Tamarack Valley Energy : Announces 43% Increase in Proved Developed Producing Reserves and Operational Update.

Calgary, Alberta - February 27, 2017 - Tamarack Valley Energy Ltd. ("Tamarack" or the "Company") is pleased to announce the results of its independent oil and gas reserves evaluation as of December 31, 2016, prepared by GLJ Petroleum Consultants Ltd. ("GLJ"), summarized below. The reserves evaluation contained herein does not include the impact of the Spur Resources Ltd. acquisition that closed January 11, 2017 (the "Viking Acquisition"). Pro-forma reserves details including the new assets from the Viking Acquisition will be made available concurrent with the Company's year-end 2016 financial and operating results with further details included in the 2016 Annual Information Form, both of which are expected to be issued and filed on March 23, 2017.

Throughout 2016, Tamarack continued to focus on the successful execution of its core strategy and strategic acquisitions generating positive results despite ongoing weakness in commodity prices. The Company achieved strong reserves additions organically due to the success of its drilling program, enhancements to completion techniques and improvements in well performance, all of which contributed to attractive capital efficiencies. Tamarack's complementary acquisitions during 2016 at Wilson Creek / Redwater and the low-decline acquired production at Penny (collectively the "Acquired Assets") further supported the growth profile and contributed to near and longer-term value creation. A successful development program and cost reductions on the Acquired Assets during the latter half of 2016 led to an increase in the net present value of before tax future net revenues discounted at 10% ("NPVBT10") of proved plus probable ("2P") reserves to approximately $240 million compared to the purchase price paid of $85 million in June of 2016.

The NPVBT10 of Tamarack's total 2P reserves increased by 61% year over year to $668.8 million, representing

$4.55 per fully diluted share. Tamarack delivered 5% growth per fully diluted share in proved developed producing reserves ("PDP"), and increased its drilling location inventory while maintaining a strong balance sheet. On an absolute basis, the Company's significant reserves growth includes a 43% increase in PDP, a 34% increase in total proved ("1P") reserves and a 26% increase in 2P reserves.

• PDP reserves increased by 43% on an absolute basis and by 5% per fully diluted share.

• Increased 1P reserves by 34% to 33.4 million boe, and 2P reserves by 26% to 56.5 million boe.

• Oil and natural gas liquids ("NGLs") weighting across all reserves categories increased to approximately 60% compared to 2015 weightings of approximately 50% on PDP, 52% on 1P and 54% on 2P.

• Significant increases in oil reserves of 85%, 67% and 45% on PDP, 1P and 2P, respectively, over 2015.

• As a percentage of total 2P reserves, 1P reserves increased from 56% to 59%.

• Including acquisitions, the Company replaced 322% of production on a 1P basis and 406% on a 2P basis.

• Maintained a consistent approach to reserves booking, with 1P reserves including only 67 (52.6 net) proved undeveloped horizontal Cardium drilling locations and 2P reserves including only 103 (81.1 net) proved plus probable undeveloped horizontal Cardium drilling locations.

• Achieved 1P finding and development ("F&D") costs of approximately $14.44/boe and 1P finding, development and acquisition ("FD&A") costs of approximately $14.68/boe, both including the change in future development capital ("FDC").

• Achieved 2P F&D costs of approximately $7.20/boe and 2P FD&A costs of approximately $11.34/boe, both including the change in FDC.

• Realized three year average 2P F&D costs of approximately $15.14/boe and 2P FD&A costs of $15.68/boe, both including the change in FDC.

• Generated a 2P F&D recycle ratio of 2.3 times and a 2P FD&A recycle ratio of 1.5 times using the estimated 2016 operating netback, excluding hedges, of $16.55/boe (unaudited) and a 2P F&D recycle ratio of 3.1 times and a 2P FD&A recycle ratio of 1.9 times using the estimated Q4 2016 operating netback, excluding hedges, of $22.03/boe (unaudited).

• Increased 2P reserve life index to 15.0 years based on estimated 2016 average production of 10,344 boe/d.

  Reserves Snapshot by Category: PDP 1P 2P

  Reserves Added(1) (mboe) 9,940 12,163 15,332

  Total Reserves (mboe)(2) 20,517 33,404 56,544

  Reserves Replacement 263% 322% 406%

  NPV10 BT ($mm) $281.1 $411.1 $668.8

  FD&A Cost per boe(3) $13.98 $14.68 $11.34 Recycle Ratio(4) 1.2x 1.1x 1.5x

  F&D Cost per boe (3) $23.72 $14.44 $7.20

  Recycle Ratio(4) - 1.1x 2.3x

  Reserves per Fully Diluted Share Growth(4) 5% (2%) (8%)

• This number takes the difference in reserves year over year plus the production for the year.

• Total reserves are Company Interest reserves which include royalty volumes.

• Including changes in FDC.

• Based on a 2016 estimated operating netback excluding hedges of $16.55 per boe (unaudited).

• 2016 over 2015, based on 147.03 million shares outstanding and 107.61 million at December 31, 2016 and 2015, respectively.

The following tables highlight Tamarack's 2016 year-end independent reserves assessment and evaluation prepared by GLJ with an effective date of December 31, 2016 (the "GLJ Report"). The GLJ Report has been prepared in accordance with definitions, standards and procedures contained in National Instrument 51-101 - Standards of Disclosure for Oil and Gas Activities ("NI 51-101") and the Canadian Oil and Gas Evaluation Handbook. All evaluations and summaries of future net revenue are stated prior to provision for interest, debt service charges or general administrative expenses and after deduction of royalties, operating costs, estimated well abandonment and reclamation costs and estimated future capital expenditures. It should not be assumed that the estimates of future net revenues presented in the tables below represent the fair market value of the reserves.

CRUDE OIL(1)

CONVENTIONAL

NATURAL GAS

NATURAL GAS

LIQUIDS

TOTAL OIL

EQUIVALENT

RESERVES CATEGORY

(Mbbls)

(Mbbls)

TOTAL PROVED PLUS

PROBABLE 28,398 24,484 134,607 120,395 5,711 4,733 56,544 49,284

Note:

1. Heavy oil included in the Crude Oil product type represents less than 4% of any reserves category and as such is immaterial.

2. Columns may not add due to rounding.

RESERVES CATEGORY

PROVED:

0%

($000s)

5%

($000s)

10%

($000s)

15%

($000s)

20%

($000s)

Unit Value Before Income Tax Discounted at 10% Per Year(1)

($/Boe)

1. Unit values based on Company net reserves

2. The prices used to estimate net present values are the average of those used by the largest independent industry reserve evaluators.

3. Columns may not add due to rounding.

1. Reserves additions under Infill Drilling, Improved Recovery and Extensions are combined and reported as "Extensions and Improved Recovery".

2. Columns may not add due to rounding.

3. Company Gross Reserves exclude royalty volumes.

The following is a summary of GLJ's estimated future development capital required to bring proved and probable undeveloped reserves on production.

Notes:

(1) FDC as per GLJ independent reserve evaluation effective December 31, 2016 based on GLJ forecast pricing.

1. While Nl 51-101 requires that the effects of acquisitions and dispositions be excluded from the calculation of finding and development costs, FD&A costs have been presented because acquisitions and dispositions can have a significant impact on the Company's ongoing reserve replacement costs and excluding these amounts could result in an inaccurate portrayal of the Company's cost structure. Finding and development costs both including and excluding acquisitions and dispositions have been presented above.

2. The calculation of FD&A costs incorporates the change in FDC required to bring proved undeveloped and developed reserves into production. In all cases, the FD&A number is calculated by dividing the identified capital expenditures by the applicable reserves additions after changes in FDC costs.

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

4. The capital expenditures also exclude capitalized administration costs.

5. Columns may not add due to rounding.

To date in the first quarter of 2017, Tamarack has remained focused on executing its capital program and continues to be on target for expected activity levels and production volumes. Since the start of the year, the Company has brought a total of 15 (13.9 net) new wells on production, including 11 (10.9 net) Viking light oil wells, two net extended reach horizontal Cardium light oil wells, one net Notikewin liquids-rich natural gas well, and one net heavy oil well. Volumes from these new wells are contributing to the Company's current production of approximately 19,000 boe/d and Tamarack remains on target to meet its first half production guidance range of 18,500 to 19,000 boe/d despite numerous factors negatively impacting field operations thus far in the first quarter. Tamarack has experienced non-operated production curtailments, a third-party gas plant curtailment, earlier than expected road