TUSK Energy Corporation
TSX : TSK

TUSK Energy Corporation

March 22, 2007 19:40 ET

TUSK Releases Year-End Results

CALGARY, ALBERTA--(CCNMatthews - March 22, 2007) -

NOT FOR DISSEMINATION IN THE UNITED STATES OF AMERICA. ANY FAILURE TO COMPLY WITH THIS RESTRICTION MAY CONSTITUTE A VIOLATION OF U.S. SECURITIES LAWS.

TUSK Energy Corporation (TSX:TSK) ("TUSK") is pleased to release the financial results for the period December 31, 2006.

HIGHLIGHTS

On November 13, 2006 TUSK announced a business combination with Zenas Energy Corp. ("Zenas"). The transaction closed and was effective December 31, 2006. In conjunction with the business combination TUSK changed its fiscal year end from March 31st to December 31st. Accordingly the financial statements of TUSK contained in this report contain nine months of operations of TUSK from April 1, 2006 to December 31, 2006 while the balance sheet reflects the combined assets, liabilities and shareholders equity of the combined entity.

The transaction combined the light oil and natural gas exploration potential of the Mega/Gutah area, the large natural gas resource play at Elleh and the lower risk moderate depth exploration and development opportunities of the Peace River Arch.

A fourth focus area has been added effective March 22nd at Conroy, British Columbia, details of which are the subject of a separate news release.



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Period Ended Year Ended
December 31, 2006 March 31, 2006 Change
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($) ($)
Financial
Oil and gas revenue 14,330,928 11,789,528 22
Funds from operations(1) 6,606,670 5,079,364 30
Per share - basic 0.14 0.14 -
- diluted 0.13 - -
Net income (loss) (3,445,155) (1,334,777) (154)
Per share - basic and diluted (0.07) (0.04) (75)
Capital expenditures 42,684,074 45,527,645 (6)
Working capital 11,958,388 3,250,161 268
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(000s) (#) (#) (%)
Share Data
Weighted average shares outstanding 48,878,044 36,769,494 33
Equity outstanding
Common shares 88,879,722 40,555,371 119
Stock options 8,866,000 3,345,000 170
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Operations
Production volumes
Crude oil (bbls/d) 494 283 75
Natural gas liquids (bbls/d) 13 13 -
Natural gas (mcf/d) 2,832 1,558 82
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Combined (boe/d) 979 556 76
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Netback ($/boe)(2)
Average selling price 53.21 58.07 (8)
Royalties 10.06 11.21 (10)
Operations expense 9.49 12.34 (28)
Transportation expense 2.77 5.36 (37)
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Operating netback 30.89 29.16 (6)
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(1) Funds from operations is a non-GAAP measure that represents net income
(loss) before depletion, depreciation and amortization, future taxes and
stock-based compensation. See further discussion under Non-GAAP Measures
in the Management's Discussion and Analysis.
(2) Netback is a non-GAAP measure that represents specific revenue and
expenses on a per unit of production basis. Natural gas has been
converted to boe at a ratio of 6 mcf : 1 bbl.


LETTER TO SHAREHOLDERS

Winter Drilling Results

TUSK enjoyed considerable success this winter with only three of the 23 gross (13 net) wells drilled being dry holes. The total program, which includes 6 wells drilled in December, resulted in 16 successful wells, 4 standing wells and 3 dry holes.

At Elleh TUSK drilled 7 gross wells (3.5 net) including six horizontal wells and one vertical well. The horizontal wells are being tied-in and the vertical well is a standing well. In addition, a 68 square mile 3D seismic program was shot and a 15 km all season road was constructed. TUSK plans to drill another six horizontal wells at Elleh this summer utilizing the new road for access. Production rates and reserves additions at Elleh from this winters program were at or above expectations.

At Mega/Gutah TUSK drilled ten gross wells (7.5 net) this winter. Nine of the wells were drilled through the Keg River target zone and cased for further evaluation while one well (0.5 net) was drilled to a shallower zone and abandoned. Three of the wells, all drilled in the Gutah area, have been completed and will be tied-in in the next few weeks. Five of the wells are standing cased and two were dry holes. The standing wells all had indications of hydrocarbons in the wellbore and at least two of these, and possibly four, are expected to be on production once further completion work is done next winter.

The winter program has defined an oil pool at Gutah which TUSK estimates to contain 11 million barrels of light (46 degrees API) oil. We now have an inventory of at least 5 lower risk development locations at Gutah. In addition, we have added much to our knowledge of this very significant Keg River exploration fairway and anticipate adding production and reserves in the future at very economic rates from both Gutah and other areas.

In the Peace River Arch "PRA" area TUSK participated in 6 gross wells (2 net) with a 100% success rate. We expect to drill 12 wells in this area through the remainder of 2007. PRA has been a very successful area for TUSK and we expect to continue to grow our production and reserves in this core area.

Capital Spending and Production Targets

TUSK now anticipates a 2007 capital spending budget of approximately $75 million and average 2007 production levels of between 4,000 and 4,500 Boe/d. Further, with the existing opportunities at Elleh, Mega/Gutah and the PRA and the addition of the Conroy project, TUSK anticipates production levels to exceed 6,000 boe/d in mid 2008. Production guidance for 2007 has been lowered from previous expectations of between 4,500 and 5,000 Boe/d based on actual drilling results and the timing of production additions resulting from wells drilled during this winters drilling program.

We announce that the company regretfully accepted the resignation of Mr. James S. Artindale as a director of the Company. Jim has been an excellent contributor to TUSK and the predecessor companies Blizzard Energy Inc. and Zenas Energy Corp. Jim has accepted a position in industry and resigned to remove any potential conflicts of interest.

On behalf of the Board of Directors,

John R. Rooney, Chief Executive Officer

MANAGEMENT'S DISCUSSION AND ANALYSIS

The following discussion and analysis has been prepared by management and reviewed and approved by the Board of Directors. This commentary is based on information available as at March 21, 2007. The discussion and analysis is a review of the operational results of the Corporation with disclosure of oil and gas activities in accordance with Canadian Securities Regulators National Instrument 51-101 Standards of Disclosure for Oil and Gas Activities and a review of financial results of the Corporation based on Canadian generally accepted accounting principles. Its focus is primarily a discussion of the operational and financial performance for the period ended December 31, 2006 and the year ended March 31, 2006 and should be read in conjunction with the financial statements for the period ended December 31, 2006 and the year ended March 31, 2006.

Zenas Acquisition

TUSK Energy Corporation acquired Zenas Energy Corp. through a plan of arrangement effective December 31, 2006. The consolidated balance sheet and consolidated statements of cash flow include the accounts of Zenas Energy Corp. as at December 31, 2006.

Change in Year-End

TUSK Energy Corporation has changed its year-end from March 31 to December 31, effective December 31, 2006. The financial information in the December 31, 2006 financial information includes nine months of operations. Comparative information compares the nine months ended December 31, 2006 to the year ended March 31, 2006.

Basis of Presentation

The financial data presented below has been prepared in accordance with Canadian generally accepted accounting principles. The reporting and the measurement currency is the Canadian dollar.

Non-GAAP Measures

The Management's Discussion and Analysis contains the term funds flow from operations and operating netback which should not be considered an alternative to, or more meaningful than funds flow from operating activities as determined in accordance with Canadian generally accepted accounting principles as an indicator of the Corporation's performance. Management believes that in addition to net earnings, funds flow from operations and operating netback are useful supplemental measures as they demonstrate the Corporation's ability to generate the cash necessary to repay debt or fund future growth through capital investment. The Corporation's determination of cash flow from operations may not be comparable to that reported by other companies. The reconciliation between net earnings and cash flow from operations can be found in the consolidated statements of cash flows in the unaudited interim consolidated financial statements and the audited consolidated financial statements. The Corporation also presents funds flow from operations per share whereby per share amounts are calculated using weighted average shares outstanding consistent with the calculation of earnings per share.

BOE Presentation

Barrels of oil equivalent may be misleading, particularly if used in isolation. The boe conversion ratio of 6 mcf: 1 bbl of oil 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.



Netback per boe

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Period Ended Year Ended
December 31, 2006 March 31, 2006
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(per boe) ($) ($)
Oil and gas revenue 53.21 58.07
Royalties, net of Alberta Royalty Tax Credit 10.06 11.21
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Net revenue 43.15 46.86
Operating expenses 9.49 12.34
Transportation expenses 2.77 5.36
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Net operating revenue 30.89 29.16
General and administrative expenses 9.16 6.29
Interest income (2.81) (2.14)
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Netback per boe 24.54 25.01
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Land Holdings

At December 31, 2006, TUSK's undeveloped land holdings were 515,623 gross (202,936 net) acres, while total land holdings amounted to 587,951 gross (230,321 net) acres. The following table summarizes the Corporation's land holdings at year-end:



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Undeveloped Developed
Average Average
Gross Net Interest Gross Net Interest
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(acres) (acres) (%) (acres) (acres) (%)

Alberta 285,418 142,513 50 53,390 19,214 36
British Columbia 229,396 59,614 26 18,938 8,171 43
Saskatchewan 809 809 100 - - -
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Total 515,623 202,936 39 72,328 27,385 38
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Drilling Activity

TUSK participated in the drilling of 18 gross (6.9 net) wells in the nine months ended December 31, 2006, compared to the year ended March 31, 2006 when the Corporation participated in the drilling of 24 gross (10.1 net) wells. Of this December 31, 2006 total, 14 gross (4.8 net) were exploratory and 4 gross (1.7 net) were development wells. The Corporation's success rate was 86% for exploration wells and 75% for development wells, representing an overall success rate of 83% in 2006.



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Exploration Development Total
Gross Net Gross Net Gross Net
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(#) (#) (#) (#) (#) (#)
Nine Months Ended
December 31, 2006
Light and Medium
Oil 6 3.0 2 1 8 4.0
Natural Gas 5 1.1 - - 5 1.1
Drilling Suspended 1 0.1 1 0.5 2 0.6
Dry and abandoned 2 1.0 1 0.2 3 1.2
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Total wells 14 5.2 4 1.7 18 6.9
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Success rate (%) 86% 75% 83%
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Year Ended March 31, 2005
Light and Medium
Oil 5 2.3 2 0.9 7 3.2
Natural Gas 7 2.2 2 0.7 9 2.9
Drilling Suspended 4 2.0 1 0.5 5 2.5
Dry and abandoned 3 1.5 - - 3 1.5
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Total wells 19 8.0 5 2.1 24 10.1
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Success rate (%) 84% 100% 88%
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In addition, TUSK farmed out lands during the period ended December 31, 2006 in which three wells were drilled at no cost to TUSK. TUSK has a GORR interest in these and currently, these wells are classified as suspended.

Reserves

The following reserve information is based on the evaluations prepared by independent reserve engineers for both TUSK and Zenas' oil and gas properties as of December 31, 2006.

Forecast Prices and Costs

Summary of Oil and Gas Reserves

The following table outlines the oil and gas reserves of the Corporation by product type on a gross (before royalties) and net (after royalties) basis. At December 31, 2006, the Corporation had 6,712,000 gross (5,425,000 net) proved boe's and 9,408,000 gross (7,585,000 net) proved plus probable boe's.



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Crude Oil Natural Gas Liquids Natural Gas
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Gross Net Gross Net Gross Net
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(mbbls) (mbbls) (mbbls) (mbbls) (mmcf) (mmcf)
Proved
Developed
producing 1,500 1,178 195 136 14,312 11,480
Developed
non-producing 11 10 15 12 4,173 3,358
Undeveloped 484 342 36 29 8,341 7,470
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Total proved 1,995 1,530 246 177 26,826 22,308
Probable 962 745 99 70 9,810 8,070
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Total proved plus
probable 2,957 2,275 345 247 36,636 30,378
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Net Present Values of Future Net Revenue

The net present values of future net revenue of the Corporation's reserves at various discount rates on a before and after tax basis are outlined below. At December 31, 2006, the Corporation had approximately $194 million of tax deductions available to reduce future taxable income, and as a result there is no reduction to the net present values (10% discount rate) for future income taxes.



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Before Income Taxes
Discounted At
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0% 5% 10% 15% 20%
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(M$) (M$) (M$) (M$) (M$)
Proved
Developed producing 116,899 95,719 82,536 73,321 66,398
Developed non-producing 18,736 12,654 9,441 7,477 6,156
Undeveloped 39,573 22,927 14,088 8,768 5,267
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Total proved 175,208 131,300 106,065 89,566 77,821
Probable 80,412 53,815 39,931 31,515 25,897
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Total proved plus probable 255,620 185,115 145,996 121,081 103,718
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Reserve Life Index

The reserve life index of TUSK has been calculated using annualized quarter ended December 31, 2006 production volumes for TUSK and Zenas combined and gross proved and proved plus probable reserves using forecast prices and costs. The reserve life index of the Corporation as at December 31, 2006, on a boe basis, was 6.8 years for proved reserves and 9.6 years for proved plus probable reserves.



Net Asset Value at December 31, 2006 and March 31, 2006

December March
($ thousands) 5% 10% 5% 10%
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Proved plus probable reserve
value, before tax 185,115 145,996 78,102 62,166
Undeveloped land (1) 40,587 40,587 17,051 17,051
Seismic (2) 10,000 10,000 5,000 5,000
Working Capital 11,958 11,958 3,250 3,250

Net Asset Value 247,660 208,541 103,403 87,467
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Common shares outstanding 88,879,722 88,879,722 40,555,371 40,555,371
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Net Asset Value per share $2.79 $2.35 $2.55 $2.16
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(1) Undeveloped land values are based on internal estimates of market value
considering recent sales of similar properties in the same general area.
(2) Seismic inventory values are an internal estimate of replacement value.


Finding, Development and Acquisition Costs

Advisory

The aggregate of the exploration and development costs incurred in the most recent financial year and the change during the year in estimated future development capital generally will not reflect total finding and development costs related to reserve additions for that year.



Finding, Development and Acquisition Costs for the nine months
ended December 31, 2006 for proved plus probable reserve
additions per boe

Without future development capital $24.33
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With future development capital $28.11
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Financial and Operating Results

Oil & Gas Production and Revenue

Oil and gas revenue, before royalties, for the nine months ended December 31, 2006 was $14,330,927. Oil and gas revenue before royalties for the year ended March 31, 2006 was $11,789,528. Boe production for the period ended December 31, 2006 was 269,256 boe (979 boe/day) compared to 203,039 boe (556 doe/day) for the year ended March 31, 2006. BOE/per day increased 76% during the same time period. The increase in production is the result of additional wells being tied in during the first quarter of 2006 and the purchase of production and further development of production in the Puskwa/Peoria area.



Period Ended Year Ended
December 31, 2006 March 31, 2006
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Oil and Gas Revenues, Before Royalties $14,330,927 $11,789,528

Oil Production (bbls) 134,988 103,382
Oil Revenue $ 8,794,038 $ 6,556,397
Oil Price ($/bbl) $ 65.15 $ 63.42

NGL Production (bbls) 4,457 4,828
NGL Revenue $ 219,905 $ 169,131
NGL Price ($/bbl) $ 49.34 $ 35.03

Gas Production (Mcf) 778,867 568,971
Gas Revenue $ 5,316,984 $ 5,063,998
Gas Price ($/Mcf) $ 6.83 $ 8.90

BOE Production 269,256 203,039
BOE per Day 979 556
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Royalties

Total royalties, net of Alberta Royalty Tax Credit, were $2,709,795 ($10.06/boe) for the period ended December 31, 2006. Total royalties, net of Alberta Royalty Tax Credit, were $2,275,672 ($11.21/boe) for the year ended March 31, 2006. Net royalties represented 19% of gross revenues for the period ended December 31, 2006 and the year ended March 31, 2006. Royalties per BOE decreased from $11.21/boe for the year ended March 31, 2006 to $10.06 for the nine months ended December 31, 2006. The 10% decrease is the result of three new wells coming on production that are on royalty holidays. The royalty holidays are in place for either twelve production months or the value of $1,000,000 in royalties, whichever occurs first. The provincial government has announced the cancellation of the ARTC program effective January 1, 2007.



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Period Ended Year Ended
December 31, 2006 March 31, 2006
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($) ($)
Crown royalties 2,267,158 1,680,344
Freehold royalties 211,386 568,123
Gross overriding royalties 300,663 366,217
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2,779,207 2,614,684
Alberta Royalty Tax Credit (69,412) (339,012)
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Net royalties 2,709,795 2,275,672
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Net royalties per boe (6:1) 10.06 11.21
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Operating Expenses

Operating expenses for the period ended December 31, 2006 were $2,555,792 ($9.49/boe) and were $2,505,829 ($12.34/boe) for the year ended March 31, 2006, resulting in a 28% decrease in operating expenses per boe. The 28% decrease in operating costs per boe is mainly the result of the commissioning of the new battery at Mega in August 2006, providing operating expense efficiencies and the 33% increase in boe production for the period ended December 31, 2006 compared to the year ended March 31, 2006.

Transportation Expenses

The newly constructed facilities at Mega have reduced transportation expenses. Transportation expenses for the period ended December 31, 2006 were $746,980 ($2.77/boe) as compared to $1,087,036 ($5.36/boe) for the year ended March 31, 2006, which was a 37% decrease in transportation expenses per boe.

Stock Based Compensation

Stock based compensation for the period ended was $2,349,163 and $1,790,890 for the year ended March 31, 2006. The increase in stock based compensation was due to the addition of 3,776,000 stock options upon the merger with Zenas Energy Corp.

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

TUSK is in the early stages of exploration and development at its Mega property and has invested capital in the construction of infrastructure to ensure current and future production will be put onstream quickly and efficiently. This investment has led to high DD&A costs on a per boe basis. Depletion, depreciation and accretion was $8,170,062 for the period ended December 31, 2006, which represents a provision of $30.34/boe of production. For the year ended March 31, 2006, depletion, depreciation and accretion was $4,671,251, which represents a provision of $22.97/boe of production. The depletion provision for the period ended December 31, 2006 excluded $27.5 million of costs for undeveloped properties including $9.8 million of seismic costs, $4.7 million of exploratory drilling costs and $13.0 million for undeveloped land costs.

General and Administrative Expenses

Gross general and administrative costs for the period ended December 31, 2006 were $4,346,179. For the year ended March 31, 2006, gross general and administrative costs were $3,409,304, including $1,018,742 charged under the Technical Services Agreement with TKE Energy Trust which ended effective November 2, 2005. Net general and administrative expenses for the nine months ended December 31, 2006 were $9.16/BOE and $6.29/BOE for the year ended March 31, 2006, resulting in a 46% increase in net general and administrative expenses per boe. The increase in net general and administrative costs per boe include a variety of items. There was a reduction in overhead recoveries due to the change in year end from March 31 to December 31. The change in year end excludes significant overhead recoveries which would normally occur as a result of TUSK's major drilling program in winter access areas during the months of January through March. Other items included a one time payout of an executive contract due to the merger with Zenas, salaries and associated costs, additional employees, consultants, office lease and technology.



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Period Ended Year Ended
December 31, 2006 March 31, 2006
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($) ($)
Gross general and administrative expenses 4,346,179 3,409,304
Overhead recoveries (711,657) (1,148,240)
Exploration and development costs
capitalized (1,166,801) (984,200)
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Net general and administrative expenses 2,467,721 1,276,864
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Per boe 9.16 6.29
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Provision for Income Taxes

The provision for income taxes for the period ended December 31, 2006 was a recovery of the future income taxes totalling asset of $467,400. For the year ended March 31, 2006, the provision for income taxes was comprised of a recovery of $48,000. At December 31, 2006, the Corporation had an estimated $193 million in unclaimed income tax pools, which includes $86 million in unclaimed tax pools as a result of the merger with Zenas Energy Corp. The provision for income taxes includes the effects of a reduction in future federal and provincial income tax rates enacted during the period and includes the impact of certain tax balance adjustments.

Investments

The Company has invested a total of $4,270,643 in 12.3 million common shares of an oil and gas company which is listed on the TSX Venture Exchange. The investment is carried at cost. Fair value of the investment at December 31, 2006 was approximately $6.8 million. One director of the Company is a director of this company and one officer of the Company is a director of this company.

The Company has invested a total of $257,689 in common shares of a private drilling company. The investment is carried at cost.

Management expects to dispose of its investments during the coming year, and accordingly these investments are categorized as current assets.

Equity

On June 7, 2006, the Corporation closed a prospectus offering of 7.31 million common shares of TUSK and 3.89 million common shares of TUSK issued on a flow-through basis. The common shares and flow-through shares were issued upon the closing of the bought-deal offering arranged through a syndicate of underwriters. The common shares were issued at a price of $4.10 per share and the flow-through shares were issued at a price of $5.15 per share for total gross proceeds of $50,004,400.

The Corporation issued a total of 37,204,118 common shares on the acquisition of Zenas, effective December 31, 2006.

As at December 31, 2006 there were 8,866,000 stock options outstanding and at March 21, 2007 there were 8,878,500 stock options outstanding.

At March 21, 2007, there were 88,879,722 common shares issued and outstanding.

Capital Expenditures

Capital additions, excluding acquisitions, for the year ended December 31, 2006 were $42,234,073. For the year ended March 31, 2006 capital additions, excluding acquisitions were $45,527,645.



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Period Ended Year Ended
December 31, 2006 March 31, 2006
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($) ($)
Land 2,576,571 5,203,938
Seismic and exploration 15,156,878 3,918,510
Drilling and completion 21,813,827 27,037,716
Facilities 2,593,748 9,185,462
Corporate 93,049 182,019
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Total 42,234,073 45,527,645
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Acquisitions

Acquisition of Zenas Energy Corp.

Effective December 31, 2006, the Company entered into a business combination with Zenas Energy Corp. ("Zenas") whereby TUSK acquired all of the issued and outstanding shares of Zenas pursuant to a plan of arrangement. The previous shareholders of Zenas received 1.033 shares of TUSK for each outstanding Zenas share. A total of 37,204,118 TUSK shares were issued pursuant to the transaction concurrent with the business combination. TUSK and Zenas amalgamated on January 1, 2007 and continue as TUSK. The value of the transaction, based upon the adjusted weighted average trading price for TUSK shares for the five trading days before and after the announcement on November 13, 2006 of $2.65 was $100.14 million (including $1.53 million in transaction costs). The transaction was accounted for using the purchase method.



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Cost of acquisition: ($)
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TUSK shares issued 98,609,514
Corporate 1,530,000
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100,139,514
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Allocated at estimated fair values: ($)
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Cash 4,503,121
Accounts receivable 4,588,288
Prepaid expenses 365,750
Property, plant and equipment 114,554,877
Accounts payable and accrued liabilities (14,303,253)
Future income taxes (7,674,624)
Asset retirement obligations (1,894,645)
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100,139,514
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The Puskwa Acquisition

On April 21, 2006, pursuant to an agreement with an arm's-length private Alberta company, TUSK acquired 6.52 net natural gas wells producing approximately 240 boe/d net, a 44.5% net working interest in a natural gas plant infrastructure in the Puskwa area of northwest Alberta and 42 net section of oil and gas rights in exchange for 110,080 acres (11,008 acres net) of undeveloped land. The gas plant and the associated lands acquired are located in the Peace River Arch area of Alberta.

Commitments

a) Flow-Through Commitment

At December 31, 2006, the Corporation has fulfilled its obligation to expend $20,033,500 in flow-through expenditures.

b) Cutbank Seismic Commitment

Under a series of agreements, TUSK agreed to expend $20 million on seismic to earn interests in approximately 194,000 acres of petroleum and natural gas rights located in two areas: the Puskwa area of northwest Alberta and the Cutbank area of northeast British Columbia. TUSK will earn a working interest in the lands by shooting the seismic and have the opportunity to increase its interest in prospective portions of the Cutbank lands by drilling farm-in wells. The transaction was as of April 1, 2006. At December 31, 2006 a total of $13.5 million had been expended on the commitment.

c) Drilling Rigs

The Corporation has made commitments for two drilling rigs as follows:

- 220 day/year for 3 years starting at rig delivery in December 2005, with an obligation of $6,800/day.

- 250 day/year for 4 years starting at rig delivery in February 2007, with an obligation of $9,700/day.

d) Office Lease Obligations

The Corporation committed to payments under operating leases for office space to January 31, 2013 as follows:



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Year Amount
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($)
2007 352,000
2008 513,000
2009 536,000
2010 544,000
2011 and thereafter 1,133,000


Liquidity and Capital Resources

TUSK had working capital of $11,958,388 at December 31, 2006.

The Corporation has a $20 million demand revolving operating credit facility and a $2 million non-revolving acquisition/development loan with a Canadian chartered bank each of which bear interest at the bank's prime lending rate plus three quarters of one per cent. The credit facility is secured by a $25 million fixed and floating charge debenture on the assets of the Corporation, a general assignment of book debts and a $6.9 million letter of guarantee. None of the credit facility was drawn at December 31, 2006.

Subsequent to year-end, the bank loan was increased to a $45 million demand revolving operating facility, secured by a $100 million fixed and floating charge debenture as well as other security already granted.

On an ongoing basis, TUSK will typically 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 on favourable terms. When financing corporate acquisitions, TUSK may also assume certain future liabilities. Commodity prices and production volumes have the largest impact on TUSK's ability to generate adequate cash flow to meet all its obligations. A prolonged decrease in commodity prices would negatively affect TUSK's cash flow from operations and would also likely result in a reduction in the amount of bank loan available. If TUSK's capital expenditure program does not result in sufficient additional reserves and/or production it would likely have a negative impact on TUSK's liquidity.

TUSK may adjust its capital expenditure program depending on the commodity price outlook. TUSK believes that internally generated cash flow and incremental bank debt should be sufficient to finance current operations and planned capital spending in the next year.

Business Risks, Uncertainties and Forward-Looking Statements

Statements in this document may contain forward-looking information including expectations of future production, components of cash flow and earnings, expected future events and/or financial results that are forward looking in nature and subject to substantial risks and uncertainties. The reader is cautioned that assumptions used in the preparation of such information may prove to be incorrect. The Corporation cautions the readers that actual performance will be affected by a number of factors, as many may respond to changes in economic and political circumstances throughout the world. Events or circumstances may cause actual results to differ materially from those predicted, a result of numerous known and unknown risks, uncertainties, and other factors, many of which are beyond the control of the Corporation. These risks, include, but are not limited to; associated with the oil and gas industry, commodity prices and exchange rate changes. Industry related risks could include, but are not limited to; operational risks in exploration, development and production, delays or changes in plans, risks associated with the uncertainty of reserve estimates, health and safety risks and the uncertainty of estimates and projections of production costs and expenses. These external factors beyond the Corporation's control may affect the marketability of oil and natural gas produced, industry conditions including changes in laws and regulations, changes in income tax regulations, increased competition, fluctuations in commodity prices, interest rates, and variations in the Canadian/United States dollar exchange rate. The reader is cautioned not to place undue reliance on this forward-looking information.

TUSK's production and exploration activities are concentrated in the Western Canada Sedimentary Basin, where activity is highly competitive and includes a variety of different sized companies ranging from smaller junior producers to the much larger integrated petroleum companies. TUSK is subject to the various types of business risks and uncertainties including:

- Finding and developing oil and natural gas reserves at economic costs;

- Production of oil and natural gas in commercial quantities; and

- Marketability of oil and natural gas produced.

In order to reduce exploration risk, TUSK strives to employ highly qualified and motivated professional employees with a demonstrated ability to generate quality proprietary geological and geophysical prospects. To help maximize drilling success, TUSK combines exploration in areas that afford multi-zone prospect potential, targeting a range of low to moderate risk prospects with some exposure to select high-risk with high-reward opportunities. TUSK also explores in areas where the Corporation has significant drilling experience.

The Corporation mitigates its risk related to producing hydrocarbons through the utilization of the most appropriate technology and information systems. In addition, TUSK seeks to maintain operational control of the majority of its prospects.

Oil and gas exploration and production can involve environmental risks such as pollution of the environmental and destruction of natural habitat, as well as safety risks such as personal injury. In order to mitigate such risk, TUSK conducts its operations at high standards and follows safety procedures intended to reduce the potential for personal injury to employees, contractors and the public at large. The Corporation maintains current insurance coverage for general and comprehensive liability as well as limited pollution liability. The amount and terms of this insurance are reviewed on an ongoing basis and adjusted as necessary to reflect changing corporate requirements, as well as industry standards and government regulations. TUSK may periodically use financial or physical delivery hedges to reduce its exposure against the potential adverse impact of commodity price volatility, as governed by formal policies approved by senior management subject to controls established by the Board of Directors. At December 31, 2006, no hedges were in place.

Outlook

Through the business combination with Zenas, TUSK developed into a large junior oil & gas company with a high quality asset base, strong exploration and operational capability, and financial strength.

The recent announcement of the Conroy farm-in is a significant step forward for TUSK. This deal brings a 90,000 acre contiguous land base with a large known accumulation of natural gas. We expect to allocate a significant portion of our 2008 capital expenditure budget to this project, and new production from this area, along with the continued development of the Elleh and Mega/Gutah areas, will contribute to the next phase of production growth for TUSK. The TUSK professional staff has successfully executed similar large development programs in the past and we are excited about this new opportunity.

The company now has four core areas, a high quality and growing production base, a large concentrated land base, a strong balance sheet and a team of dedicated professionals. TUSK is poised to grow without relying on financing or asset additions.

2006 was a challenging year for many in our business due to highly variable commodity prices, increasing service costs and generally smaller reservoir targets with higher decline rates. Finding costs are at historic highs while netbacks have suffered due to low natural gas prices associated with high inventory levels. As we move forward we will employ a rigorous approach to cost control to ensure TUSK meets the objectives of profitable growth and increasing shareholder value.



Quarterly Data

----------------------------------------------------------------------------
Three Months Dec.31, Sep.30, June 30, Mar.31, Dec.31, Sep.30, June 30,
Ended 2006 2006 2006 2006 2005 2005 2005
----------------------------------------------------------------------------
(unaudited)($000's
except for per
share amounts) ($) ($) ($) ($) ($) ($) ($)

Oil and gas revenue
Oil & NGL's
(bbls/d) 699 502 318 305 376 331 175
Natural gas
(mcf/d) 3,636 2,493 2,362 1,191 1,736 1,754 1,538
Total (boe/d) 1,305 918 711 504 665 623 432
Oil and gas
revenues before
royalties 6,327 4,656 3,348 2,402 3,338 2,777 1,482
Capital
expenditures 13,246 11,273 17,715 23,733 3,463 8,710 9,621
Funds from
operations 2,934 2,226 1,447 730 2,079 1,757 460
Per share - basic 0.07 0.04 0.03 0.02 0.06 0.05 0.01
- diluted 0.06 0.04 0.03 0.02 0.06 0.05 0.01
Net Income (loss) (2,342) (420) (683) (494) (322) 13 (542)
Per share - basic
and diluted (0.05) (0.01) (0.01) (0.02) (0.01) - (0.02)


Fourth Quarter Analysis

----------------------------------------------------------------------------
Three Months Ended December 31, 2006 March 31, 2006
----------------------------------------------------------------------------
Daily production
Crude oil (bbls/d) 682 289
Natural gas liquids (bbls/d) 17 16
Natural gas (mcf/d) 3,636 1,191
----------------------------------------------------------------------------
Total (boe/d) 1,305 504
----------------------------------------------------------------------------
($) ($)
Summary of Product Prices
Crude oil ($/bbl) 57.75 57.61
Natural gas liquids ($/bbl) 38.16 38.10
Natural gas ($/mcf) 7.90 7.90
----------------------------------------------------------------------------
($) ($)
Financial (000's except for per share
amounts)
Oil and gas revenue, before royalties 6,327 2,402
Royalties, net of Alberta Royalty Tax
Credit 1,258 486
Oil and gas operating and transportation 1,125 1,031
General and administrative 1,268 370
Depletion, depreciation and accretion 4,368 1,363
Stock-based compensation 1,546 203
Funds from operations 2,934 730
Net Loss (2,342) (494)
Per share - basic and diluted (0.05) (0.02)
Capital expenditures 13,696 23,733
Working capital 11,958 3,250
----------------------------------------------------------------------------
----------------------------------------------------------------------------


Oil and Gas Revenues

Oil and gas revenue was $6,326,666 ($52.68/boe) in the three months ended December 31, 2006 compared to $2,401,741 (52.96/boe) in the three months ended March 31, 2006. The 163% increase in the three months ended December 31, 2006 compared to the three months ended March 31, 2006 was due to the 159% increase in production from 504 boe/d for the three months ended March 31, 2006 compared to 1,305 boe/d for the three months ended December 31, 2006.

Royalties

Royalties remained constant on a per boe basis for the three months ended December 31, 2006 were $1,257,737 ($10.47/boe) compared to $485,547 ($10.71/boe) for the three months ended March 31, 2006.

Operating and Transportation Expenses

Operating and transportation expense was $3,302,772 ($12.27/boe) for the three months ended December 31, 2006 compared to $1,916,194 ($22.73/boe) for the three months ended March 31, 2006. The 46% decrease in operating and transportation expenses per boe is the result of the commissioning of the new battery at Mega in August 2006 and the 159% increase in production volumes between the two quarters.

General and Administrative Expenses

General and administrative expense was $1,267,747 ($10.56/boe) for the three months ended December 31, 2006 compared to $370,224 ($8.16/boe) for the three months ended March 31, 2006. The 242% (29%/boe) increase in general and administrative expenses consists of a one time payout of an executive contract due to the merger with Zenas Energy Corp. in December 2006, salaries and associated costs, additional employees, consultants, office lease and technology. Also, due to the change in the year end from March 31 to December 31, the amount of overhead recoveries from the most active months of the Corporation (January to March) has not been included in the period ended December 31, 2006. The increases in the various general and administrative expenses reflect the cost to administer the growth of the Corporation.

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

TUSK is in the early stages of exploration and development at its Mega property and has invested capital in the construction of infrastructure to ensure current and future production will be put onstream quickly and efficiently. Depletion, depreciation and accretion was $4,368,317 ($36.38/boe) for the three months ended December 31, 2006 compared to $1,363,499 ($30.07/boe) for the three months ended March 31, 2006.

Stock Based Compensation

Stock Based Compensation for the three months ended December 31, 2006 was $1,545,502 and $203,346 for the three months ended March 31, 2006. The significant increase in stock based compensation is due to the addition of 3,776,000 stock options upon the merger with Zenas Energy Corp. in December 2006.

Funds from Operations

Funds from operations for the three months ended December 31, 2006 were $2,934,085 ($24.43/boe) compared to $729,998 ($16.10/boe) for the three months ended March 31, 2006. The 302% (52%/boe) increase in funds from operations reflects the overall increase in production and revenues and the decrease in expenses excluding the non-cash expenses reflected in the Corporation's financial statements.

Net Loss

The net loss for the three months ended December 31, 2006 was $2,342,334 ($19.50/boe) compared to $494,347 ($10.91/boe) for the three months ended March 31, 2006. The 374% (79%/boe) increase in the net loss includes the one time expenses associated with the merger with Zenas Energy Corp., the significant investment in infrastructure in the Mega area and the increased costs of general and administrative expenses to administer the growth of the Corporation.

Critical Accounting Estimates

Depletion and Depreciation Expense

The Corporation uses the full cost method of accounting for exploration and development activities whereby all costs associated with these activities are capitalized, whether successful or not. The aggregate of capitalized costs, net of certain costs related to unproved properties, and estimated future development costs are amortized using the unit-of-production method based on estimated proved reserves. Changes in estimated proven reserves or future development costs have a direct impact on depletion and depreciation expense. Certain costs related to unproved properties and major development projects may be excluded from costs subject to depletion until proved reserves have been determined or their value is impaired. These properties are reviewed quarterly to determine if proved reserves should be assigned, at which point they would be included in the depletion calculation, or for impairment, for which any write-down would be charged to depletion and depreciation expense.

Full Cost Accounting Ceiling Test

Oil and gas assets are evaluated at least annually to determine that the costs are recoverable and do not exceed the fair value of the properties. The costs are assessed to be recoverable if the sum of the undiscounted cash flows expected from the production of proved reserves and the lower of cost and market of unproved properties exceed the carrying value of the oil and gad assets. If the carrying value of the oil and gas assets is not assessed to be recoverable, 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 costs 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 would be charged as additional depletion and depreciation expense.

Asset Retirement Obligations

The Corporation records a liability for the fair value of legal obligations associated with the retirement of long-lived tangible assets in the period in which they are incurred, normally when the asset is purchased or developed. On recognition of the liability, there is a corresponding increase in the carrying amount of the related asset known as the asset retirement cost. The total future asset retirement obligation is an estimate based on the Corporation'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 undiscounted amount of the estimated cash flows required to settle the asset retirement obligation is an estimate that is subject to measurement uncertainty and any change would impact the liability.

Income Taxes

The determination of the Corporation's income and other tax liabilities required interpretation of complex laws and regulations often involving multiple jurisdictions. 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.

Disclosure Controls and Procedures

Disclosure controls and procedures have been designed to ensure that information required to be disclosed by the Corporation is accumulated and communicated to the Corporation's management as appropriate to allow timely decisions regarding required disclosure. The Corporation's Chief Executive Officer and Chief Financial Officer have concluded, based on their evaluation as of the end of the period covered by the Corporation's annual filings for the most recently completed financial year, that the Corporation's disclosure controls and procedures as of the end of such period are effective to provide reasonable assurance that material information related to the Corporation is made known to them by others within the Corporation. It should be noted that while the Corporation's Chief Executive Officer and Chief Financial Officer believe that 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 will prevent all errors and 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 Corporation's Chief Executive Officer and Chief Financial Officer have designed or caused to be designed under their supervision internal controls over financial reporting related to the Corporation to provide reasonable assurance regarding the reliability of the Corporation's financial reporting and the preparation of financial statements together with the other financial information for external purposes in accordance with the Canadian GAAP.

The Corporation's Chief Executive Officer and Chief Financial Officer are required to cause the Corporation to disclose herein any change in the Corporation's internal control over financial reporting that occurred during the Corporation's most recent interim period that has materially affected, or is reasonably likely to materially affect, the Corporation's internal control over financial reporting. The Corporation has identified two areas of potential material weakness in the Corporation's internal control over financial reporting during the three months ended December 31, 2006. The areas are as follows:

Income Taxes

On a monthly basis, the Corporation makes the necessary provision for income tax and other tax related expenses. Income tax is a highly technical area that requires an in-depth understanding of federal, provincial and state tax laws and the Corporation's accounting staff has only a fair and reasonable knowledge of the rules related to income tax accounting and reporting. Although these have not resulted in a material misstatement of the financial statements, this lack of knowledge represents a material weakness in the Corporation's control environment as a material error relating to income tax accounting or disclosure could go undetected.

To address this risk, the Corporation consults with its third party expert advisors on a regular basis for advice, and also has quarterly reviews of the financial statements completed by the Corporation's auditors. The quarterly reviews and annual audit are presented to the Audit Committee for its review and approval.

Complex and non-routine transactions

As required, the Corporation records complex and non-routine transactions. These sometimes are extremely technical in nature and require an in-depth understanding of Generally Accepted Accounting Principles ("GAAP"). The Corporation's accounting staff has only a fair and reasonable knowledge of the rules related to GAAP and reporting and the transactions may not be recorded correctly, potentially resulting in material misstatement of the financial statements of the Corporation. To address this risk, the Corporation consults with its third party expert advisors as needed in connection with the recording and reporting of complex and non-routine transactions.

It should be noted that a control system, including the Corporation's disclosure and internal controls and procedures, no matter how well conceived can provide only reasonable, but not absolute, assurance that the objectives of the control system will be met and it should not be expected that the disclosure and internal controls and procedures will prevent all errors or fraud.

National Instrument 52-109 Certification of Disclosure in Issuer's Annual and Interim Filing ("NI 52-109") Update

Effective March 30, 2004, National Instrument 52-109 requires a certification process over disclosure and internal controls over financial reporting. Initially, an internal control design was required to provide reasonable assurance regarding the reliability of the financial reporting and preparation of financial statements in accordance with Canadian GAAP. Subsequently, an evaluation of the effectiveness over the internal control design was to have been certified by the Chief Executive Officer and Chief Financial Officer for the year ended December 31, 2007. The Canadian Securities Administrator's ("CSA") issued a notice on February 9, 2007 proposing the requirements under NI 52-109 be extended becoming effective for the Corporation at year end December 31, 2008. This extension is intended to allow significant lead time for issuers to plan and implement efficiently the activities required to support the additional certifications and disclosures relating to internal controls over financial reporting. The CSA further indicates that they plan, by the end of March 2007 to seek all necessary approvals to publish revisions to NI 52-109 for public comment. The Corporation will continue to work diligently to ensure compliance with this requirement by December 31, 2008.

SEDAR

TUSK Energy Corporation is a Toronto Stock Exchange listed company.

As a result, additional public information can be accessed on the Corporation's website at www.tusk-energy.com and on the Canadian Securities Administrators' System for Electronic Document Analysis and Retrieval ("SEDAR") at www.sedar.com.

Gordon K. Case, CA, Vice-President, Finance & Chief Financial Officer

March 21, 2007

Calgary, Alberta



CONSOLIDATED BALANCE SHEETS
(Unaudited)

----------------------------------------------------------------------------
December 31, 2006 March 31, 2006
----------------------------------------------------------------------------
($) ($)
Assets
Current
Cash and cash equivalents 27,186,993 31,472,862
Investments (note 3) 4,528,332 -
Accounts receivable 18,476,388 10,236,473
Prepaid expenses 758,938 1,273,460
----------------------------------------------------------------------------
50,950,651 42,982,795
Investments (note 3) - 4,270,643
Property, plant and equipment (note 4) 226,409,548 75,497,707
----------------------------------------------------------------------------
277,360,199 122,751,145
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Liabilities
Current
Accounts payable 38,992,263 39,732,634
Future income taxes (note 8) 8,849,624 2,135,000
Asset retirement obligations (note 2) 2,930,307 695,150
Shareholders' equity
Share capital (note 7) 227,078,091 80,478,642
Contributed surplus (note 7) 6,284,482 2,957,214
Deficit (6,774,568) (3,247,495)
----------------------------------------------------------------------------
226,588,005 80,188,361
----------------------------------------------------------------------------
277,360,199 122,751,145
----------------------------------------------------------------------------
----------------------------------------------------------------------------

See accompanying notes to the consolidated financial statements.

Commitments (note 12)

STATEMENTS OF OPERATIONS AND DEFICIT
(Unaudited)

----------------------------------------------------------------------------
For the For the
Period Ended Year Ended
December 31, 2006 March 31, 2006
----------------------------------------------------------------------------
($) ($)
Revenue
Oil and gas revenue 14,330,927 11,789,528
Royalties, net of Alberta Royalty Tax Credit 2,709,795 2,275,672
----------------------------------------------------------------------------
11,621,132 9,513,856
Interest income 756,031 435,237
----------------------------------------------------------------------------
12,377,163 9,949,093
----------------------------------------------------------------------------
Expenses
Oil and gas operating 2,555,792 2,505,829
Transportation 746,980 1,087,036
General and administrative (note 11) 2,467,721 1,276,864
Stock-based compensation (note 7) 2,349,163 1,790,890
Depreciation, depletion and accretion 8,170,062 4,671,251
----------------------------------------------------------------------------
16,289,718 11,331,870
----------------------------------------------------------------------------
Loss before taxes (3,912,555) (1,382,777)
----------------------------------------------------------------------------
Income taxes
Less: Future tax reduction (note 8) (467,400) (48,000)
----------------------------------------------------------------------------
Net Loss for the period (3,445,155) (1,334,777)
----------------------------------------------------------------------------
Deficit, beginning of period (3,247,495) (1,912,718)
----------------------------------------------------------------------------
Normal Course Issuer Bid (note 7) (81,918) -
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Deficit, end of period (6,774,568) (3,247,495)
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Net loss per share (note 7)
Basic and diluted (0.07) (0.04)
----------------------------------------------------------------------------
----------------------------------------------------------------------------

See accompanying notes to the consolidated financial statements.


CONSOLIDATED STATEMENTS OF CASH FLOW
(Unaudited)

----------------------------------------------------------------------------
For the For the
Period Ended Year Ended
December 31, 2006 March 31, 2006
----------------------------------------------------------------------------
($) ($)
Operating activities
Net loss for the period (3,445,155) (1,334,777)
Add items not requiring cash
Stock-based compensation 2,349,163 1,790,890
Depreciation, depletion and accretion 8,170,062 4,671,251
Future tax expense (reduction) (467,400) (48,000)
----------------------------------------------------------------------------
6,606,670 5,079,364
Change in non-cash working capital (1,393,570) (43,753)
----------------------------------------------------------------------------
Cash provided by operating activities 5,213,100 5,035,611
----------------------------------------------------------------------------
Financing activities
Issue of capital stock 50,191,999 24,866,250
Share issue costs (2,807,155) (1,531,873)
Repurchase of common shares (492,492) -
----------------------------------------------------------------------------
Cash provided by financing activities 46,892,352 23,334,377
----------------------------------------------------------------------------
Investing activities
Short-term investments 27,984,676 19,999,810
Investment (257,689) (120,000)
Property, plant and equipment (42,685,344) (45,527,645)
Acquisition (note 5) 2,973,121 -
Change in non-cash working capital (16,421,409) 20,446,127
----------------------------------------------------------------------------
Cash provided by (used in) investing
activities (28,406,645) (5,201,708)
----------------------------------------------------------------------------
Increase (decrease) in cash and cash
equivalents 23,698,807 23,168,280
Cash and cash equivalents, beginning of period 3,488,186 8,304,582
----------------------------------------------------------------------------
Cash and cash equivalents, end of period 27,186,993 31,472,862
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Interest paid 41,184 27,890
Taxes paid 27,600 8,736
----------------------------------------------------------------------------
----------------------------------------------------------------------------

Supplemental disclosure of cash flow information (note 10)

See accompanying notes to the financial statements.

NOTES TO FINANCIAL STATEMENTS
(Unaudited)


Period Ended December 31, 2006 and year ended March 31, 2006.

Nature of Business and Basis of Presentation

TUSK Energy Corporation ("TUSK" or the "Company") was incorporated on September 24, 2004 and commenced commercial operations on November 2, 2004 under a Plan of Arrangement entered into by TUSK Energy Inc., TKE Energy Trust, and TUSK ("Plan of Arrangement"). Under the Plan of Arrangement, various assets of TUSK Energy Inc. were transferred to TUSK.

TUSK Energy Corporation acquired Zenas Energy Corp. through a plan of arrangement effective December 31, 2006. The consolidated balance sheet and consolidated statements of cash flow include the accounts of Zenas Energy Corp. as at December 31, 2006.

TUSK is involved in the exploration, development and production of petroleum and natural gas in British Columbia, Alberta and Saskatchewan. The financial statements are stated in Canadian dollars and have been prepared in accordance with Canadian generally accepted accounting principles.

1. Accounting Policies

These financial statements have been prepared by management in accordance with Canadian generally accepted accounting principles and a summary of accounting policies follows.

(a) Principles of Consolidation

TUSK Energy Corporation acquired Zenas Energy Corp. through a plan of arrangement effective December 31, 2006. The consolidated balance sheet and consolidated statements of cash flow include the accounts of Zenas Energy Corp. as at December 31, 2006. All inter-company transactions have been eliminated.

(b) Joint Operations

Substantially all of the exploration, development and production activities are conducted jointly with others and accordingly, the Company only reflects its proportionate interest in such activities.

(c) Measurement Uncertainty

The amounts recorded for depletion and depreciation of petroleum and natural gas property, plant and equipment and the provision for asset retirement obligations are based on estimates. The cost recovery ceiling test is based on estimates of proved reserves, production rates, petroleum and natural gas prices, future costs and other relevant assumptions. By their nature, these estimates are subject to measurement uncertainty and the effect on the financial statements of changes in such estimates in future periods could be significant.

(d) Cash, Cash Equivalents and Short-Term Investments

Cash, cash equivalents and short-term investments consist of cash in the bank, less outstanding cheques and short-term deposits with a maturity of less than three months.

(e) Petroleum and Natural Gas Properties

The Company follows the full cost method of accounting for petroleum and natural gas operations, whereby all costs related to the acquisition, exploration and development of petroleum and natural gas reserves are capitalized. Such costs include lease acquisition costs, geological and geophysical costs, carrying charges of non-producing properties, costs of drilling both productive and non-productive wells, the cost of petroleum and natural gas production equipment and overhead charges related to exploration and development activities.

Petroleum and natural gas assets are evaluated at least annually to determine that the costs are recoverable and do not exceed the fair value of the properties. The costs are assessed to be recoverable if the sum of the undiscounted cash flows expected from the production of proved reserves and the lower of cost and market of unproved properties exceed the carrying value of the petroleum and natural gas assets. If the carrying value of the petroleum and natural gas assets is not assessed to be recoverable, 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 future product prices and costs and are discounted using a risk-free rate.

Proceeds from the disposition of petroleum and natural gas properties are applied against capitalized costs except for dispositions that would change the rate of depletion and depreciation by 20% or more, in which case a gain or loss would be recorded.

(f) Depletion and Depreciation

Capitalized costs, together with estimated future capital costs associated with proven reserves, are depleted and depreciated using the unit-of-production method based on estimated gross proven reserves of petroleum and natural gas as determined by independent engineers. For purposes of this calculation, reserves and production are converted to equivalent units of oil based on a relative energy content of six thousand cubic feet of gas to one barrel of oil. Costs of significant unproved properties, net of impairments, are excluded from the depletion and depreciation calculation.

(g) Asset Retirement Obligations

The Company records a liability for the fair value of legal obligations associated with the retirement of long-lived tangible assets in the period in which they are incurred, normally when the asset is purchased or developed. On recognition of the liability, there is a corresponding increase in the carrying amount of the related asset known as the asset retirement cost, which is depleted on a unit-of-production basis over the life of the reserves. The liability is adjusted each reporting period to reflect the passage of time, with the accretion charged to earnings, and for revisions to the estimated future cash flows. Actual costs incurred upon settlement of the obligations are charged against the liability.

(h) Revenue Recognition

Revenues from the sale of petroleum and natural gas are recorded when title and risks pass to an external party.

(i) Income Taxes

The Company follows the asset and liability method of accounting for income taxes. Temporary differences arising from the differences between the tax basis of an asset or liability and its carrying amount on the balance sheet are used to calculate future income tax assets or liabilities. Future income tax assets or liabilities are calculated using tax rates anticipated to apply in the periods that the temporary differences are expected to reverse.

(j) Stock-Based Compensation Plan

The Company applies the fair value method for valuing stock option grants. Under this method, compensation cost, attributable to share options granted to employees, officers and directors of TUSK is measured at fair value at the grant date and expensed with a corresponding increase to contributed surplus. Upon the exercise of the stock options, consideration paid together with the amount previously recognized in contributed surplus is recorded as an increase to share capital.

The Company has not incorporated an estimated forfeiture rate for stock options, rather, the company accounts for actual forfeiture as they occur.

(k) Per Share Information

Per share information is calculated on the basis of the weighted average number of common shares outstanding during the fiscal year. Diluted per share information reflects the potential dilution that could occur if securities or other contracts to issue common shares were exercised or converted to common shares. Diluted per share information is calculated using the treasury stock method that assumes any proceeds received by the Company upon the exercise of in-the-money stock options plus the unamortized stock compensation cost would be used to buy back common shares at the average market price for the period.

(l) Flow-Through Shares

Flow-through shares are issued at a fixed price and the proceeds are used to fund qualifying exploration and development expenditures within a defined period. The qualifying deductions funded by the flow-through arrangements are renounced to investors in accordance with Canadian tax legislation. To recognize the foregone tax benefits of flow-through shares, share capital is reduced and a future income tax liability is recorded for the estimated future tax cost of the renounced expenditures, when the expenditures are renounced.

2. Asset Retirement Obligations

The Company's asset retirement obligations result from net ownership interests in petroleum and natural gas assets including well sites, gathering systems and processing facilities. The Company estimates the total undiscounted amount of cash flows required to settle its asset retirement obligations is approximately $3,133,502, which will be incurred between 2007 and 2031. A credit-adjusted risk-free rate of 10.8% percent and an inflation rate of 2.0 percent were used to calculate the fair value of the asset retirement obligation.

A reconciliation of the asset retirement obligations is provided below:



----------------------------------------------------------------------------
Period Ended Year Ended
December 31, 2006 March 31, 2006
----------------------------------------------------------------------------
($) ($)
Balance, beginning of period 695,150 389,168
Liabilities acquired in period 1,894,645 -
Liabilities incurred in period 273,029 262,229
Changes in prior period estimate - 11,847
Accretion expense 67,483 31,906
----------------------------------------------------------------------------
Balance, end of year 2,930,307 695,150
----------------------------------------------------------------------------
----------------------------------------------------------------------------


3. Investments

The Company has invested a total of $4,270,643 in 12.3 million common shares of Loon Energy Inc. ("Loon"), an oil and gas company which is listed on the TSX Venture Exchange. The investment is carried at cost. Fair value of the investment at December 31, 2006 was approximately $6.8 million. One director of the Company is a director of Loon and one officer of the Company is a director of Loon. TUSK supplies certain personnel and general, accounting and administrative service for a fee of $6,000.

The Company has invested a total of $257,689 in common shares of Ironhand Drilling, a private drilling company. The investment is carried at cost.

4. Property, Plant and Equipment



----------------------------------------------------------------------------
December 31, 2006
----------------------------------------------------------------------------
Accumulated
Depletion and Net Book
Cost Depreciation Value
----------------------------------------------------------------------------
($) ($) ($)
Oil and gas properties 239,989,080 13,809,394 226,179,686
Furniture and equipment 301,232 71,370 229,862
----------------------------------------------------------------------------
Net book value 240,290,312 13,880,764 226,409,548
----------------------------------------------------------------------------
----------------------------------------------------------------------------


----------------------------------------------------------------------------
March 31, 2006
----------------------------------------------------------------------------
Accumulated
Depletion and Net Book
Cost Depreciation Value
----------------------------------------------------------------------------
($) ($) ($)
Oil and gas properties 81,093,874 5,750,883 75,342,991
Furniture and equipment 182,019 27,303 154,716
----------------------------------------------------------------------------
Net book value 81,275,893 5,778,186 75,497,707
----------------------------------------------------------------------------
----------------------------------------------------------------------------


As at December 31, 2006, the depletion calculation excluded unproved properties of $27.5 million (March 31, 2006 - $18.0 million). Capitalized general and administrative expenses for the period were $1,166,801 (Year ended March 31, 2006 - $984,000).

The Company performed a ceiling test calculation at December 31, 2006 resulting in the undiscounted cash flows from proved reserves and the lower of cost and market of unproved properties exceeding the carrying value of oil and gas assets. The following table summarizes the future benchmark prices the Company used in the ceiling test:



----------------------------------------------------------------------------
Crude Oil Natural Gas
-----------------------------------
Year West Texas Edmonton AECO
----------------------------------------------------------------------------
(US$/bbl) (CDN$/bbl) (CDN$/mmbtu)
2007 63.00 70.09 7.50
2008 61.00 67.52 8.00
2009 60.00 66.68 7.75
2010 58.00 64.41 7.65
2011 57.00 63.27 7.80
2012 58.14 64.57 7.70
Thereafter (2)
----------------------------------------------------------------------------
----------------------------------------------------------------------------

(1) Future prices incorporated a $0.88 US/CDN exchange rate for 2007 and
thereafter.
(2) Percentage change of 2% represents the change in future prices each year
from 2013 to 2022 and then constant to the end of the reserve life.


5. Acquisition of Zenas Energy Corp.

On December 31, 2006, the Company closed a business combination with Zenas Energy Corp. ("Zenas") whereby the Company acquired all of the issued and outstanding shares of Zenas pursuant to a plan of arrangement. Zenas is a junior exploration and production company engaged in the exploration and development of oil and natural gas in Western Canada. The previous shareholders of Zenas received 1.033 shares of TUSK for each outstanding Zenas share. TUSK and Zenas amalgamated on January 1, 2007 and continued as TUSK. The transaction was accounted for using the purchase method. The allocations of the purchase price for the acquisition has not been finalized. The preliminary allocation of the purchase price, based on management's estimates is as follows:



----------------------------------------------------------------------------
Cost of acquisition: ($)
----------------------------------------------------------------------------

TUSK shares issued (note 7) 98,609,514
Transaction costs 1,530,000
----------------------------------------------------------------------------
100,139,514
----------------------------------------------------------------------------
----------------------------------------------------------------------------

----------------------------------------------------------------------------
Allocated at estimated fair values: ($)
----------------------------------------------------------------------------

Cash 4,503,121
Accounts receivable 4,588,288
Prepaid expenses 365,750
Property, plant and equipment 114,554,877
Accounts payable and accrued liabilities (14,303,253)
Future income taxes (7,674,624)
Asset retirement obligations (1,894,645)
----------------------------------------------------------------------------
100,139,514
----------------------------------------------------------------------------
----------------------------------------------------------------------------


6. Bank Debt

The Company has a $20 million demand revolving operating credit facility and a $2 million non-revolving acquisition/development loan with a Canadian chartered bank each of which bear interest at the bank's prime lending rate plus three quarters of one per cent. The credit facility is secured by a $25 million fixed and floating charge debenture on the assets of the Company, a general assignment of book debts and a $10 million cash term deposit. None of the credit facility was drawn at December 31, 2006. As at December 31, 2006, the Company provided a $6.9 million letter of guarantee (See Note 12b).

Subsequent to December 31, 2006, the bank loan was increased to a $45 million demand revolving operating facility, secured by a $100 million fixed and floating charge debenture as well as other security already granted.

7. Share Capital

(a) Authorized

An unlimited number of common shares and preferred shares without nominal or par value.

(b) Issued and Outstanding



----------------------------------------------------------------------------
Shares Amount
----------------------------------------------------------------------------
(#) ($)
Period Ended December 31, 2006
Balance, beginning of period 40,555,371 80,478,642
Issuance for the purchase of Zenas (note 5) 37,204,118 98,609,514
Issued for cash
Exercise of stock options 83,333 187,499
Issuance of common shares 7,310,000 29,971,000
Issuance of common shares - flow through basis 3,890,000 20,033,500
Normal Course Issuer Bid (163,100) (410,574)
Exercise of stock options
Reclassification of contributed surplus - 70,665
Share issue expenses, net of tax
effect of $945,000 - (1,862,155)
----------------------------------------------------------------------------
Balance, end of period 88,879,722 227,078,091
----------------------------------------------------------------------------
----------------------------------------------------------------------------


Year Ended March 31, 2006
Balance, beginning of year 35,030,371 60,543,549
Issued for cash
Exercise of special warrants 5,385,000 24,551,250
Exercise of stock options 140,000 315,000
Less: tax effect of flow-through shares - (4,033,000)
Exercise of stock options
Reclassification of contributed surplus - 118,716
Share issue expenses, net of tax
Effect of $515,000 - (1,016,873)
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Balance, end of year 40,555,371 80,478,642
----------------------------------------------------------------------------
----------------------------------------------------------------------------


(c) Special Warrants

One common share was issued, at no additional cost, to holders of Class A special warrants and Class B flow-through special warrants January 9, 2006.

(d) Stock Options

The Company has a stock option plan whereby the Company may grant options to its service providers for up to 10% of its issued and outstanding common shares from time to time. Under this plan, the exercise price of each option equals the market price of the Company's stock on the date of grant. The maximum term of an option is 5 years.

Stock options vest one third on the first, second and third anniversary from the date of grant. Stock options issued as a result of the merger with Zenas Energy Corp. vest one third immediately and one third on the first and second anniversary from the date of grant.

The following table summarizes information regarding stock options outstanding at December 31, 2006:



----------------------------------------------------------------------------
Weighted Average Remaining
Exercise Price Outstanding Contractual Life Exercisable
----------------------------------------------------------------------------
($) (#) (years) (#)
2.25 1,825,000 3.00 1,825,000
4.95 410,000 3.20 273,333
4.55 120,000 3.25 80,000
4.73 120,000 3.75 80,000
4.35 200,000 3.90 133,333
4.30 540,000 3.90 360,000
3.79 20,000 4.30 13,334
3.20 685,000 4.50 -
4.10 780,000 4.50 -
3.50 150,000 4.70 -
3.20 120,000 4.75 -
3.07 120,000 4.80 -
2.97 3,776,000 5.00 1,258,667
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3.20 8,866,000 4.28 4,023,667
----------------------------------------------------------------------------
----------------------------------------------------------------------------

A summary of the status of the Company's Stock Option plan as of December
31, 2006 and changes during period then ended is presented below:

----------------------------------------------------------------------------
Options Weighted Average
Outstanding Exercise Price
----------------------------------------------------------------------------
Period Ended December 31, 2006 (#) ($)
Outstanding, beginning of period 3,345,000 3.23
Granted 5,676,000 3.18
Cancelled (71,667) 3.71
Exercised (83,333) 2.25
----------------------------------------------------------------------------
Outstanding, end of period 8,866,000 3.20
----------------------------------------------------------------------------
Year Ended March 31, 2006
Outstanding, beginning of period 2,715,000 2.88
Granted 860,000 4.37
Cancelled (90,000) 4.95
Exercised (140,000) 2.25
----------------------------------------------------------------------------
Outstanding, end of period 3,345,000 3.23
----------------------------------------------------------------------------
----------------------------------------------------------------------------


Insiders of TUSK were granted a total of 4,780,000 stock options during the nine months ended December 31, 2006

(e) Per Share Amounts

Per share amounts have been calculated on the weighted average number of shares outstanding. The weighted average shares outstanding for the period ended December 31, 2006 was 48,878,044 (Year ended March 31, 2006 - 36,769,494). TUSK uses the treasury stock method to determine the dilutive effect of options outstanding. Under this method only "in the money" options impact the calculations. Zero shares added in calculating diluted earnings per share as all options outstanding are anti-dilutive.

(f) Stock-Based Compensation

The fair values of all common share options granted are estimated on the date of grant using the Black-Scholes option-pricing model. The weighted average fair market value of options granted during the period ended December 31, 2006 and the assumptions used in their determination are as noted below.



----------------------------------------------------------------------------
Period Ended Year Ended
December 31, 2006 March 31, 2006
----------------------------------------------------------------------------
Weighted average fair market value
per option $1.48 $2.14
Risk-free interest rate (%) 3.11% 2.71%
Volatility (%) 51% 54%
Expected life (years) 5 5
----------------------------------------------------------------------------
----------------------------------------------------------------------------


The Company adopted the fair value based method of accounting for stock-based compensation for its stock option plan. Stock compensation is being recognized in earnings.

(g) Contributed Surplus

The following table reconciles the Company's contributed surplus:



----------------------------------------------------------------------------
For the period ended For the year ended
December 31, 2006 March 31, 2006
----------------------------------------------------------------------------
($) ($)
Balance, beginning of year 2,957,214 1,285,040
Stock-based compensation expense 2,349,163 1,790,890
Stock-based compensation
capitalized 1,048,770 -
Transfer to share capital on
exercise of options (70,665) (118,716)
----------------------------------------------------------------------------
Balance, end of year 6,284,482 2,957,214
----------------------------------------------------------------------------
----------------------------------------------------------------------------


(h) Normal Course Issuer Bid

Under a Normal Course Issuer bid, the Company received approval in July 2006 to purchase up to 4,800,000 of its outstanding common shares until August 1, 2007. A total of 163,100 common shares at a cost of $492,492 were purchased under the plan during the period ended December 31, 2006. There were no purchases subsequent to December 31, 2006.

8. Future Income Taxes

Tax Expense

The combined provision for tax expense in the statement of loss and deficit reflect an effective tax rate that differs from the expected statutory tax rate. Differences were accounted for as follows:



----------------------------------------------------------------------------
For the period ended For the year ended
December 31, 2006 March 31, 2006
----------------------------------------------------------------------------
($) ($)
Loss before taxes (3,912,555) (1,382,777)
Statutory income tax rate 34.12% 35.62%
----------------------------------------------------------------------------
Expected tax reduction (1,335,000) (492,500)
Add (deduct):
Non-deductible stock-based
compensation 771,000 602,100
Non-deductible crown charges 259,000 293,100
Resource allowance (213,000) (295,500)
Tax rate change (184,400) (155,200)
Other 235,000 -
----------------------------------------------------------------------------
Future tax reduction (467,400) (48,000)
----------------------------------------------------------------------------
----------------------------------------------------------------------------

Future Income Taxes

The future income tax liability at December 31, 2006 and March 31, 2006 is
comprised of the tax effect of temporary differences as follows:


----------------------------------------------------------------------------
For the period ended For the year ended
December 31, 2006 March 31, 2006
----------------------------------------------------------------------------
($) ($)
Property, plant and equipment (12,104,135) (3,799,700)
Asset retirement obligations 908,000 233,700
Share issue costs 2,334,371 1,431,000
Charitable donations 12,140 -
----------------------------------------------------------------------------
Future income tax liability (8,849,624) (2,135,000)
----------------------------------------------------------------------------
----------------------------------------------------------------------------


As at December 31, 2006, the Company has tax deductions of approximately $194 million that are available to shelter future taxable income, including $86 million in unclaimed tax pools as a result of the merger with Zenas Energy Corp.

9. Financial Instruments

(a) Credit Risk

The Company's accounts receivable are with customers and joint venture partners in the petroleum and natural gas business and are subject to normal credit risks. To mitigate this risk, the Company sells substantially all of its production to two primary purchasers under normal industry sale and payment terms.

(b) Foreign Currency Exchange Risk

The Company is exposed to foreign currency fluctuations as crude oil prices received are referenced in U.S. dollar denominated prices.

(c) Fair Value of Financial Instruments

The Company's financial instruments recognized in the balance sheet consist of accounts receivable, accounts payable, bank indebtedness and obligations under capital leases. The fair value of these financial instruments approximates their carrying amounts due to their short terms to maturity or the indexed rate of interest on the bank indebtedness.

10. Cash Flow Information

Changes in non-cash working capital were as follows:



----------------------------------------------------------------------------
Period ended Year ended
December 31, 2006 March 31, 2006
----------------------------------------------------------------------------
($) ($)

Accounts receivable (3,651,627) 5,309,344
Prepaid expenses 880,272 (1,055,486)
Accounts payable and accrued
liabilities (15,043,644) 16,148,526
----------------------------------------------------------------------------
Net change (17,814,979) 20,402,374
----------------------------------------------------------------------------

Net change by activity:
Operating (1,393,570) (43,753)
Financing (16,421,409) 20,446,127
----------------------------------------------------------------------------
Net change (17,814,979) 20,402,374
----------------------------------------------------------------------------


11. Technical Services Agreement

Under the technical services agreement, TUSK was charged a technical services fee by TKE Energy Trust, on a cost recovery basis, in respect of management, development, exploitation, operations and marketing activities on the basis of relative production and capital expenditures which ended November 2, 2005. For the year ended March 31, 2006, the technical service fee included in general and administrative costs was $1,018,742.

12. Commitments

(a) Flow-through Commitment

At December 31, 2006, the Corporation has fulfilled its obligation to expend $20,033,500 in flow-through expenditures.

(b) Cutbank Seismic Commitment

Under a series of agreements, TUSK and a third party have agreed to expend a total of $40 million ($20 million net) to earn interests in certain petroleum and natural gas rights. TUSK will earn a 5% working interest in the lands by shooting the seismic and have the opportunity to increase their joint interests to 25% in prospective portions of the properties. The transaction was effective as of April 1, 2006. As at December 31, 2006, the Corporation provided a $6.9 million letter of guarantee, which will be reduced by 50% of defined expenditures.

(c) Drilling Rigs

The Company has made commitments for two drilling rigs as follows:

- 220 day/year for 3 years starting at rig delivery in December 2005, with an obligation of $6,800/day.

- 250 day/year for 4 years starting at rig delivery in February 2007, with an obligation of $9,700/day.

(d) Office Lease Obligations

The Company committed to payments under operating leases for office space as follows:



----------------------------------------------------------------------------
Year Amount
----------------------------------------------------------------------------
($)
2007 352,000
2008 513,000
2009 536,000
2010 544,000
2011 & thereafter 1,133,000


This news release shall not constitute an offer to sell or the solicitation of any offer to buy securities of TUSK Energy Corporation ("TUSK") in any jurisdiction, including the United States. The common shares of TUSK have not been and will not be registered under the United States Securities Act of 1933, as amended (the "U.S. Securities Act") or any state securities laws and have not been and will not be offered or sold in the United States or to any U.S. person except in certain transactions exempt from the registration requirements of the U.S. Securities Act and applicable state securities laws.

Contact Information

  • TUSK Energy Corporation
    Norman W. Holton
    Chairman
    (403) 264-8875
    (403) 263-4247 (FAX)
    or
    TUSK Energy Corporation
    John R. Rooney
    Chief Executive Officer
    (403) 264-8875
    (403) 263-4247 (FAX)
    or
    TUSK Energy Corporation
    1900, 700 - 4th Avenue SW
    Calgary, Alberta T2P 3J4
    Website: www.tusk-energy.com