Penn West Announces its Financial Results for the Fourth Quarter and Year Ended December 31, 2013 and 2013 Reserve Results
CALGARY, Alberta, March 7, 2014 /PRNewswire/ --
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.
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
(2) "Non-GAAP Measures Advisory" sections below.
(3) Includes the effect of capital carried by partners.
Includes dividends paid prior to amounts reinvested in shares under
(4) the dividend reinvestment plan.
Please refer to the "Oil and Gas Information Advisory" section below
(5) 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 Year ended
December 31 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
Three months ended Year ended
(millions) December 31 December 31
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
Development capital includes costs related to Property, Plant and
(1) 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 Year ended
December 31 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
Barrels of
Light & Natural Gas Oil
Reserve Medium Oil Heavy Oil Natural Gas Liquids 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
Working interest (gross) reserves are before royalty burdens and
(1) 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
Barrels of
Light & Natural Gas Oil
Reserve Medium Oil Heavy Oil Natural Gas Liquids 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
Net after royalty reserves are working interest reserves including
(1) 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 http://www.sedar.com.
c) Reconciliation of Working Interest (Gross) Reserves using forecast prices and costs
Reconciliation Light and Medium Oil Heavy Oil
Items [(1)] (mmbbl) (mmbbl)
Proved Proved
plus plus
Proved Probable probable Proved Probable 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 Natural Gas Liquids Natural Gas
Items [(1)] (mmbbl) (bcf)
Proved Proved
plus plus
Proved Probable probable Proved Probable 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 Barrels of Oil Equivalent
Items [(1)] (mmboe)
Proved
plus
Proved Probable 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
2013
(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
Western
Edmonton Canada Cromer Natural Exchange
WTI Par Select LSB gas rate
Cushing, 40 20.5 35 AECO Edmonton Inflation
degrees degrees degrees gas rate
Oklahoma API API API price (US$
($CAD/ ($CAD/ equals
Year ($US/bbl) ($CAD/bbl)($CAD/bbl) ($CAD/bbl) MMbtu) bbl) (%) $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
3-Year
2013 2012 2011 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
Proved Future Proved plus Probable
Year Development Costs 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 http://www.sedar.com and on EDGAR at http://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
Three months ended Year ended
(millions, except per share amounts) December 31 December 31
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 http://www.sedar.com and in the United States at http://www.sec.gov. Readers are cautioned that this list of risk factors should not be construed as exhaustive.
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 Year ended
December 31 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 Year ended
December 31 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)
Shareholders' Other
Capital 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)
Retained
Shareholders' Other Earnings
Capital Reserves (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 - 9th Avenue SW
Calgary, Alberta T2P 1K3
Phone: +1-403-777-2500
Fax: +1-403-777-2699
Toll Free: 1-866-693-2707
Website: http://www.pennwest.com
Investor Relations:
Toll Free: 1-888-770-2633
E-mail: investor_relations@pennwest.com
Clayton Paradis, Manager, Investor Relations
Phone: +1-403-539-6343
E-mail: clayton.paradis@pennwest.com
(PWT. PWE)
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