SM Energy Co (SM) 2005 Q1 法說會逐字稿

Good morning. At this time I would like to welcome everyone to the St. Mary Land and Exploration First Quarter 2005 Earnings Release Conference Call. [OPERATOR'S INSTRUCTIONS]. After the speakers' remarks, there will be a question and answer period. [OPERATOR'S INSTRUCTIONS]. Thank you. Mr. Hanley, you may begin your conference.

Good morning to all of you joining us by phone and online for St. Mary Land & Exploration Company's First Quarter 2005 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 of Investor Relations. I will now turn the call over to Mark.

Thank You, Bob. Good morning. St. Mary is pleased to report record earnings production and cash flow for the first quarter of this year. Recent horizontal drilling success in Centrahoma opens up a significant new multi-year period for the company. For the third straight quarter, we have shown sequential production growth.

First quarter daily production is 6% higher than the December quarter and 13% higher than the March 2004 quarter. Although, we have seen cost increase somewhat, margins have increased more rapidly. Compared to the prior year quarter, net revenue for Mcfe has increased 35% while cash margins after LOE, and G&A has increased 43%. Although we have see F&D costs increase, our returns remain excellent. We have prepared three-year drilling lookbacks using actual historical data and projections for future data based on year-end engineering and end-of-the-year strip pricing, which happened to be lower than today's strip for wells completed or P&A.

For the three years combined the drilling results generated a 26% compounded rate of return of the three-year payout. These results include a complete well costs, geological and geophysical costs, exploration overheads and leasehold costs. For 2004, drilling activities, the rate of return was 25% and that was despite a disappointing year at Northeast Mayfield. This is also consistent with our financial statement, return on equity of 29% for the quarter.

Net income for the quarter ended March 31, '05, was $35.1 million or $0.54 per diluted share compared to $21.4 million or $0.33 per share for March quarter 2004. Discretionary cash flow increased by 62% to $91 million. Production increased 12% to 20.6 Bcfe. Production increased 1.03 Bcfe at the Constitution field due to the Paggi-Broussard well; 0.85 Bcfe at the Bakken play. 0.35 Bcfe at Vermillion 273 and 1.26 Bcfe due to the three acquisitions Goldmark, Borders, and Agate. Although our Northeast Mayfield is down from one year ago, our net production has remained relatively flat for the past few quarters. Judge Digby declined 0.39 Bcfe. The average

price increased 35% to $6.78 per Mcfe, while our cash margin increased 43% to $4.93.

Unit costs increased somewhat, as production expense, excluding taxes increased $0.15 cents to $1.07. Reflecting both inflation and the fact that oil as a percentage of production grew from 37% to 42%. Also LOE increased about $0.08 per Mcfe in the first quarter relative to the fourth quarter of 2004 due to higher workover expense. Most of this was in the Rockies and was associated particularly with about three wells.

In addition, we had higher LOE expense at Judge Digby. These items we don't expect to be necessarily recurring in the future. So we think this quarter is a little higher than normal. Taxes increased $0.13 per Mcfe due to higher prices. DD&A increased significantly to $1.46 and G&A expense declined $0.01 to $0.29 per Mcfe. 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. The Agate acquisition closed as planned with $41.9 million booked alone gas properties. Reserves were approximately 23.3 Bcfe. The company executed and amended and restated credit agreement with a five-year term, the initial borrowing base under the facility was calculated as $400 million, when our outstanding loans are less than the 50% of our calculated borrowing base, the interest rate is LIBOR plus one percentage.

With that, I will turn it over to Doug to give an operations update.

Good morning. I would like to review our first quarter operating, beginning with the Gulf Coast and Permian regions. We have one rig running in the Permian, while we have drilled and completed injector wells at the Shugart Delaware unit. We are now injecting 2800 barrels of water per day at Shugart. We have 5 wells remaining to be drilled to complete the water flood pattern and finalize the flood. The rig is moved to partly Delaware unit where we are drilling the fifth well of our 11-well program.

In the Gulf Coast, Judge Digby field is currently averaging 97 million cubic feet per day, gross of approximately 9.5 million cubic feet per day net. The possibility exists of additional Grassroots well in the southern portion of the field in 2005. A rig is on location in Chandeleur Sound Block 55, where we will operate the drilling of 2 to 4 prospects with a 50% working interest. We also plan to spud a well in West Cameron Block 542 in May, where we will operate with 35% working interest.

All of these prospects are 3-D seismic projects with direct hydrocarbon indicators. In the ArkLa Tex, we have a rig running at the Huxley field in the James Lime horizontal play and plan to continue our horizontal program with Spider after finalizing the current well. We hope to pick up an additional rig to develop cotton valley and Travis peak reserves of Box Church field. At Elm Grove, we have interesting two non-operating rigs developing cotton valley and Houston reserves. The Rockies continue to be one of the company's most active areas with the Hanging Woman Basin, CBM development, Vertical Red River play, and horizontal Bakken development, all moving forward.

At Hanging Woman Basin, we drilled 20 wells in the first quarter and expect to drill approximately 130 wells in the remainder of the year. Our drilling plans include a sufficient number of fee in state locations to provide flexibility while waiting to obtain Federal permitance. The project is very early in the watering phase with current production averaging approximately 1.6 million a day, which is higher than the Netherland, Sewell forecast. Horizontal Bakken locations completed in the first quarter include the Franz 2-15H flowing 490 barrels of oil per day; the State 4-16H at 600 barrels of oil per day; Lowell Larson 12-22H with 320 barrels of oil per day. Total net Bakken production was approximately 2050 barrels of oil per day in first quarter as compared to 975 barrels of oil per day in the fourth quarter of 2004. We have two operator drilling rigs running in Bakken as well as two operator reentry rigs. We have completed six Bakken or in the process of completing six Bakken reentries in North Dakota to date. The Mondac Federal 328 has the largest cumulative production, having produced 19000 barrels since 12/29/04 with a current rate of 110 barrels of oil per day. The Flattop Bute

is producing 100 barrels of oil per day after being put on pump last week.

Four of the reentries are currently being fraced, cleaned out, or put on pump. An additional 25 reentries are being identified in North Dakota. In the Big Horn base, we are preparing to spud the first well of a three-well program at the recently acquired Fourbear field. In the Mid-Continent, net field rate at Northeast Mayfield stabilized at 18.7 million cubic feet equivalent per day in the first quarter, as compared with 18.5 million cubic feet equivalent per day in the fourth quarter of 2004.

Significant completions at Northeast Mayfield include Parks #1 at 4 million cubic feet per day and the Wanda #1 at 8.8 million cubic feet per day. Our expectation for the remainder of the year is to have two operator rigs and two non-operator rigs at Northeast. We are very excited about our recent horizontal Cromwell test at Centrahoma field in the Arkoma Basin. Since 2001, the Mid-Continent region has established a core position of 36000 gross and 20000 net contiguous acres through leasing and niche producing property acquisition. The existence of widespread gas saturation has been established in the Cromwell with vertical production in a total of 18 sections. St Mary's average working interest in the 18 sections is approximately 80%. And additional 19 sections to the east are also viewed as having potential for Cromwell development where we have an average working interest of approximately 50%.

The vertical Cromwell producers have average initial rates of 500 to 700 Mcf a day and are expected to produce 0.5 to 0.7 Bcf per well.

The first month's rate on our initial horizontal test was 2.8 million cubic feet per day, which implies an ultimate recovery in excess of the 1.5 to 2.0 Bcf we are using in our development economics. While sand thickness varies over the Company's leasehold position, it is expected to take on average four wells per section to develop the reserves in the Cromwell. In addition, the gas saturated Wapanuka formation is present under the acreage position and has produced from vertical wells in the area but is less well defined. We are hopeful the horizontal drilling and completion techniques employed in the Cromwell will unlock the Wapanuka potential as well. Furthermore, the Company has established economic vertical production from the Woodford Shale on this acreage position.

To further delineate the extent of the play and the impact of horizontal development on the various formations, approximately 8 to 10 horizontal wells will be are drilled prior to year end. Given continued success, we plan to ramp up to a three-rig program in 2006 with 24-30 horizontal well completions expected. While still early, the results are extremely encouraging and we have every expectation that these efforts will result in a multi-year development with substantial volume additions over time.

Thank you Doug. We are pleased with first quarter results on several fronts. Not only do we have record of production and financial performance as well as good drilling results to date but we believe our horizontal Cromwell success opens up a very significant play for the Company. We will also be testing the Wapanuka and Woodford Shale in the same 20,000 net acres that we control with the similar horizontal technology. St. Mary's inventory of quality plays has never been better. We have multi-year plays in the Bakken, Northeast Mayfield, Red River, and Cromwell as well as the long-term project of Hanging Woman. We are fortunate to have a wealth of organic opportunities while in a high oil & gas price environment. With that we will open it up for questions.

[OPERATOR INSTRUCTIONS] Dan Morrison, Aperion Group

Could you elaborate a little bit about -- you mentioned a vertical Woodford Shale well, was that a recent completion?

That was about 6 months ago and it

in the 600 Mcf a day range and it has been on a very shallow decline. It's making about 430 Mcf a day currently.

And you said you plan drill about, was it a -- 11 or 14 horizontal wells in that area this year?

I think 8 to 10 is a good range for the remainder of the year.

We test each of those different geologic concepts with those wells.

We will. The majority of them will be in the Cromwell, but we are going to test the Woodford and Wapanuka with horizontal wells.

Alright. We will keep an eye on it.

Larry Busnardo, Petrie Parkman

On the Cromwell play, can you just give us an indication of what the difference in well costs, vertical versus horizontal?

We were drilling completely in the vertical wells for about $850,000 and the horizontal well, you know we have one data point but given how that well drilled and our expectation going forward, we are assuming about $2 million completed well cost. We think there may be some efficiencies we gain over time but those efficiencies may be offset by slight cost increases over time as well. So $2 million looks like a good number.

Okay. How many wells do you plan on drilling this year in the area both and then break that out vertical versus horizontal?

We have -- we just started a vertical Cromwell test, and we are in the process of attempting to pick up a second rig, but I don't have the exact split Larry, but the expectation would be -- the program will be skewed heavily towards horizontal and it may be that by mid-year or later in the year, we are drilling exclusively horizontal well. That'd be my expectation, if it continues to work.

And that's on the 19 Sections to the East, are you still developing the ones I guess primarily the 11 sections?

Yes, there is a core area that's on structure. Centrahoma is an oil producing field that's been around for decades and produce from very shallow intervals, as nearly as shallow than few thousand feet down to this, this depth interval we are looking at which by the way in the -- the Wapanuka is about 6,500 feet deep, the Cromwell is about 7,000 and the Woodford is about 7,500 feet deep, but Centrahoma proper has produced for a long, long time from different horizons. Our

guys saw the resource base that was present here and as I mentioned put through a series of acquisitions and leasing, put together a great position that basically covers the entire structure and then moves off structure to the east where we see some additional geological events happening. That Eastern portion is less well defined, but certainly we are pretty excited about the prospectivity of it. But the core area covers about 18 sections. We drilled in 11 of those, we've drilled Cromwell test in 11 of those but Cromwell production has been established in total of 18.

Okay, and then on the Woodford wells 8 to 10 this year, can you just give us an indication there as well what the cost -- I mean the initial cost that you make for you to drill those and then potentially

do you have an estimate on those?

There is actually 8 to 10, that's the total number of horizontal wells we planned to

and that's a combination of Cromwell, Wapanuka and Woodford. We have currently one data point, albeit a good data point, that we have an economic well just from a vertical standpoint that was completed with the conventional geo

. So, we think horizontal drilling in the Woodford should enhance that production, but we'll have a couple of data points hopefully -- in the next 4, 5 months we will have a couple of wells down and it will be early but we will at least have IPs on --

couple of Woodford horizontals, 5 or 6 additional Cromwell test and one or two Wapanuka tests for the remainder of the year.

Okay, and just looking at the production mix for the first quarter, it looks like it's now skewed more towards oil, what's primarily driving that?

Essentially, I think the -- we did have the Fourbear acquisition late last year, that was Gold Mark and then also the Bakken production has been increasing as well.

Okay, and then in the guidance is there still a couple of

in there for acquisitions?

Yes.

David Tameron, First Albany Corp.

I won't ask you more questions on the Cromwell because I think they have been answered, but Mark, you mentioned some numbers at the beginning of the statements about production quarter-over-quarter. Can you run through those again -- I got the last couple of -- but I get the first -- you've given a variance versus

?

In terms of production that were 6% over the fourth quarter.

And then you went region by region for Williston, Vermillion 73--?

No, I am sorry, sure let me give you that. We increased the constitution field, which was the Paggi-Broussard by 1.03 BCFE. And then the Bakken play is about 0.85, 0.35 at Vermillion 273 and then the three acquisitions just 1.26.

Okay, another question on acquisitions. If assuming you don't do any acquisitions this year, you don't see anything in the next few months, would you guys consider stepping back into the market to repurchase shares?

Quite frankly, we think this is a very attractive time for us to be doing that when we are not in a black-out period, we anticipate that we probably will be doing that.

Okay, what was your authorization?

We are authorized for -- the original authorization was for 6 million on a split-basis shares and we've done about a million of that so we have a 5 million not that we are authorized on.

Michael Scialla, A. G. Edwards & Sons, Inc.

Good morning guys. Question on the Bakken play. Any drilling going on outside that identified fairway right now with anybody in the industry?

There's certainly some activity up in and around the

, which is in the North East of our position. We are not as involved in -- and we certainly are trying to follow it but not a lot of data getting released; there's a lot of rumors right now, but it's hard to really pin down whether economic wells are being made. We certainly think we have a handle on what's going on in Richland County, Montana, and Mackenzie and Billings County and North Dakota, but you get outside of that and it's pretty early and what we're picking up is just mostly rumors.

Okay, and what's the rig situation like there now?

It's difficult. It's very tight. We had actually hoped to pick up a third rig in the Bakken, a third drilling rig and out of Wyoming and move it up to the Williston and that rig has now been committed or the commitment is continuing to the operator that had it. We thought it was going to get turned loose. I think there's a lot of -- I mean everybody is in scramble mode across the entire lower 48 and all of the basins and I don't think, I mean I think that Williston is competitive like the other areas are, and things are tight.

Okay. And then with your re-entries, are you pleased with the production you're seeing out of those and do you plan to continue with two re-entry rigs there -- on the North Dakota site?

We are pleased and we do plan to continue with two rigs and these things -- I think we're throwing out numbers in the kind of the 150-Mbo range and with the

to date and the rates we are seeing, that's still bills achievable. I think these things have pretty good numbers even down to 100 Mbo. So, we'll definitely forge ahead.

Okay, and then in the Hanging Woman play, do you see any risk to getting that 130 well program done this year, the permitting situation going to allow you to do that?

It's difficult. Unfortunately, as you know, it's not black and white and it's great if we could give definitive timelines and definitive answers. What I can say is that the Nance Petroleum guys in Billings have done an exceptional job of balancing the program and looking forward to areas that provide flexibility. Currently, we have 40 permits in the Hanging Woman basin proper that are contingent on any future federal permitting issues, and we have about 60 locations in what we call the River area, which is South and East of our Hanging Woman Basin proper that are all in fee acreage. And so, we have a pretty high level of confidence in those 100 or so locations. We've actually drilled 29 to date. We had 20 in the first quarter but, yes, so you can comfortably get to that, you know, kind of that 130 number. Figures could change and certainly they can change either way but, I do give the Billings' folks a ton of credit for looking way out in trying to manage that knowing that it's a difficult process to manage.

Yes, okay. Thanks.

Rehan Rashid, Friedman, Billings, Ramsey Group Inc.

Good morning, Mark. In the Hanging Woman Basin, I know

is a bit difficult at this point in time, but from a full field development standpoint, as we try to look past this year and see what issues could be on hand or you could encounter for further development, any thoughts on that front as to what we should be keeping an eye out for? What are you working towards, not just for ensuring this year's program but looking out '06 and beyond?

I think the -- just continuation, I mean, I think our expectation, our hope would be that actually over time we could accelerate the drilling program as we get more information and get better with the permitting process. I think, we'll also, within the next 12 months or so, have a real good handle on how the earlier wells have performed and that will narrow down our expectation area. So, so far though, things are performing well.

And from a permitting standpoint, I mean, good comfort with 130 locations this year, I mean, are there enough acreage designated, call it for each state or whatever, that will give you some comfort, okay, -- guess permitting takes time but it should not be a problem for some portion of the acreage or it's just too early to go there --.

As Doug mentioned, we have about 40 permits in hand in 60 locations in the river area that are fee acreage. The Wyoming side is definitely easier than the Montana side and then fee is definitely easier than the Federal on the Montana side, there are -- is talk of requiring an AIS but we understand that they have still allocated a number of locations during that process that will be allowed to be permitted and we believe Nance will be able to get some of those locations, but that time table is not as clear as, you know, we would love it to be, but I think we have a lot in hand and we have started the ball rolling on the Federal permits.

In the Bakken, how many wells are producing or did produce that 2050 barrels average?

I can tell we have 19 operated wells in Montana. Those are predominantly grassroots wells. I guess about five of them are reentries. Then we have a couple of our North Dakota reentries on line. So in the 20, 21 range and then I am not quite as up to speed on the non-op wells. But, I would say, probably around 10.

Philip Dodge, Stanford Eagle.

Good morning everybody. My question Northeast Mayfield, was your present level of activity was the target fee to maintain production or can you possible increase it?

We certainly -- we've -- we are through a lot of the steep initial declines on some of the early wells or some of the plush production that came on in '03 and '04. So, we are in a more shallow portion of the curve on some of the more mature wells and that coupled with the fact that the activity scaled back, I think the combination would be - I think if we can hope for a flattish case that would probably be the best case, but having said, that I don't expect 30% annual decline there either. I think it's -- I would say flattish to slightly down, but it is going to depend -- you know, we just had a greater total completion. I mentioned the Wanda well at 8.8 million a day. We have about 44% working in that well. We operated -- actually after we IPd the well, we continued to open it up to about 10.9 million a day. So, and you get a few of those along and that has a major impact on your rate out there and candidly we hadn't had a well like that for about 18 months. So, we will do one of those, but given the uncertainty of how you can often you are going to have a Wanda type well , it is little difficult to predict. I think I am most comfortable saying something that looks pretty flattish.

What would you say the decline rate is on the current base?

I would guess it's in the 20s.

All right. That's a challenge to over come. Thanks very much.

OPERATOR INSTRUCTIONS]. You have follow-up question from Michael Scialla, A.G. Edwards.

Just a follow-up on the Hanging Woman. Can you say anything about performance there in terms of either oil production or gas production as it compares to the JM Huber or Fidelity fields there in the northern part of the plateau?

I know from an absolute standpoint, Mike that we are making about 25,000 barrels of water a day and I think I mentioned that gross rate of about 1.6 million of gas. I also know that we used the Fidelity and Huber areas as analogues in the shallow curves. But, I can't give you a good answer of how that 25,000 and one-six compares. I think the 25,000 water is certainly indicative of the high perms that we expected and we are not seeing anything on our water rates that suggest lower term than our analog fields but that's about as far as I can take it.

Okay. And then, one follow-up on the horizontal Centrahoma drilling. You said you had one rig there now and you are hoping to drill mostly horizontal wells. Is that continued upon getting another rig or can you drill horizontal wells with the rig you have?

We can drill horizontal wells with the rig we have and we could probably get 4 or 5 -- even if we didn't get another rig, we will get, let's just say 4 or 5 horizontal wells drilled by end of the year. But, certainly, we want to get another rig and we need to step up the pace and move it forward and get some of these other formations tested and start and get some of these other formations tested and start moving out away from this core area and delineating, you know, the scope of this thing. So, that's fully our intent. Everybody understands the challenges of getting rigs, but the Tulsa guys are working that hard right now.

Okay. And then one final question. Can you give us an idea of your long-term plans for Gulf of Mexico? It sounds like you are staffing up down there and looking to emphasize that a little bit more than you have in the past.

Yes, we've gone through an evolution in the Gulf Coast, Gulf of Mexico. As many of your remember, in the mid to late 90, we were testing some pretty big ideas, but we tended to test some deeper structures in the Gulf Coast, in some cases in and around our fee lands. We moved away from that strategy to a little more conservative strategy of drilling, what we call,

shots, which is just basically trying to get updip -- downtip production that is watered out, typically fairly small targets, and we've had some pretty good success with that, but it's tough to grow a region organically drilling, you know, 2 bcf attic shots. So, what we have evolved to and set a strategy and brought in the people that supported the strategy is really something that revolves around direct hydrocarbon indicators where we think we can realistically test ideas that are meaningful and sizeable, but have probabilities of success in the 40-60% range, not in the 20-30% range. So, we've changed our profile of what we are looking at. The things we mentioned earlier about Chandeleur Sound and West Cam 542,

those are 3-D Seismic based direct hydrocarbon indicators, and we have some excellent people with excellent track records in the Gulf coast, in the Gulf coast area that are screening and developing those projects and prospects for us. We also have

our 3-D seismic data in a very cost effective manner, partly through our JV, I had mentioned in a previous call with Yuma Exploration where we are 50:50 and we have access to about 890 square miles of 3-D Seismic in South Louisiana and the Texas Gulf Coast. So, we're executing a strategy, we think it has the risk profile that fits with St. Mary and, we think it has the type of potential that will have an impact on us from a reserve and production standpoint.

Great, thanks.

David Tameron, First Albany.

Hi, quick question. Could you give us a little more detail on what your plans are for the Big Horn Basin after the

acquisition just going forward? You mentioned that briefly, but can you talk a little more about that?

Yes, I think these three wells, in the original economics of the acquisition, we had 6 drilling locations, and we're going to test three of those and it will be very telling. And, you know, we will clearly be able to give you a better answer David, after we drill those wells, but I think it's prudent to go out there and drill through these wells, see how they perform, you know, we're continuing to do some, we will be initiating some

additions and zone additions, you know, some stimulations, and it's probably a bit early, but certainly we are going to do -- we're going to follow our plan and execute our plan of going up there and test these ideas and get three of these at least initial wells drilled.

So, you said you're going to drill 3 this year?

We'll drill at least 3 this year. I suppose in a success case, we could drill more. We also have three Big Horn Basin wells drilled -- planned to drill at Murphy Dome, we've about 52% work interest there, that still came -- fairly certainly that came in Flying -- the Flying J acquisition and we've enhanced our ownership over time with some follow-on acquisitions, but we've done some perk additions that turned out very favorable. So, we're going to drill 3 wells there, also, and then depending on the timing and the result I suppose we could move back to 4 barrel before the end of the year, that's certainly a possibility.

Okay. Who's your other partner, you said 52% on the other acreage you had, who's your partner on that?

I don't have a good answer for you. I know there are a couple of additional small parties that we've continued to try to buy out, and I do think there is one larger name there --

-- and I do think there is one larger name there, but I had to

from there.

Okay, and then one final question. There's some property to change, St. Marathon properties up in the Powder

. Did you guys take a look at those at all? And is that an area you would be looking to consolidate if prices its are right?

We did look at it, and candidly given our position and the rate at which one can develop the acreage up there, and the term remaining on that acreage. Trying to roll, the Nance acreage together with Pennaco acreage, and come up with the development plan that made any resemblance of sense. We just couldn't get there. So our parts of that acreage that fit's very well with our edge and certainly, we are in discussions with the new owner and -- maybe things might make sense there either from a unit at

or some type of JV. But trying to do that whole thing in one bite and coupled with our existing acreage and then come up with a development plan that you could execute before you ran out off term, just didn't make sense to us.

All right.

[OPERATOR INSTRUCTIONS]

I just want to thank everyone today. Thank you.

This concludes today's St Mary Land & Exploration's First Quarter 2005 Earnings Conference call, you may now disconnect.