Athabasca Oil Corporation Announces 2017 Third Quarter Results

CALGARY, Alberta, Nov. 02, 2017 (GLOBE NEWSWIRE) — Athabasca Oil Corporation (TSX:ATH) (“Athabasca” or the “Company”) is pleased to provide its 2017 third quarter results and an operations update. The quarter marks continued execution of Athabasca’s strategy with strong consecutive quarterly cash flow growth supported by corporate production now in excess of 40,000 boe/d.

Third Quarter and Recent Highlights

• Q3 2017 Operating and Financial Results    

  • Production of 36,133 boe/d (90% liquids), representing 143% year over year per share growth
    • Current production of approximately 41,000 boe/d (October estimate)
  • Consecutive quarter of strong cash flow growth, earnings and ongoing cost discipline
    • Funds flow of $34.4 million ($0.07 per share)
    • Net income of $5.1 million ($0.01 per share)
    • G&A of $2/boe, a 64% reduction year over year
    • Capital expenditures of $67.7 million
  • Net debt of $365 million (2.7x D/CF annualized) and strong liquidity supported by $174 million of cash and equivalents, a $183 million Duvernay capital carry balance and a $120 million credit facility

• Light Oil – High Margin Liquids-Rich Growth

  • Production of 7,875 boe/d (54% liquids), representing 108% per share growth over Q3 2016
    • Current production of 10,500 boe/d (October estimate)
  • Realized netbacks of ~$19/boe

      Placid Montney (70% working interest)

  • Recent IP30s of 1,206 boe/d (66% liquids) exceed upsized type curve expectation
  • Currently drilling a 6 well pad that is intended to maintain 2018 Light Oil volumes in excess of 10,000 boe/d

      Kaybob Duvernay (30% working interest)

  • 3 well volatile oil pad exceeds type curve with restricted IP30s of 795 boe/d (72% liquids)
  • Murphy planning to operate two rigs until break-up for significant volatile oil delineation

• Thermal Oil – Underpins Low Corporate Decline and Free Cash Flow Generation

  • Production of 28,258 bbl/d, representing 155% per share growth over Q3 2016
    • Current production of 30,400 bbl/d (October estimate)
  • Operating income of $38.6 million and $18.2 million of free cash flow
  • Realized netbacks of ~$15/bbl (~$18/bbl Leismer & ~$3/bbl Hangingstone)

Athabasca’s Strategy

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 funded and flexible development outlook capable of delivering strong economic growth.

The Company’s near term focus is maximizing profitability and shareholder returns through modest activity in Light Oil and ongoing Thermal Oil optimization. Both divisions are positioned for accelerated operations and growth with commodity price support. The Company is guided by a strategy that includes:

  • Light Oil:  Defined and Material Margin Growth
    • A scalable operated Montney position at Placid
    • Funded Duvernay development through the joint venture with Murphy
    • Current production in excess of 10,000 boe/d with scalable growth to 20,000 boe/d by 2020 with a 1-rig program in the Montney and current Duvernay development plans
  • Thermal Oil:  Free Cash Flow with Leverage to Oil Prices
    • A large and established low decline production base
    • Significant free cash flow generation in the current environment
    • Reserve life index of over 70 years (proved plus probable)
  • Financial Sustainability 
    • Maturing cash flow profile with strong sustainability metrics and a low overall corporate production decline of approximately 10% annually
    • Diverse asset base provides flexibility in future capital allocation decisions
    • Five year term debt with no financial covenants and strong liquidity

Financial and Operating Highlights

  3 months ended Sept. 30 9 months ended Sept. 30
($ Thousands, unless otherwise noted) 2017 2016 2017 2016
Petroleum and natural gas volumes (boe/d) 36,133 11,848 33,183 12,098
Petroleum and natural gas sales volumes (boe/d) 7,875 3,018 6,197 5,019
Light Oil operating income1 $ 13,748 $ 5,511 $ 37,001 $ 17,632
Light Oil operating netback1 ($/boe) $ 18.98 $ 19.85 $ 21.87 $ 12.82
Capital expenditures $ 53,406 $ 18,920 $ 162,113 $ 55,095
Recovery of capital-carry through capital expenditures $ (6,092 ) $ (4,286 ) $ (30,265 ) $ (5,760 )
Bitumen production (bbl/d) 28,258 8,830 26,986 7,079
Thermal Oil operating income (loss)1 $ 38,610 $ (6,088 ) $ 78,345 $ (41,079 )
Thermal Oil operating netback1 ($/bbl) $ 14.66 $ (6.80 ) $ 10.64 $ (20.99 )
Capital expenditures2 $ 20,382 $ 3,754 $ 45,376 $ 6,857
Cash flow from operating activities $ 49,488 $ (18,990 ) $ 24,637 $ (51,297 )
  per share (basic) $ 0.10 $ (0.05 ) $ 0.05 $ (0.13 )
Funds flow from operations1 $ 34,400 $ (15,778 ) $ 60,315 $ (84,622 )
  per share (basic) $ 0.07 $ (0.04 ) $ 0.12 $ (0.21 )
Net income (loss) and comprehensive income (loss) $ 5,113 $ (33,032 ) $ 181 $ (157,331 )
  per share (basic and diluted) $ 0.01 $ (0.08 ) $ $ (0.39 )
Weighted average shares outstanding (basic) 509,335,251 405,556,092 496,845,215 405,357,248
Weighted average shares outstanding (diluted) 513,332,423 405,556,092 502,283,110 405,357,248
Leismer Corner Acquisition3 $ (881 ) $ $ (626,645 ) $
Net proceeds from sale of assets $ $ (1,944 ) $ 90,205 $ 390,394
Net proceeds from issuance of 2022 Notes $ $ $ 542,117 $
Repayment of 2017 Notes and term loan $   $ $ (550,000 ) $ (285,441 )
As at ($ Thousands)     Sept. 30,
Dec. 31
Cash and cash equivalents $ 174,076 $ 650,301
Restricted cash $ 113,372 $ 107,012
Capital-carry receivable (current & LT portion – undiscounted) $ 183,204 $ 213,469
Face value of long-term debt (current & LT portion)4 $ 562,950 $ 550,000

1) Refer to “Advisories and Other Guidance” in the MD&A for additional information on Non-GAAP Financial Measures.
2) Thermal Oil capital expenditures excludes the cost of the Leismer Corner Acquisition.
3) Consists of cash of $435.9 million, common shares of $166.0 million and contingent payment obligations of $24.7 million for the nine months ended September 30, 2017.
4) Face value of the US dollar denominated 2022 Notes as at September 30, 2017 is US$450 million. The 2022 Notes were translated into Canadian dollars at the period end exchange rate of US$1.00=C$1.2510.

Operations Update

Light Oil

Production averaged 7,875 boe/d (54% liquids) in Q3 2017. October production averaged approximately 10,500 boe/d with volumes driven by the tie-in of Montney wells from last winter’s program and representing approximately 175% per share growth since Q3 2016. The Company remains on track to achieve the upper end of its annual Light Oil guidance of 6,500 – 7,500 boe/d.

Light Oil operating income was $13.7 million ($18.98/boe netback). Capital expenditures totaled $47.3 million net with activity focused on completing two Montney pads, commencing the second half drilling program at Placid and ongoing Duvernay joint development operations. Operating expenses were $10.90/boe in Q3 2017 and were impacted by a 19 day planned turnaround at the Keyera Simonette gas plant. Operating expenses are expected to drop in Q4 2017 and into 2018 supported by additional production growth and field optimization.

Greater Placid Montney (Athabasca operated, 70% working interest)

At Placid the Company has established scale of operations with a high netback production base, ownership in strategic regional infrastructure and a multi-year low risk development inventory. The Montney asset is positioned for flexible, scalable and economic growth in the current price environment.

During the quarter Athabasca completed the remaining two pads (eight wells) from last winter’s five multi-well pad program. The first pad (surface location 03-04-61-23W5) was placed on production in September and the second pad (surface location 7-33-60-20W5) is expected to be on production through permanent facilities in early November. IP30s from the 3-4 pad averaged 1,206 boe/d (66% liquids) supporting the previously increased type curve (IP30s 1,000 boe/d 57% liquids & 675 mboe EUR). The Company attributes stronger well performance to the higher proppant completion design which appears to yield a more effective reservoir stimulation. Extended production is supporting stronger liquids rates at higher flowing pressures when compared to the prior design as well as offsetting regional industry wells. Long term liquids yields are a significant driver in well economics.

  Placid 2016/17 Winter Program   IP301 IP901 IP1801
  Pad Surface Location   boe/d % liquids boe/d % liquids boe/d % liquids
07-30-60-23W5 On-stream December 813 70 % 690 67 % 657 61 %
12-19-60-23W5 (Pod 2)2 On-stream April 821 51 % 670 61 % 705 55 %
16-30-60-23W52 On-stream April 1,053 50 % 798 58 % 824 52 %
03-04-61-23W53 On-stream September 1,206 66 %
07-33-60-20W5 On-stream November

1) IPs reflect sales gas, free condensate and estimated plant based NGL recovery.
2) Peak 30 day rates reported on Pad 2 & 3 as the initial rates in April were temporarily restricted by spring road bans and the 16-day Keyera unplanned outage.
3) Includes IP30s for 3 wells and an IP27 for the 1-28 well which was initially shut-in during completions operations of the adjacent 7-33 pad.

The Company spud a six well pad in August (surface location 7-30-60-23W5 – Pod 2) with completions anticipated in Q1 2018. The Company views the 7-30 Pod 2 pad as a low risk capital efficient development that should maintain base Light Oil production levels through 2018. Decisions regarding 2018 activity will be finalized later this year and the Company retains flexibility to adapt activity levels to results and external market conditions.

Over the past year Athabasca has completed a number of strategic land acquisitions through industry swaps and crown land sales. The Company’s operated Montney position now stands at approximately 80,000 gross acres, of which 48,000 gross acres (36,000 net) are high-graded Placid development. An inventory of over 200 locations positions the Company for multi-year growth.

Greater Kaybob Duvernay (Murphy operated, 30% working interest)

Joint venture operations commenced in the fall of 2016 with the objectives of driving near-term production and cash flow growth, delineation across all phase windows, optimizing well design and maximizing land retention.

The 2017/18 winter program is underway and Murphy expects to run two rigs until spring break-up. Planned operations include significant volatile oil delineation at Simonette, Kaybob West, Kaybob North and Kaybob East as well as condensate rich gas drilling Saxon. Murphy is testing a number of completion techniques in the initial wells, leveraging off their experience in the Eagle Ford oil window.

During the quarter a three well volatile oil pad at Kaybob West (11-18-64-20W5 surface location) had average restricted IP30s of 795 boe/d (72% liquids), exceeding Athabasca type well expectations of 530 boe/d.

Kaybob Duvernay Activity Area Date Restricted IP301
Pad Location / UWI boe/d  % liquids
2 well pad (Surface 04-32-064-20W5)
  16-36-64-21W5 Kaybob West Volatile Oil On-stream June 1,790 75 %
  3-28-64-20W5 On-stream June 830 74 %
3 well pad (11-18-064-20W5)
  16-23-64-21W5 Kaybob West Volatile Oil On-stream July 780 72 %
  10-23-64-21W5 On-stream July 850 71 %
  13-24-64-21W5 On-stream July 760 74 %
1 well pad (16-18-065-20W5)  
  05-09-065-20W5 Kaybob West Volatile Oil On Soak / Q4 test
2 well pad (05-29-064-20W5)  
  10-36-64-21W5 Kaybob West Volatile Oil Completed /
Q4 On-stream
2 well pad (15-16-063-24W5)
  00/7-29-63-24W5 Simonette Volatile Oil Q4 Completion /
Q1 On-stream
2 well pad (12-29-064-18W5)
  14-36-64-19W5 Kaybob East Volatile Oil Q4 spud
3 well pad (16-03-062-23W5)
  13-09-62-23W5 Saxon Condensate Rich Gas Q4 Spud

1) IPs reflect sales gas, free condensate and estimated plant based NGL recovery.

The Company remains encouraged by strong offsetting industry well results and robust activity levels (Shell, Encana and Chevron). The Duvernay competes with other top North American shale plays and boasts high free liquids (200 – 1,000 bbl/mmcf), premium value condensate production and a low 5% royalty over the first three years (compared to average Permian rates of ~25%). Resulting operating netbacks for an 80% liquids well at US$55/bbl WTI are approximately C$45/boe. The joint venture positions Athabasca shareholders with a funded Duvernay development profile over the next four years and long-term upside with a 30% working interest in over 200,000 prospective Duvernay acres and an inventory of approximately 1,500 drilling locations.

Thermal Oil

Production averaged 28,258 bbl/d in Q3 2017. Thermal Oil operating income was $38.6 million ($14.66/bbl) with $20.4 million of capital expenditures during the quarter. Resulting free cash flow was $18.2 million. Current Thermal Oil production is approximately 30,400 bbl/d (October estimate).


Leismer production averaged 19,498 bbl/d in Q3 2017 which incorporated facility maintenance in July and August. October production averaged approximately 20,900 bbl/d.

The Company is taking deliberate steps to prudently manage reservoir performance and maximize profitability. Near-term operations are focused on production and steam optimization across the field and the start-up of predrilled infills on Pad L5 in 2018. The Company expects to manage production between 20,000 – 22,000 bbl/d.

The Company estimates a low average 32% recovery factor on existing wells to date with recoveries expected to reach approximately 65% long-term, in line with comparable industry projects. The asset’s reserve life index is over 30 years proven and over 70 years proved plus probable. Management remains pleased with the quality of the asset and inherent flexibility to reduce capital while maintaining production in this environment.


Hangingstone averaged 8,760 bbl/d in Q3 2017 with $2.3 million of operating income. October production averaged approximately 9,500 bbl/d. Production is expected to continue to increase with steam chamber growth. Hangingstone is expected to require minimal capital over the next several years.

Balance Sheet, Hedging and Sustainability

Financial sustainability remains a core part of Athabasca’s strategy and throughout 2017 the Company has focused on activities that drive increased margins and improve financial resiliency. 2017 capital has been primarily directed to the high margin Montney and Duvernay with Light Oil volumes currently in excess of 10,000 boe/d.

The Company manages its exposure to commodity prices through an active hedging program and intends to hedge up to 50% of 2018 volumes. The Company currently has 20,000 bbl/d hedged for the remainder of 2017 at an average price of ~C$50.75/bbl Western Canadian Select (heavy blend), 18,000 bbl/d for Q1 2018 at ~C$48/bbl, 11,000 bbl/d for Q2 2018 at ~C$48/bbl and 5,000 bbl/d for Q3 2018 at ~C$48/bbl.

The Company maintains a strong balance sheet with net debt at the end of Q3 2017 of $365 million (2.7x net debt to quarterly funds flow annualized). Liquidity is supported by $174 million of cash and equivalents, a $183 million Duvernay carry balance and a $120 million credit facility. The Company also has significant asset value in its established and operated Thermal and Light Oil infrastructure.

2017 Guidance and 2018 Outlook

Reaffirming 2017 Guidance

Athabasca’s 2017 capital budget is unchanged at $210 million with annual corporate production expected to average approximately 35,000 boe/d.

2017 Full Year
  Production (boe/d) 33,500 – 36,500
  Liquids Weighting (%) ~91%
  Funds Flow from Operations ($MM) ~$80
  Production (boe/d) 6,500 – 7,500
  Operating Income ($MM) ~$60
  Capital Expenditures ($MM) $ 150
  Bitumen Production (bbl/d) 27,000 – 29,000
  Operating Income ($MM) ~$105
  Capital Expenditures ($MM) $ 60
  WTI (US$/bbl) $ 50.00
  Western Canadian Select (C$/bbl) $ 49.25
  AECO Gas (C$/mcf) $ 2.15
  FX (US$/C$) 0.77

2018 Outlook

Management expects to align 2018 capital spending with corporate cash flow. The Company’s assets afford it significant capital flexibility in both the Light Oil and Thermal Oil divisions.

Placid Montney activity has no near-term land expiries and a program of six to eight wells annually is expected to hold production flat. Drilling operations are underway on a six well development pad with completions expected to follow in Q1 2018. This base level of activity is expected to support Light Oil volume in excess of 10,000 boe/d for 2018.

In the Duvernay, funded growth is driven through the joint venture and the Company is protected by a capital carry on the first $1 billion of investment (7.5% capital exposure for a 30% WI). 2018 activity is expected to be consistent with the joint development agreement which contemplates approximately $350 million of gross investment (approximately $26 million net), up from approximately $200 million gross in 2017.

In Thermal Oil, the Company will continue to optimize capital and operations in order to maximize profitability and long-term recoveries.

Athabasca is firmly positioned as an intermediate producer and in 2018 expects to maintain production in excess of 40,000 boe/d (~90% liquids), approximately 15% growth year over year, with a modest capital program. The Company retains readiness to accelerate activity in both divisions with commodity price support. The 2018 capital budget and guidance will be released on December 6th.

Board Additions and Management Update

Athabasca is pleased to announce the recent appointments of Anne Downey and Henry Sykes as directors to the Company’s Board of Directors, which is now comprised of seven members.

Ms. Downey has 40 years of upstream oil and gas experience at Gulf Canada, Petro-Canada and Statoil Canada. Ms. Downey previously held the role of VP Operations at Statoil Canada responsible for oil sands asset development, operations and technology strategy and implementation. Ms. Downey was selected to be an Industry member of the Alberta Government’s Oil Sands Advisory Group.

Mr. Sykes has more than 35 years of legal and upstream oil and gas experience. Mr. Sykes was previously President and a director of MGM Energy from 2007-2014 and President of ConocoPhillips Canada from 2001-2006. Prior to this Mr. Sykes was a partner at Bennett Jones, specializing in mergers and acquisitions, corporate and securities law in Calgary.

The Company is also pleased to announce a key addition to Athabasca’s executive leadership team with the appointment of Angela Avery as General Counsel and Vice President of Business Development. Ms. Avery has over 20 years of diverse legal and business experience within the energy industry with a focus on major transactions. Prior to Athabasca, Ms. Avery held senior management roles at ConocoPhillips including Chief Compliance Officer of the global business based in Houston and Vice President, Law and Business Development of the Canadian business.

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

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