SM Energy Co (SM) 2008 Q3 法說會逐字稿

Good morning.

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

At this time, I would like to welcome everyone to the third 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 session.

(OPERATOR INSTRUCTIONS) Thank you.

Mr.

Brent Collins, you may begin the conference.

Thank you.

Good morning to all of you joining us by phone and online for St.

Mary Land & Exploration Company third quarter of 2008 earnings conference call.

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

These statements involve risks which may cause actual results too 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-KA.

We 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.

Lastly, we may use the terms probable, possible and three key reserves and estimated alternate recovery or EUR in this call.

Probable reserves are unproved reserves, which are more likely than not to be recoverable, possible reserves are less likely to be recoverable than probable reserves.

Estimates of probable and possible reserves which may potentially be recoverable for additional drilling or recovery techniques are by their nature more uncertain than estimates of proved reserves and accordingly are subject to substantially greater risks of not actually being realized by the Company.

EUR means those quantities of petroleum which are estimated to be potentially recoverable from the accumulation and those quantities produced there from.

The 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; Mark Solomon, Controller; Matthew Purchase, Treasurer and 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 this morning for our third quarter earnings conference call.

Before turning the call over to Wade and Jay for their respective financial and operational reviews, I have a few opening remarks I would like to share.

The third quarter was certainly a challenging quarter both for us in the E&P sector as well as for many of you on the call this morning.

Declining commodity prices, hurricane disruptions, and financial turmoil have tested many companies in our sector.

I am pleased to report that St.

Mary is in solid shape in spite of these events.

As you will hear in a moment, we are well capitalized and have sufficient liquidity to meet our expected near-term needs.

Consistent with what we have been saying all year, our expected 2008 exploration and development budget will be within or near cash flow.

So you haven't heard St.

Mary talk about pulling back capital investments or coming to the market for financing.

As many of you who follow the Company closely know, we have talked for a while now about transforming the Company, theme one it is an early mover, and is focused on repeatable resource plays.

In recent weeks, a competitor of ours ours brought into the spotlight the Eagle Ford Shale in south Texas with an announcement of a successful horizontal test.

The Eagle Ford is a great example of how this shift in strategy has taken route at St.

Mary.

As you'll recall, the second half of 2007 we made two acquisitions in the Maverick basin, targeting the shallow gas play.

What we also knew at the time is that the basin had additional formations of interest including the Pierce Hole and Eagle Ford Shales.

We did our technical work early and have been building a position over the last 12 months in the Eagle Ford Shale through joint ventures and grass roots leasing.

Today we have the potential to capture a position in the Eagle Ford that could be in excess of 200,000 net acres, 65% of which would be operated by St.

Mary.

You should expect to see more of this from St.

Mary.

The early capture of new potential resources and with success in these emerging plays they will add to our growing, multiyear inventory of drilling projects.

I'll now turn the call over to our new CFO, Wade Pursell.

Wade joined us in September and we are very glad to have him onboard.

Wade?

Thank you, Tony.

Yesterday we released our quarterly earnings press release and financial highlights, where you can review our quarterly and years end results.

I am going to focus my remarks this morning on the results from the third quarter 2008.

Production for the third quarter of 2008 was 27.7 BCF equivalent which was slightly under our guidance of 28 to 29 Bcfe.

We estimate that we lost about eight-tenths of a Bcfe as a result of hurricanes Gustav and Ike, which would have put us at 28.5 Bcfe for the third quarter, in the middle of our guidance range.

Reported net income for the third quarter was $88 million or $1.40 per diluted share, the estimated income which adjusts for nonrecurring and certain noncash items was $75.4 million or $1.20 per diluted share which was higher than the First Call estimate.

There's three significant adjustments this quarter.

The noncash benefit related to the change in the liability related to the legacy NPT plant, bad debt expense stemming from the bankruptcy of Sim Group, and the loss related to the hurricanes.

The after tax deduct from reported net income for the change in the NPT liability was $22.1 million or $0.35 per share, and with the result of the decrease of the NPT liability between June 30, and September 30, due to a significant decrease in forecasted prices for oil and natural gas as of the end of the third quarter.

The after tax adjustment related to the Sim Group bad debt expense was $4.2 million or $0.07 per share, we had exposure to Sim Group who is a purchaser of a portion of crude oil prior to their bankruptcy for June and July production.

As a result, we recognized bad debt expense in the second and third quarter.

We don't believe we have any further bad debt exposure to Sim Group and we continue to work on collecting the amounts owed to St.

Mary.

Consistent we prior practice we adjusted for the impact of the hurricanes in the third quarter, the after tax adjustment of $4.4 million for hurricanes reflects the loss we expect to incur after insurance reimbursements related to the remediation, repair, salvage, and abandonment efforts related to our properties that were impacted by the storm.

The specific properties that were impacted were Vermilion 281 and our properties at Goat Island and Galveston Bay.

The reserves and production associated with these properties are not material to the financial position of the Company.

Discretionary cash flow for the quarter was $193.2 million or $3.06 per diluted share.

GAAP cash flow from operating activities if the quarter came in at $252 million.

LOE for the quarter of $1.57 per Mcf equivalent which includes amounts or workovers was slightly higher than we had guided for the quarter.

The shortfall in production related to the hurricanes helped push our per unit cost up slightly since there were fewer units in production that offset the fixed cost in our LOE structure.

For most of the quarter oilfield supplies and services were in high demand which resulted in LOE costs being at the higher end of our expectations and there was little release in the cost per services that involve fuel costs.

Transportation in the third quarter was $0.24 per Mcf equivalent, and the increase year-over-year is being driven by the change in asset composition and the associated transportation arrangement in the Gulf Coast and ArkLaTex regions.

While the transportation expense has bee increasing as a result of these new transportation arrangements the natural gas price we realized at the wellhead has also been increasing and offsets the increased transportation costs.

Production taxes for the quarter was $0.81 per Mcf equivalent which was lower than we had guided for the quarter due to lower commodity prices being realized in the period.

G&A for the third quarter 2008 was $0.87 per Mcf equivalent which was above the guidance we provided for the quarter.

Our G&A is largely comprised of fixed costs so the shortfall in production from the hurricanes pushed G&A up on a per unit basis.

Additionally parts of our G&A are tied to the profitability of the Company which was higher than what had been forecasted at the time guidance was provided.

Year-over-year we have seen an increase in G&A on a per Mcf equivalent basis due primarily to increases in compensation-related costs linked to increased head count and larger payments for the NPTs.

DD&A came in lower than we had guided to $2.61 per Mcf equivalent.

This is primarily related to the curtailment of production in higher DD&A per unit depletion pools as a result of hurricanes Gustav and Ike.

Our effective tax rate in the third quarter of 2008 was 36.8% which was om line with the guidance provided.

Current taxes comprised 12% of our tax expense for the quarter.

I will now spend a few minutes discussing our financial position and liquidity situation.

At the end of the third quarter we had 287.5 million in 3.5% convertible notes outstanding and 170 million drawn on our credit facility.

Our debt to book cap ratio stood at 31%, the convertible notes have a very attractive cash coupon rate and do not have any financial covenants associated them.

Barring something extraordinary, the first time that these notes could be put to it is April 2012.

On October 1, the borrowing base on our credit facility was redetermined by our bank group in an amount of $1.4 billion, secondary elected to stay with our commitment, amount of $500 million at that time.

Which we believe is sufficient for our near term use.

September 30 and October 28, we had 170 million and 198 million drawn respectively, so you can see we have a fair amount of room under the revolver.

The credit facility has two financial covenants, a total debt to trailing 12 month EBITDA limitation and a minimum modified current ratio multiple.

At quarter end our debt to trailing EBITDA was 0.56 times which is well within the limit of 3.5 times.

The modified current ratio was 1.77 which is well above the 1.0 times required by the credit facility.

The bank group is comprised of 11 banks led by Wachovia/Wells-Fargo, soon to be one apparently.

We have had no issues drawing on our credit facility to date.

We feel that we are well capitalized at this point and have some dry powder at our disposal.

With respect to hedging we were in a net liability position with all of our hedged counterparties as of September 30, which had been the case for most of 2008.

As a result of lower forecasted commodity prices we have moved recently into a net asset position with the majority of our hedging counterparties and actually have a total net hedge asset.

All but two of our hedge counterparties are in the bank group with a revolving credit facility and I might also add that the other two were participating banks in the first round of the capital purchases from the US Treasury.

We regularly review credit worthiness for our hedge counterparties.

Lastly our Form 10-Q with be filed with he SEC later today.

You can find more detailed information on our financial standing liquidity and hedging positions.

I will now turn the call over to Jay for operations.

Thank you, Wade.

Company-wide we are currently running 15 rigs, I will briefly cover the areas we are focused and making most of our capital investments.

Tony has already mentioned our involvement in prospective shale plays in south Texas.

In the joint venture, with TXEO and Anadarko we have discussed previously four horizontal tests have now been drilled and are at various stages of testing.

Two of these wells were horizontal reentry wells targeting the Eagle Ford Shale, while the Piersol interval was tested with one horizontal reentry and one horizontal grass roots well.

TXEO is the operator in the JV and they released information on these four wells in the October 20, press release.

I you will direct you to that for more details.

We are planning to drill our first St.

Mary shale wells in south Texas outside of the JV area I just discussed in the first quarter.

As Tony noted we have acquired a significant amount of acreage in the area.

At this point we think we have captured the most prospective based on our geologic model, and we will have some production data points across the acreage in the first half of 2009.

In east Texas St.

Mary is currently drilling its first horizontal Haynesville shale well which is located in Desoto Parish Louisiana in the Spider field.

The rig is currently taking core samples in the Bossier and Haynesville sections, and is expected to kick off the horizontal lateral within the next two weeks.

The well design calls for an approximately 4500-foot horizontal lateral.

The well should be completed early in January of 2009.

We have 50,000-acres in the Haynesville play and the first well is an important step in our development plan.

The results from our operating horizontal Woodford shale program in eastern Oklahoma continued to improve.

To date the Company has drilled and completed 24 wells that have meaningful production histories.

The average estimated ultimate recovery for the last 14 wells is 3.4 Bcfe.

The four most recent wells have preliminary EURs which are at or above that per well average.

The Company has previously guided to a range of 2.7 to 3 Bcf for a typical horizontal Woodford well.

Our completed well cost in the play for 4,000 foot plus lateral lengths vary from 4 million to $5.5 million depending on depth and number of completion stages.

We currently have three rigs working in the play and are also participating in a number of [Koner] operated wells.

Our plans for the next several quarters include simulfracing some down spaced wells which is an important next step in that development.

In eastern McKenzie county North Dakota, St.

Mary has a rig contracted to start drilling Bakken and Three Forks wells in our Bear Den prospect area in late November.

As we previously announced St.

Mary recently acquired 6200 net acres in Bear Den which brings our total acreage in that area to roughly 10,000 net acres.

The area around Bear Den is overpressured relative to some other parts of the play and we are encouraged by recent Koner operated wells that we participated in and around our acreage.

After a number of delays we do have results on three horizontal Bakken test wells we drilled earlier this year in the Company's Powers Lake and Stillwater prospects on the Montrail Burke county line.

At current commodity prices, basis differentials and costs, our Bakken completion results in that area do not indicate potential for acceptable economics.

I should note that law dated from the first of these wells confirmed the presence of a nice looking Three Fork section under the Bakken, several offset operators have made good wells in the Three Forks and that area, and that will be our focus for that area going forward.

Moving to our west Texas activities during this year the Company began testing the viability of 40 acre increased density Wolfberry oil wells at Sweetie Peck in the Permian basin.

The program included 15 wells in three pilot areas, early results from testing have been positive.

Performance of these wells has been similar to the wells drilled on 80-acre spacing.

At the time of the acquisition of the Sweetie Peck assets in late 2006 we did not place a large value on the 40 acre locations because we were uncertain how economic they might be.

We are currently working on our capital budget and plan for next year although we don't have any definite numbers to share with you today I think it is fair to say that with the addition of Haynesville and south Texas shale drilling in our portfolio, we have a very exciting inventory of opportunities to choose from in 2009.

With that I will turn it back over to Tony.

Thank you, Jay.

Yesterday we also updated guidance for the remainder of the year.

Our expected production range for the year now stands at 112.5 to 113.5 Bcf equivalent and reflects the negative production impacts for hurricanes Ike and Gustav.

At the midpoint of this guidance range, year-over-year production growth on retained properties will be 10% based on our exploration and development budget of $758 million which is near our expected cash flow for this year.

As Jay mentioned, we are right in the middle of our planning process for 2009.

What we can tell you is that we plan to have a program that will be at or within cash flow for next year.

We will update everyone in late December on our capital plans and production guidance for 2009.

Financially, St.

Mary is very strong at the moment, we have a fair amount of dry powder at our disposal and by a number of different metrics, we are conservatively levered.

I am confident that we will weather the financial upheaval that the broad economy is currently working its way through and when the storm passes, St.

Mary will be well positioned by virtue of its improved inventory, and strong financial position to grow significant value for our stockholders.

With that, we will turn the call over for questions.

(OPERATOR INSTRUCTIONS) We will pause for just a moment to compile the Q&A roster.

Your first question comes from Stephen Beck with Jefferies and Company.

Your line is open.

Morning.

Morning.

I have a couple.

Can you tell us how many acres you have in the Powers 8 prospect?

I think between Powers Lake and Stillwater we had about 25,000 acres.

Okay.

Looking at, haven't heard anything about Hanging Woman, is there any update to Hanging Woman and the test that you had there?

Nope, not really.

Okay.

And then I guess last, looking at the Haynesville, the horizontal, Desoto, can you tell us how the, results of the nearest horizontal and how far away that horizontal is from your current well?

There's a number of wells that have been completed around us.

I don't have an exact distance for you.

It is probably, I don't even want to speculate.

It's in northern Desoto Parish, so it is pretty close to a number of wells, as I recall looking at the map there were a number of southwestern verticals that were drilled in the area.

So, we think it is good area, it is in the core of the play.

We think it is a good spot to test.

Okay.

That's it for me for now.

Thanks.

All right.

Stephen, on the Hanging Woman, I think it is important to mention that that is not material to our forward plans and growth trajectory.

We continue to produce the field and we have seen production up tick of about 1 million a day or so for the year, but going forward, that is not going to be material to our growth rate.

Sure, understood.

Thanks a lot.

You bet.

Thank you.

(OPERATOR INSTRUCTIONS) Your next question comes from the line of Jack Aydin, with KeyBanc Capital, your line is open.

Hi, Tony.

Hi Jay.

Morning.

How are you guys.

I just want to do a little bit more into the Eagle Ford prospect.

Everybody knew that the formation was there, what makes it so attractive now, and also, we are hearing that there is some water issue involved there.

Can you elaborate a little bit more on it, what you see, what you know, there?

Well, Jack we are probably not prepared to give much of a talk about our geologic concept here because we still view it as a competitive play.

The water issue, I am not familiar with what people are saying about it.

I haven't heard that one.

Again, I think we probably reserve most of our comments here until we have got some well tests to talk about.

Do you have any tests, did you test any well there yet or no?

Well, we tested the wells with TXEO, which they have already released on those, if you look, they had a press release on October 20, they talked about those.

Okay.

Jack, both of those announced test, both at TXEO and also the others that were announced by Petrohawk are in reasonable close proximity to our current acreage position.

We think we are in a very good neighborhood but quite frankly, we are still going through a lot of the geologic work and understanding what some of these offset operators have delivered as far as their latest test results.

Okay.

I guess I will just say I mean you saw Petrohawk's announcement.

They talked some about their geologic ideas, we don't disagree with them.

I mean generally what they said is pretty much in conformance with our view of the pathology and the rock properties.

What is interesting to me is basically, if they were interested in the play, why would they announce the play, why wouldn't acquire more acreage and wait for an announcement?

That's what I am really puzzled with.

We asked the same question.

Okay.

And I'm not sure why they would other than they had their own priorities at the time.

We certainly wouldn't have shared that.

Okay.

Thanks, Tony.

Well, I guess I got what I wanted to get, thanks.

All right.

Jack, take care.

Your next question comes from Mike Scialla with Thomas Weisel Partners.

In terms of your Woodford wells, the 14 that had the 3.4 Bcf EUR, you got a pretty wide range of costs there, 4 million to 5.5 million.

What was the depth in general on those 14?

Were those the deeper and are you seeing higher recoveries as you go deeper, or I guess what I am really trying to get at is as you move east in the play what do you expect in terms of an EUR and a cost?

Well, no question as you move east it gets deeper and the costs go up.

I have seen it AFEs as high as 5.7 million in some of the play there, and we have, we have participated in a number of Koners over there we've had well costs well in excess of that.

The 4 million is really over, probably where you would say 9,000 TBD kind of numbers, and the 5.5 is probably more like 11.

There's some of that as the number of completion stages we are pumping as well so it is not just completely dead.

I have not gotten data to show a direct correlation between depth and EUR.

That's something we will be talking with the guys down there about.

We do believe that it is probably likely that EUR will go up some at higher depths but there's enough scatter in the data right now that with that number of wells, I don't think I can conclusively say that.

Is it fair to say as you move east, that 3.4 we might see more upside to and the cost might be on the higher end of that range you gave?

I am not going to forecast upside in the EUR but I can tell you the cost will definitely be on the upside -- on the high side of that range.

Okay.

At Sweetie Peck, if the 40s work over most of that area, can you talk about what the potential there might be and I know you had some issues with rigs over there a while ago.

How is that situation looking?

Well, we, let me I am going to take that in two piece, first of all there's 164 40s in the peak for Sweetie Peck.

We don't think all of those will drill out, but I think a good share of them will.

So I would say it is a nice addition and certainly something we will be focused on.

In terms of the rig there's a little bit of, we talk a lot about rig issues last year, and our rig count was going up and down.

If you actually looked at how many wells we drilled we drilled exactly the number of wells we said we were going to drill in the plan.

Somehow or another in our communication of the rig issues we were having, people got the idea that we were having difficulty and slowing down or something, and in fact we got exactly the number of wells drilled we said we were going to drill in plan.

Our rigs there are very stable, we have pretty much a Nabors rig fleet there and they're doing a very good job for us.

We will just see what happens here as price move down some.

Obviously we are hoping costs move down some as well.

But the 40s that we drilled so far are going to be economic at these prices.

We are happy with that.

Mike, I think most of the rig issues here, remembering we are all from last years we were ramping that program up and sorting through the better rigs in the basin but we have a very strong rig fleet now, very good crews as well as a St.

Mary drilling group that is providing supervision for program.

Okay.

Great.

Thanks.

Just one last one on the Bakken play can you talk a little bit about what you are seeing in that Bear Den area, why you, like how you mentioned some other wells that are being drilled there, you say in terms of rates or anything else as how that compares to say your northern acreage?

Well, the Bear Den area looks very good.

We participated in 10 or 12 Koner wells in that area, at various levels of working interest and they have their real nice high IPs and pretty decent 10-day rates you see in the average of the play.

The area up north, the Burke trail we never did see the IP rates that the rest of the play was seeing.

It is not overpressured like the Bear Den partial area, and there's a lot of water production as well.

So we just didn't get the kind of tests that we think you need to support economic, certainly not at these prices.

I guess the one point I will continue to make is that you guys need to be watching differentials in the Bakken.

New oil coming out of the Bakken right now has got about a $20 off NYMEX differential.

When you're at $65 oil prices, you are talking about $43 net backs.

So there's a lot of these marginal wells that just don't work.

We are clearly looking at the strip and looking at our best acreage and Bear Den has some very good numbers, plus 600-barrel a day kind of IPs out of a lot of the wells there, and we think that's going to be a very attractive area.

In terms of the Three Forks potential on that northern acreage, you mentioned there are a couple of wells that looked good around you.

Is that anything you can elaborate on?

Yes.

Continental drilled that Omar well which just offsets our Stillwater acreage the IP of 1200 barrels a day in the Three Forks.

So there's some really good looking Three Forks stuff up there.

We just haven't tested it yet.

We logged pay but we elected to complete the Bakken there, so I think what we will be doing is going back and relooking at the Three Forks and trying to get some offsets there.

Thank you.

You bet.

Thanks, Mike.

At this time there are no further questions.

All right.

Well, we certainly appreciate everyone joining us this morning.

St.

Mary had very, another very solid quarter, even with hurricane impacts.

We continue to be a financially strong Company with significant dry powder for future opportunities.

We have a growing inventory of significant resource plays that we are very excited about, and at this point, I am very pleased with the Company's transformation, and very excited about the opportunities in front of us.

With that we would like to thank you all for joining us today.

This concludes today's conference call.

You may now disconnect.