CALGARY, ALBERTA–(Marketwired – Dec. 2, 2015) – Athabasca Oil Corporation (TSX:ATH) (“Athabasca” or “the Company”) is pleased to announce that its Board of Directors has approved a 2016 capital budget of $91 million. This budget is closely aligned with Athabasca’s key strategic priorities which include preserving a strong balance sheet to manage through economic cycles, demonstrating execution excellence in both core Light Oil and Hangingstone assets and positioning the Company to capitalize on future economic growth. Despite lower planned expenditures relative to 2015, Athabasca anticipates annual per share production growth in excess of 125% in 2016.
2016 Capital Budget and Production Guidance
Athabasca’s 2016 capital budget of $91 million is centered on capital management which will allow the Company to strategically advance its core assets. Based on this level of capital spending, Athabasca is targeting average corporate production of 16,000 – 18,000 boe/d in 2016. This includes Hangingstone ramping up to design capacity towards the end of the year and maintaining 2015 exit volumes within Light Oil following the completion of the 2015/16 winter program.
Light Oil Division
In the Light Oil Division, Athabasca commenced drilling operations for the winter 2015/16 program in September and has allocated $71 million in 2016 to complete planned activities. Average Light Oil production in 2016 is anticipated to be 7,000 – 8,000 boe/d, in-line with the Company’s 2015 exit rate guidance. Additional capital activities for the balance of the year will be assessed post break-up and will be contingent on projects meeting internal hurdle rates and stability in commodity markets.
During 2016, Athabasca will invest $36 million in the Duvernay to complete planned winter activities. The Company’s core objectives in the Duvernay are to establish the strong economic potential and significant running room in the play. This will be achieved through demonstrating pad drilling cost efficiencies, and ongoing appraisal and delineation of the volatile oil window.
Over the past three drilling seasons, Athabasca has drilled 22 wells (17 horizontals, five verticals) in the Duvernay focused on retaining 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 held into the intermediate term, allowing considerable flexibility in the pace of development going forward.
Duvernay Volatile Oil Window
At Kaybob East, the Company spud a two well pad at Section 5-65-18W5 in early September and is realizing significant operational efficiencies. The 00/16-6-65-18W5 well was rig released in approximately 16 days and completed with a ~1,100 lbs/ft frac design for an estimated drill and complete (“D&C”) cost of $8.8 million. The 02/16-6-65-18W5 well was rig released in less than 14 days and completed with a ~2,000 lbs/ft frac design for an estimated D&C cost of $9.4 million. Both wells are undergoing a planned soak period with expected on-stream timing in Q1 2016.
Duvernay Condensate Rich Gas Window
At Kaybob West, the Company spud a four well pad in the condensate rich window at Section 36-63-20W5 in mid-October. Drilling operations are proceeding as planned with the first well rig released in approximately 20 days at an estimated drilling cost of $3.5 million. Drilling on the remaining three wells is expected to be completed by early 2016. The Company intends to complete the four wells after break-up, with a planned on-stream date in Q3 2016. D&C costs are expected to be below $10 million per well.
At Placid, the Company spud a three well Montney pad in September at Section 19-60-23W5 to follow up on two successful wells drilled in the winter of 2014/15. Drilling operations on the pad have been completed with an average 23 day spud to rig release and estimated drill costs of $4.0 million per well. In Q1 2016 Athabasca will spend $18 million to complete and tie-in the pad. Additionally the Company will complete the construction of the Placid inter-connect to Athabasca’s extensive Kaybob infrastructure network with an anticipated completion date in late April.
Thermal Oil Division
At Hangingstone, the Company continues to progress with its production ramp-up. The Company now has 21 well pairs converted to SAGD production and current volumes exceed 6,000 bbl/d. The start-up of the dilbit pipeline to the Cheecham terminal commences next week and is expected to be completed before year-end.
In 2016, Athabasca will spend $5 million of capital on facility and well pair optimization at Hangingstone. The ramp-up to the project’s design capacity of 12,000 bbl/d in Q4 2016 remains on track with no additional development capital required and only minimal maintenance capital needed in the initial years. Average Hangingstone production in 2016 is anticipated to be 9,000 – 10,000 bbl/d, reflecting the continued strong ramp-up of the Company’s inaugural SAGD project.
Through management of the existing SAGD producers and the additional available well pairs, Athabasca forecasts that the facility will have a relatively flat production profile for the first five to seven years once it reaches nameplate production.
Balance Sheet and Liquidity
Balance sheet preservation is a key priority for Athabasca. At current commodity prices, the Company’s focus will be on capital discipline and liquidity preservation, and based on 2016 capital and production guidance, Athabasca anticipates ending 2016 with cash and cash equivalents of approximately $550 million under the current capital structure. With continued operational success throughout 2016, and a stabilization of commodity prices, Athabasca will transition towards achieving its longer term goal of aligning its capital structure with its production and cash flow expectations. The Company is currently targeting a reduction in total debt outstanding of up to $300 million by the end of 2016.
The success and timing of Athabasca’s balance sheet transition will be closely tied to planned operational and strategic milestones expected to be achieved in 2016, as well as the commodity environment and market conditions throughout the upcoming year. Given its considerable asset base, strong liquidity position and no debt maturities that occur until 2017, the Company has flexibility to evaluate the various funding alternatives available to it and select those options which best achieve its capital structure objectives and strategic plans going forward.
General & Administrative (“G&A”) Expenses
Athabasca anticipates 2016 expensed G&A of approximately $30 – $35 million. This is a substantial reduction from previous levels and demonstrates the Company’s strong commitment to capital efficiencies and ensuring the long term competiveness of its cost structure.
|2016 Capital Budget*($ million)||Full Year|
|Operations & Other||5|
|Total Light Oil||$71|
|TOTAL CAPITAL SPENDING||$91|
|* Figures may not add up due to rounding.|
|2016 Guidance||Full Year|
|Production (boe/d)||7,000 – 8,000|
|Liquids Weighting (%)||54%|
|Operating Income* ($MM)||~$65|
|Operating Netback ($/boe)||~$24|
|Bitumen Production (bbl/d)||9,000 – 10,000|
|Operating Income* ($MM)||~$2|
|Production (boe/d)||16,000 – 18,000|
|Liquids Weighting (%)||~80%|
|Funds Flow from Operations* ($MM)||~($17)|
|Net Debt ($MM)||~$250|
|Cash & Equivalents ($MM)||~$550|
|Edmonton Par (C$/bbl)||$61.25|
|Western Canadian Select (C$/bbl)||$48.50|
|AECO Gas (C$/mcf)||$3.50|
|* Operating Income and Funds Flow from Operations estimates reflect the mid-point of production guidance. Thermal Operating Income reflects the production ramp-up to design capacity by the end of 2016.|
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.
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 Company’s expectation that Hangingstone Project 1 will have a flat production profile for its initial 5 to 7 years of production after achieving nameplate production (12,000 bbl/d); the Company’s forecast of its 2016 per share production growth; the Company’s plans and strategies to reduce its debt by up to $300 million by the end of 2016 and refinancing its balance sheet over the next 18 months; the timing of 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 expected timing of the Company’s Light Oil division wells coming on-stream; the economic potential of the Company’s Duvernay assets; the Company’s expected production from the Light Oil and Thermal Oil divisions at December 31, 2015 and at December 31, 2016; the anticipation that lower service costs will continue into 2016; the Company’s expected flexibility in its pace of development; the Company’s estimated costs to drill and complete its Duvernay and Montney wells and the Company’s expected cost efficiencies by utilizing pad drilling; the Company’s plan to complete the Placid inter-connect pipeline by the end of April 2016; the Company’s expectation that its Montney wells will be tied-in to its Kaybob-area infrastructure before break-up; the Company’s plans for, and results of, exploration and development activities; the Company’s estimated future commitments; the receipt of proceeds from the remaining promissory notes issued by Phoenix Energy Holdings Limited; the Company’s expected funding-in-place at the end of 2016; the Company’s business and financing plans and strategies; expectations regarding the 2016 capital budget and the Company’s use and allocation of the 2016 budget amounts amongst the Company’s Light Oil and Thermal Oil divisions; 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; changes to royalty regimes and environmental and climate change regulations, environmental risks and hazards; alternatives to and changing demand for petroleum products; 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.
Athabasca Oil Corporation
Media and Financial Community
Vice President, Capital Markets and Communications