High Point Resources Inc.

High Point Resources Inc.

March 10, 2005 16:15 ET

High Point Resources Announces 2004 Results


NEWS RELEASE TRANSMITTED BY CCNMatthews

FOR: HIGH POINT RESOURCES INC.

TSX SYMBOL: HPR

MARCH 10, 2005 - 16:15 ET

High Point Resources Announces 2004 Results

CALGARY, ALBERTA--(CCNMatthews - March 10, 2005) - High Point Resources
Inc. (TSX:HPR) is pleased to announce its operating and financial
results for the three months and year ended December 31, 2004.

Report to Shareholders

One year ago, High Point accomplished its operating objectives in its
strategic business plan. High Point became a low cost natural gas
producer. Production, reserves and land were all associated with
long-life gas reservoirs in the deeper portion of the Western Canadian
sedimentary basin. A multi-year gas development program and a
drill-ready exploration program were in place.



Achievements

In 2004, we expanded our presence in all core areas. Key operating
achievements included:
- Production growth of 42 percent.
- Proved producing reserves growth of 32 percent.
- Reserve life index of 8.3 years proved, 10.5 years proved plus
probable
- Proved producing reserves replaced production by 2.7 times.
- Proved and probable reserves increased by 14 percent.
- Undeveloped land increased by 32 percent.
- Unit operating costs were reduced by 27% to $3.60 per boe.

The expanded and improved asset base resulted in a:
- Thirty-two percent increase in cash flow per share.
- Thirty-three percent increase in earnings per share.
- Fifteen percent increase in net asset value per share.
- Twenty-five percent reduction in year-end debt to cash flow.


The 2004 achievements were a result of organic growth. High Point made
no corporate or production acquisitions in 2004 and divested several
non-core assets.

Capital Activities

High Point invested $63.2 million in 2004; 62 percent on drilling and
completions, 22 percent on facilities and pipelines and 15 percent on
land and seismic. The capital investment increased proved producing
reserves by 2.9 million boes, proved and probable reserves by 2.6
million boes and undeveloped land by 26,000 net acres. Excluding the
capital for land and seismic, which are related to future projects,
proved producing reserves were added at a cost of $16.50 per boe. The
capital program was funded by $22 in cash flow, $5 million in asset
sales, $14 million in equity and a $22 million increase in net debt.

High Point has a drilling inventory of over 160 development locations in
its three core operating areas of Desan/Peggo, Ferrier and Ricinus. High
Point operates all of its major developments with a corporate average
working interest of 75 percent. In the next three years, the company
plans to drill approximately 60 wells or 40% of the current inventory.
The expansion of our land holdings at Ferrier and the emergence of
Ricinus as a strong development property allow a better balance between
winter and summer capital programs in the future. In 2005, High Point
will evaluate the best alternatives to monetize the excess drilling
inventory which is not required to meet our three year growth plan.

High Point has been assembling land in the Ricinus area of West Central
Alberta since 2002. Forty-three sections of land have been acquired in
the Ricinus area at an average working interest of 67 per cent. Ricinus
commenced production in April, 2004 and gas processing facilities were
expanded in October, 2004. High Point is currently producing more than
450 boe per day from five wells. Two additional development wells at
Ricinus are planned for the first quarter of 2005. Ricinus will be a
focal point of operations in 2005 and beyond.

In addition to the development program, success on any of the company's
exploration prospects would have a material effect on the value of the
company. Desan, Ricinus and Lochend are all projects that were derived
from grass roots exploration in High Point's three year history. The
exploration prospects are drill-ready. Wells are licensed at Kotcho and
Ricinus, while locations are being selected on our Mackenzie prospect.
Three dimensional seismic has also identified deeper targets underlying
our Ferrier development lands.

High Point attempted to drill its Kotcho Keg River reef prospect in the
fall of 2004. The well experienced mechanical problems and had to be
junked and abandoned prior to penetrating the Keg River formation. A new
well is licensed on the same location and was slated for drilling in
March of this year. Unseasonably warm weather is occurring in Northeast
British Columbia, resulting in a deferral of the Kotcho re-drill until
after spring break-up. High Point plans to drill an exploratory gas well
at Ricinus targeting the Leduc reef complex as a substitute for the
Kotcho well. The Ricinus well site is currently being built with a
drilling rig contracted for April, 2005.

Financial Resources

The goal when we established High Point was to have sustainable and
profitable growth. Our plan is to accomplish this growth through
re-investment of cash flow and increased bank facilities. The quality
and long-life nature of High Point's asset base allows us to maintain
higher debt levels than most junior oil and gas companies, maximizing
leverage for our shareholders. The cost of debt in 2004 was 4.4 percent.
High Point also maintains an active hedging policy to ensure sufficient
cash flow to execute the capital program and service the debt.

Outlook

High Point will continue with its organic growth strategy in 2005.
Internal estimates indicate that the first quarter 2005 drilling program
has increased the proved producing reserves and average 2005 production
by approximately 20% over levels achieved in 2004. By relying solely on
its drilling program to fuel growth, High Point will continue to
experience "choppy" quarterly growth; however annual growth will remain
strong.

The strength in commodity prices in both the short and long term is
resulting in an extremely competitive market for production, prospects
and services. In the areas where High Point operates, land value has
increased fourfold in the last two years. Having established our land
and prospect inventory early in the current cycle, High Point has
significant advantages over a number of its competitors. A large
drilling and prospect inventory, combined with a low operating cost
structure positions High Point to take advantage of strong commodity
prices, while remaining profitable when prices retreat.

As the company production base expands, organic production growth of 25
to 30 percent is achievable from the development program, in the current
commodity price environment. Success at any one of our high impact
exploration wells would result in a step rate increase to the annual
production and reserve growth of the company.

On behalf of the management and staff of High Point, I would like to
thank the shareholders and directors for their continued support.

Glen Yeryk

President & CEO



Highlights

Year ended Three months ended
December 31, December 31,
% %
Increase Increase
(unaudited) 2004 2003 (Decrease) 2004 2003 (Decrease)
------------------------------------------------------------------------
Production:
Light oil
(bbls/d) 38 115 (67) 17 101 (83)
Heavy oil
(bbls/d) - 125 (100) - 48 (100)
Gas (mcf/d) 15,166 10,133 50 15,037 13,533 11
Liquids
(bbls/d) 443 193 130 549 344 60
---------------------------------------------------------
BOE at 6:1 gas 3,009 2,121 42 3,072 2,749 12

Total BOE
Produced 1,101,144 774,257 42 282,651 252,875 12
------------------------------------------------------------------------
Prices
Light oil
($/bbl) 48.71 41.12 18 57.13 37.12 54
Heavy oil
($/bbl) - 25.76 - - 17.76 -
Gas (pre hedge)
($/mcf) 6.07 5.86 4 5.90 5.33 11
Gas (including
hedge) ($/mcf) 6.25 5.88 6 6.55 5.33 23
NGLs ($/bbl) 39.28 32.61 20 45.40 31.69 43

$ Per BOE
Gross revenues
(net of hedges) 37.94 35.02 8 40.50 32.05 26
Royalties
(net of ARTC) (9.88) (9.94) (1) (7.61) (9.59) (21)
Operating costs (3.60) (4.91) (27) (3.89) (4.31) (10)
---------------------------------------------------------
Field net back 24.46 20.17 21 29.00 18.15 60
Other revenue 0.04 0.16 (75) - - -
G & A (2.42) (3.13) (23) (2.02) (3.06) (34)
Interest (1.71) (1.31) 31 (1.59) (1.76) (10)
Taxes & other (0.24) (0.46) (48) (0.71) (1.32) (46)
---------------------------------------------------------
Cash flow 20.13 15.43 30 24.68 12.01 105
------------------------------------------------------------------------
Financial: ($000)
Gross revenues
(net of hedges) 41,780 27,110 54 11,449 8,105 41
Royalties
(net of ARTC) (10,882) (7,698) 41 (2,152) (2,427) (11)
Other income 45 124 (64) 1 1 -
Operating -
cash expenses (3,962) (3,799) 4 (1,100) (1,089) 1
G & A -
cash expenses (2,661) (2,422) 10 (571) (775) (26)
Interest -
cash expenses (1,885) (1,016) 86 (449) (444) 1
Current taxes (269) (352) (24) (201) (334) (40)
---------------------------------------------------------
Cash flow 22,166 11,947 86 6,977 3,037 130
D, D & A. (17,325) (12,340) 40 (4,952) (3,789) 31
Future Tax
(Expense)
Recovery (1,088) 2,180 (150) (414) 1,241 (133)
Other - non
cash expenses (737) (143) 415 (160) (35) 357
---------------------------------------------------------
Earnings (loss) 3,016 1,644 83 1,451 454 249

Net corporate
debt (000's) 62,004 40,006 55 62,004 40,006 55
Weighted
average
outstanding
shares: 75,766,587 78,799,042
55,329,790 37 67,544,528 17
Cash flow
per share
(basic) ($) 0.29 0.22 32 0.09 0.04 125
Earnings (loss)
per share ($) 0.04 0.03 33 0.02 0.01 100


Management's Discussion and Analysis

Management's Discussion & Analysis ("MD&A") of financial results and
operations is presented by management of High Point Resources Inc.
("High Point" or the "Corporation") to review financial results and
operating activities for the three and twelve month periods ended
December 31, 2004, and the three and twelve month periods ended December
31, 2003. The MD&A has been prepared in accordance with Canadian
generally accepted accounting principles ('GAAP'). This MD&A is based on
information available as of March 9, 2005.

This MD&A contains forward-looking statements, including forecasted
future production, cash flow and earnings. These statements are based on
management's current expectations, which involve a number of risks and
uncertainties which could cause actual results to differ materially from
those projected in the MD&A. These risks include competition and
operational risks relating to exploration and development activities;
fluctuating commodity prices and exchange rates; uncertainty in
estimates of reserves, production and costs; and legislative,
environmental and other regulatory or political changes. Accordingly,
there is no assurance that the forward-looking statements will prove to
be correct and High Point assumes no obligation to publicly update or
revise any forward-looking statements.

Natural gas reserves and volumes are converted to barrels of oil
equivalent (boe) on the basis of six thousand cubic feet (mcf) of gas to
one barrel (bbl) of oil. Boes 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 a value equivalency at the wellhead.

All references to dollar values refer to Canadian dollars, unless
otherwise stated.

Additional information relating to the Company, including the Annual
Information Form, can be found on the SEDAR website at www.sedar.com.

Non-GAAP Measurements

The MD&A uses the terms "cash flow from operations" and "cash flow",
which should not be considered an alternative to, or more meaningful
than, cash flow from operating activities or net earnings as determined
in accordance with Canadian GAAP as an indicator of High Point's
performance. High Point's determination of cash flow from operations may
not be comparable to that reported by other companies. The
reconciliation between net earnings and cash flow from operations can be
found in the Consolidated Statements of Cash Flows. The Corporation also
presents "cash flow per share", whereby cash flow from operations is
divided by the weighted average number of shares outstanding to
determine per share amounts.

High Point uses the term net debt in its MD&A and presents a table
showing how it has been determined. This measure does not have any
standardized meaning prescribed by Canadian GAAP and therefore may not
be comparable to similar measures presented by other companies.

High Point uses these non-GAAP measures to assist readers in
understanding High Point's overall financial position and in comparing
High Point's results to industry averages.

Corporate Vision and Strategy

High Point is an oil and gas company engaged in the exploration for, and
development and production of natural gas and light oil in Alberta and
NE British Columbia. The Corporation follows a strategy of assembling a
land base in the west half of the Western Canadian Sedimentary Basin
that features high-quality, long-life natural gas reserves. While the
oil and gas industry is subject to fluctuating product prices, we are of
the view that North American gas prices will remain strong because of a
scarcity of supply and increasing demand. High Point focuses on
properties with sustainable natural gas development and high impact
natural gas exploration. The Corporation has a very focused land base in
West Central Alberta and North East British Columbia, comprised of five
core areas which offer multi-year exploration and development potential
near gas infrastructure. High Point's strong internal prospect
generation may be supplemented by strategic acquisitions to provide
continuing growth.



Production by property

Year ended December 31,
------------------------------------------------------------------------
2004 2003
------------------------------------------------------------------------
Natural Natural
Gas Oil NGL BOE Gas Oil NGL BOE
mmcf/d bbl/d bbl/d boe/d mmcf/d bbl/d bbl/d boe/d
------------------------------------------------------------------------
Desan 8,722 - 44 1,498 6,545 - 38 1,128
------------------------------------------------------------------------
Ferrier 3,404 1 191 759 1,196 3 66 268
------------------------------------------------------------------------
Lochend 1,535 37 162 455 575 45 61 202
------------------------------------------------------------------------
Medicine
Lodge 602 - 8 108 1,248 - 20 228
------------------------------------------------------------------------
Alexander/
Newton (sold) 381 - 1 65 179 - - 30
------------------------------------------------------------------------
Ricinus 452 - 37 112 12 - 1 3
------------------------------------------------------------------------
Lloydminster
(sold) - - - - - 125 - 125
------------------------------------------------------------------------
Progress
(sold) - - - - 44 61 - 68
------------------------------------------------------------------------
Other 70 - - 12 334 6 7 69
------------------------------------------------------------------------
Total
boe/day 15,166 38 443 3,009 10,133 240 193 2,121
------------------------------------------------------------------------




Three months ended December 31,
------------------------------------------------------------------------
2004 2003
------------------------------------------------------------------------
Natural Natural
Gas Oil NGL BOE Gas Oil NGL BOE
mmcf/d bbl/d bbl/d boe/d mmcf/d bbl/d bbl/d boe/d
------------------------------------------------------------------------
Desan 7,593 - 38 1,303 8,281 - 48 1,428
------------------------------------------------------------------------
Ferrier 4,338 2 269 994 2,598 5 151 589
------------------------------------------------------------------------
Lochend 1,193 18 133 350 1,105 51 116 351
------------------------------------------------------------------------
Medicine
Lodge 541 - 8 98 909 - 13 165
------------------------------------------------------------------------
Alexander/
Newton
(sold) 232 - 1 40 402 - 1 68
------------------------------------------------------------------------
Ricinus 1,243 - 99 306 - - - -
------------------------------------------------------------------------
Lloydminster
(sold) - - - - - 48 - 48
------------------------------------------------------------------------
Progress
(sold) - - - - 43 42 - 49
------------------------------------------------------------------------
Other (103) (3) 1 (19) 195 3 15 51
------------------------------------------------------------------------
Total
boe/day 15,037 17 549 3,072 13,533 149 344 2,749
------------------------------------------------------------------------


Production from the Ricinus area began late in 2004, resulting in
average production of only 112 boe per day for 2004. Current production
from the Ricinus area is more than 450 boe per day.

Product mix

High Point's product mix averaged 99% natural gas and natural gas
liquids during 2004.



------------------------------------------------------------------------
Year ended Three months ended
December 31, December 31,
------------------------------------------------------------------------
2004 2003 2004 2003
------------------------------------------------------------------------
Natural gas
(mcf/d) 15,166 84% 10,133 80% 15,037 82% 13,553 82%
NGLs (bbls/d) 443 15% 193 9% 549 18% 344 13%
Oil (bbls/d) 38 1% 240 11% 17 0% 149 5%
Boe/d (6:1) 3,009 100% 2,121 100% 3,072 100% 2,749 100%
------------------------------------------------------------------------


Average production for 2004 was 3,009 boe per day, up 42% from 2,121 boe
per day in 2003, reflecting growth from the successful drilling programs
at Ferrier, Ricinus, Lochend and Desan. Desan and Ferrier accounted for
75% of total production in 2004.

Daily production of 3,072 boe per day in the fourth quarter was up 3%
from 2,978 boe per day in the third quarter, as some of the wells
drilled at Ferrier and Ricinus in the summer were tied in. Six of the
wells drilled at Ferrier and Ricinus were not tied in until the first
quarter of 2005, as availability of services in the industry continues
to be an issue.



Commodity pricing and marketing
------------------------------------------------------------------------
Year ended Three months ended
December 31, December 31,
------------------------------------------------------------------------
2004 2003 2004 2003
------------------------------------------------------------------------
High Point average prices
------------------------------------------------------------------------
Light oil ($/bbl) 48.71 41.12 57.13 37.12
------------------------------------------------------------------------
Heavy oil ($/bbl) - 25.76 - 17.76
------------------------------------------------------------------------
Natural gas ($/mcf) 6.07 5.86 5.90 5.33
------------------------------------------------------------------------
Hedging impact ($/mcf) 0.18 0.02 0.65 -
------------------------------------------------------------------------
Net gas ($/mcf) 6.25 5.88 6.55 5.33
------------------------------------------------------------------------
Natural gas liquids ($/bbl) 39.28 32.61 45.40 31.69
------------------------------------------------------------------------


Petroleum products are sold to major Canadian marketers at spot
reference prices based on USD WTI for crude oil and AECO-C for natural
gas. The average wellhead price of natural gas increased 3% from
$5.86/mcf in 2003 to $6.07/mcf ($6.25 after hedging) in 2004. Fourth
quarter 2004 gas pricing was $5.90/mcf ($6.55 after hedging), compared
to $5.83 ($5.85 after hedging) in the third quarter of 2004 and $5.33 in
the fourth quarter of 2003.

Commodity risk management

High Point enters into hedging transactions to protect our cash flows
and enhance our ability to carry out our planned capital expenditure
program. Hedging contracts outstanding in December, 2004 covered
one-half of December gas sales and result in prices on that portion of
High Point's sales being fixed at those price levels. The hedging of gas
sales in 2004 contributed $1.0 million to gas revenues.

The following is a summary of all hedging activities affecting 2004 and
2005:



------------------------------------------------------------------------
Period Volume Hedged AECO Price
------------------------------------------------------------------------
Feb. 1, 2003 2,000 GJ/day (1.9 mmcf/d) $5.50/GJ ($5.80/Mcf)
- Jan. 31, 2004 to $7.54/GJ ($7.86/Mcf)
------------------------------------------------------------------------
Mar. 1, 2003 2,000 GJ/day (1.9 mmcf/d) $5.50/GJ ($5.80/Mcf)
- Feb. 29, 2004 to $7.47/GJ ($7.88/Mcf)
------------------------------------------------------------------------
Jan. 1, 2004 4,000 GJ/day (3.8 mmcf/d) $7.21/GJ ($7.61Mcf)
- Mar. 31, 2004
------------------------------------------------------------------------
Feb. 1, 2004 2,000 GJ/day (1.9 mmcf/d) $6.04/GJ ($6.36/mcf)
- Oct. 31, 2004
------------------------------------------------------------------------
Apr. 1, 2004 4,000 GJ/day (3.8 mmcf/d) $5.89/GJ ($6.20/mcf)
- Oct. 31, 2004
------------------------------------------------------------------------
Nov. 1, 2004 3,000 GJ/day (2.9 mmcf/d) $7.90/GJ ($8.32/mcf)
- Mar. 31, 2005
------------------------------------------------------------------------
Nov. 1, 2004 3,000 GJ/day (2.9 mmcf/d) $8.01/GJ ($8.41/mcf)
- Mar. 31, 2005
------------------------------------------------------------------------
Nov. 1, 2004 2,000 GJ/day (1.9 mmcf/d) $8.58/GJ ($9.01/mcf)
- Mar. 31, 2005
------------------------------------------------------------------------
Apr. 1, 2005 6,000 GJ/day (5.7 mmcf/d) $6.95/GJ ($7.30/mcf)
- Oct. 31, 2005
------------------------------------------------------------------------
Apr. 1, 2005 3,000 GJ/day (2.9 mmcf/d) $6.82/GJ ($7.16/mcf)
- Oct. 31, 2005
------------------------------------------------------------------------


The CICA issued Accounting Guideline 13 "Hedging Relationships",
effective for fiscal years beginning on or after July 1, 2003. The
Guideline addresses the type of contracts that qualify for hedge
accounting and the requirement to evaluate hedges for effectiveness.
High Point has adopted hedge accounting for all its hedging contracts,
as physical sales contracts are entered into at the same time and on
identical terms as the hedge contracts. As a result, the Company has a
perfect relationship between the hedge contract and the underlying
physical sale. The adoption of the new Guideline had no effect on High
Point's Consolidated Financial Statements. As of December 31, 2004, the
outstanding hedge contracts had an unrealized positive value of
$958,980. Credit risks associated with hedging contracts are obviated by
restricting transactions to financially strong counterparties.



Petroleum and natural gas - gross revenues
------------------------------------------------------------------------
Year ended Three months ended
December 31, December 31,
------------------------------------------------------------------------
2004 2003 2004 2003
------------------------------------------------------------------------
$000 % $000 % $000 % $000 %
------------------------------------------------------------------------
Natural gas 35,998 84 23,356 82 8,852 79 7,138 83
------------------------------------------------------------------------
NGLs 6,372 15 2,295 8 2,292 20 1,003 17
------------------------------------------------------------------------
Oil 673 1 2,895 10 90 1 423 5
------------------------------------------------------------------------
Royalty revenue 37 - 159 5 - 42
------------------------------------------------------------------------
Subtotal 43,080 100 28,705 100 11,239 100 8,606 100
------------------------------------------------------------------------
Transportation (2,332) (1,650) (689) (503)
------------------------------------------------------------------------
Hedging gain 1,032 55 899 2
------------------------------------------------------------------------
Total revenue 41,780 27,110 11,449 8,105
------------------------------------------------------------------------


In 2004, 99% of High Point's revenues came from sales of natural gas and
associated liquids, up from 84% in 2003. Gross revenues in 2004 were
$41.8 million, up 54% from $27.1 million in 2003. Revenue increases were
due to an aggressive drilling program and the acquisition of Glacier
Ridge Resources in July 2003, which led to a 42% increase in daily
production volumes, combined with increased commodity prices and hedging
gains.

Gross revenues of $11.4 million in the fourth quarter were up from $9.9
million in the third quarter, reflecting a 3% increase in production
volumes between quarters and a $0.70 per mcf increase in gas prices
received, largely due to High point's hedging program.



Royalties
------------------------------------------------------------------------
Year ended December 31, Three months ended December 31,
------------------------------------------------------------------------
(000's) 2004 2003 2004 2003
------------------------------------------------------------------------
Crown 8,740 6,185 1,603 1,986
------------------------------------------------------------------------
Other 2,770 1,979 585 524
------------------------------------------------------------------------
ARTC & GCA (628) (466) (36) (83)
------------------------------------------------------------------------
Total 10,882 7,698 2,152 2,427
------------------------------------------------------------------------

Royalties as a percentage of sales
------------------------------------------------------------------------
Desan Ferrier Lochend Medicine Ricinus Average
Lodge
------------------------------------------------------------------------
Crown 26% 21% 9% 29% 0% 21%
------------------------------------------------------------------------
GORR 12% 2% 10% 3% 2% 7%
------------------------------------------------------------------------
Total royalties 38% 23% 19% 32% 2% 28%
------------------------------------------------------------------------


In 2004, royalties net of ARTC and gas cost allowance credits were
$9.88/Boe, compared to $9.94/Boe in 2003. Royalty rates dropped with the
payout of the bridge financing facility, which had a 5% gross overriding
royalty attached to specific projects in the Desan area. With the
repayment of the loan facility in July 2004, the gross overriding
royalty dropped from 5% to 1.6%. High Point purchased the remaining 1.6%
gross overriding royalty effective January 1, 2005 for $590,000.

Crown royalty rates were also down from the 23% average in 2003 because
of deep well royalty credits earned by drilling at Ferrier and Ricinus.
Amounts received in 2004 for gas cost allowance credits and Alberta
royalty tax credits were up 35% over 2003.

Operating expenses

Operating expenses were $3.60/Boe for 2004, down 27% from the $4.91/Boe
for the same period in 2003. This decrease reflects the sale of higher
cost oil properties in the second half of 2003 and increased production
from lower cost gas properties. Operating costs in the fourth quarter of
2004 were $3.89/Boe, down 10% from $4.31/Boe in the fourth quarter of
2003.

High Point's focused land base, operating control of its gas properties
and ownership of key in-field facilities and pipelines will ensure that
operating costs remain top quartile in 2005.



General and administration costs
------------------------------------------------------------------------
Year ended Three months ended
December 31, December 31,
------------------------------------------------------------------------
2004 2003 2004 2003
------------------------------------------------------------------------
$000 $/Boe $000 $/Boe $000 $/Boe $000 $/Boe
------------------------------------------------------------------------
Gross 3,640 3.31 3,122 4.03 901 3.19 1,043 4.12
------------------------------------------------------------------------
Recoveries (979) (0.89) (700) (0.90) (330) (1.17) (268) (1.06)
------------------------------------------------------------------------
Total 2,661 2.42 2,422 3.13 571 2.02 775 3.06
------------------------------------------------------------------------


While total general and administration expenses were 10% higher in 2004,
per boe G&A costs declined 23% from 2003 as production levels increased.
Personnel and consulting costs increased 23% with the growth in the
Corporation, while office rent and expenses increased 41%, as the
Corporation's office lease was renewed at a higher rate in the second
quarter of 2003. At December 31, 2004, High Point had 17 employees and 7
part-time consultants.

General and administration ("G&A") expenses in the three month period
ended December 31, 2004 were 26% lower than the same three month period
ended December 31, 2003. This reflects increased overhead recoveries
from higher capital expenditures in 2004, and 'one time' expenses in
December 2003 related to the move to the TSX exchange from the TSX
Venture exchange.

Interest

Interest expense incurred under the bank credit facility was $1,289,506
in 2004 compared with $713,931 for 2003, reflecting increased drawings
since March 31, 2003. At December 31, 2004, $50 million had been drawn
against the credit facility compared with $20 million drawn against the
credit facility and $10 million drawn under a bridge financing facility
at December 31, 2003. Fourth quarter bank interest was $449,326 compared
with $299,298 for the fourth quarter of 2003.

Other cash interest paid in 2004 was $595,804, which included $48,818 on
the convertible debentures, and $546,986 on the bridge financing
facility. $15 million was drawn against the bridge facility throughout
the greater portion of the first half of 2004 until it was repaid in
July, 2004. Fourth quarter other interest was nil in 2004 and $145,398
in 2003.

For 2004, the effective interest rate was 4.4% (4.7% for 2003).

Current taxes

The current tax expense of $268,787 includes 2004 Large Corporations Tax
("LCT") instalments of $189,442 offset by a credit of $82,671 for 2003,
representing assessed LCT that was lower than had been accrued in 2003.
Also included is $162,016 for Part XII.6 tax related to the timing of
flow through share expenditures in 2004.

Cash flow

Increased production levels and improved prices led to cash flow for
2004 of $22,165,572 or $0.29 per share, compared to $11,947,386 or $0.22
per share for the same period in 2003, an increase of 86%.

Netbacks

Operating netbacks increased 21% in 2004, which reflects a 6% increase
in selling prices, complemented by hedging gains and a 27% reduction in
per unit operating costs.



Year ended December 31,
------------------------------------------------------------------------
2004 2003
------------------------------------------------------------------------
$000 $/Boe $000 $/Boe $/boe
% change
------------------------------------------------------------------------
Gross revenue 40,748 37.01 27,056 34.95 6
------------------------------------------------------------------------
Hedges 1,032 0.93 55 0.07 1,228
------------------------------------------------------------------------
Royalties (11,510) (10.45) (8,165) (10.54) (1)
------------------------------------------------------------------------
ARTC & GCA 628 0.57 466 0.60 (5)
------------------------------------------------------------------------
Subtotal 30,898 28.06 19,412 25.08 12
------------------------------------------------------------------------
Operating costs (cash) (3,962) (3.60) (3,799) (4.91) (27)
------------------------------------------------------------------------
Operating netback 26,936 24.46 15,613 20.17 21
------------------------------------------------------------------------
Other 45 0.04 124 0.16 (75)
------------------------------------------------------------------------
Administration
costs (cash) (2,661) (2.42) (2,422) (3.13) (23)
------------------------------------------------------------------------
Interest costs (1,885) (1.71) (1,016) (1.31) (30)
------------------------------------------------------------------------
Taxes & other (269) (0.24) (352) (0.46) (48)
------------------------------------------------------------------------
Cash flow from
operations 22,166 20.13 11,947 15.43 30
------------------------------------------------------------------------

Three months ended December 31,
------------------------------------------------------------------------
2004 2003
------------------------------------------------------------------------
$000 $/Boe $000 $/Boe $/boe
% change
------------------------------------------------------------------------
Gross revenue 10,550 37.33 8,103 32.04 17
------------------------------------------------------------------------
Hedges 899 3.17 2 0.01 3,160
------------------------------------------------------------------------
Royalties (2,188) (7.74) (2,411) (9.53) (19)
------------------------------------------------------------------------
ARTC & GCA 36 0.13 (16) (0.06) 317
------------------------------------------------------------------------
Subtotal 9,297 32.89 5,678 22.46 46
------------------------------------------------------------------------
Operating costs (cash) (1,100) (3.89) (1,089) (4.31) (10)
------------------------------------------------------------------------
Operating netback 8,197 29.00 4,589 18.15 60
------------------------------------------------------------------------
Other 1 - 1 - -
------------------------------------------------------------------------
Administration
costs (cash) (571) (2.02) (775) (3.06) (34)
------------------------------------------------------------------------
Interest costs (449) (1.59) (444) (1.76) (10)
------------------------------------------------------------------------
Taxes & other (201) (0.71) (334) (1.32) (46)
------------------------------------------------------------------------
Cash flow from
operations 6,977 24.68 3,037 12.01 105
------------------------------------------------------------------------

Netbacks per BOE and cash flow from operations, by property
------------------------------------------------------------------------
Desan Ferrier Lochend Medicine Alexander Ricinus
Lodge /Newton
------------------------------------------------------------------------
Revenue 33.58 43.31 35.99 40.39 40.94 43.31
------------------------------------------------------------------------
Royalties (12.89) (9.79) (6.88) (12.82) (8.41) (0.92)
------------------------------------------------------------------------
Operating
costs (3.09) (3.97) (3.85) (2.28) (4.51) (9.21)
------------------------------------------------------------------------
Field netback 17.60 29.55 25.26 25.29 28.02 33.18
------------------------------------------------------------------------
Cash flow
(000's) 9,650 8,207 4,202 997 663 1,365
------------------------------------------------------------------------
Cash flow % 38% 33% 17% 4% 3% 5%
------------------------------------------------------------------------
Netbacks & cash flow at the property level do not include ARTC and
corporate hedging.


The netbacks at Desan will improve in 2005, as new ells are drilled on
non-GORR lands and per unit third party transportation costs are reduced.

The netbacks at Desan will improve as new wells are drilled on non-GORR
lands.

Depletion and Depreciation

Total depletion and depreciation for the year ended December 31, 2004
was $17.3 million compared to $12.3 million in 2003. The amounts were
higher in 2004 because of the much larger property and equipment
carrying value and higher production. Depletion and depreciation rates
for oil and gas properties were $15.68/boe for 2004, down slightly from
$15.76 in 2003. A ceiling test was performed as at December 31, 2004,
resulting in an excess of fair market value over net book value of
depletable assets of $24 million.

Depletion and depreciation was $4.9 million for the fourth quarter of
2004, compared to $3.8 million in 2003. Depletion and depreciation rates
for oil and gas properties were $17.46/boe for the fourth quarter of
2004, compared to $14.84/boe in 2003.

In January, 2004, High Point adopted a new accounting standard relating
to asset retirement obligations ("ARO"). For the fourth quarter and year
ended 2004 respectively, accretion expense of $33,031 and $111,949
relating to the ARO was recorded. This compares to $17,356 and $69,422
recorded for 2003 on a restated basis.

Stock-Based Compensation

Stock-based compensation expense of $127,445 was recorded for the fourth
quarter and $604,294 was recorded for 2004, pursuant to the new
accounting standard adopted January 1, 2004. There were no amounts
recorded in 2003.

Future Taxes

A future tax provision of $1,088,223 was recorded in 2004. The provision
includes a $1 million dollar recovery mainly relating to recognition of
an Alberta provincial tax rate reduction. Given current capital spending
levels, High Point does not expect to be taxable until 2006 or later.



------------------------------------------------------------------------
Future income tax liability $ 000s
------------------------------------------------------------------------
Balance at December 31, 2003 29,836
------------------------------------------------------------------------
Flow through share renouncement in 2004 50
------------------------------------------------------------------------
Tax effect of share issue costs (343)
------------------------------------------------------------------------
Provision for 2004 1,088
------------------------------------------------------------------------
Balance at December 31, 2004 30,631
------------------------------------------------------------------------


In 2003, High Point issued $16 million in flow-through shares and had
renounced the tax benefit of $16 million to the shareholders. Pursuant
to the 'look back' provisions governing flow-through shares, the
Corporation was required to spend the $16 million in exploratory capital
expenditures in 2004. As of December 31, 2004, the Corporation had
fulfilled its obligation.

In 2004, the Corporation issued $7.5 million in flow-through shares and
has renounced the tax benefit to the shareholders. By December 31, 2004,
the Corporation had spent $6.3 million in eligible capital expenditures,
leaving $1.2 million to be spent by December 31, 2005 under the 'look
back' provision. These amounts were spent early in 2005.

Earnings

The increased production and cash flow led to earnings of $3,015,676 or
$0.04 per share, compared to $1,644,101 or $0.03 per share in 2003. Net
earnings in the fourth quarter of 2004 were $1,451,298 or $0.02 per
share, compared to $453,246 or $0.01 per share in 2003. The results for
2003 have been restated due to the retroactive adoption of the new asset
retirement obligation standard.

Capital expenditures

Capital expenditures were $63.2 million in 2004, compared to $52.0
million in 2003. After dispositions, 2004 net capital expenditures were
$58.7 million. The 2004 expenditures include approximately $1.5 million
in pipe purchases related to first quarter 2005 drilling. A total of 41
wells (21.5 net) were drilled in 2004 or in progress at December 31,
2004, with a 98% success rate.

Fourth quarter capital expenditures in 2004 were $19.1 million, compared
to $12.5 million in the third quarter and $14.4 million in the fourth
quarter of 2003. A total of 10 wells (net 5.75) were drilled, or were
drilling, in the fourth quarter of 2004.



------------------------------------------------------------------------
Year ended Three months ended
$ 000s December 31, December 31,
------------------------------------------------------------------------
2004 2003 2004 2003
------------------------------------------------------------------------
Land 6,495 2,712 1,896 66
------------------------------------------------------------------------
Geological and geophysical 3,437 1,211 1,449 49
------------------------------------------------------------------------
Drilling, completions
and abandonments 39,431 37,944 13,063 12,056
------------------------------------------------------------------------
Plant and facilities 13,552 9,948 2,630 2,696
------------------------------------------------------------------------
Other assets 284 214 60 21
------------------------------------------------------------------------
Total capital expenditures 63,199 52,029 19,098 14,888
------------------------------------------------------------------------

Expenditures by area
------------------------------------------------------------------------
For the Drilling,
year ended Geological completion
December 31, 2004 and and Plant and
($ 000s) Land geophysical abandon facilities Other Total
------------------------------------------------------------------------
Desan - 1,103 16,036 7,286 - 24,425
------------------------------------------------------------------------
Lochend 7 - 1,444 622 - 2,073
------------------------------------------------------------------------
Ricinus 802 616 8,066 1,868 - 11,352
------------------------------------------------------------------------
Ferrier 2,584 1,117 10,906 2,105 - 16,712
------------------------------------------------------------------------
Kotcho-Sierra 66 148 1,841 - - 2,055
------------------------------------------------------------------------
Mackenzie - 390 - - - 390
------------------------------------------------------------------------
Other 3,036 63 1,138 1,671 284 6,192
------------------------------------------------------------------------
Total 6,495 3,437 39,431 13,552 284 63,199
------------------------------------------------------------------------


Effective January 28, 2004 the Corporation sold its gas producing
properties at Wembley, Alberta for proceeds of $1.1 million. Effective
November 1, 2004 the Corporation sold its gas producing properties at
Alexander and Newton for proceeds of $3.5 million.



Wells drilled
------------------------------------------------------------------------
Drilled & Drilled & Work in
producing standing progress
------------------------------------------------------------------------
Gross Net Gross Net Gross Net
------------------------------------------------------------------------
Desan 3 3.00 4 4.00 2 2
Lochend 4 0.84 2 0.42 1 0.21
Ferrier 8 3.01 - - 8 3.32
Ricinus 3 2.76 - - 1 0.75
Kotcho - - 1 0.45 - -
Other 4 0.71 - - - -
Total 22 10.32 7 4.87 12 6.28
------------------------------------------------------------------------


A total of $6.5 million was spent in 2004 on land acquisition, with $2.6
million spent to acquire 24 sections of land at Peggo/Pesh in
northeastern B.C. and $2.5 million to acquire 9 1/2 sections at Ferrier,
all at a 100% working interest. The acquisition of these lands
perpetuates High Point's 3-year inventory of in-house exploration and
development projects.

The winter drilling program at Desan saw seven gas wells drilled in the
first quarter of 2004, with three tied in and on production, and four
requiring further testing this winter. A total of 16 Desan wells were on
production during 2004. In December 2004, two new wells were spud at
Desan and were drilling at December 31, 2004. The wells are part of the
2005 winter drilling program of six to eight wells, which will be
completed by March 31, 2005.

At Lochend, seven oil/gas wells were drilled, with four put on
production and one currently being tied in, while two others are
awaiting further evaluation.

At Ferrier, sixteen gas wells were drilled, with eight on production and
eight being completed and tied in during the first quarter of 2005. Wet
fall conditions and difficulty in procuring field services delayed the
tie-in of these wells.

Three exploratory gas wells at Ricinus were drilled, tied in and on
production at December 31, 2004, with a fourth well being tied in and on
production in January 2005.

Plant and facilities expenditures of $13.6 million reflect the
construction of compression facilities and associated pipelines in 2004
at Desan, Ferrier and Ricinus. Ownership of these facilities improves
operational control and keeps operating costs low.

Shares Outstanding

At December 31, 2004, 79,386,196 common shares were outstanding. At the
date of this report, there are 79,446,197 common shares outstanding and
5,297,333 stock options outstanding to employees, consultants, officers
and directors, with an average exercise price of $1.51 per share. All
options are granted for a maximum term of five years and vest one third
upon issue, one third after one year, and one third after two years.

Debt and Working capital

At year-end, High Point had a $12.0 million working capital deficiency
and had drawn $50 million on its $60 million bank credit facility.



------------------------------------------------------------------------
December 31, December 31,
($ 000's) 2004 2003
------------------------------------------------------------------------
Cash & working capital (deficiency) (12,004) (10,006)
Bank debt (50,000) (20,000)
Bridge financing - (10,000)
------------------------------------------------------------------------
Net debt (62,004) (40,006)
------------------------------------------------------------------------
------------------------------------------------------------------------

------------------------------------------------------------------------
Source of funds used in 2004 $ 000s
------------------------------------------------------------------------
Net proceeds from disposal of properties 4,601
Decrease in bridge financing (10,000)
Increase in bank financing 30,000
Issuance of shares, net of costs 14,175
Funds provided by operations 22,166
Change in cash and working capital 1,998
Other 259
63,199

------------------------------------------------------------------------
Additions to property and equipment 63,199
------------------------------------------------------------------------


Liquidity and Capital Resources

The $63.2 million capital expenditure program in 2004 was funded by cash
flow from operations of $22.2 million, an equity issue of $14.2 million
net of issue costs, $4.6 million of proceeds from asset sales, and an
increase of $22.0 million in net debt.

On May 11, 2004, the Corporation issued 3,870,000 common shares at $1.95
per share and 3,000,000 flow-through shares at $2.50 per share for total
proceeds of $15,046,000. Costs of $870,479 were recorded in relation to
the issue.

On July 21, 2004, the bank credit facility was increased from $32
million to $52 million and the $15 million bridge financing facility was
repaid. The repayment consolidated the Corporation's debt and lowered
overall interest costs.

The $52 million bank credit facility was increased to $60 million on
December 17, 2004. On December 2, 2004 a $15 million standby bridge
financing facility was signed and may be drawn anytime up to March 31,
2005. The Corporation's cash flow and credit facilities are sufficient
to fund the planned capital expenditures program for 2005.

Reserves

High Point retained the independent engineering firm of Gilbert Laustsen
Jung Associates Ltd. ("GLJ") to evaluate the Corporation's reserve
properties at December 31, 2004.



Reserves reconciliation
------------------------------------------------------------------------
Crude oil and liquids (mbbl)
------------------------------------------------------------------------
Proven Probable Total
------------------------------------------------------------------------
Total at December 31, 2003 1,338.7 386.8 1,725.5
Development 665.5 335.5 1001
Acquisitions - - -
Dispositions (1) - (1)
Production (183.2) - (183.2)
Revisions 24 (124.8) (100.8)
------------------------------------------------------------------------
Total at December 31, 2004 1,844 597.5 2,441.5
------------------------------------------------------------------------
------------------------------------------------------------------------

------------------------------------------------------------------------
Natural gas (bcf)
------------------------------------------------------------------------
Proven Probable Total
------------------------------------------------------------------------
Total at December 31, 2003 41.3 8.78 50.08
Development 8.38 3.18 11.56
Acquisitions - - -
Dispositions (0.67) (0.18) (0.85)
Production (5.51) - (5.51)
Revisions 0.36 (1.11) (0.75)
------------------------------------------------------------------------
Total at December 31, 2004 43.86 10.67 54.53
------------------------------------------------------------------------
------------------------------------------------------------------------

------------------------------------------------------------------------
Barrel equivalent (6:1) (mmbbl)
------------------------------------------------------------------------
Proven Probable Total
------------------------------------------------------------------------
Total at December 31, 2003 8.22 1.85 10.07
Development 2.06 0.87 2.93
Acquisitions - 0.00
Dispositions (0.11) (0.03) (0.14)
Production (1.1) - (1.1)
Revisions 0.08 (0.31) (0.23)
------------------------------------------------------------------------
Total at December 31, 2004 9.15 2.38 11.53
------------------------------------------------------------------------
------------------------------------------------------------------------

GLJ used the following pricing assumptions in the escalated reserves
pricing case.

------------------------------------------------------------------------
Pricing WTI Edmonton Reference AECO-C Spot
assumptions ($U.S./bbl) Price ($Cdn./bbl) Price ($Cdn./MMBTU)
------------------------------------------------------------------------
2005 42.00 50.25 6.60
2006 40.00 47.75 6.35
2007 38.00 45.50 6.15
2008 36.00 43.25 6.00
------------------------------------------------------------------------

Summary of reserve value - escalated prices
------------------------------------------------------------------------
Reserves category Oil mbbl Sales Gas mmcf NGL mbbl
------------------------------------------------------------------------
Gross Net Gross Net Gross Net
------------------------------------------------------------------------
Proved producing 4 3 37,454 28,636 1,363 966
Proved developed
nonproducing 54 47 2,176 1,652 120 80
Proved undeveloped 0 0 4,222 3,498 304 217
Total proved 58 50 43,852 33,786 1,787 1,263
------------------------------------------------------------------------
------------------------------------------------------------------------
Probable 91 72 10,685 8,141 507 346
Total proved plus
probable 149 122 54,537 41,927 2,294 1,609
------------------------------------------------------------------------
------------------------------------------------------------------------

------------------------------------------------------------------------
Cumulative Cash Flow (BIT) $ 000
------------------------------------------------------------------------
Reserves category Discounted (per year) at:
------------------------------------------------------------------------
0% 10% 15%
------------------------------------------------------------------------
Proved producing 157,571 95,382 80,907
Proved developed nonproducing 12,331 8,192 7,103
Proved undeveloped 19,448 6,408 4,119
Total proved 189,350 109,982 92,129
------------------------------------------------------------------------
------------------------------------------------------------------------
Probable 48,224 16,483 11,822
Total proved plus probable 237,574 126,465 103,951
------------------------------------------------------------------------
------------------------------------------------------------------------


Gross reserves are the total of the Company's working and/or royalty
interest share before deduction of royalties owned by others.

Net reserves are the total of the Company's working and/or royalty
interest share after deducting the amounts attributable to royalties
owned by others.

Land

High Point's undeveloped land was valued at $16.0 million at December
31, 2004 by Seaton-Jordan & Associates Ltd. The Corporation's land
holdings at December 31, 2004 were as follows:



------------------------------------------------------------------------
Developed Undeveloped Total
------------------------------------------------------------------------
Gross Net Gross Net Gross Net
------------------------------------------------------------------------
Alberta 26,412 10,961 107,795 37,918 134,207 48,879
British Columbia 12,871 12,871 73,684 69,866 86,555 82,737
------------------------------------------------------------------------
Total 39,283 23,832 181,479 107,784 220,762 131,616
------------------------------------------------------------------------
------------------------------------------------------------------------


In 2004, High Point acquired 24 sections of land at Peggo/Pesh in
northeastern B.C. and 9 1/2 sections at Ferrier, all at a 100% working
interest. At Ricinus, High Point increased its working interest in
existing lands and purchased 10 sections of exploratory land with deeper
zone potential. The acquisition of these lands perpetuates High Point's
3-year inventory of in-house exploration and development projects.



Net asset value - December 31, 2004
------------------------------------------------------------------------
Discounted at 0% 5% 10%
------------------------------------------------------------------------
Present value of P+P reserves 237,574 164,128 126,465
Value of undeveloped land 16,006 16,006 16,006
Seismic value 10,900 10,900 10,900
Stock option proceeds 8,029 8,029 8,029
Net debt (62,004) (62,004) (62,004)
------------------------------------------------------------------------
Net asset value 210,505 137,059 99,396
Diluted shares outstanding (thousands) 84,744 84,744 84,744
------------------------------------------------------------------------
Net asset value per share $ 2.48 $ 1.62 $ 1.17
------------------------------------------------------------------------


A company's reserve life has a significant impact on net asset values.
The present value of High Point's long life reserves is impacted more
severely by discount rates and backwardized oil and gas prices than is
the case for companies with short life reserves.

The GLJ engineering evaluation forecasts future capital of $11.7 million
to develop the proved and probable reserves. This capital expenditure
represents 34 percent of the forecast cash flow for proved and probable
reserves in 2005. Full reinvestment of cash flow would result in a
significant increase in the value of the company.

Contractual Obligations

The Corporation has lease arrangements for office space to April 30,
2006. The future minimum lease payments total $437,989 (2005 - $328,492
and 2006 - $109,497).

Off-Balance Sheet Obligations

The Corporation has no off-balance sheet obligations.

Changes in Accounting Policies

Stock-based compensation

Effective January 1, 2004, the Corporation adopted a new accounting
standard on stock based compensation as presented in the CICA Handbook
section 3870. The standard requires the recognition of stock based
compensation expense for all employees and non-employees using the fair
value method with recognition of compensation awards as an expense. The
Corporation adopted the new accounting policy in 2004 on a retroactive
basis with no restatement of prior periods. Accordingly on January 1,
2004 the accumulated deficit and share capital were increased by
$955,315. The Black-Scholes option pricing model has been used to
calculate the fair value of the stock options granted. For the twelve
months ended December 31, 2004, the Corporation recognized a
compensation expense of $604,294.

Asset retirement obligation

The Corporation adopted the new standard for asset retirement
obligations, as set out in the CICA Handbook section 3110, effective
January 1, 2004. The new standard requires the recognition and
measurement of future liabilities related to the legal obligation to
abandon and reclaim property, plant and equipment. The liability must be
recorded at fair value in the period in which the asset is recorded,
with a corresponding increase in the recorded amounts for oil and gas
properties. The amount of the asset retirement obligation accretes over
time until the obligation is settled.

Full cost accounting guideline

The Corporation adopted the new guideline for full cost accounting as
laid out in Accounting Guideline 16, whereby the carrying value of oil
and gas properties is limited to their estimated fair value. The fair
value is calculated based on the expected future cash flows from proved
and probable reserves using expected future prices and costs discounted
at a risk-free rate. The adoption of this new policy at December 31,
2003 resulted in no changes to the financial statements.

Critical Accounting Estimates

There are a number of critical estimates underlying the accounting
policies we employ in preparing the Consolidated Financial Statements.

Revenue estimates

Payment for sales in the oil and gas industry occurs up to two months
after the month of production. Sales are estimated based upon
information received from field offices regarding production levels and
published industry pricing and transportation data.

Cost estimates

Costs for services performed but not yet billed are estimated based on
original quotes and historical cost information.

Reserves

The full cost method of accounting, which is used to account for oil and
gas activities, relies on estimates of proven reserves that will
ultimately be recoverable from the properties. These estimates are
utilized in calculating unit-of-production depletion, potential
impairment of asset carrying costs and future site restoration expense.
The process of estimating reserves is complex and requires significant
judgement, based on available geological, geophysical, engineering and
economic data.

Reserves are evaluated at year-end by an independent engineering firm
and quarterly updates to those reserves, as well as new reserves from
wells drilled in the current year, are estimated by Company engineers.

Although we make every effort to ensure that our critical estimates are
accurate, changing economic and operational conditions, as well as
governmental regulations, can significantly affect those estimates,
which may cause significant fluctuation in earnings, cash flows and
finding and on-stream costs.

Business Risks

High Point is engaged in the exploration, development and production of
crude oil and natural gas. The oil and gas business is inherently risky
and there is no assurance that hydrocarbon reserves will be discovered
and economically produced. Operational risks include competition,
reservoir performance uncertainties, environmental factors, and
regulatory, environment and safety concerns. Financial risks associated
with the petroleum industry include fluctuations in commodity prices,
interest rates, currency exchange rates and the cost of goods and
services.

High Point employs highly qualified and motivated professionals, uses
sound operating and business practices, and evaluates all potential and
existing wells using the latest technology. High Point complies with
government regulations and has in place an up-to-date emergency response
test. Environment and safety policies and standards are strictly adhered
to. High Point maintains property and liability insurance coverage, as
well as business interruption insurance on key properties. A commodity
hedging program is in place to protect product pricing on a portion of
production and ensure cash flows are available for reinvestment.



Cash Flow Sensitivities

Cash Flow Per Share
($ 000's) Basic

Natural gas price change of $0.10/mcf 610 .008
Natural gas production change of 1 mmcf/day 1,628 .020
Crude oil and NGLs price change of $1.00 CDN per bbl 202 .002
NGLs production change of 100 bbls/day 816 .010
Interest rate change of 1% on 2005 bank debt 627 .008
Foreign exchange rate of $0.01 ($US - CDN) 575 .007


Cash flow sensitivities are calculated as they relate to the
Corporation's 2005 budgeted revenues and expenses, and outstanding
shares at December 31, 2004. The Corporation's current hedging contracts
have not been reflected in these sensitivities.

Outlook

High Point is currently completing its first quarter drilling program,
with six wells drilled at Desan, two at Ricinus and one at Ferrier.
Several wells drilled in 2004 in the Ferrier area were not tied in until
March, resulting in first quarter 2005 production that is expected to be
relatively flat. As the Ferrier wells are tied in and the expected
production from first quarter drilling comes on-stream in early April,
production volumes are expected to exceed 4,000 boe per day, with
average production for 2005 expected to be 30% higher than in 2004.

A capital budget of $50 million has been approved for 2005, which
includes the winter drilling program at Desan and Ricinus, as well as
another active summer drilling program of 10-15 wells at Ferrier/Ricinus
and the redrilling of the exploratory well at Kotcho. A farm-in on a
deeper target at Ricinus will result in an exploratory well being
drilled in April/May. As production increases in 2005, cash flow will
increase to bring debt to cash flow ratios to less than two times. Cash
flows are forecast to grow to a level where cash flows can sustain the
ongoing capital expenditure program looking forward to 2006 and beyond.



Quarterly Review of Operating and Financial Performance
------------------------------------------------------------------------
2004 First Second Third Fourth
Quarter Quarter Quarter Quarter Total
------------------------------------------------------------------------
Average daily production
Natural gas (mcf/d) 14,069 16,480 15,080 15,037 15,166
Oil and liquids (bbl/d) 442 449 465 566 481
Barrels equivalent (boe/d) 2,787 3,196 2,978 3,072 3,009

Prices
Natural gas ($/mcf) 6.12 6.46 5.85 6.55 6.25
Light oil ($/bbl) 41.25 47.49 63.62 57.13 48.71
Natural gas liquids ($/bbl) 33.45 35.21 38.12 45.40 39.28

Financial ($000)
Net petroleum and natural
gas sales 6,649 7,682 7,270 9,297 30,898
Cash flow from operations 4,618 5,405 5,166 6,977 22,166
Per share - basic and
diluted 0.07 0.07 0.07 0.09 0.29
Net income (loss) after tax 1,321 (298) 542 1,451 3,016
Per share - basic and
diluted 0.02 (0.00) 0.01 0.02 0.04
Total assets 170,868 172,963 182,925 193,363 193,363
Long term financial
liabilities 0 0 0 0 0
------------------------------------------------------------------------
2003 (restated) First Second Third Fourth
Quarter Quarter Quarter Quarter Total
------------------------------------------------------------------------
Average daily production
Natural gas (mcf/d) 5,669 10,006 11,225 13,533 10,133
Oil and liquids (bbl/d) 369 396 471 493 433
Barrels equivalent (boe/d) 1,314 2,063 2,341 2,749 2,121

Prices
Natural gas ($/mcf) 7.46 6.22 5.48 5.33 5.88
Light oil ($/bbl) 48.57 39.96 39.73 37.12 41.12
Natural gas liquids ($/bbl) 43.42 30.94 31.94 31.69 32.61

Financial ($000)
Net petroleum and natural
gas sales 3,530 4,806 5,398 5,678 19,412
Cash flow from operations 2,462 3,587 2,861 3,037 11,947
Per share - basic and
diluted 0.06 0.08 0.04 0.04 0.22
Net income (loss) after tax 295 1,885 (989) 454 1,644
Per share - basic and
diluted 0.01 0.04 (0.02) 0.01 0.03
Total assets 71,820 74,702 140,832 151,813 151,813
Long term financial
liabilities 2,862 2,881 2,899 2,918 2,918
------------------------------------------------------------------------


HIGH POINT RESOURCES INC.
Consolidated Balance Sheets
As at December 31
------------------------------------------------------------------------
------------------------------------------------------------------------
2004 2003
-------------------------
(Restated
- Note 2)
ASSETS (note 6) $ $

CURRENT
Cash and cash equivalents - 2,148,978
Accounts receivable 9,951,298 7,705,266
Prepaid expenses and deposits 678,580 735,127
-------------------------
10,629,878 10,589,371

Goodwill (note 3) 14,674,423 14,588,938

Property and equipment (note 4) 168,059,132 126,635,044
-------------------------
193,363,433 151,813,353
-------------------------
-------------------------

LIABILITIES

Current
Bank indebtedness 131,433 -
Accounts payable and accrued liabilities 22,502,551 20,595,297
Short-term debt (note 6) - 10,000,000
Bank debt (note 6) 50,000,000 20,000,000
-------------------------
72,633,984 50,595,297

Convertible debentures (note 7) - 2,917,967

Asset retirement obligation (note 5) 1,793,436 1,521,265

Future tax liability (note 9) 30,631,057 29,836,165
-------------------------
105,058,477 84,870,694
-------------------------

Commitments (notes 10 and 11)

SHAREHOLDERS' EQUITY

Share capital (note 8) 91,151,899 73,185,579
Contributed surplus (note 8(iv)) 1,559,609
Common stock conversion rights (note 8(i)) - 223,993
Deficit (4,406,552) (6,466,913)
-------------------------
88,304,956 66,942,659
-------------------------
193,363,433 151,813,353
-------------------------
-------------------------
See accompanying notes



HIGH POINT RESOURCES INC.
Consolidated Statements of Operations and Deficit
Year Ended December 31
------------------------------------------------------------------------
------------------------------------------------------------------------
2004 2003
-------------------------
$ $
-------------------------
(Restated
- Note2)
REVENUE

Petroleum and natural gas 44,111,853 28,761,159
Royalties, net of ARTC (10,881,856) (7,698,531)
Transportation expense (2,331,701) (1,650,486)
-------------------------
Petroleum and natural gas sales,
net after royalties and transportation 30,898,296 19,412,142
Other income 44,758 124,500
-------------------------
30,943,054 19,536,642
-------------------------

EXPENSES

Operating 3,961,903 3,798,875
Asset retirement accretion (notes 2 and 3) 111,949 69,422
General and administration 2,661,482 2,422,049
Stock-based compensation (notes 2 and 8(iv)) 604,294 -
Depletion and depreciation 17,324,922 12,339,486
Interest 1,885,310 1,016,397
Accretion on debentures (note 7) 20,508 74,360
-------------------------
26,570,368 19,720,589
-------------------------

EARNINGS (LOSS) BEFORE INCOME TAXES 4,372,686 (183,947)

PROVISION FOR (RECOVERY OF) INCOME TAXES (note 9)

Current 268,787 351,935
Future 1,088,223 (2,179,983)
-------------------------

NET EARNINGS 3,015,676 1,644,101
-------------------------
-------------------------

DEFICIT, BEGINNING OF YEAR (6,466,913) (8,248,746)
-------------------------
Retroactive application of change
in accounting policy (note 2) (955,315) 137,732
-------------------------
DEFICIT, END OF YEAR (4,406,552) (6,466,913)
-------------------------
NET EARNINGS PER SHARE (note 8)
(basic and diluted) 0.04 0.03
-------------------------

See accompanying notes


HIGH POINT RESOURCES INC.
Consolidated Statements of Cash Flows
Year Ended December 31
------------------------------------------------------------------------
------------------------------------------------------------------------
2004 2003
$ $
-------------------------
(Restated
- note 2)
Cash provided by (used in):

OPERATING ACTIVITIES
Net earnings 3,015,676 1,644,101
Add items not requiring cash:
Depletion and depreciation 17,324,922 12,339,486
Future income taxes 1,088,223 (2,179,983)
Accretion on debentures (note 7) 20,508 74,360
Asset retirement accretion (notes 2 and 5) 111,949 69,422
Stock based compensation (notes 2 and 8(iv)) 604,294 -
-------------------------
CASH FLOW FROM OPERATIONS 22,165,572 11,947,386

Change in non-cash working capital relating
to operating activities (2,026,759) (5,659,973)
-------------------------
20,138,813 6,287,413
-------------------------
FINANCING ACTIVITIES
Increase in bank debt 30,000,000 20,000,000
Issue of common shares 14,175,521 39,535,537
Increase (decrease) in short-term debt (10,000,000) 10,000,000
Proceeds from notes receivable (note 8(iii)) 335,000 450,000
-------------------------
34,510,521 69,985,537
-------------------------
INVESTING ACTIVITIES
Additions to property and equipment (62,972,499) (51,517,139)
Abandonments (226,674) (512,296)
Acquisition of company (note 3) - (28,659,909)
Proceeds on sale of oil and gas properties
(note 4) 4,600,623 3,247,929
Working capital assumed on acquisition of
company (note 3) (75,723) (6,674,740)
Change in non-cash working capital related
to investing activities 1,744,528 7,835,459
-------------------------
(56,929,745) (76,280,696)
-------------------------
INCREASE (DECREASE) IN CASH (2,280,411) (7,746)

CASH (BANK INDEBTEDNESS), BEGINNING OF YEAR 2,148,978 2,156,724
-------------------------

CASH (BANK INDEBTEDNESS), END OF YEAR (131,433) 2,148,978
-------------------------
-------------------------

SUPPLEMENTARY INFORMATION
Cash interest paid 1,885,310 1,016,397
Cash taxes paid 268,787 351,935


See accompanying notes


Notes to the Consolidated Financial Statements

1. DESCRIPTION OF BUSINESS

High Point Resources Inc. (hereafter "High Point" or the "Corporation")
is incorporated under the Business Corporations Act of Alberta and its
principal business activity is petroleum and natural gas exploration
development and production in Western Canada. High Point is listed on
the TSX Exchange under the symbol "HPR".

2. SIGNIFICANT ACCOUNTING POLICIES

The consolidated financial statements include the accounts of the
Corporation and its wholly-owned subsidiaries.

The consolidated financial statements which have been prepared in
accordance with Canadian generally accepted accounting principles, have
in management's opinion been properly prepared within reasonable limits
of materiality and within the framework of the accounting policies
summarized below:

Cash and cash equivalents

Short-term investments with initial maturities less than three months
are considered to be cash equivalents and are recorded at cost, which
approximates fair market value.

Property and equipment

Petroleum and natural gas properties and related equipment

The Corporation follows the full-cost method of accounting whereby all
costs related to the exploration for and development of petroleum and
natural gas reserves, whether productive or unproductive, are
capitalized in one Canadian cost centre. Such costs include land
acquisition, drilling, equipping, geological and geophysical and
overhead expenses related to exploration and development activities.
These costs are depleted on the unit-of-production method using
estimated gross proven petroleum and natural gas reserves as determined
by independent professional engineers. Petroleum and natural gas
reserves are converted to a common unit of measure on an energy
equivalent basis of six mcf of gas to one barrel of oil. Costs of
acquiring and evaluating unproven properties are excluded from depletion
calculations until it is determined whether or not proven reserves are
attributable to the properties or impairment occurs.

Proceeds from the sale of petroleum and natural gas properties and
related equipment are applied against capitalized costs, with no gain or
loss recognized, unless such a sale would result in a change in the rate
of depletion of 20% or more.

Ceiling test

Effective January 1, 2004, the Corporation adopted the new CICA
accounting guideline for full cost accounting as per CICA accounting
guideline 16. Under the new guideline, future net revenues from 'total
proven reserves' used in the 'ceiling test' calculation are estimated
using expected future product prices and costs ('escalating'), whereas
prior to the adoption, constant pricing was used. Future general and
administrative, and financing charges, associated with the future net
revenues are no longer deducted in arriving at the 'ceiling' value.
Where a ceiling test failure occurs, 'probable' reserve values may now
be included in determining the impairment amount which is based on the
fair value of the associated reserves.

The adoption of the new guideline has resulted in no change to net
income, fixed assets or other reported amounts in the consolidated
financial statements.

Office furniture, equipment and other

Office furniture, equipment and other assets are recorded at cost and
depreciated on a declining balance basis at rates varying from 20% to
30%.

Asset retirement obligation

In 2004 the Corporation adopted the new CICA accounting standard for
asset retirement obligations. The standard requires the recognition and
measurement of liabilities related to the legal obligation to abandon
and reclaim property, plant and equipment upon acquisition,
construction, development and/or normal use of the asset. The initial
liability must be measured at fair value and subsequently adjusted for
the accretion of discount and changes in the fair value. The asset
retirement cost is capitalized as part of property and equipment and
depleted into earnings over time.

The adoption of the standard has been applied retroactively with
restatement of prior periods and the impact is outlined below:



As at
Balance Sheet December 31, 2003
Increase (decrease) $
--------------------------------------------------------------------
Asset retirement costs included in
property and equipment 1,451,843
Accumulated amortization of costs included
in property and equipment 90,480
Asset retirement obligation 1,521,265
Future site restoration and abandonment costs (451,886)
Retained earnings (deficit) 291,984


--------------------------------------------------------------------
Income Statement Twelve months ended
Increase (decrease) December 31, 2003
$
--------------------------------------------------------------------
Accretion expense 69,422
--------------------------------------------------------------------
Depletion and depreciation 90,480
--------------------------------------------------------------------
Provision for future site restoration and abandonment (314,154)
--------------------------------------------------------------------
Net income 154,252
--------------------------------------------------------------------
Net income per share 0.003
--------------------------------------------------------------------


Revenue recognition

Petroleum and natural gas sales are recognized when commodities are sold.

Transportation expenses

Transportation expenses to move gas to the inlet to the Nova pipeline
system are recorded as a reduction in sales revenue.

Joint interests

Some of the Corporation's petroleum and natural gas activities are
conducted jointly with others. These consolidated financial statements
reflect only the Corporation's proportionate interest in such activities.

Measurement uncertainty

The amounts recorded for depletion and depreciation of property and
equipment, the asset retirement obligation, and the ceiling test
calculation are based on estimates of proven reserves, production rates,
oil and natural gas prices, future costs and other relevant assumptions.
By their nature, these estimates are subject to measurement uncertainty
and the effect on the financial statements of changes in such estimates
in future years could be significant.

Income taxes

The liability method is used in accounting for income taxes. Under this
method, future income tax assets and liabilities are recognized based on
differences between the financial reporting and tax bases of assets and
liabilities, and measured using the substantively enacted tax rates and
laws that will be in effect when the differences are expected to
reverse. The effect on future tax assets and liabilities of a change in
tax rates is recognized in income in the period in which the change
occurs.

Flow-through shares

The Corporation has financed a portion of its exploration and
development activities through the issuance of flow-through shares.
Under the terms of the flow-through share agreements, the tax attributes
of the related expenditures are renounced to subscribers. To recognize
the foregone tax benefits to the Corporation, the carrying value of the
shares issued is reduced by the tax effect of the tax benefits renounced
to subscribers when the renouncements are filed.

Financial instruments

The Corporation periodically enters into commodity price derivative
instruments to reduce the Corporation's exposure to adverse fluctuations
in commodity prices. No contracts are entered into for trading or
speculative purposes. Gains and losses relating to commodity swaps that
meet hedge criteria are recognized as part of petroleum and natural gas
revenue concurrently with the hedged transaction.

Financial instruments recognized on the balance sheet include cash and
cash equivalents, accounts receivable, bank indebtedness, accounts
payable, short-term debt, bank debt and convertible debentures. As at
December 31, 2004 and 2003 there are no significant differences between
the carrying amounts reported on the balance sheet and their estimated
fair values.

Stock-based compensation

Effective January 1, 2004, the Corporation adopted the new CICA
accounting standard for stock based compensation. The standard requires
the recognition of stock based compensation expense for all employees
and non-employees using the fair value method with recognition of
compensation awards as an expense. The Corporation adopted the new
accounting policy in 2004 on a retroactive basis with no restatement of
prior periods. Accordingly on January 1, 2004 the accumulated deficit
and share capital were increased by $955,315 to reflect the cumulative
effect of the change on prior periods. The Black-Scholes option pricing
model has been used to calculate the fair value of the stock options
granted.

Goodwill

Goodwill, which represents the excess of purchase price over fair value
of net assets acquired, is not amortized and is assessed by the
Corporation for impairment at least annually. Impairment is assessed
based on a comparison of fair value of the net assets acquired to the
carrying value of the net assets, including goodwill. Any excess of
carrying value over and above fair value is the impairment amount, and
is charged to earnings in the period identified.

3. ACQUISITION OF GLACIER RIDGE RESOURCES LTD.

On July 15, 2003, the Corporation acquired all of the issued and
outstanding shares of Glacier Ridge Resources Ltd. ("Glacier"). The
Glacier acquisition was accounted for by the purchase method and shares
were acquired for an aggregate of:

a. $28.5 million in cash and transaction costs of $159,909;

b. $10.5 million payable by the issuance of 6,562,504 common shares of
High Point at a deemed value of $1.70 per common share; and

c. non-interest bearing promissory notes due August 31, 2004 in an
aggregate amount equal to a portion of the difference in reserve value
of Glacier's properties on July 1, 2004 compared with April 1, 2003, and
which was not to exceed $4.2 million. On the date of acquisition, no
value was assigned to the notes as the amount could not be quantified.
Glacier's bank debt and working capital deficit, totaling approximately
$6.7 million, were assumed in the acquisition. At August 31, 2004 the
promissory notes expired with no additional reserve value attributed to
the Glacier properties during the agreement period ended July 1, 2004.

In 2004, the Corporation increased goodwill by $85,485 to reflect an
increase in Glacier Ridge's pre acquisition working capital deficit and
an adjustment to the carrying value of property, plant and equipment.



--------------
Calculation of Purchase Price: $
--------------
Fair value of cash and shares issued 39,656,257
Transaction costs 159,909
--------------
39,816,166
--------------
--------------
Allocation of Purchase Price:
Goodwill 14,674,423
Property, plant & equipment 43,605,213
Working capital deficit and debt (6,750,463)
Future site restoration (59,199)
Future income tax (11,653,808)
--------------
39,816,166
--------------
--------------


4. PROPERTY AND EQUIPMENT

--------------------------------------------
2004
--------------------------------------------
Accumulated
Historical Depletion and Net Book
Cost Depreciation Value
$ $ $
--------------------------------------------
Petroleum and natural gas
properties and related
equipment 217,880,920 50,048,221 167,832,699
Office furniture, equipment
and other 576,429 349,996 226,433
--------------------------------------------
218,457,349 50,398,217 168,059,132
--------------------------------------------
--------------------------------------------

--------------------------------------------
2003
--------------------------------------------
Accumulated
Historical Depletion and Net Book
Cost Depreciation Value
$ $ $
--------------------------------------------
Petroleum and natural gas
properties and related
equipment 159,229,615 32,782,610 126,447,005
Office furniture, equipment
and other 576,576 388,537 188,039
--------------------------------------------
159,806,191 33,171,147 126,635,044
--------------------------------------------
--------------------------------------------


On January 28, 2004, the Corporation sold its interest at Wembley,
Alberta, for net proceeds of $1,086,623, and on November 1, 2004, the
Corporation sold its interest at Alexander/Newton, Alberta, for proceeds
of $3,514,000. No gain or loss was recognized on these disposals.

On December 1, 2003, the Corporation sold its interest at Progress and
Monitor Alberta, as well as its heavy oil properties at Lloydminster,
Saskatchewan for net proceeds of $2,535,948. In addition, various other
minor interests were sold for proceeds of $711,981 in 2003.

During 2004, $258,741 of general and administrative expenses were
capitalized (nil in 2003).

At December 31, 2004, carrying costs of $13,500,891 (2003 - $8,050,497)
related to unproven properties have been excluded from the depletion
calculation.

At December 31, 2004, property, plant and equipment includes costs of
$1,571,759 related to the asset retirement obligation (net of
depletion). Actual abandonment costs for 2004 were $226,674 (2003 -
$512,296).

5. ASSET RETIREMENT OBLIGATION

The Corporation's asset retirement obligations result from net ownership
interests in oil and gas assets. The total estimated undiscounted cash
flows required to settle these asset retirement obligations is
approximately $3.8 million which will be incurred between 2004 and 2024.
A credit adjusted risk free rate of 8% and an inflation rate of 2.1%
were used to calculate the fair value of the obligation.



------------------------------------------------------------------------
Asset Retirement Obligation Years ended
December 31, December 31,
2004 2003
------------------------------------------------------------------------
Balance - beginning of year 1,521,265 867,781
Liabilities incurred 386,896 1,096,358
Accretion expense 111,949 69,422
Liabilities settled (226,674) (512,296)
Balance - end of year 1,793,436 1,521,265
------------------------------------------------------------------------


6. LOANS

At December 31, 2004, the Corporation has a revolving term credit
facility with a Canadian chartered bank. The facility consists of two
parts, Part A is for $54,000,000 with interest at the bank's prime rate
plus 0.25%, and Part B is for an additional $6,000,000 with interest at
the bank's prime rate plus 1.25%. Collateral for the facility consists
of a demand debenture for $100,000,000 secured by a first floating
charge over all assets. At December 31, 2004, $50,000,000 was drawn
against the credit facility.

The Corporation had additional financing by way of a 'Secured
Development Bridge Facility' set up with a Canadian lending corporation.
This facility provided $10,000,000 on November 17, 2003 with an
additional $5,000,000 drawn on January 28, 2004. The effective interest
rate was at bank prime plus 3% and the maturity date was January 1,
2005. In addition, the lender was granted a 5% gross overriding royalty
('GOR') on selected future development projects, reducing to a 1.6% GOR
upon prepayment of the loan.

On July 21, 2004, the Corporation repaid the $15,000,000 'Secured
Development Bridge Facility'. In doing so, the Gross Overriding Royalty
which was placed on specific development projects during the loan
period, was fixed at 1.6%.

On December 2, 2004 a standby 'Secured Development Bridge Facility' was
set up with a Canadian lending corporation. The facility would allow for
up to two drawdowns before March 31, 2005 for a minimum of $7,500,000 on
the first drawdown, and to a maximum of $15,000,000 combined. Interest
would be paid at bank prime plus 3.25%. As of December 31, 2004, the
facility was not activated and no amount had been drawn against it. On
March 4, 2005 the first drawdown of $7,500,000 occurred, with a second
draw planned before the end of March, 2005.

For the year ended December 31, 2004, the effective interest rate on all
borrowings was 4.4% (4.7% in 2003).

7. CONVERTIBLE DEBENTURES

The Corporation had convertible debentures outstanding of $3,000,000 at
December 31, 2003. Pursuant to the terms of the debentures the holders
exercised their right to convert the debentures into common shares at
$1.60 per share prior to March 31, 2004 (see note 8(i)). Interest on the
debentures was payable quarterly at an annual rate of 7%.

For the first quarter of 2004, the Corporation incurred interest expense
of $48,818 on the debentures plus non-cash financing charges of $20,508
related to the accretion of the discount on the debentures.



8. SHARE CAPITAL

Authorized
Unlimited number of voting common shares with no par value
Unlimited number of non-voting preferred shares issuable in series

--------------------------
Issued and outstanding common shares Number of Amount
Shares $
--------------------------
Balance at December 31, 2002 39,366,150 31,626,326
Issue of common shares for cash (ii) 7,634,207 11,069,600
Issue on acquisition of Glacier (v) 15,937,504 26,156,257
Issued for cash on exercise of stock options 331,667 208,500
Issue of flow-through common shares for
cash (ii) 7,200,000 16,000,000
Share issue costs, net of tax of $1,117,595 (1,624,969)
Tax benefits renounced on flow-through
shares (ii) (10,700,135)
Repayment of notes receivable (iii) 450,000
--------------------------

Balance at December 31, 2003 70,469,528 73,185,579
Conversion of debentures (i) 1,875,000 3,162,468
Issued for cash on exercise of stock options 171,668 151,511
Share issue costs, net of tax of $343,761 (678,729)
Repayment of notes receivable (iii) 335,000
Issue of common shares for cash (ii) 3,870,000 7,546,500
Issue of flow-through common shares
for cash (ii) 3,000,000 7,500,000
Tax benefits renounced on flow-through
shares (ii) (50,430)
--------------------------
Balance at December 31, 2004 79,386,196 91,151,899
--------------------------
--------------------------


(i) As described in Note 7, the convertible debentures were converted to
shares in the first quarter of 2004. 1,875,000 shares at $1.60 per share
were issued in exchange for retirement of the debenture liability. The
carrying value of the debentures prior to conversion was $2,938,475. In
addition, the $223,993 equity component representing the holders'
conversion rights based upon fair value of the debentures at the time of
issue, was applied to share capital.

(ii) In May 2004, the Corporation issued 3,870,000 common shares at
$1.95 per share for proceeds of $7,546,500 and 3,000,000 flow-through
shares at $2.50 per share for proceeds of $7,500,000.

The Corporation renounced $150,000 to the shareholders at June 30, 2004
and the balance in January, 2005, having expended $6,300,000 in
exploratory costs relating to this issue in 2004, and under the 'look
back' provision governing flow-through shares, will be required to
expend the balance of $1,200,000 prior to December 31, 2005. The
aggregate tax benefit to be lost by the Corporation is $2,521,500 at
current tax rates.

On October 31, 2002, the Corporation issued 8,548,332 flow-through
shares for proceeds of $10,258,001 less issue costs of $694,260. The
Corporation renounced $10,258,001 to shareholders in 2002 and expended
the full amount in 2003. The tax benefit lost to the Corporation in 2003
was $4,180,135. On March 12, 2003, the Corporation issued 7,634,207
common shares at $1.45 per share for proceeds of $11,069,600 less issue
costs of $749,200.

On June 24, 2003, the Corporation issued 4,000,000 flow-through shares
at $2.00 per share for proceeds of $8,000,000 less issue costs of
$497,500.

On December 23, 2003, the Corporation issued 3,200,000 flow-through
shares at $2.50 per share for proceeds of $8,000,000 less issue costs of
$497,500.

At December 31, 2004 all of the $16,000,000 in exploratory costs
required to be expended under the 2003 flow-through share offerings had
been incurred. These costs were renounced to shareholders in 2003. The
tax benefit lost to the Corporation in 2003 was $6,520,000.

(iii) Interest free loans were issued by the Corporation in 2001 and
2002 to certain officers and an employee for the purpose of purchasing
shares of the Corporation. The loans are evidenced by promissory notes
and the shares are pledged to the Corporation as collateral. The shares
are being held in trust, to be released as the loans are repaid. During
2004 $335,000 of such loans were repaid (2003 - $450,000) and at
December 31, 2004, $555,000 remains outstanding. The market value of the
shares held as collateral at December 31, 2004 was $805,329.

(iv) As described in note 1, the Corporation adopted a new accounting
policy with respect to stock based compensation in 2004. The effect on
contributed surplus at January 1, 2004 for retroactively adopting the
standard without restatement of prior periods was $955,315. The stock
based compensation expense for 2004 was $604,294 and was applied to
contributed surplus.

(v) On July 15, 2003, the Corporation issued 9,375,000 common shares at
$1.60 per share for proceeds of $15,000,000, which proceeds were used in
the acquisition of Glacier. A further 6,562,504 common shares were
issued at a deemed value of $1.70 per share as part of the consideration
paid for the acquisition of Glacier. Share issue costs of $998,364 were
incurred in relation to this issue.

Stock options

The Corporation has established a stock option plan whereby options may
be granted to the Corporation's directors, officers and employees for up
to 10% of the common shares issued and outstanding. The exercise price
of each option equals the market price of the Corporation's stock on the
date of the grant and an option's maximum term is five years. The stock
options vest one-third immediately, one-third after one year following
the date of grant and one-third two years following the date of grant. A
compensation expense of $604,294 was recognized in 2004 under the plan.
The following is a continuity of stock options outstanding for which
shares have been reserved:



---------------------------------------------------
2004 2003
---------------------------------------------------
Weighted Weighted
Average Average
Number Exercise Number Exercise
of Shares Price $ of Shares Price $
---------------------------------------------------
Opening 3,350,002 1.25 2,696,669 1.05
Granted 2,215,000 1.84 985,000 1.60
Exercised (171,668) 0.88 (331,667) 0.63
Expired (36,000) 2.35 - -
----------- -----------
Closing 5,357,334 1.50 3,350,002 1.25
----------- -----------
----------- -----------

Exercisable,
end of year 3,576,196 1.35 2,151,528 1.16
----------- -----------
----------- -----------

-----------------------------------------------------------
Options Outstanding Options Exercisable
-----------------------------------------------------------
Weighted Weighted Weighted
Average Average Average
Remaining Exercise Exercise
Number Life Price Number Price
Outstanding (Years) $ Exercisable $
-----------------------------------------------------------
Range of
exercise
prices

$0.30 - $0.69 150,001 1.5 0.39 150,001 0.39
$0.90 - $1.05 241,667 0.7 1.00 241,667 1.00
$1.20 - $1.20 1,801,666 2.4 1.20 1,801,666 1.20
$1.58 - $1.80 2,708,000 4.2 1.74 1,230,877 1.66
$2.06 - $2.35 456,000 4.2 2.19 151,985 2.19
------------ -----------
5,357,334 3.4 3,576,196 1.35
------------ -----------
------------ -----------


The fair value of options granted during the year was estimated at the
date of grant using a Black-Scholes Option Pricing Model with the
following assumptions for 2004: risk-free interest rate of 3.5% - 3.9%;
dividend yield of 0%; volatility factor of the market price of the
Corporation's common shares of 36% - 40%; and, an average expected life
of the options of 3 years. For purposes of pro-forma disclosure, the
estimated fair value of the options is amortized to expense over the
option vesting periods. On a pro-forma basis, had the fair value method
been used in 2003, the net loss for the year ended December 31, 2003
would be increased by $81,894. Basic and diluted net loss per share
would be unchanged.

Earnings per share

The Corporation utilizes the treasury stock method in the determination
of diluted per share amounts. Under this method, the diluted weighted
average number of shares is calculated assuming the proceeds that arise
from the exercise of outstanding and in the money options are used to
purchase common shares of the Corporation at their average market price
for the period. The weighted average number of common shares outstanding
during the year was 75,766,587 (2003 - 55,329,790) and 77,130,290
diluted (2003 - 56,246,310).

9. FUTURE INCOME TAXES

The components of the future income tax liability are as follows:



----------------------------
2004 2003
$ $
----------------------------
Differences between tax base and reported
amounts for depreciable assets 26,356,290 35,328,662
Benefit of non-capital losses (2,173,703) (2,983,032)
Benefit of attributed crown royalty income (823,573) (596,582)
Share issue costs - (1,586,944)
Provision for future site restoration
and abandonment costs - (325,939)
Partnership deferral 7,272,043 -
----------------------------
30,631,057 29,836,165
----------------------------
----------------------------


The total income taxes are different than the amount computed by
applying the combined Canadian federal and provincial corporate tax
rates of 38.87% (2003 - 40.75%) to the earnings (loss) before taxes. The
majority of these differences are explained as follows:



----------------------------
2004 2003
$ $
----------------------------
Expected tax 1,707,971 (137,816)
Add (deduct) income tax effect of:
Non-deductible crown royalties,
net of ARTC 2,372,622 2,042,346
Resource allowance (1,784,332) (1,510,154)
Attributed Royalty Income
Carryforward (153,734) (99,052)
Share Issue costs
Income tax rate reduction (1,007,349) (2,462,910)
Non-taxable or non-deductible items 247,686 (58,020)
Part XII.6 tax 162,016 63,893
Large corporation tax 106,771 288,043
Other (294,641) 45,622
----------------------------
Income taxes (recovery) 1,357,010 (1,828,048)
----------------------------
----------------------------


10. COMMITMENTS

The Corporation has entered into lease arrangements for office space to
April 30, 2006. The future minimum lease payments total $465,527 (2005 -
$328,607 and 2006 - $136,920).



11. FINANCIAL INSTRUMENTS

Gas Hedging
------------------------------------------------------------------------
Period Volume Hedged AECO Price
------------------------------------------------------------------------
Nov. 1, 2004
- Mar. 31, 2005 3,000 GJ/day (2.9 mmcf/d) $7.90/GJ ($8.32/mcf)
Nov. 1, 2004
- Mar. 31, 2005 3,000 GJ/day (2.9 mmcf/d) $8.01/GJ ($8.41/mcf)
Nov. 1, 2004
- Mar 31, 2005 2,000 GJ/day (1.9 mmcf/d) $8.58/GJ ($9.01/mcf)
Apr. 1, 2005
- Oct 31, 2005 6,000 GJ/day (5.7 mmcf/d) $6.95/GJ ($7.30/mcf)
------------------------------------------------------------------------


The estimated fair value of the Corporation's commodity hedging
contracts at December 31, 2004 was $958,980, being the amount the
Corporation would gain if it sold off its position.

12. SUBSEQUENT EVENTS

Effective January 1, 2005, the Corporation purchased the rights to the
Gross Overriding Royalty for the Desan area of NE British Columbia for
$590,000. The Gross Overriding Royalty had been part of the Bridge
Financing Facility set up in 2003, as described under note 6.

An agreement is in place whereby the Corporation's interests at Medicine
Lodge will be sold effective March 31, 2005 for proceeds of $2.6 million
dollars.

On February 24, 2005, the Corporation entered into a natural gas swap
and matching physical sale with a major Canadian marketer, fixing the
price on 3,000 GJ per day of natural gas at $6.82 per GJ for the period
April 1, 2005 through October 31, 2005.

-30-

Contact Information

  • FOR FURTHER INFORMATION PLEASE CONTACT:
    High Point Resources Inc.
    Glen Yeryk
    President & Chief Executive Officer
    (403) 261-8303
    Email: gleny@highpointres.com
    or
    High Point Resources Inc.
    Jim Brown
    Vice President Finance & Chief Financial Officer
    (403) 261-8318
    Email: jimb@highpointres.com