Baytex Energy Corp (BTE) 2015 Q4 法說會逐字稿

Good morning, ladies and gentlemen. Welcome to the Baytex Energy Corporation 2015 year-end results conference call.

Please be advised that this call is being recorded.

I would now like to turn the meeting over to Mr. Brian Ector, Senior Vice President, Capital Markets and Public Affairs. Please go ahead, Mr. Ector.

Thank you, Melanie. Good morning, ladies and gentlemen, and thank you for joining us today to discuss our fourth quarter and year end 2015 financial and operating results. With me today are Jim Bowzer, 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.

On the call today we will also be discussing the evaluation of our reserves at year-end 2015. These evaluations have been prepared in accordance with Canadian disclosure standards, which are not comparable in all respects to United States or other foreign disclosure standards. Our remarks regarding reserves are also forward-looking statements.

I refer you to our advisories regarding forward-looking statements, oil and gas information and non-GAAP financial measures and the notice to US residents contained in today's press release. All dollar amounts referenced in our remarks are in Canadian dollars, unless otherwise specified.

I would now like to turn the call over to Jim.

Thanks, Brian, and good morning, everyone.

Today I'm going to discuss our results for the fourth quarter and year end for 2015 and how we continue to position our Company to withstand the low commodity price environment. I will also discuss how we remain focused on prudently managing our operations to maintain strong levels of financial liquidity.

I'll break my comments into four parts for you today. First, I will talk about our 2015 operating and financial results. Second, I'll provide an update on our balance sheet and liquidity. Third, I'm going to discuss our year-end 2015 reserve report. And, lastly, I will provide an update on our operational plans for 2016.

Our operating results for the fourth quarter and full-year 2015 were consistent with our expectations and reflect a reduced pace in the drilling activity. Production averaged over 81,000 BOEs per day during the fourth quarter, as compared to just over 82,000 BOEs a day for the third quarter. For the full year 2015, production averaged 84,600 BOEs per day in line with guidance.

Capital expenditures for exploration and development activities totaled CAD141 million in the fourth quarter and CAD521 million for the full year 2015, in line with our annual guidance. In 2015 we participated in the drilling of 82 net dwells with a 99% success rate. And importantly, we realized over CAD150 million in efficiencies in 2015 as we focused on cost reductions initiatives across all of our operations.

Our performance in the Eagle Ford was strong during the fourth quarter, as we maintained a consistent pace of development, averaging six drilling rigs and two frac crews on our lands. In the Eagle Ford we produced approximately 40,000 BOEs per day as compared to 39,000 BOEs per day in the third quarter.

Significant advancements were made in the past year to delineate a multi zone development potential of our Sugarkane acreage. We continued to implement stack and frac pilots which target up to three zones in the Eagle Ford formation, in addition to the overlying Austin Chalk formation. In 2015 we drilled 15 net wells on our Eagle Ford acreage, of which 56% targeted the lower Eagle Ford, 26% targeted the Austin Chalk, 11% targeted the upper Eagle Ford and 7% targeted the upper portion of the lower Eagle Ford.

In recent production data from one pad, which consists of four wells that targeted three zones, achieved 30-day initial production rates ranging from, per well, ranging from 1400 to 1875 BOEs per day. We currently have 13 of these multi-zone projects in various stages of execution and production. Of the 61 wells, gross wells, that commenced production during the fourth quarter in the Eagle Ford, 46 of those wells had been producing for more than 30 days and have established an average 30-day initial production rate of approximately 1100 BOEs per day.

Production in Canada averaged 41,000 BOEs a day in the fourth quarter, as compared to approximately 43,000 BOEs per day in the third quarter. The reduced volumes in Canada are due to the cancellation of the Canadian drilling program as a result of low crude oil prices. We generated funds from operations of CAD93 million, or CAD0.44 per share during the fourth quarter. For the full year, funds from operations averaged CAD560 million or CAD2.61 per share.

Our operating net back in the fourth quarter was CAD12.32 per BOE, or CAD16.41 per BOE, including financial derivative gains. Our Canadian operations generated an operating net back CAD5.73 per BOE, while the Eagle Ford generated an operating net back of CAD18.77 per BOE.

I would like to highlight a couple of key points regarding our net back for this quarter. Our Eagle Ford assets are located in South Texas, proximal to Gulf Coast markets, with light oil and condensate production priced off of a Louisiana Light Sweet crude oil benchmark, which typically trades at a premium to WTI. Declining production in the region has increased competition for crude supplies resulting in lower transportation and gathering costs and improved price realizations. This strong pricing combined with low cash costs contributed positively to our operating net back in the quarter.

And as I mentioned, during the quarter we continued to focus on cost-reduction initiatives across all of our operations, production and operating expenses decreased to 25% on a per BOE basis, and transportation expenses have been reduced by 30% on a per BOE basis as compared to the fourth quarter of 2014. We are also benefiting from the Eagle Ford assets, which have lower operating costs and comprise a larger percentage of our production.

On the corporate side, our G&A was CAD12.8 million in the quarter as compared to CAD17 million in the fourth quarter of 2014. This decrease is primarily a result of reductions to staffing levels to coincide with lower levels of activity combined with reductions in discretionary spending. Now, for a little more color on our financial liquidity, we continue to adjust our 2016 capital plans based on our outlook for funds flow to minimize any future increases to our debt balances.

Total long-term debt at the end of the year was CAD1.88 billion, comprised of a bank loan of CAD257 million and senior unsecured notes of CAD1.62 billion. We have unsecured revolving credit facilities consisting of an CAD800 million Canadian facility and a $200 million US facility that mature in June of 2019. At the end of December, we had approximately CAD820 million in undrawn capacity on these facilities.

Our bank lending syndicate agreed to relax the financial covenants contained in our unsecured revolving credit facilities twice during 2015. In each case, these amendments were obtained proactively, as we remained in compliance with our unamended financial covenants throughout 2015. Our debt to trailing 12-months EBITDA was 2.97 times at December 31.

We will continue to manage our credit facilities and if the outlook for commodity prices remains low or further deteriorates, we may seek further covenant relief. This could possibly include granting our bank lending syndicate security over our assets. The indentures governing our senior unsecured notes provide that we may secure up to $575 million US of indebtedness in priority to the unsecured notes.

Now shifting to our 2015 reserves, the addition of the Eagle Ford to our portfolio has significantly enhanced the quality of both production and reserve base. In 2015, 86% of our exploration and development activities took place in the Eagle Ford. Our reserves report reflect this investment profile with significant growth in the Eagle Ford reserves offset by reduced heavy oil and thermal reserves.

In the Eagle Ford, our proved plus probable reserves increased 8% to 203 million BOEs and we replaced 205% of production there. Since the time of acquisition in June 2014, we have increased our proved plus probable reserves in the Eagle Ford by 22%. Excluding thermal reductions, our proved plus probable reserves increased 2% to 347 million BOE and we replaced 122% of production.

In aggregate, proved plus probable reserves decreased 3% to 417 million BOE, due largely to shifting thermal reserves to contingent resources at Cliffdale as activity here now falls outside our five-year investment plan. We also saw the removal of heavy oil reserves due to reduced commodity prices and technical revisions. Our year-end reserves are comprised of 81% liquids and 19% natural gas.

We realized finding and development costs of CAD7.68 per BOE on a proved plus probable basis, based on our 2015 operating net back of CAD of 15.78 per BOE, we generated a strong recycle ratio of 2.1 times. And we achieved a significant reduction in our future development costs from CAD3.4 billion at year-end 2014 to CAD3.0 billion at year-end 2015. This was primarily due to decreases in drilling, completion, and facility capital costs, as well as the removal of capital associated with a reduction in our thermal reserves. All in all, we're very pleased with our year-end reserves report for 2015.

Now with respect to our marketing efforts, for 2016, we have entered into hedges on approximately 45% of our net WTI exposure, with 19% fixed at approximately CAD61.50 per BOE, and 26% hedged utilizing a three-way collar structure. We have also entered into hedges on approximately 35% of our net heavy oil differential exposure and 41% of our net natural gas exposures. You can find the details around our hedging programs in today's press release.

The unrealized financial derivatives gain, with respect to our WTI hedges on February 25, 2016, was approximately CAD152 million. Now I'd like to comment on the Outlook for 2016. We are committed to preserving financial liquidity through this downturn and, as we have outlined in the past, we are targeting capital expenditures to approximate funds from operations in order to minimize additional bank borrowings.

Our original production guidance was set at 74,000 to 78,000 BOEs per day with a budgeted exploration and development expenditure range of CAD325 million to CAD400 million. This budget contemplated ramping-up activity in the second half of 2016. Based on the forward strip for the remainder of 2016, we do not plan to execute our heavy oil development program this year. We will forgo the drilling of 12 net (inaudible) wells and 24 net wells at Lloydminster.

In addition, we are proactively shutting in approximately 7500 barrels per day of currently low or negative margin heavy oil production in order to optimize of the value of our resource base and maximize our funds from operations. Should net backs improve, we have the ability to restart these wells within a month. We currently anticipate that this production will be brought back online mid-year 2016.

In the Eagle Ford, we now anticipate a reduced pace of development in 2016, with approximately 4 to 5 rigs and 1 to 2 frac crews working on our lands. At this pace, we anticipate bringing approximately 30 net wells on production in 2016, as compared to our prior expectations of 35 to 40 net wells.

In aggregate, we now anticipate the 2016 capital expenditures of CAD225 million to CAD265 million, of which approximately 95% will be invested in the Eagle Ford. At the midpoint, this reflects a 33% reduction in capital spending relative to our initial expectation and a 53% reduction relative to 2015 capital expenditures. Taking into account the shut-in heavy oil volumes and a reduced capital program, we now have a revised production guidance range of 68,000 to 72,000 BOEs per day for 2016. Our revised production guidance represents an approximate 5% reduction in our original guidance excluding the impact of shut-in volumes.

This compares to a 33% reduction in our capital budget demonstrating the continued strong performance of our assets. Our 2016 capital program will remain flexible and allows for adjustments to spending based on changes in the commodity price environment. And with that, I will conclude my formal remarks and ask the operator to please open the call for questions.

(Operator Instructions)

Dan Kecskes of Global Credit Advisers.

Hey, good morning, guys. Looking at the language in the release with regards to the revolver, it looks like there are things that you would do if pricing goes lower. How do you feel about covenant compliance going into the middle of this year, and, if it gets tight, is this something you are working on now or have not yet started?

Dan, I'll let Rod answer any details that we may have here, but just suffice it to say that we have continued through this downturn to work successfully with our banks on the covenant release that we've [released] to date and feel that's sufficient for now. And, like we mentioned, that we do have, as in our debenture disclosures, the ability to secure part of our facility if that would be deemed necessary in the future.

How long would it take to go from starting those conversations to achieving that, if you felt that oil moved lower in the next month or two?

Yes. It's really something that -- I wouldn't speculate on a start-to-finish conversation on something like that. But our bank syndicate has been supportive. And if we need the ability to do that, that is a potential for the future. But at this stage, that's really all we can comment on.

Perfect. Thank you very much.

Thomas Matthews, AltaCorp Capital.

Hey, guys. Just a quick question on the Eagle Ford well costs: Marathon has come out and said that their well costs have dropped to as low as $5 million per well. Just wondering if you can translate that to yours, or are you still sticking with that $6 million number?

No, we've brought our costs down, essentially in line with the actual data that we've seen to date and the AFEs that we are getting today. So, relative to -- and just for clarity, here, I believe their numbers that they published do not include the tie-in costs. I may be mistaken if they've changed that, but I don't believe they include the tie-in in artificial lift, so we have a little bit of discrepancy.

But our $6 million that we were quoting, we have moved down for this year quite substantially to $5.6 million. And we hope to improve on that as the year goes on. But our numbers that I just quoted include the full tie-in, hook-up in artificial lift -- everything for the well.

Right, okay -- makes sense.

And then, as far as the technical revisions go in your reserve report, it seems like it was -- you had very positive technical revisions down there. Are your EUR assumptions also changed internally here, or is it still the 800,000 boe per well?

They are still coming in on about that range. We've got now four or five different areas and four or five different levels of formation that we're drilling within the entire Eagle Ford window. So, there's a range in that, but that's kind of a decent mid-point.

It's a little early; the IPs continue to improve, as they did from 2014 to 2015. Of course, it's just here in the first quarter in 2016, but hopefully we'll see another round of improvements this year.

Okay. And then, just finally -- so, 30 wells brought on. Some of those are in backlog. How many new wells do you anticipate drilling this year?

It's about 30.

Oh, it is 30. So, kind of 30 for 30, so it's not (multiple speakers)?

Yes, approximately, that's about right. That's about right, Thomas.

Okay. Sounds good. That's all that I had. Thanks.

Thank you.

Sean Sneeden of Oppenheimer.

Hi. Thank you for taking the question. Can you talk a little bit about the heavy oil wells that were shut in, and what do you think you need to see in terms of price, in order to bring those back online? And can you help us just understand what the cost associated with doing both those actions might be?

Sure. It's really -- the volume that we're shutting in is really a reflection of where pricing has been over the past quarter here, so far in Q1 of 2016. So, as we get below $35 a barrel, part of the production becomes uneconomic at kind of a $14 to $15 WCS differential, which is where we were throughout parts of January and most of February. And we kind of anticipated staying shut in through the second quarter.

Now, if we get a price spike, we can bring it on in relatively short order, and would probably seek to do that. But if prices kind of stabilize through the quarter, at the end of the first and on into the second -- we're into spring breakup where roads require work if you're moving crude around. And so, our operating expenses are always a little higher during spring breakup. So, it's a good quarter if you're going to have production shut-in to go ahead and forgo the little bit of incremental operating expense that exists in that second quarter.

And then, as you move into the third, hopefully prices will follow the forward curve. We're up into the $37 to $38, $39, maybe $40 a barrel range; and we anticipated at that stage probably bringing all that back online at that time frame.

Okay. That's helpful. So, anything close to that $40 range, you feel it makes sense -- assuming kind of a normal differential -- to bring it back.

Yes, what we don't want to be is just continually turning it on and turning it off. So, as prices got down into the $20s that we saw -- in the high $20s and low $30s, and the WCS differential was out at $15, that's when we made the decision to go ahead and take off this low-margin or negative-margin production, which some of it is, and go ahead and get that offline; it's likely we'll stay down for the second quarter.

Differentials have moved in. They are in kind of the $12 to $13 range right now, as we move out; so, that will help a little bit as we move into the second quarter.

Prices are up a little bit. And if they move a little bit higher here, towards the higher end of the $30s, we will take consideration of it, knowing the fact that moving crude and fluids around all of the fields in Canada is a little bit more expensive to do during the second quarter. So, we'll take that into account. But if it looks like prices are going to sustain themselves in the high $30s or low $40s, I would expect, at some point here, most of that production would come online, and it would stay online.

Okay. That's helpful.

And can you just remind me what the cost associated -- is it material at all to bring it back online?

Not really. We can get, Brian, the details on that if you've got some modeling, but it isn't very expensive to shut it in. It's not very expensive to bring it back.

Okay. That's helpful.

It does cost a little.

Sure. And then maybe two quick questions: Number one, I appreciate the disclosure on the reserves in the release. I'm just curious if you guys have run what your [PDP], PV10 numbers might be if you were to assume the strip rather than the price deck that was in there?

Yes, if we've got modeling questions like that, why don't we follow up with Brian on the specific disclosures. All we have on NPVs are what are in the NI [51-101] as disclosures at this stage.

Okay. Fair enough. And then, lastly, perhaps as a follow-up to one of the other questions here, if we assume that the strip plays out this year, and we end up bringing back the 7,500 barrels a day, do you feel that you should be able to maintain compliance with the covenant that you guys have suggested there -- the 5.25 times the revolver?

Yes. This is Rod talking. We currently, under current strip prices, see ourselves well through Q2 and probably through Q3 under the current strip. But there's other options that we can do to see ourselves be in compliant with the covenants throughout 2016.

Okay. That's helpful. And in terms of other options, would that include asset sales or something along those lines?

There is a number of options, but I don't want to speculate right now.

Okay. Fair enough. Thank you very much.

Thanks, Sean.

Dennis Fong, Canaccord.

Hi. Good morning, gentlemen, and congrats on another quarter, as well as managing through a tough 2015. I have a couple quick questions. The first one is on the Eagle Ford, specifically with the budget. I was first curious as to how much associated facilities were included in your revised budget? And second, if you are participating in all of the wells drilled within the AMI?

Yes, a couple answers there. I think the facilities number is approximately $20 million and change -- in that range that we've got in the budget. And I don't know that we will spend all of that, but that's what we've got in the remainder of our budget for the Eagle Ford in 2016.

And your follow-up question was --?

If you are participating in all of the wells within the AMI or if you're --?

Yes, essentially we are. We're making that judgment primarily based on the economics of individual wells, as they do vary across our acreage position.

Okay. And just one last question, just with respect to Canada -- the small amount in capital that you are allocating towards Canada, is that for just base maintenance or strat wells or--?

Yes. That's essentially just small amounts to base maintenance capital. We did have one drill well that we did this year already that's in the numbers that's behind us, but the rest of it is just basically maintenance capital.

Okay. Perfect. Thank you.

Thanks, Dan.

Thomas Matthews, AltaCorp Capital.

Sorry, guys, I just wanted to follow up on a prior question. So, the existing guidance right now, the 68,000 to 72,000 boe, that includes all of the shut-in production assuming it doesn't come back on for the entire year? Or do you have a little bit coming back on in your assumptions?

Thomas, that assumes that it's shut in -- that's essentially as we're tapering into it from now until the beginning of the third quarter. So, it assumes that it does come back at mid-year.

Okay. That was it for me.

Thanks for the follow-up.

There are no further questions registered at this time. I'd like to turn the meeting back over to Mr. Ector.

Thank you, Melanie, and thanks everyone for participating in our year-end conference call. Have a great day.

Thank you. The conference has now ended. Please disconnect your lines at this time. We thank you for your participation.