CALGARY, ALBERTA--(Marketwire - Nov. 14, 2011) - Petrobank Energy and Resources Ltd. (News - Market indicators) is pleased to announce 2011 third quarter financial and operating results highlighted by funds flow from operations of $1.37 per diluted share.

Petrobank's results include the financial and operating results of PetroBakken Energy Ltd. (TSX:PBN), 59% owned by Petrobank at September 30, 2011. PetroBakken announced third quarter financial and operating results on November 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 September 30, 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 "Non-GAAP Measures" at the end of this news release for information regarding the presentation of the financial information in this news release. A full copy of our 2011 Third 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.

In this report, quarterly comparisons are third quarter 2011 compared to third 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 the shares of the business unit were distributed to Petrobank shareholders.

HIGHLIGHTS

Q3 2011 Financial Overview

• Net income from continuing operations, adjusted for gains on derivative financial liabilities, for the three months ended September 30, 2011 of $4.7 million decreased $17.6 million compared to the same period in the prior year. The decrease is primarily due to a foreign exchange loss in the third quarter of 2011, compared to a gain in the comparative period, partially offset by higher revenue as a result of higher pricing.
• PetroBakken's production averaged 39,074 barrels of oil equivalent ("boe") per day in the third quarter of 2011, representing an 11 percent increase compared to the second quarter of 2011. The increase in production over the second quarter was the result of a combination of restoring production that was shut-in due to the extended spring break-up and production additions from new wells that were put on production in the latter part of the third quarter.
• PetroBakken's operating netback (excluding hedging activity) of $50.04 per boe in the third quarter decreased 12 percent compared to the second quarter of 2011, and increased 15 percent over the prior year period. The decrease over the second quarter was primarily a result of lower pricing that more than offset decreased royalty and production expenses.
• Capital expenditures were $302.6 million in the third quarter, up four percent from a year ago. The increase is attributable to PetroBakken's drilling program, partially offset by decreased spending at our Heavy Oil Business Unit, which acquired Baytex Energy Corp.'s 50 percent working interest in the Kerrobert project for $18.1 million in the third quarter of the prior year. PetroBakken drilled 96 (70.1 net) wells in the third quarter. Capital expenditures for the Heavy Oil Business Unit totalled $30.8 million in the third quarter, including $20.0 million on facilities, drilling and completion expenditures.

Heavy Oil Business Unit Operational Highlights

• The Kerrobert expansion project is in the production start-up phase, with all wells capable of production and 11 of the 12 well-pairs on combustion.
• Drilling and facilities construction at the Dawson demonstration project started in the third quarter and we anticipate that the Pre-Ignition Heating Cycle ("PIHC") will begin by the end of the year.
• The Energy Resources Conservation Board ("ERCB") has scheduled the May River project hearing for March 6, 2012.
• In early October, we suspended all field operations at the Conklin demonstration project.

Kerrobert Project

At the Kerrobert expansion project, we have successfully put nine of the 10 new well pairs to air injection and have increased air injection rates over the quarter. One of the air injection wells is currently not operational; however, we continue to operate the associated production well as the reservoir is being heated by surrounding air injection wells. All of our technical measurements confirm that we have achieved high temperature combustion. There are increasing temperatures at the toes of the production wells and along the wellbores, and we have produced upgraded oil. The project's central processing facility is operating normally. All of these characteristics are positive milestones for the Kerrobert expansion.

Early stage production has been low and inconsistent, with third quarter 2011 average production of approximately 30 barrels of oil per day at Kerrobert. We are mainly producing cold, heavy native oil which is difficult to move down the wellbore and tends to produce sporadically as it is pumped to the surface. We have taken a controlled approach to manage air injection and production to initiate combustion and increase reservoir pressure across a much broader area. We believe this approach will maximize combustion front development and reservoir recovery. Based on our experience with the two pilot wells, as the initial cold native oil production transitions to hot upgraded THAI^® oil production, we expect production rates to greatly improve. However, our operating approach may extend the time frame for achieving normalized production rates.

Our operational plan at Kerrobert is to continue to increase air injection rates, build out the combustion front, increase the overall pressure in the reservoir and increase production of upgraded THAI^® oil.

Dawson Project

During the third quarter we began the field work and drilling at our Dawson demonstration project. We have drilled and completed two horizontal production wells and one of the air injection wells on time and on budget. The second air injection well will be completed by year-end 2011. The surface facilities from the Kerrobert demonstration project have been relocated to Dawson and are ready to be installed. We are also moving some non-essential equipment from the Conklin demonstration project to the Dawson site. PIHC is expected to begin in December and air injection will begin in early 2012.

The environmental assessment and regulatory application associated with the Dawson commercial project are near completion. The applications to the ERCB and Alberta Environment are expected to be submitted later this year. We expect that the regulatory review cycle could take up to 18 months.

Conklin Demonstration Project

We have suspended operations at our Conklin demonstration project which was being used as a field scale testing site for enhancements to the THAI(R) process. All the testing that was scheduled for Conklin was completed, leading to the decision to suspend operations. Once our May River project has been approved by regulators, we will evaluate whether to integrate the Conklin facilities into our May River project or abandon the site. Once the site is fully suspended, operating costs and maintenance capital at our Conklin project are expected to be reduced to a minimal amount with savings of approximately $1.0 million each month compared to continuing operations.

May River Project

Our May River project continues to move towards our ERCB hearing on March 6, 2012. Pending the outcome of the ERCB hearing, which is expected approximately three months after the hearing date, we will update the May River project development schedule and proceed with our internal project approval and sanctioning processes. 

Plover Property

As previously reported, earlier this year we acquired more undeveloped land along the Kerrobert trend in Saskatchewan. We have been evaluating third party 3-D seismic surveys on this land over the last several months. Three stratigraphic wells are expected to be drilled in Q1 2012 to better define the resource.

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 numerous means, including 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 September 30, 2011, on a standalone basis, independent of PetroBakken, Petrobank had bank debt of $58.8 million, a working capital deficit of $17.5 million and committed credit capacity of $141.2 million. The availability of Petrobank's $200 million credit facility was reduced to $100 million at September 30, 2011 based on the value of Petrobank's ownership in PetroBakken. We expect the reduction to be temporary, with future increases in availability subject to PetroBakken's share price. Our near-term capital spending is expected to decrease significantly once our Dawson demonstration project is completed at the end of 2011. Other capital projects will largely be dependent on regulatory approvals which, as previously mentioned, are expected in mid-2012 for the May River project and 2013 for the Dawson commercial project. Our current sources of capital are expected to be more than adequate for our planned projects through the end of 2012. Petrobank expects to release formal 2012 capital expenditure guidance in mid-December.

Based on Petrobank's current ownership and PetroBakken's current 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 our ownership in PetroBakken or other corporate assets.

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

EXECUTIVE APPOINTMENTS

Petrobank is pleased to announce the promotion and appointment of Mr. Chad Magus as Controller effective October 1, 2011. Mr. Magus joined Petrobank in 2004 and was most recently Petrobank's Manager of Reporting and Planning and leads a team responsible for all accounting functions. He has contributed to Petrobank's many strategic initiatives and gained significant transactional, tax, operational and financial experience. Mr. Magus is a Chartered Accountant.

Petrobank has also appointed Mr. Dwight Mervold as Vice President, Operations and Production effective November 1, 2011. Mr. Mervold's career spans more than 24 years, including positions in the field and management responsibilities for heavy oil and natural gas production with a number of Canadian energy companies. Mr. Mervold is a member of the Association of Professional Engineers, Geologists, and Geophysicists of Alberta.

SUMMARY OF FINANCIAL AND OPERATING RESULTS

The following table provides a summary of Petrobank's financial and operating results for the three and nine month periods ended September 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 distributed to Petrobank shareholders at December 31, 2010.

⁽²⁾ Non-GAAP measure. See "Non-GAAP Measures" section within this press release.

⁽³⁾ Net income has been adjusted for the IFRS accounting effects of changes in the gain on derivative financial liability. For the three and nine months ended September 30, 2011, adjusted net income includes a $10.6 million and $71.7 million reduction (2010 - $58.8 million increase and $17.7 million decrease) 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 nine months ended September 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, November 15, 2011 at 9:00 a.m. Mountain Time (11:00 a.m. Eastern Time) to discuss Petrobank's third quarter financial and operating results. The investor conference call details are as follows:

Live call dial-in number(s): 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/111511/index.php and is also available on our website at: http://www.petrobank.com/investors/presentations-webcasts.

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):

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, 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, the 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.