APF Energy Trust
TSX : AY.UN
TSX : AY.DB

APF Energy Trust

May 13, 2005 05:00 ET

APF Energy Releases First Quarter 2005 Financial & Operating Results

CALGARY, ALBERTA--(CCNMatthews - May 13, 2005) - On April 13, 2005, APF Energy Trust (TSX:AY.UN) (TSX:AY.DB) ("APF") and StarPoint Energy Trust ("StarPoint") jointly announced a proposed merger (the "Merger") that would see each APF unitholder receive 0.63 of a StarPoint unit and 1 common share of Rockyview Energy Inc. ("Rockyview"), a publicly-traded junior exploration and production company for each APF unit held. The Merger is expected to close in late June, following an APF unitholder meeting to be held on June 20, 2005, in Calgary. An information circular respecting the Merger and the creation of Rockyview is expected to be mailed to APF unitholders on or about May 24, 2005.

On May 9, 2005, StarPoint announced that it had agreed to acquire assets from EnCana Corporation (the "EnCana Assets") for $392 million (the "EnCana Transaction"), and concurrently announced a financing of trust units and convertible debentures. The EnCana Assets are located proximate to existing APF and StarPoint production in southern and east-central Alberta, and are currently producing 6,400 barrels of oil equivalent per day ("boe/d"). In conjunction with this announcement, StarPoint stated that it would increase its monthly distribution to $0.21 per unit, from $0.20. The board of directors and management of APF unanimously approved the EnCana Transaction.

The combined Trust will move forward under the StarPoint name with its current management team, lead by President & Chief Executive Officer Paul Colborne. As a result of Merger and the EnCana Transaction, StarPoint has revised its 2005 exit production rate guidance to more than 31,500 boe/d. Proforma all the transactions, StarPoint will have an enterprise value of approximately $2 billion.

Rockyview will be run by APF's current executive officers, lead by Steve Cloutier as President & Chief Executive Officer. Other senior management will include Alan MacDonald, Chief Financial Officer, Dan Allan, Chief Operating Officer, Wayne Geddes, Vice President, Land and Howard Anderson, Vice President, Engineering. Rockyview will retain APF's Wood River assets in central Alberta which are currently producing approximately 1,000 boe/d. The production portfolio is gas weighted at 85% with 15% representing crude oil and liquids. These assets are prospective for both conventional and coalbed methane production and management has identified 50 drilling locations.



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SUMMARY OF OPERATING & FINANCIAL RESULTS
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FINANCIAL Three Months Ended March 31
---------------------------------
($000, except per unit/boe amounts) 2005 2004
(restated)
------------------------------------------------------------------------
Oil and gas revenue 73,191 46,355
Cash flow from operations(1) 32,896 21,858
Per unit - basic $ 0.55 $ 0.58
Per unit - diluted $ 0.51 $ 0.52
Distributions declared 28,594 19,829
Per unit $ 0.48 $ 0.53
Payout ratio 87% 91%
Total assets 860,440 496,871
Bank debt 183,000 55,000
Capital Expenditures 22,729 12,560
Market
Units outstanding (000)
End of period 59,944 39,670
Weighted average - basic 59,381 37,381
Weighted average - diluted 64,011 42,167
Trust unit trading
High $ 12.33 $ 12.63
Low $ 11.46 $ 10.32
Close $ 12.00 $ 12.28
Average daily volume 375,191 254,769
------------------------------------------------------------------------


------------------------------------------------------------------------
Three Months Ended March 31
---------------------------------
2005 2004
------------------------------------------------------------------------
OPERATIONS
------------------------------------------------------------------------
Average daily production
Crude oil (bbl) 7,302 6,104
NGLs (bbl) 903 424
Natural gas (mcf) 57,689 37,729
---------------------------------
Total (boe)(2) 17,820 12,816
------------------------------------------------------------------------
Average commodity prices ($Cdn.)
Total crude oil (bbl) $ 48.11 $ 38.83
NGLs (bbl) 44.11 33.80
Natural gas (mcf) 7.08 6.63
---------------------------------
Average (boe)(2) $ 44.88 $ 39.13
------------------------------------------------------------------------
Gross Drilling (net)
Oil 14 (8.4) 3 (1.3)
Gas 48 (13.2) 23 (11.3)
Dry 1 (0.6) 1 (1.0)
------------------------------------------------------------------------
Total 63 (22.2) 27 (13.6)
------------------------------------------------------------------------

(1) Management uses cash flow (before changes in non-cash working
capital) to analyze operating performance and leverage. Cash flow as
present 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 well head.


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 unaudited interim Consolidated Financial Statements ("Interim Consolidated Financial Statements") for the period ended March 31, 2005 and the December 31, 2004 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).

This MD&A is dated May 11, 2005

RESULTS OF OPERATIONS

PRODUCTION

The Trust increased average production volumes by 39 percent to 17,820 boe/d for the period ended March 31, 2005, 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 drilling program which achieved a 98 percent success rate. Natural gas production averaged 57,689 mcf/d in the first quarter 2005, 53 percent higher than the comparable period which averaged 37,729 mcf/d. Strengthened natural gas production reflects full quarter production from drilling and acquisition activities undertaken throughout 2004 including the purchase of Great Northern. New production added in the first quarter of 2005 was primarily attributable to the tie in of natural gas wells drilled during the fourth quarter of 2004.

The Trust increased light/medium and heavy oil production by 23 and 4 percent, respectively, during the period ended March 31, 2005, despite inclement weather conditions and early break-up. NGL production volumes increased 113 percent relative to the comparable period year last year, due primarily to the gas-levered Great Northern acquisition.



Three Months Ended
March 31
-------------------------------
2005 2004 % Change
------------------------------------------------------------------------
Light/medium crude oil (bbl/d) 6,191 5,031 23
Heavy oil (bbl/d) 1,111 1,073 4
NGL (bbl/d) 903 424 113
Natural gas (mcf/d) 57,689 37,729 53
------------------------------------------------------------------------
Total (boe/d) 17,820 12,816 39
------------------------------------------------------------------------
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Production split
------------------------------------------------------------------------
Oil & NGLs 46% 51% (10)
Natural Gas 54% 49% 10
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COMMODITY PRICES AND RISK MANAGEMENT

First quarter crude prices before realized derivatives increased 24 percent, compared to the same quarter in 2004, which is consistent with the upward trend of the benchmark West Texas Intermediate ("WTI") over the same period. APF received a lower price than WTI due to the price differential between light oil and heavy oil. The increased WTI price was partially offset by the weakening of the US dollar which declined 7 percent in value against the Canadian dollar. First quarter natural gas prices before realized derivatives increased 7 percent over the comparable quarter, while the benchmark AECO price decreased slightly.

Price realizations included the impact of realized crude oil and natural gas financial derivative instruments. For the quarter ended March 31, 2005, crude oil price realizations increased 24 percent to $43.53 per boe and include the settlement of crude oil derivatives, which lowered pricing before derivatives by 11 percent or $4.58 per boe.

The impact of realized derivatives did not significantly impact natural gas price realizations. Consistent with pricing before derivatives, for the period ended March 31, 2005, price realizations were up slightly to $7.13 per mcf, which represents a 3 percent increase over the comparable quarter.


Three Months Ended
March 31
-------------------------------
Prices - Before Derivatives ($Cdn.) 2005 2004 % Change
------------------------------------------------------------------------
Light/medium crude oil (bbl) $ 53.26 $ 40.94 30
Heavy oil (bbl) 19.43 28.95 (33)
------------------------------------------------------------------------
Total crude oil (bbl) 48.11 38.83 24
NGLs (bbl) 44.11 33.80 31
Natural gas (mcf) 7.08 6.63 7
------------------------------------------------------------------------
Total (boe) $ 44.88 $ 39.13 15
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------------------------------------------------------------------------

Realized Oil and Gas Derivatives ($Cdn.)
------------------------------------------------------------------------
Crude oil (bbl) $ (4.58) $ (3.77) 21
Natural gas (mcf) 0.05 0.31 (84)
------------------------------------------------------------------------
Total (boe) $ (1.71) $ (0.86) 99
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Prices - After Realized Oil and Gas Derivatives ($Cdn.)
------------------------------------------------------------------------
Total crude oil (bbl) $ 43.53 $ 35.06 24
NGLs (bbl) 44.11 33.80 31
Natural gas (mcf) 7.13 6.95 3
------------------------------------------------------------------------
Total (boe) $ 43.17 $ 38.27 13
------------------------------------------------------------------------
------------------------------------------------------------------------

Reference Pricing
------------------------------------------------------------------------
WTI ($U.S./bbl) 49.84 35.15 42
Edmonton Par ($Cdn./bbl) 61.67 45.59 35
AECO gas ($Cdn./mcf) 6.51 6.61 (1)
Foreign exchange ($U.S./$Cdn.) 1.2270 1.3178 (7)
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Derivative instruments are also used to manage exposure to foreign currency exchange rates, interest rates and electricity rates. APF does not enter into derivative contracts for speculative purposes. The Trust's objective is to provide unitholders with stable cash distributions and strong overall returns. The Trust has established a risk management framework to mitigate risks inherent in the oil and gas sector.

RISK MANAGEMENT

Electricity price risk

At March 31, 2005, the Trust had a 2MW (7x24) contract with a fixed price of $46.40/MWh for calendar 2005. The Trust's electricity cost management activities had an unrealized gain of $0.12 million at March 31, 2005.

Foreign currency risk

The Trust's currency risk management activities had an unrealized gain of $1.02 million at March 31, 2005. The derivative instruments currently outstanding are as follows:



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

At March 31, 2005 the Trust's interest rate risk management activities had an unrealized loss of $0.41 million related to the following fixed rate contracts:



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


Commodity price risk

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 March 31, 2005, the Trust had recorded a $12.89 million unrealized loss on outstanding crude oil derivative instruments and a $6.00 million unrealized loss on outstanding natural gas derivative instruments.

Following is a summary of crude oil and natural gas derivative instruments outstanding at March 31, 2005:



Following is a summary of crude oil and natural gas derivative
instruments outstanding at March 31, 2005:

2005 2006
Type and term -----------------------------------------
of contracts Commodity Q2 Q3 Q4 Q1 Q2 Q3
------------------------------------------------------------------------
Collar
($U.S./mmbtu)
Average floor Natural gas 6.50 6.50 6.50 - - -
Average ceiling Natural gas 6.90 6.90 6.90 - - -
Average production
(mmbtu/day) Natural gas 5,000 5,000 1,667 - - -
Collar ($Cdn./GJ)
Average floor Natural gas 6.13 6.13 6.72 6.92 - -
Average ceiling Natural gas 7.25 7.25 9.10 9.72 - -
Average production
(GJ/day) Natural gas 20,000 20,000 26,667 30,000 - -
Collar ($U.S./bbl)
Average floor Crude Oil 40.50 43.14 46.50 45.43 46.20 50.00
Average ceiling Crude Oil 47.18 51.08 54.48 54.26 55.38 64.00
Average production
(bbls/day) Crude Oil 3,000 3,500 3,000 3,500 2,500 500
Sold call ($U.S./bbl)
Average price Crude Oil 40.95 - - - - -
Average production Crude Oil 500 - - - - -
Average premium
(bbls/day) Crude Oil 3.45 - - - - -
Swap ($U.S./bbl)
Average price Crude Oil 36.66 - - - - -
Average production
(bbls/day) Crude Oil 667 - - - - -
------------------------------------------------------------------------
------------------------------------------------------------------------


Following the announcement of the proposed combination with StarPoint, APF in conjunction with and on behalf of StarPoint, entered into the following crude oil and natural gas derivative instruments to assist the combined entity in locking in the valuation metrics of the transaction and to maintain solid, steady distributions to unitholders.

Following is a summary of crude oil and natural gas derivative instruments entered into subsequent to March 31, 2005:



For
Type and 2005 2006 all of
term of ------------------------------------------------
contracts Commodity Q3 Q4 Q1 Q2 Q3 Q4 2007
------------------------------------------------------------------------
Swap
($Cdn./GJ)
Average Natural
price gas 7.65 7.76 7.70 7.56 7.56 7.56 -
Average
production Natural
(GJ/day) gas 9,000 6,000 8,000 16,000 16,000 16,000 -
------------------------------------------------------------------------
Swap
($Cdn./bbls)
Average Crude
price oil 67.60 67.25 65.01 64.56 64.52 64.52 63.49
Average
production Crude
(bbls/day) oil 1,000 1,500 1,300 2,250 2,500 2,500 1,000
------------------------------------------------------------------------
------------------------------------------------------------------------


OIL AND GAS REVENUE

Gross oil and gas revenue for the period ended March 31, 2005 increased 58 percent over the comparable quarter in 2004 due to the Trust's acquisition of Great Northern and sustained strength in commodity prices. The variance can be explained by a 15 percent increase in prices (before realized derivatives) on 39 percent higher production volumes.


Three Months Ended
March 31
-------------------------------
($000 except per boe amounts) 2005 2004 % Change
------------------------------------------------------------------------
Light/medium crude oil sales 29,674 18,742 58
Heavy oil sales 1,943 2,827 (31)
NGL sales 3,583 1,306 174
Natural gas sales 36,777 22,766 62
------------------------------------------------------------------------
Gross oil and gas revenue 71,977 45,641 58

Realized oil and gas derivatives (2,735) (1,027) 166
Transportation (1,449) (865) 68
Other 1,214 714 70
------------------------------------------------------------------------
Net oil and gas revenue 69,007 44,463 55

Per boe $ 43.03 $ 38.12 13
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ROYALTIES

Total royalties recorded for the first quarter of 2005 are approximately 18.6 percent of gross oil and gas revenue which represents a 6 percent decrease from the comparable period. Royalties per barrel of oil equivalent produced were 9 percent higher, reflecting the increase in oil prices during the period.



Three Months Ended
March 31
-------------------------------
($000 except per boe amounts) 2005 2004 % Change
------------------------------------------------------------------------
Crown royalties 8,290 5,426 53
Freehold royalties 3,830 2,773 38
Overriding royalties 1,469 858 71
------------------------------------------------------------------------
Total royalties 13,589 9,057 50
------------------------------------------------------------------------
% of gross oil and gas revenue 18.6% 19.8% (6)
Per boe $ 8.47 $ 7.77 9
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OPERATING EXPENSE

On a gross and per boe basis, operating costs were higher for the three months ended March 31, 2005 when compared to the same period in 2004 due primarily to the acquisition and integration of Great Northern. The Trust completed a significant portion of optimization projects on Great Northern properties during the latter part of 2004 and the first quarter of 2005.



Three Months Ended
March 31
-------------------------------
($000 except per boe amounts) 2005 2004 % Change
------------------------------------------------------------------------
Operating expense 14,852 8,910 67
Per boe $ 9.26 $ 7.64 21
------------------------------------------------------------------------
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OPERATING NETBACKS

Operating netbacks per boe for the period ended March 31, 2005 increased by 11 percent from $22.71 to $25.30, due primarily to higher price realizations after derivatives and royalty income, offset by higher transportation and operating costs related to Great Northern properties.



Three Months Ended
March 31
-------------------------------
($ per boe) 2005 2004 % Change
------------------------------------------------------------------------
Price - after realized derivatives $ 43.17 $ 38.27 13
Other revenue 0.76 0.59 29
Royalties (8.47) (7.77) 9
Operating expense (9.26) (7.64) 21
Transportation (0.90) (0.74) 22
------------------------------------------------------------------------
Operating netback $ 25.30 $ 22.71 11
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GENERAL AND ADMINISTRATIVE

On a gross and per boe basis, general and administrative ("G&A") expense for the first quarter increased commensurate with increased staffing levels required by growth in the Trust's operations from corporate and property acquisitions in 2004. During the quarter, APF increased its technical staff to facilitate growth through the drill bit. Included in G&A, is a performance bonus paid to senior employees, including officers, based on criteria determined by APF's compensation committee.


Three Months Ended
March 31
-------------------------------
($000 except per boe amounts) 2005 2004 % Change
------------------------------------------------------------------------
General and administrative 3,528 1,839 92
Per boe $ 2.20 $ 1.58 39
------------------------------------------------------------------------
------------------------------------------------------------------------


INTEREST ON LONG-TERM DEBT AND CONVERTIBLE DEBENTURES

Interest expense on long-term debt on a gross and on a per boe basis has increased commensurate with higher average debt levels used to fund growth in the Trust's operations and to finance the acquisition of Great Northern.

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.

Interest and financing charges on convertible debentures for the first quarter on a gross basis decreased marginally due to debenture holders converting their debentures to units of APF. The decrease in the per boe interest charge is due a significant increase in production and relatively static interest expense.



Three Months Ended
March 31
-------------------------------
Restated
($000 except per boe amounts) 2005 2004 % Change
------------------------------------------------------------------------
Interest on long-term debt 1,836 $ 977 88
Per boe $ 1.14 $ 0.84 36

Interest and financing charges on
convertible debentures 1,283 $ 1,325 (3)
Per boe $ 0.80 $ 1.14 (30)
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------------------------------------------------------------------------


DEPLETION, DEPRECIATION, AND ACCRETION

Depletion, depreciation and accretion ("DD&A") per boe increased 15 percent from the comparable quarter and increased 58 percent on a gross basis for the quarter ended March 31, 2005. The increase in total depletion expense from the prior year is a result of increased production levels and increased depletion rates due primarily to the acquisition of Great Northern and increased capital spending resulting in a larger depletable base.



Three Months Ended
March 31
-------------------------------
($000 except per boe amounts) 2005 2004 % Change
------------------------------------------------------------------------
Depletion, depreciation and accretion 26,981 17,033 58
Per boe $ 16.82 $ 14.60 15
------------------------------------------------------------------------
------------------------------------------------------------------------


UNIT-BASED COMPENSATION

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. During the first quarter of 2005, the Trust granted 0.35 million unit appreciation rights. The fair value of rights granted was estimated using a Black-Scholes option-pricing model and incorporated the following assumptions: risk-free rate interest rate of 3.66 percent; average volatility of 13.24 percent; expected rights terms of 5 years; and dividend yield of 11.60 percent.



Three Months Ended
March 31
-------------------------------
($000 except per boe amounts) 2005 2004 % Change
------------------------------------------------------------------------
Compensation expense 35 257 (86)
Per boe $ 0.02 $ 0.22 (90)
------------------------------------------------------------------------
------------------------------------------------------------------------


TAXES

Saskatchewan capital tax and federal large corporation tax increased 29 percent during the three months ended March 31, 2005 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.

During the first quarter, APF recovered $9.89 million in future income taxes compared to a future tax recovery of $5.61 in the comparable period in 2004. The increase is primary due to the additional future tax liability acquired with the Great Northern acquisition. At March 31, 2005 APF had a future income tax liability of $76.82 million as compared to $86.71 million at the end of 2004.



Three Months Ended
March 31
-------------------------------
($000 except per boe amounts) 2005 2004 % Change
------------------------------------------------------------------------
Capital and other taxes 782 605 29
Per boe $ 0.49 $ 0.52 (6)

Recovery of future taxes (9,892) (5,607) 76
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------------------------------------------------------------------------


SUMMARY OF QUARTERLY RESULTS

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

($000, except 2005 2004 (restated)
per unit amounts) Q1 Q4 Q3 Q2 Q1
------------------------------------------------------------------------
Total revenue 73,191 66,066 46,776 39,169 32,141
Net income/
(loss) (2,371) 34,870 3,176 4,788 6,802
Per unit
- basic $ (0.04) $ 0.60 $ 0.06 $ 0.11 $ 0.18
Per unit
- diluted $ (0.04) $ 0.58 $ 0.06 $ 0.11 $ 0.18
Cash flow from
operations 32,896 31,125 29,729 24,415 21,858
Per unit $ 0.55 $ 0.53 $ 0.54 $ 0.56 $ 0.58
Distributions
declared 28,594 28,068 26,517 22,516 19,829
Per unit $ 0.48 $ 0.48 $ 0.48 $ 0.51 $ 0.53
Total assets 860,440 862,170 833,093 853,234 496,871
Total long-term
debt 183,000 169,000 150,000 190,000 55,000
------------------------------------------------------------------------
------------------------------------------------------------------------


($000, except 2003 (restated)
per unit amounts) Q4 Q3 Q2
------------------------------------------------------------------------
Total revenue 31,543 32,737 33,295
Net income/ (loss) (3,852) 9,799 20,977
Per unit - basic $ (0.11) $ 0.30 $ 0.65
Per unit - diluted $ (0.11) $ 0.30 $ 0.65
Cash flow from operations 14,873 19,389 21,563
Per unit $ 0.44 $ 0.60 $ 0.67
Distributions declared 17,822 18,909 18,916
Per unit $ 0.53 $ 0.57 $ 0.59
Total assets 498,750 501,689 446,527
Total long-term debt 98,000 90,000 102,000
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------------------------------------------------------------------------


Total revenues increased commensurate with production volumes and a strong commodity price environment. Total revenue, beginning January 1, 2004, includes the impact of unrealized derivative losses on commodity contracts outstanding at the end of each quarter. The volatility in quarterly net income is primarily a result of the Trust's unrealized derivative gains/losses.

Cash flow from operations and declared distributions increased steadily since the fourth quarter of 2003. Growth in cash flows was 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. The increase in long-term debt at the end of the first quarter 2005 is the result of a very active capital development program, accrued for at the end of 2004 and paid during the first quarter of 2005.

LIQUIDITY AND CAPITAL RESOURCES

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 March 31, 2005, a current derivative asset of $1.33 million was recorded on the balance sheet (2004 - $3.31 million) offset by a current derivative liability of $18.39 million (2004 - $3.14 million). The ultimate settlement of these derivative positions is dependent upon changes in commodity prices, foreign currency exchange rates, interest rates and electricity prices during the remaining life of derivative contracts. Excluding the Trust's net current liability for commodity and foreign currency contracts the working capital deficiency would be $4.84 million at March 31, 2005 (2004 - $12.16 million). The Trust's anticipated cash flow from operations will be sufficient to meet this current deficit.

At March 31, 2005, the Trust had a revolving credit and term facility for $200 million (2004 - $200 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 facility continues to be secured by the Trust's oil and gas properties. At March 31, 2005, $183 million was drawn under the facility (2004 - $169 million).

The following table summarized APF's total capitalization at March 31, 2005 and December 31, 2004:



The following table summarized APF's total capitalization at March 31,
2005 and December 31, 2004:

(000, except per unit amount) March 31, 2005 December 31, 2004
------------------------------------------------------------------------
Units outstanding 59,944 58,845
Trust unit price (1) $ 12.00 $ 11.72
-------------------------------------
Market Value 719,328 689,663
Working capital deficiency 21,894 11,991
Convertible debentures 48,561 48,566
Bank debt 183,000 169,000
------------------------------------------------------------------------
Total capitalization (2) 972,783 919,220
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------------------------------------------------------------------------

(1) Based on closing price at March 31, 2005
(2) Total capitalization as presented does not have any standardized
meaning prescribed by Canadian GAAP and therefore it may not be
comparable with the calculation of similar measures for other
entities. Total capitalization is not intended to represent the
total funds from equity and debt received by the Trust.


UNITHOLDERS' EQUITY

At March 31, 2005, the Trust had 59.94 million Trust units outstanding representing an increase of approximately 1.10 million units from December 31, 2004. The increase in units outstanding is primarily attributable to 1.05 million units issued pursuant to the Distribution Reinvestment Incentive Plan ("DRIP") and the optional cash payment plan. The remaining 0.05 million share were issued pursuant to the employee options and rights. See note 7 of the interim financial statements for further details.

For the quarter ended March 31, 2005, the Trust declared distributions of $28.59 million, or $0.48 per trust unit (2004 - $19.83 million or $0.53 per unit).

CAPITAL EXPENDITURES

Net capital expenditures were $22.73 million during the quarter compared to $12.56 million during the first quarter of 2004. The increase in capital expenditures reflects the significant increase in the size of the Trust both in terms of market capitalization, enterprise value and production. A considerable portion of capital expenditures during the quarter was spent on completions and the tie-in of wells drilled during the fourth quarter of 2004. During the first quarter of 2005, APF's planned drilling program was significantly curtailed due to inclement weather conditions and early break-up.



The following table summarizes the Trust's capital spending activity:

Three Months Ended March 31
-------------------------------------
($000) 2005 2004
------------------------------------------------------------------------
Property acquisitions 698 925
Land acquisitions 1,668 1,432
Seismic 2,772 734
Drilling and completions 11,592 7,559
Production facilities 5,894 1,829
Head office 305 280
------------------------------------------------------------------------
Subtotal 22,929 12,759
------------------------------------------------------------------------
Dispositions (200) (199)
------------------------------------------------------------------------
Net capital expenditures 22,729 12,560
------------------------------------------------------------------------
------------------------------------------------------------------------


CONTRACTUAL OBLIGATIONS AND COMMITMENTS

The Trust has contractual obligations in the normal course of operations including purchase of assets and services, operating agreements, transportation commitments and sales commitments. These obligations are of a recurring and consistent nature and impact cash flow in an ongoing manner.

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.

GUARANTEES AND OFF-BALANCE SHEET ARRANGEMENTS

APF has not entered into any off-balance sheet arrangements or guarantees.

BUSINESS RISKS

No changes have been made to the Business Risks as stated in APF's 2004 Annual Report.

CRITICAL ACCOUNTING ESTIMATES

APF's financial statements have been prepared in accordance with Canadian general accepted accounting policies (GAAP). Certain accounting policies require management to make appropriate decisions with respect to the formulation of estimates and assumptions that affect the reported amounts of assets, liabilities, revenues and expenses. APF's management review their estimates frequently; however, the emergence of new information and changed circumstances may result in actual results or changes to estimated amounts that differ materially from current estimates. APF attempts to mitigate this risk by employing individuals with the appropriate skill set and knowledge to make reasonable estimates; developing internal reporting systems; and comparing past estimates to actual results.

The Trust's financial and operating results include estimates on the following:

- Depletion, depreciation and accretion based on estimates of oil and gas reserves;

- Estimated revenues, operating expenses and royalties for which actual revenues and costs have not been received;

- Estimated capital expenditures on projects that are in progress;

- Estimated fair value of derivative contracts;

- Estimated value of asset retirement obligation including estimates of future costs and the timing of the costs.

OUTLOOK

During the second quarter of 2005, APF expects to complete the previously announced merger with StarPoint Energy Trust. Details regarding this transaction are provided in a news release that was issued jointly on April 13, 2005.

2005 CASH FLOW SENSITIVITY

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 per
Variable Assumption Change flow ($000) unit
------------------------------------------------------------------------
Crude oil price
($/bbl) $ 42.00 $ 1.00 $ 3,010 $ 0.05
Natural gas price
($/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
------------------------------------------------------------------------
------------------------------------------------------------------------


ADDITIONAL INFORMATION

Additional information regarding the Trust including the Trust's annual information form is available on SEDAR at http://www.sedar.com or on APF's website http://www.apfenergy.com



CONSOLIDATED BALANCE SHEETS (unaudited)
March 31, December 31,
($000) 2005 2004
------------------------------------------------------------------------
ASSETS
Current assets
Cash 1,299 567
Accounts receivable 45,321 42,200
Derivative asset (note 4) 1,329 3,313
Other current assets 6,848 7,162
------------------------------------------------------------------------
54,797 53,242
Asset retirement fund 3,475 3,271
Goodwill 118,478 118,478
Property, plant and equipment 683,690 687,179
------------------------------------------------------------------------
860,440 862,170
------------------------------------------------------------------------
------------------------------------------------------------------------

LIABILITIES
Current liabilities
Accounts payable and accrued liabilities 48,712 52,677
Derivative liability (note 4) 18,388 3,141
Distribution payable (note 2) 9,591 9,415
------------------------------------------------------------------------
76,691 65,233
Future income taxes 76,819 86,711
Long-term debt 183,000 169,000
Convertible debentures (note 5) 47,743 47,697
Asset retirement obligations (note 6) 31,538 30,993
Derivative liability (note 4) 1,304 335
------------------------------------------------------------------------
417,095 399,969
------------------------------------------------------------------------

UNITHOLDERS' EQUITY
Unitholders' investment account (note 7) 622,274 610,194
Contributed surplus (note 8) 318 289
Accumulated earnings 124,491 126,862
Accumulated distributions (note 2) (304,887) (276,293)
Convertible debenture conversion feature
(note 5) 1,149 1,149
------------------------------------------------------------------------
443,345 462,201
------------------------------------------------------------------------
860,440 862,170
------------------------------------------------------------------------
------------------------------------------------------------------------

See accompanying notes to consolidated financial statements

Approved by the Board of Directors


Martin Hislop Director Donald Engle Director


CONSOLIDATED STATEMENTS OF OPERATIONS AND ACCUMULATED EARNINGS
(unaudited)

($000 except for per unit amounts)
For the three months ended March 31 2005 2004
------------------------------------------------------------------------
Restated (note 3)
REVENUE
Oil and gas 73,191 46,355
Realized derivative loss - net (note 4) (2,735) (1,027)
Unrealized derivative loss - net (note 4) (18,384) (3,265)
Royalties expense, net of ARTC (13,589) (9,057)
Transportation (1,449) (865)
------------------------------------------------------------------------
37,034 32,141
------------------------------------------------------------------------

EXPENSES
Operating 14,852 8,910
General and administrative 3,528 1,839
Interest on long-term debt 1,836 977
Convertible debenture interest
and financing charges 1,283 1,325
Depletion, depreciation and accretion 26,981 17,033
Unit-based compensation expense
(recovery) (note 8) 35 257
Capital and other taxes 782 605
------------------------------------------------------------------------
49,297 30,946
------------------------------------------------------------------------

Income/(loss) before income taxes (12,263) 1,195
Recovery of future income taxes (9,892) (5,607)
------------------------------------------------------------------------
Net income/(loss) (2,371) 6,802
Accumulated earnings - beginning of period 126,862 78,637
Change in accounting policy - 1,029
------------------------------------------------------------------------
Accumulated earnings - end of period,
as restated 124,491 86,468
------------------------------------------------------------------------
------------------------------------------------------------------------

Net income per unit - basic $ (0.04) $ 0.18
Net income per unit - diluted (1) $ (0.04) $ 0.18

(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 STATEMENTS OF CASH FLOWS (unaudited)
($000 except for per unit amounts)

For the three months ended March 31 2005 2004
------------------------------------------------------------------------
Restated (note 3)
Cash flows from operating activities
Net income (loss) (2,371) 6,802
Items not affecting cash
Depletion, depreciation and accretion 26,981 17,033
Debenture accretion and amortization
of deferred financing charges 161 183
Future income taxes (9,892) (5,607)
Unrealized derivative loss - net (note 4) 18,384 3,265
Unit-based compensation expense (note 8) 35 257
Amortization of premiums received (184) -
Asset retirement expenditures (note 6) (218) (75)
------------------------------------------------------------------------
Cash flow from operations 32,896 21,858
Net change in non-cash working capital
items (note 9) (3,893) (4,576)
Asset retirement fund contribution - net (204) (351)
------------------------------------------------------------------------
Net cash provided by operating activities 28,799 16,931
------------------------------------------------------------------------

Cash flows from investing activities
Additions to property, plant and equipment (22,231) (11,834)
Purchase of oil and natural gas properties (698) (925)
Proceeds on sale of properties 200 199
Changes in non-cash working capital
- investing items (2,989) (2,965)
------------------------------------------------------------------------
Net cash used in investing activities (25,718) (15,525)
------------------------------------------------------------------------

Cash flows from financing activities
Issue of units for cash 58 55,387
Issue of units for cash under DRIP 9,865 8,495
Issue of units for cash upon exercise
of stock options/rights 434 509
Unit issue costs - (3,066)
Net proceeds (repayment) of long-term debt 14,000 (43,000)
Cash distributions, net of distribution
reinvestment (26,882) (19,829)
Changes in non-cash working capital
- financing items 176 (544)
------------------------------------------------------------------------
Net cash provided by financing activities (2,349) (2,048)
------------------------------------------------------------------------

Change in cash during the period 732 (642)
Cash - Beginning of period 567 1,381
------------------------------------------------------------------------
Cash - End of period 1,299 739
------------------------------------------------------------------------
------------------------------------------------------------------------

Supplemental information (note 9)

See accompanying notes to consolidated financial statements


NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

March 31, 2005 and 2004 (unaudited)

1. SIGNIFICANT ACCOUNTING POLICIES

The interim consolidated financial statements of APF Energy Trust ("APF") have been prepared by management in accordance with accounting principles generally accepted in Canada. The interim consolidated financial statements have been prepared following the same accounting policies and methods of computation as the consolidated financial statements for the fiscal year ended December 31, 2004. The disclosures provided below are incremental to those included with the annual consolidated financial statements. The interim consolidated financial statements should be read in conjunction with the consolidated financial statements and notes thereto in APF's annual report for the year ended December 31, 2004.



2. RECONCILATION OF CASH FLOW AND DISTRIBUTIONS

For the three months ended March 31
($000 except for per unit amounts) 2005 2004
------------------------------------------------------------------------
Cash flow before changes in non-cash
working capital 32,896 21,858
Add (deduct):
Abandonment fund contributions (422) (426)
Cash retained to fund operations (3,880) (1,603)
------------------------------------------------------------------------
Cash distributions declared 28,594 19,829
------------------------------------------------------------------------
Cash distributed to date 19,003 12,886
Cash distribution payable 9,591 6,943
------------------------------------------------------------------------
28,594 19,829
Opening accumulated distributions 276,293 179,363
------------------------------------------------------------------------
Closing accumulated distributions 304,887 199,192
------------------------------------------------------------------------
------------------------------------------------------------------------

Actual cash distribution declared per unit $ 0.48 $ 0.53
------------------------------------------------------------------------
------------------------------------------------------------------------


3. CHANGE IN ACCOUNTING POLICY

Consistent with Note 3 of APF's December 31, 2004 audited financial statements, 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. As a result of adopting the revised standard, comparative statements of operations and accumulated earnings were restated. Convertible debenture interest and financing charges were increased by $1.33 million with a corresponding decrease in net income of $1.33 million for the period ended March 31, 2004.

4. 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.

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 fair values of these instruments are based on an approximation of the amounts that would have been paid to or received from counterparties to settle the instruments outstanding as at March 31, 2005 with reference to forward prices and market values provided by independent sources. The actual amounts realized may differ from these estimates.



The following is a summary of the change in unrealized amounts from
December 31, 2004 to March 31, 2005:

Total Total
realized unrealized
($000) gain/(loss) gain/(loss)
------------------------------------------------------------------------
FV of contracts at December 31, 2004 223
Change in fair value of derivative contracts
during the period (21,119)
Fair value of derivative contracts realized
during the period (2,735) 2,735
------------------------------------------------------------------------
Fair value of contracts, March 31, 2005 (18,161)
------------------------------------------------------------------------
Unamortized premiums received on sold call options (202)
------------------------------------------------------------------------
FV of contracts and premiums received,
March 31, 2005 (18,363)
------------------------------------------------------------------------
------------------------------------------------------------------------

The following is a summary of unrealized fair value financial positions
by risk management activity at March 31, 2005:

Total unrealized
($000) gain/(loss)
------------------------------------------------------------------------
Commodity price
Crude oil (12,886)
Natural gas (6,004)
Utilities 123
Foreign currency 1,015
Interest rate (409)
------------------------------------------------------------------------
(18,161)
Unamortized premiums received on sold call options (202)
------------------------------------------------------------------------
(18,363)
------------------------------------------------------------------------
------------------------------------------------------------------------

The following highlights the balance sheet classification of unrealized
fair value financial positions at March 31, 2005:

Unrealized
($000) asset (liability)
------------------------------------------------------------------------
Current asset 1,329
Long-term asset -

Current liability (18,388)
Long-term liability (1,304)
------------------------------------------------------------------------
(18,363)
------------------------------------------------------------------------
------------------------------------------------------------------------


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.



5. CONVERTIBLE DEBENTURES

Liability Equity
($000) Component Component Total
------------------------------------------------------------------------
Carrying value at December 31, 2004 47,697 1,149 48,846
Accretion of liability 51 - 51
Conversions into Trust Units (5) - (5)
------------------------------------------------------------------------
Carrying value at March 31, 2005 47,743 1,149 48,892
------------------------------------------------------------------------


6. 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) March 31, 2005 December 31, 2004
------------------------------------------------------------------------
Asset retirement obligation,
beginning of year 30,993 21,803
Liabilities acquired - 7,866
Liabilities incurred 143 834
Liabilities settled (218) (1,083)
Accretion expense 620 1,573
------------------------------------------------------------------------
Asset retirement obligation,
end of year 31,538 30,993
------------------------------------------------------------------------
------------------------------------------------------------------------

The abandonment fund is currently funded at $0.42 million per quarter
through cash flow from operations.

7. UNITHOLDERS' INVESTMENT ACCOUNT

March 31, 2005 December 31, 2004
----------------------------------------
Trust Units Units (000) ($000) Units (000) ($000)
------------------------------------------------------------------------
Balance - Beginning of period 58,845 610,194 34,074 324,318
Corporate acquisitions (note 5) - - 12,885 156,943
Issued for cash 5 58 7,877 90,451
Cost of units issued - - (5,270)
Regular DRIP 154 1,712 516 5,764
Premium DRIP 885 9,865 3,031 33,895
Issued on conversion of debentures 1 5 19 220
Issued on exercise of options/rights 54 434 442 3,799
Allocated from contributed surplus - 6 - 74
------------------------------------------------------------------------
Balance - End of period 59,944 622,274 58,845 610,194
------------------------------------------------------------------------
------------------------------------------------------------------------


The per unit calculations for the period ended March 31, 2005 was based on weighted average trust units outstanding of 59.38 million (March 31, 2004 - 37.38 million). In computing net income per unit - diluted, 0.31 million units (March 31, 2004 - 0.47 million) were added to the weighted average number of units outstanding for the quarter, reflecting the dilutive effect of employee options and rights. An additional 4.32 million trust units (March 31, 2004 - 4.32 million) were added to the weighted average number of units outstanding for the quarter relating to the assumed conversion of debentures. Interest on debentures assumed to be converted into trust units totalled $1.28 million (2004 - $1.33 million) and was added back to net income for per unit - diluted calculations.



8. UNIT-BASED COMPENSATION PLANS

a) A summary of the changes in the rights outstanding under the Rights
Plan is as follows:

March 31, 2005 December 31, 2004
Weighted Weighted
Average Average
Trust Unit Rights Rights (000) Price ($) Rights (000) Price ($)
------------------------------------------------------------------------
Balance - Beginning
of period 1,871 9.84 1,824 9.09
Granted 345 11.71 952 11.91
Exercised (54) 8.02 (395) 8.49
Cancelled (191) 9.73 (510) 9.43
------------------------------------------------------------------------
Balance - Before price
reduction 1,971 10.22 1,871 10.56
Reduction of exercise price - (0.14) - (0.72)
------------------------------------------------------------------------
Balance - End of period 1,971 10.08 1,871 9.84
------------------------------------------------------------------------
Exercisable - End of period 275 8.71 241 8.50
------------------------------------------------------------------------
------------------------------------------------------------------------


The Trust incurred non-cash compensation expense of $0.04 million during the quarter (2004 - $0.26 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.

On April 1, 2005, an additional 336,455 rights were granted with an exercise price of $12.00. These rights were granted to employees hired during the three month period ended March 31, 2005.

b) During the three month period ended March 31, 2005 no options were granted under the Options Plan. At March 31, 2005, there was 0.08 million options outstanding with an exercise price of $9.68 and a contractual life of 1 year.

c) The following table reconciles the movement in the contributed surplus balance:



($000) March 31, 2005 December 31, 2004
------------------------------------------------------------------------
Balance, beginning of period 289 1,241
Compensation expense (recovery) 35 (878)
Reclassification to common shares on exercise (6) (74)
------------------------------------------------------------------------
Balance, end of period 318 289
------------------------------------------------------------------------
------------------------------------------------------------------------

9. SUPPLEMENTAL CASH FLOW INFORMATION

a) Cash payments related to certain items:

Three Months Ended March 31
-----------------------------
($000) 2005 2004
------------------------------------------------------------------------
Interest 1,817 665
Interest on debentures 2,283 2,664
Interest rate swap settlement 120 172
Capital and other taxes 1,052 520
------------------------------------------------------------------------
------------------------------------------------------------------------

b) Net change in non-cash working capital items:

Three Months Ended March 31
-----------------------------
($000) 2005 2004
------------------------------------------------------------------------
Accounts receivable (3,121) (956)
Other current assets 204 (197)
Accounts payable and accrued liabilities (976) (3,423)
------------------------------------------------------------------------
(3,893) (4,576)
------------------------------------------------------------------------
------------------------------------------------------------------------


10. COMPARATIVE FIGURES

Certain comparative figures have been re-classified to conform with current-period presentation.

11. SUBSEQUENT EVENT

On April 13, 2005, APF entered into an agreement providing for the combination of StarPoint Energy Trust and APF Energy Trust. Prior to the combination, certain APF assets will be transferred to a separate exploration and development company, Rockyview Energy Inc. ("Rockyview"). Under the terms of the Combination Agreement, each APF trust unit issued and outstanding will be exchanged for 0.63 of a StarPoint trust unit. In addition, APF unitholders will be entitled to receive one common share of Rockyview for each APF trust unit held. The transaction is subject to regulatory approval and the approval by a majority of at least two thirds of APF unitholders voting at a special meeting of unitholders. It is expected that the meeting relating to such approvals will be held on or about June 20, 2005.

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. The Toronto Stock Exchange has neither approved nor disapproved of the contents of this news release.

Contact Information

  • APF Energy Trust
    Steve Cloutier
    President
    (403) 294-1000 or Toll Free (800) 838-9206
    or
    APF Energy Trust
    Alan MacDonald
    V.P. Finance & CFO
    (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: http://www.apfenergy.com