Welton Energy Corporation
TSX : WLT
TSX : WLT.DB

Welton Energy Corporation

November 14, 2007 09:00 ET

Welton Energy Corporation Announces 2007 Third Quarter Financial and Operating Results

CALGARY, ALBERTA--(Marketwire - Nov. 14, 2007) - Welton Energy Corporation (TSX:WLT)(TSX:WLT.DB) is pleased to present its financial and operating results for the three and nine months ended September 30, 2007.



Operational and Financial Highlights

Three months Nine months
ended ended
September 30 Change September 30 Change
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2007 2006 % 2007 2006 %
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Average Daily Production
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Crude oil (bbls/d)
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Heavy oil 298 589 (49) 378 542 (30)
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Light oil 26 24 8 35 29 21
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Natural gas
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liquids (bbls/d) 59 50 18 62 57 9
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Natural gas (Mcf/d) 1,938 1,931 - 1,976 1,954 1
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Total (boe/d)(2) 706 985 (28) 805 954 (16)
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Wells completed (gross/net)
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Natural Gas 2/0.4 1/0.3 3/0.7 5/1.4
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Oil 4/1.7 3/1.5 6/2.1 8/2.6
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Dry 1/1 3/1.4 1/1 7/2.7
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Total 7/3.1 7/3.2 10/3.8 20/6.7
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Undeveloped land holdings
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Gross acres 121,363 145,978 (17)
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Net acres 49,199 55,938 (12)
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Oil and gas
revenues ($000s) 2,774 4,215 (34) 9,804 11,496 (15)
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Funds flow from
operations(1) ($000s) 588 1,612 (64) 2,862 4,062 (30)
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Per share - basic ($) 0.01 0.04 (75) 0.06 0.11 (45)
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Per share - diluted ($) 0.01 0.04 (75) 0.06 0.10 (40)
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Income (loss) ($000s) (1,053) (499) 140 (2,557) (1,454) 86
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Per share - basic ($) (0.02) (0.01) 200 (0.06) (0.04) 50
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Per share - diluted ($) (0.02) (0.01) 200 (0.06) (0.04) 50
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Capital expenditures
($000s) 2,433 4,573 (47) 5,238 13,597 (61)
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Shares outstanding (000s)
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Weighted average
- basic 46,527 39,759 17 44,403 39,021 14
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Weighted average
- diluted 46,527 39,759 17 44,403 39,021 11
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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.


Message to Shareholders

We are pleased to report on the Company's operations for the nine months ended September 30, 2007 and to date. Management's Discussion and Analysis of the Company's financial results for the third quarter of 2007 is provided with the comparative financial statements for the period.

Key Achievements to Date in 2007:

- Current production is approximately 950 boe/d, up from Q3 average of 706 boe/d.

- Drilled ten wells; eight successful and seven placed on production.

- Placed the Chime 9-36 deep basin gas well on production.

- Drilled five successful wells at Mantario, one at 100%, three at 25% and one at 12.5%. All have been placed on production.

- Drilled a successful well at Ricinus which was placed on production at the end of October.

- Earned a 50% interest in 27 sections of land through the drilling of one potential gas well and one dry hole in Jensen.

- Drilled and cased the first of a three well commitment in Trutch.

Production

Current daily production is approximately 950 boe/d which is up from Q3's average of 706 boe/d. As previously advised, current production levels at Mantario were down from those projected prior to the placing on production of the recent new drills in the area. Other similar infill locations are being evaluated for drilling. The partners have agreed to implement an injectivity test program for the field to determine how best to proceed with a pressure maintenance project. Pressure maintenance along with both infill and step out drilling are expected to maintain and increase current production levels. Approximately 55% of the Company's total production is Saskatchewan heavy oil and 45% is light oil, natural gas and associated liquids in Alberta. The Company realized prices of $42.54 per barrel of oil equivalent during the third quarter.

Saskatchewan

Mantario

Welton and its partners have drilled six wells in Mantario to date in 2007. All but one of these wells were successful and have been placed on production. This drilling, in particular one well which was drilled 100% by Welton, has resulted in the restoration of Welton's production from this area to its prior levels. As mentioned, additional infill/development locations have been identified and locations will be proposed to the partners in due course. Agreement by the partners to commence injectivity testing is a positive step in further development of this field.

British Columbia

Trutch

Welton previously announced finalization of a farm in agreement on 19 sections of land in the Trutch Area of British Columbia. This area is a multi zone natural gas prospect. A gas pipeline runs through our agreement lands. The first of three planned wells in this area has been drilled and cased. Additional drilling will be considered after completion and evaluation of the results of the initial three well program.

Alberta

Chime

The Chime 9-36 location was placed on production during the quarter and is currently producing at just over 1 mmcf/d (33 boe net). As previously discussed, this well is a deep basin tight gas project in which Welton owns a 20% working interest in 5,760 acres, covered by 3D seismic. Additional locations have been identified and drilling will be considered at such time as natural gas prices improve and we fully understand the impact of Alberta's new royalty regime on this type of activity, details of which are yet to be announced.

Ricinus

Welton participated in the drilling, casing and completion of a well at Ricinus (net 16% working interest). The well was placed on production from the Lower Cardium zone at the end of October at a rate of over 35 boe/d. Additional locations will be considered for drilling based on performance of the new well, gas prices and a complete understanding of the new Alberta royalty structure.

Boundary Lake

This project is being readied for activity this winter. Plans to drill are being evaluated in the context of lower gas prices and the new Alberta royalty schedule.

Brazeau River Waterflood Project

This Nisku I pool project (94.75% interest) continues to perform within the parameters of our model. Gradual increases in oil production accompanied by a lower gas/oil ratio indicates that the oil is approaching the perforations in the well bore. Work is being undertaken to increase the rate of water injection to increase the speed of this process. We are evaluating the impact of the proposed new royalty regulations on this project.

Mergers

As previously discussed, the Company remains active in the merger/acquisition market.

Outlook

The Company has an exciting portfolio of projects on which activity is planned during the remainder of this year and beyond. Projects exist in the three provinces of Saskatchewan, British Columbia and Alberta with a mix of both oil and natural gas targets.

The Alberta government has recently announced proposed changes to royalties payable on all Crown mineral rights. These proposals, if enacted on January 1, 2009 as announced, will have effects on the Company's net operating income. The nature and extent of these royalty changes cannot be fully determined, as complete information has not yet been released by the government, and these changes are dependent on oil and gas prices and volumes at the time, as well as depth of wells.

The government has announced their intention to introduce royalty incentives for deep gas wells but until this announcement is made we are unable to assess the impact on our deep gas production at Chime, Ricinus and Karr.

Currently, approximately 55% of our production is in the province of Saskatchewan, and therefore not subject to the Alberta royalty changes.

With respect to oil production, we expect net operating revenues from our Brazeau waterflood project will be negatively impacted. Based on the highest projected daily production from Brazeau, added to our current production, and using current pricing estimates, the negative impact on total company net operating income could be 6%.

Our future activity in Alberta and elsewhere will be managed to deal effectively with the proposed changes.

Respectfully submitted on behalf of the Board of Directors:

Signed by Donald A. Engle

Donald A. Engle, President and Chief Executive Officer

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 month periods ended September 30, 2007 and 2006 and should be read in conjunction with the unaudited financial statements and accompanying notes included in this report and the December 31, 2006 and 2005 audited financial statements and accompanying notes included in the Company's 2006 Annual Report. This discussion and analysis is based on information available to November 7, 2007. 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 principals ("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 (e.g. a chart depicting daily production volumes by month) can be found on its website at www.weltonenergy.com or through the SEDAR system at www.sedar.com.

Third Quarter 2007 - Summary and Outlook

Although Welton had a poor quarter in terms of production volumes and funds flow the Company has now seen three consecutive months of increased production as a result of initiatives implemented. Welton estimates current production to be 950 boe/d, which is up from the Q3 average of 706 boepd.

These increases have resulted from:

- The drilling of a successful 100% owned well in Mantario

- The drilling of two successful 25% W.I. wells at Mantario

- The successful implementation of production optimization procedures at Mantario

A fourth Mantario well, an exploration well, in which the Company had a 100% W.I., was unsuccessful.

Two more wells were drilled in the quarter; one was placed on production at the beginning of October and the second one is due to commence production by early November.

Also in Q3, the Company entered two new areas. At Trutch, preparations were undertaken for the drilling of a three well commitment. The first well was spud in the last week of October. At Jensen, the Company entered into a two well program which also began in October, in which the Company earned a 50% interest in 27 sections of land through the drilling of one potential gas well and one dry hole.

Production

The following table sets out the average daily production values:



Three Nine
months ended months ended
September 30 Change September 30 Change
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2007 2006 (%) 2007 2006 (%)
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Crude oil (bbl/d)
---------------------------------------------------------------------------
Heavy oil 298 589 (49) 378 542 (30)
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Light oil 26 24 8 35 29 21
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Natural gas
liquids (bbl/d) 59 50 18 62 57 9
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Natural gas (mcf/d) 1,938 1,931 - 1,976 1,954 1
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Total boe/d 706 985 (28) 805 954 (16)
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For the third quarter of 2007, the Company produced a total of 706 boe/d from over 50 wells in Alberta and Saskatchewan. Heavy and light crude oil production represented 46% of total production while natural gas and associated natural gas liquids represented the remaining 54%. The heavy oil production comes from the Company's heavy oil field in Mantario, Saskatchewan. The decrease in production from this area can be attributed to the operator's deferral of activity required to maintain production in heavy oil pools to offset reservoir performance issues. Welton took the lead in correcting this by drilling 3 gross (1.5 net) successful wells in this area that began producing in late August and September 2007. Current heavy oil production is averaging over 450 bbl/d. The Company is continuing to evaluate the feasibility of a pressure maintenance program for the field. Pressure maintenance along with additional infill and step out drilling is expected to maximize current production levels. The Company is hopeful that agreement between all working interest owners in the field will be reached soon and that water injection will commence in the near future.

For the nine months ended September 30, 2007 production averaged 805 boe/d, a decrease of 16% from production of 954 boe/d for the first nine months of 2006. As discussed above, this decrease is due to lower production from the Company's heavy oil property at Mantario, which is partially offset by increases in light oil and natural gas liquids. Production for the third quarter of 2007 was also 7% lower than the second quarter of 2007 which was 760 boe/d primarily due to the closure of the Brazeau facility for 11 days and the Karr facility for the month of July.

Commodity Prices

The following table represents relevant quarterly average commodity price benchmarks:



Three Nine
months ended months ended
September 30 Change September 30 Change
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2007 2006 (%) 2007 2006 (%)
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Crude Oil
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West Texas Intermediate
("WTI" - US$/bbl) 75.38 70.44 7 66.07 68.05 (3)
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Hardisty Heavy oil
(Cdn$/bbl) 47.43 51.55 (8) 44.28 45.14 (2)
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Natural Gas
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AECO (Cdn$/Mcf) 5.25 5.61 (6) 6.77 6.38 6
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Overall crude oil prices remained strong during the third quarter with an average WTI price of US$75.38/bbl, up 7% from $70.44/bbl during the same period last year. As production is traded in US currencies, any strengthening of the Canadian dollar has an adverse impact on revenue. For the first three quarters, the increased strength of the Canadian dollar has offset much of the gain in crude oil prices over the last year. Heavy oil prices decreased 8% to $47.43/bbl versus $51.55/bbl in the prior year. This reflects a widening of the heavy oil differential in addition to the impact of a stronger Canadian dollar relative to the US dollar compared to the third quarter of 2006. Benchmark natural gas prices (AECO Hub in Alberta) for the third quarter have dropped 6%, from $5.61/mcf in 2006 to $5.25/mcf in 2007.

Year to date crude oil prices for 2007 were 3% lower than those seen during the first three quarters of 2006. WTI averaged US$66.07/bbl compared to US$68.05/bbl during 2006. Heavy oil prices were 2% lower during the first three quarters of 2007 at $44.28/bbl compared to $45.14/bbl during the same period of 2006. Natural gas prices for the first nine months of 2007 averaged 6% higher than 2006.



Average Realized Three Nine
Sales Prices months ended months ended
September 30 Change September 30 Change
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2007 2006 (%) 2007 2006 (%)
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Heavy oil ($/bbl) 43.46 51.19 (15) 41.53 44.13 (6)
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Light oil ($/bbl) 83.16 82.48 1 71.31 72.81 (2)
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Natural gas ($/Mcf) 5.55 5.48 1 6.93 6.57 5
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Natural gas liquids ($/bbl) 70.76 61.16 16 63.78 59.16 8
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Total ($/boe) 42.54 46.48 (8) 44.56 44.07 1
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The Company's average realized price for heavy oil was $43.46/bbl for the third quarter which was slightly lower than the comparable benchmark Heavy Hardisty oil price of $47.43/bbl. The variance is due largely to quality differences and the increased cost of diluent. The realized natural gas price for the third quarter was $5.55/mcf which was slightly higher than the average AECO price for the quarter. The decreases in heavy oil prices compared to the third quarter of 2006 were slightly offset by an increase in realized light oil, natural gas and associated liquids prices resulting in total average realized sales prices of $42.54/boe, a decrease of 8% from 2006.

Year to date total realized sales prices were $44.56/boe which is 1% higher than the same period of 2006. This was mostly attributable to increases in realized natural gas and natural gas liquids prices compared to 2006.



Revenue

Production Revenue Three Nine
months ended months ended
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September 30 Change September 30 Change
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($ thousands) 2007 2006 (%) 2007 2006 (%)
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Heavy oil 1,192 2,775 (57) 4,290 6,465 (34)
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Light oil 198 181 9 691 582 19
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Natural gas 990 974 2 3,736 3,503 7
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Natural gas liquids 382 283 35 1,076 924 16
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Total(1) 2,762 4,213 (34) 9,793 11,474 (15)
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(1)Total production revenue excludes sulphur revenue.


For the three months ended September 30, 2007 the Company's production revenue decreased 34% to $2,762 versus $4,213 for the same period of 2006. The decrease in total revenue can be attributed mainly to lower heavy oil production volumes as well as lower heavy oil prices. Heavy oil revenues from Welton's Mantario property were $1,192 compared to $2,775 in the third quarter of the prior year due to decreases in both volumes and prices as discussed above.

Production revenue for the first nine months of 2007 was $9,793 compared to $11,474 in the first three quarters of 2006. Again, the decrease was mostly due to the decreased heavy oil revenues offset partially by increased light oil, natural gas and NGL revenues.

Royalties

Royalties for the Company include all royalties to provincial governments, freeholders and other overriding royalties, and during 2006 were net of the Alberta Royalty Tax Credit (ARTC), a tax rebate that was received from the Alberta government for eligible crown royalties paid. The ARTC was eliminated by the Alberta government effective January 1, 2007. Therefore, 2006 was the final year that Welton received the ARTC credit and its elimination contributed to an increase in the 2007 royalty rate of 7%. As a percentage of revenue, the third quarter royalty rate was 23% compared to 26% for the same quarter in 2006 as a result of prior period capital cost adjustments, eliminating the increases seen by the elimination of the ARTC. The year to date royalty rate was 22% compared to 21% during 2006.

The impact of the proposed new royalty regime is discussed below under "Royalty Regime".



Operating expenses

2007 2006
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($/boe) Q3 Q2 Q1 Q4 Q3 Q2 Q1
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Operating expenses $14.27 $10.92 $10.13 $8.74 $9.31 $11.88 13.27
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Unit operating expenses were $14.27/boe for the third quarter of 2007, an increase of 53% compared to the third quarter of 2006 and an increase of 31% from the second quarter of 2007. Lower production volumes contributed to total fixed costs being distributed amongst relatively smaller production volumes, resulting in higher per boe operating costs for the quarter. Decreased operating costs due to operational efficiencies achieved at the Mantario property were partially offset by increased fixed operating costs from closures at the Brazeau and Karr facilities in the third quarter of 2007 versus the third quarter of 2006. Additionally, the new production from Karr, representing approximately 20% of our total volumes, has significantly higher operating costs for condensate handling and third party gas processing, due to the liquids rich and sour gas production involved.



Three Nine
months ended months ended
Netbacks September 30 Change September 30 Change
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($/boe) 2007 2006 (%) 2007 2006 (%)
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Oil, NGL and natural
gas revenue 42.54 46.48 (8) 44.56 44.07 1
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Royalty expense
(net of ARTC) (9.71) (11.96) (19) (9.79) (9.17) 7
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Production expenses (14.27) (9.31) 53 (11.59) (11.45) 1
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Netback 18.56 25.21 (26) 23.18 23.45 (1)
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Royalty as percentage
of revenue (%) 23 26 (12) 22 21 5
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For the third quarter 2007, the Company realized a netback of $18.56/boe representing a 26% decrease versus $25.21/boe during the same period in 2006. Revenue decreases on a per boe basis were primarily a result of lower heavy oil prices. The reduction in the netback due to lower prices was partially offset by lower royalties but significantly higher operating costs per boe had a major negative impact on third quarter netbacks. Total royalties decreased in proportion to the decrease in revenues. Royalty rates per boe decreased primarily as a result of the reduction in heavy oil pricing in Mantario, causing a decrease in the overall royalty rate in Saskatchewan. Operating expenses were $14.27/boe during the third quarter of 2007 compared to $9.31/boe in the same quarter of 2006.

The Company realized a netback of $23.18/boe for the first nine months of 2007 compared to $23.45/boe for the same period of 2006. The increase in the year to date netback due to higher prices was partially offset by higher operating costs and royalty expenses.



General and Administrative

Three Nine
months ended months ended
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September 30 Change September 30 Change
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($ thousands, except
per boe amounts) 2007 2006 (%) 2007 2006 (%)
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General and administrative 542 472 15 1,519 1,536 (1)
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Overhead recoveries and
capitalized overhead (87) (78) 12 (219) (222) (1)
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Net 455 394 15 1,300 1,314 (1)
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Per boe $7.01 $4.35 61 $5.91 $5.05 17
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Stock-based compensation
expense 95 94 1 267 245 9
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Per boe $1.46 $1.03 42 $1.22 $0.94 30
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Total expense 550 488 13 1,567 1,559 1
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Total per boe $8.47 $5.38 57 $7.12 $5.99 19
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Net general and administrative costs (excluding non-cash stock-based compensation expense) totalled $455 for the third quarter of 2007 compared to $394 during the same quarter of 2006. The increase was due primarily to staff recruitment charges incurred to obtain new personnel in the third quarter. Overhead recoveries and capitalized overhead of $87 were recognized in the third quarter of 2007 which is an increase of 12% (2006 - $78) 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. Net general and administrative expenses for the nine months ended September 30, 2007 were $1,300 or 1% lower than 2006.

For the third quarter of 2007, on a per boe basis, general and administrative expenses (excluding non-cash stock-based compensation) increased by 61% to $7.01 per boe from $4.35 per boe in 2006 due primarily to lower production volumes and one-time administrative costs associated with the recruitment of new staff, as the majority of total administrative costs remained relatively constant. Year to date costs, on a per boe basis, were $5.91 per boe compared to $5.05 per boe during 2006 as lower overall costs were offset by lower production volumes.

Stock-based compensation expense is the amortization over the vesting period of the fair value of stock options granted to employees, directors and certain 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 months ended September 30, 2007 was $95 compared to $94 for the same period in 2006. During the third quarter of 2007, 165,000 stock options were granted. Year to date stock based compensation expense was $267 compared to $245 during the same period of 2006.



Interest and Financing Charges

Three Nine
months ended months ended
September 30 Change September 30 Change
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($ thousands) 2007 2006 (%) 2007 2006 (%)
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Interest and loan fees
on bridge and bank loans 4 23 (83) 59 211 (72)
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Interest on debentures 212 212 - 628 495 27
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Amortization of
debenture issue costs 32 32 - 95 73 30
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Accretion of debentures 38 38 - 112 89 26
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Total interest and
financing charges 286 305 (6) 894 868 3
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Interest and financing charges totaled $894 for the first three quarters of 2007 compared to $868 for the same period of 2006, an increase of 3%. A decrease in interest on the bridge loan was offset by an increase in debenture interest. During the first quarter of 2006, and therefore impacting the nine months ended September 30, 2006, $172 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. Interest of $628 was paid on the Company's convertible debentures compared to $495 in 2006 (the debentures were issued in February 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.



Depreciation, Depletion and Accretion

Three Nine
months ended months ended
September 30 Change September 30 Change
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($ thousands, except
per boe amounts) 2007 2006 (%) 2007 2006 (%)
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Depletion and depreciation 1,839 2,115 (13) 6,105 5,517 11
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Per boe $28.29 $23.34 21 $27.75 $21.19 31
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Accretion expense 34 18 89 108 55 96
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Per boe $ 0.52 $ 0.20 160 $ 0.49 $ 0.22 123
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For the quarter ending September 30, 2007, depletion and depreciation expense for the Company's oil and gas properties amounted to $1,839 (2006 - $2,115) or $28.29 (2006 - $23.34) per boe. Overall dollar decreases for depletion expense were attributed to lower production volumes. The higher depletion rate per boe is primarily a result of adding higher cost proved reserve additions than in previous periods and adjustments to estimates 2007 relating to Q2.

Accretion expense for the quarter ended September 30, 2007 was $34 compared to $18 for the same quarter of 2006. The year to date accretion expense is $108 compared to $55 during 2006. The quarterly and the year to date accretion expenses have increased significantly compared to the prior year due to the increase in the asset retirement obligation. At September 30, 2007, the Company has recorded an asset retirement obligation of $1,676 (2006 - $1,037). This amount is the net present value of the total future un-inflated asset retirement costs of $2,306 (2006 - $2,212). 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 primarily due to wells added from drilling as well as revisions to the estimated abandonment costs and the timing of abandonment activities that were recognized during the fourth quarter of 2006. Also, increasing costs from oil field service providers contributed to the increased obligation. The asset retirement obligation has increased from $1,246 at December 2006 due to the addition of liabilities for new wells drilled in 2007 as well as new facilities added at Karr during the first quarter.

Income Taxes

The Company has $18 (2006 - $57) in current income tax expense for the third quarter. The year to date current tax expense was $73 compared to $137 for 2006. These current taxes relate to Saskatchewan resource surcharge. The decrease from the prior year is due to decreased revenues from the Company's Mantario heavy oil field in Saskatchewan. The Company has no other current income taxes because it has the ability to utilize its tax pools and non-capital loss carryforwards. The approximate resource tax pool balances remaining at September 30, 2007, notwithstanding renouncements discussed under Contractual Obligations, are estimated to be $45,840.

Net Loss

Net loss for the three months ended September 30, 2007 was $1,053 versus $499 in 2006. Compared to the prior year, lower realized prices and production volumes and the resulting lower revenue as well as higher operating costs were partially offset by lower royalties and a larger future income tax recovery and resulted in a greater net loss compared to the prior year. The net loss for the nine months ended September 30, 2007 was $2,557 compared to $1,454 for the nine months ended September 30, 2006. Lower production revenue from lower production volumes as well as higher depletion expense were partially offset by lower royalties and operating costs and a larger future income tax recovery and resulted in an overall greater net loss compared to 2006.



Capital Expenditures

Three Nine
months ended months ended
September 30 Change September 30 Change
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($ thousands, except
per boe amounts) 2007 2006 (%) 2007 2006 (%)
---------------------------------------------------------------------------
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Exploration drilling 1,383 2,441 (43) 2,252 5,161 (56)
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Development drilling 571 528 8 783 3,741 (79)
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Production equipment 295 665 (56) 1,133 2,280 (50)
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Land and seismic 156 887 (82) 990 1,274 (22)
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Corporate acquisitions - - - - 981 (100)
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Other 28 52 (46) 80 160 (50)
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Total 2,433 4,573 (47) 5,238 13,597 (61)
---------------------------------------------------------------------------
---------------------------------------------------------------------------


For the third quarter of 2007, a total of $2,433 in capital was spent versus $4,573 for 2006. During the third quarter, $1,383 was spent on exploration drilling; the majority of which was for the drilling of the 14-6 Ricinus oil well that began drilling in August, the completion of the 9-36 Chime well that began drilling during June 2007, and the drilling of a dry hole at Mantario. Spending on developmental drilling totaled $571 for the third quarter. The majority of this was for the drilling of three successful oil wells in Mantario.

During the third quarter of the prior year the Company's capital expenditures were mostly for the drilling of three exploration wells at Mantario, an exploration well at Chime, developmental drilling of heavy oil wells in Saskatchewan and costs related to the re-completion of the Karr 16-19 well. Year to date capital expenditures were $5,238 compared to $13,597 during the first nine months of 2006. During the prior year, total capital expenditures included $981 for corporate acquisitions representing the purchase of a private oil and gas company, the principal assets of which were high working interest exploration lands in Saskatchewan and Alberta.

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 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 2006 or to date in 2007 and 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 offset against the convertible debenture balance and are being amortized to interest and financing charges over the life of the debentures.

Flow-through Equity Financings

On May 10, 2007 the Company completed an equity financing arrangement on a "bought-deal" basis. The Company issued, on a private placement basis, 2,967 common shares on a "flow-through" basis eligible for Canadian Exploration Expenses (the "Flow-Through Shares") at a price of $0.86 per Flow-Through Share for total gross proceeds of $2,552. On April 30, 2007, and in addition to the "bought-deal" financing, the Company issued to insiders, management and acquaintances a total of 1,599 Flow-Through Shares at a price of $0.86 per Flow-Through Common Share for total gross proceeds of $1,375.

Note Financings and Banking Facility

At September 30, 2007, the Company had in place banking arrangements for a $7,000 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. As at September 30, 2007, a total of $1,855 was drawn on the facility compared to a balance of $1,325 at December 31, 2006.

For the third quarter of 2007 the Company's sources of cash totalled $2,443 versus cash requirements of $3,577, and as of September 30, 2007 the cash on hand was $NIL. The Company intends to finance the remainder of its $2,800 planned capital program through funds generated from operations, its current credit facility and possible flow-through financings completed during the fourth quarter.

Royalty Regime

On October 25, 2007, the Alberta government released the details of new royalty framework in response to the Alberta Royalty Review Panel's report. Although the government has committed to implementing certain elements of this report, we do not have sufficient information to determine the full impact on those changes.

The effect of the Alberta royalty rate changes on Welton will be determined based on the actual legislation enacted, the production rates, commodity prices and product mix after January 1, 2009. Future royalties and taxes payable, as well as the determination of the net conventional reserves, will likely be affected based on the Company's interpretation of the publicly available information to date.



Funds Flow

Three Nine
months ended months ended
September 30 Change September 30 Change
---------------------------------------------------------------------------
($ thousands) 2007 2006 (%) 2007 2006 (%)
---------------------------------------------------------------------------
---------------------------------------------------------------------------
Sources
---------------------------------------------------------------------------
Funds flow from operations 588 1,612 (64) 2,862 4,062 (30)
---------------------------------------------------------------------------
Issue of common shares, net - - - - 119 (100)
---------------------------------------------------------------------------
Issuance of convertible
debentures - - - - 10,500 (100)
---------------------------------------------------------------------------
Issuance of flow-through
shares, net - 3,781 (100) 3,707 3,781 (2)
---------------------------------------------------------------------------
Increase in bank loan 1,855 - - 530 - -
---------------------------------------------------------------------------
Working capital - 2,132 (100) - 2,168 (100)
---------------------------------------------------------------------------
---------------------------------------------------------------------------
2,443 7,525 (68) 7,099 20,630 (66)
---------------------------------------------------------------------------
---------------------------------------------------------------------------
Uses
---------------------------------------------------------------------------
Oil and natural gas
property expenditures 2,433 4,573 (47) 5,238 12,616 (58)
---------------------------------------------------------------------------
Repayment of notes - - - - 10,500 (100)
---------------------------------------------------------------------------
Working capital 1,144 - - 1,861 - -
---------------------------------------------------------------------------
Deferred financing charges - - - - 139 (100)
---------------------------------------------------------------------------
Decrease in bank loan - 2,517 (100) - - -
---------------------------------------------------------------------------
Acquisitions - - - - 981 (100)
---------------------------------------------------------------------------
---------------------------------------------------------------------------
3,577 7,090 (50) 7,099 24,236 (71)
---------------------------------------------------------------------------
---------------------------------------------------------------------------
(Decrease)/Increase
in cash (1,134) 435 (360) - (3,606) (100)
---------------------------------------------------------------------------
---------------------------------------------------------------------------


Working Capital

On September 30, 2007, the Company had negative working capital of $4,839 versus negative working capital of $6,171 at December 31, 2006.

Contractual Obligations

The Company has obligations to renounce qualifying tax deductions under the flow-through share agreements it has entered into. The Company had an obligation to incur qualifying expenditures totaling $2,599 during 2007 to meet the flow-through share obligations resulting from its August 2006 flow-through share issuance. As at September 30, 2007 the Company has satisfied all of this obligation. As a result of the May flow-through financing mentioned above the Company has until the end of 2008 to incur additional qualifying expenditures totaling $3,927 to meet its flow-through share obligations.

Off-Balance Sheet Arrangements

The Company has no off-balance sheet arrangements.

Changes in Accounting Policies - Financial Instruments

In April 2005, the Canadian Accounting Standards Board issued new Handbook Sections 1530 "Comprehensive Income", 3855 "Financial Instruments - Recognition and Measurement", and 3865 "Hedges". Under these new standards, all financial assets should be measured at fair value with the exception of loans, receivables, and investments that are held to maturity and certain equity investments, which should be measured at cost. Similarly, all financial liabilities should be measured at fair value when they are held for trading or they are derivatives. Gains and losses on financial instruments measured at fair value will be recognized in the income statements in the periods they arise with the exception of gains and losses arising from:

- Financial assets held for sale, for which unrealized gains and losses are deferred in other comprehensive income until sold or impaired; and

- Certain financial instruments that qualify for hedge accounting.

Other comprehensive income comprises revenues, expenses, gains and losses that are recognized in comprehensive income, but are excluded from net income. Unrealized gains and losses on financial instruments held for sale will be included in other comprehensive income and reclassified to net income when realized. Comprehensive income and its components will be a required disclosure under the new standards. These standards have been adopted by Welton as of January 1, 2007 on a prospective basis. These new Canadian requirements did not have a significant impact on the Company's financial statements. Under the new standards deferred financing charges of $163 have been netted against the convertible debentures and are no longer presented separately on the balance sheet.

Controls and Procedures

Disclosure Controls

The Company has designed disclosure controls and procedures to provide reasonable assurance that material information relating to the Company is made known to management by others within the Company, particularly during the period in which the annual filings are being prepared. Disclosure controls and procedures are designed to provide reasonable assurance that all relevant information is gathered and reported to management, including the Chief Executive Officer ("CEO") and the Acting Vice President, Finance and Chief Financial Officer ("VP Finance"), on a timely basis so appropriate decisions can be made regarding public disclosure. A control system, no matter how well designed or operated, has inherent limitations. Therefore, these systems provide reasonable, but not absolute, assurance that the objectives of the control system are met.

The Company's CEO and VP Finance have evaluated the effectiveness of the Company's disclosure controls and procedures as of November 7, 2007 and based on that evaluation these officers have concluded that the Company's disclosure controls and procedures were effective to provide reasonable assurance that information required to be disclosed by the Company in reports it files or submits under applicable securities legislation is recorded, processed, summarized and reported within the time periods as required and made known to them on a timely basis.

Internal Control over Financial Reporting

Our management is responsible for establishing and maintaining adequate internal control over financial reporting as defined in Multi-lateral Instrument 52-109 - Certification of Issuers' Annual and Interim Filings. Our internal controls over financial reporting are designed to provide reasonable assurance regarding the reliability of our financial reporting and preparation of our financial statements for external reporting purposes in accordance with accounting principles generally accepted in Canada. Our internal controls over financial reporting include those policies and procedures that: pertain to the maintenance of records that in reasonable detail accurately and fairly reflect our transactions and disposition of assets; provide reasonable assurance that transactions are recorded as necessary to permit preparation of our financial statements in accordance with generally accepted accounting principles; receipts and expenditures of our assets are being made only in accordance with authorizations of our management and directors; and provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use or disposition of our assets that could have a material effect on our financial statements. Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements.

During the third quarter, staffing changes were made to the accounting department, including the addition of certain senior accounting personnel. These changes have not affected, nor are reasonably likely to materially affect, the Company's internal control over financial reporting during the three or nine month periods ended September 30, 2007. Management anticipates improvements in future control systems through an augmented segregation of incompatible duties and an increase in the technical accounting knowledge to address any complex and non-routine accounting transactions that may arise.



Selected Quarterly Financial Information

2007 2006 2005
---------------------------------------------------------------------------
($thousands,
except per
share amounts) Q3 Q2 Q1 Q4 Q3 Q2 Q1 Q4
---------------------------------------------------------------------------
---------------------------------------------------------------------------
Production
revenue 2,774 3,194 3,836 3,760 4,215 3,884 3,397 4,316
---------------------------------------------------------------------------
Net income
(loss) (1,053) (593) (911) (1,045) (499) (314) (641) 744
---------------------------------------------------------------------------
Per share amounts:
---------------------------------------------------------------------------
Basic
Net income
(loss) (0.02) (0.01) (0.02) (0.02) (0.01) - (0.02) 0.01
---------------------------------------------------------------------------
Diluted
Net income
(loss) (0.02) (0.01) (0.02) (0.02) (0.01) - (0.02) 0.01
---------------------------------------------------------------------------
Funds flow 588 1,220 1,055 1,094 1,612 1,588 862 1,284
---------------------------------------------------------------------------
Per share amounts:
---------------------------------------------------------------------------
Basic
Funds flow 0.01 0.03 0.03 0.03 0.04 0.04 0.02 0.04
---------------------------------------------------------------------------
Diluted
Funds flow 0.01 0.03 0.03 0.03 0.04 0.04 0.02 0.04
---------------------------------------------------------------------------
---------------------------------------------------------------------------


Welton Energy Corporation
Consolidated Balance Sheet (Unaudited)
(in thousands of dollars)


September 30, 2007 December 31, 2006
----------------------------------------------------------------------------
Assets

Current assets

Cash $ - $ -

Accounts receivable 2,487 3,057

Other assets 177 185
----------------------------------------------------------------------------
2,664 3,242

Property, plant and equipment (note 4) 49,983 50,267
Deferred financing charges (notes 3 and 7) - 259
----------------------------------------------------------------------------
$ 52,647 $ 53,768
----------------------------------------------------------------------------
----------------------------------------------------------------------------

Liabilities

Current liabilities

Accounts payable and accrued liabilities $ 5,648 $ 8,088

Bank loan (note 6) 1,855 1,325
----------------------------------------------------------------------------
7,503 9,413

Convertible debentures (note 7) 10,143 10,195
Future tax liability 912 966
Asset retirement obligation (note 5) 1,676 1,246
----------------------------------------------------------------------------
20,234 21,820
Shareholders' equity
Share capital (note 8) 33,570 30,815
Equity component of debentures (note 7) 432 432
Contributed surplus 6,165 5,898

Deficit (7,754) (5,197)
----------------------------------------------------------------------------
32,413 31,948

----------------------------------------------------------------------------
$ 52,647 $ 53,768
----------------------------------------------------------------------------
----------------------------------------------------------------------------

The accompanying notes are an integral part of these financial statements


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

Three months ended Nine months ended
September 30 September 30

2007 2006 2007 2006
----------------------------------------------------------------------------

Revenues

Production $ 2,774 $ 4,215 $ 9,804 $11,496

Royalty expense (net of ARTC) (630) (1,084) (2,152) (2,389)

Other income 31 19 80 121
----------------------------------------------------------------------------
2,175 3,150 7,732 9,228
----------------------------------------------------------------------------

Expenses

Depletion, depreciation and
accretion 1,873 2,133 6,213 5,572
Production 926 844 2,549 2,981
General and administrative 550 488 1,567 1,559
Interest, financing and bank
charges (note 11) 286 305 894 868
----------------------------------------------------------------------------
3,635 3,770 11,223 10,980
----------------------------------------------------------------------------

Income (loss) before income taxes (1,460) (620) (3,491) (1,752)
Provision for (recovery of)
income taxes

Current 18 57 73 137

Future (425) (178) (1,007) (435)
----------------------------------------------------------------------------

Net income (loss) and other
comprehensive loss (1,053) (499) (2,557) (1,454)

Deficit, beginning of period (6,701) (3,653) (5,197) (2,698)
----------------------------------------------------------------------------
Deficit, end of period $(7,754) $(4,152) $(7,754) $(4,152)
----------------------------------------------------------------------------
----------------------------------------------------------------------------

Net loss per common share:

- basic (note 8) $ (0.02) $ (0.01) $ (0.06) $ (0.04)
- diluted (note 8) $ (0.02) $ (0.01) $ (0.06) $ (0.04)
----------------------------------------------------------------------------

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

2007 2006 2007 2006
----------------------------------------------------------------------------
Cash flows related to the
following activities:

Operating

Net Income (loss) $(1,053) $ (499) $(2,557) $(1,454)

Add items not requiring cash:
Depletion, depreciation and
accretion 1,873 2,133 6,213 5,572
Future income taxes (recoveries) (425) (178) (1,007) (435)
Stock-based compensation 95 94 267 245
Non-cash financing charges and other 70 69 207 174
Asset retirement expenditures 28 (7) (261) (40)
----------------------------------------------------------------------------
Funds flow 588 1,612 2,862 4,062
Changes in non-cash working capital
relating to operating activities (1,463) 1,111 (2,519) (196)
----------------------------------------------------------------------------
(875) 2,723 343 3,866
----------------------------------------------------------------------------

Financing
Issuance of common shares, net (note 8) - - - 119
Repayment of notes (note 7) - - - (10,500)
Issuance of convertible debentures
(note 7) - - - 10,500
Issuance of flow-through shares, net
(note 8) - 3,781 3,707 3,781
Deferred financing charges - - - (139)
Increase (decrease) in bank loan 1,855 (2,517) 530 -
----------------------------------------------------------------------------
1,855 1,264 4,237 3,761
----------------------------------------------------------------------------

Investing
Oil and natural gas property
expenditures (2,433) (4,573) (5,238) (12,616)
Corporate acquisitions - - - (981)
Changes in non-cash investing
working capital 319 1,021 658 2,364
----------------------------------------------------------------------------
(2,114) (3,552) (4,580) (11,233)
----------------------------------------------------------------------------

Net increase (decrease) in cash (1,134) 435 - (3,606)

Cash, beginning of period 1,134 - - 4,041
----------------------------------------------------------------------------
Cash, end of period $ - $ 435 $ - $ 435
----------------------------------------------------------------------------
----------------------------------------------------------------------------

Supplementary information:
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Interest paid $ 213 $ 232 $ 685 $ 637
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Taxes paid $ 274 $ - $ 287 $ -
----------------------------------------------------------------------------
----------------------------------------------------------------------------

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, 2006, except as noted below. 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, 2006.

3. Changes in Accounting Policies - Financial Instruments

Effective January 1, 2007 Welton adopted the new Handbook Sections 1530 "Comprehensive Income", 3855 "Financial Instruments - Recognition and Measurement", and 3865 "Hedges" on a prospective basis. Under these new standards, all financial assets should be measured at fair value with the exception of loans, receivables, and investments that are held to maturity and certain equity investments, which should be measured at cost. Similarly, all financial liabilities should be measured at fair value when they are held for trading or they are derivatives. Gains and losses on financial instruments measured at fair value will be recognized in the income statements in the periods they arise with the exception of gains and losses arising from:

- Financial assets held for sale, for which unrealized gains and losses are deferred in other comprehensive income until sold or impaired; and

- Certain financial instruments that qualify for hedge accounting.

Other comprehensive income comprises revenues, expenses, gains and losses that are recognized in comprehensive income, but are excluded from net income. Unrealized gains and losses on financial instruments held for sale will be included in other comprehensive income and reclassified to net income when realized. Comprehensive income and its components are required disclosures under the new standards.

These new Canadian requirements did not have a significant impact on the Company's financial statements. Under the new standards deferred financing charges of $163 have been netted against the convertible debentures and are no longer presented separately on the balance sheet.



4. Property, Plant and Equipment

----------------------------------------------------------------------------
September 30, 2007 December 31, 2006
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Petroleum and natural gas properties $ 41,071 $ 37,506
----------------------------------------------------------------------------
Land and seismic 13,513 12,442
----------------------------------------------------------------------------
Production equipment 14,449 13,263
----------------------------------------------------------------------------
Other 277 278
----------------------------------------------------------------------------
----------------------------------------------------------------------------
69,310 63,489
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Accumulated depletion and depreciation (19,327) (13,222)
----------------------------------------------------------------------------
$ 49,983 $ 50,267
----------------------------------------------------------------------------
----------------------------------------------------------------------------


The calculation of the 2007 depletion and depreciation excludes $7,132 (2006 - $11,383) for undeveloped properties and includes $3,454 (2006 - $4,664) for future development capital. General and administrative costs of $174 (2006 - $207) were capitalized during 2007.

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 $2,306 (2006 - $2,102). These costs are expected to be incurred over 35 years.



----------------------------------------------------------------------------
----------------------------------------------------------------------------
Balance, December 31, 2006 $ 1,246
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Increase in liability during period 78
----------------------------------------------------------------------------
Obligations settled (249)
----------------------------------------------------------------------------
Changes in estimates 340
----------------------------------------------------------------------------
Accretion 40
----------------------------------------------------------------------------
Balance, March 31, 2007 $ 1,455
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Obligations settled (40)
----------------------------------------------------------------------------
Changes in estimates 41
----------------------------------------------------------------------------
Accretion 34
----------------------------------------------------------------------------
Balance, June 30, 2007 $ 1,490
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Increase in liability during period 69
----------------------------------------------------------------------------
Obligations settled 28
----------------------------------------------------------------------------
Changes in estimates 55
----------------------------------------------------------------------------
Accretion 34
----------------------------------------------------------------------------
Balance, September 30, 2007 $ 1,676
----------------------------------------------------------------------------
----------------------------------------------------------------------------


6. Bank Loan

At September 30, 2007, the Company had in place banking arrangements for a $7,000 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. At September 30, 2007, $1,855 was drawn on the facility.

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 a price of $1.55 and mature on January 15, 2009.



Debt Deferred Total Debt Equity Principal
Portion Financing Portion Portion Outstanding
----------------------------------------------------------------------------
February 27,
2006
Issuance $ 10,068 $ - $ 10,068 $ 432 $ 10,500
----------------------------------------------------------------------------
Accretion 127 - 127 - -
----------------------------------------------------------------------------
Balance,
December
31, 2006 10,195 - 10,195 432 10,500
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Change in
accounting
policy - (259) (259) - -
----------------------------------------------------------------------------
Accretion 37 - 37 - -
----------------------------------------------------------------------------
Amortization - 31 31 - -
----------------------------------------------------------------------------
Balance, March
31, 2007 10,232 (228) 10,004 432 10,500
----------------------------------------------------------------------------
Accretion 37 - 37 - -
----------------------------------------------------------------------------
Amortization - 32 32 - -
----------------------------------------------------------------------------
Balance, June
30, 2007 10,269 (196) 10,073 432 10,500
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Accretion 38 - 38 - -
----------------------------------------------------------------------------
Amortization - 32 32 - -
----------------------------------------------------------------------------
Balance,
September 30,
2007 $ 10,307 $ (164) $ 10,143 $ 432 $ 10,500
----------------------------------------------------------------------------
----------------------------------------------------------------------------


8. Share Capital

Authorized

An unlimited number of common shares with no par value.

Number of Shares Amount
----------------------------------------------------------------------------
Balance, December 31, 2006 41,961 $ 30,815
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Tax effect of flow-through share renunciations - (1,023)
----------------------------------------------------------------------------
Issue of flow-through common shares 4,566 3,927
----------------------------------------------------------------------------
Share issue costs, net of future tax effect of $70 - (149)
----------------------------------------------------------------------------
Balance, September 30, 2007 46,527 $ 33,570
----------------------------------------------------------------------------
----------------------------------------------------------------------------


On May 10, 2007 the Company completed an equity financing arrangement on a "bought-deal" basis. The Company issued, on a private placement basis, 2,967 common shares on a "flow-through" basis eligible for Canadian Exploration Expenses (the "Flow-Through Shares") at a price of $0.86 per Flow-Through Share for total gross proceeds of $2,552. On April 30, 2007, and in addition to the "bought-deal" financing, the Company issued to insiders, management and close personal friends a total of 1,599 Flow-Through Shares at a price of $0.86 per Flow-Through Common Share for total gross proceeds of $1,375.

The following table shows the basic and diluted weighted average shares outstanding for the three and Nine month periods ended September 30, 2007 and 2006:



Three months ended Nine months ended
September 30 September 30
2007 2006 2007 2006
----------------------------------------------------------------------------
Basic weighted average common shares 46,527 39,759 44,403 39,021
----------------------------------------------------------------------------
Diluted weighted average common shares 46,527 39,759 44,403 39,021
----------------------------------------------------------------------------


The Company's stock options and convertible debentures have been excluded from the diluted calculations as the Company is in a loss position and the impact would be anti-dilutive.

Common Share Warrants

On August 4, 2005, pursuant to the acquisition of Infiniti Resources International Ltd. the Company issued 1,979 warrants. These warrants were exercisable at $1.75 per common share until August 4, 2007 when they expired. All warrants expired unexercised on 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, 2006 3,808 $ 0.93
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Granted - -
----------------------------------------------------------------------------
Exercised - -
----------------------------------------------------------------------------
Cancelled (87) 1.00
----------------------------------------------------------------------------


Weighted Average
Number Exercise Price
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Outstanding, March 31, 2007 3,721 $ 0.93
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Granted 60 $ 0.85
----------------------------------------------------------------------------
Exercised - -
----------------------------------------------------------------------------
Cancelled - -
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Outstanding, June 30, 2007 3,781 $ 0.92
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Granted 165 $ 0.64
----------------------------------------------------------------------------
Exercised - -
----------------------------------------------------------------------------
Cancelled (76) $ 1.03
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Outstanding, September 30, 2007 3,870 $ 0.91
----------------------------------------------------------------------------
----------------------------------------------------------------------------


A summary of the options outstanding under the Company's Option Plan as at
September 30, 2007 is as follows:

Weighted
average
Ranges of Options remaining Weighted average
exercise price outstanding term (years) Exercisable exercise price
----------------------------------------------------------------------------
----------------------------------------------------------------------------
$ 0.27 - $0.64 1,315 1.6 1,150 $ 0.35
----------------------------------------------------------------------------
$ 0.85 - $1.18 1,315 3.2 670 $ 0.99
----------------------------------------------------------------------------
$ 1.20 - $1.50 1,240 2.9 755 $ 1.43
----------------------------------------------------------------------------
----------------------------------------------------------------------------
$ 0.27 - $1.50 3,870 2.5 2,575 $ 0.84
----------------------------------------------------------------------------
----------------------------------------------------------------------------


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
----------------------------------------------------------------------------
----------------------------------------------------------------------------
2007 2006 2007 2006
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Interest and loan fees on bridge
and bank loans 4 23 59 211
----------------------------------------------------------------------------
Interest on debentures 212 212 628 495
----------------------------------------------------------------------------
Amortization of debenture issue costs 32 32 95 73
----------------------------------------------------------------------------
Accretion of debentures 38 38 112 89
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Total interest and financing charges $ 286 $ 305 $ 894 $ 868
----------------------------------------------------------------------------
----------------------------------------------------------------------------


12. Commitments

The Company had an obligation to incur $2,599 of qualifying expenditures by the end of 2007, to meet its August 2006 flow-through share obligations. As at September 30, 2007, the Company had satisfied all of this obligation.

The Company also has an obligation to incur $3,927 of qualifying expenditures by the end of 2008 to meet its April and May 2007 flow-through share obligations. As at September, 2007, the Company satisfied $1,127 of this obligation.

13. Reclassification

Certain information provided for prior periods has been reclassified to conform to the presentation adopted in 2007.

Contact Information

  • Welton Energy Corporation
    Donald A. Engle
    President and Chief Executive Officer
    (403) 215-4747
    or
    Welton Energy Corporation
    Giles Twogood
    Acting Vice President, Finance
    (403) 215-4750
    Website: www.weltonenergy.com