Baytex Energy Corp. (BTE) Q4 2019 Earnings Report, Transcript and Summary

Thank you for standing by. This is the conference operator. Welcome to the Baytex Energy Corp. Fourth Quarter and Year-end Conference Call and Webcast. [Operator Instructions]. I would now like to turn the conference over to Brian Ector, Vice President, Capital Markets. Please go ahead.

Thank you, Ariel. Good morning, ladies and gentlemen, and thank you for joining us today to discuss our fourth quarter and full year 2019 financial and operating results. With me today are Ed LaFehr, our President and Chief Executive Officer; Rod Gray, Executive VP and Chief Financial Officer; Kendall Arthur, Vice President, Heavy Oil; and Chad Lundberg, Vice President, Light Oil. While listening, please keep in mind that some of our remarks will contain forward-looking statements within the meaning of applicable securities laws. I would refer you to the advisories regarding forward-looking statements, oil and gas information and non-GAAP financial and capital management measures in today's press release. On the call today, we will also be discussing the evaluation of our reserves at year-end 2019. These evaluations have been prepared in accordance with Canadian disclosure standards, which are not comparable in all respects to United States or other foreign disclosure standards. Our remarks regarding reserves are also forward-looking statements. All dollars referenced in our remarks are in Canadian dollars, unless otherwise specified. And with that, I would now like to turn the call over to Ed.

Thanks, Brian, and good morning, everyone. I'd like to welcome everybody to our year-end 2019 conference call. As a reminder, we released preliminary unaudited financial and operating results on January 20, 2020 in conjunction with the release of our 2019 reserves. Our audited financial and operating results for the 3 months and year ended December 31, 2019 are unchanged from the preliminary results. These results demonstrate the benefits of our diversified oil-weighted portfolio and our commitment to allocate capital effectively, generate free cash flow and further strengthen our balance sheet. While we have been a publicly listed corporation for more than 25 years, we are taking steps to systematically transform Baytex. We have shifted our portfolio to predominantly high operating netback, light oil assets while also reducing our cash cost structure and improving capital efficiencies. More recently, we have refinanced our long-term notes and extended the term of our revolving credit facilities to 2024. These steps give us the confidence and flexibility to execute our business plan to continue driving free cash flow and strengthen our balance sheet. I'll pass the call over to Rod Gray, our CFO, in a few minutes to elaborate on the debt refinancing. 2019 was an exceptional year. Our operating results were strong. We maintained diligent capital and cost control, and we delivered on every facet of our business that we control. We produced 97,680 BOEs per day, 82% liquids, exceeding the high end of our annual guidance, while capital expenditures were at the low end of our annual guidance at $552 million. Production during the fourth quarter averaged 96,360 BOEs per day, and we hit all of our cost targets with operating expenses averaging $11 per BOE and general and administrative expenses under $1.30 per BOE. For 2019, we generated EBITDA of $1 billion and free cash flow of $329 million. In our 25-year history, this is the highest level of EBITDA and free cash flow that we have ever generated. And we delivered on our operating netback including hedging of $29 per BOE representing a 39% improvement over 2018. We also reduced our net debt by 17% or $393 million due to the strong free cash flow and the strengthening of the Canadian dollar relative to the U.S. dollar. We redeemed our $150 million principal amount of 6.75% senior unsecured notes, nearly two years early. We also demonstrated reserves growth with proved developed producing reserves increasing 5%, finding and development costs of $13 per BOE and a recycle ratio of 2.3x. In aggregate, we replaced 112% of 2019 production, adding 40 million BOEs of proved plus probable reserves through our development activities. In the Eagle Ford, strong well performance continues to be driven by enhanced completions across our acreage position. In the Viking, over 90% of our drilling was extended reach horizontal wells. In our heavy oil assets, we delivered stable production with limited capital investment. And we continued to advance our Duvernay light oil asset with two of the best wells in the East Shale Basin. We also recognized that developing environmentally and socially responsible energy plays an important role in raising the standard of living of people around the world. In 2019, we continued our excellent health, safety and environmental performance and published our fourth corporate sustainability report. This report demonstrates our commitment to transparency and to managing the environmental and social impacts of our business. We have elevated our standards, establishing a target to reduce our greenhouse gas emissions intensity by 30% over the next 3 years. We believe our safety and environmental leadership will serve us well as we continue to adapt to changing market conditions. I would now like to turn the call over to Rod to elaborate on our debt refinancing.

Thanks, Ed, and good morning, everyone. In 2019, we set a priority to strengthen our balance sheet. As Ed mentioned, we delivered on this commitment with a 17% reduction in our overall net debt. Subsequent to year-end, we further improved our financial position, taking several important steps to adjust our debt capital structure. First, we enhanced our long-term note maturity schedule, which provides us significant flexibility and liquidity to execute our business plan. On February 5, we issued $500 million of senior unsecured notes at 8.75% that mature on April 1, 2027. These notes are redeemable at our option, in whole or in part, at specified redemption prices after April 1, 2023. Using the net proceeds from the new 2027 notes, we redeemed $400 million of 5.125% senior unsecured notes due June 2021 at par on February 2020. We've also issued a redemption notice for the CAD 300 million 6.625% senior unsecured notes due July 19, 2022, and those will be redeemed March 6, 2020 at 101.1% of the principal amount. Following these redemptions, our only two long-term note maturities will consist of the $400 million note due June 2024 and the new $500 million note due April 2027. And second, we amended our credit facilities to extend the maturities of our revolving facilities and term loan, both to April 2, 2024. The credit facilities are not borrowing base facilities and do not require annual or semiannual reviews. Our facilities total approximately $1.05 billion and include $575 million of the revolving credit facility and a $300 million term loan. Following the $500 million note issue and the redemption of both the $400 million and CAD 300 million notes, our credit facilities are approximately 1/3 undrawn with over $300 million of liquidity and an overall weighted average interest rate of approximately 6%. Combined, these changes have extended our debt maturities and confirmed the available credit from our bank syndicate.

Thanks, Rod. Given the volatility in our capital markets today we're very pleased with our improved capital structure and the significant flexibility and liquidity we have today. Let's now turn our attention to operations, starting with light oil, Eagle Ford and Viking assets. Production in the Eagle Ford averaged over 38,000 barrels per day during the fourth quarter 2019 and 39,000 BOEs per day for the year. In 2019, we invested $178 million on exploration and development in the Eagle Ford and generated an operating netback of $416 million. This led to prolific cash flow of $238 million at an asset level. We commenced production from 25 net wells. The wells brought on stream during 2019 delivered average 30-day initial production rates of 1,900 BOEs per day per well, an 8% improvement over 2018 wells. Production in the Viking averaged 22,000 BOEs per day during Q4 2019 and 22,500 BOEs per day for the full year 2019. We invested $266 million on exploration and development in the Viking and generated an operating netback of $349 million. This led to $80 million of cash flow at an asset level. We drilled 244 net wells and commenced production from 240 net wells approximately 25% fewer wells in 2019 versus 2018 to hold our production flat. We also added 229 high-quality net drilling opportunities through multiple deals and asset swaps in the Viking. Moving to our heavy oil assets in Canada. Peace River and Lloydminster produced a combined 30,000 BOEs per day during the fourth quarter and 29,000 BOEs per day for the full year 2019. We drilled 40 net heavy oil wells, including 34 net wells at Lloydminster and 6 net wells at Peace River. We invested $80 million on exploration and development on our heavy oil assets and generated an operating netback of $188 million. This led to cash flow of $108 million at an asset level. Finally, in the East Shale Duvernay, we continue to advance the delineation of this early stage, high netback light oil resource play. In Q1 2020, we drilled 2 wells at Pembina, and completion activities are scheduled for Q2 2020. The success of our drilling program in the Pembina core area has significantly derisked our approximately 38-kilometer long acreage fairway where we hold 275 sections of 100% working interest Duvernay lands. Let's turn to risk management. We continue to manage our commodity price risk through an active hedging program. In 2019, we realized a financial derivatives gain of $76 million. All of our 2020 hedges are quoted in U.S. dollars. For 2020, we have hedges on approximately 48% of our net crude oil exposure, largely utilizing 3-way option structures that when WTI is between $50 and $58 per barrel, we receive $58 per barrel. And when WTI is below $50 per barrel, we receive WTI plus about $8 per barrel. The contracts also provide upside participation to approximately $63 per barrel. Our hedges also include WTI-based fixed price swaps for 3,500 barrels per day at approximately $57 per barrel. We also have in place both light and heavy basis differential swaps. For our light oil in Canada, we have WTI to MSW basis differential swaps for 4,250 barrels per day at $6.19 per barrel. For our heavy oil, we have WCS differential hedges on 5,500 barrels per day at a WTI to WCS differential of $16.25 per barrel. Additionally, crude by rail is an integral part of our egress and marketing strategy. For 2020, we have contracted 11,500 barrels per day, approximately 40% of our heavy oil volumes to market by rail. Full details of our hedge program can be found in our year-end financial statements. So now let me conclude by saying we have a high quality and diversified oil portfolio with an extensive inventory of drilling opportunities. We have a strong team and Board, all aligned in driving our strategic, operational and financial direction. Our commitment to shareholders remains to deliver stable production, generate free cash flow and further strengthen our balance sheet. Our 2020 annual guidance remains unchanged as we target production of 93,000 to 97,000 BOEs per day, with exploration and development expenditures of $500 million to $575 million. For Q1 2020, production is trending above 97,000 BOEs per day, with exploration and development expenditures of approximately $200 million, consistent with our plan and capital guidance range. Our exploration and development program is expected to be fully funded from adjusted funds flow at the forward strip, and we have the operational flexibility to adjust our spending plans based on changes in commodity prices. So with that, I will ask the operator to please open the call for questions.

[Operator Instructions]. Our first question comes from Phil Skolnick of Eight Capital.

Yes. Just with what you're saying about your Q1 production and the CapEx spending in Q1, how should we think about the cadence of -- throughout the year of both spending and kind of how your production profile should look through each of the quarters?

Yes. Good question. We typically come out with a fairly strong Q1 program and no different this year, where we're generating above high end of guidance on production. In Q2, we moved that capital down considerably. So in Q2, April and May are very limited in our Canadian asset spending and overall. So we don't pick up activity until about June, and we typically will use April and May to recalibrate our views of the macro, what's going on with pricing, where our cash flow is, and we'll make calls on our second half program during that period. But we fully expect to be free cash positive in the first half of the year, high CapEx in Q1, very low CapEx in Q2, strong hedge book, pricing on the differentials is good, our railing programs have been essentially uninterrupted on a week-to-week basis. We miss railcars on a day-to-day basis, but week-to-week, month-to-month, we're fine on blockades and things like that. So we're egressing all of our crude. We're looking strong for the first half of the year, and we'll make those calls fill on second half year program in April and May. But expect production to be high in Q1. It moderates through breakup in Q3, and we start coming back strong for the end of the year.

Okay. And so is the Q1 production rate, I mean, I guess, and that was due to Q4 activity. And so like how did you exit the year in production-wise in '19?

Well, 96,300 was our Q4 number. December number was a little bit north of that, but not much. So about 97,000, and we've basically been holding that pretty flat. But it's also providing new resources and pull-through to Q2 and Q3. So it does give us those additional barrels coming through the rest of the year.

Okay. And then my final question. Just we've seen differentials across the board, MSW and WCS narrowing significantly. Are you going to look to maybe take advantage of that to hedge a bit more as well?

Yes. Let me hit that in a second on the differential. We have been hedging there. But part of the reason for Q1 CapEx being where it is, is the Duvernay. And we did drill in case two wells, pretty exciting in that we've got those two wells down and ready to be fracked in June and July. So they're right in the heart of our best acreage, and we did spend the money in Q1 with, obviously, no production. So that was a bit of the spending in Q1. But on hedging, yes, we did layer on a couple of recent WCS heavy oil differential hedges. We're getting those around $16 a barrel. So our average now is $16.20, as I mentioned, on the financial derivatives. And we've put on some attractive rail contracts there at the end of sort of Q4. So we've been layering in. The other thing we've done is on MSW, where it's moved into $6 a barrel. We've been layering on some hedges there as well. But all of those additional hedges are included in the numbers I just quoted.

Our next question comes from Greg Pardy of RBC Capital Markets.

A couple of questions, but I'm going to turn Phil's question around a little bit. Would you consider really monetizing the hedges that you've got in place now? I think I know the answer to the question, but it's a big number, like it's over $100 million sitting on the books now. Just curious as to how you think about that?

Very important protection for us. I'll let Rod Gray address the question. We have looked at it recently.

Greg, we have looked at it. But the fact is, we've got the three way structures in place. And you've actually got two contracts that are probably out of the money and one that's in the money. So you'd be doubling down on the call back. I think we're a little north of -- depending on your time when you look at it, there was $90 million to $100 million of value in the, call it, puts that we owned. But there's also exposure on the other -- the call and the other sold put that we have out there. But we utilize the hedging program to moderate our cash flow and our expectations, and we're not looking to take speculative positions on that. So we wouldn't be looking to monetize that right now.

Okay. No. It's a good -- I think, it's a good thorough answer. The other -- well, I mean, maybe, again, just a little bit of what Phil was asking. I mean should we expect more than 97,000 BOE a day in 1Q?

Yes. We said we're trending above 97,000 barrels a day. And I would say, comfortably above 97,000 barrels a day. So we got another month to go, and we'll close here shortly.

Okay. And last thing is, I mean, you alluded to capital flexibility as to what you're going to do in the second half. But let's just say you decided to scale back the capital spend. We know you don't need to. But if you did, where we would you take the dollars out of?

Yes. We would probably, at this point in time, take it out of the heavy oil program. It's, again, premature there. But what I'm talking about is moderating down the low end of guidance. I think that's kind of where we're -- we're not talking about outside of guidance at this point on how we see our cash flow, how we see the year. Yes, everybody's panicked on pricing. But even as I said, at the forward strip, with a strong hedge program, with a strong set of operations underneath us, we're projected to be fully funded at the strip price within guidance. So that could be $500 million in capital versus the midpoint of $540 million and trending still within our guidance on production. So I'm not -- there's no reason we need to be talking outside of our guidance at this point.

Okay. And again, all of that would really be the Canadian heavy program?

Yes. Maybe not all, we would look to -- we might do some trimming in some other areas. But the heavy oil program, with the differentials where they are now, is similar to where we were at budget time when WTI was at $55 or $52 to $55, and the differential was between $17 and $20. We're not seeing the heavy oil margins drifting away on us. They're drifting down for sure, as everything is, but there's still good profitability in the heavy oil program. So we'll see where we get on that, Greg. But certainly, a chunk of the reduction in our capital program would come from heavy oil.

Our next question comes from David Popowich of CIBC.

My questions have already been asked.

Thanks, Dave.

This concludes the question-and-answer session. I would like to turn the conference back over to Brian Ector for any closing remarks.

All right. Thank you, Ariel. Thanks, everyone, for participating in our year-end conference call today. Have a great day, everyone.

This concludes today's conference call. You may disconnect your lines. Thank you for participating, and have a pleasant day.