CALGARY, ALBERTA--(Marketwire - Aug. 15, 2011) - Petrobank Energy and Resources Ltd. (News - Market indicators) is pleased to announce 2011 second quarter financial and operating results highlighted by funds flow from operations of $1.38 per diluted share.

Petrobank's results include the financial and operating results of PetroBakken Energy Ltd. (TSX:PBN), 59% owned by Petrobank at June 30, 2011. PetroBakken announced second quarter financial and operating results on August 8, 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 June 30, 2011.

Tehis 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 "Resources and 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 Second Quarter Financial Statements and MD&A have been filed on our website at www.petrobank.com and will be available under our profile on SEDAR at www.sedar.com.

HIGHLIGHTS

In this report, quarterly comparisons are second quarter 2011 compared to second 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.

Q2 2011 Financial Highlights

• Net income from continuing operations, adjusted for gains on derivative financial liabilities, for the three months ended June 30, 2011 of $25.5 million increased $71.3 million compared to the same period in the prior year. The increase is primarily due to higher revenue as a result of higher pricing, a non-cash gain arising from the disposition of PetroBakken non-core assets, and certain costs related to convertible debentures in the second quarter of 2010 which did not exist in the current period.
• PetroBakken's production averaged 35,300 barrels of oil equivalent ("boe") per day in the second quarter of 2011, representing a 15% decrease compared to the first quarter of 2011, and a 16% decrease from the prior year period. Light oil production increases, primarily from PetroBakken's Cardium play, were more than offset by shut-in production of approximately 6,200 boe per day for the quarter due to an extended spring break-up that prevented access to leases.
• PetroBakken's operating netback (excluding hedging activity) of $56.63 per boe in the second quarter increased 8% compared to the first quarter of 2011, and 23% over the prior year period, primarily as a result of higher pricing that more than offset increased royalty and production expenses.
• Capital expenditures were $168.7 million in the second quarter, up 26% from a year ago. The increases are attributable to our Heavy Oil Business Unit's ten well-pair expansion project at Kerrobert, which has experienced cumulative cost overruns of approximately $30 million, long lead equipment purchases for our May River project and increased activity at our Dawson project.

Heavy Oil Business Unit 2011 Operational Highlights

• May River best estimate contingent resources increased 11% to 624.1 million barrels at June 1, 2011 (see "Resources and Contingent Resources") as a result of 2011 oil sands evaluation well drilling. 
• Eight of the Kerrobert expansion well-pairs have completed the Pre-Ignition Heating Cycle ("PIHC") and are now on air injection.
• Our Dawson demonstration project is proceeding and we anticipate that drilling will start in the fourth quarter of 2011.
• The Energy Resources Conservation Board ("ERCB") has determined that two parties who filed Statements of Concerns are entitled to participate in the ERCB's consideration of the May River application. We anticipate that the ERCB will schedule a hearing for the application shortly, with the hearing likely to take place in late 2011 or the first quarter of 2012.

OPERATIONAL UPDATE

Kerrobert Project

Our Kerrobert project operations are underway with eight of the ten new well-pairs on air injection and in the initial production phase. The first expansion well-pair was placed on air injection and production in the middle of May, with an additional four well-pairs placed on air injection by the end of the second quarter. The PIHC for the remaining five well-pairs began at the end of the second quarter and currently three of these well-pairs are on air injection, with the remainder expected to be on air injection by September.

Our operating procedures continue to evolve. We have been able to reduce the duration of the PIHC from a planned eight weeks to approximately four weeks. Following the PIHC, the vertical wells commence air injection at low rates and the horizontal production wells are brought on production with a progressive cavity pump. The initial clean-up fluids consist of water, including condensed water from the PIHC steam injection, and some native oil. As these fluids are produced, the combustion gas volume increases, the temperature in the horizontal well begins to rise and the well begins to produce an oil and water emulsion at low rates. Well bore temperatures will increase and combustion gas, along with some native oil and occasional upgraded THAI^® oil, will be produced. As we measure the combustion gas communication and rising well bore temperatures, we will increase the air injection in stages to facilitate the combustion zone development.

The second quarter was a period of transition for the Kerrobert project. We completed the drilling of the expansion wells, began operations on the new wells and started dismantling the temporary facilities in anticipation of the new wells being tied into the new central processing facility ("CPF"). Very wet weather delayed our access to the CPF and well-site until mid-July. We experienced significant down time on the original Kerrobert wells due to pump changes, decommissioning of the original Kerrobert facilities and delayed tie-in to the new CPF. These activities resulted in second quarter Kerrobert production of approximately 40 bopd.

Dawson Project

We received final ERCB and Alberta Environment ("AENV") approval for our Dawson demonstration project during the fourth quarter of 2010. This project will consist of two THAI^® well-pairs plus associated surface facilities. We expect that one well-pair will be drilled during 2011 and the second will be drilled in 2012.

In the second quarter of 2011, we drilled two stratigraphic evaluation wells. We are currently decommissioning the surface facilities from our first two wells at the Kerrobert project and will begin moving the facilities to our Dawson project in the third quarter of 2011. Civil work has begun and it is expected that drilling will commence in mid-September. Drilling activities for the remainder of 2011 will include completing an observation well as an air injector, as well as drilling a water disposal well, an observation well and one horizontal production well.

PIHC is planned to start in the fourth quarter of 2011, and air injection is expected to commence before year-end.

The environmental assessment and regulatory application associated with the Dawson 10,000 bopd expansion project are underway with the application to the ERCB and AENV scheduled to be submitted during the fourth quarter of 2011. We expect that the regulatory review cycle could take up to 18 months.

Conklin Demonstration Project

With our Kerrobert and Dawson projects both moving forward, we are now evaluating options for the Conklin demonstration project to become predominantly a field scale testing site for future technology enhancements to the THAI^® process. We have received approval from the ERCB to conduct a wet combustion process on P1B and have submitted an application to the ERCB to drill another air injector further along the P1B well bore to evaluate our new multi-THAI^® configuration.

May River Project

The May River application was previously submitted to the Board of the ERCB (the "Board") for review. The Board recently determined that two of the parties who filed Statements of Concern are entitled to participate in the Board's consideration of the May River application. We anticipate that the Board will schedule a hearing in respect of the May River application shortly, with the hearing likely to take place in late 2011 or the first quarter of 2012.

Now that we have received clarity from the Board with respect to the Statements of Concern we plan to continue our consultation with these parties to clarify and resolve their issues prior to the hearing.

As previously disclosed, 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. Our external reserves evaluator, McDaniel & Associates Consultants Ltd., updated our 2010 reserve report to reflect these drilling results. May River best estimate contingent resources increased 11% to 624.1 million barrels at June 1, 2011 (see "Resources and Contingent Resources"). May River proved plus probable reserves remains relatively unchanged at 90.6 million barrels. These reserves are not included in our contingent resource estimates. Our June 28, 2011 press release provides more information about our updated May River reserve and resource estimates.

Land Acquisition

On May 27, 2011, Petrobank acquired 566 acres of petroleum and natural gas rights on the Kerrobert trend in Saskatchewan situated adjacent to the 4,092 acres of land that we purchased on March 31, 2011. This is the third acquisition of land that we have made in six months on the same trend as Kerrobert and we currently control 13,533 gross and 11,517 net acres of land on the trend. To define the resource potential of our new lands, we purchased three third party 3-D seismic surveys and plan to drill two stratigraphic delineation wells.

Archon Technologies Ltd. ("Archon")

Archon, our wholly-owned technology subsidiary, continues to expand research and development efforts and review and assess several other enhanced oil recovery techniques. Archon currently has eight patents granted, or pending, and is preparing applications for eight new patents.

Now that we have signed a collaboration agreement with Pemex Exploración y Producción, we are actively engaged with them to evaluate potential reservoirs for the use of THAI^®.

During the second quarter, Archon entered into a new Technology License and Royalty Agreement ("License Agreement") with Petrominerales. The License Agreement gives Petrominerales the right to use Archon's patented THAI^® in-situ combustion technology and related technologies (the "Technologies") for the development of heavy oil resources in Colombia. In addition, Petrominerales has an exclusive right to sublicense the Technologies to third parties in Colombia for up to 10 years, provided certain contractual commitments are met, including commencing a pilot project within three years.

In exchange for the right to use and sublicense the Technologies in Colombia, Petrominerales has agreed to pay Archon a specified royalty based upon production, and has granted Archon the right to acquire a working interest in third party THAI^® heavy oil joint ventures with Petrominerales. Archon, or an Archon affiliate, can elect to participate in a third party heavy oil joint venture for up to 25% of Petrominerales' share in the joint venture. For heavy oil projects that are 100% Petrominerales working interest, Archon does not have a right to acquire a working interest and Petrominerales is solely obligated to pay a specified royalty rate to Archon.

PETROBANK'S LIQUIDITY AND CAPITAL RESOURCES

Petrobank and PetroBakken manage their capital structure independently, 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 June 30, 2011, on a standalone basis independent of PetroBakken, Petrobank had bank debt of $45.5 million, a working capital deficit of $21.4 million and available credit capacity of $154.5 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.

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

SUMMARY OF FINANCIAL AND OPERATING RESULTS

The following table provides a summary of Petrobank's financial and operating results for the three and six month periods ended June 30, 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.

Summary of Results ⁽¹⁾

⁽¹⁾ Petrominerales Ltd. ("Petrominerales") has been presented as discontinued operations in the comparative period as this business unit was spun off to Petrobank shareholders at December 31, 2010.
⁽²⁾ Non-GAAP measure. See "Non-GAAP Measures" section within Management's Discussion and Analysis ("MD&A").
⁽³⁾ Net income has been adjusted for the IFRS accounting effects of changes in the gain on derivative financial liability. For the three and six months ended June 30, 2011, adjusted net income includes a $32.8 million and $61.0 million reduction (2010 - $60.8 million and $76.4 million) for this gain. Management considers adjusted net income a better measure of the Company's economic performance period over period.
⁽⁴⁾ Net income attributable to Petrobank shareholders for the three and six months ended June 30, 2010 includes the operating results of Petrominerales.
⁽⁵⁾ Includes expenditures on property, plant and equipment, exploration and evaluation and other intangible assets.
⁽⁶⁾ Consists of common shares, stock options, directors deferred common shares, deferred common shares, and incentive shares as at the period end date.
⁽⁷⁾ Six Mcf of natural gas is equivalent to one barrel of oil equivalent ("boe").
⁽⁸⁾ Net of transportation expenses.
⁽⁹⁾ Excludes hedging activities.
⁽¹⁰⁾ HBU bitumen and heavy oil volumes are excluded from average daily production as Conklin and Kerrobert operations are considered to be in the exploration and evaluation phase and accordingly are capitalized.

INVESTOR CONFERENCE CALL

Management of Petrobank will be holding a conference call for investors, financial analysts, media and any interested persons on Tuesday, August 16, 2011 at 9:00 a.m. Mountain Time (11:00 a.m. Eastern Time) to discuss Petrobank's second quarter financial and operating results. The investor conference call details are as follows:

Live call dial-in number(s): 416-695-6616 / 800-355-4959

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

Replay pass code: 6674103

The live audio webcast link is: http://events.digitalmedia.telus.com/petrobank/081611/index.php and is also available on our website at: http://www.petrobank.com/investors/.

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 15 sections of petroleum and natural gas rights along the Kerrobert channel trend near 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 International Financial Report Standards, which are considered to be generally accepted accounting principles ("GAAP"), such as funds flow from continuing operations, funds flow per share, adjusted net income, adjusted net income 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. Adjusted net income is determined by adding back any losses or deducting any gains on the derivative financial liabilities. Management considers funds flow from continuing operations, funds flow per share, adjusted net income and adjusted net income 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. Profitability relative to commodity prices per unit of production is demonstrated by an operating netback. Funds flow from continuing operations, funds flow per share, adjusted net income, adjusted net income 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):

Resources and Contingent Resources:  In this press release, Petrobank has disclosed estimated volumes of "contingent resources" associated with our May River property. "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 property, 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, timing for obtaining regulatory approvals, future resource potential, potential technology enhancements and anticipated sources of available financing. Forward-looking statements are necessarily based on a number of assumptions and judgments, including but not limited to, assumptions relating to the outlook for commodity and capital markets, the success of future resource evaluation and development activities, he successful application of our technology, the performance of producing wells and reservoirs, well development and operating performance, general economic 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; weather conditions and access to our properties; 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; uncertainties associated with the regulatory review and approval process in respect to our projects; risks associated with the application of early stage technology; 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.