Baytex Energy Corp. (BTE) Q2 2018 Earnings Report, Transcript and Summary

Thank you for standing by. This is the conference operator. 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. [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, 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 the 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.

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 18. We are 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 the 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 21, 2018 and the transaction is expected to close on August 22, 2018. For further information on the transaction, please see the joint press release dated June 18, 2018 and the joint management information circular dated July 12, 2018, which was mailed to shareholders of Baytex and Raging River on July 20th of 2018. Now let’s turn our attention to second quarter results. I am 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 a 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 a 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 dimension remains outstanding. To highlight the quality of this asset, the Eagle Ford generated net operating income of a CAD 118 million with CAD 48 million of CapEx, netting free cash of CAD 70 million on the quarter. Production averaged 36,600 BOEs per day, bringing on 7.6 net wells on the quarter. These wells demonstrated 30-day initial production rates of approximately 1,850 BOEs per day, representing a 25% improvement over wells brought on production in 2017 and were the highest IP30s in our history with the asset. This exceptional well performance is largely attributable to two 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 BOEs 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 30-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 the second rig starting up in August. At Lloydminster, production averaged 10,300 BOEs per day. Seven net wells drilled in Q1 2018 established peak 30-day initial production rates of approximately 200 barrels per day per well in the second quarter. In addition, we continued to advance our Kerrobert thermal project. Production at Kerrobert 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 multi-lateral 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 US$71 per barrel. And our realized light oil and condensate price was almost US$68 per barrel or CAD 87 per barrel. As a result, the Eagle Ford generated an operating netback of CAD 35 per BOE, a level we have not seen since we first acquired the asset in 2014. In Canada we generated an operating net frac 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 remained strong with our US$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 one year to June 2020. We continued 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 totaled 7,500 barrels per day for 2019 and 5,000 barrels per day for 2020. So, let me now conclude by saying, I am 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 equivalent per day, with budgeted exploration development capital expenditures of CAD 325 million to CAD 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 the 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 on 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.

Absolutely. We will now begin the question-and-answer session. [Operator Instructions] Our first question comes from Greg Pardy with RBC Capital Markets. Please go ahead.

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 time table is going to look like for the other 10 that you’ve got laid out?

Yeah, sure. Yeah, first well was a facility constraint 900 BOE a day well, second was announced 600 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 of appraisal mode and half development mode if you want to call it that. So, this year we’ve got nine, it’s actually nine total wells. If we have good run on our performance, we could probably squeeze another well and at the end make it 10. 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. And we’re very excited about the area available. These wells are better than average. They’re not all going to be 900 barrels a day and nor are they going to be our field average of 300. They’re going to be somewhere in between above our 300 barrels to 400 barrels a day historic average and we’re very pleased with the first two, we’re expecting good results on the third and watch this space. It is an exciting area for us, but we do have some risk in the Northern area. So, we do want appraise the edges of the field to the North.

Okay. Ed, and maybe just a follow-up to that, just cost on the well -- on these wells and then just a number. How many of these are multi-laterals, how many laterals would you have?

First well would have been 14 multi-lateral, there is a couple of stubs. So, it’s 14 laterals. The second was 16 laterals or actually more. You really need to look at meterage on these wells where we’re trying to push up into that 15,000, 17,000 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 to 15 laterals depending on the shape of the formation that we’re drilling in the area.

Okay, great. And then just cost?

Cost on the wells are running about CAD 2.6 million for DC and equipped high-end. However, that does not include the full cost of our infrastructure. We’ve 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 will be half cycle costs of CAD 2.6 million per well.

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 to tail there in terms of where the barrels are going, daily requirements all out of the good stuff?

Yeah, sure. We’ve been very actively moving up our volumes on crude by rail for two reasons. One is, it really helps clear our market in the tight environment. Second is, when the differential moves to around an CAD 18 to CAD 20 level, we see superior field netbacks by moving to rail. And the reasons why our -- we’re able to manifest low barrels on roughly 1,000 barrels per tranche, although we’ve done some recently quite a bit larger than that, this is unblended raw bitumen. So, there is 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 could run at raw is two-fold. One is, we’re moving into heated railcars. 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 advantaged 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 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 and still awaits 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.

That’s great. Thanks very much.

Our next question comes from Thomas Matthews with AltaCorp Capital.

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

Well, 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% of our barrels -- of our heavy oil differential hedged to $14.30. And 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 rails. So, we’re not really concerned about the near-term, we’re going to 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 CAD 12 to CAD 14 range by sort of circa end of 2019. 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.

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 have you -- is there any changes in cost with some of the new completion techniques that you’re doing there? I don’t think there has been a big step change, but just kind of curious if costs went up along with the rates because we haven’t really talked about Eagle Ford costs, I don’t think last quarter and maybe not last quarter either?

Right. That’s a good question. And we have definitely seen some inflation. We’ve also seen some scope increase on our wells in terms of we’re moving the longer laterals, more stage -- more stages per well, more proppant and all of that is driving well cost. Last year which would have been a CAD 4.7 million all-in DC&E to more like a CADE 5.4 million all-in DC&E for normalized 5,500 foot lateral, but we’re drilling 6,000 foot laterals. So, 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.

Okay, perfect. That’s great color. So, will they all be that lateral length kind of going forward, I mean is that the new direction then?

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

Okay, great. Thank you. That’s it for me.

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.

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