Sabretooth Energy Ltd.
TSX : SAB

Sabretooth Energy Ltd.

November 08, 2007 22:49 ET

Sabretooth Energy Announces Third Quarter 2007 Results

Successful Expansion and Drilling Completes Third Quarter

CALGARY, ALBERTA--(Marketwire - Nov. 8, 2007) - Sabretooth Energy Ltd. (TSX:SAB) ("Sabretooth" or "the company") is pleased to announce financial and operational highlights for the third quarter of 2007.

Third Quarter Highlights:

- First production from the 100% W.I. George 14-28-82-5W6 discovery well. The Lower Kiskatinaw zone in the well is currently choked back to 2 MMCF/d from 5 MMCF/d. The Basal Kiskatinaw zone, tested at 1 MMCF/d remains behind pipe at this time.

- Development wells were subsequently drilled at 3-33-82-5W6 and 102/14-28-82-5W6. Both wells were cased for multi-zone gas and 3-33 is on production at this time from the Basal Kiskatinaw zone at 1.2 MMCF/d. 102/14-28 is being tied in and will initially produce 1 MMCF/d from the Cretaceous. Gas has been tested in 3 other zones, Montney, Rock Creek and the Charlie Lake. Additional uphole completions will be pursued as existing production profiles are established.

- A fourth well at George is currently being drilled to exploit a fourth distinct Kiskatinaw reservoir.

- Drilled four (1.2 net) development wells at Gunnell in north east British Columbia. These wells are now tied in and began production in late August. The wells are expected to stabilize at a combined production rate of 400 boe/d net to the Company. Twelve additional horizontal development wells are planned in the area for 2007/2008.

- Drilled and cased 2 gross (0.73 net) wells at Eaglesham, Alberta resulting in 1 new pool Wabamun discovery to date.

- Received GEP from B.C. Oil and Gas Commission for allowing us to produce our oil discovery at Oak at 100 bbls/d.

- Production averaging 2,003 boe/d for the quarter, an increase of 21% over Q3, 2006.

- Funds flow of $3.9 million for the quarter, an increase of 21% over Q3, 2006.

Production is currently 3,600 boe/d and with 3 tie-ins and 5 wells (2 currently drilling) to be completed by year end we are well on track to exceed our 4,000 boe/d exit target. As well, we have choked back our prolific George Kiskatinaw discoveries to more prudently manage these reservoirs over the long term.

The merger of Sabretooth and Bear Ridge creates a reliable production base. With our significant landholdings on the Pease River Arch we have a quality suite of drillable prospects on both sides of the B.C. / Alberta border. Our committed and talented team looks forward to adding to our recent drill bit success in this target rich area.

Subsequent Event

Sabretooth Energy has assessed the impact of the oil and gas royalty changes announced by the Government of Alberta on October 25, 2007. The new royalties have no material adverse effect on the company's reserves at this time.

Based on the GLJ October 1, 2007 price forecast which forecasts 2009 AECO spot gas at $6.80/mmbtu, the Company's internal reserve estimates at Q3, 2007 have a net increase in PV(10) of less than 1% under the new royalties. The 2009 cash flow from the same report is negatively impacted by less than 2% on the Total Proved plus Probable case and is not impacted on the Total Proved case. Based on our evaluation we anticipate no negative impact to the Company's bank lines due to royalties at year end.

The new royalties have a negative impact of 7% on 2009 cash flow to the projects in the forecast 2008 capital spending. The 2008 proposed capital budget focuses initially on our Alberta Peace River Arch properties until the end of Q1 2008. Subsequently, the company will focus on it's portfolio of prospects in British Columbia.

The $60 MM proposed capital budget for 2008 will see spending in Alberta cut to 30% of the budget, with the balance to be deployed in British Columbia. Sabretooth is fortunate to have a portfolio which contains quality prospects in both Provinces; however, land purchases and future exploration are increasingly being focused in British Columbia.

Sabretooth's current production split is 68% in Alberta and 32% in British Columbia. With the successful completion of the 2008 proposed budget, we anticipate 52% of production will be in British Columbia.

Ultimately, the impact of the new royalties on cash flow will depend on actual commodity pricing in 2009, but Sabretooth is confident that the steps it is taking in 2008 will maximize shareholder return and mitigate the negative effects of the new Alberta royalties.

Subsequent to September 30, 2007 the Company issued 2,329,225 stock options with an exercise price of $2.09 to Directors, employees and consultants. The options are exercisable into common shares of the Company.

About Sabretooth Energy Ltd.

Sabretooth Energy Ltd. is a public oil and gas exploration and development company, located in Calgary, Alberta and carrying out operations in Western Canada. Sabertooth trades on the Toronto Stock Exchange (TSX) under the symbol "SAB".

Our mandate is to grow through a balanced approach of drill bit adds, accretive acquisitions, and aggressive exploitation of upside.



Q3 2007 Highlights

Three months ended Nine months ended
September 30, September 30,
2007 2006 2007 2006
----------------------------------------------------------------------------

Financial ($)

Production revenue $ 7,049,000 $ 5,661,000 $ 16,586,000 $ 21,792,000
Realized gain (loss) on
hedge $ 1,596,000 $ 337,000 $ 1,866,000 $ 254,000
Unrealized gain (loss)
on hedge $ (99,000) $ 1,484,000 $ (82,000)$ 1,484,000

Net income (loss) $ (497,000) $ 699,000 $ 3,558,000 $ 2,958,000
Funds flow from
operations $ 3,875,000 $ 3,192,000 $ 8,539,000 $ 12,827,000
----------------------------------------------------------------------------

Production volumes
Natural gas (mcf/d) 10,813 9,418 7,477 10,595
Crude oil (bbls/d) 165 10 127 5
Natural gas liquids
(bbls/d) 36 80 31 132
Total (boe/d) (6:1) 2,003 1,659 1,404 1,903

Sales prices
Natural gas ($/mcf) $ 7.12 $ 5.90 $ 7.51 $ 6.59
Natural gas, not
including hedges
($/mcf) $ 5.60 $ 6.29 $ 6.63 $ 6.68
Crude oil ($/bbl) $ 80.61 $ 69.71 $ 71.66 $ 67.35
Natural gas liquids
($/bbl) $ 75.89 $ 65.71 $ 67.16 $ 72.69
Total ($/boe) $ 46.91 $ 39.29 $ 48.12 $ 42.43
Netbacks, not including
unrealized hedges
($/boe)
Price $ 46.91 $ 39.29 $ 48.12 $ 42.43
Royalties, net of ARTC (7.89) (8.18) (7.89) (9.39)
Transportation (1.32) (1.46) (1.45) (0.94)
Operating costs (10.61) (6.32) (10.75) (4.78)
----------------------------------------------------------------------------
Total $ 27.09 $ 23.33 $ 28.03 $ 27.32
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Capital expenditures ($)
----------------------------------------------------------------------------

Total capital
expenditures $ 4,112,000 $ 8,663,000 $ 24,210,000 $ 23,452,000
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Land (net acres)

Developed 46,192 20,715 46,192 20,715

Undeveloped 132,997 31,166 132,997 31,166
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Total Land 179,189 51,881 179,189 51,881
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Management's Discussion and Analysis

For the nine months ended September 30, 2007

(Dated November 7, 2007)

Management's discussion and analysis of the financial and operating results for the Company should be read in conjunction with the Company's unaudited financial statements and related notes for the nine months ended September 2007 as well as with the audited financial statements for the year ended December 31, 2006.

Basis of Presentation

The financial data presented below has been prepared in accordance with Canadian Generally Accepted Accounting Principles ("GAAP"). The reporting and the measurement currency is the Canadian dollar. For the purpose of calculating unit costs, natural gas is converted to a barrel equivalent ("boe") using six thousand cubic feet of natural gas equal to one barrel of oil unless otherwise stated. The term barrels of oil equivalents (BOE) may be misleading, particularly if used in isolation. A BOE conversion ratio for gas of 6 mcf:1 boe is based on an energy equivalency conversion method primarily applicable at the burner tip and does not represent a value equivalency at the wellhead.

Non-GAAP Measurements

Within the Management Discussion and Analysis references are made to terms commonly used in the oil and gas industry. Netback is not defined by GAAP in Canada and is referred to as a non-GAAP measure. Netbacks equal total revenue less royalties, operating costs and transportation costs calculated on a boe basis. Management utilizes this measure to analyze operating performance. Total boes are calculated by multiplying the daily production by the number of days in the period.

Funds flow from operations is a non-GAAP term that represents net income (loss) adjusted for non-cash items including depletion, depreciation, accretion, future income taxes, stock-based compensation, unrealized hedge gains (losses), asset write-downs and gains (losses) on sale of assets and before adjustments for changes in working capital. The Company evaluates its performance based on earnings and funds flow from operations. The Company considers funds flow from operations a key measure as it demonstrates the Company's ability to generate the cash flow necessary to fund future growth through capital investment and to repay debt. The Company's calculation of funds flow from operations may not be comparable to that reported by other companies. Funds flow from operations per share is calculated using the same weighted average number of shares outstanding used in the calculation of income (loss) per share.

Forward Looking Statements

Certain statements contained within the Management's Discussion and Analysis, and in certain documents incorporated by reference into this document, constitute forward-looking statements. These statements related to future events or our future performance. All statements other than statements of historical fact may be forward-looking statements. Forward-looking statements are often, but not always, identified by the use of words such as "seek", "anticipate", "budget", "plan", "continue", "estimate", "expect", "forecast", "may", "will", "project", "predict", "potential", "targeting", "intend", "could", "might", "should", "believe", and similar expressions. These statements involve known and unknown risks, uncertainties and other factors that may cause actual results or events to differ materially from those anticipated in such forward-looking statements. We believe the expectations reflected in those forward-looking statements are reasonable but no assurance can be given that these expectations will prove to be correct and such forward-looking statements included in, or incorporated by reference into, the Management's Discussion and Analysis should not be unduly relied upon. These statements speak only as of the date of the Management's Discussion and Analysis or as of the date specified in the documents incorporated by reference into this Management's Discussion and Analysis, as the case may be.

In particular, this Management's Discussion and Analysis, and the documents incorporated by reference, contain forward-looking statements pertaining to the following:

- the performance characteristics of our oil and natural gas properties;

- oil and natural gas production levels;

- the size of the oil and natural gas reserves;

- projections of market prices and costs;

- supply and demand for oil and natural gas;

- expectations regarding the ability to raise capital and to continually add to reserves through acquisitions and development;

- treatment under governmental regulatory regimes and tax laws; and

- capital expenditures programs.

The actual results could differ materially from those anticipated in these forward-looking statements as a result of the risk factors set forth below and elsewhere in the Management's Discussion and Analysis:

- volatility in market prices for oil and natural gas;

- liabilities inherent in oil and natural gas operations;

- uncertainties associated with estimating oil and natural gas reserves;

- competition for, among other things, capital, acquisitions of reserves, undeveloped lands and skilled personnel;

- incorrect assessments of the value of acquisitions;

- geological, technical, drilling and processing problems;

- changes in income tax laws or changes in tax laws and incentive programs relating to the oil and gas industry and income trusts; and

- other factors as discussed under "Risks and Uncertainties".

Statements relating to "reserves" or "resources" are deemed to be forward-looking statements, as they involve the implied assessment, based on certain estimates and assumptions that the resources and reserves described can be profitably produced in the future. Readers are cautioned that the foregoing lists of factors are not exhaustive. The forward looking statements contained in this Management's Discussion and Analysis and the documents incorporated by reference herein are expressly qualified by this cautionary statement. We do not undertake any obligation to publicly update or revise any forward-looking statements.

Business Acquisition

On August 21, 2007 the Company acquired all of the issued and outstanding shares of Bear Ridge Resources Ltd. ("Bear Ridge"), an Alberta-based oil & gas company whose shares were listed on the TSX, for 18,477,506 common voting shares and 1,050,000 warrants and approximately $59,013,000 in cash including transaction costs. The transaction was accounted for using the purchase method whereby the assets acquired and liabilities assumed are recorded at their fair value. The accounts of the Company include the results of Bear Ridge effective August 21, 2007.



The purchase price equation is as follows:

$(000's)
----------------------------------------------------------------------------
Cost of Acquisition
----------------------------------------------------------------------------

Cash $56,813
Common shares (18,477,506 at $2.81 per share) 51,927
Warrants (1,050,000 at $0.57) 598
Transaction costs 2,200
----------------------------------------------------------------------------
Total $111,538
----------------------------------------------------------------------------


$(000's)
----------------------------------------------------------------------------
The Fair Value of the Assets and Liabilities Acquired Have
Been Allocated as Follows:
----------------------------------------------------------------------------

Cash and Cash Equivalents $34,261
Accounts Receivable 6,362
Deposits and prepaid expenses 94
Commodity contracts 1,456
Investment in commercial paper 21,760
Property and equipment 66,465
Future tax liability, net of previously unrecognized tax
assets of the Company (3,847)
Accounts payable and accrued liabilities (10,969)
Asset retirement obligations (4,044)
----------------------------------------------------------------------------
Total $111,538
----------------------------------------------------------------------------


The above amounts are estimates made by management based on currently available information. Amendments may be made to the purchase equation as the cost estimates and balances are finalized.

The attributed values of the common shares and warrants issued have been excluded from the consolidated statement of cash flows as non-cash transactions.

Each warrant entitles the holder to acquire one common share on a "flow-through" basis under the Income Tax Act (Canada) at a price of $3.81 per share. The warrants expire on March 31, 2009.

The Bear Ridge acquisition resulted in one dissenting shareholder. The shareholder holds 449,358 Bear Ridge shares and 389,435 Bear Ridge warrants with a strike price of $1.41. An accrual has been made for management's best estimate of the settlement which will be paid to this Bear Ridge shareholder. The dispute is currently with the courts. The Company does not expect any additional costs to be incurred on this matter other than the amount already accrued as part of the purchase price of Bear Ridge. The estimated settlement price is subject to measurement uncertainty and the effect of the changes to the estimate when resolved will be applied against the purchase price of Bear Ridge.

Bear Ridge Resources Inc. and its wholly owned subsidiary Bear Ridge Exploration Ltd. were amalgamated and have been renamed to Sabretooth Resources Ltd., a wholly owned subsidiary of Sabretooth Energy Ltd.

The acquisition of Bear Ridge created a natural gas leveraged company with high working interests and an extensive suite of drillable locations on a large prospective undeveloped land base. The combined entity has a strong presence in its core areas in the Peace River Arch and will provide significant economies of scale with its existing infrastructure and compatible land base. Upon acquisition date, the combined entities had:

- Approximately 7 million boe of Proven and Probable (company interest) reserves based on December 31, 2006 NI 51-101 compliant reserve reports;

- Current production of 3,600 boe/d comprised of 450 bbls/d of oil and natural gas liquids and 18.9 mmcf/d of natural gas (85% weighted to natural gas). At the time of acquisition production was 3,300 boe/d;

- A land base of approximately 133,000 net undeveloped acres; and

- Approximately 44.3 million shares outstanding on a fully diluted basis.



Financial Results and Highlights

Three months ended Nine months ended
September 30, September 30,
----------------------------------------
$('000s) 2007 2006 2007 2006
----------------------------------------------------------------------------
Revenue, net of
royalties $ 7,093 $ 6,236 $15,357 $18,808
Funds flow from
operations (1) $ 3,875 $ 3,192 $ 8,539 $12,827
Net income (loss) $ (497) $ 699 $(3,558) $ 2,958
----------------------------------------------------------------------------

(1) Funds flow from operations is a non-GAAP term that represents net
earnings adjusted for non-cash items Including depletion and
depreciation, accretion, future income taxes, stock-based compensation,
unrealized hedge gains (losses), asset write-downs and gains (losses) on
sale of assets. Funds flow per share is calculated by dividing funds
flow from operations as previously described by the weighted average
number of common shares outstanding during the year. The Company
evaluates its performance based on earnings and funds flow from
operations. The Company considers funds flow from operations a key
measure as it demonstrates the Company's ability to generate the cash
flow necessary to fund future growth through capital investment and to
repay debt.


Revenue

Production revenue was $16,586,000 for the nine months ended September 30, 2007, compared to $21,792,000 for the same time period in 2006. Production revenue was $7,049,000 for the three months ended September 30, 2007, compared with $5,661,000 for the three months ended September 30, 2006. The decrease of production revenue for the nine months ended September 30, 2007is due to the natural declines in the Fourth Creek Kiskatinaw formations. The increase in production revenues for the third quarter of 2007 compared to 2006 is due to the acquisition of Bear Ridge.

Total production revenue is comprised of natural gas, crude oil and natural gas liquids for the nine month and three months ended September 30, 2007 and 2006.

Pricing

Sabretooth's average natural gas price, not including realized gain on hedges, received during the third quarter of 2007 was $5.60 per mcf compared to the average AECO C posted price of $4.92 per mcf during the same period (2006 - $6.29 per mcf compared to the average AECO C posted price of $5.45 per mcf during the same period). The difference is due to the higher heat content the Company's gas contains. The Company received a third quarter average crude oil price of $80.61 per bbl as compared to the Edmonton Par price of $80.58 per bbl (2006 - $69.71 per bbl as compared to the Edmonton Par price of $79.79 per bbl during the same period). This variance is due to the quality differential of the oil produced versus Edmonton Par. NGL prices averaged $ 75.89 per bbl during the three month period as compared to the Edmonton pentane reference price of $ 79.20 per bbl (2006 - $65.71 per bbl as compared to the Edmonton pentane price of $79.79 per bbl during the same period).

Sabretooth's average natural gas price, not including realized gain on hedges, received during the first nine months of 2007 was $6.63 mcf compared to the average AECO C posted price of $ 6.36 per mcf during the same period (2006 - $ 6.68 per mcf compared to the average AECO C posted price of $6.12 per mcf during the same period). The difference is due to the higher heat content the Company's gas contains. The Company received an average crude oil price of $71.66 per bbl as compared to the Edmonton Par price of $73.67 per bbl for the first nine months of 2007 (2006 - $67.35 per bbl as compared to the Edmonton Par price of $76.08 per bbl during the same period). This variance is due to the quality differential of the oil produced versus Edmonton Par. NGL prices averaged $67.16 per bbl during the nine months ended September 30, 2007 as compared to the Edmonton pentane reference price of $73.72 per bbl (2006 - $72.69 per bbl as compared to the Edmonton pentane price of $ 77.45 per bbl during the same period).

During the three and nine months period ended September 30, 2007 realized a hedge gain of $1,596,000 and $1,866,000 respectively. During the three month period and the nine month period ended September 30, 2006, Sabretooth realized gains on hedges of $337,000 and $254,000 respectively.



Three months ended Nine months ended
September 30, September 30,
----------------------------------------

Average Selling Price 2007 2006 2007 2006
----------------------------------------------------------------------------
Natural gas (per Mcf) $ 7.12 $ 5.90 $ 7.51 $ 6.59
Crude Oil (per bbl) $ 80.61 $ 69.71 $ 71.66 $ 67.35
Natural gas liquids (per bbl) $ 75.89 $ 65.71 $ 67.16 $ 72.69
----------------------------------------------------------------------------
Per BOE $ 46.91 $ 39.29 $ 48.12 $ 42.43
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Production

Production for the third quarter of 2007 was 184,289 boe and averaged 2,003 boe/d. For the nine months ended September 30, 2007, production averaged 1,404 boe/d for a total of 383,428 boe. For the three and nine months ended September 30, 2006 production was 152,644 boe and averaged 1,659 boe/d and 519,599 boe and averaged 1,903 boe/d respectively.

The 344 boe/d increase in production for the third quarter of 2007 compared to 2006 is due to the acquisition of Bear Ridge. The decrease of 499 boe/d for the nine months ended September 30, 2007 is due to the natural declines in the Fourth Creek Kiskatinaw formations.



Three months ended September 30,
----------------------------------------------------------
2007 2006
----------------------------------------------------------
Total Per day Total Per day
----------------------------------------------------------------------------
Natural Gas 994,786 mcf 10,813 mcf/d 866,462 mcf 9,418 mcf/d
Crude Oil 15,138 bbls 165 bbls/d 918 bbls 10 bbld
NGLs 3,353 bbls 36 bbls/d 7,316 bbls 80 bbls/d
----------------------------------------------------------------------------
Total 184,289 boe 2,003 boe/d 152,644 boe 1,659 boe/d
----------------------------------------------------------------------------


Nine months ended September 30,
----------------------------------------------------------
2007 2006
----------------------------------------------------------
Total Per day Total Per day
----------------------------------------------------------------------------
Natural Gas 2,041,195 mcf 7,477 mcf/d 2,892,375 mcf 10,595 mcf/d
Crude Oil 34,750 bbls 127 bbls/d 1,452 bbls 5 bbls/d
NGLs 8,479 bbls 31 bbls/d 36,084 bbls 132 bbls/d
----------------------------------------------------------------------------
Total 383,428 boe 1,404 boe/d 519,599 boe 1,903 boe/d
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Royalty Expense

Royalties (net of ARTC for 2006) for the three and nine months ended September 30, 2007 were $1,454,000 and $3,026,000 respectively, both approximately 21% and 18% of revenues respectively. For the three and nine months ended September 30, 2006 royalties were $1,249,000 and $4,877,000 respectively both approximately 22% of revenues. The decrease in royalties during the three and nine months ended September 30, 2007 as compared to the same of periods in 2006 was due to the decrease in production revenue. As well, certain wells in British Columbia were eligible for royalty holidays during 2007. These factors more than offset the elimination of ARTC effective January 1, 2007.

Transportation

Transportation costs for the third quarter of 2007 were $244,000 or $1.32 per boe. For the nine months ended September 30, 2007 transportation costs were $557,000 or $1.45 per boe. Transportation costs for the third quarter of 2006 were $223,000 or $1.46 per boe. For the nine months ended September 30, 2006 transportation costs were $488,000 or $0.94 per boe. The increase in transportation costs in 2007 as compared to 2006 was mainly due to switching to a firm service contract from an interruptible service contract, which is more expensive but guarantees our natural gas transportation. The Company also began producing natural gas in British Columbia in the fourth quarter of 2006 which increased our transportation costs. In British Columbia, there is an infrastructure in place that enables natural gas producers to avoid facility construction in exchange for regulated gathering, processing and transmission fees. This all-in charge is included in transportation expense.

Operating Costs

Operating costs during the third quarter of 2007 were $1,955,000 or $10.61 per boe compared to $965,000 or $6.32 per boe for the same time period in 2006. For the nine months ended September 30, 2007 operating costs were $4,123,000 or $10.75 per boe compared to the nine months ended September 30, 2006 operating costs were $2,485,000 or $4.78 per boe. The increase in operating costs per boe during the three and nine months ended September 30, 2007 compared to the same periods in 2006 was due to the decrease in production volumes and certain operating expenses, such as compressors and an artificial lift being added, both of which are fixed costs. The acquisition of Bear Ridge during the third quarter added production volumes and the increase in operating cost per boe declined during the third quarter.



Three months ended Nine months ended
September 30, September 30,
----------------------------------------
$('000s) 2007 2006 2007 2006
----------------------------------------------------------------------------

Operating Costs ($) $1,955 $ 965 $4,123 $2,485
Per Unit of Production
($/boe @ 6:1) $10.61 $6.32 $10.75 $ 4.78
----------------------------------------------------------------------------


Operating Netbacks

Sabretooth's netback for the third quarter of 2007 was $27.09 compared to $23.33 for the third quarter of 2006. For the nine months ending September 30, 2007, the netback was $28.03 compared to $27.32 for the same period in 2006. These netbacks per boe are comprised of the following:



Three months ended Nine months ended
September 30, September 30,
----------------------------------------
2007 2006 2007 2006
----------------------------------------------------------------------------
Production revenue,
including realized hedge
gains (losses) $46.91 $39.29 $48.12 $42.43
Royalty expense, net of
ARTC (7.89) (8.18) (7.89) (9.39)
Transportation (1.32) (1.46) (1.45) (0.94)
Operating Costs (10.61) (6.32) (10.75) (4.78)
----------------------------------------------------------------------------

Netback, $/boe @ 6:1 $27.09 $23.33 $28.03 $27.32
----------------------------------------------------------------------------
----------------------------------------------------------------------------


General and Administrative Expenses

General and administrative ('G&A") expenses for the nine months ended September 30, 2007 were $1,973,000 or $5.15 per boe. For the third quarter of 2007, G&A expenses were $895,000 or $ 4.86 per boe. For the three and nine months ended September 30, 2007 Sabretooth capitalized approximately $293,000 and $686,000 of G&A expenses related to exploration and development respectively.

For the nine months ended September 30, 2006, G&A expenses were $1,137,000 or $2.19 per boe. For the third quarter of 2006, G&A expenses were $317,000 or $2.08 per boe. For the three and nine months ended September 30, 2006 Sabretooth capitalized approximately $96,000 and $379,000 of G&A expenses related to exploration and development respectively.

The increase in G&A expense on a per boe basis in 2007, as compared to the same periods in 2006, is due to the reduction in production volumes as a result of natural declines, however, the acquisition of Bear Ridge in the later part of the third quarter did increase production volumes and reduced the per boe G&A expense.



Three months ended Nine months ended
September 30, September 30,
----------------------------------------
$('000s) 2007 2006 2007 2006
----------------------------------------------------------------------------
G&A Expense ($) $ 895 $ 317 $1,973 $1,137
Per Unit of Production
($/boe @6:1) $4.86 $2.08 $ 5.15 $ 2.19
----------------------------------------------------------------------------


Interest Expense

Interest expense for the three months ended September 30, 2007 were $223,000 compared to $51,000 for the three months ended September 30, 2006. Interest expense for the nine months ended September 30, 2007 were $437,000 compared to $ 83,000 for the period in 2006. The increase in interest expense was a result of increased bank debt in 2007 as well as Part XII.6 tax the company incurs on unexpended flow-through share renouncement.



Three months ended Nine months ended
September 30, September 30,
$('000s) 2007 2006 2007 2006
----------------------------------------------------------------------------
Interest Expense ($) $ 223 $ 51 $ 437 $ 83
Per Unit of Production
($/boe @6:1) $1.21 $0.33 $1.14 $0.16
----------------------------------------------------------------------------


Depletion, Deprecation and Accretion ("DD&A")

DD&A expense for the three months ended September 30, 2007 was $4,333,000. DD&A expense for the nine months ended September 30, 2007 was $10,191,000. On a unit of production basis, depletion expense was $23.51 and $26.58 per boe for the three and nine months respectively.

DD&A expense for the three months ended September 30, 2006 was $3,407,000. DD&A expense for the nine months ended September 30, 2006 was $10,392,000. On a unit of production basis, depletion expense was $22.32 and $20.00 per boe for the three and nine months respectively.

The per boe increase in three and nine months ended 2007 compared to the same periods in 2006 is mainly due to significant investment in capital projects without a corresponding increase in proven reserves.

The depletion rate is impacted by the costs to acquire, explore and develop reserves of crude oil and natural gas, known as finding, development and acquisition costs. In the early stages of exploration, capital costs may be recognized before proven reserves are fully booked leading to higher initial depletion rates. In addition higher depletion rates also result as new production often receives lower reserves assignments under NI 51-101 due to the naturally unpredictable nature of newer production.

Asset Retirement Obligations

The Company acquired 289 new assets subject to retirement obligations during the nine months ended September 30, 2007. The Bear Ridge acquisition added 267 new assets to our base. $46,000 was recognized as an accretion expense for the third quarter of 2007 and $74,000 for the nine months ended September 30, 2007, along with an increase in asset retirement obligations of $4,416,000 for the nine month period.

The Company acquired eight new assets subject to retirement obligations during the nine months ended September 30, 2006. $8,000 was recognized as an accretion expense for the third quarter of 2006 and $24,000 for the nine months ended September 30, 2006.

Stock Based Compensation

The Company recognizes stock based compensation expense for all stock options granted. For the three and nine months ended September 30, 2007, Sabretooth recorded $77,000 and $222,000 respectively in stock based compensation expense, with a corresponding increase to contributed surplus, for stock options issued.

For the three and nine months ended September 30, 2006, Sabretooth recorded $99,000 and $239,000 respectively in stock based compensation expense, with a corresponding increase to contributed surplus, for stock and performance options issued.

Common Shares Outstanding

On November 9, 2006, the Company completed a private placement of 8,000,000 common voting shares at an issue price of $2.00 for gross proceeds of $16,000,000 on a flow-through basis. In accordance with the terms of the offering and pursuant to certain provisions of the Income Tax Act (Canada), the Company renounced, for income tax purposes, exploration expenditures of $16,000,000 to the holders of the flow-through common shares effective December 31, 2006. Future tax cost of approximately $5,000,000 associated with renouncing the expenditures was recorded on the date of renunciation in the first quarter of 2007. As at September 30, 2007, the Company has incurred the full $16,000,000 of qualifying expenditures. Transaction costs were $1,041,000 including fees paid to underwriters.

On March 9, 2007, the shareholders approved the exchange of Common non-voting shares for Common voting shares on a 1- for -1 basis and then to consolidate the Common voting shares on a 4-for-1 basis.

On August 21, 2007 the company issued 18,477,506 common shares at a deemed value of $2.81 per share for total deemed proceeds of approximately $51,927,000 as part of the acquisition of Bear Ridge.

On August 21, 2007 the company issued 1,050,000 warrants at a deemed value of $0.57 per warrant for total deemed proceeds of approximately $598,000 as part of the acquisition of Bear Ridge. Each warrant entitles the holder to acquire one common share on a "flow-through" CDE basis under the Income Tax Act (Canada) at a price of $3.81 pre share. The warrants expire on March 31, 2009.

Income Taxes

The Company has non-capital loss carry-forwards, investment tax credit carry-forwards and Scientific and Experimental Development expenses available to reduce future years' income for tax purposes. The Scientific Research and Development expenses of approximately $22,704,000 available for carry-forward do not expire. The non-capital loss and investment tax credit carry-forwards expire as follows:



Non-capital losses Investment tax credits
Year of expiry $('000s) $('000s)
----------------------------------------------------------------------------
2007 $ - $ -
2008 - -
2009 4,498 -
2010 - 930
2011 - 1,280
2012 - 672
2013 6,812 761
2014 3,293 338
2025 9,668 -
---------------------------------------------------
$ 24,271 $ 3,981

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


In addition, the Company has UCC pools of approximately $33,000,000, COGPE pools of approximately $15,000,000, CEE pools of approximately $21,000,000, CDE pools of approximately $20,000,000, and share issuance costs of approximately $4,000,000 which can be used to reduce taxable income in the future.

As at September 30, 2007, $2,663,000 has been recognized as a future income tax asset.



Capital Expenditures

Three months ended Nine months ended
September 30, September 30,
----------------------------------------
$('000s) 2007 2006 2007 2006
----------------------------------------------------------------------------
Land acquisition costs $ (469) $169 $1,868 $4,586
Geological & geophysical $ 190 $9 $1,746 $1,763
Drilling, completions & workovers $2,645 $4,050 $14,537 $8,647
Tangible equipment $1,306 $4,309 $5,227 $8,030
Capitalized overhead $ 293 $96 $686 $379
Office furniture & equipment $ 147 - $146 $47
----------------------------------------------------------------------------

Total capital expenditures $4,112 $8,633 $24,210 $23,452
----------------------------------------------------------------------------
----------------------------------------------------------------------------


Liquidity and Capital Resources

The Company has established two credit facilities with a Canadian chartered bank. Credit facility A is a $50,000,000 revolving operating demand loan which bears interest at the bank prime rate plus 0% to 1.5%, depending on the Company's debt to cash flow ratio. Credit facility B is a $5,000,000 non-revolving acquisition/development demand loan, which bears interest at the bank prime rate plus 0.50%. Both Credit Facilities A and B are subject to periodic review by the bank and are secured by a general assignment of book debts and a $100,000,000 demand debenture with a first floating charge over all assets of the Company. The Company is authorized to access the credit facilities with prior approval of the Board. The Company is required to meet certain financial based covenants under the terms of this facility. As at September 30, 2007, the Company has drawn $38,588,000 on Facility A and $Nil on Facility B.

The Company holds Asset Backed Commercial Paper which it acquired as part of the Bear Ridge transaction that it has valued at $21,760,000. As at September 30, 2007, the Company held Canadian third party asset-backed commercial paper ("ABCP") with an original cost of $24,147,000. At the dates the Company acquired these investments they were rated R1 (High) and backed by R1 (High) AAA rated assets, and liquidity agreements. These investments matured during the third quarter of 2007 but, as a result of the liquidity issues in the ABCP market, did not settle on maturity. As a result the Company has classified it's ABCP as long-term investments.

On August 16, 2007 an announcement was made by a group representing banks, asset providers and major investors that they had agreed in principle to a long-term proposal and interim agreement to convert the ABCP's into long-term floating rate notes maturing no earlier than the scheduled maturity of the underlying assets. On September 6, 2007, a pan-Canadian restructuring committee consisting of major investors was formed. The committee was created to propose a solution to the liquidity problem affecting the ABCP and has retained legal and financial advisors to oversee the proposed restructuring process. On October 16, 2007, it was announced that the committee expected that the restructuring would be completed on or before December 14, 2007. Through to December 14, 2007, by means of Extraordinary Resolutions of the various trusts that had issued ABCP, trading of the ABCP has ceased and investors have committed not to take any action that would precipitate an event of default.

The ABCP in which the Company has invested has not traded in an active market since mid-August 2007 and there are currently no market quotations available. The ABCP in which the Company has invested continues to be rated R1 High (Under Review with Developing implications) by DBRS.

The valuation technique used by the Company to estimate the fair value of its investments in ABCP incorporates probability-weighted discounted cash flows considering the best available public information regarding market conditions and other factors that a market participant would consider for such investments. This evaluation resulted in a reduction of $2,387,000 to the estimated fair value of the ABCP upon the Company's acquisition of BER. The assumptions used in determining the estimated fair value reflect the public statements made by the pan-Canadian restructuring committee that it expects the ABCP will be converted into long-term floating rate notes with maturities matching the maturities of the underlying assets and bearing market interest rates commensurate with the nature of the underlying assets and their associated cash flows and the credit rating and risk associated with the long-term floating rate notes. Assumptions have been made as to the long-term interest rates to be received from the long-term floating rate notes.

The Company believes the fair value assigned to the ABCP upon the acquisition of BER on August 21, 2007 remains appropriate at September 30, 2007 and no further adjustments are required.

Continuing uncertainties regarding the value of the assets which underlie the ABCP, the amount and timing of cash flows and the outcome of the restructuring process could give rise to a further change in the value of the Company's investment in ABCP which would impact the Company's earnings.

As at September 30, 2007, the Company's working capital deficit was approximately $43,475,000, (December 31, 2006 working capital $87,000) reflecting the first nine months activity level of the Company including the acquisition of Bear Ridge. The working capital deficit excludes the entire Asset Backed Commercial Paper investment which is not classified as a current asset. Including the investment (prior to the allowance) the Company's working capital deficit is $19,328,000.

Contractual Obligations

Sabretooth is committed to various contractual obligations and commitments in the normal course of operations and financing activities. These are outlined as follows:



1) Office Leases - The minimum annual net lease payments, exclusive of
operating costs are as follows:

2007 $ 35,000
2008 139,000
2009 139,000
2010 139,000
2011 143,000
Thereafter 107,000
--------------
$ 702,000
--------------


2) Asset Retirement Obligations - Sabretooth is the owner of oil and natural gas wells and related surface equipment and facilities. These assets will have to be abandoned and the surface returned to its natural state. As at September 30, 2007, total estimated undiscounted future cash flows required to settle these obligations is approximately $14,009,000 which is exclusive of salvage values and adjusted for expected inflation. This estimate is subject to change based on amendments to environmental laws and as new information with respect to the Company's operations become available. Sabretooth estimates that the salvage value of its field equipment would offset a portion of its estimated future asset retirement obligation. Sabretooth does not expect to incur significant asset retirement cost obligations within the next five years.

3) Flow-through Qualifying Expenditures - At December 31, 2006, Sabretooth had an obligation related to the issuance of flow-through common shares to incur approximately $16,000,000 of qualifying expenditures before December 31, 2007. This amount has been fully expended as at September 30, 2007.

4) Flow-through Qualifying Expenditures - Sabretooth assumed obligations related to the Bear Ridge acquisition from issuance of flow-through common shares to incur approximately $24,000,000 of qualifying expenditures before December 31, 2008 and $11,295,000 before March 31, 2009. Approximately $17,754,000 of qualifying expenditures has been incurred to September 30, 2007. The Company also has 1,050,000 CDE warrants which are exercisable at a price of $3.81 and expire March 31, 2009. If they are exercised the Company would have an obligation to spend $4,000,000 of CDE expenditures.

5) The Company, as a result of the acquisition of Bear Ridge, has a contract for gathering and processing fees, on a fiscal year basis, as follows:




----------------------------------------------------------------------------
2007 2008
$284,000 $374,000
----------------------------------------------------------------------------


Outstanding Share Data

As of the date of this MD&A, Sabretooth had the following securities outstanding:

1) 39,065,356 common voting shares;

2) 4,214,476 stock options.; and

3) 1,050,000 warrants.

On March 9, 2007, the shareholders approved the exchange of Common non-voting shares for Common voting shares on a 1- for -1 basis and then to consolidate the Common voting shares on a 4-for-1 basis. During the nine months ended September 30, 2007, the Company granted 182,500 options (post share consolidation) with an exercise price of $6.40 exercisable into common voting shares and cancelled 43,000 options (post consolidation) with an weighted average exercise price of $5.55.

On August 21, 2007, the Company completed the acquisition of Bear Ridge Resources and issued 18,477,506 common voting shares with a deemed value of $2.81 per share for total of $51,927,000.

On August 21, 2007, the Company completed the acquisition of Bear Ridge Resources and issued 1,050,000 warrants with a deemed value of $0.57 per warrant. Each warrant entitles the holder to acquire one common share on a "flow-through" basis under the Income Tax Act (Canada) at a price of $3.81 pre share. The warrants expire on March 31, 2009.



Quarterly Information

Financial 2007 2006 2005
----------------------------------------------------------------------------

($ thousands
except
per share data) Q3 Q2 Q1 Q4 Q3 Q2 Q1 Q4
----------------------------------------------------------------------------
Revenues
(including
gains
(losses)
on financial
commodity
contract) $8,547 $5,150 $4,686 $5,369 $7,485 $6,928 $9,272 $7,596
Royalties, net
of ARTC 1,454 578 994 1,290 1,249 983 2,645 1,756
Operating
expenses 1,955 1,186 982 945 965 783 736 572
Transportation
expenses 244 140 173 198 223 130 135 39
Net income
(loss) (497) 141 3,914 (646) 699 115 2,144 860
Per Share -
basic (0.02) 0.01 0.19 (0.03) 0.04 0.01 0.12 0.06
Per share -
diluted (0.02) 0.01 0.18 (0.03) 0.04 0.01 0.11 0.06
Funds flow 3,875 2,177 2,487 3,094 3,192 4,248 5,388 4,732
Per Share -
basic 0.14 0.11 0.12 0.16 0.17 0.23 0.29 0.34
Per share -
diluted 0.13 0.10 0.12 0.15 0.17 0.21 0.27 0.31
Capital
expenditures,
net 4,112 6,142 13,956 12,281 8,633 6,066 8,753 2,193
Acquisition
expenditures,
net 24,752 - - - - - - 1,435
----------------------------------------------------------------------------
Total
expenditures $28,864 $6,142 $13,956 $12,281 $8,633 $ 6,066 $8,753 $3,628
----------------------------------------------------------------------------


2007 2006 2005
----------------------------------------------------------------------------
Operations Q3 Q2 Q1 Q4 Q3 Q2 Q1 Q4
----------------------------------------------------------------------------
Production
Volumes
Natural gas
(mcf/day) 10,813 5,140 6,429 8,308 9,418 10,602 11,776 10,782
Oil (bbl/day) 165 114 103 49 10 3 3 3
NGLs (bbl/day) 36 24 32 21 80 148 178 33
Total boe/day 2,003 995 1,206 1,454 1,659 1,918 2,144 1,833
----------------------------------------------------------------------------
Average
selling
price
Natural gas
($per mcf) 7.12 7.47 7.71 7.09 5.90 6.13 7.58 11.32
Oil ($per bbl) 80.61 63.55 66.14 60.42 69.71 66.21 60.83 58.64
NGLs ($per bbl) 75.89 65.86 57.93 67.11 65.71 70.94 74.25 68.75
----------------------------------------------------------------------------
Combined ($per
boe) 46.91 49.84 43.07 43.96 39.29 39.00 47.91 67.94
Royalties
($per boe) 7.89 6.38 9.16 9.64 8.18 5.64 13.71 15.71
Operation
expense
($per boe) 10.61 13.09 9.05 7.07 6.32 4.49 3.83 5.11
Transportation
($per boe) 1.32 1.54 1.60 1.48 1.46 0.74 0.7 0.35
----------------------------------------------------------------------------

Netback ($per
boe) 27.09 28.83 23.26 25.77 23.33 28.13 29.67 46.77
----------------------------------------------------------------------------
----------------------------------------------------------------------------


Financial Instruments

The nature of Sabretooth's operations results in exposure to fluctuations in commodity prices. Management continuously monitors commodity prices and initiates instruments to manage exposure to these risks when it deems appropriate. As a means of managing commodity price volatility, the Company enters into various derivative financial instrument agreements and physical contracts. Collars ensure that the commodity prices realized will fall into a contracted range for a contracted sale volume based on the monthly index price. Monthly gains and losses are determined based on the differential between the AECO daily index and the AECO monthly index when the monthly index price falls in between the floor and the ceiling. The following information presents all positions for the derivative financial instruments outstanding as at September 30, 2007.



----------------------------------------------------------------------------
Start Date Term Volume Price Basis
----------------------------------------------------------------------------
April 1, 2007 April 1, 2007 to 3,000 $5.50 floor AECO
October 31, 2007 GJ/day $8.05 ceiling

----------------------------------------------------------------------------
April 1, 2007 April 1, 2007 to 3,000 $6.24 floor AECO
October 31, 2007 GJ/day $8.00 ceiling

----------------------------------------------------------------------------
April 1, 2007 April 1, 2007 to 2,000 $7.26 fixed AECO
October 31, 2007 GJ/day

----------------------------------------------------------------------------
August 1, August 1, 2007 to 9,000 $6.50 floor AECO
2007 December 31, GJ/day
2007 $9.60 ceiling

----------------------------------------------------------------------------
November 1, November 1, 3,000 $7.75 floor AECO
2007 2007 to March 31, GJ/day
2008 $10.00 ceiling

----------------------------------------------------------------------------
January 1, January 1, 2008 to 3,150 $6.50 floor AECO
2008 December 31, GJ/day
2008 $10.00 ceiling

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


Realized gains totalling $1,596,000 for the three months ending and $1,866,000 for the nine months ended September 30, 2007 (September 30, 2006 - $254,000) respectively, from the derivatives was recognized in income and the fair value of the swap plus costless collars outstanding at September 30, 2007 was approximately $2,324,000.

Off Balance Sheet Arrangements

The Company does not presently utilize any off-balance sheet arrangements to enhance its liquidity and capital resource positions, or for any other purpose. During the period ended September 30, 2007, Sabretooth Energy Ltd. did not enter into any off-balance sheet transactions.

Related Party Transactions

During 2007, Sabretooth entered into commercial business transactions with the following related parties:

a) A director of the Company is a partner of a law firm that provides legal services to the Company. During the nine months ended September 30, 2007, the Company paid approximately $44,000 (September 30, 2006 - $11,000) to this firm for legal fees and disbursements. Additionally, $Nil is included in accounts payable and accrued liabilities at September 30, 2007 (December 31, 2006 - $2,000) for this firm. Approximately $29,000 has been capitalized as part of the acquisition cost of Bear Ridge and included in property and equipment. $15,000 has been included as general and administrative expense.

b) A director of the Company is the Chairman of a corporation that provided drilling services to the Company. During the nine months ended September 30, 2007, the Company paid approximately $2,281,000 (December 31, 2006 - $1,682,000 September 30, 2006 - $773,000) for drilling and services, which has been included in property and equipment. Additionally, $Nil is included in accounts payable and accrued liabilities at September 30, 2007 (December 31, 2006 - $250,000) for this corporation.

c) A director of the Company is the owner of a corporation that provides drilling services to the Company. During the nine months ended September 30, 2007, the Company paid approximately $688,000 (year ended December 31, 2006 - $Nil; nine months ended September 30, 2006 - $17,000) for drilling and services, which has been included in property and equipment.

These transactions have been recorded at the exchange amount, which is the amount of consideration established and agreed to by the related parties.

Disclosure Controls and Procedures

The Corporation's Chief Executive Officer and Chief Financial Officer are responsible for establishing and maintaining the Corporation's disclosure controls and procedures, including adherence to the Disclosure Policy adopted by the Corporation. The Disclosure Policy requires all staff to keep the Corporation's Chief Executive Officer and Chief Financial Officer fully apprised of all material information affecting the Corporation so that they may evaluate and discuss this information and determine the appropriateness and timing for public release. Access to such material information by the Chief Executive Officer and Chief Financial Officer is facilitated by the fact that there are so few members of the Corporation's senior management and there is frequent and regular communication among all of them.

The Chief Executive Officer and Chief Financial Officer, after evaluating the effectiveness of the Corporation's disclosure controls and procedures as of September 30, 2007, have concluded that the Corporations disclosure controls and procedures were adequate and effective to ensure that material information relating to the Corporation would have been known to them. It should be noted that while the Corporation's disclosure controls and procedures provide a reasonable level of assurance that they are effective, they do not expect that the disclosure controls and procedures or internal control over financial reporting will prevent all errors or fraud. A control system, no matter how well conceived or operated, can provide only reasonable, not absolute, assurance that the objectives of the control system are met.

Internal Controls over Financial Reporting

The Chief Executive Officer and Chief Financial Officer are also responsible for designing internal controls over financial reporting or causing them to be designed under their supervision in order to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with Canadian GAAP.

Management has designed internal controls over financial reporting as of September 30, 2007. The relatively small size of the Corporation makes the identification and authorization process relatively efficient; however, during the review of the design of internal controls over financial reporting it was noted that, due to the limited number of staff at Sabretooth, it is not feasible to achieve complete segregation of incompatible duties nor does the Corporation have a sufficient number of finance personnel with all the technical accounting knowledge to address all complex and non-routine accounting transactions that may arise, which may lead to the possibility of inaccuracies in financial reporting. The Corporation has acquired knowledgeable and competent accounting staff to ensure that high-quality financial reporting and other internal controls over financial reporting have been designed which provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements. Management and the Board of Directors work to mitigate the risk of a material misstatement in financial reporting; however, a control system, no matter how well conceived or operated, can provide only reasonable, not absolute, assurance that the objectives of the control system are met.

Changes in Accounting Policies

Financial Instruments

Effective January 1, 2007, the Company adopted a series of new standards released by the Canadian Institute of Chartered Accountants, which establish guidance for the recognition and measurement of financial instruments. Section 1530 "Comprehensive Income", Section 3855 "Financial Instruments - Recognition and Measurement", Section 3861 "Financial Instruments - Disclosure and Presentation" and Section 3865 "Hedges" were released in April 2005 and are effective for interim and annual financial statement years beginning on or after October 1, 2006. To accommodate these new sections, there have been a number of amendments to other existing accounting standards. These policies provide comprehensive requirements for the recognition and measurement of financial instruments, introduce a new component of equity referred to as accumulated other comprehensive income ("AOCI"), and a Statement of Comprehensive Income. In accordance with the transitional provision of these policies, comparative interim financial statements are not to be restated.

Under these new standards, all financial instruments, including derivatives, are to be recognized on the balance sheet. Derivatives are to be measured at fair value and unrealized gains and losses reported in the statement of operations unless the "normal sale and purchase" exemption is utilized or the derivatives are designated as cash flow or net investment hedges. All changes in fair value are included in earnings unless cash flow hedge or net investment accounting is used, in which case, changes in fair value are recorded in other comprehensive income to the extent the hedge is effective, and in earnings to the extent it is ineffective. The Company has not identified any material embedded derivatives in any of its financial instruments. The Company has elected to account for its commodity sales contracts and other non-financial contracts, held for the purpose of receipt or delivery of non-financial items in accordance with its expected purchase, sale or usage requirements on an accrual basis. The Company's other financial instruments (accounts receivable and accounts payable) are measured at amortized cost using the effective interest rate method. Transaction costs are added to the amount of the associated financial instrument and amortized accordingly.

Section 3865 established standards for when and how hedge accounting may be applied. Hedge accounting continues to be optional and the Company does not currently apply hedge accounting.

There has been no impact on the financial statements by adopting the new requirements.

Accounting Changes

Effective January 1, 2007 the Company adopted the revised recommendations of the CICA Handbook Section 1506, Accounting Changes. Under the revised standards, voluntary changes in accounting policies are permitted only if they result in financial statements which provide more reliable and relevant information. Accounting policy changes are applied retrospectively unless it is impractical to determine the period or cumulative impact of the change. Corrections of prior period errors are applied retrospectively and changes in accounting estimates are applied prospectively by including these changes in earnings. These standards are effective for all changes in accounting policies, changes in accounting estimates and corrections of prior period errors initiated in periods beginning on or after January 1, 2007.

In addition, the Company has assessed new and revised accounting pronouncements that have been issued that are not yet effective and determined that the following may have a significant impact on the Company:

a) Financial Instruments - Disclosures and Presentation

As of January 1, 2008, the Company will be required to adopt two new CICA standards. Handbook Section 3862, Financial Instruments - Disclosures and Handbook Section 3863, Financial Instruments - Presentation. These Handbook Sections will replace existing Handbook Section 3861, Financial Instruments - Presentation and Disclosure. The new disclosure standard increases the emphasis on the risks associated with both recognized and unrecognized financial instruments and how those risks are managed. The new presentation standard carries forward the former presentation requirements.

b) Capital Disclosures

Also as of January 1, 2008, the Company will be required to adopt Handbook Section 1535, Capital Disclosures which will require companies to disclose their objectives, policies and processes for managing capital. In addition, disclosures are to include whether companies have complied with externally imposed capital requirements.

Both new standards were issued in December 2006, and the Company is assessing the impact on its financial statements.

Convergence of Canadian GAAP with International Financial Reporting Standards

In 2006, Canada's Accounting Standards Board (AcSB) issued a strategic plan that will result in Canadian GAAP, as it applies to publicly accountable entities, being converged with International Financial Reporting Standards over a transitional period. The AcSB is expected to develop and release a detailed implementation plan with a transition period initially indicated to be five years. The Corporation will consider the effect that this implementation plan might have on the financial statements during the transition period.

Application of Critical Accounting

The significant accounting policies used by Sabretooth are disclosed in note 2 to the Unaudited Interim Consolidated Financial Statements for the period ended September 30, 2007 and note 3 to the Audited Consolidated Financial Statements for the year ended December 31, 2006. Certain accounting policies require that management make appropriate decisions with respect to the formulation of estimates and assumptions that affect the reported amounts of assets, liabilities, revenues and expenses. Management reviews its estimates on a regular basis. The emergence of new information and changed circumstance may result in actual results or changes to estimate amounts that differ materially from current estimates. The following discussion identifies the critical accounting policies and practices of the Company and helps assess the likelihood of materially different results being reported.

Application of Critical Accounting Estimates

Reserves

Under the National Instrument 51-101 (NI 51-101) "Proved" reserves are defined as those reserves that can be estimated with a high degree of certainty to be recoverable. The level of certainty should result in at least a 90% probability that the quantities actually recovered will equal or exceed the estimated Proved reserves. It does not mean that there is a 90% probability that the Proved reserves will be recovered; it means that there must be at least a 90% probability that the given amount or more will be recovered. "Proved plus Probable" reserves are the most likely case and are based on a 50% certainty that they will equal or exceed the reserves estimated.

These oil and gas reserve estimates are made using all available geological and reservoir data, as well as historical production data. All of the Company's reserves were evaluated and reported on by an independent qualified reserves evaluator. However, revisions can occur as a result of various factors including: actual reservoir performance, change in price and cost forecasts or a change in the Company's plans. Reserve changes will impact the financial results as reserves are used in the calculation of depletion and are used to assess whether asset impairment occurs. Reserve changes also affect other Non-GAAP measurements such as finding and development costs; recycle ratios and net asset value calculations.

Depletion

The Company follows the full cost method of accounting for oil and natural gas properties. Under this method, all costs related to the acquisition of, exploration for and development of oil and natural gas reserves are capitalized whether successful or not. Depletion of the capitalized oil and natural gas properties and depreciation of production equipment which includes estimated future development costs less estimated salvage values are calculated using the unit-of-production method, based on production volumes in relation to estimated proven reserves.

An increase in estimated proved reserves would result in reduction in depletion expense. A decrease in estimated future development costs would also result in a reduction in depletion expense.

Unproved Properties

The cost of acquisition and evaluation of unproved properties are initially excluded from the depletion calculation. An impairment test is performed on these assets to determine whether the carrying value exceeds the fair value. Any excess in carrying value over fair value is impairment. When proved reserves are assigned or a property is considered to be impaired, the cost of the property or the amount of the impairment will be added to the capitalized costs for the calculation of depletion.

Ceiling Test

The ceiling test is a cost recovery test intended to identify and measure potential impairment of assets. An impairment loss is recorded if the sum of the undiscounted cash flows expected from the production of the proved reserves and the lower of cost and market of unproved properties does not exceed the carrying values of the petroleum and natural gas assets. An impairment loss is recognized to the extent that the carrying value exceeds the sum of the discounted cash flows expected from the production of proved and probable reserves and the lower of cost and market of unproved properties. The cash flows are estimated using the future product prices and costs and are discounted using the risk free rate. By their nature, these estimates are subject to measurement uncertainty and the impact on the financial statements could be material. Any impairment as a result of this ceiling test will be charged to operation as additional depletion and depreciation expense.

Asset Retirement Obligations

The Company records a liability for the fair value of legal obligations associated with the retirement of petroleum and natural gas assets. The liability is equal to the discounted fair value of the obligation in the period in which the asset is recorded with an equal offset to the carrying amount of the asset. The liability then accretes to its fair value with the passage of time and the accretion is recognized as an expense in the financial statements. The total amount of the asset retirement obligation is an estimate based on the Company's net ownership interest in all wells and facilities, the estimated costs to abandon and reclaim the wells and facilities and the estimated timing of the costs to be incurred in future periods. The total amount of the estimated cash flows required to settle the asset retirement obligation, the timing of those cash flows and the discount rate used to calculate the present value of those cash flows are all estimates subject to measurement uncertainty. Any change in these estimated would impact the asset retirement liability and the accretion expense.

Stock Based Compensation

The Company uses fair value accounting for stock-based compensation. Under this method, all equity instruments awarded to employees and the cost of the service received as considerations are measured and recognized based on the fair value of the equity instruments issued. Compensation expense is recognized over the period of related employee service, usually the vesting period of the equity instrument awarded.

Income Taxes

The determination of income and other tax liabilities requires interpretation of complex laws and regulations. All tax filings are subject to audit and potential reassessment after the lapse of considerable time. Accordingly, the actual income tax liability may differ significantly from that estimated and recorded by management.

Acquisition of Bear Ridge Resources Ltd.

Management makes various assumptions in determining the fair values of any acquired company's assets and liabilities in a business combination. The most significant assumptions and judgments made relate to the estimation of the fair value of Sabretooth's shares issued in the transaction and the fair value of the oil and natural gas properties acquired. To determine the fair value of the oil and gas properties, management estimated oil and natural gas reserves and future prices of oil and natural gas.

Other Estimates

The accrual method of accounting requires management to incorporate certain estimates including estimates of revenues, royalties and operating costs as at a specific reporting date, but for which actual revenues and costs have not yet been received. In addition, estimates are made on capital projects which are in progress or recently completed where actual costs have not been received by the reporting date. The Company obtains the estimates from the individuals with the most knowledge of the activity and from all project documentation received. The estimates are reviewed for reasonableness and compared to past performance to assess the reliability of the estimates. Past estimates are compared to actual results in order to make informed decisions on future estimates.

Risks and Uncertainties

The Company is engaged in the exploration, development, production and acquisition of crude oil and natural gas. This business is inherently risky and there is no assurance that hydrocarbon reserves will be discovered and economically produced. Financial risks associated with the petroleum industry include fluctuations in commodity prices, interest rates and currency exchange rates along with the credit risk of the Company's industry partners. Operational risks include reservoir performance uncertainties, the reliance on operators of our non-operated properties, competition, environmental and safety issues, and a complex and changing regulatory environment. Sabretooth is taking steps to reduce its business risks by increasing the number of core areas it has and increasing the number of areas it operates. This will spread the operational risks over several areas, reducing the potential impact on Sabretooth of unfavourable operational issues that may occur at any one area. It will also enable Sabretooth to control the timing, direction and costs related to exploration and development activities.

Environmental and safety risks are mitigated through compliance with provincial and federal environmental and safety regulations, by maintaining adequate insurance, and by adopting appropriate emergency response and safety procedures. The Company manages commodity pricing uncertainties with a risk management program that encompasses a variety of financial instruments. These include forward sales contracts on natural gas production and financial sales contracts.

Outlook

Sabretooth's current production is approximately 3,600 boe/d.

In 2007, the Company has budgeted approximately $32 million for its proposed capital programs of which approximately $25 million has been spent as of September 30, 2007. These expenditures are expected to be funded by bank debt and cash flow. A substantial amount of the Company's spending is discretionary in nature. The Company generally has a high working interest and operational control of its major properties. Therefore, timing of expenditures can be matched to financial resources.

The Company has access to credit facilities of $55 million subject to periodic review. As at November 7, 2007, the Company has drawn approximately $41.4 million on its operating line of credit, and holds asset backed commercial paper with a face value of approximately $24.2 million. Management believes that the value of the asset backed commercial paper is not materially different than it's face value.



Corporate Information

----------------------------------------------------------------------------
----------------------------------------------------------------------------
OFFICERS AND
DIRECTORS MANAGEMENT ADVISORS
----------------------------------------------------------------------------

Marshall Abbott Marshall Abbott AUDITORS
Chairman and CEO Chairman and CEO Collins Barrow Calgary LLP
Sabretooth Energy Ltd.
Vicky Badger BANKER
Thomas Brinkerhoff Manager, Geology National Bank of Canada
President
Brinkerhoff Drilling John Bell ENGINEERING CONSULTANTS
2000 Inc. Production/ Facilities GLJ Petroleum Consultants
Manager
John H. Campbell, Jr. LEGAL COUNSEL
Managing Director Cheryl Clark Stikeman Elliot LLP
Quantum Energy Partners Controller
HEAD OFFICE
Vincent Chahley Paul Collier Suite 702, 2303 - 4(th)
Independent Businessman Manager, Geology Street, S.W.
Calgary, Alberta T2S 2S7
Brent Perry Karl DeMong Tel: (403) 229-3050
Partner Drilling/Completions Fax: (403) 229-0603
Felesky Flynn LLP Manager Email: dougs@sabretooth.ca

Hank Swartout Louis Hwang WEBSITE
Independent Businessman Chief Geophysicist www.sabretooth.ca

S. Wil VanLoh, Jr. Sandra Fischer
Managing Partner Production Accountant
Quantum Energy Partners
Tammy Leskun
Land Administrator

Ben Leung
Financial Reporting Manager

David Mackie
Chief Geologist

Joe McFarlane
Chief Financial Officer

Mike Ponto
Vice President, Land

Bruce Riep
Senior Surface Landman

Christine Robertson
Chief Operating Officer

Cindy Villanueva
Office Manager

Doug Swartout
Business Development


Contact Information