Burmis Energy Inc.
TSX : BME

Burmis Energy Inc.

August 13, 2007 08:00 ET

Burmis Energy Reports Results for the Second Quarter of 2007

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

HIGHLIGHTS

- Drilled 15 gross (7.5 net) wells with an 85 percent success rate during the first half of 2007

- Average production increased eight percent to 2,286 barrels of oil equivalent per day in the second quarter of 2007 compared to 2,124 barrels of oil equivalent per day in the second quarter of 2006

- Closed a $7.36 million financing in May involving the issuance of 2.0 million flow-through common shares

- Tied in gas wells at Pembina, Easyford, and Brewster

- Current productive capability is approximately 2,500 net barrels of oil equivalent per day

- Tie-in projects are underway on five wells which have tested net deliverability of approximately 600 barrels of oil equivalent per day



three months six months
ended June 30, ended June 30,
2007 2006 2007 2006 Change
----------------------------------------------------------------------------
----------------------------------------------------------------------------
FINANCIAL
($000s, except shares and per
share amounts)
Gross petroleum and natural
gas revenue $ 10,535 $ 8,902 $ 20,055 $ 19,625 + 2%
Funds flow from operations (1) $ 4,964 $ 4,926 $ 10,283 $ 10,671 - 4%
Basic per share $ 0.13 $ 0.14 $ 0.27 $ 0.31 - 13%
Diluted per share $ 0.12 $ 0.14 $ 0.26 $ 0.30 - 13%
Earnings and other
comprehensive income $ 695 $ 948 $ 1,922 $ 2,188 - 12%
Basic per share $ 0.02 $ 0.03 $ 0.05 $ 0.06 - 17%
Diluted per share $ 0.02 $ 0.03 $ 0.05 $ 0.06 - 17%
Weighted average shares
('000's) 38,550 34,268 38,058 34,247 + 11%
Common shares outstanding
('000's) 39,561 34,523 39,561 34,523 + 15%
Capital expenditures (2) $ 7,183 $ 12,129 $ 30,955 $ 19,038 + 63%
Working capital deficiency $ 27,609 $ 10,693 + 158%
Total assets $122,388 $ 84,857 + 44%
Shareholders' equity $ 72,725 $ 53,655 + 36%
----------------------------------------------------------------------------
----------------------------------------------------------------------------

(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 in 2007 include $5.1 million for a producing
property acquisition in the Ferrier area of west central Alberta.


three months six months
ended June 30, ended June 30,
2007 2006 2007 2006 Change
----------------------------------------------------------------------------
----------------------------------------------------------------------------
OPERATING
Natural gas (mcf/day) 10,084 9,068 9,787 9,456 + 4%
Average price ($Cdn./mcf) $ 7.77 $ 6.20 $ 7.76 $ 7.12 + 9%
Oil and NGL's (bbl/day) 605 612 584 647 - 10%
Average price ($Cdn./bbl) $ 61.50 $ 67.54 $ 59.31 $ 63.17 - 6%
Barrels of oil equivalent per
day (1) 2,286 2,124 2,215 2,223 + -%
Operating netback ($Cdn./boe)
(2) $ 29.49 $ 29.42 $ 30.28 $ 29.43 + 3%
Cash netback ($Cdn./boe) (3) $ 23.86 $ 25.49 $ 25.65 $ 26.53 - 3%
----------------------------------------------------------------------------
----------------------------------------------------------------------------

(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

Burmis recorded average sales of 2,286 barrels of oil equivalent per day in the second quarter of 2007, an increase of eight percent compared to average production of 2,124 barrels of oil equivalent per day in the second quarter of 2006 and seven percent compared to average production of 2,143 barrels of oil equivalent per day in the first quarter of 2007. Average sales of 2,215 barrels of oil equivalent per day over the first half of 2007 were consistent with the prior year. The Company experienced downtime on a significant gas and condensate well at Brazeau due to a pipeline hydrate and an unscheduled plant outage. Downtime was also experienced at Hoadley and Westerose for three weeks due to a turnaround at the Rimbey gas plant. These operational factors reduced production by approximately 55 barrels of oil equivalent per day in the second quarter.

Burmis drilled 15 gross (7.5 net) wells in the first half of 2007, 11 (6.4 net) of which were cased as potential natural gas wells for an 85 percent success rate. In the second quarter, one (1.0 net) well was drilled and cased as a potential natural gas well at Whitecourt.

The second quarter was less active for the Company due to a prolonged spring break-up with corresponding extensive road bans in April and May and wet weather in May and June. The Company has commenced five gas well tie-in projects which were delayed due to the wet weather and extended spring break-up. The Company's drilling and completion programs, which were also delayed, are now underway.

At Easyford, one (0.25 net) gas well was tied in during June and is producing at approximately 0.2 million cubic feet per day. In the Brewster area, a natural gas well (0.4 net) was partially brought on-stream in late June. At Pembina, two (0.9 net) gas wells were tied-in in late July at a combined rate of 0.7 million cubic feet per day.

BRAZEAU

Two wells which were cased at Brazeau in the first quarter were completed in the second quarter. One (0.13 net) well tested natural gas at a rate of 2.5 million cubic feet per day. Another (0.33 net) well tested natural gas at a rate of 0.7 million cubic feet per day. These non-operated wells are awaiting tie-in.

Burmis procured and successfully tested a water disposal well which will be used to handle water from its Brazeau 1-26-46-13W5M Nisku natural gas and condensate well. This well in which Burmis has a 66 percent working interest will be tied into an existing midstream sour gas processing plant in the Brazeau area. Construction is currently underway on the gas gathering pipeline for this well. This project is expected to be completed in mid-August. The Company requires several approvals from the AEUB including a site specific Emergency Response Plan ("ERP") and approval to inject water in the disposal well prior to commencing production. This well is expected to add approximately 200 barrels of oil equivalent per day of initial net production to Burmis.

In July, the Company re-entered an 80 percent working interest well which tested natural gas at a rate of 2.5 million cubic feet per day on a short term test. The Company has started the approval process for the tie-in of this well to an existing third party gas plant. This well is expected to add approximately 220 barrels of oil equivalent per day of initial net production to Burmis in September.

An additional 25 percent working interest cased well at Brazeau is currently being completed to evaluate two potential productive zones.

BREWSTER

Burmis has an average working interest of 44 percent in fourteen sections of land in the Brewster area which has multi-zone potential for natural gas. The Company's first exploration well on this property commenced partial production in late June. Burmis has a 40 percent working interest in this well. The Company is participating with a 40 percent working interest in two development locations on this property in the third quarter. Burmis also plans to participate in a three-dimensional seismic program in the fourth quarter of 2007 to further evaluate its undeveloped lands at Brewster.

FERRIER NORTH

Burmis has a working interest of 100 percent in four sections of land at Ferrier North. The Company drilled and cased a gas well at Ferrier in the first quarter of 2007. This well was completed and commenced production in mid April at an initial rate of approximately 1.0 million cubic feet per day from a single zone. The Company has identified two additional prospective zones in this well for future evaluation. Burmis is currently drilling a development location to follow up on this discovery at Ferrier. The Company has identified two additional locations on its undeveloped lands and there is potential to down-space this property to two wells per section for optimum development.

PEMBINA

Two (0.9 net) gas wells which were drilled and cased in the first quarter were tied in and commenced production in July at a combined rate of 0.7 million cubic feet per day. Burmis has identified two (1.6 net) locations on this property for its winter drilling program.

During the second quarter Burmis constructed an 8.5 km pipeline to the west of the existing Blue Rapids gathering system. This new pipeline is a strategic asset which opens up a new drilling corridor and expands the capture area for the Blue Rapids Gas Plant in which the Company has a 15 percent ownership.

EASYFORD

The Company drilled and cased two (1.25 net) wells at Easyford in the first quarter. One (0.25 net) gas well was tied in and commenced production in June at a rate of 0.2 million cubic feet per day. The second (1.0 net) well was completed in July but did not yield economic hydrocarbons and was abandoned.

HOADLEY

Burmis is tying in a sour gas well at Hoadley which is expected to add approximately 80 barrels of oil equivalent per day of net production to Burmis. Due to land access issues, the Company is projecting this well to commence production in the fourth quarter.

COMMODITY PRICE RISK MANAGEMENT

Burmis has 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.

OUTLOOK

Burmis will continue with an active exploration and development program over the remainder of 2007. The Company has a program of medium depth locations targeting liquid rich natural gas at Ferrier, Brazeau and Brewster. One (1.0 net) cased well at Whitecourt, one (0.5 net) cased well at Tangent, and one (0.25 net) cased well at Brazeau are currently being completed.

Canadian natural gas prices have lagged surging crude oil prices in the first half of 2007 due to high storage levels in the United States and Canada. A higher volume of LNG imports into the USA market as a result of lower European natural gas prices contributed to higher storage builds. Canadian natural gas prices have also been negatively impacted by a higher Canadian dollar. However, natural gas remains the cleanest burning fossil fuel and the fossil fuel of choice for new electric generation projects. Ultimately the demand for this commodity will continue to grow. Furthermore, drilling activity for natural gas in Canada has been substantially reduced which will lower Canadian natural gas supply and provide support for natural gas prices.

Due to weather delays encountered and operational downtime incurred to date in 2007, and longer than expected approval processes for well tie-ins, the Company is revising its production guidance. Burmis is now estimating average production of 2,550 boepd for 2007 with an exit production rate of 3,250 boepd. The Company has reduced its capital budget to $50 million and plans to drill approximately 9 gross (5.4 net) wells in the second half of 2007.

Burmis is confident that its production base will grow in the second half of 2007 with tie-in projects underway for five liquid rich natural gas wells which are expected to add 600 barrels of oil equivalent per day of net production. Three additional wells are currently undergoing completion operations. Our near term drilling program includes wells at Ferrier, Brewster, and Brazeau. Industry service costs have improved in 2007 providing some offset to the challenge of lower natural gas prices. Our Company is building a solid and concentrated asset base in west central Alberta which supports our sustainability and our ability to overcome challenges and achieve profitable growth.

I look forward to further updating you on our activities as we implement the remainder of our 2007 exploration and development program.

Respectfully submitted on behalf of the Board of Directors,

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

August 13, 2007

MANAGEMENT'S DISCUSSION AND ANALYSIS - August 13, 2007

The following should be read in conjunction with the unaudited consolidated interim financial statements and notes thereto for the three and six months ended June 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 half 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 half of 2007 was very active for Burmis. The Company participated in drilling 15 gross (7.5 net) wells, and completed a complementary property acquisition in the Ferrier area of west central Alberta in late March. However, prolonged spring break-up conditions and generally wet weather in June of 2007 delayed well completion and tie-in activities, limiting growth in the Company's production.

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 half of 2007 did not increase as anticipated from the comparable period of 2006. Average production totaled 2,215 barrels of oil equivalent per day in the first half of 2007 compared to production of 2,223 barrels of oil equivalent per day in the comparable period of 2006. Funds flow from operations (defined above) totaled $10.3 million ($0.27 per common share - basic) in the first half of 2007 compared to $10.7 million ($0.31 per common share - basic) in the first half of 2006. Cash provided by operating activities during the first half of 2007 totaled $9.6 million, a decrease of seven percent compared to $10.4 million in the first half of 2006 as a result of increased asset retirement expenditures in 2007. Earnings and other comprehensive income totaled $1.9 million ($0.05 per common share - basic) in the first half of 2007 compared to $2.2 million ($0.06 per common share - basic) in the first half of 2006. During the second quarter of 2007, production averaged 2,286 barrels of oil equivalent per day, eight percent higher than 2,124 barrels of oil equivalent per day in the second quarter of 2006.

During the first half of 2007, the West Texas Intermediate ("WTI") reference price for crude oil averaged US $61.59 per barrel compared to US $67.14 per barrel during the first half of 2006. Crude oil prices decreased 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 have recovered to in excess of US $70 per barrel early in the second half of 2007 as reduced crude oil imports into the United States and increased refinery utilization rates have resulted in large draws in crude oil inventories. Additionally, ongoing geopolitical factors in Africa and the Middle East continue to underpin crude oil prices.

Natural gas prices increased during the first half of 2007, with the AECO reference price for natural gas averaging $6.87 per gigajoule compared to $6.46 per gigajoule in the first half 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. However, prices for natural gas have softened significantly as a result of higher than projected rates of natural gas storage builds, causing current natural gas prices in both Canada and the United States to be below prior year levels.

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

Revenues

Gross petroleum and natural gas revenues increased two percent to $20.1 million in the first half of 2007 compared to $19.6 million in 2006. The following table outlines gross revenues by product, as well as daily production volumes and sales prices by product.



----------------------------------------------------------------------------
----------------------------------------------------------------------------
six months ended June 30, 2007 2006
($000's unless otherwise noted) Daily Daily
Production Production
Component of Revenue Amount & Prices Amount & Prices
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Natural Gas $13,739 9,787 mcf/d $12,182 9,456 mcf/d
$ 7.76/mcf $ 7.12/mcf
Crude Oil & NGL's 6,268 584 bbl/d 7,420 647 bbl/d
$59.31/bbl $63.17/bbl (1)
Crude Oil Hedge Loss Realized - (25)
Royalty Income 48 48
----------------------------------------------------------------------------
$20,055 $19,625
----------------------------------------------------------------------------
----------------------------------------------------------------------------

(1) Includes impact of realized hedging losses.


Natural gas sales volumes increased four percent in the first half of 2007 over 2006 levels. Crude oil and natural gas liquid sales volumes decreased ten percent from 2006 to 2007 as reduced crude oil volumes at Easyford and Kidney and lower NGL production at Pembina more than offset the impact of increased NGL volumes from the Company's Brazeau and Ferrier properties.

During the first quarter of 2007, Burmis entered into fixed price physical natural gas sales contracts at an intra-Alberta inventory transfer point for 3,000 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:



----------------------------------------------------------------------------
----------------------------------------------------------------------------
Period Gigajoules per day Fixed Price
----------------------------------------------------------------------------
(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
----------------------------------------------------------------------------
----------------------------------------------------------------------------


Subsequent to June 30, 2007 the Company entered into fixed price physical natural gas sales contracts at an intra-Alberta inventory transfer point for 2,000 gigajoules per day. The contracts cover the period from November 1, 2007 to December 31, 2007 at an average fixed price of $6.90 per gigajoule.

There were no derivative financial instruments pertaining to the Company's production in place at June 30, 2007.



Royalties
----------------------------------------------------------------------------
----------------------------------------------------------------------------

six months ended June 30, 2007 2006
----------------------------------------------------------------------------
----------------------------------------------------------------------------
($'000's)

Crown royalties $3,379 $3,616

Other royalties 895 979

Alberta Royalty Tax Credit - (250)
----------------------------------------------------------------------------

Net royalties $4,274 $4,345
----------------------------------------------------------------------------
----------------------------------------------------------------------------

Average royalty rate as a percentage of revenues 21.3% 22.1%
----------------------------------------------------------------------------
----------------------------------------------------------------------------


Royalties were consistent from 2006 to 2007. As a percentage of revenue, royalties have decreased slightly compared to 2006. During the first half 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 $3.6 million ($9.08 per barrel of oil equivalent) during the first half of 2007 compared to $3.4 million ($8.55 per barrel of oil equivalent) during 2006. Total operating costs increased due to inflationary pressures and additional production from sour natural gas wells as compared to the prior year. On a barrel of oil equivalent basis, operating costs increased six percent in the first half of 2007 compared to the first half of 2006, consistent with the overall increase in operating costs.

Operating Netback

The Company's operating netback of $30.28 per barrel of oil equivalent in the first half of 2007 was three percent higher than the netback of $29.43 per barrel of oil equivalent the first half of 2006. The impact of increased natural gas prices was partially offset by reduced crude oil prices and increased operating costs per barrel of oil equivalent of production.

General and Administrative Expenses

General and administrative expenses totaled $1.5 million in the first half of 2007 compared to $1.1 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 the second quarter of 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 $70,000 in respect of an interest free loan made to an officer of the Company. On a barrel of oil equivalent basis, cash general and administrative expenses were $3.55 in the first half of 2007 compared to $2.66 in the first half of 2006.

Stock Based Compensation Expense

Stock based compensation expense totalled $415,000 in the first half of 2007 compared to $282,000 in the first half of 2006. During the first six months of 2007, the Company 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 $7.0 million in the first half of 2007 compared to $7.5 million in 2006. The decrease in depletion, depreciation and accretion expense is due to a reduction in the overall rate of depletion, depreciation and accretion to $17.53 per barrel of oil equivalent in 2007 from $18.53 in the first half of 2006. The decrease in the rate of depletion, depreciation and accretion in 2007 reflects the success achieved from the Company's capital program in 2006 and the first half of 2007.

Interest

Interest expense totalled $475,000 in the first half of 2007 compared to $101,000 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 the first half of 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 increased to $0.8 million in the first half of 2007 compared to $0.7 million in the comparable period of 2006. The tax provision in 2006 was reduced by an approximate $0.5 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.

SECOND QUARTER 2007 RESULTS

Revenues increased to $10.5 million in the second quarter of 2007 from $8.9 million in the second quarter of 2006. Natural gas production averaged 10,084 mcf per day in the second quarter of 2007 compared to 9,068 mcf per day in the second quarter of 2006 as a result of new wells at Brazeau and Ferrier, partially offset by reduced production at Pembina. Crude oil and NGL production averaged 605 barrels per day in the second quarter of 2007 compared to 612 barrels per day in the second quarter of 2006. Prices received for natural gas in the second quarter of 2007 were $7.77 per mcf, an increase of 25 percent compared to the second quarter of 2006 as a result of stronger AECO reference prices and the impact of the fixed price physical natural gas contracts entered into during the first quarter of 2007. Crude oil and NGL prices decreased nine percent to $61.50 per barrel in the second quarter of 2007 as a result of reductions in the WTI reference price and strengthening of the Canadian dollar as compared with 2006.

Royalties, as a percentage of revenue, increased to 22.2 percent in the second quarter of 2007 from 16.8 percent in the comparable period of 2006. During the second quarter of 2006, an adjustment to reduce crown royalties was received, reducing the effective royalty rate. Operating costs increased in the second quarter of 2007 as a result of increased production rates, inflationary pressures and increased production from sour natural gas wells.

The Company's operating netback of $29.49 per barrel of oil equivalent in the second quarter of 2007 was consistent with the operating netback of $29.42 realized in the second quarter of 2006. Increased commodity prices were offset by higher royalties and operating costs per barrel of oil equivalent.

Earnings in the second quarter of 2007 decreased to $0.7 million ($0.02 per common share - basic) from $0.9 million ($0.03 per common share - basic) in the second quarter of 2006.

CAPITAL EXPENDITURES

Capital expenditures totalled $31.0 million in the first half of 2007. The Company's capital program included exploratory drilling expenditures of $14.1 million, development drilling expenditures of $4.8 million and investments in production facilities totalling $5.0 million. During the first half of 2007, Burmis acquired approximately 2,400 acres of land at crown land sales for $1.6 million, and spent $0.4 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.

During the first half of 2006, the Company's capital expenditures totalled $19.0 million.

LIQUIDITY AND CAPITAL RESOURCES

At June 30, 2007 Burmis had a total working capital deficiency of $27.6 million.

The Company's revolving production loan 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 production loan 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 June 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 June 30, 2007, no exploration expenditures under this flow-through obligation had been incurred.

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

Burmis has remaining office lease space commitments of $118,000 in 2007 and $59,000 in 2008.

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 June 30, 2007 one loan in the amount of $250,000 had been provided under the program. Subsequent to June 30, 2007 two additional loans totalling $400,000 in aggregate were advanced under the program.

During the first half of 2007, the Company was charged legal fees totalling approximately $70,000 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 and / 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 December 31, 2006 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 2006 2005
OPERATING Second First Fourth Third Second First Fourth Third
----------------------------------------------------------------------------
Natural gas
(mcf/d) 10,084 9,486 9,417 9,914 9,068 9,848 7,615 6,864
Price
($/mcf) 7.77 7.74 7.00 5.74 6.20 7.97 11.30 8.87
Oil and
NGL's
(bbl/d) 605 562 527 606 612 682 616 695
Price
($/bbl) 61.50 56.91 54.91 66.60 67.54 59.20 59.92 63.64
Barrels of
oil
equivalent
(per day) 2,286 2,143 2,097 2,258 2,124 2,323 1,885 1,839
EARNINGS
('000's of
dollars)
----------------------------------------------------------------------------
Crude oil
and natural
gas liquid
revenues 3,389 2,879 2,662 3,715 3,764 3,631 3,508 4,056
Natural gas
revenues 7,146 6,641 6,079 5,256 5,138 7,092 7,947 5,616
Royalties (2,349) (1,925) (1,718)(1,587)(1,499)(2,846)(2,722)(2,492)
Interest
and other
income 37 6 7 2 1 9 4 7
-------------------------------------------------------------
8,223 7,601 7,030 7,386 7,404 7,886 8,737 7,187
Operating
expenses 2,052 1,590 2,038 1,713 1,716 1,723 1,552 1,321
General and
administrative 973 520 480 426 681 390 363 403
Stock based
compensation 222 193 184 126 95 187 198 202
Depletion,
depreciation
and accretion 3,658 3,370 3,248 3,259 3,525 3,929 3,117 2,491
Loss on
provision
for retirement
obligation - - 548 - - - - -
Interest 303 172 203 131 73 28 16 83
Other - - - 1 8 - 2 13
-------------------------------------------------------------
Total
expenses 7,208 5,845 6,701 5,656 6,098 6,257 5,248 4,513
Earnings
before income
taxes 1,015 1,756 329 1,730 1,306 1,629 3,489 2,674
Current income
taxes 1 - - 2 - - - 1
Future income
taxes 319 529 (274) 492 358 389 1,096 1,025
-------------------------------------------------------------
320 529 (274) 494 358 389 1,096 1,026
-------------------------------------------------------------
Earnings
and other
comprehensive
income 695 1,227 603 1,236 948 1,240 2,393 1,648
----------------------------------------------------------------------------
----------------------------------------------------------------------------
per share (basic) $0.02 $0.03 $0.02 $0.04 $0.03 $0.04 $0.07 $0.05
----------------------------------------------------------------------------
----------------------------------------------------------------------------
FUNDS FLOW
('000's of
dollars) 4,964 5,319 4,309 5,113 4,926 5,745 6,694 5,381
----------------------------------------------------------------------------
----------------------------------------------------------------------------
per share (basic) $0.13 $0.14 $0.12 $0.15 $0.14 $0.17 $0.20 $0.17
----------------------------------------------------------------------------
----------------------------------------------------------------------------
NETBACKS ($/boe)
----------------------------------------------------------------------------
Petroleum
and natural
gas revenues 50.64 49.35 45.32 43.17 46.06 51.29 65.40 57.25
Royalties (11.29) (9.98) (8.91) (7.63) (7.76)(13.61)(15.69)(14.73)
Operating
expenses (9.86) (8.24) (10.57) (8.25) (8.88) (8.24) (8.95) (7.81)
-------------------------------------------------------------
Operating
netback 29.49 31.13 25.84 27.29 29.42 29.44 40.76 34.71
General and
administrative (4.34) (2.69) (2.48) (2.05) (3.52) (1.87) (2.09) (2.38)
Interest
and other
income
(expense) (1.28) (0.86) (1.02) (0.63) (0.41) (0.09) (0.08) (0.53)
Current income
taxes (0.01) - - - - - - -
-------------------------------------------------------------
Cash netback 23.86 27.58 22.34 24.61 25.49 27.48 38.59 31.80
----------------------------------------------------------------------------
----------------------------------------------------------------------------
TOTAL ASSETS
($'000's of
dollars) 122,388 120,456 100,737 96,693 84,857 73,230 71,876 68,302
----------------------------------------------------------------------------
----------------------------------------------------------------------------


BURMIS ENERGY INC.
Consolidated Balance Sheets

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

Assets
Current assets
Cash $ 127 $ 31
Accounts receivable 7,363 10,301
----------------------------------------------------------------------------
7,490 10,332
Petroleum and natural gas properties (note 2) 114,718 90,405
Loan receivable (note 3) 180 -
----------------------------------------------------------------------------
$ 122,388 $ 100,737
----------------------------------------------------------------------------
----------------------------------------------------------------------------

Liabilities and Shareholders' Equity
Current liabilities
Accounts payable and accrued liabilities $ 15,480 $ 15,020
Production loan facility (note 4) 19,619 8,000
Current portion of asset retirement obligation
(note 5) - 669
----------------------------------------------------------------------------
35,099 23,689
Asset retirement obligation (note 5) 2,930 2,777
Future income tax liability 11,634 7,601
Shareholders' equity
Share capital (note 6) 56,613 52,895
Contributed surplus (note 6) 1,882 1,467
Retained earnings 14,230 12,308
----------------------------------------------------------------------------
72,725 66,670

$ 122,388 $ 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 period
ended June 30, ended June 30,
(unaudited) 2007 2006 2007 2006
----------------------------------------------------------------------------
Revenues
Petroleum and natural gas
(note 8) $ 10,535 $ 8,902 $20,055 $ 19,625
Royalties (2,349) (1,499) (4,274) (4,345)
Interest and other income 37 1 43 10
----------------------------------------------------------------------------
8,223 7,404 15,824 15,290
Expenses
Operating 2,052 1,716 3,642 3,439
General and administrative 973 681 1,493 1,071
Stock based compensation 222 95 415 282
Depletion, depreciation and
accretion 3,658 3,525 7,028 7,454
Interest paid 303 73 475 101
Other - 8 - 8
----------------------------------------------------------------------------
7,208 6,098 13,053 12,355
Earnings and other
comprehensive income before
income taxes 1,015 1,306 2,771 2,935
Income taxes
Current 1 - 1 -
Future 319 358 848 747
----------------------------------------------------------------------------
320 358 849 747
----------------------------------------------------------------------------
Earnings and other
comprehensive income $ 695 $ 948 $ 1,922 $ 2,188
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Earnings and other
comprehensive income per share
(note 7)
Basic $ 0.02 $ 0.03 $ 0.05 $ 0.06
Diluted $ 0.02 $ 0.03 $ 0.05 $ 0.06
----------------------------------------------------------------------------
----------------------------------------------------------------------------


Consolidated Statement of Retained Earnings and Other Comprehensive Income
(thousands of dollars)
----------------------------------------------------------------------------
----------------------------------------------------------------------------

three months six months
ended June 30, ended June 30,
(unaudited) 2007 2006 2007 2006
----------------------------------------------------------------------------
Retained earnings and other
comprehensive income,
beginning of period $ 13,535 $ 9,521 $12,308 $ 8,281
Earnings and other
comprehensive income 695 948 1,922 2,188
----------------------------------------------------------------------------
Retained earnings and other
comprehensive income,
end of period $ 14,230 $ 10,469 $14,230 $ 10,469
----------------------------------------------------------------------------
----------------------------------------------------------------------------

See accompanying notes to consolidated financial statements.


BURMIS ENERGY INC.
Consolidated Statement of Cash Flows

(thousands of dollars, except per share amounts)
----------------------------------------------------------------------------
----------------------------------------------------------------------------

three months six months
ended June 30, ended June 30,
(unaudited) 2007 2006 2007 2006
----------------------------------------------------------------------------

Cash provided by (used in)
Operations
Earnings and other comprehensive
income $ 695 $ 948 $ 1,922 $ 2,188
Items not affecting cash
Depletion, depreciation and
accretion 3,658 3,525 7,028 7,454
Stock based compensation 222 95 415 282
Non-cash compensation 70 - 70 -
Future income taxes 319 358 848 747
Asset retirement expenditures (112) (27) (902) (27)
Changes in non-cash working
capital (note 9) 58 (1,198) 262 (289)
----------------------------------------------------------------------------
4,910 3,701 9,643 10,355
Financing
Production loan facility 879 4,610 11,619 4,787
Issue of common shares for
cash, net of share issue costs 6,903 - 6,903 -
Exercise of stock options - 164 - 164
----------------------------------------------------------------------------
7,782 4,774 18,522 4,951
Investments
Additions to petroleum and
natural gas properties (7,183) (12,129) (25,896) (19,038)
Acquisition of petroleum and
natural gas properties - - (5,059) -
Changes in non-cash working
capital (note 9) (5,269) 3,731 3,136 3,388
Loan receivable (note 3) (250) - (250) -
----------------------------------------------------------------------------
(12,702) (8,398) (28,069) (15,650)

Increase (decrease) in cash (10) 77 96 (344)
Cash, beginning of period 137 - 31 421
----------------------------------------------------------------------------
Cash, end of period $ 127 $ 77 $ 127 $ 77
----------------------------------------------------------------------------
----------------------------------------------------------------------------

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 June 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 December 31, 2006 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:
----------------------------------------------------------------------------
----------------------------------------------------------------------------
June 30, December 31,
2007 2006
----------------------------------------------------------------------------
Petroleum and natural gas properties $ 151,888 $ 120,642
Accumulated depletion and depreciation (37,170) (30,237)
----------------------------------------------------------------------------
$ 114,718 $ 90,405
----------------------------------------------------------------------------
----------------------------------------------------------------------------


Costs of unproved properties excluded from costs subject to depletion and depreciation at June 30, 2007 were $7.1 million. Future development costs of $2.1 million have been included in costs subject to depletion.

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

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 June 30, 2007 one loan in the amount of $250,000 had been provided under the program. This has been recorded as a loan receivable in the amount of $180,000, being the fair value of the loan at the time it was made assuming settlement in March 2012 using a discount rate of 8.0 percent, and a non-cash compensation charge of $70,000. Subsequent to June 30, 2007 two additional loans totalling $400,000 in aggregate were advanced under the program.

4. Production loan facility:

During the reported period, the Company's revolving production loan 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 June 30, 2007 is approximately $3.9 million. These costs will be incurred between 2007 and 2027, with a significant majority being incurred after 2007. A credit adjusted risk-free rate of six percent was used to calculate the fair value of the asset retirement obligations.



A reconciliation of the asset retirement obligation is provided below:
----------------------------------------------------------------------------
----------------------------------------------------------------------------
six months ended June 30, 2007 2006
----------------------------------------------------------------------------
Balance, beginning of period $ 3,446 $ 2,433
Accretion expense 95 75
Liabilities incurred 291 385
Liabilities settled (902) (27)
----------------------------------------------------------------------------
Balance, end of period $ 2,930 $ 2,866
----------------------------------------------------------------------------
----------------------------------------------------------------------------


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
Tax effect of 2006 flow-through share issue - (3,327)
Share issuance costs - (457)
Tax benefit of share issue costs - 142
----------------------------------------------------------------------------
Balance, June 30, 2007 39,561,133 $ 56,613
----------------------------------------------------------------------------
----------------------------------------------------------------------------


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:
----------------------------------------------------------------------------
----------------------------------------------------------------------------
six months ended June 30, 2007 2006
----------------------------------------------------------------------------
Balance, beginning of period $ 1,467 $ 998
Stock-based compensation expense 415 282
Transfer to share capital on exercise of stock
options - (76)
----------------------------------------------------------------------------
Balance, end of period $ 1,882 $ 1,204
----------------------------------------------------------------------------
----------------------------------------------------------------------------


(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 June 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
----------------------------------------------------------------------------
Outstanding, June 30, 2007 3,745,500 $ 1.70 2.4 years
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Exercisable, June 30, 2007 2,368,000 $ 1.04 1.3 years
----------------------------------------------------------------------------
----------------------------------------------------------------------------


The outstanding stock options and associated exercise prices are outlined
below:
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Weighted Average
Exercise Price Shares Life Remaining
----------------------------------------------------------------------------
$ 0.50 1,485,000 0.6 years
$ 1.02 - $1.35 331,500 1.8 years
$ 2.45 - $2.57 1,008,000 3.2 years
$ 2.97 - $3.10 921,000 4.6 years
----------------------------------------------------------------------------
$ 0.50 - $3.10 3,745,500 2.4 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 six months
ended June 30, ended June 30,
2007 2006 2007 2006
----------------------------------------------------------------------------
Weighted average common
shares outstanding 38,550,144 34,267,924 38,058,371 34,246,647
Shares issuable pursuant
to stock options 2,824,500 2,713,500 2,824,500 2,713,500
Shares to be purchased
from proceeds of stock
options (1,639,688) (969,345) (1,778,564) (932,806)
----------------------------------------------------------------------------
Weighted average diluted
common shares
outstanding 39,734,956 36,012,079 39,104,307 36,027,341
----------------------------------------------------------------------------
----------------------------------------------------------------------------

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 June 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)
July 2007 to December 2007 1,000 $ 8.03
July 2007 to December 2007 1,000 $ 7.87
July 2007 to December 2007 1,000 $ 7.71
----------------------------------------------------------------------------
----------------------------------------------------------------------------


Subsequent to June 30, 2007 the Company entered into fixed price physical natural gas sales contracts at an intra-Alberta inventory transfer point for 2,000 gigajoules per day. The contracts cover the period from November 1, 2007 to December 31, 2007 at an average fixed price of $6.90 per gigajoule.

(b) Crude Oil

The Company periodically enters into crude oil sales agreements to provide exposure to a portfolio of pricing indices. At June 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
----------------------------------------------------------------------------
----------------------------------------------------------------------------
June 30, 2007 2006
----------------------------------------------------------------------------
Accounts receivable $ 2,938 $ (1,281)
Accounts payable 460 4,380
----------------------------------------------------------------------------
Total $ 3,398 $ 3,099
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Relating to:

Operating activities $ 262 $ (289)
Investing activities $ 3,136 $ 3,388
----------------------------------------------------------------------------
----------------------------------------------------------------------------


10. Segment information:

June 30, 2007
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Canada United States Total
----------------------------------------------------------------------------
Revenues, net of royalties $ 15,310 $ 471 $ 15,781
Earnings before income taxes $ 2,423 $ 348 $ 2,771
Earnings $ 1,575 $ 347 $ 1,922
----------------------------------------------------------------------------
----------------------------------------------------------------------------

Petroleum and natural gas properties
Cost $ 149,490 $ 2,398 $ 151,888
Accumulated depletion, depreciation
and amortization (35,975) (1,195) (37,170)
----------------------------------------------------------------------------

Net book value $ 113,515 $ 1,203 $ 114,718
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Capital expenditures $ 30,955 $ - $ 30,955
----------------------------------------------------------------------------
----------------------------------------------------------------------------

June 30, 2006

----------------------------------------------------------------------------
----------------------------------------------------------------------------
Canada United States Total
----------------------------------------------------------------------------
Revenues, net of royalties $ 14,753 $ 527 $ 15,280
Earnings before income taxes $ 2,545 $ 390 $ 2,935
Earnings $ 1,798 $ 390 $ 2,188
----------------------------------------------------------------------------
----------------------------------------------------------------------------

Petroleum and natural gas properties
Cost $ 96,237 $ 2,399 $ 98,636
Accumulated depletion, depreciation
and amortization (22,791) (1,028) (23,819)
----------------------------------------------------------------------------
Net book value $ 73,446 $ 1,371 $ 74,817
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Capital expenditures $ 18,715 $ 323 $ 19,038
----------------------------------------------------------------------------
----------------------------------------------------------------------------

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