SM Energy Co (SM) 2005 Q2 法說會逐字稿

Good morning.

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

At this time, I would like to welcome everyone to the St. Mary Land & Exploration Second Quarter 2005 Earnings Release Conference Call. (OPERATOR INSTRUCTIONS) Mr. Hanley, you may begin your conference.

Thank you, Tammy, and good morning to all of you joining us by phone and online for St. Mary Land & Exploration Company's Second 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 online -- 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 and chief financial officer; and myself, Bob Hanley, vice president of Investor Relations.

I will now turn the call over to Mark.

Good morning.

St. Mary is pleased once again to report record earnings, production, and cash flow for the second quarter of this year.

For the fourth straight quarter we have shown sequential production growth, second quarter daily production is 5 percent higher than the March quarter, and 21 percent higher than the June '04 quarter.

Although we have seen cost increase somewhat, margins have increased more rapidly.

Net income for the quarter ended June 30 of '05, was $38.3 million, or 59 cents per diluted share, compared to 21.8 million, or 34 cents per share for the June quarter of 2004.

Discretionary cash flow increased by 63 percent to 105 million.

Production increased 21 percent to 239 million cubic feet equivalent a day.

Production increased 13 million cubic feet a day due to Paggi-Broussard well, 13 million a day at the Bakken play, 24 million a day from new wells completed in 2004 and 2005, and 14 million a day due to the Goldmark, Border and Agate acquisitions.

Northeast Mayfield and Judge Digby net production has remained relatively flat compared to the prior year.

The average realized price increase 38 percent to $7.28 per Mcfe, while our cash margin increased 47 percent to $5.56 per Mcfe.

Included in our realized prices and net hedging loss of 11 cents for the quarter June of '05, compared to a hedging loss of 62 cents for the prior year.

Production expense excluding taxes increased only 1 cent, to 96 cents per Mcfe.

Taxes increased 17 cents per Mcfe due to higher prices.

DD&A increased 41 cents to $1.56, and general administrative expense increased 4 cents, to 34 cents.

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 estimated liability for the net profits plan increased by $12.2 million due to record oil and gas prices.

We closed our previously announced acquisition of properties in Wyoming for $36.7 million cash, for approximately 22.5 Bcf of reserves on August 1.

Our forecasted volumes for the year were increased to 85 to 88 Bcf equivalent, compared to 75 Bcf equivalent in 2004.

Doug will now update you on our larger plays, including the Bakken, Hanging Woman, and Cromwell, as well as other significant drilling activities.

Thanks, Mark.

Good morning.

I'd like to review our second quarter operating highlights beginning with the Bakken play.

The Bakken play continues to be extremely active in Richland County, Montana, with 17 total rigs running in the play.

St. Mary participated in 11 Bakken completions in the second quarter, including the Charlie Creek 233-H, where we have a 61 percent working interest, which IP'd at 620 BOE per day.

The Norgaard 12-6H, 83 percent working interest, which IP'd at 510 BOE per day, and the Bonnie (ph) of 15H, 50 percent working interest, which IP'd at 760 BOE per day.

The Company continues to keep two drilling rigs operating in the play, with one of the rigs being shared with a conventional vertical Red River program.

Given the Company's acreage position in Richland County, it is expected to continue this two-rig program through the end of 2006.

In North Dakota, the Company continues to evaluate its sizable acreage position by utilizing existing well bores for reentry to the Bakken dolomite.

As previously released, we have seen mixed results with the re-entries, with average post-frac initial rates of approximately 125 barrels of oil per day.

Most of the re-entries have occurred in well bores which previously produced from the Bakken shell, and in many cases we have seen partial depletion from the shell production.

The Bakken appears to be more naturally fractured in North Dakota, which facilitates communication between the shell and Dolomite.

In addition, the natural fractures make fracture stimulation less effective.

The plan for North Dakota is to continue to evaluate the Bakken dolomite using re-entries with a focus on multi-laterals in lieu of fracture stimulation.

Net Bakken production averaged 2,720 BOE per day in the second quarter of 2005, which compares to 2,200 BOE per day in the first quarter of 2005, and 690 BOE per day in the second quarter of 2004.

Hanging Woman CBM [inaudible] in the Powder River Basin is producing approximately 2.3 million cubic feet per day of gross gas, and continues to exceed the forecast rate at this stage of development.

As of late July, approximately 82 wells were producing, 36 wells were drilled and waiting on completion, 79 locations were permitted but not yet drilled, and permitting was in progress on 33 locations.

By utilizing 160 acre spacing and multi-seam completions, we are able to develop a large resource base while drastically reducing a number of wells.

Moving to the Mid-Continent, the Mounty (ph) No. 1 in Cole County, Oklahoma continues to produce in excess of 1.8 million cubic feet per day from the Cromwell.

The second horizontal Cromwell test that filled the Lanette 4-4H is currently drilling.

It should reach total depth and be fracked and tested in approximately one month.

The first horizontal Woodford well at Centrahoma has been fracked and is waiting test.

Tubing is being run and the well should be flowing to cells this week.

A second rig is scheduled for arrival in Cole County in late September.

With a two-rig program, we should be able to drill seven additional horizontal wells in the Cromwell, Woodford, and Wapanuka by year-end.

Elsewhere, we are testing a large leasehold position at Garrison Field in Shelby County, Texas.

We're continuing development efforts at Parkway and Shugart fields in the Permian Basin, and we are drilling an amplitude-driven exploratory test at West Cameron Block 542.

We are focusing on Atoka and Grant Wash development at Northeast Mayfield, and are encouraged by recent Grant Wash tests.

The Company continues to evaluate opportunities to add multi-year, repeatable plays to its existing inventory while we continue to move technologies across regional borders and into new basins.

We have witnessed increases in services and supply costs during the second quarter.

We continue to evaluate the impact of these costs increases on all of our capital programs in each of our regions.

We have increased our focus no efficiencies and have been able to offset some of the cost increases by reducing drilling time.

While the current strength and commodity prices have more than offset the impact of increasing cost, we will keep a watchful eye on this side of the business.

With that, I'll turn the call back over to Mark.

Thank you.

We're pleased to reap the benefits of high prices and growing production.

Our challenge is to create value from this point forward.

We have an outstanding inventory of quality, multi-year growth plays, including the Bakken, Hanging Woman, and Centrahoma, at a time of high oil and gas prices.

With a large acreage position and talented people, we continue to generate new ideas, which we expect to add to our inventory of quality plays.

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

Tammy?

Yes, sir, we are compiling the Q&A roster.

Your first question comes from the line of David Tameron, Jefferies & Company.

Good morning.

Question for you.

Can you talk a little more about the acquisition you made that you -- I guess you announced it previously at the end of June and then you just closed it yesterday?

Sure.

Right.

We bought properties from the Wall (ph) family, all within Wyoming, predominantly Wind River Basin, Powder River Basin, a couple of non-op properties in the Green, but it's predominantly Wind and Powder.

The key field is a field called Bixan Draw.

It's a tensely filled, very attractive, as it's very consistent with what we're trying to do at Murphy Dome and Fourbear, at our strategy in the Tensleep and the Big Horn Basin.

Those same technologies will translate to Big Sand draw; that's one of the key assets.

Okay.

And that's the majority of the -- the proven reserve, is that associated with that?

A big chunk of the proven reserves and essentially all of the non-producing is associated with that field.

I think it's 72 percent approved developed, and there is a non-producing component, and that is almost entirely a Big Sand draw, but there are some other valuable fields.

We have an interest in African Swallow, Austin Creek, those are a couple of the other fields that we have substantial value in the package, but the real gem and where we see the real upside is at Big Sand draw.

Okay.

And can you talk a little more about in the Powder, I think Doug yesterday mentioned at the conference, you were talking about commingling, and some of the operations going on there.

Can you give us a little more detail on that, sort of what you're doing there?

Right.

For the sake that those weren't at the conference, David's talking about a CBO conference I was a panelist at yesterday, along with a couple other companies in the Powder and Retone (ph).

There were quite a few questions about commingling and I think it's a big deal and it's real important to the Company.

When we went into the Hanging Woman Basin, we looked at the play and we really focused on the shallow coals initially, knowing that there was additional potential in the deeper coals.

There are three shallow coal seams, and they vary in thickness from 10 to 25 feet thick, generally.

And we went into the project thinking we'd have to drill individual wells to each coal seam, and we went into the project initially thinking we had to do it on 80-acre spacing.

What we've done is, given the permeability if these shallow coals, it became evident that we could develop the play on 160 acre spacing.

We started to experiment with commingling -- [inaudible] hole commingling in the well bore, and we had some encouraging results, but as Mark has mentioned in some of his presentations that many of you have heard, these coals really produce better if they have water on top of them, a certain water level, but not too much.

They need to have their own unique water level, and you need to be able to measure the gas -- ideally, you want to be able to measure the gas from the individual seams in order to predict performance.

That's been difficult and obviously it's impossible just by commingling all the zones within a well bore, but one of our technical people -- one of our engineers in Billings developed a packer that allows us to isolate coal seams and keep independent water levels on those seams and meter the gas independently from the seam.

So it's a substantial technology that we're pretty excited about, and we think it's going to make a tremendous impact on the economics of the play.

As our Billings guys continue to remind me, you need to focus on the resource we're developing, not on the well count.

I think we all get hung up on well count, but they reminded me that with the 150 or so wells that we've drilled, we're going to have developed about a township of resource space, and had we drilled that on 80s, it would have taken twice that number of wells, or 300 wells, and had we drilled that with an individual well for a coal seam, it would take about 900 wells, so, effectively, they're developing the same resource with 150 wells and using the original methodologies that at Powder it would have taken 900 wells.

So that was a long answer to your question, David, but hopefully that helps.

No, no, a lot of good detail.

And how much is it exactly -- do you have any quantification of what it does to your costs by commingling?

I mean, does it cut it --

It's very, very small on incremental basis.

I mean, you have the same tubular, the same casing and tubing, you just have one pump in the well as you normally would.

You were going to perforate the three zones anyway, really, it's just to a large part -- to a large extent, it's just the incremental cost of the packer.

There are probably a couple of things I'm not thinking of, maybe a separate meter run to meter the gas individually, but it's very small incrementally.

Okay, and one last question and I'll let somebody else jump on.

Remind me again, your acreage in the Bakken, obviously, you were there early and you have a lot on the Montana site.

Do you guys have anything -- a lot of people have seen removement, I guess it's to the Dakotas, kind of east of the proven fairway; do you have acreage in that area as well, or could you just remind me exactly where your acreage is, compared to like, you know, EOG is making a lot of noise about the wells they're drilling up there, etc.

We have really focused on -- in our discussions, we've really focused on Richland County, Montana, and McKenzie, and Billings County, North Dakota, and we focused on what we view as the middle Bakken dolomite trend, which is certainly what's made the play in Richland County, Montana.

There are other theories -- the Bakken covers a substantial area.

There is a zero line to the south and west, and then there's a line where -- you get outside of the thermal maturity window as you move north and east, but it's a substantial area that the Bakken covers, and many people believe that if you have storage, be it sandstone, limestone, or any type of storage adjacent to the Bakken shell, that it's going to get sourced with Bakken oil.

So there are other plays in the Bakken that really have nothing to do with the Bakken dolomite play that we're playing.

We know that people are active up in Manassa (ph) and Anacline (ph), in that part of the world, for example.

Mostly what we've -- want we have to go by are just mostly rumors.

We don't have a lot of concrete data like we do in the dolomite fairway.

We did participate in one well and it was a tiny interest up around Manassa, that had a reasonable IP, but it's kind of too soon to tell what the EUR is going to be.

That's about the extent of my knowledge outside of the dolomite fairway.

Okay.

And most of that is the McKenzie County; is that correct, or is that --

I think -- [inaudible] David, and certainly the stuff up around the Manassa and Anacline would be north and east of McKenzie, but I'm not -- when you mentioned, EOG and what they're making noise about, for example, I'm not familiar with where their play is.

Okay.

Okay.

I'll let somebody else jump on.

Thanks.

I appreciate it.

Your next question comes from the line of Rehan Rashid at BR.

Morning.

On the Gulf Coast side, you had announced in your previous press release the SML 24-1.

Any thoughts on the production rates we are looking for, and what's next in the area?

I know [inaudible] is something that was talked about at some point in time.

Yes, the 24-1 has been -- the first production has been delayed.

Our appreciation is, it's going to kind of be mid-September.

We don't operate.

We have our 21 percent royalty interest in the well, which is substantial, and we're probably a little hesitant to release expected IP as other people operate the wells, but we're pretty comfortable thinking that it's going to be in the 15 to 20 million a day range.

On the Viceroy prospect, which is targeting at similar intervals, just down west -- down a major east-west fault, the rig was on location -- actually, it's been probably a couple of months ago -- been on location, just barely got the well spun, and there was a fire in the living quarters that wasn't well related, it was just an electrical fire in the living quarters, but it was a pretty substantial fire, and they've basically been rebuilding that part of the rig and it's been shut down.

I don't have a great date on when it's supposed to fire back up and when it's supposed to get going again, but that's the status out there right now.

Who was the operator on Viceroy?

Burlington operates both the 24-1 and Viceroy, Burlington Resources.

Gotcha, gotcha.

On your Bakken play, roughly called it 30 or so wells this year.

How is the program looking for next year, separated by your two areas?

Maybe I'll probably give everybody a little color on that, just how we see the thing moving forward.

I'm sure people are curious.

As I mentioned in the script, we're going to keep two rigs busy in Richland County through the end of '06, that's the expectation.

One of those rigs will be alternating between an occasional vertical Red River well, but by and large the focus will be mostly Bakken.

Where it goes past '06 is going, to some extent, depend on whether there is additional development or enhancement in Richland County or secondary projects in Richland County.

But maybe, probably more so what's going to dominate the '07-'08 program would be either North Dakota.

And what's happening there, for everyone's sake is, as I mentioned, the fracs really haven't been particularly effective.

Our post-frac rates compared to our pre-frac rates really aren't that -- we're just not seeing much difference, and one the key reasons is that the reservoir is already much naturally fractured and it's difficult to frac a naturally fractured reservoir and get a big response.

So what we've moved toward in the interim here is multi-laterals, and we've drilled, preparing a test, our first multi-lateral re-entry at Cinnamon Creek, although that well is kind of edgy on the dolomite porosity.

We're going to drill at least three more trilaterals, and those will be re-entries.

We have two additional re-entries planned at Mondac.

The Mondac acreage is very close to the Montana border and that's where we've had our best re-entry to date.

We're watching a well that a competitor is drilling that's right on the -- right on the North Dakota/Montana state line.

That will be a key data point.

One of the large independents is drilling a Grassroots well in North Dakota between our Mondac acreage and our PR Creek acreage.

That will be a key data point.

We have twelve 640-acre Bakken spacing units approved by the state in North Dakota.

We're permitting a Grassroots well on federal acreage at Mondac.

So what we have queued up is, effectively a two-rig program for the balance of this year and full year '06.

Additional re-entries in North Dakota, additional data points in North Dakota that will be provided by other operators, and then we're forging ahead under the premise that if things continue to work certainly in the Mondac area, we're going to be prepared to drill additional wells there, which will take us into '07.

Okay.

And on your [inaudible] and your Norgaard and Charlie Creek, the initial rates are definitely much more than what I was looking for.

How have they been holding up since your press release at the end of June?

That's a good question and I should know the answer to that, but I really -- I haven't looked at the dailies -- daily production on those wells lately.

They were very impressive IPs, although the 5 to 600-barrel-a-day range -- and, by the way, we did report these in DOE, these IPs and DOEs.

I've been a little inconsistent in the past.

Sometimes I talk about oil and sometimes I talk about oil equivalent.

But these IPs certainly on the Charlie Creek and the Norgaard well are in line with the historical IPs.

The Bonnie [inaudible] was a little bit on the high side, but it just -- given what I know at this point, I'd expect those to be in similar BUR range of our previous producers.

One last question before I hop off.

On the CBM side, again '06 in terms of permitting and possibly even beyond, and in terms of an exit rate for '05, what the earlier guesstimate was for 1.3 million a day [inaudible] north of that.

But also on that front, for CBMA permitting, B exit rates and how are you seeing the inclines of production for continued CBM play?

The permitting side, I think I mentioned, we have over 70 in hand and we're working on 33 or 34 additional permits.

We are forging ahead.

We have run into a little bit of roadblock and many of you are aware of this.

On the Montana side, there was a ruling that the EIS that was established in Montana was considered to be not valid given the way development is occurring.

And there is probably going to be a new EIS in Montana, and that's going to cause us to refocus and shift our efforts away from the acreage that's right on the border, and really continue to stay in Wyoming.

We are fully expecting to maintain a program.

We were in Billings a couple of weeks ago and had this discussion on numerous occasions.

We're fully expecting to maintain a program of 130 to 150 wells per year range.

Again, that's -- we're developing a lot of resources on 160 acre spacing using multi-seam completions, but that's the range we intend to stay in.

We don't have a crystal ball, we can't predict exactly what's happening, going to happen permitting-wise, but in Wyoming, we are continuing to get permits issued.

We do have a lot of B and state acreage in Wyoming.

About 70 percent of our reserves are -- of our 3P reserves that we've discussed previously are in Wyoming.

As far as addressing your exit rate question, I don't have good feel for that.

It would just be nothing more than a guess if I even threw a number out.

We are very happy with the incline.

You know, we've gone from zero to a couple million a day, 2.3 million a day in fairly short order.

I think that's all happened in about six or seven months.

So --

[Inaudible].

And, I'm sorry, what did you say?

What percent on 3P reserves is in Wyoming?

Seventy-percent.

Okay, thank you.

Your next question comes from the line of Dan Morrison, Aperion Group.

A couple of quickies.

One, your horizontal Woodford that's completing currently.

Where is that generally, at least like a county, or kind of direction in a county?

Sure.

It's Cole County, Oklahoma.

And it's -- we use different nomenclature.

We talk about the Cromwell play, we talk about Centrahome, we talk about Cole County, but we're talking effectively about the same area and the same acreage position.

Okay.

And will you go ahead and disclose some results on that once you do it, or just wait for your next operational update?

We would probably wait until the next operational update.

Okay.

And next question, there is a lot of stuff going on down in the Delaware Basin as far as some emerging plays that look pretty impactful.

Are you all active down there, doing anything currently?

Parkway and Shugart are two fills we talk about quite a bit.

Those are in the Delaware Basin.

Those are conventional Delaware oil and gas production [inaudible], actually.

There has been a strong [inaudible] play in the Delaware.

We have not played that.

It's a 3-D seismic driven play, and we really haven't played that all.

As far as any other emerging plays, I'm not sure I'm totally up to speed on that, Dan.

Okay.

Just speaking of Shugart, though, we are seeing pretty good response in the last four months or so.

We're feeling pretty good about that water flood that we're doing there.

Good.

And what counties are those in?

It's Lee and Eddy County.

Okay, so their [inaudible] Great, thanks.

Your next question comes from the line of Subash Chandra, Morgan Keegan.

Hi.

This is Omava Katraman (ph) for Subash.

I was wondering if you could give us an update on the vertical Cromwell; and, secondly, the second rig that is expected to come on in the Centrahome?

When is that expected and do you have any additional plans of adding rigs in the region?

Excuse me.

We really replaced our vertical Cromwell program with the horizontal Cromwell program, at least for the time being.

We announced last quarter that we had an exciting success at Mattie (ph) No. 1 that came in about 3 million a day, and mentioned this morning it's still producing 1.8 million a day.

So it looks like we definitely have a keeper there.

It's a very strong well.

We're drilling our second horizontal Cromwell currently, the Lanette 4-4H.

Should have a test on that in about a month.

If we continue to see success via horizontal drilling in the Cromwell, I wouldn't really look for us to go back to a vertical program.

The vertical wells were coming with initial rates in the 600 Mcf a day range, making about 0.6 of a B, and obviously we're seeing tremendous multiple on the initial rate on the horizontal, so I'd expect us to really stay with the horizontal programs.

As far as the second rig, I've heard estimates from September 15 to October 1, and I'm suggesting -- or kind of mentioning, I guess, for the time being just a late September, early October.

If we get the rig then, it should be able to drill three wells, and then the there horizontal wells before year-end.

And the existing rig after it finishes the Lanette that it's on currently, should be able to drill four additional horizontal wells by year-end.

So I would anticipate seven total horizontal wells after the Lanette is finalized between that point and year-end.

Okay, thank you.

Your next question comes from the line of Larry Busnardo, Petrie Parkman.

Good morning.

On the Cromwell program, can you talk about how that would then lead into 2006, seven additional horizontal wells this year, and then having the two-rig program, what you think you could get done there?

We know the -- we've talked about the 18 or so sections that have vertical Cromwell production, and for lack of a better word, we've been kind of calling that the core area.

And then as we move east, we talked about 19 sections to the east that have Cromwell present, but very little well control, very little production history.

I think the future is clearly going to depend on the next few wells and how they act, and the ultimate future and how substantial it becomes will depend if we're able to extend it to the east.

But even if confined to this 18-section area, it's a substantial play for St. Mary.

If we're able to move the play east, it becomes even bigger.

We also -- we really haven't talked about this a whole lot, but we also have a 22 square mile 3-D shoot on this acreage to the east, where we're looking for some thrust at Wapanuka and additional Cromwell, and some at Deeper Horizons, down the [inaudible] section, so there is going to be a lot going on in Cole County for the next several years.

How active it is, is clearly going to be contingent on how this program performs between now and the remainder of the year.

Okay.

And you can keep those two rigs that you have been cutting into next year, you're not going to lose one at all?

We can keep them unless we're just not seeing the well perform.

Yes, and then you can just let it go.

Right.

You gave a rate of approximately 600 million a day, and then 0.6 B. What's the cost of these wells?

Well, that was the vertical program.

Oh, okay.

And we're not really drilling vertical wells anymore.

We're not for the time being, anyway.

Gotcha.

We're thinking that's a 2 BCF well and the cost was about 2 million.

Okay.

Looking at the Bakken play, when you talk about the dual laterals, what does that add in terms of incremental cost, or can you just remind me what the basically single laterals and different costs between the two, the single and the double?

Yes.

The single lateral -- reentries were single lateral frac reentries were running about 1.2 million, and it's a good question.

Basically, the tradeoff is, we can alleviate the $400,000 frac job and drill two or three additional laterals and for effectively the same cost, so we're expecting our multiple lateral wells to cost about 1.2 to 1.3, which is exactly where our frac single lateral wells were coming in.

Okay.

And how many remaining Bakken wells this year?

We had a total of 45 that we expect this year, both operated and non-operated.

And how many are down, did you give that earlier?

No, but Doug is getting that.

Our 2005, we've got -- our 2005 program, we have 11 operated wells producing -- we have, one, two, three, four, five -- four either drilling or waiting on completion, and our non-op program, we have ten non-op producing and five either drilling or waiting on completion.

Okay.

And then lastly, just in terms of the guidance, on the production guidance, is there any additional amounts in there for acquisitions?

[Inaudible]

[Inaudible], okay.

Got it.

That's it, thank you.

Your next question comes from the line of Kyle Cavanaugh, Palisade Capital.

Good morning, gentleman.

I have a couple of accounting questions.

Could you walk through the net profits [inaudible] liability.

What factors that drive the increase year-over-year in the quarter?

It's probably a little unusual accounting, in that we try to set up a liability that reflects a present value relative to future cash payments, even though we're not recognizing the revenue to date, and so it's kind of a non-cash, sort of separated item.

We do in that calculation, oil and gas prices are a part of that calculation, and obviously as we've seen prices going up, that piece of that calculation has increased fairly significantly.

Okay.

So it's just driven by expected improvements, so a result of --

It's kind of going with favorable oil and gas prices going up.

Okay.

And then the derivative loss in the quarter is down substantially year-over-year.

Is that basically -- could you tell me what kind of contracts are out there that [inaudible]

Sure.

On the gas side, for the remainder of 2005, we have about 24 percent of our production hedged.

That's it.

We hedge it based on the individual regions where we produce it, but on a theoretical NYMEX basis, it's about at 7.11, and then in 2006, we had 12 percent, and that's at 7.13, and then on the oil side, for the rest of this year we have about 22.5 percent hedge, with a theoretical price of 48.42, and then in 2006, we have 13 percent at theoretical NYMEX price of 48.22.

My last question is on the abandonment impairment of properties.

Is that basically a function of just the cost of services, the year-over-year increase?

I think it's probably expiring leases.

Okay.

That's it.

All right.

Thank you.

Your next question comes from the line of Joe Allman, RBC Capital Markets.

Good morning, everybody.

It sounds like Centrahoma has a chance of ramping up activities, especially if these next seven wells work out well.

Can you talk about other operating areas in terms of which ones might be ramping up in terms of activity next year versus this year?

Well, certainly, the Anadarko Basin, also the Mid-Continent region is going to continue to be active, and some of these technologies we're using in the Arkoma and Centrahoma may apply to areas in the Anadarko as well.

Mayfield is going to continue to be active, as Mark said.

I know there's been a lot of question about the expectation for production there.

We've -- we increased production at Mayfield 14 percent quarter-to-quarter, and about 9 percent year-over-year.

So it's going to continue to be an important property for us.

That's really turning into more of an Atoka, Granite Wash play and less of deep morrow play.

We're also seeing activity in Southwest Mayfield in the Granite Wash, which is the property we've owned for almost 10 years now.

In the ArkLaTex region, we are excited about the James Lime, the Spider Field just continues to extend both north and east, more substantially than we originally thought.

We were concerned as we moved east that our well performance would drop off.

We haven't seen that and we're now in the process of extending that fill to the north.

We also believe, as I mentioned in [inaudible] the script, that we're trying to move technologies across regional boundaries and from basin to basin.

We think some of the things we're doing with the fracs at the horizontal levels in the Mid-Continent will apply to the ArkLaTex, and to the James Lime, in particular.

So that's a focused area.

We're looking at trying to get our hands on some fairly large acreage positions that we think are amenable to that technology.

We have -- Elm Grove is an area that's continued to grow.

That was our Border, or [inaudible] acquisition that we completed in '04, an we're continuing to see that extend to the south more substantially than we originally estimated.

The Green River Basin has just turned out to be much, much more active than we anticipated, as the southern part of our Rockies region.

We've already participated in 39 wells in the Southern Rockies, which is the Green and the Wind and the Powder, which is substantially higher than our expectations going into 2005.

There are a lot of things going on, really, company-wide where we're able to see some future growth.

We have our Gulf Coast program and we're in a couple of active JVs, and we've talked about -- I think in our last phone call we discussed our strategy shift toward amplitude-driven projects on the Gulf Coast and the team we have put together there that we're excited about that future.

So, hopefully, that was helpful.

Hopefully, that answers your question.

That's very helpful.

Just quickly on the Granite Wash, are you seeing results improve as time goes on and, if so, what would you attribute that to?

I think what we're seeing like any new area -- there was Granite Wash production Southwest Mayfield for decades, but Northeast Mayfield really had a deep focus.

It was a Morrow, Atoka focus for us, and I guess going back far enough in time it was even a [inaudible] focus, but the Granite Wash is new, and the Granite Wash is difficult from a log analysis standpoint.

Anybody that's ever worked that part of the world knows that it can fool you, and about the time you think you have it figured out, you realize in fact that you don't.

But what we have now, we're starting to have enough case total (ph) test similar to the evolution we went through in the Atoka.

We're starting to get enough case total test that we can now differentiate between Granite Wash [inaudible] that will produce and those that are going to be wet.

So I think that's really what's attributed or contributed to our recent success in Mayfield, is a few of the key tests.

You know, there is a big Granite Wash plane in the Texas Panhandle that's been moving south and east for some time now, and while I think this is a slightly different animal, certainly that play is moving into Mayfield and we'll see how substantial it is as time evolves.

So it sounds like success in your Granite Wash play is more just area driven than kind of technology driven.

It is.

We're using vertical wells with conventional fracs to produce it.

You really can't -- I can't suggest it's a new technology; it's just more than anything, test in a few zones and figuring out what's going to produce out there.

All right.

Thank you.

Your next question comes from the line of Michael Scialla, AG Edwards.

Morning.

Question is for Mark or maybe Dave.

It looked like your deferred tax rate was quite a bit below what we had anticipated, and I'm wondering if that 35 percent rate is what we should expect going forward for the remainder of the year?

Mike, I think that rate is probably a little bit low.

I would expect it would probably be a little bit closer to the 40/60 split for the year.

We continue to have pretty high IDC deduction, so that's given us the ability to keep that cash tax portion down.

Okay.

Question on your Bakken play.

This next dual lateral well gives you encouragement over on the North Dakota side.

Is there a chance that could open the door back up in McKenzie County, or are you maybe willing to drill deeper into McKenzie County instead of closer to the border?

And, if so, what kind of inventory would you have there?

I think it certainly may make a difference, but as we talked before, not only as you move further to the south and east, not only is the fairway standing the actual dolomite, it's section is thinning as well.

When you get down around the Roughrider area, which is as far south and east as we've tested anything, the dolomite down there is only about three feet thick, and that compares to 12 feet or so in some of the prime areas in Richland County.

So just from the amount of oil in place, by definition it has to be going down.

But it's going to depend on economics.

Even if -- you know, while these wells were 125 barrel a day average, with the current oil prices and the cost for drilling, these wells are probably going to provide modest returns.

We're able to delineate our acreage, we're able to test new concepts, experiment with new technology while generating a modest return.

We'll crack the nut.

A lot of these unconventional plays take years to figure out.

I mean, we were poking around in Richland County for two or three years before it became evident that that was going to work, and clearly the Barnett play was more like a decade before people figured out that was going to work.

So we have the luxury of having 180,000 net HBP acres in Richland, McKenzie and Billings County, and I think we have time on our side, and we have a group in Billings that has a technology orientation, and I think we'll figure it out.

I think multi-laterals are going to be part of the puzzle.

Okay.

And then could you give us a little bit more detail on your -- I think you mentioned Green River Basin, where you anticipate 39 wells.

Is that primarily Allman Lewis, or is that part of your CBM play on that?

Yes, that's primarily Allman Lewis (ph).

It's primarily in the Wamsutter -- in the Wamsutter area.

We have a sizable acreage position in and around Wamsutter that is predominantly non-operated, but we do have several key operated wells as well, but that's the biggest driver behind that 39 well count that I threw out earlier, although that does include a few wells in the Wind River Basin, and it may have a couple wells -- it may have a few of the Atlantic Rim wells in that number.

It also has -- that would include the Fourbear, Tensleep wells that we talked about as well.

But predominantly, the line share would be the Wamsutter area.

And who is the operator, your partner there that's operating most of your wells in Wamsutter?

It varies.

The bigger names are Questar, Devon, BP.

Those are the three probably dominant operators that we have a non-op interest with.

Okay.

Thank you.

Thank you. (OPERATOR INSTRUCTIONS) We do have a follow up question from Rehan Rashid, FBR.

Just on your Gulf of Mexico side, any update there?

I guess the key well we're drilling right now is West Cam 542, but we're probably 30 days or so from having that down, and it's an exciting well that definitely has -- it's a little more sizable feature than some of the things we've tested down there over the last couple of years.

But it has an element of risk like all Gulf Coast exploration does.

So we're keeping our fingers crossed.

What's your working interest, who is the operator?

We're the operator, and we have 35 percent.

Okay.

And evolution of the Gulf of Mexico program going into '06, any thoughts on that front, or the rest of this year?

I think -- I imagine -- we're going to be opportunistic obviously, but our strategy on the Gulf Coast in general is to continue a limited program, a pretty selective program in South Louisiana on-shore.

We'd like to grow South Texas on-shore, and we're probably going to do that.

If we accomplish that goal, it's probably going to be via a producing property acquisition, which we've actively been looking at.

The Gulf of Mexico will be selective opportunities on the shelf, and maybe occasionally taking even a small interest in some of the intermediate water depth plays, where we feel like the risk level is appropriate.

Not the super large, super expensive, large target deep water, but I think there's a niche developing in the intermediate water depths that would allow some selective investment there to develop some of the smaller fields that the majors have left behind.

So that's something we're certainly looking at.

That's typically not what I think about when I think about St. Mary.

What from a technical competent standpoint, could you remind us what has been done to develop the ability to participate in such wells?

I think we talked about four, and we closed our Lafayette office, which was really a South Louisiana focused office for the most part in spring of '04, and relocated that to Houston under new management, and really brought in a new G&G team that had a lot of Gulf Coast, Gulf of Mexico experience predominantly in 3-D seismic, and amplitude-driven plays, and that's the concept we're testing.

We're testing it on a limited basis and we're being very selective about the plays and about the level of working interest we carry.

And the -- what the link is between intermediate deep water and what we're doing right now on the shelf and on the Gulf Coast in general is that most of those plays are seismic driven, and it's really, in my opinion, it's not dissimilar to what happened on the shelf a decade ago or 15 years ago, where there majors were moving out, some of the smaller independents came in behind the majors and started developing the 50 BCF and 20 BCF targets, and ultimately the 10 BCF and 5 BCF target that were left behind using technology and using seismic.

If we can convince ourselves that we have that competency in our organization, and we can use it effectively, then I think it is a natural extension of our skill set.

But it would be done on a very limited basis.

Okay.

Thank.

Your next question comes from the line of Edward Mitchtesago (ph) Pritchard Capital.

Hi, guys, how you doing?

I was just wondering if you could make a quick comment and some color on what you have going on as far as Williston Basin growth.

The two primary plays that we've had in Williston are the Red River, which we've been doing, really, since 1991.

We continue to do that play.

We've had about an 86 percent success rate since we first got involved there.

The key to that play is being able to us 3-D seismic to map ferocity development, and we think the only company that's been able to successfully do that.

We replenished some of our acreage position with the Fly J (ph) acquisition and some of the other acquisitions that we did, and we've been able to use that technology and replicate it kind of in the basin.

I think this year we have, I want to say six 3-D surveys for the Red River this year that we have planned.

And generally, these are fairly small, sort of, we call them postage stamp 3-D surveys.

In general, you'll get one to three wells that tend to shoot out of that.

So that's a continuing project that we've been doing for many years, and then Doug has obviously talked about the Bakken play, and those are the two primary plays in the Williston.

Okay.

Do you want to talk about any of the others?

Those are the two big ones.

Okay, great.

Thanks, guys.

At this time, there are no further questions.

Well, thank you very much for joining us today.

It's always good to have nice results to report on.

Thank you.

This concludes today's conference call.

You may now disconnect.