Petrobank Announces Another Record Quarter and Significant Production Increases

Petrobank Energy and Resources Ltd. ("Petrobank" or the "Company") (TSX:PBG) is
pleased to announce record third quarter 2008 financial and operating results
driven by strong production increases and superior operating netbacks. 


THIRD QUARTER 2008 HIGHLIGHTS

(all comparisons are third quarter 2008 compared to the third quarter of 2007)

- Production more than tripled to 30,850 barrels of oil equivalent per day
("boepd").


- Production has now increased further to over 40,000 boepd.

- Canadian Business Unit ("CBU") production increased by 239% to 18,365 boepd
and averaged 21,660 boepd in October. 


- Latin American Business Unit ("LABU") production increased by 176% to 12,485
barrels of oil per day ("bopd") and has subsequently increased to 19,590 bopd. 


- Funds flow from operations increased by 412% to $216.7 million ($2.36 per
diluted share). 


- Net income increased by 487% to $123.2 million ($1.35 per diluted share).

- Strong operating netbacks of $84.95 per boe in the CBU and $90.44 per barrel
in the LABU. 


- Drilled 61.6 net Bakken wells during the quarter, on pace to exceed our 2008
goal to drill 154 net Bakken wells.


- Repurchased 298,400 common shares.

FINANCIAL & 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, 2008 and 2007.
Consolidated financial statements with Management's Discussion and Analysis
("MD&A") are available on the Company's website at www.petrobank.com and will
also be available on the SEDAR website at www.sedar.com. 




                         Three months ended        Nine months ended
                               September 30,     %      September 30,     %
                            2008       2007 change      2008    2007 change
----------------------------------------------------------------------------
Financial
($000s, except where
 noted)
Oil and natural gas
 revenue                 306,913     61,567    399   722,308 127,897    465
Funds flow from
 operations (1)          216,709     42,316    412   518,120  82,131    531
 Per share - basic ($)      2.62       0.55    376      6.32    1.09    480
           - diluted ($)    2.36       0.48    392      5.65    1.01    459
Net income               123,226     20,978    487   216,399  41,281    424
 Per share - basic ($)      1.49       0.27    452      2.64    0.55    380
           - diluted ($)    1.35       0.25    440      2.39    0.53    351
EBITDA (1)               235,377     44,168    433   544,724  85,830    535
Capital expenditures     257,305    135,417     90   629,931 373,736     69
Total assets           2,044,996    930,855    120 2,044,996 930,855    120
Net debt (1)             230,585     37,762    511   230,585  37,762    511
Common shares
 outstanding, end
 of period (000s)
 Basic                    82,474     76,897      7    82,474  76,897      7
 Diluted (2)              98,173     90,083      9    98,173  90,083      9
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Operations
CBU operating netback
 ($/boe except where
 noted) (1) (3)
 Oil and NGL revenue
  ($/bbl)                 115.11      76.56     50    109.65   71.00     54
 Natural gas revenue
  ($/mcf)                   7.94       5.35     48      8.47    6.51     30
 Oil and natural gas
  revenue                 106.51      62.86     69    100.98   56.87     78
 Royalties                 12.72       4.18    204     10.68    4.71    127
 Production expenses        8.84       8.44      5      8.99    8.55      5
----------------------------------------------------------------------------
 Operating netback (4)     84.95      50.24     69     81.31   43.61     86
LABU operating netback
 ($/bbl) (1)
 Oil revenue              110.53      72.74     52    104.63   66.84     57
 Royalties                 11.71       6.32     85     10.52    5.60     88
 Production expenses        8.38       7.42     13      9.76    7.40     32
----------------------------------------------------------------------------
 Operating netback (4)     90.44      59.00     53     84.35   53.84     57
Average daily production
 (3)
 CBU - oil and NGL
  (bbls)                  16,024      3,745    328    13,868   2,531    448
 CBU - natural gas
  (mcf)                   14,047     10,006     40    14,381  12,053     19
----------------------------------------------------------------------------
 Total CBU (boe)          18,365      5,413    239    16,265   4,540    258
 LABU - oil (bbls)        12,485      4,522    176     9,497   3,146    202
----------------------------------------------------------------------------
Total Company
 conventional (boe)       30,850      9,935    211    25,762   7,686    235
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(1) Non-GAAP measure. See "Non-GAAP Measures" section within the MD&A.
(2) Assumes 8.8 million common shares will be issued upon conversion of the
    Company's convertible debentures.
(3) Six mcf of natural gas is equivalent to one barrel of oil equivalent
    ("boe"). Heavy Oil Business Unit ("HBU") bitumen volumes are excluded as
    Whitesands operations are considered to be in the pre-operating stage
    and all expenses, net of revenues, are capitalized.
(4) Excludes hedging activities.



OPERATIONAL UPDATE

CANADIAN BUSINESS UNIT 

- Record third quarter production of 18,365 boepd, a 239% increase from the
third quarter of 2007.


- Production has increased further to average 21,660 boepd in October. 

- Drilled 61.6 net Bakken wells in the third quarter. 

- Completed construction of the Creelman oil battery and gathering system.

The CBU achieved record production levels during the third quarter. We drilled
73 (61.6 net) Bakken wells during the quarter and put 66 (54.0 net) new wells on
production. The production during the quarter averaged 18,365 boepd which
represents an 11% increase over the second quarter and a 239% increase over the
third quarter of 2007. We continue to add incremental volumes and during October
production averaged 21,660 boepd. Approximately 85% of our CBU production is now
Bakken light oil which delivers a high operating netback due to premium pricing,
relatively low royalties, and low operating costs. The average netback over the
quarter for the CBU was $84.95 per boe, despite declining commodity prices. 


Our level of activity in southeast Saskatchewan on the Bakken play will meet or
exceed our 2008 expectations for both drilling and new facilities. Petrobank
utilized 10 drilling rigs at times during the third quarter and successfully
drilled 61.6 net wells, resulting in a combined total of 136.4 net wells drilled
in the first nine months of 2008. We are on-track to exceed our goal of drilling
154 net wells this year. Currently we have seven rigs working in southeast
Saskatchewan and the Company plans to move to six rigs starting in December. 


New facilities allow for the conservation of natural gas and natural gas liquids
from the Bakken oil production and provide the additional benefit of lowering
operating costs with the efficiencies created through this new infrastructure.
The Creelman battery and gathering system, completed in September 2008, resulted
in the immediate conservation of 800 mcf per day of gas and associated liquids.
The new Freestone battery, gas conservation facility and 70 kilometre gas
pipeline will commence operations in early December, and we anticipate this will
result in the further addition of approximately four mmcf per day of natural gas
and associated natural gas liquids.


Due to a combination of low gas prices, the implementation of the new Alberta
royalty regime, and a recent unsuccessful drill result, Petrobank is
re-evaluating our plans to build a 25 mmcf per day gas plant in the Cornwall
area. A variety of less expensive pipeline and facility alternatives are being
examined to bring the gas and liquids from our first well to market. We still
expect initial production from this area to commence by April 2009.


As part of our efforts to build our inventory of future drilling locations,
Petrobank has acquired additional land in areas that are prospective for Bakken
light oil and we will be drilling our first wells in both the Montney and Horn
River Shale Basin play areas of northeast British Columbia in the next two
months. These geological plays cater to Petrobank's technical strengths in
horizontal drilling and multi-stage hydraulic fracture stimulations that have
been successfully employed in the Bakken play. We have a 100% working interest
in 14 sections of prospective Montney acreage and we will spud our first well
here in November. An independent resource assessment of this acreage indicates
potential best estimate contingent recoverable resource of 148 Bcf. We plan to
vertically drill and evaluate the Montney formation prior to continuing with the
horizontal portion of the well. Some of Petrobank's 65 sections (43,428 acres)
of 100% working interest lands in the Horn River Shale Basin north of Fort
Nelson, British Columbia are close to all-season access and we will also spud
our first evaluation well on this play during the fourth quarter. Other
operators in these areas continue to have strong initial results and we are
eager to add new drilling locations to our inventory with successful tests in
these promising resource plays.


Solid production growth and strong cash flow from operations allows us to
maintain an active program and strengthen our balance sheet while also being
cognizant of the recent sharp decline in commodity prices. Our primary focus and
key efforts through the balance of 2008 and into 2009 will be to maintain an
active program that continues to increase oil reserves and production from the
Bakken. We will also be positioning for future growth by strategically investing
in opportunities that add quality drilling locations to our significant prospect
inventory that is focused on large oil and natural gas resource plays. This high
quality inventory positions the CBU to deliver significant future production and
reserves growth when commodity prices improve. 


HEAVY OIL BUSINESS UNIT 

- Successfully began production from the world's first THAI(TM)/CAPRI(TM) well
which incorporates our revised downhole completion design, effectively
eliminating sand production. 


- After a further extended review period we now expect regulatory approval for
our Whitesands three well expansion by the end of November.


- Acquired 35 kilometres of 2D seismic at Sutton Creek, Saskatchewan and we
expect to have an initial evaluation of the data by year end.


Whitesands Project

During the third quarter we began production of our P-3B THAI(TM) /CAPRI(TM)
well with encouraging early results. Inter-well communication was rapidly
established and combustion temperatures reached 500 degrees Celsius. As
previously disclosed, Petrobank drilled P-3B late in the second quarter of 2008
and completion operations commenced on the well in late July. This well has been
designed to demonstrate the additional upgrading potential of our patented
CAPRI(TM) process which places an active catalyst bed between two concentric
slotted liners. In laboratory tests, CAPRI(TM) has achieved an upgrading effect
of seven degrees API in addition to the upgrading effect resulting from the
THAI(TM) process. The P-3B well also incorporates our narrower slot design,
intended to significantly reduce sand production from the McMurray sandstone
reservoir typically encountered at Whitesands.


In September, P-1 and P-2 on-stream factors improved. Although it is not our
intention to drill any further wells incorporating the completion initially used
in P-1 and P-2, with the modification of de-sand vessel internals we have also
been able to continuously improve sand management from the P-1 and P-2 wells. 


In September and October, a number of planned shutdowns were scheduled. During
the same period unplanned shutdowns occurred which led to additional downtime.
The planned shutdowns included the replacement of the thermocouple string in
P-3B to add additional thermocouple sensors, as well as the shutdown of the A-3
air injection well to replace the well's packer assembly pursuant to regulatory
requirements. Shutdowns were also planned to tie-in the new wellhead gas
separation and tank separation system on P-3B. Unplanned shutdowns included an
Alberta grid electric power failure and the shutdown of the compressors used for
air injection due to a failure in the compressor's cooling system. These
resulted in wells being shut in and restarted, causing non-rateable production.
The P-1 and P-2 wells were brought back on-line early in November and the P-3B
well will be brought back on-line following the packer replacement on A-3 which
is expected to be completed by the middle of November. We do not plan any major
plant shut downs until we tie-in our three well expansion.


Since the commencement of air injection and oil production in August on P-3B,
the well has exhibited negligible sand production, in contrast to what was
encountered in the initial three wells. First produced fluids consisted of oil
and water emulsions from the steam preheat as well as residual drilling mud,
which diminished as the well cleaned up. During the initial period we achieved
oil production rates up to 300 barrels per day on low air injection rates, with
oil cuts of 40 to 50%. P-3B has been operating at a well bore temperature below
the optimum range for the catalyst and therefore it is still too early to assess
the effectiveness of the catalyst. However, the produced oil has been upgraded
to 11.5 degrees API due to the thermal cracking effects of the THAI(TM) process.
The operating plan is to increase well bore temperatures for optimum catalyst
efficiency and continue to analyze produced oil quality to assess the catalyst
effectiveness. Produced gas analysis from P-3B is consistent with the P-1 and
P-2 wells and indicates high temperature combustion with the associated
production of free hydrogen. During the early start-up phase of P-3B, the P-1
and P-2 wells were operated at lower air injection rates. These wells have
achieved higher on-stream factors with oil production rates of up to 400 barrels
per day for each well. Produced oil quality is averaging approximately 12
degrees API, compared to the native eight degree API bitumen in-situ. With P-3B
production anticipated to stabilize during the third quarter, we had planned to
gradually increase air injection on all three wells; however recent plant
shutdowns have delayed these operating plans.


We continue to recover a light oil condensate in the secondary separators that
is being carried in the vapour phase by the overhead gas stream. This lighter
oil is over 30 degrees API and is not included in the production rates noted
above. We continue to analyze the quality and quantity of this light fraction.
Estimates indicate that this could be up to 10% of the total produced
hydrocarbons. This lighter oil component further demonstrates significant
in-situ thermal cracking and the potential for co-production of other high-value
by-products. 


Our improved surface facilities design utilizing primary gas separation followed
by tank separation of oil, water and sand (rather than using a single pressure
vessel) is being installed on P-3B and, when combined with the success of our
narrower liner slot size, is expected to eliminate most operational challenges
caused by sand production in this well and future wells. These improved surface
facilities will be operational during the third week of November. 


We have now been expecting Alberta government regulatory approval for our three
well expansion for several months. We are disappointed with the lack of
regulatory progress and have tried to work closely with regulatory agencies to
expedite timely approval. Unfortunately, the process for oil sands development
in Alberta is being delayed by a number of factors beyond our control. We have
positioned ourselves to be able to execute this expansion as soon as possible
following approval. The same drilling rig that efficiently drilled P-3B is
currently racked on the plant site. All of the equipment necessary to modify the
plant to handle the increased production is either on-site, in production, or
waiting in yards for shipment. Our current understanding is that Alberta's
Energy Resources Conservation Board ("ERCB") will make its decision on the
expansion on November 24, 2008. All plans are in place for accelerated site
preparation, drilling, and facility modifications once regulatory approval of
the three well expansion project is received. 


May River Project 

The May River Project is our commercial expansion plan for the THAI(TM)
technology on the Whitesands leases. Plant production experience and engineering
analysis to date provided the basis for simplifying our May River central
processing facility design. The central facilities for the project will be
located approximately two kilometres from the current Whitesands site. May River
is planned to be built in phases, beginning with initial production capacity of
10,000 bopd of partially upgraded oil, ultimately building capacity to 100,000
bopd. 


At May River we will be incorporating on-site electric power generation from our
low BTU produced gas. We expect to be able to generate enough power from this
gas to be more than energy self-sufficient, which will further reduce the carbon
footprint of the project. This will effectively offset coal-fired power
generation from the Alberta electrical grid and reduce the greenhouse gas
emissions of the project. Elemental sulphur will also be recovered using the
CrystaSulf(R) technology. This technology is designed to recover sulphur from
the produced H2S more efficiently and with a much lower energy use than
competing technologies. We have recently acquired the worldwide use and license
rights to the CrystaSulf(R) technology for all global heavy oil applications,
and will be incorporating this technology into our planned commercial
developments, as well as any new joint venture opportunities that we choose to
pursue. Produced sulphur is expected to provide additional revenue from the
project. Regulatory applications for May River's first phase will now be filed
later in November due to delayed receipt of the environmental and engineering
reports from third party consultants necessary for the application.


Dawson Project

The Dawson project is a joint venture involving our first Alberta-based, third
party THAI(TM) license. This project is located near Peace River Alberta and
will be developed in the Bluesky Formation. The upper portions of this formation
contain 11 degree API heavy oil, comparable to other conventional heavy oil
reservoirs throughout western Canada. We are planning to implement a two-well
project that will also incorporate our simplified facility design. In August
2008, a stratigraphic well was drilled on the project site that will be used as
a thermal observation well during the operations phase. The ERCB application for
the project is expected to be filed in November and with timely regulatory
approval we could commence construction at Dawson in the first quarter of 2009. 


Sutton Creek, Saskatchewan

We have acquired 35 kilometres of 2D seismic on our 23,040 acre oil sands lease
in Saskatchewan. We had originally planned to shoot a 45 kilometre program but
due to poor weather conditions the program was reduced, however we were able to
acquire data over the key target areas. Interpretation is expected to be
completed by year end at which time we will determine the next steps in an
exploration drilling program early in 2009. 


Business Development

Our wholly-owned subsidiary, Archon Technologies Ltd., continues to evaluate a
number of innovative engineering, environmental, and other value-added
technology options to improve operational efficiency and reliability, and to
reduce the overall environmental impact of hydrocarbon recovery. Other
technologies being assessed include enriched oxygen injection, produced
gas-fired cogeneration, enhanced produced water quality, and partial surface
upgrading.


We are also in late-stage negotiations on several joint ventures to demonstrate
and commercialize THAI(TM) in a wide range of large global resource
opportunities. This portfolio-based approach should also allow us to more
rapidly advance the technology and mitigate regulatory delays with the goal of
obtaining efficient and timely project approvals.


LATIN AMERICAN BUSINESS UNIT - Petrominerales Ltd. (TSX: PMG - owned 76.4%)

A full operational update of our 76.4% owned Latin American Business Unit,
Petrominerales Ltd., was published on November 6, 2008 and can be found at
www.petrominerales.com and www.sedar.com. Highlights of this release included: 


- Average crude oil production increased 176% to 12,485 bopd compared to the
third quarter of 2007.


- Production is now 19,590 bopd including production from our recently completed
Corcel-C3 well. 


- Petrominerales will be casing the Corcel-D1 well as a new pool discovery and
will immediately move to drill the D2 and D3 wells.


- Operating costs have decreased from US$10.75 per barrel in the second quarter
of 2008 to US$8.02 per barrel in the third quarter.


- Superior operating netbacks of US$86.66 per barrel reflecting a 53% increase
over the third quarter of 2007.


- Funds flow from operations increased by 288% to US$78.3 million (US$0.75 per
diluted share).


- Net income increased by 466% to US$58.0 million (US$0.57 per diluted share). 

- Strong financial position with net working capital of US$55.0 million at
September 30, 2008, an undrawn credit facility with an US$80 million borrowing
base and strong cash flows.


- Repurchased 701,800 common shares.

- Repurchased convertible debentures with a face value of US$15.5 million for
US$9.4 million.


OFFICER APPOINTMENTS

Petrobank is pleased to announce the appointment of Mr. Allen Knight, P.Eng.,
MBA as Vice President, New Ventures. Mr. Knight brings over 30 years experience
in the oil and gas industry in various senior roles with a demonstrated ability
to execute strategic acquisitions. 


Petrobank has promoted Mr. Peter Hawkes, P.Geol. to Vice President, Exploration
of the Canadian Business Unit. Mr. Hawkes has 26 years of oil and gas experience
and has played a significant role in Petrobank's exploration success since
joining the Company in 2005. 


To more clearly reflect certain roles and responsibilities within our executive
team, we have also promoted Mr. Chris Bloomer to Senior Vice President and Chief
Operating Officer, Heavy Oil, Mr. Corey Ruttan to Senior Vice President and
Chief Financial Officer and Mr. Gregg Smith to Senior Vice President and Chief
Operating Officer, Canada.


One of the key elements of our success has been the strength of our people and
we believe that these promotions reflect the strength and depth of our entire
team, who are all instrumental in delivering Petrobank's operational goals and
guiding our strategic direction.


Conference Call

Petrobank will be holding a conference call on Friday, November 14, 2008 at
9:00am (Mountain Time) to discuss Petrobank's third quarter financial and
operating results. The investor conference call details are as follows:


Webcast Link: http://events.onlinebroadcasting.com/petrobank/111408/index.php

Dial-in Number: 416-641-6105 or 1-866-862-3927

Petrobank Energy and Resources Ltd.

Petrobank Energy and Resources Ltd. is a Calgary-based oil and natural gas
exploration and production company with operations in western Canada and
Colombia. The Company operates high-impact projects through three business units
and a technology subsidiary. The Canadian Business Unit is focused on developing
a solid production platform from the Bakken light oil play in southeast
Saskatchewan, and exploiting a large undeveloped land base through the
application of new technology to large oil and gas resource opportunities. The
Latin American Business Unit, operated by Petrobank's 76.4% owned TSX-listed
subsidiary, Petrominerales Ltd. (trading symbol: PMG), is a Latin American-based
exploration and production company producing oil from three blocks in Colombia
and has contracts on 14 exploration blocks covering a total of 1.6 million acres
in the Llanos and Putumayo Basins. Whitesands Insitu Partnership, a partnership
between Petrobank and its wholly-owned subsidiary Whitesands Insitu Inc., owns
75 net sections of oil sands leases in Alberta, 36 sections of oil sands
licenses in Saskatchewan and operates the Whitesands project which is
field-demonstrating Petrobank's patented THAITM heavy oil recovery process.
THAITM 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. THAITM and CAPRITM are registered trademarks of Archon
Technologies Ltd., a wholly-owned subsidiary of Petrobank. 


Forward-Looking Statements

Certain information provided in this press release constitutes forward-looking
statements. The words "anticipate", "expect", "project", "estimate", "forecast"
and similar expressions are intended to identify such forward-looking
statements. Specifically, this press release contains forward-looking statements
relating to results of operations and the timing of certain projects. 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 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" or "resource" estimates. "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" as described
below. The following are excerpts from the definitions of resources and
reserves, contained in Section 5 of the COGE Handbook, which is referenced by
the Canadian Securities Administrators in "National Instrument 51-101 Standards
of Disclosure for Oil and Gas Activities": 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. Contingencies may include factors
such as economic, legal, environmental, political, and regulatory matters, or a
lack of markets. It is also appropriate to classify as contingent resources the
estimated discovered recoverable quantities associated with a project in the
early evaluation stage. Contingent Resources are further classified in
accordance with the level of certainty associated with the estimates and may be
subclassified based on project maturity and/or characterized by their economic
status. Resources and contingent resources do not constitute, and should not be
confused with, reserves.


Barrels of Oil Equivalent ("boe")

Disclosure provided herein in respect of boe units may be misleading,
particularly if used in isolation. A boe conversion relationship of 6 mcf to 1
barrel 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.