Bear Ridge Resources Ltd.
TSX : BER

Bear Ridge Resources Ltd.

November 14, 2006 21:59 ET

Bear Ridge Announces 2006 Third Quarter Highlights

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



Financial Review and Operating Highlights

Three Months Ended Nine Months Ended
FINANCIAL September 30 September 30
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(in 000s, except
share amounts) 2006 2005 Change 2006 2005 Change
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Petroleum and
natural gas
revenue 13,829 4,585 202% 43,913 9,951 341%
Cash flow from
operations 4,975 2,742 81% 18,949 6,077 212%
Per share
- basic ($) 0.10 0.10 0.40 0.25 68%
Per share
- diluted ($) 0.09 0.09 0.38 0.23 74%
Net income (loss) (1,111) 9,258 (107)% (1,666) 10,308 (116)%
Per share
- basic ($) (0.02) 0.33 (103)% (0.04) 0.43 (107)%
Per share
- diluted ($) (0.02) 0.30 (103)% (0.04) 0.39 (110)%
Capital
Expenditures 29,189 11,163 161% 192,873 57,542 235%
Related to
acquisitions - - - 109,594 21,436 411%
Related to
current
operations 29,189 11,163 161% 83,279 36,106 131%
Working capital
deficiency (20,335) (9,018) 125% (20,335) (9,018) 125%
Bank debt (83,486) (83,486)
Shares
outstanding
(000s)
At period end 50,130 27,928 79% 50,130 27,928 79%
Weighted
average,
basic 50,130 27,927 80% 47,371 24,040 97%
Weighted
average,
diluted 52,548 30,727 71% 50,006 26,547 88%
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OPERATING
Production
Natural gas
(mcf/d) 15,710 2,795 462% 15,889 2,186 627%
Oil and NGL's
(bbls/d) 665 318 109% 640 264 142%
Total oil and
equivalent
(boe/d) 3,283 784 319% 3,288 628 424%
Average wellhead
prices
Natural gas
($/mcf) $ 6.56 $ 9.63 (32)% $ 7.31 $ 8.56 (15)%
Oil and NGL's
($/bbl) $ 71.14 $ 72.10 (1)% $ 69.82 $ 67.19 4%
Total oil and
equivalent
($/boe) $ 45.78 $ 63.57 (28)% $ 48.93 $ 58.05 (16)%
Operating costs
($/boe) $ 12.59 $ 7.53 67% $ 9.52 $ 7.37 29%
G&A costs ($/boe) $ 2.40 $ 4.15 (42)% $ 2.48 $ 5.27 (53)%
Operating netback
($/boe) $ 22.12 $ 42.38 (48)% $ 27.30 $ 40.99 (33)%
Wells drilled
Gross 15 12 63 20
Net 9.0 5.77 32.9 12.27
Net success rate 78% 100% 83% 95%
Undeveloped land
(net acres) 131,600 45,000 192% 131,600 45,000 192%
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THIRD QUARTER 2006 HIGHLIGHTS

- Bear Ridge achieved successful drilling results on its high impact, 3D driven natural gas project at Tupper in Northeast BC. Initial drilling and 3D seismic results indicate a Montney gas pool with a potential 800 bcf of Original Gas In Place on Bear Ridge's Tupper land block.

- Bear Ridge drilled 15 (9.0 net) wells during the quarter with a 78 percent success rate.

- Third quarter production was up 319 percent to 3,283 boe per day from 784 boe per day in the third quarter of 2005. Production per share was up 133 percent compared to the same quarter of 2005.

- During the quarter Bear Ridge completed minor property dispositions of 70 boe per day of non-core production for $2.6 million.

- Cash flow from operations totaled $5 million in the quarter, up 81 percent from $2.7 million in the third quarter of 2005.

- Capital investments in the quarter totaled $29 million, net of dispositions of $2.6 million, with $20 million directed towards drilling and completions and $1.5 million expended on land and seismic acquisitions.

- The Company's undeveloped land position has grown by 188 percent to 129,445 net acres from 45,000 in the third quarter of 2005.

MESSAGE TO SHAREHOLDERS

OPERATIONS

Bear Ridge continued its active capital program during the third quarter of 2006 drilling a total of 15 (9.0 net) wells with a 78 percent success rate. Drilling operations during the quarter were highlighted by our first gas discovery well at Tupper in NEBC. At Tupper we drilled one well and successfully completed the well as a new natural gas pool discovery. The c-56-A well was drilled and completed in the Lower Montney formation and flowed up casing at restricted rates of 1 to 2 mmcf/d during a partial cleanup period of approximately 18 hours. Due to the wells proximity to a near by school, completion operations were restricted to a single zone and a limited duration test period. Additional evaluation of the Lower Montney and fracture stimulation of the Upper Montney is planned for the summer of 2007.

Our second Tupper well, c-86-A, was drilled early in the fourth quarter and completion of the Lower Montney was successful with flow rates exceeding 3 mmcf/d. Fracture stimulation of the Upper Montney in this well is planned for later in November.

At West Central Alberta we drilled 3 (2.2 net) wells with a 100 percent success rate. One (1.0 net) well was completed as a dual Viking and Mannville gas well, one (0.4 net) well was completed as a Mannville gas well and one (0.7 net) well was drilled targeting Devonian Wabamun gas. Two of these wells are onstream and the third is waiting on tie-in.

In the Peace River Arch Area of Alberta we drilled 9 (4.7 net) wells resulting in one oil well, 4 successful oil and gas wells, 2 gas wells and 2 unsuccessful wells. At Cecil, we drilled a 100 percent working interest new oil pool discovery in the Basal Kiskatinaw formation. Additional development locations are planned to delineate this new oil pool. At Mulligan and Gordondale we drilled 2 (0.75 net) gas wells targeting the Doig and Dunvegan formations respectively. Both wells are anticipated to be tied-in before year end. In our new Eaglesham project area the Company drilled 4 (0.98 net) oil and gas wells during the quarter. Year to date Bear Ridge has drilled six successful wells at Eaglesham resulting in Wabamun, Montney and Bluesky/Gething discoveries.

In Northeast BC, which includes our productive Gunnell and Mica areas and our high growth Tupper project, we drilled 3 (2.18 net) wells with a 100 percent success rate. One (0.2 net) horizontal gas well was drilled in our Gunnell gas resource play targeting the Jean Marie formation. One (1.0) well was drilled in Mica as a re-drill on the original 15-6 wellbore which was previously lost to a mechanical failure. The 2/15-6 Mica well was completed as a successful gas well in the Doe sand of the Middle Kiskatinaw and was back on production in early October.

Bear Ridge continues to be active in all of its core projects. Subsequent to the end of the third quarter, Bear Ridge drilled and cased 4 (2.75 net) wells resulting in one oil well and 3 potential gas wells. We are currently drilling 3 (1.75 net) wells with an additional 4 (2.89 net) wells to be drilled prior to year end 2006.

LAND

At Crown land sales in the fourth quarter Bear Ridge purchased an additional 6,733 net undeveloped acres in one of its 3D driven seismic exploration project at Eaglesham.. In addition, Bear Ridge purchased another 724 net undeveloped acres in the Tupper project area bringing our total undeveloped lands in this project area to 19,016 net acres. Bear Ridge now controls a total of 32 contiguous sections of land on this high impact natural gas play. The Company's total net undeveloped land position has grown to 136,902 acres subsequent to the quarter end.

PRODUCTION

Third quarter production averaged 3,283 boe per day. During August the company was unable to rectify a mechanical failure that occurred early in July at the 15-6 Mica well. This event prevented the Company from restoring 500 boe per day from this well to reach expected production rates in late August of 4,500 boe per day. The 15-6 Mica well was re-drilled in the quarter and returned to production at a rate of 500 boe per day in early October, leaving the Company without production from this well for the entire third quarter. Several other factors impacted the Company's production during the quarter. The most significant factors were TCPL pipeline shut downs and unplanned third party plant outages during September that reduced production by over 1,000 boe per day for a portion of the month. MRL restrictions placed on production in the Cecil area reduced production by an additional 500 boe per day.

Production for the week ended November 3, 2006 averaged approximately 4,100 boe per day with an additional 900 boe per day behind pipe and 500 boe per day shut in due to MRL restrictions at Cecil. Of the 900 boe per day of behind pipe volumes, 550 is expected to be on production prior to year end with the remainder coming on at various times during 2007. MRL restricted production of 500 boe per day at Cecil is not expected to be back on stream until the second quarter of 2007.

FINANCIAL RESOURCES

At September 30, 2006 Bear Ridge had drawn $83.5 million on its credit facilities and maintained a working capital deficiency of $20.3 million for total net debt of $103.8 million. During the quarter the Company expanded its credit facilities to a maximum of $110.0 million through the addition of a $30.0 million non-revolving loan facility and $10.0 million acquisition and development drilling facility. All facilities will be reviewed again at the end of the first quarter.

Bear Ridge identified the significant value and future upside potential of the Tupper project and has made the strategic decision to maintain a 100 percent interest in the project. Total seismic and land costs at Tupper are approximately $14 million to date. By year end 2006 Bear Ridge will have drilled and completed 3 Montney delineation wells at Tupper at an estimated cost of approximately $11 million, bringing the Company's total Tupper investment to approximately $25 million. The Company forecasts total year end net debt to be approximately $106 million. As a result of maintaining the significant upside of this investment for shareholders at a 100% working interest, Bear Ridge has carried a higher than budgeted level of debt to finance the project.

Bear Ridge has moved forward with a number of initiatives to initially finance the expanded Tupper capital program and current debt levels, including:

- A new $30 million non - revolving loan facility was put in place in September, 2006 to help fund the initial Tupper development phase. Coupled with the Company's existing $80 million credit facility, Bear Ridge has increased available lines to $110 million.

- The Company is currently reviewing property disposition alternatives and has identified certain non-strategic properties that it may monetize.

- The Company reduced its 2006 drilling program from 78 (46 net) wells to 74 (40 net) wells.

- Bear Ridge has employed an active hedging program and currently has 10,000 GJ per day hedged for the November-March winter period and 9,000 GJ per day hedged for the April-October summer period.

HEDGING

The Company continued its proactive commodity hedging program during the quarter in light of an accelerated 2006 capital program, debt levels and record natural gas storage levels. We have hedged 9,000 GJ per day during the winter period which provide the Company with a guaranteed floor of $8.20 per GJ on hedged volumes with pricing upside to $10.85 per GJ. The Company has also hedged 8,000 GJ per day for the summer 2007 period with a guaranteed floor on hedged volumes of $6.25 per GJ with pricing upside to $7.90 per GJ.

OUTLOOK

Bear Ridge continues to execute a drillbit growth strategy focused on large scale, 3D driven exploration projects in the Peace River Arch and NEBC regions. Our 3D seismic data base has grown to 1,200 square kilometers primarily covering our Earring, Josephine, Eaglesham, Clear Hills, Gunnell and Tupper projects. All of these projects continue to enjoy success and provide solid growth potential for the Company.

We are extremely excited about the potential of our Tupper, project as it presents an opportunity to capture significant value for shareholders. Initial drilling and completion operations have been in line with management's expectations. Drilling and completion results coupled with 3D seismic interpretation indicate a potential resource of 800 bcf of Original Gas In Place from the Montney zone alone within the Company's contiguous land block. Additional potential has been identified on 3D seismic in the Halfway, Paddy and Dunvegan and has been encountered in the initial 2 Tupper wells.

Our third Tupper well is currently drilling and should reach total depth in late November 2006. Bear Ridge plans to drill 6 to 8 vertical Montney tests and 2 to 4 horizontal Montney wells at Tupper in 2007. Initial production from Tupper is forecast for October 2007. With the success of our Tupper project we expect to deliver significant per share reserve and production growth over the next few years.

Bear Ridge is currently reviewing its entire 2007 capital program in light of early success at Tupper and expects to provide market guidance for 2007 in early December, 2006.

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 November 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 three and nine month periods ended September 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 third quarter of 2006 averaged 3,283 boe per day compared to 784 boe per day for the three months ended September 30, 2005, an increase of 319%. Current production rates averaged 4,100 for the week ended November 3rd with an additional 900 boe behind pipe and 500 boe shut in due to MRL restrictions at Cecil. Of the behind pipe production 550 boe per day is expected to be on in the fourth quarter with the remaining production coming on at various times in 2007. Restricted production is expected to be back on stream in the second quarter of 2007. An additional 8 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 nine month periods ended September 30, 2006 totaled $9.5 million and $31.7 million, respectively, representing increases of 283% and 521% 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 $9.9 million from the second quarter of 2006, natural gas revenues in the third quarter are down 1.0% as a result of lower prices received during the quarter.

Natural gas production of 15,710 mcf per day for the third quarter represents an increase of 6.8% from natural gas production of 14,713 mcf per day during the second quarter. The increase in production was the result of new production brought on stream and production back on from plant turn-arounds in June. An additional 500 boe per day of production expected from downhole repairs at the Company's 15-6 well did not come back on until early in October. Production was further curtailed in September due to pipeline maintenance and shut downs which resulted in approximately 1,000 boe per day of gas production being shut in for half of the month.

Natural gas pricing for the third quarter of 2006 averaged $6.56 per mcf compared to $7.38 per mcf in the second quarter of the year. This decrease of 11.1% is the result of decreases in the AECO gas daily spot price over this period. Bear Ridge benefited from costless collar arrangements during the third quarter, which contributed approximately $0.9 million in realized hedging gains. Without these arrangements, the Company's natural gas price in the third quarter would have averaged $5.97 per mcf.

Oil and NGL's

Oil and NGL revenue for the three and nine month periods ended September 30, 2006 totaled $4.4 million and $12.2 million, respectively, representing increases of 106% and 152% 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 second quarter of 2006, revenues for the third quarter were up by 12.8%. Production of 665 bbl/d was up 15.5% from 576 bbl per day in the second quarter due to increased oil production as a result of drilling activities in the Earring area. The increase in production levels were offset by lower oil pricing during the quarter.

Oil prices for the three months ended September 30, 2006 averaged $71.32 per bbl, a decrease of 8.2 % from the second quarter of 2006 which averaged $77.73 per bbl. NGL prices received by Bear Ridge totaled $70.53 per bbl during the third quarter compared to $65.95 in the second quarter, representing an increase of 6.9%.



Three months ended Nine months ended
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Results of Sept 30, Sept 30, % Sept 30, Sept 30, %
Operations 2006 2005 Change 2006 2005 Change
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Revenues (000's)

Natural gas $ 9,478 $ 2,477 283% $ 31,723 $ 5,109 521%
Oil and NGL's 4,351 $ 2,108 106% 12,190 $ 4,842 152%
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Total revenues $ 13,829 $ 4,585 202% $ 43,913 $ 9,951 341%
Less acquisition
adjustment (1) - - - 1,691 - -
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Total revenues
per financial
statements $ 13,829 $ 4,585 202% $ 42,222 $ 9,951 324%
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Average Daily
Production
Volumes
Natural gas
(mcf/d) 15,710 2,795 462% 15,889 2,186 627%
Oil & NGL's
(bbl/d) 665 318 109% 640 264 142%
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Total production
(boe/d) 3,283 784 319% 3,288 628 424%
Acquisition
adjustment (1) - - - 108 - -
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(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 Nine months ended
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Sept 30, Sept 30, Sept 30, Sept 30,
2006 2005 2006 2005
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Bear Ridge's Average
Selling Price
Natural gas - $/mcf
including hedging $ 6.56 $ 9.63 $ 7.31 $ 8.56
Natural gas - $/mcf
excluding hedging $ 5.97 $ 9.63 $ 6.68 $ 8.56
Crude oil - $/bbl $ 71.32 $ 72.83 $ 70.65 $ 67.33
NGL's - $/bbl $ 70.53 $ 63.84 $ 67.76 $ 66.09
Total average
selling price - $/boe $ 45.78 $ 63.58 $ 48.93 $ 58.05

Benchmark Pricing
AECO gas daily
spot - $/mcf $ 5.33 $ 8.82 $ 6.05 $ 7.43
WTI oil - US $/bbl $ 70.48 $ 63.19 $ 68.21 $ 55.04
Edmonton par - CDN $/bbl $ 79.08 $ 75.67 $ 75.53 $ 67.63
US/CDN average
exchange rate 0.89 0.83 0.88 0.82
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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.



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

Natural Gas
April 1 to October 31, 2006 2,000 GJ/d $ 9.00CDN $12.85CDN
April 1 to October 31, 2006 1,000 GJ/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) 2,000 GJ/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 2,000 GJ/d $ 8.00CDN $10.85CDN
April 1, 2007 to October 31, 2007 3,000 GJ/d $ 5.50CDN $ 8.05CDN
April 1, 2007 to October 31, 2007 3,000 GJ/d $ 6.24CDN $ 8.00CDN
April 1, 2007 to October 31, 2007(2) 2,000 GJ/d $ 7.26CDN -
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(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 September 30, 2006 royalties, net of the Alberta Royalty Tax Credit ("ARTC"), totaled $2.9 million or 21.4 % of total revenues. This rate as a percentage of revenue represents an increase of 5.2% from the second quarter royalty rate of 16.2%. The increase from the second quarter is the result of the Company's annual gas cost allowance, 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 being received during the second quarter. Revenue in the second quarter also included heging gains of $1.5 million compared to hedging gains of $0.9 million in the third quarter. These gains are not subject to royalties and effectively reduce royalties as a percentage of revenue.

Royalty rates for the nine month period ended September 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 nine month periods then ended. For the three months ended September 30, 2005 the royalty holiday had expired and the rate for this period is consistent with the rate for the three months ended September 30, 2006.

ARTC recoveries totaled $86,271 for the third quarter and $336,271 year to date after minor adjustments from previous year claims. 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. The ARTC program will be discontinued effective January 1, 2007 after which point the Company will no longer be eligible for this tax credit for future periods.



Three months ended Nine months ended
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Sept 30, Sept 30, % Sept 30, Sept 30, %
Royalties (000's) 2006 2005 Change 2006 2005 Change
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Crown $ 2,704 $ 975 177% $ 8,376 $ 1,638 411%
Freehold and GORR 351 156 125% 1,143 276 314%
ARTC (86) (210) (59)% (336) (375) (10)%
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Total Royalty
Expense $ 2,969 $ 921 222% $ 9,183 $ 1,539 497%
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Royalties per boe $ 9.83 $ 12.78 (23)% $ 10.73 $ 8.97 20%
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Three months ended Nine months ended
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Average royalty rates Sept 30, Sept 30, Sept 30, Sept 30,
(% of sales) 2006 2005 2006 2005
---------------------------------------------------------------------------
Royalty Category
Crown 19.5% 21.3% 19.8% 16.5%
Freehold and GORR 2.5% 3.4% 2.7% 2.8%
ARTC (0.6)% (4.6)% (0.8)% (3.8)%
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Total Royalty 21.4% 20.1% 21.7% 15.5%
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OPERATING EXPENSES

When compared with the previous year Bear Ridge's operating costs per boe for the three and nine month periods ended September 30, 2006 have increased by 67.0% and 29.0% respectively. The increase in costs is due to a significant change in the Company's production base which has grown from being relatively small and concentrated as at September 30, 2005 to one that is much more substantial.

During the current quarter, operating costs increased to $12.59 per boe, an increase of 43.7% when compared to operating costs of $8.76 from the second quarter of 2006. The increase on a boe basis is due to higher than anticipated processing fees, non-operated charges, significant repair and maintenance expenses incurred over the summer and short term water processing and handling charges, combined with the 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 last quarter of 2006 and into 2007 as production volumes increase.



Three months ended Nine months ended
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Sept 30, Sept 30, % Sept 30, Sept 30, %
2006 2005 Change 2006 2005 Change
---------------------------------------------------------------------------
Operating Costs
(000's) $ 3,802 $ 543 600% $ 8,332 $ 1,265 559%
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Operating Costs
per boe $ 12.59 $ 7.53 67% $ 9.52 $ 7.37 29%
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TRANSPORTATION EXPENSES

Transportation expenses for the third quarter ended September 30, 2006 totaled $377,623 or $1.24 per boe down from the second quarter of 2006 of $434,342, or $1.58 per boe. Transportation costs were higher in the previous quarter as a 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 third quarter of 2006, the Company's netback totaled $22.12 which represents a decrease of $9.54 per boe when compared with netbacks of $31.66 per boe from the second quarter of 2006. This decrease in netbacks is a result of lower overall sales price for the period due to lower gas pricing and higher operating costs. The Company expects that higher commodity prices and improved operating costs on a boe basis will drive netbacks higher.

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



Three months ended Nine months ended
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Sept 30, Sept 30, Sept 30, Sept 30,
Operating Netback ($/boe) 2006 2005 2006 2005
---------------------------------------------------------------------------
Sales price $ 45.78 $ 63.58 $ 48.93 $ 58.06
Royalties (9.83) (12.78) (10.73) (8.97)
Operating expense (12.59) (7.53) (9.52) (7.37)
Transportation expense (1.24) (0.89) (1.38) (0.71)
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Operating Netback $ 22.12 $ 42.38 $ 27.30 $ 40.99
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GENERAL AND ADMINISTRATIVE EXPENSES ("G&A")

G&A expenses for the third quarter of 2006 totaled $726,470 or $2.40 per boe compared to $298,968 or $4.15 per boe for the same quarter of 2005. Year to date G&A expense has totaled $2,235,095 or $2.48 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 $5.27 per boe.

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 $519,337, or 35.2% of total gross G&A costs incurred during the third quarter of 2006. The capitalization rate is in line with G&A costs capitalized in the second quarter of 2006 when the capitalization rate equaled 39.2%. 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 Nine months ended
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% %
Sept 30, Sept 30, Change Sept 30, Sept 30, Change
G & A Expense
(000's) 2006 2005 2006 2005
---------------------------------------------------------------------------
G&A expense
(gross) $ 1,473 $ 315 368% $ 4,392 $ 920 377%
G&A capitalized (519) - - (1,653) - -
Overhead
recoveries (228) (16) - (504) (17) -
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G&A expense (net) $ 726 $ 299 143% $ 2,235 $ 903 148%
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G&A expense
$ per boe $ 2.40 $ 4.15 (42)% $ 2.48 $ 5.27 (53)%
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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 September 30, 2006, the Company incurred stock based compensation expense of $604,950 or $2.00 per boe compared to $216,761 or $3.01 per boe for the three month period ended September 30, 2005. For the nine month period ended September 30, 2006, the Company incurred stock based compensation expenses of $1,693,950 or $1.89 per boe compared to $703,000 or $4.10 per boe for the nine month period ended September 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 nine months ended September 30, 2006 totaled $2.4 million. Draws on the Company's credit facilities to fund the cash component of the Veteran acquisition and to execute Bear Ridge's capital program 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 $49,302.

Interest for the three months ended September 30, 2006 totaled $1,059,262 representing an increase of 30% from interest charges of $810,509 from the previous quarter of 2006. The increase was a result of the Company carrying a larger amount of bank debt and higher interest rates in the third quarter compared to the second.

DEPLETION, DEPRECIATION AND ACCRETION

Depletion and depreciation totaled $8.7 million for the three months ended September 30, 2006 or $28.59 per boe. The depletion rate dropped from $29.39 in the previous quarter due to increases in reserves due to new production brought on during the quarter.

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 increased in the third quarter of 2006 to $55,000 compared to $47,000 in the previous quarter due to asset dispositions in the second 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 Nine months ended
---------------------------------------------------------------------------
Sept 30, Sept 30, Sept 30, Sept 30,
2006 2005 2006 2005
---------------------------------------------------------------------------
Total costs (000's)
Depletion and depreciation $ 8,636 $ 2,077 $ 23,360 $ 4,091
Accretion 55 7 158 17
---------------------------------------------------------------------------
Combined $ 8,691 $ 2,084 $ 23,518 $ 4,108
---------------------------------------------------------------------------

Cost per boe
Depletion and depreciation $ 28.59 $ 28.81 $ 26.01 $ 23.86
Accretion $ 0.18 $ 0.10 $ 0.18 $ 0.10
---------------------------------------------------------------------------
---------------------------------------------------------------------------


TAXES

As at September 30, 2006, Bear Ridge had available approximately $215 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 reviewed 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 third 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 and due to the increase in tax pool balances outpacing cash flow generated from operations. The recognized recovery during the quarter totaled $2.6 million.

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 $17.3 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. On May 12, 2006, the Company closed a private placement of 3,150,000 flow-through common shares for proceeds of $23,152,500. Pursuant to this private placement, the Company is committed to incur these expenditures by December 31, 2007. As at September 30, 2006 approximately $4.3 million of this commitment remains.

CASH FLOW AND NET INCOME

Cash flow from operations totaled $5.0 million for the three months ended September 30, 2006 or $0.10 basic cash flow per share compared to cash flow of $7.0 million or $0.15 basic cash flow per share from the second quarter of 2006. Cash flow was impacted in the third quarter by lower commodity prices combined with higher operating costs and lower realized hedging gains. These items were partially offset by higher production levels for the quarter.

The Company realized a net loss for the nine months ended September 30, 2006 totaling totaled $1.7 million, which represents a significant reduction from the $10.3 million in net income generated in the previous year. Income in the previous year was largely due to a $9.0 million future income tax recovery. Ignoring future income taxes, increased revenues during 2006 have been offset by higher operating costs associated with those revenues combined with higher depletion and stock based compensation charges. The Company recorded a net loss of $1.1 million for the three months ended September 30, 2006 compared to net income of $0.5 million for the previous quarter. Higher production volumes in the third quarter were impacted by lower commodity prices and higher operating costs.



Three months ended Nine months ended
---------------------------------------------------------------------------
Sept 30, Sept 30, Sept 30, Sept 30,
2006 2005 2006 2005
---------------------------------------------------------------------------
Cash flow from operations
per share
Basic $ 0.10 $ 0.10 $ 0.42 $ 0.25
Diluted $ 0.09 $ 0.09 $ 0.40 $ 0.23
Net income (loss)
- per share
Basic $ (0.02) $ 0.33 $ (0.04) $ 0.43
Diluted $ (0.02) $ 0.30 $ (0.03) $ 0.39
---------------------------------------------------------------------------
---------------------------------------------------------------------------


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 third quarter totaled $29.2 million compared to $11.2 million in the same period of the prior year. For the first nine months of the year net capital expenditures totaled $82.9 million compared to $57.5 million in the first nine months of 2005.

The third quarter of 2006 continued to be an active quarter for Bear Ridge with the drilling of 15 (9 net) wells resulting in 12 (6 net) gas wells and 1 (1 net) oil wells and 2 (2 net) abandoned wells, for a 78 percent success rate.

Capital expenditures during the quarter focused heavily on infrastructure activities with the tie-in of most of the wells drilled in the second quarter, including tie-in of wells drilled in the second quarter Gordondale program, Gunnell and Central Alberta. The Company completed compression installation in the Gunnel and Earring areas as well as completion of an oil battery in the Earring area. Drilling activities focused on the downhole repairs and re-drill of the 15-6 well in Mica, initial drilling and completion operations in the Tupper area as well as drilling in the Earring and Eaglesham areas.

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 emerging new development at Eaglesham.

During the third quarter Bear Ridge disposed of certain non core properties for total sale proceeds of $2.6 million.

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



Three months ended Nine months ended
---------------------------------------------------------------------------
Sept 30, Sept 30, Sept 30, Sept 30,
Capital Expenditures (000's) 2006 2005 2006 2005
---------------------------------------------------------------------------
Land $ 1,016 $ 1,801 $ 14,985 $ 4,888
Geological & geophysical 578 144 4,684 703
Drilling & completions 19,585 7,959 50,892 17,317
Equipment & facilities 10,125 1,117 21,325 2,022
Office & furniture 58 44 191 49
Asset retirement obligation 400 98 495 583
Property
acquisition/(disposition) (2,573) - (9,293) 23,636
Corporate acquisition - - 109,594 8,344
---------------------------------------------------------------------------
Total Expenditures $ 29,189 $ 11,163 $ 192,873 $ 57,542
---------------------------------------------------------------------------
---------------------------------------------------------------------------


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 September 30, 2006 Bear Ridge had drawn $83.5 million on its credit facilities and had a working capital deficiency of $20.3 million for total net debt of $103.8 million. During the quarter the Company expanded its credit facilities to a maximum of $110.0 million through the addition of a $30.0 million non-revolving loan facility and $10.0 million acquisition and development drilling facility.

As a result of maintaining the significant upside of the Company's investment in Tupper for shareholders at a 100% working interest, Bear Ridge has carried a higher than budgeted level of debt to finance the project. Bear Ridge has moved forward with a number of initiatives to initially finance the expanded Tupper capital program and current debt levels, including:

- A new $30 million non - revolving loan facility was put in place in September, 2006 to help fund the initial Tupper development phase. Coupled with the Company's existing $80 million credit facility, Bear Ridge has increased available lines to $110 million.

- The Company is currently reviewing property disposition alternatives and has identified certain non-strategic properties that it may monetize.

- The Company reduced its 2006 drilling program from 78 (46 net) wells to 74 (40 net) wells.

- Bear Ridge has employed an active hedging program and currently has 10,000 GJ per day hedged for the November-March winter period and 9,000 GJ per day hedged for the April-October summer period.

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) Q3 Q2 Q1
---------------------------------------------------------------------------
Revenues 14,520 13,806 14,587
Royalties 2,969 2,231 3,983
Operating expenses 3,802 2,415 2,115
Transportation expenses 377 434 424

Cash flow (000's) 4,975 7,003 6,972
Per share - basic 0.10 0.15 0.16
Per share - diluted 0.09 0.14 0.15

Net Income (loss) (1,111) 524 (1,078)
Per share - basic (0.02) 0.01 (0.02)
Per share - diluted (0.02) 0.01 (0.02)

Capital expenditures, net 29,189 17,361 36,729
Acquisition expenditures - - 109,594
---------------------------------------------------------------------------
Total expenditures 29,189 17,361 146,323
---------------------------------------------------------------------------
---------------------------------------------------------------------------

2006
---------------------------------------------------------------------------
Operations Q3 Q2 Q1
---------------------------------------------------------------------------
Production volumes
Natural gas (mcf/day) 15,710 14,713 17,262
Oil and NGL's (bbl/day) 665 576 678
---------------------------------------------------------------------------
Total boe/day 3,283 3,028 3,555
---------------------------------------------------------------------------
---------------------------------------------------------------------------
Average Selling Price
Natural gas ($ per mcf) 6.56 $ 7.38 $ 7.96
Oil and NGL ($ per bbl) 71.14 74.87 64.59
---------------------------------------------------------------------------
Combined ($ per boe) 45.78 $ 50.10 $ 50.89
Royalties ($ per boe) 9.83 8.10 13.72
Operating expense ($ per boe) 12.59 8.76 7.28
Transportation ($ per boe) 1.24 1.58 1.46
---------------------------------------------------------------------------
Netback ($ per boe) 22.12 $ 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)

September 30, December 31,
($ thousands) 2006 2005
---------------------------------------------------------------------------
ASSETS
Current
Accounts receivable $ 15,629 $ 7,373
Investment (note 3) 571 -
Deposits and prepaid expenses 676 626
Financial commodity contracts (note 8) 612 -
---------------------------------------------------------------------------
17,488 7,999
Future income tax - 9,457
Goodwill (note 2) 31,740 -
Property and equipment (note 4) 235,695 66,182
---------------------------------------------------------------------------
$ 284,923 $ 83,638
---------------------------------------------------------------------------
---------------------------------------------------------------------------

LIABILITIES AND SHAREHOLDERS' EQUITY
Current
Accounts payable and accrued liabilities $ 37,823 $ 14,642
Credit facilities (note 5) 83,486 5,248
---------------------------------------------------------------------------
121,309 19,890
Asset retirement obligations (note 6) 3,192 519
Future income tax 3,993 -
---------------------------------------------------------------------------
128,494 20,409

Shareholders' equity
Share capital (note 7(a)) 146,090 52,537
Warrants 711 711
Contributed surplus (note 7(b)) 2,307 994
Retained earnings 7,321 8,987
---------------------------------------------------------------------------
156,429 63,229
---------------------------------------------------------------------------
$ 284,923 $ 83,638
---------------------------------------------------------------------------
---------------------------------------------------------------------------

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)

($ thousands, Three Months Nine Months
except per Ended Ended
share data September 30, September 30,
---------------------------------------------------------------------------
2006 2005 2006 2005
---------------------------------------------------------------------------
REVENUE
Petroleum and natural gas
sales $ 13,829 $ 4,585 $ 42,222 $ 9,951
Gain on financial commodity
contracts 691 - 691 -
Royalties, net of Alberta
Royalty Tax Credit (2,969) (921) (9,183) (1,538)
---------------------------------------------------------------------------
11,551 3,664 33,730 8,413
---------------------------------------------------------------------------
EXPENSES
Operating 3,802 543 8,332 1,265
Transportation 377 64 1,236 121
General and administrative 726 299 2,235 903
Stock based compensation 605 217 1,694 703
Interest on credit facilities 1,059 16 2,366 49
Depletion, depreciation and
accretion 8,691 2,085 23,518 4,108
---------------------------------------------------------------------------
15,260 3,224 39,381 7,149
---------------------------------------------------------------------------

Income (loss) before income taxes (3,709) 440 (5,651) 1,264

Income taxes
Future income tax recovery (2,598) (8,818) (3,985) (9,042)
---------------------------------------------------------------------------

Net income (loss) (1,111) 9,258 (1,666) 10,308

Retained earnings (deficit),
beginning of period 8,432 (901) 8,987 (1,949)
Preferred share dividend - (105) - (105)
---------------------------------------------------------------------------
Retained earnings, end of period $ 7,321 $ 8,252 $ 7,321 $ 8,252
---------------------------------------------------------------------------
---------------------------------------------------------------------------

Net income (loss) per share
(note 7(d))
Basic $ (0.02) $ 0.33 $ (0.04) $ 0.43
Diluted $ (0.02) $ 0.30 $ (0.04) $ 0.39
---------------------------------------------------------------------------

See accompanying notes


CONSOLIDATED STATEMENTS OF CASH FLOWS
(Unaudited)

Three Months Ended Nine Months Ended
($ thousands) September 30, September 30,
---------------------------------------------------------------------------
2006 2005 2006 2005
---------------------------------------------------------------------------
OPERATING ACTIVITIES
Net income (loss) $ (1,111) $ 9,258 $ (1,666) $ 10,308
Items not involving cash:
Unrealized gain on financial
commodity contracts(note 8) (612) - (612) -
Depletion, depreciation and
accretion 8,691 2,085 23,518 4,108
Future income tax recovery (2,598) (8,818) (3,985) (9,042)
Stock based compensation 605 217 1,694 703
---------------------------------------------------------------------------
Cash flow from operations
before changes in non
cash working capital 4,975 2,742 18,949 6,077
Change in non-cash working
capital (note 9) 2,689 (2,393) (4,937) (2,150)
---------------------------------------------------------------------------
Cash provided by (used in)
operating activities 7,664 349 14,012 3,927
---------------------------------------------------------------------------

FINANCING ACTIVITIES
Common shares issued, net of
issue costs (13) (29) 22,313 19,162
Preferred shares issued - - - 6,175
Advances on credit facilities 21,936 5,946 73,815 5,946
Repayment of debt - - - (2,000)
---------------------------------------------------------------------------
Cash provided by financing
activities 21,923 5,917 96,128 29,283
---------------------------------------------------------------------------

INVESTING ACTIVITIES
Acquisition of properties - - - (3,052)
Expenditures on property and
equipment (31,362) (11,065) (92,648) (24,980)
Property and equipment
dispositions 2,573 - 9,293 -
Acquisition of Veteran
Resources Inc. (note 2) - - (35,753) -
Acquisition of partnership - - - (8,344)
Change in non-cash working
capital (note 9) (798) 1,220 8,968 2,686
---------------------------------------------------------------------------
Cash used in investing
activities (29,587) (9,845) (110,140) (33,690)
---------------------------------------------------------------------------
Change in cash and cash
equivalents $ - $ (3,579) $ - $ (480)
Cash and cash equivalents,
beginning of period $ - $ 3,579 $ - $ 480
---------------------------------------------------------------------------
Cash and cash equivalents, end
of period $ - $ - $ - $ -
---------------------------------------------------------------------------
---------------------------------------------------------------------------


Notes to the Consolidated Financial Statements

As at and for the period ended September 30, 2006

(Unaudited)

NOTE 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.

NOTE 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 $ 4,263,447
Deposits and prepaid expenses 160,988
Property and equipment 109,594,000
Goodwill 31,740,015
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
---------------------------------------------------------------------------
---------------------------------------------------------------------------


NOTE 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 cost and is subject to impairment in the event of a non-temporary decline in value.

NOTE 4. PROPERTY AND EQUIPMENT



Accumulated
depletion and Net book
Cost depreciation value
---------------------------------------------------------------------------
Petroleum and natural gas
properties $ 283,254,974 48,075,309 $ 235,179,665
Office equipment 1,315,373 799,611 515,762
---------------------------------------------------------------------------
$ 284,570,347 48,874,920 $ 235,695,427
---------------------------------------------------------------------------
---------------------------------------------------------------------------


During the period ended September 30, 2006, the Company capitalized general and administrative expenses in the amount of $1.7 million (2005 - $0.4 million) related to exploration and development expenditures.

As at September 30, 2006, costs totaling $34.4 million related to unproven properties have been excluded from assets subject to depletion, while estimated future development costs of $7.3 million, related to proven reserves, were included in the calculation of depletion expense.

NOTE 5. CREDIT FACILITIES

As at September 30, 2006 the Company had combined credit facilities totaling $110 million. The facilities are comprised of the following individual components:

A revolving production loan with a Canadian financial institution to a maximum of $70 million and an acquisition and development loan to a maximum of $10 million. The revolving production loan bears interest at prime plus an applicable margin based on the Company's debt to cash flow ratio, while the acquisition and development loan bears interest at prime plus one percent.

A $110 million non-revolving loan facility bearing interest at the rate of prime plus two percent. The amount available under the facility is reduced by the amount drawn on the revolving production and acquisition and development loans and is due May 31, 2007. The non-revolving facility is secured by a $200 million subordinated fixed and floating charge debenture on the assets of the Company.

NOTE 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 September 30, 2006.



Amount
---------------------------------------------------------------------------
Balance January 1, 2006 $ 519,416
Liabilities incurred 665,000
Liabilities acquired 2,020,000
Liabilities transferred on disposition (170,000)
Accretion expense 157,900
---------------------------------------------------------------------------
Balance September 30, 2006 $ 3,192,316
---------------------------------------------------------------------------
---------------------------------------------------------------------------


Total estimated future asset retirement costs of $6.9 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.



NOTE 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 - (935,026)
---------------------------------------------------------------------------
Balance, September 30, 2006 50,130,306 146,089,673
---------------------------------------------------------------------------
---------------------------------------------------------------------------

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 September 30, 2006, approximately $4.3
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 nine months ended September 30, 2006 is as follows:

Amount
---------------------------------------------------------------------------
Balance, January 1, 2006 $ 994,066
Stock based compensation 1,693,950
Options and special performance units exercised (381,000)
---------------------------------------------------------------------------
Balance, September 30, 2006 $ 2,307,016
---------------------------------------------------------------------------
---------------------------------------------------------------------------


c) Stock based compensation

i. Stock options:

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

Weighted
Average
Number Exercise Price
---------------------------------------------------------------------------
Balance outstanding, January 1, 2006 1,231,673 $ 3.82
Granted 2,177,000 4.85
Cancelled (180,000) 4.93
Exercised (65,004) 3.65
---------------------------------------------------------------------------
Balance outstanding, September 30, 2006 3,163,669 $ 4.47
---------------------------------------------------------------------------
---------------------------------------------------------------------------

As at September 30, 2006 368,890 options are exercisable at an average
exercise price of $3.80 per option.

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

Weighted Average
Number Remaining Weighted Average
Grant Price Outstanding Contractual Life Exercise Price
---------------------------------------------------------------------------
$ 3.25 to $3.65 496,669 3.45 $ 3.48
$ 3.94 to $5.08 2,667,000 4.21 4.66
---------------------------------------------------------------------------
3,163,669 4.09 $ 4.47
---------------------------------------------------------------------------
---------------------------------------------------------------------------


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 nine months ended September 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 $ 1.65 $ 1.15
---------------------------------------------------------------------------

ii. Special Performance Units

A summary of the SPU's outstanding as at September 30, 2006 and changes for
the nine 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, September 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 nine month periods ended September 30, 2006 and 2005 as follows:

Weighted average - common Three months ended Nine months ended
shares outstanding September 30, September 30,
---------------------------------------------------------------------------
2006 2005 2006 2005
---------------------------------------------------------------------------
Basic 50,130,306 27,927,761 47,370,518 24,040,283
Add dilutive effect of:
Warrants 1,907,041 1,799,806 2,010,839 1,654,516
SPU's 389,355 952,769 389,455 834,050
Stock Options 121,027 46,911 235,423 18,199
---------------------------------------------------------------------------
Diluted 52,547,729 30,727,247 50,006,235 26,547,048
---------------------------------------------------------------------------
---------------------------------------------------------------------------


NOTE 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 September 30, 2006, the Company had the following fixed price financial and physical costless collar arrangements:



---------------------------------------------------------------------------
Hedged
Term Type Volumes Floor Ceiling
---------------------------------------------------------------------------
Oil
January 2006 to December 2006 Financial 200 bbl/d $ 55.00US $ 73.00US
Natural Gas
April 1 to October 31, 2006 Physical 2,000 GJ/d $ 9.00CDN $12.85CDN
April 1 to October 31, 2006 Physical 1,000 GJ/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 2,000 GJ/d $ 8.76CDN -
November 1, 2006 to March 31,
2007 Physical 2,000 GJ/d $ 8.00CDN $11.50CDN
November 1, 2006 to March 31,
2007 Physical 5,000 GJ/d $ 8.00CDN $11.65CDN
April 1, 2007 - October 31,
2007 Physical 3,000 GJ/d $ 5.50CDN $ 8.05CDN
April 1, 2007 - October 31,
2007 Physical 3,000 GJ/d $ 6.24CDN $ 8.00CDN
April 1, 2007 to October 31,
2007(2) Physical 2,000 GJ/d $ 7.26CDN -
---------------------------------------------------------------------------

(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


The Company has elected not to apply hedge accounting to the financial contracts noted above. The following table reconciles the changes in the fair value of the contracts that have not been designated as hedges:



Amount
---------------------------------------------------------------------------
Realized gains on financial contracts $ 78,721
Unrealized gain on financial contracts as at September 30, 2006 612,300
---------------------------------------------------------------------------
Gain on financial commodity contracts $ 691,021
---------------------------------------------------------------------------
---------------------------------------------------------------------------


NOTE 9. SUPPLEMENTAL CASH FLOW INFORMATION

Three months ended Nine months ended
September 30, September 30,
---------------------------------------------------------------------------
2006 2005 2006 2005
---------------------------------------------------------------------------
Changes in non-cash
working capital -
Operating

Accounts
receivable $ (1,809,752) $ 1,819,999 $ 3,244,787 $ (81,942)

Deposits and
prepaid expenses 380,456 (107,186) 43,621 (255,391)

Accounts payable
and accrued 4,118,689 (4,106,079) (8,225,770) (1,812,187)
liabilities
---------------------------------------------------------------------------
$ 2,689,391 $ (2,393,266) $ (4,937,364) $ (2,149,520)
---------------------------------------------------------------------------
---------------------------------------------------------------------------

Changes in non-cash
working capital -
Capital

Accounts
receivable $ (3,324,501) $ 908,554 (6,737,813) (562,831)

Deposits and
prepaid expenses - - 67,858 -

Accounts payable
and accrued 2,526,850 312,214 15,637,863 3,249,283
liabilities
---------------------------------------------------------------------------
$ (797,651) $ 1,220,768 $ 8,967,908 $ 2,686,452
---------------------------------------------------------------------------
---------------------------------------------------------------------------

Interest Paid $ 1,059,262 $ 16,422 $ 2,366,415 $ 49,302
---------------------------------------------------------------------------


Corporate Information

DIRECTORS OFFICERS
David Ambedian (1)(3) Russell J. Tripp, L.L.B., P.Land
Independent Businessman Chief Executive Officer

Vincent Chahley Douglas C. Hibbs, B.Sc., P.Geol.
Independent Businessman President

John Howard(1)(2) Calvin E. Jaycock, P.Geol.
Independent Businessman Vice President, Exploration

Martin A. Lambert(3) Brian A. Baker, CA
Partner, Bennett Jones LLP Vice President, Finance and
Chief Financial Officer
David Richards(1)
Managing Director, Allan C. Slessor
Network Capital Inc. Vice President, Land

Garry Tanner(2) Colin B. Witwer, P.Eng.
Senior Vice President & Chief Vice President, Operations
Operating Officer
Enerplus Resources Fund Kelly Novakowski, CMA
Controller

Russell J. Tripp,
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


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)