The Globe and Mail

Go to the Globe and Mail homepage

Jump to main navigationJump to main content

Press release from CNW Group

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

Thursday, August 04, 2011

Athabasca Oil Sands Corp. Reports 2011 Second Quarter Financial Results and Provides Operational Update06:00 EDT Thursday, August 04, 2011CALGARY, 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 ActivitiesThe 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 ActivitiesAthabasca 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 ProgramInitial 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 slickwaterfracture 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.DevelopmentThe 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 BudgetBased 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 AdvisoryThis 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.For further information: MEDIA:        FINANCIAL COMMUNITY: Heather Douglas      Tracy Robinson Vice President, Communications & External Affairs  Manager, Investor Relations (403) 532-7408       (403) 532-7446 hdouglas@aosc.com      trobinson@aosc.com