SM Energy Co (SM) 2006 Q4 法說會逐字稿

Good morning, my name is Phyllis and I will be your conference operator today.

At this time I would like to welcome everyone to the St. Mary Land & Exploration full-year and fourth-quarter 2006 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).

I would now like to turn the call over to Mr. Brent Collins, Director of Investor Relations.

You may begin your conference.

Thank you, Phyllis.

And good morning to all of you joining us by phone and online for St. Mary Land & Exploration Company's full-year and fourth-quarter 2006 earnings conference call.

Before we start I need to read the following statement.

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

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

These risks include such factors as the volatility and level of the oil and natural gas prices; the uncertain nature of the expected benefits from the acquisition of oil and gas properties and the ability to successfully integrate acquisitions; the potential effects of increased levels of debt financing; the imprecise nature of estimating oil and gas reserves; the ability of additional economic economically attractive exploration, development and property acquisition opportunities for future growth and any necessary financings; environmental matters and the potential impact of government regulations.

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

The company officials on the call this morning are Mark Hellerstein, Chairman and Chief Executive Officer;

Tony Best, President;

Jay Ottoson, Executive Vice President and Chief Operating Officer;

Dave Honeyfield, Vice President, Chief Financial Officer;

Jerry Hertzler, Director of Business Development;

Dennis Zubieta, Manager of Reservoir Engineering; and myself, Brent Collins, Director of Investor Relations.

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

Thanks, Brent.

Good morning and thank you for joining us today.

As many of you know, this will be my last St. Mary conference call as I will be retiring as CEO.

Tony Best will assume the duties of CEO today after a very good and seamless transition.

As you must know, I have mixed emotions leaving today.

I'm excited to begin this new phase of my life where I'll have more time to pursue personal interests; at the same time I know I'll miss the day-to-day interactions with colleagues and partners.

I've thoroughly enjoyed my 15 years at St. Mary.

I've seen the Company grow from an $80 million private Company to a $2 billion New York Stock Exchange listed public company.

Being recognized in each of the last five years as one of the 100 best performing companies in America by the three top business magazines is an achievement that I never imagined in my wildest dreams.

Not only has our performance been superb for our shareholders, but it has provided a great workplace and financial opportunity for its employees and has allowed St. Mary to be a positive contributor to the community.

St. Mary has done this with a commitment to integrity and over the years has developed a pristine reputation.

This record is the result of the efforts of an extraordinary team of people with talent, knowledge, passion, creativity and moral fiber.

I would love to take credit, but in reality my contributions were modest.

I'm just proud to have been a part of this wonderful organization and look forward to serving as its non-executive chairman.

It is nice to end on a positive note.

St. Mary announced record production, reserves, earnings and cash flow and I'll miss the relationships of the buy and sell side, outside advisers and employees.

Thanks again for 15 great years.

Now I'll turn it over to Tony.

Thank you, Mark. 2006 was a record year for St. Mary.

We set all-time records for proved reserves, production, earnings and discretionary cash flow.

More importantly, our activity this year has put us in a position to continue to grow in 2007 and beyond.

We grew our proved reserve base by 17% to 927.6 Bcfe as of year end of which 78% is proved developed and 52% is natural gas.

Our finding and development cost for the year was $3.56 per Mcfe with a 244% reserve replacement percentage.

We were impacted by a downward 52.2 Bcfe price revision that resulted from a 44% decrease in natural gas price used for reserves from year end 2005.

We had 66.3 Bcfe in positive performance revisions and acquisitions contributed 99.2 Bcfe in reserve additions.

Excluding the price revision mentioned above, our F&D cost would have been $2.90 per Mcfe and our reserve replacement percentage would have been 300%.

Our proved probable and possible 3P reserves were 2.9 Tcfe at year end, a 16% increase from 2005.

Production for 2006 was a record 92.8 Bcfe, 6% higher than the prior year.

The increase in production was driven by growth in the midcontinent and Hanging Woman Basin.

Net income for 2006 was $190 million or $2.94 per diluted share compared to $151.9 million or $2.33 per diluted share for the prior year.

This is a record both in absolute dollars and on a diluted share basis.

Discretionary cash flow increased to a record $521.1 million, up 14% from last year.

The average realized equivalent price, including the impact of hedging, remained essentially flat compared to last year at $8.18 (multiple speakers).

Operating costs continued to increase year-over-year as lease operating expense increased $0.29 to $1.37 per Mcfe.

In addition to general cost inflation we also had a significant amount of workover activity in 2006 mostly in the Rockies, midcontinent and Gulf Coast which added to our LOE increase.

Production taxes decreased $0.02 to $0.54 per Mcfe;

G&A increased $0.05 year-over-year to $0.42 per Mcfe.

The increase was driven primarily by increased headcount and base compensation plus the recognition of additional stock compensation expense as a result of the adoption of FAS 123R.

As a result of our realized price remaining flat and our cash cost increasing our cash margin decreased $0.28 to $5.85 per Mcfe in 2006.

DD&A including impairments increased $0.15 to $1.67 per Mcfe.

This increase in DD&A reflects the higher cost of drilling and acquisitions in recent years.

Production in the fourth quarter of 2006 was 25.1 Bcfe, 15% higher than the hurricane impacted fourth quarter of 2005 and 8% higher than in the third quarter of 2006.

Our fourth-quarter '06 production averaged 273 million cubic feet a day, the highest in company history.

Earnings for the fourth quarter of 2006 were $43.5 million or $0.69 per diluted share, down from $51.2 million or $0.78 per million per diluted share for the same period the preceding year.

Discretionary cash flow decreased to $126.4 million in the fourth quarter from $141 million in the corresponding period of 2005.

While volumes increased significantly quarter to quarter, the net realized equivalent price including the effects of hedging decreased from $9.97 per Mcfe to $7.73 per Mcfe over the same period.

Excluding our hedges, our quarterly equivalent price of $7.20 per Mcfe was a 32% decrease over '05.

I will now touch on some of the highlights of 2006.

Companywide we drilled or participated in 354 conventional wells with a 95% success rate.

We also performed 95 recompletions with an 82% success rate.

At the Hanging Woman coalbed natural gas project, 138 wells were drilled in '06, 96% of which were operated by the Company.

This is an increase from the 125 drilled in '05.

Most cart production at Hanging Woman Basin is 14.2 million cubic feet per day gross, 9 million cubic feet per day net, from 268 gross producing wells.

In our horizontal Arkoma program targeting the Wapanuka limestone, the Cromwell sandstone and Woodford shale, we have increased our net acreage to approximately 38,700 acres as of year-end, a 94% increase from year-end 2005.

In early '06, our first four horizontal wells in the Woodford shale were disappointing, so we called a technical timeout at midyear and redesigned our stimulations using lessons learned from offset operators, service companies and technical consultants.

Using our improved frac design, we subsequently drilled two much more successful wells, the Theresa Hampton and the Elaine.

Our most recent well, the [Churner], unfortunately has not performed as well as we had anticipated.

We believe that we drilled out of the Woodford interval into a zone with more clay which then swelled when we fraced the well.

The Churner is producing below levels we were expecting; however, the daily production is gradually increasing as the well continues to produce.

We have two horizontal Woodford wells, our eighth and ninth, currently drilling.

As you've heard me say before, this is still an emerging clay and we have much to learn.

Our focus going forward will be both on technical advancement and drilling execution.

At the Elm Grove field, development of the field continues to exceed expectations.

In addition to the successful lower Cotton Valley wells that have been the focus of activity in the field in recent years, 2006 saw successful uphole recompletions in the [Hauston] interval using coil tubing assisted fracs that open the door to a new phase of development in the field.

Activity continues to move south at Elm Grove onto acreage where we have a higher working interest.

Also of interest, one of the operators in the field recently began a 20 acre pilot program on nearby acreage which, if successful, could provide even more upside at Elm Grove.

In the Gulf Coast the direct hydrocarbon indicator exploratory program had a successful year with discoveries in six out of eight prospects, including the Tucson and Holly prospects which we operate.

The Tucson well, St. Mary working interest of 29%, is currently producing 11.5 million cubic feet equivalent per day gross and the Holly well, St. Mary working interest 41%, is producing 3.2 million cubic feet per day gross.

Additionally, we had successes with our operating partners offshore.

At Vermillion 101 and at Garden Banks 195, the Zloty prospect.

The Vermillion 101 discovery well, St. Mary working interest 25%, began flowing to sales in December and is currently producing 11.4 million cubic feet equivalent per day gross.

The Zloty well, St. Mary working interest 30%, is awaiting production facilities and won't flow to sales until mid 2008.

The operator of the St. Mary 24-1 sidetrack, a significant royalty well that was completed last year and then shut in with mechanical problems, has decided to plug and abandon the well.

We currently don't know if the operator plans to drill a new replacement well at this time.

In the Permian the highlight last year was the acquisition of the Sweetie Peck field in the Midland basin.

This acquisition was the largest in company history and provides us with a multiyear inventory of low-risk drilling locations.

We opened our Midland office earlier this month and we've taken over operatorship of the field.

We have two rigs running now and plan to increase the rig count to four by year-end.

On the financial front we repurchased 3.3 million shares of common stock in the second quarter of 2006.

The shares we repurchased at an average price that was below our assessed net asset value per share at the time of the repurchase, and we locked in this economic gain by hedging a commensurate amount of our production at the time.

I believe this demonstrates our ability to create value for our shareholders through financial transactions as well as through drilling and acquisitions.

Now I'd like to introduce our new Chief Operating Officer, Jay Ottoson.

He just came on board in December and he's already proving to be a great addition to St. Mary.

I'll turn the call over to now to Jay to discuss our 2007 plans.

Thank you, Tony, and good morning, everyone.

The 2007 capital budget of $821 million includes $721 million for exploration and development and $100 million for acquisitions.

We will operate 72% of our budgeted exploration and development dollars into 2007.

The exploration and development budget is almost $200 million or 38% greater than the $523 million we spent in 2006.

The increase relates primarily to the Sweetie Peck acquisition, increased activity in the ArkLaTex region related to Elm Grove, and the horizontal limestone program and a near doubling of capital being deployed at Hanging Woman Basin.

In the midcontinent we've budgeted $206 million for 2007, 82% of which will be operated by the Company.

Two operated rigs are scheduled to work in the horizontal Arkoma program focusing on the Woodford shale and 30 gross wells our planned in the Mayfield development area.

In the Rockies $155 million is planned for 2007;

St. Mary will operate 81% of these capital expenditures.

Three operated rigs will work throughout the region in 2007.

The reentry program targeting the Mississippi interval in the Williston basin will be expanded and activity will ramp up in the Wind River and Big Horn basins.

At Hanging Woman Basin $58 million is budgeted for 2007, up from $30.4 million in 2006. 218 operated wells are planned for 2007 primarily focusing on the shallow and intermediate coal packages, although additional horizontal wells are planned to be drilled in the deeper coal seams.

We began the program with two truck mounted drilling rigs and anticipate being at four to six rigs in the second half of this year.

All of our planned activity at Hanging Woman in 2007 is scheduled in the state of Wyoming.

The Company also will participate in approximately 40 non-operated wells this year.

In the ArkLaTex region we're forecasting $131 million in 2007 capital expenditures, a significant increase from the $88 million we spent in 2006.

The focus for 2007 is on execution of the horizontal limestone program and accelerating activity in the Elm Grove field. 22 horizontal limestone wells are planned for 2007 of which St. Mary will operate over 90%.

At Elm Grove field we continue to work with the operator to accelerate development where 87 new drill wells and 20 Hauston recompletions are planned for the year.

We also have five wells budgeted at Terryville and the lower Cotton Valley formation.

In the Permian we've budgeted $111 million in capital for 2007.

The Company began with two operated rigs running in the recently acquired Sweetie Peck field in the Midland basin and, as Tony mentioned, we plan to be up to four rigs by year-end.

This is a tight oil play targeting the Spraberry interval which includes the Spraberry, Leonard and Wilcamp formations.

St. Mary will operate 100% of this drilling program where 54 wells are planned for 2007.

We also have activity planned at our East Shugart Delaware and Parkway Delaware waterflood programs.

The Gulf Coast region has $60 million of capital budget for 2007; the Company will continue to focus on low to moderate risk direct hydrocarbon indicator based exploration prospects in 2007.

Additionally, St. Mary will be participating with our operating partner to complete production facilities for the previously announced Zloty discovery in the intermediate deepwater of the Gulf of Mexico.

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

Thanks, Jay. 2006 was a successful year for St. Mary with record proved reserves and production, net income and discretionary cash flow.

We're also poised for continued success in 2007.

We entered the year with the largest inventory of projects in our history, armed with a very talented employee base and a strong balance sheet.

Now before we turn the call over for questions, I'd like to take a moment to say a few words about our outgoing CEO, Mark Hellerstein.

I've had the pleasure of working side-by-side with Mark as we focused on a smooth, efficient executive transition over the past eight months.

This handover process could not have gone better and I look forward to our ongoing collaboration as he continues to serve the Company as Chairman of the Board.

Today is mark's final day as CEO of St. Mary, and on behalf of our employees, Board of Directors, stockholders and his many colleagues and friends, I'd like to extend our heartfelt thinks for his many years of dedication and service to St. Mary.

Mark, we all wish you the best of luck and Godspeed as you begin a new chapter in your life.

With that we'll now respond to your questions.

(OPERATOR INSTRUCTIONS).

Philip Dodge, Stanford Group.

Thanks for the comments.

Questions on the Bakken.

Could you go through what your activity looks like there in 2007 and also what activity there will be if any on the North Dakota side of the play?

And Mark Hellerstein, all the best.

Thank you, Phil.

Phil, this is Tony.

For 2007 in the Bakken we plan to drill about five wells this year and those will be on the Montana side.

On the North Dakota side, that's an area where we continue to watch some of the other offset operators as far as their continued development in the Bakken.

As you know we've seen less success on the North Dakota side through a series of reentries and deeper tests in the Bakken.

So for the time being we're going to focus on other plays this year in the northern Rockies, primarily in the Mississippi and we'll go ahead and continue to watch and see what others are doing on the North Dakota side.

Have you seen any encouragement on the North Dakota side in recent days or weeks or is it about the same conclusion?

Phil, we've seen a handful of what we think would be successful wells on the North Dakota side from several operators.

We're also participating ourselves in a couple of the areas where there's more of a structural component to the Bakken.

But for the most part we're going to watch and see if there is continued success or significant success on the North Dakota side before getting back into that activity in a broader play.

Thanks, Tony.

Rehan Rashid, FBR.

Just a couple of questions.

First, on Hanging Woman Basin, how many wells are expected to be drilled this year?

We expect to drill 218 wells that we will operate.

We'll also participate in 40 additional wells with other operators.

Any thoughts on what exit rate for production might be for '07 here and what are you thinking about '08 and then just give us a feel for overall development plan for Hanging Woman Basin.

This does seem like an acceleration.

Yes, that's exactly the indication for 2007.

In looking at that in 2006 with the Billings team, we asked the question if it was possible to accelerate that program.

With a two rig program that would basically be about a 20-year drilling program at Hanging Woman Basin.

The team came back and they expect to significantly increase the program to something that could he more like a 10-year program.

As far as projected rates, we have not projected year-end rates at Hanging Woman.

As we mentioned earlier, the current rate is over 14 million a day gross.

We remain excited about the play, it's still emerging.

We still have a lot to learn.

But we feel that we're on an accelerated track and we're anxious to see the results of continuing that play.

I should point out too that at the end of last year we did drill four horizontal wells which were the first ones in the field and we're waiting to see the results of those wells.

As you probably know, it takes anywhere from 6 to 18 months for those wells to deepwater before we see gas break through and it will take us a little bit of time to see the results of those first four horizontal wells.

I'm drawing from memory here, but there was a deeper coal test that was going to be done or will be done and they had a reasonable amount of the 3P upside associated with that.

Any update on that front?

Rehan, the four wells that Tony was talking about, those were the deeper coal tests.

Okay, perfect.

Two more quick questions.

On the capital allocation front, $720 million for '07, if I were to annualize the fourth-quarter production for '06 and look at the guidance for '07, we're going from 100 Bcf to a guidance of 104 to 106, just without doing any of the math, it seems like that we're not -- a production ramps should have been a little bit more stronger based on the increase in capital spending we're seeing.

And also, for '07 the rough cash flow number that I can come up with is somewhere around 450 to $500 million.

Is this a -- will you be willing to take up your debt leverage as much if the difference indeed is $200 million between cash flows and CapEx?

First of all, we ended the year at a little over 92 Bcfe, and then we are giving guidance of 103 to 105 Bcfe for next year.

So it's a little bit of difference from (multiple speakers) -- 104 to 106, excuse me.

But as far as the program for next year, it is a significant ramp up on exploration and development.

And the bulk of that increase, approximately $200 million, almost half of that is associated with the acquisition in the Permian Basin at Sweetie Peck plus some additional development in that area.

The remainder of the increase includes some significant increases in our program, as we mentioned earlier.

That would include a significant increase at Elm Grove where we will be almost doubling the number of wells that we'll be participating in with the operator there as well as the Hauston recompletions.

We'll have 20 of those in 2007; we only had a handful of those in 2006.

In addition to that, obviously the significant increase at Hanging Woman Basin that we talked about earlier is a significant increase in capital there as well.

But in terms of your question about would we be willing to take on debt or do other -- take other options to increase our capitalization, the answer to that is, yes.

And Dave may want to comment on that as well.

The other thing you might want to just keep in mind is in terms of the capital spend in '07, there will be capital spent on hopefully increasing leasehold.

Some of the increase at Hanging Woman Basin is for development of infrastructure.

And then some of the intermediate deepwater completion capital that will be spent, we don't expect production to come on until probably mid '08 on that basis.

Along those lines then, how much of CapEx in '07 is that meaning at a PUD conversion or something that you won't see much benefit for until later years?

I would estimate somewhere in the probably 50 to $100 million range just because I don't have a precise number on that.

Okay.

I'll follow-up later.

Thank you.

David Tameron, Wachovia.

Good morning, everyone.

And again, Mark, congratulations on a great tenure.

Hope everything goes well for you in your next venture.

It's been a pleasure working with you.

Thanks.

A couple things.

If I look at prior presentations, going back to November/December and then look at today's -- I just want to make sure I'm looking at apples-to-apples, it looks like Elm Grove, you've kind of increased the upside there as far as your 3P number.

Is that an accurate read?

It looks like you increased the number of locations and increased the PUDs there.

Am I looking at apples-to-apples?

I think part of that also has to do with the increase relative to the Hauston and that's probably what you haven't seen before, Dave.

Okay.

So what's changed recently?

Is it just more results from the second half of the year?

Is it a more aggressive program going forward or what's kind of changed within that?

I think it's fair to say that it is a more aggressive program going forward.

For example, in the latter part of last year one of the prime operators was drilling with one rig.

They're expecting to proceed with three rigs throughout this year.

So that is a significant increase in activity year-to-year.

Okay.

And then Tony, we've talked a little bit about this, but in the Woodford my understanding is your acreage is near other operators down there, even adjacent to.

Are other operators from what you hear from them and do you have interest in those wells?

Can you see what they're doing?

Have results been similar?

Or you mentioned the Theresa Hampton, the Lane was good, the Turner was not so good.

Can you talk about what you're seeing from your neighbors out there?

I guess what I'm trying to get at is this more a function of acreage?

Is it more a function of they're further up the learning curve because they've drilled 150 wells versus your 10 wells?

Can you talk a little more about the discrepancy in the Woodford?

Sure.

First of all, yes, there are several offset operators directly adjacent to our acreage position.

And we have gone back and have taken a look at a variety of wells, ours as well as some of the offset operators.

We've done comparisons on probably the last 15 or so wells.

And the distribution on performance is pretty mixed for all of the folks involved with those wells, ourselves included.

So there is a mixture of performance, it's not just St. Mary.

If you look at the distribution there, you've got some of their wells falling below ours and some of our wells falling above theirs.

So I think truly it is a function of geology as well as completion designs.

As I mentioned last year, and just a few minutes ago in my remarks, I think one of the things that we've really been focused on is trying to learn as much as we can from whoever is successful in the play, in the Woodford.

And that has definitely helped us as far as the results of our simulation design.

As I mentioned, the first four wells were rather disappointing.

The two wells after we redesigned our stimulations came on much better.

And I think that's consistent with some of the mixed results that we're seeing with offset operators as well.

The same holds true also on well costs.

As a result of cost increases all of the completed well costs in the Woodford have gone up, but that's also a mixed bag as far as the various operators as well.

We've seen completed well costs by offset operators that have been higher than ours, some others have been lower.

So I think that basically characterizes the (multiple speakers) play in that it is a -- continues to be an emerging play.

We're all still learning how to best drill and complete these wells.

All right, good answer.

Going to the Permian, Sweetie Peck, remind me again, these wells -- I think the target when you rolled it out was between 1.5 to $2 million per well.

Is that the right number and, if so, is that still -- coming back two months later after that acquisition is that what you're still expecting and then what kind of reserves are you getting per well out here?

For the Sweetie Peck acquisition, basically our completed well cost target is $1.6 million and obviously our job is to get as efficient as we can and get that number lower.

We have brought on two new rigs and a few months ago, just prior to closing that acquisition, part of the concern was were rigs going to be available and at what price?

And we've been very pleasantly surprised with the availability of rigs.

We had a chance to actually take a look at six to eight rigs and were able to select the rigs that were best suited for this development.

In addition to that, we saw our first rate reduction on dayrates that we've seen in over three years.

So that was very encouraging.

I think that's going to help us as far as trying to lower our completed well cost, but as we mentioned, we just took over operatorship at the beginning of this month and we have a ways to go, but we're very encouraged with where we are at this point.

And how many locations do you have out there?

I think when you did the initial acquisition you talked about 80 acre locations, but my understanding is you can go to 40s or you think there's potential to go to 40s.

Can you just recap that for me?

We have 266 3P locations identified at Sweetie Peck.

We are currently drilling on 80 acre spacing.

We will be testing going forward 40 acre spacing, but at this point out focus is on an 80 acre program.

We do have one 40 acres spaced well in the field which was drilled by the prior operator and production to date seems to be on par with the 80 acre offsets if not even a little bit better.

But again, I caution that's one 40 acre spacing unit in the field at this point.

Okay.

And then one more question and I'll jump off.

The Powder River Basin, there's been noise about the lawsuit in Montana going to the Circuit Court of Appeals in San Francisco, etc.

Can you recap the regulatory environment, where we're at on that particular dewatering, what the impact could be to you '07/'08 if any as far as getting permits, etc.?

Sure.

Original estimates as far as a decision by the Ninth Circuit Court out of San Francisco was somewhere like mid '07 to third-quarter '07.

We basically focused our plans for this year on the Wyoming side.

As you can appreciate, you never know for sure exactly how those situations are going to turn out or if there's going to be appeals or challenge to that.

So we've gone ahead and developed our plans not based on results of the court action, which means basically we will be focused on the Wyoming side at Hanging Woman Basin.

Would that be an '08 event for you impact wise if for whatever reason it got hung up?

At the present time we've got 70% of our acreage on the Wyoming side.

So we've got multi-year opportunities to continue with our program on the Wyoming side.

We still have the option to look at state and fee acreage on the Montana side.

So I mean we still have options to move across the border in that regard.

All right, thanks for the Q&A.

I'll jump off.

Michael Scialla, AG Edwards.

Good morning, everyone.

I'd like to echo everybody else's remarks and say, Mark, you'll be missed, it really has been a pleasure working with you.

Thank you, Mike.

I want to follow up on David's question on the Elm Grove, your presentation showing that potential.

I'm assuming that does not include the down spacing potential that you mentioned in your remarks, Tony?

That's correct.

And is it 680 Bcf of potential, or is that 680 potential locations?

That is 680 potential gross locations, Michael.

So 195 Bcf of potential?

Correct.

How much of that is proved or is that an upside number?

On the proved basis we have a total of close to 80 Bcf.

Okay.

And then for your exploration charges -- I sorry if I missed this in your prepared remarks;

I missed the first part of your comments.

But you had about $16 million in exploration expense this quarter. does that reflect Gulf of Mexico activity or what drove that up in fourth quarter?

Mike, this is Dave Honeyfield.

Part of that is just ongoing G&G and there may have been some delay rentals that were paid out of that item.

I think (multiple speakers), yes, and then we had a dry hole that occurred after the end of the year that for accounting purposes you end up having to push that back into the fourth quarter.

But that was -- I think we had mentioned that we've had a success in six to eight of our DHI programs; it was six to seven prior to this particular well.

I know that's a hard number to forecast, but I'd assume for '07 you would expect on a quarter-by-quarter basis to be somewhat lower than that on average.

Yes, bear with me one sec here and I can double check.

Yes, you can probably pull out -- you can probably reduce that a couple, $3 million on a quarterly basis.

Okay.

We don't have the exact numbers right in front of us right now, Michael, but --.

That's pretty indicative.

Okay, that's fine.

Your drill bit finding costs for '06 were looked like nearly $5 an M. Were there some timing issues there or drilling a lot of PUDs or is that really reflective of the true cost structure of the Company right now?

No, we actually indicated that it was $3.56 (multiple speakers) for '08.

Okay, and is that -- do you think that's reflective of what you'll see going forward?

We're certainly not anticipating that going forward, Mike.

We had -- some of the items that we've touched on through the year or throughout the year in that we had the early tests in the Woodford that we didn't get the reserves that we had wanted.

We also had been testing the fringes up in the Bakken during '06, so we had a little bit higher cost in that regard.

So going forward we're certainly hopeful that that cost gets more in line with the on average right around $3 sort of range.

But fortunately we're starting to see what feels like a leveling on the cost side of the business.

We'll just need to keep an eye on it throughout the year.

Something else we have seen too is, like Dave indicated, and I mentioned a few minutes ago that we are starting see some at least flattening if not reduction in ongoing drilling cost.

We looked at Baker Hughes most recent data and it shows by region and by basin that in every case the rig activity is flat to declining.

And of course that will vary by basin and by region.

But we haven't quite seen the same turnaround yet on the services side as far as fracs and simulation cost, but at least we've seen more availability of frac crews and the equipment associated with that.

Okay, that's helpful.

Tony, I wanted to ask you given your background, is the Permian likely to get more emphasis now going forward and if so do you need to bulk up there more with acquisitions and if that's the case what does the market look like there now?

I think we're basically going to continue to be active in every region where we operate right now.

I think it's fair to say that with our acquisition with Sweetie Peck and the opening of our new office there I would certainly expect to see the deal flow increase in the Permian Basin.

In fact, in talking with our new team on the ground there in Midland right in the last week or two, they've indicated there's already been a surge of interest and a lot of deals being brought to our new office there.

So I would certainly expect that to continue and hopefully we'll be able to find some additional opportunities there as a result of that.

Okay.

Wanted to ask about one other area.

The horizontal James Lime play, I notice you didn't list that in your presentation as an area of significant drilling potential.

Can you talk about that play a little more, what are you seeing there?

Sure.

This is a play we haven't talked a lot about before this year for a variety of reasons.

First of all we've been leasing in this play.

For the last three or four years we have been drilling in two of our fields in the ArkLaTex area which includes the Huxley Field and the Spider Field and in the process of learning to drill these James Lime horizontal wells we continue to improve our performance there.

We were initially averaging somewhere over to 2.5 million a day as far as IPs.

At the Spider Field we've had continued success and it optimized those completions to the point where we're seeing IPs now over 5 million a day.

And as a result of that we have gone out to lease and expand our position in that play and we have increased our acreage position there by 63% year-to-year.

So that's why we haven't said a whole lot about it until this year because we're in the process of acquiring additional leasehold.

But what I'm excited about is looking at this now more on a regional trend basis and being able to leverage from our success -- earlier success at these other fields and we'll be drilling horizontal lime with two rigs this year so that's an increase year-to-year.

And we expect to participate and operate 22 new wells in that play this year.

Can you give me just a general sense of what kind of well costs and reserves you're targeting?

Yes, the well costs for these are between 2.5 to $3.5 million.

And the EURs are in the 1.5 to 2 Bcf range.

Okay.

And just one last question.

On the Woodford, you've mentioned the costs had varied from operator to operator.

What was the range of cost on your horizontal wells there?

We've seen everything from about $4 million to 5.5.

And again, that has tended to ratchet up based on obviously increasing costs.

But we're hopeful that will moderate now with some of the breakover in costs that we're seeing.

Would you care to say what the two good wells that you have in that play, what kind of EURs you expect out of those?

Let's see, we're probably looking in the 2 Bcf range and that's just for the Woodford.

Okay.

Thank you very much.

John Gerdes, SunTrust Securities.

Mark, all the best to you.

Tony, as far as this Woodford work, what are you thinking technically as far as this eighth and ninth well?

What do you need to do here do you think?

I think the first thing we need to do is to be sure that we have a chance to focus on two things.

One would be drilling execution in terms of making sure that we remain in zone.

As I mentioned on our most recent well, we don't believe that that was the case to the full extent of the lateral.

The other is to make sure that we continue to optimize our stimulation designs going forward.

And I think those are the keys in that play going forward as well as continuing to do our regional geology and focus more on what some of the offset operators are doing.

Tony, are you stimulating about every 500 feet like some of your competitors are doing?

We tend to look at longer intervals than that, not just 500.

Okay.

Order vision -- shifting over to the Williston Basin, there's been a little bit of drilling activity by the firm over the last few years.

What are you planning in the (indiscernible) Red River this year?

As I mentioned earlier, we'll drill a handful of Bakken wells this year.

But in addition to that we are shifting some of our focus to some of the other zones of interest including Red River, including Madison, and [Iskew].

And for this year we expect to drill around 15 wells in the Williston.

But that would include both Mississippi in age and also the old edition Red River?

That's correct.

Okay.

What's your sense of optimism in terms of the infield work that's going to be done by industry in terms of Elm Grove?

What are your volumetrics suggesting?

That's going to probably be the way the ultimate development density there?

Too soon to tell.

I think the key is going to be to watch the 20 acre offset pilot.

And I didn't mention, but the operator of that pilot is the same operator, key operator for us at Elm Grove.

So we're obviously very hopeful that if that test is successful that we would have similar opportunity within Elm Grove.

But going down to 20 acre spacing would be he a great upside for us.

This is one asset that has just continued to get better and better since we first acquired it and a great success with the lower Cotton Valley and now with the Hauston and now with the potential to go to 20 acre spacing we remain very excited about this play.

Last question.

As far as your drilling activity leveraging off of your acquisition late last year, Sweetie Peck, how many wells are you planning on getting drilled this year?

I have noted here at least 30?

We'll be drilling 54 wells expected in the Sweetie Peck field this year and all those will be operated by St. Mary.

Okay, thank you very much, Tony.

Nicholas Pope, JPMorgan.

Just trying to get just a little more clarification on the James Lime play.

Is it at 43,000 gross acres?

Can you say how much is in the Spider and Huxley fields?

Let's see, I don't know if I've got -- hold on just a second.

As far as Spider we've got about 13,000 net acres there -- gross acres, I'm sorry.

Total James Lime gross acreage is 50,000.

So is the 43,000 net?

That's net.

Oh, okay, I've got it.

And do you know what the Huxley is?

I don't have that number in front of me, Nick.

all right.

That was all I had.

Nick, it's about 4000 acres at Huxley.

Got it.

Thank you.

You bet.

Jack Aydin, KeyBanc.

Mark, we will miss you and good luck.

Thank you, Jack.

Most of my questions were answered, but how much room in terms of wells in the James Lime horizontal potential you have, how many wells potential?

Total for James Lime, we're showing 57 3P, kind of gross locations.

Okay.

You mentioned Elm Grove, but you haven't touched on Terryville.

I'm surprised because it looks like you've got some potential acreage there.

Could you shed a little more light on what you're doing in Terryville?

You bet.

One of the things we've been very impressed about is working with the operator at Terryville; we met with them a few weeks ago.

They shared with us that in 2006 from their drilling program at Terryville they took their total production from 1 million a day at the beginning of the year to a year-end rate of 55 million a day.

And we have been negotiating with the operator so that we can consolidate our acreage position and come up with a single development plan.

Those negotiations were completed late last year, so we are poised this year to proceed with that play to participate with the operator.

And we're pretty excited about the results they've had.

We believe our acreage is very much perspective.

It's centered in the field.

So they will be moving on to our acreage and beginning to drill this year.

We have in our plan five wells planned for the Terryville field and of course that could go up depending on their rate of drilling in the program, but we're very optimistic at this point.

How much acreage do you have in the play in Terryville?

Right now we've around 4000 gross acres.

Okay, thanks.

At this time there are no further questions.

We appreciate everyone calling in and, again, thanks for the questions.

And Mark, again, best of luck to you.

Thank you all.

Thank you very much for joining us.

This concludes today's conference.

You may now disconnect.