Bear Ridge Resources Ltd.
TSX : BER

Bear Ridge Resources Ltd.

August 14, 2006 21:47 ET

Bear Ridge Announces 2006 Second Quarter Highlights

CALGARY, ALBERTA--(CCNMatthews - Aug. 14, 2006) - Bear Ridge Resources Ltd. (TSX:BER) is pleased to present its financial and operating results for the second quarter of 2006.



Financial Review and Operating Highlights

FINANCIAL Three Months Ended June 30 Six Months Ended June 30
------------------------------------------------------------------------
(in 000s, except
share amounts) 2006 2005 Change 2006 2005 Change
------------------------------------------------------------------------
Petroleum and
natural gas
revenue 13,806 4,176 231 % 28,393 5,366 429 %
Cash flow from
operations 7,003 2,927 139 % 13,975 3,334 319 %
Per share
- basic ($) 0.15 0.12 25 % 0.30 0.15 100 %
Per share
- diluted ($) 0.14 0.11 27 % 0.29 0.14 107 %
Net income (loss) 524 1,255 (58)% (554) 1,048 (153)%
Per share
- basic ($) 0.01 0.05 (80)% (0.01) 0.05 (120)%
Per share
- diluted ($) 0.01 0.05 (80)% (0.01) 0.04 (125)%
Capital Expenditures
Related to
acquisitions - - - 109,594 21,436 411 %
Related to current
operations 17,361 19,958 (13)% 54,090 24,944 117 %
Working capital
deficiency (18,960) (560) (3,285)% (18,960) (560) (3,285)%
Bank debt (61,550) - - (61,550) - -
Shares outstanding
(000s)
At period end 50,130 27,928 79 % 50,130 27,928 79 %
Weighted average,
basic 48,676 24,913 95 % 45,967 22,064 108 %
Weighted average,
diluted 51,295 26,619 93 % 48,688 24,254 101 %
------------------------------------------------------------------------
OPERATING
Production
Natural gas
(mcf/d) 14,713 2,365 522 % 15,980 1,876 752 %
Oil and NGL's
(bbls/d) 576 413 40 % 627 236 166 %
Total oil and
equivalent
(boe/d) 3,028 808 275 % 3,290 549 499 %
Average wellhead
prices
Natural gas
($/mcf) $ 7.38 $ 8.03 (8)% $ 7.69 $ 7.75 (1)%
Oil and NGL's
($/bbl) $ 74.87 $ 65.03 15 % $ 69.10 $ 63.98 8 %
Total oil and
equivalent
(boe/d) $ 50.10 $ 56.81 (12)% $ 50.52 $ 54.02 (6)%
Operating costs
($/boe) $ 8.76 $ 7.55 16 % $ 7.97 $ 7.26 10 %
G&A costs ($/boe) $ 3.31 $ 4.54 (27)% $ 2.53 $ 6.08 (58)%
Operating Netback
($/boe) $ 31.66 $ 44.79 (29)% $ 29.92 $ 39.98 (25)%
Wells Drilled
Gross 23 1 48 8
Net 11.6 0.25 23.9 6.5
Net success rate 87% 100% 85% 88%
Undeveloped land
(net acres) 122,000 42,000 191 % 122,000 42,000 191 %
------------------------------------------------------------------------
------------------------------------------------------------------------


Second Quarter 2006 Highlights

- Bear Ridge drilled 23 (11.6 net) wells during the quarter with an 87 percent success rate.

- Second quarter production was up 275 percent to 3,028 boe per day from 808 boe per day in the second quarter of 2005. Production per share was up 150 percent compared to the same quarter of 2005.

- Cash flow from operations totaled $7 million in the quarter, up 139 percent from $2.9 million in the second quarter of 2005. Cash flow per share climbed 27 percent compared to the same quarter of 2005.

- Capital investment in the quarter was $17.4 million, net of dispositions of $6.7 million, with $13.3 million directed towards drilling and completions and $4.1 million expended on land and seismic acquisition.

- The Company's undeveloped land position is up 191 percent to 122,000 net acres from 42,000 in the second quarter of 2005.

- In April the Company completed the issue of 3.15 million flow through common shares for total net proceeds of approximately $22 million.

- During the quarter Bear Ridge completed minor property dispositions of 130 boe per day for proceeds of $6.5 million and subsequent to the quarter closed the sale of an additional 70 boe per day of non-core production for $2.8 million.

Message to Shareholders

Bear Ridge conducted a very active and successful capital program in the second quarter of 2006 drilling a total of 23 (11.6 net) wells with an 87 percent success. After a slow start to the year, we have accelerated our drilling program and are now well ahead of schedule, with 48 (23.9 net) wells drilled in the first half of the year out of a planned 78 well drilling program for 2006. Drilling rigs are contracted to execute the balance of the program and we do not foresee any issues that would adversely affect timing of planned operations. Year to date, our drilling and completion results are in line with expectations and we have a good balance of development drilling and high impact wells planned for the remainder of the year.

Second quarter production was below our forecast primarily due to plant turnarounds and production delays due to wet surface conditions, shortage of services and extended timelines for regulatory approvals. The quarter was also impacted by (i) a downhole mechanical failure in our 15-6 Mica well that has resulted in 300 boe per day being shut-in, and (ii) minor property dispositions of 200 boe per day.

Recent tie-ins of successful second quarter wells are projected to increase production to 4,500 boe per day over the next week with incremental behind pipe volumes of 1,500 boe per day, the majority of which, are scheduled to come on stream by the end of the third quarter. Our productive capacity now stands at 6,000 boe per day and tie-in operations are well underway to bring these behind pipe volumes on stream.

Bear Ridge accelerated its capital program in the first half of 2006 in order to capture and evaluate a number of competitive growth opportunities. Of our total $80 million 2006 capital program, $54 million or 68 percent was expended in the first half of the year, with land and seismic investments representing $18 million or 33 percent of total spending. During the quarter the Company reduced its overall debt position by 14% to 80 million as at June 30, 2006. The Company generated cash proceeds of $33.5 million during the quarter; $22 million from a flow through share issue, $6.5 million from minor property dispositions and $2.5 million from equalization of seismic and land costs on our Josephine project. An additional $2.8 million was received subsequent to the end of the quarter on closing of an additional minor property disposition. Subsequent to June 30, 2006, Bear Ridge negotiated an increase in the Company's credit facilities to $80.0 million. The increase is subject to final approval by the lender which is expected to be received prior to August 25, 2006. Cash flow over the last half of 2006 is forecast to exceed capital spending and thereby further reduce the Company's debt position by year end.

The Company initiated a proactive commodity hedging program early in the year in light of an accelerated 2006 capital program, debt levels and record natural gas storage levels. We hedged 10,000 GJ per day representing over 50 percent of our May to October production at guaranteed minimum prices of $7.25 per GJ in order to provide certainty to our budgeted natural gas price of $6.00 per mcf for the period. During the quarter this program contributed $1.5 million to cash flows and allowed Bear Ridge to execute a very active capital program and capture numerous growth opportunities during a period of curtailed activities and reduced production targets throughout the sector. In light of continued uncertainty around natural gas storage levels and pricing for the upcoming winter season we have expanded our hedging stance in order to protect our upcoming winter drilling program and currently have 9,000 GJ per day hedged from November to March. The program will provide Bear Ridge a guaranteed minimum price of $8.15/GJ while providing upside potential to $10.80/GJ on hedged volumes.

Bear Ridge has been very active at crown land sales in the first half of 2006 and has increased its net undeveloped land position by 160 percent from 47,000 net acres at year-end 2005 to 122,000 net acres at June 30, 2006. Of particular note, we acquired a 100 percent interest in 27 contiguous sections (17,280 net acres) on a high impact natural gas resource play in the Tupper area of Northeast British Columbia. Bear Ridge shot and purchased a total of 135 square kilometers of 3D seismic evaluating both our land position and a rapidly developing Montney gas pool directly offsetting our land block. If successful, our Tupper project has the potential to deliver significant per share reserve and production growth. Our first well at Tupper is planned for the third quarter of 2006.

OUTLOOK

In light of production delays experienced in the first half of the year coupled with the sale of 200 boe per day, the Company is reducing its average 2006 production forecast to 4,200-4,400 boe per day. However, with a current productive capacity of 6,000 boe per day and a solid drilling, completion and tie-in program planned for the balance of the year, Bear Ridge is well positioned to meet its year-end production target and we are maintaining exit guidance of approximately 6,000 boe per day.

Our capital acceleration into the first half of the year allowed us to evaluate and acquire a number of significant growth opportunities. We have contracted 2 drilling rigs for the upcoming summer and winter drilling programs and have lined up related services to ensure timely execution of completions and tie-ins. Bear Ridge is well hedged for the remainder of the summer 2006 period and has a good start on a hedge position for the upcoming winter drilling season. We expect the balance sheet will continue to improve as cash flow is forecast to exceed capital spending in the second half of 2006.

Bear Ridge will continue to execute a drillbit growth strategy anchored by significant 3D seismic investments in order to provide high impact growth potential at acceptable levels of risk. We have acquired over 1,200 square kilometers of 3D seismic data in our Peace River Arch and NEBC focus regions, with 1,000 square kilometers of data covering our Earring, Josephine, Eaglesham, Clear Hills, Gunnell and Tupper projects. Year to date, 3D-driven drilling has yielded 4 new pool discoveries at Earring, 3 new pool discoveries at Eaglesham, 1 new pool discovery at Clear Hills and a string of 10 successful development wells at Gunnell. Our first drilling operations on our high impact Josephine and Tupper 3D projects are scheduled for the second half and additional exploration and development wells are planned to follow up on our first half successes at Earring, Eaglesham, Clear Hills and Gunnell.

Russell J. Tripp

Chairman and Chief Executive Officer

August 14, 2006

Management's Discussion and Analysis

Management's discussion and analysis ("MD&A") has been prepared as of August 14, 2006 by Bear Ridge Resources Ltd. ("Bear Ridge" or "the Company"). The MD&A should be read in conjunction with the Company's unaudited consolidated financial statements for the six and three month periods ended June 30, 2006 and 2005, and the consolidated financial statements for the year ended December 31, 2005 which have been prepared in accordance with Canadian generally accepted accounting principles ("GAAP") and have been filed on sedar at: www.sedar.com.

Given the objectives of the MD&A, certain information presented is of a forward looking nature. Such forward looking financial and operational information involves known and unknown risks and uncertainties, some of which are beyond the Company's control. These include but are not limited to; the impact of general economic conditions, volatility of commodity prices, currency fluctuations, imprecision of reserve estimates, environmental risks, government regulations, stock market volatility, and competition from other producers. Although assumptions used in the preparation of forward looking information are considered reasonable by management at the time, actual results could differ materially from those contained in such forward-looking information.

The presentation of the MD&A uses the following terms which, although universally applied in analyzing performance within our industry, are required to be disclosed under GAAP.

Non-GAAP Measurements - The MD&A contains the term cash flow from operations, which should not be considered an alternative to, or more meaningful than cash flow from operating activities as determined in accordance with GAAP as an indicator of the Company's performance. Bear Ridge's determination of cash flow from operations may not be comparable to that reported by other companies, especially those in other industries. The reconciliation between net earnings and cash flow from operations can be found in the consolidated statement of cash flows. The Company also presents cash flows from operations per share whereby per share amounts are calculated using weighted average shares outstanding consistent with the calculation of earnings per share. The Company also uses operating netback as an indicator of operating performance. Operating netback is calculated on a per boe basis taking the sales price and deducting royalties, operating and transportation expenses.

BOE Presentation - The term barrels of oil equivalents (BOE) may be misleading, particularly if used in isolation. A BOE conversion ratio of 6 mcf: 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 BOE conversions in the report are derived by converting gas to oil in the ratio of six thousand cubic feet of gas to one barrel of oil.

PETROLEUM AND NATURAL GAS SALES

Production for the second quarter of 2006 averaged 3,028 boe per day compared to 808 boe per day for the three months ended June 30, 2005, an increase of 275%. Recent tie-ins of successful second quarter wells are projected to increase production to 4,500 boe per day over the next week with incremental behind pipe volumes of 1,500 boe per day, the majority of which, are scheduled to come on stream by the end of the third quarter. An additional 6 wells are currently standing waiting on completion and have not been included in Bear Ridge's behind pipe numbers.

Natural Gas

Natural gas revenues for the three and six month periods ended June 30, 2006 totaled $22.2 million and $9.9 million, respectively, representing increases of 745% and 472% when compared with the same periods from 2005. These increases were the direct result of increased production volumes from drilling activities and volumes acquired through the Veteran acquisition in the first quarter of 2006. When compared to natural gas revenues of $12.3 million from the first quarter of 2006, natural gas revenues in the second quarter are down 5.5% as a result of decreases in production and price received.

Natural gas production of 14,713 mcf per day for the second quarter was down 14.8% from 17,262 mcf per day during the first quarter. The decrease in natural gas volume was due to natural declines combined with delays in bringing on gas shut-in in from the Earring area during the first quarter, the sale of approximately 780 mcf per day of non-core assets in May and significant production decreases in June due to plant turn-arounds. Combined downtime in June accounted for approximately 925 boe per day of lost production for the month which translates into approximately 310 boe per day of overall production and 72% of the decline in natural gas production for the quarter.

Natural gas pricing for the second quarter of 2006 averaged $7.38 per mcf compared to $7.96 per mcf in the first quarter of the year. This decrease of 7.3% compares favorably to a decrease in the AECO gas daily spot price of 19.8% over the same period. Bear Ridge benefited from costless collar arrangements during the second quarter, which contributed approximately $1.5 million in realized hedging gains. Without these arrangements, the Company's natural gas price in the second quarter would have averaged $6.26 per mcf.

Oil and NGL's

Oil and NGL revenue for the three and six month periods ended June 30, 2006 totaled $3.9 million and $7.8 million, respectively, representing increases of 60% and 187% when compared with the same periods of 2005. These increases were the direct result of increased production volumes from drilling activities, the Veteran acquisition in the first quarter of 2006 and improved pricing during 2006. When compared to oil and NGL revenues of $3.9 million from the first quarter of 2006, revenues for the second quarter remained flat. Production of 576 bbl/d was down 15.0% from 678 bbl per day in the first quarter mostly due to a decrease of 120 bbl/d in NGL volumes associated with lower gas production in the quarter. The decrease in production levels were offset by improved pricing in the quarter.

Oil prices for the three months ended June 30, 2006 averaged $77.73 per bbl, an increase of 21.8% from the first quarter of 2006 average price of $63.84 per bbl. Increases in pricing are the result of premium pricing received on condensate volumes sold during the second quarter and an oil price equalization payment received which added approximately $3.00 per boe to Bear Ridge's realized oil price for the quarter. NGL prices received by Bear Ridge totaled $65.95 per bbl during the second quarter compared to $67.14 in the first quarter, representing a change of only 1.7%.



Three months ended Six months ended
------------------------------------------------------------------------
Results of June 30, June 30, % June 30, June 30, %
Operations 2006 2005 Change 2006 2005 Change
------------------------------------------------------------------------
Revenues (000's)
Natural gas $ 9,882 $ 1,729 472% $22,246 $ 2,632 745%
Oil and NGL's 3,924 2,447 60% 7,838 2,734 187%
------------------------------------------------------------------------
Total revenues $13,806 $ 4,176 231% $30,084 $ 5,366 461%
Less acquisition
adjustment (1) - - 1,691 -
------------------------------------------------------------------------
Total revenues per
financial
statements $13,806 $ 4,176 231% $28,393 $ 5,366 429%
------------------------------------------------------------------------
------------------------------------------------------------------------

Average Daily Production
Volumes
Natural gas (mcf/d) 14,713 2,365 522% 16,696 1,876 790%
Oil & NGL's (bbl/d) 576 413 40% 658 236 179%
------------------------------------------------------------------------
Total production
(boe/d) 3,028 808 275% 3,440 549 527%
Acquisition
adjustment (1) - - 150 -
------------------------------------------------------------------------

(1) The acquisition adjustment relates to revenues and production
volumes allocated, for accounting purposes, to the first 19 days of
January, 2006 prior to closing the acquisition of Veteran Resources
Inc. by Bear Ridge.


PRICES AND MARKETING

Oil prices are derived from the WTI average price adjusted for the U.S. dollar exchange rate and quality differentials. Bear Ridge sells its natural gas into the daily spot market based on the Alberta AECO reference price. The Company currently produces gas with a high heating value and as such the values expressed on a $ per mcf basis are generally higher than the AECO per mcf average. A comparison of Bear Ridge's natural gas and crude oil pricing with AECO and WTI benchmark pricing is as follows:



Three months ended Six months ended
------------------------------------------------------------------------
June 30, June 30, June 30, June 30,
2006 2005 2006 2005
------------------------------------------------------------------------
Bear Ridge's Average
Selling Price
Natural gas - $/mcf
including hedging $ 7.38 $ 8.03 $ 7.69 $ 7.75
Natural gas - $/mcf
excluding hedging $ 6.75 $ 8.03 $ 7.19 $ 7.75
Crude oil - $/bbl $ 77.73 $ 65.03 $ 70.24 $ 63.98
NGL's - $/bbl $ 65.95 $ 65.03 $ 66.70 $ 69.85
Total average selling price
- $/boe $ 50.10 $ 56.81 $ 50.52 $ 54.02

Benchmark Pricing
AECO gas daily spot - $/mcf $ 6.04 $ 7.42 $ 6.77 $ 7.27
WTI oil - US $/bbl $ 70.70 $ 53.17 $ 67.08 $ 55.97
Edmonton par - CDN $/bbl $ 78.55 $ 65.43 $ 73.76 $ 64.39
US/CDN average exchange
rate 0.89 0.80 0.88 0.81
------------------------------------------------------------------------


Bear Ridge is exposed to fluctuations in natural gas and oil prices and occasionally enters into future price contracts specifying either a fixed future settlement price or a range of prices. The primary reason for doing so is to protect cash flows to ensure the Company has the necessary resources to complete its capital program. Bear Ridge currently has the following costless collar commodity contracts, fixed price sales and put options in place.



------------------------------------------------------------------------
Term Hedged volumes Floor Ceiling
------------------------------------------------------------------------
Oil
January 2006 - December 2006 200 bbl/d $ 55.00US $ 73.00US

Natural Gas
April 1 to October 31, 2006 2,000GJ/d $ 9.00CDN $ 12.85CDN
April 1 to October 31, 2006 1,000GJ/d $ 9.00CDN $ 13.05CDN
May 1 to October 31, 2006 3,000 GJ/d $ 6.50CDN $ 7.55CDN
May 1 to October 31, 2006(1) 4,000 GJ/d $ 6.50CDN -
November 1, 2006 to March 31,
2007(2) 2,000GJ/d $ 8.76CDN -
November 1, 2006 to March 31,
2007 5,000 GJ/d $ 8.00CDN $ 11.65CDN
November 1, 2006 to March 31,
2007 2,000GJ/d $ 8.00CDN $ 10.85CDN
------------------------------------------------------------------------

(1) Put options guarantee a floor price of $6.50 and have no price
ceiling. The cost of each put to the company is approximately $0.52
per GJ

(2) Fixed price sale


ROYALTIES

For the three months ended June 30, 2006 royalties, net of the Alberta Royalty Tax Credit ("ARTC"), totaled $2,230,947 or 16.2 % of total revenues. This rate as a percentage of revenue represents a significant reduction in royalties when compared to with the first quarter average of 27.3% of revenue. Revenues in the second quarter included $1.5 million of realized hedging gains, which are not subject to royalties. When combined with the receipt of the Company's annual gas cost allowance in the quarter, of approximately $344,000, and a royalty credit received from the B.C. government for last years summer drilling in the Mica area of $160,000, Bear Ridge's royalties as a percentage of revenue dropped 11.1% from the first quarter of 2006.

Royalty rates for the three and six month periods ended June 30, 2006 are higher than the comparable periods in 2005 due to the majority of oil sales in 2005 being subject to a royalty holiday for the first half of the year, which substantially reduced royalties as a percentage of revenue for the three and six month periods then ended.

ARTC recoveries totaled $125,000 for the second quarter and $250,000 year to date. Bear Ridge did not have properties eligible for ARTC during the first quarter of 2005, but acquire properties that were eligible early in the second quarter of 2005 that were eligible and resulting in a recovery. Based on the level of Alberta crown royalties paid by Bear Ridge to date for 2006, the Company expects to receive the maximum credit of $500,000 during the year.



------------------------------------------------------------------------
Three months ended Six months ended
------------------------------------------------------------------------
June 30, June 30, % June 30, June 30, %
Royalties(000's) 2006 2005 Change 2006 2005 Change
------------------------------------------------------------------------
Crown $ 1,880 $ 419 348 % $ 5,438 $ 662 721 %
Freehold and GORR 476 33 134 % 1,026 120 755 %
ARTC (125) (165) (24)% (250) (165) 52 %
------------------------------------------------------------------------
Total Royalty
Expense $ 2,231 $ 287 677 % $ 6,214 $ 617 907 %
------------------------------------------------------------------------
Royalties per boe $ 8.10 $ 3.91 107 % $ 11.19 $ 6.21 80 %
------------------------------------------------------------------------
------------------------------------------------------------------------


Three months Six months
ended ended
------------------------------------------------------------------------
Average royalty rates June 30, June 30, June 30, June 30,
(% of sales) 2006 2005 2006 2005
------------------------------------------------------------------------
Royalty Category
Crown 13.6 % 10.1 % 19.2 % 12.4 %
Freehold and GORR 3.5 % 0.9 % 3.6 % 2.2 %
ARTC (0.9)% (4.0)% (0.9)% (3.1)%
------------------------------------------------------------------------
Total Royalty 16.2 % 7.0 % 21.9 % 11.5 %
------------------------------------------------------------------------
------------------------------------------------------------------------


OPERATING EXPENSES

When compared with the previous year Bear Ridge's operating costs per boe for the three and six month periods ended June 30, 2006 have increased by 16.0% and 9.8% respectively. The increase in costs is due to a significant change in the Company's expanding production base which has grown from being relatively small and concentrated as at June 30, 2005 to one that is much more substantial.

When compared to the first quarter of 2006, operating costs per boe increased from $7.28 in the first quarter to $8.76 in the second quarter, an increase of 20.3%. The increase on a boe basis is due to higher than anticipated processing fees, non-operated charges, lower production rates during the quarter and continuing inflationary pressure driving up industry's overall operating cost structure. Despite the upward trend, the Company believes operating costs on a boe basis will decrease in the second half of the 2006 as a number of higher volume wells are tied-in.



------------------------------------------------------------------------
Three months ended Six months ended
------------------------------------------------------------------------
June 30, June 30, % June 30, June 30, %
2006 2005 Change 2006 2005 Change
------------------------------------------------------------------------
Operating Costs
(000's) $ 2,415 $ 555 335 % $ 4,530 $ 721 528 %
Operating Costs
per boe $ 8.76 $ 7.55 16 % $ 7.97 $ 7.26 10 %
------------------------------------------------------------------------
------------------------------------------------------------------------


TRANSPORTATION EXPENSES

Transportation expenses for the second quarter ended June 30, 2006 totaled $434,342 or $1.58 per boe. When compared with transportation charges from the first quarter of 2006 of $424,026, or $1.46 per boe, transportation costs have increased by 8.2% as the result of one time charges for previous period pipeline fees relating to gas production from Bear Ridge's Gunnell property in northeast British Columbia.

When compared to 2005, increased transportation fees on a boe basis are the result of higher transportation costs per unit on natural gas combined with the Company producing more gas compared to oil.

OPERATING NETBACK

During the second quarter of 2006, the Company's netback totaled $31.66 which represents an increase of $3.23 or 11.4% when compared with netbacks of $28.43 per boe from the first quarter of 2006. This increase is a result of additional revenues due to hedging gains in the quarter and lower royalties on a boe basis.

When compared to the prior year, netbacks for the three and six month periods ended June 30, 2006, are lower primarily due to lower natural gas prices in 2006 and a royalty holiday that expired in 2005 which reduced royalties significantly during that period.



Three months ended Six months ended
------------------------------------------------------------------------
June 30, June 30, June 30, June 30,
Operating Netback ($/boe) 2006 2005 2006 2005
------------------------------------------------------------------------
Sales price $ 50.10 $ 56.81 $ 50.52 $ 54.02
Royalties (8.10) (3.91) (11.19) (6.21)
Operating expense (8.76) (7.55) (7.97) (7.26)
Transportation expense (1.58) (0.56) (1.44) (0.57)
------------------------------------------------------------------------
Operating Netback $ 31.66 $ 44.79 $ 29.92 $ 39.98
------------------------------------------------------------------------
------------------------------------------------------------------------


GENERAL AND ADMINISTRATIVE EXPENSES ("G&A")

G&A expenses for the second quarter of 2006 totaled $911,765 or $3.31 per boe compared to $334,225 or $4.54 per boe for the same quarter of 2005. Year to date G&A expense has totaled $1,508,625 or $2.53 per boe, which although higher on an overall dollar basis compared to the same period of 2005, represents a significant reduction on a boe basis from $6.08 per boe.

When compared with the first quarter of 2006, G&A expenses increased from $596,860 to $911,765, an increase of 53%, largely the result of additional employees added during the quarter, higher compensation costs, and public Company costs related to annual filings. As production increases throughout the year, the Company expects G&A costs per boe to decline due to better economies of scale.

Capitalized G&A amounted to $719,027, or 39.2% of total gross G&A costs incurred during the second quarter of 2006. The capitalization rate is in line with G&A costs capitalized in the first quarter of 2006 when the capitalization rate equaled 37.2%. The Company maintains the policy of capitalizing only those costs directly attributable to exploration activities and does not include an allocation of administrative overhead.



------------------------------------------------------------------------
Three months ended Six months ended
------------------------------------------------------------------------
G & A Expense June 30, June 30, % June 30, June 30, %
(000's) 2006 2005 Change 2006 2005 Change
------------------------------------------------------------------------
G&A expense
(gross) $ 1,833 $ 334 449 % $ 2,901 $ 604 380 %
G&A capitalized (719) - - (1,117) - -
Overhead
recoveries (202) - - (275) - -
------------------------------------------------------------------------
G&A expense (net) $ 912 $ 334 173 % $ 1,509 $ 604 150 %
------------------------------------------------------------------------
------------------------------------------------------------------------
G&A expense $ per
boe $ 3.31 $ 4.54 (27)% $ 2.53 $ 6.08 (58)%
------------------------------------------------------------------------
------------------------------------------------------------------------


STOCK BASED COMPENSATION

Stock based compensation measures the implicit cost of compensating key personnel through the issuance of stock options and special performance units as further described in the audited financial statements.

For the three month period ended June 30, 2006, the Company incurred stock based compensation expense of $604,000 or $2.19 per boe compared to $298,241 or $4.06 per boe for the three month period ended June 30, 2005. For the six month period ended June 30, 2006, the Company incurred stock based compensation expenses of $1,089,000 or $1.83 per boe compared to $486,239 or $4.89 per boe for the six month period ended June 30, 2005. Increased stock based compensation expense on a total dollar basis is a result of an increased number of stock options issued for the balance of 2006 compared to 2005.

INTEREST EXPENSE

Interest expense for the six months ended June 30, 2006 totaled $1,307,152. Draws on the Company's credit facilities to fund the cash component of the Veteran acquisition and to execute Bear Ridge's capital budget resulted in higher interest charges when compared to the same period of 2005 when Bear Ridge was a much smaller Company and interest for the same period totaled $32,880.

Interest for the three months ended June 30, 2006 totaled $810,509, representing an increase of 63% from interest charges of $496,643 from the first quarter of 2006. The increase was a result of the Company carrying a larger amount of bank debt and higher interest rates in the second quarter compared to the first.

DEPLETION, DEPRECIATION AND ACCRETION

Depletion and depreciation totaled $8.1 million for the three months ended June 30, 2006 or $29.39 per boe. The depletion rate increased from $22.79 in the previous quarter due to increased capital costs and conservative reserve estimates for wells in the early stage of their productive lives.

The depletion rate is impacted by the costs to acquire, explore and develop reserves of crude oil and natural gas, known as finding and development costs. In the early stages of exploration, capital costs may be recognized before proven reserves are fully booked leading to higher initial depletion rates. In addition higher depletion rates also result as new production often receives lower reserves assignments under NI 51-101 due to the naturally unpredictable nature of newer production.

Accretion expense decreased in the second quarter of 2006 to $47,000 compared to $56,000 in the previous quarter due to asset dispositions in the quarter. Accretion expense in 2006 is higher than 2005 due to a much smaller asset base at that point in time. The Company expects its accretion expense to continue to increase on a quarterly basis as more wells are drilled and the asset retirement obligation continues to grow.



Three months ended Six months ended
------------------------------------------------------------------------
June 30, June 30, June 30, June 30,
2006 2005 2006 2005
------------------------------------------------------------------------
Total costs (000's)
Depletion and depreciation $ 8,105 $ 1,591 $ 14,724 $ 2,013
Accretion 47 6 103 10
------------------------------------------------------------------------
Combined $ 8,152 $ 1,597 $ 14,827 $ 2,023
------------------------------------------------------------------------

Cost per boe
Depletion and depreciation $ 29.39 $ 21.65 $ 24.73 $ 20.27
Accretion $ 0.17 $ 0.08 $ 0.17 $ 0.10
------------------------------------------------------------------------
------------------------------------------------------------------------


TAXES

As at June 30, 2006, Bear Ridge had available approximately $185 million in tax pools to shelter taxable income earned. During 2005, Bear Ridge recognized a future income tax asset of approximately $9.5 million and had additional unrecognized assets related to additional tax pools of approximately $11.5 million. Upon acquisition of Veteran, Bear Ridge revisited its unrecognized future income tax asset and with the increased revenues from the acquired properties Bear Ridge recognized the full value of previously unrecognized tax pools against the tax liability acquired as part of the Veteran acquisition. The future tax liability acquired from Veteran, totaling $12 million, when combined with Bear Ridge's recognized tax asset from 2005 and the tax effect of flow-through share renouncements made during the first quarter of 2006 resulted in a future tax liability on Bear Ridge's balance sheet at the end of the first quarter of 2006.

During the second quarter of 2006, Bear Ridge recorded a reduction of its overall future income tax liability as a result of a decrease in income tax rates applied to the difference between the carrying value and income tax value of the Company's assets in future years. The recognized recovery during the quarter totaled $2,277,000.

For 2006, Bear Ridge does not expect to incur cash income tax expense on cash flows generated from operations and with recent federal budget proposals does not expect to incur capital taxes.

As the result of various flow-through share offerings completed by Bear Ridge during 2005, the Company renounced to subscribers $17.2 million in qualifying expenditures related to flow through arrangements during February 2006. As at March 31, 2006, Bear Ridge had incurred all eligible expenditures under the flow through agreements.

CASH FLOW AND NET INCOME

Cash flow from operations totaled $7.0 million for the three months ended June 30, 2006 or $0.15 basic cash flow per share compared to cash flow of $7.0 million or $0.16 basic cash flow per share from the first quarter of 2006. Cash flow was positively impacted in the second quarter by hedging gains of approximately $1.5 million and royalty recoveries of approximately $0.5 million. These items helped offset lower production due to tie-in delays, access to service rigs and approximately 350 boe per day of shut-in production in the quarter. On a per share basis, cash flow decreased as a result of new shares issued by way of a flow through financing completed in May.

Net loss for the six months ended June 30, 2006 totaled $0.5 million, which is a reduction of $1.5 million from the $1.0million in net income generated in the previous year. Increased revenues during 2006 have been offset by higher costs associated with those revenues combined with higher depletion and stock based compensation charges. The Company recorded net income of $0.5million for the three months ended June 30, 2006. The income represents a $1.6 million improvement in earnings from the net loss of $1.1 million recorded in the first quarter of 2006. Second quarter income was the result of lower production volumes combined with higher depletion and stock based compensation charges being offset by a recovery in future income taxes.



Three months ended Six months ended
------------------------------------------------------------------------
June 30, June 30, June 30, June 30,
2006 2005 2006 2005
------------------------------------------------------------------------
Cash flow from operations
per share
Basic $ 0.15 $ 0.12 $ 0.30 $ 0.15
Diluted $ 0.14 $ 0.11 $ 0.29 $ 0.14
Net income (loss) - per
share
Basic and diluted $ 0.01 $ 0.05 $ (0.01)$ 0.05
------------------------------------------------------------------------
------------------------------------------------------------------------


CAPITAL EXPENDITURES

Bear Ridge executes a growth strategy primarily through exploration and development activities complemented with strategic corporate and property acquisitions. Net capital expenditures in the second quarter totaled $17.3 million compared to $19.9 million in the same period of the prior year. For the first six months of the year net capital expenditures totaled $54.0 million compared to $24.9 million in the first six months of 2005.

The second quarter of 2006 continued to be an active quarter for Bear Ridge with the drilling of 23 (11.6 net) wells resulting in 17 (7.75 net) gas wells and 3 (1.5 net) oil wells and 3 (2.25 net) abandoned wells, for a 87 percent success rate.

Capital expenditures during the quarter focused on a nine well shallow gas program in the Gordondale area, three Wabamun wells at Eaglesham and additional drilling in Gunnell, Earring and Nelson. During the quarter the Company constructed a $2.5 million oil battery at Earring to bring recently drilled wells on production and allow the Company to tie-in previously shut-in gas in the area to Bear Ridge infrastructure. Bear Ridge incurred additional facilities expenditures to add necessary compression in the Earring area and new pipeline infrastructure connecting recent discoveries.

Bear Ridge continued to be active at crown land sales acquiring key pieces of land in the Company's project at Tupper and other parcels in our current core areas in the Peace River Arch.

During the second quarter Bear Ridge disposed of certain non core properties for total sale proceeds of $ 6.5 million and was reimbursed an additional $3.3 million for seismic and land costs as part of a joint venture agreement.

Capital expenditures for the three and six month periods ended June 30, 2006 and 2005 are outlined as follows:



Three months ended Six months ended
------------------------------------------------------------------------
June 30, June 30, June 30, June 30,
Capital Expenditures (000's) 2006 2005 2006 2005
------------------------------------------------------------------------
Land $ 3,066 $ 2,505 $ 13,969 $ 3,088
Geological & geophysical 1,004 471 4,107 559
Drilling & completions 13,261 5,640 31,307 9,357
Equipment & facilities 6,641 904 11,199 905
Office and furniture 94 6 133 6
Asset retirement obligation 15 87 95 485
Property acq/(disp) (6,720) 2,000 (6,720) 23,636
Corporate acquisition - 8,344 109,594 8,344
------------------------------------------------------------------------
Total Expenditures $ 17,361 $ 19,957 $ 163,684 $ 46,380
------------------------------------------------------------------------
------------------------------------------------------------------------


The Company records the fair value of future obligations associated with the retirement of long-lived tangible assets, such as oil and gas wells, well sites and facilities. Accounting for the recognition of this obligation results in a corresponding increase to the carrying values of these assets. This amount has been classified above as the Company's Asset Retirement obligation.

EQUITY

During the first quarter of 2006 Bear Ridge issued 413,638 shares as the result of the exercise of stock options and special performance units and another 62,100 shares as part of a flow through share private placement. Proceeds generated from these issuances totaled $517,717.

On May 12, 2006 the Company closed a bought deal financing whereby the Company issued 3,150,000 common shares, on a flow through basis, at a price of $7.35 per share for total proceeds of $23,152,500.

LIQUIDITY AND CAPITAL RESOURCES

At June 30, 2006 Bear Ridge had drawn $61.5 million on its credit facility and had a working capital deficiency of $19.0 million for total net debt of $80.5 million. The Company has a revolving demand loan facility to a maximum of $70.0 million. Subsequent to the end of the quarter, the lender proposed an agreement to expand the Company's credit facilities to $80.0 million. The agreement is subject to final approval by the lender which is expected to take place prior to August 25, 2006.

During the quarter, Bear Ridge realized net proceeds of approximately $22.0 million from a flow through financing and closed the sale of approximately 130 boe per day of production for $6.5 million. Subsequent to June 30, 2006, Bear Ridge closed the sale of an additional 60 boe per day of production for $2.8 million. Additional proceeds were received during the quarter through the reimbursement of $3.3 million of seismic and land costs as part of a joint venture agreement. These activities helped reduce the Company's net debt balance from $92.1 million in the first quarter to $80.5 million at June 30, 2006. Bear Ridge has not yet brought in a partner on our Tupper prospect at this point in time resulting in less of a reduction to the net debt balance than anticipated at the end of the first quarter. By accelerating certain capital expenditures into the first and second quarters, Bear Ridge has run a higher debt level. Cash flow over the last half of 2006 is forecast to exceed spending and thereby further reduce the Company's debt position by year end.

On an ongoing basis, the Company will typically utilize three sources of funding to finance its capital expenditure program; internally generated cash flow from operations, debt where deemed appropriate and new equity issues if available on favorable terms. When financing corporate acquisitions the Company may also assume certain future liabilities. In addition, the Company may adjust its capital expenditure program depending on the commodity price outlook, and further opportunities that are identified.

CRITICAL ACCOUNTING ESTIMATES

The significant accounting policies used by Bear Ridge are disclosed in Note 2 of the audited consolidated financial statements as at December 31, 2005. Certain accounting policies require management to make appropriate decisions in determining estimates and making assumptions that affect the reported amounts of assets, liabilities, revenues and expenses. Management reviews its estimates regularly. The emergence of new information and changed circumstance may result in actual results or changes to estimated amounts that may differ materially from current estimates. The following discussion helps assess the accounting policies and practices of the Company as they relate to estimates and the likelihood of material differences occurring.

Proved Oil and Gas Reserves

Under National Instrument 51-101, "Proved" reserves are defined as those reserves that can be estimated with a high degree of certainty to be recoverable. In accordance with this definition, the level of certainty targeted by the reporting company should result in at least a 90 percent probability that the quantities actually recovered will equal or exceed the estimated Proved reserves. In the case of "Probable" reserves it must be equally likely that the actual remaining quantities recovered will be greater or less than the sum of the estimated Proved plus Probable reserves. With respect to the consideration of certainty, in order to report reserves as Proved plus Probable, the reporting company must believe that there is at least a 50 percent probability that the quantities actually recovered will equal or exceed the sum of the estimated Proved plus Probable reserves.

Reserve estimates are made using all available geological and reservoir data, as well as historical production information. Estimates are reviewed internally on a quarterly basis, and at least annually by external engineers, and are revised as appropriate. Revisions can occur as a result of various factors including: actual reservoir production, changes in commodity price forecasts and relevant operating costs or changes in the Company's plans. Changes in proved oil and gas reserves will impact financial results as reserves are used in the depletion calculation and are used to assess asset valuation and impairment. Reserve changes also affect other industry financial benchmarks such as finding and development costs; recycle ratios and net asset value calculations.

Depletion

The Company applies the full cost method of accounting for exploration and development activities. Under this method, all costs associated with the acquisition of, exploration for, and development of petroleum and natural gas reserves are capitalized whether or not the activities are successful. The aggregate of net capitalized costs and estimated future development costs, less undeveloped land, is depleted using the unit-of-production method based on production volumes in relation to estimated proven reserves. An increase in estimated proved oil and gas reserves would result in a corresponding reduction in depletion expense. A decrease in estimated future development costs would also result in a corresponding reduction in depletion expense.

Unproved Properties

Certain costs related to the acquisition and evaluation of unproved properties may be excluded from costs subject to depletion. These properties are reviewed quarterly to determine whether any impairment in value has occurred. When proved reserves are assigned or an unproved property is considered to be impaired, the cost of the unproved property or the amount of the impairment will be added to the capitalized costs subject to depletion.

Ceiling Test

The Ceiling test is a two part cost recovery test to assess the valuation of the Company's petroleum and natural gas properties. The first part measures whether impairment has occurred based on undiscounted future cash flows using estimated future prices, costs and proved reserves. When the first part indicates impairment exists, the second part of the test measures the amount of impairment based on discounted future cash flows from proved and probable reserves. The Company reviews the related estimates when it performs its ceiling test on a quarterly basis. The impact of changes in the estimates of future prices and costs applied and the quantity of proved and probable reserves on the financial statements could be material.

Asset Retirement Obligations

In recognizing its asset retirement obligation, the Company records a liability equal to the discounted fair value of the estimated costs to abandon petroleum and natural gas wells, dismantle and remove tangible equipment and return land to its original condition. Arriving at a discounted fair value requires the Company to make estimates relating to the projected timing of incurring costs, inflation rates and risk adjusted discount rates. These estimates will vary over time as new information becomes available and will impact both the liability recorded as well as the accretion expense. These estimates are reviewed by the Company on a quarterly basis to ensure circumstances supporting the estimates are still considered reasonable.

Income Taxes

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

Stock-based Compensation

The fair value of stock options granted is calculated using the Black-Scholes option pricing model and is recorded over the vesting period of the related options. The calculation involves estimates of the expected volatility in the trading value of the Company's shares, the price of the underlying shares, the expected life of the option, expected dividends and the risk-free rate of interest. All of these estimates are subjective and are reviewed by management on a quarterly basis.



QUARTERLY INFORMATION

2006
------------------------------------------------------------------------
Financial
($ thousands except per share data) Q2 Q1
------------------------------------------------------------------------
Revenues 13,806 14,587
Royalties 2,231 3,983
Operating expenses 2,415 2,115
Transportation expenses 434 424

Cash flow (000's) 7,003 6,972
Per share - basic 0.15 0.16
Per share - diluted 0.14 0.15

Net Income (loss) 524 (1,078)
Per share - basic 0.01 (0.02)
Per share - diluted 0.01 (0.02)

Capital expenditures, net 17,311 36,729
Acquisition expenditures - 109,594
------------------------------------------------------------------------
Total expenditures 17,311 146,323
------------------------------------------------------------------------
------------------------------------------------------------------------

2006
------------------------------------------------------------------------
Operations Q2 Q1
------------------------------------------------------------------------
Production volumes
Natural gas (mcf/day) 14,713 17,262
Oil and NGL's (bbl/day) 576 678
------------------------------------------------------------------------
Total boe/day 3,028 3,555
------------------------------------------------------------------------
------------------------------------------------------------------------
Average Selling Price
Natural gas ($ per mcf) $ 7.38 $ 7.96
Oil and NGL ($ per bbl) 74.87 64.59
------------------------------------------------------------------------
Combined ($ per boe) $ 50.10 $ 50.89
Royalties ($ per boe) 8.10 13.72
Operating expense ($ per boe) 8.76 7.28
Transportation ($ per boe) 1.58 1.46
------------------------------------------------------------------------
Netback ($ per boe) $ 31.66 $ 28.43
------------------------------------------------------------------------
------------------------------------------------------------------------


2005
------------------------------------------------------------------------
Financial
($ thousands except per share data) Q4 Q3 Q2 Q1
------------------------------------------------------------------------
Revenues 4,679 4,585 4,176 1,191
Royalties 1,146 921 287 330
Operating expenses 718 607 595 166
Transportation expenses 80 64 41 16

Cash flow (000's) 2,389 2,741 2,927 406
Per share - basic 0.08 0.10 0.12 0.02
Per share - diluted 0.08 0.09 0.11 0.02

Net Income (loss) 629 9,259 1,255 (208)
Per share - basic 0.02 0.33 0.05 (0.01)
Per share - diluted 0.02 0.30 0.05 (0.01)

Capital expenditures, net 14,602 11,162 9,526 2,045
Acquisition expenditures - - 10,344 24,466
------------------------------------------------------------------------
Total expenditures 14,602 11,162 19,870 26,511
------------------------------------------------------------------------
------------------------------------------------------------------------

2005
------------------------------------------------------------------------
Operations Q4 Q3 Q2 Q1
------------------------------------------------------------------------
Production volumes
Natural gas (mcf/day) 2,858 2,795 2,365 1,381
Oil and NGL's (bbl/day) 223 318 413 57
------------------------------------------------------------------------
Total boe/day 700 784 808 287
------------------------------------------------------------------------
------------------------------------------------------------------------
Average Selling Price
Natural gas ($ per mcf) $ 12.41 $ 9.63 $ 8.03 $ 7.26
Oil and NGL ($ per bbl) 68.80 72.83 64.25 58.76
------------------------------------------------------------------------
Combined ($ per boe) $ 72.70 $ 63.58 $ 56.81 $ 46.09
Royalties ($ per boe) 17.82 12.78 3.91 12.77
Operating expense ($ per boe) 9.93 7.53 7.55 6.45
Transportation ($ per boe) 1.23 0.89 0.56 0.63
------------------------------------------------------------------------
Netback ($ per boe) $ 43.75 $ 42.38 $ 44.79 $ 26.24
------------------------------------------------------------------------
------------------------------------------------------------------------


CONSOLIDATED BALANCE SHEETS

(Unaudited)

June 30, December 31,
2006 2005
------------------------------------------------------------------------
ASSETS
Current
Accounts receivable $ 15,219,067 $ 7,372,473
Investment (note 3) 571,250 -
Deposits and prepaid expenses 307,860 626,376
------------------------------------------------------------------------
16,098,177 7,998,849
Future income tax - 9,457,000
Goodwill (note 2) 31,644,214 -
Property and equipment (note 4) 215,142,046 66,182,124
------------------------------------------------------------------------
$ 262,884,438 $ 83,637,973
------------------------------------------------------------------------
------------------------------------------------------------------------

LIABILITIES AND SHAREHOLDERS' EQUITY
Current
Revolving production loan (note 5) $ 61,549,548 $ 5,247,541
Accounts payable and accrued liabilities 35,057,687 14,642,478
------------------------------------------------------------------------
96,607,235 19,890,019
Asset retirement obligations (note 6) 2,737,416 519,416
Future income tax 6,591,332 -
------------------------------------------------------------------------
105,935,983 20,409,435
Shareholders' equity
Share capital (note 7(a)) 146,102,581 52,536,431
Warrants 711,354 711,354
Contributed surplus (note 7(b)) 1,702,066 994,066
Retained earnings 8,432,454 8,986,687
------------------------------------------------------------------------
156,948,455 63,228,538
------------------------------------------------------------------------
$ 262,884,438 $ 83,637,973
------------------------------------------------------------------------
------------------------------------------------------------------------
See accompanying notes


On behalf of the Board:

"David Ambedian" "Russell J. Tripp"
David Ambedian Russell J. Tripp
Director Director


CONSOLIDATED STATEMENTS OF INCOME (LOSS) AND RETAINED EARNINGS (DEFICIT)
(Unaudited)

Three Months Six Months
Ended Ended
June 30, June 30,
------------------------------------------------------------------------
2006 2005 2006 2005
------------------------------------------------------------------------
REVENUE
Petroleum and
natural gas sales $13,805,640 $ 4,175,526 $28,392,618 $ 5,366,053
Royalties, net of
Alberta Royalty Tax
Credit (2,230,947) (287,280) (6,213,962) (617,249)
------------------------------------------------------------------------
11,574,693 3,888,246 22,178,656 4,748,804
------------------------------------------------------------------------
EXPENSES
Operating 2,415,156 554,610 4,529,716 721,136
Transportation 434,342 40,812 858,368 56,973
General and
administrative 911,765 333,487 1,508,625 604,079
Stock based
compensation 604,000 298,241 1,089,000 486,239
Interest on
production loan 810,509 32,048 1,307,152 32,880
Depletion,
depreciation
and accretion 8,152,271 1,597,313 14,827,028 2,023,374
------------------------------------------------------------------------
13,328,043 2,856,511 24,119,889 3,924,681
------------------------------------------------------------------------

Income (loss) before
income taxes (1,753,350) 1,031,735 (1,941,233) 824,123

Income taxes
Future income tax
(recovery) (2,277,000) (223,600) (1,387,000) (223,600)
------------------------------------------------------------------------

Net income (loss) 523,650 1,255,335 (554,233) 1,047,723

Retained earnings
(deficit), beginning
of period 7,908,804 (2,156,723) 8,986,687 (1,949,111)
------------------------------------------------------------------------
Retained earnings
(deficit), end of
period $ 8,432,454 $ (901,388) $ 8,432,454 $ (901,388)
------------------------------------------------------------------------
------------------------------------------------------------------------

Net income (loss) per
share (note 7(d))
Basic $ 0.01 $ 0.05 $ (0.01) $ 0.05
Diluted $ 0.01 $ 0.05 $ (0.01) $ 0.04
------------------------------------------------------------------------

See accompanying notes


CONSOLIDATED STATEMENTS OF CASH FLOWS
(Unaudited)

Three Months Ended Six Months Ended
June 30, June 30,
------------------------------------------------------------------------
2006 2005 2006 2005
------------------------------------------------------------------------
OPERATING ACTIVITIES
Net income (loss) $ 523,650 $ 1,255,335 $ (554,233) $ 1,047,723
Items not involving
cash:
Depletion,
depreciation
and accretion 8,152,271 1,597,313 14,827,028 2,023,374
Future income tax (2,277,000) (223,600) (1,387,000) (223,600)
Stock based
compensation 604,000 298,241 1,089,000 486,239
------------------------------------------------------------------------
Cash flow from
operations before
changes in non-cash
working capital 7,002,921 2,927,289 13,974,795 3,333,736
Change in non-cash
working capital
(note 9) (10,326,271) 3,096,372 (7,626,756) 243,746
------------------------------------------------------------------------
Cash provided by
(used in) operating
activities (3,323,350) 6,023,661 6,348,039 3,577,482
------------------------------------------------------------------------
FINANCING ACTIVITIES
Common shares issued,
net of issue costs 21,902,776 11,888,375 22,326,432 19,191,421
Preferred shares
issued (repurchased) - (24,999) - 6,175,001
Advances on
(repayment of)
revolving
production loan (1,329,943) - 51,878,734 (2,000,000)
------------------------------------------------------------------------
Cash provided by
financing activities 20,572,833 11,863,376 74,205,166 23,366,422
------------------------------------------------------------------------
INVESTING ACTIVITIES
Acquisition of
properties - (2,000,000) - (3,051,889)
Expenditures on
property and
equipment (24,066,005) (9,526,187) (61,286,198) (13,914,645)
Property and
equipment
dispositions 6,719,996 - 6,719,996 -
Acquisition of
Veteran Resources
Inc. (note 2) - - (35,752,568) -
Acquisition
of partnership - (8,344,050) - (8,344,050)
Change in non-cash
working capital
(note 9) 96,526 (443,181) 9,765,565 1,465,684
------------------------------------------------------------------------
Cash used in
investing
activities (16,734,783) (20,313,418) (80,553,205) (23,844,900)
------------------------------------------------------------------------
Change in cash - (2,426,381) - 3,099,004
Cash and cash
equivalents,
beginning of period - 6,005,787 - 480,402
------------------------------------------------------------------------
Cash and cash
equivalents,
end of period $ - $ 3,579,406 $ - $ 3,579,406
------------------------------------------------------------------------
------------------------------------------------------------------------

See accompanying notes


Notes to the Consolidated Financial Statements
As at and for the period ended June 30, 2006
(Unaudited)


1. BASIS OF PRESENTATION

The interim consolidated financial statements of Bear Ridge Resources Ltd. ("Bear Ridge" or "the Company") have been prepared in accordance with Canadian generally accepted accounting principles and are consistent with the presentation and disclosure in the audited consolidated financial statements and notes thereto for the year ended December 31, 2005. The interim financial statements contain disclosures which are incremental to Bear Ridge's annual financial statements. Certain disclosures, which are normally required to be included in the notes to the financial statements, have been condensed or omitted and as such the interim financial statements do not conform in all respects to the note disclosure requirements of Canadian generally accepted accounting principles for annual financial statements. The interim financial statements should be read in conjunction with Bear Ridge's audited consolidated financial statements and notes thereto for the year ended December 31, 2005.

2. ACQUISITION OF VETERAN RESOURCES INC.

Pursuant to an Arrangement Agreement ("the Agreement") dated November 4, 2005 the Company agreed to complete a business combination with Veteran Resources Inc. ("Veteran"), a public oil and gas company, by way of a Plan of Arrangement. Under the terms of the Agreement, Bear Ridge agreed to acquire all of the issued and outstanding shares of Veteran for consideration consisting of $34,651,144 and 17,022,333 Bear Ridge common shares valued at a five day, pre and post announcement, weighted average price of $4.48 per share. The Agreement received regulatory and Veteran shareholder approval on January 17, 2006 and closed January 19, 2006. The combination is an acquisition of Veteran by Bear Ridge and consequently Veteran's results of operations have been included with Bear Ridge's operations from the date of close, January 19, 2006.

The estimated fair value of the assets and liabilities acquired have been allocated as follows:



Accounts receivable $ 4,359,248
Deposits and prepaid expenses 160,988
Property and equipment 109,594,000
Goodwill 31,644,214
Accounts payable (15,268,559)
Bank debt (4,423,272)
Asset retirement obligations (2,020,000)
Future income taxes (12,034,000)
------------------------------------------------------------------------
Total $ 112,012,619
------------------------------------------------------------------------
------------------------------------------------------------------------


On closing, Bear Ridge assumed a future income tax liability of approximately $23.5 million representing the difference between the book value and the tax value of the assets acquired. The liability was offset by previously unrecognized Bear Ridge tax deductions and accordingly the tax liability was reduced to $12.0 million on acquisition.



Consideration paid:
------------------------------------------------------------------------
17,022,333 common shares issued $ 76,260,051
Cash 34,651,144
Bear Ridge transaction costs 1,101,424
------------------------------------------------------------------------
Total consideration $ 112,012,619
------------------------------------------------------------------------
------------------------------------------------------------------------


3. INVESTMENT

Effective March 23, 2006 Bear Ridge entered into a joint venture agreement with a private oil and gas company. As part of the agreement, the private company issued Bear Ridge 457,000 shares, valued at the founder's price of $1.25 per share, in consideration for land and seismic costs totaling $571,250 previously incurred by Bear Ridge. The investment is carried at the lower of cost and market value.



4. PROPERTY AND EQUIPMENT

Accumulated
depletion and Net book
Cost depreciation value
------------------------------------------------------------------------
Petroleum and natural gas
properties 254,123,838 39,475,309 214,648,529
Office equipment 1,257,538 764,021 493,517
------------------------------------------------------------------------
255,381,376 40,239,330 215,142,046
------------------------------------------------------------------------
------------------------------------------------------------------------


During the period ended June 30, 2006, the Company capitalized general and administrative expenses in the amount of $1.1 million (2005 - $0.6 million) related to exploration and development expenditures.

As at June 30, 2006, costs totaling $34.2 million related to unproven properties have been excluded from assets subject to depletion, while estimated future development costs of $12.5 million, related to proven reserves, were included in the calculation of depletion expense.

5. REVOLVING PRODUCTION LOAN

Effective January 19, 2006, in connection with closing the Veteran acquisition, Bear Ridge expanded the maximum amount available under its revolving production loan facility to $60.0 million to provide funds for the payment of the $35 million cash portion of the Veteran acquisition and the assumption of $6.3 million of Veteran bank debt. The maximum facility available was further expanded to $70.0 million effective February 17, 2006.

As at June 30, 2006, the Company was in breach of its covenant to maintain a working capital ratio of not less than 1:1. The lender agreed to waive compliance with this covenant as at June 30, 2006. Subsequent to the end of the quarter, the lender proposed an agreement to expand the Company's credit facilities to $80.0 million. The agreement is subject to final approval by the lender which is expected to take place prior to August 25, 2006.

6. ASSET RETIREMENT OBLIGATIONS

The following table presents the reconciliation of the beginning and ending carrying amount of the Company's asset retirement obligations for the period ended June 30, 2006.



Amount
------------------------------------------------------------------------
Balance January 1, 2006 $ 519,416
Liabilities incurred 265,000
Liabilities acquired 2,020,000
Liabilities settled on disposition (170,000)
Accretion expense 103,000
------------------------------------------------------------------------
Balance June 30, 2006 $ 2,737,416
------------------------------------------------------------------------
------------------------------------------------------------------------


Total estimated future asset retirement costs of $6.4 million have been discounted using an average credit adjusted risk free rate of 7 percent. An inflation factor of 2 percent has been applied to the estimated asset retirement costs. These obligations are to be settled based on the economic lives of the underlying assets, which currently extend up to 19 years into the future and will be funded from general corporate resources at the time of abandonment.

7. SHARE CAPITAL

a) Issued and outstanding shares:



------------------------------------------------------------------------
Common Shares Number $
------------------------------------------------------------------------
Balance, January 1, 2006 29,482,235 52,536,431
Issued on acquisition of Veteran (note 2) 17,022,333 76,260,051
Issued for cash (i) 3,212,100 23,429,466
Issued on exercise of stock options and special
performance units 413,638 621,751
Future tax effect of flow through shares (ii) - (5,823,000)
Share issuance costs, net of future tax effect
of $421,667 - (922,118)
------------------------------------------------------------------------
Balance, June 30, 2006 50,130,306 146,102,581
------------------------------------------------------------------------
------------------------------------------------------------------------

i. On January 19, 2006, the Company closed a private placement to newly
appointed members of senior management of 62,100 flow through common
shares at a price of $4.46 per common share for gross proceeds of
$276,966. These expenditures were incurred prior to June 30, 2006.

On May 12, 2006 the Company closed a private placement of 3,150,000
flow-through common shares at $7.35 per share for gross proceeds of
$23,152,500 (total net proceeds of $21,994,875). Pursuant to this
private placement, Bear Ridge is committed to incur these expenditures
by December 31, 2007. As at June 30, 2006, approximately $14.6 million
of this commitment remains.

ii. Under flow through agreements entered into in during 2005, the
Company committed to incur $17,250,500 in qualifying expenditures by
December 31, 2006. The renouncements to shareholders were made February
26, 2006 with an effective date of December 31, 2005. The future income
tax effect of this issuance was recorded on the date of renouncement.
As at June 30, 2006, the Company had incurred the entire amount of
qualifying expenditures.


b) Contributed surplus

A summary of the change in the Company's contributed surplus balance for the six months ended June 30, 2006 is as follows:



Amount
------------------------------------------------------------------------
Balance, January 1, 2006 $ 994,066
Stock based compensation 1,089,000
Options and special performance units exercised (381,000)
------------------------------------------------------------------------
Balance, June 30, 2006 $ 1,702,066
------------------------------------------------------------------------
------------------------------------------------------------------------


c) Stock based compensation

i. Stock options:

A summary of the options outstanding as at June 30, 2006 and the changes for the six month period then ended is presented below:



Weighted Average
Number Exercise Price
------------------------------------------------------------------------
Balance outstanding, January 1, 2006 1,231,673 $ 3.82
Granted 1,940,000 4.93
Exercised (65,004) 3.65
------------------------------------------------------------------------
Balance outstanding, June 30, 2006 3,106,669 $ 4.52
------------------------------------------------------------------------
------------------------------------------------------------------------


As at June 30, 2006 165,556 options are exercisable at an average exercise price of $3.48 per option.

The following table summarizes information about stock options outstanding at June 30, 2006:



Weighted Average
Number Remaining Weighted Average
Grant Price Outstanding Contractual Life Exercise Price
------------------------------------------------------------------------
$ 3.25 to $3.65 496,669 3.70 $ 3.48
$ 4.00 to $5.00 2,610,000 4.41 4.72
------------------------------------------------------------------------
3,106,669 4.30 $ 4.52
------------------------------------------------------------------------
------------------------------------------------------------------------


The weighted average fair market value of options granted and the relevant assumptions used in their calculation for the year ended December 31, 2005 and the six months ended June 30, 2006 are as follows:



2006 2005
------------------------------------------------------------------------
Risk-free interest rate (%) 3.0 3.0
Volatility (%) 40.0 36.0
Expected Life (years) 3.5 3.5
Weighted average fair value per option $ 1.63 $ 1.15
------------------------------------------------------------------------


ii. Special Performance Units

A summary of the SPU's outstanding as at June 30, 2006 and changes
for the six month period then ended is presented below:

Weighted Average
Number Exercise Price ($)
------------------------------------------------------------------------
Balance outstanding, January 1, 2006 955,276 $ 0.01
Exercised (448,426) 0.01
------------------------------------------------------------------------
Balance outstanding, June 30, 2006 506,850 $ 0.01
------------------------------------------------------------------------
------------------------------------------------------------------------


On January 18, 2006, 448,426 SPU's, representing the first third of the originally granted SPU's, vested and were exercised resulting in the issuance of 348,634 common shares.

d) Per share amounts

The following table summarizes the weighted average shares outstanding for three and six month periods ended June 30, 2006 and 2005 as follows:



Weighted average - common Three months ended Six months ended
shares outstanding June 30, June 30,
------------------------------------------------------------------------
2006 2005 2006 2005
------------------------------------------------------------------------
Basic 48,676,460 24,912,827 45,967,753 22,064,327
Add dilutive effect of:
Warrants 2,005,471 1,341,382 2,048,228 1,553,321
SPU's 389,450 361,459 389,491 632,089
Stock Options 223,182 3,716 282,582 4,302
------------------------------------------------------------------------
Diluted 51,294,563 26,619,384 48,688,055 24,254,039
------------------------------------------------------------------------
------------------------------------------------------------------------


8. FINANCIAL INSTRUMENTS

Commodity price risk management

The Company uses various types of financial and physical sales contracts to manage risk related to fluctuating commodity prices. At June 30, 2006, the Company had the following fixed price financial and physical costless collar arrangements:




------------------------------------------------------------------------
Hedged
Term Type Volumes Floor Ceiling
------------------------------------------------------------------------
Oil
January 2006 - December 2006 Financial 200 bbl/d $ 55.00US $ 73.00US
Natural Gas
April 1 - October 31, 2006 Physical 2,000GJ/d $ 9.00CDN $12.85CDN
April 1 - October 31, 2006 Physical 1,000GJ/d $ 9.00CDN $13.05CDN
May 1 to October 31, 2006 Physical 3,000 GJ/d $ 6.50CDN $ 7.55CDN
May 1 to October 31, 2006(1) Physical 2,000 GJ/d $ 6.50CDN -
May 1 to October 31, 2006(1) Financial 2,000 GJ/d $ 6.50CDN -
November 1, 2006 to March
31, 2007(2) Financial 2,000GJ/d $ 8.76CDN -
November 1, 2006 to March
31, 2007 Physical 2,000GJ/d $ 8.00CDN $10.85CDN
November 1, 2006 to March
31, 2007 Physical 5,000 GJ/d $ 8.00CDN $11.65CDN
------------------------------------------------------------------------
(1) Put options guarantee a floor price of $6.50 and have no price
ceiling. The cost of each put to the Company is approximately $0.52
per GJ

(2) Fixed price sale


As at June 30, 2006 the value of the individual put and call options that comprise the oil collar and put options for 2,000 GJ/d of gas production, together represent an unrecognized net loss of approximately CDN $24,000. This loss would only be realized in the event that the Company chose to unwind the costless collar arrangement and settle the put and call options individually. The remaining natural gas collars and remaining put options are commitments to deliver physical volumes and as such are not considered financial instruments for financial statement purposes.



9. SUPPLEMENTAL CASH FLOW INFORMATION

Three months ended Six months ended
June 30, June 30,
------------------------------------------------------------------------
2006 2005 2006 2005
------------------------------------------------------------------------
Changes in
non-cash working
capital -
Operating
Accounts
receivable $ (5,486,621) $ (988,317) $ 5,508,019 $ (1,901,941)
Deposits and
prepaid
expenses (605,144) 21,241 (336,835) (148,205)
Accounts payable
and accrued
liabilities (4,234,506) 4,063,448 (12,869,940) 2,293,892
------------------------------------------------------------------------
$(10,326,271) $ 3,096,372 $ (7,626,756) $ 243,746
------------------------------------------------------------------------
------------------------------------------------------------------------
Changes in
non-cash working
capital -
Capital
Accounts
receivable $ 3,030,842 $ (197,250) $ (3,413,312) $ (1,471,385)
Deposits and
prepaid expenses 635 - 67,858 -
Accounts payable
and accrued
liabilities (2,934,951) (245,931) 13,111,019 2,937,069
------------------------------------------------------------------------
$ 96,526 $ (443,181) $ 9,765,565 $ 1,465,684
------------------------------------------------------------------------
------------------------------------------------------------------------
Interest Payments
Included in the
Statement of Cash
Flows $ 810,509 $ 32,048 $ 1,307,512 $ 32,880
------------------------------------------------------------------------


Corporate Information


DIRECTORS
David Ambedian (1)(3)
Independent Businessman

Vincent Chahley
Independent Businessman

John Howard(1)(2)
Independent Businessman

Martin A. Lambert(3)
Partner, Bennett Jones LLP

David Richards(1)
Managing Director,
Network Capital Inc.

Garry Tanner(2)
Senior Vice President & Chief
Operating Officer
Enerplus Resources Fund

Russell J. Tripp, L.L.B., P.Land
Chairman & Chief Executive Officer

(1) member of audit committee

(2) member of reserve committee

(3) member of corporate governance,compensation and environmental health
and safety committee


OFFICERS

Russell J. Tripp, L.L.B., P.Land
Chief Executive Officer

Douglas C. Hibbs, B.Sc., P.Geol.
President

Calvin E. Jaycock, P.Geol.
Vice President, Exploration

Brian A. Baker, CA
Vice President, Finance and
Chief Financial Officer

Allan C. Slessor
Vice President, Land

Colin B. Witwer, P.Eng.
Vice President, Operations


CORPORATE OFFICE

Suite 2200
330 - 5th Ave SW
Calgary, Alberta T2P 0L4
Telephone: (403) 537-8440
Fax: (403) 537-8450
Website: www.bearridge.ca

INVESTOR RELATIONS
www.bearridge.ca
Trustee and Transfer Agent
Valiant Trust Company
310, 606 - 4 Street SW
Calgary, Alberta T2P 1T1
Telephone: (403) 233-2801
Fax: (403) 233-2857

STOCK EXCHANGE
The Toronto Stock Exchange
Trading symbol: BER

BANKER
National Bank of Canada
2700, 530 - 8 Avenue SW
Calgary, Alberta T2P 3S8

SOLICITOR
Bennett Jones LLP
4500, 855 - 2 Street SW
Calgary, Alberta T2P 4K7

AUDITORS
Deloitte & Touche LLP
3000, 700 - 2 Street SW
Calgary, Alberta T2P 0S7

CONSULTING ENGINEERS
GLJ Petroleum Consultants
4100, 400 - 3 Avenue SW
Calgary, Alberta T2P 4J2


ABBREVIATIONS


ARTC Alberta Royalty Tax Credit
bbl barrel
bbl/d barrels of oil per day
mbbls thousand barrels
boe barrels of oil equivalent(1)
boe/d barrels of oil equivalent per day(1)
mboe thousand barrels of oil equivalent(1)
mmboe million barrels of oil equivalent(1)
mmbtu million British thermal units
mcf thousand cubic feet
mmcf million cubic feet
bcf billion cubic feet
mcf/d thousand cubic feet per day
mmcf/d million cubic feet per day
NGL natural gas liquid
NPV net present value
P+P proved plus probable
WTI West Texas Intermediate

(1) 6 mcf of gas = 1 barrel of oil



Contact Information

  • Bear Ridge Resources Ltd.
    Russell J. Tripp
    Chairman and Chief Executive Officer
    (403) 537-8440
    or
    Bear Ridge Resources Ltd.
    Douglas C. Hibbs
    President
    (403) 537-8440
    or
    Bear Ridge Resources Ltd.
    Brian A. Baker
    Vice President Finance and Chief Financial Officer
    (403) 537-8440
    or
    Bear Ridge Resources Ltd.
    2200, 330 - 5th Avenue SW
    Calgary, Alberta, T2P 0L4
    (403) 537-8440
    (403) 537-8450 (FAX) (FAX)