CALGARY, March 12, 2014 /CNW/ – Athabasca Oil Corporation (“Athabasca” or the “Company”) (TSX: ATH) is pleased to report its fourth quarter and 2014 year-end financial and operating results in conjunction with its year-end reserves and resource information.
2014 highlights and recent accomplishments:
The Company has filed on SEDAR its audited financial statements and related Management’s Discussion and Analysis (“MD&A”) for the year ended December 31, 2014. Selected financial and operational information is outlined below and should be read in conjunction with Athabasca’s audited financial statements and related MD&A and Annual Information Form (“AIF”) which will be available for review at www.sedar.com and on our website at www.atha.com. The AIF includes the Company’s statement of reserves data and other detailed information concerning the evaluations that were conducted by the Company’s independent qualified reserves evaluators, GLJ Petroleum Consultants Ltd. and DeGolyer and MacNaughton Canada Limited, effective as at December 31, 2014.
|
1 Funding in place is defined as cash and cash equivalents, short-term investments, promissory notes (secured by irrevocable standby letters of credit from HSBC Canada) and undrawn credit facilities. |
|
($ Thousands, except per share and |
Q4 |
Q4 |
December 31, |
December 31, |
||||||||
|
SALES VOLUMES |
||||||||||||
|
Oil (bbl/d) |
2,458 |
2,206 |
2,361 |
2,444 |
||||||||
|
Natural gas (Mcf/d) |
17,428 |
22,019 |
18,168 |
19,450 |
||||||||
|
Natural gas liquids (bbl/d) |
672 |
821 |
734 |
712 |
||||||||
|
Total (boe/d) |
6,035 |
6,697 |
6,120 |
6,397 |
||||||||
|
REALIZED PRICES |
||||||||||||
|
Oil ($/bbl) |
$ |
72.17 |
$ |
78.51 |
$ |
89.20 |
$ |
87.36 |
||||
|
Natural gas ($/Mcf) |
$ |
3.81 |
$ |
3.84 |
$ |
4.89 |
$ |
3.56 |
||||
|
Natural gas liquids ($/bbl) |
$ |
38.32 |
$ |
65.00 |
$ |
67.90 |
$ |
65.82 |
||||
|
Realized price ($/boe) |
$ |
44.66 |
$ |
46.47 |
$ |
57.06 |
$ |
51.55 |
||||
|
Royalties ($/boe) |
$ |
(6.40) |
$ |
(6.92) |
$ |
(6.93) |
$ |
(4.97) |
||||
|
Operating expenses and transportation ($/boe) |
$ |
(15.88) |
$ |
(12.40) |
$ |
(14.89) |
$ |
(14.36) |
||||
|
Light Oil Netback ($/boe) (1) |
$ |
22.38 |
$ |
27.15 |
$ |
35.24 |
$ |
32.22 |
||||
|
LIGHT OIL NETBACK |
||||||||||||
|
Petroleum and natural gas sales |
$ |
24,804 |
$ |
28,621 |
$ |
127,487 |
$ |
120,298 |
||||
|
Midstream revenues |
$ |
509 |
$ |
1,491 |
$ |
2,667 |
$ |
2,198 |
||||
|
Royalties |
$ |
(3,556) |
$ |
(4,263) |
$ |
(15,497) |
$ |
(11,589) |
||||
|
Operating expenses and transportation |
$ |
(9,326) |
$ |
(9,132) |
$ |
(35,923) |
$ |
(35,649) |
||||
|
$ |
12,431 |
$ |
16,717 |
$ |
78,734 |
$ |
75,258 |
|||||
|
CASH FLOWS(1) |
||||||||||||
|
Funds Flow from Operations |
$ |
(2,520) |
$ |
7,728 |
$ |
13,314 |
$ |
(3,739) |
||||
|
Funds Flow from Operations per share (basic and diluted) |
$ |
(0.01) |
$ |
0.02 |
$ |
0.03 |
$ |
(0.01) |
||||
|
NET LOSS AND COMPREHENSIVE LOSS |
||||||||||||
|
Net loss and comprehensive loss |
$ |
(129,507) |
$ |
(40,162) |
$ |
(227,558) |
$ |
(126,138) |
||||
|
Net loss and comprehensive loss per share (basic & diluted) |
$ |
(0.32) |
$ |
(0.10) |
$ |
(0.57) |
$ |
(0.32) |
||||
|
SHARES OUTSTANDING |
||||||||||||
|
Weighted average shares outstanding – basic |
402,031,471 |
400,624,090 |
401,512,412 |
400,111,681 |
||||||||
|
Weighted average shares outstanding – diluted |
402,031,471 |
400,624,090 |
401,512,412 |
400,111,681 |
||||||||
|
CAPITAL EXPENDITURES (incl. capitalized G&A & interest) |
||||||||||||
|
Light Oil Division |
$ |
87,870 |
$ |
40,103 |
$ |
199,938 |
$ |
282,050 |
||||
|
Thermal Oil Division |
$ |
78,876 |
$ |
161,812 |
$ |
416,967 |
$ |
447,819 |
||||
|
Investments and assets held for sale |
$ |
– |
$ |
3,200 |
$ |
8,120 |
$ |
17,614 |
||||
|
Corporate |
$ |
4,427 |
$ |
3,240 |
$ |
9,953 |
$ |
14,078 |
||||
|
$ |
171,173 |
$ |
208,355 |
$ |
634,978 |
$ |
761,561 |
|||||
|
FINANCING AND DIVESTITURES |
||||||||||||
|
Net proceeds from asset sales |
$ |
3,302 |
$ |
147,221 |
$ |
1,245,171 |
$ |
173,894 |
||||
|
Net proceeds from long term debt (net of repayments) |
$ |
(651) |
$ |
– |
$ |
235,394 |
$ |
– |
||||
|
LIQUIDITY(1) |
||||||||||||
|
Available Funding |
$ |
1,345,990 |
$ |
672,790 |
$ |
1,345,990 |
$ |
672,790 |
||||
|
Net Debt(1) |
$ |
(122,134) |
$ |
(884,970) |
$ |
(122,134) |
$ |
(884,970) |
||||
|
BALANCE SHEET |
||||||||||||
|
Total assets |
$ |
4,297,803 |
$ |
4,342,325 |
$ |
4,297,803 |
$ |
4,342,325 |
||||
|
Long-term debt, net of debt issuance costs |
$ |
786,649 |
$ |
533,210 |
$ |
786,649 |
$ |
533,210 |
||||
|
Shareholders’ equity |
$ |
3,164,186 |
$ |
3,373,957 |
$ |
3,164,186 |
$ |
3,373,957 |
||||
|
(1) |
Refer to the MD&A “Advisories and Other Guidance” for important information regarding non-GAAP financial measures. |
Light Oil
Athabasca’s production averaged 6,120 boe/d (51% liquids) in 2014 compared to 6,397 boe/d (49% liquids) in 2013. Fourth quarter 2014 production averaged 6,035 boe/d (52% liquids) and second half 2014 production averaged 6,208 boe/d, within guidance of 6,000 – 6,500 boe/d.
Light Oil netbacks were $35.24/boe in 2014 and compared to $32.22/boe in 2013. Netbacks improved year over year due to higher underlying commodity prices early in the year and higher liquids volumes as the Duvernay became a more material component of corporate production.
The Company deployed $200 million of capital (including $9 million of capitalized G&A) in Light Oil during 2014. The program was predominately focused on Duvernay development in the Kaybob region and a Montney appraisal program at Placid. The Company made progress towards its main objectives of retaining its Duvernay acreage into the intermediate term and transitioning land to resource value.
Duvernay Overview
During 2014, the Company successfully drilled five Duvernay Wells (four horizontal, one vertical) and completed six horizontal Duvernay wells in the Greater Kaybob area. Four of the completed wells were brought on-stream during the year with the remaining two wells expected to come on-stream in 2015.
In the third quarter, Athabasca commenced its winter 2014/15 program with three rigs drilling as of December 31, 2014. The winter 2014/15 program consists of ten wells (seven horizontal, three verticals) and drilling operations are expected to be completed by the end of Q1 2015. Two horizontal wells have been completed from this program. The remaining completions have been deferred until the second half of the year and timing will depend on service costs and the commodity price outlook.
Approximately 95% of Athabasca’s core 200,000 acre land position at Kaybob is now held into intermediate term, allowing considerable flexibility in the pace of development going forward. Delineation drilling over the past three drilling seasons sets the framework for operations to transition to development in the condensate rich gas window with ongoing appraisal work in the volatile oil window.
Duvernay Condensate Rich Gas Window
At Kaybob West, 8-34-62-20W5 was drilled in the liquids rich gas window offsetting strong results from industry and Athabasca. The 8-34 well was completed in Q4 2014 and brought on-stream in February, 2015. It has produced at an average restricted rate of over 635 boe/d (53% liquids, 53⁰API) during its first 26 days of production. This well offsets Athabasca’s 2-34-62-20W5 which has been on production since December 2012 with cumulative production in excess of 400 mboe (48% liquids, 52⁰API) and is currently flowing at approximately 275 boe/d.
Athabasca continues to gain confidence in the Kaybob West area with extended production data and offsetting industry activity. A number of large operators have commenced multi-well pad development adjacent to Athabasca’s acreage. In January, Athabasca commenced drilling of a two well pad in Section 36-63-20W5. Both wells were rig released in approximately 35 days at a cost of approximately $5.9 million each. Athabasca believes that there is significant potential to reduce costs further through pad drilling and expects development costs to reach $10 – 12 million per well (drilling and completion capital). Completions operations on 8-36-63-20W5 and 1-36-63-20W5 have been deferred to the second half of 2015.
At Saxon, three wells were drilled in the liquids rich gas window. 15-15-62-23W5 (50% working interest) was successfully completed in January and is undergoing a planned soak period with an expected on-stream date after break-up this year. 12-28-62-23W5 was rig released in late January with completions scheduled for the second half of 2015. Athabasca also drilled a vertical land retention well at 1-28-61-23W5.
Duvernay Volatile Oil Window
The Company continues to be encouraged by its preliminary results in the volatile oil window. The 2014/15 winter program includes four new wells (two horizontals, two verticals) and one completion of a previously drilled well at Simonette. The primary objectives of the program are land retention, understanding reservoir characteristics and establishing initial productivity rates.
At Simonette, 16-36-63-25W5 was completed in October, 2014. Following a planned soak period the well was placed on production in early March producing into a third party facility with liquids currently being trucked. The Company plans to establish an initial production rate and the well will then be shut-in over spring break-up.
At Kaybob East, 2-7-65-18W5 was drilled in an on-strike orientation with a 1,600 meter horizontal lateral section. Completions are scheduled for the summer and infrastructure is in place for production following a planned soak period. The Company remains encouraged by production from offsetting industry wells and the potential to de-risk a significant amount of acreage in the volatile oil window with this well.
At Kaybob West North, the Company drilled and cored 14-33-65-21W5 as a vertical land retention well.
At Two Creeks, 1-16-64-16W5 and 13-5-64-15W5 were drilled as horizontal and vertical land retention wells, respectively. The Company cored the Duvernay at both locations.
Montney
At Placid, Athabasca drilled, completed and tested two wells offsetting industry success. The objective of the program was to demonstrate both the quality and extent of the resource to be considered for future funding. The wells have horizontal lateral lengths of approximately 2,300 meters and were completed with multi-stage, energized slickwater hybrid completions similar to offset operators. The first well at 8-20-60-23W5 was flow tested for 10 days and had a final restricted 24 hour flow rate of 1,540 boe/d with a liquid yield of 358 bbl/mmcf. The well was brought on production to a third party facility in early March. The second well at 9-26-60-24W5 was tested in early March. Disclosure on extended production rates will be provided when available.
Thermal Oil
In 2014, the Company spent $417 million of capital (including $33 million of capitalized G&A and $45 million of capitalized interest) in the Thermal Oil division. The majority of the capital was spent at Hangingstone including $374 million on Hangingstone Project 1 and $27 million on Hangingstone Project 2. A total of $16 million was spent on other Thermal Oil projects outside of Hangingstone.
Hangingstone
At Hangingstone, significant milestones were achieved in 2014 including the completion of the SAGD drilling program and substantial completion of the Central Processing Facility (the “CPF”) and regional infrastructure. The focus through the first quarter of 2015 is commissioning the CPF and preparing for first steam which is still expected at the end of March. First production is expected four to six months after first steam. Project costs are expected to fall within 5% of the sanctioned budget.
Hangingstone Project 1 is expected to provide the Company with a predicable stable production profile and a long reserve life. The current cash flow breakeven price is approximately US$50/bbl WTI. The majority of the project capital has now been incurred and production ramp up is planned to occur in the second half of 2015 with plateau production of 12,000 bbl/d in 2016. Achieving targeted production ramp-up will be an important strategic milestone for Athabasca as it will demonstrate the quality of the Company’s Hangingstone asset base and its ability to build and operate large-scale projects. Athabasca has over 8 billion barrels (best estimate) of contingent resource in its Thermal Oil division for future development.
Reserves and Contingent Resources
Athabasca’s independent qualified reserves evaluators, GLJ Petroleum Consultants and DeGolyer and MacNaughton Canada Limited, completed their respective independent reserve and resource evaluations effective December 31, 2014. The Light Oil Division realized 52% growth in gross proved plus probable reserves, increasing to 50 mmboe (49% liquids), which was primarily driven by Duvernay appraisal drilling. Thermal Oil proved plus probable reserves were assessed at 313 mmboe, consistent with the prior year excluding the Dover disposition. Corporate gross proved plus probable reserves stand at 362 mmboe (93% liquids) and excluding the Dover disposition, increased 5% year over year. Additional details are provided in the appendix to this release.
2015 Budget and Guidance
Athabasca’s Board of Directors has approved a full year 2015 capital budget of $305 million ($266 million initial budget and $39 million of carryover capital not spent in 2014). A core objective of Athabasca’s 2015 capital program is to maintain balance sheet strength and the Company retains flexibility to adjust the program as needed through the balance of year.
|
2015 Capital Budget(1) |
$ Millions |
|||
|
LIGHT OIL (full year) |
||||
|
Duvernay (drill & completion) |
$ |
166 |
||
|
Montney (drill & completion) |
$ |
17 |
||
|
Other (facilities, equipment and roads) |
$ |
20 |
||
|
Total Light Oil (includes $35.6 million of 2014 carryover capital) |
$ |
203 |
||
|
THERMAL OIL |
||||
|
Hangingstone Project 1 (capital & capitalized start-up costs) |
$ |
68 |
||
|
Hangingstone Expansion (pre-engineering) |
$ |
12 |
||
|
Other |
$ |
16 |
||
|
Total Thermal Oil (includes $3.6 million of 2014 carryover capital) |
$ |
96 |
||
|
CORPORATE |
$ |
6 |
||
|
TOTAL CAPITAL SPENDING (excluding capitalized G&A and interest)(2) |
$ |
305 |
||
|
(1) |
The budget is based on commodity prices assumptions of US$50/bbl WTI and C$2.80/mcf AECO and foreign exchange of 0.78 US/CAD |
|
(2) |
Capitalized G&A and interest is estimated at approximately $60 million |
Light Oil budget
Athabasca’s 2014/15 winter program includes ten Duvernay wells and two Montney appraisal wells at Placid. The Board has approved a total 2015 Light Oil budget of $203 million including $36 million of carryover capital from the 2014 fiscal year that was previously approved as part of the 2014/15 winter program. The Company has deferred approximately $60 million of capital related to the completion and tie-in of four wells and one drilling location originally planned to be completed before spring break-up until the second half of 2015. Final spending decisions will be based on service cost structures and the commodity price outlook later in the year.
The Company remains on track to meet or exceed Q1 2015 production guidance of approximately 5,000 boe/d. The 2015 year-end Light Oil exit production target of 7,000 – 8,000 boe/d is unchanged assuming the deferred completion activity is completed during 2015.
Thermal Oil budget
The Board has approved a 2015 Thermal Oil budget of $96 million with $68 million focused on the commissioning and ramp-up of Hangingstone Project 1. The 2015 year-end Hangingstone exit production target remains between 3,000 – 6,000 bbl/d.
Consolidated budget
The 2015 corporate year-end exit target is between 10,000 – 14,000 boe/d. Based on its current capital spending, production and cash flow outlook, Athabasca anticipates 2015 year-end funding in place of approximately $800 million.
Strategic Initiatives Update
In the fall, Athabasca outlined some near-term priorities which included refocusing activities on its core Hangingstone and Kaybob assets, a thorough cost structure review and the initiation of a Board of Directors renewal process. An initiative to streamline costs is ongoing with the goal to align the organization to the current operating environment, its capital plans and growth profile. In January, Mr. Carlos Fierro and Mr. Paul Haggis were appointed as independent directors to the Board. Both individuals bring extensive financial and energy sector experience that will be of great value to shareholders.
Conference Call and Webcast (March 12, 2014, 9:30 am Eastern Time)
A conference call and webcast to discuss the results will be held for the investment community today beginning at 7:30 a.m. MT (9:30 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 12:30 p.m. ET on March 12, 2015until midnight on March 26, 2015 by dialing 855-859-2056 (toll-free in North America) or 416-849-0833 and entering conference password 93724263. An audio webcast of the conference call will also be available on the Company’s website or at http://www.newswire.ca/en/webcast/detail/1491505/1661069.
About Athabasca Oil Corporation
Athabasca Oil Corporation is a Canadian energy company with a focused strategy on the development of thermal and light oil assets. Situated in Alberta’s Western Canadian Sedimentary Basin, the Company has amassed a significant land base of extensive, high quality resources. Athabasca’s common shares trade on the TSX under the symbol “ATH”. For more information, visit www.atha.com.
Appendix: 2014 Year-end Reserves and Resources
Athabasca’s independent qualified reserves evaluators, GLJ Petroleum Consultants Ltd. and DeGolyer and MacNaughton Canada Limited completed the following independent reserve evaluations effective December 31, 2014. For additional detail, refer to the Annual Information Form filed on www.sedar.com.
|
Light Oil (mmboe) |
Thermal (mmbbl) |
Total (mmboe) |
||||
|
Proved |
Proved + |
Proved |
Proved + |
Proved |
Proved + |
|
|
December 31, 2013 |
14.5 |
32.5 |
51.1 |
449.8 |
65.7 |
482.3 |
|
Discoveries |
2.7 |
6.8 |
– |
– |
2.7 |
6.8 |
|
Extensions and Improved Recovery |
1.9 |
17.9 |
– |
– |
1.9 |
17.9 |
|
Technical Revisions |
(1.6) |
(2.5) |
– |
– |
(1.6) |
(2.5) |
|
Acquisitions |
– |
– |
– |
– |
– |
– |
|
Dispositions(1) |
– |
– |
– |
(137.6) |
– |
(137.6) |
|
Economic Factors |
(3.7) |
(2.9) |
0.3 |
0.5 |
(3.4) |
(2.5) |
|
Production |
(2.2) |
(2.2) |
– |
– |
(2.2) |
(2.2) |
|
December 31, 2014 |
11.6 |
49.6 |
51.4 |
312.7 |
63.0 |
362.3 |
|
NPV10 (Before Tax – $ millions) |
$100 |
$366 |
$589 |
$1,511 |
$689 |
$1,877 |
|
(1) |
The Dover asset was divested on August 29, 2014 |
The Company has 8.5 billion barrels of contingent resource (best estimate) at Dover West, Hangingstone and Birch.
|
Best Estimate Contingent Resources (MMbbl) |
||
|
2014 |
2013 |
|
|
Dover (1) |
– |
1,222 |
|
Dover West Sands |
2,894 |
2,957 |
|
Dover West Carbonates |
2,756 |
3,001 |
|
Birch |
2,111 |
2,111 |
|
Grosmont(2) |
– |
418 |
|
Hangingstone |
782 |
782 |
|
Total |
8,543 |
10,492 |
|
NPV10 (Before Tax – $ millions) |
$ 16,185 |
$20,728 |
|
(1) |
The Dover asset was divested on August 29, 2014 |
|
(2) |
The Grosmont asset was uneconomic at year-end 2014 |
[expand title=”Advisories & Contact”]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: the timing of first steam for, the ramp-up of production from and the timing of achieving plateau production from, Hangingstone Project 1; the Company’s projection that the costs of the Hangingstone Project 1 will come in within 5% of its sanctioned budget; the Company’s expectations that it will meet or exceed its first quarter 2015 production guidance; the reductions in Duvernay well drilling and completion costs expected to be realized by the Company; the timing of drilling and completion operations in the Company’s Light Oil division; the benefits expected to be realized from placing the Company’s Light Oil division Duvernay wells a soak period; the Company’s expected production from the Light Oil division in the first quarter of 2015 and from the Light Oil and Thermal Oil divisions at December 31, 2015; the expected timing of the Company’s Light Oil division wells coming on-stream; the Company’s expected flexibility in its pace of development; the Company’s drilling plans, in particular, with respect to the Duvernay and Montney formations; the Company’s plans for, and results of, exploration and development activities; the Company’s estimated future commitments; the Company’s expected funding-in-place at the end of 2015; the Company’s business and financing plans; the Company’s business and financing strategies; expectations regarding the 2015 capital budget; and the future allocation of capital.
The information and statements in this News Release relating to Athabasca’s estimated contingent resources (best estimate) is also deemed to be forward-looking information, as it involves the implied assessment, based on certain estimates and assumptions, that the resources described exist in the quantities predicted or estimated, and that the resources described can be profitably produced in the future. The resources estimates contained in this News Release were evaluated by GLJ Petroleum Consultants (GLJ) and DeGolyer and MacHaughton Canada Limited (D&M) in their respective reserves and resources reports dated effective December 31, 2014. For important additional information regarding Athabasca’s reserves and resources estimates and the evaluations that were conducted by GLJ and D&M please see “Independent Reserve and Resource Evaluations” in the Company’s most recent Annual Information Form (“AIF”) dated March12, 2015 that is available on SEDAR at www.sedar.com.
With respect to forward-looking information contained in this News Release, assumptions have been made regarding, among other things: geological and engineering estimates in respect of Athabasca’s reserves and resources; commodity prices for petroleum and natural gas; Athabasca’s cash-flow break-even commodity price; ; the Company’s ability to demonstrate the quality of its asset base and to build large-scale projects; 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; the geography of the areas in which the Company is conducting exploration and development activities; the Company’s ability to obtain 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; will have on the Company, including on the Company’s financial condition and results of operations.
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 AIF, including, but not limited to: fluctuations in market prices for crude oil, natural gas and bitumen blend; general economic, market and business conditions in Canada, the United States and globally the substantial capital requirements of Athabasca’s projects and the ability to obtain financing for Athabasca’s capital requirements; failure by counterparties to make payments or perform their operational or other obligations to Athabasca in compliance with the terms of contractual arrangements between Athabasca and such counterparties, including in compliance with the time schedules set out in such contractual arrangements, and the possible consequences thereof; aboriginal claims; failure to obtain regulatory approvals or maintain compliance with regulatory requirements; failure to meet development schedules and potential cost overruns; variations in foreign exchange and interest rates; factors affecting potential profitability; risks related to future acquisition and joint venture activities; reliance on, competition for, loss of, and failure to attract key personnel; global financial uncertainty; uncertainties inherent in estimating quantities of reserves and resources; changes to Athabasca’s status given the current stage of development; uncertainties inherent in SAGD and other bitumen recovery processes; risks related to hydraulic fracturing, including those related to induced seismicity; expiration of leases and permits; risks inherent in Athabasca’s operations, including those related to exploration, development and production of petroleum, natural gas and oil sands reserves and resources; risks related to gathering and processing facilities and pipeline systems; availability of drilling and related equipment and limitations on access to Athabasca’s assets; increases in costs could make Athabasca’s projects uneconomic; the effect of diluent and natural gas supply constraints and increases in the costs thereof; environmental risks and hazards; failure to accurately estimate abandonment and reclamation costs; the potential for management estimates and assumptions to be inaccurate; long term reliance on third parties; reliance on third party infrastructure; seasonality; hedging risks; risks associated with maintaining systems of internal controls; insurance risks; claims made in respect of Athabasca’s operations, properties or assets; competition for, among other things, capital, export pipeline capacity and skilled personnel; the failure of Athabasca or the holder of certain licenses, leases or permits to meet specific requirements of such licenses, leases or permits; risks related to the Athabasca’s amended credit facilities; senior secured notes and term loans; and risks related to the Athabasca’s common shares.
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. 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.
Test Results and Initial Production Rates:
The well test results provided in this News Release should be considered to be preliminary. Test results and initial production rates disclosed herein may not necessarily be indicative of long term performance or of ultimate recovery.
SOURCE Athabasca Oil Corporation