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 October 27, 2006 to November 2, 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 third quarter 2006 results |
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2. |
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Press Release announcing offer to purchase outstanding convertible debentures |
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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November 2, 2006 |
By: |
/s/ Gordon M. Anderson
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Name: |
Gordon M. Anderson |
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Title: |
Vice President |
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NEWS RELEASE
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Attention: Financial Editors Stock Symbol: |
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(PGF.UN) - TSX; (PGH) NYSE |
PENGROWTH ENERGY TRUST ANNOUNCES
THIRD QUARTER 2006 RESULTS
(Calgary, November 1, 2006) /CCNMatthews/ Pengrowth Corporation, administrator of Pengrowth
Energy Trust (collectively Pengrowth), is pleased to announce the interim unaudited operating and
financial results for the three and nine month periods ended September 30, 2006.
Average daily production increased four percent to 58,344 boe per day in the third quarter of
2006 from 56,325 boe per day in the second quarter and remained relatively stable when compared to
the third quarter of 2005. The increase is mainly attributable to improved volumes at the Sable
Offshore Energy Project after second quarter operational curtailments and new production from the
Prespatou and heavy oil areas. Pengrowth has increased its full year production outlook to 62,500
to 63,500 boe per day which incorporates production additions from the Dunvegan and Carson Creek
area acquisitions, the Esprit Energy Trust business combination and anticipated production
additions from planned 2006 development activities, excluding the impact from other future
acquisitions or divestitures.
During the quarter, Pengrowth generated $143.3 million ($0.89 per average trust unit
outstanding) of distributable cash from operations and distributions to unitholders
totaled $0.75 per trust unit.
Pengrowths average realized price after hedging decreased two percent to $53.67 per boe in
the third quarter of 2006 when compared to $54.91 per boe recorded in the second quarter of 2006
and four percent when compared to the same period in 2005 when $56.07 was recorded. The decrease is
due mainly to the continuing decline in natural gas prices and the negative impact of the strong
Canadian dollar on relatively robust crude oil prices.
During the third quarter, Pengrowth successfully completed an acquisition from Exxon Mobil
Canada Energy of the shares of a wholly owned subsidiary company that owned and controlled assets
in the Carson Creek area in central Alberta for a total purchase price of $475 million prior to
adjustments.
The Carson Creek assets provide
Pengrowth with ownership in one of the larger conventional original oil-in-place reservoirs
in the Western Canadian Sedimentary Basin, are in close proximity to Pengrowths existing Judy
Creek and Swan Hills properties, and add approximately 19 million boe of proved plus probable
reserves and approximately 5,100 boe per day of mainly high-quality, light crude oil production.
Subsequent to quarter-end, Pengrowth also successfully completed the business combination
with Esprit Energy Trust, which closed on October 2, 2006. This combination capitalized on the
opportunity to acquire long life natural gas assets in an environment of lower natural gas prices.
As a result of the combination, Pengrowth acquired approximately 18,350 boe per day of current
production, 71.7 million boe of proved plus probable oil and natural gas reserves and 250,000 net
acres of undeveloped land, including shallow gas and coalbed methane potential.
Presidents Message
To our valued unitholders,
I am pleased to announce the unaudited quarterly results for the three months and nine months ended
September 30, 2006. The third quarter of 2006 was characterized by Pengrowths commitment to
providing stable distributions to unitholders while executing its business plan for continued
growth and success in both its operational activities and financial results.
In my annual letter dated February 27, 2006, I stated that Pengrowths objectives for the year
ahead would be focused upon:
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1. |
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continuing to seek out high-quality acquisitions which target areas in which we already
hold significant interests including large oil-in-place reservoirs, shallow gas properties
with additional development potential and areas with coalbed methane prospects; and |
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2. |
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to capitalize on organic growth opportunities including an increased concentration on
exploiting our existing asset base, aggressively pursuing improved reserve recovery potential
and enhancing operational efficiencies. |
I am pleased to report that Pengrowth achieved success in both areas.
During the third quarter, Pengrowth successfully completed an acquisition from Exxon Mobil Canada
Energy of the shares of a wholly owned subsidiary company which owned and controlled assets in the
Carson Creek area in central Alberta for a total purchase price of $475 million prior to
adjustments. The Carson Creek acquisition was in line with our strategic direction and further
strengthened Pengrowths high-quality asset base.
The Carson Creek assets provide Pengrowth with ownership in one of the larger conventional original
oil-in-place reservoirs in the Western Canadian Sedimentary Basin and they are in close proximity
to Pengrowths existing Judy Creek and Swan Hills properties. The acquisition expands our strategic
focus area in light crude oil; provides anticipated field operating synergies; further development
potential; and is expected to improve overall efficiencies for both the Judy Creek and Carson Creek
facilities. The acquisition adds approximately 19 million barrels of oil equivalent (boe) of proved
plus probable reserves and approximately 5,100 boe per day of mainly high-quality, light crude oil
production.
In conjunction with the Carson Creek acquisition, Pengrowth completed a bought deal equity offering
in which 23,310,000 trust units were issued at $22.60 per trust unit for gross proceeds of
$526,806,000. The majority of the net proceeds from the offering were used to fund the acquisition,
with the remaining net proceeds being applied against Pengrowths revolving credit facility or for
general corporate purposes.
Subsequent to quarter-end, Pengrowth also successfully completed the business combination with
Esprit Energy Trust, which closed on October 2, 2006. This combination illustrated our commitment
to capitalize on counter-cyclical acquisitions as evidenced by acquiring these long life natural
gas assets in the current environment of lower natural gas prices. As a result of the combination,
Pengrowth acquired approximately 18,350 boe per day of current production, 71.7 million boe of
proved plus probable oil and natural gas reserves and 250,000 net acres of undeveloped land,
including shallow gas and coalbed methane potential.
The Esprit assets are highly concentrated with seven properties making up over 70 percent of the
corporate total and are of a high quality with a proved plus probable reserve life index of 10.5
years. Esprits net undeveloped acreage position adds approximately 60 percent to Pengrowths
existing undeveloped land base to total approximately 660,000 net acres. This large land base is
expected to provide significant upside to the trust based on the growth and development
opportunities associated with it.
The combination of these acquisitions is accretive to unitholders on all significant metrics
including distributable
cash, production and reserves per trust unit. Pengrowth also expects to realize additional value
through infill development drilling opportunities, drilling on undeveloped lands and enhanced oil
recovery potential. Pengrowths anticipated fourth quarter production is now approximately 79,000
boe per day which represents a slight decrease relative to our previous 81,000 boe per day estimate
due to a combination of temporary third-party facility restrictions at Willesden Green and Three
Hills; on-going well remediation and optimization work in Carson Creek; and weather-related delays
in drilling and tie-ins across most areas. The trust retains an above sector average reserve life
index of 10.6 years and the production mix will remain balanced at approximately 51 percent natural
gas with the remainder in oil and natural gas liquids. The combination of our operations teams
provides additional resources and technical expertise to take advantage of our expanded inventory
of organic growth opportunities.
In the third quarter of 2006, Pengrowth continued to focus on enhancing its business through
internal development opportunities including the further exploitation of our asset base and the
active pursuit of improved reserve recovery. This was apparent in third quarter average daily
production which increased four percent quarter over quarter. The increase is attributable to not
only improved volumes at the Sable Offshore Energy Project but also our internal development
program with new production additions from the Prespatou and the
heavy oil areas.
We have raised our forecast for full year production to 62,500 to 63,500 boe per day which not only
reflects the production associated with the Esprit and Carson Creek area acquisitions but also
includes anticipated production additions from planned 2006 development activities. Pengrowth has
spent approximately $179 million in the first three quarters of the year on its maintenance and
development program with the majority of its development program directed at increasing production and
improving reserve recovery through infill drilling. The 2006 capital program has been increased to
$280 million, mainly reflecting additional capital related to the addition of the Esprit business
combination.
During the third quarter, development capital totaled $56.8 million with approximately 75 percent
directed towards drilling and completions. Pengrowths development program provided strong results
during the quarter which included drilling 93 gross wells (43.7 net) with a 94 percent success
rate.
Production testing of the new Quirk Creek gas well, in which Pengrowth holds a 68 percent working
interest, was completed and has commenced production in October at a restricted rate of
approximately 5 mmcf per day (3.4 mmcf per day net). We have also had some good success in our
two-phase coalbed methane project in the Twining area of southern Alberta. In Phase 1, 11 wells
were completed and five of these wells were tied in and are expected to begin production in the
fourth quarter. The second phase consists of a 50 well program and during the third quarter
Pengrowth drilled ten wells with an average working interest of 61 percent. Partners in the area
drilled an additional 17 wells of which 15 are expected to be completed for production and the
remaining two to come on stream in the fourth quarter. In addition, we have had reasonable success
in the development of the new miscible flood pattern at Judy Creek which has continued to provide
positive returns.
Pengrowths high quality, long-life assets have provided the trust with a stable production profile
that is reflected in the steady distribution provided to unitholders. Distributable cash generated
from operations remained relatively flat in the third quarter at $143 million ($0.89 per average
trust unit outstanding) compared with $149 million ($0.93 per trust unit) in the second quarter of
2006. Distributions to unitholders during the quarter totaled $0.75 per trust unit.
The Honourable Jim Flaherty, Canadian Minister of Finance, made an announcement yesterday outlining
proposed changes to the taxation of income trusts. In his announcement, Mr. Flaherty included a
proposed tax on distributions paid on publicly traded income trusts and limited partnerships. As
Pengrowth is an existing, publicly traded income trust these proposed changes would not affect
Pengrowth until 2011. At this stage, this remains a proposal and would need to be approved by the
Canadian government before becoming legislation. Pengrowth will continue to pay close attention to
the governments stance on taxing distributions from income trusts and any potential impact this
may have on Pengrowth and its stakeholders.
The past quarter has been a period of significant growth and change for the trust with considerable
challenges and opportunities evident ahead. Our skilled and experienced team of employees has
increased substantially and along with our talented leadership team and Board of Directors, we
remain dedicated to meeting these challenges head on and exploiting opportunities fully with
innovative strategies focused on long term growth. I would like to offer my sincere appreciation to
our team for their efforts thus far in 2006 and I look forward to continuing to work with them in
striving towards providing unitholders with continued solid returns and superior value.
James S. Kinnear
Chairman, President and Chief Executive Officer
November 1, 2006
Summary of Financial and Operating Results
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Three Months ended |
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Nine Months ended |
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September 30 |
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% |
|
September 30 |
|
% |
(thousands, except per unit amounts) |
|
2006 |
|
2005 |
|
Change |
|
2006 |
|
2005 |
|
Change |
|
INCOME STATEMENT |
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|
|
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|
|
|
|
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Oil and gas sales |
|
$ |
287,757 |
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|
$ |
304,484 |
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|
|
-5 |
% |
|
$ |
863,185 |
|
|
$ |
797,587 |
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|
|
8 |
% |
Net income |
|
$ |
82,542 |
|
|
$ |
100,243 |
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|
|
-18 |
% |
|
$ |
258,993 |
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|
$ |
209,663 |
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|
|
24 |
% |
Net income per trust unit |
|
$ |
0.51 |
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|
$ |
0.63 |
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|
|
-19 |
% |
|
$ |
1.61 |
|
|
$ |
1.34 |
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|
|
20 |
% |
|
CASH FLOW |
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|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash flows from operating activities |
|
$ |
174,294 |
|
|
$ |
158,976 |
|
|
|
10 |
% |
|
$ |
484,219 |
|
|
$ |
421,482 |
|
|
|
15 |
% |
Cash flows from operating activities per trust unit |
|
$ |
1.08 |
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|
$ |
1.00 |
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|
|
8 |
% |
|
$ |
3.01 |
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|
$ |
2.70 |
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|
|
11 |
% |
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|
|
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|
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|
|
Distributable cash * |
|
$ |
143,347 |
|
|
$ |
162,009 |
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|
|
-12 |
% |
|
$ |
436,604 |
|
|
$ |
423,860 |
|
|
|
3 |
% |
Distributable cash per trust unit * |
|
$ |
0.89 |
|
|
$ |
1.02 |
|
|
|
-13 |
% |
|
$ |
2.72 |
|
|
$ |
2.71 |
|
|
|
0 |
% |
Distributions paid or declared |
|
$ |
132,513 |
|
|
$ |
109,853 |
|
|
|
21 |
% |
|
$ |
373,412 |
|
|
$ |
326,119 |
|
|
|
15 |
% |
Distributions paid or declared per trust unit |
|
$ |
0.75 |
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|
$ |
0.69 |
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|
|
9 |
% |
|
$ |
2.25 |
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|
$ |
2.07 |
|
|
|
9 |
% |
Payout ratio* |
|
|
92 |
% |
|
|
68 |
% |
|
|
24 |
% |
|
|
86 |
% |
|
|
77 |
% |
|
|
9 |
% |
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Development capital |
|
$ |
56,774 |
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|
$ |
40,848 |
|
|
|
39 |
% |
|
$ |
179,028 |
|
|
$ |
115,600 |
|
|
|
55 |
% |
Development capital per trust unit |
|
$ |
0.35 |
|
|
$ |
0.26 |
|
|
|
35 |
% |
|
$ |
1.11 |
|
|
$ |
0.74 |
|
|
|
50 |
% |
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|
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|
|
|
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|
|
|
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|
Weighted average number of trust units outstanding |
|
|
161,502 |
|
|
|
158,789 |
|
|
|
2 |
% |
|
|
160,753 |
|
|
|
156,318 |
|
|
|
3 |
% |
|
BALANCE SHEET |
|
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|
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|
|
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Working capital |
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|
|
|
|
|
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|
$ |
(139,799 |
) |
|
$ |
(77,528 |
) |
|
|
80 |
% |
Property, plant and equipment |
|
|
|
|
|
|
|
|
|
|
|
|
|
$ |
2,556,802 |
|
|
$ |
2,090,399 |
|
|
|
22 |
% |
Long term debt |
|
|
|
|
|
|
|
|
|
|
|
|
|
$ |
459,910 |
|
|
$ |
422,220 |
|
|
|
9 |
% |
Unitholders equity |
|
|
|
|
|
|
|
|
|
|
|
|
|
$ |
1,888,365 |
|
|
$ |
1,467,859 |
|
|
|
29 |
% |
Unitholders equity per trust unit |
|
|
|
|
|
|
|
|
|
|
|
|
|
$ |
10.24 |
|
|
$ |
9.22 |
|
|
|
11 |
% |
|
|
|
|
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Number of trust units outstanding at period end |
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|
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|
|
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|
|
|
184,459 |
|
|
|
159,263 |
|
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|
16 |
% |
|
DAILY PRODUCTION |
|
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|
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|
|
|
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|
|
|
|
|
|
|
|
Crude oil (barrels) |
|
|
20,651 |
|
|
|
20,660 |
|
|
|
0 |
% |
|
|
20,750 |
|
|
|
20,670 |
|
|
|
0 |
% |
Heavy oil (barrels) |
|
|
5,272 |
|
|
|
5,405 |
|
|
|
-2 |
% |
|
|
5,054 |
|
|
|
5,695 |
|
|
|
-11 |
% |
Natural gas (mcf) |
|
|
158,757 |
|
|
|
164,288 |
|
|
|
-3 |
% |
|
|
155,873 |
|
|
|
158,426 |
|
|
|
-2 |
% |
Natural gas liquids (barrels) |
|
|
5,961 |
|
|
|
5,448 |
|
|
|
9 |
% |
|
|
6,054 |
|
|
|
5,885 |
|
|
|
3 |
% |
Total production (boe) |
|
|
58,344 |
|
|
|
58,894 |
|
|
|
-1 |
% |
|
|
57,836 |
|
|
|
58,654 |
|
|
|
-1 |
% |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
TOTAL PRODUCTION (mboe) |
|
|
5,368 |
|
|
|
5,418 |
|
|
|
-1 |
% |
|
|
15,789 |
|
|
|
16,013 |
|
|
|
-1 |
% |
|
PRODUCTION PROFILE |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Crude oil |
|
|
36 |
% |
|
|
35 |
% |
|
|
|
|
|
|
36 |
% |
|
|
35 |
% |
|
|
|
|
Heavy oil |
|
|
9 |
% |
|
|
9 |
% |
|
|
|
|
|
|
9 |
% |
|
|
10 |
% |
|
|
|
|
Natural gas |
|
|
45 |
% |
|
|
47 |
% |
|
|
|
|
|
|
45 |
% |
|
|
45 |
% |
|
|
|
|
Natural gas liquids |
|
|
10 |
% |
|
|
9 |
% |
|
|
|
|
|
|
10 |
% |
|
|
10 |
% |
|
|
|
|
|
AVERAGE REALIZED PRICES (after hedging) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Crude oil (per barrel) |
|
$ |
72.61 |
|
|
$ |
63.95 |
|
|
|
14 |
% |
|
$ |
69.49 |
|
|
$ |
58.31 |
|
|
|
19 |
% |
Heavy oil (per barrel) |
|
$ |
51.47 |
|
|
$ |
47.74 |
|
|
|
8 |
% |
|
$ |
43.72 |
|
|
$ |
33.82 |
|
|
|
29 |
% |
Natural gas (per mcf) |
|
$ |
6.29 |
|
|
$ |
8.57 |
|
|
|
-27 |
% |
|
$ |
7.26 |
|
|
$ |
7.61 |
|
|
|
-5 |
% |
Natural gas liquids (per barrel) |
|
$ |
60.76 |
|
|
$ |
57.75 |
|
|
|
5 |
% |
|
$ |
59.30 |
|
|
$ |
52.59 |
|
|
|
13 |
% |
Average realized price per boe |
|
$ |
53.67 |
|
|
$ |
56.07 |
|
|
|
-4 |
% |
|
$ |
54.53 |
|
|
$ |
49.66 |
|
|
|
10 |
% |
|
* |
|
See the section entitled Non-GAAP Financial Measures |
Summary of Trust Unit Trading Data
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|
Three Months ended |
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|
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Nine Months ended |
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|
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|
September 30 |
|
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|
September 30 |
|
|
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|
(thousands, except per trust unit amounts) |
|
2006 |
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2005 |
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|
2006 |
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|
2005 |
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TRUST UNIT TRADING |
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PGH (NYSE) |
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High |
|
$ |
24.95 |
|
|
|
U.S. |
|
|
$ |
25.75 |
|
|
|
U.S. |
|
|
$ |
25.15 |
|
|
|
U.S. |
|
|
$ |
25.75 |
|
|
|
U.S. |
|
Low |
|
$ |
18.90 |
|
|
|
U.S. |
|
|
$ |
21.55 |
|
|
|
U.S. |
|
|
$ |
18.90 |
|
|
|
U.S. |
|
|
$ |
18.11 |
|
|
|
U.S. |
|
Close |
|
$ |
19.62 |
|
|
|
U.S. |
|
|
$ |
25.42 |
|
|
|
U.S. |
|
|
$ |
19.62 |
|
|
|
U.S. |
|
|
$ |
25.42 |
|
|
|
U.S. |
|
Value |
|
$ |
603,978 |
|
|
|
U.S. |
|
|
$ |
340,318 |
|
|
|
U.S. |
|
|
$ |
1,257,186 |
|
|
|
U.S. |
|
|
$ |
1,190,435 |
|
|
|
U.S. |
|
Volume |
|
|
27,359 |
|
|
|
|
|
|
|
14,502 |
|
|
|
|
|
|
|
55,057 |
|
|
|
|
|
|
|
55,276 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
PGF.A (TSX) * |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
High |
|
$ |
28.25 |
|
|
|
|
|
|
$ |
30.10 |
|
|
|
|
|
|
$ |
28.96 |
|
|
|
|
|
|
$ |
30.10 |
|
|
|
|
|
Low |
|
$ |
24.95 |
|
|
|
|
|
|
$ |
26.30 |
|
|
|
|
|
|
$ |
24.20 |
|
|
|
|
|
|
$ |
22.15 |
|
|
|
|
|
Close |
|
$ |
25.30 |
|
|
|
|
|
|
$ |
29.50 |
|
|
|
|
|
|
$ |
25.30 |
|
|
|
|
|
|
$ |
29.50 |
|
|
|
|
|
Value |
|
$ |
110,607 |
|
|
|
|
|
|
$ |
58,000 |
|
|
|
|
|
|
$ |
192,056 |
|
|
|
|
|
|
$ |
157,672 |
|
|
|
|
|
Volume |
|
|
4,297 |
|
|
|
|
|
|
|
2,047 |
|
|
|
|
|
|
|
7,351 |
|
|
|
|
|
|
|
5,894 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
PGF.B (TSX) * |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
High |
|
$ |
27.25 |
|
|
|
|
|
|
$ |
21.26 |
|
|
|
|
|
|
$ |
27.25 |
|
|
|
|
|
|
$ |
21.26 |
|
|
|
|
|
Low |
|
$ |
24.84 |
|
|
|
|
|
|
$ |
18.25 |
|
|
|
|
|
|
$ |
20.71 |
|
|
|
|
|
|
$ |
16.10 |
|
|
|
|
|
Close |
|
$ |
25.31 |
|
|
|
|
|
|
$ |
20.58 |
|
|
|
|
|
|
$ |
25.31 |
|
|
|
|
|
|
$ |
20.58 |
|
|
|
|
|
Value |
|
$ |
363,983 |
|
|
|
|
|
|
$ |
441,039 |
|
|
|
|
|
|
$ |
1,243,673 |
|
|
|
|
|
|
$ |
1,327,210 |
|
|
|
|
|
Volume |
|
|
14,226 |
|
|
|
|
|
|
|
22,738 |
|
|
|
|
|
|
|
51,547 |
|
|
|
|
|
|
|
71,326 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
PGF.UN (TSX) * |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
High |
|
$ |
26.11 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$ |
26.11 |
|
|
|
|
|
|
|
|
|
|
|
|
|
Low |
|
$ |
21.02 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$ |
21.02 |
|
|
|
|
|
|
|
|
|
|
|
|
|
Close |
|
$ |
21.94 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$ |
21.94 |
|
|
|
|
|
|
|
|
|
|
|
|
|
Value |
|
$ |
707,966 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$ |
707,966 |
|
|
|
|
|
|
|
|
|
|
|
|
|
Volume |
|
|
29,262 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
29,262 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
* |
|
July 27, 2006, Pengrowths Class A trust units and Class B trust units were
consolidated into a single class of trust units whereas the Class A trust units
were delisted from the Toronto Stock Exchange and the Class B
trust units were
renamed as Trust units and their trading symbol changed to PGF.UN. |
The following discussion and analysis of financial results should be read in conjunction with
the audited consolidated financial statements for the year ended December 31, 2005 and the interim
unaudited consolidated financial statements for the nine months ended September 30, 2006 and is
based on information available to November 1, 2006.
Frequently Recurring Terms
For the purposes of this discussion and analysis, 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.
Pengrowth uses the following frequently recurring industry terms in this discussion and analysis:
bbls refers to barrels, boe refers to barrels of oil equivalent, mboe refers to a thousand
barrels of oil equivalent, mcf refers to thousand cubic feet, gj refers to gigajoule and
mmbtu refers to million British thermal units.
Advisory Regarding Forward-Looking Statements
This discussion and analysis 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 discussion and analysis 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 expenses for 2006, 2006 operating expenses 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,
work-overs, 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 predictions, 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 under
the heading Risk Factors in Pengrowths most recent Annual Information Form, its most recent
consolidated financial statements, discussion and analysis, managements information circular,
quarterly reports, material change reports and news releases. Copies of the Trusts Canadian
public filings are available on SEDAR at www.sedar.com. The Trusts U.S. public filings, including
the Trusts most recent annual report form 40-F as supplemented by its filings on form 6-K, are
available at www.sec.gov.
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
discussion and analysis are made as of the date of this
discussion and analysis and Pengrowth does not undertake any obligation to update publicly or to
revise any of the included forward-looking statements, whether as a result of new information,
future events or otherwise, except as required by law. The forward-looking statements contained in
this discussion and analysis are expressly qualified by this cautionary statement.
Critical Accounting Estimates
As discussed in Note 1 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 discussion and analysis 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 funds generated from operations, distributable cash, distributable cash per trust
unit, payout ratio and operating netbacks do not have standardized meanings prescribed by GAAP. 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 discussion, Pengrowth uses
the international standard of six thousand cubic feet 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
The third quarter results in this press release contain no material amounts relating to the
September 28, 2006 completed acquisition of assets in the Carson Creek area of Alberta, or the
Esprit Energy Trust (Esprit) business combination completed on October 2, 2006.
Production
Average daily production for the third quarter of 2006 increased four percent from the second
quarter of 2006. This increase is attributable primarily to improved volumes after the operational
curtailments at the Sable Offshore Energy Project (SOEP) during the second quarter and new
production from the Prespatou and heavy oil areas. Production for both the third quarter and first
nine months of 2006 decreased marginally from the same periods in 2005 as additions from Judy Creek
improved gas sales, the Dunvegan area acquisition and new production from development activities
were not able to offset the Monterey Exploration Ltd. (Monterey) and other minor previously
disclosed divestitures, the operational downtime at SOEP and natural production declines.
At this time, Pengrowth anticipates full year production of 62,500 to 63,500 boe per day, up from
its previous production guidance of 56,000 to 57,500 boe per day. This estimate incorporates
production additions from the Dunvegan and Carson Creek area acquisitions, the Esprit business
combination and anticipated production additions from planned 2006 development activities. The
above estimate excludes the impact from other future acquisitions or divestitures.
Daily Production
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three months ended |
|
Nine months ended |
|
|
Sept 30, 2006 |
|
Jun 30, 2006 |
|
Sept 30, 2005 |
|
Sept 30, 2006 |
|
Sept 30, 2005 |
|
Light crude oil (bbls) |
|
|
20,651 |
|
|
|
20,342 |
|
|
|
20,660 |
|
|
|
20,750 |
|
|
|
20,670 |
|
Heavy oil (bbls) |
|
|
5,272 |
|
|
|
4,869 |
|
|
|
5,405 |
|
|
|
5,054 |
|
|
|
5,695 |
|
Natural gas (mcf) |
|
|
158,757 |
|
|
|
150,976 |
|
|
|
164,288 |
|
|
|
155,873 |
|
|
|
158,426 |
|
Natural gas liquids (bbls) |
|
|
5,961 |
|
|
|
5,952 |
|
|
|
5,448 |
|
|
|
6,054 |
|
|
|
5,885 |
|
|
Total boe per day |
|
|
58,344 |
|
|
|
56,325 |
|
|
|
58,894 |
|
|
|
57,836 |
|
|
|
58,654 |
|
|
Light crude oil production volumes for the third quarter of 2006 increased two percent from the
second quarter of 2006, while in comparison to the third quarter of 2005, the production volumes
were flat. For the first nine months of 2006 versus the same period in 2005, production increased
minimally as improvements at Weyburn, Judy Creek and Swan Hills offset natural production declines.
Heavy oil production increased eight percent in the third quarter of 2006 from the second quarter
of 2006 as new production from drilling at Bodo and Cactus Lake came on stream. The two percent
decrease in production for the third quarter of 2006 compared to the same quarter of 2005 is
attributable to natural production declines. For the first nine months, production decreased 11
percent due to natural production declines.
Natural gas production for the third quarter of 2006 increased five percent from the second quarter
of 2006. This increase is primarily due to new production from wells drilled in the Prespatou area
and improved volumes after the operational curtailments at SOEP and the Hanlan turnaround during
the second quarter. Production for the third quarter of 2006 compared to the same quarter of 2005
decreased three percent. Additions from the Dunvegan area and Carson Creek acquisitions and new
production from the Prespatou and Princess areas were more than offset by natural production
declines and the Monterey and other minor previously disclosed divestments. For the first nine
months of 2006 compared to the same period in 2005, production decreased by almost two percent.
Additional production volumes from increased gas sales at Judy Creek due to lower residue gas
solvent utilization, ongoing development activities, particularly the Prespatou and Princess
drilling programs completed in the second half of 2005, and the Dunvegan area and Crispin
acquisitions, were more than offset by SOEP operational downtime, the Monterey and other
divestments, and natural production declines.
Natural gas liquids (NGLs) production for the third quarter of 2006 remained flat from the second
quarter of 2006. In comparing the third quarter of 2006 to the same quarter of 2005, production
increased nine percent primarily from acquisition activity. Production for the first nine months
of 2006 increased three percent in comparison to the same period of 2005 due to the increased
ownership in Swan Hills.
Pricing and Commodity Price Hedging
U.S. based prices for North American crude oil remained strong in the third quarter of 2006,
but continued to be partially offset by the negative impact of the strong Canadian dollar. Natural
gas prices in North America continued to decline in the third quarter of 2006 from the second
quarter of 2006.
Average Realized Prices
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three months ended |
|
|
Nine months ended |
|
(Cdn$) |
|
Sept 30, 2006 |
|
|
Jun 30, 2006 |
|
|
Sept 30, 2005 |
|
|
Sept 30, 2006 |
|
|
Sept 30, 2005 |
|
|
Light crude oil (per bbl) |
|
|
75.53 |
|
|
|
75.67 |
|
|
|
74.37 |
|
|
|
72.04 |
|
|
|
64.94 |
|
after hedging |
|
|
72.61 |
|
|
|
72.67 |
|
|
|
63.95 |
|
|
|
69.49 |
|
|
|
58.31 |
|
Heavy oil (per bbl) |
|
|
51.47 |
|
|
|
50.07 |
|
|
|
47.74 |
|
|
|
43.72 |
|
|
|
33.82 |
|
Natural gas (per mcf) |
|
|
6.22 |
|
|
|
6.69 |
|
|
|
8.69 |
|
|
|
7.21 |
|
|
|
7.63 |
|
after hedging |
|
|
6.29 |
|
|
|
6.76 |
|
|
|
8.57 |
|
|
|
7.26 |
|
|
|
7.61 |
|
Natural gas liquids (per bbl) |
|
|
60.76 |
|
|
|
58.92 |
|
|
|
57.75 |
|
|
|
59.30 |
|
|
|
52.59 |
|
|
Total per boe |
|
|
54.51 |
|
|
|
55.80 |
|
|
|
60.06 |
|
|
|
55.30 |
|
|
|
52.04 |
|
after hedging |
|
|
53.67 |
|
|
|
54.91 |
|
|
|
56.07 |
|
|
|
54.53 |
|
|
|
49.66 |
|
|
Benchmark prices |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
WTI oil (U.S.$ per bbl) |
|
|
70.54 |
|
|
|
70.72 |
|
|
|
63.31 |
|
|
|
68.21 |
|
|
|
55.60 |
|
AECO spot gas (Cdn$ per gj) |
|
|
5.72 |
|
|
|
5.95 |
|
|
|
7.75 |
|
|
|
6.82 |
|
|
|
7.03 |
|
NYMEX gas (U.S.$ per mmbtu) |
|
|
6.66 |
|
|
|
6.76 |
|
|
|
8.49 |
|
|
|
7.47 |
|
|
|
7.16 |
|
Currency (U.S.$/Cdn$) |
|
|
0.89 |
|
|
|
0.89 |
|
|
|
0.83 |
|
|
|
0.88 |
|
|
|
0.82 |
|
|
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.
Hedging Losses (Gains)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three months ended |
|
|
Nine months ended |
|
Realized |
|
Sept 30, 2006 |
|
|
Jun 30, 2006 |
|
|
Sept 30, 2005 |
|
|
Sept 30, 2006 |
|
|
Sept 30, 2005 |
|
|
|
Light crude oil ($ millions) |
|
|
5.5 |
|
|
|
5.6 |
|
|
|
19.8 |
|
|
|
14.4 |
|
|
|
37.4 |
|
Light crude oil ($ per bbl) |
|
|
2.92 |
|
|
|
3.00 |
|
|
|
10.42 |
|
|
|
2.55 |
|
|
|
6.63 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural gas ($ millions) |
|
|
(1.0 |
) |
|
|
(1.0 |
) |
|
|
1.8 |
|
|
|
(2.3 |
) |
|
|
0.7 |
|
Natural gas ($ per mcf) |
|
|
(0.07 |
) |
|
|
(0.07 |
) |
|
|
0.12 |
|
|
|
(0.05 |
) |
|
|
0.02 |
|
|
Combined ($ millions) |
|
|
4.5 |
|
|
|
4.6 |
|
|
|
21.6 |
|
|
|
12.1 |
|
|
|
38.1 |
|
Combined ($ per boe) |
|
|
0.84 |
|
|
|
0.89 |
|
|
|
3.99 |
|
|
|
0.77 |
|
|
|
2.38 |
|
|
Starting in the second quarter of 2006, Pengrowth no longer adopted hedge accounting for any new
hedges entered into. Pengrowth will recognize any changes to the fair value of commodity hedges
entered into after the first quarter in the income statement.
Commodity price hedges in place at September 30, 2006 are provided in Note 11 to the Financial
Statements. At September 30, 2006, the mark-to-market value of the fixed price financial sales
contracts represented a potential gain of $15.0 million, which includes a $16.6 million gain year
to date that has been recognized on the income statement. At
September 30, 2005, the
mark-to-market
value of the fixed price financial sales contracts represented a potential loss of $64.2 million,
none of which was recognized on the income statement.
In conjunction with the Murphy acquisition, which closed in 2004, Pengrowth assumed certain fixed
price natural gas sales contracts and firm pipeline demand charge contracts. 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 September 30, 2006 of $14.3 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. As at September 30, 2006, Pengrowth
would be required to pay $17.8 million to terminate the fixed price physical sales contract. This
amount is not included above in hedging losses (gains).
Oil and Gas Sales Contribution Analysis
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
($ millions) |
|
Three months ended |
|
|
|
|
|
|
Nine months ended |
|
|
|
Sept 30, |
|
|
% of |
|
|
Jun 30, |
|
|
% of |
|
|
Sept 30, |
|
|
% of |
|
|
Sept 30, |
|
|
% of |
|
|
Sept 30, |
|
|
% of |
|
Sales Revenue |
|
2006 |
|
|
total |
|
|
2006 |
|
|
total |
|
|
2005 |
|
|
total |
|
|
2006 |
|
|
total |
|
|
2005 |
|
|
total |
|
|
Light crude oil |
|
|
137.9 |
|
|
|
48 |
|
|
|
134.6 |
|
|
|
47 |
|
|
|
121.6 |
|
|
|
40 |
|
|
|
393.6 |
|
|
|
46 |
|
|
|
329.1 |
|
|
|
41 |
|
Natural gas |
|
|
91.9 |
|
|
|
32 |
|
|
|
92.8 |
|
|
|
33 |
|
|
|
129.5 |
|
|
|
43 |
|
|
|
309.1 |
|
|
|
36 |
|
|
|
329.0 |
|
|
|
41 |
|
Natural gas liquids |
|
|
33.3 |
|
|
|
11 |
|
|
|
31.9 |
|
|
|
11 |
|
|
|
29.0 |
|
|
|
9 |
|
|
|
98.0 |
|
|
|
11 |
|
|
|
84.5 |
|
|
|
11 |
|
Heavy oil |
|
|
24.9 |
|
|
|
9 |
|
|
|
22.2 |
|
|
|
8 |
|
|
|
23.8 |
|
|
|
8 |
|
|
|
60.3 |
|
|
|
7 |
|
|
|
52.6 |
|
|
|
7 |
|
Brokered sales/sulphur |
|
|
(0.2 |
) |
|
|
0 |
|
|
|
2.0 |
|
|
|
1 |
|
|
|
0.6 |
|
|
|
0 |
|
|
|
2.2 |
|
|
|
0 |
|
|
|
2.4 |
|
|
|
0 |
|
|
Total oil and gas sales |
|
|
287.8 |
|
|
|
|
|
|
|
283.5 |
|
|
|
|
|
|
|
304.5 |
|
|
|
|
|
|
|
863.2 |
|
|
|
|
|
|
|
797.6 |
|
|
|
|
|
Oil and Gas Sales Price and Volume 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, for the third quarter of 2006 compared to
the second quarter of 2006.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
($ millions) |
|
Light oil |
|
|
Natural gas |
|
|
NGL |
|
|
Heavy oil |
|
|
Other |
|
|
Total |
|
|
|
Quarter ended June 30, 2006 |
|
|
134.6 |
|
|
|
92.8 |
|
|
|
31.9 |
|
|
|
22.2 |
|
|
|
2.0 |
|
|
|
283.5 |
|
Effect of change in product prices |
|
|
(0.3 |
) |
|
|
(6.9 |
) |
|
|
1.0 |
|
|
|
0.7 |
|
|
|
|
|
|
|
(5.5 |
) |
Effect of change in sales volumes |
|
|
3.7 |
|
|
|
5.8 |
|
|
|
0.4 |
|
|
|
2.1 |
|
|
|
|
|
|
|
12.0 |
|
Effect of change in hedging losses |
|
|
0.1 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
0.1 |
|
Other |
|
|
(0.2 |
) |
|
|
0.2 |
|
|
|
|
|
|
|
(0.1 |
) |
|
|
(2.2 |
) |
|
|
(2.3 |
) |
|
Quarter ended September 30, 2006 |
|
|
137.9 |
|
|
|
91.9 |
|
|
|
33.3 |
|
|
|
24.9 |
|
|
|
(0.2 |
) |
|
|
287.8 |
|
|
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, for the first nine months of 2006 compared to
the same period of 2005.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
($ millions) |
|
Light oil |
|
|
Natural gas |
|
|
NGL |
|
|
Heavy oil |
|
|
Other |
|
|
Total |
|
|
|
Year to date September 30, 2005 |
|
|
329.1 |
|
|
|
329.0 |
|
|
|
84.5 |
|
|
|
52.6 |
|
|
|
2.4 |
|
|
|
797.6 |
|
Effect of change in product prices |
|
|
40.2 |
|
|
|
(17.7 |
) |
|
|
11.1 |
|
|
|
13.7 |
|
|
|
|
|
|
|
47.3 |
|
Effect of change in sales volumes |
|
|
1.4 |
|
|
|
(5.3 |
) |
|
|
2.4 |
|
|
|
(5.9 |
) |
|
|
|
|
|
|
(7.4 |
) |
Effect of change in hedging losses |
|
|
23.0 |
|
|
|
3.0 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
26.0 |
|
Other |
|
|
(0.1 |
) |
|
|
0.1 |
|
|
|
|
|
|
|
(0.1 |
) |
|
|
(0.2 |
) |
|
|
(0.3 |
) |
|
Year to date September 30, 2006 |
|
|
393.6 |
|
|
|
309.1 |
|
|
|
98.0 |
|
|
|
60.3 |
|
|
|
2.2 |
|
|
|
863.2 |
|
|
Processing, Interest and Other Income
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three months ended |
|
|
Nine months ended |
|
($ millions) |
|
Sept 30, 2006 |
|
|
Jun 30, 2006 |
|
|
Sept 30, 2005 |
|
|
Sept 30, 2006 |
|
|
Sept 30, 2005 |
|
|
|
Processing,
interest & other
income |
|
|
4.7 |
|
|
|
4.1 |
|
|
|
2.1 |
|
|
|
12.6 |
|
|
|
13.7 |
|
$ per boe |
|
|
0.88 |
|
|
|
0.80 |
|
|
|
0.39 |
|
|
|
0.80 |
|
|
|
0.86 |
|
|
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 expenses reported separately.
Royalties
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three months ended |
|
|
Nine months ended |
|
($ millions) |
|
Sept 30, 2006 |
|
|
Jun 30, 2006 |
|
|
Sept 30, 2005 |
|
|
Sept 30, 2006 |
|
|
Sept 30, 2005 |
|
|
|
Royalty expense |
|
|
57.8 |
|
|
|
45.3 |
|
|
|
57.4 |
|
|
|
168.4 |
|
|
|
145.9 |
|
$ per boe |
|
|
10.77 |
|
|
|
8.84 |
|
|
|
10.60 |
|
|
|
10.67 |
|
|
|
9.11 |
|
|
Royalties as a percent of sales |
|
|
20.1 |
% |
|
|
16.0 |
% |
|
|
18.9 |
% |
|
|
19.5 |
% |
|
|
18.3 |
% |
Royalties include crown, freehold and overriding royalties as well as mineral taxes. The royalty
rate for the third quarter of 2006 compared to the second quarter of 2006 increased by 4.1 percent.
This was primarily due to a favorable adjustment of $5.0 million recorded in the second quarter for
SOEP. SOEP has a five tier royalty regime based on gross revenue for the first three tiers and net
revenue for the final two tiers. During 2005, the royalty obligation at SOEP was approximately two
percent of gross revenue (Tier II) but progressed to five percent of gross revenue (Tier III)
starting with October 2005 production. This was recognized in March 2006 when the annual royalty
submission was filed. Based on Pengrowths forecast the royalty obligation is now in the fourth
tier which is 30 percent of net revenue (gross revenue less certain capital and other costs
associated with getting the gas and natural gas liquids to the project boundary) commencing with
March 2006 production, which is later than previously estimated in the first quarter.
Operating Expenses
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three months ended |
|
|
Nine months ended |
|
($ millions) |
|
Sept 30, 2006 |
|
|
Jun 30, 2006 |
|
|
Sept 30, 2005 |
|
|
Sept 30, 2006 |
|
|
Sept 30, 2005 |
|
|
|
Operating expenses |
|
|
58.8 |
|
|
|
58.0 |
|
|
|
57.4 |
|
|
|
170.8 |
|
|
|
156.9 |
|
$ per boe |
|
|
10.94 |
|
|
|
11.32 |
|
|
|
10.59 |
|
|
|
10.82 |
|
|
|
9.80 |
|
|
Operating expenses increased minimally in the third quarter of 2006 in comparison to the second
quarter of 2006; while the expense per boe decreased as production volumes improved from the second
quarters maintenance/turnaround activity. Increased utility costs and higher maintenance were the
most significant reasons for the increase in expenses in comparing the first nine months of 2006
versus the same period in 2005. Operating expenses include costs incurred to earn processing and
other income reported separately.
Transportation Costs
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three months ended |
|
|
Nine months ended |
|
($ millions) |
|
Sept 30, 2006 |
|
|
Jun 30, 2006 |
|
|
Sept 30, 2005 |
|
|
Sept 30, 2006 |
|
|
Sept 30, 2005 |
|
|
|
Light oil transportation |
|
|
0.5 |
|
|
|
0.5 |
|
|
|
0.6 |
|
|
|
1.5 |
|
|
|
1.7 |
|
$ per bbl |
|
|
0.26 |
|
|
|
0.27 |
|
|
|
0.29 |
|
|
|
0.26 |
|
|
|
0.30 |
|
Natural gas transportation |
|
|
1.3 |
|
|
|
1.2 |
|
|
|
1.4 |
|
|
|
3.8 |
|
|
|
3.9 |
|
$ per mcf |
|
|
0.09 |
|
|
|
0.09 |
|
|
|
0.09 |
|
|
|
0.09 |
|
|
|
0.09 |
|
|
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. Prior to September 30, 2006, 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 |
|
|
Nine months ended |
|
($ millions) |
|
Sept 30, 2006 |
|
|
Jun 30, 2006 |
|
|
Sept 30, 2005 |
|
|
Sept 30, 2006 |
|
|
Sept 30, 2005 |
|
|
|
Purchased and capitalized |
|
|
7.9 |
|
|
|
6.7 |
|
|
|
6.9 |
|
|
|
25.2 |
|
|
|
20.2 |
|
Amortization |
|
|
8.8 |
|
|
|
8.5 |
|
|
|
6.0 |
|
|
|
25.3 |
|
|
|
17.3 |
|
|
The cost of injectants (primarily natural gas and ethane) purchased for injection in miscible
flood programs is amortized equally 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 developed is expected to be somewhat shorter relative to the historical miscible
patterns in the project. Accordingly, the cost of injectants purchased in 2005 and 2006 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. During the third quarter of 2006, the balance
of unamortized injectant costs decreased by $0.9 million to $35.2 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 expenses. The cost
of purchased injectants increased 18 percent in the third quarter of 2006 from the second quarter
of 2006 primarily due to the increase in volume of injectants. The 14 percent increase in the third
quarter of 2006 compared to the same quarter of 2005 is due to increased injection volumes. On a
year to date basis, the 25 percent increase in purchased injectants is due to increased injection
volumes and the price of injectants.
Operating 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, heavy oil, natural gas and natural gas liquids
production.
Pengrowth recorded an operating netback of $30.82 per boe (after hedging) in the third quarter of
2006 compared to $33.94 per boe (after hedging) for the same period in 2005, mainly due to lower
average commodity prices, higher operating expenses and royalty expenses.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Combined Netbacks ($ per boe) |
|
Three months ended |
|
|
Nine months ended |
|
|
|
Sept 30, 2006 |
|
|
Jun 30, 2006 |
|
|
Sept 30, 2005 |
|
|
Sept 30, 2006 |
|
|
Sept 30, 2005 |
|
|
|
|
|
|
|
Sales price |
|
$ |
53.67 |
|
|
$ |
54.91 |
|
|
$ |
56.07 |
|
|
$ |
54.53 |
|
|
$ |
49.66 |
|
Other production income |
|
|
(0.06 |
) |
|
|
0.41 |
|
|
|
0.13 |
|
|
|
0.13 |
|
|
|
0.15 |
|
|
|
|
|
|
|
|
|
53.61 |
|
|
|
55.32 |
|
|
|
56.20 |
|
|
|
54.66 |
|
|
|
49.81 |
|
Processing, interest and other income |
|
|
0.88 |
|
|
|
0.80 |
|
|
|
0.39 |
|
|
|
0.80 |
|
|
|
0.86 |
|
Royalties |
|
|
(10.77 |
) |
|
|
(8.84 |
) |
|
|
(10.60 |
) |
|
|
(10.67 |
) |
|
|
(9.11 |
) |
Operating expenses |
|
|
(10.94 |
) |
|
|
(11.32 |
) |
|
|
(10.59 |
) |
|
|
(10.82 |
) |
|
|
(9.80 |
) |
Transportation costs |
|
|
(0.33 |
) |
|
|
(0.35 |
) |
|
|
(0.36 |
) |
|
|
(0.34 |
) |
|
|
(0.35 |
) |
Amortization of injectants |
|
|
(1.63 |
) |
|
|
(1.67 |
) |
|
|
(1.10 |
) |
|
|
(1.60 |
) |
|
|
(1.08 |
) |
|
|
|
|
|
Operating netback |
|
$ |
30.82 |
|
|
$ |
33.94 |
|
|
$ |
33.94 |
|
|
$ |
32.03 |
|
|
$ |
30.33 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Light Crude Netbacks ($ per bbl) |
|
Three months ended |
|
|
Nine months ended |
|
|
|
Sept 30, 2006 |
|
|
Jun 30, 2006 |
|
|
Sept 30, 2005 |
|
|
Sept 30, 2006 |
|
|
Sept 30, 2005 |
|
|
|
|
|
|
|
Sales price |
|
$ |
72.61 |
|
|
$ |
72.67 |
|
|
$ |
63.95 |
|
|
$ |
69.49 |
|
|
$ |
58.31 |
|
Other production income |
|
|
(0.19 |
) |
|
|
1.07 |
|
|
|
0.37 |
|
|
|
0.31 |
|
|
|
0.44 |
|
|
|
|
|
|
|
|
|
72.42 |
|
|
|
73.74 |
|
|
|
64.32 |
|
|
|
69.80 |
|
|
|
58.75 |
|
Processing, interest and other income |
|
|
0.60 |
|
|
|
0.50 |
|
|
|
0.64 |
|
|
|
0.56 |
|
|
|
0.51 |
|
Royalties |
|
|
(12.19 |
) |
|
|
(11.27 |
) |
|
|
(11.03 |
) |
|
|
(10.21 |
) |
|
|
(9.39 |
) |
Operating expenses |
|
|
(13.20 |
) |
|
|
(12.17 |
) |
|
|
(12.85 |
) |
|
|
(12.09 |
) |
|
|
(11.58 |
) |
Transportation costs |
|
|
(0.26 |
) |
|
|
(0.27 |
) |
|
|
(0.29 |
) |
|
|
(0.26 |
) |
|
|
(0.30 |
) |
Amortization of injectants |
|
|
(4.61 |
) |
|
|
(4.61 |
) |
|
|
(3.14 |
) |
|
|
(4.46 |
) |
|
|
(3.07 |
) |
|
|
|
|
|
Operating netback |
|
$ |
42.76 |
|
|
$ |
45.92 |
|
|
$ |
37.65 |
|
|
$ |
43.34 |
|
|
$ |
34.92 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Heavy Oil Netbacks ($ per bbl) |
|
Three months ended |
|
|
Nine months ended |
|
|
|
Sept 30, 2006 |
|
|
Jun 30, 2006 |
|
|
Sept 30, 2005 |
|
|
Sept 30, 2006 |
|
|
Sept 30, 2005 |
|
|
|
|
|
|
|
Sales price |
|
$ |
51.47 |
|
|
$ |
50.07 |
|
|
$ |
47.74 |
|
|
$ |
43.72 |
|
|
$ |
33.82 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Processing, interest and other income |
|
|
0.38 |
|
|
|
0.16 |
|
|
|
(0.83 |
) |
|
|
0.31 |
|
|
|
0.24 |
|
Royalties |
|
|
(6.27 |
) |
|
|
(4.75 |
) |
|
|
(8.00 |
) |
|
|
(4.24 |
) |
|
|
(5.03 |
) |
Operating expenses |
|
|
(16.28 |
) |
|
|
(16.03 |
) |
|
|
(16.30 |
) |
|
|
(15.51 |
) |
|
|
(16.95 |
) |
|
|
|
|
|
Operating netback |
|
$ |
29.30 |
|
|
$ |
29.45 |
|
|
$ |
22.61 |
|
|
$ |
24.28 |
|
|
$ |
12.08 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural Gas Netbacks ($ per mcf) |
|
Three months ended |
|
|
Nine months ended |
|
|
|
Sept 30, 2006 |
|
|
Jun 30, 2006 |
|
|
Sept 30, 2005 |
|
|
Sept 30, 2006 |
|
|
Sept 30, 2005 |
|
|
|
|
|
|
|
Sales price |
|
$ |
6.29 |
|
|
$ |
6.76 |
|
|
$ |
8.57 |
|
|
$ |
7.26 |
|
|
$ |
7.61 |
|
Other production income |
|
|
|
|
|
|
0.01 |
|
|
|
|
|
|
|
0.01 |
|
|
|
|
|
|
|
|
|
|
|
|
|
6.29 |
|
|
|
6.77 |
|
|
|
8.57 |
|
|
|
7.27 |
|
|
|
7.61 |
|
|
Processing, interest and other income |
|
|
0.23 |
|
|
|
0.23 |
|
|
|
0.09 |
|
|
|
0.21 |
|
|
|
0.24 |
|
Royalties |
|
|
(1.34 |
) |
|
|
(0.93 |
) |
|
|
(1.47 |
) |
|
|
(1.61 |
) |
|
|
(1.36 |
) |
Operating expenses |
|
|
(1.38 |
) |
|
|
(1.66 |
) |
|
|
(1.31 |
) |
|
|
(1.52 |
) |
|
|
(1.19 |
) |
Transportation costs |
|
|
(0.09 |
) |
|
|
(0.09 |
) |
|
|
(0.09 |
) |
|
|
(0.09 |
) |
|
|
(0.09 |
) |
|
|
|
|
|
Operating netback |
|
$ |
3.71 |
|
|
$ |
4.32 |
|
|
$ |
5.79 |
|
|
$ |
4.26 |
|
|
$ |
5.21 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
NGLs Netbacks ($ per bbl) |
|
Three months ended |
|
|
Nine months ended |
|
|
|
Sept 30, 2006 |
|
|
Jun 30, 2006 |
|
|
Sept 30, 2005 |
|
|
Sept 30, 2006 |
|
|
Sept 30, 2005 |
|
|
|
|
|
|
|
Sales price |
|
$ |
60.76 |
|
|
$ |
58.92 |
|
|
$ |
57.75 |
|
|
$ |
59.30 |
|
|
$ |
52.59 |
|
|
Royalties |
|
|
(21.84 |
) |
|
|
(17.67 |
) |
|
|
(20.57 |
) |
|
|
(21.93 |
) |
|
|
(16.27 |
) |
Operating expenses |
|
|
(10.26 |
) |
|
|
(10.20 |
) |
|
|
(10.13 |
) |
|
|
(9.69 |
) |
|
|
(8.65 |
) |
|
|
|
|
|
Operating netback |
|
$ |
28.66 |
|
|
$ |
31.05 |
|
|
$ |
27.05 |
|
|
$ |
27.68 |
|
|
$ |
27.67 |
|
|
|
|
|
|
Other production income consists of sulphur sales and brokered sales and purchases. A prior
period adjustment for brokered sales is included in the second quarter of 2006 while both the
second and third quarter of 2006 include adjustments for brokered purchases.
Interest
Interest expense increased eight percent to $7.1 million for the third quarter of 2006 from
$6.5 million in the second quarter of 2006 primarily due to an increase in the average interest
rate. Interest expense increased by $1.4 million in the third quarter of 2006 compared to the same
period in 2005 due to higher average interest rates.
General and Administrative (G&A)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three months ended |
|
|
Nine months ended |
|
($ millions) |
|
Sept 30, 2006 |
|
|
Jun 30, 2006 |
|
|
Sept 30, 2005 |
|
|
Sept 30, 2006 |
|
|
Sept 30, 2005 |
|
|
|
Cash G&A expense |
|
|
6.8 |
|
|
|
8.1 |
|
|
|
7.0 |
|
|
|
22.4 |
|
|
|
19.7 |
|
$ per boe |
|
|
1.27 |
|
|
|
1.59 |
|
|
|
1.29 |
|
|
|
1.42 |
|
|
|
1.23 |
|
Non-cash G&A expense |
|
|
0.9 |
|
|
|
0.6 |
|
|
|
0.6 |
|
|
|
2.8 |
|
|
|
2.1 |
|
$ per boe |
|
|
0.17 |
|
|
|
0.11 |
|
|
|
0.11 |
|
|
|
0.18 |
|
|
|
0.13 |
|
|
Total G&A ($ millions) |
|
|
7.7 |
|
|
|
8.7 |
|
|
|
7.6 |
|
|
|
25.2 |
|
|
|
21.8 |
|
Total G&A ($ per boe) |
|
|
1.44 |
|
|
|
1.70 |
|
|
|
1.40 |
|
|
|
1.60 |
|
|
|
1.36 |
|
|
The cash component of G&A for the third quarter of 2006 compared to the second quarter of 2006
decreased in part due to the timing of compensation expenses for retention programs. Retention
programs were the main reason for the $3.4 million increase in the first nine months of 2006 versus
the same period in 2005.
Management Fees
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three months ended |
|
|
Nine months ended |
|
($ millions) |
|
Sept 30, 2006 |
|
|
Jun 30, 2006 |
|
|
Sept 30, 2005 |
|
|
Sept 30, 2006 |
|
|
Sept 30, 2005 |
|
|
|
Management Fee |
|
|
0.8 |
|
|
|
2.1 |
|
|
|
1.6 |
|
|
|
6.1 |
|
|
|
6.8 |
|
Performance Fee |
|
|
2.2 |
|
|
|
1.3 |
|
|
|
1.9 |
|
|
|
4.5 |
|
|
|
4.8 |
|
|
Total ($ millions) |
|
|
3.0 |
|
|
|
3.4 |
|
|
|
3.5 |
|
|
|
10.6 |
|
|
|
11.6 |
|
Total ($ per boe) |
|
|
0.56 |
|
|
|
0.65 |
|
|
|
0.65 |
|
|
|
0.67 |
|
|
|
0.72 |
|
|
Under the current management agreement, which came into effect July 1, 2003, the Manager will
earn a performance fee if the Trusts total returns exceed eight percent per annum on a three year
rolling average basis. The maximum fees payable until June 30, 2006, including the performance fee,
were limited to 80 percent of the fees plus expenses that would otherwise have been payable under
the original management agreement that was effective prior to July 1, 2003. Commencing July 1,
2006, for the remaining three year term, the maximum fees payable are limited to 60 percent of the
fees that would have been payable under the original agreement or $12 million, whichever is lower.
The current agreement expires on June 30, 2009 and does not contain a further right of renewal.
Depletion, Depreciation and Accretion
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three months ended |
|
|
Nine months ended |
|
($ millions) |
|
Sept 30, 2006 |
|
|
Jun 30, 2006 |
|
|
Sept 30, 2005 |
|
|
Sept 30, 2006 |
|
|
Sept 30, 2005 |
|
|
Depletion and Depreciation |
|
|
83.5 |
|
|
|
67.8 |
|
|
|
73.5 |
|
|
|
222.4 |
|
|
|
213.6 |
|
$ per boe |
|
|
15.56 |
|
|
|
13.23 |
|
|
|
13.57 |
|
|
|
14.09 |
|
|
|
13.34 |
|
Accretion |
|
|
4.5 |
|
|
|
3.9 |
|
|
|
3.5 |
|
|
|
11.7 |
|
|
|
10.5 |
|
$ per boe |
|
|
0.84 |
|
|
|
0.76 |
|
|
|
0.66 |
|
|
|
0.74 |
|
|
|
0.66 |
|
|
Depletion and depreciation of property, plant and equipment is provided on the unit of production
method based on total proved reserves. The increase in the third quarter rates for both depletion
and depreciation and accretion is due to the inclusion of the Carson Creek property.
Other Expenses
Other expenses, on a year to date basis, consist of costs related to the consolidation of Class
A and Class B trust units
($ 2.7 million) and the Saskatchewan Resource Surcharge.
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 capital expenditures and repay debt.
On October 31, 2006, the Federal Government announced it intends to remove certain deductions
currently available to the Trust when calculating taxable income. While no specific legislation has
been proposed making it difficult to fully assess the impact of the announcement, the intent of the
proposal is to change Pengrowths taxability starting in 2011.
Capital Expenditures
During the first nine months of 2006, Pengrowth spent $179.0 million on development and
optimization activities. The largest expenditures were at Judy Creek ($29.4 million), SOEP ($17.7
million), Quirk Creek ($11.0 million), West Pembina ($9.7 million), Bodo ($8.4 million), Weyburn
($8.2 million), Three Hills Creek ($7.1 million) and Prespatou
($6.6 million). Pengrowth engages in limited exploration activities and in the first nine months of
2006 most of the capital spent on development was directed towards increasing production and
improving reserve recovery through infill drilling. An additional $528 million was incurred to
complete the Carson Creek area, Dunvegan area and other acquisitions.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three months ended |
|
|
Nine months ended |
|
($ millions) |
|
Sept 30, 2006 |
|
|
Jun 30, 2006 |
|
|
Sept 30, 2005 |
|
|
Sept 30, 2006 |
|
|
Sept 30, 2005 |
|
|
Geological and geophysical |
|
|
0.5 |
|
|
|
1.1 |
|
|
|
0.2 |
|
|
|
2.8 |
|
|
|
1.4 |
|
Drilling and completions |
|
|
42.2 |
|
|
|
33.5 |
|
|
|
29.8 |
|
|
|
133.5 |
|
|
|
89.2 |
|
Plant and facilities |
|
|
9.4 |
|
|
|
7.5 |
|
|
|
10.0 |
|
|
|
30.3 |
|
|
|
23.9 |
|
Land purchases |
|
|
4.7 |
|
|
|
5.0 |
|
|
|
0.8 |
|
|
|
12.4 |
|
|
|
1.1 |
|
|
Development capital |
|
|
56.8 |
|
|
|
47.1 |
|
|
|
40.8 |
|
|
|
179.0 |
|
|
|
115.6 |
|
|
Acquisitions |
|
|
473.8 |
|
|
|
4.4 |
|
|
|
2.1 |
|
|
|
528.0 |
|
|
|
93.3 |
|
|
Total capital expenditures
and acquisitions |
|
|
530.6 |
|
|
|
51.5 |
|
|
|
42.9 |
|
|
|
707.0 |
|
|
|
208.9 |
|
|
Pengrowth currently anticipates capital expenditures for maintenance and development of
approximately $280 million for 2006, up from our previous guidance of $261 million. The increase
from our previous guidance includes post acquisition capital expenditures primarily related to the
Esprit business combination.
Acquisitions and Dispositions
On September 28, 2006, Pengrowth acquired all of the issued and outstanding shares of a company
which had interests in oil and natural gas assets in the Carson Creek area of Alberta and the
adjacent Carson Creek Gas Plant for $475 million prior to adjustments. Goodwill of $133 million was
determined based on the excess of the total consideration paid less the value assigned to the
identifiable assets and liabilities including the future tax liability.
On March 30, 2006, Pengrowth closed the acquisition of an additional working interest in the
Dunvegan area as well as some minor oil and gas properties in central Alberta for approximately $48
million.
On January 12, 2006, Pengrowth divested oil and gas properties for $22 million of cash, prior to
adjustments, and approximately eight million shares in Monterey. Pengrowth holds approximately 34
percent of the common shares of Monterey.
Financial Resources and Liquidity
Pengrowths capital structure is as follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
As at |
|
As at |
|
As at |
|
|
September 30 |
|
December 31 |
|
September 30 |
($ thousands) |
|
2006 |
|
2005 |
|
2005 |
|
|
Revolving credit facilities |
|
|
132,000 |
|
|
|
35,000 |
|
|
|
190,000 |
|
Senior unsecured notes |
|
|
327,910 |
|
|
|
333,089 |
|
|
|
232,220 |
|
Working capital deficit |
|
|
119,234 |
|
|
|
77,639 |
|
|
|
63,524 |
|
Note payable |
|
|
20,000 |
|
|
|
20,000 |
|
|
|
35,000 |
|
Cash balance |
|
|
(928 |
) |
|
|
|
|
|
|
(997 |
) |
|
Net Debt |
|
|
598,216 |
|
|
|
465,728 |
|
|
|
519,747 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Unitholders equity |
|
|
1,888,365 |
|
|
|
1,475,996 |
|
|
|
1,467,859 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net debt as a percentage of total book capitalization |
|
|
24.1 |
% |
|
|
24.0 |
% |
|
|
26.1 |
% |
|
|
|
|
|
|
|
|
|
|
|
|
|
Trailing 12 months cash flow * |
|
|
680,811 |
|
|
|
618,070 |
|
|
|
514,766 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net debt to trailing 12 months cash flow* |
|
|
0.9 |
|
|
|
0.8 |
|
|
|
1.0 |
|
|
|
|
* |
|
Cash flow in this table is defined as cash flow from operating activities after working capital
changes |
The $97 million increase in the revolving credit facilities from December 31, 2005 is primarily due
to capital expenditures, acquisitions, and the purchase of portfolio investments exceeding cash
withholdings, proceeds from the Monterey transaction and net proceeds from the equity offering that
closed September 28, 2006.
Pengrowth funds its capital expenditures through a combination of cash withholdings, available
credit from its bank credit facilities and proceeds from exercise of trust unit rights and the
distribution reinvestment plan. The credit facility and other sources of cash are expected to be
sufficient to meet Pengrowths near term capital requirements and provide the flexibility to pursue
profitable growth opportunities. A significant decline in oil and natural gas prices could impact
our access to bank credit facilities and our ability to fund operations and maintain distributions.
At September 30, 2006, Pengrowth maintained a $500 million term credit facility and a $35 million
demand operating line of credit. These facilities were reduced by drawings of $132 million and by
$17 million in letters of credit outstanding at period end. Pengrowth remains well positioned to
fund its 2006 development program and to take advantage of acquisition opportunities as they arise.
At September 30, 2006, Pengrowth had $387 million available to draw from its credit facilities.
On October 2, 2006, concurrent with the closing of the business combination with Esprit, Pengrowth
increased its term credit facility to $950 million. A total of $315 million was used to repay and
cancel Esprits credit facility. On October 2, 2006, Pengrowth had over $500 million available to
draw from its credit facilities after the increase to its credit facility and repayment of Esprits
facility.
Pengrowth does not have any off balance sheet financing arrangements.
Pengrowths U.S. $200 million senior unsecured notes, Pound sterling denominated £50 million senior
unsecured notes, and the revolving credit facilities have certain financial covenants which may
restrict the total amount of Pengrowths borrowings. The financial covenants are different between
the revolving credit facilities and the senior unsecured notes and some of the covenants are
summarized below:
|
1. |
|
Total senior debt should not be greater than three times Earnings Before Income Taxes
Depreciation and Amortization (EBITDA) for the last four fiscal quarters |
|
|
2. |
|
Total debt should not be greater than 3.5 times EBITDA for the last four fiscal
quarters |
|
|
3. |
|
Total senior debt should be less than 50% of total book capitalization
|
|
|
4. |
|
EBITDA should not be less than four times interest expense |
In the event that Pengrowth enters into a significant acquisition, certain credit facility
financial covenants are relaxed for two fiscal quarters after the close of the acquisition.
The actual loan documents are filed on SEDAR as Other Material Contracts. As at September 30,
2006, Pengrowth was in compliance with all its financial covenants. In the event that Pengrowth
was not in compliance with any of the financial covenants in its credit facility or senior
unsecured notes, Pengrowth would be in default of that specific debt and would have to repay the
debt, refinance the debt or negotiate new terms with the debt holders and may have to suspend
distributions to unitholders.
On November 1, 2006, Pengrowth announced its offer to purchase all of the outstanding 6.5 percent
convertible extendible unsecured subordinated debentures (the Debentures). Approximately $95.8
million of Debentures remained outstanding at September 30, 2006. Following the completion of the
business combination with Esprit on October 2, 2006, Pengrowth assumed all the covenants and
obligations of Esprit under its Debenture Indenture providing for the issuance of the Debentures.
Pursuant to the change of control provisions in the Debenture Indenture, Pengrowth is required
within 30 days of such change of control, to make an offer to purchase all the outstanding
Debentures at a price equal to 101 percent of the principal amount of the outstanding Debentures,
plus any accrued but unpaid interest.
Distributable Cash and Distributions
There is no standardized measure of distributable cash and therefore distributable cash, as
reported by Pengrowth, may not be comparable to similar measures presented by other trusts. The
following table provides a reconciliation of distributable cash and payout ratio:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
($ thousands, except per trust unit amounts) |
|
Three months ended |
|
|
Nine months ended |
|
|
|
Sept 30, 2006 |
|
|
Jun 30, 2006 |
|
|
Sept 30, 2005 |
|
|
Sept 30, 2006 |
|
|
Sept 30, 2005 |
|
|
Cash flows from operating activities |
|
|
174,294 |
|
|
|
118,326 |
|
|
|
158,976 |
|
|
|
484,219 |
|
|
|
421,482 |
|
Change in non-cash operating working capital |
|
|
(31,351 |
) |
|
|
34,219 |
|
|
|
(789 |
) |
|
|
(47,471 |
) |
|
|
(1,840 |
) |
|
Funds generated from operations |
|
|
142,943 |
|
|
|
152,545 |
|
|
|
158,187 |
|
|
|
436,748 |
|
|
|
419,642 |
|
|
Change in deferred injectants |
|
|
(870 |
) |
|
|
(1,853 |
) |
|
|
892 |
|
|
|
(80 |
) |
|
|
2,854 |
|
Change in remediation trust funds |
|
|
(599 |
) |
|
|
(279 |
) |
|
|
(272 |
) |
|
|
(1,269 |
) |
|
|
(804 |
) |
Change in deferred charges |
|
|
1,997 |
|
|
|
(1,716 |
) |
|
|
2,818 |
|
|
|
1,069 |
|
|
|
2,028 |
|
Other |
|
|
(124 |
) |
|
|
383 |
|
|
|
384 |
|
|
|
136 |
|
|
|
140 |
|
|
Distributable cash |
|
|
143,347 |
|
|
|
149,080 |
|
|
|
162,009 |
|
|
|
436,604 |
|
|
|
423,860 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Allocation of Distributable cash |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash withheld |
|
|
10,834 |
|
|
|
28,483 |
|
|
|
52,156 |
|
|
|
63,192 |
|
|
|
97,741 |
|
Distributions paid or declared |
|
|
132,513 |
|
|
|
120,597 |
|
|
|
109,853 |
|
|
|
373,412 |
|
|
|
326,119 |
|
|
Distributable cash |
|
|
143,347 |
|
|
|
149,080 |
|
|
|
162,009 |
|
|
|
436,604 |
|
|
|
423,860 |
|
|
Distributable cash per trust unit |
|
|
0.89 |
|
|
|
0.93 |
|
|
|
1.02 |
|
|
|
2.72 |
|
|
|
2.71 |
|
Distributions paid or declared per trust unit |
|
|
0.75 |
|
|
|
0.75 |
|
|
|
0.69 |
|
|
|
2.25 |
|
|
|
2.07 |
|
Payout ratio (1) |
|
|
92 |
% |
|
|
81 |
% |
|
|
68 |
% |
|
|
86 |
% |
|
|
77 |
% |
|
|
|
|
(1) |
|
Payout ratio is calculated as distributions paid or declared divided by
distributable cash |
Distributable cash is derived from producing and selling oil, natural gas and related products.
As such, distributable cash is highly dependent on commodity prices. From time to time, Pengrowth
enters into forward commodity contracts to fix the commodity price and mitigate price volatility.
Details of commodity contracts are contained in Note 11 to the September 30, 2006 Financial
Statements.
The Board of Directors and Management regularly monitor forecasted distributable cash and payout
ratio. The Board considers a number of factors, including expectations of future commodity prices,
capital expenditure requirements, and the availability of debt and equity capital. Pursuant to the
Royalty Indenture, the Board can establish a reserve for certain items including up to 20 percent
of Gross Revenue to fund various costs including future capital expenditures, royalty income in any
future period and future abandonment costs.
Cash distributions are paid to unitholders on the 15th day of the second month following
the month of production. Pengrowth paid $0.75 per trust unit as cash distributions during the
third quarter of 2006.
Taxability of Distributions
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.
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 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.
Summary of Quarterly Results
The following table is a summary of quarterly results for 2006, 2005 and 2004.
This table also shows the relatively high commodity prices sustained throughout all quarter
results, which have had a positive impact on net income and distributable cash.
|
|
|
|
|
|
|
|
|
|
|
|
|
2006 |
|
Q1 |
|
Q2 |
|
Q3 |
|
Oil and gas sales ($000s) |
|
|
291,896 |
|
|
|
283,532 |
|
|
|
287,757 |
|
Net income ($000s) |
|
|
66,335 |
|
|
|
110,116 |
|
|
|
82,542 |
|
Net income per trust unit ($) |
|
|
0.41 |
|
|
|
0.69 |
|
|
|
0.51 |
|
Net income per trust unit diluted ($) |
|
|
0.41 |
|
|
|
0.68 |
|
|
|
0.51 |
|
Distributable cash ($000s) |
|
|
144,177 |
|
|
|
149,080 |
|
|
|
143,347 |
|
Actual distributions paid or declared per trust unit ($) |
|
|
0.75 |
|
|
|
0.75 |
|
|
|
0.75 |
|
Daily production (boe) |
|
|
58,845 |
|
|
|
56,325 |
|
|
|
58,344 |
|
Total production (mboe) |
|
|
5,296 |
|
|
|
5,126 |
|
|
|
5,368 |
|
Average realized price ($ per boe) |
|
|
55.04 |
|
|
|
54.91 |
|
|
|
53.67 |
|
Operating netback ($ per boe) |
|
|
31.44 |
|
|
|
33.94 |
|
|
|
30.82 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2005 |
|
Q1 |
|
Q2 |
|
Q3 |
|
Q4 |
|
Oil and gas sales ($000s) |
|
|
239,913 |
|
|
|
253,189 |
|
|
|
304,484 |
|
|
|
353,923 |
|
Net income ($000s) |
|
|
56,314 |
|
|
|
53,106 |
|
|
|
100,243 |
|
|
|
116,663 |
|
Net income per trust unit ($) |
|
|
0.37 |
|
|
|
0.34 |
|
|
|
0.63 |
|
|
|
0.73 |
|
Net income per trust unit diluted ($) |
|
|
0.37 |
|
|
|
0.34 |
|
|
|
0.63 |
|
|
|
0.73 |
|
Distributable cash ($000s) |
|
|
127,804 |
|
|
|
134,047 |
|
|
|
162,009 |
|
|
|
195,879 |
|
Actual distributions paid or declared per trust unit ($) |
|
|
0.69 |
|
|
|
0.69 |
|
|
|
0.69 |
|
|
|
0.75 |
|
Daily production (boe) |
|
|
59,082 |
|
|
|
57,988 |
|
|
|
58,894 |
|
|
|
61,442 |
|
Total production (mboe) |
|
|
5,317 |
|
|
|
5,277 |
|
|
|
5,418 |
|
|
|
5,653 |
|
Average realized price ($ per boe) |
|
|
44.97 |
|
|
|
47.79 |
|
|
|
56.07 |
|
|
|
62.55 |
|
Operating netback ($ per boe) |
|
|
27.70 |
|
|
|
29.26 |
|
|
|
33.94 |
|
|
|
38.81 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2004 |
|
Q1 |
|
Q2 |
|
Q3 |
|
Q4 |
|
Oil and gas sales ($000s) |
|
|
168,771 |
|
|
|
197,284 |
|
|
|
226,514 |
|
|
|
223,183 |
|
Net income ($000s) |
|
|
38,652 |
|
|
|
32,684 |
|
|
|
51,271 |
|
|
|
31,138 |
|
Net income per trust unit ($) |
|
|
0.31 |
|
|
|
0.24 |
|
|
|
0.38 |
|
|
|
0.23 |
|
Net income per trust unit diluted ($) |
|
|
0.31 |
|
|
|
0.24 |
|
|
|
0.38 |
|
|
|
0.23 |
|
Distributable cash ($000s) |
|
|
92,895 |
|
|
|
99,021 |
|
|
|
104,304 |
|
|
|
104,958 |
|
Actual distributions paid or declared per trust unit ($) |
|
|
0.63 |
|
|
|
0.64 |
|
|
|
0.67 |
|
|
|
0.69 |
|
Daily production (boe) |
|
|
45,668 |
|
|
|
51,451 |
|
|
|
60,151 |
|
|
|
57,425 |
|
Total production (mboe) |
|
|
4,156 |
|
|
|
4,682 |
|
|
|
5,534 |
|
|
|
5,283 |
|
Average realized price ($ per boe) |
|
|
40.37 |
|
|
|
41.83 |
|
|
|
40.90 |
|
|
|
42.08 |
|
Operating netback ($ per boe) |
|
|
25.71 |
|
|
|
25.71 |
|
|
|
22.77 |
|
|
|
24.31 |
|
Subsequent Events
On October 2, 2006 Pengrowth and Esprit completed the previously announced business combination
of Pengrowth and Esprit (the Combination). Under the terms of the agreement, each Esprit trust
unit was exchanged for 0.53 of a Pengrowth trust unit (the new trust units from the consolidation
of Pengrowths Class A and Class B trust units effective on July 27, 2006). The Combination was
approved by in excess of 99 percent of the votes cast at the Esprit unitholder meeting held on
September 26, 2006. As a result of the
Combination, approximately 35,514,327 Pengrowth trust units were issued to Esprit unitholders,
including 789,170 Pengrowth trust units issued to the Corporation which were exchanged with and
immediately cancelled by Pengrowth.
On October 27, 2006 Pengrowth entered into an exclusivity agreement with a third party with respect
to a possible significant asset acquisition. Under the terms of the agreement, Pengrowth has made
a $30 million payment as an exclusivity fee. If Pengrowth chooses not to proceed, the $30 million
is not refundable. If the vendor chooses not to
proceed, the $30 million is refundable. Pengrowth is now in the process of determining whether it
will proceed in light of a variety of considerations, including the recent Federal Government
announcement on taxability of Trusts. Pengrowth has no information as to whether the vendor will
proceed.
Subsequent to September 30, 2006, Pengrowth has entered into a series of fixed price commodity
sales contracts with third parties. The effect of these contracts is to fix the price received in
2007 for approximately 16,250 boe per day. Including contracts entered into prior to the third
quarter, the total volumes subject to fixed price commodity sales contracts is approximately 21,920
boe per day for the majority of 2007.
Outlook
At this time, Pengrowth anticipates full year production of 62,500 to 63,500 boe per day, up
from its previous production guidance of 56,000 to 57,500 boe per day. The increase in estimated
production is mainly as a result of the Carson Creek area and the Esprit acquisitions. The fourth
quarter production is estimated at 79,000 boe per day. This two percent decrease relative to our
previous 81,000 boe per day estimate at acquisition is due to a combination of temporary
third-party facility restrictions at Willesden Green and Three Hills; on-going well remediation and
optimization work in Carson Creek; and weather-related delays in drilling and tie-ins across most
areas. Offsetting the additions from acquisitions and planned 2006 development activities are the
Monterey and other minor previously disclosed divestitures and expected production declines from
normal operations. The above estimate excludes the impact from other future acquisitions or
divestitures.
Pengrowth expects to increase its total operating expenses for 2006 to approximately $245 million,
up from its previous guidance of $220 million as a result of the Esprit strategic business
combination and the Carson Creek area acquisition. Assuming Pengrowths average production results
for 2006 are as forecast above, Pengrowth now estimates 2006 operating expenses per boe of between
$10.55 and $10.75 and combined G&A and management fees of approximately $2.30 to $2.40 per boe.
Pengrowth currently anticipates capital expenditures for maintenance and development of
approximately $280 million for 2006, up from our previous guidance of $261 million. The increase
from our previous guidance includes post acquisition capital expenditures primarily related to the
Esprit business combination.
Disclosure Controls and Procedures
The Chief Executive Office, James Kinnear, and the Chief Financial Officer, Christopher
Webster, have evaluated Pengrowths disclosure controls and procedures for the period ending
September 30, 2006. Based on that evaluation, there has not been any change in the companys
disclosure controls and procedures and internal controls over financial reporting during the last
fiscal quarter that has materially affected, or is reasonably likely to materially affect,
Pengrowths internal controls over financial reporting.
CONFERENCE CALL AND CONTACT INFORMATION
Pengrowth will hold a conference call beginning at 9:00 A.M. Mountain Time on Thursday,
November 2, 2006 during which management will review Pengrowths 2006 third quarter financial and
operating results and respond to inquiries from the investment community. To participate callers
may dial (800) 814-4853 or Toronto local (416) 644-3422. To ensure timely participation in the
teleconference, callers are encouraged to dial in 10 to 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 on the
Pengrowth website. A telephone replay will be
available through to midnight Eastern Time on Thursday, November 9, 2006 by dialing (877)
289-8525 or Toronto local (416) 640-1917 and entering passcode number 21206447#. 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
Operations Review
REVIEW OF DEVELOPMENT ACTIVITIES (All volumes stated below are net to Pengrowth unless
otherwise stated)
In addition to the acquisitions announced in the third quarter, Pengrowth remained focused on
developing internal opportunities. Development capital in the quarter totaled $56.8 million with
approximately 75 percent directed towards drilling and completions. During the quarter, Pengrowth
drilled 93 gross (43.7 net) wells with a 94 percent success rate.
NORTHEAST BRITISH COLUMBIA (NEBC) / NORTHWEST ALBERTA
|
|
|
A farmout well was drilled at Grand Prairie and is currently undergoing
production testing. |
|
|
|
At Cutbank, three non-operated wells were drilled and are on production at a combined
initial rate of 5.1mmcf per day. Four additional wells are planned for the fourth quarter
of 2006. |
|
|
|
Two successful oil wells were drilled at Rigel adding 210 bbls per day. |
|
|
|
Devon, the operator of the Dunvegan Gas Unit, drilled five successful gas wells that are
expected to be tied in during the fourth quarter. |
|
|
|
Monterey drilled eight wells in the quarter with Pengrowth participating in seven of
those wells. This resulted in four gas wells, one suspended well and two dry holes. Tie
in of the gas wells is expected during the fourth quarter of this year. |
CENTRAL
|
|
|
During the quarter, 13 wells were drilled at the Weyburn Unit bringing the total
number of wells drilled at the property in 2006 to 38. An additional 13 to 17 wells are
expected to be drilled before year end. The 2006 drilling program has been very
successful adding 9,397 bbls per day (917 bbls per day net) of incremental production. |
|
|
|
At Swan Hills, the last well in a four well program was drilled during the third quarter.
Three of the four wells averaged 510 bbls per day (114 bbls per day net) of production.
The fourth well of the 2006 program is expected to commence production in the fourth
quarter of 2006. Work is underway on the development of two new miscible patterns
including the drilling of a new injection well to support solvent injection which will
also commence in the upcoming quarter. |
|
|
|
Tie in work on three new West Pembina wells was completed and incremental production of
2.6 mmcf per day was realized. One non-operated well (50 percent working interest) was
drilled and cased in the quarter at West Pembina. |
|
|
|
An infill oil producer at Judy Creek which was rig released in the second quarter of 2006
was brought on production in the third quarter and has a current oil rate of 95 bbls per
day. |
|
|
|
Power interruptions due to severe lightning storms in August resulted in electrical
operational problems and 13 days of reduced production at Judy Creek of approximately 400
bbls of oil per day. |
SOUTHERN
|
|
|
In the Twining area, completions on the 11 wells of phase one of the coalbed
methane (CBM) program were completed in the third quarter. Five of the 11 wells were
tied in and began production during the quarter. |
|
|
|
A 50 well CBM program (Phase 2) commenced with the drilling of 10 wells (average working
interest of 61 percent) in the third quarter. |
|
|
|
Partners drilled 17 wells of which 15 are expected to be completed for CBM production.
The remaining two wells are anticipated to be on stream in the fourth quarter of 2006. |
|
|
|
Pengrowth drilled, completed and tied in 16 wells (100 percent working interest) at
Princess in the third quarter targeting shallow gas. |
|
|
|
Two wells (100 percent working interest) were drilled and cased at Elnora and Trochu.
Testing is expected to commence in the fourth quarter of 2006. |
|
|
|
A Pekisko gas well in the Twining Unit (88 percent working interest) was successfully
tested at 0.71 mmcf per day. |
|
|
|
At Monogram, a 70 well re-frac program was completed adding 1.75 mmcf per day (0.94 mmcf
per day net) of incremental production. |
|
|
|
Production testing of the new Quirk Creek gas well (68 percent working interest) was
completed in the third quarter. It commenced production in October at approximately 5
mmcf per day (3.4 mmcf per day net). |
|
|
|
At Mikwan/Three Hills, four Belly River and Mannville conventional wells were drilled and
completed and all tested gas. |
HEAVY OIL
|
|
|
During the quarter, three horizontal wells at East Bodo came on stream at 150
bbls of oil per day. |
SABLE OFFSHORE ENERGY PROJECT (SOEP)
Production
|
|
|
Third quarter gross raw gas production from the five SOEP fields Thebaud, Venture, North
Triumph, Alma and South Venture averaged 416 mmcf per day (35 mmcf per day net). |
|
|
|
Monthly raw gas production for July, August and September was 433 mmcf per day (36.4 mmcf
per day net); 427 mmcf per day (35.9 mmcf per day net); and 387 mmcf per day (32.5 mmcf
per day net), respectively. |
|
|
|
Production was reduced in the third quarter due to a required September shutdown in order
to test the compression control systems and complete final tie ins. |
|
|
|
Pengrowth shipped approximately 67,000 bbls of condensate in the third quarter. |
|
|
|
A condensate cargo expected for late September was moved to early October. |
Tier II Status as of September 30, 2006
|
|
|
Shutdown to test compression computer and instrumentation systems started on September
20, 2006. |
|
|
|
Modifications to the Goldboro gas plant were also made during the shutdown. |
|
|
|
In-service for the compressor is scheduled for late 2006. |
Consolidated Balance Sheet
(Stated in thousands of dollars)
|
|
|
|
|
|
|
|
|
|
|
As at |
|
|
As at |
|
|
|
September 30 |
|
|
December 31 |
|
|
|
2006 |
|
|
2005 |
|
|
|
|
(unaudited) |
|
|
(audited) |
|
ASSETS |
|
|
|
|
|
|
|
|
CURRENT ASSETS |
|
|
|
|
|
|
|
|
Cash |
|
$ |
928 |
|
|
$ |
|
|
Accounts receivable |
|
|
105,116 |
|
|
|
127,394 |
|
|
|
|
|
106,044 |
|
|
|
127,394 |
|
|
|
|
|
|
|
|
|
|
UNREALIZED MARK-TO-MARKET GAIN ON
COMMODITY CONTRACTS |
|
|
16,637 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
OTHER ASSETS (Note 8) |
|
|
19,434 |
|
|
|
13,215 |
|
|
|
|
|
|
|
|
|
|
LONG TERM INVESTMENTS (Note 4) |
|
|
26,990 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
GOODWILL (Note 3) |
|
|
315,666 |
|
|
|
182,835 |
|
|
|
|
|
|
|
|
|
|
PROPERTY, PLANT AND EQUIPMENT (Note 3) |
|
|
2,556,802 |
|
|
|
2,067,988 |
|
|
|
|
|
|
|
|
|
|
|
|
|
$ |
3,041,573 |
|
|
$ |
2,391,432 |
|
|
|
|
|
|
|
|
|
|
|
LIABILITIES AND UNITHOLDERS EQUITY |
|
|
|
|
|
|
|
|
CURRENT LIABILITIES |
|
|
|
|
|
|
|
|
Bank indebtedness |
|
$ |
|
|
|
$ |
14,567 |
|
Accounts payable and accrued liabilities |
|
|
124,600 |
|
|
|
111,493 |
|
Distributions payable to unitholders |
|
|
92,252 |
|
|
|
79,983 |
|
Due to Pengrowth Management Limited |
|
|
4,418 |
|
|
|
8,277 |
|
Other liabilities (Note 12) |
|
|
24,573 |
|
|
|
25,279 |
|
|
|
|
|
245,843 |
|
|
|
239,599 |
|
|
|
|
|
|
|
|
|
|
CONTRACT LIABILITIES |
|
|
9,683 |
|
|
|
12,937 |
|
|
|
|
|
|
|
|
|
|
LONG TERM DEBT (Note 2) |
|
|
459,910 |
|
|
|
368,089 |
|
|
|
|
|
|
|
|
|
|
ASSET RETIREMENT OBLIGATIONS (Notes 3 and 7) |
|
|
229,793 |
|
|
|
184,699 |
|
|
|
|
|
|
|
|
|
|
FUTURE INCOME TAXES (Note 3) |
|
|
207,979 |
|
|
|
110,112 |
|
|
|
|
|
|
|
|
|
|
TRUST UNITHOLDERS EQUITY (Note 5) |
|
|
|
|
|
|
|
|
Trust Unitholders capital |
|
|
3,040,038 |
|
|
|
2,514,997 |
|
Contributed surplus |
|
|
5,393 |
|
|
|
3,646 |
|
Deficit |
|
|
(1,157,066 |
) |
|
|
(1,042,647 |
) |
|
|
|
|
1,888,365 |
|
|
|
1,475,996 |
|
|
|
SUBSEQUENT EVENTS (Note 13) |
|
|
|
|
|
|
|
|
|
|
$ |
3,041,573 |
|
|
$ |
2,391,432 |
|
|
See accompanying notes to the consolidated financial statements.
Consolidated Statements of Income and Deficit
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(Stated in thousands of dollars) |
|
|
|
|
|
|
(unaudited) |
|
|
|
|
|
|
|
|
Three months ended |
|
|
Nine months ended |
|
|
|
September 30 |
|
|
September 30 |
|
|
|
2006 |
|
|
2005 |
|
|
2006 |
|
|
2005 |
|
|
|
REVENUES |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil and gas sales |
|
$ |
287,757 |
|
|
$ |
304,484 |
|
|
$ |
863,185 |
|
|
$ |
797,587 |
|
Processing and other income |
|
|
3,319 |
|
|
|
2,039 |
|
|
|
10,524 |
|
|
|
11,771 |
|
Royalties, net of incentives |
|
|
(57,810 |
) |
|
|
(57,414 |
) |
|
|
(168,435 |
) |
|
|
(145,879 |
) |
|
|
|
|
233,266 |
|
|
|
249,109 |
|
|
|
705,274 |
|
|
|
663,479 |
|
Interest and other income |
|
|
1,389 |
|
|
|
74 |
|
|
|
2,085 |
|
|
|
1,916 |
|
|
NET REVENUE |
|
|
234,655 |
|
|
|
249,183 |
|
|
|
707,359 |
|
|
|
665,395 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
EXPENSES |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating |
|
|
58,748 |
|
|
|
57,371 |
|
|
|
170,768 |
|
|
|
156,885 |
|
Transportation |
|
|
1,760 |
|
|
|
1,969 |
|
|
|
5,299 |
|
|
|
5,584 |
|
Amortization of injectants for miscible floods |
|
|
8,756 |
|
|
|
5,969 |
|
|
|
25,263 |
|
|
|
17,322 |
|
Interest |
|
|
7,051 |
|
|
|
5,644 |
|
|
|
19,340 |
|
|
|
16,786 |
|
General and administrative |
|
|
7,729 |
|
|
|
7,559 |
|
|
|
25,246 |
|
|
|
21,765 |
|
Management fee |
|
|
2,999 |
|
|
|
3,537 |
|
|
|
10,557 |
|
|
|
11,588 |
|
Foreign exchange (gain) loss (Note 9) |
|
|
123 |
|
|
|
(12,255 |
) |
|
|
(8,997 |
) |
|
|
(8,470 |
) |
Depletion and depreciation |
|
|
83,513 |
|
|
|
73,541 |
|
|
|
222,396 |
|
|
|
213,594 |
|
Accretion (Note 7) |
|
|
4,490 |
|
|
|
3,578 |
|
|
|
11,721 |
|
|
|
10,531 |
|
Unrealized gain (loss) on commodity contracts (Notes 1 and 11) |
|
|
(20,026 |
) |
|
|
|
|
|
|
(16,637 |
) |
|
|
|
|
Other expenses |
|
|
1,365 |
|
|
|
1,511 |
|
|
|
6,142 |
|
|
|
3,225 |
|
|
|
|
|
156,508 |
|
|
|
148,424 |
|
|
|
471,098 |
|
|
|
448,810 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
NET INCOME BEFORE TAXES |
|
|
78,147 |
|
|
|
100,759 |
|
|
|
236,261 |
|
|
|
216,585 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
INCOME TAX EXPENSE |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Capital |
|
|
|
|
|
|
605 |
|
|
|
11 |
|
|
|
1,497 |
|
Future (Reduction) |
|
|
(4,395 |
) |
|
|
(89 |
) |
|
|
(22,743 |
) |
|
|
5,425 |
|
|
|
|
|
(4,395 |
) |
|
|
516 |
|
|
|
(22,732 |
) |
|
|
6,922 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
NET INCOME |
|
$ |
82,542 |
|
|
$ |
100,243 |
|
|
$ |
258,993 |
|
|
$ |
209,663 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Deficit, beginning of period |
|
|
(1,107,095 |
) |
|
|
(1,029,842 |
) |
|
|
(1,042,647 |
) |
|
|
(922,996 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Distributions declared |
|
|
(132,513 |
) |
|
|
(109,853 |
) |
|
|
(373,412 |
) |
|
|
(326,119 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
DEFICIT, END OF PERIOD |
|
$ |
(1,157,066 |
) |
|
$ |
(1,039,452 |
) |
|
$ |
(1,157,066 |
) |
|
$ |
(1,039,452 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
NET INCOME PER TRUST UNIT (Note 5) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Basic |
|
$ |
0.51 |
|
|
$ |
0.63 |
|
|
$ |
1.61 |
|
|
$ |
1.34 |
|
Diluted |
|
$ |
0.51 |
|
|
$ |
0.63 |
|
|
$ |
1.60 |
|
|
$ |
1.34 |
|
|
See accompanying notes to the consolidated financial statements.
Consolidated Statements of Cash Flow
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(Stated in thousands of dollars) |
|
|
|
|
|
|
(unaudited) |
|
|
|
|
|
|
|
|
Three months ended |
|
|
Nine months ended |
|
|
|
September 30 |
|
|
September 30 |
|
|
|
2006 |
|
|
2005 |
|
|
2006 |
|
|
2005 |
|
|
|
CASH PROVIDED BY (USED FOR): |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
OPERATING |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income |
|
$ |
82,542 |
|
|
$ |
100,243 |
|
|
$ |
258,993 |
|
|
$ |
209,663 |
|
Depletion, depreciation and accretion |
|
|
88,003 |
|
|
|
77,119 |
|
|
|
234,117 |
|
|
|
224,125 |
|
Future income taxes |
|
|
(4,395 |
) |
|
|
(89 |
) |
|
|
(22,743 |
) |
|
|
5,425 |
|
Contract liability amortization |
|
|
(1,320 |
) |
|
|
(1,448 |
) |
|
|
(3,960 |
) |
|
|
(4,346 |
) |
Amortization of injectants |
|
|
8,756 |
|
|
|
5,969 |
|
|
|
25,263 |
|
|
|
17,322 |
|
Purchase of injectants |
|
|
(7,886 |
) |
|
|
(6,861 |
) |
|
|
(25,183 |
) |
|
|
(20,176 |
) |
Expenditures on remediation |
|
|
(1,970 |
) |
|
|
(1,676 |
) |
|
|
(5,820 |
) |
|
|
(4,300 |
) |
Unrealized foreign exchange (gain) loss (Note 9) |
|
|
300 |
|
|
|
(12,860 |
) |
|
|
(9,060 |
) |
|
|
(8,180 |
) |
Unrealized gain on commodity contracts (Notes 1 and 11) |
|
|
(20,026 |
) |
|
|
|
|
|
|
(16,637 |
) |
|
|
|
|
Trust unit based compensation (Note 6) |
|
|
936 |
|
|
|
608 |
|
|
|
2,847 |
|
|
|
2,137 |
|
Deferred charges |
|
|
(2,721 |
) |
|
|
(4,283 |
) |
|
|
(5,085 |
) |
|
|
(4,283 |
) |
Amortization of deferred charges |
|
|
724 |
|
|
|
1,465 |
|
|
|
4,016 |
|
|
|
2,255 |
|
Changes in non-cash operating working capital (Note 10) |
|
|
31,351 |
|
|
|
789 |
|
|
|
47,471 |
|
|
|
1,840 |
|
|
|
|
|
174,294 |
|
|
|
158,976 |
|
|
|
484,219 |
|
|
|
421,482 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
FINANCING |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Distributions |
|
|
(120,698 |
) |
|
|
(109,455 |
) |
|
|
(361,143 |
) |
|
|
(323,252 |
) |
Change in long term debt, net |
|
|
(30,000 |
) |
|
|
(26,428 |
) |
|
|
97,000 |
|
|
|
64,541 |
|
Proceeds from issue of trust units |
|
|
506,550 |
|
|
|
15,477 |
|
|
|
523,941 |
|
|
|
32,007 |
|
|
|
|
|
355,852 |
|
|
|
(120,406 |
) |
|
|
259,798 |
|
|
|
(226,704 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
INVESTING |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Expenditures on property acquisitions |
|
|
(473,883 |
) |
|
|
(2,861 |
) |
|
|
(528,045 |
) |
|
|
(94,427 |
) |
Expenditures on property, plant and equipment |
|
|
(56,774 |
) |
|
|
(40,050 |
) |
|
|
(179,028 |
) |
|
|
(114,486 |
) |
Proceeds on property dispositions |
|
|
(1,998 |
) |
|
|
18,623 |
|
|
|
15,755 |
|
|
|
18,623 |
|
Change in remediation trust fund |
|
|
(599 |
) |
|
|
(272 |
) |
|
|
(1,269 |
) |
|
|
(804 |
) |
Purchase of long term investments |
|
|
|
|
|
|
|
|
|
|
(19,990 |
) |
|
|
|
|
Change in non-cash investing working capital (Note 10) |
|
|
2,839 |
|
|
|
1,527 |
|
|
|
(15,945 |
) |
|
|
1,527 |
|
|
|
|
|
(530,415 |
) |
|
|
(23,033 |
) |
|
|
(728,522 |
) |
|
|
(189,567 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
CHANGE IN CASH AND BANK INDEBTEDNESS |
|
|
(269 |
) |
|
|
15,537 |
|
|
|
15,495 |
|
|
|
5,211 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
CASH (BANK INDEBTEDNESS) AT BEGINNING OF PERIOD |
|
|
1,197 |
|
|
|
(14,540 |
) |
|
|
(14,567 |
) |
|
|
(4,214 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
CASH AT END OF PERIOD |
|
$ |
928 |
|
|
$ |
997 |
|
|
$ |
928 |
|
|
$ |
997 |
|
|
See accompanying notes to the consolidated financial statements.
Notes To Consolidated Financial Statements
(Unaudited)
September 30, 2006
(Tabular dollar amounts are stated in thousands of dollars except per trust unit amounts)
1. |
|
SIGNIFICANT ACCOUNTING POLICIES |
|
|
|
The interim consolidated financial statements of Pengrowth Energy Trust include the
accounts of Pengrowth Energy Trust (the Trust), Pengrowth Corporation (the Corporation) and its
subsidiaries (collectively referred to as Pengrowth). The financial statements do not
contain the accounts of Pengrowth Management Limited (the Manager). |
|
|
|
The financial statements have been prepared by management in accordance with generally
accepted accounting principles in Canada. The interim consolidated financial statements
have been prepared following the same accounting policies and methods of computation as the
consolidated financial statements for the fiscal year ended
December 31, 2005, except as
discussed below. The disclosures provided below are incremental to those included with the
annual consolidated financial statements. The interim consolidated financial statements should be
read in conjunction with the consolidated financial statements and the notes thereto in
Pengrowths annual report for the year ended December 31, 2005. |
|
|
|
FINANCIAL INSTRUMENTS |
|
|
Effective May 1, 2006, Pengrowth no longer designates new commodity contracts as hedges.
Commodity contracts that do not qualify as hedges, or are not designated as hedges, are
recorded using the fair value method of accounting whereby instruments are recorded in the
consolidated balance sheet as either an asset or liability with
changes in fair value recognized
in net earnings. Realized gains or losses from financial derivatives related to commodity
prices are recognized in natural gas and crude oil revenues as the related sales occur.
Unrealized gains and losses are recognized in expenses at the end of each respective
reporting period. The fair value of derivative instruments is based
on quoted market prices or, in
its absence, estimated using third party market indications and forecasts. |
|
|
|
Commodity contracts are used by Pengrowth to manage economic exposure to market risks
relating to commodity prices. Pengrowths policy is not to utilize derivative financial
instruments for speculative purposes. |
|
|
|
Financial derivative contracts previously designated as hedges continue to be designated as
hedges and are accounted for as disclosed in the annual financial statements. |
|
2. |
|
LONG TERM DEBT |
|
|
|
|
|
|
|
|
|
|
|
As at |
|
|
As at |
|
|
|
September 30, |
|
|
December 31, |
|
|
|
2006 |
|
|
2005 |
|
|
U.S. dollar denominated debt: |
|
|
|
|
|
|
|
|
U.S. $150 million senior unsecured notes at 4.93 percent due
April 2010 |
|
$ |
167,655 |
|
|
$ |
174,450 |
|
U.S. $50 million senior unsecured notes at 5.47 percent due
April 2013 |
|
|
55,885 |
|
|
|
58,150 |
|
|
|
|
|
223,540 |
|
|
|
232,600 |
|
Pound sterling denominated 50 million unsecured notes at
5.46 percent due December 2015 |
|
|
104,370 |
|
|
|
100,489 |
|
Canadian dollar revolving credit facility |
|
|
132,000 |
|
|
|
35,000 |
|
|
|
|
$ |
459,910 |
|
|
$ |
368,089 |
|
|
|
|
On June 16, 2006, Pengrowth entered into a new $500 million extendible revolving term
credit facility syndicated among eight financial institutions. The facility is unsecured,
covenant based and has a three year term. Pengrowth has the option to extend the facility
each year, subject to the approval of the lenders, or repay the entire balance at the end of
the three year term. Various borrowing options are available under the facility including
prime rate based advances and bankers acceptance loans. This facility carries floating
interest rates that are expected to range between 0.65 percent and 1.15 percent over
bankers acceptance rates, depending on Pengrowths consolidated ratio of senior debt to
earnings before interest, taxes and non-cash items. In addition, Pengrowth has a $35 million
demand operating line of credit for working capital purposes. The facilities were reduced by
drawings of $132 million and by outstanding letters of credit in the amount of approximately
$17 million at September 30, 2006. |
|
|
|
On October 2, 2006, concurrent with the closing of the business combination with Esprit
Energy Trust (Esprit), Pengrowth increased its extendible revolving credit facility to
$950,000,000 and the addition of two new financial institutions into the syndicate. No other
material changes were made to the credit facility. $315 million of the increase was used to
repay and cancel Esprits credit facility, leaving over $500 million available to draw from
the credit facility. |
|
3. |
|
CORPORATE ACQUISITION |
|
|
|
On September 28, 2006, Pengrowth acquired all of the issued and outstanding shares of a
company which has interests in oil and natural gas assets in the Carson Creek area of
Alberta (the Carson Creek 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: |
|
|
|
|
Property, plant and equipment |
|
$ |
502,270 |
|
Goodwill |
|
|
132,831 |
|
Asset retirement obligations |
|
|
(38,874 |
) |
Future income taxes |
|
|
(120,610 |
) |
|
|
|
$ |
475,617 |
|
|
|
Cost of Acquisition: |
|
|
|
|
Cash |
|
$ |
475,558 |
|
Acquisition costs |
|
|
59 |
|
|
|
|
$ |
475,617 |
|
|
|
|
Property, plant and equipment of $502 million represents the fair value of the assets
acquired determined in part by an independent reserve evaluation. Goodwill of $133 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 tax liability.
|
|
|
|
The future income tax liability was determined based on the enacted income tax rate of
approximately 29 percent. The asset retirement obligations were determined using
Pengrowths estimated costs to remediate, reclaim and abandon the wells and facilities, the
estimated timing of the costs to be incurred in future periods, an inflation rate of two
percent, and a discount rate of eight percent. |
|
|
|
Results of operations from the Carson Creek acquisition subsequent to the acquisition date
are included in the consolidated financial statements. Final determination of the cost of
the acquisition and the allocation thereof to the fair values of the Carson Creek assets is
still pending. |
|
4. |
|
LONG TERM INVESTMENTS |
|
|
|
|
|
|
|
|
|
|
|
September 30, 2006 |
|
December 31, 2005 |
|
Investment in Esprit Energy Trust |
|
$ |
19,990 |
|
|
|
|
|
Equity investments |
|
|
7,000 |
|
|
|
|
|
|
|
|
$ |
26,990 |
|
|
|
|
|
|
|
|
INVESTMENT IN ESPRIT ENERGY TRUST |
|
|
On July 24, 2006, Pengrowth announced an agreement providing for the combination of
Pengrowth and Esprit (See Note 13). As at September 30, 2006, Pengrowth held 1,489,000
Esprit trust units with a market value of approximately $17.3 million. The investment is
accounted for at cost. Distributions earned on the Esprit trust units of $1.4 million are
recorded in other income, as received. On October 2, 2006, in connection with the business
combination with Esprit, the Corporation received 789,170 Pengrowth trust units which were
exchanged with and immediately cancelled by Pengrowth. |
|
|
|
EQUITY INVESTMENTS |
|
|
On January 12, 2006 Pengrowth closed certain transactions with Monterey Exploration Ltd.
(Monterey) under which Pengrowth has sold certain oil and gas properties for $22 million in
cash, less closing adjustments, and 8,048,132 common shares of |
|
|
|
Monterey. As of September 30,
2006, Pengrowth held approximately 34 percent of the common shares of Monterey.
Pengrowth utilizes the equity method of accounting for the investment in Monterey. The
investment is initially recorded at cost and adjusted thereafter to include Pengrowths pro
rata share of post-acquisition earnings of Monterey. Any dividends received or receivable
from Monterey would reduce the carrying value of the investment. |
|
5. |
|
TRUST UNITHOLDERS EQUITY |
|
|
|
Trust Unitholders Capital |
|
|
|
The total authorized capital of Pengrowth is 500,000,000 trust units. |
|
|
|
Total Trust Units: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Nine months ended |
|
Year ended |
|
|
September 30, 2006 |
|
December 31, 2005 |
|
|
Number |
|
|
|
|
|
Number |
|
|
Trust units issued |
|
of trust units |
|
Amount |
|
of trust units |
|
Amount |
|
Balance, beginning of period |
|
|
159,864,083 |
|
|
$ |
2,514,997 |
|
|
|
152,972,555 |
|
|
$ |
2,383,284 |
|
Issued for the Crispin acquisition (non-
cash) |
|
|
|
|
|
|
|
|
|
|
4,225,313 |
|
|
|
87,960 |
|
Issued for cash |
|
|
23,310,000 |
|
|
|
526,806 |
|
|
|
|
|
|
|
|
|
Issue costs |
|
|
|
|
|
|
(27,886 |
) |
|
|
|
|
|
|
|
|
Issued on redemption of Deferred |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Entitlement Trust Units (DEUs) |
|
|
12,106 |
|
|
|
193 |
|
|
|
|
|
|
|
|
|
Issued for cash on exercise of trust unit
options and rights |
|
|
553,270 |
|
|
|
8,613 |
|
|
|
1,512,211 |
|
|
|
21,818 |
|
Issued for cash under Distribution |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Reinvestment Plan (DRIP) |
|
|
719,780 |
|
|
|
16,408 |
|
|
|
1,154,004 |
|
|
|
20,726 |
|
Trust unit rights incentive plan (non-cash
exercised) |
|
|
|
|
|
|
907 |
|
|
|
|
|
|
|
1,209 |
|
|
Balance, end of period |
|
|
184,459,239 |
|
|
$ |
3,040,038 |
|
|
|
159,864,083 |
|
|
$ |
2,514,997 |
|
|
Consolidated Trust Units:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Nine months ended |
|
Year ended |
|
|
September 30, 2006 |
|
December 31, 2005 |
|
|
Number |
|
|
|
|
|
Number |
|
|
Trust units issued |
|
of trust units |
|
Amount |
|
of trust units |
|
Amount |
|
Balance, beginning of period |
|
|
|
|
|
$ |
|
|
|
|
|
|
|
$ |
|
|
Issued in trust unit consolidation |
|
|
160,921,001 |
|
|
|
2,535,949 |
|
|
|
|
|
|
|
|
|
Issued for cash |
|
|
23,310,000 |
|
|
|
526,806 |
|
|
|
|
|
|
|
|
|
Issue costs |
|
|
|
|
|
|
(27,886 |
) |
|
|
|
|
|
|
|
|
Issued on redemption of DEUs |
|
|
12,106 |
|
|
|
193 |
|
|
|
|
|
|
|
|
|
Issued for cash on exercise of trust unit
options and rights |
|
|
44,732 |
|
|
|
716 |
|
|
|
|
|
|
|
|
|
Issued for cash under DRIP |
|
|
156,432 |
|
|
|
3,774 |
|
|
|
|
|
|
|
|
|
Trust unit rights incentive plan (non-cash
exercised) |
|
|
|
|
|
|
255 |
|
|
|
|
|
|
|
|
|
|
Balance, end of period |
|
|
184,444,271 |
|
|
$ |
3,039,807 |
|
|
|
|
|
|
$ |
|
|
|
Class A Trust Units:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Nine months ended |
|
Year ended |
|
|
September 30, 2006 |
|
December 31, 2005 |
|
|
Number |
|
|
|
|
|
Number |
|
|
Trust units issued |
|
of trust units |
|
Amount |
|
of trust units |
|
Amount |
|
Balance, beginning of period |
|
|
77,524,673 |
|
|
$ |
1,196,121 |
|
|
|
76,792,759 |
|
|
$ |
1,176,427 |
|
Issued for the Crispin acquisition (non-
cash) |
|
|
|
|
|
|
|
|
|
|
686,732 |
|
|
|
19,002 |
|
Trust units converted to (from) Class A
trust units |
|
|
2,760 |
|
|
|
43 |
|
|
|
45,182 |
|
|
|
692 |
|
Trust units converted to consolidated
trust units |
|
|
(77,512,465 |
) |
|
|
(1,195,933 |
) |
|
|
|
|
|
|
|
|
|
Balance, end of period |
|
|
14,968 |
|
|
$ |
231 |
|
|
|
77,524,673 |
|
|
$ |
1,196,121 |
|
|
Class B Trust Units:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Nine months ended |
|
Year ended |
|
|
September 30, 2006 |
|
December 31, 2005 |
|
|
Number |
|
|
|
|
|
Number |
|
|
Trust units issued |
|
of trust units |
|
Amount |
|
of trust units |
|
Amount |
|
Balance, beginning of period |
|
|
82,301,443 |
|
|
$ |
1,318,294 |
|
|
|
76,106,471 |
|
|
$ |
1,205,734 |
|
Trust units converted to (from) Class B
trust units |
|
|
1,095 |
|
|
|
17 |
|
|
|
(9,824 |
) |
|
|
(151 |
) |
Issued for the Crispin acquisition (non-
cash) |
|
|
|
|
|
|
|
|
|
|
3,538,581 |
|
|
|
68,958 |
|
Issued for cash on exercise of trust unit
options and rights |
|
|
508,538 |
|
|
|
7,897 |
|
|
|
1,512,211 |
|
|
|
21,818 |
|
Issued for cash under DRIP |
|
|
563,348 |
|
|
|
12,634 |
|
|
|
1,154,004 |
|
|
|
20,726 |
|
Trust unit rights incentive plan (non-cash
exercised) |
|
|
|
|
|
|
652 |
|
|
|
|
|
|
|
1,209 |
|
Trust units converted to consolidated
trust units |
|
|
(83,374,424 |
) |
|
|
(1,339,494 |
) |
|
|
|
|
|
|
|
|
|
Balance, end of period |
|
|
|
|
|
$ |
|
|
|
|
82,301,443 |
|
|
$ |
1,318,294 |
|
|
Unclassified Trust Units:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Nine months ended |
|
Year ended |
|
|
September 30, 2006 |
|
December 31, 2005 |
|
|
Number |
|
|
|
|
|
Number |
|
|
Trust units issued |
|
of trust units |
|
Amount |
|
of trust units |
|
Amount |
|
Balance, beginning of period |
|
|
37,967 |
|
|
$ |
582 |
|
|
|
73,325 |
|
|
$ |
1,123 |
|
Converted to Class A or Class B trust
units |
|
|
(3,855 |
) |
|
|
(60 |
) |
|
|
(35,358 |
) |
|
|
(541 |
) |
Trust units converted to consolidated
trust units |
|
|
(34,112 |
) |
|
|
(522 |
) |
|
|
|
|
|
|
|
|
|
Balance, end of period |
|
|
|
|
|
$ |
|
|
|
|
37,967 |
|
|
$ |
582 |
|
|
Class A Trust Unit and Class B Trust Unit Consolidation
On June 23, 2006 the Pengrowth unitholders voted to consolidate the Class A trust units and Class
B trust units into one class of trust units (consolidated trust units). As a result:
Effective as of 5:00 p.m. (MDT) on June 27, 2006, the restrictions on the Class B trust units
that provided that the Class B trust units may only be held by residents of Canada was eliminated.
Effective as of 5:00 p.m. (MDT) on July 27, 2006;
|
|
|
the Class A trust units were delisted from the Toronto Stock Exchange (effective as
of the close of markets); |
|
|
|
|
the Class B trust units were renamed consolidated trust units and the trading symbol
of the consolidated trust units was changed from PGF.B to PGF.UN; |
|
|
|
|
all of the issued and outstanding Class A trust units were converted into
consolidated trust units on the basis of one consolidated trust unit for each whole Class
A trust unit previously held (with the exception of Class A trust units held by residents
of Canada who have provided a residency declaration to the Trustee); |
|
|
|
|
the consolidated trust units were substitutionally listed in place of the Class A
trust units on the New York Stock Exchange under the symbol PGH; and |
|
|
|
|
the unclassified trust units were converted into consolidated trust units on the
basis of one consolidated trust unit for each unclassified trust unit held. |
Per Trust Unit Amounts
The per trust unit amounts of net income are based on the following weighted average trust units
outstanding for the period. The weighted average trust units outstanding for the three months
ended September 30, 2006 were 161,502,209 trust units (September 30, 2005 158,789,481 trust
units) and for the nine months ended September 30, 2006 were 160,752,712 trust units (September 30,
2005 156,318,245). In computing diluted net income per trust unit, 670,218 trust units were added
to the weighted average number of trust units outstanding during the three months ended September
30, 2006 (September 30, 2005 507,494 trust units) and 647,654 trust units were added to the
weighted average number of trust units outstanding during the nine months ended September 30, 2006
(September 30, 2005 502,233) for the dilutive effect of trust unit options, rights and deferred
entitlement trust units (DEUs). For the three months ended September 30, 2006, no anti-dilutive
options, rights or DEUs (September 30, 2005 10,140) and for the nine months ended September 30,
2006 no anti-dilutive options, rights or DEUs (September 30, 2005 549,284), were excluded from
the diluted net income per trust unit calculation as their effect is anti-dilutive.
Contributed Surplus
|
|
|
|
|
|
|
|
|
|
|
Nine months ended |
|
Year ended December |
|
|
September 30, 2006 |
|
31, 2005 |
|
Balance, beginning of period |
|
$ |
3,646 |
|
|
$ |
1,923 |
|
Trust unit rights incentive plan (non-cash expensed) |
|
|
1,056 |
|
|
|
1,740 |
|
DEUs (non-cash expensed) |
|
|
1,791 |
|
|
|
1,192 |
|
Trust unit rights incentive plan (non-cash exercised) |
|
|
(907 |
) |
|
|
(1,209 |
) |
Redemption of DEUs (non-cash exercised) |
|
|
(193 |
) |
|
|
|
|
|
Balance, end of period |
|
$ |
5,393 |
|
|
$ |
3,646 |
|
|
Deficit
|
|
|
|
|
|
|
|
|
|
|
As at |
|
As at |
|
|
September 30, 2006 |
|
December 31, 2005 |
|
Accumulated earnings |
|
$ |
1,312,376 |
|
|
$ |
1,053,383 |
|
Accumulated distributions paid or declared |
|
|
(2,469,442 |
) |
|
|
(2,096,030 |
) |
|
|
|
$ |
(1,157,066 |
) |
|
$ |
(1,042,647 |
) |
|
|
|
Pengrowth is obligated by virtue of its Royalty and Trust Indentures to distribute to
unitholders a significant portion of its cash flow from operations. Cash flow from operations
typically exceeds net income as a result of non-cash expenses such as depletion, depreciation and
accretion. These non-cash expenses result in a deficit being recorded despite Pengrowth
distributing less than its cash flow from operations. |
|
6. |
|
TRUST UNIT BASED COMPENSATION PLANS |
|
|
|
Trust Unit Option Plan As at September 30, 2006, options to purchase 109,323 trust units
were outstanding (December 31, 2005 259,317 Class B trust units) that expire at various dates to
June 28, 2009. All outstanding trust unit options were fully expensed by December 31, 2004. |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Nine months ended |
|
Year ended |
|
|
September 30, 2006 |
|
December 31, 2005 |
|
|
|
|
|
|
Weighted |
|
|
|
|
|
Weighted |
|
|
Number |
|
average |
|
Number |
|
average |
Trust unit options |
|
of options |
|
exercise price |
|
of options |
|
exercise price |
|
Outstanding at beginning of period |
|
|
259,317 |
|
|
$ |
17.28 |
|
|
|
845,374 |
|
|
$ |
16.97 |
|
Exercised |
|
|
(144,594 |
) |
|
$ |
18.09 |
|
|
|
(558,307 |
) |
|
$ |
16.74 |
|
Expired or cancelled |
|
|
(5,400 |
) |
|
$ |
16.96 |
|
|
|
(27,750 |
) |
|
$ |
18.63 |
|
|
Outstanding and exercisable at period-end |
|
|
109,323 |
|
|
$ |
16.23 |
|
|
|
259,317 |
|
|
$ |
17.28 |
|
|
|
|
Trust Unit Rights Incentive Plan
As at September 30, 2006, rights to purchase 1,456,806 trust units were outstanding (December
31, 2005 1,441,737 Class B trust units) that expire at various dates to August 2, 2011. |
|
|
|
Compensation expense associated with the trust unit rights granted during 2006 was based on the
estimated fair value of $1.87 per trust unit right. The fair value of trust unit rights granted
during the nine months ended September 30, 2006 was estimated at eight percent of the exercise
price at the date of grant using a binomial lattice option pricing model with the following
assumptions: risk-free rate of 4.1 percent, volatility of 19 percent and reductions in the exercise
price over the life of the trust unit rights. For the nine months ended September 30, 2006,
compensation expense of $1,056,000 (September 30, 2005 $1,308,000) related to the trust unit
rights was recorded. |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Nine months ended |
|
Year ended |
|
|
September 30, 2006 |
|
December 31, 2005 |
|
|
|
|
|
|
Weighted |
|
|
|
|
|
Weighted |
|
|
Number |
|
average |
|
Number |
|
average |
Trust unit rights |
|
of rights |
|
exercise price |
|
of rights |
|
exercise price |
|
Outstanding at beginning of period |
|
|
1,441,737 |
|
|
$ |
14.85 |
|
|
|
2,011,451 |
|
|
$ |
14.23 |
|
Granted(1) |
|
|
477,366 |
|
|
$ |
23.34 |
|
|
|
606,575 |
|
|
$ |
18.34 |
|
Exercised |
|
|
(408,676 |
) |
|
$ |
14.68 |
|
|
|
(953,904 |
) |
|
$ |
12.81 |
|
Cancelled |
|
|
(53,621 |
) |
|
$ |
16.89 |
|
|
|
(222,385 |
) |
|
$ |
16.19 |
|
|
Outstanding at period-end |
|
|
1,456,806 |
|
|
$ |
16.33 |
|
|
|
1,441,737 |
|
|
$ |
14.85 |
|
|
Exercisable at period-end |
|
|
717,272 |
|
|
$ |
14.11 |
|
|
|
668,473 |
|
|
$ |
13.73 |
|
|
|
|
|
(1) |
|
Weighted average exercise price of rights granted is based on the exercise price at the
date of grant. |
|
|
Long Term Incentive Program As at September 30, 2006, 338,221 DEUs were outstanding
(December 31, 2005 185,591), including accrued distributions re-invested to September 30, 2006.
The DEUs vest on various dates to February 27, 2009. For the nine months ended September 30, 2006,
Pengrowth recorded compensation expense of $1,791,000 (September 30, 2005 - |
|
|
$829,000) associated with the DEUs based on the weighted average estimated fair value of $20.74
(2005 $18.18) per DEU. For the nine months ended September 30, 2006, 12,106 consolidated trust
units were issued on redemption of DEUs by retired employees. |
|
|
|
|
|
|
|
|
|
|
|
Nine months ended |
|
Year ended |
Number of DEUs |
|
September 30, 2006 |
|
December 31, 2005 |
|
Outstanding, beginning of period |
|
|
185,591 |
|
|
|
|
|
Granted |
|
|
165,419 |
|
|
|
194,229 |
|
Cancelled |
|
|
(25,647 |
) |
|
|
(26,258 |
) |
Redeemed |
|
|
(12,106 |
) |
|
|
|
|
Deemed DRIP |
|
|
24,964 |
|
|
|
17,620 |
|
|
Outstanding, end of period |
|
|
338,221 |
|
|
|
185,591 |
|
|
|
|
Trust Unit Award Plans
Pengrowth has an incentive plan to reward and retain employees whereby trust units and, in some
cases trust units and cash, are awarded to eligible employees. Employees will receive the trust
units and cash on or about July 1, 2007. Pengrowth acquired the trust units to be awarded on the
open market for $5.1 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 monthly to net income on a straight line basis. The cash portion of
the incentive plan of approximately $1.1 million is being accrued monthly. |
|
|
During the three months ended September 30, 2006, $0.7 million has been charged to net income and
during the nine months ended September 30, 2006, $4.2 million has been charged to net income. |
7. |
|
ASSET RETIREMENT OBLIGATIONS |
|
|
|
|
|
|
|
|
|
|
|
Nine months ended |
|
Year ended |
|
|
September 30, 2006 |
|
December 31, 2005 |
|
Asset retirement obligations, beginning of period |
|
$ |
184,699 |
|
|
$ |
171,866 |
|
Increase (decrease) in liabilities related to: |
|
|
|
|
|
|
|
|
Acquisitions |
|
|
39,237 |
|
|
|
6,347 |
|
Additions |
|
|
1,455 |
|
|
|
1,972 |
|
Disposals |
|
|
(1,500 |
) |
|
|
(3,844 |
) |
Revisions |
|
|
|
|
|
|
1,549 |
|
Accretion expense |
|
|
11,721 |
|
|
|
14,162 |
|
Liabilities settled during the period |
|
|
(5,819 |
) |
|
|
(7,353 |
) |
|
Asset retirement obligations, end of period |
|
$ |
229,793 |
|
|
$ |
184,699 |
|
|
8. OTHER ASSETS
|
|
|
|
|
|
|
|
|
|
|
As at |
|
As at |
|
|
September 30, 2006 |
|
December 31,2005 |
|
Imputed interest on note payable net of accumulated
amortization of $3,420 (2005 - $2,859) |
|
$ |
187 |
|
|
$ |
748 |
|
Debt issue costs net of accumulated amortization of
$1,098 (2005 - $821) |
|
|
1,720 |
|
|
|
1,997 |
|
Deferred compensation expense net of accumulated
amortization of $5,316 (2005 - $2,143) |
|
|
4,048 |
|
|
|
2,141 |
|
|
|
|
|
5,955 |
|
|
|
4,886 |
|
Deferred foreign exchange gain on revaluation of U.K.
debt hedge |
|
|
3,881 |
|
|
|
|
|
Remediation trust funds |
|
|
9,598 |
|
|
|
8,329 |
|
|
|
|
$ |
19,434 |
|
|
$ |
13,215 |
|
|
9. FOREIGN EXCHANGE (GAIN) LOSS
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three months ended |
|
Nine months ended |
|
|
September 30, |
|
September 30, |
|
|
2006 |
|
2005 |
|
2006 |
|
2005 |
|
Unrealized foreign exchange (gain)
loss on translation of U.S. dollar
denominated debt
|
|
$ |
300 |
|
|
$ |
(12,860 |
) |
|
$ |
(9,060 |
) |
|
$ |
(8,180 |
) |
Realized foreign exchange (gain) loss |
|
|
(177 |
) |
|
|
605 |
|
|
|
63 |
|
|
|
(290 |
) |
|
|
|
$ |
123 |
|
|
$ |
(12,255 |
) |
|
$ |
(8,997 |
) |
|
$ |
(8,470 |
) |
|
|
|
The U.S. dollar and U.K. pound sterling denominated debt are translated into Canadian dollars at
the Bank of Canada exchange rate in effect at the close of business on the balance sheet date.
Foreign exchange gains and losses on the U.S. dollar denominated debt are included in income.
Foreign exchange gains and losses on translating the U.K pound sterling denominated debt and the
associated gains and losses on the U.K. pound sterling denominated exchange swap are deferred and
included in deferred charges. |
|
10. |
|
OTHER CASH FLOW DISCLOSURES |
|
|
|
Change in Non-Cash Operating Working Capital
Cash provided by (used for): |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three months ended |
|
Nine months ended |
|
|
September 30, |
|
September 30, |
|
|
2006 |
|
2005 |
|
2006 |
|
2005 |
|
Accounts receivable |
|
$ |
12,462 |
|
|
$ |
(24,052 |
) |
|
$ |
22,278 |
|
|
$ |
(21,508 |
) |
Inventory |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
439 |
|
Accounts payable and accrued liabilities |
|
|
17,895 |
|
|
|
23,884 |
|
|
|
29,052 |
|
|
|
25,138 |
|
Due to Pengrowth Management Limited |
|
|
994 |
|
|
|
957 |
|
|
|
(3,859 |
) |
|
|
(2,229 |
) |
|
|
|
$ |
31,351 |
|
|
$ |
789 |
|
|
$ |
47,471 |
|
|
$ |
1,840 |
|
|
|
|
Change in Non-Cash Investing Working Capital
Cash provided by (used for): |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three months ended |
|
Nine months ended |
|
|
September 30, |
|
September 30, |
|
|
2006 |
|
2005 |
|
2006 |
|
2005 |
|
Accounts payable for capital accruals |
|
$ |
2,839 |
|
|
$ |
1,527 |
|
|
$ |
(15,945 |
) |
|
$ |
1,527 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three months ended |
|
Nine months ended |
|
|
September 30, |
|
September 30, |
|
|
2006 |
|
2005 |
|
2006 |
|
2005 |
|
Cash payments made (refund received) for taxes |
|
$ |
189 |
|
|
$ |
626 |
|
|
$ |
23 |
|
|
$ |
(266 |
) |
Cash payments made for interest |
|
$ |
2,272 |
|
|
$ |
2,763 |
|
|
$ |
14,715 |
|
|
$ |
12,952 |
|
|
11. |
|
FINANCIAL INSTRUMENTS |
|
|
|
Pengrowth has a price risk management program whereby the commodity price associated with
a portion of its future production is fixed. Pengrowth sells forward a portion of its future
production through a combination of fixed price sales contracts with customers and commodity swap
agreements with financial counterparties. The forward and futures contracts are subject to market
risk from fluctuating commodity prices and exchange rates. |
As at September 30, 2006, Pengrowth had fixed the price and applied hedge accounting to future
production as follows:
Crude Oil:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Volume |
|
Reference |
|
Price |
Remaining Term |
|
(bbl per day) |
|
Point |
|
per bbl |
|
Financial: |
|
|
|
|
|
|
|
|
|
|
|
|
Oct 1, 2006 - Dec 31, 2006 |
|
|
4,000 |
|
|
WTI(1) |
|
$64.08 Cdn |
|
Natural Gas:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Volume |
|
Reference |
|
Price |
Remaining Term |
|
(mmbtu per day) |
|
Point |
|
per mmbtu |
|
Financial: |
|
|
|
|
|
|
|
|
|
|
|
|
Oct 1, 2006 Dec 31, 2006 |
|
|
2,500 |
|
|
Transco Z6(1) |
|
$10.63 Cdn |
Oct 1, 2006 Dec 31, 2006 |
|
|
2,370 |
|
|
AECO |
|
$ 8.03 Cdn |
|
|
|
|
(1) |
|
Associated Cdn $ / U.S. $ foreign exchange rate has been fixed. |
The estimated fair value of the financial crude oil and natural gas contracts has been
determined based on the amounts Pengrowth would receive or pay to terminate the contracts at
period-end. At September 30, 2006, the amount Pengrowth would receive (pay) to terminate the
financial crude oil and natural gas contracts would be $(2.8) million and $1.2 million,
respectively.
As at September 30, 2006, Pengrowth had fixed the price and recognized the
mark-to-market loss on future production as follows:
Crude Oil:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Volume |
|
Reference |
|
Price |
Remaining Term |
|
(bbl per day) |
|
Point |
|
per bbl |
|
Financial: |
|
|
|
|
|
|
|
|
|
|
|
|
Jan 1, 2007 Dec 31, 2007 |
|
|
2,000 |
|
|
WTI(1) |
|
$79.50 Cdn |
Jan 1, 2007 Dec 31, 2007 |
|
|
1,000 |
|
|
WTI(1)
|
|
$86.15 Cdn |
Jan 1, 2007 Dec 31, 2007 |
|
|
1,000 |
|
|
WTI(1) |
|
$86.20 Cdn |
|
Natural Gas:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Volume |
|
Reference |
|
Price |
Remaining Term |
|
(mmbtu per day) |
|
Point |
|
per mmbtu |
|
Financial: |
|
|
|
|
|
|
|
|
|
|
|
|
Nov 1, 2006 Oct 1, 2007 |
|
|
5,000 |
|
|
Transco Z6(1) |
|
$11.62 Cdn |
Nov 1, 2006 Oct 1, 2007 |
|
|
5,000 |
|
|
Chicago MI(1) |
|
$9.69 Cdn |
|
|
|
|
(1) |
|
Associated Cdn $ / U.S. $ foreign exchange rate has been fixed. |
The estimated fair value of the financial crude oil and natural gas contracts has been
determined based on the amounts Pengrowth would receive or pay to terminate the contracts at
period-end. At September 30, 2006, the amount Pengrowth would receive to terminate the financial
crude oil and natural gas contracts would be $10.4 million and $6.2 million, respectively.
Natural Gas Fixed Price Sales Contract:
Pengrowth also has a natural gas fixed price physical sales contract outstanding which was assumed
in the 2004 Murphy acquisition, the details of which are provided below:
|
|
|
|
|
|
|
|
|
|
|
Volume |
|
Price |
Remaining Term |
|
(mmbtu per day) |
|
per mmbtu(2) |
|
2006 to
2009 |
|
|
|
|
|
|
|
|
Oct 1, 2006 Oct 31, 2006 |
|
|
3,886 |
|
|
$2.23 Cdn |
Nov 1, 2006 Oct 31, 2007 |
|
|
3,886 |
|
|
$2.29 Cdn |
Nov 1, 2007 Oct 31, 2008 |
|
|
3,886 |
|
|
$2.34 Cdn |
Nov 1, 2008 Apr 30, 2009 |
|
|
3,886 |
|
|
$2.40 Cdn |
|
|
|
|
(2) |
|
Reference price based on AECO |
As at September 30, 2006, the amount Pengrowth would pay to terminate the natural gas fixed price
sales contract would be $17.8 million.
Fair
Value of Financial Instruments
The carrying value of
financial instruments included in the balance sheet, other than long term debt, the note payable,
long term investments and remediation trust funds approximate their fair value due to their short
maturity. The fair value of the other financial instruments is as follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
As at September 30, 2006 |
|
As at December 31, 2005 |
|
|
|
|
|
|
Net Book |
|
|
|
|
|
Net Book |
|
|
Fair Value |
|
Value |
|
Fair Value |
|
Value |
|
Remediation Funds |
|
$ |
9,980 |
|
|
$ |
9,598 |
|
|
$ |
9,071 |
|
|
$ |
8,329 |
|
U.S. dollar denominated debt |
|
|
215,779 |
|
|
|
223,540 |
|
|
|
220,187 |
|
|
|
232,600 |
|
U. K. £ denominated debt |
|
|
101,874 |
|
|
|
104,370 |
|
|
|
101,257 |
|
|
|
100,489 |
|
|
12. OTHER LIABILITIES
|
|
|
|
|
|
|
|
|
|
|
As at |
|
As at |
|
|
September 30, 2006 |
|
December 31,2005 |
|
Current portion of contract
liabilities |
|
$ |
4,573 |
|
|
$ |
5,279 |
|
Note Payable |
|
|
20,000 |
|
|
|
20,000 |
|
|
|
|
$ |
24,573 |
|
|
$ |
25,279 |
|
|
13. SUBSEQUENT EVENTS
On October 2, 2006 Pengrowth and Esprit announced the completion of the previously announced
business combination. The combination was approved by in excess of 99 percent of the votes cast at
the Esprit unitholder meeting held on September 26, 2006. As a result of the combination,
approximately 35,514,327 Pengrowth trust units were issued to Esprit unitholders, including 789,170
Pengrowth trust units issued to the Corporation which were exchanged with and immediately cancelled
by Pengrowth.
On October 2, 2006, concurrent with the closing of the business combination with Esprit, Pengrowth
increased its extendible revolving credit facility to $950,000,000 and the addition of two new
financial institutions into the syndicate. No other material changes were made to the credit
facility. $315 million of the increase was used to repay and cancel Esprits credit facility,
leaving over $500 million available to draw from the credit facility.
On October 27, 2006, Pengrowth entered into an exclusivity agreement with a third party with
respect to a possible significant asset acquisition. Under the terms of the agreement, Pengrowth
has made a $30 million payment as an exclusivity fee. If Pengrowth chooses not to proceed, the $30
million is not refundable. If the vendor chooses not to proceed, the $30 million is refundable.
Pengrowth is now in the process of determining whether it will proceed in light of a variety of
considerations, including the recent Federal Government announcement on taxability of Trusts.
Pengrowth has no information as to whether the vendor will proceed.
Subsequent to September 30, 2006, Pengrowth has entered into a series of fixed price commodity
sales contracts with third parties. The effect of theses contracts is to fix the price received in
2007 for a volume equivalent to approximately 25 percent of Pengrowths total production for the
nine months ended September 30, 2006. The forward and futures contracts are subject to market risk
from fluctuating commodity prices and exchange rates.
Pengrowth had fixed the price and will recognize the mark-to-market loss on future production in
future periods as follows:
Crude Oil:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Volume |
|
Reference |
|
Price |
Remaining Term |
|
(bbl per day) |
|
Point |
|
per bbl |
|
Financial: |
|
|
|
|
|
|
|
|
|
|
|
|
Jan 1, 2007
Dec 31, 2007 |
|
|
7,000 |
|
|
WTI (1) |
|
$73.49 Cdn |
|
Natural Gas:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Volume |
|
Reference |
|
Price |
Remaining Term |
|
(mmbtu per day) |
|
Point |
|
per mmbtu |
|
Financial: |
|
|
|
|
|
|
|
|
|
|
|
|
Jan 1, 2007 Dec 31,2007 |
|
|
45,020 |
|
|
AECO |
|
$7.98 Cdn |
Jan 1, 2007 Dec
31, 2007 |
|
|
10,500 |
|
|
Chicago MI(1) |
|
$8.89 Cdn |
|
|
|
|
(1) |
|
Associated Cdn $ / U.S. $ foreign exchange rate has been fixed. |
NEWS RELEASE
|
|
|
|
|
Attention: Financial Editors
|
|
Stock Symbol:
|
|
(PGF.UN) - TSX; |
|
|
|
|
(PGH) NYSE |
PENGROWTH ENERGY TRUST ANNOUNCES OFFER TO PURCHASE
OUTSTANDING CONVERTIBLE DEBENTURES
(Calgary November 1, 2006) /CCN Matthews/ Pengrowth Corporation, administrator of Pengrowth
Energy Trust, (collectively, Pengrowth) today announced that it has made an offer to purchase all
the outstanding 6.5 percent convertible extendible unsecured subordinated debentures (the
Debentures).
Following the completion of the business combination with Esprit Energy Trust (Esprit) on October
2, 2006, Pengrowth assumed all the covenants and obligations of Esprit under its Debenture
Indenture providing for the issuance of the Debentures. Pursuant to the change of control
provisions in the Debenture Indenture, Pengrowth is required within 30 days of such change of
control, to make an offer to purchase all the outstanding Debentures at a price equal to 101
percent of the principal amount of the outstanding Debentures, plus any accrued but unpaid interest
(the Offer). The Offer will remain open for 35 days. The Offer expires at 5:00 PM Mountain Time
on December 6, 2006. Holders of the Debentures are not obliged to accept the Offer and Debentures
that are not tendered to the Offer will continue to exist under their current terms.
The Debentures trade on the Toronto Stock Exchange under the symbol PGF.DB and have traded in the
range of $99.45 to $107.00 over the past 12 months. The Debentures closed at $101.50 on October 31,
2006. Each $1,000 principal amount of Debentures is convertible into Pengrowth trust units at
$25.54 per trust unit, which is a rate of approximately 39.16144 Pengrowth trust units for each
$1,000 principal amount of Debentures, subject to the terms and conditions of the Debenture
Indenture. The Debentures mature on December 31, 2010.
Pengrowth Energy Trust is one of the larger energy royalty trusts in North America. Trust units
trade on the Toronto Stock Exchange (PGF.UN) and the New York Stock Exchange (PGH). Through the
purchase of trust units, unitholders participate in the ownership of a large portfolio of crude oil
and natural gas properties, receiving the net cash flow (after expenses and other withholdings),
paid monthly, as the oil and gas reserves are produced. Pengrowths property portfolio is one of
the strongest in the energy trust sector with a proved plus probable reserve life index of 10.6
years and a reserve base of 219.4 million boe at December 31, 2005. Pengrowths assets are
characterized by low decline rates and high development potential allowing for stable production.
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
Advisory:
This news release shall not constitute an offer to sell or the solicitation of an offer to buy
Pengrowth trust units, nor shall there be any sale of Pengrowth trust units in any jurisdiction in
which such offer, solicitation or sale would be unlawful prior to registration or qualification
under the securities laws of such jurisdiction.
Caution Regarding Engineering Terms:
When used herein, the term boe means barrels of oil equivalent on the basis of one boe being equal
to one barrel of oil or NGLs or 6,000 cubic feet of natural gas (6 mcf: 1 bbl). 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.
The U.S. Securities and Exchange Commission (SEC) permits United States oil and natural gas
companies, in their filings therewith, to disclose only proved reserves net of royalties and
interests of others that geological and engineering data demonstrate with reasonable certainty to
be recoverable in future years from known reservoirs under existing economic and operating
conditions. Canadian securities laws permit oil and natural gas companies, in their filings with
Canadian securities regulators, to disclose reserves prior to the deduction of royalties and
interests of others, and to disclose probable reserves. Probable reserves are of a higher risk and
are generally believed to be less likely to be recovered than proved reserves. Certain reserve
information included in the documents incorporated by reference to describe our reserves, such as
probable reserve information, is prohibited in filings with the SEC by U.S. oil and natural gas
companies.
Caution Regarding Forward Looking Information:
This press 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 press release include, but are not limited to, statements with respect
to: the business combination with Esprit, reserves, reserve life
indices, estimated production, remaining producing reserve lives, and development plans and
programs. 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 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 predictions, 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 under
the heading Business Risks in our managements discussion and analysis for the year ended
December 31, 2005 and under Risk Factors in our Annual Information Form dated March 29, 2006.
The foregoing list of factors that may affect future results is not exhaustive. When relying on our
forward-looking statements to make decisions, investors and others should carefully consider the
foregoing factors and other uncertainties and potential events. Furthermore, the forward-looking
statements contained in this press release are made as of the date of this press 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 press release are expressly qualified by this
cautionary statement.