Petrobank Reports Q1 2011 Funds Flow from Operations of $168.4 Million

CALGARY, ALBERTA--(Marketwire - May 16, 2011) - Petrobank Energy and Resources Ltd. (TSX:PBG) is pleased to announce 2011 first quarter financial and operating results highlighted by funds flow from operations of $1.57 per diluted share.

Petrobank's results include the financial and operating results of PetroBakken Energy Ltd. (TSX:PBN), 59% owned by Petrobank at March 31, 2011. PetroBakken announced first quarter financial and operating results on May 10, 2011.

All financial figures are unaudited and in Canadian dollars ($) unless noted otherwise. All financial statements have been prepared in accordance with International Financial Reporting Standards ("IFRS") including comparative figures pertaining to Petrobank's 2010 results. A reconciliation of comparative figures is provided in the notes to the Unaudited Interim Consolidated Financial Statements for the period ended March 31, 2011.

This news release includes forward-looking statements and information within the meaning of applicable securities laws. Readers are advised to review "Forward-Looking Information and Statements" at the conclusion of this news release. Readers are also referred to "Information Regarding Contingent Resources" and "Non-GAAP Measures" at the end of this news release for information regarding the presentation of the financial and contingent resources information in this news release. A full copy of our 2011 First Quarter Financial Statements and MD&A have been filed on our website at www.petrobank.com and under our profile on SEDAR at www.sedar.com.

HIGHLIGHTS

In this report, quarterly comparisons are first quarter 2011 compared to first quarter 2010 unless otherwise noted. The results of Petrominerales Ltd. ("Petrominerales") (TSX:PMG), previously majority owned by Petrobank, have been separately disclosed as discontinued operations up until December 31, 2010, the date this business unit was spun off to Petrobank shareholders.

• Funds flow from continuing operations increased eight percent to $168.4 million, or $1.58 per basic share, compared to the fourth quarter of 2011 primarily as a result of PetroBakken's higher operating netbacks.
• PetroBakken's operating netback (excluding hedging activity) of $52.42 per barrel of oil equivalent ("boe") increased nine percent, compared to the fourth quarter of 2010, primarily as a result of higher pricing, and decreased slightly by one percent from the prior year period, primarily due to increased production expenses.
• Net income attributable to Petrobank shareholders from continuing operations increased $20.3 million to $20.6 million in the first quarter of 2011 compared to the first quarter of 2010. The increase is due mainly to a non-cash gain arising from the revaluation of PetroBakken's convertible debentures derivative financial liability.
• Capital expenditures were $361.7 million in the first quarter, up 73 percent from a year ago and 20 percent from the fourth quarter of 2010. The increases were primarily driven by PetroBakken's aggressive drilling program and extensive facility investments, and the Heavy Oil Business Unit's 10 well-pair expansion project at Kerrobert.
• On January 4, 2011, Petrobank entered into a new three year $200 million credit agreement with a syndicate of lenders.

• Start up of Kerrobert expansion project is on schedule with the first of the new production wells being tied into the central processing facility.
• A five year collaboration agreement has been signed with Pemex Exploración y Producción, a subsidiary entity of the Mexican state oil company Petroleos Mexicanos ("Pemex"), as the first step to licensing our THAI^® technology in Mexico.
• We have acquired and agreed to acquire a further seven sections of land in Saskatchewan on the Kerrobert Waseca channel trend.
• Our Dawson demonstration project is moving forward and we anticipate starting to drill in the third quarter of 2011.
• The Kerrobert demonstration project production averaged 110 barrels of oil per day ("bopd") for the first quarter and the two wells are now being prepared to be tied into the new production facility.

Kerrobert Project

The Kerrobert expansion project has been commissioned and the central processing facility ("CPF") is ready to accept production. Drilling and completion of the 10 air injection wells is complete, nine of the new horizontal production wells are drilled, with five completed and the remaining five on schedule to be completed and tied in by June 30.

We had anticipated the Pre-Injection Heating Cycle ("PIHC") in the new wells to take up to 60 days; however temperature response was achieved in less than twenty days, which allowed us to accelerate air injection operations. Air injection began on three injector wells on the first pad in April. The two remaining wells on this pad are near the end of their PIHC and will be on air before the end of May. We expect to begin the PIHC in the injector wells on the second pad by mid-June. All production will be brought into the CPF as the wells come on-stream, including the two original wells from the demonstration project. The production wells are all on schedule to be producing into the CPF by mid-July.

We are pleased with the final placement of the injection and production wells as they were drilled within our new design parameters. The new production 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 and operating capability.

Capital costs for the 10 well-pairs and facilities expansion are estimated at approximately $95 million versus an original budget of approximately $75 million. Pipeline and facilities costs are on budget and on schedule. Drilling and completion costs exceeded budget primarily related of the horizontal production wells. The start-up of the drilling program was behind schedule due to mechanical and operating problems with the drilling rig, and one well had to be re-drilled due to intermediate casing failure while cementing. The completion costs of the injection and production wells are on budget.

During the first quarter of 2011, the initial two wells' production was approximately 110 bopd. Operations on the initial two wells were impacted by the drilling and construction activities related to the expansion. During April, road bans and limited access due to expansion drilling activities resulted in lower on-stream times with production averaging 105 bopd.

Dawson Project

We received final Energy Resources Conservation Board ("ERCB") and Alberta Environment ("AENV") approval for our initial Dawson project during the fourth quarter of 2010. The Dawson project will initially consist of two THAI^® well-pairs plus associated surface facilities.

Field activities conducted during the first quarter of 2011 included drilling two stratigraphic wells that were cored to confirm seismic contours and the drilling of two ground water monitoring wells. Our plan is to start construction of access roads and leases late in the second quarter while drilling and completion activities will begin in the third quarter of 2011.

We will move the surface facilities from our first two wells at the Kerrobert project to our Dawson project in the third quarter of 2011. PIHC is planned to commence in the fourth quarter of 2011. Production is also expected to commence in the fourth quarter.

In order to capitalize on the full potential at Dawson, the environmental assessment and regulatory application associated with the Dawson expansion is underway. The Dawson expansion project is being designed as a 10,000 bopd capacity project and the required regulatory applications for both the ERCB and AENV are scheduled to be submitted during the third quarter of 2011. We expect the regulatory review cycle could take up to 18 months.

Conklin Demonstration Project

As part of our on-going evaluation of our Conklin operations, we have abandoned the original three wells that were previously shut-in as well as P2B and P3B. During the first quarter of 2011, we observed that the P1B well, where the toe was drilled well short of the combustion zone, is beginning to heat up. We are in the process of evaluating the multi-THAI® configuration, adding another air injector on P1B further along this well bore and drilling a new production well in a better part of the reservoir.

With our Kerrobert and Dawson projects moving forward, we are now primarily evaluating options for the Conklin demonstration project as a field scale testing site for future technology enhancements to the THAI^® process.

May River Project

The May River application is proceeding through the regulatory process. We have responded to all of the information requests and have recently filed our final response to the three Statements of Concerns ("SOC") with the ERCB. We do not believe that the SOCs have merit to warrant the granting of standing; however this decision rests with the ERCB.

During the first quarter of 2011, we drilled 11 oil sands evaluation wells to further evaluate resource potential and further delineate the resource for future expansion phases of the May River property. Based on internal estimates these wells added approximately 40 million barrels of best estimate contingent resource and we have asked our external reserve evaluator, McDaniel & Associates Consultants Ltd., to update our 2010 reserve report to reflect these drilling results.

Archon Technologies Ltd. ("Archon")

Archon, our wholly-owned technology subsidiary, continues to advance our suite of technologies, including a novel process to remove H₂S in the produced gas stream that will further enhance our CrystaSulf™ process. We plan to field test this technology during 2011. Our ongoing research and development efforts have identified new technologies and enhancements to existing intellectual property that could result in as many as eight new patents in the coming year which will serve to further strengthen and improve our core THAI^® and CAPRI^® patents.

During the first quarter, we signed a five year non-commercial general collaboration agreement concerning research, scientific, technological and human resources development with Pemex Exploración y Producción ("PEP"), a subsidiary entity of the Mexican state oil company, Pemex. This agreement provides for the sharing of scientific and technological information, pursuant to the regulations in force, and the evaluation of enhanced oil recovery technologies for heavy oil deposits in Mexico. This agreement is an important first step in a possible negotiation, under Mexican law, of a licensing deal that will permit PEP to utilize Petrobank's THAI^® technology.

Land Acquisitions

As previously reported Petrobank acquired 3.5 sections (2,240 acres) of petroleum and natural gas rights at a Saskatchewan Crown Sale in late 2010. The lands are located in the Plover area on the same trend as our Kerrobert project. During the first quarter we purchased 3-D seismic and we plan to drill a stratigraphic well later in 2011 to define the resource potential.

Petrobank closed an acquisition on March 31, 2011 to acquire 6.5 sections (4,160 acres) of petroleum and natural gas rights. These lands are situated two miles southeast of the acquired Plover lands, and are also located on the same trend as Kerrobert.

SUMMARY OF FINANCIAL AND OPERATING RESULTS

The following table provides a summary of Petrobank's financial and operating results for the three month periods ended March 31, 2011 and 2010. Unaudited condensed interim consolidated financial statements with Management's Discussion and Analysis ("MD&A") will be available on the Company's website at www.petrobank.com and on the SEDAR website at www.sedar.com.

PETROBANK'S LIQUIDITY AND CAPITAL RESOURCES

Petrobank and PetroBakken manage their capital structure independently and generate their own cash flows, and have the ability to fund their operations through the issuance of secured and unsecured debt as well as equity financing. Petrobank's capital resources are focused on funding corporate and Heavy Oil Business Unit expenditures. At March 31, 2011, independent of PetroBakken, Petrobank on a standalone basis had a working capital deficit of $28.7 million and available credit capacity of $196.2 million.

Based on Petrobank's current ownership and PetroBakken's intentions of paying an annual dividend of $0.96 per PetroBakken share, Petrobank expects to receive $105 million of dividends annually from PetroBakken, paid monthly. Petrobank can also raise funds by selling a portion of its ownership in PetroBakken or by issuing additional debt secured by this interest.

Petrobank expects to sufficiently fund our HBU capital expenditure program with available credit, cash from operations and dividends received from PetroBakken.

ANNUAL GENERAL MEETING AND WEBCAST

Petrobank's annual general meeting (the "Meeting") will be held Wednesday, May 25, 2011 at 2:00 p.m. (Calgary time) in the Main Ballroom of The Metropolitan Centre, 333 Fourth Avenue SW, Calgary, Alberta. The Meeting and corporate presentation will be webcast live and available for replay at www.petrobank.com under the "Investors" section. After the formal business of the Meeting and corporate presentation, management of the Company will provide a question and answer period. For those participating by webcast, you are invited to also submit questions. Petrobank's management will endeavour to answer as many questions as possible during the time frame allotted. Before and after the Meeting, management and staff of Petrobank and PetroBakken will be presenting informational displays regarding Company activities and we cordially invite all guests to attend.

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, 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 14 sections of petroleum and natural gas rights in Kerrobert, Saskatchewan, and operates the Kerrobert and Conklin projects which are 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.

Non-GAAP Measures:This press release contains financial terms that are not considered measures under generally accepted accounting principles ("GAAP"), such as funds flow from continuing operations, funds flow per share and operating netback. These measures are commonly utilized in the oil and gas industry and are considered informative for management and shareholders. Specifically, funds flow from continuing operations and funds flow per share reflect cash generated from operating activities before changes in non-cash working capital. Management considers funds flow from operations and funds flow per share important as they help evaluate performance and demonstrate the Company's ability to generate sufficient cash to fund future growth opportunities and repay debt or financing obligations. Profitability relative to commodity prices per unit of production is demonstrated by an operating netback. Funds flow from continuing operations, funds flow per share and operating netbacks may not be comparable to those reported by other companies nor should they be viewed as an alternative to net income or other measures of financial performance calculated in accordance with GAAP.

The following table shows the reconciliation of funds flow from continuing operations to cash flow from operating activities from continuing operations for the periods noted (in $000s):

Contingent Resources: In this press release, Petrobank has disclosed estimated volumes of "contingent resources". "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.

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, future resource potential, potential technology enhancements and sources of available financing. 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, recompletions and related activities; timing and rig availability, outcome of exploration contract negotiations; fluctuation in foreign currency exchange rates; the uncertainty of reserve 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 forecasted. 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.

Natural gas volumes have been converted to barrels of oil equivalent ("boe"). Six thousand cubic feet ("Mcf") of natural gas is equal to one barrel of oil equivalent based on an energy equivalency conversion method primarily attributable at the burner tip and does not represent a value equivalency at the wellhead. Boes may be misleading, especially if used in isolation.