Exhibit 99.2

MANAGEMENT’S DISCUSSION AND ANALYSIS

For the year ended December 31, 2013

This management’s discussion and analysis (“MD&A”) of financial conditions and results of operations should be read in conjunction with the audited consolidated financial statements of Penn West Petroleum Ltd. (“Penn West”, “we”, “us”, “our”, the “Company”) for the years ended December 31, 2013 and 2012. The date of this MD&A is March 6, 2014. All dollar amounts contained in this MD&A are expressed in millions of Canadian dollars unless noted otherwise.

For additional information, including our audited consolidated financial statements and Annual Information Form, please go to our website at www.pennwest.com, in Canada to the SEDAR website at www.sedar.com or in the United States to the SEC website at www.sec.gov.

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, netback, gross revenues, sustainability ratio, recycle ratio, net operating income and net debt to funds flow 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 IFRS. Netback is the per unit of production amount of revenue less royalties, operating costs, transportation and realized risk management gains and losses, and is used in capital allocation decisions and to economically rank projects. See “Results of Operations – Netbacks” below for a calculation of our netbacks. Gross revenue is total revenues including realized risk management gains and losses and is used to assess the cash realizations on commodity sales. Sustainability ratio is a comparison of a company’s cash outflows (capital investment and dividends paid less DRIP) to its cash inflows (funds flow) and is used by the Company to assess the appropriateness of its dividend levels and the long-term ability to fund its development plans. Recycle ratio is a comparison of our netback to our finding and development costs and is used to assess the cost of finding reserves compared to the cash received. Net operating income includes oil and gas sales, royalties, operating expenses and transportation. Net debt to funds flow is the ratio of our net debt to our 12 months trailing funds flow and is used to assess the appropriateness of the Company’s level of leverage. Net debt is the estimated amount of long-term debt plus working capital deficit excluding the current portion of risk management and deferred funding assets.

Calculation of Funds Flow

(millions, except per share amounts)	Year ended December 31
	2013			2012
Cash flow from operating activities	$	1,039		$	1,193
Change in non-cash working capital		(51	)		(37	)
Decommissioning expenditures		66			92
Funds flow	$	1,054		$	1,248
Basic per share	$	2.17		$	2.62
Diluted per share	$	2.17		$	2.62

PENN WEST 2013 MANAGEMENT’S DISCUSSION AND ANALYSIS 1

Annual Financial Summary

	Year ended December 31
(millions, except per share amounts)	2013			2012			2011
Gross revenues (1)	$	2,835		$	3,283		$	3,604
Funds flow		1,054			1,248			1,537
Basic per share		2.17			2.62			3.29
Diluted per share		2.17			2.62			3.29
Net income (loss)		(838	)		149			617
Basic per share		(1.72	)		0.31			1.32
Diluted per share		(1.72	)		0.31			1.32
Development capital expenditures (2)		816			1,752			1,846
Property acquisition (disposition), net		(525	)		(1,615	)		(266	)
Long-term debt		2,458			2,690			3,219
Dividends/ distributions paid (3)		458			512			420
Total assets	$	12,644		$	14,437		$	15,555

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

(2) Includes the effect of capital carried by partners.

(3) Includes dividends paid and reinvested in shares under the dividend reinvestment plan.

2013 Highlights

• Production in 2013 was within guidance at 135,093 boe per day compared to 161,195 boe per day in 2012. The decline in production was primarily due to asset dispositions completed in late 2012 and 2013.

• In 2013, we closed property dispositions in non-core areas where minimal capital was allocated in our five-year plan for total proceeds of $525 million. Average annual production for the disposed properties was approximately 11,000 boe per day.

• Disposition proceeds received during 2013 were applied to the company’s credit facilities with a net reduction in long-term debt of $356 million during the year, prior to foreign currency translations.

• Development capital expenditures for 2013 were $816 million (2012 - $1,752 million), which was below our initial guidance of $900 million as a result of successful cost reduction strategies which lowered drilling and completion costs at our key light-oil plays during the year.

• We drilled 206 net wells (2012 - 282 net wells), excluding stratigraphic and service wells.

• Netbacks increased to $29.69 per boe in 2013 from $26.58 per boe in 2012.

• Funds flow for 2013 was $1,054 million compared to $1,248 million in 2012. The decline in funds flow from 2012 is mainly due to lower production volumes resulting from asset dispositions in late 2012 and the monetization of crude oil collars and foreign exchange contracts in 2012.

• Net loss was $838 million in 2013 compared to net income of $149 million in 2012. The decline in net income was largely due to non-cash impairment charges recorded on certain natural gas assets due to limited planned development capital and lower estimated reserve recoveries on properties in Manitoba. Lower revenues from lower production volumes due to disposition activity and unrealized foreign exchange losses on the translation of US denominated senior, unsecured notes also contributed to the decrease.

PENN WEST 2013 MANAGEMENT’S DISCUSSION AND ANALYSIS 2

Quarterly Financial Summary

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

Three months ended	Dec. 31 2013			Sep. 30 2013		June 30 2013			Mar. 31 2013			Dec. 31 2012			Sep. 30 2012			June 30 2012		Mar. 31 2012
Gross revenues (1)	$	613		$	773	$	745		$	704		$	799		$	840		$	774	$	870
Funds flow		216			293		278			267			295			344			272		337
Basic per share		0.44			0.60		0.57			0.55			0.62			0.72			0.57		0.71
Diluted per share		0.44			0.60		0.57			0.55			0.62			0.72			0.57		0.71
Net income (loss)		(728	)		27		(40	)		(97	)		(78	)		(67	)		235		59
Basic per share		(1.49	)		0.06		(0.08	)		(0.20	)		(0.16	)		(0.14	)		0.50		0.12
Diluted per share		(1.49	)		0.06		(0.08	)		(0.20	)		(0.16	)		(0.14	)		0.50		0.12
Dividends declared		68			68		131			130			129			129			128		128
Per share	$	0.14		$	0.14	$	0.27		$	0.27		$	0.27		$	0.27		$	0.27	$	0.27
Production
Liquids (bbls/d) (2)		78,657			84,460		88,146			89,250			99,071			105,588			104,758		107,199
Natural gas (mmcf/d)		272			296		312			321			329			329			351		361
Total (boe/d)		123,995			133,712		140,083			142,804			153,931			160,339			163,181		167,420

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

(2) Includes crude oil and natural gas liquids.

Business Strategy

In November 2013, we announced our five-year plan which aims to position us as a leading oil producer in the Western Canadian Sedimentary basin. Key features of the long-term strategy include:

• Promoting operational excellence across all levels of the Company,

• Focusing our development activities on projects with the highest returns in three of our core areas (Cardium, Viking, Slave Point),

• Non-core asset rationalization including $1.5 - $2 billion of asset dispositions,

• Debt reduction,

• Continuing to drive cost reductions, and

• A sustainable dividend strategy moving forward.

During the fourth quarter of 2013 and into 2014, we have progressed on a number of these strategies with $486 million of dispositions closed during the period along with the recently announced $175 million disposition expected to close in the first quarter of 2014. Our development program was focused on the Cardium and Viking areas where we increased activity levels and continued to realize significant drilling and completion cost reductions. In 2014, we will continue to focus on these key strategies outlined in our long-term plan.

PENN WEST 2013 MANAGEMENT’S DISCUSSION AND ANALYSIS 3

Business Environment

The following table outlines quarterly averages for benchmark prices and our realized prices for the previous five quarters.

	Q4 2013			Q3 2013			Q2 2013			Q1 2013			Q4 2012
Benchmark prices
WTI crude oil (US$/bbl)	$	97.50		$	105.80		$	94.23		$	94.34		$	88.20
Edm mixed sweet par price (CAD$/bbl)		86.33			104.69			92.58			88.17			83.96
AECO Monthly Index (CAD$/mcf)		3.15			2.67			3.59			3.08			3.06
Penn West average sales price (1)
Light oil and NGL (per bbl)		77.43			92.42			82.65			80.23			75.91
Heavy oil (per bbl)		58.66			84.02			67.10			50.78			59.85
Total liquids (per bbl)		73.94			90.88			79.89			74.84			73.18
Natural gas (per mcf)		3.53			2.83			3.70			3.18			3.28
Benchmark differentials
WTI - Edm Light Sweet ($US/bbl)		(15.02	)		(4.80	)		(3.60	)		(7.11	)		(3.46	)
WTI - WCS Heavy ($US/bbl)	$	(32.21	)	$	(17.47	)	$	(19.13	)	$	(31.82	)	$	(18.21	)

(1) Excludes the impact of realized hedging gains or losses.

Crude Oil

For 2013, WTI averaged US$98.00 per barrel compared to US$94.17 per barrel in 2012. Canadian oil price realizations remained volatile in 2013 with the differential between WTI and Edmonton Light Sweet peaking during the fourth quarter of 2013 primarily due to refineries working through their fall turnaround schedule. The differentials subsequently narrowed and refinery utilization rates have returned to normal. During 2013, pipeline capacity constraints at times disrupted the movement of crude oil out of Western Canada and producers increased the use of rail as a method of transportation. A series of train derailments in the second half of 2013 has put increased scrutiny on crude by rail transport.

The U.S. Government has yet to indicate whether it will approve the Keystone XL pipeline project. In Canada, the National Energy Board (“NEB”) has recommended that Enbridge’s Gateway project be approved subject to meeting various conditions. Additionally, Kinder Morgan has submitted a formal application to the NEB for the expansion of their TransMountain system. The completion of these projects could ease current pipeline constraints out of Western Canada.

Currently, we have 20,000 barrels per day of crude oil production for the first half of 2014 swapped at WTI US$93.74 per barrel and an additional 10,000 barrels per day for the same period collared between WTI US$93.20 and WTI US$101.00 per barrel.

Natural Gas

In 2013, the AECO average monthly index was $3.12 per mcf compared to $2.40 per mcf in 2012. Entering the summer months of 2013, inventory levels were significantly lower than in previous years due to lower natural gas drilling activity over the past two years. A cool summer season across most of North America increased inventory levels, however, due to extremely cold winter temperatures late in 2013 inventory levels have decreased and were approximately 15 percent lower year-over-year.

In 2014, cold weather and declining inventories have resulted in AECO natural gas prices that are averaging approximately $4.00 per mcf. The cold weather in 2014 led to periods of extreme volatility in natural gas prices as intra-day AECO spot prices touched approximately $40 per mcf in February. Coal prices have not responded to the increase in natural gas prices thus natural gas does not appear to be positioned to increase market share from coal in the power generation sector should power demand increase.

We have 140,000 mcf per day of 2014 natural gas production hedged with 90,000 mcf per day swapped at $3.90 per mcf and 50,000 mcf per day collared between $3.41 and $4.17 per mcf along with 70,000 mcf per day of 2015 natural gas production collared between $3.69 per mcf and $4.52 per mcf.

PENN WEST 2013 MANAGEMENT’S DISCUSSION AND ANALYSIS 4

Average Sales Prices

	Year ended December 31
	2013			2012		% change
Light oil (per bbl)	$	88.38		$	80.50		10
Risk management gain (loss) (per bbl) (1)		(0.37	)		0.19		(100	)
Light oil net (per bbl)		88.01			80.69		9
Heavy oil (per bbl)		65.12			63.67		2
NGL’s (per bbl)		51.75			53.75		(4	)
Natural gas (per mcf)		3.31			2.45		35
Risk management gain (per mcf) (1)		0.14			0.34		(59	)
Natural gas net (per mcf)		3.45			2.79		24
Weighted average (per boe)		57.71			53.60		8
Risk management gain (per boe) (1)		0.16			0.81		(80	)
Weighted average net (per boe)	$	57.87		$	54.41		6

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

Performance Indicators

Our management and Board of Directors monitor our performance based upon a number of qualitative and quantitative factors including:

• Finding and development (“F&D”) costs – We use these metrics to assess the continuing economic viability and the relative development stage of our resource plays.

• Base operations – Includes our production performance and execution of our operational, health, safety, environmental and regulatory programs.

• Shareholder value measures – These include key enterprise value metrics such as funds flow per share and dividends per share.

• Financial, business and strategic considerations – These include the management of our asset portfolio, financial stewardship and the overall goal of creating competitive return on investment for our shareholders.

Finding and Development costs

	Year ended December 31
	2013		2012		2011		3-Year average
Including FDC (1)
F&D costs per boe – proved plus probable	$	9.47	$	25.50	$	26.79	$	22.49
F&D costs per boe – proved	$	16.51	$	30.96	$	37.05	$	31.02
Excluding FDC (2)
F&D costs per boe – proved plus probable	$	17.17	$	17.48	$	15.07	$	16.33
F&D costs per boe – proved	$	18.00	$	26.69	$	23.55	$	23.31

(1) The calculation of F&D includes the change in FDC and excludes the effects of acquisitions and dispositions.

(2) The calculation of F&D excludes the change in FDC and excludes the effects of acquisitions and dispositions.

PENN WEST 2013 MANAGEMENT’S DISCUSSION AND ANALYSIS 5

Our proved reserves continue to reflect a high percentage of developed reserves. Of total proved reserves, 75 percent were developed at December 31, 2013 (2012 – 78 percent). At December 31, 2013, total proved reserves as a percentage of proved plus probable reserves were 67 percent (2012 – 66 percent). On a proved plus probable basis our reserves were weighted 70 percent to crude oil and liquids (2012 – 71 percent) and 30 percent to natural gas (2012 – 29 percent). Our focused drilling program during the year highlighted by the realization of significant drilling and completions cost reductions and the potential of our waterflood programs partially offset oil weighted dispositions that occurred primarily in the fourth quarter of 2013.

Capital expenditures for 2013 have been reduced by $83 million related to joint venture carried capital (2012 – $137 million).

The aggregate of the exploration and development costs incurred in the most recent financial year and the change during that year in estimated future development costs generally will not reflect total finding and development costs related to reserves additions for that year. For comparative purposes we also disclose F&D costs excluding FDC. F&D costs are calculated in accordance with NI 51-101, which include the change in FDC, on a proved and proved plus probable basis.

Base operations

In the second half of 2013, we increased the focus of our development programs by concentrating on three core areas of our portfolio; the Cardium, Viking and Slave Point. For 2014, our development plans will emphasize these areas and increased application of waterflood programs. We have plans for further non-core dispositions as part of our strategy to increase the focus of our portfolio and strengthen our balance sheet.

Shareholder Value Measures

	Year ended December 31
	2013		2012		2011
Funds flow per share	$	2.17	$	2.62	$	3.29
Dividends paid per share	$	0.95	$	1.08	$	0.90

The company views funds flow per share as an important measure to drive shareholder returns. Increases in the metric are often correlated to share price increases and the generation of funds flow is critical to funding the development of our extensive light-oil resources. Dividends impose natural capital investment limits on management and thus may limit shareholder exposure to excessive operational and other risks.

Our last monthly distribution payment of $0.09 per unit as a trust was declared in December 2010 and paid in January 2011. Subsequent to converting to a corporation in January 2011, we began paying a quarterly dividend of $0.27 per share, which continued into 2013. In June 2013, we announced a reduction of our quarterly dividend from $0.27 per share to $0.14 per share as a means to provide increased financial flexibility. This change was effective for the third quarter dividend announced in August 2013 and paid in October 2013.

PENN WEST 2013 MANAGEMENT’S DISCUSSION AND ANALYSIS 6

Financial, business and strategic considerations

	Year ended December 31
	2013			2012			2011
Net debt to funds flow (1,2)		2.7			2.5			2.5
Average production weighting
Liquids weighting		63	%		65	%		63	%
Natural gas weighting		37	%		35	%		37	%
Netbacks (2)	$	29.69		$	26.58		$	30.95
Recycle ratio (2,3)		3.1			1.0			1.2
Sustainability ratio (2)		112	%		172	%		141	%

(1) Net debt includes long-term debt and working capital surplus/ deficiency.

(2) Refer to our non-GAAP advisory for definitions.

(3) F&D costs, including the change in FDC, on a proved plus probable basis are used in the calculation.

We anticipate our net debt to funds flow ratio to improve in future years as we continue to de-lever our balance sheet and focus on light-oil, higher return projects outlined in our five-year plan.

Liquids weighting is important to increasing funds flow, as the netback on a boe basis is significantly higher than for natural gas. Our production weighting has remained relatively consistent over the past three years, as production additions from our light-oil focused development programs have been offset by non-core disposition activity. As we move forward, our long-term plan is to focus development in three main light-oil areas; the Cardium, Slave Point and Viking.

One of the key strategies in our long-term plan is cost reduction to realize improvements in our netbacks which, in turn drives higher funds flow. The 2013 increase in netbacks compared to 2012 was primarily due to higher commodity prices while the decrease between 2012 and 2011 was attributed to lower commodity prices.

We monitor our recycle ratio to ensure that our capital programs provide economic benefit to our shareholders. The improvement in recycle ratio in 2013 can largely be attributed to a more focused capital program and cost improvements across our key light-oil plays which significantly reduced our F&D cost. The increase in our netback also contributed to the improvement.

Sustainability ratio is used to ensure our capital expenditures and dividend programs are appropriate relative to our capitalization. We have targeted for a 110 percent sustainability ratio in our long-term plan. In 2013, through a focus on operational excellence across our plays, we realized significant reductions to drilling costs and cycle times, which have a positive impact on this metric.

RESULTS OF OPERATIONS

Production

	Year ended December 31
Daily production	2013		2012		% change
Light oil (bbls/d)		59,842		75,951		(21	)
Heavy oil (bbls/d)		15,511		17,361		(11	)
NGL’s (bbls/d)		9,745		10,832		(10	)
Natural gas (mmcf/d)		300		342		(12	)
Total production (boe/d)		135,093		161,195		(16	)

Our production levels for 2013 were lower than 2012, primarily due to the full-year effect of non-core property dispositions that were closed during the fourth quarter of 2012. Non-core property dispositions which closed during the fourth quarter of 2013 and the shut-in of uneconomic production during 2013, also contributed to the decline.

PENN WEST 2013 MANAGEMENT’S DISCUSSION AND ANALYSIS 7

Netbacks

	Light Oil and									2013			2012
	NGL			Heavy Oil			Natural Gas			Combined			Combined
	(bbl)			(bbl)			(mcf)			(boe)			(boe)
Operating netback (1):
Sales price	$	83.25		$	65.12		$	3.31		$	57.71		$	53.60
Risk management gain (loss) (2)		(0.32	)		—			0.14			0.16			0.81
Royalties		(15.19	)		(9.93	)		(0.60	)		(10.29	)		(10.07	)
Operating costs		(20.54	)		(19.38	)		(2.03	)		(17.30	)		(17.26	)
Transportation		—			(0.06	)		(0.26	)		(0.59	)		(0.50	)
Netback	$	47.20		$	35.75		$	0.56		$	29.69		$	26.58
	(bbls/d)			(bbls/d)			(mmcf/d)			(boe/d)			(boe/d)
Production		69,587			15,511			300			135,093			161,195

(1) Excluded from the netback calculation is $17 million primarily related to realized risk management losses on foreign exchange contracts.

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

Production Revenues

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

	Year ended December 31
(millions)	2013		2012		2011
Light oil and NGL	$	2,088	$	2,529	$	2,657
Heavy oil		369		405		452
Natural gas		378		349		495
Gross revenues (1)	$	2,835	$	3,283	$	3,604

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

In 2013, liquid revenues have declined from 2012 due to lower production volumes resulting from asset dispositions closed in 2012; this was partially offset by increases in crude oil prices. Natural gas revenues increased mainly due to higher prices which more than offset production declines.

Lower commodity price realizations in 2012, partially offset by an increase in liquids production, resulted in a decline in liquids revenue from 2011. Natural gas revenues were affected by lower production, due to our development focus on light oil, and a significant decline in natural gas prices.

Reconciliation of Change in Production Revenues

(millions)
Gross revenues – January 1 – December 31, 2012	$	3,283
Decrease in light oil and NGL production		(507	)
Increase in light oil and NGL prices (including realized risk management)		66
Decrease in heavy oil production		(44	)
Increase in heavy oil prices		8
Decrease in natural gas production		(44	)
Increase in natural gas prices (including realized risk management)		73
Gross revenues – January 1 – December 31, 2013	$	2,835

PENN WEST 2013 MANAGEMENT’S DISCUSSION AND ANALYSIS 8

Royalties

	Year ended December 31
	2013			2012			2011
Royalties (millions)	$	507		$	595		$	661
Average royalty rate (1)		18	%		18	%		18	%
$/boe	$	10.29		$	10.07		$	11.09

(1) Excludes effects of risk management activities.

For 2013, royalty expense decreased from 2012 primarily due to the asset dispositions completed in 2012, which resulted in lower production volumes and revenues.

Lower commodity prices in 2012, partially offset by the impact of wider Canadian crude oil differentials to WTI, resulted in lower royalties compared to 2011.

Average royalty rates have remained consistent between 2013 and the comparative periods.

Expenses

	Year ended December 31
(millions)	2013		2012			2011
Operating	$	853	$	1,019		$	1,036
Transportation		29		29			29
Financing		184		199			190
Share-based compensation	$	32	$	(10	)	$	84
	Year ended December 31
(per boe)	2013		2012			2011
Operating	$	17.30	$	17.26		$	17.40
Transportation		0.59		0.50			0.49
Financing		3.73		3.37			3.20
Share-based compensation	$	0.65	$	(0.17	)	$	1.41

Operating

The reduction in operating costs in 2013 compared to 2012 is attributed to the asset dispositions that closed late in 2012 along with field staff reductions and other cost reduction initiatives in 2013 aimed at streamlining our operations.

The decrease between 2012 and 2011 was due to lower electricity costs and acquisition and disposition activity. The temporary interruptions experienced in the second quarter of 2011 from the wild fires in Slave Lake and flooding in Manitoba and Saskatchewan led to increased workover and maintenance activity in 2011.

Operating costs for 2013 included a realized gain on electricity contracts of $11 million (2012 – $7 million and 2011 – $11 million). For 2013, the average Alberta pool price was $80.19 per MWh (2012 – $64.31 per MWh and 2011 – $76.21 per MWh). We currently have the following contracts in place that fix the price on our electricity consumption; in 2014 approximately 80 MW fixed at $58.50 per MWh, in 2015 approximately 80 MW fixed at $56.69 per MWh and in 2016 approximately 25 MW fixed at $49.90 per MWh.

PENN WEST 2013 MANAGEMENT’S DISCUSSION AND ANALYSIS 9

Financing

The Company has an 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 standby fees on unutilized credit lines and stamping fees on bankers’ acceptances and LIBOR loans that vary depending on certain consolidated financial ratios. At December 31, 2013, approximately $2.6 billion was undrawn under this facility.

As at December 31, 2013, the value of the Company’s senior unsecured notes was $2.1 billion compared to $1.9 billion at the end of 2012. No new note issuances occurred in 2013, thus the increase is attributed to a weaker Canadian dollar compared to the US dollar partially offset by a $5 million repayment on our senior unsecured notes during the year. Summary information on our senior unsecured notes outstanding is as follows:

	As at December 31
	2013			2012
Weighted average remaining life (years)		4.5			5.5
Weighted average interest rate (1)		6.1	%		6.1	%

(1) Excludes the effect of cross currency swaps.

At December 31, 2013, we had $650 million of interest rate swaps outstanding at a weighted average fixed rate of 2.65 percent which expired in January 2014. These swaps fix a portion of the interest rates under our bank facility.

At December 31, 2013, 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	%		3.5
2008 Notes	May 29, 2008		US$480, CAD$30		8 – 12 years		6.25	%		4.0
UK Notes	July 31, 2008		£57		10 years		6.95	%(1)		4.6
2009 Notes	May 5, 2009		US$149 (2), £20, €10, CAD$5		5 – 10 years		8.85	%(3)		3.1
2010 Q1 Notes	March 16, 2010		US$250, CAD$50		5 – 15 years		5.47	%		4.8
2010 Q4 Notes	December 2, 2010, January 4, 2011		US$170, CAD$60		5 – 15 years		5.00	%		7.7
2011 Notes	November 30, 2011		US$105, CAD$30		5 – 10 years		4.49	%		6.1

(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, which began in 2013 with a repayment of $5 million, and extend over the remaining six 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.

Our debt capital structure includes short-term financings under our syndicated bank facility and long-term instruments through our senior unsecured notes. Financing charges in 2013 decreased compared to 2012 as the outstanding balance under our credit facility was lower. While the Company’s senior unsecured notes currently contain higher interest rates than drawings under our syndicated bank facilities held in short-term money market instruments, we believe the long-term nature 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 credit facility are subject to fluctuations in short-term money market rates as advances on the credit facility are generally made under short-term instruments. As at December 31, 2013, none (2012 – four percent) of our long-term debt instruments were exposed to changes in short-term interest rates.

PENN WEST 2013 MANAGEMENT’S DISCUSSION AND ANALYSIS 10

Realized gains and losses on the interest rate swaps are recorded as financing costs. For 2013 an expense of $9 million (2012 – $9 million) was recorded in financing costs to reflect that the floating interest rate was lower than the fixed interest rate transacted under our interest rate swaps.

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”) which includes restricted options, restricted rights and share rights, our Long-Term Retention and Incentive Plan (“LTRIP”), our Deferred Share Unit Plan (the “DSU”) and our Performance Share Unit Plan (“PSU”).

Share-based compensation consisted of the following:

	Year ended December 31
(millions)	2013		2012			2011
Options	$	15	$	21		$	18
Restricted Options		—		6			22
Restricted Rights		—		(45	)		(29	)
Share Rights		—		—			1
LTRIP		13		8			14
DSU		1		—			—
PSU		3		—			—
Expiry of TURIP at Jan. 1, 2011		—		—			(196	)
Share Rights at Jan. 1, 2011		—		—			16
Restricted Options at Jan. 1, 2011		—		—			65
Restricted Rights liability at Jan. 1, 2011		—		—			173
Share-based compensation	$	32	$	(10	)	$	84

During 2013, $6 million of PSU expense was accelerated and reclassified from share-based compensation to restructuring in the Consolidated Statement of Income (Loss), related to the severance of former executives.

The share price used in the fair value calculation of the Restricted Rights, LTRIP, DSU and PSU obligations at December 31, 2013 was $8.87 (2012 – $10.80 and 2011 – $20.19).

General and Administrative Expenses (“G&A”)

	Year ended December 31
(millions, except per boe amounts)	2013		2012		2011
Gross	$	213	$	254	$	222
Per boe		4.33		4.31		3.72
Net		160		172		142
Per boe	$	3.24	$	2.91	$	2.38

The decrease in G&A expense from the comparable periods is due to staff reductions in 2013. G&A on a per boe basis has increased due to lower production volumes primarily resulting from the effect of the dispositions closed in the fourth quarter of 2012.

Restructuring Expense

During 2013, significant changes were made to our cost structure to increase operational efficiencies through reducing our staffing levels both at our head office and in the field. We recorded a restructuring charge of $38 million ($0.76 per boe); with $32 million related to office and field severances and $6 million in accelerated PSU payments.

In 2012, we incurred $13 million of restructuring charges related to severance payments as a result of internal reorganizing.

PENN WEST 2013 MANAGEMENT’S DISCUSSION AND ANALYSIS 11

Depletion, Depreciation, Impairment and Accretion

	Year ended December 31
(millions, except per boe amounts)	2013		2012		2011
Depletion and depreciation (“D&D”)	$	1,050	$	1,248	$	1,168
D&D expense per boe		21.29		21.17		19.62
Impairment (recovery)		742		277		(10	)
Impairment (recovery) per boe		15.05		4.69		(0.17	)
Accretion of decommissioning liability		43		54		45
Accretion expense per boe	$	0.87	$	0.90	$	0.76

The decrease in our D&D expense in 2013 is attributed to lower production volumes due to the dispositions that closed in 2012. The increase in 2012 compared to 2011 was related to our capital spending substantially weighted to light-oil development and the divestment of non-core properties.

In 2013, we recorded an impairment charge in the fourth quarter on certain non-core natural gas assets in British Columbia and Alberta primarily due to limited planned development capital. Additionally, an impairment charge was recorded in an oil weighted area in Manitoba due to lower estimated reserve recoveries. In 2012, we recorded an impairment charge during the fourth quarter related to legacy, base natural gas assets in northern British Columbia as a result of low natural gas prices.

The accretion per boe decreased in 2013 compared to 2012 as a result of dispositions closed late in the prior year.

Taxes

	Year ended December 31
(millions)	2013			2012		2011
Deferred tax expense (recovery)	$	(243	)	$	63	$	(227	)

In 2013, the deferred income tax recovery was primarily due to impairment charges recorded during the fourth quarter of 2013. Also included in the recovery in 2013 was a $7 million income tax refund related to a legacy tax dispute that was resolved.

In 2012, we recorded a deferred tax expense primarily due to gains on property dispositions and from unrealized risk management gains.

The deferred tax recovery for the year ended December 31, 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.

Tax Pools

	As at December 31
(millions)	2013		2012		2011
Undepreciated capital cost (UCC)	$	1,057	$	1,155	$	1,085
Canadian oil and gas property expense (COGPE)		20		24		1,395
Canadian development expense (CDE)		1,519		2,713		2,104
Canadian exploration expense (CEE)		250		348		294
Non-capital losses		2,761		2,182		2,966
Other		57		21		31
Total	$	5,664	$	6,443	$	7,875

Tax pool amounts exclude income deferred in operating partnerships of $637 million in 2013 (2012 – $835 million and 2011 – $1,654 million).

PENN WEST 2013 MANAGEMENT’S DISCUSSION AND ANALYSIS 12

Foreign Exchange

	Year ended December 31
(millions)	2013		2012			2011
Unrealized foreign exchange loss (gain)	$	126	$	(32	)	$	38

We record unrealized foreign exchange gains or losses to translate the U.S., UK and Euro denominated senior, unsecured notes and the related accrued interest to Canadian dollars using the exchange rates in effect on the balance sheet date. The unrealized losses in 2013 and 2011 were due to the weakening of the Canadian dollar relative to the US dollar. The unrealized gain in 2012 can be attributed to the Canadian dollar strengthening compared to the US dollar. As at December 31, 2013, we have 39 percent of the repayment of our US denominated senior, unsecured notes hedged at US$1.00 equals CAD$1.00 and all of the UK and Euro denominated senior, unsecured notes under cross currency swaps. The offsetting gains on these hedges were $39 million for 2013 based on the exchange rate on December 31, 2013 of USD/CAD of 1.06, and are recorded as risk management.

Funds Flow and Net Income (Loss)

	Year ended December 31
	2013			2012		2011
Funds flow (1) (millions)	$	1,054		$	1,248	$	1,537
Basic per share		2.17			2.62		3.29
Diluted per share		2.17			2.62		3.29
Net income (loss) (millions)		(838	)		149		617
Basic per share		(1.72	)		0.31		1.32
Diluted per share	$	(1.72	)	$	0.31	$	1.32

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

The decline in funds flow in 2013 from 2012 is mainly due to lower production volumes resulting from asset dispositions closed in late 2012 and the monetization of crude oil collars and foreign exchange contracts in 2012. Funds flow in 2012 decreased from 2011 as a result of lower commodity price realizations and disposition activity.

The decline in net income in 2013 compared to 2012 was largely due to impairment charges recorded on certain natural gas assets as a result of limited planned development capital and changes to lower estimated reserve recoveries in Manitoba. Lower revenues from lower production volumes due to disposition activity and unrealized foreign exchange losses from the weakening of the Canadian dollar compared to the US dollar also contributed to the decrease.

In 2012, net income decreased from 2011 as lower revenues from the decline in commodity prices and an impairment charge on legacy natural gas properties were partially offset by gains from property dispositions and risk management gains.

PENN WEST 2013 MANAGEMENT’S DISCUSSION AND ANALYSIS 13

	Year ended December 31
	2013						2012						2011
	per boe			%			per boe			%			per boe			%
Oil and natural gas revenues (1)	$	57.50			100		$	55.63			100		$	60.54			100
Royalties		(10.29	)		(18	)		(10.07	)		(18	)		(11.09	)		(18	)
Operating expenses (2)		(17.30	)		(30	)		(17.26	)		(31	)		(17.40	)		(29	)
Transportation		(0.59	)		(1	)		(0.50	)		(1	)		(0.49	)		(1	)
Net operating income		29.32			51			27.80			50			31.56			52
General and administrative expenses		(3.24	)		(6	)		(2.91	)		(6	)		(2.38	)		(4	)
Restructuring		(0.76	)		(1	)		(0.23	)		—			—			—
Share-based compensation – cash		(0.34	)		(1	)		(0.14	)		—			(0.15	)		—
Financing (3)		(3.73	)		(6	)		(3.37	)		(6	)		(3.20	)		(5	)
Income tax refund		0.13			—			—			—			—			—
Funds flow		21.38			37			21.15			38			25.83			43
Unrealized foreign exchange gain (loss)		(2.56	)		(4	)		0.54			1			(0.64	)		(1	)
Share-based compensation		(0.31	)		(1	)		0.31			—			(1.26	)		(2	)
Risk management activities (4)		(0.93	)		(2	)		2.55			5			0.55			1
Depletion, depreciation and impairment		(21.29	)		(37	)		(21.17	)		(38	)		(19.62	)		(32	)
PP&E (impairment) recovery		(15.05	)		(26	)		(4.69	)		(8	)		0.17			—
Goodwill impairment		(0.98	)		(2	)		—			—			—			—
Accretion		(0.87	)		(1	)		(0.90	)		(2	)		(0.76	)		(1	)
Gain (loss) on dispositions		(0.29	)		—			6.08			11			2.53			4
Exploration and evaluation		(0.89	)		(2	)		(0.29	)		(1	)		(0.25	)		(1	)
Deferred tax recovery (expense)		4.80			8			(1.07	)		(2	)		3.80			6
Net income (loss)	$	(16.99	)		(30	)	$	2.51			4		$	10.35			17

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

(2) Operating expenses include realized gains/ losses on electricity swaps.

(3) Financing expenses include realized losses on interest rate swaps.

(4) Risk management activities relate to unrealized gains and losses on derivative instruments.

Drilling

	Year ended December 31
	2013					2012
	Gross		Net			Gross		Net
Oil		274		201			349		263
Natural gas		6		4			23		19
Dry		1		1			—		—
		281		206			372		282
Stratigraphic and service		41		18			72		32
Total		322		224			444		314
Success rate (1)				99	%				100	%

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

PENN WEST 2013 MANAGEMENT’S DISCUSSION AND ANALYSIS 14

Capital Expenditures

	Year ended December 31
(millions)	2013			2012			2011
Land acquisition and retention	$	4		$	37		$	181
Drilling and completions		543			1,148			1,217
Facilities and well equipping		332			675			521
Geological and geophysical		10			13			9
Corporate		10			16			25
Capital carried by partners		(83	)		(137	)		(107	)
Development capital expenditures (1)		816			1,752			1,846
Property dispositions, net		(525	)		(1,615	)		(266	)
Business combinations		—			—			286
Total expenditures	$	291		$	137		$	1,866

(1) Exploration and development capital includes costs related to Property, Plant and Equipment and Exploration and Evaluation activities.

In the second half of 2013, our development programs were focused on the Cardium, Viking and Slave Point, consistent with our long-term strategy. Capital expenditures have decreased compared to 2012 and 2011 as we re-focused our development plans and reduced our drilling and completions cost per well.

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

	Year ended December 31
(millions)	2013		2012		2011
E&E capital expenditures	$	80	$	228	$	321

During 2013, we had non-cash E&E expenses of $44 million (2012 – $17 million) primarily related to land expiries and to minor properties which have no capital allocations in our long-term strategy.

Gain (loss) on asset dispositions

	Year ended December 31
(millions)	2013			2012		2011
Gain (loss) on asset dispositions	$	(14	)	$	359	$	151

The gains and losses recorded in each year relate to non-core property dispositions. In 2013, we completed the phase one portion of our disposition strategy outlined in our long-term plan and divested non-core assets to improve our balance sheet and focus our operations. We realized net proceeds of $525 million from our net disposition activity during the year which had associated production of approximately 11,000 boe per day, weighted 65 percent to liquids. Proceeds were applied to our credit facility.

Goodwill

	Year ended December 31
(millions)	2013		2012		2011
Balance, beginning and end of year	$	1,912	$	1,966	$	1,991

We recorded goodwill on our acquisitions of Petrofund Energy Trust, Canetic Resources Trust and Vault Energy Trust in prior years. In 2013, we reduced our goodwill balance by $54 million as a result of allocating goodwill to non-core property dispositions completed in prior years of which $25 million related to 2012 and $29 million related to prior years. The goodwill reduction in 2012 recorded against gains on dispositions and resulted in a decrease to earnings per share of $0.06. The reduction to years prior to this was offset to January 1, 2012 retained earnings. We recorded an impairment charge of $48 million related to a non-core play to which goodwill was associated and disposed of $6 million related to non-core asset dispositions during 2013.

PENN WEST 2013 MANAGEMENT’S DISCUSSION AND ANALYSIS 15

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.

Liquidity and Capital Resources

Capitalization

	As at December 31
	2013			2012			2011
(millions)	%			%			%
Common shares issued, at market (1)	$	4,338	60	$	5,176	62	$	9,517	71
Bank loans and long-term notes		2,458	34		2,690	33		3,219	24
Working capital (net) (2)		402	6		450	5		645	5
Total enterprise value	$	7,198	100	$	8,316	100	$	13,381	100

(1) The share price at December 31, 2013 was $8.87 (2012—$10.80 and 2011—$20.19).

(2) Excludes the current portion of deferred funding asset, risk management and long-term debt.

Dividends

	Year ended December 31
(millions)	2013		2012		2011
Dividends declared	$	397	$	514	$	506
Per share		0.82		1.08		1.08
Dividends paid (1)	$	458	$	512	$	420

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

In June 2013, we announced a change in our quarterly dividend to $0.14 per share from $0.27 per share effective for our third quarter dividend.

On March 6, 2014, we declared our first quarter dividend of $0.14 per share to be paid on April 15, 2014 to shareholders of record on March 31, 2014. Shareholders are advised that this dividend is designated as an “eligible dividend” for Canadian income tax purposes.

PENN WEST 2013 MANAGEMENT’S DISCUSSION AND ANALYSIS 16

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. For further information regarding our dividend policy, including the factors that could affect the amount of quarterly dividend that we pay and the risks relating thereto, see “Dividends and Dividend Policy – Dividend Policy” in our Annual Information Form, which is available on our website at www.pennwest.com, on the SEDAR website at www.sedar.com, and on the SEC website at www.sec.gov.

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 capital structure. We 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 December 31, 2013, the Company was in compliance with all of these financial covenants which consist of the following:

	Limit	December 31, 2013
Senior debt to EBITDA (1)	Less than 3:1		2.2
Total debt to EBITDA (1)	Less than 4:1		2.2
Senior debt to capitalization	Less than 50%		24	%
Total debt to capitalization	Less than 55%		24	%

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

The 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.

PENN WEST 2013 MANAGEMENT’S DISCUSSION AND ANALYSIS 17

Financial Instruments

We had the following financial instruments outstanding as at December 31, 2013. 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		10,000 bbls/d	Jan/14 – Jun/14		US$93.20 to $101.00/bbl			$—
WTI Swaps		20,000 bbls/d	Jan/14 – Jun/14		US$93.74/bbl			(15	)
Natural gas
AECO Forwards		90,000 mcf/d	Jan/14 – Dec/14		$3.90/mcf			—
AECO Collars		50,000 mcf/d	Jan/14 – Dec/14		$3.41 to $4.17/mcf			(2	)
Electricity swaps
Alberta Power Pool		70 MW	Jan/14 – Dec/14		$58.50/MWh			(3	)
Alberta Power Pool		10 MW	Jan/14 – Dec/15		$58.50/MWh			(1	)
Alberta Power Pool		70 MW	Jan/15 – Dec/15		$56.43/MWh			(4	)
Alberta Power Pool		25 MW	Jan/16 – Dec/16		$49.90/MWh			—
Interest rate swaps		$650	Jan/14		2.65	%		(1	)
Foreign exchange forwards on senior notes
3 to 15-year initial term		US$641	2014 – 2022		1.000 CAD/USD			50
Cross currency swaps
10-year initial term		£57	2018		2.0075 CAD/GBP, 6.95%			(12	)
10-year initial term		£20	2019		1.8051 CAD/GBP, 9.15%			—
10-year initial term		€10	2019		1.5870 CAD/EUR, 9.22%			—
Total								$12

Subsequent to December 31, 2013, we entered into AECO collars in 2015 on 70,000 mcf per day between $3.69 per mcf and $4.52 per mcf and foreign exchange forward contracts on revenue from January 2014 to June 2014 on $84 million per month at a floor of 1.0775 CAD/USD and a ceiling of 1.1050 CAD/USD.

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

PENN WEST 2013 MANAGEMENT’S DISCUSSION AND ANALYSIS 18

Outlook

This outlook section is included to provide shareholders with information about our expectations as at March 6, 2014 for production and capital expenditures in 2014 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 2014, including our non-core asset disposition program.

For 2014, our development capital expenditures budget is $900 million. Our forecast 2014 average production is 101,000 boe per day to 106,000 boe per day.

For the first quarter of 2014, we expect our development capital budget to be approximately $230 million.

There have been no changes to our guidance from our 2014 forecast average production outlined in our January 21, 2014 press release “Penn West Provides Fourth Quarter 2013 Operational Update and Announces Additional Non-Core Asset Dispositions for Expected Proceeds of Approximately $175 Million” and our 2014 development capital expenditures budget outlined in our November 6, 2013 press release “Penn West Announces its Financial Results for the Third Quarter Ended September 30, 2013” released and filed on SEDAR at www.sedar.com and on EDGAR at www.sec.gov.

Sensitivity Analysis

Estimated sensitivities to selected key assumptions on funds flow 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		16		0.03
Liquids production	1,000 bbls/day		25		0.05
Price per mcf of natural gas	$0.10		—		—
Natural gas production	10 mmcf/day		6		0.01
Effective interest rate	1%		3		0.01
Exchange rate ($US per $CAD)	$0.01		16		0.03

PENN WEST 2013 MANAGEMENT’S DISCUSSION AND ANALYSIS 19

Contractual Obligations and Commitments

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

(millions)	2014		2015		2016		2017		2018		Thereafter
Long-term debt	$	64	$	265	$	631	$	258	$	474	$	766
Transportation		55		73		61		57		55		306
Power infrastructure		14		14		14		14		14		11
Drilling rigs		11		15		11		6		—		—
Purchase obligations (1)		5		5		1		1		1		—
Interest obligations		138		127		107		84		63		84
Office lease (2)		58		58		57		54		54		347
Decommissioning liability (3)	$	75	$	72	$	70	$	84	$	86	$	216

(1) These amounts represent estimated commitments of $8 million for CO₂ purchases and $5 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 $306 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 30, 2016. If we are not successful in renewing or replacing the facility, we could be required to obtain other facilities including term bank loans. In addition, we have an aggregate of $2.1 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 December 31, 2013	489,077,284
Issued pursuant to dividend reinvestment plan	1,611,664
As at March 6, 2014	490,688,948
Options outstanding:
As at December 31, 2013	14,951,830
Forfeited	(375,635	)
As at March 6, 2014	14,576,195
Share Rights outstanding:
As at December 31, 2013	40,310
Forfeited	(4,800	)
As at March 6, 2014	35,510
Restricted Options outstanding (1):
As at December 31, 2013	3,055,414
Forfeited	(161,506	)
As at March 6, 2014	2,893,908

(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.

PENN WEST 2013 MANAGEMENT’S DISCUSSION AND ANALYSIS 20

Fourth Quarter 2013 Highlights

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

	Three months ended December 31
	2013			2012			% change
Financial
(millions, except per share amounts)
Gross revenues (1)	$	613		$	799			(23	)
Funds flow		216			295			(27	)
Basic per share		0.44			0.62			(29	)
Diluted per share		0.44			0.62			(29	)
Net loss		(728	)		(78	)		(100	)
Basic per share		(1.49	)		(0.16	)		(100	)
Diluted per share		(1.49	)		(0.16	)		(100	)
Development capital expenditures (2)		208			348			(40	)
Property acquisition (disposition), net	$	(473	)	$	(1,264	)		(63	)
Dividends
(millions)
Dividends paid (3)	$	68		$	129			(47	)
DRIP		(14	)		(31	)		(55	)
Dividends paid in cash	$	54		$	98			(45	)
Operations
Daily production
Light oil and NGL (bbls/d)		64,056			82,224			(22	)
Heavy oil (bbls/d)		14,601			16,847			(13	)
Natural gas (mmcf/d)		272			329			(17	)
Total production (boe/d)		123,995			153,931			(19	)
Average sales price
Light oil and NGL (per bbl)	$	77.43		$	75.91			2
Heavy oil (per bbl)		58.66			59.85			(2	)
Natural gas (per mcf)	$	3.53		$	3.28			8
Netback per boe
Sales price	$	54.65		$	54.10			1
Risk management gain		0.62			0.51			22
Net sales price		55.27			54.61			1
Royalties		(10.13	)		(10.10	)		—
Operating expenses		(17.86	)		(17.16	)		4
Transportation		(0.62	)		(0.51	)		22
Netback	$	26.66		$	26.84			(1	)

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

(2) Includes the effect of capital carried by partners.

(3) Includes dividends paid prior to amounts reinvested in shares under the dividend reinvestment plan.

PENN WEST 2013 MANAGEMENT’S DISCUSSION AND ANALYSIS 21

Financial

Gross revenues and funds flow decreased in the fourth quarter of 2013 compared to 2012 primarily due to lower production volumes as a result of asset dispositions occurring in both periods.

Net loss increased during the fourth quarter of 2013 compared to 2012 primarily due to non-cash impairment charges on certain non-core natural gas assets due to limited planned development capital and lower estimated reserve recoveries in Manitoba.

We closed non-core asset dispositions during the fourth quarter for proceeds of $486 million. The proceeds were applied to reduce bank debt.

Operations

Development capital was $208 million during the fourth quarter of 2013 as we concentrated our drilling program in the Lodgepole and Crimson Lake areas of the Cardium and Dodsland area of the Viking and drilled a total of 56 net wells. Additionally, we initiated a waterflood pilot in the Willesden Green area of the Cardium.

Average production in the fourth quarter of 2013 was 123,995 boe per day after the impact of net asset dispositions. During the fourth quarter of 2013, we completed net asset dispositions with combined production of approximately 10,800 boe per day.

In the fourth quarter of 2013, WTI crude oil prices averaged US$97.50 per barrel compared to US$105.80 per barrel in the third quarter of 2013 and US$88.20 per barrel for the fourth quarter of 2012. Differentials widened during the period with Edmonton light sweet oil trading at a discount of $15.02 per barrel to WTI during the fourth quarter of 2013 (2012 – $3.46 per barrel) compared to a discount of $4.80 per barrel during the third quarter of 2013. In the fourth quarter of 2013, the AECO Monthly Index averaged $3.15 per mcf compared to $2.67 per mcf in the third quarter of 2013 and $3.06 per mcf for the fourth quarter of 2012.

Netbacks were comparable quarter over quarter at $26.66 per boe compared to $26.84 per boe in the fourth quarter of 2012.

Disclosure Controls and Procedures

As of December 31, 2013, an internal evaluation was carried out under the supervision of our President and Chief Executive Officer (the “CEO”) and Executive Vice President and Chief Financial Officer (the “CFO”) of the effectiveness of Penn West’s disclosure controls and procedures as defined in Rule 13a-15 under the US Securities Exchange Act of 1934 (the “Exchange Act”) and as defined in Canada by National Instrument 52-109, Certification of Disclosure in Issuers’ Annual and Interim Filings (“NI 52-109”). Based on that evaluation, the CEO and the CFO concluded that as of December 31, 2013 the disclosure controls and procedures were effective to provide reasonable assurance that the information required to be disclosed in the reports that Penn West files or submits under the Exchange Act or under Canadian securities legislation is recorded, processed, summarized and reported, within the time periods specified in the rules and forms therein. Disclosure controls and procedures include, without limitation, controls and procedures designed to ensure that information required to be disclosed by an issuer in the reports that it files or submits under the Exchange Act is accumulated and communicated to the issuer’s management, including its CEO and CFO, or persons performing similar functions, as appropriate to allow timely decisions regarding required disclosure.

PENN WEST 2013 MANAGEMENT’S DISCUSSION AND ANALYSIS 22

Internal Control over Financial Reporting (“ICOFR”)

Our management is responsible for establishing and maintaining adequate internal control over financial reporting (ICOFR). As of December 31, 2013, an internal evaluation was carried out by management under the supervision and with the participation of our CEO and CFO of the effectiveness of our ICOFR as defined in Rule 13a-15 under the Exchange Act and as defined in Canada by NI 52-109. The assessment was based on the framework in Internal Control – Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO 1992). Based on that evaluation, management concluded that as of December 31, 2013 our ICOFR was effective. We have certified our ICOFR and obtained auditor attestation of the operating effectiveness of our internal control over financial reporting in conjunction with our 2013 year-end audited consolidated financial statements.

Our internal control over financial reporting as of December 31, 2013 has been audited by KPMG LLP, an independent registered public accounting firm, as stated in their attestation report which is included herein.

In 2013, we reduced our goodwill balance by $54 million to reflect goodwill being associated with asset dispositions of prior years, this change was made retroactively. As a result, we made enhancements to our methodology for associating goodwill to cash generating units and dispositions. No other changes in our ICOFR were made during the year ended December 31, 2013 that have materially affected, or are reasonably likely to materially affect, our ICOFR.

New Accounting Pronouncements

During 2013, we adopted the following standards all of which were applied retroactively except for IFRS 13 and the IAS 36 amendment which was applied prospectively.

IFRS 7 “Financial Instruments - Disclosures” was amended, effective January 1, 2013, outlining new disclosure requirements when offsetting financial assets and liabilities. The additional disclosure requirements have been reflected in this reporting period.

IFRS 10 “Consolidated Financial Statements” outlines a new methodology to determine whether to consolidate an investee. This new standard became effective on January 1, 2013. There was no impact to us on adoption of this standard.

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 became effective on January 1, 2013 and applies to our interest in the Peace River Oil Partnership. We determined that our interest in the Peace River Oil Partnership continues to be a joint operation under the new standard; thus continue to proportionately record its interest in the assets, liabilities, revenue, and expenses in the Partnership.

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 became effective on January 1, 2013. We have updated our disclosures as required.

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 became effective on January 1, 2013. There was no impact to us on adoption of this standard.

IAS 36 “Impairment of assets” was amended to reverse the unintended requirement in IFRS 13 “Fair Value Measurement” to disclose the recoverable amount of every cash-generating unit to which significant goodwill or indefinite-lived intangible assets have been allocated. Under the amendments, recoverable amount is required to be disclosed only when an impairment loss has been recognized or reversed. We have early adopted these amendments and updated our disclosures as required.

PENN WEST 2013 MANAGEMENT’S DISCUSSION AND ANALYSIS 23

Future Accounting Pronouncements

In May 2011, the International Accounting Standards Board issued IFRS 9 “Financial Instruments” which outlines a new methodology for the recognition and measurement requirements for financial instruments. This new standard will eventually replace IAS 39 “Financial Instruments: Recognition and Measurement”. This standard is still in development and no effective date has been set; therefore, we cannot assess the impact of this standard at this time.

The International Accounting Standards Board issued amendments to IAS 32, “Financial Instruments: Presentation”, which clarify the requirements for offsetting financial assets and liabilities. The amendments clarify when an entity has a legally enforceable right to offset and certain other requirements that are necessary to present a net financial asset or liability. The amendments are required to be applied retrospectively for annual periods beginning on or after January 1, 2014. We are currently assessing the impact of this standard at this time.

In May 2013, IFRIC 21 “Levies” was issued and provides guidance on accounting for levies in accordance with the requirements of IAS 37, “Provisions, Contingent Liabilities and Contingent Assets”. The interpretation defines a levy as an outflow from an entity imposed by a government in accordance with legislation. It also notes that levies do not arise from executory contracts or other contractual arrangements. The interpretation also confirms that an entity recognizes a liability for a levy only when the triggering event specified in the legislation occurs. This IFRIC is effective for annual periods commencing on or after January 1, 2014 and is to be applied retrospectively. We intend to adopt IFRIC 21 in our financial statements for the annual period beginning January 1, 2014. The extent of the impact of adoption of the amendments has not yet been determined.

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.

Critical Accounting Estimates

Our significant accounting policies are detailed in Note 3 to our audited consolidated financial statements. In the determination of financial results, we must make certain critical accounting estimates as follows:

Depletion and Impairments

Costs of developing oil and natural gas reserves are capitalized and depleted against associated oil and natural gas production using the unit-of-production method based on the estimated proved plus probable reserves with forecast commodity pricing.

All of our reserves were evaluated or audited by Sproule Associates Limited (“SAL”), an independent, qualified reserve evaluation engineering firm. Our reserves are determined in compliance with National Instrument 51-101. The evaluation of oil and natural gas reserves is, by its nature, based on complex extrapolations and models as well as other significant engineering, reservoir, capital, pricing and cost assumptions. Reserve estimates are a key component in the calculation of depletion and are an important component in determining the recoverable amount in impairment tests. 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, the latter of which is based on its discounted future cash flows using an applicable discount rate. To the extent that the recoverable amount, which could be based in part on our reserves, is less than the carrying amount of property, plant and equipment, a write-down against income is recorded. In 2013, we recorded a before tax impairment charge totalling $742 million related to certain non-core natural gas assets in British Columbia and Alberta due to limited planned development capital and in Manitoba due to lower estimated reserve recoveries. In 2012, we recorded a $277 million impairment related to certain properties in northern British Columbia, primarily due to weak forward natural gas price forecasts on December 31, 2012.

PENN WEST 2013 MANAGEMENT’S DISCUSSION AND ANALYSIS 24

Decommissioning Liability

The decommissioning liability is the present value of our future statutory, contractual, legal or constructive obligations to retire long-lived assets including wells, facilities and pipelines. The liability is recorded 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 liability amount through accretion charges to income. Revisions to the estimated amount or timing of the obligations are reflected as increases or decreases to the recorded decommissioning liability. Actual decommissioning expenditures are charged to the liability to the extent of the then-recorded liability. Amounts capitalized to the related assets are amortized to income consistent with the depletion or depreciation of the underlying asset. Note 10 to our audited consolidated financial statements details the impact of these accounting standards.

Financial Instruments

Financial instruments included in the balance sheets consist of accounts receivable, fair values of derivative financial instruments, current liabilities and long-term debt. Except for the senior notes, 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 debt. The estimated fair value of the senior notes is disclosed in Note 9 to our audited consolidated financial statements.

Our revenues from the sale of crude oil, natural gas liquids and natural gas are directly impacted by changes to the underlying commodity prices. To ensure that funds flows are sufficient to fund planned capital programs and dividends, financial instruments including collars may be utilized from time to time. Collars ensure that commodity prices realized will fall into a contracted range for a contracted sales volume.

Substantially all of our accounts receivable are with customers in the oil and natural gas industry and are subject to normal industry credit risk. We may, from time to time, use various types of financial instruments to reduce our exposure to fluctuating oil and natural gas prices, electricity costs, exchange rates and interest rates. The use of these financial instruments exposes us to credit risks associated with the possible non-performance of counterparties to the derivative contracts. We limit this risk by executing counterparty risk procedures which include transacting only with financial institutions who are members of our credit facility or those with high credit ratings as well as obtaining security in certain circumstances.

Goodwill

Goodwill is recorded on a business combination when the total purchase consideration exceeds the fair value of the net identifiable assets and liabilities of the acquired entity. The goodwill balance is not amortized; however, it must be assessed for impairment at least annually. In 2013, we recorded a $48 million goodwill impairment charge related to a non-core play to which goodwill was associated.

Deferred Tax

Deferred taxes are recorded based on the liability method of accounting whereby temporary differences are calculated assuming financial assets and liabilities will be settled at their carrying amount. Deferred taxes are computed on temporary differences using substantively enacted income tax rates expected to apply when future income tax assets and liabilities are realized or settled.

PENN WEST 2013 MANAGEMENT’S DISCUSSION AND ANALYSIS 25

Forward-Looking Statements

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”, “budget”, “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: under “Business Strategy”, our belief that our five-year plan positions us as a leading oil producer in the Western Canadian Sedimentary basin and the key features of the long-term strategy, including the promotion of operational excellence across all levels of the Company, focusing our development activities on projects with the highest returns in three of our core areas (Cardium, Viking, Slave Point), non-core asset rationalization including $1.5 to $2 billion of asset dispositions, debt reduction, continuing to drive cost reductions and a sustainable dividend strategy moving forward, our intention in 2014 to continue to focus on the key strategies outlined in our long-term plan, and our expectation that we will close the recently announced $175 million disposition in the first quarter of 2014; under “Crude Oil”, our suggestion that the completion of certain pipeline projects could ease current pipeline constraints out of Western Canada; under “Natural Gas”, our assertion that natural gas is not currently positioned to increase market share from coal in the power generation sector should power demand increase; under “Performance Indicators”, our intention that in 2014 our development plans will emphasize the Cardium, Viking and Slave Point areas and increased application of waterflood programs, our plans for further non-core asset dispositions as part of our strategy to increase the focus of our portfolio and strengthen our balance sheet, our belief that funds flow per share is an important measure to drive shareholder returns and that increases in this metric are correlated to share price, our belief that dividends impose natural capital investment limits on management and thus may limit shareholder exposure to excessive operational and other risks, our expectation that our net debt to funds flow ratio will improve in future years as we continue to de-lever our balance sheet and focus on light-oil, higher return projects, our intention as we move forward to focus development in three main light-oil areas (the Cardium, Slave Point and Viking), our intention to focus on cost reduction to realize improvements in our netbacks which in turn drives higher funds flow, and our target for a 110 percent sustainability ratio in our long-term plan; under “Environmental and Climate Change”, our dedication to reducing the environmental impact from our operations through our environmental programs and our intention to continuously monitor our operations to minimize the environmental impact thereof and to allocate sufficient capital to reclamation and other activities to mitigate the impact on the areas in which we operate; under “Liquidity and Capital Resources”, the details of our first quarter dividend, the factors that could affect future cash dividend levels, and our belief that our debt and risk management actions and plans may 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; under “Outlook”, our forecast 2014 annual and first quarter development capital expenditure budgets and 2014 average daily production volumes; and certain disclosures contained under the heading “Sensitivity Analysis” relating to our estimated sensitivities to selected key assumptions on our future funds flow.

With respect to forward-looking statements contained in this document, we have made assumptions regarding, among other things: the terms and timing of asset sales completed under our ongoing program to sell between $1.5 billion and $2.0 billion of non-core assets, including the asset sale anticipated to close in the first quarter of 2014; our ability to execute or long-term plan as described herein and the impact that the successful execution of such plan will have on our Company and our shareholders; 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 and natural gas 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; the stability of the regulatory environment in which we operate and the likelihood of our obtaining regulatory approvals and of other regulatory outcomes; our ability to market our oil and natural gas successfully to current and new customers, including our ability to access rail, pipeline and other transportation infrastructure; our ability to obtain financing on acceptable

PENN WEST 2013 MANAGEMENT’S DISCUSSION AND ANALYSIS 26

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”.

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 possibility that we are unable to execute some or all of our ongoing non-core asset disposition program on favourable terms or at all, including the disposition discussed herein that is scheduled to close in the first quarter of 2014, whether due to the failure to receive requisite regulatory approvals or satisfy applicable closing conditions or for other reasons that we cannot anticipate; the possibility that we will not be able to successfully execute our long-term plan in part or in full, and the possibility that some or all of the benefits that we anticipate will accrue to our Company and our securityholders as a result of the successful execution of such plan do not materialize; 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 and political 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 and natural gas produced in Canada as compared to other markets and transportation restrictions, including pipeline and railway capacity constraints; royalties payable in respect of our oil and natural gas production and changes to government royalty frameworks; 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 extreme cold during winter months, wild fires and flooding; failure to obtain regulatory, industry partner and other third-party consents and approvals when required, including for acquisitions, dispositions and mergers; failure to realize the anticipated benefits of dispositions, acquisitions, joint ventures and partnerships, including those discussed herein; uncertainties regarding decisions and outcomes on oil and natural gas facilities and other assets jointly owned with and in some cases operated by third parties; changes in tax and other laws that affect us and our securityholders; the potential failure of counterparties to honour their contractual obligations; 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; 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.

PENN WEST 2013 MANAGEMENT’S DISCUSSION AND ANALYSIS 27