Athabasca Oil Corporation Provides Second Quarter 2012 Results and Operational Update

CALGARY, July 26, 2012 /CNW/ - Athabasca Oil Corporation (TSX:  ATH) today reported second quarter 2012 operational results.

Highlights include:

  • 13% increase in contingent resource (best estimate) to 10,401 million barrels (bbl);
  • Thermal Assisted Gravity Drainage (TAGD) "proof of concept" field test successfully delivered all test targets, paving the way to approval and construction of the TAGD pilot/demonstration project;
  • The Light Oil Division re-tested its Kaybob Duvernay well at a stabilized rate of 800 barrels of oil equivalent per day (boe/d) reporting a 70% increase in oil rate (650 bbl/d of 43°API oil) at a flowing pressure of approximately 7,000 kiloPascals gauge (kPag);
  • More than 7,000 boe/d of production from the Light Oil Division (50% oil and NGLs) behind pipe, awaiting completion of Athabasca's wholly-owned treating facilities.

Athabasca is pleased to report that pursuant to recent third party independent evaluations it has increased its total proved plus probable reserves to 359 million boe. Additionally, the company's contingent resource (best estimate) has increased to 10,401 million bbl, which includes pro forma resources attributable by GLJ Petroleum Consultants Ltd. (GLJ) to the company's acquisitions in the Dover West Liege area. The third-party independent evaluations were prepared by GLJ and DeGolyer and MacNaughton Canada Limited (D&M) with effective dates of April 30, 2012 and are reported in the company's Pro Forma Reserves and Resource Assessment (see Schedule A, attached).

"It is very encouraging that Athabasca continues to add considerable bitumen resources and that the company's projects are tracking on schedule," says Sveinung Svarte, president and CEO. "The Duvernay well production re-test results are also very strong, and confirm Athabasca's light oil strategy targeting the liquids-rich portion of the Western Canadian sedimentary basin."

Athabasca has filed its financial statements and management's discussion and analysis (M&DA) for the three and six month periods ended June 30, 2012. These documents can be retrieved electronically from Athabasca's website ( and, later this morning, from SEDAR (

Thermal Oil Division

The company had an active and productive Q2 2012, proceeding on many fronts — exploration, development, road construction, TAGD production testing, environmental impact assessments, engineering procurement and modularization — as it added value to its numerous thermal oil assets.

Effective April 30, 2012, according to GLJ's and D&M's pro forma reserve and resource assessments, the Thermal Oil Division reports total proved plus probable reserves of 339 million bbl, and a 13% increase of its contingent resource (best estimate) to 10,401 million bbl.

Hangingstone SAGD
The winter drilling and seismic programs were successful at Hangingstone, reconfirming Athabasca's original bitumen resource estimates for the area and demonstrating the company's geological and geophysical teams' deep understanding of the subsurface depositional environments. The drilling program was completed without a safety incident, reaffirming Athabasca's track record and focus on safety during field operations.

The front end engineering and design (FEED) process for the Hangingstone Project 1 (a 12,000 bbl/d steam assisted gravity drainage, or SAGD, project) is progressing as scheduled and the company is fully staffed for the project execution. Regulatory approval is expected during Q3 2012, procurement of long-lead equipment has been undertaken, and first steam is anticipated by Q3 2014. Hangingstone Project 1 is intended to be followed by two 35,000 bbl/d SAGD projects in line with the area's potential production of more than 80,000 bbl/d.

Dover West Sands SAGD
During Q1 2012, Athabasca acquired a 25% interest in 29,300 acres of oil sands leases in the Dover West area. During Q2 2012, the company increased its ownership to a 100% working interest in those leases.

Athabasca substantially completed its 64 kilometre road construction at Dover West during Q2 2012, and is on track for the scheduled start-up of a 12,000 bbl/d SAGD production facility in 2015. Regulatory approval is expected in 2013.

Engineering and development plans progressed, during Q2 2012, at Dover West. The regulatory approval process is moving forward, on schedule.

Dover West Carbonates TAGD
Situated 90 kilometres northwest of Fort McMurray, Athabasca's 100%-owned Leduc carbonate trend — originally formed as a carbonate reef and characterized today by excellent porosity and permeability — lies below the company's Dover West sands. Based upon GLJ's April 30, 2012 pro forma assessments, and employing SAGD production technology, Athabasca's Leduc trend is estimated to contain 16,300 million barrels of total petroleum initially in place (PIIP), and 2,800 million barrels of contingent resource (best estimate).

Production from the company's bitumen-rich Leduc carbonates at Dover West is forecasted to utilize the TAGD production process. A "proof of concept" field test successfully delivered all of its objectives, confirming that the company could effectively heat the reservoir and mobilize bitumen to a production well, paving the way to initiating the TAGD pilot/demonstration project.

The field test successfully mobilized bitumen at lower temperatures than those utilized in the SAGD production process. The field test also gathered data on the Leduc reservoir permeability and thermal conductivity. Finally, it demonstrated the reliability and performance of the heating cables.

The bitumen was mobilized at 70 to 90 degrees Celsius (°C) and field testing demonstrated that approximately 60% to 70% of the bitumen, heated to greater than 80 °C, was recovered during the production process. The heating cables were fully operational throughout the field test.

Data obtained during the field test has enabled Athabasca to model its proprietary production technology, and to simulate the performance of a commercial TAGD project in the Leduc carbonates.

The Leduc field testing indicates that effective reservoir permeability is considerably higher than previously anticipated. Reservoir modelling based upon field testing, illustrates that commercial scale wells heated to temperatures in the range of 120 - 140 °C should yield single well production rates in the order of 1,000 - 2,000 bbl/d, depending on reservoir thickness.

Because the TAGD process does not require steam generation and water treatment facilities which are essential parts of SAGD projects, total capital exposure is reduced by approximately 50% compared to a SAGD project. Accordingly, expected rates of return for a TAGD project will be in the order of approximately 5% to 10% higher than for a comparably sized SAGD project.

Athabasca anticipates receiving regulatory approval for the TAGD pilot/demonstration project by year-end. Work continues on design and procurement of the project, and an innovative heater assembly facility is being constructed near Strathmore, Alberta.

Pending regulatory approval, Athabasca plans to launch its TAGD pilot/demonstration project in 2013, with an initial two-year-long drilling, construction and installation phase, followed by a production phase. The company anticipates achieving the objectives of the pilot/demonstration project within two years after start up.

Joint Venture Activities
The company has been undertaking joint venture initiatives during the first six months of 2012 and is confident that an oil sands joint venture agreement may be concluded during Q3 2012.

Light Oil Division

A mid-year review of the company's drilling, completion and testing program, effective April 30, 2012, by GLJ, has resulted in an increase in the Light Oil Division's total proved plus probable reserves to 20 million boe, comprised of 45% oil and NGLs.

Athabasca currently has more than 7,000 boe/d (50% oil and NGLs) behind pipe, awaiting tie-in during Q3 and Q4 2012.

The second quarter, 2012 was quiet from a completion point of view, as expected during spring break-up, with only two new wells completed. Athabasca drilled 10 wells during Q2, all of which are scheduled to be completed during the third quarter.

The company recently re-tested its previously announced Kaybob Duvernay horizontal oil well at 100/08-18-064-17W5M (previously denoted as 102/07-18-064-17W5M). The well was flowed for another 90 hours, achieving final stabilized rates of 800 boe/d (650 bbl/d of 43° API oil plus 65 bbl/d of NGLs) at a flowing pressure of approximately 7,000 kPag. This production test result represents a significant increase in rates from the original test results (70% increase in oil rate) and a tenfold increase in flowing pressure.

During Q2 2012, Athabasca conducted multi-stage hydraulic fracture completions on one Montney and one Nordegg well, both with successful results. The Kaybob East 100/04-26-64-18W5M horizontal Montney well was flow tested for 72 hours, producing at a final stabilized rate of approximately 965 boe/d (20% oil) at a flowing pressure of 12,500 kPag, reaffirming the presence of high quality Montney reservoir rock in Athabasca's Kaybob East area.

Given positive drilling and production testing results, the company has increased the capacity of certain facilities and has accelerated infrastructure construction, adding $60-million to its 2012 Light Oil capital budget.

Athabasca is currently constructing three oil batteries and gas compression facilities which will enable it to bring processing capacity to 36,000 bbl/d of oil production and 43 mmcf/d of gas production by year-end. The company is also extending the Simonette-Kaybob West trunk pipeline into the Kaybob East and Placid areas. These new facilities and pipelines are designed to reduce Athabasca's dependence on third-party infrastructure, increasing certainty of future growth plans. Bullish on the area, the company has advanced $40 million of its anticipated 2013 drilling budget to Q4 2012, facilitating production increases in 2012.

Given the foregoing field activities, the company is increasing its year-end exit rate production estimates to between 10,000 and 11,000 boe/d. The total 2012 Light Oil capital budget now stands at $525 million. The increased Light Oil capital budget is expected to be offset by a reduction in the Thermal Oil capital budget as a result of a reduced working interest in certain project areas as a result of a possible joint venture arrangement.

Athabasca is a dynamic, Canadian company focused on the development of oil resource plays in Alberta, Canada. The company has accumulated an extensive, high quality resource base suitable for the extraction of thermal crude oil (bitumen) and light oil.  Well financed and endowed with quality assets and talented people, Athabasca is poised to become a major Canadian oil producer. It aspires to produce 220,000 boe/d by 2020, half thermal oil and half light oil. Athabasca is traded on the TSX under the symbol ATH.

Conference Call and Webcast Today July 26, 2012
9:00 am Mountain Time (11:00 am Eastern Time)

A conference call to discuss the second quarter will be held for the investment community and media on July 26, 2012 at 9:00 a.m. MT (11:00 a.m. ET). To participate, please dial 888-231-8191 (toll-free in North America) or 647-427-7450 approximately 15 minutes prior to the conference call. An archived recording of the call will be available from approximately 2:00 p.m. ET on July 26 until midnight on August 9, 2012 by dialing 855-859-2056 (toll-free in North America) or 416-849-0833 and entering conference password 96770614.

We also invite you to view the live video-stream webcast and conference call presentation via the following URL:
The webcast will be archived for approximately 365 days.

Reader Advisory:

This News Release contains forward-looking information that involves various risks, uncertainties and other factors. All information other than statements of historical fact is forward-looking information. 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 information. The forward-looking information is not historical fact, but rather is based on the Company's current plans, objectives, goals, strategies, estimates, assumptions and projections about the Company's industry, business and future financial results. This information involves 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 information. No assurance can be given that these expectations will prove to be correct and such forward-looking information included in this News Release should not be unduly relied upon. This information speaks only as of the date of this News Release. In particular, this News Release may contain forward-looking information pertaining to the following: expected timing of receipt of first significant revenues from the Company's assets; the Company's capital expenditure programs; the estimated quantity of the Company's Probable and Possible Reserves and Contingent Resources; the Company's drilling plans; the Company's plans for, and results of, exploration and development activities; the Company's estimated future commitments; business plans; development of the Company's Thermal Oil Division projects; timing of facilities construction and production; the use of in-situ recovery methods such as Steam Assisted Gravity Drainage (SAGD) and Thermal Assisted Gravity Drainage (TAGD) for production of recoverable bitumen, including the potential benefits of such methods; targeted 2012 exit rate production and long term production goals; timing of submission of project regulatory applications; estimated timing of first steaming, selection of equipment manufactures and internal sanction, as applicable, of the Company's projects; estimated initial and full production of the Company's projects; Athabasca's plans with respect to the Light Oil Divisions assets and the expected benefits to be received by Athabasca from such assets; expectations regarding the Company's Light Oil Division development areas including anticipated production levels and timing of receipt of significant revenues and operating results therefrom; and  expected increase to number of staff members in 2012.

With respect to forward-looking information contained in this News Release, assumptions have been made regarding, among other things: the Company's ability to obtain qualified staff and equipment in a timely and cost-efficient manner; the regulatory framework governing royalties, taxes and environmental matters in the jurisdictions in which the Company conducts and will conduct its business; the applicability of technologies for the recovery and production of the Company's reserves and resources; future capital expenditures to be made by the Company; future sources of funding for the Company's capital programs; the Company's future debt levels; geological and engineering estimates in respect of the Company's reserves and resources; the geography of the areas in which the Company is conducting exploration and development activities; the impact that the agreements relating to the PetroChina Transaction (the "PetroChina Transaction Agreements") will have on the Company, including on the Company's financial condition and results of operations; and the Company's ability to obtain financing on acceptable terms.

Actual results could differ materially from those anticipated in this forward-looking information as a result of the risk factors set forth in the Company's most recent Annual Information Form filed on March 27, 2012 ("AIF") that is available on SEDAR at, including, but not limited to: fluctuations in market prices for crude oil, natural gas and bitumen blend; general economic, market and business conditions; dependence on Cretaceous as the joint venture participant in the Dover oil sands projects; variations in foreign exchange and interest rates; factors affecting potential profitability; factors affecting funding, including the development of new business opportunities, the availability of financing, developments in technology, the priorities of the Company and of its current and future joint venture partners and general economic conditions; uncertainties inherent in estimating quantities of reserves and resources; uncertainties inherent in SAGD and TAGD; the potential impact of the exercise of the Dover put/call options on the Company; failure to meet the conditions precedent to the exercise by the Company of the Dover put option; failure to receive regulatory approval for the Dover, Hangingstone, Dover West Sands or other oil sands projects when anticipated or at all; failure to obtain necessary regulatory approvals for completion of the Dover put/call option transaction, if any; failure to meet development schedules and potential cost overruns; increases in operating costs making projects uneconomic; the effect of diluent and natural gas supply constraints and increases in the costs thereof; gas over bitumen issues affecting operational results; the potential for adverse consequences in the event that the Company defaults under certain of the PetroChina Transaction Agreements; environmental risks and hazards and the cost of compliance with environmental regulations; failure to obtain or retain key personnel; the substantial capital requirements of the Company's projects; the need to obtain regulatory approvals and maintain compliance with regulatory requirements; changes to royalty regimes; political risks; failure to accurately estimate abandonment and reclamation costs; risks inherent in the Company'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 and TAGD and the production of crude oil and natural gas using multi-stage fracture and other stimulation technologies; the potential for management estimates and assumptions to be inaccurate; reliance on third party infrastructure for project facilities; failure by counterparties (including without limitation Cretaceous) to comply with  contractual arrangements between the Company and such counterparties; the potential lack of available drilling equipment and limitations on access to the Company's assets; Aboriginal claims; seasonality; hedging risks; insurance risks; claims made in respect of the Company's operations, properties or assets; the potential for adverse consequences as a result of the change of control provisions in the PetroChina Transaction Agreements; competition for, among other things, capital, the acquisition of reserves and resources, export pipeline capacity and skilled personnel; the failure of the Company or the holder of certain licenses or leases to meet specific requirements of such licenses or leases; risk of reassessments of the Company's tax filings by taxation authorities; risks arising from future acquisition and joint venture activities; volatility in the market price of the common shares; and the effect that the issuance of additional securities by the Company could have on the market price of the common shares. In addition, information and statements in this News Release relating to "reserves" and "resources" are deemed to be forward-looking information, 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. For further information regarding the assumptions relating to the Company's reserves and resources see "Independent Reserve and Resource Evaluations - Contingent Resources Estimates" and "Risk Factors" in the AIF. For additional information regarding the specific contingencies which prevent the classification of the Company's Contingent Resources as Reserves see "Independent Reserve and Resource Evaluations - Contingent Resources Estimates" in the AIF. The forward-looking statements included in this News Release are expressly qualified by this cautionary statement. Athabasca does not undertake any obligation to publicly update or revise any forward-looking statements except as required by applicable securities laws.

Oil and Gas Information:

"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.

Test Results and Initial Production Rates:

A pressure transient analysis or well-test interpretation has not been carried out and thus the test results provided in this News Release should be considered to be preliminary until such analysis or interpretation has been completed. Test results and initial production rates disclosed herein may not necessarily be indicative of long term performance or of ultimate recovery.

Schedule  A
Pro Forma Reserves and Resources Summary
for Athabasca Oil Corporation
by GLJ Petroleum Consultants Ltd

The following table sets forth certain summary information in respect of the oil sands and light oil assets of Athabasca Oil Corporation ("Athabasca" or the "Company") as at April 30, 2012(1).

Asset   Working
Interest Best
  Light Oil
Gross Proved
  Light Oil
  Light Oil
Dover(8)(9)   40   -   137.5   15.7   1,222   -   -   -
Dover West                                
  Oil Sands   100   -   84.5   20.9   2,930(12)   -   -   -
  Carbonates   100   -   -   -   2809   -   -   -
Birch   100   -   -   -   2,111   -   -   -
Hangingstone   100   -   117.5   14.8   911   -   -   -
Grosmont(7)   50   -   -   -   418   -   -   -
Light Oil   99.6   -   -   -   -   8.4   11.8   5.3
Total   N/A   -   339.5   51.5   10,401   8.4   11.8   5.3


(1)      Totals may not add due to rounding.
(2)      The product type that is reasonably expected is bitumen which is a naturally occurring viscous mixture consisting mainly of pentanes and heavier hydrocarbons. Its viscosity is greater than 10,000 milliPascal seconds (centipoise) measured at original temperature in the reservoir and atmospheric pressure, on a gas-free basis. Crude bitumen may contain sulphur and other non-hydrocarbon compounds.
(3)      Based on: (i) the reports of GLJ Petroleum Consultants Ltd. ("GLJ") dated effective as of April 30, 2012 assessing and evaluating the Proved, Probable and Possible Reserves and Contingent Resources of the Company, as applicable, located in the Dover, Dover West Sands, Dover West Carbonates and Grosmont areas of Alberta and the Proved, Probable and Possible Reserves attributable to the light oil assets of the Company; and (ii) the reports of DeGolyer and MacNaughton Canada Limited ("D&M") dated effective as of April 30, 2012 assessing and evaluating the Probable Reserves, Possible Reserves and Contingent Resources of Athabasca located in the Birch and Hangingstone areas of Alberta (the "Engineering Reports").
(4)      "Gross Reserves" are the Company's working interest (operating or non-operating) share before deducting royalties and without including any royalty interests of the Company.
  "Proved Reserves" are those reserves that can be estimated with a high degree of certainty to be recoverable. It is likely that the actual remaining quantities recovered will exceed the estimated proved reserves.
  "Probable Reserves" are those additional reserves that are less certain to be recovered than Proved Reserves. It is equally likely that the actual remaining quantities recovered will be greater or less than the sum of the estimated Proved Reserves plus Probable Reserves.
  "Possible Reserves" are those additional reserves that are less certain to be recovered than Probable Reserves. There is a 10% probability that the quantities actually recovered will equal or exceed the sum of Proved Reserves plus Probable Reserves plus Possible Reserves.
(5)      "Contingent Resources" are defined in the Canadian Oil and Gas Evaluation Handbook prepared jointly by The Society of Petroleum Evaluation Engineers (Calgary Chapter) and the Canadian Institute of Mining, Metallurgy & Petroleum (Petroleum Society) (the "COGE Handbook"), as 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 economic matters, further facility design and preparation of firm development plans, regulatory matters, including regulatory applications, associated reservoir studies, delineation drilling, Company approvals and other factors such as legal, environmental and political 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. The volumes of contingent bitumen resources in the above table were calculated at the outlet of the proposed extraction plant.
  "Best Estimate" is a classification of estimated resources described in the COGE Handbook as being considered to be the best estimate of the quantity that will actually be recovered. It is equally likely that the actual remaining quantities recovered will be greater or less than the Best Estimate. If probabilistic methods are used, there should be a 50% probability (P50) that the quantities actually recovered will equal or exceed the Best Estimate.
  There is no certainty that it will be commercially viable for the Company to produce any portion of the Contingent Resources on any of its properties.
(6)      The estimates of reserves for individual properties may not reflect the same confidence level as estimates of reserves for all properties, due to the effects of aggregation.
(7)      GLJ does not consider the Best Estimate Contingent Resources attributable to Grosmont to be currently economically recoverable.
(8)     Excludes certain non-oil sands acreage held by the Company in formations under and adjacent to the same surface area as Athabasca's oil sands leases.
(9)      The Company's investment in Dover is accounted for by the equity method and the resource estimates set out above reflect only the Company's 40% working interest in Dover which is held directly by the Company's subsidiary, AOC (Dover) Energy Inc.
(10)      For additional information regarding the Company's interest in, and the location of, the Company's Contingent Resources see "Description of Athabasca's Business - Oil Sands Division" and "Description of Athabasca's Business - Light Oil Division" in the Company's most recent Annual Information Form dated March 27, 2012 (the "AIF") that is available on SEDAR at  For additional information regarding the risks and level of uncertainty associated with the recovery of the Company's Contingent Resources see "Independent Reserve and Resource Evaluations - Contingent Resource Estimates" and "Risk Factors" in the AIF. For additional information regarding the specific contingencies which prevent the classification of the Company's Contingent Resources to reserves see "Independent Reserve and Resource Evaluations - Contingent Resource Estimates" in the AIF.
(11)      BOEs may be misleading, particularly if used in isolation.  A BOE conversion ratio of 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. As the value ratio between natural gas and crude oil based on the current prices of natural gas and crude oil is significantly different from the energy equivalency of 6:1, utilizing a conversion on a 6:1 basis may be misleading as an indication of value.
(12)      The Engineering Reports indicate that there are 2,171 MMbbls of Best Estimate Contingent Resources attributable to the Dover West Oilsands, as at April 30, 2012.  However, based upon a pro forma reserves and resources assessment of the Dover West Oilsands that was prepared by GLJ to reflect the acquisition of the remaining 75% working interest in certain thermal oil assets in the Dover West Oilsands area which was completed on May 30, 2012, the Best Estimate Contingent Resources in the Dover West Oilsands are 2,930 MMbbls.




SOURCE: Athabasca Oil Corporation

For further information:


Heather Douglas
Vice President, Communications & External Affairs 
(403) 532-7408

Financial Community

Andre De Leebeeck
Director, Partner & Investor Relations
(403) 817-8048

Tracy Robinson
Manager, Investor Relations
(403) 532-7446

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