Baytex Energy Trust
TSX : BTE.UN
NYSE : BTE

Baytex Energy Trust

March 13, 2007 09:02 ET

Baytex Energy Trust Announces Record Cash Flow and Net Income for 2006

CALGARY, ALBERTA--(CCNMatthews - March 13, 2007) - Baytex Energy Trust (TSX:BTE.UN) (NYSE:BTE) is pleased to announce its operating and financial results for the three months and year ended December 31, 2006.

2006 Highlights

- Record cash flow of $275 million, 21% higher than the previous record set in 2005;

- Record net income of $147 million, 84% higher than the previous record set in 2005;

- Increased distributions per trust unit by 20%;

- Maintained conservative payout ratio at 52%;

- Fully funded distributions and capital expenditures by internally generated cash flow;

- Reduced total debt by 13% compared to one year ago;

- Achieved FD&A costs (excluding FDC) of $7.31/boe (one-year) and $7.36/boe (three-year);

- Realized recycle ratios of 3.7 (one-year) and 3.3 (three-year); and

- Delivered 38.7% one-year total return to unitholders compared to a negative 3.7% return for the TSX/S&P Energy Trust Index, 47.2% two-year annualized return (20.0% for the Index) and 43.5% three-year annualized return (23.4% for the Index). Our returns rank us as the best performer among all oil and gas income trusts for each of the one-year, two-year and three-year periods.



Three Months Ended Year Ended
------------------------------- ---------------------
December September December December December
31, 30, 31, 31, 31,
FINANCIAL 2006 2006 2005 2006 2005
------------------------------- ---------------------

($ thousands, except
per unit amounts)
Petroleum and natural
gas sales 134,541 145,754 162,356 556,689 546,940
Cash flow from
operations (1) 63,519 71,930 65,487 274,662 227,465
Per unit - basic 0.85 0.98 0.95 3.77 3.38
- diluted 0.79 0.90 0.86 3.45 3.12

Cash distributions 34,516 35,219 28,582 143,072 114,221
Per unit 0.54 0.54 0.45 2.16 1.80
Net income 19,988 42,040 35,184 147,069 79,876
Per unit - basic 0.27 0.57 0.51 2.02 1.19
- diluted 0.26 0.54 0.47 1.91 1.15

Exploration and
development 24,343 35,684 31,046 132,381 130,492
Net acquisitions
(dispositions) 7 1,303 (47,477) 702 21,957
Total capital
expenditures 24,350 36,987 (16,431) 133,083 152,449

Long-term notes 209,691 200,694 209,799 209,691 209,799
Convertible
debentures 18,906 21,173 73,766 18,906 73,766
Bank loan 127,495 130,685 123,588 127,495 123,588
Other working capital
deficiency 10,718 12,295 16,506 10,718 16,506
Notional
mark-to-market assets (2,393) (2,801) (5,183) (2,393) (5,183)
Total net debt 364,417 362,046 418,476 364,417 418,476



Three Months Ended Year Ended
------------------------------- ---------------------
December September December December December
31, 30, 31, 31, 31,
OPERATING 2006 2006 2005 2006 2005
------------------------------- ---------------------
Daily production
Light oil & NGL
(bbl/d) 3,643 3,594 4,022 3,735 3,842
Heavy oil (bbl/d) 22,416 21,325 24,051 21,325 21,265
Total oil (bbl/d) 26,059 24,919 28,073 25,060 25,107
Natural gas
(MMcf/d) 51.4 54.9 58.9 55.4 60.4
Oil equivalent
(boe/d @ 6:1) 34,631 34,074 37,895 34,292 35,177

Average prices
(before hedging)
WTI oil (US$/bbl) 60.21 70.48 60.02 66.22 56.56
Edmonton par oil
($/bbl) 64.49 79.17 71.18 72.77 68.75
BTE light oil & NGL
($/bbl) 48.62 57.94 55.78 53.84 53.84
BTE heavy oil
($/bbl) 41.15 48.28 37.75 43.57 37.38
BTE total oil
($/bbl) 42.19 49.68 40.33 45.10 39.90
BTE natural gas
($/Mcf) 7.03 6.35 10.69 7.13 8.22
BTE oil equivalent
($/boe) 42.19 46.57 46.48 44.48 42.60

TRUST UNIT
INFORMATION
TSX (C$)
Unit Price
High $25.82 $28.66 $18.78 $28.66 $18.78
Low $18.95 $21.50 $14.13 $16.81 $12.42
Close $22.28 $23.35 $17.70 $22.28 $17.70
Volume traded
(thousands) 31,901 23,943 21,534 102,652 87,481

NYSE (US$) (2)
Unit Price
High $22.84 $25.87 N/A $25.87 N/A
Low $16.63 $19.26 N/A $16.63 N/A
Close $18.96 $20.91 N/A $18.96 N/A
Volume traded
(thousands) 8,580 5,353 N/A 21,496 N/A

Units outstanding
(thousands) (3) 77,498 76,839 71,475 77,498 71,475


(1) Cash flow 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. The Trust's cash flow from
operations may not be comparable to other companies. The Trust
considers cash flow a key measure of performance as it demonstrates
the Trust's ability to generate the cash flow necessary to fund future
distributions and capital investments.

(2) Data reflects the periods since commencement of trading on March 27,
2006 on the NYSE.

(3) Number of trust units outstanding includes the conversion of
exchangeable shares at the respective exchange ratios in effect at
the end of the reporting periods.

(4) Total return is computed as the sum of capital appreciation in unit
price and cash distributions received, and assumes that cash
distributions are re-invested into additional trust units as received.


Operations Review

Capital expenditures during 2006 totaled $133 million, with $132.4 million spent on exploration and development activities and $0.7 million spent on minor acquisitions net of dispositions of assets.

During the fourth quarter, Baytex participated in the drilling of 24 (20.1 net) wells, resulting in 22 (18.1 net) oil wells and two (2.0 net) gas wells for a 100% success rate. For all of 2006, Baytex participated in the drilling of 128 (117.6 net) wells, resulting in 98 (91.3 net) oil wells, 21 (18.1 net) gas wells, three (3.0 net) stratigraphic test wells and six (5.2 net) dry holes. Overall success rate for the year was 94.5% (94.8% net). In addition, 31 wells were drilled by other operators during 2006, including five wells drilled in the fourth quarter, with Baytex retaining various royalty or working interests.

Financial Review

Cash flow from operations increased to a record $275 million in 2006, an improvement of 21% over 2005 results. Oil and gas production averaged 34,292 boe/d in 2006, which was essentially consistent with the 2005 average of 34,647 boe/d after adjusting for 2,100 bbl/d of thermal heavy oil production acquired in October and sold in December of 2005. Oil prices continued to set historical highs with WTI averaging US$66.22 per bbl in 2006 compared to the previous record of US$56.56 in 2005. Heavy oil prices, reflecting improvements in transportation and refining fundamentals, were particularly strong in 2006 with Baytex receiving an average price of $43.57 per bbl, an increase of 17% from one year earlier. Natural gas prices were less robust, with Baytex receiving an average wellhead price of $7.13 per mcf, a decrease of 13% from 2005. The key factor related to the Trust's cash flow improvement for 2006 over 2005 was the expiry of certain WTI derivative contracts which resulted in significant hedging losses in 2005. No WTI hedging gains or losses were realized in 2006.

Net income in 2006 was a record $147 million, an increase of $84% over 2005. The key contributors to this improvement were the elimination of hedging losses and a future income tax recovery resulting from a reduction of Canadian income tax rates.

After maintaining its distribution constant at $0.15 per month per unit since inception, Baytex increased its monthly distribution in January 2006 by 20% to $0.18 per unit. Despite this increase, total cash distributed (net of a modest 9% participation in our DRIP) represented a conservative payout ratio of 52%, reflecting our strategy to execute a business model which allows us to fund our capital program and distributions with internally generated cash flow.

Total net debt at year-end 2006 was $364 million, including $19 million of convertible debentures issued in June 2005 with a conversion price of $14.75 per trust unit. The majority of Baytex's remaining debt is in the form of senior subordinated term notes maturing in 2010. Baytex continues to have excellent financial flexibility with over $160 million in undrawn credit facilities at the end of 2006.

Capital Program Efficiency

Baytex's 2006 internal development program, led by advancements at Celtic and Seal, was an unequivocal success. Since the conversion to an income trust in late 2003, Baytex has continued to demonstrate superior capital and operational efficiencies as it prudently executes its strategy for long-term sustainability.



The efficiency of Baytex's capital programs is summarized as follows:

Three
Year Average
2006 2004 - 2006
----------- ------------
Excluding Future Development Costs ("FDC")

FD&A Costs - Proved ($/boe)
Exploration and development $ 9.61 $ 9.96
Acquisitions (net of dispositions) 5.38 7.49
----------- ------------
Total $ 9.57 $ 8.89
----------- ------------
----------- ------------

FD&A costs - Proved plus Probable ($/boe)
Exploration and development $ 7.35 $ 8.14
Acquisitions (net of dispositions) 3.89 6.32
----------- -----------
Total $ 7.31 $ 7.36
----------- ------------
----------- ------------

Operating Netback ($/boe) $ 26.75 $ 24.18

Recycle Ratio - Proved plus Probable 3.7 3.3

Reserves Replacement Ratio - Proved plus Probable 145% 203%

Including Future Development Costs

FD&A costs - Proved ($/boe)
Exploration and development $ 20.49 $ 16.49
Acquisitions (net of dispositions) 6.46 9.25
----------- ------------
Total $ 20.36 $ 13.33
----------- ------------
----------- ------------

FD&A costs - Proved plus Probable ($/boe)
Exploration and development $ 15.77 $ 13.73
Acquisitions (net of dispositions) 4.44 7.84
----------- ------------
Total $ 15.66 $ 11.20
----------- ------------
----------- ------------

Recycle Ratio - Proved plus Probable 1.7 2.0


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 the 2006 year-end report.


Forecast Prices
Discounted at ($ thousands)
----------------------------
5% 10%
------------- --------------
Proved plus probable reserves (1) 2,021,697 1,631,335
Undeveloped land (2) 100,090 100,090
Total debt (3) (347,904) (347,904)
------------- --------------
Net asset value 1,773,883 1,383,521
------------- --------------
------------- --------------
Diluted trust units (4) 78,828,360 78,828,360
Net asset value per trust unit $ 22.50 $ 17.55

Notes:
(1) As evaluated by Sproule Associates Limited as at December 31, 2006.
Net present value of future net revenue does not represent fair
market value of the reserves.
(2) As evaluated by Baytex as at December 31, 2006 on 618,135 net acres
of undeveloped land.
(3) Long-term debt net of working capital as at December 31, 2006,
excluding convertible debentures and notional assets associated with
the mark-to-market value of derivative contracts.
(4) Includes 75,121,664 trust units, 1,573,153 exchangeable shares converted
at an exchange ratio of 1.51072 and 1,330,102 trust units issuable on
the conversion of the outstanding convertible debentures as at
December 31, 2006.


Oil and Gas Reserves

Baytex announced certain of its year-end 2006 reserves information on February 12, 2007. Following is additional summary information with regard to oil and gas reserves as at December 31, 2006. Other detailed information as required under NI 51-101 will be included in Baytex's Annual Information Form.



Reconciliation of Company Interest Reserves (3)
By Principal Product Type
Forecast Prices and Costs
----------------------------------------------------------------------------

Light and Medium Crude Oil Heavy Oil
---------------------------- ----------------------------
Proved + Proved +
Proved Probable Probable Proved Probable Probable
(1) (1) (1) (1) (1) (1)
------- -------- -------- ------- -------- ---------
(Mbbl) (Mbbl) (Mbbl) (Mbbl) (Mbbl) (Mbbl)

December 31, 2005 5,472 2,342 7,814 71,266 26,286 97,552
Extensions - - - 1,828 887 2,715
Discoveries 25 12 37 90 25 115
Technical Revisions 312 (351) (39) 9,890 5,649 15,539
Acquisitions 121 51 172 - - -
Dispositions - - - - - -
Economic Factors 36 (10) 26 518 82 600
Production (780) - (780) (7,784) - (7,784)
------- -------- -------- ------- -------- ---------
December 31, 2006 5,186 2,044 7,230 75,808 32,929 108,737
------- -------- -------- ------- -------- ---------
------- -------- -------- ------- -------- ---------


Natural Gas Liquids Natural Gas
---------------------------- ----------------------------
Proved + Proved +
Proved Probable Probable Proved Probable Probable
(1) (1) (1) (1) (1) (1)
------- -------- -------- ------- -------- ---------
(Mbbl) (Mbbl) (Mbbl) (MMcf) (MMcf) (MMcf)

December 31, 2005 3,635 1,254 4,889 125,537 50,862 176,399
Extensions 138 29 167 4,817 90 4,907
Discoveries 76 26 102 2,458 1,449 3,907
Technical Revisions 308 (226) 82 (2,425) (11,535) (13,960)
Acquisitions - - - 32 15 47
Dispositions - - - - - -
Economic Factors (112) (69) (181) (1,779) (1,244) (3,023)
Production (583) - (583) (20,219) - (20,219)
------- -------- -------- ------- -------- ---------
December 31, 2006 3,462 1,014 4,476 108,421 39,637 148,058
------- -------- -------- ------- -------- ---------
------- -------- -------- ------- -------- ---------


Oil Equivalent (2)
---------------------------
Proved +
Proved Probable Probable
(1) (1) (1)
--------- -------- --------
(Mboe) (Mboe) (Mboe)

December 31, 2005 101,296 38,359 139,655
Extensions 2,769 931 3,700
Discoveries 601 305 906
Technical Revisions 10,106 3,150 13,256
Acquisitions 127 53 180
Dispositions - - -
Economic Factors 146 (206) (60)
Production (12,517) - (12,517)
--------- -------- --------
December 31, 2006 102,528 42,592 145,120
--------- -------- --------
--------- -------- --------

Notes:

(1) Reserves information as at December 31, 2005 and 2006 is prepared in
accordance with NI 51-101.
(2) 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.
(3) Company interest reserves include solution gas but do not include
royalty interest.


Management's Discussion and Analysis

Management's discussion and analysis ("MD&A"), dated March 12, 2007, should be read in conjunction with the unaudited interim consolidated financial statements for the three months and the year ended December 31, 2006 and the audited consolidated financial statements and MD&A for the year ended December 31, 2005. 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.

Cash flow from operations is not a measure based on generally accepted accounting principles ("GAAP"), but is a financial term commonly used in the oil and gas industry. It represents cash generated from operating activities before changes in non-cash working capital, site restoration and reclamation expenditures, other assets and deferred credits. The Trust's cash flow from operations may not be comparable to other companies. The Trust considers it a key measure as it demonstrates the ability of the Trust to generate the cash flow necessary to fund future distributions and capital investments.

Production. Light oil and natural gas liquids ("NGL") production for the fourth quarter of 2006 decreased by 9% to 3,643 bbl/d from 4,022 bbl/d a year earlier. Heavy oil production decreased 7% to 22,416 bbl/d for the fourth quarter of 2006 compared to 24,051 bbl/d a year ago. Natural gas production decreased by 13% to 51.4 mmcf/d for the fourth quarter of 2006 compared to 58.9 mmcf/d for the same period last year. The decrease in light oil, NGL and natural gas volumes was largely due to delayed timing of certain natural gas tie-ins and natural declines. The decrease in heavy oil production is attributable to the sale of approximately 2,100 bbl/d of thermal production at year-end 2005.

For the year ended December 31, 2006, light oil & NGL production decreased by 3% to 3,735 bbl/d from 3,842 bbl/d for last year. Heavy oil production for 2006 was consistent with that of the prior year with production of 21,325 bbl/d compared to 21,265 bbl/d in 2005. Natural gas production decreased by 8% to average 55.4 mmcf/d for 2006 compared to 60.4 mmcf/d for 2005. The decrease in light oil, NGL and natural gas volumes was largely due to delayed timing of certain natural gas tie-ins and natural declines. Heavy oil production increased slightly due to development activities and full-year ownership of the properties at Celtic, offset by the sale of thermal production at year-end 2005.

Revenue. Petroleum and natural gas sales decreased 17% to $134.5 million for the fourth quarter of 2006 from $162.4 million for the same period in 2005. For the year, petroleum and natural gas sales increased by 2% to $556.7 million in 2006 from $546.9 million a year earlier.

For the per sales unit calculations, heavy oil sales for the three months ended December 31, 2006 were 28 bbl/d higher (three months ended December 31, 2005 - 70 bbl/d higher) than the production for the period due to inventory in transit under the Frontier supply agreement. The inventory adjustments had minimal effect on sales for the years ended December 31, 2006 and December 31, 2005.



Three Months ended December 31
------------------------------------------------
2006 2005
------------------------------------------------
$ 000s $/Unit(1) $ 000s $/Unit(1)
-------- --------- --------- ----------
Oil revenue (barrels)
Light oil & NGL 16,294 48.62 20,637 55.78
Heavy oil 84,961 41.15 83,783 37.75
Derivative contracts gain
(loss) 503 0.24 (14,109) (6.36)
-------- --------- --------- ----------
Total oil revenue 101,758 42.40 90,311 34.88
Natural gas revenue (Mcf) 33,286 7.03 57,936 10.69
-------- --------- --------- ----------
Total revenue (boe) 135,044 42.35 148,247 42.44
-------- --------- --------- ----------
-------- --------- --------- ----------

(1) Per-unit oil revenue is in $/bbl; per-unit natural gas revenue is in
$/Mcf.


Revenue from light oil and NGL for the fourth quarter of 2006 decreased 21% from the same period a year ago due to a 9% decrease in production combined with a 13% decrease in wellhead prices. Revenue from heavy oil increased 1% as the result of a 9% increase in wellhead prices, partially offset by a 7% decrease in production. Revenue from natural gas decreased 43% as the result of a 34% decrease in wellhead prices and a 13% decrease in production.




Year ended December 31
------------------------------------------------
2006 2005
------------------------------------------------
$ 000s $/Unit(1) $ 000s $/Unit(1)
-------- --------- --------- ----------
Oil revenue (barrels)
Light oil & NGL 73,387 53.84 75,507 53.84
Heavy oil 339,066 43.57 290,163 37.38
Derivative contracts gain
(loss) 2,529 0.32 (48,462) (6.24)
-------- --------- --------- ----------
Total oil revenue 414,982 45.38 317,208 34.61
Natural gas revenue (Mcf) 144,236 7.13 181,270 8.22
-------- --------- --------- ----------
Total revenue (boe) 559,218 44.68 498,478 38.82
-------- --------- --------- ----------
-------- --------- --------- ----------

(1) Per-unit oil revenue is in $/bbl; per-unit natural gas revenue is in
$/Mcf.


For the year ended December 31, 2006, light oil and NGL revenue decreased 3% from last year due to a decrease in production. Revenue from heavy oil increased 17% due to the increase in wellhead prices. Revenue from natural gas decreased 20% compared to 2005, as production decreased 8% and average price decreased 13%.

Royalties. Total royalties decreased to $18.5 million for the fourth quarter of 2006 from $27.3 million in 2005. This decrease is reflective of the decrease in total revenue. Total royalties for the fourth quarter of 2006 were 13.8% of sales compared to 16.8% of sales for the same period in 2005. For the fourth quarter of 2006, royalties were 14.7% of sales for light oil and NGL, 12.1% for heavy oil and 17.5% for natural gas. These rates compared to 16.2%, 11.7% and 24.3%, respectively, for the same period last year.

For the year ended December 31, 2006, royalties increased to $85.0 million from $81.9 million for last year. Total royalties in 2006 were 15.3% of sales, compared to 15.0% of sales for 2005. For 2006, royalties were 14.6% of sales for light oil and NGL, 14.6% for heavy oil and 17.2% for natural gas. These rates compared to 15.1%, 12.4% and 19.0%, respectively, for 2005. Royalties are generally based on market index prices realized by the industry in the period, with rates increasing as price and volume escalate. Baytex's increased effective royalty rate for heavy oil in 2006 was reflective of the higher market price.

Operating Expenses. Operating expenses for the fourth quarter of 2006 decreased to $29.8 million from $33.3 million in the corresponding quarter last year. Operating expenses were $9.36 per boe for the fourth quarter of 2006 compared to $9.55 per boe for the fourth quarter of 2005. For the fourth quarter of 2006, operating expenses were $12.25 per barrel of light oil and NGL, $9.47 per barrel of heavy oil and $1.31 per mcf of natural gas. The operating expenses for the same period a year ago were $6.28, $11.00 and $1.22, respectively.

Operating expenses for the year 2006 increased to $112.4 million from $110.6 million in 2005. Operating expenses were $8.98 per boe for 2006 compared to $8.62 per boe for the prior year. In 2006, operating expenses were $11.17 per barrel of light oil and NGL, $9.23 per barrel of heavy oil and $1.25 per mcf of natural gas compared to $9.06, $9.56 and $1.08, respectively, for the year earlier.

Transportation Expenses. Transportation expenses for the fourth quarter of 2006 were $6.4 million compared to $6.0 million for the fourth quarter of 2005. These expenses were $2.00 per boe for the fourth quarter of 2006 compared to $1.71 for the same period in 2005. Transportation expenses were $2.41 per barrel of oil and $0.12 per mcf of natural gas. The corresponding amounts for 2005 were $2.02 and $0.14, respectively.

Transportation expenses for the year ended December 31, 2006 were $24.3 million compared to $22.4 million for 2005. These expenses were $1.95 per boe in 2006 compared to $1.74 in 2005. Transportation expenses were $2.38 per barrel of oil and $0.13 per mcf of natural gas in 2006, and $2.11 per barrel of oil and $0.14 per mcf of natural gas in 2005.

General and Administrative Expenses. General and administrative expenses for the fourth quarter of 2006 increased to $5.9 million from $4.6 million in 2005. On a per sales unit basis, these expenses were $1.84 per boe for the fourth quarter of 2006 compared to $1.32 per boe for the same period in 2005. The increased costs are due to escalating costs in the labour market, additional expenses associated with the New York Stock Exchange listing and costs relating to compliance requirements under the Sarbanes-Oxley Act. In accordance with our full cost accounting policy, no expenses were capitalized in either the fourth quarter of 2006 or 2005.

General and administrative expenses for the year were $20.8 million, compared to $16.0 million for the prior year. On a per sales unit basis, these expenses were $1.67 per boe in 2006 and $1.25 per boe in 2005. The increase is attributable to the same factors influencing the fourth quarter variance. In accordance with our full cost accounting policy, no expenses were capitalized in either 2006 or 2005.

Unit-based Compensation Expense. Compensation expense related to the Trust's unit rights incentive plan was $2.2 million for the fourth quarter of 2006 compared to $1.8 million for the fourth quarter of 2005. For the year ended December 31, 2006, compensation expense was $7.5 million compared to $5.3 million for 2005.

Compensation expense associated with rights granted under the plan is recognized in income over the vesting period of the plan with a corresponding increase in contributed surplus. The exercise of trust unit rights are recorded as an increase in trust units with a corresponding reduction in contributed surplus.

Interest Expenses. Interest expenses decreased to $8.8 million for the fourth quarter of 2006 from $9.7 million for the same quarter last year, primarily due to the decrease in convertible debentures outstanding and the effect of a stronger Canadian dollar on U.S. dollar denominated interest expenses.

In 2006, interest expenses were $35.0 million compared to $33.1 million for last year. The increase is attributable to a gradual increase in interest rates partially offset by the decrease in outstanding convertible debentures and the increasing strength of the Canadian currency.

Foreign Exchange. Foreign exchange in the fourth quarter of 2006 was a loss of $9.0 million compared to a loss of $0.9 million in the prior year. The loss is based on the translation of the U.S. dollar denominated long-term debt at 0.8581 at December 31, 2006 compared to 0.8966 at September 30, 2006. The 2005 loss is based on translation at 0.8577 at December 31, 2005 compared to 0.8613 at September 30, 2005.

The foreign exchange gain for 2006 was $0.1 million compared to $6.8 million in the prior year. The 2006 gain is based on the translation of the U.S. dollar denominated long-term debt at 0.8581 at December 31, 2006 compared to 0.8577 at December 31, 2005. The 2005 gain is based on translation at 0.8577 at December 31, 2005 compared to 0.8308 at December 31, 2004.

Depletion, Depreciation and Accretion. The provision for depletion, depreciation and accretion at $39.5 million for the fourth quarter of 2006 represents a decrease from $41.6 million for the same quarter in 2005. This decrease is due to lower production in the current period. On a sales-unit basis, the provision for the current quarter was $12.38 per boe compared to $11.91 per boe for the same quarter in 2005.

Depletion, depreciation and accretion decreased to $152.6 million for 2006 compared to $167.1 million for 2005. On a sales-unit basis, the provision for the current year was $12.19 per boe compared to $13.02 per boe for 2005.

Taxes. Current tax expenses increased to $2.5 million for the fourth quarter of 2006 from $2.4 million for the same quarter a year ago. The current tax expenses are comprised of $1.8 million of Saskatchewan Capital Tax and $0.6 million of prior period adjustments compared to $2.1 million of Saskatchewan Capital Tax and $0.3 million of Large Corporation Tax in the corresponding period in 2005.

Current tax expenses were $8.4 million for 2006 compared to $8.7 million last year. The current tax expenses are comprised of $8.2 million of Saskatchewan Capital Tax, a recovery of $0.4 million of Large Corporation Tax and $0.6 million of prior period adjustments compared to $6.9 million of Saskatchewan Capital Tax and $1.8 million of Large Corporation Tax in 2005.

Net Income. Net income for the fourth quarter of 2006 was $20.0 million compared to $35.2 million for the fourth quarter in 2005. The variance was the result of lower production, lower sales prices, and losses due to foreign exchange which was partially offset by a recovery of future income tax .

Net income for 2006 was $147.1 million compared to $79.9 million for 2005. The variance was primarily due to the elimination of realized loss in financial derivatives and a larger future income tax recovery for 2006.

Liquidity and Capital Resources. At December 31, 2006, total net debt was $364.4 million compared to $418.5 million at the end of 2005, with the decrease mainly attributable to the conversion of convertible debentures. Bank borrowings and working capital deficiency at year-end 2006 were $138.2 million compared to total credit facilities of $300 million.

Capital Expenditures

The Trust's total capital expenditures for 2006 and 2005 are summarized as follows:




Year Ended December 31
----------------------------
($thousands) 2006 2005
------------- --------------
Land 11,118 7,126
Seismic 2,202 4,949
Drilling and completion 97,273 90,180
Equipment 19,240 23,611
Other 2,548 4,626
------------- --------------
Total exploration and development 132,381 130,492
Property acquisitions 1,530 70,986
Property dispositions (828) (49,029)
------------- --------------
Total capital expenditures 133,083 152,449
------------- --------------
------------- --------------


Evaluation of Disclosure Controls and Procedures. Raymond Chan, the President and Chief Executive Officer, and Derek Aylesworth, the Chief Financial Officer of Baytex (together the "Disclosure Officers"), are responsible for establishing and maintaining disclosure controls and procedures for Baytex. For the year ended December 31, 2006, the Disclosure Officers evaluated the effectiveness of the disclosure controls and procedures. As a result of this evaluation, the Disclosure Officers have concluded that the disclosure controls and procedures are effective to provide reasonable assurance that all material or potentially material information about the activities of Baytex is made known to them by others within Baytex.

It should be noted that while our Disclosure Officers believe that Baytex's disclosure controls and procedures provide a reasonable level of assurance with regard to their effectiveness, they do not expect that the disclosure controls and procedures or internal controls over financial reporting will prevent all errors and fraud. A control system, no matter how well conceived or operated, can provide only reasonable, but not absolute, assurance that the objectives of the control system are met.

There were no changes in our internal control over financial reporting during the four quarter ended December 31, 2006 that materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

Conference Call

Baytex will host a conference call and question and answer session at 2:00 p.m. MT (4:00 p.m. ET) on Tuesday, March 13, 2007 to discuss our fourth quarter and 2006 results. The conference call will be hosted by Raymond Chan, President and Chief Executive Officer, Derek Aylesworth, Chief Financial Officer and Anthony Marino, Chief Operating Officer. Interested parties are invited to participate by calling toll-free across North America at 1-800-745-2189. An archived recording of the call will be available from March 13, 2007 until March 27, 2007 by dialing 1-800-558-5253 or 416-626-4100 within the Toronto area, and entering the access code 21330615. The conference call will also be archived on Baytex's website at www.baytex.ab.ca.

Forward-Looking Statements

Certain statements in this press release are "forward-looking statements" within the meaning of the United States Private Securities Litigation Reform Act of 1995. Specifically, this press release contains forward-looking statements relating to Management's approach to operations and Baytex's production, cash flow, debt levels and cash distribution practices. The reader is cautioned that assumptions used in the preparation of such information, 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: general economic, market and business conditions; industry capacity; competitive action by other companies; fluctuations in oil and gas prices; the ability to produce and transport crude oil and natural gas to markets; the result of exploration and development drilling and related activities; fluctuation in foreign currency exchange rates; the imprecision of reserves estimates; the ability of suppliers to meet commitments; actions by governmental authorities including increases in taxes; decisions or approvals of administrative tribunals; change in environmental and other regulations; risks associated with oil and gas operations; the weather in Baytex's areas of operations; and other factors, many of which are beyond the control of Baytex. 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.

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. Trust units of Baytex are traded on the Toronto Stock Exchange under the symbol BTE.UN and on the New York Stock Exchange under the symbol BTE.

Financial statements for the years ended December 31, 2006 and December 31, 2005 are attached.



Baytex Energy Trust
Consolidated Balance Sheets
(thousands)

December 31, 2006 December 31, 2005
-------------------------------------------

Assets
Current assets
Accounts receivable $ 64,716 $ 73,869
Crude oil inventory 9,609 9,984
Financial derivative
contracts (note 13) 3,448 5,183
-------------------------------------------
77,773 89,036

Deferred charges and other
assets 4,475 9,038
Petroleum and natural gas
properties 959,626 969,738
Goodwill 37,755 37,755
-------------------------------------------
$ 1,079,629 $ 1,105,567
-------------------------------------------
-------------------------------------------


Liabilities
Current liabilities
Accounts payable and accrued
liabilities $ 71,521 $ 89,966
Distributions payable to
unitholders 13,522 10,393
Bank loan 127,495 123,588
Financial derivative
contracts (note 13) 1,055 -
-------------------------------------------
213,593 233,947


Long-term debt (note 3) 209,691 209,799
Convertible debentures (note 4) 18,906 73,766
Asset retirement obligations
(note 5) 39,855 33,010
Deferred obligations (note 14) 2,391 4,558
Future income taxes 118,858 159,745
-------------------------------------------
603,294 704,825


Non-controlling interest (note 7) 17,187 12,810


Unitholders' Equity
Unitholders' capital (note 6) 637,156 555,020
Conversion feature of
debentures (note 4) 940 3,698
Contributed surplus 13,357 10,332
Deficit (192,305) (181,118)
-------------------------------------------
459,148 387,932
-------------------------------------------
$ 1,079,629 $ 1,105,567
-------------------------------------------
-------------------------------------------

See accompanying notes to the consolidated financial statements.


Baytex Energy Trust
Consolidated Statements of Operations and Deficit
(thousands, except per unit data)

Three Months Ended Year Ended
December 31 December 31
-------------------- -------------------
2006 2005 2006 2005
-------------------- -------------------

Revenue
Petroleum and natural
gas sales $ 134,541 $ 162,356 $ 556,689 $ 546,940
Royalties (18,539) (27,269) (85,043) (81,898)
Realized gain (loss) on
financial derivatives 503 (14,109) 2,529 (48,462)
Unrealized gain (loss) on
financial derivatives (408) 26,409 (2,790) 14,696
---------- ---------- ---------- --------
116,097 147,387 471,385 431,276
---------- ---------- ---------- --------


Expenses
Operating 29,848 33,344 112,406 110,648
Transportation 6,376 5,959 24,346 22,399
General and administrative 5,883 4,617 20,843 16,010
Unit based compensation
(note 8) 2,168 1,809 7,460 5,346
Interest (note 11) 8,750 9,740 34,960 33,124
Foreign exchange loss (gain) 8,997 864 (108) (6,784)
Depletion, depreciation and
accretion 39,488 41,587 152,579 167,135
---------- ---------- ---------- --------
101,510 97,920 352,486 347,878
---------- ---------- ---------- --------

Income before taxes and
non-controlling interest 14,587 49,467 118,899 83,398
---------- ---------- ---------- --------

Taxes (recovery) (note 10)
Current 2,466 2,410 8,414 8,747
Future (10,167) 11,088 (41,169) (7,074)
---------- ---------- ---------- --------
(7,701) 13,498 (32,755) 1,673
---------- ---------- ---------- --------

Income before non-controlling
interest 22,288 35,969 151,654 81,725
Non-controlling interest
(note 7) (2,300) (785) (4,585) (1,849)
---------- ---------- ---------- --------
Net income 19,988 35,184 147,069 79,876

Deficit, beginning
of period (171,813) (185,320) (181,118) (139,453)
Distributions to
unitholders (40,480) (30,982) (158,256) (121,541)
---------- ---------- ---------- --------

Deficit, end of period $(192,305) $(181,118) $(192,305) $(181,118)
---------- ---------- ---------- --------
---------- ---------- ---------- --------

Net income per trust unit
Basic $ 0.27 $ 0.51 $ 2.02 $ 1.19
Diluted $ 0.26 $ 0.47 $ 1.91 $ 1.15

Weighted average trust
units (note 9)
Basic 74,848 68,669 72,947 67,382
Diluted 78,408 77,610 80,438 74,131

See accompanying notes to the consolidated financial statements.


Baytex Energy Trust
Consolidated Statements of Cash Flows
(thousands)
Three Months Ended Year Ended
December 31 December 31
-------------------- -------------------
2006 2005 2006 2005
-------------------- -------------------

Cash provided by (used in):

OPERATING ACTIVITIES
Net income $ 19,988 $ 35,184 $ 147,069 $ 79,876
Items not affecting cash:
Unit based compensation
(note 8) 2,168 1,809 7,460 5,346
Amortization of deferred
charges 304 459 1,267 1,492
Foreign exchange
loss (gain) 8,997 864 (108) (6,784)
Depletion, depreciation
and accretion 39,488 41,587 152,579 167,135
Accretion on debentures 33 120 189 321
Unrealized loss (gain)
on financial
derivatives (note 13) 408 (26,409) 2,790 (14,696)
Future income tax
(recovery) (10,167) 11,088 (41,169) (7,074)
Non-controlling interest
(note 7) 2,300 785 4,585 1,849
---------- ---------- ---------- --------
63,519 65,487 274,662 227,465
Change in non-cash working
capital (1,878) 3,393 (9,058) (20,212)
Asset retirement expenditures (233) (382) (1,747) (1,637)
Decrease in deferred charges
and other assets (409) (1,134) (1,875) (977)
---------- ---------- ---------- --------
60,999 67,364 261,982 204,639
---------- ---------- ---------- --------

FINANCING ACTIVITIES
Increase (Decrease) in
bank loan (3,189) (64,853) 3,907 (37,856)
Payments of distributions (35,079) (27,897) (141,453) (114,221)
Issue of trust units
(note 6) 1,427 507 8,509 2,916
Issuance of convertible
debentures (note 4) - - - 100,000
Convertible debentures
issue costs (note 4) - - - (4,250)
---------- ---------- ---------- --------
(36,841) (92,243) (129,037) (53,411)
---------- ---------- ---------- --------

INVESTING ACTIVITIES
Petroleum and natural
gas property expenditures (24,380) (29,608) (133,911) (201,478)
Disposal of petroleum and
natural gas properties 30 46,039 828 49,029
Change in non-cash working
capital 192 8,448 138 1,221
---------- ---------- ---------- --------
(24,158) 24,879 (132,945) (151,228)
---------- ---------- ---------- --------


Change in cash and cash
equivalents - - - -

Cash and cash equivalents,
beginning of period - - - -
---------- ---------- ---------- --------

Cash and cash equivalents,
end of period $ - $ - $ - $ -
---------- ---------- ---------- --------
---------- ---------- ---------- --------

See accompanying notes to the consolidated financial statements.

Notes to the Consolidated Financial Statements
Three Months and Year Ended December 31, 2006 and 2005
(all tabular amounts in thousands, except per unit amounts)


1. Basis of Presentation

Baytex Energy Trust (the "Trust") was established on September 2, 2003 under a Plan of Arrangement involving the Trust and Baytex Energy Ltd. (the "Company"). The Trust is an open-ended investment trust created pursuant to a trust indenture. Subsequent to the Plan of Arrangement, the Company is a subsidiary of the Trust.

The consolidated financial statements include the accounts of the Trust and its subsidiaries and have been prepared by management in accordance with Canadian generally accepted accounting principles as described in note 2.

2. Accounting Policies

The interim consolidated financial statements have been prepared following the same accounting policies and methods of computation as the consolidated financial statements of the Trust as at December 31, 2005. The interim consolidated financial statements contain disclosures, which are supplemental to the Trust's annual consolidated financial statements. Certain disclosures, which are normally required to be included in the notes to the annual consolidated financial statements, have been condensed or omitted. The interim consolidated financial statements should be read in conjunction with the Trust's consolidated financial statements and notes thereto for the year ended December 31, 2005.



3. Long-term Debt
December 31, December 31,
2006 2005
------------ -------------
10.5% senior subordinated notes (US$247) $ 288 $ 288
9.625% senior subordinated notes (US$179,699) 209,403 209,511
------------ -------------
$ 209,691 $ 209,799
------------ -------------
------------ -------------


The company has US$247,000 senior subordinated notes bearing interest at 10.5% payable semi-annually with principal repayable on February 15, 2011. These notes are unsecured and are subordinate to the Company's bank credit facilities.

US$179.7 million of 9.625% senior subordinated notes due July 15, 2010 are unsecured and are subordinate to the Company's bank credit facilities. After July 15 of each of the following years, these notes are redeemable, at the Company's option, in whole or in part with not less than 30 nor more than 60 days' notice at the following redemption prices (expressed as percentage of the principal amount of the notes): 2007 at 104.813%, 2008 at 102.406%, 2009 and thereafter at 100%. The Company entered into an interest rate swap contract converting the fixed rate to a floating rate reset quarterly at the three month LIBOR rate plus 5.2% until the maturity of these notes.

4. Convertible Unsecured Subordinated Debentures

On June 6, 2005 the Trust issued $100 million principal amount of 6.5% convertible unsecured subordinated debentures for net proceeds of $95.8 million. The debentures pay interest semi-annually and are convertible at the option of the holder at any time into fully paid trust units at a conversion price of $14.75 per trust unit. The debentures mature on December 31, 2010 at which time they are due and payable.

The debentures have been classified as debt net of the fair value of the conversion feature which has been classified as unitholders' equity. This resulted in $95.2 million being classified as debt and $4.8 million being classified as equity. Issue costs are being amortized over the term of the debentures, and the debt portion will accrete up to the principal balance at maturity. The accretion, amortization of issue costs and the interest paid are expensed as interest expense in the consolidated statements of operations. If the debentures are converted to trust units, a portion of the value of the conversion feature under unitholders' equity will be reclassified to unitholders' capital along with the principal amounts converted.



Conversion
Number of Convertible Feature of
Debentures Debentures Debentures
----------------------------------------------
Issued on June 6, 2005 100,000 $ 95,200 $ 4,800
Conversion (22,848) (21,755) (1,102)
Accretion - 321 -
----------------------------------------------
Balance, December 31, 2005 77,152 $ 73,766 $ 3,698
Conversion (57,533) (55,049) (2,758)
Accretion - 189 -
----------------------------------------------
Balance, December 31, 2006 19,619 $ 18,906 $ 940
----------------------------------------------
----------------------------------------------


5. Asset Retirement Obligations
2006 2005
------------ -------------
Balance, beginning of year $ 33,010 $ 73,297
Liabilities incurred 1,199 406
Liabilities settled (1,747) (1,637)
Acquisition of liabilities - 3,410
Disposition of liabilities (122) (2,117)
Accretion 2,678 5,762
Change in estimate(1) 4,837 (46,111)
------------ -------------
Balance, end of year $ 39,855 $ 33,010
------------ -------------
------------ -------------

(1) The change in estimate is partially due to the fluctuations in
forecasted market prices of petroleum and natural gas which affect the
projected economic life of the wells and facilities, This results in
changes to the timing of when wells and facilities are abandoned and
reclaimed thus changing the discounted present value of asset retirement
obligations. Other factors affecting the liability amount are change in
status of wells and change in the estimated costs of abandonment and
reclamations.


The Trust's asset retirement obligations are based on the Trust's net ownership in wells and facilities. Management estimates the costs to abandon and reclaim the wells and the facilities and the estimated time period during which these costs will be incurred in the future. The undiscounted amount of estimated cash flow required to settle the retirement obligations at December 31, 2006 is $236 million. Estimated cash flow has been discounted at a credit-adjusted risk free rate of 8.0% and an estimated annual inflation rate of 5.0% for the year 2007, 4.0% for 2008, 3.0% for 2009 and 2.0% thereafter.



6. Unitholders' Capital

Trust Units

The Trust is authorized to issue an unlimited number of trust units

Number of units Amount
---------------- -------------
Balance, December 31, 2004 66,538 $ 515,663
Issued on conversion of debentures 1,549 22,859
Issued on conversion of exchangeable shares 363 5,373
Issued on exercise of trust unit rights 369 2,916
Transfer from contributed surplus on exercise
of trust unit rights - 1,301
Issued pursuant to distribution reinvestment
program 464 6,908
---------------- -------------
Balance, December 31, 2005 69,283 555,020
Issued on conversion of debentures 3,901 54,799
Issued on conversion of exchangeable shares 34 720
Issued on exercise of trust unit rights 1,250 8,509
Transfer from contributed surplus on exercise
of trust unit rights - 4,434
Issued pursuant to distribution reinvestment
program 654 13,674
---------------- -------------
Balance, December 31, 2006 75,122 $ 637,156
---------------- -------------
---------------- -------------


7. Non-Controlling Interest

The Company is authorized to issue an unlimited number of exchangeable shares. The exchangeable shares can be converted (at the option of the holder) into trust units at any time up to September 2, 2013. Up to 1.9 million exchangeable shares may be redeemed annually by the Company for either a cash payment or the issue of trust units. The number of trust units issued upon conversion is based upon the exchange ratio in effect at the conversion date. The exchange ratio is calculated monthly based on the cash distribution paid divided by the weighted average trust unit price for the five day trading period ending on the record date. The exchange ratio at December 31, 2006 was 1.51072 trust units per exchangeable share. Cash distributions are not paid on the exchangeable shares. The exchangeable shares are not publicly traded, although they may be transferred by the holder without first being converted to trust units.

The exchangeable shares of the Company are presented as a non-controlling interest on the consolidated balance sheet because they fail to meet the non-transferability criteria necessary in order for them to be classified as equity. Net income has been reduced by an amount equivalent to the non-controlling interest proportionate share of the Trust's consolidated net income with a corresponding increase to the non-controlling interest on the balance sheet.



Number of
Exchangeable
Shares Amount
---------------- -------------
Balance, December 31, 2004 1,876 $ 12,936
Exchanged for trust units (279) (1,975)
Non-controlling interest in net income - 1,849
---------------- -------------
Balance, December 31, 2005 1,597 12,810
Exchanged for trust units (24) (208)
Non-controlling interest in net income - 4,585
---------------- -------------
Balance, December 31, 2006 1,573 $ 17,187
---------------- -------------
---------------- -------------


8. Trust Unit Rights Incentive Plan

The Trust has a Trust Unit Rights Incentive Plan (the "Plan") whereby the maximum number of trust units issuable pursuant to the plan is a "rolling" maximum equal to 10% of the outstanding trust units plus the number of trust units which may be issued on the exchange of outstanding exchangeable shares. Any increase in the issued and outstanding units will result in an increase in the available number of trust units issuable under the plan, and any exercises of incentive rights will make new grants available under the plan, effectively resulting in a re-loading of the number of rights available to grant under the plan. Trust unit rights are granted at the volume weighted average trading price of the trust units for the five trading days prior to the date of grant, vest over three years and have a term of five years. The Plan provides for the exercise price of the rights to be reduced in future periods by a portion of the future distributions, subject to certain performance criteria.

The Trust recorded compensation expense of $7.5 million for the year ended December 31, 2006 ($5.3 million in 2005) pursuant to rights granted under the Plan.

Effective January 1, 2006, the Trust commenced using the binomial-lattice model to calculate the estimated fair value of the unit rights issued. The following assumptions were used to arrive at the estimate of fair values:



2006 2005
-------------------------------
Expected annual right's exercise price
reduction $ 2.16 $ 1.80
Expected volatility 23% - 28% 23%
Risk-free interest rate 3.54% - 4.45% 3.30% - 3.84%
Expected life of right (years) Various (1) 5

(1) The binomial-lattice model calculates the fair values based on an
optimal strategy, resulting in various expected life of unit rights. The
maximum term is limited to five years by the Trust Unit Rights Incentive
Plan.

The number of unit rights outstanding and exercise prices are detailed
below:

Weighted average
Number of rights exercise price (1)
------------------ -------------------
Balance, December 31, 2004 3,537 $ 9.60
Granted 2,451 $ 15.01
Exercised (369) $ 7.90
Cancelled (253) $ 9.83
------------------ -------------------
Balance, December 31, 2005 5,366 $ 10.88
Granted 2,443 $ 21.66
Exercised (1,250) $ 6.81
Cancelled (246) $ 11.54
--------------------------------------
Balance, December 31, 2006 6,313 $ 14.00
------------------ -------------------
------------------ -------------------

(1) Exercise price reflects grant prices less reduction in exercise price as
discussed above.

The following table summarizes information about the unit rights outstanding
at December 31, 2006:

Number Number
Outstanding Weighted Weighted Exercisable Weighted
at Average Average at Average
Range of December 31, Remaining Exercise December 31, Exercise
Exercise Prices 2006 Term Price 2006 Price
----------------- ------------ ---------- --------- ------------ ----------
(years)
$ 3.25 to $ 8.00 1,191 2.0 $ 5.14 1,033 $ 4.89
$ 8.01 to $12.00 930 3.1 $ 9.33 435 $ 8.94
$ 12.01 to $16.00 2,085 3.9 $ 13.31 552 $ 12.93
$ 16.01 to $20.00 270 4.6 $ 19.43 - -
$ 20.01 to $24.05 1,837 4.8 $ 22.10 - -
----------------------------------------------------------------------------
$ 3.25 to $24.05 6,313 3.7 $ 14.00 2,020 $ 7.96
----------------------------------------------------------------------------
----------------------------------------------------------------------------


9. Net Income Per Unit

The Trust applies the treasury stock method to asses the dilutive effect of outstanding trust unit rights on net income per unit. The weighted average exchangeable shares outstanding during the year, converted at the year-end exchange ratio, and the trust units issuable on conversion of convertible debentures, have also been included in the calculation of the diluted weighted average number of trust units outstanding:



2006
Net income
per
Net income Trust units trust unit
------------- ------------- ------------
Net income per basic unit $ 147,069 72,947 $ 2.02
Dilutive effect of trust unit rights - 2,592
Conversion of convertible debentures 1,647 2,515
Exchange of exchangeable shares 4,585 2,384
------------- ------------
Net income per diluted unit $ 153,301 80,438 $ 1.91
------------- ------------
------------- ------------

2005
Net income
per
Net income Trust units trust unit
------------- ------------- ------------
Net income per basic unit $ 79,876 67,382 $ 1.19
Dilutive effect of trust unit rights - 1,438
Conversion of convertible debentures 3,168 2,981
Exchange of exchangeable shares 1,849 2,330
------------- ------------
Net income per diluted unit $ 84,893 74,131 $ 1.15
------------- ------------
------------- ------------


The dilutive effect of trust unit incentive rights above did not include 2.1 million trust unit rights (2005 - 3.9 million) because the respective proceeds of exercise plus the amount of compensation expense attributed to future services not yet recognized exceeded the average market price of the trust units during the year.



10. Income Taxes (Recovery)

The provision for (recovery of) income taxes has been computed as follows:

2006 2005
----------- ----------

Income before income taxes and non-controlling
interest $ 118,899 $ 83,398
Expected income taxes at the statutory rate of 37.00%
(2005 - 40.10%) $ 43,992 $ 33,443
Increase (decrease) in taxes resulting from:
Resource allowance (11,236) (13,650)
Alberta royalty tax credit (110) (130)
Net income of the Trust (56,261) (29,415)
Non-taxable portion of foreign exchange gain (20) (1,360)
Effect of change in tax rate (26,175) 2,734
Effect of change in opening tax pool balances 3,451 851
Effect of change in valuation allowance 1,597 (1,400)
Unit based compensation 2,760 2,143
Other 833 (290)
Current taxes 8,414 8,747
----------------------
Provision for (recovery of) income taxes $ (32,755) $ 1,673
----------- ----------
----------- ----------


On October 31, 2006, the Federal Government announced its intention to tax the distributions of income trusts beginning in 2011 at the corporate tax rates. If this legislation is enacted there could potentially be additional future income taxes to be recorded by the Trust. At this time, an estimate of the financial effect of the announcement is not determinable.



11. Interest Expense

The Trust incurred interest expense on its outstanding debt as follows:

Three Months Ended Year Ended
December 31 December 31
------------------ -------------------
2006 2005 2006 2005
------------------ -------------------
Bank loan and miscellaneous financing $ 2,479 $ 2,514 $ 9,263 $ 8,318
Amortization of deferred charge 304 458 1,267 1,492
Long-term debt 5,967 6,768 24,430 23,314
------------------ -------------------
Total interest $ 8,750 $ 9,740 $ 34,960 $ 33,124
------------------ -------------------
------------------ -------------------

12. Supplemental Cash Flow Information

Three Months Ended Year Ended
December 31 December 31
------------------ -------------------
2006 2005 2006 2005
------------------ -------------------
Interest paid $ 2,902 $ 5,841 $ 32,373 $ 29,728
Income taxes paid $ 1,973 $ 1,593 $ 7,636 $ 8,536

13. Financial Derivative Contracts

At December 31, 2006, the Trust had the following derivative contracts:

OIL
---------------------------------------------------------------
Period Volume Price Index
---------------------------------------------------------------
Price collar Calendar 2007 2,000 bbl/d US$55.00 - $83.60 WTI
Price collar Calendar 2007 3,000 bbl/d US$55.00 - $83.75 WTI
Price collar Calendar 2007 2,000 bbl/d US$60.00 - $80.40 WTI
Price collar Calendar 2007 1,000 bbl/d US$60.00 - $80.60 WTI

FOREIGN CURRENCY
---------------------------------------------------------------------
Period Amount Floor Cap
---------------------------------------------------------------------
Collar Calendar 2007 US$5,000,000 per month CAD/US$1.0835 CAD/US$1.1600

INTEREST RATE
----------------------------------------------------------------------
Period Principal Rate
----------------------------------------------------------------------
Swap November 2003 to July 2010 US$179,699,000 3-month LIBOR plus 5.2%


Under the CICA guideline for hedge accounting, the Trust's financial derivative contracts for oil and foreign currency do not qualify as effective accounting hedges. Accordingly, these contracts have been accounted for based on the fair value method.

14. COMMITMENTS AND CONTINGENCIES

In October 2002, the Trust entered into a long-term crude oil supply contract with a third party that requires the delivery of up to 20,000 barrels per day of Lloydminster Blend crude oil at a price fixed at 71% of NYMEX WTI oil price settled on a monthly basis. The contract is for an initial term of five years commencing January 1, 2003.

At December 31, 2006, the Trust added the following natural gas physical sales contracts:



GAS
---------------------------------------------------------------
Period Volume Price
---------------------------------------------------------------
Price collar November 1, 2006 to March 31, 2007 5,000 GJ/d $ 8.00 - $9.45
Price collar November 1, 2006 to March 31, 2007 5,000 GJ/d $ 8.00 - $9.50
Price collar November 1, 2006 to March 31, 2007 5,000 GJ/d $ 8.00 - $10.15
Price collar April 1, 2007 to October 31, 2007 5,000 GJ/d $ 6.65 - $9.15
Price collar April 1, 2007 to October 31, 2007 5,000 GJ/d $ 6.65 - $9.30

Subsequent to December 31, 2006, the Trust added the following natural gas
physical sales contracts:

---------------------------------------------------------------
Period Volume Price
---------------------------------------------------------------
Price collar April 1, 2007 to October 31, 2007 2,500 GJ/d $ 6.65 - $8.25
Price collar April 1, 2007 to October 31, 2007 2,000 GJ/d $ 6.65 - $8.30
Price collar April 1, 2007 to October 31, 2007 2,500 GJ/d $ 6.65 - $8.73

At December 31, 2006, the Trust had operating lease and transportation
obligations as summarized below:

OPERATING LEASES AND TRANSPORTATION AGREEMENTS

Payments Due
------------------------------------------------------
Total 1 year 2 years 3 years 4 years 5 years
--------- -------- --------- --------- ------- -------
Operating leases $ 6,891 $ 1,761 $ 2,199 $ 2,199 $ 732 $ -
Transportation
agreements 3,177 2,015 926 204 26 6
--------- -------- --------- --------- ------- -------
Total $ 10,068 $ 3,776 $ 3,125 $ 2,403 $ 758 $ 6
--------- -------- --------- --------- ------- -------
--------- -------- --------- --------- ------- -------


OTHER

At December 31, 2006, there were outstanding letters of credit aggregating $7.3 million (2005 - $7.1 million) issued as security for performance under certain contracts.

The Company has future contractual processing obligations with respect to assets acquired in the Stoddart area. The fair value of $7.8 million of the original obligation is being drawn down over the life of the obligations which continue until October 2008.

In connection with a purchase of properties, Baytex became liable for contingent consideration whereby an additional amount would be payable by Baytex if the price for crude oil exceeds a base price in each of the succeeding six years. As at December 31, 2006, an additional $0.5 million was paid for year one's obligations under the agreement and has been recorded as an adjustment to the original purchase price of the properties. It is currently not determinable if further payments will be required under this agreement, therefore no accrual has been made.

The Trust is engaged in litigation and claims arising in the normal course of operations, none of which could reasonably be expected to materially affect the Trust's financial position or reported results of operations.

Contact Information

  • Baytex Energy Trust
    Ray Chan
    President & Chief Executive Officer
    (403) 267-0715
    or
    Baytex Energy Trust
    Derek Aylesworth
    Chief Financial Officer
    (403) 538-3639
    or
    Baytex Energy Trust
    Erin Hurst
    Investor Relations Representative
    (403) 538-3681 or Toll Free Number: 1-800-524-5521
    Website: www.baytex.ab.ca