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Baytex Cuts Spending for 2021, Plans 168 Completions (+11% YOY); 2020 Results

Share Print Bookmark    |    Thursday,February 25,2021

Baytex Energy Corp. reported its 2021 capital plan and Q4 / full year 2020 results (all amounts are in Canadian dollars unless otherwise noted).

2021 Plan

- Capex: $225-275 million - down 11% at the midpoint vs. 2020 levels

• D&C: $235 million
  

• Facilities: $10 million

• Land & Seismic: $5 million

- Production: 73-77 MBOEPD - relatively flat from full year 2020 output

- Wells TIL: 168 net wells - up 11% vs. 2020

• Viking: 120 net wells
  

• Eagle Ford: 18 net wells

• Heavy Oil: 28 net wells

• East Duvernay: 2 net wells

- Rig Count: 2 rigs running (both in Viking - other rig data not disclosed)

Baytex expects to generate over $250 million of free cash flow in 2021 and increase our financial liquidity to over $550 million.

It has entered into hedges on approximately 48% of our net crude oil exposure for 2021, largely utilizing a 3-way option structure that provides WTI price protection at US$45/bbl with upside participation to US$52/bbl.

Q4 / Full Year 2020 Results

“In 2020, we responded aggressively to the downturn brought on by Covid-19, improved our cost structure and capital efficiencies, exceeded our GHG emissions intensity target, and enhanced our overall sustainability. The strong recovery in commodity prices in early 2021 has us on track to deliver over $250 million ($0.45 per basic share) of free cash flow in 2021. We resumed drilling activity late last year and are building significant operational momentum with current production over 78,000 boe/d. We are executing our plan to maximize free cash flow and accelerate our debt reduction strategy,” commented Ed LaFehr, President and Chief Executive Officer.

• Production in line with guidance at 70,475 boe/d (82% oil and NGL) in Q4/2020 and 79,781 boe/d (82% oil and NGL) for the full-year 2020.
• Exploration and development expenditures totaled $78 million in Q4/2020, bringing aggregate spending for 2020 to $280 million, in line with guidance.
• Delivered adjusted funds flow of $82 million ($0.15 per basic share) in Q4/2020 and $312 million ($0.56 per basic share) for 2020.
• Generated free cash flow of $2 million in Q4/2020 and $18 million ($0.03 per basic share) for 2020.
• Refinanced US$500 million of long-term notes to 2027 and extended credit facility to 2024.
• Maintained undrawn credit capacity of $367 million and liquidity, net of working capital, of $319 million.
• Achieved a 46% reduction in our GHG emissions intensity through year-end 2020, relative to our 2018 baseline. This represents an annual reduction of 1.5 million tonnes of CO2e and is equivalent to taking 330,000 cars off the road annually. 
• Our net asset value at year-end 2020, discounted at 10%, is estimated to be $2.78 per share. This is based on the estimated reserves value plus a value for undeveloped acreage, net of long-term debt and working capital.

Our 2020 reserves report reflects the impact of a materially lower commodity price forecast being utilized by our reserves evaluator, which has WTI averaging US$56/bbl over the next ten years, down 20% from one year ago. At year-end 2020, proved developed producing reserves total 120 mmboe, proved reserves total 271 mmboe and our proved plus probable reserves total 462 mmboe. We removed 29 million barrels of proved reserves (65% heavy oil and bitumen) and 41 million barrels of proved plus probable reserves (80% heavy oil and bitumen), which are uneconomic using this commodity price forecast.

2020 Results

In one of the most challenging years experienced by our industry, we delivered on our commitment to preserve financial liquidity, capture cost savings, generate free cash flow and keep our operations safe. We also re-set our business in response to the volatile crude oil market and improved our capital efficiencies and overall sustainability.

Production during the fourth quarter averaged 70,475 boe/d (82% oil and NGL), as compared to 77,814 boe/d (82% oil and NGL) in Q3/2020. The reduced volumes reflect a lower level of completion activity in the Viking and Eagle Ford from March through November, and the carry-over of drilled and uncompleted wells into 2021. As we execute our plans for 2021, production has increased to over 78,000 boe/d, consistent with our full-year guidance.

Production in 2020 averaged 79,781 boe/d as compared to 97,680 boe/d in 2019. The lower volumes reflect the approximate 50% reduction in capital spending and the impact of voluntary shut-ins earlier in the year. Exploration and development expenditures totaled $78 million in Q4/2020 and $280 million for full-year 2020. We participated in the completion of 217 (152.4 net) wells with a 100% success rate during the year.

We delivered adjusted funds flow of $82 million ($0.15 per basic share) in Q4/2020 and $312 million ($0.56 per basic share) in 2020. This resulted in free cash flow of $18 million in 2020, which, along with the Canadian dollar strengthening relative to the U.S. dollar, contributed to a $24 million reduction in our net debt this year.

We recorded net income of $221 million ($0.39 per basic share) in Q4/2020 and a net loss of $2.4 billion ($4.35 per basic share) in 2020. In March 2020, due to the sharp decline in forecasted commodity prices, we recorded total impairments of $2.7 billion as the carrying value of our oil and gas properties exceeded the estimated recoverable amounts. At December 31, 2020 with updated development plans and changes in commodity prices, we recorded an impairment reversal of $356 million. Revisions to forecast crude oil prices could result in reversals or additional impairment charges in the future.

Operating Results

Eagle Ford and Viking Light Oil

Production in the Eagle Ford averaged 25,154 boe/d (77% oil and NGL) during Q4/2020, as compared to 28,650 boe/d in Q3/2020. Production for the full-year 2020 averaged 31,179 boe/d, as compared to 39,055 boe/d in 2019. The lower volumes reflect reduced completion activity as we adjusted our development plan in response to volatile commodity prices. In 2020, we invested $105 million on exploration and development in the Eagle Ford and generated an operating netback of $202 million.

Activity in the Eagle Ford resumed during the fourth quarter with 26 (7.1 net) wells drilled and 9 (2.7 net wells) brought onstream. The remainder of the wells drilled during the fourth quarter are expected to be onstream in Q1/2021. We expect to bring approximately 18 net wells on production in the Eagle Ford in 2021.

Production in the Viking averaged 15,326 boe/d (89% oil and NGL) during Q4/2020, as compared to 18,774 boe/d in Q3/2020. Full-year 2020 production averaged 19,614 boe/d, as compared to 22,546 boe/d in 2019.   In 2020, we invested $105 million on exploration and development in the Viking and generated an operating netback of $163 million.

We had previously suspended all drilling in the Viking, and as such, there was limited activity from March through October. We resumed drilling in November with two rigs mobilized to execute a 30-well drilling program. In 2021, we expect to bring approximately 120 net wells onstream, including 43 net wells during the first quarter.

Heavy Oil

Our heavy oil assets at Peace River and Lloydminster produced a combined 24,228 boe/d (90% oil and NGL) during the fourth quarter, as compared to 24,791 boe/d in Q3/2020. Production for the full-year 2020 averaged 23,335 boe/d, as compared to 29,378 boe/d in 2019. The impact of voluntary shut-ins for the full-year 2020 was approximately 6,000 boe/d. In addition, we had previously suspended all heavy oil drilling, and as such, there was limited activity during the year. In 2020, we invested $41 million on exploration and development on our heavy oil assets and generated an operating netback of $27 million.

We have scheduled minimal heavy oil development for the first half of 2021. At current commodity prices, we intend to implement a drilling program in the second half of the year, which could see us drill upwards of 30 net wells at Lloydminster and 6 net wells at Peace River.

Pembina Area Duvernay Light Oil

Production in the Pembina Duvernay averaged 2,031 boe/d (84% oil and NGL) during Q4/2020, as compared to 1,474 boe/d in Q3/2020. Production for the full-year 2020 averaged 1,507 boe/d, as compared to 1,688 boe/d in 2019.

We continue to prudently advance our Pembina Duvernay Shale light oil play. Our most recent two wells were completed in October. The 10-16 well was brought on-stream November 2 and generated a 30-day initial production rate of 1,300 boe/d (69% oil). The 11-16 well was brought on-stream November 17 and generated a facility constrained 30-day initial production rate of 900 boe/d (68% oil). Based on early flowback results, these two wells demonstrate repeatability of our 11-30 pad completed in 2019. We have the flexibility in 2021 to drill up to 4 net wells in the second half of the year.   

Financial Liquidity

Our credit facilities total approximately $1.03 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 December 31, 2020, we had $367 million of undrawn capacity on our credit facilities, resulting in liquidity, net of working capital, of $319 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 $1.85 billion at December 31, 2020, down from $1.91 billion at September 30, 2020. Based on the forward strip, we expect to increase our financial liquidity to over $550 million in 2021.

Risk Management

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 48% 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 50% of our expected 2021 heavy oil production at a WTI-WCS differential of approximately US$13.31/bbl.

For 2021, we are contracted to deliver 5,500 bbl/d of our heavy oil volumes to market by rail.

A complete listing of our financial derivative contracts can be found in Note 18 to our 2020 financial statements.

Board Renewal and Governance

Naveen Dargan, a long-standing board member, has announced his intent to retire from the Baytex Board at the 2021 Annual Meeting of Shareholders to be held in April 2021. Baytex thanks Mr. Dargan for his valued contribution during his tenure on the Board. His hard work and dedication for the benefit of all stakeholders is greatly appreciated.

Baytex has an ongoing board renewal process led by the Nominating and Governance Committee of the Board. Since September 2019, Baytex has added three independent Board members from various professional backgrounds. Following Mr. Dargan’s retirement, the Board will be comprised of eight directors with seven of eight being independent, including the Chair of the Board and all committee members. In addition, two of eight directors are women.

ESG – Update on GHG Emissions Reduction

In 2019, Baytex established for the first time a GHG emissions reduction target. Our objective was to reduce our corporate GHG emission intensity (tonnes of CO₂e per boe) by 30% by 2021, relative to our 2018 baseline. We are pleased to announce that we have exceeded this target in scope and timing, achieving a 46% reduction in our GHG emissions intensity through year-end 2020. This represents an annual reduction of 1.6 million tonnes of CO₂e and is equivalent to taking 340,000 cars off the road annually. To achieve our goal, we completed our Peace River gas plant in mid-2018 and significantly advanced our Viking emissions reduction project.

Continual improvement is an important element of our corporate culture and we are setting the bar higher. We have established a new target with an objective to reduce our corporate GHG emission intensity (tonnes of CO2 per boe) by a further 33% from current levels by 2025. This equates to an approximate 65% reduction by 2025, relative to our 2018 baseline. Our emissions reduction strategy includes increased gas conservation and combustion, reusing associated gas as fuel for field activities, reduced emissions from storage tanks, along with monitoring and preventing fugitive emissions.

Year-end 2020 Reserves

Baytex's year-end 2020 proved and probable reserves were evaluated by McDaniel & Associates Consultants Ltd. (“McDaniel”), an independent qualified reserves evaluator. All of our oil and gas properties were evaluated in accordance with National Instrument 51-101 “Standards of Disclosure for Oil and Gas Activities” (“NI 51-101”) and the Canadian Oil and Gas Evaluation Handbook (the “COGE Handbook”) using the average commodity price forecasts and inflation rates of McDaniel, GLJ Petroleum Consultants (“GLJ”) and Sproule Associates Limited (“Sproule”) as of January 1, 2021.

Reserves associated with our thermal heavy oil projects at Gemini (Cold Lake) and Kerrobert have been classified as bitumen. Complete reserves disclosure will be included in our Annual Information Form for the year ended December 31, 2020, which will be filed on or before March 31, 2021.

Our 2020 reserves report reflects the impact of a materially lower commodity price forecast being utilized by our reserves evaluator, which was brought on by Covid-19 and the extremely volatile crude oil market. We highlight the updated commodity price forecast on page 11 which has WTI averaging US$56/bbl over the next ten years, down 20% from one year ago. Consistent with the $2.4 billion impairment we recorded in 2020, we removed 29 million barrels of proved reserves (65% heavy oil and bitumen) and 41 million barrels of proved plus probable reserves (80% heavy oil and bitumen), which are uneconomic under the commodity price forecast.

• Our proved developed producing ("PDP") reserves total 120 mmboe, proved reserves (“1P”) total 271 mmboe and our proved plus probable reserves (“2P”) total 462 mmboe.
  
  
• Reserves on a 1P basis are comprised of 81% oil and NGL (48% light oil, 33% NGL’s, 16% heavy oil and 3% bitumen) and 19% natural gas. PDP reserves represent 44% of 1P reserves (45% at year-end 2019) and 1P reserves represent 59% of 2P reserves (59% at year-end 2019).
  
  
• Baytex maintains a strong reserves life index of 4.7 years based on PDP reserves, 10.5 years based on 1P reserves and 17.9 years based on 2P reserves.
  
  
• Future development costs have been reduced by $464 million on a 1P basis and $709 million on a 2P basis.
  
  
• Our net asset value at year-end 2020, discounted at 10%, is estimated to be $2.78 per share. This is based on the estimated reserves value plus a value for undeveloped acreage, net of long-term debt and working capital.