Athabasca Oil Corporation Announces 2018 Third Quarter Results

CALGARY, Nov. 07, 2018 - Athabasca Oil Corp. (TSX: ATH) (“Athabasca” or the “Company”) is pleased to provide its 2018 third quarter results and an operations update.

Q3 2018 Results and Operational Highlights

Consolidated Results – Strength in Execution

• Production of 40,612 boe/d (88% liquids), representing 12% growth year over year
• Record adjusted funds flow of $62.2 million ($0.12/sh) and operating income of $83.7 million
• Capital expenditures of $52.4 million; 75% weighted to high margin Light Oil activity
• Net debt of $372 million and available funding capacity of $356 million

Light Oil – High Margin Liquids Rich Growth

• Production of 10,135 boe/d, representing 29% growth year over year
• Operating income of $29.8 million, representing 117% growth year over year
• Top tier netbacks of $31.95/boe supported by high liquids (51%) and low lifting costs ($7.52/boe)
• Placid Montney: multi-well pad tie-in underway with a single drilling rig active in the field
• Duvernay: strong results with 937 boe/d IP30s (91% liquids) on a recent multi-well volatile oil pad

Thermal Oil – Low Decline Production

• Production of 30,477 bbl/d, representing 8% growth year over year
• Operating income of $62.3 million and free cash flow of $48.6 million
• Reduced non-energy costs by 25% year over year with Leismer at an all-time low of $6.69/bbl

Business Environment and Outlook

• Athabasca is strategically slowing production in Thermal Oil by 5,000 – 8,000 bbl/d for the balance of the year to optimize netbacks during an unprecedented WCS differential environment
• Reiterating 2018 production guidance of 39,000 – 41,000 boe/d on a $200 million capital program
• Differentials are expected to narrow in 2019 with a resumption in refining demand and increased egress capacity
• The Company plans to align 2019 capital with cash flow and is prepared to pare back activity as required; a low corporate decline allows the Company to maintain production with modest capital

Athabasca is a liquids-weighted intermediate producer with exposure to Canada’s most active resource plays (Montney, Duvernay, Oil Sands). The Company’s emphasis is on generating strong margins to maximize shareholder return and generate free cash flow into the future.

The Company offers investors excellent exposure to improving oil prices with low total leverage and funds flow sensitivity of approximately $80 million for each incremental US$5/bbl increase in WTI.

Financial and Operational Highlights

1. Refer to the "Advisories and Other Guidance" section in the MD&A for additional information on Non-GAAP Financial Measures.
   
2. Includes realized gain (loss) on commodity risk management contracts of $(8.4) million and $(32.9) million for the three and nine months ended September 30, 2018, respectively ($3.7 million and $6.7 million for the three and nine months ended September 30, 2017, respectively).
   
3. Capital expenditures include capitalized G&A.
   
4. Subsequent to September 30, 2018 Athabasca's available credit and letter of credit facilities increased to $127 million.
   
5. The face value of the 2022 Notes is US$450 million. The 2022 Notes were translated into Canadian dollars at the September 30, 2018 exchange rate of US$1.00 = C$1.2924.

Business Environment

The global crude outlook remains supported by strong demand, low inventories, ongoing geopolitical risk and a decrease in spare productive capacity. Athabasca is a beneficiary with its oil-weighted portfolio.

Despite the strong global crude outlook, Canadian producers have experienced unprecedented differential volatility across light and heavy product streams due to pipeline capacity constraints and refinery turnarounds in key consuming US regions.

The Company anticipates differentials to remain wider than historical levels through the winter. Athabasca has responded to the widening differentials by strategically slowing production by 5,000 – 8,000 bbl/d for the balance of the year (November and December) at Hangingstone and Leismer to optimize netbacks with no long term impacts to the reservoirs.

WCS differentials are expected to normalize between US$18 – 24/bbl over the mid-term supported by a resumption in refinery demand (~1.5 mmbbl/d of peak outages), mobilization of industry crude by rail (currently ~300,000 bbl/d), producer curtailments and Enbridge’s Line 3 Replacement project (370,000 bbl/d). The US refinery complex has made significant investments over the past decade to increase processing capacity of heavy feedstock. Canadian heavy production is expected to have an increasing market share offsetting declines in Venezuela and Mexico.

Athabasca also continues to optimize netback performance by mitigating apportionment with sales to refineries (~60% in Q3) and through access to leased storage in Edmonton. Athabasca has secured long term egress to multiple end markets with 25,000 bbl/d of capacity on TransCanada Keystone XL and 20,000 bbl/d of capacity on the Trans Mountain Expansion Project.

As a net consumer of gas the Company is also a beneficiary of the low Alberta gas pricing environment.

Athabasca has significant flexibility in capital allocation. Thermal Oil underpins a low corporate decline of approximately 10% and provides shareholders free cash flow torque to normalizing differentials and strengthening global oil fundamentals. Placid Montney bolsters the Company’s exposure to high netback production with a flexible development. Kaybob Duvernay is self-funded with minimal capital exposure to the end of 2019 through a joint venture and also increases the Company’s exposure to high value condensate production.

The Company’s priority is to maintain balance street strength by aligning 2019 activity levels to forecasted cash flow and is prepared to implement a minimal capital program until Canadian differentials improve. Growth projects beyond this level will be evaluated in the context of maintaining financial flexibility, corporate free cash flow and external market conditions.

Athabasca ended the quarter with net debt of $372 million. The Company has also recently enhanced its liquidity position by $66.5 million through an increase in letter of credit facilities and the return of a letter of credit issued by the Company in relation to the Trans Mountain Expansion Project until closer to the project startup. Available funding capacity is now estimated at $356 million, including $128 million of cash and equivalents, $127 million of available credit facilities, and a $101 million Duvernay capital carry.

Midstream Transaction

Athabasca is exploring monetization options of its extensive Thermal Oil infrastructure. The Company believes that current timing is favorable following the integration of Leismer and market precedent transactions. A process is underway to explore a wide range of alternatives for this infrastructure which could include a sale, partnership or joint venture. The infrastructure will remain a strategic asset for future growth initiatives at Leismer and Corner.

The Company maintains flexibility for use of potential proceeds which could include bolstering liquidity and/or debt reduction, investing in projects across its asset base that will generate attractive returns for shareholders, and initiating a share buyback program.

Operations Update

Light Oil

Q3 2018 production averaged 10,135 boe/d (51% liquids), representing 29% growth year over year. Light Oil generated third quarter operating income of $29.8 million with a netback of $31.95/boe, supported by a high liquids weighting and low operating expenses of $7.52/boe. Athabasca’s Light Oil netbacks are top tier when compared to Alberta’s other liquids-rich Montney and Duvernay resource producers. The Company spent $38.6 million (net of capital carry) during the quarter.

Greater Placid Montney (70% operated working interest)

During the quarter Athabasca completed a six well development pad (surface location 12-19-60-23W5) which is currently being tied into permanent facilities. Drilling is underway on a seven well development pad (surface location 16-30-60-23W5). In light of current differential volatility and a focus on maximizing shareholder returns, the Company has elected to temporarily defer completion operations.

Over the past two years Athabasca has transitioned Placid from early stage resource capture to efficient multi-well pad development. The Company has organically grown production to ~8,500 boe/d net (~12,000 boe/d gross) and maintains a regional competitive advantage with ownership and operatorship of significant infrastructure. The Company has high graded ~200 liquids rich Montney locations and is positioned for scalable and flexible development.

Greater Kaybob Duvernay (30% non-operated working interest)

Activity in the Duvernay remains robust with the joint venture partnership executing an annual budget of C$387 million (C$30 million net) in 2018 which includes completion operations on 24 wells and placing 26 wells on production. The Duvernay is contributing to strong production and cash flow growth. Q3 Duvernay production was 4,298 boe/d net (63% liquids), up 150% year over year.

Operations are focused on development drilling at Kaybob West and volatile oil delineation across Athabasca’s extensive acreage positon. The joint venture has seen a step change in cost performance with the transition to multi-well pads. The latest development wells have averaged C$8 – 10 million per well (drill & complete).

A string of strong well results continued during the third quarter. IP30s on a five well liquids-rich pad at Kaybob West averaged 1,178 boe/d per well (57% liquids), a two well volatile oil pad at Kaybob East IP30s averaged 711 boe/d (85% liquids) and a three well volatile oil pad at Kaybob West IP30s averaged 937 boe/d (91% liquids).

Thermal Oil

Q3 2018 production averaged 30,477 bbl/d, representing 8% growth year over year.

Thermal Oil generated Q3 2018 operating income of $62.3 million with a netback of $23.30/bbl. Leismer and Hangingstone accounted for operating income of $53.3 million ($27.55/bbl) and $9.0 million ($12.20/bbl) respectively. Financial results were supported by higher realized crude oil prices and ongoing cost optimization. Optimization initiatives have reduced non-energy operating costs by 25% year-over-year to a record low, with Leismer at $6.69/bbl and Hangingstone at $12.20/bbl. Capital expenditures in the third quarter were $13.7 million with resulting free cash flow of $48.6 million.

At Leismer, field activity included the tie-in of four standing infill wells and the installation of a fifth steam generator that was previously held in inventory. The steam generator reduces downtime for planned maintenance and provides excess steam capacity for the start-up of future sustaining well pairs. The Company has commenced operations on the next Leismer sustaining pad (Pad L7) with drilling to be completed this winter and on-stream timing in H2 2019. Project capital for Pad L7 is $55 million with the majority of capital allocated to 2019.

These initiatives are expected to support base annual production between 20,000 – 22,000 bbl/d over the next several years. The Leismer project has a reserve life of ~80 years (Proved + Probable).

2018 Guidance

Athabasca’s 2018 budget is $200 million and includes $85 million in Thermal Oil and $115 million in Light Oil ($85 million Placid Montney and $30 million net Kaybob Duvernay).

The Company anticipates achieving its prior annual guidance of 39,000 – 41,000 boe/d despite the temporary production curtailments in Thermal Oil for the remainder of the year.

About Athabasca Oil Corporation

Athabasca Oil Corp. 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 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 2018 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 November 7, 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.

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 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.

Non-GAAP Financial Measures

The "Adjusted Funds Flow”, "Light Oil Operating Income", “Light Oil Operating Netback”, “Light Oil Capital Expenditures Net of Capital-Carry”, "Thermal Oil Operating Income", "Thermal Oil Operating Netback", “Consolidated Operating Income”, “Consolidated Operating Netback”, and “Consolidated Capital Expenditures Net of Capital-Carry” 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.

Adjusted Funds Flow is not intended to represent cash flow from operating activities, net earnings or other measures of financial performance calculated in accordance with IFRS. The Adjusted Funds Flow 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. Adjusted Funds Flow per share is calculated as Adjusted Funds Flow divided by the applicable number of weighted average shares outstanding.

The Light Oil Operating Income and Light Oil Operating Netback measures in this News Release are calculated by subtracting royalties, operating expenses and transportation & marketing expenses from petroleum and natural gas sales. 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 & marketing expenses from blended bitumen sales. The Thermal Oil Operating Netback measure is presented on a per bbl basis of bitumen sales. 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 Consolidated Operating Income and Consolidated Operating Netback measures in this News Release are calculated by adding or subtracting realized gains (losses) on commodity risk management contracts, royalties, the cost of diluent blending, operating expenses and transportation & marketing expenses from petroleum and natural gas sales. The Consolidated Operating Netback measure is presented on a per boe basis. The Consolidated Operating Income and the Consolidated Operating Netback measures allow management and others to evaluate the production results from the Company’s Light Oil and Thermal Oil assets combined together including the impact of realized commodity risk management gains or losses.

The Consolidated Capital Expenditures Net of Capital-Carry and Light Oil Capital Expenditures Net of Capital-Carry measures in this News Release are outlined in the Company’s Q3 2018 MD&A. These measures allow management and others to evaluate the true net cash outflow related to Athabasca's capital expenditures.