CALGARY, Alberta, Aug. 01, 2018 (GLOBE NEWSWIRE) — Athabasca Oil Corporation (TSX:ATH) (“Athabasca” or the “Company”) is pleased to provide its 2018 second quarter results and an operations update.
Athabasca is a uniquely positioned low-decline, oil-weighted producer with assets in the most active resource plays in Western Canada (Montney, Duvernay and oil sands). The second quarter marks solid operations in both Light Oil and Thermal Oil with strong funds flow growth over the prior quarter.
Q2 2018 Results and Recent Operations Highlights
Consolidated – Strength in Execution and Financial Sustainability
- Production of 37,658 boe/d (84% liquids); with full-year guidance of 39,000 – 41,000 boe/d
- Operating income of $70.6 million (excluding hedging); adjusted funds flow of $25.7 million ($0.05/sh)
- Capital expenditures of $38.9 million ($10.3 million Light Oil and $28.6 million Thermal Oil)
- Funding capacity of ~$275 million (includes cash, available credit facilities and Duvernay capital carry)
Light Oil – High Margin Liquids Rich Growth
- Q2 production of 11,872 boe/d (48% liquids), representing 64% growth year over year
- Operating income of $30.9 million and top tier netbacks of $28.64/boe
- Placid Montney: six well pad rig released in May with completions to commence in August
- Kaybob Duvernay: strong well results with IP30s averaging ~1,000 boe/d (73% liquids) for the latest 14 wells; C$8.2 million pacesetter pad drill and complete costs (C$7.6 million pacesetter well)
Thermal Oil – Low Decline Production
- Q2 production of 25,786 bbl/d, reflecting ~4,000 bbl/d of downtime for a turnaround at Leismer
- Operating income of $39.6 million ($29.5 million from Leismer and $10.1 million from Hangingstone)
- Free cash flow of $11 million despite $15 million of one-time turnaround costs
- Norlite diluent sourcing tied-in with anticipated annual savings of ~$20 million
2018 Outlook – Continued High Return Activity
- $45 million budget expansion includes a one rig program at Placid and completions of a six well pad
- $185 million corporate capital budget; $165 million funds flow (US$68 WTI & US$21 WCS differential)
- ~$300 million annualized H2 2018 funds flow
Athabasca’s focus remains on margin growth and financial sustainability. The Company offers investors excellent exposure to improving oil prices with low total leverage and unhedged funds flow sensitivity of approximately $80 million for each incremental US$5/bbl increase in WTI.
Financial and Operational Highlights
|3 months ended June 30
||6 months ended June 30|
|($ Thousands, unless otherwise noted)||2018||2017
|Petroleum and Natural Gas Volumes (boe/d)||37,658||36,574||39,107||31,683|
|Operating Netback1,2 ($/boe)||$||13.01||$||13.28||$||8.80||$||11.05|
|Capital Expenditures Net of Capital-Carry1,3||$||38,888||$||32,181||$||95,549||$||111,624|
|LIGHT OIL DIVISION|
|Oil, Condensate and NGLs (bbl/d)||5,740||4,071||5,493||3,022|
|Natural Gas (mcf/d)||36,792||19,056||34,166||13,936|
|Petroleum and Natural Gas Volumes (boe/d)||11,872||7,246||11,187||5,344|
|Operating Netback1 ($/boe)||$||28.64||$||24.85||$||27.27||$||24.04|
|Capital Expenditures Net of Capital-Carry1,3||$||10,286||$||17,568||$||51,316||$||84,534|
|THERMAL OIL DIVISION|
|Bitumen Production (bbl/d)||25,786||29,328||27,920||26,339|
|Operating Netback1 ($/bbl)||$||15.79||$||10.11||$||6.33||$||7.76|
|CASH FLOW AND FUNDS FLOW|
|Cash Flow from Operating Activities||$||27,605||$||28,049||$||24,364||$||(24,851)|
|per share (basic)||$||0.05||$||0.06||$||0.05||$||(0.05)|
|Adjusted Funds Flow1||$||25,680||$||27,567||$||19,320||$||25,915|
|per share (basic)||$||0.05||$||0.05||$||0.04||$||0.05|
|NET INCOME (LOSS) AND COMPREHENSIVE INCOME (LOSS)|
|Net Income (Loss) and Comprehensive Income (Loss)||$||(19,267)||$||24,233||$||(112,597)||$||(4,932)|
|per share (basic and diluted)||$||(0.04)||$||0.05||$||(0.22)||$||(0.01)|
|COMMON SHARES OUTSTANDING|
|Weighted Average Shares Outstanding (basic)||514,679,681||508,655,464||512,448,170||490,492,488|
|Weighted Average Shares Outstanding (diluted)||514,679,681||514,174,746||512,448,170||490,492,488|
|As at ($ Thousands)||June 30,
|LIQUIDITY AND BALANCE SHEET|
|Cash and Cash Equivalents||$||93,293||$||163,321|
|Available Credit Facilities||$||59,991||$||61,899|
|Capital-Carry Receivable (current & LT portion – discounted)||$||123,152||$||164,023|
|Face Value of Long-term Debt4||$||591,390||$||563,310|
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 $(23.9) million and $(24.5) million for the three and six months ended June 30, 2018, respectively ($0.7 million and $3.0 million for the three and six months ended June 30, 2017, respectively).
3) Capital expenditures include capitalized G&A.
4) The face value of the 2022 Notes is US$450 million. As at June 30, 2018, the 2022 Notes were translated into Canadian dollars at the period end exchange rate of US$1.00=C$1.3142.
The global outlook for crude oil continues to strengthen and Athabasca is a significant beneficiary with its oil-weighted portfolio. Q2 2018 WTI prices have improved by approximately 40% compared to the prior year supporting strong financial performance in both Light Oil and Thermal Oil.
Despite the strong global crude outlook, Canadian producers continue to experience heavy oil differential and basis spread volatility due to pipeline capacity constraints. Western Canadian Select (“WCS”) differentials have, however, improved significantly relative to Q1 2018 and averaged US$19.24/bbl in Q2 2018. The improved differential further supported Athabasca’s strong Thermal Oil financial performance in the quarter. Athabasca continues to optimize netback performance by mitigating apportionment with sales to refineries (70% in Q2) and through access to leased storage in Edmonton.
The Company anticipates WCS differentials to normalize to below US$20/bbl over the mid-term supported by the mobilization of industry rail, strong demand for heavy feedstock from PADD II/III refiners and the start-up of Northwest Refining’s Alberta based Sturgeon Refinery (80,000 bbl/d). The Company has secured WCS differential hedges of approximately 17,000 bbl/d in Q3 2018 at US$16.17/bbl. Athabasca’s commodity hedging program targets up to 50% of near term production with a focus on minimizing the impact of differentials through financial hedges and physical sales.
Recent developments around heavy oil pipeline projects have also been positive and are expected to support long term WCS differentials in the low teens as additional pipeline capacity becomes operational. Athabasca has secured long term egress to multiple end markets and recently its increased capacity on TransCanada Keystone XL to 25,000 bbl/d. The Company also has 20,000 bbl/d of capacity on the Trans Mountain Expansion Project.
The Company is a net consumer of gas and is a beneficiary of the current low Alberta gas pricing environment.
Athabasca’s outlook and financial sustainability are underpinned by high margin Light Oil growth, low break-even costs at Leismer, established capital discipline, and prudent balance sheet management.
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.
Athabasca is an intermediate producer with strong and competitive investment opportunities across its portfolio in the current operating environment. The Company has tremendous leverage to oil prices and is focused on maximizing profitability through measured activity in Light Oil and ongoing Thermal Oil optimization. The strategy is guided by:
- Light Oil (Montney and Duvernay): Defined and Material Margin Growth
- Thermal Oil: Low Decline, Long-Life, Free Cash Flow Generating Assets
- Financial Sustainability: Increasing Margins, Flexible Capital, Strong Liquidity
The Company’s strategy is intended to ensure both its Light Oil and Thermal Oil businesses are financially robust and competitive, with exceptional growth potential. The Company will continue its strategic emphasis on generating strong oil-weighted margins and significant free cash flow to maximize shareholder returns and provide strategic optionality into the future.
Q2 2018 production averaged 11,872 boe/d (48% liquids), representing 64% growth year over year. Light Oil generated second quarter operating income of $30.9 million with a netback of $28.64/boe, supported by a high liquids weighting and low operating costs of $9.40/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 $10.3 million (net of capital carry) on Montney and Duvernay activity during the quarter.
Athabasca has increased its Light Oil capital budget by $45 million to $115 million to continue activity in the Montney at Placid. The expanded program will support production and cash flow growth in early 2019. The Company forecasts 2018 Light Oil production of 10,500 – 11,500 boe/d, operating income of approximately $130 million and free cash flow of $15 million (US$68 WTI and C$1.50 AECO).
Greater Placid Montney (70% operated working interest)
Athabasca’s Montney program has continued to demonstrate strong results with compelling economics. Over the last two years, the Company has drilled 24 wells with IP90s averaging 830 boe/d (57% liquids) and IP180s averaging 815 boe/d (52% liquids). The high free liquid content of these wells, low operating costs due to operated infrastructure and high quality product has resulted in industry leading netbacks over the last three quarters. Placid produced 8,641 boe/d in Q2 2018 (12,344 boe/d gross). Individual well payouts are approximately 14 months at US$65 WTI and the Company maintains a flexible capital program.
Completions operations will commence on a six well development pad (surface location 12-19-60-23W5 Pod 3) in August with on-stream timing before year-end. The Company will spud an additional six well pad (surface location 16-30-60-23W5 Pod 2) this fall and will commence construction on another multi-well pad site. Completions on the 16-30 pad are expected in Q1 2019.
Placid is positioned with an inventory of over 200 high graded locations and egress in place to support multi-year development. A continuous single rig program can drill 15 wells per year and would drive modest production growth of approximately 15% annually. Athabasca has operational flexibility to run up to three rigs at Placid.
Greater Kaybob Duvernay (30% non-operated working interest)
Activity in the Duvernay remains robust with the joint venture executing an annual budget of C$387 million (C$30 million net) including completion operations on 29 wells and placing 28 wells on production. The Duvernay is expected to contribute strong production and cash flow growth into year-end.
Operations are focused on development drilling at Kaybob West and ongoing volatile oil delineation across Athabasca’s extensive acreage positon. The joint venture has seen a material step change in drilling and completion performance with the latest pacesetter pad averaging C$8.2 million per well (C$7.6 million pacesetter well) at Kaybob West. Coupled with strong initial production results in this area the Duvernay is quickly transitioning to development with competitive economics relative to other top North American shale plays.
Recent results include a three well liquid-rich pad at Saxon with restricted IP30s averaging 1,325 boe/d per well (57% liquids) and a four well pad at Kaybob West in the volatile oil window with initial rates averaging 700 boe/d per well (82% liquids). IP30s on the latest 14 wells have averaged 1,000 boe/d (73% liquids).
Q2 2018 production averaged 25,786 bbl/d and reflected approximately 4,000 bbl/d of budgeted downtime related to the Leismer turnaround. Volumes have since returned to pre-turnaround levels.
Thermal Oil generated second quarter operating income of $39.6 million with a netback of $15.79/bbl, of which Leismer and Hangingstone accounted for $29.5 million and $10.1 million respectively. Financial results improved significantly quarter over quarter due to higher crude oil prices and the narrowing of WCS differentials. Athabasca’s realized bitumen price improved to $38.46/bbl in Q2 2018, up 126% from Q1 2018.
Capital expenditures in the second quarter were $28.6 million and included $15 million on Leismer turnaround activities. The Norlite diluent tie-in at Leismer is now operational and is expected to lower fixed costs by approximately $20 million annually, improving margins and further enhancing the project’s low cost operating structure. The Company has also tied-in four pre-drilled infill wells at Leismer that are expected to be brought on-stream in the third quarter.
The Company forecasts 2018 annual Thermal Oil production of 28,500 – 29,500 bbl/d, operating income of $165 million and free cash flow of $95 million (US$68 WTI and US$21 WCS differential).
Athabasca has increased its 2018 capital budget by $45 million to reflect continued activity in the Montney at Placid through H2 2018. The revised $185 million corporate capital budget includes $70 million in Thermal Oil and $115 million in Light Oil ($85 million Placid Montney and $30 million net Kaybob Duvernay). Corporate production guidance is 39,000 – 41,000 boe/d (87% liquids).
Adjusted funds flow guidance has been increased to $165 million (from $145 million) primarily on underlying commodity prices (US$68 WTI and US$21 WCS differential), with annualized H2 2018 funds flow estimated at $300 million.
Athabasca offers investors excellent exposure to improving oil prices with low total leverage and unhedged funds flow sensitivity of approximately $80 million for each incremental US$5/bbl increase in WTI.
Athabasca maintains a strong financial position with funding capacity of approximately $275 million, including cash, available credit facilities and the Duvernay capital carry balance.
|2018 Guidance||Full Year|
|Production (boe/d)||39,000 – 41,000|
|Liquids Weighting (%)||~87%|
|Adjusted Funds Flow ($MM)||$165|
|H2 2018 Funds Flow Annualized ($MM)||~$300|
|Operating Income ($MM)||$295|
|LIGHT OIL (net)|
|Production (boe/d)||10,500 – 11,500|
|Operating Income ($MM)||$130|
|Capital Expenditures ($MM)||$115|
|Bitumen Production (bbl/d)||28,500 – 29,500|
|Operating Income ($MM)||$165|
|Capital Expenditures ($MM)||$70|
|WCS Differential (US$/bbl)||$21|
|AECO Gas (C$/mcf)||$1.50|
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 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 August 1, 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.
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 (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. 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 and 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 and 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 and 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 2018 MD&A. These measures allow management and others to evaluate the true net cash outflow related to Athabasca’s capital expenditures.