UNITED
STATES
SECURITIES
AND EXCHANGE COMMISSION
Washington,
D.C. 20549
Form
6-K
REPORT
OF FOREIGN ISSUER PURSUANT TO RULE 13A-16 OR 15D-16 OF THE SECURITIES EXCHANGE
ACT OF 1934
For the
month of: May 2005
Commission
File Number: 00-115124
PETROFUND
ENERGY TRUST
(Name of
Registrant)
Barclay
Centre
600
444 7Avenue SW
Calgary,
Alberta
Canada
T2P 0X8
(Address
of Principal Executive Offices)
Indicate
by check mark whether the registrant files or will file annual reports under
cover of Form 20-F or Form 40-F:
Form 20-F
_____ Form 40-F
__X_
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 Securities Exchange Act of 1934:
Yes
______ No
__X_
If “Yes”
is marked, indicate below the file number assigned to the registrant in
connection with Rule 12g3-2(b): N/A
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.
PETROFUND
ENERGY TRUST
Date: May
12, 2005 By: __/s/
Hugo Potts____________
Hugo
StJ. A.
Potts, Esq.
Corporate
Secretary
EXHIBIT
Exhibit |
Description
of Exhibit |
1. |
First
Quarter Report dated May 10, 2005. |
EXHIBIT
1
News
Release
Calgary
- May 10, 2005
Petrofund
Energy
Trust (TSX:
PTF.UN; AMEX: PTF)
Announces
Results for the First Quarter of 2005
Petrofund
Energy Trust is pleased to provide its results for the first quarter of 2005.
Key items from the quarter include:
- |
Average
production of 35,234 boe per day, a 32% increase over the first quarter of
last year. |
- |
Cash
flow increased 49% over the first quarter of 2004 to $73 million, due
primarily to additional production from the Ultima acquisition,
development drilling and higher commodity
prices. |
- |
First
quarter payout ratio remained at 67%, identical to the previous quarter,
and a 6% change from 73% in the first quarter of
2004. |
- |
Operating
costs for the quarter, which include a prior period adjustment of $0.79
per boe, increased to $10.09 per boe due to increasing industry costs.
This was a 23% increase over first quarter of last
year. |
- |
General
and administrative costs down 12% from last year to $1.15 per boe.
|
- |
The
Trust exited the quarter with a 1.0:1.0 debt to cash flow ratio based on
annualized first quarter cash flow. |
- |
Invested
$48 million in drilling and development activities resulting in 73 wells
with a 97% success rate. Partially as a result of this success, the Trust
is announcing a 33% increase in its 2005 development budget from $90
million to $120 million. |
Petrofund's
first quarter report is presented below:
[Missing Graphic Reference]
1st
Quarter Report
for
the three months ended March 31, 2005
FINANCIAL HIGHLIGHTS
|
|
(thousands
of Canadian dollars and units, except per unit amounts) |
|
|
|
2005 |
|
2004 |
|
Variance |
|
INCOME
STATEMENT |
|
|
|
|
|
|
|
Oil
and natural gas sales |
|
$ |
154,768 |
|
$ |
99,699 |
|
|
55 |
% |
Cash
flow (1) |
|
$ |
72,959 |
|
$ |
49,047 |
|
|
49 |
% |
Per
unit (2) |
|
$ |
0.73 |
|
$ |
0.67 |
|
|
9 |
% |
Per
boe |
|
$ |
23.01 |
|
$ |
20.26 |
|
|
14 |
% |
Cash
distributions paid per unit |
|
$ |
0.48 |
|
$ |
0.48 |
|
|
- |
% |
Net
income |
|
$ |
19,243 |
|
$ |
7,629 |
|
|
152 |
% |
Net
income per unit |
|
|
|
|
|
|
|
|
|
|
Basic |
|
$ |
0.19 |
|
$ |
0.10 |
|
|
90 |
% |
Diluted |
|
$ |
0.19 |
|
$ |
0.10 |
|
|
90 |
% |
UNITS
AND EXCHANGEABLE SHARES OUTSTANDING (2) |
|
|
|
|
|
|
|
|
|
|
Weighted
average |
|
|
100,603 |
|
|
73,674 |
|
|
37 |
% |
Diluted |
|
|
100,644 |
|
|
73,872 |
|
|
36 |
% |
At
period-end |
|
|
100,746 |
|
|
73,682 |
|
|
37 |
% |
BALANCE
SHEET |
|
|
|
|
|
|
|
|
|
|
Working
capital (deficit) (3) |
|
$ |
(59,531 |
) |
$ |
(56,093 |
) |
|
(6 |
)% |
Property,
plant and equipment, net |
|
$ |
1,259,248 |
|
$ |
883,191 |
|
|
43 |
% |
Long-term
debt |
|
$ |
239,237 |
|
$ |
90,040 |
|
|
166 |
% |
Unitholders’
equity |
|
$ |
992,882 |
|
$ |
615,952 |
|
|
61 |
% |
MARKET
CAPITALIZATION, as at
March 31 |
|
$ |
1,777,156 |
|
$ |
1,278,390 |
|
|
39 |
% |
TOTAL
CAPITALIZATION, as
at March 31 (3),(4)
|
|
$ |
2,075,924 |
|
$ |
1,424,523 |
|
|
46 |
% |
TRUST
UNIT TRADING (TSX: PTF.UN) |
|
|
|
|
|
|
|
|
|
|
High |
|
$ |
19.33 |
|
$ |
19.24 |
|
|
- |
% |
Low |
|
$ |
15.50 |
|
$ |
14.56 |
|
|
6 |
% |
Close |
|
$ |
17.64 |
|
$ |
17.35 |
|
|
2 |
% |
Average
daily volumes |
|
|
264
|
|
|
204 |
|
|
29 |
% |
TRUST
UNIT TRADING (AMEX: PTF) |
|
|
|
|
|
|
|
|
|
|
High |
|
$ |
16.05 |
|
$ |
14.96 |
|
|
7 |
% |
Low |
|
$ |
12.66 |
|
$ |
10.95 |
|
|
16 |
% |
Close |
|
$ |
14.62 |
|
$ |
13.22 |
|
|
11 |
% |
Average
daily volumes |
|
|
643 |
|
|
633 |
|
|
2 |
% |
(1) Cash
flow before net changes in non-cash operating working capital balances
(Non-GAAP
measure, see special notes in the Management Discussion and
Analysis).
(2) See
Note 2 to Interim Consolidated Financial Statements.
(3) Excludes
net unrealized losses on commodity contracts.
(4) Total
capitalization equals market capitalization plus net debt.
|
OPERATIONAL
HIGHLIGHTS
|
|
(thousands
of Canadian dollars, except per unit amounts) |
|
DAILY
PRODUCTION |
|
|
2005 |
|
|
2004 |
|
Variance |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil
(bbls) |
|
|
18,238 |
|
|
11,579 |
|
|
58 |
% |
|
Natural
gas (mcf) |
|
|
88,271 |
|
|
77,925 |
|
|
13 |
% |
|
Natural
gas liquids (bbls) |
|
|
2,283 |
|
|
2,040 |
|
|
12 |
% |
|
BOE
(6:1) |
|
|
35,234 |
|
|
26,607 |
|
|
32 |
% |
|
Total
production (mboe) |
|
|
3,171 |
|
|
2,421 |
|
|
31 |
% |
|
PRODUCTION
PROFILE |
|
|
|
|
|
|
|
|
Oil
|
|
|
52 |
% |
|
44 |
% |
|
|
|
|
Natural
gas |
|
|
42 |
% |
|
48 |
% |
|
|
|
|
Natural
gas liquids |
|
|
6 |
% |
|
8 |
% |
|
|
|
|
PRICES
|
|
|
|
|
|
|
|
|
Oil
(per bbl) |
|
$ |
54.74 |
|
$ |
42.50 |
|
|
29 |
% |
Natural
gas (per mcf) |
|
$ |
6.97 |
|
$ |
6.76 |
|
|
3 |
% |
Natural
gas liquids (per bbl) |
|
$ |
46.04 |
|
$ |
37.06 |
|
|
24 |
% |
BOE
(6:1) |
|
$ |
48.79 |
|
$ |
41.15 |
|
|
19 |
% |
Cash
operating netback per BOE |
|
$ |
25.45 |
|
$ |
22.71 |
|
|
12 |
% |
LEASE
OPERATING COSTS |
|
$ |
32,010 |
|
$ |
19,829 |
|
|
(61 |
)% |
Cost
per boe |
|
$ |
10.09 |
|
$ |
8.19 |
|
|
(23 |
)% |
GENERAL
AND ADMINISTRATIVE COSTS |
|
$ |
3,639 |
|
$ |
3,138 |
|
|
(16 |
)% |
Cost
per boe |
|
$ |
1.15 |
|
$ |
1.30 |
|
|
12 |
% |
SPECIAL
NOTES
As
discussed per the February 2005 notice of the annual meeting, Peter N. Thomson
did not stand for re-election, as director, at the April 13, 2005 meeting of the
Unitholders.
As
announced in March 2005, Mr. Edward J. Brown joined on April 1, 2005 as Vice
President, Finance. Mr. Brown was subsequently appointed Chief Financial Officer
on May 1, 2005, upon the retirement of Vince P. Moyer.
Management
Discussion & Analysis
three
months ended March 31, 2005
The
following Management Discussion and Analysis (MD&A) of financial results
should be read in conjunction with the unaudited Consolidated Financial
Statements of Petrofund Energy Trust (“Petrofund” or the “Trust”) for the three
months ended March 31, 2005 and the December 31, 2004 audited consolidated
financial statements and management’s discussion and analysis included in the
Petrofund Energy Trust 2004 annual report. All the oil and natural gas
properties are held by Petrofund Corp. (“PC”) a wholly owned subsidiary of the
Trust. This commentary is based on information available to May 10, 2005.
Additional information (including Petrofund’s annual information form) can be
obtained on Sedar at www.sedar.com or on the Trust’s website at
www.petrofund.ca.
All
amounts are stated in Canadian dollars unless otherwise noted. Where amounts and
volumes are expressed on a barrel of oil equivalent (“boe”) basis, gas volumes
have been converted to barrels of oil at 6,000 cubic feet per barrel (6
mcf/bbl). BOEs may be misleading, particularly if used in isolation. A BOE
conversion of 6 mcf/1 bbl is based on an energy equivalency conversion method
primarily applicable at the burner tip and does not represent a value
equivalency at the wellhead.
NON
GAAP MEASURES
Management
uses cash flow (before changes in non-cash working capital) to analyze operating
performance and leverage. Cash flow as presented does not have any standardized
meaning prescribed by Canadian generally accepted accounting principles (“GAAP”)
and may not be comparable with the calculation of similar measures for other
entities. Cash flow as presented is not intended to represent operating cash
flows or operating profits for the period, nor should it be viewed as an
alternative to cash flow from operating activities, net earnings or other
measures of financial performance calculated in accordance with Canadian GAAP.
All references to cash flow throughout this report are based on cash flow before
changes in non-cash working capital.
Management
uses certain key performance indicators and industry benchmarks such as
operating netbacks ("netbacks"), finding, development and acquisition costs
("FD&A"), and total capitalization to analyze financial and operating
performance. These performance indicators and benchmarks as presented do not
have any standardized meaning prescribed by Canadian GAAP and, therefore, may
not be comparable with the calculation of similar measures for other
entities.
FORWARD-LOOKING
STATEMENTS
This
disclosure includes statements about expected future events and/or financial
results that are forward-looking in nature and subject to substantial risks and
uncertainties. For those statements, Petrofund claims the protection of the safe
harbor for forward-looking statements provisions contained in the U.S. Private
Securities Litigation Reform Act of 1995. Petrofund cautions that actual
performance will be affected by a number of factors, many of which are beyond
its control. These include general economic conditions in Canada and the United
States; industry conditions including changes in laws and regulations; changes
in
income
tax regulations; increased competition; and fluctuations in commodity prices,
foreign exchange and interest rates. In addition, there are numerous risks and
uncertainties associated with oil and natural gas operations and the evaluation
of oil and natural gas reserves. As a result, future events and results may vary
substantially from what Petrofund currently foresees.
A more
complete discussion of the various factors that may affect future results is
contained in Petrofund’s recent filings with the Securities and Exchange
Commission and Canadian securities regulatory authorities.
RESULT
SUMMARY
FIRST
QUARTER 2005 VERSUS FOURTH QUARTER 2004
The Trust
generated cash flow of $73.0 million or $0.73 per unit in the first quarter of
2005 compared to $72.3 million or $0.72 per unit in the fourth quarter of 2004.
The Trust maintained monthly cash distributions of $0.16 per unit and a payout
ratio of 67% in the first quarter of 2005.
The first
quarter of 2005 was one of the most active quarters in its history for
Petrofund’s drilling and development activities. Total expenditures for the
quarter were $48.4 million. These activities will provide new production in the
second and third quarters of 2005, as discussed further in the Operational
Highlights.
Daily
production volumes in the first quarter of 2005 of 35,234 boe were slightly
below fourth quarter volumes of 2004 of 36,025 boe. This decrease resulted from
the natural production decline and the temporary shut in of production at one
minor property, but was partially offset by production additions from
development activities.
Net
income of $19.2 million in the first quarter of 2005 decreased from $50.9
million in the fourth quarter of 2004 mainly due to a change of $50.2 million in
non-cash adjustments on commodity contracts. The Trust recognized an unrealized
(non-cash) commodity adjustment of $23.8 million versus an unrealized (non-cash)
commodity gain of $26.4 million in the fourth quarter of 2004. Both adjustments
were a result of the accounting standard governing price risk management
activity. In addition, the future income tax recovery in the first quarter of
2005 was $12.7 million compared to $774,000 expense in the fourth quarter of
2004.
The cash
loss on commodity contracts during the first quarter of 2005 was $8.2 million
compared to a $14.1 million loss in the fourth quarter of 2004.
Royalties
were 20% of revenue in the first quarter of 2005, compared to 20% for the three
months ended December 31, 2004.
Lease
operating costs increased to $10.09/boe in the first quarter of 2005 from
$8.82/boe in the fourth quarter of 2004. The most significant contributor to the
higher operating costs in the first quarter of 2005 versus 2004 was general
industry increases for all types of services including surface and downhole well
repair costs and facility maintenance work. Costs in the first quarter of 2005
included prior year adjustments from operators of $2.5 million or $0.79 per
boe.
HIGHLIGHTS
OF THE THREE MONTHS ENDED MARCH 31, 2005
The Trust
paid out cash distributions of $0.48 per unit in the first quarter of 2005 as
compared to $0.48 per unit in the first quarter of 2004.
The
Trust’s payout ratio for the three months ended March 31, 2005 was 67% remaining
the same as the fourth quarter of 2004 and compared to 73% in the first quarter
of 2004.
Net
income increased 152% to $19.2 million in the first quarter of 2005 versus $7.6
million in the first quarter of 2004.
The Trust
generated cash flow of $73.0 million, an increase of 49% over the first quarter
of 2004.
Average
production on a boe basis increased 32% to 35,234 boe/d in the first quarter of
2005 from 26,607 boe/d in the first quarter of 2004.
Average
prices in the first quarter of 2005 were up 19% on a boe basis from the same
period the prior year.
Petrofund
has a strong balance sheet with a net debt to cash flow ratio of 1.0:1.0 of
annualized first quarter 2005 cash flow.
The Trust
has a balanced production profile which averaged 42% natural gas and 58% oil and
liquids in the first quarter of 2005.
The
weighted average Trust units outstanding increased from 73.7 million in the
first quarter of 2004 to 100.6 million in the first quarter of
2005.
The Trust
market capitalization as at March 31, 2005, was approximately $1.8 billion ($1.3
billion March 31, 2004).
OPERATIONAL
HIGHLIGHTS
Petrofund
had an active drilling program in the first quarter of 2005, with 73 wells
drilled. The program consisted of 70 working interest wells (23.2 net) and three
farmout wells resulting in 50 gas wells, 20 oil wells, one service well and two
dry and abandoned wells for an overall 97% success rate. Following is a summary
of properties where significant activity occurred.
July
Lake, British Columbia
Petrofund
finished drilling four wells of a five well program in the shortened winter
drilling season. The wells were all successful horizontal Jean Marie gas wells
and Petrofund has 100% working interest in all the wells. A pipeline gathering
system and compressor station were completed before break-up resulting in all
four wells commencing production at quarter end. It is expected these wells will
provide approximately 5.5 mmcf/d new production to Petrofund in the second
quarter of 2005.
Turin,
Alberta
At the
Turin property in southern Alberta, Petrofund commenced a 10 well drilling
program in February. At quarter end, six wells had been drilled (4.75 net)
resulting in four oil wells, one gas well and one unproductive well. The wells
are currently being completed and new production facilities are under
construction to tie the wells into existing treating facilities. The
unproductive wellbore may be utilized as a water injection well. Expected
production increase from the five wells is approximately 200 boe/d net to
Petrofund and is scheduled to come on stream in May 2005.
Three
Hills Creek, Alberta
Petrofund
participated in the drilling of 26 wells (9.1 net) as part of the ongoing CBM
(coalbed methane) development in this area. Testing of the wells is underway and
facilities are currently being installed to bring the production on stream in
the third quarter of 2005. Petrofund’s net share of this production is expected
to be 750 mcf/d.
Weyburn,
Saskatchewan
In the
Weyburn Unit, 11 horizontal infill wells (2.3 net) were drilled in the first
quarter of 2005. Eight of these 11 wells were re-entries, where additional
horizontal legs are drilled from existing welbores. Petrofund’s net production
from these wells of 250 boe/d will be seen during the second quarter of
2005.
Border,
British Columbia
Nine
Bluesky-Gething gas wells (0.8 net) were drilled in the Border ”B” Unit this
winter. Production from the new wells will help offset the natural production
decline from the reservoir and maintain gas throughput at the Border gas plant.
Petrofund’s net production from these wells totals 1.0 mmcf/d.
Fort
Saskatchewan, Alberta
A
production optimization review of the low pressure gas gathering system for our
Beaverhill Lake Viking Gas Unit (95% WI) resulted in the installation of a 750
hp booster compressor giving an immediate gain of 400 mcf/d and allowing a
significant further expected increase in ultimate recovery as the upgrade will
be capable of taking the entire field to much lower pressures.
The
upgrade has also allowed the Lindbrook facility to handle new production from a
100% WI deep gas well that started production in March at 500 mcf/d and will
also allow opportunities for custom processing.
Cherhill,
Alberta
The
central oil treating facility at Cherhill was expanded in March to increase
produced water handling capability. This expansion has allowed Petrofund to
restart several high water-cut oil wells that were shut in due to lack of
capacity. Petrofund will also now be able to upsize the pumps on several
producing oil wells and expects to realize a total gain of 150 bbl/d of oil
production during the second quarter of 2005.
Ferrier,
Alberta
Compression
was installed to increase production capacity at the Ferrier gas plant. A
workover and tie-in of a standing well, along with continued optimization should
increase production by approximately 1.5 mmcf/d.
Armisie,
Alberta
The
Armisie field was shut in for approximately eight weeks during the first quarter
of 2005 due to restrictions at the gas processing plant that handles the Armisie
solution gas and non associated gas. This restriction is not likely to reoccur.
Petrofund lost approximately 400 boe/d production during the
shut-in.
CASH
DISTRIBUTIONS
For
the three months ended March 31, |
2005 |
2004 |
Distributions
paid per unit |
$0.48 |
$0.48 |
Trust
unitholders who held their units throughout first quarter of 2005 received cash
distributions of $0.48 per unit as compared to $0.48 per unit in 2004. For 2005
the Trust distributed $0.16 per unit in April, has announced $0.16 per unit for
May, and has indicated $0.16 per unit for June.
The Trust
generated cash flow available for distribution before reserve for capital
expenditures in the first quarter of 2005 of $71.7 million. The Trust paid out
$47.9 million in distributions representing a payout ratio of 67%.
For the
12 months ended March 31, 2005, the Trust generated cash flow available for
distribution of $255.3 million, and allocated $87.4 million for investment in
development drilling and other projects. Distributions of $182.5 million were
paid out, representing a payout ratio of 71%. For a detailed analysis of cash
flow available for distribution and distributions paid refer to Note 7 to the
Interim Consolidated Financial Statements.
RESULTS
OF OPERATIONS
PRODUCTION
In
accordance with Canadian practice, production volumes and reserves are reported
on a working interest basis, before deduction of Crown and other royalties,
unless otherwise indicated.
Production
volumes averaged 35,234 boe/d in the first quarter of 2005, an increase of 32%
over average production volumes of 26,607 boe/d in the first quarter of 2004.
The change in production reflects the acquisition of Ultima in June of 2004,
PC’s development drilling program and the Central Alberta acquisition in
November 2004.
For
the three months ended March 31, |
2005 |
2004 |
Daily
Production
|
|
|
Oil
(bbls) |
18,238 |
11,579 |
Natural
gas (mcf) |
88,271 |
77,925 |
Natural
gas liquids (bbls) |
2,283 |
2,040 |
Total
(boe 6:1) |
35,234 |
26,607 |
PRICING
& PRICE RISK MANAGEMENT
Revenues
from the sale of crude oil, natural gas, and natural gas liquids and sulphur
increased 55% to $154.8 million in the first quarter of 2005 from $99.7 million
in the first quarter of 2004 due to a 31% increase in production and a 19%
increase in prices on a boe basis.
Crude oil
sales increased to $89.9 million in the first quarter of 2005 from $44.8 million
in the first quarter of 2004 due to a 58% increase in production from 11,579
bbl/d in the first quarter of 2004 to 18,238 bbl/d in the first quarter of 2005
and a 29% increase in the oil price. The average WTI oil price increased from
$35.14 US/bbl in 2004 to $49.84 US/bbl in the first quarter of 2005 or 42%;
however, the Canadian par price at Edmonton increased only 35% from $45.60/bbl
to $61.45/bbl due to the significant strengthening of the Canadian dollar
relative to the U.S. dollar which averaged $0.82 in the first quarter of 2005
versus $0.76 in the first quarter of 2004. The average Canadian wellhead price
received by Petrofund increased from $42.50/bbl in the first quarter of 2004 to
$54.74/bbl in the first quarter of 2005. Petrofund’s differential from Edmonton
par was $3.10/bbl in the first quarter of 2004 versus $6.71/bbl in the first
quarter of 2005 as quality differentials for medium crudes have
increased.
Natural
gas sales increased to $55.4 million in the first quarter of 2005 from $48.0
million in the first quarter of 2004 due to a 13% increase in production and a
3% increase in the average prices received from $6.76/mcf in the first quarter
of 2004 to $6.97/mcf in the first quarter of 2005. The monthly AECO price per
mmbtu increased from $6.61 in the first quarter of 2004 to $6.69 in the first
quarter of 2005. Production volumes averaged 88.3 mmcf/d in the first quarter of
2005 compared to 77.9 mmcf/d in the first quarter of 2004.
Sales of
natural gas liquids and sulphur increased to $9.5 million in the first quarter
of 2005 from $6.9 million in the first quarter of 2004 as production increased
to 2,283 bbl/d in the first quarter of 2005 from 2,040 bbl/d in the first
quarter of 2004. The average price increased from $37.06/bbl in the first
quarter of 2004 to $46.04/bbl in the first quarter of 2005.
Average
prices received for the three months ended March
31, |
2005 |
2004 |
Oil
(per bbl) (1) |
$ 54.74 |
$
42.50 |
Natural
gas (per mcf) (1) |
6.97 |
6.76 |
Natural
gas liquids (per bbl) (1) |
46.04 |
37.06 |
Weighted
average (6:1) |
$ 48.79 |
$
41.15 |
(1) Prices
are before realized gains/losses on commodity contracts and before
transportation costs.
Production
Revenue ($
millions) |
2005 |
2004 |
Oil |
$ 89.9 |
$
44.8 |
Natural
gas |
55.4 |
48.0 |
Natural
gas liquids & sulphur |
9.5 |
6.9 |
Total |
$ 154.8 |
$
99.7 |
The Trust
has a formal risk management policy which permits the risk management committee
to use specified price risk management strategies for up to 40% of crude oil,
natural gas and NGL production including: fixed price contracts; costless
collars; the purchase of floor price options; and other derivative financial
instruments to reduce price volatility and ensure minimum prices for a maximum
of eighteen months beyond the current date. The program is designed to provide
price protection on a portion of the Trust’s future production in the event of
adverse commodity price movement, while retaining significant exposure to upside
price movements. By doing this, the Trust seeks to provide a measure of
stability to cash distributions as well as ensure Petrofund realizes positive
economic returns from its capital development and acquisition activities.
As at
March 31, 2005, Petrofund had 24.7 mmcf/d of natural gas and 5,000 bbl/d of
crude oil hedged for remainder of 2005. A summary of the hedged volumes and
prices by quarter is shown in the following table (see Note 8 to the Interim
Consolidated Financial Statements for a detailed disclosure of all derivative
financial instruments and their corresponding mark-to-market values):
|
|
Average
Volumes (mcf/d) |
|
|
|
2005 |
|
2006 |
|
Natural
Gas |
|
2005 |
|
Q2 |
|
Q3 |
|
Q4 |
|
Q1 |
|
Q2 |
|
Fixed
|
|
3,158 |
|
4,737 |
|
4,737 |
|
- |
|
- |
|
- |
|
Collars |
|
15,790
|
|
18,948 |
|
18,948
|
|
9,474
|
|
4,737 |
|
- |
|
Three
way collars |
|
5,790
|
|
4,737 |
|
4,737 |
|
7,895 |
|
9,474 |
|
- |
|
Total
mcf/d |
|
24,738
|
|
28,422 |
|
28,422
|
|
17,369
|
|
14,211 |
|
- |
|
|
|
|
|
|
|
Average
Prices ($/mcf) |
|
Fixed
price |
|
$ |
7.06 |
|
$ |
7.07 |
|
$ |
7.06 |
|
$ |
- |
|
$ |
- |
|
$ |
- |
|
Collar
ceiling price |
|
|
9.81 |
|
|
8.73 |
|
|
8.73 |
|
|
11.98 |
|
|
13.61 |
|
|
- |
|
Collar
floor price |
|
|
6.54 |
|
|
6.33 |
|
|
6.33 |
|
|
6.96 |
|
|
7.28 |
|
|
- |
|
Three
way ceiling price |
|
|
8.78 |
|
|
7.92 |
|
|
7.92 |
|
|
10.49 |
|
|
11.77 |
|
|
- |
|
Three
way floor price |
|
|
5.96 |
|
|
5.80 |
|
|
5.80 |
|
|
6.28 |
|
|
6.52 |
|
|
- |
|
Three
way floor short |
|
$ |
4.91 |
|
$ |
4.75 |
|
$ |
4.75 |
|
$ |
5.23 |
|
$ |
5.47 |
|
$ |
- |
|
|
|
Average
Volumes (bbl/d) |
|
|
|
2005 |
|
2006 |
|
Oil |
|
2005 |
|
Q2 |
|
Q3 |
|
Q4 |
|
Q1 |
|
Q2 |
|
Collared
|
|
1,000 |
|
1,000 |
|
1,000 |
|
1,000 |
|
2,000 |
|
- |
|
Three
way collars |
|
4,000
|
|
4,000
|
|
4,000
|
|
4,000
|
|
1,000 |
|
1,000 |
|
Total
bbl/d |
|
5,000
|
|
5,000
|
|
5,000
|
|
5,000
|
|
3,000 |
|
1,000 |
|
|
|
|
|
|
|
Average
Price ($/bbl) |
|
Collar
ceiling price |
|
$ |
67.76 |
|
$66.53 |
$68.77 |
$ |
67.98 |
|
$ |
78.63 |
|
$ |
- |
|
Collar
floor price |
|
|
49.99 |
|
48.38 |
50.80 |
|
50.80 |
|
|
52.62 |
|
|
- |
|
Three
way ceiling price |
|
|
45.24 |
|
44.03 |
45.85 |
|
45.85 |
|
|
64.11 |
|
|
71.67 |
|
Three
way floor price |
|
|
35.57 |
|
35.57 |
35.57 |
|
35.57 |
|
|
48.38 |
|
|
50.80 |
|
Three
way floor short |
|
$ |
30.85 |
|
$30.85 |
$30.85 |
$ |
30.85 |
|
$ |
42.34 |
|
$ |
44.76 |
|
|
2005 |
|
2006 |
Alberta
Power |
2005 |
Q2 |
Q3 |
Q4 |
|
Q1 |
Q2 |
Fixed
MW/h |
2.0 |
2.0 |
2.0 |
2.0 |
|
- |
- |
Fixed
price ($/MWh) |
$44.50 |
$44.50 |
$44.50 |
$44.50 |
|
- |
- |
Three-way
Collars
A
three-way collar is transacted by selling a call to create a ceiling, buying a
put to create a floor, then selling a put below the floor to create a floor
short. For example, a three-way collar of $35 - $40 - $50 would result in the
following prices received. For market prices above the ceiling ($50), Petrofund
receives $50. For market prices between the ceiling and the floor ($40-$50),
Petrofund receives the market price. For market prices between the floor and the
floor short ($35-$40), Petrofund receives $40. For market prices below the floor
short ($35), Petrofund receives the market price plus $5.
As at May
10th, 2005 Petrofund had entered into the following additional hedge (not
included in the table above):
1) |
Collar
for April 1, 2006-June 30, 2006 for 1,000 bbl/d of crude (WTI) between
$57.45 and $84.67/bbl levels. |
Petrofund
has no volumes hedged after June 30, 2006. All foreign exchange calculations in
this section of the report incorporate the Bank of Canada US dollar rate at the
close on March 31, 2005 of CDN $1.2096:US$. For a complete listing of all hedge
transaction details please see Note 8 to the Interim Consolidated Financial
Statements.
LOSS
ON COMMODITY CONTRACTS (in
$ thousands) |
|
For
the three months ended March 31, |
|
2005 |
|
2004 |
|
Realized
losses |
|
$ |
(8,166 |
) |
$ |
(4,900 |
) |
Change
in fair value |
|
|
|
|
|
|
|
Fair
value, beginning of period |
|
|
(11,318 |
) |
|
(6,771 |
) |
Less
fair value, end of period |
|
|
(35,090 |
) |
|
(16,901 |
) |
Change
in fair value of financial instruments |
|
|
(23,772 |
) |
|
(10,130 |
) |
Amortization
of deferred commodity contracts |
|
|
(59 |
) |
|
(2,461 |
) |
Total
non-cash adjustments |
|
|
(23,831 |
) |
|
(12,591 |
) |
Total |
|
$ |
(31,997 |
) |
$ |
(17,491 |
) |
ROYALTIES |
|
|
For
the three months ended March 31, |
2005 |
2004 |
Royalties
($ millions) |
$31.8 |
$18.6 |
Average
royalty rate (%) |
20 |
19 |
$/boe |
$10.04 |
$7.67 |
Royalties,
which include crown, freehold and overrides paid on oil and natural gas
production, increased to $31.8 million in the first quarter of 2005 from $18.6
million in the first quarter of 2004, net of the Alberta Royalty Credit (“ARC”).
Royalties, as a percentage of revenues before hedging losses, increased to 20%
of revenues in the first quarter of 2005 from 19% of revenues in the first
quarter of 2004.
EXPENSES |
|
|
|
|
|
For
the three months ended March 31, |
|
2005 |
|
2004 |
|
Expenses
($
millions) |
|
|
|
|
|
Lease
operating |
|
$ |
32.0 |
|
$ |
19.8 |
|
Transportation |
|
|
2.0 |
|
|
1.4 |
|
General
& administrative |
|
|
3.6 |
|
|
3.1 |
|
Financing
costs |
|
|
2.1 |
|
|
0.9 |
|
Expenses
per boe |
|
|
|
|
|
|
|
Lease
operating |
|
$ |
10.09 |
|
$ |
8.19 |
|
Transportation |
|
|
0.64 |
|
|
0.56 |
|
General
& administrative |
|
|
1.15 |
|
|
1.30 |
|
Financing
costs |
|
|
0.67 |
|
|
0.37 |
|
Lease
Operating
Oil and
gas lease operating expenses increased to $32.0 million in the first quarter of
2005 from $19.8 million in the first quarter of 2004 due to the additional wells
on production and the increase in costs on a boe basis. Operating costs on a boe
basis increased to $10.09 in the first quarter of 2005 from $8.19 in the first
quarter of 2004.
The most
significant contributor to the higher operating costs in the first quarter of
2005 versus 2004 was general industry increases for all types of services
including surface and downhole well repair costs and facility maintenance work.
In addition, costs in the first quarter of 2005 include prior year adjustments
from operators of $2.5 million or $0.79 per boe.
Transportation
Costs
Transportation
costs on a boe basis were $0.64 in the first quarter of 2005 as compared to
$0.56 in the first quarter of 2004, which reflects the higher transportation
costs associated with the Ultima properties.
General
& Administrative ("G&A")
G&A
costs on a boe basis were $1.15 per boe in the first quarter 2005 as compared to
$1.30 per boe in the same period 2004. General and administrative costs, net of
overhead recoveries, increased to $3.6 million in 2005 from $3.1 million in
2004. G&A costs in the first quarter of 2005 included $74,000 relating to
the external costs associated with compliance with Section 404 of the
Sarbanes-Oxley Act (“SOX 404”) and $74,000 for the reclassification of units,
which equates to $ 0.05 per boe.
Financing
Costs
Interest
and other financing costs increased to $2.1 million in the first quarter of 2005
from $906,000 in the first quarter of 2004 due to the increase in the average
loan balance outstanding, offset by a decrease in the average prime loan rate
from 4.305% in first quarter of 2004 to 4.25% in the first quarter of 2005. The
average loan outstanding in the first quarter of 2005 was $233.2 million versus
$89.8 million in the first quarter of 2004.
The bank
loan outstanding at March 31, 2005, was $239.2 million as compared to $214.4
million at December 31, 2004.
DEPLETION,
DEPRECIATION & ACCRETION
Depletion,
depreciation and accretion expense increased to $43.7 million in the first
quarter of 2005 from $29.5 million in first quarter of 2004 due to the increase
in production and an increase in the depletion rate. The rate per boe increased
to $13.78 in the first quarter of 2005 from $12.20 in the first quarter of 2004.
The increase in the rate over 2004 reflects the increasing cost of acquisitions.
Unproved properties are included in the depletion and depreciation expense
calculation.
INCOME
TAXES
Current
taxes consist of the Federal Large Corporations Tax and some minor amounts
relating to income taxes of corporate entities acquired. The Federal Large
Corporations Tax is based primarily on the debt and equity balances of the
Trust’s 100% owned subsidiary, Petrofund Corp. as at March 31, 2005. The Federal
Large Corporations Tax rate is being reduced in stages over a period of five
years commencing in 2004, so that by 2008, the tax will be
eliminated.
Capital
taxes of $787,000 in the first quarter of 2005 (2004 - $737,000) are primarily
the Saskatchewan Capital Tax and Resource Surcharge, which is based upon gross
revenues earned in Saskatchewan.
Future
income tax liabilities arise due to the differences between the tax basis of
Petrofund Corp’s assets and their respective accounting carrying cost. The
future income tax recovery in the first quarter of 2005 was $12.7 million
compared to $443,000 expense in the first quarter of 2004 as a result of an
increase in non-cash commodity contract losses.
NET
INCOME
For
the three months ended March 31, |
|
2005 |
|
2004 |
|
Net
income ($000’s) |
|
$ |
19,243 |
|
$ |
7,629 |
|
Net
income per Trust unit |
|
|
|
|
|
|
|
Basic |
|
$ |
0.19 |
|
$ |
0.10 |
|
Diluted |
|
$ |
0.19 |
|
$ |
0.10 |
|
Net
income before taxes decreased from $8.1 million in the first quarter of 2004 to
$6.6 million in the first quarter of 2005 mainly due to a 61% increase in lease
operating costs, a 48% increase in depletion offset by a 55% increase in
revenues. Production was up 31% and prices increased 19% on a boe basis.
The Trust
recognized a net loss on commodity contracts of $32.0 million in the first
quarter of 2005 compared to $17.5 million in the first quarter of 2004. The
unrealized (non-cash) loss on commodity contracts was $23.8 million in the first
quarter of 2005 compared to $12.6 million in the first quarter of
2004.
The
increase in depletion is due to increased production and the increase in the
depletion rate reflecting the increasing cost of acquisitions.
Total
cash netbacks increased by $23.9 million. On a boe basis cash netbacks were up
to $23.35 in the first quarter of 2005 from $20.72 in the first quarter of 2004.
Total
Cash Netbacks |
|
2005 |
|
2004 |
|
Operating
netback |
|
$ |
25.45 |
|
$ |
22.71 |
|
Financing
costs |
|
|
0.67 |
|
|
0.37 |
|
General
and administrative |
|
|
1.15 |
|
|
1.30 |
|
Capital
and current taxes |
|
|
0.28 |
|
|
0.32 |
|
Total
cash netback per BOE |
|
$ |
23.35 |
|
$ |
20.72 |
|
As a
result of the changes discussed above, net income increased to $11.6 million in
the first quarter of 2005 from the $7.6 million reported in the first quarter of
2004.
Operating
Netbacks 2005 |
|
Oil
$/bbl |
|
Gas
$/mcf |
|
NGL
$ /bbll |
|
Total
$ /boe |
|
Selling
price |
|
$ |
54.74 |
|
$ |
6.97 |
|
$ |
46.04 |
|
$ |
48.79 |
|
Cash
cost of hedging |
|
|
(5.02 |
) |
|
- |
|
|
- |
|
(2.57) |
Net
selling price |
|
|
49.72 |
|
|
6.97 |
|
|
46.04 |
|
|
46.22- |
|
Royalties,
net of ARC |
|
|
10.13 |
|
|
1.62 |
|
|
11.50 |
|
|
10.04- |
|
Operating |
|
|
12.00 |
|
|
1.32 |
|
|
9.03 |
|
|
10.09- |
|
Transportation |
|
|
0.58 |
|
|
0.13 |
|
|
0.50 |
|
|
0.64- |
|
Operating
netback |
|
$ |
27.01 |
|
$ |
3.90 |
|
$ |
25.01 |
|
$ |
25.45 - |
|
Operating
Netbacks 2004 |
|
Oil
$/bbl |
|
Gas
$/mcf |
|
NGL
$ /bbl |
|
Total
$ /boe |
|
Selling
price |
|
$ |
42.50 |
|
$ |
6.76 |
|
$ |
37.06 |
|
$ |
41.15 |
|
Cash
cost of hedging |
|
|
(4.91 |
) |
|
- |
|
|
- |
|
(2.02) |
Net
selling price |
|
|
37.59 |
|
|
6.76 |
|
|
37.06 |
|
|
39.13 |
|
Royalties,
net of ARC |
|
|
6.43 |
|
|
1.37 |
|
|
11.11 |
|
|
7.67 |
|
Operating |
|
|
11.94 |
|
|
0.84 |
|
|
6.79 |
|
|
8.19 |
|
Transportation |
|
|
0.22 |
|
|
0.15 |
|
|
0.41 |
|
|
0.56 |
|
Operating
netback |
|
$ |
19.00 |
|
$ |
4.40 |
|
$ |
18.75 |
|
$ |
22.71 |
|
QUARTERLY
FINANCIAL DATA
|
|
Net
Oil and |
|
Net |
|
Net
income per Unit |
|
($
millions, except per unit amounts) |
|
Natural
Gas Sales
(1) |
|
Income |
|
Basic |
|
Diluted |
|
2005
|
|
|
|
|
|
|
|
|
|
First
quarter |
|
$ |
122.9 |
|
$ |
19.2 |
|
$ |
0.19 |
|
$ |
0.19 |
|
2004 |
|
|
|
|
|
|
|
|
|
|
|
|
|
First
quarter |
|
$ |
81.1 |
|
$ |
7.6 |
|
$ |
0.10 |
|
$ |
0.10 |
|
Second
quarter |
|
|
89.9 |
|
|
0.8 |
|
|
0.01 |
|
|
0.01 |
|
Third
quarter |
|
|
119.9 |
|
|
15.1 |
|
|
0.15 |
|
|
0.15 |
|
Fourth
quarter |
|
|
125.9 |
|
|
50.9 |
|
|
0.51 |
|
|
0.51 |
|
2003 |
|
|
|
|
|
|
|
|
|
|
|
|
|
Second
quarter |
|
$ |
77.9 |
|
$ |
15.3 |
|
$ |
0.26 |
|
$ |
0.26 |
|
Third
quarter |
|
|
75.4 |
|
|
15.1 |
|
|
0.23 |
|
|
0.23 |
|
Fourth
quarter |
|
|
76.8 |
|
|
24.3 |
|
|
0.35 |
|
|
0.35 |
|
(1) Net after
royalties
CAPITAL
EXPENDITURES
Acquisitions
During
the three months ended March 31, 2005, PC spent $6.3 million to acquire minor
property interests in the Turin area, as compared to $1.1 million in the first
quarter of 2004.
Development
Activities
During
the three months ended March 31, 2005, PC incurred $48.4 million drilling and
development activities as compared to $12.6 million in the three months ended
March 31, 2004. A total of 73 wells were drilled, of which 50 were gas, 20 oil,
1 service well and 2 dry and abandoned for an overall success rate of 97%.
A summary
of capital expenditures for the period is as follows (in $
thousands):
For
the three months ended March 31, |
|
2005 |
|
2004 |
|
Property
acquisitions (1)
|
|
$ |
6,251 |
|
$ |
1,090 |
|
Development
expenditures: |
|
|
|
|
|
|
|
Land
& seismic |
|
|
3,969 |
|
|
607 |
|
Drilling
& completion |
|
|
22,398 |
|
|
5,686 |
|
Well
equipping |
|
|
5,051 |
|
|
1,198 |
|
Tie-ins |
|
|
4,351 |
|
|
1,081 |
|
Facilities |
|
|
8,716 |
|
|
2,546 |
|
CO2
purchases |
|
|
3,818 |
|
|
1,458 |
|
Other |
|
|
87 |
|
|
40 |
|
Total |
|
|
48,390 |
|
|
12,616 |
|
Total
net capital expenditures |
|
$ |
54,641 |
|
$ |
13,706 |
|
(1) |
The
property acquisition totals exclude non-cash future income tax adjustments
for the difference between the cost and tax basis is of assets acquired by
way of corporate acquisitions. |
ASSET
RETIREMENT FUND
As at
March 31, 2005, PC had $7.5 million set aside in cash to fund future abandonment
costs. This cash fund is in place to fund significant future reclamation costs,
such as the decommissioning of a major facility. PC performs well reclamation
and abandonments, flare pit remediation work, etc. on a routine basis, which
reduces cash flow available for distribution to proactively address
environmental concerns. Petrofund incurred $1.1 million for these activities in
the first quarter of 2005 compared to $1.2 million in the first quarter of 2004.
PC expects to spend a further $5 million to $6 million on reclamation and
abandonment work in 2005.
GOODWILL
The
goodwill balance of $180.3 million arose as a result of the Ultima and Central
Alberta acquisitions in 2004. The goodwill balance was determined based on the
excess of total consideration paid plus the future income tax liability less the
fair value of the assets acquired in each transaction.
Accounting
standards require that the goodwill balance be assessed for impairment at least
annually or more frequently if events or changes in circumstances indicate that
the balance might be impaired. If such an impairment exists, it would be charged
to income in the period in which the impairment occurs. The Trust has determined
that there was no goodwill impairment as of March 31, 2005.
DEBT
As at
March 31, 2005, the amount outstanding on the credit facility was $239.2
million, with $85.8 million available to finance future activities prior to the
increase in the borrowing base.
On April
29, 2005, PC’s borrowing base was increased to $415 million and the revolving
period on the syndicated facility of $390 million was extended for a further 364
day period ending on April 28, 2006. In the event that the revolving bank line
is not extended at the end of the 364 day revolving period, no payments are
required to be made to non-extending lenders during the first year of the term
period. However, Petrofund will be required to maintain certain minimum balances
on deposit with the syndicate agent.
LIQUIDITY
AND CAPITAL RESOURCES
The
working capital deficit was $59.5 million at March 31, 2005, an increase of
$10.2 million from the $49.3 million deficit as at December 31, 2004. The March
31, 2005 and December 31, 2004 deficits excludes net unrealized losses on
commodity contracts. Current assets increased $7.4 million from $48.6 million at
December 31, 2004 to $56.0 million at March 31, 2005. Current liabilities
increased $17.6 million from $97.9 million at December 31, 2004 to $115.5
million at March 31, 2005. This increase in liabilities reflects an increase in
the capital expenditures in the quarter and an increase in distributions payable
to Unitholders.
During
first quarter of 2005 the Trust generated cash flow of $73.0 million and paid
out $47.9 million in distributions. The excess of $25.0 million was used to
partially fund the Trust’s capital expenditure program.
Total
long-term debt increased to $239.2 million at March 31, 2005, from $214.4
million at December 31, 2004, due to the cost of development activities.
The
banking syndicate reviewed the borrowing base in conjunction with its review of
the independent engineering report as at December 31, 2004 and increased the
limit on the facility to $415 million from $325 million effective April 29,
2005.
The
changes in total long- term debt were due to:
For
the three months ended March 31, ($
thousands) |
|
2005 |
|
2004 |
|
Cash
flow |
|
$ |
72,959 |
|
$ |
49,047 |
|
Proceeds
received from issuance of Trust units |
|
|
4,190 |
|
|
907 |
|
Net
change in non-cash working capital balances |
|
|
(7,132 |
) |
|
25,846 |
|
Distributions
paid |
|
|
(47,894 |
) |
(34,910) |
Expenditures
on oil & natural properties, net |
|
|
(54,641 |
) |
(13,706) |
Asset
retirement reserve |
|
|
(476 |
) |
(363) |
Redemption
of exchangeable shares |
|
|
(387 |
) |
(451) |
Capital
lease repayments |
|
|
(406 |
) |
(86) |
(Increase)
decrease in cash |
|
|
8,964 |
|
(6,415) |
|
|
$ |
(24,823 |
) |
$ |
19,869 |
|
In the
absence of an equity issue, long-term debt will increase in 2005 due to the
capital expenditure program which is expected to be in the $120 million range
(excluding acquisitions) of which a significant portion is expected to be funded
from cash flow. If the Trust is successful in completing one or more significant
acquisitions in 2005 these would be financed by further utilization of the
credit facility or a combination of additional bank borrowing and a possible
equity issue of treasury units.
Capitalization
Analysis
($
thousands, except per unit and percent amounts) |
|
2005 |
|
2004 |
|
Working
capital (deficiency) (1) |
|
$ |
(59,531 |
) |
$
(56,093) |
Bank
debt |
|
|
239,237 |
|
|
89,838 |
|
Capital
lease obligation |
|
|
- |
|
|
202 |
|
Net
debt obligation |
|
$ |
298,768 |
|
$ |
146,133 |
|
Units
outstanding and issuable for Exchangeable Shares |
|
|
100,746 |
|
|
73,682 |
|
Market
Price at March 31, |
|
|
17.64 |
|
|
17.35 |
|
Market
capitalization |
|
$ |
1,777,156 |
|
$ |
1,278,390 |
|
Total
capitalization |
|
$ |
2,075,924 |
|
$ |
1,424,523 |
|
Net
debt as a percentage of total capitalization |
|
|
14 |
% |
|
10 |
% |
(1)
Excludes
net unrealized losses on commodity contracts.
Based on
annualized first quarter 2005 cash flow, Petrofund’s net debt to cash flow ratio
is 1.0:1.0.
Total
capitalization as presented does not have any standardized meaning prescribed by
Canadian GAAP and therefore it may not be comparable with the calculation of
similar measures for other entities. Total capitalization is not intended to
represent the total funds from equity and debt received by the
Trust.
UNITHOLDERS’
EQUITY
The
weighted average Trust units/exchangeable shares outstanding are as
follows:
For
the three months ended March 31, |
2005 |
2004 |
Basic |
100,602,757 |
73,673,782 |
Diluted |
100,644,186 |
73,872,208 |
Trust
units/exchangeable shares outstanding:
As
at March 31, |
2005 |
2004 |
Trust
units outstanding |
100,206,640 |
72,743,253 |
Trust
units issuable for exchangeable shares (Note
3) |
539,147 |
939,147 |
|
100,745,787
|
73,682,400
|
The Trust
had 100,206,640 Trust units outstanding at March 31, 2005 compared to 72,743,253
Trust units at the end of March 31, 2004. The weighted average number of Trust
units outstanding including Exchangeable Shares, was 100,745,787 Trust units for
the first quarter of 2005 as compared to 73,682,400 for 2004. During the first
quarter of 2005, 316,251 Exchangeable Shares were converted into 400,000 Trust
units and 17,747 were redeemed for cash leaving 422,650 Exchangeable Shares
outstanding at March 31, 2005 which are convertable into 539,147 Trust
units.
FINANCIAL
INSTRUMENTS
The net
negative fair value of the commodity contracts at March 31, 2005 of $35.1
million has been recorded on the balance sheet as "commodity contracts" under
assets or liabilities, as appropriate. The negative change in the fair value of
the contracts, from January 1, 2005 to March 31, 2005 of $23.8 million is
recorded in the income statement on a separate line as “loss on commodity
contracts". The line item also includes realized losses on commodity contracts
of $8.2 million for three months ended March 31, 2005 compared to $4.9 million
for three months ended March 31, 2004.
Deferred
Commodity Contracts ($000’s) |
|
Jan
1,
2005 |
|
Amortized
to
Expense |
|
Mar
31,
2005 |
|
Current
Asset |
|
|
|
|
|
|
|
|
|
|
Deferred
loss |
|
$ |
517 |
|
$ |
(129 |
) |
$ |
388 |
|
Current
Liability |
|
|
|
|
|
|
|
|
|
|
Deferred
gain |
|
|
(184 |
) |
|
70 |
|
|
(114 |
) |
|
|
$ |
333 |
|
$ |
(59 |
) |
$ |
274 |
|
Commodity
Contracts ($000’s) |
|
|
Jan
1,
2005 |
|
|
Change
in
Fair
Value |
|
|
Mar
31,
2005 |
|
Current
Asset |
|
|
|
|
|
|
|
|
|
|
Commodity
contracts |
|
$ |
3,281 |
|
$ |
(3,093 |
) |
$ |
188 |
|
Current
Liability |
|
|
|
|
|
|
|
|
|
|
Commodity
contracts |
|
|
(14,599 |
) |
|
(20,679 |
) |
|
(35,278 |
) |
|
|
$ |
(11,318 |
) |
$ |
(23,772 |
) |
$ |
(35,090 |
) |
NON-RESIDENT
OWNERSHIP
Based on
information available to the Trust, Petrofund estimated that non-resident
ownership was approximately 71% as of April 30, 2005. While there are, at
present, no restrictions or deadlines on Petrofund pertaining to non-resident
ownership levels, the Trust will continue to provide non-resident ownership
level updates on a quarterly basis. Petrofund continues to monitor developments
in this area.
OFF-BALANCE
SHEET ARRANGEMENTS
The Trust
has no off-balance sheet financing arrangements.
OUTLOOK
FOR 2005
The level
of cash flow for 2005 will be affected by oil and gas prices, the Canadian - US
dollar exchange rate and the Trust’s ability to add reserves and production in a
cost effective manner. Both product prices and the exchange rate showed
significant volatility in 2004 and this trend is expected to continue in 2005.
The acquisition market is expected to continue to be active. Nevertheless,
competition for these assets is expected to be fierce due to increased demand
resulting from the increasing number of oil and gas companies that have
converted to a trust structure. The Trust expects prices for quality, long life
assets to be at or near record levels. Petrofund expects to be an active
participant in this market but success will be tempered by a commitment to
maintain historic discipline and bid only at levels consistent with the best
long term interest of our unitholders.
Acquisition
activities will be complemented by an extensive drilling and farmout program
that will be conducted on our existing land base.
Although
product prices have remained at high levels, the strengthening of the Canadian
dollar in the first quarter of 2005 moderated the net effect of these prices on
Petrofund’s cash flow. The WTI U.S. price increased 42% to $49.84/bbl in 2005
from $35.14/bbl in the first quarter of 2004; however, as the (US/CDN) exchange
rate averaged $0.82 in 2005 as compared to $0.76 in the first quarter of 2004
the par price at Edmonton was up only 35%. The Trust expects the Canadian dollar
to remain strong throughout 2005.
Petrofund
pursues a well defined risk management program to help offset the effect of
price fluctuations. This program utilizes collars as the main hedging tool but
Petrofund also enters into fixed price transactions when commodity prices
approach historic highs. To date, the Trust has not entered into any currency
related transactions. A discussion of the risk management strategies and hedged
positions appear elsewhere in this report.
SENSITIVITY
ANALYSIS
Below is
a table that shows sensitivities to pre-hedging cash flow as a result of product
price and operational changes that can significantly affect cash flow and
results of operations. The table is based on actual 2005 prices received for the
first quarter of 2005 and production volumes of 35,000 boe/d. These
sensitivities are approximations only and are not necessarily valid at other
price and production levels. As well, hedging activities can significantly
affect these sensitivities.
|
|
Change |
|
$000’s
|
|
$/unit
per
year |
|
Price
per barrel of oil* |
|
$ |
1.00
US |
|
$ |
7,607 |
|
$ |
0.075 |
|
Price
per mcf of natural gas* |
|
$ |
0.25
CDN |
|
$ |
6,143 |
|
$ |
0.061 |
|
US/Cdn
exchange rate |
|
$ |
0.01 |
|
$ |
4,681 |
|
$ |
0.046 |
|
Interest
rate on debt ($239 million) |
|
|
1 |
% |
$ |
2,390 |
|
$ |
0.024 |
|
Oil
production volumes* |
|
|
100
bbl/day |
|
$ |
1,638 |
|
$ |
0.016 |
|
Gas
production volumes* |
|
|
1
mmcf/day |
|
$ |
1,946 |
|
$ |
0.019 |
|
* After
adjustment for estimated royalties.
Consolidated
Balance Sheet
(thousands
of dollars) (unaudited)
As
at March 31, 2005 and December 31, 2004 |
|
2005 |
|
2004 |
|
Assets |
|
|
|
|
|
Current
assets |
|
|
|
|
|
|
|
Accounts
receivable |
|
$ |
40,027 |
|
$ |
37,713 |
|
Deferred
loss on commodity contracts |
|
|
388 |
|
|
517 |
|
Commodity
contracts (Note
8) |
|
|
188 |
|
|
3,281 |
|
Prepaid
expenses |
|
|
15,985 |
|
|
10,847 |
|
Total
current assets |
|
|
56,588 |
|
|
52,358 |
|
Asset
retirement reserve fund (Note
6(b)) |
|
|
7,529 |
|
|
7,053 |
|
Goodwill |
|
|
180,307 |
|
|
180,307 |
|
Oil
and natural gas royalty and property interests, |
|
|
|
|
|
|
|
at
cost less accumulated depletion and depreciation |
|
|
|
|
|
|
|
of
$675,757 (2004 - $632,668) |
|
|
1,259,248 |
|
|
1,246,694 |
|
|
|
$ |
1,503,672 |
|
$ |
1,486,412 |
|
Liabilities
and Unitholders' Equity |
|
|
|
|
|
|
|
Current
liabilities |
|
|
|
|
|
|
|
Bank
overdraft |
|
$ |
9,697 |
|
$ |
733 |
|
Accounts
payable and accrued liabilities |
|
|
61,280 |
|
|
60,961 |
|
Current
portion of capital lease obligations |
|
|
202 |
|
|
608 |
|
Deferred
gain on commodity contracts |
|
|
114 |
|
|
184 |
|
Commodity
contracts (Note
8) |
|
|
35,278 |
|
|
14,599 |
|
Distributions
payable to Unitholders (Note
7) |
|
|
44,364 |
|
|
35,568 |
|
Total
current liabilities |
|
|
150,935 |
|
|
112,653 |
|
Long-term
debt (Note
5) |
|
|
239,237 |
|
|
214,414 |
|
Future
income taxes |
|
|
68,705 |
|
|
81,411 |
|
Asset
retirement obligations
(Note
6(a)) |
|
|
51,913 |
|
|
51,408 |
|
Total
liabilities |
|
|
510,790 |
|
|
459,886 |
|
Unitholders'
equity |
|
|
|
|
|
|
|
Unitholders'
capital (Note
2) |
|
|
1,486,633 |
|
|
1,477,963 |
|
Exchangeable
shares (Note
3) |
|
|
6,038 |
|
|
10,518 |
|
Accumulated
earnings |
|
|
291,855 |
|
|
272,612 |
|
Accumulated
cash distributions (Note
7)
|
|
|
(791,644 |
) |
(734,567) |
Total
unitholders' equity |
|
|
992,882 |
|
|
1,026,526 |
|
|
|
$ |
1,503,672 |
|
$ |
1,486,412 |
|
The
accompanying notes to the Interim Consolidated Financial Statements are an
integral part of this consolidated balance sheet.
Consolidated
Statement of Operations and Accumulated Earnings
(thousands
of dollars, except per unit amounts) (unaudited)
For
the three months ended March 31, |
|
2005 |
|
2004 |
|
Revenues
|
|
|
|
|
|
|
|
Oil
and natural gas sales |
|
$ |
154,768 |
|
$ |
99,699 |
|
Royalties |
|
|
(31,844 |
) |
(18,578) |
Loss
on commodity contracts |
|
|
(31,997 |
) |
(17,491) |
|
|
|
90,927 |
|
|
63,630 |
|
Expenses
|
|
|
|
|
|
|
|
Lease
operating |
|
|
32,010 |
|
|
19,829 |
|
Transportation
costs |
|
|
2,036 |
|
|
1,355 |
|
Financing
costs |
|
|
2,131 |
|
|
906 |
|
General
and administrative |
|
|
3,639 |
|
|
3,138 |
|
Capital
taxes |
|
|
787 |
|
|
737 |
|
Depletion,
depreciation and accretion |
|
|
43,702 |
|
|
29,546 |
|
|
|
|
84,305 |
|
|
55,511 |
|
Income
before provision for income taxes |
|
|
6,622 |
|
|
8,119 |
|
Provision
for (recovery of) income taxes |
|
|
|
|
|
|
|
Current
|
|
|
85 |
|
|
47 |
|
Future |
|
|
(12,706 |
) |
|
443 |
|
|
|
|
(12,621 |
) |
|
490 |
|
Net
income |
|
|
19,243 |
|
|
7,629 |
|
Accumulated
earnings,
beginning of period |
|
|
272,612 |
|
|
198,253 |
|
Accumulated
earnings,
end of period |
|
$ |
291,855 |
|
$ |
205,882 |
|
Net
income per Trust unit (Note
2) |
|
|
|
|
|
|
|
Basic |
|
$ |
0.19 |
|
$ |
0.10 |
|
Diluted |
|
$ |
0.19 |
|
$ |
0.10 |
|
The
accompanying notes to the Interim Consolidated Financial Statements are an
integral part of these consolidated statements.
Consolidated
Statement of Cash Flows
(thousands
of dollars) (unaudited)
For
the three months ended March 31, |
2005 |
2004 |
|
|
|
Cash
provided by (used in): |
|
|
Operating
activities |
|
|
Net
income |
$19,243
|
$7,629
|
Add
items not affecting cash: |
|
|
Depletion,
depreciation and accretion |
43,702 |
29,546 |
Commodity
contracts |
23,831 |
12,591 |
Future
income taxes |
(12,706)
|
443 |
Actual
abandonment costs incurred (Note
6) |
(1,111) |
(1,162)
|
|
72,959 |
49,047 |
Net
change in non-cash operating working capital
balances |
(7,132)
|
25,846 |
Cash
provided by operating activities |
65,827 |
74,893 |
Financing
activities |
|
|
Bank
loan |
24,823 |
(19,869) |
Distributions
paid (Note
7) |
(47,894) |
(34,910) |
Redemption
of exchangeable shares (Note
3) |
(387) |
(451) |
Capital
lease repayments |
(406) |
(86) |
Issuance
of Trust units (Note
2) |
4,190 |
907 |
Cash
used in financing activities |
(19,674) |
(54,409) |
Investing
activities |
|
|
Asset
retirement reserve (Note
6(b)) |
(476) |
(363) |
Property
acquisitions |
(6,251) |
(1,090) |
|
Development
expenditures |
(48,390) |
(12,616) |
|
Cash
used in investing activities |
(55,117) |
(14,069) |
Net
change in cash (bank overdraft) |
(8,964) |
6,415 |
Cash
(bank overdraft), beginning of period |
(733) |
2,182 |
Cash
(bank overdraft), end of period |
$ (9,697)
|
$8,597 |
Interest
paid during the period |
$ 2,148 |
$944 |
Income
taxes paid during the period |
$ 244 |
$55 |
The
accompanying notes to the Interim Consolidated Financial Statements are an
integral part of these consolidated statements.
Notes to
Interim Consolidated Financial Statements
March
31, 2005 and 2004
(unaudited)
(tabular
amounts in thousands of dollars, except per unit amounts)
1. |
INTERIM
FINANCIAL STATEMENTS |
These
unaudited interim consolidated financial statements follow the same accounting
policies and methods of their application as the most recent annual financial
statements. The note disclosure requirements for annual financial statements
provide additional disclosures to that required for interim financial
statements. Accordingly, these interim financial statements should be read in
conjunction with the audited consolidated financial statements of Petrofund
Energy Trust (“Petrofund” or the “Trust”) as at December 31, 2004 and 2003 and
for each of the years in the three-year period ended December 31,
2004.
Authorized:
unlimited number of Trust units |
|
Number
of
Units |
|
$000’s |
|
Issued |
|
|
|
|
|
December
31, 2004 |
|
|
99,511,576 |
|
$ |
1,477,963 |
|
Exchangeable
shares converted (Note
3) |
|
|
400,000 |
|
|
4,480 |
|
Options
exercised |
|
|
270,324 |
|
|
3,799 |
|
Unit
purchase plan |
|
|
1,681 |
|
|
31 |
|
Unit
incentive plan |
|
|
23,059 |
|
|
360 |
|
March
31, 2005 |
|
|
100,206,640 |
|
$ |
1,486,633 |
|
The
weighted average Trust units/exchangeable shares outstanding are as
follows:
For
the three months ended March 31, |
|
2005 |
|
2004 |
|
Basic |
|
|
100,602,757 |
|
|
73,673,783 |
|
Diluted |
|
|
100,644,186 |
|
|
73,872,208 |
|
The
diluted amounts include all dilutive instruments.
Trust
units/exchangeable shares outstanding:
As
at March 31, |
|
2005 |
|
2004 |
|
Trust
units outstanding |
|
|
100,206,640 |
|
|
72,743,253 |
|
Trust
units issuable for exchangeable shares (Note
3) |
|
|
539,147 |
|
|
939,147 |
|
|
|
|
100,745,787 |
|
|
73,682,400 |
|
Issued
and Outstanding |
|
Number
of Shares |
|
$000’s |
|
Balance,
December 31, 2004 |
|
|
756,648 |
|
$ |
10,518 |
|
Redemption
of shares |
|
|
(17,747 |
) |
|
- |
|
Exchanged
for Trust Units (1) |
|
|
(316,251 |
) |
|
(4,480 |
) |
Balance,
March 31, 2005 |
|
|
422,650 |
|
|
6,038 |
|
Exchangeable
ratio, end of period |
|
|
1.27563 |
|
|
- |
|
Exchangeable
for Trust units |
|
|
539,147 |
|
$ |
6,038 |
|
(1)
On March
7, 2005, 316,251 Exchangeable Shares were converted to 400,000 Trust units at an
exchange rate of
1.26482.
4. |
RESTRICTED
UNIT PLAN ("RUP") AND LONG-TERM INCENTIVE PLAN
("LTIP") |
On
February 17, 2004, the Board of Directors approved the adoption of the RUP and
LTIP which authorizes the Trust to issue units to directors, officers,
employees, or consultants of the Trust or any of its subsidiaries. The units,
plus accrued distributions, vest over time and upon vesting may be redeemed by
the holder for cash or units under the RUP and for units only under the LTIP.
The units are issued, or the cash paid out, on the vesting dates based upon the
weighted average trading prices of the units for the last 20 trading days prior
to the vesting dates. The estimated value of the units to be issued, or the cash
to be paid out, is charged to expense over the vesting periods of the grants.
The number of units outstanding, excluding accrued distributions, is as follows:
|
|
RUP |
|
LTIP |
|
Balance,
December 31, 2004 |
|
|
51,426 |
|
|
31,156 |
|
Units
issued |
|
|
(18,760 |
) |
(31,156) |
Granted |
|
|
93,510 |
|
|
61,245 |
|
Forfeitures |
|
|
(752 |
) |
|
- |
|
Balance,
March 31, 2005 |
|
|
125,424 |
|
|
61,245 |
|
The Trust
recorded compensation expenses of $450,000 in the first quarter of 2005 (2004 -
$267,000). The compensation expense was based on the March 31, 2005 unit price
of $17.64, distributions of $0.48 per unit during the quarter and management’s
estimate of the number of RUP and LTIP units to be issued on
maturity.
Under the
loan agreements, as at March 31, 2005, Petrofund Corp. (“PC”), a wholly-owned
subsidiary of the Trust had a revolving working capital operating facility of
$25 million and a syndicated facility of $300 million. On April 29, 2005, PC
increased its syndicated facility to $390 million, bringing PC’s borrowing base
to $415 million. Interest on the working capital loan is at prime and interest
on the syndicated facility varies with PC’s debt to cash ratio from prime plus
80 basis points or, at the Trust’s option, banker’s acceptances rates plus
stamping fees. The prime rate at March 31, 2005 was 4.25%. As at March 31, 2005,
there was no amount outstanding under the working capital facility and $239.2
million outstanding under the syndicated facility.
The
revolving period on the syndicated facility ends on April 28, 2006, unless
extended for a further 364 day period. In the event that the revolving bank line
is not extended at the end of the 364 day revolving period, no payments are
required to be made to non-extending lenders during the first year of the term
period. However, PC will be required to maintain certain minimum balances on
deposit with the syndicate agent.
The limit
of the syndicated facility is subject to adjustment from time to time to reflect
changes in PC’s asset base.
The
credit facility is secured by a debenture of $600 million pursuant to which a
Canadian chartered bank, as principal and as agent for the other lenders,
received a first ranking security interest on all of PC’s assets.
The loan
is the legal obligation of PC. While principal and interest payments are
allowable deductions in the calculation of royalty income, the Unitholders have
no direct liability to the bank or to PC should the assets securing the loan
generate insufficient cash flow to repay the obligation.
Substantially
all of the credit facility is financed with Banker’s Acceptances, resulting in a
reduction in the stated bank loan interest rates.
6. |
ASSET
RETIREMENT OBLIGATIONS
AND RESERVE FUND |
(a) Asset
Retirement Obligations (“ARO”)
The total
future asset retirement obligation was estimated by management based on the
Trust's net ownership interest in wells and facilities and the estimated timing
of the costs to be incurred in future periods. The following reconciles the
Trust's outstanding ARO for the periods indicated:
For
the three months ended March 31, ($000’s) |
|
2005 |
|
2004 |
|
Balance,
at beginning of period |
|
$ |
51,408 |
|
$ |
34,363 |
|
Increase
in liabilities during the period |
|
|
1,003 |
|
|
215 |
|
Accretion
expense during period |
|
|
613 |
|
|
554 |
|
Actual
costs incurred during the period |
|
|
(1,111 |
) |
(1,162) |
Balance,
at end of period |
|
$ |
51,913 |
|
$ |
33,970 |
|
(b)
Asset
Retirement Reserve Fund
PC
maintains a cash reserve to finance large and unusual oil and natural gas
property reclamation and abandonment costs by withholding distributions accruing
to Unitholders. At March 31, 2005, the cash reserve was $7.5 million (2004 -
$4.1 million). In first quarter of 2005 PC increased the cash reserve by
withholding $476,000 from distributions accruing to Unitholders. In addition,
routine ongoing reclamation and abandonment costs of $1.1 million in the first
quarter of 2005 (2004 - $1.2 million) were incurred and deducted from
distributions accruing to Unitholders.
7. |
DISTRIBUTIONS
ACCRUING TO UNITHOLDERS |
Under the
terms of the Trust Indenture, the Trust makes monthly distributions within a
specified period following the end of each month (“Cash Distribution Date”).
Distributions are equal to amounts received by the Trust on the Cash
Distribution Date less permitted expenses. Distributions to Unitholders coincide
with cash receipts of royalty and income and debt repayments from PC. An overall
analysis is as follows:
For
the period ended |
|
Cash
Distribution Date |
|
2005 |
|
2004 |
|
November
30 |
|
|
January
31 |
|
$ |
0.16 |
|
$ |
0.16 |
|
December
31 |
|
|
February
28 |
|
|
0.16 |
|
|
0.16 |
|
January
31 |
|
|
March
31 |
|
|
0.16 |
|
|
0.16 |
|
Cash
Distributions per Trust unit |
|
|
|
|
$ |
0.48 |
|
$ |
0.48 |
|
Reconciliation
of Distributions Accruing to Unitholders
(thousands
of dollars)
For
the three months ended March 31, |
|
2005 |
|
2004 |
|
Distributions
payable, beginning of period |
|
$ |
35,568 |
|
$ |
53,452 |
|
Distributions
accruing during the period |
|
|
|
|
|
|
|
Cash
flow provided by operating activities |
|
|
65,827 |
|
|
74,893 |
|
Net
change in non-cash operating working |
|
|
|
|
|
|
|
capital
balance |
|
|
7,132 |
|
|
(25,846 |
) |
Amortization
of the cost of commodity contracts |
|
|
- |
|
|
(221 |
) |
Redemption
of exchangeable shares |
|
|
(387 |
) |
|
(451 |
) |
Asset
retirement reserve |
|
|
(476 |
) |
|
(363 |
) |
Capital
lease repayment |
|
|
(406 |
) |
|
(86 |
) |
Cash
flow before capital reinvestment |
|
|
71,690 |
|
|
47,926 |
|
Reserve
for capital expenditures |
|
|
(15,000 |
) |
|
(7,500 |
) |
Total
distributions accruing during the period |
|
|
56,690 |
|
|
40,426 |
|
Distributions
paid |
|
|
(47,894 |
) |
|
(34,910 |
) |
Distributions
payable, end of period
(1) |
|
$ |
44,364 |
|
$ |
58,968 |
|
(1) |
It
is expected that a portion of this amount will be used to fund capital
expenditures in the future. |
Accumulated
Cash Distributions
(thousands
of dollars) |
|
|
|
|
|
For
the three months ended March 31, |
|
2005 |
|
2004 |
|
Accumulated
cash distributions, beginning of year |
|
$ |
734,567 |
|
$ |
581,155 |
|
Distributions
accruing during the period |
|
|
56,690 |
|
|
40,426 |
|
Redemption
of exchangeable shares |
|
|
387 |
|
|
451 |
|
Accumulated
cash distributions, end of period |
|
$ |
791,644 |
|
$ |
622,032 |
|
8. |
DERIVATIVE
FINANCIAL INSTRUMENTS AND PHYSICAL
CONTRACTS |
The Trust
enters into various pricing mechanisms to reduce price volatility and establish
minimum prices for a portion of its oil and gas production. These include
fixed-price contracts and the use of derivative financial
instruments.
The
outstanding derivative financial instruments, all of which constitute effective
economic hedges, and the related unrealized gains or losses since inception of
the contracts at March 31, 2005, are summarized separately below:
Natural
Gas |
Term |
Volume
mcf/d |
Price
$/mcf |
Delivery
Point |
Unrealized
Gain (Loss)
$000’s |
Fixed |
April
1, 2005 to June 30, 2005 |
4,737 |
$7.07 |
AECO |
$(398) |
Collar |
April
1, 2005 to October 31, 2005 |
4,737 |
$6.33-$8.44 |
AECO |
(418) |
Collar |
April
1, 2005 to October 31, 2005 |
4,737 |
$6.33-$9.60 |
AECO |
(128) |
Collar |
April
1, 2005 to October 31, 2005 |
4,737 |
$6.33-$8.44 |
AECO |
(418) |
Collar |
April
1, 2005 to October 31, 2005 |
4,737 |
$6.33-$8.44 |
AECO |
(418) |
Three
way collar |
April
1, 2005 to October 31, 2005 |
4,737 |
$4.75-$5.80-$7.92 |
AECO |
(652) |
Fixed |
July
1, 2005 to September 30, 2005 |
4,737 |
$7.06 |
AECO |
(607) |
Three
way collar |
November
1, 2005 to March 31, 2006 |
4,737 |
$5.68-$6.70-$10.55 |
AECO |
(467) |
Three
way collar |
November
1, 2005 to March 31, 2006 |
4,737 |
$5.28-$6.33-$12.98 |
AECO |
(233) |
Collar |
November
1, 2005 to March 31, 2006 |
4,737 |
$7.28-$13.61 |
AECO |
40 |
Total |
|
|
|
|
$(3,699) |
Oil |
Term |
Volume
bbl/d |
Price
$/bbl |
Delivery
Point |
Unrealized
Loss
$000’s |
Three
way collar |
January
1, 2005 to December 31, 2005 |
1,000 |
$24.19-$29.03-$35.08 |
Edmonton |
$
(10,025) |
Three
way collar |
January
1, 2005 to December 31, 2005 |
1,000 |
$29.03-$32.43-$40.90 |
Edmonton |
(8,214) |
Three
way collar |
January
1, 2005 to December 31, 2005 |
1,000 |
$27.82-$32.42-$39.67 |
Edmonton |
(8,570) |
Three
way collar |
April
1, 2005 to June 30, 2005 |
1,000 |
$42.34-$48.38-$60.48 |
Edmonton |
(760) |
Collar |
April
1, 2005 to June 30, 2005 |
1,000 |
$48.38-$66.53 |
Edmonton |
(364) |
Three
way collar |
July
1, 2005 to December 31, 2005 |
1,000 |
$42.34-$48.38-$67.74 |
Edmonton |
(1,126) |
Collar |
July
1, 2005 to September 30, 2005 |
1,000 |
$50.80-$68.77 |
Edmonton |
(476) |
Collar |
October
1, 2005 to December 31, 2005 |
1,000 |
$50.80-$67.98 |
Edmonton |
(529) |
Three
way collar |
January
1, 2006 to March 31, 2006 |
1,000 |
$42.34-$48.38-$64.11 |
Edmonton |
(725) |
Collar |
January
1, 2006 to March 31, 2006 |
1,000 |
$50.80-$72.58 |
Edmonton |
(325) |
Collar |
January
1, 2006 to March 31, 2006 |
1,000 |
$54.43-$84.67 |
Edmonton |
(4) |
Three
way collar |
April
1, 2006 to June 30, 2006 |
1,000 |
$44.76-$50.80-$71.67 |
Edmonton |
(421) |
Total |
|
|
|
|
$(31,539) |
Electricity |
Term |
Volume
MW/h |
Price
$/MWh |
Delivery
Point |
Unrealized
Gain
$000’s |
Fixed
Price |
February
1, 2004 to December 31, 2005 |
2.0 |
$44.50 |
Alberta
Power Pool |
$148 |
Derivative
financial instruments and related hedge contracts involve a degree of credit
risk, which the Trust controls through the use of financially sound
counterparties. The gains or losses incurred are recognized on a monthly basis
over the terms of the hedge contracts. All foreign exchange calculations in this
section of the report incorporate the Bank of Canada US dollar rate at the close
on March 31, 2005 of CDN $1.2096:US$.
Petrofund
Energy Trust is a Calgary based royalty trust that acquires and manages
producing oil and gas properties in Western Canada. The Trust pays its
Unitholders monthly cash distributions, which are derived from the Trust’s cash
flow from these properties. Petrofund Energy Trust was founded in 1988 and was
one of the first oil and gas royalty trusts in Canada.
This news
release may include statements about expected future events and/or financial
results that are forward-looking in nature and subject to risks and
uncertainties. For those statements, we claim the protection of the safe harbor
for forward-looking statements provisions contained in the U.S. Private
Securities Litigation Reform Act of 1995. Petrofund Energy Trust cautions that
actual performance will be affected by a number of factors, many of which are
beyond its control. Future events and results may vary substantially from what
Petrofund Energy Trust currently foresees. Discussion of the various factors
that may affect future results is contained in Petrofund Energy Trust’s recent
filings with the Securities and Exchange Commission and Canadian securities
regulatory authorities.
In
regards to barrels of oil equivalent (boe), boes may be misleading, particularly
if used in isolation. A BOE conversion of 6 mcf:1 bbl is based on an energy
equivalency conversion method primarily applicable at the burner tip and does
not represent a value equivalency at the wellhead.
PETROFUND
ENERGY TRUST
Jeffery
E. Errico
President
and Chief Executive Officer
For
Petrofund Investor Relations:
Phone:
(403) 218-4736
Fax:
(403) 539-4300
Toll
Free: 1-866-318-1767
Website:
www.petrofund.ca
For
information regarding this press release:
Chris
Dutcher
Director,
Business Development
Phone:
(403) 218-8625
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