Baytex Energy - Q2 2018

Transcript

Operator (participant)

Welcome to the Baytex Energy Corp Second 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. To join the question queue, you may press star then one on your telephone keypad. Should you need assistance during the conference call, you may signal an operator by pressing star and zero. 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 (EVP, Capital Markets and Public Affairs)

Thank you, operator. Good morning, ladies and gentlemen, and thank you for joining us today to discuss our second 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. As you are all aware, we have announced a strategic combination with Raging River Exploration Inc. We are currently in a restricted period, and as a result, our comments on the transaction will be limited to our prepared remarks, and we cannot address any questions related to the transaction on today's call. 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 the advisories regarding forward-looking statements, oil and gas information, and non-GAAP financial and capital management measures in today's press release. All dollar amounts 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.

Ed LaFehr (President and CEO)

Thanks, Brian, and I'd like to welcome everyone to our second quarter 2018 conference call. Prior to discussing our results for the quarter, I want to touch on the transaction with Raging River that was announced on June eighteenth. We are very excited to be uniting two strong oil companies with exceptional people and assets. This is a major and essential step in repositioning Baytex for growth with a strengthened balance sheet. The combined organization will be a well-capitalized, oil-weighted company with an attractive growth and free cash flow profile. Our vision is to deliver per-share growth and value creation by unlocking the full potential of our high-quality oil assets through our new dynamic team.

The combined company is expected to have production of approximately 94,000 BOEs per day from a high-quality portfolio of oil assets, including Viking, Peace River, Lloydminster, and East Duvernay shale properties in Canada and the Eagle Ford in Texas. The combined company will have a deep inventory of drilling prospects that generate top-tier returns on invested capital. The transaction will result in holders of common shares of Raging River receiving, directly or indirectly, 1.36 common shares of Baytex for each Raging River share owned and is subject to approval by the shareholders of both companies. Furthermore, the transaction is subject to the Court of Queen's Bench of Alberta and certain regulatory and other authorities, as well as the satisfaction or waiver of other customary closing conditions.

Baytex and Raging River shareholders will hold their respective shareholder meetings on August twenty-first, 2018, and the transaction is expected to close on August twenty-second, 2018. For further information on the transaction, please see the joint press release dated June eighteenth, 2018, and the joint management information circular dated July twelfth, 2018, which was mailed to shareholders of Baytex and Raging River on July twentieth of 2018. Now, let's turn our attention to second quarter results. I'm pleased with our performance in 2018. We delivered on our operational and financial targets, successfully executing our drilling program with strong results in the Eagle Ford and in Canada. Production increased 2% to an average of 70,700 BOEs per day and brings first half 2018 production to 70,100 BOEs per day, in line with our full year guidance.

In the second quarter, we generated adjusted funds flow of CAD 107 million, with exploration and development capital expenditures totaling CAD 79 million. Excluding realized financial derivatives, gains and losses, adjusted funds flow in the second quarter was CAD 136 million, compared to CAD 94 million in Q1 2018. This represents our highest quarterly adjusted funds flow on an unhedged basis since the fourth quarter of 2014. These results demonstrate the strength of our oil-dominated asset portfolio. Let's turn our attention now to operations. In the Eagle Ford, performance across all dimensions remains outstanding. To highlight the quality of this asset, the Eagle Ford generated net operating income of CAD 118 million, with CAD 48 million of CapEx, netting free cash of CAD 70 million on the quarter.

Production averaged 36,600 BOE per day, bringing on 7.6 net wells in the quarter. These wells demonstrated thirty-day initial production rates of approximately 1,850 BOE per day, representing a 25% improvement over wells brought on production in 2017 and are the highest IP30s in our history with the asset. This exceptional well performance is largely attributed to enhanced completions. During the second quarter, we averaged 6,000-foot laterals with 28 effective frac stages and approximately 2,100 pounds of proppant per foot. Turning to Canada now. We are executing our 2018 drilling program as budgeted, with activity now ramping up as we build 2018 exit rate heading into 2019. At Peace River, production averaged 16,800 BOE per day.

Four net wells commenced production during the quarter, including our first two wells on our Northern Seal acreage acquired in January 2017. These two wells generated thirty-day initial production rates of 918 BOEs per day and 660 BOEs per day, respectively. Approximately 10 wells are anticipated to be drilled in the Northern Seal area in 2018, with a second rig starting up in August. At Lloydminster, production averaged 10,300 BOEs per day. Seven net wells drilled in Q1 2018 established peak thirty-day initial production rates of approximately 200 barrels per day per well in the second quarter. In addition, we continued to advance our Karrobert thermal project. Production at Karrobert averaged 600 BOEs per day in the first half of 2018, and we expect to exit 2018 producing approximately 2,000 BOEs per day.

We also recommenced our Soda Lake multilateral drilling program in June and added a second rig in the Lloyd area in July. Let's now shift to our financial results. During the second quarter, we benefited from continued strong liquids pricing in the Eagle Ford and improved heavy oil price realizations in Canada. In the Eagle Ford, our assets are proximal to Gulf Coast markets, with light oil and condensate production priced off the LLS crude oil benchmark, which is a function of Brent price. In Q2 2018, the price for LLS averaged over $71 per barrel, and our realized light oil and condensate price was almost $68 per barrel, or 87 CAD per barrel. As a result, the Eagle Ford generated an operating netback of $35 per BOE, a level we have not seen since we first acquired the asset in 2014.

In Canada, we generated an operating netback of CAD 18 per BOE, which was driven by higher WTI prices and improved heavy oil differentials relative to the first quarter. Our diversified oil portfolio generated a corporate-level operating netback, excluding hedging, of CAD 27 per BOE. This represents a 48% improvement over 2017. Financial liquidity remains strong, with our $575 million revolving credit facility 70% undrawn, and our first long-term note maturity not till 2021. In April, we extended the maturity of our revolving credit facilities by 1 year to June 2020. We continue to manage financial risk through an active hedging program. You will find a complete listing of our financial derivative contracts in Note 17 to our second quarter financial statements. As part of our risk management program, we also transport crude oil to markets by rail when economics warrant.

In Q2 2018, we delivered approximately 8,300 barrels per day of heavy oil to market by rail, representing one-third of our volumes. We have secured additional rail capacity, which will increase our crude by rail volumes to approximately 9,500 barrels per day in Q3 2018, and 10,500 barrels per day in Q4 2018. We have also contracted future year crude by rail volumes, which to date total 7,500 barrels per day for 2019 and 5,000 barrels per day for 2020. So let me now conclude by saying, I'm extraordinarily proud of our team for delivering strong operational and financial performance, while at the same time securing a transformative merger with Raging River Exploration.

Our 2018 production guidance range is unchanged at 68,000 barrels a day to 72,000 barrels of oil equivalent per day, with budgeted exploration development capital expenditures of CAD 325-375 million. We are incredibly excited to be moving forward with the proposed merger with Raging River as we unite two strong oil companies. The merger creates a company with world-class oil assets and a strong balance sheet led by a top-tier team. We believe the combined company will deliver powerful new offer to shareholders through a blend of industry-leading returns, attractive production growth, and strong free cash flow. Following closing of the merger, we will provide revised guidance for the merged company. As we mentioned at the outset, we cannot address any questions related to the strategic combination with Raging River because we are in a restricted period.

Keeping that in mind, I would ask you to please limit your questions to our second quarter results, and with that, I will ask the operator to please open the call for questions.

Operator (participant)

Absolutely. We will now begin the question-and-answer session. To join the question queue, you may press star, then one on your telephone keypad. You will hear a tone acknowledging your request. If you are using a speakerphone, please pick up your handset before pressing any keys. To withdraw your question, please press star, then two. We will pause for a moment as callers join the queue.... Our first question comes from Greg Pardy with RBC Capital Markets. Please go ahead.

Greg Pardy (Analyst)

Thanks. Yeah, thanks. Thanks very much. Ed, just a couple of questions, but maybe the first one is, could you provide just a little bit more color around the large, those two large Peace River Arch wells, and then maybe what the program, the drilling timetable is gonna look like for the other 10 that you've got laid out?

Ed LaFehr (President and CEO)

Yeah, sure. Yeah, the first well was a facility-constrained, nine hundred BOE a day well. Second was announced six hundred, as I just mentioned. The area is new for us. It's almost completely virgin. There were only a couple of competitor wells in the area, and we had never drilled a well there. So up in that block of land, we are in sort of a half appraisal mode and half development mode, if you wanna call it that. So, this year, we've got nine... It's actually nine total wells. If we have a good run on our performance, we could probably squeeze another well in at the end and make it ten. We've drilled now three in the area. The third one is on production and cleaning up, and the fourth well is being drilled as we speak.

So we've got another five or six to go this year. We're very excited about the area, though. These wells are better than average. They're not all gonna be 900 barrels a day, and nor are they gonna be our field average of 300. They're gonna be somewhere in between, above our 300-400 barrels a day historic average. We're very pleased with the first two. We're expecting good results on the third. You know, watch this space. It is an exciting area for us, but we do have some risk in the northern area, so we do want to appraise the edges of the field to the north.

Greg Pardy (Analyst)

Okay. And then just to follow up to that, then just cost on the well, on these wells, and then just the number. How many—these are multilaterals. How many laterals would you have?

Ed LaFehr (President and CEO)

First well would have been 14 multi. There was a couple of stubs, so it's 14 laterals. The second was 16 laterals, so actually more. You really need to look at meterage on these wells, where we're trying to push up into that 15-17 thousand-meter range for the wells. Not all laterals are created equal in terms of their length. But typically, we'll be running our standard 10-15 laterals, depending on the shape of the formation that we're drilling in the area.

Greg Pardy (Analyst)

Okay, great, and then just cost?

Ed LaFehr (President and CEO)

Costs on the wells are running about CAD 2.6 million for DC&E tie-in. However, that does not include the full cost of our infrastructure. We built out some roads and pads and gas infrastructure coming in, and we talked about that as a separate piece of infrastructure spending in the area. But those would be half-cycle costs of CAD 2.6 million per well.

Greg Pardy (Analyst)

Okay, great. And then maybe just shifting gears, I mean, you did touch on crude by rail, but, can you just maybe just give us a little bit more detail there in terms of, you know, where the barrels are going, diluent requirements, all that other good stuff?

Ed LaFehr (President and CEO)

Yeah, sure. We've been very actively moving up our volumes on crude by rail for two reasons. One is it really helps clear a market in a tight environment. Second is, when the differential moves to around an 18-20 dollar level, we see superior field netbacks by moving to rail. And the reasons why are we're able to manifest load barrels on roughly 1,000 barrels per tranche, although we've done some recently, they're quite a bit larger than that. This is unblended, raw bitumen, so there's no condensate blending. In terms of the overall cost structure for us, it's very advantaged versus other methods where blending is required. And the reason we can run it raw is twofold.

One is, we're moving into heated rail cars, but the important one is that we're moving these barrels to a specific market on the Gulf Coast, and all of the 8,000 of our 9,000 barrels a day today are running out of Peace River, Nampa, to the Gulf Coast, and that's where we get this advantage set up in terms of our overall cost structure and where we are on the differential projected going forward. We've even secured longer term contracts. We just put on another 2,500 barrels a day through Q4 and all of 2019, and we've secured our first deal, our first two-year 5,000 barrel a deal starting January 1, 2019, running right through all of 2020, into this same market at, as I said, 5,000 barrels a day.

So we've continued to step up our volumes. 4Q will be 10,500 barrels a day contracted, so those are already done. And we're continuing to look for more. That's not quite 50% of our heavy, but we'd like to get to the point where we can talk about sort of 50% of our heavy on rail. It's still a ways off, but we're able to. With the manifest opportunities we have, both in Lloyd and in Peace River, we're able to do this successively in small steps.

Greg Pardy (Analyst)

That's great. Thanks very much.

Operator (participant)

Our next question comes from Thomas Matthews with AltaCorp Capital.

Thomas Matthews (Analyst)

... Hi, guys. You actually answered part of my crude by rail questions there with the $18-$20. Just to follow up on that, I guess how, you know, how long in duration does the diff have to be wider to start adding to your rail commitments? Or are you just looking at, you know, kind of strip pricing and being opportunistic? Or, you know, I guess what's the decision-making steps there?

Ed LaFehr (President and CEO)

I just spoke about the two-year deal we just did, 2019 right through 2020. We're really not concerned about current pricing. We're well hedged for the balance of 2018, with 30-some% of our heavy oil barrels differential hedged to $14.30. The crude by rail volumes are picking up, so we've got roughly a third on, and we're moving closer to 40% crude by rail. We're not really concerned about the near term. We're gonna continue to develop our field into this market.

And we do see back half of 2019 into 2020 as the overlap period where we get Enbridge Line 3 on, TMX comes on, and we should be, with one or two of those lines, back into differentials in a twelve to fourteen dollar range, by sort of circa end of 2019 and 2020. But we just did a deal. We just did a rail deal that went right through 2020. We think it's good business, and it's a form of a physical hedge for us.

Thomas Matthews (Analyst)

Got it. Thanks for that. And then, just, on the Eagle Ford, have you seen much cost inflation kind of quarter over quarter, just overall? Or, you know, have you, is there any changes in cost with, with some of the new completion techniques that you're doing there? I don't think there's been a big step change, but just kind of curious, if costs have went up along with the rates, because we haven't really talked about Eagle Ford costs, I don't think.

Ed LaFehr (President and CEO)

No

Thomas Matthews (Analyst)

... this quarter and maybe not last quarter either.

Ed LaFehr (President and CEO)

Right. That's a good question, and we have definitely seen some inflation. But we've also seen some scope increase on our wells in terms of we're moving to longer laterals, more stages per well, you know, more proppants. And all of that is driving a well cost last year, which would've been a CAD 4.7 million all-in DC & E, to more like a CAD 5.4 million all-in DC & E for a normalized 5,500-foot lateral. But we're drilling 6,000-foot laterals, so, you know, that cost would be more like a CAD 5.8 million number for a 6,000-foot lateral, all in with the degree of completions we're putting in the well.

Thomas Matthews (Analyst)

Okay. Yeah, perfect. That's, that's great color.

Ed LaFehr (President and CEO)

Okay.

Thomas Matthews (Analyst)

Will they all be that lateral length kind of going forward? I mean, is that the new direction then?

Ed LaFehr (President and CEO)

We'd like it to be.

Thomas Matthews (Analyst)

You know, yes?

Ed LaFehr (President and CEO)

But no, I would say it'll vary quite a bit between 5,000 and even 8,000 and upwards, so we've got some units that are being renegotiated, lease line boundaries renegotiated, and so we'd like to push to a bit longer laterals, but you'll see quite a variety of lengths on our wells.

Thomas Matthews (Analyst)

Okay. Great. Thank you. That's it for me.

Operator (participant)

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

Ed LaFehr (President and CEO)

All right. Thanks, operator. Thanks, everyone, for participating in our second quarter conference call. Have a great day.

Operator (participant)

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