SM Energy Co (SM) 2007 Q3 法說會逐字稿

Good morning.

My name is Heather and I will be your conference operator today.

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

Mary Land and Exploration's third quarter 2007 earnings conference call.

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

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

(Operator instructions).

Mr.

Collins, you may begin your conference.

Thank you, Heather.

Good morning to all of you joining us by phone and on line for St.

Mary Land and Exploration Company's third quarter 2007 earnings conference call.

Before we start, I would like to advise you that we will making forward looking statements during this call about our plans, expectations and assumptions regarding our future performance.

These statements involve risks which may cause our actual results to differ materially from the results expressed or implied in our forward-looking statements.

For a discussion of these please refer to information about forward looking statements in our earnings press release and the risk factors section of our 2006 form 10K and subsequent 10Q filed with the SEC.

We'll also discuss non GAAP financial measures that we believe are useful in evaluating our performance.

A reconciliation of those measures to the most directly comparable GAAP measures and other information about these non GAAP measures are included in our earnings press release from last night.

Lastly, we may use the terms probable, possible and (inaudible) reserves in this call.

Probable reserves are untrue of preserves which are more likely than not to be recoverable.

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

Estimates of probable and possible reserves which may potentially be recoverable through additional drilling or recovery techniques provide our nature more uncertain than estimates of crude reserves and accordingly are subject to substantially greater risk of not actually being realized by the company.

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

I'll now turn the call over to Tony.

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

After a few opening remarks, I'll turn the call over to Dave Honeyfield, our CFO for a view of our financial results.

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

After Jay's discussion, we'll turn the call over for questions.

The third quarter was another successful quarter for St.

Mary.

It marked the seventh consecutive quarter that we have grown production and we set a new quarterly production record with over 298 million cubic feet equivalent per day.

The performance of our regional drilling programs as well as integrating and building upon our recent acquisitions are responsible for this increase in production.

As a result, in our third quarter operations update, we increased our full year 2007 production guidance range to 106 to 107 Bcf equivalent.

Our 40% production waiting to crude oil allowed us to benefit from the run up in crude oil prices during the quarter and our hedging program protected us from some of the softening gas prices that also occurred in the third quarter.

During the quarter, we announce the $153 million acquisition of oil and gas properties at the Gold River Field in South Texas which targets the Olmos gas formation.

This transaction closed on October 4, 2007 as planned.

These properties are adjacent to the Olmos properties the Catarine Field that we closed on in June of this year.

Our Gulf Coast team in Houston is now busy integrating these two acquisitions and we are very pleased to have another multi year, highly repeatable drilling program in our portfolio.

The model of entering the play on the small scale and then expanding our presence as we improve our understanding is one that we have successfully used twice during the past year in the Wolfberry as well as in the Olmos.

It is a model that we intend to replicate going forward.

In the third quarter, we also announced our planned divestiture of non-core oil and gas assets, the majority of which are located in Mid Continent and Rocky Mountain regions.

We expect bid by the middle of November and plan to close the transaction by year end.

This planned divestiture will allow us to rationalize our portfolio and will allow our people to focus their time and efforts on projects that will provide the most growth potential for St.

Mary.

The proceeds from the sale of these properties will also benefit our cash flow and allow us to pay down bank borrowings.

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

Thank you, Tony.

As presented in our press release last night, St.

Mary reported quarterly net income for the third quarter of 2007 of $57.7 million or $0.89 per diluted share.

This compares to $55.9 million or $0.88 per diluted share for the same period last year.

Adjusting for non cash and nonrecurring items, our adjusted net income for the third quarter of 2007 was $57.8 million or $0.89 per diluted share compared to $53 million or $0.83 per diluted share for the third quarter in 2006.

Discretionary cash flow for the third quarter was $162.3 million, that's up 16% from the $140.5 million in the comparable period last year.

On the financial highlights release with yesterday's press release provide additional detail on our financial results.

Additionally, our form 10Q will be filed later in the day today.

I'll now touch on a couple of significant items for the quarter.

First, revenues for the quarter were $246.7 million, an increase of 25% from the $198 million in the prior year's quarter.

The increase is due to a 19% increase in equivalent production volumes between periods combined with strong realized prices.

Revenue from realized oil and gas hedges was $10.2 million during the quarter, up from $4.8 million for the same period last year.

The current periods realize hedge gains were due to favorable natural gas derivative settlements offsetting realized losses on our oil derivative contracts.

Our net realized equivalent price for the quarter was $8.69 per MMCFE/d, which was up 4% from the $8.33 per MMCFE/d we realized in the third quarter of 2006.

Including the effects of hedging, the realized gas price was down 2% from the same period a year ago to $7.03 while our realized oil price increased 10% to $67.56 per barrel.

One note regarding our gas price realization for hedging, several of our regions produced higher BTU gas that [scripted with MGLs].

The percentage of our gas production that benefits from extraction of liquids has increased in recent quarters due to the Sweetie Peck and Catarina acquisitions.

The volumes for this rich gas are measured entirely on Mcf; however, the sales revenues reflect prices for dry gas plus the realized revenues from the NGLs.

Since NGLs tend to trend with crude prices and the run up in crude prices, we've seen our gas realizations have been improved as a result.

Moving on to the lease operating expense and transportation, each were up slightly on the per MCFE basis over year end and sequentially from the second quarter.

The third quarter of 2007 saw significant work over that equated to approximately $0.03 per MCFE at the non operating Judge Digby Field.

TD&A on a per MCFE basis increased 25% quarter over quarter from last year.

This is a direct result of the higher costs incurred to acquire and develop assets in recent years of relative to our historic base.

TD&A on a per MCFE basis will probably continue to be pressured upward as relatively higher finding cost assets become a larger part of our production base.

Exploration expense came in slightly lower than our guidance at $15.3 million due to lower than anticipated G&G costs in the quarter.

The increase year over year, however, is a result of increased technical headcount, some higher net profit pool payments, as well as seismic activity in the Mid-Continent region.

Our G&A came in slightly higher than our guidance, primarily as the result of higher than anticipated cash and stock base compensation expense associated with our growing employee base as well as costs to offices to support this higher headcount level.

A portion of our stock base compensation moves directionally with our share price which had increased roughly 10% in September.

We continue to expect the current cash taxes will account for approximately 15% of our total tax expense for the remainder of the year.

While we're generating significant net income and cash flow, our capital expenditures are significant enough to allow us to utilize the accelerated deduction associated with IDCs and reduce current cash taxes.

We also expect that the proceeds from the anticipated divestiture will be tax deferred by utilizing a reverse Section 1031 exchange structure.

Our balance sheet remains strong with our debt to book capitalization ratios standing at 32% at the end of the quarter.

We utilized our borrowing facility to fund the acquisition of the Gold River assets in early October making our pro forma debt to book capital ratio approximately 39%.

The proceeds from our previously announced planned divestiture of non core oil and gas assets will be used to pay down outstanding borrowing under the revolving credit facility.

Our plan is to bring down our debt to book capital ratio to somewhere between 30% and 32% by the end of the year.

During the third quarter, we repurchased approximately 791,000 shares of stock in the open market during August for a weighted average cost of $32.76 per share.

We have Board authorization to repurchase an additional 5.2 million shares and continue to evaluate opportunities to repurchase stock as part of the company's ongoing business plan.

Lastly, in our press release from last evening we provided a summary schedule of our current hedging positions.

For the fourth quarter, we're 67% hedged on oil with a break even price of $65.28 and 50% hedged for gas with a break even price of $8.91 per Mcf for the fourth quarter.

The form 10Q that will be filed later today will have a more detailed hedging schedule for those that are interested.

With that, Ill turn the call over to Jay.

Thank you, Dave.

In our October 15th press release, we provided a detailed overview of our activity in each of our regional areas.

I'll refer to listeners on this call to that press release for specific regional operating statistics and focus my remarks on our highlight plays in each region.

Starting in the Arklatex, we continue to see excellent results in the operator James Lime play.

We have two solid wells in Spider Field, the Weyerhaeuser 11-2 and Weyerhaeuser 12-2, both of which are 100% working interest wells.

Wells had initial 10 day sales rate averages of 3 million a day and 3.2 million a day respectively.

These wells continued a successful development of our established production basin and the James Lime trend.

In our last earnings call, we discussed two successful operated wells which expand the play along the 75 miles long trend from northern Louisiana into eastern Texas.

These wells, the Middlebrook 1-H and the George Smith 1 are meeting the company's expectations and we're currently drilling more wells in these extension areas.

The James Lime is clearly an area we are all excited about and we're working to expand our acreage in the area.

In the two Cotton Valley programs operated by others, we're pleased with pace and results of development.

In Elm Grove, there are three non-operated rigs operating on acreage in which we have an interest.

Our operating partners continue to examine 20-acre increased density drilling and are examining whether horizontal development may be applicable in the field.

At Terryville, two rigs are operating on acreage where the company has an interest.

Recent drilling results have been consistent with our expectations.

In the Mid-Continent, St.

Mary continues to make strides in our horizontal Woodford program and the Arkoma Basin.

Our recent wells drilled and completed utilizing a larger pipe size and high volume crack simulation for Duncan Shores 1-1 in which we have an 81% working interest, the Phillips 5-12 where we have an 83% working interest and the James 1-34, a 72 % working interest appear to validate this well design that we plan to use going forward.

These recent wells have helped further our understanding of the reservoir system and we're actively working the geologic side of the equation.

We're currently acquiring an additional 3-D seismic and by year end should have approximately 75% of our acreage covered with 3-D.

We plan to have one to two rigs operating in this program for the remainder of year.

Currently one well is completing and a second well drilling.

It's still early days in this play and it's important to note that we've only drilled and completed 13 wells in the trend; however, we are encouraged with these recent results.

In the Mayfield development in western Oklahoma, we are operating two drilling rigs.

Activity there is focused on additional Granite Wash opportunities and high grading our Atoka program.

Moving on to the Permian.

On a net basis, we've ramped up our activity in the tight oil program targeting the Spraberry interval, which has contribution from the Spraberry, Leonard and Wolf Camp formations.

This play is now widely being referred to as the Wolfberry play throughout the industry.

In the same area operated Sweetie Peck field, the typical well performance continues to meet expectations set at the time of its acquisition in late 2006.

For most of the year our activity has been running ahead of schedule at Sweetie Peck.

In the third quarter, we reduced our recount from five to three as a result of some disappointing grade performance.

In addition to upgrading our rigs there, we've also added additional drilling staff to monitor and enhance our drilling performance.

At Halff East, as a result of better than expected productivity, we are more than doubling the originally planned 15 wells in this non-operated program where we have a 65% working interest.

Our operating partner has two rigs running in the program.

Between these two Wolfberry plays, the company plans to drill or participate in the drilling of approximately 80 wells in 2007, up from our original budget of 69 wells.

In the Gulf Coast, the company completed eight operating wells targeting the Olmos formation of the Catarina Field during the third quarter.

This field was acquired in June 2007.

On our last earnings call, we announced that we had entered into an agreement to acquire $153 million of oil and gas assets at the Gold River Field targeting the Olmos as well.

These properties are adjacent to the Catarina Field acquisition we closed in June of this year.

The Gold River transaction closed in early October and the Gulf Coast team is busy integrating these two new assets.

The combination of these two acquisitions gives us another strong multi year drilling program.

In total, the company plans to run two to three rigs in the Olmos for the remainder of this year.

Also in the Gulf Coast region, we had two exploration discoveries in the third quarter from our DHI Program.

These targeted the mid-Miocene era sands and are anticipated to be on production near the end of 2008.

We also continue to participate in the completion and development of previously announced exploration wells.

In the Rocky Mountain region, the major story impacting the third quarter was a significant pressure on natural gas prices particularly pricing tied to CIG.

Fortunately, 70% of our production in the Rockies is crude oil.

A meaningful portion of our Rocky gas production is gas associated with oil production.

The company's exposure to CIG is relatively modest representing approximately 7% of St.

Mary's total equivalent production.

In the Rocky Mountain conventional program, the companies operated efforts have been centered on programs targeting the Mississippian aged intervals and Red River formation in the Williston Basin, as well as a Bakken infill program in Montana.

They currently have 47,000 gross and 32,000 net acres in the North Dakota Bakken trend near the Nesson anticline and are monitoring activity in the area closely.

In the greater Green River Basin, the company has deferred a number of projects due to the natural gas price issues mentioned earlier.

At Hanging Woman Basin, the company temporarily restrained gas production of the program due to the weak CIG pricing that we've experienced in the quarter.

At September 30th, production was 11.1 million cubic feet a day gross and 6.8 million a day net.

The company has recently increased production in Hanging Woman Basin as a result of securing more favorable pricing subsequent the quarter end.

Current production stands at 15.4 million a day gross and 9.6 million a day net.

St.

Mary has six operating rigs running at this time at Hanging Woman and the focus of the program for the remainder of the year is to expand our Eastern development area, complete the 80-acre infill program in the [shallow coal] and drill several additional test wells in the deeper Robertson Hendrick coals.

We expect total production for Hanging Woman Basin to be approximately 3 BCFE for the full year 2007, which is 50% higher than 2006's production.

Our key resource areas are clearly driving our production growth.

Our daily production rate increased 46.7 million cubic feet a day between the third quarter 2006 and third quarter 2007.

Of this growth, 38.5 million cubic feet equivalent per day or roughly 80% came from Sweetie Peck, the horizontal Woodford, Elm Grove, the James Lime program and our Granite Wash program.

We are committed to improving and enhancing on our operating abilities on these existing programs and continuing to build through grassroots leasing efforts or review of acquisitions, economic drilling inventory, both of which will enable us to continue growth.

The data room is open for our previously announced divestiture of non core oil and gas properties.

This marketing process is being coordinated by Albrecht & Associates.

The properties are located primarily in the Rocky Mountain and Mid-Continent regions.

We believe it's an appropriate time to be selling properties for the regions Tony mentioned earlier.

Our exploration and development capital budget remains unchanged at $727 million for 2007.

We're currently in the process of developing our 2008 capital program and while it's too early to give specific numbers, I think it's safe to assume that we're looking at an exploration and development budget that will be within 2008 cash flows.

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

Thank you, Jay.

I'm pleased with our operating and financial results for the third quarter and I'm excited to see the progress we're making to improve and expand our drilling inventory.

We continue to see encouraging results in a number of our key resource plays, such as the James Lime, the Woodford shale, and the Wolfberry.

Our recent South Texas Olmos acquisitions were done at attractive financial metrics and give us several years of drilling inventory.

While our company continues to grow, both organically and through acquisitions, we intend to maintain our financial and operating discipline as well as our commitment to NAV per share growth.

We'll now turn the call over for questions.

(Operator instructions).

Your first question comes from Ellen Hannan with Bear Stearns.

Good morning.

Good morning, Ellen.

Just the few questions for you here.

First, on the price realizations on your oil volumes.

Your guidance for the third quarter was a realization $3 to $4 a barrel of WTI and you came in actually pretty close to WTI, yet you're looking for an even wider basis differential in the first quarter.

Maybe you can talk about that a little bit.

Ellen, this is Dave.

I think we might actually want to double check the realizations on the oil.

Let me pull that up real quick here.

For the third quarter before hedging, we were at $71.68, net of hedging it was $67.56 and we had the NYMEX prices at about $75.38.

Okay.

I have the NYMEX price as $71.08 so that must be the difference.

The drilling complete cost on your Woodford wells year to date.

Can you tell us what that's running?

The last couple we drilled -- this is Jay -- we drilled in the low fives.

I think the potential -- the last one we drilled was in the mid to high fours and we think the potential is probably mid-fours.

Duncan Shores I think was 5.2 in that range.

And over to the James Lime program that you talked about.

In your mid-quarter operating update, you mentioned a couple of wells.

One was the first 10 days results of the 800 a day.

Is that not on the low end of what you would expect a James Lime well to be producing?

I think if you look at these wells, they come in pretty strong and then they'll decline to around a million a day and they'll stay pretty flat right in there.

So you get a lot of decline initially.

That's why we always quote 10-day rates or 30-day rates for these wells and don't give you the first hour of production.

It tends to a hike the wells to much.

If you're thinking about a million a day flat for a while on these wells, it's probably reasonable.

Reserve-wise, we haven't really changed our view on the reserves on the wells even though the initial rates have increased.

What are you currently looking for an EUR on the well; on a typical James Lime well?

I think it's about 2B.

A for cost of --?

One and a half to two is what we said in all our public information.

And for cost of what?

They're about $3 million.

Just a point of clarification, in the operations update that you're referencing those were not the initial 10-day IP rates.

Those were kind of current sales rates.

We actually -- those were completed in August.

So what we're trying to do is give you an update in terms of how the wells we're preparing after the initial IP rate, which is within our expectations.

Those were not IPs for those James Lime wells.

Those wells IP'd -- one of them might be over 4 million a day.

I think the expectation is you're going to get a very hyperbolic performance and they're going to level out around that million a day number.

Those are pretty reasonable numbers.

I actually got the figures here.

George Smith IP'd at -- not IP'd, it's a 10-day sales rate, 3.6, and (inaudible) was 4.5.

So we were just trying to give an indication of what the well is performing at.

Thanks.

I have another question.

On your Sweetie Peck where you talked about transitioning the drilling program in house.

Can you talk about what you mean by that and what you hope to accomplish there?

Well, when we started the program up, we didn't have a drilling staff in Midland and we basically have been using contract staff for engineering drilling management.

In general, just the entire operation has been contracted.

We noted in a report, we had the couple rigs we decided to lay down this quarter.

We were having a number of operational issues with a couple of the rigs.

I think it was a combination of some crewing issues.

The crew issues out in the Permian Basin were really tough.

We weren't happy with the crews we had on the rigs.

We weren't particularly happy with the supervision either.

It wasn't that the supervision was necessarily bad; it was just that we feel like we need a higher level of attention to some of the details of the operation.

We've been out for a while looking for drilling and engineering support -- internal drilling and engineering support for there and drilling supervision anyway.

We decided to go ahead and lay those two rigs down and get our internal resources on board and then as we go forward we'll be picking up some additional rigs and resorting our rig fleet there to try to get a better performance and I think we are going to focus more internal attention just on the daily operations on the rig.

We don't want to impugn anybody.

We're doing the best we could with the people we had.

Frankly, we just weren't satisfied that that performance was adequate.

We're going to meet our rate expectations at Sweetie Peck anyway.

We're going to be -- actually, our wells are performing at or above where we expected to be and we're able to pick up some activity in our non-operated properties there that we hadn't planned on.

So, on a net basis we're going to end up better off than we expected to be this year.

Obviously, it's a little disappointing.

We were at a buy rig program and we were excited about that, but we started to have some safety issues.

We were starting to have some real performance issues with a couple of these and just decided the right answer from a net asset value perspective was to lay them down.

Ellen, what was -- this is Tony -- one of the things that was very telling to me was the drilling contractor actually stated he thanked us for laying down the two rigs because he was having a very difficult time finding qualified crews to man his rigs.

So it's not very often you hear a drilling contractor thanking you for laying down rigs, but they are really stretched in that particular region.

Okay.

Thanks.

One final question for me and I think you addressed it briefly.

In terms of the outlook for your CapEx for '08, I think, Tony, you mentioned within cash flows.

When do you plan to set that budget for next year?

We actually are in the process of working our plans and budget for next year.

We expect to have that completed and up for board approval by year end and would expect to get some guidance on that in January sometime, early January, late in the year.

That's it for me.

Thank you very much.

Thanks, Ellen.

Your next question comes from David Tameron with Wachovia.

Hi.

Good morning.

Good morning, David:

A couple questions.

James Lime; can we dig into exactly what you're doing there and how you complete these loads?

Are you cracking them?

Are you doing dual lateral, horizontal, vertical?

Can you just talk more into that?

I know you did it last quarter, but can you hit that again for me.

Sure.

In general, we're completing these wells with long 7,000 foot laterals with a packers-plus type completion.

Some of the individual sections will be cracked.

Some will just be pumped in.

Some will be broken down in other ways, but generally they're cracked jobs.

It's a packers-plus long lateral.

We don't really -- we're not really advocates of dual laterals in these.

We have one we just did recently due to some mechanical problems we had and we ended up with a dual lateral, but it wasn't something we really intended to do.

We really believe that a stimulated packers-plus completion is probably best practice at this point.

Are you guys hitting a lot of water-bearing -- are water-bearing faults an issue out there?

Yes, they're an issue.

You've got to stay away from them.

You don't want to cut wet faults and that's probably the biggest risk in the play and there isn't a huge amount of 3 D out here over a lot of this acreage, so you may see us picking up and shooting some.

We've been pretty fortunate so far and I've heard comments about -- from people about wet faults and drilling wet fault.

It can happen.

That is one of the risks of the play.

All right.

And remind me, what formation -- you hitting the [Rodessa] the James --

It's the James Lime is the section we're in.

It's about 200 foot thick.

We have a particular portion of it we'd like to be in.

Where you land the wells we think is important, but this is basically a James Lime play.

It is?

Okay.

A lot people were referring to James Lime as a whole.

I just wanted to confirm that.

Going to production growth quarter over quarter, it looks like fourth quarter is going to be flat versus third quarter guidance.

I guess maybe this is a Tony question.

How do you think about the production growth into '08 if you're staying within cash flow?

Actually, Dave has a couple of comments he's going to share and then I'll comment.

I think, Dave, in terms of fourth quarter, we mentioned the couple of deferrals that we had in the Rockies and then also having to constrain a little bit of the Hanging Woman production.

Those were kind of October items.

So that's a little bit of the reason why you're not seeing that continued growth.

We also have a couple of non-Op projects that are in our Gulf Coast region that we just haven't factored in at this point in time.

The timing of those coming on line is just not precise in our minds, so rather than disappoint folks, we brought that out.

If they come on line and we think they're going to push us beyond the top of the range, we'll certainly update guidance at that point.

And then going into 2008, I don't know that we're ready to really talk about that right now.

We certainly have been pleased with the ability to grow production over the last seven quarters and that continues to be the goal.

This is really not something that we're touching on right now.

And again, getting back to kind of our planning and budgeting efforts, Dave will be focused on that over the next few weeks and then obviously that will drive our forecast into production next year.

All right.

Thanks.

Your next question comes from Stephen Berman with Pritchard Capital.

Good morning.

Just a clarification.

On the Gulf Coast there's two exploration discoveries I believe you said would come onto production near the end of 2008 in a press release as from mid-October of 2007.

Can you just clarify that please?

We're talking about Amber Jack -- it was a couple small discoveries that we made.

Elm Grove we made earlier this year.

It should be on in the first quarter.

Amber Jack should be subsequent to that.

I know that we said 2008.

I think we're being pretty conservative about that timing.

There's a couple of exploration discoveries that we expect to bring on, like Jay mentioned, either late this year or very early next year and then there are a couple of other discoveries that are longer term and those are the ones being referred to for late 2008.

There are different discoveries being brought on.

Okay.

Thank you.

Your next question comes from Stephen Beck with Jefferies and Company.

Good morning, everyone.

Good Morning:

You had mentioned earlier that some of your Sweetie Peck non-Op properties were performing better than expected.

I was wondering if you could talk a little bit about your operating properties at Sweetie Peck and how they're performing.

Yes, I mentioned it earlier.

I think in general we're doing at our expectations or little better in terms of rates.

Well costs, we've been coming in pretty close to where we said, again, and we talked about our rig issues earlier.

Those are driving our cost up some.

That's probably the reason we've elected to lay down a couple rigs there.

We expect that to come in line.

We've had some pretty nice rates early on in some of our wells at Sweetie Peck that's actually put us over our production budget.

So performance has been very good and we just need to get really consistent and happy with our drilling program there.

We need to distinguish between -- Sweetie Peck is our operated property.

Halff East is our non-operated properly.

Halff East is operated by a very fine operator down there and we had -- at the beginning of the year this year, we had gotten ourselves into Halff East we had budgeted about 15 wells.

There were some questions about some of the area there and whether some of it might have been a little wet.

As we've gone through the year, we set some of those at figured out its better than we thought.

We were able to expand that program and accelerate it.

It kind of offset our shortfall in drilling at Sweetie Peck.

Halff East is operated by Henry Petroleum and these are the folks that we acquired the Sweetie Peck assets from.

We know them very well; very capable operator and the Halff East was a field that was basically pushing out the play.

So we were waiting to see actual results, and like Jay said, based on the productivity we've seen, we're now expanding that play.

Okay.

In the Woodford, I know that you said you moved to a larger pipe.

I think last quarter you mentioned about the idea of testing a 7 inch pipe.

I was wondering if you have done that and if so, how that is performing relative to the 5 inch pipe.

We haven't tested 7 inch yet.

I haven't been able to convince the guys in the region that it's worth the extra cost.

They're probably right.

I think somebody in the trend will test it.

We'll see how that works out.

Right now we think we can apply as much horsepower as we need to the 5 .

Okay.

How many acres do you have in the Woodford now?

Net?

We doubled that year to year.

Right now it's right around 40,000 acres.

The acreage in the Woodford is pretty well tied up at this point.

There's not a lot of potential to increase that position.

Okay.

Although, I will say during the -- late last year we were able to take advantage before some of the acreage got taken out and we're able to, like you said, expand our position there by double.

On average, how long does it take for you to drill a well at Woodford now?

I think we're right at 40-something days and then you've got a completion on top of that.

You can probably figure a 60-day well per well.

If you look at it from that standpoint, that's probably reasonable.

Okay.

Given the results of your last several wells, I was wondering if you could talk about the geographic dispersion of your wells.

Are the better performing wells kind of clumped together or are you having -- or are they rather dispersed across your acreage?

Well, we've kind of been focusing on one area because that's where we had 3 D.

We've got a bunch of 3-D coming in in the fourth quarter that we'll be using for next year.

All these wells have been in a relatively close proximity.

I think there's a lot to learn yet about the Woodford and what happens geographically.

I hear a number of our competitors talking about that issue.

I've heard people talking about sweet spots.

We've had a couple wells that are clearly better than others.

If you look at the play and you look at all the public data on the play, there's a very -- you can make a very strong correlation on initial rates in the play.

It falls right along the probability curve.

I think if you look at that, the 50% point of the probability curve out there is a well that will come on at about 1.8 million a day.

We certainly had a number -- several wells above that.

There are some wells out there that are significantly better, but it kind of argues that it's fairly statistical.

You're going to have some wells, some good wells and some not so good wells and the trick here is going to be getting to the point where your average well is going to be astronomic and we think that at that 1.8 million a day rate you can't make an economic well here.

So, we've had several good ones in kind of an area and then we've had at least one that's kind of out of the area that's been good.

We've had some wells in the same general area that haven't been so good.

I will tell you there's a lot more to drilling these then just where you're drilling.

Where you land the well is important.

How much sand you get in it is important.

Steering is real important.

There's a lot of complexity to this.

We've seen some variability in our results as a result.

I would comment one of the -- Wanda, the well that we talked about last time we had attempted that peak completion system and we ended up making a well out of Wanda.

Then the peak system wouldn't work and you end up going and in cracking it and perforating it and cracking it conventionally and still made a well.

So we were real happy with the way that turned out after messing around with that peak system for the time period we did.

I think it's still really early days.

No matter how many wells we all drill, we're still real early in this play, but there's clearly a statistical aspects to it at this point based on what we can see.

Going over to the Atoka.

This will be my final question.

You mentioned about high grading the project.

I was wondering if you could expand a little bit more on that and give us a flavor for what you're thinking in terms of rig counts going forward and timing of expanding that?

I think Mayfield is an interesting asset.

You've got Atoka and then Granite Wash on top.

The Granite Wash wells that we've done have better economics than the Atoka.

And so we've been looking at the Atoka and our costs, of course, have gone up dramatically out there along with the rest of the industries.

So you have the play.

It's a relatively high cost to play, but generally during periods of high prices good economics because you get almost 50% of production in these wells in the first year.

So the trick to these is is there a way to get our costs down.

Is there a way and specifically then a lot of the costs in the completion - can we focus our completion and reduce our completion costs by making sure we're only perforating and completing in the intervals that are the most productive.

So we're doing some technical work looking at --okay, let's really look at this.

Is there a way we can really work on getting our crack costs down here?

Meanwhile, we're really focusing a lot of effort on the Granite Wash where we think the economics are better.

If we can get our costs down substantially especially our crack costs in the utopia, it opens up a lot more opportunity for us there.

As it stands, we're high grading locations.

We're offsetting wells that were better wells, looking for sweet spots and our activity level has come down some.

I would expect that in 2008 our activity level at Mayfield will be lower than it was this year as a result of that, unless we can really break open the cost aspect.

I think declining activity level based on our current results, high grading of the program to try and get the economics looking better and then a real focus on costs.

If we can get the costs where we need to get them there's a lot of potential out there, but right now with the cost where they are, it's hard to get really excited.

Thank you.

As Jay mentioned, we have a lot of running room here.

We've got over 500 3P locations.

It's important right now to really get as efficient with these wells as we can.

Great.

Thank you very much.

Thank you.

Your next question comes from Rehan Rashid with Friedman, Billings, Ramsey.

Good morning.

I'm going to (inaudible) real quick.

The 20-acre horizontal.

Could you just kind of walk us through maybe the time line when you figure out if this is going to work or not and is this included in your 173 upside on (inaudible).

The 20 acres are in the 3P number.

We do think the 20s are going to work.

They're already drilling -- we're doing some 20-acre work out there already.

It's an [AFB] for a number of them and lot of the other part of the field is already being developed on 20.

So, I feel pretty comfortable with 20 there.

Horizontally, it's very interesting.

There's been a couple of the operators that have drilled horizontal wells out there just in the last couple of months.

We really don't have a lot of results on them yet.

I think the horizontal play is just inevitable in my view in a lot of these fields.

There's clearly sections of the Cotton Valley that were tighter than other sections on initial completion that are not depleted and I think you're going to have the opportunity to come back into some of these places where you may have produced or gone down for some period of time and drilled horizontally in some of these non-depleted sections and make good wells.

I think we're very optimistic about the applicability of horizontal drilling to some of these bigger assets that we own there.

In general, I'm very optimistic about horizontal Cotton Valley drilling in all of East Texas and Northern Louisiana.

I think it's a great play and we're looking hard at it.

Okay.

Shifting to the Wolfberry play.

Could you kind of walk us through in terms of your acreage position, how much running room do you see there?

And maybe walk me through what exactly are you seeing from an economic standpoint for Wolfberry here?

Well, it's really two major assets.

Halff East is one and the [Onona] property we talked about.

We have about a 9,000 acre gross position there; 5,400 net.

Total 3P locations is about 67 and that would include 40's there.

We're at about 60 wells at this point.

It's about double our current well count.

Sweetie Peck is about 13,500 gross acres; 13,200 net.

Again, 248 total 3P locations.

We're at about 160 right now so add another 80, 90 wells to that.

Again, we're at 80 on that; '40's are potential and the 3P locations include 40.

So, we're drilling some 40's late this year, early next year.

We'll get some results on that.

We're pretty convinced that 40's are going to work on a large part of the acreage position.

Maybe not all of it, but a large part of it.

Typical well costs 1.6 to 1.8.

Typical reserves about 160,000 barrels.

So it's basically about a Bcf reserves; so about $1.60, $1.80.

I think if you look at our total costs you're probably going to have finding cost in the $2 range.

But is this separate from your Spraberry targets in the field?

I guess we ought to talk about this a little bit.

There's a real misperception.

Anytime somebody says the word Spraberry, folks think, "Oh, Spraberry.

That's that that stuff out there in the middle of the basin.

It's sort of pseudo economic.

It's been drilled for 50 years." This is not Spraberry.

This is closer to the shelf.

We include the Spraberry in the crack because it's there and some of Spraberry in here is good, but this is the whole section; Wolf Camp through Spraberry, bottom to top.

It's a big pile of limestone and it's not - as some people like to say - it's not your father's Spraberry.

We call it - I think people in the industry, especially in Midland, call us the Wolfberry play, but basically it's a big pile of rock, including the Spraberry section cracked essentially all at the same time.

There's large crack jobs; 9, 10 stage crack jobs.

It gets back.

It's really the technology that being developed in all these big pile of tight rock plays in which we opened the whole thing up and it's very different than the old conventional Spraberry stuff that people have in their minds.

It's a very economic play.

At these prices, it's very economic, obviously.

It's a great repeatable play and we're very encouraged about what we've seen so far on our rates.

We think we're coming in right where we thought.

Process has been a bit of an issue for us, although we really have been drilling in that 1.6, 1.8 range.

We talk about -- we just want to make sure it stays there and that's part of the reason we're shuffling our rig fleet.

Okay.

Last one on your Hanging Woman Basin.

The deeper coals; the same thoughts there in terms of what's the progression.

Have you completed anything there?

How many more before you get a better feel for what you have?

We have for horizontals completed in there now.

We're going to drill about five more here in the fourth quarter, early 2008 to increase density and look at some completion technique issues.

I think, quite frankly, it's going to be a while yet.

We had kind of been saying we'd know something here at the end of this year.

I'm not sure that we're going to be able to make any real decision that early.

I think it will probably late next year, frankly, before we really are convinced we know what we've got in the deep.

It just takes a lot of time to dewater these wells and look at them, but we'll have nine wells in a pilot area there hopefully by the first part of the year that we'll be able to watch.

It's a real important program to us.

The deep is a lot of the reserves -- the 3P reserves out there.

But it's also -- if you look at it from a risk standpoint, it's clearly possible reserves at this point.

I think we're not convinced that it's going to work, but we're not convinced yet that isn't.

We're going to need to drill these wells and get some more data.

Okay.

Thank you.

Your next question comes from Phillip Dodge with Sanford Group.

Good morning, everybody.

Thanks for the comments.

A question on Sweetie Peck how your estimate or evaluation of recoverable reserves compares now with the time of the acquisition.

We're right where we thought we'd be.

Our initial rates have actually been a little higher than we thought they we're going to be.

So that's been encouraging, but we haven't changed our long term view of it.

We are still in the same ballpark that I just mentioned.

Okay.

I'll show will power and limit myself to one question.

Thanks very much.

Thanks,

Your next question comes from Larry Busnardo with Tristone Capital.

Good morning.

Good morning, Larry.

Just in regards to the Gulf Coast region there in South Texas, both Catarina and the Gold River Field.

How is the integration of those two assets going?

Can you just give us an update on that and how soon you think until they're fully integrated?

So far, so good.

I think everything is going real well.

We had a big advantage in here in that the two acquisition areas both happen to be operated by the same contract management firm.

So we're basically able to take the two assets over and maintain the current operators, so we didn't have to staff up to do it.

We didn't really have to shuffle people and the guys who operate there have been in there, been in South Texas, been in those assets for a long time.

So, really no hiccups at all in terms of transitioning the operation.

Will it remain contract operators or do you plan to bring that in-house at some point as well?

Just given what you talked about at Sweetie Peck.

I think it's important to distinguish here.

South Texas is a completely different labor market than Midland.

I don't want to - I've lived in Midland.

I love Midland, but I will tell you right now the unemployment rate in Midland is 2.3%.

Everybody who can possibly work is working.

I was down there just a few weeks ago and it's hard to get service in restaurants.

People are --every store there has a "for hire" sign or "looking for people" sign in the door.

And frankly, they're just getting a lot people out on drilling rigs out there who are not the kind of quality people that we necessarily want to be working with.

South Texas is a very different situation.

A lot of families working together down in South Texas.

There's more availability of rigs.

More availability of crew.

Much more stable group of people.

In general, we've been very pleased with the people we work with down there.

So I think Midland's in a mini boom right now and labor is really tight and frankly that is the rationale and the reason why we had to lay those rigs down.

It really was a crewing issue, not that the equipment was bad, not that opportunities were bad, it was just a people thing.

South Texas, again, is very different.

The contract operations -- if I could bring all operations under the same tent and have everybody work for us, we'd do that, but it's not practical to do that.

Frankly, the South Texas operations are very well run.

They've got a good, consistent group of people.

If we tried to hire them, it would probably ruin their business model and we'd end up worse off at this point.

There may be a point in the future where we entertain something like that, but not right now.

Remind me on the two sales.

They're fairly similar, right, geologically?

Very, very similar.

Larry, there is one other transition issue and that's probably more on the technical side in terms of building staff with our Houston group and they are pursuing that to make sure that first of all we're doing the technical homework for the play and able to work that going forward.

This is going to be an area of focus going forward.

Do you think by -- as you get through the remainder of this year and start heading into next, at that point you're ready to really get ramped up and have the program where you want to be?

We have a lot of activity planned for next year in these assets.

As we continue to drill and prove up some of what we hope to be there, there's going to be additional opportunity, especially in the Gold River acquisition.

There's quite a bit of acreage that we bought with that.

I think it's another one of those great places in the world where there's a lot of multi-pay opportunity and there's other things we can look at and do.

It's a great core area which is something we really needed in that Gulf Coast region.

It was a core area that we can really focus on on-shore.

We're excited about it.

Just one final one in Sweetie Peck.

When you talk about the 40 acres, has there been any 40-acre wells drilled up to this point?

I don't think we drilled a 40 yet.

We've got one down.

We don't have any real information yet on it, but we had one down and we're drilling a few more.

It's going to take a little while, probably six months or so, looking at the results of those wells to really have a feeling for are we stealing from the parent when we complete the daughter well.

I doubt it will be a significant economic issue.

Again, most of the value of these wells is up front, so if you get pretty decent rates upfront the economics will (inaudible).

Really more of a finding cost issue longer term, but I think we are pretty optimistic about the 40's.

Larry, that one well we drilled, it's been there for a while and so far we haven't seen any interference, but again that's one well.

How long has that been out?

It's been out close to a year I believe, but it looks like it's holding up just like the other offsetting wells so we haven't seen any offset decline.

Okay.

All right, that's it.

Thanks guys.

Thanks, Larry.

There are no further questions at this time.

Thank you very much.

We appreciate those calling in this morning.

Thank you.

This does conclude today's conference call.

You may now disconnect.