CALGARY, Alberta – Baytex Energy Corp. (“Baytex”)(TSX: BTE, NYSE: BTE.BC) reports its operating and financial results for the three and nine months ended September 30, 2020 (all amounts are in Canadian dollars unless otherwise noted).
“We have made tremendous progress to re-set our business in the face of extremely volatile crude oil markets. Our third quarter results demonstrate the success of our actions as we generated free cash flow of $60 million and increased financial liquidity to $344 million. I am also especially pleased with our response to the Covid pandemic with intensified efforts to improve all aspects of our cost structure and capital efficiencies, while protecting the health and safety of our personnel,” commented Ed LaFehr, President and Chief Executive Officer.
Q3 2020 Highlights
- Generated production of 77,814 boe/d (82% oil and NGL) in Q3/2020 and 82,907 boe/d (82% oil and NGL) for the first nine months of 2020.
- Delivered adjusted funds flow of $79 million ($0.14 per basic share) in Q3/2020 and $229 million ($0.41 per basic share) for the first nine months of 2020.
- Generated free cash flow of $60 million ($0.11 per basic share) in Q3/2020 and $16 million ($0.03 per basic share) for the first nine months of 2020.
- Realized an operating netback of $17.05/boe in Q3/2020, up from $5.96/boe in Q2/2020.
- Reduced net debt by $89 million during the third quarter through a combination of free cash flow and the Canadian dollar strengthening relative to the U.S. dollar.
- Maintained undrawn credit capacity of $426 million and liquidity, net of working capital, of $344 million.
2020 Outlook and Revised Guidance
We have responded aggressively to the downturn brought on by Covid-19 as we minimize capital spending, identify cost savings and maintain our liquidity.
We expect production to average approximately 80,000 boe/d, which represents the mid-point of our guidance range of 78,000 to 82,000 boe/d. Annual capital spending is forecast to be $260 to $290 million, an approximate 50% reduction from our original plan of $500 to $575 million.
We are also reducing our full-year 2020 operating expense guidance by 7% (at the mid-point) to $11.20 to $11.40/boe. We remain intensely focused on driving further efficiencies to capture and sustain cost reductions identified during this downturn, while protecting the health and safety of our personnel.
After two quarters of little to no capital spending in Canada, we have resumed drilling activity during the fourth quarter. We have mobilized two drilling rigs to execute a 30-well drilling program in the Viking and completed two Duvernay wells drilled earlier this year. In addition, with the increase in natural gas prices, we have identified opportunities in west-central Alberta at Pembina O’Chiese to drill natural gas wells with strong economics and capital efficiencies and have two wells planned for this winter.
The following table summarizes our updated 2020 guidance. We are in the process of setting our 2021 capital budget, the details of which are expected to be released in December following approval by our Board of Directors.
|2020 Guidance (1)||2020 Revised Guidance|
|Exploration and development expenditures||$260 – $290 million||no change|
|Production (boe/d)||78,000 – 82,000||~ 80,000|
|Royalty rate||~ 18.5%||~ 18%|
|Operating||$11.75 – $12.50/boe||$11.20 – $11.40/boe|
|Transportation||$0.95 – $1.05/boe||no change|
|General and administrative||$38 million ($1.30/boe)||no change|
|Interest||$112 million ($3.84/boe)||$108 million ($3.70/boe)|
|Leasing expenditures||$7 million||$6 million|
|Asset retirement obligations||$10 million||$8 million|
(1) As announced on June 25, 2020
During the third quarter we began to benefit from our actions to reduce capital, capture cost savings and maintain liquidity. We generated free cash flow of $60 million during the quarter and $16 million through the first nine months of this year and also increased our financial liquidity to $344 million.
The following table summarizes the important measures we have undertaken to position us for success as markets recover.
|Negotiated bank credit facility extension and refinanced long-term notes||
|Dynamic response to oil price collapse||
|High graded portfolio and economic inventory||
|Established Covid-19 task force and flexible working team||
|Three Months Ended||Nine Months Ended|
(thousands of Canadian dollars, except per common share amounts)
|Petroleum and natural gas sales||$||252,538||$||152,689||$||424,600||$||741,841||$||1,360,024|
|Adjusted funds flow (1)||78,508||17,887||213,379||229,330
|Per share – basic||0.14||0.03||0.38||0.41
|Per share – diluted||0.14||0.03||0.38||0.41
|Net income (loss)||(23,444||)||(138,463||)||15,151||(2,660,124
|Per share – basic||(0.04||)||(0.25||)||0.03||(4.75
|Per share – diluted||(0.04||)||(0.25||)||0.03||(4.75
|Exploration and development expenditures (1)||$||15,902||$||9,852||$||139,085||$||202,531||$||399,174|
|Acquisitions, net of divestitures||(98||)||(11||)||(30||)||(149||)||1,617|
|Total oil and natural gas capital expenditures||$||15,804||$||9,841||$||139,055||$||202,382||$||400,791|
|Credit facilities (2)||$||624,826||$||704,135||$||570,792||$||624,826||$||570,792|
|Long-term notes (2)||1,199,160||1,225,395||1,359,480||1,199,160||1,359,480|
|Working capital deficiency||82,093||65,423||41,067||82,093||41,067|
|Net debt (1)||$||1,906,079||$||1,994,953||$||1,971,339||$||1,906,079||$||1,971,339|
|Shares Outstanding – basic (thousands)|
|End of period||561,163||560,545||557,972||561,163||557,972|
|MEH oil (US$/bbl)||41.63||26.40||61.07||39.19||62.63|
|MEH oil differential to WTI (US$/bbl)||0.70||(1.45||)||4.62||0.87||5.57|
|Edmonton par ($/bbl)||49.83||29.85||68.41||43.70||69.59|
|Edmonton par differential to WTI (US$/bbl)||(3.51||)||(6.31||)||(4.66||)||(6.04||)||(4.70||)|
|WCS heavy oil ($/bbl)||42.40||22.70||58.39||33.34||60.24|
|WCS differential to WTI (US$/bbl)||(9.09||)||(11.47||)||(12.24||)||(13.70||)||(11.74||)|
|CAD/USD average exchange rate||1.3316||1.3860||1.3207||1.3541||1.3292|
|Three Months Ended||Nine Months Ended|
|Light oil and condensate (bbl/d)||34,101||38,951||42,829||39,570||43,479|
|Heavy oil (bbl/d)||22,138||11,832||25,712||20,946||26,637|
|Total liquids (bbl/d)||63,656||58,417||78,084||68,140||80,861|
|Natural gas (mcf/d)||84,945||84,546||101,054||88,602||103,587|
|Oil equivalent (boe/d @ 6:1) (3)||77,814||72,508||94,927||82,907||98,125|
|Netback (thousands of Canadian dollars)|
|Total sales, net of blending and other expense (4)||$||241,865||$||147,229||$||411,650||$||704,351||$||1,309,396|
|Operating netback (1)||$||121,994||$||39,362||$||229,353||$||305,081||$||733,192|
|General and administrative||(7,741||)||(7,438||)||(9,934||)||(24,954||)||(35,576||)|
|Cash financing and interest||(25,418||)||(27,387||)||(26,752||)||(81,340||)||(83,028||)|
|Realized financial derivatives gain (loss)||(9,743||)||13,624||20,857||30,731||52,664|
|Adjusted funds flow (1)||$||78,508||$||17,887||$||213,379||$||229,330||$||670,279|
|Netback (per boe)|
|Total sales, net of blending and other expense (4)||$||33.79||$||22.31||$||47.14||$||31.01||$||48.88|
|Operating netback (1)||$||17.05||$||5.96||$||26.27||$||13.43||$||27.37|
|General and administrative||(1.08||)||(1.13||)||(1.14||)||(1.10||)||(1.33||)|
|Cash financing and interest||(3.55||)||(4.15||)||(3.06||)||(3.58||)||(3.10||)|
|Realized financial derivatives gain (loss)||(1.36||)||2.06||2.39||1.35||1.97|
|Adjusted funds flow (1)||$||10.97||$||2.71||$||24.43||$||10.10||$||25.02|
- The terms “adjusted funds flow”, “exploration and development expenditures”, “net debt” and “operating netback” do not have any standardized meaning as prescribed by Canadian Generally Accepted Accounting Principles (“GAAP”) and therefore may not be comparable to similar measures presented by other companies where similar terminology is used. See the advisory on non-GAAP measures at the end of this press release.
- Principal amount of instruments. The carrying amount of debt issue costs associated with the credit facilities and long-term notes are excluded on the basis that these amounts have been paid by Baytex and do not represent an additional source of capital or repayment obligations.
- Barrel of oil equivalent (“boe”) amounts have been calculated using a conversion rate of six thousand cubic feet of natural gas to one barrel of oil. The use of boe amounts 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 is based on an energy equivalency conversion method primarily applicable at the burner tip and does not represent a value equivalency at the wellhead.
- Realized heavy oil prices are calculated based on sales dollars, net of blending and other expense. We include the cost of blending diluent in our realized heavy oil sales price in order to compare the realized pricing on our produced volumes to the WCS benchmark.
- Other is comprised of realized foreign exchange gain or loss, other income or expense, current income tax expense or recovery and share-based compensation. Refer to the Q3/2020 MD&A for further information on these amounts.
Production during the third quarter averaged 77,814 boe/d (82% oil and NGL), as compared to 72,508 boe/d (81% oil and NGL) in Q2/2020. The higher production reflects the re-start of previously shut-in volumes in Canada, partially offset by lower activity in the Viking and Eagle Ford. Our third quarter production was reduced by approximately 5,000 boe/d due to voluntary shut-ins. Exploration and development spending totaled a modest $16 million during the third quarter.
We delivered adjusted funds flow of $79 million ($0.14 per basic share) in Q3/2020 and generated an operating netback of $17.05/boe ($15.69/boe inclusive of realized financial derivatives loss). The Eagle Ford generated an operating netback of $18.99/boe and our Canadian operations generated an operating netback of $15.90/boe.
We continue to emphasize cost reductions across all facets of our organization. Through the first nine months of 2020 our team has driven operating costs down to $11.08/boe, despite lower production volumes. This compares favorably to our guidance range of $11.75 to $12.50/boe. As a result, we are reducing our full-year 2020 operating expense guidance by 7% (at the mid-point) to $11.20 to $11.40/boe.
Eagle Ford and Viking Light Oil
Production in the Eagle Ford averaged 28,650 boe/d (77% oil and NGL) during Q3/2020, as compared to 34,817 boe/d in Q2/2020. The lower volumes reflect reduced completion activity as we adjusted our development plan in response to volatile commodity prices. We commenced production from six (0.8 net) wells during the third quarter, as compared to 47 (10.7 net) in the first half of 2020. Activity in the Eagle Ford has recently resumed and we have 0.75 net drilling rigs and 0.5 net frac crews running on our lands. We expect to bring approximately 16 net wells on production in the Eagle Ford in 2020.
Production in the Viking averaged 18,774 boe/d (91% oil and NGL) during Q3/2020, as compared to 19,717 boe/d in Q2/2020. We had previously suspended all drilling in the Viking, and as such, there was limited activity during the third quarter. In the first nine months of 2020, we invested $77 million on exploration and development in the Viking and commenced production from 83
(78.5 net) wells. After two quarters of minimal capital spend, we have resumed drilling activity in the Viking with two drillings rigs mobilized to execute a 30-well drilling program during the fourth quarter.
Our heavy oil assets at Peace River and Lloydminster produced a combined 24,791 boe/d (89% oil and NGL) during the third quarter, as compared to 13,082 boe/d in Q2/2020. The increased production reflects the re-start of previously shut-in production as operating netbacks improved. The quarterly impact of voluntary shut-ins for heavy oil was approximately 5,000 boe/d, down from 17,000 boe/d in Q2/2020. We currently have approximately 2,000 boe/d of heavy oil production shut-in. We had previously suspended all heavy oil drilling, and as such, there was limited activity during the third quarter. In the first nine month of 2020, we invested $41 million on exploration and development and drilled 33 (33.0 net) wells.
Pembina Area Duvernay Light Oil
Production in the Pembina Duvernay averaged 1,474 boe/d (79% oil and NGL) during Q3/2020, as compared to 717 boe/d in Q2/2020. The increased production during the third quarter reflects the re-start of previously shut-in production as operating netbacks improved.
In Q1/2020, we drilled two wells in the core of our Pembina acreage, bringing total wells drilled to nine in this area. These two wells were fracture stimulated in October using a “plug and perf” system with fracture diversion technology. The wells are scheduled to be placed on production in November. The two wells confirm visibility to a $7.0 million well cost in a full development scenario. The success of our drilling program in the Pembina area has significantly de-risked our approximately 38-kilometre long acreage fairway, where we hold 232 sections (100% working interest) of Duvernay land.
Our credit facilities total approximately $1.07 billion and have a maturity date of April 2, 2024. These are not borrowing base facilities and do not require annual or semi-annual reviews. As of September 30, 2020, we had $426 million of undrawn capacity on our credit facilities, resulting in liquidity, net of working capital, of $344 million. In addition, our first long-term note maturity of US$400 million is not until June 2024.
Our net debt, which includes our credit facilities, long-term notes and working capital, totaled $1.9 billion at September 30, 2020, down from $2.0 billion at June 30, 2020. Based on the forward strip, we expect to maintain our financial liquidity and remain onside with our financial covenants.
The following table summarizes the financial covenants applicable to the credit facilities and Baytex’s compliance therewith as at September 30, 2020.
|Covenant Description||Position as at
September 30, 2020
|Senior Secured Debt(1) to Bank EBITDA(2) (Maximum Ratio)||1.1:1.0||3.5:1.0|
|Interest Coverage(3) (Minimum Ratio)||5.4:1.0||2.0:1.0|
- Senior Secured Debt is defined as the principal amount of the credit facilities and other secured obligations identified in the credit agreement. As at September 30, 2020, the Company’s Senior Secured Debt totaled $640.3 million which includes $624.8 million of principal amounts outstanding and $15.5 million of letters of credit.
- Bank EBITDA is calculated based on terms and definitions set out in the credit agreement which adjusts net income or loss for financing and interest expense, income tax, non-recurring losses, certain specific unrealized and non-cash transactions (including depletion, depreciation, exploration and evaluation expense, impairment, deferred income tax expense or recovery, unrealized gains and losses on financial derivatives and foreign exchange and share-based compensation) and is calculated based on a trailing twelve month basis including the impact of material acquisitions as if they had occurred at the beginning of the twelve month period. Bank EBITDA for the twelve months ended September 30, 2020 was $566.1 million.
- Interest coverage is computed as the ratio of Bank EBITDA to financing and interest expense, excluding accretion of debt issue costs and asset retirement obligations, and is calculated on a trailing twelve month basis. Financing and interest expense, excluding accretion of debt issue costs and asset retirement obligations, for the twelve months ended September 30, 2020 was $105.2 million.
To manage commodity price movements, we utilize various financial derivative contracts and crude-by-rail to reduce the volatility of our adjusted funds flow. The following table summarizes our crude oil hedges in place.
|WTI Fixed Hedges|
|Fixed Price (US$/bbl)||$||42.78||—|
|WTI 3-Way Option (1)|
|Baytex Receives (2) (3) (4)||WTI plus US$7.60||US$45|
|Total Volumes (bbl/d)||32,500||13,500|
- WTI 3-way options consist of a sold put, a bought put and a sold call. Baytex’s average sold put, bought put and sold call for Q4/2020 are US$50.44/bbl, US$58.04/bbl and US$63.06/bbl, respectively. Baytex’s average sold put, bought put and sold call for 2021 are US$35/bbl, US$45/bbl and US$53.57/bbl, respectively.
- For Q4/2020, Baytex receives WTI plus US$7.60/bbl when WTI is at or below US$50.44/bbl; Baytex receives US$58.04/bbl when WTI is between US$50.44/bbl and US$58.04/bbl; Baytex receives WTI when WTI is between US$58.04/bbl and US$63.06/bbl; and Baytex receives US$63.06/bbl when WTI is above US$63.06/bbl.
- For 2021, Baytex receives WTI plus US$10/bbl when WTI is at or below US$35/bbl; Baytex receives US$45/bbl when WTI is between US$35/bbl and US$45/bbl; Baytex receives WTI when WTI is between US$45/bbl and US$53.57; and Baytex receives US$53.57/bbl when WTI is above US$53.57/bbl.
- Based on the forward strip for the balance of 2020, Baytex will receive WTI plus US$7.60/bbl. Based on the forward strip for 2021, Baytex will receive US$45/bbl.
For Q4/2020, we also have WTI-MSW basis differential swaps for 5,000 bbl/d of our light oil production in Canada at US$6.15/bbl and WCS differential hedges on 6,500 bbl/d at a WTI-WCS differential of US$16.27/bbl.
We also have WTI-MSW differential hedges on approximately 40% of our expected 2021 Canadian light oil production at US$5.17/bbl and WCS differential hedges on approximately 45% of our expected 2021 heavy oil production at a WTI-WCS differential of approximately US$13.50/bbl.
A complete listing of our financial derivative contracts can be found in Note 17 to our Q3/2020 financial statements.
The Board of Directors is pleased to announce the appointment of Steve Reynish as a director of Baytex.
“We are very pleased that Steve has joined the Baytex board. His strategic perspective and tremendous breadth of experience across technology, ESG, marketing, and corporate development will serve the board and Baytex well in the years ahead,” commented Mark Bly, Chairman of Baytex.
Mr. Reynish is currently the President and Chief Executive Officer of Enlighten Innovations, a private Calgary based clean energy technology organization which he joined in 2020. Immediately prior to Enlighten Mr. Reynish served as an Executive Vice President at Suncor Energy Inc. for eight years in a variety of capacities where he was accountable for the company’s strategy, ESG and corporate development initiatives, new technology development, joint venture and commercial portfolios – all instrumental in positioning Suncor as a top-tier Western Canadian based integrated energy company. Prior to Suncor, Mr. Reynish served as President of Marathon Oil Canada, which he joined through the acquisition of Western Oil Sands where he was Executive Vice President, Operations. Prior to his entry into Canada, he held senior positions within the Anglo American Group, including Vice President of Mining of Anglo Base Metals in Johannesburg and Chief Executive Officer of Bindura Nickel in Zimbabwe. Mr. Reynish holds a Masters degree in Mining Engineering and an MBA, both earned in the UK. He has completed Post Graduate studies at IMD and the Wharton School. He is a member of the board of Energy Safety Canada, the Institute of Corporate Directors (ICD) and National Association of Corporate Directors (NCAD), and a former Member of the Board of Governors of the Oxford Institute of Energy Studies, the Canadian Associated of Petroleum Produces (CAPP) and the Canada Institute.
On March 24, 2020 we received notice from the New York Stock Exchange (“NYSE”) that Baytex was no longer in compliance with one of the NYSE’s continued listing standards because the average closing price of Baytex’s common shares was less than US$1.00 per share over a consecutive 30 trading period. At this time, Baytex has not regained compliance and expects that its common shares will be delisted from the NYSE on December 3, 2020. This will not affect Baytex’s business operations and will not affect the continued listing and trading of Baytex’s common shares on the Toronto Stock Exchange. Currently, over 80% of the daily trading in Baytex common shares occurs in Canada, ensuring investors will retain significant trading liquidity going forward. In addition, Baytex expects to realize significant cost savings over time as a result of the delisting.
Baytex is formally terminating its dividend reinvestment plan (“DRIP”). All participants (as defined in the DRIP) effective as of the termination date, will be issued a certificate for any common shares and a cheque for any cash balance remaining in the participants’ account pursuant to the terms of the plan.
Our condensed consolidated interim unaudited financial statements for the three and nine months ended September 30, 2020 and the related Management’s Discussion and Analysis of the operating and financial results can be accessed on our website at www.baytexenergy.com and will be available shortly through SEDAR at www.sedar.com and EDGAR at www.sec.gov/edgar.shtml.
|Conference Call Tomorrow
9:00 a.m. MST (11:00 a.m. EST)
|Baytex will host a conference call tomorrow, November 3, 2020, starting at 9:00am MST (11:00am EST). To participate, please dial toll free in North America 1-800-319-4610 or international 1-416-915-3239. Alternatively, to listen to the conference call online, please enter http://services.choruscall.ca/links/baytexq320201103.html in your web browser.
An archived recording of the conference call will be available shortly after the event by accessing the webcast link above. The conference call will also be archived on the Baytex website at www.baytexenergy.com.