CALGARY, Alberta – Baytex Energy Corp. (“Baytex”)(TSX: BTE) reports its operating and financial results for the three months ended March 31, 2021 (all amounts are in Canadian dollars unless otherwise noted).
“We delivered strong first quarter production and free cash flow as we accelerate our deleveraging strategy. At current commodity prices, we expect to generate over $250 million of free cash flow in 2021 and we have an exciting, new, oil exploration discovery in the Clearwater oil play in Peace River with follow-up drilling already scheduled for H2/2021. I am also pleased to announce our five-year outlook which demonstrates our operational and financial strength in a US$55 WTI pricing environment as we target over $1 billion of cumulative free cash flow through 2025,” commented Ed LaFehr, President and Chief Executive Officer.
Q1 2021 Highlights
- Generated production of 78,780 boe/d (81% oil and NGL), a 12% increase over Q4/2020.
- Delivered adjusted funds flow of $157 million ($0.28 per basic share), a 91% increase compared to $82 million ($0.15 per basic share) in Q4/2020.
- Generated free cash flow of $70 million ($0.13 per basic share).
- Realized an operating netback of $29.80/boe, up from $15.19/boe in Q4/2020.
- Reduced net debt by $89 million through a combination of free cash flow and the Canadian dollar strengthening relative to the U.S. dollar.
We are benefiting from a disciplined approach to capital allocation and improvements to our cost structure and capital efficiencies along with the recovery in commodity prices. Drilling activity resumed late last year and we are building significant operational momentum with first quarter production up 12% from Q4/2020, largely driven by our light oil business. We are on track to deliver over $250 million ($0.45 per basic share) of free cash flow, which will accelerate our debt reduction efforts.
As a result of this operational momentum and the strength in commodity prices, we are increasing both our production and capital spending guidance. This will position our business for continued strong operating performance and free cash flow generation going forward. We are now forecasting 2021 exploration and development expenditures of $285 to $315 million, up from $225 to $275 million, which was set in a US$40 to US$45 pricing environment. The increased expenditures will largely occur in the fourth quarter and will be allocated across our portfolio of light and heavy oil assets, including our emerging Clearwater play at Peace River. Our revised production guidance range is 77,000 to 79,000 boe/d, up from 73,000 to 77,000 boe/d.
We are providing a five-year outlook (2021 to 2025) to highlight our financial and operational sustainability and meaningful free cash flow generation. Through this plan period, we will maintain a disciplined and returns based capital allocation philosophy.
Assuming a constant US$55/bbl WTI price, we will target capital expenditures at less than 70% of our adjusted funds flow, while optimizing our production in the 80,000 to 85,000 boe/d range. We project annual capital spending of approximately $400 million from 2022 to 2025 and expect to generate over $1 billion of cumulative free cash flow. Our leverage ratios are expected to improve materially as we target a net debt to EBITDA ratio of under 1.5x. Throughout the plan period we will continue to monitor our leverage position and assess market conditions to determine the best methods or combination thereof to enhance shareholder returns. These could include share buy-backs, a dividend or reinvestment for organic growth.
|Three Months Ended
|March 31, 2021
||December 31, 2020||March 31, 2020|
(thousands of Canadian dollars, except per common share amounts)
|Petroleum and natural gas sales||$||384,702||$||233,636||$||336,614|
|Adjusted funds flow (1)||156,582||82,176||132,935|
|Per share – basic||0.28||0.15||0.24|
|Per share – diluted||0.28||0.15||0.24|
|Net income (loss)||(35,352||)||221,160||(2,498,217||)|
|Per share – basic||(0.06||)||0.39||(4.46||)|
|Per share – diluted||(0.06||)||0.39||(4.46||)|
|Exploration and development expenditures (1)||$||83,588||$||77,809||$||176,777|
|Acquisitions, net of divestitures||(203||)||(33||)||(40||)|
|Total oil and natural gas capital expenditures||$||83,385||$||77,776||$||176,737|
|Credit facilities (2)||$||606,637||$||651,173||$||678,740|
|Long-term notes (2)||1,131,480||1,147,950||1,270,800|
|Working capital deficiency||20,777||48,478||102,077|
|Net debt (1)||$||1,758,894||$||1,847,601||$||2,051,617|
|Shares Outstanding – basic (thousands)|
|End of period||564,111||561,227||560,483|
|MEH oil (US$/bbl)||59.36||43.05||49.54|
|MEH oil differential to WTI (US$/bbl)||1.52||0.39||3.37|
|Edmonton par ($/bbl)||66.58||50.24||51.43|
|Edmonton par differential to WTI (US$/bbl)||(5.27||)||(4.11||)||(7.92||)|
|WCS heavy oil ($/bbl)||57.46||43.46||34.48|
|WCS differential to WTI (US$/bbl)||(12.46||)||(9.31||)||(20.53||)|
|CAD/USD average exchange rate||1.2663||1.3031||1.3445|
|Three Months Ended
|March 31, 2021
||December 31, 2020||March 31, 2020|
|Light oil and condensate (bbl/d)||35,430||29,568||45,717|
|Heavy oil (bbl/d)||21,989||21,725||28,854|
|Total liquids (bbl/d)||63,657||57,788||82,393|
|Natural gas (mcf/d)||90,739||76,116||96,356|
|Oil equivalent (boe/d @ 6:1) (3)||78,780||70,475||98,452|
|Netback (thousands of Canadian dollars)|
|Total sales, net of blending and other expense (4)||$||367,582||$||222,745||$||315,257|
|Operating netback (1)||$||211,296||$||98,498||$||143,725|
|General and administrative||(8,733||)||(9,313||)||(9,775||)|
|Cash financing and interest||(24,403||)||(25,194||)||(28,535||)|
|Realized financial derivatives (loss) gain||(20,768||)||17,105||26,850|
|Adjusted funds flow (1)||$||156,582||$||82,176||$||132,935|
|Netback (per boe)|
|Total sales, net of blending and other expense (4)||$||51.84||$||34.35||$||35.19|
|Operating netback (1)||$||29.80||$||15.19||$||16.05|
|General and administrative||(1.23||)||(1.44||)||(1.09||)|
|Cash financing and interest||(3.44||)||(3.89||)||(3.19||)|
|Realized financial derivatives (loss) gain||(2.93||)||2.64||3.00|
|Adjusted funds flow (1)||$||22.08||$||12.67||$||14.84|
|(1)||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.|
|(2)||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.|
|(3)||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.|
|(4)||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.|
|(5)||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 Q1/2021 MD&A for further information on these amounts.|
During Q1/2021, we executed on our plan to maximize free cash flow and reduce debt. During the quarter, we delivered adjusted funds flow of $157 million ($0.28 per basic share). This resulted in free cash flow of $70 million, which, along with the Canadian dollar strengthening relative to the U.S. dollar, contributed to an $89 million reduction in our net debt.
Production during the first quarter averaged 78,780 boe/d (81% oil and NGL), up 12% as compared to 70,475 boe/d (82% oil and NGL) in Q4/2020. The increased production largely reflects the resumption of drilling activity in the Viking and Eagle Ford which began in the fourth quarter. Exploration and development expenditures totaled $84 million in Q1/2021 that included the drilling of 68 (46.5 net) wells with a 100% success rate.
In 2021, we expect to benefit from our diversified oil weighted portfolio and our commitment to allocate capital effectively. Based on the forward strip(1), we expect to generate over $250 million of free cash flow in 2021.
As a result of our strong operational momentum and the strength in commodity prices, we are increasing both our production and capital spending guidance. This will position our business for continued strong operating performance and free cash flow generation going forward. We are now forecasting 2021 exploration and development expenditures of $285 to $315 million, up from $225 to $275 million, which was set in a US$40 to US$45 pricing environment. The increased spend will largely occur in the fourth quarter and will be allocated across our portfolio of light and heavy oil assets. Our revised production guidance range is 77,000 to 79,000 boe/d, up from 73,000 to 77,000 boe/d.
We have also fine-tuned several of our cost assumptions to reflect higher production volumes and increased activity. In addition, our interest expense guidance is 7% lower due to reduced net debt and the Canadian dollar strengthening relative to the U.S. dollar.
The following table highlights our updated 2021 annual guidance.
|2021 Guidance (2)||2021 Revised Guidance|
|Exploration and development expenditures||$225 – $275 million||$285 – $315 million|
|Production (boe/d)||73,000 – 77,000||77,000 – 79,000|
|Royalty rate||18.0% – 18.5%||no change|
|Operating||$11.50 – $12.25/boe||$11.25 – $12.00/boe|
|Transportation||$1.00 – $1.10/boe||$1.15 – $1.25/boe|
|General and administrative||$42 million ($1.53/boe)||$42 million ($1.48/boe)|
|Interest||$105 million ($3.84/boe)||$98 million ($3.46/boe)|
|Leasing expenditures||$4 million||no change|
|Asset retirement obligations||$6 million||no change|
Eagle Ford and Viking Light Oil
Production in the Eagle Ford averaged 26,741 boe/d (77% oil and NGL) during Q1/2021, as compared to 25,154 boe/d in Q4/2020. During the first quarter, we commenced production from 24 (7.0 net) wells, up from 9 (2.7 net) wells in Q4/2020. In Q1/2021, we invested $41 million on exploration and development in the Eagle Ford and generated an operating netback of $84 million. We expect to bring approximately 20 net wells on production in the Eagle Ford in 2021, up from 18 net wells previously.
|(1)||2021 full-year pricing assumptions: WTI – US$60/bbl; WCS differential – US$12/bbl; MSW differential – US$4.5/bbl, NYMEX Gas – US$2.80/mcf; AECO Gas – $2.80/mcf and Exchange Rate (CAD/USD) – 1.25.|
|(2)||As announced on December 2, 2020.|
Production in the Viking averaged 19,403 boe/d (91% oil and NGL) during Q1/2021, as compared to 15,326 boe/d in Q4/2020. During the first quarter, we commenced production from 44 (43.2 net) wells. In Q1/2021, we invested $35 million on exploration and development in the Viking and generated an operating netback of $72 million. We expect to bring approximately 120 net wells on production in the Viking in 2021.
Our heavy oil assets at Peace River and Lloydminster produced a combined 24,395 boe/d (90% oil and NGL) during the Q1/2021, as compared to 24,228 boe/d in Q4/2020. We scheduled minimal heavy oil development for the first half of 2021. Our heavy oil program is expected to kick off in July with 35 net wells planned for the year, including up to six net wells in our Spirit River (Clearwater equivalent) play.
Peace River Clearwater
Across all of our core assets, inventory enhancement continues to be a priority. We are also committed to building and maintaining respectful relationships with Indigenous communities and creating opportunities for meaningful economic participation and inclusion. One year ago, we executed a strategic agreement with the Peavine Metis settlement in the Peace River area that covers 60 sections of land directly to the south of our existing Seal operations. At the time, we identified significant potential for this early stage exploratory play targeting the Spirit River formation, a Clearwater formation equivalent.
Our initial exploration well was drilled during the first quarter and has shown promising early results with a 30-day initial production rate of 175 bbl/d from two laterals. With this early success, we are planning up to six additional Clearwater multi-lateral wells for H2/2021. Across our acreage position in northwest Alberta, we estimate that over 100 sections are prospective for Clearwater development.
Pembina Area Duvernay Light Oil
Production in the Pembina Duvernay averaged 2,138 boe/d (84% oil and NGL) during Q1/2021, as compared to 2,031 boe/d in Q4/2020. We now have nine producing wells in the Pembina area and have significantly de-risked our approximately 38-kilometre long acreage fairway, where we hold 232 sections (100% working interest) of Duvernay land. We plan to drill a further two 100% working interest wells in the second half of the year.
Our credit facilities total approximately $1.0 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 March 31, 2021, we had $401 million of undrawn capacity on our credit facilities, resulting in liquidity, net of working capital, of $381 million. We are well within our financial covenants and 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 $1.76 billion at March 31, 2021, down from $1.85 billion at December 31, 2020. Based on the forward strip, we expect to increase our financial liquidity to over $550 million in 2021.
To manage commodity price movements, we utilize various financial derivative contracts and crude-by-rail to reduce the volatility of our adjusted funds flow.
For 2021, we have entered into hedges on approximately 47% of our net crude oil exposure utilizing a combination of fixed price swaps at US$45/bbl and a 3-way option structure that provides price protection at US$44.71/bbl with upside participation to US$52.42/bbl. We also have WTI-MSW differential hedges on approximately 50% of our expected 2021 Canadian light oil production at US$5.05/bbl and WCS differential hedges on approximately 55% of our expected 2021 heavy oil production at a WTI-WCS differential of approximately US$13.31/bbl.
For 2022, we have entered into hedges on approximately 33% of our net crude oil exposure utilizing a combination of swaptions at US$53.50/bbl and a 3-way option structure that provides price protection at US$54.91/bbl with upside participation to US$64.68/bbl. We also have WCS differential hedges on approximately 35% of our expected 2022 heavy oil production at a WTI-WCS differential of approximately US$12.47/bbl.
A complete listing of our financial derivative contracts can be found in Note 16 to our Q1/2021 financial statements.
Our condensed consolidated interim unaudited financial statements for the three months ended March 31, 2021 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. MDT (11:00 a.m. EDT)
|Baytex will host a conference call tomorrow, April 30, 2021, starting at 9:00am MDT (11:00am EDT). 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/baytex20210430.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.