Baytex Energy Corp (BTE) 2014 Q2 法說會逐字稿

All participants please stand by; your conferences ready to begin. Good morning, ladies and gentlemen. Welcome to the Baytex Energy Corp Second Quarter 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 Bus President, Capital Markets and Public Affairs. Please go ahead, Mr. Ector.

Thank you, Mary. Good morning, ladies and gentlemen, and thank you for joining us today to discuss our second quarter 2014 financial and operating results. With me 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. I refer you to our advisories regarding forward-looking statements and non-GAAP financial measures contained in today's press release. I would now like to turn the call over to Jim.

Thanks, Brian. Good morning, everyone. We are pleased to report our second quarter results, which include 20 days of operations from our recently acquired Eagle Ford asset. The Eagle Ford is one of the premier resource plays in North America, and will be an important growth engine for Baytex going forward. The second quarter of 2014 was very active for Baytex, and we also believe it was marked by some significant achievements. I would like to highlight a few of those achievements for you beginning with a few in operating results. We generated production of approximately 67,000 boes per day, which was underpinned by strong performance from our base business. Production increased 12% over the first quarter of 2014 and 15% over the second quarter of 2013.

We delivered funds from operations of CAD202.5 million or CAD1.49 per basic share. This excludes acquisition-related costs of CAD37 million and represents a 19% increase over the first quarter of 2014, and a 30% increase over the second quarter of 2013. We realized an operating net back of approximately CAD41 per boe, which is one of the strongest in company history. This represents an increase of 11% over the first quarter of 2014, and 28% over the second quarter of 2013. Our Canadian operations generated an operating net back of approximately CAD39 per boe, while the Eagle Ford generated an operating net back of approximately CAD54 per boe. And, lastly, we maintained a conservative payout ratio net of dividend reinvestment plan participation of 37%. The second area I would like to highlight relates to the advances we have made executing some key objectives.

As you well know, we closed the CAD2.8 billion acquisition of Aurora adding 22,000 net contiguous acres in the Sugarkane Field located in south Texas in the core of the liquids rich Eagle Ford shale. Subsequent to the quarter we announced the divestiture of our North Dakota assets for gross proceeds of approximately CAD357 million. This transaction is scheduled to close near the end of the third quarter, and was the result of the portfolio review previously announced. For the first time we assess the -- in addition, for the first time we access the US high yield market in a material way completing the issuance of CAD800 million of senior unsecured notes in two equal [tronches of CAD400 million.

These notes have maturities of 7 and 10 years, and bear interest at 5 1/8 and 5 5/8. We also entered into our first Brent-based heavy oil contract during the quarter and I will provide more color on that later. Lastly with the closing of the Eagle Ford acquisition, the monthly dividend on our common shares was increased by 9% to CAD0.24 per share from CAD0.22 cents per share. Now, I will discuss some of the details of our operations during the second quarter. Production on our base business, which excludes the Eagle Ford for this part of the discussion, averaged approximately 61,000 boes a day during the second quarter, a 2% increase from the first quarter of 2014, a 4% increase from the second quarter of 2013.

The Eagle Ford production averaged approximately 28,000 boes a day for the 20-day period, resulting in approximately 6100 boes per day being added to our average volumes for the second quarter. Capital expenditures across all operations for the second quarter totaled CAD149 million, and included the drilling of 51 gross or 28 net wells with 100% success rate. Spending on our Eagle Ford assets totaled CAD26 million and included the drilling of 11 gross or 2.9 net wells. At the end of the quarter drilling operations in the Eagle Ford were underway on 10 gross wells. 40 gross wells were awaiting fracture stimulation and 12 gross wells were being stimulated or prepared for production.

Our average working interest for these wells is approximately 27%. Production from our Peace River area properties averaged approximately 26,100 barrels per day in the second quarter, an increase of 1% from first quarter of 2014, and 15% from the second quarter of 2013. We drove 12 cold horizontal producers encompassing a total of 148 laterals in the Peace River area during the second quarter. In our Lloydminster heavy oil area, second-quarter drilling included 9.2 net oil wells. We continue to expand the use of multilateral horizontal drilling techniques, drilling two multilateral wells a Lloydminster, one with two laterals and one with four laterals. In the Cliffdale area of Peace River, thermal operations continued as planned with steam injection at Pad 2 commencing on schedule in June. At the SAGD Gemini pilot project, oil production commenced in April of 2014 and the 600 meter horizontal well pair is currently producing approximately 1000 barrels per day, which is in line with our expectations.

We continue to analyze reservoir performance here to confirm the commercial viability of a future development project. Now, I want to spend a few minutes on heavy oil pricing and our marketing efforts. The discount for Canadian heavy oil, as measured by the differential to WTI, averaged 19% in the second quarter as compared to 23% in the first quarter of 2014, and 20% in the second quarter of 2013. The strong heavy oil market reflected increased refinery demand in the US Midwest and a continued increase in rail capacity exiting Canada.

Our realized heavy oil price in the second quarter averaged 88% of WCF, up from 83% one year ago. These improved price realizations reflect both strong benchmark prices and increased utilization of rail. In the second quarter approximately 55% of our heavy oil volumes were delivered to market by rail as compared to 42% for the full year 2013. For the third quarter we expect to deliver approximately 60% of our total heavy oil volumes to market by rail. Our marketing team continues to focus on opportunities to further mitigate the volatility in WCS price differentials by transporting crude oil to higher value markets by rail.

I am pleased to announce that during the second quarter we entered into our first Brent-based fixed differential heavy oil sale. This six-month term rail contract runs from October 1, 2014, to March 31, 2015, and is expected to represent approximately 25% of our crude by rail volumes during that time frame. For the third quarter we have entered into hedges on approximately 51% of our WTI exposure at a weighted average price of approximately $96 USD per barrel. Our total monetary debt at the end of the second quarter is CAD2.46 billion with CAD461 million in undrawn capacity on existing credit facilities. We have ample liquidity to allow us to execute our growth and income model, and we continue to target a total monetary debt to FFO ratio of under two times. I will now touch on the North Dakota asset sale in a bit more detail.

In anticipation of our Eagle Ford transaction, we initiated a portfolio review of our assets late in the second quarter. During this review we identified assets representing 5% to potentially 10% of our production that are not likely to command capital going forward given the fact that our plans are to direct capital to the highest rate of return projects in our portfolio.

Earlier this week, we announced that we had entered into an agreement to sell our North Dakota assets with an effective date of July 1, 2014, for gross proceeds of approximately CAD357 million. Production from the North Dakota assets averaged approximately 3200 barrels of oil equivalent per day in the second quarter, and as of December 31, 2013, the assets were estimated to have proved plus probable reserve of 53.5 million barrels of oil equivalent. For Baytex the disposition proceeds represent attractive metrics of approximately CAD112,000 per barrel flowing barrel, and CAD20 per boe of proved plus probable reserve including future development costs.

Our after tax net proceeds from the sale of are estimated at CAD275 million, and will be applied against outstanding bank debt. Before I close, let me update you on our guidance, which now reflects the expected closing of the North Dakota asset sale. Our capital plans are unchanged from the guidance we just issued last month, and as we had previously incorporated a reduction of spending in North Dakota during the second half of the year, so for the second half of 2014, again, our capital expenditures for exploration and development activities are forecasted to be CAD440 million to CAD465 million, and we expect to generate an average production rate of 86,000 boes to 88,000 boes per day.

Our full year 2014 production guidance is 74,000 to 76,000 boes per day with budgeted exploration and development expenditures of CAD765 million to CAD790 million. In summary, our second quarter results reflected strong production volumes, increased funds from operations and improved net backs. For the second half of this year we will continue to implement our capital program, targeting over 90% of our spending directed to our three key oil resource plays, the Eagle Ford, Peace River and Lloydminster, which provides some of the highest rate of return projects in North America. We are certainly pleased with our direction and are well positioned to deliver future growth and income. And with that will conclude my formal remarks, and I would like to ask the operator to please open the call for questions at this time.

Thank you. We will now take questions from the telephone lines. (Operator Instructions). The first question is from Mark Friesen from RBC Capital Markets. Please, go ahead.

Thanks, good morning. My first question is just about the Brent [link contract that you implemented. Are the volumes of that coming out of existing rail shipments, or is this incremental to the volumes you've already been shipping by rail?

Good morning, Mark. This is Jim. It is a bit of a mix. As you noted our third -- our projection for third quarter volumes on rail are going up, so it's really a matter of how much rail total capacity we are going to have in that six-month duration. I would call it as partially incremental in a partial consolidation of some of our other contracts into this one.

Okay. And are you able to give any guidance on to what kind of differential from Brent you've entered?

No, what we have disclosed is -- for competitive reasons is probably all you are going to get on that for the time being.

Moving over into Lloydminster and the multilateral wells that you have been starting to drill there, specifically. How should we be thinking of your multilateral program there? What are, I guess, the costs or operating benefits of the wells, and should we be thinking of this as driving improved economics, or could we expect some production growth from the Lloydminster or maybe both? How should we be looking at the multilateral program?

It is certainly going to improve if it continues to work our capital efficiencies, because, you know, you only have one vertical well board and you are getting the multilaterals out of it. But I'll let Rick Ramsay here, our chief operating officer, provide just a little more color for you if that's okay, Mark.

Yes, please.

Good morning, Mark. We are fairly early into translating that technology over to our Saskatchewan assets, and really, as Jim has commented, it's pretty much going to be a capital efficiency gain that we are going to see there. Generally, we are spending about CAD950,000 for a drill complete and equipped for a single leg well there, and for a two well -- two-leg well, we are bringing that down to about CAD1.1 million to CAD1.2 million, so that's really where we are going to be seeing the efficiencies.

Yes. Great, That's good. Do you expect to see any production growth out of Lloyd, or are you still planning to keep that region flat?

That's really not going to change our overall production profile. It is just really an improvement on the capital side.

Okay. Great. Maybe while I still have you, Rick, a question on Cliffdale. Can you maybe comment on the schedule or the pipeline of follow-up thermal module?

You know, Mark, it is sort of early into our second module will there and still very much learning how the performance is looking. We just started steaming in June on our 13--10 facility, and we really want to understand better the performance there. Obviously, with the new Aurora acquisition we will be making decisions on capital allocation across the entire organization as we work our way through the budget process, so it's sort of premature both from a technical perspective and the capital availability perspective on when we will be moving forward with the next modules there.

Okay. And just my final question is about the Eagle Ford. Are there any Austin Chalk locations currently scheduled, or when do you think you might test the Austin chalk locations?

Mark, this is Jim, again. As you well know, we've had had an announcement of another chalk well with 30-day IP that came out. I can't remember if it was may or around that time frame but it's 1600 barrels a day, which is by far the best results. Certainly pleased with that and to get to your question, yes there are a few more tests being put forth this year to continue to delineate the productivity of the upper Eagle Ford/Austin Chalk combination there.

Thanks very much Jim and Rick.

Thank you.

Thank you. The following question is from Dirk Lever from AltaCorp Capital. Please, go ahead.

Thank you very much. Good morning and congratulations on the results. When you are looking at your production and what was core and you were talking about 5% to 10%. So, you've sold off the assets in the Bakken. So, you soldier North Dakota assets. Do you have some more, some smaller asset, we can see disappear over time as you sell them off or is the sale program done now?

I wouldn't say it is done, and I don't want to speculate too much on the size of what remains, because we are just sort of sorting through the next phase of that from when we started this, Dirk, it was just a couple months ago. We really worked hard to get that put together and to get a full bid [suite in. We are very pleased within just a few weeks, 6 to 10 weeks to get a PSA fully signed, so I was quite pleased with the team's efforts on that. We will be looking at a few other things that really don't fit. That are legacy assets of not nearly as in individual pieces as big as what the North Dakota one was, but we will look at those as we go forward here, and there is probably a few other little things we need to just -- were better off in somebody else's hands.

Got you. So we shouldn't be surprised if there is some small (inaudible) that are sold off over a period of time?

Yes, I wouldn't be.

Thank you very much.

You bet, Dirk.

Thank you. The following question is from Patrick Bryden from Scotiabank. You may now proceed.

Good morning, gentlemen. Just curious on the Eagle Ford. If you can give us a sense on how you think [boes may progress given the drillings and completions and tie-ins that are in the hopper.

Sure, Pat. In general, I would say a couple of things. One, as we have move to these large six-well pads where you are drilling six wells on each pad, and then you are coming back to zipper frac everything together and then bring them on altogether in a sequence, the inventory of existing wells has increased a little bit, which is fine. That's just part of what those capital efficiency gains bring you, so you need to think of it that it's going be a little lumpier than it has in the past coming forward. We will see many wells coming on at the same time more than in the past. A boost from that and then a little bit of a delay and you will see it -- I'd like to use the word lumpy in our production forecast going forward. On a quarter to quarter basis it may not be too bad, so I don't want to overemphasize that because there is quite a bit of activity as we've got about 10 rigs running on our acreage here. You will see it continue to ramp into -- you -- I've rattled off the inventory numbers, and as we move into August those wells over the next couple months that are inventory, a bunch of those will come online and will boost production into the second quarter, or excuse me into the third and then on into the fourth, as well, as that program continues.

Great and any kind of seasonal patterning to it or just chewing away with the 10 rigs and getting things done?

There is not a lot of seasonal patterning that I would project at this point in time. Once in awhile if winter hits down there it can freeze some things up and really cause some production problems for short durations of moving fluids around. You can imagine in south Texas there is not a lot of heat tape running on water lines and things like that, so if it ever does freeze it can raise a little bit of havoc. From a drilling standpoint it is 24-hour operations, 365 days of the year.

Great, and --

And all of the equipment is dedicated, the frackers are dedicated. The rigs are fully dedicated, so it isn't like you are bringing too many in and laying them off either.

Understood, thank you. And is there any differentiation or distinction between sort of the oil versus liquid windows are going to be pursuing, or is that split looking to be consistent with the past?

It should be fairly consistent. It will vary on -- a couple of things that drive that. One, you are trying to maximize the individual rates of return although, all of these are very, very high. We are not too worried about that. You are still trying to do that as well. We have conversations with Met the about that. Secondly, you know, the volumes have continued to ramp up, and you are expanding the production facility, so you try to time your drilling where the -- in best proximity to production facilities have got the expanded capacity to take the fluids in. That may drive a little bit of it as we go forward as well, Pat.

Okay. Great. And last question, it's always tricky to figure out pricing dynamics. Any commentary on some of the recent changes legislatively and/or supply versus demand in that neck of the woods?

There have been several things out here recently in the press over the past couple months. Everyone knows that you have the couple of companies that were involved in getting a stabilizer classified as processing equipment, so that the field condensate in some cases can be classified as exportable. It looks like that is moving forward. You had a recent discussion from the commerce department saying that they hadn't changed the rules. That the rules have always allowed export of products, and it is clear anytime you go through some sort of processing equipment that stabilizes crude, whether through a tower or other devices, the refineries have been doing it for years. It's really that this is happening in the field in field gas plants and in field stabilization columns or stabilization tanks. To pull off the lighter ends of propanes and butanes, there is not any difference between what is happening from a chemistry standpoint in those fluids, and it sounds like a lot of this is getting exported. I don't know if you read the data. There was something out about the first very large, full tanker condensates is heading out of the Gulf of Mexico and that caught a bit of news. I think it's just a matter of people getting comfortable that the rules are being applied properly and that the classification of your equipment does, indeed, meet the condensate process guidelines.

Got it. Appreciate that. I will get out of the way if I can just have one more last question, please, may be for Rick. When we look at the Gemini steamed oil ratio, is it possible to get a sense for where the ISORs are right now, or at least maybe where you are thinking the steamed oil ratios are for the life of wells? Thanks a lot.

Yes. Certainly, you know, currently, we started up our steam circulation in late February, and we are currently running with a [cume SOR of 3.3, and an instantaneous SOR of 1.9, and that's as probably as good as what we could hope for.

Great. And, [life of well, do you have any thoughts as you think ahead?

Sorry, I didn't catch your question?

Sorry, the life of a typical well in that area, do you have any thoughts as you think about the potential for commerciality?

You know, the life generally ranges -- I guess, you know, where it is a pilot project for us, and we are early days into the production life there, but the typical life would be about a five to six year time frame from a steaming perspective, and then just converting over to coal production afterwards.

Okay. And and SOR might be in the range of say three or something like that or two?

Probably be from a [cume perspective down in the low two range.

Okay.

If it also matches, historically, with what we've seen in some of our other projects.

Great. Thanks very much for your time, everyone. Appreciate it.

Thanks, pat.

Thank you. The following question is from [Peter Oten] from Bank of America/Merrill Lynch. You may now proceed.

Good morning, guys. Just a follow-up of Eagle Ford and Pat's question. Just for a little more granularity. If you take the 20 days and pro rate, you've got something about 27.5 thousand boes a day as a second, maybe end of second-quarter rate on the Eagle Ford. Looking at your second half guidance of 86 to 88, that would almost imply that Eagle Ford has been fairly flat in the second half if you assume Canada is 60,000 boes. So, just looking for a little bit more granularity around whether Canada comes down what kind of exit rate you'd be looking for on the Eagle Ford appreciating that the production is lumpy.

Peter, just in general, you know, we are looking to continue to maximize our capital efficiencies here. I won't take this all the way back to the big picture of -- we're -- what we have going forward, and what we have been doing throughout the long-term history of Baytex, is providing capital efficiencies that are good enough to throw off enough cash to support the dividend, and a moderate growth rate of around 6%, so as we go forward, we are trying to balance that. So, if our production gets higher in one area we may pull back more capital in another to make a sure our growth rates don't get out of hand, and that we manage that inventory over the long haul and continue to deliver consistent results around kind of that 5% to 6% growth rate and continued effort. And then don't forget that we take out our North Dakota sale in this volume here, as well, and for the second half the projection of North Dakota was about 3800 boes a day net to -- Baytex volumes as we go forward, and that's already out of those numbers as we go forward. So, I that provides the color of how we are going to try to manage it, as opposed to exactly watch the numbers will be. It will be in that range.

Do you have control on the Eagle Ford, I guess, per say? I guess That's the question around Marathon's goal and where they are going to grow it towards year-end? And would you expect Canada to decline, I guess, as you fund that growth on the Eagle Ford side?

Parts of it may. It just depends on the overall production that we get there, but, like I said, I think the biggest piece you might be missing is the separation of North Dakota from the remaining part of the year in those numbers.

Okay. Thanks a lot, guys.

You bet.

Thank you. The following question is from Phil Skolnick from Canaccord Genuity. Please, go ahead.

Yes, thanks. How have the well results in the Peace River been progressing? Have you still been experiencing those high IP rates you had been in the past?

I will let Rick give you the details on that. Go ahead, Rick.

Sure. Yeah, Phil, we drilled 12 wells in Q2 followed up by eight wells which we drilled through Q1., And overall the performance is -- we do have a number of different tiers that we focus on, but, overall, the performance is fitting exactly in the range that we anticipate.

Are you seeing any of those high rate wells, or are they just now -- they are coming back to the more normal levels that you saw in the past?

Yes. We are seeing a range across those levels. We have seen a couple up in that higher range that we were reporting previously, and some coming in a little lower, in the lower part of our range, but overall averaging out sort of right in the middle of the guidance we've provided on expected performance from those wells.

Okay. Thanks.

Thank you. There are no further questions registered at this time. I would now like to turn the meeting back over to Mr. Ector.

All right. Thank you, Mary and thanks everyone for participating in our second quarter conference call today. Have a great day, everyone.

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