Quarterly / Earnings Reports | Third Quarter (3Q) Update

Baytex Reports Q3 2019 Results

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Baytex Energy Corp. reported its Q3 2019 results (all amounts are in Canadian dollars unless otherwise noted).

Strong operating performance has continued across our asset base during the third quarter. We continue to drive cost and capital efficiencies, stable production and substantial free cash flow. Given our year-to-date results, we expect to exceed our 2019 full-year annual production guidance of 97,000 boe/d with exploration and development capital expenditures of approximately $560 million. 2019 exit production is forecast at 95,000-97,000 boe/d.

Our commitment remains to generate free cash flow and improve our balance sheet. We delivered free cash flow (adjusted funds flow less exploration and development capital expenditures) of $74 million in Q3/2019 and $271 million through the first nine months of 2019. This strong free cash flow has contributed to a 13% reduction in our net debt this year.

Q3/2019 Highlights

• Generated production of 94,927 boe/d (82% oil and NGL) in Q3/2019 and 98,125 boe/d (82% oil and NGL) for the first nine months of 2019.
  
  
• Delivered adjusted funds flow of $213 million ($0.38 per basic share) in Q3/2019 and $670 million ($1.20 per basic share) for the first nine months of 2019.
  
  
• Redeemed US$150 million principal amount of 6.75% senior unsecured notes at par on September 13, 2019.
  
  
• Reduced net debt by $57 million during the quarter ($294 million year-to-date) as adjusted funds flow exceeded capital expenditures and the Canadian dollar strengthened relative to the U.S. dollar.
  
  
• Realized an operating netback (inclusive of hedging) of $28.66/boe.
  
  
• Eagle Ford production averaged 36,793 boe/d in Q3/2019 and 39,221 boe/d for the first nine months of 2019. We established average 30-day initial production rates of approximately 2,100 boe/d per well from 20 (4.6 net) wells that commenced production during the quarter, which represents an approximate 20% improvement over wells brought on-stream in 2018.
  
  
• Production in Canada averaged 58,134 boe/d in Q3/2019 and 58,904 boe/d for the first nine months of 2019. We successfully executed our third quarter development program in Canada with 102 (92.5 net) oil wells drilled.
  
  
• Using the forward strip for the remainder of 2019⁽¹⁾, we are forecasting adjusted funds flow for 2019 of approximately $875 million. Based on planned capital expenditures, we expect to generate approximately $300 million of free cash flow in 2019.
  
  
  1. 2019 full-year pricing assumptions: WTI - US$56/bbl; LLS - US$62/bbl; WCS differential - US$12/bbl; MSW differential US$5/bbl, NYMEX Gas - US$2.60/mcf; AECO Gas - $1.54/mcf and Exchange Rate (CAD/USD) - 1.33.
     
     
• Published our fourth biennial corporate sustainability report, demonstrating our commitment to transparency and accountability, and our progress in managing the environmental and social impacts of our business. We established a greenhouse gas emissions reduction target with an objective of reducing our corporate emission intensity by 30% by 2021, relative to our 2018 baseline

Operating Results

Strong operating performance continued across our business during the third quarter. We continue to drive cost and capital efficiencies, stable production and substantial free cash flow.

Production during the third quarter averaged 94,927 boe/d (82% oil and NGL), as compared to 98,402 boe/d (82% oil and NGL) in Q2/2019. Our operating results were consistent with our expectations and reflect the timing of our 2019 development program in Canada and the Eagle Ford, and the impact of a third party facility turnaround at Peace River.

Production in the first nine months of 2019 averaged 98,125 boe/d. Given our strong performance year-to-date, we expect to exceed our 2019 full-year annual production guidance of 97,000 boe/d with exploration and development expenditures of approximately $560 million. 2019 exit production is forecast at 95,000-97,000 boe/d.

Exploration and development expenditures totaled $139 million in Q3/2019, bringing aggregate spending in the nine months of 2019 to $399 million. We participated in the drilling of 124 (97.8 net) wells with a 100% success rate during the third quarter.

Eagle Ford and Viking Light Oil

Production in the Eagle Ford averaged 36,793 boe/d (77% liquids) during Q3/2019, as compared to 39,822 boe/d in Q2/2019. The lower volumes during the quarter reflect the timing of completion activity. We commenced production from 20 (4.6 net) wells during the third quarter, as compared to 29 (5.0 net) wells during the second quarter. The wells brought on-stream generated an average 30-day initial production rate of approximately 2,100 boe/d per well, which represents an approximate 20% improvement over wells brought on-stream in 2018.

During Q3/2019, production from the Viking averaged 22,198 boe/d, as compared to 22,565 boe/d in Q2/2019. We maintained an active pace of development during the third quarter with 72.5 net wells drilled and 49.4 net wells brought on production. We currently have three drilling rigs and two frac crews executing our program and expect to drill approximately 245 net wells this year. Inventory enhancement continues to be a priority. We have completed multiple deals and swaps year-to-date adding 220 net unbooked drilling opportunities.

Heavy Oil

Our heavy oil assets at Peace River and Lloydminster produced a combined 28,483 boe/d during the third quarter, as compared to 29,983 boe/d in Q2/2019. The lower volumes reflect the timing of our 2019 development program, which is strongly weighted (80%) to the second half of the year and the impact of a third party facility turnaround. During the third quarter, we drilled 20 net heavy oil wells, including four net multi-lateral horizontal wells at Peace River. Heavy oil production is expected to increase to more than 30,000 boe/d during the fourth quarter due to new well completions and the expansion of our Kerrobert thermal project.

East Duvernay Shale Light Oil

We continue to prudently advance the delineation of the East Duvernay Shale, an early stage, high operating netback light oil resource play. To-date, we have drilled seven wells at Pembina, which confirms the prospectivity of our acreage. Two wells brought on-stream in 2019 generated an average 30-day initial production rate of approximately 1,050 boe/d per well (75% liquids) and are in the top 15% of all wells drilled to date in the play. The success of our drilling program in the Pembina area has significantly de-risked our approximately 38 kilometer long acreage fairway, where we hold 275 sections (100% working interest) of Duvernay land.

Financial Review

We delivered adjusted funds flow of $213 million ($0.38 per basic share) in Q3/2019 and $670 million ($1.20 per basic share) through the first nine months of 2019. This resulted in free cash flow (adjusted funds flow less exploration and development capital expenditures) of $74 million in Q3/2019 and $271 million through the first nine months of 2019. This strong free cash flow has contributed to a 13% reduction in our net debt this year including the redemption of our US$150 million senior unsecured notes on September 13, 2019.

We realized an operating netback of $26.27/boe in Q3/2019, as compared to $29.27/boe in Q2/2019 and $31.39/boe in Q3/2018. Including financial derivatives, our operating netback improved to $28.66/boe, as compared to $27.32/boe in Q3/2018.

Our Canadian operations generated an operating netback of $25.43/boe during Q3/2019 while our Eagle Ford asset generated an operating netback of $27.58/boe. During the third quarter, Canadian differentials remained tight, which contributed to strong price realizations.

Financial Liquidity

We are delivering on our commitment to generate meaningful free cash flow and improve our balance sheet. We redeemed US$150 million principal amount of 6.75% senior unsecured notes at par on September 13, 2019 with the redemption funded from free cash flow generated this year. During the third quarter, we reduced net debt by $57 million ($294 million year-to-date) as adjusted funds flow exceeded capital expenditures and the Canadian dollar strengthened relative to the U.S. dollar over this period. Our net debt, which includes our bank loan, long-term notes and working capital, totaled $1.97 billion at September 30, 2019.

We maintain strong financial liquidity with our credit facilities approximately 50% undrawn and our first long-term note maturity not until 2021. Our credit facilities total approximately $1.06 billion, mature April 2021 and are comprised of US$575 million of revolving credit facilities and a $300 million non-revolving term loan. The credit facilities are not borrowing base facilities and do not require annual or semi-annual reviews.

Risk Management

As part of our normal operations, we are exposed to movements in commodity prices. In an effort to manage these exposures, we utilize various financial derivative contracts and crude-by-rail to reduce the volatility in our adjusted funds flow. We realized a financial derivatives gain of $21 million in Q3/2019 on these contracts.

For the fourth quarter of 2019, we have entered into hedges on approximately 53% of our net crude oil exposure. This includes 44% of our net WTI exposure with 20% fixed at US$62.35/bbl and 24% hedged utilizing a 3-way option structure that provides us with a US$10/bbl premium to WTI when WTI is at or below US$55.64/bbl and allows upside participation to US$73.65/bbl.

For 2020, we have entered into hedges on approximately 33% of our net crude oil exposure, largely utilizing a 3-way option structure that provides us with an US$8/bbl premium to WTI when WTI is at or below US$50.50/bbl and allows upside participation to US$63.59/bbl. In addition to the 3-way option structure, for the first quarter of 2020 we have also entered into WTI-based fixed price swaps for 4,000 bbl/d at US$55.90/bbl.

Crude-by-rail is an integral part of our egress and marketing strategy for our heavy oil production. For Q4/2019, we expect to deliver 11,500 bbl/d (approximately 40%) of our heavy oil volumes to market by rail. For 2020, our crude by rail volumes are currently contracted at 7,500 bbl/d.

A complete listing of our financial derivative contracts can be found in Note 18 to our Q3/2019 financial statements.

2019 Guidance

Given our strong year-to-date operating performance, we now expect to exceed our 2019 full-year annual production guidance of 97,000 boe/d. 2019 exit production is forecast at 95,000-97,000 boe/d. We remain focused on driving cost and capital efficiencies in our business and anticipate exploration and development expenditures for 2019 of approximately $560 million.

Based on the forward strip for the balance of 2019⁽¹⁾, we are forecasting adjusted funds flow of approximately $875 million and expect to generate approximately $300 million of free cash flow, which supports our de-leveraging strategy. Adjusted funds flow in excess of exploration and development expenditures, leasing expenditures and asset retirement obligations, will be used to reduce our indebtedness.