SM Energy Co (SM) 2002 Q4 法說會逐字稿

Good morning.

My name is Tamara and I will be your conference facilitator today.

At this time, I'll like to welcome everyone to the St. Mary Land & Exploration Year-End 2002 Earnings Conference Call.

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

After the speaker's remarks, there will be a question-and-answer period.

If you would like to ask a question during this time, simply press star then the number "1" on you telephone keypad.

If you would like to withdraw your question, press the "#" key.

Thank you Mr. Hanley, you may begin your conference.

Thank you Tamara, and good morning to all of you joining us by phone and online to St. Mary Land & Exploration Company's year-end 2002 earnings conference call.

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

Except what 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 and 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.

Online this morning are, Mark Hellerstein, Chairman, President, and Chief Executive Officer;

Ronald Boone, Executive Vice President and Chief Operating Officer, Richard Norris, Vice President-Finance, and myself Rob Hanley, Vice President, Business Development.

I will now turn the call over to Mark.

Thank you.

Good morning.

Our financial markets were characterized by scandals, scoundrels, and instability.

The year 2002 reflected a return of some stability to the oil and gas markets, with NYMEX prices averaging 3.25 for MMBTU, and 26.06 per barrel, down approximately 18% on a realized MCFE basis.

For St. Mary it was a year of substantial reserve growth.

We had solid drilling results overall, led by the Mid-Continent region at the North East Mayfield play.

Acquisitions were major growth components in 2002, with the closing of the $69m Burlington resources, Williston transactions; the largest acquisition in our history, together with excellent niche acquisitions in the Arkoma through the merchant resources acquisition and then the East Texas Horizontal Lime play at Huxley.

The $68m Flying J acquisition was announced in 2002 and closed in January of 2003.

After the Flying J acquisition, our reserves are 558 Bcf equivalent.

The Rockies are 48% of our reserve base and we are 48% oil.

During the year St. Mary completed $100m, 5.75% convertible note offering and moved to the New York stock exchange.

The instability in the financial markets placed increased pressure for governance and oversight by our independent directors.

We grew our production 2% to 55.1 Bcf equivalent, despite no significant acquisitions until December, when the Burlington resources acquisition closed.

Net income was $27.6m or $0.99 per basic share, third best in the history of the company; this compares to 40.5m or $1.45 per basic share in 2001.

Discretionary cash flow was $118.8m or 4.26 per share down from $138.6m in 2001.

The average realized price decline to 11% and $3.37 per Mcf equivalent.

Unit cost overall were stable for the period as lease operating expenses including taxes declined $0.10 to $0.92 per MCFE.

DD&A including impairments increased $0.04 to $0.99 and G&A increased $0.04 to $0.26 per MCFE.

Oil and gas reserves grew by 28%, 491 Bcf equivalent.

The company replaced 305% of its 2002 production and in all includes refining cost of $1.15 per MCFE.

We are pleased with these results and believe they compare favorably with the industry results.

For the quarter, we earned $7m or $0.25 per basic share compared to $1m for the fourth quarter of 2001.

Cash flow for the fourth quarter increased to 13%, $31.2m.

Average daily oil and gas production during the fourth quarter of 2002 totaled to 156.8m cubic feet a day, up 4% from the comparable period in 2001.

In the fourth quarter, oil and gas production cost including taxes declined $0.18 to $0.89 per MCFE.

G&A increased $0.16 from $0.10 per Mcf reflecting unusually low G&A cost in the fourth quarter of 2001, as only nominal bonuses were paid in that year and the accrual was reversed.

DD&A was $1.06 per MCFE compared to $0.97 in the fourth quarter of 2001.

Fourth quarter results reflect a pre-tax loss on the sale of the Flour Bluff field of $2.6m.

I will now turn it over to Ron Boone, our COO, who will discuss activities for 2002 as well as looking forward to our budget for 2003.

As Mark mentioned, 2002 was a busy and successful year for St Mary.

We had a very solid year growing as reported in detail in our January 27th release and as the largest acquisition in the company's history, closing the Burlington acquisition on December 3rd.

We followed the closing of Burlington 10 days later with the announcement of the Flying J acquisition on December 13th and subsequently closed that transaction on January 30th of this year.

There were 41 new completions in the Mid-Continent region in 2002 and northeast Mayfield Field in Beckham County, was a major area of focus in 2002 with completion of 10 new wells during the year with average IPs of 6.75m cubic feet a day.

Completions in the fourth quarter included the Anderson 119 where we had 57% of 5.3m a day and the Brother's 220 where we had 34% for 11.7m a day.

Our Coal County play in the Arkoma Basin was also active in 2002 with the drilling of 10 successful wells including the 100% interest, 81.36 in the fourth quarter or 1.6m cubic feet a day.

There were 15 successful completion on the ArkLaTex Region during 2002, fourth quarter completions include the [Dupree] #1 where we had 90% interest at 2.4m a day and the DSK #1 where we had 39% at 2m a day.

Twelve successful completions in the Permian in 2002 included the [Telepart] #1 where we had 45% in the fourth quarter for 220 barrels of oil and 191 Mcf per day.

At Judge Digby Field the Majors #4 where we had 11.5% established production in the deepest field place discovered today in the Judge Digby Field.

The first field completion in the Tuscaloosa C3 and C4 [sand] intervals tested at 36m cubic feet a day.

Company widely participated in just under a 100 wells in 2002 with an 83% success rate.

Both the Burlington and Flying J acquisitions were very major transactions for the company.

The Burlington packages are perfect geographical fit with our existing Williston presence with extensive overlap of Burlington ownership in St. Mary operated properties and vice-versa.

But, primarily, operated package is very concentrated in a very manageable well count with high ownership and high quality long-life properties and represent the 14% increase in St. Mary's November 2002 net production.

The Flying J assets are a less concentrated package with net reserves and production similar to the Burlington assets in larger number of well bores.

The Williston portion of the package, which represents 50% of the total, is again an excellent fit with our existing mass presence.

The remainder of the value is split between the Powder River, Win River, and Green River Basins and represents a significant increase in our presence in those operating areas.

All of the acquisitions are 92% developed as evaluated by St. Mary.

It included an extra of 300,000 net acres of undeveloped oil and gas leases in the Green River, Powder River, and Williston Basins alone.

The $225m capital budget for 2003 represents a 16% increase in the 2002 spinning levels. 40% of the budget is allocated to acquisitions of which over 80% has already been identified and will close in the first quarter of this year.

The drilling portion of the budget represents a 27% increase over 2002.

The largest change in that budget allocation will be in the Rockies with budget is spinning nearly doubling over 2002 as a result of both Burlington and Flying J acquisitions.

The Rockies at present managed by the [Billings] office will represent 20% of the total budget.

The Mid-Continent also representing 20% of the budget is projected to be flat with 2002 spinning levels.

The Gulf Coast and ArkLaTex will both represent approximately 8% of the budget and in additional 4% of the budget is allocated to large potential players, primarily unconventional gas.

We have a large inventory of opportunities including a number rising from the Burlington Flying J and Huxley acquisitions made in 2002 and early 2003.

Some of the more significant projects includes 16 wells in North East Mayfield, 10 wells near Arkoma Basin, 9 wells in the Granite Wash in Oklahoma, 13 operated new wells and reentries are planned in the Williston as well as seven Green River test, 6 Odom Lime wells at Fort Chadbourne, and four injection wells of Shugart, water flood project in West Texas. 35 wells are planned in the architect region including 10 horizontal James Lime wells in South Texas -- excuse South Louisiana and offset to last year's [politic] highland discovery will spread in the first quarter.

And two new wells are planned at Judge Digby including a [wildcat] testing a new forward block on the South West plank of the field.

At our Hanging Woman Basin coaled methane project where we'll control 143,000 gross acres in the northern part of the Powder River Basin.

We conducted two power projects in 2002, testing in the lower most Robert's coal in continuing.

Future development of this 150-200 BCF project where St. Mary controls approximately 90% will hinge on future gas prices, and the favorable EIS decision from the BOM on coal bed development in Wyoming and Montana.

We have reached total depth and set [casing] at 16,000 feet in our Duschene Deep prospect in Duschene, Utah.

Production testing of this basin, centered gas prospect targeting cretaceous age [inaudible] sandstones will begin in the first quarter.

St. Mary controls approximately 12,000 acres of the Duschene prospect area with an ultimate interest of 66%.

Our Carrier Cotton Valley re-project in East Texas.

We are actively marketing the industry partners with the intention of participating for 25% interest in this high risk, high reserve potential exploratory test.

We presented the prospect at the North American prospect Expo in January and it had a number of showing space on interest generated at May.

We have budgeted well at Carrier in 2003.

We entered 2003 on positive note.

Our financial condition is excellent.

Oil and gas prices are high.

We have already closed approximately 73m of our $90m acquisition budget.

Production has ramped up dramatically already as a result of excellent drilling results in North East Mayfield and the closing of the Burlington resources and Flying J acquisitions.

We have an outstanding inventory prospects to be drilled.

Rig and other service costs are moderate and the rig count is now increased to the extent many had expected.

A long-term outlook for gas prices is excellent.

Production is forecast to grow to 70-75 BCF equivalent up from 55 BCF equivalent in 2002.

Based on NYMEX strip price of 414 per MCF equivalent, we would realize approximately 404 per MCFE after hedges.

Assuming this price tag, operating expenses including taxes are forecasted a $1.22-1.32 per MCF equivalent and G&A is forecasted to $0.21-0.25 per MCF equivalent.

Based on these assumptions discretionary cash flow is forecasted at $5.40-5.60 per share.

With that we will open it up to questions.

At this time, I would like to remind everyone in order to ask a question please press star then the number "1" on your telephone keypad.

We will pause for just a moment to compile the Q&A roster.

Your first question comes from Joe Allman of RBC Capital Markets.

Hi.

Good morning guys.

Now that you have got your oil at around 48% of the total portfolio, given certain goal would you like to keep it in a nice kind -- close to 50-50 balance or would you prefer more of gas or do you have preference?

Although in a strategic sense we would be biased towards gas because in the longer term we think of its environmental qualities and North American market might be more favorable.

We basically look at our decisions on a micro basis and we have found that we can get much better rates of return on acquisition side on the oil side and that's why we have made those acquisitions.

We will, I think continue to look at things in micro sense, in terms of drilling adds, the gas side has been more significant than the oil side.

Okay.

Thank you.

And then Mark towards the end of your comment, just before you opened up to Q&A, you said certain price of gas that you would realize, I think you said 404, for MCSE after hedging?

Yeah, the impact on the Imax basis.

But, what was the pricing you were using the price tag?

That was 414, just to give you a little more flavor of it.

We were about 35% hedged on gas at 4.25 in Imax and on oil we are a little over 50% hedged about $26 in Imax.

Could you talk about -- what was your cash position at yearend and what is it now?

Our cash in equivalent at yearend was $12m, we currently have about 70, I believe in debt outstanding, and that's after we did the Flying J acquisition.

Current cash had come down to nominal amount of around 2-3m.

Thank you guys.

The next question come from Larry Busnardo of Petrie Parkman.

Good morning.

Now that you have reached TD at the Deep Duschene prospect, what would be the timing of the testing process be?

And then how soon could that be hooked up for production assuming that it's successful?

Our plan is to actually have a pipeline to the well before we start completion.

We have seen on a number of these type gas and reservoirs that shutting those wells in after you have stimulated them and start with your initial completion is just because of that.

So it will be hooked up to sales almost immediately, it will be an extend completion because it is a large gross center of all and typical of reliable place there that it will be multiple fraction.

We are in the process of designing some of that, so it will be several week completion and then we will be selling gas basically from day one.

Would you, with the plan going forward, again assuming that if successful to continue to drill, would you drill a second well immediately following completion of this one?

Yeah, basically we have on returns of our agreements we have six months to spud our second well, so that's the timeframe we definitely required to move forward on and we will be prepared to do that when we have enough information of this well to encourage us.

Great.

And then just one last one.

At Judge Digby could you give me what current field production is?

You know, I have might looked it up.

The last number I saw was about 180m.

It's unfairly volatile, but that number is pretty solid.

Our net production is actually come up as a result of the some of the initial completions in our interest.

Okay.

Great.

Thanks.

The next question comes from Ellen Hannan of Bear Stearns.

Ms. Hannan your line is now open.

Hello.

Hi Ellen.

Hi, sorry about that.

Mute button got in the way.

Just a couple of question, one, want to make sure, I am clear on your production guidance for '03, does it include all the acquisitions?

Yes it does.

You said about 80% of which are complete or will be complete by the end of the quarter?

Right.

Okay.

Secondly on the Hanging Woman, do you expect to be able to have any kind of activity there in '03?

We don't have a lot of activity planned, we actually are evaluation Roberts coal theme, which is fairly critical in the economics and we did a new completion there.

The first completion we had some issues relative to some coal finds and this one where we're having good water production and we're just starting to see a little bit of gas and we want to evaluate that first and then we have to get the record of decision on the [AISs] and so we don't anticipate that that will have a significant amount of development activity this year.

Okay.

And lastly on the east Texas I think you called it the career prospects.

Could you talk about the kind of the cost and reserve side potential and what percent interest you might retain?

It's roughly a $5m test.

It's a deep Cotton Valley, very large what we believe is a platform reef and it has reserve potential in our opinion conservatively in the 1/2 Tcf to 1 Tcf may be larger if you wanted to get a little dreamy.

It's fairly high risk.

It's a long way -- so many things that's really identified the productive potential.

We've done 3-D over the whole thing and we've had a lot of technical work that suggest that it's a very viable concept.

But the real risk is porosity development that the depths of 16,000-18,000 ft in those Cotton reefs.

We believe there is a very solid technical reason why there is good porosity development, but ultimately it's only going to be resolved with the test.

And our intention is to keep it about 25% of that.

We think that we can mange that and with discovery it could be obviously a very, very significant for St. Mary.

Okay.

Great thank you very much.

At this time I would remind every one, in order to ask a question please press star then the "1" on your telephone keypad.

You next question comes from Mike Scialla of A.G. Edward.

Good morning Mark.

Good morning, Mike.

Question on your fourth quarter numbers.

You had mentioned in your product guidance that you would realize a pre-tax gain when you liquidated interest rates slop.

Did that actually flow through the numbers, because of that I didn't - it is the way you recognize them?

Because in the prior quarter in the third quarter we had recognized an unrealized gain.

We had to do a mark-to- market on that, that's not considered qualified hedge.

And so we had recognized about a little over $4m unrealized derivative gain in the third quarter then we basically liquidated it and realized that gain and actually there is a slightly less net amount in the fourth quarter.

So the net amount in the fourth quarter was in several hundred thousand to the negative but wasn't a real large number.

And then I may have missed it but when you announced your crude reserve did you give a SEC pretax PV-10 for those reserves?

We didn't -- I can get that for you just hold on.

It's $824.8m.

And what price was that based on?

On the oil side it was 31.20 and on the gas side 474 both the NYMEX.

Okay and then one last question.

On your Burlington acquisition.

Can you give us some kind of sense of how many prospects you might be able to identify with your 3-D seismic?

I think it's pre-mature.

We obviously the [inaudible] office has been pretty much overwhelmed by both Burlington and Flying J. We haven't been up there and had a review.

We are actually scheduled to be up there later this week and had to re-schedule, so that isn't something that we had a chance to determine.

Okay.

We have scheduled believe, I want to say relative to those two acquisitions, I want to say six 3-D seismic surveys this year.

Thank you.

Our next question comes from Den Morrison of Apirean (ph).

Hey Mark.

Well Den.

The acquisitions that you've got pending here in the first quarter can you characterize those at all?

Basically we have one small one that's in the main range but we did close one for additional interest at Fort Chadbourne.

Essentially is almost all of the non-operated interest on the field that we had acquired as part of King Ranch and the amount was just over $5m.

Okay.

And the other is Flying J, which we talked about.

Right.

Do you anticipate selling any assets in the current environment taking advantage of the market that seems to be upon us.

But we're going to do some clean up.

We actually have a couple of smaller packages in the market place right now and we have a company-wide process in progress to identify some other kind of clean up type things because we agree we think this is a good time to clean up the portfolio there.

Yes.

Any idea on magnitude, dollars, or reserves?

I don't think it's going to be a very large.

It's going to be more -- smaller value properties and hopefully quite a few properties but not lot of value.

Okay and the PV-10 number you gave a minute ago was that a pre-tax number or after-tax number?

That was a pre-tax number.

Okay great Thanks.

We have a follow-up from Ellen Hannan of Bear Stearns & Co.

Thank you I just one last question I forgot to ask.

Could you give any guidance on in '03, Mark on how much of your tax do you expect to be deferred?

We really have not...

I mean you've lost in a substantial amount of your prices through your hedging.

So would you kind of speculate?

Our current projection is about 50-50.

Okay.

Thank you very much.

We have a follow-up question from Joe Allman of RBC Capital Markets.

Hi again.

On the [SUC] PV-10 number do you have the after-tax number for us?

I don't have that at my fingertips.

And on the same prospect could you - what's the potential size there?

And then could you describe that a little bit for us?

And you know, how many wells might you drill.

If it's successful how many wells might you drill in that prospect to prove up the potential?

Well we would like to talk that a lot.

We consider a tight hold.

It's a competitive area.

Its base is [Syner] gas.

There is a lot of gas employees we control 12000 acres and we'll have ultimately 65-70% in the acreage block.

So you can do some numbers on back of envelope to yourself but we -- really aren't talking about the law.

It is potentially a significant development.

In terms of -- so in the production testing what are the -the potential risks and what's going to happen to make it successful?

What gets hampered if you could describe that?

Well these are T deep type gas ends -- and the hole -- the major risk is whether you have adequate permeability and whether you are able to successfully complete them with a newest fracture technologies.

We have a tremendous amount of experience of that.

These are very similar reservoirs to a lot of things we're doing in Oklahoma.

We have encouragement with both our drilling shores and our well logs but really until you perforate and start your stimulations the risk is that you don't achieve enough producing rate to be commercial with fairly significant low cost.

And that's the risk in many of these types of [plays].

There is a lot of gas employees and if you're successfully able to unlock it -- you're talking about large reserves and large numbers of wells but the first challenge is to make it commercial completion, which means you have get flow rates probably in excess of 3m cubic feet a day and some fairly decent well have net backs which is a problem in the Rocky Mountains today.

And your prospect and I think you previously talked about that and then if that's the same one I remember one time the closest analogy was Indonesia.

Do you have any closer analogy to that?

Are you talking about Carrier?

Yes Carrier, yes.

Actually there is -- another platform reef that was identified about 80 miles to the south-west that reef did not have to cut for porosity development that we were hoping to get at carrier, but it certainly does demonstrate that the environment for the deeper water and the larger reefs is definitely demonstrated and viable.

So we do have a little more encouragement, but again that one large unknown.

Thank you.

Next question comes from Jack Aydin of McDonald Investments.

Hi guys.

Good morning Jack.

Mark your production taxes in this fourth quarter were down nicely.

Is that due to the mix or something different?

As a percentage wise they were -- you know it looked like they were down?

Jack, we got a big credit in the Gulf Coast area on some taxes that we previously paid.

Okay.

Going forward what kind -- are we going to get credit or should we go back to the old rate?

I think the old rate is fine.

We don't have a new rate, because this is a one-time credit that we received.

How about your DD&A?

It looks like, going forward, it looks like a little higher than used to.

Is that due to the mix?

Yeah.

I think one of the things when you look at the Williston Basin, previously we had a very low rate there, kind of in the -- it isn't exactly pretty close -- probably in the $0.85 range.

With the acquisition of Burlington and Flying J, both of those are a little over $1 type rate, and so when you do an overall average that brings up the rate on every thing in the Williston and then our Gulf Coast rate went up a bit.

Obviously, finding cost in general over the last few years have increased as cost and prices have gone up.

I will get in the -- offline and ask other questions.

Thanks.

Mr. Hanley, at this time there are no further questions.

Do you have any closing comments?

We might wait for Jack to come back on if he had another question.

At this time I would like to remind every one, in order to ask a question please press star then the number "1" on your telephone keypad.

Your next question comes from Larry Busnardo of Petrie Parkman.

Yes, just a quick follow-up.

On the guidance for '03, how much of that is related to acquisitions other than the Flying J?

The Flying J was just under $70m and we had $90m total acquisitions.

And then we have also closed, we mentioned the Fort Chadbourne.

It is not a lot.

So it is minimal.

Okay, thanks

You have a follow-up question from Jack Aydin of McDonald Investment.

Hi Mark, you mentioned that your debt is 70m at the year-end.

Is that you paid down some of that $99m that you borrowed or what?

No, no.

I am sorry Jack.

The 70m is on our bank line after the Flying J acquisition, not at year-end.

It was after the Flying J acquisition.

So your long-term debts at the year-end, what is it?

At year-end it--

$114m.

Yes, $114m.

Thanks Mark.

Mr. Hanley, there are no further questions.

Do you have nay closing comments?

Mark does.

Hi again.

Thank you for joining us, and we appreciate your continued interest in St Mary.

This concludes today's St. Mary Land & Exploration year-end 2002 earnings conference call.

You may now disconnect