Exhibit 99.2

EX-99.2 3 d394912dex992.htm EXHIBIT 99.2 Exhibit 99.2

Exhibit 99.2

MANAGEMENT’S DISCUSSION AND ANALYSIS

For the six months ended June 30, 2012

This management’s discussion and analysis (“MD&A”) of financial conditions and results of operations should be read in conjunction with the unaudited interim condensed consolidated financial statements of Penn West Petroleum Ltd. (“Penn West”, “We”, “Us”, “Our”, the “Company”) for the three and the six months ended June 30, 2012 and the audited consolidated financial statements and MD&A for the year ended December 31, 2011. The date of this MD&A is August 9, 2012. All dollar amounts contained in this MD&A are expressed in millions of Canadian dollars unless noted otherwise.

Please refer to our cautionary notes relating to forward-looking statements at the end of this 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. Given that the value ratio based on the current price of crude oil as compared to natural gas is significantly different from the energy equivalency conversion ratio of 6:1, utilizing a conversion on a 6:1 basis is misleading as an indication of value.

Certain financial measures including funds flow, funds flow per share-basic, funds flow per share-diluted and netback included in this MD&A do not have a standardized meaning prescribed by International Financial Reporting Standards (“IFRS”) and therefore are considered non-GAAP measures; 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 the per unit of production amount of revenue less royalties, operating costs, transportation and realized risk management and is used by us in capital allocation decisions and to economically rank projects.

Calculation of Funds Flow


	Three months ended June 30					Six months ended June 30
(millions, except per share amounts)	2012			2011		2012		2011
Cash flow from operating activities	$	280		$	255	$	514	$	495
Increase (decrease) in non-cash working capital		(23	)		133		56		229
Decommissioning expenditures		15			8		39		28

Funds flow	$	272		$	396	$	609	$	752

Basic per share	$	0.57		$	0.85	$	1.29	$	1.62
Diluted per share	$	0.57		$	0.85	$	1.29	$	1.62


PENN WEST EXPLORATION SECOND QUARTER 2012		MANAGEMENT’S DISCUSSION & ANALYSIS		1

Second Quarter Highlights

•

Funds flow for the second quarter of 2012 was $272 million compared to $396 million in the comparative period of 2011. Funds flow decreased from the comparative period primarily due to lower commodity price realizations.

•

Net income was $235 million in the second quarter of 2012 compared to $271 million in 2011. Net income in 2012 was affected by lower revenues from weaker commodity prices, however, this was offset by unrealized risk management gains from our hedging program.

•

Production in the second quarter of 2012 averaged 163,181 boe per day compared to 156,107 boe per day in the second quarter of 2011. During the second quarter of 2012 we completed a number of significant planned turnarounds and maintenance activities which resulted in peak volumes of approximately 10,000 boe per day being off-line for portions of the quarter. In the comparative period in 2011, production was impacted by temporary interruptions due to wild fires in Northern Alberta and flooding throughout Southern Saskatchewan and Manitoba.

•

Capital expenditures totalled $310 million during the quarter, including proceeds from net dispositions of $19 million. Second quarter activities were primarily focused on completions, tie-ins and facilities construction.

•

Netbacks were $23.84 per boe compared to $32.60 per boe in the second quarter of 2011.

2012 First Half Highlights

•

Funds flow was $609 million for the first six months of 2012 compared to $752 million in the comparative period of 2011. Funds flow decreased from the comparative period primarily due to lower commodity prices and wider Canadian crude oil differentials.

•

Net income was $294 million in the first half of 2012 compared to $562 million in 2011. In 2011 we recorded a one-time $304 million deferred income tax recovery related to our conversion to an E&P company from an income trust.

•

Production in the first half of 2012 has averaged 165,301 boe per day compared to 161,093 boe per day for the first six months of 2011.

•

Capital expenditures totalled $648 million in the first half of 2012 net of proceeds from net dispositions of $341 million. In the first six months of 2012, we have drilled 208 net wells.

•

Netbacks were $25.61 per boe for the first six months of 2012 compared to $31.03 per boe in 2011.

Quarterly Financial Summary

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


Three months ended	June 30 2012		Mar. 31 2012		Dec. 31 2011			Sep. 30 2011		June 30 2011		Mar. 31 2011		Dec. 31 2010			Sep 30 2010
Gross revenues ⁽¹⁾	$	774	$	870	$	979		$	861	$	920	$	844	$	782		$	728
Funds flow		272		337		437			348		396		356		305			267
Basic per share		0.57		0.71		0.93			0.74		0.85		0.77		0.67			0.59
Diluted per share		0.57		0.71		0.93			0.74		0.85		0.77		0.66			0.58
Net income (loss)		235		59		(62	)		138		271		291		(37	)		304
Basic per share		0.50		0.12		(0.13	)		0.29		0.58		0.63		(0.08	)		0.67
Diluted per share		0.50		0.12		(0.13	)		0.29		0.58		0.63		(0.08	)		0.66
Dividends declared		128		128		127			127		127		125		123			177
Per share	$	0.27	$	0.27	$	0.27		$	0.27	$	0.27	$	0.27	$	0.27		$	0.39
Production
Liquids (bbls/d) ⁽²⁾		104,758		107,199		108,071			101,392		98,998		104,349		105,296			98,380
Natural gas (mmcf/d)		351		361		364			360		343		371		365			394

Total (boe/d)		163,181		167,420		168,801			161,323		156,107		166,135		166,148			164,087

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

(2)	Includes crude oil and natural gas liquids.


PENN WEST EXPLORATION SECOND QUARTER 2012		MANAGEMENT’S DISCUSSION & ANALYSIS		2

Business Strategy

Since 2009, our capital program has focused on light-oil plays and the use of horizontal multi-stage fracture techniques which have been key drivers in the growth of Penn West’s oil production. Currently, horizontal multi-stage oil wells comprise approximately five percent of our total well count providing approximately 20 percent of production, and more than one-third of our funds flow. With key technical skills regarding the application of horizontal multi-stage technologies and a drilling inventory of over 10,000 locations largely weighted to oil, our future development potential is substantial. In addition to our light-oil growth, our dividend offers shareholders a return during times of market volatility. We will continue to work through our light-oil development plans with continued attention on cost optimization in the second half of 2012.

Business Environment

Ongoing concerns regarding the financial stability of certain European Union countries and the potential impact on global economic growth continue to contribute to volatile commodity and equity markets. While the European Union has progressed toward implementing funding assistance mechanisms and austerity measures, issues such as high sovereign borrowing costs persist, causing cautious global growth outlooks. North American growth remains generally on forecast offset by some concerns related to the rate of job creation in the US. Recent fiscal easing in China is believed to enable the region to continue its growth albeit at rates lower than forecasts made in recent years. World oil demand forecasts remain consistent at just short of 90 million barrels per day with its growth rate correlated to global economic growth.

Volatility in Canadian crude oil realizations compared to benchmark prices such as Brent and WTI continues. WTI continues to trade at a discount to Brent due to transportation bottlenecks in Cushing, Oklahoma. Canadian crudes also continue to trade at a differential to WTI, with Edmonton light sweet trading at a discount of approximately $4 per barrel to WTI in June 2012 and approximately $10 per barrel to date in 2012.

Global crude oil inventories started the second quarter of 2012 at levels below the five-year average; however, inventories grew to above average levels by the end of the quarter. Non-OPEC production continues to decline, with North America being the exception. North American production and inventory levels increased during the quarter due to higher drilling activity levels in tight-oil plays such as the Bakken and Eagle Ford plays in the U.S. and the Cardium, Carbonates and oil sands plays in Western Canada. North American production increases are outpacing infrastructure development creating bottlenecks in certain US consuming regions such as Cushing. Producers are increasing the use of alternative transportation such as rail and trucking to mitigate some of the effects of these bottlenecks. Saudi Arabia increased production by roughly 1.0 million barrels per day during the quarter in an effort to ease supply concerns from the oil embargo imposed on Iran by western nations.

After an extremely mild winter, North American natural gas inventories entered the second quarter at record highs of approximately 2.5 trillion cubic feet or close to 60 percent above the five-year average. Natural gas inventory levels declined during the second quarter however they are still approximately 20 percent above the five-year average. The drawdown was in part due to unusually hot weather over much of the U.S. that increased natural gas demand for power generation. As a result, gas prices have come off their recent lows. Many forecasters believe gas consumption for power generation will continue at relatively high levels and possibly increase in the future. On the supply side, the number of drilling rigs targeting gas continues to decrease. Currently there are approximately 500 rigs drilling for natural gas in the lower 48 states in the U.S. compared to 950 at this time last year. The decline in rig activity has been offset by associated gas from continued high drilling activity levels for oil and liquids-rich gas plays which has kept gas production relatively flat. As many gas producers continue to focus on gas prospects with high liquids content, propane and ethane prices have declined over the first half of this year eliminating some of the economic uplift that liquids-rich gas plays have over dry gas. The level of active rigs targeting dry natural gas is expected to remain at low levels over the coming months.


PENN WEST EXPLORATION SECOND QUARTER 2012		MANAGEMENT’S DISCUSSION & ANALYSIS		3

Crude Oil

In the second quarter of 2012, WTI crude oil prices averaged US$93.54 per barrel compared to US$102.95 per barrel in the first quarter of 2012 and US$102.55 per barrel for the second quarter of 2011. WTI at Cushing, Oklahoma continues to trade at a discount to ocean access crudes of a similar quality, however, the start-up of the first phase to reverse the Seaway Pipeline from Cushing to Houston has helped narrow that discount. The discount is expected to narrow further when the second phase of the Seaway Pipeline reversal comes on at the end of the first quarter of 2013. There are a number of other pipeline projects in various stages of permitting or construction that are expected to help address transportation bottlenecks, improve operational flexibility and reduce future pricing discounts.

Our average liquids price for the second quarter of 2012, before the impact of the realized portion of risk management, was $72.92 per barrel compared to $82.21 per barrel in the first quarter of 2012 and $90.29 per barrel in the second quarter of 2011. The lower price realized in the second quarter compared to prior quarters, is primarily due to the decline in WTI. Differentials to WTI for Canadian crude streams, although there was some volatility month-to-month, remained essentially unchanged from the first quarter. Currently, we have 60,000 barrels per day of our budgeted 2012 crude oil production hedged between US$85.53 and US$100.20 per barrel and 44,000 barrels per day of our forecast 2013 production hedged between US$91.70 and US$104.99 per barrel.

Natural Gas

In the second quarter of 2012, the AECO Monthly Index averaged $1.83 per mcf compared to $2.52 per mcf in the first quarter of 2012 and $3.74 per mcf for the second quarter of 2011. North American inventory levels continue to be oversupplied as a decline in natural gas drilling activity has been offset by an increase in oil drilling activity and associated gas production related to this activity. Subsequent to June 30, 2012, AECO spot prices have traded as high as $2.50 per mcf as hotter than normal weather has increased the demand for natural gas this summer. Current AECO spot prices are at their highest level since early January 2012.

Our corporate average natural gas price for the second quarter of 2012, before the impact of the realized portion of risk management, was $1.98 per mcf compared to $2.29 per mcf in the first quarter of 2012 and $4.06 per mcf in the second quarter of 2011. We currently have 50,000 mcf per day of natural gas production hedged for 2012 at an average price of $4.30 per mcf and 52,000 mcf per day of natural gas hedged for 2013 at an average price of $3.25 per mcf.

RESULTS OF OPERATIONS

Production


	Three months ended June 30							Six months ended June 30
Daily production	2012		2011		% change			2012		2011		% change
Light oil and NGL (bbls/d)		87,536		81,329		8			88,282		83,478		6
Heavy oil (bbls/d)		17,222		17,669		(3	)		17,696		18,181		(3	)
Natural gas (mmcf/d)		351		343		2			356		357		—

Total production (boe/d)		163,181		156,107		5			165,301		161,093		3

In the second quarter of 2012, we completed a significant turnaround and maintenance program which resulted in peak volumes of approximately 10,000 boe per day being off-line for portions of the quarter. In early 2012, we also completed net asset dispositions with total average production of 4,500 boe per day. In the comparative period in 2011, production was impacted by temporary interruptions due to wild fires in Northern Alberta and flooding throughout Southern Saskatchewan and Manitoba.

When economic to do so, we strive to maintain an appropriate mix of liquids and natural gas production in order to reduce exposure to price volatility that can affect a single commodity. Given the weak outlook for natural gas prices in the medium term and our significant inventory of light-oil locations, we plan to continue allocating substantially all of our capital investments to oil weighted projects.


PENN WEST EXPLORATION SECOND QUARTER 2012		MANAGEMENT’S DISCUSSION & ANALYSIS		4

Average Sales Prices


	Three months ended June 30									Six months ended June 30
	2012			2011			% change			2012			2011			% change
Light oil and liquids (per bbl)	$	75.20		$	93.99			(20	)	$	79.72		$	86.89			(8	)
Risk management loss (per bbl)⁽¹⁾		(0.87	)		(4.42	)		(80	)		(2.57	)		(2.94	)		(13	)

Light oil and liquids net (per bbl)		74.33			89.57			(17	)		77.15			83.95			(8	)


Heavy oil (per bbl)		61.36			73.23			(16	)		67.17			67.91			(1	)


Natural gas (per mcf)		1.98			4.06			(51	)		2.14			3.92			(45	)
Risk management gain (per mcf)⁽¹⁾		0.35			—			100			0.41			—			100

Natural gas net (per mcf)		2.33			4.06			(43	)		2.55			3.92			(35	)


Weighted average (per boe)		51.06			66.18			(23	)		54.37			61.38			(11	)
Risk management gain (loss) (per boe)⁽¹⁾		0.29			(2.30	)		100			(0.49	)		(1.53	)		(68	)

Weighted average net (per boe)	$	51.35		$	63.88			(20	)	$	53.88		$	59.85			(10	)

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


PENN WEST EXPLORATION SECOND QUARTER 2012		MANAGEMENT’S DISCUSSION & ANALYSIS		5

Netbacks


	Three months ended June 30									Six months ended June 30
	2012			2011			% change			2012			2011			% change
Light oil and NGL ⁽¹⁾
Production (bbls/day)		87,536			81,329			8			88,282			83,478			6
Operating netback ($/bbl):
Sales price	$	75.20		$	93.99			(20	)	$	79.72		$	86.89			(8	)
Risk management loss⁽²⁾		(0.87	)		(4.42	)		(80	)		(2.57	)		(2.94	)		(13	)
Royalties		(15.94	)		(18.42	)		(13	)		(16.46	)		(16.93	)		(3	)
Operating costs		(19.85	)		(23.34	)		(15	)		(20.42	)		(21.12	)		(3	)

Netback	$	38.54		$	47.81			(19	)	$	40.27		$	45.90			(12	)

Conventional heavy oil
Production (bbls/day)		17,222			17,669			(3	)		17,696			18,181			(3	)
Operating netback ($/bbl):
Sales price	$	61.36		$	73.23			(16	)	$	67.17		$	67.91			(1	)
Royalties		(8.51	)		(10.77	)		(21	)		(9.32	)		(9.77	)		(5	)
Operating costs		(19.43	)		(17.62	)		10			(19.43	)		(17.64	)		10
Transportation		(0.12	)		(0.09	)		33			(0.10	)		(0.09	)		11

Netback	$	33.30		$	44.75			(26	)	$	38.32		$	40.41			(5	)

Total liquids
Production (bbls/day)		104,758			98,998			6			105,978			101,659			4
Operating netback ($/bbl):
Sales price	$	72.92		$	90.29			(19	)	$	77.62		$	83.50			(7	)
Risk management loss⁽²⁾		(0.73	)		(3.63	)		(80	)		(2.14	)		(2.42	)		(12	)
Royalties		(14.72	)		(17.05	)		(14	)		(15.27	)		(15.65	)		(2	)
Operating costs		(19.78	)		(22.32	)		(11	)		(20.25	)		(20.50	)		(1	)
Transportation		(0.02	)		(0.02	)		—			(0.02	)		(0.02	)		—

Netback	$	37.67		$	47.27			(20	)	$	39.94		$	44.91			(11	)

Natural gas
Production (mmcf/day)		351			343			2			356			357			—
Operating netback ($/mcf):
Sales price	$	1.98		$	4.06			(51	)	$	2.14		$	3.92			(45	)
Risk management gain ⁽²⁾		0.35			—			100			0.41			—			100
Royalties		(0.18	)		(0.55	)		(67	)		(0.20	)		(0.51	)		(61	)
Operating costs		(2.08	)		(2.11	)		(1	)		(2.12	)		(1.98	)		7
Transportation		(0.23	)		(0.21	)		10			(0.23	)		(0.22	)		5

Netback	$	(0.16	)	$	1.19			(100	)	$	—		$	1.21			(100	)

Combined totals
Production (boe/day)		163,181			156,107			5			165,301			161,093			3
Operating netback ($/boe):
Sales price	$	51.06		$	66.18			(23	)	$	54.37		$	61.38			(11	)
Risk management gain (loss)⁽²⁾		0.29			(2.30	)		100			(0.49	)		(1.53	)		(68	)
Royalties		(9.84	)		(12.01	)		(18	)		(10.22	)		(11.00	)		(7	)
Operating costs		(17.16	)		(18.79	)		(9	)		(17.55	)		(17.32	)		1
Transportation		(0.51	)		(0.48	)		6			(0.50	)		(0.50	)		—

Netback	$	23.84		$	32.60			(27	)	$	25.61		$	31.03			(17	)

(1)	Excluded from the netback calculation is $23 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.


PENN WEST EXPLORATION SECOND QUARTER 2012		MANAGEMENT’S DISCUSSION & ANALYSIS		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)	2012		2011		% change			2012		2011		% change
Light oil and NGL	$	604	$	676		(11	)	$	1,263	$	1,288		(2	)
Heavy oil		96		117		(18	)		216		223		(3	)
Natural gas		74		127		(42	)		165		253		(35	)

Gross revenues ⁽¹⁾	$	774	$	920		(16	)	$	1,644	$	1,764		(7	)

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

In the second quarter of 2012, the weaker commodity price environment and volatility in oil differentials between Edmonton light sweet and WTI led to a decrease in revenues. For crude oil, the decline in revenues was partially offset by an increase in our light-oil production, due to strong development results at our light-oil plays. On an overall basis, net property dispositions in early 2012 led to a decrease in revenues, while in the comparative period wild fires and flooding affected production which resulted in lower revenues.

Reconciliation of Decrease in Production Revenues


(millions)
Gross revenues – January 1 – June 30, 2011	$	1,764
Increase in light oil and NGL production		82
Decrease in light oil and NGL prices (including realized risk management)		(107	)
Decrease in heavy oil production		(5	)
Decrease in heavy oil prices		(2	)
Decrease in natural gas prices		(88	)

Gross revenues – January 1 – June 30, 2012	$	1,644

Royalties


	Three months ended June 30									Six months ended June 30
	2012			2011			% change			2012			2011			% change
Royalties (millions)	$	147		$	171			(14	)	$	308		$	321			(4	)
Average royalty rate ⁽¹⁾		19	%		18	%		1			19	%		18	%		1
$/boe	$	9.84		$	12.01			(18	)	$	10.22		$	11.00			(7	)

(1)	Excludes effects of risk management activities.

Total royalties have decreased as a result of a weaker commodity price environment. Royalty rates have increased due to a higher percentage of our production weighted to liquids, a decline in natural gas prices and the impact of Canadian crude oil discounts to WTI.


PENN WEST EXPLORATION SECOND QUARTER 2012		MANAGEMENT’S DISCUSSION & ANALYSIS		7

Expenses


	Three months ended June 30								Six months ended June 30
(millions)	2012			2011		% change			2012			2011		% change
Operating	$	255		$	267		(4	)	$	528		$	505		5
Transportation		7			7		—			15			15		—
Financing		49			48		2			96			95		1
Share-based compensation	$	(30	)	$	4		(100	)	$	(13	)	$	82		(100	)

	Three months ended June 30								Six months ended June 30
(per boe)	2012			2011		% change			2012			2011		% change
Operating	$	17.16		$	18.79		(9	)	$	17.55		$	17.32		1
Transportation		0.51			0.48		6			0.50			0.50		—
Financing		3.32			3.36		(1	)		3.20			3.26		(2	)
Share-based compensation	$	(1.99	)	$	0.22		(100	)	$	(0.41	)	$	2.82		(100	)

Operating

On a quarterly basis, operating costs decreased from 2011 primarily due to the wild fires and flooding interruptions that occurred in the comparative period. The second quarter of 2012 included increased turnaround and maintenance activity in comparison to 2011.

Operating costs for the second quarter of 2012 include a realized loss on electricity contracts of $2 million (2011 – $2 million) and for the first six months of 2012 a realized loss of $1 million (2011 – $2 million gain). In the first half of 2012, the average Alberta pool price was $50.07 per MWh (2011 – $66.90 per MWh). We have contracts in place that fix the price on approximately 75 percent of our Alberta electricity consumption for 2012 at $53.65 per MWh and in 2013, 2014 and 2015 we have approximately 50 percent of our Alberta electricity consumption fixed at $55.20 per MWh, $58.50 per MWh and $58.32 per MWh, respectively.

Financing

In June 2012, we renewed our unsecured, revolving syndicated bank facility with an aggregate borrowing limit of $3.0 billion. The facility expires on June 30, 2016 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, 2012, approximately $1.3 billion was undrawn under this facility.


PENN WEST EXPLORATION SECOND QUARTER 2012		MANAGEMENT’S DISCUSSION & ANALYSIS		8

As at June 30, 2012, the Company had $2.0 billion (December 31, 2011 – $2.0 billion) of senior unsecured notes outstanding with a weighted average interest rate, including the effects of cross currency swaps, of approximately 6.1 percent (December 31, 2011 – 6.1 percent) and a weighted average remaining term of 6.0 years (December 31, 2011 – 6.5 years). At June 30, 2012, the Company had $650 million of interest rate swaps outstanding at a weighted average fixed rate of 2.65 percent and an expiry date of January 2014. These swaps fix a portion of the interest rates under our bank facility.

At June 30, 2012, we had the following senior unsecured notes outstanding:


	Issue date	Amount (millions)	Term	Average interest rate	Weighted average remaining term
2007 Notes	May 31, 2007	US$475	8 – 15 years	5.80%	5.0 years
2008 Notes	May 29, 2008	US$480, CAD$30	8 – 12 years	6.25%	5.5 years
UK Notes	July 31, 2008	£57	10 years	6.95% ⁽¹⁾	6.1 years
2009 Notes	May 5, 2009	US$154, £20, €10, CAD$5 ⁽²⁾	5 – 10 years	8.85% ⁽³⁾	4.5 years
2010 Q1 Notes	March 16, 2010	US$250, CAD$50	5 – 15 years	5.47%	6.3 years
2010 Q4 Notes	December 2, 2010, January 4, 2011	US$170, CAD$60	5 – 15 years	5.00%	9.2 years
2011 Notes	November 30, 2011	US$105, CAD$30	5 – 10 years	4.49%	7.6 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)	A portion of the 2009 Notes have equal repayments, beginning in 2013, over the remaining seven years.

(3)	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.

Financing charges in 2012 were comparable to 2011. In 2011, we repaid all outstanding convertible debentures and entered into additional fixed-rate, senior unsecured notes late in the year. While the Company’s senior unsecured notes contain higher interest rates than the syndicated bank facilities held in short-term money market instruments, 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, 2012, 29 percent (December 31, 2011 – 19 percent) of our long-term debt instruments were exposed to changes in short-term interest rates.

Realized gains and losses on the interest rate swaps are recorded as financing costs. For the second quarter of 2012 an expense of $2 million (2011 – $3 million) and for the first six months of 2012 an expense of $4 million (2011 – $6 million) were recorded in financing to reflect that the floating interest rate was lower than the fixed interest rate transacted under our interest rate swaps.


PENN WEST EXPLORATION SECOND QUARTER 2012		MANAGEMENT’S DISCUSSION & ANALYSIS		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”), our Long-Term Retention and Incentive Plan (“LTRIP”), and our Deferred Share Unit Plan (the “DSU”).

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. 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, received one common share right (“Share Rights”) issued under the CSRIP for each trust unit right. After January 1, 2011, all grants are under the Option Plan.

The Restricted Options, Share Rights and subsequent grants under the Option Plan receive equity treatment for accounting purposes 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 option grants are calculated using a Black-Scholes option-pricing model and the fair value of the Share Rights were calculated using a Binomial Lattice option-pricing model. 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 for the Restricted Rights with the fair value 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 resulted in a net $58 million charge to income during the first quarter of 2011.

The change in the fair value of outstanding LTRIP awards is charged to income based on the common share price at the end of each reporting period plus accumulated dividends. 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 charged to income to adjust the LTRIP obligation to fair value until settlement.

Share-based compensation consisted of the following:


	Three months ended June 30									Six months ended June 30
(millions)	2012			2011			% change			2012			2011			% change
Options	$	7		$	4			75		$	13		$	8			63
Restricted Options		1			6			(83	)		4			13			(69	)
Restricted Rights		(38	)		(10	)		100			(35	)		(5	)		100
Share Rights		—			—			—			—			1			(100	)
LTRIP		—			4			(100	)		5			7			(29	)
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	$	(30	)	$	4			(100	)	$	(13	)	$	82			(100	)

The share price used in the fair value calculation of the LTRIP liability and Restricted Rights obligation at June 30, 2012 was $13.66 per share (2011 – $22.27).


PENN WEST EXPLORATION SECOND QUARTER 2012		MANAGEMENT’S DISCUSSION & ANALYSIS		10

General and Administrative Expenses (“G&A”)


	Three months ended June 30						Six months ended June 30
(millions, except per boe amounts)	2012		2011		% change		2012		2011		% change
Gross	$	63	$	56		13	$	128	$	113		13
Per boe		4.25		3.94		8		4.26		3.88		10
Net		44		37		19		83		74		12
Per boe	$	2.95	$	2.64		12	$	2.75	$	2.54		8

Overall, G&A expenses have increased in 2012 compared to 2011 due to higher staff salaries and staff levels.

Depletion, Depreciation and Accretion


	Three months ended June 30							Six months ended June 30
(millions, except per boe amounts)	2012		2011		% change			2012		2011		% change
Depletion and depreciation (“D&D”)	$	306	$	311		(2	)	$	618	$	558		11
D&D expense per boe		20.66		21.87		(6	)		20.57		19.15		7

Accretion of decommissioning liability		10		10		—			21		22		(5	)
Accretion expense per boe	$	0.71	$	0.76		(7	)	$	0.70	$	0.76		(8	)

In the second quarter of 2011, we recorded an impairment charge of $29 million relating to properties in central Alberta, to reflect lower forecast cash flows from weaker commodity prices.

Taxes


	Three months ended June 30							Six months ended June 30
(millions)	2012		2011		% change			2012		2011			% change
Deferred tax expense (recovery)	$	83	$	98		(15	)	$	107	$	(253	)		100

In the second quarter of both 2012 and 2011, we recorded higher deferred tax expenses primarily as a result of unrealized risk management gains and property dispositions.

The deferred tax recovery for the six months ended June 30, 2011 includes a $304 million recovery related to the tax rate differential on our conversion from a trust to an E&P company on January 1, 2011. As a corporation, we are subject to income taxes at Canadian corporate tax rates. Under the former trust structure, IFRS required us 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.


PENN WEST EXPLORATION SECOND QUARTER 2012		MANAGEMENT’S DISCUSSION & ANALYSIS		11

Foreign Exchange


	Three months ended June 30							Six months ended June 30
(millions)	2012		2011			% change		2012		2011			% change
Unrealized foreign exchange loss (gain)	$	35	$	(7	)		100	$	4	$	(45	)		100

We record unrealized foreign exchange gains or losses to translate the U.S., UK and Euro denominated notes and the related accrued interest to Canadian dollars using the exchange rates in effect on the balance sheet date. The unrealized loss in the second quarter of 2012 was primarily due to the weakening of the Canadian dollar relative to the US dollar.

Funds Flow and Net Income


	Three months ended June 30							Six months ended June 30
(millions, except per share amounts)	2012		2011		% change			2012		2011		% change
Funds flow ⁽¹⁾(millions)	$	272	$	396		(31	)	$	609	$	752		(19	)
Basic per share		0.57		0.85		(33	)		1.29		1.62		(20	)
Diluted per share		0.57		0.85		(33	)		1.29		1.62		(20	)
Net income (millions)		235		271		(13	)		294		562		(48	)
Basic per share		0.50		0.58		(14	)		0.62		1.21		(49	)
Diluted per share	$	0.50	$	0.58		(14	)	$	0.62	$	1.21		(49	)

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

Funds flow in 2012 decreased from the comparative periods primarily due to lower commodity prices and wider Canadian crude oil differentials.

Net income remained strong in the second quarter of 2012 compared to the second quarter of 2011, as lower revenues were partially offset by unrealized risk management gains. On a year-to-date basis, net income was higher in 2011 due to a one-time deferred income tax recovery of $304 million related to our conversion to an E&P company.

Capital Expenditures


	Three months ended June 30									Six months ended June 30
(millions)	2012			2011			% change			2012			2011			% change
Land acquisition and retention	$	27		$	88			(69	)	$	35		$	106			(67	)
Drilling and completions		179			130			38			676			481			41
Facilities and well equipping		138			73			89			337			219			54
Geological and geophysical		2			1			100			10			7			43
Corporate		3			6			(50	)		11			9			22

Capital expenditures ⁽¹⁾		349			298			17			1,069			822			30
Joint venture, carried capital		(20	)		(13	)		54			(80	)		(45	)		78
Property dispositions, net		(19	)		(45	)		(58	)		(341	)		(101	)		100
Business combinations		—			286			(100	)		—			286			(100	)

Total capital expenditures	$	310		$	526			(41	)	$	648		$	962			(33	)

(1)	Capital expenditures include costs related to Property, Plant and Equipment and Exploration and Evaluation activities.

Throughout the second quarter of 2012 our capital activity was focused on completion, tie-ins and facility construction relating to the wells we drilled in the early part of the year at our light-oil properties in the Carbonates, Cardium, Viking and Spearfish.


PENN WEST EXPLORATION SECOND QUARTER 2012		MANAGEMENT’S DISCUSSION & ANALYSIS		12

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


	Three months ended June 30						Six months ended June 30
(millions)	2012		2011		% change		2012		2011		% change
E&E capital expenditures	$	52	$	20		100	$	150	$	65		100

For the first six months of 2012, we had a non-cash E&E expense of $1 million (2011 – $4 million) related to land expiries.

Gain on asset dispositions


	Three months ended June 30							Six months ended June 30
(millions)	2012		2011		% change			2012		2011		% change
Gain on asset dispositions	$	23	$	127		(82	)	$	95	$	151		(37	)

The gains recognized in income during 2012 and 2011 related to minor property dispositions.

Goodwill


(millions)	June 30, 2012		December 31, 2011
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 in prior years.

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, CO₂ sequestration, water management and site abandonment/reclamation. Operations are continuously monitored to minimize the environmental impact and sufficient capital is allocated to reclamation and other activities to mitigate the impact on the areas in which we operate.


PENN WEST EXPLORATION SECOND QUARTER 2012		MANAGEMENT’S DISCUSSION & ANALYSIS		13

Liquidity and Capital Resources

Capitalization


	June 30, 2012				December 31, 2011
(millions)			%				%
Common shares issued, at market ⁽¹⁾	$	6,483		63	$	9,517		73
Bank loans and long-term notes		3,691		36		3,219		25
Working capital deficiency ⁽²⁾		148		1		318		2

Total enterprise value	$	10,322		100	$	13,054		100

(1)	The share price at June 30, 2012 was $13.66 (December 31, 2011 – $20.19).

(2)	Excludes the current portion of risk management and share-based compensation liability.

Dividends


	Three months ended June 30						Six months ended June 30
(millions, except per share amounts)	2012		2011		% change		2012		2011		% change
Dividends declared	$	128	$	127		1	$	256	$	252		2
Per share		0.27		0.27		—		0.27		0.27		—
Dividends paid ⁽¹⁾	$	128	$	125		2	$	255	$	166		54

(1)	Includes amounts funded by the dividend reinvestment plan.

On August 9, 2012, our Board of Directors declared a 2012 third quarter dividend of $0.27 per share to be paid on October 15, 2012 to shareholders of record on September 28, 2012. Shareholders are advised that this dividend is designated as an “eligible dividend” for Canadian income tax purposes.

Liquidity

The Company currently has an unsecured, revolving, syndicated bank facility with an aggregate borrowing limit of $3.0 billion expiring on June 30, 2016. For further details on our debt instruments, please refer to the “Financing” section of this MD&A.

We actively manage our debt portfolio and consider opportunities to reduce or diversify our debt structure. We actively consider operating and financial risks and take actions as appropriate to limit our exposure to certain risks. We maintain close relationships with our lenders and agents to monitor credit market developments. These actions and plans 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 hence the longer-term execution of our business strategies.

The Company has a number of covenants related to its syndicated bank facility and senior, unsecured notes. On June 30, 2012, the Company was in compliance with all of these financial covenants which comprise the following:


	Limit	June 30, 2012
Senior debt to EBITDA ⁽¹⁾	Less than 3:1		2.4
Total debt to EBITDA ⁽¹⁾	Less than 4:1		2.4
Senior debt to capitalization	Less than 50%		28.7	%
Total debt to capitalization	Less than 55%		28.7	%

(1)	EBITDA is calculated in accordance with Penn West’s lending agreements wherein unrealized risk management gains and losses and impairment provisions are excluded.


PENN WEST EXPLORATION SECOND QUARTER 2012		MANAGEMENT’S DISCUSSION & ANALYSIS		14

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 investment plans. Our dividend level could change based on these and other factors and is subject to the approval of our Board of Directors.

Financial Instruments

We had the following financial instruments outstanding as at June 30, 2012. 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 (millions)
Crude oil
WTI Collars	60,000 bbls/d	Jul/12 – Dec/12	US$85.53 to $100.20/bbl	$	40
WTI Collars	41,000 bbls/d	Jan/13 – Dec/13	US$94.51 to $108.28/bbl		162

Natural gas
AECO Forwards ⁽¹⁾	52,730 GJ/d	Jul/12 – Dec/12	$4.08/GJ		19

Electricity swaps
Alberta Power Pool	45 MW	Jul/12 – Dec/12	$53.02/MWh		5
Alberta Power Pool	30 MW	Jul/12 – Dec/13	$54.60/MWh		5
Alberta Power Pool	20 MW	Jan/13 – Dec/13	$56.10/MWh		2
Alberta Power Pool	50 MW	Jan/14 – Dec/14	$58.50/MWh		3

Interest rate swaps	$650	Jul/12 – Jan/14	2.65%		(16	)

Foreign exchange contracts on revenues
12-month initial term	US$936	Jul/12 – Dec/12	1.022 CAD/USD		1
12-month initial term	US$360	Jan/13 – Dec/13	1.033 CAD/USD		3
12-month initial term	US$360	Jan/13 – Dec/13	1.033 –1.058 CAD/USD		5

Foreign exchange forwards on senior notes
3 to 15-year initial term	US$641	2014 – 2022	1.000 CAD/USD		31

Cross currency swaps
10-year initial term	£57	2018	2.0075 CAD/GBP, 6.95%		(23	)
10-year initial term	£20	2019	1.8051 CAD/GBP, 9.15%		(4	)
10-year initial term	€10	2019	1.5870 CAD/EUR, 9.22%		(3	)

Total				$	230

(1)	The forward contracts total approximately 50,000 mcf per day with an average price of $4.30 per mcf.

Subsequent to June 30, 2012, we realized proceeds of $66 million as we rearranged our 2013 oil collar position and monetized our 2013 foreign exchange contracts. Our previous position for 2013 was 41,000 barrels per day between US$94.51 and US$108.28 per barrel and we currently have 44,000 barrels per day between US$91.70 and US$104.99 per barrel. Additionally, we entered into natural gas forward contracts on 52,000 mcf per day for 2013 production at $3.25 per mcf and electricity swaps on 55 MWh in 2015 at $58.32 per MWh.

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


PENN WEST EXPLORATION SECOND QUARTER 2012		MANAGEMENT’S DISCUSSION & ANALYSIS		15

Outlook

This outlook section is included to provide shareholders with information about our expectations as at August 9, 2012 for production and capital expenditures for 2012 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 discussion under “Forward-Looking Statements” and are cautioned that numerous factors could potentially impact our capital expenditure levels and production performance for 2012, including our current disposition program.

In response to uncertainties in the outlook for commodity price realizations we have elected to slow the rate of our near-term capital investment. Our forecast exploration and development capital, net of acquisitions and dispositions closed to date in 2012, is now forecast to be in the range of $1.2 billion to $1.25 billion, a reduction of $100 million to $150 million. After giving effect to reduced capital spending and net acquisitions and dispositions closed to date in 2012, our forecast average production for 2012 is now between 165,000 and 168,500 boe per day.

Our prior forecast, released on May 4, 2012 with our first quarter results and filed on SEDAR at www.sedar.com, reflecting the impact of net acquisitions and dispositions at that time, was for 2012 average production of between 168,500 and 172,500 boe per day and exploration and development capital in the range of $1.3 billion to $1.4 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			21		0.04
Liquids production		1,000 bbls/day			19		0.04
Price per mcf of natural gas	$	0.10			9		0.02
Natural gas production		10 mmcf/day			1		—
Effective interest rate		1	%		8		0.02
Exchange rate ($US per $CAD)	$	0.01			13		0.03

Contractual Obligations and Commitments

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


(millions)	2012		2013		2014		2015		2016		Thereafter
Long-term debt	$	—	$	5	$	61	$	256	$	1,938	$	1,431
Transportation		11		21		13		9		3		—
Transportation ($US)		2		4		37		37		33		231
Power infrastructure		16		15		15		15		15		12
Drilling rigs		15		26		21		16		10		3
Purchase obligations ⁽¹⁾		7		13		11		10		2		5
Interest obligations		88		176		173		162		121		216
Office lease ⁽²⁾		39		66		60		60		59		479
Decommissioning liability ⁽³⁾	$	33	$	67	$	64	$	61	$	58	$	291

(1)	These amounts represent estimated commitments of $34 million for CO₂ purchases and $13 million for processing fees related to our interests in the Weyburn Unit.

(2)	The future office lease commitments above are contracted to be reduced by sublease recoveries totalling $416 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.


PENN WEST EXPLORATION SECOND QUARTER 2012		MANAGEMENT’S DISCUSSION & ANALYSIS		16

Our syndicated credit facility is due for renewal on June 30, 2016. If we are not successful in renewing or replacing the facility, we could be required to obtain other loans including term bank loans. In addition, we have an aggregate of $2.0 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.

We are involved in various claims and litigation in the normal course of business and record provisions for claims as required.

Equity Instruments


Common shares issued:
As at June 30, 2012	474,588,693
Issued on exercise of share rights	7,975
Issued pursuant to dividend reinvestment plan	2,317,812

As at August 9, 2012	476,914,480

Options outstanding:
As at June 30, 2012	15,509,189
Forfeited	(125,756	)

As at August 9, 2012	15,383,433

Share Rights outstanding:
As at June 30, 2012	1,183,146
Exercised	(7,333	)
Forfeited	(423,930	)

As at August 9, 2012	751,883

Restricted Options outstanding ⁽¹⁾:
As at June 30, 2012	12,650,569
Forfeited	(172,642	)

As at August 9, 2012	12,477,927

(1)	Each holder of a Restricted Option holds a Restricted Right and has the option to settle the Restricted Right in cash or common shares upon exercise. Refer to the “Expenses – Share-Based Compensation” section of this MD&A for further details.

Internal Control over Financial Reporting (“ICOFR”)

No changes in our ICOFR were made during the quarter ended June 30, 2012 that have materially affected, or are reasonably likely to materially affect, our ICOFR.

Future Accounting Pronouncements

In May 2011, the International Accounting Standards Board issued the following standards which are not yet effective:

IFRS 10 “Consolidated Financial Statements” outlines 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.

IFRS 11 “Joint Arrangements” 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. We currently believe that our interest in the Peace River Oil Partnership is appropriately classified as a joint operation; therefore, our partnership interest will continue to be proportionately consolidated upon adoption of this standard.


PENN WEST EXPLORATION SECOND QUARTER 2012		MANAGEMENT’S DISCUSSION & ANALYSIS		17

IFRS 12 “Disclosure of Interests in Other Entities” outlines 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 are currently assessing the impact of this standard.

IFRS 13 “Fair Value Measurement” 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 are currently assessing the impact of this standard.

Financial statement impacts related to our corporate conversion on January 1, 2011

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 thus we 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 under the CSRIP 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.

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.


PENN WEST EXPLORATION SECOND QUARTER 2012		MANAGEMENT’S DISCUSSION & ANALYSIS		18

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.

In particular, this document contains forward-looking statements pertaining to, without limitation, the following: certain disclosures contained under the heading “Business Strategy” relating to, among other things, our intention to continue the focus of our capital program on light-oil plays and the use of horizontal multi-stage fracture techniques, our belief with respect to key technical skills regarding the application of horizontal multistage technologies; our belief that we have a drilling inventory of over 10,000 locations largely weighted to oil, our belief that our future development potential is substantial, our belief that our dividend offers shareholders a return during times of market volatility, and our intention to continue to work through our light-oil development plans with continued attention on cost optimization as we move in the second half of 2012; certain disclosures contained under the headings “Business Environment”, “Crude Oil” and “Natural Gas” relating to, among other things, our view of the outlook for crude oil and natural gas prices, price differentials for crude oil and the impact that certain infrastructure projects may have on such differentials and related matters, and supply-demand fundamentals for crude oil and natural gas going forward; our intention to maintain an appropriate mix of liquids and natural gas production in order to reduce exposure to price volatility that can affect a single commodity; our intention to continue allocating substantially all of our capital investments to oil weighted projects; the disclosure under the heading “Environmental and Climate Change” relating to the environmental risks and hazards we face, the potential impact such risks could have on us, and our intention to reduce our environmental impact and allocate sufficient capital to reclamation and other activities; all matters relating to our dividend policy, including 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; certain disclosures contained under the heading “Outlook” relating to our forecast exploration and development capital expenditures for 2012 and our forecast average production levels for 2012; certain disclosures contained under the heading “Sensitivity Analysis” relating to our estimated sensitivities to certain key assumptions on our future funds flow; the alternatives available to us and the potential outcomes if we are not successful in renewing or replacing our credit facility; and our expectations regarding the impact that certain future accounting pronouncements may have on us and our financial statements.

With respect to forward-looking statements contained in this document, we have made assumptions regarding, among other things: future crude oil, natural gas liquids and natural gas prices and differentials between light, medium and heavy oil prices and Canadian, WTI and world oil prices; future capital expenditure levels; future crude oil, natural gas liquids and natural gas production levels; drilling results; future exchange rates and interest rates; the amount of future cash dividends that we intend to pay and the level of participation in our dividend reinvestment plan; 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, including our ability to renew or replace our credit facility and our ability to finance the repayment of our senior unsecured notes on maturity; 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”.


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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; 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, price differentials for crude oil produced in Canada as compared to other markets, and transportation restrictions; 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 or environmental events that can reduce production or cause production to be shut-in or delayed, including wild fires and flooding; 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) 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 and on EDGAR at www.sec.gov.


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