SM Energy Co (SM) 2007 Q1 法說會逐字稿

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

Mary Land & Exploration first quarter earnings conference call.

(OPERATOR INSTRUCTIONS) Thank you.

I would like to turn the call over to Mr.

Collins, Director of Relations.

Sir, mese please go ahead.

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

For St.

Mary Land & Exploration Company's first quarter 2007 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 the volatility and level of oil and natural gas prices, the availability of economically attractive exploration and development and property acquisition opportunities, and any necessary financing, lower prices realized on oil and gas sales resulting from our commodity price risk management activities, unsuccessful exploration and development drilling, the imprecise nature of estimating oil and gas reserves, uncertainties inherent in projecting future rates of production from drilling activities and acquisitions, drilling and operating service availability, uncertainties in cash flow, the financial strength of hedged contract counter-parties, the negative impact that lower oil and natural gas prices could have on our ability to borrow, litigation, environmental matters and the potential impact of government regulations.

Additionally, St.

Mary may use the terms probable and possible reserves in this conference call, which SEC guidelines prohibit from being included in filings with the SEC.

Probable reserves are unproved reserves which are more likely than not to be recoverable.

Possible reserves are unproved reserves which are less likely to be be recoverable than probable reserves.

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

The company officials that are on the call this morning are Tony Best, President and Chief Executive Officer; Jay Ottoson, Executive Vice President and Chief Operating Officer; David Honeyfield, Senior Vice President, Chief Financial Officer; [Dennis Zubietta], Manager of Reservoir Engineering; and myself Brent Collins, Director of Investor Relations.

I will now turn the call over to Tony.

Thank you, Brent.

Good morning and thank you for joining us for our first quarter 2007 earnings conference call.

After a few brief remarks I will turn the call over to Dave Honeyfield, our CFO, for a review of our financial results for the first quarter.

Jay Ottoson, our COO, will then provide an update of our operations.

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

The first several months of 2007 have been exciting and eventful for the Company.

We transitioned to new senior management, opened a new office in Midland, assumed operatorship of the assets in the [Sweety Peg] program area and raised 287.5 million in a private placement of new senior convertible notes.

We've also hired 48 new employees year to date, which is critical to executing our business plan, and continuing to grow our company.

Operationally, we've had significant developments in a number of our regions, which Jay will discuss in more detail later in the call.

The production for the first quarter of 2007 averaged 283 million cubic feet equivalent per day.

A new quarterly record that was 16% higher than the same period in 2006.

For the first quarter of 2007, we had solid financial results.

Realized oil and natural gas prices after the effects of hedging were higher than we had budgeted at the beginning of the year, and as a result of our revenues -- and as a result our revenues, discretionary cash flow, and operating margin were all stronger than budgeted.

These positives were tempered by higher-than-expected lease operating expense, and exploration costs.

Lease operating expense was impacted by increased costs related to ongoing well servicing, particularly on the oil properties in the Rockies, as well as unplanned workovers in that region.

Exploration expense was affected by three exploratory dry holes, which were recognized during the quarter.

I will now turn the call over to Dave for a review of our quarterly financial results.

Thank you, Tony.

As presented in our press release last night, St.

Mary reported net income for the first quarter of 2007 of $40 million, or $0.63 per diluted share.

This compares to 50.5 million, or $0.76 per diluted share for the same period last year.

Net income and diluted earnings per share include various noncash items that are typically not included in the Street estimates of the Company's financial results.

Excluding these noncash charges relating to the change in our net profit plan liability, and unrealized derivative loss, net income for the first quarter of 2007 would have been $45.6 million and diluted earnings per share would have been $0.72 per share.

As Tony mentioned, discretionary cash flow for the first quarter saw a new quarterly record of 144.2 million, which was up 18% from the 122.7 million in the comparable period last year.

Our financial highlights package released with last night's press release details our financial performance for the quarter, so I will simply touch on a couple of the various items.

Additionally, our Form 10-Q will be filed later today, and will provide you with additional detailed information.

A couple of the more significant items for the quarter include revenues for the quarter being up -- pardon me, revenues for the quarter being 221 million, which is an increase of 14% from the 193.6 million in the prior year's quarter.

The increase is due primarily to a 16% increase in production volumes between periods.

This was offset by a slight decrease in realized commodity prices.

Additionally, revenues from realized oil and gas hedge gains increased to 18.7 million, which was up 5.1 million from the same period last year.

The current period's realized gains were almost entirely due to favorable natural gas derivative settlements.

Our net realized equivalent price for the quarter was $8.34 per mcfe, which is down 3% from the $8.61 per mcfe we realized in the first quarter of '06.

Although the amount realized in '07 was higher than what we had budgeted at the beginning of the year.

Realized prices for both oil and natural gas, however, were down 3% year-over-year.

Lease operating and transportation expense increased 14% on a per mcfe basis in the first quarter of 2007, versus the first quarter of '06.

The principal drivers of this were significant unplanned workover activity, and increased well servicing costs in the Rockies.

Jay will talk a little bit more on this in his operations review.

DD&A on a per mcfe basis had increased 22% quarter over quarter from last year.

This is a result of the higher costs incurred to develop and acquire producing assets in recent years.

Increases in per mcfe DD&A is something that St.

Mary and I expect the industry as a whole will generally continue to see as higher cost assets are brought to a productive state.

Exploration expense was 20.8 million in the quarter, nearly double the amount recognized last year in the corresponding period.

The difference is due primarily to three exploratory dry holes that were recorded in the quarter.

Two of these wells were in the Gulf Coast, and one was in the Rockies.

You may have noted that compared to our revised guidance that we issued on April 18, our exploration expense was lower and our G&A expense was higher than guidance by approximately the same amounts.

This was due to a change in the allocation of compensation expense associated -- pardon me, compensation to exploration expense related to a reduction of net profit pool payments for the quarter.

Before turning the call over to Jay, I do want to point out one item related to the $287.5 million of 3.5% senior convertible notes that we placed in April.

In contrast to our old 5.75% notes that we called and then were converted in March, the new 3.5% senior convertible notes allow for net share settlement.

This feature allows us to use the treasury stock method for the calculation of diluted earnings per share.

And accordingly, these new notes will not be factored into the calculation of diluted earnings per share until the per share conversion price for the notes, which is $54.42 has been reached.

With that, I will now turn the call over to Jay.

Thanks, Dave.

In the first quarter of 2007, St.

Mary participated in drilling of 81 conventional wells of which 76 were i successfully completed for a 94% success rate.

Additionally, the Company recompleted 17 wells with 11 of those being successful for a 65% success rate.

As of the end of the quarter, St.

Mary was completing 64 recompleting 17, and drilling 32 conventional wells.

In the mid continent region, there were 20 successful completions out 22 attempts for a 91% success rate.

At quarter end, the Company was participating in 16 completions, 3 recompletions, and 15 drilling operations.

Updating our activity in the horizontal Arkoma program, St.

Mary's recently completed two wells the wells Lambert 13 in which we owned a 97% working interest is the 8th horizontal Woodford well drilled by the Company and is producing at an average rate over the past several weeks of one million cubic feet a day.

This is a disappointing result for us, as our initial test rates from the well indicated significantly higher deliverability.

But the well is still cleaning up and will be an economic success.

The Cosmo 42 in which we own 100% working interest is the Company's 9th horizontal woodford well and currently producing the sales at a rate of 600,000 cubic feet a day.

This well encountered a number of drilling problems due to steep geologic dips in the area, but we had anticipated a better IP here as well.

We continue to evaluate various drilling and completion techniques to ensure the best long-term performance from this program and are also pursuing cost-saving technologies to improve our overall economics.

The Company's currently operating two rigs in this program, both of which are drilling horizontal wells targeting the Woodford shale.

In the northeast Mayfield area the Company is operating two drilling rigs at this time.

There were eight wells successfully completed during the first quarter.

At quarter end three wells were being completed and three wells were drilling in the field.

As we mentioned before, this is a play that requires a lot of attention to commodity prices and completion costs environment when making investment decisions.

Recent day rate reductions for rigs in the mid continent as well as stronger strip prices for natural gas certainly helped this project.

In the Constitution field, the Loretta B Casey number one well in which we own a 40% working interest which target the the harder sand was recently completed and is producing at a rate of 6.1 million cubic feet a day.

This rate is constrained by the gas plant's current capacity.

This well is an offset to the Pagey Brusard number one and two wells in which we also owned a 40% working interest.

The Constitution field has truly been a great field for the Company and we continue to work with our partner to identify other potential projects in the field.

However, I think it is fair to say at this point that future projects at Constitution will be smaller in number, and of smaller size than what we've seen with these previous wells.

Moving on to the Rockies, there were 19 successful completions out of 20 attempts for a 95% success rate, excluding coal bed methane wells in the Rockies region during the first quarter.

At quarter end, St.

Mary was in the process of completing 14 wells and participating in 7 drilling operations.

The Company currently has two operating rigs dedicated to its conventional drilling program.

In the Hanging Woman coal bed methane program, 28 wells were drilled in the first quarter and two rigs operating in the program as of March 31.

The drilling program at Hanging Woman Basin is on schedule and activity in the play will be ramping up as rigs are added and winter weather conditions subside.

311 wells were producing at the end of the first quarter compared to 263 at the end of the fourth quarter.

Production at the end of March was approximately 14.7 million cubic feet a day gross, and 8.9 million cubic feet a day net.

The Company is operating two rigs in the program at the current time with plans to increase the number of rigs in the second quarter in accordance with our drilling plan.

As both Tony and Dave noted our LOE expense in the Rockies was higher than budgeted.

This increased cost was due to several more difficult and expected workovers which occurred during the quarter.

And continued pressure on well servicing costs.

For clarification, the well servicing costs that we are referring to relate to maintenance-type work typically associated with oil properties, such as rod and rod pump changes that are expensed as LOE.

We know that many of you are hearing the drilling and completion costs are flattening from other operators and larger service companies and we see that as well.

These are largely costs that are capitalized, however, as part of the completed well costs and don't run through the LOE line.

Well servicing companies are facing many of the same competitive pressures including pay inflation as other segments of the industry.

And because of our earlier production profile, we are more exposed to increases in well servicing costs when they occur.

That being said, we have also benefited from higher oil prices on a gas equivalent basis.

In the Shreveport regional office, the Company successfully completed 20 wells out of 21 attempts for a 95% success rate during the first quarter.

At quarter end nine wells were completed and three wells drilling in the region.

At Elm Grove the Company is very pleased with the pace of development being pursued by our operating partners.

A 20-acre increase density program is being pursued on acreage adjacent to us by one of our partners and we expect that program to move on to our acreage at some point this year.

Also we recently heard a partner presenting at an investor conference saying that they were planning a series of horizontal test wells in the Lower Cotton Valley at Elm Grove.

Clearly there is a lot going on there and we feel that things are going well.

At Terryville which is also a Lower Cotton Valley program, the operator has informed us that they plan to drill five wells on our acreage this year and there are some indications that they may want to increase that number.

Time will tell what the final number will be but we are very encouraged to see activity ramping up on our acreage at Terryville.

The Company also continues to see impressive results in this horizontal carbonate program.

At Spider Field, the Company recently completed the Hewitt 10-2 in which we had a 100% working interest in the James line at a rate of 4.2 million cubic feet a day.

The Company currently has one operating rig dedicated to the horizontal carbonate program with plans to add a second rig later this year.

In the Gulf Coast, St.

Mary was completing six wells and was drilling two wells at the end of the quarter.

The Company had two exploratory discoveries in the first quarter.

In south Louisiana, we had a discovery with the Clomont number one well in which we had a 35% working interest, which is an offset to the successful [Inaudible] number one well at the south [Dusant] prospect that was announced in 2006.

First production from this well is expected in the third quarter of 2007.

In Galveston Bay, the state track 236 1 well, St.

Mary, 50% working interest is completing and first production is expected in the fourth quarter of 2007.

The Company has spent $7.4 million in the first quarter related to two dry holes in the Gulf Coast from its exploration program.

Including the nonoperated Battle Ax intermediate deep water prospect at East Briggs 369.

In the Permian Basin, the Company successfully completed all 17 wells attempted during the first quarter.

At quarter end, 19 wells were completing and five wells drilling in the region.

At Sweety Peg, St.

Mary has increase net production to 2805-barrels a day at the end of the quarter from 2610 at the end of 2006.

The Company is currently operating two rigs in the play with two additional rigs scheduled to be added in the second quarter.

Our new office in Midland opened in February and is now fully staffed.

Our exploration and development capital budget remains unchanged at $721 million for 2007.

We regularly review our capital program in total and at the regional level to factor in the most current information on commodity prices, drilling and completion costs, program performance and other factors.

Looking out for the rest of 2007, our focus will be successfully executing our program.

A number of our programs are meeting or exceeding our expectations but there are a few that we need to continue to work to improve.

In addition, operating costs are an area that we need to work on harder.

As an oilier company we will have higher operating costs than our gassier counterparts.

That said, we know that part of maintaining solid operating margins that we enjoyed is keeping our costs down so we will spend more time looking at ways to improve that.

That with that I will turn the call back over to Tony.

Thank you, Jay.

Exiting the first quarter, there are a number of items to be pleased with.

We posted solid first quarter results with record production, and discretionary cash flow.

Prices are strong and drilling and completion costs seem to be leveling off.

Our Sweety Peg, horizontal James line and Elm Grove programs continue to perform very well.

There are also some areas where we need to improve.

Clearly, we're frustrated by the horizontal Arkoma results from our most recent wells.

And we need to better understand what is happening and how to improve productivity in this play.

And focusing on reducing operating costs will be a priority for us going forward.

On balance, I am pleased where we are right now.

We will continue to focus on execution of our 2007 plan.

We are doing a lot of things right and I am confident that our employees will help us improve in the areas that I have identified.

We remain committed to delivering value to our stockholders, and I am confident that we will again achieve this business imperative in 2007.

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

(OPERATOR INSTRUCTIONS) Your first question comes from Scott Hanold of RBC Capital Markets.

Thanks.

Good morning.

Good morning, Scott.

Looking at the Woodford results, considering that I guess the results were a little bit less than you anticipated from those two wells, what things do you expect to do to try to improve those rates?

Or I guess better said, why do you think those rates didn't come in as you expected?

I think the first of all, the wells Lambert well, I'm not really sure what happened to be honest.

We had a higher test rate and we put rand tubing and put it to sales, it just hasn't made the rates we expect.

It is still making some load fluid back.

We have had trouble with some fill in some previous wells.

I don't think that is the problem here, because it is making quite a bit of fluid.

Frankly, I don't fully understand it yet.

And it would be premature for me to tell that you that I do.

I'm going down there next week and I am going to spend a lot of time with them on it.

The Cosmo well, I think it was a geologic issue.

We ended up in a well that was steeply dipping up away from us as we drilled the horizontal.

We drilled out the bottom.

We had some other drilling problems with the well.

And I think that one probably was a geologic failure in that sense.

I don't really see that one as indicative of future results, because I think we know -- but we've learned something from that and know better.

We have two other wells drilling right now, very hopeful that our results continue to -- will have continued to improve.

Our costs are still lower than the industry average in the play.

And with that said, we need to get better deliverability.

So we're going to be focusing on the G&G part of this, and working hard on -- again working hard on our completions but we clearly need to pick the right candidates here, so.

On those two wells that you're currently drilling is there anything that you are going to try differently on the completion or stimulation of those wells?

Well, one of the wells we're actually taking, we're drilling -- we didn't set intermediate and we're drilling the holes, the well from surface, in one shot.

Which is a significant cost savings effort on our part.

On the completions, we had planned to complete them essentially the way that Newfield and we have completed the last couple of wells which is a higher density frac technique.

That is something that I need to talk to the guys next week and make sure we're real comfortable with what we're doing.

At this point, I don't know of anything that we're doing that is wrong.

It is just we had -- we did have a disappointing result on this last well, and I don't know how to explain that any better at this point.

Okay.

Fair enough.

And then switching to the Hanging Woman Basin, I think last time, or the time before, you guys talked about drilling several horizontal wells there, in the Roberts, and I understand they need some time to dewater, but do you have any preliminary results out of there that tells you anything?

At this point, Scott, it is a little premature.

We're not expecting to see results or gas break-through until late this year.

And as you know, those wells are all variable, taking anywhere from 6 to 18 months to dewater and see gas break through.

So a little bit early yet to say on those horizontal wells.

Okay.

What is there -- what is your expectation?

What kind of rates should we be looking for to say this potentially is a success?

And remind us of the cost of the horizontal well in theory.

As far as the cost of the wells, a typical vertical well is basically about $.025 million, and the expected ER's are about a quarter BCF, for typical vertical well.

The horizontal wells are slightly more expensive than that.

But as far as IP's, it is a little hard to say at this point, since these are the first horizontal wells we've drilled.

So we're going to have to wait for them to dewater and then see gas break through and make some -- draw some conclusions from that.

So if I am understanding right, there is not sort of a production rate you're hoping for to say hey, this makes it economic but it will take a little bit of time to watch it?

That's right.

I mean at this point we just need to see these wells dewater and then see what kind of initial rates we get.

But the good news is, with the lower -- the deeper coal scene, I meanwhile they are tighter and that's why we are testing the horizontal technology, they also have higher gas content.

So we're looking forward to seeing the results of those first four horizontal wells.

What kind of results do you get on your vertical wells, what kind of IP rates?

Those are again about 230, 250,000 cubic feet per day.

So a good way to think about those is kind of a quarter, quarter, and a quarter, a quarter of a million to drill them, quarter of B in terms of EUR, and then about a quarter of a million in terms of IP.

And are those completed in a single zone, or do you complete those as multiple zone wells.

Most of them are multi zone completions and I need to point out when we say IP that these wells actually come on low and then come on, actually ramp production to a peak, and then come off the peak, and that number we're quoting you is the peak rate, and it occurs sometimes 6 to 12 months after the well initially starts production.

Yes.

Good enough.

Thank you.

Thanks, Scott.

Your next question comes from Larry Busnardo of TRI-Stone Capital.

Good morning, Tony.

Good morning, Larry.

How are you doing?

Good.

Just looking at Sweety Peg, can you talk about what you've seen on the initial program and how that relates back to your early expectations on the play?

Yes, Larry, we've been extremely pleased to date with pretty much all facets of that acquisition, and the transition to operations.

The guys down there are working that hard.

They're right on schedule.

They're picking up the third rig, which should be in the field any day now.

So we're actually seeing better progress in terms of being able to add the additional rigs earlier.

Right now, we're targeting 54 wells, for the year, and that remains the same.

But everything has gone pretty much as planned on that program, and as you know, with an acquisition of that size, that's your initial challenge, is getting those -- getting the operations transitioned, getting the people on board and getting the office opened and that could not have gone better so far this year.

Just remind me, what is going to be the plan for next year?

You got 54 wells this year.

You will go into next year with 4 rigs.

Do you plan to keep the 4 rigs running?

And how many well do you think you can get drilled there?

We really haven't defined our program for '08 yet.

I think it is fair to say that if we continue to see positive results, we certainly want to build on that.

And like we have shared, we're ramping to four rigs, we are going to keep four rigs to the rest of the year, and then program performance will dictate our plans for next year.

Is there a potential that you maybe even add additional rigs next year?

Or is four kind of the limit for right now?

Or since it is still early, you just want to see how it goes with the initial program?

I think there is always that potential, but I think right now, the key is to focus on execution in the program for 2007.

Fouring rigs, believe me, is plenty to keep us busy there in the field and then we will let performance drive where we go from there.

Just, shifting over to the Woodford, can you just remind us what are the well costs there?

It sounds like, a big part of the economics of the play or making these wells economic is going to be one, obviously getting good IP rates but also lowering the costs.

Where have costs gone from where you have initially started to where they are now and then where do you think they could go?

I think right now, we're seeing kind of an average completed well cost there of about 4.3 million.

And obviously, that has continued to trend up, as have drilling and completion costs over the last couple of years.

Originally, those were in the low 3 million kind of range, and then pretty much as the rest of the operators have seen, those have trended up over 4 million.

As Jay mentioned earlier, our key focus is obviously on completion design and optimization, but the other key element here is to do everything we can to minimize the costs associated with these wells.

Okay.

Great.

That's it.

Thanks, Tony.

All right.

Take care, Larry.

Your next question comes from David Tameron of Wachovia.

Good morning, Tony.

Good morning, Dave.

How are you doing?

Good.

Good.

Couple of questions.

Hanging Woman Basin.

Infrastructure-wise, with the coming tightness in the Rockies this summer, et cetera, et cetera, do you guys foresee that impacting development over the next six months?

I don't think we've identified any issues with that at this point.

It is taking us longer to get wells hooked up and flowing than we like.

But a lot of that is regulatory.

We haven't talked about or had any indication that we're going to have an issue getting our infrastructure done.

Okay.

And given the early phase of the play, I would assume that you'd continue drilling even if prices dipped down for an extended period of time, given the dewatering, et cetera?

You look at it you got 6to 12 months before first production, so the decision on drilling a well really is a month out kind of an issue.

We got about 70% of our gas hedged at this point.

So I don't think we'd slow down for a short term.

We had, for example, in April, there were some basis issues in April in the Rockies, we didn't slow down for that, so this is a long-term project, and we will probably maintain our pace, unless something comes up to tell us that we need to do something different.

At this point, we haven't seen that.

Okay.

And then Jay, last week, when you spoke at the [Platte]conference here in Denver, you mentioned your people needs.

You guys are still trying to aggressively hire.

Can you remind me what you said, where you're looking to add people?

We're adding people in every regional office.

Midland is pretty well fully staffed at this point.

But we have people needs in Houston, Shreveport, Tulsa, Billings and Denver.

And we're adding drilling staff as well as administrative personnel.

It is a tough market out there for people.

We have been successful.

I think as a company, we have added something like 60 people in the last three or four months.

So we are being successful in recruiting.

I think St.

Mary is an attractive place to work.

But it is a challenge.

And I think it is one of those industry issues that is not going away.

Okay.

So I guess, and partially where I'm going with this, even though service costs are coming down for the industry as a whole, you would expect G&A costs to continue not just for St.

Mary but the industry as a whole as people need to recruit through G&A costs head higher?

I don't think there is much question that you're going to see increasing pressure on salaries, and at least on a per person basis, and hopefully, on a unit basis, we can grow fast enough to keep our G&A reasonable.

Grant pointed out to me I think we said earlier in the, the 48 employees were hired, and the number I quoted you of 60 goes back a little bit into 2006.

Dave, this is David Honeyfield.

Certainly on an absolute basis, that G&A cost will increase, the production will go along with it, and right now, our guidance for the year is $0.44 to $0.48 per mcfe, which is generally in line.

Clearly, a piece of that is related to the net profit payments and such.

So there is always variability, but like Jay mentioned, it is something that we're seeing throughout the industry, and part of that cost ends up getting allocated to exploration expense as well, but overall, like we said, on a per mcfe, I don't think it will be a dramatic step.

All right.

Thanks.

That's all I got.

All right.

Dave.

Thank you.

Your next question comes from [Sebastian Andrew] of Jefferies and Company.

Hi, good morning.

In the Hanging Woman Basin, could you express in maybe barrels per MCF the kind of water you're seeing?

We don't have that figure with us.

We can get that to you.

Do you think it will be kind of similar to the overall powder play?

I don't know that I even know that number for the overall powder play.

Or do you have current order production rate?

I have it here somewhere.

Actually, it is not on this sheet.

Hold on.

I don't want to give you a number that is wrong.

I will follow-up.

No problem.

We can get back to that.

In the Woodford, the prior wells, I guess, three or four that work nicely for you, how have they been holding up?

And to get a cut in the $2 F&D range is there a ballpark IP number that one needs to see or is the correlation there not really obvious?

If you go back to the history of our woodford program and we had three or four disappointing wells initially, we drilled some stuff that just doesn't work out well and we had three or four that we're improving and these last couple are at the end of that, we have been using numbers around two BCF a well so that implies if you want to get to the $2 range, that is a $4 million well.

Some of our competitors are coming out with higher reserve numbers and higher costs but they are still in that kind of $2 range.

I don't know that I have enough data at this point to draw strong correlation between IP and EUR.

We actually had one of our wells that the rate keeps going up.

We started out kind of low, the Churner well we talked about, actually started out at 600 or 700 a day and has come up some but I have seen industry data at the conferences I've been at where some of our industry competitors are seeing strong correlations between initial production rates and six to nine-month cume.

Nobody has one of these wells out there that is terrifically far out.

So we do believe there is a correlation between initial production, and cum eventually.

And clearly, from an economic standpoint, having high initial production is a great thing from a PW standpoint.

So we're working hard.

We do think that there is a rationale to think that if you get a good frac job and good completion you should have higher IP's.

That makes sense to us.

From what we see these things are hyperbolic.

They are going to come down pretty fast and then flatten out.

It is still early days but that is the kind of production we anticipate.

So we want to get our IP's up, no question we would like to see higher numbers here and we just need to keep working away at it.

Where you see maybe the -- in your limited data set, where you don't see the hyperbolic, where you see in that one instance, production going the other way or production hold up fairly flat after IP, what would you attribute that to?

That particular well, we attribute it -- we drilled out the bottom of the zone, and we felt like our frac job that we ended up completing a bunch of stuff below the shale, and we made a lot of water early on, and it just, it was a clean-up process, and then we got back into the well, and found out we had fill.

Fill in the well.

So I think there is -- that is going to be an issue on these laterals, is to make sure the well bore is cleaned out and that you really got everything back.

And so I think to be honest, we talk about these rates, we give numbers, because everybody wants to hear them and we're excited about some of this stuff, too.

But these are -- this is a long-term project.

These wells are going to produce for a long, long time.

And we tend to give these rates that are two, three-week kind of measured numbers, really you need to look at more data over a longer period of time to have a real understanding of what is going to happen.

So we talk about nine-month cumes, and nine month cume, six-month cumes, it there is a number that is real meaningful.

Sometimes we get too tied up on these initials wells because the wells are still cleaning up, they are still pulling black load fluid.

Another way to think about that is we've drilled nine wells and we've got almost 300 potential 3P locations, so as Jay mentioned we're still very early on in this emerging play and we still have a lot to learn.

But it is going to be a function of both completion design, but also drilling execution.

And you got to do both as well as manage your costs while you do it.

And one last one, in New York, at the IPAA, you said you weren't really looking at rationalizing any assets right now, really more focused on the growth side.

Has that evolved any?

I know it has only been a week or, two or is it even on deck to consider this year?

Does it make sense maybe in some of these areas that you mentioned, like constitution, et cetera, where future projects smaller, that someone else would pay a lot more for that potential?

Actually, since IPAA -- I've been on the road for the last two weeks, so that is not something we've worked in the last few days.

But what I can tell you is that this year, we will take a look at our entire portfolio.

In fact, we will do that every year to assess where our various assets are and their level of maturity.

For the most part, however, if you look at our inventory of assets, many of these are relatively new and still developing plays, so I mean there is not going to be large assets or programs that I think lend themselves to divestiture any time soon.

But I think it is just good business sense every year for us to review our portfolio and decide if there are some properties that it may be time to divest.

Thanks much.

You bet.

Your next question comes from Philip Dodge of Stanford Goup.

Good morning, Phil.

Good morning, everybody.

Thanks for the comments.

First, I want to ask you about Constitution, what the two Apache wells are currently producing.

Those, let's see, we're getting our current rates, Phil--.

Just wondering how they're holding up.

Current growth rate on Apache one is 32 million a one.

Net.

And it is making 1500 barrels a day of condensate.

And Apache's 2's growth rate is 2 million a day and about 12 million-barrels a day condensate and our working interest again, is 40%.

And then with the drilling of wells with smaller potential, would you expect to be able to maintain, still maintain or increase production a little bit to Constitution?

Well, we brought that well on 6 million a day, I mentioned it is constrained by plant capacity, we really don't know how much we can add there as we get some of the constraints off.

You know -- I think we were careful how we worded this.

These are big wells, at fairly steep decline rates and I think you can expect that we will not replace production here over a significant period of time.

Okay.

And then is there any current drilling at Judge Digby or planned for later there year?

There is one well that is being deepened--.

Is it recomplete or deepening?

Yes, it's a deepening.

That is BP operated?

Right now, Phil, we're basically watching BP, they're deepening a well, the majors number six, I believe, and we're anxious to see the results of that work.

As far as I know, that is about the only immediate work plan there.

Yes, that is what is going on.

And then any activity anticipated for the fee lands later this year?

We've had a number of serious inquiries in terms of opportunities to possibly see some additional exploration work there.

We also have had some discussions with some of the opportunities to possibly see some additional exploration work there.

We have also had some discussions with some of the operators that have been involved in the field, we had one operator that had a very productive well there last year, first quarter was producing somewhere around 15 million a day, that well has had mechanical problems, and has been PA'd, and we have -- we don't have definitive information that they plan to drill a replacement well, but we continue our discussions with them on that.

Yes, that would be Conoco Phillips since they took over Burlington?

That's correct.

And then finally, just a detail, could you give us the average prices for oil and gas before the effect of hedging in the quarter?

Most of this data you guys probably already have but for the quarter the NYMEX oil price was 58.27 and then the pre-hedge realized price was 52.61.

There wasn't much in the way of hedge gain or loss on that, just $0.01.

Gas on the other hand, the NYMEX price was 6.96.

The net realized before hedge was 6.82.

And then the gas price after effective hedges was $8.04.

Okay.

That was 6.82 I needed.

Thanks very much.

All right, Phil, thank you.

Your next question comes from Nicholas Pope.

JPMorgan.

Hi, guys.

Nick, how are you doing?

Good.

I was hoping you could expand on plans for growth in the Permian Basin now that you have the Midland office fully staffed?

Is it going to come from tack-on leases or potentially acquisitions?

And just trying to get a feel of what that market is right now out there in the Permian Basin, what it looks like.

Yes, Nick, obviously, our primary focus and our first priority right now is to make sure that we're focused on this year's drilling plans, that those continue to perform well, as we've been -- as I mentioned we've been very pleased with what we've seen so far.

Having said that, since the first day we opened the office, we have continued to have a surge of inquiries in terms of people coming by, with opportunities for us to consider.

Everything from small kind of acquisitions to partnering to seismic deals to land deals.

And that has been very promising.

And we've continued to review those, to evaluate them and screen them.

And to me, that is exactly why we have a presence in the Permian Basin now, is certainly to execute on our new acquisition at Sweety Peg, but also to leave the front porch light on and let folks know we're interested to see what other opportunities might be out there and we have been very pleasantly surprised.

So to me, it is that kind of deal flow that I think is going to generate kind of our next opportunities in the Permian.

I can't tell you what those are at this point.

But I do know that we have had an awful lot to look at in a very short period of time so we're very hopeful more will be coming.

All right.

Thanks a lot.

All right, Nick, take care.

Your next question comes from John Gerdes of SunTrust.

Good morning, Tony.

Hi, John.

How are you?

I'm good.

How are you?

Fine, thanks.

A couple of things.

On the Woodford, you mentioned some possibility of some fill on one of the lateral sections.

You guys are completing -- what is the completion design here?

You are working with a mechanical, like a packer, mechanical isolation, with a pre-perforated type of a liner?

Yes, these are cemented liners with that we, as I recall, we tried several different things.

To be honest, I need to make sure I check on this particular well.

The one we had fill-in was the Churner well.

And they went back in with coil tube and cleaned it out and found some bridges deep in that lateral.

My recollection is that was a cemented liner completion, as I recall.

Dennis, is that right?

Yes.

We've done -- we are trying a lot of different things.

One of the reasons I'm going down there next week is there is this whole alphabet soup of different completion techniques from Peak and Xscape and Packer's Plus and liner completions and we really need to -- I really need to get a better understanding of exactly what all the differences are between those and which ones we are really thinking hard on using.

Probably the most interesting thing we're doing with this well is we're trying to drill the whole vertical end, horizontal section in one shot and that has a significant potential for reducing our costs.

Are you--?

But with all that said, we have been very cost focused and I think it is fine to be cost focused, we want to be cost focused, we want to drill cheap wells but I want to make reserves here, so we need to make sure we're not getting the cart in front of the horse.

We need to cut costs but we also need to make the kind of wells that our competitors are making in the play.

So we are going to keep working on it it.

And you guys, as far as the stimulation density, are you working with about every 500 feet or so is what you're kinds of currently the last couple of wells?

Yes, we are.

And basically, we've been following the industry trend on that.

I think in general, our well costs are still lower than others.

One of of the issues that I need to get in there and talk to guys about hole sizes, and a number of issues, just to make sure that we're doing everything we can.

The other issue here is just the G&G aspect of it.

To make sure that we're picking the best possible locations.

I know the guys are working it hard, but like this Cosmo well, clearly a more difficult target, where you are steeply dipping up and away from you, and we drilled out the bottom, at least once, and you tend to end up at the bottom of the shale a lot.

The kind of -- we sort of believe that you need to be in the middle of this thing most of the time to make a good well.

Some people will say you really don't need to steer them.

We kind of think you do.

So there is a number of issues there to work.

And I think there's plenty of ground that we can make up here, and I'm not -- we are making economic wells, generally, I just like to see the reserve -- I would like to see higher IPs because it gives me the feeling that we are going to hit the higher reserve numbers.

Is 3-D helping you at all here?

Yes, we've got 3-D.

We knew what we were heading for.

We just didn't anticipate some of the issues we ended up with.

The other issue with the Cosmo well, is we ended up having to side track the well at one point so it was a fairly expensive proposition.

And you mentioned the fact of drilling a hole, the vertical and the lateral section, you mentioned one trip?

Is that what you're suggesting?

We said surface.

And we're drilling the whole remainder of the well in one trip.

Not in one trip, but in one hole size.

One hole size.

And that is not uncommon.

You see people do it in the Barnett.

Right.

Shifting gears, the Hanging Woman Basin, you are getting production progression here, I mean you exited the year, the last year at about 13 million a day gross, you're approaching 15, and what is your all sense of -- do you anticipate now looking forward some acceleration at some point here?

I know you talked about dewatering and that process is still unfolding and that takes time, appreciable time, maybe a couple of years I guess but at some point do you anticipate a bit more of a hockey stick progression in terms of the volumes there at Hanging Woman?

And if you do, kind of a sense of when that trajectory might unfold.

As John, as we've talked, one of our priorities this year is to accelerate that program.

And basically take it from a two rig program to a four rig program.

And that is quite a ramp-up year to year going from 138 wells last year to 218, plus 40 non-op wells that we will participate in.

So I mean I would expect to see a ramp-up in production.

Our ultimate objective is to take this from a 20-year kind of a development program to a 10-year development program.

But I don't know if it is going to be a hockey stick, but clearly, our intent is to see an upward incline in production.

Well, you mentioned the accelerated rig activity which would create hopefully that force of production progression but just the nature of these wells as you do dewater them, do you tend to pick up an acceleration to the upside in terms of the deliverability and that being the expectation over the next several quarters?

With the existing producing wells.

This is Dave.

I think if you look at last year, we produced -- it was about a B total production, out of Hanging Woman Basin, during 2006.

And I think it will probably be about BB's for the full year, so each quarter, I would expect that to go up, and there is a little bit of an impact in terms of timing, when a pod comes on, because we tend to drill these in groups of wells, and then so you may have a little bit of activity and then you start the dewatering for a group of say 20 wells or 30 wells or so.

So it is not -- it is probably not going to be as steady as maybe we would all like to see.

But I think if you measure it, from year end to year end to year end, yes, you will continue to see that increase.

And we may have some better visibility here, as we get later in the year, in terms of kind of longer term type production forecasts here, but I would say right now, that 2 BCF number for the year is probably a pretty good number.

Right.

Thank you.

Thanks, John.

Your next question comes from Scott Hanold of RBC Capital Markets.

Thanks.

I had a follow-up on hedging.

I guess you guys said you are about 70% hedged on your gas.

Can you sort of talk about what your strategy is with your Rockies gas, considering how the basin can blow out, are you hedging at NYMEX, are you looking at more basin specific hedges in place and sort of give us your thoughts on what Rockies express could do going forward in your view.

Scott, in terms of the have you on hedging, overall, as a company, and probably a broader answer that you're looking for here, but overall company, we tend to hedge around acquisitions but we also will look at specific projects if we think it makes sense, and I think the Rockies, CIG issue, is one of those that at least in my opinion, if you look at year -- I guess about two years out, right now, the basis is back down to under a dollar.

Well, it always seems to be about under a dollar about two years out, so it is one of those things that we are starting to look at quite a bit more closely, as the volumes, particularly out of Hanging Woman Basin, like we just talked about a moment ago, start to increase.

If we end up hedging on that stuff, the only way to hedge is to make sure you hedge it in the basin.

What we've done historically on the gas side is we've had -- I will call them regional hedges, where it is tied through a delivery pipe, that corresponds with our actual physical deliveries, so that basis has been hedged.

And I think we will do something very similar in the Rockies going forward, as we move along.

Overall, for the year, in terms of where we're at right now, let's see, our gas hedge percentage for the company as a total, we're about 45% hedged for the remainder of the year.

And the break-even price is just over $9 NYMEX.

Clearly, I think -- I wouldn't get too focused in on the Rockies gas hedge percentage right now, only because the majority of the production out of the Rockies is still oil production for us.

Looking forward, when you see those pretty -- I guess, favorable differentials over the next say year or two, when you look forward at sort of some of those indexes, are you able to efficiently put some of those hedges in place or what would you need to happen to get more comfortable to start layering in some of those forward years for some of that potential growth in Rockies gas.

I think really a lot of it is just visibility in really what sort of volumes we think we're going to actually have out there.

The markets are quite liquid.

So getting the hedges done is not a problem.

But making sure that we know what the appropriate volumes are to hedge so that we're not out there with speculative hedge positions in place.

Okay.

Thank you, guys.

Thanks, Scott.

Your next question comes from Jack Aydin of KeyBanc.

Hi, everyone.

Good morning, Jack.

Tony, do you have a ceiling or limit on exploration and dry well expenses for the year?

I mean it looks like you -- you -- compared to a year ago, you run through 40% of last year, number, in the first quarter.

So do you have a upper limit to what you think you might spend on there, or you would like to?

Jack, this is Dave, actually.

We had -- it was about $9 million, about $9.7 million of dry hole costs that came through in the first quarter of 2007.

And there was a little bit of dry hole costs that we had last year as well.

Overall, for the year, I'm not sure if we've got a precise number, but I wouldn't expect to see the level that we've had this year.

I think we're well over -- we spent well over a quarter of our exploration dollars for the year, so I would probably temper that back, a couple 3 million, 3 or $4 million a quarter at this point.

If you look at the program, we drilled -- most of our offshore exploration stuff was in the first quarter.

We really don't have a lot out there coming up.

So it should have been disproportionate in the first quarter.

Tony, is the offshore area, is it core area for you, or -- I mean is it the type of play that you like to be involved for your size of a company?

I know that the present value of the production and cash flow is important, but is that an area that you really like to focus on?

Jack, what we've done is primarily leveraged our technical team in Houston, which has DHI technical capability, and we've used that to look at a variety of exploration opportunities, both onshore as well as offshore, and you know, as we've announced, we've had a couple of good discoveries.

However, having said that, I think we are going to be selective going forward, in terms of exactly what DHI prospects are we going to want to participate in.

Obviously, the deeper water you head towards, the higher the costs, and the higher exposure.

And we have excellent partners that we participate with.

We don't operate when we get into deeper water.

One of the dry holes that we just discussed, the Battle Ax, we've got a very good partner there.

And in that case, unfortunately, it turned out to be dry.

But we will take a look at these prospects on a case by case basis.

But I think it is fair to say longer term, we will probably not put any priority on the deeper exploration plays.

Thank you.

All right, Jack.

(OPERATOR INSTRUCTIONS) At this time, there are no questions.

Are there any closing remarks?

No, not at this point.

We would like to thank everybody for calling in and participating in the call this morning.

This concludes today's conference call.

You may now disconnect.