Harvest retained qualified, Independent Reserves Evaluators to evaluate and prepare reports on 100% of Harvest's crude oil and natural gas reserves as of December 31, 2010. Harvest's reserves were evaluated by McDaniel (who evaluated approximately 20% of Harvest's total proved plus probable reserves) and GLJ (who evaluated approximately 80% of Harvest's total proved plus probable reserves). All of Harvest's reserves were evaluated using the price and cost assumptions of McDaniel as at January 1, 2011.

The Statement summarizes the crude oil, natural gas liquids and natural gas reserves of Harvest and the Operating Subsidiaries and the net present values of future net revenue for these reserves using forecast prices and costs. The Reserve Report has been prepared by the Independent Reserve Evaluators in accordance with other requirements contained in NI 51-101. Additional information not required by NI 51-101 has been presented to provide continuity and additional information which Harvest believes is important to the readers of this information. Harvest engaged the Independent Reserves Evaluators to provide an evaluation of proved and proved plus probable reserves and no attempt was made to evaluate possible reserves.

All of Harvest and the Operating Subsidiaries' reserves are in Canada and, specifically, in the provinces of Alberta, British Columbia and Saskatchewan.

Disclosure provided herein in respect of BOE's may be misleading, particularly if used in isolation. A BOE conversion ratio of 6 Mcf: 1 bbl is based on an energy equivalency conversion method primarily applicable at the burner tip and does not represent a value equivalency at the wellhead. It should not be assumed that the estimates of future net revenues presented in the tables below represent the fair market value of the reserves. There is no assurance that the forecast prices and cost assumptions will be attained and variance could be material. The recovery and reserve estimates of Harvest and the Operating Subsidiaries' crude oil, natural gas liquids and natural gas reserves provided herein are estimates only and there is no guarantee that the estimated reserves will be recovered. Actual crude oil, natural gas and natural gas liquid reserves may be greater than or less than the estiamtes provided herein.

The following tables summarize certain information contained in Harvest’s reserves report.

Harvest Reserves Summary as at December 31, 2010 – Forecast Prices and Costs

Gross⁽¹⁾

Net⁽²⁾

Notes:

1. “Gross” reserves means the total working interest share of Harvest’s remaining recoverable reserves before deductions of royalties payable to others.
2. “Net” reserves means Harvest’s gross reserves less all royalties payable to others.
3. Oil equivalent amounts have been calculated using a conversion rate of six thousand cubic feet of natural gas to one barrel of oil. BOEs may be misleading, particularly if used in isolation. This conversion ratio is based on an energy equivalency conversion method primarily applicable at the burner tip and does not represent a value equivalency at the wellhead.
4. Columns may not add due to rounding.
5. The reserves attributable to Harvest’s Hay River property, which is an area that produces medium gravity crude oil (average 24° API), are subject to a heavy oil royalty regime in British Columbia and would be required, under NI 51-101, to be classified as heavy oil for that reason. We have presented Hay River reserves as medium gravity crude in the following reserve tables as they would otherwise be classified in this fashion were it not for the lower rate royalty regime applied in British Columbia. If the Hay River reserves were included in the heavy crude oil category, it would increase the gross heavy oil reserves and reduce the light/medium oil reserves by the following amounts: Proved Developed Producing: 11.4 MMbbl, Proved Undeveloped: 5.8 MMbbl, Total Proved: 17.2 MMbbl, Probable: 5.5 MMbbl and Proved plus Probable: 22.7 MMbbl, and would increase the net heavy oil reserves and reduce the light/medium oil reserves by the following amounts: Proved Developed Producing: 9.9 MMbbl, Proved Undeveloped: 4.9 MMbbl, Total Proved: 14.8 MMbbl, Probable: 4.9 MMbbl, and Proved plus Probable: 19.7 MMbbl.

Harvest Net Present Value of Future Net Revenue of Reserves as at December 31, 2010 –
Forecast Prices and Costs

Note:

1. Columns may not add due to rounding.

McDaniel & Associates Consultants Ltd. January 1, 2010 Price Forecast

The forecast cost and price assumptions assume increases in wellhead selling prices and take into account inflation with respect to future operating and capital costs. Crude oil and natural gas benchmark reference pricing, inflation and exchange rates utilized in the Reserve Report, based on McDaniel's then current forecast at the date of the Report, were as follows: 

Summary of Pricing and Inflation Rate Assumptions as of january 1, 2011

Forecast Prices and Costs

Notes:

1. West Texas Intermediate at Cushing Oklahoma 40 degrees API/0.5% sulphur
2. Edmonton Light Sweet 40 degrees API, 0.3% sulphur
3. Bow River at Hardisty Alberta (Heavy stream)
4. Heavy crude oil 12 degrees API at Hardisty Alberta (after deduction of blending costs to reach pipeline quality)
5. Exchange rates used to generate the benchmark reference prices in this table.

Harvest 2010 Reconciliation Table – Forecast Prices and Costs

Note: (1) Columns may not add due to rounding.