SM Energy Co (SM) 2013 Q3 法說會逐字稿

Good morning my name is Kathy, and I will be your conference operator today.

At this time I would like to welcome everyone to the SM Energy third-quarter 2013 earnings conference call.

(Operator Instructions)

I'd now like to turn the conference over to David Copeland, Executive Vice President and General Counsel.

Please go ahead, sir

Thank you, Kathy.

Good morning to all joining us by phone and online for SM Energy Company's third-quarter 2013 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, pending divestitures, and assumptions regarding our future performance.

These statements involve risk 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 factor section of our form 10-K that was held on February 21, 2013.

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

Reconciliation of these 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 three-P 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, Chief Executive Officer; Jay Ottoson, President and Chief Operating Officer; Wade Pursell, Executive Vice President and Chief Financial Officer; Brent Collins, Senior Director of Planning and Investor Relations; and I am the Company's Executive Vice President, General Counsel, and Corporate Secretary.

I will now turn the call over to Tony.

Thank you, David.

Good morning, everyone, and thank you for joining us for the third-quarter 2013 SM Energy earnings call.

We will be referencing slides this morning that we posted on our website yesterday.

I'll start on Slide 3 and go through a few key messages for the quarter.

SM Energy had a very strong quarter, with record quarterly production of 12.8 million barrels of oil equivalent, with 50% of this production being oil, condensate, or NGLs.

Along with our record production, we reported record quarterly EBITDAX, which was greater than our quarterly capital expenditures.

Over the past few months, there's been a lot of attention on the Permian basin and a fair number of questions about our Permian program, which up until now, has been something we haven't talked much about, due to our ongoing leasing efforts in the basin.

We feel that we have now reached a point where we can talk about our position and program plans in more detail.

As many of you already know, we drilled and completed our first horizontal Wolfcamp B well in our Sweetie Peck field and have seen very strong results to date.

From an acreage standpoint, we've been working hard to add acreage into play, and I'm pleased to say that our efforts have been successful, as we've added significant acreage to our Midland basin position, which Jay will cover in detail during his operational update.

Lastly, I'd like to point out that although a lot of attention in investor meetings and calls is directed at our new venture programs, it is important to note that it is the successful execution of our core development programs that is driving the growth of our Company today.

With that I'll move to Slide 4 to do a quick rundown of our quarterly performance.

From a production standpoint, we are at the high end of our guidance range, with an average 139,000 barrels of oil equivalent per day during the quarter.

From a cost standpoint, we were within or below our guidance range on all guided metrics.

A few of the costs which came in below our range were cash G&A, which was less than expected due to lower compensation-related expenses, and our DD&A rate, which came in 14% below the midpoint of our guidance range.

The decrease in DD&A is a result of lower finding and development costs in our core development plays as we continue to gain efficiencies and drive cost down.

We reported GAAP net income of $1.04 per diluted share for the quarter and adjusted net income of $1.54 per diluted share.

Our quarterly EBITDAX for the quarter was $410 million, which, as I mentioned before, is a Company record.

I'll now turn the call over to Jay for his operational review.

Thank you, Tony.

Good morning, everyone.

I'll start on Slide 6, with a quick discussion of our production for the quarter.

As Tony mentioned in his introduction, our average daily production for the quarter was approximately 139,000 barrels of oil equivalent per day, which is a 5% sequential increase from the second quarter of 2013 and a 34% increase from the third quarter of 2012.

Year over year, liquids production grew by 48%.

Our product mix for the quarter was 50% liquids, which we had indicated was our expectation to achieve by year end.

We got to that number a little earlier than expected because we had a number of lower liquid-yield wells in the operated Eagle Ford shut in during the quarter for extended periods, due to offset drilling and completion operations.

As indicated on Slide 7, our operated Eagle Ford program total volume grew 3% sequentially this quarter, and 68% year over year.

You can see the impact of the simultaneous operations related shut-ins I just referred to, in the reduction in gas rate from the second to the third quarter.

We do expect that trend to reverse in the fourth quarter.

We brought on 25 completed wells during the quarter, 22 of which were in what we refer to as Area One or Briscoe Ranch.

Year-to-date, we have completed 75 wells.

From an infrastructure standpoint, everything is staying on schedule.

There are now 12 central gathering facilities operating on our acreage, and our gathering system buildout is keeping pace with our development plans.

On Slide 8, the non-operated Eagle Ford program continues to provide solid, steady production growth.

Volumes grew 14% sequentially from the prior period.

Anadarko has run a consistent program for the past several quarters and has recently added a tenth rig.

They've also told us that they will be adding additional frac capacity to help bring down the inventory of drilled but completed wells.

We continue to be very pleased with the operators development of this asset.

Moving to Slide 9, our Bakken/Three Forks program had 9% sequential production growth.

We maintained a 3-rig program and made 13 gross completions.

We are participating with others in down-spacing pilots, the results of which we will incorporate into our drilling plans and estimations of economic inventory at year-end.

We're also evaluating all the claims being made for revised completion designs in the basin, and we'll make adjustments to our completion plans if we see merit in doing so.

At this point, our typical long-lateral completion is at 26-stage, sliding-sleeves frac job, using about 80,000 barrels of fluid.

As shown on Slide 10, our Permian production grew 3% sequentially.

We brought on five new wells in the Permian this quarter, two in the Tredway Mississippian prospect area, two in the Bone Spring intervals on our acreage position in southeast New Mexico, and one in the Wolfcamp B shale.

I would like to spend some extra time today going over our Permian acreage position, recent results, and plans.

Slide 11 is a locator map of our acreage position in the Permian basin.

In total, we have roughly 130,000 net acres.

This count excludes about 14,000 acres we are currently marketing located on the western edge of the Midland Basin in Andrews County.

You may recall that we drilled several Leonard shale test wells on that acreage prior to starting our sale process.

Our assets in Southeast New Mexico are currently producing about 1500 barrels of oil equivalent per day net to SM and consist of 2 waterflood units, the Parkway Delaware unit and the East Sugar Delaware unit and associated acreage.

We operate both units and have a 33% working interest in Parkway and a 73% working interest in East Sugar.

We have recently been drilling some waterflood infill wells at East Sugar and have completed a number of Bone Spring horizontal wells in the last year or so on our Parkway acreage.

As I indicated earlier, we completed two of those Bone Springs wells during the third quarter.

We have a few more Bone Spring locations left to drill, and continue to look for additional upside on the acreage.

Our Tredway Mississippian prospect acreage position currently stands at 54,500 acres, and our wells there produce about 1800 barrels of oil equivalent per day net to SM.

You may recall from previous discussions that we had subdivided the prospect into a northern area, a central area which we call Roy, and a southern area.

We have previously indicated that wells in the Roy area generally generate fairly consistent results, but that the north and south areas were relatively unproven.

The two wells we completed in the third quarter were in the northern area.

We are taking a hiatus on Tredway drilling during the fourth quarter to evaluate all our results to date and determine our best forward path with the asset.

The remainder of our acreage position, 72,500 acres, is Midland basin acreage that we believe is highly perspective for a number of shale targets.

Our operated Sweetie Peck and non-operated Halff East assets, which total about 19,000 net acres, currently generate the remainder of our current Permian production.

We previously drilled these legacy assets vertically and completed them in multiple non-shale rock layers within the Spraberry and Wolfcamp intervals.

The industry refers to these as Wolfberry wells.

What we're all finding now is that shale source rock throughout this intervals appears to have been largely undrained by our previous vertical completions, and can generate prolific production in horizontal wells.

The remainder of our perspective shale acreage, roughly 53,500 acres, is a new acreage position that we have been building over the last year in the northern Midland basin which we call Buffalo.

I will discuss that position in more detail a little later in the presentation.

I am now on Slide 12, which shows the location of our Midland basin shale acreage position and a number of reported Wolfcamp Shale horizontal well results.

Our first operated well in the play, the Dorcus 3035H at Sweetie Peck, had a 30 day IP rate of 1226 barrels of oil equivalent per day, which we believe compares quite favorably to what our peers have been reporting in the basin for Wolfcamp Shale wells.

On Slide 13, we're showing several decline curves and how the early time data for the Dorcus well compares to those curves.

The lower curve is the curve which we've been using for initial AFE economics.

The front end of this lower curve was developed based on average reported public data for similar lateral-link wells in the central portion of the Midland basin.

We then projected the average oil rate forward, using a hyperbolic exponent of 1.3 and an 8% terminal decline, and applied an average gas/oil ratio to convert the oil curve to a barrels-of-oil equivalent curve.

This resulting curve generates an estimated ultimate recovery of 430,000 barrels of oil equivalent.

The upper red curve is a more optimistic estimate and uses a higher initial oil production rate, a steeper initial decline, a 1.6 D factor, and a 6% terminal decline, and generates an estimated ultimate recovery of 660,000 barrels of oil equivalent.

This 660,000 barrels of oil equivalent number is fairly similar to numbers some of our peers are quoting for wells and our general neighborhood.

At this point, our Dorcus well is out-performing both of these curves.

We have another well at Sweetie Peck, the Britain 3133H, flowing back right now, and a third well, the CVX 4134H, drilled but not yet completed.

We will use data from these three wells and develop an average, or so-called projected type curve, over the next few months for future Wolfcamp B drilling at Sweetie Peck.

In the upper-right portion of Slide 13 are some completion details for the Dorcus well.

You will note that we put a lot of sand and fluid into this completion.

On Slide 14, we're showing with the potential horizontal development of the Wolfcamp B interval could look like at Sweetie Peck.

We've identified the three wells that we have completed or are currently completing -- the Dorcus, the Britain, and the CVX.

We estimate that there are approximately 65 potential Wolfcamp B locations, assuming 107-acre spacing.

Lateral links will vary from 5000 to 7600 feet in length, depending on lease limitations.

As the map indicates, there are a couple of areas in Sweetie Peck where we drilled Wolfberry wells down to 20-acre spacing, where we're currently assuming that we may not be able to fit in as many wells as in other areas.

Of course, we'll do everything we can over time to increase our economic well count.

Slide 15 shows a log of a vertical well in the eastern portion of the Sweetie Peck field.

Our first few wells are all targeting the Wolfcamp B interval.

But, there are other good-looking intervals here that are already being tested in other locations by industry participants.

We believe that there is substantial upside at Sweetie Peck beyond just the Wolfcamp B and expect to test the potential during early 2014.

Our Halff East acreage position is operated by Concho.

They're in the process of drilling and completing several Wolfcamp wells on the acreage, and we'll do them the courtesy of allowing them to discuss their operated wells when they have results.

Moving to the northern Midland basin, I am now on Slide 16.

I mentioned earlier that we have built an acreage position we call the Buffalo prospect.

This position was built at relatively low cost around a vertical science well named Tatonka that we drilled earlier this year.

The acreage is primarily in southern Gaines and Dawson counties.

In general, the core and log data we took from the science wells look very similar to data we gathered from core and logs at Sweetie Peck, which encouraged us to increase our land acquisition effort.

We will be reentering the Tatonka well and completing it horizontally in the Wolfcamp B in December.

I'm now on Slide 17, where I'll summarize our shale drilling plans for the remainder of this year in the Midland basin.

At Sweetie Peck, we plan to flow back the Britain well, complete the CVX well, and drill two additional horizontal wells.

At Buffalo, we'll complete the Tatonka horizontal leg in December.

We'll give information about our 2014 plans when we announced our budget for next year, also in December.

That concludes our survey of Permian basin acreage and activity.

Regarding our new ventures program, we have a quick update on Slide 18.

In the Powder River basin frontier play, we did not have a rig running in the third quarter but have recently picked one up in October.

We've been pushing ahead with our permitting effort and have 10 permits in hand, with an additional 22 applications submitted.

As a reminder these wells currently take 80 days or so to drill, so approximately 5 permits can support a rigline for a year.

We firmly believe that we'll be able to obtain the permits we need to support our contemplated levels of activity over time.

Lastly, in East Texas, we recently leased or committed to acquire approximately an additional 20,000 net acres in the play, bringing our total to about 215,000 net acres.

We drilled an Eagle Ford test on the western end of our acreage position in the third quarter, which we plan to have completed shortly.

We currently have two rigs running in the area, and we'll be drilling a series of additional tests wells in the coming months.

Before turning the call over to Wade for his elaboration on our strong financial position, I'll make a quick comment on our Anadarko basin divestiture process.

We had great participation in our sales process.

It was very well run, and we're very proud of our employees, who put the sales process together in the information.

We received bids late last week and are in the process of evaluating those.

We're still targeting a closing date sometime around year end.

Given where we are in the process, we won't be able to give any more color on that today.

With that I'll turn the call over to Wade for his financial update

Thank you, Jay.

I'll start on Slide 20.

First thing I'll mention this morning is during the third quarter, our net cash from operations exceeded our capital expenditures, resulting in an unchanged long-term debt balance for the quarter.

Our capital structure remains very straightforward and transparent, with 4 pieces of long-term debt in a revolving credit facility, which we currently have only $28 million drawn against.

As a reminder, our borrowing base increased in the third quarter $2.2 billion up from $1.8 billion at the end of the second quarter, and our current revolver commitment is $1.3 billion.

The increase to our borrowing base is driven by our increasing reserve base at mid year.

So, moving to Slide 21, we're showing our debt maturity timeline for our unsecured bonds and secured credit facility.

As you can see, the earliest maturity of the bonds is over five years out.

Turning to Slide 22, my last slide, we have a graph which shows our debt to trailing 12 months' EBITDAX against a group of peer companies that we track internally.

As you can see, the slide -- our leverage metric improved quarter over quarter, with growing EBITDAX and unchanged debt.

It also shows that we are significantly below our peer group average of 2.5 times debt to trailing 12 month EBITDAX.

Finally we did add a lot of hedges during the quarter.

You can see those details in the 10-Q which we filed this morning.

So with that I'll turn the call over to Tony for his closing remarks

Thank you, Wade.

Before handing the call over for your questions, I'd like to spend a few minutes reviewing what we think are the key takeaways from this morning's call.

First, we had an excellent quarter with record production at the top end of our guidance range and record quarterly EBITDAX of $410 million, which grew 57% from this time last year and which exceeded our CapEx spending for the quarter.

Second, our balance sheet remains strong, as Wade just pointed out.

Our outstanding debt was unchanged from the prior quarter, and we have approximately $1.3 billion available under our revolver.

As our EBITDAX continues to grow, our preferred leverage metric, debt to trailing 12 month EBITDAX, has improved during the quarter, and we are now at 1.2 times, which is half of the peer group average.

Lastly, we continue to grow our oily inventory.

We've been working hard in the Permian, putting together an extended position in the basin, and I'm happy that we're now at a point to be able to share more about our success and our plans for that program in today's call.

Our first Wolfcamp B horizontal well looks very encouraging thus far, and we'll be drilling wells in this interval for the remainder of the year.

We are anxious to test our newly acquired acreage in the northern Midland basin as we move toward year end.

In 2013 we have significantly increased the amount of oily inventory in the Company.

We've expanded our position in the Permian, have obtained a substantial and still-growing position in East Texas, and a significant position in the Powder River basin.

All three of these emerging plays are oily, and our success here will continue to shift our production mix towards the liquid side as well as contribute SM Energy's long-term growth with continued success.

I'd now like to open the call up for your questions.

(Operator Instructions)

Pearce Hammond, Simmons & Company.

Morning and congrats on a great quarter.

Thanks, Pierce.

Tony and Jay, can you provide a bit of a broad outline on your thinkings for the 2014 capital budget?

I know you're going to get the guidance in December, but -- any kind of general thoughts?

I know the Mitsui agreement will roll off at some point next year, the Kerry will, so just some general thoughts?

Yes, Pierce.

As we talked about earlier, we're going through the budgeting process right now and expect to provide 2014 capital guidance in December, but, directionally, what I would say at this point is, you should expect a capital program that's similarly sized and focused like 2013.

The additional change to that would be the Mitsui Kerry, which we will expect to be completed some time during the first half of next year.

And we've kind of said if you think about that as kind of $250 million, $260 million a year, maybe somewhere around $150 million might be something reasonable to add to kind of the size of our CapEx this year.

But again that's directional; we're going through the specific budget plans for next year.

I should mention, too, that the success that we're seeing right now is baked into the 15% growth target for next year.

No, 13.

Great.

And then my follow-up would be -- some producers had talked about an upper and then a lower Eagle Ford.

Do you see that same sort of horizons on your acreage in Eagle Ford?

Let me mention one thing, a correction a my last comment.

I should mention when I talked about our kind of directional guidance on CapEx next year, that minimal success from our new venture plays is baked into that plan for next year at this point.

Thank you for the clarification.

Let me -- I'd like to address that question on the upper Eagle Ford.

We're aware that Rosetta is doing some pilot testing in the upper Eagle Ford, and we look forward to seeing their results.

We've always believed that there's hydrocarbon storage in the upper Eagle Ford and to some extent in the Austin Chalk; however, we also believe that the fracs we're doing are already drinking that rock.

So, if they prove something up there, we'll be happy to follow up on that.

Thank you very much.

Thanks, Pearce.

Jeb Bachmann, Howard Weil.

Jay, I had a couple questions on the Wolfcamp.

I noticed you didn't include any cost assumptions for those wells, and understanding you're putting a lot of science into these early wells, can you give us any kind of commentary on that at this point?

Well, you're right, Jeb, we are putting a lot of science in here and experimenting with different proppants, and some pretty expensive proppants, on the early wells.

The direction we're taking here is to leave it all in the field and make good wells early on.

I do think we'll see some substantial cost reduction over time.

The Dorcus well cost was about $8.5 million, but you can see we put a lot of effort into it.

We're getting faster at drilling them.

I think we can get our costs down over time.

We are going to spend more money on premium proppants for some of the early wells just to see with impact of that is.

But we're going to make wells here early on, and then we'll optimize costs in the future.

Okay.

Then looking up into Gaines and Dawson County, is Tatonka the only vertical well control you have on that acreage at this point?

There's a lot of vertical wells up there.

Tatonka 's is the only well where we have core and logs that we can really compared to.

And as I indicated earlier, the core and logs looks very, very similar to our Sweetie Peck core and logs, which we have an identical set of logs and core from Sweetie Peck.

So, we really built the position based on the science that we saw, and we're very hopeful that we'll get similar results

In that core analysis, that includes the maturity of the rock up there, you're saying it's similar to Sweetie Peck?

Yes.

And I will say if you get much farther north than our position in Gaines and Dawson, it will get immature.

So the risk as you go north is immaturity.

There's different risks as you go east and west.

We built this position in a very specific location for a very specific reason, and we certainly hope that we're right, but the core and logs are very encouraging And you mentioned the Bone Springs wells.

Did you have any rates on those yet; are those flowing back at this time?

Generally they're making our AFE numbers.

We drilled a number of wells, they are going to have EURs between 300,000, 400,000 barrels, typically they'll IP somewhere around 500,000.

They're nice wells; they're not huge in the context of our overall program, just because we don't have that many locations.

Okay, and just two quick ones if I may.

Any update on the Andrews County sale (inaudible) Anadarko basin update?

You know, Jeb, we're in the process, and we have some bids and we're moving forward, and that's really all I can say

Okay, and the last one from me.

Tony, with the strong balance sheet and Nasset sale proceeds likely coming in the door here shortly, any kind of commentary as to what you guys plan to do going forward, in terms of ramping up activity or looking for adding new acreage in some of your stronger areas?

I would say we certainly have the dry powder to execute the program that we've laid out, but also we've got the strength of the balance sheet to pursue additional opportunities as we see them.

As I mentioned, our capital plans for next year, which include 15% production growth on a higher base for this year, include very little success in our new venture areas.

So we've got tremendous opportunity if we continue to see success, and we certainly could ramp those programs, especially in East Texas, if we see success there.

So, we've got a lot of running room, and we've got a strong balance sheet to support that.

Great.

Thanks for the comments, guys

You bet.

Thank you

Michael Hall, Hycodan Energy

Thanks.

Good morning.

Congrats on a very solid quarter

Thank you

First just a couple quick ones.

In the Permian program -- just trying to think through -- as that progresses into next year, assuming success in the north, is that eventually, does that look like a two-rig program with one winning in the southern, in Sweetie Peck and one of Buffalo?

Or, would you initially be hopping a rig back between the two areas?

And is that an additive program to the 2013 spending?

Or how should we think about that as we go forward?

This is Jay.

It's just too early to tell.

I think we could clearly support a several-rig program in the Sweetie Peck area alone.

And if we're successful in Tatonka, which unfortunately we won't really know until mid-December, which is after really when we'll put our budget together, we could support a multi-rig program there as well.

So, as Tony said, we're positioning our sales from a capital standpoint, from a debt standpoint, and for bringing in some proceeds, to be able to ramp during 2014 in the Permian or in East Texas.

And we honestly expect that we will be doing that to some extent, but I think our initial shot at budget will be probably fairly conservative in the sense that we won't budget a lot for success we haven't seen yet.

But clearly I think there's an opportunity here, both in East Texas and in the Permian, to ramp into some really nice oily success next year, and that's why we're selling assets, that's why we're building our war chest here, essentially to be able go out and do that.

Okay.

That's helpful, appreciate the color.

I guess, along those lines, East Texas, can someone remind me what to expect from a data flow standpoint on that asset and what you all are testing, and when we should expect to hear more about it?

You bet.

As you go forward there

Sure, great question; I'm glad you brought up.

As we indicated, we're completing and Eagle Ford test during the fourth quarter on the western end of our position.

We have two rigs running, drilling Woodbine test right now farther east over in the San Jacinto County area generally.

And we have several more tests to come there.

I don't think you'll hear much from us about results until sometime next year, probably early in the year on the Eagle Ford test, a little later perhaps on some of the Woodbine tests; these are fairly long wells to drill and test.

Obviously, we're looking forward to getting our wells drilled and seeing how this plays out.

As I said, we're going to release our 2014 budget mid-December, and you should assume that we're not going to budget for success in the program, and with success we would need to revisit our production on capital forecast sometime next year.

Okay, great.

And are you looking at any other targets on that asset outside of the Woodbine and Eagle Ford at this point?

Obviously --

Well there are several --

Putting any capital to work on another target?

Well, there several other intervals of interest.

The Austin chalk is going to get some focus, I can tell you, during next year.

I haven't seen any specific plans to drill any other targets other than those three yet, but I wouldn't be surprised -- if we're successful in some of these, that we'll find some other ways to spend some expiration capital during next year.

Great.

And last one on my -- is just housekeeping on the new Permian acreage in Buffalo, what was roughly the working interest there?

We are going to be 100% essentially on all of it.

Okay, great.

Perfect.

Thanks very much.

And congrats again

Thank you.

Joe Magner, Macquarie.

Good morning.

Just want to, sorry, go back to the CapEx question.

Just want to clarify.

Tony you mentioned that next year's program initially will be sort of similar to 2013 levels with the addition of the Mitsui Kerry for a portion of the year, and that there is some of that new venture spending in there?

There are a lot of comments being thrown around regarding what's being considered with the 2014 guidance that we'll get in December versus what we might see later in the year as you get more information.

So is that -- my understanding of that correct?

Initially it will be similar, but there could be upside with more detail and more information from these newer opportunities?

Yes, I would say that's reasonable.

And keep in mind, too, that each year, we have a component of our budget that's focused on new ventures.

And it's generally been running somewhere around $125 million or so per year.

But again that varies a little bit, but that's kind of what we had in mind for -- that's what we had in our budget for this year.

So I would expect something comparable next year, but again, as Jay mentioned, we're certainly poised for ramp up if we have success with some of these emerging plays.

Okay, I also wanted to, I guess, follow-up on a comment that was made briefly about what is and is not included in your 15% production growth target for next year?

I think in the past you said that there's a small amount of new ventures built into that, primarily associated with Powder River Basin.

Is there much in their for the Wolfcamp at this point?

No.

This is Jay.

But no, there isn't.

Really, the statement you just made is accurate; there's a little bit of Powder River Basin upside in there.

We basically bake that in, assuming we're going to run a rig or 2 up there, but we're not budgeting and we haven't -- in our modeling, we have not assumed success in East Texas or in the Permian Wolfcamp shale in our 15% numbers.

So, I think what you'll see, as Tony indicated, when we come out with our budget, it's going to be a little too early to tell on both those plays in terms of how big we go.

We may very well, given our success at Sweetie Peck, go ahead and budget a little more activity there, but that might be offset in some other areas.

But I think the 15% number is a good number to start with, and we'll see what happens in Tatonka and East Texas, and we'll make adjustments later in the year as we need to.

Okay, thanks for that.

And just one last one.

You mentioned that the production mix shift in the third quarter was due to some gas wells that were shut in, and maybe we would see that revert fourth quarter.

How much impact could that have, and I guess what -- how much more could it shift back to the gas side of the equation with those wells being brought back online?

Great question.

I think what we always have said is we'd be running at about 50% by year end.

That was our target.

I still think that's a correct assumption, is that when we exit the year, we'll be running at about 50%.

That number will be helped by the fact that when we sell the Anadarko basin assets, that actually shifts us to a more oily mix as well.

I would expect to see -- with gas rigs coming back from the Eagle Ford in the fourth quarter -- I would expect us to have a slightly gassier mix in the fourth quarter.

I haven't calculated an exact number for that, but I'm guessing it's going to be somewhere around 52%.

But that's a really detailed number, and I'm guessing a little bit.

But a couple percent shift back toward gas wouldn't surprise me at all

Okay, that's all I've got, thanks

Welles Fitzpatrick, Johnson Rice.

On the quarter over quarter growth in the Eagle Ford, obviously that slowed a little bit to the shut-ins, but have you guys had any or do you see any issues with regards to interruptible capacity until you hit the next bump in your contracts?

We have never had problems shipping gas on an interruptible basis.

At this point we have all the firm we for the volumes we've been shipping.

But we believe that there's interruptible available until we need -- until we get our next firm tranche.

Okay, perfect.

And then am I remembering correctly that the Roy area is around 21,000 of the 55 in Tredway?

That's about right, yes.

Okay.

And any commentary -- and you hit on it a little bit earlier and I suppose it is easy enough to follow the money -- that you guys are permitting a lot around that initial San Jacinto well, but any commentary on how I believe that 2500-footer held up, and the longer dated rates?

You know we haven't had a lot of opportunity to flow the well, but, in general, the wells we've drilled, although they have had mechanical troubles, have looked pretty good to us.

Really it is way too early.

And we're going to get some wells drilled with decent linked laterals and get good completions on them, and at this point, I would say everything is still really up in the air.

Okay, perfect, that's all I had.

Thanks so much.

Thanks, Welles

David Tameron, Wells Fargo.

Thanks.

Most of the questions have been asked.

Just going back to the DD&A rate, pretty substantial drop both in the third quarter and the full year.

And I know you mentioned this when you did your mid, your revolver determination, that you had increasing reserves, but -- is it the right read from my end the reserve growth is greater than you anticipated?

Or is there something else going on in that calculation?

You're reading it correctly.

It's a combination of the reserves that we did at midyear, not only adding reserves, the cost improvements we've been seeing getting baked in there as well.

David, I think a lot of people don't recognize -- we've been -- over the last three years, we are in the top quartile of our peers for F&D, all in F&D, and that number is rolling into our numbers as we go forward.

And it's approaching -- our DD&A rate is approaching that number, which has been in the $14 range for the past 3-year average.

So it's coming down.

And it's moved a little more than we expected this quarter, but clearly we're moving toward our long-term F&D average.

Okay.

David, I would say, too, that it's also a function of the improving quality of the portfolio, which we've continued to core up over the last two years.

That make sense.

All right, that's all I got.

Thanks, and again nice quarter.

Thank you.

Matt Portillo, TPH

Good morning, guys.

Just a few quick questions from me.

In terms of the Bakken, can you give us an update on some of the down spacing that you're testing, and maybe when we could expect some results there?

And then I guess the second question alongside that, as inventory increases, how do you guys think about capitalizing this asset from an acceleration perspective, and does this kind of still fit in the core part of your portfolio with the emergence of the Permian as kind of another play that may ultimately garner additional capital?

Well, good question.

We're in several -- frankly we're in some of Kodiak's wells, so we're in several different spacing tests, and we're monitoring all those.

I think it's an interesting question about acceleration.

If you think about what's happening in the Bakken right now with what some people refer to as kind of a technical Renaissance in fracturing and all the things that are going on there, I think it's actually a very powerful argument for not going too fast.

We really believe that potential for adding value through this type of technological betterment, through down spacing and better frac technique, is one of the best reasons for moderation in your pace of development.

And we've maintained a pretty constant three-rig program there, which we think is consistent with the kind of inventory we have.

We're going to be able now to take advantage of spacing -- down spacing -- and better technical work as we go forward.

I don't think that -- I had a supervisor one time that said, you know, you can PV yourself to death.

It's appropriate, we think, to maintain a moderate pace, where we can take advantage of these great assets getting better over time.

So we think the Bakken and Three Forks is a big part of our portfolio.

We love the area, we have no intention of exiting it, we have cored it up a little bit, where we sold to non-op assets that we didn't think were performing as well, and we'll continue to do that as appropriate.

But our operated acreage looks really good to us, and we're looking forward to applying new techniques and additional spacing learnings that we get to that acreage as we go forward.

I think a good way to think about our development portfolio today is kind of that three-legged stool.

It's an over used cliche, but in our case it's true.

Certainly, you've got the Eagle Ford, the Bakken remains a very strong leg on that stool, and now you're seeing the Permian forming another strong leg with our core development plans.

Great.

And then just a quick question in regards to the type curves presented on the Wolfcamp B. You mentioned that came from public data.

Just curious on the 430,000 EUR?

Could you mention which counties you guys included in that, just to make sure that we're thinking of like-to-like kind of asset analysis there?

Well, this is Jay.

I'm going to pick words just a little bit.

I never used the words that those are type curves, and they're not -- we're not using them as type curves, because a type curve to me means an average of a bunch of our wells that apply to our data.

What those are -- that low curve, we took the front-end oil rates from a bunch of Southern Midland basin wells -- a lot of this would be the far south areas where people have more data -- the EOG areas, all those other areas -- and we took the front-end oil rates for that, and then we projected them forward using but we think is actually a pretty reasonable number for the long-term B factor, the 1.3, and an 8% terminal decline, which generally is going to be how we would book wells early on, with a fairly conservative B and higher terminal decline in some people use.

The higher curve that's on that sheet really is just an upper -- it's a higher estimate for us.

We used a higher decline rate early on, kind of set the initial production rate up, based on the fact that Dorcus looked like it was going to do that.

We used what we hear from a lot of industry participants is a little more standard, 1.6 B and a 6% decline, which again, those are yet to be proven in any well.

B factors in these types of plays tend to come down over time, unfortunately.

But we are not representing any curve on there as a type curve for Sweetie Peck development.

Until we get three or four wells behind us and get some run time on them so we can build a good average, we're -- we won't to represent anything as a type curve.

Those are just decline curves that we put on there so people could see -- this is kind of what the thing is looking like.

We should have something that looks like an average type curve here in a few months, after we get a couple more wells and get some more data.

But I think the 660 number that is on there is very similar to some numbers that some of our other industry participants are throwing out in some of their investor presentations.

And that curve shape is not too far from some of the curve shapes that you'll see people showing in investor presentations.

Great, thank you.

And then, just my last question.

You guys mentioned that Anadarko is picking up incremental frac crews on your non-operated acreage to blow down some of the wells.

I was wondering if you could provide a little bit of color on how many wells are kind of in inventory today?

And then, does this change your kind of growth rate assumptions on your non-operated acreage over the next 6 to 12 months?

You know, I don't have that number at my fingertips here, so I'm not going to quote another that might be wrong.

And it doesn't change our perceptions of the growth rate.

I think we've always maintained that this thing would grow at an average of about of 5% growth rate per quarter.

Sometimes it's a little lumpy.

Our views on that haven't changed.

Thank you very much.

Thank you.

Mike Scallia, Stifel

Good morning, guys.

Jay, you had said that your Buffalo area to the north, there's the risk of immature rock, and you mentioned some risks to the east and west.

Can I infer that, even if you do have success with your Tatonka well, that you probably don't grow that position from the 53,000 acres that you have now?

Mike, there's still some more acreage in our buy area, but we probably won't be moving north, and we will be moving a long way east or west, either.

We think we're basically at the end of the perspective rock up there, at least at this point.

We may learn something that tells us that we're being overly conservative about that.

And we have a little bigger buy area than what we've actually bought, and we'd like to pick up some additional acreage still, but it's going to be pretty close to where we are now.

Okay.

And then looking at your cross-section for Sweetie Peck, you show seven I think potential intervals that are perspective.

Have you heard of any other companies testing any of those, or have you tested any -- I guess, obviously, you haven't at this point.

But where do you think you go next with a horizontal well the beyond the Wolfcamp B?

I'm pretty sure our next test will be in the Cline.

And the reason for that is largely because it's the deepest and it would hold the most acreage to do that.

So if Cline works, we'd drill -- we would probably focus on Cline drilling for some period of time, in order to get all depths held.

We're enthusiastic about the lower Spraberry shale there.

I think that's another pretty good target.

If you read some investors stuff, there's people targeting the Joe Mill and other thing in other areas.

Wolfcamp A looks like a good target, but I think right now we're probably more focused on the Cline than anything else.

And I think you'll really see us drill a test in the Cline early next year.

And when I look at that, I mean, it just looks -- you got so many different intervals that are perspective vertically.

Wouldn't that argue for tighter vertical spacing?

Or why does horizontal take preference over vertical development here?

Well, if you go back to the way these wells were completed, what they did, what we did is -- we would drill a vertical well, and then we would essentially complete the -- and I'm going to call them carbonates, but they're kind of dirty carbonates, intervals all in between -- so you'd make like a 12 stage frac completion, at which you're completing 12 different intervals through here.

That wouldn't work in a shale.

If you want to target shale, you can't make a completion where you target 12 little fracs in a shale, because that won't add up to 1 big well.

So, what you need in a shale, is you need to get long laterals, you need to get a long opportunity to put a bunch of fracs into that individual shale.

Putting one single frac into a shale is not going to make -- 5 different shales isn't the same as having a 5,000-foot lateral with 26 stages of frac in it.

So I don't think vertical is the right way to go here.

I think what we'll be doing is targeting specific shales, as long of laterals as we can drill within our lease limits, and we'll go -- we'll try to start at the deep end and get the acreage held if we can, to the extent we can do that.

That helps, thanks.

And one last one for me.

The 22 wells you brought on in the Area One.

Do you have enough production history on those to say how they're performing versus your type curve?

Not really.

We have had a lot of up and down time, we've tubed up a bunch of the wells, we've tried some different techniques, we're leaving some of the wells, leaving them on restricted chokes for long periods of time.

So some of the wells that I've looked at look pretty good, in general, on some of the yields, but other than that I really can't say a whole lot; it's is just too early.

We'll update that during our reserve process and probably give more information sometime next year on it.

Great, thank you much

Thank you.

Scott Hanold, RBC

Thanks.

I'd like to dig into the DD&A rate that changed a little bit more.

You obviously indicated that had to do with kind of the updated reserve report was a big reason for that.

Can you give us a sense on some -- a little bit of the mix shift and component shift that you saw in that.

Specifically, is there a lot more Eagle Ford PUDs in there, and what were the assumptions on well cost and EURs versus what the old reserve report had previously indicated?

And whether or not the assets you have for up sale in the Anadarko basis would have been included in that number as well?

There's a lot of questions there.

We probably should -- I can't answer that much detail on our mid-year reserve report, Scott.

But I will say that PUDs didn't have much to do with it.

I heard you mention PUDs, but beyond that we really can't say much more about the mid-year reserve report.

Anadarko that would've been held for sale?

That's an asset held for sale now, so the Anadarko basin is not in there.

Okay so the Anadarko is out, and implicitly there are some improved EURs and lower well costs in the Eagle Ford PUDs, but you're not going to quantify that at that point, is that right?

Well, this is Jay, and I will just say, in general, our reserves report looks good, and our cost of been coming down.

And that's consistent with the trend, a long-term trend here of improving our portfolio, as Tony indicated

Okay, fair enough.

And then moving to the Permian, just a question.

You know the Sweetie Peck area has obviously a very strong result from Dorcus.

When you look at where that asset is positioned relative to the basin over the Midland, it's more toward the central basin platform.

And did some of your acreage start to come out of the basin a little bit?

Does it tend to be a little bit shallower than some of the other industry activity you're seeing today?

Can you give us a little bit of color on that?

Well, I think that was the big risk really at Sweetie Peck, is you are more toward the shelf edge.

And I think it's a really interesting result from an industry standpoint, because I think it tells you that you can get closer to that shelf edge than maybe people thought.

I don't know that that means there's going to be a lot of acquisition opportunities for anybody, because a lot of this acreage is already held.

But it is probably the closest well to that western edge that's really made a good result.

And, that was where the risk was, I think.

Okay.

So, anyway, I'm -- it's a good first result.

We're excited about it.

It's obviously very encouraging.

It's still early days

Absolutely.

And to that point, with some of the vertical wells that you have done that are -- in looking at your map, Dorcas was somewhat in the central part of your asset base.

If you go a little bit further to the west, do you see any significant changes in the geology in depth or composition in some of the vertical wells?

Well, our mapping would show that some of the shales are more perspective on the east side of the block than they are on the west side of the block.

That's not just the Wolfcamp B but it relates to other intervals as well.

I think the farther west you go, the more risk you run that these things thin.

And certainly we saw that up in Andrews County when we got up there.

Base and center is great.

I think all we've proved here was that you don't have to be dead base and center to make one of these wells work really well.

Okay.

And then one last question.

With respect to trying to hold this acreage, you referred to looking at the Cline.

When you drilled the vertical wells, did you pretty much just go down to the Wolfcamp as the deeper zone, or are any of those any bit deeper?

So when you're looking at potential Cline over this acreage position, does a good chunk of this still need to be held to that lower formation?

I don't want to get into a whole bunch of specific land details, because frankly I don't know them as well as I should for question like that.

There's no question that some of the vertical, early vertical wells didn't go quite as deep.

The way that play worked out, people kept taking them deeper and deeper over time.

So some of the early wells didn't go quite as deep.

In general, we are going to drill the Cline early, because we think it gives us our best shot at -- A, it's a good thing to do; B, it will help us solve any issues we have like that.

Okay, fair enough.

Thanks, guys.

Thank you.

Brian Velie, Capital One Security.

Good morning, everyone.

Couple of quick questions.

In the Buffalo area, is there any reason to believe that costs for wells there would be any different than what you're seeing or what you saw in the Dorcus well, or can we assume kind of $8.5 million with heavy science and trending downward over time is a safe assumption for that area as well?

At this point I really don't have any way to give you a number that's better than that

Okay.

We don't expect will cost to be significantly different.

Okay that's helpful, thanks.

One other quick question.

I'm not sure if you can comment or not, but you mentioned that the Buffalo acreage was acquired at a relatively low cost.

Can you put a number on that?

Or is there an average that you think we could use?

We're still closing and acquiring a little bit, so I don't think we'll use a number.

What I can say is it was low-cost compared to some of the numbers you'll see in the more established areas of the basin.

Fair enough.

I think that's --

Thank you.

James Spicer -- Wells Fargo

Good morning.

Just going back to the balance sheet for a minute, you guys are clearly in a very strong financial position here.

Spending is roughly in line with cash flow.

You're going to be building of a pretty substantial war chest through the proceeds from the Anadarko basin sale and some of your other smaller asset sales.

It sounds like the intention here is to use the proceeds from these sales to support and potentially accelerate the CapEx program.

Just wondering whether there are any other uses of proceeds that you're contemplating?

Be it further depth reduction, share repurchases, dividends, anything else?

Yes, James, it's Wade.

Just a tagalong to what Tony said, we'll be reviewing all those capital allocation decisions over the next few months before we come out with our 2014 plan.

And it really does depend on success in the new ventures area.

So those could add a lot of capital for very good reasons.

So, right now that's really all we're saying on it, but as, we always do, we'll review all of our options and consider our balance sheet as we go along.

Okay.

And then a related question.

The 1.2 times leverage where you guys are today, is that something you view as a good long-term level that you feel is optimal for running the business?

Or do you think that could move up materially higher or lower, given your view on capital spending?

Yes, this is Wade again, James.

The 1.2 times is a very comfortable level, obviously.

You've heard me say in the past that we would be comfortable going up to around a 2 times level.

That's still the case; that hasn't changed.

It's a very enviable position to be in, where we are right now, but we would move that up for the right reasons.

That's helpful, thank you.

You bet.

John Nelson, Citigroup.

Good morning.

Congratulations on the quarter.

Thank you, John.

First just a housekeeping item.

Can you confirm the Dorcus well rate was a two-stream rate, and what an approximate number might be on a three-stream basis?

John, I have to apologize, but I could not hear the question.

Could you just speak up just a little bit?

Is this better?

Yes, just talk loud, okay?

I'm not -- I'm getting a little old, maybe.

I don't hear as well.

Sorry about that.

The question was on the Dorcus well and whether that reported number was a two-stream rate, and if there was an approximate number you could provide on what a three-stream level equivalent might be?

That was a two-stream number; it's wet gas and oil.

And it is rich gas, but I don't know the exact -- I don't know what the three-stream number would be, because our gas contracts don't provide us with a liquid volume.

But it's pretty rich gas.

Fair enough.

And then in your prepared comments, you talked about putting a lot of sand and fluid relative to peers, and you also I think had tighter frac-stage spacing.

Jay, sort of peer-leading well results, if you were to sort of normalize on that basis -- I'm just curious your thoughts on if we've sort of run as far as we can as part of increasing the intensity of the wells?

Or whether there'd be sort of diminishing returns from continuing that trend?

Well, our focus here early on was -- we wanted to put everything into this we could, so we went about as tight as big as we thought we could.

And probably one of the biggest fracs we've ever pumped.

And that was our focus, was to really make these wells work early on.

And they are economic the way we're pumping them.

I think most of our optimization -- we're going to look at the different proppant types.

We pump this well with all white sand; the Britain well we're actually using a premium resin-coated product.

And we're going to pump ceramic on one of these jobs here pretty quickly.

As far as stage spacing and fluid volumes, I think we're probably of the top end of where we would be, and we'd probably start working our way.

So we'll get this stuff done, this testing done, and we'll probably start working our way down as opposed up.

And that was really are focus, was let's do the big stuff first and not sneak our way into it over time.

We wanted to do the testing early.

So I guess that's an answer to that question.

That's great color, thanks.

Last question -- I got to ask -- it's obviously very exciting sort of news coming from the Permian, and the balance on your stock today is encouraging, but there is still what I would consider a pretty staggering valuation discrepancy between sort of where you guys trade and either were more Permian pure plays are trading sort of or buying assets at?

Given that you guys have been proactive in reshaping the portfolio historically, I'm wondering if you would evaluate monetizing the Permian here or there might not be a tax efficient way of sort of capitalizing that arbitrage?

Well, I'll take a first stab at.

Obviously we are; we see the multiple as well.

We have been encouraged recently by the stock performance clearly outperforming all of our peers in the EPX at a significant level this year.

As I said before, over the next few minutes we'll be looking at our capital allocation decisions, and we factor everything in, and that's not going to change.

Regarding your specific question about monetizing the Permian, we always look at our assets as part of that process, and that's why we're filling the Anadarko basin.

Permian is part of our three-legged stool, as Tony said earlier, but beyond that I'm not sure I would say any more

I would say that part of why we spent so much time on the Permian today was that so people could understand what we believe is a really compelling portfolio there.

And we certainly hope to see that result and some value accretion to the Company for doing that.

Fair enough.

Thanks, guys.

Congrats on the quarter.

Thank you.

At this time there are no questions.

Thank you, operator.

And thank all of you for joining us for the third-quarter call.

Again I would like to certainly complement our organization for putting up some great numbers and for their execution and exploration efforts.

We look forward to talking to you at our fourth-quarter call, as well as year-end.

Thanks so much.

Thank you this concludes today's conference call, you may now disconnect.