Sierra Vista Energy Ltd.
TSX VENTURE : SVR.A
TSX VENTURE : SVR.B

Sierra Vista Energy Ltd.

November 29, 2007 19:18 ET

Sierra Vista Announces Filing of Third Quarter 2007 Financial Statements and MD&A and Updates Reserves

CALGARY, ALBERTA--(Marketwire - Nov. 29, 2007) -

NOT FOR DISTRIBUTION IN THE UNITED STATES NEWSWIRE SERVICES OR FOR DISSEMINATION IN THE UNITED STATES.

Sierra Vista Energy Ltd. (TSX VENTURE:SVR.A) (TSX VENTURE:SVR.B) ("Sierra Vista" or the "Company") today announces that it has filed its unaudited interim financial statements and management's discussion and analysis for the three and nine months ended September 30, 2007. Select operational and financial results are outlined below and should be read in conjunction with the Company's unaudited interim financial statements and related MD&A which can be found on Sedar at www.sedar.com. The Company also announces that it has received the updated independent evaluation of its reserves as at September 30, 2007. Select reserve information is outlined in the tables below.

Third Quarter Events Include the Following:

- Production averaged 303 boe/d for the first nine months of 2007 as compared to 138 boe/d in the first nine months of 2006, representing a 120% increase. For the three months ended September 30, 2007 production averaged 291 boe/d as compared to 135 boe/d for the same quarter in 2006, representing a 116% increase, quarter over quarter.

- Revenue increased 125% in the first nine months of 2007 to $4,330,640 from $1,924,457 for the first nine months of 2006. For the third quarter 2007, revenue increased 118% to $1,293,672 from $594,130 recorded in the third quarter of 2006;

- Cash flow was $452,187 in the first nine months of 2007 a decrease from $929,058 in the same period of 2006, a decrease of 51%, year over year. For the third quarter of 2007, the Company recorded negative cash flow of $265,692 due to increased operating and G&A expenses incurred during the quarter.

- Subsequent to September 30, 2007, the Company elected not to proceed with completion of the Ante Creek farm-in agreement thereby eliminating approximately $6,868,000 in future capital commitments that would have been required to satisfy its obligation under the Ante Creek farm-in agreement.

- During the quarter, the Company announced that the President and CEO and the Vice-President, Business Development both ceased employment with the Company. The Company is continuing its search for a new President; and

- The Company has initiated a rigorous G&A cost reduction program to reduce overall G&A expenses going forward.



Three Months Ended Nine Months Ended
September 30 September 30
2007 2006 2007 2006
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Financial
Petroleum and
natural gas
revenue $ 1,293,672 594,130 $ 4,330,640 $ 1,924,457
Cash flow from
operations ($265,692) $ 279,917 $ 452,187 $ 929,058
Per share -
basic ($0.01) $ 0.01 $ 0.01 $ 0.04
Per share -
diluted ($0.01) $ 0.01 $ 0.01 $ 0.04
Net income
(loss) ($21,812,121) ($105,355) ($22,932,704) $ 562,641
Per share -
basic ($0.52) $ 0.00 ($0.57) $ 0.03
Per share -
diluted ($0.52) $ 0.00 ($0.57) $ 0.03
Capital
expenditures $ 326,428 $ 6,483,386 $ 5,408,040 $ 19,008,878
Working
capital
deficiency,
including
bank debt ($1,744,901) ($3,204,067) ($1,744,901) ($3,204,067)
Total assets $ 17,205,287 $ 27,433,823 $ 17,205,287 $ 27,433,823

Operating
Crude oil and
natural gas
liquids (bbl/d) 118 53 136 56
Natural gas
(mcf/d) 1,035 490 1,002 492
Barrels of oil
equivalent
(boe/d) (6:1) 291 135 303 138

Average Prices
Crude oil and
natural gas
liquids
($/bbl) $ 69.48 $ 67.56 $ 64.32 $ 65.55
Natural gas
($/mcf) $ 5.66 $ 5.95 $ 7.13 $ 6.93
Barrels of oil
equivalent
($/boe) $ 48.38 $ 48.19 $ 52.41 $ 51.29

Field
operating
netback per
boe $ 19.34 $ 32.94 $ 26.37 $ 34.98

Share Capital
Weighted
average
shares
outstanding 41,676,950 26,107,270 40,509,594 21,152,077
Actual Class A
Shares
outstanding -
end of period 29,976,950 17,487,950 29,976,950 17,487,950
Actual Class B
Shares
outstanding -
end of period 1,170,000 1,170,000 1,170,000 1,170,000
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Reserves Update

As outlined in the Company's news release dated August 31, 2007, the Company commissioned an updated independent reserve evaluation from Sproule Associates Limited ("Sproule"). The evaluation was completed using the reserves definitions in the Canadian Oil and Gas Evaluation Handbook and the Canadian Securities Administrators National Instrument 51-101 ("NI 51-101"). The evaluation was effective September 30, 2007 and incorporated the termination of the Ante Creek farm-in agreement and the resulting forfeiture of 32.5% working interest in the 3.25 sections of land earned under the farm-in agreement. Total working interest proved plus probable reserves at September 30, 2007 were 890,200 boe comprised of 309,600 barrels of oil and natural gas liquids and 3,483 million cubic feet of natural gas. The following table summarizes the Company's working interest reserves on a gross basis (before deduction for royalties) and the Net Present Value of the Reserves as at September 30, 2007 using forecasted prices and costs based on the Sproule September 30, 2007 price forecast.



SUMMARY OF OIL AND NATURALGAS RESERVES
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Net Present Value
Working Interest Reserves (Before Tax)
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Oil and Liquids Natural Gas Total 5% 10%
(Mbbl) (MMcf) (Mboe) ($000'S) ($000'S)
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Proved
Developed
Producing 107.0 1,245 314.4 8,433 7,458
Developed
Non-Producing 4.2 10 5.9 101 89
Undeveloped 84.5 797 217.3 2,251 1,552
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Total Proved 195.6 2,052 537.6 10,785 9,099
Probable 114.1 1,431 352.6 6,148 4,462
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Total Proved Plus
Probable 309.6 3,483 890.2 16,932 13,561
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RECONCILIATION OF COMPANY INTEREST RESERVES BY BARREL OF OIL EQUIVALENT

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BOE
----------------------------------------------------------------------------
Proved Plus
Proved Probable
Factors (Mboe) (Mboe)
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December 31, 2006 1,102 1,636

Discoveries - -
Extensions - -
Infill drilling - -
Technical revisions (258) (333)
Working interest revisions (236) (357)
Economic factors 13 27
Acquisitions - -
Dispositions - -
Production(1) (83) (83)
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September 30, 2007 538 890
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(1) Unaudited


Outlook

Although the Company has scaled back its operations and has implemented a cost reduction program, it will continue with a program to meet its obligations associated with the flow-through shares issued in 2006 and 2007. To this end, the Company is pleased to announce that today it is expected to spud an exploration well that is expected to complete its remaining Canadian Exploration Expense obligation for 2007. The anticipated cost to drill, case and complete the well is $1,450,000. The Company is currently formulating its plans for 2008.

MANAGEMENT'S DISCUSSION AND ANALYSIS

The following management discussion and analysis ("MD&A") of financial conditions and results of operations is as of November 29, 2007 and should be read in conjunction with the unaudited interim financial statements of Sierra Vista Energy Ltd. ("Sierra Vista" or the "Company") for the three and nine months ended September 30, 2007 and the audited financial statements for the year ended December 31, 2006 and also should be read in conjunction with the Company's December 31, 2006 MD&A. Additional information relating to the Company, including the Company's December 31, 2006 Annual Information Form, can be found on the SEDAR website at www.sedar.com.

Discussion with regard to Sierra Vista's 2007 outlook is based on currently available information. The financial data presented below has been prepared in accordance with Canadian generally accepted accounting principles (GAAP). The reporting and operating currency is the Canadian dollar.

This MD&A contains the terms "funds flow from operations", "funds flow per share" and "operating netback" which do not have standardized meanings prescribed by Canadian GAAP and therefore may not be comparable to performance measures presented by others. Funds flow from operations, as used by the Company, is comprised of cash flow from operating activities before changes in non-cash operating working capital. Operating netback represents revenue less royalties, operating expenses and transportations expenses. These non-GAAP measures may not be comparable to the calculation of similar measures for other entities. The Company believes that operating netback and funds flow from (used by) operations represent indicators of the Company's performance and a key measure of the Company's ability to generate the necessary cash to fund future capital expenditures. Funds from (used by) operations and operating netback as presented is not intended to represent operating cash flow or operating profits for the period nor should they be viewed as an alternative to cash flow from operating activities, net earnings (loss) or other measures of financial performance calculated in accordance with Canadian GAAP. See "Funds Flow from Operations" and "Netbacks".

The term barrels of oil equivalent ("boe") may be misleading, particularly if used in isolation. A boe conversion ratio of 6 thousand cubic feet (mcf) equals 1 barrel (bbl) is based on an energy equivalency conversion method primarily applicable at the burner tip and does not represent a value equivalency at the wellhead. All boe conversions in this report are derived by converting gas to oil in the ratio of six thousand cubic feet of gas to one barrel of oil.

SPECIAL NOTE REGARDING FORWARD-LOOKING STATEMENTS

Certain information regarding the Company set forth in this report includes forward looking statements. All statements other than statements of historical facts contained in this MD&A, including statements regarding our future financial position, business strategy and plans and objectives of management for future operations, are forward-looking statements. The words "believe," "may," "will," "estimate," "continue," "anticipate," "intend," "should," "plan," "expect" and similar expressions, as they relate to us, are intended to identify forward-looking statements. We have based these forward-looking statements largely on our current expectations and projections about future events and financial trends that we believe may affect our financial condition, results of operations, business strategy and financial needs. These forward-looking statements are subject to a number of risks, uncertainties and assumptions described elsewhere in this report.

Other sections of this report may include additional factors, which could adversely affect our business and financial performance. Moreover, we operate in a very competitive and rapidly changing environment. New risk factors emerge from time to time and it is not possible for our management to predict all risk factors, nor can we assess the impact of all factors on our business or the extent to which any factor, or combination of factors, may cause actual results to differ materially from those contained in any forward-looking statements.

Readers are cautioned not to place undue reliance on forward-looking statements, as there can be no assurance that the plans, intentions or expectations upon which they are based will occur. By their nature, forward-looking statements involve numerous assumptions, known and unknown risks and uncertainties, both general and specific, that contribute to the possibility that the predictions, forecasts, projections and other forward-looking statements will not occur, which may cause the Company's actual performance and financial results in future periods to differ materially from any estimates or projections of future performance or results expressed or implied by such forward-looking statements.

We undertake no obligation to update publicly or revise any forward-looking statements. Furthermore, the forward-looking statements contained in this report are made as of the date of this report, and we undertake no obligation to update publicly or to revise any of the included forward-looking statements unless required by applicable securities laws, whether as a result of new information, future events or otherwise. The forward-looking statements in this report are expressly qualified by this cautionary statement.

CORPORATE OVERVIEW

Sierra Vista Energy Ltd. was incorporated under the laws of the Province of Alberta on June 7, 2005 and commenced operation in September 2005. Sierra Vista is a public junior oil and natural gas company focused on the exploration and development and production of light crude oil and natural gas principally in the Peace River Arch area of central Alberta. The Company's shares trade on the TSX Venture exchange under the symbols SVR.A and SVR.B.



SELECTED INFORMATION
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Three Months Ended Nine Months Ended
September 30 September 30
2007 2006 2007 2006
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Petroleum and
natural gas
revenue, before
royalties $ 1,293,672 $ 594,130 $ 4,330,640 $ 1,924,457
Funds flow
from (used
in) operations ($265,692) $ 279,917 $ 452,187 $ 929,058
Funds flow
from (used
in) operations
per share -
basic and
diluted ($0.01) $ 0.01 $ 0.01 $ 0.04
Net (loss)
income ($21,812,121) ($105,355) ($22,932,704) $ 562,641
Net (loss)
income per
share -
basic ($0.52) $ 0.00 ($0.57) $ 0.03
Net (loss)
income per
share -
diluted ($0.52) $ 0.00 ($0.57) $ 0.03
Capital
expenditures $ 326,428 $ 6,483,386 $ 5,408,040 $ 19,008,878
Working
capital
deficit,
including
bank debt ($1,744,901) ($3,204,067) ($1,744,901) ($3,204,067)
Production
(boe/d) 291 135 303 138
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PRODUCTION
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Three Months Ended Nine Months Ended
September 30 September 30
2007 2006 2007 2006
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Production
Crude oil and
natural
gas liquids
(bbl/d) 118 53 136 56
Natural gas
(mcf/d) 1,035 490 1,002 492
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Oil equivalent
production
(boe/d) 291 135 303 138
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For the three months ended September 30, 2007, Sierra Vista averaged 291 boe/d as compared with 135 boe/d in the third quarter of 2006, a 116% increase quarter over quarter. Production for the quarter was comprised of 118 boe/d of crude oil and natural gas liquids and 1,035 mcf/d of natural gas resulting in a 41% weighting to light (40oAPI), sweet, crude oil.

For the nine months ended September 30, 2007, Sierra Vista averaged 303 boe/d as compared to 138 boe/d for the nine months ended September 30, 2006, representing a 120% increase. Production for the nine months ended September 30, 2007 was comprised of 136 boe/d of crude oil and natural gas liquids and 1,002 mcf/d of natural gas resulting in a 45% weighting to light, sweet, crude oil, consistent with the third quarter of 2007.



PRICING

Benchmark Prices

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Three Months Ended Nine Months Ended
September 30 September 30
2007 2006 2007 2006
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Crude oil - WTI (US$ per Bbl) $ 70.57 $ 70.36 $ 68.15 $ 68.70
Crude oil - Edmonton Par Price
($ per Bbl) $ 80.27 $ 79.40 $ 76.60 $ 76.79
Natural gas - AECO ($/mcf) $ 5.67 $ 6.09 $ 6.37 $ 6.02
Exchange rate ($US/$Cdn) 0.96 0.89 0.91 0.88
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West Texas Intermediate at Cushing, Oklahoma ("WTI") is the benchmark reference price for North American crude oil prices. Canadian crude oil prices are based upon the average of several postings, primarily at Edmonton Alberta, and represents the WTI price adjusted for quality and transportation differentials, the US/CDN dollars exchange rate and local demand and supply influences. Crude oil prices averaged US$70.57 per barrel and $80.27 at Edmonton for the third quarter of 2007 as global political instability and concerns regarding crude oil supply levels continued to keep global oil prices unstable and at historical highs.

United States natural gas prices are commonly referenced to the New York Mercantile Exchange at Henry Hub in Louisiana ("NYMEX") while Canadian natural gas prices are typically referenced to the AECO Hub in Alberta. Natural gas prices are influenced more by North American supply and demand than global fundamentals. Natural gas prices averaged $5.67 per Mcf at AECO with prices remaining very volatile as current natural gas inventory levels remain at or above the five year average. North American weather during the winter heating season will be a major factor in future natural gas pricing.



Realized Prices

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Three Months Ended Nine Months Ended
September 30 September 30
2007 2006 2007 2006
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Average Prices
Crude oil and natural gas liquids
($/bbl) $ 69.48 $ 67.56 $ 64.32 $ 65.55
Natural gas ($/mcf) $ 5.66 $ 5.95 $ 7.13 $ 6.93
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Oil equivalent ($/boe) $ 48.38 $ 48.19 $ 52.41 $ 51.29
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Sierra Vista's averaged realized price for its crude oil and natural gas liquids was $69.48 per barrel in the third quarter of 2007 and $5.66 per mcf for natural gas. For the nine months ended September 30, 2007, Sierra Vista's realized price for crude oil and natural gas liquids was $64.32 per barrel and $7.13 per mcf for natural gas. The Company continues to realize an approximately 10% premium natural gas price as compared to the AECO benchmark prices, reflecting the higher heat content of Sierra Vista's natural gas stream coming from the Company's Ante Creek property. In addition, greater than 90% of Sierra Vista's crude oil production is light, sweet oil (40o API) which receives top tier pricing relative to the Edmonton posted price.



REVENUES

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Three Months Ended Nine Months Ended
September 30 September 30
2007 2006 2007 2006
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Production Revenue
Crude oil and natural gas
liquids $ 755,064 $ 325,532 $ 2,381,058 $ 996,580
Natural gas $ 538,608 $ 268,598 $ 1,949,582 $ 927,877
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Total production revenue $ 1,293,672 $ 594,130 $ 4,330,640 $ 1,924,457
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For the three months ended September 30, 2007, Sierra Vista recorded $755,064 in crude oil and natural gas liquids sales and $538,608 in natural gas sales, a 132% and 101% increase, respectively over the third quarter of 2006. The increase in crude oil revenue in the quarter was attributable to a 123% increase in crude oil and natural gas liquids production in the third quarter of 2007 coupled with a 3% increase in the crude oil and natural gas liquids prices in the quarter. The increase in natural gas revenue is a result of an 111% increase in natural gas production in the third quarter of 2007 combined partially offset by a 7% decrease in realized natural gas prices in the quarter, as compared to the third quarter of 2006.

For the nine months ended September 30, 2007, Sierra Vista recorded $2,381,058 in crude oil and natural gas liquids sales and $1,949,582 in natural gas sales, a 139% and 110% increase respectively over the nine months ended September 30, 2006. The increase in crude oil revenue is a result of a 143% increase in crude oil and natural gas liquids production for the nine months ended September 30, 2007 which was partially offset by a 2% reduction in crude oil prices received for 2007 as compared to the same period in 2006. The increase in natural gas revenue is attributable to a 104% increase in natural gas production and a 3% increase in natural gas prices for the nine months ended September 30, 2007 as compared to the same period in 2006.

The Company currently has no financial derivatives or physical delivery contracts in place. All production volumes are currently sold into the Alberta spot market.



ROYALTIES

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Three Months Ended Nine Months Ended
September 30 September 30
2007 2006 2007 2006
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Gross royalties $234,977 $114,364 $791,098 $416,602
Alberta Royalty Tax Credit - ($17,629) - ($92,711)
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Net royalties $234,977 $ 96,735 $791,098 $323,891
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As a percentage of revenue 18% 16% 18% 17%
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On a per boe basis $ 8.79 $ 7.83 $ 9.57 $ 8.62
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The average royalty rate for the third quarter 2007 increased to 18% of revenue as compared to the average royalty rate in the third quarter of 2006 of 16%. The increase in the average royalty rate is a result of the elimination of the ARTC program by the Alberta government. Effective January 1, 2007, the Alberta government eliminated the ARTC program which will have the affect of increasing the royalties paid as a percentage of revenue. Royalties for the three and nine months ended September 30, 2007, on a per boe basis, were $8.79 and $9.57, respectively, as compared to $7.83 and $8.62 for the same periods in 2006. The increase on a per boe basis is a result of the elimination of the ARTC program.

On October 25, 2007, the Alberta government announced the New Royalty Framework that will come into effect on January 1, 2009, which was in response to the Alberta Royalty Review Panel's recommendations announced on September 18, 2007. Currently, 100% of the Company's production is in the province of Alberta. Although all details were not announced, the Company expects that the New Royalty Framework will increase the Company's corporate average royalty rate.



OPERATING EXPENSES

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Three Months Ended Nine Months Ended
September 30 September 30
2007 2006 2007 2006
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Operating expenses $507,640 $81,261 $1,266,732 $262,216
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Operating expenses per boe $ 18.98 $ 6.58 $ 15.33 $ 6.98
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Operating expenses for the three months ended September 30, 2007, increased to $18.98 per boe, an increase from $6.58 per boe in the third quarter of 2006. The increase in operating costs during the third quarter of 2007 is a result of prior period third party gathering and processing adjustments invoiced by the operator of the Company's Ante Creek property.

Operating expenses for the nine months ended September 30, 2007 were $15.33 per boe compared with $6.98 per boe in the nine months ended September 30, 2006. The increase in operating costs during the nine months ended September 30, 2007 is a result of prior period third party gathering and processing adjustments invoiced by the operator of the Company's Ante Creek property combined with the Company's Ante Creek property being shut in for a period of time during the second quarter of 2007 due to a third party compressor failure and scheduled plant maintenance.

TRANSPORTATION EXPENSES

Transportation expenses were $34,201 or $1.27 per boe for the quarter ended September 30, 2007 as compared with $10,338 or $0.84 per boe for the third quarter of 2006. Transportation expenses were $94,397 or $1.14 per boe for the nine months ended September 30, 2007 as compared to $26,722 or $0.71 per boe in the nine months ended September 30, 2006.



NETBACKS
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Three Months Ended Nine Months Ended
Barrels of oil September 30 September 30
eqivalent ($/BOE) 2007 2006 2007 2006
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Revenue $48.38 $48.19 $52.41 $51.29
Royalties ($8.79) ($7.83) ($9.57) ($8.62)
Operating expenses ($18.98) ($6.58) ($15.33) ($6.98)
Transportation expenses ($1.27) ($0.84) ($1.14) ($0.71)
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Field operating netback ($/BOE) $19.34 $32.94 $26.37 $34.98
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Field operating netbacks were $19.34 per boe for the quarter ended September 30, 2007 as compared with $32.94 per boe for the quarter ended September 30, 2006 and $26.37 per boe for the nine months ended September 30, 2007 as compared to $34.98 per boe for the nine months ended September 30, 2006. The lower netbacks for both the three and nine months ended September 30, 2007 reflects the higher operating costs incurred in the third quarter combined with the Company's Ante Creek property being shut in for a period of time during the second quarter of 2007, due to a third party compressor failure and scheduled plant maintenance.



GENERAL AND ADMINISTRATIVE EXPENSES

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Three Months Ended Nine Months Ended
September 30 September 30
2007 2006 2007 2006
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Gross general and administrative $681,157 $288,220 $1,574,116 $775,358
Overhead recoveries and
capitalized general and
administrative ($155,193)($142,041) ($432,547) ($349,880)
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Net general and administrative
expenses $525,964 $146,179 $1,141,569 $425,478
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During the third quarter 2007, general and administrative expenses ("G&A"), net of recoveries, were $525,964 as compared to $146,179 for the quarter ended September 30, 2006. G&A, net of recoveries, for the nine months ended September 30, 2007 was $1,141,569 compared to $425,478 for the nine months ended September 30, 2006. The increase in G&A for the third quarter and year to date relative to prior periods is due to severance costs, business development, legal, insurance, and other costs relating to regulatory manners and other management issues. During the quarter, the President and Chief Executive Officer as well as the Vice-President, Business Development ceased employment with the Company. The Company continues its search for a new President and Chief Executive Officer. The Company has undertaken a rigorous cost reduction program to lower overall G&A costs going forward.

STOCK-BASED COMPENSATION

Stock-based compensation expense is the amortization over the vesting period of the stock options granted to employees, directors, and key consultants of the Company. The fair value of the stock options granted is estimated at the grant date using the Black Scholes option pricing model. During the nine months ended September 30, 2007, the Company issued 982,500 stock options. No stock options were issued in the quarter ended September 30, 2007. Stock-based compensation for the quarter ended September 30, 2007 was $148,803 as compared with $67,525 for the quarter ended September 30, 2006. For the nine months ended September 30, 2007, stock-based compensation was $544,669 as compared to the $84,822 for the nine months ended September 30, 2006. The increase in stock-based compensation expense is a result of the increase in the numbers of options issued and the increased volatility of the Company's stock price in 2007 as compared to the same periods in 2006.

INTEREST EXPENSE

Bank debt interest expense for the quarter ended September 30, 2007 was $15,004 compared with $5,283 in the same quarter in 2006. The increase in bank debt interest expense for the quarter is due to the increased bank debt levels utilized during the quarter. Bank debt interest expense for the nine months ended September 30, 2007 was $47,294 as compared to $16,758 for the nine months ended September 30, 2006.

Interest and accretion expense relating to the $10 million, 9.5% convertible debenture for the quarter ended September 30, 2007 was $372,443 with no corresponding expense in the second quarter of 2006. Interest expense for the second quarter 2007 relating to the convertible debenture was made up of interest expense of $243,356, accretion of the convertible debenture of $119,497 and amortization of the debt portion of the convertible debenture issue costs of $9,590.

For the nine months ended September 30, 2007, interest and accretion on the convertible debenture was $874,410 with no corresponding expense for the nine months ended September 30, 2006. The interest and accretion expense is made up of interest expense of $576,507, accretion of the convertible debenture of $275,771 and amortization of the convertible debenture issue costs of $22,132.

The convertible debenture was issued on February 22, 2007. The accretion of the convertible debenture liability component and amortization of the debenture issue costs will be charged to interest expense using the effective interest rate method.



DEPLETION, DEPRECIATION AND ACCRETION

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Three Months Ended Nine Months Ended
September 30 September 30
2007 2006 2007 2006
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Depletion and depreciation
expense $ 1,967,525 $328,822 $ 3,689,820 $773,811
Accretion expense $ 7,458 $ 2,961 $ 22,374 $ 7,320
Impairment provision for
oil and gas properties $23,734,341 - $23,734,341 -
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Total $25,709,324 $331,783 $27,446,535 $781,131
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Depletion, depreciation and accretion for the quarter ended September 30, 2007 was $1,967,525 or $73.58 per boe as compared to $328,822 or $26.48 per boe for the quarter ended September 30, 2006. Depletion, depreciation and accretion for the nine months ended September 30, 2007 was $3,689,820 or $44.66 per boe as compared with $773,811 or $30.75 per boe for the nine months ended September 30, 2006. The increase in depletion on an absolute and boe basis is a result of increased production volumes, a higher depletable base and lower proved reserves at September 30, 2007, as compared to the same periods in 2006.

At September 30, 2007, the impairment recognition portion of the ceiling test indicated the estimated undiscounted future cash flows from proved reserves was less than the carrying amount of producing petroleum and natural gas properties. In the second stage of the AcG-16 impairment test, the discounted future cash flows from the proved plus probable reserves were compared to the carrying amount of the oil and gas properties to determine a ceiling test write-down. A write-down of $23,734,341 was included in DD&A for the three and nine months ended September 30, 2007.

The Company follows the full cost method of accounting for its operations as described in the CICA's accounting guideline 16, "Oil and Gas Accounting - Full Cost". Accordingly, the cost of all wells, both successful and unsuccessful, are added to the Company's capital base and are depleted on the unit of production method based on estimated gross proved reserves at forecast prices and costs as determined by independent engineers and the Company's internal estimates. Costs of unproven properties, seismic and undeveloped land, net of impairments, are excluded from the depletion calculation and future capital costs associated with proved undeveloped reserves are included in the depletion calculation.

In recognizing an asset retirement obligation "ARO" associated with the retirement of a tangible long-lived asset, the Company records a liability in the period in which it is incurred and becomes determinable, with an offsetting increase in the carrying amount of the associated asset. The cost of the tangible asset, including the initially recognized ARO is depleted such that the cost of the ARO is recognized over the useful life of the asset. The ARO is recorded at fair value and accretion expense is recognized over time as the discounted liability is accreted to its expected settlement value.

The provision for asset retirement obligations are determined by management in consultation with the Company's independent engineers and are based on prevailing regulations, costs, technology and industry standards. The Company estimates that the total future value of its asset retirement obligations at September 30, 2007 is $719,870. Current expenditures for actual abandonment and site restoration in the quarter ended September 30, 2007 were $nil.

TAXES

During the second quarter of 2007, the Company recorded a future income tax recovery of $4,440,785 compared to a future income tax recovery in the same quarter of 2006 of $14,036. For the nine months ended September 30, 2007, the Company recorded a future income tax recovery of $4,904,216 compared to a future income tax recovery of $499,536 for the nine months ended September 30, 2006. The future income tax recovery in the third quarter of 2007 is primarily a result of the ceiling test write-down incurred at September 30, 2007.

The Company paid no cash taxes during the three and nine month periods in 2007 and 2006.

As of September 30, 2007, the Company has approximately $25.5 million in tax pools available to offset future taxable income.



NET INCOME (LOSS) AND COMPREHENSIVE INCOME (LOSS)

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Three Months Ended Nine Months Ended
September 30 September 30
2007 2006 2007 2006
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Net income (loss) ($21,812,121) ($105,355) ($22,932,704) $562,641
Net income (loss)
- per basic share ($0.52) $0.00 ($0.57) $ 0.03
Net income (loss)
- per diluted share ($0.52) $0.00 ($0.57) $ 0.03
Weighted average shares
outstanding - basic (1) 41,676,950 26,107,270 40,509,594 21,152,077
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Weighted average shares
outstanding - diluted (1) 41,676,950 26,107,270 40,509,594 21,874,312
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(1) Assumes conversion of Class B shares as at September 30, 2007 at a
price of $1.00 per Class A share and as at September 30, 2006 at a price
of $1.28 per Class A share.


For the three and nine months ended September 30, 2007, all outstanding stock options, warrants and shares that would be issued upon the conversion of the convertible debenture are anti-dilutive and have been excluded in calculating the diluted weighted average shares outstanding.

At September 30, 2006, all outstanding stock options and warrants were in-the-money and have been included in the weighted average diluted shares outstanding.

FUNDS FLOW FROM OPERATIONS

It is management's view that funds flow from operations is a useful measure of performance and a good benchmark when comparing results from period to period. Funds flow from operations is a non-GAAP measure, reconciled with net loss in the table below:



----------------------------------------------------------------------------
----------------------------------------------------------------------------
Three Months Ended Nine Months Ended
September 30 September 30
2007 2006 2007 2006
----------------------------------------------------------------------------
Net (loss) income ($21,812,121) ($105,355) ($22,932,704) $562,641
Add back (subtract)
items not effecting cash:
Depletion, depreciation
and accretion $25,709,324 $331,783 $27,446,535 $781,131
Stock-based compensation $ 148,803 $ 67,525 $ 544,669 $ 84,822
Amortization of convertible
debenture issue costs $ 9,590 - $ 22,132 -
Accretion of convertible
debenture $ 119,497 - $ 275,771 -
Future income tax recovery ($4,440,785) ($14,036) ($4,904,216) ($499,536)
----------------------------------------------------------------------------
Funds flow from operations ($265,692) $279,917 $ 452,187 $929,058
Funds flow per share - basic ($0.01) $ 0.01 $ 0.01 $ 0.04
Funds flow per share - diluted ($0.01) $ 0.01 $ 0.01 $ 0.04
----------------------------------------------------------------------------
----------------------------------------------------------------------------


SHARE CAPITAL

----------------------------------------------------------------------------
----------------------------------------------------------------------------
Three Months Ended Nine Months Ended
September 30 September 30
2007 2006 2007 2006
----------------------------------------------------------------------------
Weighted Average Class A and B
shares outstanding
Basic - Class A 29,976,950 16,966,645 28,809,594 12,011,452
Basic - Class B(1) 11,700,000 9,140,625 11,700,000 9,140,625
----------------------------------------------------------------------------
Weighted average shares
outstanding - basic 41,676,950 26,107,270 40,509,594 21,152,077
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Weighted average shares
outstanding - diluted 41,676,950 26,107,270 40,509,594 21,874,312
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(1) Assumes conversion of Class B shares as at September 30, 2007 at a
price of $1.00 per Class A share and as at September 30, 2006 at a price
of $1.28 per Class A share.


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

Outstanding Securities Outstanding at
September 30
2007 2006
----------------------------------------------------------------------------
Class A shares 29,976,950 17,487,950
Class B shares 1,170,000 1,170,000
Stock options 2,590,500 1,390,000
Warrants 5,255,000 333,000
Convertible debenture 11,111,111 -
----------------------------------------------------------------------------
----------------------------------------------------------------------------


As of the date of this MD&A, there were 29,976,950 Class A and 1,170,000 Class B shares issued and outstanding.

For the three and nine months ended September 30, 2007, all outstanding stock options, warrants and convertible securities are anti-dilutive and have been excluded in calculating the diluted shares outstanding.

The Company's Class B shares are convertible, at the option of the Company, at any time after September 30, 2008 and before September 30, 2010, into Class A shares. The number of Class A shares obtained upon conversion of each Class B share will be equal to $10.00 divided by the greater of $1.00 and the then current market price of the Class A shares. If conversion has not occurred by the close of business September 30, 2010, then the Class B shares will be convertible, at the option of the shareholder, at any time after October 1, 2010 and before November 1, 2010 into Class A shares on the same basis. On November 1, 2010, all remaining Class B shares will be automatically converted to Class A shares on the same basis.



CAPITAL EXPENDITURES

----------------------------------------------------------------------------
----------------------------------------------------------------------------
Three Months Ended Nine Months Ended
September 30 September 30
2007 2006 2007 2006
----------------------------------------------------------------------------
Land and seismic $ 30,898 $ 147,618 $ 622,972 $ 659,145
Drilling and completions $246,001 $4,434,995 $3,137,066 $12,692,347
Equipment and facilities ($6,709) $1,804,318 $1,384,354 $ 3,323,917
Property acquisitions
(dispositions) ($92,500) - ($92,500)$ 2,086,456
Other(1) $148,738 $ 96,455 $ 356,148 $ 247,013
----------------------------------------------------------------------------
Total $326,428 $6,483,386 $5,408,040 $19,008,878
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(1) Includes capitalized general and administrative


DRILLING SUMMARY

----------------------------------------------------------------------------
----------------------------------------------------------------------------
Three Months Ended Nine Months Ended
September 30 September 30
2007 2006 2007 2006
----------------------------------------------------------------------------
Gross Net Gross Net Gross Net Gross Net
----------------------------------------------------------------------------
Oil - - 2.0 1.2 1.0 0.7 4.0 3.2
Natural gas - - 2.0 1.0 - - 5.0 2.8
Dry - - - - 1.0 0.2 3.0 1.9
----------------------------------------------------------------------------
Total - - 4.0 2.2 2.0 0.9 12.0 7.9
----------------------------------------------------------------------------
----------------------------------------------------------------------------


During the three months ended September 30, 2007, the Company did not participate in the drilling of any wells. During the nine months ended September 30, 2007, the Company participated in the drilling of 2 gross (0.9 net) well with a 50% success rate.

LIQUIDITY AND CAPITAL RESOURCES

At September 30, 2007, the Company had a $6,500,000 revolving bank credit facility. Subsequent to September 30, 2007, the bank credit facility was reduced to $4,000,000. The facility bears interest at prime plus 0.50% and is secured by a floating first charge over all of the Company's assets. While the credit facility is repayable on demand, the Company is not subject to scheduled repayments. As at September 30, 2007, the Company had a working capital deficit of $1,744,901. As of the date of the MD&A, approximately $1,264,000 was owed under the credit facility and the Company had an approximately $235,000 working capital deficit, excluding bank debt. At September 30, 2007, the Company was not in compliance with the net debt to trailing cash flow covenant under the credit facility.

Subsequent to September 30, 2007, the Company elected not to proceed with drilling the remaining wells required under its farm-in agreement in the Ante Creek area. As a result of the Company's decision, the farmor terminated the farm-in agreement in accordance with its terms, and the Company forfeited 32.5% working interest in 3.25 sections of land earned under the Ante Creek farm-in agreement. As a result of termination of the Ante Creek farm-in agreement, the Company eliminated approximately $6,868,000 in future capital commitments that would have been required to satisfy its obligations under the Ante Creek farm-in agreement.

As at September 30, 2007 and at the date hereof, the Company has a remaining obligation to spend approximately $1,400,000 on qualified Canadian Exploration Expenses before December 31, 2007. The Company has identified and entered into a farm-in agreement to drill a qualified Canadian Exploration Expense well which is expected to spud prior to December 1, 2007. The Company currently has enough unused credit facility with its bank to fund the approximately $1,450,000 to drill, case and complete the well.

The Company has the obligation to spend an additional $5,000,400 on qualified Canadian Exploration Expenses before December 31, 2008. The Company is currently evaluating its financing options for the 2008 expenditures.

The future operations of the Company is dependent on its ability to successfully explore, develop and produce economically viable reserves and market petroleum products from its properties and raise capital (through debt, equity or through the sale of certain of its assets) to support its activities and meet its obligations as outlined in note 10, and receiving the continued financial support from its lender and creditors.

The Company's cash flow and earnings are highly sensitive to changes in commodity prices, exchange rates and other factors that are beyond the control of the Company.

CRITICAL ACCOUNTING ESTIMATES

Oil and Gas Reserve Estimates

Estimates of economically recoverable oil and natural gas reserves (including natural gas liquids) and the future net cash flows therefrom are based upon a number of variable factors and assumptions, such as commodity prices, projected production from the properties, the assumed affects of regulation by government agencies and future operating costs. All of these estimates may vary from actual results. Estimates of the recoverable oil and natural gas reserves attributable to any particular group of properties, classifications of such reserves based on risk recovery and estimates of future net revenues expected therefrom, may vary. The Company's actual production, revenues, taxes, development and operating expenditures with respect to its reserves may vary from such estimates, and such variances could be material.

Ceiling Test

The ceiling test calculation is used to assess the valuation of the Company's petroleum and natural gas properties. The first part measures whether impairment has occurred based on undiscounted future cash flows using estimated future prices, costs and proved reserves. When the first part indicates impairment exists, the second part of the test measures the amount of impairment based on discounted estimated future cash flows from proved and probable reserves. The Company reviews the related estimates when it performs its ceiling test on a quarterly basis. The impact of changes in the estimates of future prices and costs applied and the quantity of proved and probable reserves on the financial statements could be material. The Company incurred a $23,734,341 ceiling test write-down at September 30, 2007.

Unproven Properties

Costs related to unproven properties are excluded from costs subject to depletion until proved reserves have been determined or their value is impaired. These properties are reviewed quarterly, based on management's estimates of future prospects and any impairment is transferred to the costs being depleted.

Stock-Based Compensation

The Company has a stock-based compensation plan which reserves shares of common stock for issuance to key employees, consultants and directors. The Company accounts for grants issued under this plan using the fair value recognition provisions whereby the cost of options granted to employees is charged to income with a corresponding increase in contributed surplus, based on an estimate of the fair value determined using the Black-Scholes option pricing model and amortized over the vesting period of the options issued.

Asset Retirement Obligations

The Company records the fair value of an asset retirement obligation as a liability in the period in which it incurs a legal obligation associated with the asset, normally when the asset is purchased or developed. The associated asset retirement costs are capitalized as part of the carrying amount of the long lived asset and depleted and depreciated using a unit-of-production method over the life of the estimated proved reserves. Subsequent to the initial measurement of the asset retirement obligations, the obligations are adjusted at the end of each period to reflect the passage of time and changes in the estimated future cash flows underlying the obligation.

Inherent in the fair value calculation of ARO are numerous assumptions and judgments including the ultimate settlement amounts, inflation factors, credit adjusted discount rates, timing of settlement, and changes in the legal, regulatory, environmental and political environments. To the extent future revisions to these assumptions impact the fair value of the existing ARO liability, a corresponding adjustment is made to the petroleum and natural gas properties balance.

BUSINESS RISKS

Exploration, development and production of petroleum and natural gas involves many risks that even the combination of experience and diligent evaluation may not be sufficient to overcome. Utilizing highly skilled professionals, focusing in areas where the Company has existing knowledge and expertise or access to such expertise, using the most up to date technology, and controlling costs to maximize margins, mitigate these risks. The Company maintains a comprehensive insurance program that insures liability and property consistent with good industry practices. The program is designed to mitigate risks and protect against significant loss. However, the Company is not fully insured against all these risks, nor are all such risks insurable.

The reserve and recovery information contained in the Company's independent reserve evaluation is only an estimate. The actual production and ultimate recovery of reserves from the properties may be greater or less than the estimates prepared by the independent reserve engineers. A significant portion of the Company's assets are located at the Ante Creek property whose relatively short production history may make estimates on this property more subject to revisions. The reserve report was prepared using forecasted commodity prices as determined by independent engineers. If lower prices for crude oil, natural gas liquids and natural gas are realized by the Company, the present value of the estimated future cash flows for the reserves would be reduced and such reductions could be significant.

Financial risks include exposure to fluctuation in commodity prices, currency exchange rates and interest rates. To mitigate the risks, the Company may enter into physical contracts for the sale of crude oil, natural gas liquids and natural gas at fixed prices. The Company may also institute financial hedging techniques for interest rates, currency exchange rates and commodity prices. If utilized, such transactions would be subject to certain limits on term and amount as established by the Board of Directors.

Oil and Gas Risk

Inherent in development of oil and gas reserves are risks, among others, of drilling dry holes, encountering production or drilling difficulties or experiencing high decline rates in producing wells. In addition, a major market risk exposure is in the pricing applicable to our oil and gas production. Realized pricing is primarily driven by the prevailing worldwide price for crude oil and spot prices applicable to our oil and natural gas production. Prices received for oil and gas production have been and remain volatile and unpredictable. If oil and gas prices decline significantly, even if only for a short period of time, it is possible that non-cash write-downs of our oil and gas properties could occur under the full-cost accounting method. Under these rules, we review the carrying value of our proved oil and gas properties each quarter to ensure that capitalized costs of proved oil and gas properties, net of accumulated depreciation, depletion and amortization do not exceed the "ceiling." This ceiling is the present value of estimated future net cash flows from proved oil and gas reserves, discounted at 10 percent, plus the lower of cost or fair value of unproved properties included in the costs being amortized, net of related tax effects. If capitalized costs exceed this limit, the excess is charged to additional depletion, depreciation and accretion expense. The calculation of estimated future net cash flows is based on forecasted prices for crude oil and natural gas except for volumes sold under long-term contracts. Write-downs required by these rules do not impact cash flow from operating activities; however, as discussed above, sustained low prices would have a material adverse effect on future cash flows.

Financial and Liquidity Risks

The Company anticipates that it will make capital expenditures for the acquisition, exploration, development and production of oil and natural gas in the future. On an ongoing basis, the Company will typically plan to utilize three sources of funding to finance its capital expenditure program; internally generated cash flow from operations, debt where deemed appropriate and new equity issues, if available at favourable terms. In addition, the Company may contemplate the sale of producing properties or the sale of other assets to fund its contractual obligations.

Funds flow is influenced by many factors, which the Company cannot control, such as commodity prices, the United States versus the Canadian exchange rate, interest rates and changes to existing government regulations and tax policies. Should circumstances affect cash flow in a detrimental way, the Company may have limited ability to expand the capital necessary to undertake or complete future drilling programs. In such circumstances, the Company would be required to either reduce the level of its capital expenditures or supplement its capital expenditure program with additional debt and/or equity financing. There can be no assurance that debt or equity financing will be available or sufficient to meet these requirements or, if debt or equity is available, that it will be on terms acceptable to the Company. Moreover, future activities may require the Company to alter its capitalization significantly. The inability of the Company to access sufficient capital for its operations could have a material adverse effect on the Company's financial condition, results of operations and prospects.

Issuance of Debt

From time to time, the Company may enter into transactions to acquire assets or the shares of other corporations. These transactions may be financed partially or wholly with debt, which may increase the Company's debt levels above industry standards. Neither the Company's articles nor its by-laws limit the amount of indebtedness that the Company may incur. The level of the Company's indebtedness from time to time could impair the Company's ability to obtain additional financing in the future on a timely basis to take advantage of business opportunities that my arise.

Supply of Service and Production Equipment

The supply of service and production equipment at competitive prices is critical to the ability to add reserves at a competitive cost and produce these reserves in an economic and timely fashion. In periods of increased activity, these supplies and services can be difficult to obtain. Demand for such limited equipment or access restrictions may affect the availability of such equipment to the Company and may delay exploration and development activities. The Company attempts to mitigate this risk by developing strong long-term relationships with suppliers and contractors. There can be no assurances that these relationships will increase the availability of the supplies and services.

Related Party Transactions

A director of the Company is also a partner in a law firm which is used extensively for legal work related to the Company's activities. Fees for the legal work are charged at the law firm's standard billing rates.

Contractual Obligations and Commitments

The Company has entered into a standard daywork contract with a drilling contractor to utilize a drilling rig for a period of three years. The terms of the contract call for a minimum requirement of 250 operating days per year for a total of 750 operating days over the three-year term of the contract. The contract expires in November 2009.

As a result of the Company issuing flow-through shares in 2006, the Company has committed to spend $5,000,000 before December 31, 2007, on qualified Canadian Exploration Expenses. The total estimated remaining obligation at September 30, 2007 under this commitment is approximately $1,400,000.

As a result of the Company issuing flow-through shares in February 2007, the Company has committed to spend $5,000,400 before December 31, 2008, on qualified Canadian Exploration Expenses.

The Company has entered into a farm-in agreement to drill an exploratory well on lands of an industry partner. The total capital commitment required under this agreement is approximately $1,450,000 with the expenditures qualifying for Canadian Exploration Expenses.

The Company has entered into a five year office lease agreement commencing on April 1, 2006. The following table outlines the Company's estimated remaining lease commitments over the life of the agreement:



----------------------------------------------------------------------------
----------------------------------------------------------------------------
2007 2008 2009 2010 2011 Total
----------------------------------------------------------------------------
Lease payments $42,609 $173,800 $174,921 $178,284 $44,851 $614,465
----------------------------------------------------------------------------
----------------------------------------------------------------------------


GUARANTEES AND OFF-BALANCE SHEET ARRANGEMENTS

The Company has not entered into any off-balance sheet arrangements or guarantees.

SUMMARY OF QUARTERLY RESULTS

The following table summarizes certain quarterly financial information relating to the Company.



----------------------------------------------------------------------------
----------------------------------------------------------------------------
2007 2006
----------------------------------------------------
Q3 Q2 Q1 Q4
----------------------------------------------------------------------------
Production revenue
before royalties $1,293,672 $1,295,008 $1,741,960 $1,082,723
Funds flow from
operations (1) ($265,692) $22,806 $695,073 $152,382
Funds flow per share
- basic (1) ($0.01) $0.00 $0.02 $0.01
Funds flow per share
- diluted (1) ($0.01) $0.00 $0.02 $0.01
Net loss ($21,812,121) ($780,683) ($339,900) ($793,791)
Net loss per share
- basic ($0.52) ($0.02) ($0.01) ($0.03)
Net loss per share
- diluted ($0.52) ($0.02) ($0.01) ($0.03)
Total assets $17,205,287 $42,605,686 $47,488,192 $40,518,063
Total bank debt $1,075,695 $683,561 - $626,310
----------------------------------------------------------------------------
----------------------------------------------------------------------------


----------------------------------------------------------------------------
----------------------------------------------------------------------------
2006 2005
----------------------------------------------------
Q3 Q2 Q1 Q4
----------------------------------------------------------------------------
Production revenue
before royalties $594,130 $655,831 $674,496 $331,611
Funds flow from
operations (1) $279,917 $294,709 $354,432 $179,576
Funds flow per share
- basic (1) $0.01 $0.02 $0.02 $0.01
Funds flow per share
- diluted (1) $0.01 $0.02 $0.02 $0.01
Net income (loss) ($105,355) $578,792 $89,204 ($158,933)
Net income (loss) per
share - basic $0.00 $0.03 $0.01 ($0.01)
Net income (loss) per
share - diluted $0.00 $0.03 $0.01 ($0.01)
Total assets $27,433,823 $21,865,189 $17,386,000 $14,171,866
Total bank debt $500,000 $2,506,446 - -
----------------------------------------------------------------------------
----------------------------------------------------------------------------

(1) Funds flow from operations and funds flow from operations per share are
non-GAAP measures. See "Funds Flow from Operations".


CHANGES IN ACCOUNTING POLICIES

Financial Instruments

On January 1, 2007, the Company adopted CICA Section 3855, Financial Instruments - Recognition and Measurement and Section 3861, Financial Instruments - Disclosure and Presentation. These standards establish the recognition and measurement criteria for financial assets, liabilities and derivatives. All financial instruments are required to be measured at fair value on initial recognition of the instrument, except for certain related party transactions. Measurement 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" as defined by this standard.

Accounts receivable are designated as "loans and receivables" and are carried at cost which approximates fair value. Accounts payable are designated as "other financial liabilities" and are carried at cost. Long-term debt is designated as "other financial liabilities" and carried at amortized cost using the effective interest rate method. The financing costs associated with the Company's $10 million private placement of unsecured convertible debentures on February 22, 2007 are included in the amortized cost of the debt. These costs are charged to interest expense using the effective interest rate method over the term of the debt, which matures on February 23, 2012.

Hedges

Effective January 1, 2007, the Company adopted the CICA Section 3865, "Hedges". The Company currently does not utilize hedges or other derivative financial instruments in its operations, and as a result, the adoption of Section 3865 has no impact on the financial statements of the Company.

The adoption of these new standards has no impact on the Company's deficit as at January 1, 2007.

DISCLOSURE CONTROLS AND PROCEDURES

Disclosure controls and procedures have been designed to ensure that information required to be disclosed by the Company is accumulated and communicated to the Company's management as appropriate to allow timely decisions regarding required disclosure. The Company's Chief Executive Officer and Chief Financial Officer have concluded, based on their evaluation, that the Company's disclosure controls and procedures, as defined in Multilateral Instrument 52-109 - Certification of Disclosure in Issuers' Annual and Interim Filings, are effective to provide reasonable assurance that material information related to the Company is made known to them, particularly during the interim period ended September 30, 2007, and was recorded, processed, summarized and reported within the time periods under applicable securities legislation.

INTERNAL CONTROLS OVER FINANCIAL REPORTING

There has been no changes in the Company's internal control over financial reporting that occurred during the most recent interim period ended September 30, 2007 that may have materially affected, or are reasonably likely to materially affect, the Company's internal control over financial reporting.

ADDITIONAL INFORMATION

Additional information relating to the Company is filed on the SEDAR website at www.sedar.com. Also, information can also be obtained by contacting the Company at Sierra Vista Energy Ltd., 850, 101 - 6th Avenue S.W., Calgary, Alberta, T2P 3P4 or by email at info@sierravista.ca. Information is also accessible on the Company's website at www.sierravista.ca.

CAUTIONARY STATEMENT REGARDING FORWARD LOOKING INFORMATION

Some of the statements contained herein including, without limitation, financial and business prospects, financial outlooks, and production forecasts may be forward-looking statements which reflect management's expectations regarding future plans and intentions, growth, results of operations, performance and business prospects and opportunities. In particular, this news release contains forward-looking statements pertaining to the quality of reserves, oil and natural gas production levels, capital expenditure programs, projections of market prices and costs, supply and demand for oil and natural gas; and expectations regarding the Company's ability to raise capital and to continually add to reserves through acquisitions and development.

The Company's actual results could differ materially from those anticipated in these forward-looking statements as a result of the risk factors set forth above and elsewhere in this news release including uncertainty of reserve estimates, volatility in market prices for oil and natural gas, liabilities and risks inherent in oil and natural gas operations, uncertainties associated with estimating reserves, competition for, among other things, capital, acquisitions or reserves, undeveloped lands and skilled personnel, geological, technical, drilling and processing problems.

Words such as "may", "will", "should", "could", "anticipate", "believe", "expect", "intend", "plan", "potential", continue" and similar expressions have been used to identify these forward-looking statements. These statements reflect management's current expectations and are based on uncertainties. Although the forward-looking statements contained within this news release are based upon what management believes to be reasonable assumptions, management cannot assure that actual results will be consistent with these forward-looking statements. Investors should not place undue reliance on forward-looking statements. These forward-looking statements are made as of the date hereof and we assume no obligation to update or revise them to reflect new events or circumstances unless required under applicable securities laws.

Where amounts are expressed on a barrel of oil equivalent ("BOE") basis, natural gas volumes have been converted to BOE using a ratio of 6,000 cubic feet of natural gas to one barrel of oil equivalent. This conversion ratio is based upon energy equivalent conversion method primarily applicable at the burner tip and does not represent value equivalence at the wellhead. BOE figures may be misleading, particularly if used in isolation.





Contact Information

  • Sierra Vista Energy Ltd.
    Mr. Morley W. Mychaluk
    Interim President & CEO
    (403) 265-9393 ext 202
    (403) 265-9224 (FAX)
    or
    Sierra Vista Energy Ltd.
    Mr. Bruce Stewart
    Chief Financial Officer
    (403) 265-9393 ext 205
    (403) 265-9224 (FAX)
    or
    Sierra Vista Energy Ltd.
    Suite 850, 101-6th Avenue SW
    Calgary, Alberta T2P 3P4