Petrobank Announces 2010 Reserves, Including First THAI(R) Reserves, and Heavy Oil Operational Update

CALGARY, ALBERTA--(Marketwire - March 10, 2011) - Petrobank Energy and Resources Ltd. ("Petrobank" or the "Company") (TSX:PBG) is pleased to announce our year end 2010 reserves evaluation and to provide an operational update of our Heavy Oil Business Unit ("HBU") activities. Our independent reserves evaluator, McDaniel & Associates Consultants Ltd. ("McDaniel"), has assigned the first THAI^® proven reserves at our Kerrobert project.

All references to $ are Canadian dollars unless otherwise noted. Total Company share includes Petrobank's 59% share of PetroBakken Energy Ltd. ("PetroBakken") reserves and net present values ("NPV"). When referencing 2009 for comparative purposes, Total Company share of reserves and net present value excludes reserves and NPV related to Petrominerales Ltd. as Petrobank's ownership in Petrominerales Ltd. was distributed to our shareholders on December 31, 2010.

HIGHLIGHTS

• THAI^® proved and proved plus probable ("2P") reserves recognized for the Kerrobert project are 3.0 million barrels and 4.8 million barrels, respectively, with before tax NPV at 8% of $6.2 million and $46.0 million, respectively.
• McDaniel forecast that the THAI^® sales oil price at Kerrobert will receive a 10% percent premium over conventional native quality heavy oil.
• HBU 2P reserves increased 36% to 95.4 million barrels with NPV, before tax, discounted at 8% increasing 50% to $724 million at December 31, 2010.
• HBU best estimate contingent bitumen resources totalled 560 million barrels with NPV, before tax, discounted at 8% of $3.0 billion (see "Contingent Resources").
• PetroBakken Company Interest 2P reserves increased by 18% to 171.4 million barrels of oil equivalent ("MMboe") at December 31, 2010.
• PetroBakken replaced 274% of production as a result of operations and acquisitions less dispositions.
• PetroBakken NPV (before tax, discounted at 10%) of 2P reserves increased by 13% to $4.1 billion.
• Petrobank Total Company 2P reserves increased by 21% to 196.5 MMboe.
• Petrobank Total Company 2P NPV, before tax and discounted by 10% for PetroBakken and 8% for HBU, increased by 12% to $3.2 billion.

CORPORATE RESERVES / RESOURCES SUMMARY BY BUSINESS UNIT
Company Interest⁽¹⁾, Forecast Prices 

	PetroBakken		HBU – Heavy Oil		HBU - Bitumen		Total Company(2)
	(Mboe	)	(Mbbls	)	(Mbbls	)	(Mboe	)
Developed Producing	66,183		575		-		39,623
Total Proved	103,028		3,032		-		63,819
Proved + Probable (2P)	171,377		4,837		90,572		196,521
Best Estimate Contingent Resources(3)	-		-		560,131		560,131

⁽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 only Petrobank's 59% share of PetroBakken reserves as at December 31, 2010.
⁽³⁾   See "Contingent Resources".

Net Present Value, Before Tax, Forecast Prices ($ millions) (1)
	PetroBakken			HBU –  Heavy Oil			HBU – Bitumen			Total Company(2)
Developed Producing	$	2,135		$	2			-		$	1,262
Total Proved	$	2,845		$	6			-		$	1,685
Proved + Probable (2P)	$	4,142		$	46		$	678		$	3,168
Best Estimate Contingent Resources		-			-		$	3,000		$	3,000

⁽¹⁾ 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% for PetroBakken and at 8% for the HBU. The net present values do not represent the fair market value of the reserves and/or resources.
⁽²⁾ Total Company includes only Petrobank's 59% share of PetroBakken net present value as at December 31, 2010.

Price Forecasts⁽¹⁾

	PetroBakken				HBU
	AECO Natural Gas(1)		WTI Crude Oil(1)		WTI Crude Oil(1)		Kerrobert THAI® Oil at Fieldgate(2)		Conklin SAGD Bitumen at Fieldgate(2)
Year	($/Mcf	)	(US$/bbl	)	(US$/bbl	)	(CDN$/bbl	)	(CDN$/bbl	)
2011	4.04		88.40		85.00		62.69		56.41
2012	4.66		89.14		87.70		64.66		58.32
2013	4.99		88.77		90.50		64.09		56.82
2014	6.58		88.88		93.40		66.16		58.66
2015	6.69		90.22		96.30		68.34		60.65
2016	6.80		91.57		99.40		70.61		62.69
Thereafter inflation rate	1.50	%	1.50	%	2.00	%	2.00	%	2.00	%

⁽¹⁾ Sproule Associates Ltd.'s ("Sproule")'s (PetroBakken) US$/CDN$ forecast rate is 0.932 and McDaniel's (HBU) is 0.975 throughout all years.
⁽²⁾  Actual prices used were adjusted for crude oil and bitumen quality differentials, natural gas heat content, transportation and marketing costs specific to the Company's operations. Price forecasts were provided by McDaniel in respect of HBU and Sproule in respect of PetroBakken.
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 is pleased to announce we have achieved a significant milestone with the recognition by McDaniel of THAI^® reserves at our Kerrobert project. This third party validation of the THAI^® technology confirms that THAI^® is able to economically extract oil in a reservoir that had previously been conventionally produced. This Waseca Channel reservoir has been drilled and in production for most of the past 30 years, yet over 90% of the petroleum initially-in-place ("PIIP") is estimated to be otherwise unrecoverable using conventional recovery methods. The THAI^® technology has allowed us to create sizable incremental value from this previously non-producing resource. McDaniel has initially assigned 3.0 million barrels of proved reserves and 4.8 million barrels of 2P reserves as at December 31, 2010, a significant first step in recognizing the ultimate reserves potential of this field. McDaniel also assigned proved, probable and possible reserves of 8.5 million barrels, representing a 46% recovery factor (see "Possible Reserves"). As this is the first year for THAI^® reserve recognition, we anticipated a conservative assessment by McDaniel in assigning 2P reserves representing only 26% of exploitable oil-in-place ("EOIP") at Kerrobert. Over time, we anticipate that ultimate recovery factors may achieve planned rates of 65% - 75% of EOIP.

Starting in 2009, McDaniel conducted extensive bottom up analysis of the THAI^® technology and subsequently validated THAI^® by issuing the THAI^® Transition Report, as previously disclosed. The McDaniel THAI^® Transition Report stated that EOIP evaluated using THAI^® is 17% higher than EOIP evaluated using steam assisted gravity drainage ("SAGD") extraction in our Conklin bitumen pool. Throughout 2010, Petrobank has demonstrated improved on-stream times and production levels at our Kerrobert two well-pair project. At year-end 2010, production levels were at economic rates with consistent on-stream times, leading to McDaniel's initial reserve recognition. McDaniel has also recognized the incremental value of THAI^®'s in-situ upgrading with sales oil revenues projected at approximately 10% higher than those for conventional heavy oil at Kerrobert.

McDaniel also used Kerrobert as an analogue for their evaluation of our Dawson property. McDaniel has assigned 32.5 million barrels of EOIP at Dawson (see "Exploitable Oil-in-Place"). McDaniel is not yet able to assign reserves as it is too early in this project's development. McDaniel has confirmed that they will continue to use Kerrobert, and future THAI^® projects, as analogues for other heavy oil reservoirs that may ultimately be developed with THAI^®.

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. McDaniel has elected for this report to continue to estimate our reserves and contingent resources at Conklin/May River assuming a SAGD development. 2P reserves at Conklin have increased by 29% to 90.6 million barrels of bitumen. Best estimate contingent resources at May River have decreased 7% to 560 million barrels, primarily as a result of our 2010 oil sands evaluation drilling results which slightly modified pool boundaries.

We believe that initial THAI^® reserve recognition at Kerrobert is a fundamental milestone for the THAI^® technology and with continued operating success we expect to be able to use THAI^® as the basis for assigning reserves to all our heavy oil and bitumen resources.

HBU RESERVES / RESOURCES SUMMARY

The following tables summarize the McDaniel report as at December 31, 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) at 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), or our Dawson property (31.5 sections).

Reserves and Resources (1) as of December 31,	2010		2009		Change
	(MMbbl	)	(MMbbl	)	%
Proved Reserves (P)	3.0		0.0		n/a
Proved plus Probable Reserves (2P)	95.4		70.0		36
Proved plus Probable plus Possible Reserves (3P) (2)	110.0		78.8		40
Low Estimate Contingent Resources (3) (4)	474.0		483.2		(2	)
Best Estimate Contingent Resources (3) (4)	560.1		599.1		(7	)
High Estimate Contingent Resources (3) (4)	697.2		738.9		(6	)

⁽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 "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, 2010 - $ Millions (1) (2) (3)
Net Present Value Discounted at:	0	%	5	%	8	%	10	%
Proved Reserves (1P)	20		11		6		4
Proved plus Probable Reserves (2P)	2,405		1,102		724		555
Proved plus Probable plus Possible Reserves (3P)	3,163		1,405		929		722
Low Estimate Contingent Resources	10,180		3,923		2,190		1,450
Best Estimate Contingent Resources	14,088		5,258		3,000		2,067
High Estimate Contingent Resources	20,413		6,821		3,794		2,615

⁽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 Expansion Project

Drilling and facilities construction activity levels at the Kerrobert 10 well-pair expansion have progressed rapidly since the project got underway during Q3 2010. We commenced the pipeline infrastructure construction in late September 2010 and shortly thereafter we began construction of the central processing facility ("CPF"), which is now 75% complete. The first of two air injection pads is complete and we are currently tying in the first of four production satellites. The CPF is expected to be operational by mid-April. Temporary steam generating facilities for the pre-ignition heating cycle ("PIHC") are in place and are in operation on the first air injection pad. Drilling and completion of all 10 air injection wells is complete and three of the new horizontal production wells are drilled and in the process of being completed. We also abandoned the 13 pre-existing vertical and horizontal cold production wells on the property. Facilities, drilling and completions operations are generally on schedule except for the horizontal drilling program which is currently four weeks delayed, due to early start-up issues with the drilling rig and extreme cold weather conditions. We are implementing changes to the drilling operations to return the program close to schedule, including mobilizing an additional drilling rig, which should see all of the production wells completed by the end of May. The drilling of the horizontal wells has met or exceeded our design parameters with respect to trajectory and relationship to the air injection wells. These wells are larger in diameter, have a higher open flow area to the reservoir, a tighter mesh in the FacsRite™ screen for improved solids control and an improved wellhead configuration, all of which are expected to result in improved production capability.

We initiated the PIHC in three injector wells on the first pad on March 6^th. The PIHC will be performed only on the injection wells to condition the reservoir and establish communication with the production well prior to air injection. According to our start-up protocol, the PIHC is expected to last 20 to 60 days. We expect air injection and production on these first expansion wells to commence in the second quarter of 2011 with sustained target production in each well being reached approximately one year after first air injection. The PIHC on the second pad of five injector wells is planned for late in the second quarter of 2011. We expect to have all of the new wells on air injection and producing THAI^® oil by the end of July. 

Since the beginning of the year, the on-stream time of the two pilot wells has improved dramatically to approximately 95 percent. For the past few months we have been operating the wells in a controlled state to minimize downtime and pump changes to ensure stability of economic production rates. The majority of production continues to come from the KP2 well which was drilled relatively flat as compared to the KP1 well where the toe is located higher in the reservoir, adversely affecting communication with the combustion front and well control. The well configuration for the 10 new producer wells will mitigate this issue as they are planned to be drilled similar to KP2. We are evaluating a remediation strategy for KP1 to improve communication with the mobile oil zone and improve production. Peak production rates for the two wells combined have been as high as 355 barrels of oil per day ("bopd") in the last four months. From December 1, 2010 to February 28, 2011, average calendar day production rate from the KP2 well has been approximately 121 bopd and KP1 has been approximately 35 bopd. The produced oil has been consistently upgraded in-situ by 4 - 7 degrees API, requiring less diluent to meet pipeline API quality. Since we have achieved our objective of formal reserves recognition at Kerrobert, we will focus on increasing production towards design capacity of 600 bopd per well. Under normal operations, design capacity is expected to be achieved approximately one-year after air injection has commenced.

Dawson Project

The Dawson property is situated in a large Bluesky heavy oil/oil sands fairway in the Peace River region of northwest Alberta. The upper portions of this formation contain 11° API heavy oil, which is comparable to other conventional heavy oil reservoirs throughout Western Canada. Existing conventional cold production typically recovers less than 10 percent of PIIP; with THAI^® we expect to achieve significantly higher recovery rates.

Based on a 2010 McDaniel evaluation of the resource, the Dawson property was estimated to contain best estimate EOIP (10 metre reservoir thickness cut-off) of 32.5 million barrels (see "Exploitable Oil-in-Place"). As we reported last fall, Petrobank acquired Shell's 50% working interest in the Dawson project and a 100% working interest in an additional 27 sections of land prospective for Bluesky heavy oil resource adjacent to the Dawson project. As a result of this acquisition, we now have a 100 percent interest in 31.5 sections of land in the Dawson area.

We received final Energy Resources Conservation Board ("ERCB") and Alberta Environment ("AENV") approval for our initial Dawson project during the fourth quarter of 2010. Dawson will initially consist of two THAI^® well-pairs plus associated surface facilities. We intend to move the surface facilities from our first two wells at the Kerrobert project, as they will be incorporated into the Kerrobert expansion facilities, to our Dawson project during the third quarter of 2011. We anticipate work on the initial Dawson project to begin during the second quarter of 2011 with PIHC commencing during the third quarter. Production is expected to commence in the fourth quarter of 2011 with ramp-up to design capacity over the following twelve months.

Also at Dawson we will be drilling a minimum of three stratigraphic wells to expand the geological extent of the reservoir. All wells will be cored through the Bluesky/Gething for rock property analysis and one well will be drilled deeper to test the Pekisko which also has heavy oil potential across our additional 27 sections of land offsetting the project.

In order to capitalize on the full potential at Dawson, the environmental assessment associated with a regulatory application has been started for the second phase of the Dawson development. Phase II is being designed as a 10,000 bopd project and the required regulatory applications for both the ERCB and AENV are scheduled to be submitted during the third quarter of 2011. The regulatory review cycle could take up to 18 months with a project execution time similar to our Kerrobert project.

Conklin Pilot Project

We continue to evaluate our Conklin pilot project for the demonstration of potential enhancements to the THAI^® process. To date, Conklin has proven the operation and effectiveness of THAI^® in a bitumen reservoir. The project has confirmed that we can ignite and sustain high temperature combustion and through the use of 4-D seismic we have been able to establish that the combustion front progresses along the wellbore from toe-to-heel. We have also demonstrated the ability to manage and control the combustion front and the overall safe operation of the THAI^® process. After some initial challenges with sand production, we deployed FacsRite^™ liners in two wells, which overcame the problem and is now being incorporated in to all our future THAI^® well designs. The Conklin pilot has also demonstrated that the process is operationally robust and that the process produces in-situ upgraded oil that can attract a premium field price compared to native oil. The original well design and surface facilities at Conklin have provided excellent prototype modelling for current design enhancements which we are employing in all of our new facilities. Unfortunately, the original wells are sub optimal for continued operation. In addition, the localized reservoir at Conklin remains a challenge as it is of poorer quality with relatively thin basal sand sections (five to eight metres) in the toe area of the wells, resulting in low initial sustainable production rates. The reservoir quality improves closer to the heel of the wells to over 15 metres of basal sands. We are reviewing options to utilize Conklin as a field testing facility for technology enhancements, which may include drilling new injector and production wells in better parts of the reservoir.

May River Project

The May River project is currently in the final detailed engineering phase, and orders have been placed for some long lead time equipment, including power generation turbines and air compression. Upgrades to the existing roads have been completed, along with other infrastructure work that can be accomplished prior to receiving final regulatory approval. Draft approval from AENV, which is conditional on receiving ERCB approval, was received on April 12, 2010. ERCB project approval remains in process, with a third round of supplemental information requests having been received and responded to in early 2011.

We plan to drill 12 to 17 stratigraphic wells on our leases this year to further evaluate additional resource potential, optimize well placements for the 18 well-pairs planned for the 10,000 bopd Phase 1 development and further delineate the resource for future expansion phases of the May River project.

Archon Technologies Ltd. ("Archon")

Archon, our wholly-owned technology subsidiary, was granted additional patents in Russia and Mexico during the fourth quarter of 2010 and first quarter of 2011, respectively. Further research is continuing and we expect field scale testing of new concepts, such as enriched oxygen injection and direct oxidation of sulphur in produced gas, during 2011.

Business Development

We remain engaged with several parties interested in licensing the THAI^® and CAPRI^® technologies. Although an agreement has not been finalized to date, we continue to make progress in the negotiation of formal agreements with respect to potential licensing arrangements.

Land Acquisition

Petrobank acquired 3.5 sections (907.7 hectares) of land in a Saskatchewan Crown Sale in late 2010. The lands are located in the Plover Area on the same trend as the Kerrobert project. We plan to purchase or shoot 3-D seismic and drill a stratigraphic well in 2011 to further define the resource potential.

PETROBAKKEN (59% OWNED BY PETROBANK)

PetroBakken announced year end reserves on February 21, 2011, highlighted as follows:

• 2010 average production of 41,688 boepd increased 58% over 2009.
• Proved plus probable Company Interest⁽¹⁾ reserves increased by 18% to 171.4 MMboe at December 31, 2010, replacing production by 274% (2P Company Gross⁽²⁾ reserves increased 18% to 169.2 MMboe).
• Our new entry into the Cardium play in Alberta during 2010, through three corporate acquisitions and our initial drilling campaign, has yielded incremental 2P reserve additions of 43 MMboe. Our first 55 operated wells drilled in 2010 resulted in reserve recognition for 149 of our undeveloped Pembina Cardium locations (out of our current inventory of over 650). This drilling campaign has accelerated into 2011.
• From July 2010 to mid-February 2011, PetroBakken drilled 80 (65.9 net) PetroBakken-executed Cardium wells, of which:
  • 44 (39 net) wells are producing,
  • 16 (11.4 net) wells are completed but not yet producing, and
  • 20 (15.5 net) wells are waiting on completion. 
• Production results from single-leg horizontal multi-stage fracture stimulated Cardium wells continue to meet expectations with:
  • seven day average rates of 423 barrels of oil per day ("bopd") from 40 wells,
  • thirty day average rates of 246 bopd from 38 wells, and
  • sixty day average rates of 176 bopd from 21 wells. 
• In PetroBakken's 2010 reserve report, producing Bakken bilateral horizontal wells received, on average, an incremental 35,000 barrels ("bbls") of oil over 2009 reserve assignments for 2P undeveloped bilateral horizontal locations. 
• Activity in the Bakken play continues to move forward with bilateral drilling and enhanced oil recovery ("EOR") projects.

Notes:
⁽¹⁾ "Company Interest" reserves represent PetroBakken's working interest share of reserves including its royalty interests in reserves and before deduction of the Company's royalty obligations.
⁽²⁾ "Company Gross" reserves represent PetroBakken's working interest share of reserves excluding its royalty interests in reserves and before deduction of royalty obligations.

PetroBakken Reserves
Forecast Prices⁽¹⁾ 

As at December 31, 2010	Company Gross(2)								Royalty Interests (3)		Company Interest(4)
	Total Oil (Mbbl	)	NGL (Mbbl	)	Natural Gas (MMcf	)	Sub-total (Mboe	)	Sub-total (Mboe	)	Total (Mboe	)
Proved Developed Producing	50,888		3,807		63,790		65,326		857		66,183
Total Proved	80,866		5,414		94,337		102,003		1,025		103,028
Proved + Probable (2P)	136,153		8,871		148,754		169,816		1,561		171,377

PetroBakken Net Present Value – Before Tax ($ millions)(5)
Forecast Prices(1)
As at December 31, 2010
	0	%	5	%	8	%	10	%	15	%
Proved Developed Producing	3,355.3		2,574.1		2,285.9		2,135.0		1,849.3
Total Proved	4,765.3		3,541.1		3,084.3		2,844.8		2,392.2
Proved + Probable (2P)	8,367.7		5,521.1		4,598.1		4,141.6		3,325.6

PetroBakken Working Interest Reserve Reconciliation – Forecast Prices(1) (Mboe)(2)
	Developed		Total		Proved+
	Producing		Proved		Probable
PetroBakken reserves at December 31, 2009	59,412		89,470		143,638
2010 production net of royalty interest	(15,031	)	(15,031	)	(15,031	)
Net acquisitions	3,283		5,344		6,817
Net additions and revisions	17,662		22,220		34,393
PetroBakken reserves at December 31, 2010	65,326		102,003		169,816
PetroBakken year-over-year increase in reserves	10	%	14	%	18	%
PetroBakken production replacement	139	%	183	%	274	%

Notes:
⁽¹⁾  Based on the Sproule price forecast effective December 31, 2010.
⁽²⁾ Company Gross reserves, which represent PetroBakken's working interest share of reserves excluding its royalty interests in reserves and before deduction of royalty obligations.
⁽³⁾  Royalty interest reserves owned by PetroBakken.
⁽⁴⁾  "Company Interest" reserves, which represent PetroBakken's working interest share of reserves including its royalty interests in reserves and before deduction of PetroBakken's royalty obligations.
⁽⁵⁾ Company working interest reserves value plus royalties received less royalties and burdens.

PetroBakken FD&A Costs⁽¹⁾
For the year ended December 31, 2010

		F&D		Acquisitions(2)		Dispositions		FD&A(4)
Capital expenditures (unaudited-$000s)
	Capital expenditures	781,523		-		-		781,523
	Acquisition/(Disposition) capital(3)	-		714,305		(133,632	)	580,673
	Total capital	781,523		714,305		(133,632	)	1,362,196
	Less: Land value	94,751		352,002		-		446,753
	Total capital excluding land value	686,772		362,303		(133,632	)	915,443
Change in FDC ($000s)
	Total Proved	44,932		133,724		(22,835	)	155,821
	Proved + Probable (2P)	116,303		173,837		(32,540	)	257,600
Total costs ($000s)
	Total Proved	826,455		848,029		(156,467	)	1,518,017
	Proved + Probable (2P)	897,826		888,142		(166,712	)	1,619,796
Net reserve additions (mboe)
	Total Proved	22,220		13,608		(8,264	)	27,564
	Proved + Probable (2P)	34,393		21,235		(14,419	)	41,209
FD&A costs ($/boe) (including land)
	Total Proved	37.19		62.32		18.93		55.07
	Proved + Probable (2P)	26.11		41.82		11.52		39.31
FD&A costs ($/boe) (excluding land)
	Total Proved	32.93		36.45		18.93		38.86
	Proved + Probable (2P)	23.35		25.25		11.52		28.47
For the year-ended Dec. 31, 2009
FD&A costs ($/boe) (including land)
	Total Proved	45.22		46.81		43.57		46.83
	Proved + Probable (2P)	33.02		32.42		32.89		32.48
FD&A costs ($/boe) (excluding land)
	Total Proved	40.52		42.97		43.57		42.56
	Proved + Probable (2P)	30.37		29.96		32.89		29.81
For the three years-ended Dec. 31, 2010
FD&A costs ($/boe) (including land)
	Total Proved	36.17		49.63		27.94		46.31
	Proved + Probable (2P)	27.41		34.12		18.38		33.29
FD&A costs ($/boe) (excluding land)
	Total Proved	30.74		41.31		27.94		38.29
	Proved + Probable (2P)	23.66		28.77		18.38		27.94

⁽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⁾  Includes the corporate acquisitions of Berens Energy Ltd., Rondo Petroleum Inc. and Result Energy Inc. and certain other asset acquisitions.
⁽³⁾  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.
⁽⁴⁾ PetroBakken uses FD&A as a measure of the efficiency of its overall capital program including the effect of acquisitions and dispositions.

FINANCIAL STATEMENT RELEASE DATE AND INVESTOR CONFERENCE CALL
Petrobank plans to release fourth quarter 2010 financial results after markets close on Monday, March 14, 2011. Management of Petrobank will be holding a conference call for investors, financial analysts, media and any interested persons on Wednesday, March 16, 2011 at 8:00 a.m. Mountain Time (10:00 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: 416-340-8527 / 877-440-9795

Replay dial-in numbers: 905-694-9451 / 800-408-3053
Replay pass code: 7468252

The live audio webcast link is: http://events.digitalmedia.telus.com/petrobank/031511/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 a premier light oil production company combining, high growth, long-life Bakken reserves and production with legacy 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. PetroBakken's strategy is to deliver accretive production and reserves growth, along with an attractive dividend yield. Whitesands Insitu Partnership, a partnership between Petrobank and its wholly-owned subsidiary Whitesands Insitu Inc., owns 104 net sections of oil sands leases in Alberta, 36 sections of oil sands licenses in Saskatchewan and 4 net sections of petroleum and natural gas rights in Kerrobert, Saskatchewan, and operates the Whitesands project which is field-demonstrating Petrobank's patented THAI^® heavy oil recovery process. THAI^® is an evolutionary in-situ combustion technology for the recovery of bitumen and heavy oil that integrates existing proven technologies and provides the opportunity to create a step change in the development of heavy oil resources globally. 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, projected levels of in situ upgrading and resulting oil pricing, potential resource and reserve increases, future production rates, timing for regulatory approvals and the completion of potential licensing agreements. 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 negotiation of future licensing arrangements, 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. 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. 

Petroleum Initially-In-Place (PIIP): That quantity of petroleum that is estimated to exist originally in naturally occurring accumulations. It includes that quantity of petroleum that is estimated, as of a given date, to be contained in known accumulations, prior to production, plus those estimated quantities in accumulations yet to be discovered.

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.