CALGARY, Alberta, July 29, 2020 (GLOBE NEWSWIRE) -- Athabasca Oil Corporation (TSX: ATH) (“Athabasca” or the “Company”) reported its operating and consolidated financial results for the three months ended June 30, 2020.
The second quarter was defined by unprecedented moves in commodity prices due to the COVID-19 pandemic and resulting oil demand destruction. Athabasca responded swiftly to mitigate the impact of these unexpected events. The Company entered 2020 with a strong liquidity position allowing it to withstand the economic impact on its low decline, long reserve life assets.
Resiliency Measures Taken in Response to COVID-19
- Reduction to Capital: 2020 budget of $85 million reflecting a $40 million reduction.
- Production Curtailments:Temporary curtailments; assets returning to productive capacity in Q3.
- Contingent Bitumen Royalty:$70 million for an upsized Royalty at a very attractive cost of capital.
- Reduced Future Financial Commitments:Reassigned 15,000 bbl/d of Keystone XL transportation.
- Risk Management:~$45 million in realized hedging gains in H1 2020.
- Q2 Production:~27,100 boe/d including ~17,600 bbl/d from Thermal Oil & ~9,500 boe/d from Light Oil. Volumes were temporarily curtailed in response to unprecedented pricing.
- Leismer: Production temporarily curtailed to ~15,000 bbl/d and now restored with July averaging ~18,500 bbl/d. The asset has an estimated operating breakeven of US$23/bbl WCS (using a $12.50 WCS differential). Non-condensable gas co-injection across mature pads is proving successful with a field SOR of 3.4x in July.
- Hangingstone:The asset was shut-in on April 2. A planned facility turnaround has now been completed. With recent improvements in pricing, the asset will be brought back on production in September 2020. Corporate hedges have been implemented to protect downside volatility.
- Placid Montney:10 new well start-ups were deferred until early July and are now all on stream.
- Kaybob Duvernay:Well results continue to screen as top liquids wells in the Basin with Kaybob East IP90s averaging 840 boe/d (85% liquids). 16 wells have been brought on stream in 2020.
Balance Sheet and Financial Highlights
- Balance Sheet: $170 million in liquidity, of which $167 million is unrestricted cash.
- Capital: $5.8 million during Q2; minimal activity for the balance of 2020 (~$25 million in H2 2020).
- Financial Results: Q2 Operating Income of $6.2 million with financial results impacted by realized price declines related to the onset of the COVID-19 pandemic.
- RBL renewal: The credit facility was renewed at $41 million which reflects the outstanding letters of credit for long term transportation contracts and is secured by the Company’s cash balances.
Business Environment and the Impact of COVID-19
In March 2020, the COVID-19 outbreak was declared a pandemic by the World Health Organization. Global commodity prices declined significantly as countries around the world enacted emergency measures to combat the spread of the virus. The decrease in oil demand has been unprecedented with an estimated peak demand impact of 20 MMbbl/d in April 2020 (Goldman Sachs Global Investment Research). Since April, global demand has improved while OPEC and North American producers have cut production. Global inventories have begun to moderate with economies reopening and leading to a partial recovery and stabilization in oil prices.
In Alberta, physical markets and regional benchmark prices (e.g. Western Canadian Select “WCS” heavy oil) have materially strengthened with WTI prices and tighter differentials as a result of curtailed volumes. Athabasca expects WCS differentials to widen from current spot levels (US$7.79/bbl August WCS index differentials) through the fall as more industry volumes are placed back on production.
The global heavy oil market continues to see structural supply declines in Venezuela and Mexico, extended OPEC production cuts and growing petrochemical demand. These shifting dynamics are expected to support heavy oil pricing benchmarks with US refineries in PADD II and III requiring a heavier feedstock. Athabasca is well positioned for this changing dynamic with its Thermal Oil assets.
Corporate Update and Response to COVID-19
Safety is a key priority for Athabasca. The Company has implemented business procedures that comply with Alberta Health Guidelines. Athabasca has successfully transitioned its office staff back to the office and the field sites continue to take site specific pre-cautionary measures related to COVID-19. The Company has not experienced any COVID-19 cases in the Calgary office or at its field sites.
The Company has taken swift action in response to the pandemic and economic crisis. Major initiatives to date include a reduction to the 2020 capital program, significant production curtailments, partnering with service companies to reduce operating costs and reducing future financial commitments on the Keystone XL pipeline. Finally, the Company bolstered its liquidity by $70 million through an upsized Contingent Bitumen Royalty.
The Company is well positioned to navigate the current challenging environment with $170 million in liquidity, of which $167 million is unrestricted cash. The Company’s RBL credit facility was renewed at $41 million which reflects the current outstanding letters of credit for long term transportation commitments and is secured by the Company’s cash balances. Athabasca is currently pursuing additional financial support under the previously announced EDC RBL support program. Athabasca is disappointed in the lack of urgency by the Federal Government to administer the program in an effective manner.
Athabasca remains focused on maximizing corporate funds flow and maintaining strong corporate liquidity. Athabasca maintains long-term optionality across a deep inventory of high-quality Thermal Oil projects and flexible Light Oil development opportunities. This balanced portfolio provides shareholders with differentiated exposure to liquids weighted production and significant long reserve life assets. The low decline nature of the Company’s assets allows for minimal capital investment while maintaining its production base for a crude oil demand recovery.
Financial and Operational Highlights
|Three months ended|
|Six months ended|
|($ Thousands, unless otherwise noted)||2020||2019||2020||2019|
|Petroleum and natural gas production (boe/d)||27,067||33,958||31,812||36,568|
|Operating Income (Loss)(1)(2)||$||6,166||$||67,122||$||7,264||$||125,724|
|Operating Netback(1)(2) ($/boe)||$||2.37||$||22.19||$||1.21||$||19.29|
|Capital Expenditures Net of Capital-Carry(1)||$||5,811||$||26,888||$||59,317||$||58,644|
|LIGHT OIL DIVISION|
|Petroleum and natural gas production (boe/d)||9,466||10,210||8,854||10,957|
|Percentage liquids (%)||62||%||51||%||61||%||52||%|
|Operating Income (Loss)(1)||$||6,350||$||25,637||$||19,133||$||56,917|
|Operating Netback(1) ($/boe)||$||7.37||$||27.59||$||11.88||$||28.70|
|Capital Expenditures Net of Capital-Carry(1)||$||1,089||$||5,029||$||36,877||$||13,676|
|THERMAL OIL DIVISION|
|Bitumen production (bbl/d)||17,601||23,748||22,958||25,611|
|Operating Income (Loss)(1)||$||(24,619||)||$||56,522||$||(57,730||)||$||101,650|
|Operating Netback(1) ($/bbl)||$||(14.21||)||$||26.97||$||(13.17||)||$||22.42|
|CASH FLOW AND FUNDS FLOW|
|Cash flow from operating activities||$||(31,186||)||$||61,488||$||(34,207||)||$||42,916|
|per share - basic||$||(0.06||)||$||0.12||$||(0.06||)||$||0.08|
|Adjusted Funds Flow(1)||$||(16,214||)||$||47,757||$||(44,097||)||$||89,376|
|per share - basic||$||(0.03||)||$||0.09||$||(0.08||)||$||0.17|
|NET INCOME (LOSS) & COMPREHENSIVE INCOME (LOSS)|
|Net income (loss) & comprehensive income (loss)||$||(65,335||)||$||57,091||$||(581,816||)||$||263,887|
|per share - basic||$||(0.12||)||$||0.11||$||(1.10||)||$||0.51|
|per share - diluted||$||(0.12||)||$||0.11||$||(1.10||)||$||0.50|
|COMMON SHARES OUTSTANDING|
|Weighted average shares outstanding - basic||530,363,434||522,459,443||526,979,706||519,253,275|
|Weighted average shares outstanding - diluted||530,363,434||527,661,455||526,979,706||525,417,016|
|June 30,||December 31,|
|As at ($ Thousands)||2020||2019|
|LIQUIDITY AND BALANCE SHEET|
|Cash and cash equivalents||$||167,442||$||254,389|
|Restricted cash (current and long-term)||$||152,125||$||110,609|
|Available credit facilities(3)||$||2,560||$||85,815|
|Capital-carry receivable (undiscounted)||$||—||$||22,740|
|Face value of long-term debt(4)||$||613,260||$||583,425|
(1) Refer to the Advisories in this News Release and the “Advisories and Other Guidance” section within the Company’s Q2 2020 MD&A for additional information on Non-GAAP Financial Measures.
(2) Includes realized commodity risk management gains of $24.4 million and $45.9 million for the three and six months ended June 30, 2020, respectively (three and six months ended June 30, 2019 - $15.0 million loss and $32.8 million loss).
(3) Includes available credit under Athabasca's Credit Facility and Unsecured Letter of Credit Facility.
(4) The face value of the 2022 Notes is US$450 million. The 2022 Notes were translated into Canadian dollars at the June 30, 2020 exchange rate of US$1.00 = C$1.3628.
In Q2 2020, production averaged 17,600 bbl/d. The Company took proactive steps to temporarily curtail Leismer volumes and fully suspend Hangingstone operations in response to unprecedented commodity prices. Activity in the field was minimal during the quarter with $4.7 million of capital expenditures. The Company has halted all major capital projects for the H2 2020 with budgeted activity only including routine pump-changes on wells.
At Leismer, volumes were curtailed down to 15,000 bbl/d in late April. As the commodity outlook improved the Company commenced ramping up volumes through the balance of the quarter. July production is expected to average ~18,500 bbl/d. Leismer operations are now benefiting from the water disposal project which was completed in Q1 2020. The project is estimated to reduce non-energy operating costs by approximately $10 million on an annual basis. In addition, Leismer’s steam oil ratio (“SOR”) is currently 3.4x supported by the ramp-up of sustaining Pad L7 and NCG co-injection on the mature pads. These activities have reduced field wide steam demand by 15% relative to the prior year and is supporting lower energy operating costs and emissions.
At Hangingstone, operations were suspended in April 2020. Through the summer planned turnaround activities were completed. With the improved commodity price outlook, the Company is planning to restart field operations in September. To protect against future commodity price volatility the Company has hedged the production profile through next winter and intends to secure additional risk management activities for the balance of 2021. The Company has utilized a collar hedge structure with a minimum WCS floor price of ~US$25/bbl with upside potential to ~US$31/bbl WCS (Q4 2020 – Q1 2021).
In Q2 2020, production averaged 9,466 boe/d (62% liquids). In response to unprecedented commodity prices, the Company elected to defer the start-up of its new Montney development wells. Capital expenditures were $1.1 million during the quarter as the Company completed its winter Montney and Duvernay program. No additional Light Oil activity is planned for the balance of the year.
At Greater Placid, production from the 10 Montney development wells from the winter program were deferred to July and all wells are now on-stream. Placid is positioned for flexible future development with an inventory of approximately 200 locations and no near-term land retention requirements.
In the Greater Kaybob Duvernay 16 wells have been brought on-stream year-to-date. In the volatile oil window, production results have been consistently strong. Recent multi-well pads at Kaybob East have had IP30s averaging ~1,000 boe/d per well (88% liquids) and IP90s ~840 boe/d (85% liquids). Drilling and completion costs have been reduced to ~C$7.5 million (2-well pads) with line of sight to further improvements with multi-well pad development. These results compare favorably to the East Shale Basin Duvernay due to low capital costs and higher sustained liquids rates. Greater Kaybob is positioned for flexible future development with an inventory of approximately 700 locations, established infrastructure and no near-term land retention requirements.
Athabasca reiterates its $85 million 2020 capital budget, a $40 million reduction from the original budget, with minimal activity planned for the balance of the year (H2 2020 ~$25 million). The Company forecasts Q4 2020 production between 32,000 – 34,000 boe/d (~88% liquids) reflecting a ramp-up in volumes following curtailments and the Hangingstone suspension. Athabasca is well positioned to navigate the current challenging environment with $170 million in liquidity, of which $167 million is unrestricted cash.
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:
Chief Financial Officer
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: our strategic plans and growth strategies; restoring production following curtailments and the Hangingstone suspension; the Company’s 2020 capital budget; expectations on global oil fundamentals; and other matters.
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 4, 2020 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, including those that may be related to the COVID-19 pandemic; 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.
The risks and uncertainties referred to above are described in more detail in Athabasca’s most recent AIF, which is available on the Company’s SEDAR profile at www.sedar.com. Readers are cautioned that the foregoing list of risk factors should not be construed as exhaustive. The forward-looking information included in this News Release is expressly qualified by this cautionary statement and is made as of the date of this News Release. The Company does not undertake any obligation to publicly update or revise any forward-looking information except as required by applicable securities laws.
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.
Operating break‐even reflects the estimated WCS oil price per barrel required to generate an asset level operating income of Cdn $0. Break‐even is used to assess the impact of changes in WCS oil prices on operating income of an asset and could impact future investment decisions. Break‐even does not have any standardized meaning and therefore should not be used to make comparisons to similar measures presented by other issuers.
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.
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 (Loss)", "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. Adjusted Funds Flow is calculated by adding certain non-cash changes to working capital and settlement of provisions to cash flow from operating activities. 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 measure in this News Release is calculated by subtracting royalties, operating expenses and transportation & marketing expenses from petroleum and natural gas sales. The Light Oil Operating Netback measure is calculated by dividing the Light Oil Operating Income (Loss) by the Light Oil production and 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 Thermal Oil Operating Income (Loss) measure in this News Release with respect to the Leismer Project and Hangingstone Project is calculated by subtracting the cost of diluent blending, royalties, operating expenses and transportation & marketing expenses from blended bitumen sales and adjusting for the impacts of inventory write-downs. The Thermal Oil Operating Netback measure is calculated by dividing the respective projects Operating Income (Loss) by its respective bitumen sales volumes and is presented on a per barrel basis. The Thermal Oil Operating Income (Loss) 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 measure in this News Release is 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 and adjusting for the impacts of inventory write-downs. The Consolidated Operating Netback measure is calculated by dividing Consolidated Operating Income (Loss) by the total sales volumes and 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 Q2 2020 MD&A. These measures allow management and others to evaluate the true net cash outflow related to Athabasca's capital expenditures.