1. | Press Release announcing First Quarter 2006 Results. |
PENGROWTH ENERGY TRUST by its administrator PENGROWTH CORPORATION |
||||
May 2, 2006 | By: | /s/ Gordon M. Anderson | ||
Name: | Gordon M. Anderson | |||
Title: | Vice President | |||
Attention: Financial Editors
|
Stock Symbol: | (PGF.A / PGF.B) TSX; | ||
(PGH) NYSE |
Three months ended | ||||||||||||
March 31 | % | |||||||||||
(thousands, except per unit amounts) | 2006 | 2005 | Change | |||||||||
INCOME STATEMENT |
||||||||||||
Oil and gas sales |
$ | 291,896 | $ | 239,913 | 22 | % | ||||||
Net income |
$ | 66,335 | $ | 56,314 | 18 | % | ||||||
Net income per trust unit |
$ | 0.41 | $ | 0.37 | 11 | % | ||||||
CASH FLOW |
||||||||||||
Funds generated from operations* |
$ | 141,260 | $ | 126,407 | 12 | % | ||||||
Funds generated from operations per trust unit* |
$ | 0.88 | $ | 0.82 | 7 | % | ||||||
Distributable cash * |
$ | 144,177 | $ | 127,804 | 13 | % | ||||||
Distributable cash per trust unit * |
$ | 0.90 | $ | 0.83 | 8 | % | ||||||
Distributions paid or declared |
$ | 120,302 | $ | 115,022 | 5 | % | ||||||
Distributions paid or declared per trust unit |
$ | 0.75 | $ | 0.69 | 9 | % | ||||||
Payout Ratio* |
85 | % | 91 | % | -6 | % | ||||||
Development capital |
$ | 75,078 | $ | 45,736 | 64 | % | ||||||
Weighted average number of trust units outstanding |
160,149 | 153,388 | 4 | % | ||||||||
BALANCE SHEET |
||||||||||||
Working capital |
$ | (139,121 | ) | $ | (97,897 | ) | 42 | % | ||||
Property, plant and equipment and other assets |
$ | 2,098,385 | $ | 2,061,105 | 2 | % | ||||||
Long term debt |
$ | 421,095 | $ | 441,920 | -5 | % | ||||||
Unitholders equity |
$ | 1,432,824 | $ | 1,414,203 | 1 | % | ||||||
Unitholders equity per trust unit |
$ | 8.93 | $ | 9.21 | -3 | % | ||||||
Number of trust units outstanding at period end |
160,383 | 153,621 | 4 | % | ||||||||
DAILY PRODUCTION |
||||||||||||
Crude oil (barrels) |
21,262 | 20,443 | 4 | % | ||||||||
Heavy oil (barrels) |
5,018 | 6,046 | -17 | % | ||||||||
Natural gas (mcf) |
157,876 | 157,491 | 0 | % | ||||||||
Natural gas liquids (barrels) |
6,252 | 6,345 | -1 | % | ||||||||
Total production (boe) |
58,845 | 59,082 | 0 | % | ||||||||
TOTAL PRODUCTION (mboe) |
5,296 | 5,317 | 0 | % | ||||||||
PRODUCTION PROFILE |
||||||||||||
Crude oil |
36 | % | 35 | % | ||||||||
Heavy oil |
8 | % | 10 | % | ||||||||
Natural gas |
45 | % | 44 | % | ||||||||
Natural gas liquids |
11 | % | 11 | % | ||||||||
AVERAGE REALIZED PRICES (after hedging) |
||||||||||||
Crude oil (per barrel) |
$ | 63.31 | $ | 54.42 | 16 | % | ||||||
Heavy oil (per barrel) |
$ | 29.18 | $ | 24.39 | 20 | % | ||||||
Natural gas (per mcf) |
$ | 8.76 | $ | 6.84 | 28 | % | ||||||
Natural gas liquids (per barrel) |
$ | 58.23 | $ | 50.48 | 15 | % | ||||||
Average realized price per boe |
$ | 55.04 | $ | 44.97 | 22 | % |
Three months ended | ||||||||
March 31 | ||||||||
(thousands, except per trust unit amounts) | 2006 | 2005 | ||||||
TRUST UNIT TRADING (Class A) |
||||||||
PGH (NYSE) |
||||||||
High |
$ | 25.15 US | $ | 22.94 US | ||||
Low |
$ | 21.82 US | $ | 18.11 US | ||||
Close |
$ | 23.10 US | $ | 20.00 US | ||||
Value |
$ | 316,218 US | $ | 515,131 US | ||||
Volume (thousands of trust units) |
13,421 | 24,621 | ||||||
PGF.A (TSX) |
||||||||
High |
$ | 28.96 | $ | 28.29 | ||||
Low |
$ | 24.96 | $ | 22.15 | ||||
Close |
$ | 26.88 | $ | 24.03 | ||||
Value |
$ | 33,841 | $ | 53,267 | ||||
Volume (thousands of trust units) |
1,244 | 2,049 | ||||||
TRUST UNIT TRADING (Class B) |
||||||||
PGF.B (TSX) |
||||||||
High |
$ | 24.50 | $ | 19.90 | ||||
Low |
$ | 20.71 | $ | 16.10 | ||||
Close |
$ | 23.32 | $ | 17.05 | ||||
Value |
$ | 420,062 | $ | 543,701 | ||||
Volume (thousands of trust units) |
18,338 | 29,219 |
Three months ended | ||||||||||||
Mar 31, 2006 | Dec 31, 2005 | Mar 31, 2005 | ||||||||||
Light crude oil (bbls) |
21,262 | 21,179 | 20,443 | |||||||||
Heavy oil (bbls) |
5,018 | 5,410 | 6,046 | |||||||||
Natural gas (mcf) |
157,876 | 168,862 | 157,491 | |||||||||
Natural gas liquids (bbls) |
6,252 | 6,710 | 6,345 | |||||||||
Total boe per day |
58,845 | 61,442 | 59,082 | |||||||||
Three months ended | ||||||||||||
(Cdn$) | Mar 31, 2006 | Dec 31, 2005 | Mar 31, 2005 | |||||||||
Light crude oil (per bbl) |
65.06 | 67.00 | 58.03 | |||||||||
after hedging |
63.31 | 59.40 | 54.42 | |||||||||
Heavy oil (per bbl) |
29.18 | 31.77 | 24.39 | |||||||||
Natural gas (per mcf) |
8.74 | 12.80 | 6.85 | |||||||||
after hedging |
8.76 | 11.97 | 6.84 | |||||||||
Natural gas liquids (per bbl) |
58.23 | 58.46 | 50.48 | |||||||||
Total per boe |
55.62 | 67.43 | 46.25 | |||||||||
after hedging |
55.04 | 62.55 | 44.97 | |||||||||
Benchmark prices |
||||||||||||
WTI oil (U.S. $ per bbl) |
63.48 | 60.05 | 50.03 | |||||||||
AECO spot gas (Cdn $ per gj) |
8.79 | 11.08 | 6.34 | |||||||||
NYMEX gas (U.S. $ per mmbtu) |
8.98 | 12.97 | 6.27 | |||||||||
Currency (U.S. $/Cdn $) |
0.87 | 0.85 | 0.82 | |||||||||
Three months ended | ||||||||||||
Mar 31, 2006 | Dec 31, 2005 | Mar 31, 2005 | ||||||||||
Light crude oil ($ million) |
3.3 | 14.8 | 6.6 | |||||||||
Light crude oil ($ per bbl) |
1.75 | 7.60 | 3.61 | |||||||||
Natural gas ($ million) |
(0.3 | ) | 12.9 | 0.1 | ||||||||
Natural gas ($ per mcf) |
(0.02 | ) | 0.83 | 0.01 | ||||||||
Combined ($ million) |
3.0 | 27.7 | 6.7 | |||||||||
Combined ($ per boe) |
0.58 | 4.88 | 1.28 | |||||||||
($ millions) | Three months ended | |||||||||||||||||||||||
% of | % of | % of | ||||||||||||||||||||||
Sales Revenue | Mar 31, 2006 | total | Dec 31, 2005 | total | Mar 31, 2005 | total | ||||||||||||||||||
Natural gas |
124.4 | 43 | % | 186.0 | 53 | % | 96.9 | 40 | % | |||||||||||||||
Light crude oil |
121.1 | 41 | % | 115.7 | 33 | % | 100.1 | 42 | % | |||||||||||||||
Natural gas liquids |
32.8 | 11 | % | 36.1 | 10 | % | 28.8 | 12 | % | |||||||||||||||
Heavy oil |
13.2 | 5 | % | 15.8 | 4 | % | 13.3 | 6 | % | |||||||||||||||
Brokered sales/sulphur |
0.4 | | 0.3 | | 0.8 | | ||||||||||||||||||
Total oil and gas sales |
291.9 | 353.9 | 239.9 |
($ millions) | Natural gas | Light oil | NGL | Heavy oil | Other | Total | ||||||||||||||||||
Quarter ended December 31,
2005 |
186.0 | 115.7 | 36.1 | 15.8 | 0.3 | 353.9 | ||||||||||||||||||
Effect of change in product
prices |
(57.7 | ) | (3.7 | ) | (0.1 | ) | (1.2 | ) | | (62.7 | ) | |||||||||||||
Effect of change in sales
volumes |
(17.0 | ) | (2.3 | ) | (3.2 | ) | (1.4 | ) | | (23.9 | ) | |||||||||||||
Effect of change in hedging
losses |
13.1 | 11.4 | | | | 24.5 | ||||||||||||||||||
Other |
| | | | 0.1 | 0.1 | ||||||||||||||||||
Quarter ended March 31, 2006 |
124.4 | 121.1 | 32.8 | 13.2 | 0.4 | 291.9 | ||||||||||||||||||
($ millions) | Natural gas | Light oil | NGL | Heavy oil | Other | Total | ||||||||||||||||||
Quarter ended March
31, 2005 |
96.9 | 100.1 | 28.8 | 13.3 | 0.8 | 239.9 | ||||||||||||||||||
Effect of change in
product prices |
26.9 | 13.4 | 4.4 | 2.2 | | 46.9 | ||||||||||||||||||
Effect of change in
sales volumes |
0.2 | 4.3 | (0.4 | ) | (2.3 | ) | | 1.8 | ||||||||||||||||
Effect of change in
hedging losses |
0.4 | 3.3 | | | | 3.7 | ||||||||||||||||||
Other |
| | | | (0.4 | ) | (0.4 | ) | ||||||||||||||||
Quarter ended March
31, 2006 |
124.4 | 121.1 | 32.8 | 13.2 | 0.4 | 291.9 | ||||||||||||||||||
Three months ended | ||||||||||||
($ millions) | Mar 31, 2006 | Dec 31, 2005 | Mar 31, 2005 | |||||||||
Processing, interest & other income |
3.8 | 4.0 | 4.2 | |||||||||
$ per boe |
0.71 | 0.71 | 0.79 | |||||||||
Three months ended | ||||||||||||
($ millions) | Mar 31, 2006 | Dec 31, 2005 | Mar 31, 2005 | |||||||||
Royalty expense |
65.3 | 68.0 | 40.6 | |||||||||
$ per boe |
12.34 | 12.03 | 7.63 | |||||||||
Royalties as a percent of sales |
22.4 | % | 19.2 | % | 16.9 | % |
Three months ended | ||||||||||||
($ millions) | Mar 31, 2006 | Dec 31, 2005 | Mar 31, 2005 | |||||||||
Operating expenses |
54.0 | 61.2 | 49.1 | |||||||||
$ per boe |
10.20 | 10.83 | 9.23 | |||||||||
Three months ended | ||||||||||||
($ millions) | Mar 31, 2006 | Dec 31, 2005 | Mar 31, 2005 | |||||||||
Light oil transportation |
0.5 | 0.5 | 0.5 | |||||||||
$ per bbl |
0.27 | 0.27 | 0.30 | |||||||||
Natural gas transportation |
1.3 | 1.8 | 1.3 | |||||||||
$ per mcf |
0.09 | 0.12 | 0.09 | |||||||||
Three months ended | ||||||||||||
($ millions) | Mar 31, 2006 | Dec 31, 2005 | Mar 31, 2005 | |||||||||
Purchased and capitalized |
10.6 | 14.5 | 7.6 | |||||||||
Amortization |
8.0 | 7.1 | 5.4 | |||||||||
Combined Netbacks ($ per boe) | Three months ended | |||||||||||
Mar 31, 2006 | Dec 31, 2005 | Mar 31, 2005 | ||||||||||
Sales price |
$ | 55.04 | $ | 62.55 | $ | 44.97 | ||||||
Other production income |
0.07 | 0.06 | 0.15 | |||||||||
55.11 | 62.61 | 45.12 | ||||||||||
Processing, interest and other income |
0.71 | 0.71 | 0.79 | |||||||||
Royalties |
(12.34 | ) | (12.02 | ) | (7.63 | ) | ||||||
Operating expenses |
(10.20 | ) | (10.83 | ) | (9.23 | ) | ||||||
Transportation costs |
(0.33 | ) | (0.41 | ) | (0.34 | ) | ||||||
Amortization of injectants |
(1.51 | ) | (1.25 | ) | (1.01 | ) | ||||||
Operating netback |
$ | 31.44 | $ | 38.81 | $ | 27.70 | ||||||
Light Crude Netbacks ($ per bbl) | Three months ended | |||||||||||
Mar 31, 2006 | Dec 31, 2005 | Mar 31, 2005 | ||||||||||
Sales price |
$ | 63.31 | $ | 59.40 | $ | 54.42 | ||||||
Other production income |
0.06 | 0.17 | 0.42 | |||||||||
63.37 | 59.57 | 54.84 | ||||||||||
Processing, interest and other income |
0.59 | 0.34 | 0.38 | |||||||||
Royalties |
(7.23 | ) | (6.47 | ) | (7.11 | ) | ||||||
Operating expenses |
(10.90 | ) | (14.32 | ) | (10.74 | ) | ||||||
Transportation costs |
(0.27 | ) | (0.27 | ) | (0.30 | ) | ||||||
Amortization of injectants |
(4.17 | ) | (3.63 | ) | (2.93 | ) | ||||||
Operating netback |
$ | 41.39 | $ | 35.22 | $ | 34.14 | ||||||
Heavy Oil Netbacks ($ per bbl) | Three months ended | |||||||||||
Mar 31, 2006 | Dec 31, 2005 | Mar 31, 2005 | ||||||||||
Sales price |
$ | 29.18 | $ | 31.77 | $ | 24.39 | ||||||
Processing, interest and other income |
0.38 | 0.74 | 0.99 | |||||||||
Royalties |
(1.55 | ) | (2.98 | ) | (2.58 | ) | ||||||
Operating expenses |
(14.16 | ) | (11.60 | ) | (18.56 | ) | ||||||
Operating netback |
$ | 13.85 | $ | 17.93 | $ | 4.24 | ||||||
Natural Gas Netbacks ($ per mcf) | Three months ended | |||||||||||
Mar 31, 2006 | Dec 31, 2005 | Mar 31, 2005 | ||||||||||
Sales price |
$ | 8.76 | $ | 11.97 | $ | 6.84 | ||||||
Other production income |
0.02 | | | |||||||||
8.78 | 11.97 | 6.84 | ||||||||||
Processing, interest and other income |
0.18 | 0.19 | 0.21 | |||||||||
Royalties |
(2.54 | ) | (2.62 | ) | (1.27 | ) | ||||||
Operating expenses |
(1.54 | ) | (1.38 | ) | (1.08 | ) | ||||||
Transportation costs |
(0.09 | ) | (0.12 | ) | (0.09 | ) | ||||||
Operating netback |
$ | 4.79 | $ | 20.01 | $ | 11.45 | ||||||
NGLs Netbacks ($ per bbl) | Three months ended | |||||||||||
Mar 31, 2006 | Dec 31, 2005 | Mar 31, 2005 | ||||||||||
Sales price |
$ | 58.23 | $ | 58.46 | $ | 50.48 | ||||||
Royalties |
(26.10 | ) | (21.29 | ) | (14.07 | ) | ||||||
Operating expenses |
(8.65 | ) | (10.05 | ) | (6.88 | ) | ||||||
Operating netback |
$ | 23.48 | $ | 27.12 | $ | 29.53 | ||||||
Three months ended | ||||||||||||
($ millions) | Mar 31, 2006 | Dec 31, 2005 | Mar 31, 2005 | |||||||||
Cash G&A expense |
7.5 | 7.7 | 6.3 | |||||||||
$ per boe |
1.41 | 1.36 | 1.18 | |||||||||
Non-cash G&A expense |
1.3 | 0.8 | 0.8 | |||||||||
$ per boe |
0.26 | 0.14 | 0.15 | |||||||||
Total G&A ($ million) |
8.8 | 8.5 | 7.1 | |||||||||
Total G&A ($ per boe) |
1.67 | 1.50 | 1.33 | |||||||||
Three months ended | ||||||||||||
($ millions) | Mar 31, 2006 | Dec 31, 2005 | Mar 31, 2005 | |||||||||
Management Fee |
3.2 | 2.2 | 3.1 | |||||||||
Performance Fee |
1.0 | 2.2 | 0.6 | |||||||||
Total ($ million) |
4.2 | 4.4 | 3.7 | |||||||||
Total ($ per boe) |
0.80 | 0.77 | 0.70 | |||||||||
Three months ended | ||||||||||||
($ millions) | Mar 31, 2006 | Dec 31, 2005 | Mar 31, 2005 | |||||||||
Depletion and Depreciation |
71.1 | 71.4 | 69.1 | |||||||||
$ per boe |
13.42 | 12.63 | 13.00 | |||||||||
Accretion |
3.3 | 3.6 | 3.4 | |||||||||
$ per boe |
0.63 | 0.64 | 0.64 | |||||||||
Three months ended | ||||||||||||
($ millions) | Mar 31, 2006 | Dec 31, 2005 | Mar 31, 2005 | |||||||||
Geological and geophysical |
1.2 | | 0.6 | |||||||||
Drilling and completions |
57.8 | 41.1 | 34.3 | |||||||||
Plant and facilities |
13.4 | 10.2 | 10.6 | |||||||||
Land purchases |
2.7 | 8.8 | 0.2 | |||||||||
Development capital |
75.1 | 60.1 | 45.7 | |||||||||
Acquisitions |
49.8 | | 89.8 | |||||||||
Total capital expenditures
and acquisitions |
124.9 | 60.1 | 135.5 | |||||||||
($ thousands, except per trust unit amounts) | Three months ended | |||||||||||
Mar 31, 2006 | Dec 31, 2005 | Mar 31, 2005 | ||||||||||
Cash generated from operations |
191,599 | 196,588 | 136,420 | |||||||||
Change in non-cash operating working capital |
(50,339 | ) | (7,993 | ) | (10,013 | ) | ||||||
Funds generated from operations |
141,260 | 188,595 | 126,407 | |||||||||
Change in deferred injectants |
2,643 | 7,411 | 2,179 | |||||||||
Change in remediation trust funds |
(391 | ) | 784 | (263 | ) | |||||||
Change in deferred charges |
788 | (793 | ) | (395 | ) | |||||||
Other |
(123 | ) | (118 | ) | (124 | ) | ||||||
Distributable cash |
144,177 | 195,879 | 127,804 | |||||||||
Allocation of Distributable cash |
||||||||||||
Cash withheld |
23,875 | 76,021 | 12,782 | |||||||||
Distributions paid or declared |
120,302 | 119,858 | 115,022 | |||||||||
Distributable cash |
144,177 | 195,879 | 127,804 | |||||||||
Distributable cash per trust unit |
0.90 | 1.23 | 0.83 | |||||||||
Distributions paid or declared per trust unit |
0.75 | 0.75 | 0.69 | |||||||||
Payout ratio (1) |
85 | % | 64 | % | 91 | % | ||||||
2006 | Q1 | |||
Oil and gas sales ($000s) |
291,896 | |||
Net income ($000s) |
66,335 | |||
Net income per trust unit ($) |
0.41 | |||
Net income per trust unit diluted ($) |
0.41 | |||
Distributable cash ($000s) |
144,177 | |||
Actual distributions paid or declared per trust unit ($) |
0.75 | |||
Daily production (boe) |
58,845 | |||
Total production (mboe) |
5,296 | |||
Average realized price ($ per boe) |
55.04 | |||
Operating netback ($ per boe) |
31.44 |
2005 | Q1 | Q2 | Q3 | Q4 | ||||||||||||
Oil and gas sales ($000s) |
239,913 | 253,189 | 304,484 | 353,923 | ||||||||||||
Net income ($000s) |
56,314 | 53,106 | 100,243 | 116,663 | ||||||||||||
Net income per trust unit ($) |
0.37 | 0.34 | 0.63 | 0.73 | ||||||||||||
Net income per trust unit diluted ($) |
0.37 | 0.34 | 0.63 | 0.73 | ||||||||||||
Distributable cash ($000s) |
127,804 | 134,047 | 162,009 | 195,879 | ||||||||||||
Actual distributions paid or declared per trust unit ($) |
0.69 | 0.69 | 0.69 | 0.75 | ||||||||||||
Daily production (boe) |
59,082 | 57,988 | 58,894 | 61,442 | ||||||||||||
Total production (mboe) |
5,317 | 5,277 | 5,418 | 5,653 | ||||||||||||
Average realized price ($ per boe) |
44.97 | 47.79 | 56.07 | 62.55 | ||||||||||||
Operating netback ($ per boe) |
27.70 | 29.26 | 33.94 | 38.81 |
2004 | Q1 | Q2 | Q3 | Q4 | ||||||||||||
Oil and gas sales ($000s) |
168,771 | 197,284 | 226,514 | 223,183 | ||||||||||||
Net income ($000s) |
38,652 | 32,684 | 51,271 | 31,138 | ||||||||||||
Net income per trust unit ($) |
0.31 | 0.24 | 0.38 | 0.23 | ||||||||||||
Net income per trust unit diluted ($) |
0.31 | 0.24 | 0.38 | 0.23 | ||||||||||||
Distributable cash ($000s) |
92,895 | 99,021 | 104,304 | 104,958 | ||||||||||||
Actual distributions paid or declared per trust unit ($) |
0.63 | 0.64 | 0.67 | 0.69 | ||||||||||||
Daily production (boe) |
45,668 | 51,451 | 60,151 | 57,425 | ||||||||||||
Total production (mboe) |
4,156 | 4,682 | 5,534 | 5,283 | ||||||||||||
Average realized price ($ per boe) |
40.37 | 41.83 | 40.90 | 42.08 | ||||||||||||
Operating netback ($ per boe) |
25.71 | 25.71 | 22.77 | 24.31 |
| Two gas wells were drilled and cased at Rigel. An operated gas cap producer tested 2 mmcf per day (gross) and a non-operated gas well is yet to be completed. The target zone (Bluesky) was found to be present and an initial production rate of 450 mcf per day is anticipated. | |
| A successful oil well was drilled in the Oak C Pool capable of 70 bbls per day. | |
| Two standing operated gas wells at Gutah were tied-into a third party gathering system. | |
| Seven non-operated gas wells were drilled in the Gutah area, five of which were tied in before spring breakup and two which are still standing. | |
| Five gas wells were drilled and cased at Prespatou. Four have been tied-in to the existing facility which is currently being expanded from 4 mmcf per day to 12 mmcf per day. Expansion is anticipated to be completed during the second quarter. | |
| Four Notikewin gas wells were drilled at Bulrush with two successes and two abandonments. One successful recompletion was conducted and two recompletions did not yield economic quantities of gas. One standing well was tied-in. | |
| A gas well recompletion from the Gething formation at Wildmint will be on stream in the second quarter with an anticipated initial production rate of 450 mcf per day. | |
| A reactivation and recompletion of a North Pine waterflood producer at Squirrel were concluded with an initial production rate of 90 bbls per day. | |
| A gas well recompletion at Weasel tested 162 mcf per day of incremental production. | |
| A Bluesky gas well recompletion at Beatton will yield 200 mcf per day for the remainder of the year. | |
| A new gathering line was installed from West Weasel to the Duke system that will facilitate three gas wells to produce at capability. Compression will be installed in the second quarter to bring this system on line. | |
| Drilling operations of a non-operated gas well at Karr were suspended at intermediate casing. Drilling will restart again in December 2006. |
| A new miscible flood pattern was initiated in the Judy Creek A Pool with two new injectors and one oil well which tested at 160 bbl per day during the first quarter. |
| As part of a 40 well program, 11 wells are currently on stream. Initial rates net to Pengrowth are approximately 100 barrels per day. |
| One oil well was drilled and a second oil well will spudded in the second quarter. |
| Three successful gas wells were drilled with two completed during the first quarter. The third well is standing and awaiting completion operations in the third quarter. |
| One non-operated well was drilled, cased and tied-in to the Quirk Creek gas plant. Completion and production testing of the well are expected in June 2006. |
| Eleven Coal Bed Methane (CBM) wells were drilled, cased and logged. Completion operations will commence in the second quarter. | |
| A Belly River well was drilled and is currently awaiting tie in. |
| Three new drills from fourth quarter 2005 were recompleted in the first quarter of 2006 along with three recompletions yielding positive results from the Belly River and Lower Mannville Ellerslie formations with an initial cumulative production rate of 1.2 mmcf per day. Only one of these six wells remains to be tied in during the second quarter of 2006. |
| At Elnora there is one standing Ellerslie gas well and at Huxley there is one well completed and awaiting tie in. |
| One well and one recompletion were successful at Provost in the first quarter. | |
| A 3D seismic program was completed at Bodo and will lead to future locations. | |
| Polymer skid construction is completed and is forecast to start up at Bodo in the second quarter. |
| First quarter gross raw gas production from the five SOEP fields, Thebaud, Venture, North Triumph, Alma and South Venture averaged 379 mmcf per day (32 mmcf per day net). | ||
| Monthly raw production for January, February and March was 398 mmcf per day (33 mmcf per day net); 387 mmcf per day (32 mmcf per day net); and 352 mmcf per day (30 mmcf per day net), respectively. | ||
| Pengrowth shipped approximately 114,000 bbls of condensate in the first quarter. | ||
| The Venture 7 (V7) development well spudded on August 5, 2005 started production on December 28, 2005. V7 initial production was approximately 50 mmcf per day gross (4.2 mmcf per day net to Pengrowth). | ||
| In early January, the Alma mono ethylene glycol (MEG) line experienced a leak. A temporary facility was installed and a permanent repair was completed in March. | ||
| The drilling rig Galaxy II spudded the Alma 3 well on February 9, 2006. By March 31, 2006 Alma 3 was perforated and being tied-in for production. |
| Fabrication of the compression topsides, jacket and piles was approximately 99 percent complete. | ||
| Cut-in work in preparation for the compressor installation continued at the Thebaud facilities. | ||
| In-service for the compressor is scheduled for late 2006. |
As at | As at | |||||||
March 31 | December 31 | |||||||
2006 | 2005 | |||||||
ASSETS |
||||||||
CURRENT ASSETS |
||||||||
Accounts receivable |
$ | 94,672 | $ | 127,394 | ||||
REMEDIATION TRUST FUNDS |
8,720 | 8,329 | ||||||
DEFERRED CHARGES (Note 7) |
6,680 | 4,886 | ||||||
EQUITY INVESTMENT (Note 3) |
7,000 | | ||||||
GOODWILL |
182,835 | 182,835 | ||||||
PROPERTY, PLANT AND EQUIPMENT
AND OTHER ASSETS |
2,098,385 | 2,067,988 | ||||||
$ | 2,398,292 | $ | 2,391,432 | |||||
LIABILITIES AND UNITHOLDERS EQUITY |
||||||||
CURRENT LIABILITIES |
||||||||
Bank indebtedness |
$ | 6,341 | $ | 14,567 | ||||
Accounts payable and accrued liabilities |
114,479 | 111,493 | ||||||
Distributions payable to unitholders |
80,240 | 79,983 | ||||||
Due to Pengrowth Management Limited |
7,689 | 8,277 | ||||||
Note payable |
20,000 | 20,000 | ||||||
Current portion of contract liabilities |
5,044 | 5,279 | ||||||
233,793 | 239,599 | |||||||
CONTRACT LIABILITIES |
11,852 | 12,937 | ||||||
LONG TERM DEBT (Note 2) |
421,095 | 368,089 | ||||||
ASSET RETIREMENT OBLIGATIONS (Note 6) |
186,069 | 184,699 | ||||||
FUTURE INCOME TAXES |
112,659 | 110,112 | ||||||
TRUST UNITHOLDERS EQUITY |
||||||||
Trust Unitholders capital (Note 4) |
2,524,862 | 2,514,997 | ||||||
Contributed surplus (Note 4) |
4,576 | 3,646 | ||||||
Deficit (Note 4) |
(1,096,614 | ) | (1,042,647 | ) | ||||
1,432,824 | 1,475,996 | |||||||
$ | 2,398,292 | $ | 2,391,432 | |||||
Three months ended | ||||||||
March 31 | ||||||||
2006 | 2005 | |||||||
REVENUES |
||||||||
Oil and gas sales |
$ | 291,896 | $ | 239,913 | ||||
Processing and other income |
3,219 | 4,118 | ||||||
Royalties, net of incentives |
(65,335 | ) | (40,565 | ) | ||||
229,780 | 203,466 | |||||||
Interest and other income |
565 | 112 | ||||||
NET REVENUE |
230,345 | 203,578 | ||||||
EXPENSES |
||||||||
Operating |
54,018 | 49,079 | ||||||
Transportation |
1,758 | 1,807 | ||||||
Amortization of injectants for miscible floods |
7,972 | 5,392 | ||||||
Interest |
5,778 | 5,433 | ||||||
General and administrative |
8,820 | 7,081 | ||||||
Management fee |
4,241 | 3,708 | ||||||
Foreign exchange loss (Note 8) |
1,239 | 1,360 | ||||||
Depletion and depreciation |
71,056 | 69,149 | ||||||
Accretion (Note 6) |
3,328 | 3,403 | ||||||
158,210 | 146,412 | |||||||
NET INCOME BEFORE TAXES |
72,135 | 57,166 | ||||||
INCOME TAX EXPENSE (REDUCTION) |
||||||||
Capital |
1,480 | 1,297 | ||||||
Future |
4,320 | (445 | ) | |||||
5,800 | 852 | |||||||
NET INCOME |
$ | 66,335 | $ | 56,314 | ||||
Deficit, beginning of period |
(1,042,647 | ) | (922,996 | ) | ||||
Distributions paid or declared |
(120,302 | ) | (105,998 | ) | ||||
DEFICIT, END OF PERIOD |
$ | (1,096,614 | ) | $ | (972,680 | ) | ||
NET INCOME PER TRUST UNIT (Note 4) Basic |
$ | 0.41 | $ | 0.37 | ||||
Diluted |
$ | 0.41 | $ | 0.37 | ||||
Three months ended | ||||||||
March 31 | ||||||||
2006 | 2005 | |||||||
CASH PROVIDED BY (USED FOR): |
||||||||
OPERATING |
||||||||
Net income |
$ | 66,335 | $ | 56,314 | ||||
Depletion, depreciation and accretion |
74,384 | 72,552 | ||||||
Future income taxes |
4,320 | (445 | ) | |||||
Contract liability amortization |
(1,320 | ) | (1,449 | ) | ||||
Amortization of injectants |
7,972 | 5,392 | ||||||
Purchase of injectants |
(10,615 | ) | (7,571 | ) | ||||
Expenditures on remediation |
(1,380 | ) | (1,118 | ) | ||||
Unrealized foreign exchange loss (Note 8) |
1,000 | 1,520 | ||||||
Trust unit based compensation (Note 5) |
1,352 | 817 | ||||||
Deferred charges |
(2,364 | ) | | |||||
Amortization of deferred charges |
1,576 | 395 | ||||||
Changes in non-cash operating working capital (Note 9) |
50,339 | 10,013 | ||||||
191,599 | 136,420 | |||||||
FINANCING |
||||||||
Distributions |
(120,045 | ) | (105,757 | ) | ||||
Change in long term debt, net |
51,000 | 95,000 | ||||||
Proceeds from issue of trust units |
9,443 | 9,883 | ||||||
(59,602 | ) | (874 | ) | |||||
INVESTING |
||||||||
Expenditures on property acquisitions |
(49,785 | ) | (89,950 | ) | ||||
Expenditures on property, plant and equipment |
(75,078 | ) | (45,535 | ) | ||||
Proceeds on property dispositions |
16,702 | | ||||||
Change in remediation trust fund |
(391 | ) | (263 | ) | ||||
Change in non-cash investing working capital (Note 9) |
(15,219 | ) | (3,192 | ) | ||||
(123,771 | ) | (138,940 | ) | |||||
CHANGE IN CASH AND TERM DEPOSITS |
8,226 | (3,394 | ) | |||||
BANK INDEBTEDNESS AT BEGINNING OF PERIOD |
(14,567 | ) | (4,214 | ) | ||||
BANK INDEBTEDNESS AT END OF PERIOD |
$ | (6,341 | ) | $ | (7,608 | ) | ||
1. | SIGNIFICANT ACCOUNTING POLICIES | |
The interim consolidated financial statements of Pengrowth Energy Trust include the accounts of Pengrowth Energy Trust (the Trust), Pengrowth Corporation (the Corporation) and its subsidiaries (collectively referred to as Pengrowth). The financial statements do not contain the accounts of Pengrowth Management Limited (the Manager). | ||
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, 2005. 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 Pengrowths annual report for the year ended December 31, 2005. | ||
2. | LONG TERM DEBT |
As at | As at | |||||||
March 31, | December 31, | |||||||
2006 | 2005 | |||||||
U.S. dollar denominated debt: |
||||||||
U.S. $150 million senior unsecured notes at 4.93 percent due
April 2010 |
$ | 175,200 | $ | 174,450 | ||||
U.S. $50 million senior unsecured notes at 5.47 percent due
April 2013 |
58,400 | 58,150 | ||||||
233,600 | 232,600 | |||||||
Pounds sterling denominated £50 million unsecured notes at
5.46 percent due December 2015 |
101,495 | 100,489 | ||||||
Canadian dollar revolving credit borrowings |
86,000 | 35,000 | ||||||
$ | 421,095 | $ | 368,089 | |||||
Pengrowth has a $370 million revolving unsecured credit facility syndicated among eight financial institutions with an extendible 364 day revolving period and a three year amortization term period. The facilities were reduced by drawings of $86 million and by outstanding letters of credit in the amount of approximately $17 million at March 31, 2006. In addition, Pengrowth has a $35 million demand operating line 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 Pengrowth. The margins and stamping fees vary from zero percent to 1.4 percent depending on financial statement ratios and the form of borrowing. | ||
The revolving credit facility will revolve until June 16, 2006, whereupon it may be renewed for a further 364 days, subject to satisfactory review by the lenders, or converted into a term facility. If converted to a term facility, one third of the amount outstanding would be repaid in equal quarterly instalments in each of the first two years with the final one third to be repaid upon maturity of the term period. Pengrowth can post, at its option, security suitable to the banks in lieu of the first years payments. In such an instance, no principal payment would be made to the banks for one year following the date of non-renewal. |
3. | EQUITY INVESTMENT | |
On January 12, 2006 Pengrowth closed certain transactions with Monterey Exploration Ltd. (Monterey) under which Pengrowth has sold certain oil and gas properties for $22 million in cash, less closing adjustments, and 8,048,132 common shares of Monterey. As of March 31, 2006 Pengrowth holds approximately 34 percent of the common shares of Monterey. | ||
Pengrowth utilizes the equity method of accounting for the investment in Monterey. The investment is initially recorded at cost and adjusted thereafter to include Pengrowths pro rata share of post-acquisition earnings of Monterey. Any dividends received or receivable from Monterey would reduce the carrying value of the investment. | ||
4. | TRUST UNITHOLDERS EQUITY | |
Trust Unitholders Capital | ||
The total authorized capital of Pengrowth is 500,000,000 trust units. | ||
Total Trust Units: |
Three months ended | Year ended | |||||||||||||||
March 31, 2006 | December 31, 2005 | |||||||||||||||
Number | Number | |||||||||||||||
Trust units issued | of trust units | Amount | of trust units | Amount | ||||||||||||
Balance, beginning of period |
159,864,083 | $ | 2,514,997 | 152,972,555 | $ | 2,383,284 | ||||||||||
Issued for the Crispin acquisition (non-cash) |
| | 4,225,313 | 87,960 | ||||||||||||
Issued for cash on exercise of trust unit
options and rights |
235,244 | 5,058 | 1,512,211 | 21,818 | ||||||||||||
Issued for cash under Distribution
Reinvestment Plan (DRIP) |
284,076 | 4,385 | 1,154,004 | 20,726 | ||||||||||||
Trust unit rights incentive plan (non-cash
exercised) |
| 422 | | 1,209 | ||||||||||||
Balance, end of year |
160,383,403 | $ | 2,524,862 | 159,864,083 | $ | 2,514,997 | ||||||||||
Class A Trust Units: |
Three months ended | Year ended | |||||||||||||||
March 31, 2006 | December 31, 2005 | |||||||||||||||
Number | Number | |||||||||||||||
Trust units issued | of trust units | Amount | of trust units | Amount | ||||||||||||
Balance, beginning of period |
77,524,673 | $ | 1,196,121 | 76,792,759 | $ | 1,176,427 | ||||||||||
Issued for the Crispin acquisition (non-cash) |
| | 686,732 | 19,002 | ||||||||||||
Trust units converted |
200 | 3 | 45,182 | 692 | ||||||||||||
Balance, end of period |
77,524,873 | $ | 1,196,124 | 77,524,673 | $ | 1,196,121 | ||||||||||
Class B Trust Units: |
Three months ended | Year ended | |||||||||||||||
March 31, 2006 | December 31, 2005 | |||||||||||||||
Number | Number | |||||||||||||||
Trust units issued | of trust units | Amount | of trust units | Amount | ||||||||||||
Balance, beginning of period |
82,301,443 | $ | 1,318,294 | 76,106,471 | $ | 1,205,734 | ||||||||||
Trust units converted |
3,655 | 58 | (9,824 | ) | (151 | ) | ||||||||||
Issued for the Crispin acquisition (non-cash) |
| | 3,538,581 | 68,958 | ||||||||||||
Issued for cash on exercise of trust unit
options and rights |
235,244 | 5,058 | 1,512,211 | 21,818 | ||||||||||||
Issued for cash under Distribution
Reinvestment Plan (DRIP) |
284,076 | 4,385 | 1,154,004 | 20,726 | ||||||||||||
Trust unit rights incentive plan
(non-cash
exercised) |
| 422 | | 1,209 | ||||||||||||
Balance, end of period |
82,824,418 | $ | 1,328,217 | 82,301,443 | $ | 1,318,294 | ||||||||||
Unclassified Trust Units: |
Three months ended | Year ended | |||||||||||||||
March 31, 2006 | December 31, 2005 | |||||||||||||||
Number | Number | |||||||||||||||
Trust Units Issued | of units | Amount | of units | Amount | ||||||||||||
Balance, beginning of period |
37,967 | $ | 582 | 73,325 | $ | 1,123 | ||||||||||
Converted to Class A or Class B trust
units |
(3,855 | ) | (61 | ) | (35,358 | ) | (541 | ) | ||||||||
Balance, end of period |
34,112 | $ | 521 | 37,967 | $ | 582 | ||||||||||
Per Trust Unit Amounts | ||
The per trust unit amounts of net income are based on the following weighted average trust units outstanding for the period. The weighted average trust units outstanding for the three months ended March 31, 2006 were 160,148,880 trust units (March 31, 2005 153,387,514 trust units). In computing diluted net income per trust unit, 545,536 trust units were added to the weighted average number of trust units outstanding during the three months ended March 31, 2006 (March 31, 2005 574,190 trust units) for the dilutive effect of trust unit options, rights and deferred entitlement trust units (DEUs). For the three months ended March 31, 2006, 595,707 options, rights and deferred entitlement trust units (March 31, 2005 1,318,508 options and rights) were excluded from the diluted net income per trust unit calculation as their effect is anti-dilutive. | ||
Contributed Surplus |
Three months | Twelve months | |||||||
ended | ended December | |||||||
March 31, 2006 | 31, 2005 | |||||||
Balance, beginning of period |
$ | 3,646 | $ | 1 ,923 | ||||
Trust unit rights incentive plan (non-cash expensed) |
789 | 1,740 | ||||||
Deferred entitlement trust units (non-cash expensed) |
563 | 1,192 | ||||||
Trust unit rights incentive plan (non-cash exercised) |
(422 | ) | (1,209 | ) | ||||
Balance, end of period |
$ | 4,576 | $ | 3,646 | ||||
Deficit |
As at | As at | |||||||
March 31, | December 31, | |||||||
2006 | 2005 | |||||||
Accumulated earnings |
$ | 1,119,718 | $ | 1,053,383 | ||||
Accumulated distributions paid or declared |
(2,216,332 | ) | (2,096,030 | ) | ||||
$ | (1,096,614 | ) | $ | (1,042,647 | ) | |||
Pengrowth is obligated by virtue of its Royalty and Trust Indentures to distribute to unitholders a significant portion of its cash flow from operations. Cash flow from operations typically exceeds net income as a result of non cash expenses such as depletion, depreciation and accretion. These non-cash expenses result in a deficit being recorded despite Pengrowth distributing less than its cash flow from operations. | ||
5. | TRUST UNIT BASED COMPENSATION PLANS | |
Trust Unit Option Plan | ||
As at March 31, 2006, options to purchase 174,033 Class B trust units were outstanding (December 31, 2005 options to purchase 259,317 Class B trust units) that expire at various dates to June 28, 2009. All outstanding trust unit options were fully expensed by December 31, 2004. |
Three months ended | Twelve months ended | |||||||||||||||
March 31, 2006 | December 31, 2005 | |||||||||||||||
Weighted | Weighted | |||||||||||||||
Trust unit options | Number | average | Number | average | ||||||||||||
of options | exercise price | of options | exercise price | |||||||||||||
Outstanding at beginning of period |
259,317 | $ | 17.28 | 845,374 | $ | 16.97 | ||||||||||
Exercised |
(85,284 | ) | $ | 17.99 | (558,307 | ) | $ | 16.74 | ||||||||
Expired |
| | (27,750 | ) | $ | 18.63 | ||||||||||
Outstanding and exercisable at period-end |
174,033 | $ | 16.94 | 259,317 | $ | 17.28 | ||||||||||
Trust Unit Rights Incentive Plan | ||
As at March 31, 2006, rights to purchase 1,670,407 Class B trust units were outstanding (December 31, 2005 1,441,737) that expire at various dates to February 27, 2011. | ||
Compensation expense is based on a fair value method. Compensation expense associated with the trust unit rights granted during the first quarter of 2006 was based on the estimated fair value of $1.86 per trust unit right. The fair value of trust unit rights granted during the three months ended March 31, 2006 was estimated at 8 percent of the exercise price at the date of grant using a binomial lattice option pricing model with the following assumptions: risk-free rate of 4.1 percent, volatility of 19 percent and reductions in the exercise price over the life of the trust unit rights. For the three months ended March 31, 2006, compensation expense of $789,000 (March 31, 2005 $695,000) related to the trust unit rights was recorded. |
Three months ended | Twelve months ended | |||||||||||||||
March 31, 2006 | December 31, 2005 | |||||||||||||||
Weighted | Weighted | |||||||||||||||
Trust unit rights | Number | average | Number | average | ||||||||||||
of rights | exercise price | of rights | exercise price | |||||||||||||
Outstanding at beginning of period |
1,441,737 | $ | 14.85 | 2,011,451 | $ | 14.23 | ||||||||||
Granted (1) |
444,909 | $ | 23.20 | 606,575 | $ | 18.34 | ||||||||||
Exercised |
(198,792 | ) | $ | 14.34 | (953,904 | ) | $ | 12.81 | ||||||||
Cancelled |
(17,447 | ) | $ | 15.98 | (222,385 | ) | $ | 16.19 | ||||||||
Outstanding at period-end |
1,670,407 | $ | 16.73 | 1,441,737 | $ | 14.85 | ||||||||||
Exercisable at period-end |
610,506 | $ | 15.48 | 668,473 | $ | 13.73 | ||||||||||
(1) | Weighted average exercise price of rights granted is based on the exercise price at the date of grant. |
Long Term Incentive Program | ||
As at March 31, 2006, 339,563 deferred entitlement trust units (DEUs) were outstanding (December 31, 2005 185,591), including accrued distributions re-invested to March 31, 2006. The DEUs vest on various dates to February 27, 2009. For the three months ended March 31, 2006, Pengrowth recorded compensation expense of $563,000 (March 31, 2005 $122,000) associated with the DEUs based on the weighted average estimated fair value of $20.69 (2005 $18.14) per DEU. |
Three months ended | Twelve months ended | |||||||
Number of DEUs | March 31, 2006 | December 31, 2005 | ||||||
Outstanding, beginning of period |
185,591 | | ||||||
Granted |
151,996 | 194,229 | ||||||
Cancelled |
(11,070 | ) | (26,258 | ) | ||||
Deemed DRIP |
13,046 | 17,620 | ||||||
Outstanding, end of period |
339,563 | 185,591 | ||||||
Trust Unit Award Plans | ||
Effective February 27, 2006, Pengrowth established a new incentive plan to reward and retain employees whereby Class B trust units and cash will be awarded to eligible employees. Employees will receive the trust units and cash on or about July 1, 2007. Pengrowth acquired the Class B trust units to be awarded on the open market for $2.4 million and placed them in a trust account established for the benefit of the eligible employees. The cost to acquire the trust units has been recorded as deferred compensation expense and is being charged to net income on a straight line basis over 16 months. In addition, the cash portion of the incentive plan of approximately $1.1 million is being accrued over 16 months. | ||
During the three months ended March 31, 2006 $1.6 million has been charged to net income for the February 27, 2006 plan and the previously disclosed July 13, 2005 plan. | ||
6. | ASSET RETIREMENT OBLIGATIONS |
Three months ended | Twelve Months ended | |||||||
March 31, 2006 | December 31, 2005 | |||||||
Asset retirement obligations, beginning of
period |
$ | 184,699 | $ | 171,866 | ||||
Increase (decrease) in liabilities related to: |
||||||||
Acquisitions |
448 | 6,347 | ||||||
Additions |
474 | 1,972 | ||||||
Disposals |
(1,500 | ) | (3,844 | ) | ||||
Revisions |
| 1,549 | ||||||
Accretion expense |
3,328 | 14,162 | ||||||
Liabilities settled during the period |
(1,380 | ) | (7,353 | ) | ||||
Asset retirement obligations, end of period |
$ | 186,069 | $ | 184,699 | ||||
7. | DEFERRED CHARGES |
As at | As at | |||||||
March 31, 2006 | December 31, 2006 | |||||||
Imputed interest on note payable net of
accumulated amortization of $3,047 (2005 - $2,859) |
$ | 560 | $ | 748 | ||||
U.S. debt issue costs net of accumulated
amortization of $892 (2005 - $816) |
1,249 | 1,325 | ||||||
Deferred compensation expense net of
accumulated amortization of $3,437 (2005 - $2,143) |
3,207 | 2,141 | ||||||
U.K. debt issue costs net of accumulated
amortization of $23 (2005 - $5) |
658 | 672 | ||||||
Deferred foreign exchange loss on
revaluation of U.K. debt hedge |
1,006 | | ||||||
$ | 6,680 | $ | 4,886 | |||||
8. | FOREIGN EXCHANGE LOSS (GAIN) |
Three months ended | ||||||||
March 31, | ||||||||
2006 | 2005 | |||||||
Unrealized foreign exchange loss on translation of
U.S. dollar denominated debt |
$ | 1,000 | $ | 1,520 | ||||
Realized foreign exchange loss (gain) |
239 | (160 | ) | |||||
$ | 1,239 | $ | 1,360 | |||||
The U.S. dollar and U.K. pound sterling denominated debt are translated into Canadian dollars at the Bank of Canada exchange rate in effect at the close of business on the balance sheet date. Foreign exchange gains and losses on the U.S. dollar denominated debt are included in income. Foreign exchange gains and losses on translating the U.K pound sterling denominated debt and the associated gains and losses on the U.K. pound sterling denominated exchange swap are deferred and included in deferred charges. |
9. | OTHER CASH FLOW DISCLOSURES |
Change in Non-Cash Operating Working Capital | |||
Cash provided by (used for): |
Three months ended | ||||||||
March 31, | ||||||||
2006 | 2005 | |||||||
Accounts receivable |
$ | 32,722 | $ | (1,092 | ) | |||
Inventory |
| 439 | ||||||
Accounts payable and accrued liabilities |
18,205 | 12,565 | ||||||
Due to Pengrowth Management Limited |
(588 | ) | (1,899 | ) | ||||
$ | 50,339 | $ | 10,013 | |||||
Change in Non-Cash Investing Working Capital | |||
Cash provided by (used for): |
Three months ended | ||||||||
March 31, | ||||||||
2006 | 2005 | |||||||
Accounts payable for capital accruals |
$ | (15,219 | ) | $ | (3,192 | ) | ||
Cash Payments |
Three months ended | ||||||||
March 31, | ||||||||
2006 | 2005 | |||||||
Cash payments made for taxes |
$ | 1,125 | $ | 1,247 | ||||
Cash payments made for interest |
$ | 1,092 | $ | 1,875 | ||||
10. | FINANCIAL INSTRUMENTS | |
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 March 31, 2006, Pengrowth had fixed the price applicable to future production as follows: |
Crude Oil: |
Volume | Reference | Price | ||||||||||
Remaining Term | (bbl/day) | Point | per bbl | |||||||||
Financial: |
||||||||||||
Apr 1, 2006 Dec 31, 2006 |
4,000 | WTI (1) | $64.08 Cdn | |||||||||
Natural Gas: |
Volume | Reference | Price | ||||||||||
Remaining Term | (mmbtu/day) | Point | per mmbtu | |||||||||
Financial: |
||||||||||||
Apr 1, 2006 Dec 31, 2006 |
2,500 | Transco Z6 (1) | $10.63 Cdn | |||||||||
Apr 1, 2006 Dec 31, 2006 |
2,370 | AECO | $8.03 Cdn | |||||||||
(1) | Associated Cdn$ / U.S.$ foreign exchange rate has been fixed. |
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 March 31, 2006, the amount Pengrowth would pay (receive) to terminate the financial crude oil and natural gas contracts would be $17.6 million and $(0.3) million, respectively. | ||
Natural Gas Fixed Price Sales Contract: | ||
Pengrowth also has a natural gas fixed price physical sales contract outstanding which was assumed in the 2004 Murphy acquisition, the details of which are provided below: |
Volume | Price | |||||||
Remaining Term | (mmbtu/day) | per mmbtu (2) | ||||||
2006 to 2009 |
||||||||
Apr 1, 2006 Oct 31, 2006 |
3,886 | $2.23 Cdn | ||||||
Nov 1, 2006 Oct 31, 2007 |
3,886 | $2.29 Cdn | ||||||
Nov 1, 2007 Oct 31, 2008 |
3,886 | $2.34 Cdn | ||||||
Nov 1, 2008 Apr 30, 2009 |
3,886 | $2.40 Cdn | ||||||
(2) | Reference price based on AECO |
As at March 31, 2006, the amount Pengrowth would pay to terminate the natural gas fixed price sales contract would be $26.9 million. | ||
Fair Value of Financial Instruments | ||
The carrying value of financial instruments included in the balance sheet, other than long term debt, the note payable and remediation trust funds approximate their fair value due to their short maturity. The fair value of the other financial instruments is as follows: |
As at March 31, 2006 | As at December 31, 2005 | |||||||||||||||
Net Book | Net Book | |||||||||||||||
Fair Value | Value | Fair Value | Value | |||||||||||||
Remediation Funds |
$ | 9,833 | $ | 8,720 | $ | 9,071 | $ | 8,329 | ||||||||
U.S. dollar denominated debt |
221,575 | 233,600 | 220,187 | 232,600 | ||||||||||||
£ denominated debt |
98,189 | 101,495 | 101,257 | 100,489 | ||||||||||||