Athabasca Oil Corporation Announces $265 Million Leismer Infrastructure Transaction, Preliminary 2019 Capital Guidance of $95 – $110 Million and Streamlined Cost Structure

CBJ Newsmakers

CALGARY, Alberta, Dec. 10, 2018 (GLOBE NEWSWIRE) — Athabasca Oil Corporation (TSX: ATH) (“Athabasca” or the “Company”) is pleased to provide an update on its midstream process, preliminary 2019 capital guidance expectations and its recent reductions in corporate costs.

Strategic Infrastructure Transaction

Athabasca has entered into an agreement with Enbridge Inc. (“Enbridge”) for the sale of its Leismer pipelines and Cheecham storage terminal (“Leismer Infrastructure Transaction”). Enbridge has been a key partner with Athabasca across its Thermal Oil business unit and the Company looks forward to continuing this long term strategic relationship. The transaction unlocks tremendous value for shareholders while preserving strategic flexibility for the long term development of Athabasca’s high quality Leismer and Corner assets, each of which have regulatory approval for 40,000 bbl/d and a reserve life in excess of 80 years. Key elements of the transaction include:

  • $265 million cash consideration with an annual toll of ~$26 million
  • Priority service on pipelines and dilbit/diluent tanks; excess volumes receive a discounted toll
  • Enhanced credit terms with Enbridge across the Thermal Oil business

Transaction proceeds are approximately 50% of Athabasca’s market capitalization and will significantly bolster the Company’s liquidity, reduce net debt and improve financial resiliency. Leismer’s cost structure will remain competitive with other top tier oil sands projects with a US$43 WTI operating break-even price (assuming a US$18 WCS differential). Future use of proceeds may include debt reduction, growth initiatives or share buybacks. The transaction is expected to close in Q1 2019.   

Athabasca acquired the Leismer and Corner assets in early 2017 for cash consideration of $435 million, 100 million of common shares and contingent value payments triggered at oil prices above US$65 WTI (inflated adjusted). In less than two years, the Company has recovered approximately $500 million of its investment through free cash flow generation, the sale of a contingent bitumen royalty and the transaction proceeds.

Athabasca has taken a number of steps to enhance liquidity to ensure financial resiliency. Early in Q4 2018, the Company obtained the release of a $41.5 million letter of credit related to the Trans Mountain Expansion Project and secured a $25 million increase to its letter of credit facilities. Pro forma funding capacity, including enhancements to Enbridge credit terms, is now approximately $525 million (cash and cash equivalents, available credit facilities and Duvernay capital carry).

Athabasca Outlook

Canadian producers have experienced unprecedented differential and basis spread volatility across light and heavy product streams due to pipeline capacity constraints. This has culminated in Western Canadian Select (“WCS”) heavy differentials trading to peak levels of US$55 in early Q4. Recently, the Alberta Government announced mandatory short term industry production curtailments (“the Industry Curtailments”) starting in January 2019 to alleviate the high differential situation until additional egress is added in 2019. Athabasca is supportive of these actions and views them as a necessary step to rebalance inventories in the near term and provide a bridge to permanent market access initiatives.

Following the Alberta Government’s announcement, the WCS differential outlook has improved significantly. Athabasca expects differentials to moderate in 2019 supported by the Industry Curtailments (325,000 bbl/d), additional crude by rail (currently ~275,000 bbl/d), the start-up of Northwest Refining’s Sturgeon Refinery (80,000 bbl/d) and the Enbridge Line 3 replacement project in H2 2019 (375,000 bbl/d).

Capital Discipline: 2019 Capital & Production Guidance

Athabasca is implementing a minimum 2019 capital program with a focus on maintaining base production until market fundamentals improve.

  • Preliminary capital guidance of $95 – $110 million
  • Production guidance range of 37,500 – 40,000 boe/d (88% liquids)

In Light Oil, capital expenditures are expected to range between $15 – 30 million net with production guidance between 10,000 – 11,000 boe/d.

Placid Montney is positioned for flexible pad development with no near term land expiries. The Company has minimal activity planned for the balance of the winter and recently rig released a seven well pad. Completion activity on this pad and drilling on the next multi-well pads has been be deferred until the pricing environment improves. 

The Kaybob Duvernay joint venture has been successful at delineating both the gas condensate and the volatile oil windows. Athabasca’s exposure remains protected by the capital carry to the end of 2019 and the asset is expected to be self-funded during the year. Preliminary expenditures are expected between $200 – 375 million gross ($15 – 30 million net) for a resulting 30% WI.  Development will continue in the highest returning areas with an inventory of approximately 1,000 gross wells. 

In Thermal Oil, capital expenditures are estimated at $80 million with production guidance between 27,500 – 29,000 bbl/d. The Industry Curtailments are not currently included in annual guidance and are expected to be a temporary measure to restore balance in inventories and tighten historically high differentials. Athabasca’s proportional share of the 325,000 bbl/d industry curtailments is estimated at 1,500 – 2,000 bbl/d on a monthly basis through Q1 2019.

At Leismer, the Company has commenced activity on the next five well sustaining pad and associated facilities which are expected to be placed on production in H2 2019. This will be the first sustaining pad drilled at Leismer since the acquisition in 2017. Athabasca has successfully maintained base production through low-cost optimization initiatives. The remainder of the budget relates to operations maintenance and production optimization activities at Leismer and Hangingstone.

The Company retains flexibility to accelerate growth projects across its portfolio beyond this base level of activity. Future capital decisions will be evaluated in the context of maintaining financial flexibility, corporate cash flow and external market conditions.

Enhancing Competitiveness and Resiliency

Athabasca has pro-actively undertaken a number of actions to enhance its competitiveness and resiliency:

Netback Optimization

  • 30% reduction in year-over-year Light Oil operating costs, with Q3 2018 costs of $7.52/boe
  • 25% reduction in year-over-year Thermal Oil non-energy operating costs, with Leismer and Hangingstone at records lows of $6.69/bbl and at $12.20/bbl in Q3 2018
  • $20 million reduction in run-rate Leismer diluent costs with the tie-in to Norlite in Q2 2018
  • Thermal Oil production curtailments in November and December of approximately 8,000 bbl/d

Streamlined Corporate Cost Structure

  • 25% reduction in head office staff effective immediately  
  • Executives and Directors electing a salary rollback of 10%

Marketing and Risk Management

  • Thermal Oil apportionment protection through direct sales to refineries (~40% of 2019 production) and access to leased storage in Edmonton
  • Thermal Oil hedging: 55% of Q1 2019 at ~US$21 WCS diff and 30% of 2019 at ~US$22 WCS diff

Stronger Balance Sheet

  • $41.5 million release of TMX letter of credit and a $25 million increase in letter of credit facilities
  • Funding capacity is ~$525 million; term debt in place until 2022 with no maintenance covenants

These actions provide the Company with an effective cost structure and improved liquidity. Athabasca is confident it can compete effectively in the North American market.

“While we are encouraged by the recent short-term steps taken by the Alberta Government, significant damage has already been done to both the Canadian economy and investor confidence,” said Robert Broen, Athabasca’s President & Chief Executive Officer. “The sector is still a long ways away from permanent solutions. Our governments, both Federally and Provincially, need to prioritize long term projects to ensure access to new end markets and to maximize value for Canada. This environment has forced us to make several challenging decisions to ensure our resiliency as a Company including a 50% reduction in 2019 capital spend and a 25% reduction in our Calgary office staff.”

Uniquely positioned, low‐decline, oil‐weighted producer
Athabasca has taken significant steps over the last few years to strategically position the Company with competitive Light Oil and Thermal Oil assets that have exceptional opportunities to generate free cash flow. The Leismer Infrastructure Transaction coupled with a disciplined capital program and enhanced cost structure will allow the Company to remain resilient through a challenging macro environment. The Company’s diverse, low decline and long reserve life portfolio is an advantage during periods of extreme volatility and underpins significant asset value for shareholders. Athabasca offers investors excellent exposure to improving oil prices with low leverage and funds flow sensitivity of $80 million for each incremental US$5/bbl increase in WTI.

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.

For more information, please contact:
Matthew Taylor                                                                               
Vice President, Capital Markets and Communications                                    
1-403-817-9104                
mtaylor@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”,  “believe”, “view”, ”contemplate”, “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 operating and 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 contains forward-looking information pertaining to, but not limited to, the following: the Company’s 2019 guidance and multi-year outlook; type well economic metrics; estimated recovery factors and reserve life index; and other matters.

Information relating to “reserves” is also deemed to be forward-looking information, as it involves the implied assessment, based on certain estimates and assumptions, that the reserves described exist in the quantities predicted or estimated and that the reserves can be profitably produced in the future. With respect to forward-looking information contained in this News Release, assumptions have been made regarding, among other things: commodity outlook; the regulatory framework in the jurisdictions in which the Company conducts business; the Company’s financial and operational flexibility; the Company’s, capital expenditure outlook, financial sustainability and ability to access sources of funding; geological and engineering estimates in respect of Athabasca’s reserves and resources; and other matters.

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 7, 2018 available on SEDAR at www.sedar.com, including, but not limited to: fluctuations in commodity prices, foreign exchange and interest rates; political and general economic, market and business conditions in Alberta, Canada, the United States and globally; changes to royalty regimes, environmental risks and hazards; the potential for management estimates and assumptions to be inaccurate; the dependence on Murphy as the operator of the Company’s Duvernay assets; the capital requirements of Athabasca’s projects and the ability to obtain financing; operational and business interruption risks; failure by counterparties to make payments or perform their operational or other obligations to Athabasca in compliance with the terms of contractual arrangements; aboriginal claims; failure to obtain regulatory approvals or maintain compliance with regulatory requirements; uncertainties inherent in estimating quantities of reserves and resources; litigation risk; environmental risks and hazards; reliance on third party infrastructure; hedging risks; insurance risks; claims made in respect of Athabasca’s operations, properties or assets; risks related to  Athabasca’s amended credit facilities and senior secured notes; and risks related to  Athabasca’s common shares.

Also included in this press release are estimates of Athabasca’s 2019 capital expenditures, adjusted funds flow, operating netbacks and operating income levels, which are based on the various assumptions as to production levels, commodity prices and currency exchange rates and other assumptions disclosed in this news release. To the extent any such estimate constitutes a financial outlook, it was approved by management and the Board of Directors of Athabasca on December 10, 2018, and is included to provide readers with an understanding of the Company’s outlook. Management does not have firm commitments for all of the costs, expenditures, prices or other financial assumptions used to prepare the financial outlook or assurance that such operating results will be achieved and, accordingly, the complete financial effects of all of those costs, expenditures, prices and operating results are not objectively determinable. The actual results of operations of the Company and the resulting financial results may vary from the amounts set forth herein, and such variations may be material. The financial outlook contained in this New Release was made as of the date of this press release and the Company disclaims any intention or obligations to update or revise such financial outlook, whether as a result of new information, future events or otherwise, unless required pursuant to applicable law.

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.

Drilling Locations

The 1,000 Duvernay drilling locations referenced in this news release include: 64 proved undeveloped or non-producing locations and 35 probable undeveloped locations for a total of 99 undeveloped booked locations with the balance being unbooked locations. The 200 Montney drilling locations referenced include: 84 proved undeveloped locations with the balance being unbooked locations. Proved undeveloped locations and probable undeveloped locations are booked and derived from the Company’s most recent independent reserves evaluation as prepared by McDaniel as of December 31, 2017 and account for drilling locations that have associated proved and/or probable reserves, as applicable. Unbooked locations are internal management estimates. Unbooked locations do not have attributed reserves or resources (including contingent or prospective). Unbooked locations have been identified by management as an estimation of Athabasca’s multi-year drilling activities expected to occur over the next two decades based on evaluation of applicable geologic, seismic, engineering, production and reserves information. There is no certainty that the Company will drill all unbooked drilling locations and if drilled there is no certainty that such locations will result in additional oil and gas reserves, resources or production. The drilling locations on which the Company will actually drill wells, including the number and timing thereof is ultimately dependent upon the availability of funding, oil and natural gas prices, provincial fiscal and royalty policies, costs, actual drilling results and additional reservoir information that is obtained and other factors.

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