EX-99.80 81 a05-22113_1ex99d80.htm EXHIBIT 99

Exhibit 99.80

BUSINESS ACQUISITION REPORT

July 20, 2005

TABLE OF CONTENTS

Definitions		1
Special Note Regarding Forward Looking Statements		3
Abbreviations and Conversion		4
Notes on Reserves Data		5
StarPoint Energy Trust		6
The EnCana Acquisition		6
Information Concerning the EnCana Assets		6
The APF Combination		16
Information Concerning the APF Assets		17
Effect of the EnCana Acquisition and APF Combination on the Trust		28
Effect on Operations		30
Prior Valuations		30
Informed Persons, Associates and Affiliates		30
Schedule “A” - Schedule of Revenues, Royalties and Operating Expenses for the EnCana Assets		A-1
Schedule “B” - Financial Statements of APF		B-1
Schedule “C” - Pro Forma Consolidated Financial Statements		C-1

DEFINITIONS

Unless the context indicates otherwise, the following terms shall have the meanings set out below when used in this business acquisition report. Certain other terms and abbreviations used herein, but not defined herein, are defined in NI 51-101 or the COGE Handbook and, unless the context otherwise requires, shall have the same meanings herein as in NI 51-101 or the COGE Handbook.

“ABCA” means the Business Corporations Act (Alberta), R.S.A. 2000, c. B-9, as amended, including the regulations promulgated thereunder;

“Administrator” means StarPoint Energy Ltd., a corporation formed by the amalgamation under the ABCA of StarPoint, E3 and StarPoint Acquisition Ltd. as a step to the Arrangement;

“APF” means APF Energy Trust, an unincorporated trust formed pursuant to the laws of the Province of Alberta;

“APF Combination” means the indirect acquisition by the Trust of the APF Assets in exchange for Trust Units;

“APF Assets” means those petroleum and natural gas properties and related assets described under the heading “The APF Combination – Information Concerning the APF Assets” that the Trust indirectly acquired pursuant to the APF Combination;

“APF ExploreCo” means Rockyview Energy Inc., a corporation incorporated under the ABCA;

“APF ExploreCo Assets” means certain petroleum and natural gas properties and related assets formerly held indirectly by APF and transferred to APF ExploreCo prior to the completion of the APF Combination;

“APF Reports” means the independent engineering reports of Sproule dated February 18, 2005 and of GLJ dated February 28, 2005 evaluating, effective December 31, 2004, the oil, NGL and natural gas reserves attributable to the APF Assets, in the case of GLJ, and the coalbed methane reserves attributable to the APF Assets in the case of Sproule;

“Arrangement” means the plan of arrangement under the section 193 of the ABCA and section 192 of the Canada Business Corporations Act involving StarPoint Energy Ltd., E3 Energy Inc., the Trust, Mission Oil & Gas Inc., StarPoint Acquisition Ltd., StarPoint Exchangeco Ltd., the securityholders of StarPoint Energy Ltd. and the securityholders of E3 Energy Inc., which was completed on January 7, 2005;

“COGE Handbook” means the Canadian Oil and Gas Evaluation Handbook prepared jointly by the Society of Petroleum Evaluation Engineers (Calgary chapter) and the Canadian Institute of Mining, Metallurgy & Petroleum;

“EnCana” means EnCana Corporation;

“EnCana Acquisition” means the indirect acquisition by the Trust of the EnCana Assets;

“EnCana Assets” means those petroleum and natural gas properties and related assets described under the heading “The EnCana Acquisition – Information Concerning the EnCana Assets” that the Trust indirectly acquired pursuant to the EnCana Acquisition;

“EnCana Asset Reports” means the independent engineering reports of McDaniel dated April 29, 2005 and of GLJ dated April 29, 2005, evaluating, effective March 31, 2005, the oil, NGL and natural gas reserves attributable to the EnCana Assets;

“GLJ” means Gilbert Laustsen Jung Associates Ltd., independent oil and gas reservoir engineers of Calgary, Alberta;

“McDaniel” means McDaniel & Associates Consultants Ltd., independent oil and gas reservoir engineers of Calgary, Alberta;

“NI 51-101” means National Instrument 51-101 - Standards of Disclosure for Oil and Gas Activities;

“Sproule” means Sproule Associates Limited, independent oil and gas reservoir engineers of Calgary, Alberta;

“Trust Units” means units of the Trust; and

“Unitholder” means a holder of Trust Units.

Words importing the singular number only include the plural, and vice versa, and words importing any gender include all genders. All dollar amounts set forth in this business acquisition report are in Canadian dollars, except where otherwise indicated.

SPECIAL NOTE REGARDING FORWARD LOOKING STATEMENTS

Certain statements contained in this business acquisition report constitute forward-looking statements. The use of any of the words “anticipate”, “continue”, “estimate”, “expect”, “may”, “will”, “project”, “should”, “believe” and similar expressions are intended to identify forward-looking statements. These statements involve known and unknown risks, uncertainties and other factors that may cause actual results or events to differ materially from those anticipated in such forward-looking statements. The Trust and the Administrator believe the expectations reflected in those forward-looking statements are reasonable, but no assurance can be given that these expectations will prove to be correct. Such forward-looking statements included in this business acquisition report should not be unduly relied upon. These statements speak only as of the date of this business acquisition report.

In particular, this business acquisition report contains forward-looking statements pertaining to the following:

• the performance characteristics of oil and natural gas properties;

• oil and natural gas production levels;

• capital expenditure programs;

• the size of the oil and natural gas reserves;

• projections of market prices and costs and the related sensitivity of distributions;

• supply and demand for oil and natural gas;

• expectations regarding the ability to raise capital and to continually add to reserves through acquisitions and development;

• treatment under governmental regulatory regimes and tax laws; and

• capital expenditure programs.

Actual results could differ materially from those anticipated in these forward-looking statements as a result of the risk factors set forth below:

• volatility in market prices for oil and natural gas;

• liabilities inherent in oil and natural gas operations;

• uncertainties associated with estimating oil and natural gas reserves;

• competition for, among other things, capital, acquisitions of reserves, undeveloped lands and skilled personnel;

• incorrect assessments of the value of acquisitions and exploration and development programs;

• geological, technical, drilling and processing problems;

• changes in income tax laws or changes in tax laws and incentive programs relating to the oil and gas industry and income trusts; and

• failure to realize the anticipated benefits of acquisitions.

Statements relating to “reserves” or “resources” are deemed to be forward-looking statements, as they involve the implied assessment, based on certain estimates and assumptions, that the resources and reserves described can be profitably produced in the future.

Readers are cautioned that the foregoing lists of factors are not exhaustive. The forward-looking statements contained in this business acquisition report are expressly qualified by this cautionary statement. Except as required under applicable securities laws, neither the Trust nor the Administrator undertake any obligation to publicly update or revise any forward-looking statements.

ABBREVIATIONS AND CONVERSION

In this business acquisition report, the abbreviations set forth below have the following meanings:

Oil and Natural Gas Liquids

Bbl		barrel
Bbls		barrels
Mbbls		thousand barrels
MMbbls		million barrels
Mstb		1,000 stock tank barrels
Bbls/d		barrels per day
BOPD		barrels of oil per day
NGLs		natural gas liquids
STB		standard tank barrels

Natural Gas

Mcf		thousand cubic feet
MMcf		million cubic feet
Mcf/d		thousand cubic feet per day
MMcf/d		million cubic feet per day
MMBTU		million British Thermal Units
Bcf		billion cubic feet
GJ		gigajoule

Other

AECO		EnCana’s natural gas storage facility located at Suffield, Alberta
API		American Petroleum Institute
°API		an indication of the specific gravity of crude oil measured on the API gravity scale. Liquid petroleum with a specified gravity of 28° API or higher is generally referred to as light crude oil
ARTC		Alberta Royalty Tax Credit
BOE		barrel of oil equivalent on the basis of 1 BOE to 6 Mcf of natural gas. BOEs may be misleading, particularly if used in isolation. A BOE conversion ratio of 1 BOE for 6 Mcf is based on an energy equivalency conversion method primarily applicable at the burner tip and does not represent a value equivalency at the wellhead
BOE/d		barrel of oil equivalent per day
m3		cubic metres
MBOE		1,000 barrels of oil equivalent
$000s		thousands of dollars
WTI		West Texas Intermediate, the reference price paid in U.S. dollars at Cushing, Oklahoma for crude oil of standard grade

NOTES ON RESERVES DATA

The determination of oil and gas reserves involves the preparation of estimates that have an inherent degree of associated uncertainty. Categories of proved, probable and possible reserves have been established to reflect the level of these uncertainties and to provide an indication of the probability of recovery.

The estimation and classification of reserves requires the application of professional judgment combined with geological and engineering knowledge to assess whether or not specific reserves classification criteria have been satisfied. Knowledge of concepts including uncertainty and risk, probability and statistics, and deterministic and probabilistic estimation methods is required to properly use and apply reserves definitions.

“Reserves” are estimated remaining quantities of oil and natural gas and related substances anticipated to be recoverable from known accumulations, from a given date forward, based on (a) analysis of drilling, geological, geophysical, and engineering data; (b) the use of established technology; and (c) specified economic conditions, which are generally accepted as being reasonable and are disclosed. Reserves are classified according to the degree of certainty associated with the estimates.

“Proved” reserves are those reserves that can be estimated with a high degree of certainty to be recoverable. It is likely that the actual remaining quantities recovered will exceed the estimated proved reserves.

“Developed Producing” reserves are those reserves that are expected to be recovered from completion intervals open at the time of the estimate. These reserves may be currently producing or, if shut-in, they must have previously been on production, and the date of resumption of production must be known with reasonable certainty.

“Developed Non-Producing” reserves are those reserves that either have not been on production, or have previously been on production, but are shut-in, and the date of resumption of production is unknown.

“Undeveloped” reserves are those reserves expected to be recovered from known accumulations where a significant expenditure (e.g., when compared to the cost of drilling a well) is required to render them capable of production. They must fully meet the requirements of the reserves classification (proved, probable, possible) to which they are assigned.

In multi-well pools, it may be appropriate to allocate total pool reserves between the developed and undeveloped categories or to sub-divide the developed reserves for the pool between developed producing and developed non-producing. This allocation should be based on the estimator’s assessment as to the reserves that will be recovered from specific wells, facilities and completion intervals in the pool and their respective development and production status.

“Probable” reserves are those additional reserves that are less certain to be recovered than proved reserves. It is equally likely that the actual remaining quantities recovered will be greater or less than the sum of the estimated Proved plus Probable reserves.

“gross” means: (a) in relation to an issuer’s interest in production or reserves, its “company gross reserves”, which are its working interest (operating or non-operating) share before deduction of royalties and without including any royalty interests of the issuer; (b) in relation to wells, the total number of wells in which an issuer has an interest; and (c) in relation to properties, the total area of properties in which an issuer has an interest.

“net” means: (a) in relation to an issuer’s interest in production or reserves its working interest (operating or non-operating) share after deduction of royalty obligations, plus the its royalty interests in production or reserves; (b) in relation to an issuer’s interest in wells, the number of wells obtained by aggregating the issuer’s working interest in each of its gross wells; and (c) in relation to an issuer’s interest in a property, the total area in which the issuer has an interest multiplied by the working interest owned by the issuer.

STARPOINT ENERGY TRUST

General

The Trust is an open–ended unincorporated investment trust governed by the laws of the Province of Alberta and created pursuant to the Trust Indenture. The head office of the Trust is located at Suite 3900, 205 - 5th Avenue S.W., Calgary, Alberta.

The Administrator is a corporation amalgamated under the Business Corporations Act (Alberta). The Administrator is a wholly-owned subsidiary of the Trust.

Responsible Officer

For further information concerning the acquisition described in this report, contact Brett Herman, Vice-President, Finance and Chief Financial Officer of the Administrator, at (403) 268-7800.

THE ENCANA ACQUISITION

General

On June 30, 2005, the Trust indirectly acquired the EnCana Assets from EnCana for aggregate cash consideration of $392 million. The effective date of the EnCana Acquisition was May 1, 2005.

Financing of the EnCana Acquisition

On May 26, 2005, the Trust completed an offering of 17,800,000 subscription receipts at a price of $18.00 each and 6.50% convertible extendible unsecured subordinated debentures in the aggregate principal amount of $60,000,000, for total net proceeds of $304,380,000. The net proceeds of the offering were used by the Trust to fund a portion of the purchase price of the EnCana Acquisition, with the balance being funded though additional borrowings under the Trust’s credit facility.

Upon the completion of the EnCana Acquisition, the subscription receipts that had been issued by the Trust pursuant to the offering were exchanged for an equivalent number of Trust Units. In addition, the maturity date of the 6.50% convertible extendible unsecured subordinated debentures was extended from July 31, 2005 to July 31, 2010.

INFORMATION CONCERNING THE ENCANA ASSETS

Oil and Natural Gas Reserves

In accordance with NI 51-101, McDaniel and GLJ prepared the EnCana Asset Reports. The EnCana Asset Reports evaluated, as at March 31, 2005, the oil, NGL and natural gas reserves attributable to the EnCana Assets. The tables below are a summary of the oil, NGL and natural gas reserves attributable to the EnCana Assets and the net present value of future net revenue attributable to such reserves as evaluated in the EnCana Asset Reports, based on constant and forecast price and cost assumptions. The tables summarize the data contained in the EnCana Asset Reports and, as a result, may contain slightly different numbers than such reports due to rounding. Also due to rounding, certain columns may not add exactly.

revenue attributable to reserves estimated by McDaniel and GLJ represent the fair market value of those reserves. Other assumptions and qualifications relating to costs, prices for future production and other matters are summarized herein. The recovery and reserve estimates of oil, NGL and natural gas reserves provided herein are estimates only. Actual oil, NGL and natural gas reserves may be greater than or less than the estimates provided herein.

The Trust is entitled to deduct from its income all amounts which are paid or payable by it to Unitholders in a given financial year. As a result, the Trust does not anticipate being liable for any material amount of income tax on income. Therefore, the net present values of future net revenue after income taxes will be the same as the net present values of future net revenue before income taxes presented in the tables below.

Summary of Oil and Gas Reserves – Constant Prices and Costs

	Gross Reserves				Net Reserves
	Light and Medium Crude Oil	Heavy Crude Oil	Natural Gas Liquids	Natural Gas	Light and Medium Crude Oil	Heavy Crude Oil	Natural Gas Liquids	Natural Gas
	Mbbls	Mbbls	Mbbls	MMcf	Mbbls	Mbbls	Mbbls	MMcf

Proved
Developed Producing	5,121	5,998	63	6,335	4,995	5,550	57	5,936
Developed Non-Producing	259	1,306	10	1,062	231	1,240	9	1,040
Undeveloped	1,775	425	4	839	1,709	401	4	763
Total Proved	7,155	7,729	77	8,235	6,936	7,191	69	7,739
Probable	4,588	1,394	19	3,701	4,461	1,298	17	3,459
Total Proved plus Probable	11,743	9,124	96	11,937	11,396	8,489	86	11,198

Net Present Value of Future Net Revenue – Constant Prices and Costs

	Before Future Income Tax Expenses and Discounted at
	0%	10%
	(M$)	(M$)

Proved
Developed Producing	352,640	239,477
Developed Non-Producing	44,439	30,899
Undeveloped	54,961	37,938
Total Proved	452,041	308,314
Probable	211,445	110,796
Total Proved plus Probable	663,486	419,110

Additional Information Concerning Future Net Revenue – Constant Prices and Costs

(Undiscounted)	Revenue	Royalties	Operating Costs	Development Costs	Abandonment and Reclamation Costs	Future Net Revenue Before Income Taxes
	(M$)	(M$)	(M$)	(M$)	(M$)	(M$)

Total Proved Reserves	722,307	52,473	178,393	22,968	16,430	452,041
Total Proved plus Probable	1,018,254	73,357	230,449	34,036	16,929	663,486

Future Net Revenue by Production Group – Constant Prices and Costs

		Future Net Revenue Before Income Taxes and Discounted at 10%
		(M$)

Proved
Light and Medium Crude Oil(1)		166,789
Heavy Oil(1)		135,664
Natural Gas(2)		5,861

Proved plus Probable
Light and Medium Crude Oil(1)		259,756
Heavy Oil(1)		154,200
Natural Gas(2)		5,154

Notes:

(1) Including solution gas and other by-products.

(2) Including by-products, but excluding solution gas from oil wells.

Summary of Oil and Gas Reserves – Forecast Prices and Costs

	Gross Reserves				Net Reserves
	Light and Medium Crude Oil	Heavy Crude Oil	Natural Gas Liquids	Natural Gas	Light and Medium Crude Oil	Heavy Crude Oil	Natural Gas Liquids	Natural Gas
	Mbbls	Mbbls	Mbbls	MMcf	Mbbls	Mbbls	Mbbls	MMcf

Proved
Developed Producing	5,120	5,908	61	6,305	4,994	5,464	55	5,911
Developed Non-Producing	260	1,293	10	1,064	233	1,227	9	1,041
Undeveloped	1,775	402	4	837	1,709	378	4	761
Total Proved	7,155	7,603	75	8,205	6,936	7,070	67	7,713
Probable	4,588	1,422	20	3,705	4,461	1,326	17	3,462
Total Proved plus Probable	11,743	9,024	95	11,910	11,396	8,395	85	11,175

Net Present Value of Future Net Revenue – Forecast Prices and Costs

	Before Future Income Tax Expenses and Discounted at
	0%	5%	10%	15%	20%
	(M$)	(M$)	(M$)	(M$)	(M$)

Proved
Developed Producing	268,650	223,217	193,533	172,541	156,794
Developed Non-Producing	35,091	29,660	25,551	22,332	19,766
Undeveloped	40,865	33,941	28,650	24,503	21,164
Total Proved	344,607	286,818	247,734	219,375	197,724
Probable	161,488	113,449	85,916	68,239	55,996
Total Proved plus Probable	506,094	400,268	333,650	287,614	253,720

Additional Information Concerning Future Net Revenue – Forecast Prices and Costs

(Undiscounted)	Revenue	Royalties	Operating Costs	Development Costs	Abandonment and Reclamation Costs	Future Net Revenue Before Income Taxes
	(M$)	(M$)	(M$)	(M$)	(M$)	(M$)

Total Proved Reserves	630,411	45,742	196,266	23,455	20,341	344,607
Total Proved plus Probable	886,898	63,520	260,731	34,778	21,773	506,094

Future Net Revenue by Production Group – Forecast Prices and Costs

		Future Net Revenue Before Income Taxes and Discounted at 10%
		(M$)

Proved
Light and Medium Crude Oil(1)		133,926
Heavy Oil(1)		108,794
Natural Gas(2)		5,014

Proved plus Probable
Light and Medium Crude Oil(1)		205,889
Heavy Oil(1)		123,760
Natural Gas(2)		3,971

Notes:

(1) Including solution gas and other by-products.

(2) Including by-products, but excluding solution gas from oil wells.

Pricing Assumptions – Constant Prices and Costs

McDaniel and GLJ employed the following pricing and exchange rate assumptions as of March 31, 2005 in the EnCana Asset Reports in estimating reserves data using constant prices and costs.

Edmonton Par Price 40° API	Bow River Medium 25° API	AECO - C Spot	Natural Gasolines & Condensate	Exchange Rate
($Cdn/Bbl)	($Cdn/Bbl)	($Cdn/MMBTU)	($Cdn/Bbl)	($US/$Cdn)

67.38	44.12	7.87	68.97	0.826

Pricing Assumptions – Forecast Prices and Costs

McDaniel and GLJ employed the following pricing, exchange rate and inflation rate assumptions as of April 1, 2005 in the EnCana Asset Reports in estimating reserves data using forecast prices and costs.

	Medium and Light Crude Oil			Natural Gas
Year	WTI Cushing Oklahoma 40° API	Edmonton Par Price 40° API	Bow River Medium 25° API	AECO - C Spot	Exchange Rate
	(US$/Bbl)	($CDN/Bbl)	($CDN/Bbl)	($CDN/GJ)	($US/$Cdn)
2005	53.00	63.20	43.30	7.55	0.825
2006	50.00	59.60	42.00	7.30	0.825
2007	45.00	53.50	39.30	6.70	0.825
2008	40.00	47.40	35.30	6.00	0.825
2009	37.90	44.90	33.40	5.65	0.825
2010	38.60	45.70	34.00	5.75	0.825
2011	39.40	46.60	34.70	5.90	0.825
2012	40.20	47.60	35.40	5.95	0.825
2013	41.00	48.50	36.10	6.10	0.825
2014	41.80	49.50	36.80	6.20	0.825
2015	42.60	50.40	37.50	6.35	0.825
2016	43.50	51.50	38.30	6.45	0.825
2017	44.40	52.50	39.10	6.60	0.825
2018	45.30	53.60	39.90	6.80	0.825
2019	46.20	54.70	40.70	6.85	0.825
2020	47.10	55.70	41.50	7.00	0.825
2021	48.00	56.80	42.30	7.15	0.825
2022	49.00	58.00	43.10	7.30	0.825
2023	50.00	59.20	44.00	7.45	0.825
2024	51.00	60.40	44.90	7.60	0.825
Thereafter	51.00	60.40	44.90	7.60	0.825

Future Development Costs

The table below sets out the total development costs deducted in the estimation in the EnCana Asset Reports of future net revenue attributable to proved reserves (using both constant prices and costs and forecast prices and costs) and proved plus probable reserves (using forecast prices and costs only).

	Constant Prices and Costs	Forecast Prices and Costs
	Proved Reserves	Proved Reserves	Proved Plus Probable Reserves
	(M$)	(M$)	(M$)

2005	10,436	10,436	11,274
2006	7,510	7,660	17,008
2007	3,707	3,857	5,038
2008	70	74	0
2009	70	76	76
Remaining Years	1,175	1,352	1,381
Total Undiscounted	22,968	23,455	34,777
Total Discounted at 10% per year	20,720	21,084	31,185

The Trust has three sources of funding available to finance its capital expenditure programs: internally generated cash flow from operations, debt financing when appropriate and new issues of Trust Units, if available on favourable terms. The Trust expects to fund the above future development costs primarily through internally generated cash flow and, to a much lesser extent, debt. The cost of the debt component for funding future development costs is expected to be minimal and to not materially impact the disclosed reserves or future net revenue.

Oil and Gas Properties

The following is a description of the major oil and natural gas properties comprising the EnCana Assets.

Countess, Alberta

The Countess properties are located in southern Alberta, approximately 130 kilometres southeast from the City of Calgary, Alberta. The EnCana Assets include an average operated working interest of approximately 100% in 23,580 (22,533 net) acres of land in this area. There are 84 (82 net) producing oil wells, 13 (13 net) non-producing oil wells and 2 (2 net) non-producing natural gas wells on the Countess properties.

The majority of the Countess production is obtained from the Rosemary Lower Mannville Z and RR oil pools and the Duchess Lower Mannville X and VVV oil pools which are currently under active waterflood schemes. A small portion of the production is obtained from 38 single well batteries. The medium oil (26-33° API) is produced from Lower Mannville sandstones at 1,100 to 1,200 metres in depth.

Substantially all of the Countess production is pipelined to one of two 100% working interest central facilities located at Rosemary and Duchess. The central facilities include oil, gas and water separation and treating equipment, crude oil pipeline connection, salt water disposal facilities, and solution gas gathering facilities. A small portion of the production is produced to single well batteries where oil and water are separated and trucked to various area facilities for processing and sale.

For the year ended December 31, 2004, 5 (5 net) development wells were drilled in the area resulting in 5 (5 net) oil wells. For the quarter ended March 31, 2005, no exploration or development wells were drilled in the area.

Planned exploration and development activity in the Countess area for 2005 includes the drilling of 6 (6 net) wells at an estimated total net cost of approximately $4.8 million.

Provost, Alberta

The Provost properties are located in Eastern Alberta, approximately 260 kilometres southeast from the City of Edmonton, Alberta. The EnCana Assets include an average operated working interest of approximately 100% in 22,934 (22,929 net) acres of land in this area. There are 153 (153 net) producing oil wells and 84 (83 net) non-producing oil wells on the Provost properties.

The majority of the Provost production is obtained from the Provost Lloydminster O and Sparky D oil pools and the Hayter Sparky FF, GG, T and W oil pools. The Provost oil pools are currently under active waterflood schemes and the Hayter pool will commence waterflood once Alberta Energy Utilities Board approval is obtained. A small portion of the production is obtained from Cummings and Colony oil pools at Provost and Cummings and General Petroleum oil pools at Hayter. The medium and heavy oil (20-25° API) is produced from Middle and Lower Mannville sandstones at 700 to 900 metres in depth.

The majority of the production is processed through a pipeline connected 100% working interest central facility located at Provost. The central facility includes oil, gas and water separation and treating equipment, crude oil pipeline connection, salt water disposal facilities, and solution gas gathering facilities. Gas production at Hayter is custom processed through a third party facility.

For the year ended December 31, 2004, 58 (58 net) development wells were drilled in the area resulting in 58 (58 net) oil wells. For the quarter ended March 31, 2005, no exploration or development wells were drilled in the area.

Planned exploration and development activity in the Provost area for 2005 includes the drilling of 4 (4 net) wells at an estimated total net cost of approximately $1.0 million.

Alderson, Alberta

The Alderson properties are located in Southern Alberta, approximately 190 kilometres southeast from the City of Calgary, Alberta. The EnCana Assets include an average operated working interest of 100% in 14,650 (14,650 net) acres of land in this area. There are 97 (97 net) producing oil wells and 53 (53 net) non-producing oil wells on the Alderson properties.

The majority of the Alderson production is obtained from the Suffield West Arcs D and Lower Mannville D3D and E3E oil pools and several Alderson Lower Mannville oil pools which are currently under active waterflood schemes. A small portion of the production is obtained from 44 single well batteries. The medium oil (27-31° API) is produced from Lower Mannville sandstones at 900 to 1,000 meters depth and the Arcs Nisku carbonate formation at approximately 1,250 metres in depth.

Substantially all of the Alderson production is pipelined to one of four 100% working interest central facilities located at West Suffield and Alderson. The central facilities include oil, gas and water separation and treating equipment, crude oil pipeline connection, salt water disposal facilities, and solution gas gathering facilities. A small portion of the production is produced to single well batteries where oil and water are separated and trucked to various area facilities for processing and sale.

For the year ended December 31, 2004, 15 (15 net) development wells were drilled in the area resulting in 15 (15 net) oil wells. For the quarter ended March 31, 2005, 1 (1 net) development well was drilled in the area resulting in 1 (1 net) oil well.

Planned exploration and development activity in the Alderson area for 2005 includes the drilling of 7 (7 net) wells at an estimated total net cost of approximately $4.6 million.

Oil and Gas Wells

The following table sets forth the number and status of wells, effective March 31, 2005, in which the Trust acquired a working interest through its acquisition of the EnCana Assets.

	Producing Wells				Non-Producing Wells
	Oil		Natural Gas		Oil		Natural Gas
	Gross	Net	Gross	Net	Gross	Net	Gross	Net
Countess	84	82	—	—	13	13	2	2
Provost	153	153	—	—	84	83	—	—
Alderson	97	97	—	—	53	53	—	—
Total	334	332	—	—	150	149	2	2

Properties with no Attributed Reserves

The following table summarizes the gross and net acres of unproved properties, effective March 31, 2005, in which the Trust acquired a working interest through its acquisition of the EnCana Assets and also the number of net acres for which the Trust’s rights to explore, develop or exploit will, absent further action, expire within one year.

	Gross Acres	Net Acres	Net Acres Expiring Within One Year

Countess	15,897	15,897	Nil
Provost	16,063	16,063	Nil
Alderson	6,210	6,210	Nil
Total	38,170	38,170	Nil

Drilling Activity

The following table sets forth the gross and net exploratory and development wells drilled on the properties comprising the EnCana Assets during the year ended December 31, 2004.

	Exploratory Wells		Development Wells
	Gross	Net	Gross	Net
Crude Oil	—	—	77	77
Natural Gas	—	—	—	—
Dry	—	—	—	—
Total:	—	—	77	77

No exploratory or development wells were drilled on the properties comprising the EnCana Assets during the three months ended March 31, 2005.

Additional Information Concerning Abandonment and Reclamation Costs

Well abandonment costs have been estimated area by area. Such costs are included in the EnCana Asset Reports as deductions in arriving at future net revenue. The expected total abandonment costs, net of estimated salvage value, included in the EnCana Asset Reports for 468 net wells under the proved reserves category is $20.3 million undiscounted ($7.7 million discounted at 10%), of which a total of $1.8 million is estimated to be incurred in 2005, 2006 and 2007. This estimate does not include expected reclamation costs for surface leases of $4.7 million undiscounted ($1.8 million discounted at 10%).

Costs Incurred

The following table summarizes capital expenditures (net of incentives and net of certain proceeds and including capitalized general and administrative expenses) incurred for the year ended December 31, 2004 with respect to the EnCana Assets.

	Property Acquisition Costs
	Proved Properties	Unproved Properties	Exploration Costs	Development Costs
Total (M$)	—	—	—	32,123

The following table summarizes capital expenditures (net of incentives and net of certain proceeds and including capitalized general and administrative expenses) incurred for the three months ended March 31, 2005 with respect to the EnCana Assets.

	Property Acquisition Costs
	Proved Properties	Unproved Properties	Exploration Costs	Development Costs
Total (M$)	—	—	—	304

Production Estimates

The following table discloses for each product type the total volume of production estimated by McDaniel and GLJ in the EnCana Asset Reports for 2005 in the estimates of future net revenue from proved reserves disclosed above.

	Crude Oil	Natural Gas	Natural Gas Liquids	BOE	%
	(Bbls/d)	(Mcf/d)	(Bbls/d)	(BOE/d)
Countess	1,939	3,662	15	2,564	39
Provost	1,954	392	16	2,035	31
Alderson	1,879	643	—	1,986	30
Estimated Total Production	5,772	4,697	31	6,585	100

Production History

The following tables disclose, on a quarterly basis for the year ended December 31, 2004 and the three months ended March 31, 2005, certain information in respect of production, product prices received, royalties paid, operating expenses and resulting netback for the EnCana Assets.

Average Daily Production Volume

	Three Months Ended
	Mar. 31, 2004	June 30, 2004	Sept. 30, 2004	Dec. 31, 2004	Mar. 31, 2005
Natural gas (Mcf/d)	4,567	4,623	5,390	6,216	5,742
Crude Oil (Bbls/d)	5,602	5,862	6,142	6,312	5,913
NGL (Bbls/d)	24	21	28	34	20
Total (BOE/d)	6,387	6,654	7,068	7,382	6,890

Prices Received, Royalties Paid, Production Costs and Netback – Crude Oil and NGLs

	Three Months Ended
($ per Bbl)	Mar. 31, 2004	June 30, 2004	Sept. 30, 2004	Dec. 31, 2004	Mar. 31, 2005
Prices Received	36.11	39.40	43.94	39.30	41.07
Royalties Paid	1.65	2.16	2.16	1.85	1.92
Production Costs	7.65	8.34	7.30	7.46	8.18
Netback(1)	26.81	28.90	34.48	29.99	30.97

Note:

(1) Netback is calculated by deducting royalties paid and production costs from prices received.

Prices Received, Royalties Paid, Production Costs and Netback — Natural Gas

	Three Months Ended
($ per Mcf)	Mar. 31, 2004	June 30, 2004	Sept. 30, 2004	Dec. 31, 2004	Mar. 31, 2005
Prices Received	6.77	7.02	6.87	7.41	7.09
Royalties Paid	0.35	0.36	0.36	0.37	0.27
Production Costs	0.66	0.58	0.59	0.41	0.34
Netback(1)	5.76	6.08	5.92	6.63	6.48

Note:

(1) Netback is calculated by deducting royalties paid and production costs from prices received.

Production Volume by Field

The following table indicates the average daily production from the important fields comprising the EnCana Assets for the year ended December 31, 2004.

Field	Crude Oil	Natural Gas	Natural Gas Liquids	BOE	%
	(Bbls/d)	(Mcf/d)	(Bbls/d)	(BOE/d)
Countess	2,247	4,359	13	2,987	43
Provost	1,914	335	13	1,983	29
Alderson	1,820	508	1	1,905	28
Total	5,981	5,202	27	6,875	100

The following table indicates the average daily production from the important fields comprising the EnCana Assets for the three months ended March 31, 2005.

Field	Crude Oil	Natural Gas	Natural Gas Liquids	BOE	%
	(Bbls/d)	(Mcf/d)	(Bbls/d)	(BOE/d)
Countess	2,025	4,760	11	2,829	41
Provost	1,906	233	8	1,953	28
Alderson	1,982	749	1	2,108	31
Total	5,913	5,742	20	6,890	100

Financial Statements

Schedule “A” hereto contains an audited Statement of Net Operating Revenue concerning the EnCana Assets for the years ended December 31, 2004, 2003 and 2002 and an unaudited Statement of Net Operating Revenue concerning the EnCana Assets for the three month period ended March 31, 2005.

THE APF COMBINATION

The Trust completed the APF Combination on June 27, 2005. Pursuant to the APF Combination, the Trust acquired all of the assets of APF and assumed all of its liabilities. This resulted in the Trust indirectly acquiring the APF Assets. In exchange, the Trust issued 0.63 of a Trust Unit for every outstanding trust unit of APF. Approximately 39,659,628 Trust Units were issued pursuant to the APF Combination. In addition, the Trust assumed APF’s obligations with respect to its outstanding 9.40% convertible, unsecured, subordinated debentures, maturing July 31, 2008, in an aggregate principal amount of $46,986,000.

Prior to the completion of the APF Combination, the APF ExploreCo Assets and the liabilities associated therewith were transferred to APF ExploreCo and each holder of trust units of APF was given the right to receive common shares in APF ExploreCo. The APF ExploreCo Assets consisted of approximately 1,000 BOE/d of production, primarily natural gas from properties located in Central Alberta. The APF ExploreCo Assets were not acquired by the Trust pursuant to the APF Combination and do not form part of the APF Assets.

INFORMATION CONCERNING THE APF ASSETS

Oil and Natural Gas Reserves

In accordance with NI 51-101, Sproule and GLJ prepared the APF Reports. The APF Reports evaluated, as at December 31, 2004, the oil, NGL and natural gas reserves attributable to the APF Assets. The tables below are a summary of the oil, NGL and natural gas reserves attributable to the APF Assets and the net present value of future net revenue attributable to such reserves as evaluated in the APF Reports, based on constant and forecast price and cost assumptions. The tables summarize the data contained in the APF Reports and, as a result, may contain slightly different numbers than such reports due to rounding. Also due to rounding, certain columns may not add exactly.

The net present value of future net revenue attributable to reserves is stated without provision for interest costs and general and administrative costs, but after providing for estimated royalties, production costs, development costs, other income, future capital expenditures, and well abandonment costs for only those wells assigned reserves by Sproule and GLJ. It should not be assumed that the undiscounted or discounted net present value of future net revenue attributable to reserves estimated by Sproule and GLJ represent the fair market value of those reserves. Other assumptions and qualifications relating to costs, prices for future production and other matters are summarized herein. The recovery and reserve estimates of oil, NGL and natural gas reserves provided herein are estimates only. Actual oil, NGL and natural gas reserves may be greater than or less than the estimates provided herein.

Summary of Oil and Gas Reserves – Constant Prices and Costs

	Gross Reserves				Net Reserves
	Light and Medium Crude Oil	Heavy Crude Oil	Natural Gas Liquids	Natural Gas	Light and Medium Crude Oil	Heavy Crude Oil	Natural Gas Liquids	Natural Gas
	Mbbls	Mbbls	Mbbls	MMcf	Mbbls	Mbbls	Mbbls	MMcf

Proved
Developed Producing	15,490	959	1,886	92,014	13,819	921	1,398	76,015
Developed Non-Producing	471	404	96	9,480	431	386	67	7,673
Undeveloped	2,172	143	130	14,811	1,936	132	87	11,924
Total Proved	18,132	1,506	2,112	116,305	16,186	1,440	1,552	95,612
Probable	6,508	1,036	598	36,449	5,752	962	453	30,060
Total Proved plus Probable	24,640	2,542	2,711	152,754	21,938	2,402	2,004	125,673

Net Present Value of Future Net Revenue – Constant Prices and Costs

	Before Future Income Tax Expenses and Discounted at
	0%	10%
	(M$)	(M$)
Proved
Developed Producing	666,312	425,660
Developed Non-Producing	47,820	28,555
Undeveloped	73,023	33,281
Total Proved	787,155	487,496
Probable	258,421	113,531
Total Proved plus Probable	1,045,576	601,027

Additional Information Concerning Future Net Revenue – Constant Prices and Costs

(Undiscounted)	Revenue	Royalties	Operating Costs	Development Costs	Abandonment and Reclamation Costs	Future Net Revenue Before Income Taxes
	(M$)	(M$)	(M$)	(M$)	(M$)	(M$)

Total Proved Reserves	1,594,785	268,909	465,193	42,301	31,227	787,155
Total Proved plus Probable	2,121,896	356,881	606,550	79,457	33,432	1,045,576

Future Net Revenue by Production Group – Constant Prices and Costs

		Future Net Revenue Before Income Taxes and Discounted at 10%
		(M$)
Proved
Light and Medium Crude Oil(1)		206,669
Heavy Oil(1)		6,536
Natural Gas(2)		274,291

Proved plus Probable
Light and Medium Crude Oil(1)		255,874
Heavy Oil(1)		9,948
Natural Gas(2)		335,205

Notes:

(1) Including solution gas and other by-products.

(2) Including by-products, but excluding solution gas from oil wells.

Summary of Oil and Gas Reserves – Forecast Prices and Costs

	Gross Reserves				Net Reserves
	Light and Medium Crude Oil	Heavy Crude Oil	Natural Gas Liquids	Natural Gas	Light and Medium Crude Oil	Heavy Crude Oil	Natural Gas Liquids	Natural Gas
	Mbbls	Mbbls	Mbbls	MMcf	Mbbls	Mbbls	Mbbls	MMcf

Proved
Developed Producing	15,200	1,048	1,868	91,196	13,567	974	1,387	75,333
Developed Non-Producing	477	477	97	9,432	438	451	67	7,616
Undeveloped	2,169	154	130	14,681	1,982	142	88	11,813
Total Proved	17,846	1,678	2,094	115,308	15,987	1,567	1,541	94,761
Probable	6,461	1,072	598	36,017	5,727	970	453	29,694
Total Proved plus Probable	24,307	2,750	2,692	151,325	21,713	2,536	1,995	124,454

Net Present Value of Future Net Revenue – Forecast Prices and Costs

	Before Future Income Tax Expenses and Discounted at
	0%	5%	10%	15%	20%
	(M$)	(M$)	(M$)	(M$)	(M$)
Proved
Developed Producing	606,117	485,915	413,038	363,245	326,603
Developed Non-Producing	46,583	34,179	27,377	22,935	19,747
Undeveloped	59,701	39,119	26,828	18,886	13,407
Total Proved	712,401	559,213	467,243	405,065	359,757
Probable	243,153	152,890	109,320	83,651	66,679
Total Proved plus Probable	955,554	712,103	576,563	488,716	426,437

Additional Information Concerning Future Net Revenue – Forecast Prices and Costs

(Undiscounted)	Revenue	Royalties	Operating Costs	Development Costs	Abandonment and Reclamation Costs	Future Net Revenue Before Income Taxes
	(M$)	(M$)	(M$)	(M$)	(M$)	(M$)

Total Proved Reserves	1,607,140	266,629	543,172	44,115	40,824	712,401
Total Proved plus Probable	2,177,203	358,072	735,483	81,703	46,391	955,554

Future Net Revenue by Production Group – Forecast Prices and Costs

		Future Net Revenue Before Income Taxes and Discounted at 10%
		(M$)
Proved
Light and Medium Crude Oil(1)		213,724
Heavy Oil(1)		14,052
Natural Gas(2)		239,468

Proved plus Probable
Light and Medium Crude Oil(1)		265,241
Heavy Oil(1)		20,417
Natural Gas(2)		290,905

Notes:

(1) Including solution gas and other by-products.

(2) Including by-products, but excluding solution gas from oil wells.

Pricing Assumptions – Constant Prices and Costs

Sproule and GLJ employed the following pricing and exchange rate assumptions as of December 31, 2004 in the APF Reports in estimating reserves data using constant prices and costs.

Edmonton Par Price 40° API	Cromer Medium 29.3° API	AECO - C Spot	Butanes	Pentanes Plus	Exchange Rate
($/Bbl)	($/Bbl)	($/MMBTU)	($/Bbl)	($/Bbl)	($US/$Cdn)
46.54	32.12	6.79	34.44	48.97	0.8308

Pricing Assumptions – Forecast Prices and Costs

Sproule and GLJ employed the following pricing, exchange rate and inflation rate assumptions as of December 31, 2004 in the APF Reports in estimating reserves data using forecast prices and costs.

	Medium and Light Crude Oil			Natural Gas
Year	WTI Cushing Oklahoma 40° API	Edmonton Par Price 40° API	Cromer Medium 29.3° API	AECO - C Spot	Exchange Rate
	(US$/Bbl)	($CDN/Bbl)	($CDN/Bbl)	($CDN/MMBTU)	($US/$Cdn)
2004	41.38	52.96	45.75	6.88	0.769
2005	42.00	50.25	43.75	6.60	0.82
2006	40.00	47.75	41.50	6.35	0.82
2007	38.00	45.50	39.50	6.15	0.82
2008	36.00	43.25	37.75	6.00	0.82
2009	34.00	40.75	35.50	6.00	0.82
2010	33.00	39.50	34.25	6.00	0.82
2011	33.00	39.50	34.25	6.00	0.82
2012	33.00	39.50	34.25	6.00	0.82
2013	33.50	40.00	34.75	6.10	0.82

	Medium and Light Crude Oil			Natural Gas
Year	WTI Cushing Oklahoma 40° API	Edmonton Par Price 40° API	Cromer Medium 29.3° API	AECO - C Spot	Exchange Rate
	(US$/Bbl)	($CDN/Bbl)	($CDN/Bbl)	($CDN/MMBTU)	($US/$Cdn)
2014	34.00	40.75	35.50	6.20	0.82
2015	34.50	41.25	36.00	6.30	0.82

Escalated at 2.0% per year thereafter.

Future Development Costs

The table below sets out the total development costs deducted in the estimation in the APF Reports of future net revenue attributable to proved reserves (using both constant prices and costs and forecast prices and costs) and proved plus probable reserves (using forecast prices and costs only).

	Constant Prices and Costs	Forecast Prices and Costs
	Proved Reserves	Proved Reserves	Proved Plus Probable Reserves
	(M$)	(M$)	(M$)
2005	25,184	25,184	49,796
2006	8,594	8,766	18,598
2007	1,569	1,632	3,362
2008	624	663	910
2009	1,158	1,253	1,258
Remaining Years	5,172	6,617	7,779
Total Undiscounted	42,301	44,115	81,703
Total Discounted at 10% per year	35,949	36,634	70,632

Oil and Gas Properties

The following is a description of the major oil and natural gas properties comprising the APF Assets.

Southeast Saskatchewan

The Southeast Saskatchewan properties are located within 120 kilometres of the City of Estevan, Saskatchewan and are bounded by the US border to the south, the Manitoba border to the east and Weyburn, Saskatchewan to the west. The APF Assets include an average working interest of 32% in 275,388 (88,555 net) acres of land in this area.

Substantially all of the production is pipelined to company-owned central facilities including oil, gas and water separation and treating equipment, crude oil pipeline connection and salt water disposal facilities. Some facilities are connected to solution gas gathering facilities resulting in small quantities of solution gas sales. Some production is produced to single well batteries where oil and water are separated and trucked to company owned facilities for processing and sale.

For the year ended December 31, 2004, APF participated in drilling 19 (10.0 net) development oil wells and 1 (1.0 net) dry well. For the quarter ended March 31, 2005, 3 (0.6 net) development oil wells were drilled in the area.

Planned exploration and development activity in Southeast Saskatchewan for 2005 includes approximately $8.6 million for the drilling of 12 (7.9 net) wells and approximately $1.3 million for seismic programs, for an estimated total net cost of approximately $9.9 million.

Southern Alberta

The Southern Alberta properties are located approximately 350 kilometres south and southwest of the City of Calgary, Alberta and include the Robsart assets located in the southwest corner of Saskatchewan. The APF Assets include an average working interest of 46% in 704,589 (326,661 net) acres of land in this area.

APF’s facilities are comprised of a compressor and processing facility at Countess and several booster compressors. The compression facilities supply gas to pipelines for sales distribution.

For the year ended December 31, 2004, 1 (0.5 net) exploration wells and 113 (58.5 net) development wells were drilled in the area resulting in 101 (53.2 net) natural gas wells, 7 (1.6 net) oil wells and 1 (0.5 net) suspended well. For the quarter ended March 31, 2005, 1 (0.1 net) exploration well and 4 (0.7 net) development wells were drilled in the area resulting in 2 (0.2 net) natural gas wells, 3 (0.6 net) oil wells.

Planned exploration and development activity in Southern Alberta for 2005 includes approximately $8.0 million for the drilling of 46 (38.7 net) wells and approximately $2.0 million for seismic programs, for an estimated total net cost of approximately $10.0 million.

Central Alberta

The Central Alberta assets are generally located north of the City of Calgary and south of the City of Edmonton with the eastern most properties of Epping and Chauvin being located less than 50 kilometres from the Saskatchewan border. The APF Assets include an average working interest of 30% in 369,014 (109,066 net) acres of land in this area.

The APF Assets include a 41% working interest in a gas plant and a 74% working interest in a compressor facility at Joffre, Alberta, which serves as a gathering and processing point for natural gas produced by the Central Alberta properties. In addition, the APF Assets include various working interests in two Innisfail batteries.

For the year ended December 31, 2004, 10 (7.2 net) exploration wells and 7 (1.5 net) development wells were drilled in the area resulting in 16 (8.5 net) natural gas wells and 1 (0.2 net) oil well. For the quarter ended March 31, 2005, 10 (6.9 net) exploration wells were drilled in the area resulting in 3 (0.8 net) natural gas wells and 7 (6.1 net) oil wells.

Planned exploration and development activity for Central Alberta during 2005 includes approximately $11.4 million for the drilling of 33 (25.0 net) wells and approximately $1.0 million for seismic programs at an estimated total net cost of approximately $12.4 million.

Western Alberta

The Western Alberta assets are located north of the City of Edmonton, Alberta. The APF Assets include an average working interest of 45% in 531,464 (241,760 net) acres of land in this area

The APF Assets include working interests in batteries at several of its properties in this region, including Pembina, Paddle River and Sakwatamau. These facilities include gas plants, a gathering and inlet separator, compression and an acid gas injection battery.

For the year ended December 31, 2004, 12 (8.1 net) exploration wells and 15 (4.1 net) development wells were drilled in the area resulting in 13 (5.9 net) natural gas wells, 10 (0.6 net) oil wells, 1 (0.0 net) injection well and 3 (2.0 net) dry wells. For the quarter ended March 31, 2005, 1 (0.03 net) development oil well and 1 (0.6 net) dry well were drilled.

Planned exploration and development activity in Western Alberta for 2005 includes approximately $5.8 million for the drilling of 10 (3.2 net) wells and approximately $3.3 million for seismic programs, for an estimated total net cost of approximately $9.1 million.

Coalbed Methane

The coalbed methane (“CBM”) properties are primarily located at the Doris and Corbett properties northwest of Edmonton, Alberta with some additional prospects within its Southern Alberta holdings, proximate to the town of Stettler. The Doris and Corbett lands are included in the Western Alberta properties described above.

During 2004, 4 (0.79 net) exploration CBM wells and 5 (3.5 net) development CBM wells were drilled on the Western Alberta properties.

The APF Assets also include CBM production in the Powder River Basin, located north of Casper, Wyoming, USA. The APF Assets include a working interest of 47% in 31,014 (14,437 net) acres of land in Wyoming. During 2004, 79 (27.6 net) development CBM wells and 2 (1.7 net) injection wells were drilled on these properties. For the quarter ended March 31, 2005, 31 (7.1 net) development CBM wells were drilled on these properties.

Planned exploration and development activity for Wyoming during 2005 totals approximately $4.5 million for the drilling of 77 (31.7 net) wells.

Oil and Gas Wells

The following table sets forth the number and status of wells, effective March 31, 2005, in which the Trust acquired a working interest through the acquisition of the APF Assets.

	Producing Wells				Non-Producing Wells
	Oil		Natural Gas		Oil		Natural Gas
	Gross	Net	Gross	Net	Gross	Net	Gross	Net
Alberta	1,230	213.5	999	565.7	10	3.6	83	31.9
British Columbia	—	—	6	1.0	—	—	—	—
Saskatchewan	1,159	280.6	258	32.2	2	1.0	5	2.0
Wyoming	—	—	63	18.0	—	—	24	23.0
Total	2,389	494.1	1,326	616.9	12	4.6	112	56.9

Properties with no Attributed Reserves

The following table summarizes the gross and net acres of unproved properties, effective March 31, 2005, in which the Trust acquired a working interest through the acquisition of the APF Assets and also the number of net acres for which the Trust’s rights to explore, develop or exploit will, absent further action, expire within one year.

	Gross Acres	Net Acres	Net Acres Expiring Within One Year

Alberta	840,188	346,738	62,089
Saskatchewan	331,467	138,725	4,605
British Columbia	13,547	672	—
Manitoba	1,559	541	—
Wyoming	21,873	10,815	2,623
Total	1,208,634	497,491	69,317

Drilling Activity

The following table sets forth the gross and net exploratory and development wells drilled on the properties comprising the APF Assets during the year ended December 31, 2004.

	Exploratory Wells		Development Wells
	Gross	Net	Gross	Net
Oil	1	1.0	36	11.4
Natural Gas	16	7.7	193	85.9
Dry	2	1.0	2	2.0
Other	1	0.5	—	—
Total:	20	10.2	231	99.3

The following table sets forth the gross and net exploratory and development wells drilled on the properties comprising the APF Assets during the three months ended March 31, 2005.

	Exploratory Wells		Development Wells
	Gross	Net	Gross	Net
Oil	—	—	14	8.4
Natural Gas	3	1.7	33	6.4
Dry	1	0.6	—	—
Other	—	—	—	—
Total:	4	2.3	47	14.8

Additional Information Concerning Abandonment and Reclamation Costs

Well abandonment costs have been estimated area by area. Such costs are included in the APF Reports as deductions in arriving at future net revenue. The expected total abandonment costs included in the APF Reports for 1,463 net wells under the proved plus probable reserves category is $46.4 million undiscounted ($13.8 million discounted at 10%), of which a total of $4.0 million is estimated to be incurred in 2005, 2006 and 2007. This estimate does not include expected reclamation costs for surface leases of $56.3 million undiscounted ($5.3 million discounted at 10%).

Costs Incurred

	Property Acquisition Costs
	Proved Properties	Unproved Properties	Exploration Costs	Development Costs
Total (M$)	6,962	4,775	3,856	48,885

The following table summarizes capital expenditures (net of incentives and net of certain proceeds and including capitalized general and administrative expenses) incurred for the three months ended March 31, 2005 with respect to the APF Assets.

	Property Acquisition Costs
	Proved Properties	Unproved Properties	Exploration Costs	Development Costs
Total (M$)	111	1,396	2,546	14,640

Production Estimates

The following table discloses for each product type the total volume of production estimated by GLJ and Sproule in the APF Report for 2005 in the estimates of future net revenue from proved reserves disclosed above.

	Crude Oil	Natural Gas	Natural Gas Liquids	BOE	%
	(Bbls/d)	(Mcf/d)	(Bbls/d)	(BOE/d)
Alberta	2,902	46,396	788	11,423	69.8
Saskatchewan	4,164	2,537	5	4,592	28.1
British Columbia	—	126	—	21	0.1
Wyoming	—	1,950	—	325	2.0
Estimated Total Production	7,066	51,009	793	16,361	100

Production History

Average Daily Production Volume

	Three Months Ended
	Mar. 31, 2004	June 30, 2004	Sept. 30, 2004	Dec. 31, 2004	Mar. 31, 2005
Oil & NGL (Bbls/d)	8,766	8,390	8,657	8,803	8,128
Natural gas (Mcf/d)	51,209	53,785	52,994	52,585	52,009
Total (BOE/d)	17,301	17,354	17,490	17,567	16,796

Prices Received, Royalties Paid, Production Costs and Netback – Crude Oil and NGLs

	Three Months Ended
($ per Bbl)	Mar. 31, 2004	June 30, 2004	Sept. 30, 2004	Dec. 31, 2004	Mar. 31, 2005
Prices Received	36.85	39.92	42.57	40.13	44.95
Royalties Paid	7.07	7.61	9.47	8.36	9.05
Production Costs	11.71	11.20	11.55	10.87	10.18
Netback(1)	18.07	21.11	21.55	20.90	25.72

Note:

(1) Netback is calculated by deducting royalties paid and production costs from prices received.

Prices Received, Royalties Paid, Production Costs and Netback – Natural Gas

	Three Months Ended
($ per Mcf)	Mar. 31, 2004	June 30, 2004	Sept. 30, 2004	Dec. 31, 2004	Mar. 31, 2005
Prices Received	6.73	6.85	6.21	6.46	6.84
Royalties Paid	1.40	1.55	1.18	1.20	1.33
Production Costs	0.77	0.91	1.37	1.29	1.47
Netback(1)	4.56	4.39	3.66	3.97	4.04

Note:

(1) Netback is calculated by deducting royalties paid and production costs from prices received.

Production Volume by Field

The following table indicates the average daily production from the important fields comprising the APF Assets for the year ended December 31, 2004.

Business Units	Crude Oil	Natural Gas	Natural Gas Liquids	BOE	%
	(Bbls/d)	(Mcf/d)	(Bbls/d)	(BOE/d)
Coalbed Methane	—	1,095	—	183	1.1
Central Alberta	2,810	18,159	452	6,289	36.4
Southeast Saskatchewan	3,490	772	—	3,619	20.9
Southern Alberta	406	18,315	80	3,539	20.5
Western Alberta	988	13,724	378	3,653	21.1
Total	7,694	52,065	910	17,281	100

The following table indicates the average daily production from the important fields comprising the APF Assets for the three months ended March 31, 2005.

Business Units	Crude Oil	Natural Gas	Natural Gas Liquids	BOE	%
	(Bbls/d)	(Mcf/d)	(Bbls/d)	(BOE/d)
Coalbed Methane	—	1,384	—	231	1.4
Central Alberta	2,427	17,250	484	5,786	34.4
Southeast Saskatchewan	3,390	790	—	3,522	21.0
Southern Alberta	401	21,146	64	3,989	23.8
Western Alberta	1,008	11,439	354	3,269	19.5
Total	7,226	52,009	902	16,796	100

Financial Statements

Schedule “B” hereto contains audited annual financial statements for APF for the years ended December 31, 2004 and 2003 and unaudited comparative interim financial statements for the three months ended March 31, 2005. On June 4, 2004, APF acquired all of the issued and outstanding shares of Great Northern Exploration Ltd. Schedule “B” also contains audited annual financial statements for Great Northern Exploration Ltd. for the years ended December 31, 2003 and 2002 and unaudited comparative financial statements for the three months ended March 31, 2004. Finally, Schedule “B” contains unaudited pro forma combined financial statements for APF giving effect to the acquisition of Great Northern Exploration Ltd. by APF and the transfer by APF of the APF ExploreCo Assets to APF ExploreCo prior to the completion of the APF Combination.

EFFECT OF THE ENCANA ACQUISITION AND APF COMBINATION ON THE TRUST

Selected Pro Forma Financial Information

The following tables set out certain pro forma combined financial information for the EnCana Assets, the APF Assets and the Trust for the year ended December 31, 2004 and as at and for the three month period ended March 31, 2005 after giving effect to the Arrangement, the acquisition by the Trust of Selkirk Energy Partnership on January 28, 2005, the EnCana Acquisition, the APF Combination, the offering of 3,760,000 Trust Units completed on February 10, 2005 and the offering of 17,800,000 subscription receipts and $60,000,000 of debentures completed on May 26, 2005. The information provided below is qualified in its entirety by the unaudited pro forma combined financial statements attached as Schedule “C” hereto.

For the year ended December 31, 2004	Trust(1)		EnCana Assets(2)	APF Assets(1)		Pro Forma(3)
	($000’s)		($000’s)	($000’s)		($000’s)
Net petroleum and natural gas revenue(4)	99,904		95,897	204,386		400,187
Net earnings (loss)	5,379		77,971	47,515		85,876
Per unit (basic)	$	0.18	—	$	0.70	$	0.99
Per unit (diluted)	$	0.18	—	$	0.70	$	0.98

Note:

(1) Information is derived from the applicable audited financial statements and applicable unaudited pro forma financial statements.

(2) Information is derived from the applicable audited financial statements.

(3) Information is derived from the applicable unaudited pro forma financial statements.

(4) Before transportation expenses.

For the three months ended March 31, 2005	Trust(1)		EnCana Assets(2)	APF Assets(1)			Pro Forma(3)
	($000’s)		($000’s)	($000’s)			($000’s)
Net petroleum and natural gas revenue(4)	29,111		24,433	35,090			88,364
Net earnings (loss)	2,233		19,890	(2,776		)	3,358
Per unit (basic)	$	0.12	—	$	(0.04	)	$	0.04
Per unit (diluted)	$	0.11	—	$	(0.04	)	$	0.04
Total Assets	519,743		—	820,626			2,080,605
Total Liabilities	210,386		—	393,996			720,982
Net Equity	309,357		—	426,630			1,359,623

Note:

(1) Information is derived from the applicable unaudited financial statements and the applicable unaudited pro forma financial statements.

(2) Information is derived from the applicable unaudited financial statements.

(3) Information is derived from the applicable unaudited pro forma financial statements.

(4) Before transportation expenses.

Selected Combined Operational Information

The following tables set forth certain combined operational information after giving effect to the Arrangement, the acquisition by the Trust of Selkirk Energy Partnership on January 28, 2005, the EnCana Acquisition and the APF Combination.

Important information concerning the oil and natural gas properties and operations of the Trust is contained in the renewal annual information form of the Trust dated March 28, 2005. Important information concerning the oil and natural gas properties in respect of the EnCana Assets and the APF Assets is set forth herein under the headings “Information Concerning the EnCana Assets” and “Information Concerning the APF Assets”. Readers are encouraged to carefully review the renewal annual information form of the Trust and the information provided herein concerning the EnCana Assets and the APF Assets as the tables below provide a summary only.

	Trust	EnCana Assets	APF Assets	Pro Forma
Average Daily Production
(For the year ended December 31, 2004)
Crude oil & NGLs (Bbls/d)	6,553	6,008	8,604	21,165
Natural gas (Mcf/d)	17,111	5,202	52,065	74,378
Oil equivalent (BOE/d)	9,405	6,875	17,281	33,561
Average Daily Production
(For the three months ended March 31, 2005)
Crude oil & NGLs (Bbls/d)	6,666	5,933	8,128	20,727
Natural gas (Mcf/d)	16,416	5,742	52,009	74,167
Oil equivalent (BOE/d)	9,402	6,890	16,796	33,088
Net Proved Reserves(1)
Light/medium crude oil & NGLs (Mbbls)	8,193	7,003	17,528	32,724
Heavy crude oil (Mbbls)	2,701	7,070	1,567	11,338
Natural gas (MMcf)	27,128	7,713	94,761	129,602
Oil equivalent (MBOE)	15,415	15,359	34,889	65,662
Net Proved plus Probable Reserves(1)
Light/medium crude oil & NGLs (Mbbls)	15,030	11,481	23,708	50,219
Heavy crude oil (Mbbls)	3,671	8,395	2,536	14,602
Natural gas (MMcf)	45,786	11,175	124,454	181,415
Oil equivalent (MBOE)	26,332	21,739	46,986	95,057
Net Undeveloped Land(2)	186,726	38,170	497,491	722,387

Notes:

(1) Reserves information is at December 31, 2004, except with respect to the EnCana Assets which is at March 31, 2005, and is based on forecast prices and costs.

(2) As at March 31, 2005.

EFFECT ON OPERATIONS

In connection with the APF Combination, the Administrator assumed the employment of 49 employees formerly employed by APF.

The Trust and the Administrator are currently in the process of assessing the manner in which they will integrate the EnCana Assets and APF Assets into the operations and structure of the Trust. This assessment may lead the Trust and Administrator to determine that a reorganization of the Trust’s subsidiaries is required. The Trust does not anticipate that any such reorganization will have a material affect on the operations or financial position of the Trust.

PRIOR VALUATIONS

No valuation required by securities legislation or a Canadian stock exchange or market to support the consideration payable by the Trust pursuant to the EnCana Acquisition or the APF Combination has been obtained within the past 12 months by the Trust, EnCana or APF.

INFORMED PERSONS, ASSOCIATES AND AFFILIATES

No informed person, associate or affiliate of the Trust, as those terms are defined under applicable securities legislation, was a party to the EnCana Acquisition or the APF Combination.

SCHEDULE “A” - SCHEDULE OF REVENUES, ROYALTIES AND OPERATING EXPENSES FOR THE ENCANA ASSETS

A-1

EnCana Assets

Schedule of Revenues, Royalties and Operating Expenses

Years Ended December 31, 2004, 2003 and 2002

($ thousands)

	PricewaterhouseCoopers LLP
	Chartered Accountants
	111 5th Avenue SW, Suite 3100
	Calgary, Alberta
	Canada T2P 5L3
	Telephone +1 (403) 509 7500
	Facsimile +1 (403) 781 1825

April 29, 2005

Auditors’ Report

To the Directors of EnCana Corporation

At the request of EnCana Corporation, we have audited the schedule of revenues, royalties and operating expenses for the years ended December 31, 2004, 2003 and 2002 for the EnCana Assets. This financial information is the responsibility of management. Our responsibility is to express an opinion on this financial information based on our audits.

We conducted our audits in accordance with Canadian generally accepted auditing standards. Those standards require that we plan and perform an audit to obtain reasonable assurance whether the financial information is free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial information. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial information presentation.

In our opinion, the schedule of revenues, royalties and operating expenses present fairly, in all material respects, the revenues, royalties and operating expenses for the EnCana Assets for the years ended December 31, 2004, 2003 and 2002 in accordance with the basis of accounting disclosed in note 1.

Chartered Accountants

Calgary, Alberta

PricewaterhouseCoopers refers to the Canadian firm of PricewaterhouseCoopers LLP and the other member firms of PricewaterhouseCoopers International Limited, each of which is a separate and independent legal entity.

EnCana Assets

Schedule of Revenues, Royalties and Operating Expenses

($ thousands)

	Year Ended December 31,
	2004		2003		2002

Revenues	$	100,896	$	89,709	$	93,341
Royalties	4,999		5,345		4,785
	95,897		84,364		88,556

Operating expenses	17,926		17,741		16,274

Excess of revenues over operating expenses	$	77,971	$	66,623	$	72,282

See accompanying Notes to Schedule

EnCana Assets

Notes to Schedule of Revenues, Royalties and Operating Expenses

Years Ended December 31, 2004, 2003 and 2002

1. Basis of presentation

The schedule of Revenues, Royalties and Operating Expenses includes the operating results relating to the EnCana Assets. The results have been compiled on an activity month basis.

The EnCana Assets consist of crude oil and natural gas assets which have been offered for sale and are located in East Central Alberta (Provost Battery 1 and Hayter) and South East Alberta (Alderson East, Alderson Kininvie, Countess and Suffield West).

The Schedule of Revenues, Royalties and Operating Expenses for these properties does not include any provision for the depletion and depreciation, asset retirement costs, future capital costs, impairment of unevaluated properties, administrative costs and income taxes for these properties as these amounts are based on the consolidated operations of the vendor of which these properties form only a part.

2. Significant accounting policies

(A) Joint Venture Operations

Substantially all of the EnCana Assets are operated through joint ventures therefore the schedules reflect only the vendor’s proportionate interest.

(B) Revenue Recognition

Revenues are recorded net of related transportation costs when the product is delivered. Gas revenues are based on AECO pricing references used for sales between EnCana operating divisions and do not reflect ultimate marketing related activities. Oil revenues are based on blended prices established by EnCana marketing for similar product delivered to a common carrier.

(C) Royalties

Royalties are recorded at the time the product is produced and sold. Royalties are calculated in accordance with the applicable regulations and/or the terms of individual royalty agreements. Gas crown royalties are based on the Alberta Government posted reference prices. Oil crown royalties are taken in kind by the Government of Alberta. The annual adjustment relating to gas cost allowance is recorded when received.

(D) Operating Expenses

Operating expenses include amounts incurred on extraction of product to the surface, gathering, field processing, treating and field storage.

EnCana Assets

Schedule of Revenues, Royalties and Operating Expenses

Three Months Ended March 31, 2005 and 2004 (unaudited)

($ thousands)

EnCana Assets

Schedule of Revenues, Royalties and Operating Expenses

($ thousands)

	Three Months Ended March 31,
	2005		2004

Revenues	$	25,596	$	21,308
Royalties	1,163		989
	24,433		20,319

Operating expenses	4,543		4,189

Excess of revenues over operating expenses	$	19,890	$	16,130

See accompanying Notes to Schedule

EnCana Assets

Notes to Schedule of Revenues, Royalties and Operating Expenses

Three Months Ended March 31, 2005 and 2004 (unaudited)

1. Basis of presentation

The schedule of Revenues, Royalties and Operating Expenses includes the operating results relating to the EnCana Assets. The results have been compiled on an activity month basis.

2. Significant accounting policies

(A) Joint Venture Operations

Substantially all of the EnCana Assets are operated through joint ventures therefore the schedules reflect only the vendor’s proportionate interest.

(B) Revenue Recognition

(C) Royalties

(D) Operating Expenses

Operating expenses include amounts incurred on extraction of product to the surface, gathering, field processing, treating and field storage.

SCHEDULE “B” - FINANCIAL STATEMENTS OF APF

B-1

CONSOLIDATED BALANCE SHEETS (unaudited)

($000)	March 31, 2005		December 31, 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		Donald Engle
Director		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 (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 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

($000)	Liability Component		Equity 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:

Trust Unit Rights	Rights (000)		March 31, 2005 Weighted Average Price ($)		Rights (000)		December 31, 2004 Weighted Average Price ($)
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.

	PricewaterhouseCoopers LLP
	Chartered Accountants
	111 5th Avenue SW, Suite 3100
	Calgary, Alberta
	Canada T2P 5L3
	Telephone +1 (403) 509 7500
	Facsimile +1 (403) 781 1825

AUDITORS’ REPORT

To the Unitholders of APF Energy Trust

We have audited the consolidated balance sheets of APF Energy Trust as at December 31, 2004 and 2003 and the consolidated statements of operations and accumulated earnings and cash flows for the years then ended. These financial statements are the responsibility of the Trust’s management. Our responsibility is to express an opinion on these financial statements based on our audits.

We conducted our audits in accordance with Canadian generally accepted auditing standards. Those standards require that we plan and perform an audit to obtain reasonable assurance whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation.

In our opinion, these consolidated financial statements present fairly, in all material respects, the financial position of the Trust as at December 31, 2004 and 2003 and the results of its operations and its cash flows for the years then ended in accordance with Canadian generally accepted accounting principles.

Calgary, Alberta
February 25, 2005	Chartered Accountants

CONSOLIDATED BALANCE SHEET

($000s except for per unit amounts)

As at December 31	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	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	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

NOTE 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.

NOTE 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 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.

NOTE 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 majoriity 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’ 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.

NOTE 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

NOTE 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

NOTE 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.

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:

			Foreign
Year	WTI Oil		Exchange	WTI Oil		AECO Gas
	($U.S./bbl)		($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

NOTE 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.

($000)	Deferred derivative loss recognized on transition	Total realized gain/(loss)		Total 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:

($000)	Total unrealized 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:

($000)	Unrealized asset (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:

	Type of	Average	Average daily
Period	commodity	contract	daily quantity	Price per bbl, GJ or 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 March 2005	Crude oil	Sold call	500 bbls	$U.S. 42.37 ($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 June 2005	Crude oil	Sold call	500 bbls	$U.S. 40.95 ($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 March 2005	Natural gas	Sold call	5,000 GJ	$Cdn. 11.80
January to March 2005	Natural gas	Collar	5,000 GJ	$Cdn. 7.00 to $Cdn. 11.35
April to October 2005	Natural gas	Collar	5,000 mmbtu	$U.S. 6.50 to $U.S. 6.90
April to October 2005	Natural 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:

Term	Type of Contract	Amount ($U.S. 000)	Exchange rate ($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

NOTE 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).

NOTE 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
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 noncapital 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).

NOTE 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:

($000)	Liability component		Equity 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

NOTE 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.

NOTE 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 elect 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		5,333	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 2003, 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

NOTE 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 replaced in 2001 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
Trust unit options	Options (000)		Weighted average price ($)	Options (000)		Weighted average price ($)
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
Range	Weighted average remaining contractual life (years)	Options outstanding (000)	Weighted average exercise price ($)	Options exercisable (000)	Weighted average exercise price ($)
7.00 to 7.99	0.18	1	7.15	1	7.15
8.00 to 8.99	0.68	—	8.85	—	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
Trust unit rights	Rights (000)		Weighted average price ($)		Rights (000)		Weighted average price ($)
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
Range	Weighted average remaining contractual life (years)	Rights outstanding (000)	Weighted average exercise price ($)	Rights exercisable (000)	Weighted average exercise price ($)
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 2, 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.

NOTE 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

NOTE 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
Derivatives liabilities	386		—
	(10,473	)	5,823

NOTE 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

AUDITORS’ REPORT TO THE SHAREHOLDERS

We have audited the balance sheets of Great Northern Exploration Ltd. as at December 31, 2003 and 2002 and the statements of operations and retained earnings and cash flows for the years then ended. These financial statements are the responsibility of the company’s management. Our responsibility is to express an opinion on these financial statements based on our audits.

We conducted our audits in accordance with Canadian generally accepted auditing standards. Those standards require that we plan and perform an audit to obtain reasonable assurance whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation.

In our opinion, these financial statements present fairly, in all material respects, the financial position of the company as at December 31, 2003 and 2002 and the results of its operations and its cash flows for the years then ended in accordance with Canadian generally accepted accounting principles.

(Signed) “KPMG LLP”

Chartered Accountants
Calgary, Canada

March 17, 2004

CONSOLIDATED FINANCIAL STATEMENTS

CONSOLIDATED BALANCE SHEET

As at December 31,		2003	2002
		$	$
ASSETS

*Current assets*

Accounts receivable		12,456,000	5,192,000
Prepaid expenses		609,000	382,000
		13,065,000	5,574,000
Property and equipment	(note 5)	120,491,000	34,789,000
		133,556,000	40,363,000

LIABILITIES AND SHAREHOLDERS’ EQUITY

*Current liabilities*

Accounts payable		19,754,000	10,656,000
Bank debt	(note 6)	38,555,000	5,107,000
		58,309,000	15,763,000
Future income taxes	(note 11)	8,097,000	—
Future site restoration	(note 7)	630,000	136,000
		67,036,000	15,899,000
*Shareholders’ equity*
Share capital	(note 8)	54,281,000	22,866,000
Contributed surplus	(note 3)	136,000
Retained earnings		12,103,000	1,598,000
		66,520,000	24,464,000
Subsequent events	(note 14)	133,556,000	40,363,000

On behalf of the Board of Directors:

James M. Saunders

Director

Warren Steckley

Director

(See accompanying notes to the consolidated financial statements)

CONSOLIDATED STATEMENT OF OPERATIONS AND RETAINED EARNINGS

Year ended December 31,		2003		2002
		$		$
*Revenue*

Petroleum and natural gas sales		51,317,000		12,170,000
Royalties, net		(9,928,000	)	(1,965,000	)
		41,389,000		10,205,000

*Expenses*

Operating		9,617,000		2,626,000
General and administrative		1,363,000		938,000
Financial charges		1,172,000		220,000
Depletion and depreciation		12,021,000		2,848,000
		24,173,000		6,632,000
*Earnings before taxes*		17,216,000		3,573,000

Capital taxes		306,000		116,000
Future income taxes	(note 11)	6,405,000		1,663,000
		6,711,000		1,779,000

*Net earnings*		10,505,000		1,794,000

*Retained earnings (deficit) , beginning of year*		1,598,000		(196,000	)
*Retained earnings , end of year*		12,103,000		1,598,000
*Net earnings per share*
Basic		0.30		0.08
Diluted		0.29		0.07

(See accompanying notes to the consolidated financial statements)

MANAGEMENT’S DISCUSSION A N D ANALYSIS

CONSOLIDATED STATEMENT OF CASH FLOW

Year ended December 31,		2003		2002
		$		$
*Cash flow related to the following activities*

Operating
Net earnings for the period		10,505,000		1,794,000
Items not affecting cash:
Depletion and depreciation		12,021,000		2,848,000
Stock-based compensation	(note 3)	136,000		—
Future income taxes		6,405,000		1,663,000
Cash flow from operations		29,067,000		6,305,000
Changes in non-cash operating working capital items		3,717,000		(706,000	)
		32,784,000		5,599,000

*Financing*

Change in bank debt		33,448,000		(8,888,000	)
Share issuance, net		33,106,000		4,276,000
		66,554,000		(4,612,000	)
*Cash available for investment activities*		99,338,000		987,000

*Investing*

Property and equipment additions		(96,880,000	)	(13,602,000	)
Site restoration expenditures		(348,000	)	—
Changes in non-cash investing working capital items		(2,110,000	)	4,401,000
		(99,338,000)		(9,201,000	)
*Change in cash*		—		(8,214,000	)

*Cash, beginning of year*		—		8,214,000
*Cash, end of year*		—		—

(See accompanying notes to the consolidated financial statements)

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

YEAR ENDED DECEMBER 31, 2003

(tabular amounts in thousands of dollars, unless otherwise stated)

1. NATURE OF OPERATIONS

The shareholders of Great Northern Exploration Ltd. (“the Company”), approved a name change from Ascot Energy Resources Ltd. (“Ascot”) and a share consolidation on the basis of one new share for every five existing common shares at the Annual and Special Meeting held on September 26, 2002. All share data including number of common shares outstanding, per share data and stock options outstanding have been adjusted to reflect the share consolidation.

On July 10, 2002, the Company acquired all the shares of Great Northern Exploration Ltd. (“Great Northern”), a private corporation. Great Northern was incorporated on August 9, 2001 and commenced active operations in September 2001.

The transaction has been accounted for as a reverse takeover of the Company by Great Northern. Accordingly, the results of operations for 2002 include those of Great Northern from the date of incorporation and those of the Company from the date of the acquisition to December 31, 2002.

The Company is engaged primarily in the exploration for and development and production of petroleum and natural gas in Western Canada.

2. SIGNIFICANT ACCOUNTING POLICIES

a) Basis of Presentation

The consolidated financial statements include the accounts of Great Northern Exploration Ltd. (the “Company”) and its wholly owned subsidiaries.

The Company’s financial statements have been prepared in accordance with Canadian generally accepted accounting principles and reflect the following policies:

b) Petroleum and Natural Gas Operations

I) CAPITALIZED COSTS

The Company follows the full cost method of accounting for petroleum and natural gas operations whereby all costs of exploring for and developing oil and gas properties and related reserves are capitalized into a single Canadian cost center. Costs include land acquisition costs, geological and geophysical expenditures, costs of drilling both productive and non-productive wells, well equipment and certain other overhead expenditures related to exploration.

Gains or losses on the sale or disposition of oil and gas properties are not ordinarily recognized except under circumstances which result in a significant revision of depletion rates.

II) DEPLETION AND DEPRECIATION

Petroleum and natural gas properties and related equipment, excluding undeveloped properties, are depleted and depreciated using the unit-of-production method based on estimated gross proved reserves. For purposes of this calculation, petroleum and natural gas reserves are converted at the energy equivalent conversion rate of six thousand cubic feet of natural gas to one barrel of crude oil. In determining its depletion base, the Company includes estimated future costs to be incurred in developing proved reserves and excludes salvage values and the cost of unproved properties. Costs of acquiring and evaluating unproved properties are excluded from the depletion base until it is determined whether proved reserves are attributable to the properties or impairment occurs.

III) CEILING TEST

In applying the full-cost method, the Company calculates a “ceiling test” to capitalized costs to ensure that such costs do not exceed future net revenues from estimated production of proven reserves, using prices and costs in effect at the Company’s year end, less administrative, financing, site restoration and abandonment, and income tax expenses, plus the costs of unproven properties. Any reduction in value as a result of the ceiling test is charged to operations as an element of depletion and depreciation expense. Undeveloped land is evaluated for impairment at each balance sheet date.

c) Joint Ventures

Substantially all of the Company’s exploration and development activities are conducted jointly with others and, accordingly, the financial statements reflect only the Company’s proportionate interest in such activities.

d) Flow-through Shares

The Company from time to time issues flow-through shares. Under these financing agreements, shares are issued at a fixed price with the resultant proceeds used to fund exploration and development work within a defined time period. The exploration and development expenditures funded by flow-through arrangements are renounced to investors in accordance with the appropriate tax legislation. A future tax liability is recorded and share capital is reduced by the estimated tax benefits transferred to shareholders.

e) Future Site Restoration and Abandonment Costs

Estimated future costs relating to site restoration and abandonment of petroleum and natural gas properties and related facilities
are accrued on a unit of production basis over the estimated life of the proved reserves. Costs are based on engineering estimates, net of expected recoveries, based upon current prices and in accordance with current legislation, technology and industry standards.

f) Future Income Taxes

Income taxes are calculated using the liability method of tax allocation. Temporary differences arising from the difference between the tax basis of an asset or liability and its carrying amount on the balance sheet are used to calculate future income tax liabilities or assets. The effect on future income tax liabilities or assets of a change in tax rates is recognized in net income in the period in which the change occurs.

g) Stock-Based Compensation Plan

The Company has a stock-based compensation plan which is described in note 9. As of January 1, 2003, the Company adopted a new accounting standard on stock-based compensation. Stock option expense is recorded as general and administrative expense for all options granted on or after January 1, 2003, with a corresponding increase recorded to contributed surplus. The expense related to options issued during 2002 is disclosed as proforma information in note 9.

The fair value of options granted are estimated at the date of the grant using the Black-Scholes valuation model. Upon the exercise of the stock options, consideration paid by employees or directors together with the amount previously recognized in contributed surplus, is credited to share capital.

h) Per Share Amounts

Per share amounts are calculated on the basis of the weighted average number of common shares outstanding during the period.

The treasury stock method of calculating diluted per share amounts is used whereby any proceeds from the exercise of stock options or other dilutive instruments are assumed to be used to purchase common shares at the average market price during the period.

i) Revenue Recognition

Petroleum and natural as sales are recognized as revenue at the time the respective commodities are delivered to purchasers.

j) Financial Instruments

Settlement of crude oil and natural gas swap agreements, which have been arranged as a hedge against commodity price, are reflected in revenues at the time of sale of the related hedged production.

k) Measurement Uncertainty

The amount recorded for depletion and depreciation of property and equipment, the provision for site restoration costs and the ceiling test calculation are based upon estimates of gross proved reserves, production rates, crude oil and natural gas prices, future costs and other relevant assumptions. By their nature, these estimates are subject to measurement uncertainty, and the impact on the financial statements of future periods could be material.

3. CHANGE IN ACCOUNTING POLICY

Stock -Based Compensation Plan

In September 2003, the Canadian Institute of Chartered Accountants (“CICA”) amended Handbook Section 3870 - “Stock-based Compensation and Other Stock-based Payments”. Pursuant to new transitional rules approved by the CICA, the Company early adopted the amended standard on a prospective basis and now records stock-based compensation expense in the Consolidated Statement of Operations for all common share options granted to employees and directors on or after January 1, 2003. As a result of adopting this amended standard, net earnings for the year ended December 31, 2003 decreased by $136 thousand and contributed surplus increased by an equal amount.

Common share options granted prior to January 1, 2003 do not result in a compensation expense and the Company continues to disclose the proforma earnings impact of related stock-based compensation expense for these options (note 9).

4. BUSINESS COMBINATION

On July 10, 2002, the business transaction between Ascot and Great Northern was formally approved. This reverse takeover by Great Northern of Ascot resulted in Ascot issuing 6.5 common shares for each 1 share of Great Northern in which there were 14,052,000 Great Northern common shares issued and outstanding. Total shares issued pursuant to the business transaction were 91,338,000 or 18,267,600 common shares after the above mentioned share consolidation.

The Company acquired all of the shares of Great Northern and has accounted for the transaction as an acquisition of the Company by Great Northern.

	$
Net assets acquired
Property and equipment	20,573
Working capital	626
Future income tax asset	3,215
Long-term debt	(13,995	)
Transaction costs	(2,167	)
Purchase price - common share equity value	8,252

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

5. PROPERTY, PLANT AND EQUIPMENT

			Accumulated
			Depletion and		Net
2003	Cost		Depreciation		Book Value
	$		$		$
Petroleum and natural gas properties		134,644		14,219		120,425
Office equipment	88		22		66
	134,732		14,241		120,491

			Accumulated
			Depletion and		Net
2002	Cost		Depreciation		Book Value
	$		$		$
Petroleum and natural gas properties		37,457		2,702		34,755
Office equipment	47		13		34
	37,504		2,715		34,789

The Company has capitalized, as part of petroleum and natural gas properties, indirect exploration overhead relating to property acquisition, exploration and development activities of $553 thousand for the year ended December 31, 2003 (2002 - $147 thousand).

Undeveloped land costs of $9.4 million (2002 - $6.0 million) have been excluded from the amount subject to depletion and depreciation.

6. CREDIT FACILITIES

	2003	2002
	$	$
Prime rate advances	8,555	107
Bankers’ acceptances	30,000	5,000
	38,555	5,107

Subsequent to December 31, 2003, the Company amended its demand revolving credit facility to a maximum of $70 million. The credit facility bears interest at the lenders’ prime rate or at the Bankers’ Acceptance rate plus a stamping fee of 1.25%. The $70 million borrowing base is subject to a semi-annual and annual review by the lender. The credit facility is secured by a first fixed and floating charge debenture in the amount of $100 million covering all the Company’s assets.

7. SITE RESTORATION AND ABANDONMENTS

At December 31, 2003, total future removal and site restoration costs to be accrued over the life of the remaining proved reserves were estimated, net of recoveries, at $7.7 million (2002 - $2.1 million) of which $630 thousand (2002 - $136 thousand) has been accrued. This estimate is subject to change based on amendments to environmental laws and as new information concerning operations becomes available.

8. SHARE CAPITAL

a ) Authorized

Unlimited number of common voting shares

Unlimited number of preferred shares, issuable in series

b) Issued

	Number of
	Shares	Amount
		$
Balance, December 31, 2001	17,065,100	11,890
Issued for cash	1,202,500	550
Acquisition of Ascot Energy Resources Ltd.	10,726,182	8,252
Exercise of stock options	110,500	85
Flow-through shares issued	1,379,400	4,000
Tax benefit renounced to shareholders	—	(1,705	)
Share issue costs, net of tax effect	—	(206	)
Balance, December 31, 2002	30,483,682	22,866
Issued on private placement	4,000,000	13,800
Issued on private placement	3,750,000	15,000
Exercise of stock options	125,000	142
Flow-through shares issued	1,100,000	6,050
Tax benefit renounced to shareholders	—	(2,456	)
Share issue costs, net of future tax	—	(1,121	)
Balance, December 31, 2003	39,458,682	54,281

In December 2003, 1,100,000 flow-through common shares were issued at a price of $5.50 per share for gross proceeds of $6.1 million. Under the terms of the flow-through agreement, the Company is required to expend $6.1 million on qualifying crude oil and natural gas expenditures prior to December 31, 2004. As at December 31, 2003, the Company had incurred qualifying expenditures in the amount of $0.6 million.

9. STOCK-BASED COMPENSATION

The Company has implemented a Stock Option Plan for directors and employees. Options under the Plan vest over a four year period with 25% vesting upon each anniversary date of the grant. As of December 31, 2003, there were 3,001,250 common shares reserved for issuance to eligible participants. At December 31, 2003, 3,405,875 (2002 - 2,474,875) options with exercise prices between $0.77 and $4.55 were outstanding and exercisable at various dates to December 11, 2008. The exercise price of each option equals the market price of the Company’s common shares on the date of the grant.

The following tables summarize the information about the share options as at December 31:

			2003				2002
			Weighted				Weighted
			average				average
			exercise				exercise
Fixed Options	Shares		price		Shares		price
Outstanding at beginning of year	2,474,875		$	1.36	1,397,500		$	0.77
Granted	1,268,875		$	3.80	1,200,875		$	1.99
Exercised	(125,000	)	$	1.15	(110,500	)	$	0.77
Cancelled	(212,875	)	$	2.23	(13,000	)	$	0.77
Outstanding at end of year	3,405,875		$	2.22	2,474,875		$	1.36
Options exercisable at year end	637,000		$	1.01	232,375		$	0.77

	Options outstanding				Options exercisable
	Number				Number
	outstanding	Weighted	Weighted		exercisable	Weighted
	at	average	average		at	average
	December 31,	remaining	exercise		December 31,	exercise
Range of exercise prices	2003	life (years)	price		2003	price
$ 0.77 - $1.50	1,192,750	7.9	$	0.77	497,250	$	0.77
$ 1.85 - $2.20	975,225	8.5	$	2.01	139,750	$	1.87
$ 2.63 - $3.95	564,275	9.1	$	3.27	—	$	—
$ 4.00 - $4.55	673,625	8.8	$	4.22	—	$	—
	3,405,875		$	2.22	637,000	$	1.01

For options granted to employees from January 1, 2002 to December 31, 2002, the Company follows the settlement method of accounting. Since all options were granted with an exercise price equal to the market price at the date of the grant, no compensation cost has been charged to income at the time of the 2002 option grants. Had compensation cost for the Company’s stock options been determined based on the fair market value at the grant dates of the awards, the Company’s net earnings and net earnings per share for the year ended December 31, 2002 would have been the pro forma amounts indicated following:

	2003	2002
	$	$
Net earnings
As reported	10,505	1,794
Pro forma	10,345	1,750
Net earnings per common share - basic
As reported	0.30	0.08
Pro forma	0.30	0.08
Net earnings per common share - diluted
As reported	0.29	0.07
Pro forma	0.28	0.07

For options granted after January 1, 2003, the Company follows the fair value method (note 3).

The weighted average fair market value of options granted in the year ended December 31, 2003 are $1.39 per option. The fair market of each option granted was estimated on the date of grant using the Modified Black-Scholes option-pricing model with the following assumptions:

	2003		2002
Risk-free interest rate	4.50	%	4.00	%
Estimated hold period prior to exercise (years)	5		4
Volatility in the price of the Company’s common shares	38	%	44	%
Dividend per share	$0.00		$0.00

10. PER SHARE AMOUNTS

Basic per share amounts are calculated using the weighted average number of shares outstanding during the year.

In the calculation of diluted per share amounts, options under the stock option plan are assumed to have been converted or exercised on the later of the beginning of the year and the date granted. The treasury stock method assumes that proceeds received from the exercise of in-the-money stock options are used to repurchase common shares at the average market rate.

	2003	2002
Weighted average shares outstanding (thousands)
Basic	34,865	23,024
Diluted	36,318	24,016

11. INCOME TAXES

The provision for income tax differs from the result which would be obtained by applying the combined Federal and Provincial

statutory income tax rates to income before taxes. This difference results from the following:

	2003		2002
	$		$
Earnings (loss) before taxes	17,216		3,573
Statutory income tax rate	40.6	%	42.8	%
Expected income tax	6,990		1,529
Increase (decrease) resulting from:
Non-deductible crown charges	2,769		760
Resource allowance	(3,044	)	(597	)
Statutory rate adjustment	(310	)	(224	)
Other	—		23
Change in valuation allowance	—		172
Provision for taxes	6,405		1,663

The future income tax liability is comprised of temporary differences related to the following:

	2003		2002
	$		$
Property and equipment	(9,572	)	(928	)
Statutory tax rate adjustment	339		286
Future site restoration	201		44
Share issue	759		313
Non-capital losses	946		827
Valuation allowance	(770	)	(542	)
Future income taxes	8,097		—

12. SUPPLEMENTAL CASH FLOW INFORMATION

Changes in non-cash working capital:

	2003		2002
	$		$
Accounts receivable	(7,264	)	(3,187	)
Prepaid expenses	(227	)	509
Accounts payable	9,098		6,373
Changes in non-cash working capital	1,607		3,695
These changes relate to the following activities:
Operating activities	3,717		(706	)
Investing activities	(2,110	)	4,401
	1,607		3,695

Amounts paid during the year relating to interest expense and capital taxes are as follows:

	2003	2002
	$	$
Interest paid in the year	1,204	220
Capital taxes paid in the year	210	—
	1,414	220

13. FINANCIAL INSTRUMENTS

The Company is exposed to fluctuations in commodity prices, interest rates and Canada/U.S. exchange rates. The Company, when appropriate, utilizes financial instruments to manage its exposure to these risks.

a) Commodity Price Risk Management

Financial instruments are entered into by the Company to protect the downside prices received on the sale of a portion of its crude oil and natural gas production. The agreements entered into are forward transactions providing the Company with a range of fixed prices on the commodities sold. Petroleum and natural gas revenue for the year ended December 31, 2003 include losses of $1.7 million (2002 - $133 thousand loss) on those transactions.

The following contracts were outstanding as at December 31, 2003:

Commodity	Type	Term	Volume	Price	Index

Natural gas	Fixed	January 2004 - March 2004	6,000 GJ’s/d	$6.57/GJ	AECO
Crude oil	Fixed	January 2004 - March 2004	600 bbls/d	US $28.70/bbl	WTI
Crude oil	Fixed	April 2004 - June 2004	600 bbls/d	US $27.50/bbl	WTI
Crude oil	Fixed	July 2004 - September 2004	400 bbls/d	US $28.25/bbl	WTI
Crude oil	Fixed	October 2004 - December 2004	300 bbls/d	US $27.30/bbl	WTI

The estimated fair value at December 31, 2003 of these transactions, had the contracts been settled at that time, would be a loss of $487 thousand.

b) Credit Risk Management

The Company has estimated that the fair value of its financial instruments, which include accounts receivable, accounts payable and accrued liabilities, and long-term debt, approximate their carrying values.

The majority of the Company’s accounts receivable are with other companies in the oil and gas industry and are subject to normal industry credit risk.

14. SUBSEQUENT EVENTS

On January 22, 2004, the Company acquired crude oil and natural gas assets that produce approximately 580 barrels of oil equivalent per day of production for approximately $23 million. The acquisition included working interests in existing Company operated producing properties, gas processing facilities, infrastructure and undeveloped land.

As a result of completion of the above mentioned acquisition, the Company renegotiated its credit facilities as described in note 6.

On February 2, 2004, the Company issued 4,250,000 common shares at a price of $4.50 per share for gross proceeds of $19.1
million.

GREAT NORTHERN EXPLORATION LTD.
CONSOLIDATED BALANCE SHEET

	March 31, 2004	December 31, 2003 (Restated - note 3)
	(unaudited)	$
	$
ASSETS

Current assets
Accounts receivable	11,473,000	12,456,000
Prepaid expenses	546,000	609,000
	12,019,000	13,065,000
Property and equipment (note 4)	160,448,000	125,718,000

	172,467,000	138,783,000

LIABILITIES AND SHAREHOLDERS’ EQUITY

Current liabilities
Accounts payable	21,916,000	19,754,000
Bank debt (note 5)	45,596,000	38,555,000
	67,512,000	58,309,000
Future income taxes	9,641,000	8,097,000
Asset retirement obligations (note 8)	7,866,000	6,923,000
	85,019,000	73,329,000

Shareholders’ equity
Share capital (note 6)	72,859,000	54,281,000
Contributed surplus	251,000	136,000
Retained earnings	14,338,000	11,037,000
	87,448,000	65,454,000

Subsequent event (note 10)
	172,467,000	138,783,000

(See accompanying notes to the consolidated financial statements)

GREAT NORTHERN EXPLORATION LTD.

CONSOLIDATED STATEMENT OF OPERATIONS AND RETAINED EARNINGS

Three months ended March 31,	2004			2003 (Restated - note 3)
	(unaudited)
	$			$
Revenue
Petroleum and natural gas sales	19,529,000			8,895,000
Royalties, net	(3,909,000		)	(2,019,000		)
	15,620,000			6,876,000

Expenses
Operating	3,892,000			1,367,000
General and administrative	304,000			324,000
Financial charges	538,000			51,000
Depletion, depreciation and accretion (note 8)	5,591,000			1,531,000
	10,325,000			3,273,000

Earnings before taxes	5,295,000			3,603,000
Capital taxes	94,000			29,000
Future income taxes	1,900,000			1,402,000
	1,994,000			1,431,000

Net earnings	3,301,000			2,172,000

Retained earnings, beginning of period	12,103,000			1,598,000

Retroactive application of change in accounting policy (note 3(b))	(1,066,000		)	(390,000		)

Retained earnings, end of period	14,338,000			3,380,000

Net earnings per share
Basic	$	0.08		$	0.07
Diluted	$	0.08		$	0.07

(See accompanying notes to the consolidated financial statements)

GREAT NORTHERN EXPLORATION LTD.
CONSOLIDATED STATEMENT OF CASH FLOW


Three months ended March 31,	2004		2003 (Restated - note 3)
	(unaudited)
	$		$
Cash flow related to the following activities

Operating
Net earnings for the period	3,301,000		2,337,000
Items not affecting cash:
Depletion, depreciation and accretion	5,591,000		1,366,000
Future income taxes	1,900,000		1,402,000
Stock-based compensation	115,000		—

Cash flow from operations	10,907,000		5,105,000

Changes in non-cash operating working capital items	520,000		1,584,000
	11,427,000		6,689,000
Financing
Change in bank debt	7,041,000		3,971,000
Share issuance, net	18,222,000		32,000
	25,263,000		4,003,000

Cash available for investment activities	36,690,000		10,692,000

Investing
Property and equipment additions	(39,290,000	)	(8,974,000	)
Site restoration expenditures	(88,000	)	(41,000	)
Changes in non-cash investing working capital items	2,688,000		(1,677,000	)
	(36,690,000	)	(10,692,000	)

Change in cash	—		—

Cash, beginning of period	—		—

Cash, end of period	—		—

(See accompanying notes to the consolidated financial statements)

GREAT NORTHERN EXPLORATION LTD.

SELECTED NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

THREE MONTHS ENDED MARCH 31, 2004

(unaudited)

(tabular amounts in thousands of dollars, unless otherwise stated)

1. NATURE OF OPERATIONS

The Company is engaged primarily in the exploration for and development and production of petroleum and natural gas in Western Canada.

2. SIGNIFICANT ACCOUNTING POLICIES

a) Basis of Presentation

The consolidated financial statements include the accounts of Great Northern Exploration Ltd. (the “Company”) and its wholly-owned subsidiaries.

The interim consolidated financial statements and the notes thereto of the Company have been prepared following the same accounting policies and methods of computation as the audited consolidated financial statements of the Company as at December 31, 2003 except as disclosed in note 3. These interim consolidated financial statements should be read in conjunction with the Company’s audited consolidated financial statements and notes thereto for the year ended December 31, 2003.

3. CHANGE IN ACCOUNTING POLICY

a) Full Cost Accounting Guideline

In January 2004, the Company adopted Accounting Guideline 16 “Oil and Gas Accounting - Full Cost”, the new guideline issued by the Canadian Institute of Chartered Accountants (“CICA”) which replaces Accounting Guideline 5, “Full Cost Accounting in the Oil & Gas Industry”.

The recoverability of a cost center is tested by comparing the carrying value of the cost center to the sum of the undiscounted cash flows expected from the cost center’s use and eventual disposition. If the carrying value is unrecoverable the cost center is written down to its fair value using the expected present value approach. This approach incorporates risks and uncertainties in the expected future cash flows which are discounted using a credit adjusted risk free rate.

Under Accounting Guideline 5, future net revenues for ceiling test purposes were based on proved reserves and were not discounted. Estimated future general and administrative costs and financing charges associated with future net revenues were deducted in arriving at the “ceiling”.

There were no charges to net income, property, plant and equipment or any other reported amounts in the consolidated financial statements as a result of adopting this guideline.

b) Asset Retirement Obligation

In January 2004, the Company adopted CICA Handbook Section 3110, “Asset Retirement Obligations”. This change in accounting policy has been applied retroactively with restatement of prior periods presented for comparative purposes.

The Company recognizes the fair value of its asset retirement obligation (“ARO”) in the period in which it is incurred and when a reasonable estimate of fair value can be made. The fair value of the estimated ARO is recorded as a long-term liability, with a corresponding increase in the carrying amount of the related asset. The capitalized amount is depleted on a unit-of-production basis over the life of the reserves. The liability amount is increased each reporting period due to the passage of time and the amount of accretion is charged to earnings in the period. Revisions to the estimated timing of cash flows or to the original estimated undiscounted cost would also result in an increase or decrease to the ARO. Actual costs incurred upon settlement of the ARO are charged against the ARO to the extent of the liability recorded. Any difference between the actual costs incurred upon settlement of the ARO and the recorded liability is recognized as a gain or loss in the Company’s earnings in the period in which the settlement occurs.

Previously, the Company recognized a provision for site restoration and abandonment costs calculated on the unit-of-production method over the life of the petroleum and natural gas properties based on total estimated proved reserves and the estimated future liability.

This change in accounting policy has been applied retroactively with restatement of prior periods presented for comparative purposes as follows:

Consolidated Balance Sheet as at December 31, 2003

	As Reported	Change		As Restated
	$	$		$
Assets
Property and equipment	120,491	5,227		125,718
Liabilities and shareholders’ equity Future site restoration	630	(630	)	—
Asset retirement obligations	—	6,923		6,923
Retained earnings	12,103	(1,066	)	11,037

Consolidated Statement of Operations and Retained Earnings for the Three Months ended March 31, 2003

	As Reported	Change		As Restated
	$	$		$
Depletion and depreciation	1,366	90		1,456
Accretion	—	75		75
Net earnings	2,337	(165	)	2,172

There was no impact on the Company’s cash flow as a result of adopting this new policy. See note 7 for additional information on the asset retirement obligation and the impact on the consolidated financial statements.

4. PROPERTY AND EQUIPMENT

	March 31, 2004
		Accumulated
		Depletion and	Net
	Cost	Depreciation	Book Value
	$	$	$

Petroleum and natural gas properties	180,938	20,549	160,389
Office equipment	92	33	59
	181,030	20,582	160,448

	December 31, 2003
		Accumulated
		Depletion and	Net
	Cost	Depreciation	Book Value
	$	$	$

Petroleum and natural gas properties	140,773	15,121	125,652
Office equipment	88	22	66
	140,861	15,143	125,718

The Company has capitalized, as part of petroleum and natural gas properties, indirect exploration overhead relating to property acquisition, exploration and development activities of $115 thousand for the three months ended March 31, 2004 (year ended December 31, 2003 - $553 thousand).

At March 31, 2004, undeveloped land costs of $9.4 million (December 31, 2003 - $9.4 million) have been excluded from the amount subject to depletion and depreciation.

5. CREDIT FACILITIES

	March 31,	December 31,
	2004	2003
	$	$

Prime rate advances	5,596	8,555
Bankers’ acceptances	40,000	30,000
	45,596	38,555

The Company has a demand revolving credit facility to a maximum of $70 million. The credit facility bears interest at the lenders’ prime rate or at the Bankers’ Acceptance rate plus a stamping fee of 1.25%. The $70 million borrowing base is subject to a semi-annual and annual review by the lender. The credit facility is secured by a first fixed and floating charge debenture in the amount of $100 million covering all the Company’s assets.

6. SHARE CAPITAL

a) Authorized

Unlimited number of common voting shares

Unlimited number of preferred shares, issuable in series

b) Issued

	Number of
	Shares	Amount
		$

Balance, December 31, 2002	30,483,682	22,866
Issued on private placement	4,000,000	13,800
Issued on private placement	3,750,000	15,000
Exercise of stock options	125,000	142
Flow-through shares issued	1,100,000	6,050
Tax benefit renounced to shareholders	—	(2,456	)
Share issue costs, net of future tax	—	(1,121	)
Balance, December 31, 2003	39,458,682	54,281

Issued on private placement	4,250,000	19,125
Exercise of stock options	6,250	12
Share issue costs, net of future tax	—	(559	)

Balance, March 31, 2004	43,714,932	72,859

Basic per share amounts are calculated using the weighted average number of shares outstanding during the year.

The reconciling items between the basic and diluted average common shares outstanding are outstanding stock options.

	Three months ended March 31,
	2004	2003
Weighted average shares outstanding (thousands)
Basic	42,173	30,499
Diluted	43,876	31,637

7. STOCK-BASED COMPENSATION

The Company has implemented a Stock Option Plan for directors and employees. Options under the Plan vest over a four year period with 25% vesting upon each anniversary date of the grant. As of March 31, 2004, there were 2,995,000 common shares reserved for issuance to eligible participants. At March 31, 2004, 3,423,375 (December 31, 2003 - 3,405,875) options with exercise prices between $0.77 and $4.60 were outstanding and exercisable at various dates to December 11, 2008. On April 6, 2004, 435,375 conditionally granted share options with an exercise price of $4.25 were cancelled. The exercise price of each option equals the market price of the Company’s common shares on the date of the grant.

The following tables summarize the information about the share options:

	Three months ended March 31, 2004				Year ended December 31, 2003
			Weighted				Weighted
			average				average
			exercise				exercise
Fixed Options	Shares		price		Shares		price

Outstanding at beginning of period	3,405,875		$	2.22	2,474,875		$	1.36
Granted	93,750		$	4.33	1,268,875		$	3.80
Exercised	(6,250	)	$	2.00	(125,000	)	$	1.15
Cancelled	(70,000	)	$	4.00	(212,875	)	$	2.23
Outstanding at end of period	3,423,375		$	2.24	3,405,875		$	2.22
Options exercisable at period end	682,750		$	1.12	637,000		$	1.01

Options outstanding					Options exercisable
	Number	Weighted			Number
	outstanding	average	Weighted		exercisable	Weighted
	at	remaining	average		at	average
Range of	March 31,	contractual	exercise		March 31,	exercise
exercise prices	2004	life (years)	price		2004	price

$ 0.77 - $1.50	1,192,750	7.7	$	0.77	500,500	$	0.77
$ 1.85 - $2.20	968,975	8.3	$	2.01	133,500	$	1.86
$ 2.63 - $3.95	564,275	8.7	$	3.27	48,750	$	2.66
$ 4.00 - $4.60	697,375	8.6	$	4.26	—	$	—
	3,423,375		$	2.24	682,750	$	1.12

	2003		2004 (Restated - note 3)

Net earnings
As reported	$	3,301	$	2,172
Pro forma	$	3,260	$	2,146

Net earnings per common share - basic
As reported	$	0.08	$	0.07
Pro forma	$	0.08	$	0.07

Net earnings per common share - diluted
As reported	$	0.08	$	0.07
Pro forma	$	0.07	$	0.07

For options granted after January 1, 2003, the Company follows the fair value method.

The weighted average fair market value of options granted in the year ended March 31, 2004 is $1.08 per option. The fair market of each option granted was estimated on the date of grant using the Modified Black-Scholes option-pricing model with the following assumptions:

	2004			2003

Risk-free interest rate	4.50		%	4.50		%
Estimated hold period prior to exercise (years)	5			5
Volatility in the price of the Company’s common shares	15		%	38		%
Dividend per share	$	0.00		$	0.00

8. ASSET RETIREMENT OBLIGATIONS

The Company’s asset retirement obligations are based on the Company’s net ownership in wells and facilities and management’s estimate of costs to abandon and reclaim those wells and facilities as well as an estimate of the future timing of the costs to be incurred.

The Company has estimated the present value of its total asset retirement obligations to be $7.9 million at March 31, 2004 based on a total future liability of $21.1 million. Payments to settle asset retirement obligations occur over the operating lives of the underlying assets, estimated to be from zero to 50 years, with the majority of costs incurred between 2010 and 2026. Estimated cash flows have been discounted at the Company’s credit-adjusted risk free rate of 8 percent and an inflation rate of 2.0 percent.

	Three months ended March 31,				Year ended December 31,
	2004		2003		2003

Asset retirement obligations, beginning of period	6,923		3,155		3,155
Liabilities incurred during period	879		699		3,626
Liabilities settled during period	(88	)	(41	)	(348	)
Accretion	152		75		490
Asset retirement obligations, end of period	7,866		3,888		6,923

9. FINANCIAL INSTRUMENTS

a) Commodity Price Risk Management

Financial instruments are entered into by the Company to protect the downside prices received on the sale of a portion of its crude oil and natural gas production. The agreements entered into are forward transactions providing the Company with a range of fixed prices on the commodities sold. Petroleum and natural gas revenue for the three months ended March 31, 2004 include losses of $0.2 million (2003 - $1.3 million loss) on those transactions.

The following contracts were outstanding as at March 31, 2004:

Commodity	Type	Term	Volume	Price	Index

Natural gas	Fixed	April 2004 - September 2004	4,000 GJ’s/d	$5.88/GJ	AECO
Natural gas	Fixed	October 2004 - December 2004	1,333 GJ’s/d	$5.88/GJ	AECO
Crude oil	Fixed	April 2004 - June 2004	600 bbls/d	US $27.50/bbl	WTI
Crude oil	Fixed	July 2004 - September 2004	600 bbls/d	US $29.17/bbl	WTI
Crude oil	Fixed	October 2004 - December 2004	600 bbls/d	US $28.70/bbl	WTI

The estimated fair value at March 31, 2004 of these transactions, had the contracts been settled at that time, would be a loss of $1.5 million.

10. SUBSEQUENT EVENT

Recent APF Offer

On April 7, 2004, APF Energy Inc., APF Energy Trust (collectively, the “Offeror”) and Great Northern announced that the Offeror had agreed to make an offer to acquire all of the outstanding common shares of Great Northern Exploration Ltd. and all common shares which may become outstanding on the exercise of the outstanding stock options, on the basis of, at the election of the holder, either:

a) $5.05 cash for each Common Share; provided that not more than $55.2 million in cash shall be payable in the aggregate under the Offer, with the balance being paid in trust units (“APF Units”) of APF Energy Trust at an exchange rate of 0.414614 Trust Units per Common Share (the “Cash Alternative”);

b) 0.414614 Trust Units for each GNEL Share (the “Trust Unit Alternative”); or

subject to the stated maximum, any combination thereof (the “Offer”) as more particularly described and upon the terms and subject to the conditions set forth in the “Offering Circular” dated April 26, 2004.

The Offer is scheduled to expire on June 1, 2004.

	PricewaterhouseCoopers LLP
	Chartered Accountants
	111 5th Avenue SW, Suite 3100
	Calgary, Alberta
	Canada T2P 5L3
Compilation Report	Telephone +1 (403) 509 7500
	Facsimile +1 (403) 781 1825

To the Directors of Starpoint Energy Trust

We have read the accompanying unaudited pro forma consolidated balance sheet as at March 31, 2005, as well as the consolidated statement of operations of APF Energy Trust (“APF”) for the three month period ended March 31, 2005 and the year ended December 31, 2004, and have performed the following procedures.

1. Compared the figures in the column captioned “APF Energy Trust” to the unaudited consolidated financial statements of APF for the three month period ended March 31, 2005 or the audited consolidated financial statements for the year ended December 31, 2004, and found them to be in agreement.

2. Compared the figures in the column captioned “Great Northern Exploration Ltd.” to the unaudited financial statements of the applicable entity for the five months ended May 31, 2004 and found them to be in agreement.

3. Made enquiries of certain officials of APF who had responsibility for financial and accounting matters (until APF was acquired by Starpoint Energy Trust in June 2005), as well as certain officials of Starpoint who have responsibility for financial and accounting matters about:

(a) the basis for determination of the pro forma adjustments; and

(b) whether the pro forma financial statements comply as to form in all material respects with Securities Acts of the various Provinces of Canada (the “Acts”).

The officials:

(a) described to us the basis for determination of the pro forma adjustments, and

(b) stated that the pro forma statements comply as to form in all material respects with the Acts.

4. Read the notes to the pro forma statements, and found them to be consistent with the basis described to us for determination of the pro forma adjustments.

5. Recalculated the application of the pro forma adjustments to the aggregate of the amounts in the column captioned “Pro Forma APF Energy Trust”, as at March 31, 2005, as well as the three month period ended March 31, 2005 and the year ended December 31, 2004 and found the amounts to be arithmetically correct.

A pro forma financial statement is based on management assumptions and adjustments which are inherently subjective. The foregoing procedures are substantially less than either an audit or a review, the objective of which is the expression of assurance with respect to management’s assumptions, the pro forma adjustments, and the application of the adjustments to the historical financial information. Accordingly, we express no such assurance. The foregoing procedures would not necessarily reveal matters of significance to the pro forma financial statements, and we therefore make no representation about the sufficiency of the procedures for the purposes of a reader of such statements.

Chartered Accountants
July 20, 2005
Calgary, Alberta

APF ENERGY TRUST

Pro Forma Consolidated Balance Sheet
As at March 31, 2005
(Unaudited)

			Rockyview		Pro Forma
			Adjustments		APF Energy
($000s except for per unit amounts)	APF Energy Trust		(note 2)		Trust

ASSETS
Current assets
Cash	1,299		—		1,299
Accounts receivable	45,321		—		45,321
Derivative asset	1,329		—		1,329
Other current assets	6,848		(55	)(d)	6,793
	54,797		(55	)	54,742
Asset retirement fund	3,475		—		3,475
Goodwill	118,478		—		118,478
Property, plant and equipment	683,690		(39,759	)(a)	643,931
	860,440		(39,814	)	820,626

LIABILITIES
Current liabilities
Accounts payable and accrued liabilities	48,712		—		48,712
Derivative liabilities	18,388		—		18,388
Distribution payable	9,591		—		9,591
	76,691		—		76,691
Future income taxes	76,819		4,028	(a)	80,847
Long-term debt	183,000		(24,455	)(c)	158,545
Convertible debentures	47,743		(1,861	)(d)	45,882
Asset retirement obligation	31,538		(811	)(a)	30,727
Derivative liabilities	1,304		—		1,304
	417,095		(23,099	)	393,996

UNITHOLDERS’ EQUITY
Unitholders’ investment account	622,274		(42,976	)(a)	605,922
			1,861	(d)
			318	(c)
			24,455	(c)
			45	(d)
			(55	)(d)

Contributed surplus	318		242	(c)	—
			(560	)(c)
Accumulated earnings	124,491		.		124,491
Accumulated distributions	(304,887	)	—		(304,887	)
Convertible debenture conversion feature	1,149		(45	)(d)	1,104
	443,345		(16,715	)	426,630
	860,440		(39,814	)	820,626

See accompanying notes to consolidated financial statements.

APF ENERGY TRUST

Pro Forma Consolidated Statement of Operations
For the year ended December 31, 2004
(unaudited)

($000s except for per unit amounts)	APF Energy Trust 12 months ended December 31, 2004		Great Northern Exploration five months ended May 31, 2004		Great Northern Exploration Adjustments (note 3)		Rockyview Adjustments (note 4)		Pro Forma APF Energy Trust

REVENUE
Oil and gas	253,213		35,607		—		(15,988	)(h)	272,832
Realized derivative loss - net	(16,329	)	(935	)	—		—		(17,264	)
Unrealized derivative loss - net	223		—		—		—		223
Royalties expense, net of ARTC	(47,710	)	(7,042	)	(208	)(v)	3,555	(h)	(51,405	)
Transportation	(5,245	)	—		—		—		(5,245	)
	184,152		27,630		(208	)	(12,433	)	199,141

EXPENSES
Operating	51,788		7,857		—		(2,681	)(h)	56,964
General and administrative	10,635		3,932		—		—		14,567
Interest on long-term debt	5,405		811		1,366	(ii)	(1,223	)(b)	6,359
Convertible debenture interest and financing charges	5,263		—		—		(205	)(c)	5,058
Depletion, depreciation and accretion	85,997		9,577		5,272	(i)	(7,356	)(g)	93,490
Unit-based compensation expense	(877	)	192		—		270	(e)	(415	)
Capital and other taxes	3,321		—		296	(iv)	(88	)(d)	3,529
	161,532		22,369		6,934		(11,283	)	179,552

Income / (loss) before income taxes	22,620		5,261		(7,142	)	(1,150	)	19,589

Provision for income taxes (recovery)
Current			200		(200)	(iv)	—		—
Future	(27,016	)	2,041		(2,607	)(iii)	(344	)(a)	(27,926	)

Net income / (loss) for period	49,636		3,020		(4,335	)	(806	)	47,515
Net income per unit - basic and diluted	1.02								0.70

APF ENERGY TRUST

Pro Forma Consolidated Statement of Operations
For the period ended March 31, 2005
(unaudited)

($000s except for per unit amounts)	APF Energy Trust 3 months ended March 31, 2005		Rockyview Adjustments (note 4)		Pro Forma APF Energy Trust

REVENUE
Oil and gas	73,191		(4,139	)(h)	69,052
Realized derivative loss - net	(2,735	)	—		(2,735	)
Unrealized derivative loss - net	(18,384	)	—		(18,384	)
Royalties expense, net of ARTC	(13,589	)	746	(h)	(12,843	)
Transportation	(1,449	)	—		(1,449	)
	37,034		(3,393	)	33,641

EXPENSES
Operating	14,852		(536	)(h)	14,316
General and administrative	3,528		—		3,528
Interest on long-term debt	1,836		(301	)(b)	1,535
Convertible debenture interest and financing charges	1,283		(50	)(c)	1,233
Depletion, depreciation and accretion	26,981		(2,059	)(g)	24,922
Unit-based compensation expense	35		242	(e)	277
Capital and other taxes	782		(80	)(d)	702
	49,297		(2,784	)	46,513

Income / (loss) before income taxes	(12,263	)	(609	)	(12,872	)

Provision for income taxes (recovery)
Current	—		—		—
Future	(9,892	)	(204	)(a)	(10,096	)

Net income / (loss) for period	(2,371	)	(405	)	(2,776	)
Net income per unit - basic and diluted	(0.04	)			(0.04	)

See accompanying notes to consolidated financial statements.

APF ENERGY TRUST

Notes to Pro Forma Consolidated Financial Statements

As at and for the period ended March 31, 2005 and the period ended December 31, 2004.

1. Basis of presentation:

The pro-forma consolidated financial statements of APF Energy Trust (the “APF Trust”), which owns a 99% interest in certain oil and gas royalties, have been prepared by management to give effect to the purchase of Great Northern Exploration Ltd. (“GNEL”) and to reflect the arrangement (the “Arrangement”) relating to the creation of Rockyview Energy Inc. (“Rockyview”), a public corporation concentrating on the exploration and development of oil and natural gas reserves. GNEL was involved in oil and gas exploration, development and production in western Canada. Pursuant to the Arrangement, APF Energy Inc (“APF Inc.”) transfered interests in certain oil and natural properties (the “Rockyview Assets”) to Rockyview. The arrangement was completed on June 27, 2005. These pro-forma consolidated financial statements do not include the effects of the merger with Starpoint Energy Trust (“Starpoint”).

The GNEL shares were purchased by APF Trust through a take-over bid, which closed June 4, 2004 (the “Acquisition”). The pro-forma consolidated financial statements of operations gives effect to the Acquisition and the Arrangement as if they occurred January 1, 2004.

Accounting policies used in the preparation of the pro forma financial statements are in accordance with those disclosed in APF Trust’s audited consolidated financial statements as at December 31, 2004 and for the year then ended and the unaudited interim Consolidated Financial Statements for the period ended March 31, 2005 (collectively, the “APF historical financial statements”). The pro forma statements have been prepared from information derived from and should be read in conjunction with the APF historical financial statements In the opinion of management, the pro forma statements include all necessary adjustments for a fair presentation of the ongoing entity.

Under the Arrangement, interests in certain oil and natural gas properties, formally owned by APF Inc. were transferred to Rockyview. As the former APF Trust unitholders are the controlling shareholder group of Rockyview, the assets and liabilities of Rockyview have been accounted for on a “continuity of interests” basis, and therefore no adjustment to carrying values of the assets and liabilities of APF Inc. transferred to Rockyview was required to account for the transaction. The revenues and operating expenses transferred to Rockyview have been derived from the schedule of revenue and expenses for the properties transferred to Rockyview.

The Trust is an open–ended investment trust under the laws of the Province of Alberta.

The royalty interests (the “Royalty”) in producing oil and natural gas properties acquired from APF Inc. and APF Energy Limited Partnership (collectively “APF”) effectively transfer 99% of the economic interest in such properties to the Unitholders. The Royalty constitutes a royalty interest in the oil and natural gas properties owned by APF but does not confer ownership in the underlying resource properties. APF is permitted to borrow funds to finance the purchase of additional properties and tangibles, for capital expenditures or for other financial obligations or encumbrances in respect of the properties should the properties not generate sufficient income to repay debt. The Trust is entitled to 99% of the production and incidental revenues from the properties less all costs and expenses in respect of the properties, taxes in respect of the properties, general and administrative costs of APF and the Royalty and debt service charges (including principal repayments). The Trust is required to reimburse APF for Crown royalties and charges in respect of production allocable to the Royalty.

2. The pro-forma consolidated balance sheet gives effect to the following assumptions and adjustments:

(a) Under the Arrangement, the Rockyview Assets were transferred to Rockyview based upon APF Inc’s carrying value. The carrying value of the Rockyview Assets was determined based on the portion of the total proven oil and natural gas reserves (discounted at 10 percent) as determined by independent reserve engineers for proved properties. The associated asset retirement obligation of the Rockyview Assets was based upon APF Inc’s carrying value and estimated based on the Rockyview Assets transferred and assumptions as used in APF’s Trust’s consolidated financial statements.

	($000)
Oil and natural gas assets and equipment	33,072
Undeveloped land	5,180
Seismic	1,507
Future income tax asset	4,028
Total assets transferred	43,787
Asset retirement obligation	(811	)
Net assets transferred at carrying value	42,976

The above amounts are estimates, which were made by management in the preparation of the pro forma financial statements based on information available at the time. Amendments will be made to these amounts as estimates are finalized;

(b) The future income tax on the pro forma consolidated balance sheet has been determined on the basis of the difference between the net book values of the assets and liabilities and the corresponding tax basis that resulted in APF Inc. after the completion of the Arrangement. The increase in future income tax liability arises as a result of the assets transferred by APF Inc. having a greater tax basis than the net book value;

(c) All options and rights including ones which have not vested were exercisable as a result of the combination with Starpoint; therefore, the unamortized fair value of APF options and rights has been expensed. Contributed surplus has been reduced to reflect the assumed exercise of options and rights at January 1, 2004 for proceeds of approximately $24.5 million. Long-term debt has been reduced to account for the approximate proceeds received from the exercise of these options and rights and applied against the outstanding principal;

(d) As at June 27, 2005, $1,906,000 of convertible debentures had been converted; therefore, other current assets have been reduced to reflect the corresponding write-off of deferred financing costs related to the convertible debentures. As a result of the conversion of the debentures, that portion of the convertible debenture conversion feature has been transferred to unitholders’ investment.

3. Pro forma assumptions and adjustments to the statement of operations as a result of GNEL:

(i) The purchase price allocated to GNEL assets is amortized on a unit of production basis;

(ii) The interest for the change of bank debt related to the Acquisition has been recorded at 5% per annum with no deemed principal repayments;

(iii) Current taxes were adjusted to account for income taxes if the income from the Acquisition subject to the royalty calculation was in effect January 1, 2004. The future income tax expense has been adjusted to reflect the impact on earnings of the transactions at an effective rate of 36.5%;

(iv) Saskatchewan surtax is applied to certain properties and capital taxes have been reclassified from income taxes;

(v) Alberta Royalty Tax Credit was adjusted to reduce the amount to the maximum allowable for the period.

4. Pro forma assumptions and adjustments to the statement of operations as a result of the Rockyview Arrangement:

(a) The future income tax expense has been adjusted to reflect the impact on earnings of the transactions at an effective rate of 36.5%;

(b) Interest expense attributable to long term debt decreased due to the reduction in debt from applying the proceeds from the options and rights against the principal, an interest rate of 5% was used for the calculation;

(c) Convertible debenture interest and associated accretion decreased to reflect the convertible debentures that have been converted in order for debenture holder’s to receive a share of Rockyview;

(d) Capital taxes have been reduced to reflect the decreased capital base of APF Trust;

(e) To reflect the options and rights exercised, the unamortized fair value of APF’s options and rights was expensed;

(f) The net income per unit has been calculated using the number of APF Trust units, assuming the exercise of all outstanding APF Trust options, rights and convertible debentures, as though they had been converted at the beginning of the year. All options and rights were treated as exercised as a result of the merger with Starpoint.

Approximate APF trust units outstanding		60,963,943
Approximate conversion of APF options and rights		2,386,391
Approximate dilutive effect of convertible debentures		4,316,533
Total diluted trust units outstanding at the effective date of the arrangement		67,666,867

(g) Depreciation, depletion and accretion expense has been adjusted to reflect the application of the appropriate unit-of-production rate for the Rockyview Assets based on Rockyview’s estimated proved petroleum and natural gas reserves as determined by independent reserve engineers.

(h) The revenues, royalties, and operating expenses of Rockyview have been eliminated as a result of the sale of the assets to Rockyview Energy Inc.

SCHEDULE “C” - PRO FORMA CONSOLIDATED FINANCIAL STATEMENTS

C-1

KPMG LLP
Chartered Accountants	Telephone	(403) 691-8000
200-205 5 Avenue SW	Fax	(403) 691-8008
Calgary AB T2P 4B9	Internet	www.kpmg.ca

COMPILATION REPORT ON PRO FORMA FINANCIAL STATEMENTS

To the Trustee of StarPoint Energy Trust

We have read the accompanying unaudited pro forma consolidated balance sheet of StarPoint Energy Trust as at March 31, 2005 and the unaudited pro forma consolidated statement of operations for the three months ended March 31, 2005 and the year ended December 31, 2004 and have performed the following procedures:

1. Compared the figures in the columns captioned “StarPoint Energy Trust” to the unaudited interim consolidated financial statements of StarPoint Energy Trust as at March 31, 2005 and for the three months then ended and found them to be in agreement.

2. Compared the figures in the column captioned “StarPoint Energy Ltd” to the audited consolidated financial statements of StarPoint Energy Ltd. for the year ended December 31, 2004 and found them to be in agreement.

3. Compared the figures in the columns captioned “APF Pro Forma Total” to the unaudited pro forma consolidated financial statements of APF Energy Trust as at March 31, 2005 and for the three months then ended and for the year ended December 31, 2004 and found them to be in agreement.

4. Compared the figures in the column captioned “E3 Energy Inc.” to the audited consolidated financial statements of E3 Energy Inc. for the year ended December 31, 2004 and found them to be in agreement.

5. Compared the figures in the columns captioned “Encana Assets” to the unaudited Schedule of Revenues, Royalties and Operating Expenses for the Encana Assets for the three months ended March 31, 2005 and to the audited Schedule of Revenues, Royalties and Operating Expenses for the Encana Assets for the year ended December 31, 2004 and found them to be in agreement.

6. Made enquires of certain officials of StarPoint Energy Trust who have responsibility for financial and accounting matters about:

(a) the basis for the determination of the pro forma adjustments; and

(b) whether the pro forma consolidated financial statements comply as to form in all material respects with the regulatory requirements of the various Securities Commissions and similar regulatory authorities in Canada.

KPMG LLP, a Canadian owned limited liability partnership, is the Canadian member firm of KPMG International, a Swiss association

The officials:

(a) described to us the basis for determination of the pro forma adjustments; and

(b) stated that the pro forma consolidated financial statements comply as to form in all material respects with the regulatory requirements of the various Securities Commissions and similar regulatory authorities in Canada.

7. Read the notes to the pro forma consolidated financial statements and found them to be consistent with the basis described to us for determination of the pro forma adjustments.

8. Recalculated the application of the pro forma adjustments to the aggregate of the amounts in the applicable columns captioned “StarPoint Energy Trust”, “StarPoint Energy Ltd.”,”E3 Energy Inc.”, “Encana Assets”, and “APF Pro Forma Total”, as at March 31, 2005 and for the three months then ended and for the year ended December 31, 2004 and found the amounts in the columns captioned “StarPoint Trust Pro Forma Total” to be arithmetically correct.

A pro forma financial statement is based on management assumptions and adjustments which are inherently subjective. The foregoing procedures are substantially less than either an audit or a review, the objective of which is the expression of assurance with respect to management’s assumptions, the pro forma adjustments and the application of the adjustments to the historical financial information. Accordingly, we express no such assurance. The foregoing procedures would not necessarily reveal matters of significance to the pro forma consolidated financial statements, and we therefore make no representation about the sufficiency of the procedures for the purposes of a reader of such statements.

(Signed) KPMG LLP
Chartered Accountants

Calgary, Canada
July 20, 2005

STARPOINT ENERGY TRUST

Pro Forma Consolidated Balance Sheet

As at March 31, 2005
(Unaudited)
(Thousands of dollars)

	StarPoint			APF									Star Point Trust
	Energy			Pro Forma			Pro Forma Adjustments						Pro Forma
	Trust			Total			APF			Encana Assets			Total

Assets

Current assets:
Cash and cash equivalents	$	—		$	1,299		$	(1,299	)(2e)	$	—		$	—
Accounts receivable and other	44,411			53,443			—			—			97,854
	44,411			54,742			(1,299		)	—			97,854

Deferred financing costs	—			—			—			2,400		(2d)	2,400
Asset retirement fund	—			3,475			—			—			3,475

Property and equipment	353,572			643,931			(643,931		)(2c)	390,700		(2c)
							731,412		(2c)				1,475,684
Goodwill	121,760			118,478			(118,478		)(2c)	17,782		(2c)
							361,650		(2c)				501,192
	$	519,743		$	820,626		$	329,354		$	410,882		$	2,080,605

Current Liabilities and Unitholders’ Equity

Current liabilities:
Accounts payable and accrued liabilities	$	35,908		$	76,691		$	14,228	(2a)	$	—		$	126,827
Bank loan	98,611			—			7,000		(2d)	392,000		(2c)
							(1,299		)(2e)	(57,600		)(2d)
							158,545		(2e)	(304,130		)(2d)	293,127
	134,519			76,691			178,474			30,270			419,954

Convertible debentures	—			45,882			(45,882		)(2h)	49,800		(2d),(f)
							46,001		(2h)				95,801
Long-term debt	—			158,545			(158,545		)(2e)	—			—
Derivative liability	—			1,304			—			—			1,304
Asset retirement obligation	16,804			30,727						16,482		(2c),(g)	64,013
Future tax liability	54,574			80,847			—			—			135,421

Non Controlling interest	4,489			—			—			—			4,489

Unitholders’ Equity
Unitholders capital	314,364			605,922			(605,922		)(2c)	320,400		(2d)
							735,448		(2c)	(16,270		)(2d)
							(7,000		)(2d)				1,346,942
Convertible debentures	—			1,104			(1,104		)(2h)	10,200		(2f)
							7,488		(2h)				17,688
Contributed surplus	1,333			—			—			—			1,333
Accumulated distributions	(15,118		)	(304,887		)	304,887		(2c)	—			(15,118		)
Accumulated earnings	8,778			124,491			(124,491		)(2c)	—			8,778
	309,357			426,630			309,306			314,330			1,359,623
	$	519,743		$	820,626		$	329,354		$	410,882		$	2,080,605

See accompanying notes to pro forma consolidated financial statements.

STARPOINT ENERGY TRUST

Pro Forma Consolidated Statement of Operations

Three months ended March 31, 2005
(Unaudited)

(Thousands of dollars except per unit amounts)

				Pro Forma Adjustments
	Starpoint			Selkirk			APF									StarPoint Trust
	Energy			Energy			Pro Forma			Encana			Pro Forma			Pro Forma
	Trust			Partnership			Total			Assets			Adjustments			Total
				(note 3e)
Revenue
Oil and gas sales	$	35,873		$	1,390		$	47,933		$	25,596		$	—		$	110,792
Royalties expense, net of ARTC	(7,799		)	(353		)	(12,843		)	(1,163		)	—			(22,158		)
	28,074			1,037			35,090			24,433			—			88,634

Expenses:
Operating and transportation	5,332			199			15,765			4,543			—			25,839
General and administrative	828			1,002			3,528			—			—			5,358
Plan of arrangement costs	3,357			—			—			—			—			3,357
Depletion, depreciation and accretion	15,077			534			24,922			—			15,361		(3b)	55,894
Unit based compensation	1,333			—			277			—			—			1,610
Accretion of equity component of debentures	—			—			—			—			226		(3a)	226
Interest and bank charges	1,094			(7		)	2,768			—			627		(3a)
													975		(3a)	5,457
	27,021			1,728			47,260			4,543			17,189			97,741

Income (loss) before income taxes	1,053			(691		)	(12,170		)	19,890			(17,189		)	(9,107		)

Income taxes:
Capital	874			—			702			—			(599		)(3c)	977
Future income taxes (recovery)	(3,092		)	—			(10,096		)	—			(601		)(3c)	(13,789		)
	(2,218		)				(9,394		)	—			(1,200		)	(12,812		)

Non Controlling interest	347			—			—			—			—			347

Net income (loss)	$	2,924		$	(691	)	$	(2,776	)	$	19,890		$	(15,989	)	$	3,358

Net income per unit and exchangeable share (note 3f):
Basic																$	0.04
Diluted																$	0.04

See accompanying notes to pro forma consolidated financial statements.

STARPOINT ENERGY TRUST

Pro Forma Consolidated Statement of Operations

Year ended December 31, 2004
(Unaudited)

(Thousands of dollars except per unit amounts)

							Pro Forma Adjustments
	Starpoint						Selkirk			Upton												APF									Starpoint Trust
	Energy			E3 Energy			Energy			Resources			Mission						Pro Forma			Pro Forma			Encana			Pro Forma			Pro Forma
	Ltd.			Inc.			Partnership			Ltd.			Assets			Other			Sub Total			Total			Assets			Adjustments			Total
							(note 4g)			(note 4f)			(note 4a)
Revenue
Oil and gas sales	$	102,019		$	17,344		$	16,851		$	5,439		$	(12,493	)	$	—		$	129,160		$	255,791		$	100,896		$	—		$	485,847
Royalties expense, net of ARTC	(24,262		)	(2,990		)	(3,990		)	(1,237		)	3,178			—			(29,301		)	(51,405		)	(4,999		)	—			(85,705		)
Other	—			—			45			—			—			—			45			—			—			—			45
	77,757			14,354			12,906			4,202			(9,315		)	—			99,904			204,386			95,897			—			400,187

Expenses:
Operating and transportation	18,895			4,513			2,016			810			(3,075		)	—			23,159			62,209			17,926			—			103,294
General and administrative	2,393			1,659			707			3,930									8,689			14,567			—			—			23,256
Stock based compensation	1,979			357			—									(357)		(4e)	1,979			(415		)	—			—			1,564
Depletion, depreciation and amortization	36,152			3,964			5,553			2,549			—			1,418		(4a),(c)	49,636			93,490			—			42,213		(4c)	185,339
Accretion of ARO	685			104			23			—			—			(49		)(4a),(c)	763						—			989		(4c)	1,752
Accretion of equity component of debentures	—			—			—			—			—			—			—			—			—			905		(4b)	905
Interest and bank charges	2,252			286			—			155						(363		)(4b)										2,510		(4b)
																500		(4b)	2,830			11,417			—			8,317		(4b)	25,074
	62,356			10,883			8,299			7,444			(3,075		)	1,149			87,056			181,268			17,926			54,934			341,184

Income (loss) before income taxes)	15,401			3,471			4,607			(3,242		)	(6,240		)	(1,149		)	12,848			23,118			77,971			(54,934		)	59,003

Income taxes:
Capital	2,916			12			—			—						274		(4d)	3,202			3,529			—			(5,883		)(4d)	848
Future income taxes (recovery)	6,080			590			755			—			—			(3,158		)(4d)	4,267			(27,926		)	—			(4,062		)(4d)	(27,721		)
	8,996			602			755			—			—			(2,884		)	7,469			(24,397		)	—			(9,945		)	(26,873		)

Net income (loss)	$	6,405		$	2,869		$	3,852		$	(3,242	)	$	(6,240	)	$	1,735		$	5,379		$	47,515		$	77,971		$	(44,989	)	$	85,876

Net income per unit and exchangeable share (note 4h):
Basic																															$	0.99
Diluted																															$	0.98

See accompanying notes to pro forma consolidated financial statements.

STARPOINT ENERGY TRUST

Notes to Pro Forma Consolidated Financial Statements

As at March 31, 2005 and for the three months then ended and the year ended December 31, 2004
(Unaudited)

(Tabular amounts in thousands of dollars)

1. Basis of presentation:

The accompanying unaudited pro forma consolidated balance sheet of StarPoint Energy Trust (“StarPoint”) as at March 31, 2005 and the unaudited pro forma consolidated statements of operations for the three months ended March 31, 2005 and the year ended December 31, 2004 (the “pro forma financial statements”) have been prepared to reflect the following:

• The acquisition of all the issued and outstanding units of APF Energy Trust (“APF”) for consideration totaling approximately $735.4 million through the issuance of 39,659,628 StarPoint units at an adjusted price of $18.54 per unit;

• The acquisition of the Encana Assets (“Encana Assets”) for cash consideration of approximately $392.0 million;

• The issuance of $60,000,000 convertible debentures at a coupon rate of 6.5 % per annum with a conversion price of $19.75 per StarPoint unit; and

• The issuance of 17,800,000 StarPoint units at $18 per unit for gross proceeds totaling $320.4 million.

The pro forma financial statements have been prepared from information derived from and should be read in conjunction with the following:

1) StarPoint’s unaudited interim consolidated financial statements as at March 31, 2005 and for the three months then ended;

2) StarPoint Energy Ltd.’s audited consolidated financial statements as at December 31, 2004 and for the year then ended;

3) E3 Energy Inc.’s (“E3”) audited consolidated financial statements as at December 31, 2004 and for the year then ended;

4) The unaudited statement of net operating revenues of the Mission Assets for the nine months ended September 30, 2004. These amounts have been adjusted to incorporate the unaudited results of these assets for the period from October 1, 2004 to December 31, 2004;

5) The unaudited interim consolidated financial statements of the Selkirk Energy Group (“Selkirk”) as at October 31, 2004 and for the nine months then ended. These amounts have been adjusted to include the unaudited operations of Selkirk for the period from January 1, 2004 to January 31, 2004 and November 1, 2004 to December 31, 2004. Further, as StarPoint acquired Selkirk on January 28, 2005, the pro forma consolidated statement of operations for the three months ended March 31, 2005 has been adjusted to include the unaudited operations of Selkirk for the period from January 1, 2005 to January 27, 2005;

6) APF’s unaudited interim consolidated financial statements as at March 31, 2005 and for the three months then ended and audited consolidated financial statements as at December 31, 2004 and for the year then ended;

7) The unaudited schedule of revenues, royalties and operating expenses for the Encana Assets for the three months ended March 31, 2005 and the audited schedule of revenues, royalties and operating expenses for the Encana Assets for the year ended December 31, 2004;

8) The audited consolidated financial statements of Upton Resources Ltd. as at December 31, 2003 and for the year then ended. As StarPoint acquired Upton on January 24, 2004 the pro forma consolidated statement of operations for the year ended December 31, 2004 has been adjusted to include the operations of Upton Resources Inc. for the period from January 1, 2004 to January 23, 2004;

9) The unaudited pro forma consolidated financial statements of APF as at March 31, 2005 and for the three months then ended and the year ended December 31, 2004; and

10) The audited financial statement of StarPoint Energy Trust as at December 31, 2004.

The pro forma financial statements have been prepared by management in accordance with Canadian generally accepted accounting principles. The unaudited pro forma consolidated balance sheet gives effect to the assumed transactions and assumptions described in note 2 as if they had occurred on March 31, 2005. The unaudited pro forma consolidated statements of operations give effect to the transactions and assumptions in notes 2, 3 and 4 as if they had occurred on January 1, 2004. The pro forma financial statements may not be indicative of the results that actually would have occurred if the events reflected therein had been in effect on the dates indicated or of the results which may be obtained in the future. In preparing these pro forma financial statements, no adjustments have been made to reflect the expected operating synergies and administrative cost savings that could result from the combining of the operations of StarPoint and the acquired entities.

Accounting policies used in the preparation of the pro forma financial statements are in accordance with those disclosed in StarPoint’s unaudited consolidated financial statements as at March 31, 2005 and for the three months then ended and StarPoint Energy Ltd.’s audited consolidated financial statements as at December 31, 2004 and for the year then ended.

In the opinion of management of StarPoint, the pro forma financial statements include all of the necessary adjustments for the fair presentation of StarPoint.

2. Balance Sheet Adjustments (March 31, 2005):

The unaudited consolidated balance sheet as at March 31, 2005 gives effect to the following assumptions and adjustments as if they occurred on March 31, 2005:

(a) On April 13, 2005, StarPoint entered into an agreement to acquire all the issued and outstanding units of APF. For purposes of the purchase price determination, StarPoint has used an adjusted unit price of $18.54 per StarPoint unit and has assumed that 39,659,628 StarPoint units will be issued. StarPoint will be deemed to be the acquirer of APF and will account for the acquisition using the purchase method of accounting.

The pro forma consolidated balance sheet includes $14,228,000 in costs to be incurred by APF for required severance and other assumed liabilities. In addition, StarPoint has assumed $7,000,000 in unit issue costs relating to the issuance of the 39,659,628 StarPoint units to APF unitholders.

(b) On May 9, 2005, StarPoint entered into an agreement to issue 17,800,000 StarPoint units at $18 per unit for gross proceeds totaling $320.4 million, to acquire the Encana Assets.

	APF			Encana Assets

Cost of acquisition:
Cash	$	—		$	392,000
Units issued	735,448			—
	$	735,448		$	392,000

Allocated:
Property and equipment	$	731,412		$	390,700
Goodwill	361,650			17,782
Working capital (including severance and other assumed liabilities totaling approximately $14,228)	(36,177		)	—
Convertible debentures	(53,489		)	—
Derivative liability	(1,304		)	—
Long-term debt	(158,545		)	—
Asset retirement fund	3,475			—
Asset retirement obligation	(30,727		)	(16,482		)
Future income taxes	(80,847		)	—
	$	735,448		$	392,000

The allocation of the purchase price to the assets and liabilities will be finalized once the fair values of the assets and liabilities are determined. Accordingly, the above allocations will change.

(d) The bank loan and unitholders’ capital has been adjusted to reflect the following:

(i) net proceeds totaling $304,130,000 ($320,400,000 less issue costs of $16,270,000) on the issue of 17,800,000 StarPoint units pursuant to an underwriting agreement dated May 9, 2005;

(ii) $7,000,000 of unit issue costs on the acquisition of APF;

(iii) proceeds of $57,600,000 ($60,000,000 less deferred financing costs of $2,400,000) on the issue of the convertible debentures pursuant to the agreement dated May 9, 2005; and

(e) The bank loan has been adjusted to reflect the repayment of APF long term debt of $158,545,000 and the reclassification of the APF cash balance of $1,299,000.

(f) Unitholders’ capital and the convertible debenture balance have been adjusted by $10,200,000 to reflect the fair value of the conversion feature relating to the issue of $60,000,000 of convertible debentures.

(g) The asset retirement obligation for StarPoint has been measured based on the assumptions and terms consistent with those used by StarPoint. The liability was estimated based on the net ownership of all wells and facilities, the estimated costs to abandon and reclaim the wells and facilities and the estimated timing of the costs to be incurred in future periods.

(h) As at June 27, 2005, APF debentures with a face value of $46,986,000 and a fair value of $53,489,000 had not been converted. Pursuant to a debenture agreement dated June 27, 2005, the APF debenture obligation was undertaken by StarPoint and has been recorded as a pro forma adjustment. Unitholders’ capital and the convertible debenture balance have been adjusted by $46,001,000 and $7,488,000 respectively. The amount recorded in unitholders’ equity reflects the fair value of the conversion feature relating to these debentures.

3. Statement of Operations Adjustments (Three Months Ended March 31, 2005):

The unaudited consolidated pro forma statement of operations for the three months ended March 31, 2005 gives effect to the following assumptions and adjustments as if they occurred on January 1, 2004:

(a) Interest expense has been adjusted to give effect to the cash portion of the consideration paid on the acquisitions of Selkirk and the Encana Assets and the interest on the issuance of the convertible debentures less the proceeds received from the exercise of options, equity issues and the convertible debenture issue. Accretion of the equity component of the convertible debenture issue has been adjusted to give effect to the issuance of the convertible debentures.

(b) Depreciation, depletion and accretion have been adjusted to reflect the application of the appropriate unit-of-production rate for the full cost pool allocated to StarPoint based on the estimated proved petroleum and natural gas reserves after adjustments for the acquisitions of APF and the Encana Assets.

(c) Capital taxes have been adjusted to reflect the increased size of StarPoint after the completion of the acquisitions of APF and the Encana Assets.

The pro forma consolidated statement of operations has been adjusted to reflect the elimination of current income taxes which will be eliminated under the Trust structure. The future income tax provision reflects the tax impact of the pro forma adjustments in the pro forma consolidated statement of operations.

(d) No new options are assumed to be issued in the period.

(e) StarPoint acquired Selkirk on January 28, 2005. The pro forma consolidated statement of operations for the three months ended March 31, 2005 has been adjusted to incorporate the unaudited operating results for the period from January 1, 2005 to January 27, 2005.

(f) The net income per StarPoint unit and exchangeable share has been based on the following historical weighted average number of shares of StarPoint adjusted as follows:

		Three
		months ended
		March 31,2005

Weighted average StarPoint units and exchangeable shares		29,535,473
Issued on acquisition of APF		39,659,628
Equity issue		17,800,000
Weighted average StarPoint units and exchangeable shares		86,995,101

Allocated as follows:
StarPoint units		84,868,873
Exchangeable shares		2,126,228

4. Statement of Operations Adjustments (Year ended December 31, 2004):

The unaudited consolidated pro forma consolidated statement of operations for the year ended December 31, 2004 gives effect to the following assumptions and adjustments as if they occurred on January 1, 2004:

(a) On November 26, 2004, StarPoint, E3, StarPoint Energy Trust, Mission Oil & Gas Inc. (“Mission”), StarPoint Acquisition Ltd. and StarPoint Exchangeco Ltd. entered into the Arrangement which became effective on January 7, 2005. Under the Arrangement:

(i) StarPoint Energy Ltd. issued 14,258,946 common shares at an adjusted purchase price of $4.32 per share to the shareholders of E3;

(ii) virtually all of StarPoint’s and E3’s existing producing oil and gas assets were transferred to the benefit of StarPoint Energy Trust; and

(iii) certain exploration assets, undeveloped lands and limited producing oil and natural gas assets (the “Mission Assets”) held by StarPoint were transferred to Mission.

StarPoint was deemed the acquirer of E3 and consequently accounted for the acquisition using the purchase method of accounting. The revenue, royalties and operating expenses related to the Mission Assets have been deducted from the unaudited pro forma consolidated statement of operations of StarPoint for the year ended December 31, 2004 and related adjustments have been made to depletion, depreciation and accretion and income taxes. The properties comprising the Mission Assets were acquired by StarPoint or its subsidiary companies at various points in time. The pro forma consolidated statement of operations has been adjusted only for the revenues and related expenditures incurred after the properties were acquired by StarPoint.

(b) Interest expense has been adjusted to give effect to the cash portion of the consideration paid on the acquisitions of Selkirk and the Encana Assets and the interest on the convertible debentures less the proceeds received from the exercise of options, the equity issues and convertible debenture issue. Accretion of the equity component of the convertible debenture issue has been adjusted to give effect to the issuance of the convertible debentures.

(c) Depreciation, depletion and accretion have been adjusted to reflect the application of the appropriate unit-of-production rate for the full cost pool allocated to StarPoint based on the estimated proved petroleum and natural gas reserves after adjustments for all acquisitions.

(d) Capital taxes have been adjusted to reflect the increased size of StarPoint after the completion of the acquisitions.

(e) No new options are assumed to be issued in the period.

(f) StarPoint acquired Upton Resources Inc. on January 24, 2004. The pro forma consolidated statement of operations for the year ended December 31, 2004 has been adjusted to incorporate the unaudited operating results of Upton Resources Inc. for the pre-acquisition period from January 1, 2004 to January 23, 2004.

(g) StarPoint acquired Selkirk on January 28, 2005. The pro forma consolidated statement of operations for the year ended December 31, 2004 has been adjusted to incorporate the unaudited operating results of Selkirk for the year ended December 31, 2004.

(h) The net income per StarPoint unit and exchangeable share has been based on the following historical weighted average number of shares of StarPoint adjusted for the following:

		Year ended
		December 31,
		2004

StarPoint Energy Ltd. pro forma weighted average shares outstanding		79,642,000
Issued on acquisition of E3		14,258,946
		93,900,946
StarPoint units and exchangeable shares outstanding after giving effect to the Arrangement		24,099,444
Options exercised		1,515,962
Equity issue		3,760,000
Issued on acquisition of APF		39,659,628
Equity issue		17,800,000
Weighted average StarPoint units and exchangeable shares		86,835,034

Allocated as follows:
StarPoint units		83,340,439
Exchangeable shares		3,494,595