Petrobank Announces 2011 Reserves and Heavy Oil Operational Update

CALGARY, ALBERTA--(Marketwire - March 8, 2012) - Petrobank Energy and Resources Ltd. ("Petrobank" or the "Company") (TSX:PBG) announces our year end 2011 reserves evaluation by McDaniel and Associates Consultants Ltd. ("McDaniel") and provides an operational update of our Heavy Oil Business Unit ("HBU") activities. May River reserves and contingent resources are provided for reference, however, as disclosed, this property was sold February 28, 2012.

All references to $ are Canadian dollars unless otherwise noted. All reserve and resource numbers presented herein are total company interest in such reserves or resources, unless otherwise noted. Total Company share includes Petrobank's 59% share of PetroBakken Energy Ltd. ("PetroBakken") reserves and net present values ("NPV").

SUMMARY

• THAI® proved reserves for the Kerrobert project have been adjusted to zero. Additionally, proved plus probable ("2P") reserves at Kerrobert were adjusted to 3.6 million barrels. These reductions were based upon the early start-up stage production levels at Kerrobert at year end 2011.
• THAI® proved plus probable plus possible ("3P") reserves recognized for the Kerrobert project are unchanged at 8.5 million barrels.
• Best estimate contingent bitumen resources based on steam assisted gravity drainage ("SAGD") associated with the May River property totalled 624 million barrels.
• Exploitable Oil-in-Place ("EOIP") (see "Exploitable Oil-in-Place") associated with our Plover and Luseland properties was recognized for the first time and totalled 28.7 million barrels; EOIP of all heavy oil properties totalled 80.5 million barrels.
• Positive production trend at our Kerrobert project with average daily production increasing from 30 barrels of oil per day ("bopd") in Q3 2011 to 41 bopd in Q4 2011 and averaging approximately 155 bopd for January and February 2012.
• PetroBakken's 2P reserves increased by 19% to 203.5 million barrels of oil equivalent ("MMboe") at December 31, 2011, replacing 2011 production by 315%.
• PetroBakken's Cardium business unit's 2P reserves increased by 66% in 2011, replacing production by 800%.
• PetroBakken's Bakken business unit's 2P reserves increased by 7% in 2011, replacing production by 173%.

CORPORATE RESERVES / RESOURCES SUMMARY BY BUSINESS UNIT

Company Interest(1)

	PetroBakken		HBU - Heavy Oil		HBU - Bitumen		Total Company(2	)
	(Mboe)(4	)	(Mbbls)(4	)	(Mbbls	)	(Mboe	)
Proved Developed Producing	74,110		-		-		43,725
Total Proved	119,867		-		-		70,722
Proved + Probable (2P)	203,464		3,598		90,603		214,245
Proved + Probable + Possible (3P)	203,464		8,490		102,982		231,516
Best Estimate Contingent Resources(3)	-		-		624,127		624,127

(1)	"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.
(2)	Total Company includes HBU reserves and resources and Petrobank's 59% share of PetroBakken reserves as at December 31, 2011.
(3)	See "Resources and Contingent Resources".
(4)	"Mboe" means thousand barrels of oil equivalent and "Mbbls" means thousand barrels.

Net Present Value, Before Tax, Forecast Prices ($ millions) (1)
	PetroBakken		HBU - Heavy Oil		HBU - Bitumen		Total Company(2	)
Proved Developed Producing	2,405.8		-		-		1,419.4
Total Proved	3,133.9		-		-		1,849.0
Proved + Probable (2P)	4,720.4		4.6		548.2		3,337.8
Proved + Probable + Possible (3P)	-		139.6		640.9		780.5
Best Estimate Contingent Resources	-		-		2,431.9		2,431.9

(1)	PetroBakken based on Sproule Associates Ltd.'s forecast prices. HBU based on McDaniel forecast bitumen and heavy oil netback prices. Interest expenses and corporate overhead were not included. Net present values are discounted at 10%. The net present values do not represent the fair market value of the reserves and/or resources.
(2)	Total Company includes HBU net present values and Petrobank's 59% share of PetroBakken net present value as at December 31, 2011.

The full reserve disclosure tables, as required under National Instrument 51-101, will be contained in the Company's Annual Information Form which will be filed on the SEDAR website at www.sedar.com later in March.

HBU RESERVES

Petrobank received the world's first THAI® reserves at our Kerrobert project for year-end 2010. At that time, we had two demonstration wells in operation for approximately 15 months and had initiated the full-field development of another 10 well-pairs and associated surface facilities. The Kerrobert project was operational with all 12 production wells capable of production in September, 2011. As the THAI® process builds, early stage production in late 2011 was less than what our original two demonstration wells were producing in late 2010. The demonstration wells had been on production for more than a year by late 2010. Because reserves are measured at year-end and the full-field development wells were showing lower production at that specific point in time, McDaniel lowered their estimate for proved and 2P production. This lower estimated production resulted in the proved production profile showing negative net present value and therefore caused the elimination of proved reserves. The lower estimated 2P production profile also resulted in a 25% decrease in proved plus probable reserves at December 31, 2011. There was no change to the proved, probable and possible (see "Possible Reserves") estimated production or reserves of 8.5 million barrels. In the near term, operating success at Kerrobert should result in significantly higher assigned reserves from Kerrobert's 18.7 million barrels of EOIP.

McDaniel has estimated EOIP at Dawson, Plover and Luseland of 33.2 million barrels, 3.5 million barrels and 25.1 million barrels, respectively. Including Kerrobert, total EOIP of all the Company's heavy oil properties was 80.5 million barrels.

McDaniel has continued to evaluate our Conklin and May River bitumen properties using SAGD extraction techniques as they have classified it as an immobile bitumen reservoir. 2P reserves at Conklin are essentially unchanged at 90.6 million barrels of bitumen. Best estimate contingent resources at May River are essentially unchanged compared to our June 1, 2011 update at 624 million barrels. These reserves and contingent resources were sold effective February 28, 2012.

HBU RESERVES / RESOURCES SUMMARY

The following tables summarize the McDaniel report as at December 31, 2011 and 2010. Reserves were assigned to the Conklin, Alberta pilot project and our Kerrobert, Saskatchewan property (4 sections) and contingent resources were assigned to our May River leases (62 sections) near Conklin. The McDaniel report does not include any reserves or recoverable resources associated with our Glover lease (10 sections), our Sutton Creek lease (36 sections), our Plover and Luseland properties (11 sections), or our Dawson property (31.5 sections).

Reserves and Resources (1)as of December 31,	2011		2010		Change
	(MMbbl	)	(MMbbl	)	%
Kerrobert
Proved Reserves (P)	0.0		3.0		(100	)
Proved plus Probable Reserves (2P)	3.6		4.8		(25	)
Proved plus Probable plus Possible Reserves (3P) (2)	8.5		8.5		0
Conklin and May River Properties (sold Feb. 28, 2012)
Proved Reserves (P)	0.0		0.0		n/a
Proved plus Probable Reserves (2P)	90.6		90.6		0
Proved plus Probable plus Possible Reserves (3P) (2)	103.0		101.5		1
Low Estimate Contingent Resources (3) (4)	484.9		474.0		2
Best Estimate Contingent Resources (3) (4)	624.1		560.1		11
High Estimate Contingent Resources (3) (4)	793.0		697.2		14

(1)	Gross reserves and/or resources include the working interest reserves/resources excluding the Company's royalty interests in reserves and before deductions of royalties payable to others.
(2)	Possible reserves are those additional reserves that are less certain to be recovered than probable reserves. See "Possible Reserves".
(3)	Contingent resources, as evaluated by McDaniel, are those quantities of bitumen estimated to be potentially recoverable using SAGD technology from known accumulations but are classified as a resource rather than a reserve primarily due to the absence of regulatory approvals, detailed design estimates and near term development plans and are in addition to 3P reserves. See "Resources and Contingent Resources".
(4)	A low estimate means higher certainty (P90), a best estimate (P50) means most likely and a high estimate means lower certainty (P10).

Before Tax Net Present Value - December 31, 2011 - $Millions (1) (2) (3)
Net Present Value Discounted at:	0	%	5	%	8	%	10	%
Kerrobert
Proved Reserves (1P)	0		0		0		0
Proved plus Probable Reserves (2P)	11		7		6		5
Proved plus Probable plus Possible Reserves (3P)	240		180		154		140
Conklin and May River Properties (sold Feb. 28, 2012)
Proved Reserves (1P)	0		0		0		0
Proved plus Probable Reserves (2P)	2,365		1,081		712		548
Proved plus Probable plus Possible Reserves (3P)	3,012		1,290		835		641
Low Estimate Contingent Resources	11,312		4,243		2,429		1,681
Best Estimate Contingent Resources	16,438		6,010		3,463		2,432
High Estimate Contingent Resources	22,677		8,230		4,774		3,387

(1)	Based on McDaniel forecast bitumen and heavy oil netback prices.
(2)	Interest expenses and corporate overhead were not included.
(3)	The net present values do not represent the fair market value of the reserves and/or resources.

HEAVY OIL BUSINESS UNIT OPERATIONAL UPDATE

Kerrobert Project

Fourth quarter 2011 production increased to 41 bopd from 30 bopd in the third quarter. This trend of increasing production continued in early 2012 with average January and February production of approximately 155 bopd. We have recently begun to see upgraded THAI® oil, with typical API gravity in the 13 degree range compared to native oil with 10 degree API.

During our third quarter 2011 operational update, we disclosed that our operational plan at Kerrobert was to continue to optimize air injection rates in order to gradually build out the combustion front, increase the overall pressure in the reservoir and to increase sustained production of upgraded THAI® oil. We are managing operations based on this plan and continue to optimize the THAI® process in a consistent and patient operating manner to progressively increase THAI® production.

Dawson Demonstration Project

As previously disclosed in mid-December 2011, we have elected to defer further work on the Dawson project until the second quarter of 2012. We will reassess development plans after spring break-up.

Plover Property

During 2012, we drilled three stratigraphic wells at our Plover Property. We continue to develop plans to further evaluate and develop this property.

Archon Technologies Ltd. ("Archon")

During the fourth quarter 2011, Archon filed three THAI® related patents that will contribute to extending the patent life of our technology and enhancing the scope of the THAI® process.

PETROBAKKEN (59% OWNED BY PETROBANK)

PetroBakken announced year end reserves on February 27, 2012, highlighted as follows:

• PetroBakken's 2P reserves increased by 19% to 203.5 MMboe at December 31, 2011, replacing 2011 production by 315%.
• PetroBakken's average light oil weighting of their reserves is 80%; 85% when natural gas liquids are included.
• PetroBakken delivered finding, development and net acquisition ("FD&A") costs of $18.95/boe excluding changes in Future Development Capital ("FDC"), and $30.74/boe, including changes in FDC.
• PetroBakken's Cardium business unit increased 2P reserves by 66% in 2011, replacing production by 800%. Incremental 2P reserve additions in this business unit of 32.7 MMboe resulted in total 2P reserves of 72.2 MMboe at the end of the year.
• PetroBakken's Bakken business unit increased 2P reserves by 7% in 2011, replacing production by 173%. The 2P reserves for the Bakken increased by 12.9 MMboe and at year-end totalled 88.5 MMboe.

PetroBakken Reserves

Forecast Prices(1)

As at December 31, 2011	Company Gross(2)								Royalty Interests(3	)	PetroBakken Interest(4	)
	Total Oil (Mbbl	)	NGL (Mbbl	)	Natural Gas (MMcf	)	Sub-total (Mboe	)	Sub-total (Mboe	)	Total (Mboe	)
Proved Developed Producing	57,800		4,170		67,825		73,274		836		74,110
Total Proved	95,397		6,279		103,292		118,891		976		119,867
Proved + Probable (2P)	161,665		10,745		176,919		201,897		1,568		203,464

PetroBakken Net Present Value - Before Tax ($millions)(5)(6)
Forecast Prices(1)
As at December 31, 2011
	0	%	5	%	10	%
Proved Developed Producing	3,724.1		2,887.9		2,405.8
Total Proved	5,328.8		3,932.9		3,133.9
Proved + Probable (2P)	9,691.7		6,354.8		4,720.4

PetroBakken Net Present Value - After Tax ($millions)(5)(6)
Forecast Prices(1)
As at December 31, 2011
	0	%	5	%	10	%
Proved Developed Producing	3,367.5		2,638.8		2,215.6
Total Proved	4,548.2		3,377.0		2,701.8
Proved + Probable (2P)	7,755.8		5,139.0		3,839.1

Working Interest Reserve Reconciliation (Mboe)(2)
Forecast Prices(1)
As at December 31, 2011
	Developed		Total		Proved+
	Producing		Proved		Probable
PetroBakken reserves at December 31, 2010	65,326		102,003		169,816
2011 production net of royalty interest	(14,773	)	(14,773	)	(14,773	)
Net dispositions	(433	)	(677	)	(927	)
Net additions and revisions	23,154		32,338		47,781
PetroBakken reserves at December 31, 2011	73,274		118,891		201,897
PetroBakken year-over-year increase in reserves	12	%	17	%	19	%
PetroBakken production replacement	157	%	219	%	323	%

Notes:
(1)	Based on the Sproule price forecast effective December 31, 2011.
(2)	Company Gross reserves, which represent PetroBakken's working interest share of reserves excluding PetroBakken's royalty interests in reserves and before deduction of royalty obligations.
(3)	Royalty interest reserves owned by PetroBakken.
(4)	"PetroBakken Interest" reserves, which represent PetroBakken's working interest share of reserves including PetroBakken's royalty interests in reserves and before deduction of PetroBakken's royalty obligations.
(5)	PetroBakken 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)	The disclosures required in accordance with National Instrument 51-101 of the Canadian Securities Administrators will be available in PetroBakken's Annual Information Form to be filed on the SEDAR website at http://www.sedar.com/ prior to March 31, 2012.

PetroBakken FD&A Costs(1)

For the year ended December 31, 2011

		F&D		Acquisitions & Dispositions		FD&A(3	)
Capital expenditures (unaudited-$000s)
	Capital expenditures	943,271		-		943,271
	Acquisition/(Disposition) capital(2)	-		(51,631	)	(51,631	)
	Total capital	943,271		(51,631	)	891,640
	Less: Land value	34,289		-		34,289
	Total capital excluding land value	908,982		(51,631	)	857,351
Change in FDC ($000s)
	Total Proved	362,379		-		362,379
	Proved + Probable (2P)	555,147		(26	)	555,121
Total costs ($000s)
	Total Proved	1,305,650		(51,631	)	1,254,019
	Proved + Probable (2P)	1,498,418		(51,657	)	1,446,761
Net reserve additions (mboe)
	Total Proved	32,480		(677	)	31,803
	Proved + Probable (2P)	47,989		(927	)	47,063
FD&A costs ($/boe) (including land)
	Total Proved	40.20		76.26		39.43
	Proved + Probable (2P)	31.22		55.73		30.74
FD&A costs ($/boe) (excluding land)
	Total Proved	39.14		76.26		38.35
	Proved + Probable (2P)	30.51		55.73		30.01
For the year-ended Dec. 31, 2010(4)
FD&A costs ($/boe) (including land)
	Total Proved	37.19		129.41		55.07
	Proved + Probable (2P)	26.11		105.91		39.31
FD&A costs ($/boe) (excluding land)
	Total Proved	32.93		129.41		38.86
	Proved + Probable (2P)	23.35		105.91		28.47
For the year-ended Dec. 31, 2009
FD&A costs ($/boe) (including land)
	Total Proved	45.22		47.12		46.83
	Proved + Probable (2P)	33.02		32.38		32.48
FD&A costs ($/boe) (excluding land)
	Total Proved	40.52		47.12		42.56
	Proved + Probable (2P)	30.37		32.38		29.81
For the three years-ended Dec. 31, 2011
FD&A costs ($/boe) (including land)
	Total Proved	39.83		54.83		46.76
	Proved + Probable (2P)	29.70		38.08		33.58
FD&A costs ($/boe) (excluding land)
	Total Proved	37.15		44.52		40.56
	Proved + Probable (2P)	27.97		31.41		29.56

(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)	Portion of the purchase prices allocated to property, plant & equipment and reflects the net present value of each corporate acquisition as at its acquisition date based on 2P NPV10%, before tax.
(3)	PetroBakken uses FD&A as a measure of the efficiency of its overall capital program including the effect of acquisitions and dispositions.
(4)	Included the corporate acquisitions of Berens Energy Ltd., Rondo Petroleum Inc., Result Energy Inc. and certain other asset acquisitions.

FINANCIAL STATEMENT RELEASE DATE AND INVESTOR CONFERENCE CALL

Petrobank plans to release fourth quarter 2011 financial results after markets close on Wednesday, March 14, 2012. Management of Petrobank will be holding a conference call for investors, financial analysts, media and any interested persons on Thursday, March 15, 2012 at 9:00 a.m. Mountain Time (11:00 a.m. Eastern Time) to discuss Petrobank's fourth quarter financial and operating results. The investor conference call details are as follows:

Live call dial-in numbers:	416-695-6616 / 800-952-6845
Replay dial-in numbers:	905-694-9451 / 800-408-3053
Replay pass code:	4657181

The live audio webcast link is: http://events.digitalmedia.telus.com/petrobank/031512/index.php.

Petrobank Energy and Resources Ltd. is a Calgary-based oil and natural gas exploration and production company with operations in western Canada. The Company operates high-impact projects through two business units and a technology subsidiary. Petrobank's 59% owned TSX-listed subsidiary, PetroBakken Energy Ltd. (TSX:PBN), is an oil and gas exploration and production company combining light oil Bakken and Cardium resource plays with conventional light oil assets. Whitesands Insitu Partnership, a partnership between Petrobank and its wholly-owned subsidiary Whitesands Insitu Inc., applies Petrobank's patented THAI® heavy oil recovery process in the field. THAI® is an evolutionary in-situ combustion technology for the recovery of bitumen and heavy oil. THAI® and CAPRI® are registered trademarks of Archon Technologies Ltd., a wholly-owned subsidiary of Petrobank Energy and Resources Ltd., for specialized methods for recovery of oil from subterranean formations through in-situ combustion techniques and methodologies with or without upgrading catalysts. Used under license by Petrobank Energy and Resources Ltd.

Forward-Looking Statements: Certain information provided in this press release constitutes forward-looking statements. Specifically, this press release contains forward-looking statements relating to financial results, results from operations, the timing of certain projects, anticipated recovery factors, future oil and gas exploration and development activities, potential resource and reserve increases and future production rates. Forward-looking statements are necessarily based upon assumptions and judgments with respect to the future including, but not limited to, the outlook for commodity markets and capital markets, success of future evaluation and development activities, the successful application of technology, prevailing commodity prices, the performance of producing wells and reservoirs, well development and operating performance, general economic and business conditions, weather, and the regulatory and legal environment. The reader is cautioned that assumptions used in the preparation of such information, although considered reasonable at the time of preparation, may prove to be incorrect. Actual results achieved during the forecast period will vary from the information provided herein as a result of numerous known and unknown risks and uncertainties and other factors. You can find a discussion of those risks and uncertainties in our Canadian securities filings. Such factors include, but are not limited to: general economic, market and business conditions; fluctuations in oil prices; the results of exploration and development drilling, risks associated with the development and application of early stage technology, recompletions and related activities; timing and rig availability; fluctuation in foreign currency exchange rates; the uncertainty of reserve and resource estimates; changes in environmental and other regulations; risks associated with oil and gas operations; and other factors, many of which are beyond the control of the Company. There is no representation by Petrobank 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, Petrobank 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.

Resources and Contingent Resources: In this press release, Petrobank has disclosed estimated volumes of "contingent resources". "Resources" are oil and gas volumes that are estimated to have originally existed in the earth's crust as naturally occurring accumulations but are not capable of being classified as "reserves". "Contingent resources" are those quantities of petroleum estimated, as of a given date, to be potentially recoverable from known accumulations using established technology or technology under development, but which are not currently considered to be commercially recoverable due to one or more contingencies. In respect of the May River project, contingencies include current uncertainties around the specific scope and timing of the development of the project; lack of regulatory approvals; uncertainty regarding marketing plans for production from the subject area; and need for improved estimation of project costs. Contingent resources do not constitute, and should not be confused with, reserves. Petrobank disposed of the May River property following the date of the McDaniel evaluation and there is no certainty that it will be commercially viable to produce any portion of the contingent resources on the May River property.

Possible Reserves: Possible reserves are those additional reserves that are less certain to be recovered than probable reserves. There is a 10% probability that the quantities actually recovered will equal or exceed the sum of proved plus probable plus possible reserves.

Exploitable Oil-In-Place (EOIP): Exploitable Oil in Place is the estimated discovered volume of oil, from known accumulations, before any production has been removed, which is contained in a subsurface stratigraphic interval that meets or exceeds certain reservoir characteristics considered necessary for the application of known recovery technologies. Examples of such reservoir characteristics include continuous net pay, porosity, and mass bitumen content. EOIP is a resources that does not constitute, and should not be confused with, reserves. There is no certainty that it will be commercially viable to produce any portion of the resource.

Net Present Values (NPV): Estimated values of future net revenue disclosed in this press release do not necessarily represent fair market values.

Barrels of Oil Equivalent: Disclosure provided in this press release in respect of barrels of oil equivalent ("boe") units may be misleading, particularly if used in isolation. A boe conversion relationship of 6 mcf to 1 bbl is based on an energy equivalency conversion method primarily applicable at the burner tip and does not represent a value equivalency at the well head.