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PetroBakken Announces 2012 Reserves Replacing 229% of 2012 Production and Achieving Proved Plus Probable FD&A Costs of $11.91/boe and F&D Costs of $26.74/boe

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CALGARY, ALBERTA -- (Marketwire) -- 02/21/13 -- PetroBakken Energy Ltd. ("PetroBakken" or the "Company") (TSX: PBN) is pleased to announce the Company's 2012 year-end reserves and provide an operational update.

Unless otherwise noted, all reserves herein are "Company Interest" reserves, which represent the Company's working interest and royalty interest share of reserves, before deduction of the Company's royalty obligations. All values in this press release are based on Sproule's forecast prices and estimates of future operating and capital costs at December 31, 2012. The Company's annual audit of our consolidated financial statements is not yet complete and accordingly all financial amounts herein are management's best estimates which are unaudited and subject to change.

HIGHLIGHTS

-- Proved plus probable ("2P") reserves (before dispositions) grew by 10% to 206.8 million barrels of oil equivalent ("MMboe") at December 31, 2012.-- The 2012 capital program replaced 229% of 2012 production through the addition of 35.8 MMboe of 2P reserves and achieved a recycle ratio of 1.8 times, based on our 2012 operating netback of $47.89.-- The light oil and liquids weighting of our reserves is 82%.-- In 2012, PetroBakken delivered finding, development and net acquisition ("FD&A") costs, including changes in future development capital ("FDC"), of $11.45/boe for total proved reserves and $11.91/boe for 2P reserves.-- 2012 acquisitions and divestitures resulted in the net disposition of 11.1 MMBoe total proved reserves and 16.9 MMBoe of 2P reserves, yielding disposition metrics (including FDC) of $64.59/boe for total proved reserves and $43.38/boe for 2P reserves.-- Our F&D costs (including land purchases) were $26.83/boe for proved reserve additions and $26.74/boe for 2P reserves.-- Total FDC for our 2P reserves decreased by $94.6 million in 2012 to $1.8 billion, with FDC per well remaining largely unchanged year over year across our resource plays. The ratio of proved developed to 2P reserves increased year-over-year from 36% to 39% and the ratio of total proved to 2P reserves increased from 59% to 64%.-- Early stage success in our enhanced oil recovery ("EOR") initiatives resulted in the initial booking of additional 2P reserves related to our pilot natural gas flood in the Bakken.-- Production in January 2013, based on field estimates, was approximately 49,700 barrels of oil equivalent per day ('boepd"). Currently, we have 48 (36 net) wells at various stages of completion waiting to be brought on production.-- Our current combined dividend reinvestment plan ("DRIP") and stock dividend program ("SDP") participation is approximately 30%.



RESERVES

Sproule Associates Limited ("Sproule") has completed their evaluation of PetroBakken's reserves, effective December 31, 2012 ("Sproule Evaluation").

Year-end 2012 2P reserves grew 2% to 206.8 MMboe, with total organic additions of 35.8 MMboe more than replacing our 16.9 MMboe of non-core dispositions and 15.7 MMboe of production. Sproule's net present value of our 2P reserves, discounted at 10%, is $4.0 billion before tax and $3.4 billion on an after tax basis. Our operating recycle ratio for 2012 was 1.8 times based on an operating netback of $47.89/boe. These results were driven primarily by strong performance in the Cardium business unit and continued maturation of our Bakken business unit.

We had an active program in 2012, drilling 217 net wells with a 98% success rate. Total net capital expenditures in 2012 were $320 million, with $928 million spent on exploration and development activities (including approximately $75 million of our 2013 capital that was accelerated into November and December of 2012) and $24 million on land, less net dispositions of $632 million. 2P F&D costs were $26.74/boe (including FDC), representing an improvement of 14% over 2011, primarily due to innovations in our drilling and completion techniques in the Cardium and lower service costs. The Company's three- year weighted average F&D cost, including land and FDC, is $28.37/boe, generating an operating recycle ratio of 1.8 times.

2P reserves in the Cardium business unit increased from 72.2 MMboe in 2011 to 93.7 MMboe in 2012, representing a 30% increase and replacing production by 461%. Our drilling activity led to additions of 28.0 MMBoe. In 2012, FD&A costs for this business unit were $18.42/boe, generating an operating recycle ratio of 2.6 times based on our operating netback for the business unit of $47.76/boe. The Cardium business unit will continue to be a key source of growth for PetroBakken, with a development drilling inventory of over 580 net locations, of which 306 net locations were included in the Sproule Evaluation.

2P reserve growth in the Bakken business unit (before dispositions) was relatively flat for 2012, replacing approximately 107% of production. This moderation of growth is consistent with our business plan of relatively stable production generating positive free cash flow net of capital expenditures. Net reserve additions in the Bakken business unit (before dispositions) were 7.0 MMboe, resulting in year-end 2P reserves of 78.7 MMboe. The potential for future EOR-related reserve growth in the Bakken is encouraging after receiving initial 2P reserve recognition for the early stage success of our pilot natural gas flood. At year-end, we had an inventory of over 900 net locations in the business unit, of which 347 net locations were included in the Sproule Evaluation.

ReservesForecast Prices(1)As at December 31, 2012 Royalty Interests Company Company Gross(2) (3) Interest(4) --------------------------------------------------------------- Total Natural Oil NGL Gas Sub-total Sub-total Total (Mbbl) (Mbbl) (MMcf) (Mboe) (Mboe) (Mboe)----------------------------------------------------------------------------Proved Developed Producing 61,448 4,766 86,388 80,611 698 81,309Total Proved 99,185 7,503 143,694 130,637 722 131,359Proved + Probable (2P) 157,156 11,860 219,988 205,681 1,077 206,758----------------------------------------------------------------------------Net Present Value - Before Tax ($ millions)(5)(6)Forecast Prices(1)As at December 31, 2012 0% 5% 10%----------------------------------------------------------------------------Proved Developed Producing $ 3,528 $ 2,732 $ 2,258Total Proved 4,919 3,573 2,792Proved + Probable (2P) $ 8,186 $ 5,442 $ 4,014----------------------------------------------------------------------------Net Present Value - After Tax ($ millions)(5)(6)Forecast Prices(1)As at December 31, 2012 0% 5% 10%----------------------------------------------------------------------------Proved Developed Producing $ 3,254 $ 2,574 $ 2,160Total Proved 4,287 3,177 2,521Proved + Probable (2P) $ 6,700 $ 4,545 $ 3,404----------------------------------------------------------------------------Company Interest Reserve Reconciliation (Mboe)(4)Forecast Prices(1)As at December 31, 2012 Developed Total Proved+ Producing Proved Probable----------------------------------------------------------------------------PetroBakken reserves at December 31, 2011 74,110 119,867 203,4642012 production (15,659) (15,659) (15,659)Net dispositions (7,693) (11,061) (16,882)Net additions and revisions 30,551 38,212 35,835 ---------------------------------PetroBakken reserves at December 31, 2012 81,309 131,359 206,758PetroBakken year-over-year increase in reserves 10% 10% 2%PetroBakken production replacement (7) (8) 195% 244% 229%----------------------------------------------------------------------------Notes:(1) Based on the Sproule price forecast effective December 31, 2012.(2) Company Gross reserves, which represent the Company's working interest share of reserves excluding the Company's royalty interests in reserves and before deduction of royalty obligations.(3) Royalty interest reserves owned by the Company.(4) "Company Interest" reserves, which represent the Company's working interest share of reserves including the Company's royalty interests in reserves and before deduction of the Company's royalty obligations.(5) Company working interest reserves value plus royalties received less royalties and burdens.(6) Estimated values of future net revenue disclosed in this press release do not represent fair market values.(7) Represents total reserve additions, including revisions and before dispositions, as a percentage of 2012 production.(8) The disclosures required in accordance with National Instrument 51-101 of the Canadian Securities Administrators will be available in the Company's Annual Information Form to be filed on the SEDAR website at http://www.sedar.com/ prior to March 31, 2013.F&D and FD&A Costs(1)For the year ended December 31, 2012 Acquisitions F&D & FD&A(3) Dispositions----------------------------------------------------------------------------Capital expenditures (unaudited- $000s) Capital expenditures $ 952,556 $ - $ 952,556 Acquisition/(Disposition) capital - (632,173) (632,173) ------------------------------------------- Total capital 952,556 (632,173) 320,383 Less: Land value 24,323 - 24,323 ------------------------------------------- Total capital excluding land value $ 928,233 $ (632,173) $ 296,060Change in FDC ($000s) Total Proved $ 72,620 $ (82,252) $ (9,632) Proved + Probable (2P) $ 5,545 $ (100,109) $ (94,564)----------------------------------------------------------------------------Total costs ($000s) Total Proved $ 1,025,176 $ (714,425) $ 310,752 Proved + Probable (2P) $ 958,101 $ (732,282) $ 225,819Net reserve additions (mboe) Total Proved 38,212 (11,061) 27,151 Proved + Probable (2P) 35,835 (16,882) 18,953----------------------------------------------------------------------------F&D and FD&A costs ($/boe) (including land) Total Proved $ 26.83 $ (64.59) $ 11.45 Proved + Probable (2P) 26.74 (43.38) 11.91FD&A costs ($/boe) (excluding land) Total Proved 26.19 (64.59) 10.55 Proved + Probable (2P) $ 26.06 $ (43.38) $ 10.63----------------------------------------------------------------------------For the year-ended Dec. 31, 2011F&D and FD&A costs ($/boe) (including land) Total Proved $ 40.20 $ (76.28) $ 39.43 Proved + Probable (2P) 31.22 (55.73) 30.74F&D and FD&A costs ($/boe) (excluding land) Total Proved 39.14 (76.28) 38.35 Proved + Probable (2P) $ 30.51 $ (55.73) $ 30.01For the 3 years-ended Dec. 31, 2012(2)F&D and FD&A costs ($/boe) (including land) Total Proved $ 33.98 $ (11.65) $ 35.63 Proved + Probable (2P) 28.37 (5.64) 30.71F&D and FD&A costs ($/boe) (excluding land) Total Proved 32.33 (66.70) 29.79 Proved + Probable (2P) $ 27.08 $ (37.66) $ 25.99----------------------------------------------------------------------------(1) 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 reserve additions for that year.(2) FD&A costs for 2010 include the corporate acquisitions of Berens Energy Ltd., Rondo Petroleum Inc., Result Energy Inc. and certain other asset acquisitions. For corporate acquisitions, acquisition costs represent the portion of the purchase prices allocated to property, plant & equipment and reflect the net present value of each corporate acquisition as at its acquisition date based on 2P NPV10%, before tax.(3) The Company uses FD&A as a measure of the efficiency of its overall capital program including the effect of acquisitions and dispositions.(4) Boe's may be misleading, particularly if used in isolation. A boe conversion ratio of 1 boe for 6 thousand cubic feet of natural gas is based on an energy equivalency conversion method primarily applicable at the burner tip and does not represent a value equivalency at the wellhead.



OPERATIONAL UPDATE

Production in January 2013, based on field estimates, was approximately 49,700 boepd (83% light oil and liquids), up from our fourth quarter 2012 average production of 47,192 boepd. In January, our Bakken business unit produced approximately 19,800 boepd and our Cardium business unit produced approximately 20,800 boepd, with the remainder of the production generated by our southeast Saskatchewan Conventional and AB/BC business units. During the month of January, production was negatively impacted by approximately 600 boepd due to restrictions at third-party facilities in the Cardium.

Currently we have 13 rigs operating in the field, with 6 in the Cardium, 4 in the Bakken, 1 in Southeast Saskatchewan, 1 in Swan Hills and 1 in a new play area. Drilling activity year to date has resulted in 39 (30 net) wells drilled, comprised of 13 (11 net) in the Bakken, 12 (10 net) in the Cardium, 9 (5 net) in our Saskatchewan Conventional business unit and 5 (4 net) on our emerging plays. Currently, we have 48 (36 net) wells at various stages of completion waiting to be brought on production.

With our active program at the end of 2012 generating strong production growth leading into year-end, we anticipate a base production profile that will have steeper declines in the first part of this year, followed by lower declines in the later part of the year. We have forecasted an average production decline rate from December 2012 to December 2013 of 39%. On a quarterly basis, our base production decline from fourth quarter 2012 to fourth quarter 2013 is expected to be 31%, normalizing the impacts of our strong production additions during December 2012. We now forecast 2014 base declines to range from 28% to 33%.

Our 2013 capital expenditure plan of $675 million is more balanced throughout the year, which will help us reduce production volatility and manage declines while delivering anticipated year-over-year average production growth of 8% to 12%.

REALIZED PRICES AND COMMODITY DIFFERENTIALS

North America is currently experiencing infrastructure challenges resulting from growth in domestic production of oil and gas due to the development of oil sands assets and the application of horizontal multi-stage fracturing technology. The impact has been felt across the continent through lower realized oil and gas prices, with WTI prices trading at a discount to Brent pricing and North American natural gas trading well below world prices. To compound the problem, increased production from Western Canada and the mid-western United States has resulted in additional discounts for crude produced in Canada. The biggest impact has been on the price other producers receive for heavy crudes, where discounts of 25% to 35% of WTI have been experienced. The current differential for our light oil production is approximately 7% off WTI, allowing us to benefit from realized pricing that is more favourable than our internal 2013 forecast of US$90/bbl WTI with a 10% differential.

Consistent with the rest of our industry, commodity price volatility will impact our results and we will continue to take steps to mitigate commodity price risks and attempt to optimize our rates of return.

DIVIDEND REINVESTMENT PROGRAM AND SHARE DIVIDEND PLAN

PetroBakken has a DRIP in place that is available only to Canadian PetroBakken shareholders. Our SDP is now available to both Canadian shareholders and most non-Canadian shareholders. The DRIP and the SDP allow shareholders to effectively receive their monthly PetroBakken dividends as PetroBakken shares at a 5% discount to the market price at the date of the dividend payment. Current combined DRIP and SDP participation is approximately 30%.

For further information regarding our SDP and DRIP, please visit PetroBakken's website at www.petrobakken.com or contact Olympia Trust Company at 403-668-8887, toll free at 1-800-727-4493 or via email at corporateactions@olympiatrust.com.

PetroBakken Energy Ltd. is an oil and gas exploration and production company combining light oil Bakken and Cardium resource plays with conventional light oil assets, delivering industry leading operating netbacks, strong cash flows and production growth. PetroBakken is applying leading edge technology to a multi-year inventory of Bakken and Cardium light oil development locations, along with a significant inventory of opportunities in the Horn River and Montney gas resource plays in northeast BC. Our strategy is to deliver accretive production and reserves growth, along with an attractive dividend yield.

Forward-Looking Statements

This press release contains forward-looking statements. More particularly, it contains forward-looking statements concerning 2013 production rates, potential exploration and development activities, our 2013 capital budget, potential drilling locations, timing for bringing restricted production on-stream and the future potential of enhanced oil recovery projects. The forward- looking statements are based on certain key expectations and assumptions, including expectations and assumptions concerning the availability of capital, the success of future drilling, completion, recompletion and development activities, the performance of existing wells, the performance of new wells, prevailing commodity prices and economic conditions, the cost and availability of labour and services, the ability to market our production, weather and access to drilling locations.

Although we believe that the expectations and assumptions on which the forward-looking statements are based are reasonable, undue reliance should not be placed on the forward-looking statements because we can give no assurance that they will prove to be correct. Since forward-looking statements address future events and conditions, by their very nature they involve inherent risks and uncertainties. Actual results could differ materially from those currently anticipated due to a number of factors and risks. These include, but are not limited to, risks associated with the oil and gas industry in general (e.g., operational risks in development, exploration and production; delays or changes in plans with respect to exploration or development projects or capital expenditures; the uncertainty of reserve estimates; the uncertainty of estimates and projections relating to production, costs and expenses; reliance on industry partners, availability of equipment and personnel, uncertainty surrounding timing for drilling and completion activities resulting from weather and other factors; changes in applicable regulatory regimes and health, safety and environmental risks), commodity price and exchange rate fluctuations and general economic conditions. Certain of these risks are set out in more detail in our Annual Information Form which has been filed on SEDAR and can be accessed at www.sedar.com. There is no representation by PetroBakken that actual results achieved during the forecast period will be the same in whole or in part as those forecast. Except as may be required by applicable securities laws, PetroBakken assumes no obligation to publicly update or revise any forward - looking statements made herein or otherwise, whether as a result of new information, future events or otherwise.

Caution Respecting BOE

When used in this press release, Boe means a barrel of oil equivalent on the basis of 1 Boe to 6 thousand cubic feet of natural gas. Boe per day means a barrel of oil equivalent per day. Boe's may be misleading, particularly if used in isolation . A Boe conversion ratio of 1 Boe for 6 thousand cubic feet of natural gas is based on an energy equivalency conversion method primarily applicable at the burner tip and does not represent a value equivalency at the wellhead. Given that the value ratio of oil compared to natural gas based on currently prevailing prices is significantly different than the energy equivalency conversion ratio of 6 Mcf to 1 BOE, utilizing a conversion ratio of 6 Mcf to 1 BOE may be misleading as an indication of value.



Contacts:
PetroBakken Energy Ltd.
John D. Wright
President and Chief Executive Officer
(403) 268.7800

PetroBakken Energy Ltd.
Peter D. Scott
Senior Vice President and Chief Financial Officer
(403) 268.7800

PetroBakken Energy Ltd.
Bill A. Kanters
Vice President Capital Markets
(403) 268.7800
www.petrobakken.com



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