SM Energy Co (SM) 2007 Q2 法說會逐字稿

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

Mary Land & Exploration second quarter 2007 earnings conference call.

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

After the speakers' remarks, there will be a question-and-answer session.

(OPERATOR INSTRUCTIONS) Thank you.

I would now like to turn the call over to Mr.

Brent Collins, Director of Investor Relations.

You may begin your conference.

Thank you, and good morning to all of you joining us by phone and on-line for St.

Mary Land & Exploration Company second quarter 2007 earnings conference call.

Before we start I would like to read the following statements.

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 results include -- 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, the pending nature of the announced acquisition of properties in south Texas as well as the ability to complete this transaction.

The uncertain nature of the expected benefits from the acquisition of oil and gas properties, and the ability to successfully integrate acquisitions, 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, uncertainties in cash flow, the financial strength of hedged contract counterparties, the negative impact that lower oil and natural gases 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, possible, and 3P 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 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 a 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 Vice President and Chief Financial Officer; Jerry Hertzberg, 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.

Thank you, Brent.

Good morning.

Thank you for joining us for our second quarter 2007 earnings conference call.

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

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

After that we'll turn the call over for any of your questions.

I'm happy to announce that we've had a very solid second quarter.

The Company set new quarterly records for net income, discretionary cash flow, and production.

Our financial results reflect record production volume and strong realized commodity prices during the quarter.

In the second quarter of 2007, production reached a new quarterly record of 286 million cubic feet equivalent per day.

This increase reflects the successes of our drilling programs around the Company as well as our ability to integrate and execute on acquired properties.

A strong price environment also helped our financial numbers.

Since approximately 40% of our production is oil, we benefited from the high prices that we saw from the market during the quarter.

I think this demonstrates the benefits that we realized from a diversified and balanced portfolio.

We also have strong realizations on natural gas from our hedging program that provided us with almost $0.60 more per Mcf than we would have realized otherwise.

As a consequence of all these factors we posted a solid operating margin of $6.12 per Mcf equivalent for the quarter, or 71% of our realized equivalent price.

Operating costs were down sequentially, primarily as a result of less workover activity in the second quarter.

And we are actively looking at ways to further reduce our operating costs.

And Jay will comment on a few of those initiatives in a moment.

Also on the financial side, although it seems like awhile ago, we successfully placed 287.5 million of 3.5% senior convertible notes in April of this year.

This financing was done at an attractive cost and provides us with significant financial flexibility going forward.

The equivalent production for the second quarter 2007 as I mentioned earlier averaged 286 million cubic feet per day.

This is a new quarterly record that was 15% higher than the same period in 2006.

This marks the sixth consecutive quarter that we have grown production.

In our press release yesterday we announced that we had entered into an agreement to acquire oil and natural gas assets in south Texas for 153.1 million.

These assets are adjacent to the Catarina assets that we purchased in June of this year.

Both sets of properties target natural gas in the Olmos formation.

South Texas, and in particular the Olmos gas play is an area that we have been interested in for long time.

So we're very pleased to be adding these assets to our portfolio.

These two transactions provide us with a large amount of running room in the area and make us now a significant player in this region.

Jay will discuss these transactions in more detail in his update.

These transactions continue the St.

Mary approach to making acquisitions.

Key factors in our acquisition strategy are acquiring properties with high working interest where we are the operator and have the ability to extract real value from the development of these assets.

Pursuing transactions that are conducted on a negotiated or selectively marketed basis tends to be where we've had our most success.

These attributes characterize these south Texas acquisitions as well as the recent Sweetie Peck transaction.

The recent acquisition numbers are larger in dollar terms but we are also a larger company.

Acquisitions have been and will continue to be a principal driver in growing our company.

The primary driver in our business continues to be the growth of net asset value per share.

With that, I will now turn it 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 quarterly net income for the second quarter of $59.2 million or $0.91 per diluted share.

This compares to $40.1 million or $0.61 per diluted share for the same period last year.

Adjusting for noncash and nonrecurring items, our adjusted net income for the second quarter of 2007 was $55.3 million, or $0.85 per diluted share as compared to $47.8 million or $0.73 per diluted share for the second quarter of '06.

Discretionary cash flow for the second quarter set a new quarterly record at $163.6 million, up from 21% -- pardon me, up 21% from the $135 million in the comparable period last year.

Included in the financial highlights section in our press release from yesterday are definitions, descriptions, and reconciliations for adjusted net income and discretionary cash flow.

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

Let me touch on a couple of the significant items for the quarter.

As we mentioned earlier, revenues for the quarter were $247.2 million, an increase of 28% from the $193.4 million in the prior year's quarter.

The increase is due to a 15% increase in production volumes between the periods, coupled with strong commodity price realizations.

Revenue for the second quarter included a gain of $6.3 million related to the final global insurance settlement for damages suffered to properties during hurricane Rita.

The second quarter of 2006 included a gain from the sale of proved properties for $6.4 million.

Revenue from realized oil and gas hedges was 7.3 million during the quarter, up from 49 -- up from 4.9 million for the same period last year.

The current periods realized gains were due to favorable natural gas derivative settlements offsetting slight realized losses on oil derivative settlements.

Our net realized equivalent price for the quarter was $8.58 per Mcfe, which is up 6% from the $8.09 per Mcfe we realized in the second quarter of 2006.

The realized gas price was up 10% from the same period a year ago to $7.68, and our realized oil price increased 1% to $59.97 per barrel.

Lease operating and transportation expense was flat on a per Mcfe basis in the year-over-year, and down sequentially to $1.37 per Mcfe from the $1.51 per Mcfe we experienced in the first quarter.

First quarter '07 included a number of significant workovers in our Rocky Mountain region.

Jay will comment further on operating costs in his his comments.

DD&A on a per-Mcfe basis increased 32% quarter over quarter from last year.

This is a result of assets acquired or developed in a period of increasing finding and development costs becoming a relatively larger portion of our historical asset base.

The increases in per-Mcfe DD&A is something that St.

Mary and I expect the industry as a whole will generally continue to see given the higher cost environment and the impact of bringing assets to a -- on bringing assets to a productive state.

We had a benefit from the change in the net profits plan liability in the second quarter of 2007 of $1.1 million.

This compares to a charge of $14.1 million a year ago.

And $5 million last quarter.

This liability does fluctuate based on price and cost trends.

While our debt increased quarter to quarter, our interest expense decreased roughly 40% to $3.8 million.

This is a result of paying off higher cost interest -- pardon me, higher interest bank borrowings with the proceeds that we received from the $287.5 million of 3.5% senior convertible notes in April.

At quarter end, our debt to book capitalization percentage was 30%.

Regarding the new convertible notes, I want to emphasize the treatment of these notes with respect to outstanding share count and diluted earnings per share.

Unlike the previously outstanding 5.75% notes, these new notes do not use the if converted method for the calculation of diluted earnings per share.

Rather, the diluted share impact is calculated using the treasury stock method because the 3.5% notes allow for net share settlement.

Accordingly, these new notes will not be factored into the calculation of diluted earnings per share until the 55 -- pardon me, 54.42 per share conversion price of these notes has been achieved.

We anticipate for the remainder of the year our cash taxes will account for 10 to 20% of our total tax expense.

While we're recognizing record income and cash flows, our capital expenditures are significant enough to allow us to utilize the accelerated deductions associated with IDCs and reduce the current cash tax burden.

Lastly, in our press release from last evening, we provided a summary schedule of our current hedging positions, including those hedges we entered into related to the south Texas acquisition.

The Form 10-Q that we will be filing today will have a more detailed hedging schedule for those who are interested.

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

Thanks, Dave.

And good morning, everyone.

The Company provided an operational update in our July 16, press release.

I am going to touch on some of the highlights from that release as well as give an update on recent developments, and then talk about our south Texas acquisition.

In the second quarter of 2007, St.

Mary participated in the drilling of 106 conventional wells, of which 101 were successfully completed for a 95% success rate.

Additionally the Company recompleted 17 wells with 15 of those being successful for an 88% success rate.

As of the end of the quarter, St.

Mary was completing 72 recompleting 14, and drilling 35 conventional wells.

Currently we have 18 operated rigs running across the Company.

In the Mid-Continent region there were 23 successful completions out of 24 attempts for a 96% success rate.

At quarter end, the Company was participating in 16 completions, 4 recompletions, and 10 drilling operations.

As we announced in our press release yesterday, we have recently brought to sales one of the four horizontal Woodford Shale wells in the Arkoma basin that was being completed as of our operations update in mid-July.

The Duncan Shores 1.1 well in which we have an 81% working interest had an average initial 10-day sales rate of 2.3 million cubic feet a day which compares favorably to the average rates of better wells in the play.

That well was completed using a slightly larger pipe size than we have used previously which allowed us to deliver more fluid at a higher rate during our frac job which we think is important in the completion of these wells.

We have three horizontal wells currently completing in the Woodford Shale, two of which have very similar completion designs as Duncan Shores.

This is only our 10th completed well targeting the Woodford Shale and we continue to learn and evolve in the play but we're clearly encouraged by the results from this well.

The Company is operating two rigs in this program at this time.

Also in the Mid-Continent we had some good wells in the Mayfield development area during the quarter where we're operating one drilling rig.

We're focusing most of our efforts there on the Granite Wash formation.

Moving on to the Rockies, there were 25 successful completions out of 27 attempts for a 93% success rate, excluding coal bed methane wells in the region during the second quarter.

At quarter end, St.

Mary was in the process of completing 22 wells and participating in eight drilling operations.

We had a successful Boken in fill well in Montana, Richmond County, during the quarter.

The Dynason 231-H in which we had a 98% working interest which had an initial ten-day average rate of 330 barrels of oil day and subsequently increased in rate when it was placed on pump.

We continue to look at boken infill and re-entry candidates in Montana but have limited plans for the boken in north Dakota at this time.

The Company current hall three rigs in its conventional program in the Rockies.

In the Hanging Woman Basin coal bed methane program 360 wells were producing at the end of the second quarter compared to 311 at the end of the first quarter of 2007.

Production at quarter end was 13.3 million cubic feet a day gross and 8 million a day net.

The sequential decrease in production is due to high summer temperatures impacting our compression facilities in one of our particular program areas.

We expect that additional compression facilities will be added soon.

Our drilling operations were somewhat restricted during the quarter as a result of unusually high amounts of rainfall which limited our ability to move rigs and equipment in the field.

We'll be ramping up drilling activity here in August to achieve our planned drilling schedule.

Any shortfall in wells drilled in 2007 is not expected to impact current year production due to the dewatering time required on coal bed methane wells.

In the ArkLaTex region the Company successfully completed all 19 wells it dried or participated enduring the quarter.

In the James Lime horizontal carbonite play we continue to be a leader in the play.

We've had successful test wells in sections outside our traditional development areas at Spider and Huxley in recent months that confirm the productivity of other acreage blocks in the trend.

The George Smith 1 well in which we had a 67% working interest was completed at an initial 10-day sales rate of 3.6 million cubic a time a day, and the St.

Mary operated Middlebrook 1H in which we had a 29% working interest was completed last week and has been producing to sales at an average of 4.5 million cubic feet per day.

The Middlebrook well was complete in fewer days and for less money than we had budgeted.

We're continuing to work to expand our presence in the play.

At Elm Grove the development continues on schedule.

And we expect there to be three to four nonoperated rigs running in the field for the remainder of the year.

In our Cotton Valley program at Terryville we plan to participate in eight wells on our acreage this year.

Our operating partner had two drilling rigs operating in the field at the end of the quarter.

In the Permian Basin region the Company successfully completed all 33 wells attempted during the second quarter.

Sweetie Peck continues to meet or exceed our expectations.

Production is up 19% from the end of year 2006 rate of 2.6 thousand barrels per day to 3100 barrels per day as of the end of June.

Well performance and drilling and completion costs are in line with our expectation.

We're ahead of schedule with respect to our drilling program.

Currently there are five operated rigs running in the program area.

We had anticipated having four operated rigs running in the field by year end.

With an ongoing emphasis on execution we've done everything we had set out to do to date when we purchased the Sweetie Peck assets.

In the Gulf Coast the big news is our entry into the Olmos shallow gas play in south Texas.

In June we closed on our initial acquisition of 14 BCF of proved reserves in the Catarina field for $29.5 million.

Yesterday we announced a larger transaction in south Texas on acreage adjacent to Catarina.

The highlights of the transaction are as follows.

Purchase price of $153.1 million to be funded with cash on hand and bank borrowings under the Company's existing facility.

Proved reserves of 95 bcfe, 40% of which are proved development.

41 bcfe of probable reserves, and 25 bcf of possible reserves which gives total of 123 bcf of drilling potential.

259 producing wells with current debt daily production of 9.2 million cubic feet a day which is almost entirely natural gas.

Operator shift with average working interest of 98%, and average net revenue interest of 77%.

Estimated completed well cost of $600,000 per well with $1.55 per Mcfe in operating costs inclusive of severance taxes.

The acquisition is expected to add approximately 0.7 bcf to our 2007 production forecast resulting in an increase of our production guidance for the year to a range of 104.5 bcf to 106.5 bcfe.

Consistent with historical practice we have hedged the first three years of risked natural gas production related to the acquisition using swaps.

The initial plan will be to operate one drilling rig in the field for the remainder of 2007, and increase to two rings in January 2008.

As I said the acquired properties are adjacent to the Catarina assets so we hope gain efficiencies that we can exploit as we integrate the operations.

We plan to operate two to three drilling rigs in the Olmos, one dedicated to the new properties, and one to two rigs working in Catarina for the remainder of 2007.

In 2008 we'll add a second rig for the new properties and are exploring whether there's potential to further accelerate this development.

Obviously successful integration of the assets and execution of the development plan are going to be a primary area of focus for us over the next year.

Our exploration and development capital budget remains on track and is slightly higher at $727 million for 2007.

The increase is related to $6 million in development capital related to the south Texas acquisition.

A portion of the capital has been re-allocated among the regions.

Looking ahead from an operational standpoint we're very focused on improving our operating cost structure.

The best way to ensure that we continue to enjoy strong margins is to push our operating costs down.

Earlier this year we started work on a procurement initiative aimed at lowering our cost structure by consolidating our corporate spend and taking advantage of increased purchasing efficiencies.

We saw the first results from this program in the second quarter when we aggregated our company-wide pipe purchases for the next six months.

This resulted in a meaningful decrease in our cost structure which will benefit our well costs and workover expenses.

We believe there are multiple opportunities like this for increasing efficiency and lowering costs across the Company and we're focusing a great deal of attention on the issues.

With that I will turn the call back over to Tony.

Thank you, Jay.

We are entering the second half of 2007 with strong momentum.

Operationally we are hitting our stride in the ArkLaTex and Permian and our other programs are advancing as well.

While it is still early in the life of the play, we are encouraged with our most recent results in the Woodford Shale.

The south Texas acquisition provides with us significant multiyear drilling inventory at a very attractive cost.

And financially, we had great results for the second quarter and have a strong balance sheet that gives us a lot of flexibility going forward.

With that, we'll turn the call over for questions.

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

Can you all talk about sort of your strategy going forward here?

I guess it seems that specifically the acquisition in the Gulf Coast you're becoming a little bit more bullish on that area, kind of first what made you look down there, what opportunity did you see and what kind of internal competencies do you guys have that really made you go after those assets?

And secondly sort of on a go forward basis it seems like you are becoming somewhat acquisitive as far as growth is concerned.

Can you talk about balancing organic opportunities with acquisition opportunities?

Certainly, Scott.

One of the things that we will continue to focus on is two fundamental strategies.

One is regarding St.

Mary's continued success with its acquisitions.

And as we mentioned earlier, we tend to focus on those types of acquisitions where we have a base of knowledge where we've got relationships, where we could potentially do a negotiated deal versus a broader marketed kind of deal, and the other key strategy is focused on our ability to achieve organic growth, and to me, the best way to do that is to build a multiyear inventory of drilling opportunities and certainly the recent acquisitions support that strategy.

On the Olmos this is an area where we have continued to look for additional opportunities.

We've looked at this area a number of times as part of our business development effort.

We haven't found the exact type of acquisitions that made sense for us until just recently.

And the group in Houston, the technical team there, already had a very strong understanding of the Olmos basin, and we were able to pull the trigger on those two acquisitions as a result.

I should also note that as we pursue our growth agenda, we will continue to look at additional what I call white space opportunities, areas that may be outside some of our regional footprint, and that's part of our strategy as well going forward.

And we focus our business development efforts on looking for those kinds of opportunities.

If you look for sort of those white spaces, as you call them, would you go in a big way or would it be more sort of take a position there and just kind of see how it works and potentially add to get some running room?

Yes, I would -- it's hard to say exactly what opportunities will come up but we'll certainly be opportunistic.

I think the key is -- and this is probably a good model to look at is what we're doing with the Olmos.

In that case we were able to acquire the Catarina properties first, which was a smaller acquisition, but clearly allowed us to go in and understand and pursue the technical aspects of that play, and then as we saw opportunity then to leverage that capability with the larger acquisition that we just announced.

I think it's kind of interesting because I think people saw Sweetie Peck as a large deal in a basin we hadn't been that active.

And, in fact, Tony and I and a number of other people in the Company have worked that basin for a number of years and knew the assets very well.

So I think it varies depending on what your understanding of the play is and your people.

Scott, I think the other thing, too, where can we leverage our current technical expertise and capabilities and broaden that into other analogous basins.

Scott as well think about -- Tony touched on it earlier in his comments.

These are certainly bigger deals on an absolute basis.

If you think back to like early 2003, late 2002, we had the property acquisition from Burlington, the acquisition from Flying J, and those were 75 and -- about $75 million each.

So for the size company at that time, those were pretty darn big deals.

I don't know that those are -- it's a complete shift.

Okay.

Fair enough.

And turning to the Woodford, it does seem encouraging that rate on that well that you all had.

Can you sort of talk at would point in time would you get encouraged enough to really start ramping up your activity there, and how active could you get there?

Well, we've talk about moving to a forward program at some point.

We're waiting on some seismic on the eastern side of our block.

We don't want to get out there too far without getting our 3D.

It's been really wet down there and that seismic was delayed somewhat, but we're going to get another couple wells under our belt here and make sure we really feel like the results are what we expect and we're going to talk about ramping up.

We're not going to -- it's not going to be a light switch.

It won't be on and off.

We'll probably ramp it a little bit at a time, building out our gathering facilities and everything we need to do there.

One last question.

Up in mon Montana do you guys have any update as far as the moratorium on the federal permits is concerned?

No, we don't, and frankly we stopped speculating about when that's going to happen.

I think the only thing you can say for sure is when the court finishes their business, the -- there will be a number of entities that will attempt to delay it it even further.

We've said this a number of times.

70% of our acreage is on the Wyoming side in which we're not having difficulty getting permits.

I think the Montana side is going to take some time.

We really don't know how long it's going to be.

Thank you, gentlemen.

Good quarter.

Thanks, Scott.

Your next question comes from the line of Subash Chandra with Jefferies.

I wanted to start on Sweetie Peck.

Do you have a number of producing wells at the end of the quarter?

We'll check that out.

See what we got.

While you do that, any update on the cost per well and how they've been running?

We've been coming in right on our AFEs which is about $1.6 million a well.

So everything there has been tracking right along.

Great.

Okay.

Total of 87 current producing well at Sweetie Peck.

And going to five rigs now, how many wells per quarter is that?

That you can get drilled.

Figure around 17 wells per rig per year kind of average.

Okay.

I'll back that out.

So looks like -- a dramatic ramp, clearly, from when -- what you might have thought you could do, or conveyed you could do when you bought this property.

I think we need to be careful with that.

We're still showing a 54-well count for the year.

We're getting some wells on potentially earlier, but that doesn't necessarily mean we're going to go way over our budget there.

We may get a few more wells drilled, but you've got to complete them, frac dates, so we're not counting on seeing a large amount of production here that we didn't already tell you about.

Okay.

All right.

In the Woodford, can you hazard a guess on the EURs on a couple wells that have some production history right now?

We've never used a number higher than about 2.7 B's, and I know there's a lot of bigger numbers out there, and they may very well come true.

We certainly hope they will.

But it all depends, reserves all depend on what that final decline rate, where the wells finally settle down and decline.

And we don't have any wells that are that far out.

So we're going to continue to use that 2.7 number.

It's clearly an economic program at the rates that we're generating new on these wells.

I should mention this well we just drilled had about a $5.4 million well cost.

We've got the two next wells we think are going to come in, in the mid 4's, so that's a very economic program at these rates and at that kind of 2.7, 3 Bcf kind of number.

When we see some results that would indicate to us those reserves will be higher we'll be happy to talk about it.

We're just not comfortable making those kinds of forecasts at this point.

Okay.

Any more data on this second Woodford?

Did you say it was a 3,000 foot lateral?

No, actually, I've got the data right here.

We could calculate that lateral.

Maybe if you could break down that, the well architecture.

Yes, sure.

We ran 5.5 pipe to bottom, TD was 12,956 feet measured, 9,000 feet TBD.

Pumped a seven-stage frac job at about 120 barrels a minute.

Trying to calculate the actual lateral.

Lateral is about 3650.

Very typical job.

Probably the largest frac job we've ever pumped down there.

140,000 barrels of frac fluid, 1.4 million pounds of prop.

And we got very good results with it.

I think the key thing here is we were able to pump at almost 120 barrels a minute which is something we haven't been able to do in our four and a half completions.

So we think that's obviously some of our competitors have been doing that for awhile, and we want to get to that point and that's where we're at.

So when you talk about taking the, shaving a $1 million off or so, clearly it's got to be on the completion side and sort of what you might -- are you talking about maybe doing a five stage versus seven?

Well, it's combination.

Actually the biggest change, this particular well, Duncan Shores, we had set this up to do a different type of completion on it, and we set an intermediate pipe here.

We didn't drill through the curve.

On the next couple wells we actually drilled through the curve and set all the way up.

So we save ourselves some intermediate pipe in the flat spots associated with setting that.

So that's a big part of the savings there.

Most of it is actually in the drilling and pipe setting side, the frac cost is going to be pretty similar.

And so do you think in the program going forward you can sort of not set that intermediate casing and if -- what led to you having to do that perhaps in this well?

Well, again, we had a different frac -- we were going to ta a different kind of completion in the well and decided after we got pipes set that we weren't going to do it, go to this more conventional higher rate frac job.

In terms of drilling through, and you think you ar seeing Devon and other people doing this now as well.

Initially we were real worried about lost circulation and drilling through, and what we were doing, we were running water based fluid down to intermediates, swapping over to oil based to drill the lateral.

What we found is that if we swapped to oil base at surface pipe we can drill the whole section with oil base.

Our concern was if we lost fluid we'd lose a ton of floor based fluid and it would be real expensive.

Frankly, we just haven't seen that problem.

And so I think this is pretty much going to be our standard at this point, going ahead and drilling oil base from surface pipe down.

And it saves a lot of money if you can do that.

If you don't have the flat spot associated with setting pipe, you save the pipe cost.

But you have more expensive--?

Well, yes, you don't see the -- if you don't see losses you don't have that issue.

So--.

Right.

I think it the's been a very positive -- the guys have been working the costs on these wells really hard, and I just got to give them a lot of credit but you're going to see everybody moving this direction.

These drill-throughs are typical in other plays.

Now that we know we can do it without losing a lot of fluid I think it it's going to be the standard.

I think what you're going see is cost mid 4's, reserves, I mentioned earlier, this rate we had here, we don't announce IP's because we don't think that's relevant but the 10-day rate of about 2.3 million a day is pretty good if you look at the publicly available data for wells out there.

It's a good well.

And we're excited about that.

You guys probably didn't have a chance to, Chesapeake's call, kind of wrapped up here, they threw some numbers out in the Woodford, and I don't know, Jay, where perhaps they're getting the data from but they're talking about $3 plus F&Ds out there for their program, sounded like partners program and sounded actually like third-party programs as well to some as high as $5.

A, if you venture a guess, does it sound like you feel you have enough data at this point to do so, or B, where do you think that data is coming from?

Maybe they're just mapping out the decline rate ahead of actually having the physical information.

I really can't -- I can't comment on Chesapeake's stuff.

You probably just need to ask them where they're getting that.

Our numbers are pretty much what I just showed you.

We drill a lot of wells with Newfield and they've had some very good results so I don't know where comes from.

One last one.

On -- have you given any further thought -- last we talked, you had it on asset sales, and if there are opportunities maybe, some of those areas you're in that are non operated I'm sure the operator would pay top dollar for and if you thought about rationalizing.

That's a good question.

One of things we have done and we'll continue to do is to continue to review our portfolio and look for opportunities to potentially divest some of those assets that may be more nonstrategic.

We're certainly looking at that and we'll continue and see where that goes but we're certainly very aware of the fact that it's a hot market right now from an M&A standpoint, and if we had the opportunity and we had the assets that we thought were non strategic we'd certainly try to take care of that, take advantage of that situation.

Great.

Thanks much.

Thank you.

Your next question comes from the line of Larry Busnardo with Tristone Capital.

Good morning, Larry.

Just on the James Lime play, can you tell us where those last two wells were drilled, in which field?

At this point, Larry, we're not giving a lot of specific detail, primarily because we're still leasing actively in the area.

But what I will tell you is that these two most recent wells are outside of our historical footprint in the James Lime, and one of the things you've heard me talk about is we now have an acreage position along a 75-mile trend in the James Lime, and these two wells are helping us to improve and extend along that 75-mile trend line.

So to me that's what's significant about the success of these two wells, is that it allows us to expand and continue with success along that trend.

Could you just remind us how much acreage do you have in the trend right now?

Right now we've got somewhere around 45,000 net acres, and that's a significant increase over 60% over last year and again, we're working to build that even higher at the present time.

Do you have a target in terms of acres that you're looking for, and then also how difficult is it, how competitive is the leasing out there right now?

I'd say it varies.

There are certain areas where there's more competition than others.

I think there are some areas in the 75-mile trend where we're not seeing as much competition and we're able to acquire acreage at reasonable cost.

But there are some other areas that are heating up, and that's part of the rationale for not sharing specific field information at this time.

And then again, 45,000 acres, how much would you like to get, or what number are you talking?

We haven't set a target on that.

It's really depends on the success we're having along the trend, and we'll be driven by the opportunities and obviously the availability of reasonable acreage costs.

With the rigs that you have running out there, how many more wells do you think you could get drilled this year?

We've got -- we're just adding our second rig in the horizontal James Lime play.

At last count I believe we were focused on 18 wells for this year.

18 total wells then?

That's right.

How many have you drilled to date?

I don't know that we have a--.

I don't have a number.

It's five or six.

Okay.

All right.

Your next question comes from the line of Eric Hagen with Merrill Lynch.

On the James Lime, following-on Larry's question, in terms of EURs, any data on that?

Yes, right now we're kind of estimating between one and a half to two B's per well, but that could be variable along the trend.

And the cost to drill and complete it?

It's interesting.

I think this last well, we actually completed that well for $3 million.

And significantly below our cost.

Just to give you some feeling for these wells, that well had add 6100-foot lateral with seven frac stages, and we were down -- had the well drilled for 1.9 million and a final well cost of $3 million.

So we're getting better at drilling the wells, too.

I think that's an important point, and a lot of credit to the guys in Shreveport for their work on that.

And some of the average depths on these wells are 12,500 plus.

These are challenging wells, but this is one area where we have -- we have a capability, and the expertise to really, we think, take a lead in the play.

Okay.

I don't know if I mentioned, 6,100-foot lateral.

Thanks.

In terms of a tight curve on these wells, what kind of reserve life are you looking at?

They're very hyperbolic.

It's a long life reserves but you do get quite a bit of it up-front.

We're going to get -- the number we're going to give you, the well has been flowing 4.5 million a day the Middlebrook well for about ten days and it's hung in there real nicely for us.

You may see higher numbers from some of our co-owners, but that's a good average number, and that's a really good number.

And we're excited about it.

Tony gave you a reserve number, we're really not, until you see that final decline on a well you really can't forecast that ultimate number.

But because of the high flow rates and they're holding out pretty high rates of return in the play is that fair to say?

Yes, that's fair to say.

Been very successful.

I think you're going to see a real high correlation between these initial sustained flow rates and ultimate reserves.

I believe that.

But again, we're being fairly conservative, I think, about the way we release these numbers.

Great.

Then following up on that you've listed in the 3P, you've got 78 locations.

How many of those are associated -- I'm trying to get at, in terms of your 45,000 net acres, how much have you evaluated, and is there up side to that 3P number?

I think clearly there's upside to that.

A lot of the acreage that we have acquired over the last year obviously remains to be tested and pursued, although clearly these two most recent wells are allowing us to expand our perspective on this play with success.

And the EURs that I quoted earlier, the range there, 1.5 to 2 is more kind of an average of what we've seen over the last few years.

So hopefully as we move along the trend and if we continue to get results like we've seen with these recent wells we would expect that number to increase.

So it's fair to say at least a third or more of your acreage is for the most part unevaluated?

Unevaluated might be a strong word.

We have a lot of acreage that -- for example, the Middlebrook well was the first well in a pretty significant area.

It's -- so I think, we've got some upside here.

Putting together acreage in east Texas is not an easy thing.

Having to drill these long laterals means there's a lot of land work to do to get to it, and you end up sharing it with people when you do that.

Again, I think we're being fairly conservative here and not trying to get way out there on it.

But there's some upside to this.

Great.

Then switching over to the Olmos play, same kind of question.

So what, EURs, well costs.

Is this long-lived reserves?

Typically EURs on a project are about 400 million cubic feet.

Well cost is about 600,000.

Long-lifed reserves but pretty hyperbolic, frac jobs, very tight sand, typically most of these wells are -- there's probably 4 or 5 different productive intervals so you'll complete in what you think is kind of a good looking interval then you'll have some behind pipe.

A lot of them have behind pipe opportunities in them.

A lot of the PDP we bought has behind pipe in it which is one of the reasons we really like this package.

So, yes, it's long-life reserves, it's a little longer perhaps than our average R to P, and it's just a great -- this is just a great farming operation.

There's a lot of acreage here.

I believe the number is 56,000 net acres in this package we just bought, a lot of which is not -- there's no penetration.

So what we're showing here, I think, is hopefully a conservative view again of where we think we can go with the play.

And again, keep in mind these wells are relatively shallow, inexpensive.

The depths in the new acquisition are from 3500 to 4500 feet.

Those are all vertical.

We do vertical completions here.

Who are some operators in the play around you?

I guess Lewis is probably one of the bigger operators down there, they are a private company out of San Antonio, I believe.

So you see Lewis a lot.

You don't see a lot of majors.

I think that's part of the attraction to it.

It's mostly independents.

The Maverick basin hasn't gotten a huge amount of attention from major players.

Escondido is another operator down there but Lewis may be the biggest operator down there.

One more question on the Boken in North Dakota.

It seems like your results there have been improving.

How much acreage do you have there?

In general what is your acreage?

Is it located adjacent to -- to the east, ERG has had some really positive results now, and I also think down the Anticline down the nose, there have been some good results.

In general when do you think you might get interested in drilling another well there?

Eric, let me give you kind of a -- the total acreage is about 81,000 net with about 25,000 of that in Montana, 55 in North Dakota.

And, we have maintained that on the Montana side we've had much more consistent success.

We've done some relatively inexpensive testing on the North Dakota side, but for the most part, we're nearing the end as far as the primary Boken trend on the Montana side.

And we see that getting narrow and thinner on the North Dakota side.

So while we've had some good recent success, we've probably got a handful of those wells identified for drilling this year.

Having said that most of that acreage too is held by production.

So we continue to watch our industry counterparts, and certainly if we see some opportunity we could step back in and take advantage of some of the advancements being made.

It seems like on the North Dakota side it's going to be more defining the sweet spot, the sort of fractures forms.

Do you see any evidence that you've got acreage nearby where they're going to get results or--?

Well, we're looking at it.

I think if you look at North Dakota in just a general Boken sense, other than EOGs partial field, which I think is a great asset, there's a handful of wells there that haven't really made any money.

You're exactly right, the lithology is very different than it is in the main Montana Richmond County trend.

Even when you follow the Montana Richmond County trend into North Dakota, the wells get crappy.

So I think we like the -- we like the position we're in.

We obviously are very interested -- we've got people in Billings who are very expert in this play, and we've been playing that area for a long time, and if there's something significant that happens we're going to be in it.

Great.

By the way, crappy is a technical term.

Yes, I'm sure.

Thanks.

Appreciate the clarification.

Thanks again.

Your next question comes from the line of [Richard Ellis] with [Capital One South Company].

I think you answered most of the questions related to the James Lime that I had, but the only other one I wanted to touch on is what do you think contributed most to the improvement that you saw in the costs for the Middlebrook well.

I know you were expecting about 3.5 million or so, and it probably came in around 3 million.

Is it a change in the completion method or just learning curve advance?

Well, I give the guys in Shreveport a lot of credit.

I think a lot of this is just penetration rate, bit selection.

We got down on the well a lot faster than we anticipated.

We're drilling in a newer area for us, and so we may have -- but in general this well came in at lower than our average cost for the trend.

So, I mean, that's a great sign for that particular area that we're in that we can get our P rates up.

But I think the guys -- they drilled a lot of these now.

Especially the -- we have some people in the field there who are just exceptionally experienced in drilling these kind of wells.

And I think part of is it P rate, part of it is just the location, and part of it is just experience and know-how.

I see.

And it was about 9500 feet deep in a 6100 lateral?

I think that's right.

I don't have the measured depth at TD here but that's about right.

Okay.

About 20 days or so to drill?

Yes, I think it was 19.

19 or 20 days to TD.

What were you averaging to drill number of days prior to this one?

A bit higher than that I guess.

I think we were about five days ahead of the curve.

Okay, great.

Okay.

Well, I appreciate it.

Great quarter.

Thanks, Richard.

Your next question comes from the line of Michael Scialla with A G.

Edwards.

Question on the Woodford.

Your 537 3P locations, what's the assumption there for spacing?

Four wells a section.

Essentially 160s.

Okay.

And how much acreage do you have there now?

We'll get an exact number here for you.

We've got over 40,000 acres now.

A little over 40,000 acres.

That's net?

Okay.

And then along the same lines, the 642 3P locations in Elm Grove, is that based 20 or 40-acre spacing?

Those are 20.

Do you have any sense for the 3P potential at Terryville at this point?

We've got a sheet here somewhere.

3P is 19 bcf.

Okay.

And then with -- you talked about it quite a bit, but the 3P that you've listed at Olmos is that assuming some better recoveries, or down spacing, or just some bypass zones?

There is some buying pipe in that number but most of it is just cost on new drilling locations.

And again, as I mentioned, there's a lot of acreage out there in that acreage we purchased where there isn't a lot of penetration so we really couldn't put reserves on it.

So it's just stepping out from.

That's right.

And one final one.

On Hanging Woman, did you ever get any results on the horizontal well in those deeper coal?

We have four wells drilled and really still dewatering and we're hoping we'll have a little more to say about it maybe fourth quarter.

Okay.

Great.

Thank you.

Thanks, Michael.

Your next question comes from the line of Philip Dodge with Stanford Group.

Thank you.

Good morning, everybody.

Good morning.

Two questions on the Catarina acquisition.

First, the simple.

Does it have common infrastructure with the smaller acquisition that you made in June?

The Catarina was the one that we made in June, then we have not named the specific acquisition that we just announced.

Common infrastructure.

There really isn't common infrastructure.

They're separate.

Okay.

Yes, they're separate.

The great thing, I think, about them, they're essentially adjacent to one another so we're going to be able to consolidate operations here.

As we build mass we're going to be able to work on our operating costs.

I was thinking of logistics.

Phil, I think one key aspect, though, is that there is a common contract operator at this point, working both fields.

So there are some integrated benefits that way.

And the other question is whether you have an estimate of the production that you would expect to generate drilling the 151 PUD locations.

I don't know that we've projected that.

Current rate is we -- that we've announced that at is about 9.2 million a day.

And -- we have not done projections longer term with the drilling program.

Clearly we put numbers together for the acquisition analysis, and as we mentioned we're planning on going to a two-rig program, and there's potential to go higher.

We haven't announced a production schedule yet, for that.

Do you think I could start by taking fairly normal ratio on the 57 bcf of reserves, estimated to go with the PUDs?

That's not an unreasonable approach.

Okay.

Thanks very much.

All right, Phil.

Thank you.

Your next question comes from the line of Rehan Rashid with FBR.

Continuing down the acquisition thought process.

What -- for the two-rig program, maybe an '08 production outlook, or if not that, just what could be the IP rate and how many days to drill a well so we could--?

The spud to spud timing on the wells is about 15 days.

And I think if you assume IPs in the 250 to 300 range that's probably reasonable.

Okay.

And the decline rate of the typical hyperbolic?

Probably be 1.5, something like that.

Kind of average IPs.

Could be 350 to 400.

On a gross basis.

Shifting to the Woodford, real quick, now is that possibly a little bit better results than what you had seen in the past.

Does this many an acceleration of activity in '08?

We haven't put together our 2008 program yet, but obviously the key to any acceleration has to be consistent delivery of results, and as many of you have noted, and obviously we're aware as well, we have not had consistent results to date, but again that's only 10 wells.

And I think one of the things that you will see us continue is to focus on the technical aspects of this play to make sure that first of all, before there's any acceleration, we have done our technical homework.

Jay mentioned earlier about acquiring additional 3-D seismic as well as obviously perfecting and optimizing both our drilling and our completion design.

But having said that, when we have consistent results then certainly we would look at acceleration opportunities.

So what do you guys think is a driver of this inconsistency as compared to some of the other folks, seems like relatively consistent results?

Well, we talked about in the last conference call.

I think we came at this a little differently, and we came at it from a position of wanting to drill a low-cost well.

And so we were running smaller pipe sizes, trying things, a number of different completion techniques to try to reduce the cost.

And I think some of our competitors, and I think rightly so, went after it from the standpoint of let's make a well first and work the cost afterwards.

So I think we're sort of meeting in the middle here.

That's my expectation.

I think we will have -- we will be on the low end of the cost curve for these wells.

But it took us 10 wells to get to where we really feel like we're making the kind of wells we can make.

Tony is exactly right.

We need to get a number of additional wells down where we feel like we have repeatable results here before we step on the gas and try to accelerate this thing.

But we're very encouraged by these results.

I think it lines up with basically what you're seeing other people in the play seeing for results at this point.

And then we are positioned to accelerate the play and do more here.

We've got a great acreage position as soon as we reach that point, we're not afraid to step on the gas some if we're seeing good solid performance.

I guess the real question I was trying to ask was exactly that great acreage position.

When you compare your results, your course, the geology, any differences compared to the others in terms of costing or fractures or anything like that, or more oily shales than not?

Any kind of comments on that front?

It's almost been a little bit of a soap opera in terms of our geology versus -- I can remember a year ago people saying that basically it looked like it was better going north, some said it was better going south, some said ours was about the say.

It's continued to wander across the map.

I think what's important is that first of all, we understand the geology that we have, and our ability to extract the hydrocarbons at an economic rate.

And I've heard some industry comments and some from our competitors that now they're viewing our geology very similar.

So that's kind of, like I said, a little bit of a soap opera, but we're going to focus on the geology we have and deliver the best results we can.

So I would surmise, technically speaking, you see no difference.

At this point we don't.

There are some -- if you look at this play, it's not all one big pancake Woodford Shale across this whole area.

There are some areas where you get up on structure and it gets more fractured, and frankly I think vertical wells may be a better answer to some of that, and they're cheap.

But we're trying to do the science, and we're definitely working, getting our 3D in place, working our frac designs, everything we think we should be doing, and we're getting close to where we feel like we've really got something we can accelerate on.

Okay.

Perfect.

And just some thoughts on the Hanging Woman Basin.

Where is the production now and maybe some outlook into what other catalysts need to happen to be more comfortable , the 3P upside that we talk

Right now the current growth rate is about 13.3 million a day, and net rate would be a little over 8 million.

And again, same question in terms of acceleration and the catalyst to be more comfortable with the 3P discussion.

Well, I think people -- you talk 3 P, and sometimes I'm afraid people are confusing 3P with three different kind of proven, and it's not true.

You look at -- there's a lot of the Hanging Woman reserves are in the possible category.

50% of the reserves are in the deep.

The 3P reserves are in the deep where we really don't have any significant producing penetrations at this point.

So there is a lot of risk to this and we recognize it.

I think what you have to see is our de-watering times have been longer than we expected in the core part of Hanging Woman.

We drilled it on 160-acre spacing because we felt that would be the economic approach.

Our dewatering time has been longer.

Because of that we started doing some infill 80s there.

We'll see how that works out.

If you look at where we've been most successful it's really on the Eastern portion of the play in what we call the River One areas.

We're drilling a bunch of wells right next to that in the River Two area this year.

We're drilling those on 80s.

We expect to see faster dewatering and better results there.

Again, the intermediate and the deep coals we really need to do some more testing work and working forward.

So these reserves are going to come in over a long period of time -- I think that's important.

It's not all going to show up next year.

On the deeper side, when would you expect your first -- I think did you drill something earlier on.

Yes, I mentioned earlier.

We expect to see some results fourth quarter on some of that dewatering, but I'll tell you, this is a significant resource over a big area.

Drilling four horizontal wells in one spot does not prove asset beat.

There's a lot of work to do.

Now, to be honest, I mean, CIG prices really have been poor.

Right.

And what we're hoping this year is where we ramp in production as the prices improve into next year and you do see that basis narrowing.

So if you look at it from the that standpoint really hasn't been -- the timing really hasn't been that bad.

That's fine.

That's fine.

All right.

Thank you.

Thank you.

Your next question comes from the line of Eric Hagen with Merrill Lynch.

A follow-up on the Olmos play.

How big of a trend is this, and is it big basin center type play?

Is there a chance to lease up some exploration acreage, or--?

Yes, it's a good-sized play, and there's a number of different play types in there.

It's kind of a beach front-type play, originally deposited from the northwest, kind of a shelf front, and you'll have four or five different of these producing zones in there that are fairly thin, say 20 to 30 feet.

There's a lot of activity down there.

We've looked at a number of different packages and there is some acreage down there.

They're big ranches.

So you can work with some big foot print.

We're excited about it.

We think there's a lot running room and opportunity.

With that said, there's obviously competition there, too.

And we recognize that.

There's some very qualified, very good independent players in the basin.

But we do think there's some upside to that.

Eric, this is multi-county kind of expansion -- or expansive area for the play.

In addition to that though, as we did with Sweetie Peck, our primary focus is going to be obviously on the transition and execution of our plans with our new acquisition, but clearly we'll continue to look outside that if we can acquire additional acreage for reasonable price.

Great.

Thanks.

Thank you.

Your next question comes from the line of Larry Busnardo with Tristone Capital.

Just a couple quick follow-ups.

On the rig count, you got 18 rigs running right now.

Where do you see that going for the remainder of the years and then how well the commodity prices impact that primarily I guess on the gas side of things, or given your hedge position do you look past that and kind of keep plugging away with all the opportunities you have in front of you?

Yes, Larry, right now we had kind of projected a 12 to 18 rig count for the year, kind of ramping up through the year.

So we're kind of at the 18.

We expect that to probably go up a couple more rigs.

Right now from a commodity price standpoint, rig availability standpoint, we're able to find for the most part the rigs that we need to expand our plays.

So we're kind of cautiously optimistic that hopefully rig rates will hold reasonably where there and we can continue with our drilling program.

Larry, I think what you're see on the gas price, certainly in the short-term shoulder months here it is down quit a bit but you get out through the winter and into next couple of year strip and it's held up pretty good.

Larry, I think one of the other things, too, that we'll focus on is putting together a consistent drilling program in most of our regions and trying to lock in some of our rigs, but obviously that depends on success in our multiple plays.

Yes, that's part of my second question.

I thought you did a good job here with the table you got in the release, just kind of laying out the 3P reserves and your drilling locations.

I think the thing that stands out here is the number of locations that you have out there.

And I guess going forward, should we -- do you think we see you as you head into 2008 maybe accelerating some of these, or is that kind of the main plan?

I know you talked about acquisitions being part of it, and augmenting your growth going forward, but is the plan to accelerate growth on these existing assets to kind of pick up the pace and move these forward a little bit?

I don't know if it's just a matter of acceleration.

I think the key is to grow the inventory to multiyear, so that based on market conditions you can accelerate or have variability with your program based on what the market has given you.

But the key is to have that flexibility and to have the options associated with the broad inventory of prospects.

So I think the key right now is let's grow the portfolio, let's get a higher inventory of opportunities like you ar seeing in the press release, and then we can vary the speed with those programs based on market conditions.

I think the -- it's great to have a bigger inventory.

What it it means is your economic opportunities are increasing, which means they should get on average get better as we high grade those.

I think the question was asked earlier about acquisitions versus organic and we do have a track record of making acquisitions but I do think we are shifting to some extent to a drilling, or a drilling and operational focus which I think is really positive.

We're going to get more focus on LOE, we're going to have more focus on drilling cost, more focus on F&D.

It's just I think a real opportunity for us to just get better.

Okay.

Great.

Thanks, guys.

Thank you.

Your next question comes from the line of Subash Chandra with Jefferies.

I was writing kind of fast, I just wanted to confirm on the vertical part of the Woodford that you hope to go from three strings to two?

We're setting surface pipe and then we're going all the way to TD with 5.5 is where we're at.

Okay.

Is there a chance to use bigger pipe or is pretty much that what the regional average is?

That's an interesting question, and we've been debating the benefits of going to 7-inch on bottom.

There's actually some technology out there where you could drill in 7-inch.

So that's kind of an interesting issue.

We're not sure of the hydraulic benefits that's necessarily correlate, if you get bigger than 5.5 you're necessarily going to get any value for that.

I wouldn't be surprised if we don't try it at some point but right now I can't tell you that it's going to make a big difference in the wells.

I was curious if there's a tool out there that allows perhaps to fine-tune the frac stages and find areas that might be better, just a better frac candidates rather than doing sort of a standard, I don't know, frac every 500 feet or so.

We're working on some things, trying to look at the horizontal section and try to pick places we think are better to perforate and better to frac.

I don't want to talk about what we're doing.

I think every operator out there is trying different things to look at that.

It's not necessarily a tool so much as it is used in your existing tool in a more, I guess a more intellectual way.

But I do think as we go forward here we're all learning.

Woodford is a great source of gas.

Got a lot of gas in the rock.

I think we'll get better.

People will get better.

Thanks.

Thank you.

Your next question comes from the line of Michael Scialla with A.G.

Edwards.

I just wanted to follow up with one more on the 3P reserves in the Atoka/Granite Wash.

That 533 location you have listed there, are those based off of vertical wells?

They're all verticals.

And that's in northeast Mayfield mostly?

Southwest Mayfield and northeast Mayfield.

Have you or any other operators tried any horizontal wells in that play at this point?

Say that again, Mike, sorry.

Has there been any horizontal drilling in that play at all?

I'm not aware.

Are you aware of any horizontal wells at Mayfield?

No, and I don't think it -- I don't think it makes a heck of a lot of sense.

Most of this, there's -- it's kind of a multibed kind of a multifrac stage kind of completion, and if you -- I don't think that a horizontal will really work here.

It's pretty deep, too.

It would be a very expensive completion.

Okay.

Thank you.

Yes.

At this time there are no further questions.

Are there any closing remarks?

No, I think we certainly appreciate the questions and the audience calling in this morning.

As I mentioned earlier, we had had strong momentum going forward.

We fully intend to execute on our program for this year, and we're very optimistic about, especially well our recent rules and some of our developing plays.

And I can tell you as far as our new acquisition, I think that's a perfect example of how we intend to grow our multiyear drilling inventory, which would allow us to take advantage of those opportunities going forward.

Thanks very much for calling in this morning.

This concludes today's St.

Mary Land & Exploration second quarter 2007 earnings conference call.

You may now disconnect.