Baytex Energy Corp (BTE) 2017 Q2 法說會逐字稿

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 Corp. Second Quarter Conference Call. (Operator Instructions)

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 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.

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 have been able to substantially grow production, and we have done so largely within funds from operations at a USD 50 price per barrel.

This excellent performance is due to some of the strongest well results we have seen to date in Eagle Ford, and a safe and highly efficient start-up of our development program in Canada. Our team is pushing to reposition the business for success at 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 of 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 '17 to $175 million.

Reflective of our strong operating results in 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 day.

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. And 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 resource plays in North America. It is the asset that generates our highest cash netbacks and contains over a decade of drilling inventory, with new prospective trends and opportunities still emerging.

In the second quarter, we directed 76% of our capital expenditures towards these assets, and production averaged 38,500 BOEs per day, a 7% increase over the first quarter of 2017.

During the second quarter, we averaged 4 to 5 drilling rigs and 1 to 2 completion crews on our lands, and we commenced 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 USD 4.7 million to USD 4.9 million. This is below our 2017 budget cost assumption of USD 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 3 recently completed Karnes 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 double 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 7 multilateral wells during the first 6 months of the year. 6 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 20, 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 breakup. 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 USD 575 million revolving credit facility 2/3 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 and 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 at June 30, 2017, was 0.7:1.0 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 USD 54.46 per barrel and 39% hedged utilizing 3-way collar structures with downside production at USD 47 per barrel and upside participation to USD 59 per barrel.

We have also entered into hedges on approximately 49% of our WCS exposure at a price differential to WTI of USD 13.73 per barrel and 68% of our net natural gas exposure through a combination of AECO swaps at $3 per mcf and NYMEX swaps at USB 2.98 per mmbtu.

We're also executing our hedge program for 2018. We have now entered into hedges on approximately 20% of our net WTI exposure with 15% fixed at USD 51.28 per barrel and 5% hedged utilizing 3-way option structures that provide us with downside protection at USD 54 per barrel and upside participation to USD 60 per barrel.

As for the WCS differential, we have entered into hedges on approximately 20% of our net exposure at a price differential to WTI of USD 14.42 per barrel and 19% of our net natural gas exposure through a combination of AECO swaps at $2.82 per mcf and NYMEX swaps at USD 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 USD 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.

Ed, how goes the progress in terms of reducing the OpEx on the Murphy assets 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 that 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 -- it's absolute cost reductions, not just volume increases. And Rick Ramsay, our COO, can say a bit more about that. But it's a -- 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 bringing on the balance of the shut-in volumes?

Yes. Volumes -- we've got a decline rate up there, but those shut-in volumes are being brought back and 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 been 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, 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, though, 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's got some stretch targets above 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're 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 -- aligned 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 Karnes City wells, for example, are a little bit deeper. They have a bit higher pressure and temperature. They take exceedingly well with the big fracs. And we're seeing the best wells range in the 2,500 to 2,700 barrel a day range. And we're seeing pads come on, on 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 the field in the condensate window. I would say there's a lot of running room, Greg. But it's yet to be developed.

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

I just had a follow-up question just on the Eagle Ford 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're 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 reserve season in a couple of months and have a deep look at it. But it's too early to say whether we would adjust the EORs or not. We're very excited. Early days, and there's a lot of potential.

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

We risk our locations. So 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 any more regionally, I mean, in terms of spacing width. 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 reserve 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 and 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 of the northern Austin Chalk locations in our inventory, not even in contingent, let alone 2P; nor have we included any reserves around an EOR scheme that other operators are not only contemplating but piloting and generating some very exciting results. So it's early days. Really is early days in the oil window, even though we've been at this now, what, 3, 4 years since -- 3 years since we purchased the asset, and it's grown substantially and continues to grow.

Right. And then, yes, you mentioned Austin Chalk; that was going to be my last question. Just on -- you've seen 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 2 wells in the Austin Chalk now, in the northernmost tip -- sort of north-central 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 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 it'd 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 #1 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 debt. And I've been pretty open about that. Internally, we're evaluating many opportunities, including and starting with disposing of any noncore assets that we may have. Secondly, we're looking at creative things like royalty carve-outs or GORR sales. We're looking at working interest dilutions. We're looking at a combination of joint venture opportunities for some acreage that we wouldn't get to 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 A&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 a 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 it will be value-accretive rather than erosive. We're not going to do something right now in a knee-jerk fashion, if that helps.

(Operator Instructions) Your next question comes from the line of David Popowich from CIBC.

I guess just wanted to follow up a 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 that first half production has averaged 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 we're in, where we may have to pare back at the edges some -- a couple of wells in Peace River and some things in 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, and 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 wells. Our activity set has been up across the board. This is the first time we've been 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 than the base. But our corporate decline rate is still hanging in the 32% to 33-ish percent range, if that helps.

Yes, it does. I guess, just to add to that question. Can you give us some sense of how you expect production will evolve over the next 2 quarters? I mean, any indication that Q3 production is tracking in line with where Q2 was, given your drilled uncompleted 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 flowbacks that's higher than average. We had a strong activity set coming into the quarter. And we're talking to the operator there about trimming rigs, not necessarily flowbacks. But we will see a reduction of flowbacks in the second half of the year in the 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 give me an oil price, Dave, and 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're likely to pull back our rig program. If we're in a $50 world, we can go hard.

All right. I appreciate it. And just for my last question, I just wanted to expand a bit just on the corporate sale process. I mean, it definitely sounds positive that you guys have these high-intensity fracs going, and you barely tapped 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 interests very aligned with Marathon on this front in terms of proving up some of those new resource opportunities in thetime frame that will allow you guys to reduce your debt by the end of 2018?

Well, absolutely. We're -- they're not worried about us and our balance sheet. But on the other hand, they're 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've 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 to $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. Does that help?

Yes, it does. I appreciate it.

And there are no further questions at this time. I 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.

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