Welton Energy Corporation
TSX : WLT
TSX : WLT.DB

Welton Energy Corporation

August 09, 2007 18:47 ET

Welton Energy Corporation Announces 2007 Second Quarter Financial and Operating Results

CALGARY, ALBERTA--(Marketwire - Aug. 9, 2007) - Welton Energy Corporation (TSX:WLT) (TSX:WLT.DB) is pleased to present its financial and operating results for the three and six months ended June 30, 2007.



Operational and Financial Highlights

Three months Six months
ended ended
June 30 Change June 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 300 522 (43) 419 518 (19)
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Light oil 28 30 (7) 40 32 25
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Natural gas liquids (bbls/d) 97 47 106 63 61 3
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Natural gas (Mcf/d) 2,012 1,782 13 1,995 1,965 2
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Total (boe/d)(2) 760 895 (15) 855 938 (9)
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Wells completed (gross/net)
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Natural Gas - - - 2/0.9
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Oil - 1/0.3 2/0.4 5/1.2
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Dry - 2/0.5 1/0.2 3/1.0
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Total - 3/0.8 3/0.6 10/3.1
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Undeveloped land holdings
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Gross acres 132,159 140,724
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Net acres 49,765 44,679
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Oil and gas revenues ($000s) 3,194 3,884 (18) 7,030 7,281 (3)
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Funds flow from operations(1)
($000s) 1,220 1,588 (23) 2,274 2,450 (7)
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Per share - basic ($) 0.03 0.04 (25) 0.05 0.06 (17)
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Per share - diluted ($) 0.03 0.04 (25) 0.05 0.06 (17)
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Income (loss) ($000s) (593) (314) 89 (1,504) (955) 57
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Per share - basic ($) (0.01) - - (0.03) (0.02) 50
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Per share - diluted ($) (0.01) - - (0.03) (0.02) 50
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Capital expenditures ($000s) 1,470 2,433 (40) 2,805 9,024 (69)
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Shares outstanding (000s)
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Weighted average - basic 44,673 38,659 43,324 38,639
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Weighted average - diluted 44,673 38,659 43,324 38,639
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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 six months ended June 30, 2007 and to date. Management's Discussion and Analysis of the Company's financial results for the second quarter of 2007 is provided with the comparative financial statements for the period.

Key Achievements to Date in 2007

- Drilled and cased one exploratory well at Chime.

- Drilled four successful wells at Mantario. Two were placed on production in March 2007 and the other two are currently being placed on production.

- Placed a re-completed well on stream at Karr in late March 2007. Production is expected to average 175 boe/d (net) from this well.

- Added significant new natural gas prospect at Trutch, British Columbia with plans to drill 3 wells this fall.

- Completed 3D seismic program at Eatonia which has identified new opportunities.

- Funds flow of $1.2 million compared to $1.1 million in Q1 2007.

Production

Welton's average production for the second quarter of 2007 was 760 boe/d. As previously advised, current production levels at Mantario are down from those projected. We believe this is a combination of spring breakup related issues, which prevented access to wellsites for performance of routine maintenance, delaying of drilling by the operator and reservoir performance. The partners are evaluating the feasibility of implementing a pressure maintenance program for the field. We are hopeful that this program can be started soon. Pressure maintenance along with both infill and step out drilling are expected to increase current production levels. Drilling of two wells took place in July, both of which were successful and they are currently being placed on production. Approximately 39% of the Company's total production is heavy oil and 61% is light oil, natural gas and associated liquids. The Company realized prices of $46.16 per barrel of oil equivalent during the second quarter.

Alberta

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. Welton will participate in the drilling of three wells this summer/fall, paying 75% of drill and case costs to earn a 45% working interest. The Company will also pay 100% of the first $550,000 of seismic acquisition on the prospect. A larger winter drilling program is planned for this winter, dependent on success of the three well program.

Boundary Lake

This project is being readied for activity this fall, timing dependent on access availability. Seismic will be shot to finalize possible locations prior to drilling this winter. Winter 2006 drilling by competitors resulted in three nearby wells being cased and one being placed on production.

Brazeau River Waterflood Project

This Nisku I pool project (94.75% interest) continues to perform according to our model. Response to the waterflood was detected in December 2006, and oil production at low initial rates commenced prior to year end and continues with no material change. Current production rates are approximately 75 boe/d. We are monitoring the gas to oil ratio to ensure it reaches the correct level prior to increasing production rates to the projected level of 300 boe/d.

Chime

The Chime 9-36 location was drilled to total depth of 3.334 metres and cased for several prospective gas zones. Completion operations on three zones are underway and preliminary results are encouraging. A follow-up location has been licensed and drilling is expected in the third quarter contingent on successful completion operations at 9-36.

Karr

The tie-in of a previously drilled liquids-rich sour gas well occurred at the end of March this year. This well has provided net production rates to Welton of approximately 140 boe/d and facility work planned for the third quarter should increase this to 175 boe/d. Welton holds a 20.5% revenue interest and paid 10% of the tie in costs.

Saskatchewan

Mantario

Welton and its partners have drilled four wells in Mantario to date in 2007. All of these wells were successful with two wells being placed on production in late March, and the other two currently being placed on production. Additional drilling is planned dependent on satisfactory sustained production capabilities of the new wells. Also, as mentioned, we are hopeful for an early start to a pressure maintenance program.

Additional Crown lands have been posted in the area by a competitor, and a well license issued, with drilling anticipated to be timed to the land sale which is scheduled for August 2007.

Eatonia

A 3D seismic program following up drilling done in this area during late 2006 has recently been completed and interpreted. New drilling locations have been identified.

Dankin

Acquisition of additional 2D seismic has been acquired and reprocessed along with existing 2D seismic, in total amounting to 110 kilometers. Several areas of interest were identified for further work. If the drilling at Eatonia is successful, a 3D program will be extended into this area to enhance identified drilling opportunities.

Financing

Welton successfully completed $4 million of financings in the second quarter, comprised of a $2.6 million bought deal flow-through financing on May 10, 2007. Concurrently, a non-brokered financing on the same terms as the bought deal financing for $1.4 million was closed on April 30, 2007.

Outlook

The Company has an exciting portfolio of projects on which activity is planned during the remainder of this year and beyond.

We anticipate continuation of the infill drilling program at Mantario in the near future and hope for an early start to pressure maintenance in the field. New seismic data has identified interesting drilling opportunities on our 100% owned lands in Saskatchewan. Drilling of three wells at Trutch, where Welton will pay 75% of the costs to drill and case three wells to earn a 45% working interest, is planned to start in late August. Success with this program will lead to a larger exploration program this winter. As a result of the positive results from our new well at Chime, Alberta, additional drilling is expected to commence in the third quarter. A well at Ricinus is slated to be drilled in the third quarter. Welton holds a 16% working interest in the well.

Welton continues to be active in reviewing corporate and property acquisition opportunities that will complement its existing assets. Welton's Board and Management 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:

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 six month periods ended June 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 August 8, 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 can be found on its website at www.weltonenergy.com or through the SEDAR system at www.sedar.com.

Second Quarter 2007 - Summary and Outlook

The second quarter of 2007 was a challenging one for Welton. Production volumes were negatively impacted by spring break up conditions as well as reservoir performance issues at the Company's Mantario heavy oil field in Saskatchewan. These decreased production volumes negatively impacted a significant portion of the Company's per boe metrics including netbacks, operating costs and general and administrative costs. Average realized prices were also lower in the second quarter as compared to the prior year. However, overall funds flow from operations totaled $1,220 which is slightly higher than the previous quarter's $1,055. To address the reservoir performance issues at Mantario, the Company began an infill and step out drilling program early in the third quarter and anticipates continuing this program. Welton hopes to commence pressure maintenance in the Mantario field in the near future. During the second quarter the Company entered into a 19 section joint venture agreement in the prospective natural gas area of Trutch in northeastern British Columbia. Activity is expected to commence at Trutch in late August. Late in the second quarter Welton participated in the drilling of a non-operated well in the Company's Chime area. Drilling was completed during July and the well was cased to total depth to evaluate potential gas reservoirs in three zones. Completion activities are currently underway. The Company was also successful in completing a $4,000 flow through equity financing during the second quarter.



Production

The following table sets out the average daily production values:

Three months Six months
ended ended
June 30 Change June 30 Change
2007 2006 (%) 2007 2006 (%)
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Crude oil (bbl/d)
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Heavy oil 300 522 (43) 419 518 (19)
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Light oil 28 30 (7) 40 32 25
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Natural gas liquids (bbl/d) 97 47 106 63 61 3
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Natural gas (mcf/d) 2,012 1,782 13 1,995 1,965 2
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Total boe/d 760 895 (15) 855 938 (9)
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For the second quarter of 2007, the Company produced a total of 760 boe/d from over 50 wells in Alberta and Saskatchewan. Heavy and light crude oil production represented 43% of total production while natural gas and associated natural gas liquids represented the remaining 57%. The heavy oil production comes from the Company's heavy oil field in Mantario, Saskatchewan. The decrease in production from this area was partially due to wet field conditions at Mantario which began in the first quarter of 2007 and continued into the second quarter. The wet field conditions hampered the operators' ability to move equipment onto the wells to fix operational problems. Also contributing to the decrease in production from the Company's Mantario heavy oil pool are reservoir performance issues. The Company is currently evaluating the feasibility of a pressure maintenance program for the field. Pressure maintenance along with both infill and step out drilling are expected to correct the current situation. 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. Drilling in this area commenced early in the third quarter. The increase in natural gas and associated liquids compared to the second quarter of 2006 was due largely to production from two new wells at Karr, the 10-15 and the 13-19.

For the six months ended June 30, 2007 production averaged 855 boe/d, a decrease of 9% from production of 938 boe/d for the first six months of 2006. As discussed above, this decrease is due to lower production from the Company's heavy oil property at Mantario. Production for the second quarter of 2007 was also 20% lower than the first quarter of 2007 which was 951 boe/d; again due to lower heavy oil production from the Company's Mantario property.

Commodity Prices

The following table represents relevant quarterly average commodity price benchmarks:


Three months Six months
ended ended
June 30 Change June 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$/bbl) 64.94 70.36 (8) 61.41 66.85 (8)
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Hardisty Heavy oil (Cdn$/bbl) 42.95 53.23 (19) 42.73 41.94 2
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Natural Gas
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AECO (Cdn$/Mcf) 7.13 6.00 19 7.27 6.77 7
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Overall crude oil prices remained strong during the second quarter with an average WTI price of US$64.94/bbl. However, this was down 8% from $70.36/bbl during the same period last year. Heavy oil prices decreased 19% to $42.95/bbl versus $53.23/bbl in the prior year. This reflects decreased oil prices, the impact of a stronger Canadian dollar relative to the US dollar, and a widening of the heavy oil differential compared to the second quarter of 2006. Benchmark natural gas prices (AECO Hub in Alberta) for the second quarter have risen 19%, from $6.00/mcf in 2006 to $7.13/mcf in 2007.

Year to date crude oil prices for 2007 were 8% lower than those seen during the first half of 2006. WTI averaged US$61.41/bbl compared to US$66.85/bbl during 2006. Heavy oil prices were 2% higher during the first half of 2007 at $42.73/bbl compared to $41.94/bbl during the same period of 2006. Natural gas prices for the first six months of 2007 averaged 7% higher than 2006.



Average Realized Three months Six months
Sales Prices ended ended
June 30 Change June 30 Change
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2007 2006 (%) 2007 2006 (%)
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Heavy oil ($/bbl) 41.77 51.03 (18) 40.83 40.04 2
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Light oil ($/bbl) 70.76 76.37 (7) 67.44 69.15 (2)
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Natural gas ($/Mcf) 7.36 6.17 19 7.60 7.11 7
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Natural gas liquids ($/bbl) 59.36 59.12 - 60.49 58.31 4
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Total ($/boe) 46.16 47.73 (3) 45.41 43.35 5
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The Company's average realized price for heavy oil was $41.77/bbl for the second quarter which was slightly lower than the comparable benchmark Heavy Hardisty oil price of $42.95/bbl. The variance is due largely to quality differences. The realized natural gas price for the second quarter was $7.36/mcf which was slightly higher than the average AECO price for the quarter. The decreases in light and heavy oil prices compared to the second quarter of 2006 were offset by an increase in realized natural gas prices resulting in total average realized sales prices of $46.16/boe, a decrease of 3% from 2006.

Year to date total realized sales prices were $45.41/boe which is 5% 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 months Six months
ended ended
June 30 Change June 30 Change
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($ thousands) 2007 2006 (%) 2007 2006 (%)
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Heavy oil 1,139 2,424 (53) 3,097 3,691 (16)
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Light oil 183 205 (11) 493 401 23
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Natural gas 1,348 1,001 35 2,746 2,529 9
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Natural gas liquids 524 252 108 694 640 8
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Total(1) 3,194 3,882 (18) 7,030 7,261 (3)
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(1) Total production revenue excludes sulphur revenue.


For the three months ended June 30, 2007 the Company's production revenue decreased 18% to $3,194 versus $3,882 for the same period of 2006. The decrease in total revenue can be attributed to lower heavy oil production volumes as well as lower heavy oil prices. Heavy oil revenues from Welton's Mantario property were $1,139 compared to $2,424 in the second quarter of the prior year due to decreases in both volumes and prices as discussed above.

Production revenue for the first six months of 2007 was $7,030 compared to $7,261 in the first half 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 override 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 in the year. 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 2%. As a percentage of revenue, royalties for the second quarter of both 2007 and 2006 are 16%. The year to date royalty rate was 22% compared to 18% during 2006.



Operating expenses

2006 2007
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($/boe) Q1 Q2 Q3 Q4 Q1 Q2
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Operating expenses $ 13.27 $ 11.88 $ 9.31 $ 8.74 $ 10.13 $ 10.92
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Unit operating expenses were $10.92/boe for the second quarter of 2007, a decrease of 8% compared to the second quarter of 2006 but an increase of 8% from the first 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. Per boe operating costs are lower than the same period of 2006 due mostly to lower heavy oil operating costs. Operational efficiencies have been achieved at the Mantario property and have lowered average operating costs for the second quarter of 2007 versus the second quarter of 2006. These lower per unit operating costs from the heavy oil properties were partially offset by high operating costs at the Brazeau waterflood which are expected to decrease as the production is increased towards the projected rate of 300 boe/d. Also, additional start up costs for the new Karr 10-15 well were incurred during the second quarter and contributed to higher per unit operating costs.



Three months Six months
ended ended
Netbacks June 30 Change June 30 Change
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($/boe) 2007 2006 (%) 2007 2006 (%)
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Oil, NGL and natural gas
revenue 46.16 47.73 (3) 45.41 43.35 5
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Royalty expense (net of ARTC) (7.27) (7.43) (2) (9.83) (7.69) 28
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Production expenses (10.92) (11.88) (8) (10.48) (12.59) (17)
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Netback 27.97 28.42 (2) 25.10 23.07 9
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Royalty as percentage of
revenue (%) 16 16 - 22 18 22
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For the second quarter 2007, the Company realized a netback of $27.97/boe representing a 2% decrease versus $28.42/boe during the same period in 2006. Revenue decreases on a per boe basis were primarily a result of lower heavy oil prices. The decrease in the netback due to lower prices was partially offset by lower royalties and operating costs. Royalties per boe decreased in proportion to the decrease in revenues. Operating expenses were $10.92/boe during the second quarter of 2007 compared to $11.88/boe in the same quarter of 2006.

The Company realized a netback of $25.10/boe for the first six months of 2007 compared to $23.07/boe for the same period of 2006. The 9% increase in the overall netback is largely due to the 17% decrease in operating costs.

The decreased operating costs can be attributed to the shut in of the high operating cost Karr 16-19 well during the second quarter of 2006 as well as additional operational efficiencies that were achieved at the Mantario heavy oil field during 2006 and continued into 2007. The increase in the year to date netback due to higher prices and lower operating costs was partially offset by higher royalty expenses. Royalties were higher during the first half of 2007, as compared to the first half of 2006, due to numerous factors including the elimination of the Alberta Royalty Tax Credit (ARTC) as well as prior period adjustments on non-operated properties.



General and Administrative

Three months Six months
ended ended
June 30 Change June 30 Change
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($ thousands, except
per boe amounts) 2007 2006 (%) 2007 2006 (%)
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General and administrative 507 505 - 977 1,064 (8)
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Overhead recoveries and
capitalized overhead (62) (67) (7) (132) (144) (8)
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Net 445 438 2 845 920 (8)
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Per boe $ 6.42 $ 5.37 20 $ 5.45 $ 5.42 1
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Stock-based compensation
expense 87 95 (8) 172 151 14
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Per boe $ 1.26 $ 1.17 8 $ 1.11 $ 0.89 25
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Total expense 532 533 - 1,017 1,071 (5)
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Total per boe $ 7.68 $ 6.54 17 $ 6.56 $ 6.31 4
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Net general and administrative costs (excluding non-cash stock-based compensation expense) totalled $445 for the second quarter of 2007 compared to $438 during the same quarter of 2006, remaining approximately unchanged as there were no significant changes in the nature and amount of administrative costs of the Company. Overhead recoveries and capitalized overhead of $62 were recognized in the second quarter of 2007 which is a decrease of 7% (2006 - $67) 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 six months ended June 30, 2007 were $845 or 8% lower than 2006.

For the second quarter of 2007, on a per boe basis, general and administrative expenses (excluding non-cash stock-based compensation) increased by 20% to $6.42 per boe from $5.37 per boe in 2006 due entirely to lower production volumes as the total costs remained relatively constant. Year to date costs, on a per boe basis, were $5.45 per boe compared to $5.42 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 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 months ended June 30, 2007 was $87 compared to $95 for the same period in 2006. The decrease is a function of proportionately more of the compensation expense being recorded in the first year of the options' life, with options vesting equally over a three-year period pursuant to the Company's stock option plan, as well as a lower average fair value option price. During the second quarter of 2007, 60,000 stock options were granted. Year to date stock based compensation expense was $172 compared to $151 during the same period of 2006.

The Company also utilizes the services of Brompton Group Limited ("BGL"), a related party, for certain senior management services, certain accounting and administrative staff and related expenses. For the second quarter of 2007 fees of $2 (2006 - $20) were recorded for BGL. A total of $5 (2006 - $54) was recorded during the six months ended June 30, 2007.



Interest and Financing Charges
Three months Six months
ended ended
June 30 Change June 30 Change
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($ thousands) 2007 2006 (%) 2007 2006 (%)
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Interest and loan fees on
bridge and bank loans 31 16 94 55 188 (71)
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Interest on debentures 209 209 - 416 283 47
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Amortization of debenture
issue costs 32 32 - 63 41 54
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Accretion of debentures 37 37 - 74 51 45
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Total interest and financing
charges 309 294 5 608 563 8
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The Company incurred $309 of interest and operating loan fees in the second quarter of 2007 versus $294 in the prior year. A higher amount of interest was paid on the bank loan due to a higher average outstanding loan balance during the second quarter of 2007 compared to 2006.

Interest and financing charges totaled $608 for the first half of 2007 compared to $563 for the same period of 2006, or an increase of 8%. 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 six months ended June 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 $416 was paid on the Company's convertible debentures compared to $283 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 months Six months
ended ended
June 30 Change June 30 Change
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($ thousands, except
per boe amounts) 2007 2006 (%) 2007 2006 (%)
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Depletion and depreciation 1,900 1,754 8 4,266 3,402 25
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Per boe 27.54 21.54 28 27.52 20.04 37
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Accretion expense 34 18 89 74 37 100
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Per boe 0.49 0.22 123 0.48 0.22 118
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For the quarter ending June 30, 2007, depletion and depreciation expense for the Company's oil and gas properties amounted to $1,900 (2006 - $1,754) or $27.54 (2006 - $21.54) per boe. Overall dollar increases for depletion expense were attributed to a higher depletion rate offset partially by lower production volumes. The higher depletion rate per boe is primarily a result of adding higher cost proved reserve additions than in previous periods.

Accretion expense for the quarter ended June 30, 2007 was $34 compared to $18 for the same quarter of 2006. The year to date accretion expense is $74 compared to $37 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 June 30, 2007, the Company has recorded an asset retirement obligation of $1,490 (2006 - $950). This amount is the net present value of the total future asset retirement costs of $2,163 (2006 - $2,101). 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 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 $13 (2006 - $50) in current income tax expense for the second quarter. The year to date current tax expense was $55 compared to $80 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 non-capital loss carry forwards, which as of June 30, 2007 are estimated to be $15,602. These losses will expire over four years from 2008 to 2011 and the Company expects to be able to fully utilize the losses prior to expiry.

Net Loss

Net loss for the three months ended June 30, 2007 was $593 versus $314 in 2006. Compared to the prior year, lower realized prices and production volumes and the resulting lower revenue as well as higher depletion costs were partially offset by lower royalties, operating costs and a larger future income tax recovery and resulted in a greater net loss compared to the prior year. The net loss for the six months ended June 30, 2007 was $1,504 compared to $955 for the six months ended June 30, 2006. Lower production revenue from lower production volumes as well as higher royalties and depletion expense were partially offset by lower operating costs and a larger future income tax recovery and resulted in an overall greater net loss compared to 2006.



Capital Expenditures
Three months Six months
ended ended
June 30 Change June 30 Change
----------------------------------------------------------------------------
($ thousands, except
per boe amounts) 2007 2006 (%) 2007 2006 (%)
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Exploration drilling 627 273 130 869 2,720 (68)
----------------------------------------------------------------------------
Development drilling 11 829 (99) 212 3,213 (93)
----------------------------------------------------------------------------
Production equipment 117 914 (87) 838 1,615 (48)
----------------------------------------------------------------------------
Land and seismic 692 378 83 835 387 116
----------------------------------------------------------------------------
Corporate acquisitions - 1 - - 981 -
----------------------------------------------------------------------------
Other 23 38 (39) 51 108 (53)
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Total 1,470 2,433 (40) 2,805 9,024 (69)
----------------------------------------------------------------------------
----------------------------------------------------------------------------


For the second quarter of 2007, a total of $1,470 in capital was spent versus $2,433 for 2006. During the second quarter, $627 was spent on exploration drilling; the majority of which was for the 9-36 Chime well that began drilling during June 2007. Spending on land and seismic totaled $692 for the second quarter. The majority of this was for the 3D seismic program that was shot over the Company's Eatonia prospect as well as the acquisition of additional 2D seismic covering the Company's Dankin prospect. The Dankin and Eatonia prospects are both on 100% owned lands in Saskatchewan. During the second quarter of the prior year the Company's capital expenditures were mostly for developmental wells at Mantario, an exploration well at Chime, and costs related to the Brazeau waterflood project. Year to date capital expenditures were $2,805 compared to $9,024 during the first six 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. 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 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.

Note Financings and Banking Facility

At June 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. The facility was completely undrawn at the end of the quarter compared to a balance of $1,325 at December 31, 2006.

For the second quarter of 2007 the Company's sources of cash totalled $4,928 versus cash requirements of $3,794, and as of June 30, 2007 the cash on hand was $1,134. The Company intends to finance the remainder of its $6,500 planned capital program through funds generated from operations, its current credit facility and the flow-through financings completed during the second quarter.



Funds Flow
Three months Six months
ended ended
June 30 Change June 30 Change
----------------------------------------------------------------------------
($ thousands) 2007 2006 (%) 2007 2006 (%)
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Sources
----------------------------------------------------------------------------
Funds flow from operations 1,220 1,588 (23) 2,274 2,450 (7)
----------------------------------------------------------------------------
Issue of common shares, net - - - - 119 -
----------------------------------------------------------------------------
Issuance of convertible
debentures - - - - 10,500 -
----------------------------------------------------------------------------
Issuance of flow-through
shares, net 3,708 - - 3,708 - -
----------------------------------------------------------------------------
Increase in bank loan - 2,517 - - 2,517 -
----------------------------------------------------------------------------
Working capital - - - - 36 -
----------------------------------------------------------------------------
----------------------------------------------------------------------------
4,928 4,105 20 5,982 15,622 (62)
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Uses
----------------------------------------------------------------------------
Oil and natural gas property
expenditures 1,470 2,432 (40) 2,805 8,043 (65)
----------------------------------------------------------------------------
Repayment of notes - - - - 10,500 -
----------------------------------------------------------------------------
Working capital 199 4,009 (95) 718 - -
----------------------------------------------------------------------------
Deferred financing charges - 58 - - 139 -
----------------------------------------------------------------------------
Issuance of common shares,
net - 1 - - - -
----------------------------------------------------------------------------
Decrease in bank loan 2,125 - - 1,325 - -
----------------------------------------------------------------------------
Acquisitions - 1 - - 981 -
----------------------------------------------------------------------------
----------------------------------------------------------------------------
3,794 6,501 (42) 4,848 19,663 (75)
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(Decrease)/Increase in cash 1,134 (2,396) 147 1,134 (4,041) 128
----------------------------------------------------------------------------
----------------------------------------------------------------------------


Working Capital

On June 30, 2007, the Company had negative working capital of $2,993 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 has 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 June 30, 2007 the Company has satisfied $1,761 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.

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 Group Limited ("BGL"), a related party. The types of services and fees charged are discussed in the General and Administrative costs discussion.

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 $196 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 Vice President, Finance ("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 August 8, 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.

No changes were made in our internal control over financial reporting during the three or six month period ended June 30, 2007, that have materially affected, or are reasonably likely to affect, our internal control over financial reporting.



Selected Quarterly Financial Information

2007 2006 2005
----------------------------------------------------------------------------
($thousands, except
per share amounts) Q2 Q1 Q4 Q3 Q2 Q1 Q4 Q3
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Production revenue 3,194 3,836 3,760 4,215 3,884 3,397 4,316 2,642
----------------------------------------------------------------------------
Net income (loss) (593) (911) (1,045) (499) (314) (641) 744 (532)
----------------------------------------------------------------------------
Per share amounts:
----------------------------------------------------------------------------
Basic
Net income (loss) (0.01) (0.02) (0.02) (0.01) - (0.02) 0.01 (0.02)
----------------------------------------------------------------------------
Diluted
Net income (loss) (0.01) (0.02) (0.02) (0.01) - (0.02) 0.01 (0.02)
----------------------------------------------------------------------------
Funds flow 1,220 1,055 1,094 1,612 1,588 862 1,284 911
----------------------------------------------------------------------------
Per share amounts:
----------------------------------------------------------------------------
Basic
Funds flow 0.03 0.03 0.03 0.04 0.04 0.02 0.04 0.03
----------------------------------------------------------------------------
Diluted
Funds flow 0.03 0.03 0.03 0.04 0.04 0.02 0.04 0.03
----------------------------------------------------------------------------
----------------------------------------------------------------------------


Welton Energy Corporation
Consolidated Balance Sheet (Unaudited)

(in thousands of dollars)

June 30, 2007 December 31, 2006
----------------------------------------------------------------------------

Assets

Current assets
Cash $ 1,134 $ -
Accounts receivable 2,103 3,057
Other assets 209 185
----------------------------------------------------------------------------
3,446 3,242

Property, plant and equipment (note 4) 49,264 50,267
Deferred financing charges (note 7) - 259
----------------------------------------------------------------------------
$ 52,710 $ 53,768
----------------------------------------------------------------------------
----------------------------------------------------------------------------

Liabilities

Current liabilities
Accounts payable and accrued liabilities $ 6,439 $ 8,088
Bank loan (note 6) - 1,325
----------------------------------------------------------------------------
6,439 9,413

Convertible debentures (note 7) 10,073 10,195
Future tax liability 1,337 966
Asset retirement obligation (note 5) 1,490 1,246
----------------------------------------------------------------------------
19,339 21,820

Shareholders' equity
Share capital (note 8) 33,570 30,815
Equity component of debentures (note 7) 432 432
Contributed surplus 6,070 5,898
Deficit (6,701) (5,197)
----------------------------------------------------------------------------
33,371 31,948

----------------------------------------------------------------------------
$ 52,710 $ 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 Six months ended
June 30 June 30
2007 2006 2007 2006
----------------------------------------------------------------------------

Revenues
Production $ 3,194 $ 3,884 $ 7,030 $ 7,281
Royalty expense (net of ARTC) (504) (605) (1,522) (1,305)
Other income 23 10 49 102
----------------------------------------------------------------------------
2,713 3,289 5,557 6,078
----------------------------------------------------------------------------

Expenses
Depletion, depreciation and
accretion 1,934 1,772 4,340 3,439
Production 756 968 1,623 2,137
General and administrative 532 533 1,017 1,071
Interest, financing and bank
charges (note 11) 309 294 608 563
----------------------------------------------------------------------------
3,531 3,567 7,588 7,210
----------------------------------------------------------------------------

Loss before income taxes (818) (278) (2,031) (1,132)
Provision for (recovery of) income
taxes
Current 13 50 55 80
Future (238) (14) (582) (257)
----------------------------------------------------------------------------

Net loss and other comprehensive loss (593) (314) (1,504) (955)

Deficit, beginning of period (6,108) (3,339) (5,197) (2,698)
----------------------------------------------------------------------------
Deficit, end of period $ (6,701) $ (3,653) $ (6,701) $ (3,653)
----------------------------------------------------------------------------
----------------------------------------------------------------------------

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

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 Six months ended
June 30 June 30
2007 2006 2007 2006
----------------------------------------------------------------------------
Cash flows related to the following
activities:

Operating
Net Loss $ (593) $ (314) $ (1,504) $ (955)
Add items not requiring cash:
Depletion, depreciation and
accretion 1,934 1,772 4,340 3,439
Future income taxes (recoveries) (238) (14) (582) (257)
Stock-based compensation 87 95 172 151
Non-cash financing charges and
other 70 69 137 105
Asset retirement expenditures (40) (20) (289) (33)
----------------------------------------------------------------------------
Funds flow 1,220 1,588 2,274 2,450
Changes in non-cash working
capital relating to operating
activities (710) (4,095) (1,057) (1,307)
----------------------------------------------------------------------------
510 (2,507) 1,217 1,143
----------------------------------------------------------------------------

Financing
Issuance of common shares,
net (note 8) - (1) - 119
Repayment of notes (note 7) - - - (10,500)
Issuance of convertible
debentures (note 7) - - - 10,500
Issuance of flow-through shares,
net (note 8) 3,708 - 3,708 -
Deferred financing charges (58) (139)
Increase (decrease) in bank loan (2,125) 2,517 (1,325) 2,517
Changes in non-cash financing
working capital - (74) - -
----------------------------------------------------------------------------
1,583 2,384 2,383 2,497
----------------------------------------------------------------------------

Investing
Oil and natural gas property
expenditures (1,470) (2,432) (2,805) (8,043)
Corporate acquisitions - (1) - (981)
Changes in non-cash investing
working capital 511 160 339 1,343
----------------------------------------------------------------------------
(959) (2,273) (2,466) (7,681)
----------------------------------------------------------------------------

Net increase (decrease) in cash 1,134 (2,396) 1,134 (4,041)

Cash, beginning of period - 2,396 - 4,041
----------------------------------------------------------------------------
Cash, end of period $ 1,134 $ - $ 1,134 $ -
----------------------------------------------------------------------------
----------------------------------------------------------------------------

Supplementary information:
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Interest paid $ 240 $ 302 $ 471 $ 405
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Taxes paid $ 13 $ - $ 13 $ -
----------------------------------------------------------------------------
----------------------------------------------------------------------------

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. 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 $196 have been netted against the convertible debentures and are no longer presented separately on the balance sheet.



4. Property, Plant and Equipment

----------------------------------------------------------------------------
June 30, 2007 December 31, 2006
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Petroleum and natural gas properties $ 39,051 $ 37,506
----------------------------------------------------------------------------
Land and seismic 13,329 12,442
----------------------------------------------------------------------------
Production equipment 14,095 13,263
----------------------------------------------------------------------------
Other 277 278
----------------------------------------------------------------------------
----------------------------------------------------------------------------
66,752 63,489
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Accumulated depletion and depreciation (17,488) (13,222)
----------------------------------------------------------------------------
$ 49,264 $ 50,267
----------------------------------------------------------------------------
----------------------------------------------------------------------------


The calculation of the 2007 depletion and depreciation excludes $7,856 (2006 - $12,601) for undeveloped properties and includes $3,346 (2006 - $4,664) for future development capital. General and administrative costs of $113 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 $2,163 (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
----------------------------------------------------------------------------
----------------------------------------------------------------------------


6. Bank Loan

At June 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 June 30, 2007, the facility was completely undrawn.

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.



Total
Debt Deferred 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
----------------------------------------------------------------------------
----------------------------------------------------------------------------

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 $72 - (151)
----------------------------------------------------------------------------
Tax effect of flow-through share renunciations - (2,922)
----------------------------------------------------------------------------
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, June 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 six month periods ended June 30, 2007 and
2006:

Three months ended Six months ended
June 30 June 30
2007 2006 2007 2006
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Basic weighted average common shares 44,673 38,659 43,324 38,639
----------------------------------------------------------------------------
Diluted weighted average common shares 44,673 38,659 43,324 38,639
----------------------------------------------------------------------------
----------------------------------------------------------------------------

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.

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

Number of
Shares Amount
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Common Share Warrants
----------------------------------------------------------------------------
Balance, December 31, 2006 1,979 $ -
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Warrants exercised - -
----------------------------------------------------------------------------
Expiry of warrants - -
----------------------------------------------------------------------------
Balance, June 30, 2007 1,979 $ -
----------------------------------------------------------------------------
----------------------------------------------------------------------------


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. No warrants were exercised prior to expiry.

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
----------------------------------------------------------------------------
----------------------------------------------------------------------------

Outstanding, March 31, 2007 3,721 $0.93
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Granted 60 0.85
----------------------------------------------------------------------------
Exercised - -
----------------------------------------------------------------------------
Cancelled - -
----------------------------------------------------------------------------
----------------------------------------------------------------------------

Outstanding, June 30, 2007 3,781 $0.92
----------------------------------------------------------------------------
----------------------------------------------------------------------------

A summary of the options outstanding under the Company's Option Plan as at
June 30, 2007 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 1.3 1,150 $0.35
----------------------------------------------------------------------------
$0.85 - $1.18 1,391 3.4 749 $0.90
----------------------------------------------------------------------------
$1.20 - $1.50 1,240 3.2 668 $1.45
----------------------------------------------------------------------------
----------------------------------------------------------------------------
$0.27 - $1.50 3,781 2.7 2,567 $0.80
----------------------------------------------------------------------------
----------------------------------------------------------------------------


10. Related-Party Transactions

Certain management functions of the Company have been provided by Brompton Group Limited ("BGL"). This includes the provision of certain senior management functions, certain accounting and administrative staff, office space, supplies and office equipment. Pursuant to this arrangement, BGL is entitled to recover costs in providing these services. For the three and six month periods ended June 30, 2007, costs of $2 (2006 - $20) and $5 (2006 - $54) respectively were recorded for BGL. Of the above amounts, $5 (2006 - $13) was payable to BGL at June 30, 2007.

All related-party transactions were recorded at the exchange amount in 2007 and 2006.



11. Interest and Financing Charges

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

Three months ended Six months ended
June 30 June 30
----------------------------------------------------------------------------
----------------------------------------------------------------------------
2007 2006 2007 2006
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Interest and loan fees on bridge
and bank loans 31 16 55 188
----------------------------------------------------------------------------
Interest on debentures 209 209 416 283
----------------------------------------------------------------------------
Amortization of debenture issue costs 32 32 63 41
----------------------------------------------------------------------------
Accretion of debentures 37 37 74 51
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Total interest and financing charges 309 294 608 563
----------------------------------------------------------------------------
----------------------------------------------------------------------------


12. Commitments

The Company has 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 June 30, 2007, the Company had satisfied $1,761 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 June, 2007, the Company had not satisfied any 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
    Shyla M. Stinson
    Vice President, Finance
    (403) 215-4750
    Website: www.weltonenergy.com