CALGARY, Alberta – Baytex Energy Corp. (“Baytex”)(TSX: BTE) reports its operating and financial results for the three and six months ended June 30, 2021 (all amounts are in Canadian dollars unless otherwise noted).
“During the second quarter, we delivered strong operating results and substantial free cash flow. Our free cash flow profile continues to improve resulting in accelerated debt reduction. We are taking proactive measures to reduce our net debt with the repurchase and cancellation of US$106 million of our outstanding long-term notes due 2024 during and subsequent to the quarter. At current commodity prices, we now expect to generate over $350 million of free cash flow in 2021. In addition, we are drilling our fourth follow up well as we continue to advance our exciting, new, oil discovery in the Clearwater play in Peace River,” commented Ed LaFehr, President and Chief Executive Officer.
Q2 2021 Highlights
- Generated production of 81,162 boe/d (81% oil and NGL), a 3% increase over Q1/2021.
- Delivered adjusted funds flow of $176 million ($0.31 per basic share), a 12% increase compared to $157 million ($0.28 per basic share) in Q1/2021.
- Generated free cash flow of $112 million ($0.20 per basic share).
- Realized an operating netback of $33.92/boe, up from $29.80/boe in Q1/2021.
- Repurchased and cancelled US$5.8 million principal amount of 5.625% long-term notes. Subsequent to quarter-end, repurchased and cancelled an additional US$100 million principal amount of 5.625% long-term notes.
- Reduced net debt by $129 million through a combination of free cash flow and the Canadian dollar strengthening relative to the U.S. dollar.
As a result of our strong operating performance through the first half of 2021, we are increasing our production guidance to 79,000 to 80,000 boe/d, up from 77,000 to 79,000 boe/d, previously. We continue to forecast 2021 exploration and development expenditures of $285 to $315 million. Our free cash flow profile continues to improve as we benefit from our diversified oil weighted portfolio and our commitment to allocate capital effectively. At current commodity prices, we now expect to deliver over $350 million ($0.62 per basic share) of free cash flow this year, which will accelerate our debt reduction efforts.
Our five-year outlook (2021 to 2025) highlights our financial and operational sustainability and meaningful free cash flow generation. Through this plan period, we are committed to a disciplined and returns based capital allocation philosophy.
We have updated year one of our five-year outlook (2021) to reflect year-to-date commodity prices and the forward strip for the balance of the year. The remaining years (2022 to 2025) continue to be based on a constant US$55/bbl WTI price. Under the plan, we expect to generate over $1 billion of cumulative free cash flow as we target capital expenditures at less than 70% of our adjusted funds flow, while optimizing production in the 80,000 to 85,000 boe/d range. Under constant US$60/bbl and $65/bbl WTI pricing scenarios, we expect to generate in excess of $1.5 billion and $2.0 billion of cumulative free cash flow, respectively.
Based on the strong pricing environment and free cash flow forecast for 2021, we have accelerated our debt repayment strategy by approximately one year over the base plan presented last quarter. We now anticipate hitting our net debt target of $1.0 to $1.2 billion in 2023 at US$55/bbl. Throughout the plan period we will continue to monitor our leverage position and assess market conditions to determine the best methods or combination thereof to enhance shareholder returns. These could include share buy-backs, a dividend and/or reinvestment for organic growth.
|Three Months Ended||Six Months Ended|
|June 30, 2021
||March 31, 2021||June 30, 2020||June 30, 2021
||June 30, 2020|
(thousands of Canadian dollars, except per common share amounts)
|Petroleum and natural gas sales||$||442,354||$||384,702||$||152,689||$||827,056||$||489,303|
|Adjusted funds flow (1)||175,883||156,582||17,887||332,465||150,822|
|Per share – basic||0.31||0.28||0.03||0.59||0.27|
|Per share – diluted||0.31||0.28||0.03||0.59||0.27|
|Net income (loss)||1,052,999||(35,352||)||(138,463||)||1,017,647||(2,636,680||)|
|Per share – basic||1.87||(0.06||)||(0.25||)||1.81||(4.71||)|
|Per share – diluted||1.85||(0.06||)||(0.25||)||1.79||(4.71||)|
|Exploration and development expenditures (1)||$||61,485||$||83,588||$||9,852||$||145,073||$||186,629|
|Acquisitions, net of divestitures||(18||)||(203||)||(11||)||(221||)||(51||)|
|Total oil and natural gas capital expenditures||$||61,467||$||83,385||$||9,841||$||144,852||$||186,578|
|Credit facilities (2)||$||486,623||$||606,637||$||704,135||$||486,623||$||704,135|
|Long-term notes (2)||1,109,211||1,131,480||1,225,395||1,109,211||1,225,395|
|Working capital deficiency||33,795||20,777||65,423||33,795||65,423|
|Net debt (1)||$||1,629,629||$||1,758,894||$||1,994,953||$||1,629,629||$||1,994,953|
|Shares Outstanding – basic (thousands)|
|End of period||564,182||564,111||560,545||564,182||560,545|
|MEH oil (US$/bbl)||67.15||59.36||26.40||63.26||37.97|
|MEH oil differential to WTI (US$/bbl)||1.08||1.52||(1.45||)||1.30||0.96|
|Edmonton par ($/bbl)||77.28||66.58||29.85||71.93||40.64|
|Edmonton par differential to WTI (US$/bbl)||(3.13||)||(5.27||)||(6.31||)||(4.28||)||(7.24||)|
|WCS heavy oil ($/bbl)||67.03||57.46||22.70||62.33||28.68|
|WCS differential to WTI (US$/bbl)||(11.48||)||(12.46||)||(11.47||)||(11.98||)||(16.00||)|
|CAD/USD average exchange rate||1.2279||1.2663||1.3860||1.2471||1.3653|
|Three Months Ended||Six Months Ended|
|June 30, 2021
||March 31, 2021||June 30, 2020||June 30, 2021
||June 30, 2020|
|Light oil and condensate (bbl/d)||37,134||35,430||38,951||36,286||42,333|
|Heavy oil (bbl/d)||21,269||21,989||11,832||21,627||20,343|
|Total liquids (bbl/d)||65,966||63,657||58,417||64,817||70,404|
|Natural gas (mcf/d)||91,172||90,739||84,546||90,957||90,451|
|Oil equivalent (boe/d @ 6:1) (3)||81,162||78,780||72,508||79,978||85,479|
|Netback (thousands of Canadian dollars)|
|Total sales, net of blending and other expense (4)||$||422,387||$||367,582||$||147,229||$||789,969||$||462,486|
|Operating netback (1)||$||250,469||$||211,296||$||39,362||$||461,765||$||183,087|
|General and administrative||(10,610||)||(8,733||)||(7,438||)||(19,343||)||(17,213||)|
|Cash financing and interest||(23,554||)||(24,403||)||(27,387||)||(47,957||)||(55,922||)|
|Realized financial derivatives (loss) gain||(39,024||)||(20,768||)||13,624||(59,792||)||40,474|
|Adjusted funds flow (1)||$||175,883||$||156,582||$||17,887||$||332,465||$||150,822|
|Netback (per boe)|
|Total sales, net of blending and other expense (4)||$||57.19||$||51.84||$||22.31||$||54.57||$||29.73|
|Operating netback (1)||$||33.92||$||29.80||$||5.96||$||31.90||$||11.77|
|General and administrative||(1.44||)||(1.23||)||(1.13||)||(1.34||)||(1.11||)|
|Cash financing and interest||(3.19||)||(3.44||)||(4.15||)||(3.31||)||(3.59||)|
|Realized financial derivatives (loss) gain||(5.28||)||(2.93||)||2.06||(4.13||)||2.60|
|Adjusted funds flow (1)||$||23.81||$||22.08||$||2.71||$||22.97||$||9.69|
(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 Q2/2021 MD&A for further information on these amounts.
During Q2/2021, we delivered strong operating and financial results as we executed on our plan to maximize free cash flow and reduce debt. During the quarter, we delivered adjusted funds flow of $176 million ($0.31 per basic share). This resulted in substantial quarterly free cash flow of $112 million, which along with the Canadian dollar strengthening relative to the U.S. dollar, contributed to a $129 million reduction in our net debt.
Production during the second quarter averaged 81,162 boe/d (81% oil and NGL), up 3% as compared to 78,780 boe/d (81% oil and NGL) in Q1/2021. The increased production reflects the timing of completion activity in the Eagle Ford and and strong performance across our light and heavy oil assets in Canada. Exploration and development expenditures totaled $61 million in Q2/2021 that included the drilling of 34 (19.7 net) wells with a 100% success rate.
During Q2/2021, we reported net income of $1.1 billion ($1.85 per diluted share). At June 30, 2021, we identified indicators of impairment reversal for our oil and gas properties due to the increase in forecasted commodity prices. As a result, we recorded an impairment reversal of $1.1 billion during the second quarter as the estimated recoverable amounts exceeded the carrying value of our oil and gas properties.
In 2021, we are benefiting from our diversified oil weighted portfolio and our commitment to allocate capital effectively. Based on the forward strip(1), we expect to generate over $350 million of free cash flow in 2021.
As a result of our strong operating performance through the first half of 2021, we are increasing our production guidance to 79,000 to 80,000 boe/d, up from 77,000 to 79,000 boe/d, previously. We continue to forecast 2021 exploration and development expenditures of $285 to $315 million.
Our interest expense guidance is 3% lower due to reduced net debt and the repurchase and cancellation of US$106 million principal amount of 5.625% long-term notes.
The following table highlights our updated 2021 annual guidance.
|2021 Guidance (2)||2021 Revised Guidance|
|Exploration and development expenditures||$285 – $315 million||no change|
|Production (boe/d)||77,000 – 79,000||79,000 – 80,000|
|Royalty rate||18.0% – 18.5%||no change|
|Operating||$11.25 – $12.00/boe||no change|
|Transportation||$1.15 – $1.25/boe||no change|
|General and administrative||$42 million ($1.48/boe)||$42 million ($1.45/boe)|
|Interest||$98 million ($3.46/boe)||$95 million ($3.27/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 33,957 boe/d (80% oil and NGL) during Q2/2021, as compared to 26,741 boe/d in Q1/2021. The higher volumes reflect an increased pace of completions and continued strong operating performance. During the second quarter we commenced production from 38 (10.2 net) wells, up from 24 (7.0 net) wells in Q1/2021. In Q2/2021, we invested $31 million on exploration and development in the Eagle Ford and generated an operating netback of $112 million. We expect to bring approximately 22 net wells on production in the Eagle Ford in 2021.
(1) 2021 full-year pricing assumptions: WTI – US$64/bbl; WCS differential – US$13/bbl; MSW differential – US$4/bbl, NYMEX Gas – US$3.30/mcf; AECO Gas – $3.45/mcf and Exchange Rate (CAD/USD) – 1.26.
(2) As announced on April 29, 2021.
Production in the Viking averaged 16,301 boe/d (88% oil and NGL) during Q2/2021, as compared to 19,403 boe/d in Q1/2021. Our capital program in the second quarter included the seasonal slowdown, which resulted in the completion of 14 (14.0 net) wells, as compared to 44 (43.2 net) wells during the first quarter. In Q2/2021, we invested $17 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 during 2021.
Our heavy oil assets at Peace River and Lloydminster produced a combined 23,304 boe/d (91% oil and NGL) during the Q2/2021, as compared to 24,395 boe/d in Q1/2021. We scheduled minimal heavy oil development for the first half of 2021. Our heavy oil program kicked off in June with approximately 35 net wells planned for the year, including up to seven 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. In early 2020, we executed a strategic agreement with the Peavine Métis 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 appraisal program continues to yield encouraging results and pending continued success, sets the stage for a potential increase in activity in 2022. We plan to drill up to seven net appraisal wells in 2021, of which five net appraisal wells will occur on our Peavine lands. Across our acreage position in northwest Alberta, we estimate that over 100 sections are prospective for Clearwater development. The following table summarizes our Peavine appraisal program for 2021.
|Area||Well||Spud||Rig Release||# of Laterals||30-Day Initial Production Rate (bbl/d)|
|Peavine||100/04-34-078-16W5||January 6||January 19||2||175|
|Peavine||102/04-34-078-16W5||June 15||June 21||2||175|
|Peavine||100/13-27-078-16W5||June 22||July 6||8||On Production July 10|
|Peavine||100/05-34-078-16W5||July 8||July 18||8||On Production July 22|
Pembina Area Duvernay Light Oil
Production in the Pembina Duvernay averaged 1,698 boe/d (80% oil and NGL) during Q2/2021, as compared to 2,138 boe/d in Q1/2021. 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 expect to bring two additional 100% working interest wells on production during the third quarter.
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 June 30, 2021, we had $511 million of undrawn capacity on our credit facilities, resulting in liquidity, net of working capital, of $477 million.
Our net debt, which includes our credit facilities, long-term notes and working capital, totaled $1.63 billion at June 30, 2021, down from $1.76 billion at March 31, 2021.
On May 4, 2021, we repurchased and cancelled US$5.8 million principal amount of 5.625% long-term notes. Subsequent to the quarter, we used free cash flow generated in the first half of 2021 to repurchase and cancel US$100 million principal amount of the 5.625% long-term notes at the call price of 100.938% plus accrued interest effective July 28, 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 the second half of 2021, we have entered into hedges on approximately 45% 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 net Canadian light oil exposure at US$5.03/bbl and WCS differential hedges on approximately 50% of our net expected heavy oil exposure at a WTI-WCS differential of approximately US$13.23/bbl.
For 2022, we have entered into hedges on approximately 42% 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$57.76/bbl with upside participation to US$67.51/bbl. We also have WTI-MSW differential hedges on approximately 13% of our expected net Canadian light oil exposure at US$4.63/bbl and WCS differential hedges on approximately 39% of our expected net heavy oil exposure at a WTI-WCS differential of approximately US$12.53/bbl.
A complete listing of our financial derivative contracts can be found in Note 16 to our Q2/2021 financial statements.
Our condensed consolidated interim unaudited financial statements for the three and six months ended June 30, 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, July 29, 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/baytex20210729.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.