Tamarack Valley Energy

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2010 ANNUAL REPORT

solid plan key initial assets proven management team effective process for growth

2010 ANNUAL REPORT

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corporate profile Tamarack Valley Energy is a junior oil and gas exploration and production company focused in the Western Canada Sedimentary Basin. The Company applies a rigorous, proven modeling process to carefully manage risk and identify growth opportunities, and controls assets at Lochend, Harmattan/Garrington, Buck Lake and Quaich areas in Alberta and Wilder in northeast British Columbia.

Tamarack Valley trades on the TSX Venture Exchange with the symbol TVE and was just recently named one of the 2011 TSX Venture 50 companies.

The Company was created with the combination of Tango Energy Inc. and two private companies in mid-2010, after which the management team and board of directors were largely reconstituted.

annual general meeting Tamarack Valley Energy invites all shareholders to attend the Company’s annual meeting on Wednesday, June 22, 2011 at 3:00 pm (MDT) in the Viking Room of the Calgary Petroleum Club, 319 Fifth Avenue SW, Calgary, Alberta.

TABLE OF CONTENTS

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2 3 5 5 8 9

Financial & Operating Highlights Message to Shareholders Operations Review Property Review Land Holdings Reserves

11 25 26 27 30 42

Management's Discussion & Analysis Management's Report Independent Auditors' Report Consolidated Financial Statements Notes to Consolidated Financial Statements Corporate Information

2010 ANNUAL REPORT

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financial & operating highlights 2010 FINANCIAL ($000s except per share and shares outstanding) Petroleum and natural gas revenue (before royalties) Funds flow from operations Per share - basic and diluted Cash flow from operating activities Net earnings (loss) Per share - basic and diluted Capital expenditures Working capital (deficiency) Total assets Shares outstanding - weighted average OPERATIONAL Daily sales volumes Oil (bbls/d) NGL's (bbls/d) Gas (mcf/d) Total (boe/d) Realized prices Oil (/bbl) Gas (/mcf) Field operating netbacks Wells drilled Gross Net Net success rate

Year ended December 31, 2009

7,614 3,902 0.04 (167) (6,443) (0.06) 11,030 (1,162) 44,922 99,884,466

4,401 2,041 0.03 951 (3,423) (0.05) 3,946 (1,479) 33,865 65,774,620

27 16 4,243 750 $ $ $

76.59 4.14 14.26 2 1.97 100%

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17 2,687 465 $ $ $

54.36 4.14 12.03 1 0.60 100%

...economic production growth is the ultimate measure of success in the oil and gas business.

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2010 ANNUAL REPORT

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message to shareholders In June 2010, we created Tamarack Valley Energy through the combination of three companies. We refreshed our board of directors and rebuilt our senior management team to execute a clear, determined business plan designed to identify four core focus areas around which to build the Company for the long term. Initially, given the original assets within the Company in June 2010, we focused on effectively transitioning the Company from a pure deep gas strategy to an oil drilling strategy.

By the end of Q4 2010, I believe we had efficiently made this transition and in a relatively short period of time, successfully positioned Tamarack Valley for long term growth and value creation.

We utilize specific resource play screening criteria to identify and evaluate prospective areas for repeatability, scope, large original oil or gas-inplace per section, which usually suggests sizeable reserves, and long life opportunities. Our long term goal involves the identification and development of assets in four different areas. By the end of 2010, we had identified three target plays, initiating land acquisition activities for Cardium potential in both the Lochend and Garrington areas in west central Alberta, and a shallow Viking oil play in Alberta. We announced the addition of another core area in February 2011 at Buck Lake in central Alberta. We acquired a 75 percent working interest in 8.5 gross sections of land (7.5 gross sections of Cardium rights). We are also committed to drilling two wells in this area in 2011.

Obviously economic production growth is the ultimate measure of success in the oil and gas business. The fourth quarter of 2010 was pivotal for Tamarack Valley as we drilled our first well in Lochend, west central Alberta. To date this well is one of the most successful wells in the area and has added material oil production and significant cash flow improvements for us. We now control 7.74 net sections of land in Lochend. Late in the fourth quarter, we initiated drilling our first well in Garrington, and this is now in a testing phase. We have grown our land base in this area to 3.8 net sections. Our 2011 plans for both these areas include a multi-well drilling program initiating in the second quarter of 2011 as well as participation in the development of gas handling facilities servicing both areas. Our goal is to optimize costs and production levels in all areas.

At our shallow Viking oil opportunity in Alberta, our third target play, we are in the process of accumulating land and have a total of 21.4 net sections at this stage. The area is characterized by high original-oil-in-place, demonstrable vertical well production and successful analogs. We are continuing to add land at reasonable prices and also plan to drill our first well in the area in 2011.

We have chosen to delay drilling operations from the first quarter to the second quarter of 2011 because much of our land base remains accessible during the spring break up season when most areas are not accessible due to road bans. Embarking on a spring, multi-well drilling program enables us to access the ideal oil field services at competitive prices, even though this delay has affected production growth in the first three months of 2011.

In order to execute our plans in 2010 and in the short term, we completed a $4.5 million flow through share offering in October 2010, and in March 2011, we raised an additional $23 million. These funds will all be used to execute a multi-well drilling program and continue to build our land positions in our new areas. Tamarack will continue to monetize non-core assets to fund growth, while improving our asset quality and focus. We have been encouraged by the support we have seen from the investment community, however we realize that continued access to funds will be determined by our ability to continue to deliver consistent and meaningful results. Going forward, if we require additional funds, we will consider carefully what balance of new financing, debt and funding from cash flow will best drive growth.

When we first created this Company, our production was almost entirely natural gas, largely weighted to our Quaich asset. This area has continued to perform well for the Company with lower than anticipated production declines and more resource-in-place than originally anticipated. Our new Lochend oil production only impacted Tamarack Valley at the end of 2010 in the fourth quarter.

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2010 ANNUAL REPORT

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message to shareholders

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Overall, we increased production to average 856 boe/d in the fourth quarter, an increase of 18 percent quarter over quarter, and 70 percent year over year. Our production mix in the fourth quarter had improved to an 85 percent natural gas weighting compared with a 98 percent natural gas weighting in the third quarter of 2010. Our Company netbacks more than doubled from the third to the fourth quarter of 2010 to $19.51 per boe from $8.28. On an annual basis, in 2009, the Company netback was $12.03 compared with $14.26 in 2010. Our solid results from Quaich and positive drilling results also generated a 31 percent increase in proved preserves for an average cost of $26.78/boe (F&D), with much of the reserve additions in the form of high netback oil.

We have achieved a great deal at Tamarack Valley in a short period of time. Our challenges in 2011 will be to continue to maintain the momentum we have generated. For a company of this size, we have an aggressive drilling program planned as we prove up our target plays. Meanwhile, we remain focused on gaining critical mass and demonstrating operational success.

I am encouraged by our early results that have been driven by a solid team at Tamarack Valley. I'd like to express my appreciation to our committed, knowledgeable board of directors, to my colleagues who provide the energy, enthusiasm and creativity necessary to drive the Company, and also to our shareholders, old and new, for their faith in our vision for Tamarack Valley. I look forward to updating you as we report our first quarter of 2011.

Brian Schmidt President, CEO & Director April 29, 2011

...we remain focused on gaining critical mass and demonstrating operational success.

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2010 ANNUAL REPORT

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operations review BC

Tamarack Valley's oil and gas properties are all located in the provinces of Alberta and British Columbia. During the fourth quarter of 2010, Tamarack’s average production was 856 boe/d. The following are area summaries of the Company’s core producing properties.

Fort St. John

ALBERTA

WILDER

LOCHEND AREA, ALBERTA ANSELL

Tamarack Valley has interests in 7.75 (7.74 net) sections of land in the Lochend area. Tamarack drilled and performed a 12 stage multi-fracture completion at 16-32-26-3W5M (94 percent) in late 2010. The well began producing on November 23, 2010 and its initial three day rate was 1,006 boe/d and the 30 day rate was 498 boe/d (based on production days). This well performance has exceeded the Company’s production type curve and continues to do so today. To the end of the first quarter of 2011, this well has produced over 20,000 barrels of oil. Tamarack has identified 24 net Cardium horizontal drilling locations on its existing lands.

During 2011, Tamarack expects to drill two wells, off setting the 16-32 well at 8-29-26-3W5M and at 15-32-26-3W5M from the same surface location.

Drilling from multi-well pads reduces costs while minimizing our footprint on the environment. The Company is also working on a plan to conserve the solution gas from this area.

R4

R3W5M

TVE land TVE locations Industry well licenses Cardium vertical wells

T27

15-32 8-29

5

16-32 T26

HANLAN

Edmonton

BUCK LAKE GARRINGTON LOCHEND Calgary

Oil Gas

QUAICH

2010 ANNUAL REPORT

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operations review R3

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R2W5M

HARMATTAN / GARRINGTON AREA, ALBERTA

T32

Tamarack Valley has an interest in 9.25 (3.9 net) sections of land with one recently drilled Cardium multi-frac horizontal well at 16-36-31-3W5M. This well was drilled during December 2010 and was completed in early 2011. The well was placed on pump in February and during the next 11 days it averaged 124 boe/d.

This well continues to perform below expectations.

Industry competitors have drilled several wells in the area above our production type curve off-setting our lands and as a result, we plan to drill one or two Cardium wells in the Harmattan / Garrington area during the remainder of 2011.

16-36 TVE land TVE locations Industry well licenses Cardium vertical wells

T31

The current estimated resource well inventory is 11.5 net horizontal wells in the Cardium. Viking oil potential also exists on Tamarack lands, but the Company will wait for industry to derisk this play before adding locations to our drilling inventory.

R6

R5W5M

BUCK LAKE AREA, ALBERTA On March 11, 2011, Tamarack closed the purchase of a 75 percent working interest in 8.5 (6.4 net) sections of land in the Buck Lake area for $5 million. Included in the acquisition was a commitment to drill two Cardium horizontal wells. The first of these two wells (5-24-46-6W5M) has been drilled and completed and is currently on flow back. The second commitment well will be drilled by November 1, 2011.

Tamarack has identified 20 net horizontal wells on its lands.

T46

5-24

TVE 75% WI Cardium land TVE 75% WI excl. Cardium rights TVE location - drilled Industry well licenses Cardium vertical wells

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2010 ANNUAL REPORT

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operations review QUAICH AREA. ALBERTA Tamarack Valley owns an interest in 31.75 (16.03 net) sections of land in townships nine and ten, range three, west of the fifth meridian. Tamarack Valley has two producing wells that are tied into Tamarack's 60 percent owned pipeline which is connected to a partner's facility. Two of the five completed zones are currently producing. The remaining three zones will be turned on as deliverability is required. At December 31, 2010, reserves were assigned to two of the 31.75 sections in this area. Further seismic and drilling is planned for the development of Quaich natural gas as gas prices improve.

R3

R2W5M

TVE land 2D Seismic Licensed location Existing Cadomin producers

T10

T9

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2010 ANNUAL REPORT

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operations review

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LAND HOLDINGS Tamarack Valley had 86,312 gross (51,225 net) acres of undeveloped land at December 31, 2010. No reserves have been assigned to these lands and the lands are located in Alberta and British Columbia. Tamarack Valley expects that 11,682 gross (6,161 net) acres will expire during 2011.

In March 2011, the Company sold 11,188 gross (5,594 net) acres of land in British Columbia which were due to expire in 2011. Also in March 2011, Tamarack closed the purchase of 5,440 acres (4,080 net acres) in the Buck Lake area of Alberta, which included a commitment to drill two Cardium horizontal wells.

Undeveloped Land Holdings (acres)

Alberta British Columbia

As at December 31, 2010 Gross Net 55,365 35,595 30,947 15,630 86,312 51,225

As at March 31, 2011 Gross Net 69,122 47,994 19,759 13,827 88,881 61,821

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2010 ANNUAL REPORT

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operations review RESERVES Tamarack Valley began 2010 as a gas company with proved reserves consisting of 97 percent natural gas and three percent NGL's and proved plus probable reserves of 95 percent natural gas and five percent NGL's. During 2010, drilling success at Lochend and Garrington changed the reserve weighting of light oil and NGL's to 24 percent of proved and 30 percent of proved plus probable reserves. Light crude oil now represents 51 percent of future net present value discounted at 10 percent on a proved plus probable basis.

InSite Petroleum Consultants Ltd. evaluated Tamarack Valley's reserves as of December 31, 2010. Proved reserves increased by 31 percent to 1,665 mboe from 1,272 mboe at December 31, 2009. Proved plus probable reserves increased by 25 percent to 3,031 mboe from 2,427 mboe at December 31, 2009. The following tables show reserves and estimated future net present values at year end 2010 using InSite's forecast oil and gas prices and costs.

Reserve Summary - Forecast Prices and Costs - InSite December 31, 2010 Prices Effective December 31, 2010 Oil Light and Medium Gross Net Reserves category Proved developed producing Proved developed non-producing Proved undeveloped Total proved Probable Total proved + probable

Natural Gas Assoc. & Solution Non-Assoc.

Gross Net Gross Net

Natural Gas Liquids Gross Net

(mstb)

(mstb)

(mmcf)

(mmcf)

(mmcf)

(mmcf)

(mstb)

(mstb)

101.6 40.4 165.3 307.3 346.7 654.0

92.2 37.4 147.9 277.6 304.6 582.2

0.0 0.0 226.1 226.1 320.6 546.7

0.0 0.0 217.0 217.0 309.1 526.1

5,305.0 2,262.9 0.0 7,567.9 5,174.7 12,742.6

3,809.4 1,717.9 0.0 5,527.3 4,109.5 9,636.8

13.0 24.0 21.3 58.3 103.6 162.0

8.0 15.1 16.2 39.4 72.1 111.5

Total BOE Gross Net (mboe)

(mboe)

998.8 735.2 441.6 338.9 224.2 200.3 1,664.6 1,274.4 1,366.2 1,113.1 3,030.8 2,387.5

Summary of Net Present Values of Future Net Revenue Forecast Prices and Costs - InSite December 31, 2010 Prices Effective December 31, 2010

Reserves category Proved developed producing Proved developed non-producing Proved undeveloped Total proved Probable Total proved + probable

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0%

Before Income Taxes Discounted at (%/year) 5% 10% 15%

20%

0%

After Income Taxes Discounted at (%/year) 5% 10% 15%

(M$)

(M$)

(M$)

(M$)

(M$)

(M$)

(M$)

(M$)

(M$)

(M$)

20,943.6 8,711.7 9,041.3 38,696.5 41,999.5 80,696.0

17,644.4 5,305.1 6,161.5 29,111.0 26,914.5 56,025.4

15,332.0 3,419.6 4,411.1 23,162.6 18,968.3 42,130.9

13,631.4 2,280.1 3,254.0 19,165.5 14,264.8 33,430.3

12,331.8 1,541.4 2,436.6 16,309.7 11,217.8 27,527.6

20,943.6 8,711.7 7,757.5 37,412.7 31,543.0 68,955.7

17,644.4 5,305.1 5,539.9 28,489.4 20,484.8 48,974.2

15,332.0 3,419.6 4,096.0 22,847.6 14,672.7 37,520.2

13,631.4 2,280.1 3,087.9 18,999.4 11,219.9 30,219.2

12,331.8 1,541.4 2,345.9 16,219.1 8,964.4 25,183.5

20%

2010 ANNUAL REPORT

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operations review

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RESERVES RECONCILIATION The following table sets forth a reconciliation of Tamarack Valley's total proved, probable and total proved plus probable reserves as at December 31, 2010 against such reserves as at December 31, 2009 based on forecast price and cost assumptions.

Reserves Reconciliation - Forecast Price Case Reconciliation of Company WI Reserves by Principal Product Type WI Share Light & Medium Oil

Opening balance Production Technical revisions Discoveries Closing balance

Associated & Non-Associated Gas WI Proved + WI Proved WI Probable Probable

WI Proved

WI Probable

WI Proved + Probable

(mstb)

(mstb)

(mstb)

(mmcf)

(mmcf)

(mmcf)

0.0 -10.1 0.0 317.0 306.8

0.0 0.0 0.0 346.3 346.3

0.0 -10.1 0.0 663.3 653.2

7,397.3 -1,535.3 1,705.9 0.0 7,567.9

6,488.3 0.0 -1,313.5 0.0 5,174.7

13,885.5 -1,535.3 392.4 0.0 12,742.6

During 2010 Tamarack spent $10.775 million on its capital program which added 663.9 mboe of proved and 875.4 mboe of proved plus probable reserves, including revisions. Future development capital of $7.0 million for proved reserves and $13.8 million for proved plus probable was included in the reserve report. Approximately 22 percent of the capital expenditures spent in 2010 were related to land acquisitions.

Including the two private company acquisitions that closed on June 17, 2010 ($4.03 million assigned value) finding, development and acquisitions costs were $32.82/boe proved and $32.68/boe proved plus probable. There were no reserve additions associated with the acquisition of the two private companies.

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management’s discussion & analysis of financial results The following Management's Discussion and Analysis (“MD&A”) is a review of the operational and financial results and outlook for Tamarack Valley Energy Ltd. (formerly Tango Energy Inc.) (“Tamarack” or the “Company”) for the three months and years ended December 31, 2010 and 2009. This MD&A is dated and based on information available at March 23, 2011 and should be read in conjunction with the audited consolidated financial statements and notes for the years ended December 31, 2010 and 2009.

The financial data contained in this document has been prepared in accordance with Canadian generally accepted accounting principles (“GAAP”), and unless otherwise indicated all references to dollar amounts are in Canadian currency.

For the purpose of calculating unit costs, natural gas volumes have been converted to a barrel of oil equivalent (“boe”) using six thousand cubic feet equal to one barrel unless otherwise stated. A boe conversion ratio of 6:1 is based upon an energy equivalency conversion method primarily applicable at the burner tip and does not represent a value equivalency at the wellhead. This conversion conforms with Canadian Securities Regulators National Instrument 51-101 Standards of Disclosure for Oil and Gas Activities (“NI 51-101”). Boe's may be misleading, particularly if used in isolation.

NON-GAAP MEASUREMENTS The term “operating netback per barrel” and its components are calculated by dividing revenue, royalties and production expenses by the gross sales volume during the period. Operating netback per barrel is a non-GAAP measure and it is commonly used by oil and gas companies to illustrate the unit contribution of each barrel produced.

The terms “funds used in operations” and “funds from operations” used in this discussion are not recognized measures under GAAP. Management believes that in addition to net earnings, funds used in operations and funds from operations are useful supplemental measures as they provide an indication of the results generated by the Company's principal business activities before the consideration of how those activities are financed or how the results are taxed. Readers are cautioned, however, that these measures should not be construed as alternatives to cash flow or net earnings determined in accordance with GAAP as an indication of Tamarack's performance.

RECONCILIATION OF CASH FLOW (PER GAAP) TO FUNDS FROM (USED IN) OPERATIONS Tamarack's method of calculating funds from (used in) operations may differ from other companies, and accordingly it may not be comparable to measures used by other companies. Tamarack calculates funds from (used in) operations as cash flow from (used in) operating activities as determined under GAAP, before the change in non-cash working capital related to operating activities and abandonment expenditures incurred, as the Company believes the uncertainty surrounding the timing of collection, payment or incurrence of these items makes them less useful in evaluating Tamarack's operating performance.

A summary of this reconciliation is presented as follows:

Cash provided by (used in) operating activities Changes in non-cash working capital Abandonment expenditures Funds from (used in) operations

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Three months ended December 31, 2010 2009 (72,338) (58,413) 1,027,061 460,766 4,627 954,723 406,980

Years ended December 31, 2010 2009 (389,270) 179,950 221,963 730,980 39,745 (167,307) 950,675

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2010 ANNUAL REPORT

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management’s discussion & analysis of financial results

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FORWARD LOOKING STATEMENTS This disclosure contains certain forward looking statements, regarding operating cost rates, cash taxes, financial liquidity, employment of parttime consultants and anticipated results on financial reporting as a result of IFRS transition that involve substantial known and unknown risks and uncertainties, certain of which are beyond Tamarack's control. These include, but are not limited to: the impact of global general economic conditions and in particular economic conditions in Canada and the United States; industry conditions; changes in laws and regulations including the adoption of new environmental laws and regulations and changes in how they are interpreted and enforced; changes to the Alberta royalty regime which may significantly impact royalty expenses; competition; the lack of availability of qualified personnel or management; the lack of availability of or access to services; fluctuations in foreign exchange, interest rates or commodity prices; the results of exploration and development drilling related activities; imprecision in reserve estimates; market volatility; changes to market valuations; and obtaining required approvals of regulatory authorities as well as those risks identified in the "Business Risks" section.

Management believes the assumptions used and expectations reflected in such forward looking statements are reasonable, but no assurance can be given that these expectations will prove to be correct. These known and unknown risks and uncertainties may cause actual financial and operating results, performance, levels of activity and achievements to differ materially from those expressed in, or implied by, such forward-looking statements. All forward-looking statements contained in this document are made as of the date hereof and the Company, undertakes no obligation, except as required by applicable securities legislation, to publicly update or revise any forward looking statements. The forward looking statements contained herein are expressly qualified by this cautionary statement.

ACQUISITION OF A PRIVATE COMPANY On June 17, 2010, the Company's shareholders approved the acquisition of a private oil and gas company ("Private Co.") and a corporate name change from Tango Energy Inc. to Tamarack Valley Energy Ltd. In conjunction with the private company purchase, with shareholder approval, the Company's board of directors was substantially reconstituted and a new management team took over the day-to-day operations of the Company.

PRODUCTION

Production Oil and natural gas liquids (bbls/d) Natural gas (mcf/d) Total (boe/d)

Three months ended December 31, 2010 2009 % change

2010

125 4,386 856

43 4,243 750

19 2,911 504

558 51 70

Years ended December 31, 2009 % change 17 2,687 465

153 58 61

Production for the fourth quarter of 2010 increased by 18% to 856 boe/d from 723 boe/d in the third quarter of 2010, and increased by 70% from 504 boe/d in the fourth quarter of 2009. Production for the year ended December 31, 2010 averaged 750 boe/d, representing a 61% improvement over the year ended December 31, 2009 when production averaged 465 boe/d.

Increases in production in 2010 from 2009 were primarily due to a second successful well at Quaich 12-34-09-03 W5M. The well drilled in the fourth quarter of 2009 was brought on-stream in late 2009. Production from the original discovery well was shut-in from early December 2009 to midJanuary 2010, when the Quaich 12-34 well was first brought on-stream to allow for a production test into the sales line. Both Quaich wells have been producing at very consistent rates since mid-January 2010, with limited declines. Production was also increased with the successful drilling of the Company's first Cardium oil well in Lochend. The well was brought on-stream on November 23, 2010, and averaged 379 bopd during its first thirty days of production and contributed 109 boe/d to the fourth quarter production average. Production averaged 817 boe/d in January, 2011, which included the Lochend 16-32 well being shut-in for the last three days of the month while pumping equipment was installed.

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management’s discussion & analysis of financial results

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PETROLEUM AND NATURAL GAS SALES & ROYALTIES Revenue from crude oil, natural gas and associated natural gas liquids sales increased by 66% to $2,462,995 from $1,483,914 in the third quarter of 2010 and by 82% in the fourth quarter of 2010 as compared to the same period in 2009 ($2,462,995 versus $1,355,548). Natural gas prices averaged $3.79/mcf and oil and natural gas liquids prices averaged $81.13/bbl in the fourth quarter of 2010 as compared to $4.68/mcf and $60.44/bbl in the fourth quarter of 2009. The 82% increase to revenue was primarily caused by the 70% increase in production combined with a 34% increase in oil and natural gas liquid prices partially offset by a 19% decrease in natural gas prices.

For the year ended December 31, 2010, revenue from crude oil, natural gas and associated natural gas liquids sales was $7,613,528, 73% higher than for the year ended December 31, 2009, when revenue totalled $4,400,541. Natural gas prices averaged $4.14/mcf and oil and natural gas liquids prices averaged $76.59/bbl during the twelve month period in 2010 compared to $4.14/mcf and $54.36/bbl respectively, for the same period in 2009. The 73% increase to revenue was due to the 61% increase in production combined with a 41% increase in oil and natural gas liquids prices.

Currently the Company does not have any hedges in place.

Three months ended December 31, 2010 2009 % change Revenue Oil and NGLs Natural gas Total Average realized price Oil and NGLs ($/bbl) Natural gas ($/mcf) Combined average ($/boe) Benchmark pricing Edmonton par (Cdn$/bbl) AECO monthly index (Cdn$/mcf) Royalty expenses $/boe Percent of sales

2010

Years ended December 31, 2009 % change

$932,084 1,530,911 $2,462,995

$103,357 1,252,191 $1,355,548

802 22 82

$1,199,678 6,413,850 $7,613,528

$341,515 4,059,026 $4,400,541

251 58 73

81.13 3.79 31.28

60.44 4.68 29.25

34 (19) 7

76.59 4.14 27.81

54.36 4.14 25.92

41 7

80.33 3.58 $242,156 3.08 10

76.56 4.23 $228,217 4.92 17

5 (15) 6 (38) (41)

77.50 4.13 $1,180,773 4.31 16

65.87 4.13 $504,942 2.98 11

18 134 45 45

The Company's realized natural gas prices for the years ended 2010 compared to the period ended 2009 correlate to the AECO monthly index pricing during those same periods. When comparing the three months ended December 31, 2010 to the same period in 2009, the Company's realized natural gas prices do not correlate exactly with AECO monthly index pricing. The reason is that the natural gas produced in the Hanlan area can produce to two different third party gas plants with varying transportation rates and heating content yields. The price correlation to benchmark pricing varies depending on the sales volumes that swing between these two third party facilities.

The Company's realized crude oil and natural gas liquids prices for the three months ended and the year ended December 31, 2010 compared to the similar periods in 2009 do not correlate to the Edmonton Par Canadian price posting for the same periods. This is due to the fact that the Company only began producing crude oil during the fourth quarter of 2010. Prior to that, all of the Company's liquids production was from natural gas liquids and condensate which get priced at varying discounts to Edmonton Par pricing depending on market conditions, pipeline capacity and the season.

Royalty expenses for the three months and year ended December 31, 2010 were $242,156 or $3.08/boe, representing 10% of revenue and $1,180,773 or $4.31/boe, representing 16% of revenue, respectively. Similar comparisons to the three months and year ended December 31, 2009 were a royalty expense of $228,217 or $4.92/boe, representing 17% of revenue and $504,942 or $2.98/boe or 11% of revenue, respectively.

The Company received approximately $340,000 in Gas Cost Allowance (GCA) credits during the second quarter of 2009 and approximately $120,000 in GCA credits during the third quarter of 2009. Prior to taking into account the 2009 GCA credits, the year ended 2009 normalized royalty rate would have been approximately 22% or $5.69/boe.

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2010 ANNUAL REPORT

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management’s discussion & analysis of financial results

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Both the Lochend Cardium 16-32-026-03W 5M well and the Quaich 12-34-09-03 W5M well are eligible for the 5% incentive royalty rate from the Alberta Crown. This incentive royalty rate is subject to a volume related cap which was reached for the Quaich well late in the third quarter of 2010.

The 2010 royalty rate of 16% is lower than the normalized 2009 rate of 22% due to the 5% incentive royalty that the Quaich 12-34 well received during 2010. The royalty rate decreased to 10% of revenue or $3.08/boe in the fourth quarter of 2010 from 17% of revenue or $4.92/boe for the same period in 2009 due to the Lochend well coming on-stream in the fourth quarter of 2010 at the 5% incentive rate.

PRODUCTION EXPENSES Production expenses for the three months ended December 31, 2010 increased by 50% to $684,535 from $454,997 in the same period in 2009.

Production costs on a boe basis were $8.69 in the fourth quarter of 2010 compared to $9.82 in the fourth quarter of 2009. The increase in total production expenses was caused by the 70% increase in production. Production costs per boe decreased during the fourth quarter of 2010 compared to the same period in 2009 with the lower cost production increase in Quaich and the new well in Lochend. The production costs per boe for Lochend 16-32 well was $5.04/boe during the fourth quarter. This well impacted the fourth quarter corporate average by reducing production costs per boe by $0.54. Due to the production profile of Cardium oil wells (high initial rates with high declines during the first six months of production), the Company's operating costs rate will fluctuate quarter over quarter depending on the timing of future Cardium production additions.

The Company expects its operating cost rate will increase during the first quarter of 2011.

Production expenses increased by 36% to $2,530,684, or $9.24 on a boe basis, for the year ended December 31, 2010, which compare with $1,854,390, or $10.92 per boe, in the same period of 2009. Total production expenses increased during the 2010 period as a consequence of the 61% increase to production partially offset through reduced production costs per boe which declined by 15% because of the increase in production in Quaich and the new Cardium well in Lochend.

OPERATING NETBACK

Average realized sales Royalty expenses Production expenses Operating netback

Three months ended December 31, 2010 2009 % change 31.28 29.25 7 (3.08) (4.92) (38) (8.69) (9.82) (11) 19.51 14.51 34

2010 27.81 (4.31) (9.24) 14.26

Years ended December 31, 2009 % change 25.92 7 (2.97) 45 (10.92) (15) 12.03 19

GENERAL AND ADMINISTRATIVE EXPENSES General and administrative expenses for the three months and year ended December 31, 2010 were $587,627 and $4,034,504, which is substantially higher than $247,977 and $1,062,101 for the same periods in 2009. The vast majority of this increase in general and administrative expenses was related to $2,248,356 of transaction costs associated with the recapitalization of the Company and reorganization of management that closed on June 17, 2010. In addition approximately $61,000 costs were incurred in 2010 associated with combining the Company's offices with the Private Co.'s offices into one and the resulting termination of the duplicate office lease. Excluding the transaction costs associated with the recapitalization and reorganization and the costs associated with combining the two offices, normalized general and administrative expenses would have been $1,725,148 for the year ended December 31, 2010. This would represent an increase of 62% during the year ended December 31, 2010, as compared to the same period in 2009. This increase is as a result of the Company currently employing four more professionals than it did in 2009 and increased expenses related to additional space requirements.

General and administrative expenses on a boe basis excluding costs associated with the recapitalization of the Company and reorganization of management were $7.46 and $6.30 in the fourth quarter of 2010 and the year ended 2010, respectively, compared to $5.35 and $6.26 for the same periods in 2009.

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Subsequent to the closing of the private company acquisition in June, 2010, the officers and directors were principally reconstituted resulting in eight full-time employees. The Company also moved offices to a sub-leased space in August 2010 and added another full-time employee in late November 2010. The Company plans to periodically employ the use of part-time consultants on an as-required basis which will impact future general and administrative expenses.

Tamarack capitalized $100,500 and $203,900 of general and administrative costs relating to exploration and development activities for the three months and year ended December 31, 2010 compared to $121,400 and $386,400 for the three months and year ended December 31, 2009.

STOCK-BASED COMPENSATION EXPENSES Stock-based compensation expenses of $596,794 and $1,682,176 relating to the preferred shares and stock options for the three months and year ended December 31, 2010 increased compared to $62,661 and $255,227 relating to the stock options which were outstanding for the same periods in 2009. The expense increased period over period due to the preferred shares and stock options issued in the second quarter of 2010.

The Company capitalized $223,506 and $237,306 (net of tax of $75,668 and $81,268 respectively) of stock-based compensation expenses relating to exploration and development activities for the three months and year ended December 31, 2010 compared to $18,454 and $75,123 (net of tax of $7,546 and $30,477 respectively) for the three months and year ended December 31, 2009.

The fair value of each stock option grant and the preferred shares issued were estimated on the date of grant using the Black-Scholes option-pricing model with the following assumptions used for grants in the year ended December 31, 2010: average expected volatility of 80 percent, average risk-free interest rate of 2.5 percent, zero dividend yield, and expected life of five years.

The average fair value of stock options and preferred shares granted during the year ended December 31, 2010 was $0.25 per option and $0.23 per preferred share. The Company has not re-priced any stock options. Tamarack has not incorporated an estimated forfeiture rate for stock options or preferred shares that will not vest, rather the Company accounts for actual forfeitures as they occur.

The Company issued 500,000 stock options during the fourth quarter of 2010 and 350,000 stock options during the second quarter of 2010.

INTEREST Interest earned was $6,047 in the fourth quarter of 2010 compared to interest expense of $17,376 for the same period in 2009 and interest expense $34,874 for the year ended December 31, 2010 compared to $28,433 for the same period in 2009. Interest expense was higher in 2010 as a result of increased borrowings on the Company's credit facility during the first half of 2010 and due to the accrued taxes payable relating to Part 12.6 tax calculated on the portion of renounced qualified oil and natural gas expenditures that were not incurred. The Company was undrawn on its revolving operating demand line at December 31, 2010, compared to being $1,475,000 drawn on its line at December 31, 2009.

DEPLETION, DEPRECIATION AND ACCRETION

Depletion and depreciation Accretion Total Depletion and depreciation ($/boe) Accretion ($/boe) Total ($/boe)

15

Three months ended December 31, 2010 2009 % change $1,870,160 $1,195,401 56 14,146 13,400 6 $1,884,306 $1,208,801 56 $23.75 0.18 $23.93

$25.80 0.29 $26.09

(8) (38) (8)

2010 $6,981,659 55,546 $7,037,205 $25.50 0.20 $25.70

Years ended December 31, 2009 % change $5,411,426 29 55,300 $5,466,726 29 $31.88 0.33 $32.21

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Depletion, depreciation and accretion expense was $1,884,306 in the fourth quarter of 2010, 56% higher than $1,208,801 for the fourth quarter of 2009. For the year ended December 31, 2010, depletion, depreciation and accretion expense increased by 29% to $7,037,205 from $5,466,726 for the same period in 2009. Depletion expense was calculated using an estimate of proved reserves as evaluated by a third party engineering firm as of December 31, 2010. Costs associated with unproved properties, including undeveloped land, seismic and salvage value of $7,602,630 were excluded from costs subject to the depletion calculation for the fourth quarter of 2010 compared to $1,323,250 for the fourth quarter of 2009. Future development costs of $8,804,500 have been included in the depletion calculation for the fourth quarter of 2010 compared to $1,451,000 for the fourth quarter of 2009. Depletion, depreciation and accretion expense increased during the fourth quarter of 2010 compared to 2009 and during the 2010 year compared to 2009 due to the increase in production.

On a unit-of-production basis, the depletion, depreciation and accretion expense decreased in 2010 from 2009 due to the reserve additions resulting from the successful Quaich 12-34 well that was drilled in the fourth quarter of 2009 and the new Lochend and Garrington wells drilled in the fourth quarter of 2010.

Accretion expense for the three months and year ended December 31, 2010 was $14,146 and $55,546, respectively, compared to $13,400 and $55,300 for the same periods in 2009.

INCOME TAXES The Company did not incur any cash tax expense in 2010, nor does it expect to pay any cash taxes in 2011 based on current commodity prices, forecast taxable income, existing tax pools and planned capital expenditures.

For the three months and year ended December 31, 2010, future income tax reductions of $873,286 and $2,443,286 were recorded, respectively, due to the loss before taxes generated in each period. The Company also recognized a benefit of $2,150,000 associated with tax pools that came with the acquisition of Private Co. The Company has accumulated the following tax pools for the years ended December 31, 2010 and 2009.

(000s)

Canadian exploration expense Canadian development expense Canadian oil and gas property expense Undepreciated capital cost Non-capital losses Share and debt issue costs Other Total

December 31, 2010 $ 9,867,578 3,600,884 4,618,434 3,972,277 15,909,398 461,213 337,191 $ 38,766,975

December 31, 2009 $ 6,579,800 891,734 143,019 4,139,109 1,503,666 255,772 337,191 $ 13,850,291

On October 21, 2010, the Corporation issued 11,067,194 flow-through common shares related to Canadian exploration expenditures ("CEE") for gross proceeds of $3,500,000. Under the terms of the flow-through share agreements, the Corporation is required to renounce the $3,500,000 of qualifying Canadian exploration expense in 2011.

On October 21, 2010, the Corporation issued 3,382,664 flow-through common shares related to Canadian development expenditures ("CDE") for gross proceeds of $1,000,000. Under the terms of the flow-through share agreements, the Corporation is required to renounce the $1,000,000 of qualifying Canadian development expense in 2011.

NET LOSS AND FUNDS FROM (USED IN) OPERATIONS The net loss during the three months and year ended December 31, 2010 was $653,093 ($0.00 per share basic and diluted) and $6,443,402 ($0.06 per share basic and diluted), respectively, compared to a net loss of $584,081 ($0.01 per share basic and diluted) and $3,423,178 ($0.05 per share basic and diluted) for the same periods in 2009.

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management’s discussion & analysis of financial results The net loss for both the fourth quarter and the 2010 year was higher than the same periods in 2009 due to the costs associated with the recapitalization of the Company and reorganization of management and due to increases in production expenses, stock-based compensation expenses and depletion, depreciation and accretion expense, offset by increased revenues.

Funds from operations during the three months and year ended December 31, 2010 were $954,723 and a use of funds of $167,307, respectively, compared to funds from operations of $406,980 and $950,675 for the same periods in 2009. The decrease in funds from operations was mainly the result of the approximate $2.3 million of costs associated with the recapitalization of the Company and reorganization of management.

CAPITAL EXPENDITURES The following table summarizes capital spending, excluding non-cash items:

Land Geological and geophysical Drilling and completion Equipment and facilities Acquisitions (dispositions) Capitalized G&A Office equipment Total capital expenditures

Three months ended December 31, 2010 2009 % change $7,667 $0 0 58,825 1,934 2,942 6,990,230 736,399 849 529,618 189,704 179 100,500 121,000 (17) 22,993 $7,709,833 $1,049,037 635

2010 $2,334,281 95,955 7,709,462 635,498 203,900 51,066 $11,030,162

Years ended December 31, 2009 % change $52,610 4,337 69,355 38 2,658,661 190 758,734 (16) 386,000 (47) 20,415 150 $3,945,775 180

The Company's fourth quarter 2010 capital expenditures were $7,709,833 compared to $1,049,037 incurred during the fourth quarter of 2009.

Capital expenditures for the year ended December 31, 2010 were $11,030,162 compared to $3,945,375 for the same period in 2009.

Since the Company's reorganization in June, 2010, the Company increased its total undeveloped land by 6,240 gross (5,400 net) acres. Included in the additions was the entry land acquisition of the Company's third core oil resource play, an Alberta Viking oil play, which it is currently evaluating its de-risk strategy. The Company increased its undeveloped Cardium prospective land in Garrington/Harmattan area by 2,240 gross (838 net) acres.

In late 2010, Tamarack drilled its first Lochend Cardium oil well located at 16-32-026-03 W5, in which the Company owns a 94% working interest.

The well began producing on November 23, 2010. The Company also spudded its first Cardium oil well in the Garrington/Harmattan area on November 29, 2010 at 16-36-031-03 W5. The Company pays 100% of the drill, completion and equipping costs to earn a 70% working interest in this exploratory well. This exploration well was rig released on December 18, 2010 and during December 2010, the Company incurred approximately two-thirds of the costs to complete this well.

LIQUIDITY AND CAPITAL RESOURCES Tamarack's working capital deficiency was $1,162,450 at December 31, 2010 which consisted of cash of $3,641,025 offset by a working capital deficiency of $4,803,475. Tamarack's working capital deficiency including current debt at December 31, 2009, was $1,479,485, which consisted of cash of $8,406 offset by a working capital deficiency of $12,891 and current bank debt of $1,475,000.

On October 21, 2010, the Company issued 11,067,194 flow-through common shares related to Canadian exploration expenditures ("CEE flowthrough shares") pursuant to the Income Tax Act (Canada) for gross proceeds of $3,500,000. Under the terms of the CEE flow-through share agreements, the Company is required to renounce the $3,500,000 of qualifying oil and natural gas expenditures effective December 31, 2010 and has until December 31, 2011 to incur the expenditures.

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Also on October 21, 2010, the Company issued 3,382,664 flow-through common shares related to Canadian development expenditures ("CDE flowthrough shares") pursuant to the Income Tax Act (Canada) for gross proceeds of $1,000,000. Under the terms of the CDE flow-through share agreements, the Company is required to renounce the $1,000,000 of qualifying oil and natural gas expenditures effective December 31, 2010 and had until December 31, 2011 to incur the expenditures.

The proceeds from the CEE flow-through were used to drill an identified Garrington Cardium exploratory well in late 2010. This exploratory well will also satisfy the remaining obligation pursuant to the December 31, 2009 flow-through. The proceeds from the CDE flow-through were used to fracture stimulate and complete the Lochend 16-32 well in November of 2010.

On March 10, 2011, the Corporation closed a bought deal short form prospectus financing of 46,939,550 common shares at $0.49 per common share for gross proceeds of $23,000,380. Due to certain dealer requirements in the United States, the Corporation also closed a separate and concurrent non-brokered private placement for 100,000 common shares at a price of $0.49 per common share for gross proceeds of $49,000.

Certain officers and directors purchased 350,000 common shares for gross proceeds of $171,500 in conjunction with the offerings.

At December 31, 2010, there were 137,849,246 common shares, 23,356,997 preferred shares and 850,000 options outstanding.

At March 23, 2011, there were 184,888,796 common shares, 23,356,997 preferred shares and 850,000 options outstanding.

The Company has a $4,000,000 revolving operating demand line of credit available and a $1,000,000 non-revolving acquisition/development demand line of credit with a Canadian chartered bank as at December 31, 2010. The interest rate on the revolving operating demand line of credit is at the bank's prime rate plus 1.25% and at the bank's prime rate plus 1.75% on the non-revolving acquisition/development demand line of credit.

These facilities are secured by a $40.0 million debenture with a floating charge over all assets. The next scheduled review of these lines of credit is May 31, 2011. As the available lending limits of the facilities are based on the bank's interpretation of the Company's reserves and future commodity prices, there can be no assurance as to the amount of available facilities that will be determined at each scheduled review. Pursuant to the terms of the credit facilities, the Company has provided the covenant that at all times its working capital ratio shall be not less than 1 to 1.

The working capital ratio is defined under the terms of the credit facilities as current assets, including the undrawn portion of the revolving credit facility, to current liabilities, excluding any current bank indebtedness.

At December 31, 2010, the Company had not utilized the revolving operating demand line or the non-revolving acquisition/development line of credit. The Company is in compliance with its covenant as at December 31, 2010.

On June 17, 2010, the Company acquired all of the issued and outstanding shares of Private Co. The Private Co. was in the pre-production stage and had not commenced active operations. As consideration the Company issued 55,114,768 common shares. The results of Private Co. have been included in the accounts of the Company commencing June 17, 2010. The transaction was accounted for using the purchase method of accounting. The fair values assigned to the net assets and liabilities and consideration paid are as follows: Net assets acquired at fair value: Cash and cash equivalents Property and equipment Working capital deficiency Future income tax asset Asset retirement obligations Consideration: Share capital (55,114,768 common shares)

$ 7,045,250 1,877,750 (18,000) 2,150,000 (55,000) $11,000,000 $11,000,000

Although commodity price volatility continues in the oil and gas industry, Tamarack's strategy remains focused on the acquisition, development and production of petroleum and natural gas properties in western Canada. Tamarack is well financed and positioned to take advantage of opportunities created by commodity price volatility and does not anticipate any issues in meeting the Company's obligations with the available debt facilities and cash on hand.

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management’s discussion & analysis of financial results CONTRACTUAL OBLIGATIONS In the normal course of business the Company has obligations which represent contracts and other commitments with an estimated payment of $281,796 for 2011; $281,796 for 2012; and $117,415 for 2013. These obligations are related to office lease commitments.

On October 21, 2010, the Corporation issued 11,067,194 flow-through common shares related to Canadian exploration expenditures ("CEE") for gross proceeds of $3,500,000. Under the terms of the flow-through share agreements, the Corporation is required to renounce the $3,500,000 of qualifying oil and natural gas expenditures effective December 31, 2010 and had until December 31, 2010 to incur the expenditures. The Corporation has incurred $2,713,788 of qualifying expenditures, with the balance of $786,212 to be incurred on or prior to December 31, 2011.

On October 21, 2010, the Corporation issued 3,382,664 flow-through common shares related to Canadian development expenditures ("CDE") for gross proceeds of $1,000,000. Under the terms of the flow-through share agreements, the Corporation is required to renounce the $1,000,000 of qualifying oil and natural gas expenditures effective December 31, 2010 and had until December 31, 2010 to incur the expenditures. The Corporation has incurred the full amount of qualifying expenses as of December 31, 2010.

SELECTED QUARTERLY INFORMATION Three months ended Sales volumes Natural gas (mcf/d) Oil and NGLs (bbls/d) Average boe/d (6:1) Product prices Natural gas ($/mcf) Oil and NGL's ($/bbl) Oil equivalent ($/boe)

Dec. 31, 2010

Sep. 30, 2010

Jun. 30, 2010

Mar. 31, 2010

Dec. 31, 2009

Sep. 30, 2009

Jun. 30, 2009

Mar. 31, 2009

4,386 125 856

4,254 14 723

4,333 15 737

3,997 17 683

2,911 19 504

2,482 19 433

2,681 17 464

2,673 14 459

3.79 81.13 31.28

3.61 55.22 22.31

4.16 66.68 25.83

5.08 68.99 31.46

4.68 60.44 29.26

3.21 51.62 20.73

3.43 59.99 22.03

5.13 42.99 31.18

2,464 (652) (0.00) (0.00)

1,484 (1,992) (0.02) (0.02)

1,732 (3,100) (0.03) (0.03)

1,934 (699) (0.01) (0.01)

1,355 (584) (0.01) (0.01)

828 (1,014) (0.01) (0.01)

930 (983) (0.01) (0.01)

1,288 (1,126) (0.02) (0.02)

7,710 44,922 (1,162) 781 -

2,736 36,150 1,513 758 916

58 39,193 4,347 744 1,386

526 32,630 (1,305) 654 4,407

1,049 33,865 (1,479) 669 4,631

1,399 34,196 (832) 695 4,904

($000s, except per share amounts)

Financial results Gross revenues Net loss Per share - basic Per share - diluted Additions to property and equipment, net of proceeds Total assets Working capital (deficiency) Asset retirement obligations Future income taxes

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353 33,641 407 727 5,184

1,144 35,662 572 700 5,523

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SELECTED ANNUAL INFORMATION Year Ended Dec. 31, 2010

Year Ended Dec. 31, 2009

Year Ended Dec. 31, 2008

7,614 (6,443) (0.06) (0.06) 44,922 7,994

4,401 (3,423) (0.05) (0.05) 33,865 8,019

8,528 (1,603) (0.02) (0.02) 38,557 9,619

($000s, except per share amounts)

Financial results Gross revenues Net loss Per share - basic Per share - diluted Total assets (end of period) Total liabilities (end of period) CRITICAL ACCOUNTING ESTIMATES

The significant accounting policies used by Tamarack are disclosed in the notes to Tamarack's audited financial statements. 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. The following discusses such accounting policies and is included in Management's Discussion and Analysis to aid the reader in assessing the critical accounting policies and practices of the Company, and the likelihood of materially different results being reported. Tamarack's management reviews its estimates regularly. The emergence of new information and changed circumstances may result in actual results, or changes to estimated amounts, that differ materially from current estimates.

The following assessment of significant accounting policies is not meant to be exhaustive. The Company might realize different results from the application of new accounting standards promulgated, from time to time, by various rule-making bodies.

Impairment of Property and Equipment The Company is required to regularly review the carrying value of all property and equipment for potential impairment. Impairment is indicated if the carrying amount of property and equipment is not recoverable by the future undiscounted cash flows from proved reserves. If impairment is indicated, the amount of impairment is determined by the amount the carrying amount exceeds the estimated fair value of the property and equipment and it is charged against earnings. The assessment of impairment is dependent on estimates of reserves, production rates, commodity prices, forecast costs and risk free interest rates.

Depletion Expense The Company uses the full cost method of accounting for exploration and development activities. In accordance with this method of accounting all costs associated with exploration and development are capitalized whether or not the activities funded were successful. The aggregate of net capitalized costs and estimated future development costs, less estimated salvage values, is amortized using the unit-of-production method based on estimated proved oil and gas reserves.

An increase or decrease in estimated proved oil and gas reserves would result in a corresponding reduction or increase in depletion expense. An increase or decrease in estimated future development costs would result in a corresponding increase or decrease in depletion expense.

Withheld Costs Certain costs related to unproved properties may be excluded from costs subject to depletion until proved reserves have been determined or their value is impaired. These properties are reviewed quarterly and any impairment is transferred to the costs being depleted.

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management’s discussion & analysis of financial results Asset Retirement Obligations Asset retirement obligations are estimated based on existing laws, contracts or other policies. The fair value of the asset retirement requires an estimate of future costs to abandon and reclaim wells, pipelines and facilities discounted to its present value using the Company's credit adjusted risk-free interest rate. The liability is adjusted each reporting period to reflect the passage of time and the accretion is charged to earnings.

Revisions to the estimated timing of cash flows or to the original undiscounted cost could also result in an increase or decrease to the obligation.

Legal, Environmental Remediation and Other Contingent Matters The Company is required to determine whether a loss is probable based on judgment and interpretation of laws and regulations and whether the loss can reasonably be estimated. When a loss is determined it is charged to earnings. The Company's management must continually monitor known and potential contingent matters and make appropriate provisions by charges to earnings when warranted by circumstance.

Future Taxes The Company uses the asset and liability method of tax calculation. Differences between the tax basis of an asset or liability and its carrying amount in the balance sheet are used to calculate future income tax liabilities or assets. Future income tax assets or liabilities are calculated using the substantively enacted tax rates anticipated to apply in the period that the temporary differences are expected to reverse. The Company applies the “more likely than not” criteria to determine the valuation allowance recorded against any future tax assets. That is, the Company determines whether it is more likely than not that the asset will or will not be realized. Any change in assessment of these criteria could significantly impact future earnings.

Stock-based Compensation The Company uses the fair value method for valuing stock option and preferred shares grants. Under this method, compensation cost attributable to all share options and preferred shares granted is measured at fair value at the grant date and expensed over the vesting period. The Black-Scholes option pricing model is used to estimate the fair value of the stock options and preferred shares and it contains such estimates as expected share price volatility and the Company's risk-free interest rate. Any changes in these assumptions could alter the fair value and net earnings.

CHANGE IN ACCOUNTING POLICIES Future Accounting Changes In February 2008, the Canadian Accounting Standards Board confirmed January 1, 2011 as the effective date for the requirement to report under International Financial Reporting Standards (“IFRS”) with comparative 2010 periods converted as well. Canadian generally accepted accounting principles as we currently know them, will cease to exist for all public reporting entities.

The Company has prepared an outline of an IFRS changeover plan. The Company has assessed accounting elections available upon changeover under IFRS 1 and has considered accounting policies for IFRS reporting. The first financial reports under IFRS will commence in the first quarter of 2011 with comparison to the first quarter of 2010. The December 31, 2009 balance sheet will be converted to IFRS reporting standards and become the opening balance sheet for IFRS reporting.

Changes in accounting policies will occur and may materially impact the Company's financial statements. The most significant impacted area is expected to be property, plant and equipment.

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The major differences between Canadian GAAP and IFRS applicable to the Company are as follows: (i) Exploration and evaluation of mineral resources (“E&E”) - IFRS 6: IFRS 6 is the only specific standard that applies to extractive industries. This standard refers to a very clear and definitive segregation of capital expenditures into three main categories - pre-exploration, Exploration and Evaluation (“E&E”), and post-exploration or development and production expenditures. Under IFRS, all pre-acquisition costs are expensed, while under Canadian GAAP, these costs may be capitalized. E&E costs under IFRS may either be expensed or capitalized. The Company expects to capitalize E&E expenditures. Under IFRS, the E&E expenditures must be assessed for impairment when the facts suggest that the carrying amount of an asset exceeds its recoverable amount. Furthermore, when an E&E asset is transferred to post-exploration, an impairment test must be conducted. (ii) Componentization: Under IFRS, the full cost pool under Canadian GAAP must be broken down into economic components and then depleted on a component basis. IFRS allows depletion to be calculated using either proven reserves or using proven and probable reserves. The Company anticipates that it will calculate and record depletion using proven plus probable reserves. The International Accounting Standards Board (“IASB”) has implemented an amendment to IFRS 1 that will permit the Company to apply IFRS prospectively by utilizing its current reserves at the transition date to allocate the Company's full cost pool, with the provision that an impairment test, under IFRS standards, be conducted at the transition date.

The Company anticipates using this exemption to allocate its full cost pool based on reserve values. (iii) Impairment of property and equipment: The full cost pool under Canadian GAAP following the removal of E&E assets, must be broken down into cash generating units (“CGU's”), which are the smallest group of assets capable of generating independent cash inflows. The cash generating units must be tested for impairment when there are indicators of impairment. The impairment test can be based on either “value in use” or “fair value less costs to sell”.

The Company expects to use “fair value less costs to sell” as the basis for the impairment test under IFRS. The CGU's can also be determined by using the exemption discussed above to allocate the full cost pool. Assets are required to be assessed for impairment upon transition to IFRS. Tamarack Valley expects there will be an impairment of development and production assets of approximately $5.6 million, a decrease in the deferred tax liability of $1.4 million and a charge to the opening deficit of $4.2 million on transition to IFRS. (iv) Provisions and contingent assets and liabilities: IAS 37, Provisions, Contingent Liabilities and Contingent Assets requires a provision to be recognized when there is a present obligation as a result of a past transaction or event. It is probable that an outflow of resources will be required to settle the obligation; and a reliable estimate can be made of the obligation. The threshold for recognition of a provision under Canadian GAAP is higher than under IFRS (70% vs. 50%). Therefore, it is possible that some contingent liabilities not recognized under Canadian GAAP may meet the recognition criteria under IFRS. Furthermore, IFRS requires the use of best estimates, mid-points, or probabilistic weighted averages as the measurement method. Under Canadian GAAP, the discount rate used in determining the value of asset retirement obligations is the credit adjusted risk-free rate applicable to the Company. IFRS requires the use of a risk-free rate when the expected cash flows are risked. As a result, Tamarack Valley has measured its asset abandonment liability on transition using a risk free rate of 4% resulting in an increase to the asset abandonment liability of approximately $245,000 and a decrease to deferred tax liability of approximately $62,000 with an offsetting charge to the opening deficit of $183,000. The asset abandonment liability will be re-measured each reporting period using the risk-free rate in the reporting period and the asset abandonment provision under IFRS will accordingly vary from the amount reported under Canadian GAAP in Tamarack Valley's 2010 financial statements. (v) Income taxes: IAS 12, Income Taxes, prescribes that an entity account for the tax consequences of transactions and other events in the same way that it accounts for the transactions and other events themselves. Therefore, where transactions and other events are recognized in earnings, the recognition of deferred tax assets or liabilities which arise from those transactions should also be recorded in earnings. For transactions that are recognized outside of the statement of earnings, either in other comprehensive income or directly in equity, any related tax effects should also be recognized outside the statement of earnings. The Company is still analyzing the implications of this standard.

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management’s discussion & analysis of financial results (vi) Share-based payments: Under IFRS 2, Share-Based Payment, awards will continue to be measured at fair value, with compensation expense under our plans recognized over the service period. For the Company's plan which is equity-settled, the Company will continue to recognize a corresponding increase in equity. Unlike Canadian GAAP, the service period under IFRS may commence prior to the date of grant and end on the vesting date. This represents a difference in timing and ultimately does not impact the overall expense. The Company currently applies a graded expense allocation method consistent with IFRS, however will have to incorporate a forfeiture rate on transition. Tamarack Valley expects minimal impact based on the forfeiture rate chosen and on transition. (vii) Disclosures: IFRS requires significant disclosures for account policies, use of IFRS 1 mandatory exemptions, and use of IFRS 1 elective exemptions. It is expected that the IFRS disclosures for the Company will be substantial, as the basis of substance over form reflected in IFRS will require much more detailed disclosures than Canadian GAAP requires. (viii) IFRS standards recognize only the value of common shares in share capital and as such the premium on flow-through shares and income tax effects are segregated from share capital. Tamarack Valley expects that there will be an increase in share capital of approximately $5.3 million with an offsetting charge to the opening deficit of the same.

During the fourth quarter, management continued to attend training seminars and worked on developing positions for the policy changes so that the quantitative impact of adoption can be made in the fourth quarter of 2010 and the first quarter of 2011.

BUSINESS RISKS Tamarack faces or will face a number of business risks, both known and unknown, with respect to its oil and gas exploration, development and production activities that could cause actual results or events to differ materially from those forecast. Most of these risks (financial, operational or regulatory) are not within the Company's control. While the following sections discuss some of these risks they should not be construed as exhaustive.

Financial Risks Financial risks include commodity pricing; exchange and interest rates; and volatile markets. Commodity price fluctuations result from market forces completely out of the Company's control and can significantly affect the Company's financial results. In addition, fluctuations between the Canadian dollar and the US dollar can also have a significant impact. Expenses are all incurred in Canadian dollars while crude oil, and to some extent natural gas, prices are based on reference prices denominated in US dollars. As a result of both of these factors Tamarack may enter into derivative instruments to partially mitigate the effects of downward price volatility. To evaluate the need for hedging Management, with direction from the Board of Directors, monitors future pricing trends together with the cash flow necessary to fulfill capital expenditure requirements.

Tamarack will only enter into a hedge to reduce downside uncertainty of pricing, not as a speculative venture.

Operational Risks Oil and natural gas operations involve many risks that even a combination of experience, knowledge and careful evaluation may not be able to overcome. The long-term commercial success of Tamarack depends on its ability to find, acquire, develop and commercially produce oil and natural gas reserves. Without the continual addition of new reserves, existing reserves and their subsequent production will decline over time as they are exploited. A future increase in Tamarack's reserves will depend not only on its ability to explore and develop any properties it may have; but also on its ability to select and acquire suitable producing properties or prospects. No assurance can be given that further commercial quantities of oil and natural gas will be discovered or acquired by Tamarack.

Tamarack endeavors to mitigate these risks by, among other things, ensuring that its employees are highly qualified and motivated. Prior to initiating capital projects the Tamarack technical team completes an economic analysis, which attempts to reflect the risks involved in successfully completing the project. In an effort to mitigate the risk of not finding new reserves, or of finding reserves that are not economically viable, Tamarack utilizes various technical tools, such as 2D and 3D seismic data, rock sample analysis and the latest drilling and completing technology.

23

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2010 ANNUAL REPORT

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management’s discussion & analysis of financial results

>

Insurance is in place to protect against major asset destruction or business interruption, including well blow-outs and pollution. In addition, Tamarack cultivates long-term relationships with its suppliers in an effort to ensure good service regardless of the current cycle of oil and gas activity.

Operational risk is mitigated by having Tamarack staff address the continued development of a new or established reservoir, on a go-forward basis, using the same procedure that is used to mitigate exploration risk. The decision to produce reserves is made based on the amount of capital required, commodity prices, production practices and reservoir quality. Tamarack evaluates reservoir development based on the timing and amount of additional capital required and the expected change in production values. Finding and development costs are controlled when capital is employed cost-effectively.

Regulatory Risks Regulatory risks include the possibility of changes to royalty, tax, environmental and safety legislation. Tamarack endeavours to anticipate the costs related to compliance and budget sensibly for them. Changes to environmental and safety legislation may also cause delays to Tamarack's drilling plans, its production efficiencies and may adversely affect its future earnings. Restrictive new legislation is a risk we cannot control.

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2010 ANNUAL REPORT

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management’s report The management of Tamarack Valley Energy (the “Company”) is responsible for the preparation and integrity of the accompanying consolidated financial statements and all other information contained in this report. The consolidated financial statements have been prepared in accordance with generally accepted accounting principles (“GAAP”) in Canada and include amounts that are based on management's informed judgments and estimates where necessary.

The Company has established internal accounting control systems which are designed to provide reasonable assurance regarding the reliability of the Company's financial reporting and the preparation of the consolidated financial statements together with the other financial information for external purposes in accordance with Canadian GAAP. The Board of Directors, through its Audit Committee, monitors management's financial and accounting policies and practices and the preparation of these consolidated financial statements. The Audit Committee meets periodically with the external auditors and management to review the work of each and the propriety of the discharge of their responsibilities.

The Audit Committee reviews the consolidated financial statements of the Company with management and the external auditors prior to submission to the Board of Directors for final approval. The Board of Directors also reviews the consolidated financial statements before they are finalized. The external auditors have full and free access to the Audit Committee to discuss auditing and financial reporting matters. The Audit Committee reviews the independence of the external auditors and pre-approves audit and permitted non-audit services and fees. The Shareholders have appointed KPMG LLP as the external auditors of the Company, and in that capacity, they have audited the consolidated financial statements for the years ended December 31, 2010 and 2009.

Brian Schmidt President, CEO & Director April 29, 2011

25

Ron Hozjan Vice President, Finance & CFO

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2010 ANNUAL REPORT

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independent auditors’ report

>

To the Shareholders We have audited the accompanying consolidated financial statements of Tamarack Valley Energy Ltd., which comprise the consolidated balance sheets as at December 31, 2010 and 2009, the consolidated statements of operations, comprehensive loss and deficit and cash flows for the years then ended, and notes, comprising a summary of significant accounting policies and other explanatory information.

MANAGEMENT'S RESPONSIBILITY FOR THE CONSOLIDATED FINANCIAL STATEMENTS Management is responsible for the preparation and fair presentation of these consolidated financial statements in accordance with Canadian generally accepted accounting principles, and for such internal control as management determines is necessary to enable the preparation of consolidated financial statements that are free from material misstatement, whether due to fraud or error.

AUDITORS' RESPONSIBILITY Our responsibility is to express an opinion on these consolidated financial statements based on our audits. We conducted our audits in accordance with Canadian generally accepted auditing standards. Those standards require that we comply with ethical requirements and plan and perform the audit to obtain reasonable assurance about whether the consolidated financial statements are free from material misstatement.

An audit involves performing procedures to obtain audit evidence about the amounts and disclosures in the consolidated financial statements. The procedures selected depend on our judgment, including the assessment of the risks of material misstatement of the consolidated financial statements, whether due to fraud or error. In making those risk assessments, we consider internal control relevant to the entity's preparation and fair presentation of the consolidated financial statements in order to design audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the entity's internal control. An audit also includes evaluating the appropriateness of accounting policies used and the reasonableness of accounting estimates made by management, as well as evaluating the overall presentation of the consolidated financial statements.

We believe that the audit evidence we have obtained in our audits is sufficient and appropriate to provide a basis for our audit opinion.

OPINION In our opinion, the consolidated financial statements present fairly, in all material respects, the consolidated financial position of Tamarack Valley Energy Ltd. as at December 31, 2010 and 2009, and the results of its consolidated operations and its consolidated cash flows for the years then ended in accordance with Canadian generally accepted accounting principles.

Chartered Accountants Calgary, Canada March 23, 2011

26

2010 ANNUAL REPORT

>

>

consolidated balance sheets As at December 31,

2010

Assets Current assets: Cash and cash equivalents Accounts receivable Prepaid expenses and deposits

$

Property and equipment (note 5) $

Liabilities and Shareholders' Equity Current liabilities: Bank debt (note 6) Accounts payable and accrued liabilities

$

Asset retirement obligations (note 7) Future income taxes (note 9) Shareholders' equity: Share capital (note 8) Contributed surplus (note 8(f)) Deficit

3,641,025 1,930,443 479,443 6,050,911 38,870,647 44,921,558

7,213,361 7,213,361

2009

$

$

$

8,406 927,536 304,046 1,239,988 32,624,734 33,864,722

1,475,000 1,244,473 2,719,473

780,656

669,024

-

4,630,830

45,129,919 4,278,245 (12,480,623) 36,927,541

29,120,114 2,762,502 (6,037,221) 25,845,395

Commitments (note 11) Subsequent event (note 13) $ See accompanying notes to the consolidated financial statements.

On behalf of the Board:

Dean Setoguchi Director

27

Floyd Price Director

44,921,558

$

33,864,722

2010 ANNUAL REPORT

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consolidated statements of operations, comprehensive loss & deficit For the years ended December 31, Revenue: Petroleum and natural gas Royalties

Expenses: Production General and administration Re-organization costs Stock-based compensation Interest Depletion, depreciation and accretion

2010

$

7,613,528 (1,180,773) 6,432,755

2009

$

4,400,541 (504,942) 3,895,599

2,530,684 1,725,148 2,309,356 1,682,176 34,874 7,037,205 15,319,443

1,854,390 1,062,101 255,227 28,433 5,466,726 8,666,877

Loss before taxes

(8,886,688)

(4,771,278)

Future income tax reduction (note 9)

(2,443,286)

(1,348,100)

Net loss and comprehensive loss for the year

(6,443,402)

(3,423,178)

(6,037,221) (12,480,623)

(2,614,043) (6,037,221)

($ 0.06)

($ 0.05)

99,884,466

65,774,620

Deficit, beginning of year Deficit, end of year Loss per share (note 8(g)): Basic and diluted Weighted average common shares outstanding during the period

>

See accompanying notes to the consolidated financial statements.

28

2010 ANNUAL REPORT

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consolidated statements of cash flows For the years ended December 31,

2010

2009

($ 6,443,402)

($ 3,423,178)

7,037,205 1,682,176 (2,443,286) (167,307) (221,963) (389,270)

5,466,726 255,227 (1,348,100) (39,745) 910,930 (730,980) 179,950

4,487,254 (1,475,000) 3,012,254

1,475,000 2,991,750 4,466,750

(11,030,162) 7,045,250 4,994,547 1,009,635

(3,945,775) (1,061,244) (5,007,019)

3,632,619

(360,319)

8,406

368,725

Cash provided by (used in): Operating: Net loss for the year Items not involving cash: Depletion, depreciation and accretion Stock-based compensation Future income tax (reduction) Abandonment expenditures Change in non-cash working capital

Financing: Issuance of shares, net Change in bank debt Short term investments

Investing: Property and equipment additions Cash received on acquisition (note 4) Change in non-cash working capital

Change in cash and cash equivalents Cash and cash equivalents, beginning of year Cash and cash equivalents, end of year

$

3,641,025

$

8,406

Supplemental cash flow information: Interest paid

$

34,874

$

28,433

See accompanying notes to the consolidated financial statements.

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2010 ANNUAL REPORT

notes to the consolidated financial statements

>

>

For the years ended December 31, 2010 and 2009 1. NATURE OF OPERATIONS Tamarack Valley Energy Ltd. (formerly Tango Energy Inc.) (“Tamarack� or the "Corporation") is incorporated under the Business Corporations Act of Alberta.

On June 17, 2010, the Corporation's shareholders approved the acquisition of a private oil and gas company (see note 4) and a corporate name change from Tango Energy Inc. to Tamarack Valley Energy Ltd. In conjunction with the private company purchase, the Corporation's officers and directors were principally reconstituted following the acquisition.

2. SIGNIFICANT ACCOUNTING POLICIES The consolidated financial statements of the Corporation have been prepared by management in accordance with Canadian generally accepted accounting principles. Since the determination of many assets, liabilities, revenues and expenses is dependent upon future events, the preparation of these consolidated financial statements requires the use of estimates and assumptions, which have been made with careful judgment. In the opinion of management, these consolidated financial statements have been properly prepared within reasonable limits of materiality and within the framework of the significant accounting policies summarized below. (a) Principles of consolidation: The consolidated financial statements include the accounts of the Corporation and its wholly owned subsidiary Tamarack Acquisition Corp. All intercompany balances and transactions have been eliminated (b) Property and equipment: The Corporation follows the full cost method of accounting for oil and gas operations whereby all costs related to the acquisition of, exploration for and development of petroleum and natural gas reserves are capitalized. These costs include lease acquisition, geological and geophysical, drilling of both productive and non-productive wells, equipment costs, asset retirement costs and overhead expenses related to exploration and development activities. Costs of acquiring and evaluating unproved properties are excluded from the depletion calculation until it is determined whether or not proved reserves are attributable to the properties or impairment occurs. When proved reserves are assigned to the property or the property is considered to be impaired, the cost of the property or the amount of the impairment is added to the depletable base.

Proceeds from the sale of oil and gas properties are applied against capitalized costs, with no gain or loss recognized, unless such a sale would alter the rate of depletion and depreciation by 20% or more.

Depletion of oil and gas properties and depreciation of production equipment is provided on accumulated costs using the unit-of-production method based on an independent engineering firm's estimate of proved oil and gas reserves, before royalties. Production and reserves of natural gas are converted to equivalent barrels of crude oil based on the energy equivalent ratio of six thousand cubic feet of natural gas to one barrel of crude oil.

The depletion and depreciation cost base includes total capitalized costs, less costs of unproved properties, plus provision for future development costs of proved undeveloped reserves. Petroleum and natural gas properties are evaluated in each reporting period to determine if the carrying amount in a cost center is recoverable and does not exceed the fair value of the properties in the cost center.

The carrying amounts are assessed to be recoverable when the sum of the undiscounted cash flows expected from the production of proved reserves, the cost, less impairment, of unproved properties and the cost of major development projects exceeds the carrying amount of the cost center. When the carrying amount is not assessed to be recoverable, an impairment loss is recognized to the extent that the carrying amount of the cost center exceeds the sum of the discounted cash flows expected from the production of proved and probable reserves, the cost, less impairment, of unproved properties and the cost of major development projects of the cost center. The cash flows are estimated using expected future product prices and costs and are discounted using a risk-free interest rate.

Office furniture and computer equipment are recorded at cost and are depreciated on the declining balance basis using rates varying from 20% to 30%.

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2010 ANNUAL REPORT

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notes to the consolidated financial statements For the years ended December 31, 2010 and 2009 2. SIGNIFICANT ACCOUNTING POLICIES (CONTINUED) (c) Asset retirement obligations: The liability for the Corporation's asset retirement obligation is recorded in the period in which it is incurred, discounted to its present value using the Corporation's credit adjusted risk-free interest rate and the corresponding amount is recognized by increasing the carrying amount of property and equipment. The asset recorded is depleted on a unit of production basis over the life of the reserves. The liability amount is increased each reporting period due to the passage of time and the amount of accretion is charged to earnings in the period.

Revisions to the estimated timing of cash flows or to the original estimated undiscounted cost could also result in an increase or decrease to the obligation. Actual costs incurred upon settlement of the retirement obligation are charged against the obligation to the extent of the liability recorded. (d) Joint interests: Substantially all of the Corporation's oil and gas exploration and development activities are conducted jointly with others and, accordingly, the financial statements reflect only the Corporation's proportionate interest in such activities. (e) Future income taxes: The Corporation uses the asset and liability method of accounting for future income taxes, under which future income tax assets and liabilities are determined based on "temporary differences" arising from the difference between the tax basis of an asset or liability and its carrying amount on the balance sheet. These temporary differences are measured using the current, or substantively enacted, tax rates and laws expected to apply when these differences reverse. A valuation allowance is recorded against any future income tax assets if it is more likely than not that the asset will not be realized. (f) Financial instruments: A financial instrument is defined as any contract that gives rise to a financial asset for one entity and a financial liability or equity instrument for another entity. Initially, all financial instruments, including all derivatives, are recognized on the balance sheet at fair value. Subsequent measurement is then based on the financial instruments being classified into one of the five categories: held for trading; held to maturity; loans and receivables; available for sale; and other liabilities. The Corporation has designated its cash and cash equivalents as held for trading which is measured at fair value. Accounts receivable are classified as loans and receivables which are measured at amortized cost.

Accounts payable and accrued liabilities and bank debt are classified as other liabilities which are measured at amortized cost, which is determined using the effective interest method.

The Corporation will assess at each reporting period whether a financial asset is impaired with any impairment recorded in earnings.

The Corporation is exposed to market risks resulting from fluctuations in commodity prices, foreign exchange rates and interest rates in the normal course of operations. A variety of financial derivative contracts may be used by the Corporation to reduce its exposure to these fluctuations. As a result, all financial derivative contracts are classified as held for trading and are recorded on the balance sheet at fair value, with changes in fair value recognized in earnings. Settlements on financial derivative contracts are recognized in earnings at the time each transaction under a contract is settled. The Corporation does not use these financial derivative contracts for trading or speculative purposes. The Corporation does not designate its financial derivative contracts as effective accounting hedges even though the Corporation considers all of these transactions to be effective economic hedges.

The Corporation has elected to account for any physical delivery sales contracts, which may be entered into for the purpose of receipt or delivery of non-financial items in accordance with its expected purchase, sale or usage requirements as executory contracts on an accrual basis. As such, these contracts will not be recorded at fair value on the balance sheet.

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2010 ANNUAL REPORT

notes to the consolidated financial statements

>

>

For the years ended December 31, 2010 and 2009 2. SIGNIFICANT ACCOUNTING POLICIES (CONTINUED) (f) Financial instruments (continued): The Corporation measures and recognizes embedded derivatives separately from the host contracts when the economic characteristics and risks of the embedded derivative are not closely related to those of the host contract, when it meets the definition of a derivative and when the entire contract is not measured at fair value. Embedded derivatives are recorded at fair value.

The Corporation immediately expenses all transaction costs incurred in relation to the acquisition of a financial asset or liability. Bank debt is presented net of deferred interest payments, with interest recognized in earnings on an effective interest rate basis. (g) Stock-based compensation plan: The Corporation uses the fair value method for valuing stock option grants and preferred shares issued. Under this method, compensation cost attributable to all stock options granted and preferred shares issued is measured at fair value at the grant and issue date and expensed over the vesting period with a corresponding increase to contributed surplus. Upon the exercise of the stock options and preferred shares, consideration received together with the amount previously recognized in contributed surplus is recorded as an increase to share capital. (h) Cash and cash equivalents: Cash and cash equivalents include term deposits and short-term investments with original maturities of three months or less. (i) Per share amounts: Basic per share amounts are calculated using the weighted average common shares outstanding during the period. Diluted per share amounts are calculated using the treasury stock method. Diluted calculations reflect the weighted average incremental common shares that would be issued upon exercise of dilutive instruments assuming the proceeds would be used to repurchase shares at average market prices for the period.

Anti-dilutive instruments are not included in the calculation. (j) Measurement uncertainty: The amounts recorded for depletion and depreciation of property and equipment and the provisions for asset retirement obligations, stock-based compensation and future income taxes are based on estimates. The depletion calculation and ceiling test is based on estimates of reserves, production rates, oil and natural gas prices, royalties and future costs. Asset retirement obligations are based on estimate of future abandonment costs, timelines to abandonment and discount rates. Stock-based compensation is based on estimate of expected lives and volatility in stock prices. Future taxes are based on estimated as to the reversal of temporary differences. By their nature, these estimates are subject to measurement uncertainty and the impact on the financial statements of changes in such estimates in future periods could be significant. (k) Flow-through shares: The resource expenditure deductions for income tax purposes related to exploratory and development activities funded by flow-through share arrangements are renounced to investors in accordance with tax legislation. The estimated tax cost of the renounced tax deductions are reflected in share capital and future income taxes when the expenditures are renounced. (l) Revenue recognition: Petroleum and natural gas revenues are recognized when the title and risk pass to the purchaser and collection is reasonably assured. (m) Comparative figures: Certain comparative figures have been reclassified to conform to the current year's presentation.

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2010 ANNUAL REPORT

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notes to the consolidated financial statements

>

For the years ended December 31, 2010 and 2009 3. CHANGE IN ACCOUNTING POLICIES Future Accounting Changes On January 1, 2011, International Financial Reporting Standards ("IFRS") as issued by the International Accounting Standards Board will become the generally accepted accounting principles in Canada. The adoption date of January 1, 2011 will require the restatement, for comparative purposes, of amounts reported by Tamarack Valley for the year ended December 31, 2010, including the opening balance sheet as at January 1, 2010. The transition from Canadian GAAP to IFRS is significant with differences affecting the financial position and results of operations. Tamarack Valley is finalizing the impact on its financial statements of the convergence of Canadian GAAP with IFRS. 4. ACQUISITION On June 17, 2010, the Corporation acquired all of the issued and outstanding shares of a private oil and gas company ("Private Co."). Private Co. was in the pre-production stage and had not commenced active operations. As consideration the Corporation issued 55,114,768 common shares. The results of Private Co. have been included in the accounts of the Corporation commencing June 17, 2010. The transaction was accounted for using the purchase method of accounting. The fair values assigned to the net assets and liabilities and consideration paid are as follows: Net assets acquired at fair value: Cash and cash equivalents Property and equipment Working capital deficiency Future income tax asset Asset retirement obligations

$ 7,045,250 1,877,750 (18,000) 2,150,000 (55,000) $11,000,000 $11,000,000

Consideration: Share capital (55,114,768 common shares) 5. PROPERTY AND EQUIPMENT

December 31, 2010 Petroleum and natural gas properties Office furniture and computer equipment

December 31, 2009 Petroleum and natural gas properties Office furniture and computer equipment

Cost $ 69,472,002 239,260 $ 69,711,262

Accumulated Depletion and Depreciation ($ 30,692,805) (147,810) ($ 30,840,615)

Net Book Value $ 38,779,197 91,450 $ 38,870,647

$ 56,295,495 188,195 $ 56,483,690

($ 23,736,728) (122,228) ($ 23,858,956)

$ 32,558,767 65,967 $ 32,624,734

During the year ended December 31, 2010, the Corporation capitalized $446,806 (December 31, 2009 - $492,000) of general and administrative and stock-based compensation expenses directly related to exploration and development activities. During the year ended December 31, 2010, the future tax liability of $81,268 (December 31, 2009 - $30,477), associated with the capitalized stock-based compensation was also capitalized.

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2010 ANNUAL REPORT

notes to the consolidated financial statements

>

>

For the years ended December 31, 2010 and 2009 5. PROPERTY AND EQUIPMENT (CONTINUED) Costs associated with unproved properties, including undeveloped land, seismic and salvage value excluded from costs subject to depletion at December 31, 2010 was $7,602,630 (December 31, 2009 - $1,227,000). At December 31, 2010, future development costs of proved reserves of $8,804,500 (December 31, 2009 - $1,451,000) have been included in the depletion calculation.

The Corporation performed a ceiling test calculation at December 31, 2010 to assess the recoverable value of the petroleum and natural gas assets.

As at December 31, 2010 there was no impairment required. For purposes of the ceiling test calculation, the Corporation used the January 1, 2011 commodity price forecast of its independent reserve evaluators. The following table summarizes the benchmark prices used in the calculation:

2011 2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 and thereafter

Currency Exchange Rate

W.T.I @ Cushing

Edm Ref Price

Tamarack Oil & NGL Price

AECO Natural Gas

Tamarack Natural Gas Price

(US$/Cdn$)

($US/bbl)

($Cdn/bbl)

(Cdn$/bbl)

(Cdn$/mcf)

(Cdn$/mcf)

$ 0.98 0.97 0.96 0.96 0.96 0.96 0.96 0.96 0.96 0.96 $ 0.96

$ 88.00 90.00 92.00 94.00 96.00 97.92 99.88 101.88 103.91 $ 105.99 +2%/yr

$ 87.30 90.28 93.83 95.88 97.92 99.88 101.88 103.91 105.99 $ 108.11 +2%/yr

$ 86.27 $ 87.82 $ 89.83 $ 89.06 $ 91.71 $ 94.41 $ 96.75 $ 99.05 $ 101.32 $ 103.71 +2%/yr

$ 4.14 4.71 5.29 5.76 6.27 6.77 7.02 7.16 7.30 $ 7.45 +2%/yr

$ 4.33 4.91 5.54 6.07 6.60 7.11 7.37 7.50 7.64 $ 7.79 +2%/yr

6. BANK DEBT The Corporation has a $4,000,000 revolving operating demand line of credit available and a $1,000,000 non-revolving acquisition/development demand line of credit with a Canadian chartered bank as at December 31, 2010. The interest rate on the revolving operating demand line of credit is at the bank's prime rate plus 1.25% and at the bank's prime rate plus 1.75% on the non-revolving acquisition/development demand line of credit.

These facilities are secured by a $40.0 million debenture with a floating charge over all assets. The next scheduled review of these lines of credit is May 31, 2011. As the available lending limits of the facilities are based on the bank's interpretation of the Corporation's reserves and future commodity prices, there can be no assurance as to the amount of available facilities that will be determined at each scheduled review. Pursuant to the terms of the credit facilities, the Corporation has provided the covenant that at all times its working capital ratio shall be not less than 1 to 1.

The working capital ratio is defined under the terms of the credit facilities as current assets, including the undrawn portion of the revolving credit facility, to current liabilities, excluding any current bank indebtedness. At December 31, 2010, the Corporation had not utilized the revolving operating demand line of credit (December 31, 2009 - $1,475,000) or the non-revolving acquisition/development line of credit (December 31, 2009 nil). The Corporation is in compliance with its covenant as at December 31, 2010.

7. ASSET RETIREMENT OBLIGATIONS The asset retirement obligations result from net ownership interests in petroleum and natural gas assets including well sites, gathering systems and processing facilities. The Corporation estimates the total undiscounted amount of cash flows required to settle its asset retirement obligations to be approximately $1,270,000 ( December 31, 2009 - $1,244,000), which will be incurred between 2011 and 2038. A credit adjusted risk-free rate of 8% and an inflation rate of 2% was used to calculate the fair value of the asset retirement obligations.

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2010 ANNUAL REPORT

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notes to the consolidated financial statements

>

For the years ended December 31, 2010 and 2009 7. ASSET RETIREMENT OBLIGATIONS (CONTINUED) A reconciliation of the asset retirement obligations is provided below:

Balance, beginning of the year Liabilities incurred Liabilities acquired (note 4) Revisions Accretion expense Abandonment expenditures Balance, end of the year

$

$

2010 669,024 9,494 55,000 (8,408) 55,546 780,656

$

$

2009 711,666 13,739 (71,936) 55,300 (39,745) 669,024

8. SHARE CAPITAL (a) Authorized: Unlimited number of common shares and preferred shares without nominal or par value. (b)Issued and outstanding: Common Shares Balance, December 31, 2009 and 2008 Issued on Private Co. acquisition (note 4) Issued pursuant to flow-through share offering Exercise of stock options Transfer from contributed surplus on exercise of stock options Share issue costs, net of tax effect of $118,812 Balance, December 31, 2010

Number of Shares 65,774,620 55,114,768 14,449,858 2,510,000 137,849,246

Amount $ 29,120,114 11,000,000 4,500,000 437,300 403,739 (331,234) $ 45,129,919

On October 21, 2010 the Corporation issued 11,067,194 flow-through common shares related to Canadian exploration expenditures for gross proceeds of $3,500,000 and 3,382,664 flow-through common shares related to Canadian development expenditures for gross proceeds of $1,000,000. Certain officers, directors and employees acquired 616,500 of the flow-through common shares for gross proceeds of $194,968. (c) Preferred share plan: Under the Corporation's preferred share plan, preferred shares are exchangeable into common shares upon payment of $0.26 per common share.

Preferred shares issued must be exchanged within a five-year term, and vest one-third on each of the first, second and third anniversaries from the date of grant. A summary of the status of the Corporation's preferred share plan as of December 31, 2010 and changes during the period then ended is presented below:

Outstanding, December 31, 2009 Issued Outstanding, December 31, 2010

35

Number of Preferred Shares 23,356,997 23,356,997

WeightedAverage Exchange Price $ 0.26 $ 0.26

2010 ANNUAL REPORT

notes to the consolidated financial statements

>

>

For the years ended December 31, 2010 and 2009 8. SHARE CAPITAL (CONTINUED) (c) Preferred share plan (continued): The following table summarizes information about preferred shares outstanding and exercisable at December 31, 2010: Preferred Shares Outstanding Weighted Average Remaining Number Contractual Outstanding Life (Years) 23,356,997 4.5 23,356,997 4.5

Exchange Price $ 0.26

Preferred Shares Exercisable

Number Exercisable -

(d) Stock option plan: Under the Corporation's stock option plan it may grant up to 1,670,450 options to its employees, directors and consultants of which 850,000 options have been issued. Stock options issued have a five-year term, are exercisable at the exercise price and vest one-third on each of the first, second and third anniversaries from the date of grant.

A summary of the status of the Corporation's stock option plan as of December 31, 2010 and changes during the period then ended is presented below:

Number of Options 3,515,000 1,860,000 (985,000) 4,390,000 (2,510,000) 850,000 (1,880,000) 850,000

Outstanding, December 31, 2008 Granted Forfeited/expired Outstanding, December 31, 2009 Exercised Granted Expired Outstanding, December 31, 2010

WeightedAverage Exercise Price $ 0.41 0.13 0.56 $ 0.26 0.17 0.34 0.36 $ 0.34

The following table summarizes information about stock options outstanding and exercisable at December 31, 2010: Options Outstanding

Range of Exercise Price $ 0.30 - 0.37

Number Outstanding 850,000 850,000

Weighted Average Exercise Price $ 0.34 $ 0.34

Options Exercisable Weighted Average Remaining Contractual Life (Years) 4.7 4.7

Remaining Number Exercisable -

Weighted Average Exercise Price -

36

2010 ANNUAL REPORT

>

notes to the consolidated financial statements

>

For the years ended December 31, 2010 and 2009 8. SHARE CAPITAL (CONTINUED) (e) Stock-based compensation: The fair value of each stock option grant and the preferred shares issued was estimated on the date of grant using the Black-Scholes option-pricing model with the following assumptions used for grants in the year ended December 31, 2010: average expected volatility of 80 percent (December 31, 2009 - 195 percent), average risk-free interest rate of 2.5 percent (December 31, 2009 - 5.0 percent), zero dividend yield (December 31, 2009 zero dividend yield), and expected life of five years (December 31, 2009 - five years). The average fair value of stock options and preferred shares granted during the year ended December 31, 2010 was $0.25 (December 31, 2009 - $0.13) per option and $0.23 per preferred share. The Corporation has not re-priced any stock options. The Corporation has not incorporated an estimated forfeiture rate for stock options or preferred shares that will not vest, rather the Corporation accounts for actual forfeitures as they occur. (f) Contributed surplus: A reconciliation of contributed surplus is provided below:

Balance, beginning of year Stock-based compensation expense Stock-based compensation capitalized Stock options exercised Balance, end of year

December 31, 2010 $ 2,762,502 1,682,176 237,306 (403,739) $ 4,278,245

December 31, 2009 $ 2,432,152 255,227 75,123 $ 2,762,502

Stock-based compensation expense includes amounts attributable to both the preferred shares and options granted. (g) Per share amounts: Per share amounts have been calculated using the weighted average number of shares outstanding. In computing diluted per share amounts for the years ended December 31, 2010 and 2009, no common shares were added to the basic weighted average number of common shares outstanding for the diluted effect of preferred shares and stock options, as they were anti-dilutive and no adjustments to earnings were necessary.

9. INCOME TAXES The tax provision differs from the expected tax provision obtained by applying the combined Federal and Provincial statutory tax rates to the loss before taxes as follows: December 31, December 31, 2010 2009 $ (8,886,688) $ (4,771,278) Loss before taxes Expected tax rate 28% 29% $ (2,488,273) $ (1,383,671) Expected income tax reduction Decrease (increase) in taxes resulting from: Future tax rate reduction 249,147 (41,623) Non-deductible expenses 599,408 74,016 Valuation allowance (801,926) Other (1,642) 3,178 $ (2,443,286) $ (1,348,100) Future tax reduction

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2010 ANNUAL REPORT

notes to the consolidated financial statements

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For the years ended December 31, 2010 and 2009 9. INCOME TAXES (CONTINUED) The components of the net future income tax liability are as follows:

Future income tax assets : Non capital losses carried forward Share issue costs Asset retirement obligations Future income tax liabilities : Valuation allowance Property and equipment Net future income tax liability

December 31, 2010

December 31, 2009

$ 4,011,069 121,760 199,145 4,331,974

$

(1,720,982) (2,610,992) $ -

421,027 70,082 170,668 661,777 (5,292,607) ($ 4,630,830)

At December 31, 2010, the Corporation had $15,903,000 of non-capital losses which expire between the years 2025 and 2030.

10. CAPITAL MANAGEMENT The Corporation's objectives when managing its capital are to preserve the ability to meet our financial obligations while maintaining a level of financial flexibility which allows us to take advantage of opportunities - such as farm-ins, land sales, acquisitions, and drilling opportunities - as they arise. The Corporation manages its capital structure and adjusts it as a result of changes in economic conditions and the risk characteristics of the underlying petroleum and natural gas assets. The Corporation considers its capital structure to include shareholders' equity, bank debt and working capital which are shown in the table below. In order to maintain or adjust the capital structure, the Corporation may from time to time issue shares, adjust its capital spending or hedge its production to manage current and forecasted debt levels.

Shareholders' equity Bank debt Working capital (deficiency), excluding bank debt

December 31, 2010 $ 36,927,541 (1,162,450)

December 31, 2009 $ 25,845,395 1,475,000 (4,485)

The Corporation manages its capital and financing requirements using the non-GAAP financial ratio of net debt to annualized funds from operations.

Net debt is defined as bank debt plus or minus working capital. Funds from operations are defined as cash flow from operating activities before changes in non-cash working capital and abandonment expenditures. The net debt to annualized funds from operations ratio is calculated by dividing total net debt by annualized funds from operations for the most recent quarter. The Corporation's strategy is to maintain this ratio at no more than 2 to 1.

The Corporation budgets for capital expenditures annually but continually monitors its capital program, and may increase or decrease its expenditures depending on the Corporation's net debt to annualized funds from operations ratio which is subject to, among other items, fluctuations in production rates and commodity prices.

The Corporation's share capital is not subject to external restrictions. The Corporation has not paid or declared any dividends since the date of incorporation, nor are any contemplated in the foreseeable future.

There were no changes in the Corporation's approach to capital management during the period.

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2010 ANNUAL REPORT

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notes to the consolidated financial statements For the years ended December 31, 2010 and 2009 11. COMMITMENTS (a) In the normal course of business the Corporation has obligations which represent contracts and other commitments with an estimated payment of $281,796 for 2011; $281,796 for 2012; and $117,415 for 2013. (b) On October 21, 2010, the Corporation issued 11,067,194 flow-through common shares related to Canadian exploration expenditures ("CEE") for gross proceeds of $3,500,000. Under the terms of the flow-through share agreements, the Corporation is required to renounce the $3,500,000 of qualifying oil and natural gas expenditures effective December 31, 2010 and has until December 31, 2011 to incur the expenditures. The Corporation has incurred $2,713,788 of qualifying expenditures, with the balance of $786,212 to be incurred on or prior to December 31, 2011. (c) On October 21, 2010, the Corporation issued 3,382,664 flow-through common shares related to Canadian development expenditures ("CDE") for gross proceeds of $1,000,000. Under the terms of the flow-through share agreements, the Corporation is required to renounce the $1,000,000 of qualifying oil and natural gas expenditures effective December 31, 2010 and had until December 31, 2010 to incur the expenditures. The Corporation has incurred the full amount of qualifying expenses as of December 31, 2010.

12. FINANCIAL INSTRUMENTS The Corporation has exposure to the following risks from its use of financial instruments: credit risk, liquidity risk and market risk.

This note presents information about the Corporation's exposure to each of the above risks and the Corporation's objectives, policies and processes for measuring and managing risk. Further qualitative disclosures are found throughout these financial statements. (a) Credit risk: The Corporation is exposed to credit risk with respect to its accounts receivable and cash and cash equivalents.

Credit risk is the risk of financial loss to the Corporation if a customer or counterparty to a financial instrument fails to meet its contractual obligations, and arises principally from the Corporation's receivables from joint interest partners and petroleum and natural gas purchasers.

As at December 31, 2010, the Corporation's receivables consisted of $1,056,407 (December 31, 2009- $616,832) from purchasers of the Corporation's petroleum and natural gas, $474,036 (December 31, 2009 - $310,704) from joint interest partners and $400,000 in drilling credits to be received.

The Corporation has not experienced any collection issues with its joint interest partners. However, the receivables are from participants in the petroleum and natural gas sector, and collection of the outstanding balances is dependent on industry factors such as commodity price fluctuations, escalating costs and the risk of unsuccessful drilling. The Corporation typically does not obtain collateral from petroleum and natural gas purchasers or joint interest partners.

Cash and cash equivalent consist of bank balances with large credit-worthy financial institutions.

The carrying amount of receivables and cash and cash equivalent represents the maximum credit exposure. The Corporation does not have an allowance for doubtful accounts as at December 31, 2010 and 2009 and did not provide for any doubtful accounts nor was it required to write-off any receivables during the year ended December 31, 2010 and 2009. The Corporation as at December 31, 2010 did not consider any of its receivables to be past due.

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2010 ANNUAL REPORT

notes to the consolidated financial statements

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For the years ended December 31, 2010 and 2009 12. FINANCIAL INSTRUMENTS (CONTINUED) (b) Liquidity risk: Liquidity risk is the risk that the Corporation will not be able to meet its financial obligations as they are due. The Corporation utilizes prudent cash and debt management to mitigate the likelihood of encountering difficulties in meeting its financial obligations. As disclosed in note 10, the Corporation targets a net debt to annualized funds from operations ratio of no more than 2 to 1 to manage the Corporation's overall liquidity risk.

The Corporation prepares annual capital expenditure budgets, which are regularly monitored and updated as considered necessary. Further, the Corporation utilizes authorizations for expenditures on both operated and non-operated projects to further manage capital expenditures. The Corporation also attempts to match its payment cycle with collection of petroleum and natural gas revenues on the 25th of each month.

Accounts payable and accrued liabilities totaling $7,213,361 are considered due within one year. (c) Market risk: Market risk is the risk that changes in market prices, such as foreign exchange rates, commodity prices, and interest rates will affect the Corporation's net earnings or the value of financial instruments. The objective of market risk management is to manage and control market risk exposures within acceptable limits, while maximizing returns and meeting shareholder objectives.

Foreign currency exchange rate risk is the risk that the fair value or future cash flows will fluctuate as a result of changes in foreign exchange rates.

Although substantially all of the Corporation's petroleum and natural gas sales will be denominated in Canadian dollars, the underlying market prices in Canada for petroleum and natural gas are impacted by changes in the exchange rate between the Canadian and United States dollar. The Corporation had no forward exchange rate contracts in place as at or during the year ended December 31, 2010 and 2009.

Commodity price risk is the risk that the fair value or future cash flows will fluctuate as a result of changes in commodity prices. Commodity prices for petroleum and natural gas are impacted by not only the relationship between the Canadian and United States dollar, as outlined above, but also North American and world economic events that dictate the levels of each commodity's supply and demand. The Corporation had no commodity price contracts in place as at or during the year ended December 31, 2010 and 2009.

Interest rate risk is the risk that future cash flows will fluctuate as a result of changes in the market interest rates. The Corporation is exposed to interest rate fluctuations on its cash and bank debt when outstanding. The Corporation had no interest rate swaps or financial contracts in place as at or during the year ended December 31, 2010 and 2009. Fluctuations in interest rates during the years ended December 31, 2010 and 2009 would not have had a significant impact on the financial statements. (d) Fair value: Financial instruments include cash and cash equivalents, accounts receivable and accounts payable and accrued liabilities and bank debt. The carrying value cash and cash equivalents, of accounts receivable, accounts payable and accrued liabilities approximate fair value due to their shortterms to maturity. Bank debt when outstanding bears interest at a floating market rate and is due on demand and accordingly the fair value approximates the carrying value.

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notes to the consolidated financial statements For the years ended December 31, 2010 and 2009 12. FINANCIAL INSTRUMENTS (CONTINUED) (d) Fair value (continued): Cash and cash equivalents is measured in the financial statements at fair value. These financial instruments require disclosure about how fair value was determined based on significant levels of inputs described in the following hierarchy: Level 1 - quoted prices are available in active markets for identical assets or liabilities as of the reporting date. Active markets are those in which transactions occur in sufficient frequency and value to provide pricing information on an ongoing basis.

Level 2 - pricing inputs are other than quoted prices in active markets included in Level 1. Prices in Level 2 are either directly or indirectly observable as of the reporting date. Level 2 valuations are based on inputs including quoted forward prices for commodities, time value and volatility factors, which can be substantially observed or corroborated in the marketplace.

Level 3 - valuations in this level are those with inputs for the asset or liability that are not based on observable market data.

The Corporation's cash and cash equivalents have a fair value based on a quoted market value that also represents their carrying value and are considered Level 1.

13. SUBSEQUENT EVENT On March 10, 2011, the Corporation closed a bought deal short form prospectus financing of 46,939,550 common shares at $0.49 per common share for gross proceeds of $23,000,380. The Corporation also closed a separate and concurrent private placement for 100,000 common shares at a price of $0.49 per common share for gross proceeds of $49,000. Certain officers and directors purchased 350,000 common shares for gross proceeds of $171,500 in conjunction with the offerings.

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2010 ANNUAL REPORT

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corporate information DIRECTORS

BANKER

Floyd Price - Chairman (3)

National Bank of Canada

Anthony Lambert (1)(2)(3)

LEGAL COUNSEL

Dean Setoguchi (1)

Osler, Hoskin & Harcourt LLP

David MacKenzie (1)(3)

AUDITOR

John Gunn (2)

KPMG LLP

Brian Schmidt

STOCK EXCHANGE

Ron Hozjan

Toronto Venture Exchange - TSXV

(1) Member of Audit Committee of the Board of Directors (2) Member of the Reserves Committee of the Board of Directors (3) Member of the Compensation & Governance Committee of the Board of Directors

STOCK SYMBOL

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TVE MANAGEMENT TEAM CORPORATE OFFICE Brian Schmidt President & Chief Executive Officer Ron Hozjan VP Finance & Chief Financial Officer Lew Hayes VP Production & Operations

1800, 407 - 2nd Street SW Calgary, AB T2P 2Y3 Tel: 403.263.4440 Fax: 403.263.5551 www.tamarackvalley.ca

Niels Gundesen VP Engineering Ken Cruikshank VP Land

Designed by Sandy Seifert. Printed by Signature Press.

Noralee Bradley Corporate Secretary

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1800, 407 - 2nd Street SW Calgary, Alberta, T2P 2Y3 Tel: 403.263.4440 Fax: 403.263.5551 www.tamarackvalley.ca