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;

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

“Administrator” means StarPoint Energy Ltd., a corporation amalgamated under the ABCA and a wholly-owned subsidiary of the Trust;

“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;

“Nexen” means Nexen Inc.;

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

“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;

“Sproule Report” means the independent engineering report of Sproule dated June 30, 2005 evaluating, effective March 31, 2005, the oil, NGL and natural gas reserves attributable to the Nexen Assets;

“Trust” means StarPoint Energy Trust, a unincorporated trust formed pursuant to the laws of Alberta;

“Trust Indenture” means the trust indenture dated December 6, 2004 between Olympia Trust Company and StarPoint, pursuant to which the Trust is governed;

“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 Corporation’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 BOE	Alberta Royalty Tax Credit 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
$000s or M$	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 nonoperating) 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. The Administrator has generally been delegated the significant management decisions 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 ACQUISITION

General

On August 9, 2005, the Trust indirectly acquired the Nexen Assets from Nexen for aggregate cash consideration of $317.3 million. The effective date of the Acquisition was June 1, 2005.

Financing of the Acquisition

On August 9, 2005, the Trust completed an offering of 13,000,000 subscription receipts at a price of $18.65 each for total net proceeds of $230,327,500. The net proceeds of the offering were used by the Trust to fund a portion of the purchase price of the Acquisition, with the balance being funded though additional borrowings under the Trust’s credit facility. Upon the completion of the Acquisition, the subscription receipts that had been issued by the Trust pursuant to the offering were exchanged for an equivalent number of Trust Units.

INFORMATION CONCERNING THE NEXEN ASSETS

Oil and Natural Gas Reserves

In accordance with NI 51-101, Sproule prepared the Sproule Report. The Sproule Report evaluated, as at March 31, 2005, the oil, NGL and natural gas reserves attributable to the Nexen Assets. The tables below are a summary of the oil, NGL and natural gas reserves attributable to the Nexen Assets and the net present value of future net revenue attributable to such reserves as evaluated in the Sproule Report, based on constant and forecast price and cost assumptions. The tables summarize the data contained in the Sproule Report 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. It should not be assumed that the undiscounted or discounted net present value of future net revenue attributable to reserves estimated by Sproule 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	Natural Gas	Light and Medium Crude Oil	Natural Gas
	Mbbls	MMcf	Mbbls	MMcf

Proved
Developed Producing	9,294	4,819	8,278	4,475
Developed Non-Producing	41	—	37	—
Undeveloped	1,065	701	996	647
Total Proved	10,399	5,521	9,311	5,122
Probable	4,884	2,598	4,404	2,439
Total Proved plus Probable	15,284	8,119	13,715	7,561

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

	Before Future Income Tax Expenses and Discounted at
	Before Future Income Tax Expenses and Discounted at
	0%	10%
	(M$)	(M$)
Proved
Developed Producing	404,109	268,115
Developed Non-Producing	692	583
Undeveloped	41,487	29,126
Total Proved	446,289	297,825
Probable	211,758	100,560
Total Proved plus Probable	658,047	398,385

Additional Information Concerning Future Net Revenue – Constant Prices and Costs

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

Total Proved Reserves	726,463	95,823	136,016	20,826	27,508	446,289
Total Proved plus Probable	1,065,312	134,303	194,468	43,306	35,190	658,047

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)		297,825
Proved plus Probable
Light and Medium Crude Oil(1)		398,385

Notes:

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

Summary of Oil and Gas Reserves – Forecast Prices and Costs

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

Proved
Developed Producing	9,286	4,821	8,283	4,476
Developed Non-Producing	22	—	20	—
Undeveloped	1,065	701	997	648
Total Proved	10,373	5,522	9,299	5,124
Probable	4,866	2,600	4,397	2,440
Total Proved plus Probable	15,239	8,122	13,696	7,564

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	238,198	200,830	176,845	159,870	147,045
Developed Non-Producing	274	264	254	245	237
Undeveloped	24,124	20,287	17,332	14,979	13,059
Total Proved	262,596	221,381	194,431	175,094	160,340
Probable	118,814	75,261	56,409	44,856	36,982
Total Proved plus Probable	374,410	296,642	250,840	219,950	197,322

Additional Information Concerning Future Net Revenue – Forecast Prices and Costs

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

Total Proved Reserves	545,909	72,272	154,484	20,936	35,620	262,596
Total Proved plus Probable	792,418	99,249	228,393	43,786	46,580	374,410

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)		194,431
Proved plus Probable
Light and Medium Crude Oil(1)		250,840

Notes:

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

Pricing Assumptions – Constant Prices and Costs

The following pricing and exchange rate assumptions as of March 31, 2005 were used in the Sproule Report in estimating reserves data using constant prices and costs.

Light and Medium Crude Oil		Natural Gas
Edmonton Par Price 40°API		AECO -C Spot		Exchange Rate
($Cdn/Bbl)		($Cdn/MMBTU)		($US/$Cdn)
$	67.38	$	7.87	$	0.826

Pricing Assumptions – Forecast Prices and Costs

The following pricing, exchange rate and inflation rate assumptions as of March 31, 2005 were used in the Sproule Report in estimating reserves data using forecast prices and costs.

	Light and Medium Crude Oil	Natural Gas
Year	Edmonton Par Price 40° API	AECO - C Spot	Exchange Rate
	($CDN/Bbl)	($CDN/MMBTU)	($US/$Cdn)
2005	63.85	7.93	$	0.8225
2006	60.05	7.72	$	0.8225
2007	50.58	6.91	$	0.8225
2008	43.35	6.13	$	0.8225
2009	41.10	5.76	$	0.8225
2010	41.78	5.85	$	0.8225
2011	42.52	5.98	$	0.8225
2012	43.31	6.05	$	0.8225
2013	44.05	6.19	$	0.8225
2014	44.85	6.29	$	0.8225
2015	45.61	6.43	$	0.8225
2016	46.46	6.53	$	0.8225
2017 to 2024	+1.75%	+1.75%	$	0.8225
Thereafter	+0.75%	+0.75%	$	0.8225

Future Development Costs

The table below sets out the total development costs deducted in the estimation in the Sproule Report 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	15,686	15,686	23,783
2006	5,140	5,250	17,235
2007	—	—	2,769
2008	—	—	—
2009	—	—	—
Remaining Years	—	—	—
Total Undiscounted	20,826	20,936	43,787
Total Discounted at 10% per year	19,950	20,050	40,949

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 properties comprising the Nexen Assets are located in southeast Saskatchewan, approximately 210 kilometres southeast of Regina. The Nexen Assets feature a land base situated along the Frobisher/Kisbey/Alida subcrop edge. Interests range from royalty interests to working interests up to 100%, with the average working interest being approximately 65%. The Nexen Assets are 85% operated with a land base of 44,593 (37,851 net) undeveloped acres.

Production from the Nexen Assets is weighted 92% to oil, with the balance being solution gas. Average production from the Nexen Assets during the six months ended June 30, 2005 was 6,350 BOE/d. Oil production from the assets is generally light sweet crude with a 38° API. The acquired properties include Edenvale (Alida West), Ingoldsby, Nottingham, Cantal and Queensdale.

Facilities associated with the Nexen Assets include the Nottingham gas plant and gathering system, a 75% working interest in an Arlington pipeline and several operated and non-operated oil batteries. All natural gas production from the Nexen Assets is in the form of solution gas, which is conserved from existing production and processed at the Nottingham gas plant or the BP Steelmen gas plant. The Nexen Assets include a 17.5% working interest in the Nottingham gas plant.

The Nexen Assets include 520 (390.5 net) producing oil wells and 117 (77.5 net) non-producing oil wells. For the year ended December 31, 2004, Nexen participated in the drilling of 24 (19 net) development oils wells. For the six months ended June 30, 2005, Nexen participated in the drilling of 17 (9.7 net) development oil wells.

Planned exploration and development activity on the Nexen properties for the final six months of 2005 includes the drilling of 12 (9.9 net) wells at an estimated total net cost of $8.0 million.

Oil and Gas Wells

The following table sets forth the number and status of wells, effective June 30, 2005, in which the Trust acquired a working interest through its acquisition of the Nexen Assets.

Producing Wells

Non-Producing Wells

Oil

Natural Gas

Oil

Natural Gas

Gross

Net

Gross

Net

Gross

Net

Gross

Net

Total

520

390.5

—

117

77.5

—

Properties with no Attributed Reserves

The following table summarizes the gross and net acres of unproved properties, effective June 30, 2005, in which the Trust acquired an interest through its acquisition of the Nexen 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




Total	44,593	37,851	12,030

Drilling Activity

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

	Exploratory Wells		Development Wells
	Gross	Net	Gross	Net
Crude Oil	—	—	24	19

The following table sets forth the gross and net exploratory and development wells drilled on the properties comprising the Nexen Assets during the six months ended June 30, 2005.

	Exploratory Wells		Development Wells
	Gross	Net	Gross	Net
Crude Oil	—	—	17	9.7

Additional Information Concerning Abandonment and Reclamation Costs

Well abandonment costs have been estimated area by area. Such costs are included in the Sproule Report as deductions in arriving at future net revenue. The expected total abandonment costs, net of estimated salvage value, included in the Sproule Report for 569 net wells under the proved reserves category is $16.2 million undiscounted ($6.2 million discounted at 10%), of which a total of $0.3 million is estimated to be incurred in 2005, 2006 and 2007. This estimate does not include expected reclamation costs for surface leases of $5.7 million undiscounted ($2.2 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 Nexen Assets.

	Property Acquisition Costs
	Proved Properties	Unproved Properties	Exploration Costs	Development Costs
	Proved Properties	Unproved Properties	Exploration Costs	Development Costs
Total (M$)	2	—	241	17,967

The following table summarizes capital expenditures (net of incentives and net of certain proceeds and including capitalized general and administrative expenses) incurred for the six months ended June 30, 2005 with respect to the Nexen Assets.

	Property Acquisition Costs
	Proved Properties	Unproved Properties	Exploration Costs	Development Costs
	Proved Properties	Unproved Properties	Exploration Costs	Development Costs
Total (M$)	—	—	392	8,474

Production Estimates

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

Crude Oil (Bbls/d)	Natural Gas (Mcf/d)	BOE (BOE/d)	%
Crude Oil (Bbls/d)	Natural Gas (Mcf/d)	BOE (BOE/d)	%
5,667	3,150	6,192	100

Production History

The following tables disclose, on a quarterly basis for the year ended December 31, 2004 and the six months ended June 30, 2005, certain information in respect of production, product prices received, royalties paid, operating expenses and resulting netback for the Nexen Assets.

Average Daily Production Volume

	Three Months Ended
	Mar. 31, 2004	June 30, 2004	Sept. 30, 2004	Dec. 31, 2004	Mar. 31, 2005	June 30, 2005
Natural gas (Mcf/d)	3,293	2,744	3,090	3,280	3,315	3,078
Crude Oil (Bbls/d)	5,749	5,217	5,326	5,504	5,797	5,758
NGL (Bbls/d)	14	13	12	8	20	59
Total (BOE/d)	6,312	5,687	5,853	6,058	6,369	6,330

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

($ per Bbl)	Three Months Ended
	Mar. 31, 2004	June 30, 2004	Sept. 30, 2004	Dec. 31, 2004	Mar. 31, 2005	June 30, 2005
Prices Received	43.95	48.59	54.46	51.51	57.47	59.66
Royalties Paid	9.74	10.90	12.15	11.06	11.64	12.20
Production Costs	6.41	6.87	8.81	7.72	5.19	5.89
Netback(1)	27.80	30.82	33.50	32.73	40.64	41.57

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

($ per Bbl)	Three Months Ended
	Mar. 31, 2004	June 30, 2004	Sept. 30, 2004	Dec. 31, 2004	Mar. 31, 2005	June 30, 2005
Prices Received	8.00	8.12	8.93	9.95	9.68	9.68
Royalties Paid	0.61	0.57	0.62	0.73	0.70	0.67
Production Costs	1.07	1.14	1.47	1.29	0.87	0.98
Netback(1)	6.32	6.40	6.84	7.93	8.11	8.04

Note:

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

Financial Statements

Schedule “A” hereto contains an audited Schedule of Revenue and Expenses concerning the Nexen Assets for the years ended December 31, 2004, 2003 and 2002 and an unaudited Schedule of Revenue and Expenses concerning the Nexen Assets for the six month periods ended June 30, 2005 and 2004.

EFFECT ON OPERATIONS

Following the completion of the Acquisition, the Trust conducted a review of the Nexen Assets with a view to determining whether a disposition of certain of the acquired assets not considered core to the operations of the subsidiaries of the Trust would be beneficial. As a result of this review, the Trust entered into an agreement on September 30, 2005 with a third party to dispose of non-core assets comprising approximately 500 BOE/d of production for cash consideration of $27.5 million. The Trust anticipates that the disposition will close on January 3, 2006, with an effective date of June 1, 2005.

In addition to the above, the Trust and the Administrator are currently in the process of assessing the manner in which they will integrate the Nexen 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 Acquisition has been obtained within the past 12 months by the Trust.

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 Acquisition.

Nexen Canada No. 5

Schedule of Revenue and Expenses

For the years ended December 31, 2004, 2003 and 2002

And for the six months ended June 30, 2005 and 2004

($000’s)

	June 30						December 31
	2005			2004			2004			2003			2002
	(unaudited)
REVENUE	$	67,468		$	51,683		$	112,001		$	104,798		$	106,782
ROYALTIES	(12,949		)	(10,615		)	(22,730		)	(21,397		)	(23,374		)
OPERATING EXPENSES	(7,106		)	(7,165		)	(15,700		)	(14,019		)	(12,036		)
NET OPERATING INCOME	$	47,413		$	33,903		$	73,571		$	69,382		$	71,372

Definitions	1
Special Note Regarding Forward Looking Statements	2
Abbreviations and Conversion	3
Notes on Reserves Data	4
StarPoint Energy Trust	5
The Acquisition	5
Information Concerning the Nexen Assets	5
Effect on Operations	13
Prior Valuations	13
Informed Persons, Associates and Affiliates	13
Schedule “A” - Schedule of Revenue and Expenses for the Nexen Assets	A-1

Calgary, Alberta	(signed) Deloitte & Touche LLP
February 28, 2005	Chartered Accountants