Veteran Resources Inc.

Veteran Resources Inc.

March 18, 2005 08:00 ET

Veteran Resources Inc. Announces 2004 Reserves, Replacing 2004 Production By 676 Percent


NEWS RELEASE TRANSMITTED BY CCNMatthews

FOR: VETERAN RESOURCES INC.

TSX SYMBOL: VTI

MARCH 18, 2005 - 08:00 ET

Veteran Resources Inc. Announces 2004 Reserves,
Replacing 2004 Production By 676 Percent

CALGARY, ALBERTA--(CCNMatthews - March 18, 2005) - Veteran Resources
Inc. ("Veteran" or the "Company") (TSX:VTI) is pleased to announce its
2004 financial results and year-end reserves, as well as an activity
update.

2004 HIGHLIGHTS

- Established Peace River Arch (PRA) core area exploration group and
implemented a full cycle exploration program

- Invested the largest capital budget in Veteran's history - $11.3
million

- Drilled a record 27 (8.6 net) wells with an 89 percent success rate

- Increased year-end production capability to 1,400 boe per day, up 280
percent from 2003.

- Added 1,208 mboe proven and 1,349 mboe proven plus probable in
reserves at finding and development costs of $9.37 and $8.39 respectively

- Replaced 2004 production by 676 percent


2005 ACTIVITY UPDATE

The 2005 budget of $16 million anticipates the drilling of 27 wells. To
date, 11 (6.4 net) wells have been drilled with an 82 percent success
rate. The Company continues to focus its activity in the Peace River
Arch (PRA) where it operated the drilling of seven (5.5 net) wells. Two
additional wells are expected to be drilled by the end of the first
quarter.

Current production now stands at 1,000 boe per day which reflects
anticipated declines at Gunnell. Most of the drilling activity is recent
and therefore awaiting tie-in. In total, the Company has tested 1,200
boe per day which currently stands behind pipe, awaiting tie-in. It is
expected that approximately 500 boe per day will be on-stream near the
end of the first quarter while pipelining will commence on the remaining
production after spring break-up. Tie-in operations are being hampered
by extremely mild winter conditions which could impact on-stream timing
at Cecil and Earring, delaying initial production until summer.

Cecil, AB

A total of three wells were drilled at Cecil, two at 26 percent and one
at 100 percent. The first two are tied-in and restricted to producing at
rates of 125 boe per day. The third well, at 100 percent working
interest, is expected to start producing on April 1 at similar rates. An
application is being prepared that if successful would eliminate the
production restriction on all Cecil wells. Five locations are in various
stages of licensing in anticipation of resuming drilling activity after
spring break-up.

Earring, AB

A second well at Earring, a twin to our wildcat discovery drilled last
year, was drilled with the intention of completing two of the four zones
previously encountered. These two zones are present in the new well
while two additional zones were also encountered, testing at 0.3 mmcf
per day and 3.0 mmcf per day each. Pipelining operations are underway
and 2.0 to 3.0 mmcf per day from the second well is expected to be
on-stream by the end of March. Production from the first well, expected
to be in the 3.0 to 3.5 mmcf per day range, requires significant
pipeline construction which will be completed during the summer.

Boundary Lake, AB

The Company has commenced drilling its PRA shallow gas play. A total of
three wells were drilled at 100 percent working interest. Results to
date have been mixed. One well drill stem tested at higher than expected
rates of 1.0 mmcf per day and is estimated to be pipelined during the
second quarter. The other two wells encountered gas zones as anticipated
but pressure data indicated that the reservoirs had been breached by the
Peace River which can scour to depths of more than 300 metres. A fourth
well is currently drilling.

Gunnell, BC

Two horizontal wells were drilled at Gunnell in which the Company has 30
percent working interest. The first well and the previously announced
well drilled late last year are currently producing at combined gross
rates of approximately 5.0 (1.5 net) mmcf per day. This rate is lower
than capability, primarily as a result of pipeline back- pressure rather
than reservoir decline, but is well within our production forecast
models. The second well drilled in 2005 produced while drilling at rates
of 5.0 mmcf per day and is expected to be tied-in by the end of March.
Initial rates for this well are anticipated to be in the 2.5 (0.8 net)
mmcf per day to 3.0 (0.9 net) mmcf per day range. Further drilling at
Gunnell is expected to commence later in the year.

Snowfall, AB

Veteran participated at 12.5 percent working interest in two wells. The
offset to last year's Debolt discovery was successful and is currently
being completed. Initial rates are expected to be in the 1.0 (0.1 net)
mmcf day range. The second well was a 2,700 metre Precambrian test to
evaluate the Keg River Formation. The well successfully encountered
light oil from the Keg River but due to soft ground conditions was cased
without testing. The well is currently being completed after which flow
rates will be determined. A third well, in which Veteran has 100 percent
working interest, is currently drilling. None of these wells drilled
will be tied-in until frozen ground conditions exist late in 2005.

2004 RESERVE INFORMATION

The Company's 2004 year-end reserves were determined by Sproule
Associates Limited through generally accepted engineering methods and
are the total remaining recoverable reserves associated with the acreage
in which the Corporation holds an interest. The net Company Reserves
based on forecast prices and costs are summarized in the following Table.



SUMMARY OF OIL AND GAS RESERVES - Gross(1) and Net(2)
As of December 31, 2004
Forecast Prices and Costs

Reserves Light and Natural Gas Natural Gas Barrels of Oil
Category Medium Oil Liquids Equivalent(3)
Gross Net Gross Net Gross Net Gross Net
(mbbl) (mbbl) (mmcf) (mmcf) (mbbl) (mbbl) (mboe) (mboe)
------------------------------------------------------------------------
Proved
Producing 469.3 432.7 3,104 2,935 46.1 47.2 1,032.7 969.1
Non-producing 12.4 10.9 1,085 868 3.4 2.4 196.6 158.0
Undeveloped 72.5 54.4 3,764 2,764 1.2 5.1 701.0 520.2
------------------------------------------------------------------------
Total Proved 554.2 498.0 7,953 6,567 50.7 54.7 1,930.3 1,647.3
Probable 182.5 170.5 2,430 2,040 17.1 15.4 604.6 525.9
------------------------------------------------------------------------
Total Proved
plus Probable 736.7 668.5 10,383 8,607 67.8 70.1 2,534.9 2,173.2

Notes:
(1) "Gross reserves" are the Corporation's working interest share of
reserves before the deduction of royalties.
(2) "Net reserves" are defined as the "gross reserves" of the properties
in which the Corporation has an interest, less all interests and
royalties owned by others but including all gross overriding
royalties owned by the Company.
(3) Reserves are commonly stated in barrels of oil equivalent "boe"
using a six-to-one conversion basis when converting thousands of
cubic feet of natural gas to barrels of oil and a one-to-one
conversion basis for natural gas liquids to oil. Such conversions
may be misleading, particularly if used in isolation. A six-to-one
conversion ratio is based on energy equivalence between natural gas
and oil at the burner tip and does not represent economic
equivalence of products at the wellhead or point of sale.


On a proved plus probable basis, crude oil and natural gas liquids
reserves increased in 2004 from 706.3 mbbl to 804.5 mbbl for an overall
increase of 98.2 mbbl or 14 percent. Similarly, on a net proved plus
probable basis, natural gas reserves increased from 4,073 mmcf to 10,383
mmcf for an increase of 6,310 mmcf or 155 percent.



Net Present Values of Future Net Revenue
As of December 31, 2004
Forecast Prices and Costs

Reserves Future Net Revenue Before Taxes(1)
Category (Discounted at %/year)
0 5 10 15 20
-----------------------------------------------------------------------
Proved
Producing 22,931 19,550 17,125 15,317 13,922
Non-producing 3,848 2,796 2,224 1,865 1,614
Undeveloped 14,989 12,384 10,602 9,306 8,317
-----------------------------------------------------------------------
Total Proved 41,768 34,730 29,951 26,488 23,853
Probable 13,013 8,106 5,611 4,184 3,289
-----------------------------------------------------------------------
Total Proved
plus Probable 54,781 42,836 35,562 30,672 27,142

Notes:
(1) Net Revenue prior to provision of income taxes, interest, debt
service charges and general and administrative expenses. It should
not be assumed that the undiscounted and discounted future net
revenues estimated by Sproule Associates represent the fair market
value of the reserves.


Pricing Assumptions

The forecast prices that formed the basis for the forecast reserves and
revenue projections were based on Sproule's December 31, 2004 pricing
model.



Summary of Future Pricing
Sproule Associates December 31, 2004
Forecast Prices

Edmonton Natural
WTI Cushing Par Price Gas AECO
Oklahoma 40 degrees API Gas Price
Year ($US/bbl) ($Cdn/bbl) ($Cdn/mmBtu)
-------------------------------------------------------
2005 44.29 51.25 6.97
2006 41.60 48.03 6.66
2007 37.09 42.64 6.21
2008 33.46 38.31 5.73
2009 31.84(1) 36.36(1) 5.37(1)

Notes:
(1) escalation rate of 1.5% thereafter


NET RESERVES RECONCILIATION(1)
As of December 31, 2004
Forecast Prices and Costs

Crude Oil Associated &
And NGL's Unassociated Gas Total
-----------------------------------------------------------------------
(mbbl) (mbbl) (mboe)(2)
-----------------------------------------------------------------------
Net Net Net Net Net Net
Proved P+P Proved P+P Proved P+P
-----------------------------------------------------------------------
Dec 31/03 423.7 652.8 2710.0 4068.0 875.4 1330.8
Extensions 63.6 64.8 1569.9 2041.4 325.3 405.0
Improved Recovery - - - - - -
Technical Revisions 90.4 43.9 232.4 20.1 129.1 47.3
Discoveries 47.7 49.8 2609.1 3031.9 482.6 555.1
Acquisitions - - - - - -
Dispositions - - - - - -
Economic Factors - - - - - -
Production (72.7) (72.7) (554.4) (554.4) (165.1) (165.1)
-----------------------------------------------------------------------
Dec 31/04 552.7 738.6 6567.0 8607.0 1647.3 2173.1

Notes:
(1) NI 51-101 specifies that year over year changes in reserves be
reported on a "Net" basis. "Net reserves" are defined as the
"Gross reserves" of the properties in which the Corporation has
an interest, less all interests and royalties owned by others but
including all gross overriding royalties owned by the Company.
(2) Reserves and production are commonly stated in barrels of oil
equivalent "boe" using a six-to-one conversion basis when
converting thousands of cubic feet of natural gas to barrels of oil
and a one-to-one conversion basis for natural gas liquids to oil.
Such conversions may be misleading, particularly if used in
isolation. A six-to-one conversion ratio is based on energy
equivalence between natural gas and oil at the burner tip and does
not represent economic equivalence of products at the wellhead or
point of sale.


Finding and Development Costs 2004

Finding and development costs are calculated by dividing the total
Corporation's exploration and development costs incurred in the current
fiscal year by the proved and probable reserves added during that
period. The following table shows that in 2004 the Corporation's finding
and development costs were $9.37/boe on a proved basis and $8.39/boe on
a proved plus probable basis.



Net capital expenditures (thousands $) 11,320.0
Proven reserves added (mboe) 1,208.4
Proven plus probable reserves added (mboe) 1,349.4
Average cost/boe(proven) $ 9.37
Average cost/boe (proven plus probable) $ 8.39

The financial information that follows is derived from the 2004 audited
financial statements.

HIGHLIGHTS
For the years ended December 31,
2004 2003 Change
------------------------------------------------------------------------

FINANCIAL
Oil and natural gas revenues $ 8,933,552 $ 4,861,871 84%


Funds from operations (1) $ 3,999,988 $ 2,003,157 100%
Per common share - basic $ 0.07 $ 0.05
Per common share - diluted $ 0.07 $ 0.04


Net earnings $ 1,128,799 $ 327,348 245%
Per common share - basic $ 0.02 $ 0.01
Per common share - diluted $ 0.02 $ 0.01


Capital expenditures
- Capital assets, net $ 11,133,479 $ 6,556,690 70%
- Corporate acquisitions $ - $ 7,010,330 -100%


Working capital deficiency,
including bank loan $ 8,528,851 $ 2,893,475 195%

Shareholders' equity $ 23,136,575 $ 21,816,669 6%


Common shares outstanding December 31
Basic 61,853,706 57,852,226 7%
Weighted average - basic 58,046,569 43,885,304 32%
Diluted 67,399,706 67,705,869 0%


OPERATIONS
Average daily sales
Natural gas (mcf per day) 1,850 1,122 65%
Crude oil (bbl per day) 213 124 72%
Natural gas liquids (bbl per day) 24 18 31%
Barrels of oil equivalent (boe per day) 545 329 66%


Average sales price
Natural gas (per mcf) $ 7.03 $ 6.69 5%
Crude oil (per bbl) $ 48.54 $ 41.53 17%
Natural gas liquids (per bbl) $ 44.71 $ 38.28 17%


Netback pricing (per barrel of oil equivalent)
Oil and natural gas revenues $ 44.76 $ 40.56 10%
Royalties $ (6.60) $ (5.09) 30%
Production $ (10.33) $ (8.13) 27%
----------------------------------
$ 27.83 $ 27.34 2%
----------------------------------
----------------------------------

------------------------------------------------------------------------
Wells drilled
Gross 27 10
Net 8.59 6.95
Success rate 89% 40%
------------------------------------------------------------------------

(1) Funds from operations is a non-GAAP measure that represents cash
generated from operating activities before changes in non-cash
working capital and is used by the Company to analyze operating
performance, leverage and liquidity. Funds from operations may not
be comparable to similar measures used by other companies.



BALANCE SHEETS

As at December 31 2004 2003
------------------------------------------------------------------------

ASSETS

Current

Cash $ - $ 330,231
Accounts receivable 3,076,374 1,678,319
Prepaid expenses 134,755 175,166
------------------------------------------------------------------------
3,211,129 2,183,716

Capital assets 34,436,786 26,350,721
------------------------------------------------------------------------
$ 37,647,915 $ 28,534,437
------------------------------------------------------------------------
------------------------------------------------------------------------

LIABILITIES

Current
Bank overdraft $ 254,684 $ -
Accounts payable and accrued liabilities 5,957,296 3,599,191
Bank loan 5,528,000 1,478,000
------------------------------------------------------------------------
11,739,980 5,077,191

Asset retirement obligations 1,670,088 1,640,577

Future income taxes 1,101,272 -

Contingencies and commitments

SHAREHOLDERS' EQUITY
Share capital 21,702,999 28,591,051
Contributed surplus 304,777 70,521
Retained earnings (deficit) 1,128,799 (6,844,903)
------------------------------------------------------------------------
23,136,575 21,816,669
------------------------------------------------------------------------
$ 37,647,915 $ 28,534,437
------------------------------------------------------------------------
------------------------------------------------------------------------


STATEMENTS OF EARNINGS AND RETAINED EARNINGS (DEFICIT)

------------------------------------------------------------------------
For the years ended December 31,
2004 2003
------------------------------------------------------------------------

REVENUES
Oil and natural gas $ 8,933,552 $ 4,861,871
Royalties, net of ARTC (1,316,495) (610,318)
------------------------------------------------------------------------
7,617,057 4,251,553

EXPENSES
Production 2,061,389 974,061
General and administrative 1,532,369 1,229,914
Financing charges 229,080 81,029
Depletion, depreciation and accretion 3,263,520 1,605,288
------------------------------------------------------------------------
7,086,358 3,890,292
------------------------------------------------------------------------
Earnings before taxes 530,699 361,261

Capital taxes 28,487 33,913
Future income tax recovery (626,587) -
------------------------------------------------------------------------
(598,100) 33,913
------------------------------------------------------------------------


Net earnings for the year 1,128,799 327,348
Deficit, beginning of year,
as previously reported (6,760,752) (7,050,605)
Change in accounting policy (84,151) (121,646)
------------------------------------------------------------------------
Deficit, beginning of year, as restated (6,844,903) (7,172,251)
Elimination of deficit through
reduction of share capital 6,844,903 -
------------------------------------------------------------------------
Retained earnings (deficit), end of year $ 1,128,799 $ (6,844,903)
------------------------------------------------------------------------
------------------------------------------------------------------------

Earnings per common share
Basic $ 0.02 $ 0.01
------------------------------------------------------------------------
------------------------------------------------------------------------
Diluted $ 0.02 $ 0.01
------------------------------------------------------------------------
------------------------------------------------------------------------


STATEMENTS OF CASH FLOWS

------------------------------------------------------------------------
For the years ended December 31,
2004 2003
------------------------------------------------------------------------

OPERATING ACTIVITIES

Net earnings for the year $ 1,128,799 $ 327,348
Non-cash items
Stock-based compensation 234,256 70,521
Depletion, depreciation and accretion 3,263,520 1,605,288
Future income taxes (626,587) -
------------------------------------------------------------------------
Funds from operations 3,999,988 2,003,157
Expenditures on asset retirements (186,594) -
Changes in non-cash working capital (1,317,096) (852,190)
------------------------------------------------------------------------
2,496,298 1,150,967
------------------------------------------------------------------------

FINANCING ACTIVITIES
Bank loan 4,050,000 (1,972,000)
Proceeds on issuance of common shares 1,684,710 14,181,684
Costs on issuance of common shares - (924,774)
Advances from directors,
officers and shareholders - (1,575,000)
------------------------------------------------------------------------
5,734,710 9,709,910
------------------------------------------------------------------------

INVESTING ACTIVITIES
Capital asset additions (11,133,479) (6,556,690)
Acquisition of American
Leduc Petroleums Limited - (7,010,330)
Changes in non-cash working capital 2,317,556 1,632,464
------------------------------------------------------------------------
(8,815,923) (11,934,556)

Decrease in cash (584,915) (1,073,679)
Cash, beginning of year 330,231 1,403,910
------------------------------------------------------------------------
Cash (bank overdraft), end of year $ (254,684) $ 330,231
------------------------------------------------------------------------
------------------------------------------------------------------------

Cash taxes $ 60,541 $ 1,246
Interest paid $ 232,182 $ 73,034



Caution to Reader

This report contains forward-looking statements and the reader is
cautioned not to place undue reliance on these statements, as there can
be no assurance that the plans, intentions or expectations upon which
they are based will occur. By their nature, forward-looking statements
involve numerous assumptions, known and unknown risks and uncertainties,
both general and specific, that contribute to the possibility that the
predictions, forecasts, projections and other forward-looking statements
will not occur. Although Veteran believes that the expectations
represented by such forward-looking statements are reasonable, there can
be no assurance that such expectations will prove to be correct. These
statements are based on current expectations that involve a number of
risks and uncertainties including but not limited to: the risks
associated with the oil and gas industry (e.g., operational risks in
development, exploration, and production; the uncertainty of reserve
estimations; the uncertainty of estimates and projections relating to
production, costs and expenses, and health, safety, and environmental
risks), commodity price and exchange rate fluctuations and uncertainties
resulting from potential delays or changes in plans with respect to
exploration or development projects or capital expenditures. Additional
information on these and other factors that could affect Veteran's
operations or financial results are included in Veteran's reports on
file with regulatory authorities. The Company cautions that events or
circumstances could cause actual results to differ materially from those
projected.

Conversion

Boe's are derived by converting natural gas to oil in the ratio of 6 mcf
to 1 bbl. Boe's may be misleading, particularly if used in isolation. A
boe conversion ratio of 6 mcf to 1 bbl is based on an energy equivalency
conversion method primarily applicable at the burner tip and does not
represent an equivalency at the wellhead.

-30-

Contact Information

  • FOR FURTHER INFORMATION PLEASE CONTACT:
    Veteran Resources Inc.
    Philip J. Loudon
    President and Chief Executive Officer
    (403) 699-8629
    or
    Veteran Resources Inc.
    J. Peter Henry
    Vice President and Chief Financial Officer
    (403) 699-8632
    Website:www.veteranresources.net
    The TSX does not accept responsibility for the adequacy or accuracy of
    this release.