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SECURITIES AND EXCHANGE COMMISSION
FORM 6-K
Report of Foreign Private Issuer
Pursuant to Rule 13a-16 or 15d-16 of the
Securities Exchange Act of 1934
For the period October 31, 2003 to November 11, 2003
PENGROWTH ENERGY TRUST
Petro-Canada Centre – East Tower
2900, 111 – 5th Avenue S.W.
Calgary, Alberta T2P 3Y6 Canada
[Indicate by check mark whether the registrant files or will file annual reports under cover Form 20-F or Form 40-F.]
| Form 20-F o | Form 40-F þ |
[Indicate by check mark whether the registrant by furnishing the information contained in this Form is also thereby furnishing the information to the Commission pursuant to Rule 12g3-2(b) under the Security Exchange Act of 1934.
| Yes o | No þ |
[If “Yes” is marked, indicate below the file number assigned to the registrant in connection with Rule 12g3-2(b): ]
| SIGNATURES | ||||||||
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DOCUMENTS FURNISHED HEREUNDER:
| 1. | Third Quarter Report for the period ended September 30, 2003. |
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SIGNATURES
Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.
|
PENGROWTH ENERGY TRUST by its administrator PENGROWTH CORPORATION |
||||
| November 11, 2003 | By: | |||
Name: Gordon M. Anderson Title: Vice President |
||||
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THIRD QUARTER RESULTS
SEPTEMBER 30, 2003
HIGHLIGHTS
•
Distributable cash for the third quarter 2003 increased 58% over the third quarter of 2002 to $73.0 million as a result of
higher commodity prices and increased production. For the nine month period, distributable cash increased 90% to
$241.9 million, and a further $26.8 million was retained to fund capital expenditures. At the end of the third quarter
2003, $6.5 million is available for distribution in future months.
•
As a result of sustained strength in commodity prices, Pengrowth realized netbacks of $18.31 per boe for the quarter,
and $20.05 per boe on a year to date basis.
•
Cash distributions increased to $0.63 per unit in the third quarter 2003 from $0.52 per unit in the same quarter last year.
For the nine month period ended September 30, 2003, cash distributions increased to $2.05 per unit compared to
$1.47 per unit for the same period in 2002.
•
Pengrowth’s on-going development program helped offset natural production declines during the quarter.
Production for the third quarter averaged 48,850 boepd, up slightly from the second quarter average production rate
of 48,839 boepd.
•
Capital expenditures during the third quarter totaled $20.7 million. Total capital expenditures of $56.2 million on a year
to date basis have been made.
•
On July 23, Pengrowth closed a public offering of 8.5 million trust units at $16.95 per unit to raise total gross proceeds
of $144.1 million (net $136.3 million). A portion of the proceeds were used to repay bank indebtedness and a cash
balance of $78.0 million was on hand at the end of the third quarter.
•
At the end of the third quarter, Pengrowth had a net debt to net debt plus equity ratio of 15%, which underscores the
strong financial position at the end of the quarter. In addition to the cash balance of $78.0 million, unutilized
borrowing capacity of approximately $226 million was available at the end of the third quarter to fund future
acquisitions.
•
Subsequent to quarter end, Pengrowth announced it had entered into an agreement to purchase Emera’s 8.4%
interest in the Sable Offshore Energy Project (SOEP) platform facilities for a purchase price of $65 million prior to
adjustments. This acquisition will eliminate the remainder of the SOEP processing fees which currently average
approximately $1.3 million per month.
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Note regarding currency: All figures contained within this report are quoted in Canadian dollars unless otherwise indicated.
Financial and Operating Highlights
| Three Months ended | Nine Months ended | ||||||||||||||||||||||||
| September 30 | September 30 | ||||||||||||||||||||||||
| % | % | ||||||||||||||||||||||||
| (thousands, except per unit amounts) | 2003 | 2002 | Change | 2003 | 2002 | Change | |||||||||||||||||||
INCOME STATEMENT |
|||||||||||||||||||||||||
Oil and gas sales |
$ | 160,695 | $ | 111,205 | 45 | % | $ | 530,718 | $ | 314,383 | 69 | % | |||||||||||||
Net income |
$ | 33,025 | $ | 12,497 | 164 | % | $ | 146,510 | $ | 26,543 | 452 | % | |||||||||||||
Net income per unit |
$ | 0.28 | $ | 0.14 | 100 | % | $ | 1.29 | $ | 0.31 | 316 | % | |||||||||||||
Funds generated from operations |
$ | 86,977 | $ | 52,703 | 65 | % | $ | 278,947 | $ | 150,182 | 86 | % | |||||||||||||
Funds generated from operations per unit |
$ | 0.73 | $ | 0.58 | 26 | % | $ | 2.45 | $ | 1.75 | 40 | % | |||||||||||||
Funds withheld to fund capital expenditures |
$ | 8,106 | $ | — | 100 | % | $ | 26,831 | $ | — | 100 | % | |||||||||||||
Distributable cash before withholding* |
$ | 81,057 | $ | 46,139 | 76 | % | $ | 268,777 | $ | 127,398 | 111 | % | |||||||||||||
Distributable cash before withholding per unit* |
$ | 0.68 | $ | 0.51 | 33 | % | $ | 2.36 | $ | 1.49 | 58 | % | |||||||||||||
Distributable cash* |
$ | 72,951 | $ | 46,139 | 58 | % | $ | 241,946 | $ | 127,398 | 90 | % | |||||||||||||
Actual distributions paid or declared per unit |
$ | 0.63 | $ | 0.52 | 21 | % | $ | 2.05 | $ | 1.47 | 40 | % | |||||||||||||
Weighted average number of units outstanding |
118,928 | 90,380 | 32 | % | 113,751 | 85,783 | 33 | % | |||||||||||||||||
BALANCE SHEET |
|||||||||||||||||||||||||
Working capital |
$ | 24,852 | $ | (26,132 | ) | 195 | % | $ | 24,852 | $ | (26,132 | ) | 195 | % | |||||||||||
Property, plant and equipment and other assets |
$ | 1,419,193 | $ | 1,123,863 | 26 | % | $ | 1,419,193 | $ | 1,123,863 | 26 | % | |||||||||||||
Long-term debt |
$ | 269,980 | $ | 259,024 | 4 | % | $ | 269,980 | $ | 259,024 | 4 | % | |||||||||||||
Unitholders’ equity |
$ | 1,126,721 | $ | 834,309 | 35 | % | $ | 1,126,721 | $ | 834,309 | 35 | % | |||||||||||||
Unitholders’ equity per unit |
$ | 9.29 | $ | 9.23 | 1 | % | $ | 9.29 | $ | 9.23 | 1 | % | |||||||||||||
Number of units outstanding at period end |
121,286 | 90,398 | 34 | % | 121,286 | 90,398 | 34 | % | |||||||||||||||||
TRUST UNIT TRADING (TSX) |
|||||||||||||||||||||||||
High |
$ | 17.87 | $ | 15.63 | $ | 18.22 | $ | 17.00 | |||||||||||||||||
Low |
$ | 16.20 | $ | 13.01 | $ | 13.39 | $ | 13.01 | |||||||||||||||||
Close |
$ | 17.25 | $ | 14.90 | $ | 17.25 | $ | 14.90 | |||||||||||||||||
Value |
$ | 349,497 | $ | 140,784 | 148 | % | $ | 1,166,122 | $ | 503,516 | 132 | % | |||||||||||||
Volume (thousands of units) |
20,476 | 9,367 | 119 | % | 73,172 | 33,350 | 119 | % | |||||||||||||||||
TRUST UNIT TRADING (NYSE) — Listed on April 10, 2002 |
|||||||||||||||||||||||||
High |
$ | 13.13 | US | $ | 10.25 | US | $ | 13.80 | US | $ | 10.90 | US | |||||||||||||
Low |
$ | 11.55 | US | $ | 8.40 | US | $ | 9.07 | US | $ | 8.40 | US | |||||||||||||
Close |
$ | 12.81 | US | $ | 9.37 | US | $ | 12.81 | US | $ | 9.37 | US | |||||||||||||
Value |
$ | 230,205 | US | $ | 11,027 | US | 1988 | % | $ | 582,065 | US | $ | 29,135 | US | 1898 | % | |||||||||
Volume (thousands of units) |
18,614 | 1,141 | 1531 | % | 49,282 | 2,925 | 1585 | % | |||||||||||||||||
DAILY PRODUCTION |
|||||||||||||||||||||||||
Crude oil (barrels) |
22,852 | 17,640 | 30 | % | 23,722 | 18,079 | 31 | % | |||||||||||||||||
Natural gas (thousands of cubic feet) |
122,140 | 105,434 | 16 | % | 120,693 | 106,430 | 13 | % | |||||||||||||||||
Natural gas liquids (barrels) |
5,641 | 4,991 | 13 | % | 5,660 | 5,114 | 11 | % | |||||||||||||||||
Total production (BOE) 6:1 |
48,850 | 40,203 | 22 | % | 49,498 | 40,931 | 21 | % | |||||||||||||||||
PRODUCTION INCREASE (year over year) |
22 | % | -7 | % | 21 | % | 5 | % | |||||||||||||||||
PRODUCTION PROFILE (6:1 conversion) |
|||||||||||||||||||||||||
Crude oil |
47 | % | 44 | % | 48 | % | 44 | % | |||||||||||||||||
Natural gas |
42 | % | 44 | % | 41 | % | 43 | % | |||||||||||||||||
Natural gas liquids |
11 | % | 12 | % | 11 | % | 13 | % | |||||||||||||||||
AVERAGE PRICES |
|||||||||||||||||||||||||
Crude oil (per barrel) |
$ | 39.06 | $ | 40.40 | -3 | % | $ | 41.45 | $ | 37.19 | 11 | % | |||||||||||||
Natural gas (per mcf) |
$ | 5.67 | $ | 3.38 | 68 | % | $ | 6.49 | $ | 3.32 | 95 | % | |||||||||||||
Natural gas liquids (per barrel) |
$ | 32.44 | $ | 30.42 | 7 | % | $ | 35.47 | $ | 27.11 | 31 | % | |||||||||||||
Average price per BOE |
$ | 35.76 | $ | 30.07 | 19 | % | $ | 39.27 | $ | 28.13 | 40 | % | |||||||||||||
*See Note 2 to Financial Statements
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President’s Message
Pengrowth is very pleased to present the unaudited quarterly results for the three months and nine months ended September 30, 2003.
Sustained strength in commodity prices, and successful results of operations contributed to the favorable third quarter results, and Energy Trust also reported an excellent financial position at the end of the third quarter of 2003. During the quarter, Pengrowth trust unitholders continued to benefit from the expertise and wisdom of the Trust’s experienced personnel, including team members in the operations group. Second quarter production levels were sustained during the third quarter at approximately 48,800 boepd through on-going development and production optimization activities. Pengrowth’s average realized commodity price for the third quarter declined by about 5% from the second quarter of 2003 to Cdn $35.76 per BOE, however distributable cash increased marginally to $73.0 million compared to $71.8 million reported for the second quarter of 2003, partially as a result of lower overall expenses for the quarter.
The majority of Pengrowth’s revenue is denominated in U.S. dollars and thus the rising Canadian dollar relative to the U.S. dollar could result in a decrease in both cash flow and earnings from operations in the future, depending upon the relative level of oil and gas prices.
Looking forward, strength in commodity price levels could assist in moderating the downward pressure of a stronger Canadian dollar. The upcoming winter heating season could provide upward pressure on natural gas prices which are currently trading in the range of Cdn $5.00 — $5.25 per mcf. Oil prices have recently been hovering in the U.S. $28.00 — U.S. $30.00 WTI range and some analysts predict that this may be indicative of a new target price band for OPEC, particularly considering the recent decline in the U.S. dollar relative to other major world currencies.
Pengrowth’s present ratio of net debt to total capitalization is approximately 14% at book, reflecting the trust’s favourable financial position. At September 30, 2003, cash on hand totaled $78.0 million, and together with unused lines of credit of approximately $226 million, Energy Trust is well positioned to capitalize on future acquisition opportunities.
Since completing the U.S. $200 million private placement in April, Pengrowth has recorded an approximate $20 million book gain due to the rise in the Canadian dollar relative to its U.S. counterpart.
Trading activity on both the TSX and NYSE remained brisk with average daily trading volumes on the TSX and NYSE at approximately 325,000 and 295,000 respectively for the three months ended September 30, 2003. On the TSX the unit price traded between a low of Cdn $16.20 and a high of Cdn $17.87, while on the NYSE, units traded between U.S. $11.55 and U.S. $13.13. The firm unit price reflects, in part, the positive market response to the stable distributions unitholders received during this period (Cdn $0.21 per trust unit for the July, August and September distributions).
Subsequent to quarter end, an agreement was announced to purchase Emera’s 8.4% interest in the Sable Offshore Energy Project (SOEP) production platform facilities for a consideration of $65 million, subject to adjustments. This acquisition will complete the consolidation of Pengrowth’s interests in SOEP, which commenced with the acquisition of the onshore facilities in May of this year. It will have the added benefit of eliminating Pengrowth’s requirement to post further letters
3
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of credit to Emera, and will also reduce SOEP operating costs by approximately $1.3 million per month through elimination of the Emera processing fees. The net effect for Energy Trust is to reduce overall operating costs by approximately $0.80 per BOE based on current production rates. It is contemplated that this acquisition will be financed through existing credit facilities. Capital expenditures which totaled $56.2 million for the first nine months of the year have been fully funded through 1) withholdings from distributable income totaling $26.8 million; 2) DRIP proceeds of $17.2 million; and 3) proceeds from the issuance of new trust units — options and rights exercise of $14.7 million.
Pengrowth is well positioned to take advantage of future acquisitions that are potentially accretive to unitholders. We continue to pursue such opportunities to enhance distributable income, and increase overall returns on behalf of our unitholders.
James S. Kinnear
Chairman, President and Chief Executive Officer
October 31, 2003
For further information about Pengrowth, please visit our website www.pengrowth.com or contact:
Investor Relations, Calgary Telephone: (403) 233-0224 Toll Free: 1-800-223-4122 Facsimile: (403) 294-0051
Investor Relations, Toronto Telephone: (416) 362-1748 Toll Free: 1-888-744-1111 Facsimile: (416) 362-8191
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Management’s Discussion and Analysis
The following discussion and analysis of financial results should be read in conjunction with:
| • | The MD&A and the audited consolidated financial statements for the years ended December 31, 2002 and 2001; and | ||
| • | The interim unaudited consolidated financial statements as at and for the nine month’s ended September 30, 2003. |
Note Regarding Forward-Looking Statements
This discussion and analysis contains forward-looking statements. These statements relate to future events or our future performance. In some cases, you can identify forward-looking statements by terminology such as “may”, “will”, “should”, “expect”, “plan”, “anticipate”, “believe”, “estimate”, “predict”, “potential”, “continue”, or the negative of these terms or other comparable terminology. These statements are only predictions. A number of factors, including the business risks discussed below, may cause actual results to vary materially from these estimates. Actual events or results may differ materially. In addition, this discussion contains forward-looking statements attributed to third party industry sources. Readers should not place undue reliance on these forward-looking statements.
When converting natural gas to equivalent barrels of oil within this discussion, Pengrowth uses the international standard of 6 thousand cubic feet (mcf) to one barrel of oil equivalent (boe). Production volumes and revenues are reported on a gross basis (before crown and freehold royalties) in accordance with Canadian practice. All amounts are stated in Canadian dollars unless otherwise specified.
Distributable Cash
Distributable cash increased by 58% to $73.0 million in the third quarter of 2003, from $46.1 million in the third quarter of 2002. For the nine months ended September 30, 2003, Pengrowth recorded $241.9 million in distributable cash, compared to $127.4 million in the first nine months of 2002. An additional $26.8 million of distributable cash from the first nine months of 2003 was withheld to fund capital expenditures and a balance of $6.5 million remained to be distributed to unitholders in future months.
Actual distributions were $0.63 per unit for the third quarter of 2003 compared to $0.52 per unit for the third quarter of 2002, and $2.05 per unit on a year to date basis in 2003 compared to $1.47 per unit for the first nine months of 2002.
The increase in distributable cash is attributable mainly to higher commodity prices (Pengrowth’s average per boe selling price was 40% higher in the first nine months of 2003 compared to the same period in the prior year), and a 21% increase in production, offset in part by a reduced payout ratio — commencing with the January 2003 distribution, approximately 10% of cash available for distribution has been withheld to repay debt or fund capital expenditures.
The following is a summary of recent monthly distributions and future key dates:
| Ex-Distribution | Distribution | Distribution Amount | US$ | |||||||||
| Date* | Record Date | Payment Date | per Trust Unit | Amount** | ||||||||
| December 27, 2002 | December 31, 2002 | January 15, 2003 | $ | 0.20 | $ | 0.13 | ||||||
| January 30, 2003 | February 3, 2003 | February 15, 2003 | $ | 0.20 | $ | 0.13 | ||||||
| February 27, 2003 | March 3, 2003 | March 15, 2003 | $ | 0.25 | $ | 0.17 | ||||||
| March 28, 2003 | April 1, 2003 | April 15, 2003 | $ | 0.25 | $ | 0.17 | ||||||
| April 29, 2003 | May 1, 2003 | May 15, 2003 | $ | 0.25 | $ | 0.18 | ||||||
| May 29, 2003 | June 2, 2003 | June 15, 2003 | $ | 0.25 | $ | 0.18 | ||||||
| June 26, 2003 | June 30, 2003 | July 15, 2003 | $ | 0.21 | $ | 0.15 | ||||||
| July 29, 2003 | July 31, 2003 | August 15, 2003 | $ | 0.21 | $ | 0.15 | ||||||
| August 27, 2003 | August 29, 2003 | September 15, 2003 | $ | 0.21 | $ | 0.15 | ||||||
| September 26, 2003 | September 30, 2003 | October 15, 2003 | $ | 0.21 | $ | 0.15 | ||||||
| October 29, 2003 | October 31, 2003 | November 15, 2003 | $ | 0.21 | $ | 0.16 | ||||||
| November 27, 2003 | December 1, 2003 | December 15, 2003 | ||||||||||
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* To benefit from the monthly cash distribution, unitholders must purchase or hold trust units prior to the ex-distribution date.
** Before applicable withholding taxes.
Net Income
Net income for the third quarter of 2003 was $33.0 million compared to $12.5 million for the previous year. The increase is due mainly to higher production and commodity prices compared to the prior year. For the first nine months of 2003, Pengrowth recorded net income of $146.5 million, compared to $26.5 million for the previous year. Net income for the nine month period ended September 30, 2003 includes a foreign exchange gain of $19.5 million. This relates mainly to an unrealized gain on Pengrowth’s U.S. dollar denominated debt due to a rise in the Canadian dollar relative to the U.S. dollar since the U.S. $200 million debt financing was completed in April, 2003.
Netbacks
| Three months ended | Nine months ended | |||||||||||||||
| September 30 | September 30 | |||||||||||||||
| Netbacks per boe of Production (6:1) | 2003 | 2002 | 2003 | 2002 | ||||||||||||
Oil and gas sales |
$ | 35.76 | $ | 30.07 | $ | 39.27 | $ | 28.13 | ||||||||
Crown and freehold royalties, net of incentives |
(6.17 | ) | (5.23 | ) | (7.01 | ) | (4.17 | ) | ||||||||
Other income |
0.62 | 0.65 | 0.58 | 0.44 | ||||||||||||
Operating costs |
(7.98 | ) | (8.03 | ) | (8.14 | ) | (7.86 | ) | ||||||||
Amortization of injectants |
(1.69 | ) | (2.89 | ) | (1.96 | ) | (3.06 | ) | ||||||||
Operating Netback |
20.54 | 14.57 | 22.74 | 13.48 | ||||||||||||
Interest |
(0.98 | ) | (0.95 | ) | (1.06 | ) | (0.84 | ) | ||||||||
General and administrative |
(0.86 | ) | (0.54 | ) | (0.87 | ) | (0.65 | ) | ||||||||
Management fees |
(0.40 | ) | (0.36 | ) | (0.59 | ) | (0.40 | ) | ||||||||
Capital taxes and Other |
0.01 | (0.05 | ) | (0.17 | ) | (0.06 | ) | |||||||||
Netback per boe |
$ | 18.31 | $ | 12.67 | $ | 20.05 | $ | 11.53 | ||||||||
Production
Total BOE production has increased 22% in the third quarter of 2003, compared to the third quarter of 2002. For the nine months ended September 30, 2003 total production is 21% higher than the same period last year. The increase in production is attributable mainly to the acquisition of properties in British Columbia on October 1, 2002.
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| Three months ended | Nine months ended | ||||||||||||||||||||||||
| September 30 | September 30 | ||||||||||||||||||||||||
| 2003 | 2002 | %Change | 2003 | 2002 | %Change | ||||||||||||||||||||
Daily Production |
|||||||||||||||||||||||||
Crude oil (bbls/d) |
22,852 | 17,640 | +30 | % | 23,722 | 18,079 | +31 | % | |||||||||||||||||
Natural gas (mcf/d) |
122,140 | 105,434 | +16 | % | 120,693 | 106,430 | +13 | % | |||||||||||||||||
Natural gas liquids (bbls/d) |
5,641 | 4,991 | +13 | % | 5,660 | 5,114 | +11 | % | |||||||||||||||||
Total boe/d |
48,850 | 40,203 | +22 | % | 49,498 | 40,931 | +21 | % | |||||||||||||||||
Total production (mboe) |
4,494 | 3,698 | +22 | % | 13,513 | 11,174 | +21 | % | |||||||||||||||||
Production per trust unit (boe per unit) |
0.04 | 0.04 | — | 0.12 | 0.13 | -8 | % | ||||||||||||||||||
Oil production volumes increased 30% in the third quarter, and 31% for the nine month period ended September 30, 2003, compared to the same periods last year. Most of this increase is attributable to the acquisition of oil producing properties in B.C. including Rigel, Squirrel and Oak.
Natural gas production increased 16% in the third quarter of 2003 compared to the third quarter of 2002 and increased 13% on a year to date basis. This increase is attributable to the B.C. property acquisition on October 1, 2002 as well as the acquisition of additional interests in the Quirk Creek area in the second quarter of 2002, offset in part by natural production declines.
Natural gas liquids production increased 13% in the third quarter of 2003 over the third quarter of 2002 and 11% on a year to date basis.
Assuming there are no further acquisitions, dispositions or major production interruptions during the fourth quarter, Pengrowth expects to meet the 2003 production forecast of 48,500 boepd.
Prices
| Three months ended | Nine months ended | ||||||||||||||||||||||||
| September 30 | September 30 | ||||||||||||||||||||||||
| Average realized prices Cdn $ | |||||||||||||||||||||||||
| (after impact of hedging) | 2003 | 2002 | %Change | 2003 | 2002 | %Change | |||||||||||||||||||
Crude oil (per bbl) |
$ | 39.06 | $ | 40.40 | -3 | % | $ | 41.45 | $ | 37.19 | +11 | % | |||||||||||||
Natural gas (per mcf) |
$ | 5.67 | $ | 3.38 | +68 | % | $ | 6.49 | $ | 3.32 | +95 | % | |||||||||||||
Natural gas liquids (per boe) |
$ | 32.44 | $ | 30.42 | +7 | % | $ | 35.47 | $ | 27.11 | +31 | % | |||||||||||||
Total per boe |
$ | 35.76 | $ | 30.07 | +19 | % | $ | 39.27 | $ | 28.13 | +40 | % | |||||||||||||
WTI Oil Price ($US / bbl) |
AECO Gas Price ($Cdn / mcf) |
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Pengrowth’s average crude oil price declined 3% in the third quarter of 2003 compared to the third quarter of 2002. During this period, the West Texas Intermediate (WTI) oil price increased 7% however the decrease in the U.S. dollar relative to the Canadian dollar resulted in a 6% decline in the Canadian dollar equivalent WTI benchmark oil price. A reduction in net hedging losses on crude oil in the third quarter of 2003 compared to the third quarter of 2002 partially offset this decline.
For the first nine months of 2003, Pengrowth’s average crude oil price was 11% higher than the same period last year. This increase is in line with the exchange rate adjusted increase in WTI during the period — WTI increased by 22% offset by a 10% decrease in the Cdn $/US $ exchange rate. An increase in hedging losses in the first nine months of 2003 reduced Pengrowth’s average realized crude oil price, while lower differentials on some streams of crude in 2003 increased the average price relative to the prior year.
Pengrowth’s average natural gas price for the third quarter of 2003 increased by 68% over prices realized in the third quarter of 2002. For the first nine months of 2003 prices increased by 95% to $6.49 per mcf compared to $3.32 per mcf over the same period last year. By comparison, the AECO and Nymex indices posted gains of 92% and 90% respectively in the first nine months of 2003 as compared to the same period last year. Hedging losses accounted for a reduction of approximately $0.49 per mcf in Pengrowth’s net realized gas price for the nine month period.
Price Risk Management Program
Natural Gas
In the third quarter of 2003, Pengrowth realized a net hedging loss of $1.3
million related to fixed price gas contracts (as compared to monthly AECO
average spot prices) and natural gas financial swap contracts, compared to a
net hedging gain of $0.1 million for the same period last year. On a year to
date basis, Pengrowth has realized a net hedging loss on natural gas of $16.3
million in the first nine months of 2003, compared to a net hedging loss of
$0.4 million for the same period last year.
Crude Oil
Net hedging losses realized on crude oil price swap transactions were $0.3
million in the third quarter of 2003, and $8.3 million on a year to date basis,
compared to a loss of $3.2 million in the third quarter of 2002 and $3.6
million net loss in the first nine months of 2002.
Current Position
Pengrowth currently has 11,000 barrels per day of crude oil (approximately 48%
of current oil production) hedged for the remainder of 2003 at an average price
of Cdn $41.48 per barrel, and 9,500 barrels per day of 2004 production at an
average price of Cdn $38.11. Pengrowth has fixed the exchange rate on all of
our current crude oil hedging contracts.
Approximately 26% of current natural gas production is also hedged — 14,218 mcf per day of Western gas production is hedged at an average plantgate price of Cdn $6.07 per mcf, and 17,000 MMBTU of Eastern gas at an average plantgate price of Cdn $5.11 per MMBTU for the remainder of 2003.
Based on the closing forward market prices at September 30,2003, the mark-to-market value of Pengrowth’s financial swap contracts was $1.0 million - negative $8.0 million on natural gas contracts and positive $9.0 million for crude oil. The details of Pengrowth’s commodity hedges are provided in Note 8 to the financial statements.
Royalties
Royalties, including crown and freehold royalties, were 17.2 % of oil and gas sales in the three months ended September 30, 2003, compared to 17.4 % in 2002. For the nine month period, royalties were 17.9 % and 14.9% in 2003 and 2002, respectively. The increase in the year to date royalty percentage in 2003 over 2002 is due in part to higher average commodity prices in 2003, particularly natural gas, the addition of the B.C. properties in October 2002 (which have a higher royalty rate than the balance of Pengrowth’s property portfolio), and lower injection credits relative to total crown royalties. In addition, increased hedging losses in 2003 result in a higher reported royalty rate, since hedging losses on financial swaps do not impact royalty calculations.
Operating Costs
Operating costs were $35.8 million ($7.98 per boe) for the third quarter of 2003, compared to $29.7 million ($8.03 per boe) for the third quarter of 2002. Third quarter operating costs per boe are somewhat lower than the $8.22 per boe
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recorded in the first six months of 2003 due in part to the acquisition of an 8.4% interest in the SOEP onshore facilities on May 8, 2003, which has reduced processing fees at Sable by approximately $1.2 million per month.
For the nine months ended September 30, 2003, operating costs were $110.0 million ($8.14 per boe), compared to $87.8 million ($7.86 per boe) for the first nine months of 2002.
Injectants for miscible floods
During the third quarter of 2003, Pengrowth purchased $2.2 million of injectants and amortized a related $7.6 million against third quarter income and distributable cash. On a year to date basis, Pengrowth has purchased $17.1 million of injectants and amortized $26.5 million. At September 30, 2003, the balance of unamortized injectant costs was $24.4 million.
General and administrative
General and administrative expenses (G&A) were $3.9 million in the third quarter of 2003 compared to $2.0 million for the third quarter of 2002. For the nine months ended September 30, 2003, G&A expenses were $11.8 million compared to $7.2 million for the same period last year. On a per boe basis, year to date G&A is $0.87 per boe, compared to $0.65 per boe for the first nine months of 2002. G&A costs have increased in 2003 due to a number of factors including the move to larger office space and increased staffing due to the purchase of the BC properties at the end of 2002, and increased legal and regulatory expenses associated with being listed on the New York Stock Exchange since April 2002.
Management Fees
Management fees were $1.8 million for the third quarter of 2003 compared to $1.3 million for the third quarter of 2002. For the nine month period, management fees were $7.9 million in 2003 compared to $4.5 million in 2002. On a per boe basis, management fees for the first nine months of 2003 are $0.59 per boe, compared to $0.40 per boe in 2002. Although the management fee rate decreased effective July 1, 2003 there is an increase in total management fees due to the higher fee base in 2003 — management fees are calculated on a percentage of “net operating income” (oil and gas sales and other income, less royalties, operating costs, solvent amortization and reclamation funding).
A new management agreement, which was approved at the annual general meeting on June 17, 2003, is effective July 1, 2003. Under the terms of this agreement, the base fee has been reduced from a sliding scale between 3.5% and 2.5%, to 2% on the first $200 million of net operating income and 1% on net operating income over $200 million; acquisition fees have been eliminated, and the manager is eligible to receive a ‘performance fee’ if certain performance criteria are met; in particular returns that exceed 8% per annum on a three year rolling average basis. The maximum fees, including the performance fee, is limited to 80% of the fees that would otherwise have been paid under the old management agreement (including acquisition fees) for the first three years, and 60% for the second three years.
Interest
Interest expense increased to $4.4 million in the third quarter of 2003 compared to $3.5 million for the third quarter of 2002. This increase is due to higher average long term debt and higher interest rates paid in the third quarter of 2003. All of Pengrowth’s debt outstanding at the end of the third quarter of 2003 is U.S. dollar denominated and is fixed rate term debt with a higher effective interest rate than the floating rate bank debt in 2002. The recent increase in the Canadian dollar relative to the U.S. dollar has helped to offset the higher interest rate on the term debt, since this interest is payable in U.S. dollars.
For the first nine months of 2003, interest expense was $14.4 million compared to $9.3 million for the first nine months of 2002. Included in 2003 interest is $2.2 million associated with terminating interest rate swaps on $125 million of Canadian bank debt.
Depletion and Depreciation
Depletion and depreciation increased to $44.1 million in the third quarter of 2003 compared to $31.5 million in the third quarter of 2002. For the nine month period, depletion and depreciation was $130.9 million compared to $93.6 million in the first nine months of 2002. On a per boe basis, depletion and depreciation has increased to $9.69 per boe in the first nine months of 2003 compared to $8.37 per boe in the first nine months of 2002. The purchase of B.C. properties in the fourth quarter of 2002 has increased depletion due to the shorter reserve life of these properties relative to the balance of Pengrowth’s property portfolio. The May 2003 purchase of a working interest in the SOEP onshore facilities,
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with no associated increase in reserves, also increased the amount of depreciation per boe.
LIQUIDITY AND CAPITAL RESOURCES
Pengrowth’s long-term debt at September 30, 2003 was fixed rate term debt all denominated in U.S. dollars and translated to $270 million, compared to $317 million at December 31, 2002. Due to the recent increase in the Canadian dollar relative to the U.S. dollar, an unrealized gain of $20.3 million has been recorded since the debt issuance in April 2003.
At September 30, 2003 Pengrowth also had cash and term deposits of $78.0 million, resulting in net debt (long term debt less cash and term deposits) of $191.9 million. The ratio of net debt to trailing 12-month distributable cash at September 30, 2003 was 0.6 times, compared to 1.6 times at December 31, 2002. The ratio of net debt to net debt plus equity is 15% at September 30, 2003, compared to 23% at year-end 2002. Distributable cash covered interest expense by 16 times in the first nine months of 2003.
Capital Spending
Capital expenditures for the nine months ending September 30, 2003 totaled $56.2 million of which $48.2 million was spent on drilling, completion and tie-ins, and $8.0 million was spent on facilities and equipment. 2003 expenditures include $14.8 million at Judy Creek, $11.3 million at Sable, $6.1 million at Weyburn, $4.6 million at McLeod River, $3.2 million at Oak, and $2.1 million at Elm.
Approximately one half of the first nine months capital expenditures have been funded through the 10% holdback from distributable cash, and proceeds from the DRIP and option programs have funded the balance.
Subsequent Event
On October 31, 2003, Pengrowth entered into an agreement with Emera Offshore Incorporated (“Emera”) to purchase Emera’s 8.4% interest in the Sable Offshore Energy Project platform facilities for a purchase price of $65 million before adjustments.
The acquisition is scheduled to close on or about December 15, 2003. The acquisition will provide the following significant benefits for Pengrowth Energy Trust:
| • | A material reduction in processing fees incurred by Pengrowth. Gilbert Laustsen Jung & Associates (“GLJ”), independent engineers, have estimated that the purchase price of the platform interests under the proposed payment schedule is equivalent to the net present value of the reduction in the processing fees using a present value discount factor of approximately 12% based on proven reserves (including anticipated downward revisions of SOEP reserves). GLJ are currently in the process of evaluating the reserves for year-end 2003. SOEP reserves constitute approximately 15% of Pengrowth’s reserves and production. | ||
| • | For the nine months ended September 30, 2003, the reduction in processing fees for the platforms would have lowered Pengrowth’s operating costs by approximately $10.9 million, reducing our operating costs per boe, from $8.14 per boe to $7.33 per boe. | ||
| • | These transactions are expected to be accretive to Unitholders of Pengrowth Energy Trust and are forecast to result in an increase in distributions of approximately 5 cents per unit in each of the next five years. | ||
| • | A significant reduction in letter of credit requirements (“L/C’s”). | ||
| • | The return by Emera of a $25 million L/C issued by Pengrowth. | ||
| • | The elimination of the requirement to issue a further $45 million in L/C’s to Emera in the 2004-2005 period. |
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OPERATIONS REVIEW
REVIEW OF DEVELOPMENT ACTIVITIES (all volumes stated below are net to Pengrowth unless otherwise stated)
OPERATED PROPERTIES:
Judy Creek: (Judy Creek “A” Pool – 100% working interest; Judy Creek “B” Pool 98.4% working interest)
| • | Drilling activities during the third quarter included two wells in the Judy Creek “A” Pool, a water injector in the Northwest quadrant of the pool to improve oil recovery in a newly formed waterflood pattern and an infill producer in the Southwest quadrant of the pool with current production from this new producer at 60 bopd (net). This was the third infill producer to be drilled in this quadrant in 2003, with plans for additional drilling during the fourth quarter of 2003 and 2004. | ||
| • | Water injection commenced at injector 06-15-064-11W5 during the third quarter (drilled in the second quarter). Current incremental oil production from this new waterflood pattern is in excess of 60 bopd (net). | ||
| • | Workovers were conducted on two “A” Pool horizontal miscible injectors with one worked over to improve injection performance and the second workover performed in preparation for a new miscible flood. |
McLeod River: (47.5% average working interest)
| • | One well was drilled and is currently being completed. Another will spud in mid October. | ||
| • | A total of 5 wells have been drilled to date in 2003 with two on production, one under evaluation, one being completed and one standing. | ||
| • | One wellsite compressor was installed increasing production from 70 mcf/d to 210 mcf/d (net) and a field compressor was downsized to increase efficiency. | ||
| • | 1 1/2 sections of crown land was purchased with plans to drill a well in the first quarter of 2004. |
Cessford: (82.5% working interest)
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| • | Commenced an 8 well Milk River/Medicine Hat drilling program on one section of operated land. Wells to be tied in by early November. (Additional details regarding Cessford can be found in the Non-Operated Properties Review). |
Oak: (88.9% working interest)
| • | Oak “C” unitization is complete and starting to see positive signs of waterflood response. | ||
| • | Currently seeking Oil and Gas Corporation approval and working on unitization issues with partners to form the Oak “B” Cecil Unit. |
Laprise: (100% working interest)
| • | A suspended Baldonnel gas well was placed on production August 26 and is currently producing approximately 1.6 mmcf/d (net). | ||
| • | Purchased one section of crown land and have a location which will be drilled in early 2004. |
Tupper: (50% working interest)
| • | Drilled 3 wells in Tupper resulting in two gas wells and one abandonment. | ||
| • | The first gas well went on production September 15 at approximately 1.3 mmcf/d (net) and the second should come on production in early November. | ||
B.C. Undeveloped Lands:
| • | Pengrowth owns approximately 247,000 net acres of net undeveloped land in Northeastern B.C. On these lands, Pengrowth has completed 14 farmout transactions with other companies and our land department is actively pursuing other transactions. Year to date, our farmout activities have resulted in 17 wells drilled, 8 wells reworked and 5 wells committed to but not yet drilled. Approximately $13 million has been spent by others on Pengrowth undeveloped B.C. lands so far this year. |
NON-OPERATED PROPERTIES:
Sable Offshore Energy Project: (8.4% royalty interest)
Tier 1
| • | Third quarter gross raw gas production from the SOEP Tier 1 fields, Thebaud, Venture and North Triumph was 458.0 mmcf/d for July, 417.7 mmcf/d for August and 415.8 mmcf/d for September. Production volumes in August and September were down from July volumes due to mechanical problems with one of the gas compressors at the Goldboro gas plant and flare tip replacements at Thebaud. |
Tier 2 Project Status Review
| • | The Alma jacket was successfully set in April 2003 and two production wells were subsequently drilled. In September 2003 the topsides were installed on the jacket. The two Alma wells will be perforated and |
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| tested in late October with sales gas expected to flow in early November. | |||
| • | Fabrication of the jacket and topsides for South Venture (the second Tier 2 field) is underway. South Venture is expected to start production in early 2005. |
Weyburn: (9.8% working interest)
| • | CO2 injection continued to average approximately 90 mmcf/d during the third quarter. Three horizontal wells were drilled in July with another six wells expected to be drilled and on production by mid November. The operator, Encana, also continues to pursue low cost production optimization strategies which resulted in an incremental 600 bopd (59 bopd Pengrowth). |
Swan Hills: (10.5% working interest)
| • | The operator, Devon Canada, embarked on a three well drilling program with two wells rig released in September. The third well was spudded on September 27, 2003. It is anticipated that the wells will be on-stream by November. |
Cessford: (60% working interest)
| • | Pengrowth is currently participating in a 73 well shallow gas drilling program in the Cessford area of Alberta which is operated by EOG Resources. The productive horizons are the Medicine Hat and Milk River formations. The wells will be completed and tied in during October and are expected to be on-stream by the end of November. Pengrowth anticipates its share of incremental reserves resulting from this program to be in the range of 6 bcf. |
2003 Tax Estimate Update
Pengrowth forecasts that in the current commodity price environment, approximately 55-60% of distributions paid in 2003 will be taxable to unitholders, with the remainder of distributions treated as return of capital and thus tax deferred.
James S. Kinnear
Chairman, President and Chief Executive Officer
October 31, 2003
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Consolidated Balance Sheets
(Stated in thousands of dollars)
| As at | As at | |||||||
| September 30 | December 31 | |||||||
| 2003 | 2002 | |||||||
| (unaudited) | (audited) | |||||||
ASSETS |
||||||||
CURRENT ASSETS |
||||||||
Cash and term deposits |
$ | 78,041 | $ | 8,292 | ||||
Marketable securities |
— | 1,906 | ||||||
Accounts receivable |
39,613 | 41,426 | ||||||
Inventory |
829 | 1,301 | ||||||
| 118,483 | 52,925 | |||||||
REMEDIATION TRUST FUND |
7,136 | 6,679 | ||||||
DEFERRED CHARGES(Note 3) |
2,014 | — | ||||||
PROPERTY, PLANT AND EQUIPMENT
AND OTHER ASSETS |
1,419,193 | 1,444,668 | ||||||
| $ | 1,546,826 | $ | 1,504,272 | |||||
LIABILITIES AND UNITHOLDERS’ EQUITY |
||||||||
CURRENT LIABILITIES |
||||||||
Accounts payable and accrued liabilities |
$ | 35,663 | $ | 43,092 | ||||
Distributions payable to unitholders |
57,443 | 45,315 | ||||||
Due to Pengrowth Management Limited |
525 | 1,086 | ||||||
| 93,631 | 89,493 | |||||||
LONG-TERM DEBT (Note 3) |
269,980 | 316,501 | ||||||
FUTURESITERESTORATION COSTS |
56,494 | 44,339 | ||||||
TRUST UNITHOLDERS’ EQUITY (Note 4) |
1,126,721 | 1,053,939 | ||||||
SUBSEQUENT EVENT (Note 9) |
||||||||
| $ | 1,546,826 | $ | 1,504,272 | |||||
See accompanying notes to the consolidated financial statements.
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Consolidated Statements of Income
| Three months ended | Nine months ended | ||||||||||||||||||||
| September 30 | September 30 | ||||||||||||||||||||
| (Stated in thousands of dollars) | |||||||||||||||||||||
| (Unaudited) | 2003 | 2002 | 2003 | 2002 | |||||||||||||||||
REVENUES |
|||||||||||||||||||||
Oil and gas sales |
$ | 160,695 | $ | 111,205 | $ | 530,718 | $ | 314,383 | |||||||||||||
Processing and other income |
2,408 | 2,030 | 7,387 | 5,066 | |||||||||||||||||
Crown royalties, net of incentives |
(26,114 | ) | (17,560 | ) | (88,890 | ) | (41,693 | ) | |||||||||||||
Freehold royalties and mineral taxes |
(1,594 | ) | (1,736 | ) | (5,846 | ) | (5,042 | ) | |||||||||||||
| 135,395 | 93,939 | 443,369 | 272,714 | ||||||||||||||||||
Interest and other income |
364 | 380 | 419 | (145 | ) | ||||||||||||||||
NET REVENUE |
135,759 | 94,319 | 443,788 | 272,569 | |||||||||||||||||
EXPENSES |
|||||||||||||||||||||
Operating |
35,845 | 29,717 | 109,980 | 87,774 | |||||||||||||||||
Amortization of injectants for miscible floods |
7,610 | 10,704 | 26,506 | 34,158 | |||||||||||||||||
Interest |
4,402 | 3,529 | 14,390 | 9,333 | |||||||||||||||||
General and administrative |
3,862 | 1,999 | 11,803 | 7,218 | |||||||||||||||||
Management fee |
1,817 | 1,343 | 7,912 | 4,483 | |||||||||||||||||
Capital taxes |
368 | 468 | 1,439 | 749 | |||||||||||||||||
Foreign exchange loss (gain) (Note 6) |
24 | (292 | ) | (19,452 | ) | 69 | |||||||||||||||
Depletion and depreciation |
44,149 | 31,464 | 130,892 | 93,577 | |||||||||||||||||
Future site restoration |
4,646 | 2,881 | 13,770 | 8,640 | |||||||||||||||||
| 102,723 | 81,813 | 297,240 | 246,001 | ||||||||||||||||||
INCOME
BEFORE THE FOLLOWING |
33,036 | 12,506 | 146,548 | 26,568 | |||||||||||||||||
ROYALTY
INCOME ATTRIBUTABLE TO ROYALTY UNITS
OTHER THAN THOSE HELD BY PENGROWTH ENERGY TRUST |
11 | 9 | 38 | 25 | |||||||||||||||||
NET INCOME |
$ | 33,025 | $ | 12,497 | $ | 146,510 | $ | 26,543 | |||||||||||||
NET INCOME PER UNIT (Note 4) |
Basic | $ | 0.278 | $ | 0.138 | $ | 1.288 | $ | 0.309 | ||||||||||||
| Diluted | $ | 0.276 | $ | 0.138 | $ | 1.282 | $ | 0.309 | |||||||||||||
See accompanying notes to the consolidated financial statements.
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Consolidated Statements of Cash Flow
| Three months ended | Nine months ended | |||||||||||||||
| September 30 | September 30 | |||||||||||||||
| (Stated in thousands of dollars) | ||||||||||||||||
| (Unaudited) | 2003 | 2002 | 2003 | 2002 | ||||||||||||
CASH PROVIDED BY (USED FOR): |
||||||||||||||||
OPERATING |
||||||||||||||||
Net income |
$ | 33,025 | $ | 12,497 | $ | 146,510 | $ | 26,543 | ||||||||
Items not involving cash |
||||||||||||||||
Depletion, depreciation and future site restoration |
48,795 | 34,345 | 144,662 | 102,217 | ||||||||||||
Amortization of injectants |
7,610 | 10,704 | 26,506 | 34,158 | ||||||||||||
Purchase of injectants |
(2,231 | ) | (4,298 | ) | (17,077 | ) | (11,744 | ) | ||||||||
Expenditures on remediation |
(778 | ) | (370 | ) | (1,615 | ) | (817 | ) | ||||||||
Unrealized foreign exchange loss (gain) (Note 6) |
480 | — | (20,260 | ) | — | |||||||||||
Amortization of deferred charges (Note 3) |
76 | — | 127 | — | ||||||||||||
Loss (gain) on sale of marketable securities |
— | (175 | ) | 94 | (175 | ) | ||||||||||
Funds generated from operations |
86,977 | 52,703 | 278,947 | 150,182 | ||||||||||||
Distributions |
(74,426 | ) | (43,378 | ) | (229,818 | ) | (115,798 | ) | ||||||||
Changes in non-cash operating working capital (Note 7) |
13,137 | 2,771 | (5,053 | ) | (6,127 | ) | ||||||||||
| 25,688 | 12,096 | 44,076 | 28,257 | |||||||||||||
FINANCING |
||||||||||||||||
Change in long-term debt |
(64,780 | ) | 39,901 | (26,261 | ) | (86,432 | ) | |||||||||
Proceeds from issue of trust units |
143,850 | 738 | 168,218 | 117,961 | ||||||||||||
| 79,070 | 40,639 | 141,957 | 31,529 | |||||||||||||
INVESTING |
||||||||||||||||
Deposit on acquisition |
— | (29,063 | ) | — | (29,063 | ) | ||||||||||
Expenditures on property acquisitions |
(146 | ) | (1,681 | ) | (61,488 | ) | (35,636 | ) | ||||||||
Expenditures on property, plant and equipment |
(20,678 | ) | (14,783 | ) | (56,193 | ) | (40,215 | ) | ||||||||
Proceeds on property dispositions |
84 | (72 | ) | 2,835 | 44,523 | |||||||||||
Deferred charges |
(3 | ) | — | (2,141 | ) | — | ||||||||||
Change in Remediation Trust Fund |
(277 | ) | (145 | ) | (457 | ) | (483 | ) | ||||||||
Purchase of marketable securities |
— | — | — | (2,780 | ) | |||||||||||
Proceeds from sale of marketable securities |
— | 959 | 1,812 | 1,050 | ||||||||||||
Change in non-cash investing working capital (Note 7) |
(1,410 | ) | (1,835 | ) | (652 | ) | 1,684 | |||||||||
| (22,430 | ) | (46,620 | ) | (116,284 | ) | (60,920 | ) | |||||||||
INCREASE (DECREASE) IN CASH AND TERM DEPOSITS |
82,328 | 6,115 | 69,749 | (1,134 | ) | |||||||||||
CASH AND TERM DEPOSITS (BANK INDEBTEDNESS) AT
BEGINNING OF PERIOD |
(4,287 | ) | (3,452 | ) | 8,292 | 3,797 | ||||||||||
CASH AND TERM DEPOSITS AT END OF PERIOD |
$ | 78,041 | $ | 2,663 | $ | 78,041 | $ | 2,663 | ||||||||
See accompanying notes to the consolidated financial statements.
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Consolidated Statements of Trust
Unitholders’ Equity
| Three months ended | Nine months ended | |||||||||||||||
| September 30 | September 30 | |||||||||||||||
| (Stated In thousands of dollars) | ||||||||||||||||
| (Unaudited) | 2003 | 2002 | 2003 | 2002 | ||||||||||||
Unitholders’ equity at beginning of period |
$ | 1,022,797 | $ | 867,213 | $ | 1,053,939 | $ | 817,203 | ||||||||
Units issued, net of issue costs |
143,850 | 738 | 168,218 | 117,961 | ||||||||||||
Net income for period |
33,025 | 12,497 | 146,510 | 26,543 | ||||||||||||
Distributable cash (Note 2) |
(72,951 | ) | (46,139 | ) | (241,946 | ) | (127,398 | ) | ||||||||
TRUST UNITHOLDERS’ EQUITY AT END OF PERIOD |
$ | 1,126,721 | $ | 834,309 | $ | 1,126,721 | $ | 834,309 | ||||||||
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Notes To Consolidated Financial Statements
(Unaudited)
SEPTEMBER 30, 2003
(Tabular amounts are stated in thousands of dollars except per unit amounts)
| 1. | SIGNIFICANT ACCOUNTING POLICY | |
| The interim consolidated financial statements of Pengrowth Energy Trust include the accounts of Pengrowth Energy Trust and Pengrowth Corporation (collectively referred to as “Pengrowth”). The financial statements have been prepared by management in accordance with accounting principles generally accepted in Canada. The interim consolidated financial statements have been prepared following the same accounting policies and methods of computation as the consolidated financial statements for the fiscal year ended December 31, 2002. The disclosures provided below are incremental to those included with the annual consolidated financial statements. The interim consolidated financial statements should be read in conjunction with the consolidated financial statements and the notes thereto in Pengrowth’s annual report for the year ended December 31, 2002. | ||
| 2. | DISTRIBUTABLE CASH | |
| There is no standardized measure of Distributable Cash and therefore Distributable Cash, as presented below, may not be comparable to similar measures presented by other energy trusts. |
| Three months ended | Nine months ended | |||||||||||||||
| September 30 | September 30 | |||||||||||||||
| 2003 | 2002 | 2003 | 2002 | |||||||||||||
Net income |
$ | 33,025 | $ | 12,497 | $ | 146,510 | $ | 26,543 | ||||||||
Add (Deduct): |
||||||||||||||||
Depletion, depreciation and future site
restoration |
48,795 | 34,345 | 144,662 | 102,217 | ||||||||||||
Remediation expenses and trust fund contributions |
(1,118 | ) | (578 | ) | (2,260 | ) | (1,487 | ) | ||||||||
Unrealized foreign exchange loss (gain) (Note 6) |
480 | — | (20,260 | ) | — | |||||||||||
Other |
(125 | ) | (125 | ) | 125 | 125 | ||||||||||
Distributable cash before withholding |
81,057 | 46,139 | 268,777 | 127,398 | ||||||||||||
Cash withheld to fund capital expenditures |
(8,106 | ) | — | (26,831 | ) | — | ||||||||||
Distributable cash |
$ | 72,951 | $ | 46,139 | $ | 241,946 | $ | 127,398 | ||||||||
Less: Actual distributions paid or declared |
(66,493 | ) | (45,799 | ) | (235,488 | ) | (127,058 | ) | ||||||||
Balance to be distributed |
$ | 6,458 | $ | 340 | $ | 6,458 | $ | 340 | ||||||||
Actual distributions paid or declared per unit |
$ | 0.630 | $ | 0.520 | $ | 2.050 | $ | 1.470 | ||||||||
| The per unit amount of distributions paid or declared reflect actual distributions paid or declared based on units outstanding at the time. |
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| 3. | LONG TERM DEBT |
| As at | As at | |||||||
| September 30, | December 31, | |||||||
| 2003 | 2002 | |||||||
U.S. dollar denominated debt: |
||||||||
U.S. $150 million senior unsecured notes at 4.93% due April 2010 |
$ | 217,680 | $ | — | ||||
U.S. $50 million senior unsecured notes at 5.47% due April 2013 |
72,560 | — | ||||||
Unrealized foreign exchange gain on translation |
(20,260 | ) | — | |||||
| 269,980 | — | |||||||
Canadian dollar revolving credit borrowings |
— | 316,501 | ||||||
| $ | 269,980 | $ | 316,501 | |||||
| On April 23, 2003, Pengrowth closed a U.S. $200 million private placement of senior unsecured notes to a group of U.S. investors. The notes were offered in two tranches of U.S. $150 million at 4.93% due April 2010 and U.S. $50 million at 5.47% due in April 2013. The term notes contain certain financial maintenance covenants and interest is paid semi-annually. The proceeds from the private placement were used to repay a portion of Pengrowth’s outstanding bank debt. Costs incurred in connection with issuing the notes, in the amount of $2,141,000, are being amortized straight line over the term of the notes. | ||
| In June 2003, the Corporation negotiated a $225 million revolving credit facility syndicated among eight financial institutions with an extendible 364 day revolving period and a two year amortization term period. In addition, it has a $35 million demand operating line of credit. The borrowing capacity under these facilities is currently reduced by outstanding letters of credit in the amount of approximately $34 million. For 2004, the borrowing capacity will be reduced by a further $25 million of letters of credit. Interest payable on amounts drawn is at the prevailing bankers’ acceptance rates plus stamping fees, lenders’ prime lending rates, or U.S. libor rates plus applicable margins, depending on the form of borrowing by the Corporation. The margins and stamping fees vary from 0.25 percent to 1.50 percent depending on financial statement ratios and the form of borrowing. | ||
| The credit facility will revolve until June 18, 2004, whereupon it may be renewed for a further 364 days, subject to satisfactory review by the lenders, or converted into a term facility with amounts outstanding under the facility repayable in eight equal quarterly installments. The Corporation can post, at its option, security suitable to the banks in lieu of the first year’s payments. | ||
| 4. | TRUST UNITS | |
| The authorized capital of Pengrowth is 500,000,000 trust units. |
| September 30, 2003 | December 31, 2002 | |||||||||||||||
| Number | Number | |||||||||||||||
| Trust Units Issued | of units | Amount | of units | Amount | ||||||||||||
Balance, beginning of period |
110,562,327 | $ | 1,662,726 | 82,240,069 | $ | 1,280,599 | ||||||||||
Issued for cash |
8,500,000 | 144,075 | 28,125,000 | 404,350 | ||||||||||||
Less: issue expenses |
— | (7,776 | ) | — | (24,989 | ) | ||||||||||
Issued for cash on exercise of stock options and rights |
1,066,155 | 14,709 | 66,093 | 871 | ||||||||||||
Issued for cash under Distribution Reinvestment (“DRIP”) Plan |
1,157,871 | 17,210 | 131,165 | 1,895 | ||||||||||||
Balance, end of period |
121,286,353 | $ | 1,830,944 | 110,562,327 | $ | 1,662,726 | ||||||||||
| The per unit amounts for net income are based on weighted average units outstanding for the period. The weighted average units outstanding for the three months ended September 30, 2003 were 118,928,247 units and for the nine months ended September 30, 2003 were 113,751,004 (three months ended September 30, 2002 – 90,379,792 units, nine months ended September 30, 2002 – 85,782,649 units). In computing diluted net income per unit, 621,952 units were added to the weighted average number of units outstanding during the quarter ended September 30, 2003 (September 30, 2002 – 89,929 units) and 487,391 units were added for the nine months ended |
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| September 30, 2003 (nine months ended September 30, 2002 – 49,936 units) for the dilutive effect of employee stock options and rights. | ||
| Trust Unit Option Plan | ||
| As at September 30, 2003, options to purchase 3,706,805 trust units were outstanding (December 31, 2002 – 4,451,131) that expire at various dates to June 28, 2009. |
| September 30, 2003 | December 31, 2002 | |||||||||||||||
| Weighted | Weighted | |||||||||||||||
| Number | Average | Number | Average | |||||||||||||
| Trust Unit Options | of options | Exercise price | of options | Exercise price | ||||||||||||
Outstanding at beginning of period |
4,451,131 | $ | 16.78 | 3,106,635 | $ | 17.78 | ||||||||||
Granted |
— | — | 1,895,603 | 15.14 | ||||||||||||
Exercised |
(682,280 | ) | 13.93 | (66,093 | ) | 13.17 | ||||||||||
Cancelled |
(62,046 | ) | 17.17 | (485,014 | ) | 17.23 | ||||||||||
Outstanding at period-end |
3,706,805 | $ | 17.30 | 4,451,131 | $ | 16.78 | ||||||||||
Exercisable at period-end |
3,264,289 | $ | 17.73 | 3,715,271 | $ | 17.04 | ||||||||||
| Rights Incentive Plan | ||
| As at September 30, 2003, rights to purchase 1,648,325 trust units were outstanding (December 31, 2002 – 1,964,100) that expire at various dates to June 9, 2008. |
| September 30, 2003 | December 31, 2002 | |||||||||||||||
| Weighted | Weighted | |||||||||||||||
| Number | Average | Number | Average | |||||||||||||
| Rights Incentive Options | Of rights | Exercise price | of rights | Exercise price | ||||||||||||
Outstanding at beginning of period |
1,964,100 | $ | 13.29 | — | $ | — | ||||||||||
Granted |
100,800 | 15.76 | 1,964,100 | 13.61 | ||||||||||||
Exercised |
(383,875 | ) | 13.56 | — | — | |||||||||||
Cancelled |
(32,700 | ) | 12.75 | — | — | |||||||||||
Outstanding at period-end |
1,648,325 | $ | 12.30 | 1,964,100 | $ | 13.29 | ||||||||||
Exercisable at period-end |
327,625 | $ | 12.43 | 654,700 | $ | 13.29 | ||||||||||
| Fair Value of Unit Based Compensation | ||
| Had compensation cost for options and rights granted to employees since January 1, 2002, been calculated based on the fair value method, net income would be reduced as follows: |
| Three months ended | Nine months ended | ||||||||||||||||
| September 30 | September 30 | ||||||||||||||||
| 2003 | 2002 | 2003 | 2002 | ||||||||||||||
Net income |
$ | 33,025 | $ | 12,497 | $ | 146,510 | $ | 26,543 | |||||||||
Compensation cost related to options |
(111 | ) | (128 | ) | (312 | ) | (803 | ) | |||||||||
Compensation cost related to rights |
(1,404 | ) | — | (6,000 | ) | — | |||||||||||
Pro forma net income |
$ | 31,510 | $ | 12,369 | $ | 140,198 | $ | 25,740 | |||||||||
Pro forma net income per unit: |
|||||||||||||||||
Basic |
$ | 0.265 | $ | 0.137 | $ | 1.232 | $ | 0.300 | |||||||||
Diluted |
$ | 0.264 | $ | 0.137 | $ | 1.227 | $ | 0.300 | |||||||||
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| 5. | GUARANTEE | |
| Pengrowth has adopted the provisions of Accounting Guideline acG-14, Disclosure of Guarantees. | ||
| As at September 30, 2003, the Corporation has provided a guarantee to an investment dealer pursuant to the employee Trust Unit Margin Purchase Plan. Under the terms of this plan, participants may purchase trust units and finance up to 75% of the purchase price through the investment dealer. Participants maintain personal margin loans with the investment dealer and are responsible for all interest costs and obligations with respect to their margin loans. The Corporation has provided a $5 million letter of credit to the investment dealer in relation to amounts owing under the plan. | ||
| The Corporation acts as a guarantor on all margin loans under the plan. As at September 30, 2003, 2,477,510 trust units were deposited under the plan with a market value of $42,737,048 and a corresponding margin loan of $6,358,248. The investment dealer has limited the total margin loan available under the plan to the lesser of $15 million or 35% of the market value of the units held under the plan. If the market value of the trust units under the plan declines, the Corporation may be required to make payments or post additional letters of credit to the investment dealer. Any payments to be made by the Corporation would be reduced by proceeds of liquidating the individual’s trust units held under the plan. | ||
| 6. | FOREIGN EXCHANGE LOSS (GAIN) |
| Three months ended | Nine months ended | |||||||||||||||
| September 30 | September 30 | |||||||||||||||
| 2003 | 2002 | 2003 | 2002 | |||||||||||||
Unrealized foreign exchange loss (gain)
on translation of U.S. dollar
denominated debt |
$ | 480 | $ | — | $ | (20,260 | ) | $ | — | |||||||
Realized foreign exchange losses (gains) |
(456 | ) | (292 | ) | 808 | 69 | ||||||||||
| $ | 24 | $ | (292 | ) | $ | (19,452 | ) | $ | 69 | |||||||
| The U.S. dollar denominated debt is translated into Canadian dollars at the exchange rate in effect at the balance sheet date. Foreign exchange gains and losses are included in income. | ||
| 7. | OTHER CASH FLOW DISCLOSURES | |
| Change in Non-Cash Operating Working Capital |
| Three months ended | Nine months ended | |||||||||||||||
| September 30 | September 30 | |||||||||||||||
| 2003 | 2002 | 2003 | 2002 | |||||||||||||
Accounts receivable |
$ | 5,710 | $ | 156 | $ | 1,813 | $ | (4,727 | ) | |||||||
Inventory |
(139 | ) | 282 | 472 | 1,711 | |||||||||||
Accounts payable and accrued liabilities |
7,825 | 2,371 | (6,777 | ) | (3,104 | ) | ||||||||||
Due to Pengrowth Management Limited |
(259 | ) | (38 | ) | (561 | ) | (7 | ) | ||||||||
| $ | 13,137 | $ | 2,771 | $ | (5,053 | ) | $ | (6,127 | ) | |||||||
| Change in Non-Cash Investing Working Capital |
| Three months ended | Nine months ended | |||||||||||||||
| September 30 | September 30 | |||||||||||||||
| 2003 | 2002 | 2003 | 2002 | |||||||||||||
Accounts payable for capital accruals |
$ | (1,410 | ) | $ | (1,835 | ) | $ | (652 | ) | $ | 1,684 | |||||
| Cash Payments |
| Three months ended | Nine months ended | |||||||||||||||
| September 30 | September 30 | |||||||||||||||
| 2003 | 2002 | 2003 | 2002 | |||||||||||||
Cash payments made for taxes |
$ | 366 | $ | 500 | $ | 1,363 | $ | 1,290 | ||||||||
Cash payments made for interest |
$ | 2,065 | $ | 3,265 | $ | 9,346 | $ | 9,803 | ||||||||
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| 8. | FINANCIAL INSTRUMENTS | |
| Interest Rate Risk | ||
| On April 23, 2003, Pengrowth completed a U.S. $200 million private placement of fixed rate seven and ten year term notes. Proceeds from the notes were used to pay down existing floating rate bank debt. The interest and principal payments on the term notes are payable in U.S. dollars. Pengrowth had previously fixed the interest rates on $125 million of Canadian bank debt using interest rate swaps. During the second and third quarter, Pengrowth terminated these interest rate swaps at a total cost including accrued interest of approximately $2,229,000. | ||
| Foreign Exchange Risk | ||
| Pengrowth entered into a foreign exchange swap which fixed the Canadian to U.S. dollar exchange rate at Cdn $1.55 per U.S. $1 on U.S. $750,000 per month for 2003 and 2004. This swap has mitigated a portion of the exchange risk on U.S. dollar denominated gas sales. The estimated fair value of the foreign exchange swap has been determined based on the amount Pengrowth would receive or pay to terminate the contract at period end. At September 30, 2003, the amount Pengrowth would receive to terminate the foreign exchange swap would be Cdn $2,097,000. | ||
| Forward and Futures Contracts | ||
| Pengrowth has a price risk management program whereby the commodity price associated with a portion of its future production is fixed. Pengrowth sells forward a portion of its future production through a combination of fixed price sales contracts with customers and commodity swap agreements with financial counterparties. The forward and futures contracts are subject to market risk from fluctuating commodity prices and exchange rates. | ||
| As at September 30, 2003, Pengrowth had fixed the price applicable to future production as follows: | ||
| Crude Oil: |
| Volume | Reference | Price | ||||||||||
| Remaining Term | (bbl/d) | Point | Per bbl | |||||||||
2003 |
||||||||||||
Financial: |
||||||||||||
Oct 1, 2003 – Dec 31, 2003 |
11,000 | WTI(1) | $41.48Cdn | |||||||||
2004 |
||||||||||||
Financial: |
||||||||||||
Jan 1, 2004 – Dec 31, 2004 |
9,500 | WTI(1) | $38.11Cdn | |||||||||
| Natural Gas: |
| Volume | Reference | Price | ||||||||||
| Remaining Term | (mmbtu/d) | Point | Per mmbtu | |||||||||
2003 |
||||||||||||
Financial: |
||||||||||||
Oct 1, 2003 – Dec 31, 2003 |
7,500 | Tetco M3(1) | $7.37Cdn | |||||||||
Oct 1, 2003 – Dec 31, 2003 |
7,000 | Transco Z6 | $ | 3.90 U.S. | ||||||||
Oct 1, 2003 – Dec 31, 2003 |
2,500 | Tetco M3(1) | $8.42Cdn | |||||||||
Oct 1, 2003 – Dec 31, 2003 |
2,370 | AECO | $6.96Cdn | |||||||||
Oct 1, 2003 – Dec 31, 2003 |
2,370 | Sumas(1) | $7.28Cdn | |||||||||
Physical: |
||||||||||||
Oct 1, 2003 – Dec 31, 2003 |
9,478 | AECO | $5.73Cdn | |||||||||
2004 |
||||||||||||
Financial: |
||||||||||||
Jan 1, 2004 – Dec 31, 2004 |
5,000 | Tetco M3(1) | $6.90Cdn | |||||||||
Jan 1, 2004 – Dec 31, 2004 |
7,000 | Transco Z6 | $ | 3.90 U.S. | ||||||||
| (1) | Associated CDN$/US$ foreign exchange rate has been fixed. |
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| The estimated fair value of the financial crude oil and natural gas contracts has been determined based on the amounts Pengrowth would receive or pay to terminate the contracts at period end. At September 30, 2003, the amount Pengrowth would receive to terminate the financial crude oil contracts is $9,011,000, and the amount Pengrowth would pay to terminate the financial natural gas contracts is $7,962,000. | ||
| Fair Value of Financial Instruments | ||
| The carrying value of financial instruments included in the balance sheet, other than long-term debt and remediation trust fund, approximate their fair value due to their short maturity. The fair value of the Remediation Trust Fund at September 30, 2003 was $7,693,000 (December 31, 2002 – $7,193,000). The fair value of the U.S. denominated debt approximates its carrying value as the rate on the debt does not vary significantly from market rates. | ||
| 9. | SUBSEQUENT EVENT | |
| On October 31, 2003, Pengrowth entered into an agreement with Emera Offshore Incorporated (“Emera”) to purchase Emera’s 8.4% interest in the Sable Offshore Energy Project (“SOEP”) platform facilities for a purchase price of $65 million before adjustments. |
23
Table of Contents
Corporate Information
DIRECTORS OF PENGROWTH CORPORATION
Thomas A. Cumming
Business Consultant
Michael A. Grandin
Chairman and Chief Executive Officer, Fording Canadian Coal Trust
James S. Kinnear; Chairman
President, Pengrowth Management Limited
Francis G. Vetsch
President, Vetsch Resource Management Ltd.
Stanley H. Wong
President, Carbine Resources Ltd.
John B. Zaozirny; Lead Director
Counsel, McCarthy Tetrault
Director Emeritus
Thomas S. Dobson
President, T.S. Dobson Consultant Ltd.
OFFICERS OF PENGROWTH CORPORATION
James S. Kinnear
Chairman, President and Chief Executive Officer
Robert B. Hodgins
Chief Financial Officer
Gordon M. Anderson
Vice President
Henry D. McKinnon
Vice President, Operations
Lynn Kis
Vice President, Engineering
Charles V. Selby
Corporate Secretary
Chris Webster
Treasurer
Lianne Bigham
Controller
TRUSTEE
Computershare Trust Company of Canada
BANKERS
Bank Syndicate Agent: Royal Bank of Canada
AUDITORS
KPMG LLP
ENGINEERING CONSULTANTS
Gilbert Laustsen Jung Associates Ltd.
ABBREVIATIONS
| bbl | barrel | |
| bcf | billion cubic feet | |
| boe* | barrels of oil equivalent | |
| boe per day* | barrels of oil equivalent per day | |
| lt | long.tonnes | |
| mbbls | thousand barrels | |
| mmbbls | million barrels | |
| mboe* | thousand barrels of oil equivalent | |
| mmboe* | million barrels of oil equivalent | |
| mcf | thousand cubic feet | |
| mmcf | million cubic feet | |
| mcf per day | thousand cubic feet per day | |
| mmcf per day | million cubic feet per day |
Pengrowth Energy Trust (Energy Trust)
Pengrowth Corporation (Corporation)
*6 mcf of gas = 1 barrel of oil
PENGROWTH AND A STRONG COMMUNITY
Pengrowth Management Limited believes in enhancing the community where our
employees live and work. Pengrowth supports causes and institutions both
financially and through volunteer efforts and is proud of these associations
and partnerships with many community-building non-profit organizations.
Pengrowth has a substantial investment in our community and although 100 percent of the costs are attributed to Pengrowth Management, Pengrowth Energy Trust unitholders benefit through the visibility associated with these vital partnerships.
STOCK EXCHANGE LISTINGS
The Toronto Stock Exchange:
Symbol: PGF.UN
The New York Stock Exchange:
Symbol: PGH
PENGROWTH ENERGY TRUST
Head Office
Suite 2900, 111 – 5 Avenue S.W.
Calgary, Alberta T2P 3Y6 Canada
Telephone: (403) 233-0224
Toll-Free: 1 800 223-4122
Facsimile: (403) 265-6251
Email: pengrowth@pengrowth.com
Website: http://www.pengrowth.com
Toronto Office
2315, 200 Bay Street
Toronto, Ontario M5J 2J2 Canada
Telephone: (416) 362-1748
Toll-Free: 1 888 744-1111
Facsimile: (416) 362-8191
Halifax Office
Suite 407
1959 Upper Water Street
Halifax, NS B3J 3N2 Canada
Telephone: (902) 425-8778
Facsimile: (902) 425-7887
Contact: Jim MacDonald, General Manager, East Coast Operations
INVESTOR RELATIONS
For investor relations enquiries, please contact:
Investor Relations, Calgary
Telephone: (403) 233-0224
Toll-Free: 1 800 223-4122
Facsimile: (403) 294-0051
Email: pengrowth@pengrowth.com or Investor Relations, Toronto
Telephone: (416) 362-1748
Toll-Free: 1 888 744-1111
Facsimile: (416) 362-8191