APF Energy Trust

APF Energy Trust

March 03, 2005 21:30 ET

APF Energy Releases 2004 Financial and Operating Results


NEWS RELEASE TRANSMITTED BY CCNMatthews

FOR: APF ENERGY TRUST

TSX SYMBOL: AY.UN
TSX SYMBOL: AY.DB

MARCH 3, 2005 - 21:30 ET

APF Energy Releases 2004 Financial and Operating
Results

CALGARY, ALBERTA--(CCNMatthews - March 3, 2005) - APF Energy Trust
(TSX:AY.UN) (TSX:AY.DB) ("APF") is pleased to announce its 2004 year-end
financial and operating results.

HIGHLIGHTS

- Completed the $291.08 million acquisition of Great Northern
Exploration Ltd., adding 5,600 boe/d and growing the Trust by
approximately 45%.

- APF had record cash flow of $107.13 million in 2004 and declared cash
distributions of $96.93 million, resulting in a 2004 payout ratio of 90
percent. APF realized cash flow of $31.13 million for the three months
ended December 31, 2004, an increase of 109 percent over the fourth
quarter of 2003. The Trust declared cash distributions of $28.07 million
($0.48 per unit) for the three months ended December 31, 2004.

- Drilled 284 (131.1 net) wells with a 98 percent success rate, a 73
percent increase over 2003 activity levels.

- Capital expenditures of $68.78 million were devoted to the 2004
development program and resulted in incremental production that offset
natural production declines on existing properties. Ongoing internal
development and optimization activities are expected to result in
average production of approximately 18,000 to 18,500 boe/d, with the
potential to increase, pending rig and crew availability. Production
averaged 16,012 boe/d in 2004, compared to 14,463 boe/d in 2003.
Production for the three months ended December 31, 2004 averaged 18,450
boe/d.

- Provided investors with a 16 percent cash yield throughout the year.

- Strong participation levels in the Premium Distribution, Distribution
Reinvestment and Optional Unit Purchase Plan provided $39.66 million of
funding, which was utilized in partially funding the capital development
program.



Three Months Ended Twelve Months Ended
SUMMARY OF OPERATING December 31 December 31
& FINANCIAL RESULTS 2004 2003 2004 2003
------------------------------------------------------------------------
FINANCIAL Restated(3) Restated(3)
($000, except per
unit/boe amounts)
Cash flow from operations(1) 31,125 14,873 107,126 81,019
Per unit - basic $ 0.53 $ 0.44 $ 2.21 $ 2.62
Per unit - diluted $ 0.50 $ 0.39 $ 2.03 $ 2.42
Distributions 28,068 17,822 96,930 68,713
Per unit $ 0.48 $ 0.53 $ 2.00 $ 2.20
Payout ratio 90% 120% 90% 85%
Bank debt 169,000 98,000 169,000 98,000
Operating costs per boe $ 9.21 $ 7.96 $ 8.84 $ 7.12
Operating netbacks per boe
(before derivatives) $ 26.33 $ 18.20 $ 25.34 $ 22.89
Market
Units outstanding (000s)
End of period 58,845 34,074 58,845 34,074
Weighted average - basic 58,292 33,907 48,486 30,970
Weighted average - diluted 62,675 38,612 52,869 33,489
Trust unit trading
High $ 12.47 $ 12.67 $ 12.63 $ 12.67
Low $ 11.31 $ 11.45 $ 10.32 $ 9.30
Close $ 11.72 $ 12.54 $ 11.72 $ 12.54
Average daily volume 336,761 123,000 305,706 163,000
------------------------------------------------------------------------
------------------------------------------------------------------------
OPERATIONS
Daily production (average)
Crude oil (bbl) 7,734 6,498 6,969 6,472
NGLs (bbl) 1,048 474 758 358
Natural gas (mcf) 58,008 36,929 49,712 33,799
-------------------------------------------
Total (boe)(2) 18,450 13,127 16,012 12,463
Average commodity prices
($Cdn.)
Total crude oil (bbl) $ 46.43 $ 32.68 $ 44.63 $ 36.07
NGLs (bbl) $ 41.82 $ 31.37 $ 40.09 $ 31.83
Natural gas (mcf) $ 6.74 $ 5.59 $ 6.79 $ 6.64
-------------------------------------------
Average (boe)(2) $ 43.01 $ 33.04 $ 42.40 $ 37.66
Drilling (gross wells)
Oil 15 31 37 60
Gas 112 15 135 80
Coalbed methane 55 19 104 19
Other 3 0 8 5
-------------------------------------------
Total 185 65 284 164
------------------------------------------------------------------------
------------------------------------------------------------------------

(1) 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 GAAP and therefore it may not be comparable with the
calculation of similar measures for other entities. Cash flow as
presented is not intended to represent operating cash flow 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 and accrued interest on convertible debentures.

(2) BOE's may be misleading, particularly if used in isolation. In
accordance with NI 51-101, a BOE conversion ratio for natural gas
of 6 Mcf: 1 bbl has been used which is based on an energy
equivalency conversion method primarily applicable at the burner
tip and does not represent a value equivalency at the wellhead.

(3) 2003 comparative results have been restated for the three and twelve
month periods ended December 31 to reflect the adoption of CICA
Handbook Section 3110 "Asset Retirement Obligations", as well as
section 3870, "Stock-based Compensation and Other Stock-based
Payments"


MANAGEMENT'S DISCUSSION AND ANALYSIS

This Management's Discussion and Analysis ("MD&A") for APF Energy Trust
("APF" or the "Trust") should be read in conjunction with the December
31, 2004 and 2003 audited annual consolidated financial statements
("consolidated financial statements") and related note disclosures. The
consolidated financial statements have been prepared in accordance with
Canadian generally accepted accounting principles ("Canadian GAAP") and
are presented in Canadian currency (except where indicated as being in
another currency). APF is an oil and gas issuer and disclosures
pertaining to oil and gas activities are presented in accordance with
National Instrument 51-101 ("NI 51-101"). This MD&A is dated March 1,
2005.

RESULTS OF OPERATIONS

PRODUCTION AND MARKETING

The Trust increased average production volumes by 28 percent to 16,012
boe/d for the year ended December 31, 2004 due primarily to the
acquisition of Great Northern Exploration Ltd ("Great Northern") which
added 5,600 boe/d of production effective June 2004, combined with a
successful drilling program. The Great Northern acquisition and the
Trust's gas-focused drilling program, has shifted production from 45
percent natural gas-weighted in 2003, to 52 percent in 2004.

The Trust increased light/medium and heavy oil production by seven and
nine percent respectively during 2004, despite unseasonable conditions
that extended beyond the traditional spring break-up period. NGL and
natural gas daily production volumes increased 112 and 47 percent
respectively relative to the prior year, due primarily to the
gas-levered Great Northern acquisition. The increase in production
volumes is more pronounced in the fourth quarter and is more
representative of the impact of Great Northern going forward.




Three Months Ended Twelve Months Ended
December 31 December 31
---------------------------------------------------
2004 2003 %Change 2004 2003 %Change
------------------------------------------------------------------------
Light/medium crude
oil (bbl/d) 6,443 5,205 24 5,802 5,399 7
Heavy oil (bbl/d) 1,291 1,293 (0) 1,167 1,073 9
NGL (bbl/d) 1,048 474 121 758 358 112
Natural gas (mcf/d) 58,008 36,929 57 49,712 33,799 47
------------------------------------------------------------------------
Total (boe/d) 18,450 13,127 41 16,012 12,463 28
------------------------------------------------------------------------
------------------------------------------------------------------------
Production split
------------------------------------------------------------------------
Oil & NGLs 48% 53% (10) 48% 55% (12)
Natural Gas 52% 47% 12 52% 45% 14
------------------------------------------------------------------------
------------------------------------------------------------------------


Crude oil is sold under 30-day evergreen contracts while the majority of
natural gas production is sold in the spot market. Approximately 15
percent of natural gas volumes are sold to aggregators pursuant to
long-term contracts declining from 20 percent prior to acquiring Great
Northern volumes.

REALIZED OIL AND GAS PRICES

The Trust's combined crude oil pricing before derivatives increased 24
percent for the year and 42 percent for the three months ended December
31, 2004, relative to the industry benchmark West Texas Intermediate
("WTI") measured in U.S. currency, which increased 33 and 55 percent
over the same periods. The difference is consistent with observed
differentials between WTI and the Canadian dollar-denominated Edmonton
Par crude, which increased 22 and 46 percent for the year and three
months ended December 31, 2004 respectively. U.S. and Canadian product
differentials are primarily driven by U.S./Cdn. currency exchange rates;
however, quality differentials and U.S. demand for Canadian imports also
impact relative pricing. The remaining difference between the Trust's
combined crude pricing before derivatives as compared to Edmonton Par is
due to product quality differentials attributable to the Trust's heavy
oil production. For the year ended December 31, 2004, heavy oil as a
percentage of total crude oil production remained relatively unchanged
whereas this percentage for the three months ended December 31, 2004
decreased from 20 percent to 17 percent. As a result, the Trust realized
a higher average price relative to the comparative period.

Natural gas pricing before derivatives for the year ended December 31,
2004 increased two percent over the prior year. This is consistent with
the one percent increase in the benchmark AECO price for the
corresponding period as the relative balance between the supply of and
demand for natural gas in North America remained constant. For the three
months ended December 31, 2004, the 21 percent increase in the price of
natural gas relative to the comparable quarter is due mainly to
depressed North American natural gas prices during October and November
2003.

Price realizations include the impact of realized crude oil and natural
gas financial derivative instruments. For the year ended December 31,
2004, crude oil price realizations increased 11 percent to $38.19 per
boe and include the settlement of crude oil derivatives, which lowered
pricing before derivatives by 14 percent or $6.44 per boe. Crude oil
price realizations during the fourth quarter of 2004 were 18 percent
higher than 2003 price realizations despite derivative losses that
lowered per boe pricing 20 percent from $46.43 before derivatives to
$37.23 after realized derivatives.

The impact of realized derivatives did not significantly impact natural
gas price realizations. Consistent with pricing before derivatives, for
the year ended December 31, 2004, price realizations were up slightly to
$6.80 per mcf, which represents a two percent increase over the prior
year. Price realizations during the fourth quarter of 2004 were up 18
percent as compared to 2003, due to depressed North American natural gas
prices during the first two months of the fourth quarter of 2003.

Effective January 1, 2004, the Trust began segregating costs associated
with the transportation and selling of crude oil, natural gas and NGLs.
Previously, the Trust had followed industry practice, presenting revenue
net of these costs. The comparative figures have been restated with
these costs segregated, resulting in an increase to the gross price per
mcf (boe).



Three Months Ended Twelve Months Ended
December 31 December 31
Prices - Before ---------------------------------------------------
Derivatives ($Cdn.) 2004 2003 %Change 2004 2003 %Change
------------------------------------------------------------------------
Light/medium crude
oil (bbl) $49.89 $35.21 42 $47.29 $38.03 24
Heavy oil (bbl) 29.15 22.48 30 31.43 $26.19 20
------------------------------------------------------------------------
Total crude oil (bbl) 46.43 32.68 42 44.63 36.07 24
NGLs (bbl) 41.82 31.37 33 40.09 $31.83 26
Natural gas (mcf) 6.74 5.59 21 6.79 $ 6.64 2
------------------------------------------------------------------------
Total (boe) $43.01 $33.04 30 $42.40 $37.66 13
------------------------------------------------------------------------
------------------------------------------------------------------------

Realized Oil and Gas Derivatives ($Cdn.)
------------------------------------------------------------------------
Crude oil (bbl) $(9.20) $(1.01) 811 $(6.44) $(1.61) 300
Natural gas (mcf) 0.05 0.16 (69) 0.01 0.02 (50)
------------------------------------------------------------------------
Total (boe) $(3.69) $(0.04) 9,125 $(2.78) $(0.79) 252
------------------------------------------------------------------------
------------------------------------------------------------------------

Prices - After Realized Oil and Gas Derivatives ($Cdn.)
------------------------------------------------------------------------
Total crude oil
(bbl) $37.23 $31.67 18 $38.19 $34.46 11
NGLs (bbl) 41.82 31.37 33 40.09 31.83 26
Natural gas (mcf) 6.79 5.75 18 6.80 6.66 2
------------------------------------------------------------------------
Total (boe) $39.32 $33.00 19 $39.62 $36.87 7
------------------------------------------------------------------------
------------------------------------------------------------------------

Reference Pricing
------------------------------------------------------------------------
WTI ($U.S./bbl) $48.28 $31.18 55 $41.40 $31.04 33
Edmonton Par
($Cdn./bbl) $57.71 $39.56 46 $52.55 $43.14 22
AECO gas ($Cdn./mcf) $ 7.08 $ 5.59 27 $ 6.79 $ 6.70 1
Foreign exchange
($U.S./$Cdn.) 1.2207 1.3157 (7) 1.3282 1.4010 (5)
------------------------------------------------------------------------
------------------------------------------------------------------------


The Trust uses derivative instruments to manage commodity price
fluctuations and stabilize cash flows available for unitholder
distributions and future development programs (see Risk Management
section of this document). Derivative instruments are also used to help
manage exposures to foreign currency exchange rates, interest rates, and
electricity rates. APF does not enter into derivative contracts for
speculative purposes. A detailed summary of the Trust's derivative
position at December 31, 2004 is presented in the Risk Management
section of this document.

APF's current approach to derivatives involves the use of swaps,
collars, and sold WTI call options for light and medium crude oil, and
swaps and collars for natural gas. The following table summarizes crude
oil and natural gas derivative contracts settled during 2004 as a
percentage of quarterly production volumes and contracts outstanding as
at the date of this report relating to future production:



Percentage of 2004 2005 2006
--------------------------------------------------
Production hedged Q1 Q2 Q3 Q4 Q1 Q2 Q3 Q4 Q1 Q2
------------------------------------------------------------------------
Crude oil 49% 44% 44% 49% 34% 50% 47% 27% 27% 7%
Natural gas 33% 30% 35% 22% 16% 41% 41% 25% 16% 0%
------------------------------------------------------------------------
------------------------------------------------------------------------


OIL AND GAS REVENUE

Gross oil and gas revenue for the year ended December 31, 2004 increased
45 percent over the prior year, due to the Trust's acquisition of Great
Northern and sustained strength in commodity prices. Seven months of
Great Northern production volumes are reflected in the 2004 fiscal year.
The impact of Great Northern is more evident when comparing the three
month periods ended December 31. Gross oil and gas revenue for the
fourth quarter of 2004 increased 83 percent over the comparable period
in 2003. The variance can be explained by a 30 percent increase in
prices (before realized derivatives) on 41 percent higher production
volumes.

Effective January 1, 2004, the Trust began segregating costs associated
with the transportation and selling of crude oil, natural gas and NGLs.
Previously, the Trust had followed industry practice, presenting revenue
net of these costs. The comparative figures have been restated with
these costs segregated, resulting in an increase to the gross price per
mcf (boe).




Three Months Ended Twelve Months Ended
December 31 December 31
Oil and Gas ---------------------------------------------------
($000 except Restated Restated
per boe amounts) 2004 2003 %Change 2004 2003 %Change
------------------------------------------------------------------------
Light/medium crude
oil sales 29,571 16,862 75 100,419 74,934 34
Heavy oil sales 3,463 2,675 29 13,423 10,260 31
NGL sales 4,031 1,368 195 11,115 4,157 167
Natural gas sales 35,944 18,997 89 123,527 81,938 51
------------------------------------------------------------------------
Gross oil and
gas revenue 73,009 39,902 83 248,484 171,289 45

Realized oil and
gas derivatives (6,260) (44) 14,127 (16,305) (3,565) 357
Transportation (1,427) (1,150) 24 (5,245) (4,174) 26
Other 2,197 421 422 4,729 1,925 146
------------------------------------------------------------------------
Net oil and
gas revenue 67,519 39,129 73 231,663 165,475 40

Per boe $ 39.79 $ 32.39 23 $ 39.53 $ 36.38 9
------------------------------------------------------------------------
------------------------------------------------------------------------


ROYALTIES

Royalties paid are calculated in accordance with royalty reference rates
directly related to gross oil and gas revenues generated by the Trust
from mineral leases with the Crown, freeholders and other operators.
Total royalties for the year ended December 31, 2004 as a percentage of
gross oil and gas revenue were consistent with rates paid during the
prior year. Total royalties recorded for the fourth quarter of 2004 are
approximately 18 percent of gross oil and gas revenue due to an
adjustment for royalties previously accrued for during 2004. Going
forward, the Trust expects royalty rates to remain consistent with
annual rates recorded in 2004 and 2003.




Three Months Ended Twelve Months Ended
December 31 December 31
---------------------------------------------------
($000 except Restated Restated
per boe amounts) 2004 2003 %Change 2004 2003 %Change
------------------------------------------------------------------------
Crown royalties 8,711 4,838 80 30,429 19,364 57
Freehold royalties 3,231 2,120 52 12,679 10,193 24
Overriding royalties 1,309 609 115 4,602 2,916 58
------------------------------------------------------------------------
Total royalties 13,251 7,567 75 47,710 32,473 47
------------------------------------------------------------------------
% of gross oil and
gas revenue 18.1% 19.0% (4) 19.2% 19.0% 1
Per boe $ 7.81 $ 6.27 25 $ 8.14 $ 7.14 14
------------------------------------------------------------------------
------------------------------------------------------------------------


OPERATING EXPENSE

On a gross and per boe basis, operating costs were higher for the three
months and year ended December 31, 2004 when compared to the same
periods in 2003 due primarily to the acquisition and integration of
Great Northern. The Trust completed a significant portion of
optimization projects planned for Great Northern properties during the
third and fourth quarters of 2004 and operating costs have trended lower
following completion of these initiatives. The Trust has planned for
additional initiatives to control future field costs and expects
operating costs to continue to trend downwards to an average $9.00 per
boe during fiscal 2005.




Three Months Ended Twelve Months Ended
December 31 December 31
---------------------------------------------------
($000 except Restated Restated
per boe amounts) 2004 2003 %Change 2004 2003 %Change
------------------------------------------------------------------------
Operating expense 15,628 9,619 62 51,788 32,370 60
Per boe $ 9.21 $ 7.96 16 $ 8.84 $ 7.12 24
------------------------------------------------------------------------
------------------------------------------------------------------------


PRODUCT NETBACKS

Light/medium crude oil netbacks for the year ended December 31, 2004
decreased by two percent from $19.76 to $19.31, due primarily to lower
price realizations after derivatives and higher operating costs related
to Great Northern properties. The 2004 quarterly light/medium netback
increased four percent over the prior period presented, resulting from
higher prices received before derivatives and a smaller increase in
operating costs relative to the prior period.



Three Months Ended Twelve Months Ended
December 31 December 31
---------------------------------------------------
Light/medium crude Restated Restated
oil ($Cdn. per bbl) 2004 2003 %Change 2004 2003 %Change
------------------------------------------------------------------------
Price - After
realized
derivatives $ 38.85 $ 33.95 14 $ 39.55 $ 36.10 10
------------------------------------------------------------------------
Royalties (9.24) (7.55) 22 (9.01) (7.56) 19
Operating expense (12.76) (10.26) 24 (11.23) (8.78) 28
------------------------------------------------------------------------
Operating netback $ 16.85 $ 16.14 4 $ 19.31 $ 19.76 (2)
------------------------------------------------------------------------
------------------------------------------------------------------------


Heavy oil netbacks increased 22 percent and 95 percent for year and
three months ended December 31, 2004, respectively, as compared to the
prior periods in 2003. The increase is due primarily to higher price
realizations offset by an increase in royalty expense. Operating costs
for the year ended December 31, 2004 increased four percent over the
prior year but were down 14 percent during the fourth quarter due to
additional processing recoveries that reduce operating costs.



Three Months Ended Twelve Months Ended
December 31 December 31
---------------------------------------------------
Heavy oil Restated Restated
($Cdn. per bbl) 2004 2003 %Change 2004 2003 %Change
------------------------------------------------------------------------
Price - After
realized
derivatives $ 29.15 $ 22.48 30 $ 31.43 $ 26.19 20
------------------------------------------------------------------------
Royalties (4.68) (3.51) 33 (4.42) (2.56) 73
Operating expense (9.93) (11.53) (14) (11.09) (10.62) 4
------------------------------------------------------------------------
Operating netback $ 14.54 $ 7.44 95 $ 15.92 $ 13.01 22
------------------------------------------------------------------------
------------------------------------------------------------------------


NGL netbacks increased 33 percent and 59 percent for year and three
months ended December 31, 2004, respectively, relative to the
corresponding periods in 2003 due to higher price realizations in a
strong commodity price environment.



Three Months Ended Twelve Months Ended
December 31 December 31
---------------------------------------------------
Restated Restated
NGLs ($Cdn. per bbl) 2004 2003 %Change 2004 2003 %Change
------------------------------------------------------------------------
Price - After
realized
derivatives $ 41.82 $ 31.37 33 $ 40.09 $ 31.83 26
------------------------------------------------------------------------
Royalties (7.52) (9.84) (24) (10.31) (9.41) 10
Operating expense - - - - - -
------------------------------------------------------------------------
Operating netback $ 34.30 $ 21.53 59 $ 29.78 $ 22.42 33
------------------------------------------------------------------------
------------------------------------------------------------------------


Natural gas netbacks declined six percent for the year ended December
31, 2004 and increased 15 percent for the three months ended December
31, 2004. Price realizations for the year ended December 31, 2004 were
relatively flat as compared to 2003 and the 21 percent
quarter-over-quarter increase in the price of natural gas after
deducting transportation is due to unusually low North American natural
gas prices experienced during October and November of 2003. The increase
in operating costs per mcf was due to planned optimization initiatives
related to Great Northern properties.



Three Months Ended Twelve Months Ended
December 31 December 31
---------------------------------------------------
Natural gas Restated Restated
($Cdn. per mcf) 2004 2003 %Change 2004 2003 %Change
------------------------------------------------------------------------
Price - After
realized
derivatives $ 6.79 $ 5.75 18 $ 6.80 $ 6.66 2
Transportation (0.27) (0.34) (21) (0.29) (0.34) (15)
------------------------------------------------------------------------
6.52 5.41 21 6.51 6.32 3
Royalties (1.22) (0.92) 33 (1.31) (1.24) 6
Operating expense (1.29) (0.99) 30 (1.28) (0.89) 44
------------------------------------------------------------------------
Operating netback $ 4.01 $ 3.50 15 $ 3.92 $ 4.19 (6)
------------------------------------------------------------------------
------------------------------------------------------------------------


On a combined boe basis, the increase in price realizations less
transportation and other income is consistent with higher commodity
prices offset by realized derivative losses. Despite the negative impact
of derivatives and higher operating costs during the year ended December
31, 2004, netbacks increased two percent over 2003. Netbacks for the
fourth quarter performed better against the comparable quarter due to a
weaker commodity price environment during the fourth quarter of 2003,
combined with operating costs that have trended lower since the third
quarter of 2004.



Three Months Ended Twelve Months Ended
December 31 December 31
---------------------------------------------------
Combined Restated Restated
($Cdn. per boe) 2004 2003 %Change 2004 2003 %Change
------------------------------------------------------------------------
Price - After
realized
derivatives $ 39.32 $ 33.00 19 $ 39.62 $ 36.87 7
Transportation (0.84) (0.95) (12) (0.90) (0.92) (2)
Other 1.18 0.35 237 0.82 0.41 100
------------------------------------------------------------------------
39.66 32.40 22 39.54 36.36 9
Royalties (7.81) (6.27) 25 (8.14) (7.14) 14
Operating expense (9.21) (7.97) 16 (8.84) (7.12) 24
------------------------------------------------------------------------
Operating netback $ 22.64 $ 18.16 25 $ 22.56 $ 22.10 2
------------------------------------------------------------------------
------------------------------------------------------------------------


GENERAL AND ADMINISTRATIVE

General and administrative ("G&A") expense for the year ended December
31, 2004, increased commensurate with increased staffing levels required
by growth in the Trust's operations from recent corporate and property
acquisitions. On a per boe basis, G&A has declined 18 percent for the
year and 43 percent for the three months ended December 31, 2004 due
primarily to lower costs accrued for under the Trust's short-term
incentive plan ("STIP").



---------------------------------------------------
($000 except Restated Restated
per boe amounts) 2004 2003 %Change 2004 2003 %Change
------------------------------------------------------------------------
General and
administrative 3,197 3,980 (20) 10,635 10,023 6
Per boe $ 1.88 $ 3.29 (43) $ 1.81 $ 2.20 (18)
------------------------------------------------------------------------
------------------------------------------------------------------------


The STIP is designed to align employee and unitholder interests and to
reward exceptional employee performance. The STIP enables all eligible
employees to participate in a group bonus pool, provided the Trust
generates a minimum total annual return of 10 percent. The total annual
return on the Trust units as calculated by management for the year ended
December 31, 2004 was 10.7 percent (2003 - 50 percent). Based on this
total return figure, the 2004 STIP bonus pool was $1.17 million (2003 -
$3.35 million). Senior employees, including officers, are also eligible
to receive performance bonuses based on criteria applicable to their
individual responsibilities. Excluding the STIP, G&A cost per boe for
the year and three months ended December 31, 2004 was $1.62 (2003 -
$1.47).

INTEREST ON LONG-TERM DEBT AND CONVERTIBLE DEBENTURES

Interest expense on long-term debt on a per boe basis remained
consistent with 2003 for both the year and three months ended December
31, 2004. On a gross basis, interest expense has increased commensurate
with higher average debt levels used to fund growth in the Trust's
operations.

Interest and financing charges on convertible debentures for the year
ended December 31, 2004 increased 97 percent in dollar terms and 53
percent on a per boe basis due to the fact that the debentures were
issued on July 3, 2003, resulting in only six months of interest expense
being included in the comparative figure. For the quarter ended December
31, 2004, interest expense on debentures decreased one percent in dollar
terms as compared to the same period in 2003 due to $0.22 million in
conversions during 2004.

Effective December 31, 2004, the Trust retroactively adopted the revised
CICA Handbook Section 3860 ("HB 3860"), "Financial Instruments -
Presentation and Disclosure" for financial instruments that may be
settled at the issuer's option in cash or its own equity instruments.
The revised standard requires the Trust to classify the convertible
debenture proceeds as either debt or equity based on fair value
measurement and the substance of the contractual arrangement. The Trust
previously presented the convertible debenture proceeds (net of
financing costs) and related interest obligations as equity on the
consolidated balance sheet on the basis that the Trust could settle its
obligations in exchange for trust units. The comparative figures
presented have been restated to conform to the amended accounting
standard.



Three Months Ended Twelve Months Ended
December 31 December 31
---------------------------------------------------
($000 except Restated Restated
per boe amounts) 2004 2003 %Change 2004 2003 %Change
------------------------------------------------------------------------
Interest on
long-term debt 1,556 1,088 43 5,405 4,171 30
Per boe $ 0.92 $ 0.90 2 $ 0.92 $ 0.92 1
Interest and
financing charges
on convertible
debentures 1,327 1,347 (1) 5,263 2,669 97
Per boe $ 0.78 $ 1.12 (30) $ 0.90 $ 0.59 53
------------------------------------------------------------------------
------------------------------------------------------------------------


DEPLETION, DEPRECIATION, AND ACCRETION

Depletion, depreciation and accretion ("DD&A") per boe increased 25
percent for the year and decreased 35 percent for the quarter ended
December 31, 2004, respectively, as compared to the prior periods
presented. The annual increase is due primarily to the acquisition of
Great Northern resulting in a larger depletable base. The decrease
quarter-over-quarter is attributable to an increase in proved reserves
following the Trust's most active drilling quarter and revisions to the
Trust's depletable base during the fourth quarter of 2004.

Effective January 1, 2004, the Trust retroactively adopted CICA Handbook
Section 3110, "Asset Retirement Obligations" (ARO). The new standard
requires that the fair value of an asset retirement obligation be
recognized in the period in which it is incurred with a corresponding
increase to property, plant and equipment. Prior periods presented
include the impact of adopting this standard.



Three Months Ended Twelve Months Ended
December 31 December 31
---------------------------------------------------
($000 except Restated Restated
per boe amounts) 2004 2003 %Change 2004 2003 %Change
------------------------------------------------------------------------
Depletion,
depreciation
and accretion 16,108 17,704 (9) 85,997 53,389 61
Per boe $ 9.49 $ 14.66 (35) $ 14.68 $ 11.74 25
------------------------------------------------------------------------
------------------------------------------------------------------------



UNIT-BASED COMPENSATION

For the year and three months ended December 31, 2004, the Trust
recorded a recovery of unit-based compensation of $0.88 million and
$1.87 million respectively, as compared to an expense of $1.24 million
and $0.58 million for the corresponding periods in 2003. The decrease in
unit-based compensation expense recorded in 2004 is due to a change in
the Trust's approach to valuing equity instruments awarded to employees
and directors. During the fourth quarter of 2004, the Trust began using
the Black-Scholes option-pricing model to estimate the fair value of
unit-based compensation. Previously, the Trust used the excess of the
period-end market price over the exercise price as an estimate of fair
value.

Effective December 31, 2003, the Trust prospectively adopted CICA
Handbook Section 3870, "Stock-based Compensation and Other Stock-based
Payments." The standard requires that equity instruments awarded to
employees after December 31, 2002 be measured at fair value and
recognized over the vesting period. Companies that adopted the standard
during 2003 were permitted to provide proforma disclosure of equity
instruments granted before January 1, 2003. Comparative figures for 2003
have been restated to reflect the impact of unit-based compensation.



Three Months Ended Twelve Months Ended
December 31 December 31
---------------------------------------------------
($000 except Restated Restated
per boe amounts) 2004 2003 %Change 2004 2003 %Change
------------------------------------------------------------------------
Compensation expense
(recovery) (1,866) 582 (421) (877) 1,241 (171)
Per boe $ (1.10) $ 0.48 (328) $ (0.15) $ 0.27 (155)
------------------------------------------------------------------------
------------------------------------------------------------------------


TAXES

Saskatchewan capital tax and federal large corporation tax increased 22
percent for the year and 54 percent for the quarter ended December 31,
2004 as compared to fiscal 2003 reflecting an increase in taxable
capital after the acquisition of Great Northern.

Future income taxes are recorded on corporate acquisitions to the extent
the book value of assets acquired, excluding goodwill, exceeds the tax
basis. This future income tax liability increases the book cost of the
assets acquired. It is anticipated that the future income tax liability
will not be paid by APF Energy, but will instead be passed on to
unitholders along with the income. Accordingly, this income tax
liability will reduce each year and will be recognized as an income tax
recovery at that time, to the extent that no income taxes were paid by
APF Energy. For the year ended December 31, 2004, the Trust recovered
$27.02 million in future income taxes compared to a future tax recovery
of $14.21 million in 2003. At December 31, 2004 the Trust had a future
income tax liability of $86.71 million as compared to $63.99 million at
the end of 2003. The increase is due primarily to the future tax
liability acquired with Great Northern, less recoveries recognized
during the year. The December 31, 2003 comparative figures include the
impact of adopting CICA Handbook Section 3110 "Asset Retirement
Obligations".



Three Months Ended Twelve Months Ended
December 31 December 31
---------------------------------------------------
($000 except Restated Restated
per boe amounts) 2004 2003 %Change 2004 2003 %Change
------------------------------------------------------------------------
Capital and
other taxes 957 623 54 3,321 2,720 22
Per boe $ 0.56 $ 0.52 9 $ 0.57 $ 0.60 (5)
Recovery of
future taxes (5,712) 451 1,367 (27,016) (14,207) 90
------------------------------------------------------------------------
------------------------------------------------------------------------

SUMMARY OF ANNUAL RESULTS

Year Ended December 31
-------------------------------
($000, except Restated Restated
per unit amounts) 2004 2003 2002
------------------------------------------------------------------------
Total revenue 184,152 132,984 75,314
Net income 49,636 40,608 11,582
Per unit - basic $ 1.02 $ 1.31 $ 0.57
Per unit - diluted $ 1.02 $ 1.29 $ 0.56
Cash flow from operations 107,126 81,019 43,789
Per unit $ 2.21 $ 2.62 $ 2.14
Distributions 96,930 68,713 37,766
Per unit $ 2.00 $ 2.20 $ 1.81
Total assets 862,170 498,750 306,322
Total long-term debt 169,000 98,000 88,000
------------------------------------------------------------------------
------------------------------------------------------------------------


Total revenue is primarily affected by commodity prices, production
volumes, royalties and realized and unrealized (non-cash) derivative
gains and losses. Total revenue has increased commensurate with strong
commodity prices, corporate and property acquisitions and internal
development activity. The Trust has been an active acquirer over the
past three years, completing the acquisition of Great Northern during
2004; the acquisitions of CanScot Resources, Nycan Energy, Hawk Oil, and
an additional interest at Swan Hills during 2003; and the acquisitions
of Kinwest Resources and Paddle River assets in 2002.

The new accounting requirement to recognize gains/losses in the Trust's
unrealized derivative position has introduced additional non-cash
volatility in reported income. Prior to fiscal 2004, derivative
gains/losses were reflected in income upon settlement of the related
contracts; the 2003 and 2002 figures presented above have not been
restated in accordance with the transitional provision of the new
accounting pronouncement.

Net income has increased each year; however, the growth in income was
lowered by realized oil and gas derivative losses, higher royalty
expense in proportion with gross oil and gas revenues and higher
operating costs and DD&A as a percentage of gross oil and gas revenues.
The sustained strength in commodity prices, particularly light/medium
crude oil has resulted in larger than expected derivative losses.
Operating costs associated with newly-acquired Great Northern properties
escalated through the third quarter of 2004, but have trended downward
during the fourth quarter and should remain stable throughout fiscal
2005. As the Trust is able to take advantage of internal development
opportunities, DD&A per boe is expected to remain consistent with 2004.

Given the sustained strength in commodity prices during 2004, despite
realized oil and gas derivative losses and higher cash operating costs,
the Trust has generated growth in cash flow from operations. Cash
distributions have also increased, however, distributions declared per
unit have decreased to provide the Trust with additional development
capital to sustain future cash distributions. Non-cash items such as
depletion, depreciation and accretion, future income taxes, and
unrealized gains or losses on derivative instruments do not influence
the Trust's current ability to distribute cash to unitholders.

The increase in total assets year-over-year is due primarily to oil and
gas assets and goodwill purchased through corporate acquisitions. The
increase in total long-term debt is commensurate with a larger asset
base and increased development expenditures.

SUMMARY OF QUARTERLY RESULTS

The following table highlights the Trust's performance for the two most
recent fiscal years presented on a quarterly basis:



2004 Restated
($000, except ------------------------------------------
unit amounts) Q4 Q3 Q2 Q1
------------------------------------------------------------------------
Total revenue 66,066 46,776 39,169 32,141
Net income 34,870 3,176 4,788 6,802
Per unit - basic $ 0.60 $ 0.06 $ 0.11 $ 0.18
Per unit - diluted $ 0.58 $ 0.06 $ 0.11 $ 0.18
Cash flow from operations 31,125 29,729 24,415 21,857
Per unit $ 0.53 $ 0.54 $ 0.56 $ 0.58
Distributions 28,068 26,517 22,516 19,829
Per unit $ 0.48 $ 0.48 $ 0.51 $ 0.53
Total assets 862,170 833,093 853,234 496,871
Total long-term debt 169,000 150,000 190,000 55,000


2003 Restated
($000, except ------------------------------------------
unit amounts) Q4 Q3 Q2 Q1
------------------------------------------------------------------------
Total revenue 31,543 32,737 33,295 35,410
Net income (3,852) 9,799 20,977 13,687
Per unit - basic $ (0.11) $ 0.30 $ 0.65 $ 0.54
Per unit - diluted $ (0.11) $ 0.30 $ 0.65 $ 0.54
Cash flow from operations 14,873 19,389 21,563 25,194
Per unit $ 0.44 $ 0.60 $ 0.67 $ 1.00
Distributions 17,822 18,909 18,916 13,066
Per unit $ 0.53 $ 0.57 $ 0.59 $ 0.51
Total assets 498,750 501,689 446,527 377,916
Total long-term debt 98,000 90,000 102,000 97,000
------------------------------------------------------------------------
------------------------------------------------------------------------


Total revenue has trended upward over the past eight quarters. The new
accounting requirement to mark the Trust's unrealized derivative
position to market at period end and record the change in income lowered
2004 quarterly revenues by $3.27 million in Q1, $2.22 million in Q2, and
$6.09 million in Q3, and increased Q4 total revenue by $0.22 million. As
previously mentioned, unrealized gains/losses were not recorded for
periods prior to 2004.

The volatility in quarterly net income over the past two years is
partially due to derivative gains/losses, higher operating costs and
non-cash charges such as DD&A as well as the timing of certain other
cash expenses. Net income for the fourth quarter of 2003 is
significantly lower than any other quarter reported over the past two
years due to the STIP bonus accrual recorded at December 31.

Cash flow from operations and cash distributions to unitholders have
increased steadily since the fourth quarter of 2003. Growth in cash
flows has been less than the observed increase in gross oil and gas
revenues due to realized derivative losses and higher cash operating
costs. Non-cash items such as DD&A, future income taxes, and unrealized
gains or losses on derivative instruments do not influence the Trust's
ability to distribute cash to unitholders.

Significant corporate and property acquisitions explain the movement in
total assets and total long-term debt. Great Northern was acquired in
June 2004; CanScot was acquired in September 2003; Nycan Energy in April
2003; and Hawk Oil was acquired in February 2003. The increase in
long-term debt at the end of 2004 is the result of the most active
capital development program in the Trust's history.

LIQUIDITY AND CAPITAL RESOURCES

WORKING CAPITAL

At December 31, 2004, the Trust had a working capital deficit of
approximately $11.99 million as compared to $8.19 million at December
31, 2003. The 46 percent increase is the result of the fourth quarter of
2004 being the Trust's most active drilling quarter since inception. The
Trust anticipates cash flow from operations will be sufficient to meet
this current deficit.

Included in the calculation of working capital are unrealized derivative
instruments measured at fair value and recorded on the balance sheet as
a current asset or liability in accordance with EIC 128. At December 31,
2004, a current derivative asset of $3.31 million was recorded on the
balance sheet (2003 - $nil) offset by a current derivative liability of
$3.14 million (2003 - $nil). The ultimate settlement of these derivative
positions is dependent upon changes in commodity prices, foreign
currency exchange rates, and interest rates during the remaining life of
derivative contracts.

LONG-TERM DEBT

Credit facility

At December 31, 2004, the Trust had a revolving credit and term facility
for $200 million (2003 - $150 million) with a syndicate of Canadian
financial institutions. The facility may be drawn down or repaid at any
time but there are no scheduled repayment terms.

The debt is collateralized by a $300 million demand debenture containing
a first fixed charge on all crude oil and natural gas assets of APF as
required by the lenders and a floating charge on all other property
together with a general assignment of book debts. At December 31, 2004,
the interest rate was Bank Prime of 4.25 percent plus 0.125 percent
(2003 - 4.50 percent plus 0.125 percent).

Convertible debentures

On July 3, 2003, the Trust issued $50 million of 9.40 percent unsecured
subordinated convertible debentures ("convertible debentures") for
proceeds of $50 million ($47.68 million net of issue costs). Interest is
paid semi-annually on January 31 and July 31 and the instruments mature
on July 31, 2008.

The debentures are convertible at the holder's option into fully paid
and non-assessable trust units at any time prior to July 31, 2008, at a
conversion price of $11.25 per trust unit. The holder will receive
accrued and unpaid interest up to and including the conversion date. The
Trust can redeem the debentures after July 31, 2006, or earlier under
certain circumstances. The convertible debentures become redeemable at
$1,050 per convertible debenture, in whole or in part, after July 31,
2006 and redeemable at $1,025 after July 31, 2007 and before maturity.



The following table highlights accretion, conversions and the carrying
value of Trust's convertible debentures:

Liability Equity
($000s) Component Component Total
------------------------------------------------------------------------
Issued on July 3, 2003 48,817 1,183 50,000
Accretion of liability during 2003 89 - 89
Conversions into Trust units during 2003 (1,187) (29) (1,216)
------------------------------------------------------------------------
Carrying value at December 31, 2003 47,719 1,154 48,873
------------------------------------------------------------------------
Accretion of liability during 2004 193 - 193
Conversions into Trust units during 2004 (215) (5) (220)
------------------------------------------------------------------------
Carrying value at December 31, 2004 47,697 1,149 48,846
------------------------------------------------------------------------
------------------------------------------------------------------------

UNITHOLDERS' EQUITY

Trust unit offerings

At December 31, 2004, the Trust had 58.85 million Trust units
outstanding (2003 - 34.07 million) and a market capitalization of
approximately $690 million (2003 - $427 million). During 2004, the Trust
completed three trust unit issuances:

Price per Gross
Date of Issue Units Issued Unit Proceeds Use of Proceeds
------------------------------------------------------------------------
1. February 4, 2004 4.77 million $11.60 $ 55.27 Reduced financial
leverage; a
portion of
proceeds were
used to finance
Great Northern
acquisition.
2. June 4, 2004 12.89 million $12.18 $156.94 Issued as part
of the Great
Northern
acquisition.
3. September 8, 3.10 million $11.30 $ 35.03 Reduced
2004 financial
leverage and
partially fund
the Trust's
expanded 2004
capital
expenditure
program.


Distribution reinvestment plan

Commencing December 2003, the Trust initiated a distribution
reinvestment plan ("DRIP") for Canadian resident unitholders. The DRIP
permits eligible unitholders to direct their distributions to the
purchase of additional units at 95 percent of the average market price
as defined in the plan ("Regular DRIP").

The premium distribution component permits eligible unitholders to elect
to receive 102 percent of the cash the unitholder would otherwise have
received on the distribution date ("Premium DRIP"). Participation in the
Regular DRIP and Premium DRIP is subject to proration by the Trust. The
DRIP also allows those unitholders who participate in either the
distribution reinvestment component or the premium distribution
component to purchase additional trust units directly from the Trust for
cash at a purchase price equal to the average market price (with no
discount) in minimum amounts of $1,000 per remittance and up to $100,000
aggregate amount of remittances by a unitholder in any calendar month,
all subject to an overall annual limit of 2 percent of the outstanding
Trust units.

The Trust issued 3.03 million trust units during the year ended December
31, 2004 (2003 - 0.12 million) pursuant to the Premium DRIP, generating
$33.89 million in proceeds (2003 - $1.33 million). During the fourth
quarter of 2004, the Trust issued 0.89 million Trust units (2003 - 0.12
million) for total proceeds of $9.91 million (2003 - $1.33 million) in
respect of the Premium DRIP. Under the Regular DRIP, the Trust issued
0.52 million Trust units during 2004 (2003 - 0.02 million) for proceeds
of $5.76 million (2003 - $0.27 million). During the quarter ended
December 31, 2004, the Trust issued 0.16 million units (2003 - 0.02
million) for proceeds of $1.81 million (2003 - $0.27 million).

Unitholder distributions

Distributions to unitholders are paid monthly and can fluctuate
depending on the cash flow generated from operations. Distributable cash
is dependent upon many factors including commodity prices, production
levels, debt levels, capital spending requirements, and other market
factors. The Trust declared unitholder distributions of $96.93 million,
or $2.00 per trust unit during the year ended December 31, 2004 (2003 -
$68.71 million or $2.20 per unit). For the quarter ended December 31,
2004, the Trust declared distributions of $28.07 million, or $0.48 per
Trust unit (2003 - $17.82 million or $0.53 per unit).

The Trust distributed 90 percent of cash flow from operations for both
the three months and year ended December 31, 2004 as compared to 120
percent and 85 percent for the three months and the year ended December
31, 2003.

Taxation of unitholder distributions

Distributions to unitholders have two components for taxation purposes:
the taxable return on capital portion and the tax deferred return of
capital. The return on capital is considered taxable to unitholders
whereas the return of capital reduces the adjusted cost base of the unit
each time a distribution is received. The following table summarizes the
components of annual distributions paid by the Trust since inception:



Tax
Taxable Deferred Cash
Amount Amount Distribution
Per Unit Per Unit Per Unit Tax
Payment (Other (Return of for Tax Taxable Deferred
Period Income) Capital) Purposes Percentage Percentage
------------------------------------------------------------------------
2004 $1.374 $0.636 $ 2.010 68.345% 31.655%
2003 $1.718 $0.462 $ 2.180 78.814% 21.186%
2002 $1.143 $0.657 $ 1.800 63.517% 36.483%
2001 $1.741 $1.304 $ 3.045 57.175% 42.825%
2000 $1.181 $0.719 $ 1.900 62.137% 37.863%
1999 $0.526 $1.029 $ 1.555 33.826% 66.174%
1998 $0.453 $1.387 $ 1.840 24.625% 75.375%
1997 $0.597 $0.913 $ 1.510 39.536% 60.464%
------------------------------------------------------------------------
$8.733 $7.107 $15.840
------------------------------------------------------------------------
------------------------------------------------------------------------



Distribution payments to U.S. resident unitholders are subject to 15
percent Canadian withholding tax, which is deducted from the
distribution amount prior to deposit into accounts.

CAPITAL EXPENDITURES

Net capital expenditures for the year ended December 31, 2004 totalled
$369.71 million (2003 - $191.18 million). The current year includes the
$291.08 million gross acquisition cost of Great Northern and the
comparative year reflects the gross acquisition cost of Hawk Oil Inc.
($49.70 million), Nycan Energy Corp. ($42.44 million), and CanScot
Resources Ltd. ($42.08 million). Overall, the aggregate value of
corporate acquisitions during 2004 exceeded 2003 levels by $156.86
million. The $24.13 million increase in seismic, drilling and
completions, and production facilities over 2003 is attributable to a
larger asset base and development opportunities resulting from the
aforementioned acquisitions completed in 2003 and 2004.

Given the magnitude of corporate acquisitions during 2004, fewer
property acquisitions were completed as compared to 2003, during which
the Trust had acquired incremental production at Countess for $7.03
million and an interest in Swan Hills Unit No. 1 for $15.90 million.
Conversely, the Trust was more active at crown land sales during 2004 in
order to continue to build high-quality drilling prospects so that
production and reserves can be added independent of acquisition activity.

Net capital expenditures for the quarter increased to $39.25 million
from $8.59 million during the same period in 2003 and is explained by
the fact that the three months ended December 31, 2004 was the Trust's
most active quarter for drilling and development since inception, as the
Trust capitalized on the drilling opportunities associated with the
Great Northern acquisition.



Three Months Ended Twelve Months Ended
December 31 December 31
------------------------------------------------------------------------
($000) 2004 2003 2004 2003
------------------------------------------------------------------------
Corporate acquisitions - - 291,084 137,622
Property acquisitions 3,764 3,107 10,351 26,928
Land acquisitions 4,248 487 10,344 2,310
Seismic 2,991 96 4,561 1,070
Drilling and completions 22,291 8,519 41,449 24,287
Production facilities 5,621 3,216 11,222 7,749
Head office 643 116 1,203 494
------------------------------------------------------------------------
Subtotal 39,559 15,541 370,214 200,460
------------------------------------------------------------------------
Dispositions (306) (6,953) (505) (9,284)
------------------------------------------------------------------------
Net capital expenditures 39,253 8,588 369,709 191,176
------------------------------------------------------------------------
------------------------------------------------------------------------


CONTRACTUAL OBLIGATIONS AND CONTINGENCIES

The Trust is involved in certain legal actions that occurred in the
normal course of business. The Trust is required to determine whether a
contingent loss is probable and whether that loss can be reasonably
estimated. When the loss has satisfied both criteria, it is charged to
net income. Management is of the opinion that losses, if any, arising
from such legal actions would not have a material effect on these
financial statements.

The Trust leases its office premises through an arrangement deemed to be
an operating lease for accounting purposes. As such, the Trust is not
required to record its lease obligation as a liability nor does it
record its leased premises as an asset. The estimated operating lease
commitments for the Trust's leased office premises for the next five
years are as follows:



($000)
------------------------------------------------------------------------
2005 1,398
2006 1,213
2007 1,252
2008 1,083
2009 934
Thereafter 934
------------------------------------------------------------------------
------------------------------------------------------------------------


RISK MANAGEMENT

The Trust's objective is to provide unitholders with stable cash
distributions and strong overall returns. APF is committed to full-cycle
internal development opportunities and selectively pursuing acquisitions
identified to be accretive on a per unit basis to cash flow, production,
reserves, and net asset value as a means to achieving its objectives.
The Trust has established a risk management framework in order to
mitigate risks inherent in the oil and gas sector.

Commodity price risk

Commodity price risk is defined as fluctuations in crude oil, natural
gas, and natural gas liquid prices. The Trust uses derivative
instruments as part of its risk management approach to manage commodity
price fluctuations and stabilize cash flows available for unitholder
distributions and future development programs. At December 31, 2004, the
Trust had recorded a $2.30 million unrealized loss on outstanding crude
oil derivative instruments and a $2.06 million unrealized gain on
outstanding natural gas derivative instruments.



Crude oil and natural gas derivative instruments outstanding at the end
of 2004 are as follows:

Average
Type of Daily Average Daily
Period Commodity Contract Quantity Price per bbl/GJ,mmbtu
------------------------------------------------------------------------
January to
March 2005 Crude oil Swap 1,500 bbls U.S.$35.78
January to
March 2005 Crude oil Collar 1,000 bbls U.S.$38.00 to U.S.$44.95
January to U.S.$42.37
March 2005 Crude oil Sold Call 500 bbls (U.S.$3.19 premium)
April to
June 2005 Crude oil Swap 667 bbls U.S.$36.66
April to
June 2005 Crude oil Collar 2,000 bbls U.S.$39.25 to U.S.$44.94
April to U.S.$40.95
June 2005 Crude oil Sold Call 500 bbls (U.S.$3.45 premium)
July to
September
2005 Crude oil Collar 1,000 bbls U.S.$41.00 to U.S.$51.30

January to Natural
March 2005 gas Sold Call 5,000 GJ Cdn.$11.80
January to Natural
March 2005 gas Collar 5,000 GJ Cdn.$7.00 to Cdn.$11.35
April to Natural
October 2005 gas Collar 5,000 mmbtu U.S.$6.50 to U.S.$6.90
April to Natural
October 2005 gas Collar 10,000 GJ Cdn.$6.25 to Cdn.$7.20
------------------------------------------------------------------------
------------------------------------------------------------------------

The following contracts were entered into subsequent to December 31,
2004:

Average
Type of Daily Average Daily
Period Commodity Contract Quantity Price per Unit
------------------------------------------------------------------------
April to
June 2005 Crude oil Collar 1,000 bbls U.S.$43.00 to U.S.$51.65
July to
September
2005 Crude oil Collar 2,500 bbls U.S.$44.00 to U.S.$50.99
October to
December
2005 Crude oil Collar 1,500 bbls U.S.$44.00 to U.S.$51.82
January to
March 2006 Crude oil Collar 2,000 bbls U.S.$44.00 to U.S.$51.28
April to
June 2006 Crude oil Collar 500 bbls U.S.$44.00 to U.S.$50.60
April to
October Natural
2005 gas Collar 10,000 GJ Cdn.$6.00 to Cdn.$7.30
November 2005 Natural
to March 2006 gas Collar 10,000 GJ Cdn.$6.50 to Cdn.$9.90
------------------------------------------------------------------------
------------------------------------------------------------------------


Electricity price risk

Electricity price risk is defined as fluctuations in input power prices
charged to operating costs. The Trust's electricity cost management
activities had an unrealized gain of $0.03 million at year-end. APF had
assumed a fixed price electricity contract through the acquisition of
Great Northern. At December 31, 2004, the Trust had a 2MW (7x24)
contract with a fixed price of $46.40/MWh for calendar 2005; the forward
price in the market for calendar 2005 was $49.00/MWh.

Foreign currency risk

Foreign currency risk is the risk that a variation in the U.S.$/Cdn.$
exchange rate will negatively impact the Trust's operating and financial
results. The Trust's currency risk management activities had an
unrealized gain of $1.10 million at December 31, 2004. The derivative
instruments currently outstanding are as follows:



Type of Amount Exchange Rate
Term Contract (U.S.$000) (U.S.$/Cdn.$)
------------------------------------------------------------------------
January to April 2005 Forward 5,000 1.3550
January to April 2005 Forward 5,000 1.3680
January to December 2005 Collar 5,000 1.2300 to 1.2700
January to December 2005 Collar 10,000 1.2000 to 1.2600
February to December 2005 Collar 10,000 1.2300 to 1.2700
------------------------------------------------------------------------
------------------------------------------------------------------------


The costless collar arrangements have counterparty call options on
December 30, 2005 whereby the Trust's counterparty can extend the
contract term for calendar 2006 at an average rate of 1.2740.

Interest rate risk

Interest rate risk is the risk that variations in interest rates will
negatively impact the Trust's financial results. The Trust had entered
into various derivative instruments to manage its interest rate exposure
on debt instruments. At December 31, 2004 the Trust's interest rate risk
management activities had an unrealized loss of $0.67 million related to
the following fixed rate contracts:



Term Amount ($000) Interest rate
------------------------------------------------------------------------
January 2005 to November 2005 20,000 3.58% plus stamping fee
January 2005 to May 2006 20,000 3.60% plus stamping fee
January 2005 to March 2007 20,000 3.58% plus stamping fee
January 2005 to September 2007 20,000 3.65% plus stamping fee
------------------------------------------------------------------------
------------------------------------------------------------------------


Production risk

Production risk relates to the Trust's ability to produce, process and
transport crude oil and natural gas. To manage this risk to an
acceptable level, the Trust performs regular and proactive maintenance
on its wells, facilities and pipelines. The Trust operates approximately
85 percent of its production, which affords greater control over
operations.

Natural decline and reserve replacement risk

Natural decline risk relates to the Trust's ability to replace reserves
in excess of annual production declines through development activities
such as drilling, well completions, well workovers and other capital
activities. The Trust manages its business using a portfolio approach
whereby capital is allocated across a number of areas so that
significant capital is not risked on any one activity. Capital is spent
only after strict economic criteria for production and reserve additions
are assessed.

The Trust's reserves are evaluated on an annual basis by independent
third-party consultants reporting to the Trust's Audit and Reserves
Committee of the Board of Directors. The Trust's approach is to invest
in mature, long-life properties with a high proved producing component
combined with low-risk development opportunities where the reserve risk
is generally lower and cash flows are more stable and predictable.

Acquisition risk

Acquisition risk arises when the Trust acquires producing properties as
a means to growing its asset base. The Trust is proactive in seeking out
corporate or property transactions that will be accretive on a per unit
basis to cash flow, production, reserves, and net asset value. The
cross-functional acquisition teams identify opportunities for value
enhancement through operational efficiencies or strategic fit, and
evaluate estimates against established acquisition and economic hurdle
rates.

Environmental health and safety risk

Environment, health and safety risks relate primarily to field
operations associated with oil and gas assets. To mitigate this risk, a
preventative environmental, health and safety program is in place as
well as operational loss insurance coverage. APF employees and
contractors adhere to APF's environment, health and safety program,
which is routinely reviewed and updated to ensure the Trust operates in
a manner consistent with best practices in the industry. The Board of
Directors is actively involved in the risk assessment and risk
mitigation process.

Regulation, tax and royalty risk

Regulation, tax and royalty risk relates to changing government royalty
regulations, income tax laws and incentive programs impacting the
Trust's financial and operating results. The tax efficiency of the
royalty trust model is contingent upon its status as a mutual fund trust
under Canadian tax laws and, therefore, may be subject to unanticipated
legislative and/or regulatory modification. Management and oversight
committees, with the assistance of legal counsel, stay informed of
proposed changes in laws and regulations and proactively respond to and
plan for the effects that these changes.

Capital market risk

APF's ability to maintain its financial strength and liquidity is
dependent upon its ability to access Canadian capital markets. If
Canadian debt or equity markets were to become less accessible to the
Trust, it may affect the ability of APF to continue to replace
production and maintain distributions.

SIGNIFICANT ACCOUNTING POLICIES AND ESTIMATES

CONSOLIDATION

These consolidated financial statements include the accounts of the
Trust, Energy, LP and Tika and are referred to collectively as "APF" or
"the Trust". Investments in jointly controlled companies and
unincorporated joint ventures are accounted for using the proportionate
consolidation method, whereby the Trust's proportionate share of
revenues, expenses, assets and liabilities are included in the accounts.

REVENUE RECOGNITION

Revenue associated with the sale of crude oil, natural gas, and natural
gas liquids owned by the Trust are recognized when title passes from the
Trust to its customers.

PROPERTY, PLANT, AND EQUIPMENT

APF uses the full cost method for oil and gas exploration, development
and production activities as set out in CICA Accounting Guideline 16
("AcG-16"), "Oil and Gas Accounting - Full Cost". The cost of acquiring
oil and natural gas properties as well as subsequent development costs
are capitalized and accumulated in a cost center. Maintenance and
repairs are charged against income, and renewals and enhancements, which
extend the economic life of the property, plant and equipment, are
capitalized. Gains and losses are not recognized upon disposition of oil
and natural gas properties unless such a disposition would alter the
rate of depletion by at least 20 percent.

AcG-16 requires that a ceiling test be performed at least annually to
assess the carrying value of oil and gas assets. A cost center is tested
for recoverability using undiscounted future cash flows from proved
reserves and forward indexed commodity prices, adjusted for contractual
obligations and product quality differentials. A cost center is written
down to its fair value when its carrying value, less the cost of
unproved properties, is in excess of the related undiscounted cash
flows. Fair value is estimated using accepted present value techniques
that incorporate risk and uncertainty when determining expected future
cash flows. Unproved properties are excluded from the ceiling test
calculation and subject to a separate impairment test.

DEPRECIATION, DEPLETION, AND ACCRETION

In accordance with the full cost accounting method, all crude oil and
natural gas acquisition, exploration, and development costs, including
asset retirement costs, are accumulated in a cost center. The aggregate
of net capitalized costs and estimated future development costs, less
the cost of unproved properties and estimated salvage value, is
amortized using the unit-of-production method based on current period
production and estimated proved oil and gas reserves calculated using
constant prices.

All other equipment is depreciated over the estimated useful life of the
respective assets.

OIL AND GAS RESERVES

The estimation of reserves is a subjective process. Forecasts are based
on engineering data, projected future rates of production, estimated
commodity prices, and consider the timing of future expenditures. The
Trust expects reserve estimates to be revised based on the results of
future drilling activity, testing, production levels, and economics of
recovery based on cash flow forecasts.

GOODWILL

Goodwill is the residual amount that results when the purchase price of
an acquired business exceeds the fair value of the net identifiable
assets and liabilities of the acquired business. Net identifiable
liabilities acquired include an estimate of future income taxes. In
accordance with CICA Handbook Section 3062 ("HB 3062"), "Goodwill and
Other Intangibles", goodwill for the reporting unit, the consolidated
Trust, is tested at least annually for impairment. Impairment is charged
to income during the period in which it is deemed to have occurred.

The test for impairment is the comparison of the book value of net
assets to the fair value of the Trust. If the fair value of the Trust is
less than its book value, the impairment loss is measured by allocating
the fair value of the Trust to the identifiable assets and liabilities
at their fair values. The excess of the Trust's fair value over the
identifiable net assets is the implied fair value of goodwill. If this
amount is less than the book value of goodwill, the difference is the
impairment amount and would be charged to income during the period.

INCOME TAXES

The Trust is an inter vivos trust for income tax purposes. As such, the
Trust is taxable on income that is not distributed or distributable to
unitholders. As the Trust distributes all of its taxable income to the
unitholders no current provision for income taxes has been recorded.
Should the Trust incur any income taxes, the funds available for
distribution would be reduced accordingly.

The provision for income taxes is recorded in Energy using the liability
method of accounting for income taxes. Future income taxes are recorded
to the extent the accounting bases of assets and liabilities differ from
their corresponding tax values using substantively enacted income tax
rates. Accumulated future income tax balances are adjusted to reflect
changes in income tax rates that are substantively enacted during the
period with the adjustment recognized in net income.

The determination of the Trust's income and other tax liabilities are
subject to audit and potential reassessment after the lapse of
considerable time. Accordingly, actual income tax liabilities or
recoveries may differ significantly from estimates.

COMMITMENTS AND CONTINGENCIES

APF is involved in various legal claims associated with the normal
course of operations. APF is required to determine whether a contingent
loss is probable and whether that loss can be reasonably estimated. When
the loss has satisfied both criteria it is charged to net income.
Management is of the opinion that losses, if any, arising from such
legal actions would not have a material effect on these financial
statements.

CHANGES IN ACCOUNTING POLICIES AND ESTIMATES

ASSET RETIREMENT OBLIGATIONS

Effective January 1, 2004, APF retroactively adopted CICA Handbook
Section 3110, "Asset Retirement Obligations" (ARO). The new standard
requires that the fair value of an asset retirement obligation be
recognized in the period in which it is incurred if a reasonable
estimate of fair value can be made.

The present value of the asset retirement obligation is recognized as a
liability with the corresponding asset retirement cost capitalized as
part of property, plant and equipment. The asset retirement obligation
will increase over time due to accretion and the asset retirement cost
will be depreciated on a basis consistent with depreciation and
depletion. APF previously used the unit-of-production method to match
estimated future retirement costs with the revenues generated over the
life of the petroleum and natural gas properties based on total
estimated proved reserves and an estimated future liability.

The impact of this change has been disclosed in Note 3 to the
consolidated financial statements.

COMPENSATION EXPENSE

Effective December 31, 2003, APF prospectively adopted CICA Handbook
Section 3870, "Stock-based Compensation and Other Stock-based Payments."
The standard requires that equity instruments awarded to employees after
December 31, 2002 be measured at fair value and recognized over the
related period of service ("vesting period") with a corresponding
increase to contributed surplus. When rights are exercised by employees
and directors of the Trust, the consideration paid is recorded to the
unitholders' investment account along with related non-cash compensation
expense previously recognized in contributed surplus.

APF has established a Trust Units Options Plan (the "Plan") and a Trust
Unit Incentive Rights Plan (the "Rights Plan") for employees and
independent directors that are described in Note 13 to the financial
statements. The exercise price of the rights granted under the Rights
Plan may be reduced in future periods based on future operating
performance in accordance with the terms of the Rights Plan. The Trust
uses a Black-Scholes option-pricing model to estimate the fair value of
rights awarded under the Rights Plan as at the grant date. The fair
value ascribed to awarded rights is not subsequently revised for any
change in underlying assumptions. Compensation expense is adjusted
prospectively for rights cancelled under the Rights Plan during the
period.

Details of both the Options Plan and Rights Plan are disclosed in Note
13 and the impact of this change has been disclosed in Note 3 to the
consolidated financial statements.

DERIVATIVE INSTRUMENTS AND HEDGING RELATIONSHIPS

Effective January 1, 2004, APF prospectively adopted CICA Accounting
Guideline 13 ("AcG-13"), "Hedging Relationships" and the amended
Emerging Issues Committee 126 ("EIC-126"), "Accounting for Trading,
Speculative or Non Trading Derivative Financial Instruments". In
accordance with the new guideline, all unrealized derivative instruments
that either do not qualify as a hedge under AcG-13, or are not
designated as a hedge, are recorded as a derivative asset or a
derivative liability on the consolidated balance sheet with any changes
in fair value during the period recognized in income. Prior to January
1, 2004, the Trust recognized gains and losses on derivative contracts
at the time of settlement.

In order to apply hedge accounting, an entity must formally document the
hedging arrangement and sufficiently demonstrate the effectiveness of
the hedging relationship. Based on a review of the Trust's derivative
position at January 1, 2004, the majority of derivative contracts did
not qualify for hedge accounting.

APF's mark-to-market position on derivative contracts is disclosed in
Note 7 and the transitional impact of this change has been disclosed in
Note 3 to the consolidated financial statements.

FINANCIAL INSTRUMENTS WITH A CONVERSION FEATURE

Effective December 31, 2004, APF retroactively adopted the revised CICA
Handbook Section 3860 ("HB 3860"), "Financial Instruments - Presentation
and Disclosure" for financial instruments that may be settled at the
issuer's option in cash or its own equity instruments. The revised
standard requires APF to classify the convertible debenture proceeds as
either debt or equity based on fair value measurement and the substance
of the contractual arrangement. The Trust previously presented the
convertible debenture proceeds (net of financing costs) and related
interest obligations as equity on the consolidated balance sheet on the
basis that the Trust could settle its obligations in exchange for trust
units.

The Trust's obligation to make scheduled payments of principal and
interest constitutes a financial liability under the revised standard
and exists until the instrument is either converted or redeemed. The
holders' option to convert the financial liability into trust units is
an embedded conversion option. The conversion option is presented as
equity because it is the initial value ascribed to the holders' right to
convert a financial liability into trust units at the date of issuance.
The sum of the liability and equity components is equal to the $50.0
million proceeds received from the convertible debenture issuance.
Details of the convertible debentures are disclosed in Note 10 and the
impact of this change on prior periods presented has been disclosed in
Note 3 to the consolidated financial statements.

OUTLOOK

STRATEGY

APF emphasizes a full-cycle approach to its business and plans to
continue with internal development opportunities as a means to enhancing
its production base and ultimately creating value for unitholders.
Consistent with its full-cycle approach, APF actively added to its
undeveloped land position through crown land sales during 2004 in order
to establish high-quality drilling prospects. The objective is to
position APF so that production and reserves can be added independent of
acquisition activity. In that regard, the Trust's ability to add
production through the drill bit creates a competitive advantage over
those competitors that have depleted their development inventories and
are reliant upon acquisitions to build or maintain their production base.

APF will continue to pursue acquisitions that will be accretive on a per
unit basis to cash flow, production, reserves and net asset value. APF
is committed to maintaining stable cash distributions over the
long-term. In order to mitigate the commodity price risk that is
inherent to the oil and gas sector, APF will continue to actively hedge
commodity prices. APF believes that over the long term, outlook for both
crude oil and natural gas pricing remains strong.

2005 CAPITAL INVESTMENT AND DEVELOPMENT ACTIVITIES

Based on current estimates and assumptions, APF plans to focus its 2005
capital program in the following manner:



Drilling &
Business Unit ($000) Development Land & Seismic Total
------------------------------------------------------------------------
Southeast Saskatchewan 8,554 1,300 9,854
Southern 7,952 2,000 9,952
Central 11,394 1,035 12,429
Western 5,781 3,300 9,081
CBM - Alberta 15,289 375 15,664
CBM - Wyoming 4,483 - 4,483
------------------------------------------------------------------------
Total 53,453 8,010 61,463
------------------------------------------------------------------------
------------------------------------------------------------------------


In addition, the Trust anticipates spending $2.80 million on
environmental health and safety initiatives throughout the year.

The Trust expects its 2005 core capital investment program to be funded
from its DRIP, cash flow and proceeds from the divestiture of non-core
assets.

Recent land acquisitions within the Western Business Unit ("Western")
complement ongoing and planned internal development activities at APF's
Paddle River properties. Coalbed methane opportunities exist in the
Upper Mannville formation and APF is currently in the de-watering
process at Corbett Creek.

The Central Business Unit ("Central") contains a large inventory of
conventional and unconventional drilling opportunities. APF will
continue to exploit new opportunities and undeveloped acres while
continuing to focus internal development capital on the core Innisfail
asset. CBM activity in the Horseshoe Canyon coals is expected to
increase as APF continues to build its unconventional asset base.

A significant percentage of the upcoming year's capital budget will be
targeted at Queensdale and Handsworth located within the Southeast
Saskatchewan Business Unit ("Southeast Saskatchewan"). This area has
historically generated excellent operating results and full cycle
investment returns and is capable of generating excellent economics
despite high natural decline rates.

APF is most active in its Southern Business Unit ("Southern"). The
historical focus has been low productivity, long life shallow gas in the
Milk River and Medicine Hat formations. Future development will move
beyond shallow gas drilling to include deeper prospects at Countess,
Turin and Carmangay.

2005 PRODUCTION VOLUMES

The production outlook for 2005 will be principally impacted by weather,
timing of new production and drilling activity. APF expects to average
18,000 to 18,500 boe/d of production based on its capital budget of
$61.46 million for fiscal 2005. Assumptions include drilling costs,
well performance, operating costs, projected sales volumes, interest
rates, foreign currency exchange rates and other factors that impact
operations. These inputs can change significantly as a result of actual
events and may result in material variances from the Trust's estimates.



The following tables provide projected estimates for 2005 of the
sensitivity of the Trust's 2005 cash flow to changes in a number of
variables:

Impact on Impact on
annual cash cash flow
Variable Assumption Change flow ($000) per unit
------------------------------------------------------------------------
Crude oil price
($U.S./bbl) $ 42.00 $ 1.00 $ 3,010 $ 0.05
Natural gas price
($Cdn./mcf) $ 6.60 $ 0.10 $ 1,730 $ 0.03
U.S.$/Cdn.$
exchange rate $ 0.82 $ 0.01 $ 1,540 $ 0.02
Interest rate 5.0% 1.0% $ 2,010 $ 0.03
Crude oil production
(bbl/d) 8,500 100 bbl/d $ 890 $ 0.01
Natural gas
production (mcf/d) 58,000 1,000 mcf/d $ 1,360 $ 0.02
------------------------------------------------------------------------
------------------------------------------------------------------------


CONSOLIDATED BALANCE SHEET
($000s except for per unit amounts)

As at December 31 (unaudited) 2004 2003
------------------------------------------------------------------------
Restated
(note 3)
ASSETS
Current assets
Cash 567 1,381
Accounts receivable 42,200 27,542
Derivative asset (note 7) 3,313 -
Other current assets 7,162 5,549
------------------------------------------------------------------------
53,242 34,472
Asset retirement fund 3,271 2,342
Goodwill (note 5) 118,478 48,230
Property, plant and equipment (note 6) 687,179 413,706
------------------------------------------------------------------------
862,170 498,750
------------------------------------------------------------------------
------------------------------------------------------------------------

LIABILITIES
Current liabilities
Accounts payable and accrued liabilities 52,677 36,698
Derivative liability (note 7) 3,141 -
Distribution payable (note 4) 9,415 5,963
------------------------------------------------------------------------
65,233 42,661
Future income taxes (note 9) 86,711 63,991
Long-term debt (note 8) 169,000 98,000
Convertible debentures (note 10) 47,697 47,719
Asset retirement obligations (note 11) 30,993 21,803
Derivative liability (note 7) 335 -
------------------------------------------------------------------------
399,969 274,174
------------------------------------------------------------------------

UNITHOLDERS' EQUITY
Unitholders' investment account (note 12) 610,194 324,318
Contributed surplus (note 13) 289 1,241
Accumulated earnings 126,862 77,226
Accumulated distributions (note 4) (276,293) (179,363)
Convertible debenture conversion feature
(note 10) 1,149 1,154
------------------------------------------------------------------------
462,201 224,576
------------------------------------------------------------------------
862,170 498,750
------------------------------------------------------------------------
------------------------------------------------------------------------


Contractual obligations and commitments (note 16)
See accompanying notes to consolidated financial statements

Approved by the Board of Directors




------------------------- ------------------------

Martin Hislop Donald Engle
Director Director



CONSOLIDATED STATEMENT OF OPERATIONS AND ACCUMULATED EARNINGS

($000s except for per unit amounts)

For the year ended December 31 (unaudited) 2004 2003
------------------------------------------------------------------------
Restated
(note 3)
REVENUE
Oil and gas 253,213 173,196
Realized derivative loss - net (note 7) (16,329) (3,565)
Unrealized derivative gain - net (note 7) 223 -
Royalties expense, net of ARTC (47,710) (32,473)
Transportation (5,245) (4,174)
------------------------------------------------------------------------
184,152 132,984
------------------------------------------------------------------------

EXPENSES
Operating 51,788 32,370
General and administrative 10,635 10,023
Interest on long-term debt (note 8) 5,405 4,171
Convertible debenture interest and
financing charges (note 10) 5,263 2,669
Depletion, depreciation and accretion 85,997 53,389
Unit-based compensation expense (recovery)
(note 13) (877) 1,241
Capital and other taxes 3,321 2,720
------------------------------------------------------------------------
161,532 106,583
------------------------------------------------------------------------

Income before future income taxes 22,620 26,401
Recovery of future income taxes (note 9) (27,016) (14,207)
------------------------------------------------------------------------
Net income 49,636 40,608
Accumulated earnings - beginning of period,
as previously reported 77,226 35,589
Change in accounting policy (note 3) - 1,029
------------------------------------------------------------------------
Accumulated earnings - end of period,
as restated 126,862 77,226
------------------------------------------------------------------------
------------------------------------------------------------------------

Net income per unit - basic $ 1.02 $ 1.31

Net income per unit - diluted (1) $ 1.02 $ 1.29

(1) Convertible debenture interest has been added back to net income to
calculate net income per unit - diluted.

See accompanying notes to consolidated financial statements


CONSOLIDATED STATEMENT OF CASH FLOWS
($000s except for per unit amounts)

For the year ended December 31 (unaudited) 2004 2003
------------------------------------------------------------------------
Restated
(note 3)
Cash flows from operating activities
Net income 49,636 40,608
Items not affecting cash
Depletion, depreciation and accretion 85,997 53,389
Debenture accretion and amortization of
deferred financing charges 692 362
Future income taxes (27,016) (14,207)
Unrealized derivative gain - net (note 7) (223) -
Unit-based compensation expense (recovery)
(note 13) (877) 1,241
Asset retirement expenditures (note 11) (1,083) (374)
------------------------------------------------------------------------
Cash flow from operations 107,126 81,019
Net change in non-cash working capital items
(note 15) (10,473) 5,823
Asset retirement fund contribution - net (929) (1,558)
------------------------------------------------------------------------
Net cash provided by operating activities 95,724 85,284
------------------------------------------------------------------------

Cash flows from investing activities
Corporate acquisitions (note 5) (65,405) (58,259)
Additions to property, plant and equipment (68,779) (33,601)
Purchase of oil and natural gas properties (10,351) (29,238)
Proceeds on sale of properties 505 9,284
Changes in non-cash working capital
- investing items 5,205 2,961
------------------------------------------------------------------------
Net cash used in investing activities (138,825) (108,853)
------------------------------------------------------------------------

Cash flows from financing activities
Issue of units for cash 90,451 55,670
Issue of units for cash under DRIP 33,895 1,329

Issue of units for cash upon exercise of
stock options/rights 3,799 1,749
Net proceeds (repayment) of convertible
debentures - 47,681
Unit issue costs (5,270) (3,467)
Net proceeds (repayment) of long-term debt 7,126 (12,920)
Cash distributions, net of distribution
reinvestment (91,166) (68,440)
Changes in non-cash working capital
- financing items 3,452 2,398
------------------------------------------------------------------------
Net cash provided by financing activities 42,287 24,000
------------------------------------------------------------------------

Change in cash during the period (814) 431
Cash - Beginning of period 1,381 950
------------------------------------------------------------------------
Cash - End of period 567 1,381
------------------------------------------------------------------------
------------------------------------------------------------------------

Supplemental information (note 14)

See accompanying notes to consolidated financial statements


NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

December 31, 2004 and 2003 (unaudited)

1. BASIS OF PRESENTATION

APF Energy Trust (the "Trust")

The Trust is an open-end investment trust under the laws of the Province
of Alberta.

APF Energy Inc. ("Energy")

Energy was incorporated and organized for the purpose of acquiring,
developing, exploiting and disposing of oil and natural gas properties,
including certain initial properties and granting a royalty thereon to
the Trust.

APF Energy Limited Partnership ("LP")

LP was formed for the purpose of acquiring, developing, exploiting and
disposing of oil and natural gas properties and granting a royalty
thereon to the Trust.

Tika Energy Inc. ("Tika")

Tika is a wholly owned subsidiary of Energy and was incorporated in
Wyoming for the purpose of acquiring, developing, exploiting and
disposing of coalbed methane gas properties in the United States.

2. SIGNIFICANT ACCOUNTING POLICIES

Consolidation

These consolidated financial statements include the accounts of the
Trust, Energy, LP and Tika and are referred to collectively as "APF" or
"the Trust". Investments in jointly controlled companies and
unincorporated joint ventures are accounted for using the proportionate
consolidation method, whereby the Trust's proportionate share of
revenues, expenses, assets and liabilities are included in the accounts.

Revenue recognition

Revenue associated with the sale of crude oil, natural gas, and natural
gas liquids owned by the Trust are recognized when title passes from the
Trust to its customers.

Property, plant and equipment

APF uses the full cost accounting method for oil and gas exploration,
development and production activities as set out in CICA Accounting
Guideline 16 ("AcG-16"), "Oil and Gas Accounting - Full Cost". The cost
of acquiring oil and natural gas properties as well as subsequent
development costs are capitalized and accumulated in a cost center.
Maintenance and repairs are charged against income, and renewals and
enhancements, which extend the economic life of the property, plant and
equipment, are capitalized. Gains and losses are not recognized upon
disposition of oil and natural gas properties unless such a disposition
would alter the rate of depletion by at least 20 percent.

All other equipment is carried at the lesser of depreciated cost and
fair value.

Ceiling test

AcG-16 requires that a ceiling test be performed at least annually to
assess the carrying value of oil and gas assets. A cost centre is tested
for recoverability using undiscounted future cash flows from proved
reserves and forward indexed commodity prices, adjusted for contractual
obligations and product quality differentials. A cost centre is written
down to its fair value when its carrying value, less the cost of
unproved properties, is in excess of the related undiscounted cash
flows. Fair value is estimated using accepted present value techniques
that incorporate risk and uncertainty when determining expected future
cash flows. Unproved properties are excluded from the ceiling test
calculation and subject to a separate impairment test.

Depletion, depreciation and accretion

In accordance with the full cost accounting method, all crude oil and
natural gas acquisition, exploration, and development costs, including
asset retirement costs, are accumulated in a cost center. The aggregate
of net capitalized costs and estimated future development costs, less
the cost of unproved properties and estimated salvage value, is
amortized using the unit-of-production method based on current period
production and estimated proved oil and gas reserves calculated using
constant prices.

All other equipment is depreciated over the estimated useful life of the
respective assets.

Oil and gas reserves

The estimation of reserves is a subjective process. Forecasts are based
on engineering data, projected future rates of production, estimated
commodity prices, and consider the timing of future expenditures. The
Trust expects reserve estimates to be revised based on the results of
future drilling activity, testing, production levels, and economics of
recovery based on cash flow forecasts.

Goodwill

Goodwill is the residual amount that results when the purchase price of
an acquired business exceeds the fair value of the net identifiable
assets and liabilities of the acquired business. Net identifiable
liabilities acquired include an estimate of future income taxes. In
accordance with CICA Handbook Section 3062 ("HB 3062"), "Goodwill and
Other Intangibles", goodwill for the reporting unit, the consolidated
Trust, is tested at least annually for impairment. Impairment is charged
to income during the period in which it is deemed to have occurred.

The test for impairment is the comparison of the book value of net
assets to the fair value of the Trust. If the fair value of the Trust is
less than its book value, the impairment loss is measured by allocating
the fair value of the Trust to the identifiable assets and liabilities
at their fair values. The excess of the Trust's fair value over the
identifiable net assets is the implied fair value of goodwill. If this
amount is less than the book value of goodwill, the difference is the
impairment amount and would be charged to income during the period.

Unit-based compensation expense

Effective December 31, 2003, the Trust prospectively adopted CICA
Handbook Section 3870, "Stock-based Compensation and Other Stock-based
Payments." The standard requires that equity instruments awarded to
employees after December 31, 2002 be measured at fair value and
recognized over the related vesting period with a corresponding increase
to contributed surplus. When rights are exercised by employees and
directors of the Trust, the consideration paid is recorded to the
unitholders' investment account along with related non-cash compensation
expense previously recognized in contributed surplus.

APF has established a Trust Units Options Plan (the "Plan") and a Trust
Unit Incentive Rights Plan (the "Rights Plan") for employees and
independent directors that are described in Note 13. The exercise price
of the rights granted under the Rights Plan may be reduced in future
periods based on future operating performance in accordance with the
terms of the Rights Plan. The Trust uses a Black-Scholes option-pricing
model to estimate the fair value of rights awarded under the Rights Plan
at the grant date. The fair value ascribed to awarded rights is not
subsequently revised for any change in underlying assumptions.
Unit-based compensation expense is adjusted prospectively for rights
cancelled under the Rights Plan during the period.

The new accounting standard resulted in the Trust recognizing an expense
of $1.24 million for the year ended December 31, 2003 with a
corresponding increase to contributed surplus. In conformity with the
amended accounting standard, the Trust has elected to disclose pro forma
results for equity instruments awarded to employees prior to January 1,
2003 as if CICA Handbook Section 3870, "Stock-based Compensation and
Other Stock-based Payments" had been adopted retroactively.

There was no impact on the Trust's cash flow as a result of adopting the
new standard. See Note 13 for additional information on compensation
plans.

Income taxes

The Trust is an inter vivos trust for income tax purposes. As such, the
Trust is taxable on income that is not distributed or distributable to
unitholders. As the Trust distributes all of its taxable income to the
unitholders no current provision for income taxes has been recorded.
Should the Trust incur any income taxes, the funds available for
distribution would be reduced accordingly.

The provision for income taxes is recorded in Energy using the liability
method of accounting for income taxes. Future income taxes are recorded
to the extent the accounting bases of assets and liabilities differ from
their corresponding tax values using substantively enacted income tax
rates. Accumulated future income tax balances are adjusted to reflect
changes in income tax rates that are substantively enacted during the
period with the adjustment recognized in net income.

The determination of the Trust's income and other tax liabilities are
subject to audit and potential reassessment after the lapse of
considerable time. Accordingly, actual income tax liabilities or
recoveries may differ significantly from estimates.

Trust unit calculations

The Trust applies the treasury stock method to determine the dilutive
effect of trust unit rights and trust unit options. Under the treasury
stock method, outstanding and exercisable instruments that will have a
dilutive effect are included in per unit - diluted calculations, ordered
from most dilutive to least dilutive.

The dilutive effect of convertible debentures is determined using the
"if-converted" method whereby if the current market price per unit is in
excess of the stated conversion price per unit the weighted-average
number of potential units assumed issued are included in the per unit -
diluted calculations. The units issued upon conversion are included in
the denominator of per unit - basic calculations from the date of
conversion. Consequently, units assumed issued are weighted for the
period the convertible debentures were outstanding, and units actually
issued are weighted for the period the units were outstanding.

Measurement uncertainty

The timely preparation of financial statements in conformity with
Canadian generally accepted accounting principles ("GAAP") requires that
management make estimates and assumptions and use judgment regarding
assets, liabilities, revenues, and expenses. Such estimates primarily
relate to unsettled transactions and events as of the date of the
financial statements. Accordingly, actual results may differ from
estimated amounts as future confirming events occur.

Amounts recorded for depreciation, depletion, and amortization, asset
retirement costs and obligations, and amounts used for ceiling test and
impairment calculations are based on estimates of oil and natural gas
reserves and future costs required to develop those reserves. By their
nature, these estimates are subject to measurement uncertainty, and the
impact on the financial statements of future periods could be material.

3. CHANGES IN ACCOUNTING POLICIES

Asset retirement obligations

Effective January 1, 2004, the Trust retroactively adopted CICA Handbook
Section 3110, "Asset Retirement Obligations" (ARO). The standard
requires that the fair value of an asset retirement obligation be
recognized in the period in which it is incurred. The present value of
the asset retirement obligation is recognized as a liability with the
corresponding asset retirement cost capitalized as part of property,
plant and equipment. The asset retirement obligation will increase over
time due to accretion and the asset retirement cost will be depreciated
on a basis consistent with depreciation and depletion. APF previously
used the unit-of-production method to match estimated future retirement
costs with the revenues generated over the life of the petroleum and
natural gas properties based on total estimated proved reserves and an
estimated future liability.



The following table summarizes the impact of the new standard on the
2003 comparative period:

As at and for the year ended December 31, 2003
($000s except for ------------------------------------------------
per unit amounts) As reported Change As restated
------------------------------------------------------------------------
Consolidated Balance Sheet
Assets
Property, plant, and equipment 401,286 12,420 413,706
Liabilities
Future income taxes 64,222 (231) 63,991
Asset retirement obligation - 21,803 21,803
Site restoration liability 10,410 (10,410) -
Unitholders' Equity
Opening accumulated earnings 35,589 1,029 36,618
Consolidated Statement of Operations
Depletion, depreciation, and
accretion 50,417 2,972 53,389
Site restoration 3,327 (3,327) -
Recovery of future income taxes (14,333) 126 (14,207)
------------------------------------------------------------------------
------------------------------------------------------------------------

See Note 11 for additional information on asset retirement obligations.


Derivative instruments and hedging relationships

Effective January 1, 2004, the Trust prospectively adopted CICA
Accounting Guideline 13 ("AcG-13"), "Hedging Relationships" and the
amended Emerging Issues Committee Abstract 128, "Accounting for Trading,
Speculative or Non Trading Derivative Financial Instruments". In
accordance with these standards, all unrealized derivative instruments
that either do not qualify as a hedge under AcG-13, or are not
designated as a hedge, are recorded as a derivative asset or a
derivative liability on the consolidated balance sheet with any changes
in fair value during the period recognized in income. Prior to January
1, 2004, the Trust recognized gains and losses on derivative contracts
at the time of settlement.

In order to apply hedge accounting, an entity must formally document the
hedging arrangement and sufficiently demonstrate the effectiveness of
the hedging relationship. Based on a review of the Trust's derivative
position at January 1, 2004, the majority of derivative contracts did
not qualify for hedge accounting. Consequently, the Trust recorded $1.30
million liability as an estimate for the fair value of its derivative
position on January 1, 2004, which was comprised of a $0.40 million
unrealized loss on crude oil and natural gas derivative instruments and
a $0.90 million unrealized loss on interest rate swaps. In accordance
with the transitional provisions of the new guideline, the Trust
recorded a corresponding deferred derivative loss, which was amortized
into income during 2004 upon settlement of the underlying derivative
instruments. There was no impact on the Trust's cash flow as a result of
adopting this new guideline. See Note 7 for additional disclosure on
derivative instruments.

Financial instruments with a conversion feature

Effective December 31, 2004, the Trust retroactively adopted the revised
CICA Handbook Section 3860 ("HB 3860"), "Financial Instruments -
Presentation and Disclosure" for financial instruments that may be
settled at the issuer's option in cash or its own equity. The revised
standard requires the Trust to classify proceeds from convertible
debentures issued on July 3, 2003 as either debt or equity based on fair
value measurement and the substance of the contractual arrangement. The
Trust previously presented the convertible debenture proceeds (net of
financing costs) and related interest obligations as equity on the
consolidated balance sheet on the basis that the Trust could settle its
obligations in exchange for trust units.

The Trust's obligation to make scheduled payments of principal and
interest constitutes a financial liability under the revised standard
and exists until the instrument is either converted or redeemed. The
holders' option to convert the financial liability into trust units is
an embedded conversion option. Gross proceeds of $50 million received at
issuance were allocated $48.82 million to debt and $1.18 million to the
equity conversion feature. At December 31, 2003, after conversions and
accretion, the debt component was $47.72 million and the equity
component was $1.15 million. Underwriter costs and professional fees
associated with the issuance totalled $2.32 million and will be
amortized into income on a straight-line basis over the term of the
instrument. At December 31, 2003, $2.04 million was included in other
current assets.



The following table summarizes the impact of the revised standard on the
2003 comparative period:

As at and for the year ended December 31, 2003
($000s except for ------------------------------------------------
per unit amounts) As reported Change As restated
------------------------------------------------------------------------
Consolidated Balance Sheet
Assets
Other current assets
(includes deferred financing) 3,506 2,043 5,549
------------------------------------------------------------------------
3,506 2,043 5,549
------------------------------------------------------------------------
Liabilities
Accounts payable and accrued
liabilities 36,711 (13) 36,698
Convertible debentures - 47,719 47,719
------------------------------------------------------------------------
36,711 47,706 84,417
------------------------------------------------------------------------
Unitholders' Equity
Unitholders investment account 324,317 1 324,318
Convertible debentures 46,466 (46,466) -
Accumulated interest on
convertible debentures (2,317) 2,317 -
Convertible debenture conversion
feature - 1,154 1,154
------------------------------------------------------------------------
368,466 (42,994) 325,472
------------------------------------------------------------------------
Consolidated Statement of Operations
Convertible debenture interest
and financing charges - 2,669 2,669
------------------------------------------------------------------------
------------------------------------------------------------------------

There was no impact on the Trust's cash flow as a result of adopting
the revised standard. See Note 10 for additional information on
convertible debentures.


4. DISTRIBUTIONS

For the year ended December 31
($000s except for per unit amounts) 2004 2003
------------------------------------------------------------------------
Restated
(note 3)

Cash flow from operations 107,126 81,019
Add (deduct):
Abandonment fund contributions (2,012) (1,932)
Cash retained to fund operations (6,368) (21,556)
Working capital change (1,816) 11,182
------------------------------------------------------------------------
Distributions 96,930 68,713
------------------------------------------------------------------------
Distributed to date 87,515 62,750
Distribution payable 9,415 5,963
------------------------------------------------------------------------
96,930 68,713
Opening accumulated distributions 179,363 110,650
------------------------------------------------------------------------
Closing accumulated distributions 276,293 179,363
------------------------------------------------------------------------
------------------------------------------------------------------------

Actual distribution declared per unit $ 2.00 $ 2.20
------------------------------------------------------------------------
------------------------------------------------------------------------


5. ACQUISITIONS

On June 4, 2004, the Trust acquired the issued and outstanding shares of
Great Northern Exploration Ltd. ("Great Northern"). During 2003, APF
acquired the issued and outstanding shares of Hawk Oil Inc. ("Hawk Oil")
on February 5, Nycan Energy Corp. ("Nycan") on April 28, and CanScot
Resources Ltd. ("CanScot") on September 26.



The purchase price allocation for each acquisition and components of
consideration paid is as follows:

Great Northern CanScot Nycan Hawk Oil
($000) 2004 2003 2003 2003
------------------------------------------------------------------------
Net assets acquired at
assigned values:
------------------------------------------------------------------------
Working capital deficiency (4,857) 178 928 (634)
Property, plant and equipment 255,941 32,980 47,495 57,146
Undeveloped land and seismic 22,943 - - -
Goodwill 70,248 16,884 8,792 11,078
Debt assumed (63,874) (6,150) (8,870) (7,900)
Financial derivatives (1,103) - - -
Asset retirement obligation (7,866) (388) (580) (263)
Future income taxes (49,084) (7,399) (13,266) (18,266)
------------------------------------------------------------------------
Net assets acquired 222,348 36,105 34,499 41,161
------------------------------------------------------------------------
------------------------------------------------------------------------

Purchase price comprised of:
------------------------------------------------------------------------
Trust units 156,943 15,433 - 37,710
Cash 63,250 - - 2,856
Bank debt - 19,689 34,374 -
Acquisition costs 2,155 983 125 595
------------------------------------------------------------------------
Purchase price 222,348 36,105 34,499 41,161
------------------------------------------------------------------------
------------------------------------------------------------------------


The following table highlights investing cash flows associated with
corporate acquisitions completed in 2004 and 2003:

Great Northern CanScot Nycan Hawk Oil
($000) 2004 2003 2003 2003
------------------------------------------------------------------------
Net assets acquired 222,348 36,105 34,499 41,161
Deduct:
Debt assumed (cash acquired) - (156) (212) 5
Trust units issued (156,943) (15,433) - (37,710)
------------------------------------------------------------------------
Net cash flows from
corporate acquisitions 65,405 20,516 34,287 3,456
------------------------------------------------------------------------
------------------------------------------------------------------------

6. PROPERTY, PLANT AND EQUIPMENT

($000) 2004 2003
------------------------------------------------------------------------
Property, plant, and equipment 907,819 548,229
Accumulated depletion, depreciation,
and accretion (220,640) (134,523)
------------------------------------------------------------------------
687,179 413,706
------------------------------------------------------------------------
------------------------------------------------------------------------


Future development costs of $48.22 million (2003 - $25.00 million)
related to total proved reserves were included as depletable costs in
the calculation of depletion, depreciation and accretion. Costs related
to unproved properties totalled $28.45 million (2003 - $10.80 million)
and were excluded from depletable costs. All costs of unproved
properties, net of any associated revenues, have been capitalized.
Ultimate recoverability of these costs will be dependent upon the
finding of proved oil and natural gas reserves. The Trust performed a
separate impairment review of assets excluded from the ceiling test and
determined that $nil (2003 - $nil) should be charged to income during
the year.

Included in property, plant, and equipment are asset retirement costs of
$26.54 million (2003 - $18.86 million). The Trust capitalized $0.50
million (2003 - $0.46 million) of administrative costs during the year
associated with coalbed methane projects considered to be in the
pre-production stage.

The prices used in the ceiling test evaluation of the Trust's natural
gas, crude oil, and natural gas liquids reserves at December 31, 2004
were as follows:



WTI Oil Exchange WTI Oil AECO Gas
Year ($U.S./bbl) ($U.S./$Cdn.) ($Cdn./bbl) ($Cdn./mmbtu)
------------------------------------------------------------------------
2005 42.76 1.1667 48.95 6.43
2006 40.56 1.1931 47.37 6.56
2007 39.44 1.2202 47.26 6.28
2008 37.77 1.2561 46.74 6.04
2009 37.14 1.2961 47.31 5.83
2010 - 2016(1) 37.41 1.2961 47.56 5.87
Remainder (2) 2.00% 1.2961 2.00% 2.00%
------------------------------------------------------------------------
(1) Represents the average for the period noted
(2) Percentage change represents the annual change each year from 2014
to the end of the reserve life


7. RISK MANAGEMENT AND FINANCIAL INSTRUMENTS

The Trust has entered into various derivative instruments and physical
contracts to manage fluctuations in commodity prices, foreign currency
exchange rates, utility prices, and interest rates in the normal course
of operations. A derivative instrument meets the definition of a
financial instrument because it involves the exchange of financial
assets, usually cash, and not the delivery or acceptance of oil and gas
inventory. Conversely, a physical contract is not a financial instrument
because it involves the delivery or acceptance of physical product. In
conformity with AcG-13 and EIC 128 (see note 3), the following
information only presents positions related to financial instruments.

The estimated fair value of unrealized derivative instruments is
reported on the consolidated balance sheet with any change in the
unrealized positions recorded to income.



The following is a summary of the change in unrealized amounts from
January 1, 2004 to December 31, 2004:

Deferred
derivative loss Total
recognized on realized Total
($000) transition gain/(loss) gain/(loss)
------------------------------------------------------------------------
Fair value of contracts,
January 1, 2004 1,300 (1,300)
Fair value of derivative
contracts entered into
during the period (14,806)
Fair value of derivative
contracts realized during
the period (16,329) 16,329
------------------------------------------------------------------------
Fair value of contracts,
December 31, 2004 223
------------------------------------------------------------------------
Premiums received on sold call options (386)
------------------------------------------------------------------------
FV of contracts and premiums received, December 31, 2004 (163)
------------------------------------------------------------------------
------------------------------------------------------------------------

The following is a summary of unrealized fair value financial positions
by risk management activity at December 31, 2004:

Total
unrealized
($000) gain/(loss)
------------------------------------------------------------------------
Commodity price
Crude oil (2,298)
Natural gas 2,059
Utilities 32
Foreign currency 1,103
Interest rate (673)
------------------------------------------------------------------------
223
Premiums received on sold call options (386)
------------------------------------------------------------------------
(163)
------------------------------------------------------------------------
------------------------------------------------------------------------


The following highlights the balance sheet classification of unrealized
fair value financial positions at December 31, 2004:

Unrealized
asset
($000) (liability)
------------------------------------------------------------------------
Current asset 3,313
Long-term asset -

Current liability (3,141)
Long-term liability (335)
------------------------------------------------------------------------
(163)
------------------------------------------------------------------------
------------------------------------------------------------------------


Commodity price risk

Commodity price risk is defined as fluctuations in crude oil, natural
gas, and natural gas liquid prices. The Trust uses derivative
instruments as part of its risk management approach to manage commodity
price fluctuations and stabilize cash flows available for unitholder
distributions and future development programs. At December 31, 2004, the
Trust had recorded a $2.30 million unrealized loss on outstanding crude
oil derivative instruments and a $2.06 million unrealized gain on
outstanding natural gas derivative instruments.



Crude oil and natural gas derivative instruments outstanding at the end
of 2004 are as follows:

Average
Type of Daily Average Daily
Period Commodity Contract Quantity Price per bbl/GJ,mmbtu
------------------------------------------------------------------------
January to
March 2005 Crude oil Swap 1,500 bbls U.S.$35.78
January to
March 2005 Crude oil Collar 1,000 bbls U.S.$38.00 to U.S.$44.95
January to U.S.$42.37
March 2005 Crude oil Sold Call 500 bbls (U.S.$3.19 premium)
April to
June 2005 Crude oil Swap 667 bbls U.S.$36.66
April to
June 2005 Crude oil Collar 2,000 bbls U.S.$39.25 to U.S.$44.94
April to U.S.$40.95
June 2005 Crude oil Sold Call 500 bbls (U.S.$3.45 premium)
July to
September
2005 Crude oil Collar 1,000 bbls U.S.$41.00 to U.S.$51.30

January to Natural
March 2005 gas Sold Call 5,000 GJ Cdn.$11.80
January to Natural
March 2005 gas Collar 5,000 GJ Cdn.$7.00 to Cdn.$11.35
April to Natural
October 2005 gas Collar 5,000 mmbtu U.S.$6.50 to U.S.$6.90
April to Natural
October 2005 gas Collar 10,000 GJ Cdn.$6.25 to Cdn.$7.20
------------------------------------------------------------------------
------------------------------------------------------------------------


Electricity price risk

The Trust's electricity cost management activities had an unrealized
gain of $0.03 million at year end. APF had assumed a fixed price
electricity contract through the acquisition of Great Northern. At
December 31, 2004, the Trust had a 2MW (7x24) contract with a fixed
price of $46.40/MWh for calendar 2005.

Foreign currency risk

The Trust's foreign currency risk management activities had an
unrealized gain of $1.10 million at year end. Foreign currency risk is
the risk that a variation in the U.S./Cdn. exchange rate will negatively
impact the Trust's operating and financial results. At December 31,
2004, the Trust had entered into contracts to sell U.S. dollars at a
fixed rate in exchange for Canadian dollars as follows:



Type of Amount Exchange Rate
Term Contract (U.S.$000) (U.S.$/Cdn.$)
------------------------------------------------------------------------
January to April 2005 Forward 5,000 1.3550
January to April 2005 Forward 5,000 1.3680
January to December 2005 Collar 5,000 1.2300 to 1.2700
January to December 2005 Collar 10,000 1.2000 to 1.2600
------------------------------------------------------------------------
------------------------------------------------------------------------


The costless collar arrangements have counterparty call options on
December 30, 2005 whereby the Trust's counterparty can extend the $5.00
million contract term for calendar 2006 at 1.3100 and the $10.00 million
contract term for calendar 2006 at 1.2700.

Interest rate risk

The Trust's interest rate risk management activities had an unrealized
loss of $0.67 million at year end. The Trust had entered into various
derivative instruments to manage its interest rate exposure on debt
instruments. At December 31, 2004 the Trust had fixed the interest rate
on a portion of its debt as follows:



Term Amount ($000) Interest rate
------------------------------------------------------------------------
January 2005 to November 2005 20,000 3.58% plus stamping fee
January 2005 to May 2006 20,000 3.60% plus stamping fee
January 2005 to March 2007 20,000 3.58% plus stamping fee
January 2005 to September 2007 20,000 3.65% plus stamping fee
------------------------------------------------------------------------
------------------------------------------------------------------------


Fair value of financial assets and liabilities

The fair values of financial instruments presented on the consolidated
balance sheet, other than long-term borrowings, approximate their
carrying amount due to the short-term nature of those instruments. The
estimated fair values of long-term borrowings approximated its fair
value due to the floating rate of interest charged under the facilities.

8. LONG-TERM DEBT

At December 31, 2004, APF had a revolving credit and term facility for
$200 million (2003 - $150 million) with a syndicate of Canadian
financial institutions. The facility may be drawn down or repaid at any
time but there are no scheduled repayment terms. The credit facility
bears interest based on a sliding scale tied to APF's debt-to-cash flow
ratio: from a minimum of the bank's prime rate to a maximum of the
bank's prime rate plus 1.625 percent (2003 - 0.125 to 1.625 percent) or
where available, at Banker's Acceptances rates plus a stamping fee of
1.00 to 2.25 percent (2003 - 1.125 to 2.00 percent). The facility
contains an option to extend the revolving period for an additional 364
days at the option of the lenders upon notice from the Trust no earlier
than 180 days and no less than 90 days prior to the end of the initial
revolving period, being October 31, 2005. If not extended, the
outstanding principal converts to a one-year non-revolving reducing loan
for a term of one year. From the date of conversion to a one-year term
facility, APF will pay one-sixth of the outstanding principal after 180
days and one-twelfth of the outstanding principal every 90 days
thereafter.

The debt is collateralized by a $300 million demand debenture containing
a first fixed charge on all crude oil and natural gas assets of APF as
required by the lenders and a floating charge on all other property
together with a general assignment of book debts. At December 31, 2004,
the interest rate was bank prime of 4.25 percent plus 0.125 percent
(2003 - 4.5 percent plus 0.125 percent).

9. INCOME TAXES

The Trust applies substantively enacted income tax rates to derive its
future income tax liability and the related provision (recovery) during
the year. The Trust recorded a future income tax recovery of $27.02
million during the year (2003 - $14.21 million). The acquisition of
Great Northern increased the future tax liability by $49.08 million
resulting from temporary differences between tax bases and the fair
value assigned to assets and liabilities acquired.

Federal corporate income tax rate reductions received Royal Accent
during 2003. The applicable tax rate on resource income will ultimately
be reduced from 28 per cent to 21 per cent over a five-year period,
provide for the deduction of crown royalties and eliminate the deduction
for resource allowance. The tax provision differs from the amount
computed by applying the combined Canadian federal and provincial income
tax statutory rates to income before future income tax recovery as
follows:



($000) 2004 2003
------------------------------------------------------------------------
Restated
(note 3)
Income before income taxes 22,620 26,401
Statutory tax rate 40.32% 42.75%
------------------------------------------------------------------------
Expected tax provision (recovery) 9,120 11,286
Adjustments:
Net income of the Trust (26,191) (19,886)
Resource allowance (1,625) (2,250)
Non-deductible crown charges 2,056 669
Capital tax 972 1,163
Rate reduction (2,088) (3,717)
Revision to tax pool estimates (8,972) -
Other (288) (1,472)
------------------------------------------------------------------------
Recovery of future income taxes (27,016) (14,207)
------------------------------------------------------------------------
Future tax liability comprised of:
Accounting basis for capital assets in excess
of tax basis 102,663 80,269
Asset retirement obligations (11,197) (7,775)
Derivative contracts (59) -
Future tax losses likely to be utilized (4,696) (8,503)
------------------------------------------------------------------------
------------------------------------------------------------------------
86,711 63,991
------------------------------------------------------------------------
------------------------------------------------------------------------


The petroleum and natural gas properties and facilities owned by Energy
and LP have an approximate tax bases of $185.00 million (2003 - $70.00
million) available for future use as deductions from taxable income.
Included in the tax bases are non-capital loss carry forwards of $6.60
million (2003- $22.30) which expire during years 2005 through 2010. No
current income taxes were paid or payable in 2004 or 2003.

Taxable income of the Trust is comprised of income from royalties,
adjusted for crown royalties and resource allowance, less deductions for
Canadian oil and natural gas property expense (COGPE), which is claimed
at a rate of 10 percent on a declining balance basis and issue costs
which are claimed at 20 percent per year on a straight-line basis. Any
losses that occur in the Trust must be retained in the Trust and may be
carried forward and deducted from taxable income for a period of seven
years. The tax bases held within the Trust at December 31, 2004 was
$214.00 million (2003 - $122.30 million).

10. CONVERTIBLE DEBENTURES

On July 3, 2003, APF issued $50.0 million of 9.40 percent unsecured
subordinated convertible debentures ("convertible debentures") for
proceeds of $50.0 million ($47.7 million net of issue costs). Interest
is paid semi-annually on January 31 and July 31 and the instruments
mature on July 31, 2008.

The debentures are convertible at the holder's option into fully paid
and non-assessable Trust units at any time prior to July 31, 2008, at a
conversion price of $11.25 per Trust unit. The holder will receive
accrued and unpaid interest up to and including the conversion date. The
debentures are not redeemable by the Trust before July 31, 2006, except
under certain circumstances. The convertible debentures become
redeemable at $1,050 per convertible debenture, in whole or in part,
after July 31, 2006 and redeemable at $1,025 after July 31, 2007 and
before maturity.

The convertible debentures are a debt security with an embedded
conversion option and the following summarizes the accounting for the
principal amount of the convertible debentures since their issuance:



Liability Equity
($000s) Component Component Total
------------------------------------------------------------------------
Issued on July 3, 2003 48,817 1,183 50,000
Accretion of liability during 2003 89 - 89
Conversions into Trust Units during
2003 (1,187) (29) (1,216)
------------------------------------------------------------------------
Carrying value at December 31, 2003 47,719 1,154 48,873
------------------------------------------------------------------------
Accretion of liability during 2004 193 - 193
Conversions into Trust Units during
2004 (215) (5) (220)
------------------------------------------------------------------------
Carrying value at December 31, 2004 47,697 1,149 48,846
------------------------------------------------------------------------
------------------------------------------------------------------------


11. ASSET RETIREMENT OBLIGATIONS

The following table presents the reconciliation of the beginning and
ending aggregate asset retirement obligation associated with the
retirement of oil and gas properties:



($000) 2004 2003
------------------------------------------------------------------------
Asset retirement obligation, beginning of year 21,803 12,961
Liabilities acquired 7,866 4,673
Liabilities incurred 834 3,249
Liabilities settled (1,083) (374)
Accretion expense 1,573 1,294
------------------------------------------------------------------------
Asset retirement obligation, end of year 30,993 21,803
------------------------------------------------------------------------
------------------------------------------------------------------------


The total undiscounted amount of estimated cash flows required to settle
the obligation is $108.29 million (2003 - $70.72 million), which has
been discounted using a credit-adjusted risk free rate of eight percent
and an inflation factor of one and one-half percent. Most of these
obligations are not expected to be paid for several years, or decades,
in the future and will be funded from general company resources and the
fund reserved for site reclamation and abandonment. The abandonment fund
is currently funded at $0.53 million per quarter through cash flow from
operations.

12. UNITHOLDERS' INVESTMENT ACCOUNT

The per unit calculations for the year ended December 31, 2004 was based
on weighted average Trust units outstanding of 48.49 million (2003 -
30.97 million). In computing net income per unit - diluted, 0.33 million
units (2003 - 0.33 million) were added to the weighted average number of
units outstanding for the year, reflecting the dilutive effect of
employee options and rights. An additional 4.32 million Trust units
(2003 - 2.18 million) were added to the weighted average number of units
outstanding for the year relating to the assumed conversion of
debentures. Interest on debentures assumed to be converted into Trust
units totalled $5.26 million (2003 - $2.67 million) and was added back
to net income for per unit - diluted calculations.



December 31, 2004 December 31, 2003
--------------------------------------------
Trust Units Units (000) ($000) Units (000) ($000)
------------------------------------------------------------------------
Balance - Beginning
of period 34,074 324,318 22,942 214,405
Corporate acquisitions
(note 5) 12,885 156,943 5,332 53,143
Issued for cash 7,877 90,451 5,352 55,670
Cost of units issued - (5,270) - (3,467)
Regular DRIP 516 5,764 24 273
Premium DRIP 3,031 33,895 117 1,329
Issued on conversion
of debentures 19 220 108 1,216
Issued on exercise of
options/rights 442 3,799 199 1,749
Allocated from
contributed surplus - 74 - -
------------------------------------------------------------------------
Balance - End of period 58,845 610,194 34,074 324,318
------------------------------------------------------------------------
------------------------------------------------------------------------


Unitholders' rights plan

In 1999, the Trust created a Unitholders' Rights Plan and authorized the
issuance of one right in respect of each Trust unit outstanding. Each
right would entitle a unitholder under certain circumstances to acquire
upon payment of an exercise price of $50.00, the number of Trust units
having an aggregate market price equal to twice the exercise price of
the rights.

Units issued for cash

The Trust issued Trust units on two separate occasions: 4.77 million
Trust units at $11.60 per unit for gross proceeds of $55.27 million on
February 4, 2004; and 3.10 million Trust units at $11.30 per unit for
gross proceeds of $35.03 million on September 8, 2004.

Distribution reinvestment program

Commencing December 2003, the Trust initiated a distribution
reinvestment plan ("DRIP"). The DRIP permits eligible unitholders to
direct their distributions to the purchase of additional units at 95
percent of the average market price as defined in the plan ("Regular
DRIP"). The premium distribution component permits eligible unitholders
to elect to receive 102 percent of the cash the unitholder would
otherwise have received on the distribution date ("Premium DRIP").
Participation in the Regular DRIP and Premium DRIP is subject to
proration by the Trust. Unitholders who participate in either the
Regular DRIP or the Premium DRIP are also eligible to participate in the
optional unit purchase plan as defined in the DRIP.

13. UNIT-BASED COMPENSATION PLANS

APF has established a Trust Units Options Plan (the "Plan") and a Trust
Unit Incentive Rights Plan (the "Rights Plan") for employees and
independent directors. Pursuant to the Plan arrangement, employees,
directors and long-term consultants may be granted options to purchase
Trust units. The exercise price for each option granted was not less
than the market price of the Trust's units on the grant date and the
contractual term of each option is not to exceed five years. Options
granted before February 1, 1998 vested immediately; options granted
after January 28, 1998 vested in one-third increments on the first,
second and third anniversaries of their grant date. The Plan was
terminated in 2001 and replaced with the Rights Plan. No additional
options have been granted under the Plan since 2001. A summary of the
change in the Plan during 2004 and 2003 is as follows:



December 31, 2004 December 31, 2003
Weighted Weighted
Average Average
Trust Unit Options Options(000) Price($) Options(000) Price($)
------------------------------------------------------------------------
Balance- Beginning
of period 126 9.59 244 9.13
Granted - - - -
Exercised (46) 9.45 (107) 8.55
Cancelled - - (11) 9.42
------------------------------------------------------------------------
Balance - End
of period 80 9.68 126 9.59
------------------------------------------------------------------------
Exercisable - End
of period 80 9.68 60 9.48
------------------------------------------------------------------------
------------------------------------------------------------------------

The following table summarizes Plan related information at
December 31, 2004:

December 31, 2004
---------------------------------------------------------
Weighted
average Weighted Weighted
remaining Options average Options average
contractual outstanding exercise exercisable exercise
life (years) (000) price($) (000) price($)
------------------------------------------------------------------------
Range
7.00 to 7.99 0.18 1 7.15 1 7.15
8.00 to 8.99 0.68 0 8.85 0 8.85
9.00 to 9.99 1.16 79 9.70 79 9.70
------------------------------------------------------------------------
1.16 80 9.68 80 9.68
------------------------------------------------------------------------
------------------------------------------------------------------------


Under the Rights Plan, employees, directors and long-term consultants
may be granted rights to purchase Trust units. The exercise price for
each right granted is not to be less than the market price of the
Trust's units on the grant date and the contractual term of each right
is not to exceed ten years. The exercise price of the rights is adjusted
downwards from time to time by the amount, if any, that distributions to
unitholders in any calendar quarter exceeds a percentage of the Trust's
net book value of property, plant, and equipment, as determined by the
Trust.



A summary of the change in the Rights Plan during 2004 and 2003 is as
follows:

December 31, 2004 December 31, 2003
Weighted Weighted
Average Average
Trust Unit Rights Rights(000) Price($) Rights(000) Price($)
------------------------------------------------------------------------
Balance - Beginning
of period 1,824 9.09 429 9.37
Granted 952 11.91 1,538 9.78
Exercised (395) 8.49 (92) 9.05
Cancelled (510) 9.43 (51) 9.67
------------------------------------------------------------------------
Balance - Before
price reduction 1,871 10.56 1,824 9.72
Reduction of
exercise price - (0.72) - (0.63)
------------------------------------------------------------------------
Balance - End of period 1,871 9.84 1,824 9.09
------------------------------------------------------------------------
Exercisable - End
of period 241 8.50 47 8.58
------------------------------------------------------------------------
------------------------------------------------------------------------

The following table summarizes Rights Plan related information at
December 31, 2004:

December 31, 2004
---------------------------------------------------------
Weighted
average Weighted Weighted
remaining Rights average Rights average
contractual outstanding exercise exercisable exercise
life (years) (000) price($) (000) price($)
------------------------------------------------------------------------
Range
7.00 to 7.99 7.17 140 7.68 52 7.68
8.00 to 8.99 8.26 808 8.38 156 8.38
9.00 to 9.99 8.45 17 9.43 5 9.49
10.00 to 10.99 8.75 83 10.59 28 10.59
11.00 to 11.99 9.39 823 11.56 - -
------------------------------------------------------------------------
8.70 1,871 9.84 241 8.50
------------------------------------------------------------------------
------------------------------------------------------------------------


In conformity with CICA Handbook Section 3870, "Stock-based Compensation
and Other Stock-based Payments" discussed in note 3, no compensation
cost has been recognized for unit-based compensation granted prior to
January 1, 2003. In accordance with the transitional provisions, the
Trust has disclosed pro forma results as if the new standard had been
adopted retroactively. At December 31, 2004, proforma net income and
earnings per share would not have been materially different from those
disclosed in the consolidated statement of operations and accumulated
earnings.

The fair value of rights granted after December 31, 2002 was estimated
using a Black-Scholes option-pricing model incorporating the following
assumptions: risk-free interest rates ranging from 3.01 to 4.62 percent;
volatility ranging from 16.14 and 22.63 percent; expected rights term of
five years; and dividend yield rates ranging from 11.10 to 13.87
percent, representing the difference between the anticipated
distribution and price reduction yields. The initial fair value ascribed
to rights granted under the Rights Plan is not subsequently revised for
changes in any of the underlying assumptions and is recorded as
compensation expense evenly over the contractual vesting period.
Compensation expense is adjusted prospectively for rights cancelled
under the Rights Plan during the period.

The Trust recorded a recovery of compensation expense of $0.88 million
during 2004 (2003 - expense of $1.24 million) related to vested rights
issued under the Rights Plan with a corresponding increase to
contributed surplus. When rights are exercised by employees and
directors of the Trust, the consideration paid is recorded to the
unitholders' investment account along with related non-cash compensation
expense previously recognized in contributed surplus.



14. SUPPLEMENTAL CASH FLOW INFORMATION

Twelve Months Ended December 31
---------------------------------
($000) 2004 2003
------------------------------------------------------------------------
Cash payments related to certain items
Interest 957 4,070
Interest on debentures 4,947 30
Interest rate swap settlement 901 -
Capital and other taxes 3,507 3,389
------------------------------------------------------------------------
------------------------------------------------------------------------


15. NET CHANGE IN NON-CASH WORKING CAPITAL ITEMS

Twelve Months Ended December 31
---------------------------------
($000) 2004 2003
------------------------------------------------------------------------
Change in working capital items
Accounts receivable (551) 1,016
Other current assets (1,415) (397)
Accounts payable and accrued liabilities (8,893) 5,204
Derviatives liabilities 386 -
------------------------------------------------------------------------
(10,473) 5,823
------------------------------------------------------------------------
------------------------------------------------------------------------


16. CONTRACTUAL OBLIGATIONS AND COMMITMENTS

APF is involved in certain legal actions that occurred in the normal
course of business. APF is required to determine whether a contingent
loss is probable and whether that loss can be reasonably estimated. When
the loss has satisfied both criteria, it is charged to income.
Management is of the opinion that losses, if any, arising from such
legal actions would not have a material effect on these financial
statements.

The Trust leases its office premises through an arrangement deemed to be
an operating lease for accounting purposes. As such, the Trust is not
required to record its lease obligation as a liability nor does it
record its leased premises as an asset. The estimated operating lease
commitments for the Trust's leased office premises for the next five
years are as follows:



($000)
------------------------------------------------------------------------
2005 1,398
2006 1,213
2007 1,252
2008 1,083
2009 934
Thereafter 934
------------------------------------------------------------------------
------------------------------------------------------------------------


Certain statements in this material may be "forward-looking statements"
including outlook on oil and gas prices, estimates of future production,
estimated completion dates of acquisitions and construction and
development projects, business plans for drilling and exploration,
estimated amounts and timing of capital expenditures and anticipated
future debt levels and royalty rates. Information concerning reserves
contained in this material may also be deemed to be forward-looking
statements as such estimates involve the implied assessment that the
resources described can be profitably produced in the future. These
statements are based on current expectations, estimates and projections
that involve a number of risks and uncertainties, which could cause
actual results to differ from those anticipated by APF. This news
release is not for distribution to U.S. newswire services or for
distribution in the U.S.

-30-

Contact Information

  • FOR FURTHER INFORMATION PLEASE CONTACT:
    APF Energy Trust
    Steve Cloutier
    President
    (403) 294-1000 or Toll Free (800) 838-9206
    or
    APF Energy Trust
    Alan MacDonald
    V.P. Finance
    (403) 294-1000 or Toll Free (800) 838-9206
    or
    APF Energy Trust
    Christine Ezinga
    Corporate Planning Analyst
    (403) 294-1000 or Toll Free (800) 838-9206
    (403) 294-1074 (FAX)
    Email: invest@apfenergy.com
    Website: www.apfenergy.com
    The Toronto Stock Exchange has neither approved nor disapproved of the
    contents of this news release.