SM Energy Co (SM) 2004 Q1 法說會逐字稿

Good morning, my name is Tanya (ph) and I will be your conference facilitator today.

At this time I would like to welcome everyone to the St. Mary Land & Exploration Company first-quarter 2004 earnings call.

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

After the speakers' remarks there will be a question-and-answer period. (OPERATOR INSTRUCTIONS) Mr. Hanley, you may begin your conference.

Thank you, Tanya.

Good morning to all of you joining us by phone and online for St. Mary Land & Exploration Company's first-quarter 2004 earnings conference call.

Before we start I need to read the following statement.

Except for historical information statements made during this conference call, including information regarding the business of the Company, may be forward-looking statements.

These statements involve known and unknown risks which may cause the company's actual results to differ materially from forecasted results.

These risks include such factors as uncertainties in cash flow and reserves, oil and gas operating risks, volatility of oil and gas 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 (ph), Vice President of Finance; and myself, Bob Hanley, Vice President of Investor Relations.

I'll now turn the call over to Mark.

Although our first-quarter results remain very healthy, they're down somewhat from a year ago.

This reflects relatively flat production, somewhat lower prices and modest cost increases.

Net income for the quarter ended March 31, '04 was $21.4 million or 66 cents per diluted share compared to 27.4 million or 81 cents per share before the cumulative affect of change in accounting principle of an additional $5.4 million or 16 cents per share.

Discretionary cash flow was essentially unchanged at $56.2 million while our shares outstanding declined at the end of the period by 3.1 million shares.

Production increased 3 percent to 18.5 BCF equivalent.

Production from Fort Chadbourne and other fields sold in 2003 was 250 million cubic feet equivalent in the first-quarter of 2003.

Also we lost production in the first-quarter due to the electric grid at the HCASA field going down when several transformers blew as well as freeze ups in the Williston Basin causing us to lose 150 million cubic feet equivalent.

You should note that last year we did only have two months of Flying J production.

The average realized price decreased 6 percent to $5.02 per MCF equivalent.

Unit costs increased modestly for the year's production expense including taxes increased 10 cents to $1.28 per MCFE, 3 cents of that was an increase in production taxes.

DD&A increased 7 cents to $1.12.

And general and administrative expense increased 2 cents to 36 cents.

The increase in LOE outside of taxes is primarily due to the change in our asset mix in which we became oilier as well as maturing and of producing properties and some general inflation.

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.

G&A increased due to an increase in personnel, an increase in incentive compensation as well as onetime costs during the first-quarter associated with Sarbanes-Oxley 404 compliance.

That amounted to $268,000 and we have severance and other costs associated with the move of our Gulf Coast and Permian regions to a new Houston office of $316,000.

Approximately 1.2 million of the 2004 net G&A expense reflects a non-cash mark to market effect of accruing compensation expense under our net profits interest bonus plan compared to 575,000 in 2003.

We have recommended to our shareholders the approval of a performance-based restricted stock program which will replace our regular stock option program.

Should the plan be approved we will begin recognizing expense associated with the plan in the June quarter.

Our forecast guidance has taken the expense associated with these grants into account.

As you know, St. Mary reacquired 3.38 million shares from Flying J for $91 million or 26.92 per share on February 9th.

Our weighted average shares outstanding for the earnings per share calculations were reduced by 1.9 million shares reflecting the partial period.

Future quarters will reflect a full reduction of 3.38 million shares.

The acquisition market continues to be very competitive, although we've been willing to reduce our rate of return requirements somewhat to reflect very low incremental borrowing costs in our bank facility, we did not close any acquisitions in the first-quarter.

Doug will now discuss our drilling results for the first-quarter as well as an update of our CAPEX forecast for the year.

I'd like to update you on the company's current activity in our core areas.

In the ArkLaTex we continue to keep an operated (ph) drilling rig active on our 7,500 acre lease block at Spider Field in DeSoto Parish Louisiana.

The most recent completion at Spider, the DeSoto Parish School Board No. 1, had an IP of 2.9 million cubic feet a day and is producing at a rate of 1.6 million cubic feet a day after 3 1/2 weeks of sales.

The Jefferson No. 1 has been drilled and tubing run and will be turned to cells after the currently drilling Jefferson No. 2 is finalized and the rig is moved off of the shared location.

Plans call for continuous development of this acreage position during 2004 with the possibility of minor breaks in the development schedule if the rig is deployed to test other horizontal ideas (ph) in the area.

Gulf Coast activity will be increasing with the 18,000 foot with Miami Corp.

No. 3 and Cameron Parish expected to spud in June.

This deep test where St. Mary's interest is 25 percent targets Camerion (ph) and miogyp (ph) sands in a structurally high position updipped to shows and production.

The company's Ester (ph) prospect where we have a 38 percent working interest should spud in July.

The Davit (ph) No. 1 at Judge Digby has reached total depth.

St. Mary estimates 15 feet of pay in the C series where we have a 6.5 percent working interest and 136 feet of pay in the B series where our interest increases to 11.5 percent.

Completion operations are preparing to commence with first production expected in approximately two months.

The 3-D seismic chute of the company's 25,000 acre fee land position in St. Mary Parish has been completed.

The process data has been delivered and prospects are being generated.

The two key underwriters, Burlington Resources and El Paso, are both working the data as well as an outside consulting firm hired by St. Mary.

A prospect review with the company's outside consultants is scheduled for the first week of May.

It is hoped that drilling will commence to test the first of these prospects prior to year-end.

Moving to the Permian, the gross filled rate at the Parkway Delaware unit has increased from 1,207 barrels of oil per day in December to a current rate of approximately 1,373 barrels of oil per day.

The increase is primarily the result of two infill wells that have recently been completed.

Two additional wells have been drilled and one was put on pump this week.

The fourth well is awaiting a frac job. 12 additional infills will be necessary to complete the pattern in order to maximize reserve recovery.

At the Sugar Delaware units the pilot response continues to be encouraging with the pilot rate having increased from 50 barrels of oil per day to 90 barrels of oil per day.

Four additional injectors are budgeted for 2004 with a total of eight additional injectors expected to complete the water plug pattern.

Water has been procured from offsetting producing units and water lines are being permitted.

In the mid-continent activity continues at Northeast Mayfield where St. Mary has four operated drilling rigs running and is participating in four nonoperated drilling operations.

In addition, nine wells that the Company has an interest in are either completing or testing.

St. Mary expects to participate in a total of 33 wells at Northeast Mayfield in 2004 where the company's working interest will average approximately 30 percent.

In the Rockies the Company continues to expand the Bakken (ph) play.

The Franz 148H 100 percent working interest in Richland County, Montana has reached total depth in it's second lateral.

Each lateral will be fraced and the well be placed on production.

The rig meanwhile will move approximately 5 miles southeast of the Franz to drill another dual lateral Bakken well.

That well will be followed by a 100 percent working interest well directly offsetting a recently drilled Headington well that had an initial producing rate of 600 barrels of oil per day.

In our vertical Red River program the Asbeck 1535H where we have a 99 percent working interest has been completely flowing at a 10 day average rate of 589 barrels of oil per day and 671 MCF per day.

The well is located in the Ridgelawn field where two additional Red River tests have been identified seismically.

Five additional Williston Basin 3-D surveys are planned for 2004 with two in North Dakota and three in Montana.

The Hanging Woman CBM play continues to progress.

The pipeline contract has been signed and completion is scheduled for a late 2004 startup.

The state APDs have been submitted for approval and we expect to have the approval permits or the approved permits in early May.

The federal plan of development will be submitted between June 1st and June 15th which we anticipate will be approved by August 15th.

Our plan continues to call for the drilling of approximately 100 wells by year end.

Our acquisition efforts are funded primarily on private companies where we see sellers emerging to potentially take advantage of this high commodity price environment.

We will continue to look at asset deals in our core areas and will participate in market processes only when we feel we have proprietary knowledge and a true competitive advantage.

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

In summary, we began 2004 with a solid if not spectacular first-quarter.

The acquisition market remains highly competitive and we remain disciplined and persistent.

Drilling results to date are mixed with excellent results in the Williston, good results -- initial results in the ArkLaTex, and mixed results in the Mid Continent but with significant activity approaching closure.

Our Hanging Woman project is proceeding on schedule and we remain cautiously optimistic about our prospects and our fee acreage.

For the first time we exceeded $1 billion in total market capitalization.

The current high price environment has made our current asset base appreciate considerably, drilling economics on existing prospects excellent, and our financial position outstanding.

The acquisition market is challenging as is growing a successful larger company, but the challenge was similar on a smaller scale 12 years ago prior to going public.

We have grown our technical expertise and our land position and we remain optimistic about the future.

With that we'll open it up or questions.

(OPERATOR INSTRUCTIONS) Scott Hanold, RBC Capital Markets.

Based on your guidance it looks like you anticipate some good production growth in the second half of the year.

Could you provide a bit of color to that, and when you expect things to ramp up and what areas or wells that's coming from?

Obviously one of our key areas has been Northeast Mayfield in Oklahoma.

We have nine wells that are completing at Mayfield; certainly those wells we have high expectations for.

We only had four wells that completed in the first-quarter, so we had a little bit of a drought.

These are typically 100 to 120 day wells, so we went through a little bit of a timing issue there where the number of completions didn't really stack up.

We're hoping that we'll see additional volume increases there as well as at the Spider field, which I mentioned, we have a 7,500 acre block we continue to develop and we'll keep a rig busy there pretty much the entire year.

Our first well really exceeded our expectations.

It was close to 3 million a day.

I think after almost a month it's still about 1.6.

We were hoping for 1.5 million day type IP there so that was a positive surprise for us.

In addition, the Bakken play continues to expand.

The Franz well that I mentioned is a 15 mile stepout from our previous wells at Spring Lake and Charlie Creek which has been primarily where we've been focused.

Other players are playing in the area so it's not a -- certainly it's not a wildcat by those standards.

But for us it's a big stepout onto our larger acreage trend.

And we have the next three wells in the Bakken horizontal play, the next three grass-roots wells are all 100 percent wells.

So we have several things happening that certainly have the ability to provide a production volume uplift as well as the fact that we have a team or an A&D person in each of our regional offices as well as an A&D group at corporate that has multiple evaluations going on at any given time.

And certainly even though, as Mark said, it's a challenging environment, we're certainly hopeful that one of those will pop for us.

And then just in terms of progression of production, it looks like in the second-quarter you're kind of guiding -- if I take the midpoint it's sort of flattish, but then too, looking at your full year number, are you going to see a pretty good stepup starting in the third-quarter then?

I think in terms of our CAPEX expenditures we are seeing that -- that does tend to ramp up after the first-quarter so we do expect that activity levels in terms of drilling will be growing.

We have a little bit built in for acquisitions in the latter part of the year, in our total forecast it's about 4 BCF.

So that will be contributing as well.

So in your 78 to 82 guidance is about 4 for acquisition?

That's correct.

And as far as that non cash stock comp that you're going to be booking, is that going to be about 500,000 to 1 million a quarter, does that sound about right?

No, that probably was a little higher in the first-quarter because it's affected by the Nymex strip.

And this is not on the stock, that was on the net profits pool.

In terms of the stock compensation, there wasn't anything in that in the first-quarter because it hasn't yet been approved by shareholders.

The way we believe that will be accounted for is the first grant will be made in June and that 25 percent vests immediately, so that 25 percent will be recognized as expense in the second-quarter.

Then basically as it vests over the three-year period we'll take in basically a proportionate cost as it's vesting.

What do you anticipate your second-quarter booking will be roughly?

Approximately $2 million.

Is that a pretty good run rate on a quarterly basis?

No, actually that -- because on the initial grant you recognize 25 percent right away, then the rest of it is basically amortized over three years.

So it's about $0.5 million each quarter.

But then next year on the first grant date you'll have that 25 percent hit, it'll kind of follow that pattern.

Okay, thanks.

Larry Busnardo, Petrie Parkman.

Doug, can you talk a little bit more on the Bakken shale (ph) play, just in terms of your acreage position, the number of wells that you'll get drilled this year and then what the program would look like for next year provided you have continued success there?

Sure.

As I mentioned, the Franz well was really a meaningful step up from us at least away from where most of our previous activity had been.

You've heard us talk about the strand and the Vaira well which were concentrated in the Spring Lake area.

The Franz is a significant stepout.

From there we go about 5 miles southeast to another 100 percent well and then come back south about two miles to another 100 percent well which, as I mentioned, Headington has drilled a 600 barrel a day well we'll be offsetting.

We have 57,000 gross, 40,000 net acres in Richland County.

To date the bulk of the play has been focused in this fairway that we have mapped in Richland County.

There are ten rigs running in the play, eight of those are in what we define as the fairway in Richland County, two of them are outside, so certainly it has room to expand.

Two of them are outside to the northwest on the Montana side.

The exciting part about the Franz and some of our current activity is we're moving into the heart of that 40,000 net acres.

We had probably the equivalent of three or four sections in the Spring Lake area.

Obviously with 40,000 acres we have multiple contiguous sections as we move more into the heart of Richland County as we move more toward the North Dakota border.

I think we have 11 Bakken grassroots and Bakken re-entries budgeted.

I think that should be our expectation at least at this point for 2004.

One question that's come up a few times is where does this thing go?

Does it happen to go into North Dakota and, in talking to Bob Nance yesterday, we intend to test a Bakken horizontal in North Dakota in 2004.

We'll find a well that we can re-enter to keep the capital cost down.

And we'll test the concept later in the year.

If that works -- I mean we are frankly gaining a fair amount of confidence on the Montana side based on offset results and based on our own results.

If that continues and then we have a positive North Dakota test then we have a lot of running room.

I don't really have the total number of locations quantified at this point, but sizeable acreage position in the heart of the current play and clearly on the North Dakota side we're one of the dominant if not the dominant players right across the state line.

What's the capital program look like for this year to drill those grassroots wells in the re-entries?

This is approximate, we had scheduled for the Williston I think about $27 million of which about half was for Red River and about half for Bakken.

Those are kind of rough numbers.

Okay.

And then just a clarification.

In your guidance you said four BCF is associated with acquisitions, is that correct?

That is correct.

And then just lastly.

If you have just a breakout between what your actual LOE number was in production taxes?

On an MCF basis or actual?

Just actual number.

16.9 was LOE and 6.6 for production taxes.

All right, thanks.

David Tameron, Stifel Nicolaus.

A question for you.

Can you talk a little bit about -- getting back to Scott's question about CAPEX?

You had 40 million in investing on the cash-flow statement, is that all CAPEX for the first-quarter?

What was the actual expenditure in the first-quarter?

We had about 44 million of CAPEX in the first-quarter.

Okay.

So that's 44 of what?

We've increased the drilling portion of our budget from 173 to 188.

Yes, you still have -- and that was my next question -- you still have 100 million in there for acquisitions.

Right.

And of the 180, the increase was primarily in the mid-continent.

Okay.

So I mean -- and what I'm getting at is just how back end weighted are you in your drilling program?

Is just the first-quarter more just Mayfield timing --?

Certainly the first quarter has -- for whatever reason, generally the first quarter does tend to have less completions in it than as we go through the year.

Do you anticipate a ramp-up in drilling in the second half or just kind of a catch-up from some of these Mayfield wells.

I guess Doug said there was only four in the first quarter.

I saw in the press release, it said you had, I think, eight completing and four more drilling.

Right.

Definitely in Q1, we had only four wells that were completed, and frankly, David, they weren't our better wells at Mayfield.

They were kind of in that 2 to 5 million a day range.

I think we have all gotten spoiled a little bit with some of the 15, 20 million a day rates we have seen at Mayfield.

And we are hopeful there are a few more of those out there, by all means.

But with the nine wells we have completing or testing currently, certainly that will give us a nice volume addition, or we are certainly hopeful they will.

And then whether we ramp up past four operated rigs, that is doubtful.

I think a lot of the ramp-up will occur on the non-op side.

There are a lot of very active, very big players out there, and we are certainly expecting them to be active throughout the rest of the year.

We are getting our information from them as to what their plans are going forward and adjusting our budget accordingly.

And taking that one step further, I guess everybody was spoiled by the big rates at NE Mayfield.

When you did your forecast, was that upside to that 78 to 82 number?

I mean, did you kind of model on mid-level rates or how did you look at (multiple speakers)?

Absolutely.

We were modeling IPs (ph) in more of the five to eight or four to eight range, not the 15 to 20 range.

So that is certainly upside.

One thing too that you kind of -- that we kind of face early on here, having had NE Mayfield ramp up with some very good wells, they do tend to come off fairly quickly when you have some of those 15 or 20 million a day wells, and so you fight that decline.

A lot of that has kind of come off, a little more at the lower end and turning hyberbolics (ph), so we're not fighting that quite like we were earlier.

In addition, during the first quarter we did have the Dean well, which was producing at about 11 million cubic feet a day.

That well was I think the biggest well we had producing at NE Mayfield.

We had to do a recompletion there, and so it had to come off-line for about three weeks.

It came back on pretty close to what it was when we took it off, but we did lose about three weeks of production from the most prolific well out there.

That is fair.

Hanging Woman Basin, I know you targeted -- I don't know what -- you have 100 wells out there for '04?

Right.

I'm trying to figure out where you are on that program.

I know that's more back end weighted, but can you talk a little bit more about that?

Sure.

It's roughly split about 50-50 between wells that fall on fee or state and wells that fall on federal.

We have our application for permit to drill in on the fee and state locations.

And we're expecting a pretty rapid turnaround there.

Certainly we expect to stay on our timeline which assumed that we'd spud that program in May.

We will be submitting our plan development on the federal locations in the first couple weeks of June.

And we've done quite a bit of work to convince ourselves between outside consultants that are helping us on the permitting, between conversations with the BLM to convince ourselves that thinking we'll have those permits back in a couple of months is not a ridiculous assumption.

We had one of our CBM team members at a presentation this week and a rep from the BLM in DC said that the 1400 permit backlog at Buffalo, Wyoming had been essentially erased.

And what we've heard from the BLM in phone calls to them and from our consultants is that it's a two to three week time from the time they receive the plan of development to the time they actually pick it up and start the process which has a 45 day clock associated with it.

That's how we're coming up with that two month roughly to get our federal permit.

We'll drill those first 50 wells that are essentially almost all fee in a couple of state locations.

And the expectation is we'll have our plan of development approved and we'll start drilling our federal locations in August and have those completed in the October/November time frame which correlates with the completion of the trunk line and, of course, in the interim we'll be installing our gathering system.

So really nothing has changed since last call as far as our expectation of when things will come together and when we'll get the wells drilled and when we'll be selling gas.

And Andersen and the Roberts Course, are those still be two main coals I guess along with the Brewster or are you just kind of --?

Actually Anderson Canyon Cook or the shallower coals are going to be our initial focus.

The Roberts and the Brewster Arnold are certainly coals that we plan to develop on the Wyoming side and are part of our plan.

But in 2004 we're going to focus more on this first 100 wells in the shallower coal sections.

Okay.

And one more question.

Mark, you scared the hell out of me a little bit here when you talked about lowering your rate of return on acquisition.

And I know you mentioned that was in relation to lower cost of capital.

Can you just talk a little bit more about that and just --?

It's really a reflection of our strengthening balance sheet.

Today we have about $6 million of debt outstanding and we have just over $20 million of restricted cash that's been set aside for possible 1031 exchanges.

We think we'll use a little bit of that but a lot of that we won't use.

And so essentially within the next month we'll be out of our commercial bank lines.

And our incremental cost of borrowing at our banks is LIBOR plus 1.25 which I think is about 3 percent, in that sort of range which is a very low cost of incremental capital in that.

So what we've done is on the first $50 million that we take down on our bank lines we've lowered our rate of return requirements to reflect that lower incremental cost of capital.

So it's not a function of everything is heating up and you have to be more competitive so you're willing to --?

I think it reflects that you have to be more -- I think it's a reflection of that but it's also a reflection of our lower interest rate cost on that incremental amount.

It's reflecting both a competitive market and our cost of capital.

So is the lower rate of return just strictly a function of the debt or is there also a little piece in there where --?

Basically what we've done is we've done that up to 50 million -- until we have $50 million outstanding and then we go back to the old method.

Okay.

Thank you, that's all I got.

Ellen Hannan, Bear Stearns.

My questions have been answered, thank you.

Phillip Dodge, Stanford Group.

As I remember May 1st was a critical date in the possible leasing of the fee acreage.

Is that correct, correct me if I'm wrong?

And if it's right, has anything happened?

You are correct, Phil, and nothing has actually happened.

We've had periodic conversations, more in the past, as far as possibly extensions that we had made some proposals and nothing developed that way so we're kind of waiting anxiously as you are.

Quite frankly we're somewhat neutral on what happens.

Under the existing terms of their option is if they exercise their option we'll have a 25 percent royalty together with the right to participate up to 25 percent as a working interest owner and then there's a lease bonus of $250 an acre.

We're very comfortable with that.

If they do not do that then essentially we have 100 percent as well as the 3-D seismic that they shot which we now have and are working.

We feel relatively comfortable that we'll be able to generate prospects and be able to sell them to others kind of depending on the type of project, participate to some extent if we want to, but it actually gives us a little bit larger working interest to kind of work with (multiple speakers).

So we're kind of neutral on whether they do it or not.

Okay.

And another question.

I know you discouraged us from being obsessed with Judge Digby, but it sounds like you got a pretty nice well coming along.

I just wonder if you can give us some indication of what you expect the trend in your Judge Digby production over the balance of the year to be?

Actually Digby has surprised us on the positive side.

So far this year we've averaged right at 11 million a day net (ph) (indiscernible).

I was quoting something closer to 10 and expecting a little decline.

So we've had some positive surprises at Digby.

The David well, or the 'Davide' well depending on where you grew up, is going to be a meaningful well.

But certainly BP will start in the C zone and 6.5 percent working interest and frankly that's the thinest zone.

So depending on how long it takes to deplete the C they'll be moving up to the B where we have higher interest and certainly much more pay so we expect more prolific rates out of that well.

Discussions have centered around an additional well needed to develop some of these B reserves.

But the Davide well basically extended the B reservoir much further south than had been seen before at Judge Digby.

So there's a discussion about another B well to develop additional reserves or to accelerate some of the reserves in this large pay interval.

I don't know the exact timing of that.

But clearly we'll have some decline in our existing wells.

We'll have some uplift or new volumes from the Davide well.

And then depending on whether an additional B well is drilled, we'll see hopefully a positive impact from that.

But I don't have an exact profile for you of what that's going to look like over time.

They call it Davide in Eastern Massachusetts so I'll call it that.

Do you think it could give you some incremental production or is it a matter just offsetting the decline in the rest of the field?

Again, it depends on how long the C produces which I’d expect to be at a lower rate with only 15 feet of net equivalent pay.

But as we move up to the B, as you've seen, it's not uncommon for some of these thicker Tuscaloosa sands to produce at 50, 60 million a day.

So an 11.5 working maybe 8 or 9 net, we could see 4 or 5 or 6 million a day net to us which would more than offset decline by all means.

So there could be some incremental uplift at Digby.

That's it.

Thanks very much.

Dan Morrison, Hyberian (ph).

Quick kind of getting back to Northeast Mayfield, the four wells that were completed in the first quarter, did those have kind of average working interest, were they a little below average?

Your interest out there varies so much.

It really does.

I was –- I actually peeked at that real quick before the call.

I didn't actually do the math, but just eyeballing it looks pretty average.

We had one of the wells at 10.2, one at 28.9, one at 55.4 and one at 31.4.

I think that gets us awfully close to that 30 percent, 30 to 31 percent average that we've been quoting.

And the wells that are pending completion right now, are they kind of following the same boat?

Good question.

Without reading them all off, I have a high of 55 and then some that get down in the 13 to 16 range.

But yes, I think that 30 percent definitely should apply.

That's a good number to go with.

Are those a mix of Atoka and Morrow?

They are, they certainly are.

I don't have that exactly broke out, but some of them will be -- it looks like probably of the nine at least five will be Atoka completions and four will be Morrow with possibly some co-mingle Atoka.

Okay.

Thank you very much.

Jack Aydin, KeyBanc Capital Markets.

Could you just give us an idea of how much it costs you in terms of lost production in the utility and other downtime in some of the areas of operation?

Yes, that was about 150 million cubic feet and then the fields that we sold last year they contributed about 250 last year, and the Dean was probably -- it was 220 and that's other net.

The Dean was up 220.

If you don't mind, Doug, could you go around the map a little bit?

I know you mentioned the Gulf Coast and you mentioned the CBM in terms of drilling for the year.

Could you give us an idea how many wells you might drill in mid-continent and the Rockies and ArkLaTex for the balance of the year?

What is your plan?

A gross number, whatever, just to get an idea because you throw so many numbers it is very hard to --.

Let me pull our budget spreadsheets out and try to help get a --.

I'll call you back on the outside line -- whatever you prefer.

Sure.

Probably short of shuffling a lot of sizeable spreadsheets here and trying to pull all those numbers, I can put a little table together and get back with you on that would probably be better.

Thank you.

We'll have to just check with our F&D requirements that we -- we're filing our Q today.

If we find that that's something that is viewed as special as opposed to just being part of the total budget picture we'll add that to our 10-Q.

Thanks.

Rehan Rishad (ph), Friedman, Billings & Ramsey.

Actually all of our questions have been answered.

Thanks, appreciate it.

John Gerdis (ph), St. Mary.

A couple things.

Doug, really for you, you seem to be, my sense is increasingly excited about what you're doing what this Bakken dolomite (ph).

Talk a little bit about -- and you're also talking about some pretty good trend extension here as well.

Talk a little bit about this depositional environment and where you think this could go?

We started out of course, as I mentioned, pretty focused in one township in Richland County.

We're playing off of some acreage we picked up in the Flying J acquisition and the Burlington acquisition.

Really, frankly, we're pretty cautious about the play.

The Bakken play conjures up some memories of disappointments back in the late '80s, early '90s.

So we had the luxury with this acreage position of the 57,000 gross 40,000 net that almost every acre practically is held by production.

There was a sense of urgency of lease explorations we had to beat.

So again, we had the luxury of watching this unfold and some of our competitors in the area were able to prove up some locations for us.

Headington has been very active, Glyco (ph) has been very active.

Others have joined the play in the last few months and they've drilled around our acreage position and have been drilling some good wells.

I think what you're hearing in my voice, John, is just a higher level of confidence that this is real and it's going to extend and the latest understanding that I have is that one of those companies has actually proposed a well -- all within about three miles of the North Dakota border which is about five townships -- of course, a township is six miles by six miles -- about five townships from where we started our play up in the Strand Vaira area.

It's unfolding like we hoped it would to the extent that it's moving to the south and east where the lion's share of our acreage is positioned.

We have others that are drilling offsets to our HVP leasehold which again gives us a much higher level of confidence to go out there and spend $2.4 million on a grassroots well or $950,000 on a re-entry.

And we also, by using re-entries to prove up our acreage, it can keep the cost down on the initial well whereas if the reentry is successful then drill a grassroots well offsetting that.

I think the folks in Billings have just done a great job of managing this play, making sure we didn't get too far ahead of ourselves initially until we saw what was really unfolding and then, now that we're starting to get confidence, gearing up and moving forward.

Drilling this dolomite ore, are you seeing it –- is it a fair characterization to suggest you're seeing -- somewhat uniformity it appears in terms of these well completions?

There has been some variance in IP, but there's been variance in the way the wells are drilled and completed.

So how much of it's due to the depositional environment or the dolomite itself like you brought up, or how much of it's a function of the completion technique.

Some people or some have continued to drill single laterals and that's certainly going to influence the IP and the ultimate recovery.

Some have fraced the open hole laterals and using different techniques and that obviously is going to influence it.

So it looks like in most cases though, even the single laterals and even wells that may not have been fraced exactly like we would have fraced them are generally, as a general, statement, still looking like pretty good wells.

There aren't a lot of really, really poor wells in the play which is what we've been conscious of and concerned about.

And you're generally drilling dual laterals here, right?

Dual laterals in the case of the grassroots wells and some of the re-entries have been singles.

One last question.

On the 3-D work you've obviously done over your fee acreage, you're working that internally.

Realizing it's early days here, what's your sense of what it's telling you?

Too early?

It is early, we do have prospects and we are looking or we are focused on that area between Bayou (ph) Sallie (ph) and the Belill (ph) which had never have been shot before.

And one of the issues is trying to tie the horizons we're seeing back to the producing horizons on structure.

And what we're playing really is Bayou Sallie and Belill are big pronounced structures, we're playing the gap in between so we're looking for complex faulting, compound faulting that's occurring between those two major structural features.

As a result it's a lot more complex.

It's not like the big highs just pop out, it's more looking for complex faulting to set up trapping.

But we are seeing some interesting things.

I think, you're right, it is early but over the next couple months it'll start to crystallize a bit.

That's helpful.

Thank you.

(OPERATOR INSTRUCTIONS) David Tameron.

One more quick question.

Getting back to Hanging Woman Basin, you guys have thrown out a number of 150 Bs of probable or 147 I guess based on your economic model.

Is that a risk number?

Obviously they're probables but how much -- can you just talk a little bit about that?

Is that a risk number?

How much upside is there to that number?

It's risk to the extent that it only includes five coals and it's only on the Wyoming side.

It's only on our Wyoming acreage.

So while we didn't go in and apply some weighting factor, what we did was say if we only look at five of the coals, and those are those three shallow coals I mentioned plus the two deeper coals, clearly there are additional coal seams that we think will provide future opportunities and clearly we have a substantial acreage position on the Montana side of the border.

So the point being we certainly didn't quantify every single location or every single coal.

We tried to focus on what we could see as being developed over the next few years and what we felt had the most immediate potential and the highest likelihood of being developed quickly.

I think if -- we did have our people map all of the coals on both the Montana and Wyoming side that met certain minimum geologic criteria and that generated about just under 2,600 locations.

I believe the five coal seams on the Wyoming side was 1,600 if I remember correctly.

Okay.

Thanks.

Dan Morrison.

One other quick follow-up on the seismic options on the fee lands.

Isn't there a looming expiration for some of those, what's the timing on that?

Actually Phil had asked about that.

We do have a May 1st date and it's one where quite frankly we're pretty neutral on what happens.

We're happy with the deal structure under the option agreement that if we get it back we actually end up with a larger working interest that we have the ability to either drill part of the cells, farm out part, and we also have gotten the seismic for free plus the fees that they paid us, the $900,000.

We're very comfortable either way that goes.

So that's basically --?

What actually happened a little bit, and one of the reasons that it puts a little pressure on Burlington and El Paso is I believe it was a 300 square mile survey was the entire thing, ours is about 25,000 miles of that -- acres, excuse me.

Yes, 25,000 acres, excuse me.

The original terms that we had, we had kind of the earlier of two dates which was the May 1st or six months after they have the data, the May 1st came up earlier.

With all of the other surveys that were done in that program, they didn't have that earlier of the May date, they had six months after they had the data.

So they haven't had our data very long and we're not sure how that's going to impact how they have to decide and that's put sort of an additional sort of pressure on them to make a decision quicker.

Okay, thanks.

At this time there are no further questions.

We'll wait just one moment.

(OPERATOR INSTRUCTIONS)

There do not appear to be any further questions so with that we'll sign off for today and we appreciate your calling in.

This concludes today's conference.

You may now disconnect.