Baytex Energy Trust
TSX : BTE.UN
NYSE : BTE

Baytex Energy Trust

March 11, 2010 09:00 ET

Baytex Energy Trust Announces Fourth Quarter 2009 Results

CALGARY, ALBERTA--(Marketwire - March 11, 2010) - Baytex Energy Trust ("Baytex") (TSX:BTE.UN) (NYSE:BTE) is pleased to announce its operating and financial results for the three months and year ended December 31, 2009 (in Canadian dollars unless otherwise denoted).

Highlights

- Produced a quarterly record of 42,713 boe/d for Q4/09 and an annual record of 41,382 boe/d (an increase of 3% over 2008);

- Generated funds from operations of $97.3 million in Q4/09 (an increase of 10% over the prior quarter) and annual funds from operations of $332.2 million (the second highest annual result in Baytex history);

- Increased total proved reserves 3% to 129 million boe, and total proved plus probable reserves 5% to 197 million boe;

- Inclusive of acquisitions, replaced 165% of production, with finding development and acquisition ("FD&A") costs of $11.63 per boe for proved plus probable reserves excluding changes in future development costs ("FDC"). Three year average (2007 - 2009) FD&A costs are $11.89 per boe for proved plus probable reserves excluding FDC;

- Replaced 113% of production through exploration and development ("E&D") activities alone while investing only 47% of funds from operations into E&D;

- Realized a recycle ratio (operating netback divided by FD&A costs) based on a proved plus probable reserves (excluding FDC) of 2.4x in 2009 and 2.5x for the three year average;

- Advanced development of our key resource play at Seal, increasing year end reserves by 16% to 31 million barrels on a total proved basis, and by 39% to 55 million barrels on a proved plus probable basis, and continuing to advance our development techniques;

- Pre-paid the remaining deferred acquisition payments for our Bakken-Three Forks lands in North Dakota, providing greater and accelerated operating control as we continue to develop this light oil resource play; and

- Delivered total market return (assuming reinvestment of distributions) of 28% in the fourth quarter (121% for twelve months ended December 31, 2009).



Three Months Ended Year Ended
----------------------------------------------------------------------------
December September December December December
31, 2009 30, 2009 31, 2008 31, 2009 31, 2008
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FINANCIAL (thousands of
Canadian dollars, except
per unit amounts)
Petroleum and natural gas
sales 237,981 208,229 199,890 789,820 1,159,718
Funds from operations (1) 97,344 88,809 60,472 332,186 433,823
Per unit - basic 0.90 0.83 0.62 3.17 4.73
Per unit - diluted 0.87 0.80 0.61 3.10 4.51
Cash distributions
declared 37,286 32,799 55,314 137,601 197,026
Per unit 0.42 0.36 0.68 1.56 2.64
Net income 27,956 40,657 52,401 87,574 259,894
Per unit - basic 0.26 0.38 0.54 0.83 2.83
Per unit - diluted 0.25 0.37 0.53 0.82 2.74

Exploration and
development 45,471 34,180 42,789 157,044 184,678
Acquisitions net of
dispositions 37,083 93,662 8,174 133,077 265,099
--------------------------------------------------
Total oil and gas
expenditures 82,554 127,842 50,963 290,121 449,777

Bank loan 265,088 272,918 208,482 265,088 208,482
Convertible debentures 7,736 8,799 10,195 7,736 10,195
Long-term notes 150,000 150,000 220,362 150,000 220,362
Working capital
deficiency 51,452 34,573 94,053 51,452 94,053
--------------------------------------------------
Total monetary debt (2) 474,276 466,290 533,092 474,276 533,092
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Three Months Ended Year Ended
----------------------------------------------------------------------------
December September December December December
31, 2009 30, 2009 31, 2008 31, 2009 31, 2008
----------------------------------------------------------------------------
OPERATING
Daily production
Light oil and NGL (bbl/d) 6,541 7,021 7,803 6,937 7,575
Heavy oil (bbl/d) 26,423 25,532 24,635 24,678 23,530
Total oil (bbl/d) 32,964 32,553 32,438 31,615 31,105
Natural gas (mmcf/d) 58.5 60.4 57.6 58.6 54.8
Oil equivalent
(boe/d @ 6:1) (3) 42,713 42,623 42,035 41,382 40,239

Average prices (before
hedging)
WTI oil (US$/bbl) 76.19 68.18 58.35 61.80 99.59
Edmonton par oil ($/bbl) 76.73 71.70 63.94 66.20 102.86
BTE light oil and NGL
($/bbl) 62.68 57.50 55.31 54.25 88.92
BTE heavy oil ($/bbl) (4) 57.24 55.12 38.93 49.88 65.22
BTE total oil ($/bbl) 58.31 55.64 42.83 50.85 70.94
BTE natural gas ($/mcf) 4.87 3.42 7.05 4.35 7.92
BTE oil equivalent ($/boe) 51.71 47.27 42.71 45.00 65.66

USD/CAD noon rate at
period end 0.9555 0.9327 0.8166 0.9555 0.8166
USD/CAD average rate for
period 0.9467 0.9113 0.8247 0.8760 0.9371

TRUST UNIT INFORMATION
TSX
Unit price (Cdn$)
High $ 30.50 $ 25.35 $ 27.05 $ 30.50 $ 35.37
Low $ 21.57 $ 17.80 $ 12.81 $ 9.77 $ 12.81
Close $ 29.70 $ 23.60 $ 14.65 $ 29.70 $ 14.65
Volume traded (thousands) 22,820 24,885 31,267 112,146 123,417

NYSE
Unit price (US$)
High $ 29.32 $ 23.69 $ 25.49 $ 29.32 $ 35.20
Low $ 19.83 $ 15.20 $ 10.16 $ 7.84 $ 10.16
Close $ 28.30 $ 22.04 $ 11.95 $ 28.30 $ 11.95
Volume traded (thousands) 5,492 5,778 14,498 33,241 34,514

Units outstanding
(thousands) 109,299 107,777 97,685 109,299 97,685
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(1) Funds from operations is a non-GAAP term that represents cash generated
from operating activities before changes in non- cash working capital
and other operating items. Baytex s funds from operations may not be
comparable to other issuers. 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 and capital
investments. For a reconciliation of funds from operations to cash flow
from operating activities, see Management s Discussion and Analysis of
the operating and financial results for the three months and year ended
December 31, 2009.

(2) Total monetary debt is a non-GAAP term which we define to be the sum of
monetary working capital (which is current assets less current
liabilities (excluding non-cash items such as future income tax assets
or liabilities and unrealized financial instrument gains or losses)),
the principal amount of long-term debt and the balance sheet value of
the convertible debentures.

(3) Barrel of oil equivalent ("boe") amounts have been calculated using a
conversion rate of six thousand cubic feet of natural gas to one barrel
of oil. The use of boe amounts 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.

(4) Heavy oil wellhead prices are net of blending costs.


Operations Review

Production averaged 42,713 boe/d during the fourth quarter of 2009, as compared to 42,623 boe/d in the third quarter. Production was within guidance of approximately 42,500 to 43,000 boe/d for the fourth quarter of 2009. Production for the full year 2009 averaged 41,382 boe/d, up 3% versus 40,239 boe/d in 2008.

Capital expenditures for exploration and development activities totaled $45.5 million for the fourth quarter of 2009, bringing full year 2009 exploration and development expenditures to $157.0 million. During the fourth quarter, Baytex participated in the drilling of 25 (20.9 net) wells, resulting in 25 (20.9 net) oil wells, for a 100% success rate. Fourth quarter drilling included ten (9.1 net) wells in the Lloydminster area, four (4.0 net) wells at Seal, one (1.0 net) well at Dawson, one (1.0 net) well at Stoddart, two (2.0 net) wells in central Alberta, three (3.0 net) wells in the Pembina area, and four (0.8 net) wells in the United States. For the full year 2009, Baytex participated in the drilling of 113 (99.0 net), resulting in 100 (88.6 net) oil wells, five (3.4 net) gas wells, four (3.0 net) service and stratigraphic test wells and four (4.0 net) dry holes, for a success rate of 96% (96% net).

Consistent with previous guidance, our exploration and development capital budget for 2010 is $235 million, which is designed to generate an average production rate of 43,500 boe/d. Production in the first quarter of 2010 is expected to be approximately 42,500 to 43,000 boe/d.

Heavy Oil

In 2009, heavy oil production averaged 24,678 bbl/d. During 2009, we drilled 90 (82.3 net) wells in our heavy oil areas, resulting in 83 (76.3 net) oil wells, two (2.0 net) stratigraphic test wells, two (1.0 net) service wells, and three (3.0 net) dry and abandoned wells, for a success rate of 97% (96% net).

Heavy oil production from Seal averaged approximately 6,400 bbl/d in the fourth quarter, and we exited 2009 producing approximately 7,000 bbl/d. Production at Seal for the full year 2009 averaged 5,100 bbl/d, up 38% versus a 2008 average production rate of 3,700 bbl/d. The development techniques we employ at Seal continue to evolve, resulting in higher production rates, increased recovery and improved capital efficiencies. Our fourth quarter drilling program at Seal included three eight-lateral wells, of which two were on production at year-end with first-month production rates in excess of 500 bbl/d. Also in the fourth quarter, Baytex re-entered an existing single lateral well and added two additional laterals, increasing production from the well from 56 bbl/d to 268 bbl/d.

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 single-leg horizontal wells at Seal and drill additional horizontal legs at closer inter-well spacing to increase production and ultimate recovery.

Light Oil & Natural Gas

During 2009, production averaged 16,704 boe/d, which was comprised of 6,937 bbl/d of light oil and NGL and 58.6 mmcf/d of natural gas. During 2009, we drilled 23 (16.7 net) wells resulting in 17 (12.2 net) oil wells, five (3.5 net) gas wells and one (1.0 net) dry hole for a success rate of 96% (94% net).

During the fourth quarter, we pre-paid our remaining deferred acquisition payments for the Bakken-Three Forks land position in North Dakota that we acquired in July 2008. Under the terms of the pre-pay agreement, Baytex paid US$33.2 million to complete our deferred payments, which would otherwise have totaled US$36 million over approximately the next five to six quarters. In addition, Baytex was assigned an operating area corresponding to approximately 38% of the lands in the project area, an expansion of eleven operated sections from the operating area designated in the July 2008 agreement. In addition to decreasing the cost of the remaining land payments, the purpose of the pre-pay was to increase our degree of operating control in this large light oil resource play. We drilled two Baytex-operated horizontal oil wells (37.5% working interest) during the fourth quarter and subsequently applied multi-stage fracture treatments to both wells. For the full-year 2009, we drilled four Baytex-operated horizontal oil wells (37.5% working interest) with a 100% success rate. Peak 30-day production from the Baytex operated wells has averaged 300 bbl/d per well for the first three wells, consistent with our current model of productivity for this project. For 2010, we plan to accelerate activity, with 15 to 20 gross wells (5.6 to 7.5 net) expected to be drilled in the project.

We continued development of our Viking light oil resource play on lands in Alberta and Saskatchewan. In Alberta, we placed two new horizontal Viking wells on production during the fourth quarter with first month average production rates of over 150 bbl/d per well. Subsequent to the end of the fourth quarter, we drilled and completed an additional Viking horizontal well in southwest Saskatchewan. Baytex plans to drill approximately 10 Viking horizontal wells in 2010, with drilling planned in both Alberta and Saskatchewan.

Baytex drilled two (2.0 net) successful Cardium horizontal wells during the fourth quarter, which were completed with multi-stage fracture stimulations subsequent to the end of the quarter. Initial production rates of over 100 bbl/d per well are in line with our pre-drilling expectations. We plan to drill approximately five Cardium wells in 2010, and have identified up to 43 gross (29 net) drilling locations on our Cardium lands.

In our exploratory Mowry Shale light oil resource play in Wyoming, we completed the horizontal multi-stage frac well that was drilled in the third quarter of 2009. Production averaged only 33 bbl/d in the first month of production. We will further evaluate the production, micro-seismic survey and tiltmeter results from this well before deciding about further investments in this project.

Financial Review

Funds from operations ("FFO") were $97.3 million for the fourth quarter of 2009, an increase of 10% compared to the third quarter of 2009. This increase was largely driven by improvement in oil prices, as the average WTI price for the quarter was US$76.19 per bbl, a 12% increase over the third quarter. Baytex received an average oil price of $58.31 in the fourth quarter (net of our physical heavy oil hedging losses), an increase of 4.8% over the third quarter. We also received an average natural gas price of $4.87 per mcf in the fourth quarter, an increase of 42.4% over the prior quarter. Commodity price improvements were partially offset by increased royalties and general and administrative expenses.

The fourth quarter funds from operations are net of a non-recurring additional general and administrative expense item of $3.4 million. As previously disclosed, this item relates to tax indemnification payments made on behalf of certain of our employees who experienced unintended tax consequences related to our Trust Unit Rights Incentive Plan.

The heavy oil pricing differential averaged 16% for the fourth quarter of 2009, compared to 15% in the third quarter of 2009 and 35% in the fourth quarter of 2008. The continued impact of additional third party transportation capacity and refining infrastructure has lead to the significant improvement in differentials for heavy oil. This trend has continued into 2010, with heavy oil differentials averaging less than 12% in the first quarter. Significantly for Baytex, the end of 2009 saw the expiry of a series of heavy oil sales contracts (entered into in 2007) under which we had sold 10,340 bbl/d at an average differential of 33%. With the expiry of these contracts, we will more fully receive the benefits of the lower market differentials that currently exist for heavy oil.

For the fourth quarter, total cash distributions declared were $37.3 million, or $0.42 per unit, representing a payout ratio of 38% net of distribution reinvestment plan ("DRIP") participation (47% before DRIP). During the fourth quarter, Baytex increased its monthly distribution by 50%, to $0.18 per unit commencing with the distribution in respect of December operations. The distribution increase was supported by the improvement in oil prices and the strength of our operational results. Based on the current commodity price strip, we expect to generate sufficient funds from operations in 2010 to fully fund our E&D capital program and our distributions from internally generated funds. We are pleased to note that during the fourth quarter of 2009, we marked the significant milestone of having paid out cumulative distributions in excess of $1 billion.

At the end of the fourth quarter, total monetary debt was $474 million, which offers us undrawn credit facilities of $198 million and represents a debt-to-cash flow ratio of 1.2 times based on annualized fourth quarter 2009 cash flow. Both of these metrics are well within our leverage and liquidity targets, and provide ample capacity to finance our operations.

We continue to work towards a planned conversion from the current Trust structure to a corporate legal form, and expect to have this conversion transaction completed before the end of 2010.

Last year was challenging for the broad economy as well as for the oil and gas industry. During this challenging period, Baytex was able to generate full year FFO of $332 million. This annual FFO result for 2009 was our second highest since trust inception, topped only by our 2008 results which were supported by an average WTI oil price of nearly US$100 per bbl. Our financial results in 2009 included the completion of an equity offering in the first quarter and the issuance of long term debt in the Canadian bond market in the third quarter. Completion of these transactions during an extraordinarily difficult year demonstrated support for Baytex in both the equity and the debt capital markets. We are pleased to note that our equity units generated a total return (including reinvestment of distributions) of 121% in 2009, which was among the highest in the oil and gas sector.

Capital Program Efficiency

Since conversion to an income trust in late 2003, Baytex has consistently demonstrated high capital and operational efficiencies to support our objective long-term sustainability. Based on the evaluation of our petroleum and natural gas reserves prepared in accordance with National Instrument 51-101 "Standards of Disclosure for Oil and Gas Activities" ("NI 51-101") by our independent reserve evaluator, Sproule Associates Limited ("Sproule"), the efficiency of our capital programs are summarized as follows:



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

Excluding Future Development Costs

FD&A costs Proved ($/boe)
Exploration and development $ 12.54 $ 14.26 $ 10.03 $ 12.17
Acquisitions (net of dispositions) 21.27 22.99 20.63 21.68
----------------------------------------------------------------------------
Total $ 15.45 $ 18.37 $ 14.75 $ 16.20
----------------------------------------------------------------------------

FD&A costs Proved plus probable
($/boe)
Exploration and development $ 9.25 $ 10.53 $ 9.17 $ 9.67
Acquisitions (net of dispositions) 16.70 15.83 12.30 14.41
----------------------------------------------------------------------------
Total $ 11.63 $ 13.11 $ 10.90 $ 11.89
----------------------------------------------------------------------------

Recycle ratio based on operating
netback(2)
Proved plus probable 2.4 2.6 2.2 2.5

Reserves replacement ratio(3)
Proved plus probable 165% 233% 274% 222%

Including Future Development Costs

FD&A costs Proved ($/boe)
Exploration and development $ 22.96 $ 11.01 $ 8.82 $ 13.92
Acquisitions (net of dispositions) 28.28 27.87 22.93 25.97
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Total $ 24.73 $ 18.95 $ 15.10 $ 19.03
----------------------------------------------------------------------------

FD&A costs Proved plus probable
($/boe)
Exploration and development $ 20.01 $ 12.09 $ 9.27 $ 12.81
Acquisitions (net of dispositions) 23.12 20.23 14.05 17.82
----------------------------------------------------------------------------
Total $ 21.00 $ 16.06 $ 11.91 $ 15.16
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(1) 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.
(2) 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.
(3) 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 petroleum and natural 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 our existing properties beyond those included in the 2009 year end report.



(thousands of Canadian dollars, except per unit amounts)
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Forecast Prices Before Tax
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Proved plus probable reserves (1) 3,832,932
Undeveloped land (2) 220,607
Net monetary debt excluding convertible debentures (3) (466,540)
Asset retirement obligations (4) (54,593)
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Net asset value 3,532,406
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Diluted trust units (5) 109,828,742
Net asset value per trust unit $ 32.16
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Forecast Prices After Tax
Proved plus probable reserves (1) 3,190,571
Undeveloped land (2) 220,607
Net monetary debt excluding convertible debentures (3) (466,540)
Asset retirement obligations (4) (40,664)
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Net asset value 2,903,974
----------------------------------------------------------------------------
Diluted trust units (5) 109,828,742
Net asset value per trust unit $ 26.44
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(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 the 787,168 net acres of undeveloped land Baytex
held at December 31, 2009 was estimated by Management. This internal
evaluation generally represents what we believe to be the replacement
cost of our land at the present time based upon current industry
activity. In order to determine replacement cost, we have 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) Net monetary debt is 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 financial instruments (as the pricing effect of the financial
instruments have already been reflected by Sproule in the values noted
above).
(4) Management estimate of asset retirement obligations as at December 31,
2009 discounted at 8% (net of applicable future tax for Forecast
Prices After Tax calculations).
(5) Includes 109,298,911 trust units outstanding and 529,831 trust units
issuable on the conversion of the $7.8 million outstanding convertible
debentures as at December 31, 2009.


Petroleum and Natural Gas Reserves

Baytex announced certain of its year end 2009 reserves information on February 22, 2010. The following is additional summary information with regard to oil and gas reserves as at December 31, 2009. Other detailed information as required under NI 51-101 will be included in our Annual Information Form for the year ended December 31, 2009, which will be filed in late March 2010.



Reconciliation of Gross Company Interest Reserves (1)
By Principal Product Type
Forecast Prices and Costs
----------------------------------------------------------------------------
Light and Medium Crude Oil Heavy Oil
-------------------------------------------------------------
Proved + Proved +
Proved Probable Probable Proved Probable Probable
(2) (2) (2) (2) (2) (2)
(mbbl) (mbbl) (mbbl) (mbbl) (mbbl) (mbbl)
----------------------------------------------------------------------------
December 31,
2008 15,029 10,784 25,813 86,936 39,116 126,052
Extensions 1,060 2,060 3,120 7,554 6,138 13,692
Discoveries 84 104 188 84 32 116
Improved
Recoveries 914 507 1,421 6,412 4,667 11,079
Technical
Revisions (862) (3,253) (4,115) (120) (2,741) (2,861)
Acquisitions 88 26 114 5,122 1,349 6,471
Dispositions - - - (7) (6) (13)
Economic
Factors 18 5 23 81 (13) 68
Production (1,763) - (1,763) (9,008) - (9,008)
----------------------------------------------------------------------------

December 31,
2009 14,568 10,233 24,801 97,054 48,542 145,596
----------------------------------------------------------------------------


Natural Gas including
Natural Gas Liquids solution gas
-------------------------------------------------------------
Proved + Proved +
Proved Probable Probable Proved Probable Probable
(2) (2) (2) (2) (2) (2)
(mbbl) (mbbl) (mbbl) (mmcf) (mmcf) (mmcf)
----------------------------------------------------------------------------
December 31,
2008 3,726 1,847 5,573 119,976 58,226 178,202
Extensions 1 78 79 435 3,000 3,435
Discoveries 33 16 49 795 405 1,200
Improved
Recoveries 37 34 71 1,329 920 2,249
Technical
Revisions (282) (510) (792) (14,345) (20,017) (34,362)
Acquisitions 114 33 147 5,599 1,817 7,416
Dispositions - - - (169) (43) (212)
Economic
Factors (43) 3 (40) (2,686) (218) (2,904)
Production (769) - (769) (21,275) - (21,275)
----------------------------------------------------------------------------

December 31,
2009 2,817 1,501 4,318 89,659 44,090 133,749
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Oil Equivalent (3)
-----------------------------------------
Proved +
Proved Probable Probable
(2) (2) (2)
(mboe) (mboe) (mboe)
----------------------------------------------------------------------------
December 31, 2008 125,688 61,451 187,139
Extensions 8,687 8,776 17,463
Discoveries 334 220 554
Improved Recoveries 7,585 5,361 12,946
Technical Revisions (3,655) (9,840) (13,495)
Acquisitions 6,257 1,711 7,968
Dispositions (35) (13) (48)
Economic Factors (392) (42) (434)
Production (15,086) - (15,086)
----------------------------------------------------------------------------

December 31, 2009 129,383 67,624 197,007
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(1) Gross Company interest reserves include solution gas but do not include
royalty interests.
(2) Reserves information as at December 31, 2009 and 2008 is prepared in
accordance with NI 51-101.
(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 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.


Additional Information

Our unaudited consolidated financial statements for the three months and years ended December 31, 2009 and 2008 and related Management's Discussion and Analysis can be accessed immediately on our website at www.baytex.ab.ca and will be available shortly through SEDAR at www.sedar.com and EDGAR at www.sec.gov/edgar.shtml.

Our audited consolidated financial statements for the years ended December 31, 2009 and 2008 and related Management's Discussion and Analysis and our Annual Information Form for the year ended December 31, 2009 will be posted our website and filed on SEDAR and EDGAR later this month.

Conference Call

Baytex will hold a conference call and question and answer session at 1:00 p.m. MT (3:00 p.m. ET) on Thursday, March 11, 2010 to discuss our fourth quarter 2009 results. The conference call will be hosted by Anthony Marino, President and Chief Executive Officer, and Derek Aylesworth, Chief Financial Officer. Interested parties are invited to participate by calling toll-free across North America at 1-800-769-8320. An archived recording of the call will be available from March 11, 2010 until March 18, 2010 by dialing 1-800-408-3053 (within North America) or 416-695-5800 within the Toronto area and entering the reservation code 7732266. The conference call will also be archived on Baytex's website at www.baytex.ab.ca.

Advisory Regarding Forward-Looking Statements

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 document 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 document 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: our exploration and development capital expenditures for 2010; our production levels for both full-year 2010 and the first quarter of 2010; our ability to improve initial production rates, recovery rates and capital efficiencies at our Seal heavy oil resource play through enhanced development techniques; initial production rates from new wells; development plans for our properties; well productivity from new wells drilled; development plans for our properties; the number of indentified drilling locations on our Cardium lands; our ability to fund our capital expenditures and distributions from funds from operations; our liquidity and financial capacity; the value of our undeveloped land holdings; and the amount of future asset retirement obligations. In addition, information and statements relating to reserves are deemed to be forward-looking statements, as they involve implied assessment, based on certain estimates and assumptions, that the reserves described exist in quantities predicted or estimated, and that the reserves can be profitably produced in the future.

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 oil 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.

Contact Information

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