Petrobank Announces Record First Quarter Results

Petrobank Energy and Resources Ltd. ("Petrobank" or the "Company") (TSX:PBG)
(OSLO:PBG) is pleased to announce record first quarter 2008 financial and
operating results.


HIGHLIGHTS

- Average production in the first quarter of 2008 increased to 22,524 barrels of
oil equivalent per day ("boepd") compared to 6,139 boepd in the first quarter
2007, a 267% increase. Canadian Business Unit ("CBU") production increased by
239% to 13,889 boepd and production from the Latin American Business Unit
("LABU") increased by 323% to 8,635 barrels of oil per day ("bopd").


- The Peerless Energy Inc. ("Peerless") acquisition was completed on January 28,
2008 for $338.8 million, including net debt assumed. Peerless 3P reserves at
December 31, 2007 totalled 18.7 million boe with net present value, before tax,
discounted at 10% of $445.6 million. Production and financial results for
Peerless have been included in Petrobank's results starting January 28, 2008.


- Funds flow from operations increased by 577% to $123.5 million in the first
quarter 2008 or $1.36 per diluted share compared to $18.2 million ($0.25 per
diluted share) in the first quarter of 2007.


- First quarter 2008 net income increased by 850% to $35.5 million compared to
$3.7 million in the first quarter of 2007. On a per diluted share basis, net
income increased by 700% to $0.40.


FINANCIAL & OPERATING HIGHLIGHTS

The following table provides a summary of Petrobank's financial and operating
results for the three months ended March 31, 2008 and 2007. Consolidated
financial statements with Management's Discussion and Analysis ("MD&A") are
available on our website at www.petrobank.com under the "Investor Relations -
Financial Reports" section.




(All references to $ are Canadian dollars unless otherwise noted)

Three months ended March 31,                     2008       2007   % change
----------------------------------------------------------------------------
Financial
($000s, except where noted)
Oil and natural gas revenue                   173,604     29,471        489
Funds flow from operations (1)                123,488     18,235        577
  Per share - basic ($)                          1.53       0.25        512
            - diluted ($)                        1.36       0.25        444
Net income                                     35,537      3,739        850
  Per share - basic ($)                          0.44       0.05        780
            - diluted ($)                        0.40       0.05        700
Capital expenditures                          200,270     72,612        176
Total assets                                1,737,225    480,896        261
Net debt (1)                                  181,306     93,932         93
Common shares outstanding, end of
 period (000s)
  Basic                                        82,489     72,433         14
  Diluted (2)                                  96,889     76,689         26
----------------------------------------------------------------------------
----------------------------------------------------------------------------

Operations
Canadian Business Unit ("CBU") operating
 netback ($/boe except where noted) (1) (3)
  Oil and NGL revenue ($/bbl)                   91.87      62.87         46
  Natural gas revenue ($/mcf)                    7.73       7.05         10
  Oil and natural gas revenue                   83.55      50.80         64
  Royalties                                      6.74       5.78         17
  Production expenses                            9.35       8.42         11
----------------------------------------------------------------------------
  Operating netback (4)                         67.46      36.60         84
Latin American Business Unit ("LABU")
 operating netback ($/bbl) (1)
  Oil revenue                                   86.53      58.44         48
  Royalties                                      8.25       4.67         77
  Production expenses                           10.86       8.26         31
----------------------------------------------------------------------------
  Operating netback (4)                         67.42      45.51         48
Average daily production (3)
  CBU - oil and NGL (bbls)                     11,351      1,692        571
  CBU - natural gas (mcf)                      15,229     14,429          6
----------------------------------------------------------------------------
  Total CBU (boe)                              13,889      4,097        239
  LABU - oil (bbls)                             8,635      2,042        323
----------------------------------------------------------------------------
  Total Company conventional (boe)             22,524      6,139        267
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(1) Non-GAAP measure. See "Non-GAAP Measures" section within Management's
    Discussion and Analysis ("MD&A").
(2) Assumes 8.8 million common shares will be issued upon conversion of the
    Company's convertible debentures which were issued in May 2007.
(3) Six mcf of natural gas is equivalent to one barrel of oil equivalent
    ("boe"). Heavy Oil Business Unit ("HBU") bitumen volumes are excluded
    from average daily production as Whitesands operations are considered
    to be in the pre-operating stage and accordingly are capitalized.
(4) Excludes hedging activities.



OPERATIONAL UPDATE

CANADIAN BUSINESS UNIT

Petrobank's Canadian Business Unit production averaged 13,889 boepd in the first
quarter, a 239% increase from the 4,097 boepd produced in the first quarter of
2007 and a 68% increase from the 8,254 boepd produced in the fourth quarter of
2007. On January 28, 2008, we closed the acquisition of Peerless for $339
million, including net debt assumed. Production for this quarter only includes
two months of the Peerless production acquired. Canadian Business Unit
production averaged 16,238 boepd in March 2008, including 12,400 boepd of high
netback, Bakken production.


In February 2008, we purchased an additional 7.5 sections of Bakken acreage at
the Crown land sale, further increasing our Bakken land base to 214 sections
(137,000 net acres). Of this, 186 net sections were undeveloped with an
estimated drilling inventory of over 660 (624 net) locations based on only four
wells per section. Our plan is to drill 154 of these locations (net) in 2008,
which we expect will make Petrobank the most active operator in the play.


In the first quarter of 2008 we drilled 45.2 net Bakken locations. After an
earlier than expected spring break-up from late March through mid-April, we have
now recommenced our extensive Bakken development drilling program with seven
active rigs operating on the trend, resulting in two to three new wells per
week. In addition, we have started construction of our first satellite facility
which will process production from our Creelman area with a pipeline connection
to our main Midale facility to capture the associated natural gas and liquids
production. This facility is expected to be fully operational by the end of
July. We also expect to have the Peerless Innes facility pipeline connected to
our Midale facility in the same time frame. Our previously announced Freestone
facility will now be an oil battery and gas conservation facility with a
pipeline connection to our main Midale facility for natural gas liquids
extraction and gas processing. This Freestone facility is expected to be
completed by the end of the third quarter of 2008 and will likely also process
gas for other third parties. These infrastructure enhancements will allow us to
maximize our liquids rich natural gas production and reserves from the play
while significantly reducing operating costs and improving our overall project
economics.


The Bakken formation produces light oil in close proximity to Canada's main oil
pipelines. Operating netbacks are high, particularly when considering the
current environment of record oil prices, the attractive Saskatchewan royalty
regime, and relatively low operating costs. The operating netback for our
operated Bakken oil production during the first quarter of 2008 was $79.19 per
barrel, with WTI averaging US$97.82 per barrel during this period.


During the balance of 2008, in addition to our ongoing development of our Bakken
field we plan to initiate the testing of exciting new exploration and applied
technology ideas in southeast Saskatchewan, northwest Alberta, northeast British
Columbia, and Princeton, British Columbia.


HEAVY OIL BUSINESS UNIT

Whitesands Project

At Whitesands we continue to produce partially upgraded oil via the THAI(TM)
process. THAI(TM) continues to meet or exceed our technical expectations and our
plans to expand Whitesands and develop the Dawson and May River projects are
proceeding. However, operations at Whitesands have been hampered by excess sand
production, which is due to the liner slot size used in the original three wells
and is not related to the THAI(TM) process. The long term plan for all future
wells is to implement a revised down-hole completion design in conjunction with
simplified surface facilities, which should eliminate the large majority of the
produced sand and allow us to produce our new wells at higher rates and
increased on-stream factors. In the interim, we will continue to make temporary
modifications to our operating procedures and surface equipment to deal with
this sand production from the existing wells.


Facility upgrades at Whitesands to better manage produced sand and to improve
gas sweetening were fully operational by the end of the first quarter. The
wellhead de-sand facilities, which were mechanically complete at the end of
2007, have improved on-stream factors. The extended well on-stream times have
also more fully demonstrated a unique production characteristic of the initial
three wells, whereby they periodically unload large liquid and sand volumes that
overload the surface facilities. While the new sand handling facilities have
been able to manage production cycles, enabling longer run times, they still
require downtime for cleanouts and to solve mechanical and operations
procedures. The present facilities design, while improving operations, will be
modified for future facilities. During the quarter we installed temporary
facilities, similar to our revised design for the May River and Dawson projects,
which utilizes primary gas separation followed by tank separation of oil, water
and sand, rather than using one pressure vessel. Each well was tested several
times with positive results, confirming our future design path. Extreme cold
weather during the first quarter, along with commissioning and operating
problems with the new incinerator brought on-stream in February, constrained
operations and slowed the rate of increase of air injection and production.


Produced oil continues to show a substantial degree of upgrading at the
wellhead, ranging between 11 and 17 degrees API and is currently averaging 12
degrees API, compared to the native 8 degree API bitumen in-situ. In addition,
we have segregated oil with an API gravity of over 30 degrees from our secondary
separation. This lighter oil is carried by the overhead gas stream as a vapour,
condensing in the secondary separators. This lighter fraction is indicative of
significant in-situ thermal cracking. Produced gas analysis also indicates
ongoing high temperature combustion with significant levels of free hydrogen
production, which will be beneficial for the CAPRI(TM) process. Finally, initial
analysis of our 4D seismic survey acquired early in the first quarter has
provided a clear indication of the area affected by the THAI(TM) process,
further demonstrating the toe-to-heel flow direction.


Early in the second quarter we received the license to the drill our first
THAI(TM)/CAPRI(TM) well, P3B, as a replacement for our existing P3 well; the
well pad is complete, the rig is on-site and we expect to begin drilling later
this week. Because of the unique nature of this well, additional review with the
regulatory authorities was required, further delaying the timing for approval of
the well license. The first THAI(TM)/CAPRI(TM) integrated liner for P3B has been
successfully manufactured and is being transported to the site this week. This
major accomplishment is a world-first and has proven the design and
manufacturing feasibility of integrating a catalyst within a production liner.
The liner also incorporates narrower slots designed to minimize sand production.


In advance of drilling P3B we shut-in the P3 well and initiated a workover
operation to pull the production, steam control, and thermocouple instrument
tubing strings from the horizontal section of the well. We have been able to
successfully remove all of the production tubing and the majority of the
instrument and control tubing. Examination of the tubing showed it to be in good
condition and we plan to attempt to retrieve the remaining tubing, log the
original liner and evaluate the well for further utilization.


Our regulatory application for the three well expansion project, adjacent to the
existing Whitesands site, is in the approval process. We are ready to commence
drilling these THAI(TM)/CAPRI(TM) wells and expect to receive an indication of
final timing from the regulatory authorities later this month. With prompt
approval, these wells could be drilled in the third quarter of 2008.


May River Project

The May River Project is our commercial expansion plan for the THAI(TM)
technology on the Whitesands leases. Recent plant production experience and
engineering to date provided the basis for simplifying our central May River
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 to 15,000 bopd of partially upgraded oil, ultimately building capacity to
100,000 bopd. The regulatory applications for the first phase are expected to be
filed in the third quarter of 2008. With timely receipt of regulatory approvals,
construction could begin in early 2009 with project startup in late 2009.


Dawson Project

The Dawson project is a joint venture involving our first Alberta-based, third
party THAI(TM) license. This project is located in Alberta's Peace River area
and is the first THAI(TM) project in a conventional heavy oil reservoir, another
important step in taking the technology to a global market. We are planning to
implement a two-well project that will incorporate our simplified facilities
design. With timely regulatory approval we could commence construction at Dawson
later in 2008. This summer, we expect to drill a stratigraphic well which will
be used to confirm horizontal well locations and will also be used as a thermal
observation well.


Sutton Creek, Saskatchewan

In 2007 we acquired a township of land (36 square miles or 23,040 acres) with
oil sands potential at Sutton Creek, Saskatchewan. This new land position is
located within a new and promising oil sands fairway. A 2D seismic survey is
planned for the area in the second half of 2008 as ground conditions permit.


Technology Development - Archon Technologies Ltd.

We achieved a major milestone with the successful manufacturing of the first
THAI(TM)/CAPRI(TM) liner. This significant innovation further demonstrates our
ability to convert the intellectual property being generated by Archon into
practical solutions for the oil industry.


We have also evaluated a number of heavy oil reservoirs with potential third
party licensing partners, and have conducted laboratory reactor tests of their
oil to determine the combustion characteristics and the degree of potential
upgrading. These evaluations have demonstrated the feasibility of THAI(TM) in a
wide range of heavy oil reservoirs domestically and internationally.


As part of our ongoing research and development process we are working with
other research institutions. Recently we entered into a research program with
the University of Bath and the University of Birmingham to evaluate the
optimization of CAPRI(TM) for the in-situ upgrading of heavy oil. This project
has received $1.5 million in funding from the Engineering and Physical Sciences
Research Council (EPRSC) (UK).


Archon is continuing to evaluate a number of innovative engineering,
environmental, and other value added technology options to improve operational
efficiency and flexibility and to reduce the environmental impact of commercial
developments. Other technologies include enriched oxygen injection, utilizing
produced gas to cogenerate enough power to be energy self sufficient, sulphur
recovery, and partial surface upgrading. These technologies can be incorporated
into commercial designs and will have a major impact in further reducing our
overall environmental footprint and greenhouse gas emissions.


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 May 6, 2008 and can be found at
www.petrominerales.com and www.sedar.com. Highlights of the first quarter
include:


- Crude oil production increased by 323%, averaging 8,635 bopd in the first
quarter of 2008, mainly due to production from our Corcel-A1, Corcel-A2,
Orito-121 and Orito-161 wells.


- Operating netbacks increased by 73% to US$67.15 per barrel in the first
quarter of 2008.


- Petrominerales funds flow from operations increased by 769% to US$45.2 million.

- Petrominerales net income increased by 1,227% to US$22.2 million.

ANNUAL AND SPECIAL MEETING

We remind shareholders that Petrobank's annual and special meeting (the
"Meeting") will be held tomorrow (Wednesday, May 14, 2008) at 3:00 p.m. (Calgary
time) in the Devonian Room of the Calgary Petroleum Club, 319 Fifth Avenue SW,
Calgary, Alberta, Canada, T2P 0L5.


In addition, the Meeting will be webcast live and available for replay at
http://www.petrobank.com/inv-corporatepresentation.html. To listen to the
Meeting live please enter
http://www.newswire.ca/en/webcast/viewEvent.cgi?eventID=2280960 in your web
browser. After the formal business of the Meeting and corporate presentation,
management of the Company will provide a question and answer period. For
shareholders participating by webcast, you may e-mail questions to
[e-mail]. Petrobank's management will endeavor to answer as many
questions as possible during the time frame allotted.


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 CBU is developing a solid production platform
from low risk gas opportunities in central Alberta and an extensive inventory of
Bakken light oil locations in southeast Saskatchewan, complemented by new
exploration projects and a large undeveloped land base. The LABU, 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 15 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 oil sands leases containing
up to 805 million barrels of proved, probable, possible and contingent
recoverable resources, based on conventional (SAGD) technology, and operates the
Whitesands project which is field-demonstrating Petrobank's patented THAI(TM)
heavy oil recovery process. THAI(TM) 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(TM) and CAPRI(TM) 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.


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
bbl is based on an energy equivalency conversion method primarily applicable at
the burner tip and does not represent a value equivalency at the well head.