Baytex Energy Corp. (BTE) Q2 2017 Earnings Report, Transcript and Summary

Good morning. My name is Kelly and I will be your conference operator today. At this time, I would like to welcome everyone to the Baytex Energy Corporation Second Quarter Conference Call. All participants are in a listen-only mode. After the speakers' remarks, there will be a question-and-answer session [Operator Instructions] Thank you. And I will now turn the call over to Brian Ector, Senior Vice President, Capital Markets and Public Affairs. Mr. Ector, you may begin.

Well, thank you, Kelly. Good morning ladies and gentlemen and thank you for joining us today to discuss our second 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 Ramsey, 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 reference 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'm very pleased to report that we have continued the positive momentum we began in the first quarter of 2017. Driven by the excellent capital efficiencies across our portfolio, we've been able to substantially grow production and we have done so largely within funds from operations at $50 price per barrel. This excellent is due to some of the strongest well results we've seen results to date at Eagle Ford and a safe and highly efficient startup of our development program in Canada. Our team is pushing to reposition the business for success of these low commodity prices with production currently above the high end of our guidance and capital spending tracking toward the low end of our guidance. Overall, our second quarter production of 72,800 BOEs per day was up 5% over the first quarter and up 12% from the fourth quarter of 2016. Production in the first half 2017 has averaged just over 71,000 BOEs per day. During the second quarter, exploration and development capital expenditures totaled $78 million, bringing the aggregate spending for the first half of 2017 to $175 million. Reflective of our strong operating results from the first half of the year, we are tightening our 2017 production guidance range to 69,000 and 70,000 barrels of oil equivalent per day. It was previously 68,000 to 70,000 BOE per year. We are now forecasting full year 2017 capital expenditures of $310 million to $330 million, down from $325 million to $350 million. We are also improving our guidance for operating expenses by 4% at the midpoint to $10.75 to $11.25 per BOE as we continue to drive cost efficiencies across our business. Operationally, we have delivered outstanding results in the Eagle Ford. As I'm sure most of you are aware, our Eagle Ford assets are located in Karnes County, Texas, which ranks as one of the premier oil resources place in North America. It is the asset that generates our highest cash netback and contains over a decade of drilling inventory with new perspective trends and opportunities still emerging. In the second quarter, we directed 76% of our capital expenditures towards these assets and production average 38,500 BOEs per day, a 7% increase over the first quarter of 2017. During the second quarter, we averaged four to five drilling rigs and one to two completion crews on our lands and we commence production from 35 gross wells. We continue to see strong well performance driven by enhanced completions in the oil window. The cost to drill, complete, equip, and tie-in a well ranges from $4.7 million to $4.9 million. This is below our 2017 budget cost assumption of $5 million per well. 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. Our three recently completed current city pads totaling 11 wells, all within the oil window of our Longhorn acreage, established 30-day initial gross production rates of approximately 2,150 BOEs per day per well. These pads were completed with approximately 30 effective frac stages per well and proppant per completed foot of approximately 1,900 pounds, which is more than doubled the frac intensity of wells previously drilled in the area. Turning to Canada, we have continued to execute our 2017 drilling program with strong results in both Peace River and Lloydminster. Our second quarter production of just over 34,000 BOEs per day represents an increase of 3% over the first quarter and 8% over the fourth quarter of 2016. At Peace River, we drilled seven multilateral wells during the first six months of the year, six of the wells have been producing for more than 30 days and have established an average 30-day initial production rate of approximately 400 barrels of oil per day per well. Two of these wells ranked among the top oil wells drilled in Alberta during this period. This performance is ahead of our budget expectations. The integration of the Peace River acquisition, which closed on January 20th, has gone exceptionally well. We're making terrific progress and we're driving the operating cost structure of the acquired assets down by almost 30%. At Lloydminster, we had a relatively quiet second quarter, which is typical of the region during spring break up. Overall, we've drilled 15 net wells to-date in the area with results that are consistent with our expectations. Let's shift now to our financial results. We generated funds from operations of $83 million or $0.35 per share in the second quarter of 2017 as compared to $81 million or $0.35 per share in the first quarter of 2017. The small increase in funds from operations is largely attributable to higher production volumes, which more than offset the decline in crude oil prices. Funds from operations for the first half of the year totaled $165 million or $0.70 per share as compared to $127 million or $0.60 per share in the first half of 2016. So a substantial increase year-on-year. Our operating net back excluding hedging was $18.30 per BOE in the second quarter of 2017 as compared to $14.39 per barrel in the second quarter of 2016. We continue to maintain strong financial liquidity with our $575 million revolving credit facility, two-thirds undrawn and our first meaningful long-term note not maturing until 2021. With our strategy to spend within funds from operations, we expect this liquidity position to remain stable going forward. Our revolving credit facilities, which currently mature in June of 2019 are covenant-based, do not require annual or semiannual reviews. We are well within our financial covenants of these facilities as our senior secured debt to bank EBITDA ratio as of June 30th, 2017 was 0.7 to 1.0 as compared to a maximum permitted ratio of 5:1 and our interest coverage ratio was 4:1 as compared to a minimum required ratio of 1.25:1. With respect to commodity price risk management, for the second half of 2017, we have entered into hedges on approximately 48% of our net WTI exposure with 9% fixed at $54.46 per barrel and 39% hedged utilizing three-way collars structures with downside production at $47 per barrel and upside participation to $59 per barrel. We have also entered into hedges on approximately 49% of our WCS exposure at a price differential to WTI of $13.73 per barrel and 68% of our net natural gas exposure to a combination of AECO swaps at $3 per mcf and NYMEX swaps at $2.98 per mmbtu. We're also executing our hedge program for 2018. We've now entered into hedges on approximately 20% of our net WTI exposure with 15% fixed at $51.28 per barrel and 5% hedged utilizing three-way option structures that provide us with downside protection at $54 per barrel and upside participation to $60 per barrel. As for the WCS differential, we've entered into hedges on approximately 20% of our net exposure at a price differential to WTI of $14.42 per barrel and 19% of our net natural gas exposure to a combination of AECO swaps at $2.82 per mcf and NYMEX swaps at $3 per mmbtu. To conclude, we are extremely pleased with our sequential quarterly growth in production and funds from operations since the fourth quarter of 2016. The combination of increased activity levels, optimization of our development programs and strong execution are generating impressive results across the full portfolio. We have delivered some of the best well results to date in Eagle Ford. Our Canadian program is being successfully executed and we are driving our cost structure lower with revised OpEx guidance and we are maintaining strong financial liquidity. All of this has led to our ability to generate strong funds from operations and grow production with oil prices around $50 per barrel. And with that, I will conclude my formal remarks and ask the operator to please open the call for questions.

[Operator Instructions] Your first question today comes from the line of Greg Pardy of RBC. Your line is open.

Thanks. Good morning. Ed, how goes the progress in terms of reducing the OpEx on the Murphy asset you bought earlier this year?

Well, I mentioned 30% cost reduction. We bought the assets at $30 a barrel and we're now sitting in the low $20s per barrel. A very small amount of that is a volume increase. We've moved production from about 3,000 to 3,300 -- 3,500 barrels a day today. But we've driven the cost -- the absolute cost in net asset we're running about $36 million. We've now moved that annual run rate on cost to $24 million. So, it's a full -- its absolute cost reductions, not just volume increases and Rick Ramsey, our COO, can say a bit more about that. But it's -- we're turning over every stone to try and move it closer to our OpEx -- our first-class OpEx performance over in the Harmon Valley area.

Okay, perfect. And then things are looking pretty good in terms of being in the balance of shut-in volumes?

Yes. Volumes -- we've got the decline rate up there, but those shut-in volumes are being brought back in holding production around 3,500 barrels a day. But let me let Rick talk a bit further about that.

Yes. Thanks Ed. On the operating cost side, we've the extremely pleased with the results. Obviously, a 30% reduction in operating costs is very meaningful to that asset, specifically being a heavy oil asset. And we've really seen improvements across all of our cost categories. But the major savings that we've seen have been in labor where we've reduced our overall workforce and optimized the type of work that they're doing. And also come in the categories of maintenance, just doing things a little bit differently than what Murphy was doing and more in line with our processes over in the Harmon Valley area. And then finally, property tax, that was a fairly major cost and we've been going through a fairly detailed review and identification of the facilities and classification of that. And overall resulting in a $10 per barrel reduction relative to what our expectations were at the beginning of the year. So, extremely pleased with the progress to-date.

Okay, great. And then maybe just back on the -- I mean, yes, you guys have made tremendous progress, as you mentioned. In terms of that 3,000, so you're at about 3,500 now. Is the thinking now that again, by the end of the year, you'll bring on the majority of the balance?

Well, we said 3,500 to 4,000 barrels a day would be our exit rate some time ago and we're sticking to that. That's our goal. That's our objective. The team has got some stretch targets about that. But on the other hand, we're in an extremely volatile environment in terms of oil price and if we were at $40 a barrel or $45, like we were in July, we would be doing less work than if we believe we are in a $50 world. So, let's see where things move going forward. But expect that 3,500 to be a good solid number.

Okay, great. And then just in the Eagle Ford. I mean, you dug into it in terms of frac intensity and so forth. How much more runway do you think you have on these big wells?

Well, I think a lot. We've just now shifted the program from -- align with the operator to move from doing more work in the condensate window to more work in the oil window with bigger fracs. And what we're finding is there are certain areas within the Longhorn acreage or up in the oil window that take extremely well to the big fracs. But it's also we're finding there's some better rock in certain areas. These current city wells, for example, are a little bit deeper. They have a bit higher pressure and temperature. They take exceedingly well to the big fracs and we're seeing the best wells range and the 2,500 to 2,700 barrel a day range. And we're seeing pads come on, on an average of 2,150 barrels. So, this is early days in terms of the oil window and our activity boost moving into the oil window from what was preferentially, kind of the mid-area of field in the condensate window. I would say there's a lot of running room, Greg, but it's yet to be developed.

Okay. Thanks very much guys.

Appreciate the comment and question.

Your next question comes from the line of Thomas Matthews of AltaCorp Capital. Your line is open.

Hi guys. I just had a follow-up question, just something to go further down frac intensity. So, I know it's still early days as you mentioned, but are you seeing any sort of increase in the decline profile of these wells? And if you are or aren't, what's the likelihood of revising the expected recoveries there considering that the IP rates have been coming in pretty solid over the last few quarters?

Yes. Well, keep in mind these new wells, which really drove the 38,500 barrel a day Q2 rate, have only been on 30 to 90 days. So, in terms of IP30s and IP90s, we are all over it. In terms of seeing that we're definitely performing above our type curve, absolutely. But will it sustain long-term? We believe it will. But we -- we'll get into reserves season in a couple of months and have a deep look at it. But it's too early to say whether we would adjust EURs or not. We're very excited. Early days and there's a lot of potential.

Okay. Yes, I mean that's the answer was expecting, to be honest. But I thought I'd ask anyway. And then just as far as the location counts; are seeing anything from drilling up into the oil window that would cause a revision in the number of locations at either you have identified or that you have booked? Where are you guys at on locations?

We risk our locations. So, we -- we've risked our locations to about 400 net locations going forward, which gives us about a decade plus of inventory. So, we're sticking -- we're not revising our inventory upwards or downwards. We do believe these bigger fracs are producing more. We're not sure they're accessing anymore regionally -- I mean, in terms of spacing. So, we haven't adjusted our development plan as a result of these big fracs working nor do I think we necessarily have to. So, we'll work that as we get into reserves season and -- but we'll see where we get, but we're still sticking with our risked inventory of 400, which is a gross inventory of close to 2,000. We risk the contingent and the possible as well very heavily. So, you can see that as things continue to work in technologies and operational efficiencies improve, some of the risking will come off and that inventory will grow over time we believe. And the other thing I want to point out is we've not included really any on the Northern Austin Chalk locations in our inventory, not even in contingent, let alone 2P, nor have we included any reserves around an EUR scheme that other operators are not only contemplating, but piloting and generating some very exciting results. So, it's early days, really its early days in the oil window even though we've been at this now what, three, four years since -- three years since we purchased the asset and it has grown substantially and continues to grow.

Right. And then -- you mentioned Austin Chalk, that's going to be my last question, just on -- you've seen the offsetting operators talk about it a little bit more. What have you guys seen in this quarter that you might not have seen in prior quarters that would cause you to target more of that zone?

Well, we've drilled and completed two wells in the Austin Chalk now, in the northern most tip -- sort of northcentral or northwestern part of our acreage. So, we have now drilled and completed and collected data. We've cored one of the wells. So, we have strong geologic information. So, for the first time, we have access not only to competitor data, but we've generated the data collection and also as soon to come production performance from these Austin Chalk wells in the north. Now, we don't expect those to be online given the strong inventory of wells we've got coming on until October-ish. So, we won't have production performance from these wells for a bit and we've got another one to drill this year.

Okay. And then just an update -- and this is my last question, I promise. Just an update on any sort of disposition process. I remember in the last conference call, you said there would be a matter of months, not years. Just wondering if the improvement of late in the WTI prices has changed that outlook or is that still the desire to address some of the leverage I guess?

Yes, I've been very, hopefully, consistent and clear in my message that the number one priority was sustaining the -- stopping the production declines, sustaining the business model, getting back to generating strong capital efficiencies and cost reductions in our base business to reposition for 50. But the second priority is very much around addressing the data and I've been pretty open about that. Internally, we're evaluating many opportunities, including and starting with disposing of any non-core assets that we may have. Secondly, we're looking at creative things like royalty [carve-outs or go] sales. We're looking at working interest dilutions. We're looking at combination of joint venture opportunities for some acreage that we wouldn't get too for some period of time. So, we've got a number of things that we're looking at. And I've said 12 to 18 months as well, I have a sense of urgency to deal with the debt. I think this is really not a strong time in terms of the macro environment or the equity markets to support a lot of E&D activity to be quite frank. We've got other things on our plate right now driving performance inside the business. So, we feel like this is the time to focus internally. We've got strategy process going on inside the company and with our Board. And in due course, with the strong liquidity and time that we have, we will deal with the debt. And I believe our assets are strong enough, our team is strong enough, our Board is strong and patient, and we'll get to it and deal with it quite successfully and we will -- it will be value-accretive rather than erosive. We're not going to do something right now in a [Indiscernible] fashion if that helps.

Definitely. Thanks for all your comments Ed.

Thanks for the questions.

[Operator Instructions] Your next question comes from the line of David Popovich from CIBC. Your line is open.

Yes, thanks guys. I guess just wanted to follow-up bit on the decline issue. I was just wondering what decline rate you guys are assuming in arriving at your guidance of 69,000 to 70,000 BOEs a day this year. It seems a little bit conservative to get to that kind of production number given the first half production is average -- or is averaging 73,000 barrels a day recently.

Yes. Good question. I think we're -- I think we have been conservative. We are being conservative. But on the other hand, I think we're being prudent in the volatile world that where in. We may have to pair back the edges, some -- a couple of wells in Peace River and some things at Lloyd. But on corporate decline rate, we're still sitting where we've always been around 32% to 34% and it's in the low 40s in the Eagle Ford. It's in the low 20s or 23-ish in Canada. So, our corporate decline rate hasn't really changed. We have brought on a number of high-decline in wells. Our activities status has been up across the Board. This is the first time we went back to work in Canada in a couple of years in a meaningful way. So, we're seeing the new wells decline as they should at a higher rate at the base. But our corporate decline rate is still hanging in the 32% of the 33-ish percent range if that helps.

Yes, it does. I guess just to add to that question. Can you give us some sense on how you expect production will evolve over the next two quarters? I mean any indication that Q3 production is tracking in line with where Q2 was given your drilled and completed inventory?

Yes, July looks strong. We're producing well. It's lumpy. So, the Eagle Ford, for example, had averaged 38,500 for Q2. We had a number of flow backs that's higher than average. We had a strong activity set coming into the quarter. We're talking to the operator there about trimming rigs, not necessarily flow backs. But we will see a reduction of flow backs in the second half of the year in Eagle Ford versus the first half and that's just part of the lumpiness of the Eagle Ford. So, we're producing about 36-plus from Eagle Ford today, 36.5 and about 34 from Canada. So, we're running 70 plus-ish right now. But given an oil price, David, I'll give you a little better answer. If we're at $45, like we were in July for the rest of the year, we are likely to pull back our rig program. If we're in a $50 world, we can go hard.

All right. Thanks for the answer and I appreciate it. And just from a last question, I just want to expand a bit just on the corporate sales process. It definitely sounds positive that you guys have this high intensity fracs going and you barely tap the Austin Chalk. I guess -- I just wonder how you can balance a desire to maximize the value of those, call it, contingent resources with the desire to solve the debt problem in a timely fashion. I mean are your interest very aligned with Marathon in this in terms of proving up with some those new resource opportunities in the timeframe that will allow you guys to reduce your debt by the end of 2018?

Well, absolutely. We're -- they're not worried about us in our balance sheet. But on the other hand, they are worried about their assets and their own issues in terms of driving growth and they've talked about growth targets and Eagle Ford's a big chunk of that -- of their company. So, we're very much aligned with the operator in terms of not just this new program we're on, bigger fracs and the oil window generating these fantastic results and hopefully, they'll talk about that in their call just as we are in our call. I'm sure they will. But also appraising the Austin Chalk, they're ahead of us in appraising the Austin Chalk. They've got another well just offsetting our acreage on their 100% acreage, they come onto our acreage. We're fully aligned on that. We're already starting to talk about appraising and developing further potential across the assets. So, we're aligned with the operator. I think it's good for all seasons whether we do something inorganic with this asset or not. This asset is a world-class resource that is growing, that has further potential, and we're developing it for similar reasons that Marathon is. It works down the $30 oil. It's phenomenally economic and there's -- these big fields just keep getting bigger. So, I think we're aligned and it's good for our future.

Great. Thanks.

Does that help?

Yes, it does. I appreciate it.

And there are no further questions at this time. I'd turn the call back over to the presenters.

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