e6vk
SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549
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 February 24, 2006 to February 28, 2006
PENGROWTH ENERGY TRUST
2900, 240 4th Avenue S.W.
Calgary, Alberta T2P 4H4 Canada
(address of principal executive offices)
[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): ]
DOCUMENTS FURNISHED HEREUNDER:
1. |
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Press Release announcing unaudited financial, operating and reserve results for year ended
December 31, 2005. |
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.
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PENGROWTH ENERGY TRUST
by its administrator PENGROWTH
CORPORATION |
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February 28, 2006
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By:
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/s/ Gordon M. Anderson
Name: Gordon M. Anderson
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Title: Vice President |
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NEWS RELEASE
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Attention: Financial Editors
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Stock Symbol:
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(PGF.A / PGF.B) TSX; |
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(PGH) NYSE |
PENGROWTH ENERGY TRUST ANNOUNCES UNAUDITED FINANCIAL, OPERATING AND
RESERVE RESULTS FOR YEAR ENDED DECEMBER 31, 2005
(Calgary February 27, 2006) /CCN Matthews/ Pengrowth Corporation, administrator of Pengrowth
Energy Trust, is pleased to report operating and financial results for the fourth quarter and year
ended December 31, 2005 as well as selected information from Pengrowths independent engineering
reserve report effective December 31, 2005.
YEAR 2005 OVERVIEW
Robust commodity prices, a full year of production from the 2004 Murphy acquisition and additional
production from the Swan Hills Unit No.1 (Swan Hills) and Crispin Energy Inc. (Crispin)
acquisitions, which closed on February 28, 2005 and April 29, 2005, respectively, combined to have
a favorable impact on 2005 financial and operating results relative to 2004.
2005 KEY ACHIEVEMENTS AND MILESTONES
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Oil and gas sales increased 41 percent to $1.15 billion in 2005 resulting in record
net income of $326 million, an increase of 112 percent over 2004. |
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Production for 2005 averaged 59,357 barrels of oil equivalent (boe) per day, an
increase of ten percent versus 2004. Fourth quarter production averaged 61,442 boe per
day, an increase of four percent over the previous quarter and seven percent over the
comparable period in 2004. |
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Distributable cash reached a new high in 2005 at $620 million, an increase of 54
percent over 2004. Fourth quarter distributable cash increased 87 percent versus 2004 to
$196 million, the highest level of distributable cash generated in any quarter in
Pengrowths history. |
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Distributions paid or declared to unitholders increased 23 percent to $446 million
or $2.82 per trust unit in 2005 from $363 million or $2.63 per trust unit in 2004.
Pengrowths monthly distribution was increased in December 2005 to an annualized rate of
$3.00 per trust unit. |
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Pengrowths payout ratio to unitholders for the full year and fourth quarter of
2005 reached record lows of 72 percent and 61 percent of cash generated from operations,
respectively. |
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Pengrowths 2005 development expenditures were essentially fully funded through the
withholdings from distributable cash. |
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During the year Pengrowth spent a combined total of $176 million on maintenance and
development projects ending the year with proved plus probable reserves of 219.4 million
barrels of oil equivalent (mmboe) compared to 218.6 mmboe at
year-end 2004. Pengrowths proved plus probable reserves were replaced through the addition of 16.7 mmboe
related to acquisitions and 8.6 mmboe resulting from drilling activity, improved recoveries
and technical revisions. Additions were offset by production of 21.7 mmboe and divestures
of 2.8 mmboe. |
- 2 -
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During 2005, Pengrowth incurred Finding and Development (F&D) costs for proved
reserves of $10.63 per boe, including the change in future development capital, in
accordance with NI 51-101. Excluding the downward revision to future development capital
of approximately $37 million, Pengrowths F&D costs for proved reserves totaled $15.47 per
boe during 2005. Overall finding, development and acquisition (FD&A) costs, with and
without the change in future development capital, were $14.42 per boe and $16.12 per boe,
respectively. |
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Pengrowths average realized commodity price (after hedging) increased 28 percent
to $53.02 per boe in 2005, from $41.33 in 2004. |
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Operating netbacks increased 33 percent to $32.54 per boe (after hedging) versus
$24.51 per boe in 2004. Combined hedging losses totaled $3.04 per boe in 2005 versus $3.52
per boe in 2004. |
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On February 28, 2005, Pengrowth acquired an additional 11.9 percent working
interest in the Swan Hills property for $87 million. This acquisition increased
Pengrowths total interest in the property to 22.3 percent. |
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On April 29, 2005, Pengrowth successfully completed the acquisition of all of the
issued and outstanding shares of Crispin, adding approximately 1,900 boe per day of
production to our portfolio. |
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On December 1, 2005, Pengrowth completed a £50 million private placement of senior
unsecured ten year notes. |
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As at December 31, 2005, Pengrowth had $337 million of funds available under its
$370 million in committed credit facilities. |
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As at December 31, 2005, Pengrowth had generated a combined three-year weighted
average compound total return of 36 percent per annum for Class A and Class B unitholders. |
The following table and discussion includes non-GAAP financial measures. Certain non-GAAP financial
measures are used to facilitate the evaluation of underlying trends that can be compared with prior
periods and may not be comparable to results presented by other companies (see Non-GAAP Financial
Measures).
- 3 -
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Summary of Financial and Operating Results |
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Three Months ended |
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Twelve Months ended |
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December 31 |
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% |
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December 31 |
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% |
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(thousands, except per unit amounts) |
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2005 |
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2004 |
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Change |
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2005 |
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2004 |
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Change |
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INCOME STATEMENT
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Oil and gas sales |
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$ |
353,923 |
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$ |
223,183 |
** |
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59 |
% |
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$ |
1,151,510 |
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$ |
815,751 |
** |
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41 |
% |
Net income |
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$ |
116,663 |
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$ |
31,138 |
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275 |
% |
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$ |
326,326 |
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$ |
153,745 |
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112 |
% |
Net income per trust unit |
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$ |
0.73 |
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$ |
0.23 |
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217 |
% |
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$ |
2.08 |
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$ |
1.15 |
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81 |
% |
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Cash generated from operations |
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$ |
196,588 |
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$ |
93,287 |
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111 |
% |
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$ |
618,070 |
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$ |
404,167 |
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53 |
% |
Cash generated from operations per trust unit |
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$ |
1.23 |
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$ |
0.68 |
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81 |
% |
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$ |
3.93 |
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$ |
3.03 |
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30 |
% |
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Distributable cash * |
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$ |
195,879 |
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$ |
104,958 |
** |
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87 |
% |
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$ |
619,739 |
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$ |
401,178 |
** |
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54 |
% |
Distributable cash per trust unit * |
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$ |
1.23 |
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$ |
0.77 |
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60 |
% |
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$ |
3.94 |
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$ |
3.01 |
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31 |
% |
Distributions paid or declared |
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$ |
119,858 |
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$ |
96,466 |
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24 |
% |
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$ |
445,977 |
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$ |
363,061 |
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23 |
% |
Distributions paid or declared per unit |
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$ |
0.75 |
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$ |
0.69 |
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9 |
% |
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$ |
2.82 |
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$ |
2.63 |
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7 |
% |
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Weighted average number of trust units outstanding |
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159,528 |
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136,916 |
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17 |
% |
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157,127 |
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133,395 |
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18 |
% |
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BALANCE SHEET
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Working capital |
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$ |
(112,205 |
) |
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$ |
(78,546 |
) |
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43 |
% |
Property, plant and equipment and other assets |
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$ |
2,067,988 |
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$ |
1,989,288 |
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4 |
% |
Long term debt |
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$ |
368,089 |
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$ |
345,400 |
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7 |
% |
Unitholders equity |
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$ |
1,475,996 |
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$ |
1,462,211 |
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1 |
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Unitholders equity per trust unit |
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$ |
9.23 |
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$ |
9.56 |
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-3 |
% |
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Number of trust units outstanding at year-end |
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159,864 |
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152,973 |
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5 |
% |
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Daily Production
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Crude oil (barrels) |
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21,179 |
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20,118 |
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5 |
% |
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20,799 |
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20,817 |
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0 |
% |
Heavy oil (barrels) |
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5,410 |
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5,819 |
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-7 |
% |
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5,623 |
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3,558 |
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58 |
% |
Natural gas (mcf) |
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168,862 |
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156,621 |
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8 |
% |
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161,056 |
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144,277 |
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12 |
% |
Natural gas liquids (barrels) |
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6,710 |
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5,385 |
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25 |
% |
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6,093 |
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5,281 |
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15 |
% |
Total production (boe) |
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61,442 |
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57,425 |
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7 |
% |
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59,357 |
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53,702 |
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10 |
% |
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Total Production (mboe) |
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5,653 |
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5,283 |
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7 |
% |
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21,665 |
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19,655 |
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10 |
% |
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Production Profile
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Crude oil |
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34 |
% |
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35 |
% |
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35 |
% |
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39 |
% |
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Heavy oil |
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9 |
% |
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10 |
% |
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10 |
% |
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6 |
% |
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Natural gas |
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46 |
% |
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46 |
% |
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45 |
% |
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45 |
% |
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Natural gas liquids |
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11 |
% |
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9 |
% |
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10 |
% |
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10 |
% |
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Average Realized Prices (after hedging)
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Crude oil (per barrel) |
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$ |
59.40 |
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$ |
44.76 |
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33 |
% |
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$ |
58.59 |
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$ |
43.21 |
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36 |
% |
Heavy oil (per barrel) |
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$ |
31.77 |
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$ |
26.99 |
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18 |
% |
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$ |
33.32 |
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$ |
32.45 |
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3 |
% |
Natural gas (per mcf) |
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$ |
11.97 |
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$ |
7.02 |
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71 |
% |
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$ |
8.76 |
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$ |
6.80 |
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29 |
% |
Natural gas liquids (per barrel) |
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$ |
58.46 |
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$ |
48.04 |
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22 |
% |
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$ |
54.22 |
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$ |
42.21 |
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28 |
% |
Average realized price per boe |
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$ |
62.55 |
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$ |
42.08 |
** |
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49 |
% |
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$ |
53.02 |
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$ |
41.33 |
** |
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28 |
% |
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Proved Plus Probable (P50) Reserves
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Crude oil (mbbls) |
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|
98,684 |
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|
94,066 |
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5 |
% |
Heavy oil (mbbls) |
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|
15,790 |
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|
18,245 |
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|
-13 |
% |
Natural gas (bcf) |
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|
|
|
|
|
|
|
|
|
516 |
|
|
|
521 |
|
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|
-1 |
% |
Natural gas liquids (mbbls) |
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|
18,985 |
|
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|
19,395 |
|
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|
-2 |
% |
Total oil equivalent (mboe) |
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|
|
|
|
|
|
|
|
|
|
|
|
|
219,396 |
|
|
|
218,613 |
|
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|
0 |
% |
|
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|
* |
|
See the section entitled Non-GAAP Financial Measures |
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** |
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Restated to conform to presentation adopted in the current year |
- 4 -
Frequently Recurring Terms
For the purposes of this release, we use certain frequently recurring terms as follows: the Trust
refers to Pengrowth Energy Trust, the Corporation refers to Pengrowth Corporation, Pengrowth
refers to the Trust and the Corporation on a consolidated basis and the Manager refers to
Pengrowth Management Limited.
Advisory Regarding Forward-Looking Statements
This release contains forward-looking statements within the meaning of securities laws, including
the safe harbour provisions of the Ontario Securities Act and the United States Private
Securities Litigation Reform Act of 1995. Forward-looking information is often, but not always,
identified by the use of words such as anticipate, believe, expect, plan, intend,
forecast, target, project, may, will, should, could, estimate, predict or similar
words suggesting future outcomes or language suggesting an outlook. Forward-looking statements in
this release include, but are not limited to, statements with respect to: reserves,
average 2006 production, production additions from Pengrowths 2006 development program, the impact
on production of divestitures in 2006, total operating cost for 2006, 2006 operating costs per boe,
capital expenditures for 2006 and the breakdown of such capital expenditures for drilling,
facilities and maintenance, land and seismic acquisition and
re-completions, workovers and CO2 pilot. Statements relating
to reserves are deemed to be forward-looking statements, as they involve the implied assessment, based on
certain estimates and assumptions that the reserves described exist in the quantities predicted or
estimated and can profitably be produced in the future.
Forward-looking statements and information are based on Pengrowths current beliefs as well as
assumptions made by and information currently available to Pengrowth concerning anticipated
financial performance, business prospects, strategies and regulatory developments. Although
management considers these assumptions to be reasonable based on information currently available to
it, they may prove to be incorrect.
By their very nature, forward-looking statements involve inherent risks and uncertainties, both
general and specific, and risks that predications, forecasts, projections and other forward-looking
statements will not be achieved. We caution readers not to place undue reliance on these statements
as a number of important factors could cause the actual results to differ materially from the
beliefs, plans, objectives, expectations and anticipations, estimates and intentions expressed in
such forward-looking statements. These factors include, but are not limited to: the volatility of
oil and gas prices; production and development costs and capital expenditures; the imprecision of
reserve estimates and estimates of recoverable quantities of oil, natural gas and liquids;
Pengrowths ability to replace and expand oil and gas reserves; environmental claims and
liabilities; incorrect assessments of value when making acquisitions; increases in debt service
charges; the loss of key personnel; the marketability of production; defaults by third party
operators; unforeseen title defects; fluctuations in foreign currency and exchange rates;
inadequate insurance coverage; compliance with environmental laws and regulations; changes in tax
laws; the failure to qualify as a mutual fund trust; and Pengrowths ability to access external
sources of debt and equity capital. Further information regarding these factors may be found in the
Supplemental Information section under the heading Business Risks herein and under Risk Factors
in Pengrowths Annual Information Form which will be available
on SEDAR at www.sedar.com on or
before March 31, 2006.
Pengrowth cautions that the foregoing list of factors that may affect future results is not
exhaustive. When relying on our forward-looking statements to make decisions with respect to
Pengrowth, investors and others should carefully consider the foregoing factors and other
uncertainties and potential events. Furthermore, the forward-looking statements contained in this
release are made as of the date of the release and Pengrowth does not undertake any obligation to
up-date publicly or to revise any of the included forward-looking statements, whether as a result
of new information, future events or otherwise. The forward-looking statements contained in this
release are expressly qualified by this cautionary statement.
- 5 -
Critical Accounting Estimates
As discussed in Note 2 to the financial statements, the financial statements are prepared in
accordance with Canadian Generally Accepted Accounting Principles (GAAP).Management is
required to make estimates and assumptions that affect the reported amounts of assets and
liabilities at the date of the financial statements and revenues and expenses for the period then
ended.
The amounts recorded for depletion, depreciation and amortization of injectants and the provision
for asset retirement obligations are based on estimates. The ceiling test calculation is based on
estimates of proved reserves, production rates, oil and natural gas prices, future costs and other
relevant assumptions. As required by National Instrument 51-101 (NI 51-101), Pengrowth uses
independent qualified reserve evaluators in the preparation of reserve evaluations. By their
nature, these estimates are subject to measurement uncertainty and changes in these estimates may
impact the consolidated financial statements of future periods.
Non-GAAP Financial Measures
This release refers to certain financial measures that are not determined in accordance with GAAP
in Canada or the United States. These measures do not have standardized meanings and may not be
comparable to similar measures presented by other trusts or corporations. Measures such as
distributable cash, distributable cash per trust unit, payout ratio and operating netbacks do not
have standardized meanings prescribed by GAAP. During the second quarter of 2005, Pengrowths
withholding practice and presentation of distributable cash changed. The impact of the new practice
is discussed in the Distributable Cash, Distributions and Taxability of Distributions section of
this release, while the remaining non-GAAP measures are determined by reference to our financial
statements. We discuss these measures because we believe that they facilitate the understanding of
the results of our operations and financial position.
Conversion and Currency
When converting natural gas to equivalent barrels of oil within this release, Pengrowth uses the
international standard of six thousand cubic feet (mcf) to one barrel of oil equivalent. Barrels of
oil equivalent may be misleading, particularly if used in isolation; a conversion ratio of six mcf
of natural gas to one boe is based on an energy equivalency conversion method primarily applicable
at the burner tip and does not represent a value equivalency at the wellhead. Production volumes,
revenues and reserves are reported on a company interest gross basis (before royalties) in
accordance with Canadian practice. All amounts are stated in Canadian dollars unless otherwise
specified.
RESULTS OF OPERATIONS
Production
Average daily production increased over ten percent in 2005 compared to 2004. The increase is
attributable primarily to the Murphy, Swan Hills and Crispin acquisitions and contributions from
ongoing development activities. At this time, Pengrowth is forecasting average 2006 production of
54,000 to 56,000 boe per day from existing assets. This estimate incorporates anticipated
production additions from planned 2006 development activities. Offsetting these additions are
previously disclosed divestitures of approximately 1,300 boe per day in the first quarter of 2006
which have been excluded from the above estimate, including the divestment of approximately 1,000
boe per day related to the Monterey Exploration Ltd. (Monterey) transaction announced on January
12, 2006 and expected production declines from normal operations. The above estimate specifically
excludes the potential impact of any other future acquisitions or divestitures.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three months ended |
|
|
|
|
|
|
|
Twelve months ended |
|
|
|
|
|
Daily Production |
|
Dec 31, 2005 |
|
|
Sept 30, 2005 |
|
|
Dec 31, 2004 |
|
|
|
Dec 31, 2005 |
|
|
Dec 31, 2004 |
|
|
|
|
|
Light crude oil (bbls) (1) |
|
|
21,179 |
|
|
|
20,660 |
|
|
|
20,118 |
|
|
|
|
20,799 |
|
|
|
20,817 |
|
Heavy oil (bbls) (1) |
|
|
5,410 |
|
|
|
5,405 |
|
|
|
5,819 |
|
|
|
|
5,623 |
|
|
|
3,558 |
|
Natural gas (mcf) |
|
|
168,862 |
|
|
|
164,288 |
|
|
|
156,621 |
|
|
|
|
161,056 |
|
|
|
144,277 |
|
Natural gas liquids (bbls) (1) |
|
|
6,710 |
|
|
|
5,448 |
|
|
|
5,385 |
|
|
|
|
6,093 |
|
|
|
5,281 |
|
|
|
|
|
Total boe per day |
|
|
61,442 |
|
|
|
58,894 |
|
|
|
57,425 |
|
|
|
|
59,357 |
|
|
|
53,702 |
|
|
|
|
|
|
|
|
(1) |
|
bbls refers to barrels
|
- 6 -
Light crude oil production volumes remained relatively flat year-over-year due to the positive
impact of production related to the Swan Hills and Crispin acquisitions which largely offset
natural production declines. Improved miscible flood response at Judy Creek contributed to most of
the three percent increase in production in fourth quarter 2005 versus the third quarter of 2005.
Heavy oil production increased 58 percent year-over-year due to the inclusion of a full 12 months
of production volumes from properties acquired in the Murphy acquisition which closed on May 31,
2004. The seven percent decrease in production for the fourth quarter of 2005 compared to the
fourth quarter of 2004 is attributable to natural production declines.
Natural gas production increased 12 percent year-over-year. Additional production volumes from the
Murphy and Crispin acquisitions and ongoing development activities, particularly the Monogram
infill drilling program completed in the fourth quarter of 2004, combined to more than offset
natural production declines. The three percent increase in volumes in the fourth quarter of 2005
compared to the third quarter of 2005 is due largely to a 44 well drilling program at Princess
which was completed during the fourth quarter. Fourth quarter 2005 volumes were eight percent
higher than fourth quarter 2004 volumes primarily due to the Crispin acquisition, new wells at
Princess and Sable Offshore Energy Project (SOEP) and lower residue gas solvent demand at Judy
Creek allowing for increased sales.
Natural gas liquids (NGL) production increased 15 percent year-over-year primarily due to the
timing and size of condensate sales from SOEP. Pengrowth received six shipments from SOEP in 2005
(two shipments in the fourth quarter) compared to four shipments in the previous year.
Pricing and Commodity Price Hedging
The increase in U.S. based prices for North American crude oil and natural gas was partially offset
by the negative impact of the rising Canadian dollar relative to the U.S. dollar and hedging
losses.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three months ended |
|
|
|
Twelve months ended |
|
|
|
|
|
|
|
Dec 31, 2005 |
|
|
Sept 30, 2005 |
|
|
Dec 31, 2004 |
|
|
|
Dec 31, 2005 |
|
|
Dec 31, 2004 |
|
|
|
|
|
Average realized prices (Cdn$) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Light crude oil (per bbl) |
|
|
67.00 |
|
|
|
74.37 |
|
|
|
55.24 |
|
|
|
|
65.47 |
|
|
|
50.72 |
|
after hedging |
|
|
59.40 |
|
|
|
63.95 |
|
|
|
44.76 |
|
|
|
|
58.59 |
|
|
|
43.21 |
|
Heavy oil (per bbl) |
|
|
31.77 |
|
|
|
47.74 |
|
|
|
26.99 |
|
|
|
|
33.32 |
|
|
|
32.45 |
|
Natural gas (per mcf) |
|
|
12.80 |
|
|
|
8.69 |
|
|
|
7.25 |
|
|
|
|
8.99 |
|
|
|
7.03 |
|
after hedging |
|
|
11.97 |
|
|
|
8.57 |
|
|
|
7.02 |
|
|
|
|
8.76 |
|
|
|
6.80 |
|
Natural gas liquids (per bbl) |
|
|
58.46 |
|
|
|
57.75 |
|
|
|
48.04 |
|
|
|
|
54.22 |
|
|
|
42.21 |
|
|
|
|
|
Total per boe |
|
|
67.43 |
|
|
|
60.06 |
|
|
|
46.38 |
|
|
|
|
56.06 |
|
|
|
44.85 |
|
after hedging |
|
|
62.55 |
|
|
|
56.07 |
|
|
|
42.08 |
|
|
|
|
53.02 |
|
|
|
41.33 |
|
|
|
|
|
Benchmark prices |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
WTI oil (U.S.$ per bbl) |
|
|
60.05 |
|
|
|
63.31 |
|
|
|
48.27 |
|
|
|
|
56.70 |
|
|
|
41.47 |
|
AECO spot
gas (Cdn$ per gj) (1) |
|
|
11.08 |
|
|
|
7.75 |
|
|
|
6.72 |
|
|
|
|
8.04 |
|
|
|
6.44 |
|
NYMEX gas
(U.S. $ per mmbtu) (2) |
|
|
12.97 |
|
|
|
8.49 |
|
|
|
7.11 |
|
|
|
|
8.62 |
|
|
|
6.16 |
|
Currency (U.S.$/Cdn $) |
|
|
0.85 |
|
|
|
0.83 |
|
|
|
0.82 |
|
|
|
|
0.83 |
|
|
|
0.77 |
|
|
|
|
|
|
|
|
(1) |
|
gj refers to gigajoules |
|
(2) |
|
mmbtu refers to millions of British thermal units |
As part of our financial management strategy, Pengrowth uses forward price swap and option
contracts to manage its exposure to commodity price fluctuations, to provide a measure of stability
to monthly cash distributions and to partially secure returns on significant new acquisitions.
- 7 -
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three months ended |
|
Twelve months ended |
|
Hedging Losses |
|
Dec 31, 2005 |
|
|
Sept 30, 2005 |
|
|
Dec 31, 2004 |
|
|
|
Dec 31, 2005 |
|
|
Dec 31, 2004 |
|
|
|
|
|
Light crude oil ($ million) |
|
|
14.8 |
|
|
|
19.8 |
|
|
|
19.4 |
|
|
|
|
52.2 |
|
|
|
57.2 |
|
Light crude oil ($ per bbl) |
|
|
7.60 |
|
|
|
10.42 |
|
|
|
10.48 |
|
|
|
|
6.88 |
|
|
|
7.51 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural gas ($ million) |
|
|
12.9 |
|
|
|
1.8 |
|
|
|
3.3 |
|
|
|
|
13.6 |
|
|
|
11.9 |
|
Natural gas ($ per mcf) |
|
|
0.83 |
|
|
|
0.12 |
|
|
|
0.23 |
|
|
|
|
0.23 |
|
|
|
0.23 |
|
|
|
|
|
Combined ($ million) |
|
|
27.7 |
|
|
|
21.6 |
|
|
|
22.7 |
|
|
|
|
65.8 |
|
|
|
69.1 |
|
Combined ($ per boe) |
|
|
4.88 |
|
|
|
3.99 |
|
|
|
4.30 |
|
|
|
|
3.04 |
|
|
|
3.52 |
|
|
|
|
|
Commodity price hedges in place at December 31, 2005 are provided in Note 17 to the financial
statements. Pengrowth has not entered into any additional contracts subsequent to year-end as of
February 27, 2006.
In conjunction with the Murphy acquisition, Pengrowth assumed certain fixed price natural gas sales
contracts and firm pipeline demand charge contracts associated with the Murphy reserves. Under
these contracts, Pengrowth is obligated to sell 3,886 mmbtu per day, until April 30, 2009 at an
average remaining contract price of Cdn $2.31 per mmbtu. As required by GAAP, the fair value of the
natural gas sales contract was recognized as a liability based on the mark-to-market value at May
31, 2004. The liability at December 31, 2005 of $18.2 million for the contracts will continue to be
drawn down and recognized in income as the contracts are settled. As this is a non-cash component
of income, it is not included in the calculation of distributable cash. At December 31, 2005, the
mark-to-market value of the fixed price physical sales contract represented a potential loss of
$35.3 million.
Oil
and Gas Sales Contribution Analysis
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three months ended |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Twelve months ended |
|
|
|
|
|
|
|
Dec 31, |
|
|
|
% of |
|
|
Sept 30, |
|
|
|
% of |
|
|
Dec 31, |
|
|
|
% of |
|
|
Dec 31, |
|
|
|
% of |
|
|
Dec 31, |
|
|
|
% of |
Sales Revenue ($ million) |
|
|
2005 |
|
|
|
total |
|
|
2005 |
|
|
|
total |
|
|
2004 |
|
|
|
total |
|
|
2005 |
|
|
|
total |
|
|
2004 |
|
|
|
total |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural gas |
|
|
|
186.0 |
|
|
|
53 |
% |
|
|
|
129.5 |
|
|
|
43 |
% |
|
|
|
101.2 |
|
|
|
45 |
% |
|
|
|
514.9 |
|
|
|
45 |
% |
|
|
|
359.3 |
|
|
|
44 |
% |
Light crude oil |
|
|
|
115.7 |
|
|
|
33 |
% |
|
|
|
121.6 |
|
|
|
40 |
% |
|
|
|
82.8 |
|
|
|
37 |
% |
|
|
|
444.8 |
|
|
|
39 |
% |
|
|
|
329.2 |
|
|
|
40 |
% |
Natural gas liquids |
|
|
|
36.1 |
|
|
|
10 |
% |
|
|
|
28.9 |
|
|
|
9 |
% |
|
|
|
23.8 |
|
|
|
11 |
% |
|
|
|
120.6 |
|
|
|
10 |
% |
|
|
|
81.6 |
|
|
|
10 |
% |
Heavy oil |
|
|
|
15.8 |
|
|
|
4 |
% |
|
|
|
23.7 |
|
|
|
8 |
% |
|
|
|
14.5 |
|
|
|
7 |
% |
|
|
|
68.4 |
|
|
|
6 |
% |
|
|
|
42.3 |
|
|
|
5 |
% |
Brokered sales/sulphur |
|
|
|
0.3 |
|
|
|
0 |
% |
|
|
|
0.8 |
|
|
|
0 |
% |
|
|
|
0.9 |
|
|
|
0 |
% |
|
|
|
2.8 |
|
|
|
0 |
% |
|
|
|
3.4 |
|
|
|
1 |
% |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total oil and gas sales |
|
|
|
353.9 |
|
|
|
|
|
|
|
|
304.5 |
|
|
|
|
|
|
|
|
223.2 |
|
|
|
|
|
|
|
|
1,151.5 |
|
|
|
|
|
|
|
|
815.8 |
|
|
|
|
|
Oil and Gas Sales Price and Volumes Analysis
The following table illustrates the effect of changes in prices and volumes on the components of
oil and gas sales, including the impact of hedging.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
($ million) |
|
Natural gas |
|
|
Light oil |
|
|
NGL |
|
|
Heavy oil |
|
|
Other |
|
|
Total |
|
|
Year ended December 31, 2004 |
|
|
359.3 |
|
|
|
329.2 |
|
|
|
81.6 |
|
|
|
42.3 |
|
|
|
3.4 |
|
|
|
815.8 |
|
Effect of change in product prices |
|
|
115.3 |
|
|
|
112.0 |
|
|
|
26.7 |
|
|
|
1.8 |
|
|
|
|
|
|
|
255.8 |
|
Effect of change in sales volumes |
|
|
42.0 |
|
|
|
(1.4 |
) |
|
|
12.3 |
|
|
|
24.3 |
|
|
|
|
|
|
|
77.2 |
|
Effect of hedging losses |
|
|
(1.7 |
) |
|
|
5.0 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
3.3 |
|
Other |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(0.6 |
) |
|
|
(0.6 |
) |
|
Year ended December 31, 2005 |
|
|
514.9 |
|
|
|
444.8 |
|
|
|
120.6 |
|
|
|
68.4 |
|
|
|
2.8 |
|
|
|
1,151.5 |
|
|
Processing, Interest and Other Income
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three months ended |
|
|
|
|
|
|
|
Twelve months ended |
|
($ million) |
|
Dec 31, 2005 |
|
|
Sept 30, 2005 |
|
|
Dec 31, 2004 |
|
|
|
Dec 31, 2005 |
|
|
Dec 31, 2004 |
|
|
|
|
|
Processing, interest & other income |
|
|
4.0 |
|
|
|
2.1 |
|
|
|
4.5 |
|
|
|
|
17.7 |
|
|
|
14.2 |
|
$ per boe |
|
|
0.71 |
|
|
|
0.39 |
|
|
|
0.83 |
|
|
|
|
0.82 |
|
|
|
0.72 |
|
|
|
|
|
- 8 -
Processing, interest and other income is primarily derived from fees charged for processing
and gathering third party gas, road use, and oil and water processing. This income represents the
partial recovery of operating costs included below in Operating Expenses.
Royalties
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three months ended |
|
|
Twelve months ended |
($ million) |
|
Dec 31, 2005 |
|
Sept 30, 2005 |
|
Dec 31, 2004 |
|
|
Dec 31, 2005 |
|
Dec 31, 2004 |
|
|
|
|
Royalty expense |
|
|
68.0 |
|
|
|
57.4 |
|
|
|
49.1 |
|
|
|
|
213.9 |
|
|
|
160.4 |
|
$ per boe |
|
|
12.03 |
|
|
|
10.60 |
|
|
|
9.29 |
|
|
|
|
9.87 |
|
|
|
8.16 |
|
|
|
|
|
Royalties as a percent of sales |
|
|
19.2 |
% |
|
|
18.9 |
% |
|
|
22.0 |
% |
|
|
|
18.6 |
% |
|
|
19.7 |
% |
|
|
|
|
Royalties include crown, freehold and overriding royalties as well as mineral taxes. A lesser
credit for enhanced oil recovery relief at Judy Creek had an unfavorable impact to royalties in the
fourth quarter of 2004 as solvent injection costs were lower than anticipated.
Operating Expenses
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three months ended |
|
|
|
|
|
|
Twelve months ended |
($ million) |
|
Dec 31, 2005 |
|
Sept 30, 2005 |
|
Dec 31, 2004 |
|
|
Dec 31, 2005 |
|
Dec 31, 2004 |
|
|
|
|
Operating expenses |
|
|
61.2 |
|
|
|
57.4 |
|
|
|
42.6 |
|
|
|
|
218.1 |
|
|
|
159.7 |
|
$ per boe |
|
|
10.83 |
|
|
|
10.59 |
|
|
|
8.06 |
|
|
|
|
10.07 |
|
|
|
8.13 |
|
|
|
|
|
Operating expenses increased year-over-year as a result of timing of acquisitions partway
through 2004 and in 2005 which impacted costs by approximately $30 million. Additionally, there
was general upward pressure on the cost of goods and services in the oil and gas industry during
2005, with year-over-year increases of more than ten percent within most of these areas. Utility
costs also increased approximately $10 million year-over-year. Operating expenses include costs
incurred to earn processing and other income included above in Processing, Interest and Other
Income.
Transportation Costs
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three months ended |
|
|
|
|
|
|
Twelve months ended |
($ million) |
|
Dec 31, 2005 |
|
Sept 30, 2005 |
|
Dec 31, 2004 |
|
|
Dec 31, 2005 |
|
Dec 31, 2004 |
|
|
|
|
Light oil transportation |
|
|
0.5 |
|
|
|
0.6 |
|
|
|
0.4 |
|
|
|
|
2.2 |
|
|
|
1.8 |
|
$ per bbl |
|
|
0.27 |
|
|
|
0.29 |
|
|
|
0.23 |
|
|
|
|
0.29 |
|
|
|
0.23 |
|
Natural gas transportation |
|
|
1.8 |
|
|
|
1.4 |
|
|
|
2.0 |
|
|
|
|
5.7 |
|
|
|
6.3 |
|
$ per mcf |
|
|
0.12 |
|
|
|
0.09 |
|
|
|
0.14 |
|
|
|
|
0.10 |
|
|
|
0.12 |
|
|
|
|
|
Pengrowth incurs transportation costs for its product once the product enters a feeder or main
pipeline to the title transfer point. The transportation cost is dependant upon industry rates and
distance the product flows on the pipeline prior to changing ownership or custody. Pengrowth has
the option to sell some of its natural gas directly to premium markets outside of Alberta by
incurring additional transportation costs. In 2005, Pengrowth sold most of its natural gas without
incurring significant additional transportation costs. Similarly, Pengrowth has elected to sell
approximately 75 percent of its crude oil at market points beyond the wellhead, but at the first
major trading point, requiring minimal transportation costs.
Amortization of Injectants for Miscible Floods
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three months ended |
|
|
Twelve months ended |
($ million) |
|
Dec 31, 2005 |
|
Sept 30, 2005 |
|
Dec 31, 2004 |
|
|
Dec 31, 2005 |
|
Dec 31, 2004 |
|
|
|
|
Purchased and capitalized |
|
|
14.5 |
|
|
|
6.9 |
|
|
|
8.2 |
|
|
|
|
34.7 |
|
|
|
20.4 |
|
Amortization |
|
|
7.1 |
|
|
|
6.0 |
|
|
|
4.9 |
|
|
|
|
24.4 |
|
|
|
19.7 |
|
|
|
|
|
The cost of injectants (primarily natural gas and ethane) purchased for injection in miscible
flood programs is amortized over the period of expected future economic benefit. Prior to 2005,
the expected future economic benefit from injection was estimated at 30 months, based on the
results of previous flood patterns. Commencing in 2005 the response period for additional new
patterns being
- 9 -
developed is expected to be somewhat shorter relative to the historical
miscible patterns in the project. Accordingly, the cost of injectants purchased in 2005 will be
amortized over a 24 month period while costs incurred for the purchase of injectants in prior
periods will continue to be amortized over 30 months. As of December 31, 2005, the balance of
unamortized injectant costs was $35.3 million.
The value of Pengrowths proprietary injectants is not recorded until reproduced from the flood and
sold, although the cost of producing these injectants is included in operating costs. Pengrowth
currently anticipates similar injection volumes for Judy Creek and increased injection volumes for
Swan Hills during 2006. This combined with higher forecast prices for natural gas and ethane is
anticipated to result in increased total injectant costs for 2006.
Netbacks
There is no standardized measure of operating netbacks and therefore operating netbacks, as
presented below may not be comparable to similar measures presented by other companies. Certain
assumptions have been made in allocating operating expenses, other production income, other income
and royalty injection credits between light crude oil, heavy oil, natural gas and NGL production.
Pengrowth recorded an operating netback of $32.54 per boe (after hedging) in 2005 compared to
$24.51 (after hedging) in 2004, mainly due to higher average commodity prices in 2005 partially
offset by higher operating costs and royalties.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three months ended |
|
Twelve months ended |
Combined Netbacks ($ per boe) |
|
Dec 31, 2005 |
|
Sept 30, 2005 |
|
Dec 31, 2004 |
|
Dec 31, 2005 |
|
Dec 31, 2004 |
|
|
|
|
|
Sales price |
|
$ |
62.55 |
|
|
$ |
56.07 |
|
|
$ |
42.08 |
|
|
$ |
53.02 |
|
|
$ |
41.33 |
|
Other production income |
|
|
0.06 |
|
|
|
0.13 |
|
|
|
0.17 |
|
|
|
0.13 |
|
|
|
0.17 |
|
|
|
|
|
|
|
|
|
62.61 |
|
|
|
56.20 |
|
|
|
42.25 |
|
|
|
53.15 |
|
|
|
41.50 |
|
Processing, interest and other income |
|
|
0.71 |
|
|
|
0.39 |
|
|
|
0.83 |
|
|
|
0.82 |
|
|
|
0.72 |
|
Royalties |
|
|
(12.02 |
) |
|
|
(10.60 |
) |
|
|
(9.29 |
) |
|
|
(9.87 |
) |
|
|
(8.16 |
) |
Operating costs |
|
|
(10.83 |
) |
|
|
(10.59 |
) |
|
|
(8.07 |
) |
|
|
(10.07 |
) |
|
|
(8.13 |
) |
Transportation costs |
|
|
(0.41 |
) |
|
|
(0.36 |
) |
|
|
(0.47 |
) |
|
|
(0.36 |
) |
|
|
(0.42 |
) |
Amortization of injectants |
|
|
(1.25 |
) |
|
|
(1.10 |
) |
|
|
(0.94 |
) |
|
|
(1.13 |
) |
|
|
(1.00 |
) |
|
|
|
|
|
Operating netback |
|
$ |
38.81 |
|
|
$ |
33.94 |
|
|
$ |
24.31 |
|
|
$ |
32.54 |
|
|
$ |
24.51 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three months ended |
|
Twelve months ended |
Light Crude Netbacks ($ per bbl) |
|
Dec 31, 2005 |
|
Sept 30, 2005 |
|
Dec 31, 2004 |
|
Dec 31, 2005 |
|
Dec 31, 2004 |
|
|
|
|
|
Sales price |
|
$ |
59.40 |
|
|
$ |
63.95 |
|
|
$ |
44.76 |
|
|
$ |
58.59 |
|
|
$ |
43.21 |
|
Other production income |
|
|
0.17 |
|
|
|
0.37 |
|
|
|
0.48 |
|
|
|
0.37 |
|
|
|
0.45 |
|
|
|
|
|
|
|
|
|
59.57 |
|
|
|
64.32 |
|
|
|
45.24 |
|
|
|
58.96 |
|
|
|
43.66 |
|
Processing, interest and other income |
|
|
0.34 |
|
|
|
0.64 |
|
|
|
0.51 |
|
|
|
0.47 |
|
|
|
0.46 |
|
Royalties |
|
|
(6.47 |
) |
|
|
(11.03 |
) |
|
|
(9.65 |
) |
|
|
(8.64 |
) |
|
|
(7.62 |
) |
Operating costs |
|
|
(14.32 |
) |
|
|
(12.85 |
) |
|
|
(9.17 |
) |
|
|
(12.28 |
) |
|
|
(9.31 |
) |
Transportation costs |
|
|
(0.27 |
) |
|
|
(0.29 |
) |
|
|
(0.23 |
) |
|
|
(0.29 |
) |
|
|
(0.23 |
) |
Amortization of injectants |
|
|
(3.63 |
) |
|
|
(3.14 |
) |
|
|
(2.67 |
) |
|
|
(3.21 |
) |
|
|
(2.58 |
) |
|
|
|
|
|
Operating netback |
|
$ |
35.22 |
|
|
$ |
37.65 |
|
|
$ |
24.03 |
|
|
$ |
35.01 |
|
|
$ |
24.38 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three months ended |
|
Twelve months ended |
Heavy Oil Netbacks ($ per bbl) |
|
Dec 31, 2005 |
|
Sept 30, 2005 |
|
Dec 31, 2004 |
|
Dec 31, 2005 |
|
Dec 31, 2004 |
|
|
|
|
|
Sales price |
|
$ |
31.77 |
|
|
$ |
47.74 |
|
|
$ |
26.99 |
|
|
$ |
33.32 |
|
|
$ |
32.45 |
|
|
Processing, interest and other income |
|
|
0.74 |
|
|
|
(0.83 |
) |
|
|
|
|
|
|
0.36 |
|
|
|
|
|
Royalties |
|
|
(2.98 |
) |
|
|
(8.00 |
) |
|
|
(4.19 |
) |
|
|
(4.53 |
) |
|
|
(4.87 |
) |
Operating costs |
|
|
(11.60 |
) |
|
|
(16.30 |
) |
|
|
(9.44 |
) |
|
|
(15.65 |
) |
|
|
(9.85 |
) |
|
|
|
|
|
Operating netback |
|
$ |
17.93 |
|
|
$ |
22.61 |
|
|
$ |
13.36 |
|
|
$ |
13.50 |
|
|
$ |
17.73 |
|
|
|
|
|
|
- 10 -
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three months ended |
|
Twelve months ended |
Natural Gas Netbacks ($ per mcf) |
|
Dec 31, 2005 |
|
Sept 30, 2005 |
|
Dec 31, 2004 |
|
Dec 31, 2005 |
|
Dec 31, 2004 |
|
|
|
|
|
Sales price |
|
$ |
11.97 |
|
|
$ |
8.57 |
|
|
$ |
7.02 |
|
|
$ |
8.76 |
|
|
$ |
6.80 |
|
|
Processing, interest and other income |
|
|
0.19 |
|
|
|
0.09 |
|
|
|
0.24 |
|
|
|
0.23 |
|
|
|
0.20 |
|
Royalties |
|
|
(2.62 |
) |
|
|
(1.47 |
) |
|
|
(1.34 |
) |
|
|
(1.70 |
) |
|
|
(1.26 |
) |
Operating costs |
|
|
(1.38 |
) |
|
|
(1.31 |
) |
|
|
(1.16 |
) |
|
|
(1.24 |
) |
|
|
(1.15 |
) |
Transportation costs |
|
|
(0.12 |
) |
|
|
(0.09 |
) |
|
|
(0.14 |
) |
|
|
(0.10 |
) |
|
|
(0.12 |
) |
|
|
|
|
|
Operating netback |
|
$ |
8.04 |
|
|
$ |
5.79 |
|
|
$ |
4.62 |
|
|
$ |
5.95 |
|
|
$ |
4.47 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three months ended |
|
Twelve months ended |
NGL Netbacks ($ per bbl) |
|
Dec 31, 2005 |
|
Sept 30, 2005 |
|
Dec 31, 2004 |
|
Dec 31, 2005 |
|
Dec 31, 2004 |
|
|
|
|
|
Sales price |
|
$ |
58.46 |
|
|
$ |
57.75 |
|
|
$ |
48.04 |
|
|
$ |
54.22 |
|
|
$ |
42.21 |
|
|
Royalties |
|
|
(21.29 |
) |
|
|
(20.57 |
) |
|
|
(19.37 |
) |
|
|
(17.66 |
) |
|
|
(15.43 |
) |
Operating costs |
|
|
(10.05 |
) |
|
|
(10.13 |
) |
|
|
(7.87 |
) |
|
|
(9.04 |
) |
|
|
(7.94 |
) |
Transportation costs |
|
|
|
|
|
|
|
|
|
|
(0.10 |
) |
|
|
|
|
|
|
(0.10 |
) |
|
|
|
|
|
Operating netback |
|
$ |
27.12 |
|
|
$ |
27.05 |
|
|
$ |
20.70 |
|
|
$ |
27.52 |
|
|
$ |
18.74 |
|
|
|
|
|
|
Interest
Interest expense decreased by 28 percent to $21.6 million in 2005 from $29.9 million in 2004,
reflecting a lower average debt level, the impact of the appreciation of the Canadian dollar on
U.S. dollar denominated interest and lower standby fees. Standby fees in 2004 of $3.9 million were
related to the set-up of bridge financing utilized for the 2004 Murphy acquisition. Imputed
interest on the note payable to Emera Offshore Incorporated (Emera) was also recorded in the amount
of $1.3 million (2004 $1.6 million).
The average interest rate on Pengrowths long term debt outstanding at December 31, 2005 is 5.1
percent. Approximately 63 percent of Pengrowths outstanding debt as at December 31, 2005 incurs
interest expense payable in U.S. dollars and therefore remains subject to fluctuations in the U.S.
dollar exchange rate. The note payable is non-interest bearing.
General and Administrative
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three months ended |
|
|
Twelve months ended |
($ million) |
|
Dec 31, 2005 |
|
Sept 30, 2005 |
|
Dec 31, 2004 |
|
|
Dec 31, 2005 |
|
Dec 31, 2004 |
|
|
|
|
Cash G&A expense |
|
|
7.7 |
|
|
|
7.0 |
|
|
|
6.5 |
|
|
|
|
27.4 |
|
|
|
22.1 |
|
$ per boe |
|
|
1.36 |
|
|
|
1.29 |
|
|
|
1.23 |
|
|
|
|
1.27 |
|
|
|
1.12 |
|
Non-cash G&A expense |
|
|
0.8 |
|
|
|
0.6 |
|
|
|
0.4 |
|
|
|
|
2.9 |
|
|
|
2.3 |
|
$ per boe |
|
|
0.14 |
|
|
|
0.11 |
|
|
|
0.08 |
|
|
|
|
0.13 |
|
|
|
0.12 |
|
|
|
|
|
Total G&A ($ million) |
|
|
8.5 |
|
|
|
7.6 |
|
|
|
6.9 |
|
|
|
|
30.3 |
|
|
|
24.4 |
|
Total G&A ($ per boe) |
|
|
1.50 |
|
|
|
1.40 |
|
|
|
1.31 |
|
|
|
|
1.40 |
|
|
|
1.24 |
|
|
|
|
|
The cash component of General and Administrative (G&A) increased due to a number of factors
including the addition of personnel and office space in conjunction with the Murphy acquisition as
well as a general increase in financial reporting, legal and regulatory costs related to the growth
in our unitholder base and increasing regulatory requirements including preparing for compliance
with the Sarbanes-Oxley Act and the related requirement to report on internal controls. The
non-cash compensation is expense related to the value of trust unit options and rights (see Note 2
and Note 10 to the financial statements for details). Also included in 2005 G&A is $0.9 million
(2004 $0.8 million) for estimated reimbursement of G&A expenses incurred by the Manager, pursuant
to the management agreement.
- 11 -
Management Fees
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three months ended |
|
|
Twelve months ended |
($ million) |
|
Dec 31, 2005 |
|
Sept 30, 2005 |
|
Dec 31, 2004 |
|
|
Dec 31, 2005 |
|
Dec 31, 2004 |
|
|
|
|
Management Fee |
|
|
2.2 |
|
|
|
1.6 |
|
|
|
1.4 |
|
|
|
|
9.1 |
|
|
|
6.8 |
|
Performance Fee |
|
|
2.2 |
|
|
|
1.9 |
|
|
|
1.2 |
|
|
|
|
6.9 |
|
|
|
6.1 |
|
|
|
|
|
Total ($ million) |
|
|
4.4 |
|
|
|
3.5 |
|
|
|
2.6 |
|
|
|
|
16.0 |
|
|
|
12.9 |
|
Total ($ per boe) |
|
|
0.77 |
|
|
|
0.65 |
|
|
|
0.48 |
|
|
|
|
0.74 |
|
|
|
0.66 |
|
|
|
|
|
Under the current management agreement, which came into effect July 1, 2003 for two three-year
terms ending June 30, 2009, the Manager will earn a performance fee if the Trusts total returns
exceed eight percent per annum on a three year rolling average basis. At the end of the first term,
a review process will determine whether to extend the agreement for the second term. The maximum
fees payable, including the performance fee, is limited to 80 percent of the fees that would
otherwise have been payable under the previous management agreement for the first three years and
60 percent for the subsequent three years.
The Trust achieved a three-year average total return of 36 percent per annum at the end of 2005; as
a result the Manager earned the maximum fee payable under the new management agreement.
Foreign Currency Gains and Losses
Pengrowth recorded a net foreign exchange gain of $7.0 million in 2005, compared to a foreign
exchange gain of $17.3 million in 2004. Included in the 2005 gain is a $7.8 million unrealized
foreign exchange gain related to the U.S. dollar denominated debt. This gain arises as a result of
the increase in the Canadian to U.S. dollar exchange rate in 2005 from a rate of approximately
$0.83 at December 31, 2004 to a rate of approximately $0.86 at December 31, 2005. Offsetting this
gain is a realized foreign exchange loss of $0.8 million related mainly to U.S. dollar denominated
receivables. Revenues are recorded at the average exchange rate for the production month in which
they accrue, with payment being received on or about the 25th of the following month. As
a result of the increase in the Canadian dollar relative to the U.S. dollar over the course of the
year, a foreign exchange loss was recorded to the extent that there was a difference between the
average exchange rate for the month of production and the exchange rate at the date the payments
were received on that portion of production sales that are received in U.S. dollars. Pengrowth has
arranged a significant portion of its long term debt in U.S. dollars as a natural
hedge against a stronger Canadian dollar, as the negative impact on oil and gas sales is somewhat
offset by a reduction in the U.S. dollar denominated interest cost (See Note 12 to the financial
statements for further detail).
Depletion, Depreciation and Accretion
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three months ended |
|
|
Twelve months ended |
($ million) |
|
Dec 31, 2005 |
|
Sept 30, 2005 |
|
Dec 31, 2004 |
|
|
Dec 31, 2005 |
|
Dec 31, 2004 |
|
|
|
|
Depletion and Depreciation |
|
|
71.4 |
|
|
|
73.5 |
|
|
|
69.4 |
|
|
|
|
285.0 |
|
|
|
247.3 |
|
$ per boe |
|
|
12.63 |
|
|
|
13.57 |
|
|
|
13.14 |
|
|
|
|
13.15 |
|
|
|
12.58 |
|
Accretion |
|
|
3.6 |
|
|
|
3.6 |
|
|
|
3.2 |
|
|
|
|
14.2 |
|
|
|
10.6 |
|
$ per boe |
|
|
0.64 |
|
|
|
0.66 |
|
|
|
0.60 |
|
|
|
|
0.65 |
|
|
|
0.54 |
|
|
|
|
|
Depletion and depreciation of property, plant and equipment and other assets is provided on
the unit of production method based on total proved reserves. The provision for depletion and
depreciation increased 15 percent in 2005 due to a larger depletable asset base and a higher
depletion rate (production as a percentage of total proved reserves).
Accretion increased 34 percent year-over-year due to a larger Asset Retirement Obligation (ARO).
Taxes
In determining its taxable income, the Corporation deducts payments made to the Trust, effectively
transferring the income tax liability to unitholders thus reducing taxable income to nil. Under the
Corporations current distribution policy, funds are withheld from distributable cash to fund
future
- 12 -
capital expenditures and repay debt. As a result of increased amounts being withheld to fund
capital spending, the Corporation could become subject to taxation on a portion of its income in
the future. This can be mitigated through various options including the issuance of additional
trust units, increased tax pools from additional capital spending, modifications to the
distribution policy or changes to the corporate structure. As a result, the Corporation does not
anticipate the payment of any cash income taxes in the foreseeable future.
Capital taxes paid or payable by the Corporation, based on debt and equity levels at the end of the
year, amounted to $6.2 million in 2005 (2004 $4.6 million). This amount is comprised of Federal
Large Corporations Tax of $2.2 million (2004 $1.3 million) and Saskatchewan Capital Tax and
Resource Surcharge of $4.0 million (2004 $3.2 million). The increase in 2005 capital taxes is due
to a higher taxable capital base from the Crispin acquisition and increased capital expenditures
relative to 2004.
The corporate acquisition of Crispin in 2005 resulted in Pengrowth recording an additional future
tax liability of $22.2 million. A $75.6 million future tax liability was initially recorded in 2004
as a result of the Murphy acquisition. The future tax liability represents the difference between
the tax basis and the fair values assigned to the acquired assets. A comparison of the fair value
and tax basis at the end of the year increased the future tax liability by $12.3 million to $110.1
million.
Capital Expenditures
During 2005, Pengrowth spent $175.7 million on development and optimization activities. The largest
expenditures were in Judy Creek ($36.7 million), SOEP ($27.2 million), Princess ($11.1 million),
Weyburn ($8.8 million), Prespatou ($7.5 million) and Swan Hills ($7.2 million). Pengrowth does not
typically participate in high risk exploration activities and in 2005 most of the capital spent on
development was directed towards increasing production, arresting production declines and improving
recovery through infill drilling.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three months ended |
|
|
|
Twelve months ended |
|
($ million) |
|
Dec 31, 2005 |
|
|
Sept 30, 2005 |
|
|
Dec 31, 2004 |
|
|
|
Dec 31, 2005 |
|
|
Dec 31, 2004 |
|
|
|
|
|
Geological and geophysical |
|
|
0.7 |
|
|
|
0.2 |
|
|
|
0.2 |
|
|
|
|
2.1 |
|
|
|
0.6 |
|
Drilling and completions |
|
|
40.4 |
|
|
|
29.8 |
|
|
|
36.1 |
|
|
|
|
129.6 |
|
|
|
111.3 |
|
Plant and facilities |
|
|
10.2 |
|
|
|
10.0 |
|
|
|
17.7 |
|
|
|
|
34.1 |
|
|
|
49.1 |
|
Land purchases |
|
|
8.8 |
|
|
|
0.8 |
|
|
|
0.2 |
|
|
|
|
9.9 |
|
|
|
2.3 |
|
|
|
|
|
Development capital |
|
|
60.1 |
|
|
|
40.8 |
|
|
|
54.2 |
|
|
|
|
175.7 |
|
|
|
163.3 |
|
|
|
|
|
Acquisitions |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
175.1 |
|
|
|
569.7 |
|
|
|
|
|
Total capital
expenditures and acqusit |
|
|
60.1 |
|
|
|
40.8 |
|
|
|
54.2 |
|
|
|
|
350.8 |
|
|
|
733.0 |
|
|
|
|
|
Pengrowths planned capital expenditures for maintenance and development opportunities at
existing properties are approximately $236 million for 2006 which is the largest capital program in
Pengrowths history. Approximately half of the 2006 spending will be on a 280 gross well (132 net
well) drilling program. The remainder of the budget will be spent on recompletions and
reactivations, development of coalbed methane resources, production enhancements and ongoing
maintenance. Pengrowths 2006 capital program targets the furtherance of Pengrowths short, medium
and long term objectives, reflecting Pengrowths focus on pursuing a balanced approach to the
development of its key assets. While the most significant portion of Pengrowths 2006 capital
program will involve the continued development and maintenance of existing production and
properties, a key element of the 2006 program will be further development of mid and longer term
plays or projects in coalbed methane, heavy oil and enhanced oil recovery. Pengrowth anticipates
funding its 2006 capital expenditures through a combination of undistributed cash from operations,
unused credit facilities and any proceeds from property dispositions.
Acquisitions and Dispositions
On February 28, 2005, Pengrowth closed the acquisition of an additional 11.9 percent working
interest in Swan Hills increasing Pengrowths total working interest in the unit to 22.3 percent.
The
- 13 -
purchase price was $87 million, after adjustments from the October 1, 2004
effective date to the closing date.
On April 29, 2005, Pengrowth completed the acquisition of Crispin which held interests in oil and
natural gas assets mainly in Alberta. This represented Pengrowths first acquisition of a publicly
traded corporation and was funded through the issuance of Class A and Class B trust units valued at
approximately $88 million. Pengrowth also assumed debt of approximately $20 million as part of the
acquisition.
During the second half of 2005, Pengrowth received approximately $38 million of proceeds from the
sale of non-core oil and natural gas properties with associated production of approximately 600 boe
per day.
On May 31, 2004, Pengrowth acquired oil and natural gas assets in Alberta and Saskatchewan from a
subsidiary of Murphy Oil Corporation for a purchase price of $550 million prior to adjustments.
On August 12, 2004, Pengrowth acquired an additional 34.4 percent interest in Kaybob Notikewin Unit
No. 1 for a purchase price of $20 million, bringing Pengrowths total working interest in this unit
to just below 99 percent.
Goodwill
In accordance with Canadian GAAP, Pengrowth recorded goodwill of $12.2 million upon the Crispin
acquisition in 2005 and $170.6 million upon the Murphy acquisition in 2004. The goodwill value was
determined based on the excess of total consideration paid less the net value assigned to other
identifiable assets and liabilities, including the future income tax liability. Details of the
acquisitions are provided in Note 4 to the financial statements.
Working Capital
Working capital declined by $33.7 million from a working capital deficiency of $78.5 million in
2004 to a working capital deficiency of $112.2 million as at December 31, 2005. Most of the working
capital decline is attributable to an increase in bank indebtedness, accounts payable and accrued
liabilities, distributions payable to unitholders and the current portion of the note payable,
offset by an increase in accounts receivable as at December 31, 2005.
Pengrowth frequently operates with a working capital deficiency as a result of the fact that
distributions related to two production months of operating income are payable to unitholders at
the end of any month, but only one month of production is still receivable. At the end of December,
distributions related to November and December production months were payable on January 15 and
February 15 respectively. Novembers production revenue, received on December 25, is temporarily
applied against Pengrowths revolving credit facility until the distribution payment on January 15.
Financial Resources and Liquidity
At year-end 2005, Pengrowth had a long term debt to debt-plus-equity at book value ratio of 0.2 and
maintained $370 million in committed credit facilities which were reduced by drawings of $35
million and by $17 million in letters of credit outstanding at year-end. In addition, Pengrowth
maintains a $35 million demand operating line of credit. Pengrowth remains well positioned to fund
its 2006 development program and to take advantage of acquisition opportunities as they arise. At
December 31, 2005, Pengrowth had $337 million available to draw from its credit facilities.
Long term debt at December 31, 2005 included fixed rate term debt denominated in U.S. dollars which
translated to Cdn $232.6 million. Due to the appreciation of the Canadian dollar relative to the
U.S. dollar, an unrealized gain of Cdn $57.6 million has been recorded since the U.S. dollar
denominated debt was issued in April of 2003. Long term debt at December 31, 2005 also included
fixed rate term debt denominated in U.K. £50 million which translated to Cdn $100.5 million.
- 14 -
Through a series of hedging transactions, Pengrowth fixed the exchange rate in Canadian
dollars for all future interest payments and repayment at maturity.
Pengrowths long term debt increased by $22.7 million in fiscal 2005 to $368.1 million at December
31, 2005. At the end of 2005 Pengrowth also had a $20 million non-interest bearing note payable to
Emera related to the purchase of the SOEP offshore facilities from Emera on December 31, 2003. The
terms of this note are provided in Note 7 to the financial statements.
During the year Pengrowth incurred $87 million of new debt to fund the acquisition of an additional
interest in Swan Hills and assumed $20 million of bank debt from the acquisition of Crispin.
Pengrowth was able to fund this new debt from its existing credit facilities.
Financial Leverage and Coverage
|
|
|
|
|
|
|
|
|
|
|
|
Twelve months ended |
|
|
Dec 31, 2005 |
|
|
Dec 31, 2004 |
|
|
|
|
Distributable cash to interest expense (times) |
|
|
29 |
|
|
|
|
13 |
|
Long term debt to distributable cash (times) |
|
|
0.6 |
|
|
|
|
0.9 |
|
Long term debt to debt plus book equity (%) |
|
|
20 |
|
|
|
|
19 |
|
|
|
|
|
Commitments and Contractual Obligations
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
($ thousands) |
|
2006 |
|
2007 |
|
2008 |
|
2009 |
|
2010 |
|
Thereafter |
|
Total |
|
Long term debt (1) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
174,450 |
|
|
|
193,639 |
|
|
|
368,089 |
|
Interest payments on long term debt (2) |
|
|
17,298 |
|
|
|
17,298 |
|
|
|
17,298 |
|
|
|
17,298 |
|
|
|
11,564 |
|
|
|
34,546 |
|
|
|
115,302 |
|
Note payable |
|
|
20,000 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
20,000 |
|
|
Operating leases
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Office rent |
|
|
2,030 |
|
|
|
2,070 |
|
|
|
3,096 |
|
|
|
3,055 |
|
|
|
3,036 |
|
|
|
21,529 |
|
|
|
34,816 |
|
Vehicle leases |
|
|
852 |
|
|
|
776 |
|
|
|
604 |
|
|
|
306 |
|
|
|
91 |
|
|
|
|
|
|
|
2,629 |
|
|
|
|
|
2,882 |
|
|
|
2,846 |
|
|
|
3,700 |
|
|
|
3,361 |
|
|
|
3,127 |
|
|
|
21,529 |
|
|
|
37,445 |
|
|
Purchase obligations
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Pipeline transportation |
|
|
43,839 |
|
|
|
38,197 |
|
|
|
34,981 |
|
|
|
29,813 |
|
|
|
11,748 |
|
|
|
53,525 |
|
|
|
212,103 |
|
Capital expenditures |
|
|
33,323 |
|
|
|
7,098 |
|
|
|
294 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
40,715 |
|
CO2 purchases |
|
|
5,119 |
|
|
|
4,357 |
|
|
|
4,198 |
|
|
|
4,232 |
|
|
|
4,267 |
|
|
|
18,728 |
|
|
|
40,901 |
|
|
|
|
|
82,281 |
|
|
|
49,652 |
|
|
|
39,473 |
|
|
|
34,045 |
|
|
|
16,015 |
|
|
|
72,253 |
|
|
|
293,719 |
|
|
Remediation trust fund payments |
|
|
250 |
|
|
|
250 |
|
|
|
250 |
|
|
|
250 |
|
|
|
250 |
|
|
|
11,250 |
|
|
|
12,500 |
|
|
|
|
|
|
122,711 |
|
|
|
70,046 |
|
|
|
60,721 |
|
|
|
54,954 |
|
|
|
205,406 |
|
|
|
333,217 |
|
|
|
847,055 |
|
|
|
|
|
(1) |
|
Foreign dollar denominated debt due as follows U.S.
$150 million, in April 2010, U.S. $50
million, in April 2013 and £50 million in December 2015, translated at the Dec 31, 2005 exchange
rate. |
|
(2) |
|
Interest payments on foreign denominated debt, calculated based on Dec 31, 2005 foreign
exchange rate. |
Related Party Transactions
Details of related party transactions incurred in 2005 and 2004 are provided in Note 15 to the
financial statements. These transactions include the management fees paid to the Manager. The
Manager is controlled by James S. Kinnear, the Chairman, President and Chief Executive Officer of
the Corporation. The management fees paid to the Manager are pursuant to a management agreement
which has been approved by the trust unitholders. Mr. Kinnear does not receive any salary or bonus
in his capacity as a director and officer of the Corporation and has not received any new trust
unit options or rights since November 2002.
Related party transactions in 2005 also include $0.7 million (2004 $0.8 million) paid to a law
firm controlled by the Vice President and Corporate Secretary of Pengrowth Corporation, Charles V.
Selby. These fees are paid in respect of legal and advisory services provided by the Vice President
- 15 -
and Corporate Secretary. Mr. Selby does not receive any salary or bonus in
his capacity as Vice President and Corporate Secretary of the Corporation. Mr. Selby has from time
to time been granted trust unit rights and options.
Ceiling Test
Under Canadian GAAP, a ceiling test is applied to the carrying value of the property, plant and
equipment and other assets. The carrying value is assessed to be recoverable when the sum of the
undiscounted cash flows expected from the production of proved reserves, the lower of cost and
market of unproved properties and the cost of major development projects exceeds the carrying
value. When the carrying value is not assessed to be recoverable, an impairment loss is recognized
to the extent that the carrying value of assets exceeds the sum of the discounted cash flows
expected from the production of proved and probable reserves, the lower of cost and market of
unproved properties and the cost of major development projects. The cash flows are estimated using
expected future product prices and costs and are discounted using a risk-free interest rate. There
was a significant surplus in the ceiling test at year-end 2005.
Asset Retirement Obligations
The total future ARO were estimated by management based on estimated costs to remediate, reclaim
and abandon wells and facilities based on Pengrowths working interest and the estimated timing of
the costs to be incurred in future periods. Pengrowth has estimated the net present value of its
total ARO to be $185 million as at December 31, 2005 (2004 $172 million), based on a total
escalated future liability of $1,041 million (2004 $551 million). The significant change in the
estimated future liability is due to increasing regulatory requirements, changing the assumptions
of economic life to agree with GLJ Petroleum Consultants Ltd. (GLJ) economic life and increasing
the future inflation rate. These costs are expected to be incurred over 50 years with the majority
of the costs incurred between 2032 and 2054. Pengrowths credit adjusted risk free rate of eight
percent (2004 eight percent) and an inflation rate of 2.0 percent (2004 1.5 percent) were used
to calculate the net present value of the ARO.
Remediation Trust Funds & Remediation and Abandonment Expenses
During 2005, Pengrowth contributed $1.3 million into trust funds established to fund certain
abandonment and reclamation costs associated with Judy Creek and SOEP. The balance in these
remediation trust funds was $8.3 million at December 31, 2005.
Pengrowth takes a proactive approach to managing its well abandonment and site restoration
obligations. There is an on-going program to abandon wells and reclaim well and facility sites. In
2005, Pengrowth spent $7.4 million on abandonment and reclamation (2004 $4.4 million). Pengrowth
expects to spend approximately $11 million per year, prior to inflation, over the next ten years on
remediation and abandonment.
Distributable Cash, Distributions and Taxability of Distributions
Pengrowth generated $619.7 million ($3.94 per average trust unit outstanding) of distributable cash
from 2005 operations, compared to $401.2 million ($3.01 per unit) in 2004. Distributions paid or
declared were $446.0 million for 2005 (2004 $363.1 million) and as a percentage of cash generated
from operations (payout ratio) represent approximately 72 percent (2004 90 percent).
The Board of Directors may change the amount withheld in the future, depending on a number of
factors, including future commodity prices, capital expenditure requirements, and the availability
of debt and equity capital. Pursuant to the Royalty Indenture, the Board of Directors can establish
a reserve for certain items including up to 20 percent of Gross Revenue to fund future capital
expenditures or for the payment of royalty income in any future period.
The following discussion relates to the taxation of Canadian unitholders only. For detailed tax
information relating to non-residents, please refer to our website
www.pengrowth.com. Cash
distributions are comprised of a return of capital portion, which is tax deferred, and return on
capital
- 16 -
portion which is taxable income. The return of capital portion reduces the cost base of a
unitholders trust units for purposes of calculating a capital gain or loss upon ultimate
disposition.
Cash distributions are paid to unitholders on the 15th day of the second month following
the month of production. Cash distributions paid in the 2005 calendar year totaled $2.78 per trust
unit and are 80 percent return on capital (taxable) or $2.22 per trust unit and 20 percent return
of capital (tax deferred) or $0.56 per trust unit. Changes in the estimated taxable and deferred
portion of the cash distributions are announced quarterly.
2005 Distribution Taxability Information
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Taxable |
|
Tax deferred |
|
|
|
|
Amount |
|
Amount |
|
Total |
Payment Date |
|
(Other Income) |
|
(Return of Capital) |
|
Distribution |
|
January 15, 2005
|
|
$ |
0.1840 |
|
|
$ |
0.0460 |
|
|
$ |
0.2300 |
|
February 15, 2005
|
|
$ |
0.1840 |
|
|
$ |
0.0460 |
|
|
$ |
0.2300 |
|
March 15, 2005
|
|
$ |
0.1840 |
|
|
$ |
0.0460 |
|
|
$ |
0.2300 |
|
April 15, 2005
|
|
$ |
0.1840 |
|
|
$ |
0.0460 |
|
|
$ |
0.2300 |
|
May 15, 2005
|
|
$ |
0.1840 |
|
|
$ |
0.0460 |
|
|
$ |
0.2300 |
|
June 15, 2005
|
|
$ |
0.1840 |
|
|
$ |
0.0460 |
|
|
$ |
0.2300 |
|
July 15, 2005
|
|
$ |
0.1840 |
|
|
$ |
0.0460 |
|
|
$ |
0.2300 |
|
August 15, 2005
|
|
$ |
0.1840 |
|
|
$ |
0.0460 |
|
|
$ |
0.2300 |
|
September 15, 2005
|
|
$ |
0.1840 |
|
|
$ |
0.0460 |
|
|
$ |
0.2300 |
|
October 15, 2005
|
|
$ |
0.1840 |
|
|
$ |
0.0460 |
|
|
$ |
0.2300 |
|
November 15, 2005
|
|
$ |
0.1840 |
|
|
$ |
0.0460 |
|
|
$ |
0.2300 |
|
December 15, 2005
|
|
$ |
0.2000 |
|
|
$ |
0.0500 |
|
|
$ |
0.2500 |
|
|
|
|
$ |
2.2240 |
|
|
$ |
0.5560 |
|
|
$ |
2.7800 |
|
|
There is no standardized measure of distributable cash and therefore distributable cash, as
reported by Pengrowth, may not be comparable to similar measures presented by other trusts. In
conjunction with the change to Pengrowths withholding practice, distributable cash as presented
below may not be comparable to previous disclosures. The following table provides a reconciliation
of distributable cash.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
($ thousands, except per unit amounts) |
|
Three months ended |
|
|
Twelve months ended |
|
|
Dec 31, 2005 |
|
Sept 30, 2005 |
|
Dec 31, 2004 |
|
|
Dec 31, 2005 |
|
Dec 31, 2004 |
|
|
|
|
Cash generated from operations |
|
|
196,588 |
|
|
|
158,976 |
|
|
|
93,287 |
|
|
|
|
618,070 |
|
|
|
404,167 |
|
Change in non-cash operating working capital |
|
|
(7,993 |
) |
|
|
(789 |
) |
|
|
8,576 |
|
|
|
|
(9,833 |
) |
|
|
(1,173 |
) |
Change in deferred injectants |
|
|
7,411 |
|
|
|
892 |
|
|
|
3,228 |
|
|
|
|
10,265 |
|
|
|
746 |
|
Change in remediation trust funds |
|
|
784 |
|
|
|
(272 |
) |
|
|
32 |
|
|
|
|
(20 |
) |
|
|
(917 |
) |
Change in deferred charges |
|
|
(793 |
) |
|
|
2,818 |
|
|
|
(473 |
) |
|
|
|
1,235 |
|
|
|
(1,893 |
) |
Other |
|
|
(118 |
) |
|
|
384 |
|
|
|
308 |
|
|
|
|
22 |
|
|
|
248 |
|
|
|
|
|
Distributable cash |
|
|
195,879 |
|
|
|
162,009 |
|
|
|
104,958 |
|
|
|
|
619,739 |
|
|
|
401,178 |
|
|
|
|
|
Allocation of Distributable cash |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash withheld |
|
|
76,021 |
|
|
|
52,156 |
|
|
|
8,492 |
|
|
|
|
173,762 |
|
|
|
38,117 |
|
Distributions paid or declared |
|
|
119,858 |
|
|
|
109,853 |
|
|
|
96,466 |
|
|
|
|
445,977 |
|
|
|
363,061 |
|
|
|
|
|
Distributable cash |
|
|
195,879 |
|
|
|
162,009 |
|
|
|
104,958 |
|
|
|
|
619,739 |
|
|
|
401,178 |
|
|
|
|
|
Distributable cash per unit |
|
|
1.23 |
|
|
|
1.02 |
|
|
|
0.77 |
|
|
|
|
3.94 |
|
|
|
3.01 |
|
Distributions paid or declared per unit |
|
|
0.75 |
|
|
|
0.69 |
|
|
|
0.69 |
|
|
|
|
2.82 |
|
|
|
2.63 |
|
Payout ratio |
|
|
61 |
% |
|
|
69 |
% |
|
|
103 |
% |
|
|
|
72 |
% |
|
|
90 |
% |
|
|
|
|
At this time, Pengrowth anticipates that approximately 75 to 80 percent of 2006 distributions
will be taxable to Canadian residents; this estimate is subject to change depending on a number of
factors including, but not limited to, the level of commodity prices, acquisitions, dispositions,
and new equity offerings.
- 17 -
Trust Unit Information
Pengrowth had 159,864,083 trust units outstanding at December 31, 2005, compared to 152,972,555
trust units at December 31, 2004. The weighted average number of trust units during the year was
157,127,181 (2004 133,935,485).
On April 29, 2005, Pengrowth issued 4.2 million trust units to
complete the Crispin acquisition (see Note 4 to the financial statements for further detail).
Class A and Class B Trust Unit Structure
Maintaining its status as a mutual fund trust under Income Tax Act (Canada) is of fundamental
importance to the Trust. Generally speaking, in addition to several other requirements, in order
for a trust such as Pengrowth to be a mutual fund trust under the Income Tax Act it must satisfy
one of two tests. The first test is a benefit test that requires that the trust must not be
established
or maintained primarily for the benefit of non-residents of Canada (which is generally interpreted
to mean that the majority of unitholders must be residents of Canada) (the Benefit Test). The
second test is a property test that requires that, at all times after February 21, 1990, all or
substantially all of the trusts property consist of property other than taxable Canadian property
(the Property Exception). Pengrowth is aware that many other oil and gas income trusts have
significantly greater than 50 percent non-resident ownership and are relying on the Property
Exception to maintain their mutual fund trust status.
For reasons that may be unique to the Trust, it was not clear that the Trust could rely upon the
Property Exception, as a sale and leaseback transaction entered into with the Corporation in 1998
regarding certain facilities at Judy Creek may have resulted in the Trusts taxable Canadian
property exceeding the threshold required by the Property Exception. On November 26, 2004, the
Trust received a customary form of comfort letter from the Department of Finance (Canada) stating
that the Department of Finance will recommend to the Minister of Finance that an amendment be made
to the Property Exception that would clarify the Trusts ability to rely upon the Property
Exception.
As a result of this uncertainty, the Trust adopted the Class A and Class B trust unit structure,
which requires that the Class A trust units constitute not more than 49.75 percent of the
outstanding trust units of the Trust and that all of the Class B trust units be held by residents
of Canada, to ensure that the Trust would satisfy the Benefit Test. The Trust received an advance
tax ruling from the Canada Revenue Agency on July 26, 2004 and an amended ruling on December 1,
2004 that confirmed that the Trust would continue to be a mutual fund trust if the Class A trust
units constituted less than the ownership threshold of 49.75 percent by June 1, 2005 and the Trust
was a mutual fund trust prior to that date.
As at December 31, 2004, the Class A trust units represented 50.2 percent of the outstanding trust
units of the Trust. As a result of a public offering of Class B trust units in December of 2004,
the issuance of a majority of Class B trust units in connection with Pengrowths acquisition of
Crispin in 2005 and the issuance of Class B trust units in accordance with the Distribution
Reinvestment Program and other Pengrowth incentive plans, the ownership threshold of 49.75 percent
for the Class A trust units was achieved prior to June 1, 2005 in accordance with the advance
income tax ruling. On December 6, 2004, the Minister of Finance indicated that further discussions
and consultations concerning the appropriate tax treatment of non-residents owning resource
properties through mutual fund trusts would take place.
At present, Pengrowth is maintaining the Class A and Class B trust unit structure in compliance
with the advance income tax ruling. The Board of Directors considers it prudent at this time to
continue the Class A and Class B trust unit structure.
The Board of Directors may determine, based upon market circumstances as they exist at that time or
other factors, that it is in the best interests of all unitholders to: (a) remove the requirement
to comply with the ownership threshold that restricts the Class A trust units to 49.75 percent of
the outstanding
- 18 -
trust units; (b) remove the residency restrictions pertaining to the holding of Class B trust
units; (c) permit a free conversion of Class B trust units to Class A trust units; (d) permit the
consolidation of the trust unit capital of the Trust; (e) allow a controlled conversion of Class B
trust units to Class A trust units over time to preserve an orderly market; (f) maintain the Class
A
and Class B trust unit structure until market circumstances become more favorable to both classes
of unitholders; or (g) take such other action as the Board of Directors may consider appropriate.
Subsequent Event
On January 12, 2006, Pengrowth announced certain transactions with Monterey under which Pengrowth
has sold oil and gas properties for $22 million of cash and eight million shares in Monterey. As at
February 27, 2006 Pengrowth holds approximately 34 per percent of the common shares of Monterey.
Outlook
Pengrowth will seek to provide attractive long term returns for unitholders. Our business
objectives include:
|
|
|
Operating our properties in a safe and prudent manner in order to protect our
employees, the public, the environment and our investment; |
|
|
|
|
Maintaining a balanced portfolio of oil and gas properties in our key focus areas; |
|
|
|
|
Growing production and reserves through accretive acquisitions and low risk
development drilling; |
|
|
|
|
Increasing our undeveloped land position; |
|
|
|
|
Continuing to optimize costs and maximize netbacks; |
|
|
|
|
The selective disposition of oil and gas properties that do not meet our return
objectives; |
|
|
|
|
Continuing to maintain a stable distribution policy while withholding a portion of
distributable cash to fund future capital programs. |
At this time, Pengrowth is forecasting average 2006 production of 54,000 to 56,000 boe per day from
our existing properties. This estimate incorporates anticipated production additions from our 2006
development program, offset by the impact of divestitures of approximately 1,300 boe per day and
expected production declines from normal operations. The above estimate excludes the potential
impact of any future acquisitions or divestitures.
Total operating costs for 2006 are expected to increase to approximately $220 million. This
increase is due to the addition of a full-year of operating expenses associated with Pengrowths
increased working interest in Swan Hills and the acquisition of Crispin. Assuming Pengrowths
average production for 2006 as forecast above, Pengrowth currently estimates 2006 per boe operating
costs of approximately $11.00 per boe.
Budgeted capital expenditures for 2006 total approximately $236 million. Approximately half of the
budgeted 2006 expenditures is for a 280 gross wells (132 net wells) drilling program, 27 percent
are for facilities and maintenance, nine percent are for land and seismic acquisitions, and eight
percent for
recompletions, workovers, CO2 pilot and other. Pengrowths 2006 capital program
targets the
furtherance of Pengrowths short, medium and long term objectives, reflecting Pengrowths
focus on pursuing a balanced approach to the development of its key assets. While the most
significant portion of Pengrowths 2006 capital program will involve the continued development and
maintenance of existing production and properties, a key element of the 2006 program will be
further development of mid and longer term plays or projects in coalbed methane, heavy oil and
enhanced oil recovery. Pengrowth anticipates funding its 2006 capital expenditures through a
combination of undistributed cash from operations, unused credit facilities and any proceeds from
property dispositions.
- 19 -
CONFERENCE CALL
Pengrowth will hold a conference call beginning at 11:00 A.M. Eastern Time (9:00 A.M. Mountain
Time) on Tuesday, February 28, 2006 during which Management will review Pengrowths 2005 fourth
quarter and full year financial and operating results and respond to inquiries from the investment
community. To participate callers may dial (866) 540-8136 or Toronto local (416) 340-8010. To
ensure timely participation in the teleconference callers are encouraged to dial in 10-15 minutes
prior to commencement of the call to register. A live audio webcast will be accessible through the
Webcast and Multimedia Centre section of Pengrowths website at
www.pengrowth.com. The webcast will
be archived through February 28, 2007. A telephone replay will be available thru to midnight
Eastern Time on Tuesday, March 7, 2006 by dialing (800) 408-3053 or Toronto local ( 416)
695-5800 and entering passcode number 3176117 followed by the pound key.
PENGROWTH
CORPORATION
James S.
Kinnear, President
For
further information about Pengrowth, please visit our website www.pengrowth.com or contact:
Investor Relations, E-mail: investorrelations@pengrowth.com
Telephone: (403) 233-0224 Toll Free:
1-800-223-4122 Facsimile: (403) 294-0051
Investor Relations, Toronto, Toll Free: 1-888-744-1111
Facsimile: (416) 362-8191
- 20 -
SUPPLEMENTAL INFORMATION
Reserves
Based on an independent engineering evaluation conducted by GLJ effective December 31, 2005 and
prepared in accordance with NI 51-101, Pengrowth had proved plus probable reserves of 219.4 mmboe.
This represents 100 percent replacement of proved plus probable reserves through the acquisition of
16.7 mmboe and additions of 8.6 mmboe resulting from drilling activity, improved recoveries and
technical revisions. Additions were offset by 21.7 mmboe of production and dispositions amounting
to 2.8 mmboe.
Proved producing reserves are estimated at 143.7 mmboe; these reserves represent 82 percent of the
total proved reserves of 175.6 mmboe and 66 percent of proved plus probable reserves. The total
proved reserves account for 80 percent of proved plus probable reserves. These percentages are
virtually unchanged from 2004.
Using a ten percent discount factor and GLJ January 1, 2006 pricing, the proved producing reserves
account for 75 percent of the proved plus probable value while the total proved reserves account
for 85 percent of the proved plus probable value. Using a 6:1 boe conversion rate for natural gas,
approximately 45 percent of Pengrowths reserves are light/medium crude oil, 39 percent are natural
gas, 9 percent are NGLs and 7 percent are heavy oil.
Pengrowth is a geographically diversified energy trust with properties located across Canada in the
provinces of British Columbia, Alberta, Saskatchewan and offshore Nova Scotia. On a proved plus
probable reserve basis, the Alberta, Saskatchewan, British Columbia and offshore Nova Scotia
holdings account for 71 percent, 14 percent, 10 percent, and 5 percent, respectively of reserves
reported by GLJ.
Reserves Summary 2005
Company Interest (Company Gross Interest* plus Royalty Interest Reserves)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Light and |
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil |
|
Oil |
|
|
Medium Crude |
|
Heavy |
|
|
|
|
|
Natural |
|
Equivalent |
|
Equivalent |
|
|
Oil |
|
Oil |
|
NGLs |
|
Gas |
|
2005 |
|
2004 |
|
|
mbbl |
|
mbbl |
|
mbbl |
|
bcf |
|
mboe |
|
mboe |
|
Proved Producing |
|
|
58,219 |
|
|
|
10,924 |
|
|
|
13,566 |
|
|
|
366.2 |
|
|
|
143,741 |
|
|
|
142,353 |
|
Proved Developed |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Non Producing |
|
|
365 |
|
|
|
62 |
|
|
|
637 |
|
|
|
24.3 |
|
|
|
5,113 |
|
|
|
4,825 |
|
Proved Undeveloped |
|
|
18,768 |
|
|
|
1,699 |
|
|
|
1,139 |
|
|
|
30.8 |
|
|
|
26,745 |
|
|
|
28,324 |
|
|
Total Proved |
|
|
77,351 |
|
|
|
12,684 |
|
|
|
15,342 |
|
|
|
421.3 |
|
|
|
175,599 |
|
|
|
175,502 |
|
|
Proved plus Probable |
|
|
98,684 |
|
|
|
15,790 |
|
|
|
18,985 |
|
|
|
515.6 |
|
|
|
219,396 |
|
|
|
218,613 |
|
|
Net Interest (Company Net Interest* which is the Company Interest Reserves less Royalties
Payable)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Light and |
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil |
|
Oil |
|
|
Medium Crude |
|
Heavy |
|
|
|
|
|
|
|
|
|
Equivalent |
|
Equivalent |
|
|
Oil |
|
Oil |
|
NGLs |
|
Natural Gas |
|
2005 |
|
2004 |
|
|
mbbl |
|
mbbl |
|
mbbl |
|
bcf |
|
mboe |
|
mboe |
|
Proved Producing |
|
|
49,693 |
|
|
|
9,621 |
|
|
|
9,334 |
|
|
|
289.4 |
|
|
|
116,877 |
|
|
|
116,798 |
|
Proved Developed |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Non Producing |
|
|
308 |
|
|
|
57 |
|
|
|
460 |
|
|
|
18.4 |
|
|
|
3,893 |
|
|
|
3,757 |
|
Proved Undeveloped |
|
|
15,991 |
|
|
|
1,420 |
|
|
|
805 |
|
|
|
23.9 |
|
|
|
22,200 |
|
|
|
23,616 |
|
|
Total Proved |
|
|
65,992 |
|
|
|
11,098 |
|
|
|
10,600 |
|
|
|
331.7 |
|
|
|
142,970 |
|
|
|
144,171 |
|
|
Proved plus Probable |
|
|
83,929 |
|
|
|
13,714 |
|
|
|
13,218 |
|
|
|
404.3 |
|
|
|
178,246 |
|
|
|
179,298 |
|
|
|
|
|
(*) means Company Gross Interest and Company Net Interest as defined in the Canadian Oil and
Gas Evaluation Handbook (COGEH), Volume 2, Section 5.2,
November 1,2005. |
- 21 -
Reserve Reconciliation
Pengrowth added 25.3 mmboe of proved plus probable reserves during 2005, replacing
production by 117 percent. The acquisition of Crispin and additional interest in Swan Hills
accounted for approximately 66 percent of the reserve additions. The balance of additions resulted
mainly from drilling and improved recovery. Most significant were drilling extensions at West
Pembina, infill drilling and increased CO2 miscible flood recovery in the
Weyburn Unit. Disposition of various non-core assets resulted in a decrease of 2.8 mmboe.
Reserves
Reconciliation 2005
Company Interest Volumes (before deduction of Royalty Burdens Payable)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Light and |
|
|
|
|
|
|
|
|
|
|
|
|
Medium |
|
Heavy |
|
|
|
|
|
Natural |
|
Oil |
|
|
Crude Oil |
|
Oil |
|
NGLs |
|
Gas |
|
Equivalent |
|
|
mbbl |
|
mbbl |
|
mbbl |
|
bcf |
|
mboe |
|
Total Proved |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
December 31, 2004 |
|
|
74,175 |
|
|
|
14,622 |
|
|
|
15,488 |
|
|
|
427.3 |
|
|
|
175,502 |
|
Exploration & Development |
|
|
0 |
|
|
|
81 |
|
|
|
715 |
|
|
|
19.8 |
|
|
|
4,096 |
|
Improved Recovery |
|
|
2,328 |
|
|
|
134 |
|
|
|
448 |
|
|
|
1.7 |
|
|
|
3,193 |
|
Revisions |
|
|
709 |
|
|
|
(101 |
) |
|
|
642 |
|
|
|
16.9 |
|
|
|
4,072 |
|
Acquisitions |
|
|
9,106 |
|
|
|
0 |
|
|
|
376 |
|
|
|
19.3 |
|
|
|
12,699 |
|
Dispositions |
|
|
(1,376 |
) |
|
|
0 |
|
|
|
(103 |
) |
|
|
(4.9 |
) |
|
|
(2,296 |
) |
Production |
|
|
(7,591 |
) |
|
|
(2,052 |
) |
|
|
(2,224 |
) |
|
|
(58.8 |
) |
|
|
(21,667 |
) |
|
December 31, 2005 |
|
|
77,351 |
|
|
|
12,684 |
|
|
|
15,342 |
|
|
|
421.3 |
|
|
|
175,599 |
|
|
Proved plus Probable |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
December 31, 2004 |
|
|
94,066 |
|
|
|
18,245 |
|
|
|
19,395 |
|
|
|
521.4 |
|
|
|
218,613 |
|
Exploration & Development |
|
|
0 |
|
|
|
92 |
|
|
|
823 |
|
|
|
23.9 |
|
|
|
4,898 |
|
Improved Recovery |
|
|
2,599 |
|
|
|
149 |
|
|
|
277 |
|
|
|
1.9 |
|
|
|
3,342 |
|
Revisions |
|
|
(435 |
) |
|
|
(644 |
) |
|
|
343 |
|
|
|
6.5 |
|
|
|
344 |
|
Acquisitions |
|
|
11,702 |
|
|
|
0 |
|
|
|
478 |
|
|
|
27.1 |
|
|
|
16,697 |
|
Dispositions |
|
|
(1,657 |
) |
|
|
0 |
|
|
|
(107 |
) |
|
|
(6.4 |
) |
|
|
(2,831 |
) |
Production |
|
|
(7,591 |
) |
|
|
(2,052 |
) |
|
|
(2,224 |
) |
|
|
(58.8 |
) |
|
|
(21,667 |
) |
|
December 31, 2005 |
|
|
98,684 |
|
|
|
15,790 |
|
|
|
18,985 |
|
|
|
515.6 |
|
|
|
219,396 |
|
|
- 22 -
Reserves Reconciliation 2005
Net After Royalty Volumes
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Light and |
|
|
|
|
|
|
|
|
|
|
|
|
Medium |
|
Heavy |
|
|
|
|
|
Natural |
|
Oil |
|
|
Crude Oil |
|
Oil |
|
NGLs |
|
Gas |
|
Equivalent |
|
|
mbbl |
|
mbbl |
|
mbbl |
|
bcf |
|
mboe |
|
Total Proved |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
December 31, 2004 |
|
|
63,572 |
|
|
|
12,733 |
|
|
|
10,974 |
|
|
|
341.4 |
|
|
|
144,171 |
|
Exploration & Development |
|
|
|
|
|
|
71 |
|
|
|
494 |
|
|
|
15.6 |
|
|
|
3,163 |
|
Improved Recovery |
|
|
1,986 |
|
|
|
117 |
|
|
|
309 |
|
|
|
1.3 |
|
|
|
2,635 |
|
Revisions |
|
|
(354 |
) |
|
|
59 |
|
|
|
591 |
|
|
|
10.6 |
|
|
|
2,074 |
|
Acquisitions |
|
|
7,769 |
|
|
|
|
|
|
|
260 |
|
|
|
15.2 |
|
|
|
10,561 |
|
Dispositions |
|
|
(1,174 |
) |
|
|
|
|
|
|
(71 |
) |
|
|
(3.9 |
) |
|
|
(1,888 |
) |
Production |
|
|
(5,807 |
) |
|
|
(1,882 |
) |
|
|
(1,957 |
) |
|
|
(48.6 |
) |
|
|
(17,746 |
) |
|
December 31, 2005 |
|
|
65,992 |
|
|
|
11,098 |
|
|
|
10,600 |
|
|
|
331.7 |
|
|
|
142,970 |
|
|
Proved plus Probable |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
December 31, 2004 |
|
|
80,443 |
|
|
|
15,798 |
|
|
|
13,819 |
|
|
|
415.4 |
|
|
|
179,298 |
|
Exploration & Development |
|
|
|
|
|
|
80 |
|
|
|
573 |
|
|
|
18.7 |
|
|
|
3,776 |
|
Improved Recovery |
|
|
2,211 |
|
|
|
129 |
|
|
|
193 |
|
|
|
1.5 |
|
|
|
2,781 |
|
Revisions |
|
|
(1,461 |
) |
|
|
(412 |
) |
|
|
332 |
|
|
|
1.0 |
|
|
|
(1,370 |
) |
Acquisitions |
|
|
9,952 |
|
|
|
|
|
|
|
333 |
|
|
|
21.3 |
|
|
|
13,827 |
|
Dispositions |
|
|
(1,409 |
) |
|
|
|
|
|
|
(75 |
) |
|
|
(5.0 |
) |
|
|
(2,320 |
) |
Production |
|
|
(5,807 |
) |
|
|
(1,882 |
) |
|
|
(1,957 |
) |
|
|
(48.6 |
) |
|
|
(17,746 |
) |
|
December 31, 2005 |
|
|
83,929 |
|
|
|
13,714 |
|
|
|
13,218 |
|
|
|
404.3 |
|
|
|
178,246 |
|
|
Net Present Value (NPV) Summary 2005
At GLJ January 1, 2006 escalated prices and costs*
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Discounted at |
|
Discounted at |
|
Discounted at |
|
Discounted at |
($ thousands) |
|
Undiscounted |
|
8% |
|
10% |
|
12% |
|
15% |
|
Proved Producing |
|
|
3,676,741 |
|
|
|
2,563,707 |
|
|
|
2,401,037 |
|
|
|
2,262,789 |
|
|
|
2,089,851 |
|
Proved Developed Non |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Producing |
|
|
148,744 |
|
|
|
94,965 |
|
|
|
87,578 |
|
|
|
81,363 |
|
|
|
73,662 |
|
Proved Undeveloped |
|
|
559,904 |
|
|
|
269,672 |
|
|
|
229,572 |
|
|
|
196,476 |
|
|
|
156,685 |
|
|
Total Proved |
|
|
4,385,388 |
|
|
|
2,928,344 |
|
|
|
2,718,187 |
|
|
|
2,540,628 |
|
|
|
2,320,198 |
|
|
Proved plus Probable |
|
|
5,693,559 |
|
|
|
3,490,944 |
|
|
|
3,204,481 |
|
|
|
2,967,685 |
|
|
|
2,679,919 |
|
|
|
|
|
* Prior to provision for income taxes, interest, debt service charges and general and administrative
expenses. |
Constant Prices at December 31, 2005*
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Discounted at |
|
Discounted at |
|
Discounted at |
|
Discounted at |
($ thousands) |
|
Undiscounted |
|
8% |
|
10% |
|
12% |
|
15% |
|
Proved Producing |
|
|
4,745,097 |
|
|
|
3,127,174 |
|
|
|
2,895,985 |
|
|
|
2,701,198 |
|
|
|
2,460,128 |
|
Proved Developed Non |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Producing |
|
|
183,180 |
|
|
|
115,627 |
|
|
|
105,969 |
|
|
|
97,813 |
|
|
|
87,701 |
|
Proved Undeveloped |
|
|
770,444 |
|
|
|
396,166 |
|
|
|
342,540 |
|
|
|
297,883 |
|
|
|
243,694 |
|
|
Total Proved |
|
|
5,698,721 |
|
|
|
3,638,966 |
|
|
|
3,344,494 |
|
|
|
3,096,895 |
|
|
|
2,791,524 |
|
|
Proved plus Probable |
|
|
7,286,322 |
|
|
|
4,342,199 |
|
|
|
3,953,173 |
|
|
|
3,631,474 |
|
|
|
3,241,128 |
|
|
|
|
|
* Prior to provision for income taxes, interest, debt service charges and general and administrative
expenses. |
- 23 -
GLJs January 1, 2006 price forecast is shown below:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Edmonton Light |
|
Natural Gas |
|
|
WTI Crude Oil |
|
Crude Oil |
|
at AECO |
Year |
|
(U.S.$/bbl) |
|
(Cdn$/bbl) |
|
(Cdn$/mmbtu) |
|
2006 |
|
|
57.00 |
|
|
|
66.25 |
|
|
|
10.60 |
|
2007 |
|
|
55.00 |
|
|
|
64.00 |
|
|
|
9.25 |
|
2008 |
|
|
51.00 |
|
|
|
59.25 |
|
|
|
8.00 |
|
2009 |
|
|
48.00 |
|
|
|
55.75 |
|
|
|
7.50 |
|
2010 |
|
|
46.50 |
|
|
|
54.00 |
|
|
|
7.20 |
|
2011 |
|
|
45.00 |
|
|
|
52.25 |
|
|
|
6.90 |
|
2012 |
|
|
45.00 |
|
|
|
52.25 |
|
|
|
6.90 |
|
2013 |
|
|
46.00 |
|
|
|
53.25 |
|
|
|
7.05 |
|
2014 |
|
|
46.75 |
|
|
|
54.25 |
|
|
|
7.20 |
|
2015 |
|
|
47.75 |
|
|
|
55.50 |
|
|
|
7.40 |
|
2016 |
|
|
48.75 |
|
|
|
56.50 |
|
|
|
7.55 |
|
Escalate thereafter |
|
2.0% per year |
|
2.0% per year |
|
2.0% per year |
Constant Prices at December 31, 2005
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Edmonton Light |
|
Natural Gas |
|
|
WTI Crude Oil |
|
Crude Oil |
|
at AECO |
Year |
|
(U.S.$/bbl) |
|
(Cdn$/bbl) |
|
(Cdn$/mmbtu) |
|
2006 |
|
|
61.04 |
|
|
|
68.27 |
|
|
|
9.71 |
|
Net
Asset Value at December 31, 2005
In the following table, Pengrowths net asset value (NAV) is measured with reference to the
present value of future net cash flows from reserves, as estimated by GLJ. The calculation is shown
using both the GLJ escalated price forecast, and constant (yearend 2005) prices.
|
|
|
|
|
|
|
|
|
|
|
GLJ 2006-01 |
|
Constant |
($ thousands, except per unit amount) |
|
Price Forecast |
|
Price Forecast |
|
Value of Proved plus Probable Reserves
discounted at 10% |
|
|
3,204,481 |
|
|
|
3,953,173 |
|
Undeveloped lands (1) |
|
|
145,344 |
|
|
|
145,344 |
|
Working Capital (2) |
|
|
(28,222 |
) |
|
|
(28,222 |
) |
Remediation trust fund |
|
|
8,329 |
|
|
|
8,329 |
|
Long term debt and Note Payable |
|
|
(381,026 |
) |
|
|
(381,026 |
) |
Asset Retirement Obligation (3) |
|
|
(110,243 |
) |
|
|
(118,243 |
) |
|
Net Asset Value |
|
$ |
2,838,663 |
|
|
$ |
3,579,355 |
|
Units Outstanding (000s) |
|
|
159,864 |
|
|
|
159,864 |
|
|
Net Asset value per Unit |
|
$ |
17.76 |
|
|
$ |
22.39 |
|
|
|
|
|
(1) |
|
Pengrowths internal estimate |
|
(2) |
|
Working capital excludes distributions payable |
|
(3) |
|
The ARO is based on the same methodology used to calculate the ARO on Pengrowths year end financial statements, except that the future expected ARO costs were inflated at 2 percent and discounted at 10 percent and well abandonment costs included in the GLJ report were deducted |
Reserve
Life Index
Pengrowths proved reserve life index (RLI) remained the same at 8.6 years and the proved
plus probable RLI of 10.5 years can be compared to last years value of 10.4 years.
|
|
|
|
|
|
|
|
|
|
|
|
|
Reserve Life Index |
|
2005 |
|
2004 |
|
2003 |
|
Total Proved |
|
|
8.6 |
|
|
|
8.6 |
|
|
|
8.9 |
|
Proved plus Probable |
|
|
10.5 |
|
|
|
10.4 |
|
|
|
10.6 |
|
- 24 -
FINDING, DEVELOPMENT AND ACQUISITION COSTS
Finding
and Development Costs
During 2005, Pengrowth spent $175.7 million on development and optimization activities, which added
11.4 mmboe of proved and 8.6 mmboe of proved plus probable reserves including revisions. The
largest additions were from infill drilling and enhanced recovery development in the Weyburn
Unit CO2 miscible flood project and drilling extensions for gas in West
Pembina.
In total, Pengrowth participated in drilling 286 gross wells (94 net wells) during 2005 with a 99
percent success rate.
Pengrowth continues to develop shallow gas in southeast Alberta, drilling 44 infill wells at
Princess and participating in 108 wells at Tilley. Pengrowth was also active in drilling for gas in
northern Alberta, participating in 35 infill wells in the Dunvegan Gas Unit.
At Judy Creek, ongoing development of the hydrocarbon miscible flood project continue to be a focus
for Pengrowth. Infill drilling and miscible flood pattern development and optimization contribute
to arresting declines and improving recovery.
During 2005, significant capital expenditures were made at SOEP to further exploit gas reserves.
Two successful wells, South Venture 3 and Venture 7, were drilled and brought on stream. The
massive compression project at Thebaud is progressing with completion anticipated in late 2006 or
early 2007.
In the southeast Saskatchewan Weyburn Unit, expansion and optimization of the partner operated
CO2 miscible flood enhanced oil recovery project progresses as planned.
Forty-seven infill wells, both new and re-entry, were drilled and facilities are being expanded to
accommodate higher CO2 injection rates.
Acquisitions
and Divestitures
During 2005 Pengrowth was again active in making strategic acquisitions. Pengrowth spent
$175.1 million adding 10.4 mmboe of proved and 13.9 mmboe of proved plus probable reserves, net of
some minor dispositions of scattered non-core properties.
In February 2005, Pengrowth acquired an additional 11.9 percent working interest in Swan Hills,
increasing Pengrowths total working interest in the unit to 22.3 percent. The purchase price was
$87 million. The acquisition added 11.0 mmboe of proved plus probable reserves.
In April of 2005, Pengrowth completed the acquisition of Crispin adding approximately 1,900 boe per
day of production and 5.2 mmboe of proved plus probable reserves. The acquisition was funded
through the issuance of Class A and Class B trust units valued at approximately $88 million.
Pengrowth also assumed debt of approximately $20 million as part of the acquisition.
In the latter half of 2005, Pengrowth concluded a disposition program selling non-core oil and
natural gas properties with associated production of approximately 600 boe per day and 2.6 mmboe of
proved plus probable reserves. Total disposition proceeds were $37.6 million.
Future
Development Capital
If a company chooses to disclose finding and development costs, NI 51-101 requires that the
calculation include changes in forecasted future development costs relating to the reserves. Future
development costs reflect the amount of capital estimated by the independent evaluator that will be
required to bring non-producing, undeveloped or probable reserves on stream. These forecasts of
future development costs will change with time due to ongoing development activity, inflationary
changes in capital costs and acquisition or disposition of assets. Pengrowth provides the
calculation of finding and development costs both with and without change in future development
costs.
- 25 -
FD&A
Costs Company Interest Reserves
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Proved plus |
|
|
Proved |
|
Probable |
|
FD&A Costs Excluding Future Development Capital |
|
|
|
|
|
|
|
|
Exploration and Development Capital Expenditures ($000s) |
|
$ |
175,700 |
|
|
$ |
175,700 |
|
Exploration and Development Reserve Additions including Revisions (mboe) |
|
|
11,361 |
|
|
|
8,591 |
|
|
Finding and Development Cost ($/boe) |
|
$ |
15.47 |
|
|
$ |
20.45 |
|
|
|
|
|
|
|
|
|
|
|
Net Acquisition Capital ($000s) |
|
|
175,100 |
|
|
|
175,100 |
|
Net Acquisition Reserve Additions (mboe) |
|
|
10,403 |
|
|
|
13,866 |
|
|
Net Acquisition Cost ($/boe) |
|
|
16.83 |
|
|
|
12.63 |
|
|
|
|
|
|
|
|
|
|
|
Total Capital Expenditures including Net Acquisitions ($000s) |
|
|
350,800 |
|
|
|
350,800 |
|
Reserve Additions including Net Acquisitions (mboe) |
|
|
21,764 |
|
|
|
22,457 |
|
|
Finding, Development and Acquisition Cost ($/boe) |
|
|
16.12 |
|
|
|
15.62 |
|
|
|
|
|
|
|
|
|
|
|
FD&A Costs Including Future Development Capital |
|
|
|
|
|
|
|
|
Exploration and Development Capital Expenditures ($000s) |
|
|
175,700 |
|
|
|
175,700 |
|
Exploration and Development Change in FDC ($000s) |
|
|
(54,931 |
) |
|
|
(50,749 |
) |
Exploration and Development Capital including Change in FDC ($000s) |
|
|
120,769 |
|
|
|
124,951 |
|
Exploration and Development Reserve Additions including Revisions (mboe) |
|
|
11,361 |
|
|
|
8,591 |
|
|
Finding and Development Cost ($/boe) |
|
|
10.63 |
|
|
|
14.54 |
|
|
|
|
|
|
|
|
|
|
|
Net Acquisition Capital ($000s) |
|
|
175,100 |
|
|
|
175,100 |
|
Net Acquisition FDC ($000s) |
|
|
17,900 |
|
|
|
24,700 |
|
Net Acquisition Capital including FDC ($000s) |
|
|
193,000 |
|
|
|
199,800 |
|
Net Acquisition Reserve Additions (mboe) |
|
|
10,403 |
|
|
|
13,866 |
|
|
Net Acquisition Cost ($/boe) |
|
|
18.55 |
|
|
|
14.41 |
|
|
|
|
|
|
|
|
|
|
|
Total Capital Expenditures including Net Acquisitions ($000s) |
|
|
350,800 |
|
|
|
350,800 |
|
Total Change in FDC ($000s) |
|
|
(37,031 |
) |
|
|
(26,049 |
) |
Total Capital including Change in FDC ($000s) |
|
|
313,769 |
|
|
|
324,751 |
|
Reserve Additions including Net Acquisitions (mboe) |
|
|
21,764 |
|
|
|
22,457 |
|
|
Finding, Development and Acquisition Cost including FDC ($/boe) |
|
|
14.42 |
|
|
|
14.46 |
|
|
Total Future Net Revenue (Undiscounted)
GLJ January 1, 2006 escalated pricing:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Capital |
|
|
|
|
|
Future Net |
|
|
|
|
|
|
|
|
|
|
Operating |
|
Development |
|
Abandonment |
|
Revenue Before |
($ thousands) |
|
Revenue |
|
Royalties |
|
Costs |
|
Costs |
|
Costs* |
|
Income Tax |
|
Proved Producing |
|
|
7,508,321 |
|
|
|
1,415,040 |
|
|
|
2,161,122 |
|
|
|
129,826 |
|
|
|
125,593 |
|
|
|
3,676,741 |
|
Proved Developed |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Nonproducing |
|
|
253,600 |
|
|
|
56,850 |
|
|
|
38,331 |
|
|
|
7,933 |
|
|
|
1,743 |
|
|
|
148,744 |
|
Proved Undeveloped |
|
|
1,540,086 |
|
|
|
240,315 |
|
|
|
535,055 |
|
|
|
197,668 |
|
|
|
7,145 |
|
|
|
559,904 |
|
|
Total Proved |
|
|
9,302,007 |
|
|
|
1,712,204 |
|
|
|
2,734,507 |
|
|
|
335,427 |
|
|
|
134,481 |
|
|
|
4,385,388 |
|
|
Total Probable |
|
|
2,516,295 |
|
|
|
473,676 |
|
|
|
655,671 |
|
|
|
66,363 |
|
|
|
12,413 |
|
|
|
1,308,171 |
|
|
Proved plus Probable |
|
|
11,818,302 |
|
|
|
2,185,881 |
|
|
|
3,390,179 |
|
|
|
401,790 |
|
|
|
146,894 |
|
|
|
5,693,559 |
|
|
- 26 -
Constant Price at December 31, 2005:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Capital |
|
|
|
|
|
Future Net |
|
|
|
|
|
|
|
|
|
|
Operating |
|
Development |
|
Abandonment |
|
Revenue Before |
($ thousands) |
|
Revenue |
|
Royalties |
|
Costs |
|
Costs |
|
Costs* |
|
Income Tax |
|
Proved Producing |
|
|
8,409,412 |
|
|
|
1,606,510 |
|
|
|
1,842,164 |
|
|
|
121,923 |
|
|
|
93,718 |
|
|
|
4,745,097 |
|
Proved Developed |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Nonproducing |
|
|
293,753 |
|
|
|
67,811 |
|
|
|
33,775 |
|
|
|
7,642 |
|
|
|
1,345 |
|
|
|
183,180 |
|
Proved Undeveloped |
|
|
1,749,618 |
|
|
|
314,087 |
|
|
|
471,885 |
|
|
|
188,804 |
|
|
|
4,398 |
|
|
|
770,444 |
|
|
Total Proved |
|
|
10,452,783 |
|
|
|
1,988,409 |
|
|
|
2,347,823 |
|
|
|
318,370 |
|
|
|
99,460 |
|
|
|
5,698,721 |
|
|
Total Probable |
|
|
2,628,744 |
|
|
|
534,619 |
|
|
|
443,673 |
|
|
|
60,868 |
|
|
|
1,983 |
|
|
|
1,587,601 |
|
|
Proved plus Probable |
|
|
13,081,527 |
|
|
|
2,523,028 |
|
|
|
2,791,497 |
|
|
|
379,237 |
|
|
|
101,444 |
|
|
|
7,286,322 |
|
|
|
|
|
* |
|
Downhole abandonment costs |
Business
Risks
The amount of distributable cash available to unitholders and the value of Pengrowth Energy Trust
units are subject to numerous risk factors. As the trust units allow investors to participate in
the net cash flow from Pengrowths portfolio of producing oil and natural gas properties, the
principal risk factors that are associated with the oil and gas business include, but are not
limited to, the following influences:
|
|
The prices of Pengrowths products (crude oil, natural gas, and NGLs) fluctuate due
to many factors including local and global market supply and demand, weather patterns,
pipeline transportation, and political stability. |
|
|
The marketability of our production depends in part upon the availability,
proximity and capacity of gathering systems, pipelines and processing facilities.
Operational or economic factors may result in the inability to deliver our products to
market. |
|
|
Geological and operational risks affect the quantity and quality of reserves and
the costs
of recovering those reserves. Our actual results will vary from our reserve estimates, and
those variations could be material. |
|
|
Government royalties, income taxes, commodity taxes, and other taxes, levies and
fees have a significant economic impact on Pengrowths financial results. Changes to
federal and provincial legislation governing such royalties, taxes and fees could have a
material impact on Pengrowths financial results and the value of Pengrowth trust units. |
|
|
Environmental laws and regulatory initiatives impact Pengrowth financially and
operationally. We may incur substantial capital and operating costs to comply with
increasingly complex laws and regulations covering the protection of the environment and
human health and safety. In particular, we may be required to incur significant costs to
comply with the 1997 Kyoto Protocol to the United Nations Framework Convention on Climate
Change. |
|
|
Pengrowths oil and gas reserves will be depleted over time and our level of
distributable cash and the value of our trust units could be reduced if reserves and
production are not replaced. The ability to replace production depends on Pengrowths
success in developing existing reserves, acquiring new reserves and financing this
development and acquisition activity within the context of the capital markets. |
|
|
Increased competition for properties will drive the cost of acquisition up and
expected returns from the properties down. |
|
|
A significant portion of our properties are operated by third parties. If these
operators fail to perform their duties properly, or become insolvent, we may experience
interruptions in production and revenues from these properties or incur additional
liabilities and expenses as a result of the default of these third party operators. |
|
|
Increased activity within the oil and gas sector can increase the cost of goods and
services and make it more difficult to hire and retain professional staff. |
|
|
|
Changing interest rates influence borrowing costs and the availability of capital. |
- 27 -
|
|
Investors interest in the oil and gas sector may change over time which would
affect the availability of capital and the value of Pengrowth trust units. |
|
|
The value of Class A trust units and Class B trust units, relative to one another,
may be influenced by the different markets in which the trust units trade, the restriction
in entitlement of the Class B trust units to Canadian residents and the limitation in the
number of Class A trust units beneath an ownership threshold of 49.75 percent of all trust
units outstanding. |
|
|
Inflation may result in escalating costs which could impact unitholder
distributions and the value of Pengrowth trust units. |
|
|
Canadian / U.S. exchange rates influence revenues and, to a lesser extent,
operating and capital costs. |
|
|
The value of Pengrowth trust units is impacted directly by the related tax
treatment of the trust units and the trust unit distributions, and indirectly by the tax
treatment of alternative equity investments. Changes in Canadian or U.S. tax legislation
could adversely affect the value of our trust units. |
Pengrowth mitigates some of these risks by:
|
|
Fixing the price on a portion of its future crude oil and natural gas production. |
|
|
Fixing the Canadian / U.S. exchange rate through financial hedging contracts or by
fixing commodity prices in Canadian dollars. |
|
|
Offering competitive incentive-based compensation packages to attract and retain
highly qualified and motivated professional staff. |
|
|
|
Adhering to strict investment criteria for acquisitions. |
|
|
|
Acquiring mature production with long life reserves and proven production. |
|
|
Performing extensive geological, geophysical, engineering and environmental
analysis before committing to capital development projects. |
|
|
Geographically diversifying its portfolio. |
|
|
|
Controlling costs to maximize profitability. |
|
|
Developing and adhering to policies and practices that protect the environment and
meet or exceed the regulations imposed by the government. |
|
|
Developing and adhering to safety policies and practices that meet or exceed
regulatory standards. |
|
|
Ensuring strong third party operators for non-operated properties. |
|
|
|
Carrying insurance to cover physical losses and business interruption. |
These factors should not be considered to be exhaustive. Additional risks are outlined in the
Annual Information Form (AIF) of the Trust available on SEDAR at
www.sedar.com on or before March
31, 2006.
- 28 -
Summary
of Quarterly Results
The following table is a summary of quarterly results for 2005 and 2004. As this table illustrates,
production and distributable cash were impacted positively by the Murphy acquisition in the second
quarter of 2004.
This table also shows the relatively high commodity prices sustained throughout 2004 and 2005,
which have had a positive impact on net income and distributable cash.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2005 |
|
|
|
|
|
|
|
Q1 |
|
Q2 |
|
Q3 |
|
Q4 |
|
Oil and gas sales ($000s) |
|
|
239,913 |
|
|
|
253,189 |
|
|
|
304,484 |
|
|
|
353,923 |
|
Net income ($000s) |
|
|
56,314 |
|
|
|
53,106 |
|
|
|
100,243 |
|
|
|
116,663 |
|
Net income per unit ($) |
|
|
0.37 |
|
|
|
0.34 |
|
|
|
0.63 |
|
|
|
0.73 |
|
Net income per unit diluted ($) |
|
|
0.37 |
|
|
|
0.34 |
|
|
|
0.63 |
|
|
|
0.73 |
|
Distributable cash ($000s) |
|
|
127,804 |
|
|
|
134,047 |
|
|
|
162,009 |
|
|
|
195,879 |
|
Actual distributions paid or declared per unit ($) |
|
|
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 ($000s) |
|
|
38,652 |
|
|
|
32,684 |
|
|
|
51,271 |
|
|
|
31,138 |
|
Net income per unit ($) |
|
|
0.31 |
|
|
|
0.24 |
|
|
|
0.38 |
|
|
|
0.23 |
|
Net income
per unit diluted ($) |
|
|
0.31 |
|
|
|
0.24 |
|
|
|
0.38 |
|
|
|
0.23 |
|
Distributable cash ($000s) |
|
|
92,895 |
|
|
|
99,021 |
|
|
|
104,304 |
|
|
|
104,958 |
|
Actual distributions paid or declared per unit ($) |
|
|
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 |
|
Selected Annual Information
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Financial Results |
|
|
|
|
|
|
Twelve months ended |
|
|
|
|
|
|
($ thousands) |
|
Dec 31, 2005 |
|
|
Dec 31, 2004 |
|
|
Dec 31, 2003 |
|
|
|
|
|
|
|
Oil and gas sales* |
|
|
1,151,510 |
|
|
|
|
815,751 |
|
|
|
|
702,732 |
|
Net income |
|
|
326,326 |
|
|
|
|
153,745 |
|
|
|
|
189,297 |
|
Net income per unit |
|
|
2.08 |
|
|
|
|
1.15 |
|
|
|
|
1.63 |
|
Distributable cash * |
|
|
619,739 |
|
|
|
|
401,178 |
|
|
|
|
345,899 |
|
Actual distributions paid or declared
per unit |
|
|
2.82 |
|
|
|
|
2.63 |
|
|
|
|
2.68 |
|
Total assets |
|
|
2,391,432 |
|
|
|
|
2,276,534 |
|
|
|
|
1,673,718 |
|
Long term financial liabilities** |
|
|
381,026 |
|
|
|
|
383,616 |
|
|
|
|
294,300 |
|
Unitholders equity |
|
|
1,475,996 |
|
|
|
|
1,462,211 |
|
|
|
|
1,159,433 |
|
Number of units outstanding at year-end (thousands) |
|
|
159,864 |
|
|
|
|
152,973 |
|
|
|
|
123,874 |
|
|
|
|
* |
|
Prior years restated to conform to presentation
adopted in the current year |
|
** |
|
Long term debt plus long term portion of note payable and contract liabilities |
- 29 -
Trust Unit Information
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Volume |
|
|
Value |
|
Trust Unit Trading after re-class* |
|
High |
|
|
Low |
|
|
Close |
|
|
(000s) |
|
|
($ millions) |
|
TSX PGF.A ($ Cdn) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2005 1st quarter |
|
|
28.29 |
|
|
|
22.15 |
|
|
|
24.03 |
|
|
|
2,049 |
|
|
|
53.3 |
|
2nd quarter |
|
|
27.90 |
|
|
|
23.95 |
|
|
|
27.20 |
|
|
|
1,798 |
|
|
|
46.4 |
|
3rd quarter |
|
|
30.10 |
|
|
|
26.30 |
|
|
|
29.50 |
|
|
|
2,047 |
|
|
|
58.0 |
|
4th quarter |
|
|
29.80 |
|
|
|
23.64 |
|
|
|
27.41 |
|
|
|
1,324 |
|
|
|
35.2 |
|
Year |
|
|
30.10 |
|
|
|
22.15 |
|
|
|
27.41 |
|
|
|
7,218 |
|
|
|
192.9 |
|
2004 1st quarter |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2nd quarter |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
3rd quarter |
|
|
24.19 |
|
|
|
19.10 |
|
|
|
22.67 |
|
|
|
1,672 |
|
|
|
35.5 |
|
4th quarter |
|
|
26.33 |
|
|
|
20.03 |
|
|
|
24.93 |
|
|
|
2,607 |
|
|
|
58.9 |
|
Year |
|
|
26.33 |
|
|
|
19.10 |
|
|
|
24.93 |
|
|
|
4,279 |
|
|
|
94.4 |
|
TSX PGF.B ($ Cdn) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2005 1st quarter |
|
|
19.90 |
|
|
|
16.10 |
|
|
|
17.05 |
|
|
|
29,219 |
|
|
|
543.7 |
|
2nd quarter |
|
|
19.01 |
|
|
|
16.37 |
|
|
|
18.40 |
|
|
|
19,370 |
|
|
|
342.5 |
|
3rd quarter |
|
|
21.26 |
|
|
|
18.25 |
|
|
|
20.58 |
|
|
|
22,738 |
|
|
|
441.0 |
|
4th quarter |
|
|
23.38 |
|
|
|
17.27 |
|
|
|
22.65 |
|
|
|
19,747 |
|
|
|
411.0 |
|
Year |
|
|
23.38 |
|
|
|
16.10 |
|
|
|
22.65 |
|
|
|
91,074 |
|
|
|
1,738.2 |
|
2004 1st quarter |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2nd quarter |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
3rd quarter |
|
|
20.00 |
|
|
|
18.03 |
|
|
|
18.87 |
|
|
|
5,588 |
|
|
|
105.6 |
|
4th quarter |
|
|
20.04 |
|
|
|
17.51 |
|
|
|
18.50 |
|
|
|
16,007 |
|
|
|
301.8 |
|
Year |
|
|
20.04 |
|
|
|
17.51 |
|
|
|
18.50 |
|
|
|
21,595 |
|
|
|
407.4 |
|
NYSE PGH ($ U.S.) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2005 1st quarter |
|
|
22.94 |
|
|
|
18.11 |
|
|
|
20.00 |
|
|
|
24,621 |
|
|
|
515.1 |
|
2nd quarter |
|
|
22.74 |
|
|
|
19.05 |
|
|
|
22.25 |
|
|
|
16,153 |
|
|
|
335.0 |
|
3rd quarter |
|
|
25.75 |
|
|
|
21.55 |
|
|
|
25.42 |
|
|
|
14,502 |
|
|
|
340.3 |
|
4th quarter |
|
|
25.56 |
|
|
|
20.00 |
|
|
|
23.53 |
|
|
|
17,808 |
|
|
|
399.7 |
|
Year |
|
|
25.75 |
|
|
|
18.11 |
|
|
|
23.53 |
|
|
|
73,084 |
|
|
|
1,590.1 |
|
2004 1st quarter |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2nd quarter |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
3rd quarter |
|
|
18.94 |
|
|
|
14.40 |
|
|
|
17.93 |
|
|
|
21,200 |
|
|
|
350.4 |
|
4th quarter |
|
|
21.24 |
|
|
|
15.85 |
|
|
|
20.82 |
|
|
|
31,174 |
|
|
|
574.7 |
|
Year |
|
|
21.24 |
|
|
|
14.40 |
|
|
|
20.82 |
|
|
|
52,374 |
|
|
|
925.1 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Volume |
|
|
Value |
|
Trust Unit Trading before re-class* |
|
High |
|
|
Low |
|
|
Close |
|
|
(000s) |
|
|
($ millions) |
|
TSX PGF.UN ($ Cdn) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2004 1st quarter |
|
|
21.25 |
|
|
|
15.55 |
|
|
|
17.98 |
|
|
|
30,620 |
|
|
|
567.8 |
|
2nd quarter |
|
|
19.15 |
|
|
|
16.15 |
|
|
|
18.67 |
|
|
|
18,145 |
|
|
|
328.5 |
|
3rd quarter |
|
|
19.75 |
|
|
|
18.52 |
|
|
|
19.42 |
|
|
|
3,554 |
|
|
|
68.5 |
|
4th quarter |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year |
|
|
21.25 |
|
|
|
15.55 |
|
|
|
19.42 |
|
|
|
52,319 |
|
|
|
964.8 |
|
NYSE PGH ($ U.S.) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2004 1st quarter |
|
|
16.60 |
|
|
|
12.10 |
|
|
|
13.70 |
|
|
|
36,899 |
|
|
|
525.6 |
|
2nd quarter |
|
|
14.24 |
|
|
|
11.62 |
|
|
|
13.98 |
|
|
|
22,194 |
|
|
|
295.9 |
|
3rd quarter |
|
|
14.95 |
|
|
|
13.84 |
|
|
|
14.64 |
|
|
|
5,797 |
|
|
|
84.5 |
|
4th quarter |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year |
|
|
14.95 |
|
|
|
11.62 |
|
|
|
14.64 |
|
|
|
64,890 |
|
|
|
906.0 |
|
|
|
|
** July 27, 2004, all trust units were re-classified into Class A or Class B units.
|
|
Class A Units trade on the NYSE under PGH and on the TSX under PGF.A.
|
|
Class B units trade
only on the TSX under PGF.B. |
|
* July 27, 2004, trust units were re-classified as Class A or Class B trust units. Class A trust
units trade on the New York Stock Exchange (NYSE) under PGH and on the Toronto Stock Exchange (TSX)
under PGF.A. Class B trust units trade only on the TSX under PGF.B.
|
- 30 -
PENGROWTH ENERGY TRUST
UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS
DECEMBER 31, 2005
- 31 -
PENGROWTH ENERGY TRUST
CONSOLIDATED BALANCE SHEETS
(Stated in thousands of dollars)
|
|
|
|
|
|
|
|
|
|
|
As at |
|
|
As at |
|
|
|
December 31 |
|
|
December 31 |
|
|
|
2005 |
|
|
2004 |
|
|
|
(unaudited) |
|
|
(audited) |
|
ASSETS |
|
|
|
|
|
|
|
|
CURRENT ASSETS |
|
|
|
|
|
|
|
|
Accounts receivable |
|
$ |
127,394 |
|
|
$ |
104,228 |
|
Inventory |
|
|
|
|
|
|
439 |
|
|
|
|
|
|
|
|
|
|
|
127,394 |
|
|
|
104,667 |
|
|
|
|
|
|
|
|
|
|
REMEDIATION TRUST FUNDS (Note 3) |
|
|
8,329 |
|
|
|
8,309 |
|
|
|
|
|
|
|
|
|
|
DEFERRED CHARGES (Note 11) |
|
|
4,886 |
|
|
|
3,651 |
|
|
|
|
|
|
|
|
|
|
GOODWILL (Note 4) |
|
|
182,835 |
|
|
|
170,619 |
|
|
|
|
|
|
|
|
|
|
PROPERTY, PLANT AND EQUIPMENT
AND OTHER ASSETS (Note 5) |
|
|
2,067,988 |
|
|
|
1,989,288 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$ |
2,391,432 |
|
|
$ |
2,276,534 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
LIABILITIES AND UNITHOLDERS EQUITY |
|
|
|
|
|
|
|
|
CURRENT LIABILITIES |
|
|
|
|
|
|
|
|
Bank indebtedness |
|
$ |
14,567 |
|
|
$ |
4,214 |
|
Accounts payable and accrued liabilities |
|
|
111,493 |
|
|
|
80,423 |
|
Distributions payable to unitholders |
|
|
79,983 |
|
|
|
70,456 |
|
Due to Pengrowth Management Limited |
|
|
8,277 |
|
|
|
7,325 |
|
Note payable (Note 7) |
|
|
20,000 |
|
|
|
15,000 |
|
Current portion of contract liabilities (Note 4) |
|
|
5,279 |
|
|
|
5,795 |
|
|
|
|
|
|
|
|
|
|
|
239,599 |
|
|
|
183,213 |
|
|
|
|
|
|
|
|
|
|
NOTE PAYABLE (Note 7) |
|
|
|
|
|
|
20,000 |
|
|
|
|
|
|
|
|
|
|
CONTRACT LIABILITIES (Note 4) |
|
|
12,937 |
|
|
|
18,216 |
|
|
|
|
|
|
|
|
|
|
LONG-TERM DEBT (Note 8) |
|
|
368,089 |
|
|
|
345,400 |
|
|
|
|
|
|
|
|
|
|
ASSET RETIREMENT OBLIGATIONS (Note 6) |
|
|
184,699 |
|
|
|
171,866 |
|
|
|
|
|
|
|
|
|
|
FUTURE INCOME TAXES (Note 14) |
|
|
110,112 |
|
|
|
75,628 |
|
|
|
|
|
|
|
|
|
|
TRUST UNITHOLDERS EQUITY |
|
|
|
|
|
|
|
|
Trust Unitholders capital (Note 10) |
|
|
2,514,997 |
|
|
|
2,383,284 |
|
Contributed surplus (Note 10) |
|
|
3,646 |
|
|
|
1,923 |
|
Deficit (Note 9) |
|
|
(1,042,647 |
) |
|
|
(922,996 |
) |
|
|
|
|
|
|
|
|
|
|
1,475,996 |
|
|
|
1,462,211 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
COMMITMENTS (Note 18) |
|
|
|
|
|
|
|
|
SUBSEQUENT EVENT (Note 19) |
|
|
|
|
|
|
|
|
|
|
$ |
2,391,432 |
|
|
$ |
2,276,534 |
|
|
|
|
|
|
|
|
See accompanying notes to the consolidated financial statements.
- 32 -
PENGROWTH ENERGY TRUST
CONSOLIDATED STATEMENTS OF INCOME AND DEFICIT
(Stated in thousands of dollars)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year ended |
|
|
|
|
|
|
|
December 31 |
|
|
|
|
|
|
|
2005 |
|
|
2004 |
|
|
|
|
|
|
|
(unaudited) |
|
|
(audited) |
|
REVENUES |
|
|
|
|
|
|
|
|
|
|
|
|
Oil and gas sales |
|
|
|
|
|
$ |
1,151,510 |
|
|
$ |
815,751 |
|
Processing and other income |
|
|
|
|
|
|
15,091 |
|
|
|
12,390 |
|
Royalties, net of incentives |
|
|
|
|
|
|
(213,863 |
) |
|
|
(160,351 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
952,738 |
|
|
|
667,790 |
|
Interest and other income |
|
|
|
|
|
|
2,596 |
|
|
|
1,770 |
|
|
|
|
|
|
|
|
|
|
|
|
NET REVENUE |
|
|
|
|
|
|
955,334 |
|
|
|
669,560 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
EXPENSES |
|
|
|
|
|
|
|
|
|
|
|
|
Operating |
|
|
|
|
|
|
218,115 |
|
|
|
159,742 |
|
Transportation |
|
|
|
|
|
|
7,891 |
|
|
|
8,274 |
|
Amortization of injectants for miscible floods |
|
|
|
|
|
|
24,393 |
|
|
|
19,669 |
|
Interest |
|
|
|
|
|
|
21,642 |
|
|
|
29,924 |
|
General and administrative |
|
|
|
|
|
|
30,272 |
|
|
|
24,448 |
|
Management fee (Note 15) |
|
|
|
|
|
|
15,961 |
|
|
|
12,874 |
|
Foreign exchange gain (Note 12) |
|
|
|
|
|
|
(6,966 |
) |
|
|
(17,300 |
) |
Depletion and depreciation |
|
|
|
|
|
|
284,989 |
|
|
|
247,332 |
|
Accretion (Note 6) |
|
|
|
|
|
|
14,162 |
|
|
|
10,642 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
610,459 |
|
|
|
495,605 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
NET INCOME BEFORE TAXES |
|
|
|
|
|
|
344,875 |
|
|
|
173,955 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
INCOME TAX EXPENSE (Note 14) |
|
|
|
|
|
|
|
|
|
|
|
|
Capital |
|
|
|
|
|
|
6,273 |
|
|
|
4,594 |
|
Future |
|
|
|
|
|
|
12,276 |
|
|
|
15,616 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
18,549 |
|
|
|
20,210 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
NET INCOME |
|
|
|
|
|
$ |
326,326 |
|
|
$ |
153,745 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Deficit, beginning of year |
|
|
|
|
|
|
(922,996 |
) |
|
|
(713,680 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
Distributions paid or declared |
|
|
|
|
|
|
(445,977 |
) |
|
|
(363,061 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
DEFICIT, END OF YEAR |
|
|
|
|
|
$ |
(1,042,647 |
) |
|
$ |
(922,996 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
NET INCOME PER TRUST UNIT (Note 16) |
|
Basic |
|
$ |
2.077 |
|
|
$ |
1.153 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Diluted |
|
$ |
2.066 |
|
|
$ |
1.147 |
|
|
|
|
|
|
|
|
|
|
|
|
See accompanying notes to the consolidated financial statements.
- 33 -
PENGROWTH ENERGY TRUST
CONSOLIDATED STATEMENTS OF CASH FLOW
(Stated in thousands of dollars)
|
|
|
|
|
|
|
|
|
|
|
Year ended |
|
|
|
December 31 |
|
|
|
2005 |
|
|
2004 |
|
|
|
(unaudited) |
|
|
(audited) |
|
CASH PROVIDED BY (USED FOR): |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
OPERATING |
|
|
|
|
|
|
|
|
Net income |
|
$ |
326,326 |
|
|
$ |
153,745 |
|
Depletion, depreciation and accretion |
|
|
299,151 |
|
|
|
257,974 |
|
Future income taxes |
|
|
12,276 |
|
|
|
15,616 |
|
Contract liability amortization |
|
|
(5,795 |
) |
|
|
(4,164 |
) |
Amortization of injectants |
|
|
24,393 |
|
|
|
19,669 |
|
Purchase of injectants |
|
|
(34,658 |
) |
|
|
(20,415 |
) |
Expenditures on remediation |
|
|
(7,353 |
) |
|
|
(4,440 |
) |
Unrealized foreign exchange gain (Note 12) |
|
|
(7,800 |
) |
|
|
(18,900 |
) |
Trust unit based compensation (Note 10) |
|
|
2,932 |
|
|
|
2,264 |
|
Deferred charges (Note 11) |
|
|
(4,961 |
) |
|
|
|
|
Amortization of deferred charges (Note 11) |
|
|
3,726 |
|
|
|
1,893 |
|
Gain on sale of marketable securities |
|
|
|
|
|
|
(248 |
) |
Changes in non-cash operating working
capital (Note 13) |
|
|
9,833 |
|
|
|
1,173 |
|
|
|
|
|
|
|
|
|
|
|
618,070 |
|
|
|
404,167 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
FINANCING |
|
|
|
|
|
|
|
|
Distributions |
|
|
(436,450 |
) |
|
|
(344,744 |
) |
Change in long-term debt, net |
|
|
10,030 |
|
|
|
105,000 |
|
Note payable (Note 7) |
|
|
(15,000 |
) |
|
|
(10,000 |
) |
Proceeds from issue of trust units |
|
|
42,544 |
|
|
|
509,830 |
|
|
|
|
|
|
|
|
|
|
|
(398,876 |
) |
|
|
260,086 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
INVESTING |
|
|
|
|
|
|
|
|
Expenditures on property acquisitions |
|
|
(92,568 |
) |
|
|
(572,980 |
) |
Expenditures on property, plant and equipment |
|
|
(175,693 |
) |
|
|
(161,141 |
) |
Proceeds on property dispositions |
|
|
37,617 |
|
|
|
|
|
Change in remediation trust fund |
|
|
(20 |
) |
|
|
(917 |
) |
Purchase of marketable securities |
|
|
|
|
|
|
(2,680 |
) |
Proceeds from sale of marketable securities |
|
|
|
|
|
|
2,928 |
|
Change in non-cash investing working capital
(Note 13) |
|
|
1,117 |
|
|
|
2,169 |
|
|
|
|
|
|
|
|
|
|
|
(229,547 |
) |
|
|
(732,621 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
CHANGE IN CASH AND TERM DEPOSITS |
|
|
(10,353 |
) |
|
|
(68,368 |
) |
|
|
|
|
|
|
|
|
|
CASH AND TERM DEPOSITS
(BANK INDEBTEDNESS) AT BEGINNING OF YEAR |
|
|
(4,214 |
) |
|
|
64,154 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
CASH AND TERM DEPOSITS
(BANK INDEBTEDNESS) AT END OF YEAR |
|
$ |
(14,567 |
) |
|
$ |
(4,214 |
) |
|
|
|
|
|
|
|
See accompanying notes to the consolidated financial statements.
- 34 -
PENGROWTH ENERGY TRUST
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
YEARS ENDED DECEMBER 31, 2005 AND 2004
(Tabular amounts are stated in thousands of dollars except per trust unit amounts.)
1. STRUCTURE OF THE TRUST
Pengrowth Energy Trust (the Trust) is a closed-end investment trust created under the
laws of the Province of Alberta pursuant to a Trust Indenture dated December 2, 1988 (as
amended) between Pengrowth Corporation (Corporation) and Computershare Trust Company of Canada
(Computershare). Operations commenced on December 30, 1988. The beneficiaries of the Trust are
the holders of trust units (the unitholders).
The purpose of the Trust is to directly and indirectly explore for, develop and hold interests
in petroleum and natural gas properties, through investments in securities, royalty units, and
notes issued by the Corporation. The activities of Corporation and its subsidiaries are
financed by issuance of royalty units and interest bearing notes to the Trust and third party
debt. The Trust owns approximately 99.99 percent of the royalty units and 91 percent of the
common shares of Corporation. The Trust, through the royalty ownership, obtains substantially
all the economic benefits of Corporation. Under the terms of the Royalty Indenture, the
Corporation is entitled to retain a one percent share of royalty income and all miscellaneous
income (the Residual Interest) to the extent this amount exceeds the aggregate of debt
service charges, general and administrative expenses, and management fees. In 2005 and 2004,
this Residual Interest, as computed, did not result in any income retained by Corporation.
The royalty units and notes of Corporation held by the Trust entitle it to the net income
generated by the Corporation and its subsidiaries petroleum and natural gas properties less
amounts withheld in accordance with prudent business practices to provide for future Operating
Costs and Reclamation Obligations, as defined in the Royalty Indenture. In addition,
unitholders are entitled to receive the net income from other investments that are held
directly by the Trust. Pursuant to the Royalty Indenture, the Board of Directors of Corporation
can establish a reserve for certain items including up to 20 percent of Gross Revenue to fund
future capital expenditures or for the payment of royalty income in any future period.
Pursuant to the Trust Indenture, Trust unitholders are entitled to monthly distributions from
interest income on the notes, royalty income under the Royalty Indenture and from other
investments held directly by the Trust, less any reserves and certain expenses of the Trust
including General and Administrative costs as defined in the Trust Indenture.
The Board of Directors has general authority over the business and affairs of the Corporation
and derives its authority in respect to the Trust by virtue of the delegation of powers by the
trustee to the Corporation as Administrator in accordance with the Trust Indenture.
Pengrowth Management Limited (the Manager) has responsibility for the management of the
business affairs of the Corporation and the administration of the Trust and defers to the Board
of Directors on all matters material to the Corporation and the Trust. Corporate Governance
practices are consistent with corporations and trusts that do not have a management agreement.
The Manager owns nine percent of the common shares of Corporation, and the Manager is
controlled by an officer and a director of the Corporation.
- 35 -
2. SIGNIFICANT ACCOUNTING POLICIES
Basis
of Presentation
The Trusts consolidated financial statements have been prepared in accordance with
Generally Accepted Accounting Principles (GAAP) in Canada and they include the accounts of the
Trust, the Corporation and its subsidiaries (collectively referred to as Pengrowth). All
inter-entity transactions have been eliminated. These financial statements do not contain the
accounts of the Manager.
The Trust owns 91 percent of the shares of Corporation and, through the royalty and notes,
obtains substantially all the economic benefits of Corporation. In addition, the unitholders of
the Trust have the right to elect the majority of the Board of Directors of Corporation.
Joint
Interest Operations
A significant proportion of Pengrowths petroleum and natural gas development and
production activities are conducted with others and accordingly the accounts reflect only
Pengrowths proportionate interest in such activities.
Property,
Plant and Equipment
Pengrowth follows the full cost method of accounting for oil and gas properties and
facilities whereby all costs of developing and acquiring oil and gas properties are capitalized
and depleted on the unit of production method based on proved reserves before royalties as
estimated by independent engineers. The fair value of future estimated asset retirement
obligations associated with properties and facilities are also capitalized and depleted on the
unit of production method. The associated asset retirement obligations on future development
capital costs are also included in the cost base subject to depletion. Natural gas production
and reserves are converted to equivalent units of crude oil using their relative energy content.
General and administrative costs are not capitalized other than to the extent they are directly
related to a successful acquisition, or to the extent of Pengrowths working interest in
capital expenditure programs to which overhead fees can be recovered from partners. Overhead
fees are not charged on 100 percent owned projects.
Proceeds from disposals of oil and gas properties and equipment are credited against
capitalized costs unless the disposal would alter the rate of depletion and depreciation by
more than 20 percent, in which case a gain or loss on disposal is recorded.
Pengrowth places a limit on the carrying value of property, plant and equipment and other
assets, which may be depleted against revenues of future periods (the ceiling test). The
carrying value is assessed to be recoverable when the sum of the undiscounted cash flows
expected from the production of proved reserves, the lower of cost and market of unproved
properties and the cost of major development projects exceeds the carrying value. When the
carrying value is not assessed to be recoverable, an impairment loss is recognized to the
extent that the carrying value of assets exceeds the sum of the discounted cash flows expected
from the production of proved and probable reserves, the lower of cost and market of unproved
properties and the cost of major development projects. The cash flows are estimated using
expected future product prices and costs and are discounted using a risk-free interest rate.
The carrying value of property, plant and equipment and other assets subject to the ceiling
test includes asset retirement costs.
Repairs and maintenance costs are expensed as incurred.
Goodwill
Goodwill, which represents the excess of the total purchase price over the estimated fair
value of the net identifiable assets and liabilities acquired, is not amortized but instead is
assessed for impairment annually or as events occur that could result in impairment. Impairment
is assessed
- 36 -
by determining the fair value of the reporting entity and comparing this fair value to the
book value of the reporting entity. If the fair value of the reporting entity is less than the book
value, impairment is measured by allocating the fair value of the reporting entity to the
identifiable assets and liabilities of the reporting entity as if the reporting entity had been
acquired in a business combination for a purchase price equal to its fair value. The excess of the
fair value of the reporting entity over the assigned values of the identifiable assets and
liabilities is the fair value of the goodwill. Any excess of the book value of goodwill over this
implied fair value is the impairment amount. Impairment is charged to earnings in the period in
which it occurs. Goodwill is stated at cost less impairment.
Injectant Costs
Injectants (mostly natural gas and ethane) are used in miscible flood programs to stimulate
incremental oil recovery. The cost of hydrocarbon injectants purchased from third parties for
miscible flood projects is deferred and amortized over the period of expected future economic
benefit which is estimated as 24 to 30 months.
Inventory
Inventories of crude oil, natural gas and natural gas liquids are stated at the lower of average
cost and net realizable value.
Asset Retirement Obligations
Pengrowth recognizes the fair value of an Asset Retirement Obligation (ARO) in the period in which
it is incurred when a reasonable estimate of the fair value can be made. The fair value of the
estimated ARO is recorded as a liability, with a corresponding increase in the carrying amount of
the related asset. The capitalized amount is depleted on the unit of production method based on
proved reserves. The liability amount is increased each reporting period due to the passage of
time and the amount of accretion is expensed to income in the period. Actual costs incurred upon
the settlement of the ARO are charged against the ARO.
Pengrowth has placed cash in segregated remediation trust accounts to fund certain ARO for the
Judy Creek properties, and the Sable Offshore Energy Project (SOEP). Contributions to these
remediation trust accounts and expenditures on ARO not funded by the trust accounts are charged
against actual cash distributions in the period incurred.
Income Taxes
The Trust is a taxable trust under the Canadian Income Tax Act. As income taxes are the
responsibility of the individual unitholders and the Trust distributes all of its taxable income
to its unitholders, no provision has been made for income taxes by the Trust in these financial
statements.
The Corporation and its subsidiaries follow the tax liability method of accounting for income
taxes. Under this method, income tax liabilities and assets are recognized for the estimated tax
consequences attributable to differences between the amounts reported in the financial statements
of the Corporation and its subsidiaries and their respective tax bases, using enacted income tax
rates. The effect of a change in income tax rates on future income tax liabilities and assets is
recognized in income in the period that the change occurs.
Trust Unit Compensation Plans
Pengrowth has trust unit based compensation plans, which are described in Note 10. Compensation
expense associated with trust unit based compensation plans is recognized in income over the
vesting period of the plan with a corresponding increase in contributed surplus. The amount of
compensation expense and contributed surplus is reduced for options, rights and deferred
entitlement trust units (DEUs) that are cancelled prior to vesting. Any consideration received
upon the exercise of trust unit based compensation together with the amount of non-cash
compensation expense recognized in contributed surplus is recorded as an increase in trust
- 37 -
unitholders capital. Compensation expense is based on the estimated fair value of the trust
unit based compensation at the date of grant, as further described in Note 10.
Pengrowth does not have any outstanding trust unit compensation plans that call for settlement in
cash or other assets. Grants of such items, if any, will be recorded as expenses and liabilities
based on the intrinsic value.
Risk
Management
Financial instruments are utilized by Pengrowth to manage its exposure to commodity price
fluctuations, foreign currency and interest rate exposures. Pengrowths practice is not to utilize
financial instruments for trading or speculative purposes.
Pengrowth formally documents relationships between hedging instruments and hedged items, as well
as its risk management objective and strategy for undertaking various hedge transactions. This
process includes linking derivatives to specific assets and liabilities on the balance sheet or to
specific firm commitments or forecasted transactions. Pengrowth also formally assesses, both at
the hedges inception and on an ongoing basis, whether the derivatives that are used in hedging
transactions are highly effective in offsetting changes in fair value or cash flows of hedged
items.
Pengrowth uses forward, futures and swap contracts to manage its exposure to commodity price
fluctuations. The net receipts or payments arising from these contracts are recognized in income
as a component of oil and gas sales during the same period as the corresponding hedged position.
Foreign exchange gains and losses on foreign currency exchange swaps used to hedge U.S. dollar
denominated sales are recognized in income as a component of natural gas sales during the same
period as the corresponding hedged position.
Foreign exchange swaps were used to fix the foreign exchange rate on the interest and principal of
the £50 million ten year senior unsecured notes (see Note 17). Unrealized foreign exchange gains
and losses on the debt and related hedge are recorded as the exchange rate changes.
Measurement
Uncertainty
The preparation of financial statements in conformity with Canadian GAAP requires management to
make estimates and assumptions that affect the reported amounts of assets and liabilities at the
date of the financial statements and revenues and expenses for the period then ended.
The amounts recorded for depletion, depreciation, amortization of injectants, goodwill and ARO are
based on estimates. The ceiling test calculation is based on estimates of proved reserves,
production rates, oil and natural gas prices, future costs and other relevant assumptions. By
their nature, these estimates are subject to measurement uncertainty and may impact the
consolidated financial statements of future periods.
Earnings Per Trust Unit
In calculating diluted net income per trust unit, Pengrowth follows the treasury stock method to
determine the dilutive effect of trust unit based compensation plans and other dilutive
instruments. Under the treasury stock method, only in the money dilutive instruments impact the
diluted calculations.
Cash and Term Deposits
Pengrowth considers term deposits with an original maturity of three months or less to be cash
equivalents.
- 38 -
Revenue Recognition
Revenue from the sale of oil and natural gas is recognized when the product is delivered.
Revenue from processing and other miscellaneous sources is recognized upon completion of the
relevant service.
Comparative Figures
Certain comparative figures have been reclassified to conform to the presentation adopted in
the current year.
3. REMEDIATION TRUST FUNDS
Pengrowth is required to make contributions to a remediation trust fund that is used to cover
certain ARO of the Judy Creek properties. Pengrowth makes monthly contributions to the fund of
$0.10 per boe of production from the Judy Creek properties and an annual lump sum contribution
of $250,000.
Every five years Pengrowth must evaluate the assets in the trust fund and the outstanding ARO,
and make recommendations to the former owner of the Judy Creek properties as to whether
contribution levels should be changed. In 2004 an evaluation was completed with the results of
the evaluation determining that current funding levels would remain unchanged until the next
evaluation in 2007. Contributions to the Judy Creek remediation trust fund may change based on
future evaluations of the fund.
Pengrowth is required, pursuant to various agreements with the SOEP partners, to make
contributions to a remediation trust fund that will be used to fund the ARO of the SOEP
properties and facilities. Pengrowth makes monthly contributions to the fund of $0.04 per mcf
of natural gas production and $0.08 per boe of natural gas liquids production from SOEP.
The following summarizes Pengrowths trust fund contributions for 2005 and 2004 and
Pengrowths expenditures on ARO not covered by the trust funds:
|
|
|
|
|
|
|
|
|
|
|
2005 |
|
2004 |
|
Contributions to Judy Creek Remediation Trust Fund |
|
$ |
778 |
|
|
$ |
906 |
|
Contributions to SOEP Environmental Restoration Fund |
|
|
556 |
|
|
|
548 |
|
Expenditures related to Judy Creek Remediation Trust Fund |
|
|
(1,314 |
) |
|
|
(537 |
) |
|
|
|
|
20 |
|
|
|
917 |
|
|
|
|
|
|
|
|
|
|
|
Expenditures on ARO not covered by the trust funds |
|
|
6,039 |
|
|
|
3,903 |
|
Expenditures on ARO covered by the trust funds |
|
|
1,314 |
|
|
|
537 |
|
|
|
|
|
7,353 |
|
|
|
4,440 |
|
|
|
|
|
|
|
|
|
|
|
Total trust fund contributions and ARO expenditures not
covered by the trust funds |
|
$ |
7,373 |
|
|
$ |
5,357 |
|
|
4. ACQUISITIONS
Corporate Acquisitions
On April 29, 2005, Pengrowth acquired all of the issued and outstanding shares of Crispin
Energy Inc. (Crispin) which held interests in oil and natural gas assets mainly in Alberta.
The shares were acquired on the basis of exchanging 0.0725 Class B trust units of the Trust
for each share held by Canadian resident shareholders of Crispin and 0.0512 Class A trust
units of the Trust for each share held by non-Canadian resident shareholders of Crispin. The
average value assigned to
- 39 -
each trust unit issued was $20.80 based on the weighted average trading price of the Class A
and Class B trust units for a period before and after the acquisition was announced. The Trust
issued 3,538,581 Class B trust units and 686,732 Class A trust units valued at $88 million. The
transaction was accounted for using the purchase method of accounting with the allocation of the
purchase price and consideration as follows:
|
|
|
|
|
Allocation of purchase price: |
|
|
|
|
|
Working capital |
|
$ |
1,655 |
|
Property, plant, and equipment |
|
|
121,729 |
|
Goodwill |
|
|
12,216 |
|
Bank debt |
|
|
(20,459 |
) |
Asset retirement obligations |
|
|
(4,038 |
) |
Future income taxes |
|
|
(22,208 |
) |
|
|
|
$ |
88,895 |
|
|
Cost of acquisition: |
|
|
|
|
Trust units issued |
|
$ |
87,960 |
|
Acquisition costs |
|
|
935 |
|
|
|
|
$ |
88,895 |
|
|
Property, plant and equipment of $122 million represents the estimated fair value of the
assets acquired determined in part by an independent reserve evaluation. Goodwill of $12 million,
which is not deductible for tax purposes, was determined based on the excess of the total cost of
the acquisition less the value assigned to the identifiable assets and liabilities, including the
future income tax liability.
The future income tax liability was determined based on an enacted income tax rate of approximately
34 percent as at April 29, 2005. Results from operations of the acquired assets of Crispin
subsequent to April 29, 2005 are included in the consolidated financial statements.
On May 31, 2004, Pengrowth acquired all of the issued and outstanding shares of a company which
had interests in oil and natural gas assets in Alberta and Saskatchewan (the Murphy
acquisition). The transaction was accounted for using the purchase method of accounting with the
allocation of the purchase price and consideration paid as follows:
|
|
|
|
|
Allocation of purchase price: |
|
|
|
|
|
Working capital |
|
$ |
9,310 |
|
Property, plant, and equipment |
|
|
502,924 |
|
Goodwill |
|
|
170,619 |
|
Asset retirement obligations |
|
|
(43,876 |
) |
Future income taxes |
|
|
(60,012 |
) |
Contract liabilities |
|
|
(28,175 |
) |
|
|
|
$ |
550,790 |
|
|
Cost of acquisition: |
|
|
|
|
Cash and term deposits |
|
$ |
224,700 |
|
Acquisition facility |
|
|
325,000 |
|
Acquisition costs |
|
|
1,090 |
|
|
|
|
$ |
550,790 |
|
|
Property, plant and equipment of $503 million represents the fair value of the assets
acquired determined in part by an independent reserve evaluation, net of purchase price
adjustments.
- 40 -
Goodwill of $171 million, which is not deductible for tax purposes, was determined based
on the excess of the total consideration paid less the value assigned to the identifiable
assets and liabilities including the future income tax liability.
The future income tax liability was determined based on the enacted income tax rate of
approximately 34 percent as at May 31, 2004.
Contract liabilities include a natural gas fixed price sales contract (see Note 17) and firm
pipeline demand charge contracts. The fair value of these liabilities was determined on the
date of acquisition and is being reduced as the contracts are settled. As at December 31, 2005
a net liability of S12.3 million (2004 $17.9 million) has been recorded for the natural gas
fixed price sales contract and $5.9 million (2004 $6.1 million) has been recorded for the
firm pipeline demand charge contracts.
Results of operations from the Murphy acquisition subsequent to May 31, 2004 are included in
the consolidated financial statements.
The following unaudited pro forma information provides an indication of what Pengrowths
results of operations might have been had the Murphy acquisition taken place on January 1 of
2004:
|
|
|
|
|
|
|
|
|
|
|
2004 Pro Forma |
|
2004 Actual |
|
|
(unaudited) |
|
(audited) |
|
Oil and gas sales |
|
$ |
897,397 |
|
|
$ |
815,751 |
|
Net income |
|
$ |
180,101 |
|
|
$ |
153,745 |
|
Net income per trust unit: |
|
|
|
|
|
|
|
|
|
Basic |
|
$ |
1.206 |
|
|
$ |
1.153 |
|
|
Diluted |
|
$ |
1.201 |
|
|
$ |
1.147 |
|
|
Property Acquisitions
In February 2005, Pengrowth acquired an additional 11.9 percent working interest in Swan
Hills for a purchase price of $87 million before adjustments. The acquisition increased
Pengrowths working interest in the Swan Hills Unit No. 1 to 22.3 percent.
In August 2004, Pengrowth acquired an additional 34.4 percent working interest in Kaybob
Notikewin Unit No. l for a purchase price of $20 million before adjustments. The acquisition
increased Pengrowths working interest in the Kaybob Notikewin Unit No.l to approximately 99
percent.
5. PROPERTY, PLANT AND EQUIPMENT AND OTHER ASSETS
|
|
|
|
|
|
|
|
|
|
|
2005 |
|
2004 |
|
Property, Plant and Equipment |
|
|
|
|
|
|
|
|
Property, Plant and Equipment, at cost |
|
$ |
3,340,106 |
|
|
$ |
2,986,681 |
|
Accumulated depletion and depreciation |
|
|
(1,307,424 |
) |
|
|
(1,022,435 |
) |
|
Net book value of property, plant and equipment |
|
|
2,032,682 |
|
|
|
1,964,246 |
|
Other Assets |
|
|
|
|
|
|
|
|
Deferred injectant costs |
|
|
35,306 |
|
|
|
25,042 |
|
|
Net book value of property, plant and equipment
and other assets |
|
$ |
2,067,988 |
|
|
$ |
1,989,288 |
|
|
Property, plant and equipment includes $77.3 million (2004 $81.1 million) related to ARO, net
of accumulated depletion.
- 41 -
Pengrowth performed a ceiling test calculation at December 31, 2005 to assess the recoverable
value of the property, plant and equipment and other assets. The oil and gas future prices are
based on the January 1, 2006 commodity price forecast of our independent reserve evaluators. These
prices have been adjusted for commodity price differentials specific to Pengrowth. The following
table summarizes the benchmark prices used in the ceiling test calculation. Based on these
assumptions, the undiscounted value of future net revenues from Pengrowths proved reserves
exceeded the carrying value of property, plant and equipment and other assets at December 31, 2005.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Foreign |
|
|
|
|
|
|
|
|
|
|
Exchange |
|
Edmonton Light |
|
|
|
|
WTI Oil |
|
Rate |
|
Crude Oil |
|
AECO Gas |
Year |
|
(U.S.$/bbl) |
|
(U.S.$/Cdn$) |
|
(Cdn$/bbl) |
|
(Cdn$/mmbtu) |
|
2006 |
|
|
57.00 |
|
|
|
0.85 |
|
|
|
66.25 |
|
|
|
10.60 |
|
2007 |
|
|
55.00 |
|
|
|
0.85 |
|
|
|
64.00 |
|
|
|
9.25 |
|
2008 |
|
|
51.00 |
|
|
|
0.85 |
|
|
|
59.25 |
|
|
|
8.00 |
|
2009 |
|
|
48.00 |
|
|
|
0.85 |
|
|
|
55.75 |
|
|
|
7.50 |
|
2010 |
|
|
46.50 |
|
|
|
0.85 |
|
|
|
54.00 |
|
|
|
7.20 |
|
2011 |
|
|
45.00 |
|
|
|
0.85 |
|
|
|
52.25 |
|
|
|
6.90 |
|
2012 |
|
|
45.00 |
|
|
|
0.85 |
|
|
|
52.25 |
|
|
|
6.90 |
|
2013 |
|
|
46.00 |
|
|
|
0.85 |
|
|
|
53.25 |
|
|
|
7.05 |
|
2014 |
|
|
46.75 |
|
|
|
0.85 |
|
|
|
54.25 |
|
|
|
7.20 |
|
2015 |
|
|
47.75 |
|
|
|
0.85 |
|
|
|
55.50 |
|
|
|
7.40 |
|
2016 |
|
|
48.75 |
|
|
|
0.85 |
|
|
|
56.50 |
|
|
|
7.55 |
|
Escalate thereafter |
|
2.0% per year |
|
|
|
|
|
2.0% per year |
|
2.0% per year |
|
6. ASSET RETIREMENT OBLIGATIONS
The total future ARO were estimated by management based on Pengrowths working interest in
wells and facilities, estimated costs to remediate, reclaim and abandon the wells and facilities
and the estimated timing of the costs to be incurred in future periods. Pengrowth has estimated
the net present value of its ARO to be $185 million as at December 31, 2005 (2004 $172 million),
based on a total escalated future liability of $1,041 million (2004 $551 million). These costs
are expected to be made over 50 years with the majority of the costs incurred between 2032 and
2054. Pengrowths credit adjusted risk free rate of eight
percent (2004 eight percent) and an
inflation rate of 2.0 percent (2004 1.5 percent) were used to calculate the net present value of
the ARO.
The following reconciles Pengrowths ARO:
|
|
|
|
|
|
|
|
|
|
|
2005 |
|
2004 |
|
Asset retirement obligations, beginning of year |
|
$ |
171,866 |
|
|
$ |
102,528 |
|
Increase (decrease) in liabilities during the year
related to: |
|
|
|
|
|
|
|
|
Acquisitions |
|
|
6,347 |
|
|
|
44,368 |
|
Disposals |
|
|
(3,844 |
) |
|
|
|
|
Additions |
|
|
1,972 |
|
|
|
2,681 |
|
Revisions |
|
|
1,549 |
|
|
|
16,087 |
|
Accretion expense |
|
|
14,162 |
|
|
|
10,642 |
|
Liabilities settled during the year |
|
|
(7,353 |
) |
|
|
(4,440 |
) |
|
Asset retirement obligations, end of year |
|
$ |
184,699 |
|
|
$ |
171,866 |
|
|
- 42 -
7. NOTE PAYABLE
The note payable is due to Emera Offshore Incorporated, in respect of the acquisition of the
SOEP facility in 2003. The note payable is secured by Pengrowths working interest in SOEP. The
note payable is non-interest bearing with the final payment of $20 million due on December 31,
2006.
At December 31, 2005, $0.7 million (2004 $2.0 million) has been recorded as a deferred
charge representing the imputed interest on the non-interest bearing note. This amount will be
recognized as interest expense over the term of the note.
8. LONG TERM DEBT
|
|
|
|
|
|
|
|
|
|
|
2005 |
|
2004 |
|
U.S. dollar denominated debt: |
|
|
|
|
|
|
|
|
U.S. dollar $150 million senior unsecured notes at 4.93
percent due April 2010 |
|
$ |
174,450 |
|
|
$ |
180,300 |
|
U.S. dollar $50 million senior unsecured notes at 5.47
percent due April 2013 |
|
|
58,150 |
|
|
|
60,100 |
|
|
|
|
|
232,600 |
|
|
|
240,400 |
|
Pound sterling denominated £50 million unsecured notes at
5.46 percent due December 2015 |
|
|
100,489 |
|
|
|
|
|
Canadian dollar revolving credit borrowings |
|
|
35,000 |
|
|
|
105,000 |
|
|
|
|
$ |
368,089 |
|
|
$ |
345,400 |
|
|
On April 23, 2003, Pengrowth closed a U.S. $200 million private placement of senior unsecured
notes. The notes were offered in two tranches of U.S. $150 million at 4.93 percent due April 2010
and U.S. $50 million at 5.47 percent due in April 2013. The notes contain certain financial
maintenance covenants and interest is paid semi-annually. Costs incurred in connection with
issuing the notes, in the amount of $2.1 million are being amortized over the term of the notes
(see Note 11).
On December 1, 2005 Pengrowth closed a £50 million private placement of senior unsecured notes. In
a series of related hedging transactions, Pengrowth fixed the pound sterling to Canadian dollar
exchange rate for all the semi-annual interest payments and the principal repayments at maturity.
The notes have an effective rate of 5.49 percent after the hedging transactions. The notes contain
the same financial maintenance covenants as the U.S. dollar denominated notes. Costs incurred in
connection with issuing the notes, in the amount of $0.7 million are being amortized over the term
on the notes (see Note 11).
The Corporation 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 are currently reduced by outstanding letters of credit in the amount
of approximately $17 million. In addition, it 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 the Corporation. 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. The Corporation can post, at its option, security suitable to the
banks
- 43 -
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.
The five year schedule of long term debt repayment based on maturity is as follows: 2006 nil,
2007 nil, 2008 nil, 2009 nil, 2010 $174.45 million.
9. DEFICIT
|
|
|
|
|
|
|
|
|
|
|
2005 |
|
2004 |
|
Accumulated earnings |
|
$ |
1,053,383 |
|
|
$ |
727,057 |
|
Accumulated distributions paid or declared |
|
|
(2,096,030 |
) |
|
|
(1,650,053 |
) |
|
|
|
$ |
(1,042,647 |
) |
|
$ |
(922,996 |
) |
|
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.
10. TRUST UNITS
The total authorized capital of Pengrowth is 500,000,000 trust units.
Total Trust Units:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended |
|
Year Ended |
|
|
December 31, 2005 |
|
December 31, 2004 |
|
|
|
Number |
|
|
|
|
|
Number |
|
|
Trust units issued |
|
of trust units |
|
Amount |
|
of trust units |
|
Amount |
|
Balance, beginning of year |
|
|
152,972,555 |
|
|
$ |
2,383,284 |
|
|
|
123,873,651 |
|
|
$ |
1,872,924 |
|
Issued for cash |
|
|
|
|
|
|
|
|
|
|
26,885,000 |
|
|
|
499,480 |
|
Less: issue expenses |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(26,287 |
) |
Issued for the Crispin acquisition (non-cash) (Note 4) |
|
|
4,225,313 |
|
|
|
87,960 |
|
|
|
|
|
|
|
|
|
Issued for cash on exercise of trust unit
options and rights |
|
|
1,512,211 |
|
|
|
21,818 |
|
|
|
1,294,838 |
|
|
|
20,251 |
|
Issued for cash under Distribution
Reinvestment Plan (DRIP) |
|
|
1,154,004 |
|
|
|
20,726 |
|
|
|
918,366 |
|
|
|
16,386 |
|
Trust unit rights incentive plan (non-cash
exercised) |
|
|
|
|
|
|
1,209 |
|
|
|
|
|
|
|
530 |
|
Royalty units exchanged for trust units |
|
|
|
|
|
|
|
|
|
|
700 |
|
|
|
|
|
|
Balance, end of year |
|
|
159,864,083 |
|
|
$ |
2,514,997 |
|
|
|
152,972,555 |
|
|
$ |
2,383,284 |
|
|
Class A Trust Units:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
For the period from |
|
|
Year Ended |
|
July 27, 2004 to Dec 31, |
|
|
December 31, 2005 |
|
2004 |
|
|
|
Number |
|
|
|
|
|
Number |
|
|
Trust units issued |
|
of trust units |
|
Amount |
|
of trust units |
|
Amount |
|
Balance, beginning of period |
|
|
76,792,759 |
|
|
$ |
1,176,427 |
|
|
|
|
|
|
$ |
|
|
Issued for the Crispin acquisition
(non-cash) (Note 4) |
|
|
686,732 |
|
|
|
19,002 |
|
|
|
|
|
|
|
|
|
Trust units converted |
|
|
45,182 |
|
|
|
692 |
|
|
|
76,792,759 |
|
|
|
1,176,427 |
|
|
Balance, end of period |
|
|
77,524,673 |
|
|
$ |
1,196,121 |
|
|
|
76,792,759 |
|
|
$ |
1,176,427 |
|
|
- 44 -
Class B Trust Units:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended |
|
For the period from |
|
|
December 31, 2005 |
|
July 27, 2004 to Dec 31, 2004 |
|
|
|
Number |
|
|
|
|
|
Number |
|
|
Trust units issued |
|
of trust units |
|
Amount |
|
of trust units |
|
Amount |
|
Balance, beginning of period |
|
|
76,106,471 |
|
|
$ |
1,205,734 |
|
|
|
|
|
|
$ |
|
|
Trust units converted |
|
|
(9,824 |
) |
|
|
(151 |
) |
|
|
59,000,129 |
|
|
|
903,854 |
|
Issued for cash |
|
|
|
|
|
|
|
|
|
|
15,985,000 |
|
|
|
298,920 |
|
Less: issue expenses |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(15,577 |
) |
Issued for the Crispin acquisition
(non-cash) (Note 4) |
|
|
3,538,581 |
|
|
|
68,958 |
|
|
|
|
|
|
|
|
|
Issued for cash on exercise of trust unit
options and rights |
|
|
1,512,211 |
|
|
|
21,818 |
|
|
|
746,864 |
|
|
|
11,516 |
|
Issued for cash under Distribution
Reinvestment Plan (DRIP) |
|
|
1,154,004 |
|
|
|
20,726 |
|
|
|
374,478 |
|
|
|
6,750 |
|
Trust unit rights incentive plan (non-cash
exercised) |
|
|
|
|
|
|
1,209 |
|
|
|
|
|
|
|
271 |
|
|
Balance, end of period |
|
|
82,301,443 |
|
|
$ |
1,318,294 |
|
|
|
76,106,471 |
|
|
$ |
1,205,734 |
|
|
Unclassified Trust Units:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended |
|
Year Ended |
|
|
December 31, 2005 |
|
December 31, 2004 |
|
|
|
Number |
|
|
|
|
|
Number |
|
|
Trust Units Issued |
|
of units |
|
Amount |
|
of units |
|
Amount |
|
Balance, beginning of year |
|
|
73,325 |
|
|
$ |
1,123 |
|
|
|
123,873,651 |
|
|
$ |
1,872,924 |
|
Issued for cash |
|
|
|
|
|
|
|
|
|
|
10,900,000 |
|
|
|
200,560 |
|
Less: issue expenses |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(10,710 |
) |
Issued for cash on exercise of trust unit
options and rights |
|
|
|
|
|
|
|
|
|
|
547,974 |
|
|
|
8,735 |
|
Issued for cash under Distribution
Reinvestment Plan (DRIP) |
|
|
|
|
|
|
|
|
|
|
543,888 |
|
|
|
9,636 |
|
Trust unit rights incentive plan (non-cash
exercised) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
259 |
|
Royalty units exchanged for trust units |
|
|
|
|
|
|
|
|
|
|
700 |
|
|
|
|
|
|
Balance, prior to conversion |
|
|
|
|
|
|
|
|
|
|
135,866,213 |
|
|
$ |
2,081,404 |
|
Converted to Class A or Class B trust units |
|
|
(35,358 |
) |
|
|
(541 |
) |
|
|
(135,792,888 |
) |
|
|
( 2,080,281 |
) |
|
Balance, end of year |
|
|
37,967 |
|
|
$ |
582 |
|
|
|
73,325 |
|
|
$ |
1,123 |
|
|
On July 27, 2004 Pengrowth implemented a reclassification of its trust units whereby the
existing outstanding trust units were reclassified into Class A or Class B trust units depending on
the residency of the unitholder. Of the original trust units, 37,967 are undeclared trust units
that have
not been classified as Class A or Class B trust units as the unitholders of these trust units have
not submitted a declaration of residency certificate.
The Class A trust units and the Class B trust units have the same rights to vote and obtain
distributions upon wind-up or dissolution of the Trust. The most significant distinction between
the two classes of units is in respect of residency of the persons entitled to hold and trade the
Class A trust units and Class B trust units.
Class A trust units are not subject to any residency restriction but are subject to a restriction
on the number to be issued such that the total number of issued and outstanding Class A trust units
will not exceed 99 percent of the number issued and outstanding Class B trust units after an
initial implementation period (the Ownership Threshold). Class A trust units may be converted by
a holder at any time into Class B trust units provided that the holder is a resident of Canada and
- 45 -
provides a suitable residency declaration. Class A trust units trade on both the Toronto Stock
Exchange (TSX) and the New York Stock Exchange (NYSE).
Class B trust units may not be held by non-residents of Canada and trade only on the TSX. Class B
trust units may be converted by a holder into Class A trust units, provided that the Ownership
Threshold will not be exceeded.
If the number of issued and outstanding Class A trust units exceeds the Ownership Threshold, the
Trust may make a public announcement of the contravention and enforce one or several available
options to reduce the number of Class A trust units to the Ownership Threshold, as outlined in the
Trust Indenture.
If it appears from the securities registers, or if the Board of Directors of Corporation
determines, that a person that is a non-resident of Canada holds or beneficially owns any Class B
trust units, Pengrowth shall send a notice to the registered holder(s) of the Class B trust units
requiring such holder(s) to dispose of the Class B trust units and pending such disposition may
suspend all rights of ownership attached to such units, including the rights to receive
distributions.
Following the reclassification, the number of outstanding Class A trust units exceeded the
Ownership Threshold. On December 1, 2004, Pengrowth received a letter from the Canada Revenue
Agency that extended the date by which Pengrowth must comply with the Ownership Threshold to June
1, 2005. Pengrowth complied with the Ownership Threshold on April 29, 2005 and continued to comply
with the Ownership Threshold as of February 27, 2006.
Certain provisions exist that could prevent exclusionary offers being made for only one class of
trust units in existence at the time of the original offer. In the event that an offer is made for
only one class of trust units; in certain circumstances the Ownership Threshold would temporarily
cease to apply.
Pursuant to the terms of the Royalty Indenture and the Trust Indenture, there is attached to each
royalty unit granted by the Corporation to royalty unitholders other than the Trust the right to
exchange such royalty unit for an equivalent number of trust units. Accordingly, Computershare as
Trustee has reserved 18,240 trust units for such future conversion.
Distribution
Reinvestment Plan
Class B unitholders are eligible to participate in the Distribution Reinvestment Plan (DRIP). DRIP
entitles the unitholder to reinvest cash distributions in additional units of the Trust. The trust
units under the plan are issued from treasury at a five percent discount to the weighted average
closing price of all Class B trust units traded on the TSX for the 20 trading days
preceding a distribution payment date. Class A unitholders are not eligible to participate in DRIP.
Trust units issued on the exercise of options and rights under Pengrowths unit based compensation
plans are Class B trust units.
Contributed Surplus
|
|
|
|
|
|
|
|
|
|
|
2005 |
|
2004 |
|
Balance, beginning of year |
|
$ |
1,923 |
|
|
$ |
189 |
|
Trust unit rights incentive plan (non-cash expensed) |
|
|
1,740 |
|
|
|
2,264 |
|
Deferred entitlement trust units |
|
|
1,192 |
|
|
|
|
|
Trust unit rights incentive plan (non-cash exercised) |
|
|
(1,209 |
) |
|
|
(530 |
) |
|
Balance, end of year |
|
$ |
3,646 |
|
|
$ |
1,923 |
|
|
Trust Unit Option Plan
Pengrowth has a trust unit option plan under which directors, officers, employees and special
consultants of the Corporation and the Manager are eligible to receive options to purchase Class B
trust units. No new grants have been issued under the plan since November 2002. Under the
- 46 -
terms of the plan, up to ten percent of the issued and outstanding trust units, to a maximum of ten
million trust units, may be reserved for option and right grants. The options expire seven years
from the date of grant. One third of the options vest on the grant date, one third on the first
anniversary of the date of grant, and the remaining third on the second anniversary.
As
at December 31, 2005, options to purchase 259,317 Class B trust units were outstanding (2004
845,374) that expire at various dates to June 28, 2009.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2005 |
|
2004 |
|
|
|
|
|
|
|
Weighted |
|
|
|
|
|
Weighted |
|
|
Number |
|
average |
|
Number |
|
average |
Trust Unit Options |
|
of options |
|
exercise price |
|
of options |
|
exercise price |
|
Outstanding at beginning of year |
|
|
845,374 |
|
|
$ |
16.97 |
|
|
|
2,014,903 |
|
|
$ |
17.47 |
|
Exercised |
|
|
(558,307 |
) |
|
$ |
16.74 |
|
|
|
(838,789 |
) |
|
$ |
16.82 |
|
Expired |
|
|
(27,750 |
) |
|
$ |
18.63 |
|
|
|
(325,200 |
) |
|
$ |
20.44 |
|
Cancelled |
|
|
|
|
|
|
|
|
|
|
(5,540 |
) |
|
$ |
16.53 |
|
|
Outstanding at year-end |
|
|
259,317 |
|
|
$ |
17.28 |
|
|
|
845,374 |
|
|
$ |
16.97 |
|
|
Exercisable at year-end |
|
|
259,317 |
|
|
$ |
17.28 |
|
|
|
845,374 |
|
|
$ |
16.97 |
|
|
The following table summarizes information about trust unit options outstanding and exercisable at
December 31, 2005:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Options Outstanding and Exercisable |
|
|
|
|
|
|
|
Weighted Average |
|
|
Range of |
|
Number Outstanding |
|
Remaining Contractual |
|
Weighted Average |
Exercise Prices |
|
and Exercisable |
|
Life (years) |
|
Exercise Price |
|
$12.00 to $14.99 |
|
|
30,193 |
|
|
|
2.9 |
|
|
$ |
13.08 |
|
$15.00 to $16.99 |
|
|
38,139 |
|
|
|
2.7 |
|
|
$ |
15.05 |
|
$17.00 to $17.99 |
|
|
82,772 |
|
|
|
2.4 |
|
|
$ |
17.47 |
|
$18.00 to $20.50 |
|
|
108,213 |
|
|
|
1.9 |
|
|
$ |
19.09 |
|
|
$12.00 to $20.50 |
|
|
259,317 |
|
|
|
2.3 |
|
|
$ |
17.28 |
|
|
Trust
Unit Rights Incentive Plan
Pengrowth has a Trust Unit Rights Incentive Plan (Rights Incentive Plan), pursuant to which rights
to acquire Class B trust units may be granted to the directors, officers, employees, and special
consultants of the Corporation and the Manager. Under the Rights Incentive Plan, distributions per
trust unit to unitholders in a calendar quarter which represent a return of more than 2.5 percent
of the net book value of property, plant and equipment at the beginning of such calendar quarter
result, at the discretion of the holder, in a reduction in the exercise price. Total price
reductions calculated for 2005 were $1.49 per trust unit right (2004 $1.30 per trust unit right).
One third of the rights granted under the Rights Incentive Plan vest on the grant date, one third
on the first anniversary date of the grant and the remaining on the second anniversary. The rights
have an expiry date of five years from the date of grant.
As
at December 31, 2005, rights to purchase 1,441,737 Class B trust units were outstanding (2004
2,011,451) that expire at various dates to November 21, 2010.
- 47 -
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2005 |
|
2004 |
|
|
|
|
|
|
|
Weighted |
|
|
|
|
|
Weighted |
|
|
Number |
|
average |
|
Number |
|
average |
Trust Unit Rights |
|
of rights |
|
exercise price |
|
of rights |
|
exercise price |
|
Outstanding at beginning of year |
|
|
2,011,451 |
|
|
$ |
14.23 |
|
|
|
1,112,140 |
|
|
$ |
12.20 |
|
Granted (1) |
|
|
606,575 |
|
|
$ |
18.34 |
|
|
|
1,409,856 |
|
|
$ |
17.35 |
|
Exercised |
|
|
(953,904 |
) |
|
$ |
12.81 |
|
|
|
(456,049 |
) |
|
$ |
13.47 |
|
Cancelled |
|
|
(222,385 |
) |
|
$ |
16.19 |
|
|
|
(54,496 |
) |
|
$ |
14.19 |
|
|
Outstanding at year-end |
|
|
1,441,737 |
|
|
$ |
14.85 |
|
|
|
2,011,451 |
|
|
$ |
14.23 |
|
|
Exercisable at year-end |
|
|
668,473 |
|
|
$ |
13.73 |
|
|
|
1,037,078 |
|
|
$ |
12.48 |
|
|
|
|
|
(1) |
|
Weighted average exercise price of rights granted are based on the exercise price at the date of grant. |
The following table summarizes information about trust unit rights outstanding and exercisable
at December 31, 2005:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Rights Outstanding |
|
|
|
|
|
Rights Exercisable |
|
|
|
|
|
|
|
Weighted Average |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Remaining |
|
Weighted |
|
|
|
|
|
Weighted |
Range of |
|
Number |
|
Contractual Life |
|
Average |
|
Number |
|
Average |
Exercise Prices |
|
Outstanding |
|
(years) |
|
Exercise Price |
|
Exercisable |
|
Exercise Price |
|
$8.97 to $13.99 |
|
|
199,280 |
|
|
|
1.9 |
|
|
$ |
9.03 |
|
|
|
199,280 |
|
|
$ |
9.03 |
|
$14.00 to $15.99 |
|
|
549,620 |
|
|
|
3.1 |
|
|
$ |
14.01 |
|
|
|
223,339 |
|
|
$ |
14.01 |
|
$16.00 to $17.99 |
|
|
571,505 |
|
|
|
3.9 |
|
|
$ |
16.89 |
|
|
|
206,942 |
|
|
$ |
17.04 |
|
$18.00 to $20.99 |
|
|
121,332 |
|
|
|
4.8 |
|
|
$ |
18.65 |
|
|
|
38,912 |
|
|
$ |
18.68 |
|
|
$8.97 to $20.99 |
|
|
1,441,737 |
|
|
|
3.1 |
|
|
$ |
14.85 |
|
|
|
668,473 |
|
|
$ |
13.73 |
|
Fair
Value of Unit Based Compensation
Pengrowth records compensation expense on trust unit rights granted on or after January 1, 2003.
For trust unit options and rights granted in 2002, Pengrowth has elected to disclose the pro forma
effect on net income had compensation expense been recorded using the fair value method. All of
the trust unit options and rights issued in 2002 were fully vested prior to 2005, therefore there
is no pro forma effect on net income for 2005. The following is the pro forma effect on net income
in 2004:
|
|
|
|
|
|
|
2004 |
|
Net income |
|
$ |
153,745 |
|
Compensation expense related to rights
incentive options granted in 2002 |
|
|
(1,067 |
) |
|
Pro forma net income |
|
$ |
152,678 |
|
|
|
|
|
|
|
Pro forma net income per trust unit: |
|
|
|
|
Basic |
|
$ |
1.145 |
|
|
Diluted |
|
$ |
1.139 |
|
|
The fair value of trust unit rights granted in 2005 and 2004 was estimated at 15 percent of the
exercise price at the date of grant using a modified Black-Scholes option pricing model with the
following assumptions: risk-free rate of 3.9 percent, volatility
of 19 percent (2004 22
percent), expected life of five years and adjustments for the estimated distributions and
reductions in the exercise price over the life of the trust unit rights.
Long
Term Incentive Program
Effective January 1, 2005, the Board of Directors approved a Long Term Incentive Plan. The DEUs
issued under the plan fully vest and are converted to Class B trust units on the third anniversary
year from the date of grant and will receive deemed distributions prior to the vesting date in the
form of additional DEUs. However, the number of DEUs actually issued to each
- 48 -
participant at the end of the three year vesting period will be subject to a relative performance
test which compares Pengrowths three year average total return to the three year average total
return of a peer group of other energy trusts such that upon vesting, the number of Class B trust
units issued from treasury may range from zero to one and one-half times the number of DEUs
granted plus accrued DEUs through the deemed reinvestment of distributions.
Compensation expense related to DEUs is based on the fair value of the DEUs at the date of grant.
The number of Class B trust units awarded at the end of the vesting period is subject to certain
performance conditions. Compensation expense incorporates the estimated fair value of the DEUs at
the date of grant and an estimate of the relative performance multiplier. Fluctuations in
compensation expense may occur due to changes in estimating the outcome of the performance
conditions. An estimate of forfeiture has not been made; rather compensation expense is reduced for
actual forfeitures as they occur. Compensation expense is recognized in income over the vesting
period with a corresponding increase or decrease to Contributed Surplus. Upon issuance of the Class
B trust units at the end of the vesting period, trust unit holders capital is increased and
contributed surplus is reduced. For the 12 months ended December 31, 2005, Pengrowth recorded
compensation expense of $1.2 million associated with the DEUs. Compensation expense associated
with the DEUs was based on the weighted average estimated fair value of $18.32 per DEU.
|
|
|
|
|
|
|
Number of |
|
|
DEUs |
|
Outstanding, beginning of period |
|
|
|
|
Granted |
|
|
194,229 |
|
Cancelled |
|
|
(26,258 |
) |
Deemed DRIP |
|
|
17,620 |
|
|
Outstanding, end of period |
|
|
185,591 |
|
|
Trust Unit Award Plan
Effective July 13, 2005, Pengrowth established an incentive plan to reward and retain employees
whereby Class B trust units and cash were awarded to eligible employees. Employees received one
half of the trust units and cash on or about January 1, 2006 and will receive one half of the trust
units and cash on or about July 1, 2006. Any change in the market value of the Class B trust units
and reinvested distributions over the vesting period accrues to the eligible employees.
Pengrowth acquired the Class B trust units to be awarded under the plan on the open market for $4.3
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 one year. In addition, the cash portion of the
incentive plan of approximately $1.5 million is being accrued on a straight line basis over one
year. Any unvested trust units will be sold on the open market. During the six months ended
December 31, 2005 $2.9 million has been charged to net income.
Employee Savings Plans
Pengrowth has savings plans whereby Pengrowth will match contributions by qualifying employees of
zero to ten percent of their annual basic salary, less any of Pengrowths contributions to the
Group Registered Retirement Savings Plan (Group RRSP), to purchase trust units in the open market.
Participants in the Group RRSP can make contributions from one to 13 percent and Pengrowth will
match contributions to a maximum of five percent of their annual basic salary. Pengrowths share
of contributions to the Trust Unit Purchase Plan and Group RRSP were
$1.5 million in 2005 (2004
$1.3 million) and $0.5 million in 2005 (2004 $0.4 million), respectively.
- 49 -
Trust Unit Margin Purchase Plan
Pengrowth has a plan whereby the employees and certain consultants of Pengrowth and the Manager
can purchase trust units and finance up to 75 percent of the purchase price through an
investment dealer, subject to certain participation limits and restrictions. Certain officers
and directors hold trust units under the Trust Unit Margin Purchase Plan; however, they are
prohibited from increasing the number of trust units they can hold under the plan.
Participants maintain personal margin accounts with the investment dealer and are responsible
for all interest costs and obligations with respect to their margin loans.
Pengrowth has provided a $1 million letter of credit (2004 $5 million) to the investment
dealer to guarantee amounts owing with respect to the plan. The amount of the letter of credit
may fluctuate depending on the amounts financed pursuant to the plan. At December 31, 2005,
721,334 Class B trust units were deposited under the plan (2004
848,022) with a market value
of $16.3 million (2004 $15.7 million) and a
corresponding margin loan of $2.7 million (2004 $3.1 million).
The investment dealer has limited the total margin loan available under the plan to the lesser
of $15 million or 35 percent of the market value of the units held under the plan. If the
market value of the trust units under the plan declines, Pengrowth may be required to make
payments or post additional letters of credit to the investment dealer. Any payments to be
made by Pengrowth are to be reduced by proceeds of liquidating the individuals trust units
held under the plan. The maximum amount Pengrowth may be required to pay at December 31, 2005
was $2.7 million (2004 $3.1 million), the fair value of which is estimated to be a nominal
amount.
Redemption Rights
Trust units are redeemable at the option of the holder. The redemption price is equal to the
lesser of 95 percent of the market trading price of the Class B trust units traded on the TSX
for the ten trading days after the trust units have been surrendered for redemption and the
closing market price of the Class B trust units quoted on the TSX on the date the trust units
have been surrendered for redemption. Trust units can be redeemed for cash to a maximum of
$25,000 per month. Redemptions in excess of the cash limit must be satisfied by way of a
distribution in specie of a pro-rata share of royalty units and other assets, excluding
facilities, pipelines or other assets associated with oil and natural gas production, which are
held by the Trust at the time the trust units are to be redeemed.
11. DEFERRED CHARGES
|
|
|
|
|
|
|
|
|
|
|
2005 |
|
2004 |
|
Imputed interest on note payable (net of
accumulated amortization of $2,859, 2004
$1,587) |
|
$ |
748 |
|
|
$ |
2,020 |
|
U.S. debt issue costs (net of accumulated
amortization of $816, 2004 $510) |
|
|
1,325 |
|
|
|
1,631 |
|
Deferred compensation expense (net of
accumulated amortization of $2,143, 2004 nil) |
|
|
2,141 |
|
|
|
|
|
U.K. debt issue costs (net of accumulated
amortization of $5) |
|
|
672 |
|
|
|
|
|
|
|
|
$ |
4,886 |
|
|
$ |
3,651 |
|
|
- 50 -
12. FOREIGN EXCHANGE LOSS (GAIN)
|
|
|
|
|
|
|
|
|
|
|
2005 |
|
2004 |
|
Unrealized foreign exchange gain on
translation of U.S. dollar denominated debt |
|
$ |
(7,800 |
) |
|
$ |
(18,900 |
) |
Realized foreign exchange losses |
|
|
834 |
|
|
|
1,600 |
|
|
|
|
$ |
(6,966 |
) |
|
$ |
(17,300 |
) |
|
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.
13. OTHER CASH FLOW DISCLOSURES
Change in Non-Cash Operating Working Capital
|
|
|
|
|
|
|
|
|
Cash provided by (used for): |
|
2005 |
|
2004 |
|
Accounts receivable |
|
$ |
(21,511 |
) |
|
$ |
(22,515 |
) |
Inventory |
|
|
439 |
|
|
|
260 |
|
Accounts payable and accrued liabilities |
|
|
29,953 |
|
|
|
17,225 |
|
Due to Pengrowth Management Limited |
|
|
952 |
|
|
|
6,203 |
|
|
|
|
$ |
9,833 |
|
|
$ |
1,173 |
|
|
Change in Non-Cash Investing Working Capital
|
|
|
|
|
|
|
|
|
Cash provided by: |
|
2005 |
|
2004 |
|
Accounts payable for capital accruals |
|
$ |
1,117 |
|
|
$ |
2,169 |
|
|
Cash payments
|
|
|
|
|
|
|
|
|
|
|
2005 |
|
2004 |
|
Cash payments made for taxes(1) |
|
$ |
6,424 |
|
|
$ |
4,729 |
|
Cash payments made for interest |
|
$ |
21,779 |
|
|
$ |
28,119 |
|
|
|
|
|
(1) |
|
Capital and resource taxes |
14. INCOME TAXES
In 2003, the federal government implemented a reduction in federal corporate income tax rates
that is being phased in over a period of five years commencing 2003. The applicable tax rate
on resource income will be reduced from 28 percent to 21 percent. Additionally, crown
royalties will be an allowable deduction and the resource allowance will be eliminated.
As a result of the changes to the income tax rates, Pengrowths future tax rate applied to the
temporary differences is approximately 34 percent in 2005 (34 percent in 2004) compared to the
federal and provincial statutory rate of approximately 38 percent for the 2005 income tax year.
The provision for income taxes in the financial statements differs from the result which would have
been obtained by applying the combined federal and provincial tax rate to Pengrowths income before
taxes.
- 51 -
|
|
|
|
|
|
|
|
|
|
|
2005 |
|
2004 |
|
Income before taxes |
|
$ |
344,875 |
|
|
$ |
173,955 |
|
Combined federal and provincial tax rate |
|
|
37.6 |
% |
|
|
38.6 |
% |
|
Expected income tax |
|
|
129,673 |
|
|
|
67,147 |
|
Net income of the Trust |
|
|
(122,698 |
) |
|
|
(59,346 |
) |
Resource allowance |
|
|
(10,985 |
) |
|
|
(8,807 |
) |
Non-deductible crown charges |
|
|
22,756 |
|
|
|
16,476 |
|
Unrealized foreign exchange gain |
|
|
(1,623 |
) |
|
|
(3,648 |
) |
Attributed Canadian royalty income |
|
|
(3,541 |
) |
|
|
(3,113 |
) |
Effect of proposed tax changes |
|
|
|
|
|
|
3,850 |
|
Future tax rate difference |
|
|
(1,402 |
) |
|
|
(1,585 |
) |
Change in valuation allowance |
|
|
|
|
|
|
3,035 |
|
Other |
|
|
96 |
|
|
|
1,607 |
|
|
Future income taxes |
|
|
12,276 |
|
|
|
15,616 |
|
Capital taxes |
|
|
6,273 |
|
|
|
4,594 |
|
|
|
|
$ |
18,549 |
|
|
$ |
20,210 |
|
|
The net future income tax liability is comprised of:
|
|
|
|
|
|
|
|
|
|
|
2005 |
|
2004 |
|
Future income tax liabilities: |
|
|
|
|
|
|
|
|
Property, plant, equipment and other assets |
|
$ |
114,256 |
|
|
$ |
79,774 |
|
Unrealized foreign exchange gain |
|
|
9,689 |
|
|
|
8,378 |
|
Other |
|
|
110 |
|
|
|
|
|
|
|
|
|
124,055 |
|
|
|
88,152 |
|
Future income tax assets: |
|
|
|
|
|
|
|
|
Attributed Canadian royalty income |
|
|
(7,819 |
) |
|
|
(4,418 |
) |
Contract liabilities |
|
|
(6,124 |
) |
|
|
(8,072 |
) |
Other |
|
|
|
|
|
|
(34 |
) |
|
|
|
$ |
110,112 |
|
|
$ |
75,628 |
|
|
At December 31, 2005, the petroleum and natural gas properties and facilities owned by the
corporate subsidiaries of Pengrowth have an approximate tax basis of $634 million (2004 $607
million) available for future use as deductions from taxable income.
15. RELATED PARTY TRANSACTIONS
The Manager provides certain services pursuant to a management agreement for which
Pengrowth was charged $6.9 million (2004 $6.1 million) for performance fees and $9.1 million
(2004 $6.8 million) for a management fee. In addition, Pengrowth was charged $0.9 million
(2004 $0.8 million) for reimbursement of general and administrative expenses incurred by the
Manager pursuant to the management agreement. The law firm controlled by the Vice President
and Corporate Secretary charged $0.7 million (2004 $0.8 million) for legal and advisory
services provided to Pengrowth. The transactions have been recorded at the exchange amount.
Amounts payable to the related parties are unsecured, non-interest bearing and have no set terms
of repayment.
16. AMOUNTS PER TRUST UNIT
The per trust unit amounts for net income are based on the weighted average trust units
outstanding for the year. The weighted average trust units outstanding for 2005 were
157,127,181 trust units (2004 133,395,485 trust units). In computing diluted net income per
- 52 -
trust unit, 786,577 trust units were added to the weighted average number of trust units
outstanding during the year ended December 31, 2005 (2004 611,086) for the dilutive effect of
trust unit options, trust unit rights and DEUs. In 2005,
409,557 (2004 741,838) trust unit
options and rights were excluded from the diluted net income per unit calculation as their effect
is anti-dilutive.
17. FINANCIAL INSTRUMENTS
Interest Rate Risk
Pengrowth has minimal exposure to interest rate changes as approximately 90 percent of
Pengrowths long term debt at December 31, 2005 has fixed interest rates (Note 8).
At December 31, 2005 and 2004, there were no interest rate swaps outstanding.
Foreign Currency Exchange Risk
Pengrowth is exposed to foreign currency fluctuations as crude oil and natural gas prices received
are referenced to U.S. dollar denominated prices. Pengrowth has mitigated some of this exchange
risk by entering into fixed Canadian dollar crude oil and natural gas price swaps as outlined in
the forward and futures contracts section below. Pengrowth is exposed to foreign currency
fluctuation on the U.S. denominated notes for both interest and principal payments.
Pengrowth entered into a foreign exchange swap in conjunction with issuing £50 million of ten
year term notes (Note 8) which fixed the Cdn$ to £ exchange rate on the interest and principal of
the £ denominated debt at approximately £0.4976 per Canadian dollar. 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 year-end. At December 31, 2005, the amount Pengrowth
would pay to terminate the foreign exchange swap would be approximately $2.2 million.
At December 31, 2004, there were no foreign currency exchange swaps outstanding.
Credit Risk
Pengrowth sells a significant portion of its oil and gas to commodity marketers, and the accounts
receivable are subject to normal industry credit risks. The use of financial swap agreements
involves a degree of credit risk that Pengrowth manages through its credit policies which are
designed to limit eligible counterparties to those with A credit ratings or better.
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 December 31, 2005, Pengrowth had fixed the price applicable to future production as
follows:
Crude Oil:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Volume |
|
Reference |
|
Price |
Remaining Term |
|
(bbl/d) |
|
Point |
|
per bbl |
Financial: |
|
|
|
|
|
|
|
|
|
|
|
|
Jan 1, 2006
Dec 31, 2006 |
|
|
4,000 |
|
|
WTI (1) |
|
$64.08 Cdn |
- 53 -
Natural Gas:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Volume |
|
Reference |
|
Price |
Remaining Term |
|
(mmbtu/d) |
|
Point |
|
per mmbtu |
Financial: |
|
|
|
|
|
|
|
|
|
|
|
|
Jan 1, 2006 Mar 31, 2006 |
|
|
2,500 |
|
|
NYMEX (1) |
|
$14.56 Cdn |
Jan 1, 2006 Dec 31, 2006 |
|
|
2,500 |
|
|
Transco Z6(1) |
|
$10.63 Cdn |
Jan 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 year end. At
December 31, 2005, the amount Pengrowth would pay to terminate the financial crude oil and
natural gas contracts would be $13.0 million and $5.4 million, respectively.
Natural Gas Fixed Price Sales Contract:
Pengrowth assumed a natural gas fixed price sales contract in conjunction with the Murphy
acquisition. At December 31, 2005, the amount Pengrowth would pay to terminate the fixed
price sales contract would be $35.3 million. Details of the physical fixed price sales contract are
provided below:
|
|
|
|
|
|
|
|
|
|
|
Volume |
|
Price |
Remaining Term |
|
(mmbtu/d) |
|
per mmbtu(1) |
2006 to 2009 |
|
|
|
|
|
|
|
|
Jan 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 April 30, 2009 |
|
|
3,886 |
|
|
$2.40 Cdn |
|
|
|
(1) |
|
Reference price based on AECO |
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 note payable at December 31, 2005 and 2004 approximated its
carrying value net of the imputed interest included in deferred charges. The fair value of the
other financial instruments are as follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
As at December 31, 2005 |
|
As at December 31, 2004 |
|
|
|
|
|
Net Book |
|
|
|
Net Book |
|
Fair Value |
|
|
Value |
|
Fair Value |
|
Value |
|
Remediation Funds |
|
$ |
9,071 |
|
|
$ |
8,329 |
|
|
$ |
8,366 |
|
|
$ |
8,309 |
|
U.S. dollar denominated debt |
|
|
220,187 |
|
|
|
232,600 |
|
|
|
238,726 |
|
|
|
240,400 |
|
£ denominated debt |
|
|
101,257 |
|
|
|
100,489 |
|
|
|
|
|
|
|
|
|
|
18. COMMITMENTS
Pengrowth has future commitments under various agreements for oil and natural gas pipeline
transportation, the purchase of carbon dioxide and operating leases. The commitment to purchase
carbon dioxide arises as a result of Pengrowths working
interest in the Weyburn CO2
miscible flood project(1). Capital expenditures arise from authorized expenditures at SOEP.
- 54 -
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2006 |
|
2007 |
|
2008 |
|
2009 |
|
2010 |
|
Thereafter |
|
Total |
|
Pipeline
transportation |
|
$ |
43,839 |
|
|
$ |
38,197 |
|
|
$ |
34,981 |
|
|
$ |
29,813 |
|
|
$ |
11,748 |
|
|
$ |
53,525 |
|
|
$ |
212,103 |
|
Capital expenditures |
|
|
33,323 |
|
|
|
7,098 |
|
|
|
294 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
40,715 |
|
CO2 purchases |
|
|
5,119 |
|
|
|
4,357 |
|
|
|
4,198 |
|
|
|
4,232 |
|
|
|
4,267 |
|
|
|
18,728 |
|
|
|
40,901 |
|
Other commitments |
|
|
3,132 |
|
|
|
3,096 |
|
|
|
3,950 |
|
|
|
3,610 |
|
|
|
3,377 |
|
|
|
32,779 |
|
|
|
49,944 |
|
|
|
|
$ |
85,413 |
|
|
$ |
52,748 |
|
|
$ |
43,423 |
|
|
$ |
37,655 |
|
|
$ |
19,392 |
|
|
$ |
105,032 |
|
|
$ |
340,663 |
|
|
|
|
|
(1) |
|
Contract prices for CO2 are denominated in U.S. dollars and have been translated at
the year end foreign exchange rate. |
19. SUBSEQUENT EVENT
On January 12, 2006, Pengrowth announced certain transactions with Monterey under which
Pengrowth has sold oil and gas properties for $22 million of cash and eight million shares in
Monterey. As at February 27, 2006 Pengrowth holds approximately 34 percent of the common
shares of Monterey.
20. RECONCILIATION OF FINANCIAL STATEMENTS TO UNITED STATES GENERALLY
ACCEPTED ACCOUNTING PRINCIPLES
The significant differences between Canadian generally accepted accounting principles (Canadian
GAAP) which, in most respects, conforms to generally accepted accounting principles in the
United States (U.S. GAAP), as they apply to Pengrowth, are as follows:
|
(a) |
|
As required annually under U.S. GAAP, the carrying value of petroleum and natural gas
properties and related facilities, net of future or deferred income taxes, is limited to the
present value of after tax future net revenue from proven reserves, discounted at ten percent
(based on prices and costs at the balance sheet date), plus the lower of cost and fair value of
unproven properties. At December 31, 1998 and 1997 the application of the full cost
ceiling test under U.S. GAAP resulted in a write-down of capitalized costs of $328.6
million and $49.8 million, respectively. At December 31, 2005 and 2004, the application of
the full cost ceiling test under U.S. GAAP did not result in a write-down of capitalized
costs. |
Where the amount of a ceiling test write-down under Canadian GAAP differs from the
amount of the write-down under U.S. GAAP, the charge for depletion will differ in
subsequent years.
|
(b) |
|
Under U.S. GAAP, interest and other income would not be included as a component of Net Revenue. |
|
|
(c) |
|
Effective January 1, 2003, Pengrowth prospectively adopted U.S. standards relating to
recognizing the compensation expense associated with trust unit based compensation plans.
Under U.S. GAAP Pengrowth adopted the following: |
|
(i) |
|
For trust unit options granted on or after January 1, 2003, the estimated fair value
of the options is recognized as an expense over the vesting period. The
compensation expense associated with trust unit options granted prior to January
1, 2003 is disclosed on a pro forma basis. As of January 1, 2005 all trust unit
options were fully vested, thus there is no pro forma expense disclosed for 2005. |
|
|
(ii) |
|
For trust unit rights granted on or after January 1, 2003, the estimated fair value of
the rights, determined using a modified Black-Scholes option pricing model, is
recognized as an expense over the vesting period. The compensation expense
associated with the rights granted prior to January 1, 2003 is disclosed on a pro |
- 55 -
forma basis. As of January 1, 2005 all trust unit rights issued before January 1,
2003 are fully vested, thus there is no pro forma expense disclosed for 2005.
The following is the pro forma effect of trust unit options and rights granted prior to
January 1, 2003, had the fair value method of accounting been used:
|
|
|
|
|
Year ended December 31, |
|
2004 |
|
Net income
(loss) U.S. GAAP, as reported |
|
$ |
180,045 |
|
Compensation expense related to rights incentive
options granted prior to January 1, 2003 |
|
|
(1,067 |
) |
|
Pro forma
net income U.S. GAAP |
|
$ |
178,978 |
|
|
|
|
|
|
|
Pro forma net income U.S. GAAP per trust unit: |
|
|
|
|
|
Basic |
|
$ |
1.34 |
|
|
Diluted |
|
$ |
1.34 |
|
|
(d) |
|
Statement of Financial Accounting Standards (SFAS) 130 requires the reporting of
comprehensive income in addition to net income. Comprehensive income includes net income
plus other comprehensive income; specifically, all changes in equity of a company during a
period arising from non-owner sources. |
|
(e) |
|
SFAS 133, Accounting for Derivative Instruments and Hedging Activities establishes
accounting and reporting standards for derivative instruments and for hedging activities. This
statement requires an entity to establish, at the inception of a hedge, the method it will use for
assessing the effectiveness of the hedging derivative and the measurement approach for
determining the ineffective aspect of the hedge. Those methods must be consistent with the
entitys approach to managing risk. |
At December 31, 2005, $18.4 million has been recorded as a current liability in respect of the
fair value of financial crude oil and natural gas hedges outstanding at year end with a
corresponding change in accumulated other comprehensive income. At December 31, 2004,
$7.3 million has been recorded as a current asset in respect of the fair value of the financial
crude oil and natural gas hedges outstanding at year end with a corresponding change in
accumulated other comprehensive income. These amounts will be recognized against crude
oil and natural gas sales over the remaining terms of the related hedges.
At December 31, 2005, $0.3 million has been recorded as a current liability with respect to
the ineffective portion of crude oil and natural gas hedges outstanding at year end, with a
corresponding change in net income. At December 31, 2004, the ineffective portion of crude
oil and natural gas hedges outstanding at year end was not significant.
At December 31, 2005, Pengrowth recorded a loss of $2.2 million relating to the foreign
currency swap associated with the issuance of the £ denominated debt. As of February 14,
2006, Pengrowth had adequate documentation in place to account for the foreign currency
contract as a hedge under U.S. GAAP.
At December 31, 2004, there were no foreign exchange swaps outstanding.
(f) |
|
Under U.S. GAAP the Trusts equity is classified as redeemable equity as the Trust units are
redeemable at the option of the holder. The redemption price is equal to the lesser of 95
percent of the market trading price of the Class B trust units traded on the TSX for the ten |
- 56 -
trading days after the trust units have been surrendered for redemption and the closing market
price of the Class B trust units quoted on the TSX on the date the trust units have been
surrendered for redemption. Prior to the reclassification of trust units into Class A or Class B
trust units, the trust units were redeemable as described above except the redemption price
was based on the market trading price of the original trust units. Trust units can be redeemed
for cash to a maximum of $25,000 per month. Redemptions in excess of the cash limit must
be satisfied by way of a distribution in Specie of a pro-rata share of royalty units and other
assets, excluding facilities, pipelines or other assets associated with oil and natural gas
production, which are held by the Trust at the time the trust units are to be redeemed.
(g) |
|
Under U.S. standards, an entity that is subject to income tax in multiple jurisdictions is
required to disclose income tax expense at each jurisdiction. Pengrowth is subject to tax at
the federal and provincial level. The portion of income tax expense taxed at the federal level
is $12.9 million (2004 $14.8 million). The portion of income tax expense taxed at the
provincial level is $5.7 million (2004 $5.4 million). |
|
(h) |
|
In December 2004, the FASB issued SFAS 153 which deals with the accounting for the
exchanges of non-monetary assets. SFAS 153 is an amendment of APB Opinion 29. APB
Opinion 29 requires that exchanges of non-monetary assets should be measured based on the
fair value of the assets exchanged. SFAS 153 amends APB Opinion 29 to eliminate the
exception from using fair market value for non-monetary exchanges of similar productive
assets and introduce a broader exception for exchanges of non-monetary assets that do not
have commercial substance. SFAS 153 is effective for non-monetary asset exchanges
occurring in fiscal periods beginning after June 15, 2005. Adopting the provisions of SFAS
153 is not expected to impact the U.S. GAAP financial statements. |
In December 2004, the FASB issued SFAS 123R which deals with the accounting for
transactions in which an entity exchanges its equity instruments for goods or services.
SFAS 123R also addresses transactions in which an entity incurs liabilities in exchange for
goods or services that are based on the fair value of the entitys equity instruments or that
may be settled by the issuance of those equity instruments. SFAS 123R focuses primarily on
accounting for transactions in which an entity obtains employee services in share-based
payment transactions. SFAS 123R is a revision of SFAS 123. SFAS 123R requires a public
entity to measure the cost of employee services received in exchange for an award of equity
instruments based on the grant-date fair value of the award (with limited exceptions). That
cost will be recognized over the period during which an employee is required to provide
service in exchange for the awardthe requisite service period (usually the vesting period).
Since January 1, 2004 Pengrowth has recognized the costs of equity instruments issued in
exchange for employee services based on the grant-date fair value of the award (Note 2), in
accordance with Canadian GAAP. The methodology for determining fair value of equity
instruments issued in exchange for employee services prescribed by SFAS 123R differs
from that prescribed by Canadian GAAP. SFAS 123R is effective for exchanges in equity
instruments in exchanges for goods or services occurring in fiscal years beginning after June
15, 2005. Adopting the provisions of SFAS 123R is not expected to have a material impact
on the U.S. GAAP financial statements.
In May 2005 FASB issued SFAS 154 which deals with the accounting for all voluntary
changes in accounting principles as well as changes required by accounting pronouncements
that do not include specific transition provisions. SFAS 154 requires retrospective
application to prior periods financial statements of changes in accounting principle, unless
it is impracticable to determine either the period-specific effects or the cumulative effect of
the change. This Statement defines retrospective application as the application of a different
- 57 -
accounting principle to prior accounting periods as if that principle had always been used or
as the adjustment of previously issued financial statements to reflect a change in the
reporting entity. This Statement also redefines restatement as the revising of previously
issued financial statements to reflect the correction of an error. SFAS 123R is effective for
changes in accounting pronouncements effective in fiscal years beginning after December
15, 2005. Adopting SFAS 154 is not expected to have a material impact on the U.S. GAAP
financial statements.
Consolidated Statements of Income
The application of U.S. GAAP would have the following effect on net income as reported:
Stated in thousands of Canadian Dollars, except per trust unit amounts
|
|
|
|
|
|
|
|
|
Years ended December 31, |
|
2005 |
|
|
2004 |
|
|
Net income for the year, as reported |
|
$ |
326,326 |
|
|
$ |
153,745 |
|
|
|
|
|
|
|
|
|
|
Adjustments: |
|
|
|
|
|
|
|
|
Depletion and depreciation (a) |
|
|
24,723 |
|
|
|
26,000 |
|
Unrealized gain (loss) on ineffective portion
of oil and natural gas hedges (e) |
|
|
(255 |
) |
|
|
300 |
|
Realized loss on foreign exchange contract (e) |
|
|
(2,204 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income
U.S. GAAP |
|
$ |
348,590 |
|
|
$ |
180,045 |
|
|
|
|
|
|
|
|
|
|
Other comprehensive income: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Realized gain on foreign exchange swap (d)(e) |
|
|
|
|
|
|
(2,169 |
) |
Unrealized hedging gain (loss) (d)(e) |
|
|
(25,470 |
) |
|
|
21,186 |
|
|
|
|
|
|
|
|
|
|
|
Comprehensive income U.S. GAAP |
|
$ |
323,120 |
|
|
$ |
199,062 |
|
|
|
|
|
|
|
|
|
|
|
Net income
U.S. GAAP |
|
|
|
|
|
|
|
|
Basic |
|
$ |
2.22 |
|
|
$ |
1.35 |
|
Diluted |
|
$ |
2.21 |
|
|
$ |
1.34 |
|
|
|
|
|
|
|
|
|
|
|
- 58 -
Consolidated Balance Sheets
The application of U.S. GAAP would have the following effect on the Balance Sheets as reported:
Stated in thousands of Canadian Dollars
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
As |
|
|
Increase |
|
|
|
|
December 31, 2005 |
|
Reported |
|
|
(Decrease) |
|
|
U.S. GAAP |
|
|
Assets: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Capital assets (a) |
|
|
2,067,988 |
|
|
|
(192,219 |
) |
|
|
1,875,769 |
|
|
|
|
|
|
|
|
$ |
(192,219 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Liabilities |
|
|
|
|
|
|
|
|
|
|
|
|
Accounts payable |
|
$ |
111,493 |
|
|
$ |
255 |
|
|
$ |
111,748 |
|
Current portion of unrealized hedging loss (e) |
|
|
|
|
|
|
18,153 |
|
|
|
18,153 |
|
Current
portion of unrealized foreign currency contract (e) |
|
|
|
|
|
|
2,204 |
|
|
|
2,204 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Unitholders equity (f): |
|
|
|
|
|
|
|
|
|
|
|
|
Accumulated other comprehensive income (d)(e) |
|
$ |
|
|
|
$ |
(18,153 |
) |
|
$ |
(18,153 |
) |
Trust Unitholders Equity (a) |
|
|
1,475,996 |
|
|
|
(194,678 |
) |
|
|
1,281,318 |
|
|
|
|
|
|
|
|
$ |
(192,219 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
As |
|
|
Increase |
|
|
|
|
December 31, 2004 |
|
Reported |
|
|
(Decrease) |
|
|
U.S. GAAP |
|
|
Assets: |
|
|
|
|
|
|
|
|
|
|
|
|
Current portion of unrealized hedging gain (e) |
|
$ |
|
|
|
$ |
7,317 |
|
|
$ |
7,317 |
|
Capital assets (a) |
|
|
1,989,288 |
|
|
|
(216,942 |
) |
|
|
1,772,346 |
|
|
|
|
|
|
|
|
$ |
(209,625 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Unitholders equity (f): |
|
|
|
|
|
|
|
|
|
|
|
|
Accumulated other comprehensive income (d)(e) |
|
$ |
|
|
|
$ |
7,317 |
|
|
$ |
7,317 |
|
Trust Unitholders Equity (a) |
|
|
1,462,211 |
|
|
|
(216,942 |
) |
|
|
1,245,269 |
|
|
|
|
|
|
|
|
$ |
(209,625 |
) |
|
|
|
|
|
- 59 -
Additional disclosures required under U.S. GAAP
The components of accounts receivable are as follows:
|
|
|
|
|
|
|
|
|
|
|
As at December 31, |
|
|
|
2005 |
|
|
2004 |
|
|
Trade |
|
$ |
103,619 |
|
|
$ |
77,778 |
|
Prepaids |
|
|
20,230 |
|
|
|
15,378 |
|
Other |
|
|
3,545 |
|
|
|
11,072 |
|
|
|
|
|
|
|
|
|
|
|
|
|
$ |
127,394 |
|
|
$ |
104,228 |
|
|
The components of accounts payable and accrued liabilities are as follows:
|
|
|
|
|
|
|
|
|
|
|
As at December 31, |
|
|
|
2005 |
|
|
2004 |
|
|
Accounts payable |
|
$ |
50,756 |
|
|
$ |
37,588 |
|
Accrued liabilities |
|
|
60,737 |
|
|
|
42,835 |
|
|
|
|
|
|
|
|
|
|
|
|
|
$ |
111,493 |
|
|
$ |
80,423 |
|
|