CALGARY, ALBERTA--(Marketwired - May 12, 2015) - Athabasca Oil Corporation ("Athabasca" or the "Company") (TSX:ATH) is pleased to report its first quarter 2015 financial and operating results.
Highlights from the quarter and recent accomplishments:
- Achieved a significant milestone commencing well pair steaming at Hangingstone in late March. Construction of Hangingstone Project 1 was completed on schedule with a final cost estimate between $740 - $750 million, which is within approximately 5% of the sanctioned budget;
- First quarter Light Oil production averaged 5,877 boe/d exceeding guidance of 5,000 boe/d;
- Light Oil capital expenditures totaled $77 million in the first quarter. Athabasca's 2014/15 winter drilling program concluded in March and the Company has now held 95% of its core 200,000 acre Duvernay land position into the intermediate term;
- In early March the Company received $303 million from Brion Energy Corporation ("Brion") as payment on the first of three promissory notes issued to the Company by Brion. As of March 31, 2015, Athabasca had over $1.1 billion of funding in place(1) including approximately $660 million of cash, cash equivalents and short-term investments; and
- Athabasca completed a cost structure review and has reduced costs in most areas including a reduction in the size of its head office workforce by approximately 50% since the beginning of 2014.
(1)Funding in place is defined as cash and cash equivalents, short-term investments, promissory notes (secured by irrevocable standby letters of credit from HSBC Canada) and undrawn credit facilities.
Select Financial Information
| As at and for the three months ended ($ Thousands, except per share and boe amounts) |
March 31, 2015 |
March 31, 2014 |
|||||
| SALES VOLUMES | |||||||
| Oil (bbl/d) | 2,308 | 2,402 | |||||
| Natural gas (Mcf/d) | 18,126 | 20,021 | |||||
| Natural gas liquids (bbl/d) | 548 | 560 | |||||
| Total (boe/d) | 5,877 | 6,299 | |||||
| REALIZED PRICES | |||||||
| Oil ($/bbl) | $ | 46.75 | $ | 89.70 | |||
| Natural gas ($/Mcf) | 2.79 | 6.23 | |||||
| Natural gas liquids ($/bbl) | 25.17 | 79.93 | |||||
| Realized price ($/boe) | 29.35 | 61.12 | |||||
| Royalties ($/boe) | (3.52 | ) | (8.87 | ) | |||
| Operating expenses and transportation(1) ($/boe) | (13.37 | ) | (15.30 | ) | |||
| Light Oil Operating Netback(2) ($/boe) | $ | 12.46 | $ | 36.95 | |||
| LIGHT OIL OPERATING INCOME(2) | |||||||
| Petroleum and natural gas sales | $ | 15,511 | $ | 34,646 | |||
| Midstream revenue | 331 | 803 | |||||
| Royalties | (1,861 | ) | (5,028 | ) | |||
| Operating and transportation expenses | (7,403 | ) | (9,478 | ) | |||
| $ | 6,578 | $ | 20,943 | ||||
| CASH FLOWS | |||||||
| Funds Flow from Operations(2) | $ | 3,162 | $ | 9,468 | |||
| Funds Flow from Operations per share (basic and diluted) | $ | 0.01 | $ | 0.02 | |||
| NET LOSS AND COMPREHENSIVE LOSS | |||||||
| Net loss and comprehensive loss | $ | (25,112 | ) | $ | (21,346 | ) | |
| Net loss and comprehensive loss per share (basic and diluted) | $ | (0.06 | ) | $ | (0.05 | ) | |
| SHARES OUTSTANDING | |||||||
| Weighted average shares outstanding (basic and diluted) | 402,393,806 | 400,950,225 | |||||
| CAPITAL EXPENDITURES(3) | |||||||
| Light Oil Division | $ | 79,241 | $ | 77,449 | |||
| Thermal Oil Division | 68,504 | 157,958 | |||||
| Assets held for sale | - | 4,000 | |||||
| Corporate | 1,708 | 1,455 | |||||
| $ | 149,453 | $ | 240,862 | ||||
| FINANCING AND DIVESTITURES | |||||||
| Net proceeds from sale of investments | 300,000 | - | |||||
| Net proceeds from sale of assets | - | 56,153 | |||||
| LIQUIDITY | |||||||
| Available Funding(2) | 1,135,470 | 1,345,990 | |||||
| Net Debt(2) | 68,005 | (123,625 | ) | ||||
| (1) | Operating expenses and transportation expenses include midstream revenues of $0.62/boe (2014 - $1.42/boe). |
| (2) | Refer to "Advisories and Other Guidance" in the MD&A for additional information on Non-GAAP Financial Measures. |
| (3) | Includes $2.5 million of capitalized G&A for Light Oil and $20.7 million of capitalized G&A and interest for Thermal Oil. |
Light Oil
Athabasca's production averaged 5,877 boe/d (49% liquids) in the first quarter of 2015 exceeding guidance of 5,000 boe/d and compared to 6,299 boe/d (47% liquids) in the first quarter of 2014. Light Oil operating netbacks were $12.46/boe compared to $36.95/boe in the first quarter of 2014, primarily due to lower underlying commodity prices.
The Company deployed approximately $77 million of capital in Light Oil during the first quarter of 2015. The program was predominately focused on Duvernay land retention drilling in the Kaybob region and a Montney appraisal program at Placid.
Duvernay Overview
During the 2014/15 winter program, the Company drilled ten Duvernay wells (seven horizontals, three verticals) in the Greater Kaybob area. Two of these Duvernay horizontal wells were completed and tested. The Company elected to defer one of its program wells and completions operations on three Duvernay horizontal wells until the second half of the year in anticipation of lower service costs.
Over the past three drilling seasons Athabasca has drilled 20 wells (15 horizontals, five verticals) focused on retaining its core acreage, defining the thermal maturity windows and establishing confidence in reservoir performance. 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.
Duvernay Condensate Rich Gas Window
At Kaybob West, 8-34-62-20W5 was drilled in the condensate rich gas window offsetting strong results from Athabasca and industry. The 8-34 well was completed in Q4 2014 and brought on-stream in February, 2015. It had a restricted IP60 of 570 boe/d (61% liquids, 53° API) and is currently producing in excess of 525 boe/d. The well is being produced at a restricted rate with over 16 MPA casing pressure to enhance long term productivity. 8-34 offsets Athabasca's 2-34-62-20W5 well, which has been on production since December 2012 with cumulative production in excess of 400 mboe (48% liquids, 52° API) and is currently flowing at approximately 300 boe/d with free liquids of approximately 100 bbl/mmcf.
At Saxon, 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 in July.
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. The Company drilled a two well pad in Section 36-63-20W5 and demonstrated cost efficiencies. Both wells were rig released in approximately 35 days at a cost of approximately $5.9 million each. Completions operations on 8-36-63-20W5 and 1-36-63-20W5 have been deferred to the second half of 2015 in anticipation of lower service costs.
Duvernay Volatile Oil Window
Athabasca continues to be encouraged by its preliminary results in the volatile oil window. The 2014/15 winter program included four new wells (two horizontals, two verticals). At Simonette, 16-36-63-25W5 was completed in October, 2014. Following a planned soak period the well was placed on production in March into a third party facility, but was subsequently shut-in due to road conditions. The Company anticipates an on-stream date in July. Athabasca now has seven horizontal wells in the volatile oil window. Production from these wells and offsetting industry wells is helping de-risk the Company's core acreage.
Montney
At Placid the winter program included two Montney wells offsetting industry success. Both wells were drilled, completed and tested. The objective of the program was to demonstrate both the quality and extent of the resource for future funding consideration. The wells have horizontal lateral lengths of approximately 2,300 meters and were completed with multi-stage, energized hybrid completions similar to offset operators. The first well at 8-20-60-23W5 was placed on production through a third party facility in March and had a restricted IP30 of approximately 900 boe/d (approximately 270 bbl/mmcf free liquids) and a restricted IP60 of approximately 790 boe/d (approximately 225 bbl/mmcf free liquids). The Company remains very encouraged by the initial production data and the well is maintaining strong pressures and liquids rates. The second well at 9-26-60-24W5 was tested in early March and is expected to be tied-in later this year.
Thermal
Hangingstone
On March 23, Athabasca formally transitioned Hangingstone Project 1 from construction to operations beginning with first steam to three well pairs before the end of March. Fifteen well pairs are now on circulation with an additional seven well pairs expected to be placed on circulation by the end of the third quarter of 2015.
Construction of Hangingstone Project 1 was completed on schedule with a final cost estimate of $740 to $750 million, which is within approximately 5% of the project's sanctioned budget. Third party construction of transportation facilities is also substantially complete with the commissioning of the diluent pipeline underway and the start-up of the dilbit pipeline to the Cheecham terminal scheduled for the fourth quarter of 2015.
First production is expected in the third quarter and 22 well pairs are expected to be on SAGD production by year-end resulting in an exit target of 3,000 - 6,000 bbl/d. The project is anticipated to reach design capacity of 12,000 bbl/d by late 2016. Expansion projects towards Hangingstone's 80,000 bbl/d potential are not expected to be sanctioned until the Company demonstrates a successful ramp up of Hangingstone Project 1.
Liquidity and Corporate Cost Structure
Athabasca remains committed to maintaining a strong balance sheet. As of March 31, 2015, Athabasca had over $1.1 billion of funding in place including approximately $660 million of cash, cash equivalents and short-term investments. On March 2, 2015 the Company received payment of $303 million from Brion being the principal and interest payable under the first of three promissory notes issued to the Company on the closing of its disposition of its 40% interest in the Dover oil sands project on August 29, 2014. The remaining promissory notes, which are unconditional and secured by irrevocable, standby letters of credit issued by HSBC Bank Canada, mature as follows: $150 million on August 28, 2015 and $134 million on August 29, 2016.
The Company also continues to have access to a $125 million undrawn syndicated credit facility and a US$50 million delayed draw term loan. These non-reserve based facilities provide added financial flexibility to the Company, particularly during a period of lower commodity prices. The Company does not anticipate drawing on these instruments in the near term.
During the first quarter of 2015 Athabasca completed a cost structure review, which resulted in the Company reducing costs in most areas, including a reduction in the size of its head office workforce by approximately 50% since the beginning of 2014. The Company forecasts gross G&A of approximately $65 million for 2015 and has also recognized $17 million of restructuring and other charges in the first quarter in relation to this review. The preliminary 2016 G&A target is approximately $60 million gross.
The Company also expects to realize substantial operating and capital savings through streamlining of operations and lower related service costs through the balance of the year.
2015 Budget and Guidance
Athabasca's 2015 capital budget remains unchanged at $305 million (excluding capitalized interest and G&A).
| 2015 Budget ($million) |
Q1 Actuals | Q2 - Q4 | Full Year | |||||
| Light Oil | ||||||||
| Duvernay | $ | 57 | $ | 109 | $ | 166 | ||
| Montney | 14 | 3 | 17 | |||||
| Other | 6 | 14 | 20 | |||||
| Total Light Oil(1) | $ | 77 | $ | 126 | $ | 203 | ||
| Thermal | ||||||||
| Hangingstone Project 1 (capital & capitalized start-up) costs)(2) | $ | 44 | $ | 24 | $ | 68 | ||
| Hangingstone Expansion (pre-engineering) | 1 | 11 | 12 | |||||
| Other | 3 | 13 | 16 | |||||
| Total Thermal(3) | $ | 48 | $ | 48 | $ | 96 | ||
| Corporate | $ | 2 | $ | 4 | $ | 6 | ||
| Total Capital Spending | $ | 127 | $ | 178 | $ | 305 | ||
| Capitalized Interest & G&A | $ | 23 | $ | 37 | $ | 60 | ||
| (1) | Q1 2015 light oil capital expenditures exclude $2.5 million of capitalized G&A. |
| (2) | Operating expenses for Hangingstone Project 1 will be capitalized until mid Q3 2015 and will be expensed thereafter. |
| (3) | Q1 2015 thermal oil capital expenditures exclude $5.3 million of capitalized G&A and $15.4 million of capitalized interest. |
Light Oil budget
During the first quarter, Athabasca substantially completed its 2014/15 winter program which resulted in the drilling of seven horizontal Duvernay wells, three vertical Duvernay wells and two Placid horizontal Montney wells.
The Company's objectives for its second half 2015 Light Oil program include: demonstrating pad drilling cost efficiencies and ongoing appraisal work in the volatile oil window. Athabasca intends to complete and tie-in three previously drilled Duvernay wells. The Company also expects to commence a drilling program in late summer utilizing a single fit-for-purpose rig with the intention of drilling a four well Duvernay pad at Kaybob West and a two well pad at Kaybob East in the volatile oil window. It is expected that four of these additional six wells will be finished drilling by the end of 2015.
The 2015 capital budget for Light Oil remains unchanged at $203 million. The Company has reduced some previously planned non-productive capital expenditures and realized some expected cost savings, allowing the second half program to be completed within the original capital budget. The Company retains significant flexibility to control pace and adjust capital plans to meet its strategic objectives over the medium term.
Athabasca's second quarter production is expected to average approximately 5,000 boe/d. The 2015 year-end Light Oil exit production guidance remains unchanged at 7,000 - 8,000 boe/d, in anticipation of a successful second half 2015 capital program.
Thermal Oil budget
The 2015 Thermal Oil budget is unchanged at $96 million with $68 million to be spent on the commissioning and ramp-up of Hangingstone Project 1. The Company remains focused on the successful start-up at Hangingstone and views it as a strategic asset within its Thermal portfolio. 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 remains 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.
Conference Call and Webcast (May 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 May 12, 2015 until 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.
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", "target", "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 the ramp-up of production and of achieving plateau production from Hangingstone Project 1; the expectation that 22 well pairs will be on SAGD production at Hangingstone Project 1 by the end of the 2015; the Company's projection that the costs of the Hangingstone Project 1 will come in within 5% of its sanctioned budget; the timing of the completion and commissioning of diluent pipelines and the start-up of the dilbit pipeline to the Cheecham terminal; 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 on a soak period; the Company's expected production 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 benefits expected to be realized from the use of recovery technologies in the Company's Light Oil division, including multi-stage, energized hybrid completion technology; the anticipation of lower service costs in the second half of 2015; 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 timing of the Company's well completion operations; the Company's plans for, and results of, exploration and development activities; the Company's estimated future commitments; the receipt of proceeds from the Promissory Notes; 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.
With respect to forward-looking information contained in this News Release, assumptions have been made regarding, among other things: commodity prices for petroleum and natural gas; the regulatory framework governing royalties, taxes and environmental matters in the jurisdictions in which the Company conducts and will conduct its business and the effects that such regulatory framework will have on the Company, including on the Company's financial condition and results of operations; Athabasca's cash-flow break-even commodity price; geological and engineering estimates in respect of Athabasca's reserves and resources; the applicability of technologies for the recovery and production of the Company's reserves and resources; 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 Company's ability to obtain equipment in a timely and cost-efficient manner; the geography of the areas in which the Company is conducting exploration and development activities; and the Company's ability to obtain equipment in a timely and cost-efficient manner.
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 Annual Information Form ("AIF") dated March 11, 2015 that is available on SEDAR at www.sedar.com, including, but not limited to: fluctuations in market prices for crude oil, natural gas and bitumen blend; political and general economic, market and business conditions in Alberta, 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; risks and 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 and initial production rates 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.
Contact Information:
Matt Taylor
Vice President, Capital Markets and Communications
1-403-817-9104
mtaylor@atha.com
www.atha.com