Baytex Energy Corp

TSX:BTE

Earnings Call Transcript 2018-Q4

[Operator]

Thank you for standing by. This is the conference operator. Welcome to the Baytex Energy Corp. Fourth Quarter and Year-end Results 2018 Conference Call. [Operator Instructions] And the conference is being recorded. [Operator Instructions] I would now like to turn the conference over to Brian Ector, Vice President, Capital Markets. Please go ahead.

[Brian G. Ector]

Thank you, Ariel. Good morning, ladies and gentlemen, and thank you for joining us today to discuss our fourth quarter and year-end 2018 financial and operating results. With me today are Ed LaFehr, our President and Chief Executive Officer; Rod Gray, our Executive Vice President and Chief Financial Officer; and Jason Jaskela, our Executive Vice President, Shale 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 refer you to our advisories regarding forward-looking statements, oil and gas information and non-GAAP financial measures in the notice to U.S. residents contained in today's press release. On the call today, we will also be discussing the evaluation of our reserves at year-end 2018. 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 dollar amounts referenced in our remarks are in Canadian dollars unless otherwise specified. And I would now like to turn the call over to Ed.

[Edward D. LaFehr, President, CEO & Director]

Thank you, and good morning, everyone. I'd like to welcome everybody to our year-end 2018 conference call. 2018 was a defining year as we repositioned our company to a high netback light oil company with a stronger balance sheet. We did this by merging with Raging River to create a new Baytex with stronger assets and organizational capability than ever before. We have successfully merged our 2 companies, undertaken a detailed strategic review of our operations, confirmed the organic growth opportunities in our diversified portfolio of assets and delivered on our near-term operational targets.I am very excited about our operating performance post the merger. And we are well positioned to execute our business plan and further strengthen our balance sheet in 2019. I will start with fourth quarter results, and I would characterize the quarter this way. Our operating results were strong, we exceeded our volume expectations and full year guidance, and we maintained diligent capital and cost control. We delivered on every facet of our business that we control. The only unfortunate aspect of the quarter was delivering these strong operating results during a period where we saw sharp decline in crude oil prices, including a significant widening of Canadian light and heavy oil differentials. As we sit here today, the commodity markets have improved markedly, both globally and in Canada, which points to stronger financial results moving forward compared to Q4 2018. We delivered production of approximately 99,000 BOEs per day in Q4 '18 and 80,500 BOEs per day for the full year, exceeding our annual guidance. And we did so with capital spending for full year of $496 million, which was in line with our annual guidance. We generated adjusted funds flow of $111 million in Q4 2018 and $473 million for the full year 2018. And our cash costs, inclusive of operating expenses, transportation expenses and G&A were reduced by 4% for 2018 as compared to the midpoint of our original guidance. We also maintained strong financial liquidity with our credit facilities 50% undrawn and net debt totaling just over $2.2 billion at the end of 2018. I'm also pleased with our reserves performance in 2018, especially as it relates to our proved developed producing, or PDP reserves. Reflective of our strategic combination, PDP reserves increased 35% from 100 million BOEs to 135 million BOEs. Proved reserves increased by 23% from 256 million BOEs to 315 million BOEs. And proved plus probable or 2P reserves increased by 22% from 432 million BOEs to 527 million BOEs. We also enhanced the quality of our reserves base, adding high-value light oil in the Viking and Duvernay. These reserves, associated with the Raging River assets, increased by 4% on a 2P basis as compared to year-end 2017. More specific to Viking, our PDP reserves are up 1% as compared to year-end 2017, while our 2P reserves are within 1% of year-end 2017.Overall, we replaced 106% of our production, adding 31 million BOEs of 2P reserves through development activities. Inclusive of the merger, we replaced 422% of total 2018 production. On a PDP basis, our F&D costs were $15.82 per BOE, which generated a healthy PDP recycle ratio of 1.5x. And lastly, with respect to our reserves, our net asset value discounted at 10% is estimated to be $7.27 per share based on the estimated reserves value of $6.2 billion plus a value for undeveloped land, net of long-term debt, asset retirement obligations and working capital. Now I will briefly summarize our operations, beginning with our light oil assets in the Eagle Ford and Viking. In the Eagle Ford, we continue to see strong well performance, driven by enhanced completions in the oil window of our acreage. Production averaged over 38,000 BOEs per day in Q4 2018. For the full year, we commenced production from 26 net wells, which established average 30-day initial gross production rates of approximately 1,750 BOEs per day. This represents a 20% improvement over 2017. In the fourth quarter, we commenced production from 31 gross or 5.9 net wells, which averaged 30-day IP rates of 1,800 BOEs per day per well. Six of these were new appraisal wells in our northern Austin Chalk fracture trend and demonstrated 30-day IP rates of 1,600 BOEs per day per well.Moving to our Viking light oil. The first quarter contribution from this asset was very strong. During the fourth quarter, production averaged just under 24,000 BOEs per day, which is up from 22,000 BOEs per day for the August 22 to September 30 time frame. We maintained a steady pace of development over the quarter with 5 drilling rigs and 1.5 frac cruise executing our program. This resulted in 65.5 net wells.Moving to our heavy oil assets in Canada, our Peace River and Lloydminster heavy oil assets produced a combined 26,000 barrels per day in the fourth quarter, a slight decrease compared to 27,000 barrels per day the previous quarter. These reduced volumes represent the optimization of our heavy oil program in response to the volatile heavy oil prices in Q4. At Peace River, we drilled 12 net oil wells in 2018, which delivered average 30-day initial production rates of approximately 500 barrels per day per well. This program included 8 net wells in our northern Seal area, which delivered 25% higher than these rates from our field-wide average.At Lloydminster, we drilled 61.9 net wells in 2018, and we also successfully completed the expansion of our Kerrobert thermal project during the fourth quarter.Finally, at our Duvernay shale, light oil asset, we continue to prudently advance the delineation of this early-stage, high netback resource play. In Q4, production more than doubled from Q3 to 1,400 BOEs per day. Our focus has shifted to the Pembina area where we control over 270 sections of 100% working interest land. With 5 wells on production in the core of our Pembina area now, we have derisked approximately 35 sections of land, representing 175 potential drilling opportunities.These wells generated average 30-day initial production rates of 575 BOEs per day per well, 88% oil and liquids. Let's turn now to risk management. We continue to manage financial risk through an active hedging program. For 2019, we have entered into hedges on 30% of our net crude oil exposure, primarily utilizing 3-way options, which have been yielding an average price of approximately $63 per barrel year-to-date. Additionally, crude by rail is an integral part of our egress and marketing strategy for heavy oil. For 2019, we are contracted to deliver 11,000 barrels per day or approximately 40% of our heavy oil volumes to market by rail. You'll find the full details of our hedge program in our year-end press release and the notes to our financial statements. And finally, as we look ahead in 2019, we are executing our business plan, and we are well positioned to further strengthen our balance sheet. We are on pace for $155 million of capital expenditures in Q1 2019, which remains consistent with the midpoint of our capital guidance range of $600 million with approximately 80% of those expenditures being directed towards our high netback light oil assets in the Eagle Ford and Viking. Excellent well performance in the Eagle Ford and outstanding operating efficiency across all of our assets has Q1 2019 volumes trending ahead of expectations at over 97,000 BOEs per day. With WTI currently trading at $57 a barrel and the narrowing of Canadian differentials, we are forecasting a substantial positive impact on our adjusted funds flow. As I've mentioned in the past, in recent calls, further deleveraging remains a top priority. Based on the forward strip for 2019, our adjusted funds flow forecast has increased 32% from $605 million to approximately $800 million. This will allow up to $200 million of debt repayment, while maintaining production at the midpoint of our guidance of 95,000 BOEs per day.And lastly, I would like to highlight some board and management changes. We have an ongoing board renewal process led by our nominating and governance committee. As part of this renewal process, Ray Chan and Gary Bugeaud have decided not to stand for election as directors at our May 2019 Annual Meeting of Shareholders. Mr. Chan has been instrumental in guiding Baytex over the last 20-plus years, serving numerous executive positions during this time, including nearly 10 years as Chairman. For me, personally, he has always operated with the highest integrity, and has been a mentor to me over the past 3 years and has truly helped me navigate these challenging times. His hard work, dedication, thoughtful guidance for the benefit of all stakeholders is greatly appreciated. I would also like to thank Mr. Bugeaud, who has been involved with Raging River and its predecessor companies for the past 15 years. In addition, Rick Ramsay, our Executive Vice President and Chief Operating Officer has elected to retire on April 5, 2019. Mr. Ramsay has been with Baytex since January 2010 and has been a key leader for the organization, managing the successful development of our Peace River assets and subsequently, guiding all of our North American operations. I would like to thank Rick for his outstanding contributions and wish him well in his retirement. I am very pleased that Jason Jaskela will assume the role of Executive Vice President and Chief Operating Officer in April. Jason is a professional engineer with 19 years of industry experience. Many of you will know Jason as he was previously the Chief Operating Officer at Raging River.So to conclude, in 2018, we repositioned our company through our strategic combination with in -- which increased our high netback light oil assets while also deleveraging our balance sheet. Our operations are performing exceptionally well with excellent Q1 production and funds flow in excess of Q1 capital spending. We are also benefiting from a meaningful improvement in crude oil prices in Canada and on the Texas Gulf coast, which is expected to have a very positive impact to our adjusted funds flow.We will remain disciplined with respect to capital allocation, targeting 2019 expenditures of $550 million to $650 million, and expect to deliver average annual production of 93,000 to 97,000 BOEs per day. We are committed to delivering per-share value with a target of providing investors with a 10% to 15% total annual return. In 2019, we expect to generate meaningful free cash flow, as I've said, as we strive to reduce our debt to cash flow ratio to 1.5x in the near to medium term. And over the longer term, we believe we can offer returns through a combination of organic growth, dividends and/or share buybacks. And with that, I will conclude my formal remarks and ask the operator to please open the call for questions.

[Operator]

[Operator Instructions] Our first question comes from Greg Pardy of RBC Capital Markets.

[Greg M. Pardy, Managing Director and Co]

Thanks for the rundown. Just -- I guess a couple of areas to dig into a bit. Could you just maybe give us a sense as to what the duck count is in the Eagle Ford? And maybe just the slight adjustment you made on drilling locations? Could we start there?

[Edward D. LaFehr, President, CEO & Director]

Sure. The duck count last year, as I was talking about, it was running about in the 80s gross count for us. By the end of the year, that had moved to the mid-60s, and our target this year of course influencing the operator rather than controlling the outcome is to drive that down into the mid- to low-40s. So what was the second question on the drilling count?

[Greg M. Pardy, Managing Director and Co]

Just on -- yes, just on some of the locations that you would have adjusted in the Eagle Ford?

[Edward D. LaFehr, President, CEO & Director]

Yes. I don't think there was really any substantial adjustment. In the Eagle Ford, we were running about 250 to 260 net booked locations, if that's what you're talking about in 2017. And this year, we're looking at about 234. We drilled 21 wells though so that reduced the 260-ish down to 240. And we reduced the net count then by about 6 net wells, if that works for you.

[Greg M. Pardy, Managing Director and Co]

Okay. Yes, that's fine. And then just switching over a little bit on the crude by rail. I guess first, do you have more appetite to take additional crude by rail? And then could you just walk us through the -- a range that you have, where you're really selling that at a fixed price to WTI?

[Edward D. LaFehr, President, CEO & Director]

Yes. We are railing today 11,000 barrels a day, which is about 40% of our total heavy oil production. And I had targeted internally for the team to get about 50%. So that's another 1,000 or 1,500 barrels a day we'd like to put on. Of that 11,000, 8,000 are moving from Peace River -- 7,500 moving from Peace River and all of that is moving to the Texas Gulf Coast in Tuscaloosa, Alabama. So we would like to put on a little bit more. There are some rail constraints that still exist. There is also some pricing that needs to be right for all of us. But we're in the money on pipe economics right now. But having said that, crude by rail has been and continues to be a critical part of, not only our pricing formula, but our egress formula. So in terms of pricing, whenever we move to around an $18 to $20 differential or higher, we want to be railing. And whenever we're less than $18, we want to be on pipe. Having said that, these are contracted barrels, and we're not flexing away from those barrels. These are contracted barrels. It's not necessarily send or pay or take or pay, but it's best endeavors. And we value the relationships we have in the egress, it gives us to the particular market that we run to in the Gulf Coast. So that may be a little bit more than you were looking.

[Greg M. Pardy, Managing Director and Co]

No. It's okay. That's helpful. And just to be sure, I mean the spreads you're quoting then are versus TI, they're WCS, WTI spreads?

[Edward D. LaFehr, President, CEO & Director]

Yes.

[Greg M. Pardy, Managing Director and Co]

Okay. Okay. Great. But the other piece of it is -- I know that you guys have sold your selling I think at Peace River at write-off WTI, and I'm just trying to understand how that works?

[Edward D. LaFehr, President, CEO & Director]

Yes. Those are getting into more specific marketing arrangements, Greg. We're happy to talk off-line, but we don't -- we won't talk about our specific marketing relationships and pricing that we have with our broker into the Gulf Coast.

[Operator]

Our next question comes from Thomas Matthews of AltaCorp Capital.

[Thomas Matthews]

Just have a few questions. Just -- do you guys have any shut-in volumes still outstanding? I know that you were shutting in some barrels in Q4 to reflect the differentials. But have those been brought on again, in Q1?

[Edward D. LaFehr, President, CEO & Director]

Yes. Thomas, we did bring on those volumes mostly in January, some in February as well. We had about 1,200 barrels a day curtailed in January and February. We have nothing curtailed today in terms of the Alberta requirements. So we're moving ahead with nothing curtailed, bringing back all of our heavy. Our heavy is definitely making strong margins. It's good profitable oil right now, and so we're flowing into that market.

[Thomas Matthews]

Sounds good. And then just with the recent earthquakes in the Red Deer area. I know that some of the offsetting operators have been, or one in particular obviously has been, restricted on their fracking operations in the Duvernay. Just kind of wondering if that is filtered into your area? Or have you -- has there been any AER requirements to control fracking?

[Edward D. LaFehr, President, CEO & Director]

Well, all we're doing right now -- and I'll let Jason talk about this more specifically, but we're drilling 4 wells in the first quarter. We're not fracking any wells. We'll be fracking this summer starting in June on those 4 wells. We're in a very different area. We're 60 miles to the north and the west. We're in a more virgin area, I'm not sure exactly where it was, I think it was in the heart of the best area that was in the press. But we'll certainly stay on top of it and manage our business such that we mitigate any risk that exists. Jay, do you have anything to offer there?

[Jason Jowill Jaskela]

Yes. Absolutely. I think the AER submitted or disclosed a document that says that [ Baytex ] has to submit by March 11 the seismic data array information, the frac reports and then all their future frac plans. I think the AER will assess that and make sure that it complies with subsequents of order 2. And I expect thereafter, they'll get back to normal operations. I think it's just a precautionary measure on the AER's behalf, and I don't expect anything long-term from it.

[Thomas Matthews]

Okay. Sounds good. Just so on the oil reserves, just was looking at some of the technical revisions there and there was a lot of positive technical revisions on the tight oil side, which, I'd assume, is all Eagle Ford. I know there's been some good wells drilled over the last year, but just wondering if those technical revisions, if that trend is expected to continue? Does that respond in a type-curve revision from you guys? Or just how much of that is kind of Eagle Ford versus Austin Chalk? Just trying to understand the positive oil revisions there. Obviously, it came with a little bit of negative NGL and gas revision as well, but oil is more profitable clearly. So just trying to understand the dynamics with that technical revision there.

[Edward D. LaFehr, President, CEO & Director]

Right. I would say in the Eagle Ford, these -- the revisions in the proved area, the probable area and the 2P were all very -- relatively small and well within kind of the historical range. There are pluses and minuses. As you say this year, there were more pluses than minus, positive technical revisions than negative, largely due to the technical complexity of the reservoir. So as you mentioned, in the volatile window, where we have solution, gas, oil and condensate, it just depends how these are classified through NI 50-101. So we run through that rigor every year and sometimes things move around a little bit. But in terms of the liquids to gas ratio, everything is still running very strong in terms of -- this is 78% to 80% total liquids, 58% crude, 22% NGLs and then 22% dry gas. So it's very much on historical par, if I can call it that.

[Thomas Matthews]

Okay. Yes. So no major kind of philosophy changes from your end there?

[Edward D. LaFehr, President, CEO & Director]

No. And we're taking a conservative view I think on some of the new well performance as you saw on our 2P reserves. We haven't booked to the higher performance we're seeing on the initial, call it, IP 365s on these new wells that we've drilled over the last year, 1.25 year. So we're taking a conservative approach with respect to the new well performance.

[Thomas Matthews]

Okay. And I assume that conservative approach filters down to the Viking. If I remember from my Raging River coverage, they were always pretty conservative booking their Viking. I know -- again, some offsetting operators have taken some technical revisions down on the total recoveries from the Viking, didn't notice anything in your reserve report here. So I had assumed that the bookings are -- you're comfortable with the bookings from the Viking perspective?

[Edward D. LaFehr, President, CEO & Director]

Absolutely. We spent a lot of time on that during the merger and in our due diligence, and the PDP reserves are plus 1%, the 2P reverse are minus 1%. So we're very pleased with where we are with respect to the outcome. But there are a number of things in the inner workings of the Viking that are complex. There are 9,000 wells now in the trend, and we've change our development philosophy. We're moving more to a flat profile than a growth profile and one that generates free cash flow as opposed to growth. So we've changed some of our development thinking from that standpoint. The other thing we've changed is, we're moving aggressively towards extended reach horizontal wells. 85% of our program this year is extended reach horizontals. So when you bake that all into the reserves, basically, as you say, we think Raging River, we're conservatively booked, have a good set of reserves management and have a undeveloped booking component that comes in every year. The conveyer belt is working very well. There was no impairment on the asset, as we saw with some other competitors. So it's a philosophy that Raging River adopted that we've also employed that we think is conservative and prudent. But the development plan has changed somewhat.

[Thomas Matthews]

Okay. And then final question, I promise. Just on the free cash flow. I know there was a clear message in the press release about paying down debt and getting to that 2.2x debt to EBITDA. But just hypothetically, under what circumstances would you see a back half increase to that budget? Just to maybe accelerate a little bit of growth through your end and into 2020? Or is that just something that's not quite on the table for this year?

[Edward D. LaFehr, President, CEO & Director]

Well, those are April, May decisions. Right now, we've got approved in our capital budget, the low end of guidance around $550 million. But we have discretionary spend of about $65 million that we'll be looking at whether or not to implement. We need to continue to see -- we need to see 2 things: continue to see strong pricing; and number 2, we need to see real tangible evidence of additional egress from Western Canada. And that means shovels on the ground on TMX or line 3 and/or crude by rail ramping up to significant volumes around the 400,000-barrel a day range. That would give us the confidence then to go more towards the high end of our guidance.

[Operator]

Our next question comes from Phil Skolnick of Eight Capital.

[Philip Ross Skolnick, Managing Director of Energy Research]

Just looking at -- when you talk about your Q1 production rate of slightly over 97,000 barrels a day, was that above expectation? I mean, it sounds like it, based on the wording in the press release. And how should we think about the trajectory, come out breakup season? Because it seems like that maybe there might be some upside to your production target just based on that.

[Edward D. LaFehr, President, CEO & Director]

Yes. I think, Phil. We expect it to be a 97,000 barrels a day even with the shut-ins. Q1 was always going to be strong. We're bringing back inventory that we built up and some our optimization we had shut-in, in Q4. So we expected it to be strong. We're running -- obviously, whatever we say publicly is going to be conservative, so we're running very strong in Q1. But Q2 is always our seasonal downswing. So we've got lumpy quarters and that's when we see breakup. Obviously, that impacts both the heavy oil and the Viking. So we'll see high in Q1, we move lower in Q2, stabilize in Q3, and we deliver midpoint of guidance.

[Operator]

Our next question comes from Brian Kristjansen of Macquarie Capital Markets.

[Brian Kristjansen, Research Analyst]

You mentioned, in response to Thomas' question, changing the development in the Viking. Does that imply any change to the existing sort of 13 extended reach wells per section? Or the 22 shorties per section? Or is that just a matter of pacing?

[Edward D. LaFehr, President, CEO & Director]

Why don't I turn this over to Jason, getting into the specifics of the development?

[Jason Jowill Jaskela]

Sure. It really is just replacing longer wells with shorter wells. It doesn't really change number of wells in the section, but that really is backed into from -- backed into an oil in place [indiscernible]. So it really is simply just replacing long with shorts -- shorts for long, sorry.

[Operator]

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

[Brian G. Ector]

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

[Operator]

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