Burmis Energy Inc.
TSX : BME

Burmis Energy Inc.

November 13, 2007 06:00 ET

Burmis Energy Reports Results for the Third Quarter of 2007

CALGARY, ALBERTA--(Marketwire - Nov. 13, 2007) - Burmis Energy Inc. (TSX:BME) ("Burmis") is pleased to announce its operating and financial results for the reporting period ended September 30, 2007.

HIGHLIGHTS

- Continued drilling success at Brewster, Ferrier North and Brazeau

- Tied in one well at Brazeau in September and three wells at Ferrier North, Brazeau and Whitecourt in October to boost production in excess of 3,000 barrels of oil equivalent per day

- Average production of 2,221 barrels of oil equivalent in the third quarter of 2007

- Funds flow from operations of $15.2 million ($0.39 per share) over the nine months interim reported period



three months nine months
ended September 30, ended September 30,
2007 2006 2007 2006 Change
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FINANCIAL
($000s, except shares and
per share amounts)
Gross petroleum and
natural gas revenue $ 9,645 $ 8,971 $ 29,700 $ 28,596 + 4%
Funds flow from operations
(1) $ 4,917 $ 5,113 $ 15,200 $ 15,784 - 4%
Basic per share $ 0.12 $ 0.15 $ 0.39 $ 0.46 - 15%
Diluted per share $ 0.12 $ 0.14 $ 0.38 $ 0.44 - 14%
Earnings and other
comprehensive income $ 713 $ 1,236 $ 2,635 $ 3,424 - 23%
Basic per share $ 0.02 $ 0.04 $ 0.07 $ 0.10 - 30%
Diluted per share $ 0.02 $ 0.03 $ 0.07 $ 0.10 - 30%
Weighted average shares
('000's) 39,574 34,539 38,569 34,345 + 12%
Common shares outstanding
('000's) 39,578 34,561 39,578 34,561 + 15%
Capital expenditures (2) $ 11,297 $ 12,095 $ 42,252 $ 31,133 + 36%
Working capital deficiency $ 34,522 $ 17,643 + 96%
Total assets $131,207 $ 96,693 + 36%
Shareholders' equity $ 73,697 $ 55,110 + 34%
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(1) Funds flow from operations represents earnings before depletion,
depreciation and accretion, stock-based and non-cash compensation, and
future income taxes.
(2) Capital expenditures for the nine months ended September 30, 2007
include $5.1 million for a producing property acquisition in the Ferrier
area of west central Alberta.


three months nine months
ended September 30, ended September 30,
2007 2006 2007 2006 Change
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OPERATING
Natural gas (mcf/day) 9,570 9,914 9,714 9,610 + 1%
Average price
($Cdn./mcf) $ 6.32 $ 5.74 $ 7.28 $ 6.64 + 10%
Oil and NGL's (bbl/day) 626 606 598 633 - 6%
Average price
($Cdn./bbl) $ 70.42 $ 66.60 $ 63.23 $ 64.28 - 2%
Barrels of oil equivalent
per day (1) 2,221 2,258 2,217 2,235 - 1%
Operating netback
($Cdn./boe) (2) $ 27.88 $ 27.29 $ 29.47 $ 28.70 + 3%
Cash netback ($Cdn./boe)
(3) $ 24.07 $ 24.61 $ 25.11 $ 25.87 - 3%
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(1) In this report, all references to barrels of oil equivalent (boe) are
calculated converting natural gas to oil at a ratio of six thousand
cubic feet to one barrel of oil.
(2) Operating netback is calculated as revenues less royalties and operating
costs on a barrel of oil equivalent basis.
(3) Cash netback is calculated as funds flow from operations on a barrel of
oil equivalent basis.


OPERATIONS

In the first nine months of 2007, Burmis drilled 20 gross (10.0 net) wells resulting in 14 gross (8.6 net) gas wells and six gross (1.4 net) dry and abandoned wells for an overall success rate of 86 percent. During the third quarter, Burmis drilled five gross (2.5 net) wells resulting in three gross (2.2 net) natural gas wells at Brazeau, Brewster and Ferrier North while two gross (0.3 net) non-operated wells in the Pembina area were dry for an overall success rate of 88 percent.

During October 2007, Burmis added production from three gross (2.7 net) natural gas wells in the Brazeau, Ferrier North and Whitecourt areas of west central Alberta. Production from these new wells, combined with production from a Brazeau area natural gas well tied-in during September 2007, has boosted the Company's production to in excess of 3,000 barrels of oil equivalent per day. The Company is on track to achieve its previously announced 2007 exit rate of 3,250 barrels of oil equivalent per day.

Burmis will continue to focus its capital program on exploration and development opportunities on its Brazeau, Brewster and Ferrier North properties in west central Alberta. During the fourth quarter, Burmis expects to spud one operated well and one non-operated well. In addition, tie-in activities will be carried out on several wells to bring additional productive capacity on-stream. Currently, Burmis has approximately 400 barrels of oil equivalent of tested daily productive capacity behind pipe awaiting tie-in.

Burmis recorded average production of 2,221 barrels of oil equivalent per day during the third quarter of 2007 which was consistent with the 2,258 barrels of oil equivalent per day produced over the same period in 2006. In the month of September 2007, production averaged in excess of 2,400 barrels of oil equivalent per day. In the third quarter of 2007, Burmis encountered unanticipated downtime on several producing wells due to maintenance issues and facility outages at third party processing facilities. At Brazeau, two Nisku natural gas wells were shut-in for extensive periods due to unplanned third party plant outages. At Brewster, production during the third quarter was restricted due to a compressor constraint at a third party facility. The Company estimates that production was reduced by approximately 245 barrels of oil equivalent per day in the third quarter of 2007 as a result of operational issues.

Due to the operational downtime incurred to date in 2007 and previously cited weather and regulatory delays on well tie-ins, Burmis is lowering its estimate of average daily production to approximately 2,400 barrels of oil equivalent per day for 2007. This would generate estimated funds flow from operations of approximately $22 million assuming for 2007 assuming a natural gas price of $7.15 per mcf and a crude oil price of US $69.50 per barrel for WTI.

FERRIER NORTH

At Ferrier North, Burmis has a 100 percent working interest in four sections of land. During the third quarter of 2007, the Company drilled a well at 14-18-44-10W5 to follow up on its Rock Creek discovery located at 6-19-44-10W5. Though the Rock Creek was present on logs in the 14-18 well, Burmis chose to complete an Ostracod zone in order to assess that formation's productivity in the area. Following stimulation and clean-up of the well, test rates of approximately 3.3 million cubic feet per day of natural gas and associated liquids production of approximately 200 barrels per day were observed. This well has been tied-in to the O'Chiese gas plant and is currently producing at a restricted rate of approximately 2.0 million cubic feet per day with 150 barrels per day of associated liquids. When sufficient production history is established from the Company's two producing wells, both will be dually completed to facilitate production from both the Rock Creek and Ostracod zones to expand the Company's production from this property.

During the winter drilling season, Burmis intends to spud a third well at Ferrier North, located at 5-20-44-10W5, targeting horizons down to the Rock Creek. A fourth location has been mapped and is currently in the process of being licensed. Burmis also plans to pursue down-spacing opportunities on this property during 2008 to optimize its development.

BREWSTER

At Brewster, Burmis has assembled interests in seventeen sections of land with an average working interest of 41 percent. To date, two gross (0.8 net) natural gas wells have been drilled. The first well drilled in the area (40 percent working interest) was completed in two zones, one of which commenced production in late June while the second zone was brought on production in mid-August. Third party compressor constraints restricted production from this well during the third quarter. In early October, a 10 million cubic foot per day compressor was installed on the Brewster gas gathering system. The Company's initial well is now flowing at a gross rate of approximately 3.4 million cubic feet per day.

A second well at Brewster (40 percent working interest) was drilled and completed late in the third quarter of 2007. Following stimulation and clean-up, this well tested approximately 5.5 million cubic feet per day of natural gas. This well has been tied-in and is awaiting an expansion of the Brewster compressor station to 20 million cubic feet per day prior to being brought on production. This well is expected to commence unrestricted production in early 2008 when the compressor station expansion is completed.

During the fourth quarter of 2007, Burmis expects to spud a 100 percent working interest location at Brewster offsetting its first two wells. An additional eight gross (2.8 net) locations have been identified for drilling in 2008. Three gross (1.2 net) additional locations have been identified to the south and east for future drilling on this property. Burmis is currently acquiring 3-D seismic over the majority of its lands in the area to further evaluate future locations prior to drilling.

BRAZEAU

At Brazeau, Burmis re-entered and successfully recompleted the Rock Creek in a well located at 13-22-46-13W5 (80 percent working interest) in August. The well was brought on production in September and is currently producing at approximately 0.7 million cubic feet per day plus 20 barrels per day of associated liquids. The success of this well validates the presence of the Rock Creek seen on logs in an offsetting well and establishes three additional gross locations for future drilling.

In late October, Burmis successfully brought the 1-26-46-13W5 Nisku natural gas well (66 percent working interest before payout) on production. Estimated net production, after removal of acid gas components, is approximately 1.2 million cubic feet per day plus associated natural gas liquids of approximately 50 barrels per day.

WHITECOURT

At Whitecourt, Burmis tied in a 100 percent working interest well located at 14-19-58-11W5 in early October. The well is currently flowing at a rate of 1.0 million cubic feet per day plus associated liquids.

HEDGING ACTIVITY

Burmis entered into fixed price physical contracts for 3,000 gigajoules per day of natural gas at an average price of $7.87 per gigajoule at an intra-Alberta inventory transfer point for the period from March 1, 2007 to December 31, 2007. The Company has also entered into similar contracts for 2,000 gigajoules per day of natural gas at an average price of $6.90 per gigajoule for the period of November 1, 2007 to December 31, 2007 and 3,000 gigajoules per day of natural gas at an average price of $6.81 per gigajoule for the period from January 1, 2008 to March 31, 2008.

IMPACT OF CHANGES TO ALBERTA ROYALTY FRAMEWORK

On October 25, 2007, the Government of Alberta made public its proposal for a new royalty framework in Alberta. The proposed changes to the Alberta crown royalty framework would become effective on January 1, 2009 if they are enacted. The royalty payable under the proposed framework is very sensitive to both the price of natural gas and well production rates; however, wells drilled to measured depths greater than 2,000 meters will qualify for a reduction in royalty payable under certain conditions.

A substantial portion of Burmis' land holdings are prospective for productive horizons which range in depth from 2,000 meters to 3,000 meters. Under the proposed crown royalty framework, certain of these wells may realize a reduced royalty payable. The amount of the royalty reduction will be dependent upon the natural gas production rate, and the measured depth of the wellbore. Burmis' drilling inventory will continue to provide opportunities with acceptable economic rates of return, however, these returns will be lower than under the existing royalty system.

Burmis has reviewed the proposed changes to the Alberta crown royalty framework and has estimated the potential impact of the crown royalty changes on the Company's net operating income. Based upon the Company's estimated 2007 exit production and the Company's interpretation of publicly available data pertaining to the proposed changes in the Alberta crown royalty framework, Burmis estimates that, under the proposed Alberta royalty framework, the overall crown royalty rate for the Company's production will increase. The estimated increase in royalties would reduce net operating income available to the Company in 2009, assuming 2007 exit production rates, by approximately eight percent (based upon pricing assumptions of US $75 per barrel for WTI, $7.00 per gigajoule for natural gas and current prices for natural gas liquids) as compared with net operating income which would be generated under the existing royalty system. Under the proposed Alberta crown royalty framework, royalties will be affected by commodity type, well productivity, commodity prices and wellbore depth. The actual effect of these proposed changes on Burmis will be determined based upon the actual legislation enacted, the Company's production mix, production rates, commodity prices and wellbore depths as of January 1, 2009.

Burmis has noted the proposed crown royalty framework unfairly burdens higher productivity natural gas wells, which may have the unintended consequence of reduced natural gas drilling even if natural gas prices improve. Natural gas is the cleanest burning fossil fuel and an important component of Alberta's future energy needs. Burmis will continue to present alternative solutions to the Government of Alberta for a royalty framework which would have positive impacts on drilling activity for natural gas in Alberta.

OUTLOOK

Burmis is entering this winter season with an abundance of opportunities as well as some new challenges. Exploration success on the Ferrier North, Brewster and Brazeau properties has provided an exciting inventory of development drilling locations for liquid rich natural gas. The Company exited October with production in excess of 3,000 boepd and 400 boepd of tested production behind pipe putting us on track to meet our 2007 exit production target of 3,250 boepd. The proposed new Alberta royalty framework if enacted in 2009 would see most natural gas wells pay higher royalties if natural gas prices improve. Nevertheless, the Company's funds flow from operations would also improve in the event of higher natural gas prices. The Company will meet this challenge by diligently assessing the risks on its opportunity portfolio. The strong Canadian dollar has weakened the Canadian natural gas netback price. However, the near term outlook for natural gas is improving in anticipation of seasonal winter weather. Although natural gas storage levels in the US are high, Western Canadian natural gas storage is not full and Canadian natural gas supply is declining with lower natural gas drilling activity.

Burmis will focus its activities during this winter drilling season on three key properties, Brewster, Brazeau and Ferrier North, all in west central Alberta. The Company's Board of Directors has approved a capital budget of $31 million for 2008. This will allow for participation in drilling 13 gross (7.8 net) wells, and re-completing two gross (2.0 net) wells in 2008. Approximately $3.0 million has been allocated for land and seismic acquisition. The Company is forecasting average daily production of 3,600 barrels of oil equivalent per day in 2008. Using a natural gas price of $7.00 per mcf, a crude oil price of US $80.00 per barrel and a Canadian dollar to US dollar exchange rate of 1.02, this estimated production would generate funds flow from operations of approximately $31 million. Burmis expects to exit 2008 with production of 3,900 barrels of oil equivalent per day, and net debt at December 31, 2008 is forecast to be approximately 1.1 times trailing funds flow from operations.

Burmis is building a high quality, long life, asset base in west central Alberta. We are confident that our excellent opportunity portfolio, operational strength and sound management will help us to overcome the challenges we face and continue to build on our success to date.



I look forward to updating you on our activities as we move forward.

Respectfully submitted on behalf of the Board of Directors,

Aidan M. Walsh, P.Eng., MBA
President and Chief Executive Officer
November 13, 2007


MANAGEMENT'S DISCUSSION AND ANALYSIS - November 13, 2007

The following should be read in conjunction with the unaudited consolidated interim financial statements and notes thereto for the three and nine months ended September 30, 2007 and the audited consolidated financial statements and notes thereto and management's discussion and analysis included in the 2006 annual report of the Company. The financial statements are prepared in accordance with Canadian generally accepted accounting principles. The Company's quarterly operating and financial information is provided following Management's Discussion and Analysis of operations and should be read in conjunction with Management's Discussion and Analysis.

The quarterly financial statements were prepared following the same accounting policies and methods that were used in the 2006 audited consolidated financial statements except for the adoption of three new accounting policies outlined in Note 1 to the unaudited consolidated interim financial statements.

Burmis intends to pursue growth through exploration and development activities supported by land acquisitions and farm-in arrangements. The Company also pursues complimentary acquisitions in its core operating areas to enhance future growth.

During the first nine months of 2007, Burmis continued to focus its efforts on exploration and development activities in west central Alberta. These activities have resulted in significant growth in the Company's asset base. Burmis also has minor crude oil production in the United States which has been a source of funds flow for the Company as it carries out its activities in Canada.

Burmis evaluates its performance and that of its business segments using several criteria including funds flow from operations. Funds flow from operations is a non-GAAP measure that represents earnings before depletion, depreciation and accretion, stock-based and non-cash compensation, and future income taxes. The inclusion of site restoration expenditures and changes in non-cash working capital results in cash provided from operating activities on the statement of cash flows. Funds flow from operations is a key measure as it demonstrates the Company's ability to generate the funds necessary to achieve future growth through capital investment. Burmis also assesses its performance utilizing operating and cash netbacks. Operating netbacks represent the profit margin associated with the production and sale of crude oil, natural gas and natural gas liquids, and is calculated as revenues less royalties and operating costs on a barrel of oil equivalent basis. Cash netbacks represent the net amount retained per barrel of oil equivalent after all cash costs, and is calculated as funds flow from operations on a barrel of oil equivalent basis. These non-GAAP measures are not standardized and therefore may not be comparable to similar measures utilized by other entities.

In conformity with National Instrument 51-101, Standards of Disclosure for Oil and Gas Activities, natural gas volumes have been converted to barrels of oil equivalent ("boe") using a conversion ratio of 6 mcf to 1 bbl. This ratio is based on an energy equivalency conversion method primarily applicable at the burner tip and does not represent a value equivalency at the wellhead. Readers are cautioned that boe's may be misleading, particularly if used in isolation.

Certain information regarding Burmis set forth in this document, including management's assessment of the Company's future plans and operations, may constitute forward-looking statements under applicable securities law. By their nature, forward-looking statements necessarily involve risks associated with oil and gas exploration, production, marketing, and transportation such as loss of market, volatility of prices, currency fluctuations, imprecision of reserves estimates, environmental risks, competition from other producers and ability to access sufficient capital from internal and external sources. Readers are cautioned that the assumptions used in the preparation of forward-looking information and statements, although considered reasonable at the time may prove to be imprecise. As such, undue reliance should not be placed on forward-looking statements. Burmis' actual results and performance could differ materially from those expressed in or implied by those forward-looking statements. Accordingly, no assurance can be given that any of the events anticipated by the forward-looking statements will occur, or if they do occur, what benefit Burmis will derive therefrom.

Additional information regarding Burmis Energy Inc., including the Company's Annual Information Form, dated March 23, 2007, is available under the Company's profile on SEDAR at www.sedar.com.

OVERVIEW

The first nine months of 2007 were very active for Burmis. The Company participated in drilling 20 gross (10.0 net) wells, and completed a complementary property acquisition in the Ferrier area of west central Alberta in late March. However, operational downtime at third party natural gas processing plants reduced third quarter production, and prolonged spring break-up conditions and regulatory delays combined to slow Burmis' completion and tie-in activities, limiting growth in the Company's production in the first nine months of 2007. Production growth has resumed in October with the tie-in of three significant wells.

As a result of delays in the timing of well operations and downtime at various gas processing facilities, Burmis' operational and financial results in the first nine months of 2007 did not increase as anticipated from the comparable period of 2006. Average production totaled 2,217 barrels of oil equivalent per day in the first nine months of 2007 compared to production of 2,235 barrels of oil equivalent per day in the comparable period of 2006. Funds flow from operations (defined above) totaled $15.2 million ($0.39 per common share - basic) in the first nine months of 2007 compared to $15.8 million ($0.46 per common share - basic) in 2006. Cash provided by operating activities during the first nine months of 2007 was $14.6 million, a decrease of seven percent compared to $15.8 million in the first nine months of 2006 as a result of increased asset retirement expenditures in 2007. Earnings and other comprehensive income totaled $2.6 million ($0.07 per common share - basic) in 2007 compared to $3.4 million ($0.10 per common share - basic) in the first nine months of 2006. During the third quarter of 2007, production averaged 2,221 barrels of oil equivalent per day, two percent lower than 2,258 barrels of oil equivalent per day in the third quarter of 2006.

Natural gas prices increased during the first nine months of 2007, with the AECO reference price for natural gas averaging $6.23 per gigajoule compared to $6.06 per gigajoule in the comparable period of 2006. Natural gas inventory levels were very high during the first part of 2007 as a result of a warmer than normal winter in North America in late 2006 and early 2007. During February, natural gas inventories were drawn down substantially such that storage levels in the United States during the first half of 2007 were lower than compared to the preceding year, supporting natural gas prices through most of the second quarter of 2007. In the third quarter, natural gas in storage returned to the record high levels witnessed in the fall of 2006 which has resulted in lower natural gas prices in the third quarter. The near-term outlook for natural gas is improving in anticipation of seasonal winter weather. Although natural gas storage levels in the United States are high, western Canadian natural gas storage is not full and Canadian natural gas supply is declining with reduced levels of natural gas drilling activity.

During the first nine months of 2007, the West Texas Intermediate ("WTI") reference price for crude oil averaged US $65.93 per barrel compared to US $68.29 per barrel during the first nine months of 2006. Crude oil prices were lower during the first half of 2007 as high levels of crude oil inventories and indications of slowing growth in the United States economy put downward pressure on prices in 2007. However, crude oil prices recovered to average US $74.48 per barrel during the third quarter of 2007 as robust worldwide demand for crude oil resulted in large reductions in crude oil inventories. The rise in oil prices continued during October, with crude oil prices averaging US $85.66 per barrel. In addition to the strong worldwide demand for crude oil, ongoing geopolitical factors in Africa and the Middle East are helping to underpin crude oil prices.

The price received by the Company for crude oil and natural gas production has been reduced due to the significant strengthening of the Canadian dollar in the second and third quarters of 2007.

Revenues

Gross petroleum and natural gas revenues increased four percent to $29.7 million in the first nine months of 2007 compared to $28.6 million in 2006. The following table outlines gross revenues by product, as well as daily production volumes and sales prices by product.



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nine months ended September 30, 2007 2006
($000's unless otherwise noted) Daily Daily
Production Production
Component of Revenue Amount & Prices Amount & Prices
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Natural Gas $19,300 9,714 mcf/d $17,421 9,610 mcf/d
$ 7.28/mcf $6.64/mcf

Crude Oil & NGL's 10,323 598 bbl/d 11,136 633 bbl/d
$63.23/bbl $64.28/bbl (1)

Crude Oil Hedge Loss Realized - (25)

Royalty Income 77 64
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$29,700 $28,596
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(1) Includes impact of realized hedging losses.


Natural gas sales volumes in 2007 were consistent with 2006 levels. Increased production from new wells at Brazeau, Brewster and Ferrier was offset by decreased production from the Company's Pembina property as a result of natural field declines. Crude oil and natural gas liquid sales volumes decreased six percent from 2006 to 2007 as reduced crude oil volumes at Easyford and Kidney due to normal declines and lower NGL production at Pembina more than offset the impact of increased NGL volumes from the Company's Brazeau and Ferrier properties.

During 2007, Burmis has entered into fixed price physical natural gas sales contracts at an intra-Alberta inventory transfer point for volumes ranging from 3,000 to 5,000 gigajoules per day. The prices to be received by Burmis under these contracts in 2007 for the period from March to December are as follows:



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Period Gigajoules per day Fixed Price
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(Cdn. $ per gj)
March 1, 2007 to December 31, 2007 1,000 $8.03
March 1, 2007 to December 31, 2007 1,000 $7.87
March 1, 2007 to December 31, 2007 1,000 $7.71
November 1, 2007 to December 31, 2007 1,000 $6.93
November 1, 2007 to December 31, 2007 1,000 $6.87
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Subsequent to September 30, 2007 the Company entered into fixed price physical natural gas sales contracts at an intra-Alberta inventory transfer point for 3,000 gigajoules per day at an average price of $6.81 per gigajoule. These contracts are for the period from January 1, 2008 to March 31, 2008.
There were no derivative financial instruments pertaining to the Company's production in place at September 30, 2007.



Royalties
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nine months ended September 30, 2007 2006
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($'000's)

Crown royalties $4,660 $4,825

Other royalties 1,317 1,482

Alberta Royalty Tax Credit - (375)
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Net royalties $5,977 $5,932
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Average royalty rate as a percentage of revenues 20.1% 20.7%
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Royalties were consistent from 2006 to 2007. As a percentage of revenue, royalties have decreased slightly compared to 2006. During the first nine months of 2007, Burmis had interests in five producing wells which were on royalty holiday. The Company expects royalties to become payable on these wells at various dates throughout 2007 after Burmis receives the full benefit of these royalty holidays.

Operating Costs

Operating costs were $5.9 million ($9.73 per barrel of oil equivalent) during the first nine months of 2007 compared to $5.2 million ($8.44 per barrel of oil equivalent) during 2006. Total operating costs increased due to inflationary pressures and changes in the Company's production base as compared to the prior year. During 2007, production from the Brazeau and Ferrier areas has increased substantially from 2006 while production from the Pembina area has declined. Operating costs at Brazeau are generally higher than average due to sour gas handling requirements and higher natural gas gathering and processing fees. Operating costs at the Company's Ferrier property are lower than average, but are still above costs at Pembina where Burmis holds a 15 percent working interest in the Blue Rapids natural gas processing plant. On a barrel of oil equivalent basis, operating costs increased fifteen percent in 2007 compared to 2006, consistent with the overall increase in operating costs.

Operating Netback

The Company's operating netback of $29.47 per barrel of oil equivalent in the first nine months of 2007 was three percent higher than the netback of $28.70 per barrel of oil equivalent in the corresponding period of 2006. The impact of increased natural gas prices was partially offset by slightly reduced crude oil prices, and increased operating costs per barrel of oil equivalent of production.

General and Administrative Expenses

General and administrative expenses totaled $2.1 million in the first nine months of 2007 compared to $1.5 million in 2006. The increase is the result of increased employee compensation, as well as increased costs for rent, insurance and information technology services. During 2007, the Company paid its employees and management an aggregate discretionary bonus of $290,000 (2006 - $260,000), and recognized non-cash compensation expense of $194,000 in respect of interest free loans made to certain officers of the Company. On a barrel of oil equivalent basis, cash general and administrative expenses were $3.13 in the first nine months of 2007 compared to $2.45 in 2006.

Stock Based Compensation Expense

Stock based compensation expense totalled $647,000 for the year to date in 2007 compared to $408,000 in 2006. During 2007, the Company has granted 556,500 stock options at an average exercise price of $3.06 per common share.

Depletion, Depreciation and Accretion

Depletion, depreciation and accretion expense totalled $10.9 million in the first nine months of 2007 compared to $10.7 million in 2006. The increase in depletion, depreciation and accretion expense is due to an increase in the overall rate of depletion, depreciation and accretion to $17.94 per barrel of oil equivalent in 2007 from $17.56 in 2006.

Interest

Interest expense totalled $804,000 in the first nine months of 2007 compared to $232,000 in 2006. The Company borrows funds under a production loan facility and utilizes bankers' acceptances from time to time. As a result of the large capital program carried out by the Company in 2007, balances outstanding on the Company's credit facility are higher in 2007 than in the comparable period of 2006.

Income Taxes

The provision for income taxes was $0.9 million in 2007 compared to $1.2 million in the comparable period of 2006. The tax provision in 2007 was reduced by an approximate $0.2 million adjustment to the Company's effective tax rate due to reductions in enacted federal and provincial tax rates, as well as changes in the expectation of when the Company will become taxable.

THIRD QUARTER 2007 RESULTS

Revenues increased to $9.6 million in the third quarter of 2007 from $9.0 million in the third quarter of 2006. Natural gas production averaged 9,570 mcf per day in the third quarter of 2007 compared to 9,914 mcf per day in the third quarter of 2006. The impact of new production from wells at Brazeau, Brewster and Ferrier was more than offset by reduced production at Pembina as a result of natural declines and the impact of unplanned downtime at third party natural gas processing facilities which caused two of the Company's well in the Brazeau area to be shut-in during the third quarter. Crude oil and NGL production averaged 626 barrels per day in the third quarter of 2007 compared to 606 barrels per day in the third quarter of 2006. Prices received for natural gas in the third quarter of 2007 were $6.32 per mcf, an increase of ten percent compared to the third quarter of 2006. Although AECO natural gas reference prices were lower than in the same period of 2006, the Company benefited from the fixed price physical natural gas contracts entered into during the first quarter of 2007. Crude oil and NGL prices increased six percent to $70.42 per barrel in the third quarter of 2007 as a result of stronger WTI reference prices and increased condensate production, which receives higher prices than other natural gas liquids. These increases were partially offset by strengthening of the Canadian dollar as compared with 2006. Royalties, as a percentage of revenue, were consistent at 17.7 percent in the third quarters of 2007 and 2006.

Operating costs increased on an absolute basis and per barrel of oil equivalent. The increase in operating costs were a result of a 13th month adjustment pertaining to non-operated gas gathering charges in 2006 at Brazeau, increased lease maintenance and workover costs, and charges for natural gas gathering and processing from prior periods. In addition, a non-operated well in the Brazeau began producing significant volumes of water during the quarter, leading to significantly increased chemical and water disposal charges. This well became uneconomic to produce in October and has been shut-in. After adjusting third quarter operating costs for the cumulative impact of the above items and removing the costs and associated production for the shut-in well, operating costs pertaining to the third quarter would have been approximately $9.00 per barrel of oil equivalent.

The Company's operating netback of $27.88 per barrel of oil equivalent in the third quarter of 2007 was consistent with the operating netback of $27.29 realized in the third quarter of 2006. Increased commodity prices were offset by higher operating costs per barrel of oil equivalent.

Earnings in the third quarter of 2007 decreased to $0.7 million ($0.02 per common share - basic) from $1.2 million ($0.04 per common share - basic) in the third quarter of 2006.

CAPITAL EXPENDITURES

Capital expenditures totalled $42.3 million in the first nine months of 2007 compared to $31.1 million in the comparable period of 2006. The Company's capital program included exploratory drilling expenditures of $18.8 million, development drilling expenditures of $7.4 million and investments in production facilities totalling $7.9 million. During the first nine months of 2007, Burmis acquired approximately 4,000 acres of land at crown land sales for $1.9 million, and spent $1.2 million acquiring seismic to evaluate the Company's prospects.

In addition, Burmis acquired working interests in three natural gas wells producing 80 barrels of oil equivalent per day, 1,676 net acres of undeveloped lands and overriding royalties in three gas wells for total consideration of $5.1 million. The acquisition closed in March 2007.

LIQUIDITY AND CAPITAL RESOURCES

At September 30, 2007 Burmis had a total working capital deficiency of $34.5 million.

The Company's extendible revolving credit facility with a Canadian chartered bank was increased to $45.0 million in the second quarter of 2007. This production loan facility is subject to semi-annual review in October 2007 and May 2008 at which times repayment may be required.

On May 17, 2007 Burmis closed a private placement of 2.0 million flow-through common shares at a price of $3.68 per flow-through common share for gross proceeds of $7.36 million. Proceeds from the private placement will be used to fund the Company's exploration program in its core area of west central Alberta.

The Company currently has 39.6 million common shares outstanding. In addition, 3.7 million stock options are outstanding at an average exercise price of $1.70 per share.

Burmis has an approved capital budget of $50.0 million for 2007. These expenditures will be funded by cash provided from operating activities, proceeds from the flow-through share private placement completed in the second quarter of 2007 and use of the Company's production loan facility.

CONTRACTUAL OBLIGATIONS

The Company's extendible revolving credit facility is subject to semi-annual review in October 2007 and May 2008 at which times repayment may be required.

As a result of a private placement of flow-through common shares completed in November 2006, the Company is obligated to incur eligible Canadian Exploration Expenditures in the amount of $11.25 million under the flow-through share arrangement by December 31, 2007. As at September 30, 2007, these flow-through expenditures had been incurred.

As a result of the private placement of flow-through common shares completed in May 2007, the Company is obligated to incur eligible Canadian Exploration Expenditures in the amount of $7.36 million under the flow-through share arrangement by December 31, 2008. As at September 30, 2007, approximately $3.4 million of exploration expenditures had been incurred to fulfill this flow-through obligation.

During the second quarter of 2007, the Company committed to spend approximately $2.1 million to acquire approximately 100 square kilometres of 3-D seismic.

Burmis has office lease space commitments of $59,000 in 2007, $338,000 in 2008, $372,000 in 2009, $384,000 in 2010, $387,000 in 2011 and $97,000 in 2012.

The Company does not have any other off-balance sheet financing arrangements.

RELATED PARTY TRANSACTIONS

During the second quarter of 2007, certain directors and officers of the Company participated in the private placement of flow-through common shares which closed on May 17, 2007. These insiders purchased 60,000 flow-through common shares of the Company under the same price, terms and conditions as the remainder of the offering.

During the second quarter of 2007, the Company's Board of Directors approved an executive loan program (the "program") under which certain officers of Burmis may borrow up to $250,000 from the Company on an interest free basis. The total amount of these unsecured borrowings under the program may not exceed $1.5 million in aggregate, and are repayable to the Company no later than March 30, 2012. As of September 30, 2007 three loans totalling $650,000 in aggregate had been provided under the program. Subsequent to September 30, 2007 a loan totalling $200,000 was advanced under the program.

During the first nine months of 2007, the Company was charged legal fees totalling approximately $72,000 by a law firm, a partner of which is the Company' Secretary. The work done on behalf of the Company was in the ordinary course of business and was billed at market rates.

OTHER TRANSACTIONS

At this time, Burmis has not entered into any proposed business or property acquisitions or dispositions.

CONTROLS AND PROCEDURES

Management of Burmis is responsible for designing and maintaining internal controls over financial reporting and disclosure controls and procedures. Internal controls over financial reporting and disclosure controls and procedures are designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external reporting purposes in accordance with Canadian GAAP. These controls may not prevent or detect fraud or misstatements because of inherent limitations in any system of internal controls. During the review of the design of the Company's control system over financial reporting, it was noted that, due to the limited number of staff at Burmis, it is not feasible to achieve complete segregation of incompatible duties. The limited number of staff may also result in identifying weaknesses in accounting for complex or non-routine transactions due to a lack of technical resources within the Company. There were no significant changes in the design of the Company's internal controls over financial reporting or disclosure controls and procedures during the reported period.

CHANGES IN ACCOUNTING POLICIES

On January 1, 2007, the Company adopted the new Canadian accounting standards for financial instruments - recognition and measurement, financial instruments - presentation and disclosure, hedging and other comprehensive income. These standards have been applied prospectively.

The Company has used financial derivatives to manage the price risk attributable to anticipated sales in prior periods; however, at January 1, 2007 the Company did not have any financial derivative contracts. The adoption of these standards did not have an effect on the Company's consolidated financial statements as at January 1, 2007.

The financial instruments standard established recognition and measurement criteria for financial assets, financial liabilities and financial derivatives. All financial instruments are required to be measured at fair value on initial recording except in specific circumstances; changes in fair value in subsequent periods depends on whether the financial instrument has been classified as "held for trading", "available for sale", "held to maturity", "loans and receivables" or "other financial liabilities".

"Held for trading" financial assets and financial liabilities are measured at fair value with changes in fair value recognized in earnings. "Available for sale" financial assets are measured at fair value, with changes in fair value recognized in other comprehensive income. "Held to maturity" financial assets and "loans and receivables" and "other financial liabilities" are measured at amortized cost. The Company has classified its cash as "held for trading", its accounts receivable and loan receivable as "loans and receivables" and its accounts payable and production loan facility as "other financial liabilities".

Prior to adoption of the new standards, physical receipt and delivery contacts were not within the scope of the definition of a financial instrument. On adoption of the new standards, the Company elected to continue to account for its physical delivery contracts on an accrual basis rather than as non-financial derivatives.

Derivatives embedded in other financial instruments must be separated and fair valued as separate derivatives under the new standard. The Company has not identified any embedded derivatives in any of its instruments.



SUMMARY OF QUARTERLY OPERATING AND FINANCIAL RESULTS
----------------------------------------------------------------------------
----------------------------------------------------------------------------
2007

OPERATING Third Second First
----------------------------------------------------------------------------
Natural gas (mcf/d) 9,570 10,084 9,486
Price ($/mcf) 6.32 7.77 7.74
Oil and NGL's (bbl/d) 626 605 562
Price ($/bbl) 70.42 61.50 56.91
Barrels of oil equivalent (per day) 2,221 2,286 2,143
EARNINGS ('000's of dollars)
----------------------------------------------------------------------------
Crude oil and natural gas liquid revenues 4,055 3,389 2,879
Natural gas revenues 5,590 7,146 6,641
Royalties (1,703) (2,349) (1,925)
Interest and other income 31 37 6
--------------------------------
7,973 8,223 7,601
Operating expenses 2,246 2,052 1,590
General and administrative 597 973 520
Stock based compensation 232 222 193
Depletion, depreciation and accretion 3,829 3,658 3,370
Loss on provision for retirement obligation - - -
Interest 329 303 172
Other - - -
--------------------------------
Total expenses 7,233 7,208 5,845
Earnings before income taxes 740 1,015 1,756
Current income taxes - 1 -
Future income taxes 27 319 529
--------------------------------
27 320 529
--------------------------------
Earnings and other comprehensive income 713 695 1,227
----------------------------------------------------------------------------
----------------------------------------------------------------------------
per share (basic) $ 0.02 $ 0.02 $ 0.03
----------------------------------------------------------------------------
----------------------------------------------------------------------------
FUNDS FLOW ('000's of dollars) 4,917 4,964 5,319
----------------------------------------------------------------------------
----------------------------------------------------------------------------
per share (basic) $ 0.12 $ 0.13 $ 0.14
----------------------------------------------------------------------------
----------------------------------------------------------------------------
NETBACKS ($/boe)
----------------------------------------------------------------------------
Petroleum and natural gas revenues 47.21 50.64 49.35
Royalties (8.34) (11.29) (9.98)
Operating expenses (10.99) (9.86) (8.24)
--------------------------------
Operating netback 27.88 29.49 31.13
General and administrative (2.32) (4.34) (2.69)
Interest and other income (expense) (1.49) (1.28) (0.86)
Current income taxes - (0.01) -
--------------------------------
Cash netback 24.07 23.86 27.58
----------------------------------------------------------------------------
----------------------------------------------------------------------------
TOTAL ASSETS ($'000's of dollars) 131,207 122,388 120,456
----------------------------------------------------------------------------
----------------------------------------------------------------------------

2006 2005

OPERATING Fourth Third Second First Fourth
----------------------------------------------------------------------------
Natural gas (mcf/d) 9,417 9,914 9,068 9,848 7,615
Price ($/mcf) 7.00 5.74 6.20 7.97 11.30
Oil and NGL's (bbl/d) 527 606 612 682 616
Price ($/bbl) 54.91 66.60 67.54 59.20 59.92
Barrels of oil equivalent
(per day) 2,097 2,258 2,124 2,323 1,885
EARNINGS ('000's of dollars)
----------------------------------------------------------------------------
Crude oil and natural gas
liquid revenues 2,662 3,715 3,764 3,631 3,508
Natural gas revenues 6,079 5,256 5,138 7,092 7,947
Royalties (1,718) (1,587) (1,499) (2,846) (2,722)
Interest and other income 7 2 1 9 4
-----------------------------------------------
7,030 7,386 7,404 7,886 8,737
Operating expenses 2,038 1,713 1,716 1,723 1,552
General and
administrative 480 426 681 390 363
Stock based compensation 184 126 95 187 198
Depletion, depreciation
and accretion 3,248 3,259 3,525 3,929 3,117
Loss on provision for
retirement obligation 548 - - - -
Interest 203 131 73 28 16
Other - 1 8 - 2
-----------------------------------------------
Total expenses 6,701 5,656 6,098 6,257 5,248
Earnings before income
taxes 329 1,730 1,306 1,629 3,489
Current income taxes - 2 - - -
Future income taxes (274) 492 358 389 1,096
-----------------------------------------------
(274) 494 358 389 1,096
-----------------------------------------------
Earnings and other
comprehensive income 603 1,236 948 1,240 2,393
----------------------------------------------------------------------------
----------------------------------------------------------------------------
per share (basic) $ 0.02 $ 0.04 $ 0.03 $ 0.04 $ 0.07
----------------------------------------------------------------------------
----------------------------------------------------------------------------
FUNDS FLOW ('000's of
dollars) 4,309 5,113 4,926 5,745 6,694
----------------------------------------------------------------------------
----------------------------------------------------------------------------
per share (basic) $ 0.12 $ 0.15 $ 0.14 $ 0.17 $ 0.20
----------------------------------------------------------------------------
----------------------------------------------------------------------------
NETBACKS ($/boe)
----------------------------------------------------------------------------
Petroleum and natural gas
revenues 45.32 43.17 46.06 51.29 65.40
Royalties (8.91) (7.63) (7.76) (13.61) (15.69)
Operating expenses (10.57) (8.25) (8.88) (8.24) (8.95)
-----------------------------------------------
Operating netback 25.84 27.29 29.42 29.44 40.76
General and
administrative (2.48) (2.05) (3.52) (1.87) (2.09)
Interest and other income
(expense) (1.02) (0.63) (0.41) (0.09) (0.08)
Current income taxes - - - - -
-----------------------------------------------
Cash netback 22.34 24.61 25.49 27.48 38.59
----------------------------------------------------------------------------
----------------------------------------------------------------------------
TOTAL ASSETS ($'000's of
dollars) 100,737 96,693 84,857 73,230 71,876
----------------------------------------------------------------------------
----------------------------------------------------------------------------


BURMIS ENERGY INC.
Consolidated Balance Sheets

(thousands of dollars)
----------------------------------------------------------------------------
September 30, December 31,
(unaudited) 2007 2006
----------------------------------------------------------------------------
----------------------------------------------------------------------------


Assets
Current assets
Cash $ 776 $ 31
Accounts receivable 7,614 10,301
----------------------------------------------------------------------------
8,390 10,332
Petroleum and natural gas properties
(note 2) 122,353 90,405
Loan receivable (note 3) 464 --
----------------------------------------------------------------------------
$ 131,207 $ 100,737
----------------------------------------------------------------------------
----------------------------------------------------------------------------

Liabilities and Shareholders' Equity
Current liabilities
Accounts payable and accrued liabilities $ 17,912 $ 15,020
Revolving credit facility (note 4) 25,000 8,000
Current portion of asset retirement
obligation (note 5) - 669
----------------------------------------------------------------------------
42,912 23,689
Asset retirement obligation (note 5) 2,937 2,777
Future income tax liability 11,661 7,601
Shareholders' equity
Share capital (note 6) 56,654 52,895
Contributed surplus (note 6) 2,100 1,467
Retained earnings and other comprehensive
income 14,943 12,308
----------------------------------------------------------------------------
73,697 66,670
Commitments (note 11)
----------------------------------------------------------------------------
$ 131,207 $ 100,737
----------------------------------------------------------------------------
----------------------------------------------------------------------------

See accompanying notes to consolidated financial statements.


BURMIS ENERGY INC.
Consolidated Statement of Earnings and Other Comprehensive Income

(thousands of dollars, except per share amounts)
----------------------------------------------------------------------------
----------------------------------------------------------------------------
three months ended nine months ended
September 30, September 30,
(unaudited) 2007 2006 2007 2006
----------------------------------------------------------------------------

Revenues
Petroleum and natural gas (note 8) $ 9,645 $ 8,971 $29,700 $28,596
Royalties (1,703) (1,587) (5,977) (5,932)
Interest and other income 31 2 74 12
----------------------------------------------------------------------------
7,973 7,386 23,797 22,676
Expenses
Operating 2,246 1,713 5,888 5,152
General and administrative 597 426 2,090 1,497
Stock based compensation 232 126 647 408
Depletion, depreciation and
accretion 3,829 3,259 10,857 10,713
Interest paid 329 131 804 232
Other - 1 - 9
----------------------------------------------------------------------------
7,233 5,656 20,286 18,011
Earnings and other comprehensive
income before income taxes 740 1,730 3,511 4,665
Income taxes
Current - 2 1 2
Future 27 492 875 1,239
----------------------------------------------------------------------------
27 494 876 1,241
----------------------------------------------------------------------------
Earnings and other comprehensive
income $ 713 $ 1,236 $ 2,635 $ 3,424
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Earnings and other comprehensive
income per share (note 7)
Basic $ 0.02 $ 0.04 $ 0.07 $ 0.10
Diluted $ 0.02 $ 0.03 $ 0.07 $ 0.10
----------------------------------------------------------------------------
----------------------------------------------------------------------------


Consolidated Statement of Retained Earnings and Other Comprehensive Income
(thousands of dollars)
----------------------------------------------------------------------------
----------------------------------------------------------------------------
three months ended nine months ended
September 30, September 30,
(unaudited) 2007 2006 2007 2006
----------------------------------------------------------------------------
Retained earnings and other
comprehensive income,
beginning of period $ 14,230 $10,469 $12,308 $ 8,281
Earnings and other comprehensive
income 713 1,236 2,635 3,424
----------------------------------------------------------------------------
Retained earnings and other
comprehensive income, end of
period $ 14,943 $11,705 $14,943 $11,705
----------------------------------------------------------------------------
----------------------------------------------------------------------------

See accompanying notes to consolidated financial statements.


BURMIS ENERGY INC.
Consolidated Statement of Cash Flows

(thousands of dollars, except per share amounts)
----------------------------------------------------------------------------
----------------------------------------------------------------------------
three months ended nine months ended
September 30, September 30,
(unaudited) 2007 2006 2007 2006
----------------------------------------------------------------------------

Cash provided by (used in)
Operations
Earnings and other comprehensive
income $ 713 $ 1,236 $ 2,635 $ 3,424
Items not affecting cash
Depletion, depreciation and
accretion 3,829 3,259 10,857 10,713
Stock based compensation 232 126 647 408
Non-cash compensation (note 3) 124 - 194 -
Future income taxes 27 492 875 1,239
Other (8) - (8) -
Asset retirement expenditures (160) (61) (1,062) (88)
Changes in non-cash working capital
(note 9) 214 389 476 100
----------------------------------------------------------------------------
4,971 5,441 14,614 15,796
Financing
Revolving credit facility 5,381 8,772 17,000 13,559
Issue of common shares for cash,
net of share issue costs (1) - 6,902 -
Exercise of stock options 28 93 28 257
----------------------------------------------------------------------------
5,408 8,865 23,930 13,816
Investments
Additions to petroleum and natural
gas properties (11,297) (12,095) (37,193) (31,133)
Acquisition of petroleum and
natural gas properties - - (5,059) -
Loan receivable (note 3) (400) - (650) -
Changes in non-cash working capital
(note 9) 1,967 (2,176) 5,103 1,212
----------------------------------------------------------------------------
(9,730) (14,271) (37,799) (29,921)

Increase (decrease) in cash 649 35 745 (309)
Cash, beginning of period 127 77 31 421
----------------------------------------------------------------------------
Cash, end of period $ 776 $ 112 $ 776 $ 112
----------------------------------------------------------------------------
----------------------------------------------------------------------------

See accompanying notes to consolidated financial statements.


1. Significant accounting policies:

The consolidated financial statements of Burmis Energy Inc. (the "Company") have been prepared by management in accordance with accounting principles generally accepted in Canada. The preparation of financial statements in conformity with generally accepted accounting principles requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reported period. Actual results could differ from these estimates.

The consolidated financial statements include the accounts of the Company and its wholly-owned United States subsidiary, Bellevue Resources, Inc.

These interim consolidated financial statements have been prepared by management following the same accounting policies and methods that were used and disclosed in the audited financial statements for the year ended December 31, 2006, except as disclosed below. These consolidated interim financial statements include all adjustments necessary to present fairly the results for the interim period ended September 30, 2007. These interim financial statements should be read in conjunction with the most recent audited consolidated financial statements and notes included in the Company's annual report for the year ended December 31, 2006.

(a) New accounting policies

On January 1, 2007, the Company adopted the new Canadian accounting standards for financial instruments - recognition and measurement, financial instruments - presentation and disclosure, hedging and other comprehensive income. These standards have been applied prospectively.

The Company has used financial derivatives to manage the price risk attributable to anticipated sales in prior periods; however, at January 1, 2007 the Company did not have any financial derivative contracts. The adoption of these standards did not have an effect on the Company's consolidated financial statements as at January 1, 2007.

The financial instruments standard established recognition and measurement criteria for financial assets, financial liabilities and financial derivatives. All financial instruments are required to be measured at fair value on initial recording except in specific circumstances; changes in fair value in subsequent periods depends on whether the financial instrument has been classified as "held for trading", "available for sale", "held to maturity", "loans and receivables" or "other financial liabilities".

"Held for trading" financial assets and financial liabilities are measured at fair value with changes in fair value recognized in earnings. "Available for sale" financial assets are measured at fair value, with changes in fair value recognized in other comprehensive income. "Held to maturity" financial assets and "loans and receivables" and "other financial liabilities" are measured at amortized cost. The Company has classified its cash as "held for trading", its accounts receivable and loan receivable as "loans and receivables" and its accounts payable and production loan facility as "other financial liabilities".

Prior to adoption of the new standards, physical receipt and delivery contacts were not within the scope of the definition of a financial instrument. On adoption of the new standards, the Company elected to continue to account for its physical delivery contracts on an accrual basis rather than as non-financial derivatives.

Derivatives embedded in other financial instruments must be separated and fair valued as separate derivatives under the new standard. The Company has not identified any embedded derivatives in any of its instruments.



2. Petroleum and natural gas properties:
----------------------------------------------------------------------------
----------------------------------------------------------------------------
September 30, December 31,
2007 2006
----------------------------------------------------------------------------
Petroleum and natural gas properties $ 163,306 $ 120,642
Accumulated depletion and depreciation (40,953) (30,237)
----------------------------------------------------------------------------
$ 122,353 $ 90,405
----------------------------------------------------------------------------
----------------------------------------------------------------------------


Costs of unproved properties excluded from costs subject to depletion and depreciation at September 30, 2007 were $6.8 million. Future development costs of $1.5 million have been included in costs subject to depletion.

3. Loan receivable

The Company's board of directors approved an executive loan program under which certain officers may borrow up to $250,000 from the Company on an interest free unsecured basis. The borrowings under the program may not exceed $1.5 million in aggregate, and are repayable no later than March 30, 2012. As of September 30, 2007 loans totalling $650,000 in aggregate had been provided under the program. These were recorded as loans receivable in the amount of $456,000, being the fair value of the loans at the time they were made assuming settlement in March 2012 using discount rates applicable at the dates of the loans, and a non-cash compensation charge of $194,000 recorded in general and administrative expenses. The Company records non-cash interest income on the loans during the period which they are outstanding. Subsequent to September 30, 2007 one additional loan totalling $200,000 was advanced under the program.

4. Revolving credit facility:

During the reported period, the Company's extendible revolving credit facility was increased to $45.0 million. Repayments of the facility are not required provided the amounts borrowed do not exceed $45.0 million or an amount determined from time to time. The loan facility is reviewed semi-annually. All amounts drawn under this facility are classified as a current liability.

The loan facility is secured by a $75 million floating charge demand debenture over all Canadian assets, and a full recourse guarantee of the United States subsidiary.

5. Asset retirement obligation:

The Company's asset retirement obligations result from net ownership interests in petroleum and natural gas assets including well sites and gathering systems. The Company estimates the total undiscounted amount of cash flows required to settle its asset retirement obligations at September 30, 2007 is approximately $3.7 million. These costs will be incurred between 2008 and 2027. A credit adjusted risk-free rate of six percent and an inflation rate of two percent was used to calculate the fair value of the asset retirement obligations.



A reconciliation of the asset retirement obligation is provided below:

----------------------------------------------------------------------------
----------------------------------------------------------------------------
nine months ended September 30, 2007 2006
----------------------------------------------------------------------------
Balance, beginning of period $ 3,446 $ 2,433
Accretion expense 140 120
Liabilities incurred 413 512
Liabilities settled (1,062) (88)
----------------------------------------------------------------------------
Balance, end of period $ 2,937 $ 2,977
----------------------------------------------------------------------------
----------------------------------------------------------------------------

6. Share capital:

(a) Authorized: Unlimited number of voting common shares.

Issued:
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Number of
Shares Amount
----------------------------------------------------------------------------
Balance, December 31, 2006 37,561,133 $ 52,895
Flow-through shares issued pursuant to private
placement 2,000,000 7,360
Exercise of stock options for cash 17,000 28
Transfer from contributed surplus on exercise of
stock options - 14
Tax effect of 2006 flow-through share issue - (3,327)
Share issuance costs - (458)
Tax benefit of share issue costs - 142
----------------------------------------------------------------------------
Balance, September 30, 2007 39,578,133 $ 56,654
----------------------------------------------------------------------------
----------------------------------------------------------------------------


During the second quarter of 2007, certain directors and officers of the Company participated in the private placement of flow-through common shares which closed on May 17, 2007. These insiders purchased 60,000 flow-through common shares of the Company under the same price, terms and conditions as the remainder of the offering.



(b) Contributed surplus:

A reconciliation of contributed surplus is provided below:
----------------------------------------------------------------------------
----------------------------------------------------------------------------

nine months ended September 30, 2007 2006
----------------------------------------------------------------------------
Balance, beginning of period $ 1,467 $ 998
Stock-based compensation expense 647 408
Transfer to share capital on exercise of stock options (14) (123)
----------------------------------------------------------------------------
Balance, end of period $ 2,100 $ 1,283
----------------------------------------------------------------------------
----------------------------------------------------------------------------


(c) Stock-based compensation plan:

The Company has established a stock option plan whereby certain officers, directors and employees may be granted options to purchase common shares. The number of shares issuable under the plan is subject to a rolling maximum equal to 10 percent of the outstanding common shares. The exercise price of each option equals the market price of the common shares on the date of grant. Options granted under the plan have a maximum term of five years and vest equally over a three-year period starting on the first anniversary date of the grant.



A summary of the status of the plan as of September 30, 2007 and changes
during the period ending on that date is presented below:
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Weighted Average
Shares Exercise Price Life Remaining
----------------------------------------------------------------------------
Outstanding, December 31, 2006 3,228,000 $ 1.48 2.4 years
Granted 556,500 3.06 4.9 years
Cancelled (39,000) 2.65 4.1 years
Exercised (17,000) 1.65 1.9 years
----------------------------------------------------------------------------

Outstanding, September 30, 2007 3,728,500 $ 1.70 2.1 years
----------------------------------------------------------------------------
----------------------------------------------------------------------------

Exercisable, September 30, 2007 2,467,500 $ 1.12 1.2 years
----------------------------------------------------------------------------
----------------------------------------------------------------------------

The outstanding stock options and associated exercise prices are outlined
below:

----------------------------------------------------------------------------
----------------------------------------------------------------------------
Weighted Average
Exercise Price Shares Life Remaining
----------------------------------------------------------------------------
$0.50 1,485,000 0.3 years
$1.02 - $1.35 320,500 1.5 years
$2.45 - $2.57 1,002,000 2.9 years
$2.97 - $3.10 921,000 4.3 years
----------------------------------------------------------------------------

$0.50 - $3.10 3,728,500 2.1 years
----------------------------------------------------------------------------
----------------------------------------------------------------------------


The fair value of stock options granted during 2007 was estimated to be approximately $800,000 using the Black-Scholes model with the following assumptions: expected life of options - five years; interest rate - six percent; volatility - 45 percent.

7. Earnings per share:

Earnings per share is calculated using earnings and the weighted-average number of common shares outstanding. Diluted earnings per share is calculated using earnings and the weighted-average number of diluted common shares outstanding.



----------------------------------------------------------------------------
----------------------------------------------------------------------------
three months nine months
ended September 30, ended September 30,
2007 2006 2007 2006
----------------------------------------------------------------------------
Weighted average common
shares outstanding 39,573,992 34,538,829 38,569,129 34,345,111
Shares issuable pursuant
to stock options 1,805,500 3,008,500 2,807,500 3,008,500
Shares to be purchased from
proceeds of stock options (878,170) (1,484,116) (1,739,849) (1,418,247)
----------------------------------------------------------------------------
Weighted average diluted
common shares outstanding 40,501,322 36,063,213 39,636,780 35,935,364
----------------------------------------------------------------------------
----------------------------------------------------------------------------


During the periods presented, outstanding stock options were the only dilutive instrument.

8. Commodity price risk management:

The Company is exposed to fluctuations in both natural gas and crude oil commodity prices. The Company monitors the risks associated with these prices and periodically utilizes fixed price contracts to manage its exposure to these risks.

(a) Natural Gas

The Company periodically enters into fixed price natural gas sales agreements to provide exposure to a portfolio of pricing indices. At September 30, 2007, the Company had the following fixed price physical natural gas sales agreements in place:



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

Period Gigajoules per day Fixed Price
----------------------------------------------------------------------------
(Cdn. $ per gj)
October 2007 to December 2007 1,000 $ 8.03
October 2007 to December 2007 1,000 $ 7.87
October 2007 to December 2007 1,000 $ 7.71
November 2007 to December 2007 1,000 $ 6.93
November 2007 to December 2007 1,000 $ 6.87
----------------------------------------------------------------------------
----------------------------------------------------------------------------


Subsequent to September 30, 2007 the Company entered into fixed price physical natural gas sales contracts at an intra-Alberta inventory transfer point for 3,000 gigajoules per day. The contracts cover the period from January 1, 2008 to March 31, 2008 at an average fixed price of $6.81 per gigajoule.

(b) Crude Oil

The Company periodically enters into crude oil sales agreements to provide exposure to a portfolio of pricing indices. At September 30, 2007, the Company had no contracts in place to fix the price on any portion of its crude oil production.



9. Changes in non-cash working capital

----------------------------------------------------------------------------
----------------------------------------------------------------------------
September 30, 2007 2006
----------------------------------------------------------------------------
Accounts receivable $ 2,687 $ (4,074)
Accounts payable and accrued liabilities 2,892 5,386
----------------------------------------------------------------------------
Total $ 5,579 $ 1,312
----------------------------------------------------------------------------
----------------------------------------------------------------------------

Relating to:

Operating activities $ 476 $ 100
Investing activities $ 5,103 $ 1,212
----------------------------------------------------------------------------
----------------------------------------------------------------------------

10. Segment information:

September 30, 2007
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Canada United Total
States
----------------------------------------------------------------------------
Revenues, net of royalties $ 23,050 $ 673 $ 23,723
Earnings before income taxes $ 3,017 $ 494 $ 3,511
Earnings $ 2,142 $ 493 $ 2,635
----------------------------------------------------------------------------
----------------------------------------------------------------------------

Petroleum and natural gas properties
Cost $ 160,851 $ 2,455 $ 163,306
Accumulated depletion, depreciation
and amortization (39,727) (1,226) (40,953)
----------------------------------------------------------------------------
Net book value $ 121,124 $ 1,229 $ 122,353
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Capital expenditures $ 42,194 $ 58 $ 42,252
----------------------------------------------------------------------------
----------------------------------------------------------------------------

September 30, 2006
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Canada United Total
States
----------------------------------------------------------------------------
Revenues, net of royalties $ 21,824 $ 840 $ 22,664
Earnings before income taxes $ 4,053 $ 612 $ 4,665
Earnings $ 2,814 $ 610 $ 3,424
----------------------------------------------------------------------------
----------------------------------------------------------------------------

Petroleum and natural gas properties
Cost $ 108,454 $ 2,404 $ 110,858
Accumulated depletion, depreciation
and amortization (25,968) (1,065) (27,033)
----------------------------------------------------------------------------
Net book value $ 82,486 $ 1,339 $ 83,825
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Capital expenditures $ 30,805 $ 328 $ 31,133
----------------------------------------------------------------------------
----------------------------------------------------------------------------



11. Commitments:

As a result of the private placement of flow-through common shares completed in May 2007, the Company is obligated to incur eligible Canadian Exploration Expenditures in the amount of $7.36 million under the flow-through share arrangement by December 31, 2008. As at September 30, 2007, approximately $3.4 million of exploration expenditures had been incurred to fulfill this flow-through obligation.

During the second quarter of 2007, the Company committed to spend approximately $2.1 million to acquire approximately 100 square kilometres of 3-D seismic.

Burmis has office lease space commitments of $59,000 in 2007, $338,000 in 2008, $372,000 in 2009, $384,000 in 2010, $387,000 in 2011 and $97,000 in 2012.

Contact Information

  • Burmis Energy Inc.
    Mr. Aidan M. Walsh, P.Eng., MBA
    President and Chief Executive Officer
    (403) 781-7284
    (403) 261-9028 (FAX)
    or
    Burmis Energy Inc.
    Mr. Scott R. Dyck, CA
    Chief Financial Officer
    (403) 781-7217
    (403) 261-9028 (FAX)
    Email: ir@burmisenergy.ca
    Website: www.burmisenergy.ca