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Athabasca Oil Corporation Announces Q3 2020 Results

Athabasca Oil Corporation
·17 min read

CALGARY, Alberta, Nov. 04, 2020 (GLOBE NEWSWIRE) -- Athabasca Oil Corporation (TSX: ATH) (“Athabasca” or the “Company”) reported its operating and consolidated financial results for the three months ending September 30, 2020.

The third quarter demonstrated the significance of Athabasca’s swift response to the COVID-19 pandemic. The Company has focused on maximizing corporate funds flow and maintaining corporate liquidity. Its Leismer asset underpinned a low corporate decline rate with significant cash flow generation. The recent improvement in commodity prices allowed the Company to successfully restart its Hangingstone asset and also implement price protection through hedges over the winter season. The Light Oil division generated strong margins and has helped insulate the Company during these periods of pricing volatility.

Q3 Operating & Financial Highlights

  • Q3 Production: 32,061 boe/d (86% liquids), including 20,231 bbl/d from Thermal Oil and 11,830 boe/d (62% liquids) from Light Oil.

  • Free Cash Flow: Adjusted funds flow of $14.6 million and capital expenditures of $12.4 million resulting in free cash flow of $2.2 million.

  • Balance Sheet: Maintained strong liquidity with $152 million of unrestricted cash.

  • Leismer: Production of 18,434 bbl/d, following voluntary price-driven curtailments in Q2. The asset generated $29 million of operating income with an operating netback of $16.46/bbl.

  • Hangingstone: Operations resumed in September, after a successful planned turnaround during curtailment, with current production of ~7,000 bbl/d. The asset will ramp up into 2021.

  • Light Oil: Industry leading operating netback of $21.43/boe. Ten new wells resumed production in July in Placid Montney. Kaybob Duvernay recent well results continue to screen as top producers with IP90s of 1,125 boe/d (84% liquids) at Kaybob East and 900 bbl/d at Two Creeks.

Outlook

  • Production Guidance. Q4 2020 guidance is maintained at 32,000 – 34,000 boe/d.

  • Capital: No changes to previous capital guidance of $85 million for 2020. The Company is preparing for the option of a winter drilling season at its Leismer asset, aimed at sustaining production and profitability. Minimal activity in Light Oil is planned for the balance of the winter.

  • Hedging: The Company has realized hedging gains of $39 million year-to-date. ~55% of Thermal Oil dilbit volumes are hedged through Q4 2020 and the Company has commenced its 2021 risk management program aimed at protecting cashflow for a minimal maintenance capital program.

Athabasca’s strong liquidity position, coupled with its low decline, long reserve life assets, positions it well to withstand the current economic environment. The Company has differentiated exposure to expanded market egress on the horizon and an ultimate recovery in commodity prices.

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 however 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 towards a partial recovery and stabilization in oil prices. Despite this, the path towards a full recovery is expected to be volatile.

In Alberta, physical markets and regional benchmark prices (e.g. Western Canadian Select “WCS” heavy oil) have strengthened with WTI prices and tighter differentials as a result of curtailed volumes and falling inventories. Alberta inventories are currently at multi-year lows and have retreated to ~20 mmbbl, down from a peak of 35 – 40 mmbbl during prior constrained periods (Genscape). Athabasca expects current WCS differentials to remain supported by muted industry growth projects, strong demand for heavy oil from US Gulf Coast refineries as they face structural declines in global heavy supply (Venezuela and Mexico) and improving basin egress (including Enbridge Line 3 replacement H2 2021).

Corporate Response to COVID-19

The Company has implemented business procedures that comply with Alberta Health Guidelines. Athabasca is committed to ensuring the health and safety of all its personnel and has successfully transitioned its office staff back to the office on a full-time basis 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 took swift action in response to the pandemic and economic crisis. Major initiatives include a reduction to the 2020 capital program, significant temporary 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.

Athabasca is well positioned to navigate the current challenging environment with $152 million in unrestricted cash. The Company remains focused on safe and reliable operations while maximizing corporate funds flow and strong liquidity. Approximately 55% of Thermal Oil dilbit volumes are hedged through Q4 2020 and the Company has commenced its 2021 risk management program aimed at protecting cashflow for a minimal maintenance capital program.

Hedging Summary¹

Q4 2020

Q1 2021

Q2 2021

Q3 2021

Q4 2021

WCS Differentials

19,900

18,000

7,500

7,500

-

Average Price

$16.92

$14.44

$11.98

$11.98

-

WTI²

17,900

11,000

-

-

-

Average Price³

~$43

~$40

-

-

-

Notes:

1. Details of hedging contracts provided in the Q3 2020 MD&A.

2. WTI hedges include a combination of fixed price swaps, collars, and 3-way contracts.

3. Average pricing reflects strip commodity pricing as at Nov. 2, 2020 and does include upside pricing potential on collar instruments.


Financial and Operational Highlights

Three months ended
September 30,

Nine months ended
September 30,

($ Thousands, unless otherwise noted)

2020

2019

2020

2019

CONSOLIDATED

Petroleum and natural gas production (boe/d)

32,061

35,257

31,896

36,126

Operating Income (Loss)(1)(2)

$

42,812

$

64,614

$

50,076

$

190,338

Operating Netback(1)(2) ($/boe)

$

14.67

$

19.10

$

5.61

$

19.24

Capital expenditures

$

12,381

$

42,664

$

94,438

$

129,345

Capital Expenditures Net of Capital-Carry(1)

$

12,381

$

35,304

$

71,698

$

93,948

LIGHT OIL DIVISION

Petroleum and natural gas production (boe/d)

11,830

10,023

9,853

10,642

Percentage liquids (%)

62

%

55

%

61

%

54

%

Operating Income (Loss)(1)

$

23,327

$

21,800

$

42,460

$

78,717

Operating Netback(1) ($/boe)

$

21.43

$

23.64

$

15.73

$

27.09

Capital expenditures

$

1,917

$

21,501

$

61,534

$

63,214

Capital Expenditures Net of Capital-Carry(1)

$

1,917

$

14,141

$

38,794

$

27,817

THERMAL OIL DIVISION

Bitumen production (bbl/d)

20,231

25,234

22,043

25,484

Operating Income (Loss)(1)

$

26,844

$

51,888

$

(30,886

)

$

153,538

Operating Netback(1) ($/bbl)

$

14.66

$

21.09

$

(4.98

)

$

21.95

Capital expenditures

$

10,454

$

21,146

$

32,872

$

66,114

CASH FLOW AND FUNDS FLOW

Cash flow from operating activities

$

(4,782

)

$

16,741

$

(38,989

)

$

59,657

per share - basic

$

(0.01

)

$

0.03

$

(0.07

)

$

0.11

Adjusted Funds Flow(1)

$

14,617

$

43,906

$

(29,480

)

$

133,282

per share - basic

$

0.03

$

0.08

$

(0.06

)

$

0.26

NET INCOME & COMPREHENSIVE INCOME (LOSS)

Net income (loss) & comprehensive income (loss)

(18,818

)

(8,265

)

(600,634

)

255,622

per share - basic

$

(0.04

)

$

(0.02

)

$

(1.14

)

$

0.49

per share - diluted

$

(0.04

)

$

(0.02

)

$

(1.14

)

$

0.49

COMMON SHARES OUTSTANDING

Weighted average shares outstanding - basic

530,675,391

523,263,183

528,220,593

520,604,599

Weighted average shares outstanding - diluted

530,675,391

523,263,183

528,220,593

525,461,794


Sept. 30,

Dec. 31,

As at ($ Thousands)

2020

2019

BALANCE SHEET

Cash and cash equivalents

$

151,730

$

254,389

Restricted cash (current and long-term)

$

150,887

$

110,609

Face value of long-term debt(3)

$

600,255

$

583,425

(1) Refer to the “Advisories and Other Guidance” section within the Company’s Q3 2020 MD&A for additional information on Non-GAAP Financial Measures.

(2) Includes realized commodity risk management loss of $7.4 million and gain of $38.5 million for the three and nine months ended September 30, 2020, respectively (three and nine months ended September 30, 2019 - $9.1 million loss and $41.9 million loss).

(3) The face value of the 2022 Notes is US$450 million. The 2022 Notes were translated into Canadian dollars at the September 30, 2020 exchange rate of US$1.00 = C$1.3339.


Operations
Update

Thermal Oil

In Q3 2020, consolidated thermal production averaged 20,231 bbl/d with $27 million of operating income. Capital expenditures of $10 million were limited to routine maintenance activity.

At Leismer, production averaged 18,434 bbl/d during the quarter. Production returned to operational capacity following voluntary curtailments in the second quarter in response to extreme low pricing. The asset’s steam oil ratio averaged 3.3x and has trended lower as a result of continued success of the non-condensable gas (NCG) co-injection across the field. A low operating expense of $10.73/bbl underpinned Leismer’s netback of $16.46/bbl. The asset has demonstrated significant cost improvements over the last year, ensuring it contributes significant cash flow to the Company. Leismer has an estimated operating breakeven of US$23/bbl WCS (assuming US$12.50/bbl differential).

At Hangingstone, operations were suspended in April 2020 due to low commodity prices. During the second and third quarter, the organization successfully completed Hangingstone’s first major scheduled plant turnaround. The Company strategically extended the duration of the turnaround to manage costs and to enhance the safety of the personnel on site in response to COVID-19. Operations resumed on September 1 with October production of approximately 7,000 bbl/d. The asset is expected to ramp-up to previous rates of 9,000 – 9,500 bbl/d over the next 12 months. In the third quarter, the Company received approval from the Alberta Energy Regulator to implement NCG co-injection at the project which is expected to provide pressure maintenance and reduce the asset’s energy intensity. To protect against future commodity price volatility the Company has hedged the Hangingstone production profile through the winter utilizing 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).

Light Oil

In Q3 2020, production averaged 11,830 boe/d (62% liquids) with $23 million of operating income ($21.43/boe netback). Capital expenditures were $2 million with minimal field activity planned in the Montney and the Duvernay for the balance of the winter season.

At Greater Placid, production resumed from 10 new Montney development wells supporting a top tier netback of $19.33/boe. Placid is positioned for flexible future development with no near-term land retention requirements.

In the Greater Kaybob Duvernay, 16 new wells have been brought on-stream year-to-date. In the oil window, production results have been consistently strong with wells screening as top liquids producers in the basin. Recent results include a two well pad at Kaybob East (15-19-64-17W5) which had an IP30 of 1,400 boe/d per well (87% liquids) and an IP90 of 1,125 boe/d per well (84% liquids), and a single well at Two Creeks (13-31-64-15W5) which had an IP30 of 1,300 bbl/d (100% liquids) and an IP90 of 900 bbl/d (100% liquids). Greater Kaybob is positioned for flexible future development with an inventory of approximately 700 locations, established infrastructure and no near-term land retention requirements. The joint development agreement (“JDA”) protects the Company’s interests and minimal activity is currently planned for the balance of 2020 and 2021. Future changes to the JDA requires approval from both parties and preserves optionality to increase spending in a more robust macro environment.

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:

Matthew Taylor
Chief Financial Officer
1-403-817-9104
mtaylor@atha.com

Reader Advisory:

This News Release contains forward-looking information that involves various risks, uncertainties and other factors. All information other than statements of historical fact is forward-looking information. The use of any of the words “anticipate”, “plan”, “continue”, “estimate”, “expect”, “may”, “will”, “project”, “believe”, “view”, ”contemplate”, “target”, “potential” and similar expressions are intended to identify forward-looking information. The forward-looking information is not historical fact, but rather is based on the Company’s current plans, objectives, goals, strategies, estimates, assumptions and projections about the Company’s industry, business and future operating and financial results. This information involves known and unknown risks, uncertainties and other factors that may cause actual results or events to differ materially from those anticipated in such forward-looking information. No assurance can be given that these expectations will prove to be correct and such forward-looking information included in this News Release should not be unduly relied upon. This information speaks only as of the date of this News Release. In particular, this News Release contains forward-looking information pertaining to, but not limited to, the following: 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 adjusting for changes in non-cash working capital, restructuring expenses and settlement of provisions from 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 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. 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 (Loss) 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. 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 (Loss) 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 2020 MD&A. These measures allow management and others to evaluate the true net cash outflow related to Athabasca's capital expenditures.
The Free Cash Flow measure in this News Release is calculated by subtracting Capital Expenditures from Adjusted Funds Flow. This measure allows management and others to evaluate Athabasca’s ability to generate funds to finance operations and capital expenditures.