Welton Energy Corporation
TSX : WLT
TSX : WLT.WT
TSX : WLT.DB

Welton Energy Corporation

November 13, 2006 17:52 ET

Welton Energy Corporation Announces 2006 Third Quarter Financial and Operating Results

CALGARY, ALBERTA--(CCNMatthews - Nov. 13, 2006) - Welton Energy Corporation (TSX:WLT) (TSX:WLT.DB) (TSX:WLT.WT) is pleased to present its financial and operating results for the three and nine months ended September 30, 2006.



Operational and Financial Highlights

Three months Nine months
ended ended
September 30 Change September 30 Change
---------------------------------------------------------------------------
2006 2005 % 2006 2005 %
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Average Daily Production
Crude oil (bbls/d)
Heavy oil 589 64 820 542 6 -
Light oil 24 16 50 29 21 38
Natural gas liquids
(bbls/d) 50 119 (58) 57 98 (42)
Natural gas (Mcf/d) 1,931 1,827 6 1,954 1,361 44
Total (boe/d)(2) 985 504 95 954 352 171
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Wells completed
(gross/net)
Natural Gas 1/0.3 6/1.8 5/1.4 6/1.8
Oil 3/1.5 - / - 8/2.6 - / -
Dry 3/1.4 1/0.5 7/2.7 1/0.5
Total(3) 7/3.2 7/2.3 20/6.7 7/2.3
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Undeveloped land holdings
Gross acres 145,978 109,760 33
Net acres 55,938 26,166 114
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Oil and gas revenues ($000s) 4,215 2,642 60 11,496 5,089 126
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Funds flow from
operations(1) ($000s) 1,619 911 78 4,102 1,747 135
Per share - basic ($) 0.04 0.03 34 0.11 0.07 58
Per share - diluted ($) 0.04 0.03 34 0.10 0.06 67
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Income (loss) ($000s) (499) (532) 7 (1,454) 749 -
Per share - basic ($) (0.01) (0.02) 50 (0.04) 0.03 234
Per share - diluted ($) (0.01) (0.02) 50 (0.04) 0.03 234
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Capital expenditures ($000s) 4,573 28,020 (84) 13,597 30,991 (56)
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Shares outstanding (000s)
Weighted average - basic 39,759 30,162 39,021 26,254
Weighted average - diluted 40,905 31,084 40,151 27,175
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(1) Funds flow as presented (before changes in non-cash working capital) does not have any standardized meaning prescribed by Canadian GAAP and therefore it may not be comparable with the calculation of similar measures for other entities.

(2) Boe may be misleading, particularly if used in isolation. In accordance with National Instrument 51-101, a boe conversion rate for natural gas of 6 mcf to 1 bbl has been used. This ratio is based on an energy equivalency conversion method primarily applicable at the burner tip and does not represent a value equivalency of the representative commodity at the wellhead.

(3) At September 30, 2006 5 wells (2 net) were drilled but not yet completed.

Message to Shareholders

We are pleased to report on the Company's operations for the nine months ended September 30, 2006 and to date. Management's Discussion and Analysis of the Company's financial results for the first three quarters of 2006 is provided with the comparative financial statements for the period.

Throughout 2006, the Company has made focused efforts in two areas: bringing behind-pipe production on stream and exploring its 100% operated properties. These efforts have resulted in increasing average quarterly daily production from 504 boe/d in Q3 2005 to 985 boe/d in Q3 2006, a Q3 exit rate of 1,080 boe/d and a current daily rate of 1,040 boe/d; the drilling of three 100% exploration wells; and the acquisition of 11,259 gross and net undeveloped acres. The results for Welton shareholders are increasing production rates and an impressive portfolio of exploration, development and exploitation opportunities.

Key Achievements from June 30, 2006 to Date

- Third quarter average production of 985 boe/d, 95% higher than a year ago.

- Current daily production of 1,040 boe/d as of November 8, 2006.

- Cash flow of $1.6 million compared to $0.9 million in Q3 2005.

- Welton's total undeveloped land base is approximately 146,000 gross and 56,000 net acres.

- Acquisition of 7,040 gross and net acres covering three 100% owned exploration projects.

- At Brazeau, the water injection rate is over 5,000 barrels per day, up from 1,100 in Q2.

Operations

To date in 2006, Welton drilled a total of 21 wells with 16 wells cased and five abandoned.

Production

Welton's average production for the third quarter of 2006 was approximately 985 boe/d. Production in Saskatchewan from Mantario was negatively affected by unusually wet field conditions in September that limited the hauling of oil to the sales point. Normal production hauling has since resumed. Approximately 70% of the Company's total production is heavy oil and 30% is natural gas and associated liquids. The Company realized prices in the range of $51 per barrel for the third quarter. This helped to partially offset decreases in cash-flow due to the falling natural gas prices that all energy companies experienced, particularly those that are gas-weighted.

Saskatchewan

Welton and its partners have drilled 16 wells in Saskatchewan to date in 2006. Thirteen of these wells have been cased as potential oil or natural gas wells and three were abandoned. The Company has assembled 35,649 gross (22,576 net) acres of undeveloped lands.

Operated Projects

In 2006, Welton drilled four 100% exploration wells on three separate prospects to the east of its 25% owned interest in the Mantario East heavy oil pool. Two wells were abandoned and two are currently under evaluation. A fifth step out well has been licensed and drilling is expected to commence in November. Additional drilling and seismic activity is planned in this area.

Non-Operated Projects - Mantario

Since the second quarter the Company has participated in drilling an additional two wells with its partners in Saskatchewan and completed another well. Two of these wells have been completed and are producing oil wells. The operator has served notice to drill two step out wells (12.5% interest) in Mantario.

Placing of the new wells on production and production optimization work in the field is ongoing. Mantario East continues to be of significant importance to the Company. Development and exploration activity in this prolific heavy oil and natural gas field is planned to continue into 2007. Welton's interests range from 12.5% to 25% in the area.

Alberta

A total of five wells have been drilled in Alberta to date in 2006, three were cased and two were abandoned.

Operated - Boundary Lake and Brazeau River Waterflood Project

The Company recently acquired 100% working interests in 11 sections at a recent sale at Boundary Lake. This brings total acreage holdings in this area to 9,600 gross and 7,840 net acres. The first well is expected to be drilled here this winter and additional prospect development work including the shooting of a seismic program is continuing.

At the Brazeau River Nisku I pool water-flood project (94.75% interest), Welton has finalized acquisition of additional water supplies and pipelines and increased injection rates to approximately 5,400 boe/d. Initial oil production is currently targeted to commence in 2007 and is expected to increase to over 300 boe/d as the project becomes fully developed.

Non-Operated - Karr

Welton participated in the drilling of two gas exploration wells at Karr (40% interest) as well as the recompletion and tie-in of a previously drilled liquids-rich sour gas well. The 13-19 gas well was placed on production in mid-August. Current production is 128 boe/d net to Welton. The second well that was drilled is scheduled for a completion attempt this winter depending on the state of natural gas prices. Final tie-in work for the Wabamun recompletion well was deferred by the operator and is now scheduled to be completed with the well coming on stream in Q2 2007 at a rate of approximately 6.0 mmcfe/d gross (175 boe/d net to Welton). Welton holds a 20.5% revenue interest and will pay 10% of the tie in costs.

Corporate

Management

Mr. David C. Whiteley, Chief Financial Officer, has left the Company and is pursuing other activities. We want to thank David for his contribution to Welton and wish him success in his future endeavors.

Financing

Welton successfully completed a $4 million bought deal partially brokered flow-through financing in August 2006. Of this amount, approximately $1.4 million was for qualifying "CDE" expenditures and $2.5 million was for qualifying "CEE" expenditures.

Outlook

The drilling of three 100% wells in Saskatchewan coupled with the acquisition of 7,040 acres in Alberta in Q3 reflects the Company's initiative during this year to increase the number of projects it operates. During the fourth quarter of 2006 and into 2007, Welton will continue to complete and tie in wells drilled earlier this year, to optimize current operations and to develop new projects. Welton also continues to review acquisition opportunities that will complement our existing assets. Welton's planned capital spending for 2007 is $3.5 million.

Welton's diversified production has provided significant protection to the Company from the negative effects of falling natural gas prices.

Welton's Board and Management continue to own approximately 30% of the Company's securities, and remain committed to our objective of increasing shareholder value over the medium term.

Respectfully submitted on behalf of the Board of Directors:

Raymond R. Pether, Chief Executive Officer

Donald A. Engle, President

Management's Discussion and Analysis

The following discussion and analysis has been prepared by management, and reviewed and approved by the Board of Welton Energy Corporation ("Welton" or the "Company"). The following supplementary information provides a review of the financial results of the Company based, subject to the foregoing, upon accounting principles generally accepted in Canada. Its focus is primarily a comparison of the financial performance for the three and nine months ended September 30, 2006 and 2005 and should be read in conjunction with the unaudited financial statements and accompanying notes included in this report and the December 31, 2005 and 2004 audited financial statements and accompanying notes included in the Company's 2005 Annual Report. This discussion and analysis is based on information available to November 9, 2006. All amounts are in thousands of Canadian dollars, except for per share and per boe amounts, or unless otherwise noted.

Non-GAAP Measurements

In the Management's Discussion & Analysis ("MD&A") references are made to terms commonly used in the oil and gas industry that are not defined by generally accepted accounting principles ("GAAP") in Canada and are referred to as non-GAAP measures. Such non-GAAP measures should not be considered an alternative to, or more meaningful than GAAP measures as indicators of the Company's financial or operating performance. The non-GAAP measures presented are not standardized measures and therefore may not be comparable to the calculation of similar measures for other entities. The following non-GAAP measures are used in this MD&A:

1) "Funds flow from operations" and "funds flow" equal funds flow from operations before changes in non-cash working capital related to operating activities. The reconciliation between net income and funds flow from operations can be found in the Consolidated Statements of Cash Flows. The Corporation also presents "funds flow per share", whereby funds flow from operations is divided by the weighted average number of shares outstanding over the period to determine per share amounts.

2) "Netbacks" equal total revenue (net of marketing fees) per boe less royalties per boe, and operating costs per boe.

Natural gas reserves and volumes are converted to barrels of oil equivalent (boe) on the basis of six thousand cubic feet (mcf) of gas to one barrel (bbl) of oil. Boes may be misleading, particularly if used in isolation. A boe conversion ratio of 6 mcf to 1 bbl is based on an energy equivalency conversion method primarily applicable at the burner tip and does not represent a value equivalency at the wellhead.

Forward-Looking Statements

This report contains certain "forward-looking statements" within the meaning of such statements under applicable securities law. Forward-looking statements are frequently characterized by words such as "plan", "expect", "estimate", "believe" and other similar words, or statements that certain events or conditions "may" or "will" occur. By their nature, forward-looking statements involve assumptions and are subject to a variety of risks and uncertainties, including, but not limited to, those associated with resource definition, the possibility of project cost overruns or unanticipated costs and expenses, regulatory approvals, fluctuating oil and gas prices, and the ability to access sufficient capital to finance future development, reservoir performance and drilling results. Although the Company believes that the expectations represented by such forward-looking statements are reasonable, there can be no assurance that such expectations will prove to be correct. The Company does not undertake any obligation to update publicly or to revise any of the included forward-looking statements as a result of new information, future events or otherwise, subsequent to the date of this report. The reader is cautioned not to place undue reliance on forward-looking statements.

Additional information relating to the Company can be found on its website at www.weltonenergy.com or through the SEDAR system at www.sedar.com.

Third Quarter 2006 Highlights

- Average production for the third quarter increased by 95% to 985 boe/d from 504 boe/d in the third quarter of 2005.

- Welton's third quarter oil production continued to exceed 60% of total production.

- Welton lowered operating costs to $9.31/boe from $16.07/boe for a reduction of 42% from the same period last year and 22% from the prior quarter.

- Cash flow from operations was $1,619 ($0.04 per share) compared to $911 ($0.03 per share) in the prior year.

Production

For the third quarter of 2006, the Company produced a total of 985 boe/d from over 45 wells in Alberta and Saskatchewan and obtained most of its production from crude oil. Crude oil production represents over 60% of Welton's total production base, with most oil production coming from its heavy oil field in Mantario, Saskatchewan. Crude production in Mantario was negatively affected in the month of September by very wet field conditions which limited the hauling of oil to the sales point. This reduced overall Company volumes by approximately 35 boe/d. Normal production hauling has since resumed. By contrast, for the same period in 2005, Welton had production of 504 boe/d with only 16% of its production from crude oil. This shift from natural gas to oil is a trend which affects all key financial metrics including revenues, royalties and operating expenses for the Company throughout 2006. Year-to-date production was 954 boe/d versus 352 boe/d during the same period of 2005. This 171% increase was due to the corporate acquisitions completed during the third quarter of 2005 as well as successful drilling.

The following table sets out the average daily production values.



Three months Nine months
ended ended
September 30 Change September 30 Change
2006 2005 (%) 2006 2005 (%)
---------------------------------------------------------------------------
Crude oil (bbl/d)
Heavy oil 589 64 820 542 6 -
Light oil 24 16 50 29 21 38
Natural gas liquids (bbl/d) 50 119 (58) 57 98 (42)
Natural gas (mcf/d) 1,931 1,827 6 1,954 1,361 44
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Total boe/d 985 504 95 954 352 171
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Production for the third quarter is 10% higher than the previous quarter's 895 boe/d, as drier weather early in the quarter allowed access for completion efforts as well as the tie in of the Karr 13-19 well which had been drilled in early 2006.



Commodity Prices

The following table represents relevant quarterly average commodity price
benchmarks:

Three months Nine months
ended ended
September 30 Change September 30 Change
2006 2005 (%) 2006 2005 (%)
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Crude Oil
West Texas Intermediate
("WTI" - US$/bbl) 70.44 60.05 17 68.05 56.46 21
Hardisty Heavy oil
(Cdn$/bbl) 51.55 32.52 59 45.14 34.35 31
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Natural Gas
AECO (Cdn$/Mcf) 5.61 9.30 (40) 6.38 7.85 (19)
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Overall crude oil prices remained strong during the third quarter with an average WTI price of US$70.44/bbl, up 17% from the same period last year. Heavy oil prices were up 59% to $51.55/bbl versus $32.52/bbl in the prior year as seasonal demand for heavy oil peaked, largely due to strong asphalt demand during the summer paving season. Differentials began to widen during the month of September. Overall, for the first nine months of 2006 oil and heavy oil prices are up 21% and 31% respectively compared to the same period of 2005.

Natural gas prices (AECO Hub in Alberta) for the third quarter have fallen 40%, from $9.30/mcf in 2005 to $5.61/mcf as prices have retreated due to higher than average storage levels and relatively little hurricane activity in 2006. Overall, for the year natural gas prices are lower by 19% versus 2005, but have started to show signs of strengthening as we head into the winter heating season.



Average Realized Sales Prices

Three months Nine months
ended ended
September 30 Change September 30 Change
2006 2005 (%) 2006 2005 (%)
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Heavy oil ($/bbl) 51.19 39.84 28 44.13 39.84 11
Light oil ($/bbl) 82.48 75.96 9 72.81 75.96 (4)
Natural gas ($/Mcf) 5.48 9.46 (42) 6.57 8.23 (20)
Natural gas liquids ($/bbl) 61.16 63.27 (3) 59.16 62.02 (5)
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Total ($/boe) 46.48 57.00 (18) 44.07 53.01 (17)
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The Company's average realized price for heavy oil was $51.19/bbl for the third quarter which was only slightly lower than the comparable benchmark Heavy Hardisty oil price of $51.55/bbl. The realized natural gas price for the third quarter was $5.48/mcf which again was only slightly lower than the average AECO price for the quarter. Despite a 42% drop in natural gas prices, the total average realized price of $46.48/bbl for the third quarter was down only 18% compared to the average realized price in 2005. This is largely due to the change in the Company's production mix toward heavy oil.



Revenue

Three months Nine months
Production Revenue ended ended
September 30 Change September 30 Change
($ thousands) 2006 2005 (%) 2006 2005 (%)
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Heavy oil 2,775 233 - 6,465 233 -
Light oil 181 127 43 582 127 358
Natural gas 974 1,590 (39) 3,503 3,058 15
Natural gas liquids 283 694 (59) 924 1,658 (44)
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Total(1) 4,213 2,644 59 11,474 5,076 126
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(1)Total production revenue excludes sulphur revenue.


For the three months ended September 30, 2006 the Company's production revenue increased 59% to $4,213 versus $2,644 for the same period of 2005. The increase in total revenue can be attributable primarily to volume increases for Welton's heavy oil properties. Heavy oil revenues from Welton's Mantario property were $2,775 compared to only $233 in the third quarter of the prior year.
Production revenue for the first nine months of 2006 was $11,474 compared to $5,076 in 2005, representing a 126% increase. This increase is largely due to the Company's added production volumes from its heavy oil property as well as other new properties added to production.



Netbacks

Three months Nine months
ended ended
September 30 Change September 30 Change
($/boe) 2006 2005 (%) 2006 2005 (%)
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Oil, NGL and natural gas
revenue 46.48 57.00 (19) 44.07 53.01 (17)
Royalty expense (net of
ARTC) (11.96) (9.35) 28 (9.17) (5.54) 66
Production expenses (9.31) (16.07) (42) (11.45) (19.34) (41)
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Netback 25.21 31.58 (20) 23.45 28.13 (17)
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Royalty as percentage of
revenue (%) 25.7 16.4 57 20.8 10.4 100
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For the third quarter 2006, the Company realized a netback of $25.21/boe or a 20% decrease versus $31.58/boe during the same period in 2005. Revenue decreases on a per boe basis were primarily a result of softer natural gas prices. In addition, certain royalty holidays that were available in 2005 were fully consumed by 2006 thus contributing to higher royalties in the current year. The decrease in netback due to lower prices and higher royalties was partially offset by bringing on production with lower operating costs than the sour gas operation of the prior year. The Company's netback per boe for the nine months ended September 30, 2006 was 17% lower that the prior year at $23.45/boe vs. $28.13/boe in 2005. This year to date decrease in netback was due to the same factors that impacted the quarterly netback.

Royalties

Royalties for the Company include all royalties to provincial governments, freeholders and other override royalties, and are net of the Alberta Royalty Tax Credit (ARTC), a tax rebate received from the Alberta government for eligible crown royalties paid in the year. In September 2006, the Alberta government announced that it will eliminate the ARTC program as of January 1, 2007. Therefore, 2006 is the final year that Welton will receive the ARTC credit. As a percentage of revenue, royalties for the third quarter 2006 are 25.7% versus 16.4% in 2005. The Company received a provincial deep-well royalty holiday for the original Karr well which contributed to lower royalty rates for 2005, but was fully consumed in 2005. Overall royalty rates in 2006 are higher because in 2005 the original Karr 16-19 well was on royalty holiday for half of the year, thus lowering the royalty rate, and in 2006 a significant portion of the Company's production came from the heavy oil wells in Saskatchewan where it pays royalties in the range of 28% to 32% depending on production levels and prices received.



Operating expenses

2005 2006
($/boe) Q1 Q2 Q3 Q4 Q1 Q2 Q3
---------------------------------------------------------------------------
Operating expenses $ 23.05 $ 21.87 $ 16.07 $ 15.49 $ 13.27 $ 11.88 $ 9.31
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Unit operating expenses continue to decrease on a quarterly basis as a result of increased production volumes without a significant corresponding increase in fixed operating costs. As well, operational optimizations were realized from adding relatively lower production cost heavy oil wells versus production from the previous year's higher cost sour gas operations at Welton's original Karr 16-19 well, which is now shut-in. Consequently, operating expenses were $9.31/boe in 2006 or a 42% decrease, compared to $16.07/boe for the same period in 2005 and a 22% improvement from the prior quarter. These improvements were achieved in an environment experiencing strong inflationary pressures for services and overall higher energy costs which contribute to higher trucking costs for water disposal, electricity and fuel costs utilized in field operations. This trend of six consecutive quarters of lower operating costs has resulted in year-to-date operating expenses averaging $11.45/boe in 2006 as compared to $19.34/boe for the comparable nine month period of 2005.



General and Administrative

Three months Nine months
ended ended
September 30 Change September 30 Change
($ thousands, except per
boe amounts) 2006 2005 (%) 2006 2005 (%)
---------------------------------------------------------------------------
General and administrative 472 461 2 1,536 991 55
Overhead recoveries and
capitalized overhead (78) (70) 11 (222) (174) 28
Net 394 391 - 1,314 817 61
Per boe $ 4.35 $ 8.43 (48) $ 5.05 $ 8.50 (41)
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Stock-based compensation
expense 94 6 - 245 15 -
Per boe $ 1.03 $ 0.14 - $ 0.94 $ 0.16 -
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Total expense 488 397 23 1,559 832 87
Total per boe $ 5.38 $ 8.56 (37) $ 5.99 $ 8.65 (31)
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Net general and administrative costs (excluding non-cash stock-based compensation expense) were essentially flat at $394 in the third quarter of 2006 versus $391 in 2005. Net general and administrative costs for the nine months ended September 30, 2006 totaled $1,314 compared to $817 in 2005, an increase of 61%. Additional fees for maintaining Welton as a public entity, three public stock exchange listings for the Company's warrants, convertible debentures and common shares as well as rent for additional office space to accommodate the Company's expanding operations all contributed to higher costs. Overhead recoveries and capitalized overhead of $78 were recognized in the third quarter of 2006 which is an increase of 11% (2005 - $70) from the prior year. Capitalized overhead is recognized for technical staff dedicated to the Company's capital program and geological reviews of new core areas.

For the third quarter of 2006, on a per boe basis, general and administrative expenses (excluding non-cash stock based compensation) declined by 48% to $4.35 per boe from $8.43 per boe in 2005 as total costs remained relatively constant and were spread across increased production volumes. On a year-to-date basis, per boe general and administrative costs decreased to $5.05 per boe compared to $8.50 per boe in 2005. Increased general and administrative costs were more than offset by production increases resulting in lower per boe costs.

Stock-based compensation expense is the amortization over the vesting period of the fair value of stock options granted to employees, directors and key consultants of the Company. The fair value of all options granted is estimated at the date of grant using the Black-Scholes option pricing model. The non-cash compensation expense for the three and nine months ended September 30, 2006 increased to $94 and $245 versus $6 and $15 respectively for the same periods in 2005. The increase is a function of additional options being granted to new staff hired to facilitate the significant growth of the Company, with options vesting equally over a three-year period pursuant to the Company's stock option plan and a higher average fair value option price.

The Company also utilizes the services of Brompton Limited ("BL"), a related party, for certain senior management services, certain accounting and administrative staff and related expenses. For the third quarter 2006 fees of $22 (2005 - $42) and $77 (2005 - $113) year-to-date were charged by BL.



Interest and Financing Charges

Three months Nine months
ended ended
September 30 Change September 30 Change
---------------------------------------------------------------------------
($ thousands) 2006 2005 (%) 2006 2005 (%)
---------------------------------------------------------------------------
Interest and loan fees
on bridge and bank loans 23 177 (87) 211 177 19
Interest on debentures 212 - - 495 - -
Amortization of debenture
issue costs 32 - - 73 - -
Accretion of debentures 38 - - 89 - -
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Total interest and financing
charges 305 177 72 868 177 391
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The Company incurred $305 of interest and operating loan fees in the third quarter of 2006 versus $177 in the prior year. During the third quarter of 2005, $177 of interest and loan fees were paid on the bridge facility that was put in place in September 2005 when Welton acquired its Mantario property. The bridge loan was fully repaid in February 2006, with the closing of the Company's convertible debenture financing. The second interest payment totaling $283 for the convertible debentures was paid on September 30, 2006 for the period from June 30, 2006. The next payment date for debenture holders is December 31, 2006. Also included in interest and financing is the amortization of the financing charges related to the debenture offering as well as the non-cash accretion of the debt portion of the debentures. This is discussed further in the liquidity and capital resources section of the MD&A. Total interest and financing charges are higher for the nine months ended September 30, 2006 as the Company had no debt until September of 2005 when it acquired its Mantario properties.



Depreciation, Depletion and Accretion

Three months Nine months
ended ended
($ thousands, except per September 30 Change September 30 Change
boe amounts) 2006 2005 (%) 2006 2005 (%)
---------------------------------------------------------------------------
Depletion and depreciation 2,115 1,304 62 5,517 2,631 110
Per boe $ 23.34 $ 28.12 (17) $ 21.19 $ 27.48 (23)
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Accretion expense 18 11 64 55 14 293
Per boe $ 0.20 $ 0.24 (17) $ 0.22 $ 0.15 47
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For the quarter ending September 30, 2006, depletion and depreciation expense for the Company's oil and gas properties amounted to $2,115 (2005 - $1,304) or $23.34 (2005 - $28.12) per boe. Overall dollar increases for depletion expense were attributed to higher production volumes to be depleted in the third quarter than in 2005. However, on a per boe basis the decrease from the prior year is primarily a result of adding lower cost proved reserve additions than in previous periods. Depletion expense for the first half of 2006 was $5,517 or $21.19/boe compared to $2,631 or $27.48/boe in 2005.

Accretion expense for the quarter ended September 30, 2006 was $18 compared to $11 for the same quarter of 2005. The year-to-date accretion expense totals $55 compared to $14 in 2005. The accretion expense has increased significantly compared to the prior year due to the increase in the asset retirement obligation. At September 30, 2006, the Company has recorded an asset retirement obligation of $1,037 (2005 - $860). This amount is the net present value of the total future asset retirement costs of $2,212 (2005 - $851). The total costs were determined by management based on the Company's working interest in its wells and facilities, estimated costs to abandon and reclaim those wells and facilities and the estimated timing of the costs to be incurred in future periods. The liability has increased significantly compared to the same period of the prior year due to the large number of wells added from acquisitions and drilling. Also, increasing costs from oil field service providers contributed to the increased obligation. The asset retirement obligation has increased from $860 at December 2005 due to the addition of liabilities for new wells drilled in 2006.

Income Taxes

The Company has $57 (2005-nil) in current income tax expense for the third quarter and $137 (2005-nil) for the nine months ended September 30, 2006. These current taxes relate to capital taxes and Saskatchewan resource taxes. The Company incurred no current taxes in the three or nine months ended September 30, 2005 as it had no Saskatchewan properties during this time and was significantly smaller in size. The Company has no other current income taxes because it has the ability to utilize its non-capital loss carry forwards, which as of September 30, 2006 totaled $17,756. These losses will expire over four years from 2007 to 2010.

In the second quarter of 2006, the federal government enacted legislation that eliminates federal capital tax, retroactive to January 1, 2006. In addition, Saskatchewan resource taxes increased as a result of gross sales revenue from Saskatchewan based properties, offset by recent capital tax rate reductions from that province. As a result, capital taxes on a go-forward basis will be based on only provincial capital taxes. On April 10, 2006, the Federal government substantively enacted a two percent decrease to the federal corporate tax rate from January 1, 2008 to January 1, 2010 and an elimination of the 1.12 percent federal surtax at January 1, 2008. These rate reductions were recorded as future tax recoveries in the second quarter of 2006 but were offset by other adjustments.

Income

Net loss for the three months ended September 30, 2006 was $499 versus $532 in 2005. Compared to the prior year, higher production volumes and the resulting higher revenue were offset by higher depletion costs, production costs, interest and general and administrative costs and resulted in a similar loss from operations as seen in the prior year.

The year-to-date net loss was $1,454 or $0.04 per diluted share compared to net income of $749 or $0.03 per diluted share for the same period of 2005. During 2005, a future income tax recovery of $1,662 related to the tax benefit of previously unrecognized tax losses was booked. Significantly higher interest and financing charges incurred in 2006 as well as higher depletion, royalties and general and administrative charges also contributed to the year to date loss compared to the prior year.



Capital Expenditures

Three months Nine months
ended ended
($ thousands, except September 30 Change September 30 Change
per boe amounts) 2006 2005 (%) 2006 2005 (%)
---------------------------------------------------------------------------
Exploration drilling 2,441 261 835 5,161 1,056 389
Development drilling 528 3,243 (84) 3,741 3,478 8
Production equipment 665 437 52 2,280 1,564 46
Land and seismic 887 21 - 1,274 842 51
Corporate acquisitions - 23,475 - 981 23,475 96
Other 52 583 (91) 160 576 (72)
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Total 4,573 28,020 (84) 13,597 30,991 (56)
---------------------------------------------------------------------------


For the third quarter of 2006, a total of $4,573 in capital was spent versus $28,020 for 2005 or $4,545 excluding corporate acquisitions. In the third quarter of 2006, $2,441 was spent on exploration drilling including three 100% Welton operated wells in Saskatchewan. One of these wells has been abandoned and two wells are currently under evaluation. Also included in the exploration drilling costs in the third quarter of 2006 is the non-operated well at Chime that was abandoned in early August. Development drilling costs in the third quarter were for wells at the Company's Mantario heavy oil property in Saskatchewan and for the re-completion of the Karr 16-19 well. Production equipment costs were primarily incurred for the tie-in of two wells in Karr, the 13-19 and the 10-15. The Company also spent approximately $887 on land and seismic during the quarter with the majority being spent on 100% lands (7,040 total acres) in the Boundary Lake area. Total year-to-date capital spending was $13,597 compared to $30,991 in the prior year, a decrease of 56%. Excluding all corporate acquisitions, capital spending for the first nine months of 2006 was $12,616 compared to $7,516 in the first nine months of 2005. Welton's planned capital spending for 2007 is $3.5 million.

Liquidity and Capital Resources

Convertible Debentures

On February 27, 2006, the Company issued $10,500 principal amount of 8% secured Convertible Debentures. The debentures bear interest from the date of issue. The first interest payment of $283 was paid on June 30, 2006 and the second interest payment of $211 was paid on September 30, 2006. The debentures are convertible at the option of the holder at any time into fully paid common shares at a conversion price of $1.55 per share, no conversions occurred in the year. The debentures mature on January 15, 2009. The proceeds of this offering were used to repay the $10,500 note payable to Brompton Financial Limited ("BFL"), a related party. The original financing was required to complete the acquisition of Era Oil & Gas Corporation on September 2, 2005.

For financial statement purposes the debentures have been classified as debt, net of the fair value of the conversion feature at the date of issue, which has been classified as part of shareholders' equity. The value of the debt was calculated as the present value of the principal and interest payments with the remainder of the value attributed to the conversion feature and recorded as equity. The debt portion of the debentures is accreted up to its full face value by the end of the debenture term. The accretion is recorded as non-cash interest and financing charges on the statement of operations and deficit. The financing charges related to the debenture offering have been recorded as a long term asset and are being amortized to interest and financing charges over the life of the debentures.

Flow-through Equity Financing

On August 2006, the Company issued 2,040 common shares at $1.25 per share, which are eligible for Canadian Exploration Expenses on a flow-through basis. In addition, the Company also issued 1,261 common shares at $1.15 per share, which are eligible for Canadian Development Expenses on a flow-through basis. Total net proceeds for both offerings, after agents' fees and issue costs, was $3,781. Employees and directors subscribed to a combined total for 1,293 of these flow-through shares.

Note Financings and Banking Facility

At September 30, 2006, the Company had in place banking arrangements for a $6,400 demand loan facility. The demand loan facility bears interest at bank prime rate plus 0.25%, and is secured by a $25,000 fixed charge Debenture and a floating charge over all assets of the Company. The maximum amount drawn on the facility during the quarter was $2,900 and the facility was completely undrawn as at September 30, 2006.

For the third quarter of 2006 the Company's sources of cash totalled $7,532 versus cash requirements of $7,097, and as of September 30, 2006 the cash on hand increased by $435 from nil at June 30, 2006. The Company intends to finance the remainder of its planned capital program through funds generated from operations and its current credit facility.



Funds Flow

Three months Nine months
ended ended
September 30 Change September 30 Change
($ thousands) 2006 2005 (%) 2006 2005 (%)
---------------------------------------------------------------------------
Sources
Funds flow from operations 1,619 911 78 4,102 1,747 135
Issue of common shares, net - - - 119 1,250 (90)
Issuance of notes - 10,500 - - 10,500 -
Issuance of convertible
debentures - - - 10,500 - -
Issuance of flow-through
shares, net 3,781 - - 3,781 987 283
Increase in bank loan - 810 - - 810 -
Working capital 2,132 680 214 2,168 - -
---------------------------------------------------------------------------

---------------------------------------------------------------------------
Uses
Oil and natural gas property
expenditures 4,573 4,208 9 12,616 7,177 76
Repayment of notes - - - 10,500 - -
Decrease in bank loan 2,517 - - - - -
Working capital - - - - 890 -
Deferred financing charges - - - 139 - -
Acquisitions - 9,685 - 981 9,685 (90)
Asset retirement expenditures 7 - - 40 - -
---------------------------------------------------------------------------

---------------------------------------------------------------------------
(Decrease)/Increase in cash 435 (992) 144 (3,606) (2,458) 47
---------------------------------------------------------------------------


Working Capital

On September 30, 2006, the Company had negative working capital of $5,248 versus negative working capital of $9,969 at December 31, 2005. The improvement is primarily due to the BFL Note payable being refinanced by long term convertible debentures (see above), offset by an active capital expenditure program in the first nine months of 2006.

Contractual Obligations

The Company has obligations to renounce qualifying tax deductions under the flow-through share agreements it has entered into described in the Income Tax section. The Company has an obligation to incur qualifying expenditures totaling $7,999 during 2006 to meet the flow-through share obligations resulting from its December 2005 flow-through share issuance. As at September 30, 2006 the Company has satisfied this entire obligation. As a result of the August flow-through financing mentioned above the Company has until the end of 2007 to incur qualifying expenditures totaling $4,000 to meet its flow-through share obligations.

As a result of a corporate acquisition in 2005, the Company assumed a commitment for a Net Profits Interest Agreement ("NPI") for the Brazeau River waterflood project. The Company's costs to be deducted from revenues in calculating the NPI include the Corporation's share of capital and operating costs and overhead expenses. Costs not recovered in a period are carried forward to subsequent periods until recovered, plus applicable interest. The NPI is non-recourse and is thus restricted to only net profits from the Brazeau River waterflood property, and no other assets of the Company. The NPI is treated like all other royalties and is not a liability of the Company, but is included in the calculation of reserves.

Related Party Transactions

Certain management functions of the Company have been provided by Brompton Limited ("BL"), the parent company of BFL. The types of services and fees charged are discussed in the General and Administrative costs discussion. For the Company's $10,500 Note Payable (see section above Note Financings) Welton has paid interest of $95 and loan and stand-by fees of $70 as at September 30, 2006 to BFL with all costs being incurred in the first quarter of 2006. No such loans existed for the first quarter of 2005.

Off-Balance Sheet Arrangements

The Company has no off-balance sheet arrangements.



Selected Quarterly Financial Information

($thousands, except 2006 2005 2004
per share amount) Q3 Q2 Q1 Q4 Q3 Q2 Q1 Q4
---------------------------------------------------------------------------
Production revenue 4,215 3,884 3,397 4,316 2,642 1,339 1,108 1,087
Net income (loss) (499) (314) (641) 744 (532) (265) 1,546 1,189
Per share amounts:
Basic
Net income (loss) (0.01) - (0.02) 0.01 (0.02) (0.01) 0.07 0.08
Diluted
Net income (loss) (0.01) - (0.02) 0.02 (0.02) (0.01) 0.06 0.07
Funds flow 1,619 1,608 875 1,313 911 471 363 511
Per share amounts:
Basic
Funds flow 0.04 0.04 0.02 0.04 0.03 0.02 0.02 0.03
Diluted
Funds flow 0.04 0.04 0.02 0.04 0.03 0.02 0.02 0.03
---------------------------------------------------------------------------



Welton Energy Corporation
Consolidated Balance Sheet (Unaudited)

(in thousands of dollars)

September 30, December 31,
2006 2005
---------------------------------------------------------------------------

Assets

Current assets
Cash and cash equivalents $ 435 $ 4,041
Accounts receivable 2,623 5,558
Other assets 265 169
---------------------------------------------------------------------------
3,323 9,768

Property, plant and equipment (note 4) 50,433 42,146
Deferred financing charges, net 291 225
Future tax asset - 1,065
---------------------------------------------------------------------------
$ 54,047 $ 53,204
---------------------------------------------------------------------------
---------------------------------------------------------------------------

Liabilities

Current liabilities
Accounts payable and accrued liabilities $ 8,571 $ 9,237
Note payable - related party (note 7) - 10,500
---------------------------------------------------------------------------
8,571 19,737

Convertible debentures (note 7) 10,157 -
Future tax liability 1,402 -
Asset retirement obligation (note 5) 1,037 860
---------------------------------------------------------------------------
21,167 20,597

Shareholders' equity
Share capital (note 8) 30,813 29,763
Equity component of debentures (note 7) 432 -
Contributed surplus 5,787 5,542
Deficit (4,152) (2,698)
---------------------------------------------------------------------------
32,880 32,607

---------------------------------------------------------------------------
$ 54,047 $ 53,204
---------------------------------------------------------------------------
---------------------------------------------------------------------------

The accompanying notes are an integral part of these financial statements


Welton Energy Corporation
Consolidated Statement of Operations and Deficit (Unaudited)
(in thousands of dollars, except per share amounts)

Three months ended Nine months ended
September 30 September 30
2006 2005 2006 2005
---------------------------------------------------------------------------

Revenues
Production $ 4,215 $ 2,642 $ 11,496 $ 5,089
Royalty expense
(net of ARTC) (1,084) (433) (2,389) (532)
Other income 19 15 121 41
---------------------------------------------------------------------------
3,150 2,224 9,228 4,598
---------------------------------------------------------------------------

Expenses
Depletion, depreciation and
accretion 2,133 1,315 5,572 2,645
Production 844 745 2,981 1,857
General and administrative 488 397 1,559 832
Interest, financing and bank
charges (note 11) 305 177 868 177
---------------------------------------------------------------------------
3,770 2,634 10,980 5,511
---------------------------------------------------------------------------

Income (loss) before income
tax (620) (410) (1,752) (913)
Provision for (recovery of)
income taxes
Current 57 - 137 -
Future (178) 122 (435) (1,662)
---------------------------------------------------------------------------

Net loss (499) (532) (1,454) 749

Deficit, beginning of period (3,653) (2,910) (2,698) (4,191)
---------------------------------------------------------------------------
Deficit, end of period $ (4,152) $ (3,442) $ (4,152) $ (3,442)
---------------------------------------------------------------------------
---------------------------------------------------------------------------

Net (loss) income per common
share :
- basic (note 8) $ (0.01) $ (0.02) $ (0.04) $ 0.03
- diluted (note 8) $ (0.01) $ (0.02) $ (0.04) $ 0.03
---------------------------------------------------------------------------

The accompanying notes are an integral part of these financial statements


Welton Energy Corporation

Consolidated Statement of Cash Flows (Unaudited)
(in thousands of dollars)

Three months ended Nine months ended
September 30 September 30
2006 2005 2006 2005
---------------------------------------------------------------------------
Cash flows related to the
following activities:

Operating
(Loss) income $ (499) $ (532) $ (1,454) $ 749
Add items not requiring
cash:
Depletion, depreciation
and accretion 2,133 1,315 5,572 2,645
Future income taxes
(recoveries) (178) 122 (435) (1,662)
Stock based compensation 94 6 245 15
Non-cash financing charges
and other 69 - 174 -
---------------------------------------------------------------------------
Funds flow 1,619 911 4,102 1,747
Asset retirement
expenditures (7) - (40) -
Changes in non-cash working
capital relating
to operating activities 1,111 680 (196) (996)
---------------------------------------------------------------------------
2,723 1,591 3,866 751
---------------------------------------------------------------------------

Financing
Issuance of common shares,
net (note 8) - - 119 1,250
Issuance of notes - 10,500 - 10,500
Repayment of notes (note 7) - - (10,500) -
Issuance of flow-through
shares, net 3,781 - 3,781 987
Issuance of convertible
debentures (note 7) - - 10,500 -
Deferred financing charges - (139) -
Increase (Decrease) in bank
loan (2,517) 810 - 810
---------------------------------------------------------------------------
1,264 11,310 3,761 13,547
---------------------------------------------------------------------------

Investing
Oil and natural gas
property expenditures (4,573) (4,208) (12,616) (7,177)
Corporate acquisitions
(note 3) - (9,685) (981) (9,685)
Changes in non-cash
investing working capital 1,021 - 2,364 106
---------------------------------------------------------------------------
(3,552) (13,893) (11,233) (16,756)
---------------------------------------------------------------------------

Net increase (decrease) in
cash 435 (992) (3,606) (2,458)

Cash, beginning of period - 1,176 4,041 2,642
---------------------------------------------------------------------------
Cash, end of period $ 435 $ 184 $ 435 $ 184
---------------------------------------------------------------------------
---------------------------------------------------------------------------

Supplementary information:
---------------------------------------------------------------------------
Interest paid $ 232 $ 58 $ 637 $ 58
---------------------------------------------------------------------------
Taxes paid $ - $ - $ - $ -
---------------------------------------------------------------------------

The accompanying notes are an integral part of these financial statements



Notes to the Consolidated Financial Statements (Unaudited)

(All amounts in thousands of Canadian dollars, unless otherwise stated)

1. Basis of Presentation

The consolidated financial statements include the accounts of Welton Energy Corporation ("Welton" or "the Company") and its wholly-owned subsidiaries.

2. Summary of Significant Accounting Policies

The Company's principal business activity is in the exploration, development and production of petroleum and natural gas in Western Canada.

The financial statements have been prepared by management in accordance with Canadian Generally Accepted Accounting Principles. The interim unaudited consolidated financial statements have been prepared following the same accounting policies and methods of computation as the consolidated financial statements for the fiscal year ended December 31, 2005. The disclosures included below are incremental to those included with the annual consolidated financial statements. The interim consolidated financial statements should be read in conjunction with the audited consolidated financial statements and the notes thereto in the Company's annual report for the year ended December 31, 2005.

3. Acquisitions

On February 9, 2006 Welton acquired all of the issued and outstanding securities of a private company for total cash consideration of $981 including positive working capital. Welton has accounted for the acquisition using the purchase method of accounting.



The allocation of the purchase price to the fair value of the assets
acquired and liabilities assumed is as follows:

Consideration:
Cash $ 959
Transaction costs 22
---------------------------------------------------------------------------
$ 981
---------------------------------------------------------------------------
Allocation of purchase price:
Undeveloped land $ 1,024
Working capital 9
Future income tax liability (52)
---------------------------------------------------------------------------
$ 981
---------------------------------------------------------------------------

4. Property, Plant and Equipment

---------------------------------------------------------------------------
September 30, 2006 December 31, 2005
---------------------------------------------------------------------------
Petroleum and natural gas properties $ 36,568 $ 28,170
Land and seismic 12,317 9,937
Production equipment 12,051 9,106
Other 277 196
---------------------------------------------------------------------------
61,213 47,409
---------------------------------------------------------------------------
Accumulated depletion and depreciation (10,780) (5,263)
---------------------------------------------------------------------------
$ 50,433 $ 42,146
---------------------------------------------------------------------------
---------------------------------------------------------------------------


The calculation of the 2006 depletion and depreciation excludes $11,383 for undeveloped properties, $3,303 for major development projects, and $411 for the estimated salvage value of production equipment.

5. Asset Retirement Obligation

The asset retirement obligation was estimated by management based on the present value at the credit adjusted risk-free rate of 8.5% of the Company's share of its wells, estimated costs to abandon and reclaim those wells and the estimated timing of the costs to be incurred in future periods. The undiscounted estimated cash flow required to settle the obligation is $2,212 (2005 - $851). These costs are expected to be incurred over 35 years.



---------------------------------------------------------------------------
Balance, December 31, 2005 $ 860
---------------------------------------------------------------------------
Increase in liability during period 62
Obligations settled (13)
Accretion expense 18
---------------------------------------------------------------------------
Balance, March 31, 2006 $ 927
---------------------------------------------------------------------------
Increase in liability during period 24
Obligations settled (20)
Accretion expense 19
---------------------------------------------------------------------------
Balance, June 30, 2006 $ 950
---------------------------------------------------------------------------
Increase in liability during period 76
Obligations settled (7)
Accretion expense 18
---------------------------------------------------------------------------
Balance, September 30, 2006 $ 1,037
---------------------------------------------------------------------------
---------------------------------------------------------------------------


6. Bank Loan

At September 30, 2006, the Company has banking arrangements which were completely undrawn with a Canadian chartered bank for a $6,400 demand loan facility. The demand loan facility bears interest at bank prime rate plus 0.25%, and is secured by a $25,000 fixed charge Debenture and a floating charge over all assets of the Company.

7. Convertible Debentures

On February 27, 2006, the Company issued $10,500 principal amount of 8% secured Convertible Debentures. Interest is paid quarterly in arrears. The debentures are convertible at the option of the holder at any time into fully paid common shares at a conversion price of $1.55 per share. After July 15, 2007 and with the consent of any holder controlling directly or indirectly more than 25% of the outstanding Convertible Debentures, the Convertible Debentures will be redeemable by the Corporation in the event that the weighted average trading price of the Common Shares on the Toronto Stock Exchange exceeds $2.06 for a period of 20 days, on payment of a price equal to par plus any accrued and unpaid interest up to and not including the date of redemption. The debentures mature on January 15, 2009. The proceeds of this offering were used to repay the $10,500 note payable to Brompton Financial Limited ("BFL"), a related party.

The Convertible Debentures have been classified as debt, net of the fair value of the conversion feature at the date of issue, which has been classified as part of shareholders' equity. The value of the debt was calculated as the present value of the principal and interest payments with the remainder of the value attributed to the conversion feature and recorded as equity. The debt portion will accrete up to the principal balance at maturity. Issue costs have been classified under deferred financing charges and are being amortized based on the term of the Debentures. The accretion, amortization of issue costs and the interest paid are expensed within "interest, financing and bank charges" in the consolidated statement of operations. If the debentures are converted into common shares, that portion of the value of the conversion feature within shareholders' equity will be reclassified to Share Capital along with the principal amount converted. The following table sets forth a reconciliation of the debenture activity.



Debt Equity Principal
Portion Portion Total Outstanding
---------------------------------------------------------------------------
February 27, 2006 Issuance $ 10,068 $ 432 $ 10,500 $ 10,500
Accretion 14 - 14 -
Conversion to common shares - - - -
---------------------------------------------------------------------------
Balance, March 31, 2006 10,082 432 10,514 10,500
---------------------------------------------------------------------------
Accretion 37 - 37 -
Conversion to common shares - - - -
---------------------------------------------------------------------------
Balance, June 30, 2006 $ 10,119 $ 432 $ 10,551 $ 10,500
---------------------------------------------------------------------------
Accretion 38 - 38 -
Conversion to common shares - - - -
---------------------------------------------------------------------------
Balance, September 30, 2006 $ 10,157 $ 432 $ 10,589 $ 10,500
---------------------------------------------------------------------------
---------------------------------------------------------------------------

8. Share Capital

Authorized
An unlimited number of common shares with no par value.

Number of Shares Amount
---------------------------------------------------------------------------
Balance, December 31, 2005 38,503 $ 29,763
---------------------------------------------------------------------------
Issue of common shares on exercise of warrants 157 125
Issue of flow-through common shares 3,301 4,000
Share issue costs, net of future tax effect of $73 - (153)
Tax effect of flow-through share renunciations - (2,922)
---------------------------------------------------------------------------
Balance, September 30, 2006 41,961 $ 30,813
---------------------------------------------------------------------------
---------------------------------------------------------------------------


On August 2006, the Company issued 2,040 common shares at $1.25 per share, which are eligible for Canadian Exploration Expenses on a flow-through basis. In addition, the Company issued 1,261 common shares at $1.15 per share, which are eligible for Canadian Development Expenses on a flow-through basis. Total net proceeds for both offerings, after agents' fees and issue costs, was $3,781. Employees and directors subscribed to a combined total for 1,293 of these flow-through shares.

The following table shows the basic and diluted weighted average shares outstanding for the three and nine month periods ended September 30, 2006 and 2005:



Three months ended Nine months ended
September 30 September 30
2006 2005 2006 2005
---------------------------------------------------------------------------
Basic weighted average common shares 39,759 30,162 39,021 26,254
---------------------------------------------------------------------------
Diluted weighted average common shares 40,905 31,804 40,151 27,175
---------------------------------------------------------------------------


A total of 1,635 options were excluded from the diluted calculations as they were anti-dilutive. The impact of the convertible debentures has also been excluded from the diluted calculations as it is anti-dilutive.

The following table is a continuity of the outstanding common share warrants:



Number of Shares Amount
---------------------------------------------------------------------------
Common Share Warrants
Balance, December 31, 2005 2,136 $ -
---------------------------------------------------------------------------
Warrants exercised (157) -
Expiry of warrants - -
---------------------------------------------------------------------------
Balance, September 30, 2006 1,979 $ -
---------------------------------------------------------------------------
---------------------------------------------------------------------------


On August 4, 2005, pursuant to the acquisition of Infiniti Resources International Ltd. the Company issued 1,979 warrants. These warrants are exercisable at $1.75 per common share until August 4, 2007.

9. Stock Option Plan

Under the Stock Option Plan, the Board of Directors may grant to any director, officer, employee or consultant, options to acquire common shares up to 10% of the outstanding common shares of the Company. Options vest at the discretion of the Board and the term shall not exceed five years from the date of grant.



A summary of the changes and the Company's outstanding options is
presented below.

Weighted Average
Number Exercise Price
---------------------------------------------------------------------------
Outstanding, December 31, 2005 2,835 $0.88
---------------------------------------------------------------------------
Granted 780 1.23
Exercised - -
Cancelled (180) 1.29
---------------------------------------------------------------------------

Outstanding, September 30, 2006 3,435 $0.94
---------------------------------------------------------------------------
---------------------------------------------------------------------------

A summary of the options outstanding under the Company's Option Plan as at
September 30, 2006 is as follows:

Weighted
average
Ranges of Options remaining Weighted average
exercise price outstanding term (years) Exercisable exercise price
---------------------------------------------------------------------------
$0.27 - $0.40 1,150 2.1 1,025 $0.35
$0.95 - $1.18 970 3.5 370 $1.00
$1.20 - $1.50 1,315 3.9 373 $1.44
---------------------------------------------------------------------------
$0.27 - $1.50 3,435 3.4 1,768 $0.72
---------------------------------------------------------------------------
---------------------------------------------------------------------------


The following weighted average assumptions were used for options granted in 2006: average expected volatility of 50%, average risk free interest rate of 4% and expected life of five years. The weighted average fair value of options granted during the year was $0.61 per share.

10. Related-Party Transactions

During the nine month period ended September 30, 2006, directors and officers of the Company have been granted 530 (2005 - 840) stock options under the Stock Option Plan.

Certain management functions of the Company have been provided by Brompton Limited ("BL"), the parent company of BFL. This includes the provision of certain senior management functions, certain accounting and administrative staff, office space, supplies and office equipment. Pursuant to this arrangement, BL is entitled to recover costs in providing these services. For the three and nine month periods ended September 30, 2006, costs of $22 (2005 - $42) and $77 (2005 - $113) respectively were charged by BL. For the note payable (see Note 7) the Company has paid interest of $95 and loan and stand-by fees of $70 in 2006 to BFL. Of the above amounts, $5 (2005 - $22) was payable to BFL and BL at September 30, 2006.

All related-party transactions were recorded at the exchange amount in 2006 and 2005.



11. Interest and Financing Charges

The following table outlines the components within interest and financing
charges.

Three months ended Nine months ended
September 30 September 30
---------------------------------------------------------------------------
2006 2005 2006 2005
---------------------------------------------------------------------------
Interest and loan fees on bridge and
bank loans 23 177 211 177
Interest on debentures 212 - 495 -
Amortization of debenture issue costs 32 - 73 -
Accretion of debentures 38 - 89 -
---------------------------------------------------------------------------
Total interest and financing charges 305 177 868 177
---------------------------------------------------------------------------
---------------------------------------------------------------------------


12. Commitments

The Company has an obligation to incur $4,000 of qualifying expenditures by the end of 2007, to meet its August 2006 flow-through share obligations. The Company had an obligation to incur qualifying expenditures totaling $7,999 during 2006, for its December 2005 flow through share issuance, to meet its flow-through share obligations. As at September 30, 2006, the Company has satisfied this entire obligation.

13. Reclassification

Certain information provided for prior periods has been reclassified to conform to the presentation adopted in 2006.



ABBREVIATIONS

bbl barrel
bbls barrels
bcf billion cubic feet
bbls/d barrels per day
boe barrels of oil equivalent
boe conversion ratio 6 mcf to 1 bbl
boe/d barrels of oil equivalent per day
mbbls thousand barrels
mboe thousand barrels of oil equivalent
mcf thousand cubic feet
mcf/d thousand cubic feet per day
mcfe/d thousand cubic feet equivalent per day
mmbtu million British thermal units
mmcf million cubic feet
mmcf/d million cubic feet per day
mmcfe/d million cubic feet equivalent per day
NGL natural gas liquids
WTI West Texas Intermediate at Cushing, Oklahoma



Contact Information