CALGARY, Alberta, Nov. 05, 2019 (GLOBE NEWSWIRE) -- Athabasca Oil Corporation (ATH.TO) (“Athabasca” or the “Company”) is pleased to report its third quarter operational and financial results.
Third Quarter and Operational Highlights:
- Adjusted Funds Flow: $43.9 million ($0.08/share) and $133.3 million ($0.26/share) for the third quarter and first nine months of 2019 respectively.
- Free Cash Flow: $8.6 million and $39.3 million for the third quarter and first nine months of 2019.
- Liquids Weighted Production: 35,257 boe/d (87% liquids) in the third quarter of 2019 included 10,023 boe/d (55% liquids) in Light Oil and 25,234 bbl/d in Thermal Oil. Thermal volumes in 2019 have been impacted by government curtailments, facility maintenance and the redistribution of steam across the field to support the startup of Leismer's new Pad L7.
- Leismer: Positioned for a strong 2019 exit with the tie-in of 5 well-pairs, supporting October production of ~18,000 bbl/d. Pad L7 production is expected to ramp-up through H1 2020.
- Placid Montney: Rig released a 4 well pad for $8.2 million net, including 3 pacesetter wells. An inventory of 11 wells ready for completion are expected to provide exceptional short term returns and sustain corporate production and cash flow in 2020 and beyond.
- Kaybob Duvernay: 13 wells to commence completion in early 2020 with Athabasca’s share of capital protected by its joint venture carry provision. Recent well results have seen sustained production well above internal type curves with substantial cost improvements.
Business Resiliency Highlights:
- Netbacks: Operational netbacks continue to be strong with Light Oil at $23.64/boe and Thermal Oil at $21.09/bbl in the third quarter of 2019. Operating costs in Light Oil are best in class at <$7/boe year to date. In Thermal Oil, the Company has completed diluent optimization projects at both Leismer and Hangingstone driving estimated cost savings of ~$16 million annually.
- Enhanced Market Access: Secured ~7,200 bbl/d of Keystone pipeline service commencing in 2020 for a term of 20 years. This capacity diversifies Thermal Oil dilbit sales to the US Gulf Coast at pipeline economics which will allow the Company to further enhance its netback.
- Low Sustaining Capital: The 2019 capital forecast remains unchanged at $135 million and is focused on maintaining base production. Forecasted 2019 Adjusted Funds Flow of ~$150 million is protected by 20,000 bbl/d of Western Canadian Select (“WCS”) hedges at a floor price of ~C$53/bbl in Q4.
- Liquidity Advantage: $336 million of cash and available credit facilities. Competitively positioned to diversify end market access, withstand market volatility with future flexibility for share buybacks and debt reduction.
- Normal Course Issuer Bid: Athabasca’s Board has approved a Special Meeting of Shareholders for the Company to pursue a share buyback given the severe dislocation in underlying value and trading price.
Athabasca continues to demonstrate its operational execution and fiscal prudence to protect its financial position during prolonged market headwinds and commodity price volatility. The Company has minimized its capital spend to ensure it is aligned with funds flow, while preserving its strong liquidity. In 2019, the Company anticipates production of ~36,000 boe/d with Thermal Oil impacted by government curtailments, facility maintenance and the redistribution of steam across the field to support the startup of Leismer Pad L7. The 2019 capital program is $135 million with forecasted Adjusted Funds Flow of ~$150 million (US$55 WTI & US$17.50 WCS differential for the balance of 2019).
The ramp up of new Pad L7 wells at Leismer and a winter program consisting of Placid and Duvernay well completions are expected to sustain production through 2020. Budget objectives for 2020 include activity focused on a minimal capital spend and alignment with funds flow. Athabasca requires low sustaining capital to sustain its production base.
The Company remains focused on increasing free cash flow by improving break-evens and mitigating external risks. The Company has preserved long term optionality across a deep inventory of high-quality Thermal Oil projects and flexible Light Oil development opportunities. This diverse portfolio provides shareholders with significant exposure to liquids weighted production and long reserve life assets.
Business Environment & Market Access
The Alberta Government announced mandatory industry production curtailments starting in January 2019 to alleviate the high differential situation. Following the curtailments, WCS heavy oil pricing and inventories have improved significantly. WCS prices have averaged C$60.24 year to date, a ~135% increase from C$25.36 in Q4 2018. Recently the Alberta government announced a program to provide curtailment relief in an effort to stimulate additional egress through crude by rail. Athabasca is supportive of initiatives that increase egress capacity out of Western Canada but also views curtailments as a necessary tool for the government to have at its disposal to normalize pricing volatility if necessary until long term egress through pipelines is in place.
The global heavy oil market continues to be supported by structural supply declines in Venezuela and Mexico, OPEC cuts and growing petrochemical demand. These dynamics are supporting heavy oil pricing benchmarks with US refineries in PADD II and III requiring a heavier feedstock. The majority of North American liquids production growth is light or condensate spec and slated for export. Athabasca is well positioned for this changing dynamic with its Thermal Oil weighted production and long-life reserve base.
Athabasca continues to pursue egress opportunities to enhance netbacks and diversify sales points for its production. The Company recently secured ~7,200 bbl/d of capacity on TC Energy’s Keystone pipeline open season. The Capacity is expected to commence in 2020 and provides the Company direct exposure to the US Gulf Coast at pipeline economics. Athabasca also has 8,000 bbl/d of direct refinery sales in 2020 which mitigates potential apportionment risk. Long term, Athabasca has secured egress with 25,000 bbl/d of capacity on the TC Energy Keystone XL pipeline and 20,000 bbl/d of capacity on the Trans Mountain Expansion Project.
Normal Course Issuer Bid
Athabasca’s Board of Directors has approved a Special Meeting of Shareholders for the Company to pursue the implementation of a Normal Course Issuer Bid (“NCIB”) through the facilities of the Toronto Stock Exchange. The Board and management believe there is a severe dislocation in underlying value and the current trading price.
In order to affect an NCIB Athabasca must reduce its stated capital pursuant to the provisions of the Business Corporations Act (Alberta). As such the Board of Directors has determined to hold a special meeting of shareholders on January 8, 2020 to consider and, if determined advisable, approve a reduction in the stated capital of Athabasca’s common shares. The record date for the special meeting of shareholders is December 4, 2019. Pursuant to the NCIB and subject to regulatory and shareholder approval, Athabasca would be able to purchase for cancellation up to 10% of its issued and outstanding common shares for a one year period at prevailing market prices at the time of purchase.
Ms. Kim Anderson, Chief Financial Officer ("CFO") has resigned from the Company, effective November 5, 2019 to pursue an opportunity outside of upstream oil and gas. “We wish Kim well on her future endeavors and want to thank her for her contributions to Athabasca over the past five years,” said Robert Broen, President & CEO.
Athabasca is pleased to announce that Mr. Matt Taylor has been appointed Chief Financial Officer of the Company effective today. Mr. Taylor has a breadth of financial and capital markets experience and has been with the Company in the capacity of Vice President Capital Markets & Communications since May 2014. Prior thereto, Mr. Taylor was Director of Energy Equity Research at National Bank Financial in Calgary. Mr. Taylor received a Bachelors of Commerce with a specialization in finance from UBC Sauder School of Business and holds a Chartered Financial Analyst designation.
Financial and Operational Highlights
|3 months ended |
|9 months ended |
|($ Thousands, unless otherwise noted)||2019||2018||2019||2018|
|Petroleum and Natural Gas Production (boe/d)||35,257||40,612||36,126||39,614|
|Operating Netback1,2 ($/boe)||$||19.10||$||23.21||$||19.24||$||13.60|
|Capital Expenditures Net of Capital-Carry1||$||35,304||$||52,389||$||93,948||$||147,938|
|LIGHT OIL DIVISION|
|Petroleum and Natural Gas Production (boe/d)||10,023||10,135||10,642||10,832|
|Operating Netback1 ($/boe)||$||23.64||$||31.95||$||27.09||$||28.76|
|Capital Expenditures Net of Capital-Carry1||$||14,141||$||38,619||$||27,817||$||89,935|
|THERMAL OIL DIVISION|
|Bitumen Production (bbl/d)||25,234||30,477||25,484||28,782|
|Operating Netback1 ($/bbl)||$||21.09||$||23.30||$||21.95||$||12.10|
|CASH FLOW AND FUNDS FLOW|
|Cash Flow from Operating Activities||$||16,741||$||61,733||$||59,657||$||86,097|
|per share - basic||$||0.03||$||0.12||$||0.11||$||0.17|
|Adjusted Funds Flow1||$||43,906||$||62,151||$||133,282||$||81,471|
|per share - basic||$||0.08||$||0.12||$||0.26||$||0.16|
|NET INCOME (LOSS) AND COMPREHENSIVE INCOME (LOSS)|
|Net Income (Loss) and Comprehensive Income (Loss)||$||(8,265||)||$||31,419||$||255,622||$||(81,178||)|
|per share - basic||$||(0.02||)||$||0.06||$||0.49||$||(0.16||)|
|per share - diluted||$||(0.02||)||$||0.06||$||0.49||$||(0.16||)|
|COMMON SHARES OUTSTANDING|
|Weighted Average Shares Outstanding - basic||523,263,183||515,792,185||520,604,599||513,575,091|
|Weighted Average Shares Outstanding - diluted||523,263,183||527,414,170||525,461,794||513,575,091|
|As at ($ Thousands)||Sept. 30 |
|Dec. 31 |
|LIQUIDITY AND BALANCE SHEET|
|Cash and Cash Equivalents||$||255,433||$||73,898|
|Available Credit Facilities3||$||80,609||$||126,491|
|Capital-Carry Receivable (current & LT portion – undiscounted)||$||46,278||$||81,675|
|Face Value of Long-term Debt4||$||595,980||$||614,070|
1) Refer to the "Advisories and Other Guidance" section in the MD&A for additional information on Non-GAAP Financial Measures.
2) Includes realized commodity risk management losses of $9.1 million and $41.9 million for the three and nine months ended September 30, 2019, respectively (September 30, 2018 - $8.4 million and $32.9 million).
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 September 30, 2019 exchange rate of US$1.00 = C$1.3244.
Q3 2019 production averaged 10,023 boe/d (55% liquids). The division generated operating income of $21.8 million relative to $14.1 million of net capital expenditures. Athabasca maintained a top decile netback of $23.64/boe supported by its high quality liquids production and low operating cost structure ($6.92/boe).
The liquids rich Montney at Greater Placid is positioned for flexible and efficient development. The Company commenced drilling a 4 well development pad (2-5-61-23W5) in September. The pad was rig released in late October with $8.2 million net drilling costs and pace setter performance achieved on 3 wells (11.5 day average spud to total depth). Completions will commence on 2 pads (11 wells) this winter with tie-in expected in H1 2020. This low risk, capital efficient development will support Athabasca’s base production and cash flow in 2020 and beyond. Placid development has strong initial liquids yields (200 – 300 bbl/mmcf), low lifting costs and a ~200 well high graded inventory.
The Greater Kaybob Duvernay program remains robust with a 2019 budget of C$256 million gross (~C$20 million net of capital carry). Activity is focused on delineation at Two Creeks, Kaybob East and Kaybob West. Two rigs are operational with completions expected to commence on 13 wells in early 2020.
By the end of this drilling season Athabasca believes the majority of the Duvernay acreage (six areas across ~210,000 gross acres) will be de-risked from a resource appraisal perspective and will be in a position to high-grade development opportunities thereafter.
Athabasca remains encouraged by strong extended production results across the volatile oil window as highlighted in the table below.
|Recent Duvernay Production Rates|
|Area||Pad Surface Location||IP30||IP90||IP120|
|boe/d||% liquids||boe/d||% liquids||boe/d||% liquids|
|Two Creeks||16-29-64-16-W5 (2 wells)||775||93||%||650||93||%||625||93||%|
|05-19-64-15-W5 (2 wells)||675||95||%||500||94||%||-||-|
|Kaybob West||16-25-65-20W5 (step-out well)||750||91||%||725||90||%||650||90||%|
|Simonette||8-3-64-24W5 (3 wells)||1,600||89||%||-||-||-||-|
Note: IPs rounded to the nearest 25 boe/d with volumes adjusted for shrinkage. Two Creeks and Kaybob West wells not tied into permanent infrastructure with liquids currently trucked.
Production for Q3 2019 and the first nine months of 2019 averaged 25,234 bbl/d and 25,484 bbl/d respectively. Production year to date has been impacted by government curtailments, facility maintenance and the redistribution of steam across the field to support the startup of Leismer Pad 7. The Company anticipates stronger Leismer production for the balance of the year and into 2020 with the recent tie-in of Pad L7.
Pad L7 is the first sustaining pad drilled since acquiring the asset in early 2017 and includes five well pairs with ~1,250m laterals (50% longer than prior wells). The new well pairs are expected to ramp-up in H1 2020. Production at Leismer averaged ~18,000 bbl/d in October an increase of ~1,500 bbl/d from Q3 2019.
The Thermal Oil division generated Q3 2019 operating income of $51.9 million with an operating netback of $21.09/bbl ($25.26/bbl at Leismer and $13.63/bbl at Hangingstone). Capital expenditures for the quarter were $21.1 million.
The Company continues to focus on cost optimization initiatives. The Company will be mitigating the increased water disposal costs seen at Leismer in 2019 by commissioning two disposal wells that will be in operations in 2020. Additionally, the Company has completed diluent optimization projects at both Leismer and Hangingstone driving estimated cost savings of ~$16 million annually.
Risk Management & Balance Sheet
Athabasca’s risk management program aims to protect a base level of capital activity while maintaining cash flow upside to the current pricing environment.
For Q4 2019, the Company has hedged 20,000 bbl/d with a WCS floor price of ~C$53.
For 2020, the Company has commenced its hedging program which currently includes 8,000 bbl/d of apportion protected WCS hedged at a differential of ~US$19.50 and 7,500 bbl/d of WTI hedged at a floor price of ~US$55.75. The hedging program targets up to 50% of near term corporate production and Athabasca will layer on additional protection to support its 2020 capital plans.
Athabasca maintains a strong financial position with liquidity of $336 million (cash and available credit facilities) and a Duvernay capital carry balance of $46 million. The Company’s term debt is in place until 2022 with no maintenance covenants.
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: the Company’s 2019 guidance; 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 6, 2019 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, free cash flow, 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, 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.
The 200 Montney drilling locations referenced include: 77 proved undeveloped locations and 12 probable undeveloped locations for a total of 89 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 McDaniel as of December 31, 2018 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, 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", "Consolidated Capital Expenditures Net of Capital-Carry", and "Consolidated Free Cash Flow" 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 2019 MD&A. These measures allow management and others to evaluate the true net cash outflow related to Athabasca's capital expenditures.
The Consolidated Free Cash Flow measure in this News Release is calculated by subtracting the Capital Expenditures Net of Capital-Carry from Adjusted Funds Flow. This measure allows management and others to evaluate Athabasca's ability to generate funds to finance our operations and capital expenditures.