EXHIBIT 99.1

FORM 51-101F1 STATEMENT OF RESERVES DATA

AND OTHER OIL AND GAS INFORMATION

AS OF MAY 31, 2007

PATCH INTERNATIONAL INC.

FORM 51-101F1

STATEMENT OF RESERVES DATA AND

OTHER OIL AND GAS INFORMATION

MCDANIEL & ASSOCIATES CONSULTANTS LTD. REPORT

McDaniel & Associates Consultants Ltd. (“McDaniel”), independent petroleum engineering consultants based in Calgary, Alberta has provided an estimate of the bitumen contingent resources and the net present value of these resources for Patch International Inc.’s (“Patch” or the “Corporation”) Dover Ells leases as of May 31, 2007 (the “McDaniel Report”).  The McDaniel Report was prepared in accordance with the standards contained in the Canadian Oil and Gas Evaluation Handbook (“COGEH”).  The Report of the independent Qualified Reserves Evaluator or Auditor (Form 51-102F2) and the Report of Management and Directors on Oil and Gas Disclosure (Form 51-101F3) are available at www.sedar.com.

In preparing its report, McDaniel relied upon factual information including ownership, technical well data and other relevant data from public sources as well as non-public data supplied by Patch. The extent and character of all factual information supplied by Patch was relied upon by McDaniel in preparing the McDaniel Report and has been accepted as represented without independent verification. McDaniel has relied upon representations made by Patch as to the completeness and accuracy of the data provided and that no material changes in the status or ownership of the property has occurred nor is expected to occur, from that which was projected in the McDaniel Report, between the date that the data was obtained for this evaluation and the date of the McDaniel Report, and that no new data has come to light that may result in a material change to the evaluation of the resources presented in the McDaniel Report.

DATE OF STATEMENT

1.	Date of the Statement	July 30, 2007
2.	Effective date of the Statement:	May 31, 2007
3.	Preparation date of the Statement:	July 30, 2007

DISCLOSURE OF RESERVES DATA

Patch currently has no oil and gas reserves.  Patch does however hold an 80% working  interest within 70 square kilometres consisting of twenty-seven sections of land located in Townships 94 through 96, Ranges 14 and 15W4 within the Province of Alberta (located approximately 90 kilometres northwest of the City of Fort McMurray), of prospective hydrocarbon horizons held in two leases. These leases are collectively referred to as the Dover Ells properties and are referred to individually as the Ells North and Ells Central properties.  Undeveloped contingent bitumen resources and the net present value of these resources were determined based on exploitation of these zones using a conventional Steam-Assisted Gravity Drainage (“SAGD”) development scenario and a projected capacity of 19,200 Bopd.¹

In preparing the study, McDaniel examined approximately 50 wells, including both Corporation wells within the Ells North and Ells Central properties, and publicly-available offsetting wells surrounding the Corporation’s land. Discovered resources² were quantified for portions of the Ells properties that have been delineated and/or penetrated by historical wells.  Significant portions of the Ells North and Ells Central properties are not delineated and remain prospective for additional accumulations of bitumen at this point in time.

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¹ Barrel oil per day

 

² Discovered resources are those quantities of oil and gas estimated on a given date to be remaining in, plus those quantities already produced from, known accumulations.  Discovered resources are divided into economic and uneconomic categories with the estimated future recoverable portion classified as reserves and contingent resources, respectively. Discovered resources can also be considered to be contingent bitumen in place amenable to SAGD recovery meaning volumes of bitumen in place that are discovered (delineated) and are of sufficient thickness and quality so as to support SAGD exploration.

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The future net revenues and net present values presented in this report were calculated using forecast prices and costs based on McDaniel’s opinion of the future crude oil, bitumen and natural gas prices at July 1, 2007 and are presented in Canadian dollars.  Net present values were determined on both a before-tax and after-tax basis.

The Corporation’s share of contingent Low Estimate, Best Estimate and High Estimate bitumen resources as of May 31,2007 and the respective net present values assigned to these resources based on constant prices and costs and forecast prices and costs were estimated. Contingent resources are those quantities of oil and gas estimated to be potentially recoverable from known accumulations, but that are currently economic and also those resources that are potentially recoverable from known accumulations and are contingent on such events as regulatory approval, a development plan, funding available and/or timing of production.

The resources assigned to the Dover Ells leases have been classified as contingent primarily due to insufficient delineation, the lack of regulatory approval to develop the lease area, the absence of a firm development plan and timing and the uncertainly of approval of funding to proceed with development.

Contingent resources have been determined for the following mutually exclusive categories:

·     Low Estimate: This is considered to be a conservative estimate of the quantity that will actually be recovered from the accumulation.  If probabilistic methods are used, this term reflects a P₉₀ confidence level.

·     Best Estimate: This is considered to be a best estimate of the quantity that will actually be recovered from the accumulation.  If probabilistic methods are used, this term is a measure of the central tendency of the uncertainty distribution (most likely/mode, P₅₀/median, or arithmetic average/mean).

·     High Estimate: This is considered to be an optimistic estimate of the quantity that will actually be recovered from the accumulation. If probabilistic methods are used, this term reflects a P₁₀ confidence level.

The following tables set forth certain information relating to the evaluation of the Corporation’s share pf gross and net bitumen resources of the Dover Ells Leases, the estimation of the potential productivity based on SAGD processes and the estimation of the net present value of the resource volumes as of May 31, 2007.  The information set forth below is derived from the McDaniel Report which has been prepared in accordance with the standards contained in the COGEH and the reserves definitions contained in National Instrument 51-101 - Standards of Disclosure For Oil and Gas Activities (“NI 51-101”).

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ESTIMATED COMPANY SHARE OF REMAINING CONTINGENT RESOURCES AS OF MAY 31, 2007 CONSTANT PRICES AND COSTS
Classification	Bitumen
	Gross (Mbb1)3	Net (Mbbl)
LOW ESTIMATE CONTINGENT RESOURCES	93,664	85,009
BEST ESTIMATE CONTINGENT RESOURCES	139,064	122,949
HIGH ESTIMATE CONTINGENT RESOURCES	203,356	177,701

ESTIMATED SHARE OF NET PRESENT VALUE AS OF MAY 31, 2007 CONSTANT PRICES AND COSTS
Classification	BEFORE INCOME TAXES DISCOUNTED AT (%/year)
	Undiscounted (M$)	5% (M$)	10% (M$)	15% (M$)	20% (M$)
LOW ESTIMATE CONTINGENT RESOURCES	910	307	85	(3)	(40)
BEST ESTIMATE CONTINGENT RESOURCES	1,607	583	210	59	(6)
HIGH ESTIMATE CONTINGENT RESOURCES	2,648	999	398	152	43

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³ Thousand barrels.

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ESTIMATED SHARE OF NET PRESENT VALUE AS OF MAY 31, 2007 CONSTANT PRICES AND COSTS
Classification	AFTER INCOME TAXES DISCOUNTED AT (%/year)
	Undiscounted (M$)	5% (M$)	10% (M$)	15% (M$)	20% (M$)
LOW ESTIMATE CONTINGENT RESOURCES	613	183	27	(33)	(56)
BEST ESTIMATE CONTINGENT RESOURCES	1,082	365	107	6	(36)
HIGH ESTIMATE CONTINGENT RESOURCES	1,785	640	227	62	(9)

ESTIMATED COMPANY SHARE OF REMAINING CONTINGENT RESOURCES AS OF MAY 31, 2007 FORECAST PRICES AND COSTS
Classification	Bitumen
	Gross (Mbb1)4	Net (Mbbl)
LOW ESTIMATE CONTINGENT RESOURCES	93,664	91,791
BEST ESTIMATE CONTINGENT RESOURCES	139,064	132,668
HIGH ESTIMATE CONTINGENT RESOURCES	203,356	189,784

ESTIMATED SHARE OF NET PRESENT VALUE AS OF MAY 31, 2007 FORECAST PRICES AND COSTS
Classification	BEFORE INCOME TAXES DISCOUNTED AT (%/year)
	Undiscounted (M$)	5% (M$)	10% (M$)	15% (M$)	20% (M$)
LOW ESTIMATE CONTINGENT RESOURCES	228	(43)	(118)	(133)	(128)
BEST ESTIMATE CONTINGENT RESOURCES	725	153	(33)	(94)	(110)
HIGH ESTIMATE CONTINGENT RESOURCES	1,468	425	76	(48)	(91)

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⁴ Thousand barrels.

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ESTIMATED SHARE OF NET PRESENT VALUE AS OF MAY 31, 2007 FORECAST PRICES AND COSTS
Classification	AFTER INCOME TAXES DISCOUNTED AT (%/year)
	Undiscounted (M$)	5% (M$)	10% (M$)	15% (M$)	20% (M$)
LOW ESTIMATE CONTINGENT RESOURCES	143	(70)	(127)	(136)	(129)
BEST ESTIMATE CONTINGENT RESOURCES	471	59	(72)	(111)	(118)
HIGH ESTIMATE CONTINGENT RESOURCES	966	234	(6)	(87)	(111)

TOTAL FUTURE NET REVENUE (UNDISCOUNTED) AS OF MAY 31, 2007 FORECAST PRICES AND COSTS
Classification	Revenue (M$)	Royalties (M$)	Operating Costs (M$)	Development Costs (M$)	Well Abandon-ment Costs (M$)	Future Net Revenue Before Income Taxes  (M$)	Income Taxes (M$)	Future Net Revenue After Income Taxes (M$)
LOW ESTIMATE CONTINGENT RESOURCES	3,830,304	76,606	2,289,598	1,210,859	24,971	228,270	85,410	142,860
BEST ESTIMATE CONTINGENT RESOURCES	5,734,124	283,151	3,104,695	1,586,310	34,978	724,989	253,706	471,282
HIGH ESTIMATE CONTINGENT RESOURCES	8,428,598	594,872	4,182,434	2,130,587	53,058	1,467,648	501,335	966,313

FUTURE NET REVENUE BY PRODUCTION GROUP AS OF MAY 31, 2007 FORECAST PRICES AND COSTS
CLASSIFICATION	PRODUCTION GROUP	FUTURE NET REVENUE BEFORE INCOME TAXES - (discounted at 10%/year) (M$)
LOW ESTIMATE CONTINGENT RESOURCES	Heavy Oil (including associated gas and by-products)	(117,992)
BEST ESTIMATE CONTINGENT RESOURCES	Heavy Oil (including associated gas and by-products)	(33,484)
HIGH ESTIMATE CONTINGENT RESOURCES	Heavy Oil (including associated gas and by-products)	75,738

PART 2PRICING ASSUMPTIONS

Forecast Prices and Costs

Please see Schedule “A”.

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Part 3Reconciliation Of Changes In Reserves And Future Net Revenue

Reserves Reconciliation

The Corporation has no previous reserves and no current reserves. There is no previous reserves report with respect to the reserves.

Future Net Revenue Reconciliation

Not applicable.

PART 4ADDITIONAL INFORMATION RELATING TO RESERVES DATA

Significant Factors or Uncertainties Affecting Reserves Data

There are a number of risks and uncertainties that may materially adversely affect Patch’s business, financial condition and / or results of operations. Additional risks and uncertainties not currently known to the management of Patch may also have an adverse effect on the business and the information set out below does not purport to be an exhaustive summary of the risks affecting Patch.

Exploration and Reserve Risk

Patch has no existing commercial reserves of any significance as defined under the COGEH rules. Its future value is therefore dependent on the success or otherwise of Patch’s activities which are principally directed towards the further exploration, appraisal and development of its assets in Alberta. Patch has a right to explore and appraise such assets but does not have a right to produce commercial quantities of hydrocarbons until such time as the reserves are determined to be commercial and appropriate exploitation licenses are granted. Exploration, appraisal and development of oil and gas reserves is speculative and involves a significant degree of risk. There is no guarantee that exploration or appraisal of the properties in which Patch holds an interest will lead to a commercial discovery or, if there is commercial discovery, that Patch will be able to realize such commercial discoveries and attributable reserves. Few properties that are explored are ultimately developed into new reserves. If at any stage Patch is precluded from pursuing its exploration or development programmes, or such programmes are otherwise not continued, Patch’s business, financial condition and / or results of operations and, accordingly, the trading price of the common shares, is likely to be materially adversely affected.

Risk of Loss of Joint Ventures and Related Agreements

Patch is subject to the risk of uncertainties or disputes with its joint venture partners under the various joint development, farm-out, joint venture and joint operating agreements. Accordingly, such disputes may result in legal proceedings that may lead to the dilution of its interest in, or the loss of, interests arising out of the agreements.

Title to Properties

Patch’s exploration and prospective production activities are dependent upon the grant and maintenance of appropriate licences, exploration and exploitation permits and regulatory consents (“Authorizations”) which may not be granted or may be withdrawn, or made subject to limitations. Although the  Authorizations may be renewed following expiry or granted (as the case may be), there can be no assurance that such Authorizations will be renewed or granted. In addition Patch will require Authorizations to  convert some of its existing title rights to exploitation or development titles. There may be delays in the conversion of relevant permits or licenses, or the relevant authorities may determine not to give effect to the conversion application. Moreover, if Patch does not meet its work and/or expenditure

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obligations under its permits, licenses and concessions, this may lead to dilution of its interest in, or the loss of, such permits, licenses and/or concessions.

Drilling and Operating Risks

Exploration and development activities may be delayed or adversely affected by factors outside the control of Patch. These include adverse climatic and geographic conditions, labour disputes, the performance of joint venture or farm-in partners on whom Patch may be or may become reliant, compliance with governmental requirements, shortage or delays in installing and commissioning plant and equipment or import or customs delays. Problems may also arise due to the quality or failure of locally obtained equipment or interruptions to services (such as power, water, fuel or transport or processing capacity) or technical support which result in failure to achieve expected target dates for exploration or production and / or result in a requirement for greater expenditure. Drilling may involve unprofitable efforts, not only with respect to dry wells, but also with respect to wells, which, though yielding some oil or gas, are not sufficiently productive to justify commercial development of cover operating and other costs. Completion of a well does not assure a profit on the investment or recovery of drilling, completion and operating costs. Substantial operational risks are involved in the drilling for, development of and production from oil and gas fields, including blow-outs, cratering, explosions, pollution, seepage or leaks, fire, earthquake activity, unusual or unexpected geological conditions, absence of economically viable reserves and other hazards which may delay, or ultimately prevent, the exploitation of such fields or may result in cost overruns or substantial losses or other extensive liabilities to Patch due to substantial environmental pollution or damage, personal injury or loss of life, clean-up responsibilities, regulatory investigation and penalties or suspension of operations. Such hazards can also severely damage or destroy equipment, surrounding areas or property of third parties. Damage or loss occurring as a result of such risks may give rise to claims against Patch. There may be circumstances where Patch’s insurance, or that of the operator of a field, will not cover or be adequate to cover the consequences of such events or where Patch may become liable for pollution or other operational hazards against which it either cannot insure or may elect not to insure on account of high premium costs. The occurrence of an event that is not fully covered by insurance could have a material adverse effect on Patch’s business, financial condition, operations and the results there from. Moreover, there can be no assurance that Patch will be able to maintain adequate insurance in the future at rates Patch consider reasonable.

Results To-Date and Additional Requirements for Capital

Patch is likely to remain cash flow negative for some time and there can be no certainty that Patch will achieve or sustain profitability or positive cash flow from its operating activities.  Patch will need to raise additional capital in the future to fund the work commitments on the properties. The future of Patch is dependent upon its ability to raise the required funding. Patch’s ability to fund its obligations is dependent upon obtaining additional financing in the form of equity, debt, joint ventures, farm-outs or a combination thereof through to the discovery of economically recoverable petroleum and natural gas reserves and the commencement of commercial production. Patch has limited debt capacity and therefore its exploration activities are expected to be financed through equity or third party joint ventures. There is no assurance that additional financing will be available on terms acceptable to Patch. Failure to obtain additional financing on a timely basis could/may cause Patch to forfeit its interest in some or all of the properties and reduce or terminate its operations. In addition, future production, oil and gas prices, environmental rehabilitation or restitution, revenues, taxes, transportation costs, capital expenditures and operating expenses and geological success are all factors which will have an impact on the amount of additional capital required. If Patch fails to satisfy minimum work obligations it may also be liable to pay penalties. Any additional equity financing may be dilutive to shareholders and debt financing, if any, may involve restrictions on financing and operating activities.

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Corporate and Regulatory Formalities

In the jurisdictions in which Patch operates, both the conduct of petroleum operations and the steps involved in Patch acquiring its current interests involve or have involved the need to  comply with numerous procedures and formalities. While Patch has endeavoured to comply with all procedures and has employed local consultants to assist in such compliance, it may not be, nor may not have been possible in all cases to-date to comply with, or obtain waivers from, all such formalities. Patch is unable to predict the effect of additional corporate and regulatory formalities which may be adopted in the future, including whether any such laws or regulations would materially increase Patch’s cost of doing business or effect its operations in any area.

Ability to Exploit Successful Discoveries

It may not always be possible for Patch to participate in the exploitation of successful discoveries made in areas in which Patch has an interest. Such exploitation may involve the need to obtain licenses or clearances from the relevant authorities, which may require conditions to be satisfied and/or the exercise of discretion by such authorities. It may or may not be possible for such conditions to be satisfied. Furthermore, the decision to proceed to further exploitation may require the participation of other companies whose interests and objectives may not be the same as those of Patch or the relevant governmental authorities may require that Patch participate in a unitized development on terms not preferential to Patch. Such further work may also require Patch to meet or commit to financial obligations, which it may not have anticipated or may not be able to commit to due to lack of funds or inability to raise funds.

Environmental Regulation

As Patch is involved in oil and gas exploration, it is subject to extensive environmental and safety legislation (eg. In relation to plugging and abandonment of wells, discharge of materials into the environment and otherwise relating to environmental protection) and this legislation may change in a manner that may require stricter or additional standards than those now in effect, a heightened degree of responsibility for companies and their directors and employees and more stringent enforcement of existing laws and regulations. There may also be unforeseen environmental liabilities resulting from oil and gas activities which may be costly to remedy. In particular, the acceptable level of pollution and the potential clean-up costs and obligations and liability for toxic or hazardous substances for which Patch may become liable as a result of its activities may be impossible to assess against the current legal framework and current enforcement practices of the various jurisdictions. The extent of potential liability, if any, for he costs of abatement of environmental hazards cannot be accurately determined and, consequently, no assurances can be given that the costs of implementing environmental measures or meeting any liabilities in the future will not be material to Patch or affect its business or operations.

Market Risk

In the event of successful development of oil and gas reserves, the marketing of Patch’s prospective production of oil and gas from such reserves will/may be dependent on market fluctuations and the availability of processing refining facilities and transportation infrastructure, including access to ports, shipping facilities, pipelines and pipeline capacity. However, due to the geographic location of the assets, these risks are not considered great.

Reliance on Strategic Relationships

In conducting its business, Patch will rely on continuing existing strategic relationships and forming new ones with other entities in the oil and gas industry, such as joint venture parties and farm-in partners, and also certain regulatory and governmental departments. While the board of directors of Patch have no

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reason to believe otherwise, there can be no assurance that its existing relationships will continue to be maintained or that new ones will be successfully formed and Patch could be materially adversely affected by change to such relationships or difficulties in forming new ones.

Competition

A number of other oil and gas companies operate, and are allowed to bid for exploration and production licenses and other services in Alberta, thereby providing competition to Patch. Larger companies, in particular, may have access to greater resources than Patch, may be more successful in the recruitment and retention of qualified employees, and may conduct their own refining and petroleum marketing operations, which may give them a competitive advantage. In addition, actual or potential competitors may be strengthened through the acquisition of additional assets and interests.

Volatility of Prices of Oil and Gas

The demand for, and price of, oil and gas is highly dependent on a variety of factors, including international supply and demand, the level of consumer product demand, weather conditions, the price and availability of alternative fuels, actions taken by governments and international cartels, and global economic and political developments. Geographic location and a lack of adequate infrastructure may also result in any oil or gas produced being sold at a discount to world market process for oil and gas. International oil prices have fluctuated widely in recent years and may continue to fluctuate significantly in the future due to numerous factors which Patch is neither able to control or predict. Fluctuations in oil and gas prices and, in particular, a material decline in the price of oil and gas may have a material adverse effect on Patch’s business, financial condition, ability to pay dividends and results of operations. The performance of an oil and gas exploration and production company’s share price may, but will not necessarily, exhibit a correlation with the price of oil and gas.

Dependence on Key Personnel

Patch has a small management team and the loss of a key individual or its inability to attract suitably qualified personnel in the future could materially and adversely affect Patch. Difficulties may also be experienced in certain jurisdictions in employing and retaining qualified personnel who are willing to work in such jurisdictions.

Market Perception

Market perception of junior oil and gas exploration companies is volatile and changes could impact the value of investors’ holdings and the ability of Patch to raise funds by the issue of securities of Patch.

Additional factors that can affect the economic impact of the project include but are not limited to unusually high development costs associated with surface infrastructure and construction, operating costs associated with production methods and its fuel and water sources, regulatory approval delays pertaining to environmental concerns or registered public  disputes through the AEUB or Alberta Environment, or unforeseen additional expenses pertaining to the additional pipeline infrastructure such as diluent and production pipelines leading to the proposed projects.

Future Development Costs

The following table outlines development costs, mainly capital and abandonment costs, deducted in the estimation of future net revenue attributable to low estimate, best estimate and high estimate contingent resources (using forecast prices and costs).

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Year	Capital Cost Forecast			Abandonment Cost Forecast
	Low Estimate Contingent Resources (M$)	Best Estimate Contingent Resources (M$)	High Estimate Contingent Resources (M$)	Low Estimate Contingent Resources (M$)	Best Estimate Contingent Resources (M$)	High Estimate Contingent Resources (M$)
2008	6,528	6,528	6,528	-	-	-
2009	8,323	8,323	8,323	-	-	-
2010	14,432	14,432	14,432	-	-	-
2011	215,361	206,961	213,802	-	-	-
2012	160,313	213,802	144,874	-	-	-
Remaining Years	805,902	1,136,264	1,742,628	24,971	34,978	53,058
Total Undiscounted	1,210,859	1,586,310	2,130,587	910	1,358	1,943
Total Discounted at 10% per year	439,054	143,686	693,662	24,971	34,978	53,058

The Corporation intends to facilitate the capital requirements going forward with the use of equity financing and/or possible debt equity financing. Aggregate cost estimates are expected to be approximately 8% of the incremental capital. This cost is not anticipated to have a material affect on the economic impact of the pending projects.

PART 5OTHER OIL AND GAS INFORMATION

Oil and Gas Properties and Wells

As defined under the COGEH rules, section 5.2.2.a, as at May 31, 2007, Patch did not have any reserves attributable to producing or non-producing oil and gas properties.

Properties With No Attributed Reserves

Dover Oil Sands Project

These properties are located at: Twp. 96 Rge. 15 W4M: Sections 2-5; 8-11; 14-17; Twp. 93 Rge. 14 W4M: Sections 25-27; 35; 36; Twp. 95 Rge. 14 W4M: Sections 4-9 and Twp 94 Rge. 14 W4M: Sections 19-21: 28-33.

On December 15, 2006, the Corporation entered into a Share Exchange Agreement with Damascus Energy Inc. (“Damascus”) (a private Canadian company), the stockholders of Damascus, and Patch Energy Inc. (“Patch Energy”), providing for the acquisition of Damascus.  By acquiring Damascus, the Corporation received the right to earn up to an 80% working interest in the Dover Oil Sands Project (previously referred to as the Dover Ells Leases), located approximately 90 kilometres northwest of the Fort McMurray area of central Alberta, Canada under a farmout agreement between Damascus and Bounty Developments Ltd. (“Bounty”).  The Dover Oil Sands Project consists of 32 square miles of land approximately 40 miles northwest of Fort McMurray, representing 20,840 acres.  The Dover Oil Sands Project includes three separate parcels, referred to as Ells North (12 gross sections), Ells Central (15 gross sections) and Ells South (5 gross sections).

The Corporation earned an initial 30% undivided working interest in the Dover Oil Sands Project in exchange for payment of CAD $7,581,500 to Bounty, reimbursement to Bounty for all expenditures made to date on the project, and the issuance of 4,341,489 Exchangeable Shares.  Under the agreement, to earn an additional 50% in the project, the Corporation was required to spud 16 evaluation wells and complete of a 2D seismic program on or before March 31, 2007.  As of April 16, 2007, the Corporation satisfied all the conditions required under the farmout agreement, earning an 80% working interest in the Dover Oil Sands Project.

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As at May 31, 2007, Patch’s held a 80% working interest within 70 square kilometres consisting of twenty-seven sections of land, of prospective hydrocarbon horizons held in the Ells North and Ells Central properties.

The Ells North property contains two exploitable bitumen pools refereed to as the McMurrary Ex (channel facies) McMurray Ex A (shoreface sand facies).  Within the Ells Central property, only the McMurray Ex A has been delineated at this time, but this property remains prospective for discovery of additional accumulations of bitumen with the channel facies.  All properties had insufficient drilling density, seismic mapping or project definition to be categorized as reserves at this time.

The McMurray Ex interval found within Ells North is composed of laterally discontinuous, undifferentiated, stacked estuarine channel deposits with very limited accumulations of associated bottom water. The McMurray Ex interval found within the Ells North and Ells Central properties is composed of fine-to-medium grained, locally stratified shoreface sand deposits with bioturbated shale laminated intervals.

The bitumen contained within the McMurray Ex and Ex A is essentially immobile at reservoir conditions and can only be recovered by in situ thermal recovery processes.  Patch plans to exploit these leases with conventional SAGD.

Regional Geology

Within the Athabasca Oil Sands Area, bitumen accumulations are predominantly attributed to clastic sediments of the McMurray Formation, the basal unit of the Lower Cretaceous Mannville Group. Lesser quantities are associated with the overlying Mannville Clearwater Formation, including the basal Wabiskaw Member, overlying Clearwater successions and the succeeding Grand Rapids Formation of the Upper Mannville Group. The Company’s exploitable bitumen volumes are attributed to the McMurray Formation.

Geology of the Dover Ells Leases

The Company’s Ells North and Ells Central properties are north-centrally situated within the Athabasca Oil Sands Area. Bitumen accumulations here are found within clastic sediments of the McMurray Formation and Wabiskaw Member of the Lower Cretaceous Mannville Group. Reservoir within the Dover Ells properties is associated predominantly with estuarine channel sequences of the McMurray Formation, as well as with the shallow marine shoreface complexes of the McMurray and overlying Wabiskaw Member. Channelized McMurray is isolated within the lower reaches of the McMurray, while stacked shoreface complexes dominate the upper reaches of the McMurray. While instances of shoreface deposits overlying channel deposits exist, no occurrences of coincidental channel and shoreface sequences amenable to conventional SAGD exploitation utilizing a single well pair are noted within the boundaries of the Ells North and Ells Central properties. Therefore, separate recovery schemes will be necessary in order to fully exploit each interval.

Overlying the McMurray shoreface deposits is the Wabiskaw C, consisting of additional stacked shallow marine shoreface deposits within an overall thinner stratigraphic interval. Exploitation of the Wabiskaw C is limited to coincidental occurrences of Wabiskaw C and underlying McMurray shoreface deposits such that an adequate reservoir thickness is achieved. The Wabiskaw A succeeds the Wabiskaw C and consists of generally thin and poorly developed stacked shoreface sequences, unfavorable for SAGD exploitation.

The channelized McMurray consists of laterally discontinuous, undifferentiated, stacked McMurray channel deposits, attributed to the McMurray EX. The channel deposits consist of overall fining-upward sequences of very fine- to coarse-grained sands, with intervals of Inclined Heterolithic Stratification (IHS) within estuarine stacked bar complexes. Reservoir quality of the interval is greatest at the base where

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sands rest directly on the Devonian unconformity. Intervals of muddy IHS commonly increase, both in occurrence and thickness, upwards within the majority of wells. Significant bioturbation is generally noted within these intervals. This has significantly enhanced vertical permeability within this zone. To date, a single main channel system oriented southeast-northwest has been delineated within the Ells North property. This may cross-cut an earlier channel system oriented east-west. This channel system represents someof the easternmost occurrences of channelized McMurray delineated to date.

The shallow marine McMurray and Wabiskaw C consists of stacked marine shoreline sequences, consisting of proximal shelf deposits, consisting of heavily bioturbated shale dominated sections overlain by lower to upper shoreface deposits, containing very fine to medium grained, locally cross-stratified sands with bioturbated, moderately to heavily shale-laminated intervals. In general, the volume of sand increases upwards in these sequences, while the volume of shale decreases, which is responsible for their coarsening –upward signature on geophysical well logs. These sequences represent oceanward-prograding shoreline complexes within a shallow marine depositional system. Exploitable occurrences of this reservoir delineated to date are present mostly within the Ells North property.

Some of the exploitable bitumen on the Ells North property is affected by impairment zones, including possibly laterally limited bottom water within the McMurray EX and a small accumulation of top gas within the McMurray EX A. The top gas has not undergone production and it is unclear if it is associated with production offsetting to the west. No impairment zones are noted for the McMurray within Ells Central.

Competent reservoir seal for the McMurray EX consists of IHS within the upper reaches of the channel sequences. Further facilitating sealing is the presence of a notable regional shale horizon that overlies the channelized interval. Sealing within the McMurray EX A generally consists of regionally extensive horizons of variably bedded shale (Wabiskaw D Shale and Wabiskaw A Shale) and/or heavy mud laminations.

Analogies

A number of analogous, producing SAGD projects were examined as part of the McDaniels Report. Analogies were chosen primarily based on similarities with respect to operating pressure and reservoir quality and facies type. These analogies are discussed in detail below:

Deer Creek Joslyn Pilot (Section 33-095-12W4)

The Deer Creek/Total SA Joslyn Pilot is a useful analogy primarily due to reservoir quality and permeability, although operationally the steam injection pressure at Joslyn is much lower than what is expected for Dover Ells.

In the area of the Pilot at Joslyn, the McMurray zone is 20 to 40 metres in thickness and is at about 90 to 105 metres of depth. The SAGD operating pressure for the Joslyn SAGD development was originally expected to be as high as 1,700 kPaa⁵, but has been revised to be 900 to 1,200 kPaa.Initial expectations from the pilot well-pair, which was drilled in 2003 and came on-stream in 2004, were to achieve a productive rate in excess of 600 Bopd. During periods in 2005 and 2006,the pilot well achieved a maximum sustained productive rate of 320 Bopd and a Cumulative Steam Oil Rations (CSOR) of 4.18.It is generally recognized that a portion of the producing well-bore for the Pilot well is not optimally placed, and that the entire length of the well-bore may not be contributing to production.

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⁵ Kilopascals measured at atmospheric pressure.

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Commercial activation of the SAGD at Joslyn has been problematic and complicated by a steam release to surface in May of 2006, which was the result of injecting steam excessive pressure, creating a fracture in the reservoir at the injector.

Due to the probability of higher-pressure operations causing further reservoir breaching, the operator now projects that operating pressure must be reduced to below 1,200 kPaa, from the originally-planned operating pressure of 1,700 kPaa. The operator has revised their expectation of well deliverability to 375 Bopd/well-pair.

Suncor Firebag (Township 95, Range 6W4)

Suncor’s Firebag Insitu project is under commercial development and approval has been received for expansion to 140,000 Bbl/d⁶. Design steam-oil ratio is 2.0, although present CSOR is closer to 4.0. Average well productivity is in the range of 1,415 Bopd with average to-date CSORs ranging from 2.0 to 6.0.

The Firebag project is a valid analogy to consider because of the reservoir pressure. The reservoir is 320 metres deep and Suncor states that reservoir pressure is 800 kPaa, although this is substantially under-pressured for the depth of the reservoir. The operating pressure for the project is not known but is suspected to be well above the initial pressure of the reservoir. Average net pay ranges from 20 to 30 metres. The reservoir has very high permeability, both vertical and horizontal, and there are areas that contain significant top-water and some mid-water.

Wells producing at Suncor’s Firebag project generally have 1,000 metres of productive well-bore and are completed with 9-5/8” liners, compared with the standard 7” liners used for most other commercial SAGD projects. The larger diameter liners essentially double the effective cross-sectional area of the Suncor wells and they can produce at higher production rates.

If the average productivity of the Firebag wells is corrected for a 700-metre horizontal with a 7” diameter liner, productivity would be closer to 525 Bopd. Steam-oil ratios are likely high for the existing project configuration due to the extremely high rates of fluid withdrawal from the reservoir and the corresponding loss of heat energy. The long, wide-diameter horizontal wells are very expensive to drill and complete.

Petro-Canada MacKay River (Township 93, Range 12W4)

Petro-Canada operates a 33,000 Bopd-capacity SAGD project directly southwest and adjacent to the Syncrude mining development. First production commenced in November 2002 and the project is presently approaching 30,000 Bopd.

Reservoir depth at MacKay River is 80 – 135 metres from surface and there is little or no bottomwater or top-gas present, and small areas of top-water. The net:gross and kv:kh⁷ parameters for this reservoir are excellent; likely some of the best SAGD reservoir quality in the northern portion of

the Athabasca Oil Sands Area.

What makes MacKay River a valid analogy for this evaluation is again the reservoir pressure: Petro-Canada states that the initial reservoir pressure is 300 – 500 kPaa. What makes MacKay River an interesting analogy for the Dover Ells properties is the initial injection pressure of 1,750 kPag. This elevated operating pressure results in much higher productivity than would be thecase for a lower-

_______________________

⁶ Barrels per day

⁷ Vertical permeability to horizontal permeability.

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pressure operation. Data from observation wells suggests that reservoir pressure near and within the steam-chamber has increased to 900 – 1,000 kPag8.

For Phase 1 (25 well pairs, on-stream since 2002), average well-pair productivity is 680 Bopd/well. Horizontal wells are typically 700 metres in length.

CSOR to-date is in the range of 2.4 to 2.5 and individual well performance ranges from a low of 1.75 to as high as 4.0. Steam quality is about 80 percent. Recovery to-date for Phase 1 is approximately 18 percent of OBIP, and Petro-Canada is forecasting ultimate recovery to be as high as 62 percent of OBIP⁹.

__________________

⁸ Kilopascals measured in gauge pressure.

⁹ Original Bitumen in place.

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Other Properties

Firebag Oil Sands Project

This property is located at: Twp. 91 Rge. 2 W4M: Sections 25-36 and Twp. 92 Rge. 2 W4M: Sections 1-6.

On January 16, 2007, the Corporation entered into a Share Exchange Agreement with 1289307 Alberta Ltd. (“1289307”) (a private Canadian company), the stockholders of 1289307, and Patch Energy, providing for the acquisition of 1289307.  Patch Energy acquired all of the issued and outstanding common shares of 1289307 in consideration for 1 Class B Preferred Voting Share and 500,000 Exchangeable Shares.

By acquiring 1289307, the Corporation received the right to earn up to a 75% working interest in 18 square miles of land located in Townships 91-92, Range 2 W4M (the “Firebag Oil Sands Project”), in the Fort McMurray area of central Alberta, Canada, pursuant to a farmout agreement with Bounty.  The Corporation earned an initial 25% working interest in the Firebag Oil Sands Project by making payments to Bounty in the amount CAD $5,100,000.  Under the agreement, the Corporation had the right to earn an additional 50% working interest by: (i) spudding 8 evaluation wells and completing a 2D seismic program on the property on or before March 31, 2007; (ii) paying Bounty CAD $2,500,000 on or before April 1, 2007; (ii) spudding 4 additional evaluation wells on or before April 1, 2008; and (iv) and completing another 2D seismic program on the property on or before March 31, 2008.  As of the filing of this report, the Corporation was able to spud 3 evaluation wells before March 31, 2007 and paid Bounty CAD $2,500,000.  The Corporation negotiated a compromise with Bounty and the remaining requirements to earn the additional 50% working interest have been waived.  In exchange for a waiver of the remaining requirements under the farmout agreement, the Corporation agreed that Bounty’s 25% working interest in the Firebag Oil Sands Project will be a carried interest until the Corporation has spent an additional CAD $1,500,000 on exploration (drilling and seismic evaluation) expenses.  As of April 16, 2007, the Corporation has earned the full 75% working interest in the Firebag Oil Sands Project.

Muskwa

Pursuant to an Assignment of Lease between the Patch Oilsands Limited Partnership and Patch Energy dated March 8, 2007 (the “Assignment”), the Patch Partnership distributed three Crown oil sands leases in the Muskwa area of Alberta, comprising 10 sections (1,024 hectares) under a 15-year lease with annual rent payable to the Alberta Crown of CAD $3.50 per hectare and Crown royalties on production, to the Patch Partnership's members in proportion to their partnership interests. As a result of the pro-rata distribution, Patch Energy has a 75% interest in 2 sections and 100% interest in 8 sections of the Muskwa property for a combined average of 95% working interest.

Leismer

This property is located at: Twp. 78 Rge. 8 W4M: Section 5; Twp. 78 Rge. 9 W4M: Section 11; and

Twp. 77 Rge. 9 W4M: W1/2 Section 9. The Corporation has a 75% working interest in the 512 hectares located in sections 5 and 11, and an 80% interest in the 128 hectares in W1/2 section 9. Sections 5 and 11 are undeveloped while W1/2 section 9 has had 2D seismic acquired and an appraisal well was drilled at location 6-19. Costs expended to date amount to $2,246,210.45.

Atlee- Buffalo

This property is located at: Twp.21 Rge. 4 W4M: W1/2 Section 30. The Corporation acquired this property under an agreement dated November 8, 2005.  Under the terms of this agreement, a test well was to be spudded no later than December 31, 2005, which was extended by agreement to June 30, 2006.  The

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Corporation earns a 50% working interest in the test well at Atlee-Buffalo, subject to an overriding royalty convertible after pay-out such that, if converted, the Corporation’s interest  reverts  to a  30%  working interest in those wells and a 30% working interest in the balance of the farm out lands, by paying 50% of the costs of each well.  This property is subject to a 1% gross overriding royalty and Crown royalties. A commitment well at 02/14-30-21-4w4 was spudded  Aug 8, 2006 and rig released Aug 13, 2006. It’s current status is cased and standing. This is a non-producing gas property. Costs expended to date amount to $202,947.49.

Cessford

This property is located at: Twp.26 Rge. 11 W4M: Section 19. The Corporation acquired this property under a farm in agreement dated June 21, 2006. By drilling the well 14-19-26-11w4 the Corporation earned an 80% interest in 256 hectares. The status of 14-19 is perforated, fracture treated and plugged. This property is subject to a 1% gross overriding royalty and Crown royalties. This is a non-producing oil and gas property. Costs expended to date amount to $307,061.55.

Halkirk

This property is located at: Twp.37 Rge. 17 W4M: NE Section 29. The Corporation acquired this property under a farm in agreement dated Jan 4, 2006. By drilling the well 103/16-29-37-17w4 the Corporation earned a 100% interest before payout converting to 50% after payout. The status of 103/16-29 is perforated, fracture treated and standing.  This property is subject to a 1% gross overriding royalty and Crown royalties. This is a non-producing oil and gas property. Costs expended to date amount to $310,507.95.

McLeod

This property is located at: Twp.56 Rge. 13 W5M: Section 20. The Corporation acquired this property under a farm in agreement dated May 30, 2005. By participating in drilling the well 2-20-56-13w5 the Corporation earned a 10% interest. The status of  9-20 is pumping Belly River oil well.  This property is subject to Crown royalties. Costs expended to date amount to $224,911.75.

Red Deer

The Corporation acquired a 50% working interest in 440 hectares located in portions of sections 5-38-26w4, 33-37-26w4 and 31-37-26w4 between the dates of June 8, 2006 and Dec 15, 2006.  This is a non-producing freehold oil and gas property and is subject to an 18% lessor royalty.  Costs expended to date amount to $121,104.97.

Rumsey

The Corporation has a 26.25% working interest in 64 hectares located at NE9-34-21w4.  This is a non-producing oil and gas property. The well 102/6-9-34-21w4 was drilled and rig released July 27, 2006.It has subsequently been tested and abandoned. Costs expended to date amount to $638,432.21.

Worsley

This property is located at: Twp.87 Rge. 7 W6M: Section 13. The Corporation has a 50% working interest in 256 hectares in the above section.  This is a non-producing oil and gas property. Costs expended to date amount to $233,490.66.

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The following table sets forth the gross and net acres of the non-core area properties held by the Corporation.

	UNPROVED PROPERTIES - UNDEVELOPED LAND (hectares)
LOCATION	Gross(1)	Working Interest	Net(2)
Oil Sands Property
Ells South	1,280	80%	1,024
Firebag	4,608	75%	3,456
Muskwa	2,560	95%	2,432
Leismer	512	75%	384
TOTAL	8,960	81%	7,296
Conventional Property
Atlee-Buffalo	128	50%	64
Cessford	256	80%	205
Halkirk	64	100%	64
McLeod	256	10%	26
Red Deer	440	50%	220
Rumsey	64	26.25%	17
Worsley	256	50%	128
TOTAL	1,464	49%	724

Notes:

(1)          “Gross Acres” are the total acres in which the Corporation has or had an interest.

(2) “Net Acres” is the aggregate of the total acres in which the Corporation has or had an interest multiplied by the Corporation’s working interest percentage held therein.

Forward Contracts

No contracts or agreements are in place with the Corporation such as a transportation agreement nor through an aggregator.

Additional Information Concerning Abandonment and Reclamation Costs

Not applicable.

Tax Horizon

The Corporation is not required to pay income taxes for the financial year and my be subject to income tax in the future years depending upon future exploration and appraisal activity undertaking by the Corporation.

Costs Incurred

During the fiscal year ended May 31, 2007 the Corporation was active in the drilling and development of a number of conventional oil and gas prospects in Canada as well as the acquisition and exploration of various oil sands leases in northern Alberta.  All of the Corporation’s activity for the past fiscal year was located in western Canada.

Conventional Oil and Gas Prospects

During the year the Corporation incurred costs of approximately $800 thousand to acquire and/or farm-in on various unproved oil and gas leases, incurred approximately $100 thousand in exploration costs

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primarily associated with the shooting and processing of seismic data on these leases and a further $2.3 million was spent on development drilling and completion costs.

Oil sands activity

In December 2006 the Corporation acquired all of the issued and outstanding shares of Damascus with various unproven oilsands leases at Dover (Ells) in Alberta, which was acquired through a farm-in agreement with Bounty Developments Ltd.  The value ascribed to the oil and gas properties acquired was $23.5 million USD.  Subsequent to the acquisition the Corporation has incurred exploration costs of approximately $12.6 million on these leases, which included the drilling and evaluation of 19 evaluation wells and the shooting and processing of a 2D seismic program. Please refer to the section entitled “Properties With No Attributed Reserves- Dover Oil Sands Project”.

In January 2007 the Corporation acquired all of the issued and outstanding shares of 1289307 with various unproven oilsands leases at Firebag in Alberta, which was acquired through a farm-in agreement with Bounty.  The value ascribed to the oil and gas properties acquired was $2.0 million USD.  Subsequent to the acquisition the Corporation has incurred further acquisition costs of approximately $6.3 million to meet the initial terms of the farm-in agreement as well as exploration costs of approximately $5.9 million on these leases, which included the drilling and evaluation of 3 evaluation wells and the shooting and processing of a 2D seismic program. Please refer to the section entitled “Other Properties - Firebag Oil Sands Project”.

Exploration and Development Activities

A two-phase development plan is planned for the Ells North property and a single stage development for the Ells Central Property, due to the relatively small size of that project in comparison to other, larger multi-phase projects.10

Drilling of approximately 88 Oil Sands Evaluation Wells (“OSE”) was forecasted over the course of the next four years, in order to sufficiently delineate the lease to 8 wells/section.

On a Best Estimate basis, the timing of the project was forecasted to commence in 2012 with a 10,500 Bopd development at Ells North and a 1,700 Bopd development at Ells Central (capacities stated on a gross Lease basis).  An expansion of the Ells North project to 17,500 Bopd was forecast to be on-stream in 2014.  Cumulative production is forecasted to reach capacity in 2015 from 50 producing well-pairs drilled in 2012, 2013 and 2014.  Additional sustaining drilling is forecast for 2016 through 2035.

During this past winter, 19 new core holes were drilled resulting in a total number of 15 core holes on the Ells North parcel and  4 core holes drilled on the Ells Central parcel.  The Corporation’s technical staff is fully engaged with the interpretation and integration of related data.  The Corporation has commenced planning of a comprehensive 2007-2008 reservoir modelling evaluation, and an environmental baseline study.  The reservoir modelling will be based on core hole data collected in the past drilling season, and is estimated to cost approximately $120,000. An environmental baseline study is a prerequisite for a comprehensive SAGD application to the Alberta Energy and Utilities Board.  The data collection was done in July 2007.  The Baseline report is to be completed in the winter 2007 – 2008  and is estimated at $40,000.  In addition, the Corporation is preparing an application for a SAGD pilot program within the next 18 months. Subject to additional financing, the Corporation may accelerate this program into the 2007 – 2008 drilling season including core hole drilling, and a seismic program.

______________________

¹⁰ McDaniel’s made a number of assumptions relating to the scope of the project and the timeline for its development.

The Corporation believes that the proceeds raised from the recently completed private placement of Nom-Flow-Through Special Warrants and Flow-Through Special Warrants will be sufficient to fund it’s operations planned for the calendar year 2007.  These activities consist of the interpretation and integration of the data from drilling, applying for listing on the TSX Venture Exchange, the (“TSXV”) and market evaluation of a SAGD land infrastructure with adjacent projects.

The Corporation will require significant additional financing for its 2008-2009 exploration program, which will likely include the drilling of more core holes and shoting seismic data.  Management believes that a listing on the TSXV will improve the visibility of the Corporation and its chances for obtaining additional financing.  The Corporation does not have any commitments for additional financing as of this date. The Corporations development schedule will allow for a development timeline achieving production by 2012.

Subject to raising of additional capital, the costs of future work programs for the years 2008 through 2011 to obtain production in 2012, are as follows:

Year	Amount ($M)
2008	6,528(1)
2009	8,323(2)
2010	14,432(3)
2011	206,961(4)

Notes:

(1)        Core hole delineation drilling. and Environmental baseline evaluation.

(2)        Core hole delineation drilling, and seismic.

(3)        Core hole delineation and long lead construction items.

(4)        Construction of SAGD Project infrastructure and project commissioning.

Production Estimates and Production History

The Corporation did not have producing wells and has not drilled any wells as of May 31, 2007.

Schedule “A”

	McDANIEL & ASSOCIATES CONSULTANTS LTD.																					Table 1 - 1
	OIL SANDS PRICE FORECAST
	Based on McDaniel & Associates Consultants July 1, 2007 Commodity Forecast Pricing
	Utilizing historical product and transportation offsets
															HARDISTY DELIVERY		EDMONTON DELIVERY
					Alberta	Alberta										Netback		Netback
	U.S./		WTI	Edmonton	Bow River Hvy	Bow River Hvy	LLB	LLB	Edmonton	Diluent	Diluent	SSB (SCO)	SSB (SCO)	Edmonton	DilBit at	Bitumen at	DilBit at	Bitumen at	Natural Gas	Natural Gas	Alberta
Year	Canada	Inflation	Price	MSW1	at Hardisty2	at Hardisty	at Hardisty3	at Hardisty	C5+4	at Edmonton4	at Fieldgate	at Edmonton5,6	at Edmonton	Prem. SCO7	Hardisty	Fieldgate8	Edmonton	Fieldgate8	at AECO	at Fieldgate	Power9
	Exchange	%/year	US$/Bbl	CDN$/Bbl	CDN$/Bbl	% of WTI	CDN$/Bbl	% of WTI	CDN$/Bbl	CDN$/Bbl	CDN$/Bbl	CDN$/Bbl	% of WTI	CDN$/Bbl	CDN$/Bbl	CDN$/Bbl	CDN$/Bbl	CDN$/Bbl	CDN$/GJ	CDN$/Mmbtu	CDN$/MWH
1997	0.722	1.6	20.53	27.80	21.22	0.75	20.38	0.72	31.10			28.25	0.99						1.71
1998	0.687	1.0	14.40	20.35	14.60	0.70	13.29	0.63	21.85			20.46	0.98						1.96
1999	0.673	1.7	19.26	27.60	23.35	0.82	22.12	0.77	27.60			28.31	0.99						2.79
2000	0.674	2.7	30.31	44.72	34.35	0.76	32.59	0.72	46.25			44.96	1.00						5.32
2001	0.646	2.6	25.97	39.60	25.07	0.62	23.46	0.58	42.42			40.31	1.00						5.15		78.29
2002	0.637	2.2	26.08	39.95	31.65	0.77	30.59	0.75	40.65			41.16	1.01						3.86		50.93
2003	0.716	2.0	31.04	43.15	32.68	0.75	31.16	0.72	44.10			43.44	1.00						6.32		69.99
2004	0.770	2.0	41.40	52.54	37.60	0.70	36.80	0.68	55.77			53.20	0.99						6.20		61.66
2005	0.826	2.1	56.56	68.72	44.83	0.65	42.79	0.62	77.30			70.58	1.03						8.14		77.36
2006	0.880	2.2	66.22	72.80	51.55	0.69	50.30	0.67	77.75			73.16	0.97						6.25		87.47
2007/H1	0.882	3.2	61.55	69.60	50.45	0.72	48.42	0.69	73.70			73.00	1.05						6.90		63.58
2007 rem.	0.925	2.0	67.50	72.00	50.10	0.69	47.90	0.66	73.50	75.00	76.43	75.00	1.03	75.70	49.86	36.80	49.32	35.95	6.65	6.77	78.00
2008	0.925	2.0	66.30	70.70	50.60	0.71	48.40	0.68	72.20	73.73	75.19	72.20	1.01	72.91	48.96	36.01	48.43	35.18	6.85	6.97	80.04
2009	0.925	2.0	65.00	69.20	51.00	0.73	48.90	0.70	70.80	72.36	73.85	70.20	1.00	70.93	47.92	35.07	47.40	34.25	6.95	7.07	81.72
2010	0.925	2.0	63.70	67.80	50.60	0.73	48.90	0.71	69.40	70.99	72.51	68.30	0.99	69.04	46.95	34.22	46.44	33.42	7.10	7.23	83.40
2011	0.925	2.0	62.20	66.20	49.40	0.73	47.70	0.71	67.80	69.42	70.97	66.20	0.98	66.96	45.84	33.26	45.35	32.47	7.25	7.38	85.10
2012	0.925	2.0	60.70	64.50	48.10	0.73	46.50	0.71	66.20	67.86	69.43	64.00	0.98	64.77	44.67	32.20	44.18	31.43	7.45	7.58	87.19
2013	0.925	2.0	61.90	65.80	49.10	0.73	47.40	0.71	67.50	69.19	70.80	64.80	0.97	65.59	45.57	32.87	45.07	32.08	7.60	7.74	88.53
2014	0.925	2.0	63.20	67.20	50.10	0.73	48.40	0.71	68.90	70.62	72.26	65.70	0.96	66.50	46.54	33.59	46.03	32.78	7.80	7.94	90.64
2015	0.925	2.0	64.40	68.40	51.00	0.73	49.30	0.71	70.20	71.96	73.63	66.90	0.96	67.72	47.37	34.15	46.85	33.33	7.90	8.04	92.38
2016	0.925	2.0	65.70	69.80	52.10	0.73	50.30	0.71	71.60	73.39	75.10	68.30	0.96	69.14	48.34	34.86	47.81	34.03	8.05	8.19	94.14
2017	0.925	2.0	67.00	71.20	53.10	0.73	51.30	0.71	73.00	74.83	76.57	69.70	0.96	70.55	49.31	35.58	48.77	34.73	8.20	8.35	95.91
2018	0.925	2.0	68.40	72.70	54.20	0.73	52.40	0.71	74.60	76.47	78.24	71.20	0.96	72.07	50.34	36.31	49.80	35.44	8.40	8.55	98.07
2019	0.925	2.0	69.80	74.20	55.30	0.73	53.40	0.71	76.10	78.00	79.81	72.70	0.96	73.59	51.38	37.07	50.83	36.19	8.60	8.76	100.24
2020	0.925	2.0	71.10	75.60	56.40	0.73	54.40	0.71	77.50	79.44	81.29	74.10	0.96	75.01	52.35	37.78	51.79	36.88	8.70	8.86	102.05
2021	0.925	2.0	72.60	77.20	57.50	0.73	55.60	0.71	79.20	81.18	83.06	75.70	0.96	76.62	53.46	38.56	52.88	37.64	8.90	9.06	104.25
2022	0.925	2.0	74.05	78.74	58.65	0.73	56.71	0.71	80.78	82.80	84.72	77.24	0.96	78.19	54.53	39.33	53.94	38.39	9.08	9.24	106.34
2023	0.925	2.0	75.53	80.32	59.82	0.73	57.85	0.71	82.40	84.46	86.42	78.82	0.97	79.78	55.62	40.12	55.02	39.16	9.26	9.43	108.46
2024	0.925	2.0	77.04	81.93	61.02	0.73	59.00	0.71	84.05	86.15	88.15	80.43	0.97	81.41	56.73	40.92	56.12	39.94	9.44	9.61	110.63
2025	0.925	2.0	78.58	83.56	62.24	0.73	60.18	0.71	85.73	87.87	89.91	82.06	0.97	83.06	57.87	41.74	57.24	40.74	9.63	9.81	112.84
2026	0.925	2.0	80.16	85.24	63.48	0.73	61.39	0.71	87.44	89.63	91.71	83.74	0.97	84.75	59.03	42.58	58.39	41.56	9.83	10.00	115.10
Thereafter	0.925	2.0	+2.0%/yr	+2.0%/yr	+2.0%/yr	0.73	+2.0%/yr	0.71	+2.0%/yr	+2.0%/yr	+2.0%/yr	+2.0%/yr	0.97	+2.0%/yr	+2.0%/yr	+2.0%/yr	+2.0%/yr	+2.0%/yr	+2.0%/yr	+2.0%/yr	+2.0%/yr
		NOTES:
		1	40 degree API, 0.5 wt% sulphur
		2	BRN at Hardisty with density of 929 kg/m3, API of 20.68˚ and sulphur of 2.85 wt% as per crude assay August 2006, w.crudemonitor.ca
		3	LLB at Hardisty with density of 926.8 kg/m3, API of 21.04˚ and sulphur of 3.75 wt% as per crude assay April 2006, ww.crudemonitor.ca
		4	Edmonton C5+ price is based EPL segregated condensate price (725 kg/m3 and 0.2 wt% sulphur) and historical average premium to Edmonton MSW. Diluent price has been adjusted for naphtha-quality diluent of 720 kg/m3
		5	SSB at Edmonton with density of 872 kg/m3, API of 30.58˚ and sulphur of 0.11 wt% as per crude assay August 2006, w.crudemonitor.ca SSB production will be replaced in Q4 2007 when Syncrude's new aromatics saturation unit comes on-line, allowing for the upgrade of all bitumen to SSP (preimium synthetic)
		6	Prior to 2006/06/30 based on ECA prices quoted for SSB at Edmonton; After 2006/06/30 based on COS realized plantgate price adjusted for transportation to Edmonton
		7	Based on historical SSB price relationship to WTI with $0.70/Bbl positive quality adjustment for premium SCO
		8	Blend ratio of diluent to bitumen assumed to be 0.30 Bbl : 0.70 Bbl based on bitumen assay
		9	Includes cost of transmission; historical prices based on Alberta Spot Electricity pool price for year plus transmission; Alberta Spot Electicity price forecast is based onestimated marginal cost of natural gas fired generation assuming 7500 Btu is needed to generate 1 kWh and assuming opcosts of 2007$.01/kwh and return on capital assumed to be 2007$.01/kWh