SM Energy Co (SM) 2012 Q3 法說會逐字稿

Good day, my name is Lisa and I will be your conference Operator.

At this time, I would like to welcome everyone to the SM Energy third quarter earnings conference call.

All lines have been placed on mute to prevent any background noise.

After the speakers' remarks, there will be a question-and-answer session.

(Operator Instructions)

At this time I would now like to turn the call over to your host, Mr. David Copeland.

Please go ahead.

Thank you, Lisa.

Good morning to all of you joining us by phone and online for SM Energy's third quarter 2012 earnings conference call and operations update.

Before we start, I would like to advise you that we will be making forward-looking statements during this call about our plans, expectations and assumptions regarding our future performance.

These statements involve risks that may cause our actual results to differ materially from the results expressed or implied in our forward-looking statements.

For a discussion of these risks, you should refer to the cautionary information about forward-looking statements in our press release from yesterday afternoon, the presentation posted to our website for this call, and the Risk Factors section in our Form 10-K filed earlier this year, and the form 10-Q that was filed this morning.

We will also discuss certain non-GAAP financial measures that we believe are useful in evaluating our performance.

Reconciliation of those measures to the most directly comparable GAAP measures, and other information about these non-GAAP metrics, are described in our earnings press release from yesterday.

Additionally, we may use the terms probable, possible, and 3P reserves, and Estimated Ultimate Recovery, or EUR, on this call.

You should read the cautionary language page in our slide presentation for an important discussion of these terms, and the special risks and other considerations associated with these non-proved reserve metrics.

Company officials on the call this morning are Tony Best, our Chief Executive Officer; Jay Ottoson, our President and Chief Operating Officer; Wade Pursell, Executive Vice President and Chief Financial Officer; Brent Collins, Senior Director of Planning and Investor Relations; and myself, the Company's Senior Vice President, General Counsel and Corporate Secretary.

With that, I will turn the call over to Tony.

Thank you, David.

Good morning, everyone, and thank you for joining us this morning for our third quarter 2012 earnings call.

I'll make a few introductory remarks, and then Wade and Jay will provide their respective financial and operational reviews.

We'll be referring to slides this morning from the presentation that was posted on our website last evening, and my comments will begin with slide 3.

We reported record quarterly production of 57 BCFE or 9.5 MMBOE, which is a 13% increase in total production from the previous quarter.

As Jay will elaborate in his operational update, we started up a number of additional gathering system facilities in our operated Eagle Ford shale program in the third quarter, allowing production growth substantially during that quarter.

Lastly, we have increased our full-year production guidance, with a range of 215.5 to 218.5 BCFE from our previous guidance range of 210 to 217 BCFE.

In all, it was a strong quarter for the Company, and in addition to our production growth, we met or beat guidance on all metrics.

I will now turn the call over to Wade for his financial update.

Thank you, Tony, good morning.

I will start on slide 5 with a recap of our quarterly performance.

Adjusted net income for the quarter was $9.7 million or $0.14 per diluted share, in our EBITDAX ask for the quarter came in at $261 million, both of which I think where well above consensus estimates.

We regard to our performance against guidance, our average daily production at 620 MMCFE per day was 6% above the midpoint of our production guidance range of 565 to 603.

This out-performance was largely driven by the growth in our Eagle Ford shale program, which Jay will touch on later in the call.

On the costs side, you can see on the slide we came in below the low end of guidance on most metrics, with the remaining metrics meeting our guidance range.

I will cover a few highlights.

LOE was below the low end of the range, due primarily to the operated Eagle Ford shale program.

Cost saving initiatives and the installation of a water recycling facility have lowered costs below our earlier expectations.

Transportation expense was lower than expected, due to anticipated additional fees relating to oil transportation and compression which have yet to occur, as the systems were not placed in service during the quarter.

From a production tax standpoint we had lower than guided production taxes, due primarily to severance tax incentives for deep gas wells in the Texas portion of our Haynesville shale program.

Lastly, G&A overall was lower than guided, due primarily to greater production volumes.

Moving to slide 6, I will quickly discuss our financial position.

The third quarter was pretty quiet with regard to financing, as our capital structure remain unchanged with no new debt issuances or other financings.

Our debt-to-book cap rose slightly, ending the quarter at 47%, and our debt-to-trailing 12-month EBITDAX stands at 1.3 times.

Our long-term debt at the end of the quarter totaled about $1.3 billion, with $1.1 billion of that being unsecured term debt, with the earliest maturity in 2019.

Regarding our secured credit facility, I will point you to slide 7. Our borrowing base currently stands at $1.55 billion, and our bank commitment amount remains at $1 billion.

At the end of the quarter we had $228 million drawn, leaving $772 million of undrawn commitments.

A summary of our current hedge position is included in the appendix to the slide deck, and detailed hedging information is included in our Form 10-Q which was filed earlier this morning.

So with that, I will turn the call over to Jay.

Thank you, Wade.

I will begin my remarks on slide 9. Production for the third quarter was 57 BCFE, an increase of approximately 13% from the second quarter.

The majority of that growth was driven by our Eagle Ford shale program.

I would also like to note that our product mix for the quarter shifted to 55% gas, and as we continue to deploy capital in oily and rich gas programs, we are on track to meet our target of a 50/50 liquids to gas production ratio in 2014.

Moving to slide 10, I would like to talk about our operated Eagle Ford shale program.

This program has clearly been a large driver of production growth for the Company over the past year, with quarterly production volumes increasing by 90% from the third quarter of 2011.

As for sequential growth from the second quarter, our operated program grew by 18% to an average of 243 MMCFE per day for the quarter.

Our ability to grow production during the quarter was largely driven by a step change in the build-out of our gathering system in the operated Eagle Ford program.

During the quarter, five of the six tank batteries that we anticipated installing in the Galvan area during 2012 were installed and operational.

As we mentioned before our program for this year was back-end weighted, with approximately 60% of our well completions occurring -- expected to occur in the second half.

During the third quarter we completed 24 wells, compared to the 30 wells we completed in the entire first half of the year.

For the full year, we expect to drill complete about 74 wells, and we will have approximately 20 wells waiting on completion at year-end.

At the end of the third quarter we dropped one of our rigs in the program, with increasing efficiency, and expect to exit the year running five operated rigs.

I should note that although we do expect to be running up against our downstream limits on wet gas production capacity at some point in the fourth quarter of this year, we do have additional downstream capacity coming for this program in 2013.

I am now on slide 11.

In our non-operated Eagle Ford program, we reported net production 14,000 BOE equivalent per day for the third quarter.

As we noted during our second quarter call, our second quarter reported production in this area was negatively impacted by revisions to prior estimates.

This, combined with healthy underlying production growth, resulted in an outsized percentage of sequential growth in the third quarter.

The operators' activity level has remained constant, essentially all year, with 9 to 10 rigs running, and we expect that level of activity to continue for the remainder of 2012.

We're currently being carried by Mitsui on substantially all of the drilling and completion activities through 2012, and expect for that carry to last another two to three years.

Moving on to slide 12, we will discuss our Bakken/Three Forks program.

During the third quarter we operated four drilling rigs, with one rig in the Gooseneck area, and the other three in our Raven and Bear Den prospect areas.

This program continues to deliver strong production growth, and reported a 6% increase in sequential production growth from prior quarter, up to 11,000 BOE per day, and nearly double the quarterly production volumes from the third quarter of 2011.

We're very pleased with the results we're seeing in the Williston, both from a production and economic standpoint, as costs have recently been moving in a favorable direction in the play.

Moving to slide 13, our Mississippian Limestone program in the Midland Basin continues to have encouraging results.

We are currently running two rigs, and plan to run those two rigs for the remainder of the year in delineating our acreage position in the play.

Our wells in the area have averaged around 580 barrels a day for 7-day rates, and have reported 30-day rates around 480 BOE per day.

The average 30-day rates during the quarter were negatively impacted by some experimentation we've been doing on our artificial lift designs.

So although these numbers are somewhat lower than what we reported last quarter, it's really not a reflection of the productivity of the wells, it is really more a function of us working through our artificial lift designs.

One of the wells we drilled in this quarter was a successful step out to the southern portion of our acreage block, and I am happy to say that we're currently flowing back what appears to be a successful test in the northern side of the block as well.

So we are increasingly confident about the overall prospectively of our 68,000-acre net position.

We still believe that development well costs in the play will be around $6.5 million, and look forward to continuous improvement in that area.

On slide 14, we've updated our production guidance for the year, increasing full-year 2012 production to a range of 215.5 to 218.5 BCFE.

Based on the midpoint of that guidance, we are now projecting an approximate 28% growth in production from 2011 to 2012.

We're currently working on our capital and production plan for 2013, and expect to release that plan in mid-to-late December.

I'll now turn the call back to Tony for his closing remarks.

Thank you, Dave.

Before turning the call over for your questions, I would like to sum up a few key points from the quarter.

First, we had a great quarter on the production front, with quarterly production hitting a record of 57 BCFE, and our two largest programs nearly doubling production volumes from the third quarter of last year.

Second, we have installed five of the six tank batteries in our operated Eagle Ford program, and expect the sixth battery to be installed by year-end.

Third, we have increased our full-year production guidance to a midpoint of 217 BCFE, implying a 28% production growth for this year.

Finally, our balance sheet and financial position remains strong, with the capacity to fund our key programs going forward.

I will now turn the call over to address your questions.

(Operator Instructions)

Welles Fitzpatrick, Johnson Rice.

Morning.

Morning, Welles.

On the Eagle Ford, obviously exiting at five rigs, but you talked about bumping up against capacity in 4Q, and then obviously get a little bit more in '13.

Do you guys have, and I know you will have the full plan in late December, but do you have an idea of whether you want to be running four or five to be able to kind of keep up with that ramp?

And if you go down to four, would we expect kind of $120 million, $140 million of savings from that rig drop?

This is Javan.

Welles, we haven't released yet.

We are still working it.

My gut feel is we're probably going to need to run five rigs next year.

There may be a portion of the year where we can cut a little bit, but I think it's probably a five-rig program in order to keep up.

If you remember, there is a very large increase in our downstream capacity that happens at mid-year, where our downstream capacity goes from -- right now it is about 268, it goes to 382 at mid-year next year, so we got to get ready for that and make sure that we can make our shipper pay volumes.

So I think right now, we are thinking it's probably a five-rig program.

Our drilling is getting more efficient, and one of the things I did not -- should have mentioned earlier was, you know, we just drilled a Galvan well in less than 13 days, so we can -- we're getting more efficient in our activity.

Five rigs will probably get us where we thought, six rigs would've been a year ago, but I think it is probably going to be a five-rig program.

We are going to look at our capital program overall, though.

Tony wants us to make sure we are disciplined about this.

We are going to try to get back closer to our cash flow next year, as we've said repeatedly, and we are going to try to flatten the growth in our capital program.

So we will be looking at all the capital programs through the Company.

We've got to make room for some of the Permian here, so you can probably anticipate that we will trim rig count a little bit in some areas.

Okay.

And, on the Permian, is it safe to assume that, that 10,000-plus acres that you added is in the Leonard and not on the New Mexico side?

That would be a good assumption, yes.

Okay.

And then, one last one, kind of a Hail Mary, but other operators are beginning to talk about Nevada.

Do you guys have an exploration program or a plan for one in '13, and if so, when do you think you will talk about it?

That is a Hail Mary.

(Laughter)

Well, we're not ruling out the prospectivity of running out of acreage at this point, certainly.

But, at this point, I do not have any comment on what our program would be in '13 for Nevada, or really any comment about, in general, what our exploration programs are at this point.

There's just nothing material to say.

No, that is perfect.

Thanks for answering the questions, and congrats on the good quarter.

Thanks, Welles.

Brad Pattarozzi, Tudor, Pickering & Holt.

Thinking about 2013 plans, it's still a little early as you say, but in terms of ramping activity in the Permian, if you are going to maintain activity in the Eagle Ford at five rigs, where would you think about slowing down activity to reallocate capital into the Permian?

This is Javan, again.

Essentially all our acreage in the Bakken and all our acreage in the Granite Wash is HBP'd at this point, so we have opportunities there.

Again, with increasing efficiencies in the Bakken, and we can moderate our pace in the Granite Wash.

I would also note that this year of course we're not going to be drilling any Haynesville wells, which we did have some spend in the Haynesville last year which we will not have in 2013, so we have a little bit of room there as well.

So -- in fact, we do not have our rig count much in order to support our program in the Permian.

And I would say at this point, in the Permian, we're pretty confident in our Mississippian position.

We haven't decisioned our shale program yet, and we may very well go into the year without budgeting a lot for that program, and then, assuming success, add some later in the year if we need to.

Okay.

And thinking about the Permian again, it is still early, but in terms of giving more detail in terms of well results in the Leonard or the Mississippian, is that going to be coming with 2013 plans in December, or is that more of a 2013 timeframe in terms of getting more details on well results?

Well, the Mississippian, I think we've been very transparent about our well results, and I don't think you should anticipate getting a lot more than that.

In the Leonard, what we have said is we have four wells drilled, and we are in various stages of flowing back our completion.

I don't think we will have a definitive statement about whether all those wells -- whether we think we have a program or not, until probably sometime in the first quarter.

Okay.

And staying with the Permian for a second, capacity -- take-away capacity in the Permian, is that something to worry about now or is that something that you need to think about more into mid-to-late 2013 into 2014?

Well, we are not particularly concerned about it right now.

The area that we're in there, we're trucking the oil, so that is not much of an issue.

The gas system up there is getting built out.

We don't make that much gas, so it is not a huge issue.

We are working it.

In the shale program, I think we have a pretty solid plan there, and we will work through that.

Again, that program is basically contingent on success, so we are not getting too worried yet.

I think we have a pretty good plan.

It's a lot simpler, obviously, than the Eagle Ford system that we had to build out.

So we will see, but I think we're in pretty good shape.

Okay, great.

And the last for me, moving up to the Bakken, what do you think from a current -- incurred well costs and service costs, and also differentials?

Well, this is Javan, again.

The differentials have been moving a lot, and obviously it moved from a positive number to a negative number just in the last month.

The last number I saw was minus 10, and I saw that actually in an analyst report yesterday, and so I get -- you know, it is moving pretty quickly.

So we have moved from what was essentially a $90 world and a positive differential to an $80 world and a negative differential, in a month.

So, obviously, that is negative.

On the cost side, we're probably down about 5% from the peak at this point.

Continue to see opportunities.

We have had some rig -- potential rig cost reductions as we renew rigs, although I kind of think that will go away here as people firm up their rig plans for next year.

And then we have also seen some cost reduction on the frack side, and that is where most of our cost savings is coming from, is on pumping services.

Rig count up there is still lower than it was a year ago, and I think people are generally consolidating into more efficient pad drilling rigs, and there will be quite a bit of competition, I think, for those -- for the better rigs, and so I think the rig numbers are likely to firm up a little bit.

But in general, I think -- if you say 5%, it's probably a reasonable number.

All right, that is it for me.

Thank you.

Thanks, Brad.

Pearce Hammond, Simmons & Company.

Congrats on a great quarter.

Thank you, Pearce.

Just one quick question on realizations out of the Eagle Ford.

How are you seeing those trending, and some -- are you seeing some opportunities to improve those over the course of the next year?

As far as your differentials?

Yes, I understand.

I think if you look at NGO realizations quarter over quarter, they were down a little bit, although our percentage of what we get from an NGO barrel actually went up a little bit so they were -- I think on net, they were down slightly.

In general, we think NGO realizations will be up some over the next few quarters.

On the oil side, I think they are pretty consistent with what we have been seeing.

We always have been -- we have a gravity deduction there which, in the end, results in us having somewhat of a discount, even to WTI, although we do benefit from Louisiana prices being higher.

I do not think we're anticipating any significant change in those.

We will see some benefit when we start pipelining our oil in late year, probably in December this year.

We will probably see about a $3.00 or $4.00 a barrel gain on the transportation side of the oil side, which will end up in our net back.

So that is the one thing I would say should get a little better.

Thank you very much.

Thanks, Pearce.

Rudy Hokanson, Barrington Research.

A question on the tank batteries.

Has that become an issue that is resolved in terms of timing for what you need?

Or was it just that you were able to complete five of them, you know, earlier than you had expected, but going forward if you're going to need more there is still a delay in the system?

At this point, we do not think we need any more until next summer sometime, and we're working on other issues, compression, pipeline.

Really, the big focus this quarter is getting our oil system and our condensate system hooked up.

We will see some production interruption during the quarter associated with doing some tie-ins and slug catchers, and some things we need on the liquid side.

So I mean there is a continual -- every month, every month, every week, every quarter we're doing infrastructure additions.

At this point, we have the big centralized tank battery stuff mostly behind us for this year, and really the next bottleneck for us is probably our downstream wet gas take-away capacity, which is -- right now is 268, and then we get an increase in that in '13.

So, I think it's -- you know, we've grown production 90% in the last four quarters and, you know, sometimes it is a little lumpy due to things that happen in the field.

But, in a general sense, we are growing pretty fast, and I do not see a lot in front of us right now that keeps us from continuing to grow.

So, we continue to manage those, we will try to guide each quarter as best we can, but I think it is pretty obvious we are on a pretty significant growth trend here, and it is just a matter of when it occurs, not if.

Okay, thank you very much.

Thanks, Rudy.

Joseph Bachmann, Howard Weil.

Just had a quick question on the Eagle Ford, and noticed that on the non-op acreage, again, the production versus what kind of what Anadarko is talking about is -- I don't want to say blown out, but it's increased again, similar to the first quarter.

I was just wondering if you guys feel that you've got a better handle I guess.

Then Jay, you talked about earlier this year that you guys needed to do a better job of getting that forecast, just kind of get your thoughts on that.

Yes, this is Wade.

I will say something first, and Jay can add if he'd like.

I would say that, remember, if you're looking at the slide 11, if you went back to last quarter and remembered my remarks, if you added back 1,400 barrels a day, I think that is the number I said, from an out-of-period standpoint, if you added that back in the second quarter and then looked at the growth this quarter, it is about 28%, I think.

Okay.

And I noticed Anadarko earlier this week said that their whole Eagle Ford position grew 23%.

And that is not an apples-to-apples, as we've discussed in the past.

Depending on which wells come online, we have different percentages in the different wells, but that is pretty close.

It's not going to be perfect.

I'm not trying to say that our percentage is going to be that close to theirs every quarter, but I think it is getting a lot better, I guess is the way I would characterize it.

Okay, great.

And then, last one for me is just -- Jay, just as to timing, you said 2013 for the wet gas take-away.

What point in 2013 should we look for that?

Well, we have some increased take-away in January, about 30 million a day, and then there's another, I think it goes -- well, let me just give you the actual numbers -- 268 right now, it goes to 299 in the first quarter.

Again, we need to careful with all these numbers, because we're not going to be producing -- 299 implies a net production of something like well over 300, and it will take us some time to get to those numbers after we have this capacity, but -- so we get to 299 capacity in the first quarter, and then it jumps to 382 in the third quarter, which would imply net production rate well above 400, if we have the well capacity to do it.

So, what we are going to be doing is building into those rates, and trying to get our wells completed in a manner such that we can get as close to that as we can.

You know, there is a lot of other things out there, as we get additional capacity then we will run into other bottlenecks.

So, what I don't want people to do is just take these numbers and assume we are going to produce that every day, because that is not going to happen.

These are essentially head -- top-end numbers.

But, I think what it tells you is, hey, we're going to have quite a bit of capacity coming, and some real room to run, and we're going to grow a lot next year.

Again, it may be a little lumpy quarter to quarter, but by the time you get to year end next year, we are going to be producing a bunch of production out of this field, so, an exciting year coming.

And Jay, you're still -- you guys are still on target to get to 300 or around 300 by the end of this year?

Well, again, that is essentially a -- the most we can make on any given day.

So, the actual number is going to be lower than that.

But, yes, I think we're on track to essentially start bumping up against our wet-gas capacity by year end.

All right, great, thanks for the color, guys.

Thank you.

Your final question comes from the line of David Tameron with Wells Fargo.

A couple questions.

In the Eagle Ford, Jay, once you get past this next leg of infrastructure additions, do you need -- when will you need another -- what are the bottlenecks, and when will you need another chunk of infrastructure to take the next growth step, if you will?

Well, David, it is kind of a continuous process from here on out.

We will be adding compression consistently as we go forward.

As Wade said, we have not had to add as much as we thought we would so far, but we do anticipate adding a number of -- compression to get our wellhead pressures down, and that kind of is going to be an ongoing process.

In terms of major tank battery additions, right now it's probably going to be next summer sometime, July, August, maybe even September, before we really need to have those in place to get to that next leg.

Again, we don't have the big downstream capacity addition until July, so we don't want to get everything in place too early.

And then, you know, depending on how our completions go.

So I think we've got to get a lot of liquids out of the lines, there's a whole bunch of stuff that is just going on continuously.

Right now, the real focus in the field is to get our oil transportation stuff hooked up and going, so that we can get out of the trucking business.

So that is really what the guys in the field are focusing on, in order to improve our operations, reduce our costs, improve our net backs, is to get our oil in a pipe.

And so that is the first thing we need to do, and that is this quarter.

There will be some production interruptions this quarter associated with that.

We tried to build our guidance around the idea that we probably will have some interruptions, and also around the fact that we do have some limit on how much downstream gas we can make.

So, I hope we have accommodated all of that in our guidance.

Okay, no -- and on the trucking piece, maybe you mentioned this and I missed it, but any estimate on what that will get you, an extra -- what that helps on the net back, how much extra all that --

Yes, it should be $3.00 to $4.00 a barrel on what we can truck.

Now we're not -- or on what we can ship on the pipeline.

We didn't commit to quite enough capacity to haul -- for all our oil, but it's going to be a good -- probably 80% of it is going to end up on pipe, and should be about a $3.00 to $4.00 improvement on our net back.

Okay.

And then, just well costs, you talked about on the Bakken, can you say where they're tracking right now on the Eagle Ford?

Yes, we're about 10% below where we were.

We put out a pretty extensive set of numbers, I think it was in February or March this year, of 2012, and if you take those numbers and say we're 10% below that right now, that is probably real accurate.

Okay, and is that -- and just going forward, is that efficiencies and already some service costs built into that, or would you anticipate that -- I mean that 10%, is that going to say flattish for '13 or maybe a little bit of improvement, or how --

I think it will improve some.

We are spending some of that on some additional frack stages, but I think we will continue to see costs come down in 2013 by some amount.

You know, I just can't say enough good things, the guys down there have really done a terrific job, and the drilling side has really gone well.

I mentioned the fact that we just completed a Galvan well in 13 days, and I think the first well we drilled in that program was 40-some days in the Galvan area, and so our efficiencies are improving.

Our pad drilling, we're going to be moving to swath drilling which, again, we will probably have more downtime on our producing wells in some periods, but it is going to improve our efficiencies again there, as we get into drilling our infill wells in the better parts of the field, and we will get into that here shortly in the next few months.

A lot of things driving more and more efficiencies in the play, and I think our costs will be lower next year.

Okay.

And then, last question, in the Bakken, can you just talk about -- I know Raven and Bear Den, or you know, McKenzie and Williams Counties, and then Gooseneck, can you talk about -- are you seeing any material differences in the EURs and the production rates coming from Gooseneck versus the other two areas?

Well, Gooseneck EURs are probably 0.75 of the EURs we see in the other areas.

Okay.

Again, it is much shallower, and our well costs are probably $1.5 million lower in Gooseneck than they are in the other areas.

So, from an economic standpoint -- the other comment I will make, and you guys may have seen the announcement, and we are -- we have gotten some of our gathering systems for the Divide County area going, so we're going to be able to net back a higher net back there on -- and be able to sell our gas starting next year, so again, improving our economics in the Gooseneck area.

So I think all of it looks pretty good, and we are excited about it.

It is largely HBP'd at this point, so we have a lot of control over what we do.

We've moved to pad drilling, we're getting more efficient, so we can drill more wells with the rigs we have, and I think the guys up there are doing a terrific job.

All right, that is all I got, and congrats on the recent promotion.

Thank you, David.

Thanks, David.

At this time, I would like to turn the call over to Tony Best for closing remarks.

Thank you all for joining our call this morning, and for your continued interest in SM Energy.

We will talk to you again next quarter.

Thank you.

And this concludes today's conference.

You may now disconnect.