SM Energy Co (SM) 2006 Q2 法說會逐字稿

Good morning.

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

At this time I would like to welcome everyone to the St. Mary Land & Exploration second quarter 2006 conference call. [OPERATOR INSTRUCTIONS] I would now like to turn the call over to Mr. Brent Collins, Director of Investor Relations.

Please go ahead, sir.

Thank you, Vanessa, and good morning to all of you joining us by phone and online for St. Mary Land & Exploration Company's second quarter 2006 earnings conference call.

Before we start, I need to read the following statement.

Except for historical information, statements made during this conference call, including information regarding the business of the company, may be forward-looking statements.

These statements involve known and unknown risks which may cause the company's actual results to differ materially from the forecasted results.

These risks include such factors as uncertainties in cash flow and reserves, oil and operating risks, volatility of oil and natural gas prices, the need to replace reserves depleted by production, competition and the potential impact of government regulations, litigation and environmental matters.

The company officials on the call this morning are Mr. Hellerstein, Chairman and Chief Executive Officer;

Tony Best, President and Chief Operating Officer;

Dave Honeyfield, Vice President and Chief Financial Officer; [Jerry Hurtzberger], Director of Business Development; [Dennis Dubieta], Manager of Reservoir Engineering; and Brent Collins, Director of Investor Relations.

I'll now turn the call over to Mark.

Thank you, Brent.

Good morning.

I'm pleased to report earnings for the second quarter of 2006.

Net income for the quarter ended June 30 of '06 was $40.1 million or $0.61 per diluted share compared to $38.3 million or $0.59 per diluted share for the prior year's quarter.

Net income, excluding the non-cash expense for the net profits pool liability was $0.74 per diluted share.

Discretionary cash flow increased to $135.5 million or $2.02 a share in the second quarter of 2006 from $105.2 million in the same period of the preceding year.

We continued to see an increase in drilling and service costs, as well as a decline in natural gas prices during the quarter in the face of abnormally high storage levels.

Production increased 4% to 21.6 BCFE year-over-year.

The average realized price increased 11% to $8.09 per MCFE year-over-year.

Unit costs increased for the year as lease operating expense increased $0.41 to $1.37 per MCFE, production taxes increased $0.12 to $0.54 per MCFE, DD&A, including impairments, increased $0.03 to $1.59, and general and administrative expense increased $0.12 to $0.46 per MCFE.

In spite of these increases in cost, our realized oil and gas prices grew more rapidly than cost and our cash margin increased 3% to $5.72 per MCFE.

During the quarter we announced two transactions.

The first transaction was a Section 1031 exchange of non-core Uinta Basin properties for oil and gas properties in the Middle Bakken play in Richland County, Montana.

We recognized a gain of approximately $6 million for this transaction.

The second was an acquisition of oil and gas properties in Carthage field in East Texas for $5 million.

The acquisition market continues to be extremely competitive, but we continue to find niche acquisition opportunities that we believe create value for shareholders.

In May and June the company purchased a total of 3.3 million shares of its common stock at a weighted average cost of $0.379.

The share repurchases were funded with cash on hand and bank borrowings.

As part of the repurchase execution, the company hedged anticipated net production volumes representing the relative percentage of outstanding stock which was repurchased.

At the end of the quarter, the company had 526,818 shares remaining for possible repurchase under its authorized repurchase program.

Subsequent to year-end-- quarter-end, the board approved an increase in the number of shares that may be repurchased under the program to 6 million shares, thereby increasing the number of shares that were available to be repurchased by an additional 5.5 million shares.

We consider share repurchases when our valuation of our net asset value per share is higher than what the equity market is valuing our shares at.

I'll now turn the call over to Tony for an overview of our operating activities.

Thank you, Mark, and good morning.

In the Rockies during the second quarter there were 27 successful completions with one dry hole and we were 6 for 8 on recompletions.

At the end of the quarter we had 10 wells completing and 5 wells drilling.

In the Bakken play we completed 5 wells in the second quarter, including the Barbara 1-21H, 20% working interest for St. Mary, with an IP of 400 barrels of oil per day and the Anvik 4-18H, St. Mary working interest 65%, with an IP of 320 barrels of oil per day.

At quarter end we were completing 4 wells and drilling 2 in the Bakken and we expect to drill over 30 wells in our Bakken program this year.

At our Hanging Woman coalbed natural gas project, we have drilled 81 wells during the first half of the year, 31 of which are currently producing.

To date we have participated in drilling 296 wells since the inception of the project and 216 of those wells are now producing.

Current operated coalbed methane production is approximately 10.5 million cubic feet per day gross and 7 million cubic feet per day net.

We have 2 to 4 deep horizontal wells planned for this summer to test the deeper Roberts and Kendrick coals.

We are still on track to drill approximately 140 wells this year.

With respect to permitting on federal acreage in Montana, the supplemental EIS is scheduled to be completed in June of 2007.

In the ArkLaTex, we continue to see impressive results from our Spider field as a result of improving our stimulation techniques.

During the quarter we completed the McKenzie #1, St. Mary working interest of 26%, with an IP of 5 million cubic feet per day and the Hewitt 10-1, St. Mary working interest of 78%, with an IP of 6.8 million cubic feet per day.

We have 5 more wells planned this year at Spider.

At Elm Grove in the ArkLaTex, there are 30 wells planned for the remainder of 2006 with two non-operated rigs running in the field and we continue to be pleased with the results at Elm Grove.

In the Gulf Coast at Judge Digby the Ivy Majors #6, St. Mary working interest 11.5%, has recently been completed at 10 million cubic feet per day.

We also decisioned 4 exploratory wells. 3 are new discoveries and currently being completed and 1 was a dry hole.

All of these prospects had direct hydrocarbon indicators or DHIs and are consistent with our low to moderate risk exploration technology-- excuse me, strategy.

3 additional DHI prospects are scheduled to be spud later this year.

We will continue to monitor the performance of our Gulf Coast exploration efforts, but to date we are pleased with the results.

In the Mid-Continent, the Paggi Broussard #2, St. Mary working interest 40%, recently completed drilling.

The well began production in July with gross initial production of 14.6 million cubic feet per day and 812 barrels of condensate per day.

There appears to be some communication between this well and the Paggi Broussard #1, but at this time it appears to be less than we had expected.

In the Atoka/Granite Wash play, we completed 4 wells during the quarter, including the Megan 2-5, St. Mary working interest 36%, which had an IP of 7.1 million cubic feet per day, and the Rebecca 1-27, St. Mary working interest 55%, which IP'd at 3.7 million cubic feet per day.

We expect to drill 21 more wells at Northeast Mayfield this year.

In the Eastern Anadarko, after successfully completing the [Red] #1, St. Mary working interest 45%, for 5 million cubic feet per day in the Springer, we are drilling the [Norma Jo] 1-6, St. Mary working interest 46%, and the [Oral] #1-28, with St. Mary working interest approximately the same, and we have additional prospects planned to offset these wells.

At Centrahoma, we continue to operate 2 drilling rigs and we will participate in a third and sometimes a fourth non-operated rigs.

We are currently completing our third and fourth Woodford Shale wells and drilling is in progress on our fifth Woodford well.

This continues to be an exciting emerging play and we are focused on learning as much as we can from other Woodford shale operators, as well.

In the second quarter we also drilled 2 Wapanucka wells, 1 horizontal and 1 vertical, at Centrahoma.

The [Oak Grove] #1-8, St. Mary working interest 90%, is a horizontal well that's current testing, and the [Pringle] #1-12, St. Mary working interest 94%, is a vertical well that came on at 3 million cubic feet per day and could lead to several more vertical well locations.

Our third horizontal Wapanucka well, the [Bovieo] #2-9, St. Mary working interest 83%, has just reached TD.

And with that, I'll turn the call over.

Back to Mark.

We are pleased with our quarterly results and we continue to anticipate record production and earnings for 2006.

Our full-year production forecast is unchanged at 96 to 98 BCFE.

Our exploration development capital expenditure budget remains unchanged at $477 million.

Oil prices are high and the long-term outlook is positive.

We are seeing gas prices recover with the positive longer-term outlook.

We have an outstanding inventory of prospects to be drilled with multi-year plays in the Bakken and Red River formations in the Williston Basin, Northeast Mayfield in the Anadarko Basin, Elm Grove field in North Louisiana, Centrahoma, including the Cromwell, Woodford and Wapanucka in the Arkoma Basin, Spider and Terryville in North Louisiana and the Hanging Woman Basin.

We have also had excellent success in conventional prospects at Constitution, the Eastern Anadarko and the vertical Wapanucka, as well as 3 discoveries in the Gulf Coast and Gulf of Mexico.

With that, we'll turn it over for questions.

Thank you. [OPERATOR INSTRUCTIONS] Your first question comes from the line of Larry Busnardo of Petrie Parkman.

Good morning, Mark.

Good morning.

In regards to the Constitution field, the Paggi Broussard #2, you've got communication between the 2 wells.

How-- how is the first well producing?

Is the rate still holding up from what you'd given earlier this year?

Yes, it is.

It's continuing to do about 35 million a day and about 1600 barrels of condensate.

You've got 40% of that well?

That's correct.

How much acreage do you have there, or, I guess, the big question is what's going to happen for the remainder of this year.

How many additional wells do you have planned there?

Do you wait and see what the communication is between these 2 before deciding how to-- how to approach this going forward?

We shot some additional 3D seismic going to the south earlier this year and there are some additional bright spots.

They are smaller and so they aren't of the same sort of order magnitude as the first well or the second well and we don't have plans right now as far as drilling one of those.

Okay.

So you just wait and you produce these out for right now?

Yes.

Larry, this is Tony.

The current plan is to kind of hold the rate on the Paggi #2 until we kind of see what the impacts will be on the Paggi 1.

Okay.

In Northeast Mayfield, looking at your activity there, could you just update us on what you have planned there for the remainder of this year and then also the number of locations that you-- that you currently have there?

Right now we're envisioning drilling 21 more wells there this year and that would be a total of around 36 gross wells and 12 net for the total year.

How many additional locations do you have there, over and beyond these?

If we take a look at 3P locations, Larry, we could see as many as 512.

Okay.

How many of those are currently booked?

Not a lot.

Okay, so there's a lot of upside there?

Right.

Yes.

All right, shifting over to Judge Digby, did you say the Ivy Major came on line, was it 10 million a day?

Correct.

Okay.

What's the activity level going to be there, going forward?

Our expectation has been almost every year that we're at the end of our new development and I think we're still feeling that way for the most part.

There may be-- if there is additional wells, it won't be very many.

We have lots of recompletion activity continuing there.

I think, as you remember, we have about 15 different producing horizons and this year we did recomplete 2 wells, each of which came on at about 45 million a day and I think we would expect to continue to see that type of activity, but I don't think we're going to see a lot of new grassroots wells.

Okay.

Primarily just recompletion-type work.

Lastly, just in regards to the guidance, the full year 96 to 98, does that still include about 2 Bs a day of-- for acquisitions or I guess you've made-- you made a small acquisition.

How does that factor into the full year?

I believe we have about 1 B left in there for-- that relates to acquisitions.

Okay, perfect.

Thanks.

Your next question comes from the line of Eric Hagen from First Albany Capital.

Hey, good morning.

First off, in the Wapanucka play, could you refresh us to how many wells you've drilled there to date, what the results have been?

Also, how much does it cost to drill a well there, drill and complete a well?

If we take a look at the-- the Woodford for example, right now, we're seeing average well costs of $3.8 million per well.

In the Woodford, but the Wapanucka is a shallower formation.

Isn't that correct or--?

Right.

The Wapanucka we're seeing average well costs there of $3.6 million--

For a horizontal well.

--going forward for a horizontal.

And do you-- given the results of the vertical well were good, do you see it possibly being developed with vertical wells or--?

Actually, the vertical wells are more rifle-shot types of targets.

So there-- there's going to be fewer locations for that, but with the success of this first vertical well we do see some additional wells that we could drill vertical wells.

The typical or average cost we're seeing right now in the vertical Wapanucka is about $2.7 million.

Okay.

Then over in the Spider field, how many locations do you have there remaining to drill?

We're looking at right now drilling an additional 5 wells in 2006 and we have probably another 5 additional wells after that.

Okay.

And historically what have IP rates been like there, prior to the new completion process?

We've seen IPs in the range of 2.5 million a day.

And now they're 5-plus million typically?

Is that what you've seen in the last few wells or--?

At least the last couple have been higher.

Whether that's going to continue or not, we'll see, but we're encouraged with those first couple of wells.

Great.

Thank you.

Thank you.

Your next question comes from the line of Michael Scialla from A.G. Edwards.

Good morning, everybody.

Mark, I think I ask you this every quarter and I get the same answer, but I feel like I still need to ask it since so many companies have flocked to this Bakken play in North Dakota, are you seeing anything different now that encourages you more or not outside of the Mondak area?

Mike, we're really-- it's really the same answer.

I think our Nance office, they've studied about 50 wells, which is where they've been able to get data and maybe 9-ish of those are economic in their mind and I think 2-ish of them were good economics.

And so we continue to be somewhat discouraged, but we're watching it because there is a lot of activity there.

Okay and so I would assume all the wells that you announced were on the Montana side?

Except for we have an area called Mondak that's near the border that we're still somewhat active in.

Right.

And then the differentials there in the first quarter got pretty ugly.

Have you seen any improvement in that?

We did see some improvement.

In July there was definitely improvement, but we actually, as we move to August, we see it expanding a little bit back to where it was.

So it kind of comes and goes, but it's gotten a little bit better.

Okay.

And then switching over to the Hanging Woman Basin, I think originally you'd hoped to drill more than 200 wells in that play this year and I think, if I caught it correctly, you're looking at like 140.

Is there still a bottleneck on the permitting side or what-- what's kind of holding you back there?

Right now the bottleneck is on the permitting side and while we continue to present applications to the DEQ and other agencies in Montana, those have been a little bit slower in getting approved, so we're seeing that impacting our ability to drill as many wells as we hoped this year.

At the same time, there's-- there haven't been any issues that have come up.

I mean, it's really just more of a personnel backlog issue and then on federal permits, it does look like we're-- they're sort of on schedule to get that supplemental EIS done in June of next year.

Do you still feel like that play has net potential of on the order of 700 BCF or do you feel better or worse about that now?

We don't really have new information to change our outlook.

We have-- Netherland, Sewell analyzed it at year end and they had about 800 additional BCFE and-- net to us and we-- we haven't had an update on that report, so that's the last information we really have.

The other part of that story, too, is that 70% of our reserves are on the Wyoming side, so while we haven't been able to drill at the rate we would like in Montana, we certainly have plenty of running room to the south there.

Okay.

And one final one for me, those two acquisitions that you just did, one in the Bakken and one in the Carthage area, what kind of drilling opportunities do you see on those?

The one in East Texas we have about 13 locations.

And we're currently completing our first 2 wells.

We've got 2 more wells we'll drill this year at Carthage and then we've got, like Mark says, 12-13 locations total.

Okay.

And then in the Bakken, was that just to consolidate some of your interest in some of your existing wells or--?

I think we had one location on that Bakken acquisition that we made, trade.

Okay.

Thank you.

[OPERATOR INSTRUCTIONS] Your next question comes from the line of Philip Dodge with Stanford Group.

Good morning, everybody.

I wanted to follow up on your comment on the DHI targets on the Gulf Coast, whether after these 4 wells that you drilled you're more enthusiastic, less enthusiastic or about the same?

I'd have to say we're-- we're more enthusiastic.

I mean, 3 out of 4 discoveries, we think certainly the DHI is a strategy that could have a lot of opportunity for St. Mary and we're certainly encouraged with the first 3 discoveries.

And what would you expect those 3 discoveries to add?

We really haven't-- we're continuing to complete and test those wells, but typically for our DHI prospects we're looking in the range of 3 to 10 BCF types of targets.

And just tentatively, 2007 you think you'd ramp up that program or keep it about the same?

It really depends on execution and results this year.

We-- we will have 3 additional DHI prospects that we will drill this year or commence drilling this year and certainly it depends on the results from that, as well.

The other thing--

But if we continue to get-- if we continue to get positive results, obviously, we'll want to continue to pursuing these DHI opportunities.

And then the other thing I wanted to ask about the deep well at Burlington.

Now Conoco is drilling on the fee acreage.

What's the status there?

Is that down to total depth?

If it is, I missed it.

The status on the [Viceroy] is not good.

They had a mechanical drilling problems and we're not sure what the status is, going forward.

So they have suspended, abandoned, all those bad things or--?

Yep.

We're not exactly sure what the final outcome is, but you're in the right ballpark with our understanding.

Indications are they've got serious problems, but as far as the final outcome, obviously that's going to have to be up to them.

But we haven't heard their final plans or decisions.

Or plans.

Okay.

Thank you.

Your next question comes from the line of Rehan Rashid from FBR.

Hey, guys, this is actually Richard.

On the Spider field, I just wanted to confirm that's using Packers Plus?

That's correct.

And on the Woodford, when could we expect production tests on the third, fourth and fifth wells?

We will be-- we're actually completing two wells right now and we're drilling our fifth well.

So I would expect to see results from that in the next few weeks on the two that are completing.

Okay.

And how many wells do you expect for next year in Woodford?

Let's see.

We really haven't done our budget for next year.

We usually do that-- we usually announce that in January.

We wait until we go through our budget process and renew reserves, so we don't usually give information on budget until we get there.

Just by comparison, we'll drill 19 wells in Centrahoma this year total and, again, 5 or 6 of those, about a third of those, will be Woodford.

We'll have to wait and see, like Mark says, what our exact plans are for next year.

And that-- the numbers Tony just said are operated.

Those are operated wells, right.

Okay.

Thanks, guys.

[OPERATOR INSTRUCTIONS] Your next question comes from the line of [Brian Koosma] from JP Morgan.

Good morning, guys.

Good morning.

Good morning.

Some questions about Centrahoma.

What length laterals are you guys running into the Woodford?

They average between 2500 and 3000 feet.

Okay.

And are you seeing anything on your logs versus the logs that are being made public for the other operators that tells you anything different about the geology in your area versus like where Newfield or the other operators are at?

Actually we're seeing comparable geology from our offset-- from the offset operators and, in fact, when we have drilled vertical wells we've actually seen better productivity in the Woodford Shale than some of our offset operators who have drilled comparable wells.

So we think the rock is very close to the same, if not identical.

Okay.

And remind us again, the Centrahoma field, that's in the middle of Coal County.

Is that correct?

Yes, it's in Coal County.

Okay.

And then switching real quick to the Bakken, I mean besides the areas-- besides the Mondak and kind of Richland County, Montana, area, which parts about the play are you most excited about?

Where do you think the play will extend to first?

Well, I think based on our results, obviously we're focused on the Montana side of that play.

So it would be the play extending to the north, then, like the northeast or--?

We've been sort of in the heart of the-- of the fairway there.

Quite honestly, we don't see a multi-year inventory remaining there.

We do see some potential other things to test where we are.

One -- in the way we've drilled the ways there were 2 ways to complete the wells originally.

One way was to do single laterals with cement liners and then the other was to use dual laterals.

And initially a lot of the wells were done with dual laterals.

And with hindsight and kind of looking at results, it looks like the single laterals, if you drilled 2 singles on three 20s, that they would recover 350 each or 700 MBOE on a section.

We think the dual laterals, maybe, do 450.

And so we think there's potential to maybe infill and test that and if that works, that will set up some future activity there and then sort of going way down the road, we see potential for secondary water flood, but that's a ways down the road.

But as far as sort of grassroots new drilling, at least where we see things being pretty prolific, it's-- we don't see many multi-year inventory remaining.

Okay.

But these other areas the industry's drilling at, I mean, are you guys-- where is your acreage position relative to where the successful wells are occurring at?

Well, if you're talking about in the actual Bakken main trend, the fairway where we currently drill and operate, we have the largest acreage position of any public company in that play at this point in time.

I'm not sure-- if you're talking about the main Bakken trend.

Well, I'm just talking about extending the play.

In North Dakota, just kind of giving you rough numbers, on the Montana side in Richland County we have about 25,000 net acres and in the-- on the McKenzie County in North Dakota we have about 55,000 net acres and that-- we have-- it's in various places, so we do have some exposure to the various plays that people are playing in, but-- but right now we're not-- we're just not overly enthusiastic right at the moment.

Got you.

Okay, thanks, guys.

Thanks.

At this time, there are no further questions.

One moment, please.

We have a question from Jack Aydin from KeyBanc.

Hi, Mark.

Hi, Tony.

Hello, Jack.

Good morning.

Good morning.

On the Woodford, you had the well reach almost TD, did you start testing that well yet or did you change anything on the way you're completing it and testing it?

We continue to work on completing that well, but we're not there yet, but what I can tell you, Jack, is that we are continuing to improve our completion design.

Obviously, we see some of the results from some of our offset operators and our job right now is to perfect our completion design and certainly to be quick learners in terms of what our offset operators are doing.

By way of example, we have received and have reviewed and studied 8 specific completion reports from Newfield in leases where we have a working interest with them.

So we're learning more each day in terms of what the other operators are doing.

We also have contacted and worked with a service company to learn more, specifically the types of completion work that's being done by our competitors.

And then I should mention, also, that we are a member of the share consortium in Oklahoma and in our next horizontal Woodford well, we'll be taking a core and submitting that to the consortium for further study.

And also we are considering the use of external frac consultants to the extent that we might be able to get some additional insights and technical advice there.

But having said that, the current well that we just reached TD and we'll be completing shortly, we will be incorporating some new completion design that takes these factors into account.

When do you think you might have the result of that well?

That will be a number of weeks at least, so we'll have to complete the well and then, obviously, do some testing and kind of go from there.

Okay.

Thanks a million.

Thank you.

Okay.

At this time there are no further questions.

Mr. Collins, will there be any closing remarks?

I just want to thank everyone for joining us today and look forward to our next quarter.

This concludes today's St. Mary Land Exploration conference call.

You may now disconnect.