Penn West Announces its Financial Results for the Fourth Quarter and Year Ended December 31, 2013 and 2013 Reserve Results

March 7, 2014 4:36 AM

CALGARY, March 7, 2014 /CNW/ – PENN WEST PETROLEUM LTD. (TSX – PWT) (NYSE – PWE) (“PENN WEST” or the “COMPANY”) is pleased to announce its results for the fourth quarter and year ended December 31, 2013. All figures are in Canadian dollars unless otherwise stated.


		Three months ended December 31						Year ended December 31
				2013		2012	% change		2013		2012	% change
Financial (millions, except per share amounts)
Gross revenues ^(1,2)			$	613	$	799	(23)	$	2,835	$	3,283	(14)
Funds flow ⁽²⁾				216		295	(27)		1,054		1,248	(16)
	Basic per share ⁽²⁾			0.44		0.62	(29)		2.17		2.62	(17)
	Diluted per share ⁽²⁾			0.44		0.62	(29)		2.17		2.62	(17)
Net income (loss)				(728)		(78)	(100)		(838)		149	(100)
	Basic per share			(1.49)		(0.16)	(100)		(1.72)		0.31	(100)
	Diluted per share			(1.49)		(0.16)	(100)		(1.72)		0.31	(100)
Development capital expenditures ⁽³⁾				208		348	(40)		816		1,752	(53)
Long-term debt at period-end			$	2,458	$	2,690	(9)	$	2,458	$	2,690	(9)

Dividends (millions)
Dividends paid ⁽⁴⁾			$	68	$	129	(47)	$	458	$	512	(11)
DRIP				(14)		(31)	(55)		(95)		(117)	(19)
Dividends paid in cash			$	54	$	98	(45)	$	363	$	395	(8)

Operations
Daily production (average)
	Light oil and NGL (bbls/d)			64,056		82,224	(22)		69,587		86,783	(20)
	Heavy oil (bbls/d)			14,601		16,847	(13)		15,511		17,361	(11)
	Natural gas (mmcf/d)			272		329	(17)		300		342	(12)
Total production (boe/d) ⁽⁵⁾				123,995		153,931	(19)		135,093		161,195	(16)
Average sales price
	Light oil and NGL (per bbl)		$	77.43	$	75.91	2	$	83.25	$	77.16	8
	Heavy oil (per bbl)			58.66		59.85	(2)		65.12		63.67	2
	Natural gas (per mcf)		$	3.53	$	3.28	8	$	3.31	$	2.45	35
Netback per boe
	Sales price		$	54.65	$	54.10	1	$	57.71	$	53.60	8
	Risk management gain			0.62		0.51	22		0.16		0.81	(80)
	Net sales price			55.27		54.61	1		57.87		54.41	6
	Royalties			(10.13)		(10.10)	–		(10.29)		(10.07)	2
	Operating expenses			(17.86)		(17.16)	4		(17.30)		(17.26)	–
	Transportation			(0.62)		(0.51)	22		(0.59)		(0.50)	18
	Netback ⁽²⁾		$	26.66	$	26.84	(1)	$	29.69	$	26.58	12

(1)	Gross revenues include realized gains and losses on commodity contracts.
(2)	The terms “gross revenues”, “funds flow”, “funds flow per share-basic”, “funds flow per share-diluted” and “netback” are non-GAAP measures. Please refer to the “Calculation of Funds Flow” and “Non-GAAP Measures Advisory” sections below.
(3)	Includes the effect of capital carried by partners.
(4)	Includes dividends paid prior to amounts reinvested in shares under the dividend reinvestment plan.
(5)	Please refer to the “Oil and Gas Information Advisory” section below for information regarding the term “boe”.

PRESIDENT’S MESSAGE

Four months ago, we began discussing a new vision for Penn West. We promised focus on the Company’s industry leading light-oil positions in the Western Canada Sedimentary Basin; application of best-in-class operating practices; relentless cost control; and to de-lever the balance sheet to deliver shareholder value. We are pleased to say we are on plan.

We have instilled a value-first culture at Penn West in which we challenge the cost/benefit of every activity we engage in and question the profitability of every barrel we produce. We are ahead of our asset disposition plans to date, achieving better than planned realizations from a net operating income multiple perspective, and our organization is 35 percent smaller than the beginning of 2013. Our capital efficiency improvements continue as we realize game changing capital cost reductions across our key plays.

Our 2013 development capital totaled $816 million compared to a $900 million budget with more activity completed than planned. We are already at or within reach of our per well capital cost targets outlined in our long-term plan and will continue to drive efficiencies to further enhance returns and extend the economic longevity of our plays. These improvements were also a component of our strong finding and development (“F&D”) cost performance in 2013. Inclusive of the change in future development costs, our proved plus probable F&D costs were $9.47 per boe ⁽¹⁾ in 2013 with 76 percent of additions comprising oil and natural gas liquids. This compares to $25.50 per boe in 2012, a 63 percent improvement to an important capital investment indicator. Excluding the change in future development costs, the proved plus probable F&D cost was $17.17 per boe and is in line with our operated development capital cost target of $15 – $20 per boe in our long-term plan.

Another cornerstone of our business plan is to operate in a continuous and deliberate manner to drive cost efficiencies and predictable production performance. Our teams are already operating under these principles with the expectation that our production profile will shift as the effects of the front-end loaded programs of the past dissipate. In the Cardium, we have been running ahead of cost, time and performance expectations – including best-in-play drilling performance – and anticipate being able to advance drilling activities above our stated business plan in 2014 and future years within the planned capital allocations. With the testing of drilling and completion techniques to significantly reduce costs in the Slave Point and industry leading cost and well performance in the Viking, our organizational energy is being fueled by success. Waterflood programs across these assets, pivotal to sustainable performance, are proceeding as planned.

To date in 2014, we have benefited from stronger than planned commodity prices and a favorable currency climate; however, we remain conservative in our commodity outlook for the remainder of the year. Operating excellence and investment discipline will continue to be key organic levers while we progress through phase two of our asset divestiture strategy and deliver a laser focused portfolio and improve our balance sheet.

FOURTH QUARTER KEY POINTS

Non-core asset dispositions totalling approximately $486 million with associated production of 10,800 boe per day were closed in the fourth quarter of 2013. Asset dispositions in 2013 resulted in an approximate $90 million reduction to our decommissioning liability.
As a result of our focus on cost reductions, our recycle ratio ⁽²⁾, on a proved plus probable basis and including the change in future development costs (“FDC”), improved to 3.1 in 2013 compared to 1.0 in 2012.
Development capital was $208 million for the fourth quarter of 2013 and $816 million for 2013. For 2013, our development capital came in below our budget of $900 million primarily due to the cost reductions we realized across our plays.
Further operational improvements were experienced during the fourth quarter with continued reduction in drilling and completion costs and cycle times, notably in the Lodgepole and Crimson Lake areas of the Cardium and the Dodsland area of the Viking.

(1)	For detailed calculations and disclaimers, see “Finding and Development costs” below.
(2)	Recycle ratio is a non-GAAP measure. Please refer to our “Non-GAAP Measures Advisory” section below.

RESERVE HIGHLIGHTS

Proved plus probable finding and development cost (“F&D”) including the change in FDC for 2013 was $9.47 per boe (2012 – $25.50 per boe). The improvement includes the effects of reductions in FDC due to significant declines in our drilling and completion costs and removal of certain capital costs associated with properties no longer carrying reserves, and technical revisions to our current reserve base.
Excluding the impact of dispositions, our reserve replacement ratio ⁽¹⁾ was 97 percent in 2013.
Total working interest (gross) proved plus probable reserves were 625 mmboe at December 31, 2013 (2012 – 676 mmboe), weighted approximately 70 percent to liquids (2012 – 71 percent), and including the effect of 50 mmboe of oil weighted asset dispositions completed in 2013.
Proved plus probable net present value discounted at 10 percent (before income taxes) remained relatively consistent year-over-year with December 31, 2013 at $8.9 billion (2012 – $9.1 billion) which included a reduction of approximately $450 million related to asset dispositions completed in 2013.
Reserve additions for 2013 were weighted 76 percent to oil, excluding technical revisions.
During 2013, we completed or updated contingent resource studies covering our interests in the Cardium, Viking, Slave Point and Swan Hills areas substantiating our appraisal activities and confirming significant recoverable oil resources in these areas.

FINANCIAL HIGHLIGHTS

Funds flow for the fourth quarter of 2013 was $216 million ($0.44 per share – basic), a decrease from $293 million ($0.60 per share – basic) in the third quarter of 2013, mainly due to lower crude oil prices and lower production volumes as a result of asset dispositions in the fourth quarter of 2013.
For the fourth quarter of 2013, we recorded a net loss of $728 million ($1.49 per share – basic). The net loss was primarily due to non-cash PP&E impairment charges and unrealized foreign exchange losses on the translation of our US denominated senior, unsecured notes.
Disposition proceeds received during 2013 were applied to our credit facilities with a net reduction in long-term debt of $356 million during the year, prior to foreign currency translations.

ASSET IMPAIRMENTS

During the fourth quarter of 2013, we recorded non-cash impairment charges of $742 million related to PP&E. These impairment charges were the result of limited planned development capital in certain non-core natural gas assets and lower estimated reserve recoveries at our Manitoba properties. Our five-year plan is focused on the integrated development of our large light-oil areas in the Cardium, Slave Point and Viking.

DIVIDENDS

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

(1)	Reserve replacement ratio is calculated by dividing reserve additions by production on a proved plus probable basis.

PLAY UPDATES

Cardium

During 2013, significant cost reductions and cycle time improvements were realized with a continued focus on further reductions as we move through 2014. Compared to 2012, drilling and completion (“D&C”) costs decreased by approximately 35 – 40 percent, notably in the Lodgepole and Crimson Lake areas. In the fourth quarter of 2013, development activities were concentrated in these two areas and we maintained momentum as we moved into the first quarter of 2014 with a four-rig program. Also in the fourth quarter, horizontal waterflood development began in the Willesden Green area with the initiation of one pilot project and the construction of another which began water injection in early 2014.

For 2014, we have allocated $270 million of development capital to the Cardium with further expansion of our planned EOR pilot work along with a focused development drilling program (67 net wells) as we continue to methodically increase our activity in the area, consistent with our five-year plan.

Viking

During 2013, we became an industry leader in the area due to significant D&C cost reductions and superior well performance. These cost savings were experienced in a short time frame with average D&C costs per well during the first half of the year of $1.2 million compared to approximately $850,000 per well in the second half; close to a 30 percent reduction. The results from our development programs, primarily in the Dodsland area, consistently exceeded both our own and competitors’ type curves. We plan to continue to build on these successes in 2014, with $150 million budgeted for the area (104 net wells) as we leverage our existing infrastructure and complete a down-spaced development program. In 2014, we have plans to initiate the first and second phases of a waterflood pilot in the Avon Hills area with the third phase beginning in 2015.

Slave Point

In the Slave Point, our fourth quarter activities were focused on a selective drilling program in the Red Earth area and the initiation of a waterflood pilot in the Otter area. For 2014 we allocated $145 million to the Slave Point with a focus on completing a low-risk development drilling program in Sawn, Otter and Red Earth (21 net wells), continued expansion of the Otter waterflood pilot and the initiation of a waterflood pilot in Sawn.

DISPOSITION UPDATE

On January 21, 2014 we announced a non-core asset disposition for expected proceeds of $175 million, expected to close in mid-March 2014. The assets to be disposed are primarily located in the central and southwestern parts of Alberta with associated production of approximately 6,700 boe per day weighted 58 percent to natural gas and 1,800 currently producing or suspended wellbores.

DRILLING STATISTICS

	Three months ended December 31				Year ended December 31
	2013		2012		2013		2012
	Gross	Net	Gross	Net	Gross	Net	Gross	Net
Oil	67	53	55	31	274	201	349	263
Natural gas	3	2	–	–	6	4	23	19
Dry	1	1	–	–	1	1	–	–
	71	56	55	31	281	206	372	282
Stratigraphic and service	5	1	9	1	41	18	72	32
Total	76	57	64	32	322	224	444	314
Success rate ⁽¹⁾		98%		100%		99%		100%

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

CAPITAL EXPENDITURES

(millions)	Three months ended December 31				Year ended December 31
(millions)	2013		2012		2013		2012
Land acquisition and retention	$	–	$	1	$	4	$	37
Drilling and completions		118		160		543		1,148
Facilities and well equipping		102		205		332		675
Geological and geophysical		1		3		10		13
Corporate		3		3		10		16
Capital carried by partners		(16)		(24)		(83)		(137)
Development capital expenditures ⁽¹⁾		208		348		816		1,752
Property acquisitions (dispositions), net		(473)		(1,264)		(525)		(1,615)
Total expenditures	$	(265)	$	(916)	$	291	$	137

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

In the fourth quarter of 2013, we increased our development activity levels in the Cardium and Viking areas by reallocating capital to these plays. Cost reductions realized during 2013 on drilling and completion activities enabled us to expand our program.

LAND

	As at December 31
	Producing			Non-producing
	2013	2012	% change		2013	2012	% change
Gross acres (000s)	4,836	5,733	(16)		2,842	2,680	6
Net acres (000s)	3,308	3,841	(14)		1,957	1,896	3
Average working interest	68%	67%	1		69%	71%	(2)

COMMON SHARE DATA

		Three months ended December 31			Year ended December 31
(millions of shares)		2013	2012	% change		2013	2012	% change
Weighted average
	Basic	489.5	478.9	2		485.8	475.6	2
	Diluted	489.5	478.9	2		485.8	475.8	2
	Outstanding as at December 31					489.1	479.3	2

RESERVES DATA

Our reserves continue to reflect a high percentage of oil and liquids at 70 percent (2012 – 71 percent) and 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). In 2013, all of our reserves were evaluated or audited by Sproule Associates Limited (“SAL”), an independent, qualified engineering firm. Approximately 25 percent of total proved plus probable reserves were internally evaluated and then audited by SAL.

The reserves estimates have been calculated in compliance with National Instrument 51-101 Standards of Disclosure for Oil and Gas Activities (“NI 51-101”). Under NI 51-101, proved reserves estimates are defined as having a high degree of certainty to be recoverable with a targeted 90 percent probability in aggregate that actual reserves recovered over time will equal or exceed proved reserve estimates. For proved plus probable reserves under NI 51-101, the targeted probability is an equal (50 percent) likelihood that the actual reserves to be recovered will be equal to or greater than the proved plus probable reserves estimate. The reserves estimates set forth below are estimates only and there is no guarantee that the estimated reserves will be recovered. Actual reserves may be greater than or less than the estimates provided herein.

a) Working Interest (Gross) Reserves using forecast prices and costs


Penn West as at December 31, 2013
Reserve	Light & Medium Oil	Heavy Oil	Natural Gas	Natural Gas Liquids	Barrels of Oil Equivalent
Estimates Category ⁽¹⁾⁽²⁾	(mmbbl)	(mmbbl)	(bcf)	(mmbbl)	(mmboe)

Proved
Developed producing	141	38	585	22	299
Developed non-producing	5	–	30	1	11
Undeveloped	72	4	142	7	106
Total Proved	218	42	757	30	415
Probable	96	40	366	13	209
Total Proved plus Probable	314	82	1,123	42	625

(1)	Working interest (gross) reserves are before royalty burdens and exclude royalty interests.
(2)	Columns may not add due to rounding.

b) Net after Royalty Interest Reserves using forecast prices and costs


Penn West as at December 31, 2013
Reserve	Light & Medium Oil	Heavy Oil	Natural Gas	Natural Gas Liquids	Barrels of Oil Equivalent
Estimates Category ⁽¹⁾⁽²⁾	(mmbbl)	(mmbbl)	(bcf)	(mmbbl)	(mmboe)

Proved
Developed producing	122	34	517	16	259
Developed non-producing	4	–	25	1	9
Undeveloped	61	3	123	5	90
Total Proved	187	38	664	22	358
Probable	80	35	316	9	176
Total Proved plus Probable	267	73	980	31	534

(1)	Net after royalty reserves are working interest reserves including royalty interests and deducting royalty burdens.
(2)	Columns may not add due to rounding.

Additional reserve disclosures, as required under NI 51-101, will be contained in our Annual Information Form that will be filed on SEDAR at www.sedar.com.

c) Reconciliation of Working Interest (Gross) Reserves using forecast prices and costs

Reconciliation Items ⁽¹⁾	Light and Medium Oil (mmbbl)			Heavy Oil (mmbbl)
Reconciliation Items ⁽¹⁾	Proved	Probable	Proved plus probable	Proved	Probable	Proved plus probable
December 31, 2012	243	108	351	46	44	90
Extensions	–	1	1	1	–	1
Infill Drilling	14	7	21	2	–	2
Improved Recovery	–	5	6	–	–	1
Technical Revisions	(9)	(17)	(26)	4	(2)	2
Acquisitions	–	–	–	–	–	–
Dispositions	(11)	(8)	(19)	(7)	(3)	(9)
Economic Factors	1	–	2	–	–	1
Production	(22)	–	(22)	(6)	–	(6)
December 31, 2013	218	96	314	41	40	82

Reconciliation Items ⁽¹⁾	Natural Gas Liquids (mmbbl)			Natural Gas (bcf)
Reconciliation Items ⁽¹⁾	Proved	Probable	Proved plus probable	Proved	Probable	Proved plus probable
December 31, 2012	27	11	38	773	413	1,186
Extensions	–	–	–	13	28	41
Infill Drilling	1	–	1	12	6	18
Improved Recovery	–	–	–	–	2	2
Technical Revisions	6	2	8	121	(8)	113
Acquisitions	–	–	–	1	–	1
Dispositions	(1)	(1)	(1)	(46)	(76)	(121)
Economic Factors	–	–	–	(8)	1	(7)
Production	(4)	–	(4)	(109)	–	(109)
December 31, 2013	30	13	42	757	366	1,123

Reconciliation Items ⁽¹⁾	Barrels of Oil Equivalent (mmboe)
Reconciliation Items ⁽¹⁾	Proved	Probable	Proved plus probable
December 31, 2012	445	231	676
Extensions	3	5	9
Infill Drilling	18	9	27
Improved Recovery	1	6	7
Technical Revisions	22	(19)	4
Acquisitions	–	–	–
Dispositions	(26)	(24)	(50)
Economic Factors	–	–	1
Production	(49)	–	(49)
December 31, 2013	415	209	625

(1)	Columns may not add due to rounding.

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. The dispositions noted in our reserve numbers are primarily attributable to the dispositions we closed during the fourth quarter of 2013.

d) Net present value of future net revenue using forecast prices and costs (millions) at December 31, 2013

		Net present value of future net revenue before income taxes (discounted @)
Reserve Category ⁽¹⁾				0%		5%		10%		15%		20%

Proved
	Developed producing		$	9,826	$	6,927	$	5,412	$	4,487	$	3,864
	Developed non-producing			279		202		156		127		107
	Undeveloped			3,465		1,923		1,157		714		432
	Total proved		$	13,570	$	9,052	$	6,726	$	5,329	$	4,403
Probable				7,991		3,785		2,153		1,353		899
Total proved plus probable			$	21,561	$	12,836	$	8,879	$	6,682	$	5,302

(1)	Columns may not add due to rounding.

Net present values take into account wellbore abandonment liabilities and are based on the price assumptions that are contained in the following table. It should not be assumed that the estimated future net revenues represent fair market value of the reserves. There is no assurance that the forecast price and cost assumptions will be attained and variances could be material.

e) Summary of pricing and inflation rate assumptions using forecast prices and costs as of December 31, 2013

	Oil
Year	WTI Cushing, Oklahoma ($US/bbl)	Edmonton Par 40^o API ($CAD/bbl)	Western Canada Select 20.5^o API ($CAD/bbl)	Cromer LSB 35^o API ($CAD/bbl)	Natural gas AECO gas price ($CAD/MMbtu)	Edmonton propane ($CAD/bbl)	Inflation rate (%)	Exchange rate (US$ equals $1 CAD)

Historical
2009	61.60	66.32	58.66	63.86	4.20	38.30	0.3	0.88
2010	79.42	78.02	67.21	76.57	4.17	44.36	1.8	0.97
2011	94.83	95.15	77.09	89.68	3.68	50.17	3.0	1.01
2012	94.15	86.70	73.08	84.42	2.44	47.20	1.5	1.00
2013	97.98	93.24	74.20	91.59	3.13	38.62	0.8	0.97
Forecast
2014	94.65	92.64	77.81	90.64	4.00	45.78	1.5	0.94
2015	88.37	89.31	75.02	87.31	3.99	44.14	1.5	0.94
2016	84.25	89.63	75.29	87.63	4.00	44.30	1.5	0.94
2017	95.52	101.62	85.36	99.62	4.93	50.22	1.5	0.94
2018	96.96	103.14	86.64	101.14	5.01	50.98	1.5	0.94
2019	98.41	104.69	87.94	102.69	5.09	51.74	1.5	0.94
2020	99.89	106.26	89.26	104.26	5.18	52.52	1.5	0.94
2021	101.38	107.86	90.60	105.86	5.26	53.30	1.5	0.94
2022	102.91	109.47	91.96	107.47	5.35	54.10	1.5	0.94
2023	104.45	111.12	93.34	109.12	5.43	54.92	1.5	0.94
Thereafter escalating at	1.5%	1.5%	1.5%	1.5%	1.5%	1.5%	–	–

f) Finding and development costs (“F&D costs”)

		Year ended December 31
		2013			2012		2011		3-Year average

F&D costs 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

F&D costs 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.

Capital expenditures for 2013 have been reduced by $83 million related to joint venture carried capital (2012 – $137 million). 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. For comparative purposes we also disclose F&D costs excluding FDC.

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.

g) Future development costs using forecast prices and costs (millions)

			At December 31, 2013
Year	Proved Future Development Costs		Proved plus Probable Future Development Costs
2014	$	704	$	840
2015		973		1,533
2016		419		726
2017		58		149
2018		35		92
2019 and subsequent		60		166
Undiscounted total	$	2,249	$	3,506
Discounted @ 10%/yr	$	1,941	$	2,958

At December 31, 2012
Undiscounted total	$	2,563	$	4,118
Discounted @10%/yr	$	2,175	$	3,411

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, our development capital budget is 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.

Non-GAAP Measures Advisory

This news release includes non-GAAP measures not defined under International Financial Reporting Standards (“IFRS”) including funds flow, funds flow per share-basic, funds flow per share-diluted, netback, gross revenues and recycle ratio. Non-GAAP measures do not have any standardized meaning prescribed by GAAP and therefore may not be comparable to similar measures presented 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 dividends and planned capital programs. See “Calculation of Funds Flow” below. Netback is a per-unit-of-production measure of operating margin used in capital allocation decisions, to economically rank projects and is the per unit of production amount of revenue less royalties, operating costs, transportation and realized risk management gains and losses. Gross revenue is total revenues including realized risk management gains and losses and is used to assess the cash realizations on commodity sales. 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.

Calculation of Funds Flow

(millions, except per share amounts)	Three months ended December 31					Year ended December 31
(millions, except per share amounts)		2013		2012		2013		2012
Cash flow from operating activities		$	329	$	441	$	1,039	$	1,193
Change in non-cash working capital			(129)		(178)		(51)		(37)
Decommissioning expenditures			16		32		66		92
Funds flow		$	216	$	295	$	1,054	$	1,248

Basic per share		$	0.44	$	0.62	$	2.17	$	2.62
Diluted per share		$	0.44	$	0.62	$	2.17	$	2.62

Oil and Gas Information Advisory

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.

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 “President’s Message” – our intention to focus on our industry leading light-oil positions in the Western Canada Sedimentary Basin, the application of best-in-class operating practices, relentless cost control and to de-lever the balance sheet to deliver shareholder value; our belief that our capital efficiency improvements will continue as we realize game changing capital cost reductions across our key plays; our intention to continue to drive efficiencies to further enhance returns and extend the economic longevity of our plays; our operated development capital cost targets in our long-term plan; our intention to operate in a continuous and deliberate manner to drive cost efficiencies and predictable production performance; our expectation that our production profile will shift as the effects of the front-end loaded programs of the past dissipate; our expectation that we will be able to advance drilling activities in the Cardium above our stated business plan in 2014 and future years within the planned capital allocations; our intention that operating excellence and investment discipline will continue to be key organic levers while we progress through phase two of our asset divestiture strategy and deliver a laser focused portfolio and improve our balance sheet; under “Dividends” – the details of our first quarter 2014 dividend payment; under “Play Updates” – the details of our exploration and development programs in 2014 and beyond on our Cardium, Viking and Slave Point plays, including the amount of capital budgeted for each play in 2014, the number of net wells we plan to drill on each play in 2014, the EOR and waterflood projects we intend to undertake, our continued focus on further cost reductions and cycle time improvements, and our plans for down-spacing; under “Disposition Update” – the details of our pending non-core asset disposition; under “Reserves Data” – the estimated future development costs of our reserves; and under “Outlook” – our forecast 2014 annual and first quarter development capital expenditures budget and forecast 2014 average daily production.

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; the economic returns anticipated from expenditures on our assets; 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 execute our capital programs as planned without significant adverse impacts from various factors beyond our control, including weather, infrastructure access and delays in obtaining regulatory approvals and third party consents; 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; 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 heading “Outlook”.

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; the impact of weather conditions on our ability to execute capital programs; the risk that we will be unable to execute our capital programs as planned without significant adverse impacts from various factors beyond our control, including weather, infrastructure access and delays in obtaining regulatory approvals and third party consents; 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; 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.

Penn West Petroleum Ltd.
Consolidated Balance Sheets

		As at December 31
(CAD millions, unaudited)		2013		2012

Assets
Current
	Accounts receivable	$	263	$	364
	Other		57		79
	Deferred funding assets		139		187
	Risk management		2		76
			461		706
Non-current
	Deferred funding assets		184		238
	Exploration and evaluation assets		645		609
	Property, plant and equipment		9,392		10,892
	Goodwill		1,912		1,966
	Risk management		50		26
			12,183		13,731
Total assets		$	12,644	$	14,437

Liabilities and Shareholders’ Equity
Current
	Accounts payable and accrued liabilities	$	654	$	764
	Dividends payable		68		129
	Current portion of long-term debt		64		5
	Risk management		24		9
			810		907
Non-current
	Long-term debt		2,394		2,685
	Decommissioning liability		603		635
	Risk management		16		35
	Deferred tax liability		1,102		1,350
	Other non-current liabilities		9		5
			4,934		5,617
Shareholders’ equity
	Shareholders’ capital		9,124		8,985
	Other reserves		80		97
	Deficit		(1,494)		(262)
			7,710		8,820
Total liabilities and shareholders’ equity		$	12,644	$	14,437

Penn West Petroleum Ltd.
Consolidated Statements of Income (Loss)

			Three months ended December 31					Year ended December 31
(CAD millions, except per share amounts, unaudited)				2013		2012		2013		2012

	Oil and natural gas sales			$	606	$	791	$	2,827	$	3,235
	Royalties				(115)		(144)		(507)		(595)
					491		647		2,320		2,640

	Risk management gain (loss)
		Realized			7		8		8		48
		Unrealized			(13)		10		(94)		156
					485		665		2,234		2,844

Expenses
	Operating				204		243		853		1,019
	Transportation				7		7		29		29
	General and administrative				34		46		160		172
	Restructuring				–		13		38		13
	Share-based compensation				2		(12)		32		(10)
	Depletion, depreciation and impairment				980		598		1,792		1,525
	Impairment of goodwill				48		–		48		–
	Loss (gain) on dispositions				19		(254)		14		(359)
	Exploration and evaluation				44		15		44		17
	Unrealized risk management loss (gain)				(21)		6		(48)		5
	Unrealized foreign exchange loss (gain)				63		22		126		(32)
	Financing				45		52		184		199
	Accretion				10		22		43		54
					1,435		758		3,315		2,632
Income (loss) before taxes					(950)		(93)		(1,081)		212

	Deferred tax expense (recovery)				(222)		(15)		(243)		63

Net and comprehensive income (loss)				$	(728)	$	(78)	$	(838)	$	149

Net income (loss) per share
	Basic			$	(1.49)	$	(0.16)	$	(1.72)	$	0.31
	Diluted			$	(1.49)	$	(0.16)	$	(1.72)	$	0.31
Weighted average shares outstanding (millions)
	Basic				489.5		478.9		485.8		475.6
	Diluted				489.5		478.9		485.8		475.8

Penn West Petroleum Ltd.
Consolidated Statements of Cash Flows

		Three months ended December 31				Year ended December 31
(CAD millions, unaudited)		2013		2012		2013		2012

Operating activities
	Net income (loss)	$	(728)	$	(78)	$	(838)	$	149
	Depletion, depreciation and impairment		980		598		1,792		1,525
	Impairment of goodwill		48		–		48		–
	Loss (gain) on dispositions		19		(254)		14		(359)
	Exploration and evaluation		44		15		44		17
	Accretion		10		22		43		54
	Deferred tax expense (recovery)		(215)		(15)		(236)		63
	Share-based compensation		3		(11)		15		(18)
	Unrealized risk management loss (gain)		(8)		(4)		46		(151)
	Unrealized foreign exchange loss (gain)		63		22		126		(32)
	Decommissioning expenditures		(16)		(32)		(66)		(92)
	Change in non-cash working capital		129		178		51		37
			329		441		1,039		1,193
Investing activities
	Capital expenditures		(208)		(348)		(816)		(1,752)
	Property dispositions (acquisitions), net		473		1,264		525		1,615
	Change in non-cash working capital		61		8		(44)		(168)
			326		924		(335)		(305)
Financing activities
	Decrease in long-term debt		(608)		(1,267)		(356)		(496)
	Issue of equity		4		–		12		3
	Dividends paid		(51)		(98)		(360)		(395)
			(655)		(1,365)		(704)		(888)

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

Penn West Petroleum Ltd.
Statements of Changes in Shareholders’ Equity

(CAD millions, unaudited)
(CAD millions, unaudited)	Shareholders’ Capital		Other Reserves		Deficit		Total

Balance at January 1, 2013	$	8,985	$	97	$	(262)	$	8,820
Net and comprehensive loss		–		–		(838)		(838)
Share-based compensation		–		15		–		15
Issued on exercise of options and share rights		44		(32)		–		12
Issued to dividend reinvestment plan		95		–		–		95
Dividends declared		–		–		(394)		(394)
Balance at December 31, 2013	$	9,124	$	80	$	(1,494)	$	7,710

(CAD millions, unaudited)
(CAD millions, unaudited)	Shareholders’ Capital		Other Reserves		Retained Earnings (Deficit)		Total

Balance at January 1, 2012	$	8,840	$	95	$	103	$	9,038
Net and comprehensive income		–		–		149		149
Share-based compensation		–		27		–		27
Issued on exercise of options and share rights		28		(25)		–		3
Issued to dividend reinvestment plan		117		–		–		117
Dividends declared		–		–		(514)		(514)
Balance at December 31, 2012	$	8,985	$	97	$	(262)	$	8,820

Investor Information

Penn West shares are listed on the Toronto Stock Exchange under the symbol PWT and on the New York Stock Exchange under the symbol PWE.

A conference call and webcast presentation will be held to discuss the matters noted above at 9:00am Mountain Time (11:00am Eastern Time) on Friday, March 7, 2014. The duration of the conference call is expected to be approximately 30 minutes.

To listen to the conference call, please call 647-427-7450 or 1-888-231-8191 (toll-free). This call will be broadcast live on the Internet and may be accessed directly at the following URL: http://event.on24.com/r.htm?e=754668&s=1&k=EBF7E3EFF18CA391A6490D4CEB866F66

A digital recording will be available for replay two hours after the call’s completion, and will remain available until March 21, 2014 21:59 Mountain Time (23:59 Eastern Time). To listen to the replay, please dial 416-849-0833 or 1-855-859-2056 (toll-free) and enter Conference ID 2959082, followed by the pound (#) key.

We expect to file our annual Management’s Discussion and Analysis and audited annual consolidated financial statements on SEDAR and EDGAR shortly.

SOURCE Penn West

For further information:

PENN WEST
Penn West Plaza
Suite 200, 207 – 9^th Avenue SW
Calgary, Alberta T2P 1K3

Phone: 403-777-2500
Fax: 403-777-2699
Toll Free: 1-866-693-2707
Website: www.pennwest.com

Investor Relations:
Toll Free: 1-888-770-2633
E-mail: investor_relations@pennwest.com

Clayton Paradis, Manager, Investor Relations
Phone: 403-539-6343
E-mail: clayton.paradis@pennwest.com

Penn West Announces its Financial Results for the Fourth Quarter and Year Ended December 31, 2013 and 2013 Reserve Results

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