PENN WEST
PENN WEST PETROLEUM LTD. NEWS RELEASE PENN WEST PETROLEUM ANNOUNCES FOURTH QUARTER AND YEAR END RESULTS AND A REVIEW OF STRATEGIC ALTERNATIVES FOR IMMEDIATE RELEASE, Tuesday, March 2, 2004 PENN WEST PETROLEUM LTD. (TSE – PWT) announces results for the fourth quarter and year ended December 31, 2003, and declares a quarterly dividend of $0.125 per share Fourth quarter report for three months and year ended December 31, 2003 Highlights
Financial Results • Record cash flow of $813 million exceeded capital expenditures of $608 million by $205 million. • In December of 2003, the Board of Directors declared a special dividend of $1.50 per common share to shareholders, and initiated the payment of a quarterly dividend of $0.125 per common share. • A Normal Course Issuer Bid was implemented early in 2003, under which the Company purchased 1,249,000 shares for $52.7 million ($42.25 per share). • Natural gas prices for 2003 averaged $6.26 per mcf, an increase of 65 percent from 2002, and crude oil and liquids prices averaged $36.10, an increase of ten percent from 2002. • Cash flow from operations (1) for 2003 was $813 million ($15.11 per share, basic), an increase of 75 percent from 2002, and up 33 percent from the previous record in 2001. Cash flow from operations (1) in the fourth quarter of 2003 was $194 million ($3.59 per share, basic), an increase of 27 percent from $153 million ($2.86 per share, basic) in the fourth quarter of 2002. • Record net income of $435 million ($8.09 per share, basic) was up 175 percent from $158 million ($2.98 per share, basic) in 2002. Fourth quarter 2003 net income was $34 million ($0.65 per share, basic). This compares with net income of $62 million ($1.16 per share, basic) realized in the fourth quarter of 2002. Operations • Production for the year of 101,549 boe per day was up two percent from 99,483 boe per day in 2002. Production of natural gas for the year was 331 mmcf per day compared to 333 mmcf per day in 2002. In the fourth quarter, crude oil and liquids production averaged 47,100 barrels per day for the quarter, similar to the 47,300 barrels per day produced in the fourth quarter of 2002. Average natural gas production in the fourth quarter of 2003 was 314 mmcf per day, a seven percent decrease from the 337 mmcf per day produced in the fourth quarter of 2002. Exploration and Development • During 2003, Penn West completed an active drilling program, drilling 750 gross wells, up 105 percent from 2002. During the fourth quarter of 2003, a total of 222 net wells were drilled, primarily in the Plains and Central areas, with an 87 percent rate of success. Dividends • Today, the Company declared a quarterly dividend of $0.125 per common share that will be payable on April 1, 2004 to shareholders of record at the close of business on March 15, 2004. Other Corporate Matters • The Company has received several representations from its shareholders both for and against conversion to an income trust. Only one formal proposal has been received. The proposal from a registered shareholder holding 5,500 shares requests that the Board of Directors of Penn West carry out a detailed examination of whether converting the operation of Penn West in whole or in part into an income trust is in the best interests of the shareholders. The Board has resolved to review three alternatives examining the benefits and challenges with regard to the following options: Page 1 of 17
1) Maintaining the status quo and continuing its strategic direction as an independent oil and natural gas exploration and development company; 2) Converting the Company in whole or in part into an income trust. In this regard, the Board has instructed legal counsel to obtain an advance ruling from Canada Customs and Revenue Agency regarding the tax consequences of a potential conversion to an income trust. Receipt of a satisfactory ruling will be a material consideration in pursuing this alternative; and 3) Consider other strategic alternatives including a sale or merger of the Company.
The financial and operational results follow: 1
FINANCIAL HIGHLIGHTS ($ millions, except per share amounts) Three months ended December 31 2003 2002 % Change
Gross revenues
$ 304.1
$ 318.1
Cash flow from operations (1) Per share Diluted per share
$ 193.6 3.59 3.55
$ 152.9 2.86 2.80
Net income Per share Diluted per share
$
$
34.4 0.65 0.63
Year ended December 31 2003 2002 % Change $ 1,367.8
$ 986.9
39
27 26 27
$
812.7 15.11 14.90
$ 463.5 8.70 8.48
75 74 76
(44) (44) (45)
$
435.0 8.09 7.98
$ 158.4 2.98 2.90
175 171 175
(4)
61.9 1.16 1.14
(1) Cash flow from operations is a non-GAAP term and represents cash from operations before changes in non-cash working capital and payments for surrendered stock options.
2
ADJUSTED INCOME FROM OPERATIONS The following table provides a reconciliation of the after tax effects of certain items of a non-operational nature that are included in the Company’s financial results. Three months ended December 31 2003 2002
($ millions, except per share amounts) Net income as reported
$
34.4
$
Year ended December 31 2003
61.9
$
435.0
2002 $
158.4
Unrealized foreign exchange (gain) loss (1)
Effect of statutory tax rate changes on future income tax liabilities (2) Stock-based compensation expense (3) Adjusted income from operations (4) Per share - basic - diluted (1) (2)
(3)
(4)
(4.4)
0.2
(67.6)
3.7
-
-
(100.0)
(6.8)
4.5
-
30.4
-
$
34.5
$
62.1
$
297.8
$
155.3
$ $
0.65 0.63
$ $
1.16 1.14
$ $
5.54 5.46
$ $
2.92 2.84
Gains and losses on the translation of US dollar denominated debt to period end exchange rates are immediately recognized in net income. During the second quarter of 2003, the Canadian and Alberta Governments substantively enacted rate reductions and other income tax changes applicable to the resource industry. The impact of these changes on future income tax assets and liabilities is recorded in net income during the period that the legislation is substantively enacted. In the second quarter of 2003, the Stock Option Plan was modified to provide employees and directors the choice of a cash payment in return for surrendering the option. Quarterly provisions are made to reflect the Company’s potential liability under the Stock Option Plan. Adjusted income from operations is a non-GAAP term that the Company utilizes to evaluate its performance. Page 2 of 17
3
CAPITAL EXPENDITURES ($ millions) Three months ended December 31 2003 2002
Net property acquisitions Land acquisition and retention Drilling and completions Facilities and well equipping Geological and geophysical Head office and other
$
$
4
(95.6) 6.8 96.0 33.4 8.4 0.1 49.1
$
$
86.8 11.3 29.0 35.5 6.9 0.3 169.8
Gross acres (000s) Net acres (000s) Average working interest
$
0.3 47.4 349.6 191.4 18.1 1.3 608.1
$
$
230.3 42.5 149.3 134.2 15.6 1.4 573.3
As at December 31 2002 % Change
5,538 5,313 96%
4,402 4,158 94%
26 28 2
DRILLING PROGRAM Three months ended December 31 2003 2002 Gross Net Gross Net
Natural gas Oil Dry Total wells
101 101 28 230
Success Rate
6
$
UNDEVELOPED LAND
2003
5
Year ended December 31 2003 2002
99 95 28 222
10 18 3 31
87%
10 14 3 27 89%
Year ended December 31 2003 2002 Gross Net Gross Net 307 337 106 750
299 308 106 713
209 112 44 365
85%
197 96 42 335 87%
ACTIVITIES BY CORE AREA
Core Area Northern Peace River Arch Central Plains Southern Saskatchewan/Other
Undeveloped land as at December 31, 2003 (thousands of net acres) 2,084 111 958 1,324 836 5,313
Net wells drilled for the year ended December 31, 2003 175 4 212 313 9 713
Page 3 of 17
7 PRODUCTION AND NETBACKS Three months ended December 31 2003 2002 % Change Natural gas: MMcf per day Operating netback ($ per mcf): Sales price Royalties Operating costs Netback
314.4
$
$
Light oil and NGL’s: Barrels per day Operating netback ($ per barrel): Sales price Royalties Operating costs Netback
$
$
$
$
35.93 5.36 12.28 18.29
$
$
26.60 3.28 7.99 15.33
$
$
47,079
$
$
Combined totals: Barrels of oil equivalent (1) Daily production Operating netback ($ per boe): Sales price Royalties Operating costs Netback
$
11,035
Total liquids: Barrels per day Operating netback ($ per barrel): Sales price Royalties Operating costs Netback
$
36,044
Conventional heavy oil: Barrels per day Operating netback ($ per barrel): Sales price Royalties Operating costs Netback
5.46 1.19 0.64 3.63
33.75 4.87 11.28 17.60
$
$
99,479
$
$
33.24 6.08 7.35 19.81
$
$
337.1
(7)
5.26 1.13 0.46 3.67
4 5 39 (1)
37,498
(4)
36.95 7.50 10.90 18.55
(3) (29) 13 (1)
9,775
13
30.70 4.26 7.50 18.94
(13) (23) 7 (19)
47,273
-
35.66 6.83 10.20 18.63
(5) (29) 11 (6)
103,456
(4)
33.42 6.82 6.15 20.45
(1) (11) 20 (3)
Year ended December 31 2003 2002 % Change 331.3
$
$
6.26 1.38 0.53 4.35
$
$
35,916
$
$
37.08 6.15 11.60 19.33
$
$
10,416
$
$
32.73 4.55 7.59 20.59
$
$
46,332
$
$
36.10 5.79 10.70 19.61
$
$
101,549
$
$
36.91 7.15 6.63 23.13
$
$
332.7
-
3.79 0.83 0.46 2.50
65 66 15 74
34,151
5
34.04 5.99 10.21 17.84
9 3 14 8
9,882
5
28.39 3.84 7.45 17.10
15 18 2 20
44,033
5
32.77 5.51 9.62 17.64
10 5 11 11
99,483
2
27.18 5.20 5.81 16.17
36 38 14 43
(1) Barrels of oil equivalent (boe) are based on six mcf of natural gas equals one barrel of oil (6:1)
For 2003, liquids production increased five percent while gas production remained flat. Overall operating netbacks increased by 43 percent to $23.13 in 2003 from $16.17 in 2002. For the fourth quarter of 2003, liquids prices were reduced by $0.09 per barrel and natural gas prices were increased by $0.02 per mcf, as a result of commodity price hedge settlements. Page 4 of 17
8
RESERVE ESTIMATES
a) Reserve category splits under forecast prices and costs Light & Heavy Oil Medium Oil Reserve (MMbbl) (MMbbl) Estimates Category Proved Developed producing Developed non-producing Undeveloped Total proved Probable Total proved plus probable (1)
111.2 12.7 28.7 152.6 24.0 176.6
20.6 0.1 1.4 22.1 6.3 28.4
Natural Gas
Natural Gas Liquids
(Bcf)
(MMbbl)
577.5 57.5 62.8 697.8 115.5 813.3
12.7 1.1 1.5 15.3 2.0 17.3
(1) Working interest reserves before royalties
Penn West’s reserve estimates have been calculated in compliance with the newly implemented National Instrument 51-101 Standards of Disclosure (“NI 51-101”). These new NI 51-101 standards establish a higher mandated confidence interval for proved and probable reserves. Under NI 51-101, proved reserve estimates are defined as having a 90 percent probability that actual reserves recovered over time will equal or exceed proved reserve estimates. For probable reserves under NI 51-101, there are now equal (50 percent) probabilities that the actual reserves to be recovered will be less than or greater than the proved plus probable reserves estimate. In accordance with NI 51-101, proved undeveloped reserves have been recognized in cases where plans are in place to bring the reserves on production within a short, well-defined time frame. Proved undeveloped reserves often involve infill drilling in existing pools. It should be noted that no proved or probable reserves have been booked for coalbed methane or for CO2 miscible flooding in the Pembina area. Penn West’s reserves have been 100% evaluated by independent third party engineers. Major properties representing 91 percent of the Company’s total proved plus probable reserves were evaluated by either McDaniel & Associates Consultants Ltd. or by Gilbert Laustsen Jung Associates Ltd. depending on the particular location of the property. The balance of approximately nine percent of proved plus probable reserves was evaluated by Resources West Inc. Additional reserve disclosure tables, as required under NI 51-101, will be contained in the Annual Information Form that will be filed on Sedar.
Page 5 of 17
b) Reconciliation of Company working interest reserves by principal product type under forecast prices and costs Oil and Liquids
Reconciliation (1) Items December 31, 2002 Extensions Improved recovery Technical and economic revisions Discoveries Acquisitions Dispositions Production December 31, 2003
Natural Gas
Proved
Proved Plus Probable Proved Probable
(MMbbl)
(MMbbl)
(MMbbl)
(BCF)
Barrels of Oil Equivalent
Proved Plus Probable Probable (BCF)
(BCF)
Proved
Probable
Proved Plus Probable
(MMBOE)
(MMBOE)
(MMBOE)
211.3 15.3
37.6 2.0
248.9 17.3
896.8 72.2
115.9 16.3
1,012.7 88.5
360.8 27.4
56.9 4.7
417.7 32.1
0.1
-
0.1
0.7
-
0.7
0.2
-
0.2
(22.4) 1.3 1.8 (0.6) (16.9)
(7.8) 0.1 0.5 -
(30.1) 1.3 2.3 (0.6) (16.9)
(143.7) 0.2 1.4 (9.0) (120.9)
(17.1) 0.1 0.3 -
(160.8) 0.3 1.7 (9.0) (120.9)
190.0
32.4
222.4
697.8
115.5
813.3
(46.3) 1.3 2.1 (2.1) (37.0)
(10.6) 0.1 0.5 -
(56.9) 1.4 2.6 (2.1) (37.0)
306.3
51.6
357.9
(1) Columns may not add due to rounding
The reserve estimates contained in Table 8b are Company working interest reserves before the deduction of Crown royalties. A net reserve reconciliation after royalties will be included in the Company’s Annual Information Form. Negative proved reserve revisions totalled 46 million barrels of oil equivalent, or approximately 13 percent of the opening balance. Of this amount, approximately one percent relates to the elimination of reserves with a remaining life in excess of 50 years, where Penn West expects to recognize these reserves in subsequent years. An additional three percent is related to the transfer of reserves from proved to probable to reflect stricter guidelines for the timing of bringing undeveloped reserves on-stream. The remaining reduction of nine percent reflects technical revisions based on NI 51-101 standards and reservoir performance. These adjustments cover a number of properties, with the largest single property revision representing less than one percent of the total reduction of 13 percent. Proved plus probable reserves of 357.9 mmboe at the end of 2003, were eight percent lower than established reserves (proved plus 50 percent probable) of 389.3 mmboe, at the end of 2002.
c)
Net present values of future net revenue under forecast prices and costs ($millions) Net Present Value of Future Net Revenue Before Income Taxes (Discounted) Reserve Category 5% 10% 15% Proved Developed producing Developed non-producing Undeveloped Total proved Probable Total proved plus probable
2,346 247 284 2,877 446 3,323
1,977 162 160 2,299 295 2,593
1,728 121 87 1,936 214 2,150
Net present values are net of wellbore abandonment liabilities and are based on the price assumptions that are contained in the following table.
Page 6 of 17
d)
Summary of pricing and inflation rate assumptions as of December 31, 2003 under forecast prices and costs WTI Cushing Oklahoma ($US/bbl)
Year Historical 2000 2001 2002 2003 Forecast 2004 2005 2006 2007 2008 Thereafter*
Oil Edmonton Hardisty Par Price Heavy o o 40 API 12 API ($Cdn/bbl) ($Cdn/bbl)
Cromer Medium o 29 API ($Cdn/bbl)
Natural Gas AECO Gas Price
Edmonton NGL Mix
Inflation Rates
Exchange Rate
($Cdn/GJ)
($Cdn/bbl)
(%)
($US/$Cdn)
30.31 25.97 26.10 30.95
44.72 39.60 39.95 43.10
27.80 18.05 27.60 27.45
40.10 32.22 34.93 36.90
5.32 5.15 3.86 6.30
35.70 31.60 26.20 33.80
2.7 2.6 2.2 2.0
0.674 0.646 0.637 0.715
29.00 26.50 25.50 25.00 25.00 2%
37.70 34.30 33.00 32.30 32.30 2%
22.70 21.55 21.56 20.63 20.39 2%
32.20 29.71 28.84 28.06 27.97 2%
5.50 5.19 4.87 4.68 4.53 2%
27.90 25.50 24.50 23.80 23.70 2%
2.0 2.0 2.0 2.0 2.0 2.0
0.750 0.750 0.750 0.750 0.750 0.750
*0% after 2023
e)
Future development costs under forecast prices and costs ($ millions)
Year
2004 2005 2006 2007 2008 2009 and subsequent Undiscounted total Discounted @ 10%/yr
Proved Future Development Costs
$
$ $
196 100 57 4 20 34 411 349
9 COMMON SHARE DATA (millions of shares) 2003
2002
% Change
Weighted average: (Year ended December 31) Basic Diluted
53.8 54.5
53.2 54.6
1 -
Outstanding: (as at December 31) Basic Basic plus stock options
53.7 57.9
53.7 58.7
(1)
Page 7 of 17
5,000
93 94 95 96 97 98 99 00 01 02 03
812.7 612.9 463.5
560.0 230.3
400
200 100
122.9
300 113.0
13,958
500
0
0
0
600
90.1
10,000
12,604
15,000
10,577
20,000
11,483
25,000
700
63.0
46,332
44,033
20,779
30,000
800
41.5
35,000
38,884
32,462
40,000
900
9.4
13.0
58.2
100
45,000
6,934
184.0
97.4
150
50,000
1,753
129.0
200
164.8
250
50
332.7
245.1
300
331.3
306.2
350
330.3
Charting our Performance
93 94 95 96 97 98 99 00 01 02 03
NATURAL GAS PRODUCTION FOR THE YEAR ENDED DECEMBER 31
CRUDE OIL & NGL PRODUCTION FOR THE YEAR ENDED DECEMBER 31
(mmcf per day)
(bbls per day)
93 94 95 96 97 98 99 00 01 02 03 CASH FLOW FOR THE YEAR ENDED DECEMBER 31
($ millions)
LETTER TO OUR SHAREHOLDERS Penn West’s financial discipline, underpinned by strong commodity prices, generated record cash flows and record annual average production rates during 2003. Penn West achieved these results along with a significant reduction in bank debt, from $598 million at the end of 2002 to $442 million at the end of 2003, resulting in a 2003 year end debt to cash flow ratio of 0.5:1. Reflecting Penn West’s strong financial position, the Company also declared its first ever dividend during 2003, a special dividend of $1.50 per share and a quarterly dividend of $0.125 per share payable beginning in the first quarter of 2004. The year 2003 was one of challenge and of change for Penn West. In the first ten years since our reorganization, we used a formula of equal parts acquisition and development spending along with a healthy dose of exploration to successfully grow the Company. Increased competition for acquisitions and an increase in operating and finding costs impacted our operational performance in 2003. Despite these challenges, Penn West was able to report record cash flow and record annual average production. In addition, we believe that by developing our existing acreage and by focusing our exploration efforts, we will increase the efficiency and growth of our operations. Our production is currently 108,000 boe per day and is slightly ahead of plan. Our financial position remains strong and the outlook for commodity prices is favorable. Penn West’s focused asset base, combined with our financial discipline, presents many opportunities for future value creation. We expect that further strategic changes will be made where required to ensure that we have the proper framework for continuing the growth of Penn West and the enhancement of shareholder value. In that regard, the Board of Directors has commenced a strategic review of alternatives available to the Company as outlined in the highlight section of this news release. On behalf of the Board of Directors,
N. Murray Edwards Chairman
William E. Andrew President
Calgary, Alberta March 2, 2004
Page 8 of 17
MANAGEMENT’S DISCUSSION AND ANALYSIS Management’s discussion and analysis (“MD&A”) of financial conditions and results of operations should be read in conjunction with the unaudited interim consolidated financial statements for the three and twelve months ended December 31, 2003 and the audited consolidated financial statements and MD&A for the year ended December 31, 2002. Oil and Natural Gas Revenues Higher oil and liquids production volumes and higher commodity prices for both crude oil and natural gas, resulted in revenues increasing by 39 percent to $1,368 million for 2003 from $987 million in 2002. Natural gas production of 331 mmcf per day for the year is comparable to production of 333 mmcf per day in 2002. Production of crude oil and liquids increased five percent to 46,332 barrels per day in 2003 from 44,033 barrels per day in 2002. The average natural gas price received in 2003 increased by 65 percent to $6.26 per mcf from $3.79 per mcf in 2002 and surpassed the level of $5.24 per mcf achieved in 2001. The average crude oil and liquids price increased 10 percent to $36.10 per barrel in 2003 from $32.77 per bbl in 2002. Revenues fell by four percent to $304 million during the fourth quarter (Q4) of 2003 from $318 million in Q4 2002. This drop in revenue was attributable to a combination of lower natural gas production and lower crude oil prices received due to the strengthening of the Canadian dollar. Although the benchmark West Texas Intermediate price for crude oil was up year over year, the Company’s revenues were impacted by more than $27 million due to the strengthening of the Canadian dollar over comparable periods. The Company’s average production of natural gas was 314 mmcf per day in the quarter, which was seven percent lower than the production level in Q4 2002. Production of crude oil and liquids was similar over the two reporting periods being 47,079 barrels per day in the current quarter and 47,273 barrels per day in Q4 2002. The average natural gas price received by the Company increased four percent to $5.46 per mcf in the quarter from $5.26 in Q4 2002, and the average crude oil and liquids price was down five percent to $33.75 per barrel in the quarter from $35.66 per barrel in Q4 2002. Commodity hedging activities reduced price realizations for crude oil and liquids in the fourth quarter by $0.09 per barrel and increased the price realization for natural gas by $0.02 per mcf. Increases (decreases) in gross revenues for the year ended December 31, 2003 ($ millions) Gross revenues – 2002 $ 986.9 Increase in oil and liquids production 30.3 Increase in oil and liquids price 53.6 Decrease in natural gas production (1.9) Increase in natural gas price 298.9 Gross revenues – 2003 $ 1,367.8 Royalty Expenses The average royalty rate Penn West incurred in 2003 was 19 percent, the same average rate as in 2002. The oil and liquids royalty rate in 2003 of 16 percent compares to 17 percent in 2002. The natural gas royalty rate increased marginally from 21.9 percent in 2002 to 22.0 percent in 2003. Operating Expenses Operating expenses incurred in 2003 of $246 million were up 17 percent from $211 million in 2002. A portion of this increase reflects higher production volumes. Per unit operating costs also increased 14 percent to $6.63 per boe from $5.81 per boe in 2002. The per unit cost increase was attributable to an increase in production mix to crude oil which has higher per unit operating costs than natural gas. The proportion of crude oil in the Company’s production mix increased to 46 percent of total production in the period from 44 percent in 2002. In addition, higher expenses are being experienced in the oil properties acquired in the latter part of 2002 that have higher per unit operating costs than the Company’s historical property base, and in general field service costs. Operating expenses in Q4 2003 were $67 million, an increase of 14 percent from $59 million in Q4 2002. Per unit operating expenses in Q4 2003 of $7.35 per boe represent a 20 percent increase from $6.15 per boe in Q4 2002. This increase can be attributed to the decline in gas production over the period and the higher cost of services.
Page 9 of 17
General and Administrative Expenses Gross general and administrative expenses increased due to growth in staff levels to manage the Company’s increased drilling program and adjustments to the Company’s salary and benefit programs during 2002 and 2003. Gross expenses of $34 million in the period were up 31 percent from $26 million in 2002. Net general and administrative expenses of $13 million in the period were up 30 percent from $10 million in 2002. On a per unit basis, net expenses were $0.34 per boe in 2003 up 21 percent from $0.28 per boe for the same period of 2002. Net general and administrative expenses in Q4 2003 were $3.7 million up from $3.0 million in Q4 2002. Stock-Based Compensation At the Annual and Special Meeting of the shareholders held in May, 2003, the shareholders approved an amendment to the Company’s Stock Option Plan providing option holders the right to elect the receipt of a cash payment in exchange for surrendering the option. In the fourth quarter of 2003, $7.0 million ($4.5 million after tax) was expensed as stock-based compensation reflecting the increase in stock price over the quarter. See Notes 1 and 4 to the December 31, 2003 interim financial statements for more information on stock-based compensation. Interest Expense Interest expense for 2003 amounted to $12 million, a decrease of 40 percent from $20 million in the same period of 2002. The decrease in interest expense reflected the ability of the Company to capture the benefits of low short-term interest rates available in 2003 on U.S. denominated debt and lower debt levels. Interest expenses in Q4 2003 were $2.9 million down 37 percent from $4.6 million in Q4 2002. Depletion and Depreciation Depletion, depreciation and the site restoration provision increased by 24 percent to a total of $322 million in 2003 from $259 million in 2002. This was a direct result of increases in the Company’s production levels combined with an increase in the depletion rate. Average unit costs increased by 22 percent to $8.69 per boe in the period from $7.13 per boe in the same 2002 period. The depletion, depreciation and site restoration provision in Q4 of $97 million was up 33 percent from $73 million in Q4 2002. Foreign Exchange The Company converted its borrowings to U.S. dollars during 2002 at an average exchange rate of US$0.6392 for each Canadian dollar to capture the benefits of the positive differential between Canadian and U.S. interest rates. As at December 31, 2003, the Company had US$340 million of U.S. denominated debt. The conversion of the outstanding U.S. dollar borrowings at the end of the period, after adjusting for the impact of written Canadian dollar calls, resulted in an unrealized foreign exchange gain of $82.9 million for 2003, versus a loss in 2002 of $4.5 million. The impact of written Canadian dollar calls on the unrealized foreign exchange gain in 2003 was to reduce the potential unrealized foreign exchange gain by $12.7 million. The unrealized gain on foreign exchange in Q4 was $5.4 million compared to a loss of $0.2 million in Q4 2002. Taxes The total provision for income taxes decreased by 19 percent to $100 million in 2003 from $124 million in 2002 as a result of lower income tax rates enacted by the authorities during 2003, offset by higher pre-tax earnings. The provision for income taxes in Q4 2003 of $42 million was down from $49 million in Q4 2002 due to the lower income before tax and lower effective tax rates in the current period. Current cash income taxes were reduced in the fourth quarter by $19.1 million resulting in cash income taxes for the full year 2003 of only $9.9 million. This amount of $9.9 million is a substantial reduction from the amounts previously estimated by the Company, and is $26.1 million less than the $36.0 million of cash income taxes provided by the Company in the first two quarters of 2003. For 2004, cash income taxes are now estimated at $20 million to $40 million. Capital Expenditures Capital expenditures of $608 million in 2003 consisted of $0.3 million of net property acquisitions and $608 million of exploration and development spending. For the same period in 2002, capital expenditures were $573 Page 10 of 17
million consisting of $230 million of net property acquisitions and $343 million of exploration and development spending. The increase in exploration and development expenditures over the same period in 2002 reflects the planned increase in the number of net wells drilled in 2003 compared to 2002. This is consistent with the Company’s strategy to focus on value creation and was in response to the relatively high cost of potential acquisitions driven by a period of relatively high commodity prices. Capital expenditures in Q4 2003 of $49 million decreased 71 percent from $170 million in 2002 as a result of planned asset dispositions that closed in the period. Cash Flow and Net Income Cash flow increased by 75 percent to $813 million ($15.11 basic per share) in 2003 from the $464 million ($8.70 basic per share) in 2002. Net income increased 175 percent to $435 million ($8.09 basic per share) in 2003 from $158 million ($2.98 basic per share) in 2002. In Q4 2003, cash flow increased 27 percent to $194 million ($3.59 basic per share) from $153 million ($2.86 basic per share) in Q4 2002. This increase in cash flow for the quarter from the prior period was mainly the result of reduced cash taxes payable for the period. Net income in Q4 2003 fell 44 percent to $34 million ($0.65 basic per share) from $62 million ($1.16 basic per share) in Q4 2002. The impact of the strong Canadian dollar on Q4 net income versus 2002 was approximately $15 million. The Company achieved a year over year increase in production volumes of two percent while reinvesting less than 80 percent of cash flow. Operating netbacks in 2003 increased 43 percent to $23.13 per boe from $16.17 per boe in 2002 mainly due to the significant increase in year over year prices for natural gas. Operating netbacks in Q4 2003 were $19.81 per boe, down three percent from $20.45 in Q4 2002, as a result of the relatively strong Canadian dollar. Commodity prices for crude oil and natural gas continue to show strength as we enter 2004, providing good margins and profitability for shareholders. Liquidity and Capital Resources The record level of cash flow in 2003 allowed Penn West to fund all of its capital program for 2003 using internally generated cash flow and to use the excess funds to reduce debt, purchase shares in accordance with the approved Normal Course Issuer Bid and to declare, for the first time, a quarterly dividend and a special dividend to shareholders payable on January 2, 2004. Bank debt at the end of December 2003, before payment of the dividends, was $442 million down from $598 million in 2002. In 2003, the Company purchased 1,249,000 common shares for $52.7 million ($42.25 per share). In the fourth quarter of 2003, 355,700 common shares were purchased for $16.5 million ($46.57 per share). The Company is approved to purchase up to 2,687,824 common shares in the period to February 26, 2004. During the year, the Company reduced its revolving credit facility with a syndicate of Canadian banks to $720 million from $765 million, and retained its $50 million operating line of credit. Subsequent to year end, the operating line was increased to $100 million. This facility provides the Company significant financial flexibility to pursue profitable growth opportunities. Outlook On February 18, 2004, Penn West Petroleum Ltd. announced the closing of an acquisition of approximately 10,000 boe per day of production that included 7,000 barrels per day of conventional heavy oil and 18 million cubic feet per day of natural gas. The purchase price of $234 million included producing properties and approximately 400,000 net acres of undeveloped land located in the Kindersley/Coleville region. The acquired properties are in close proximity and represent an excellent fit with Penn West’s existing operations in southwestern Saskatchewan. The acquisition will be funded within Penn West’s existing capital spending targets of $600 to $700 million for 2004. As a result of this transaction, a number of exploration and development wells that were originally planned for 2004 will now be deferred into subsequent years. With the acquisition, Penn West has increased its forecast production range to 105,000 to 109,000 boe per day for 2004. Based on commodity prices of $30.00 U.S. per barrel of WTI and $5.80 per mcf for natural gas, cash flow is also forecast to increase to a range of $640 to $670 million ($11.80 to $12.30 basic per share). Cash income taxes for 2004 are now estimated at $20 to $40 million. Net income is forecast to be in the range of $165 to $180 million ($3.00 to $3.30 basic per share), reflecting higher depletion charges. Page 11 of 17
Sensitivity Analysis This news release includes forward-looking statements (forecasts) under applicable securities laws. These statements are subject to known or unknown risks and uncertainties that could cause actual results to differ materially from those anticipated or implied in the forward-looking statements. Sensitivities to selected key assumptions are outlined in the table below. Impact on cash flow*
Change of: $1.00 per barrel of liquids price Per common share 1,000 barrels per day in liquids production Per common share $0.10 per mcf of natural gas price Per common share 10 mmcf per day in natural gas production Per common share $0.01 in $US/$CAD exchange rate** Per common share
Impact on net income*
16.2 0.30 9.5 0.18 8.9 0.16 15.2 0.28 11.6 0.21
10.2 0.19 3.6 0.07 5.6 0.10 5.5 0.10 7.3 0.14
*$ millions, except per common share amounts ** excludes the impact of any unrealized foreign exchange gains or losses
Penn West Petroleum Ltd. Consolidated Balance Sheets
($ millions, unaudited) Assets Current Accounts receivable Prepaids and other
As at December 31, 2003
$
Property, plant and equipment $ Liabilities and shareholders’ equity Current Accounts payable and accrued liabilities Taxes payable Dividends payable Stock-based compensation (note 4)
$
Bank loan (note 2) Deferred credits (note 3) Future income taxes Shareholders’ equity Share capital (note 4) Retained earnings $
As at December 31, 2002
141.6 42.8 184.4 2,953.7 3,138.1
$
248.1 87.4 22.1 357.6
$
$
145.6 14.0 159.6 2,632.8 2,792.4
185.3 94.3 279.6
442.4 67.6 649.4 1,159.4
598.4 41.3 580.1 1,219.8
505.6 1,115.5 1,621.1 3,138.1
483.8 809.2 1,293.0 2,792.4
$
See accompanying notes to consolidated financial statements. Page 12 of 17
Penn West Petroleum Ltd. Consolidated Statements of Income and Retained Earnings Three months ended December 31 2003 2002
($ millions, except per share amounts, unaudited) Revenues Oil and natural gas Royalties
$
304.1 (55.6) 248.5
Expenses Operating General and administrative Interest on long term debt Depletion and depreciation Stock-based compensation (note 4) Foreign exchange (gain) loss Income before taxes Taxes Capital Current income Future income
Net income Retained earnings, beginning of period Dividends payable Purchase of common shares (note 4) Retained earnings, end of period
$
Net income per common share Basic Diluted
$ $
$
318.1 (64.9) 253.2
Year ended December 31 2003 2002
$
1,367.8 (265.1) 1,102.7
$
986.9 (188.9) 798.0
67.2 3.7 2.9 96.5 7.0 (5.4) 171.9 76.6
58.5 3.0 4.6 72.8 0.2 139.1 114.1
245.5 12.5 11.9 322.0 48.0 (82.9) 557.0 545.7
210.9 10.3 20.3 258.7 4.5 504.7 293.3
0.2 (19.1) 61.1 42.2
3.2 31.0 18.0 52.2
10.2 9.9 90.6 110.7
11.0 82.0 41.9 134.9
34.4
61.9
435.0
158.4
$
747.3 809.2
$
809.2 (87.4) (41.3) 1,115.5
$
650.8 809.2
$ $
1.16 1.14
$ $
8.09 7.98
$ $
2.98 2.90
1,181.7 (87.4) (13.2) 1,115.5
0.65 0.63
See accompanying notes to consolidated financial statements.
Page 13 of 17
Penn West Petroleum Ltd. Consolidated Statements of Cash Flow Three months ended December 31 2003 2002
($ millions, except per share amounts, unaudited) Operating activities Net income Depletion and depreciation Future income taxes Unrealized foreign exchange (gain) loss Stock-based compensation (note 4) Cash flow from operations (Increase) decrease in non-cash working capital Payments for surrendered options (note 4)
$
Investing activities Additions to property, plant and equipment and other, net Expenditures on abandonments Decrease in non-cash working capital
Financing activities (Decrease) increase in bank loan Issue of common shares Purchase of common shares (Increase) decrease in non-cash working capital
Increase in cash Cash, beginning of period Cash, end of period Interest paid Income and capital taxes paid
34.4 96.5 61.1 (5.4) 7.0 193.6 (6.1) (3.6) 183.9
$
Year ended December 31 2003 2002
61.9 72.8 18.0 0.2 152.9 38.0 190.9
$
435.0 322.0 90.6 (82.9) 48.0 812.7 (114.6) (13.6) 684.5
$
158.4 258.7 41.9 4.5 463.5 39.6 503.1
(49.1) (4.2) 11.4 (41.9)
(169.8) (4.9) 4.8 (169.9)
(629.4) (14.3) 58.2 (585.5)
(573.3) (10.8) 22.8 (561.3)
(129.1) 3.7 (16.5) (0.1) (142.0)
(25.6) 4.9 (0.3) (21.0)
(73.1) 26.7 (52.7) 0.1 (99.0)
37.6 20.5 0.1 58.2
$
-
$ $
21.5 32.2
$
-
$ $
3.3 2.7
$
-
$
-
$ $
4.9 2.9
$ $
12.4 140.2
Notes to the Consolidated Financial Statements ($ millions): 1. SIGNIFICANT ACCOUNTING POLICIES These interim consolidated financial statements include the accounts of the Company and its wholly owned subsidiaries and partnerships. These interim consolidated financial statements were prepared in accordance with Canadian generally accepted accounting principles. The same accounting policies and methods of computation as the audited consolidated financial statements as at and for the year ended December 31, 2002 have been used except for the accounting for stock-based compensation costs. These accounting policies and methods of computation are described in the notes to the audited consolidated financial statements for the year ended December 31, 2002. Accordingly, these financial statements should be read in conjunction with the Company’s audited consolidated financial statements and notes thereto for the year ended December 31, 2002. Due to the changes to the Stock Option Plan detailed in Note 4, the Company recognized a liability for potential future cash option payments that may be required on all vested options outstanding plus the pro-rata number of future option vestings attributable to the current period. The amount is based on the excess of the period end share price over the option exercise price. Each quarter, the liability is recalculated to reflect the current share price and outstanding options. Cash option settlements are charged against the liability. The funds received on options exercised for shares, plus the associated liability amount, are included in share capital. Page 14 of 17
2. BANK LOAN As at As at December 31, 2003 December 31, 2002 Bankers’ acceptances LIBOR advances (2003 and 2002 $US 340 million)
$ $
442.4 442.4
$
61.2 537.2 598.4
$
As at December 31, 2003, the Company had unsecured bank credit facilities of $770 million comprising a $720 million credit facility and a $50 million operating loan facility, and had outstanding letters of credit totalling $6.6 million that reduced the amount otherwise available to be drawn on the credit facility. 3. DEFERRED CREDITS As at As at December 31, 2003 December 31, 2002 Site restoration and abandonment Stock-based compensation
$ $
61.8 5.8 67.6
$
41.3 41.3
$
4. SHARE CAPITAL Common shares issued Balance, January 1, 2003 Issued on exercise of stock options Liability settlement on stock options exercised for shares Purchase of shares under Normal Course Issuer Bid Balance, December 31, 2003
Shares 53,732,540 1,208,750
(1,249,000) 53,692,290
Amount $ 483.8 26.7
$
6.5 (11.4) 505.6
The Company commenced its Normal Course Issuer Bid through the facilities of The Toronto Stock Exchange on February 27, 2003. For a period not to exceed one year, a maximum of five percent of the issued and outstanding common shares of the company, or 2,687,824 shares, may be purchased for cancellation. As at December 31, 2003, the Company had purchased 1,249,000 shares, at an average price of $42.25 per share, and a total cost of $52.7 million. The cost of these shares in excess of book value was applied to retained earnings. The shareholders approved changes to the Stock Option Plan at the Annual and Special Meeting on May 20, 2003. Employees and directors may now elect to receive a cash payment in exchange for surrendering vested stock options. The cash payment is equal to the weighted average share price for the three prior trading days less the option exercise price. As a result of the Stock Option Plan amendment, commencing June 30, 2003, the Company recognizes the potential liability that could arise if all employees and directors elected the cash settlement alternative at the period end share price. Provision is made for all vested options, including those granted in prior years, plus a pro-rata number of future option vestings attributable to the current period. For the year ended December 31, 2003, $48 million ($30.4 million after income tax) was expensed as stock-based compensation with no restatement of prior periods. During the 2003 period, $13.6 million of cash option payments were made and charged against the liability. Prior to the above amendment, no charges to earnings were made for stock option grants and certain proforma amounts were provided using the Black-Scholes option pricing model. As stock-based compensation is now charged to earnings, the pro-forma disclosures are no longer presented.
Page 15 of 17
Number of stock options
Stock options Outstanding, January 1, 2003 Granted Exercised for common shares Exercised for cash Forfeited Outstanding, December 31, 2003 Exercisable, December 31, 2003
5,005,750 1,563,850 (1,208,750) (741,820) (392,240) 4,226,790 875,480
Weighted average exercise price $
29.97 41.32 22.10 28.33 35.36 36.21 32.88
$ $
5. FINANCIAL INSTRUMENTS The Company had the following financial instruments outstanding as at December 31, 2003: Notional Volume Crude Oil WTI Costless Collars WTI Costless Collars Natural Gas AECO Costless Collars Electricity Alberta Power Pool Swaps Alberta Power Pool Swaps Alberta Power Pool Swaps Interest Rates Libor Interest Rate Swaps Foreign Exchange Canadian Dollar Call Sales
Remaining Term
Pricing
25,000 Bbls/d 10,000 Bbls/d
Jan/04 – Jun/04 Jul/04 – Sept/04
$US 25.65 to 31.08/Bbl $US 25.50 to 30.70/Bbl
25,000 GJ/d
Jan/04 – Mar/04
$6.00 to 9.07/GJ
50 MW 60 MW 60 MW
2004 2005 2006
$44.00 to $50.00/MWh $41.00 to $50.00/MWh $42.25 to $43.15/MWh
$US 100 million
Jun/04
1.164%
$US 340 million
Jan/04
CAD/USD $0.7497
In the fourth quarter of 2003, the Company recognized the full potential impact of its written Canadian calls. The total provision of $12.7 million is included in current liabilities. These instruments provided counterparties a one-day option of selling the Company US dollars at an average rate of $0.7497 CAD/US. Subsequent to December 31, 2003, the instruments were extended without any cash cost to the Company and no counterparties have exercised their put option. 6. INCOME TAXES The majority of the Company’s taxable income is generated by partnerships. Current income taxes are incurred on a portion of the partnerships’ taxable income in the year following their inclusion in the Company’s consolidated net income. Due to reductions in Federal and Provincial tax rates, the Company recorded a $100 million future income tax recovery during the second and third quarters of 2003 (2002 – provincial recovery of $6.8 million). 7. SUBSEQUENT EVENT On February 18, 2004, the Company acquired oil and natural gas assets that produce approximately 10,000 boe per day of production, including 7,000 barrels per day of conventional heavy oil and 18 million cubic feet per day of natural gas. The purchase price included producing properties and approximately 400,000 net acres of undeveloped land in southwest Saskatchewan. The purchase price of $234 million was financed by the bank loan. To reflect the increased size of Company operations, the Company increased its operating loan facility to $100 million from $50 million.
Page 16 of 17
On March 1, 2004, the Board of Directors of the Company resolved to review three alternatives examining the benefits and challenges with regard to the following options: 1) Maintaining the status quo and continuing its strategic direction as an independent oil and natural gas exploration and development company; 2) Converting the Company in whole or in part into an income trust. In this regard, the Board has instructed legal counsel to obtain an advance ruling from Canada Customs and Revenue Agency regarding the tax consequences of a potential conversion to an income trust. Receipt of a satisfactory ruling will be a material consideration in pursuing this alternative; and 3) Consider other strategic alternatives including a sale or merger of the Company.
Investor Information
Penn West Petroleum Ltd. is a senior independent Canadian oil and natural gas company, based in Calgary, Alberta, that focuses on exploration and development activity. Penn West trades on The Toronto Stock Exchange under the symbol PWT. A conference call will be held to discuss Penn West’s results at 9:00 a.m. Mountain Time, 11:00 a.m. Eastern Time on Tuesday, March 2, 2004. The North American conference call number is 1-800-814-4890. A taped recording will be available until Tuesday, March 9, 2004 by dialing 1-877-289-8525 or 416-640-1917 and entering passcode 21032541#. This call will be broadcast live on the internet and may be accessed directly on the Penn West website www.pennwest.com or at the following URL: http://www.newswire.ca/en/webcast/viewEvent.cgi?eventID=709500. Notes to Reader 1.) This document contains forward-looking statements (forecasts) under applicable securities laws. Forwardlooking statements are necessarily based upon assumptions and judgements with respect to the future including, but not limited to, the outlook for commodity markets and capital markets, the performance of producing wells and reservoirs, and the regulatory and legal environment. Many of these factors can be difficult to predict. As a result, the forward-looking statements are subject to known or unknown risks and uncertainties that could cause actual results to differ materially from those anticipated or implied in the forward-looking statements 2.) All dollar amounts contained in this document are expressed in Canadian dollars unless noted otherwise. 3.) Where applicable, natural gas has been converted to barrels of oil equivalent (boe) using a conversion rate of 6 mcf of natural gas equals 1 boe.
For further information, please contact: PENN WEST PETROLEUM LTD. Suite 2200, 425 - First Street S.W. Calgary, Alberta T2P 3L8 Phone: (403) 777-2500 Fax: (403) 777-2699 www.pennwest.com William Andrew, President Phone: (403) 777-2502
Page 17 of 17
Financial Results • Record cash flow of $813 million exceeded capital expenditures of $608 million by $205 million. • In December of 2003, the Board of Directors declared a special dividend of $1.50 per common share to shareholders, and initiated the payment of a quarterly dividend of $0.125 per common share. • A Normal Course Issuer Bid was implemented early in 2003, under which the Company purchased 1,249,000 shares for $52.7 million ($42.25 per share). • Natural gas prices for 2003 averaged $6.26 per mcf, an increase of 65 percent from 2002, and crude oil and liquids prices averaged $36.10, an increase of ten percent from 2002. • Cash flow from operations (1) for 2003 was $813 million ($15.11 per share, basic), an increase of 75 percent from 2002, and up 33 percent from the previous record in 2001. Cash flow from operations (1) in the fourth quarter of 2003 was $194 million ($3.59 per share, basic), an increase of 27 percent from $153 million ($2.86 per share, basic) in the fourth quarter of 2002. • Record net income of $435 million ($8.09 per share, basic) was up 175 percent from $158 million ($2.98 per share, basic) in 2002. Fourth quarter 2003 net income was $34 million ($0.65 per share, basic). This compares with net income of $62 million ($1.16 per share, basic) realized in the fourth quarter of 2002. Operations • Production for the year of 101,549 boe per day was up two percent from 99,483 boe per day in 2002. Production of natural gas for the year was 331 mmcf per day compared to 333 mmcf per day in 2002. In the fourth quarter, crude oil and liquids production averaged 47,100 barrels per day for the quarter, similar to the 47,300 barrels per day produced in the fourth quarter of 2002. Average natural gas production in the fourth quarter of 2003 was 314 mmcf per day, a seven percent decrease from the 337 mmcf per day produced in the fourth quarter of 2002. Exploration and Development • During 2003, Penn West completed an active drilling program, drilling 750 gross wells, up 105 percent from 2002. During the fourth quarter of 2003, a total of 222 net wells were drilled, primarily in the Plains and Central areas, with an 87 percent rate of success. Dividends • Today, the Company declared a quarterly dividend of $0.125 per common share that will be payable on April 1, 2004 to shareholders of record at the close of business on March 15, 2004. Other Corporate Matters • The Company has received several representations from its shareholders both for and against conversion to an income trust. Only one formal proposal has been received. The proposal from a registered shareholder holding 5,500 shares requests that the Board of Directors of Penn West carry out a detailed examination of whether converting the operation of Penn West in whole or in part into an income trust is in the best interests of the shareholders. The Board has resolved to review three alternatives examining the benefits and challenges with regard to the following options: Page 1 of 17
1) Maintaining the status quo and continuing its strategic direction as an independent oil and natural gas exploration and development company; 2) Converting the Company in whole or in part into an income trust. In this regard, the Board has instructed legal counsel to obtain an advance ruling from Canada Customs and Revenue Agency regarding the tax consequences of a potential conversion to an income trust. Receipt of a satisfactory ruling will be a material consideration in pursuing this alternative; and 3) Consider other strategic alternatives including a sale or merger of the Company.
The financial and operational results follow: 1
FINANCIAL HIGHLIGHTS ($ millions, except per share amounts) Three months ended December 31 2003 2002 % Change
Gross revenues
$ 304.1
$ 318.1
Cash flow from operations (1) Per share Diluted per share
$ 193.6 3.59 3.55
$ 152.9 2.86 2.80
Net income Per share Diluted per share
$
$
34.4 0.65 0.63
Year ended December 31 2003 2002 % Change $ 1,367.8
$ 986.9
39
27 26 27
$
812.7 15.11 14.90
$ 463.5 8.70 8.48
75 74 76
(44) (44) (45)
$
435.0 8.09 7.98
$ 158.4 2.98 2.90
175 171 175
(4)
61.9 1.16 1.14
(1) Cash flow from operations is a non-GAAP term and represents cash from operations before changes in non-cash working capital and payments for surrendered stock options.
2
ADJUSTED INCOME FROM OPERATIONS The following table provides a reconciliation of the after tax effects of certain items of a non-operational nature that are included in the Company’s financial results. Three months ended December 31 2003 2002
($ millions, except per share amounts) Net income as reported
$
34.4
$
Year ended December 31 2003
61.9
$
435.0
2002 $
158.4
Unrealized foreign exchange (gain) loss (1)
Effect of statutory tax rate changes on future income tax liabilities (2) Stock-based compensation expense (3) Adjusted income from operations (4) Per share - basic - diluted (1) (2)
(3)
(4)
(4.4)
0.2
(67.6)
3.7
-
-
(100.0)
(6.8)
4.5
-
30.4
-
$
34.5
$
62.1
$
297.8
$
155.3
$ $
0.65 0.63
$ $
1.16 1.14
$ $
5.54 5.46
$ $
2.92 2.84
Gains and losses on the translation of US dollar denominated debt to period end exchange rates are immediately recognized in net income. During the second quarter of 2003, the Canadian and Alberta Governments substantively enacted rate reductions and other income tax changes applicable to the resource industry. The impact of these changes on future income tax assets and liabilities is recorded in net income during the period that the legislation is substantively enacted. In the second quarter of 2003, the Stock Option Plan was modified to provide employees and directors the choice of a cash payment in return for surrendering the option. Quarterly provisions are made to reflect the Company’s potential liability under the Stock Option Plan. Adjusted income from operations is a non-GAAP term that the Company utilizes to evaluate its performance. Page 2 of 17
3
CAPITAL EXPENDITURES ($ millions) Three months ended December 31 2003 2002
Net property acquisitions Land acquisition and retention Drilling and completions Facilities and well equipping Geological and geophysical Head office and other
$
$
4
(95.6) 6.8 96.0 33.4 8.4 0.1 49.1
$
$
86.8 11.3 29.0 35.5 6.9 0.3 169.8
Gross acres (000s) Net acres (000s) Average working interest
$
0.3 47.4 349.6 191.4 18.1 1.3 608.1
$
$
230.3 42.5 149.3 134.2 15.6 1.4 573.3
As at December 31 2002 % Change
5,538 5,313 96%
4,402 4,158 94%
26 28 2
DRILLING PROGRAM Three months ended December 31 2003 2002 Gross Net Gross Net
Natural gas Oil Dry Total wells
101 101 28 230
Success Rate
6
$
UNDEVELOPED LAND
2003
5
Year ended December 31 2003 2002
99 95 28 222
10 18 3 31
87%
10 14 3 27 89%
Year ended December 31 2003 2002 Gross Net Gross Net 307 337 106 750
299 308 106 713
209 112 44 365
85%
197 96 42 335 87%
ACTIVITIES BY CORE AREA
Core Area Northern Peace River Arch Central Plains Southern Saskatchewan/Other
Undeveloped land as at December 31, 2003 (thousands of net acres) 2,084 111 958 1,324 836 5,313
Net wells drilled for the year ended December 31, 2003 175 4 212 313 9 713
Page 3 of 17
7 PRODUCTION AND NETBACKS Three months ended December 31 2003 2002 % Change Natural gas: MMcf per day Operating netback ($ per mcf): Sales price Royalties Operating costs Netback
314.4
$
$
Light oil and NGL’s: Barrels per day Operating netback ($ per barrel): Sales price Royalties Operating costs Netback
$
$
$
$
35.93 5.36 12.28 18.29
$
$
26.60 3.28 7.99 15.33
$
$
47,079
$
$
Combined totals: Barrels of oil equivalent (1) Daily production Operating netback ($ per boe): Sales price Royalties Operating costs Netback
$
11,035
Total liquids: Barrels per day Operating netback ($ per barrel): Sales price Royalties Operating costs Netback
$
36,044
Conventional heavy oil: Barrels per day Operating netback ($ per barrel): Sales price Royalties Operating costs Netback
5.46 1.19 0.64 3.63
33.75 4.87 11.28 17.60
$
$
99,479
$
$
33.24 6.08 7.35 19.81
$
$
337.1
(7)
5.26 1.13 0.46 3.67
4 5 39 (1)
37,498
(4)
36.95 7.50 10.90 18.55
(3) (29) 13 (1)
9,775
13
30.70 4.26 7.50 18.94
(13) (23) 7 (19)
47,273
-
35.66 6.83 10.20 18.63
(5) (29) 11 (6)
103,456
(4)
33.42 6.82 6.15 20.45
(1) (11) 20 (3)
Year ended December 31 2003 2002 % Change 331.3
$
$
6.26 1.38 0.53 4.35
$
$
35,916
$
$
37.08 6.15 11.60 19.33
$
$
10,416
$
$
32.73 4.55 7.59 20.59
$
$
46,332
$
$
36.10 5.79 10.70 19.61
$
$
101,549
$
$
36.91 7.15 6.63 23.13
$
$
332.7
-
3.79 0.83 0.46 2.50
65 66 15 74
34,151
5
34.04 5.99 10.21 17.84
9 3 14 8
9,882
5
28.39 3.84 7.45 17.10
15 18 2 20
44,033
5
32.77 5.51 9.62 17.64
10 5 11 11
99,483
2
27.18 5.20 5.81 16.17
36 38 14 43
(1) Barrels of oil equivalent (boe) are based on six mcf of natural gas equals one barrel of oil (6:1)
For 2003, liquids production increased five percent while gas production remained flat. Overall operating netbacks increased by 43 percent to $23.13 in 2003 from $16.17 in 2002. For the fourth quarter of 2003, liquids prices were reduced by $0.09 per barrel and natural gas prices were increased by $0.02 per mcf, as a result of commodity price hedge settlements. Page 4 of 17
8
RESERVE ESTIMATES
a) Reserve category splits under forecast prices and costs Light & Heavy Oil Medium Oil Reserve (MMbbl) (MMbbl) Estimates Category Proved Developed producing Developed non-producing Undeveloped Total proved Probable Total proved plus probable (1)
111.2 12.7 28.7 152.6 24.0 176.6
20.6 0.1 1.4 22.1 6.3 28.4
Natural Gas
Natural Gas Liquids
(Bcf)
(MMbbl)
577.5 57.5 62.8 697.8 115.5 813.3
12.7 1.1 1.5 15.3 2.0 17.3
(1) Working interest reserves before royalties
Penn West’s reserve estimates have been calculated in compliance with the newly implemented National Instrument 51-101 Standards of Disclosure (“NI 51-101”). These new NI 51-101 standards establish a higher mandated confidence interval for proved and probable reserves. Under NI 51-101, proved reserve estimates are defined as having a 90 percent probability that actual reserves recovered over time will equal or exceed proved reserve estimates. For probable reserves under NI 51-101, there are now equal (50 percent) probabilities that the actual reserves to be recovered will be less than or greater than the proved plus probable reserves estimate. In accordance with NI 51-101, proved undeveloped reserves have been recognized in cases where plans are in place to bring the reserves on production within a short, well-defined time frame. Proved undeveloped reserves often involve infill drilling in existing pools. It should be noted that no proved or probable reserves have been booked for coalbed methane or for CO2 miscible flooding in the Pembina area. Penn West’s reserves have been 100% evaluated by independent third party engineers. Major properties representing 91 percent of the Company’s total proved plus probable reserves were evaluated by either McDaniel & Associates Consultants Ltd. or by Gilbert Laustsen Jung Associates Ltd. depending on the particular location of the property. The balance of approximately nine percent of proved plus probable reserves was evaluated by Resources West Inc. Additional reserve disclosure tables, as required under NI 51-101, will be contained in the Annual Information Form that will be filed on Sedar.
Page 5 of 17
b) Reconciliation of Company working interest reserves by principal product type under forecast prices and costs Oil and Liquids
Reconciliation (1) Items December 31, 2002 Extensions Improved recovery Technical and economic revisions Discoveries Acquisitions Dispositions Production December 31, 2003
Natural Gas
Proved
Proved Plus Probable Proved Probable
(MMbbl)
(MMbbl)
(MMbbl)
(BCF)
Barrels of Oil Equivalent
Proved Plus Probable Probable (BCF)
(BCF)
Proved
Probable
Proved Plus Probable
(MMBOE)
(MMBOE)
(MMBOE)
211.3 15.3
37.6 2.0
248.9 17.3
896.8 72.2
115.9 16.3
1,012.7 88.5
360.8 27.4
56.9 4.7
417.7 32.1
0.1
-
0.1
0.7
-
0.7
0.2
-
0.2
(22.4) 1.3 1.8 (0.6) (16.9)
(7.8) 0.1 0.5 -
(30.1) 1.3 2.3 (0.6) (16.9)
(143.7) 0.2 1.4 (9.0) (120.9)
(17.1) 0.1 0.3 -
(160.8) 0.3 1.7 (9.0) (120.9)
190.0
32.4
222.4
697.8
115.5
813.3
(46.3) 1.3 2.1 (2.1) (37.0)
(10.6) 0.1 0.5 -
(56.9) 1.4 2.6 (2.1) (37.0)
306.3
51.6
357.9
(1) Columns may not add due to rounding
The reserve estimates contained in Table 8b are Company working interest reserves before the deduction of Crown royalties. A net reserve reconciliation after royalties will be included in the Company’s Annual Information Form. Negative proved reserve revisions totalled 46 million barrels of oil equivalent, or approximately 13 percent of the opening balance. Of this amount, approximately one percent relates to the elimination of reserves with a remaining life in excess of 50 years, where Penn West expects to recognize these reserves in subsequent years. An additional three percent is related to the transfer of reserves from proved to probable to reflect stricter guidelines for the timing of bringing undeveloped reserves on-stream. The remaining reduction of nine percent reflects technical revisions based on NI 51-101 standards and reservoir performance. These adjustments cover a number of properties, with the largest single property revision representing less than one percent of the total reduction of 13 percent. Proved plus probable reserves of 357.9 mmboe at the end of 2003, were eight percent lower than established reserves (proved plus 50 percent probable) of 389.3 mmboe, at the end of 2002.
c)
Net present values of future net revenue under forecast prices and costs ($millions) Net Present Value of Future Net Revenue Before Income Taxes (Discounted) Reserve Category 5% 10% 15% Proved Developed producing Developed non-producing Undeveloped Total proved Probable Total proved plus probable
2,346 247 284 2,877 446 3,323
1,977 162 160 2,299 295 2,593
1,728 121 87 1,936 214 2,150
Net present values are net of wellbore abandonment liabilities and are based on the price assumptions that are contained in the following table.
Page 6 of 17
d)
Summary of pricing and inflation rate assumptions as of December 31, 2003 under forecast prices and costs WTI Cushing Oklahoma ($US/bbl)
Year Historical 2000 2001 2002 2003 Forecast 2004 2005 2006 2007 2008 Thereafter*
Oil Edmonton Hardisty Par Price Heavy o o 40 API 12 API ($Cdn/bbl) ($Cdn/bbl)
Cromer Medium o 29 API ($Cdn/bbl)
Natural Gas AECO Gas Price
Edmonton NGL Mix
Inflation Rates
Exchange Rate
($Cdn/GJ)
($Cdn/bbl)
(%)
($US/$Cdn)
30.31 25.97 26.10 30.95
44.72 39.60 39.95 43.10
27.80 18.05 27.60 27.45
40.10 32.22 34.93 36.90
5.32 5.15 3.86 6.30
35.70 31.60 26.20 33.80
2.7 2.6 2.2 2.0
0.674 0.646 0.637 0.715
29.00 26.50 25.50 25.00 25.00 2%
37.70 34.30 33.00 32.30 32.30 2%
22.70 21.55 21.56 20.63 20.39 2%
32.20 29.71 28.84 28.06 27.97 2%
5.50 5.19 4.87 4.68 4.53 2%
27.90 25.50 24.50 23.80 23.70 2%
2.0 2.0 2.0 2.0 2.0 2.0
0.750 0.750 0.750 0.750 0.750 0.750
*0% after 2023
e)
Future development costs under forecast prices and costs ($ millions)
Year
2004 2005 2006 2007 2008 2009 and subsequent Undiscounted total Discounted @ 10%/yr
Proved Future Development Costs
$
$ $
196 100 57 4 20 34 411 349
9 COMMON SHARE DATA (millions of shares) 2003
2002
% Change
Weighted average: (Year ended December 31) Basic Diluted
53.8 54.5
53.2 54.6
1 -
Outstanding: (as at December 31) Basic Basic plus stock options
53.7 57.9
53.7 58.7
(1)
Page 7 of 17
5,000
93 94 95 96 97 98 99 00 01 02 03
812.7 612.9 463.5
560.0 230.3
400
200 100
122.9
300 113.0
13,958
500
0
0
0
600
90.1
10,000
12,604
15,000
10,577
20,000
11,483
25,000
700
63.0
46,332
44,033
20,779
30,000
800
41.5
35,000
38,884
32,462
40,000
900
9.4
13.0
58.2
100
45,000
6,934
184.0
97.4
150
50,000
1,753
129.0
200
164.8
250
50
332.7
245.1
300
331.3
306.2
350
330.3
Charting our Performance
93 94 95 96 97 98 99 00 01 02 03
NATURAL GAS PRODUCTION FOR THE YEAR ENDED DECEMBER 31
CRUDE OIL & NGL PRODUCTION FOR THE YEAR ENDED DECEMBER 31
(mmcf per day)
(bbls per day)
93 94 95 96 97 98 99 00 01 02 03 CASH FLOW FOR THE YEAR ENDED DECEMBER 31
($ millions)
LETTER TO OUR SHAREHOLDERS Penn West’s financial discipline, underpinned by strong commodity prices, generated record cash flows and record annual average production rates during 2003. Penn West achieved these results along with a significant reduction in bank debt, from $598 million at the end of 2002 to $442 million at the end of 2003, resulting in a 2003 year end debt to cash flow ratio of 0.5:1. Reflecting Penn West’s strong financial position, the Company also declared its first ever dividend during 2003, a special dividend of $1.50 per share and a quarterly dividend of $0.125 per share payable beginning in the first quarter of 2004. The year 2003 was one of challenge and of change for Penn West. In the first ten years since our reorganization, we used a formula of equal parts acquisition and development spending along with a healthy dose of exploration to successfully grow the Company. Increased competition for acquisitions and an increase in operating and finding costs impacted our operational performance in 2003. Despite these challenges, Penn West was able to report record cash flow and record annual average production. In addition, we believe that by developing our existing acreage and by focusing our exploration efforts, we will increase the efficiency and growth of our operations. Our production is currently 108,000 boe per day and is slightly ahead of plan. Our financial position remains strong and the outlook for commodity prices is favorable. Penn West’s focused asset base, combined with our financial discipline, presents many opportunities for future value creation. We expect that further strategic changes will be made where required to ensure that we have the proper framework for continuing the growth of Penn West and the enhancement of shareholder value. In that regard, the Board of Directors has commenced a strategic review of alternatives available to the Company as outlined in the highlight section of this news release. On behalf of the Board of Directors,
N. Murray Edwards Chairman
William E. Andrew President
Calgary, Alberta March 2, 2004
Page 8 of 17
MANAGEMENT’S DISCUSSION AND ANALYSIS Management’s discussion and analysis (“MD&A”) of financial conditions and results of operations should be read in conjunction with the unaudited interim consolidated financial statements for the three and twelve months ended December 31, 2003 and the audited consolidated financial statements and MD&A for the year ended December 31, 2002. Oil and Natural Gas Revenues Higher oil and liquids production volumes and higher commodity prices for both crude oil and natural gas, resulted in revenues increasing by 39 percent to $1,368 million for 2003 from $987 million in 2002. Natural gas production of 331 mmcf per day for the year is comparable to production of 333 mmcf per day in 2002. Production of crude oil and liquids increased five percent to 46,332 barrels per day in 2003 from 44,033 barrels per day in 2002. The average natural gas price received in 2003 increased by 65 percent to $6.26 per mcf from $3.79 per mcf in 2002 and surpassed the level of $5.24 per mcf achieved in 2001. The average crude oil and liquids price increased 10 percent to $36.10 per barrel in 2003 from $32.77 per bbl in 2002. Revenues fell by four percent to $304 million during the fourth quarter (Q4) of 2003 from $318 million in Q4 2002. This drop in revenue was attributable to a combination of lower natural gas production and lower crude oil prices received due to the strengthening of the Canadian dollar. Although the benchmark West Texas Intermediate price for crude oil was up year over year, the Company’s revenues were impacted by more than $27 million due to the strengthening of the Canadian dollar over comparable periods. The Company’s average production of natural gas was 314 mmcf per day in the quarter, which was seven percent lower than the production level in Q4 2002. Production of crude oil and liquids was similar over the two reporting periods being 47,079 barrels per day in the current quarter and 47,273 barrels per day in Q4 2002. The average natural gas price received by the Company increased four percent to $5.46 per mcf in the quarter from $5.26 in Q4 2002, and the average crude oil and liquids price was down five percent to $33.75 per barrel in the quarter from $35.66 per barrel in Q4 2002. Commodity hedging activities reduced price realizations for crude oil and liquids in the fourth quarter by $0.09 per barrel and increased the price realization for natural gas by $0.02 per mcf. Increases (decreases) in gross revenues for the year ended December 31, 2003 ($ millions) Gross revenues – 2002 $ 986.9 Increase in oil and liquids production 30.3 Increase in oil and liquids price 53.6 Decrease in natural gas production (1.9) Increase in natural gas price 298.9 Gross revenues – 2003 $ 1,367.8 Royalty Expenses The average royalty rate Penn West incurred in 2003 was 19 percent, the same average rate as in 2002. The oil and liquids royalty rate in 2003 of 16 percent compares to 17 percent in 2002. The natural gas royalty rate increased marginally from 21.9 percent in 2002 to 22.0 percent in 2003. Operating Expenses Operating expenses incurred in 2003 of $246 million were up 17 percent from $211 million in 2002. A portion of this increase reflects higher production volumes. Per unit operating costs also increased 14 percent to $6.63 per boe from $5.81 per boe in 2002. The per unit cost increase was attributable to an increase in production mix to crude oil which has higher per unit operating costs than natural gas. The proportion of crude oil in the Company’s production mix increased to 46 percent of total production in the period from 44 percent in 2002. In addition, higher expenses are being experienced in the oil properties acquired in the latter part of 2002 that have higher per unit operating costs than the Company’s historical property base, and in general field service costs. Operating expenses in Q4 2003 were $67 million, an increase of 14 percent from $59 million in Q4 2002. Per unit operating expenses in Q4 2003 of $7.35 per boe represent a 20 percent increase from $6.15 per boe in Q4 2002. This increase can be attributed to the decline in gas production over the period and the higher cost of services.
Page 9 of 17
General and Administrative Expenses Gross general and administrative expenses increased due to growth in staff levels to manage the Company’s increased drilling program and adjustments to the Company’s salary and benefit programs during 2002 and 2003. Gross expenses of $34 million in the period were up 31 percent from $26 million in 2002. Net general and administrative expenses of $13 million in the period were up 30 percent from $10 million in 2002. On a per unit basis, net expenses were $0.34 per boe in 2003 up 21 percent from $0.28 per boe for the same period of 2002. Net general and administrative expenses in Q4 2003 were $3.7 million up from $3.0 million in Q4 2002. Stock-Based Compensation At the Annual and Special Meeting of the shareholders held in May, 2003, the shareholders approved an amendment to the Company’s Stock Option Plan providing option holders the right to elect the receipt of a cash payment in exchange for surrendering the option. In the fourth quarter of 2003, $7.0 million ($4.5 million after tax) was expensed as stock-based compensation reflecting the increase in stock price over the quarter. See Notes 1 and 4 to the December 31, 2003 interim financial statements for more information on stock-based compensation. Interest Expense Interest expense for 2003 amounted to $12 million, a decrease of 40 percent from $20 million in the same period of 2002. The decrease in interest expense reflected the ability of the Company to capture the benefits of low short-term interest rates available in 2003 on U.S. denominated debt and lower debt levels. Interest expenses in Q4 2003 were $2.9 million down 37 percent from $4.6 million in Q4 2002. Depletion and Depreciation Depletion, depreciation and the site restoration provision increased by 24 percent to a total of $322 million in 2003 from $259 million in 2002. This was a direct result of increases in the Company’s production levels combined with an increase in the depletion rate. Average unit costs increased by 22 percent to $8.69 per boe in the period from $7.13 per boe in the same 2002 period. The depletion, depreciation and site restoration provision in Q4 of $97 million was up 33 percent from $73 million in Q4 2002. Foreign Exchange The Company converted its borrowings to U.S. dollars during 2002 at an average exchange rate of US$0.6392 for each Canadian dollar to capture the benefits of the positive differential between Canadian and U.S. interest rates. As at December 31, 2003, the Company had US$340 million of U.S. denominated debt. The conversion of the outstanding U.S. dollar borrowings at the end of the period, after adjusting for the impact of written Canadian dollar calls, resulted in an unrealized foreign exchange gain of $82.9 million for 2003, versus a loss in 2002 of $4.5 million. The impact of written Canadian dollar calls on the unrealized foreign exchange gain in 2003 was to reduce the potential unrealized foreign exchange gain by $12.7 million. The unrealized gain on foreign exchange in Q4 was $5.4 million compared to a loss of $0.2 million in Q4 2002. Taxes The total provision for income taxes decreased by 19 percent to $100 million in 2003 from $124 million in 2002 as a result of lower income tax rates enacted by the authorities during 2003, offset by higher pre-tax earnings. The provision for income taxes in Q4 2003 of $42 million was down from $49 million in Q4 2002 due to the lower income before tax and lower effective tax rates in the current period. Current cash income taxes were reduced in the fourth quarter by $19.1 million resulting in cash income taxes for the full year 2003 of only $9.9 million. This amount of $9.9 million is a substantial reduction from the amounts previously estimated by the Company, and is $26.1 million less than the $36.0 million of cash income taxes provided by the Company in the first two quarters of 2003. For 2004, cash income taxes are now estimated at $20 million to $40 million. Capital Expenditures Capital expenditures of $608 million in 2003 consisted of $0.3 million of net property acquisitions and $608 million of exploration and development spending. For the same period in 2002, capital expenditures were $573 Page 10 of 17
million consisting of $230 million of net property acquisitions and $343 million of exploration and development spending. The increase in exploration and development expenditures over the same period in 2002 reflects the planned increase in the number of net wells drilled in 2003 compared to 2002. This is consistent with the Company’s strategy to focus on value creation and was in response to the relatively high cost of potential acquisitions driven by a period of relatively high commodity prices. Capital expenditures in Q4 2003 of $49 million decreased 71 percent from $170 million in 2002 as a result of planned asset dispositions that closed in the period. Cash Flow and Net Income Cash flow increased by 75 percent to $813 million ($15.11 basic per share) in 2003 from the $464 million ($8.70 basic per share) in 2002. Net income increased 175 percent to $435 million ($8.09 basic per share) in 2003 from $158 million ($2.98 basic per share) in 2002. In Q4 2003, cash flow increased 27 percent to $194 million ($3.59 basic per share) from $153 million ($2.86 basic per share) in Q4 2002. This increase in cash flow for the quarter from the prior period was mainly the result of reduced cash taxes payable for the period. Net income in Q4 2003 fell 44 percent to $34 million ($0.65 basic per share) from $62 million ($1.16 basic per share) in Q4 2002. The impact of the strong Canadian dollar on Q4 net income versus 2002 was approximately $15 million. The Company achieved a year over year increase in production volumes of two percent while reinvesting less than 80 percent of cash flow. Operating netbacks in 2003 increased 43 percent to $23.13 per boe from $16.17 per boe in 2002 mainly due to the significant increase in year over year prices for natural gas. Operating netbacks in Q4 2003 were $19.81 per boe, down three percent from $20.45 in Q4 2002, as a result of the relatively strong Canadian dollar. Commodity prices for crude oil and natural gas continue to show strength as we enter 2004, providing good margins and profitability for shareholders. Liquidity and Capital Resources The record level of cash flow in 2003 allowed Penn West to fund all of its capital program for 2003 using internally generated cash flow and to use the excess funds to reduce debt, purchase shares in accordance with the approved Normal Course Issuer Bid and to declare, for the first time, a quarterly dividend and a special dividend to shareholders payable on January 2, 2004. Bank debt at the end of December 2003, before payment of the dividends, was $442 million down from $598 million in 2002. In 2003, the Company purchased 1,249,000 common shares for $52.7 million ($42.25 per share). In the fourth quarter of 2003, 355,700 common shares were purchased for $16.5 million ($46.57 per share). The Company is approved to purchase up to 2,687,824 common shares in the period to February 26, 2004. During the year, the Company reduced its revolving credit facility with a syndicate of Canadian banks to $720 million from $765 million, and retained its $50 million operating line of credit. Subsequent to year end, the operating line was increased to $100 million. This facility provides the Company significant financial flexibility to pursue profitable growth opportunities. Outlook On February 18, 2004, Penn West Petroleum Ltd. announced the closing of an acquisition of approximately 10,000 boe per day of production that included 7,000 barrels per day of conventional heavy oil and 18 million cubic feet per day of natural gas. The purchase price of $234 million included producing properties and approximately 400,000 net acres of undeveloped land located in the Kindersley/Coleville region. The acquired properties are in close proximity and represent an excellent fit with Penn West’s existing operations in southwestern Saskatchewan. The acquisition will be funded within Penn West’s existing capital spending targets of $600 to $700 million for 2004. As a result of this transaction, a number of exploration and development wells that were originally planned for 2004 will now be deferred into subsequent years. With the acquisition, Penn West has increased its forecast production range to 105,000 to 109,000 boe per day for 2004. Based on commodity prices of $30.00 U.S. per barrel of WTI and $5.80 per mcf for natural gas, cash flow is also forecast to increase to a range of $640 to $670 million ($11.80 to $12.30 basic per share). Cash income taxes for 2004 are now estimated at $20 to $40 million. Net income is forecast to be in the range of $165 to $180 million ($3.00 to $3.30 basic per share), reflecting higher depletion charges. Page 11 of 17
Sensitivity Analysis This news release includes forward-looking statements (forecasts) under applicable securities laws. These statements are subject to known or unknown risks and uncertainties that could cause actual results to differ materially from those anticipated or implied in the forward-looking statements. Sensitivities to selected key assumptions are outlined in the table below. Impact on cash flow*
Change of: $1.00 per barrel of liquids price Per common share 1,000 barrels per day in liquids production Per common share $0.10 per mcf of natural gas price Per common share 10 mmcf per day in natural gas production Per common share $0.01 in $US/$CAD exchange rate** Per common share
Impact on net income*
16.2 0.30 9.5 0.18 8.9 0.16 15.2 0.28 11.6 0.21
10.2 0.19 3.6 0.07 5.6 0.10 5.5 0.10 7.3 0.14
*$ millions, except per common share amounts ** excludes the impact of any unrealized foreign exchange gains or losses
Penn West Petroleum Ltd. Consolidated Balance Sheets
($ millions, unaudited) Assets Current Accounts receivable Prepaids and other
As at December 31, 2003
$
Property, plant and equipment $ Liabilities and shareholders’ equity Current Accounts payable and accrued liabilities Taxes payable Dividends payable Stock-based compensation (note 4)
$
Bank loan (note 2) Deferred credits (note 3) Future income taxes Shareholders’ equity Share capital (note 4) Retained earnings $
As at December 31, 2002
141.6 42.8 184.4 2,953.7 3,138.1
$
248.1 87.4 22.1 357.6
$
$
145.6 14.0 159.6 2,632.8 2,792.4
185.3 94.3 279.6
442.4 67.6 649.4 1,159.4
598.4 41.3 580.1 1,219.8
505.6 1,115.5 1,621.1 3,138.1
483.8 809.2 1,293.0 2,792.4
$
See accompanying notes to consolidated financial statements. Page 12 of 17
Penn West Petroleum Ltd. Consolidated Statements of Income and Retained Earnings Three months ended December 31 2003 2002
($ millions, except per share amounts, unaudited) Revenues Oil and natural gas Royalties
$
304.1 (55.6) 248.5
Expenses Operating General and administrative Interest on long term debt Depletion and depreciation Stock-based compensation (note 4) Foreign exchange (gain) loss Income before taxes Taxes Capital Current income Future income
Net income Retained earnings, beginning of period Dividends payable Purchase of common shares (note 4) Retained earnings, end of period
$
Net income per common share Basic Diluted
$ $
$
318.1 (64.9) 253.2
Year ended December 31 2003 2002
$
1,367.8 (265.1) 1,102.7
$
986.9 (188.9) 798.0
67.2 3.7 2.9 96.5 7.0 (5.4) 171.9 76.6
58.5 3.0 4.6 72.8 0.2 139.1 114.1
245.5 12.5 11.9 322.0 48.0 (82.9) 557.0 545.7
210.9 10.3 20.3 258.7 4.5 504.7 293.3
0.2 (19.1) 61.1 42.2
3.2 31.0 18.0 52.2
10.2 9.9 90.6 110.7
11.0 82.0 41.9 134.9
34.4
61.9
435.0
158.4
$
747.3 809.2
$
809.2 (87.4) (41.3) 1,115.5
$
650.8 809.2
$ $
1.16 1.14
$ $
8.09 7.98
$ $
2.98 2.90
1,181.7 (87.4) (13.2) 1,115.5
0.65 0.63
See accompanying notes to consolidated financial statements.
Page 13 of 17
Penn West Petroleum Ltd. Consolidated Statements of Cash Flow Three months ended December 31 2003 2002
($ millions, except per share amounts, unaudited) Operating activities Net income Depletion and depreciation Future income taxes Unrealized foreign exchange (gain) loss Stock-based compensation (note 4) Cash flow from operations (Increase) decrease in non-cash working capital Payments for surrendered options (note 4)
$
Investing activities Additions to property, plant and equipment and other, net Expenditures on abandonments Decrease in non-cash working capital
Financing activities (Decrease) increase in bank loan Issue of common shares Purchase of common shares (Increase) decrease in non-cash working capital
Increase in cash Cash, beginning of period Cash, end of period Interest paid Income and capital taxes paid
34.4 96.5 61.1 (5.4) 7.0 193.6 (6.1) (3.6) 183.9
$
Year ended December 31 2003 2002
61.9 72.8 18.0 0.2 152.9 38.0 190.9
$
435.0 322.0 90.6 (82.9) 48.0 812.7 (114.6) (13.6) 684.5
$
158.4 258.7 41.9 4.5 463.5 39.6 503.1
(49.1) (4.2) 11.4 (41.9)
(169.8) (4.9) 4.8 (169.9)
(629.4) (14.3) 58.2 (585.5)
(573.3) (10.8) 22.8 (561.3)
(129.1) 3.7 (16.5) (0.1) (142.0)
(25.6) 4.9 (0.3) (21.0)
(73.1) 26.7 (52.7) 0.1 (99.0)
37.6 20.5 0.1 58.2
$
-
$ $
21.5 32.2
$
-
$ $
3.3 2.7
$
-
$
-
$ $
4.9 2.9
$ $
12.4 140.2
Notes to the Consolidated Financial Statements ($ millions): 1. SIGNIFICANT ACCOUNTING POLICIES These interim consolidated financial statements include the accounts of the Company and its wholly owned subsidiaries and partnerships. These interim consolidated financial statements were prepared in accordance with Canadian generally accepted accounting principles. The same accounting policies and methods of computation as the audited consolidated financial statements as at and for the year ended December 31, 2002 have been used except for the accounting for stock-based compensation costs. These accounting policies and methods of computation are described in the notes to the audited consolidated financial statements for the year ended December 31, 2002. Accordingly, these financial statements should be read in conjunction with the Company’s audited consolidated financial statements and notes thereto for the year ended December 31, 2002. Due to the changes to the Stock Option Plan detailed in Note 4, the Company recognized a liability for potential future cash option payments that may be required on all vested options outstanding plus the pro-rata number of future option vestings attributable to the current period. The amount is based on the excess of the period end share price over the option exercise price. Each quarter, the liability is recalculated to reflect the current share price and outstanding options. Cash option settlements are charged against the liability. The funds received on options exercised for shares, plus the associated liability amount, are included in share capital. Page 14 of 17
2. BANK LOAN As at As at December 31, 2003 December 31, 2002 Bankers’ acceptances LIBOR advances (2003 and 2002 $US 340 million)
$ $
442.4 442.4
$
61.2 537.2 598.4
$
As at December 31, 2003, the Company had unsecured bank credit facilities of $770 million comprising a $720 million credit facility and a $50 million operating loan facility, and had outstanding letters of credit totalling $6.6 million that reduced the amount otherwise available to be drawn on the credit facility. 3. DEFERRED CREDITS As at As at December 31, 2003 December 31, 2002 Site restoration and abandonment Stock-based compensation
$ $
61.8 5.8 67.6
$
41.3 41.3
$
4. SHARE CAPITAL Common shares issued Balance, January 1, 2003 Issued on exercise of stock options Liability settlement on stock options exercised for shares Purchase of shares under Normal Course Issuer Bid Balance, December 31, 2003
Shares 53,732,540 1,208,750
(1,249,000) 53,692,290
Amount $ 483.8 26.7
$
6.5 (11.4) 505.6
The Company commenced its Normal Course Issuer Bid through the facilities of The Toronto Stock Exchange on February 27, 2003. For a period not to exceed one year, a maximum of five percent of the issued and outstanding common shares of the company, or 2,687,824 shares, may be purchased for cancellation. As at December 31, 2003, the Company had purchased 1,249,000 shares, at an average price of $42.25 per share, and a total cost of $52.7 million. The cost of these shares in excess of book value was applied to retained earnings. The shareholders approved changes to the Stock Option Plan at the Annual and Special Meeting on May 20, 2003. Employees and directors may now elect to receive a cash payment in exchange for surrendering vested stock options. The cash payment is equal to the weighted average share price for the three prior trading days less the option exercise price. As a result of the Stock Option Plan amendment, commencing June 30, 2003, the Company recognizes the potential liability that could arise if all employees and directors elected the cash settlement alternative at the period end share price. Provision is made for all vested options, including those granted in prior years, plus a pro-rata number of future option vestings attributable to the current period. For the year ended December 31, 2003, $48 million ($30.4 million after income tax) was expensed as stock-based compensation with no restatement of prior periods. During the 2003 period, $13.6 million of cash option payments were made and charged against the liability. Prior to the above amendment, no charges to earnings were made for stock option grants and certain proforma amounts were provided using the Black-Scholes option pricing model. As stock-based compensation is now charged to earnings, the pro-forma disclosures are no longer presented.
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Number of stock options
Stock options Outstanding, January 1, 2003 Granted Exercised for common shares Exercised for cash Forfeited Outstanding, December 31, 2003 Exercisable, December 31, 2003
5,005,750 1,563,850 (1,208,750) (741,820) (392,240) 4,226,790 875,480
Weighted average exercise price $
29.97 41.32 22.10 28.33 35.36 36.21 32.88
$ $
5. FINANCIAL INSTRUMENTS The Company had the following financial instruments outstanding as at December 31, 2003: Notional Volume Crude Oil WTI Costless Collars WTI Costless Collars Natural Gas AECO Costless Collars Electricity Alberta Power Pool Swaps Alberta Power Pool Swaps Alberta Power Pool Swaps Interest Rates Libor Interest Rate Swaps Foreign Exchange Canadian Dollar Call Sales
Remaining Term
Pricing
25,000 Bbls/d 10,000 Bbls/d
Jan/04 – Jun/04 Jul/04 – Sept/04
$US 25.65 to 31.08/Bbl $US 25.50 to 30.70/Bbl
25,000 GJ/d
Jan/04 – Mar/04
$6.00 to 9.07/GJ
50 MW 60 MW 60 MW
2004 2005 2006
$44.00 to $50.00/MWh $41.00 to $50.00/MWh $42.25 to $43.15/MWh
$US 100 million
Jun/04
1.164%
$US 340 million
Jan/04
CAD/USD $0.7497
In the fourth quarter of 2003, the Company recognized the full potential impact of its written Canadian calls. The total provision of $12.7 million is included in current liabilities. These instruments provided counterparties a one-day option of selling the Company US dollars at an average rate of $0.7497 CAD/US. Subsequent to December 31, 2003, the instruments were extended without any cash cost to the Company and no counterparties have exercised their put option. 6. INCOME TAXES The majority of the Company’s taxable income is generated by partnerships. Current income taxes are incurred on a portion of the partnerships’ taxable income in the year following their inclusion in the Company’s consolidated net income. Due to reductions in Federal and Provincial tax rates, the Company recorded a $100 million future income tax recovery during the second and third quarters of 2003 (2002 – provincial recovery of $6.8 million). 7. SUBSEQUENT EVENT On February 18, 2004, the Company acquired oil and natural gas assets that produce approximately 10,000 boe per day of production, including 7,000 barrels per day of conventional heavy oil and 18 million cubic feet per day of natural gas. The purchase price included producing properties and approximately 400,000 net acres of undeveloped land in southwest Saskatchewan. The purchase price of $234 million was financed by the bank loan. To reflect the increased size of Company operations, the Company increased its operating loan facility to $100 million from $50 million.
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On March 1, 2004, the Board of Directors of the Company resolved to review three alternatives examining the benefits and challenges with regard to the following options: 1) Maintaining the status quo and continuing its strategic direction as an independent oil and natural gas exploration and development company; 2) Converting the Company in whole or in part into an income trust. In this regard, the Board has instructed legal counsel to obtain an advance ruling from Canada Customs and Revenue Agency regarding the tax consequences of a potential conversion to an income trust. Receipt of a satisfactory ruling will be a material consideration in pursuing this alternative; and 3) Consider other strategic alternatives including a sale or merger of the Company.
Investor Information
Penn West Petroleum Ltd. is a senior independent Canadian oil and natural gas company, based in Calgary, Alberta, that focuses on exploration and development activity. Penn West trades on The Toronto Stock Exchange under the symbol PWT. A conference call will be held to discuss Penn West’s results at 9:00 a.m. Mountain Time, 11:00 a.m. Eastern Time on Tuesday, March 2, 2004. The North American conference call number is 1-800-814-4890. A taped recording will be available until Tuesday, March 9, 2004 by dialing 1-877-289-8525 or 416-640-1917 and entering passcode 21032541#. This call will be broadcast live on the internet and may be accessed directly on the Penn West website www.pennwest.com or at the following URL: http://www.newswire.ca/en/webcast/viewEvent.cgi?eventID=709500. Notes to Reader 1.) This document contains forward-looking statements (forecasts) under applicable securities laws. Forwardlooking statements are necessarily based upon assumptions and judgements with respect to the future including, but not limited to, the outlook for commodity markets and capital markets, the performance of producing wells and reservoirs, and the regulatory and legal environment. Many of these factors can be difficult to predict. As a result, the forward-looking statements are subject to known or unknown risks and uncertainties that could cause actual results to differ materially from those anticipated or implied in the forward-looking statements 2.) All dollar amounts contained in this document are expressed in Canadian dollars unless noted otherwise. 3.) Where applicable, natural gas has been converted to barrels of oil equivalent (boe) using a conversion rate of 6 mcf of natural gas equals 1 boe.
For further information, please contact: PENN WEST PETROLEUM LTD. Suite 2200, 425 - First Street S.W. Calgary, Alberta T2P 3L8 Phone: (403) 777-2500 Fax: (403) 777-2699 www.pennwest.com William Andrew, President Phone: (403) 777-2502
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