High Point Resources Inc.
TSX : HPR

High Point Resources Inc.

August 02, 2005 07:00 ET

High Point Resources Announces Second Quarter Results

CALGARY, ALBERTA--(CCNMatthews - Aug. 2, 2005) - High Point Resources Inc. (TSX:HPR) is pleased to announce its operating and financial results for the three and six months ended June 30, 2005.

President's Message

The special meeting of High Point shareholders to consider the Plan of Arrangement between Enterra and High Point is scheduled for August 16, 2005. The Board of Directors and management are recommending acceptance of the Arrangement. With an affirmative vote by the High Point shareholders for the Arrangement, this will be the final quarterly report by High Point Resources Inc.

Highlights for the second quarter were:

- Average production increased by 19% from the first quarter 2005 to 3,410 boepd.

- Cash flow increased 23% from the first quarter 2005 to over $7.8 million.

- Earnings increased by 235% from the first quarter 2005 to over $2.2 million

- Operating costs were reduced by 29% from the first quarter 2005 to $3.59/boe.

The improved financial performance was achieved despite a slight decrease in gas prices in the second quarter versus the first quarter of 2005.

High Point had planned a very active drilling program in the second quarter of 2005. The event we did not plan for was the "once in 100 year" rains which occurred in Southern Alberta during the quarter. Weather-related problems at Ricinus and plant turnarounds at Desan and Lochend resulted in the loss of approximately 200 boe per day of production in the quarter. No new drilling operations were undertaken on our Ricinus and Ferrier properties in the quarter. In addition, the planned completion of the Ricinus 11-17 well was delayed due to severe flooding in the area. Normal operations are now underway with two drilling rigs active in the field and the Ricinus 11-17 well planned for completion in early August 2005.

In comparing the last six months versus the same period in 2004, the diversification of our asset base is showing very positive results and bodes well for the future of the company. The cash flow per barrel of oil equivalent has increased by 36% despite a gas price that has only increased 8% in the same time period. The increased cash flows are a direct result of changing the product mix and reduced royalties. Revenues from oil and natural gas liquids increased by 68% and royalties were reduced by 22% from the first six months of 2004 versus 2005. As operating costs are again less than $4.00/boe, future development in all core areas assets will be very profitable.

High Point has developed a unique and profitable asset base over the last two and a half years. The focus has been on resource-based gas projects which are now highlighted by developments at Desan, Ferrier and Ricinus. The resource-based projects are characterized by low drilling risk, repeatable results and long life reserves. The company has maintained a drilling success of over 95% on these projects and has a drilling inventory of over 100 locations at Desan, Ferrier and Ricinus.

In addition to the resource based projects, High Point assembled a high quality inventory of exploration prospects which are now drill ready. The Ricinus 11-17 Leduc well was the first in a series of exploration wells planned for 2005 and beyond. The exploration prospects focused on long life, high deliverability gas reserves. All exploration projects at Ricinus (Leduc formation), Kotcho (Keg River formation), Ferrier (Banff formation) and Mackenzie (deep and shallow formations) have the required land and seismic. Locations have been selected and are awaiting drilling programs or farm-in proposals.

The proposed Plan of Arrangement with Enterra has received excellent market support since the announcement of the transaction on May 31, 2005. As mentioned earlier, High Point's directors and management are recommending that the Plan of Arrangement with Enterra be approved.

I would especially like to thank the staff, Board of Directors and shareholders of High Point for their support and guidance over the last three years.

Glen A. Yeryk
President and CEO







Highlights

Six months ended June 30, Three months ended June 30,
% Increase % Increase
(unaudited) 2005 2004 (Decrease) 2005 2004 (Decrease)
------------------------------------------------------------------------
Production:
-----------
Gas (mcf/d) 15,531 15,274 2 17,392 16,480 6
Light oil
(bbls/d) 78 56 39 67 55 22
Condensate
(bbls/d) 76 63 21 76 57 33
NGLs (bbls/d) 398 328 21 368 337 9
---------------------------------------------------------
BOE at 6:1 gas 3,141 2,992 5 3,410 3,196 7

Total BOE
Produced 568,473 544,500 4 310,328 290,847 7

------------------------------------------------------------------------
Prices
------
Gas (pre hedge)
($/mcf) 6.71 6.22 8 7.11 6.63 7
Gas (including
hedge) ($/mcf) 7.10 6.30 13 7.07 6.46 9
Light oil
($/bbl) 61.79 44.33 39 65.00 47.49 37
Condensate
($/bbl) 58.82 44.85 31 60.15 50.14 20
NGLs ($/bbl) 45.43 32.33 41 46.45 32.68 42

$ Per BOE
---------
Gross revenues
(net of hedges
and transport-
ation expense) 43.84 37.58 17 43.70 38.60 13
Royalties
(net of ARTC) (8.68) (11.27) (22) (8.68) (12.18) (29)
Operating costs (4.07) (3.70) 10 (3.59) (3.65) (2)
---------------------------------------------------------
Field netback 31.09 22.61 38 31.43 22.77 38
Other revenue - 0.02 - 0.01
G & A (3.00) (2.13) 41 (2.87) (2.43) 18
Interest and
financing
charges (3.17) (2.06) 54 (3.58) (1.94) 85
Taxes & other 0.03 (0.03) 200 0.22 0.18 22
---------------------------------------------------------
Cash flow 24.95 18.41 36 25.20 18.59 36

------------------------------------------------------------------------
Financial: ($000)
-----------------
Gross revenues
(net of hedges
and transport-
ation expense) 24,920 20,465 22 13,562 11,225 21
Royalties
(net of ARTC) (4,937) (6,134) (20) (2,694) (3,543) (24)
Other income 2 11 2 2
Operating -
cash expenses (2,312) (2,017) 15 (1,114) (1,062) 5
G & A (1,706) (1,161) 47 (892) (708) 26
Interest and
financing
charges (1,802) (1,120) 61 (1,113) (563) 98
Current taxes 18 (21) 186 69 54 28
---------------------------------------------------------
Cash flow 14,183 10,023 42 7,820 5,405 45
D, D & A. (9,212) (8,622) 7 (4,817) (4,257) 13
Future Tax
(Expense)
Recovery (1,270) (69) 174 (504) (1,326) (62)
Other - non
cash expenses (430) (309) 39 (204) (120) 71
---------------------------------------------------------
Earnings (loss) 3,271 1,023 220 2,295 (298) 870

Net corporate
debt (000's) 81,654 46,288 76 81,654 46,288 76
Weighted
average
outstanding
shares: 78,996,160 79,017,386
72,760,493 9 75,579,607 5
Cash flow
per share($) 0.18 0.14 0.10 0.07
Earnings
(loss) per
share ($) 0.04 0.01 0.03 (0.00)




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 operating activities and financial results for the three and six month periods ended June 30, 2005, with comparisons to the three and six month periods ended June 30, 2004. 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 July 29, 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 six 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.

Corporate Transaction
As announced on May 31, 2005, High Point has entered into an arrangement agreement pursuant to which a subsidiary of Enterra Trust ("Enterra") will acquire all the issued and outstanding common shares of High Point and holders of High Point common shares will be entitled to receive, for each common share of High Point, either: (i) 0.105 of a trust unit ("Trust Unit") of Enterra (which will receive monthly cash distributions); or (ii) 0.105 of an exchangeable share (the "Exchangeable Share") (the exchange ration of which will be adjusted on a monthly basis in lieu of cash distributions to unitholders) of the acquirer, Rocky Mountain Acquisition Corp. (a subsidiary of Enterra), such shares being exchangeable into Trust Units of Enterra, subject to a maximum of 2,500,000 Exchangeable Shares being issued. The acquisition is to be completed pursuant to a plan of arrangement under the Business Corporation's Act (Alberta) and is subject to the satisfaction of certain conditions, including approval of not less than 66?% of votes cast by shareholders. A meeting of shareholders of the Corporation to vote on the proposal is scheduled for August 16, 2005, with the closing of the transaction expected shortly thereafter.




Production

------------------------------------------------------------------------
Six months ended June 30,
------------------------------------------------------------------------
2005 2004
------------------------------------------------------------------------
Natural Natural
Gas Oil NGL BOE Gas Oil NGL BOE
mcf/d bbl/d bbl/d boe/d mcf/d bbl/d bbl/d boe/d
------------------------------------------------------------------------
Desan 8,389 - 54 1,452 9,366 - 48 1,609
------------------------------------------------------------------------
Ferrier 4,280 5 243 961 2,980 2 141 640
------------------------------------------------------------------------
Lochend 717 15 90 224 1,802 54 187 542
------------------------------------------------------------------------
Medicine
Lodge (sold) 261 - 3 47 715 - 9 129
------------------------------------------------------------------------
Alexander/
Newton
(sold) - - - - 308 - - 51
------------------------------------------------------------------------
Ricinus 1,696 59 84 425 69 - 3 15
------------------------------------------------------------------------
Other 188 (1) - 32 34 - 2 6
------------------------------------------------------------------------
Total per
day 15,531 78 474 3,141 15,274 56 390 2,992
------------------------------------------------------------------------

------------------------------------------------------------------------
Three months ended June 30,
------------------------------------------------------------------------
2005 2004
------------------------------------------------------------------------
Natural Natural
Gas Oil NGL BOE Gas Oil NGL BOE
mcf/d bbl/d bbl/d boe/d mcf/d bbl/d bbl/d boe/d
------------------------------------------------------------------------
Desan 10,588 - 58 1,823 10,188 - 48 1,746
------------------------------------------------------------------------
Ferrier 4,274 8 235 956 3,134 2 117 641
------------------------------------------------------------------------
Lochend 589 11 69 178 2,035 53 214 606
------------------------------------------------------------------------
Medicine
Lodge (sold) - - - - 671 - 9 121
------------------------------------------------------------------------
Alexander/
Newton
(sold) - - - - 296 - - 49
------------------------------------------------------------------------
Ricinus 1,830 48 82 435 137 - 6 29
------------------------------------------------------------------------
Other 111 - 1 18 19 - - 4
------------------------------------------------------------------------
Total per
day 17,392 67 445 3,410 16,480 55 394 3,196
------------------------------------------------------------------------



Production in the second quarter averaged 3,410 Boe per day, an increase of 19% or 542 Boe per day over the first quarter and 7% over the second quarter of 2004. This was largely due to six new wells at Desan drilled over the winter and on production at the beginning of April 2005. Production from three new Ricinus wells and two new Ferrier wells helped maintain production levels and offset declines in the first half of 2005. Declines and down time at Ricinus, Lochend and Desan due to weather and plant turnarounds, along with properties sold at Medicine Lodge (March 31, 2005) and Alexander/Newton (November 1, 2004) partially offset new production added during the first six months of 2005 to limit the production increase to 5% over the same period in 2004.

Product mix

High Point's product mix averaged 97% natural gas and natural gas liquids during the first six months of 2005 (2004 - 98%). Oil production from a new Ricinus well increased the oil percentage.


------------------------------------------------------------------------
Six months ended June 30,
------------------------------------------------------------------------
2005 2004
------------------------------------------------------------------------
Natural gas (mcf/d) 15,531 82% 15,274 85%
------------------------------------------------------------------------
Condensate (bbls/d) 76 2% 63 2%
------------------------------------------------------------------------
NGLs (bbls/d) 398 13% 328 11%
------------------------------------------------------------------------
Oil (bbls/d) 78 3% 56 2%
------------------------------------------------------------------------
Boe/d (6:1) 3,141 100% 2,992 100%
------------------------------------------------------------------------

------------------------------------------------------------------------
Three months ended June 30,
------------------------------------------------------------------------
2005 2004
------------------------------------------------------------------------
Natural gas (mcf/d) 17,392 85% 16,480 86%
------------------------------------------------------------------------
Condensate (bbls/d) 76 2% 57 2%
------------------------------------------------------------------------
NGLs (bbls/d) 368 11% 337 11%
------------------------------------------------------------------------
Oil (bbls/d) 67 2% 55 1%
------------------------------------------------------------------------
Boe/d (6:1) 3,410 100% 3,196 100%
------------------------------------------------------------------------






Commodity pricing

------------------------------------------------------------------------
Six months ended
June 30,
------------------------------------------------------------------------
High Point average prices 2005 2004
------------------------------------------------------------------------
Light oil ($/bbl) 61.79 44.33 39%
------------------------------------------------------------------------
Condensate ($/bbl) 58.82 44.85 31%
------------------------------------------------------------------------
NGLs ($/bbl) 45.43 32.33 41%
------------------------------------------------------------------------
Natural gas ($/mcf) 6.71 6.22 8%
------------------------------------------------------------------------
Hedging impact ($/mcf) 0.39 0.08 388%
------------------------------------------------------------------------
Net gas ($/mcf) 7.10 6.30 13%
------------------------------------------------------------------------

------------------------------------------------------------------------
Three months ended
June 30,
------------------------------------------------------------------------
High Point average prices 2005 2004
------------------------------------------------------------------------
Light oil ($/bbl) 65.00 47.49 37%
------------------------------------------------------------------------
Condensate ($/bbl) 60.15 50.14 20%
------------------------------------------------------------------------
NGLs ($/bbl) 46.45 32.68 42%
------------------------------------------------------------------------
Natural gas ($/mcf) 7.11 6.63 7%
------------------------------------------------------------------------
Hedging impact ($/mcf) (0.04) (0.17) (76%)
------------------------------------------------------------------------
Net gas ($/mcf) 7.07 6.46 9%
------------------------------------------------------------------------


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 7% from $6.63/mcf in the second quarter of 2004 to $7.11/mcf in the second quarter of 2005. Natural gas also increased 15% or $0.91/mcf during the second quarter of 2005 compared to the first quarter of 2005. Hedging increased the net gas price $0.39/mcf over the first six months of 2005 to average $7.10/mcf, a 13% increase over the same six month period of 2004. The increase in oil and liquids pricing reflects the increase in WTI reference prices over the past year.


Commodity risk management

High Point enters into hedging transactions to protect cash flow and enhance our ability to carry out the planned capital expenditure program. Hedging contracts in place in the second quarter of 2005 covered 49% of gas sales (56% in the first quarter) and resulted in prices on that portion of High Point's sales being fixed at those price levels. The hedging of gas sales in the second quarter resulted in a loss of $60,962 and was applied to gas revenues while the first quarter hedging contributed $1,152,618 to gas revenues.

The following is a summary of all hedging activities affecting 2005 and 2006:



------------------------------------------------------------------------
AECO
Period Volume Hedged 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)
------------------------------------------------------------------------
Apr. 1, 2005
- Oct. 31, 2005 3,000 GJ/day (2.9 mmcf/d) $6.82/GJ ($7.16/mcf)
------------------------------------------------------------------------
Nov. 1, 2005
- Mar. 31, 2006 3,000 GJ/day (2.9 mmcf/d) $8.01/GJ ($8.41/mcf)
------------------------------------------------------------------------
Nov. 1, 2005
- Mar. 31, 2006 3,000 GJ/day (2.9 mmcf/d) $8.32/GJ ($8.74/mcf)
------------------------------------------------------------------------
Nov. 1, 2005
- Mar. 31, 2006 2,000 GJ/day (1.9 mmcf/d) $8.85/GJ ($9.30/mcf)
------------------------------------------------------------------------


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, with the same counterparty and on identical terms as the hedge contracts. As a result, the Corporation 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. Based on the forward prices at June 30, 2005, the outstanding hedge contracts had an unrealized loss of $435,020. Credit risks associated with hedging contracts are obviated by restricting transactions to financially strong counterparties.

Petroleum and natural gas - gross revenues



------------------------------------------------------------------------
Six months ended June 30,
------------------------------------------------------------------------
2005 2004
------------------------------------------------------------------------
$000 % $000 %
------------------------------------------------------------------------
Natural gas 19,964 80 18,387 86
------------------------------------------------------------------------
NGLs & Condensate 4,081 16 2,439 12
------------------------------------------------------------------------
Oil 876 4 450 2
------------------------------------------------------------------------
Royalty revenue 8 53
------------------------------------------------------------------------
Subtotal 24,929 100 21,329 100
------------------------------------------------------------------------
Transportation (1,101) (1,091)
------------------------------------------------------------------------
Hedging gain 1,092 227
------------------------------------------------------------------------
Total revenue 24,920 20,465
------------------------------------------------------------------------

------------------------------------------------------------------------
Three months ended June 30,
------------------------------------------------------------------------
2005 2004
------------------------------------------------------------------------
$000 % $000 %
------------------------------------------------------------------------
Natural gas 11,756 83 10,547 87
------------------------------------------------------------------------
NGLs & Condensate 1,974 14 1,264 11
------------------------------------------------------------------------
Oil 396 3 238 2
------------------------------------------------------------------------
Royalty revenue 5 31
------------------------------------------------------------------------
Subtotal 14,131 100 12,080 100
------------------------------------------------------------------------
Transportation (508) (566)
------------------------------------------------------------------------
Hedging loss (61) (289)
------------------------------------------------------------------------
Total revenue 13,562 11,225
------------------------------------------------------------------------


Gross revenues in the first half of 2005 were $24.9 million, up 22% from $20.4 million for same period last year. The increase was due to an 8% increase in gas prices, a 5% increase in daily production levels, and hedging gains effecting another 5% increase to gas prices over the first half of 2004. Second quarter 2005 revenues of $13.5 million were up 19%, or $2.2 million, from the first quarter. The increase was due to a 19% increase in daily production since hedged gas prices were $0.07/mcf lower in the second quarter.



Royalties

------------------------------------------------------------------------
Six months ended June 30,
------------------------------------------------------------------------
2005 2004
------------------------------------------------------------------------
% of % of
$000 Sales $/Boe $000 Sales $/Boe
------------------------------------------------------------------------
Crown 4,327 18 7.61 4,693 23 8.62
------------------------------------------------------------------------
Other 1,158 5 2.04 1,736 8 3.19
------------------------------------------------------------------------
ARTC & GCA (548) (2) (0.97) (295) (1) (0.54)
------------------------------------------------------------------------
Total 4,937 21 8.68 6,134 30 11.27
------------------------------------------------------------------------

------------------------------------------------------------------------
Three months ended June 30,
------------------------------------------------------------------------
2005 2004
------------------------------------------------------------------------
% of % of
$000 Sales $/Boe $000 Sales $/Boe
------------------------------------------------------------------------
Crown 2,434 18 7.84 2,614 23 8.99
------------------------------------------------------------------------
Other 590 4 1.90 1,070 9 3.68
------------------------------------------------------------------------
ARTC & GCA (330) (2) (1.06) (141) (1) (0.49)
------------------------------------------------------------------------
Total 2,694 20 8.68 3,543 31 12.18
------------------------------------------------------------------------


Gross Overriding Royalty ("GORR") rates in 2005 dropped with the payout of the bridge financing facility in 2004 which had encumbered certain Desan production with a 5% GORR during the first six months of 2004. Also at Desan, the 6 new wells drilled in the first quarter of 2005, which increased Desan production by 69% during the second quarter, were on unencumbered crown lands held by the Corporation. The combined result was that the effective GORR rate at Desan was reduced from 12.5% during the first six months of 2004 to 7% for 2005. At Ricinus, the GORR has increased, as the new wells drilled since the end of the second quarter of 2004 are subject to a GORR.

No crown royalty expenses were recognized at Ricinus to date due to the deep well royalty credits. The average crown royalty rate for the first half was down due to the royalty credits at Ricinus and Ferrier.

Operating expenses

Operating costs in the second quarter of 2005 were $3.59/Boe, down from the $4.64/BOE in the first quarter. Operating costs were higher in the first quarter reflecting higher overall industry cost levels, winter increases in costs and the timing of annual licensing fees. Operating expenses were $4.07/Boe for the first six months of 2005 compared with $3.70/Boe for the same period in 2004. Per unit operating costs are expected to drop as production levels increase and are expected to be below $4.00/boe for the year.

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 in the top quartile for 2005.



General and administration costs

------------------------------------------------------------------------
Six months ended
June 30,
------------------------------------------------------------------------
2005 2004
------------------------------------------------------------------------
$000 $/Boe $000 $/Boe
------------------------------------------------------------------------
Gross 2,320 4.08 1,627 2.99
------------------------------------------------------------------------
Recoveries (614) (1.08) (466) (0.86)
------------------------------------------------------------------------
Total 1,706 3.00 1,161 2.13
------------------------------------------------------------------------
------------------------------------------------------------------------

------------------------------------------------------------------------
Three months ended
June 30,
------------------------------------------------------------------------
2005 2004
------------------------------------------------------------------------
$000 $/Boe $000 $/Boe
------------------------------------------------------------------------
Gross 1,209 3.90 852 2.93
------------------------------------------------------------------------
Recoveries (317) (1.03) (144) (0.50)
------------------------------------------------------------------------
Total 892 2.87 708 2.43
------------------------------------------------------------------------
------------------------------------------------------------------------


Gross General and administration ("G&A") expenses in the six month period ended June 30, 2005 were 43% higher than the same six month period ended June 30, 2004, reflecting increased personnel costs and growth in the corporation. Comparatively, cash flow increased 42% for the same six month period in 2005 versus 2004.

Interest and other financing charges

Interest expense incurred in the first six months of 2005 was $1,397,019 compared to $1,013,431 for the same six month period of 2004, reflecting higher debt levels.

Financing fees for the first six months of 2005 were $405,184 compared to $106,963 for the same period of 2004. Financing fees were up from last year due to the 'Bridge Financing Facility' in place this year with its drawdown fees of 2.5% applied to draws of $15 million in the first quarter. The financing fees are amortized over the term of the facility.

The effective interest rate on the outstanding loan balances for the first six months of 2005, including financing fees, was 5.6%.

Current taxes

A current tax expense of $85,750 was recorded in the first half of 2005 and relates to Large Corporations Tax ("LCT") installments. During the second quarter of 2005, credit adjustments of $104,023 were recognized relating to the excess of 2004 installments over the actual tax calculated for 2004.

Cash flow

Increased netbacks from increased volumes, reduced royalties and improved prices led to a 42% increase in cash flow from operations of $14.2 million or $0.18 per share for the first six months of 2005, compared to $10.0 million or $0.14 per share for the same period in 2004. Forty-three percent of the increased netbacks resulted from increased volumes and royalty reductions.



------------------------------------------------------------------------
Six months ended June 30,
------------------------------------------------------------------------
2005 2004
-------------------------------------------------------------- $/Boe
$000 $/Boe $000 $/Boe % change
------------------------------------------------------------------------
Gross revenue 23,828 41.92 20,238 37.16 13
------------------------------------------------------------------------
Hedges 1,092 1.92 227 0.42 357
------------------------------------------------------------------------
Royalties (5,485) (9.65) (6,429) (11.81) (18)
------------------------------------------------------------------------
ARTC & GCA 548 0.97 295 0.54 80
------------------------------------------------------------------------
Subtotal 19,983 35.16 14,331 26.31 34
------------------------------------------------------------------------
Operating costs (2,312) (4.07) (2,017) (3.70) 10
------------------------------------------------------------------------
Operating netback 17,671 31.09 12,314 22.61 38
------------------------------------------------------------------------
Other 2 - 11 0.02 -
------------------------------------------------------------------------
Administration costs (1,706) (3.00) (1,161) (2.13) 41
------------------------------------------------------------------------
Interest costs (1,802) (3.17) (1,120) (2.06) 54
------------------------------------------------------------------------
Taxes & other 18 0.03 (21) (0.03) 200
------------------------------------------------------------------------
Cash flow from
operations 14,183 24.95 10,023 18.41 36
------------------------------------------------------------------------

------------------------------------------------------------------------
Three months ended June 30,
------------------------------------------------------------------------
2005 2004
-------------------------------------------------------------- $/Boe
$000 $/Boe $000 $/Boe % change
------------------------------------------------------------------------
Gross revenue 13,623 43.90 11,514 39.59 11
------------------------------------------------------------------------
Hedges (61) (0.20) (289) (0.99) (80)
------------------------------------------------------------------------
Royalties (3,024) (9.74) (3,684) (12.67) (23)
------------------------------------------------------------------------
ARTC & GCA 330 1.06 141 0.49 116
------------------------------------------------------------------------
Subtotal 10,868 35.02 7,682 26.42 33
------------------------------------------------------------------------
Operating costs (1,114) (3.59) (1,062) (3.65) (2)
------------------------------------------------------------------------
Operating netback 9,754 31.43 6,620 22.77 38
------------------------------------------------------------------------
Other 2 - 2 0.01 -
------------------------------------------------------------------------
Administration costs (892) (2.87) (708) (2.43) 18
------------------------------------------------------------------------
Interest costs (1,113) (3.58) (563) (1.94) 85
------------------------------------------------------------------------
Taxes & other 69 0.22 54 0.18 22
------------------------------------------------------------------------
Cash flow from
operations 7,820 25.20 5,405 18.59 36
------------------------------------------------------------------------


Netbacks

An increase in production resulted in lower operating costs per boe in the second quarter which contributed to a 2% increase in operating netbacks to $25.20 per boe, compared with $24.65 per Boe for the first quarter. Second quarter 2005 netbacks were also 36% higher ($6.61 per boe) than the same period in 2004, while the six month period ended June 30, 2005 yielded net backs of $24.95 per boe, a 36% increase over the $18.41 net back for the same period of 2004. This reflects an 8% increase in natural gas selling prices or $0.49 per mcf, hedging gains of $0.39 per Mcf and a 22% decrease in royalty rates.



Netbacks per BOE and cash flow from operations, by property

------------------------------------------------------------------------
($ 000) Desan Ferrier Ricinus Lochend Average
------------------------------------------------------------------------
Revenue 37.44 47.32 47.65 39.45 41.92
------------------------------------------------------------------------
Royalties (11.10) (11.07) (3.30) (6.66) (9.65)
------------------------------------------------------------------------
Operating costs (3.86) (3.19) (4.04) (6.46) (4.07)
------------------------------------------------------------------------
Field netback 22.48 33.06 40.31 26.33 28.20
------------------------------------------------------------------------
Cash flow (000's) 5,909 5,752 3,101 1,069 16,031
------------------------------------------------------------------------
Cash flow % 37 36 19 7 100
------------------------------------------------------------------------

Netbacks & cash flow at the property level do not include ARTC and
corporate hedging.

Combined, other minor areas contribute to 1% of cash flow.


The netbacks at Desan will improve as new wells are drilled on non-GORR lands, alternatively, netbacks at Ferrier and Ricinus may eventually decrease as 'deep well' crown royalty credits end.

Depletion and Depreciation

Total depletion and depreciation for the six month period ended June 30, 2005 was $9,212,626 compared to $8,622,300 in 2004. On a production basis, the cost of depletion and depreciation was $16.15/Boe for the first six months of 2005 and $15.78/Boe for the same period in 2004, with second quarter depletion of $15.48/Boe compared to $14.64/Boe in 2004 reflecting higher capital costs and carrying values.

In January, 2004, High Point adopted a new accounting standard relating to asset retirement obligations ("ARO"). For the six month period ended June 30, 2005, accretion expense of $59,058 relating to the ARO was recorded, compared to $58,825 recorded for 2004.

Stock-Based Compensation

Stock-based compensation expense of $371,428 was recorded for the first half of 2005, compared with $229,425 for the same period in 2004, pursuant to the new accounting standard adopted January 1, 2004. In the second quarter of 2005, all options became fully vested as a result of the proposal by Enterra Energy Trust to acquire all of the outstanding shares of High Point. As a result, an additional stock-based compensation expense of $145,813 was recognized and included with the second quarter expense.

Future Taxes

A future tax provision of $1,269,638 was recorded in the first six months of 2005 compared with $69,124 in the first half of 2004. The 2004 provision is lower due to lower pre-tax earnings and the recognition of an Alberta provincial tax rate reduction in 2004. 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, 2004 30,631
------------------------------------------------------------------------
Flow through share renouncement in the first quarter 2,471
------------------------------------------------------------------------
Provision for the first quarter 766
------------------------------------------------------------------------
Balance at March 31, 2005 33,868
------------------------------------------------------------------------
Provision for the second quarter 504
------------------------------------------------------------------------
Balance at June 30, 2005 34,372
------------------------------------------------------------------------


In 2004, the Corporation issued $7.5 million in flow-through shares and renounced $150,000 in flow-through expenditures to the shareholders by December 31, 2004. In the first quarter of 2005, the remaining $7,350,000 in flow-through share expenditures were renounced to the shareholders. The taxable benefit lost to the Corporation through the renouncement to shareholders in 2005 was $2,471,070 at current tax rates.

Earnings

The increased cash flow from higher prices and hedging gains led to earnings of $3,270,782 or $0.04 per share for the first six months of 2005, compared to earnings of $1,022,563 or $0.01 per share in 2004, while the second quarter earnings were $2,294,857 compared to a loss of $298,529 for the same period in 2004. The 2004 earnings were primarily the result of a future tax recovery on the 2004 provincial tax rate reduction.

Capital expenditures

Capital expenditures were $27.1 million in the first quarter and $10.2 million in the second quarter of 2005 for a total of $37.3 million, an increase of 18% over 2004. In 2005, $13 million, including $2.2 million for land acquisitions, was spent during the first six months at Ricinus, compared to $4 million for the same period in 2004. A total of 15 wells (net 10.6) were drilled or in progress at June 30, 2005 with 12 on production and three waiting on completion and tie in. During the same six month period in 2004, 23 wells (net 12.3) were drilled or in progress. The higher cost of drilling in 2005 is largely due to inflation in the cost of services.



$ 000s Six months ended June 30,
------------------------------------------------------------------------
2005 2004
------------------------------------------------------------------------
Land 2,933 823
------------------------------------------------------------------------
Geological and geophysical 1,296 1,818
------------------------------------------------------------------------
Drilling, completions and abandonments 28,054 20,303
------------------------------------------------------------------------
Plant and facilities 5,017 8,456
------------------------------------------------------------------------
Other assets 43 156
------------------------------------------------------------------------
Total capital expenditures 37,343 31,556
------------------------------------------------------------------------

------------------------------------------------------------------------
$ 000s Three months ended June 30,
------------------------------------------------------------------------
2005 2004
------------------------------------------------------------------------
Land 698 -
------------------------------------------------------------------------
Geological and geophysical 16 593
------------------------------------------------------------------------
Drilling, completions and abandonments 8,243 4,923
------------------------------------------------------------------------
Plant and facilities 1,199 820
------------------------------------------------------------------------
Other assets 33 12
------------------------------------------------------------------------
Total capital expenditures 10,189 6,348
------------------------------------------------------------------------


Expenditures by area

------------------------------------------------------------------------
For the six Drilling,
months ended Geological completions Plant
June 30, 2005 and and and
($ 000s) Land geophysical abandonment facilities Other Total
------------------------------------------------------------------------
Desan 590 9 15,654 3,211 - 19,464
------------------------------------------------------------------------
Lochend - - 101 159 - 260
------------------------------------------------------------------------
Ricinus 2,188 323 9,381 1,156 - 13,048
------------------------------------------------------------------------
Ferrier 1 (69) 1,718 1,391 - 3,041
------------------------------------------------------------------------
Kotcho-
Sierra 154 128 400 - - 682
------------------------------------------------------------------------
Peggo-Pesh - 774 - - - 774
------------------------------------------------------------------------
Other - 131 800 (900) 43 74
------------------------------------------------------------------------
Total 2,933 1,296 28,054 5,017 43 37,343
------------------------------------------------------------------------


A total of $2.9 million was spent in 2005 on acquisition of P&NG rights, with $2.2 million spent at Ricinus to acquire 4 sections of land (net) and certain farm in rights and $0.1 million for a 51% interest in 3.1 sections of land in the Kotcho area of B.C. The rights to a gross overriding royalty on certain Desan wells owned by the Corporation was acquired for $0.6 million.

A seismic program on the Corporation's lands at Peggo-Pesh, B.C. was completed in the first quarter, with drilling operations planned for next winter. The undeveloped land at Peggo effectively replaces all the land developed at Desan to date.



Wells drilled-first half

------------------------------------------------------------------------
Drilled & producing Drilled & standing Work in progress
------------------------------------------------------------------------
Gross Net Gross Net Gross Net
------------------------------------------------------------------------
Desan 6 6.00 - - - -
------------------------------------------------------------------------
Ricinus 3 2.46 - - 2 1.10
------------------------------------------------------------------------
Ferrier 2 0.73 - - - -
------------------------------------------------------------------------
Lochend - - - - - -
------------------------------------------------------------------------
Other 1 0.05 - - 1 0.25
------------------------------------------------------------------------
Total 12 9.24 - - 3 1.35
------------------------------------------------------------------------


At Desan, six wells were drilled and tied in by the start of the second quarter, which increased the number of producing wells from 16 to 22. Production from the six new wells has increased production to 10.6 mmcf per day during the second quarter, compared to 6.2 mmcf per day in the first quarter. Transportation restrictions in the second quarter reduced average sales volumes by 0.6 mmcf per day.

At Ferrier, two wells (net 0.73) drilled in 2005 and six wells (net 2.57) which were drilled in the fourth quarter of 2004 were put on production. Ferrier production was 961 Boe per day for the first six months of 2005 compared to 640 Boe per day for the same period in 2004.

At Ricinus, five wells (net 3.56) have been drilled in 2005 with three wells (net 2.46) on production and two (net 1.1) waiting on completions and tie in. One well (net 0.75) drilled in 2004 was also tied in and on production in 2005. Ricinus production was 425 Boe per day for the first six months of 2005, including some down time in June due to flooding, compared to 15 Boe per day for the same period in 2004.

$5.0 million was spent on facilities and pipelines at Desan, Ferrier, and Ricinus areas in the first half, to tie in wells drilled in the fourth quarter of 2004 and the first half of 2005.

Effective March 31, 2005 the Corporation sold its gas producing properties at Medicine Lodge, Alberta for proceeds of $2.6 million.

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.

Shares Outstanding

At June 30, 2005, 79,792,531 common shares were outstanding and there were 4,950,999 stock options outstanding to employees, consultants, officers and directors, with an average exercise price of $1.51 per share. All options have fully vested in the second quarter as a result of the proposal by Enterra Energy Trust to acquire all of the outstanding shares of High Point.



Debt and Working capital

------------------------------------------------------------------------
($ 000's) June 30, 2005 December 31, 2004
------------------------------------------------------------------------
Cash & working capital (deficiency) (12,654) (12,004)
------------------------------------------------------------------------
Bank debt (54,000) (50,000)
------------------------------------------------------------------------
Bridge financing (15,000) -
------------------------------------------------------------------------
Net debt (81,654) (62,004)
------------------------------------------------------------------------


------------------------------------------------------------------------
Source of funds used in the first six months of 2005 $ 000s
------------------------------------------------------------------------
Net proceeds from disposal of properties 2,961
------------------------------------------------------------------------
Increase in bridge financing 15,000
------------------------------------------------------------------------
Increase in bank financing 4,000
------------------------------------------------------------------------
Issuance of shares, net of costs 549
------------------------------------------------------------------------
Funds provided by operations 14,183
------------------------------------------------------------------------
Change in cash and working capital 650
------------------------------------------------------------------------
Net additions to property and equipment 37,343
------------------------------------------------------------------------



Liquidity and Capital Resources

The $37.3 million capital expenditure program in 2005 was funded by cash flow from operations of $14.2 million, $3.0 million of proceeds from asset sales, $0.5 million of shares issued, and an increase of $19.6 million in debt and working capital deficit.

The bank credit facility was increased to $60 million on December 17, 2004, of which $54 million was drawn at June 30, 2005. On December 2, 2004 a $15 million standby bridge financing facility was signed and the full $15 million drawn in March 2005.

Future capital expenditures will be determined by cash flow and available loan facilities.

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 judgment, 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 and cash flows.

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.

Outlook

As described earlier, the directors and management of High Point have approved and recommended to the shareholders a business combination with a subsidiary of Enterra Energy Trust, to be considered at a special meeting of shareholders on August 16, 2005. In anticipation of that transaction, the summer capital program is proceeding, with the possibility of acceleration of the drilling program when the proposed transaction is approved.

The widespread flooding in southern Alberta throughout June and into July caused substantial operational delays, including the testing and completion of the Leduc well drilled at Ricinus 11-17, as bridges to the location were washed out. Equipment is in place and testing of this well should proceed early in August. The successful Viking well at Ricinus 4-35 is being currently being completed, while the first two wells in the summer drilling program in the Ferrier and Ricinus areas of western Alberta have been drilled and are awaiting completion. High Point has licensed or is in the process of licensing 15 locations at Ricinus and Ferrier and already has eight locations licensed and available to drill at Desan for the 2005/2006 winter drilling program.



Quarterly Review of Operating and Financial Performance

------------------------------------------------------------------------
Second First Fourth Third
Quarter 05 Quarter 05 Quarter 04 Quarter 04
------------------------------------------------------------------------
Average daily production
------------------------------------------------------------------------
Natural gas (mcf/d) 17,392 13,650 15,037 15,080
------------------------------------------------------------------------
Oil and liquids (bbl/d) 512 593 566 465
------------------------------------------------------------------------
Barrels equivalent (boe/d) 3,410 2,868 3,072 2,978
------------------------------------------------------------------------

------------------------------------------------------------------------
Prices
------------------------------------------------------------------------
Natural gas ($/mcf) 7.07 7.14 6.55 5.85
------------------------------------------------------------------------
Light oil ($/bbl) 65.00 59.37 57.13 63.62
------------------------------------------------------------------------
Natural gas liquids ($/bbl) 48.80 46.50 45.40 38.12
------------------------------------------------------------------------

------------------------------------------------------------------------
Financial ($000)
------------------------------------------------------------------------
Net petroleum and natural
gas sales 10,868 9,115 9,297 7,270
------------------------------------------------------------------------
Cash flow from operations 7,820 6,363 6,977 5,166
------------------------------------------------------------------------
Per share - basic and
diluted 0.10 0.08 0.09 0.07
------------------------------------------------------------------------
Net income (loss) after tax 2,295 976 1,451 542
------------------------------------------------------------------------
Per share - basic and
diluted 0.03 0.01 0.02 0.01
------------------------------------------------------------------------
Total assets 217,877 217,563 193,363 182,925
------------------------------------------------------------------------
Long term financial
liabilities 0 0 0 0
------------------------------------------------------------------------

------------------------------------------------------------------------
Second First Fourth Third
Quarter 04 Quarter 04 Quarter 03 Quarter 03
------------------------------------------------------------------------
Average daily production
------------------------------------------------------------------------
Natural gas (mcf/d) 16,480 14,069 13,533 11,225
------------------------------------------------------------------------
Oil and liquids (bbl/d) 449 442 493 471
------------------------------------------------------------------------
Barrels equivalent (boe/d) 3,196 2,787 2,749 2,341
------------------------------------------------------------------------

------------------------------------------------------------------------
Prices
------------------------------------------------------------------------
Natural gas ($/mcf) 6.46 6.12 5.33 5.48
------------------------------------------------------------------------
Light oil ($/bbl) 47.49 41.25 37.12 39.73
------------------------------------------------------------------------
Natural gas liquids ($/bbl) 35.21 33.45 31.69 31.94
------------------------------------------------------------------------

------------------------------------------------------------------------
Financial ($000)
------------------------------------------------------------------------
Net petroleum and
natural gas sales 7,682 6,649 5,678 5,398
------------------------------------------------------------------------
Cash flow from operations 5,405 4,618 3,037 2,861
------------------------------------------------------------------------
Per share - basic and
diluted 0.07 0.07 0.04 0.04
------------------------------------------------------------------------
Net income (loss) after tax (298) 1,321 454 (989)
------------------------------------------------------------------------
Per share - basic and
diluted (0.00) 0.02 0.01 (0.02)
------------------------------------------------------------------------
Total assets 172,963 170,868 151,813 140,832
------------------------------------------------------------------------
Long term financial
liabilities 0 0 2,918 2,899
------------------------------------------------------------------------


HIGH POINT RESOURCES INC.
Consolidated Balance Sheets

------------------------------------------------------------------------
June 30, December 31,
(Unaudited) 2005 2004
-----------------------------
ASSETS $ $

CURRENT
Accounts receivable 9,291,852 9,951,298
Prepaid expenses and deposits 725,026 678,580
-----------------------------
10,016,878 10,629,878

Goodwill 14,674,423 14,674,423

Property and equipment (note 3) 193,185,710 168,059,132
-----------------------------
217,877,011 193,363,433
-----------------------------
-----------------------------

LIABILITIES

Current
Bank indebtedness 4,174,642 131,433
Accounts payable and accrued liabilities 18,496,069 22,502,551
Short-term debt (note 2) 15,000,000 -
Bank debt (note 2) 54,000,000 50,000,000
-----------------------------
91,670,711 72,633,984

Asset retirement obligation (note 4) 1,808,918 1,793,436

Future tax liability 34,371,765 30,631,057
-----------------------------
127,851,394 105,058,477
-----------------------------

Commitments (note 6)

SHAREHOLDERS' EQUITY

Share capital (note 5) 89,389,905 91,151,899
Contributed surplus (note 5 (iii)) 1,771,482 1,559,609
Deficit (1,135,770) (4,406,552)
-----------------------------
90,025,617 88,304,956
-----------------------------
217,877,011 193,363,433
-----------------------------
-----------------------------

See accompanying notes


HIGH POINT RESOURCES INC.
Consolidated Statements of Operations and Deficit

------------------------------------------------------------------------
Three Three Six Six
months months months months
ended ended ended ended
June 30, June 30, June 30, June 30,
(Unaudited) 2005 2004 2005 2004
------------------------------------------------

REVENUE
Petroleum and
natural gas $14,070,881 $11,791,479 $26,021,190 $21,555,863
Royalties,
net of ARTC (2,693,553) (3,543,098) (4,936,651) (6,134,025)
Transportation expense (508,764) (566,084) (1,101,280) (1,090,845)
------------------------------------------------
Petroleum and natural
gas sales, net of
royalties and
transportation 10,868,564 7,682,297 19,983,259 14,330,993
Other income 1,708 2,234 2,346 11,080
------------------------------------------------
10,870,272 7,684,531 19,985,605 14,342,073
------------------------------------------------
EXPENSES
Operating 1,114,156 1,062,299 2,311,851 2,016,929
Asset retirement
accretion (note 4) 28,199 28,149 59,058 58,825
General and
administration 892,162 708,488 1,706,292 1,161,512
Stock-based
compensation
(note 5(iii)) 176,380 91,891 371,428 229,425
Depletion and
depreciation 4,817,362 4,257,539 9,212,626 8,622,300
Interest and other
financing charges
(note 2) 1,112,817 563,105 1,802,203 1,120,394
Accretion on
debentures - - - 20,508
------------------------------------------------
8,141,076 6,711,471 15,463,458 13,229,893
------------------------------------------------
EARNINGS BEFORE
INCOME TAXES 2,729,196 973,060 4,522,147 1,112,180
PROVISION FOR
(RECOVERY OF)
INCOME TAXES
Current (69,723) (54,507) (18,273) 20,493
Future 504,062 1,326,096 1,269,638 69,124
------------------------------------------------
NET EARNINGS (LOSS) 2,294,857 (298,529) 3,270,782 1,022,563
------------------------------------------------
------------------------------------------------


DEFICIT, BEGINNING
OF PERIOD (3,430,627) (6,101,136) (4,406,552) (6,466,913)
------------------------------------------------
Retroactive application
of change in
accounting policy
(note 5(iii)) - - - (955,315)
------------------------------------------------
DEFICIT, END OF PERIOD (1,135,770) (6,399,665) (1,135,770) (6,399,665)
------------------------------------------------
------------------------------------------------
NET EARNINGS PER SHARE
(basic and diluted) 0.03 (0.00) 0.04 0.01
------------------------------------------------

See accompanying notes


HIGH POINT RESOURCES INC.
Consolidated Statements of Cash Flows

------------------------------------------------------------------------
Three Three Six Six
months months months months
ended ended ended ended
June 30, June 30, June 30, June 30,
(Unaudited) 2005 2004 2005 2004
------------------------------------------------

Cash provided by (used in):

OPERATING ACTIVITIES
Net earnings (loss) $2,294,857 $(298,529) $3,270,782 $1,022,563
Add items not
requiring cash:
Depletion and
depreciation 4,817,362 4,257,539 9,212,626 8,622,300
Future income taxes 504,062 1,326,096 1,269,638 69,124
Accretion on debentures - - - 20,508
Asset retirement
accretion (note 4) 28,199 28,149 59,058 58,825
Stock based compensation
(note 5 (iii)) 176,380 91,891 371,428 229,425
------------------------------------------------
FUNDS FROM OPERATIONS 7,820,860 5,405,146 14,183,532 10,022,745
Change in non-cash
working capital
relating to operating
activities 100,959 2,012,046 (390,145) 1,433,752
------------------------------------------------
7,921,819 7,417,192 13,793,387 11,456,497
------------------------------------------------
FINANCING ACTIVITIES
Increase (decrease)
in bank debt - (5,000,000) 4,000,000 -
Issue of common shares 495,520 14,095,177 549,521 14,260,337
Increase in short-term
debt - - 15,000,000 5,000,000
------------------------------------------------
495,520 9,095,177 19,549,521 19,260,337
------------------------------------------------
INVESTING ACTIVITIES
Additions to property
and equipment (10,189,750) (6,212,868)(37,343,309)(31,397,716)
Asset retirement
obligations settled - (134,912) (158,220)
Proceeds on sale of
oil and gas
properties (note 3) 295,000 - 2,960,529 1,086,623
Change in non-cash
working capital
related to investing
activities (7,646,548) (6,166,335) (3,003,337) (2,631,559)
------------------------------------------------
(17,541,298)(12,514,115)(37,386,117)(33,100,872)
------------------------------------------------
INCREASE (DECREASE)
IN CASH (9,123,959) 3,998,254 (4,043,209) (2,384,038)

CASH (BANK
INDEBTEDNESS),
BEGINNING OF PERIOD 4,949,317 (4,233,314) (131,433) 2,148,978
------------------------------------------------

BANK INDEBTEDNESS,
END OF PERIOD (4,174,642) (235,060) (4,174,642) (235,060)
------------------------------------------------
------------------------------------------------

SUPPLEMENTARY INFORMATION
Cash interest paid 1,112,817 563,105 1,802,203 1,120,394
Cash taxes paid
(recovered) (69,723) (54,507) (18,273) 20,493

See accompanying notes


Notes to the Financial Statements
(unaudited)

1. ACCOUNTING POLICIES

These unaudited interim consolidated financial statements have been prepared in accordance with Canadian generally accepted accounting principles ('GAAP'), and follow the same accounting policies as for the financial statements for the fiscal year ended December 31, 2004. These notes are incremental to, and should be read in conjunction with, the audited financial statements for the year ended December 31, 2004.

The comparative consolidated financial statements have been reclassified from statements previously presented to conform to the presentation of the current year consolidated financial statements.

2. LOANS

At June 30, 2005, 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 June 30, 2005 the Corporation was not in compliance with a banking covenant relating to the aging of trade payables. The Corporation has received a letter from the bank, agreeing to waive this default until August 31, 2005. At June 30, 2005, $54,000,000 was drawn against the credit facility.

On December 2, 2004 a new 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 is to be paid at bank prime plus 3.25%. At June 30, 2005 the Corporation was not in compliance with a covenant in the facility relating to the maintenance of minimum working capital. The Corporation has received a letter from the lending corporation, agreeing to waive the default for the period ending June 30, 2005. As of June 30, 2005, $15,000,000 was drawn against this credit facility.



Second Quarter Ended Six Months Ended

June 30, June 30, June 30, June 30,
2005 2004 2005 2004

Interest $826,833 $506,145 $1,397,019 $1,013,431

Financing charges 285,984 56,960 405,184 106,963

---------------------------------------------
Interest and other
financing charges 1,112,817 563,105 1,802,203 1,120,394


3. PROPERTY AND EQUIPMENT

Effective March 31, 2005, the Corporation sold its interest at Medicine Lodge, Alberta and other minor interests for net proceeds of $2,665,529. A further minor interest at Ferrier, Alberta was sold on June 29, 2005 for proceeds of $295,000.

Effective January 28, 2004, the Corporation sold its interest at Wembley, Alberta and other minor interests for net proceeds of $1,086,623.

At June 30, 2005, carrying costs of $13,587,112 (2004 - $8,526,188) related to unproven properties have been excluded from the depletion calculation.

At June 30, 2005, property, plant and equipment includes costs of $1,451,405 related to the asset retirement obligation (net of depletion).

4. 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 $4.3 million which will be incurred between 2005 and 2025. A credit adjusted risk free rate of 6.75% and an inflation rate of 1.6% were used to calculate the fair value of the obligation.




------------------------------------------------------------------------
Asset Retirement Second Quarter Ended Six Months Ended
Obligation
------------------------------------------------------------------------
June 30, June 30, June 30, June 30,
2005 2004 2005 2004
------------------------------------------------------------------------
Balance - beginning
of period $1,859,532 $1,834,962 $1,793,436 $1,521,265
------------------------------------------------------------------------
Liabilities incurred
(net of disposals) (78,813) 42,917 (43,576) 349,246
------------------------------------------------------------------------
Accretion expense 28,199 28,149 59,058 58,825
------------------------------------------------------------------------
Liabilities settled - (134,912) - (158,220)
------------------------------------------------------------------------
Balance - end of period 1,808,918 1,771,116 1,808,918 1,771,116
------------------------------------------------------------------------


5. 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, 2004 79,386,196 91,151,899
Tax benefits renounced on flow-through
shares (i) (2,471,070)
Issued for cash on exercise of stock options 60,001 54,001
Stock based compensation expense (iii) 48,966
--------------------------
Balance at March 31, 2005 79,446,197 88,783,796
Issued for cash on exercise of stock options 346,334 495,520
Stock based compensation expense (iii) 110,589
--------------------------
Balance at June 30, 2005 79,792,531 89,389,905
--------------------------
--------------------------


(i) 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 $7,350,000 in January 2005 having expended $6,300,000 in exploratory costs relating to this issue by December 31, 2004, and under the 'look back' provision governing flow-through shares, expended the balance of $1,200,000 in the first quarter of 2005. The taxable benefit renounced by the Corporation in the first quarter of 2005 was $2,471,070 at current tax rates.

(ii) Interest free loans were issued by the Corporation in 2001 and 2002 to certain officers 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. At June 30, 2005, $555,000 remains outstanding. The market value of the shares held as collateral at June 30, 2005 was $1,157,083.

(iii) 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 for a balance at December 31, 2004 of $1,559,609.

In the first six months of 2005 an adjustment to contributed surplus of ($159,555) was recognized with regard to stock options exercised with the offset to share capital. First half stock based compensation expense of $371,428 was applied to contributed surplus for a balance of $1,771,482 at June 30, 2005.



Weighted Average
Options Number of Shares Exercise Price $
---------------------------------------
Outstanding, December 31, 2004 5,357,334 1.50
Granted - -
Exercised (406,335) 1.35
Expired - -
---------------------------------------
Outstanding, June 30, 2005 4,950,999 1.51
---------------------------------------
---------------------------------------


6. FINANCIAL INSTRUMENTS

Gas Hedging
------------------------------------------------------------------------
Period Volume Hedged AECO Price
------------------------------------------------------------------------
Apr. 1, 2004
- Oct 31, 2005 6,000 GJ/day (5.7 mmcf/d) $6.95/GJ ($7.30/mcf)
------------------------------------------------------------------------
Apr. 1, 2004
- Oct 31, 2005 3,000 GJ/day (2.9 mmcf/d) $6.82/GJ ($7.16/mcf)
------------------------------------------------------------------------
Nov. 1, 2005
- Mar. 31, 2006 3,000 GJ/day (2.9 mmcf/d) $8.01/GJ ($8.41/mcf)
------------------------------------------------------------------------
Nov. 1, 2005
- Mar. 31, 2006 3,000 GJ/day (2.9 mmcf/d) $8.32/GJ ($8.74/mcf)
------------------------------------------------------------------------
Nov. 1, 2005
- Mar. 31, 2006 2,000 GJ/day (1.9 mmcf/d) $8.85/GJ ($9.30/mcf)
------------------------------------------------------------------------


The estimated fair value of the Corporation's commodity hedging contracts at June 30, 2005 was ($435,020), being the amount of the Corporation's unrealized loss on the balance of the hedging contracts.

7. SUBSEQUENT EVENTS

The Corporation has entered into a definitive agreement with subsidiaries of Enterra Energy Trust ("Enterra") whereby a subsidiary of Enterra will acquire all the issued and outstanding common shares of the Corporation. The acquisition is to be completed by way of a plan of arrangement under the Business Corporation's Act (Alberta), pursuant to which shareholders of the Corporation will be entitled to receive, for each common share of the Corporation, either: (i) 0.105 of a trust unit ("Trust Unit") of Enterra (which will receive monthly cash distributions); or (ii) 0.105 of an exchangeable share (the "Exchangeable Share") (the exchange ratio of which will be adjusted on a monthly basis in lieu of cash distributions to unitholders) of the acquirer, Rocky Mountain Acquisition Corp. (a subsidiary of Enterra), such shares being exchangeable into Trust Units of Enterra, subject to a maximum of 2,500,000 Exchangeable Shares being issued. Completion of the Arrangement is subject to certain conditions, including approval of not less than 66?% of votes cast by shareholders.
A meeting of the shareholders of the Corporation to vote on the proposal is scheduled for August 16, 2005, with closing of the transaction expected shortly thereafter.

Contact Information

  • 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