Baytex Energy Corp

TSX:BTE

Earnings Call Transcript 2018-Q1

[Operator]

Thank you for standing by. This is the conference operator. Welcome to the Baytex Energy First Quarter 2018 Conference Call. [Operator Instructions] This conference is being recorded. [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.

[Brian G. Ector]

Thank you, Ariel. 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.

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

Thanks, Brian, and good morning, everyone. I'd like to welcome you to our first quarter 2018 conference call. I'm 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 net back since 2014. In Canada, we continue 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 in 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 USD 24, USD 28 per barrel. This represents our highest -- our second highest quarterly adjusted funds flow on unhedged bases 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 growth 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 profit per foot. At U.S. $65 WTI, these wells yield greater than 100% on IRRs with payouts of less than 1 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 3 net wells in the quarter including 2 multilateral, horizontal wells at Reno and 1 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 average 10,000 BOEs per day, up from 9,600 BOEs per day in the fourth quarter. We drove 20 net crude oil wells in the first quarter, 4 operated well drilled in late 2017 established at average 30-day initial production rate of approximately 200 barrels per day per well. Additionally, we completed the drilling of 3 net [ site ] well cares 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 net back, 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 fuel 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 USD 63, [ $1.16 ] per barrel represented a premium to WTI. This strong pricing environment contributed to an exceptional operating net back 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 USD 68 per barrel. In Canada, we generated an operating net back 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 USD 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 net back 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 remains strong with our USD 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 1 year to June 2020. These facilities are covenant based and do not require annual or semiannual reviews. We also elected to end the covenant release 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 in the 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 bases since the 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 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 the 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]

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

[Greg M. Pardy, Managing Director and Co]

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?

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

Yes. Sure, Greg. It's an exciting program. We have in Q1, we ran 3 rigs and 2 frac crews for the rest of the year. We're running actually 2 to 3 rigs and 1 to 2 frac crews, we'll probably add a third frac crew, a spot crew in 3Q. The work down in the dock 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're pretty excited about the results we're seeing. On Austin Chalk, we'll drill 5 to 6 wells this year. 3 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 3 will be appraisal wells, really. Testing the extent of the play to the further to the west, across the Excelsior block or in towards that area not on the Excelsior block yet, but towards that area. And then also help our South does this trend move away from the main current central fall. And that will delineate kind of the question on how big is this inventory. But overall, inventory hasn't really changed. We've -- we announced our reserves increases on 2 key 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.

[Greg M. Pardy, Managing Director and Co]

Okay. Perfect. And then may be just as a second. A few questions just coming up about just your debt levels as of March 31. And despite the cash flow we're not really seeing the deleveraging. To what extent is the -- is just FX playing into that?

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

Rod, do you want to speak to FX and changes and not really been that big a change, actually.

[Rodney D. Gray, Chief Financial Officer]

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.

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

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. It was -- I had a 1a and 1b, if you want to call it that. The first one was to sustain the business and ensure that we could hold the relevance of 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 tosee prices move up, which then give us more optionality and better valuations on our properties if and when we decide to move into an AMD portfolio maneuvering process. So that's still on the cards, very much Greg. And we're pursuing all options still. But this is a much better time for it then in mid-'17 or even late '17 when we were still not seeing a $60 price handle on WTI.

[Greg M. Pardy, Managing Director and Co]

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 upward generally to think about putting that on the balance sheet?

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

Right. I know you and others have pushed us on that before. I really like our level loaded plan now. We've kind of have it waffled since the WCS blew out in Q1. It's tighten back kind of the way we saw it coming, full cost to rail, at $17 to $20. So we're 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're 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. And we -- 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.

[Operator]

Our next question comes from Phil Skolnick of Eight Capital.

[Philip Ross Skolnick, Managing Director of Energy Research]

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're getting right relative to Maya in particular?

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

Yes. Let me be a little careful on 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're today railing about 7,000 barrels a day out of Peace River. Those are manifest trains that moved 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 or outreach area, we've 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've gotten to 8,000. And we're still moving it. That -- the Lloyd barrels, correct me if I'm wrong here, guys. But I think the Lloyd barrels move towards PADD II don't make it to the Gulf Coast, 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 the -- to WCS volatility. Is flat 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.

[Philip Ross Skolnick, Managing Director of Energy Research]

Okay. 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 asset is kind of getting out to an attractive point. Are they even more attractive now or especially given your -- what your comments about the pricing in Eagle Ford, like why not now try to do stuff like that and really accelerate that debt reduction?

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

That's a great question, Phil, and it's one that I sort of addressed with the 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. Would we look -- are we looking at diluting? I would say it, we're looking at everything including dilution, but we're also looking at these cash flows gives us opportunities to consider other options and our debt to cash flow is I think, one of you mentioned has move from 7x last year to 4.8x at the beginning of this year. We're looking at a 3 handle now moving into the 2019. And I know we are not back in the peer group yet, but I think it could be -- it's a -- 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're in active dialogue around how we can move our debt to cash flow back into a competitive realm.

[Operator]

Our next question comes from Patrick Bryden of Scotiabank.

[Patrick Ian Bryden]

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

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

Thanks, Patrick. We were as excited as anybody to see that premieres and the minister have called these meetings. We're not one of the companies that at least in my knowledge have been invited to these meetings at this point. But it'll probably be 3 to 5 big -- large producers and large railers. So we're not involved in that. But we are actively, in many different ways, for example, yesterday at the AGM, we're 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 have -- as a team in Baytex, and as a company, are very proud of what we've done. We were very pleased to see our name being cited on the corporate night's report sponsored by the global mail in the Washington Post ranked number 22. In a group of elite companies. So we're quite pleased with that. But we're not -- we're not there yet as a nation in terms of our energy policy. And I think TMX will go through. There's no reason Baytex should not go through. And for me line 3 and ridge expansion should be the simplest and most obvious of all 3 of them. So I think it's very likely by 2020, 2021, we'll be looking at 3 client lines maybe 1 in the ground and 1 started and another 1 happening. It's very likely that will be the outcome despite we've got a bit of dysfunctionality quite honestly within the political regimes. But I think we'll get our act together, we're optimistic, we're bullish on the product is needed in the Gulf Coast more than any time I've seen in my history in the oil business, which is now 30-plus years. The Canadian WCS heavy product with the lack of Venezuelan, Mexican, Saudi heavy sours 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 3 lines built and moved down to Gulf Coast. And that's without mentioning anything about how attractive our product, both on the gas and the oil size looks to Asia coming off the West Coast of Canada. So with that, Patrick, it's a bit of a ramble. But we're 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.

[Patrick Ian Bryden]

And then 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 out?

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

Well, I mentioned, we moved over 5,000 to 8,000. But it's been in small trenches. We would like to bigger trenches. But we've done a couple thousand barrels a day trenches in Peace River and we've 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're seeing some availability come into play. But it's on a very selective and ad hoc basis. So we're not getting the attention of the railers we ourselves because we're not a huge volume producer in heavy. And actually, everybody that sitting in the queue in my mind and this is my personal opinion, we're all sitting in the queue behind those 2 large producers who are in active negotiations with those railing companies.

[Operator]

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

[Brian G. Ector]

All right. Thanks, operator, and thanks everyone for participating in our first quarter 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.