SM Energy Co (SM) 2007 Q4 法說會逐字稿

Good morning.

My name is Deshonta and I will be your conference operator today.

At this time I would like to welcome everyone to the fourth quarter 2007 earnings conference call.

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

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

(OPERATOR INSTRUCTIONS) Thank you.

Mr.

Collins, you may begin your conference.

Thank you, Deshonta, and good morning to all of you joining us by phone and on-line for St.

Mary Land & Exploration Company's fourth quarter and full-year 2007 earnings call.

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

These statements involve risks 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 information about forward-looking statements in our press release from yesterday, and the risk factors section of our 2007 Form 10-K, which will be filed later today with the SEC.

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

Reconciliations 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 in this call the terms probable, possible, and 3P reserves, estimated ultimate recovery, or EUR, and contingent resources.

Definitions of these terms are included in our latest operations update press release.

Estimates of unproved reserves and contingent resources are by their nature more uncertain than estimates of proved reserves and accordingly are subject to greater substantial risk of not actually being realized by the Company.

The Company officials on the call are Tony Best, President and Chief Executive Officer; Jay Ottoson, Executive Vice President and Chief Operating Officer; Dave Honeyfield, Senior Vice President and Chief Financial Officer; and Dennis Zubieta, manager of reservoir engineering; Matthew Purchase, budget and planning director; and Brent Collins, director of investor relations.

I'll now turn the call over to Tony.

Good morning and thank you for joining us for our 2007 earnings conference call.

After a few brief opening remarks I'll turn the call over to Dave Honeyfield for a review of our financial results.

After that, Jay Ottoson will provide a quick update of our operations.

Looking back, a lot happened during 2007 for St.

Mary.

Some of these highlights include record year -- excuse me, record year-end reserves of 1,087 BCFE; annual production of 107.5 BCFE, for an annual daily average of 294.5 MMCFED inventory; discretionary cash flow of $636.9 million, which is an increase of 21% from last year.

We also had net income per diluted share of $2.94, which ties the annual record that we set last year.

All-in reserve replacement of 248%, which is an increase from 244% in 2006, and this also meets our annual goal of replacing at least 200% of our production every year.

All-in F&D costs were $3.48 per MCF equivalent, down from $3.56 in 2006.

Last year we also entered a new basin with two acquisitions in southwestern Texas, which target the almost shallow gas formation.

We also underwent a number of senior and regional management changes throughout the year, and we also opened a new regional office in Midland, Texas, which is now fully staffed.

And lastly, we've now reached our 100th anniversary, which we will be celebrating throughout the first part of 2008.

Clearly, 2007 was a very active year for St.

Mary and it sets a very good foundation for future growth.

We have entered 2008 generating strong cash flows and with a strong balance sheet.

Our focus is on advancing our key projects and pursuing ways to add to our project inventory.

I'm pleased with how the Company is positioned operationally and financially, and I have a high confidence that our 2008 program will deliver growth and value to our shareholders.

With that introduction, I will now turn the call over to Dave Honeyfield for his financial overview.

Dave?

Thank you, Tony, and good morning.

Since I know many of you on the call this morning follow the results of St.

Mary on a regular basis, I'll focus my financial commentary on the Company's quarterly performance.

For the fourth quarter of 2007 St.

Mary reported net income of $32.9 million, or $0.51 per diluted share.

This compares to $43.5 million, or $0.69 per diluted share for the comparable period in 2006.

As alluded to earlier, our fourth quarter production rate was quite strong, as were realized commodity prices, resulting in discretionary cash flow for the quarter of $176.4 million.

Tempering the benefit from the strong revenues was a relatively large noncash charge related to the change in the net profits plan liability that occurred in the quarter.

The increase in the long-term NPP liability reflects a significant increase in oil prices during the year, as well as the impact of lowering the discount rate used to value the liability from 15% to 12%.

We made this change to the estimate to better reflect market trends regarding the valuation of these types of assets.

Adjusted net income, which adjusts for NPP -- the NPP item and other significant noncash or nonrecurring items was $64.4 million versus $49.1 million in the fourth quarter last year.

On a diluted share basis adjusted net income was $1.00 per share in the fourth quarter of 2007, an increase of 30% compared to the same period in 2006.

I'll now touch on a few significant income statement line items in a bit more detail.

Oil and gas production revenue for the fourth quarter of 2007 was $273.7 million compared to $180.6 million in the comparable period of '06.

The fourth quarter daily production rate of 310.2 MCFE and a realized equivalent price, including the effect of hedging, of $9.18 per MCFE, drove this increase.

For the fourth quarter of 2007, the average realized prices, net of the effects of hedging, were $69.99 per barrel of oil and $7.80 per MCFE of gas.

These net realized prices were up 36% and 8% respectively from the fourth quarter of 2006.

On a quarterly comparison, our lease operating expense increased 7% year over year from $1.36 per MCFE in '06 to $1.45 per MCFE in '07.

With our production mix being just under 40% oil, we tend to feel -- pardon me -- we tend to feel the cost pressure for services such as fluid disposal, well maintenance, labor, and trucking more acutely than others that are more heavily weighted towards natural gas.

The offset to this cost pressure continues to be the current oil prices, which result in strong margins and returns from our oil properties.

We did see an increase in general and administrative expense from the prior year.

This is driven by an overall increase in the number of employees we have, both in Denver as well as our regional offices.

Additionally, the higher revenues driven by commodity prices also mean that we will have higher payments from the net profits plan, which was a significant factor in the G&A increase.

At the end of the the year our balance sheet is in good shape, with a debt to book capitalization ratio of 40%.

If you consider this on a pro forma basis for the proceeds from our divestiture of noncore properties that closed on January 31st this year, our debt-to-cap ratio would have been approximately 34%.

Lastly, the Company currently has a board authorization to repurchase roughly 5.2 million shares of our common stock.

Clearly, we need to be aware of trading window restrictions as well as the impact of the balance sheet of repurchases, but given the recent trading performance of the stock in the market, and the strength of the commodity strip, the acquisition of our own shares looks to be a very attractive investment.

With that, I will turn it over to Jay Ottoson.

Thank you, Dave.

Along with our earnings release last evening we also released a brief operations update.

2008 capital program is actively under way.

We have 13 rigs running currently throughout our operating regions.

Some notable highlights of our current operations include the following.

In the horizontal Woodford we've seen positive results in our last several wells.

We're becoming more confident in our appreciation of the geotechnical issues and believe we've learned the best way to drill and complete these wells.

Our average EUR currently is 2.7 BCFE for horizontal Woodford and we've recently had a well that we project to have an EUR in excess of five BCF.

Also in the mid continent, we had a very good well in the Atoka and Granite Wash program with an optimized completion that also reduced costs.

In the ArkLaTex we continue to be an active horizontal driller.

In the operated James Lime program we're operating two rigs and continue to see favorable results in the play.

At Elm Grove our operating partner drilled an excellent horizontal well in which we have a 20% working interest, the target of the taylor sand in the Cotton Valley formation.

The operator publicly reported an IP of 16.5 MMCFED and we've been very impressed with how the well'as performed based on field reports.

An offset well is currently drilling.

St.

Mary has recently drilled its first horizontal Cotton Valley well at Carthage Field, which is scheduled to be completed in March.

Our programs in the Permian, Gulf Coast and Rockies regions continue to move ahead.

I'll refer to you last night's release for updates on those regional programs.

In previous calls and filings we've noted that our 2008 capital program is within our projected cash flows.

With free cash flow, we'll have the opportunity to accelerate drilling programs, or pursue other attractive opportunities which will be accretive to our NAV per share.

With that, I will turn it back over to Tony.

Thanks, Jay.

I'm pleased with our performance for 2007 and believe that we are off to a great start for 2008.

We have lots of irons in the fire and are focused on the execution and delivery of our business plan for 2008.

Finally, it is with regret that I mention that this will be Dave Honeyfield's last call as a member of St.

Mary's management team.

Dave has been a great contributor to the success of St.

Mary over the years and we truly wish him the best of luck in his new endeavor.

We'll now turn the call over for your questions.

Thank you.

(OPERATOR INSTRUCTIONS) Your first question comes from the line of Subash Chandra with Jefferies.

Hi, good morning.

First, on the Woodford, I was curious, the five BCFEUR, what sort of ten-day average or 30-day average, do you need to see, to feel comfortable with a number like that?

Well, we wouldn't do it on a ten-day or 30-day average.

We've got three months of production or so on that well.

I think that particular well was the Duncan Shores and my recollection was it IP'd at about 3.3 million a day on a ten-day average.

Okay, and then it cleans up after that, I imagine?

Well, no, not -- these wells all have hyperbolic declines.

It hung in there pretty well.

It's hung in there pretty well at above three but all of them decline.

Got it.

In the '07 reserve report, what credit did you get for Woodford wells?

And what offset credit do you get in the Woodford?

Are you asking us what we book our PUDs at?

Yes.

Yes, what you booked your producing wells and what you might have booked the PUDs at?

Did you get 80-acre spacing or --?

No, we don't book at 80s.

We're booking at 320s at this point and as I just mentioned, we booked 2.7BCF a well.

That's our expectation.

Okay.

Okay, so 2.7 is actually what was booked for the location?

That's our expected PUD number, yes.

Got it.

Okay.

In the James Lime, we talked about this before, but Cabot obviously put up -- well, Cabot put up some pretty good ambitions for it this year and some results.

Any further flavor in the repeatability of this, and maybe how continuous the reservoir might be -- or the target might be, I guess, how continuous it might be for an 80-acre development, or are you going to see these sweet spots that are fairly far apart?

Well, you'd have to ask Cabot about their views of their development, but we're still in -- pretty much in exploration mode.

We've got a lot of acreage.

We drilled a couple, three wells across a big area.

I don't think we're ready to talk about spacing yet here.

We've drilled a number -- several successful wells.

I think there are going to be sweet spots in the play.

It looks like Cabot found them.

We are have some.

The Spider Field has always worked well for us, as well, so we expect that to occur.

It is a large play and there's probably some structural component to it.

I don't think we really know the answers to all that yet.

Okay.

And one final one.

The Bakken, when you say participated, I imagine it's nonoperated.

Do you anticipate operating in '08?

And then what is this reference -- can you be more specific about this reference on the completion technology?

Well, yes, it's a nonoperated well.

We don't have any partic -- we don't have a plan right now to drill a Bakken well in the -- what you might consider to be the hot part of the partial-type play at this point, although we're looking at it.

I think in terms of the newer technology, you're looking at more barnett style, multi-stage, external casing packer-type completions.

And now, you said that -- so this well, okay -- and utilized new drilling, that had previously not been used by St.

Mary?

No, we (inaudible) technique.

We didn't drill the well.

Right.

The sentence says it wasn't previously used by the Company, that's why I was curious.

The answer to that is that if you look at the Montana Bakken where we've been mostly active, most of those wells were completed open hole and they weren't treated in this fashion.

Dennis Zubieta.

That reference was specifically to the way we've developed the Bakken in the past and we haven't used it in that area.

We obviously drilled packer -- a bunch of packers plus completion work and other types in other places but this is a relatively new technique in the Bakken.

Right, right.

Got it.

I understand.

And just quick note here, on -- when you do these plays like the Woodford possibly and the Bakken, and you saw the open hole stimulation, is it better to case the holes off to do refracs in the future?

Or how does someone weigh the current impact versus the future potential in refracing wells?

Well, I think if you truly have an open hole, barefoot completion, there's a number of issues about when you frac them, where you're placing the frac and how that -- whether you actually know where the thing's going.

Clearly, if you have an external casing packer completion you at least have some confinement or some ability to do that.

Cemented liners, I think we used cemented liners in the Woodford, for example.

In a lot of ca -- in most cases, I think that's probably the -- your best ability to control where the frac is actually going to go, but it's not an appropriate initial completion in a lot of cases, so it's very dependent on the play.

And in terms of refracs, we haven't worked a lot yet on refracing wells in the shales, but people have refraced wells in the Bakken and done some successfully.

Okay.

Thanks much.

Thanks, Subash.

The next question comes from the line of Larry Busnardo with Tristone Capital.

Good morning.

Good morning, Larry.

Hi.

In the James Lime trend, it looks like you continue to add acreage there.

I know competition's heating up, but how much more additional acreage do you think is still up for grabs there?

Is there still quite a bit or is the play getting pretty locked up?

Well, that whole east Texas area, when you get out there, is an interesting land situation.

There's -- a lot of it's held by production and there are people who own big acreage positions that are probably not going to drill these wells, so I don't think it would be true to say that it's locked up or that you're not going to be able to get acreage.

You're correct in that it is getting more competitive.

But, Larry, you got to work it hard and really focus some resources to acquire additional acreage at this point.

What is the recent acreage been going for in terms of cost-wise?

Well, we bought acreage for $500 an acre.

It varies, depending on how close are you to production.

Okay.

When you talked about expanding the -- potentially expanding the drilling program this year, depending on programs, just wondering.

I know you got two rigs there, I guess, operating right now.

Where do you see this program going this year?

Provided results continue to meet expectations and all that, could we see you add maybe a rig or two here and expand out this program?

You're talking specifically the Cotton Valley?

Yes.

Yes.

The James Lime was the question.

Yes, just in the James Lime trend.

I think the James Lime two rigs is about where we'll end up.

I think we're -- we are -- as we talked about, we just finished the Cotton Valley horizontal well, and we have a couple more queued up behind that.

I would probably expect to see that expand if anything else in that region.

That is the one over at Carthage, correct?

Right.

And looking at that, I think you said you've got two other wells or at least two other horizontals planned there.

If those end up successful, would that increase the number of horizontals you look to drill there later this year?

Yes, potentially.

Okay.

Anything being done differently within this program, drilling or completion wise, or is it just slight tweaks or modifications to drilling and completions within the program?

Well, I think we pretty much think we know how to complete the programs.

The costs are coming down.

We've done some good work with some of our vendors to get our costs driven down.

Our drilling rate, we are getting our costs down faster.

I think in general our costs are going down in the plays so that's -- it's positive from that standpoint.

What does it take to drill -- on the vertical side, what does it take -- or how long does it take to drill and complete?

Are you talking about horizontal?

Number of days, yes, number of days.

They're about 30-day wells.

Okay.

And what are they costing right now?

I think the last number we talked about was $3.5 million.

Okay.

All right, great.

Thanks a lot, guys.

Thanks, Larry.

Your next question comes from the line of David Tameron with Wachovia.

Hi, good morning.

Good morning, David.

Most of my questions have been answered, but a couple of questions.

David, you mentioned share repurchase authorization.

Did you through out numbers and I just missed them or can you talk about how much you guys have available?

Sure, David.

We have an authorization that has 5.2 million shares remaining at the current time.

Okay.

And you are comfortable with -- obviously with your debt-to-cap right now, you just go ahead and you feel comfortable just taking that up a little bit, to repurchase shares?

Yes, I think it's important to keep in mind as well that the way the capital program was built this year, intentionally there's some flexibility there.

We intended to stay within cash flow so we have good opportunity to look at a number of things, increasing the drilling program that was talked about earlier, accretive acquisitions, if the share price is at a point that we think it's attractive to repurchase, those are alternatives.

And then also, keep in mind, the proceeds that came in from the sale of the noncore properties at the end of January was $131 million, so that debt-to-cap level's pretty manageable.

And then you look at the flexibility under the credit line, as of right now, we still have over -- about $320 million available under that facility.

All right.

Thanks.

Actually, a couple more questions.

Tony, can you talk about your acquisitions, Catrina and then I think it's the Gold River -- I guess was it Rockford that did you in the shallow gas?

Can you talk about what you're seeing now versus when you bought that thing six months ago, any changes you're making on the operational front or where you're headed in '08, '09?

Yes, right now, David -- and Jay can chime in as well -- but basically it's a three rig program.

The transition has gone very, very smoothly.

I've been very pleased with that.

So the program is continued, transition's been smooth, we're very focused on that and very pleased with where we are today, and that's going to be a significant component to our 2008 program, especially out of our Gulf Coast region.

It also positions us well for potential opportunities elsewhere in the Maverick Basin, and we see additional zones of interest beyond just the almost gas.

We continue to look at those opportunities, and we'll continue to assess that new basin.

Jay, anything else from your perspective?

Just note we have, I think, the number 66 recompletion scheduled for this year as well, so it's -- there's a real opportunity to add nice little reserve adds at low cost.

And I think we've mentioned that there's 56,000 acres associated with those deals, so we think there's a lot of upside opportunity in them.

And are you still talking -- [these wells are costing as recompletes], they're what, $600,000, $700,000?

Oh, I don't even think they're that much.

Okay.

That's a (inaudible) cost on a greenfield well, the recompletes are significantly less.

Probably more like half that, yes.

All right.

And then one more question.

Hanging Woman Basin, you moved that out of 3P.

Can you just talk a little bit about the outlook there?

We moved about half of it out of 3P into contingent resources, so we basically retained half of that in the 3P category.

And as you've heard me say in a number of different forums, I think the key long term is to right-size the Hanging Woman Basin development and clearly, we are focused on that.

A lot of activity last year, a lot of new wells, a lot of technical work being done, and we'll continue that effort in 2008, as we continue to focus on the technical aspects of this play.

But that original 3P number we had out there was somewhere around 800 BCFE, and a good portion of that, as we've mentioned before, was in the possible category.

So yes, we've shifted some from possible to contingent, but I don't view that as a huge shift.

I think what's most important is to understand the technical aspects of this play and optimize the ultimate development.

And let me just chime in a little on that.

I think when you look at definitions for what is reserves and what's resources, our view was that after looking at it for a while, there are a number of regulatory issues there.

There's a number of bird issues, just habitat issues in that area, and our view was that it was more appropriately categorized as contingent as opposed to in the 3P category.

There's no change in the resource and there 's really no change in our view of it.

We just thought it was more appropriately categorized in that way.

It also -- David, it also allows us to focus on higher growth programs that we've got in our business plan for this year.

So, I'm not taking anything away from that but we want to be sure that we focus on those that have the most growth potential, as well.

Okay.

Yes, that's where I was going with that.

And can you talk at all about the legislative -- my understanding is the CBM ruling's now going to the Supreme Court.

Again, remind me -- and I asked this question every couple months -- but remind me again in Montana how much of your acreage is prospective for CBM and what impact, if any, would this ruling have on your position there?

We've got a total of about 220,000 gross acres.

70% of that is on the Wyoming side, so we've got [plain to say grace] over in Wyoming.

And while there's issues in Montana, we haven't particularly focused on those as far as our program plans for the year.

Those things are going to run their own course.

You may remember a couple of years ago, we were trying to determine the timing for that to be resolved, and we gave up on doing that last year, so we will let that take its course.

In the meantime we will focus on our 70% acreage position.

All right.

Thanks.

Thanks, David.

Your next question comes from the line of Ronnie Ikeman with JPMorgan.

Hi.

I have just a quick question.

What are you seeing as trends in each of your operating areas in terms of drilling and completion costs?

Well, I think it's fair to say that drilling costs are coming down.

Rig rates have dropped probably 10%, 15%, almost 20% in some areas.

We've had some recent relief on pumping services, which was something we were looking for and didn't see last year.

We're starting to see some improvements in that as well and we're very encouraged by that.

So I think in general, we're pretty upbeat on our cost structure in terms of -- on the drilling side.

On the LOE side, into the end of last year, we were still seeing some increases in LOE, mostly related to labor-related costs, as Dave mentioned earlier.

We don't think that's going to continue much beyond this, and we think we'll have a pretty good LOE year, but it is a little more pressure on issues that have labor associated with it.

So you're still seeing drilling costs coming down?

Yes, we think our drilling costs are coming down some relative to last year.

Okay.

Thank you.

That's all I had.

Thanks.

(OPERATOR INSTRUCTIONS) Your next question comes from the line of Ellen Hannan with Bear, Stearns.

Good morning.

Good morning, Ellen.

Morning.

Just a couple of follow ups, I guess, bigger picture question here.

You mentioned in your operating update that you're continuing to evaluate your position in the Rocky Mountains and that you've got another package of properties up for sale.

Should we continue to think along the lines of your goal being the 200% reserve replacement every year, and what, if anything, does that play into this?

And then I guess further, is there a gas price that would change your mind, or is it simply you see better returns, or more opportunity in some of the areas -- other areas that you have been investing in?

Ellen, I think as we look at the Rockies, our intent there is to be sure that we've cored up the assets that can provide the most growth potential for the Company.

As we went through our significant divestiture, and closed on that in January, that was a large part of that, that came out of the Rockies and it was simply properties that we thought may be better off in someone else's hands.

They were not going to provide the growth that we're looking for year in, year out, and I think it allows us to be much more efficient with our resources to sell those into what we think was a very attractive market.

We'll continue to do that going forward.

It is not just the Rockies.

It's in all of our locations where we think we have assets that may be well beyond their prime and don't provide a growth trajectory for us.

But we/ll do that every year.

But coming to my other question about the 200% reserve replacement, what does this do -- what are you targeting for sale or for rationalization in terms of percentage-wise as to what you have today?

There's a number of metrics that we look at.

Part of that, as I mentioned, is that the growth potential.

The other is the level of cost associated with those properties, the level of resource support required for those.

And in terms of the 200% target, to me, that's where the focus is on those properties that can provide that growth, and allow us year in and year out to achieve that level.

Over the last three years we've been 250% reserve replacement.

The same held true in 2007.

So I think the key is to find those new opportunities that you can bring into inventory that give you a better opportunity to repeat that level of reserve replacement year in and year out.

So to me, it's a process of bringing in stronger, more growth-focused kinds of opportunities on the front end, and on the back end you're getting those others to the divest market when they've gone well beyond their prime.

Great.

One last question from me and you may have touched on this earlier.

I just want to make sure I heard this correctly.

It doesn't look like you've got anything on an operated basis that you're going to drill this year in the North Dakota Bakken.

is that correct?

You're going to participate with others, but you don't have anything you're operating yourself?

Yes, I think that's a fair characterization.

We're looking at it.

We may drill one, but in the plan -- or in the budget right now, we do not have a North Dakota operated well.

Okay.

Thank you.

That's it for me.

Thanks, Ellen.

At this time, there are no further questions.

Thank you very much for joining us this morning.

As I mentioned earlier, 2007 was a very active and solid year for St.

Mary.

We are clearly focused on delivery of our business plan this year.

I'm very pleased with where we are at this point.

We've gotten off to a very strong start and we're anxious to see the results of our programs and drilling programs through the end of 2008.

Thank you for joining us this morning.

We will talk to you next quarter.

Thank you.

This concludes today's fourth quarter 2007 earnings conference call.

You may now disconnect.