Baytex Energy Trust

Baytex Energy Trust

February 22, 2010 08:03 ET

Baytex Energy Trust Announces Year-End 2009 Reserves

CALGARY, ALBERTA--(Marketwire - Feb. 22, 2010) - Baytex Energy Trust ("Baytex") (TSX:BTE.UN)(NYSE:BTE) is pleased to announce our year-end 2009 reserves as evaluated by Sproule Associates Limited ("Sproule"), the independent reserves evaluator for all of Baytex's oil and gas properties, in accordance with National Instrument 51-101. As Baytex plans to announce our 2009 financial results on March 11, 2010, certain financial estimates have been made to facilitate the discussion of the performance of our capital program. Readers are advised that these financial estimates remain subject to audit and, as a result, are subject to revision. Complete reserves disclosure will be included in our Annual Information Form for the year ended December 31, 2009, which will be filed in late March 2010.

2009 Highlights

- Total proved reserves increased 3% to 129 million boe, while total proved plus probable reserves increased 5% to 197 million boe;

- Inclusive of acquisitions, replaced 165% of production, with finding, development and acquisition costs ("FD&A") of $11.82 per boe for proved plus probable reserves excluding changes in future development costs ("FDC"). Three-year average (2007 - 2009) FD&A costs are $11.94 per boe for proved plus probable reserves excluding FDC;

- Replaced 113% of production through exploration and development ("E&D") activities alone, while reinvesting only approximately 48% of funds from operations ("FFO") into E&D;

- Finding and development ("F&D") costs were $10.62 per boe for proved plus probable reserves excluding FDC. Three-year average F&D costs are $10.10 per boe for proved plus probable reserves excluding FDC;

- Reserve life index is 12.4 years for proved plus probable reserves and 8.2 years for proved reserves, based on our guidance of an average production rate of 43,500 boe/d for 2010;

- Year-end 2009 reserves are comprised of 89% oil (including NGLs) on a proved plus probable basis, and 88% oil (including NGLs) on a proved basis;

- Generated a recycle ratio (operating netback divided by FD&A costs) based on proved plus probable reserves (excluding FDC) of 2.3x in 2009 and 2.5x for the three-year average; and

- Increased net asset value 2% to $32.18 per trust unit.

Capital expenditures in 2009 are estimated to total $295 million, with $159 million spent on exploration and development activities, $101 million spent on property acquisitions and $35 million spent on deferred land acquisition payments related to our Bakken/Three Forks light oil resource play in North Dakota. Approximately 60% of these total expenditures were incurred for heavy oil assets with the balance incurred for light oil and natural gas assets. In 2009, we drilled a total of 113 gross (99.0 net) wells at a success rate of 96%. Our drilling program included 100 gross (88.6 net) oil wells, 5 gross (3.4 net) gas wells, 4 gross (3.0 net) service and stratigraphic test wells and 4 gross (4.0 net) dry holes.

Heavy Oil

Our year-end 2009 report reflects continued growth in our heavy oil reserves to 145 million barrels of proved plus probable reserves, an increase of 18% over 2008, and 97 million barrels of proved reserves, an increase of 12% over 2008.

At Seal, year-end 2009 proved plus probable reserves increased 39% to 55 million barrels, and proved reserves increased 16% to 31 million barrels. The steady reserve growth we have recorded since beginning development in 2005 is consistent with our view that this property holds significant long-term growth potential. At year-end 2009, primary (cold) reserves were included on only 20 of our 105 sections of oil sands leasehold at Seal, and thermal reserves were included on only one of those sections.

The development techniques we employ at Seal continue to evolve, leading to higher production rates and recoveries and increasing capital efficiencies. Our initial wells were mile-long single-lateral horizontal wells, which produced at initial rates of approximately 160 bbls/d. In August 2007, we drilled our first dual-lateral horizontal well, and in February 2008, our first triple-lateral well. During 2009, we drilled a total of 17 producing wells at Seal with a 100% success rate, comprised of one single-leg well, one dual-lateral well, seven triple-lateral wells, three four-lateral wells, two six-lateral wells, and three eight-lateral wells. Initial production rates from our first eight-lateral wells were in excess of 500 bbls/d.

We will continue to focus on development of this potential at Seal, and note that Seal will attract a larger percentage of our 2010 capital budget than any other project in our asset portfolio. In 2010, we expect to drill approximately 20 horizontal wells at Seal, largely comprised of multi-lateral wells. In addition, we intend to re-enter several existing single-leg horizontal wells and drill additional horizontal legs at closer inter-well spacing to increase recovery from these older wells.

Light Oil and Natural Gas Liquids

In combination, our proved plus probable light oil and natural gas liquids ("NGL") reserves decreased by approximately two million barrels, or 7%, to 29 million barrels at year-end 2009. This is primarily due to a 23% decrease in NGL reserves as a result of reduced natural gas investment activities, and to a lesser extent due to declines in our conventional light oil projects.

In our light oil resource plays, the year-end 2009 reserves report reflects a 25% increase in proved plus probable reserves to 12 million barrels for our Bakken/Three Forks development in North Dakota and a 150% increase in proved plus probable reserves to 2 million barrels for our Viking development project in southeastern Alberta.

In the case of our Viking development project in southeast Saskatchewan, where we have approximately 95 net sections of undeveloped land, we do not have any undeveloped locations booked at year-end 2009 on either a proved or probable basis. We plan to drill approximately five wells in this play during 2010, and consequently expect it to be a source of light oil reserves growth in the future.

Natural Gas

Natural gas reserves declined year-over-year by 47 Bcf, or 26%, to 134 Bcf on a proved plus probable basis. During 2009, we directed our efforts and capital toward oil development, and our reduced natural gas weighting and reserves reflect this focus.

Capital Program Efficiency

Three Year
2009 2008 2007 2007 - 2009
------- ------- ------- -----------

Excluding Future Development Costs

FD&A costs - Proved ($/boe)
Exploration and development $ 14.71 $ 14.26 $ 10.03 $ 12.76
Acquisitions (net of dispositions) 17.04 22.99 20.63 20.58
------- ------- ------- -----------
Total $ 15.70 $ 18.37 $ 14.75 $ 16.27
------- ------- ------- -----------
------- ------- ------- -----------

FD&A costs - Proved plus Probable
Exploration and development $ 10.62 $ 10.53 $ 9.17 $ 10.10
Acquisitions (net of dispositions) 13.63 15.88 12.30 13.85
------- ------- ------- -----------
Total $ 11.82 $ 13.11 $ 10.90 $ 11.94
------- ------- ------- -----------
------- ------- ------- -----------

Recycle ratio based on operating netback
Proved plus Probable 2.3 2.6 2.2 2.5

Reserve replacement ratio (2)
Proved plus Probable 165% 233% 274% 222%

Including Future Development Costs

FD&A costs - Proved ($/boe)
Exploration and development $ 23.07 $ 11.01 $ 8.82 $ 13.96
Acquisitions (net of dispositions) 28.80 27.87 22.93 26.08
------- ------- ------- -----------
Total $ 24.98 $ 18.95 $ 15.10 $ 19.10
------- ------- ------- -----------
------- ------- ------- -----------

FD&A costs - Proved plus Probable
Exploration and development $ 20.10 $ 12.09 $ 9.27 $ 11.08
Acquisitions (net of dispositions) 23.53 20.23 14.05 17.33
------- ------- ------- -----------
Total $ 21.20 $ 16.06 $ 11.91 $ 14.01
------- ------- ------- -----------
------- ------- ------- -----------

(1) Recycle ratio is calculated as operating netback divided by FD&A costs
(proved plus probable excluding FDC). Operating netback is calculated as
revenue minus royalties, operating expenses and transportation expenses.
(2) Reserve replacement ratio is calculated as total reserves added in the
year divided by production for the same year.

Net Asset Value

The following net asset value calculation utilizes what is generally referred to as the "produce-out" net present value of Baytex's oil and gas reserves as evaluated by Sproule. It does not take into account the possibility of Baytex being able to recognize additional reserves through future capital investment in its existing properties beyond those included in our 2009 year-end report.

Forecast Prices and Costs Before Income Taxes

($ thousands)
Proved plus probable reserves (1) 3,832,932
Undeveloped land (2) 220,607
Estimated net debt (3) (463,000)
Asset retirement obligations (4) (56,000)
Net asset value 3,534,539

Diluted trust units (5) 109,828,742

Net asset value per trust unit $32.18

(1) Net present value of future net revenue discounted at 10%
as evaluated by Sproule as at December 31, 2009. Net present
value of future net revenue does not represent fair market
value of the reserves.
(2) The value ascribed to our 787,168 net acres of undeveloped
land at December 31, 2009 was estimated by Management. This internal
evaluation generally represents the estimated replacement cost of our
undeveloped land. In determining replacement cost, we analyzed land
sale prices paid during 2009 at Provincial Crown and State lands sales
for the properties in the vicinity of our land holdings, less an
allowance for near-term expiries.
(3) Long-term debt net of working capital as at December 31, 2009,
excluding convertible debentures (which are assumed to be converted
into trust units in the Net Asset Value calculation) and notional
assets and liabilities associated with the mark-to-market value of
derivative contracts (as the pricing effect of the derivatives
contracts have already been reflected by Sproule in the values noted
(4) Management estimate of asset retirement obligations as at December 31,
2009 discounted at 8%.
(5) Includes 109,298,911 trust units and 529,831 trust units issuable on
the conversion of the $7.8 million of convertible debentures outstanding
as at December 31, 2009.

Oil and Gas Reserves as at December 31, 2009

Forecast Prices and Costs
Light and Medium Natural
Crude Oil Heavy Oil Gas Liquids
---------------- ------------------ -------------------
Reserve Gross (1) Net (2) Gross (1) Net (2) Gross (1) Net (2)
Category (Mbbl) (Mbbl) (Mbbl) (Mbbl) (Mbbl) (Mbbl)
Producing 6,078 4,588 31,362 26,001 1,989 1,450
Non-Producing 487 369 16,334 13,783 516 374
Undeveloped 8,001 6,272 49,363 41,952 313 225
Total Proved 14,567 11,229 97,059 81,736 2,818 2,049
Probable 10,233 7,846 48,538 40,956 1,500 1,084
Total Proved
Plus Probable 24,801 19,075 145,597 122,692 4,318 3,133

Forecast Prices and Costs
Natural Gas Oil Equivalent (3)
----------- -----------------
Reserve Category Gross (1) Net (2) Gross (1) Net (2)
---------------- -------- ------ -------- ------
(Bcf) (Bcf) (Mboe) (Mboe)
Developed Producing 68.6 57.5 50,854 41,621
Developed Non-Producing 11.8 8.9 19,300 16,005
Undeveloped 9.3 7.4 59,233 49,688
Total Proved 89.7 73.8 129,387 107,314
Probable 44.1 35.0 67,620 55,721
Total Proved Plus Probable 133.8 108.8 197,007 163,035

(1) "Gross" reserves means the total working and royalty interest
share of remaining recoverable reserves owned by Baytex before
deductions of royalties payable to others.
(2) "Net" reserves means Baytex'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.
A boe conversion ratio of six thousand cubic feet of natural gas
to one barrel of oil is based on an energy equivalency conversion
method primarily applicable at the burner tip and does not represent
a value equivalency at the wellhead.

Reserve Life Index

Reserve Life Index (years)
2010 -------------------------
Production Target Total Proved Proved Plus Probable
----------------- ------------ --------------------
Oil and NGL (bbl/d) 34,150 9.2 14.0
Natural Gas (mmcf/d) 56.0 4.4 6.5
Oil Equivalent (boe/d) 43,500 8.2 12.4

Net Present Value of Reserves (Forecast Prices and Costs)

Summary of Net Present Value of Future Net Revenue
As at December 31, 2009
Before Income Taxes and Discounted at (%/year)
Category 0% 5% 10% 15% 20%
--------- - - - - -
($ million) ($ million) ($ million) ($ million) ($ million)
Producing 1,780 1,474 1,279 1,143 1,041
Non-Producing 711 539 424 342 282
Undeveloped 2,118 1,430 1,032 785 620
Proved 4,609 3,443 2,735 2,270 1,943
Probable 2,596 1,576 1,098 821 641
Probable 7,205 5,019 3,833 3,091 2,584

Sproule December 31, 2009 Forecast Prices

WTI Edmonton Heavy 12 AECO Inflation Exchange
Cushing Par Price API C-Spot Rate Rate
Year US$/Bbl C$/Bbl C$/Bbl C$/MMbtu %/Yr $US/$Cdn
2010 79.17 84.25 69.93 5.36 2.0 0.92
2011 84.46 89.99 73.79 6.21 2.0 0.92
2012 86.89 92.61 74.08 6.44 2.0 0.92
2013 90.20 96.19 75.03 7.23 2.0 0.92
2014 92.01 98.13 74.58 7.98 2.0 0.92
2015 93.85 100.11 76.08 8.16 2.0 0.92
2016 95.72 102.13 77.62 8.34 2.0 0.92
2017 97.64 104.19 79.19 8.52 2.0 0.92
2018 99.59 106.30 80.79 8.71 2.0 0.92
2019 101.58 108.44 82.42 8.90 2.0 0.92
2020 103.61 110.63 84.08 9.10 2.0 0.92


The reserves information contained in this press release has been prepared in accordance with National Instrument 51-101 "Standards of Disclosure for Oil and Gas Activities" of the Canadian Securities Administrators ("NI 51-101"). Complete NI 51-101 reserves disclosure will be included in our Annual Information Form for the year ended December 31, 2009, which will be filed in late March 2010. Listed below are cautionary statements that are specifically required by NI 51-101:

Where applicable, 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. A boe conversion ratio of six thousand cubic feet of natural gas to one barrel of oil is based on an energy equivalency conversion method primarily applicable at the burner tip and does not represent a value equivalency at the wellhead.

This press release contains reserves estimates for our Seal, North Dakota and Viking properties. Estimates of reserves for individual properties may not reflect the same confidence level as estimates of reserves for all properties due to the effects of aggregation.

With respect to finding and development costs, 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 reserve additions for that year.

This press release contains estimates of the net present value of our future net revenue from our reserves. Such amounts do not represent the fair market value of our reserves.

All amounts in this press release are stated in Canadian dollars unless otherwise specified.


The oil and natural gas reserves contained in this press release have generally been prepared in accordance with Canadian disclosure standards, which are not comparable in all respects to United States or other foreign disclosure standards. For example, the United States Securities and Exchange Commission (the "SEC") requires oil and gas issuers, in their filings with the SEC, to disclose only "proved reserves", but permits the optional disclosure of "probable reserves" (both as defined in SEC rules). Canadian securities laws require oil and gas issuers, in their filings with Canadian securities regulatory authorities, to disclose not only "proved reserves" but also "probable reserves" ( both as defined in NI 51-101), both of which are defined differently from the SEC rules. Accordingly, proved, probable and proved plus probable reserves disclosed in this news release may not be comparable to United States standards. Probable reserves are higher risk and are generally believed to be less likely to be accurately estimated or recovered than proved reserves.

In addition, under Canadian disclosure requirements and industry practice, reserves and production are reported using gross volumes, which are volumes prior to deduction of royalty and similar payments. The SEC rules require reserves and production to be presented using net volumes, after deduction of applicable royalties and similar payments.

Moreover, Baytex has determined and disclosed estimated future net revenue from its reserves using forecast prices and costs, whereas the SEC rules require that reserves be estimated using a 12-month average price, calculated as the unweighted arithmetic average of the first-day-of-the-month price for each month within the 12-month period prior to the end of the reporting period. As a consequence of the foregoing, Baytex's reserve estimates and production volumes in this press release may not be comparable to those made by companies utilizing United States reporting and disclosure standards.


Funds from operations is not a measurement based on Generally Accepted Accounting Principles ("GAAP"') in Canada, but is a financial term commonly used in the oil and gas industry. Funds from operations represents cash generated from operating activities before changes in non-cash working capital, site restoration and reclamation expenditures, deferred charges and other assets. Baytex's determination of funds from operations may not be comparable with the calculation of similar measures for other entities. Baytex considers funds from operations a key measure of performance as it demonstrates its ability to generate the cash flow necessary to fund future distributions to unitholders and capital investments. The most directly comparable measures calculated in accordance with GAAP are cash flow from operating activities and net income.


In the interest of providing Baytex's unitholders and potential investors with information regarding Baytex, including management's assessment of Baytex's future plans and operations, certain statements in this press release are "forward-looking statements" within the meaning of the United States Private Securities Litigation Reform Act of 1995 and "forward-looking information" within the meaning of applicable Canadian securities legislation (collectively, "forward-looking statements"). In some cases, forward-looking statements can be identified by terminology such as "anticipate", "believe", "continue", "could", "estimate", "expect", "forecast", "intend", "may", "objective", "ongoing", "outlook", "potential", "project", "plan", "should", "target", "would", "will" or similar words suggesting future outcomes, events or performance. The forward-looking statements contained in this press release speak only as of the date of this document and are expressly qualified by this cautionary statement.

Specifically, this press release contains forward-looking statements relating to: the volumes and estimated value of our oil and gas reserves; our Seal heavy oil resource play, including its resource potential, initial production rates from wells drilled and development plans; the value of our undeveloped land holdings; the amount of future asset retirement obligations; the volume and product mix of our 2010 oil and gas production; the productive life of our reserves; future oil and natural gas prices; future results from operations and operating metrics; future costs, expenses and royalty rates; and future exploration, development and acquisition activities (including drilling plans) and related capital expenditures.

These forward-looking statements are based on certain key assumptions regarding, among other things: oil and natural gas prices and differentials between light, medium and heavy oil prices; well production rates and reserve volumes; our ability to add production and reserves through our exploration and development activities; capital expenditure levels; the availability and cost of labour and other industry services; the amount of future cash distributions that we intend to pay; interest and foreign exchange rates; and the continuance of existing and, in certain circumstances, proposed tax and royalty regimes. The reader is cautioned that such assumptions, although considered reasonable by Baytex at the time of preparation, may prove to be incorrect.

Actual results achieved during the forecast period will vary from the information provided herein as a result of numerous known and unknown risks and uncertainties and other factors. Such factors include, but are not limited to: fluctuations in market prices for petroeum and natural gas; fluctuations in foreign exchange or interest rates; general economic, market and business conditions; stock market volatility and market valuations; changes in income tax laws; industry capacity; geological, technical, drilling and processing problems and other difficulties in producing petroleum and natural gas reserves; uncertainties associated with estimating petroleum and natural gas reserves; liabilities inherent in oil and natural gas operations; competition for, among other things, capital, acquisitions of reserves, undeveloped lands and skilled personnel; risks associated with oil and gas operations; changes in royalty rates and incentive programs relating to the oil and gas industry; changes in environmental and other regulations; incorrect assessments of the value of acquisitions; and other factors, many of which are beyond the control of Baytex. These risk factors are discussed in Baytex's Annual Information Form, Form 40-F and Management's Discussion and Analysis for the year ended December 31, 2008, as filed with Canadian securities regulatory authorities and the U.S. Securities and Exchange Commission.

There is no representation by Baytex that actual results achieved during the forecast period will be the same in whole or in part as those forecast and Baytex does not undertake any obligation to update publicly or to revise any of the included forward-looking statements, whether as a result of new information, future events or otherwise, except as may be required by applicable securities law.

Baytex Energy Trust is a conventional oil and gas income trust focused on maintaining its production and asset base through internal property development and delivering consistent returns to its unitholders. Baytex's trust units are traded on the Toronto Stock Exchange under the symbol BTE.UN and on the New York Stock Exchange under the symbol BTE.

Contact Information

  • Baytex Energy Trust
    Anthony Marino
    President and Chief Executive Officer
    (403) 267-0708
    Baytex Energy Trust
    Derek Aylesworth
    Chief Financial Officer
    (403) 538-3639
    Baytex Energy Trust
    Brian Ector
    Director of Investor Relations
    (403) 267-0702
    Baytex Energy Trust
    Cheryl Arsenault
    Investor Relations
    (403) 267-0761
    Baytex Energy Trust
    Toll Free Number: 1-800-524-5521