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Harvest Energy Trust Announces Year End 2006 Reserves

Mar 12, 2007 - 22:59 ET

 CALGARY, ALBERTA--(CCNMatthews - March 12, 2007) - Harvest Energy Trust (TSX:HTE.UN) (NYSE:HTE) ("Harvest") today announces a summary of its 2006 year end reserves information. Unless otherwise indicated, all reserves stated herein are gross reserves (before royalty burdens and without including royalty interests), based on forecast prices and costs, except where indicated.

Highlights of Harvest's Reserves:

- An 82% increase in total Proved reserves and 84% increase in Proved plus Probable ("P+P") reserves to 159.2 million barrels of oil equivalent ("mmboe") (2005 - 87.7 mmboe) and 220.3 mmboe (2005 - 119.7 mmboe), respectively;

- Successful drilling and optimization activities generated approximately 18.9 mmboe of P+P reserve additions (prior to the conversion of booked undeveloped reserves), replacing approximately 87% of 2006 production;

- Compared to the reported 2005 combined proforma total Proved and P+P reserves of Harvest and Viking Energy Royalty Trust of 151.6 mmboe and 206.3 mmboe, respectively, total Proved reserves increased 5% to 159.2 mmboe and P+P reserves increased 7% to 220.3 mmboe;

- High percentage of Proved Developed Producing reserves (approximately 86%) of the total Proved reserves. Total Proved reserves represent approximately 72% of the total P+P reserves;

- Development and exploration capital investments totaled $363.5 million and added net 15.0 mmboe after the conversion of booked undeveloped reserves resulting in Finding & Development ("F&D") costs on a P+P reserve basis before changes in future development capital ("FDC") of $24.30 per boe, and including FDC of $26.04 per boe(1);

- Based on total capital spending of $2,830.6 million including acquisitions, Finding, Development and Acquisition ("FD&A") costs, before changes in FDC, are $23.13 per boe on a P+P reserve basis. Including FDC, the P+P FD&A costs are $24.59 per boe(1);

- Three year average P+P F&D costs of $13.22 excluding FDC and $14.43 including FDC, and three year average P+P FD&A costs of $14.84 excluding FDC and $17.08 including FDC;

- Reserve Life Index of approximately 9.3 (P+P) based on 2006 exit production of 65,000 boe/d; and

- The net present value (NPV) (before taxes, discounted at 10%) of Harvest's P+P reserves increased 86% to $3,276.4 million (2005 - $1,759.3 million), while the NPV of total Proved reserves increased 87% to $2,562.3 million (2005 - $1,370.3 million).

HARVEST RESERVES SUMMARY

Harvest's reserves were evaluated by the independent reserve evaluators McDaniel & Associates Consultants Ltd. ("McDaniel"), GLJ Petroleum Consultants Ltd. ("GLJ"), and Sproule Associates Limited ("Sproule") in accordance with National Instrument 51-101 ("NI 51-101") for the year ended December 31, 2006. The evaluation of Harvest's reserves was split as follows: McDaniel approximately 35%, GLJ approximately 44%, and Sproule approximately 21%. The complete reserves disclosure as required under NI 51-101, will be contained in Harvest's 2006 Renewal Annual Information Form, to be filed on SEDAR on or before March 30, 2006.



(1) Harvest's F&D costs were calculated as prescribed by NI 51-101. For
continuity, the F&D and FD&A costs presented herein were calculated both
excluding and including FDC.

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

Harvest Reserves Summary as at December 31, 2006 - Forecast Prices and Costs

Gross(1)
----------------------------------------------------------------------------
Light &
Medium Heavy Associated Natural Total Oil Total Oil
Crude Crude & Non- Gas Equivalent(3) Equivalent(3)
Reserves Oil Oil Associated Liquids 2006 2005
Category (mmbbl) (mmbbl) Gas (Bcf) (mmbbl) (mmboe) (mmboe)
----------------------------------------------------------------------------
Proved
Developed
Producing 62.2 33.6 203.9 7.0 136.8 77.0
Developed
Non-Producing 1.7 2.6 33.6 0.8 10.6 2.2
Undeveloped 4.3 3.3 22.4 0.5 11.8 8.5
Total Proved 68.2 39.5 259.9 8.2 159.2 87.7
Probable 23.3 16.7 104.9 3.6 61.1 32.0
----------------------------------------------------------------------------
Total Proved
Plus Probable 91.5 56.2 364.8 11.8 220.3 119.7
----------------------------------------------------------------------------
----------------------------------------------------------------------------


Net(2)
----------------------------------------------------------------------------
Light &
Medium Heavy Associated Natural Total Oil Total Oil
Crude Crude & Non- Gas Equivalent(3) Equivalent(3)
Reserves Oil Oil Associated Liquids 2006 2005
Category (mmbbl) (mmbbl) Gas (Bcf) (mmbbl) (mmboe) (mmboe)
----------------------------------------------------------------------------
Proved
Developed
Producing 56.1 30.3 166.6 5.2 119.3 68.4
Developed
Non-Producing 1.5 2.1 26.8 0.6 8.7 1.8
Undeveloped 3.6 2.7 18.0 0.3 9.7 7.4

Total Proved 61.2 35.1 211.4 6.1 137.7 77.6
Probable 20.8 14.7 85.1 2.6 52.2 28.0
----------------------------------------------------------------------------
Total Proved
Plus Probable 82.0 49.8 296.5 8.7 189.9 105.6
----------------------------------------------------------------------------
----------------------------------------------------------------------------
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 degrees 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: PDP:
13.5 mmboe, Proved Undeveloped: 1.8 mmboe, Total Proved: 15.3 mmboe,
Probable: 4.2 mmboe and P+P: 19.5 mmboe, and would increase the net
heavy oil reserves and reduce the light/medium oil reserves by the
following amounts: PDP: 11.9 mmboe, Proved Undeveloped: 1.5 mmboe,
Total Proved: 13.4 mmboe, Probable: 3.7 mmboe, and P+P: 17.1 mmboe.


Harvest 2006 Reconciliation Table - Forecast Prices and Costs
----------------------------------------------------------------------------
TOTAL BARREL OF OIL EQUIVALENT (boe)
-------------------------------------------
FACTORS Gross Proved Gross Proved Plus Probable
(mmboe) (mmboe)
----------------------------------------------------------------------------
December 31, 2005 87.7 119.7
Technical Revisions 6.0 3.0
Extensions/Improved Recovery 6.9 10.9
Discoveries 0.5 0.6
Economic/PV accretion 0.4 0.5
Acquisitions/Divestitures 79.5 107.4
Production (21.8) (21.8)

December 31, 2006 159.2 220.3
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Note:
(1) Columns may not add due to rounding.
(2) The net reserve reconciliation disclosure as required under NI 51-101,
will be contained in Harvest's 2006 Renewal Annual Information Form, to
be filed on SEDAR on or before March 30, 2006.

 


As indicated in the table above, our P+P reserve additions (excluding acquisitions/ dispositions) totaled 15.0mmboe, which includes approximately 18.9mmboe of additions from our capital program, with the balance primarily attributed to conversion of previously booked undeveloped reserves.

Harvest Net Present Value of Future Net Revenue of Reserves as at December 31, 2006 - Forecast Prices and Costs

Harvest's crude oil, natural gas and natural gas liquids reserves were evaluated using McDaniel's product price forecasts effective January 1, 2007 prior to provision for income taxes, interest, debt service charges and general and administrative expenses. Note that this presentation is on a before tax basis, and if the tax measures announced on October 31st become substantially enacted than the after tax values could be different than the pre-tax number presented herein. It should not be assumed that McDaniel's estimates of the discounted future net production revenue represent the fair market value of Harvest's reserves.



Reserves 0% 5% 10% 15% 20%
Category ($millions) ($millions) ($millions) ($millions) ($millions)
----------------------------------------------------------------------------
Proved
Developed
Producing 3,453.2 2,719.8 2,272.5 1,968.9 1,748.5
Developed
Non-Producing 320.2 223.7 174.5 144.2 123.3
Undeveloped 234.0 162.3 115.2 82.2 57.8
Total Proved 4,007.5 3,105.8 2,562.3 2,195.3 1,929.6
Probable 1,790.5 1,051.5 714.1 528.0 412.3
----------------------------------------------------------------------------
Total Proved
Plus Probable 5,798.0 4,157.3 3,276.4 2,723.3 2,341.9
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Note:
(1) Columns may not add due to rounding.

 


McDaniel & Associates Consultants Ltd. January 1, 2007 Price Forecast

A summary of the McDaniel price forecast as at January 1, 2007 that was used in the Harvest reserves evaluation is listed below. A complete listing of the price forecast is available on the McDaniel's website at the following link http://www.mcdan.com/pricing_forecasts.html.



Edmonton Alberta
WTI Light Bow River Alberta Alberta US/CAN
Crude Crude Hardisty Heavy AECO Exchange
Oil Oil Crude Oil Crude Oil Spot Price Rate
Year $US/bbl(1) $C/bbl(2) $C/bbl(3) $C/bbl(4) $C/GJ $US/$CAN
----------------------------------------------------------------------------
2007 62.50 70.80 49.30 39.20 6.85 0.870
2008 61.20 69.30 49.60 39.80 7.05 0.870
2009 59.80 67.70 49.80 40.20 7.40 0.870
2010 58.40 66.10 49.30 40.90 7.50 0.870

2011 56.80 64.20 47.90 39.70 7.70 0.870
2012 58.00 65.60 48.90 40.60 7.90 0.870
2013 59.10 66.80 49.80 41.30 8.10 0.870
2014 60.30 68.20 50.80 42.20 8.25 0.870
2015 61.50 69.50 51.80 43.00 8.45 0.870

2016 62.70 70.90 52.90 43.80 8.60 0.870
2017 64.00 72.30 54.00 44.80 8.75 0.870
2018 65.30 73.80 55.00 45.70 8.95 0.870
2019 66.60 75.30 56.10 46.60 9.10 0.870
2020 67.90 76.80 57.20 47.50 9.30 0.870
2021 69.30 78.30 58.40 48.50 9.50 0.870

Thereafter +2%/yr +2%/yr +2%/yr +2%/yr +2%/yr 0.870
----------------------------------------------------------------------------
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)

 


Finding, Development & Acquisition Costs

In the interests of continuity and consistency, we have elected to present F&D and FD&A costs calculated both excluding and including FDC. The aggregate of the exploration and development costs incurred in the most recent financial year and the change during that year in estimated future development costs generally will not reflect total finding and development costs related to reserves additions for that year.



mmboe Total Proved Proved plus Probable
----------------------------------------------------------------------------
Reserve additions 13.8 15.0
Total Reserve additions including
acquisitions 93.3 122.4
----------------------------------------------------------------------------


Total Proved Proved plus Probable
--------------------------------------------------
Excluding Including Excluding Including
FDC FDC FDC FDC
--------------------------------------------------
2006 Exploration &
Development Capex
($millions) $ 363.5 $ 377.1 $ 363.5 $ 389.5
2006 Total Capex Including
Acquisitions ($millions) $ 2,830.6 $ 2,936.3 $ 2,830.6 $ 3,009.4

2006 F&D ($/boe) $ 26.41 $ 27.40 $ 24.30 $ 26.04
2006 FD&A ($/boe) $ 30.34 $ 31.47 $ 23.13 $ 24.59

2005 F&D ($/boe) $ 11.80 $ 15.17 $ 10.73 $ 13.10
2005 FD&A ($/boe) $ 13.79 $ 17.62 $ 11.78 $ 15.56

Three Year Average F&D
($/boe) $ 14.67 $ 15.99 $ 13.22 $ 14.43
Three Year Average FD&A
($/boe) $ 19.15 $ 21.20 $ 14.84 $ 17.08
----------------------------------------------------------------------------

 


Harvest is one of Canada's largest energy trusts with upstream and downstream operations. We are focused on identifying opportunities to create and deliver value to unitholders through monthly distributions and unit price appreciation. With an active acquisition program and the technical approach taken to maximizing our assets, we strive to grow cash flow per unit. Harvest is a sustainable trust with an average economic life of approximately 16 years, and current production from our oil and gas business of 65,000 boe per day weighted approximately 70% to crude oil and liquids and 30% to natural gas. Harvest trust units are traded on the Toronto Stock Exchange ("TSX") under the symbol "HTE.UN" and on the New York Stock Exchange ("NYSE") under the symbol "HTE".

ADVISORY

Certain information in this press release, including management's assessment of future plans and operations, contains forward-looking information that involves risk and uncertainty. Such risks and uncertainties include, but are not limited to, risks associated with: imprecision of reserve estimates; conventional oil and natural gas operations; the volatility in commodity prices and currency exchange rates; risks associated with realizing the value of acquisitions; general economic, market and business conditions; changes in environmental legislation and regulations; the availability of sufficient capital from internal and external sources; and, such other risks and uncertainties described from time to time in Harvest's regulatory reports and filings made with securities regulators.

Forward-looking statements in this press release may include, but are not limited to, production volumes, operating costs, commodity prices, capital spending, access to credit facilities, and regulatory changes. For this purpose, any statements that are contained in this press release that are not statements of historical fact may be deemed to be forward-looking statements. Forward-looking statements often contain terms such as "may", "will", "should", "anticipate", "expects" and similar expressions.

Readers are cautioned not to place undue reliance on forward-looking statements as there can be no assurance that the plans, intentions or expectations upon which they are based will occur. Such information, although considered reasonable by management at the time of preparation, may prove to be incorrect and actual results may differ materially from those anticipated. Harvest assumes no obligation to update forward-looking statements should circumstances or management's estimates or opinions change. Forward-looking statements contained in this press release are expressly qualified by this cautionary statement.      


FOR FURTHER INFORMATION PLEASE CONTACT:

 Harvest Energy Trust
John Zahary
President & CEO
(403) 265-1178 or Toll Free: (866) 666-1178

or

Harvest Energy Trust
Robert Fotheringham
Vice President, Finance & CFO
(403) 265-1178 or Toll Free: (866) 666-1178

or

Harvest Energy Trust
Cindy Gray
Manager, Investor Relations
(403) 265-1178 or Toll Free: (866) 666-1178

or

Harvest Energy Trust
2100, 330 - 5th Avenue S.W.
Calgary, AB Canada T2P 0L4
(403) 265-1178 or Toll Free: (866) 666-1178
(403) 265-3490 (FAX)
Email: information@harvestenergy.ca
Website: www.harvestenergy.ca