SM Energy Co (SM) 2011 Q2 法說會逐字稿

Good day, ladies and gentlemen.

And welcome to the second-quarter 2011 SM Energy Company earnings conference call.

My name is Cindy and I'll be your operator for today.

At this time all participants are in a listen-only mode.

Later, we'll conduct a question-and-answer session.

(Operator Instructions) As a reminder, this conference is being recorded for replay purposes.

I would now like to turn the conference over to your host for today, David Copeland, Senior Vice President and General Counsel.

Please proceed.

Thank you.

Good morning to all of you joining us by phone and online for SM Energy's second-quarter 2011 earnings conference call and operations update.

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

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

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

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

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

With that I'll turn it over to Tony.

Good morning, everyone, and thank you for joining us for the SM Energy call this morning.

Before turning the call over to Wade and Jay for their respective financial and operational reviews, I will cover some of the highlights from the last quarter.

I'll speak briefly about our quarterly results and comment on some of our key accomplishments during the quarter.

I'll then talk briefly about our outlook for 2012.

Our comments this morning will be referring to the presentation that was posted on our Company website last night.

I'm starting on slide 3 of the presentation at this time.

The second quarter was an outstanding quarter for SM Energy.

We averaged 437 million cubic feet equivalent per day of production for the quarter, which is a new quarterly record for the Company and above our second quarter guidance.

During the quarter we announced 2 separate Eagle Ford transactions.

We are disproportionately selling down our non-operated properties, giving us more control of our CapEx pace and spend which was a key objective of the selldown.

In addition to the non-op deal, we are selling attractive acreage in LaSalle and Dimmit Counties that is separated from our main acreage position.

Now that these transactions have been announced, and we have more clarity of what our remaining position in the play looks like, we can provide more detail of our plans for the rest of this year as well as preliminary plans for next year's capital spend and production outlook.

In 2011, we expect to have approximately 50% production growth year-over-year.

And in 2012, we are projected to have 35% to 40% growth, giving us average daily production of over 600 million cubic feet equivalent per day by late next year.

I think the additional color given to shareholders today will help paint the picture of significant growth potential for the Company over the coming years.

With that, I'll turn it over to Wade for his financial review.

Thank you, Tony.

As Tony touched on we had a very strong quarter and I'm going to start on slide 5 where I'll compare our results for the quarter versus our guidance.

We had record quarterly production averaging 437 million cubic feet equivalent per day which was above our guidance range of 396 to 429.

Composition of our production stream was also roughly in line with our guidance.

From a cost side we came in below guidance for all the key metrics.

With regard to production taxes, our reported 1% as a percent of prederivative revenue is significantly below our guidance of 7%.

Large driver of this difference is due to tax incentives that we were able to realize in our Eagle Ford program.

Non-cash interest expense was the only reported figure that came in above our guidance which was due to entering into a newly amended credit facility during the quarter and I'll touch on that later.

GAAP net income was $124.5 million or $1.86 per diluted share, and adjusted net income for the quarter was $61.1 million or $0.91 per share, a significant increase from our first-quarter results.

The increase in adjusted net income is mainly driven by increased production and higher commodity prices during the quarter.

Our operating cash flow for the period was $3.39 per diluted share, which is well in excess of Street consensus of $2.78 per share.

In our appendix we've included reconciliation for both adjusted net income and operating cash flow back to the related GAAP numbers.

In all, this slide points out how well our Company has done over the past quarter with production above guidance, lower cost on a per Mcfe basis and adjusted net income and cash flow that beats Street expectations.

With that I'll move on to slide 6 and talk about our current financial position.

Our debt to book capitalization ratio at the end of the second quarter was 32%.

And total debt to trailing 12 month EBITDAX was 0.86 times.

We have 2 pieces of long-term debt outstanding as of the end of the second quarter.

The first, our 3.5% convertible notes which can be put to us or called by us in 2012.

We are able to settle these notes in all cash, all equity or any combination in between.

Our current accounting treatment is to treat these as if we will net settle these notes, meaning we would settle the principal amount in cash and any remaining upside in equity.

Second piece of debt on the balance sheet is our 6.625% high yield notes which we issued at the beginning of this year.

Moving to the next slide, slide 7, I'll discuss our newly amended, long-term revolving credit facility.

Beginning of the second quarter, we entered into a new 5-year amended credit facility.

With more recent reserve figures and a more favorable lending environment, we were able to upsize both the borrowing base and the commitment amount to $1.3 billion, and $1 billion respectively.

At the end of the quarter, this facility remained undrawn.

In addition, we were in compliance with all financial covenants.

As a final note before I turn the call to Jay, I wanted to mention that in our appendix we've included an updated hedge position summary.

Detailed hedge positions will be included in our Form 10-Q, which we expect to file with the SEC later today.

With that I'll turn the call over to Jay for the operational update.

Thank you, Wade.

Good morning, everyone.

As Tony and Wade indicated, we had a busy quarter.

As you can see on slide 9, although we were infrastructure constrained in the Eagle Ford, and our production was negatively impacted by flooding in the Williston Basin, we were still able to grow equivalent production 10% quarter-over-quarter.

I will run through activity in each of our major plays, and as I do so, point out the key capital investment changes we're making for the remainder of the year.

I'll then summarize the 2011 capital changes and give you a preview of 2012, as well as a new production rate forecast for the remainder of this year and next.

I'm now moving to slide 10.

The Eagle Ford play is where we are investing the most capital and our recently announced transactions are driving the majority of our investment plan changes.

We entered 2011 planning to sell down a portion of our Eagle Ford Shale position.

We had a couple of scenarios we were considering that essentially resulted in the same amount of capital investment which was $500 million.

As Tony mentioned earlier, during the second quarter we announced the signing of 2 transaction agreements.

The first is a divestiture of our LaSalle County acreage to Talisman and Statoil for $225 million.

The second is the transfer of a 12.5% working interest in the Anadarko operated portion of the play to Mitsui in exchange for a carry of 90% of our drilling and completion costs in the non-operated acreage until $680 million has been extended for our benefit.

These 2 transactions will result in us receiving more value while giving up less acreage than we projected at the beginning of the year.

They also will close significantly later than we had expected.

As a result, we will invest more capital in 2011 and book more production, revenue and operating costs than we had originally guided.

We now expect that we will invest $795 million in total CapEx related to the Eagle Ford Shale play.

$315 million of that amount is attributable to the non-operated Eagle Ford, where we are assuming we will incur 9 months of capital spending at our pretransaction working interest of roughly 27%.

Post-closing, SM will have 46,000 net acres in the JV area.

Moving to slide 11, which covers our operated Eagle Ford assets, post-closing of the Talisman Statoil deal, we will have approximately 150,000 net operated acres that are essentially contiguous with the working interest of 100%.

We have 4 operated drilling rigs running in the play currently.

There have been a number of news stories written over the past several months regarding water availability for Eagle Ford well completions given the drought that is occurring in Texas.

Although this drought may impact some other operators, we purchased water rights in the Rio Grande River earlier so we are not dependent on subsurface sources of water for our development.

We're building water pipelines and facilities that will allow us to move this water around our acreage block, which will result in lower completion costs in the future.

We accelerated some of our planned activity on this water system into this year, and we believe that it will be almost entirely operational by year-end.

We are lowering our projection for the number of net wells we expect to drill in 2011 from 70 to 65.

We have delayed some rig activity due to the off-take limitations we have experienced, so we do not build a larger backlog of restricted wells.

I should note, however, that the strong well results we are seeing will still allow us to fill our late year pipeline commitments.

I'll elaborate more on both of these points in a moment.

We grew production sequentially in our operated Eagle Ford program by 6% quarter-after-quarter, a rate that would have been much higher had we not had offtake infrastructure constraints which limited our ability to fully produce our wells.

Slide 12 shows our current contracted wet gas take-away capacity through 2015.

The volumes depicted here are gross wet gas volumes.

You may remember that our last call we discussed an increased offtake deal with ETC, which provides us with approximately 80 million cubic feet a day of additional capacity starting in mid-2013.

Until then we have 2 agreements in place, one with Regency using enterprise capacity, and one with KM/Copano.

The KM/Copano pipe is expected to start service by September.

During the second quarter, our offtake was all flowing on the Regency enterprise system.

We he have been promised a maximum of 150 million cubic feet a day of gross wet capacity on the Regency enterprise system over time, but that capacity is dependent on a number of projects being done and they have been experiencing delays.

We anticipate that our capacity will be stepping up during the third quarter and in fact we have been at gross production rates of around 100 million standard cubic feet a day of wet gas over the last several weeks.

We currently expect to touch 120 million standard cubic feet a day sometime in August and then step up in increments to about 170 million standard cubic feet per day of wet gas by December.

On slide 13, we provide an illustration of how this gross wet gas capacity is likely to convert to a net equivalent reported production figure.

The blue line is the total of the contracted gross wet capacity that I just reviewed on the previous slide.

The flow diagram at the bottom lays out the assumptions we use which are based on our second quarter production figures.

As you can see, we currently see a roughly 20% uplift from gross gas production to net equivalent production.

The red line represents how that production will be reported on a net equivalent basis, accounting for gas shrink, processing and royalty.

Moving to slide 14.

I will address the performance of our wells in our Galvan Ranch area.

On the bottom of the slide there are production and flowing pressure versus time plots for 3 Galvan Ranch wells with production histories of around 1 year.

The plots are on a normal scale with the wet gas rate shown as red lines and the flowing tubing pressure shown as blue lines.

As you can see, even after a year of production, these wells are producing at constrained rates of around 4 million to 5 million standard cubic feet a day of wet gas at high tubing pressures.

The reason the rates bounce around so much over the year is because at various times we were more or less constrained due to our increasing well count and fluctuating transportation limits.

These wells are clearly capable of much higher rates if we could transport the production, but that will have to wait for additional capacity to be available.

I should note that these 3 wells have condensate yields varying from 13 barrels per million standard cubic feet of gas to about 30.

And all 3 wells have high NGL yields.

We have estimated the EURs of these 3 wells by several methods.

And our proved estimates are currently between 6.6 and 7.5 Bcfe.

Our expected case reserve figures for these particular wells are significantly higher, however, and we fully expect their proved reserve estimates to move up over time.

Now, these 3 wells were early delineation wells and were drilled at fairly wide spacing.

The Galvan 10H and 14H wells shown were drilled 1,250 feet apart, which, assuming a 5,000 to 6,000-foot lateral is roughly 160 acre spacing.

The ultimate reserves we will book for development wells in this area will be based on the production demonstrated by wells drilled at development spacing.

We currently have 4 spacing pilots in operation across our operated acreage at spacing down to 625 feet.

And Anadarko has an additional pilot just north of Galvan Ranch being drilled at 300-foot spacing.

We hope to have a better sense of the impact tighter development spacing might have on well economics and EURs later this year.

In the meantime, these results are certainly encouraging and provide support for my comments earlier about being able to fill our pipeline space without as many wells producing.

Before leaving the operated Eagle Ford, I should note that during the quarter we completed and announced an arrangement with our friends at Regency in which they will be providing us with midstream and gathering services in the field.

This arrangement allows us to focus our personnel resources and capital on the drilling and completion side of our business.

We still need to conclude some additional transportation arrangements to handle all our expected oil volumes, and we are making progress on those as well.

Moving to the outside operated Eagle Ford Shale program on slide 15, Anadarko continues to move forward aggressively and added additional rig count during the quarter.

At this time, we anticipate they will run 11 to 12 rigs in the play for the remainder of the year.

Our average net quarterly production in this program increased 30% quarter-after-quarter.

And we look forward to our continuing participation in Anadarko's success.

Slide 16 addresses our Bakken/Three Forks program.

The big story this quarter was clearly the flooding that occurred in North Dakota.

As the graph on slide 16 shows, our production in the program actually shrank slightly quarter-over-quarter.

Like other operators in the Williston Basin, our drilling and completion activity was impacted and we had to shut-in some production.

At the peak of the flooding, we had approximately 1,500 barrels of oil equivalent per day of net production shut-in.

As the flooding has receded, the amount of shut-in net production has shrunk to around 800 barrels of oil equivalent per day.

We expect most of this shut-in production due to the flooding to be back on-line early in the third quarter.

We are setting up a third drilling rig right now in the play.

However, due to the flood impact, we are behind schedule on our drilling program and we will likely fall 4 or 5 gross wells short of our planned number of 34 completions this year.

Our costs in the Bakken and Three Forks are also running higher than we budgeted due to both the larger size of the completions we're now pumping and general industry cost pressures.

Moving on to slide 17.

I'll address some of our other operations.

Our operated Haynesville program continued to see solid results in the Shelby Trough area of St.

Augustine County, Texas, during the second quarter.

The Ericsson 1H, in which we have 100% working interest, had a 7 day, initial production rate of 14.8 million standard cubic feet equivalent per day at an average flowing tubing pressure of 8,900 pounds.

The Cortes 1H, in which SM also has a 100% working interest, had a 7 day IP of 11.8 million standard cubic equivalent per day, with an average flowing tubing pressure of 8,700 pounds.

I should note that each of these wells holds not only Haynesville acreage but significant uphold potential including the middle Bossier.

We believe that the resource potential on our East Texas acreage, including both the Haynesville and Bossier intervals could be as much as 1 Tcfe.

At this point, based on the performance of our wells, we decided to retain our position in this play and are no longer pursuing a farm-down or joint venture.

We're planning to run a 1 rig program until that work is complete.

We estimate that it will take us until September of next year to finish drilling and completing the necessary wells.

Once we get our acreage to HBP status, we'll decide the best timing for future drilling.

In the Niobrara play, we drilled 3 more operated wells on our acreage south of the Silo Field in southeastern Wyoming during the quarter.

We've completed 1 of those wells, the Polaris 124H, where we operate the well with a 38% working interest.

The well had a 7 day initial production rate of approximately 950 barrels of oil equivalent per day.

Our acreage position in this area totals about 26,000 net acres.

Several analysts have noticed that we have also been applying for some well permits in the Powder River Basin.

We've been adding acreage there and now have roughly 63,000 net acres in the Powder which is prospective in several intervals including the Niobrara.

We plan to drill several exploratory tests in that area during the second half.

In total we now have roughly 89,000 net acres in eastern Wyoming that is prospective for the Niobrara.

I'm now on slide 18.

In the Granite Wash we operated 1 drilling rig in the second quarter.

We drilled several successful wells, including a successful test in the Cottage Grove interval, one of the shallower, oily washes.

The Ruth 4-60H, a 44% working interest Cottage Grove test in Wheeler County, Texas, had a 7 day average initial production rate of approximately 1,380 barrels of oil equivalent per day.

Our plan is to continue focusing our efforts on oily wash opportunities with 2 rigs running in the play for the remainder of this year.

In the Permian, we have now drilled 8, 20-acre down spaced wells in the Sweetie Peck Field.

Early indications based on rates so far are positive, but it will be some time before we can reach a conclusion on this Wolfcamp program and can estimate a location count for the rest of the 20 acres.

In the meantime, we are moving the rig north to drill test wells on a roughly 87,000 net acre block of acreage we have accumulated in Borden, Garza and Lynn Counties.

The area is prospective in the Mississippian section as well as the Wolfcamp Shale and we will be testing both intervals in the second half.

Slide 19 then shows our revised capital investment plan for 2011.

I discussed the changes in the Eagle Ford drilling program earlier.

Again, our assumption is that we are paying our own way in the non-op activity at our pre-transaction working interest through the third quarter.

Note that though our arrangement with Mitsui is for a 90% carry in non-op drilling related activity after closing, we are being reimbursed for some back cost through an additional 10% carry.

The other significant change in the drilling program relates to our operated Haynesville Shale program where, as I mentioned, we have decided to continue drilling in order to hold our acreage.

In the non-drilling capital, most of the cost increase relates to our acceleration of water handling facilities construction in the Eagle Ford.

In summary, we believe our capital investment in 2011 will total about $1.55 billion.

Moving to slide 20.

Let me lay out early capital guidance for 2012.

Our major assumptions here are that we will be participating in the APC JV area at about a 14.5% working interest, but our spending will be 100% carried for the year, other than a small amount of net cost for midstream facilities.

We also are assuming we will complete HBP-ing our Haynesville acreage in 2012.

We have quite a bit of flexibility in the rest of our spending, allowing us to focus our activity on the portions of our inventory with the highest returns.

We plan to increase activity in the operated Eagle Ford, the Bakken/Three Forks and the Granite Wash.

We will be working over the next several months to determine where exactly we will invest our other operated capital.

Our testing planned in the Niobrara and the Permian later this year will certainly influence this decision.

Our total projected investment range for 2012 is $1.4 billion to $1.5 billion.

Moving to our production forecast, slide 21 shows our current forecasted projections for 2011 and 2012 production.

As you can see, our increased capital investment program and the projected investment by others on our behalf has and will continue to result in significant production growth.

With that I am going to turn the discussion back over to Wade so that he can discuss our projected cash flows and financing for our planned investment program.

Thank you, Jay.

So slide 22, we're providing an estimate of what we expect our funding needs to be in 2011 and 2012.

Top line of the table shows the capital expenditure forecast that Jay just reviewed, the $1.550 billion this year and $1.4 billion to $1.5 billion in 2012.

The next line is our current estimate of what our operating cash flow will be in those respective periods.

I should caveat that this operating cash flow estimate by saying that it assumes current strip pricing and can change significantly as commodity prices move.

Below the initial GAAP figures, we have listed out the divestitures that we have entered into during the year.

As you can see, a large part of our 2011 funding gap is addressed through this divestiture activity with the remaining amount more than covered by the $350 million of high yield notes issued earlier this year.

In 2012, we expect to see a similar manageable funding gap.

We have $1.3 billion undrawn borrowing base that we can tap into as needed.

For 2013, we expect to see our capital program within our operating cash flow while generating double-digit growth.

You might recall that this has been our stated goal during SM's transformation over the past few years.

In summary, we feel we are sufficiently capitalized to fund our capital program in the foreseeable future.

With that, I'll hand the call back to Tony for his closing remarks.

Thanks, Wade.

Thank you, Jay.

As you can tell from our financial and operational updates, this has been a very high activity quarter with record production and over $1 billion in funding transactions.

We have been able to get through our divestiture processes and provide our shareholders with more detail and clarity to our future plans and growth potential.

We look to increase production by nearly 50% year-over-year in 2011, which is a testament to the strong drilling portfolio that we have now built.

In 2012, we look to build upon that growth and get SM Energy's production to over 200 Bcf equivalent for the year.

While the drilling inventory we now have is robust, we still keep an active exploration program where we continue to test new geologic formations.

We have had encouraging results in both our Niobrara shale in eastern Wyoming as well as the Cottage Grove in the Anadarko Basin of northeastern Texas.

From a capital standpoint, we have been able to close the majority of our current year funding gap through the various divestitures that we have entered into so far this year.

While these proceeds will help shrink the gap, we will be able to use our strong balance sheet to fund the projected gap for 2011 and 2012.

With an undrawn credit revolver at the end of the second quarter, we believe, as Wade mentioned, that we are sufficiently capitalized to fund our projected capital programs.

In all, SM Energy is poised to grow significantly over the next 2 years with its extensive drilling inventory and strong balance sheet.

And, I might add, with our expanding project slate, we expect to deliver continued growth and returns for our shareholders well into the future.

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

(Operator Instructions) Our first question comes from the line of Mike Scialla from Stifel Nicolaus.

Please proceed.

Good morning, guys.

Nice numbers.

You gave some impressive guidance on growth for 2012.

Any idea on what the production mix might look like for that year?

Mike, this is Javan.

I think you can expect that our gas percentage will fall some, maybe 2% or 3%.

As long as we continue to drill in the Haynesville, the gas numbers are going to be -- it's going to be pretty sticky.

They're big wells and we're obviously in it 100%, so it keeps our gas percentage around where it is.

But they will fall some over the next year.

Mike, this is Tony.

I would say if you're thinking about the split, it's probably 57% gas, 43% liquids, and as Jay mentioned, that would be trending down slightly.

Okay.

And the three wells that you showed in your slide presentation in Galvan Ranch, are those intended to be representative of the whole area or why did you pick those?

Are those the three best or just the ones you have the most history on?

Can you talk about that at all?

Yes, they are the ones that we have the most history on.

As you look at those, you'll see they've been on for almost a year, all three of them.

The other wells we're drilling in the area are very similar but we don't have as much production history.

Great.

Okay.

And the tax break you received, production tax break you received for the quarter, how long do you expect that to last?

Well, the reason you see the number lower in the second quarter is because we were able to get comfortable that we are achieving that break.

So there was some catch-up in the second quarter.

Going forward, we believe that we'll be able to achieve it and that's reflected in our guidance.

Okay.

And then last one from me, I just want to touch on the Niobrara a little bit.

Can you talk about your decision to move into the Powder and how you would compare that acreage with the acreage that you have in the DJ?

Well, the Powder portion of the Niobrara -- this is Javan again -- is very different.

It's quite a bit deeper.

It's more of a basis centered kind of accumulation, higher pressured, over pressured, in fact, we expect.

And I think it's probably more of a bottle of oil type reservoir, as opposed to the fairly low GUR production we produced in southeastern Wyoming.

It's very, very different.

There have been some good wells drilled.

There's a number of additional wells being drilled.

There's also a number of other targets in that area in other intervals other than the Niobrara which we think are going to have some horizontal potential as well.

We've held acreage in the Powder for quite some time and we have added some over the last year.

We just haven't really talked about it but we think the position we put together now is pretty strong.

Does some of that position you have, does that include some of your old legacy acreage or is this all new acreage?

It's not all new acreage, no.

We've had acreage there for quite some time, a lot of which in fact is HVP.

Thank you.

Our next question comes from the line of Nick Pope from Dahlman Rose.

Please proceed.

Good morning, guys.

I was trying to reconcile the production beat here today.

Looks like kind of the bigger areas were fairly in line.

Could you provide production numbers for the Haynesville and mid-Con, maybe Permian for the quarter?

For the quarter, it will be posted in the Q, Nick.

Okay.

Then just kind of moving on, I know you guys have talked historically about the Eagle Ford, how you kind of view the economics I guess across the whole position from north to south as fairly similar economics, just changing profiles and volumes and components.

I was wondering like with that Galvan Ranch, I guess some of the, looks like, improving results there in Galvan Ranch, are you seeing like sweet spots emerging or do you still think like the entire position is -- you're seeing fairly consistent returns on what you're drilling?

I would have to say that I think the Galvan Ranch area is a sweet spot and I think that's demonstrated not only by our drilling but by Anadarko's drilling as well.

With that said, we've had good, solid results on a lot of our other wells in other areas as well and we think a very high percentage of this acreage is going to drill out.

As you get farther north on our other acreage to the west, you do get lower EURs, but you have higher condensate yields.

I would say I think the Galvan wells have outstanding economics.

The other areas may not be as high but again I think it's going to drill out.

Okay.

Sounds great.

And I guess just with the Bakken, the constraints I guess that you talked about during the quarter, like how much production do you think actually was down relative to where you would have expected during the quarter, just because of the weather, weather down time versus slowed completions during the quarter?

Well, we haven't added up on a cumulative basis.

As we mentioned at a peak we were down about 1,500 barrels a day net and we're still down about 800.

So if you average those two numbers, you could probably a figure 1,000 to 1,200 barrels a day were shut in for most of the quarter.

We had some periods where it was, again, toward the high end of that range and now it's lower.

I would say that a lot of our delays -- we had a couple of incidents that delayed our drilling.

Obviously a lot of you know we had a well control incident on the James well right toward the end of the first quarter.

We took about a month off frac-ing until we really felt comfortable getting back in the field and going after that.

By that time basically the flooding had started, so we were significantly delayed in our completion activity which as a result we'll be four or five wells short by year end.

For us it was a combination of the flooding and then of course delays in our completion activity which impacted our production there.

I think in fact if you look at our performance for the quarter and consider the fact that we really didn't get much of a break on our transportation issues in the Eagle Ford and we had massive flooding in the Bakken and you look at our growth, it really is pretty impressive.

The engines of our growth, where we're investing significant amounts of money in our operated program, really didn't come up that much during the quarter and yet we're still able to outperform our guidance.

I think once those two things kick in and we really start to ramp rates in those areas, it should be pretty impressive.

Absolutely.

I think it is.

And then just like one last thing, just to clean up, just the timing of the Eagle Ford deals, is it just you're expecting the Mitsui deal to close at the end of the third quarter?

Is that the same timing for the LaSalle County position as well that you're expecting right now?

Our assumption is that both of them will close before the end of the third quarter.

Okay.

That's all I had.

Great job, guys, thanks.

Next question comes from the line of Jeb Bachmann from Howard Weil.

Please proceed.

Good morning, guys.

Had a few questions, Jay.

First, on the CapEx, just wondering on the increase for this year how much of that was related to cost inflation?

Well, there's $20 million there that's specifically called out on the Bakken piece.

I think you could probably assume about $30 million of Cap cost increase on our Eagle Ford, on the Eagle Ford side.

So maybe $50 million total of that is cost increases.

Obviously, we absorbed some cost increases in some of the other areas as well, but those are the big headline numbers.

Obviously those are where we're spending the most money.

I would say about $50 million.

Switching over to the Haynesville, can you talk about where -- have you seen any kind of relief in service costs there or if rig rates are holding up because of the demand in the Eagle Ford?

You know, Jeb, we really haven't seen a lot of cost reductions there yet.

It's a little disappointing.

I think it's a consequence of the 180-some rigs that are running in the Eagle Ford now.

But we are moving to a one rig program.

We have started -- we've done a lot of things to try to cut the cost of our completions.

Our costs are coming down, not necessarily because the vendors are helping us, but because we're just getting more efficient.

We're drilling faster.

We're starting to use some white sand in our completions in the Haynesville which reduces our completion costs.

So we're using white sand and premium resin coated, generally.

So we're doing things to try to get our costs down but really haven't seen a lot on the vendor side yet.

I would say I think fracs are becoming easier to get from a schedule standpoint, which I would hope is a sign of the times, sign of good things.

I really haven't got a lot of price reduction yet on the vendor side.

And up in the Granite Wash, what was the cost on that Cottage Grove well, assuming that's cheaper than some of the other ones you've drilled so far?

I don't think I have that exact -- I know the number was around seven, but I don't know the exact number, Jeb.

Some of these wells -- I can tell you that the deeper washes, the Marmatons, are running 8s, 8.5.

A trouble-free well is probably in the 7s.

Shallower washes should be in the 6s, but some of these early wells are a little more expensive; we're doing a little bit of science.

Okay.

Last one from me.

Just to clarify.

I think you mentioned the amount of acreage exposure you had in the Permian with the Mississippian and Wolfcamp.

Can you repeat that, please?

I think we just quoted 87,000 acres.

87.

That's the upside.

Then we have 13,000 or so at Sweetie Peck and another six or so at Halff East.

We let a little bit of the Treadway acreage, the Northern acreage go just on some acreage decisions we needed to make.

We had about 100,000; now we're down to 87,000.

We feel good about that.

Great quarter, guys.

Thank you.

Our next question comes from the line of Welles Fitzpatrick from Johnson Rice.

Please proceed.

Good morning, guys.

On that 63,000 net acres in the Powder River Basin, do you guys plan any near-term tests in the Turner?

Well, I'm not aware of any near-term tests in the Turner.

We've got three Niobrara tests planned this fall.

We'll be participating in some other things that people are doing.

I'm not aware of any near-term Turner tests.

And of that legacy acreage, how much of it is HVP-ed?

I don't know that number off the top of my head, Welles.

We can find that out for you.

Okay.

And then you guys also mentioned that you were kind of getting excited about the Bossier.

Do you have any near-term plans to test that horizontally or maybe the Cotton Valley on the Haynesville acreage?

We are going to drill a Bossier test.

I believe it will be either late this year, early next year.

We had a well that we completed in the Haynesville vertically to hold some acreage very early on.

And in that particular block, a Bossier well will hold the Haynesville.

So we're planning on recompleting that well into the Bossier section, taking it lateral, but that will be probably, if not late this year, early next year.

Perfect.

And in regards to the spacing, I think you guys said a better understanding later this year.

Is that a third quarter or fourth quarter event or just up in the air for now?

Well, I have a list I think of about 20 different pilots between us and Anadarko that we're planning to drill on different spacing numbers.

And I think it varies wide -- it's going to vary a lot depending on where you are in the acreage.

I think, frankly, the lower productivity acreage will probably get spaced to a lower level than the higher productivity acreage so it's kind of an interesting issue.

Of course, I mentioned on the call that Anadarko's running a 300-foot spacing test just north of us there at Galvan.

We're going to have a wide range of data to look at it.

It will take us a while to understand it.

The important thing to know is that EUR is not an economic metric.

What really drives the spacing decision is going to be how much production do we get out of these wells in the first 18 months to 2 years.

It's not going to be forever, us making this decision.

We're going to look at the economics of -- essentially we look at IPs and early time production data and make a choice on economics.

The reason I'm cautious about all these EUR numbers is because I think you've got to be careful not to throw an EUR number out there that's based on 1,250-foot spacing and then find out when you drill it to 300 feet that that EUR is lower.

The economics may be fine.

But if everybody's out there and they put that big EUR number into a model at reduced spacing, you could end up with some significant overestimating reserves.

So we're very comfortable with where we're at.

We think we'll have a lot of information by year end that's going to lead us to a development spacing.

And a lot of other people are obviously supporting that with their own -- with other data.

So I think year end is a reasonable time frame to have a sense of it.

The next three rigs we're bringing in are pad drilling rigs.

We're going to be drilling multiple wells off a pad.

We'll be holding all those wells and frac-ing them all at once.

I think by year end, we're going to be in more of a development mode.

Will we know the ultimate answer on all the acreage?

No.

But we'll have a real good sense I think as we come into 2012.

Okay.

Perfect.

That's all I have.

Thanks, guys.

Our next question comes from the line of Brian Lively from Tudor Pickering Holt.

Please proceed.

Good morning.

Thanks for all the additional details on the quarter.

It was really helpful.

Looking at the three wells that you guys put out for Galvan Ranch, just a clarification on the proved EUR estimate.

Is that post processing or is that just the wet gas volumes?

That's a three stream number.

Okay.

And on that same slide, the tubing pressures I've kind of focused on being pretty high for a long time.

Do you have a sense of what the drawdown is on those completions now or some ballpark range?

In terms of a bottom hole pressure?

Yes, are they flowing at 1,000 pounds?

500 pounds?

Do you have a sense how hard you're pulling the formation itself?

Brian, I don't have that number off the top of my head.

I can say, it's probably not -- it's not a lot of drawdown.

These are -- we're not pulling these wells very hard.

The choke settings are way low.

I don't know the exact bottom hole numbers.

That was really the point I was trying to get to is that you mentioned on the call that these wells could flow at higher rates.

Do you have a sense of where they could flow at under a 2,000 or a 1,000-pound flowing tubing pressure?

Let me give you some -- this is sort of an anecdotal piece of data.

I don't have the exact data on those three wells.

But I can tell you that I saw a summary the other day on the Galvan area, and right now we're producing about 60 million a day of gross wet gas out of that area.

If we could get those wells to line pressure, they would make about 100 million a day.

So there's about a 40% up -- if you can get to something like an 80, 100-pound line pressure.

I'd admit, that's a lot lower than where we are right now.

So there's a lot of shut-in capacity.

I don't have the exact bottom hole pressures for you but there's a lot of opportunity here as we get additional capacity to open the chokes and be able to work.

We're putting a 16-inch gas trunk line, what we call a spine-in, all the way through our acreage, all the way from the tip of Galvan all the way up through Briscoe.

And that will be complete in October, so we'll be able to wheel gas to both ends of our gas offtake, offtake capacity.

Kinder Morgan should be there shortly, and we should have quite a bit more capacity available as we move into September.

So I think we'll be able to crank up rate pretty quickly here.

Perfect.

That really leads well into my next question.

Looking at the 2012 guidance, I assume that's the guidance derived from your expectations on your Eagle Ford type curves plus the contract at take-away.

I'm just wondering if that 35% to 40% growth includes any intermittent or spot volumes.

That's a great question.

We looked at it several different ways.

We looked at it assuming that we couldn't get anything more than our contracted capacity; and then we ran a more unconstrained case, part of an optimum case, where we actually assume we could pick up some interruptible.

When we look at that with respect to the capital spend on the well side, and we take that incremental capital and invest it in other opportunities that we have, the rates you get are almost the same.

So we may or may not, depending on whether we can get interruptible capacity or not beyond our current firm capacity, I don't think the overall rate for the Company changes that much.

There is going to be an opportunity, I think, for us to go out and potentially secure more capacity.

But we haven't really baked that in, necessarily, to the guidance.

If we did bake it in, again, that's why we've given a range of capital and a range of volumes.

But we can certainly make more gas than we're contracted to ship right now.

Brian, I think that's a good example of having a diversified portfolio where we can reallocate the capital where we get the best economics, depending on market conditions, yet still reach what we think will be that 35% to 40% growth number.

So if you are able to get the interruptible volumes, you're saying that the 35% to 40% corporate-wide growth estimate wouldn't change significantly?

Is that what you're saying?

What we're saying is that essentially you can -- it depends on the dollars, right.

You can get to that 35% or 40% in a couple different ways across that capital range.

Our base assumption is that we're going to be able to produce to our capacity.

If we can go beyond that capacity, we could potentially move the money around and do it that way.

We'll do it based on whatever way is the most capital efficient.

That makes sense.

Just kind of the last question I have is really on the other initiatives.

What other initiatives are you guys pursuing to expand the midstream and infrastructure side of the Eagle Ford, post the ETC stuff that you guys have already released?

Well, we're working on oil transportation deals mostly, Brian.

We have several deals that we're negotiating.

We need to get those in place probably for sometime late 2012-13.

Right now we're still trucking all our oil.

Over the long haul, that's not sustainable.

We do think as we continue to firm-up our production forecast, that we need to look at late 2012-13 again with respect to should we take some additional gas handling capacity, assuming it's available, and maybe even go firm on some of that.

So this is just going to be an ongoing brick-by-brick addition of infrastructure.

As we get more and more comfortable with our production forecast and spacing, we'll continue to add commitments.

You've got to remember, every one of those things we do has a commitment associated with it as well.

We're going to do it in a balanced way.

As Tony mentioned, the great thing is we have other portfolio that has great economics as well.

So we can balance the type of commitments we need to make a little bit, knowing that we have some place else to go with the capital that also has a very strong economics.

Thank you.

Our next question comes from the line of Scott Hanold from RBC.

Please proceed.

Good morning, guys.

Just so I'm clear, and you may have said it or may not have, but I'll just ask the question anyway.

If you look at your Eagle Ford Shale production, what are you running at approximately right now on an equivalent basis and what do you think it could be if you didn't have any constraints in place?

This last week we were making 100 million a day, gross wet production.

So that's gross and wet gas.

If you follow the slide, I forget which slide number it is right now in there, it's about a 20% uplift between gross wet to net Mcfe equivalent.

So that would say that right now we're producing about 120 million a day equivalent net production from the operated Eagle Ford.

You've got to add the non-op to that.

As we go forward, what I said in the call is we think we'll touch 120 million on a gross wet basis sometime in August.

We'll be somewhere around 170 million by year end.

You can essentially take both those numbers, multiply them by 1.2 to get to a net Mcfe kind of a number.

By the time you get into next year, we should be in the 200 million, 220 million capacity range.

Again, we're not counting necessarily on having all that on day one, but over time we certainly think that will be the ballpark of where we'll be in the first half.

Okay.

So again, gross wet times 1.2 is a pretty easy number to get to our net.

Okay.

Appreciate it, that clarifies it for me.

Real quickly on the Permian, did you all say that the stuff in Borden, Garza and Lynn Counties, did you just picked that up recently or is that stuff you all had before?

Actually we've had the acreage for quite some time.

We've been drilling some Mississippian exploration wells and we've been playing around with the concept of drilling the Wolfcamp Shale and I think we're moving in that direction right now.

So some of the wells that you'll test, I think you said later this year, will they be horizontal wells?

Yes, in the Mississippian we drilled some verticals and some horizontals.

The Wolfcamp Shale wells will all be horizontals if we drill them.

Anything to say about some of the industry activity around you guys?

There's a lot of leasing out there, not a lot of drilling yet.

Would you be a buyer of incremental leases?

Depends on what they cost.

And where they are.

(laughter) There's been some big players out they, Scott, that have been picking up large blocks of acreage, but like Jay said, it's mostly leasing, not a lot of drilling just yet.

Understood.

Thanks, guys.

Next question comes from the line of David Tameron from Wells Fargo.

Please proceed.

Good morning.

Congrats on a great quarter.

And for getting the Eagle Ford deal done.

Couple quick questions.

The carry portion of this, I'm kind of thinking about 300 next year, maybe 100 for the remainder of this year.

Maybe a little less than 100.

Is that in the right ballpark?

I think it's about -- it should be more like 150 this year, I think.

And then the 300 for next year seems about right.

That's in the ballpark, David.

Okay.

For Anadarko, you said they're going to run 12, you as soon 12 rigs, through the end of this year.

Did you keep that flat for your '12 assumption or can you give us any color there?

Our '12 assumption is they'll run 12 rigs.

That 150 I told you may be a little too high.

It may be more like 100 -- it should be about 50 million a month.

We're double checking that number.

Okay.

And last question.

Chesapeake's filed a trust out there in the Granite Wash.

Do you guys have -- I know you have various working interest, small working interest throughout the basin with them.

Are you aware of any portion of your acreage that's getting rolled into this trust?

No, David, I'm not.

Okay.

That's all I've got.

Thanks.

Our next question comes from the line of Subash Chandra from Jefferies.

Please proceed.

Question for next year operated Eagle Ford.

Do you have a range of maybe how many wells you might have to put in backlog, pending capacity improvements?

And perhaps if that number gets somewhat large, is it possible that you might just save a few bucks and slow down the program a little bit and allow for the capacity to play catch-up?

Well, what we put in the program is 95 wells, which is what we think we can drill to keep up with our capacity.

Clearly, if for some reason or another the capacity doesn't materialize, we would have to consider that; and we would also be out looking for interruptible on other pipes.

Our current plan is to drill and complete 95 wells.

We think that's basically a balance with our capacity, maybe a little more, frankly, than our total capacity by year end.

Okay.

So there will be no -- on those 95 wells, you don't expect any material backlog?

We certainly hope not.

And is the CapEx that you have in other categories, I would as soon none of that's in your production guidance?

We don't include anything in our production guidance for exploration.

We do include some volumes for the things that are in other operations.

Okay.

How much are the Haynesville wells costing now?

Right at $11 million.

And could you sort of just -- last question here -- explain in more detail the sequential decline in lifting costs, how much you would attribute that to the asset sales of high cost properties, how much of that might be just a surge in low cost Haynesville production or how much could be just a surge in Eagle Ford or whatever?

Don't want to put any words in your mouth.

Well, there's a number of factors that are impacting LOE.

We had a long discussion of this this last quarter.

Part of it certainly is bringing on a whole bunch of low cost production.

Part of it was that our Rockies numbers ran really low in the quarter simply because we could not get out to wells.

Other than shutting them in, we couldn't get out to maintain things, so there were a lot of workovers that we didn't do.

WOE is in that number as well.

We have consistently, as much as we try, we have consistently overestimated the rate of growth of lease operating costs.

And a lot of that I think is just we've been maybe a little too conservative about our views of the economy in general and the fact that we thought labor costs would start stepping up in steel and other factors that factor in.

We've just been somewhat conservative and we just think that we've been under-running our LOE on a pretty consistent basis.

We keep trying to get it more in line.

It's a little tough when you're growing as fast as we are anyway, but I think we've probably just been a little too conservative on some of that.

All that helps.

Thank you.

Our next question comes from the line of Andy Coleman from Raymond James.

Please proceed.

Thanks a lot.

Had a question for you about looking at 2012, this credit facility, you had about $300 million there roughly with the 3.5 notes and then about another couple hundred million from the CapEx, I guess, needs here in the short term.

I'd as soon you're going to get some bump in your credit facility next year because of the extra reserve bookings, but would that potentially lead you to either sell some more assets or slow down drilling elsewhere to keep less than half that facility drawn?

Yes, Andy, that's a fair question.

I would not anticipate us getting to that point.

I think you just said it very well.

I expect the borrowing base to continue to increase with the reserves increasing, so that's first of all.

And there will be some draw in that facility most likely next year, but I wouldn't anticipate us getting to a point where we think we need to do any further divestitures.

Okay.

Good.

The one question on the income statement, did you guys have any capitalized interest for the quarter?

We certainly did.

I don't have that number close by.

I'll check with Brian afterwards.

We'll get it to you.

Our next question comes from the line of Joe Allman from JPMorgan.

Please proceed.

Thank you.

Good morning, everybody.

Jay, how many Haynesville wells or sections do you need to drill to hold the acreage?

We have eight more wells to drill after the two we're on right now.

Okay.

That's helpful.

And then back to the Eagle Ford.

In your slides you said next year you expect 300 non-operated wells.

What's that number for 2011?

Great question.

It's probably going to be around --

Joe, this is Brent.

I think we said early on in the year that it was going to be 200.

That was obviously at a lower rig count.

Rig count's been moving up.

I would say it's 12 or 250, probably would be a good ballpark.

For next year we're just basically doing it off of a rig count, kind of a daily days-to-drill type number.

That's not based on anything Anadarko's given us, I should be clear about that.

That's just an estimate based on how many days we think it takes them to drill and a 12 rig count.

I do not have a schedule from them on what they plan to do next year.

Got you.

Okay.

That's helpful.

Over the DJ Basin, I think what you've got, what, 26,000 net acres there in the DJ?

That's right.

How many Niobrara wells have you drilled so far and how much of that acreage do you think you've proved up based on your results?

We drilled five.

The first one was very successful.

Second one was not so.

It was kind of an edgy well.

The third one I think we would say at this point was very successful.

We're completing two more.

How much have we proved up?

You know, I guess I -- I don't want to come across as too conservative.

My view, until we get these five wells complete and we have our test program pretty much done, I'm not going to throw up a great big flag and say we've won here.

I don't think we've proven a lot yet.

Certainly, we proved the wells we drilled, but I think we need to get four or five wells drilled in this thing and get some real results before we declare victory.

Our intent is that assuming these wells go well, that we'll have a single rig program running all year here next year.

That's sorts of that other operated capital that we talked about.

But really, there's a lot of variability from what we've seen in the well results.

We think we have a strong geologic concept of why these wells produce the way they produce.

But it is a very unique area.

The reservoir is under pressured as opposed to the Powder where it's over pressured.

We don't know if that's just a result of being near the Silo Field or if that's just the way it is, kind of on the edge of the basin there.

But I think we're doing some interesting things with our completions to try to make sure that we get a productive well.

A lot of people are doing -- there are people trying slick water.

There's people trying energized fracs.

There's people doing gel jobs.

I think there's a little bit of a mix there.

I think once we get through these five wells, we'll have a pretty good idea of what the risks are, what the range of outcomes are and can come up with a mean expected well that would then drive a development decision.

This is Tony.

I would say at this point that the testing appears to be following our modeling, so I mean, we're cautiously optimistic, like Jay says.

So we'll complete the testing and then determine the development opportunities after that.

That's helpful.

Just lastly, in terms of the Eagle Ford sales, how much less acreage did you sell than what you had planned?

At one point in time we said we could sell up to 30% of our position, which I believe was about 75,000 acres.

We actually sold right at --

39, plus 15.

About 55.

54, yes.

54 or 55.

Okay.

That's helpful.

All right.

Thank you.

At this time, I would like to turn the conference back to Tony for closing remarks.

Thank you all for joining the SM Energy call this morning.

This is an exciting time for our Company as we see the transformation really kick in and we continue to see significant growth.

We appreciate your interest and look forward to our next update with you in November.

Thank you very much.

Ladies and gentlemen, that concludes today's conference.

Thank you for your participation.

You may now disconnect and have a great day.