SM Energy Co (SM) 2013 Q1 法說會逐字稿

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

At this time, I would like to welcome everyone to the SM Energy 1Q 2013 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)

I would now like to turn the conference call over to Mr. David Copeland, Executive Vice President and General Counsel.

Please go ahead.

Thank you, Lynn.

Good morning to all joining us by phone and online for SM Energy Company's first-quarter 2013 earnings conference call and operations update.

Before we start, I'd 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 factor section in our form 10-K filed on February 21, 2013.

We'll 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 pages in our slide presentation for an important discussion of these terms, and the special risk 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 myself, the Company's Executive Vice President, General Counsel and Corporate Secretary.

I'll now turn the call over to Tony.

Good morning, everyone, and thank you for joining us for the first-quarter 2013 SM Energy earnings call on this snowy day in Denver.

We are changing the format of our earnings call this quarter to place more focus on performance, execution, new ventures and frequently asked questions from the street.

I will start with the quarterly performance recap and operational highlights.

I'll then hand the call over to Jay to address some current questions we've received, and review some of our exciting new ventures.

Lastly, Wade will walk through our financial position, which of course, includes a strong balance sheet.

We'll be referring to slides this morning that we posted on our website last evening.

With that, I'll begin my recap of the quarter on slide 4. Results for the first quarter were solid again compared to our performance guidance.

I trust that most of you reviewed our press release from last night, so I won't repeat all of that information on the call this morning.

I'll just note that we came in on the high side of our production guidance, and that we performed well against most of our cost guidance.

We had GAAP net income of $16.7 million, or $0.25 per diluted share.

Adjusted net income for the first quarter was $55.3 million, or $0.82 per diluted share.

EBITDAX for the quarter was a record $329 million.

I would also note that both adjusted net income and EBITDAX were higher than their respective first call estimates.

It looks to us that we came in higher on production and realizations compared to how the investment community had us modeled for this quarter.

Moving to slide 5, our operated Eagle Ford Shale program reported average daily production of 51,800 BOE per day, which represents 15% sequential production growth.

When looking at the production ramp over the last year, production has grown by 74%.

Our rig program for the first quarter remained consistent with the fourth quarter of 2012, at five operated rigs.

We made 28 flowing completions during the quarter.

Drilling in this program has been focused in what we refer to as area three, also known as Galvan Ranch, and the eastern portion of area one, also known as Briscoe Ranch.

The majority of this drilling is being done on multi-well pads that are more efficient, and require a smaller surface footprint.

The efficiencies gained from these multi-well pads are expected to result in lower overall well costs.

On slide 6, our non-operated Eagle Ford shale program continues to grow production at a healthy rate.

First-quarter production was 16,000 BOE per day, which represents 3% sequential growth from the previous quarter.

The operator utilized nine drilling rigs for this program during the quarter.

We expect to be carried by Mitsui on our portion of drilling and completion capital into 2014.

On slide 7, our Bakken Three Forks program reported average daily production of 12,200 BOE per day, a 3% increase from fourth quarter of 2012.

We operated a four-rig program and made 11 gross flowing completions during the quarter on our operated acreage.

In the second quarter, we expect to trade out two of our four rigs for a more efficient walking rig that is optimized for pad drilling.

During the first quarter, we did not experience any significant weather interruptions to our operating activities in North Dakota.

With that, I'll turn the call over to Jay.

Thank you, Tony, and good morning, everyone.

It's another snowy day in Denver.

Before discussing our new ventures activity for the quarter, I wanted to address a few specific questions we've been getting about our operated Eagle Ford program.

First, I wanted to give an update on our condensate realizations.

I'm now on slide 9. In general, all of the oil we produce from the Eagle Ford has an API gravity higher than 45 degrees, and may be considered to be condensate.

In the first quarter, our price realizations for this product were above the NYMEX WTI price, and were actually higher than in the fourth quarter of 2012.

We manage our condensate sales through a basket of sales contracts, most of which are indexed to LLS pricing, which was at a $20 premium to WTI in the first quarter.

We are in the market a great deal, negotiating sales arrangements, and have not seen material weakness in condensate gravity adjustments at this time.

We are obviously pleased with the recent prices we have received for our Eagle Ford condensate, especially when you consider that our Eagle Ford economics assume a discount to NYMEX WTI of $7 to $8, which is still our long-term expectation.

The second question I wanted to address this morning relates to our operated Eagle Ford downstream transportation agreements.

As discussed on slide 10, during the first quarter we regularly shipped wet gas production in excess of our firm downstream transportation capacity, and we continue to do so in the second quarter.

Our experience has been that there is sufficient interruptible space available, and we have had no trouble moving all the volume we produce on any given day.

We have existing contracts for more firm downstream capacity starting at mid-year, but at this point we believe that interruptible capacity will continue to be available to us as well.

We do not see downstream capacity as being a limit to our production growth at this time.

Third, I wanted to update you on our ethane rejection status, as this is a common question.

We are still rejecting ethane in South Texas in contracts which allow for ethane rejection.

Ethane rejection is a monthly election, and at this point it makes economic sense to sell the ethane as BTUs in the gas stream, versus recovering it and selling it separately.

Right now, the strips for gas and ethane suggest that we will be rejecting for quite some time.

We talked about the potential volume impact of this at our last call.

As a reminder, however, our plan is still to exit the year producing 50% liquids.

We have had several questions regarding the historic production performance of wells in what we call operated Eagle Ford area one, and the expected case data we put out for this area earlier this year.

In our year-end resource summary table, we gave an expected average three-stream EUR for area one of 600,000 BOEs.

To be clear, this 600,000 number was generated using rate-transient analysis, not by averaging our historic decline curve results from wells in area one.

Our existing wells in area one have been impacted by high back pressures due to long flow lines and a lack of compression, which has prevented them from achieving their full rate potential.

Rate-transient analysis is a better tool for predicting EURs in this circumstance, and we expect that with improvements we are making in area one facilities, that future wells will outperform our historic decline curves.

Condensate yields from existing wells in area one vary widely from as low as 30 barrels per million cubic feet of gas to 310 barrels per million cubic feet of gas.

Using our current spacing assumptions, we estimate an un-risked location-weighted average yield for all area one potential locations of 125 barrels per million cubic feet of gas.

For the AFE type curve and well economics, which we provided, and which are included in the appendix to this presentation, we used a value of 170 barrels per million cubic feet, which is the simple midpoint of the yield range, and is a conservative estimate of the expected yield of wells in area one we plan to drill in the next year or two.

I should point out again that, as reflected in our attached materials, our planned drilling programs in the Eagle Ford generate strong economic returns, and would do so even at lower commodity prices than we are currently experiencing.

Now I would like to move on, and talk about our exciting new venture program.

We think it's of critical importance to continually be exploring for the next idea that will propel the Company forward.

Even the best assets have finite lives, so it is important to keep the pipeline of potential new projects full.

At SM Energy, we have a very focused approach as to how we generate, test and ultimately develop ideas from our new ventures program.

The goal is to add self-generated economic inventory that competes in our portfolio, so that we can continually hydrate our development program.

All the projects that I'm going to speak about today were internally generated new venture projects.

We currently have two separate exploratory programs in the Midland basin -- our Permian shale program and our Mississippian limestone program.

Unfortunately, we had some delays in completion timing on some critical shale wells, so I don't have an update on that program today, other than to say that we are currently drilling our first Wolfcamp shale well on HBP'd acreage in the south Midland basin.

However, I do have a few slides, starting on slide 11, on our Mississippian program with some well updates I wanted to share.

Just to remind you, our Permian Mississippian prospect is the same geologic age as the Mississippian other people are chasing in Oklahoma and Kansas, but is more of a conventional play which produces at lower water cuts.

The slide shows a map of our entire acreage position, with a blow-up showing the horizontal wells we have drilled on the acreage to date.

As you can see, we have drilled more wells in the Roy area, and fewer wells in the Dana and Rebecca areas.

On slide 12, we have provided a listing of our horizontal Tredway wells with peak 30-day production rates and effective lateral length.

I should say that we call this prospect area Tredway internally.

And I also should mention that when I talk about effective lateral length, I'm measuring that from the first perf to the last perf.

Some people do it in different ways.

You can see that with the exception of a couple of wells with mechanical or completion issues, we've had fairly consistent results with our short lateral program.

We've recently begun using a longer lateral well design, and our first result, the Roy 1803H, has averaged 988 BOEs per day over the 12 days it's been online.

I'm now on slide 13.

As the prior slide showed, we have the most well data in the Roy area, and at this point we are comfortable showing what we think the type curves are for that area, which represents about one-third of our acreage in the Mississippian play.

The gray lines on the slide are data from the individual short lateral wells from the Roy area, and the black line represents the average of those PDP wells.

The red line is our projected type curve for our 4,400-foot effective lateral well, which has a projected EUR of 310,000 BOEs, and is 93% oil.

We then have extrapolated that result for a 7,000-foot effective lateral, which is the upper blue line on the slide.

It has a projected EUR of 440,000 BOEs, and also 93% oil.

So far, our Roy 1803 well looks like it's going to be our expected long lateral type curve.

As we have more data in the Dana and Rebecca areas, we'll provide that to you.

We are encouraged by our recent results, and we continue to make progress in driving our costs down, which is going to be a common theme in all our new venture efforts this next year.

I'm now turning to slide 14.

We haven't spent much time talking about our Powder River Basin assets recently, but we've been testing several wells in zones of interest.

Our original target in this basin, you may recall, was the Niobrara, which had mixed results based on our testing.

However, our recent results, and the results of several other operators in the Frontier section have been very good.

Our recent operated well, the Dandy State, had a peak 30-day initial production rate of 927 BOEs per day.

Two partner wells that we participated in had peak rates for 30 days of approximately 1,400 and 1,700 BOEs per day, respectively.

We are really excited about the Frontier, and we think that the Shannon [interval] could be interesting as well.

In fact, we recently completed a Shannon test that had a peak 30-day IP of approximately 500 BOEs per day.

We recently entered into an agreement to add approximately 40,000 additional net acres to our Powder River Basin position for $65 million, which includes some seismic acquisition costs.

After closing, we expect to have approximately 105,000 net acres in the total Powder River Basin, with about 62,000 net acres in what we consider to be some of the best rock for the Frontier play.

You can see from the map provided that the acreage we are adding is a great bolt-on to our existing acreage position.

Our combined position will have potential for about 250 gross Frontier wells, and we estimate that our aggregate acreage position will have about 90 million BOEs of total net resource potential.

We'll have another Frontier well completed before mid-year, and I expect that well and other wells to be drilling -- I expect that we'll be drilling additional wells in the second half, with the potential for a two-rig program in 2014.

Lastly, I'll provide an update on East Texas.

I'm on slide 15.

We've entered into additional agreements, which, subject to due diligence and closing, will expand our previously announced 105,000 net acre position to approximately 150,000 net acres.

And we continue to acquire acreage in the area.

Earlier this month we released test results for a well in our East Texas play that targeted the Woodbine formation, and we have more Woodbine tests scheduled in the second half of 2013.

The acreage position we've assembled has multi-pay potential, and we'll shortly be drilling an Eagle Ford test as well.

It's early days, but we're very enthusiastic about the potential of this project.

I'll now turn it over to Wade to talk about the balance sheet.

Thank you, Jay.

Good morning.

I'll start on slide 17, and discuss our financial position at the end of the first quarter.

Not much has changed from the prior quarter with regard to our capital structure.

It remains very straightforward, with three pieces of long-term unsecured debt and our revolver.

As of the end of the first quarter, our debt-to-trailing 12-month EBITDAX remained at 1.4 times, which is certainly below most of our peers.

Our debt-to-book cap stands at 52% at the end of the first quarter.

On the right half of the slide is a graph showing our debt maturities.

You can see that we are in really good shape there with nothing coming due till 2018, and that's simply the current maturity of our revolver.

Speaking of our revolver, on slide 18 I'll discuss our amended secured credit facility.

Earlier this month, we and our bank group amended the revolving credit facility, and redetermined the borrowing base to $1.9 billion, up from its previous $1.55 billion.

The increase in the borrowing base is a testament to the increased value of our PDP assets driven by strong reserve additions at year end.

Along with the increased borrowing base, we decided, and the banks agreed, to increase the commitments under the borrowing base to $1.3 billion.

I'll now take a couple of moments to talk about our capital allocation process.

Clearly, based on some of the new venture success that Jay talked about, there is the potential for a significant amount of capital to be deployed in these programs over the coming years with continued success.

Our process is to evaluate our capital program twice a year, and our next review will be around the middle of this year.

We will look at opportunities to high-grade our existing program, as well as monetize assets that may not compete in our portfolio.

We also have the ability to use the strength of our balance sheet to fund some of these new programs.

We are committed to a disciplined approach to allocating capital that generates high returns, preserves the strength of the balance sheet, and doesn't dilute shareholders.

So with that, I'll turn the call back over to Tony.

Thank you, Wade.

Before handing the call over to Q&A, I'm on slide 19, where I'll address the question -- why invest in SM Energy?

First, I would point to our recent performance.

We were top quartile in a number of important debt-adjusted share measures over the last three years, including production growth, proved reserve growth and EBITDAX growth.

We were also in the top quartile of all sources, finding and developments costs.

Next I'd point you to the near-term outlook for the Company.

We expect to grow production between 15% and 20% annually over the next three years.

And consensus estimates have us growing EBITDA by 20%-plus in both 2013 and 2014.

As you've heard Jay talk about, we also have a pipeline of exciting new venture projects.

We think that is very compelling as we move forward to continue growing our Company.

Lastly, I would point to our valuation.

I believe that we trade at valuation multiples that present a great entry point for investors.

With that, I'll turn the call over for your questions.

(Operator Instructions)

David Tameron, Wells Fargo.

I guess let me start with North Dakota.

You guys talked about not having any weather impacts in the first quarter.

Do you think you'll have any flooding impacts?

Anything more than you had expected going into 2Q, given some of the late snowstorms?

David, this is Jay Ottoson.

You know, it's always cold up there.

And we always have -- I think what we tried to indicate that we haven't had any abnormal related weather impacts.

We always have weather impacts in the wintertime in North Dakota.

At this point we don't have any reason to expect that we are going to have any significant flooding events there, but of course it's not over yet.

It is snowing here in Denver today and you know the weather is not over.

So we'll see how it goes.

So far nothing that really sticks out to us as being a big issue.

Okay.

Let me jump to the Powder.

Are you allowed to say -- was that QEP's acreage that you purchased?

I don't know what you can or can't say but can you answer that question?

David, we have a confidentiality agreement with the seller so we can't disclose who we bought the acreage from.

Okay.

Fair enough.

Can you talk about going forward -- there's other packages out there.

Do you wish to add to your position out there?

And second, just the operating environment, can you get permits?

How do you see your -- what do you see your activity level look like over the next 12 months out there?

Well, we certainly are interested in additional acreage.

It would have to be in a very specific area for us and that's something we'll certainly look at.

Permitting is something we gave long and hard consideration before we committed to this deal.

We're convinced that we can get permits to run a reasonable program here that makes sense from an economic standpoint.

I think you do have to be flexible.

It takes time to get permits.

A lot of this is on federal acreage.

And you need to be permitting a number of wells at the same time so you have opportunities to move around.

So you've got to be flexible.

Frankly, the opportunity to be drilling in the Frontier and the Sussex and the Shannon, all three of those intervals are prospected, gives you even more flexibility in how you run your program.

We're confident we can generate the present value that we anticipated in the acquisition.

Okay.

Let me ask one more and then -- actually, I'll jump back in the queue and let somebody else ask questions.

Thanks for the color.

Mike Scialla, Stifel Nicolaus.

On the Powder, it looks like you've got a couple wells there that are tracking above 1 million BOE-type curve.

I guess one of your issues with the Niobrara was inconsistency.

You had some good results and then some not-so-good results.

How do you compare that with the Frontier?

Is this going to be similar to where you have a wide variability in results?

Or do you think you'll get more consistency here?

Well, this is Jay again.

I think we certainly anticipate the results being significantly more consistent.

I would say in a general sense in the Niobrara and the Powder we never really had a result that we were really enthusiastic about.

The results were not great and inconsistent, I would say.

In the Frontier pretty much every well we have participated in, in this core area has been good.

There's other wells out there that have data that we're aware of as well that look good.

And we're really excited about it.

I think it does have that opportunity to have consistent results.

The other thing I'll say here, and I think it's important is we've built a really top-notch drilling and completion team in the Bakken and Three Forks and this is just an opportunity for us to put them to work really grinding away at the costs here in this area.

These are expensive wells.

A long lateral 1280 Frontier well is probably $14 million, $15 million.

And with opportunity to really work on that, we think we can generate even more value here by really grinding on costs.

So to us, it really fits in that -- it puts it right in that flywheel of excellence that we have around our drilling program in the Rockies, and it is just a real great opportunity for us.

I guess a couple follow-ups on that.

What's the depth here?

Can you get it down to your Bakken-type costs over time?

Are we really talking about the -- is it the Turner Sand within the Frontier?

Is this analogous to -- one operator in particular is doing a lot of drilling to the east of you.

Is that -- do you think that looks analogous to the acreage you have?

Well Mike, it would be pretty easy for me to get out of my depth on the geologic intervals.

My understanding has always been that these are essentially identical intervals.

They call it the Turner on the east side of the basin, they call it the Frontier on the west side of the basin.

It is fairly deep.

I don't have a depth right here, we'll have to get that to you after the call.

It's pretty hard drilling.

I think there is some significant opportunity to reduce costs with a continuous rig program and optimizing our frac work.

There's a lot of cost that goes into the frac here.

I do think there is significant opportunity to optimize cost and that's something we're going to be working on continuously.

Great, I'll hop back in the queue.

Thanks.

Ryan Todd, Deutsche Bank.

Good morning, gentlemen.

A couple more questions, one to follow-up on the new ventures.

For activity levels in the Woodbine and the PRB, how should we think about it over the remainder of 2013?

And the $65 million in your capital budget that's in that other operated bucket.

Should we expect that to fall in there -- is there potential for upwards pressure on the $1.5 billion budget?

This is Jay again.

What we have said in the Woodbine is that we think we can cover the wells we'll be drilling there out of our new venture program.

We won't be starting up our drilling program there until the second half.

Again, it will take us that long to get our rigs and permits in place.

I think one thing I should mention as a part of this, our Eagle Ford program, we're ahead of schedule, we're under budget, we're drilling wells faster than we expected.

Quite frankly, we probably have some opportunity to shift some capital around in our portfolio to cover some costs.

That is something, as Wade mentioned, that we'll look at very hard at our mid-year allocation meeting.

We have some knobs we can turn here other than just to go into more debt, if that's the question you are asking.

I think we will do that.

At this point we are talking about probably a single rig program in the Powder in the second half.

But it probably wouldn't start up until August or so.

As I said we have a well currently completing up there and we need to get prepared and get ready to really get after it.

But I doubt we start drilling there really until the August, almost the fourth quarter time frame by the time you are through it all.

Not a big spend during this calendar year.

Next year, you know, I hope we can mount a significant program, two rigs, maybe even three, depending on how it goes, depending on some of the permitting questions that David asked earlier.

But we have a lot of knobs to turn, we have a lot of things to look at.

We have some programs that are going faster than we expected at lower cost, and we're certainly going to use all those opportunities to try to manage our CapEx to a reasonable level.

Great, that's good to hear.

You mentioned it briefly earlier.

You guys have done a great job of filling out some pretty attractive in new venture regions here.

You've got a decent number of other non-core assets that you are not deploying much or any capital to at this point; Haynesville, Woodford, Granite Wash, some of the others.

Should we expect to see some of those come onto the potential monetization market in terms of funding some of these other go-forward programs?

This is Tony.

Let me address that one.

As we've done over the last several years, we'll continue to high-grade our portfolio.

And certainly part of that potential upgrade involves the monetization of existing assets.

So we'll continue to look at those opportunities, some of which you've mentioned, but each year we'll go through our entire portfolio and identify those assets that we think should go to market.

And then obviously use the proceeds to help fund some our new venture opportunities.

Great.

Thanks that's helpful, guys.

I'll leave it there.

Brian Lively, Tudor, Pickering, Holt.

Tony, I would like to reflect on that slide 19 where you went through the why invest in SM.

Operationally, no doubt you guys have done an excellent job beating estimates, growing reserve base, building new positions, high-grading the portfolio, et cetera.

But we still haven't seen the flow-through of those results to the share price, especially as it relates to the multiple, which I think was your last point.

I'm sure you guys are frustrated internally with the way the stock has performed.

And so my questions are really what do you think the market is missing here today?

And is there a point, like the question I asked last quarter, is there a point when you believe other steps are necessary to bring forward shareholder value?

And if so, what are you guys considering at this point?

I think first of all Brian, while the multiple is something that we do look at, I don't get overly frustrated with that at all.

I think our focus is to continue to execute and bring forth new opportunities to make sure that our performance remains at a high level.

So quite frankly, I'm very confident about our delivery and we are going to continue to focus on our program at hand and on execution.

And I think, over time, as I like to say, reason will prevail and those multiples will close with the peer group.

But I think absolutely one of the things we are doing right now, and this call is evidence of that, is we are focusing on the key questions and issues that may be out there with investors and analysts to make sure that we are being very transparent, very clear in terms of our strategies and execution, and then we continue to execute against the plan.

So I think a good way to think about that is we're offense, executing well and we'll keep delivering results.

No doubt, Tony.

But you guys for the last couple of years have been probably one of the stronger executing companies within the E&P space.

I'm just trying to think forward.

If you continue to post good results but you don't see the follow-through, especially as it relates to the valuation.

I mean, what do you guys do at that point?

Well, first of all, as we proceed, we've got a very strong long-range plan.

We are going to continue to execute against that.

You have heard us talk about maintaining a very strong balance sheet.

We'll continue to look at high-grading our portfolio.

If there are assets that it's timely to go to market, we will certainly do that.

I think if you look at our history over the last several years, that is exactly what we've done.

And that is how we have been able to position ourselves in some of the most exciting new ventures, yet maintain what I think is a very strong balance sheet with significant funding capacity.

And that strategy won't change going forward.

Okay, we'll leave it there.

Thanks, Tony.

Thanks, Brian.

Subash Chandra, Jefferies.

Morning.

To follow-up on the Frontier here, is there a lot of associated water with this formation?

Subash, could you repeat that?

I couldn't hear which interval you were talking about.

The Frontier.

Oh the Frontier.

No, there is not a lot of water associated with it.

Okay.

And looking back at my prior notes, you guys have had an active program there, I guess an appraisal program for some time.

This part of the basin is deep, over-pressured.

And if that is correct, how your acreage does it encompass that entire area?

Or is there some flank in that acreage as well?

Well, Subash, we provided a map so you can look at it and decide how you feel about it.

You know, we think, as we released, there is about 62,000 acres there that we think are highly prospective for the Frontier.

It is deep and it is over-pressured and frankly, that is why we like it.

This is one of the keys to making resource, pressure is one of the keys to making resource plays work.

We were looking for pressure when we went here and that is certainly what these wells have.

So I would say -- and you'll note that as you look at the results, these wells produce a little more gas, say, than our Permian program.

I think we said our Permian program, Tredway, is 93% oil, Frontier is considerably lower than that.

There's a lot of liquids that are produced out of the Frontier.

It is a deep over-pressured system.

So a lot of the values in the gas liquids as well.

Okay.

So this is the map you are talking about on page 14?

Yes, that's right.

I think we give counties on there.

But you know our view is, this is the deeper parts of the basin.

We call it the deep Powder, and it's clearly one of the areas where the Frontier's the most over-pressured.

Got it.

Okay.

And then another question.

In the Eagle Ford area 3 drilling activity, could you refresh me on the rigs and the potential to accelerate development in area 3?

Or the thought process you might go through in order to make that decision?

So far this year -- this is Javen again, most of our drilling has been in area 3. I think we had 28 completions in the first quarter.

Most of those were area 3 wells.

And that's where most of our activity has been.

We are moving quite a bit of our activity into area 1 here for the next quarter or two.

We have some specific wells we need to get drilled up there, mostly on the east side of area 1 and then we'll get back to area 3 later in the year.

As I mentioned earlier, we think at this point we are going to complete our scheduled program, in terms of the program we had anticipated, we are going to complete early.

And we are drilling the wells faster than we expected and we are drilling them at lower costs than we expected.

So we are going to have to make a decision on whether we want to go ahead and complete more wells than we anticipated and potentially -- you know, we're not drilling them as cheaply as we are quickly.

We'd have to spend more money to keep all five rigs running all the way through the year and potentially complete quite a few more wells.

Or if we want to conserve that capital and spend it in our East Texas or Powder programs and cut back to a, say a four rig program in the second half.

We know for sure that we are going to move one rig out of here for some period of time to East Texas.

We haven't decided how long that is going to be.

That is really going to be a mid-year decision for us.

As Wade mentioned, we have a process we go through at mid-year to look at all our programs and reallocate.

We just haven't made that call yet.

We are certainly very mindful of where we are with respect to CapEx versus cash flow and where we are in terms of our overall Eagle Ford program.

We do think if we wanted to spend a little more money and keep five rigs running that we could certainly do that.

It's just there's trade-offs that need to be made there with respect to our overall capital budget and program.

If I could ask a strategy question there.

So you have a very high threshold for returns, area 3 and area 1, East Texas, I think, looking at my prior notes you were sort of anticipating 25% plus type.

So good enough, maybe slightly lower in PRB is to be determined.

How do you think that might be translated if you are -- I guess you would if you are shifting from a higher to a lower, and if that is an accurate statement, IRR business?

And second, how do you think about spending within cash flows if every dollar is actually creating well above the cost of capital returns?

You know why hold onto the spend within cash flow regime?

There is two questions in there.

Let me answer the first one and then I'm going to turn it over to Wade to answer the second.

In terms of trading I understand what you're saying.

You are saying why would we move rigs out of a very highly economic play into something that we haven't proven is highly economic?

I don't know that we have ever said what we think returns in East Texas are going to be.

Clearly we think they'll meet our hurdles.

Frankly, they are going to have to do a lot better than that if we are going to drill it long-term.

The Powder numbers, if you look at a 1 million barrel well for the kind of costs that we talked about earlier in this call, we'll have very substantial economics and it could be very exciting.

Obviously we are not quite there yet, but yes, we have to prove that up.

So I don't think, in my view at least, we would not necessarily be making a return trade-off.

With that, I think I'll turn it to Wade to talk about the other question.

Well your question about within cash flow, I mean that's -- we've said for a long time that our objective was to get to that point and we still see it on the horizon by the end of this year.

We've also said that we are not setting that as a limit for ourselves going forward, just simply as a marker, frankly, that shows that we have a portfolio that has the ability to generate significant growth within cash flow, which we think is a very important sign.

At that point if we have opportunities that are high return beyond that, we'll take a strong look at that and a look at the balance sheet at the time and make the decision from there.

You know, Jay said it, it's all about the highest returns, I think we'll say it again.

The only way to do that corporately is to rank our projects and if some projects start coming in higher than others, we have to take a hard look at the ones on the lower end of the list.

And maybe those get divested or JV'd, or something else.

But that is the way we look at it.

Great, thank you very much.

Welles Fitzpatrick, Johnson Rice.

In the PRB, what is the working interest in those partner wells?

And how much of that 105,000 do you guys operate?

You know, that is a great question.

The average working interest in our Frontier position is going to be about 48%.

So it's lower than our typical percentages.

Of the whole 105,000 that is 105,000 net acres.

I don't know exactly -- the reason it is hard is because operatorship is not necessarily determined, it is determined by who permits first and a number of other issues that relate to operatorships.

I'm not sure I can tell you exactly how much of the 105,000 we would operate depending on how the wells lay out.

We are thinking right now in the Powder, the deep Powder section, there is about 250 gross wells there which is on the Frontier side.

And then there's a significant number and it's in the presentation about the Shannon and Sussex as well.

I don't know that I can give you a percentage operated, but that 48% number is a pretty good number for what we own in the sections we own.

Okay, perfect.

And then the permits that you guys have in the Frontier, it looks like it's concentrated in that Finley Draw area.

Is that correct or am I just looking at stale permits?

Of the 4 2,000 Frontier acres, how many of those are represented in the 251 gross wells?

Are those across the entirety of it?

Or is that -- could that number go up, I guess is my question?

Well, we think the 250 is a good number for the acreage as a whole.

I don't know that I think that number is going to change a lot.

We are drilling, the well we're completing right now is on the north end of our acreage position.

There is another non-op well that's been completed up there recently which looks very good to us.

So we kind of have it straddled.

I would say that the individuals we are buying this acreage from had some existing permits as well on some wells there, so we don't just have our own permits to deal with, we have theirs as well.

And we'll be doing some additional permitting.

Perfect.

One more quick one.

You guys changed the wording a little bit from the Leonard to the Bone Springs -- obviously the Leonard is in the Bone Springs.

But is that -- are you guys look for additional members or am I reading too much into that?

I don't think we actually changed the wording.

We are drilling some Bone Springs wells in New Mexico.

And we are drilling some Leonard shale wells in the Midland basin.

So I think you may be -- we may have inadvertently confused you there with that.

You're right, they're all that Pennsylvanian age stuff or Leonardian age.

But the Bone Springs wells we're drilling -- and we do have a rig running in New Mexico right now drilling some Bone Springs wells.

We just don't talk about it a lot because it is not a huge position.

Okay, perfect.

Thanks.

Got you.

Pearce Hammond, Simmons

Get some sense if you are thinking about divesting some non-core acreage or positions, what might be the timing for that?

Is that a process that could be ongoing right now?

Or is that something you tend to look at during this mid-year update or once a year or what not?

Pearce, this is Tony.

I would say that we are going to be looking at all those issues and the various options at mid-year.

And obviously, this is a great problem to have with some of our exciting new venture projects in front of us.

But we'll look at that at mid-year and then decide which ones we might consider going to market with.

Great.

And then two quick ones on the Eagle Ford.

First, do you have any potential impacts from the drought in Texas?

And then secondly, Jay, relative to your planning at the beginning of the year it sounds like the Eagle Ford's operating a lot stronger than the original plan.

When you look at your original expectations for infrastructure like tank batteries, gas processing plants, takeaway capacity, et cetera, do you think that is also developing a little bit faster than what you originally thought?

Two great questions.

Let me take the water one first.

You know, there is -- there are, no question, significant drought in Texas.

The South Texas area is really under a lot of pressure.

Fortunately, we get all our frac water out of the Rio Grande river.

I guess I should say we were knowledgeable enough or lucky enough to have acquired enough water to where even if they prorate the river substantially we'll still have plenty of water to run our program.

We feel very fortunate to have been in that position and frankly, due to some terrific work by our land and operational people in South Texas, we made that commitment.

Second issue, with respect to the infrastructure and our pace, we are ahead of schedule.

And we completed 28 wells in the first quarter, which is well ahead of where we expected to be.

It does give us some opportunity to be flexible in the second half of the year.

Our gathering system provider, Regency, has done a terrific job for us over the last three to six months in catching up with us.

I was visiting with them just the other day on schedule.

They are actually ahead of our planned schedule on a couple of facilities that are coming this summer.

We have quite a bit of facility work to be done in the fall.

At this point I really don't anticipate that midstream or downstream facilities are going to be an impediment to our growth.

It is really going to be about how we choose to allocate capital over the next 6 to 12 months.

And how we look at trying to prove up these new plays, which is very important for a company that tends to be in business, versus monetize our existing assets.

Those are things, choices we have to make.

And we'll be making those here around mid-year.

Thank you.

Jeb Bachmann, Howard Weil.

A couple of quick questions.

First on the non-op Eagle Ford.

I noticed you guys had talked about cost increasing in the first quarter.

Just wondering if the operator is doing anything to improve the efficiencies there with trucking and some of the other infrastructure to bring down those costs going forward?

You know, Jeb, I think it's probably a great question to ask Anadarko.

I don't -- you know as well as I do, it's difficult for us to know exactly what is going on at any point in time.

We get bills and we pay them, and we try to forecast those.

Based on what I have seen, I think Anadarko is doing a terrific job.

And some of this, this is just that lumpiness you get that's associated with non-op stuff.

They did have some -- our LOE was a little higher in the first quarter than we expected.

I will say from a budget standpoint, we were basically right on our LOE budget.

We were probably a little optimistic based on the trend and took our guidance down a bit little more than maybe we should have.

But I really don't think there is any significant problem, certainly nothing that we are aware of and we think Anadarko's doing terrific.

I would expect those numbers to come right back in line and we'll see what it looks like in the second quarter.

Okay.

And then looking at those few drilling completion issues in the Mississippi lime in northern Midland, wonder if you could give some color on exactly what happened there if you can?

You bet.

The Melanie well is listed.

We drilled into a cavern and ended up twisting off and had to complete a very short lateral well.

Other than that it's not a bad well for the amount of footage we put in it, it's just not what we hoped.

There is a Dana well on there that I would -- was also short lateraled.

We ended up side-tracking the well, had two laterals going.

As we completed the well, the well came on really nice and then started producing a bunch of water and we are pretty sure we fracked up into another water section above us and that's how we ended up there.

And then there's a Debbie well which is sort of on the northeast corner of the Roy area we have developed.

Looked like we drilled across a small fault or into a fault block and that well's just wet.

It's making a lot of water.

And so you know, there is still significant risk associated with some of this.

It is conventional in the sense that their porosity is in different intervals.

You do have some seismic issues here.

We've got a lot of seismic -- done a lot of seismic reprocessing and work to understand what we are drilling.

It is not an easy play.

That's why it's taken us a while to get there.

We are obviously gratified with some of the results we are seeing but we need more consistent results here.

And I think that's what we are aiming for.

Okay, great.

Last one for me, Jay, any high volume gas projects within the portfolio that you guys are looking at with gas prices now moving closer toward $4.50 maybe $4.75 this year?

We don't have any plans to intentionally drill dry gas wells.

I would say that a lot of the acreage we have acquired in East Texas has some significant gas potential associated with it that we are not currently pursuing.

It is one of those other intervals that we can chase.

In fact, we completed a well not long ago in the Chalk that we hoped would be wet gas that turned out to be dry gas and it's turned out to be really good well.

I think there is some more dry gas potential.

This is one of those things, as Tony mentioned, as we look at our portfolio and how we decide to trade this and optimize our portfolio, obviously gas prices improving some is going to be a consideration in that.

How do we look at that?

The biggest upside to us from gas price, though, is if you look at all those Eagle Ford economics we have been showing they run a $3.50 flat WTI -- or, NYMEX gas.

If you put those economics at $4.80, which is what January 2014 is right now -- $4.75 I think the last I looked, that is a big lever on our returns.

And I think we have a significant opportunity in our gas portfolio without really having to try to go out and drill dry gas wells.

Joe Magner, Macquarie Capital.

Good morning.

Just looking out at the second quarter of guidance versus the full-year average, I know it's reiterated at the prior level.

But it doesn't look like there is much difference between those two guidance ranges.

Just curious, with the step-up anticipated in the second half, where are some of the leverage opportunities on seeing some increase to second half volumes?

We've talked about operational improvements, improved drilling times that sort of thing.

Just curious where we might see some impact down the road?

Well, maybe we were a little too subtle.

We raised the lower end of that have guidance so the midpoint went up.

So we did raise our guidance.

I would say that.

The second thing in terms of -- we are ahead of schedule.

A lot of that, if we stay on a five rig pace in Eagle Ford, we will spend more money than we budgeted.

And so we have to really decide are we going to stick to the well count we had forecast or maybe a slightly higher well count at the same capital budget or are we going to continue beyond that?

We have not made that decision yet.

We would make that decision at mid-year.

If we made that decision we'd have to increase our capital program.

And I think at -- and then at that point, we would probably have to acknowledge that we are going to produce more than we expected.

At this point, given where we are at with what we've said about our budget, I think the guidance we have given is appropriate.

Okay, thanks.

I guess historically, or over the past couple of years, as you have been waiting for the infrastructure to be built out, your completion schedule has been targeted -- run alongside that.

Now that you have more visibility on that takeaway and process and capacity you have indicated a couple of times recently that the interruptible capacity could continue to be very accessible.

Is there an opportunity to get ahead of the volumes that you have committed to on a firm basis?

Or just curious how you are thinking about the takeaway from the basin now and the opportunity that presents?

This is Javan again.

To me this is all about returns.

It really doesn't -- it doesn't necessarily have to do with infrastructure at this point because I don't see it as a limit.

We are looking at our overall capital program and trying to look at three years out and ask ourselves what is the best way to have the strongest portfolio for the longest period of time?

And where do you spend the money to do that?

We need to make some allocation decisions about how much of this goes into new ventures, how much of it goes into accelerating current assets.

Clearly, you have choices.

You can burn through your current inventory or you can build new inventory.

You can drill more certain high returns, you can go after the long -- a little longer-term view.

We have to make those choices.

I think it's not an easy answer.

I think it makes sense to us to some extent to use the opportunity we have here by drilling cheaper and faster in Eagle Ford potentially to be able to prove up some of this new stuff that we think is going to work and frankly, has tougher lease terms, where we really have to get after it in an earlier time period.

Eagle Ford is very unique in the flexibility of its leasing -- of its lease terms.

We could run a three rig program and still hold all our acreage together.

We need to use that flexibility where we can to improve our overall inventory and the outlook for the Company as a whole.

Great, I'll leave it there.

Thank you.

Scott Hanold, RBC Capital Market.

Yes, thanks you guys.

Just a couple of quick ones.

You know, condensate obviously you said the pricing remains pretty robust.

Is that something that you can effectively hedge out for any period of time?

I think the -- if you look at our condensate pricing it is very directly connected to LLS.

And so LLS hedges have some benefit.

And there is also a connection to, say, natural gasoline prices.

So there is some hedging you can do on that, although that is a thinner market.

I think in general, investors should be thinking of this in terms of we are pretty connected to the LLS market.

And generally, we are going to track fairly closely with changes in LLS over the next few years.

Okay.

So when you look at your hedge book, are you considering hedging the LLS side of things?

Or is that just not a very good trade-off at this point?

Well, when we hedge, we hedge to a location.

So we always hedge -- we hedge basis when we hedge locations.

So whenever we put a hedge in place we are hedging to a specific location and trying to hedge that basis as well.

Okay.

Understood.

Then in the Permian Miss -- couple questions.

What are -- how do the returns compare with, based on what you see early on, with say like the Bakken and Eagle Ford?

And then could you remind me on what the oil and gas cuts are in that project?

I'll take the last question first, oil and gas cuts.

The oil cut varies from about 80% to about 93%, I think was what we released in the Roy area, depending -- it is a little different, depending on which portion of the Mississippian you are in.

In terms of returns, you know, I would have to say that they're still not where we'd like them to be.

If the -- if every well we drilled looked like the Roy 1803H, we would be fabulous, okay, fabulous returns.

We've got one of those and until we see more of that I would have to say we still need to improve and a lot of that is on the cost side.

We just need to get our costs down.

We are working hard in the Permian in general to get our costs down.

It is a tough environment down there.

But at this point I think the Roy area we are fairly comfortable with what kind of wells we are going to make and we are getting better at drilling them.

This last well was, frankly, even a bit of a pleasant surprise to us.

As you saw our type curve wasn't that optimistic.

But at that type curve these wells make above hurdle rate economics at our current costs.

The question is how much better can we get?

You know, as we talk about -- frankly we talk about capital allocation this summer, that is going to be a big topic.

How does this Mississippian project fall with respect to everything else we're doing?

Is it something we should continue to pursue or is it something that's better off in the hands of someone else?

So it's more of a cost versus a consistency issue, based on what you know so far?

Well, consistency's been an issue.

Obviously you look at the well results and I think we are fairly comfortable in that Roy area now that we are getting pretty consistent results.

We are obviously not trying -- we're hoping that you don't just extrapolate that to the other two areas, because we are not that confident there yet.

Okay.

Understood.

And one last question.

You know, I think the best way to frame it for Tony is that when you step back and you look at you know, what you perceive is a sizable evaluation disconnect from some of your peers, and the recent or persistent activism in the energy space, how aggressive do you all look at trying to stay in front of some of this stuff so that you don't have to deal with the situation where you are being pushed to make decisions you may not want to do?

I would say, as I mentioned earlier, our level of confidence in our portfolio continues to grow.

I think you are seeing the quality projects that we are bringing forward, both some that are in the development phase as well as the several new venture opportunities that Jay talked about.

And I think what we're doing and you're seeing it in this call, and if you kept up with us in the conferences we have attended so far this year, we are going to be very out front in terms of issues that we hear and address those immediately and directly.

If you take a look over the last couple of years, we have been painted with some different brushes that were issues to some analysts and investors.

But we are going to be very forthcoming with how we see our position relative to those issues.

A good example is condensate pricing, NGLs.

Those are and have been issues with some analysts and we're taking those head on, to let folks know that sure, condensate could be an issue longer term but we have seen actually a premium near term with that.

But that is just a good example of making sure that we are being as transparent, that we are being timely in terms of responding to some of these issues when they crop up.

Because if you take a look at the execution and the performance, it is there.

If you take a look at the confidence level in the growing portfolio, to me it's a high quality problem to have.

We've got some great projects to select from, now we are going to be making decisions in terms of how we fund those.

And then we've got a lot of flexibility with our current asset slate.

And as we've done in the last several years, we utilize those assets, those that fall out, we are not at all opposed to going to market to help fund some of the new opportunities.

I think what you'll see from us is continued focus on execution, continuing to address issues as they come up, and again a continued increase in confidence in terms of delivery on our projects.

Scott, this is Wade.

I think Tony said that well.

The only thing I would add is that we are trying to be patient.

I think the market will get it.

Since we have started a lot of this, been somewhat encouraged by the stock's performance year-to-date.

Most of the comparisons I've seen we have been out-performing the peer group.

It's a good start, we're still trading at a discount, but we think it is going to get there.

Appreciate that, guys, thanks.

Mike Kelly, Global Hunter Securities.

Was hoping to get a little bit more color on the potential progression in the southern Midland base.

And really, what do you still have to accomplish here before you talk about a defined development drilling program?

And I'm also curious just to hear kind of in your eyes how this acreage ranks now between it and the Powder and also what you have in East Texas?

Thanks.

Thanks for that question.

I think if you look at our Midland basin position we have shale acreages both south of Midland and north of Midland.

We have been focusing most of our effort on our north of Midland area, the Leonard.

As we kind of wind up our testing program and make some decisions on that we are really turning our focus to the Wolfcamp intervals, both north and south.

We have two significant assets south of Midland, the Sweetie Peck asset, which is about 13,500 acres, I believe.

And another non-operated position -- operated by Concho, which is called [Haltheast], which is another 6,000 or so acres.

So about 20,000 acres in the southern Midland basin.

Concho is about to spud their first Wolfcamp well on our acreage at Haltheast.

There have been some very good offset wells drilled and we are very optimistic about that potential result at Haltheast and we are literally in the middle of drilling our first Wolfcamp shale test at Sweetie Peck right now in one of the Wolfcamp intervals there.

As we see the results from the two wells, then I think we'll know where to go in the southern Midland basin.

That acreage is all HBP'd, so it's not going anywhere.

So we have the opportunity to test and look and make the right choices in those things.

We also have some Wolfcamp testing we'll be doing later on this year in the northern Midland basin on some acreage we acquired last year, which based on the core work I have seen, looks pretty prospective as well.

For us, it is very early stage.

When we got into the shale plays in Permian a little later than some of the other folks and had to pick up our acreage late, we are relying on some of this HBP acreage to work.

It is in a great area.

We are very close to Pioneer's wells, as I said the Haltheast area, there's a number of great wells around us.

So I think it's pretty high chance stuff but still to be determined.

Thank you.

Thanks a lot.

I would now like to turn the floor back over to Tony Best, CEO, for any closing remarks.

Thank you.

Thank you all for joining us on the call today.

We had another solid quarter and we have a lot of interesting things going on at our Company.

Our confidence continues to grow as does the quality of our portfolio.

Our operational groups are performing extremely well and I'm excited about our new ventures' potential that was discussed on the call this morning.

With that, again thank you for calling in.

We'll talk to you next quarter.

This concludes today's conference call.

You may now disconnect.