SM Energy Co (SM) 2016 Q1 法說會逐字稿

Good day, ladies and gentlemen, and welcome to the SM Energy first-quarter 2016 earnings conference call.

(Operator Instructions)

As a reminder, this conference is being recorded.

I would now like to introduce your host for today's conference, Mr. David Copeland.

Sir, you may begin.

Thank you, Antoine.

Good morning to all joining us by telephone and online for SM Energy Company's first-quarter 2016 earnings conference call and operations update.

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

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

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

We will also discuss certain non-GAAP financial measures that 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.

Other Company officials on the call this morning are Jay Ottoson, President and Chief Executive Officer; Wade Pursell, Executive Vice President and Chief Financial Officer; Herb Vogel, Executive Vice President of Operations; and Jennifer Samuels, Senior Director of Investor Relations.

I will now turn the call over to Jay.

Thank you, David.

Good morning to all of you.

Today, we're going to walk briefly through our first-quarter results and share with you some early news from our high-value Permian drilling program.

Before we do that, I would just like to point out a couple of highlights from my perspective.

First, our operational execution in the first quarter was excellent.

Our lease operating expense and G&A costs were below even our expectations, and our well costs continued to be driven lower.

Of special note is that we were able to restart our Permian drilling program and achieve very high drilling and completion efficiencies from day one.

Our well results were also excellent, and Herb will share more with you later about that.

Second, we made good investments in new Permian acreage, and bought back some of our bonds at a discount during the quarter.

We are about to launch our asset sale process for this year, for which estimated proceeds are expected to more than fund these investments.

Third, as part of our normal re-determination process on our credit facility, we were able to amend certain covenants, providing increased financial flexibility at very low cost.

We are well positioned under the new covenants in a lower-for-longer type commodity price scenario.

With that, I will turn it over Wade for his comments on the quarter and our current financial position.

Thank you, Jay.

I will start by following up on discussions we had last quarter, as I believe we're doing exactly what we laid out.

I'm on slide 4, where I want to make three important points about the balance sheet.

First, liquidity remains our priority.

We have about $1 billion in liquidity, as expected following the re-determination process, so we're in very good shape in that respect.

Coverage levels are another priority.

We are pleased with the amended covenants on the credit facility.

Our banks agreed to eliminate the total debt to EBITDAX covenant and replace it with a maximum secured debt to EBITDAX covenant of 2.75 times and a minimum interest coverage covenant of 2.0 times.

We are currently at 0.3 times secured debt to trailing 12 month EBITDAX and 7.9 times interest coverage.

So while we believe we could have lived within the total debt to EBITDAX covenant, it is great to have the added breathing room the new covenants provide.

Thirdly, last quarter, we talked about the temptation to buy back bonds at a discount.

We were able to execute open market repurchases of $46 million principal amount in the bonds, at around $0.65 on the dollar, on average, taking advantage of the market discount.

By the way, the bonds are now trading in the 80s and low 90s area, putting the yields between 8% and 8.5%.

I should remind you the earliest maturity on these bonds is 2021.

Now I will quickly turn to review a few key items from the first quarter.

I am on slide 5 now.

Our operational performance was clearly solid, meeting or exceeding internal plan expectations.

Production came in above the midpoint of guidance, at 13.4 million barrels of oil equivalent, with 31% oil in the commodity mix.

Strong production and a slightly higher oil percentage in the mix reflect the timely and successful re-initiation of drilling and completion efforts in the Permian Basin.

Herb will speak to more detail on our Permian operations and results shortly.

As you are all aware, first-quarter commodity prices were very challenging.

Realized prices were down 21% on average from the fourth quarter, which includes the precipitous drop in benchmark prices, as well as slightly higher differentials.

The oil differential in the Williston Basin increased as Clearbrook pricing had an increased discount to WTI.

And the NGL differential increased, as NGLs came in at 74% of Mont Belvieu pricing versus typically being closer to 80%.

Turning to the cost side of things, LOE was very favorable in the quarter, down both sequentially and year over year on a per unit basis, as our team remains focused on realizing cost efficiencies.

I will specifically point out LOE in the Permian Basin, where cost came down more than 30% year over year, and came down 12% sequentially.

Cost savings were generated across the company, due partly to aggressive rebidding and streamlining of services and materials.

G&A costs were also down.

$32.2 million in the quarter was 26% less than prior-year period on an absolute basis, as the Company works to align G&A with slowed capital activity.

In conjunction with the sale of non-core assets, the Company has consolidated regional offices and realized the effect of associated staff reductions.

All this resulted in adjusted EBITDAX of $182.3 million, beating consensus and in line with our internal expectations at given commodity prices.

So looking forward, in general, we are reaffirming our guidance for 2016 as we remain on track with earlier projections.

Slide 6 is unchanged, as our capital guidance for the year is unchanged.

On slide 7, guidance for all line items remain unchanged as well.

Production in the second quarter is expected to be in line with the first quarter, projected between 13.1 million to 13.5 million barrels of oil equivalent, with the oil component forecast around 31%.

We have experienced some weather-related issues in April in the Rockies region with flooded roads, but this is factored into the guidance.

Also, we do expect second-quarter production to reflect strong recent gas well completions in the Eagle Ford.

Differentials should largely be in line with the first quarter, although we expect some improvement on oil differentials in the Williston related to stronger Clearbrook and LLS pricing relative to WTI.

In regard to realizations, let's turn to slide 8. It is worth noting a couple of points specific to SM.

Our natural gas has a competitive advantage to production from other areas, specifically Marcellus Appalachian gas.

Given the demand from Mexico and regional LNG export terminals, our Eagle Ford price realizations are currently superior to Northeast hubs, and that differential is expect a to improve going forward.

We also have significant exposure to NGL prices.

NGLs made up about 25% of first-quarter total production, and our operated Eagle Ford production is about 35% NGLs.

Eagle Ford NGL production benefits from its proximity to Mont Belvieu.

Recent analyst estimates project 45% plus increases for a Mont Belvieu basket for 2017.

SM cash flow would benefit substantially from a return to these price levels.

Turning to slide 9, a couple of comments on commodity prices.

First, briefly on hedges, the hedge tables are updated in the presentation, and we have had some nominal activity since last quarter.

Bigger picture, current strip prices for benchmark oil and natural gas are exceeding our internal plan for the remainder of 2016 and 2017.

As a reminder, we stated those plans are based in projected CapEx approximating projected EBITDAX.

So with the improved pricing, we're frequently asked the question of whether we will ramp up activity.

In principle, as just discussed, liquidity and coverage remain priorities.

As a result, it's unlikely we would increase activity, i.e.

CapEx, until our projected cash flow levels have risen to the projected CapEx level.

That translates to commodity prices in the $50s for oil and upper $2s for natural gas.

Practically speaking, we have all watched the sentiment on oil prices move full swing over the past two months.

We will be watching for real duration in the outlook before we make meaningful changes to our activity levels, which are shown on slide 10.

Now I'm going to turn the call over to Herb Vogel, who will provide more operations detail behind our solid first-quarter results.

Herb?

Thanks, Wade.

During the first quarter, our operations teams continue to drive production uptime and deliver on all key metrics, which flowed through to the numbers Wade just shared with you.

We executed to our plan in terms of delivering on production targets, and maintained tight but discipline on our CapEx spend for drilling and completions.

In fact, our operated properties delivered production above our expectations, and non-operated properties somewhat below expectations.

We delivered additional cost reductions relative to plan, largely through efficiency improvements and by taking advantage of further deflation in cost of services.

Again, this quarter, we were able to consistently deliver better wells at lower cost.

Today, I'm going to focus on three areas.

First, I will review highlights of our Permian program.

Second, I will review a few specific efficiency gains and other initiatives which have achieved lower cost across our other operations.

And third, I will talk briefly about progress reducing our deferring commitments to enable us to deploy capital to our highest return areas and maximize cash flows.

I am now on slide 11, which summarizes highlights of our Permian program this year.

Since the start of the year, we completed 9 wells at Sweetie Peck out of the 24 completions planned for the year, and have produced 6 of these wells for over a month now.

Of the six, four were completed in the Wolfcamp B and two were completed in the lower Spraberry.

I have highlighted several areas in the slide, but we will note in particular that we made significant progress geo-steering to optimal intervals.

These are the [faces] which have the properties that are favorable from two perspectives.

First, they tend to have high organic [properties] to enable rapid drilling penetration rates, and second, they have the mechanical properties conducive to initiating fractures during the stimulation process.

Fundamentally, we are designing our completions to increase the complexity of the factor system near wellbore, and to maximize the surface area of the reservoir contacted.

And slickwater and higher sand loading works well to enhance both initial productivity and ultimate recovery.

Turning to actual results, I am now on slide 12, which compares the average first-year production from two of our Wolfcamp B slickwater completions to the average of 17 of our earlier hybrid fluid systems completions.

The initial two slickwater completions from December 2014 averaged production of over 230,000 barrels equivalent per well, during their first year online, about a 30% gain over the previous completion design.

Just to give a frame of reference, slide 12 also compares production from our wells to those published by three other quality operators in the Midland basin.

We have been very pleased to see production from our Wolfcamp B wells exceeding the first-year production per lateral foot of most other operators in the Midland basin.

While our Wolfcamp B wells with longer production histories have performed significantly better with slickwater completions, and are also outperforming peers, turning to slide 13, our most recent Wolfcamp B wells completed in 2016 are even better, shown here over the first 60 days of production.

These are really great wells, with the latest two hitting over 1,600 Boe per day and significantly surpassing our expectations.

And I need to point out that the data shown in that slide, in slide 13, is all natural-flowing post-frac and before we've installed any artificial lift.

We initially flow back Wolfcamp B wells naturally and follow-up controlled choke management strategy as long as possible, and then install artificial lift later to maximize our return on capital.

Our lower Spraberry completions are also performing extremely well, as shown in slide 14, with our latest wells just completed this year tracking toward better performance than our first lower Spraberry well, which was completed in November 2014.

Clearly, these are early days, but we are encouraged by the results so far.

As we mentioned before, we did not deploy much capital in Sweetie Peck during 2015 while we deployed capital elsewhere to meet commitments.

During that period of lower activity, our Permian team looked really closely at every dimension of their drilling completion programs, and looked at how they could improve efficiencies and drive lower costs.

This year, as we started investing at Sweetie Peck again, they began to deliver on the optimizations that they identified during the activity hiatus.

On slide 15, you can see over a 35% improvement in the feet drilled per day since 2014.

Attention to detail here really matters, with geosteering to optimize our lateral landing zones paying dividends.

Drilling a 7,600 foot lateral took us an average of 11.9 days in 2014, 9.6 days in early 2015, and an average of 6.2 days so far this year.

So that is a massive improvement in drilling performance.

Then on slide 16, you can see the remarkable improvement in our completion efficiency that was also an outcome of the 2015 optimization review.

Our pumping efficiency improved from around 66% to 84% year to date, and a phenomenal 92% for the last five completions.

You might wonder, how did we achieve this?

It resulted from a very thorough step-by-step review of every minute of our pumping operations, coupled with the efficiencies of zipper fracking on three well pads, and working closely with our service providers.

The bottom line then, moving to slide 17, between our drilling and completion optimizations, we have seen a 53% reduction in drill, complete, and equip costs in this year's program, relative to 2014.

Per lateral foot drilled, that puts us at best in class in the basin, despite our pumping higher sand loading levels than peers.

And obviously, that results in better wells at lower cost.

If you look closely at the figure on the right, you'll see that DNC cost us about $5 million and the equip is about $0.3 million, if you are comparing to others.

In the first-quarter call, we showed a 2016 cost of $5.8 million for our standard Sweetie Peck lower Spraberry well designs.

That has since been reduced to $5.3 million, and yields the returns shown in slide 18 for our lower Spraberry wells.

This is what we call tier 1 performance in the Midland basin, achieving over 20% IRRs at $40 WTI and [$2.50] Henry Hub.

And yet we are not standing still in terms of drilling and completion optimizations.

We have defined technical limits in drilling, and are bent on safely driving our performance to that level.

And we see several opportunities to further optimize completion performance to either reduce costs or enhance production performance.

Given the confidence we have in the achievable returns at Sweetie Peck that are best in our portfolio at current commodity price levels, we just completed moving a rig up from the Eagle Ford to Sweetie Peck, and we will have two rigs running there for the remainder of the year.

That second rig just spud a new Sweetie Peck well, so we are well on our way to achieving this year's plan at Sweetie Peck of drilling 20 and completing 24 wells.

Turning now to slide 19 and our Bakken and Three Forks program in North Dakota, here again we have driven well costs down.

We're now able to drill and complete a Northern Divide County well for $3.9 million, with our optimized plug and perf design and 10,000 foot laterals.

We are executing to plan with five completions during the first quarter, two of which were in the Bakken and Southern Divide County, where we continue to work to expand the scope of our Bakken inventory, in addition to the Three Forks that we already had there.

Early days, but those wells are performing as expected.

I should also mention that we continue to make progress driving down our lease operating costs throughout our operations in North Dakota.

Turning now to the Eagle Ford, with lower commodity prices, we are running a reduced program relative to previous years.

This has enabled us to focus even more on optimizations, some of which I have highlighted in slide 20.

Through zipper fracking on multi-well pads and optimizing with our service providers, we are now able to pump over 200 frac stages per month with one frac spread.

This is almost double the number we pumped a year ago per spread.

As you can well imagine, there are significant CapEx benefits of only rigging up half the horsepower than we did a year ago, to get the same number frac stages away, and with similar sand loading levels.

This flows through to a bottom line drill and complete cost of $600 per lateral foot this year, versus $900 last year.

In fact, drill and complete costs for our last five upper Eagle Ford wells, which have an average of 7,300 foot laterals, was down to $3.9 million per well, and that translates to less than $540 D&C costs per lateral foot.

As Wade mentioned previously, given commodity prices over the past two quarters, we're sticking to our plan and haven't completed many wells in the Eagle Ford since October.

We completed 2 wells in the first quarter, 8 year to date, and plan to complete 40 total by year end.

We have had one rig running and plan to cease drilling in August.

This will partially draw down our [duc] inventory in the Eagle Ford.

After our pilot programs, all the conclusions we shared during last quarter's call still hold, especially since we haven't completed many wells since October.

Finally, we have worked with our midstream providers and reduced our volume commitments in the operated Eagle Ford, as we indicated in last quarter's call and showed in the latest 10-Q.

We have also been working with our lessors to defer our drilling commitments in the Eagle Ford.

We continue to make progress in this area, and that enables us to redeploy capital to where it makes the most sense.

Clearly, the lessors are aligned with us, and not driving us to drill up quality inventory during a low in the commodity price cycle.

Let me conclude this section by saying that we're very fortunate.

We're very fortunate to have a portfolio that enables us to optimize our capital allocation between three great assets.

Oil in the Permian in North Dakota and gas, NGLs and condensate in the Eagle Ford, and to continue to optimize performance at each.

As commodity prices move, we can be nimble in our allocation to maximize returns from our capital program.

We have the ability to continue to grow inventory in all three plays, given the stacked pay nature of our assets and what we've learned from the pilot and well tests we have invested in over the past couple of years.

These give us confidence in our ability to deliver the returns we seek from better wells and lower cost.

With that, let me turn it back to Jay.

Jay?

Thanks, Herb.

As I said earlier, just exceptional operational execution in the quarter.

In closing, I would like to note that our stock price has recovered somewhat from it's ridiculous lows prior to our last call.

And given the strength of that move, I suppose some may question whether we can continue to outperform in that way.

Let me point out some data to you that I think is particularly relevant to that question.

First, if you will look at slide 21, you will see a comparison of 23 peer companies, including ourselves.

At this point, there's only 1 company of those 23 which is projected to be below 4 times levered at year end 2016 that has not issued some form of dilutive equity since the beginning of 2015, and that is SM Energy.

It is hard to see this as anything other than a relative buyback of our stock at the low point in the cycle.

At SM, we can still do division, and we believe our discipline on this issue has preserved and will generate significant relative value for long-term SM shareholders.

In addition, the continuing improvements we discussed today in lowering costs; reducing commitments; improving efficiencies; making good wells, coupled with our differential exposure to improving NGL prices; will result in improving operating margins and enhanced debt adjusted per share growth in coming periods, which are clearly not baked into valuations of our Company at this point.

In short, we believe that there is plenty of room for continued share price out-performance.

At this point, we would be happy to take your questions.

(Operator Instructions)

Kyle Rhodes, RBC Capital Markets.

Hi, good morning guys.

It looks like well costs in the Eagle Ford and the Williston have been better than your expectations to start the year.

As you look at your current budget of $705 million, do you think there is downside to that budget or maybe upside to your activity levels?

And if there was upside to activity levels, where would we expect to see that?

Thanks, Kyle.

This is Herb.

Yes, you are right, we have reduced CapEx in our wells, and that could lead to some additional CapEx later in the year.

We're not planning to increase our activity level at this time.

I think Wade mentioned that in his remarks

Okay, so fair to say maybe there's some downside to that $705 million budget?

Could be.

Great.

And on the M&A front, nice bolt-on deal you did near Sweetie Peck acreage.

Anything color you can [comment] on deal and then just curious if there are more opportunities like that around your footprint there.

We talked about -- this is Jay.

We talked about these bolt-on deals a number of times.

I think there are additional opportunities.

Again, we are working with a number of operators around us who may own enough acreage to drill really long laterals.

And I think you can see from our performance that people can see that we are making great wells, and in that process there is opportunity for us to be able to work with others to put together this acreage.

We do think there's additional opportunity out there.

Great.

And then last one for me, any update you can give on your first middle Spraberry well over there?

This is Herb, Kyle.

We are completing that one now.

Okay, great.

Thanks.

Welles Fitzpatrick, Johnson Rice.

Hi guys, good morning, good quarter.

If cash flows and CapEx do equalize, would the Permian still get the first incremental dollars?

Or is broader basin diversification, particularly with your constructive NGL view, something that's important from a CapEx perspective in and of itself?

Welles, I think right now the incremental dollar goes to the Permian because the returns are highest, and that's just the way we run our business.

Okay, perfect, and then a follow up on the middle Spraberry.

I believe you guys were also doing some tighter, lower Spraberry tests.

Is there any update on that, or what is the timeframe we should be looking for on those?

Welles, no, we don't have any tighter well spacing in the lower Spraberry to report yet from our wells but later in the year we should have some.

Perfect, thanks so much.

Michael Hall, Heikkinen Energy Advisors.

Thanks, good morning.

Appreciate the time.

Curious on the well cost improvements, those are some substantial improvements, particularly down in the Eagle Ford.

Were there any changes in well design driving that, or is it really that pumping efficiency and drilling efficiency that's been the lion's share of the improvement?

Just curious how much you think is potentially sticky as we move out in the cycle, in terms of those well cost improvements.

Yes, Michael, the well cost improvements vary somewhat, and those are upper Eagle Ford wells, those are five.

So those are standard completion design with slight modifications on fluid volumes.

But in general, we are seeing the efficiencies coming through most of the drilling costs on our wells.

Obviously if we go further southeast, they are going to be deeper and those will cost a little bit more, and if we go shallower, up to the Northwest, it will be less.

But most of our program is concentrated in that area that we are in now.

Okay, that is helpful.

One follow-up on that, as I would just look at the $600 per foot versus the last year's $900 per foot, how much of that would you characterize as service cost pricing versus efficiency?

Michael, we have looked at that, because we're really looking at what our longer term sustainable costs are, and it varies by our region.

In the Eagle Ford, where we already had pad drilling and we are further along in our optimizations, there's a little bit less that's sustainable and more attributed to sector deflation.

If you go to the Permian, it's a much higher percentage that is sustainable with less that's attributed to sector deflation.

So our rule of thumb has been, it's basically between 25% and 45% sustainable reductions, with the Eagle Ford being at the lower end of that sustainable and Permian being at the high end of that.

And that's assuming you return to a $80-type world.

If you're talking about $60, obviously those are more sustainable.

Okay, great.

That's exactly what I was looking for.

And then two more.

One, in the Permian, I'm curious.

What sort of incremental LOE run rates do you see on the new activity, if you will, relative to the blended total that we have seen in the region?

I'm just trying to think through maybe how that LOE progresses over the course of 2016 as you bring on more volumes.

If that makes sense.

Yes Michael, so obviously when we are doing flowbacks, our LOE ticks up for a bit on the wells.

We don't get that much flowback water, but still, with a new program, you're going to see an uptick in LOE for water handling primarily.

The other costs wouldn't be that significant an increase.

But I can't tell you a percentage increase as a result of that, we don't really look at it that way.

Okay.

I can maybe follow up.

And then last one, can you just talk a little bit more about capital spending trends through the course of the year?

Fully understand that you are drawing down DUCs, and so there is some benefit from that.

But the spending level in the first quarter relative to that completion count seemed a bit elevated.

I am trying to think through how we get second half spending rates materially lower than the first half.

If you could talk a little bit more about that.

I think if you look at the chart of rig count, it's pretty clear how we get to lower spending rates.

You can track our completions by month and our rig count by month, and it's pretty easy to get to significantly lower capital spending levels.

All right, fair enough.

Thanks.

Matt Portillo, TPH.

Good morning, guys.

Good morning.

Just a quick question follow up question in regards to capital allocation decisions.

We've obviously seen some improvement on the forward curve in regard to natural gas, and you've highlighted a fairly constructive view on NGL prices.

Is there any color you can provide?

It's been a while since we've gotten the return metrics around your Eagle Ford assets.

Is there any color you could provide at what price level you would potentially be interested in reaccelerating Eagle Ford growth, either from a gas or NGL perspective, that would drive higher rates of return than your Permian and Bakken assets?

Just trying to put some context around that.

If you go back about a year to where gas prices were in that $2.80 range, our returns across the portfolio were very similar.

At that point in time you had, again, gas at $2.80 and oil in the -- I think oil was in the mid-$40s, and you saw fairly similar returns.

What you need in the Eagle Ford really is gas above 2 1/2, $2.50, to really be interested in picking up activity.

The NGL part by itself probably isn't going to drive more drilling activity.

What it does for us is it adds a lot of cash flow, and then we can deploy that cash flow in the best way possible.

Great, and as we look at the 2016 dynamic with oil in the mid to upper $40s and the gas market in the upper $2s, low $3s, it's starting to probably look fairly attractive on a rate of return basis versus the Permian?

We would expect to be drilling again on the Eagle Ford in 2017.

Perfect.

And just a second follow-up question around the Permian, running two rigs there today, can you talk about your ability to scale up the production over time?

How many rigs you think you could run on that asset it if there is any constraints in regards to midstream, or additional build that you need to do on the gathering side just to try to put some context around the ultimate production output that, that asset could potentially generate for you?

Yes, this is Herb.

Matt, I would say the key thing is, we could ramp up with sufficient notice.

So if we say we're going to ramp up in 6 months or 12 months, this team could get there and could increase the rig count.

We are not really looking at scenarios in detail of that sort, but if the commodity price environment allowed, I don't have any doubt the team there could ramp up.

Thank you very much, I appreciate it.

Gregg Brody, Bank of America.

Good morning, guys.

I was wondering if you could provide some additional color around the asset sale program.

Are you prepared to tell us which assets you thinking of putting on the market?

And you mentioned generally larger than your cash flow outspend, but any additional color would be helpful.

Yes, I would be happy to.

We're about to send out teasers on these assets anyway, so I will just summarize generally.

We are going to sell some assets in southeast New Mexico, some waterflood properties in southeast New Mexico that we've known for a considerable point in time.

Almost all PDP.

We're going to sell some assets in the Williston Basin.

Again, older PDP oil assets.

We're going to sell some PDP in the Powder River Basin that we own there and some in east Texas.

It's a scattering, I think, of things across the Company, largely PDP assets.

And I think we indicated in the first quarter, and that was through using the strips at the time, that we thought the PDP alone was worth $100 million or more, but that's the basis for our view that we will be able to more than fund our outspend with that.

We said it would be about 400,000 barrels of production in the fourth quarter.

In the fourth quarter, that's right.

That's from everything you've just listed?

Right, yes it's 400,000 -- our assumption is that we get these deals closed around October, and then we lose 400,000 barrels in the fourth quarter, and that is rolled into our guidance already.

Is that factored into your borrowing base?

Or would it be fair to say that you would decline by whatever that $100 million PDP was for credit?

Sure, at the time it sold it would -- well, the next predetermination of the borrowing base, it would come out, which would be next spring probably.

Okay.

And then in your amendment to the credit facility, you put some possibility to buy back bonds as well as raise second lien.

Could you just talk with us about how you're thinking about using those two tools today, considering where bond prices are and as you're looking at potentially mounting prices?

Sure.

The short answer is, where the bonds are trading, the returns are not near as good as drilling in the Permian, for sure.

So we are not pursuing anything at this point.

The idea was to set ourselves up, when those bonds are trading at such a discount or should that happen again, to be able to do something a lot larger than what we were able to do in the open market.

That's the reason for it.

As we mentioned, we were able to get some $46 million retired, but we were setting ourselves up to do more if it was compelling.

So it's fair to say it was more of a return on capital that you were thinking about and not necessarily a deleveraging target?

Yes, that's right.

And just one follow up, back on the asset sales.

Do think there will be any associated G&A savings with the value of the assets you're thinking about selling, or is that pretty minimal?

There will be some savings.

Most of those savings will be field costs, not necessarily G&A.

Do you have an idea of what that is?

Is it $5 million, $10 million?

No.

Again, the G&A number, I wouldn't say, is material enough to quote a number on.

Okay.

We are continuing to work cost structure issues, and we will continue to work our G&A and all our other cost structure in an appropriate way based on what we see our activity level being over the next few years.

I appreciate the time and color, guys.

Thank you.

Brad Carpenter, Cantor Fitzgerald.

Good morning everyone, and thanks for fielding my questions.

A quick follow-up on the asset sale process.

If you successfully monetize the PDP in the Powder, would that mean a complete basin-wide exit from the Powder for SM?

No, it's just a portion of the PDP in a particular area.

It's not at all an exit from the Powder River Basin.

Got you.

Okay, thanks.

And then moving down to the Eagle Ford, you talked about it last quarter and again this quarter.

How you successfully were able to defer some commitments and enable capital flexibility.

I don't know, in the Q&A you mentioned that you will likely get back to work in the Eagle Ford in 2017, But could you remind us what your drilling and completion commitments, if any, are for 2017 and 2018 in the Eagle Ford?

Yes.

So, first of all there's a marketing commitment, and then there's a leasehold commitment that we work with the lease owners there.

And you are aware we work on large ranches and have consolidation agreements for all of our leases that define the program.

So I would say, we are progressing at different times, and 2017 would be different than 2018 on what the drilling and completion commitments would be.

For this year we are at 0.7 rigs and 40 completions, and I would expect next year would be -- the commitment level would be at that level also.

2018, I can't speak to where that would be.

Fair enough, that's helpful.

Thanks for your time, everyone.

(Operator Instructions)

Amy Stepnowski, Hartford.

Hi, I just wanted to follow-up about your comments with regards to equity issuance and obviously, you have not done that like many of your peers.

You talked about needing low $50s and high $2s for low oil and gas prices.

We certainly have gotten a balance in the last month or so.

If we were to see a return to lower oil prices and lower gas prices that would likely drive more cash burn for you, is equity issuance off the table for you?

Or can you just give us a little bit more background around the way you think about that?

Obviously, you've got the ability to do second liens, so you could do exchanges to reduce debt.

But as we think about treatment of equity holders and bondholders and going forward how that is balanced, it would be helpful.

Sure.

I will say a few words and Jay can chime in if he wants.

We set the balance sheet up so we that we won't have to do that at the bottom of the cycle, and what you are talking about would be an extension of the bottom of the cycle.

We are very comfortable with our liquidity situation which I discussed earlier, and we also have a whole lot of breathing room now with respect to covenants, should prices continue to languish or languish further.

I would not anticipate at all issuing equity in that scenario.

Yes, I will make an additional comment.

I take no issue with people who issue equity for accretive acquisitions.

If there's an opportunity somewhere down the road for us to do something that made sense, I wouldn't rule that out.

But Wade is exactly right, we set up our balance sheet, we set up our borrowing arrangements with the bank, we had a lot of flexibility.

I don't see any reason in the near term at all, even in the lower for longer scenario, where we would need to issue equity.

You do that because you have to.

I understand that.

We just are not our in that position.

We managed our business well at the top part of the cycle, so at the bottom part of the cycle, we don't have to do that kind of thing.

So you would be more comfortable then seeing leverage tick up, even though obviously it wouldn't be out of compliance with your covenants.

But leverage could tick up, but you are comfortable that you could live through that without having to issue equity.

It is an interesting comment you just made.

To be very clear, our leverage can tick up, we will not be out of compliance with our covenants.

Exactly.

The four times covenant is gone, and we have plenty of room, as we talked about earlier, in our secured debt covenant and our interest coverage to run at higher leverage ratios for some period of time if we want.

The best way to delever the balance sheet is for the prices to go up, and that's going to happen over time.

In the meantime, we don't have any early maturities, and we are in no financial jeopardy as a Company.

So we don't have any need to issue equity.

The problem with companies -- all the companies in our business is we lose our minds of the top of our cycle and we lose heart at the bottom.

We do things at the bottom because the bankers really want you to, to issue equity and get liquidity.

We don't need to do that.

We have got a great relationship with our banks.

We had a credit line that is very available, $1 billion of liquidity.

We don't need to do that at the bottom.

So, end of story.

Okay, thank you.

Subash Chandra, Guggenheim Securities.

I don't know if he's there.

Did we lose him, Antoine?

We must have lost Subash there.

If your phone is on mute, can you please unmute?

Okay.

Michael Hall, Heikkinen Energy Advisors.

Thank you, appreciate the follow-up.

I just I had a couple more questions.

One was on NGL outlook.

You did mention that differentials expanded a bit in the quarter.

What's your view as to how that plays out through the rest of the year relative to the Belvieu [basket]?

Yes, Michael, I don't know that I have a view on how NGL differentials play out for the rest of the year.

In general I would say the NGL market, if you look at the markets, oil, gas, and NGLs, if you look at fundamentals of those markets, NGLs has the most constructive fundamental demand picture going forward of any of those commodities, in the way we look at it.

We've got, I think it's almost 1 million barrels a day of ethane crackers coming in to the Gulf Coast over the next few years.

And there's some real significant demand uptick on ethane, in particular, and the rest of those commodities.

So generally people, and it's not just us, there are a lot of experts out there who are looking at the market and saying, hey, this is a constructive picture.

And the point we're trying to make today is simply, look, we've got a lot of exposure to that and we are absolutely in a great position to benefit from it because we're close to Belvieu.

Quarter to quarter, differentials, I am no expert on that.

You can't predict them.

Let me pipe in on one thing on that, Michael.

Given where the frac spread is, the fractionation spread is, we have been rejecting about 3,300 barrels per day of ethane and if that moves positively, we could start to capture that ethane and sell it as ethane rather than as methane, and that would be a benefit.

So we are almost right at that point right now.

And we do it on a monthly election basis on one of our contracts, so we can play that and optimize as we go through the year.

Okay.

So that's maybe what's driving the quarter to quarter variability relative to the Belvieu basket, it's just ethane rejection and how that plays out.

Like you said, hard to forecast.

No, Michael, that's purely on our ability to respond.

We haven't been changing our operations.

Yes, our (multiple speakers) if you are talking about our pricing, we've been talking 80% a month Belvieu pricing is what we net back to the Eagle Ford typically.

We were a little bit lower last quarter.

Okay, but that lower level wasn't the function of --?

No, no we've been rejecting ethane for quite some time.

Okay, fair enough.

We can follow-up on that, but generally it's 80% of Mont Belvieu and you can see the Eagle Ford was about 80% of Mont Belvieu this quarter.

There was something in there from the Rockies that excused the total company this quarter.

So keep it at that 80% of Mont Belvieu for your own modeling.

It's going to be your best estimate.

Okay, that's helpful.

Thank you, Jennifer.

And then last on my end is just on the Permian, I will give it a shot.

You all said in the update, or the release I believe it was, that you are tracking above internal expectations.

I'm just curious what kind of internal EUR expectations you guys are running on that asset right now.

Mike, we don't do the EUR game.

We will show you our data versus other people's data; the only part of those curves that matter is the first 18 months to two years economically anyway.

And we will let other people speculate about what's going to happen five years from now on their EURs.

All right, figured it was worth a try.

Thank you.

Jacob Gomolinski, Morgan Stanley.

Hi, good morning.

Good morning.

Just a quick philosophical question, when you talk about meeting your internal rates at $40 for oil, but I think you mentioned in your prepared remarks increasing activity at $50 and high $2s for gas, could you just help balance those two things?

Basically, as we have talked about, we want to increase activity once we are within our cash flows and right now, we're still outspending cash flow by an amount -- our operating cash flow.

So on a going forward basis, who want to get cash flow equal to CapEx.

If we need those low $50s numbers in order to balance cash flows before we would start increasing activity.

Okay, thanks very much.

Thank you.

I am showing no further questions at this time.

I would now like to turn the call over to Mr. Jay Ottoson for any closing remarks.

Thank you very much for joining us today and have a great day.

Thank you.

Ladies and gentlemen, thank you for participating in today's conference.

This concludes the program.

You may all disconnect.

Everyone have a great day.