EX-99.1 2 ex991.htm SECOND QUARTER INTERIM REPORT AND FINANCIAL STATEMENTS FOR THE PERIOD ENDED JUNE 30, 2011

ex991.htm

Exhibit 99.1

MANAGEMENT’S DISCUSSION AND ANALYSIS

For the six months ended June 30, 2011

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 Petroleum Ltd. (“Penn West”, “We”, “Us”, “Our” or the “Company”) for the six months ended June 30, 2011 and the audited consolidated financial statements and MD&A for the year ended December 31, 2010. The date of this MD&A is August 9, 2011.

On January 1, 2011, we completed our plan of arrangement under which Penn West converted from an income trust to a corporation, operating under the trade name of Penn West Exploration. Prior to this date, the consolidated financial results were presented as an income trust, Penn West’s former legal structure, as at and for the year ended December 31, 2010.

In the first quarter of 2011, we completed our change to International Financial Reporting Standards (“IFRS”) from Canadian Generally Accepted Accounting Principles (“previous GAAP”). Our previously reported consolidated financial statements were adjusted to be in compliance with IFRS on January 1, 2010, the “date of adoption”. Previously reported results and balances subsequent to the date of adoption have been restated to IFRS.

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

Please refer to our disclaimer on forward-looking statements at the end of the MD&A. 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.

Non-GAAP measures including funds flow, funds flow per share-basic, funds flow per share-diluted, netback and payout ratio included in this MD&A are not defined nor have a standardized meaning prescribed by IFRS or previous 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 decommissioning expenditures. Funds flow is used to assess our ability to fund dividend and planned capital programs. See below for reconciliations of 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 costs and is used for similar purposes to netback. Payout ratio is calculated as dividends paid divided by funds flow and is used to assess the adequacy of funds flow retained to finance capital programs.

Calculation of Funds Flow

		Three months ended June 30								Six months ended June 30
(millions, except per share amounts)		2011				2010				2011				2010
Cash flow from operating activities		$	255			$	240			$	495			$	581
Increase in non-cash working capital			133				17				229				5
Decommissioning expenditures			8				12				28				27
Funds flow		$	396			$	269			$	752			$	613
Basic per share		$	0.85			$	0.62			$	1.62			$	1.43
Diluted per share		$	0.85			$	0.61			$	1.62			$	1.41

2011 SECOND QUARTER REPORT 1

Second Quarter Highlights

• Funds flow for the second quarter increased to $396 million compared to $269 million in the second quarter of 2010. The increase was mainly due to an increase in our weighting of light-oil production and higher crude oil prices which more than offset fire, flood and facility shut-in impacts.

• Net income was $271 million compared to $745 million in the second quarter of 2010. Net income in 2011 was impacted by higher revenues and gains on both unrealized risk management items and property dispositions. The comparative 2010 figure included an after-tax gain of $572 million on the formation of the Peace River Oil Partnership.

• Production averaged 156,107 boe per day and was weighted 63 percent to liquids and 37 percent to natural gas in the second quarter of 2011 compared to 163,700 boe per day with 59 percent liquids and 41 percent natural gas in the second quarter of 2010. Production during the second quarter of 2011 was reduced by an average of approximately 13,000 boe per day from forest fires in the Slave Lake area of Northern Alberta, flooding in the Waskada area of Southwestern Manitoba and third-party facility outages.

• Excluding the adverse impact of temporary interruptions encountered during the second quarter, light oil and NGL volumes grew by 19 percent over the last year. Approximately 66 percent of our 2011 production capability is weighted to oil and liquids.

• Capital expenditures, net, totalled $285 million compared to $231 million in the second quarter of 2010. Proceeds on net property dispositions were $15 million in the second quarter of 2011 compared to $94 million of net property acquisitions in the second quarter of 2010.

• Netback was $32.60 per boe in the second quarter of 2011 compared to $23.52 per boe in the second quarter of 2010. The increase resulted primarily from higher oil prices.

2011 Year-to-date Highlights

• Funds flow for the first six months of 2011 was $752 million compared to $613 million for the first six months of 2010. The increase was due to higher revenues as a result of higher liquids production and stronger crude oil prices.

• Net income was $562 million compared to $843 million in 2010 that included the $572 million after-tax gain on the set-up of the Peace River Oil Partnership.

• Production averaged 161,093 boe per day and was weighted 63 percent to oil and 37 percent to natural gas.

• At our production capacity, our weighting to oil and liquids for the first six months of 2011 was 64 percent of average production.

• Capital expenditures, net, totalled $777 million compared to $494 million for the first six months of 2010. Proceeds on net property dispositions were $95 million in the first six months of 2011 compared to $538 million for the comparable period in 2010.

• Netback was $31.03 per boe compared to $25.92 per boe in 2010.

2011 SECOND QUARTER REPORT 2

Quarterly Financial Summary

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

		June 30				Mar. 31				Dec. 31				Sep. 30				June 30				Mar. 31				Dec. 31				Sep. 30
Three months ended		2011				2011				2010				2010				2010				2010				2009				2009
Gross revenues (1)		$	920			$	844			$	782			$	728			$	718			$	806			$	831			$	800
Funds flow			396				356				305				267				269				344				366				349
Basic per share			0.85				0.77				0.67				0.59				0.62				0.81				0.87				0.84
Diluted per share (2)			0.85				0.77				0.66				0.58				0.61				0.81				0.86				0.83
Net income (loss) (2)			271				291				(37	)			304				745				98				(12	)			7
Basic per share (2)			0.58				0.63				(0.08	)			0.67				1.72				0.23				(0.03	)			0.02
Diluted per share (2)			0.58				0.63				(0.08	)			0.66				1.69				0.23				(0.03	)			0.02
Dividends declared			127				125				123				177				196				190				189				188
Per share		$	0.27			$	0.27			$	0.27			$	0.39			$	0.45			$	0.45			$	0.45			$	0.45
Production
Liquids (bbls/d) (3)			98,998				104,349				105,296				98,380				95,777				96,317				101,636				104,583
Natural gas (mmcf/d)			343				371				365				394				408				410				411				441
Total (boe/d)			156,107				166,135				166,148				164,087				163,700				164,587				170,164				178,124

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

(2) Comparative 2010 net income (loss) and per share amounts and funds flow - diluted per share are presented under IFRS. Comparative 2009 periods are presented under previous GAAP.

(3) Includes crude oil and natural gas liquids.

Commodity Markets

Supply concerns including the Libyan conflict and other political tensions in Africa and the Middle East resulted in crude oil prices generally rising until the start of the second quarter. During the second quarter the focus on these supply issues subsided and shifted toward concerns about the pace of the economic recovery along with sovereign debt concerns. While oil prices remain relatively strong, these shifts in market focus and the announcement of releases from the Strategic Petroleum Reserve led to oil prices retreating from their recent highs as the quarter progressed. Signs of reduced demand are appearing in the U.S. and Europe while the developing economies of the world appear to be more resilient to higher oil prices. In Japan, the earthquake and tsunami that occurred towards the end of the first quarter was thought to initially reduce the economic growth outlook; however, this could vary once the reconstruction phase gains momentum. Continued economic concerns including the sovereign debt of several European countries, the U.S. debt ceiling issue, the effect on energy demand as a result of related austerity measures, and the subsequent U.S. credit downgrade could affect market confidence in the second half of the year potentially lowering demand for energy products.

North American natural gas markets continue to be over-supplied as drilling activity in the United States, particularly for liquids-rich shale gas, continues at a pace in excess of what is required to maintain market balance. Drilling activity may subside in "dry" shale gas areas as fewer companies are expected to drill to retain leases and less attractive hedging opportunities are available to producers due to the contraction of forward natural gas price curves. We expect drilling activity to remain stable in shale gas areas with high liquids content as these plays typically remain economic at lower natural gas prices.

Crude Oil

In the second quarter, WTI crude oil prices averaged US$102.55 per barrel compared to US$94.25 per barrel in the first quarter of 2011 and US$77.99 per barrel for the second quarter of 2010. Western Canadian producers encountered a number of pipeline failures during the second quarter that interrupted deliveries to markets. Above average seasonal road bans and exceptional spring flooding and wildfires, which resulted in power losses, also impacted crude oil deliveries. Despite these disruptions, the pricing differential for most Canadian crude oils to WTI narrowed during the quarter. Higher WTI prices combined with narrower pricing differentials resulted in us realizing a higher corporate price than in the first quarter despite appreciation in the Canadian dollar.

2011 SECOND QUARTER REPORT 3

Our average liquids price in the second quarter of 2011, before the impact of the realized portion of risk management, was $90.29 per barrel compared to $76.98 per barrel in the first quarter of 2011 and $65.63 per barrel for the second quarter of 2010. Currently, we have 41,000 barrels per day of our 2011 crude oil production hedged between US$79.98 per barrel and US$96.39 per barrel and 35,000 barrels per day of our 2012 production between US$86.00 per barrel and US$109.72 per barrel.

Natural Gas

In the second quarter of 2011, the AECO Monthly Index averaged $3.74 per mcf compared to $3.77 per mcf in the first quarter of 2011 and $3.86 per mcf for the second quarter of 2010. Natural gas demand benefited from a severe and lengthy winter season that has drawn down surplus inventory levels and reduced concerns about potential excess inventory levels at the end of this summer injection season.

Our corporate average natural gas price in the second quarter of 2011, before the impact of the realized portion of risk management, was $4.06 per mcf compared to $3.79 per mcf in the first quarter of 2011 and $3.83 per mcf in the second quarter of 2010. We currently have 50,000 mcf per day of our 2012 natural gas production hedged at an average price of $4.30 per mcf.

Business Strategy

In the first half of 2011, we significantly increased our pace of development, concentrating on our large-scale light-oil properties throughout the Cardium, Northern Carbonates, Spearfish (Waskada) and the Colorado (Viking). During the second half of 2011, our plan is to continue to focus on these light-oil properties and increase our capital program to move further into the appraisal and development phases across these plays. With our inventory of over 10,000 drilling locations, our significant asset base throughout western Canada and the application of horizontal multi-stage fracture technology, we believe we have a considerable number of growth opportunities. We continuously evaluate the results of our capital programs and assess areas where the rate of development may be economically increased.

RESULTS OF OPERATIONS

Production

		Three months ended June 30												Six months ended June 30
Daily production		2011				2010				% change				2011				2010				% change
Light oil and NGL (bbls/d)			80,546				77,198				4				83,872				76,818				9
Heavy oil (bbls/d)			18,452				18,579				(1	)			17,787				19,228				(7	)
Natural gas (mmcf/d)			343				408				(16	)			357				409				(13	)
Total production (boe/d)			156,107				163,700				(5	)			161,093				164,141				(2	)

Production volumes were significantly impacted during the second quarter of 2011 by temporary interruptions resulting from the wild fires in the Slave Lake region of Northern Alberta, flooding throughout Southern Saskatchewan and Manitoba and third-party facility outages. These events resulted in a reduction of average production for the quarter of approximately 13,000 boe per day. Additionally, these events led to operational delays and higher costs, notably from operating in adverse conditions and unplanned workovers, which led to delays bringing wells on-production. We currently anticipate recovering this delayed production prior to year-end 2011 and expect to exit 2011 with production between 174,000 and 177,000 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 second quarter of 2011, crude oil and NGL production averaged 98,998 barrels per day (63 percent of production) and natural gas production averaged 343 mmcf per day (37 percent of production) compared to 95,777 barrels per day (59 percent of production) and 408 mmcf per day (41 percent of production) in the second quarter of 2010.

2011 SECOND QUARTER REPORT 4

Average Sales Prices

		Three months ended June 30												Six months ended June 30
		2011				2010				% change				2011				2010				% change
Light oil and liquids (per bbl)		$	94.29			$	67.70				39			$	86.78			$	70.18				24
Risk management loss (per bbl) (1)			(4.46	)			(2.38	)			87				(2.93	)			(2.46	)			19
Light oil and liquids net (per bbl)			89.83				65.32				38				83.85				67.72				24
Heavy oil (per bbl)			72.81				57.03				28				68.01				60.77				12
Natural gas (per mcf)			4.06				3.83				6				3.92				4.64				(16	)
Risk management gain (per mcf) (1)			-				0.54				(100	)			-				0.38				(100	)
Natural gas net (per mcf)			4.06				4.37				(7	)			3.92				5.02				(22	)
Weighted average (per boe)			66.18				47.94				38				61.38				51.52				19
Risk management gain (loss) (per boe) (1)			(2.30	)			0.22				(100	)			(1.53	)			(0.20	)			100
Weighted average net (per boe)		$	63.88			$	48.16				33			$	59.85			$	51.32				17

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

2011 SECOND QUARTER REPORT 5

Netbacks

		Three months ended June 30												Six months ended June 30
		2011				2010				% change				2011				2010				% change
Light oil and NGL (1)
Production (bbls/day)			80,546				77,198				4				83,872				76,818				9
Operating netback ($/bbl):
Sales price		$	94.29			$	67.70				39			$	86.78			$	70.18				24
Risk management loss (2)			(4.46	)			(2.38	)			87				(2.93	)			(2.46	)			19
Royalties			(18.53	)			(13.41	)			38				(16.88	)			(13.89	)			22
Operating costs			(23.40	)			(20.14	)			16				(21.11	)			(20.36	)			4
Netback		$	47.90			$	31.77				51			$	45.86			$	33.47				37
Conventional heavy oil
Production (bbls/day)			18,452				18,579				(1	)			17,787				19,228				(7	)
Operating netback ($/bbl):
Sales price		$	72.81			$	57.03				28			$	68.01			$	60.77				12
Royalties			(10.61	)			(8.31	)			28				(9.83	)			(9.00	)			9
Operating costs			(17.61	)			(17.50	)			1				(17.63	)			(16.99	)			4
Transportation			(0.09	)			(0.09	)			-				(0.10	)			(0.09	)			11
Netback		$	44.50			$	31.13				43			$	40.45			$	34.69				17
Total liquids
Production (bbls/day)			98,998				95,777				3				101,659				96,046				6
Operating netback ($/bbl):
Sales price		$	90.29			$	65.63				38			$	83.50			$	68.30				22
Risk management loss (2)			(3.63	)			(1.92	)			89				(2.42	)			(1.96	)			23
Royalties			(17.05	)			(12.42	)			37				(15.65	)			(12.91	)			21
Operating costs			(22.32	)			(19.63	)			14				(20.50	)			(19.68	)			4
Transportation			(0.02	)			(0.02	)			-				(0.02	)			(0.02	)			-
Netback		$	47.27			$	31.64				49			$	44.91			$	33.73				33
Natural gas
Production (mmcf/day)			343				408				(16	)			357				409				(13	)
Operating netback ($/mcf):
Sales price		$	4.06			$	3.83				6			$	3.92			$	4.64				(16	)
Risk management gain (2)			-				0.54				(100	)			-				0.38				(100	)
Royalties			(0.55	)			(0.52	)			6				(0.51	)			(0.69	)			(26	)
Operating costs			(2.11	)			(1.62	)			30				(1.98	)			(1.63	)			21
Transportation			(0.21	)			(0.22	)			(5	)			(0.22	)			(0.22	)			-
Netback		$	1.19			$	2.01				(41	)		$	1.21			$	2.48				(51	)
Combined totals
Production (boe/day)			156,107				163,700				(5	)			161,093				164,141				(2	)
Operating netback ($/boe):
Sales price		$	66.18			$	47.94				38			$	61.38			$	51.52				19
Risk management gain (loss) (2)			(2.30	)			0.22				(100	)			(1.53	)			(0.20	)			100
Royalties			(12.01	)			(8.57	)			40				(11.00	)			(9.28	)			19
Operating costs			(18.79	)			(15.52	)			21				(17.32	)			(15.56	)			11
Transportation			(0.48	)			(0.55	)			(13	)			(0.50	)			(0.56	)			(11	)
Netback		$	32.60			$	23.52				39			$	31.03			$	25.92				20

(1) Excluded from the netback calculation is $19 million primarily related to realized risk management gains on our foreign exchange contracts which swap US dollar revenue at a fixed Canadian dollar rate.

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

2011 SECOND QUARTER REPORT 6

Production Revenues

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

		Three months ended June 30												Six months ended June 30
(millions)		2011				2010				% change				2011				2010				% change
Light oil and NGL		$	671			$	459				46			$	1,292			$	941				37
Heavy oil			122				97				26				219				212				3
Natural gas			127				162				(22	)			253				371				(32	)
Gross revenues (1)		$	920			$	718				28			$	1,764			$	1,524				16

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

The increase in light-oil revenue is due to successful drilling programs across our light-oil plays resulting in nine percent higher production on a year-to-date basis, despite the temporary interruptions related to the Slave Lake fires and flooding throughout Saskatchewan and Manitoba in the second quarter, and to higher crude oil prices compared to 2010. Heavy oil production has remained flat; however, increased prices have resulted in an increase in revenues, notably during the second quarter of 2011. Natural gas revenues declined as production has decreased by 13 percent, on a year-to-date basis, mainly due to the disposition of properties into the Cordova Joint Venture in the third quarter of 2010 and our focus on drilling at our key light-oil resource plays.

Reconciliation of Increase in Production Revenues

 (millions)

Gross revenues - January 1 - June 30, 2010		$	1,524
Increase in light oil and NGL production			86
Increase in light oil and NGL prices (including realized risk management)			265
Decrease in heavy oil production			(16	)
Increase in heavy oil prices			23
Decrease in natural gas production			(47	)
Decrease in natural gas prices			(71	)
Gross revenues - January 1 - June 30, 2011		$	1,764

Royalties

	Three months ended June 30												Six months ended June 30
	2011				2010					% change			2011				2010					% change
Royalties (millions)		$	171			$	128				34			$	321			$	276				16
Average royalty rate (1)			18	%			18	%			-				18	%			18	%			-
$/boe		$	12.01			$	8.57				40			$	11.00			$	9.28				19

(1) Excludes effects of risk management activities.

In comparison to the prior year, royalty rates remained unchanged as new wells coming on production received a lower royalty rate under various royalty incentive programs which offset higher rates on higher crude oil prices on base production.

2011 SECOND QUARTER REPORT 7

Expenses

		Three months ended June 30												Six months ended June 30
(millions)		2011				2010				% change				2011				2010				% change
Operating		$	267			$	231				16			$	505			$	462				9
Transportation			7				8				(13	)			15				17				(12	)
Financing			48				45				7				95				85				12
Share-based compensation		$	4			$	(4	)			100			$	82			$	54				52

		Three months ended June 30												Six months ended June 30
(per boe)		2011				2010				% change				2011				2010				% change
Operating		$	18.79			$	15.52				21			$	17.32			$	15.56				11
Transportation			0.48				0.55				(13	)			0.50				0.56				(11	)
Financing			3.36				2.98				13				3.26				2.85				14
Share-based compensation		$	0.22			$	(0.29	)			100			$	2.82			$	1.81				57

Operating

During the second quarter of 2011, operating costs were significantly affected by temporary production interruptions from the wild fires in Slave Lake, flooding in Manitoba and Saskatchewan and third-party facility outages. On a per boe basis, the increase is attributable primarily to lower production volumes and incremental costs incurred.

Operating costs in the second quarter include a realized loss on electricity contracts of $2 million (2010 - $2 million gain) and for the first six months of 2011 include a realized gain on electricity contracts of $2 million (2010 - $4 million loss). We have contracts in place that fix the price on approximately 90 percent of our electricity consumption for 2011 at $63.16 per MWh.

Financing

On June 27, 2011, the Company closed the renewal of its unsecured, revolving syndicated bank facility extending the term to four years with an aggregate borrowing limit of $2.25 billion. The facility expires on June 26, 2015 and is extendible. 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. Borrowing costs were reduced under the renewed bank facility. As at June 30, 2011, approximately $1.1 billion was drawn under this facility.

2011 SECOND QUARTER REPORT 8

As at June 30, 2011, the Company had $1.8 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	6.0 years
2008 Notes	May 29, 2008	US$480, CAD$30	8 - 12 years	6.25 percent	6.5 years
UK Notes	July 31, 2008	£57	10 years	6.95 percent (1)	7.1 years
2009 Notes	May 5, 2009	US$154, £20, €10, CAD$5	5 - 10 years	8.85 percent (2)	5.5 years
2010 Q1 Notes	March 16, 2010	US$250, CAD$50	5 - 15 years	5.47 percent	7.3 years
2010 Q4 Notes	December 2, 2010, January 4, 2011	US$170, CAD$60	5 - 15 years	5.00 percent	10.2 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, and to fix the exchange rate on repayment.

In January 2011, the Company completed the closing of a private placement, (the “2010 Q4 Notes”), with an aggregate principal amount of approximately US$230 million. The 2010 Q4 Notes had an original weighted average term of 10.8 years and bear a weighted average fixed interest rate of approximately 5.0 percent. The Company used the proceeds of the issue to repay advances on its syndicated bank facility.

Financing charges to date in 2011 are higher compared to 2010 since a higher percentage of our debt capital is held in longer-term, fixed rate, senior unsecured notes. The cost of borrowing under the current and previous bank facility increased compared to the facility in place during the first quarter of 2010 due to increased rates in the bank market. While the Company’s senior unsecured notes contain higher interest rates than the syndicated bank facilities held in short-term money market instruments, notwithstanding, we believe the long-term and fixed interest rates inherent in the senior notes are favourable for a portion of our debt capital structure.

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 made under short-term instruments. As at June 30, 2011, none (December 31, 2010 - none) of our long-term debt instruments were exposed to changes in short-term interest rates due to the effect of interest rate swaps. On June 30, 2011, our fixed interest rate debt (including the effects of interest rate swaps) had a weighted average rate of approximately 5.6 percent (December 31, 2010 - 5.7 percent).

At June 30, 2011, the Company had the following interest rate swaps outstanding:

Effective date	Termination date	Initial term		Nominal amount (millions)				Fixed rate (percent)
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

Realized gains and losses on the interest rate swaps are recorded as financing costs. For the second quarter of 2011 an expense of $3 million (2010 - $6 million) and for the first six months of 2011 an expense of $6 million (2010 - $12 million) was recognized in financing expense to reflect that the floating interest rate was lower than the fixed interest rate transacted under our financial instruments.

2011 SECOND QUARTER REPORT 9

Share-Based Compensation

Share-based compensation expense is related to our Stock Option Plan (the “Option Plan”), our Common Share Rights Incentive Plan (the “CSRIP”) and our Long-Term Retention and Incentive Plan (“LTRIP”).

Effective January 1, 2011, we implemented the Option Plan and amended our Trust Unit Rights Incentive Plan (“TURIP”) which became the CSRIP. Pursuant to our plan to convert from a trust to a corporation, trust unit right holders had the choice to receive one restricted option (a “Restricted Option”) and one restricted right (a “Restricted Right”) for each outstanding “in-the-money” trust unit right. For those trust unit right holders who chose not to make the election or held trust unit rights that were “out-of-the-money” on January 1, 2011, holders received one common share right (“Share Rights”) for each trust unit right. Trust unit rights issued under the former TURIP received liability treatment for accounting purposes throughout 2010 as we operated in an income trust structure. After January 1, 2011, all future grants will be only under the Option Plan.

The Restricted Options, Share Rights and subsequent grants under the Option Plan receive equity treatment for accounting purposes subsequent to our conversion to a corporation with the fair value of each instrument expensed over the expected vesting period based on a graded vesting schedule. The fair values of the Restricted Options and new option grants are calculated using a Black-Scholes option-pricing model and a Binomial Lattice option-pricing model is used to value the Share Rights. The Restricted Rights are accounted for as a liability as holders may elect to settle in cash or common shares.

On January 1, 2011, the previously recognized trust unit rights liability was removed and a share-based compensation liability was recorded with the fair value of the Restricted Rights charged to income. The fair values of the Restricted Options and Share Rights were also charged to income as at January 1, 2011, with an offset to other reserves. The elimination of the TURIP and subsequent implementation of the Option Plan and CSRIP led to a $58 million net charge to income during the first quarter of 2011.

The change in the fair value of the LTRIP is charged to income based on the common share price at the end of each reporting period plus accumulated dividends multiplied by the number of LTRIP awards outstanding. The LTRIP obligation is accrued over the vesting period as service is completed by employees and expensed based on a graded vesting schedule. Subsequent increases and decreases in the underlying common share price will result in increases and decreases, respectively, to the LTRIP obligation until settlement.

Share-based compensation consisted of the following:

		Three months ended June 30												Six months ended June 30
(millions)		2011				2010				% change				2011				2010				% change
Options		$	4			$	-				100			$	8			$	-				100
Restricted Options			6				-				100				13				-				100
Restricted Rights			(10	)			-				(100	)			(5	)			-				(100	)
Share Rights			-				-				-				1				-				100
LTRIP			4				3				33				7				3				100
TURIP			-				(7	)			100				-				51				(100	)
Expiry of TURIP at Jan. 1, 2011			-				-				-				(196	)			-				(100	)
Share Rights at Jan. 1, 2011			-				-				-				16				-				100
Restricted Options at Jan. 1, 2011			-				-				-				65				-				100
Restricted Rights liability at Jan. 1, 2011			-				-				-				173				-				100
Share-based compensation		$	4			$	(4	)			100			$	82			$	54				52

The share price used in the fair value calculation of the LTRIP liability and Restricted Rights obligation at June 30, 2011 was $22.27 (2010 - $20.30).

2011 SECOND QUARTER REPORT 10

General and Administrative Expenses (“G&A”)

		Three months ended June 30												Six months ended June 30
(millions, except per boe amounts)		2011				2010				% change				2011				2010				% change
Gross		$	56			$	48				17			$	113			$	96				18
Per boe			3.94				3.24				22				3.88				3.21				21
Net			37				34				9				74				68				9
Per boe		$	2.64			$	2.28				16			$	2.54			$	2.30				10

G&A expenses have increased in comparison to the prior year as a result of a rise in staff costs as we increased our staff levels due to the transition to an exploration and production (“E&P”) company. The per boe amount was higher in 2011 due to lower production volumes resulting from temporary production interruptions from forest fires and flooding during the second quarter. Additionally, we recorded $1 million as transaction costs during the second quarter of 2011 as part of a corporate acquisition.

Depletion, Depreciation and Accretion

		Three months ended June 30												Six months ended June 30
(millions, except per boe amounts)		2011				2010				% change				2011				2010				% change
Depletion and depreciation (“D&D”)		$	311			$	350				(11	)		$	558			$	612				(9	)
D&D expense per boe			21.87				23.56				(7	)			19.15				20.62				(7	)
Accretion of decommissioning liability			10				10				-				22				20				10
Accretion expense per boe		$	0.76			$	0.69				10			$	0.76			$	0.67				13

In the second quarter of 2011, we recorded a $29 million impairment (2010 - $80 million) on certain properties in Central Alberta due to weaker forward commodity prices.  During the first quarter of 2011, we recorded an impairment reversal of $39 million (2010 - none) to reflect stronger commodity prices resulting in higher forecast cash flows relating to properties in Central Alberta.

Taxes

		Three months ended June 30												Six months ended June 30
(millions)		2011				2010				% change				2011				2010				% change
Deferred tax expense (recovery)		$	98			$	(20	)			(100	)		$	(253	)		$	(61	)			100

In the second quarter of 2011, we recorded higher tax provisions primarily due to unrealized risk management gains and property dispositions.

The year-to-date 2011 amount includes a $304 million recovery related to the tax rate differential on our conversion from a trust to an E&P company. As a corporation, we are subject to income taxes at Canadian corporate tax rates, whereas in the trust structure under IFRS we were required to tax-effect timing differences in our trust entities at rates applicable to undistributed earnings of a trust being the maximum marginal income tax rate for individuals in the Province of Alberta.

We currently have a significant tax pool base. Based on current commodity prices and capital spending plans, we forecast these pools will shelter our taxable income for an extended period.

2011 SECOND QUARTER REPORT 11

Foreign Exchange

		Three months ended June 30												Six months ended June 30
(millions)		2011				2010				% change				2011				2010				% change
Unrealized foreign exchange (gain) loss		$	(7	)		$	74				100			$	(45	)		$	19				100

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 gains during 2011 were primarily due to the strengthening of the Canadian dollar relative to the US dollar.

Funds Flow and Net Income

		Three months ended June 30												Six months ended June 30
		2011				2010				% change				2011				2010				% change
Funds flow (1) (millions)		$	396			$	269				47			$	752			$	613				23
Basic per share			0.85				0.62				37				1.62				1.43				13
Diluted per share			0.85				0.61				39				1.62				1.41				15
Net income (millions)			271				745				(64	)			562				843				(33	)
Basic per share			0.58				1.72				(66	)			1.21				1.97				(39	)
Diluted per share		$	0.58			$	1.69				(66	)		$	1.21			$	1.94				(38	)

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

Funds flow in the second quarter of 2011 increased from the comparable period in 2010 primarily due to an increase in our weighting of light-oil production and an increase in crude oil prices. This was partially offset by lower production from temporary interruptions as a result of the forest fires in the Slave Lake region of Northern Alberta, flooding throughout Southern Saskatchewan and Manitoba and third-party facility outages. The decrease in net income from the prior year was due to significant gains on property dispositions recorded in 2010.

For the first six months of 2011, funds flow has increased from the prior year primarily due to higher crude oil prices and the proportionate increase in our light-oil production. Net income for the first six months of 2011 is lower than 2010 mainly due to lower gains on property dispositions.

Capital Expenditures

		Three months ended June 30								Six months ended June 30
(millions)		2011				2010				2011				2010
Land acquisition and retention		$	88			$	65			$	106			$	104
Drilling and completions			130				117				481				290
Facilities and well equipping			73				43				219				89
Geological and geophysical			1				4				7				9
Corporate			6				2				9				2
Capital expenditures (1)			298				231				822				494
Joint venture, carried capital			(13	)			-				(45	)			-
Capital expenditures, net			285				231				777				494
Property dispositions, net			(45	)			160				(101	)			(296	)
Business combinations			286				-				286				-
Total expenditures		$	526			$	391			$	962			$	198

(1) Capital expenditures include costs related to development capital and Exploration and Evaluation activities.

2011 SECOND QUARTER REPORT 12

Our activity levels have increased, notably in drilling, completions and well equipping, in comparison to the prior year due to successful drilling results at our light-oil resource plays over the past several months and a shift of some of our key light-oil properties from the appraisal phase to the development phase. For the remainder of 2011, we plan to continue our focus at our key light-oil resource plays which include the Cardium, Northern Carbonates, Spearfish (Waskada) and the Colorado (Viking).

For the three months ended June 30, 2011, decommissioning liabilities were reduced by $26 million (2010 - $32 million capitalized additions) and for the first six months of 2011, reduced by $17 million (2010 - $28 million capitalized additions) to reflect net property dispositions.

Gain on asset dispositions

		Three months ended June 30												Six months ended June 30
(millions)		2011				2010				% change				2011				2010				% change
Gain on asset dispositions		$	127			$	737				(83	)		$	151			$	714				(79	)

During 2011, we closed property dispositions which resulted in gains of $151 million recognized in income (2010 - $714 million). In June 2010, as a result of forming the Peace River Oil Partnership, we recognized a pre-tax gain of $749 million in income.

Exploration and evaluation (“E&E”) capital expenditures

		Three months ended June 30												Six months ended June 30
(millions)		2011				2010				% change				2011				2010				% change
E&E capital expenditures		$	20			$	5				100			$	65			$	18				100

In 2011, E&E capital increased compared to the prior year as we more actively participated in land sales consistent with our increase in all exploration activities since our conversion to an E&P focused company. During 2011, we had a non-cash E&E expense of $4 million (2010 - $1 million) related to land expiries.

In 2011, we disposed of E&E assets valued at $2 million (2010 - $33 million) as part of property dispositions.

Spartan Exploration Ltd. (“Spartan”) Acquisition

On June 1, 2011, we closed the acquisition of Spartan, a publicly traded oil and gas exploration company with assets primarily located in the Cardium light-oil resource play in Central Alberta. The total acquisition cost was $222 million, which included the assumption of $56 million of debt and working capital deficiency.

Goodwill

(millions)		June 30, 2011				December 31, 2010
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 were no indicators of impairment at June 30, 2011.

2011 SECOND QUARTER REPORT 13

Environmental and Climate Change

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 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. Operations are continuously monitored to minimize the environmental impact and allocate sufficient capital to reclamation and other activities to mitigate the impact on the areas in which we operate.

Liquidity and Capital Resources

Capitalization

		June 30, 2011								December 31, 2010
(millions)						%								%
Common shares issued, at market (1)		$	10,421				77			$	10,959				78
Bank loans and long-term notes			2,815				21				2,496				18
Convertible debentures			224				2				255				2
Working capital deficiency (surplus) (2)			(2	)			-				303				2
Total enterprise value		$	13,458				100			$	14,013				100

(1) The share price at June 30, 2011 was $22.27 (December 31, 2010 - $23.84).

(2) Excludes the current portion of risk management, deferred income taxes, convertible debentures and share-based compensation liability.

For the first six months of 2011, we declared total dividends of $252 million (2010 - $386 million) and paid total dividends, including amounts funded by the dividend reinvestment plan, of $166 million (2010 - $382 million). As a corporation, we anticipate dividends will be paid on a quarterly basis. On August 9, 2011, our Board of Directors declared our third quarter dividend of $0.27 per share to be paid on October 14, 2011 to shareholders of record on September 30, 2011.

On June 27, 2011, the Company closed the extension of its unsecured, revolving, syndicated bank facility with an aggregate borrowing limit of $2.25 billion and a four-year term and as of June 30, 2011 had approximately $1.2 billion of unused credit capacity available. For further details on our 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 available in the markets in addition to the continuation of our capital and dividend programs and the longer-term execution of our business strategies.

2011 SECOND QUARTER REPORT 14

The Company has a number of covenants related to its syndicated bank facility and senior, unsecured notes. On June 30, 2011, the Company was in compliance with all of these financial covenants which comprise the following:

	Limit	June 30, 2011
Senior debt to EBITDA	Less than 3:1	1.87
Total debt to EBITDA	Less than 4:1	1.87
Senior debt to capitalization	Less than 50 percent	23%
Total debt to capitalization	Less than 55 percent	23%

As at June 30, 2011, all senior, unsecured 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.

The amount of future cash dividends may vary depending on a variety of factors and conditions which can include, but are not limited to, fluctuations in commodity markets, production levels and capital expenditure requirements. Our dividend level could change based on these and other factors and is subject to the approval of our Board of Directors.

Convertible Debentures

During the second quarter of 2011, the series E debentures matured and were settled in cash for a total of $24 million.

We have the option of settling the convertible debentures in cash or common shares. At June 30, 2011, the balance of our unsecured, subordinated convertible debentures outstanding was as follows:

Description of security		Outstanding (millions)			Maturity date		Conversion price (per share)			Redemption price (per $1,000 face value)
PWT.DB.F 6.5% Convertible extendible		$	224		Dec. 31, 2011		$	51.55		$1,025 Dec. 31, 2010 to maturity

2011 SECOND QUARTER REPORT 15

Financial Instruments

We had the following financial instruments outstanding as at June 30, 2011. 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		41,000 bbls/d				July/11 - Dec/11				US$79.98 to $96.39/bbl				$	(48	)
WTI Collars		35,000 bbls/d				Jan/12 - Dec/12				US$86.00 to $109.72/bbl					(30	)
Natural gas
AECO Forwards (1)		25,000 GJ/d				Jan/12 - Dec/12					$4.27/GJ				3
Electricity swaps
Alberta Power Pool		90 MW				July/11 - Dec/11				$63.16/MWh					3
Alberta Power Pool		45 MW				Jan/12 - Dec/12				$53.02/MWh					4
Alberta Power Pool		30 MW				Jan/12 - Dec/13				$54.60/MWh					3
Alberta Power Pool		20 MW				Jan/13 - Dec/13				$56.10/MWh					1
Alberta Power Pool		50 MW				Jan/14 - Dec/14				$58.50/MWh					2
Interest rate swaps
			$500			July/11 - Dec/11					1.61%				(1	)
			$600			July/11 - Jan/14					2.71%				(14	)
			$50			July/11 - Jan/14					1.94%				-
Foreign exchange forwards on commodities
19-month initial term		US$189				July/11 - Dec/11				1.061 CAD/USD					19
Foreign exchange forwards on senior notes
3 to 15-year initial term		US$730					2014 - 2022			0.9986 CAD/USD					(7	)
Cross currency swaps
10-year term			£57				2018			2.0075 CAD/GBP, 6.95%					(28	)
10-year term			£20				2019			1.8051 CAD/GBP, 9.15%					(6	)
10-year term			€10				2019			1.5870 CAD/EUR, 9.22%					(2	)
Total														$	(101	)

(1) The forward contracts total approximately 23,700 mcf per day with an average price of $4.50 per mcf.

Subsequent to June 30, 2011, we entered into additional natural gas forward contracts on 26,300 mcf per day for 2012 at an average price of $4.12 per mcf. Also, after June 30, 2011, we entered into further foreign exchange contracts relating to the principal balances on our senior notes totalling US$32 million at an average exchange rate of $0.985 CAD/USD maturing from 2014 to 2020.

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

2011 SECOND QUARTER REPORT 16

Outlook

This outlook section is included to provide shareholders with information about our expectations as at August 9, 2011 for production and capital expenditures for 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".

Penn West’s capital programs will continue to move toward full scale development of our suite of large-scale light-oil plays based on successful appraisal programs. Our focus areas remain the Cardium, Northern Carbonates, Spearfish (Waskada) and the Colorado (Viking). While still allocating a significant portion of our capital programs to appraising large resource plays, we have grown our light-oil production base significantly over the past year. To date in 2011, we have been successful at land sales where we invested approximately $100 million in the first six months of 2011. We expect to continue to extend our dominance in many of western Canada’s largest and most promising light-oil plays as well as consolidate our positions in many of the new emerging source rock plays. Extreme weather conditions necessitated unplanned capital expenditures to continue certain of our capital programs in the second quarter and third quarter to date. We expect to partially offset industry cost increases due to high activity levels by operating at consistent levels and by increasing our use of pad drilling.

We expect our full year 2011 exploration and development capital program to be in the range of $1.4 billion - $1.5 billion. To date in 2011, we have realized approximately $100 million in proceeds from dispositions of non-core assets.

Extreme flooding in Southern Saskatchewan and Manitoba, forest fires in the Slave Lake region and third-party facility issues in the second quarter of 2011 have extended into the third quarter resulting in delays restoring production. Wet conditions across western Canada have delayed completion activity preventing further tie-ins of Q1 drilling. The combined effect of these factors is to delay volumes and will impact our annualized average production. We expect to recover production outages into the fourth quarter and our exit volume remains consistent with our previous guidance.

In the first six months of 2011, Penn West sold net production of approximately 1,100 boe per day.  Annual production for 2011 is expected to average between 162,000 and 164,000 boe per day. We estimate average production for the second half of 2011 to be between 163,000 and 167,000 boe per day and plan to reach full production capacity in the fourth quarter of 2011 exiting the year producing between 174,000 and 177,000 boe per day.

Our prior production forecast, released on May 5, 2011 with our first quarter results and filed on SEDAR at www.sedar.com, prior to the impact of temporary interruptions related to wildfires, flooding and third party outages, was for 2011 average production of 172,000 to 177,000 boe per day and an exploration and development capital budget of $1.1 billion - $1.2 billion.

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 the Outlook above.

						Impact on funds flow
Change of:		Change				$ millions				$/share
Price per barrel of liquids			$1.00				26				0.05
Liquids production		1,000 bbls/day					24				0.05
Price per mcf of natural gas			$0.10				11				0.02
Natural gas production		10 mmcf/day					6				0.01
Effective interest rate			1%				5				0.01
Exchange rate ($US per $CAD)			$0.01				30				0.06

2011 SECOND QUARTER REPORT 17

Contractual Obligations and Commitments

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

(millions)		2011				2012				2013				2014				2015				Thereafter
Long-term debt		$	-			$	-			$	5			$	58			$	1,309			$	1,443
Transportation			12				23				15				8				4				-
Transportation ($US)			2				4				4				4				4				-
Power infrastructure			12				11				11				11				11				13
Drilling rigs			7				15				11				8				4				-
Purchase obligations (1)			7				13				13				11				10				7
Interest obligations			80				145				145				141				113				271
Office lease (2)			35				68				66				60				60				538
Decommissioning liability (3)		$	39			$	62			$	59			$	57			$	54			$	356

(1) These amounts represent estimated commitments of $45 million for CO2 purchases and $15 million for processing fees related to our interests in the Weyburn Unit.

(2) The future office lease commitments above will be reduced by sublease recoveries totalling $475 million.

(3) These amounts represent the inflated, discounted future reclamation and abandonment costs that are expected to be incurred over the life of the properties.

Our syndicated credit facility is due for renewal on June 26, 2015. If we are not successful in renewing or replacing the facility, we could enter other loans including term bank loans or be required to repay all amounts then outstanding on the facility. In addition, we have an aggregate of $1.8 billion in senior notes maturing between 2014 and 2025. We continuously monitor our credit metrics and maintain positive working relationships with our lenders, investors and agents.

Convertible debentures with an aggregate principal amount of $224 million were outstanding on June 30, 2011 (December 31, 2010 - $255 million). The interest payable on these convertible debentures may, at our option, be settled by the issuance of common shares. As at August 9, 2011, convertible debentures with an aggregate principal amount of $224 million were outstanding. For a schedule of convertible debenture maturities, please refer to the “Convertible Debentures” section of this MD&A or Note 7 to the unaudited interim consolidated financial statements.

2011 SECOND QUARTER REPORT 18

Equity Instruments

Common shares issued:
As at June 30, 2011			467,958,856
Issued on exercise of share rights			12,882
Issued on settlement of restricted rights			532
Issued pursuant to dividend reinvestment plan			1,485,235
As at August 9, 2011			469,457,505
Options outstanding:
As at June 30, 2011			6,830,700
Granted			119,400
Forfeited			(63,030	)
As at August 9, 2011			6,887,070
Share Rights outstanding:
As at June 30, 2011			2,944,898
Exercised			(12,882	)
Forfeited			(82,224	)
As at August 9, 2011			2,849,792
Restricted Options outstanding:
As at June 30, 2011			20,724,839
Forfeited			(252,227	)
As at August 9, 2011			20,472,612

Internal Control over Financial Reporting (“ICOFR”)

No changes in our ICOFR occurred during the quarter ended June 30, 2011 that have materially affected, or are reasonably likely to materially affect, our ICOFR.

Changes in accounting policies

Adoption of IFRS

On January 1, 2011, we transitioned to IFRS, with the date of adoption of January 1, 2010. On the date of adoption, we restated our account balances to IFRS and our financial reporting is in accordance with IFRS thereafter. A full description of our new accounting policies is outlined in Note 3 to our unaudited interim consolidated financial statements.  Additionally, transition date information and reconciliations between IFRS and previous GAAP for comparative periods in 2010 are described in Note 17 to our unaudited interim consolidated financial statements. The adoption of IFRS has not led to any changes in the business operations, capital strategies or funds flow of the Company.

Significant Accounting Differences and Accounting Policies

The following outlines significant accounting policy choices and differences between IFRS and previous GAAP applicable from the date of adoption of IFRS on January 1, 2010. We operated in an income trust structure from the date of adoption until our conversion to a corporation on January 1, 2011.

Component accounting

Under IFRS, depletion and depreciation of property, plant and equipment (“PP&E”) is based on significant components. These components consist of oil and natural gas assets, facilities, turnarounds and corporate assets.

2011 SECOND QUARTER REPORT 19

Depletion and depreciation

Under previous GAAP, PP&E was 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 continue to be calculated using the unit-of-production method; however, under IFRS there is an option to use reserves volumes on a total proved or total proved plus probable basis. We have elected to deplete resource properties using total proved plus probable reserves. Other assets, consisting of computer hardware and software, office furniture, buildings and leasehold improvements, will be depreciated on a straight-line basis over their estimated useful life.

E&E assets

Oil and natural gas properties are classified as either PP&E or E&E. Under previous GAAP, oil and gas assets were classified only as PP&E. E&E assets consist of capital costs related to prospective assets for which the technical and commercial viability of extracting oil and natural gas has not yet been ascertained. These assets are initially measured at cost and classified according to the nature of the associated expenditures.

E&E costs are transferred to PP&E, to the extent they are not impaired, once their technical and commercial viability is established which will generally be 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, E&E assets are assessed for impairment. Any impairment will be charged to income as E&E expense.

Impairment of oil and natural gas properties

Under IFRS, impairment testing is performed at a lower level than under previous GAAP.  As a consequence, impairment provisions are more likely to occur as properties will no longer be tested at the country level. Under IFRS, unlike previous GAAP, impairments other than goodwill impairments may be reversed in the event future conditions change.

Classification of trust units

Under previous GAAP, trust units were classified as equity instruments. Under IFRS, trust units carried 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 concluded that our trust units were appropriately classified as equity.

Share-based payments

Under previous GAAP, share-based payments were classified as equity awards and were expensed using the straight-line method. Under IFRS, as an income trust, our equity awards met the definition of a puttable financial instrument, thus the awards were considered a liability in 2010 and expensed on a graded vesting schedule.

Asset retirement obligations (“ARO”) or decommissioning liability

Under previous GAAP, ARO was recorded when there was a legal obligation to abandon an asset. Under IFRS, ARO is recorded when there is either a legal or constructive obligation to abandon an asset.

Future (deferred) income tax

While operating as an income trust, Penn West was considered a Specified Investment Flow-Through entity (a “SIFT entity”). Under previous GAAP, income tax assets and liabilities at the trust level were measured at the enacted tax rate for SIFT entities of approximately 25 percent. Under IFRS, in the 2010 period preceding our conversion to a corporation we were required to apply a tax rate of 39 percent, representing the rate applicable to undistributed profits of the Trust.

2011 SECOND QUARTER REPORT 20

IFRS 1 - Oil and Gas Exemption

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 could 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 elected to apply this exemption. For a further discussion on IFRS 1 exemptions, refer to Note 17 of our unaudited interim consolidated financial statements.

Future accounting pronouncements

In November 2010, the International Accounting Standards Board published IFRS 9 “Financial Instruments” as part of its project to replace IAS 39 “Financial Instruments: Recognition and Measurement”. This first phase of the project outlines a single approach in determining if a financial asset or liability is measured at amortized cost or fair value and a single impairment method, replacing the multiple classifications and methods in IAS 39. The effective date for IFRS 9 is January 1, 2013. We currently believe there will be no significant impact upon adoption.

In May 2011, the IASB issued IFRS 10 “Consolidated Financial Statements” outlining a new methodology to determine whether to consolidate an investee. This new standard becomes effective for annual periods beginning on or after January 1, 2013. We believe the adoption of this standard will have no material impact on our financial statements.

In May 2011, the IASB issued IFRS 11 “Joint Arrangements”. This new standard outlines the accounting treatment for joint arrangements, notably joint operations which will follow the proportionate consolidation method and joint ventures which will follow the equity accounting method. This new standard becomes effective for annual periods beginning on or after January 1, 2013 and will apply to our interest in the Peace River Oil Partnership (“PROP”). We currently believe that our interest in PROP will be classified as a joint operation; therefore, we will continue to proportionately consolidate our interest upon adoption of this standard.

In May 2011, the IASB issued IFRS 12 “Disclosure of Interests in Other Entities” outlining disclosure requirements for interests in subsidiaries, joint arrangements, associates and unconsolidated structured entities. These disclosure requirements are required for annual periods beginning on or after January 1, 2013. We believe there will be minimal changes to our current disclosures.

In May 2011, the IASB issued IFRS 13 “Fair Value Measurement” which defines fair value, provides guidance on measuring fair value and outlines disclosure requirements for fair value measurement. This standard applies when another IFRS standard requires fair value measurements or disclosures, with some exceptions including IFRS 2 “Share based payments” and IAS 17 “Leases”. This new standard is applicable for annual periods beginning on or after January 1, 2013. We believe the adoption of this standard will have no material impact on our financial statements.

2011 SECOND QUARTER REPORT 21

IFRS impacts subsequent to our corporate conversion

Shareholders’ capital

Following the one-to-one exchange of trust units for common shares on January 1, 2011, Unitholders’ Capital was re-classified to Shareholders’ Capital.

Elimination of the consolidated deficit

Upon commencement of operations as a corporation, pursuant to the Plan of Arrangement and a resolution of the Board of Directors, Penn West’s recorded deficit of $610 million was eliminated against share capital on January 1, 2011.

Deferred Income Tax

Effective January 1, 2010, as an income trust, we were required to measure deferred income tax assets and liabilities at the trust level at a tax rate of 39 percent, representing the tax rate applicable to undistributed profits of the trust in the Province of Alberta. Deferred income tax was recorded on this basis from January 1, 2010 until our conversion to a corporation on January 1, 2011. Under IFRS, upon conversion to a corporation, the deferred income tax assets and liabilities were re-measured at the applicable corporate income tax rate of approximately 26 percent and the company recognized a $304 million deferred income tax recovery during the first quarter of 2011.

Share-based Compensation

Effective January 1, 2011, we implemented an Option Plan and amended our TURIP to become the CSRIP. Trust unit right holders had the choice to receive both a Restricted Option and a Restricted Right for outstanding “in-the-money” trust unit rights or receive a Share Right if they chose not to elect or had “out-of-the-money” trust unit rights. The elimination of the TURIP and subsequent implementation of the Option Plan and CSRIP resulted in a $58 million net charge to income during the first quarter of 2011.

Related-Party Transactions

During the first six months of 2011, we incurred $1 million (2010 - $2 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 our securityholders and potential investors with information regarding Penn West, including management's assessment of our 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", "objective", "aim", "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.

2011 SECOND QUARTER REPORT 22

In particular, this document contains forward-looking statements pertaining to, without limitation, the following: the percentage of our 2011 production capability that we believe is weighted to oil and liquids; the disclosure contained under the heading "Commodity Markets" relating to our view of the outlook for crude oil and natural gas prices, the prospects for global economic growth, the demand for energy products and the impact natural gas prices may have on drilling activity in different types of shale gas areas; our plan to continue to focus on our large-scale light-oil properties throughout the Cardium, Northern Carbonates, Spearfish (Waskada) and the Colorado (Viking) during the second half of 2011, and to increase our capital program to move further into the appraisal and development phases across these plays; our belief that our inventory of drilling locations now exceeds 10,000; our belief that we have a considerable number of growth opportunities; our belief that we will recover delayed second quarter production prior to year-end 2011 and our expectation that we will exit 2011 with production between 174,000 and 177,000 boe per day; our objective, when economic to do so, 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; our forecast that, based on current commodity prices and capital spending plans, our tax pool base will shelter our taxable income for an extended period; all matters relating to our dividend policy, including our intention to pay dividends on a quarterly basis, our ability to pay our third quarter dividend, and the factors that may affect the amount of dividends that we pay in the future (if any); the ability of our debt and risk management programs to increase the likelihood that we can maintain our financial flexibility to capture opportunities available in the markets in addition to the continuation of our capital and dividend programs and the longer-term execution of our business strategies; the disclosure contained under the heading "Outlook", which sets forth management's expectations as to our capital programs continuing to move toward full scale development of our suite of large-scale light-oil plays, the focus areas of our capital programs, our expectation that we will continue to extend our dominance in many of western Canada’s largest and most promising light oil plays as well as consolidate our positions in many of the new emerging source rock plays, our expectation that we will partially offset industry cost increases due to high activity levels by operating at consistent levels and by increasing our use of pad drilling, our anticipated exploration and development capital expenditure levels for 2011, our expectation that we will recover production outages that occurred in the second and third quarter in the fourth quarter, our forecast average daily production for the 2011 year, our forecast average daily production for the second half of 2011, our plan to reach full production capacity in the fourth quarter of 2011, and our anticipated average daily production rate at 2011 year end; the disclosure contained under the heading "Sensitivity Analysis" relating to the estimated sensitivity to selected key assumptions of our reported financial results for the 12 months subsequent to the current reporting period; and our expectations regarding the impact that the adoption of future accounting pronouncements will have on us, including on our disclosures and on our financial statements.

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 dividends 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 "Outlook" and "Sensitivity Analysis".

2011 SECOND QUARTER REPORT 23

Although we believe 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 our 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; the potential failure of counterparties to honour their contractual obligations; and the other factors described in our public filings (including our Annual Information Form and in Note 10 to our 2011 second quarter unaudited financial statements) available in Canada at www.sedar.com and in the United States at www.sec.gov. Readers are cautioned that this list of risk factors should not be construed as exhaustive.

The forward-looking statements contained in this document speak only as of the date of this document. Except as expressly required by applicable securities laws, we do 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.

2011 SECOND QUARTER REPORT 24

Penn West Petroleum Ltd.

Consolidated Balance Sheets

(CAD millions, unaudited)		Note				June 30, 2011				December 31, 2010				January 1, 2010
										(Note 17)				(Note 17)
Assets
Current
Accounts receivable						$	467			$	386			$	371
Other							93				87				101
Risk management			10				26				23				29
							586				496				501
Non-current
Deferred funding assets			4				661				678				-
Exploration and evaluation assets			5				187				128				132
Property, plant and equipment			6				11,578				11,218				11,174
Goodwill							2,020				2,020				2,020
Risk management			10				9				3				10
							14,455				14,047				13,336
Total assets						$	15,041			$	14,543			$	13,837
Liabilities and Shareholders’ Equity
Current
Accounts payable and accrued liabilities						$	675			$	910			$	568
Dividends payable							127				41				63
Convertible debentures			7				224				255				18
Risk management			10				70				85				159
							1,096				1,291				808
Non-current
Long-term debt			8				2,815				2,496				3,219
Convertible debentures							-				-				255
Decommissioning liability			9				627				648				562
Risk management			10				66				67				31
Deferred tax liability			11				1,261				1,452				1,530
Other non-current liabilities			13				10				29				15
							5,875				5,983				6,420
Shareholders’ equity
Shareholders’ capital			12				8,773				-				-
Unitholders’ capital			12				-				9,170				8,451
Other reserves			12				83				-				-
Retained earnings (deficit)							310				(610	)			(1,034	)
							9,166				8,560				7,417
Total liabilities and shareholders’ equity						$	15,041			$	14,543			$	13,837

Subsequent events (Notes 10 and 12)

Commitments and contingencies (Note 15)

See accompanying notes to the unaudited interim consolidated financial statements.

2011 SECOND QUARTER REPORT 25

Penn West Petroleum Ltd.

Consolidated Statements of Income

		Three months ended June 30												Six months ended June 30
(CAD millions, except per share amounts, unaudited)		Note				2011				2010				2011				2010
Oil and natural gas sales						$	953			$	715			$	1,809			$	1,530
Royalties							(171	)			(128	)			(321	)			(276	)
							782				587				1,488				1,254
Risk management gain (loss)
Realized							(33	)			3				(45	)			(6	)
Unrealized			10				188				119				12				155
							937				709				1,455				1,403
Expenses
Operating							267				231				505				462
Transportation							7				8				15				17
General and administrative							37				34				74				68
Share-based compensation expense (recovery)			13				4				(4	)			82				54
Depletion and depreciation			6				311				350				558				612
Gain on dispositions							(127	)			(737	)			(151	)			(714	)
Exploration and evaluation expense			5				-				1				4				1
Unrealized risk management (gain) loss			10				18				(28	)			(13	)			(3	)
Unrealized foreign exchange (gain) loss							(7	)			74				(45	)			19
Financing			7,8				48				45				95				85
Accretion			9				10				10				22				20
							568				(16	)			1,146				621
Income before taxes							369				725				309				782
Deferred tax expense (recovery)			11				98				(20	)			(253	)			(61	)
Net and comprehensive income						$	271			$	745			$	562			$	843
Net income per share
Basic						$	0.58			$	1.72			$	1.21			$	1.97
Diluted						$	0.58			$	1.69			$	1.21			$	1.94
Weighted average shares outstanding (millions)
Basic			12				466.6				433.8				464.2				428.4
Diluted			12				466.9				443.7				465.1				438.3

See accompanying notes to the unaudited interim consolidated financial statements.

2011 SECOND QUARTER REPORT 26

Penn West Petroleum Ltd.

Consolidated Statements of Cash Flows

		Three months ended June 30												Six months ended June 30
(CAD millions, unaudited)		Note				2011				2010				2011				2010
Operating activities
Net income						$	271			$	745			$	562			$	843
Depletion and depreciation			6				311				350				558				612
Gain on dispositions							(127	)			(737	)			(151	)			(714	)
Exploration and evaluation expense			5				-				1				4				1
Accretion			9				10				10				22				20
Deferred tax expense (recovery)			11				98				(20	)			(253	)			(61	)
Share-based compensation expense (recovery)			13				10				(7	)			80				51
Unrealized risk management gain			10				(170	)			(147	)			(25	)			(158	)
Unrealized foreign exchange loss (gain)							(7	)			74				(45	)			19
Decommissioning expenditures			9				(8	)			(12	)			(28	)			(27	)
Change in non-cash working capital							(133	)			(17	)			(229	)			(5	)
							255				240				495				581
Investing activities
Capital expenditures							(285	)			(231	)			(777	)			(494	)
Acquisitions							(169	)			(194	)			(196	)			(328	)
Proceeds from dispositions							184				288				291				866
Change in non-cash working capital							(115	)			(43	)			(134	)			(6	)
							(385	)			(180	)			(816	)			38
Financing activities
Increase (decrease) in bank loan							232				(345	)			289				(1,066	)
Proceeds from issuance of notes							-				-				75				304
Repayment of acquired credit facilities							(39	)			-				(39	)			-
Issue of equity							59				446				159				466
Dividends and distributions paid							(98	)			(161	)			(132	)			(323	)
Settlement of convertible debentures			7				(24	)			-				(31	)			-
							130				(60	)			321				(619	)
Change in cash							-				-				-				-
Cash, beginning of period							-				-				-				-
Cash, end of period						$	-			$	-			$	-			$	-

See accompanying notes to the unaudited interim consolidated financial statements.

2011 SECOND QUARTER REPORT 27

Penn West Petroleum Ltd.

Statements of Changes in Shareholders’ Equity

(CAD millions, unaudited)		Note				Shareholders’ Capital				Other Reserves				Retained Earnings				Total
Balance at January 1, 2011						$	9,170			$	-			$	(610	)		$	8,560
Elimination of deficit			12				(610	)			-				610				-
Net and comprehensive income							-				-				562				562
Implementation of Option Plan and CSRIP			13				-				81				-				81
Share-based compensation expense			13				-				22				-				22
Issued on exercise of options and share rights			12				179				(20	)			-				159
Issued to dividend reinvestment plan			12				34				-				-				34
Dividends declared			12				-				-				(252	)			(252	)
Balance at June 30, 2011						$	8,773			$	83			$	310			$	9,166

(CAD millions, unaudited)		Note				Unitholders’ Capital				Other Reserves				Deficit				Total
Balance at January 1, 2010						$	8,451			$	-			$	(1,034	)		$	7,417
Net and comprehensive income							-				-				843				843
Issued on exercise of trust unit rights			12				32				-				-				32
Issued to employee trust unit savings plan			12				19				-				-				19
Issued to distribution reinvestment plan			12				59				-				-				59
Issued on trust unit offering			12				428				-				-				428
Distributions declared							-				-				(386	)			(386	)
Balance at June 30, 2010						$	8,989			$	-			$	(577	)		$	8,412

See accompanying notes to the unaudited interim consolidated financial statements.

2011 SECOND QUARTER REPORT 28

Notes to the Unaudited Interim Consolidated Financial Statements

(All tabular amounts are in CAD millions except numbers of common shares, per share amounts,

percentages and various figures in Note 10)

1. Structure of Penn West

Penn West Petroleum Ltd. (“Penn West” or the “Company”) is a senior exploration and production company and is governed by the laws of the Province of Alberta, Canada. The business of Penn West is to explore for, develop and hold interests in petroleum and natural gas properties directly and through investments in securities of subsidiaries holding interests in oil and natural gas properties or related production infrastructure. Penn West owns the petroleum and natural gas assets or 100 percent of the equity, directly or indirectly, of the entities that carry on the remainder of the oil and natural gas business of Penn West, except for an unincorporated joint arrangement (the “Peace River Oil Partnership”) in which Penn West’s wholly owned subsidiaries hold a 55 percent interest.

On January 1, 2011, Penn West completed its plan of arrangement and converted from an income trust to a conventional corporation now operating under the trade name of Penn West Exploration. The consolidated results in 2011 are under Penn West’s current structure as a conventional corporation and the comparative figures in 2010 were under Penn West’s former structure as an income trust.

2. Basis of presentation and statement of compliance

a) Statement of Compliance

These unaudited interim consolidated financial statements were prepared in compliance with IAS 34 “Interim Financial Reporting” and accordingly do not contain all of the disclosures that are required in the preparation of Penn West’s annual audited consolidated financial statements. As this is the Company’s first annual period reporting under IFRS, the guidelines under IFRS 1 “First-time Adoption of IFRS” have been applied as discussed in Note 17. Prior to 2011, Penn West prepared its unaudited interim consolidated financial statements and audited annual consolidated financial statements in accordance with Canadian generally accepted accounting principles (“previous GAAP”).

The unaudited interim consolidated financial statements have been prepared on a historical cost basis, except risk management assets and liabilities which are stated at fair value as discussed in Note 10. All tabular amounts are in millions of Canadian dollars, except numbers of common shares, per share amounts, percentages and other figures as noted.

The unaudited interim consolidated financial statements were approved for issuance by the Board of Directors on August 9, 2011.

b) Basis of Consolidation

The unaudited interim consolidated financial statements include the accounts of Penn West and its wholly owned subsidiaries and its proportionate interest in partnerships. Results from acquired properties are included in Penn West’s reported results subsequent to the closing date and results from properties sold are included until the closing date.

All intercompany balances, transactions, income and expenses are eliminated on consolidation.

2011 SECOND QUARTER REPORT 29

3. Significant accounting policies

a) Critical accounting judgments and key estimates

The preparation of the consolidated financial statements in conformity with IFRS requires management to make estimates and assumptions that affect the recorded amounts of assets and liabilities, disclosure of any contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses for the period. These and other estimates are subject to measurement uncertainty and the effect on the consolidated financial statements of changes in these estimates could be material.

The following are the critical judgments that management has made in applying the Company’s accounting policies and that have the most significant effect on the amounts recognized in the consolidated financial statements.

i) Reserve estimates

Commercial petroleum reserves are determined based on estimates of oil-in-place, recovery factors and future oil and natural gas prices and costs. Penn West engages independent qualified reserve evaluators to audit or evaluate the Company’s oil and natural gas reserves at each year-end.

Reserve adjustments are made annually based on actual oil and natural gas volumes produced, the results from capital programs, revisions to previous estimates, new discoveries and acquisitions and dispositions made during the year. There are a number of estimates and assumptions that affect the process of evaluating reserves.

Proved reserves are the estimated quantities of crude oil, natural gas and natural gas liquids determined to be economically recoverable under existing economic and operating conditions with a high degree of certainty (at least 90 percent) those quantities will be exceeded. Proved plus probable reserves are the estimated quantities of crude oil, natural gas and natural gas liquids determined to be economically recoverable under existing economic and operating conditions with a 50 percent certainty those quantities will or will not be exceeded. Penn West reports production and reserve quantities in accordance with Canadian practices and specifically in accordance with Standards of Disclosures for Oil and Gas Activities (“NI 51-101”).

The estimate of proved plus probable reserves is an essential part of the depletion calculation, the impairment test and the recorded amount of oil and gas assets.

Penn West cautions users of this information that the process of estimating crude oil and natural gas reserves is subject to a level of uncertainty. The reserves are based on current and forecast economic and operating conditions; therefore, changes can be made to future assessments as a result of a number of factors, which can include commodity prices, new technology, changing economic conditions, future reservoir performance and development activity.

ii) Recoverability of asset carrying values

Penn West assesses its property, plant and equipment (“PP&E”) and goodwill for impairment by comparing the carrying amount to the recoverable amount of the underlying assets. The determination of the recoverable amount involves estimating the higher of an asset’s fair value less costs to sell or its value-in-use, which is based on its discounted future cash flows using an applicable discount rate. Future cash flows are calculated based on management’s best estimate of future commodity prices and inflation and are discounted based on management’s current assessment of market conditions.

iii) Recoverability of exploration and evaluation assets

Exploration and Evaluation (“E&E”) assets are assessed for impairment by comparing the carrying amount to the recoverable amount. The assessment of the recoverable amount involves a number of assumptions, including the timing/likelihood/amount of commercial production, future revenue/costs expected from the asset and the discount rate applied to the future revenue and costs.

2011 SECOND QUARTER REPORT 30

iv) Decommissioning liability

Penn West recognizes a provision for future abandonment activities in the consolidated financial statements at the net present value of the estimated future expenditures required to settle the estimated future obligation at the balance sheet date. The measurement of the decommissioning liability involves the use of estimates and assumptions including the discount rate, the expected timing of future expenditures and the amount of future abandonment costs. The estimates were made by management and external consultants considering current costs, technology and enacted legislation.

v) Fair value calculation on share-based payments

The fair value of share-based payments is calculated using either a Black-Scholes or Binomial Lattice option-pricing model, depending on the characteristics of the share-based payment. There are a number of estimates used in the calculation such as the future forfeiture rate, expected option life and the future price volatility of the underlying security which can vary from actual future events. The factors applied in the calculation are management’s best estimates based on historical information and future forecasts.

vi) Fair value of risk management contracts

Penn West records risk management contracts at fair value with changes in fair value recognized in income. The fair values are determined using external counterparty information which is compared to observable market data.

vii) Taxation

The calculation of deferred income taxes is based on a number of assumptions including estimating the future periods in which temporary differences, tax losses and other tax credits will reverse and the use of substantively enacted tax rates at the balance sheet date.

b) Business combinations

Penn West uses the acquisition method to account for business combinations. The net identifiable assets, liabilities and contingent liabilities acquired in transactions which meet the definition of a business combination under IFRS are measured at their fair value at the acquisition date. The acquisition date is the closing date of the business combination. Acquisition costs incurred by Penn West to complete a business combination are expensed in the period incurred except for costs related to the issue of any debt or equity securities which are recognized based on the nature of the related instrument.

Revisions may be made to the initial allocation of fair values acquired and the appropriate disclosures during the measurement period, being one year after the close date of the acquisition.

c) Goodwill

Penn West recognizes goodwill on a business combination when the total purchase consideration exceeds the fair value of the net identifiable assets acquired and liabilities assumed of the acquired entity. Following initial recognition, goodwill is recognized at cost less any accumulated impairment losses.

Goodwill is not amortized and the carrying amount is assessed for impairment on an annual basis on December 31, or more frequently if circumstances arise that indicate impairment may have occurred. To test for impairment, goodwill is assessed at a consolidated level. If the recoverable amount is less than the carrying amount, an impairment loss is recorded and allocated to the carrying value of goodwill. Goodwill impairment losses are not reversed in subsequent periods.

2011 SECOND QUARTER REPORT 31

d) Revenue

Penn West generally recognizes oil and natural gas revenue when title passes from Penn West to the purchaser or in the case of services, as contracted services are performed.

Revenue is measured at the fair value of the consideration received or receivable. Revenue from the sale of crude oil, natural gas and natural gas liquids (prior to deduction of transportation costs) is recognized when all the following conditions have been satisfied:

• Penn West has transferred the significant risks and rewards of ownership of the goods to the buyer;

• Penn West retains no continuing managerial involvement to the degree usually associated with ownership or effective control over the goods sold;

• the amount of revenue can be reliably measured;

• it is probable that the economic benefits associated with the transaction will flow to Penn West; and

• the costs incurred or to be incurred in respect of the transaction can be reliably measured.

e) Joint arrangements

A significant portion of Penn West’s exploration and development activities are conducted jointly with others and involve jointly controlled assets. Under such arrangements, Penn West has the exclusive rights to its proportionate interest in the asset and the economic benefits generated from the asset. Penn West’s share of jointly controlled assets and any liabilities incurred jointly with other parties are recognized in the consolidated financial statements to the extent of its proportionate interest. Income from the sale or use of Penn West’s interest in jointly controlled assets and its share of expenses is recognized when it is probable that the economic benefits associated with the transactions will flow to/from Penn West and the amounts can be reliably measured. The consolidated financial statements include Penn West’s share of these jointly controlled assets and liabilities and a proportionate share of the revenue, royalties and operating costs.

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 recognizing its 55 percent share of revenues, expenses, assets and liabilities. Please refer to Note 4 below.

f) Transportation expense

Transportation costs are paid by Penn West for the shipping of natural gas, crude oil and NGLs from the wellhead to the point of title transfer to buyers. These costs are recognized when services are received.

g) Foreign currency translation

Penn West’s functional currency is the Canadian dollar. Monetary items, such as accounts receivable and long-term debt, are translated to Canadian dollars at the rate of exchange in effect at the balance sheet date. Non-monetary items, such as property, plant and equipment, are translated to Canadian dollars at the rate of exchange in effect when the transactions occurred. Revenues and expenses denominated in foreign currencies are translated at the average exchange rate in effect during the period. Foreign exchange gains or losses on translation are included in income.

2011 SECOND QUARTER REPORT 32

h) E&E

i) Measurement and recognition

E&E assets are initially measured at cost. Items included in E&E primarily relate to exploratory drilling, geological & geophysical activities, acquisition of mineral rights and technical studies. Capital expenditures are classified as E&E assets until the technical feasibility and commercial viability of extracting oil and natural gas from the assets has been determined.

ii) Transfer to PP&E

E&E costs are transferred to PP&E 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 in that field, the E&E assets are considered impaired and the amounts are charged to income as E&E expense.

iii) Pre-license costs

Pre-license expenditures incurred before Penn West has obtained the legal rights to explore for hydrocarbons in a specific area are expensed.

iv) Impairment

E&E assets are tested for impairment when facts or circumstances indicate that a possible impairment may exist and prior to their reclassification to PP&E.

i) PP&E

i) Measurement and recognition

Capital expenditures are recognized as PP&E when it is probable that future economic benefits associated with the item will flow to Penn West and the cost can be reliably measured. PP&E includes capital expenditures incurred in the development phase, costs transferred from E&E and additions to the decommissioning liability.

Oil & Gas properties are included in PP&E at cost, less accumulated depletion and depreciation and any impairment losses. The cost of a fixed asset includes costs incurred initially to acquire or construct the item and betterment costs.

ii) Depletion and Depreciation

Except for components with a useful life shorter than the reserve life of the associated property, resource properties are depleted using the unit-of-production method based on production volumes before royalties in relation to total proved plus probable reserves. Natural gas volumes are converted to equivalent oil volumes based upon the relative energy content of six thousand cubic feet of natural gas to one barrel of oil. In determining its depletion base, Penn West includes estimated future costs to develop proved plus probable reserves and excludes estimated equipment salvage values and the cost of E&E assets. Changes to reserve estimates are included in the depletion calculation prospectively.

Components including significant plant turnaround costs not depleted using the unit-of-production method are depreciated on a straight-line basis over their useful life.

2011 SECOND QUARTER REPORT 33

iii) Derecognition

The carrying amount of an item of PP&E is derecognized when no future economic benefits are expected from its use or upon sale to a third party. The gain or loss arising from derecognition is included in income and is measured as the difference between the net proceeds, if any, and the carrying amount of the asset.

iv) Major maintenance and repairs

Ongoing costs to maintain properties are generally expensed as incurred. These costs include the cost of labour, consumables and small parts. The costs of material replacement parts, turnarounds and major inspections are capitalized provided it is probable that future economic benefits in excess of cost will be realized and such benefits are expected to extend beyond the current operating period. The carrying amount of a replaced part is derecognized in accordance with our derecognition policies.

v) Impairment

At the end of each quarter, Penn West reviews oil and gas properties for circumstances that indicate its assets may be impaired. These indicators can be internal (i.e. reserve changes) or external (i.e. market conditions) in nature. If an indication of impairment exists, Penn West completes an impairment test which compares the estimated recoverable amount to its carrying value. The recoverable amount is defined under IAS 36 (“Impairment of Assets”) as the higher of an asset’s or Cash Generating Unit’s (“CGU”) fair value less costs to sell and its value-in-use.

Where the recoverable amount is less than the carrying amount, the asset or CGU is deemed to be impaired. Impairment losses identified for a CGU are allocated on a pro rata basis to the assets within the CGU. The impairment loss is recognized as an expense in income.

In assessing the value-in-use, the estimated future cash flows are discounted to their present value using a pre-tax discount rate that reflects current market assessments of the time value of money and the risks specific to the asset. Value-in-use is computed as the present value of future cash flows expected to be derived from production of proved and probable reserves.

Impairment losses related to PP&E can be reversed in future periods if the estimated recoverable amount of the asset subsequently exceeds the carrying value. The impairment recovery is limited to a maximum of what the depreciated historical cost would have been if the impairment had not been recognized. The reversal of the impairment loss is recognized in depletion and depreciation.

vi) Other Property, Plant and Equipment

Penn West’s corporate assets include computer hardware and software, office furniture, buildings and leasehold improvements and are depreciated on a straight-line basis over their useful lives. Corporate assets are tested for impairment separately from oil and gas assets.

j) Inventory

Petroleum and materials inventories are valued at the lower of weighted average cost and net realizable value.

2011 SECOND QUARTER REPORT 34

k) Share-based payments

The fair value of options granted under the Stock Option Plan (the “Option Plan”) is recognized as compensation expense and a corresponding increase to other reserves over the term of the options based on a graded vesting schedule. Penn West measures the fair value of options granted under the plan at the grant date using a Black-Scholes option-pricing model. The fair value is based on market prices and considers the terms and conditions of the share options granted.

Effective January 1, 2011, Penn West amended and restated its Trust Unit Rights Incentive Plan (“TURIP”), to become the Common Share Rights Incentive Plan (“CSRIP”), and implemented the Option Plan. Trust unit right holders under the former TURIP were given the choice to elect to receive one Restricted Option and one Restricted Right in exchange for one outstanding “in-the-money” trust unit right on the effective date. As option holders who made this election have the choice to settle the Restricted Right in cash or common shares upon exercise, the amount of the related obligation is classified as a liability. Both the Restricted Option and the Restricted Right are measured using a Black Scholes option-pricing model and are expensed over the expected vesting period of the award.

Trust unit right holders who chose not to make the election or held trust unit rights that were “out-of-the-money” on the effective date received one common share right (“Share Rights”) in exchange for each trust unit right. Share Rights are measured using a Binomial Lattice option-pricing model on the date of issuance and are classified as equity awards. The fair value of the Share Rights is expensed over their expected vesting period.

In 2010, Penn West implemented a Long-Term Retention and Incentive Plan (“LTRIP”). Compensation expense related to the plan is based on a fair value calculation on each reporting date using the awards outstanding and Penn West’s share price from the Toronto Stock Exchange (“TSX”) on each balance sheet date. The fair value of the awards is expensed over the vesting period based on a graded vesting schedule. Subsequent increases and decreases in the underlying share price results in increases and decreases, respectively, to the accrued obligation until settlement.

l) Provisions

i) General

Provisions are recognized based on an estimate of expenditures required to settle present obligations at the end of the reporting period. The provision is risk adjusted to take into account any uncertainties. When the effect of the time value of money is material, the amount of a provision is equal to the present value of the future expenditures required to settle the obligations. The discount rate reflects the current assessment of the time value of money and risks specific to the liability when those risks have not already been reflected as an adjustment to future cash flows.

ii) Decommissioning liability

The fair value of future obligations for property abandonment and site restoration is recognized as a decommissioning liability on the balance sheet with a corresponding increase to the carrying amount of the related asset. The recorded liability increases over time to its future amount through accretion charges to income. Revisions to the estimated amount or timing of the obligations are reflected prospectively as increases or decreases to the recorded liability and the related asset. Actual decommissioning expenditures, up to the recorded liability at the time, are charged to the liability as the costs are incurred. Amounts capitalized to the related assets are amortized to income consistent with the depletion or depreciation of the underlying asset.

m) Leases

A lease is classified as an operating lease if it does not transfer substantially all of the risks and rewards incidental to ownership to the lessee. Operating lease payments are expensed on a straight line-basis over the life of the lease.

2011 SECOND QUARTER REPORT 35

n) Share capital

Common shares are classified as equity. Share issue costs are recorded in shareholder’s equity, net of applicable taxes. Dividends are paid at the discretion of the Board of Directors and are deducted from retained earnings.

o) Earnings per share

Earnings per share is calculated by dividing net and comprehensive income or loss attributable to the shareholders by the weighted average number of common shares outstanding during the period. Penn West computes the dilutive impact of common shares assuming the proceeds received from the pro forma exercise of in-the-money share options are used to purchase common shares at average market prices.

Penn West calculates the dilutive impact of the convertible debentures, assuming the outstanding debentures are converted at the later of the beginning of the period or the date of issue.

p) Taxation

Income taxes are based on taxable income in a taxation year. Taxable income normally differs from income reported in the consolidated statement of income as it excludes items of income or expense that are taxable or deductible in other years or are not taxable or deductible for income tax purposes.

Penn West uses the asset and liability method of accounting for deferred income taxes. Temporary differences are calculated assuming that the financial assets and liabilities will be settled at their carrying amount. Deferred income taxes are computed on temporary differences using substantively enacted income tax rates expected to apply when deferred income tax assets and liabilities are realized or settled.

q) Financial instruments

Penn West has policies and procedures in place with respect to the required documentation and approvals for the use of financial instruments and their use is currently limited to mitigating market price risk directly related to expected cash flows.

Financial instruments are measured at fair value on the balance sheet upon initial recognition of the instrument. Subsequent measurement and changes in fair value will depend on initial classification, as follows:

• Fair value through profit or loss financial assets and liabilities, classified as held for trading or designated fair value through profit or loss, are measured at fair value and changes in fair value are recognized in income;

• Loans and receivables are non-derivative financial assets with fixed or determinable payments that are not quoted in an active market;

• Available-for-sale financial instruments are measured at fair value with changes in fair value recorded in equity until the instrument or a portion thereof is derecognized or impaired at which time the amounts would be recognized in income;

• Held to maturity financial assets and loans and receivables are initially measured at fair value with subsequent measurement at amortized cost using the effective interest method. The effective interest method calculates the amortized cost of a financial asset and allocates interest income or expense over the applicable period. The rate used discounts the estimated future cash flows over either the expected life of the financial asset or liability or a shorter time-frame if it is deemed appropriate; and

• Other financial liabilities are initially measured at fair value with subsequent changes to fair value measured at amortized cost.

2011 SECOND QUARTER REPORT 36

Penn West’s current classifications are as follows:

• Cash and cash equivalents and accounts receivable are designated as loans and receivables;

• Accounts payable and accrued liabilities, dividends payable, convertible debentures and long-term debt are designated as other financial liabilities; and

• Risk management contracts are derivative financial instruments designated as fair value through profit or loss.

A gain or loss as a result of changes in the fair value of a financial asset or liability is recognized in income.

Penn West assesses each financial instrument, except those valued at fair value through profit or loss, for impairment at the reporting date and records the gain or loss in income during the period.

r) Embedded derivatives

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

• the economic characteristics and risks of the embedded derivative are not closely related to the economic characteristics and risks of the host contract;

• the embedded item, itself, meets the definition of a derivative; and

• the hybrid contract is not measured at fair value or designated as held for trading.

Penn West currently has no material embedded derivatives.

s) Compound instruments

Components of compound instruments are classified separately as financial liabilities and equity in accordance with the substance of the contractual arrangement. At the issue date, the fair value of the liability component is estimated using the prevailing market interest rate for a similar non-convertible instrument. This amount is recorded as a liability based on amortized cost until the instrument is converted or the instrument matures. The equity component is determined by deducting the liability component from the total fair value of the compound instrument and is recognized as equity, net of income tax effects, with no subsequent re-measurement.

Penn West currently has convertible debentures classified as compound instruments.

t) Classification of debt or equity

Penn West classifies financial assets, financial liabilities or equity instruments in accordance with the substance of the contractual arrangement and the definitions of a financial asset, financial liability or an equity instrument.

• Penn West’s debt instruments and convertible debentures currently have a requirement to deliver cash or common shares at the end of the term and are classified as liabilities.

• In 2010, when Penn West was operating as a trust, its trust units were considered puttable financial instruments that met the criteria in IAS 32 “Financial Instruments: Presentation” and received equity classification.

2011 SECOND QUARTER REPORT 37

u) Enhanced oil recovery

The value of proprietary injectants is not recognized as revenue until reproduced and sold to third parties. The cost of injectants purchased from third parties for miscible flood projects is included in PP&E. Injectant costs are depleted over the period of expected future economic benefit on a unit-of-production basis. Costs associated with the production of proprietary injectants are expensed.

v) Comprehensive income

Comprehensive income is defined as the change in equity from transactions and other events from non-owner sources and consists of net income and other comprehensive income (“OCI”). OCI refers to items recognized in comprehensive income that are excluded from net income calculated in accordance with IFRS. Penn West has no items requiring separate disclosure as OCI on a statement of Comprehensive Income.

Future Accounting Pronouncements

In November 2010, the International Accounting Standards Board published IFRS 9 “Financial Instruments” as part of its project to replace IAS 39 “Financial Instruments: Recognition and Measurement”. This first phase of the project outlines a single approach in determining if a financial asset or liability is measured at amortized cost or fair value and a single impairment method, replacing the multiple classifications and methods in IAS 39. The effective date for IFRS 9 is January 1, 2013. Penn West currently believes there will be no significant impact upon adoption.

In May 2011, the IASB issued IFRS 10 “Consolidated Financial Statements” outlining a new methodology to determine whether to consolidate an investee. This new standard becomes effective for annual periods beginning on or after January 1, 2013. Penn West believes the adoption of this standard will have no material impact on its financial statements.

In May 2011, the IASB issued IFRS 11 “Joint Arrangements”. This new standard outlines the accounting treatment for joint arrangements, notably joint operations which will follow the proportionate consolidation method and joint ventures which will follow the equity accounting method. This new standard becomes effective for annual periods beginning on or after January 1, 2013 and will apply to Penn West’s interest in the Peace River Oil Partnership. Penn West currently believes that its interest in the Peace River Oil Partnership is classified as a joint operation; therefore, it will continue to proportionately consolidate its interest in the Partnership upon adoption of this standard.

In May 2011, the IASB issued IFRS 12 “Disclosure of Interests in Other Entities” outlining disclosure requirements for interests in subsidiaries, joint arrangements, associates and unconsolidated structured entities. These disclosure requirements are required for annual periods beginning on or after January 1, 2013. Penn West believes there will be minimal changes to its current disclosures.

In May 2011, the IASB issued IFRS 13 “Fair Value Measurement” which defines fair value, provides guidance on measuring fair value and outlines disclosure requirements for fair value measurement. This standard applies when another IFRS standard requires fair value measurements or disclosures, with some exceptions including IFRS 2 “Share based payments” and IAS 17 “Leases”. This new standard is applicable for annual periods beginning on or after January 1, 2013. Penn West believes the adoption of this standard will have no material impact on its financial statements.

2011 SECOND QUARTER REPORT 38

4. Deferred funding assets

Peace River Oil Partnership

In 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 in exchange for a 55 percent interest in the partnership. Penn West received cash consideration of $312 million upon closing and received an additional $505 million in future commitments from Penn West’s partner to fund its share of future capital and operating expenses in the Peace River Oil Partnership. As at June 30, 2011, approximately $473 million of deferred funding remained (December 31, 2010 - $473 million).

Cordova Joint Venture

In 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 $205 million in future commitments from Penn West’s partner for its share of future capital costs in the joint venture. As at June 30, 2011, approximately $188 million of deferred funding remained (December 31, 2010 - $205 million).

5. Exploration and evaluation assets

		Six months ended June 30, 2011				Year ended December 31, 2010
Balance, beginning of period		$	128			$	132
Capital expenditures			65				58
Expense			(4	)			(1	)
Net dispositions			(2	)			(61	)
Balance, end of period		$	187			$	128

2011 SECOND QUARTER REPORT 39

6. Property, plant and equipment

Cost		Six months ended  June 30, 2011				Year ended December 31, 2010
Balance, beginning of period		$	18,554			$	17,762
Capital expenditures			712				1,129
Joint venture, carried capital			45				17
Acquisitions			30				552
Dispositions			(220	)			(1,136	)
Business combinations			286				139
Decommissioning additions (dispositions)			(24	)			91
Balance, end of period		$	19,383			$	18,554

Accumulated depletion and depreciation		Six months ended June 30, 2011				Year ended December 31, 2010
Balance, beginning of period		$	7,336			$	6,588
Depletion and depreciation			568				1,089
Dispositions			(89	)			(421	)
Impairment			29				80
Impairment reversals			(39	)			-
Balance, end of period		$	7,805			$	7,336

Net book value		June 30, 2011				December 31, 2010
Total		$	11,578			$	11,218

In addition to Penn West’s net share of capital overhead recoveries, capital additions included approximately $12 million of staff costs directly attributable to exploration and development activities (2010 - $12 million).

On June 1, 2011, we closed the acquisition of Spartan Exploration Ltd., a publicly traded oil and gas exploration company. The total acquisition cost was $222 million, which included the assumption of $56 million of debt and working capital deficiency.

An impairment test was performed on the costs capitalized to oil and natural gas properties at June 30, 2011 and December 31, 2010, using a pre-tax discount rate of 10 percent. The estimated discounted future net cash flows from proved plus probable reserves, using forecast prices, was compared to the carrying amount of the oil and natural gas property interests. In the second quarter of 2011, we recorded a $29 million impairment (2010 - $80 million) on certain properties in Central Alberta due to weaker commodity prices.

2011 SECOND QUARTER REPORT 40

7. Convertible debentures

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

		June 30, 2011				December 31, 2010
Total		$	224			$	255
Total fair value (1)		$	226			$	262

(1) Based on quoted market value.

At June 30, 2011, Penn West had the following unsecured, subordinated convertible debentures outstanding:

Description of security	Symbol	Maturity date	Conversion price (per share)	Redemption price (per $1,000 face value)
6.5% Convertible extendible	PWT.DB.F	Dec. 31, 2011	$51.55	$1,025 Dec. 31, 2010 to maturity

During the second quarter of 2011, the series E debentures matured and were settled in cash for a total of $24 million. In the first quarter of 2011, Penn West was required to make a cash offer to settle its convertible debentures as part of its conversion to a corporation. As a result $7 million were settled in cash.

		PWT.DB.D - 6.5%				PWT.DB.E - 7.2%				PWT.DB.F - 6.5%				Total
Balance, December 31, 2009		$	18			$	26			$	229			$	273
Matured (1)			(18	)			-				-				(18	)
Balance, December 31, 2010		$	-			$	26			$	229			$	255
Settled (2)			-				(2	)			(5	)			(7	)
Matured (2)			-				(24	)			-				(24	)
Balance, June 30, 2011		$	-			$	-			$	224			$	224

(1) Convertible debentures were settled in equity.

(2) Convertible debentures were settled in cash.

2011 SECOND QUARTER REPORT 41

8. Long-term debt

		June 30, 2011				December 31, 2010
Bankers’ acceptances and prime rate loans		$	1,062			$	773
U.S. Senior unsecured notes - 2007 Notes
5.68%, US$160 million, maturing May 31, 2015			155				159
5.80%, US$155 million, maturing May 31, 2017			149				154
5.90%, US$140 million, maturing May 31, 2019			135				139
6.05%, US$20 million, maturing May 31, 2022			19				20
			458				472
Senior unsecured notes - 2008 Notes
6.12%, US$153 million, maturing May 29, 2016			147				152
6.16%, CAD$30 million, maturing May 29, 2018			30				30
6.30%, US$278 million, maturing May 29, 2018			268				276
6.40%, US$49 million, maturing May 29, 2020			48				49
			493				507
UK Senior unsecured notes - UK Notes
6.95%, £57 million, maturing July 31, 2018 (1)			88				88
Senior unsecured notes - 2009 Notes
8.29%, US$50 million, maturing May 5, 2014			48				50
8.89%, US$35 million, maturing May 5, 2016			34				35
9.32%, US$34 million, maturing May 5, 2019			33				34
8.89%, US$35 million, maturing May 5, 2019 (2)			34				35
9.15%, £20 million, maturing May 5, 2019 (3)			31				31
9.22%, €10 million, maturing May 5, 2019 (4)			14				13
7.58%, CAD$5 million, maturing May 5, 2014			5				5
			199				203
Senior unsecured notes - 2010 Q1 Notes
4.53%, US$28 million, maturing March 16, 2015			27				27
4.88%, CAD$50 million, maturing March 16, 2015			50				50
5.29%, US$65 million, maturing March 16, 2017			63				64
5.85%, US$112 million, maturing March 16, 2020			109				112
5.95%, US$25 million, maturing March 16, 2022			24				25
6.10%, US$20 million, maturing March 16, 2025			19				20
			292				298
Senior unsecured notes - 2010 Q4 Notes
4.44%, CAD$10 million, maturing December 2, 2015			10				10
4.17%, US$18 million, maturing December 2, 2017			17				18
5.38%, CAD$50 million, maturing December 2, 2020			50				50
4.88%, US$84 million, maturing December 2, 2020			81				49
4.98%, US$18 million, maturing December 2, 2022			17				18
5.23%, US$50 million, maturing December 2, 2025			48				10
			223				155
Total long-term debt		$	2,815			$	2,496

(1) These notes bear interest at 7.78 percent in Pounds Sterling, however, contracts were entered into 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.

2011 SECOND QUARTER REPORT 42

Penn West has a four-year, unsecured, revolving syndicated bank facility with an aggregate borrowing limit of $2.25 billion. The facility expires on June 26, 2015 and is extendible. 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 June 30, 2011, the Company had approximately $1.2 billion of unused credit capacity available.

Letters of credit totalling $2 million were outstanding on June 30, 2011 (December 31, 2010 - $2 million) that reduced the amount otherwise available to be drawn on the syndicated facility.

Financing costs, including interest expense on the syndicated bank facility, the senior unsecured notes and the convertible debentures, were $48 million in the second quarter of 2011 (2010 - $45 million) and $95 million for the first six months of 2011 (2010 - $85 million). Also included in financing costs are realized losses on interest rate swaps of $3 million for the second quarter of 2011 (2010 - $6 million) and $6 million for the first six months of 2011 (2010 - $12 million).

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

		June 30, 2011				December 31, 2010
2007 Notes		$	487			$	500
2008 Notes			544				557
UK Notes			87				87
2009 Notes			233				239
2010 Q1 Notes			304				309
2010 Q4 Notes			220				151
Total		$	1,875			$	1,843

9. Decommissioning liability

The decommissioning liability was determined by applying an inflation factor of 2.0 percent (December 31, 2010 - 2.0 percent) and the inflated amount was discounted using a credit-adjusted rate of 7.0 percent (December 31, 2010 - 7.0 percent) over the expected useful life of the underlying assets, currently extending up to 50 years into the future with an average life of 35 years. Future cash flows from operating activities are expected to fund the obligations.

Changes to the decommissioning liability were as follows:

		Six months ended June 30, 2011				Year ended December 31, 2010
Balance, beginning of period		$	648			$	562
Net liabilities incurred during the period (1)			(17	)			54
Increase in liability due to change in estimate			-				37
Liabilities settled during the period			(28	)			(53	)
Liabilities acquired during the period			2				4
Accretion charges			22				44
Balance, end of period		$	627			$	648

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

2011 SECOND QUARTER REPORT 43

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 8 and the convertible debentures described in Note 7, the fair values of these financial instruments approximate their carrying amounts due to the short-term maturity of the instruments, the mark to market values recorded for the financial instruments and the market rate of interest applicable to the bank facility.

The fair values of all outstanding financial commodity, power, interest rate and foreign exchange contracts are reflected on the balance sheet with the changes during the period recorded in income as unrealized gains or losses.

As at June 30, 2011 and December 31, 2010, the only asset or liability measured at fair value on a recurring basis was the risk management asset and liability, which was valued based on “Level 2 inputs” being 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 asset (liability)		Six months ended June 30, 2011				Year ended December 31, 2010
Balance, beginning of period		$	(126	)		$	(151	)
Unrealized gain (loss) on financial instruments:
Commodity collars and swaps			12				23
Electricity swaps			28				8
Interest rate swaps			(1	)			(3	)
Foreign exchange forwards			(14	)			16
Cross currency swaps			-				(19	)
Total fair value, end of period		$	(101	)		$	(126	)
Total fair value consists of the following:
Fair value, end of period - current assets portion		$	26			$	23
Fair value, end of period - current liability portion			(70	)			(85	)
Fair value, end of period - non-current assets portion			9				3
Fair value, end of period - non-current liability portion			(66	)			(67	)
Total fair value, end of period		$	(101	)		$	(126	)

Based on June 30, 2011 pricing, a $1.00 change in the price per barrel of liquids would change pre-tax unrealized risk management by $14 million and a $0.10 change in the price per mcf of natural gas would change pre-tax unrealized risk management by $1 million.

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

Risk management		Six months ended June 30, 2011				Year ended December 31, 2010
Balance, beginning of period		$	(126	)		$	(151	)
Realized loss - commodity contracts			45				20
Unrealized gain (loss) - commodity contracts			(33	)			3
Realized loss - other			4				35
Unrealized gain (loss) - other			9				(33	)
Total fair value, end of period		$	(101	)		$	(126	)

2011 SECOND QUARTER REPORT 44

Penn West had the following financial instruments outstanding as at June 30, 2011. 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		41,000 bbls/d				July/11 - Dec/11				US$79.98 to $96.39/bbl				$	(48	)
WTI Collars		35,000 bbls/d				Jan/12 - Dec/12				US$86.00 to $109.72/bbl					(30	)
Natural gas
AECO Forwards (1)		25,000 GJ/d				Jan/12 - Dec/12					$4.27/GJ				3
Electricity swaps
Alberta Power Pool		90 MW				July/11 - Dec/11				$63.16/MWh					3
Alberta Power Pool		45 MW				Jan/12 - Dec/12				$53.02/MWh					4
Alberta Power Pool		30 MW				Jan/12 - Dec/13				$54.60/MWh					3
Alberta Power Pool		20 MW				Jan/13 - Dec/13				$56.10/MWh					1
Alberta Power Pool		50 MW				Jan/14 - Dec/14				$58.50/MWh					2
Interest rate swaps
			$500			July/11 - Dec/11					1.61%				(1	)
			$600			July/11 - Jan/14					2.71%				(14	)
			$50			July/11 - Jan/14					1.94%				-
Foreign exchange forwards on commodities
19-month initial term		US$189				July/11 - Dec/11				1.061 CAD/USD					19
Foreign exchange forwards on senior notes
3 to 15-year initial term		US$730					2014 - 2022			0.9986 CAD/USD					(7	)
Cross currency swaps
10-year term			£57				2018			2.0075 CAD/GBP, 6.95%					(28	)
10-year term			£20				2019			1.8051 CAD/GBP, 9.15%					(6	)
10-year term			€10				2019			1.5870 CAD/EUR, 9.22%					(2	)
Total														$	(101	)

(1) The forward contracts total approximately 23,700 mcf per day with an average price of $4.50 per mcf.

Subsequent to June 30, 2011, Penn West entered into additional natural gas forward contracts on 26,300 mcf per day for 2012 at an average price of $4.12 per mcf. Also, after June 30, 2011, Penn West entered into further foreign exchange contracts relating to the principal balances on its senior notes totalling US$32 million at an average exchange rate of $0.985 CAD/USD maturing from 2014 to 2020.

A realized gain of $2 million (2010 - $4 million loss) on electricity contracts has been included in operating costs for the first six months of 2011.

2011 SECOND QUARTER REPORT 45

Business Risks

Penn West is exposed to normal market risks inherent in the oil and natural gas business, including, but not limited to, commodity price risk, foreign currency rate risk, credit risk, interest rate risk and liquidity risk. The Company seeks to mitigate these risks through various business processes and management controls and from time to time by using financial instruments.

Commodity Price Risk

Commodity price fluctuations are among the Company’s most significant exposures. Crude oil prices are influenced by worldwide factors such as OPEC actions, world 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 activity. In accordance with policies approved by Penn West’s Board of Directors, the Company 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, net of royalties, for one additional year thereafter.

Foreign Currency Rate Risk

Prices received for crude oil are referenced to or denominated directly in US dollars, thus Penn West’s realized oil prices are impacted by Canadian dollar to US dollar exchange rates. A portion of the Company’s debt capital is denominated in US dollars, thus the principal and interest payments in Canadian dollars are also impacted by exchange rates. When considered appropriate, the Company may use financial instruments to fix or collar future exchange rates to fix the Canadian dollar equivalent of crude oil revenues or to fix US denominated long-term debt principal repayments. At June 30, 2011, the following foreign currency forward contracts were outstanding:

Nominal Amount	Termination date	Exchange rate
Sell US$189	December 2011	1.06085 CAD/USD
Buy US$23	2014	1.00100 CAD/USD
Buy US$93	2015	1.00898 CAD/USD
Buy US$88	2016	1.00100 CAD/USD
Buy US$119	2017	1.00044 CAD/USD
Buy US$130	2018	1.00100 CAD/USD
Buy US$102	2019	0.99430 CAD/USD
Buy US$155	2020	1.00100 CAD/USD
Buy US$20	2022	0.98740 CAD/USD

At June 30, 2011, Penn West had US dollar denominated debt with a face value of US$0.8 billion (December 31, 2010 - US$1.2 billion) on which the repayment of the principal amount in Canadian dollars was not fixed.

2011 SECOND QUARTER REPORT 46

Credit Risk

Credit risk is the risk of loss if purchasers or counterparties do not fulfill their contractual obligations. The Company’s accounts receivable are principally with customers in the oil and natural gas industry and are generally subject to normal industry credit risk, which includes the ability to recover unpaid receivables by retaining the partner’s share of production when Penn West is the operator. For oil and natural gas sales and financial derivatives, a counterparty risk procedure is followed whereby each counterparty is reviewed on a regular basis for the purpose of assigning a credit limit and may be requested to provide security if determined to be prudent. For financial derivatives, the Company normally transacts with counterparties who are members of the banking syndicate or other counterparties that have investment grade bond ratings. Credit events related to all counterparties are monitored and credit exposures are reassessed on a regular basis. As necessary, provisions for potential credit related losses are recognized.

As at June 30, 2011, the maximum exposure to credit risk was $467 million (December 31, 2010 - $386 million) being the carrying value of the accounts receivable.

Interest Rate Risk

A portion of the Company’s debt capital is held 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, Penn West may increase the certainty of its 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 June 30, 2011, none of the Company’s long-term debt instruments were exposed to changes in short-term interest rates (December 31, 2010 - none).

As at June 30, 2011, a total of $1.8 billion of fixed interest rate debt instruments and $0.2 billion of convertible debentures were outstanding. On the fixed interest rate debt the average remaining term was 6.9 years (December 31, 2010 - 7.2 years) with an average interest rate of 5.6 percent (December 31, 2010 - 5.7 percent), including the effects of interest rate swaps.

Liquidity Risk

Liquidity risk is the risk that the Company will be unable to meet its 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, dividend 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.

The following table outlines estimated future contractual obligations for non-derivative financial liabilities as at June 30, 2011:

		2011				2012				2013				2014				2015				Thereafter
Bank debt		$	-			$	-			$	-			$	-			$	1,062			$	-
Senior unsecured notes			-				-				5				58				247				1,443
Convertible debentures			224				-				-				-				-				-
Accounts payable and accrued liabilities			558				-				-				-				-				-
Dividends payable			127				-				-				-				-				-
Share-based liability			117				10				-				-				-				-
Total		$	1,026			$	10			$	5			$	58			$	1,309			$	1,443

2011 SECOND QUARTER REPORT 47

11. Income taxes

		June 30, 2011				December 31, 2010
Deferred tax liability		$	1,261			$	1,452

On January 1, 2011, Penn West recorded a $304 million recovery related to a change in tax rates on conversion from an income trust to a corporation. As a corporation, deferred income tax assets and liabilities were re-measured at the applicable corporate income tax rate of approximately 26 percent. Under the trust structure, Penn West was required to provide for deferred tax on timing differences at the trust level at rates of approximately 39 percent, representing the rate applicable to undistributed earnings of the trust. Also, Penn West included a net tax recovery of $41 million related to amendments and exchanges of share-based instruments under Penn West’s equity-based compensation plans that occurred on January 1, 2011.

12. Shareholders’ equity

a) Authorized

i) An unlimited number of Common Shares.

ii) 90,000,000 Preferred Shares issuable in one or more series.

Penn West has a Dividend Reinvestment and Optional Share Purchase Plan (the “DRIP”) that provides eligible shareholders the opportunity to reinvest quarterly cash dividends into additional common shares at a potential discount. Common shares are issued from treasury at 95 percent of the 10-day volume-weighted average market price when available. When common shares are not available from treasury they are acquired in the open market at prevailing market prices.

Eligible shareholders who participate in the DRIP may also purchase additional common shares, subject to a quarterly maximum of $15,000 and a minimum of $500. Optional cash purchase common shares are acquired in the open market at prevailing market prices or issued from treasury, without a discount at the 10-day volume-weighted average market price.

2011 SECOND QUARTER REPORT 48

b) Issued

Shareholders’ capital		Common Shares/ Trust Units				Amount
Balance, December 31, 2009			421,638,737			$	8,451
Issued on exercise of trust unit rights (1)			5,530,841				114
Issued to employee trust unit savings plan			2,025,699				42
Issued to distribution reinvestment plan			6,040,183				117
Issued to settle convertible debentures			922,580				18
Issued on trust unit offering (net of issue costs/tax)			23,524,209				428
Balance, December 31, 2010			459,682,249			$	9,170
Cancellation of trust units on January 1, 2011			(459,682,249	)			(9,170	)
Issuance of shares on January 1, 2011			459,682,249				9,170
Elimination of deficit			-				(610	)
Issued on exercise of restricted options (1)			6,870,887				179
Issued to dividend reinvestment plan			1,405,720				34
Balance, June 30, 2011			467,958,856			$	8,773

(1) Upon exercise of options, the net benefit is recorded as a reduction of other reserves and an increase to shareholders’ capital. Included in the exercised amount are 65,679 shares issued from Treasury as a result of individuals settling their restricted rights in equity.

Upon commencement of operations as a corporation, pursuant to the Plan of Arrangement and a resolution of the Board of Directors, Penn West’s recorded deficit of $610 million was eliminated against share capital on January 1, 2011.

Other Reserves		Six months ended June 30, 2011				Year ended December 31, 2010
Balance, beginning of period		$	-			$	-
Set-up of Option Plan and CSRIP			81				-
Share-based compensation expense			22				-
Net benefit on options exercised (1)			(20	)			-
Balance, end of period		$	83			$	-

(1) Upon exercise of options, the net benefit is recorded as a reduction of other reserves and an increase to shareholders’ capital.

Preferred Shares

No Preferred Shares were issued or outstanding.

c) Basic and Diluted

Average Common Shares Outstanding		Three months ended June 30								Six months ended June 30
(millions of shares)		2011				2010				2011				2010
Weighted average
Basic			466.6				433.8				464.2				428.4
Dilutive impact			0.3				9.9				0.9				9.9
Diluted			466.9				443.7				465.1				438.3

2011 SECOND QUARTER REPORT 49

For the second quarter of 2011, 23.6 million common shares (2010 - 12.9 million) that would be issued under the Stock Option Plan and CSRIP and 4.3 million common shares (2010 - none) that would be issued on the conversion of the convertible debentures were excluded in calculating the weighted average number of diluted shares outstanding as they were considered anti-dilutive. There were no common shares related to the convertible debentures included in the diluted calculation.

For the first six months of 2011, 15.0 million common shares (2010 - 12.9 million) that would be issued under the Stock Option Plan and CSRIP and 4.3 million common shares (2010 - nil) that would be issued on the conversion of the convertible debentures were excluded in calculating the weighted average number of diluted shares outstanding as they were considered anti-dilutive. There were no common shares related to the convertible debentures included in the diluted calculation.

d) Dividends

In the second quarter of 2011, Penn West paid dividends of $0.27 per share totalling $125 million (2010 - distributions of $192 million) including amounts funded by the DRIP. For the first six months of 2011, dividends of $166 million have been paid (2010 - distributions of $382 million).

On July 15, 2011, Penn West paid its second quarter dividend of $0.27 per share totalling $127 million. On August 9, 2011, Penn West declared its third quarter dividend of $0.27 per share to be paid on October 14, 2011 to shareholders of record on September 30, 2011.

13. Share-based compensation

Stock Option Plan (the “Option Plan”)

Penn West has an Option Plan that allows Penn West to issue options to acquire common shares to officers, employees and other service providers. The plan was effective on January 1, 2011, the date of conversion to a corporation. Prior to 2011, options holders held trust unit rights under the Trust Unit Rights Incentive Plan (“TURIP”).

To date, no options have been granted to other service providers. The number of options reserved for issuance under the terms of the Option Plan plus the number of common shares rights reserved for issuance under the CSRIP shall not exceed nine percent of the aggregate number of issued and outstanding common shares of Penn West. The grant price of options is equal to the volume-weighted average trading price of the common shares on the TSX for a five-trading-day period immediately preceding the time of grant. Options granted to date vest over a four-year period and expire five years after the date of grant.

		Six months ended June 30, 2011
Options		Number of  Options				Weighted Average Exercise Price
Outstanding, beginning of period			-			$	-
Granted			7,080,626				27.43
Forfeited			(249,926	)			27.62
Outstanding, end of period			6,830,700			$	27.43
Exercisable, end of period			-			$	-

2011 SECOND QUARTER REPORT 50

Common Share Rights Incentive Plan (“CSRIP”)

Restricted Options and Restricted Rights

Prior to 2011, options holders held trust unit rights under the TURIP. On the effective date, pursuant to the Plan of Arrangement, holders of trust unit rights could elect to exchange one outstanding “in-the-money” trust unit right for one Restricted Option and one Restricted Right. The Restricted Option and the Restricted Right must be exercised simultaneously with the Restricted Option settled in equity while the Restricted Right can be settled in common shares or cash. Restricted Options and Restricted Rights vest between a three and five-year period and expire four to six years after the date of the grant. Subsequent to January 1, 2011 only stock options will be granted under the Option Plan.

		Six months ended June 30, 2011
Restricted Options		Number of Restricted Options				Weighted Average Exercise Price
Outstanding, beginning of period			-			$	-
Exchange of TURIP			27,586,712				23.84
Exercised			(6,188,414	)			23.84
Forfeited			(673,459	)			23.84
Outstanding, end of period			20,724,839			$	23.84
Exercisable, end of period			12,206,972			$	23.84

		Six months ended June 30, 2011
Restricted Rights		Number of Restricted Rights				Weighted Average Exercise Price
Outstanding, beginning of period			-			$	-
Exchange of TURIP			27,586,712				16.11
Exercised			(6,305,741	)			15.16
Forfeited			(556,132	)			16.15
Balance before reduction of exercise price			20,724,839				16.40
Reduction of exercise price for dividends paid			-				(0.48	)
Outstanding, end of period			20,724,839			$	15.92
Exercisable, end of period			12,206,972			$	15.91

The fair value of the Restricted Rights is classified as a liability due to the cash settlement feature. At June 30, 2011, $111 million was classified as a current liability (December 31, 2010 - nil) included in accounts payable and accrued liabilities and $5 million was classified as a non-current liability (December 31, 2010 - nil) included in other non-current liabilities.

2011 SECOND QUARTER REPORT 51

Share Rights

On the date of the conversion to a corporation, trust unit right holders who elected not to exchange their trust unit rights for a Restricted Option and Restricted Right, as described above, or who held “out-of-the-money” trust unit rights were issued Share Rights under the CSRIP in exchange for their trust unit rights. Share Rights were issued with the same or similar features to trust unit rights including vesting terms, grant prices and the reduction of the exercise price for dividends paid in certain circumstances. Share Rights vest between a three and five-year period and expire four to six years after the date of the grant. No new Share Rights will be granted after January 1, 2011.

		Six months ended June 30, 2011
Share Rights		Number of Share Rights				Weighted Average Exercise Price
Outstanding, beginning of period			-			$	-
Exchange of TURIP			3,778,766				22.46
Exercised			(616,794	)			15.94
Forfeited			(217,074	)			22.10
Balance before reduction of exercise price			2,944,898				23.85
Reduction of exercise price for dividends paid			-				(0.46	)
Outstanding, end of period			2,944,898			$	23.39
Exercisable, end of period			2,341,675			$	24.50

TURIP

Prior to conversion to a corporation on January 1, 2011, Penn West had a trust unit rights incentive plan that allowed Penn West to issue trust unit rights to directors, officers, employees and other service providers. Upon conversion, trust unit rights were exchanged for either a Restricted Option with a Restricted Right or a Share Right.

		Six months ended June 30, 2011								Year ended December 31, 2010
TURIP		Number of Unit Rights				Weighted Average Exercise Price				Number of Unit Rights				Weighted Average  Exercise Price
Outstanding, beginning of period			31,365,478			$	16.88				31,816,158			$	17.65
Granted			-				-				7,689,930				19.90
Exercised			-				-				(5,530,841	)			16.38
Forfeited			-				-				(2,609,769	)			18.22
Exchange for Restricted Options/ Rights			(27,586,712	)			16.11				-				-
Exchange for Share Rights			(3,778,766	)			22.46				-				-
Balance before reduction of exercise price			-				-				31,365,478				18.38
Reduction of exercise price for distributions paid			-				-				-				(1.50	)
Outstanding, end of period			-			$	-				31,365,478			$	16.88
Exercisable, end of period			-			$	-				13,895,742			$	17.52

Prior to the conversion to a corporation, the fair value of the TURIP obligation was classified as a current liability of $171 million included in accounts payable and accrued liabilities and a non-current liability of $25 million included in other non-current liabilities.

2011 SECOND QUARTER REPORT 52

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

Under the LTRIP, Penn West employees receive cash consideration based on Penn West’s share price. Eligible employees receive a grant of a specific number of LTRIP awards (each of which notionally represents a common share) that vest over a three-year period with the cash value paid to the employee on each vesting date. The cash consideration paid will vary depending upon the performance of the Penn West share price on the TSX. 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 common shares prior to the vesting date plus dividends declared by Penn West during the period preceding the vesting date.

LTRIP awards (number of shares equivalent)		Six months ended June 30, 2011				Year ended December 31, 2010
Outstanding, beginning of period			700,669				-
Granted			889,054				740,985
Vested			(187,273	)			-
Forfeited			(73,052	)			(40,316	)
Outstanding, end of period			1,329,398				700,669

At June 30, 2011, LTRIP obligations of $6 million were classified as a current liability (December 31, 2010 - $4 million) included in accounts payable and accrued liabilities and $5 million were classified as a non-current liability (December 31, 2010 - $4 million) included in other non-current liabilities.

Share-based compensation

Share-based compensation is based on the fair value of the options at the time of grant under the Option Plan and the CSRIP, amortized over the remaining vesting period on a graded vesting schedule. Share-based compensation under the Restricted Rights and LTRIP is based on the fair value of the awards outstanding at the reporting date and is amortized based on a graded vesting schedule. Share-based compensation consisted of the following:

		Six months ended June 30
		2011				2010
Options		$	8			$	-
Restricted Options			13				-
Restricted Rights			(5	)			-
Share Rights			1				-
LTRIP			7				3
TURIP			-				51
Expiry of TURIP on January 1, 2011			(196	)			-
Share Rights at January 1, 2011			16				-
Restricted Options on January 1, 2011			65				-
Restricted Rights liability on January 1, 2011			173				-
Share-based compensation		$	82			$	54

The share price used in the fair value calculation of the LTRIP obligation and Restricted Rights obligation at June 30, 2011 was $22.27 (2010 - $20.30).

On January 1, 2011, the TURIP liability was removed and a share-based liability was recorded related to the Restricted Rights. Additionally, the fair values to reflect the initiation of the Restricted Options and the Shares Rights were recorded in other reserves.

2011 SECOND QUARTER REPORT 53

A Black-Scholes option-pricing model was used to determine the fair value of options granted in 2011 under the Option Plan with the following fair value per option and weighted average assumptions:

		Six months ended June 30
		2011 (1)				2010 (2)
Average fair value of options granted (per share)		$	6.71			$	3.54
Expected life of options (years)			4.0				3.0
Expected volatility (average)			28.2	%			32.3	%
Risk-free rate of return (average)			2.3	%			2.5	%
Dividend yield			4.4	%			8.6	%

(1) In 2011, assumptions relate to the Option Plan.

(2) In 2010, assumptions relate to the TURIP. Trust unit rights fair value was determined using a Binomial Lattice option-pricing model.

Employee retirement savings plan

Penn West has an employee retirement savings plan (the “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 common shares or are placed in low-risk investments. Shares are purchased in the open market at prevailing market prices.

Deferred share unit plan (“DSU plan”)

The DSU plan became effective January 1, 2011, allowing Penn West to grant DSU’s in lieu of cash compensation to non-employee directors providing a right to receive, upon retirement, a cash payment based on the volume-weighted-average trading price of the common shares on the TSX for the five trading days immediately prior to the day of payment. Management directors are not eligible to participate in the DSU Plan.

14. Capital management

Penn West manages its capital to provide a flexible structure to support capital programs, dividend policies, production maintenance and other operational strategies. Maintaining a strong financial position enables the capture of business opportunities and supports Penn West’s business strategy of providing shareholder return through a combination of organic growth and yield.

Shareholders’ equity, long-term debt and convertible debentures are defined as capital by Penn West. Shareholders’ equity includes shareholders’ capital, other reserves and retained earnings (deficit). Long-term debt includes bank loans and senior unsecured notes.

		June 30, 2011				December 31, 2010
Components of capital
Shareholders’ equity		$	9,166			$	8,560
Long-term debt			2,815				2,496
Convertible debentures			224				255
Total		$	12,205			$	11,311

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, current market conditions, trailing and forecast debt to capitalization ratios and debt to funds flow and other economic risk factors. Currently dividends are paid quarterly at the discretion of Penn West’s Board of Directors.

2011 SECOND QUARTER REPORT 54

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 EBITDA and senior debt and total debt to capitalization. As at June 30, 2011, the Company was in compliance with all of its financial covenants.

15. Commitments and contingencies

Penn West is involved in various litigation and claims in the normal course of business. Penn West records provisions for claims as required.

16. Related-party transactions

During the first six months of 2011, Penn West incurred $1 million (2010 - $2 million) of legal fees from a law firm of which a partner is also a director of Penn West.

2011 SECOND QUARTER REPORT 55

17. Transition to IFRS

Penn West’s accounting policies under IFRS differ from those followed under previous GAAP as described in Note 3. These accounting policies have been applied for the six months ended June 30, 2011 as well as the comparative information on the January 1, 2010 (“transition date”) opening balance sheet, the comparative information for the three months and six months ended June 30, 2010 and the comparative information for the year-ended December 31, 2010.

The adjustments arising from the application of IFRS to balance sheet account balances on the transition date and on transactions prior to that date were recognized as an adjustment to opening retained earnings or, as appropriate, another category of equity or an adjustment to another balance sheet account.

On the transition date, Penn West elected to apply IFRS 1, the application of which included the following:

i) Business combinations

For business combinations completed before the January 1, 2010 date of transition, Penn West elected not to adopt IFRS 3 “Business Combinations” retrospectively. Accordingly, the fair value of assets and liabilities on business combinations prior to the transition date remain at the amounts determined under previous GAAP.

Goodwill was required to be valued at its carrying amount on the transition date and subject to a goodwill impairment test on that date, regardless of whether there was an indication of impairment. There were no impairments calculated from the impairment test on the transition date.

ii) PP&E

Penn West recognized PP&E in the opening IFRS balance sheet applying the amendment to IFRS 1 “Additional exemptions for first-time adopters”. The recorded amount of oil and gas assets, at the date of transition, was deemed to be equal to the historical cost of oil and gas assets under previous GAAP, except for Corporate Assets and E&E assets.

The cost of oil and gas assets was allocated between CGU’s based on total proved plus probable reserve values and the fair value of certain assets on January 1, 2010. Additionally, oil and gas assets were tested for impairment on the transition date, a requirement when applying the “Deemed Cost” exemption under IFRS 1, and no impairments were indicated. The cost of corporate assets was determined in a similar manner as oil and gas assets.

iii) Share based payment transactions

Penn West granted equity instruments prior to the transition date that fall within the scope of IFRS 2 “Share based payments”. Under IFRS 1, Penn West had the option to apply IFRS 2 to only non-vested options on the transition date. Penn West chose not to use this exemption.

iv) Decommissioning liabilities

Application of the “Deemed Cost” exemption on January 1, 2010, required that changes to decommissioning liabilities on the transition date be recorded to retained earnings. On January 1, 2010, Penn West recorded certain reclamation liabilities related primarily to pipeline ownership, as they meet the definition of a constructive obligation under IAS 37 “Provisions, Contingent Liabilities and Contingent Assets”. Under previous GAAP, constructive obligations were not recognized.

2011 SECOND QUARTER REPORT 56

Reconciliation of Equity reported under previous GAAP

to Equity reported under IFRS on the Transition Date (January 1, 2010)

(CAD millions, unaudited)		Notes				Previous GAAP				Transition  Adjustments				IFRS
Assets
Current
Accounts receivable						$	371			$	-			$	371
Other							101				-				101
Deferred tax asset			A				37				(37	)			-
Risk management			B				-				29				29
							509				(8	)			501
Non-current
Exploration and evaluation assets			C				-				132				132
Property, plant and equipment			C, D				11,347				(173	)			11,174
Goodwill							2,020				-				2,020
Risk management			B				-				10				10
							13,367				(31	)			13,336
Total assets						$	13,876			$	(39	)		$	13,837
Liabilities and Unitholders’ Equity
Current liabilities
Accounts payable and accrued liabilities			E			$	515			$	53			$	568
Distribution payable							63				-				63
Convertible debentures							18				-				18
Risk management			B				130				29				159
							726				82				808
Non-current liabilities
Long-term debt							3,219				-				3,219
Convertible debentures							255				-				255
Decommissioning liability			F				568				(6	)			562
Risk management			B				21				10				31
Deferred tax liability			A				1,169				361				1,530
Other non-current liabilities			E				-				15				15
							5,958				462				6,420
Unitholders’ equity
Unitholders’ capital			E				8,451				-				8,451
Contributed surplus			E				123				(123	)			-
Deficit		A, C, D, E, F					(656	)			(378	)			(1,034	)
							7,918				(501	)			7,417
Total liabilities and unitholders’ equity						$	13,876			$	(39	)		$	13,837

2011 SECOND QUARTER REPORT 57

Reconciliation of Equity reported under previous GAAP

to Equity reported under IFRS as at June 30, 2010 and December 31, 2010

						June 30, 2010												December 31, 2010
(CAD millions, unaudited)		Notes				Previous GAAP				Effect of Transition				IFRS				Previous GAAP				Effect of Transition				IFRS
Assets
Current assets
Accounts receivable						$	344			$	-			$	344			$	386			$	-			$	386
Other							104				-				104				87				-				87
Deferred income tax			A				-				-				-				17				(17	)			-
Risk management			B				-				58				58				-				23				23
							448				58				506				490				6				496
Non-current assets
Deferred funding asset							505				-				505				678				-				678
Exploration and evaluation assets			C				-				116				116				-				128				128
Property, plant and equipment			C, D, F				10,170				600				10,770				10,180				1,038				11,218
Goodwill							2,020				-				2,020				2,020				-				2,020
Risk management			B				7				47				54				-				3				3
							12,702				763				13,465				12,878				1,169				14,047
Total assets						$	13,150			$	821			$	13,971			$	13,368			$	1,175			$	14,543
Liabilities and Unitholders’ Equity
Current liabilities
Accounts payable and accrued liabilities			E			$	483			$	93			$	576			$	743			$	167			$	910
Distributions payable							67				-				67				41				-				41
Convertible debentures			G				44				-				44				-				255				255
Risk management			B				-				61				61				62				23				85
							594				154				748				846				445				1,291
Non-current liabilities
Long-term debt							2,473				-				2,473				2,496				-				2,496
Convertible debentures			G				229				-				229				255				(255	)			-
Decommissioning liability			F				582				1				583				653				(5	)			648
Risk management			B				-				44				44				64				3				67
Deferred tax liability			A				917				548				1,465				855				597				1,452
Other non-current liabilities			E				-				17				17				-				29				29
							4,795				764				5,559				5,169				814				5,983
Unitholders’ equity
Unitholders’ capital			H				8,984				5				8,989				9,177				(7	)			9,170
Other reserves			E				141				(141	)			-				138				(138	)			-
Retained earnings (Deficit)			H				(770	)			193				(577	)			(1,116	)			506				(610	)
							8,355				57				8,412				8,199				361				8,560
Total liabilities and unitholders’ equity						$	13,150			$	821			$	13,971			$	13,368			$	1,175			$	14,543

2011 SECOND QUARTER REPORT 58

Reconciliation of Net and Comprehensive Income reported under previous GAAP

to IFRS for the six months ended June 30, 2010 and the year ended December 31, 2010

						Six months ended												Year ended
(CAD millions, except per share amounts, unaudited)						June 30, 2010												December 31, 2010
		Notes				Previous GAAP				Effect of Transition				IFRS				Previous GAAP				Effect of Transition				IFRS
Oil and natural gas sales						$	1,530			$	-			$	1,530			$	3,054			$	-			$	3,054
Royalties							(276	)			-				(276	)			(545	)			-				(545	)
							1,254				-				1,254				2,509				-				2,509
Risk management gain (loss)
Realized							(6	)			-				(6	)			(20	)			-				(20	)
Unrealized							155				-				155				23				-				23
							1,403				-				1,403				2,512				-				2,512
Expenses
Operating			E				470				(8	)			462				959				(15	)			944
Transportation							17				-				17				33				-				33
General and administrative			E				87				(19	)			68				181				(40	)			141
Unit-based compensation			E				-				54				54				-				159				159
Depletion, depreciation and accretion			D				669				(669	)			-				1,338				(1,338	)			-
Depletion and depreciation			D				-				612				612				-				1,169				1,169
Gain on dispositions			D				-				(714	)			(714	)			-				(1,082	)			(1,082	)
Exploration and evaluation expense			C				-				1				1				-				1				1
Unrealized risk management gain							(3	)			-				(3	)			(2	)			-				(2	)
Unrealized foreign exchange (gain) loss							19				-				19				(82	)			-				(82	)
Transaction costs							-				-				-				4				-				4
Financing							85				-				85				174				-				174
Accretion			D, F				-				20				20				-				44				44
							1,344				(723	)			621				2,605				(1,102	)			1,503
Income (loss) before taxes						$	59			$	723			$	782			$	(93	)		$	1,102			$	1,009
Deferred tax expense (recovery)			A				(213	)			152				(61	)			(319	)			218				(101	)
Net and comprehensive income						$	272			$	571			$	843			$	226			$	884			$	1,110
Net income per unit
Basic						$	0.63			$	1.34			$	1.97			$	0.51			$	2.00			$	2.51
Diluted			H			$	0.63			$	1.31			$	1.94			$	0.50			$	1.98			$	2.48

2011 SECOND QUARTER REPORT 59

Reconciliation of Net and Comprehensive Income reported under previous GAAP

to IFRS for the three months ended June 30, 2010

						Three months ended
(CAD millions, except per share amounts, unaudited)						June 30, 2010
		Notes				Previous GAAP				Effect of  Transition				IFRS
Oil and natural gas sales						$	715			$	-			$	715
Royalties							(128	)			-				(128	)
							587				-				587
Risk management gain
Realized							3				-				3
Unrealized							119				-				119
							709				-				709
Expenses
Operating			E				236				(5	)			231
Transportation							8				-				8
General and administrative			E				43				(9	)			34
Unit-based compensation			E				-				(4	)			(4	)
Depletion, depreciation and accretion			D				327				(327	)			-
Depletion and depreciation			D				-				350				350
Gain on dispositions			D				-				(737	)			(737	)
Exploration and evaluation expense			C				-				1				1
Unrealized risk management gain							(28	)			-				(28	)
Unrealized foreign exchange loss							74				-				74
Financing							45				-				45
Accretion			D, F				-				10				10
							705				(721	)			(16	)
Income before taxes						$	4			$	721			$	725
Deferred tax recovery			A				(191	)			171				(20	)
Net and comprehensive income						$	195			$	550			$	745
Net income per unit
Basic						$	0.45			$	1.27			$	1.72
Diluted			H			$	0.44			$	1.25			$	1.69

2011 SECOND QUARTER REPORT 60

Notes to reconciliation

A. Deferred income taxes

i) Classification

Under previous GAAP, Penn West was required to disclose the current and long-term components of deferred income taxes separately. Under IFRS, deferred income taxes are disclosed as non-current.

ii) Measurement

Under previous GAAP, income tax assets and liabilities of trust entities were measured at the enacted Specified Investment Flow-Through tax rate of approximately 25 percent. Under IFRS, Penn West was required to measure trust tax assets and liabilities at a rate of approximately 39 percent, representing the tax rate applicable to undistributed profits of a trust entity in the Province of Alberta. On the transition date, a charge to retained earnings of approximately $410 million was recorded. Penn West also recorded approximately $12 million of deferred tax recoveries related to PP&E adjustments on the transition date.

During 2010, the adjustment of the deferred tax liability for the recognition of gains on asset dispositions under IFRS and the declaration of distributions resulted in a $101 million deferred tax recovery through income.

B. Risk management classification

Under previous GAAP, Penn West grouped current and non-current risk management balances related to financial instruments. Under IFRS, Penn West reclassified risk management between current and non-current.

C. Exploration and evaluation assets

Under previous GAAP, all oil and gas assets, whether development or exploratory in nature, were included in PP&E. Under IFRS, significant E&E costs are initially recognized separately from PP&E as E&E assets. On the transition date, Penn West reclassified $132 million from PP&E to E&E assets.

Also, on the transition date, Penn West identified approximately $44 million of lands for which the Company has no current plans to develop or explore. This amount was charged directly to retained earnings as required under IFRS.

Penn West spent $18 million on E&E assets, disposed of $33 million of E&E assets and had a $1 million non-cash expense related to land expiries during the first six months of 2010. During 2010, Penn West spent $58 million on E&E assets, sold $61 million of E&E in acquisition and divestiture activities and recorded a $1 million E&E expense related to land expiries.

D. Property, plant and equipment

i) Componentization - Plant Turnaround Costs

Under previous GAAP, Penn West did not capitalize costs associated with turnarounds. Under IFRS, costs associated with major inspections of property, plant or equipment are capitalized. On the transition date, Penn West capitalized $9 million of turnaround costs to PP&E and $6 million to accumulated depletion as an opening retained earnings adjustment. Significant turnaround costs will be treated as a separate component under IFRS and depreciated on a straight-line basis. There have been no significant turnarounds requiring capitalization subsequent to the transition date.

2011 SECOND QUARTER REPORT 61

ii) Depletion, depreciation and accretion

During 2010, Penn West recorded $1,169 million of depletion and depreciation under IFRS compared to $1,293 million under previous GAAP.

Under previous GAAP, PP&E was generally depleted based on aggregations at the country level using the full cost method of accounting for oil and natural gas activities and the unit of production method based on proved reserves. Depletion of resource properties and facilities will generally continue to be calculated using the unit-of-production method under IFRS; however, Penn West has elected to deplete resource properties using proved plus probable reserves. Depreciation of other assets is calculated on a straight-line basis over their estimated useful lives.

Under previous GAAP, depletion, depreciation and accretion was disclosed in aggregate in the consolidated statement of income. Under IFRS, accretion has been disclosed on a separate line.

iii) Impairment

Under IFRS, impairment testing is performed at a lower level of asset aggregation than under previous GAAP. During the second quarter of 2010, Penn West recorded an $80 million pre-tax impairment related to certain properties in Central Alberta to reflect declining economic factors which resulted in lower estimated future cash flows. This was included in depletion and depreciation.

iv) Gains and losses on dispositions

Under previous GAAP, proceeds on dispositions were applied to PP&E unless the disposition changed the rate of depletion and depreciation by more than 20 percent in which case gains and losses were recognized. Under IFRS, gains and losses are calculated on significant dispositions and are recognized in income. During 2010, Penn West completed a number of property dispositions of which the two most significant dispositions were to form the Peace River Oil Partnership and the Cordova Joint Venture. These dispositions resulted in 2010 pre-tax gains of $749 million and $368 million, respectively.

v) PP&E continuity

Changes in PP&E from previous GAAP as at January 1, 2010, for the six months ending June 30, 2010 and the year ending December 31, 2010 were as follows:

		January 1, 2010				June 30, 2010				December 31, 2010
PP&E balance, previous GAAP		$	11,347			$	10,170			$	10,180
Reverse previous GAAP amounts:
Depletion and depreciation			-				649				1,293
ARO revisions			-				(21	)			(89	)
Record IFRS adjustments:
Set-up of E&E assets			(176	)			(176	)			(176	)
Set-up of turnaround component			3				3				3
E&E previously recorded as PP&E			-				(18	)			(58	)
Depletion and depreciation			-				(612	)			(1,169	)
Gain on dispositions			-				747				1,143
ARO revisions			-				28				91
PP&E balance, IFRS		$	11,174			$	10,770			$	11,218

2011 SECOND QUARTER REPORT 62

E. Unit-based compensation

Under previous GAAP, the fair values of trust unit rights under the TURIP were amortized to income on a straight-line basis and classified as equity instruments. Under IFRS in 2010, trust unit rights were classified as a liability and were expensed as the service of the employee was provided.

On the transition date, Penn West reversed contributed surplus (other reserves) of $123 million to remove the amount recorded as equity under previous GAAP and recorded a unit rights liability based on updated fair values per trust unit right and the service performed to that date. This resulted in the recognition of a $68 million unit rights liability on the transition date of which $53 million was recorded in accounts payable and accrued liabilities and $15 million was recorded in other non-current liabilities.

Under previous GAAP, Penn West included a portion of unit-based compensation in operating expense and the balance in general and administrative expense. Under IFRS, unit-based compensation is disclosed on a separate line on the consolidated statement of income. Penn West reclassified $4 million from operating costs and $4 million from general and administrative expenditures into unit-based compensation expense for 2010. Additionally Penn West reclassified $4 million from accounts payable and accrued liabilities into other non-current liabilities as this amount is non-current at December 31, 2010.

Under IFRS, as trust unit rights were treated as a liability, Penn West was required to revalue unit-based compensation at each reporting date. In the first six months of 2010, an additional expense of $51 million was recorded resulting in a total unit rights liability at June 30, 2010 of $110 million of which a $94 million liability was included in accounts payable and $16 million included in other non-current liabilities. In 2010, an expense of $151 million was incurred resulting in a unit rights liability of $196 million at December 31, 2010 of which $171 million was included in accounts payable and accrued liabilities and $25 million was included in other non-current liabilities.

Due to the revaluation of trust unit rights at each reporting date under IFRS, the amount recorded as an increase to unitholders’ equity on exercises changed from previous GAAP. Upon the exercise of rights, for the first six months of 2010, Penn West recorded $9 million in unitholders’ equity compared to $6 million under previous GAAP and for 2010 recorded $23 million in unitholders’ equity compared to $32 million under previous GAAP.

F. Decommissioning liability

Under previous GAAP, a decommissioning liability existed if there was a legal requirement to abandon and reclaim an asset. Under IFRS, in addition to the legal requirement, constructive obligations to abandon and reclaim an asset are included in the provision. Also, under IFRS, the decommissioning liability is calculated at a more detailed level than under previous GAAP, which results in minor differences in the present value calculation. On the transition date, Penn West recorded a reduction in the decommissioning liability of approximately $6 million with a corresponding offset to opening retained earnings.

During 2010, Penn West had $91 million of additions and changes in estimates which increased the liability and accretion charges totalling $44 million under IFRS. These amounts were $89 million and $45 million, respectively, under previous GAAP.

G. Convertible debentures

Under previous GAAP, convertible debentures that expire within a year were disclosed as a long-term liability as Penn West, at its discretion, has the option of settling the debentures in cash or equity. Under IFRS, regardless of the method of settlement, instruments expiring within one year are classified as current liabilities.

2011 SECOND QUARTER REPORT 63

H. Unitholders’ Equity

Changes to deficit from previous GAAP were as follows:

		January 1, 2010				June 30, 2010				December 31, 2010
Deficit, previous GAAP		$	(656	)		$	(770	)		$	(1,116	)
Reverse previous GAAP amounts:
Depletion, depreciation and accretion			-				669				1,338
Unit-based compensation			-				27				47
Future income tax			-				(213	)			(319	)
Record IFRS adjustments:
Set-up of turnaround component			3				3				3
Set-up of decommissioning liability			6				6				6
Set-up of unit rights liability			55				55				55
Deferred tax			(398	)			(337	)			(297	)
E&E expense			(44	)			(45	)			(45	)
Depletion and depreciation			-				(612	)			(1,169	)
Accretion			-				(20	)			(44	)
Unit-based compensation expense			-				(54	)			(151	)
Gain on dispositions			-				714				1,082
Deficit, IFRS		$	(1,034	)		$	(577	)		$	(610	)

Changes to unitholders’ capital from previous GAAP at the comparative dates were as follows:

		January 1, 2010				June 30, 2010				December 31, 2010
Unitholders’ capital, previous GAAP		$	8,451			$	8,984			$	9,177
Reverse previous GAAP amounts:
Exercises of TURIP			-				(6	)			(32	)
Tax-effect on trust unit issue costs			-				(2	)			(2	)
Record IFRS adjustments:
Exercises of TURIP			-				9				23
Tax-effect on trust unit issue costs			-				4				4
Unitholders’ capital, IFRS		$	8,451			$	8,989			$	9,170

Contributed surplus (other reserves) of $123 million was eliminated and charged through retained earnings on January 1, 2010 to record trust unit rights as a liability under IFRS.

I. Earnings per unit

Under previous GAAP in 2010, the number of units used in the year-to-date earnings per unit calculation was based on the average of the number of units outstanding in each of the interim periods. Under IFRS, the year-to-date calculation is completed independent of the quarterly calculations.

For the year-ended 2010, the diluted number of units outstanding under IFRS was 451.6 million compared to 447.6 million under previous GAAP.

2011 SECOND QUARTER REPORT 64