SM Energy Co (SM) 2009 Q3 法說會逐字稿

Good morning.

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

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

Mary Land & Exploration Company third quarter 2009 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 will now hand the floor to Mr Brent Collins, Director of Investor Relations.

Please go ahead, sir.

Thank you, la Tanya.

And good morning to all of you joining us by phone and online for St.

Mary Land & Exploration Company third quarter 2009 earnings conference call.

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

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

For discussion of these risks, you should refer to the information about forward-looking statements in our press releases from yesterday, the presentation posted to our web site for this call, and the risk factors section of our 2008 annual report on form 10-K, and subsequent quarterly reports filed on form 10-Q.

We will also discuss certain non-GAAP financial measures that we believe are useful on evaluating our performance, reconciliations of those measures to the most directly comparable GAAP measures, and other information about these non-GAAP metrics are described in our earnings press release from yesterday.

Additionally, we may use the terms, probable, possible, and 3P reserves and estimated ultimate recovery, or EUR, on this call.

We encourage you to read the cautionary language page of our presentation for discussion of special risks associated with these non-approved reserve metrics.

The Company officials on the call this morning are Tony Best, President and Chief Executive Officer, Jay Ottoson, Executive Vice President, and Chief Operating Officer, Wade Pursell Executive Vice President and Chief Financial Officer, and Brent Collins, Director of Investor Relations.

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

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

After a few brief remarks, I will turn the call over to Wade Pursell and Jay Ottoson for their respective financial and operational reviews.

As noted in our press releases yesterday, we have a presentation available on our web site that we will be referring to during the call this morning.

Let's begin with page three of our presentation, which I will use to address some of the highlights that I would like the listeners on the call to walk away with.

First, this was a very positive and important quarter for St.

Mary.

With respect to our quarterly results, we had a solid quarter and came in on target compared to our 2009 business plan.

Production was in the upper half of our guidance range and we were largely within or below our cost guidance for the quarter.

As you saw in yesterday's press release, we announced three new wells on our 100% Eagle Ford acreage with significant production rates.

We are picking up a second rig in Eagle Ford, which is the best indication we can give you about our views of the play.

In addition, there have been some positive developments in our Haynesville and Marcellus programs.

All of this activity is a result of our deliberate focus on testing our emerging resource plays that we committed to as a priority with our 2009 plans.

We took the view that it was more important to focus on growing the resource potential of the Company than to grow production in a weak, commodity-price environment.

We have been successful in implementing this plan.

We have expanded our inventory and we have done it while investing within cash flow.

We're in the middle of our 2010 planning cycle, so we won't have much to say on that today.

However, we are clearly well positioned with a strong balance sheet, and an improved and expanding project inventory, and we're excited about our growth prospects.

We will have a press release in mid-December that will outline our plans for 2010.

It is an exciting time for the Company and I'm really pleased by the way we have executed on our business plan this year.

With that, I will turn the all over to Wade to provide some color on our financial performance for the third quarter.

Wade?

Thanks, Tony.

Good morning.

I know everyone has a busy schedule this morning, so I will keep my comments brief.

I will start on slide five.

Production, 26.4 Bcf equivalent, is in the upper half of our guided range for the quarter.

On the cost side, LOE and production taxes were both below our guided range.

On LOE, we're frankly conservatives in our estimates of how much operating costs have declined from the slowdown in industry activity earlier this year.

And production taxes are primarily a function of commodity prices and we also benefited in tax credit rebate programs designed to encourage (Inaudible) billing in certain jurisdictions.

G&A was actually above our guided range for a couple of reasons.

Firstly, compensation related items, specifically, higher-than-anticipated payments from the Legacy program and CP program, that was due primarily to higher oil prices and lower LOE than we had forecasted.

Additionally, during the third quarter, we decreased the percentage of compensation that is allocated to exploration-based on a review of various job duties and functions.

On a net basis there is no impact to the P&L from this change.

Basically, less exploration to the entire G&A but it did contribute to our miss on this part of the guidance.

Finally, transportation and DD&A were both within our guided range.

I will make a couple of comments on two non-cash items that we recognized this quarter.

During the quarter we recognized a loss on the divestiture activities of $11.3 million.

Of this, $9.8 million related to our Atlantic Rim, CBM properties and our Rocky Mountain region.

These properties were part of the Rockies natural gas package that we marked earlier this year.

We did not receive acceptable bids for these particular properties and recharacterized them to assets held for use.

As part of this re-characterization the assets were impaired and the accounting guidance did take the related impairment charge.

It should be recorded in the same line as gains and losses from divestiture activities.

We also had a small impairment of undeveloped properties related to lease explanations on non-core acreage in Mid-continent and ArkLaTex regions.

So adding all of this up, the reported net loss was $4.4 million for the quarter, or $0.07 per diluted share.

And that was due mainly to the non-cash items that I just spoke about.

Adjusted net income for the quarter, which adjusts for unusual or significant non-reoccurring and non-cash items, was $14.7 million, or $0.23 per diluted share.

And that's better than Wall Street expected.

We provided adjusted net income number because we believe it is the most directly comparable to the estimate that financial analysts calculated.

In terms of cash flow, cash flow from operating activities was $111.3 million.

And discretionary cash flow was $99.9 million.

Or $1.60 per diluted share.

This was also above First Call estimates.

Moving on to slide six, you see that the balance sheet is in solid shape.

Our debt to book cap ratio is down to 33%.

We have no debt maturities until 2012.

Turning to slide seven, you see a summary of our revolving credit facility.

Our cash flow has been a little bit stronger that we had forecasted and we have been able to pay down debt on the revolver.

You might remember that the outstanding balance at the end of the second quarter was $275 million, and it is now at the end of the third quarter, down to $235 million.

So at the end of the quarter, we have a little more than $440 million of availability under the credit facility.

That's the really dark blue box in the middle of the chart.

I should add that our following determination for the revolver went smoothly.

We requested that our borrowing base be maintained at $900 million and the bank unanimously affirmed that number.

As we look to 2010, we have a lot of dry powder available to us.

Turning to slide eight, which is my last slide, based on the revised guidance that we provided yesterday, we're about 46% hedged on our expected production for the last few months of 2009, and equivalent price of $9.04.

See, we also have a solid hedge position that covers a good portion of our PDP in 2010 and 2011 and we have begun layering in some hedges in 2012.

The details of our hedge positions are included in yesterday's' press release and will be also be included in our 10-Q, which will be filed later today.

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

Thank you, Wade.

As I begin, I would just like to say that the third quarter was one of those quarters that makes it really fun to be an operations person at St.

Mary.

This morning, I will provide an operations update and then comment briefly about our preliminary thoughts for 2010.

Starting on slide 10, I will talk first about the operating portion of our Eagle Ford position.

I should note that at St.

Mary it is our practice to give initial production volumes to you as metered sales rate, averaged over a period of time, because we think this data is more meaningful than instantaneous or one-day rate and pressure data.

Back in June, we announced the results from our first horizontal well in our 100% acreage block, the Briscoe G1-H.

That well is labeled as well number one on the yellow portion of the acreage position on the slide.

In that press release, we reported an average seven-day sales rate of 5.6 million cubic feet equivalent per day.

And last night's press release, we reported the results of the three new wells that we will talk about today, using a maximum seven-day sales rate average, slightly different methodology.

Using that methodology, the Briscoe G1-H had a maximum seven day sales rate average of 6.4 million cubic feet equivalent per day.

Our highest 30-day average rate with the Briscoe G1-H figured in the same manner was 4.1 million cubic feet equivalent per day.

The Galvan Ranch 1H, labeled as well number two on the slide, was spud in early June and was drilled to a vertical depth of approximately 8500 feet.

The well had an effective lateral of 5,005 feet, and was completed with a 17-stage hydraulic fracture completion.

The well had a maximum seven-day sales rate of 8.0 million cubic feet equivalent per day.

Our highest 30-day rate was 6.0 million cubic feet equivalent per day.

This well is the farthest south of any of the wells that we have drilled to date, and makes lean gas with no condensate yield.

The Briscoe Apache ranch 1H, which is to the north and is labeled well number three, spudded mid-July and was drilled to a vertical depth of approximately 7,900 feet.

The well had an effective lateral length of roughly 4,000 feet, and a 14-stage completion.

The well had a maximum seven-day sales rate of 7.1 million cubic feet equivalent per day, and has a richer gas stream of approximately 1200 BTU's per standard cubic feet with essentially no condensate.

The 30 day rate was 5.9 million cubic feet equivalent per day.

The Galvan Ranch 4H, well number four on the slide, spud in late August and was drilled to vertical depth of roughly 9100 feet.

The well had an effective lateral length of 5,000 feet and a 15-stage hydraulic fracture completion.

Unfortunately, our temporary sales infrastructure in this portions of field has constrained our sales rate on this well to seven million cubic feet equivalent per day.

Our seven-day average production on the well is therefore going to be seven million cubic feet equivalent per day, and although we're still a few days away from having a 30-day rate, we expect that rate to be approximately seven million a day as well.

So this is our highest rate well to date in the play.

Similar to the Galvan Ranch 1H well, the production from this well is lean with no condensate.

We are currently working on the completion of our fifth and sixth wells, the Briscoe G2H and the Briscoe B1H and we will be spudding our seventh and eighth wells, the Galvan Ranch 7H, and the Briscoe G3H on our 100% acreage shortly.

As indicated in my discussion of the well results, we have moved over time to a well design that utilizes a longer lateral and more completion stages.

Over time, we will be working on optimizing our completions and the cost of those and the cost of our drilling efforts.

For now, our costs for drilling and completing these longer laterals, and completing with more frac stages is in the $4.5 million to $5.5 million range, depending on depth.

We are very pleased with the average rates we're generating from our new well, and with our drilling performance to date.

Although the current commodity price environment is challenging for dry gas wells, our wells with significant liquid yields have very high margins and excellent economics.

And as a result, we have a lot of highly perspective drilling locations.

Currently, we have one operating rig, operated rig running on our 100%.

As Tony mentioned, we announced yesterday that we are adding another rig, and we expect it to arrive in the next few days.

We're looking forward to ramping up our development work, and testing some new areas on our extensive 100% lease-hold position.

Turning to the JV north of our 100% acreage, which is the area colored in blue on the slide, same area took over from TXCO as the drilling operator earlier this year and drilled and completed the remaining three earning wells in Phase II.

In the joint venture now, Anadarko takes over operation of the wells after they had been completed.

With Phase ll of the earn-in complete, Anadarko will now take over full operatorship of the JV acreage and we will be participating as a non-operating partner with them.

As we have said before, the wells in the JV have high liquid yields.

Given the limited infrastructure in the JV area for gas sales, it is taking some time to get the wells cleaned up after completion and get comparable sales data on them.

We have seen enough, however, to believe that the JV area has significant potential and we're looking forward to participating with Anadarko in a number of upcoming wells.

In general, we have a lot of optionality across the 225,000 net acres we control with the Eagle Ford.

There is a nice mix of product streams across our acreage and enough flexibility in our lease terms to allow us to test our acreage thoroughly and pursue an appropriately paced development program.

Moving to slide number 11, I will talk briefly about the Haynesville shale.

We have 40,000 net acres in east Texas, and the bulk of our acreage position is in a fairly contiguous 30,000 net acre block in the Shelby St.

Augustine County area.

Our first vertical Haynesville well in that critical area, the USA BL number one was drilled and completed in northern St.

Augustine County.

The well had a maximum seven day sales rate of 1.9 million cubic feet equivalent per day.

We think this would translate to an IP in the low double digits for a horizontal completion.

Recent horizontal wells drilled by some of our peers in the immediate area are very encouraging.

The wells announced by Cabot with Common and Southwestern last week, and Devon yesterday, as well as, Noble recently looked very good to us.

The combination of the results from our well, the data we're seeing from the logs and core we took, and the results of offsetting competitor wells gives us reason to feel very good about our acreage.

We're currently drilling a second vertical well, the Blackstone PB number one in southern Shelly County, Texas.

I should note that we have take an very patient approach to development of our Haynesville acreage.

We did not have significant expiring acreage in 2009.

And did not see a reason to drill a number of wells during the period of very low gas prices.

We have used this time to collect data from vertical tests and offset completions, and have participated in 3D shoots over most of our acreage.

We expect to have our 3D in house over the Shelby St.

Augustine area in the first quarter of 2010, and then we will start drilling.

Slide 12 is the one on the Marcellus shale.

As we noted in our press release, we are in the process of constructing our gathering lines to tie our first well into the sales pipeline.

We were delayed somewhat as a result of encountering a threatened species of snake between our first well location and the sales pipeline.

Something that we simply didn't expect and we had to go through the appropriate steps with the regulatory agencies.

Being in northern Pennsylvania also provides for some challenges with regard to the weather, which has had an impact on the pace of our construction.

So although, we don't have metered sales data to share with you today, I can tell that you we were encouraged enough by the initial flow-back from the wells to spend the money to hook the wells up to sales and get a long-term test.

We will hook up the well closest to the sales point first and then, plan to build additional infrastructure to the second well early in 2010.

In the Granite Wash, as illustrated on slide 13, we participated at about a 25% working interest in an Apache well that they press released last week, the Hostetter 123-H on the eastern side of our acreage position.

The rates they announced at 17 million cubic feet per day at 800 barrels of oil a day are very stout and we believe the maximum seven-day rate was actually even higher than that.

We think this well is indicative of the potential that we have in a number of locations on our acreage.

We plan to move one of the rigs that we have been running in our Deep Springer program in central Oklahoma to our operated Mayfield area on the western side of our acreage position by year-end.

This is near the area where a new field and forest had been active recently and has potential in a number of exciting stacked pays.

Slide 14 provides an update of several of our other resource plays and our divestiture efforts.

First in the Woodford shale, we have no operated rigs currently running in the play.

We recently finished the drilling of of the last well in a simile frac pilot to test 64 acre well spacing or ten wells per session in the Woodford.

Our acreage position is largely held by production and we don't have to be drilling right now, given where commodity prices stand.

We will continue to watch prices and monitor costs.

With the knowledge we're gaining from the down spacing of simile frac work we're doing, we feel we will be in a very solid position to ramp our activity level up quickly when the time is more appropriate.

St Mary picked up an operated drilling rig in the Williston Basin in September.

The Company plans to test the Barden area southwest of the Vanessa incline in eastern McKenzie county in North Dakota for both the Bakken/Three Forks Sanish formations.

We also plan to test our acreage in Divide County for the Three Forks.

Two operated rigs are currently operated at Sweetie Peck in the Wolfberry tight oil play which is up from zero rigs earlier this year.

We are also drilling 40-acre wells and intend to do 20-acre down staging tests early in 2010.

With respect to the divestitures, we are currently marketing a package of non-core Rocky Mountains oil properties in Wyoming and North Dakota.

Mostly in Wyoming.

These assets will be monetized to help fund the continued testing and development of the Company's strategic resource plays.

The properties have current production of roughly 3,000 barrels of oil per day, and the marketing firm has estimated crude reserves for the package to be approximately 20 million barrels, which is 93% oil.

We think this is a very attractive set of properties and will be a great set of assets for someone, and the sale provides us with additional cash to invest in our key plays.

We're confident that there will be a significant amount of interest in the package, and we're thinking that we could potentially get a deal closed sometime early in the first quarter of 2010.

While we're on the topic of divestitures, we are working with a potential buyer on the sale of our Hanging Woman Basin CBM assets.

We're currently working that deal and really can't say anything more about it until it closes.

As Tony mentioned, we're in the middle of our planning process for 2010.

I can tell that you, we believe, we are at a sweet spot in the capital cost cycle, and have an increasing number of good opportunities to drill.

Given where oil and gas prices are in early 2010, I think you can expect us to focus on the parts of our portfolio that are oily or have higher liquid yields, areas like the Wolfberry and Bakken for oil and parts of the Eagle Ford and Granite Wash for richer gas and NGLs.

Our inventory continues to improve and we have a very strong balance sheet.

So with continued success in our key plays, you will see us ramp up activity.

With that, I will turn it back to Tony.

Thanks, Jay.

To reiterate what I mentioned before, this was really a very good quarter for the Company.

We are executing well in our 2009 program and are busy planning for 2010 and will be updating the market on that in mid-December.

Our employee, many of whom are listening this morning, are doing a great job.

And I think the investment community is beginning to take notice of these significant transformations taking place at St Mary.

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

Thank you.

(Operator Instructions).

Your first question comes from the line of Scott Hanold with RBC Capital Markets.

Good morning, guys.

Good morning, Scott.

Good morning.

In the Eagle Ford, some pretty nice results there.

Can you just give us a quick kind of refresh on sort of what you know now as part of the content of the production in the Eagle Ford, the drivers, the wet gas, and where you think that line is?

And when you look going ahead, it looks like you are focusing more on liquid part of your 100% acreage, is that correct?

Well, on the first comment, I think it is generally, you can look at properly Petro Hawk's statements about that, probably as good as any in terms of a map of how they view.

I don't think we see it any differently.

In terms of the second question, I think the -- generally, yes, we're looking at doing a lot of work in that kind of intermediate area where we have ridge gas.

We will be drilling some wells on the south end to prove up the size of the play there so we can design our infrastructure.

But generally, I think over the next six to 12 months we will focus a lot of attention in the areas where we have highest margins which are going to be in the higher liquid yield portions of the play.

And then on your zero, 100% working interest acreage, can you talk a little bit about any kind of infrastructure constraints in both the wet and the dry gas areas that would be something to think about in terms of when we look at how much you can actually grow production here?

I think in the short term, we can probably get 50 million a day out of there, probably by the end of the second quarter next year.

So I don't think there is any real short-term issues.

Longer-term, on the southern end in particular, we are going to have to bring in a pretty big inch pipeline in order to get a lot of gas out there.

So again, that is the reason for drilling some wells in the dry gas area.

There really isn't a lot of close bigger inch pipelines there.

The other thing, to think about is we're trucking all the oil out of here.

So oil pipelines are another issue.

So there are going to be some substantial infrastructure investments, not only on the oil and gas side, but on the water side as well.

To try to move water around the field to frac these wells.

That's a big cost to us that we will have to make.

But I think they're all manageable within a reasonable pace of development.

So would you actually invest some of your own capital, build out some of that initial infrastructure, and I assume that's not included in the $4.5 to $5.5 million well costs?

Whether we invest or not kind of depends on how we see the rates of return for those types of investments.

Obviously, there is a lot of different ways to do that.

We would certainly be willing to do that if that is what it took to get what we thought was a good deal.

We certainly have the capacity to do it.

In general ,we would always prefer to let pipeline companies build pipeline, and we focus on our business, but we can certainly do it if we need to.

I think, in terms of those costs that I am quoting on well, those do include the costs of typical flow line insulation, those kinds of things but not cost of large diameter pipelines.

One last quick question on the Blackstone PV number one.

In the Haynesville.

Is that going to be a horizontal well?

Or is that going to be a vertical?

It is a vertical well.

We are actually completing it such a fashion that we can take it horizontal at some point in it the future.

But we plan on just drilling it vertical at this point.

Okay.

Appreciate it.

Thanks.

Thank you.

Your next question comes from the line of Derrick Whittfield with Canaccord Adams.

Good morning, guys.

Good morning, Derrick.

I understand you have not set 2010 guidance yet, but could you guys possibly shed some light on anticipated rig count growth as we enter 2010?

We really haven't got to that level of detail.

We're right in the midst of our 2010 planning right now, Derrick.

But I can say directionally, we're going to be looking at adding some rigs, as we've already talked about.

But we haven't set a specific number.

And I think, obviously, that is going to depend on the commodity price environment, especially for gas, in terms of what we see there, but we have plenty of very strong oil projects, which we will be focused on.

And as we mentioned in our press release, as we are adding rigs in a couple of places already.

Got it.

And just on the JV acreage there, any chance you guys could offer any color on your discussions with Anadarko and sort of how that is progressing and I know you guys have Phase III left on the table still, but that was an area you guys were encouraged by I think earlier in your comments.

Yes, this is Jay again.

We have a great relationship with Anadarko.

And we're having periodic technical meetings with them to talk about what we're doing on our side of the play, and the work we've done and the work they're doing.

And I think what you're going to see over time is a real convergence of our technical effort on the kinds of wells we want to drill, and the kinds of fracs we're going to do.

We're going to learn a lot from each other.

So I think it is a very, very positive and constructive relationship.

In terms of -- we're going to let Anadarko talk about their part of the play more, more in the future, since they're the operator.

But in general, I think it looks good.

I think our activity levels in the JV will be pretty high next year.

We have quite a bit of acreage we have to hold there.

So we will be drilling a number of wells.

Thanks.

Just two more quick questions.

On the Haynesville, your first horizontal well, it is probably going to be second quarter, 2010?

Our current schedule is to spud it in March.

And in the Permian Basin, you guys mentioned 20-acre test pilots.

If I recall, you guys had quite a bit of inventory still left on 40 and 80-acre spacing.

About how much do you have?

It is hundreds of wells, hundreds of locations.

I think that the thought process on 20 is that we believe if you're going drill 20, you would like to know about it early on because the economics of these wells is really driven by the initial rates you make.

Just like any other play, any of these resource plays, the economics are all driven by the first 18 months to 24 months production.

So if you are going to make a decision to go to 20, we would like to make that decision relatively early on, so we can drill the wells before the field is completed, before you see any completion.

It just improves the economics.

So we do have a number of additional 40s out there but I think what you will probably see is we will be drilling 40s, 20s, 80s, all at the same time.

The current number of drilling locations, total 3D count is about 175.

156 of those are 40-acre locations.

That's a gross number.

And net is close to the same.

And that's just our Sweetie Peck area.

We also have another area that is non-op, Calbease, which is about 85 locations.

So there are a number of locations out there.

And certainly, with costs where they are right now, on the drilling side, this is a great time to be drilling oily projects.

Thanks for the color there, guys.

All right.

Thank you.

Thank you.

Your next question comes from the line of Welles Fitzpatrick with Johnson Rice.

Good morning, gentlemen.

Good morning, Welles.

What are the Company's working interests in the Mayfield operated area of the Granite Wash?

It varies quite a bit.

We have a lot of non-op.

On our operated stuff, it will go up to 60%.

But average is probably in the 30s.

30s to 40s.

Isn't that right, Brent?

I think that may be more across -- that is probably more across the whole -- Mayfield is -- of that 31,000 net acres, about 17,000 of that is operated.

The majority of that is in Mayfield.

So I think our working interest is higher and we operate over in the Mayfield area, and we're in a non-op position, if you look, as you go farther west, I believe, into that area where we drilled the wells down at Apache.

It is also where Chesapeake operates a lot, and we participate with them.

So I would say we operate more as you go west.

Okay.

But above 50 would be a good number to use on that operated acreage there?

That's right.

And we will check that.

I don't have my sheet in front of me.

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

Okay.

Great.

And I assume that you all are concentrating on the B zone, like the other operators in the area, is that correct?

I'm not sure what, when you refer to B, what that really means.

There are a number of washes there, yes.

We have the same -- if you look at our logs and you lay them up against the logs from say Styles ranch, the logs look almost identical and we're chasing the same targets that they're chasing over on the Texas side.

Okay.

Great.

And just to be clear, that 4.5 to 5.5 million, that assume Galvan Ranch 1H type completion, 5,000-foot lateral and around 17 stages?

Right.

Okay.

Great.

That's all I got.

Thanks so much, guys.

Thank you.

Thank you.

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

Good morning.

Just curious on one point.

I guess the decision to not have a Woodford rig active and to add a second one to the Eagle Ford, I imagine there is a number of reasons for it, but can you sort of prioritize?

I mean does it begin with just through the delineation of your potential there?

Or is it more that you want the liquids, or is it an expression of what you think the economics are between the two plays?

Well, this is Jay again.

I guess I will tackle that one.

I think generally, it is an indication that the liquid yields in the yieldford make the economics significantly better than any dry gas play that we're involved in.

I think you can just about double your margins at the current oil and gas prices by drilling the high liquid yield assets.

So if you say that the rates are the same, you get twice the margin, then you're going to go where the liquid yields are higher.

That's just the economics of it.

Subash, I think another priority though is delineation, especially in the Eagle Ford area with the significant acreage position we've got, certainly we've got more testing to do to fully delineate that.

So it is a combination of priorities, both delineation in some of these key plays, as well as, a focus on the liquid as, Jay mentioned.

Good point.

And I think, Woodford, I just know, we only need to drill, I think, eight wells in the next two years to hold our acreage.

So no pressure from a leasehold standpoint on the Woodford.

And 4.5 to 5.5, is that what you achieved to date?

Yes.

Okay.

Got you.

And I know 2010, we will have to wait for the December update, but if you were to characterize your 2010 development at this point, it is -- I mean what's your conviction level of the Eagle Ford being some of that program, and the development stage, versus strictly a delineation program?

I think clearly we're focused on continued results from our testing program there, but we're very encouraged where we are today.

If we continue to see good results, we're certainly prepared to ramp up that activity based on results.

We've got a lot of dry powder.

As Wade talked about earlier, a very strong balance sheet.

We intend to utilize that dry powder where it makes sense and where we see success in these emerging plays.

Let me tackle that question from just a little different angle.

And one of the questions, I think with the portfolio like ours, is we have so many good opportunities but a lot of them have some delineation risk associated with them.

Clearly, we want to find some areas like the Eagle Ford, like the central portion of the Eagle Ford, where we can just put a rig in there and go to development.

And start developing wells on a consistent basis and really work on the cost side, and work on just the lower risk development.

That is something we're looking to build in our 2010 program, is to put in -- to build a stronger development aspect to the program.

So you will see us focusing quite a bit on that.

All right.

And I guess where I was going with that, is there is a bit more emphasis maybe shift to, rather than resource assessment or resource captured, is a shift to actual production growth in 2010.

Well, I think that is what we're talking about right now in our budget process.

We still have a lot of proving up to do in the Haynesville, and in the Marcellus and other places that we need to do and we're going to do.

But we clearly also need to make that shift toward more of a development program and the Eagle Ford, I think, is an area where we have a lot of potential to do that and certainly, where we will be focused on doing it.

So a large portion of our spend in that area will be pushing toward lower risk, continuous development type drilling.

I think a couple of good examples there would be both the Wolfberry and the Woodford Shale program, where a couple of years ago we were pretty much in the testing phase and still determining down spacing opportunities.

And now those programs have been clearly in the development stage.

And one final one for me.

So you have I think in the Bakken, have you rigs active, any sort of schedule for when you might be able to share results?

Well, we have one rig running.

We drilled a well.

We have been sitting on that well until we had another well drilled and because we are going to simile frac the two together.

So I think it will be a little while.

I think we are continuing to drill.

I am sure we will have some results by year end to talk about.

It is a single-rig program.

I think they're going to be pretty -- I think they're going to be pretty cut and dried results.

But I think we will have something by year end, we will be releasing.

Great.

I think it is important to note too that we're still leasing in the area.

So I mean it is still a very competitive situation.

But we will see how the current well tests go and then release information accordingly.

Understood.

Thank you.

Thanks.

Thank you your next question comes from the line of Ellen Hannan with Weeden and Company.

Good morning.

Good morning, Ellen.

Tony, just a bigger picture question for you.

At the beginning of the year, the world looked a little different, and you were pretty committed to keeping your capital within your cash flow.

Certainly commodity prices are much better today.

You've increased your capital program for this year about 30%.

How do you think about that comfort level or that desire to just spend within cash flow and also, how do you balance that with the desire, assuming you have the desire, to begin to grow your volumes going into 2010?

I think that is a very timely question, Ellen.

First of all, going into the recession, where we were a year ago, clearly, we wanted to manage our capital spend within cash flow.

We have done that.

At the same time, as we've seen opportunities near term, we've taken the advantage of those new opportunities, and have increased our capital spend.

As I think about going into next year, the inventory continues to expand.

We're excited about some of these new emerging plays.

And we are not the least bit reluctant to utilize some of that dry powder.

So I think going forward, and again, obviously, depending on the economy, and commodity prices, we're certainly focused on long-term growth for St.

Mary.

And we're looking for opportunities to leverage that strong balance sheet where we can.

So, I think, what you're going to see going forward from us is both an ability, as well as, a strong intent to ramp up our activities in these successful plays.

And we've got the balance sheet to help us do that.

Great.

Thanks very helpful.

Thanks.

And just one other question, shifting over to the Marcellus, the acreage that you have, curious as to what drew you to that portion, the particular area of the Marcellus?

Have you entertained any leasing up in the state of New York?

I will mention a couple of things.

And then Jay may jump in there.

But that's an area where we spent over a year, Ellen, looking for an appropriate entry point.

A lot of activity in southwest Pennsylvania, as well as northeast Pennsylvania.

If you look at the Marcellus trend, we kind of have an entry point in between both of those high activity areas, and that was deliberate, because we could get in, in a reasonable manner in terms of lease costs.

We were also able to select what we think is a very compelling partner in the play, South Jersey.

Which had infrastructure, more contiguous acreage, and those were the elements that really focused our entry point in north central Pennsylvania.

Jay?

I think you covered it really well.

We had a handful of really important parameters that we were looking for, first and foremost, of course, was geological.

But also, the partnering angle, the ability to be near infrastructure, we're very close to a major sales pipeline.

We were looking for a large contiguous block of acreage, which is difficult to find in central Pennsylvania.

And we had a couple of our items that we were looking for some -- somebody on the ground who could help us market gas, a number of things like that.

And this particular area hit all of those boxes.

And we made a very deliberate entry in that way, and frankly, I think so far, we're very encouraged by what we have seen.

And the issue then now becomes okay, how do we build a position, and that gets more difficult.

Acreage is pretty scattered.

Acreage has gotten much more expensive.

But we're certainly trying to see where we can go with our position in Pennsylvania.

With respect to New York, you asked the question, if we have one of our criteria going in was that we would not buy acreage in New York.

We looked at -- I've been to several talks given by regulators from the state of New York.

I looked at the rules in the state of New York and the evolution of the rules in terms of fracturing and horizontal drilling, and I think it is pretty obvious that it is just not a very friendly place to do business.

And we initially essentially ruled out New York as an entry point.

Now, over time, that could change.

But I think we made the right choice at the time we made it.

Great.

That's it for me.

Thanks very much.

Thanks, Ellen.

Thank you.

Your next question comes from the line of Mike Scialla with Thomas Weisel Partners.

Good morning, guys.

Good morning, Mike.

Mike.

A question on the Bakken, those first two wells, you talked about the simul-fracs , are those actual Bakken, middle Bakken wells or is that the Three

One of them is in the Three Forks and one of them is in Bakken.

So we will simul-frac Bakken and a Three Forks well at the same time and see what happens.

Can you talk about the spacing between the two and what kind of lateral lengths you're using there?

They're the long 1280 laterals.

They are basically almost on top of each other.

So that is the -- the idea here is to try to understand whether you can make, with simul-fracing , whether you can make a better -- two better wells, versus two independent wells in the

And then do you plan to get another rig for the Divide County well or are you going to move that rig over there, or are you going to hang on the one in the one?

One rig program for now.

So we will be moving up after we finish here.

Okay.

And then on the Eagle Ford, can you talk about -- I know it is early days, but what you think the EUR might be for those four wells right now?

We're not going to speculate on EURs.

It is just way too early.

I hate -- I don't like to give numbers this early.

And the other thing about them, of course, is if you look at it from the standpoint of booking, versus expected, there can be big differences there, too.

What we're expected to do is to book P1, that is much more likely to be exceeded than underrun over time.

So I think, what you can expect is there will be a significant difference between our expectations potentially and what we will actually book, but other than, that we really can't comment on absolutely numbers at this point.

Okay.

And then the Marcellus, can you talk about what you saw with those first two wells?

I know you haven't tested them yet.

But in terms of the drilling, any issues with faults or pretty much what you were expecting going in?

The drilling went very well.

And the frac work went well.

And we're very satisfied with our vendor community there.

We did micro seismic on the wells when we did it.

We learned a lot.

Very relatively low cost to do that.

And I think we learned a lot from doing it.

And the whole process went very, very well.

Very pleased with our relationships there with the regulatory agencies and the people we work with day to day.

And we don't have anything to talk about in terms of rates.

Hopefully, once we get some actual metered production, we will be able to do that.

What's the timing on that, do you think, in terms of getting sales line hooked up?

Well, it will be over the next few months.

We will see.

I'm not sure how much data we will release, but we will talk about that some more.

Mike, we're still leasing in the area, too, but as we mentioned, I think in the press release, and some of our comment, we have certainly been encouraged enough to invest in some gathering infrastructure.

So to get us to sales.

So we are anxious to see the results of that.

But we're certainly very encouraged at this point.

Good.

Okay.

Last one for me.

Just any comment you can make on the divestiture package right now?

It sounds like you've opened the data room.

Can you give us any idea of the level of interest there and what kind of date do you hope to have bids by?

Well, we have a lot of interest.

Very strong interest.

Tons of CA's signed.

We already got 13 or 14 or 15, the last day, I think, a couple of weeks ago, we had 13 people signed up for the data room already.

And a lot of interest in the data.

And I think there will be a lot of interest in the package.

It is a very good package of assets.

There is some really interesting EUR potential in it.

It doesn't necessarily fit with our resource strategy but it certainly fits with a lot of other people and we think it is is a good package.

We're hoping to get bids in December and close in the first quarter.

That is an aggressive schedule.

But we think that the first quarter type close is a reasonable expectation.

And Mike, this is Tony.

The key with the package to me is it is a great timing to put that in the market, and at the same time, it also allows us to increase our focus on our new resource plays.

And also provide funding for the continuation and investment in those plays.

So for all of those reasons, we think it is great timing to put this on the market.

Sounds good.

Thank you.

All right.

Thanks, Mike.

Thank you.

Your next question comes from the line of David Tameron with Wells Fargo.

Good morning.

Good morning, Dave.

What's the current production from the Hanging Woman Basin?

I think it is around 10 or 11 million a day, something like that.

I think it is 9.5.

Nine?

Okay.

Couple more.

Any comments on the Petro Hawks Swift JV announced yesterday?

yesterday?

Not from us.

No, we kind of read that and it seems to make sense from their perspective.

Kind of interesting, the fact that they're joining us.

But --

3,000 acres is I think what it --

And that's where I was going.

So 3,000-acre, and what are other acreage costs going for right mow?

I won't get you in too much trouble but what other acreage?

Dave, we're not going to go there.

We're leasing and we're not going to talk about where we're going, why we're doing it or what we're paying.

But it obviously varies across the plain.

It depends whether you're far up to the northeast or down where we are.

It is pretty wide range.

So we won't venture any further with that.

I would say that I think Petro Hawk's statements and Swift, they think that is a very complimentary area to Petro Hawk's existing area, which they're obviously, very, very high on, and would expect that the acreage costs would be high.

That's all I will say.

Okay.

I understand.

Let me go back to the boring assets that provide all the cash flow for the resource plays.

If I look at the Mid-Continent, roughly 30% of your overall production is coming, or maybe it is a little higher than that, coming from that region.

What are the main fields making up that total?

The Mid-Continent volumes?

Well, the Woodford, obviously, generates a lot of volume.

Our Deep Broxton area and the Deep Springer is a significant volume.

Constitution field, which is in Texas, which we managed through our Mid-Continent office is a very large producer.

And of course that whole Mayfield, western Oklahoma area, generates quite a bit of volume.

And then the same question, Jay, in the Rockies, which the other big regional chunk.

The Rockies is probably largely Bakken.

If you look at the volumes there, there is a significant amount, as this package we're selling will essentially sell us out of most of the oil we have in Wyoming.

Okay.

So we're very -- we're becoming more and more focused on the Williston Basin, which is deliberate.

And so generally, I don't know the exact percentages but it is going to be a largely, very dominant by the Williston, once this package is sold.

Okay.

So as you make this -- what I'm trying to figure out, as you make this transition to move more of the resource -- or more capital being allocated to the resource plays, what is your current underlying decline rate?

How has that been holding up, et cetera?

That is about 25%.

And it has been about that for the last couple of years.

It hasn't changed a lot.

I think the angle you're going to here, I think if you sell a lot of Rockies properties that are way out on the decline curve, they have very low decline rates.

Yes.

So you would think over time that that number would go up.

But then you have to factor in the fact that we have a number of Woodford wells that are pretty far, getting farther out on their decline curve as well.

So over time, I think if you think about us in terms of that 25% to 27% kind of decline rate, that is probably a reasonable number.

Okay.

One more question.

I think, Tony, in the past, you said it is like picking your favorite kids, but of the plays you have right now, can you give me the top four and rank them in order?

Rank them in order?

You want me to line my kids up and then -- okay.

Let me tell you the plays that obviously we're focused on, we're excited about, and those are the emerging plays.

And not in any particular order, but clearly the Eagle Ford right now, getting a lot of traction, we're very pleased with the initial results.

We got a lot of testing to do, and a lot of running room.

So we're really excited about that particular play.

The Marcellus is a new basin entry for us.

We are very encouraged with the initial couple of wells.

You know, we've got a lot of work to do there yet.

But it is a very intriguing and exciting at this point.

We continue to see success.

The Haynesville, great position.

We're pleased to see a lot of the offset success that some of our competitors are having.

We've got some key tests in front of us there but I think we're very well positioned.

The Wolfberry is the gift that keeps on giving.

We have gone from 80 to 40 to 20-acre down spacing.

The Bakken, we've continued to grow our position there, in the Rockies.

So I think, we've got considerable running room there and then you've got kind of the latest buzz, and that's the Granite Wash.

And here we are situated in the Mayfield area, right in the midst of that play, and all of that acreage for the most part is HBP.

So that is pretty exciting.

And we're going to be moving a rig into that play and doing some St.

Mary operated tests there.

So I mean, I just look at where we are today, Dave, and we've got so many options, and we are really increasing our focus on these resource plays.

But it is going to be an exciting time for St.

Mary going forward.

And I think, we've got the dry powder and the balance sheet to promote and really grow this Company.

All right.

But you wouldn't want to rank them for me?

No.

Okay.

Can't blame me for trying.

I just shared all my kids with you.

And there are some others that we haven't talked about due to a lack of time but there are a number of exciting plays in front of us.

Congrats on the wells in Eagle Ford.

Thanks, Dave.

Take care.

Thank you.

(Operator Instructions).

Your next question comes from the line of Joe Allman with JPMorgan.

Thank you.

Good morning, everybody.

Good morning, Joe.

Just a couple of questions on infrastructure.

I think, Jay, early on, you said in the Eagle Ford, you have 50 million a day of take away capacity.

Could you talk about that a little bit further?

One of the wells that you released in yesterday's OPS update, you indicated you had some pipeline constraints.

And so just talk about what your gross production is at this point in the Eagle Ford and how that compares to the take away, where the constraints are, and where you expect production to grow, and especially relative to the infrastructure.

Well, let me just reiterate what I said earlier.

I believe what I said is, we would have about 50 million a day by the end of the second quarter of next year.

At this point, on the southern end, we are pretty limited in what we can produce.

We have a temporary sales connection, and we're only -- we're limited to about 10 million a day or something like that total out of the southern end.

We are building a trunk line that gets us to a better sales point.

And we should be able to probably get 20 or 30 million a day out of there by end of second quarter.

And the central area, we will probably have -- I think by that same time period, we will have about 30 million a day.

So in total by the end of the second quarter next year, we should be able to handle about 50.

I don't think we will be at 50 by that point yet, but that's about what we would be able to do.

We have a long-term relationship with Regency and the central part of our acreage and we're working closely with them on infrastructure issues, I don't think over the long haul, we think that is going to work fine.

On the southern end, we are going to have to bring in someone to get with a fairly large diameter pipeline, get that gas out of there.

And that's a fairly long-term commitment.

We need to drill some more wells to make sure we understand what we've got there.

We will either have to dedicate acreage or dedicate volumes or pay for something to get that done.

And that's probably once you make that decision, eight to 12 months before you really have a big line in there to do that but again, that is dry gas, we're focusing more on the central part of the play in the near term.

But I think if you look out over the next month, next year, we are going to have capacity, as we need it.

We did run into a small problem with the temporary line we've laid for this testing of this well.

But it is nothing that is going to be a long-term problem for us.

Joe, as you would expect, we have been in discussions with a number of pipeline companies, again focused on our long-term plans and our intent would be to have the infrastructure in place as we continue to have success and ramp up production.

So we want to try to time that so that it matches the production at any given time.

Is the infrastructure in the Eagle Ford slowing you down as to otherwise what you would do if you had the infrastructure in place already?

No, not at.

I think it is costing us a little more than we expected in some cases the.

But just to get the testing done, you try to step out and that stepping out costs you a little more money.

And for example, hauling water.

We spent more money than we expected on some of the wells.

But I think we're working on a pace that is consistent with our plan to test the acreage.

We have not been slowed down by our infrastructure.

We don't expect to be slowed down by our infrastructure.

We are going to make our choices based on what we think is the best thing from a return on capital employed standpoint and I can't see anything in the infrastructure that would stop us from doing this.

Can you talk about the infrastructure to handle the condensate?

I think you said that you're trucking everything now.

That is another issue, long term.

There are parts of the play right now.

We are all trucking these barrels out to another location.

We talked to several pipeline companies about, well, if we are going to lie a pipeline, why don't we lay a low line in the same trench.

I think, that is likely to happen, especially on the northern end of the play.

I will tell you, Anadarko, we are in conversations with Anadarko about these same things.

They're talking to people as well.

There is a lot of incentive for a lot of people to try to get in this gathering business both on the oil and gas side.

And we think those problems will get solved.

That's helpful.

And when you talked about the reasons why you bought where you did in the Marcellus, one of the reasons was infrastructure.

Could you address the same issues in the Marcellus?

Well, the Marcellus, you know, literally bought this contiguous, the first block we bought is just south of eastern decline up there, and it is just a few miles away to a sale point.

And we already had the tap and we are laying the line.

So when we looked at that position, there are several major pipelines across right in that area, and our partner, who happens to be South Jersey, a utility company, they're the LDC in Atlantic city, helped us with that.

And they already had a tap, and they had relationships.

They already had some firm transportation on some of these pipes.

So that was one of the things we were looking for.

One of those five items I mentioned that we were ticking off, which is someone who could help us get in the infrastructure.

We didn't know much about Pennsylvania when we went there and that is something we felt we needed to have was a partner and some relationships and some nearby infrastructure to make that work.

So, so far, so good.

We haven't tested the wells long term yet.

We will see how that goes.

Thank you.

And then lastly, just with the Wolfberry, are you expecting, you've got two rigs in there now.

Would you expect to add more rigs in 2010?

And what are you looking at in terms of cost and EUR's in the Wolfberry these days?

Well, again, we are looking at our 2010 program and we will see how much we can stuff into that cash flow sock, I guess.

But we may go up in rig count.

Certainly, we expect our partners to be drilling additional wells in their corner operated stuff as well.

So we have a pretty significant amount of spend there already.

EUR's in the trend, we've always said there with about two-thirds of a BCF.

Now, as we get down into the 40s and 20s, that number is going to come down some.

We are probably 70% or 80% of that number.

Again, we focus -- everybody focuses so much on EURs on these plays and we understand the importance of that, but the reality of it is, it is the production in the first two years that drives the economics and these wells have pretty good -- very strong economic, even though the EURs are nothing that you would crow about.

They have very strong economics.

Joe, this is a very good program for us in terms of being able to throttle the pace of development there.

At one point in time, we had five rigs in the Sweetie Peck Field and we have been as low as zero.

So we can really pace that program based on market conditions and economics.

But very strong right now.

And what are the contemporary costs versus what they were a year ago?

Well, we're drilling these wells right now at $1.2 million.

At the peak last year they were $2.1 million a well.

Very help.

Thank you.

All right, thanks.

Thank you.

Your next question comes from the line of Irene Huff with Canaccord Adams.

Hello, everybody.

I think what you have here is just a tremendous set of opportunities.

You got a big plate ahead of you.

And have you been making the turn very deliberately.

And my question for you, is there any chance you would be able to accelerate some of your exploration processes and be able to book the reserves and sort of push on the gas pedal?

And you mentioned earlier that asset sale and debt capacity as such.

Would you entertain sort of a JV or other alternative ways of raising capital if you do head into a cash crunch?

I will let Wade weigh in on that Irene but generally speaking, we are ready to step on the gas pedal with success.

And we have the balance sheet and the dry powder to accommodate that.

I'll let Wade mention -

I would say all of those options are on the table.

As we go through the vesting process for OTN and look at the returns on the investments we have in front of us.

I mean credit markets are certainly open for more capacity.

If we decide to go that direction.

And I think the JV opportunity would be as well.

So I think all of those are possibilities.

Thanks.

Thanks, Irene.

Thank you.

At this time, there are no further questions.

Mr Best, I return the floor to you for closing remarks.

Thank you, operator.

And thanks to everyone for your interest in St.

Mary.

Please stay tuned.

We have many exciting prospects and growth opportunities in front of us and we will talk to you again next quarter.

Thank you very much.

Thank you for participating in today's St.

Mary Land & Exploration Company third quarter 2009 earnings call.

You may now disconnect.