SM Energy Co (SM) 2004 Q2 法說會逐字稿

My name is Lynne (ph) and I will be your conference facilitator today.

At this time, I would like to welcome everyone to the St. Mary Land and Exploration second-quarter 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 period. (OPERATOR INSTRUCTIONS).

Mr. Hanley, you may begin your conference.

Thank you, Lynne, and good morning to all of you joining us by phone and online for St. Mary Land & Exploration Company's second-quarter 2004 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 forecasted results.

These risks include such factors as uncertainties in cash flow and reserves; oil and gas 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 officers on the call this morning are Mark Hellerstein, Chairman, President and Chief Executive Officer;

Doug York, Executive Vice President and Chief Operating Officer;

Dave Honeyfield, Vice President of Finance; and myself, Bob Hanley, Vice President, Investor Relations.

I will now turn over the call to Mark.

Thank you, Bob.

As we noted in our press release, after enjoying outstanding results and ramp-up in production in 2003, we’ve been facing the challenge of replacing and growing production from a much higher base while fighting depletion associated with some of the new flush production that we saw peaking during the second quarter of 2003.

Completion activity is gaining momentum in the second half of the year, and we expect that production will begin inclining once again in the fourth quarter.

Doug will discuss some of our more recent activities, which suggest favorable results.

Net income for the quarter ended June 30 of '04 was 21.8 million or $0.69 per diluted share, compared to 24.3 million or $0.71 per share last year.

The 2003 June quarter does include other income of 3.6 million, as a result of proceeds from a litigation settlement.

Results reflect a decline in basic weighted shares outstanding from 31.5 million shares to 28.6 million, as a result of the acquisition of 3.38 million shares acquired from Flying J in early February, which was partially offset by shares issued on option exercises.

Discretionary cash flow increased by $4.1 million to 64.5 million.

Production decreased 12 percent to 18.0 Bcf equivalent.

Production at Judge Digby declined 1.4 Bcf, but has outperformed the engineering estimates.

Northeast Mayfield declined 0.9 Bcf equivalent due to the flush of production last year, and a few new wells so far this year.

We have a fairly large backlog of wells in the completion phase, and expect the fields’ production to begin increasing once again.

The average realized price increased 13 percent to $5.29 per Mcfe.

Unit costs increased modestly for the year as production expense, including taxes, increased $0.07 to $1.20.

Production taxes actually declined by $0.05 this quarter due to tax holidays approved for Oklahoma.

DD&A increased $0.10 to $1.15, and G&A expense increased $0.04 cents to $0.30.

Total LOE before production taxes was flat at $17.1 million.

The increase in LOE per Mcfe outside of taxes is primarily due to lower production volumes.

The DD&A rate will continue to increase as we replace low-cost reserves with new reserves found or acquired in a higher cost environment.

Total absolute G&A remained virtually unchanged at 5.4 million, but G&A per Mcfe increased due to lower production volumes.

Increases in G&A include the initial grant of restricted stock units, which replaced our stock option program -- before allocations to exploration, that was $2.1 million -- an increase in personnel, onetime costs associated with Sarbanes-Oxley 404 (ph) compliance.

We've set to spend about 728,000 on that for the first six months.

These increases were offset by a reduction in our cash incentive bonus accrual, and our profits incentive plan payments.

Together, they amounted to 2.8 million before allocation to explorations.

And then we also did increase allocation to exploration expense.

We have begun to show separately the non-cash adjustment associated with estimating the value of future payments derived from future net revenues associated with the net profits interest incentive plan.

Such adjustment increased by 3.4 million on a comparable basis due to rising product prices.

The acquisition market continues to be very competitive.

We've only closed $4.9 million of acquisitions this year.

We continue to evaluate alternative uses of our strong balance sheet, including lowering our rate of return requirements somewhat to reflect our lower incremental cost of capital.

And increasing dividends, as well as the repurchase of shares.

We did repurchase 3.38 million shares earlier this year, and we are authorized to acquire up to approximately 1 million shares.

I will be recommending to the Board that we ask for an increase in that authorization, and with where the stock price is currently, we too are a value investor, and believe that our stock is below NAV and we'll begin using the current authorized amount to buy back shares.

Doug will now discuss our drilling results for this first quarter, as well as an update of our CapEx forecast for the year.

Thanks, Mark.

Good morning.

At this time, I'll provide a brief update on the current activity in each of our operating areas.

In the ArkLaTex, we continue to have success in our horizontal drilling efforts.

The Company's first horizontal well in the Petit (ph) formation, the warehouser #1H tested at a rate of 3 MMcf.

St. Mary holds a 95 percent working interest in this well.

Six additional Petit locations exist in the prospect area, in which we have an average working interest of approximately 86 percent.

A similar idea is being tested in Rusk County Texas, where we have a 50 percent working interest.

In addition, we have three James Lime wells remaining at Spider in the 2004 program, and one location remaining at Huxley.

In the Gulf Coast region, the Vermillion 273 B-3, where we hold a 50 percent working interest, logged 126 feet of pay in the R sand.

Completion operations have been finalized, and the wells should begin flowing to sales today.

Completion operations on the Dana Bradley #1, formerly known as the Esther (ph) Prospect, will begin in approximately one week.

Seventeen feet of pay were logged in this 38 percent working interest well in the Plania Lina (ph) formation.

At Judge Digby field, the Delambre #1, formerly the David #1, where St. Mary has a 6.5 percent working interest, is flowing 20 MMcf a day from the C-1 sand.

Total filled rate at Digby is 78 MMcf, which translates to 9 MMcf net to St. Mary.

Four additional development wells are planned for 2004 in the Parkway Delaware unit in the Permian region.

The first three infill wells average approximately 175 barrels of oil per day per well, bringing the gross filled rate to approximately 1700 barrels of oil per day.

Four injection wells are planned at the Shugart Delaware unit, and they should be drilled prior to year-end.

Development extension drilling continues at Northeast Mayfield in the Mid-Continent region.

St. Mary has three operated rigs running and is participating in four nonoperated wells that are currently drilling.

In total, seven wells are drilling and 10 wells are completing.

Of the 39 total wells planned at Northeast Mayfield this year, 20 of those wells will be the initial wells drilled in the section.

The significance of these initial wells is that multiple zones are being tested in these stepouts, resulting in extended completion times.

To date, the stepout wells have been encouraging to the extent that we have established commercial gas accumulations, although some zones have tested water at higher rates than expected.

Continued drilling and data collection will be critical in determining a prudent development plan for the field.

Elsewhere in the Mid-Continent, the Radtke #1 in Canadian County, Oklahoma is flowing at a rate of 9 MMcf from the lower skinner.

The Radtke #2 should be at total depth in a number of days.

St. Mary has a 40 percent working interest in these wells.

In the Rockies, the Bakken play remains active with 14 rigs running in Richland County, Montana, where the Company holds 57,000 gross acres.

Our most recent test, the Coon (ph) 2-25H, is flowing 438 barrels of oil per day from one lateral.

The Franz 14-8H is flowing 220 barrels of oil per day after two months of production, and will be put on pump in the near future.

The Vaira 2-35H, which was a late 2003 completion, is producing 325 barrels of oil per day after being put on pump.

We have one drilling rig scheduled to drill 13 Bakken locations between now and early 2006.

A second rig will drill nine Bakken locations and four Red River locations in that same time frame.

In addition, we expect to perform four Bakken reentries prior to year-end.

We also expect to participate in numerous nonoperated wells where we have acreage in the Bakken play.

26 wells have been drilled to date in the Hanging Woman Basin in the CBM (ph) play.

We currently have two rigs running and are expected to finalize the fee locations by mid to late September, at which time we expect to have our federal permits in hand.

We should have powerlines finalized in October, and the pipeline remains on schedule for an early December completion date.

We've increased our capital budget by $17 million since the last update.

The majority of the increase, $14 million, is in the Mid-Continent and is driven predominantly by additional nonoperated well proposals at Northeast Mayfield, with a smaller portion of the increase the result of higher well costs.

The Hanging Woman Basin budget increase of $2 million is the result of power and infrastructure costs being higher than anticipated.

At this time, I will turn the call back over to Mark.

Although we're enjoying high levels of earnings and cash flows, like you, we're frustrated with the decline in production.

It is difficult to follow a year in which we saw production increase by 40 percent, much of which was through organic drilling that has relatively high initial decline rates.

Without any significant acquisitions so far this year, growing production has been a challenge.

With the backlog of wells awaiting completion at Northeast Mayfield, continued successful results in the Bakken, Red River and Spider plays, together with what appears to be a nice discovery at Vermillion 273, a successful Horizontal Petit well, should set up additional opportunities.

The excellent well at Judge Digby and the excellent skinner well in Oklahoma, we are hopeful that we'll begin seeing increased seam production beginning in the fourth quarter.

With that, we'll open it up to questions.

(OPERATOR INSTRUCTIONS).

Rehan Rashid, FBR.

Just quick questions on the broader front first.

The share repurchase, did you say that you're going to ask for additional authorization beyond the 1 million that you have available currently?

That's correct.

We have a board meeting in August, this month.

So that will be a topic that we are going to discuss.

And I just emphasize that we do believe that we are selling substantially below our net asset value.

And this would make sense at this time.

The other comment you made was that you would be willing to lower your return hurdle.

How can we get comfortable in terms of the magnitude of your reduction on the return side?

What we're trying to do is actually not change the economics to ourselves, but really reflect our lower cost to capital.

Even though we had, I think, $29 million of cash and cash equivalents at June 30, today our last cash report showed about $50 million.

And that is building at about $10 million a month.

And we're basically earning one-ish percent on that money.

In addition, we have an unused $300 million commercial credit facility that essentially has an incremental cost in the 3-ish percent range.

And so, our cost to capital has come down a lot.

And so, it's really just to reflect that reduction in cost to capital.

So we think that the nets are after leveraged cost -- returns to us still should be very good.

And then, of course, our presumption should be that you will compare that lower rate of return and apply it to the net asset value and make that comparable position?

That is correct.

So again, rather than a property acquisition, or included in that property acquisition analysis -- it will be cheaper to buy back stock?

That is correct.

I will pause and let other people ask questions, and I will come back.

Joe Allman, RBC Capital Markets.

Mark, in the press release, you indicated that there were some environmental challenges, or at least some opposition in the Montana portion of the Hanging Woman Basin.

Could you give us some more detail on that?

Yes, we are aware of several lawsuits.

These aren't anything really that new.

We have the Northern Resource Plains Council that has suggested that all the federal leases that were issued should be withdrawn because they didn't go through the proper process.

There's one that is brewing, relating to air pollution.

There's nothing unique to our project relative to other coalbed methane.

These are the same environmental lawsuits that have been out there for quite some time.

We see -- the Wyoming side, we're getting permits.

We think that on the Montana side there may be a little more time delay.

But we think over time it should not be a big problem.

Can you remind us -- I think you have a total of 170,000 net acres.

What percentage is federal?

What percent is not federal?

And then, how many permits you have in hand?

And how many -- how long do you think you'll be able to drill based on the permits you have?

We actually have 154,000 net acres.

I don't have the exact number off hand on the federal.

I do know what we are drilling this year is about half federal, half fee.

And we expect to have all the federal permits in September.

And that seems to be going reasonably well.

If there's delays, the delays are in the order of 30 days.

But all in all, that process is going pretty well.

When you say all federal permits, you mean just for this year?

For this year.

And what about the permits for, say, next year?

How do you feel about getting the permits you need to drill for next year?

Actually the same way.

It would be the same process.

We don't anticipate any big problem.

It does seem like, at least Wyoming, the process has actually gotten much better this last year out of the Buffalo, Wyoming office.

I might jump in also, just on the Montana side.

Certainly our confidence improved in looking at what is happening in Montana.

One of our peer companies is, in fact, actively drilling coalbed methane wells in Montana.

And they've recently been issued permits in the adjacent township.

And that's really what gave us the confidence to go ahead and talk about the additional Montana probable reserves.

But we also are aware of, and wanted to make the investment community aware of, the fact that Montana has been a little more -- there's been more litigation on the Montana side than on the Wyoming side.

Certainly nothing that has stopped other companies from actively developing their CBM leases, though.

I think previously you gave out a number -- you estimated reserves at 147 Bcf on the first 65,000 acres, and most recently you gave out 250 Bcf on the total acreage.

Does that tell us that the initial acreage that you're drilling, you think, has more gas than the incremental acreage beyond that?

Certainly one thing that happens on the Montana side is some of the coals outcrop.

As you get close to the outcrop, you lose your gas contents.

That is one issue.

Also the depth of burial, the thickness of the coals.

So we really just took our Montana acreage and normalized it for coal thickness, depth, and of course distance from the outcrop to come up with the additional 110 Bcfe of probables.

And then, I think you have a pipeline that you expect to have online in November.

Is that still on track?

Early December, and it is on track, yes.

And then I think your production -- switching over a little bit broader -- your production is ramping up in the fourth quarter.

What specifically is going to cause that ramp-up in the fourth quarter?

We do have several things coming online.

We mentioned the well at Vermillion 273, we think that's going to have a substantial initial flow rate.

Our Petit well in the ArkLaTex region certainly is going to be a contributor, along with the additional wells at Spider that we plan to drill.

And we fully expect many of these wells at Northeast Mayfield that have been in a test mode to be flowing to sales in the fourth quarter.

It's really a combination of those things, along with just continued base level activity across the board.

And also that Radtke well that came in about 9 million a day, we'll have that together with, hopefully, an offset to that.

That's a fairly significant rate.

Larry Busnardo of Petrie Parkman.

On the Hanging Woman play, could you just update me on the number of wells that are going to be drilled this year?

And then what you have planned for next year initially?

We have 104 wells planned for this year. 96 of those wells will develop at Anderson, Canyon and Cook, which are the shallower coal seams, at less than 1000 feet.

And we have an 8-well pilot in the deeper coal seams, for a total of 104.

Our plan going forward is in the 175 to 200 well range for 2005.

Is that utilizing two rigs, or would that be more?

I'm not certain about that.

We may have to pick up a third rig to really hit that 200-well program.

Did you say 27 wells have been drilled today?

26, that's correct.

And then in the Bakken, how many wells have been drilled to the Bakken dolomite since you initiated that drilling program?

I think there's been 6 new wells.

And then I think we've had a couple of reentries.

You said 13 wells by early '06?

Right.

That's with one rig.

We're going to have one rig continuously drilling Bakken wells.

We just moved a second rig up from Texas about six weeks ago.

It started off with drilling a Red River well, then it's going to switch to a combination Bakken/Red River program.

And it will drill nine more in that same time frame.

So 22 to Bakken pud and probable locations will be developed between now and basically February of 2006 per our rig schedule.

And that is new operated wells.

We'll also have reentries as well as participation in some nonoperated wells.

Would you say of the six wells that you've drilled today -- have they met your expectations or exceeded expectations?

I think it's fair to say they have exceeded expectations.

We don't have a lot of history on our operated wells, but the one we have the most history on is the Vaira well, which is a dual lateral that was fract (ph).

And that's how we are going forward with our grass roots well.

That's probably the best example.

That well came on in the 6 to 700 barrel a day range, declined down, on a flowing basis, to about 200-ish barrels a day.

We put it on pump, and its sustaining a rate well over 300 barrels a day -- 325 is the recent average.

That's going to exceed our expectations of the way we had the well booked originally.

And Mark, given the difficult in completing acquisitions to date, could you potentially ramp up your technical personnel and look to generate additional prospects that way in order to offset the declines?

I know that in the environment we have, acquisitions have become tougher and tougher and more competitive.

So I'm just looking at it from a strategic standpoint.

Maybe focusing more on the internal generation of prospects and maybe ramping up the drilling program to help offset the declines in production and moving that forward.

What are your thoughts on that?

That's definitely something we are not only considering, but having done some of that.

As you know, we increased our organic budget this year.

Began the year from $173 million to $205 million, and a good portion of that was increased activity.

There has been some cost increase, but the vast majority of that was new activity.

It is something that we're meeting with our regions on to see if we can do that.

So it's something that we are considering and working on.

Ellen Hannan of Bear Stearns.

A couple of quick questions.

Mark, in the Hanging Woman Basin, what are you looking for for a production contribution in '05?

It's going to ramp up reasonably slowly, quite honestly.

We have not put out a production forecast, but it will take several years to start to ramp up.

And similarly on booking, reserves, I don't expect that we'll book a lot of reserves this year.

Next year, once we have some wells that reach commercial production, then you can book offsets to those, and we would expect that that would start to begin probably at a fairly good pace next year.

Production-wise, I don't think it's going to be a huge number.

I actually prefer not to quote a number right now, but it is not going to be a huge number.

It takes several years to really bring that project up to full strength.

And just one other question on Northeast Mayfield, I took notes quickly when Doug was speaking.

Did you mention that you have seen a higher water content in the wells?

Can you give us a little bit more color on that?

Sure.

This might be a good time, also, just to describe the activity in a little more detail.

If you look at Northeast Mayfield over the last four or five years, the majority of the development has occurred in really about a nine-square-mile area.

And that's really what we've considered the heart of the play.

In the last 12 months, if you move two miles to the north of that area and two miles to the south of that area, and then about six miles to the west, the field is being delineated on the fringe, and it's quite a large area.

We have about 50 sections that we have an interest in in that area.

As we move west, we are seeing commercial gas rates, particularly in the Atoka to date.

But the zones have some associated water.

And so far, the wells are producing at commercial rates, but with associated water.

So it's a bit of an known.

How that would impact longer-term production, what that might do to longer-term flow rates, we are not sure.

What we are reasonably certain about is, we are not dealing with a water dry reservoir, and that's historically been the case pretty much everywhere in western Oklahoma.

These are not water dry reservoirs, but there is some mobile water in the formation, and it is being produced in some of the wells out five or six miles west of that core area in the Atoka.

That's it for me.

Thank you very much.

Phillip Dodge, Stanford Group.

I just had another specific question on Northeast Mayfield.

You said that the production declined 0.9 Bcf.

Can you tell us what the current rate of production at Northeast Mayfield is?

Yes, the nine-tenths was second quarter to second quarter.

And I think today it's about 21 MMcf.

The peak was about 26 MMcf.

Okay, Mark.

Thank you very much.

Jack Aydin of KeyBanc Capital Markets.

Most of my questions were answered, but looking into 2005 -- I assume you're looking at the budget and everything.

What kind of budget are you looking at for 2005, if you care to talk about it?

It's probably a touch premature.

We actually finalized that.

We have kind of a formalized planning process in September with each of the regions.

And that's when we tend to finalize those numbers.

So it's a little bit premature to talk about that right now.

But looking at 2004, in essence to replace your reserves, you need a certain amount. 2005, in essence to look at it, to replace your reserves.

What kind of a base budget -- do you care to comment on it?

Again, I think it's probably just a little early to do that.

You know, our expectation is that we have a pretty phenomenal historical finding cost.

Last year, it was a dollar $1.05, and I think, looking out over a longer period of time, it's probably in the $1.25 range.

That was a combination of drilling as well as acquisitions.

Because of the higher rates of initial production with drilling wells, the economics on drilling are much better on a per-Mcf finding cost standpoint, and you can have a much higher finding costs.

And with a higher price environment, we would expect our finding costs would go up from that historical range.

But the drilling economics remain very good for us.

And I think we have not tried to project our finding costs for this year.

We've given you our CapEx, but we do not like to project finding costs or reserves until we have our Rider Scott (ph) engineering done at the end of the year.

We just think that tends to get us into trouble.

One more question.

On Hanging Woman, with the 26 wells drilled -- and I guess trying to get them on production and everything -- did you book any Hanging coalbed methane in 2003?

If not, is there a chance you might book any this year?

We did not book anything in 2003.

The rules are that the wells have to have commercial production.

And with the pipeline going in on December 1st, we will not actually start producing those wells until maybe a month or a little bit before that, before the pipeline is in, because we don't want to waste the gas.

And so then they will have to dewater, and they probably won't reach a commercial stage of dewatering by year-end.

And so, chances are we are going to book a whole lot of reserves this year.

Thank you.

(OPERATOR INSTRUCTIONS).

Dan Morrison of Aperion.

I think most of my questions have been answered.

But at Northeast Mayfield -- I missed a 9 million-a-day completion in the comments?

Was that at Northeast Mayfield?

Actually that is in Canadian County, Oklahoma.

It is in a different play.

It's a shallow, 10,000-foot, 11,000-foot lower skinner play.

And we have 40 percent working interest in a well that's making 9 million a day.

Just are in the process of drilling an offset to that well, and that should be a TD (ph) in just a matter of a few days.

We are encouraged that we think we're going to find the similar zone.

Is there going to be any running room to get that play?

It's a channel development, and people have played that.

We have a section right in the heart of the play that we have our interest in.

But as far as multi-well follow-ups, probably not.

It's going to be a highly competitive reservoir, obviously, very high perm.

And there are wells going into the channel on both sides of our section currently.

Some wells producing, additional wells being drilled, but as far as having multi-well follow-up, not really.

Did I get it right that you expect the Northeast Mayfield production to resume its growth?

Or was that a comment about the production in the aggregate?

No, I think that would be our expectation.

We currently have, I believe, 12 wells that are in the process of being completed.

And we have five wells that are currently drilling.

And we only had, I think, five wells to date in the first part of the year.

So there will be a significant amount of new activity starting to come on.

We don't have the exact timing of that, but with what we know, our expectation would be that that would come up a bit.

Our approved reserve forecast at midyear is for inclining production at Northeast Mayfield.

Great.

Thanks.

John Gerdes, Southwest Securities.

Doug, maybe of a bit of an update on this fee property three -- I know you did get some of that acreage leased, I guess 2800 acres.

If you would, just give us a quick update on where we are there.

Sure.

We've been working the seismic, as has Burlington Resources -- was one of the main underwriters and they're also the party that took the lease.

Our understanding is that they had the data reprocessed.

And our understanding further is that they were a bit disappointed with the quality of the reprocessed data.

And they are trying to decide if they want to do additional reprocessing.

But they, obviously, have some prospects in mind by virtue that they took leases.

They have not shared those specifically with us.

So we don't know exactly what they are planning to do.

They have suggested first half of 2005 that they plan to test some of their ideas.

That's about the extent of what we know at this time.

It doesn't sound like there's anything dissuading them in the context of prospectivity; it's more an issue of seismic quality at this stage, huh?

It feels like it is a data quality issue.

And these are, obviously, going to be expensive wells, and I'm sure they want to have the best quality data to work with.

Just on High Island-Miami #3, I guess to get an update there -- High Island-Miami #3 -- and also this Mermentau play.

Comments there?

Mermentau will spud really in the next couple of weeks -- and it's probably a 20 or 30-day well -- it's not certainly the same impact level that a Miami 3 is.

At Mermentau, we're looking at probably reserves in the 3 to 5 Bcf type range.

Miami 3 could be a real meaningful well for us.

It is going to spud in about a month.

And we are going to chase the Myochip (ph) and the Cameryna (ph) at what we think is the most favorable structural position in the field.

We will have 25 percent working interest.

We'll operate the drilling.

And in a successful completion scenario, BP, who is our partner, will operate the production.

We should have results on that before year-end.

AFE (ph) on that well is -- what is that?

It's in the 6 to $7 million range for dry hole cost.

Great.

Thank you for the comments.

(OPERATOR INSTRUCTIONS).

Rehan Rashid, FBR.

Mark, on Northeast Mayfield, just in terms of running room for next year.

Any thoughts on that front?

Yes, we had actually booked in terms of both probable and pud locations.

We have about -- it is in the 60-ish range, total wells that we have already identified.

And this year, we are actually drilling over 30 wells.

That compares to last year of 16.

So there definitely has been a ramp-up in rate.

And with 60 locations already identified at the approved or probable level, we have a lot of running room, we believe, for some time to come.

And that extra water, higher-than-expected water in the west, does that take away from the locations or not?

Well, this'll be a period of gathering data.

The rate on that far western well is still about 4 million a day.

So it's not a bad well.

And so we just want to look at it and make sure we understand it.

Okay.

Thank you.

(OPERATOR INSTRUCTIONS).

There are no further questions at this time.

Gentlemen, are there any closing remarks?

No.

We appreciate you all for listening in.

Thank you.

This concludes today's St. Mary Land & Exploration second-quarter earnings conference call.

You may now disconnect.