Baytex Energy Corp.
Q3 2017 Earnings Call Transcript

Published: 4 Nov 2017

[Executives:]

Brian Ector - SVP, Capital Markets & Public Affairs Edward LaFehr - CEO, President & Director Richard Ramsay - COO Rodney Gray - CFO

[Analysts:]

Thomas Matthews - AltaCorp Capital Patrick Bryden - Scotiabank Global Banking and Markets

[Operator:]

Good morning. My name is Christine, and I'll be your conference operator today. At this time, I would like to welcome everyone to the Baytex Energy Corporation Third Quarter Conference Call. [Operator Instructions]. Brian Ector, Senior Vice President, Capital Markets and Public Affairs, you may begin your conference.

[Brian Ector:]

Thank you, Christine. Good morning, ladies and gentlemen, and thank you for joining us today to discuss our third quarter 2017 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 refer you to the advisories in today's press release regarding forward-looking statements, oil and gas information, and non-GAAP financial measures. 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 LaFehr:]

Thanks, Brian. And good morning, everyone. I am pleased to report that we have continued the positive business momentum that we began early this year. Production is trending towards the high-end of our guidance with both our Eagle Ford and Canadian assets performing well. Our funds from operations have averaged approximately $80 million per quarter every quarter this year, with our capital program fully funded within this level of cash flow. We also continue to reposition our business for the current low commodity price environment by reducing our cash costs and improving capital efficiencies. Reflective of our solid operating results in the first 9 months, we are improving our guidance for both production and operating expenses. We expect full year production of 69,500 to 70,000 BOEs per day. Previously we were at 69,000 to 70,000 BOEs per day. This is despite the impact of Hurricane Harvey and low natural gas prices in Alberta, which caused us to shut in approximately 6 million cubic feet of natural gas per day production during the month of October. This production was subsequently restarted as natural gas prices improved. And we are improving our operating expense guidance by 5% to $10.50 per BOE, following a 4% reduction in the second quarter. Our full year 2017 capital expenditure guidance remains unchanged at $310 million to $330 million. Our third quarter production was 69,310 BOEs per day, while the first 9 months of 2017 averaged 70,500 BOEs per day. Exploration and development capital expenditures totaled $61.5 million for the third quarter and $236 million for the first 9 months of 2017. As part of our initiative to divest noncore assets, during the quarter we disposed off our Red Earth properties located in North Central Alberta for net proceeds of $7.3 million. The assets were producing approximately 250 BOEs per day of oil at the time of closing and included asset retirement obligations of approximately $11.6 million. Let's turn our attention now to the Eagle Ford. As previously disclosed, on August 25, our Eagle Ford operations were shut in, and drilling and completions operations were suspended due to Hurricane Harvey. With very little damage to our facilities, production in the Eagle Ford was rapidly restored. We now estimate downtime in the third quarter from the hurricane of approximately 1,500 BOEs per day as compared to our prior estimate of 2,500 BOEs per day, primarily due to flush production from well restarts in September. We directed 76% of our capital expenditures towards these assets during the third quarter. And despite the impact of the hurricane, production averaged 34,750 BOEs per day. Eagle Ford wells that commenced production during the quarter have established 30-day initial gross production rates of approximately 1,500 BOEs per day per well. During the third quarter, we averaged 28 effective frac stages per well and proppant per completed foot of approximately 1,800 pounds. We averaged 3 to 4 drilling rigs and 1 to 2 frac crews on our lands, and we commenced production from 5.8 net wells. At quarter end, we had 13.8 net wells waiting on completion. We continued to see strong well performance driven by enhanced completions in Karnes County. In addition, early results from Atascosa County are encouraging, as we exploit the oil window on our western portion of our acreage. Turning to Canada. We have continued to execute our 2017 drilling program, while also driving our cost structure lower. At Peace River, production was stable during the third quarter, averaging 18,400 BOEs per day. Our Peace River team has been innovative and diligent inlining the acquired assets with our operating philosophies. During the third quarter, we drilled our first well on our acquired lands at Seal, which generated a 30-day IP rate of approximately 400 barrels per day. We also restarted 10 pads that were shut in at the time of the acquisition, resulting in incremental production of 800 barrels per day. We have undertaken an extensive review of operations to ensure regulatory compliance and have made meaningful progress in reducing operating cost on the acquired assets. To date, we have achieved a 35% reduction with further improvements anticipated in 2018 and beyond. Production on the acquired assets averaged 3,800 BOEs per day during the third quarter, up 26% from the time of the acquisition. At Lloydminster, production averaged approximately 9,100 BOEs per day during the third quarter, up from 8,600 BOEs per day in the second quarter. The higher volumes reflected increased pace of development activity following spring breakup. We drilled 6.4 net wells during the third quarter and 23 -- 21.3 net wells during the first 9 months of 2017. During the third quarter, 3 operated wells, including 2 multi-lateral horizontal wells established an average 30-day IP rate of approximately 200 barrels per day per well. Let's shift to our financial results. We generated funds from operations of $87 million in the quarter, or $0.33 per share, and $242 million, or $1.03 per share, in the first 9 months of the year. Our operating netback including hedging was $18.27 per BOE in the third quarter of 2017. Of note, our realized light oil and condensate price in the Eagle Ford was $46.78 per barrel, representing a $3.49 per barrel discount to LLS, as compared to a historical discount of approximately $6 per barrel. This had a positive impact on our funds from operations during the quarter. Our Eagle Ford 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. We continue to employ a flexible approach to prudently manage our capital program, as we target exploration and development capital expenditures at a level that approximates our FFO. In the first 9 months of 2017, capital expenditures totaled $236 million, which was within our FFO. Our financial liquidity remained strong with our $575 million revolving credit facilities, 2/3 undrawn, and our first long-term note maturity is not until 2021. Our revolving credit facilities, which currently mature in June of 2019 are covenant-based and do not require annual or semiannual reviews. And we are well within our financial covenants on these facilities, as our senior secured debt to bank EBITDA ratio as of September 30, 2017 was 0.6

[Operator:]

[Operator Instructions]. Your first question comes from line of Thomas Matthews from AltaCorp Capital.

[Thomas Matthews:]

Brian, just a quick question on the Atascosa acreage. Is that -- how much of that acreage is booked already in your reserve report? And how much would be considered step out drilling there? Just trying to understand, if this is relatively a new area that you guys are pursuing that will have meaningful reserve impact? Or if it's just more of a development case that's already been considered in your bookings?

[Brian Ector:]

Yes, Thomas. That's a good question. That is called our Excelsior AMI. It's that horizontal strip. It's all within the oil window. It is less developed in general than our other 3 large AMIs within Sugarloaf. And that's also an area where we believe the Austin Chalk trend is coming across through the north. So I would say, it's less developed. If you want specifics, we can certainly put you on the line with Brian after the call in terms of inventory. A lot of running room out there. It's all in the black oil window. We're and Marathon are committed to appraising and developing further into the west. It's our lower working interest acreage. So as we move out that direction, which we have done and we are doing, we see less working interest production coming our way, but nonetheless it's an important piece of acreage in our grand scheme of longer-term development.

[Thomas Matthews:]

Okay, great. That helps. And then just on the op cost. Obviously, congratulations for revising it down again on your annual guidance. But that would imply an op cost increase in the Q4. Just wondering if you could provide some color on -- is that in Canada? Is that in the U.S.? Where do you see, I guess, the op cost reverting back a little bit?

[Edward LaFehr:]

Yes. Well, I'll turn this over to Rick Ramsay, our COO, to answer more specifically. But we had a Q2 op cost of $10.70, while Q1 was lower and then, of course, Q3 was $10.10. So it is a little bit lumpy depending on what we're doing in the field. We do have a turn -- we did complete a turnaround, for example, in October, our run rates in October running 68 -- 69,000 barrels a day sort of range. So dollar per BOE fluctuates a little bit quarter-on-quarter depending on the activity. Rick, did you want to say anything more on that?

[Richard Ramsay:]

Yes. Sure. There is generally what you see historically is higher operating costs in Q2, certainly in Canada because of breakup. Summer ends up looking a little bit better. And then, obviously, as we head into winter, we start seeing moderate increases in costs across all of our activities. The unit cost, as you can see, will be higher in Q4 not only due to the overall cost increase due to the things I've already mentioned, but also just slightly lower production that we are anticipating in Q4 relative to Q3.

[Operator:]

Your next question comes from line of Patrick Bryden from Scotiabank.

[Patrick Bryden:]

I just have a quick question on the Lloydminster heavy oil fairway. When you think about the application of the multi-lateral technologies that you have and the competencies you've built up over the years, how should we think about that in terms of the step changes. It's broadly applicable and scalable to the fairway there, or is that more specific to certain areas that make it tick?

[Edward LaFehr:]

Well, good question, Patrick. I'll turn this over to Rick here in a minute. But I'm very excited about what we're seeing from the multi-lats and also some of our single slotted liner wells. We've seen a real step change from, sort of, 80 barrels a day, IP30 average to 110, 120 barrels a day, with very little cost increase. Our costs are running about $750,000 per well on these multi-lats. So not a lot of cost increase from our prior 650,000, 700,000 for the single liner wells. So I'm very excited. But now we're seeing 200 barrel a day wells, and we've just drilled in Soda Lake and Lloyd -- just south of Lloyd, and we're really excited about this. It's not all of our inventory in Lloyd. Rick can talk to that more specifically. It might be more like 1/3 of our inventory at this point in time, but a decade of inventory. So it's quite -- it's a large number of wells, but it's not all of our Lloyd area that can move to this technology.

[Rodney Gray:]

Yes, Pat, the multi-laterals have certainly performed well for us, obviously, in Peace River and we have taken that through to great success in Saskatchewan. We're applying it in areas where the consolidation of the reservoir allows for the multi-laterals to be effective being unlined and in areas where ultimately we're not seeing the potential for water flood or any kind of EOR potential. So it's -- I would say that, I'd concur with Ed's view there, probably applies to about 1/3 of our portfolio across LBU, and we've certainly been extremely pleased with the results to date. Multi-laterals in Lloyd, probably will represent 50% of our activity in '18, although that hasn't been finalized yet.

[Patrick Bryden:]

Okay, great, thanks. And just one follow-up, if I may. Are you able to provide a sense for the lateral legs? And how many legs you're finding to be optimal?

[Rodney Gray:]

Well, it's quite a variety, Pat. The wells that we've drilled this year in Lloyd, they range from 3, 4 up to 6 legs, and not quite as extensive as what we see up in Peace River, where we're ranging from 8 to 14, sort of, legs.

[Patrick Bryden:]

Okay, great. And in terms of, sort of, lateral reach out, any sense for that?

[Rodney Gray:]

Yes. Sure, up in Peace River, we are generally in that 1400-meter range. Obviously, it can range, depending upon the geology that we're pursuing. A little bit shorter in Saskatchewan, probably closer to that 1100-meter per lateral range, just, obviously, driven by a little bit less continuous geology that we've got there.

[Operator:]

There are no further questions at this time. Mr. Ector, I turn the call back over to you.

[Brian Ector:]

All right, great. Thank you, Christine, and thanks to everyone for participating in the third quarter conference call. Have a great day.

[Operator:]

This concludes today's conference call. You may now disconnect.