Baytex Energy Corp. (BTE) Q1 2018 Earnings Report, Transcript and Summary

Thank you for standing by. This is the conference operator. Welcome to the Baytex Energy First Quarter 2018 Conference Call. As a reminder, all participants are in listen-only mode and the conference is being recorded. After the presentation, there will be an opportunity to ask questions. [Operator Instructions] I would now like to turn the conference over to Brian Ector, Senior Vice President, Capital Markets and Public Affairs. Please go ahead.

Thank you, Arielle. Good morning, ladies and gentlemen, and thank you for joining us today to discuss our first quarter 2018 financial and operating results. With me today are Ed LaFehr, our President and Chief Executive Officer; Rod Gray, our Chief Financial Officer; and Rick Ramsay, our Chief Operating Officer. 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 yesterday's press release. 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.

Thanks, Brian, and good morning everyone. I'd like to welcome you to our first quarter 2018 conference call. I am pleased to report that we have successfully executed our first quarter plan, which puts us on track to deliver our 2018 guidance. In the Eagle Ford, we achieved record production rates from new wells and our strongest operating netbacks since 2014. In Canada, we continued to focus on cost and capital efficiency while managing WCS pricing volatility through active hedging, crude by rail, and operational optimization. Our first quarter production was 69,500 BOEs per day, consistent with our expectations. We delivered adjusted funds flow of $84 million and exploration and development capital expenditures totaled $94 million for the quarter. Excluding realized financial derivatives, gains and losses, adjusted funds flow in Q1 2018 was $94 million compared to $104 million in Q4 2017. This was achieved despite headwinds from wide heavy oil differentials, which averaged US$24.28 per barrel. This represents our second-highest quarterly adjusted funds flow on unhedged basis since mid-2015. These results demonstrate the benefit of our heavy and light oil dominated asset portfolio. Let's turn now our attention to operations. In the Eagle Ford, well performance in Karnes County remains exceptional. In addition, early results from Atascosa County are encouraging as we exploit the oil window on the western portion of our lands. We directed 45% of our capital expenditures toward these assets during the first quarter and production averaged 36,000 BOEs per day. Eagle Ford wells that commenced production during the quarter have established 30-day initial gross production rates of approximately 1,750 BOEs per day per well, which represents a 20% improvement over wells brought on production in 2017. This strong well performance is largely attributable to enhanced completions. During the first quarter, we averaged 6,200 foot laterals with 29 effective frac stages and approximately 2,100 pounds of proppant per foot. At US$65 WTI, these wells yield greater than 100% IRRs with payouts of less than one year. Turning to Canada, we are executing our 2018 drilling program as planned while also driving our cost structure lower. At Peace River, production was stable during the first quarter, averaging 16,500 BOEs per day. We drilled three net wells in the quarter including two multi-lateral horizontal wells at Reno and one on our northern Seal acreage, the acreage that was acquired in January of 2017. Given the wide WCS differentials in Q1, we deferred the completion of these wells until second quarter. At Lloydminster, production averaged 10,000 BOEs per day, up from 9,600 BOEs per day in the fourth quarter. We drilled 20 net crude oil wells in the first quarter. Four operated wells drilled in late 2017 established an average 30-day initial production rate of approximately 200 barrels per day per well. Additionally, we completed the drilling of three net SAGD well pairs at our Kerrobert thermal project. Production at Kerrobert averaged 700 BOEs per day in the first quarter and we expect to exit 2018 producing approximately 2,000 BOEs a day from this project area. Let's now shift to our financial results. Before I discuss our corporate level operating netback, I would like to take a minute to remind everyone of the strong pricing environment we are seeing in the Eagle Ford. Our light oil and condensate production is priced off of LLS, which is a function of Brent price. As a result, we are currently benefiting from a widening of the Brent-WTI spread. In addition, increased competition for physical field supplies has resulted in improved price realizations relative to LLS. During the first quarter, our light oil and condensate price in the Eagle Ford of US$63.16 per barrel represented a premium to WTI. This strong pricing environment contributed to an exceptional operating netback of $32.48 per BOE in the Eagle Ford, a level we have not seen since 2014. As of today, current Eagle Ford price realizations have further increased to approximately US$68 per barrel. In Canada, we generated an operating netback of $8.04 per BOE, which was driven by the wider WCS differentials I alluded to earlier. Subsequent to quarter end, the WCS price differential has improved with the May index averaging US$16.92 per barrel, and early trading for the June index is even tighter. In aggregate, our diversified oil portfolio generated a corporate-level operating netback of $20.71 per BOE, excluding hedging. We also continue to drive cost and capital efficiency in our business. During the first quarter, our operating, transportation and G&A expenses totaled $13.65 per BOE, 3% below or better than the midpoint of our annual guidance. Our financial liquidity remained strong with our US$575 million revolving credit facilities, 70% undrawn and our first long-term note maturity not until 2021. In April, we extended the maturity of our revolving credit facilities by one year to June 2020. These facilities are covenant based and do not require annual or semi-annual reviews. We also elected to end the covenant relief period that was set to expire on December 31, 2018 to benefit from reduced borrowing costs. We are well within the revised financial covenants of these facilities. We also continue to manage financial risk through an active hedging program. For the balance of 2018, we have hedges of approximately 55% of our net crude oil exposure and 36% of our net heavy oil differential exposure. For 2019, we have entered into hedges on approximately 15% of our net crude oil exposure. You will find the details of our hedge program in our press release and the notes to our financial statements. As part of our risk management program, we also transport crude oil to markets by rail when economics warrant. In Q1 we delivered 6,500 barrels per day or 25% of our heavy oil volumes to market by rail, up 5,000 barrels a day in 2017. We have secured additional rail capacity, which will increase our crude by rail oil volumes to 8,000 barrels per day in Q2 2018. Let me now conclude by saying, our first quarter results are on track to achieve our 2018 guidance. While the widening of the WCS differential created some headwinds in the first quarter, we achieved the second-highest quarterly adjusted funds flow on an unhedged basis since mid-2015. This demonstrates the quality and resiliency of our oil portfolio. Our 2018 production guidance range is unchanged at 68,000 to 72,000 BOEs per day, with budgeted exploration and development capital expenditures of $325 million to $375 million. As oil prices rise, we are poised to generate significant free cash flow going forward. We are excited for the remainder of 2018 as we continue to execute our plans for the ongoing benefit of all of our stakeholders. And with that, I will ask the operator to please open the call for questions.

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

Ed, could you talk just a little bit about the running room that you see in the Eagle Ford, and then specifically what the program might look for in terms of the Austin Chalk this year?

Sure Greg. It's an exciting program we have. In Q1 we ran three rigs and two frac crews. For the rest of the year, we are running actually two to three rigs and one to two frac crews. We'll probably add a third frac crew, a spot crew, in 3Q to work down the duck inventory. So, we do have an inventory of wells we want to bring online as efficiently as possible and we need frac crews to do that, not rigs. So, we expect to bring on about 30 net wells. Plan is unchanged as per what we announced some time ago and we are pretty excited about the results we are seeing. On Austin Chalk, we'll drill five to six wells this year. Three will be direct offsets to the 2,400 barrel a day wells that we brought on a few months ago. Those were really exciting to see. And three will be appraisal wells, really testing the extent of the play further to the west across the [Excelsior] [ph] block, or in towards that area, not onto the [Excelsior] [ph] block yet but towards that area, and then also how far south does this trend move away from the main Karnes Trough [indiscernible], and that will delineate kind of the question on how big is this inventory. But overall, inventory hasn't really changed. We announced our reserves increases on 2P reserves back in February-March, and it's looking like a decade of wells at this pace, 30 net wells per year at a net well count of about 400. So that's over a decade of inventory.

Okay, perfect. And then maybe just as a second, a few questions just coming up about just your debt levels as of March 31, and despite the cash flow not the deleveraging, but to what extent is just FX playing into that?

Rod, did you want to speak to FX and the changes? It's not really been that big a change actually.

Not significant, Greg. It's Rod here. The FX rate is moving around and a good majority of our debt would be based in U.S. dollars, and so we revalue that at every quarter end. And so, you see the movement in our overall aggregate debt level as those get restated.

I would say, Greg, on kind of the direction of your question with respect to debt, I said when I came in it was a high priority. We had a 1A and a 1B, if you want to call it that. The first one was to sustain the business and ensure that we could hold the relevance and profitability of the business at around 70,000 barrels a day. We were in decline for a couple of years through the downturn. Second priority right on the heels of that, and in fact this year we believe we have an opportunity to take a step towards deleveraging. But the first step in that, given my view on the macro picture, which I talked extensively about yesterday at our AGM, was bullish and we needed to be patient to see prices move up, which then give us more optionality and better valuations on our properties if and when we decide to move into an A&D, a portfolio manoeuvring process. So, that's still on the cards very much, Greg, and we are pursuing all options still, but this is a much better time for it than in mid-2017 or even late 2017 when we were still not seeing a $60 price handle on WTI.

Okay, great. And then the last piece, notwithstanding what you just said is, to the extent you have free cash flow this year, is your inclination to take spending up or generally to think about putting that on the balance sheet?

Right. I know you and others have pushed us on that before. I really like our level-loaded plan now. We kind of haven't waffled since the WCS blew out in Q1. It's tightened back kind of the way we saw it coming, full cost of rail at $17 to $20. So, we are sticking with our plan, both in the Eagle Ford and in Canada. We think it's a properly loaded plan this year, almost regardless of price. So, we are going to stay with it. If we see prices continue to stay up and move up at this point in the year, it's still a bit early. We would probably put that money back to the revolver. If it's 20 million, it would be a nice problem to have, because then we could look at our options to grow further and add another rig to Peace River for example or to pay down debt. My current inclination is, we would put it towards paying down the debt.

All right, very good. Thanks very much, guys.

Our next question comes from Phil Skolnick of Eight Capital.

On your rail, how much of it goes down to the Gulf Coast and can you comment anything about the cost? And more importantly, what kind of realized pricing you are getting like relative to Maya in particular?

We'll have to be a little careful on the pricing but we can say a few words on that just with respect to competitive dynamics within the industry and also protecting the people we do business with. But we are today railing about 7,000 barrels a day out of Peace River. Those are manifest trains that move to the Hunt Refinery in Tuscaloosa, Alabama. So that's basically right on the Gulf Coast and receiving attractive pricing. The other 1,000 barrels a day or more, piggybacking train availability or carload availability in the Lloyd last burn, were [indiscernible]. We have been able to secure 1,000 barrels a day. We are hesitant to go too long term on this stuff, but right now we were railing 5,000 barrels a day in December last year. I said then I wanted to double it to 10,000. This year we have gotten to 8,000 and we are still moving it. The Lloyd barrels, correct me if I'm wrong here guys, but I think the Lloyd barrels moved towards Pad 2, don't make it to the Gulf Coast, but we actually don't know, we don't control where that product goes directly to the market. In terms of pricing, we need to be a little careful what we say there, but there is certainly a benefit to WCS volatility. It's been in the order of $3 to $5 kind of range. But I hate to say anything too much more than that. But it is certainly a benefit and it's part of our hedging mechanism for continuing to produce our barrels at attractive profitability.

Okay, thanks. Just another question, on the Eagle Ford, I mean you've mentioned in the past that you could look to sell a good portion of that to help accelerate the deleveraging. I mean are you – in your last call you said that the bid asks are kind of getting out to an attractive point. Are they even more attractive now, especially given what your comments about the pricing in the Eagle Ford, like why not now try to do something like that and really accelerate that debt reduction?

That's a great question, Phil, and it's one that I sort of addressed with Greg, but yours is more specific. I think the bid ask spread is coming together. Our cash flows are also increasing quite dramatically. So, our view in terms of, if you want to put a 5x cash flow multiple on our cash flow or a number based on transactions in the area, we have higher expectations of what these properties are worth. Are we looking at diluting? I would say we are looking at everything including dilution, but we are also looking as these cash flows gives us opportunities to consider other options, and our debt to cash flow, as I think one of you mentioned, has moved from 7x last year to 4.8x at the beginning of this year. We are looking at a 3 handle now moving into 2019, and I know we are not back to the peer group yet but I think it could be, it's perhaps a different transaction than what we might have been contemplating in a $50 world than today. So, we don't talk about M&A, Phil, as you know, but we are in active dialog around how we can move our debt to cash flow back into a competitive realm.

Okay, thanks.

Our next question comes from Patrick Bryden of Scotia Bank.

Just a quick question, I noticed, Ed, the Alberta government has put together a working group on crude oil by rail, and I was just wondering if you could maybe lend us some of your perspectives, given you got a background that's globally got good perspectives on the U.S., can you maybe give us a sense for how you are trying to navigate the pipeline issues and how much mitigation you think there ultimately is from the crude by rail option? Thank you very much.

We were as excited as anybody to see that the Premiers and the minister have called these meetings. We are not one of the companies that at least to my knowledge have been invited to these meetings at this point. But it will probably be the three to five big, large producers and large railers. So, we are not involved in that. But we are actively in many different ways, for example yesterday at the AGM, we are supporting Canada action. I believe having been around the world that we produce some of the cleanest, greenest, most ethically responsible, socially responsible energy in the world, and that message is not getting out there. And so, we as a team in Baytex and as a company are very proud of what we've done. We are very pleased to see our name being cited on the Corporate Knights report sponsored by Globe and Mail and the Washington Post Rank # [26] [ph] in a group of elite companies. So, we are quite pleased with that, but we are not there yet as a nation in terms of our energy policy. And [indiscernible] will go through, there is no reason [indiscernible] should not go through, and for me Line 3 Enbridge expansion should be the simplest and most obvious of all three of them. So, I think it's very likely by 2020-2021, we'll be looking at three pipelines, maybe one on the ground and one started, another one happening, it's very likely that will be the outcome despite we have got a bit of dysfunctionality quite honestly within the political regimes. But I think we'll get our act together. We are optimistic. We are bullish on the product is needed in the Gulf Coast more than any time I have seen in my history in the oil business, just now 30-plus years. The Canadian WCS heavy product with the lack of Venezuelan, Mexican, Saudi heavy sour, is coming off the market and other products are in need of a blend that requires Canadian heavy oil. So, the question is, just how do we get our arms around getting these three lines built and move down to Gulf Coast, and that's without mentioning anything about how attractive our product both on the gas and the oil side looks to Asia, coming off the West Coast to Canada. So, with that, Patrick, it's a bit of a ramble, but we are very, very pro Canadian energy playing a bigger role in the world oil mix that's due to cross 100 million barrels a day usage consumption by mid this year.

Thanks for that. And just maybe getting to the crude oil rail sort of mitigation more specifically, like are you seeing more deals happen, more flow on that front that's helping them?

I mentioned, we have moved our 5,000 to 8,000 but it's been in small tranches. We would like to do bigger tranches. But we have done a couple of thousand barrels a day tranches in Peace River and we have done another 1,000 now as I mentioned in Lloyd. We could do more than that, we'd like to do more than that, we are seeing some availability come into play, but it's on a very selective and ad hoc basis. So, we are not getting the attention of the railers we ourselves because we are not a huge volume producer in heavy. And actually everybody is sitting in the queue in my mind, and this is my personal opinion, we are all sitting in the queue behind those two large producers who are in active negotiations with those railing companies.

Understood. Appreciate the color. Thank you.

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

All right, thanks operator and thanks everyone for participating in our first quarter conference call. Have a great day.