CALGARY, Alberta, July 31, 2019 (GLOBE NEWSWIRE) -- Athabasca Oil Corporation (TSX: ATH) (“Athabasca” or the “Company”) is pleased to report continued strong financial performance with its second quarter results. With its resilient business model, the Company is well positioned to generate free cash flow in 2019 and beyond.
2019 Second Quarter Highlights
Consolidated Quarterly Results
- Production of ~34,000 boe/d (85% liquids)
- Operating income of ~$82 million (excluding hedging)
- Adjusted funds flow of ~$48 million ($0.09/share)
- Free cash flow of ~$21 million with positive contributions from both Light Oil and Thermal Oil
Light Oil – High Margin Liquids Rich Returns
- Production of ~10,200 boe/d (51% liquids)
- Operating income of ~$26 million with a top decile netback of ~$27.50/boe
- Strong initial Two Creeks Duvernay results unlock significant inventory within a shallower window of the Kaybob play; IP60 of ~725 bbl/d per well 16-29 pad and IP30 of ~725 bbl/d 5-19 pad
- Simonette Duvernay pad on-stream with initial rates >2,000 boe/d per well (~90% liquids)
Thermal Oil – Low Decline Production
- Production of ~23,800 bbl/d including downtime for maintenance at both assets
- Operating income of ~$56 million; record division netback of ~$27/bbl (~$31/bbl at Leismer)
- Leismer L7 sustaining pad commenced circulation with first production expected in Q4 2019
- Liquidity of ~$425 million (cash & available credit facilities); net debt of ~$240 million
Uniquely Positioned for Current Market Fundamentals
- Annual capital guidance of ~$135 million focused on sustaining production for 2020
- Low annual sustaining capital advantage of ~$9.50/boe; balanced H2 2019 activity includes drilling a four well Montney pad at Placid, drilling 13 Duvernay wells, a steam debottleneck project and NCG co-injection expansion at Leismer
- Annual adjusted funds flow forecast of $155 million (US$60 WTI & US$17.50 WCS differentials)
Athabasca is a liquids-weighted intermediate producer with exposure to Canada’s most active resource plays (Montney, Duvernay, Oil Sands). The Company’s high quality, long life assets provide investors with unique exposure to free cash flow which, combined with focus on strong margin opportunities, drives shareholder returns. The Company has flexibility to direct sustainable free cash flow to debt reduction, share buy backs or capital projects.
Financial and Operational Highlights
|3 months ended June 30||6 months ended June 30|
|($ Thousands, unless otherwise noted)||2019||2018||2019||2018|
|Petroleum and Natural Gas Production (boe/d)||33,958||37,658||36,568||39,107|
|Operating Netback1,2 ($/boe)||$||22.19||$||13.01||$||19.29||$||8.80|
|Capital Expenditures Net of Capital-Carry1||$||26,888||$||38,888||$||58,644||$||95,549|
|LIGHT OIL DIVISION|
|Petroleum and Natural Gas Production (boe/d)||10,210||11,872||10,957||11,187|
|Operating Netback1 ($/boe)||$||27.59||$||28.64||$||28.70||$||27.27|
|Capital Expenditures Net of Capital-Carry1||$||5,029||$||10,286||$||13,676||$||51,316|
|THERMAL OIL DIVISION|
|Bitumen Production (bbl/d)||23,748||25,786||25,611||27,920|
|Operating Netback1 ($/bbl)||$||26.97||$||15.79||$||22.42||$||6.33|
|CASH FLOW AND FUNDS FLOW|
|Cash Flow from Operating Activities||$||61,488||$||27,605||$||42,916||$||24,364|
|per share - basic||$||0.12||$||0.05||$||0.08||$||0.05|
|Adjusted Funds Flow1||$||47,757||$||25,680||$||89,376||$||19,320|
|per share - basic||$||0.09||$||0.05||$||0.17||$||0.04|
|NET INCOME (LOSS) AND COMPREHENSIVE INCOME (LOSS)|
|Net Income (Loss) and Comprehensive Income (Loss)||$||57,091||$||(19,267||)||$||263,887||$||(112,597||)|
|per share - basic||$||0.11||$||(0.04||)||$||0.51||$||(0.22||)|
|per share - diluted||$||0.11||$||(0.04||)||$||0.50||$||(0.22||)|
|COMMON SHARES OUTSTANDING|
|Weighted Average Shares Outstanding - basic||522,459,443||514,679,681||519,253,275||512,448,170|
|Weighted Average Shares Outstanding - diluted||527,661,455||514,679,681||525,417,016||512,448,170|
|As at ($ Thousands)||June 30|
|LIQUIDITY AND BALANCE SHEET|
|Cash and Cash Equivalents||$||292,851||$||73,898|
|Available Credit Facilities3||$||131,264||$||126,491|
|Capital-Carry Receivable (current & LT portion – undiscounted)||$||53,638||$||81,675|
|Face Value of Long-term Debt4||$||589,095||$||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 loss of $15.0 million and $32.8 million for the three and six months ended June 30, 2019, respectively (June 30, 2018 - $23.9 million and $24.5 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 June 30, 2019 exchange rate of US$1.00 = C$1.3091.|
In December, the Alberta Government announced mandatory industry production curtailments starting in January 2019 to alleviate the high differential situation until additional egress is added. Following the announcement, the Western Canadian Select (“WCS”) heavy oil pricing outlook has significantly improved. WCS prices have averaged C$61.18 in H1 2019, a ~140% increase from C$25.36 in Q4 2018. Athabasca remains supportive of these actions and views them as a necessary step to normalize pricing and provide a bridge to permanent market access initiatives.
Industry crude by rail remains an important factor in managing differentials and Alberta inventories. Rail capacity continues to increase and base line utilization is expected to build through 2019 as long term contracts are operationalized.
The global heavy oil market continues to tighten with supply declines in Venezuela and Mexico, OPEC cuts and growing petrochemical demand. These changing dynamics are supporting heavy oil pricing benchmarks with US refineries in the PADD II and III regions requiring a heavier feedstock. The majority of onshore North American liquids production growth is light or condensate spec and slated for export to the international market. Athabasca is well positioned for this changing global supply dynamic with its Thermal Oil weighted production and long life reserve base.
Q2 2019 production averaged 10,210 boe/d (51% liquids). The division generated operating income of $25.6 million and maintained a top decile netback of $27.59/boe. Capital expenditures for the quarter were $5.0 million (net of capital carry).
The liquids rich Montney at Greater Placid (70% operated working interest) is positioned for flexible and efficient development. Robust project economics are supported by strong initial liquids yields (200 – 300 bbl/mmcf), low lifting costs and a ~200 well high graded inventory. Drilling will recommence this fall on a four well pad at 2-5-61-23W5 (“2-5”). The Company retains flexibility for completion timing and tie-in of two pads (11 wells).
The Greater Kaybob Duvernay program (30% non-operated working interest) remains robust and the partnership is executing a jointly approved 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. Athabasca remains encouraged by continued strong production results across the volatile oil window.
At Two Creeks, two multi-well pads were recently brought on-stream with strong initial rates and high quality liquids (~41⁰API). 16-29-64-16-W5 (two well pad) had an IP30 of ~750 bbl/d and an IP60 of ~725 bbl/d per well. 5-19-64-16W5 (two well pad) had an IP30 of ~725 bbl/d per well. The Company sees significant long term potential at Two Creeks with exposure to approximately 45,000 acres in a shallower window of the play (~2,700m vertical depth) which is expected to drive lower well costs. The partnership recently completed a strategic land swap with an industry major, capturing 31 sections of consolidated acreage between Kaybob East and Two Creeks in exchange for nine non-core sections.
At Kaybob West, a significant northern step-out 16-25-65-20W5 had a facility restricted IP30 of ~800 bbl/d with an IP120 of ~700 bbl/d.
At Simonette, a three well pad 8-3-64-24W5 was recently tied into third party infrastructure. The first two wells had an average IP14 of ~2,050 boe/d (91% liquids) per well and the third well is expected to be placed on production during Q3 2019.
By the end of this year 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 the partnership will be in a position to high-grade development opportunities thereafter. Athabasca remains protected into 2020 with a current capital carry balance of $53.6 million ($238 million gross expenditures).
Q2 2019 production averaged 23,748 bbl/d. Production was impacted by facility maintenance activities and recovery from curtailed production in Q4 2018 and Q1 2019 as a response to the unprecedented WCS differential environment (~1,000 bbl/d impact to annual average). As such, the Company anticipates Thermal Oil production to trend on the lower end of its annual guidance.
The division generated operating income of $56.5 million with a record operating netback of $26.97/bbl ($31.07/bbl at Leismer and $18.04/bbl at Hangingstone). The Company’s realized bitumen price averaged $55.58/bbl, supported by a US$10.67 WCS differential during the quarter and lower seasonal blending requirements. Capital expenditures for the quarter were $21.9 million.
At Leismer, Athabasca rig released the L7 sustaining pad earlier in the year. 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 Company commenced well pair circulation in June with first production expected in Q4 2019. The upcoming winter program will include completion of a steam debottleneck project, expansion of non-condensable gas co-injection across the field and long lead initiatives aimed at maintaining base production.
Risk Management and Balance Sheet
Athabasca has protected a base level of capital activity through its risk management program while maintaining cash flow upside to the current pricing environment. For H2 2019, the Company has hedged 14,000 bbl/d of apportionment protected volumes with a WCS floor price of ~C$52.50 and an additional 2,000 bbl/d of WCS differentials at ~US$20. The Company has also secured 8,000 bbl/d of direct refinery sales for 2020. 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 through the fall.
The Company has access to 130,000 bbl of storage at Edmonton to manage and optimize product sales. Athabasca has secured long term egress to multiple end markets with 25,000 bbl/d of capacity on TC Energy Keystone XL and 20,000 bbl/d of capacity on the Trans Mountain Expansion Project.
Athabasca maintains a strong financial position with liquidity of $424 million (cash and available credit facilities) and a Duvernay capital carry balance of $53.6 million. The Company’s term debt is in place until 2022 with no maintenance covenant and the $120 million undrawn reserve based credit facility was recently reaffirmed by the banking syndicate.
Outlook and Drive to Free Cash Flow
Athabasca’s 2019 capital guidance of ~$135 million is focused on sustaining production for 2020. The Company maintains a low annual sustaining capital advantage of ~$9.50/boe. Balanced H2 2019 activity includes drilling a four well Montney pad at Placid, drilling 13 Duvernay wells, a steam debottleneck project and NCG co-injection expansion at Leismer. Annual adjusted funds flow is forecast at $155 million (US$60 WTI & US$17.50 WCS differential for the balance of 2019). The Company has flexibility to direct sustainable free cash flow to debt reduction, share buy backs or capital projects.
|2019 Guidance||Full Year|
|Production (boe/d)||37,500 – 40,000|
|Capital Expenditures ($MM)||$135|
|LIGHT OIL (net)|
|Production (boe/d)||10,000 – 11,000|
|Capital Expenditures ($MM)||$35|
|THERMAL OIL (net)|
|Production (bbl/d)||27,500 – 29,000|
|Capital Expenditures ($MM)||$100|
|ADJUSTED FUNDS FLOW SENSITIVITY1 ($MM)|
|US$60 WTI / US$17.50 WCS diff||$155|
|US$65 WTI / US$17.50 WCS diff||$175|
|1)||Funds flow sensitivity includes H1 2019 actuals, current hedging and flat pricing assumptions for the remainder of 2019 (US$10 MSW differential, US$5 C5 differential, C$1.50 AECO, 0.75 C$/US$ FX).|
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:
Vice President, Capital Markets and Communications
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", “Net Debt” 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 Q2 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.
Net debt is defined as face value of term debt plus current liabilities (adjusted for risk management contracts) less current assets (adjusted for risk management contracts).