Athabasca Oil Sands Corp. Reports 2011 Second Quarter Financial Results and Provides Operational Update

CALGARY, Aug. 4, 2011 /CNW/ --
CALGARY, Aug. 4, 2011 /CNW/ - Athabasca Oil Sands Corp. (TSX:  ATH)
('AOSC', 'Athabasca' or the 'company') announces it has filed its
financial statements and management's discussion and analysis (MD&A)
for the three and six month periods ended June 30, 2011.  These
documents can be retrieved electronically from AOSC's website (www.aosc.com) and later this morning from SEDAR (www.sedar.com).

Athabasca Operational Update

Oil Sands Activities

The company advises that its wholly-owned oil sands development projects
at Hangingstone and Dover West, as well as its joint venture projects
at MacKay River and Dover, are progressing as planned.  Athabasca
remains on target to file its Dover West clastics and carbonates
project and pilot applications prior to year-end. The company's thermal
assisted gravity drainage (TAGD) test at Dover West has generated
positive early results and AOSC expects to test bitumen production in
late 2011 or early 2012.  Athabasca continues to evaluate a number of
oil sands business development opportunities.

Deep Basin Activities

Athabasca is pleased to announce it has drilled and completed three
wells using multi-stage fracture technology, all located in the Deep
Basin area of northwestern Alberta.  Two drilling rigs are currently
operating and a third is scheduled to arrive in late September.

Athabasca initiated its horizontal well evaluation drilling program in
Q1 2011, in the southern portion of its Deep Basin lands, near Fox
Creek, Alberta.

Athabasca has acquired in excess of one million acres of land in the
Deep Basin based on light oil and liquids-rich natural gas resource
play potential in the Duvernay, Montney and Nordegg formations.
Sveinung Svarte, Athabasca's president and CEO says, 'We are excited to
have accumulated a substantial acreage position in the heart of the
fairway where industry is demonstrating significant success,
particularly in the Duvernay and Montney formations. In addition,
several other geological formations that are promising for light oil
and liquids-rich natural gas, such as the Nordegg, have been identified
within the lands, adding to the multi-zone hydrocarbon potential in the
area.'

Evaluation Drilling Program


Initial well locations and target formations were influenced by
logistical considerations to allow for operations during spring
break-up.  Easily accessible locations for Nordegg and Montney
formations were chosen for the first three wells. The first well in the
Kaybob area is located approximately 9 km northwest of Fox Creek and
was drilled within the Nordegg formation, which is a rich source rock
believed to yield medium to heavy gravity oil in the range of 17-26°
API.  Athabasca generally targets areas where the Nordegg formation has
reached high thermal maturity, increasing the possibility of yielding
lighter oil.

Initially, this strategy seems successful with the production of 41° API
oil from the 13-14-063-20W5M well, located just off Highway 43 in the
Kaybob area. The well was drilled at a lateral length of 1,200 metres,
equipped with an openhole (ball-drop) liner system, and then was
completed with a 15-stage slickwater fracture treatment.  The well flow tested for five days, with final
restricted flow rates of approximately 500 barrels of oil
equivalent/day ('BOEPD') -- 400 barrels of oil/day ('BOPD') and 0.7
million cubic feet/day ('mmcf/d') of natural gas. The well flowed with
an oil cut of 65 - 75% (25 - 35% stimulation fluid) at approximately
290 psi flowing tubing pressure.

'Athabasca purposely limited the initial flowback rate from the shale
following the fracture treatment because we believe this will both help
prevent movement and embedment of the proppant in the near wellbore
region and help prevent closure of the fracture network,' Svarte
reports. 'The well is currently suspended having reached its maximum
permitted flare volumes.  We believe that the results from this well,
which demonstrate that the Nordegg formation is capable in certain
favourable locations of yielding high API oil and with high production
rates, if repeatable, could become a game changer for the Nordegg
formation exploitation.'

Given that the Montney section in this area is also highly prospective
and immediately underlies the Nordegg formation, a second well was
drilled from this pad site into the Montney formation with the goal of
proving productivity from both zones.

The Montney horizontal well was drilled in parallel to the Nordegg
wellbore, with a lateral offset of approximately 170 metres.  The
horizontal section was 1,196 metres in length, equipped with a similar
liner system to the Nordegg well, and was completed with a 15-stage
gelled water fracture treatment.  The well was flow tested for six
days, with final flow rates of approximately 250 BOEPD (75 BOPD and 1.1
mmcf/d) at a flowing tubing pressure of 175 psi.  The oil cut was 25%
and continuing to rise throughout the flow test, with only 30% of the
stimulation fluids recovered to date.

'Although not surprised based on results from offsetting wells drilled
by other operators, Athabasca is very encouraged by these Montney
results,' adds Svarte, 'especially considering the non-optimal fracture
treatment which took a total of five days due to a combination of
equipment failure and inclement weather.'

The density of the oil from the Montney zone was measured at 37° API,
and also showed a total mass fraction of sulphur approximately 30%
higher than that measured in the Nordegg well.  Interference testing
was conducted during the flow period between the wells with downhole
recorders, followed by an extended build-up on both formations. From
this data, the company has evidence that these two wellbores are
producing from separate reservoirs.

Athabasca has constructed a multi-well battery and short gas pipeline
for these two wells, and hopes to bring them both on production within
the next one to two weeks.

Athabasca's Waskahigan 3-22-62-23W5M well also targeted the Nordegg
formation.  The lateral section was 1,228 metres in length, equipped
with a similar openhole liner system to the other wells, and was
completed with a 15-stage slickwater fracture treatment in late March
2011.  The 30-day initial production rate for the well was 78 BOPD,
with rates restricted to maintain a bottomhole pressure above 1,100 psi.  After almost three months of production, the well is still pumping at
35 - 40 BOPD with 70% oil cut and has a total of 14,325 barrels of
stimulation fluid left to recover. The most significant production
characteristic from this well is the quality of the crude oil -
approximately 32° API.

Svarte notes, 'Again, this demonstrates that the Nordegg formation can
yield lighter oil. Continued discovery of high gravity oil and high
production rates from the Nordegg could significantly change the way
industry views its potential.'

Athabasca is currently drilling four wells on two-well pads in the
Placid and Simonette areas targeting the Nordegg and Montney
formations.  The company anticipates having completion results on all
four wells by early September.

Development


The company is preparing a holding application covering approximately 20
sections of land in the Kaybob area.  Athabasca anticipates that this
will be its first commercial development in the Deep Basin, with field
development activities commencing in 2012.  This anticipated
development is based on the early drilling success at Kaybob,
Athabasca's large land position in the Duvernay, Montney and Nordegg
formations and the easy access from Highway 43.

2011 Budget


Based on the successful results from the first three wells, a budget
increase of $61.5 million was approved in June to increase the 2011
well count from six wells to 14 wells.  The 2011 capital budget for the
Deep Basin work program is currently set at $97.7 million. Athabasca
will continue to evaluate expanding this program, including its own
Duvernay evaluation drilling program, in the latter half of this year.

Athabasca is a dynamic company focused on the development of oil
resource plays including Athabasca bitumen and Deep Basin light oil in
Alberta, Canada. It was incorporated in 2006 with a goal to use the
latest technology to produce crude oil and bitumen in a sound and safe
manner. It has excellent assets, talented people and is well financed. 
It is traded on the TSX under the symbol ATH.

Reader Advisory

This News Release contains forward-looking information that involves
various risks, uncertainties and other factors. All statements other
than statements of historical fact are forward-looking statements. The
use of any of the words 'anticipate', 'plan', 'continue', 'estimate',
'expect', 'may', 'will', 'project', 'should', 'believe', 'predict',
'pursue' and 'potential' and similar expressions are intended to
identify forward-looking statements. The forward-looking information is
not historical fact, but rather is based on AOSC's current plans,
objectives, goals, strategies, estimates, assumptions and projections
about AOSC's industry, business and future financial results. These
statements involve known and unknown risks, uncertainties and other
factors that may cause actual results or events to differ materially
from those anticipated in such forward-looking statements. No assurance
can be given that these expectations will prove to be correct and such
forward-looking statements included in this News Release should not be
unduly relied upon. These statements speak only as of the date of this
News Release. In particular, this News Release may contain
forward-looking statements pertaining to the following: AOSC's capital
expenditure programs; AOSC's drilling plans; AOSC's plans for, and
results of, exploration and development activities; AOSC's estimated
future commitments; business plans; AOSC's plans with respect to the
Deep Basin assets; and the timing for receipt of regulatory approvals.
With respect to forward-looking statements and forward-looking
information contained in this News Release, assumptions have been made
regarding, among other things: future well production rates, well
drainage areas, success rates of future well drilling ; AOSC's ability
to obtain qualified staff and equipment in a timely and cost-efficient
manner; the regulatory framework governing royalties, taxes and
environmental matters; the applicability of technologies for the
recovery and production of AOSC's reserves and resources; future
capital expenditures to be made by AOSC; future sources of funding for
AOSC's capital programs; geological and engineering estimates in
respect of AOSC's reserves and resources; the geography of the areas in
which AOSC is conducting exploration and development activities;  and
AOSC's ability to obtain financing on acceptable terms. Actual results
could differ materially from those anticipated in these forward-looking
statements as a result of the risk factors set forth above and in the
Company's Annual Information Form dated March 28, 2011, which is
available on the SEDAR website at www.sedar.com ('AIF'), including:
fluctuations in market prices for crude oil, natural gas and bitumen
blend; general economic, market and business conditions; variations in
foreign exchange and interest rates; factors affecting potential
profitability; uncertainties inherent in estimating quantities of
reserves and resources; AOSC's status and stage of development;
uncertainties inherent in Steam Assisted Gravity Drainage ('SAGD'),
Cyclic Steam Stimulation ('CSS'), Thermal Assisted Gravity Drainage
('TAGD') and other bitumen recovery processes; the potential impact of
the exercise of the Put/Call Options (as defined in the AIF) on AOSC;
failure to meet development schedules and potential cost overruns;
increases in operating costs can make projects uneconomic; the effect
of diluent and natural gas supply constraints and increases in the
costs thereof; gas over bitumen issues affecting operational results;
environmental risks and hazards and the cost of compliance with
environmental regulations, including greenhouse gas regulations and
potential Canadian and U.S. climate change legislation; failure to
obtain or retain key personnel; the substantial capital requirements of
AOSC's projects; the need to obtain regulatory approvals and maintain
compliance with regulatory requirements; extent of, and cost of
compliance with, government laws and regulations and the effect of
changes in such laws and regulations from time to time; changes to
royalty regimes; political risks; failure to accurately estimate
abandonment and reclamation costs; risks inherent in AOSC's operations,
including those related to exploration, development and production of
oil sands, crude oil and natural gas reserves and resources, including
the production of oil sands reserves and resources using SAGD, CSS,
TAGD or other in-situ technologies and the production of crude oil and
natural gas using multistage fracture and other stimulation
technologies; the potential for management estimates and assumptions to
be inaccurate; long term reliance on third parties; reliance on third
party infrastructure for project facilities; failure by counterparties 
to make payments or perform their operational or other obligations to
AOSC in compliance with the terms of contractual arrangements between
AOSC and such counterparties and the possible consequences thereof; the
potential lack of available drilling equipment and limitations on
access to AOSC's assets; aboriginal claims; seasonality; hedging risks;
risks associated with establishing and maintaining systems of internal
controls; insurance risks; claims made in respect of AOSC's operations,
properties or assets; competition for, among other things, capital, the
acquisition of reserves and resources, export pipeline capacity and
skilled personnel; the failure of AOSC or the holder of certain
licenses or leases to meet specific requirements of such licenses or
leases; risks arising from future acquisition activities; volatility in
the market price of the common shares. In addition, information and
statements relating to 'reserves' and 'resources' are deemed to be
forward-looking information and statements, as they involve the implied
assessment, based on certain estimates and assumptions, that the
reserves and resources described exist in the quantities predicted or
estimated, and that the reserves and resources described can be
profitably produced in the future. The assumptions relating to AOSC's
reserves and resources are contained in the reports of GLJ Petroleum
Consultants Ltd. dated effective April 30, 2011 and  DeGolyer and
MacNaughton Canada Limited dated effective April 30, 2011. The risks
and uncertainties referred to above are described in more detail in
AOSC's AIF which is available on the SEDAR website at www.sedar.com.  See also AOSC's financial statements and Management's Discussion and
Analysis for the year ended December 31, 2010 and for the current
interim financial period, which are also available on SEDAR. Readers
are cautioned that the foregoing list of risk factors should not be
construed as exhaustive. The forward-looking statements included in
this News Release are expressly qualified by this cautionary statement.
AOSC does not undertake any obligation to publicly update or revise any
forward-looking statements except as required by applicable securities
laws.

'BOEs' may be misleading, particularly if used in isolation.  A BOE
conversion ratio of six thousand cubic feet of natural gas to one
barrel of oil equivalent (6 Mcf: 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 wellhead.

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