Bonavista Energy Trust

Bonavista Energy Trust

March 10, 2005 20:01 ET

Bonavista Energy Trust Announces 2004 Year End Results


NEWS RELEASE TRANSMITTED BY CCNMatthews

FOR: BONAVISTA ENERGY TRUST

TSX SYMBOL: BNP.UN

MARCH 10, 2005 - 20:01 ET

Bonavista Energy Trust Announces 2004 Year End Results

CALGARY, ALBERTA--(CCNMatthews - March 10, 2005) - Bonavista Energy
Trust (TSX:BNP.UN) is pleased to report to unitholders its interim
consolidated financial and operating results for the three months and
year ended December 31, 2004.



------------------------------------------------------------------------
Trust Highlights
------------------------------------------------------------------------
Three Months Year
ended ended
December 31, % December 31, %
2004 2003 Change 2004 2003 Change
------------------------------------------------------------------------
(restated) (restated)
Financial
($ thousands, except per unit)

Production
revenue 155,077 109,800 41 599,445 483,686 24

Cash flow from
operations (1) 90,659 64,072 41 350,649 285,051 23
Per unit (2) 1.11 0.90 23 4.37 4.24 3

Cash distributions 53,162 41,903 27 194,863 80,838 141
Per unit 0.83 0.75 11 3.08 1.50 105

Percentage of
cash flow
distributed 59% 65% (6) 56% N/A -

Net income (3) 52,741 32,474 62 206,323 163,213 26
Per unit (2) (3) 0.63 0.45 40 2.49 2.43 2

Total assets 1,740,251 1,072,601 62

Long-term debt,
net of working
capital 324,559 208,142 56

Unitholders' equity 1,135,036 630,348 80

Capital expenditures:
Exploitation
and development 38,573 38,361 1 145,844 135,956 7
Acquisitions, net 469,648 275,978 70 605,618 247,413 145

Weighted average
outstanding
equivalent trust
units
(thousands): (2)
Basic 82,018 71,562 15 80,196 67,217 19
Diluted 85,993 71,790 20 84,526 67,721 25
------------------------------------------------------------------------


Operating
(boe conversion
- 6:1 basis)

Production:
Natural gas
(mmcf/day) 140 123 14 144 124 16
Oil and liquids
(bbls/day) 19,814 16,906 17 18,607 15,841 17
Total oil
equivalent
(boe/day) 43,106 37,415 15 42,551 36,573 16

Product prices: (4)
Natural gas ($/mcf) 6.67 5.45 22 6.51 6.41 2
Oil and liquids
($/bbl) 35.53 27.99 27 35.30 30.65 15

Operating expenses
($/boe) 5.96 5.11 17 5.59 4.88 15

General and
Administration
expenses ($/boe) 0.54 0.30 80 0.39 0.28 39

Cash costs ($/boe) 7.50 6.14 22 6.81 6.79 -

Cash flow netback
($/boe) 22.86 18.61 23 22.52 21.35 6

Undeveloped land:
Gross acres 1,712,708 1,442,076 19
Net acres 1,312,504 1,141,990 15
Average working interest 77% 79% (2)

Drilling (gross wells) 255 180 42
Natural gas 135 68 99
Oil 105 92 14
Average Success Rate 94% 89% 5

Reserves:
Proven:
Natural gas (bcf) 419.3 228.5 84
Oil and liquids
(mbbls) 63,542 46,122 38
Total oil
equivalent (mboe) 133,427 84,204 58
Proven and probable:
Natural gas (bcf) 507.9 282.5 80
Oil and liquids
(mbbls) 79,476 59,725 33
Total oil
equivalent (mboe) 164,130 106,816 54
% Proven producing 66% 61% 5
% Proven 81% 79% 2
% Probable 19% 21% (2)
Net present value of
future cash flow before
income taxes ($ millions):
@ 0% discount rate 3,277 1,717 91
@ 5% discount rate 2,337 1,443 62
@ 10% discount rate 1,860 1,118 66
Reserve Life Index (years):
Proven 7.3 6.0 22
Proven and probable 8.6 7.3 18

Finding and development
costs ($/boe): (5)
Proven 11.99 15.96 (25)
Proven and probable 10.88 11.94 (9)

------------------------------------------------------------------------
Trust Unit Trading Statistics Three Months Ended
------------------------------------------------------------------------
December 31, September 30, June 30, March 31,
2004 2004 2004 2004
------------------------------------------------------------------------
($ per unit, except volume)

High 28.88 26.00 23.24 22.60
Low 23.59 22.52 20.69 18.07
Close 27.10 25.89 23.04 22.24
Average Daily Volume 269,429 245,067 146,600 224,660
------------------------------------------------------------------------
------------------------------------------------------------------------

NOTES:

(1) Cash flow from operations is determined before changes in non-cash
working capital to analyze operating performance and leverage. Cash
flow does not have a standardized measure prescribed by Canadian
Generally Accepted Accounting Principles and therefore may not be
comparable with the calculations with similar measures for other
companies.

(2) Includes Exchangeable Shares and Exchangeable Units, which are
convertible into Trust Units on certain terms and conditions.

(3) Net income and net income per unit for 2003 have been restated for
the adoption of the new accounting standards for asset retirement
obligations and unit-based compensation. See Note 3 of the interim
consolidated financial statements for details of this restatement.

(4) Product prices presented are wellhead prices, net of transportation
costs.

(5) Calculated in accordance with National Instrument 51-101, which
includes total capital expenditures adjusted for changes in future
capital expenditures divided by reserve additions for the years
ended December 31, 2004 and 2003.


MESSAGE TO UNITHOLDERS

Bonavista Energy Trust ("Bonavista" or the "Trust") is pleased to report
to its unitholders ("Unitholders") its consolidated financial and
operating results for the three months and year ended December 31, 2004.
The results of the fourth quarter of 2004 represent six consecutive
quarters of continuous profitable growth for Bonavista since commencing
operations as an energy trust. Bonavista's Board of Directors and
management are very pleased with the results of the decision to
reorganize and the benefits accruing to our investors. The continued
successful execution of Bonavista's proven strategies in 2004 is a
testament to the validity and effectiveness of an operationally and
technically focused energy trust. The 2004 year was also highlighted by
very strong commodity prices for both oil and natural gas and an
increased selection of drilling and acquisition opportunities for
Bonavista. This favourable environment created the opportunity for
Bonavista to expand its capital program throughout the year and complete
a significant acquisition of northeast British Columbia properties on
December 31, 2004. This acquisition has provided Bonavista with a new
Core Region with numerous optimization and exploitation opportunities.
The expanded capital programs in 2004 will position Bonavista to
continue to record profitable results, both operationally and
financially, for 2005 and beyond.

Other significant accomplishments include:

- From inception as an energy trust on July 2, 2003 to date, the Trust
has delivered a total return to its investors of 124%, comprised of a
92% increase in unit price and a 32% return from cash distributions. For
2004, the total return to investors was 57%, which is top decile
industry performance. The monthly cash distribution was maintained at
$0.25 per unit per month for the first nine months of 2004 and was
increased to $0.275 per unit per month effective October 1, 2004.
Bonavista's current monthly distribution rate results in a cash-on-cash
yield of approximately 10%;

- Operationally, Bonavista increased average production volumes to a
record 42,551 boe per day during 2004, which represents a 23% increase
over the 34,600 boe per day of production at commencement as an energy
trust on July 2, 2003. Current production rates are approximately 52,000
boe per day;

- Added 72.9 mmboe of proven and probable reserves during 2004, which
replaced annual production by 4.7 times and improved the Trust's proven
and probable reserve life index by 18% from 7.3 years to 8.6 years.
These reserves were added at an attractive finding and development cost,
including changes in future capital expenditures, of $11.99 per boe on a
proven basis and $10.88 per boe on a proven and probable basis.
Bonavista's finding and development costs were 9% lower in 2004 versus
2003, and resulted in a strong proven and probable recycle ratio of
2.1:1. Furthermore, Bonavista's total proven and probable reserves on a
per unit basis significantly increased by 24% during 2004;

- Increased undeveloped land position by 39% from 942,000 net acres at
July 2, 2003 to 1,312,500 at December 31, 2004, further enhancing future
drilling prospect inventory. Bonavista currently has over two years
inventory of drilling prospects;

- Maintained an active capital program during 2004, having invested
$145.8 million in exploitation and development activities and $605.6
million in 35 synergistic acquisitions, significantly strengthening our
core regions. The largest of these property acquisitions was the
acquisition of 10,600 boe per day of oil and natural gas properties on
December 31, 2004 in northeast British Columbia, which created a new
Core Region for Bonavista;

- Generated cash flow of $350.6 million ($4.37 per unit) and distributed
56% of cash flow generated in the twelve months ending December 31, 2004
to Unitholders with the remaining cash flow used to fund capital
expenditures and growth;

- Continued recording strong profitable growth in 2004 with average
return on equity of 29% and a strong earnings to cash flow ratio of 59%;
and

- Completed a $281.8 million equity financing and a $135 million
convertible debenture financing to fund the northeast British Columbia
property acquisition on December 31, 2004. In addition, Bonavista
expanded its existing loan facility to $475 million, which provides
significant financial flexibility to take advantage of future investment
opportunities in 2005 and beyond.

Strengths of Bonavista Energy Trust

Since its restructuring, Bonavista has successfully retained its
experienced and proven management and technical team who have a solid
understanding of our asset base and possess the necessary discipline to
deliver profitable results to our Unitholders for the long-term. The
Trust also has and will continue to benefit from an excellent
undeveloped land position with numerous low-risk development
opportunities, allowing us to maintain our base of production and
lengthen our proven and probable reserve life index over time. Our
production base is weighted 57% towards natural gas, geographically
focused within select medium depth, multi-zone regions in Alberta,
Saskatchewan and British Columbia and has one of the lowest operating
cost structures in the oil and natural gas trust sector. These
attributes combined, result in top quartile netbacks for Bonavista.
Also, these high working interest assets are predominately operated by
the Trust, ensuring that operating and capital cost efficiencies are
maintained.

Our team brings a successful track record of executing low to moderate
risk development programs, both asset and corporate acquisitions, along
with sound financial management. Unitholders benefit from a fully
internalized, industry-leading cost structure, which results in one of
the lowest per unit overhead cost structures in the energy trust
industry. The management team remains in place along with a strong Board
of Directors, who possess extensive experience in oil and natural gas
operations, corporate governance and financial management. Directors and
management also own approximately 18% of the Trust, resulting in an
alignment of interests with all Unitholders.

The Trust has the financial strength and experience to take advantage of
many future investment opportunities. This financial strength is
demonstrated by a debt to running cash flow ratio of approximately 0.7
to 1, a very favourable ratio when compared to the energy trust sector
average of 1.3 to 1. At December 31, 2004 the Trust had 14.4 million
Exchangeable Shares outstanding, which require no monthly cash
distributions, creating additional financial flexibility in the Trust.
The holders of the Exchangeable Shares receive their return through a
monthly increase in the exchange ratio into Trust Units. This structure
provides the Trust with a unique funding mechanism to expand its capital
expenditure programs should the opportunities arise. Bonavista is
committed to maintaining significant financial flexibility, with the
conservative use of debt into the future.

MANAGEMENT'S DISCUSSION AND ANALYSIS

Management's discussion and analysis ("MD&A") of the financial condition
and results of operations should be read in conjunction with Bonavista
Energy Trust's ("Bonavista" or the "Trust") consolidated financial
statements for the three months and year ended December 31, 2004 and the
audited consolidated financial statements and MD&A for the years ended
December 31, 2003 and 2002. Our audited consolidated financial
statements, Annual Report, and other disclosure documents are filed on
SEDAR at www.sedar.com or can be obtained from Bonavista's website at
www.bonavistaenergy.com. The Trust was created through the
reorganization of Bonavista Petroleum Ltd. ("BPL"), whose historical
results represent the comparative financial results for the Trust.
Barrels of oil equivalent ("boe") has been calculated using a conversion
rate of six thousand cubic feet of natural gas to one barrel of oil.

Creation of Bonavista Energy Trust - On June 26, 2003, the shareholders
approved a reorganization of BPL, as described in the Plan of
Arrangement dated May 23, 2003 and became effective on July 2, 2003. For
each share of BPL, shareholders received either two units of the Trust
or two Exchangeable Shares (exchangeable into Trust Units) plus one
common share of NuVista Energy Ltd. ("NuVista"), a newly created public
exploration and production company. The Trust and NuVista are separate
public entities. The Trust commenced operations on July 2, 2003 with the
new legal structure and business mandate pursuant to the Trust Indenture
dated May 22, 2003, while retaining approximately 90% of the assets
previously owned by BPL. The management team and employees of BPL remain
employees of the Trust and also provide technical and administrative
services to NuVista under a Technical Services Agreement.

Operations - Bonavista's exploitation and development program for the
year ended December 31, 2004 led to the drilling of 255 wells in its
three core regions, with an overall success rate of 94%. This program
resulted in 135 natural gas wells, 73 light and medium oil wells, 32
heavy oil wells and 15 dry holes. Bonavista operated the drilling of 214
of these wells, with an average working interest of 87%. In the fourth
quarter of 2004, Bonavista drilled 81 wells in its three core regions,
with an overall success rate of 95%. Operatorship and high working
interest ownership remain an integral part of our strategy to ensure
control over the pace of our growth and control of spending on any given
project. In addition to the exploitation and development program,
Bonavista executed 35 complementary acquisitions in its core regions in
2004.

Reserves - Reserve estimates have been calculated in compliance with the
National Instrument 51-101 Standards of Disclosure ("NI 51-101"). Under
NI 51-101, proven reserves are defined as reserves that can be estimated
with a high degree of certainty to be recoverable with a target of a 90
percent probability that the actual reserves recovered over time will
equal or exceed proven reserve estimates, while probable reserves are
defined as having an equal (50 percent) probability that the actual
reserves recovered will equal or exceed the proven plus probable reserve
estimates. In accordance with NI 51-101, proven undeveloped reserves
have been recognized in cases where plans are in place to bring the
reserves on production within a short, well defined time frame. Proven
undeveloped reserves often involve infill drilling into existing pools.
Of the Trust's total reserves, 87% were evaluated by independent third
party engineers, Gilbert Laustsen Jung Associates Ltd. and Ryder Scott
Company, depending on the particular location of the property. The
balance of approximately 13% of proven plus probable reserves was
evaluated internally. The reserve estimates contained in the following
table are company interest reserves before the deduction of royalties.



------------------------------------------------------------------------
Net Present Value @
Natural Oil and Total -----------------------------
Gas Liquids Reserves 0% 5% 10%
------------------------------------------------------------------------
Proven (bcf) (mbbls) (mboe) (millions)
Proven
producing 365.0 47,525 108,351 $ 2,186 $ 1,653 $ 1,366
Proven
non-producing 31.0 7,502 12,679 198 161 133
Proven
undeveloped 23.3 8,515 12,397 274 153 103
------------------------------------------------------------------------

Total Proven 419.3 63,542 133,427 2,658 1,967 1,602
Probable 88.6 15,934 30,703 619 370 258
------------------------------------------------------------------------

Total Proved
and Probable 507.9 79,476 164,130 $ 3,277 $ 2,337 $ 1,860
------------------------------------------------------------------------
------------------------------------------------------------------------


Bonavista's year end 2004 proven reserves amounted to 133.4 mmboe or a
58% increase over the 84.2 mmboe closing balance at year end 2003.
Bonavista's proven and probable reserves climbed by 54% to 164.1 mmboe
when compared to the 106.8 mmboe at year end 2003. Finding and
development costs in 2004, including changes in future capital
expenditures, amounted to $11.99 per boe ($11.60 per boe before changes
in future capital expenditures) on a proven basis and $10.88 per boe
($10.31 per boe before changes in future capital expenditures) on a
proven and probable basis.

Positive proven reserve revisions totaled 3.1 mmboe, or approximately
3.6% of the opening proven reserve balance. On a proven and probable
basis, a slight negative revision of 0.9 mmboe, or a 0.8% decrease was
experienced when compared to the opening proven and probable reserve
balance. The adjustments in the proven reserve category resulted from
technical revisions based on variances in reservoir performance year
over year. Additional reserve disclosure tables, as required under NI
51-101, will be contained in the Annual Information Form that will be
filed on SEDAR.



Financial and Operating Highlights - The following is a summary of key
financial and operating results for the respective periods noted:

------------------------------------------------------------------------
Three Months Year
ended ended
December 31, December 31,
2004 2003 2004 2003
------------------------------------------------------------------------
($ thousands, except per boe/Trust (restated) (restated)
Unit Amounts and where noted)

Prices:
Natural gas ($/mcf) 6.67 5.45 6.51 6.41
Oil and liquids ($/bbl) 35.53 27.99 35.30 30.65

Production:
Natural gas (mmcf/d) 140 123 144 124
Oil and liquids (bbls/d) 19,814 16,906 18,607 15,841
Total production (boe/d) 43,106 37,415 42,551 36,573

Production revenue 155,077 109,800 599,445 483,686
per boe 39.10 31.90 38.49 36.23

Royalty expense 30,141 20,030 125,674 92,342
per boe 7.60 5.82 8.07 6.92
% of Production revenue, net 20.0% 19.0% 21.6% 19.7%

Transportation costs 4,532 4,571 16,992 15,635
per boe 1.14 1.33 1.09 1.17

Operating expenses 23,634 17,576 87,096 65,119
per boe 5.96 5.11 5.59 4.88

General & administration expenses 2,157 1,025 6,133 3,743
per boe 0.54 0.30 0.39 0.28

Financing expenses 2,805 1,521 8,576 4,654
per boe 0.71 0.44 0.55 0.35

Cash flow from operations 90,659 64,072 350,649 285,051
per boe 22.86 18.61 22.52 21.35

Unit-based compensation 382 24 1,408 550
per boe 0.10 0.01 0.09 0.04

Depreciation, depletion and
accretion 40,122 31,608 150,428 108,457
per boe 10.12 9.18 9.66 8.12

Income and other taxes (1,437) 971 (3,185) 29,973
per boe (0.36) 0.28 (0.20) 2.25

Net income 52,741 32,474 206,323 163,213
per boe 13.30 9.43 13.25 12.22
per unit - basic 0.63 0.45 2.49 2.43

Distributions to Unitholders 53,162 41,903 194,863 80,838
per unit 0.83 0.75 3.08 1.50

------------------------------------------------------------------------


Production - As a direct result of Bonavista's successful capital
programs, production for the year ended December 31, 2004 increased 16%
to a record 42,551 boe per day when compared to 36,573 boe per day for
the same period a year ago. More specifically, average natural gas
production increased 16% to 144 mmcf per day from 124 mmcf per day in
2004 while total oil and liquids production increased 17% to 18,607 bbls
per day from 15,841 bbls per day in 2004. Production for the fourth
quarter of 2004 also reached a record level of 43,106 boe per day, up
15% from 37,415 boe per day in the fourth quarter of 2003. In the fourth
quarter of 2004, natural gas production increased 14% to 140 mmcf per
day from 123 mmcf per day for the same period a year ago, while total
oil and liquids production increased 17% to 19,814 bbls per day from
16,906 bbls per day for the same period a year ago. Our current
production is approximately 52,000 boe per day consisting of 57% natural
gas, 30% light and medium oil and 13% heavy oil. We will continue to
focus on a diversified commodity investment approach to minimize our
dependence on any one product.

Production revenue - Production revenue, net of transportation costs,
for the year ended December 31, 2004 increased by 24% to $582.5 million
when compared to $468.1 million for the same period a year ago. This
increase is attributable to a 16% increase in product volumes and a 7%
increase in commodity prices on a boe basis. For the year ended December
31, 2004 natural gas prices averaged $6.51 per mcf an increase of 2%
from $6.41 per mcf for the same period a year ago. The corporate average
oil price increased 15% to $35.30 per bbl for the year ended December
31, 2004 from $30.65 per bbl for the same period a year ago. Production
revenues, net of transportation costs, for the fourth quarter of 2004
increased by 43% to $150.5 million from $105.2 million in the fourth
quarter of 2003. This increase is attributable to a 15% increase in
production volumes and a 24% increase in commodity prices on a boe
basis. In the fourth quarter of 2004, natural gas prices averaged $6.67
per mcf, up 22% from $5.45 per mcf for the same period in 2003 and the
corporate average oil price also increased 27% to $35.53 per bbl in the
fourth quarter of 2004 from $27.99 per bbl for the same period in 2003.

Commodity hedging - As part of our financial management strategy, the
Trust has adopted a disciplined commodity hedging program. The purpose
of the hedging program is to reduce volatility in the financial results,
protect acquisition economics and stabilize cash flow and Unitholder
distributions against the unpredictable commodity price environment. At
any given period of time, our hedging strategy is restricted to a
maximum hedge position of 60% of forecasted production, net of
royalties, and primarily uses costless collars. This strategy limits the
Trust's exposure to downturns in commodity prices while allowing for
more participation in commodity price increases. For the year ended
December 31, 2004, our hedging program resulted in a net loss of $23.0
million and for the three months ended December 31, 2004, a net loss of
$4.1 million was experienced due to the stronger than expected commodity
prices realized throughout the period. A summary of hedging contracts in
place as at December 31, 2004 is outlined in Note 11 of the Notes to the
Consolidated Financial Statements.

Royalties - For the year ended December 31, 2004 royalties, net of the
Alberta Royalty Tax Credit, increased 36% from $92.3 million in 2003 to
$125.7 in 2004, primarily as a result of the higher revenues and the
acquisition of oil and natural gas properties with higher royalty rates
in 2004. For similar reasons, royalties as a percentage of production
revenue, net of transportation costs, for the year ended December 31,
2004 also increased from 19.7% in 2003 to 21.6% in 2004. For the year
ended December 31, 2004, royalties as a percentage of revenues (net of
transportation costs), by product, were 24.2% for natural gas, 20.3% for
light and medium oil and 11.2% for heavy oil. For the three months ended
December 31, 2004 royalties, net of the Alberta Royalty Tax Credit,
increased 51% from $20.0 million in 2003 to $30.1 million in 2004 also
primarily as a result of the higher revenues and the acquisition of oil
and natural gas properties with higher royalty rates during the period.
For similar reasons, royalties as a percentage of production revenue,
net of transportation costs, for the three months ended also increased
from 19.0% in 2003 to 20.0% in 2004. For the three months ended December
31, 2004, royalties as a percentage of revenues (net of transportation
costs), by product were 22.0% for natural gas, 19.5% for light and
medium oil and 10.6% for heavy oil.

Transportation costs - For the year ended December 31, 2004
transportation costs were $17.0 million ($1.09 per boe) compared to
$15.6 million ($1.17 per boe) in 2003. The 9% increase in transportation
costs results primarily due to higher production in 2004 versus 2003.
For the three months ended December 31, 2004 transportation costs were
$4.5 million ($1.14 per boe) as compared to $4.6 million ($1.33 per boe)
for the same period last year.

Operating expenses - Operating expenses were $87.1 million for the year
ended December 31, 2004 compared to $65.1 million a year ago, an
increase of 34%. For the fourth quarter of 2004, operating expenses were
$23.6 million compared to $17.6 million for the same period a year ago,
which is also an increase of 34%. Primarily driven by strong commodity
prices and record levels of industry activity, the industry is
experiencing significant increasing pressure on all costs. This coupled
with the acquisition of higher per unit operating cost properties
resulted in increased average per unit operating costs for Bonavista for
the year ended December 31, 2004. These combined factors resulted in
operating costs increasing to $5.59 per boe for the year ended December
31, 2004 from $4.88 per boe in the comparable period of 2003. Operating
costs by product for this period were $0.70 per mcf for natural gas,
$7.21 per bbl for light and medium oil and $7.71 per bbl for heavy oil.
For the three months ended December 31, 2004, operating costs increased
to $5.96 per boe from $5.11 per boe in the same quarter of 2003 and were
comprised of $0.75 per mcf for natural gas, $7.42 per bbl for light and
medium oil and $8.24 per bbl for heavy oil. Notwithstanding recent
increases, Bonavista continues to place significant emphasis on the
control of operating costs and remains one of the lowest cash cost
producers in the industry.

General and administrative expenses - General and administrative
expenses, after overhead recoveries, increased 64% to $6.1 million for
the year ended December 31, 2004 from $3.7 million in the same period in
2003. For the three months ended December 31, 2004, general and
administrative expenses increased 110% to $2.2 million from $1.0 million
in 2003. On a per boe basis, general and administrative expenses
increased 39% for the year ended December 31, 2004 to $0.39 per boe from
$0.28 per boe in 2003 and increased 80% for the three months ended
December 31, 2004 to $0.54 per boe from $0.30 per boe in the same period
in 2003. These increases are largely due to an enhanced bonus program
implemented in the fourth quarter of 2004 and also the higher staffing
levels required to manage our larger operations. As part of the Plan of
Arrangement, Bonavista entered into a Technical Services Agreement with
NuVista, through which it provides technical and administrative services
and receives a fee determined on a cost recovery basis. The fee charged
under this agreement was $1.3 million related to general and
administrative activities rendered for the year ended December 31, 2004
and $508,000 for the three months ended December 31, 2004.

Financing expenses - Financing expenses increased to $8.6 million for
the year ended December 31, 2004 from $4.7 million in the same period in
2003, and on a per boe basis increased to $0.55 per boe in 2004 from
$0.35 per boe in 2003. For the three months ended December 31, 2004,
financing charges also increased to $2.8 million from $1.5 million in
the same period in 2003, and on a per boe basis increased to $0.71 per
boe for the three months of 2004 from $0.44 per boe for the same period
in 2003. These increases are a direct consequence of higher average debt
levels in 2004, resulting from our expanded capital programs. At
December 31, 2004 our average bank borrowing interest rate was
approximately 3.5%. For the year ended December 31, 2004, Bonavista paid
cash interest of $8.6 million on bank debt compared to $4.7 million for
the corresponding period a year ago. For the three month period ended
December 31, 2004, Bonavista paid cash interest of $2.8 million on bank
debt compared to $1.5 million for the corresponding period a year ago.
Interest charges related to accrued interest on the convertible
debentures in the amount of $6.4 million for the year ended December 31,
2004 and $1.4 million for the three months ended December 31, 2004 have
been included as a reduction of accumulated earnings to reflect the
equity nature of this security.

Depreciation, depletion and accretion expenses - Depreciation, depletion
and accretion expenses increased 39% to $150.4 million for the year
ended December 31, 2004 from $108.5 million in the same period of 2003
due to higher production levels and higher average unit costs. For
similar reasons, the three months ended December 31, 2004 saw
depreciation, depletion and accretion expenses increase by 27% to $40.1
million from $31.6 million in the same period of 2003. For the year
ended December 31, 2004 the average unit cost increased to $9.66 per boe
from $8.12 per boe in 2003 and for the three months ended December 31,
2004 the average cost increased to $10.12 per boe from $9.18 per boe for
the same period a year ago. These increases are directly due to the
overall higher cost of adding new reserves, which is a trend being
experienced throughout the industry.

Income and other taxes - For the year ended December 31, 2004, the
provision for income and other taxes was a reduction of $3.2 million
compared to a provision of $30.0 million for 2003. The significantly
higher provision in 2003 relates to the period prior to the
reorganization into a trust. Under the trust structure, distributions
transfer both income and future tax liabilities to the unitholders. The
distribution payments in a period reduce future income tax liabilities
previously recorded and are recognized as a recovery of income taxes.
The $3.2 million reduction for the year ended December 31, 2004,
includes a provision for capital taxes of $4.3 million and a reduction
of future income taxes of $7.5 million. The capital taxes of $4.3
million for 2004 is higher than the $3.0 million of capital taxes in
2003 due to the larger capital tax base year over year. For the three
months ended December 31, 2004, the provision for income and other taxes
was a reduction of $1.4 million compared to a provision of $971,000
during the same period of 2003. For the year ended December 31, 2004,
Bonavista paid capital tax installments of $2.3 million compared to
$45.9 million for capital and income taxes for the same period a year
ago. For the three months ended December 31, 2004, Bonavista paid
capital tax installments of $603,000 compared to $1.0 million of capital
and income taxes for the same period a year ago.

Cash flow and net income - For the year ended December 31, 2004,
Bonavista realized a 23% increase in cash flow to $350.6 million ($4.37
per unit, basic) from $285.1 million ($4.24 per unit, basic) recorded in
the same period in 2003. This increase was primarily due to increased
production levels and higher average commodity prices realized in 2004
when compared to 2003. For the three month period ended December 31,
2004, Bonavista similarly experienced a 41% increase in cash flow to
$90.7 million ($1.11 per unit, basic) from $64.1 million ($0.90 per
unit, basic) for the same period in 2003. Net income for the year ended
December 31, 2004 also increased to $206.3 million ($2.49 per unit,
basic), a 26% increase from $163.2 million ($2.43 per unit, basic) in
2003. For the three months ended December 31, 2004, net income increased
to $52.7 million ($0.63 per unit, basic) from $32.5 million ($0.45 per
unit, basic) in 2003. The increases in net income are largely
attributable to the increased cash flow and the reduction in the income
tax provision resulting from the trust structure. For prior periods in
2003, net income has been restated for the adoption of new accounting
policies on January 1, 2004. For further information see Note 3 of the
Notes to the Consolidated Financial Statements. The changes in
accounting policies did not impact cash flow.

Capital expenditures - Capital expenditures of $751.5 million for the
year ended December 31, 2004 consisted of $605.6 million on acquisitions
and $145.9 million on exploitation and development spending. For the
same period in 2003, capital expenditures were $383.4 million,
consisting of $247.4 million of net acquisitions and $136.0 million on
exploitation and development activities. The increase in acquisition
expenditures in 2004 compared to 2003 is a result of additional
opportunities in Bonavista's existing Core Regions and a strategic
property acquisition in northeast British Columbia. For the three month
period ended December 31, 2004, capital expenditures were $508.2 million
consisting of $469.6 million on acquisitions and $38.6 million on
exploitation and development spending. For the same period in 2003,
capital expenditures were $314.4 million consisting of $276.0 million of
net property acquisitions and $38.4 million of exploitation and
development activities.

The following table outlines capital expenditures by category for the
years ended December 31, 2004 and 2003:



------------------------------------------------------------------------
Year ended
December 31,
2004 2003
------------------------------------------------------------------------
(thousands)
Land and acquisitions $ 15,602 $ 12,838
Geological and geophysical 7,327 9,228
Drilling and completion 85,175 76,465
Production equipment and facilities 37,137 36,951
Other 603 474
------------------------------------------------------------------------

Exploitation and development expenditures 145,844 135,956
Acquisitions 605,815 323,638
Dispositions (197) (76,225)
------------------------------------------------------------------------

Net capital expenditures $ 751,462 $ 383,369
------------------------------------------------------------------------
------------------------------------------------------------------------


Liquidity and capital resources - As at December 31, 2004, debt net of
working capital was $324.6 million with an attractive debt to running
cash flow ratio of 0.7:1. Based on our recently increased banking
facility to $475 million, Bonavista has significant unused bank
borrowing capability, maintaining significant flexibility to finance
expanded capital programs or future acquisition opportunities as they
arise. The Trust's revolving production loan facility with a syndicate
of Canadian chartered banks provides that borrowings may be made by way
of prime loans, bankers' acceptances and/or US dollar LIBOR advances.
These advances bear interest at the banks' prime rate and/or at money
market rates plus a stamping fee. The production loan facility is
secured by a first floating charge debenture, general assignment of book
debts and the Trust's oil and natural gas properties and equipment. The
facility is subject to an annual review by the lenders, at which time a
lender can request conversion to a term loan for one year. Under the
term period, no principal payments would be required until one year
after the renewal date of June 30, 2005.

In 2005, Bonavista plans to invest up to $230 million to expand its Core
Regions, which will be financed through retained cash flow and bank
debt, if necessary. The Trust is committed to the fundamental principal
of maintaining financial flexibility and the prudent use of debt. As
such, the 2005 capital expenditure program is based on maintaining a
conservative amount of debt in our financing structure.

Unitholders' equity - As at December 31, 2004, Bonavista had 93,202,781
equivalent Trust Units outstanding. This includes 14,391,286
Exchangeable Shares and 4,400,000 Exchangeable Units, which combined are
exchangeable into 22,044,148 additional Trust Units. The exchange ratio
in effect at December 31, 2004 for Exchangeable Shares was 1.22603 to 1.
As of March 10, 2005 Bonavista had 94,681,519 equivalent Trust Units
outstanding.

As at December 31, 2004, Unitholders' equity included $197.8 million of
convertible debentures that have been issued by the Trust. The
debentures have been treated as equity, as the Trust may elect to
satisfy the debenture interest and principal obligation by the issuance
of Trust Units. Of the 100,000 7.5% convertible debentures issued on
January 29, 2004, there have been 37,174 debentures converted to Trust
Units during 2004, leaving 62,826 debentures with a principal amount of
$62.8 million outstanding at December 31, 2004. On December 31, 2004 the
Trust also issued 135,000 6.75% convertible debentures in conjunction
with the Core Region property acquisition in British Columbia. The
debentures have a principal amount of $135 million and as at December
31, 2004 none of these debentures have been converted. New accounting
pronouncements require that convertible debentures be disclosed as
liabilities rather than equity and the Trust will retroactively adopt
the new accounting treatment on January 1, 2005.

Distributions - The Trust declared distributions of $194.9 million
($3.08 per unit) to its Unitholders for the year ended December 31,
2004. They have been treated as equity, these distributions amounted to
only 56% of cash flow and 94% of net income generated during this
period. The remaining 44% of cash flow generated in this period was used
to fund our active exploitation, development and acquisition programs.
For the three months ended December 31, 2004, the Trust distributed
$53.2 million, amounting to 59% of cash flow generated during the
period, while the remaining 41% of cash flow was reinvested to fund
exploitation, development and acquisition programs. For Canadian Income
Tax purposes, the total distributions made per unit to Unitholders
throughout 2004 will be 98% taxable as "other income" to the Unitholder.

Bonavista announces its distribution policy on a quarterly basis. The
amount of the cash distribution is determined by the Board of Directors
and is dependent upon the commodity price environment, production
levels, and the amount of capital expenditures to be funded from cash
flow. Our distribution policy incorporates the withholding of cash flow
to finance capital expenditures, which will provide more sustainable
distributions in the long-term. On October 15, 2004, Bonavista announced
a 10% increase in its monthly distribution rate to $0.275 per Trust Unit
which is comprised of the regular base monthly distribution of $0.25 per
Trust Unit plus a supplementary monthly distribution of $0.025 per Trust
Unit due to the strength of current commodity prices.

Foreign ownership - As of March 1, 2005, Bonavista's foreign ownership
level was approximately 27% and is well below the 50% level that
compromises a mutual fund trust under proposed new legislation issued in
draft form by the Department of Finance. Bonavista will continue to
monitor these developments and if it is deemed appropriate, consider
alternatives to ensure continued compliance with the federal legislation.

Update on Regulatory and Financial Reporting Matters:

a) New accounting policies - On January 1, 2004, Bonavista retroactively
adopted and implemented new accounting policies pursuant to requirements
of the Canadian Institute of Chartered Accountants ("CICA") Handbook.
The new accounting policies adopted included: "Stock-based Compensation
and Other Stock-based Payments", "Asset Retirement Obligations" and
"Hedge Accounting" and are detailed further in Note 3 of the Notes to
the Consolidated Financial Statements. Effective for fiscal years
beginning on or after November 1, 2004 new accounting rules will require
convertible debentures to be disclosed as liabilities rather than in the
equity section of the consolidated balance sheet. The Trust will
retroactively adopt this new accounting rule on January 1, 2005.

b) Convertible debentures - As at December 31, 2004 the Trust included
its obligation relating to convertible debentures in Unitholders'
equity, as the Trust may elect to satisfy the debenture interest and
principal payments by the issuance of Trust Units. New accounting
pronouncements require effective January 1, 2005, that convertible
debentures be treated as liabilities rather than equity. The Trust will
retroactively adopt the new accounting treatment on January 1, 2005.

c) Exchangeable shares - On January 19, 2005, the Emerging Issues
Committee of the CICA issued EIC Abstract 151, Exchangeable Securities
Issued by Subsidiaries of Income Trusts. EIC 151 requires that
exchangeable shares issued by the subsidiaries of an income trust be
classified as non-controlling interest unless each of two conditions is
met. The first condition is that the holders of the exchangeable shares
are entitled to receive distributions of earnings economically
equivalent to distributions received by Unitholders. The second
condition is that the exchangeable shares are ultimately required, by a
specified date, to be exchanged for units of the trust and are
non-transferable to third parties. The EIC has revised EIC 151 such that
it will be necessary to satisfy both parts of the second condition, and
that the revisions will be effective for periods ending on or after June
30, 2005. The Trust is currently assessing the impact this will have on
the consolidated financial statements.

d) Internal control reporting - Multilateral Instrument 52-111 Reporting
on Internal Control over Financial Reporting and 52-109 Certification of
Disclosure in Issuers' Annual and Interim Filings set out the key
provisions relating to the evaluation, assessment and certification of
the internal controls over financial reporting (ICOFR) by management of
the Trust, and the audit by the Trust's external auditors of
managements' assessment of ICOFR. The objective of the new rules is to
improve the quality and reliability of financial reporting by requiring
issuers to evaluate internal control over the preparation of financial
statements. The new rules are phased in with final implementation of the
evaluation of the effectiveness by management and attestation by the
external auditors of ICOFR for financial years ending after June 29,
2006. The Trust is in the process of assessing the priority areas
relating to ICOFR and will be in full compliance by the final phase in
date.

Forward-Looking Statements - Certain information set forth in this
document, including management's assessment of Bonavista's future plans
and operations, contains forward-looking statements. By their nature,
forward-looking statements are subject to numerous risks and
uncertainties, some of which are beyond Bonavista's control, including
the impact of general economic conditions, industry conditions,
volatility of commodity prices, currency fluctuations, imprecision of
reserve estimates, environmental risks, competition from other industry
participants, the lack of availability of qualified personnel or
management, stock market volatility and ability to access sufficient
capital from internal and external sources. Readers are cautioned that
the assumptions used in the preparation of such information, although
considered reasonable at the time of preparation, may prove to be
imprecise and, as such, undue reliance should not be placed on
forward-looking statements. Bonavista's actual results, performance or
achievement could differ materially from those expressed in, or implied
by, these forward-looking statements or if any of them do so, what
benefits that Bonavista will derive therefrom. Bonavista disclaims any
intention or obligation to update or revise any forward-looking
statements, whether as a result of new information, future events or
otherwise. Investors are also cautioned that cash-on-cash yield
represents a blend of return of investor's initial investment and a
return on investors initial investment and is not comparable to
traditional yield on debt instruments where investors are entitled to
full return of the principal amount of debt on maturity in addition to a
return on investment through interest payments.

Management uses cash flow (before changes in non-cash working capital)
to analyze operating performance and leverage. Cash flow as presented
does not have any standardized meaning prescribed by Canadian Generally
Accepted Accounting Principles ("GAAP") and therefore it may not be
comparable with calculations of similar measures for other entities.
Cash flow as presented is not intended to represent operating cash flow
or operating profits for the period nor should it be viewed as an
alternative to cash flow from operating activities, net income or other
measures of financial performance calculated in accordance with Canadian
GAAP. All references to cash flow throughout this MD&A are based on
funds flow from operations before changes in non-cash working capital.

OUTLOOK

The Trust continues to benefit from all the same qualities that drove
the success of Bonavista Petroleum Ltd. over its first five and one half
years as a corporate entity. Today, we continue to apply the same proven
principles and execute that strategy in a disciplined and cost-effective
manner. The foundation of this strategy is to actively pursue low to
medium risk drilling opportunities on the extensive undeveloped land
base within our geographically concentrated areas of operations. We will
also continue to search for strategic acquisition opportunities where we
can add value utilizing our own technical expertise. To accomplish these
goals, we rely upon the many talents of the Bonavista team, who possess
a successful track record and a thorough understanding of our asset base
within the Western Canadian Sedimentary Basin. This prudent approach to
our capital investment program has been very effective in the past, and
together with our steadfast commitment and attention to detail, will
provide the foundation for the future success of the Trust.

For 2005, Bonavista's preliminary capital budget includes drilling
approximately 290 wells on existing lands. Similar to 2004, these
locations generally consist of low to medium risk prospects drilled
within close proximity of company owned and operated infrastructure. The
capital required to complete this drilling program and our complementary
acquisition program is between $210 to $230 million and should result in
average daily production of approximately 51,500 to 52,500 boe per day
in 2005.

We are proud of our achievements since converting to an energy trust in
mid-2003 and are very excited about the opportunities that exist for
Bonavista in the future. We sincerely appreciate the support of all our
Unitholders endorsing our decision to reorganize into the Trust. We
would also like to thank our employees for their significant effort and
their continued enthusiasm and excitement as we continue this new phase
as an energy trust. Our experienced team remains committed to applying
the same proven strategies within the more efficient trust structure to
continue adding Unitholder value in the oil and gas business for many
years to come.



Consolidated Balance Sheets
(thousands) December 31,
2004 2003
------------------------------------------------------------------------
------------------------------------------------------------------------
(unaudited) (restated)
Assets:
Accounts receivable $ 76,821 $ 57,076
Oil and natural gas properties and equipment
(note 7) 1,635,909 1,015,525
Goodwill 27,521 -
------------------------------------------------------------------------

$ 1,740,251 $ 1,072,601
------------------------------------------------------------------------
------------------------------------------------------------------------

Liabilities and Unitholders' Equity:
Accounts payable and accrued liabilities $ 92,286 $ 59,894
Long-term debt (note 8) 309,094 205,324
Other long-term obligations 9,102 -
Asset retirement obligations (notes 3 and 6) 58,531 38,654
Future income taxes (note 10) 136,202 138,381

Unitholders' equity: (note 9)
Unitholders' capital 645,335 334,712
Contributed surplus 2,475 1,152
Exchangeable shares 40,686 41,092
Convertible debentures 188,088 -
Accumulated earnings 534,153 334,230
Accumulated cash distributions (275,701) (80,838)
------------------------------------------------------------------------
1,135,036 630,348
------------------------------------------------------------------------
Commitments (note 12)
$ 1,740,251 $ 1,072,601
------------------------------------------------------------------------
------------------------------------------------------------------------


Consolidated Statements of Operations and Retained Earnings
(thousands, except per Three Months Year
unit amounts) ended ended
December 31, December 31,
2004 2003 2004 2003
------------------------------------------------------------------------
------------------------------------------------------------------------
(unaudited) (restated) (restated)
Revenues:
Production $ 155,077 $ 109,800 $ 599,445 $ 483,686
Royalties, net of Alberta
Royalty Tax Credit (30,141) (20,030) (125,674) (92,342)
Transportation costs (4,532) (4,571) (16,992) (15,635)
------------------------------------------------------------------------
120,404 85,199 456,779 375,709
------------------------------------------------------------------------

Expenses:
Operating 23,634 17,576 87,096 65,119
General and administrative 2,157 1,025 6,133 3,743
Financing 2,805 1,521 8,576 4,654
Unit-based compensation 382 24 1,408 550
Depreciation, depletion
and accretion 40,122 31,608 150,428 108,457
------------------------------------------------------------------------
69,100 51,754 253,641 182,523
------------------------------------------------------------------------
Income before income and
other taxes 51,304 33,445 203,138 193,186
Income and other taxes
(reduction) (note 10) (1,437) 971 (3,185) 29,973
------------------------------------------------------------------------

Net income 52,741 32,474 206,323 163,213

Accumulated earnings,
beginning of period, as
previously reported 482,769 294,617 325,924 228,413
Retroactive application of
changes in accounting
policies (note 3) - 7,181 8,306 5,878
Plan of Arrangement (note 5) - (42) - (63,274)
Interest on convertible
debentures (1,357) - (6,400) -
------------------------------------------------------------------------
Accumulated earnings, end
of period $ 534,153 $ 334,230 $ 534,153 $ 334,230
------------------------------------------------------------------------
------------------------------------------------------------------------
Net income per unit
- basic $ 0.63 $ 0.45 $ 2.49 $ 2.43
------------------------------------------------------------------------
------------------------------------------------------------------------
Net income per unit
- diluted $ 0.61 $ 0.45 $ 2.44 $ 2.41
------------------------------------------------------------------------
------------------------------------------------------------------------


Consolidated Statements of Cash Flows

(thousands) Three Months Year
ended ended
December 31, December 31,
2004 2003 2004 2003
------------------------------------------------------------------------
(unaudited) (restated) (restated)

Cash provided by (used in):

Operating Activities:
Net income $ 52,741 $ 32,474 $ 206,323 $ 163,213
Items not requiring cash
from operations:
Depreciation, depletion
and accretion 40,122 31,608 150,428 108,457
Unit-based compensation 382 24 1,408 550
Future income taxes
(reduction) (2,586) (34) (7,510) 12,831
------------------------------------------------------------------------

Funds flow from operations 90,659 64,072 350,649 285,051
Asset retirement expenditures (517) (765) (1,074) (1,393)
Decrease (Increase) in
non-cash working capital
items (265) (10,438) (11,088) (13,182)
------------------------------------------------------------------------

89,877 52,869 338,487 270,476
------------------------------------------------------------------------
------------------------------------------------------------------------

Financing Activities:
Issuance of equity,
net of issue costs 267,871 - 268,197 24,191
Issuance of convertible
debentures, net of issue
costs 129,491 - 225,262 -
Cash distributions and
interest on convertible
debentures (54,518) (41,903) (201,263) (80,838)
Increase in long-term debt 44,784 125,603 101,279 71,719
Plan of Arrangement costs,
net of income taxes
payable (note 5) - 5,640 - (47,304)
Decrease (Increase) in
non-cash working capital
items 2,832 2,610 4,110 15,707
------------------------------------------------------------------------

390,460 91,950 397,585 (16,525)
------------------------------------------------------------------------
------------------------------------------------------------------------

Investing Activities:
Business acquisition
(note 4) - - (69,924) -
Exploitation and
development (38,573) (38,361) (145,843) (135,956)
Property acquisitions (441,764) (106,458) (520,502) (147,098)
Property dispositions - - 197 29,103
------------------------------------------------------------------------

(480,337) (144,819) (736,072) (253,951)
------------------------------------------------------------------------
------------------------------------------------------------------------

Decrease in cash - - - -
Cash, beginning of period - - - -

------------------------------------------------------------------------
Cash, end of period $ - $ - $ - $ -
------------------------------------------------------------------------
------------------------------------------------------------------------


Notes to Consolidated Financial Statements
Years Ended December 31, 2004 and 2003


1. Structure of the Trust and Basis of Presentation:

Bonavista Energy Trust (the "Trust" or "Bonavista") was established on
July 2, 2003 under a Plan of Arrangement entered into by the Trust,
Bonavista Petroleum Ltd. ("BPL") and its subsidiaries and partnerships
and NuVista Energy Ltd. ("NuVista"). Under the Plan of Arrangement, a
wholly-owned subsidiary of the Trust amalgamated with BPL and became the
successor company (the "Company"). The Company is a wholly-owned
subsidiary of the Trust.

Prior to the Plan of Arrangement on July 2, 2003, the consolidated
financial statements include the accounts of BPL and its subsidiaries.
After giving effect to the Plan of Arrangement, the consolidated
financial statements include the accounts of the Trust and its
subsidiaries, and its partnerships, and have been prepared by management
in accordance with Canadian Generally Accepted Accounting Principles.

2. Significant accounting policies:

As the determination of many assets, liabilities, revenues and expenses
is dependent upon future events, the preparation of these consolidated
financial statements requires the use of estimates and assumptions,
which have been made using careful judgement. In particular, the amounts
recorded for depletion and depreciation of the petroleum and natural gas
properties and for asset retirement obligations are based on estimates
of reserves and future costs. By their nature, these estimates, and
those related to future cash flows used to assess impairment, are
subject to measurement uncertainty and the impact on the financial
statements of future periods could be material. In the opinion of
management, these consolidated financial statements have been properly
prepared within reasonable limits of materiality and within the
framework of the significant accounting policies summarized below:

(a) Principles of consolidation:

The consolidated financial statements include the accounts of the Trust
and its wholly-owned subsidiary, partnership and trust. All inter-entity
transactions have been eliminated.

(b) Oil and natural gas properties and equipment:

The Trust follows the full cost method of accounting, whereby all costs
associated with the exploration for and development of oil and natural
gas reserves are capitalized in cost centres on a country-by-country
basis. Such costs include land acquisitions, drilling, well equipment
and geological and geophysical activities. Gains or losses are not
recognized upon disposition of oil and natural gas properties unless
crediting the proceeds against accumulated costs would result in a
change in the rate of depletion by 20% or more.

Costs capitalized in the cost centres, including well equipment,
together with estimated future capital costs associated with proven
reserves, are depreciated and depleted using the unit-of-production
method which is based on gross production and estimated proven oil and
natural gas reserves as determined by independent engineers. The cost of
unproven properties is excluded from the depreciation and depletion
base. For purposes of the depreciation and depletion calculations, oil
and natural gas reserves are converted to a common unit of measure on
the basis of their relative energy content, being six thousand cubic
feet of natural gas for one barrel of oil. Facilities are depreciated
using the declining balance method over their useful lives, which range
from 12 to 15 years.

Oil and natural gas properties and equipment are evaluated in each
reporting period to determine whether the carrying amount in a cost
centre is recoverable and does not exceed the fair value of the
properties in the cost centre. The carrying amounts are assessed to be
recoverable when the sum of the undiscounted cash flows expected from
the production of proved reserves, the lower of cost and market of
unproved properties and the cost of major development projects exceeds
the carrying amount of the cost centre. When the carrying amount is not
assessed to be recoverable, an impairment loss is recognized to the
extent that the carrying amount of the cost centre exceeds the sum of
the discounted cash flows expected from the production of proved and
probable reserves, the lower of cost and market of unproved properties
and the cost of major development projects of the cost centre. The cash
flows are estimated using expected future product prices and costs, and
are discounted using a risk-free interest rate.

Effective January 1, 2004, Bonavista adopted the new accounting standard
relating to full cost accounting. The adoption of this new policy
resulted in no write-down to the carrying value of oil and natural gas
assets. Prior to January 1, 2004 the ceiling test amount was the sum of
the undiscounted cash flows expected from the production of proved
reserves, the lower of cost or market of unproved properties and the
cost of major development projects less estimated future costs for
administration, financing, site restoration and income taxes. The cash
flows were estimated using period end prices and costs.

(c) Joint operations:

A portion of Bonavista's oil and natural gas operations are conducted
jointly with others. Accordingly, the consolidated financial statements
reflect only Bonavista's proportionate interest in such activities.

(d) Goodwill:

Goodwill is tested for impairment on an annual basis in the fourth
quarter. If indications of impairment are present, a loss would be
charged to earnings for the amount that the carrying value of goodwill
exceeds its fair value.

(e) Asset retirement obligation:

Bonavista records a liability for the fair value of legal obligations
associated with the retirement of long-lived tangible assets in the
period in which they are incurred, normally when the asset is purchased
or developed. On recognition of the liability there is a corresponding
increase in the carrying amount of the related asset known as the asset
retirement cost, which is depleted on a unit-of-production basis over
the life of the reserves. The liability is adjusted each reporting
period to reflect the passage of time, with the accretion charged to
earnings, and for revisions to the estimated future cash flows. Actual
costs incurred upon settlement of the obligations are charged against
the liability. The impact of the adoption of the new standard is
described in note 3.

(f) Revenue recognition:

Revenues from the sale of petroleum and natural gas are recorded when
title passes to an external party.

(g) Hedge relationships:

From time to time, Bonavista may use swap agreements or other financial
instruments to hedge its exposure to fluctuations in oil and natural gas
prices. Financial instruments are not used for speculative purposes.
Bonavista formally assesses, both at the hedge's inception and on an
ongoing basis, whether the derivatives that are used in the hedging
transactions are highly effective in offsetting changes in fair value or
cash flows of the hedged item. These derivative contracts, accounted for
as hedges, are not recognized on the balance sheet. Realized gains and
losses on these contracts are recognized in petroleum and natural gas
revenue and cash flows in the same period in which the revenues
associated with the hedged transaction are recognized. Premiums paid or
received are deferred and amortized to earnings over the term of the
contract. Financial instruments that do not qualify as a hedge are
recorded on a mark to market basis with the resulting gains or losses
taken into income.

(h) Unit-based compensation:

Bonavista has equity incentive plans, which are described in note 9.
These unit right based compensation plans for employees do not involve
the direct award of units, or call for the settlement in cash or other
assets. Bonavista uses the fair value method for valuing the unit right
options grants on or after January 1, 2002. Under this method, the
compensation cost attributable to all the unit right options granted is
measured at fair value at the grant date and expensed over the vesting
period with a corresponding increase to contributed surplus. Upon the
exercise of the unit right options, consideration received together with
the amount previously recognized in contributed surplus is recorded as
an increase to Unitholders' capital.

(i) Income taxes:

The wholly owned subsidiaries of the Trust follow the liability method
of accounting for income taxes. Under this method, income tax
liabilities and assets are recognized for the estimated tax consequences
attributable to differences between the amounts reported in the
financial statement of the Trust's corporate subsidiaries and their
respective tax rates using substantively enacted future income tax
rates. The effective change in income tax rates on future tax
liabilities and assets is recognized in income in the period in which
the change occurs. Temporary differences arising on acquisitions result
in future tax assets and liabilities.

The Trust is a taxable entity under the Income Tax Act (Canada) and is
taxable only on income that is not distributed or distributable to the
unitholders. As the Trust distributes all its taxable income to the
unitholders and meets the requirements of the Income Tax Act (Canada)
applicable to the Trust, no provision for income taxes has been made by
the Trust.

(j) Per unit amounts:

Diluted per unit amounts reflect the potential dilution that could occur
if securities or other contracts to issue trust units were exercised or
converted to trust units. The treasury stock method is used to determine
the dilutive effect of unit incentive rights and other dilutive
instruments.

(k) Comparative figures:

The comparative figures have been restated to reflect the retroactive
changes in accounting policies.

3. Changes in accounting policies:

(a) Asset retirement obligations:

On January 1, 2004 the Trust adopted the new accounting policies on
Asset Retirement Obligations. This change in accounting policy has been
applied retroactively with restatement of prior periods presented for
comparative purposes. Previously, the Trust recognized a provision for
future site reclamation and abandonment costs calculated on the
unit-of-production method over the life of the petroleum and natural gas
properties based on total estimated proved reserves and estimated future
liability.

As a result of this change, net income for the year ended December 31,
2003 increased by $3.0 million ($4.7 million net of a future income tax
expense of $1.7 million). Basic and diluted net income per Trust Unit
calculations for 2003 increased by $0.04 and $0.04, respectively, as a
result of adopting this new policy. Furthermore, the asset retirement
obligation increased by $25.9 million, oil and natural gas properties
and equipment, net of accumulated depreciation and depletion increased
by $40.9 million, and the future income tax liability increased by $5.6
million as at December 31, 2003. Opening accumulated earnings at January
1, 2003 increased by $6.5 million ($10.3 million net of a future income
tax expense of $3.8 million) to reflect the cumulative impact of
accretion and depletion expense, less the previously recorded cumulative
site restoration provision.

Opening accumulated earnings at January 1, 2002 increased by $2.8
million ($4.7 million net of a future income tax expense of $1.9
million) to reflect the cumulative impact of accretion and depletion
expense, less the previously recorded cumulative site restoration
provision.

(b) Unit-based compensation

The Trust has adopted the new accounting standard for unit-based
compensation, which requires the use of the fair value method for
valuing unit option grants. Under this method, compensation cost
attributable to all unit options granted is measured at fair value at
the grant date and expensed over the vesting period with a corresponding
increase to contributed surplus. Upon the exercise of the unit options,
consideration received together, with the amount previously recognized
in contributed surplus is recorded as an increase to Unitholders'
capital.

The Trust has retroactively adopted the change in accounting standards
with restatement of prior periods. As a result of adopting the new
accounting standard, net income for the year ended December 31, 2003
decreased by $550,000 and contributed surplus increased by $550,000.
Both basic and diluted net income per unit calculations for the year
ended December 31, 2003 decreased by $0.01 per unit as a result of
adopting the new policy. Opening accumulated earnings at January 1, 2003
decreased by $602,000 to reflect the impact of 2002 unit-based
compensation expense, and opening retained earnings at January 1, 2004
decreased by $1.2 million to reflect the cumulative impact of 2002 and
2003 unit-based compensation expense.

(c) Hedge relationships:

Effective January 1, 2004, the CICA issued Accounting Guideline 13 -
Hedging Relationships, which deals with the identification, designation,
documentation and effectiveness of hedging relationships for the purpose
of applying hedge accounting. The guideline establishes conditions for
applying hedge accounting. All of the financial instruments entered into
by Bonavista to manage commodity price risk qualify as hedges under the
new accounting guideline. Therefore, Bonavista's hedging relationships
continue to be accounted for in the same manner as in previous periods
whereby realized gains and losses on hedges are netted against the item
to which they relate to in the income statement.

4. Acquisitions:

(a) On January 29, 2004, the Trust through BPL, acquired all of the
issued and outstanding shares of TriQuest Energy Corp., a public oil and
gas company, in consideration for cash. In connection with the
acquisition the Trust also received approximately $41.2 million of
income tax pools. The acquisition has been accounted for using the
purchase method, with results of operations included from the date of
acquisition. Details of the acquisition are as follows:



------------------------------------------------------------------------
Amount
------------------------------------------------------------------------
(thousands)

Net assets acquired:
Oil and natural gas properties $ 59,000
Goodwill 21,949
Bank debt (2,491)
Working capital deficiency (843)
Asset retirement obligation (1,600)
Future income taxes (6,091)
------------------------------------------------------------------------
Net assets acquired $ 69,924
------------------------------------------------------------------------
------------------------------------------------------------------------

(thousands)
Purchase consideration:
Cash $ 69,924
------------------------------------------------------------------------

Total purchase consideration $ 69,924
------------------------------------------------------------------------
------------------------------------------------------------------------


(b) On July 29, 2004, Bonavista acquired oil and natural gas properties
through a partnership for cash consideration of $15.1 million, with
results of operations included from the date of acquisition. In
conjunction with this acquisition Bonavista, recognized $5.6 million of
goodwill and $4.0 million of future income taxes.

(c) On December 31, 2004, the Trust, through BPL, acquired oil and
natural gas properties for cash, with results of operations included
from the date of acquisition. The acquisition was financed through a
combination of bank debt, the issuance of subscription receipts and
6.75% convertible extendible unsecured subordinated debentures. Details
of the acquisition are as follows:



------------------------------------------------------------------------
Amount
------------------------------------------------------------------------
(thousands)

Net assets acquired:

Oil and natural gas properties $ 452,750
Natural gas hedge liability and other
current liabilities (18,782)
Asset retirement obligation (11,000)
Excess demand and transmission obligations (9,102)
------------------------------------------------------------------------

Net assets acquired $ 413,866
------------------------------------------------------------------------
------------------------------------------------------------------------
(thousands)
Purchase consideration:
Cash $ 413,866
------------------------------------------------------------------------
Total purchase consideration $ 413,866
------------------------------------------------------------------------
------------------------------------------------------------------------


(d) On December 1, 2003, the Trust, through an affiliated limited
partnership, acquired all of the oil and natural gas properties of
Taurus Exploration in consideration for cash and exchangeable units. In
connection with the acquisition, the Trust received approximately $100.6
million of income tax pools. The acquisition has been accounted for
using the purchase method, with results of operations included from the
date of acquisition. Details of the acquisition are as follows:



------------------------------------------------------------------------
Amount
------------------------------------------------------------------------
(thousands) (restated)

Net assets acquired:

Oil and natural gas properties $ 273,258
Asset retirement obligation (3,115)
------------------------------------------------------------------------

Net assets acquired $ 270,143
------------------------------------------------------------------------
------------------------------------------------------------------------
(thousands)
Purchase consideration:
Cash $ 100,623
Exchangeable units (note 9) 169,520
------------------------------------------------------------------------

Total purchase consideration $ 270,143
------------------------------------------------------------------------
------------------------------------------------------------------------


5. Reorganization pursuant to the Plan of Arrangement:

Under the Plan of Arrangement in July 2003 Bonavista transferred certain
producing and exploratory oil and natural gas assets to NuVista. As this
was a related party transaction, assets and liabilities were transferred
at their book value. Details are as follows:



------------------------------------------------------------------------
Amount
------------------------------------------------------------------------
(thousands) (restated)

Oil and natural gas properties and equipment $ 63,688
Future income tax asset 14,400
------------------------------------------------------------------------
Total assets transferred 78,088
Long-term debt (29,103)
Asset retirement obligation (2,846)
------------------------------------------------------------------------
Net assets transferred 46,139
Plan of Arrangement costs, net of income tax
benefit of $7,609 17,135
------------------------------------------------------------------------
Total Plan of Arrangement and reduction in
accumulated earnings $ 63,274
------------------------------------------------------------------------
------------------------------------------------------------------------


Under the Plan of Arrangement, costs include the cancellation of share
options, financial advisor, legal fees and other associated costs. In
addition, $22.6 million of income taxes became due and payable as a
result of the shortened taxation period created by the Plan of
Arrangement. On completion of the Plan of Arrangement, Bonavista entered
into a Technical Services Agreement with NuVista. Under this agreement,
Bonavista receives payment for certain technical and administrative
services provided to NuVista, on a cost recovery basis. Pursuant to the
Technical Services Agreement, there were fees of $1.3 million charged
relating to general and administrative activities and $750,000 of fees
were charged relating to capital expenditure activities for the year
ended December 31, 2004 (period from July 2, 2003 to December 31, 2003 -
$372,000 and $317,000, respectively). As at December 31, 2004, amounts
payable to Bonavista were $3.5 million (2003 - $1.7 million).

6. Asset retirement obligations:

The Trust's asset retirement obligations result from net ownership
interests in oil and natural gas assets including well sites, gathering
systems and processing facilities. The Trust estimates that the total
undiscounted amount of expenditures required to settle its asset
retirement obligations is approximately $279.4 million, which will be
incurred over the next 51 years. The majority of the costs will be
incurred between 2015 and 2034. A credit-adjusted risk-free rate of 7.5%
was used to calculate the fair value of the asset retirement obligations.



A reconciliation of the asset retirement obligations is provided below:

------------------------------------------------------------------------
Year ended Year ended
December 31, 2004 December 31, 2003
------------------------------------------------------------------------
(thousands)

Balance, beginning of period $ 38,654 $ 32,154

Accretion expense 3,235 2,243
Acquisitions 12,600 3,708
Liabilities incurred 5,116 1,942
Liabilities settled (1,074) (1,393)
------------------------------------------------------------------------
Balance, end of period $ 58,531 $ 38,654
------------------------------------------------------------------------
------------------------------------------------------------------------


7. Oil and natural gas properties and equipment:

------------------------------------------------------------------------
Accumulated
depreciation Net book
December 31, 2004 Cost and depletion value
------------------------------------------------------------------------
(thousands)

Oil and natural gas
properties $ 1,661,635 $ 401,795 $ 1,259,840
Facilities 419,732 45,095 374,637
Office equipment 2,982 1,550 1,432
------------------------------------------------------------------------
$ 2,084,349 $ 448,440 $ 1,635,909
------------------------------------------------------------------------
------------------------------------------------------------------------

December 31, 2003
------------------------------------------------------------------------
(thousands) (restated)

Oil and natural gas
properties $ 1,069,957 $ 270,163 $ 799,794
Facilities 244,435 29,892 214,543
Office equipment 2,379 1,191 1,188
------------------------------------------------------------------------
$ 1,316,771 $ 301,246 $ 1,015,525
------------------------------------------------------------------------
------------------------------------------------------------------------


Unproved property costs of $129.2 million as at December 31, 2004 (2003
- $94.8 million) were excluded from the depreciation and depletion
calculation. Future development costs of $86.1 million (2003 - $ 43.9
million) were included in the depreciation and depletion calculation.

Bonavista has calculated the ceiling test under Accounting Guideline -16
as of December 31, 2004. Based on the calculation, the present value of
future net revenues from the Trust's proved reserves exceeds the
carrying value of the Trust's oil and natural gas properties and
equipment at December 31, 2004. The impairment test was calculated using
the benchmark reference prices at January 1 for the years 2005 to 2009
and adjusted for commodity differentials specific to Bonavista.



Benchmark Reference Price Forecasts

Year
------------------------------------------------------------------------
2005 2006 2007 2008 2009 Thereafter (1)
------------------------------------------------------------------------
WTI ($U.S./bbl) 42.00 40.00 38.00 36.00 34.00 33.00
------------------------------------------------------------------------
AECO ($Cdn/mcf) 6.60 6.35 6.15 6.00 6.00 6.00
------------------------------------------------------------------------

(1) Escalated at 2% per year in 2016 and beyond.


8. Long-term debt:

The Trust has a $400 million revolving production loan facility with a
syndicate of Canadian chartered banks, which provides that borrowings
may be made by way of prime loans, bankers' acceptances and/or US dollar
LIBOR advances. These advances bear interest at the banks' prime rate
and/or at money market rates plus a stamping fee. The production loan
facility is secured by a first floating charge debenture, general
assignment of book debts and the Trust's oil and natural gas properties
and equipment. The facility is subject to an annual review by the
lenders, at which time a lender can request conversion to a term loan
for one year. Under the term period, no principal payments would be
required until one year after the renewal date of June 30, 2005.

During the year ended December 31, 2004 the Trust paid cash interest of
$8.6 million (2003 - $4.4 million).



9. Unitholders' capital and exchangeable shares:

(a) Authorized:

Unlimited number of voting trust units and exchangeable shares.

(b) Issued and outstanding:

(i) Trust units:

------------------------------------------------------------------------
Number of
Units Amount
------------------------------------------------------------------------
(thousands)

Issued pursuant to Plan of Arrangement
(note 5) 49,827,082 $ 143,104
Issued for cash 1,136,100 17,950
Issued on conversion of exchangeable shares 1,469,736 4,141
Reacquired and cancelled (3,000) (3)
Issued on acquisition of oil and natural
gas properties 10,400,000 169,520
------------------------------------------------------------------------
Balance, December 31, 2003 62,829,918 334,712

Issued on conversion of convertible
debentures 1,616,245 37,174
Issued on conversion of exchangeable
shares 162,720 406
Issued upon exercise of trust unit
incentive rights 55,750 709
Unit-based compensation - 85
Issued for cash 10,900,000 281,765
Reacquired and cancelled (6,000) (56)
Issue costs, net of future tax benefit - (9,460)
------------------------------------------------------------------------
Balance, December 31, 2004 75,558,633 $ 645,335
------------------------------------------------------------------------
------------------------------------------------------------------------


(ii) Contributed surplus:
------------------------------------------------------------------------
Amount
------------------------------------------------------------------------
(thousands)

Balance, December 31, 2002 $ 602
Unit-based compensation 550
------------------------------------------------------------------------
Balance,December 31, 2003 1,152
Unit-based compensation 1,408
Exercise of trust unit incentive rights (85)
------------------------------------------------------------------------
Balance, December 31, 2004 $ 2,475
------------------------------------------------------------------------
------------------------------------------------------------------------


(iii) Exchangeable shares of BPL:
------------------------------------------------------------------------
Number of
Units Amount
------------------------------------------------------------------------
(thousands)

Issued pursuant to Plan of Arrangement
July 2, 2003 (note 5) 15,999,999 $ 45,233
Exchanged for trust units (1,464,748) (4,141)
------------------------------------------------------------------------

Balance, December 31, 2003 14,535,251 41,092
Exchanged for trust units (143,965) (406)
------------------------------------------------------------------------
Balance, December 31, 2004 14,391,286 $ 40,686
------------------------------------------------------------------------
------------------------------------------------------------------------
Exchange ratio, end of year 1.22603 -
------------------------------------------------------------------------
Trust units issuable on exchange 17,644,148 $ 40,686
------------------------------------------------------------------------
------------------------------------------------------------------------


Pursuant to the Plan of Arrangement, 49,827,082 Trust Units and
15,999,999 Exchangeable Shares were issued on the cancellation of the
common shares of Bonavista. Shareholders of Bonavista received a
combination of two units of the Trust or exchangeable shares of
Bonavista, and one share of NuVista, a new public exploration and
production company, for each common share held.

The exchangeable shares of Bonavista are convertible into trust units
based on the exchange ratio, which is adjusted monthly, to reflect the
distribution paid on the trust units. Cash distributions are not paid on
the exchangeable shares. The Exchangeable Shares of BPL are not listed
for public trading.



(iv) Unsecured subordinated convertible debentures:

------------------------------------------------------------------------
Number of
Debentures Amount
------------------------------------------------------------------------
(thousands)

7.5% Unsecured Subordinated Convertible
Debentures:
Issued 100,000 $ 100,000
Conversion to trust units (37,174) (37,174)
Issue costs - (4,338)
------------------------------------------------------------------------
Balance, December 31, 2004 62,826 $ 58,488
------------------------------------------------------------------------
------------------------------------------------------------------------


On January 29, 2004, Bonavista issued $100 million principal amount of
7.5% unsecured subordinated convertible debentures. The issue costs
related to this offering were $4.3 million. The debentures mature on
June 30, 2009, pay interest semi-annually and are convertible at the
option of the holder into Trust Units
of Bonavista at $23.00 per Unit plus accrued and unpaid interest. The
debentures and the related interest obligations are classified as equity
on the consolidated balance sheet as the Trust may elect to satisfy the
debenture interest and principal obligations by the issuance of Trust
Units.



------------------------------------------------------------------------
Number of
Debentures Amount
------------------------------------------------------------------------
(thousands)

6.75% Unsecured Subordinated Convertible
Extendible Debentures:
Issued 135,000 $ 135,000
Issue costs - (5,400)
------------------------------------------------------------------------
Balance, December 31, 2004 135,000 $ 129,600
------------------------------------------------------------------------
------------------------------------------------------------------------


On December 31, 2004, Bonavista issued $135 million principal amount of
6.75% unsecured subordinated convertible debentures. The issue costs
related to the offering were $5.4 million. The debentures have a final
maturity date, of June 30, 2010, and will be convertible at the option
of the holder into trust units of Bonavista at a price of $29 per trust
unit, plus accrued and unpaid interest. The debentures will pay interest
semi-annually on June 30 and December 31, with the initial interest
payment due on June 30, 2005. The debentures and the related interest
obligations are classified as equity on the consolidated balance sheet
as the Trust may elect to satisfy the debenture interest and principal
obligations by the issuance of Trust Units.

c) Trust unit incentive rights plan:

The Trust has a unit incentive rights plan that allows the Trust to
issue rights to acquire trust units to directors, officers, employees
and service providers. The Trust is authorized to issue up to 3,300,000
unit rights, however, the number of trust units reserved for issuance
upon exercise of the rights shall not at any time exceed 5% of the
aggregate number of issued and outstanding trust units of the Trust.
Unit right exercise prices are equal to the market price for the trust
units on the date the unit rights are granted. If certain conditions are
met, the exercise price per unit may be calculated by deducting from the
grant price the aggregate of all distributions, on a per unit basis,
made by the Trust after the grant date. Rights granted under the plan
vest over a four-year period and expire one year after each vesting date.



------------------------------------------------------------------------
Number of Unit Grant
Rights Price
------------------------------------------------------------------------
Balance, July 2, 2003 - $ -
Granted 1,430,000 16.31
Cancelled (6,400) (16.05)
Reduction in exercise price - (1.23)
-----------------------------------------------------------

Balance, December 31, 2003 1,423,600 15.08
Granted 367,300 22.47
Exercised (55,750) (12.71)
Cancelled (62,275) (15.52)
Reduction in exercise price - (2.88)
-----------------------------------------------------------

Balance, December 31, 2004 1,672,875 $ 13.88
------------------------------------------------------------------------
------------------------------------------------------------------------

Exercisable, December 31, 2004 294,625 $ 12.08
------------------------------------------------------------------------
------------------------------------------------------------------------

The following table summarizes trust unit rights outstanding and
exercisable under the plan at December 31, 2004:

------------------------------------------------------------------------
Trust Unit Trust Unit
Rights Outstanding Rights Exercisable
--------- -------------------------------------- ----------------------
Weighted
average Weighted Weighted
Range of Number remaining average Number average
exercise outstanding at contractual exercise exercisable exercise
prices year end life price at year end price
--------- -------------- ----------- -------- ----------- ---------
$12.00 to
13.34 1,318,175 3.5 $ 12.01 291,125 $ 12.01

18.08 to
25.01 354,700 4.4 20.84 3,500 18.08
-------------- -----------
$12.00 to
25.01 1,672,875 3.7 $ 13.88 294,625 $ 12.08
------------------------------------------------------------------------
------------------------------------------------------------------------


d) Unit-based compensation:

The Trust uses the fair value based method for the determination of the
unit-based compensation costs.

The fair value of each incentive right granted was estimated on the date
of grant using the Black-Scholes option-pricing model. In the pricing
model, the risk free interest was 3.5%; volatility of 16%; a forfeiture
rate of 10% and an expected life of 4.5 years. The fair value of the
options averages $4.08 per incentive right granted.

e) Per unit amounts:

During year ended December 31, 2004, there were 80,195,657 (2003 -
67,216,876) weighted average Trust Units outstanding. For the purpose of
calculating net income per unit-basic, the net income as reported has
been reduced by the interest on the convertible debentures for the
particular period that was charged to retained earnings. On a diluted
basis, there were 84,525,566 (2003 - 67,720,856) weighted average Trust
Units outstanding after giving effect for dilutive trust unit options.
Diluted per unit calculations for the Year ended December 31, 2004
includes an additional 4,329,909 Trust Units for the dilutive impact of
the unit rights incentive plan and the convertible debenture.

10. Income taxes:

The provision for income tax differs from the result which would have
been obtained by applying the combined Federal and Provincial income tax
rates to net income before taxes. This difference results from the
following items:



------------------------------------------------------------------------
Years ended December 31,
2004 2003
------------------------------------------------------------------------
Expected tax rate 40.2% 41.0%
------------------------------------------------------------------------
------------------------------------------------------------------------
(thousands) (restated)
Expected tax expense $ 81,661 $ 79,218

Non-deductible Crown payments,
net of The Alberta Royalty Tax Credit 17,376 23,801
Resource allowance (20,987) (29,941)
Effect of change in tax rate (2,014) (14,300)
Distributions to unitholders, debenture
holders, and income of non taxable entities (84,105) (31,846)
Other 559 65
Capital taxes 4,325 2,976
------------------------------------------------------------------------
Provision for income taxes (recovery) $ (3,185) $ 29,973
------------------------------------------------------------------------
------------------------------------------------------------------------
The provision for income taxes consists of:
Current $ 4,325 $ 17,142
Future (recovery) (7,510) 12,831
------------------------------------------------------------------------
Provision for income taxes (recovery) $ (3,185) $ 29,973
------------------------------------------------------------------------
------------------------------------------------------------------------

The significant components of future income tax liabilities and assets
as at December 31 are:

------------------------------------------------------------------------
2004 2003
------------------------------------------------------------------------
(thousands) (restated)

Oil and natural gas properties $ 131,293 $ 137,724
Facilities 28,967 14,720
Asset retirement obligations (19,901) (13,382)
Financing costs (4,157) (681)
------------------------------------------------------------------------

Future income taxes $ 136,202 $ 138,381
------------------------------------------------------------------------
------------------------------------------------------------------------

11. Financial instruments:

a) Hedge instruments:

As at December 31, 2004, the Trust has hedged by way of costless collars
the following crude oil:

------------------------------------------------------------------------
Average Price
WTI (US $/bbl) Term
------------------------------------------------------------------------
6,000 bbls/d $ 30.00 - $ 44.67 January 1, 2005 - March 31, 2005
6,000 bbls/d $ 32.33 - $ 50.80 April 1, 2005 - June 30, 2005
6,000 bbls/d $ 33.00 - $ 54.13 July 1, 2005 - September 30, 2005
6,000 bbls/d $ 33.67 - $ 54.96 October 1, 2005 - December 31, 2005
3,000 bbls/d $ 34.33 - $ 54.92 January 1, 2006 - March 31, 2006
------------------------------------------------------------------------


As at December 31, 2004, the market deficiency of these financial
instruments was approximately $2.3 million.

b) Physical purchase contracts:

As at December 31, 2004, the Trust has entered into direct sale costless
collars to sell natural gas as follows:

------------------------------------------------------------------------
Average Price
AECO (Cdn $/gj) Term
------------------------------------------------------------------------
50,000 gjs/day $ 6.64 - $ 10.73 January 1, 2005 - March 31, 2005
22,500 gjs/day $ 6.08 - $ 9.01 April 1, 2005 - October 31, 2005
------------------------------------------------------------------------


c) Fair market value of financial instruments:

The carrying values of Bonavista's monetary assets and liabilities
approximates their fair value. The fair market value of the 7.5%
unsecured subordinated convertible debentures and the 6.75% unsecured
subordinated convertible extendible debentures approximated $199.6
million as at December 31, 2004.

d) Interest and credit risk:

Bonavista is exposed to interest rate risk to the extent that the bank
debt is at a floating rate of interest. Bonavista's accounts receivable
are with customers and joint venture partners in the petroleum and
natural gas business and are subject to normal credit risks.
Concentration of credit risk is mitigated by marketing production to
numerous purchasers under normal industry sale and payment terms.
Bonavista routinely assesses the financial strength of its customers.
Bonavista may be exposed to certain losses in the event of
non-performance by counterparties to commodity price contracts.
Bonavista attempts to mitigate this risk by entering into transactions
with highly rated major financial institutions.

12. Commitments:

The following is a summary of the Trust's contractual obligations and
commitments as at December 31, 2004:



------------------------------------------------------------------------
Payments Due by Period
-----------------------------------------------------
2009
and
Total 2005 2006 2007 2008 thereafter
------------------------------------------------------------------------
(thousands)

Debt repayments(1) $309,094 $ - $309,094 $ - $ - $ -
Transportation
commitments 34,285 15,727 12,266 3,597 594 2,101
Office premises 4,265 509 573 758 780 1,645
------------------------------------------------------------------------
Total contractual
obligations $347,644 $16,236 $321,933 $4,355 $1,374 $ 3,746
------------------------------------------------------------------------
------------------------------------------------------------------------

(1) Based on the existing terms of the revolving credit facility, the
first payment may be required in 2006. However, it is expected that
the revolving credit facility will be extended and no repayments
will be required in the near term. (see note 8).


INVESTOR INFORMATION

Bonavista Energy Trust is a natural gas weighted energy trust which is
committed to maintaining its emphasis on operating high quality oil and
natural gas properties, delivering consistent distributions to
unitholders and ensuring financial strength and sustainability.

Corporate information provided herein contains forward-looking
information. The reader is cautioned that assumptions used in the
preparation of such information, particularly those pertaining to cash
distributions, production volumes, commodity prices, operating costs and
drilling results, which are considered reasonable by Bonavista at the
time of preparation, may be proven to be incorrect. Actual results
achieved during the forecast period will vary from the information
provided herein and the variations may be material. There is no
representation by Bonavista that actual results achieved during the
forecast period will be the same in whole or in part as those forecast.

-30-

Contact Information

  • FOR FURTHER INFORMATION PLEASE CONTACT:
    Bonavista Energy Trust
    Keith A. MacPhail
    President & CEO
    (403) 213-4315
    or
    Ronald J. Poelzer
    Executive Vice President & CFO
    (403) 213-4308
    or
    Greg R. Warner
    Vice President, Finance
    (403) 514-7307
    Website: www.bonavistaenergy.com
    or
    Bonavista Energy Trust
    700, 311 - 6th Avenue SW
    Calgary, AB T2P 3H2
    (403) 213-4300