Athabasca Oil Corporation (TSX:ATH) ("Athabasca" or the "Company") is pleased to provide its 2017 first quarter results and an operations update. The first quarter marks the completion and integration of the transformational Statoil oil sands acquisition, a successful balance sheet refinancing and operational momentum in the Light Oil division. The Company is positioned for strong economic growth through the second half of 2017.
First Quarter and Recent Highlights
Athabasca is an intermediate oil weighted producer with exposure to several of the largest resource plays in Western Canada including the Montney, Duvernay and oil sands. The Company has a fully funded development outlook capable of delivering growth to 60,000 boe/d by 2020 (40% production per share CAGR) and is guided by a strategy that includes:
Greater Placid Montney (Athabasca operated, 70% working interest)
At Placid, Athabasca completed an active winter program that included rig releasing 20 Montney wells, the commissioning of a new battery and the tie-in of three multi-well pads. Placid is positioned for flexible and scalable economic growth over the next five years.
Two drilling rigs commenced operations last fall and the Company rig released a total of 20 horizontal wells from five pads. The program was designed to accelerate pad drilling operations targeting two Montney cycles. Drilling costs averaged $3.0 million per well with average lateral lengths of approximately 2,600 meters and the latest eight wells up to 3,000 meters. The Company maintained its drilling costs year over year as operational efficiencies offset modest service cost inflation. Drilling performance on the latest wells were industry pacesetters reaching total depth in approximately 15 days. The Company is advancing operational readiness for next winter's drilling program which will include a combination of low risk infill locations off existing pads and step-outs from the core development.
A total of three pads, 11 wells, were completed this winter with all wells placed on production in April through the Company's owned and operated infrastructure (surface locations 7-30, 16-30 & 12-19-60-23W5). The Company modified its completion design to a plug and perf from ball drop with the goal to improve fracture intensity and ultimately long term rates and recoveries. Completion costs for the program averaged $4.2 million per well ($124,000 per stage, 34 average stages per well) with proppant intensity up to 1,000 lbs/ft (1.8 T/m). The remaining two pads are expected to be completed following break-up and placed on production in the third quarter (surface locations 3-4-61-23W5 & 7-33-60-23W5).
The Placid battery and infrastructure project was commissioned in April. The new infrastructure will support Athabasca's mid-term growth targets and has capacity of 10,000 bbl/d and 36 mmcf/d (gross). The Company operates all of its regional infrastructure with liquids pipe connected to the Pembina Peace system and gas processed through Keyera's Simonette Gas Plant and marketed through the Alliance System.
In April, Athabasca's Light Oil production was impacted by a 16 day unplanned shutdown of the Keyera Simonette Gas Plant. The Company was able to partially mitigate the impact by redirecting a portion of its regional Kaybob and Placid production to the SemCAMS KA plant. During the shutdown approximately 50% of volumes were restricted with an estimated 250 boe/d impact to annual volumes.
Current Light Oil production is approximately 7,500 boe/d representing 120% growth over Q1 2017. In the Montney, initial production and pressure data from the new wells are supporting Athabasca's type curve which is highly economic in the current pricing environment (52% IRR and 22 month payback at US$50/bbl WTI). Regional production is temporarily restricted as a result of spring road bans limiting the trucking of flowback fluid. Initial free liquids yields have ranged between 300 - 500 bbl/mmcf and compare favorably to type curve expectations between 200 - 300 bbl/mmcf during the first 30 days of operation. The Company anticipates increasing gas rates over time as the wells clean-up. Extended production rates for the new wells will be provided with the Company's Q2 2017 results.
Decisions regarding second half activity levels will be finalized in the summer and the Company retains flexibility to adapt the program to results and external market conditions.
Greater Kaybob Duvernay (Murphy operated, 30% working interest)
Joint venture operations commenced in the fall of 2016 with the objective of driving near-term production and cash flow growth, delineation across all phase windows, optimizing well design and maximizing land retention.
Murphy operated two drilling rigs through the winter season and rig released eight wells from four pads. Initial activity has been focused in the condensate rich gas window at Kaybob West and in the volatile oil window at Kaybob West North. Drilling performance has been competitive with industry peers and wells have averaged approximately 24 days spud to rig release (5,000 - 6,000 meters average measured depth). Activity through the second half will step out through the volatile oil window at Kaybob East, Two Creeks and Simonette.
A two well pad at surface location 1-18-64-20W5 was spud in late 2016 and completed and placed on production through the first quarter. Utilizing an existing pad, Murphy drilled two offsets to the 1-7-64-20W5 well with average lateral lengths of approximately 1,400 meters. A restricted flow back technique was employed to evaluate completion design and reservoir production characteristics over time.
A two well pad at surface location 4-32-64-20W5 was rig released in early March with average laterals of approximately 2,800 meters. Completions operations are underway with tie-in expected post break-up.
A single well at surface location 16-18-65-20W5 was rig released in late March with a 2,900 meter lateral. This well is the longest lateral drilled to date and the most northern well in the volatile oil window. Completions operations are planned post break-up.
A three well pad at surface location 11-18-64-20W5 was rig released in April with average laterals of approximately 2,400 meters. Completions operations are underway with tie-in expected post break-up.
The 2017 budget includes spudding 16 gross wells which are a mix of pad development locations and delineation wells throughout the volatile oil window. Murphy intends to optimize well design with average lateral lengths increasing to between 2,500 - 3,000 meters and frac intensity between 2,000 - 3,000 lbs/ft (3 - 5 T/m). Total lateral drilling for the program is approximately 45,000 meters and this compares to Athabasca's initial 20 well appraisal campaign of approximately 27,000 meters since 2012.
Results from the Duvernay program are expected to pick up through H2 2017 as wells are completed and tied-in post break-up with 10 additional spuds planned for the balance of the year.
Athabasca assumed operatorship of Leismer following closing of its acquisition on January 31, 2017. The asset is meeting expectations with an established low decline production base and averaged 22,521 bbl/d through February and March. Over the same period the asset generated $17 million of operating income and $11 million of free cash flow. Leismer is a Tier 1 thermal asset with a strong free cash flow profile in the current price outlook.
As a result of strong well pair performance and prior investment in sustaining infill wells the 2017 capital budget at Leismer has been reduced by $30 million to $54 million (previously $84 million) with no impact to planned production. Athabasca also sees opportunities for operating cost reductions over the next year including alternate diluent sourcing which is expected to be operational in mid-2018.
Near-term operations will focus on production optimization across the field and the start-up of predrilled infills on Pad L5. Through the mid-term the Company intends to expand Pad L2 with five new well pairs and evaluate infill opportunities on Pads L3 and L4.
Hangingstone averaged 8,552 bbl/d for the quarter and approximately 9,200 bbl/d for March. As previously guided the Company is anticipating facility maintenance in April and May that will impact near-term production growth. The project is expected to reach name plate capacity of approximately 12,000 bbl/d in 2018 with minimal maintenance capital expected within the first five years of operations.
In the first quarter Athabasca secured 20,000 bbl/d of blended bitumen capacity on the Kinder Morgan Trans Mountain Expansion Project. The pipeline project is federally approved and is expected to be in-service in late 2019. The Company believes securing term take-away capacity to multiple end markets is essential to its long-term strategy. The Trans Mountain pipeline will provide Athabasca exposure to global oil demand growth.
2017 Outlook and Budget
Light Oil Guidance
Athabasca's 2017 Light Oil capital budget is unchanged at $135 million ($120 million for Placid Montney and $15 million net post capital carry for Duvernay) with production guidance of 6,500 - 7,500 boe/d and production expected to reach 10,000 boe/d before year-end. H2 2017 Montney capital will be assessed mid-year.
Thermal Oil Guidance
Athabasca's 2017 Thermal Oil budget has been reduced by $30 million to $75 million (approximately a 30% reduction) with unchanged production guidance of 29,000 - 32,500 bbl/d. The capital program now consists of $54 million at Leismer, $15 million at Hangingstone and an additional $6 million for maintaining Athabasca's long dated thermal leases.
Balance Sheet and Risk Management Update
In the first quarter Athabasca completed a comprehensive balance sheet refinancing transaction. This included the issuance of US$450 million of five-year covenant lite second lien notes to replace the Company's existing $550 million of second lien notes, and the establishment of a $120 million reserve based credit facility. Athabasca is well positioned to advance its strategic objectives with multi-year funding certainty, financial flexibility and a strong liquidity outlook.
At the end of the first quarter Athabasca had a cash positon of $327 million (inclusive of restricted cash) and $103 million of available credit facilities. The Company also has $203 million of remaining capital carry that will drive $1 billion of gross Duvernay investment over four years, as well as significant asset value in its established and operated Thermal and Light Oil infrastructure.
Athabasca anticipates an internally funded capital program in 2018 at US$55/bbl WTI with net debt to cash flow of less than 2.5x and trending lower in subsequent years.
The Company has recently commenced a commodity risk management program designed to protect a base level of cash flow and support its capital plans. The Company intends to hedge a minimum of 20,000 bbl/d for the balance of 2017 with 13,000 bbl/d of Western Canadian Select ("WCS") hedged at approximately C$53/bbl and an additional 7,000 bbl/d of WCS differential hedged at approximately US$14.75/bbl. Going forward, a multi-year hedging program is expected to form a part of the Company's risk management strategy.
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.
SOURCE: Athabasca Oil Corporation
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