Baytex Energy Trust

Baytex Energy Trust

March 08, 2005 09:00 ET

Baytex Energy Trust Announces Fiscal 2004 Results


NEWS RELEASE TRANSMITTED BY CCNMatthews

FOR: BAYTEX ENERGY TRUST

TSX SYMBOL: BTE.UN

MARCH 8, 2005 - 09:00 ET

Baytex Energy Trust Announces Fiscal 2004 Results

CALGARY, ALBERTA--(CCNMatthews - March 8, 2005) - Baytex Energy Trust
(TSX:BTE.UN) of Calgary, Alberta is pleased to report its operating and
financial results for the three months and year ended December 31, 2004.
The Trust commenced operations on September 2, 2003 as a result of the
reorganization of Baytex Energy Ltd. As the Trust is considered the
successor organization to Baytex Energy Ltd. for reporting purposes,
comparative information is provided for the three months and year ended
December 31, 2003. Pursuant to the Plan of Arrangement effecting the
reorganization, certain assets were not transferred to the Trust.
Accordingly, results of the corresponding periods in 2003 and 2004 are
not directly comparable.

2004 Highlights

- Completed two acquisitions of natural gas and light oil assets for a
total of $200 million, adding 6,300 boe/d of gas weighted production at
an average cost of $31,750 per boe/d.

- Increased total reserves to 120 million boe at a finding and
development cost of $10.70 per boe.

- Replaced production by 210%.

- Improved reserve life index to 9.1 years.

- Enhanced net asset value by 11% to $9.84 per unit.

- Commenced production from Seal, an impact area with long-term large
resource potential.

- Expanded internal development opportunities to ensure sustainability.



------------------------------------------------------------------------
Three Months Ended Year Ended
------------------------------------------------------------------------
December September December December December
FINANCIAL 31, 2004 30, 2004 31, 2003 31, 2004 31, 2003
------------------------------------------------------------------------
($ thousands, except per unit amounts)
Petroleum and
natural gas sales 111,521 108,216 89,526 420,400 403,022
Cash flow from
operations (1) 28,114 32,235 30,179 136,012 138,233
Per unit - basic 0.44 0.51 0.51 2.17 2.56
- diluted 0.42 0.49 0.51 2.07 2.49
Cash distributions
paid/declared 28,856 28,266 25,344 113,063 33,382
Per unit 0.45 0.45 0.45 1.80 0.60
Net income
(loss) (2) 42,108 (12,554) 8,490 13,763 35,844
Per unit
- basic(2) 0.66 (0.20) 0.14 0.22 0.66
- diluted (2) 0.65 (0.20) 0.14 0.21 0.62

Exploration and
development 29,023 20,686 22,129 94,483 179,232
Acquisitions - net
of dispositions 75,423 110,316 193 186,183 (130,849)
Total capital
expenditures 104,446 131,002 22,322 280,666 48,383

Long-term notes 216,583 232,562
Bank loan 161,444 -
Working capital
deficiency
(surplus) 44,017 (18,990)
Total net debt 422,044 213,572



Three Months Ended Year Ended
------------------------------------------------------------------------
December September December December December
31, 2004 30, 2004 31, 2003 31, 2004 31, 2003
------------------------------------------------------------------------
OPERATING
Daily production
Light oil (bbls/d) 2,786 1,890 1,982 2,172 2,273
Heavy oil (bbls/d) 22,490 22,083 24,400 22,703 23,911
Total oil (bbls/d) 25,276 23,973 26,382 24,875 26,184
Natural gas (mmcf/d) 55.5 50.9 58.9 54.9 63.0
Oil equivalent
(boe/d @ 6:1) 34,525 32,454 36,195 34,022 36,686
Average prices
(before hedging)
WTI oil (US$/bbl) 48.28 43.88 31.18 41.40 31.04
Edmonton par oil
($/bbl) 57.72 56.32 39.56 52.55 43.14
BTE light oil
($/bbl) 50.46 52.63 37.46 48.64 40.01
BTE heavy oil
($/bbl) 31.24 34.69 24.01 30.32 26.68
BTE total oil
($/bbl) 33.35 36.11 25.04 31.91 27.86
BTE natural gas
($/mcf) 6.60 6.16 5.56 6.46 6.23
BTE oil equivalent
($/boe) 35.03 36.34 27.34 33.75 30.64

TRUST UNIT
INFORMATION
Unit Price
High $ 14.00 $ 13.13 $ 10.89 $ 14.00 $ 10.89
Low $ 12.60 $ 11.65 $ 9.49 $ 9.78 $ 9.19
Close $ 12.77 $ 12.88 $ 10.85 $ 12.77 $ 10.85

Units Traded
(thousands) 22,796 13,696 30,983 93,253 40,976
Units Outstanding
(thousands)(3) 68,817 65,044 64,714 68,817 64,714
Foreign Ownership 31% 35%

(1) Cash flow from operations and cash flow from operations per unit are
non-GAAP terms that represent 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) Net income and net income per unit is after non-controlling interest
related to exchangeable shares. The net income and net income per
unit for prior periods have been restated due to the retroactive
application of the new accounting standards for non-controlling
interest (see note 3 of the consolidated financial statements).

(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.


Financial Review

Baytex's cash flow from operations in 2004 was negatively affected by
its crude oil hedging program during the year. This program was
established in the summer of 2003 with the objective of protecting cash
flow in the event of a significant decline in crude oil prices.
Management determined that as Baytex embarked on its first year of
operations as an income trust, its top priority would be to protect cash
flow for distribution purposes. In total, 15,000 bbl/d for the year was
contracted with an average cap price of US$29.75. Rapidly increasing
demand for crude oil from China and other developing countries in Asia,
combined with the volatile geopolitical situation in the Middle East,
caused oil prices to surge throughout 2004 to unprecedented levels. WTI
crude averaged US$41.40 during the year, exceeding the previous high of
US$37.37 set in 1980. This unforeseen strength resulted in oil hedging
losses of $82.4 million during the year for Baytex, representing 38% of
cash flow before hedging activities.

Continuing appreciation of the Canadian currency also negatively
affected cash flow in 2004. The Canadian dollar began the year at
US$0.7737 and ended the year at US$0.8308. From the beginning of 2003 to
the end of 2004, the Canadian dollar had appreciated an astonishing 31%.
While the associated effect on oil and gas cash flow is very
significant, the impact on Baytex is partially offset because all of
Baytex's long-term debt is denominated in U.S. dollars. Baytex's foreign
exchange hedging program further mitigated the impact of the Canadian
dollar's appreciation. During 2004, Baytex realized a gain of $4.3
million from its foreign exchange hedging contracts.

Baytex has maintained its monthly distribution at $0.15 per unit since
its conversion to an income trust in September 2003. Total distributions
in 2004 amounted to $113.1 million, representing a payout ratio of 83%.
This high payout ratio is due to the hedging losses incurred,
particularly in the fourth quarter when such losses were $27.6 million
and the payout ratio reached 103%. Excluding hedging losses, the payout
ratio in the fourth quarter would have been 52%. With the expiry of the
2004 hedging contracts, Baytex is projecting a significant improvement
in cash flow. Under the 2005 hedging program, 8,000 bbl/d have been
collared between WTI US$35.00 and US$42.55, and US$9.0 million per month
have been collared between the average exchange rates of 0.8000 and
0.8218. These contracts will provide substantial downside protection to
Baytex's cash flow while allowing for participation in the benefits of
current commodity prices. Baytex plans to maintain its monthly
distributions at $0.15 per unit in 2005 barring a significant decline in
commodity prices. The lower payout ratio in 2005 should bring the
cumulative payout ratio to the Trust's target range of 60% to 70%.

At year-end 2004, total net debt outstanding was $412.5 million,
excluding the $9.5 million notional liabilities associated with the
mark-to-market value of derivative contracts. The majority of the debt
was represented by US$180 million of unsecured senior subordinated notes
due in 2010. The 9.625% coupon on these notes has been swapped for LIBOR
based floating rates which equated to 7.85% at year-end. These notes
provide a cost efficient alternative for capital and a natural hedge on
foreign exchange exposure for the Trust's U.S. dollar based revenue. The
financial versatility of the Trust is also enhanced as Baytex has
established its credibility as an issuer in the deep and sophisticated
U.S. high yield bond market. Total senior secured revolving bank debt
outstanding at year-end 2004 was $161.4 million and should represent
less than one time 2005 projected cash flow. Baytex does not plan to
draw on its bank facilities to fund its 2005 budgeted capital programs
and cash distributions.

Operations Review

During the fourth quarter, Baytex participated in the drilling of 32
(30.1 net) wells, resulting in 25 (24.5 net) oil wells, five (3.6 net)
gas wells and two (2.0 net) dry holes. For 2004, Baytex participated in
the drilling of 138 (135.0 net) wells, resulting in 104 (103.1 net) oil
wells, 16 (14.4 net) gas wells, seven (6.5 net) service wells and 11
(11.0 net) dry holes. The overall success rate for the year was 93.8%
(93.3% net). Baytex's 2004 drilling activities placed it as the most
active operator amongst energy trusts in Saskatchewan and seventh most
active operator amongst energy trusts in Alberta, evidencing the
business strategy and the internal development opportunities of the
Trust. In addition, 29 wells were drilled by other operators through
farm-in arrangements on Baytex lands during the year with Baytex
retaining various working or royalty interests.

Production for the fourth quarter averaged 34,525 boe/d compared to
32,454 boe/d for the previous quarter. The increase is primarily due to
the acquisition of an Alberta based private company in September 2004.
In November, Baytex disposed of 370 boe/d of non-core medium gravity oil
production in central Alberta for $14 million. In late December, Baytex
completed the acquisition of 3,300 boe/d of natural gas and associated
liquids production in the West Stoddart area of northeast British
Columbia for $90 million. These two recent acquisitions significantly
expand Baytex's natural gas and light oil development inventory.

In the Seal area of Alberta, Baytex completed the drilling of its first
two horizontal wells in early January 2005. These wells are producing at
an average rate of approximately 200 bbl/d per well. Baytex is currently
drilling six non-producing vertical test wells to delineate this
20-section producing land block. In addition, four horizontal producing
wells are being drilled and are expected to be on production by the end
of the first quarter. Industry results in this area show that each
prospective section of land could hold 2.5 million barrels of
recoverable reserves with aggregate initial production of 2,000 bbl/d.
The Trust's reserves report at year-end 2004 only includes 1.1 million
barrels of proved reserves (1.5 million barrels of proved plus probable
reserves) assigned to five wells at Seal. Baytex holds 100% working
interests in approximately 100 sections of land in this area. Baytex is
very encouraged by the large resource potential in this area for heavy
oil development.

Capital Program Efficiency

Baytex's capital program for 2004 totaled $280 million, including $200
million spent on acquisitions of natural gas and light oil assets, $14
million of proceeds on the disposition of a medium gravity oil property
and $94 million for exploration and development. Spending on exploration
and development was scaled back from the original budget of $105 million
due to the acquisition activities.

Under National Instrument ("NI") 51-101, finding, development and
acquisition ("FD&A") costs are to be presented including the changes in
future development capital ("FDC") required to bring the proved
non-producing and probable reserves to production. FDC is estimated by
the independent evaluators based on prevailing industry conditions as at
the report date. It is indexed to inflation and applied to the FD&A
calculation on an undiscounted basis. The aggregate of the exploration
and development costs incurred in the most recent financial year and the
change during that year in estimated FDC generally will not reflect
total finding and development costs related to reserves additions for
that year. Furthermore, there is no provision for additional reserves
that could be recognized based on the results of spending the FDC. This
is particularly important in the case of heavy oil development, as NI
51-101 restricts the recognition of proved undeveloped and probable
reserves to an adjacent spacing-unit basis. Success in step-out drilling
could lead to the recognition of additional proved undeveloped and
probable reserves. As a result, the inclusion of FDC may not fairly
represent the efficiency of Baytex's current year capital program.
Therefore, FD&A costs are presented herein both on an including FDC and
excluding FDC basis.

Baytex is very pleased with its capital efficiency in 2004. FD&A costs
for the year averaged $10.70 per boe of proved plus probable reserves,
with approximately 77% of the total capital program spent on natural gas
and light oil activities. Similarly, recycle ratio based on cash flow
(excluding one-time hedging losses) and FD&A costs was a profitable 1.5,
particularly acceptable considering 57% of cash flow was related to
lower netback heavy oil production and 77% of the capital spending was
related to higher cost natural gas and light oil activities.



The efficiency of Baytex's 2004 capital program is summarized as
follows:

Proved +
Proved Probable
Reserves Reserves
----------------------------
FD&A Costs (excluding FDC) ($/boe)
Exploration and Development 12.61 9.58
Acquisition (net of disposal) 14.40 11.37
----------------------------
Total 13.75 10.70

FD&A Costs (including FDC) ($/boe)
Exploration and Development 14.98 12.19
Acquisition (net of disposal) 15.91 12.62
----------------------------
Total 15.58 12.46

Recycle Ratio (excluding FDC)
Including Hedging Losses 0.7 1.0
Excluding Hedging Losses 1.2 1.5

Reserves Replacement Ratio 164% 210%


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 based on forecast prices as evaluated by independent
evaluators. It does not take into account the possibility of Baytex
being able to recognize additional reserves in its existing properties
beyond those included in the 2004 year-end report.



Discounted @ 5% Discounted @10%
-----------------------------------
Proved plus probable reserves (1) $ 1,196,800,000 $ 1,019,300,000
Undeveloped land (2) 70,224,000 70,224,000
Net debt (3) (412,531,000) (412,531,000)
-----------------------------------
Net asset value $ 854,493,000 $ 676,993,000
-----------------------------------

Total trust units outstanding (4) 68,817,072 68,817,072

Net asset value per trust unit $ 12.42 $ 9.84

Notes:

(1) As evaluated by Sproule Associates Limited as at December 31, 2004.
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, 2004 on 817,000 net acres
of undeveloped land.
(3) Long-term debt net of working capital as at December 31, 2004,
excluding $9.5 million of notional liabilities associated with the
mark-to-market value of derivative contracts.
(4) Includes 66,538,252 trust units outstanding as at December 31, 2004
and 1,876,004 exchangeable shares converted at an exchange ratio of
1.21472.


Oil and Gas Reserves

Baytex announced certain of its year-end 2004 reserves information on
February 10, 2005. Following is the Trust's additional summary
information with regard to oil and gas reserves as at December 31, 2004.
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
---------------------------------------------
Proved +
Factors Proved (1) Probable (1) Probable (1)
---------------------------------------------
(Mbbl) (Mbbl) (Mbbl)

December 31, 2003 5,159 1,649 6,808
Extensions - - -
Improved Recovery 23 62 85
Technical Revisions 121 4 125
Acquisitions 2,538 777 3,315
Dispositions (739) (135) (874)
Economic Factors 38 74 112
Production (754) - (754)
---------------------------------------------
December 31, 2004 6,386 2,431 8,817
---------------------------------------------
---------------------------------------------


Heavy Oil
---------------------------------------------
Proved +
Factors Proved (1) Probable (1) Probable (1)
---------------------------------------------
(Mbbl) (Mbbl) (Mbbl)

December 31, 2003 57,568 23,606 81,174
Extensions 5,118 1,478 6,596
Improved Recovery 2,879 785 3,664
Technical Revisions (477) (661) (1,138)
Acquisitions 11 4 15
Dispositions - - -
Economic Factors (915) (324) (1,239)
Production (8,309) - (8,309)
---------------------------------------------
December 31, 2004 55,875 24,888 80,763
---------------------------------------------
---------------------------------------------



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

December 31, 2003 260 95 355
Extensions - - -
Improved Recovery - - -
Technical Revisions 14 (3) 11
Acquisitions 3,449 492 3,941
Dispositions - - -
Economic Factors (10) 7 (3)
Production (41) - (41)
---------------------------------------------
December 31, 2004 3,672 591 4,263
---------------------------------------------
---------------------------------------------



Natural Gas
---------------------------------------------
Proved +
Factors Proved (1) Probable (1) Probable (1)
---------------------------------------------
(Mmcf) (Mmcf) (Mmcf)

December 31, 2003 81,175 24,641 105,816
Extensions 3,884 2,558 6,442
Improved Recovery 541 20 561
Technical Revisions 1,663 3,972 5,635
Acquisitions 46,061 13,899 59,960
Dispositions (130) (85) (215)
Economic Factors (2,108) (904) (3,012)
Production (20,087) - (20,087)
---------------------------------------------
December 31, 2004 110,999 44,101 155,100
---------------------------------------------
---------------------------------------------


Oil Equivalent (2)
---------------------------------------------
Proved +
Factors Proved (1) Probable (1) Probable (1)
---------------------------------------------
(MBoe) (MBoe) (MBoe)

December 31, 2003 76,510 29,457 105,967
Extensions 5,766 1,904 7,670
Improved Recovery 2,993 850 3,843
Technical Revisions (64) 1 (63)
Acquisitions 13,674 3,590 17,264
Dispositions (760) (149) (909)
Economic Factors (1,239) (395) (1,634)
Production (12,452) - (12,452)
---------------------------------------------
December 31, 2004 84,428 35,258 119,686
---------------------------------------------
---------------------------------------------

Notes:
(1) Reserves information as at December 31, 2003 and 2004 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.


Reserves Life Index

Reserves Life Index (RLI)
2005 ------------------------------------
Production Proved
Target Total Proved Plus Probable
---------------------------------------------
Crude Oil (bbl/d) 26,000 7.0 9.9
Natural Gas (mmcf/d) 60.0 5.1 7.1
Oil Equivalent (boe/d) 36,000 6.4 9.1


Management's Discussion and Analysis

Baytex Energy Trust (the "Trust ") was established on September 2, 2003
under a Plan of Arrangement involving the Trust, Baytex Energy Ltd. (the
"Company") and Crew Energy Inc. ("Crew"). 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.

Prior to the Plan of Arrangement, the consolidated financial statements
included the accounts of the Company and its subsidiaries and
partnership. After giving effect to the Plan of Arrangement, the
consolidated financial statements have been prepared on a continuity of
interests basis which recognizes the Trust as the successor to the
Company.

Management's discussion and analysis ("MD&A"), dated March 7, 2005,
should be read in conjunction with the unaudited interim consolidated
financial statements for the three months and the year ended December
31, 2004 and the MD&A and the audited consolidated financial statements
for the year ended December 31, 2003. 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 and cash flow from operations per unit are not
measures based on generally accepted accounting principles ("GAAP"), but
are financial terms commonly used in the oil and gas industry. They
represent 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
performance measure as it demonstrates the ability of the Trust to
generate the cash flow necessary to fund future distributions and
capital investments.

The Trust also uses certain key performance measures and industry
benchmarks such as operating netbacks ("netbacks"), finding, development
and acquisition costs ("FD&A"), recycle ratio and payout ratio to
analyze financial and operating performance. These key performance
measures and benchmarks as presented do not have any standardized
meaning prescribed by Canadian GAAP and therefore may not be comparable
with the calculation of similar measures for other entities.

On September 22, 2004, the Company acquired all of the issued and
outstanding shares of a private oil and gas company with operations in
Alberta. The results of operations from the date of acquisition of the
private company have been included in the consolidated financial
statements. On December 22 2004, the Company acquired certain oil and
natural gas interests in the West Stoddart area of northeast British
Columbia. The consolidated financial statements include the results of
operations from these properties from the acquisition date.

Production. Light oil production for the fourth quarter of 2004
increased by 41% to 2,786 bbl/d from 1,982 bbl/d a year earlier
primarily due to the acquisition in September 2004. Heavy oil production
decreased 8% to 22,490 bbl/d for the fourth quarter of 2004 compared to
24,400 bbl/d a year ago. Natural gas production decreased by 6% to 55.5
mmcf/d for the fourth quarter of 2004 compared to 58.9 mmcf/d for the
same period last year. These decreases are primarily due to a lower
exploration and development program in 2004 following conversion to the
trust structure.

For the year ended December 31, 2004, light oil production decreased by
4% to 2,172 bbl/d from 2,273 bbl/d last year. Heavy oil production for
2004 was down 5% to 22,703 bbl/d compared to 23,911 bbl/d for the same
period in 2003. Natural gas production decreased by 13% to average 54.9
mmcf/d for 2004 compared to 63.0 mmcf/d for 2003. Production for the
year is not directly comparable to the previous year due to asset
dispositions and transfer of assets pursuant to the Plan of Arrangement.

Revenue. Petroleum and natural gas sales increased 24% to $111.5 million
for the quarter ended December 31, 2004 from $89.5 million for the same
period in 2003. For the year, petroleum and natural gas sales increased
by 4% to $420.4 million in 2004 from $403.0 million a year earlier.

For the per sales unit calculations, heavy oil sales for the three
months ended December 31, 2004 were 63 bbl/d higher (three months ended
December 31, 2003 - 606 bbl/d lower) than the production for the period
due to inventory in transit under the Frontier supply agreement. The
corresponding number for the year ended December 31, 2004 was an
increase of 5 bbl/d (year ended December 31, 2003 - decrease of 650
bbl/d).



Three Months ended December 31
------------------------------------------
2004 2003
------------------------------------------
$000s $/Unit(1) $000s $/Unit(1)
------------------------------------------
Oil revenue (barrels)
Light oil 12,931 50.46 6,830 37.46
Heavy oil 64,881 31.24 52,559 24.01
Derivative contracts loss (27,570) (11.83) (6,918) (2.92)
------------------------------------------
Total oil revenue 50,242 21.55 52,471 22.13
------------------------------------------
Natural gas revenue (mcf) 33,709 6.60 30,137 5.56
------------------------------------------
Total revenue (boe @ 6:1) 83,951 26.38 82,608 25.23
------------------------------------------
------------------------------------------
(1) Per-unit oil revenue is in $/bbl; per-unit natural gas revenue is
in $/mcf.


Revenue from light oil for the fourth quarter of 2004 increased 89% from
the same period a year ago due to a 41% increase in production and a 35%
increase in wellhead prices. Revenue from heavy oil increased 23% as an
8% decrease in production was offset by a 30% increase in wellhead
prices. Revenue from natural gas increased 12% as the 19% increase in
wellhead prices was offset by a 6% decrease in production.



Year Ended December 31
------------------------------------------
2004 2003
------------------------------------------
$000s $/Unit(1) $000s $/Unit(1)
------------------------------------------
Oil revenue (barrels)
Light oil 38,673 48.64 33,197 40.01
Heavy oil 252,016 30.32 226,482 26.68
Derivative contracts loss (78,124) (8.58) (33,777) (3.62)
------------------------------------------
Total oil revenue 212,565 23.34 225,902 24.24
------------------------------------------
Natural gas revenue (mcf) 129,711 6.46 143,343 6.23
------------------------------------------
Total revenue (boe @ 6:1) 342,276 27.48 369,245 28.07
------------------------------------------
------------------------------------------

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


For the year ended December 31, 2004, light oil revenue increased 16%
from the same period last year due to a 22% increase in wellhead prices
and a 4% decrease in production. Revenue from heavy oil increased 11%
due to a 14% increase in wellhead prices and a 5% decrease in
production. Revenue from natural gas decreased 10% as production
decreased 13% and wellhead prices increased 4% compared to 2003.

Royalties. Total royalties increased to $17.4 million for the fourth
quarter of 2004 from $13.5 million in 2003. Total royalties for the
fourth quarter of 2004 were 15.6% of sales compared to 15.1% of sales
for the same period in 2003. For the fourth quarter of 2004, royalties
were 15.9% of sales for light oil, 13.5% for heavy oil and 19.5% for
natural gas. These rates compared to 14.5%, 11.2% and 21.9%,
respectively, for the same period last year.

For the year ended December 31, 2004, royalties decreased to $66.0
million from $67.2 million for the same period last year. Total
royalties for 2004 were 15.7% of sales, a decrease from 16.7% of sales
for 2003. For 2004, royalties were 14.1% of sales for light oil, 13.3%
for heavy oil and 20.9% for natural gas. These rates compared to 17.4%,
13.0% and 22.3%, respectively, for 2003.

Operating Expenses. Operating expenses for the fourth quarter of 2004
increased to $24.3 million from $22.1 million in the corresponding
quarter last year. Operating expenses were $7.63 per boe for the fourth
quarter of 2004 compared to $6.74 per boe for the fourth quarter of
2003. For the fourth quarter of 2004, operating expenses were $8.57 per
barrel of light oil, $8.61 per barrel of heavy oil and $0.83 per mcf of
natural gas. The operating expenses 2003 were $10.43, $7.44 and $0.72,
respectively.

Operating expenses for the year 2004 increased to $89.1 million from
$86.0 million in 2003. Operating expenses were $7.15 per boe in 2004
compared to $6.54 per boe for the prior year. In 2004, operating
expenses were $9.51 per barrel of light oil, $7.83 per barrel of heavy
oil and $0.82 per mcf of natural gas versus $8.32, $7.34 and $0.73,
respectively, for 2003. Increases in per boe operating expenses are due
to lower production in 2004 combined with inflation in costs for
oilfield services during a period of record high industry activities.

Transportation Expenses. Transportation expenses for the fourth quarter
of 2004 were $4.6 million compared to $4.7 million for the fourth
quarter of 2003. These expenses were $1.43 per boe for the fourth
quarter of 2004 compared to $1.45 for the same period in 2003.
Transportation expenses were $1.58 per barrel of oil and $0.17 per mcf
of natural gas. The corresponding amounts for 2003 were $1.57 and $0.19,
respectively.

Transportation expenses for the year ended December 31, 2004 were $18.7
million compared to $17.8 million for 2003. These expenses were $1.50
per boe in 2004 compared to $1.36 in 2003. Transportation expenses were
$1.66 per barrel of oil and $0.18 per mcf of natural gas in 2004, and
$1.50 per barrel of oil and $0.17 per mcf of natural gas in 2003.

General and Administrative Expenses. General and administrative expenses
increased to $4.1 million in the fourth quarter of 2004 from $3.6
million one year ago. On a per sales unit basis, these expenses were
$1.28 per boe for the fourth quarter of 2004 compared to $1.21 per boe
for 2003. In accordance with our full cost accounting policy, no
expenses were capitalized in either the fourth quarter of 2003 or 2004.

General and administrative expenses for the year were $15.2 million in
2004 compared to $8.9 million for the prior year. On a per sales unit
basis, these expenses were $1.22 per boe in 2004 and $0.71 per boe in
2003. In accordance with our full cost accounting policy, $4.4 million
of expenses were capitalized in 2003, while no expenses have been
capitalized in 2004. The amount of capitalized expenses has been reduced
due to lower exploration activity since the effective date of the Plan
of Arrangement.

Unit-based Compensation Expense. Compensation expense related to the
Trust's unit rights incentive plan was $1.6 million for the fourth
quarter of 2004 compared to $0.2 million in the fourth quarter of 2003.

For the year ended December 31, 2004, compensation expense was $7.7
million compared to $0.7 million for 2003. Compensation expense on the
Trust's unit rights incentive plan has been determined based on the
amount that the market price of the trust unit exceeds the exercise
price for rights issued as at the date of the consolidated financial
statements. The compensation expense for 2003 also includes $0.5 million
based on the fair value of the stock options outstanding prior to the
Plan of Arrangement.

Interest Expenses. Interest expense increased to $6.4 million for the
fourth quarter of 2004 from $5.2 million for the same quarter last year.
The increase is due to interest incurred on amounts drawn on the Trust's
credit facilities in the fourth quarter of 2004.

In 2004, interest expense was $19.4 million for the year compared to
$23.5 million last year. The decrease in total interest expense is due
to the redemption of the Company's senior secured notes in May 2003 and
the stronger Canadian currency as interest on the long-term notes is
denominated in U.S. dollars.

Foreign Exchange. The foreign exchange gain in the fourth quarter of
2004 was $10.9 million compared to a gain of $10.4 million in the prior
year. The gain is based on the translation of the Company's U.S. dollar
denominated long-term debt at 0.8308 at December 31, 2004 compared to
0.7912 at September 30, 2004. The 2003 gain is based on translation at
0.7737 at December 31, 2003 compared to 0.7405 at September 30, 2003.

The foreign exchange gain for 2004 was $16.0 million compared to a gain
of $52.1 million in the prior year. The 2004 gain is based on the
translation of the Company's U.S. dollar denominated long-term debt at
0.8308 at December 31, 2004 compared to 0.7737 at December 31, 2003. The
2003 gain is based on translation at 0.7737 at December 31, 2003
compared to 0.6331 at December 31, 2002.

Depletion, Depreciation and Accretion. The provision for depletion,
depreciation and accretion was $41.5 million for the fourth quarter of
2004 compared to $42.6 million for the same quarter a year ago. On a
sales-unit basis, the provision for the current quarter was $13.04 per
boe compared to $12.79 per boe for the same quarter in 2003.

Depletion, depreciation and accretion increased to $160.8 million for
2004 compared to $123.1 million for last year. On a sales-unit basis,
the provision for the current year was $12.91 per boe compared to $9.36
per boe for a year earlier due to revisions in proved reserves under the
new standards of disclosure for oil and gas activities, NI 51-101.

Income Taxes. Current tax expenses were $1.9 million for the fourth
quarter of 2004 compared to $3.5 million for the same quarter a year
ago. The current tax expense is comprised of $1.6 million of
Saskatchewan Capital Tax and $0.3 million of Large Corporation Tax
compared to $2.7 million and $0.8 million, respectively, in the
corresponding period in 2003.

Current tax expenses were $9.0 million for 2004 compared to $9.7 million
for last year. The current tax expense is comprised of $7.0 million of
Saskatchewan Capital Tax and $2.0 million of Large Corporation Tax
compared to $8.0 million and $1.7 million, respectively, in 2003.

Net Income Net income for the fourth quarter of 2004 was $42.1 million
compared to $8.5 million for the fourth quarter of 2003. Net income for
the year ended December 31, 2004 was $13.8 million compared to $35.8
million for 2003. The increased petroleum and natural gas sales realized
through higher wellhead prices in 2004 were offset by increased charges
for depletion, depreciation and accretion, a lower foreign exchange gain
and a higher realized loss on financial derivatives.

Liquidity and Capital Resources. At December 31, 2004, total net debt
(including working capital) was $422.0 million compared to $213.6
million at December 31, 2003. The $422.0 million net debt included $9.5
million of notional liabilities based on the mark-to-market value of
derivative contracts as at December 31, 2004. At the end of December
2004, $161.4 million were outstanding under total bank credit facilities
of $250.0 million.

Capital Expenditures. Exploration and development expenditures decreased
to $94.5 million for 2004 compared to $179.2 million last year. The
lower capital expenditures reflect a different business plan since the
conversion to an income trust. For the year ended December 31, 2004, the
Trust participated in the drilling of 138 (135.0 net) wells, resulting
in 104 (103.1 net) oil wells, 16 (14.4 net) gas wells, seven (6.5 net)
stratigraphic test wells and 11 (11.0 net) dry holes compared to prior
year activities of 266 (243.4 net) wells, including 173 (158.9 net) oil
wells, 67 (61.4 net) gas wells, seven (5.1 net) service wells and 19
(18.0 net) dry holes. On September 22, 2004, the Company acquired all of
the issued and outstanding shares of a private oil and gas company with
operations in Alberta for $109 million plus adjustments. Effective
December 22, 2004, the Company acquired oil and natural gas interests in
the West Stoddart area of northeast British Columbia for $90 million
plus adjustments.



Year Ended December 31
--------------------------
($ thousands) 2004 2003
--------------------------
Land 8,744 14,138
Seismic 1,283 5,436
Drilling and completion 55,322 110,892
Equipment 25,982 42,365
Other 3,152 6,401
--------------------------
Total exploration and development 94,483 179,232
Corporate acquisition 111,042 -
Property acquisitions 89,582 6,644
Property dispositions (14,441) (137,493)
--------------------------
Total capital expenditures 280,666 48,383
--------------------------
--------------------------


ADDITIONAL INFORMATION

Additional information relating to the Trust, including the Annual
Information Form, may be found on SEDAR at www.sedar.com.

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 8, 2005 to discuss its
2004 year-end results. The conference call will be hosted by Raymond
Chan, President and Chief Executive Officer and Dan Belot,
Vice-President, Finance and Chief Financial Officer. Interested parties
are invited to participate by calling toll-free across North America at
1-888-793-1753. A recorded playback of the call will be available from
March 8 until March 22, 2005 at 1-800-558-5253 or 416-626-4100 within
the Toronto area, entering the reservation number 21230684. 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, capital programs, 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 reserve 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.

The consolidated financial statements for the periods ended December 31,
2004 and 2003 are attached.




Baytex Energy Trust
Consolidated Balance Sheets
(thousands) (Unaudited)

December 31, 2004 December 31, 2003
-------------------------------------
(restated -note 3)

Assets
Current assets
Cash and short-term investments $ - $ 53,731
Accounts receivable 41,154 48,608
Crude oil inventory 7,299 5,900
-------------------------------------
48,453 108,239

Deferred charges and other assets 6,491 7,764
Petroleum and natural gas properties 1,009,933 866,637
Goodwill (note 4) 39,259 -
-------------------------------------
$ 1,104,136 $ 982,640
-------------------------------------
-------------------------------------

Liabilities
Current liabilities
Accounts payable and
accrued liabilities $ 72,976 $ 80,126
Distributions payable to unitholders 9,981 9,123
Bank loan 161,444 -
Financial derivative contracts
(note 11) 9,513 -
-------------------------------------
253,914 89,249

Long-term debt (note 5) 216,583 232,562
Asset retirement obligations (note 6) 73,297 55,996
Future income taxes 164,909 170,952
-------------------------------------
708,703 548,759

Non-controlling interest
(notes 3 and 9) 12,962 25,705

Unitholders' Equity
Unitholders' capital (note 8) 515,728 449,403
Contributed surplus 7,494 224
Accumulated distributions (146,445) (33,382)
Accumulated income (deficit) 5,694 (8,069)
-------------------------------------
382,471 408,176
-------------------------------------
$ 1,104,136 $ 982,640
-------------------------------------
-------------------------------------

See accompanying notes to the consolidated financial statements.


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

Three Months Ended Year Ended
December 31 December 31
2004 2003 2004 2003
--------------------------------------------
(restated (restated
Revenue -note 3) -note 3)
Petroleum and natural
gas sales $ 111,521 $ 89,526 $ 420,400 $ 403,022
Royalties (17,392) (13,498) (65,988) (67,175)
Realized loss on
financial derivatives (27,570) (6,918) (78,124) (33,777)
Unrealized gain on
financial derivatives 40,585 - 597 -
--------------------------------------------
107,144 69,110 276,885 302,070
--------------------------------------------
Expenses
Operating 24,293 22,066 89,078 86,034
Transportation (note 3) 4,550 4,739 18,714 17,841
General and administrative 4,069 3,570 15,243 8,927
Unit-based compensation
(note 10) 1,587 224 7,736 739
Interest (note 5) 6,448 5,173 19,412 23,548
Costs on redemption
of notes - - - 44,771
Foreign exchange gain (10,851) (10,437) (15,979) (52,101)
Depletion, depreciation
and accretion 41,517 42,580 160,808 123,137
Reorganization costs - 209 - 18,851
--------------------------------------------
71,613 68,124 295,012 271,747
--------------------------------------------

Income (loss) before
income taxes and
non-controlling interest 35,531 986 (18,127) 30,323
--------------------------------------------

Income taxes (recovery)
Current expense 1,850 3,450 9,000 9,663
Future recovery (note 7) (9,621) (11,473) (41,237) (14,516)
--------------------------------------------
(7,771) (8,023) (32,237) (4,853)
--------------------------------------------

Income before
non-controlling interest 43,302 9,009 14,110 35,176

Non-controlling interest
(notes 3 and 9) (1,194) (519) (347) 668
--------------------------------------------

Net income $ 42,108 $ 8,490 13,763 35,844
---------------------
---------------------

Accumulated deficit,
beginning of year, as
previously reported (351) (38,489)
Accounting policy change
for non-controlling
interest (note 3) 529 -
Accounting policy change
for asset retirement
obligations (note 3) (8,247) (5,424)
---------------------
Accumulated deficit,
beginning of year,
as restated (8,069) (43,913)
---------------------
Accumulated income
(deficit), end of year $ 5,694 $ (8,069)
---------------------
---------------------

Net income per trust unit
Basic $ 0.66 $ 0.14 $ 0.22 $ 0.66
Diluted $ 0.65 $ 0.14 $ 0.21 $ 0.62
Weighted average units
Basic 63,385 59,382 62,574 53,995
Diluted 66,344 59,644 65,682 56,520

See accompanying notes to the consolidated financial statements.




Baytex Energy Trust
Consolidated Statements of Cash Flows
(thousands) (Unaudited)
Three Months Ended Year Ended
December 31 December 31
2004 2003 2004 2003
--------------------------------------------
(restated (restated
Cash provided by (used in): -note 3) -note 3)

OPERATING ACTIVITIES
Net income $ 42,108 $ 8,490 $ 13,763 $ 35,844
Items not affecting cash:
Unit-based compensation
(note 8) 1,587 224 7,736 739
Amortization of
deferred charges 2,795 276 11,171 1,027
Costs on redemption
of notes (note 5) - - - 44,771
Unrealized foreign
exchange gain (10,851) (10,437) (15,979) (52,101)
Depletion, depreciation
and accretion 41,517 42,580 160,808 123,137
Unrealized gain on
financial derivatives
(note 10) (40,585) - (597) -
Future income tax recovery (9,621) (11,473) (41,237) (14,516)
Non-controlling interest
(notes 3 and 9) 1,194 519 347 (668)
--------------------------------------------
Cash flow from operations 28,144 30,179 136,012 138,233
Change in non-cash
working capital 5,342 (5,098) 3,589 (8,060)
Site restoration and
reclamation expenditures (1,189) (261) (2,739) (880)
Decrease in deferred
charges and other assets 53 53 212 211
Decrease in deferred credits - - - (2,213)
--------------------------------------------
32,350 24,873 137,074 127,291
--------------------------------------------

FINANCING ACTIVITIES
Redemption of senior
secured notes (note 5) - - - (89,950)
Increase in bank loan 47,601 - 161,444 -
Increase in deferred
charges and other assets - (39) - (7,425)
Payments of distributions (28,169) (24,259) (112,074) (24,259)
Issue of trust units 44,295 61,525 44,505 61,525
Issue of common shares - - - 37,049
--------------------------------------------
63,727 37,227 93,875 (23,060)
--------------------------------------------

INVESTING ACTIVITIES
Petroleum and natural gas
property expenditures (118,605) (22,540) (184,065) (185,876)
Corporate acquisition
(note 4) - - (111,042) -
Disposal of petroleum and
natural gas properties 14,159 218 14,441 137,493
Change in non-cash
working capital 6,586 (9,254) (4,014) (6,215)
--------------------------------------------
(97,860) (31,576) (284,680) (54,598)
--------------------------------------------

Change in cash and
short-term investments (1,783) 30,524 (53,731) 49,633

Cash and short-term
investments, beginning
of period 1,783 23,207 53,731 4,098
--------------------------------------------

Cash and short-term
investments, end
of period $ - $ 53,731 $ - $ 53,731
--------------------------------------------
--------------------------------------------

See accompanying notes to the consolidated financial statements.


Notes to the Consolidated Financial Statements (unaudited)
Three Months and Year Ended December 31, 2004 and 2003
(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, Baytex Energy Ltd. (the
"Company") and Crew Energy Inc. ("Crew"). 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.

Prior to the Plan of Arrangement, the consolidated financial statements
included the accounts of the Company and its subsidiaries and
partnership. After giving effect to the Plan of Arrangement, the
consolidated financial statements have been prepared on a continuity of
interests basis which recognizes the Trust as the successor to the
Company. 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, 2003,
except as described below and in note 3. 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, 2003.

Goodwill is the residual amount that results when the purchase price of
an acquired business exceeds the fair value of the net identifiable
assets and liabilities of the acquired business for accounting purposes.
Goodwill is stated at cost less impairment and is not amortized. The
goodwill balance is assessed for impairment annually at year-end or more
frequently if events or changes in circumstances indicate that the asset
may be impaired. The test for impairment is conducted by the comparison
of the net book value to the fair value of the reporting entity. If the
fair value of the Trust is less that the net book value, impairment is
deemed to have occurred. The extent of the impairment is measured by
allocating the fair value of the Trust to the identifiable assets and
liabilities at their fair values. Any remainder of this allocation is
the implied value of goodwill. Any excess of the net book value of
goodwill over this implied value is the impairment amount. Impairment is
charged to income in the period in which it occurs.

3. Changes in Accounting Policy

Unit-Based Compensation

At December 31, 2003, the Trust elected to adopt amendments to CICA
Handbook Section 3870, "Stock-based Compensation and Other Stock-based
Payments" pursuant to the transitional provisions contained therein. The
adoption of the amendments related to accounting for unit-based
compensation also impacted the accounting for stock options granted by
the Company to employees before the implementation of the Plan of
Arrangement. Previously reported amounts for 2003 have been restated to
give effect to the standard as at January 1, 2003. Compensation expense
of $0.52 million was recorded for the year ended December 31, 2003
(three months ended December 31, 2003 - nil) for all stock options
granted by the Company since January 1, 2003, with a corresponding
amount recorded as contributed surplus (see note 10).

Full Cost Accounting

In 2003, the CICA issued Accounting Guideline 16, Oil and Gas Accounting
- Full Cost (AcG-16). The guideline is effective for fiscal years
beginning on or after January 1, 2004. The new guideline modifies the
ceiling test calculation applied by the Trust. The ceiling test was
changed to a two-stage process which is to be performed at least
annually. The first stage of the test is a recognition test which
compares the undiscounted future cash flow from proved reserves plus the
cost less impairment of unproved properties to the net book value of the
petroleum and natural gas assets to determine if the assets are
impaired. An impairment loss exists when the carrying amount of the
petroleum and natural gas assets exceeds such undiscounted cash flow.
The second stage determines the amount of the impairment loss to be
recorded. The impairment is measured as the amount by which the net book
value of the petroleum and natural gas assets exceeds the future
discounted cash flow from proved plus probable reserves. The adoption of
this guideline on January 1, 2004 did not have an impact on the
financial results of the Trust. The ceiling test impairment test was
calculated on January 1, 2004 using the following benchmark reference
prices at January 1, 2004 for the years 2004 to 2008 adjusted for
commodity differentials specific to the Trust:



2004 2005 2006 2007 2008
----------------------------------------
WTI ($U.S./bbl) 29.63 26.80 25.76 26.14 26.53
AECO ($Cdn/mcf) 6.03 5.36 4.80 4.91 4.98


Asset Retirement Obligations

Effective January 1, 2004, the Trust adopted the CICA Section 3110,
"Asset Retirement Obligations". This section requires recognition of a
liability at discounted fair value for the future abandonment and
reclamation associated with the petroleum and natural gas properties.
The fair value of the liability is capitalized as part of the cost of
the related asset and amortized to expense over its useful life. The
liability accretes until the date of expected settlement of the
retirement obligations. The related accretion expense is recognized in
the statement of operations. The provision will be revised for any
changes to timing related to cash flow or undiscounted abandonment
costs. Actual expenditures incurred for the purpose of site reclamation
are charged to the asset retirement obligations to the extent that the
liability exists on the balance sheet. Differences between the actual
costs incurred and the fair value of the liability recorded are
recognized to earnings in the period incurred.

The provisions of this section require that the standard be applied
retroactively with restatement of comparative periods. As a result of
this change, net income for the comparative year ended December 31, 2003
decreased by $2.8 million, net of future income tax of $0.8 million
(three months ended December 31, 2003 - $0.3 million, net of future
income tax of $0.3 million). At December 31, 2003 the asset retirement
obligations balance increased by $32.5 million to $56.0 million, the
petroleum and natural gas assets balance increased by $19.2 million to
$862.4 million and the future tax liability decreased by $5.0 million to
$169.3 million. The opening 2003 accumulated deficit increased by $5.4
million (net of future income tax of $0.8 million). There was no impact
on cash flow as a result of adopting this policy (see note 6).

Financial Derivative Contracts

Effective January 1, 2004, the Trust implemented CICA Accounting
Guideline 13 "Hedging Relationships" (AcG-13) for accounting for
derivative contracts. This guideline addresses the identification,
designation, documentation and effectiveness of hedging transactions for
the purposes of applying hedge accounting. It also establishes
conditions for applying or discontinuing hedge accounting. Under the new
guideline, hedging transactions must be documented and it must be
demonstrated that the hedges are sufficiently effective in order to
continue accrual accounting for positions hedged with derivatives. Upon
implementation of AcG-13, Emerging Issues Committee Abstract 128 (EIC
128) also became effective. EIC 128 requires that changes in the fair
value of these derivative contracts that do not qualify for hedge
accounting under AcG-13 be recognized in the balance sheet and measured
at fair value, with changes in fair value reported as income or expense
in each reporting period. The income or expense relating to the change
in fair value of the derivative contracts is an expense that has no
impact on cash flow but may result in significant fluctuations in net
income due to volatility in the underlying market prices. In accordance
with the transitional provisions of AcG-13 and EIC-128, the new
accounting treatment has been applied prospectively whereby prior
periods have not been restated.

Prior to January 1, 2004, the Trust accounted for all derivative
contracts whereby realized gains and losses on such contracts were
included in the statement of operations within the corresponding item to
which the contract was related. Following implementation of the
guideline, realized and unrealized gains and losses on derivative
contracts that do not qualify as effective hedges are reported
separately in the statement of operations.

As of January 1, 2004, the Trust recorded a deferred charge for the
unrealized loss of $10.1 million for the mark-to-market value of the
outstanding non-hedging financial derivatives. This balance was
recognized in income over the term of the previously designated hedged
item. At December 31, 2004 the mark-to-market value of these non-hedging
financial derivatives was zero as all gains and losses have been
realized and recorded in the consolidated statement of operations over
the course of the year. At December 31, 2004, the Trust recorded a
liability of $9.5 million on the mark-to-market value of the non-hedging
financial derivatives entered into in 2004 for calendar 2005 (note 11).

Transportation Costs

CICA Handbook Section 1100, "Generally Accepted Accounting Principles",
is effective for fiscal years beginning on or after October 1, 2003.
This standard focuses on what constitutes Canadian generally accepted
accounting principles and its sources, including the primary sources of
generally accepted accounting principles. In prior periods, it had been
industry practice to record revenue net of related transportation costs.
In accordance with the new accounting standards, revenue is now reported
before transportation costs with separate disclosure in the consolidated
statement of operations of transportation costs. Petroleum and natural
gas sales and transportation costs for the year ended December 31, 2004
both increased by $18.7 million (2003 - $17.8 million) and for the three
months ended December 31, 2004 increased by $4.6 million (2003 - $4.7
million) as a result of this change. This change in classification has
no impact on net income and the comparative figures have been restated
to conform to the presentation adopted for the current period.

Non-controlling interest

The Trust has implemented the accounting for the exchangeable shares
issued by the Company as required by EIC Abstract 151, "Exchangeable
Securities Issued by Subsidiaries of Income Trusts" (EIC 151), issued in
January 2005. Under EIC 151, exchangeable shares issued by a subsidiary
of an income trust are presented as non-controlling interest, unless
certain conditions are met. 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. The presentation
of the exchangeable shares at December 31, 2003 was restated to conform
to the presentation for the current year, pursuant to the transitional
provisions contained in EIC 151. Previously, the exchangeable shares
were reflected as a component of Unitholders' Equity.

As a result of the adoption of EIC 151, net income was reduced for the
year ended December 31, 2004 by $0.35 million for the non- controlling
interest's share of income and was increased for the year ended December
31, 2003 by $0.67 million for the non- controlling interest's share of
the loss from the date of the Arrangement. Net income for the three
months ended December 31, 2004 was reduced by $1.2 million (three months
ended December 31, 2004 - $0.5 million). As the exchangeable shares are
converted to trust units, the exchange is accounted for as a
step-acquisition where Unitholders' capital was increased by the fair
value of the trust units issued. The difference between the fair value
of the trust units issued and the book value of the exchangeable shares
is recorded as an increase in petroleum and natural gas properties.
During the year ended December 31, 2004, the adoption of EIC 151
resulted in a $15.0 million increase in petroleum and natural gas
properties (December 2003 - $4.3 million), a $5.7 million increase in
future income taxes (December 2003 - $1.6 million) and a $10.9 million
increase in unitholders' capital (December 2003 - $2.8 million).

4. Corporate Acquisition

Effective September 22, 2004, the Company acquired all of the issued and
outstanding shares of a private oil and gas company with operations in
Alberta. The acquisition was financed with the Company's credit
facilities. The transaction was accounted for using the purchase method
of accounting. The estimated fair value of the assets acquired and
liabilities assumed at the date of acquisition is summarized below. The
Company has not yet completed its final valuation of the assets acquired
and liabilities assumed and, therefore, the purchase price allocation
may be subject to change. Subsequent to the acquisition, the private
company was amalgamated with the Company.



Petroleum and natural gas properties $ 109,777
Goodwill 39,259
Working capital 1,447
Capital lease obligation (777)
Asset retirement obligation (8,435)
Future income taxes (30,229)
-------------
Total net assets acquired $ 111,042
-------------
-------------

Financed by:
Cash $ 110,822
Costs associated with acquisition 220
-------------
Total purchase price $ 111,042
-------------
-------------

Goodwill of $39.3 million was determined based on the excess of the
total consideration paid less the value assigned to the identifiable
assets and liabilities including the future income tax liability.


5. Long-term Debt

December 31, 2004 December 31, 2003
-------------------------------------------
10.5% senior subordinated
notes (US$247,000) $ 297 $ 319
9.625% senior subordinated
notes (US$179,699,000) 216,286 232,243
-------------------------------------------
$ 216,583 $ 232,562
-------------------------------------------
-------------------------------------------


Interest Expense

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


Three Months Ended Year Ended
December 31 December 31
2004 2003 2004 2003
-------------------------------------------
Credit facility charges $ 1,798 $ 114 $ 2,256 $ 675
Amortization of
deferred charge 267 276 1,060 1,027
Long-term debt interest 4,383 4,783 16,096 21,846
-------------------------------------------
$ 6,448 $ 5,173 $ 19,412 $ 23,548
-------------------------------------------
-------------------------------------------


6. Asset Retirement Obligations

December 31, 2004 December 31, 2003
-------------------------------------------
Balance, beginning of year $ 55,996 $ 52,244
Liabilities incurred 4,623 4,010
Liabilities settled (2,739) (880)
Acquisition of liabilities 12,797 -
Disposition of liabilities (1,722) (3,335)
Accretion 4,342 3,957
-------------------------------------------
Balance, end of year $ 73,297 $ 55,996
-------------------------------------------
-------------------------------------------


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.
Estimated cash flow has been discounted at a credit-adjusted risk free
rate of 8.0 percent and an inflation rate of 1.5 percent.

7. Income Taxes

Future income tax expense for the year ended December, 2004 included a
non-recurring adjustment to future income taxes resulting from a
decrease to the Alberta corporate income tax rate from 12.5 percent to
11.5 percent.



8. Unitholders' Capital

Trust Units

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

Trust Units # of units Amount
-------------------------------------------
Balance December 31, 2003 60,821 $ 449,403
Issued on conversion of
exchangeable shares 1,994 21,222
Issued on exercise of
trust unit rights 113 1,472
Issued pursuant to
distribution reinvestment
program 10 131
Issued for cash,
net of expenses 3,600 43,500
-------------------------------------------
Balance December 31, 2004 66,538 $ 515,728
-------------------------------------------
-------------------------------------------


On October 18, 2004, the Trust implemented a Distribution Reinvestment
Plan ("DRIP"). Under the DRIP, Canadian unitholders can elect to
reinvest monthly cash distributions in additional trust units of the
Trust. Trust units purchased from treasury under the DRIP will be issued
at a 5% discount from the weighted average closing price of the trust
units on the Toronto Stock Exchange for the period commencing on the
second business day after the distribution record date and ending on the
second business day immediately prior to the distribution payment date,
such period not to exceed 20 trading days. The Trust can also acquire
trust units to be issued under the DRIP at prevailing market prices.

9. 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 cash 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 adjusted monthly based on the
cash distribution paid divided by the weighted average trust unit price
of the five-day trading period ending on the record date. The exchange
ratio at December 31, 2004 was 1.21472 trust units per exchangeable
share (2003 - 1.04530 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 or
decrease to the non-controlling interest on the balance sheet.


Number of
Non-controlling Interest Exchangeable Shares Amount
-------------------------------------------
Issued September 2, 2003
pursuant to Plan of
Arrangement 4,732 $ 33,507
Exchanged for trust units (1,007) (7,134)
Non-controlling interest
in net loss - (668)
------------------------------------------
Balance December 31, 2003 3,725 25,705
Exchanged for trust units (1,849) (13,090)
Non-controlling interest
in net income - 347
------------------------------------------
Balance December 31, 2004 1,876 $ 12,962
------------------------------------------
------------------------------------------


10. Trust Unit Rights

Effective September 2, 2003, the Trust established a Trust Unit Rights
Incentive Plan (the "Plan") to replace the stock option plan of the
Company. A total of 5,800,000 trust unit rights are reserved for issue
under the Plan. Trust unit rights are granted at the market price of the
trust units at the time of the grant, vest over three years and have a
term of five years.

The Plan allows for the exercise price of the rights to be reduced in
future periods by a portion of the future distributions. The Trust has
determined that the amount of the reduction cannot be reasonably
estimated, as it is dependent upon a number of factors including, but
not limited to, future oil and natural gas prices, production of oil and
natural gas, determination of amounts to be withheld from future
distributions to fund capital expenditures, and the purchase and sale of
oil and natural gas assets. Therefore, it is not possible to determine a
fair value for the rights granted under the plan.

Compensation expense is determined based on the amount that the market
price of the trust unit exceeds the exercise price for rights issued as
at the date of the consolidated financial statements and is recognized
in earning over the vesting period of the plan. Compensation expense for
the unit rights for the year ended December 31, 2004 was $7.7 million
(three months ended December 31, 2004 - $1.6 million).



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

Weighted average
# of Rights exercise price (1)
------------------------------------------
Balance December 31, 2003 2,855 $ 10.15
Granted 1,297 $ 11.77
Exercised (113) $ 8.87
Cancelled (502) $ 9.54
--------------------
Balance December 31, 2004 3,537 $ 9.60
--------------------
--------------------
(1) Exercise price reflects grant price less reduction in exercise
price as discussed above.


The adoption of the amendments related to accounting for unit-based
compensation (note 3) also impacted the accounting for stock options
granted by the Company to employees before the implementation of the
Plan of Arrangement. For the year ended December 31, 2003, compensation
expense related to the stock options granted by the Company since
January 1, 2003 was $0.52 million. Compensation expense for options
granted during 2003 was based on the estimated fair value at the time of
the grant and the expense was recognized over the vesting period of the
options.



11. Financial Derivative Contracts

At December 31, 2004, the Trust had financial derivative contracts
for the following:

----------------------------------------------------------
Period Volume Price Index
----------------------------------------------------------
Oil
Price collar Calendar 2005 3,000 bbl/d US$35.00 - $42.40 WTI
Price collar Calendar 2005 2,000 bbl/d US$35.00 - $42.50 WTI
Price collar Calendar 2005 1,000 bbl/d US$35.00 - $42.70 WTI
Price collar Calendar 2005 2,000 bbl/d US$35.00 - $42.75 WTI

----------------------------------------------------------
Period Principal Rate
----------------------------------------------------------
Interest rate November 2003 3-month
swap to July 2010 US$179,699,000 LIBOR plus 5.2%


As discussed in note 3, under the new 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. At
January 1, 2004, the fair value of all outstanding financial derivative
contracts that were not considered accounting hedges was recorded on the
consolidated balance sheet with an offsetting deferred credit of $10.1
million. The deferred credit balance has been recognized into income
during the year ended December 31, 2004. The mark-to-market value of the
outstanding non-hedging financial derivatives is recorded as a liability
of $9.5 million at December 31, 2004. The change in the mark-to-market
value of these financial derivative contracts from the inception of the
contracts to December 31, 2004 has been recorded as an unrealized gain
on non-hedging financial derivatives of $0.6 million in the consolidated
statement of operations.



12. Supplemental Cash Flow Information


Three Months Ended Year Ended
December 31 December 31
2004 2003 2004 2003
-------------------------------------------
Interest paid 1,799 2,161 21,096 24,449
Income taxes paid 2,408 1,756 17,485 12,557


13. Reclassification

Certain comparative figures have been reclassified to conform to the
current periods' presentation.

14. Subsequent Event

In January 2005, the Company entered into agreements to collar the
exchange rate on US$9 million per month at average $CDN/$US rates
between $1.2168 and $1.2500.

-30-

Contact Information

  • FOR FURTHER INFORMATION PLEASE CONTACT:
    Baytex Energy Trust
    Ray Chan
    President & Chief Executive Officer
    (403) 267-0715
    or
    Baytex Energy Trust
    Dan Belot
    Vice-President, Finance & Chief Financial Officer
    (403) 267-0784
    Toll Free Number: 1-800-524-5521
    Website: www.baytex.ab.ca