Athabasca Oil Corporation Provides Operations Update and 2018 Outlook

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| Source: Athabasca Oil Corporation

CALGARY, Alberta, Dec. 06, 2017 (GLOBE NEWSWIRE) -- Athabasca Oil Corporation (TSX:ATH) (“Athabasca” or the “Company”) is pleased to provide an operations update and 2018 outlook. Highlights include:

  • Balanced 2018 Budget: $140 million capital budget ($70 million in each of Light Oil and Thermal Oil) aligned to $145 million funds flow (US$55 WTI)
  • Production Growth: 2018 production outlook of 38,500 – 41,000 boe/d (87% liquids), representing 11% per share growth year-over-year 
  • Sustainable Financial Position: 2017 year-end funding capacity of approximately $375 million and forecasted 2018 net debt to funds flow of 2.7x (US$55 WTI)
  • Positioned for Improving Commodity Prices: Flexibility for additional activity with $80 million annual funds flow upside for $5/bbl WTI

Strategic Plan Update

Over the past three years, Athabasca has responded to challenging times by executing on its well-defined strategic plan and transforming the Company from early stage exploration to a funded intermediate oil-weighted producer.

Athabasca is uniquely positioned as an oil weighted producer with current production in excess of 40,000 boe/d (~90% liquids), a low corporate decline of ~10% and exposure to the top returning resource plays in Western Canada (Montney, Duvernay and oil sands). The Company is demonstrating consistent execution, supported by recent quarterly results, with strong underlying cash flow and margin growth. Athabasca is guided by a strategy that includes:

  • Light Oil: Well Defined and Scalable Growth in the Montney and Duvernay
  • Thermal Oil: Low Decline Assets Generating Free Cash Flow
  • Financial: Balance Sheet Sustainability and Margin Growth

The Company is focused on maximizing profitability and shareholder returns. Athabasca maintains flexibility in its capital allocation decisions and is strategically positioned to generate strong free cash flow. The Company has protected its financial position through an active near-term hedging program while retaining exposure to significant upside in an improved oil commodity price environment.  Athabasca also has significant strategic flexibility in the future to generate high returns for shareholders.

Operations Update

Corporate production in November averaged approximately 41,700 boe/d (87% liquids).

In the Light Oil division November production averaged 11,200 boe/d (50% liquids, field estimate).

At Placid, Athabasca recently tied in a four well Montney pad (surface location 7-33-60-20W5) with restricted average IP30s per well of approximately 1,100 boe/d (52% liquids), exceeding its previously increased management internal type curve of 1,000 boe/d.

At Kaybob West, Murphy recently tied-in a two well Duvernay pad (05-29-064-20W5 surface location) with an IP20 of 1,250 boe/d (82% liquids) and an IP18 of 1,000 boe/d (80% liquids) respectively.

In the Thermal Oil division November production averaged 30,500 bbl/d (field estimate). Activity is focused on capital efficient well optimizations (flow control devices and non-condensable gas injection) along with advancing long lead sustaining projects.

2018 Budget and Financial Outlook  

Athabasca’s Board of Directors has approved a $140 million 2018 capital budget. Corporate production guidance is between 38,500 – 41,000 boe/d (87% liquids). The budget is aligned to forecasted funds flow of $145 million and positions the Company with 11% production per share growth year over year.

Light Oil

The base Light Oil budget is $70 million with production guidance between 10,500 – 11,500 boe/d (54% liquids), representing 45% production per share growth year over year.

In the Montney at Placid, planned activity includes completing a six well development pad and drilling six infill wells in Q1 2018. The Montney budget is $40 million net and predominately weighted to the first half. Activity levels will be reassessed mid-year and the asset is positioned for scalable growth with commodity price support.

In the Duvernay at Kaybob, 2018 joint venture plans are expected to include rig releasing 24 wells, completion operations on 27 wells and placing approximately 24 wells on production. Development plans are consistent with the joint development agreement and include significant delineation throughout the volatile oil window (approximately 80% of planned activity). The Duvernay budget is anticipated to be $357 million gross ($30 million net) and Athabasca retains a 30% working interest. 

Thermal Oil

The base Thermal Oil budget is $70 million with production guidance between 28,000 – 29,500 bbl/d. This represents 2% production per share growth year over year, in line with the Company’s strategy to maintain base production with an optimized capital program.

Planned activity at Leismer includes the scheduled turnaround during May, the tie-in of four infill wells, continued production optimization activities and long lead items for future sustaining well pairs. Minimal capital expenditures are expected at Hangingstone as the project is still in ramp-up phase.


2018 GuidanceFull Year
CORPORATE (net) 
  Production (boe/d)38,500 – 41,000
  Liquids Weighting (%)~87%
  Funds Flow from Operations ($MM)~$145
  
LIGHT OIL (net) 
  Production (boe/d)10,500 – 11,500
  Operating Income ($MM)~$115
  Capital Expenditures ($MM)$70
  
THERMAL OIL  
  Bitumen Production (bbl/d)28,000 – 29,500
  Operating Income ($MM) ~$130
  Capital Expenditures ($MM)$70
  
COMMODITY ASSUMPTIONS  
  WTI (US$/bbl)$55.00
  Western Canadian Select (C$/bbl)$52.25
  AECO Gas (C$/mcf)$1.90
  FX (US$/C$) 0.77


Financial Outlook and Risk Management

Athabasca has transformed its financial outlook by building scale and accelerating cash flow in both the Light Oil and Thermal Oil divisions. Light Oil is forecasted to account for approximately 50% of 2018 corporate operating income with netbacks of $28/boe. In Thermal Oil, the low decline nature of Company’s assets provides a strong base of free cash flow to fund future corporate investment and drive value for Athabasca’s shareholders.

The Company’s 2018 capital budget demonstrates Athabasca’s commitment towards financial sustainability and aligning capital spending with funds flow. The Company anticipates exiting 2017 with funding capacity of approximately $375 million including cash and equivalents, available credit facilities and the Duvernay capital carry balance. The Company’s $120 million credit facility was recently reaffirmed by Athabasca’s lenders at its mid-year review. Forecasted 2018 net debt to funds flow is 2.7x (US$55 WTI).

Athabasca’s risk management program is designed to provide near term balance sheet stability while preserving the Company’s upside to improving commodity prices in the medium term. In 2018, the Company intends to hedge up to 50% of 2018 production volumes, and has currently hedged 21,000 bbl/d for Q1 at ~C$48.50/bbl Western Canadian Select (heavy blend), 16,000 bbl/d for Q2 at ~C$48.75/bbl and 6,000 bbl/d for Q3 at ~C$48.50/bbl

The Company forecasts 2018 G&A of approximately $1.95/boe, which represents a 90% reduction from 2014 levels.

Board Renewal Process

As previously announced on November 17, Athabasca has engaged an international recruiting firm to fill a recent vacancy and assist in the ongoing board renewal process to ensure the Board of Directors represents the optimal skillset required to move forward with its existing strategic plan. The Company expects to provide shareholders with updates on this initiative in the coming months.

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 2018 guidance and five 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 9, 2017 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 2018 capital expenditures, funds flow from operations, 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 6, 2017, 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.

Initial Production Rates

The initial production rates provided in this News Release should be considered to be preliminary. Initial production rates disclosed herein may not necessarily be indicative of long term performance or of ultimate recovery.

Drilling Locations

The 200 (gross) Montney inventory referenced in this News Release includes 34 proved undeveloped and 12 probable undeveloped locations, for a total of 46 undeveloped booked 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 GLJ Petroleum Consultants Ltd. as of December 31, 2016 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. While certain of the unbooked drilling locations have been derisked by drilling existing wells in relative close proximity to such unbooked drilling locations, the majority of other unbooked drilling locations are farther away from existing wells where management has less information about the characteristics of the reservoir and therefore there is more uncertainty whether wells will be drilled in such locations and if drilled there is more uncertainty that such wells will result in additional oil and gas reserves, resources or production.

Non-GAAP Financial Measures

The "Funds Flow from Operations”, "Light Oil Operating Income", “Light Oil Operating Netback”, "Thermal Oil Operating Income", "Thermal Oil Operating Netback" and “Net Debt” financial measures contained in this News Release do not have standardized meanings which are prescribed by IFRS and they are considered to be non-GAAP measures. These measures may not be comparable to similar measures presented by other issuers and should not be considered in isolation with measures that are prepared in accordance with IFRS.

Funds Flow from Operations is not intended to represent cash flow from operating activities, net earnings or other measures of financial performance calculated in accordance with IFRS. The Funds Flow from Operations measure allows management and others to evaluate the Company’s ability to fund its capital programs and meet its ongoing financial obligations using cash flow internally generated from ongoing operating related activities. Funds Flow from Operations per share (basic) is calculated as Funds Flow from Operations divided by the number of weighted average basic shares outstanding.

The Light Oil Operating Income and Light Oil Operating Netback measures in this News Release are calculated by subtracting royalties and operating and transportation expenses from petroleum and natural gas sales and midstream revenues received. The Light Oil Operating Netback measure is presented on a per boe basis. The Light Oil Operating Income and the Light Oil Operating Netback measures allow management and others to evaluate the production results from the Company’s Light Oil assets.

The Operating Income and Operating Netback measures in this News Release with respect to the Leismer Project and Hangingstone Project are calculated by subtracting the cost of diluent blending, royalties, operating expenses and transportation expenses from blended bitumen sales. The Leismer Project measures also include gas revenues received. The consolidated Thermal Oil Operating Income and Operating Netback measures also include realized gains or losses on commodity risk management contracts. The Thermal Oil Operating Netback measure is presented on a per bbl basis. The Thermal Oil Operating Income and the Thermal Oil Operating Netback measures allow management and others to evaluate the production results from the Company’s Thermal Oil assets.

The Net Debt measure is calculated by summing the face value of outstanding term debt with current liabilities and subtracting current assets adjusted for the capital carry receivable and risk management contracts. The Net Debt measure is not intended to represent other measures of financial position on the Company’s balance sheet that are calculated in accordance with IFRS. The Net Debt financial measure allows management and others to evaluate the Company’s funding position and utilization of debt within its capital structure.