.2 million) that would be issued under the trust unit rights incentive plan and 4.8 million trust units (2009 - 5.3 million) that would be issued on the conversion of the convertible debentures were excluded in calculating the weighted average number of diluted trust units outstanding at they were considered anti-dilutive.

2010 THIRD QUARTER REPORT 36

9. Unit-based compensation

Trust unit rights incentive plan (“TURIP”)

Penn West has a TURIP that allows Penn West to issue rights to acquire trust units to directors, officers, employees and other service providers. To date, no rights have been granted to 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. The grant price of trust unit rights is administered to be equal to the volume-weighted average trading price of the trust units on the Toronto Stock Exchange for a five-trading-day period subsequent to the date of entitlement. If certain conditions are met, the exercise price per trust unit may be reduced by deducting from the grant price the aggregate of all distributions, on a per unit basis, paid 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 vest over a three-year period and expire four years after the date of the grant.

	Nine months ended September 30, 2010						Year ended December 31, 2009
Trust unit rights	Number of Unit Rights			Weighted Average Exercise Price			Number of Unit Rights			Weighted Average Exercise Price
Outstanding, beginning of period		31,816,158		$	17.65			25,818,380		$	22.88
Granted		7,013,330			19.97			10,889,310			12.88
Exercised		(2,273,114	)		13.78			(414,745	)		13.38
Forfeited		(2,295,892	)		18.23			(4,476,787	)		21.68
Balance before reduction of exercise price		34,260,482			18.35			31,816,158			19.75
Reduction of exercise price for distributions paid		-			(1.18	)		-			(2.10	)
Outstanding, end of period		34,260,482		$	17.17			31,816,158		$	17.65
Exercisable, end of period		16,466,105		$	17.94			11,155,528		$	20.01

Long-term retention and incentive plan (“LTRIP”)

Penn West implemented an LTRIP in the first quarter of 2010 that allows Penn West employees to receive cash consideration based on Penn West’s unit price. Eligible employees receive a grant of a specific number of trust units that vest over a three-year period with the cash value paid to the employee on each anniversary date. The cash consideration paid will vary depending upon the performance of the Penn West trust unit price on the Toronto Stock Exchange. If the service requirements are met, the cash consideration paid is based on the number of LTRIP awards vested and the five-day weighted average trading price of the trust units prior to the vest date plus cash distributions declared by Penn West during the vesting period.

LTRIP awards	Nine months ended September 30, 2010			Year-ended December 31,2009
Outstanding, beginning of period		-			-
Granted		684,154			-
Forfeited		(27,735	)		-
Outstanding, end of period		656,419			-

2010 THIRD QUARTER REPORT 37

Unit-based compensation expense

Unit-based compensation expense under the TURIP is based on the fair value of rights issued on the grant date amortized over the remaining vesting period on a straight-line basis. Unit-based compensation expense under the LTRIP is based on the intrinsic cost of the awards granted and is amortized based on a graded vesting schedule. The total unit-based compensation expense was allocated to operating expense and general and administrative expense as follows:

	Nine months ended September 30
	2010		2009
TURIP
Operating expense	$	9	$	10
General and administrative expense		27		29
LTRIP
Operating expense		3		-
General and administrative expense		2		-
Unit-based compensation expense	$	41	$	39

The unit price used in the intrinsic cost calculation as at September 30, 2010 was $20.62 (September 30, 2009 - N/A).

A Binomial Lattice option-pricing model was used to determine the fair value of trust unit rights granted under the TURIP with the following fair value per trust unit right and weighted average assumptions:

	Nine months ended September 30
	2010			2009
Average fair value of trust unit rights granted (per unit)	$	3.53		$	1.77
Expected life of trust unit rights (years)		3.0			3.0
Expected volatility (average)		32.2	%		31.2	%
Risk-free rate of return (average)		2.3	%		2.0	%
Distribution yield (1)		11.3	%		12.7	%

(1)	Represents distributions declared as a percentage of the Penn West’s market price at the balance sheet date.

Employee retirement savings plan

Penn West has an employee retirement savings plan for the benefit of all employees. Under the savings plan, employees may elect to contribute up to 10 percent of their salary and Penn West matches these contributions at a rate of $1.50 for each $1.00 of employee contribution. Both the employee’s and Penn West’s contributions 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. To date, no open market purchases have been made related to the employee retirement savings plan.

2010 THIRD QUARTER REPORT 38

10. Risk management

Financial instruments included in the balance sheets consist of accounts receivable, fair values of derivative financial instruments, current liabilities, convertible debentures and long-term debt. Except for the senior unsecured notes described in Note 5 and the convertible debentures described in Note 6, the fair values of these financial instruments approximate their carrying amounts due to the short-term maturity of the instruments and the mark to market values recorded for the financial instruments.

A detailed discussion of the key business risks faced by Penn West, which includes market risk, commodity price risk, foreign currency rate risk, credit risk, interest rate risk and liquidity risk, is included in the accompanying Management’s Discussion and Analysis under the heading “Business Risks”. The disclosure under this heading is hereby incorporated by reference into, and forms an integral part of, these financial statements.

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

As at September 30, 2010, the only asset or liability measured at fair value on a recurring basis was the risk management liability, which was valued using Level 2 inputs. Level 2 inputs are based on quoted prices in markets that are not active or based on prices that are observable for the asset or liability.

The following table reconciles the changes in the fair value of financial instruments outstanding:

Risk management	Nine months ended September 30, 2010			Year ended December 31, 2009
Balance, beginning of period	$	(151	)	$	442
Unrealized gain (loss) on financial instruments:
Commodity collars and swaps		110			(554	)
Electricity swaps		(3	)		(25	)
Interest rate swaps		(14	)		32
Foreign exchange forwards		17			(51	)
Cross currency swaps		(10	)		5
Total fair value, end of period	$	(51	)	$	(151	)

Total fair value consists of the following:
Fair value, end of period - current portion	$	(20	)	$	(130	)
Fair value, end of period - long-term portion		(31	)		(21	)
Total fair value, end of period	$	(51	)	$	(151	)

Based on September 30, 2010 pricing, a $1.00 change in the price per barrel of liquids would change the pre-tax unrealized risk management gain by $10 million and a $0.10 change in the price per mcf of natural gas would change the pre-tax unrealized risk management gain by $1 million.

2010 THIRD QUARTER REPORT 39

The following table reconciles the changes in the fair value of financial instruments including the realized component (cash settlement) in the period:

Risk management	Nine months ended September 30, 2010			Year ended December 31, 2009
Balance, beginning of period	$	(151	)	$	442
Realized (gain) - commodity contracts		(3	)		(344	)
Unrealized gain (loss) - commodity contracts		113			(210	)
Realized loss - other		27			37
Unrealized (loss) - other		(37	)		(76	)
Total fair value, end of period	$	(51	)	$	(151	)

Penn West had the following financial instruments outstanding as at September 30, 2010. Fair values are determined using external counterparty information, which is compared to observable market data. Penn West limits its credit risk by executing counterparty risk procedures which include transacting only with institutions within our credit facility or with high credit ratings and by obtaining financial security in certain circumstances.

	Notional volume	Remaining term		Pricing			Fair value
Crude oil
WTI Collars	35,000 bbls/d	Oct/10 - Dec/10		US$60.11 to $75.72/bbl			$	(29	)
WTI Collars	35,000 bbls/d	Jan/11 - Dec/11		US$80.06 to $91.98/bbl				13
Natural gas
AECO Collars (1)	63,000 GJ/d	Oct/10		$6.50 to $9.50/GJ				10
AECO Collars (2)	30,000 GJ/d	Oct/10 - Dec/10		$5.00 to $5.75/GJ				6
Electricity swaps
Alberta Power	65 MW	Oct/10 - Dec/10		$71.40/MWh				(5	)
Alberta Power	25 MW	Oct/10 - Dec/11		$66.70/MWh				(6	)
Alberta Power	65 MW	Jan/11 - Dec/11		$61.79/MWh				(10	)
Alberta Power	45 MW	Jan/12 - Dec/12		$53.02/MWh				(2	)
Alberta Power	30 MW	Jan/12 - Dec/13		$54.60/MWh				(2	)
Alberta Power	20 MW	Jan/13 - Dec/13		$56.10/MWh				-
Alberta Power	50 MW	Jan/14 - Dec/14		$58.50/MWh				(1	)
Interest rate swaps
	$250	Oct/10 - Nov/10			2.27	%		(1	)
	$500	Oct/10 - Dec/11			1.61	%		(2	)
	$600	Oct/10 - Jan/14			2.71	%		(21	)
	$50	Oct/10 - Jan/14			1.94	%		(1	)
Foreign exchange forwards
19-month term	US$599	Oct/10 - Dec/11		1.06085 CAD/USD				13
8-year term	US$80		2015	1.01027 CAD/USD				4
10-year term	US$80		2017	1.00016 CAD/USD				5
12-year term	US$70		2019	0.99124 CAD/USD				4
15-year term	US$20		2022	0.98740 CAD/USD				1
Cross currency
10-year term	£57		2018	2.0075 CAD/GBP, 6.95%				(21	)
10-year term	£20		2019	1.8051 CAD/GBP, 9.15%				(4	)
10-year term	€10		2019	1.5870 CAD/EUR, 9.22%				(2	)

Total							$	(51	)

(1)	The collars total approximately 59,700 mcf per day between prices of $6.85 and $10.02 per mcf.

(2)	The collars total approximately 28,400 mcf per day between prices of $5.27 and $6.06 per mcf.

2010 THIRD QUARTER REPORT 40

A realized loss of $10 million (2009 - $12 million) on electricity contracts has been included in operating costs for the first nine months of 2010.

Subsequent to the end of the third quarter, Penn West entered into additional crude oil collars on 10,000 barrels per day for 2012 at US$83.00 per barrel to US$94.47 per barrel.

11. Income taxes

The total future income tax liability consists of the following:

(millions)	September 30, 2010				December 31, 2009
Current asset		$	5		$	37
Long-term liability			(866	)		(1,169	)
Total		$	(861	)	$	(1,132	)

The current portion of the future income tax asset represents future income taxes attributable to the current unrealized risk management liability.

12. Capital management

Penn West manages its capital to provide a flexible structure to support production maintenance and organic growth and other operational strategies, maintain a strong financial position to capture business opportunities and to maintain a stable distribution profile to its unitholders.

Unitholders’ equity, long-term debt and convertible debentures are defined as capital by Penn West. Unitholders’ equity includes unitholders’ capital, contributed surplus and retained earnings (deficit). Long-term debt includes bank loans and senior unsecured notes.

	September 30, 2010			December 31, 2009
Components of capital
Unitholders’ equity		$	8,236	$	7,918
Long-term debt			2,260		3,219
Convertible debentures			255		273
Total		$	10,751	$	11,410

Management continuously reviews Penn West’s capital structure to ensure the objectives and strategies of Penn West are being met. The capital structure is reviewed based on a number of key factors including, but not limited to, the current market conditions, trailing and forecast debt to capitalization ratios and debt to funds flow and other economic risk factors. Distributions may be monthly, quarterly or special and in cash or in trust units at the discretion of Penn West’s Board of Directors.

The Company is subject to certain financial covenants under its unsecured, syndicated credit facility and the senior unsecured notes. These financial covenants are typical for senior unsecured lending arrangements and include senior debt and total debt to pro forma EBITDA and senior debt and total debt to capitalization. As at September 30, 2010, the Company was in compliance with all of its financial covenants.

13. Related-party transactions

During the first nine months of 2010, Penn West incurred $2 million (2009 - $1 million) of legal fees from a law firm of which a partner is also a director of Penn West.

2010 THIRD QUARTER REPORT 41