Accrete Energy Inc.

Accrete Energy Inc.

March 24, 2005 14:43 ET

Accrete Energy Inc. Announces Year-End Results


NEWS RELEASE TRANSMITTED BY CCNMatthews

FOR: ACCRETE ENERGY INC.

TSX SYMBOL: GZ

MARCH 24, 2005 - 14:43 ET

Accrete Energy Inc. Announces Year-End Results

CALGARY, ALBERTA--(CCNMatthews - March 24, 2005) - Accrete Energy Inc.
(TSX:GZ) is pleased to announce the operational and financial results
for the period from its inception on June 1, 2004 to December 31, 2004.

Accrete Energy Inc. is an oil and gas exploitation and production
company with a solid base of production, balanced drilling portfolio and
an extensive development program in core company operated properties.
Accrete shares trade under the symbol "GZ" on the Toronto Stock Exchange.

Summary of Activities

During the seven months that the Corporation has been in existence
Accrete has accomplished the following:

- Listed on the Toronto Stock Exchange under the symbol "GZ" and
commenced trading on June 11, 2004;

- Raised a total of $12 million of equity through a private placement of
2,553,500 flow-through common shares to management and directors at
$1.00 per share, a private placement of 2,446,500 common shares at $1.00
per share and a private placement of 3,500,000 common shares at $2.05
per share on a bought deal basis;

- Recruited a team of technically competent professionals;

- Commenced a drilling program resulting in 12 (10.5 net) wells with an
83% success rate;

- Constructed 22.5 kilometers of pipeline and satellite and battery
facilities;

- Added 1,683,000 barrels equivalent of proved and another 1,146,000
barrels equivalent of probable reserves through the drill bit at a cost
of $8.31 per barrel of oil equivalent on a proved plus probable basis;

- Increased productive capability to approximately 1,200 barrels
equivalent per day.

2004 Highlights include the following:



---------------------------------------------------------------------
Three Month Three Month One Month Seven Month
Period Ended Period Ended Period Ended Period Ended
December September June December
31, 2004 30, 2004 30, 2004 31, 2004
---------------------------------------------------------------------
Financial:
---------------------------------------------------------------------
Petroleum and
Natural Gas
Revenues $872,979 $490,332 $197,505 $1,560,816
---------------------------------------------------------------------
Cash Flow from
Operations $170,925 $187,466 $(76,866) $281,525
---------------------------------------------------------------------
Per Share Basic $0.01 $0.02 $(0.01) $0.03
---------------------------------------------------------------------
Loss
---------------------------------------------------------------------
Per Share Basic $(0.03) $(0.02) $(0.02) $(0.07)
---------------------------------------------------------------------
Capital
Expenditures $11,396,386 $4,601,231 $6,059,187 $22,056,804
---------------------------------------------------------------------
Wells Drilled -
Gross 6 4 2 12
---------------------------------------------------------------------
Wells Drilled -
Net 5.10 3.16 1.80 10.06
---------------------------------------------------------------------
Total Assets $25,350,827 $12,996,324 $11,851,229 $25,350,827
---------------------------------------------------------------------
Working Capital $(5,641,230) $(1,498,222) $2,926,143 $(5,641,230)
---------------------------------------------------------------------
Weighted Average
Common Shares
Outstanding
---------------------------------------------------------------------
Basic 12,966,632 9,732,936 9,732,936 11,123,123
---------------------------------------------------------------------
Diluted 13,514,398 10,659,392 10,659,392 11,670,889
---------------------------------------------------------------------
Employee Stock
Options
Outstanding 926,845 926,845 926,845 926,845
---------------------------------------------------------------------
Operations:
---------------------------------------------------------------------
Natural Gas
Production -
mcf/d 1,262 896 913 1,057
---------------------------------------------------------------------
Average Selling
Price - Natural
Gas - $/mcf $6.11 $5.94 $7.21 $6.18
---------------------------------------------------------------------
Oil Production -
bbl/d 18 - - 8
---------------------------------------------------------------------
Average Selling
Price - Crude
Oil - $/bbl $49.93 - - $49.93
---------------------------------------------------------------------
NGL Production -
bbl/d 18 - - 8
---------------------------------------------------------------------
Average Selling
Price - NGL -
$/bbl $46.79 - - $46.79
---------------------------------------------------------------------
Royalties at 6:1
- $/boe $7.46 $4.56 $4.54 $6.17
---------------------------------------------------------------------

Operating
Expenses at 6:1
- $/boe $4.85 $3.89 $5.87 $4.64
---------------------------------------------------------------------
Field netback at
6:1 - $/boe $26.07 $27.80 $30.88 $27.21
---------------------------------------------------------------------
General and
administrative
expenses $422,092 $186,233 $227,237 $835,562
---------------------------------------------------------------------


Business Environment

The oil and gas industry enjoyed a period of strong cash flows and
earnings due to relatively high oil and gas prices. Oil prices
increased dramatically due to political instability in producing
countries abroad, low US inventories and in areas in demand, especially
in emerging global economies. Canadian natural gas prices weakened
slightly in the last half of 2004 due to high storage levels caused by
increased industry activity and mild summer and fall weather.

Drilling activity increased significantly in response to these
conditions. This caused increases in the prices that the industry paid
for goods and services and resulted in an increase in drilling costs and
operating expenses over the year.

Competition for exploitable lands increased with the emergence of
several new oil and gas companies that operate in Alberta. This
increased the value of oil and gas property.

Operational Activities

Production



---------------------------------------------------------------------
3 Months Ended 3 Months Ended 1 Month Ended 7 Months Ended
December 31, September 30, June 30, December 31,
2004 2004 2004 2004
---------------------------------------------------------------------
Oil (bbl/d) 18 - - 8
---------------------------------------------------------------------
NGL (bbl/d) 18 - - 8
---------------------------------------------------------------------
Total Oil/NGL
(bbl/d) 36 - - 16
---------------------------------------------------------------------
Gas (mcf/d) 1,262 896 913 1,057
---------------------------------------------------------------------
Total (boe/d) 246 149 152 192
---------------------------------------------------------------------


Production increased in the fourth quarter with the addition of the
Claresholm area in mid-October, and the Harmattan area at the end of
December, with total production at an exit rate of approximately 1,200
boe/d. While production is capacity constrained in some areas,
management expects volume increases throughout 2005 as capacity is added
and more wells are tied in from the successful 2004 drilling program.



---------------------------------------------------------------------
3 Months Ended 3 Months Ended
December 31, 2004 September 30, 2004
---------------------------------------------------------------------
Gas Oil/ Total Gas Oil/ Total
NGL NGL
---------------------------------------------------------------------
Area mcf/d bbl/d boe/d mcf/d bbl/d boe/d
---------------------------------------------------------------------
Atlee-Buffalo 106 - 17 235 - 39
---------------------------------------------------------------------
Boltan 654 7 116 661 - 110
---------------------------------------------------------------------
Claresholm 251 1 43 - - -
---------------------------------------------------------------------
Harmattan 251 28 70 - - -
---------------------------------------------------------------------
Total 1,262 36 246 896 - 149
---------------------------------------------------------------------


---------------------------------------------------------------------
1 Month Ended 7 Months Ended
June 30, 2004 December 31, 2004
---------------------------------------------------------------------
Gas Oil/ Total Gas Oil/ Total
NGL NGL
---------------------------------------------------------------------
Area mcf/d bbl/d boe/d mcf/d bbl/d boe/d
---------------------------------------------------------------------
Atlee-Buffalo 216 - 36 177 - 30
---------------------------------------------------------------------
Boltan 697 - 116 664 3 114
---------------------------------------------------------------------
Claresholm - - - 109 1 19
---------------------------------------------------------------------
Harmattan - - - 107 12 29
---------------------------------------------------------------------
Total 913 - 152 1,057 16 192
---------------------------------------------------------------------


Revenue

---------------------------------------------------------------------
($) 3 Months Ended 3 Months Ended 1 Month Ended 7 Months Ended
December 31, September 30, June 30, December 31,
2004 2004 2004 2004
---------------------------------------------------------------------
Oil 82,165 - - 82,165
---------------------------------------------------------------------
NGL 79,670 - - 79,670
---------------------------------------------------------------------
Gas 711,144 490,332 197,505 1,398,981
---------------------------------------------------------------------
Total 872,979 490,332 197,505 1,560,816
---------------------------------------------------------------------



---------------------------------------------------------------------
($) 3 Months Ended 3 Months Ended
December 31, 2004 September 30, 2004
---------------------------------------------------------------------
Area Gas Oil/ Total Gas Oil/ Total
NGL NGL
---------------------------------------------------------------------
Atlee-Buffalo 83,465 - 83,465 109,441 - 109,441
---------------------------------------------------------------------
Boltan 319,374 35,004 354,378 380,891 - 380,891
---------------------------------------------------------------------
Claresholm 165,729 9,188 174,917 - - -
---------------------------------------------------------------------
Harmattan 142,576 117,643 260,219 - - -
---------------------------------------------------------------------
Total 711,144 161,835 872,979 490,332 - 490,332
---------------------------------------------------------------------

---------------------------------------------------------------------
($) 1 Month Ended 7 Months Ended
June 30, 2004 December 31, 2004
---------------------------------------------------------------------
Area Gas Oil/ Total Gas Oil/ Total
NGL NGL
---------------------------------------------------------------------
Atlee-Buffalo 45,565 - 45,565 238,471 - 238,471
---------------------------------------------------------------------
Boltan 151,940 - 151,940 852,205 35,004 887,209
---------------------------------------------------------------------
Claresholm - - - 165,729 9,188 174,917
---------------------------------------------------------------------
Harmattan - - - 142,576 117,643 260,219
---------------------------------------------------------------------
Total 197,505 - 197,505 1,398,981 161,835 1,560,816
---------------------------------------------------------------------


The revenue increases in the fourth quarter over the third quarter are
largely related to the volume increases. Commodity prices realized by
Accrete were marginally lower in the fourth quarter, but were offset by
increased volumes.



Royalties

---------------------------------------------------------------------
3 Months Ended 3 Months Ended 1 Month Ended 7 Months Ended
December 31, September 30, June 30, December 31,
2004 2004 2004 2004
---------------------------------------------------------------------
Area Total $ Rate Total $ Rate Total $ Rate Total $ Rate
---------------------------------------------------------------------
Atlee-
Buffalo 14,784 18% 28,678 26% 9,955 22% 53,417 22%
---------------------------------------------------------------------
Boltan 27,630 8% 34,444 9% 10,382 7% 72,456 8%
---------------------------------------------------------------------
Claresholm 51,947 30% - - - - 51,947 30%
---------------------------------------------------------------------
Harmattan 75,327 29% - - - - 75,327 29%
---------------------------------------------------------------------
Total 169,688 19% 63,122 13% 20,337 10% 253,147 16%
---------------------------------------------------------------------


The corporate royalty rate rose in the fourth quarter as new production
was added in Claresholm and Harmattan, offsetting the lower rates at
Boltan and Atlee-Buffalo. The Boltan area has a crown royalty holiday
which contributes to the lower rates at that property.



Production Expenses

---------------------------------------------------------------------
($) 3 Months Ended 3 Months Ended
December 31, 2004 September 30, 2004
---------------------------------------------------------------------
Area $ $/boe $/mcfe $ $/boe $/mcfe
---------------------------------------------------------------------
Atlee- Buffalo (2,471) (1.66) (0.28) 3,000 0.84 0.14
---------------------------------------------------------------------
Boltan 46,456 4.34 0.72 50,511 4.98 0.83
---------------------------------------------------------------------
Claresholm 35,799 9.05 1.51 - - -
---------------------------------------------------------------------
Harmattan 30,490 4.75 0.79 - - -
---------------------------------------------------------------------
Total 110,274 4.87 0.81 53,511 3.89 0.65
---------------------------------------------------------------------



---------------------------------------------------------------------
($) 1 Month Ended 7 Months Ended
June 30, 2004 December 31, 2004
---------------------------------------------------------------------
Area $ $/boe $/mcfe $ $/boe $/mcfe
---------------------------------------------------------------------
Atlee-Buffalo 9,138 8.48 1.41 9,667 1.53 0.26
---------------------------------------------------------------------
Boltan 17,659 5.06 0.84 114,626 4.71 0.79
---------------------------------------------------------------------
Claresholm - - - 35,799 9.05 1.51
---------------------------------------------------------------------
Harmattan - - - 30,490 4.75 0.79
---------------------------------------------------------------------
Total 26,797 5.87 0.98 190,582 4.64 0.77
---------------------------------------------------------------------


Operating expenses rose in the fourth quarter as new production was
added at Claresholm and Harmattan. Crude oil operating expense averaged
$3.69 per barrel and natural gas operating expense averaged $0.78 per
mcf. It is anticipated that these costs per unit of production will
gradually decline as the areas stabilize and more wells are tied in,
providing greater economies of scale.


Field and Corporate Netbacks

Field Netback



---------------------------------------------------------------------
($/boe) 3 Months 3 Months 1 Month 7 Months
Ended Ended Ended Ended
December September June December
Area 31, 2004 30, 2004 30, 2004 31, 2004
---------------------------------------------------------------------
Atlee-Buffalo 43.78 21.58 24.51 27.78
---------------------------------------------------------------------
Boltan 22.98 29.20 35.55 28.78
---------------------------------------------------------------------
Claresholm 21.25 - - 21.25
---------------------------------------------------------------------
Harmattan 24.18 - - 24.18
---------------------------------------------------------------------
Field Netback 26.17 27.20 32.94 27.17
---------------------------------------------------------------------


New production volumes provided revenue streams that offset increased
royalty rates and operating expenses.

Corporate Netback



---------------------------------------------------------------------
$ 3 Months 3 Months 1 Month 7 Months
Ended Ended Ended Ended
December September June December
Area 31, 2004 30, 2004 30, 2004 31, 2004
---------------------------------------------------------------------
Field Netback 593,017 373,699 150,371 1,117,087
---------------------------------------------------------------------
General and Administrative 422,092 186,233 227,237 835,562
---------------------------------------------------------------------
Corporate Netback 170,925 187,466 (76,866) 281,525
---------------------------------------------------------------------




General and Administrative Expense

---------------------------------------------------------------------
$ 3 Months 3 Months 1 Month 7 Months
Ended Ended Ended Ended
December September June December
31, 2004 30, 2004 30, 2004 31, 2004
---------------------------------------------------------------------
Salary & Benefits 473,517 79,266 44,122 596,905
---------------------------------------------------------------------
General Office Expenses 67,645 73,101 20,807 161,553
---------------------------------------------------------------------
Professional Fees, Dues,
etc 1,988 8,907 160,187 171,082
---------------------------------------------------------------------
Computer Services and
Software 18,382 72,935 22,698 114,015
---------------------------------------------------------------------
Insurance (10,553) 25,060 3,052 17,559
---------------------------------------------------------------------
550,979 259,269 250,866 1,061,114
---------------------------------------------------------------------
Recoveries (128,887) (73,036) (23,629) (225,552)
---------------------------------------------------------------------
Total 422,092 186,233 227,237 835,562
---------------------------------------------------------------------


General and administrative expenses reflect the startup operations of
Accrete. As at the end of 2004, key management, staff, and other
resources were in place for 2005. General and administrative expenses
represent relatively fixed costs once the startup phase has been
completed. Accrete will strive to meet its target of $2.00 per barrel
for such costs in 2005 as production ramps up significantly.

Depletion Depreciation & Accretion

Depletion, depreciation and accretion of the asset retirement obligation
for 2004 totaled $500,511 or $12.18 per boe.

Income Taxes

The Corporation is not liable for any cash taxes.

As at December 31, 2004, all expenditures needed to satisfy flow-through
share requirements had been incurred.

The tax benefits related to the $2,553,500 of flow-through shares were
renounced in February 2005 with an effective date of renunciation of
December 31, 2004.


At December 31, 2004, the Corporation's exploration and development
expenditures and undepreciated capital costs total $19,535,556 and
comprise:



---------------------------------------------------------------------
$
---------------------------------------------------------------------
Cumulative Canadian Oil and Gas Property Expense 3,312,242
---------------------------------------------------------------------
Cumulative Canadian Development Expense 6,186,956
---------------------------------------------------------------------
Cumulative Canadian Exploration Expense 4,625,599
---------------------------------------------------------------------
Undepreciated Capital Cost 5,410,759
---------------------------------------------------------------------
19,535,556
---------------------------------------------------------------------


These costs may be carried forward indefinitely to reduce future taxable
income. There are also $1,795,902 of non-capital losses which may be
carried forward for seven years to reduce future taxable income.

Cash Flow and Net Deficit

Cash flow for the seven months ended December 31, 2004 was $281,525
($0.03 per share), and $170,925 for the fourth quarter. Production
increases account for the large increase in cash flow for the quarter.
As production increases in 2005, and without start-up costs, cash flow
will increase.

Under the plan of arrangement, Olympia Energy Inc. transferred certain
producing and exploratory oil and natural gas properties to the
Corporation.

As this was a related party transaction, assets were transferred at a
book value of $1,125,284 for exploratory properties and $2,393,027 for
developed but non-producing properties.

A private placement of 5,000,000 common shares at an issuance price of
$1.00 per share was made concurrently with the plan.

An amount of $745,625 was booked to share capital and to deficit to
increase the stated value of the shares issued to $1.00 per share, being
the fair value of the shares issued.

Capital Expenditures



---------------------------------------------------------------------
$
---------------------------------------------------------------------
Drilling and completions 12,748,751
---------------------------------------------------------------------
Equipping and tie-ins 4,770,059
---------------------------------------------------------------------
Office equipment 68,305
---------------------------------------------------------------------
Total cash expenditures 17,587,115
---------------------------------------------------------------------
Allowance for future restoration expenditures 482,378
---------------------------------------------------------------------
Transferred pursuant to plan of arrangement 3,518,311
---------------------------------------------------------------------
Atlee-Buffalo property, acquired for shares 469,000
---------------------------------------------------------------------
Total 22,056,804
---------------------------------------------------------------------


The Corporation drilled 12 gross (10.5 net) wells with a success rate of
83%. Included in equipping and tie-ins is the cost to build and
commission the Harmattan pipeline and facilities, which was instrumental
in achieving an exit rate of 1,200 boe/d.

Liquidity and Capital Resources


---------------------------------------------------------------------
$
---------------------------------------------------------------------
Exploration and development program funding
---------------------------------------------------------------------
Cash flow 281,525
---------------------------------------------------------------------
Change in non-cash working capital 6,180,908
---------------------------------------------------------------------
Issue of shares, net 11,664,360
---------------------------------------------------------------------
Cash, end of period (539,678)
---------------------------------------------------------------------
Capital expenditures during the period 17,587,115
---------------------------------------------------------------------


The capital intensive nature of the Corporation's activities may create
a negative working capital position from time to time.

A $2.5 million acquisition/development facility was in place at year-end.

As at December 31, 2004, negative working capital was $5,641,230. No
amounts were drawn against the credit facility that was in place at that
time. Nevertheless, the Corporation was technically in default of its
banking agreement that stipulated that it must maintain a working
capital ratio of 1:1 including the undrawn amount of the credit facility
in current assets.

This situation was rectified subsequent to year-end when a $10 million
Revolving Operating Demand Loan facility together with a $5 million
Non-revolving Acquisition/Development Demand Loan facility was arranged
with the Corporation's bank.

The Revolving Operating Demand Loan facility will bear interest at bank
prime plus one quarter per cent. This facility has no specific terms of
repayment aside from the bank's right of demand and periodic review.

The Non-revolving Acquisition/Development Demand Loan facility will bear
interest at bank prime plus one per cent, is repayable in monthly
installments over the half-life of the reserves being financed and is
subject to the bank's right of demand and periodic review.

Both credit facilities are secured by a general assignment of book
debts, a $25,000,000 debenture with a first floating charge over all
assets with a negative pledge and an undertaking to provide fixed
charges on the Corporation's major producing reserves at the request of
the bank.

Accrete intends to fund its capital expenditure program from internally
generated cash flow, debt, and new equity if available on favorable
terms.

The Corporation's drilling program is very flexible and can be tailored
to available funds. Success in its focus areas means that additional
funds will be raised though bank debt or additional share issuances or
both to expedite the drilling program. Commodity prices and production
volumes have a large impact on the ability for the Corporation to
generate adequate cash flow to meet its obligations. A prolonged
decrease in commodity prices would negatively affect cash flow from
operations and would also likely result in a reduction in the amount of
bank loan available. If the capital expenditure program does not result
in sufficient additional reserves and/or production it would likely have
a negative impact on the Corporation's liquidity. A lack of or
restricted access to natural gas processing facilities would have a
similar effect. A prolonged decrease in commodity prices would also
likely affect the availability of funds through the public equity market.

Management expects that continued high commodity prices will contribute
to healthy cash flow and a buoyant public capital market, and that funds
will be readily available. Management also believes that adequate bank
financing will be available to supplement cash flow to fund its
exploitation program. New equity will be used in such funding if
available on favourable terms.

Outlook

The outlook for Accrete Energy Inc. is very positive.

The Corporation will continue to focus its development efforts on its
acreage at Harmattan and Claresholm with a view to increasing reserves
and production. Continued drilling in the Boltan area will be dependent
upon production testing from the gas well drilled in early 2005.

Given timely access to natural gas processing facilities and reasonable
success at the drill bit, the Corporation forecasts that it will
generate at least $12 million of cash flow in 2005. This estimate was
based on an oil price of $48 Canadian Edmonton par and a gas price of
$6.00 Canadian at the plant gate.

The Corporation will continue to seek opportunities in new areas while
aggressively developing the core areas discussed in this report. It is
expected that up to 34 wells will be drilled in 2005, with capital
expenditures totaling $23.4 million. This program includes land
purchases, tie-ins and infrastructure, and is highly adaptable to
changing information and conditions.

Critical Accounting Estimates

Oil and Gas Accounting

The Corporation follows the full-cost method of accounting whereby all
costs related to the acquisition, exploration and development of
petroleum and natural gas properties, net of government incentives, are
capitalized. Such costs include lease acquisition costs, geological and
geophysical expenditures, costs of drilling both productive and
non-productive wells and related plant and production equipment costs.

Proceeds on disposition of petroleum and natural gas properties are
accounted for as a reduction of capitalized costs with no gains or
losses recognized unless such disposition results in a change of 20% or
more in the depletion rate.

Capitalized costs, together with estimated future capital costs
associated with proved reserves are depleted and depreciated using the
unit-of-production method based on estimated gross proved reserves of
petroleum and natural gas as determined by independent engineers. For
purposes of this calculation, reserves and production are converted to
equivalent units of oil based on the relative energy content of six
thousand cubic feet of natural gas to one barrel of oil. Unproved
properties are excluded from the depletion base until it is determined
whether proved reserves are attributable to the properties or impairment
occurs.

Office furniture and fixtures are recorded at cost and are depreciated
over their useful lives on a declining balance basis at 20% per annum.

The net amount at which petroleum and natural gas properties are carried
is subject to a cost recovery test (the "ceiling test").

Oil and gas assets are evaluated at least annually to determine that the
costs are recoverable and do not exceed the fair value of the
properties. The costs are assessed to be recoverable if the sum of the
undiscounted cash flows expected from the production of proved reserves
and the lower of cost and market of unproved properties exceed the
carrying value of the oil and gas assets. If the carrying value of the
oil and gas assets is not assessed to be recoverable, an impairment loss
will be recognized to the extent that the carrying value exceeds the sum
of the discounted cash flows expected from the production of proved and
probable reserves and the lower of cost or market value of unproved
properties. The cash flows are estimated using expected future product
prices and costs and are discounted using the risk free rate.

The Corporation records a liability for the fair value of legal
obligations associated with the retirement of long-lived 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 using the unit-of- production method.
The liability is adjusted in each reporting period to reflect the
passage of time, with the accretion charged to earnings, and for
revisions to the estimated future cash flows.

Income Taxes

The determination of the Corporation's income and other tax liabilities
requires interpretation of complex laws and regulations often involving
multiple jurisdictions. All tax filings are subject to audit and
potential reassessment after a considerable lapse of time. Accordingly,
the actual income tax liability may differ significantly from the
liability estimated or recorded.

Other Estimates

The accrual method of accounting requires management to incorporate
certain estimates, including estimates of revenues, royalties and
production costs, at a specific reporting date, but for which actual
revenues and costs have not yet been received; and estimates on capital
projects which are in progress or recently completed, where actual costs
have not been received at a specific reporting date.

The Corporation ensures that the individuals with the most knowledge of
the activity are responsible for the estimate. These estimates are then
reviewed for reasonableness and past estimates are compared to actual
results in order to make informed decisions on future estimates.


Stock Based Compensation

The Corporation has not calculated an estimated forfeiture rate for
stock options that will not vest, and will account for actual
forfeitures as they occur. The fair value of each stock option is
determined at each grant date using the Black-Scholes model.

Risks

Accrete, in common with other companies participating in the oil and gas
business in Canada, is exposed to a number of business risks. These
risks can be categorized as operational, financial and regulatory, with
some beyond the Corporation's control.

Operational risks include finding and developing oil and natural gas
reserves on an economic basis, reservoir production performance,
commodity marketing risk and the risk that employees and contract
services can be hired and retained on a cost effective basis.

Accrete has mitigated these risks to the extent possible by employing a
team of highly qualified professionals, providing a compensation scheme
that will reward above average performance and by maintaining long term
relationships with its suppliers.

Accrete also maintains an insurance program that is consistent with
industry practice that should protect against the loss of assets through
fire, blowout, pollution and other untoward events and the resultant
business interruption.

Accrete maintains an inventory of prospects that are within the scope of
the Corporation's key areas and are strategically diverse so as to
minimize the Corporation's exposure to drilling risk. Furthermore,
Accrete employs the latest technological methods in that quest.

Financial risks include commodity prices, and to some extent, interest
rates and the Canadian/US exchange rate. The Corporation may employ
financial instruments, when prudent, to lessen the effects of such
risks, but it has no such contracts in place at this time.



Financial Statements

Accrete Energy Inc.
Balance Sheets

December 31, September 30, June 30,
2004 2004 2004
$ $ $
---------------------------------------------------------------------

ASSETS

Current assets
Cash 539,678 1,390,200 4,693,236
Accounts receivable 3,180,061 1,155,661 1,104,835
Prepaid expenses 71,773 60,045 74,971
---------------------------------------------------------------------
3,791,512 2,605,906 5,873,042
Property and equipment (note 3) 21,559,315 10,390,418 5,978,187
---------------------------------------------------------------------
25,350,827 12,996,324 11,851,229
---------------------------------------------------------------------
---------------------------------------------------------------------

LIABILITIES

Current liabilities
Accounts payable and
accrued liabilities 9,432,742 4,104,128 2,946,899
---------------------------------------------------------------------
9,432,742 4,104,128 2,946,899

Asset retirement
obligation (note 6) 485,400 76,820 75,500
---------------------------------------------------------------------
9,918,142 4,180,948 3,022,399
---------------------------------------------------------------------

SHAREHOLDERS' EQUITY

Share capital (note 5) 16,594,505 9,722,221 9,732,821
Contributed surplus 356,836 203,820 50,955
Deficit (1,518,656) (1,110,665) (954,946)
---------------------------------------------------------------------
15,432,685 8,815,376 8,828,830
---------------------------------------------------------------------
25,350,827 12,996,324 11,851,229
---------------------------------------------------------------------
---------------------------------------------------------------------

See accompanying notes to financial statements


Accrete Energy Inc.
Statements of Loss and Deficit

Seven Months Three Months Three Months One
Ended Ended Ended Month
Ended
December 31, December 31, September 30, June 30,
2004 2004 2004 2004
Revenue $ $ $ $

Petroleum and
natural gas revenue 1,560,816 872,979 490,332 197,505
Royalties (253,147) (169,688) (63,122) (20,337)
---------------------------------------------------------------------
1,307,669 703,291 427,210 177,168
---------------------------------------------------------------------

Expenses

Production expenses 190,582 110,274 53,511 26,797
General and
administrative, net
of recoveries 835,562 422,092 186,233 227,237
Stock based
compensation cost
(note 5) 356,836 153,016 152,865 50,955
Depletion, depreciation
and accretion 500,511 228,691 190,320 81,500
---------------------------------------------------------------------
1,883,491 914,073 582,929 386,489
---------------------------------------------------------------------
Loss before income
taxes 575,822 210,782 155,719 209,321
Future income taxes
(note 7) 197,209 197,209 - -
---------------------------------------------------------------------
Net loss for the
period 773,031 407,991 155,719 209,321
Deficit arising on
transfer of assets
(note 2) 745,625 - - 745,625
Deficit - beginning
of period - 1,110,665 954,946 -
---------------------------------------------------------------------
Deficit - end of
period 1,518,656 1,518,656 1,110,665 954,946
---------------------------------------------------------------------
---------------------------------------------------------------------
Weighted average
number of shares
(note 5) 11,123,123 12,966,632 9,732,936 9,732,936

Loss per share:
Basic 0.07 0.03 0.02 0.02
Diluted 0.07 0.03 0.02 0.02


See accompanying notes to financial statements



Accrete Energy Inc.
Statements of Cash Flows

Seven Months Three Months Three Months One
Ended Ended Ended Month
Ended
December 31, December 31, September 30, June 30,
2004 2004 2004 2004
---------------------------------------------------------------------
Cash provided by
(used in): $ $ $ $
Operating Activities
Net loss for the
period (773,031) (407,991) (155,719) (209,321)
Items not affecting
cash:
Stock based
compensation cost 356,836 153,016 152,865 50,955
Future income taxes 197,209 197,209 - -
Depletion, depreciation
and accretion 500,511 228,691 190,320 81,500
---------------------------------------------------------------------
Funds flow 281,525 170,925 187,466 (76,866)
Change in non-cash
working capital
(note 9) 168,224 115,088 221,448 (168,312)
---------------------------------------------------------------------
449,749 286,013 408,914 (245,178)
---------------------------------------------------------------------
Investing Activities
Property and equipment
additions (17,587,115) (10,989,008) (4,601,231)(1,996,876)
Change in non-cash
working capital
(note 9) 6,012,684 3,177,398 899,881 1,935,405
---------------------------------------------------------------------
(11,574,431) (7,811,610) (3,701,350) (61,471)
---------------------------------------------------------------------
Financing Activities
Issue of capital
stock - net 11,664,360 6,675,075 (10,600) 4,999,885
---------------------------------------------------------------------

Increase (decrease)
in cash 539,678 (850,522) (3,303,036) 4,693,236
Cash - beginning
of period - 1,390,200 4,693,236 -
---------------------------------------------------------------------
Cash - end of period 539,678 539,678 1,390,200 4,693,236

See accompanying notes to financial statements


Accrete Energy Inc.
Notes to the Financial Statements
For the period ended December 31, 2004



1. Significant Accounting Policies

As the determination of many assets, liabilities, revenues and expenses
is dependent upon future events, the preparation of these financial
statements requires the use of estimates and assumptions which have been
made using careful judgment. In the opinion of management, these
financial statements have been properly prepared within reasonable
limits of materiality and within the framework of the significant
accounting policies summarized below.

Accrete Energy Inc. ("Accrete") commenced operations on June 1, 2004
when it acquired assets under a plan of arrangement entered into by
Provident Energy Trust, Provident Energy Ltd., Olympia Energy Inc. and
Accrete Energy Inc.

Oil and Gas Operations

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

The Company follows the full-cost method of accounting whereby all costs
related to the acquisition, exploration and development of petroleum and
natural gas properties, net of government incentives, are capitalized.
Such costs include lease acquisition costs, geological and geophysical
expenditures, costs of drilling both productive and non-productive wells
and related plant and production equipment costs.

Proceeds on disposition of petroleum and natural gas properties are
accounted for as a reduction of capitalized costs with no gains or
losses recognized unless such disposition results in a change of 20% or
more in the depletion rate.

Capitalized costs, together with estimated future capital costs
associated with proved reserves are depleted and depreciated using the
unit-of-production method based on estimated gross proved reserves of
petroleum and natural gas as determined by independent engineers. For
purposes of this calculation, reserves and production are converted to
equivalent units of oil based on the relative energy content of six
thousand cubic feet of natural gas to one barrel of oil. Unproved
properties are excluded from the depletion base until it is determined
whether proved reserves are attributable to the properties or impairment
occurs.

Office furniture and fixtures are recorded at cost and are depreciated
over their useful lives on a declining balance basis at 20% per annum.

The net amount at which petroleum and natural gas properties are carried
is subject to a cost recovery test (the "ceiling test").

Oil and gas assets are evaluated at least annually to determine that the
costs are recoverable and do not exceed the fair value of the
properties. The costs are assessed to be recoverable if the sum of the
undiscounted cash flows expected from the production of proved reserves
and the lower of cost and market of unproved properties exceed the
carrying value of the oil and gas assets. If the carrying value of the
oil and gas assets is not assessed to be recoverable, an impairment loss
will be recognized to the extent that the carrying value exceeds the sum
of the discounted cash flows expected from the production of proved and
probable reserves and the lower of cost or market value of unproved
properties. The cash flows are estimated using expected future product
prices and costs and are discounted using a risk-free rate of interest.

The Company records a liability for the fair value of legal obligations
associated with the retirement of long-lived 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 using the unit-of-production method.
The liability is adjusted in each reporting period to reflect the
passage of time, with the accretion charged to earnings, and for
revisions to the estimated future cash flows.

Joint Ventures

A significant portion of the Company's exploration and production
activities are conducted jointly with others and the financial
statements reflect only the Company's proportionate interest in such
activities.

Stock Based Compensation

The Company has an employee stock option plan. The compensation cost in
respect of this plan is recognized in the financial statements using the
fair market value method and the cost is recognized over the vesting
period of the underlying security. The Company has not incorporated an
estimated forfeiture rate for stock options that will not vest and will
account for actual forfeitures as they occur.

Financial Instruments

The Company may enter into financial instruments and physical delivery
commodity contracts from time to time to protect future earnings and
cash flows from the potential impact of fluctuating commodity prices and
not for speculative purposes. Gains or losses on these contracts will be
included in revenues at the time the underlying commodity is sold or
when the positions are settled.

To date the Company has not entered into any such agreements.

The carrying values of the Company's monetary assets and liabilities
approximate their fair values.

Measurement Uncertainty

Amounts recorded for depreciation and depletion, the provision for asset
retirement and abandonment costs and amounts used for ceiling test
calculations are based on estimates of oil and natural gas reserves. The
Company's reserve estimates are reviewed annually by an independent
engineering firm. By their nature, these estimates of reserves and
future cash flows are subject to measurement uncertainty, and the impact
on the financial statements of future periods could be material.

Per Share Amounts

The Company uses the treasury stock method to determine the dilutive
effect of stock options and other dilutive instruments. This method
assumes that proceeds received from the exercise of in-the-money stock
options and other dilutive instruments are used to purchase common
shares at the average market price during the year.

Flow-through Shares

The resource expenditure deductions for income tax purposes related to
exploratory and development activities funded by flow-through share
arrangements are renounced to investors in accordance with income tax
legislation. Future income tax liabilities and share capital are
adjusted by the estimated cost of the renounced income tax deductions
when the related flow-through expenditures are renounced to investors.

Income Taxes

The Company follows the liability method of accounting for income taxes.
Temporary differences arising from the differences between the tax basis
of an asset or liability on the balance sheet are used to calculate
future income tax assets or liabilities. Future income tax assets or
liabilities are calculated using the rates that are anticipated to be in
effect in the periods that the temporary differences are expected to
reverse.

2. Transfer of Assets and Commencement of Operations

Under the plan of arrangement, Olympia Energy Inc. transferred certain
producing and exploratory oil and natural gas properties to the Company
and each former shareholder of Olympia received one tenth of a common
share of the Company for each Olympia share owned.

A total of 4,263,936 common shares of the Company were issued pursuant
to the plan.

As this was a related party transaction, assets were transferred at a
book value of $1,125,284 for unproved exploratory properties and
$2,393,027 for developed but non- producing properties.

A private placement of 5,000,000 common shares at an issuance price of
$1.00 per share was made concurrently with the plan.

An amount of $745,625 was booked to share capital and to deficit to
increase the stated value of the shares issued to $1.00 per share, being
the fair value of the shares issued.

3. Property and Equipment



---------------------------------------------------------------------
$
---------------------------------------------------------------------
Petroleum and natural gas properties and equipment 21,988,499
---------------------------------------------------------------------
Furniture, fixtures and other 68,305
---------------------------------------------------------------------
22,056,804
---------------------------------------------------------------------
Less: Accumulated depletion and depreciation (497,489)
---------------------------------------------------------------------
21,559,315
---------------------------------------------------------------------


At December 31, 2004 costs of $ 100,000 ($ 7,723,391 at September 30,
2004, and $1,125,284 at June 30, 2004) with respect to unproved
properties have been excluded from costs subject to depletion. No
overhead charges have been capitalized to petroleum and natural gas
properties.

4. Credit Facility

At December 31, 2004 the Company's credit facility comprised a
non-revolving Acquisition/Development Demand Loan facility with a total
available credit amount of $2,500,000 which bears interest at bank prime
plus one percent, is repayable in monthly installments over the
half-life of the reserves being financed and is subject to the bank's
right of demand and periodic review.

The facility is secured by a general assignment of book debts, a
$25,000,000 debenture with a first floating charge over all assets with
a negative pledge and an undertaking to provide fixed charges on the
Company's major producing reserves at the request of the bank.

No amounts were drawn against this facility at December 31, 2004. The
Company's credit facility was renegotiated subsequent to year end (see
note 10).

5. Share Capital

Authorized:

An unlimited number of common shares and an unlimited number of
preferred shares.

Issued and outstanding:



Common Shares Number of Amounts
Shares $
---------------------------------------------------------------------

Issued upon transfer from
Olympia Energy Inc. 4,263,936 4,263,936
---------------------------------------------------------------------
Issued for oil and gas properties 469,000 469,000
---------------------------------------------------------------------
Issued on private placement
- flow-through shares 2,553,500 2,553,500
---------------------------------------------------------------------
Issued on private placement 2,446,500 2,446,500
---------------------------------------------------------------------
Share issuance costs (115)
---------------------------------------------------------------------
Balance, June 30, 2004 9,732,936 9,732,821
---------------------------------------------------------------------
Share issuance costs (10,600)
---------------------------------------------------------------------
Balance, September 30, 2004 9,732,936 9,722,221
---------------------------------------------------------------------
Issued on private placement 3,500,000 7,175,000
---------------------------------------------------------------------
Share issuance costs (net of tax) (302,716)
---------------------------------------------------------------------
Balance, December 31, 2004 13,232,936 16,594,505
---------------------------------------------------------------------
- basic weighted average 11,123,123
---------------------------------------------------------------------
- diluted 11,670,889
---------------------------------------------------------------------

The following table reconciles the common shares used in calculating
net earnings per common share:
---------------------------------------------------------------------
Weighted average common shares outstanding - basic 11,123,123
---------------------------------------------------------------------
Effect of dilutive stock options 547,766
---------------------------------------------------------------------
Weighted average common shares outstanding - diluted 11,670,889
---------------------------------------------------------------------


The Company incurred losses for the periods ended June 30, September 30
and December 31, 2004. The use of the diluted number of shares
outstanding in the calculation of diluted earnings per share is
considered antidilutive. Accordingly, the basic weighted average number
of common shares outstanding was used in the calculation of diluted loss
per share.

Tax benefits related to the $2,553,500 of flow-through shares will be
renounced to flow-through shareholders in February 2005.

Stock Options

Under the terms of the Accrete Energy Inc. 2004 Incentive Stock Option
Plan (the "plan"), directors, officers and employees are eligible to be
granted options to purchase common shares. The plan provides for
granting up to 10% of the number of issued and outstanding common shares
that were outstanding immediately after the completion of the plan of
arrangement and the June private placement of common shares. The Company
granted all stock options that were available to officers, employees and
directors at that time.

Subsequently, it was necessary to grant additional stock options as
inducement to secure the employment of officers and employees. These
stock options have been granted subject to the approval of the
shareholders.

The following table summarizes information about stock options
outstanding at December 31, 2004:



Grant Price Options Weighted Number Weighted
Outstanding Average Exercisable Average
Remaining (Vested) Exercise
Contractual Price
Life ($/Share)
---------------------------------------------------------------------
$1.00 926,845 4.4 Years 308,948 $1.00
---------------------------------------------------------------------
$2.30 (a) 40,000 4.8 Years - $2.30
---------------------------------------------------------------------
$2.60 (a) 395,000 4.9 Years - $2.60
---------------------------------------------------------------------
$2.89 (a) 5,000 4.9 Years - $2.89
---------------------------------------------------------------------
$3.12 (a) 40,000 4.9 Years - $3.12
---------------------------------------------------------------------
1,406,845 4.6 Years 308,948 $1.55
---------------------------------------------------------------------

(a) Subject to approval by the shareholders.


The exercise price of each of the options granted equals the market
price of the Company's common shares on the date of grant.

The options granted have a term of five years to expiry. All but the
$1.00 stock options vest equally over a three year period commencing on
the first anniversary of the date of grant. The $1.00 stock options vest
equally over a three year term commencing with the date of grant.

The Company has accounted for its employee stock options granted that
were not subject to shareholder approval using the fair value method.
The fair value for such options was estimated at the date of grant using
a Black-Scholes Option Pricing Model to be $1,000,993 ($1.08 per option
granted) This value is charged to stock based compensation cost over the
vesting period. A total of $356,836 was charged in 2004.

The following assumptions were used in calculating the fair value:



---------------------------------------------------------------------
Volatility factor of expected market price 45%
---------------------------------------------------------------------
Weighted average risk-free interest rate (%) 4.5
---------------------------------------------------------------------
Dividend yield (%) -
---------------------------------------------------------------------
Weighted average expected life of options (years) 4
---------------------------------------------------------------------


The aggregate value of the stock options that have been granted subject
to shareholder approval is estimated at the dates of grant to be
$571,050 ($1.19 per option granted) computed in the same manner using a
volatility factor of 45%, a weighted average risk-free interest rate of
4.5% and a weighted average expected life of 5 years. A total of $44,127
would have been charged to stock based compensation for the period ended
December 31, 2004 had the stock based compensation related to such stock
options been recognized in the accounts.

The reconciling item between basic and diluted earnings per share is
outstanding stock options that have been approved by the shareholders.

6. Asset Retirement Obligation

Asset retirement obligation comprises:



---------------------------------------------------------------------
$
---------------------------------------------------------------------
Liabilities incurred 482,378
---------------------------------------------------------------------
Accretion expense 3,022
---------------------------------------------------------------------
Balance, end of period 485,400
---------------------------------------------------------------------


The total future asset retirement obligation was estimated based on the
Company's net ownership interest in all wells and facilities, the
estimated costs to abandon and reclaim the wells and facilities and the
estimated timing of the costs to be incurred in future periods. The
total undiscounted amount of the estimated cash flows to settle the
asset retirement obligation is approximately $1,417,000 which will be
incurred over the next twenty five years. A credit adjusted risk-free
rate of 7% was used to calculate the fair value of the obligations.


7. Income Taxes

As at December 31, 2004 all expenditures that were required to satisfy
requirements of the flow-through shares had been incurred.

The tax benefits related to the $2,553,500 of flow-through shares will
be renounced in February 2005 with an effective date of renunciation of
December 31, 2004. Accordingly, a tax liability of approximately
$986,000 will be recorded in the first quarter of 2005 to reflect the
tax effect of the renunciation.

At December 31, 2004, the Company's exploration and development
expenditures and undepreciated capital costs total $19,535,556 and
comprise:



---------------------------------------------------------------------
$
---------------------------------------------------------------------
Cumulative Canadian Oil and Gas Property Expense 3,312,242
---------------------------------------------------------------------
Cumulative Canadian Development Expense 6,186,956
---------------------------------------------------------------------
Cumulative Canadian Exploration Expense 4,625,599
---------------------------------------------------------------------
Undepreciated capital cost 5,410,759
---------------------------------------------------------------------
19,535,556
---------------------------------------------------------------------


These costs may be carried forward indefinitely to reduce future
taxable income.

The following reconciles the difference between income tax recorded
and the expected income tax expense obtained by applying the expected
income tax rate to earnings before taxes:


---------------------------------------------------------------------
$
---------------------------------------------------------------------

Loss before income taxes (575,822)
---------------------------------------------------------------------
Expected income tax recovery at the combined federal
and provincial statutory rate of 38.62% (222,382)
---------------------------------------------------------------------
Crown royalties 51,241
---------------------------------------------------------------------
Resource allowance (39,134)
---------------------------------------------------------------------
Stock based compensation cost 137,810
---------------------------------------------------------------------
Attributed crown royalty income (4,806)
---------------------------------------------------------------------
Other 2,287
---------------------------------------------------------------------
Valuation allowance 272,193
---------------------------------------------------------------------
Future income tax expense 197,209
---------------------------------------------------------------------


The following table summarizes the tax effect of temporary
differences.

---------------------------------------------------------------------
$
---------------------------------------------------------------------
Future income tax assets (liabilities):
---------------------------------------------------------------------
Carrying value of capital assets in excess of tax basis (781,576)
---------------------------------------------------------------------
Asset retirement obligation 187,461
---------------------------------------------------------------------
Share issue costs 167,925
---------------------------------------------------------------------
Losses carried forward 693,577
---------------------------------------------------------------------
Attributed crown royalty income 4,806
---------------------------------------------------------------------
272,193
---------------------------------------------------------------------
Less: Valuation allowance (272,193)
---------------------------------------------------------------------
-
---------------------------------------------------------------------


8. Financial Instruments

The Company's financial instruments recognized on the balance sheets
consist of cash, accounts receivable, prepaid expenses, and accounts
payable and accrued expenses. The fair value of all financial
instruments classified as current assets or current liabilities
approximate their carrying amounts due to the short-term maturity of
these instruments.

A portion of the Company's accounts receivable are from joint venture
partners in the oil and gas business and are subject to normal industry
credit risk. Purchasers of the Company's petroleum and natural gas
products are subject to an internal credit review designed to mitigate
the risk of non-payment and the carrying value reflects management's
assessment of the associated credit risks.

The Company is exposed to fluctuations in commodity prices that are
based in foreign currency.

The Company has not entered into any contracts during the year that
would have reduced its exposure to fluctuations in commodity prices or
exchange rates.


9. Supplemental Cash Flow Information

Change in non-cash working capital comprises:



---------------------------------------------------------------------
Seven Three Three One
Months Months Months Month
Ended Ended Ended Ended
December December September June
31, 2004 31, 2004 30, 2004 30, 2004
---------------------------------------------------------------------
$ $ $ $
---------------------------------------------------------------------
Accounts receivable (3,180,061) (2,024,400) (50,826) (1,104,835)
---------------------------------------------------------------------
Prepaid expenses (71,773) (11,728) 14,926 (74,971)
---------------------------------------------------------------------
Accounts payable and
accrued liabilities 9,432,742 5,328,614 1,157,229 2,946,899
---------------------------------------------------------------------
Change in non-cash
working capital 6,180,908 3,292,486 1,121,329 1,767,093
---------------------------------------------------------------------

---------------------------------------------------------------------
Relating to:
---------------------------------------------------------------------
Investing activities 6,012,684 3,177,398 899,881 1,935,405
---------------------------------------------------------------------
Operating activities 168,224 115,088 221,448 (168,312)
---------------------------------------------------------------------
6,180,908 3,292,486 1,121,329 1,767,093
---------------------------------------------------------------------


10. Subsequent Event

The Company arranged new credit facilities with its bank subsequent to
year-end.

The credit facilities comprise:

A Revolving Operating Demand Loan facility with a credit limit of
$10,000,000.

A Non-revolving Acquisition/Development Demand Loan facility with a
credit limit of $5,000,000.

The Revolving Operating Demand Loan facility will bear interest at bank
prime plus one quarter percent.

This facility has no specific terms of repayment aside from the bank's
right of demand and periodic review.

The Non-revolving Acquisition/Development Demand Loan facility will bear
interest at bank prime plus one percent, is repayable in monthly
installments over the half-life of the reserves being financed and is
subject to the bank's right of demand and periodic review.

Both credit facilities are secured by a general assignment of book
debts, a $25,000,000 debenture with a first floating charge over all
assets with a negative pledge and an undertaking to provide fixed
charges on the Company's major producing reserves at the request of the
bank.

Reserves and Future Net Revenue

The following is a summary of Accrete's crude oil, natural gas and NGL
reserves and the discounted value of future net cash flow as evaluated
in the GLJ Report. The pricing used in the forecast and constant price
evaluations is set forth in the notes to the tables.

All evaluations of future revenue are after the deduction of future
income tax expenses (unless otherwise noted in the tables) royalties,
development costs, production costs and well abandonment costs but
before consideration of indirect costs such as administrative, overhead
and other miscellaneous expenses. The estimated future net revenue
contained in the following tables does not necessarily represent the
fair market value of Accrete's reserves. There is no assurance that the
forecast price and cost assumptions contained in the GLJ Report will be
attained and variances could be material. Other assumptions and
qualifications relating to costs and other matters are summarized in the
notes to the following tables. The recovery and reserves estimates on
Accrete's properties described herein are estimates only. The actual
reserves on Accrete's properties may be greater or less than those
calculated.

The following tables provide reserves data and a breakdown of future net
revenue by component and production group using forecast prices and
costs and constant prices and costs.



Oil and Gas Reserves
Based on Constant Prices and Costs(8)

Light and Medium Oil Heavy Oil
---------------------------------------
Gross(1) Net(1) Gross(1) Net(1)
(mbbl) (mbbl) (mbbl) (mbbl)
---------------------------------------
Proved Developed Producing(2)(5) 2.9 2.4 - -
Proved Developed Non-Producing(2)(6) - - - -
Proved Undeveloped(2)(7) - - - -
---------------------------------------
Total Proved(2) 2.9 2.4 - -
Total Probable(3) 1.2 1.0 - -
---------------------------------------
Total Proved Plus Probable(2)(3) 4.2 3.4 - -
---------------------------------------------------------------------

Natural Gas Natural Gas
Liquids
------------------------------------
Gross(1) Net(1) Gross(1) Net(1)
(mmcf) (mmcf) (mbbl) (mbbl)
------------------------------------
Proved Developed Producing(2)(5) 4,344 3,161 194 132
Proved Developed Non-Producing(2)(6) 2,932 2,176 379 271
Proved Undeveloped(2)(7) 515 354 79 55
------------------------------------
Total Proved(2) 7,790 5,691 652 458
Total Probable(3) 6,347 4,550 334 230
------------------------------------
Total Proved Plus Probable(2)(3) 14,138 10,241 985 688
---------------------------------------------------------------------


Net Present Values of Future Net Revenue
Based on Constant Prices and Costs(8)


Before Deducting Income Taxes
Discounted At
-------------------------------------------
0% 5% 10% 15% 20%
($000) ($000) ($000) ($000) ($000)
-------------------------------------------
Proved Developed
Producing(2)(5) 25,175 21,682 19,374 17,697 16,398
Proved Developed
Non-Producing(2)(6) 21,515 18,838 16,823 15,249 13,983
Proved Undeveloped(2)(7) 2,759 2,462 2,214 2,005 1,827
-------------------------------------------
Total Proved(2) 49,450 42,981 38,411 34,950 32,208
Total Probable(3) 31,724 24,054 20,032 17,337 15,320
-------------------------------------------
Total Proved Plus
Probable(2)(3) 81,174 67,035 58,443 52,287 47,528
-------------------------------------------


After Deducting Income Taxes
Discounted At
-------------------------------------------
0% 5% 10% 15% 20%
($000) ($000) ($000) ($000) ($000)
-------------------------------------------
Proved Developed
Producing(2)(5) 23,240 20,021 17,879 16,320 15,114
Proved Developed
Non-Producing(2)(6)
Proved Undeveloped(2)(7)
-------------------------------------------
Total Proved(2) 38,984 33,733 30,052 27,285 25,105
Total Probable(3)
-------------------------------------------
Total Proved Plus
Probable(2)(3) 59,764 49,176 42,703 38,070 34,500
-------------------------------------------



Total Future Net Revenue
(Undiscounted)
Based on Constant Prices and Costs(8)

Revenue Royalties Operating Development
Costs Costs
($000) ($000) ($000) ($000)
---------------------------------------------------------------------
Total Proved(2) 76,661 17,339 8,073 1,427
Total Proved
Plus Probable (2)(3) 131,189 31,001 13,046 5,470


Future Future
Net Net
Abandonment Revenue Revenue
and Before After
Reclamation Income Income Income
Costs Taxes Taxes Taxes
($000) ($000) ($000) ($000)
---------------------------------------------------------------------
Total Proved(2) 372 49,450 10,465 38,984
Total Proved
Plus Probable (2)(3) 497 81,174 21,410 59,764



Future Net Revenue by Production Group Based Upon
Constant Prices and Costs(8)
Future Net Revenue Before Income Taxes
(Discounted at 10%/Year)
($000)
---------------------------------------------------------------------
Light and medium crude oil 1,970
Heavy oil -
Associated gas and non-associated gas(9) 36,441
Light and medium crude oil 2,519
Heavy oil -
Associated gas and non-associated gas(9) 55,925


Oil and Gas Reserves
Based on Forecast Prices and Costs(10)

Light and Medium Oil Heavy Oil
----------------------------------------
Gross(1) Net(1) Gross(1) Net(1)
(mbbl) (mbbl) (mbbl) (mbbl)
----------------------------------------
Proved Developed Producing(2)(5) 2.8 2.3 - -
Proved Developed Non-Producing(2)(6) - - - -
Proved Undeveloped(2)(7) - - - -
----------------------------------------
Total Proved(2) 2.8 2.3 - -
Total Probable(3) .5 .4 - -
----------------------------------------
Total Proved Plus Probable(2)(3) 3.3 2.7 - -
---------------------------------------------------------------------

Natural Gas Natural Gas
Liquids
----------------------------------------
Gross(1) Net(1) Gross(1) Net(1)
(mmcf) (mmcf) (mbbl) (mbbl)
----------------------------------------
Proved Developed Producing(2)(5) 4,344 3,169 194 132
Proved Developed Non-Producing(2)(6) 2,915 2,160 376 269
Proved Undeveloped(2)(7) 515 354 79 55
----------------------------------------
Total Proved(2) 7,773 5,683 649 456
Total Probable(3) 6,359 4,556 335 231
----------------------------------------
Total Proved Plus Probable(2)(3) 14,132 10,239 984 687
---------------------------------------------------------------------



Net Present Values of Future Net Revenue
Based on Forecast Prices and Costs(10)

Before Deducting Income Taxes
Discounted At
-------------------------------------------
0% 5% 10% 15% 20%
($000) ($000) ($000) ($000) ($000)
-------------------------------------------
Proved Developed
Producing(2)(5) 23,477 20,316 18,241 16,735 15,565
Proved Developed
Non-Producing(2)(6) 19,456 17,209 15,502 14,154 13,059
Proved Undeveloped(2)(7) 2,504 2,242 2,024 1,839 1,681
-------------------------------------------
Total Proved(2) 45,437 39,767 35,767 32,727 30,305
Total Probable(3) 29,936 22,003 18,230 15,796 13,995
-------------------------------------------
Total Proved Plus
Probable 75,373 61,770 53,997 48,523 44,300
-------------------------------------------


After Deducting Income Taxes
Discounted At

-------------------------------------------
0% 5% 10% 15% 20%
($000) ($000) ($000) ($000) ($000)
-------------------------------------------
Proved Developed
Producing(2)(5) 22,042 19,042 17,051 15,617 14,508
Proved Developed
Non-Producing(2)(6)
Proved Undeveloped(2)(7)
-------------------------------------------
Total Proved(2) 36,331 31,595 28,295 25,809 23,842
Total Probable(3)
-------------------------------------------
Total Proved Plus
Probable 55,933 45,695 39,765 35,586 32,372
-------------------------------------------


Total Future Net Revenue
(Undiscounted)
Based on Forecast Prices and Costs(10)

Revenue Royalties Operating Development
Costs Costs
($000) ($000) ($000) ($000)
---------------------------------------------------------------------
Total Proved(2) 72,420 16,433 8,666 1,427

Total Proved Plus
Probable(2)(3) 126,378 29,658 15,234 5,486


Future Future
Net Net
Abandonment Revenue Revenue
and Before After
Reclamation Income Income Income
Costs Taxes Taxes Taxes
($000) ($000) ($000) ($000)
---------------------------------------------------------------------
Total Proved (2) 458 45,437 9,126 3,634

Total Proved Plus
Probable(2)(3) 628 75,373 19,440 55,933



Future Net Revenue by Production Group
Based on Forecast Prices and Costs(10)

Future Net Revenue
Before Income Taxes
(Discounted at 10%/Year)
Production Group ($000)
---------------------------------------------------------------------
Total Proved(2) Light and medium crude oil 1,846
Heavy oil -
Associated gas and non-
associated gas(10) 33,921
Total Proved Plus
Probable(2)(3) Light and medium crude oil 2,423
Heavy oil -
Associated gas and non-
associated gas(10) 51,573


1) "Gross Reserves" are the anticipated working interest of Accrete
(operating or non-operating) before deducting royalties and without
including any royalty interests of Accrete. "Net Reserves" are the
anticipated working interest of Accrete (operating or non-operating)
share after deduction of royalty obligations, plus Accrete's royalty
interests in reserves.

2) "Proved" reserves are those reserves that can be estimated with a
high degree of certainty to be recoverable. It is likely that the actual
remaining quantities recovered will exceed the estimated proved
reserves."

3) Probable" reserves are those additional reserves that are less
certain to be recovered than proved reserves. It is equally likely that
the actual remaining quantities recovered will be greater or less than
the sum of the estimated proved plus probable reserves.

4) "Developed" reserves are those reserves that are expected to be
recovered from existing wells and installed facilities or, if facilities
have not been installed, that would involve a low expenditure (e.g. when
compared to the cost of drilling a well) to put the reserves on
production.

5)"Developed Producing" reserves are those reserves expected to be
recovered from completion intervals open at the time of the estimate.
These reserves may be currently producing or, if shut-in, they must have
previously been on production, and the date of resumption of production
must be known with reasonable certainty.

6) "Developed Non-Producing" reserves are those reserves that either
have not been on production, or have previously been on production, but
are shut in, and the date of resumption of production is unknown.

7) "Undeveloped" reserves are those reserves expected to be recovered
from known accumulations where a significant expenditure (for example,
when compared to the cost of drilling a well) is required to render them
capable of production. They must fully meet the requirements of the
reserves classification (proved, probable, possible) to which they are
assigned.

8) The product prices used in the constant price and cost evaluations in
the GLJ Report were as follows: $US43.45/bbl for oil at WTI@Cushing, gas
at AECO-C $6.79/mmbtu and light oil at $46.54 at Edmonton.

9) Includes NGLs.

10) The pricing assumptions used in the GLJ Report with respect to net
values of future net revenue (forecast) as well as the inflation rates
used for operating and capital costs are set forth below. GLJ is an
independent qualified reserves evaluator appointed pursuant to National
Instrument 51-101.



GLJ Forecasted Prices Effective January 1, 2005

Light and Medium Crude Oil
---------------------------------------------------------------------
WTI Edmonton Cromer
Cushing Par Price Medium
Period Oklahoma 40 degrees 29.3 degrees
($US/bbl) API API
($Cdn/bbl) ($Cdn/bbl)

---------------------------------------------------------------------
2001 25.97 39.40 31.56
2002 26.08 40.33 35.48
2003 31.07 43.66 37.55
2004 (e) 41.38 52.96 45.75
2005 Q1 43.25 52.00 45.25
2005 Q2 42.25 50.50 44.00
2005 Q3 41.50 49.75 43.25
2005 Q4 41.00 49.00 42.75

2005 Full Year 42.00 50.25 43.75

2006 40.00 47.75 41.50
2007 38.00 45.50 39.50
2008 36.00 43.25 37.75
2009 34.00 40.75 35.50
2010 33.00 39.50 34.25
2011 33.00 39.50 34.25
2012 33.00 39.50 34.25
2013 33.50 40.00 34.75
2014 34.00 40.75 35.50
2015 34.50 41.25 36.00
2016+ +2%/yr +2%/yr +2%/yr



Heavy Oil Natural Natural Inflation Exchange
Gas Gas Rate Rate
Liquids
---------------------------------------------------------------------
Bow River
Crude Oil Hardisty AECO C- Edmonton
Period Stream Heavy Spot Gas Pentanes
Quality 12 Price Plus
at degrees ($Cdn/bbl)($Cdn/bbl) %/year $US/$Cdn
Hardisty API
($Cdn/bbl)

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

2001 27.70 16.94 6.21 42.48 2.6 0.646
2002 31.83 26.57 4.04 40.73 2.2 0.637
2003 32.11 26.26 6.66 44.23 2.8 0.721
2004 (e) 36.91 29.11 6.88 54.07 1.9 0.769
2005 Q1 33.25 24.50 6.60 52.50 2.0 0.82
2005 Q2 36.25 29.00 6.30 51.00 2.0 0.82
2005 Q3 35.75 28.50 6.50 50.25 2.0 0.82
2005 Q4 35.25 28.00 6.90 49.50 2.0 0.82

2005 Full
Year 35.00 27.50 6.60 50.75 2.0 0.82

2006 35.25 28.50 6.35 48.25 2.0 0.82
2007 35.00 28.75 6.15 46.00 2.0 0.82
2008 33.25 27.25 6.00 43.75 2.0 0.82
2009 31.50 25.50 6.00 41.25 2.0 0.82
2010 30.50 24.75 6.00 40.00 2.0 0.82
2011 30.50 24.75 6.00 40.00 2.0 0.82
2012 30.50 24.75 6.00 40.00 2.0 0.82
2013 30.75 24.75 6.10 40.00 2.0 0.82
2014 31.50 25.50 6.20 41.25 2.0 0.82
2015 31.75 25.75 6.30 41.75 2.0 0.82
2016+ +2%/yr +2%/yr +2%/yr +2%/yr +2%/yr


Reconciliations of Changes in Reserves and Future Net Revenue

The following table sets forth a reconciliation of the changes in
Accrete's net light and medium crude oil, heavy oil and associated and
non-associated gas (combined) reserves as at December 31, 2004 against
Accrete's proved plus probable reserves as at June 1, 2004 based on the
forecast price and cost assumptions set forth in note 10 under the
heading "Reserves and Future Net Revenue".



Reconciliation of
Reserves by Principal Product Type
Based on Forecast Prices and Costs


Light and Medium Oil Heavy Oil
---------------------------------------------------------------------
Net Proved Net Proved
Net Net Plus Net Net Plus
Proved Probable Probable Proved Probable Probable
(mbbl) (mbbl) (mbbl) (mbbl) (mbbl) (mbbl)
---------------------------------------------------------------------
At June 1,
2004 - - - - - -
---------------------------------------------------------------------
Extensions - - - - - -
Improved
Recovery - - - - - -
Technical
Revisions - - - - - -
Discoveries 2 - 2 - - -
Acquisitions 2 - 3 - - -
Dispositions - - - -
Economic
Factors - - - - - -
Production (2) - (2) - - -
---------------------------------------------------------------------
At December
31, 2004 2 - 3 - - -
---------------------------------------------------------------------

Conventional Natural Gas Natural Gas Liquids
---------------------------------------------------------------------
Net Net
Net Net Proved & Net Net Proved Plus
Proved Probable Probable Proved Probable Probable
(mmcf) (mmcf) (mmcf) (mbbl) (mbbl) (mbbl)
---------------------------------------------------------------------
At June 1,
2004 1,050 933 1,983 - - -
---------------------------------------------------------------------
Extensions - - - - - -
Improved
Recovery - - - - - -
Technical
Revisions 211 145 356 2 1 3
Discoveries 4,493 3,453 7,946 454 230 684
Acquisitions 151 25 176 2 - 2
Dispositions - - - - - -
Economic
Factors - - - - - -
Production (222) - (222) (2) - (2)
---------------------------------------------------------------------
At December
31, 2004 5,683 4,556 10,239 456 231 687
---------------------------------------------------------------------


The following table sets forth changes between future net revenue
estimates attributable to net proved reserves as at December 31, 2004
against such reserves as at June 1, 2004.

Reconciliation of Changes in Net Present Values of Future Net Revenue
Discounted at 10%
Total Proved Reserves Constant Prices and Costs



---------------------------------------------------------------------
After Tax Before Tax
($000) ($000)

Estimated Net Present Value at June 1, 2004 2,914 3,419

---------------------------------------------------------------------
Oil and Gas Sales During the Period Net
of Production Costs and Royalties(1) (1,117) (1.117)
Changes due to Prices and Royalties
Related to Forecast Production(2) (200) (200)
Development Costs During the Period(3) 18,001 18,001
Changes in Forecast Development Costs(4) (17,519) (17,519)
Changes Resulting from Extensions and
Improved Recovery(5) - -
Changes Resulting from Discoveries(5) 25,750 25,750
Changes Resulting from Acquisitions
of Reserves(5) 6,703 6,703
Changes Resulting from Dispositions
of Reserves(5) - -
Accretion of Discount(6) 342 342
Net Change in Income Taxes(7) (7,894)
Changes Resulting from Technical
Reserves Revisions 944 944
All Other Changes(8) 2,128 2,088
--------------------------------------------------------------------
Estimated Net Present Value at
December 31, 2004 30,052 38,411


Notes:

(1) Revenue less royalties and production costs, before G&A and income
taxes.

(2) The impact of changes in prices and other economic factors on future
net revenue.

(3) Actual capital expenditures relating to the exploration, development
and production of oil and gas reserves.

(4) The change in forecast development costs.

(5) End of period net present value of the related reserves.

(6) Estimated as 10% of the beginning of period net present value.

(7) The difference between forecast income taxes at beginning of period
and the actual taxes for the period plus forecast income taxes at the
end of period.

(8) Includes changes due to revised production profiles, development
timing, operating costs, royalty rates, actual price received in 2004
versus forecast, etc.

Disclaimers

Some of the statements contained herein including, without limitation,
financial and business prospects and financial outlooks may be
forward-looking statements which reflect management's expectations
regarding future plans and intentions, growth, results of operations,
performance and business prospects and opportunities. Words such as
"may", will", "should", "could", "anticipate", "believe", "expect",
"intend", "plan", "potential", "continue" and similar expressions have
been used to identify these forward-looking statements. These
statements reflect management's current beliefs and are based on
information currently available to management. Forward-looking
statements involve significant risk and uncertainties. A number of
factors could cause actual results to differ materially from the results
discussed in the forward-looking statements including, but not limited
to, changes in general economic and market conditions and other risk
factors. Although the forward-looking statements contained herein are
based upon what management believes to be reasonable assumptions,
management cannot assure that actual results will be consistent with
these forward-looking statements. Investors should not place undue
reliance on forward-looking statements. These forward-looking
statements are made as of the date hereof and we assume no obligation to
update or revise them to reflect new events or circumstances.

Forward-looking statements and other information contained herein
concerning the oil and gas industry and Accrete Energy Inc.'s general
expectations concerning this industry are based on estimates prepared by
management using data from publicly available industry sources as well
as from reserve reports, market research and industry analysis and on
assumptions based on data and knowledge of this industry which Accrete
Energy Inc. believes to be reasonable. However, this data is inherently
imprecise, although generally indicative of relative market positions,
market shares and performance characteristics. While Accrete Energy
Inc. is not aware of any misstatements regarding any industry data
presented herein, the industry involves risks and uncertainties and is
subject to change based on various factors. All oil and natural gas
reserve information contained herein has been prepared and presented in
accordance with National Instrument 51-101 Standards of Disclosure for
Oil and Gas Activities ("NI 51-101"). The actual oil and natural gas
reserves and future production will be greater than or less than the
estimates provided herein. The estimated future net revenue from the
production of the disclosed oil and natural gas reserves does not
represent the fair market value of these reserves. Accrete Energy Inc.
has adopted the standard of 6 mcf to 1 boe when converting natural gas
to barrels of oil equivalent. Boes may be misleading particularly if
used in isolation. A boe conversion ratio of 6mcf to 1 boe is based on
an energy equivalency conversion method primarily applicable at the
burner tip and does not represent a value equivalency at the wellhead.

-30-

Contact Information

  • FOR FURTHER INFORMATION PLEASE CONTACT:
    Accrete Energy Inc.
    Mr. Peter Salamon
    President and CEO
    (403) 269-8846
    investor@accrete-energy.com
    or
    Accrete Energy Inc.
    2100, 500 - 4th Avenue SW
    Calgary, Alberta T2P 2V6