雪佛龍 (CVX) 2010 Q1 法說會逐字稿

Good day, ladies and gentleman and welcome to the first quarter 2010 Atlas Energy, Incorporated earnings conference call.

My name is Regina.

I will be your operator for today.

Later we will be conducting a question-and-answer session.

(Operator Instructions)

As a reminder, today's conference is being recorded for replay purposes.

I would now like to turn the conference over to your host for today, Mr.

Brian Begley, Vice President of Investor Relations.

Mr.

Begley, you may proceed.

Thanks, and good morning everyone.

And thank you for joining us for today's call.

As we get started, I'd like to remind everyone of the following.

During this conference call, we make certain forward-looking statements and in this context, forward-looking statements often address our expected future business and financial performance and financial condition, and often contains words such as expects, anticipates, and similar words or phrases.

The forward-looking statements, by their nature, address matters that are uncertain and are subject to certain risks and uncertainties, which could cause actual results to differ materially from those projected in the forward-looking statements.

We discussed these risks in our quarterly report on Form 10-Q, which will be filed later today, and our annual report, also on Form 10-K, particularly in item 1.

I would also like to caution you not to place undue reliance on these forward-looking statements, which reflect management's analysis only as of the date hereof.

The Company undertakes no obligations to publicly update our forward-looking statement or to publicly release the results of any revisions to forward-looking statements that may be made to reflect events or circumstances after the date hereof or to reflect the occurrence of unanticipated events.

As we introduced several periods ago, we have provided several additional financial disclosures incorporated in our earnings release in order to segregate our E&P operations from our consolidated GAAP financial statements.

These consolidated income statements and balance sheets provided for all applicable periods separate Atlas Energy's core E&P operations from the financial results of Atlas Pipeline, whose results are required to be consolidated under GAAP and Atlas Energy's results due to our controlling interest in Atlas Pipeline.

Lastly, we also provide a reconciliation from net income to adjusted net income, adjusted EBITDA and discretionary cash flow for our E&P operations, as we believe that these non-GAAP measures offer the best means of evaluating the results of our business.

With that, I would like to turn the call over to our Chairman and Chief Executive Officer, Ed Cohen, for his remarks.

Thank you very much, Brian, and hello to all.

We really do have a lot to celebrate.

First, we'll be reporting today on the excellent, increasingly successful results from our horizontal Marcellus Shale drilling.

Then, of course, we're moving rapidly to implement and to expand the Marcellus joint venture, which we've just entered into and we entered into it at record breaking prices and on extremely desirable terms.

A transaction, by the way, which has generated virtually universal praise for us and for our joint venture partner, Reliance Industries.

We have already purchased a further 42,000 acres of strategic infill acreage on behalf of the Marcellus joint venture and we did that at an average price per acre only about one-third of the acreage value that we ourselves received in last month's $3 billion Reliance joint venture.

Now, as for results, we have now spud 42 horizontal Marcellus Shale wells in our core area of Southwestern Pennsylvania.

29 of these wells have been successfully drilled to total depth and cased.

The remaining 13 wells are in the process of being drilled.

Atlas has turned 17 of these horizontal wells into line.

Six wells in the wet gas area and 11 wells in the dry gas area.

A clear picture has now emerged.

Mature Atlas wells are now averaging actual production of 4.5 million cubic feet a day, some 70 days after initial production.

As a result, we've actually had to make upward revisions in our budgetary and planning projections to provide for average anticipated EURs of 6 billion cubic feet equivalent per well, and that's a sharp increase from our original estimates of 4 billion cubic feet equivalent.

Production declines have now proven significantly shallower than originally anticipated.

Accordingly, while we had ourselves conservatively anticipated average production during the first year of 1.35 million mcfs per horizontal Marcellus well, and to be sure some bolder analysts had projected as much as 1.6 million to 1.7 million mcfs per year, we have now had to adjust our expectations upward again to anticipated average production above 2 million mcfs during the first year of a well's full operation, approximately 50% higher than our original expectation.

This is all great news and I want to point out that we owe much to the impressive dedication and exceptional effort of scores of skilled Atlas employees.

These things just don't happen on their own.

Our continued success, however, depends first on our ability to overcome prevailing low market prices for natural gas, and secondly, on our ability to resolve the pipeline constraints that I discussed in our February call.

As for prices, we would, of course, prefer higher prices, but we can make a great return even at the present NYMEX strip pricing.

In summary, Atlas will generate a 51% annual internal rate of return based on today's results, at today's prices, and at today's costs, and that's even before the benefits of our joint venture.

As a result of the Reliance joint venture, however, for each future Marcellus horizontal well, we will pay only 15% of the total costs.

But, we will receive 60% of the revenues.

Now that's a real enhancement.

And what downside protection, as some analysts have pointed out.

Furthermore, hedging has helped us enormously in the past in dealing with volatile and sometimes deteriorating prices.

During the first quarter of 2010, for example, Atlas realized an average natural gas price of $7.61 per mcf.

And that compares to an average market price of $5.68.

Currently, I'm glad to report, we have an unrealized marked-to-market hedge gain of approximately $90 million.

Now, I reported in our February conference call that Atlas' production of natural gas had then been constrained by some 22 million cubic feet per day, that's gross, in the fourth quarter of 2009.

This constraint has increased during the first quarter of 2010, and as a result, Appalachian production for Atlas is up only about 7.5% in the first quarter of 2010 as against the corresponding period in 2009.

Here's the problem.

All of Atlas' natural gas production from the Marcellus Shale is currently delivered into a legacy gathering system that was originally designed to transport low pressure gas from vertical upper Devonian wells.

While this system has meter and compression capacity of over 200 million cubic feet per day, the Company's gross deliveries of approximately 115 million cubic feet per day are hydraulically constrained due primarily to the enormous pressures generated by blockbuster horizontal Marcellus wells producing within a relatively small area into the system's relatively small diameter pipe.

Horizontal Marcellus Shale wells with flowing pressure of 1500 pounds per square inch are inhibiting older, lower pressure wells from producing into the system.

In addition, a number of wells in our wet gas window have been shut in, awaiting processing plant improvements.

Solutions, however, are on the way.

Laurel Mountain Midstream, a joint venture between our subsidiary Atlas Pipeline Partners and the Williams Companies, is currently building a new gathering system, a so-called Header System, with larger diameter pipelines and larger compressor stations, and that's being built throughout the Company's core Marcellus Shale acreage in Southwestern Pennsylvania.

The Header System is scheduled to be completed by the end of the second quarter of 2011, but Laurel Mountain intends to make parts of the new Header System available to Atlas prior to the completion of the entire system.

Now, once in service, this new system will provide to Atlas an incremental 300 million cubic feet per day of new capacity, and it has the ability to scale up to over 1 billion cubic feet per day as the Company's production grows.

By the end of the second quarter of 2011, the Company expects its gross production in the Appalachian Basin to grow to over 200 million cubic feet per day with net production to Atlas' account of between 85 million and 95 million cubic feet per day.

In the meantime, Laurel Mountain is attempting to loop existing legacy lines in order to mitigate blockage and is adding compression in order to provide further immediate incremental capacity.

One such looping project will be completed before the end of this month of May 2010.

And in all, Laurel Mountain has allocated a minimum of $160 million this year alone for upgrading our system and building the new Header System.

We are also adjusting our well turn-in schedule in an effort to turn wells into line in areas where capacity exists or is expected to become available soon.

In short, I'm confident that we'll resolve this problem expeditiously.

No gas will be lost.

It will all be produced.

And let's look for the silver lining, perhaps into a market where price has improved in the interval.

Now, our other major area, Michigan, sometimes gets lost in the hoopla about the Marcellus.

But, Michigan itself is now titillating the world with its own exciting shale extravaganza.

Many of you are aware of this.

And Atlas is well positioned to participate.

In the last month alone, we have purchased an additional approximately 20,000 acres for our own account in the emerging Utica/Collingwood Shale play in Northwestern Michigan.

This brings our total Utica/Collingwood Shale holdings in Michigan to at least 115,000 gross acres, 70,000 net.

Now, we paid on average $300 an acre for the new purchases, which were effectuated between April 2 and May 2 of this year.

That's right, the last one was just five days ago.

And, bingo, another success.

Three days ago, on May 4, as many of you know, the state of Michigan held a public auction of Utica/Collingwood Shale acreage that, in the crazed enthusiasm of its energy professional bidders and in the elevated prices bid, resembled last year's state auctions of Marcellus acreage in Pennsylvania.

In Michigan on Tuesday, the state generated $178 million, more than seven times the previous record for any Michigan state energy auction, at an average price not of $300 per acre, that's the price we've been paying in the last month, but at average prices above $1500 an acre, and some as high as $5500 per acre.

As the Detroit Free Press reported on Wednesday, state officials were, the newspaper used the word "stunned" -- state officials were stunned by the high realized prices.

Now, according to the Free Press, the state is anticipating the entry into Michigan of "major oil companies," who will be seeking to exploit the Utica and other deep shale formations.

We are, as you may know, already Michigan's largest producer of natural gas, and accordingly, already hold by production 83% of our Utica/Collingwood Shale acreage.

We are in the process right now of intensively analyzing our considerable Michigan holdings, some 270,000 acres held by production, in order to identify, if possible, additional acreage with deeper shale potential.

We intend, of course, now to strongly accelerate our shale drilling and completions in Michigan and, fortunately, it seems, we are once again ahead of the wave, having bought acreage early at low prices.

We now prepare to welcome later entrants into an arena of feverish activity.

Matt Jones, our CFO, will address our much strengthened financial position shortly.

But first, our president, Rich Weber, will cover operations.

Rich?

Thank you, Ed.

During the first quarter, Atlas spud nine horizontal Marcellus Shale wells, four for the account of our direct investment programs, and five wells that will be for the account of our joint venture with Reliance.

We turned in the line seven wells during the quarter, two of which were for our direct investment programs, one for a 50/50 joint venture, and four for our own account.

As we indicated during our last earnings call, we have determined that landing our laterals low in the Marcellus Shale section is important to achieve maximum recoveries.

Of our last four horizontal wells turned into line during the first quarter, which were all landed low in the section, these wells had an average initial rate of production of 5.3 million cubic feet per day and are exhibiting the shallow declines that we have discussed in prior calls.

While satisfying, it is important to note that these results could have been even better if we had greater capacity available to us in the Laurel Mountain gathering system.

On some of these wells, we are holding back pressure of more than 1,500 pounds.

The other three wells turned into line during the quarter were landed high in the section and are generally exhibiting inclining production, but from an initial base rate of production of 1.5 million to 2 million cubic feet per day.

These were the last wells in our inventory of drilled wells that were drilled high in the Marcellus section.

We are quite pleased with the results we are seeing from our horizontal program.

Our original 4 Bcf type curve generates an internal rate of return of approximately 30% at today's strip prices.

However, our 6 Bcf type curve that is more consistent with our results over the last several months, generates a 51% internal rate of return at today's prices.

Of course, these returns are before the financial impact of the drilling carry associated with our joint venture with Reliance, which substantially increases our return on invested capital.

Our current fully loaded AFE for a 3,000-foot lateral with a 10-stage completion in our dry gas core area is approximately 4.2 million.

As we have mentioned in the past, we expect these AFEs to decline to the $3.8 million level as we transition to a 100% water recycle and increased pad drilling.

I think the bottom line is that we have proven beyond a doubt the potential of our resource base in the Marcellus Shale.

Through our JV with Reliance, we control over 345,000 blocked up net acres in the heart of the proven Marcellus Shale play, having over 3,600 horizontal locations using conservative spacing assumptions.

With Reliance's commitment to fund up to $2.8 billion of drilling costs in the Marcellus Shale over the next five and a half years, including 75% of our 60% of well costs up to $1.4 billion and their own proportionate share of well costs for their 40% of the joint venture, we are embarking on massive, but deliberate, ramp-up in our operations.

On behalf of the joint venture, we are on track to drill 45 horizontal Marcellus Shale wells in 2010, 108 wells in 2011, 171 wells in 2012, and 300 wells per year thereafter.

This development plan will have a dramatic effect on our net production, which we expect will top 500 million cubic feet per day net to our interest in five years and approach 1 Bcf per day in 10 years.

We have the acreage and the capital necessary to perform.

Now we need to execute.

As one of the early movers, I am certain Atlas has one of the leading technical and operating teams in the Marcellus Shale.

With over 200 employees dedicated to our Marcellus operations, most of our key personnel are in place.

In addition, we are aggressively recruiting talented and experienced individuals to round out our team.

Greg Muse, our new Senior Vice President of Marcellus Operations, has proven to be an excellent hire and is already making a significant impact.

Of course, as we have discussed many times in the past, we will need a world-class gathering system to move all of this gas to market.

As Ed indicated, Laurel Mountain Midstream Partners is making progress on the buildout of a large scale Header System in Southwestern Pennsylvania that will initially give Atlas 300 million cubic feet per day of incremental capacity by the summer of 2011 and is designed to scale up over 1 Bcf per day as our production increases.

In order to give us incremental capacity in 2010 before the final completion of phase one of the Header System, Laurel Mountain has been attempting to permit and construct various looping projects as well as make part of the new Header System available to us before final completion.

However, some of these projects are facing permitting issues involving routine studies of endangered species, which has the potential to push out planned capacity increases to later in 2010 than we had originally expected.

This said, final completion of the new Header System is on track for the first half of 2011.

We are victims of our own success.

These horizontal Marcellus Shale wells are coming on-line in excess of 5 million cubic feet per day at exceptionally high flowing pressures and are outstripping the hydraulic capacity of our legacy gathering system.

Gas production from these new wells is getting to the meter but pressuring off gas from older wells producing at lower pressures.

At the end of the first quarter, we estimate that approximately 30 million cubic feet per day of gross production, or approximately 10 million cubic feet per day of net production, was curtailed or delayed due to high pressures or the unavailability of system capacity.

Of course, this production and resulting revenue is not lost forever, but rather delayed until Laurel Mountain can expand its system.

Once the new Header System is complete, these production constraints will cease.

In the meantime, we are adjusting our drilling schedule to the extent possible to take advantage of areas on the system where some capacity does exist or where we expect looping projects will be constructed.

For the remainder of 2010, we are planning to turn into line seven horizontal wells in the second quarter, six in the third quarter, and 14 wells in the fourth quarter.

As a result, we are expecting to see increasing production through the remainder of 2010 and expect net production from the Appalachian Basin to average 85 million to 95 million cubic feet per day net by the end of the second quarter of 2011.

Or sooner, if Williams is able to unlock capacity on the Laurel Mountain gathering system.

Assuming we don't see meaningful capacity additions from Laurel Mountain in 2010, but believe me, we are pushing hard, we expect total Company production in the 39 Bcfe to 41 Bcfe range for this year.

As to horizontal rigs running, we currently have two and have plans to add a third in the fourth quarter of this year.

We intend to add our fourth rig in the second quarter of 2011 and our fifth and sixth rig in the third quarter of 2011.

Ultimately, we expect to have 15 horizontal rigs running.

Moving on to other shale plays, Ed mentioned our significant position in the new and exciting Utica/Collingwood play of Northwestern Michigan.

We believe this gas stream is rich with natural gas liquids and with high measured porosities in the Collingwood, which is a combination of limestone and shale, we expect strong NGL recoveries.

We intend to begin developing the Collingwood/Utica this year through our direct investment programs.

Back in Pennsylvania, we are very encouraged in what we see in the Burkett Shale, which is an Upper Devonian shale found just above the Tulle limestone.

We understand that range resources has drilled a horizontal test with good results.

We actually tested the Burkett four times with verticals wells and are very pleased with the results.

The Burkett is prospected on almost all of our acreage in Southwestern Pennsylvania at depths between 6,000 and 7,500 feet.

We are evaluating a horizontal test well later this year.

Other producers have also successfully tested with horizontal wells the Ordovician/Utica Shale in Southwest Pennsylvania and in Eastern New York.

The Utica is a black, organic-rich shale that is found at depths ranging from 6,500 to 14,000 feet on our acreage with thicknesses between 150 and 600 feet.

We view the Utica as highly prospective and are watching carefully the activities of other operators.

Lastly, we have begun marketing our $150 million spring program and expect to break escrow in the next few weeks.

This program will primarily fund development in the New Albany Shale, where we continue to achieve results that are consistent with the expectation of average initial daily production of 300,000 cubic feet per horizontal well.

Drilling and completion costs continue to average approximately $800,000 per well and we have plans to drill at least 100 wells this year for our programs.

To a lesser extent, our spring program will also fund Marcellus wells that were identified prior to our joint venture with Reliance.

And now to our Chief Financial Officer, Matt Jones.

Thanks, Rich.

I hope that all of our call participants have had an opportunity to review our press release where we laid out in some detail the particular numerical components of our results.

As Brian mentioned, we continue to provide consolidated and consolidating data so that results specifically related to our E&P operations are more easily deciphered.

For the quarter, we generated $69.1 million of adjusted EBITDA, with significant contributions from our oil and gas margin successfully enhanced with our hedging program and contributions from our partnership management segment.

I'll discuss certain components of our results in a moment.

But, today I'd like to address a couple of areas, beginning with our current capital position and the implication of certain capital commitments that others have made to our business.

Many of you may recall that our Company over a year ago highlighted the importance of reducing debt and enhancing liquidity.

As part of that effort, we were dedicated to the objective of funding our capital budget with internally generated cash.

At the same time, we placed high importance on the further development and expansion of our Marcellus position.

We succeeded on all fronts.

Compared to the quarter ended March 31, 2009, and inclusive of the recent closing of our joint venture with Marcellus Industries, we reduced total debt from $945 million to roughly $650 million.

We've increased availability under our revolver from approximately $110 million to nearly $500 million.

While funding capital investment largely with our cash flow over this period, we made important and strategic investments in our Marcellus position that greatly advanced our ability to develop this play and helped attract significant interest in our joint venture process that culminated in the closing of our transaction with Reliance.

Importantly, the closing of the Reliance transaction and the completion last year of our gathering agreement with Laurel Mountain, of course a joint venture between the Williams Companies and Atlas Pipeline Partners, allow us to greatly expedite the expansion of our Business, while substantially reducing our required capital investment.

As we mentioned in our press release, Reliance paid roughly $340 million at closing and committed to an additional $1.36 billion in the form of a drill and carry.

The result of this, during the drill and carry, Reliance will pay 85% of the drilling and completion costs of joint venture wells for a 40% interest, and Atlas will fund 15% of the costs for a 60% interest.

Gathering costs associated with the development of our Marcellus position will be funded by Laurel Mountain Midstream and we'll pay gathering fees based on our usage of the system.

Over the course of last year, our hedging strategy enabled us to greatly reduce downside volatility in the natural gas markets and gave us better clarity with respect to anticipated cash flows.

This enabled us to better estimate the amount of internally generated cash that we'd have available to fund our capital program.

In the first quarter of 2010, we again benefited from our hedge positions, which increased our realized natural gas price on hedged volumes to $7.80 compared to the average NYMEX price of roughly $5.60.

That's $2.20 of additional margin per mcf that we received during the quarter on 7.7 Bcf, or roughly 90% of our natural gas production.

We experienced the additional benefit in the quarter of a $20 million cash gain from the early settlement of natural gas hedge positions related to calendar years 2011 through 2013.

We simultaneously rehedged those positions and the hedge schedule in our press release is reflective of these actions.

Notwithstanding the $20 million cash gain realized on forward contracts during the quarter, and based on the forward price curve of a couple days ago, as Ed had mentioned, we estimate that we have roughly $90 million or more of unrealized marked-to-market hedged gains on our existing positions, as our hedge prices generally remain well above forward spot prices.

Moving to our partnership management segment, please recall that we recognized revenue as we invest our limited partner's capital in well drilling and completion activities.

We invested approximately $73 million on behalf of our drilling partners in the first quarter.

First quarter drilling activity was slowed to a degree by weather-related delays.

At the end of the first quarter we had about $49 million of drilling partners' funds remaining to deploy, which we believe will be largely utilized during the second quarter.

We've emphasized on past calls that our partnership segment margin generation is typically more heavily weighted to the back half of the calendar year.

Also, traditionally the second quarter of a calendar year tends to be our lightest quarter, as our winter funding program is primarily invested in the fourth and first quarters.

General and administrative expenses this quarter came in at about $16.3 million.

Although we expect to continue to significantly expand our professional and technical support team dedicated to the ramp in our Marcellus activity, we anticipate that G&A expense for the remaining quarters of this year will be close to or potentially fall below the level that we experienced in the first quarter as a result of the sharing of Marcellus overhead costs with our joint venture partner and the capitalization of certain G&A associated with our partnership management business and those periods when we raised funds for the partnership well programs.

The last area I will cover is our capital spending during the quarter.

Our capital investment totaled approximately $70 million, of which $36 million was used in our well drilling efforts, largely Marcellus Shale wells, and $23 million was used in our leasing operations, again largely Marcellus related.

We funded the majority of the capital program through internally generated cash, which totaled $52 million in the quarter.

Following the end of the quarter, and with the proceeds from the Reliance JV, the vast majority of leasing investment for the quarter was recaptured.

Overall, we've greatly strengthened our capital and liquidity positions and arranged for other parties to fund the vast majority of our infrastructure development cost and well drilling and completion costs in our Marcellus play.

We remain committed to prudently accelerating value on a per share basis for our shareholders and enhancing value for those who have committed debt capital to our Company.

With that I'll return the call to our CEO, Ed Cohen.

And now I'll return it to Regina for questions.

(Operator Instructions)

Your first question today comes from the line of Michael Hall with Wells Fargo.

Thanks.

Good morning, all.

Good morning.

Seems like the Header System is coming on a bit slower than expected.

If I recall last fall, kind of thoughts were you'd have first deliveries into that system at some point, call it at the end of the second quarter of this year.

What's the primary driver of the delay there, first off.

And then, also, is there any third-party potential lines that you can sell into in the interim here, any other solutions that haven't been discussed or outlined yet?

Let me address your questions in order.

I think the reality is that in the last six months to a year, the entire United States has undergone an increase in regulatory scrutiny, and this is not, of course, not affected the energy business.

Permitting processes, as Rich alluded to, have simply become much more onerous, and I think this is something that we hadn't counted on six months ago when we were making our projections.

Nonetheless, our Company is just strongly committed to environmental and safety enhancement and we're simply having to live with this.

I think that's the major factor.

We are pressing as hard as we can in a safe and responsible fashion, and I think that, although at the present time obviously we're feeling the pain of the inadequacy of our system, especially given the tremendous blockbuster results we're getting from the Marcellus situation, I think with a little detachment six months from now we may look at this as what it is, a temporary situation that we're striving mightily to overcome.

And, as I indicated, I'm confident that we can overcome it.

As far as the third-party potential goes, remember that we have the best infrastructure in the industry in our area.

So we are probably the envy of many others who don't have a problem of conscribed and constrained systems, but in many cases don't even have systems of all and are awaiting the completion of the most elementary beginning situation.

So, while it is painful, it's, under the circumstances, not unexpected.

Okay.

Appreciate that.

And then two more, if I may.

One, the second half 2011, you are going to have a substantial increase in capacity there.

Any ability or willingness to paint a little more color around what the ramp might look like after that capacity comes on?

And then second, you talk about your partnership programs continuing to work there and bring on additional Marcellus or Appalachian production within those programs.

Why not kind of press pause and maintain as much of the net capacity within the system as you can, net to ATLS?

With respect to the second half of 2011, we are projecting a pretty significant ramp as we continue to accelerate our plan and we do expect that the system will be -- we don't expect any delays in terms of the final completion date of the Header System.

I think for right now, Michael, I'd like to get a little bit closer to the -- towards more of the end of this year before we give out any real guidance on what that second half is going to look like, but you're right to assume it's an accelerating ramp.

And give us a little time to put those figures together.

I understand.

With regard to your question was why continue to drill wells through the programs?

Well, yes.

It seems like those take up growth capacity on the system and take it away from the ability to produce net gas to ATLS.

So, why not pause --

Well, I understand what you're saying, but remember that we are obligated to finish out a program that we're raising right now.

These wells were identified as part of that program and I don't really see this being a huge issue.

A lot of these wells, quite frankly, won't be turned into line until later in the year.

I really don't see that as being a big issue.

Now, recognize that going forward, all Marcellus drilling will be done through the, at least in this AMI, will be done through the Reliance JV and we have essentially ceased drilling additional vertical wells unless, for some reason, we are trying to hold acreage.

So, you're really just seeing the remnants of us finishing out some, I don't want to say obligations, but our ability to raise partnership dollars for this spring.

And the partnership programs, don't forget, are largely undertaken outside the state of Pennsylvania and very often as a result in Tennessee, Indiana, Michigan, and elsewhere, don't have any impact at all on this particular problem.

Okay.

Alright.

Well, I appreciate the color.

And at least you got a lot of cash coming in the door.

That's right.

Your next question comes from the line of Amir Arif with Stifel.

Hi.

Good morning, guys.

Just a few questions.

First of all, on the guidance for 2010, the 39 to 41 Bcfe that you are guided for for 2010 now, does that assume you do get an incremental capacity from the new Header System this year?

Or is that assuming those permitting delays cause that to be pushed to 2011?

It's a relatively conservative estimate.

There are certain looping projects that are -- we know are going to come on line.

In fact, we've got one coming on line this month that will add incremental capacity.

But, it's a fairly conservative estimate with respect to additional capacity adds.

And, Rich, I think you mentioned you're going to drill, or complete 25, 26 wells this year in the next few quarters.

Are you still planning on drilling 45 or so?

Oh, absolutely.

Okay.

You're just going to still drill away?

This is -- Amir, this is really just a temporary situation.

And by drilling we're just really building inventory to be able to turn into line shortly.

Okay.

That makes sense.

Second question, on the decline rates, it's great that you are seeing these lower decline rates on some of your newer wells.

How much of that is -- or is any of that due to just the higher line pipe pressures that you're trying to bring us into?

There could be some of that in that we're holding back pressure.

But, more importantly, I think, in the dry gas area we're just observing more robust recoveries.

And I think it's more -- more has to do with that.

But, when you do get your new Header System on and new capacity and you're able to flow these wells fully, that you still think that you're going to get closer to 60's EUR?

Absolutely.

Right.

I might add that we had quite a few of the most sophisticated energy concerns in the world come in and review our data and it was a near unanimous conclusion that what we're estimating is correct.

That's great.

Just final question, on placing the wells in the lower part of the Marcellus, I think you mentioned you added 11 wells this quarter, but you only -- I think you already had five placed in the lower part last year.

So you only put two of those wells in the lower part.

Is it just -- were they thick enough where you could do this or you just sort of --

No.

I don't know if those numbers are right.

I think of the 11 dry gas wells that we have, four are in the -- we landed higher in the Marcellus, and the remainder we landed lower.

And all of the wells that we've landed lower, and we talked about a few of them in the last call, have been very, very stout.

And it's not that we -- this was -- I might chock this up to a little bit of learning curve.

Obviously, we tested lateral placement over the last year and there's just no question in our mind that the recoveries are maximized with a lower landing of lateral.

The lowest part of the Marcellus is the most juicy, highly organic section within the Marcellus, and we believe that we have a very, very strong frac barrier in the Onondaga right below it, and we're just capturing, we think, the real high organic part of the shale by landing low.

And I might add, we've discussed this in the past, we do share data with other companies and this phenomena has been observed by other companies as well ?

So, this is something you plan to do on all your completions going forward?

For the foreseeable future, you bet.

We are -- until we can be shown otherwise, we really feel this is the proper lateral placement and it does have a very material impact on our recoveries.

Okay.

I just -- one final question.

So, outside of the take-away capacity, you're adding the rigs.

Any other constraints that you guys see in trying to ramp up from 45 wells this year to 100 plus wells next year?

Not really.

We're really getting ahead of things in terms of staffing, permitting, et cetera.

That really isn't -- I don't really see any other constraints that would hold us back.

Terrific.

Thanks, guys.

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

Good morning.

Hi, Scott.

Obviously, the capacity constraints are something you all addressed and indicated that there's things you can do here to help ramp up production, specifically looping projects.

Could you be more specific in terms of, I now you said you had one coming out in May, how much capacity you think that'll add?

And then the other ones that are coming through the year about the timing, and kind of size of capacity?

Because, obviously, with 26 additional wells coming on line that has the potential to -- you are going to need to open up a lot more capacity.

So, can you kind of walk through that in some detail?

Well, this project that's coming on line, we're basically, in May, we actually call it the Browned Game Lands Loop, it's in, actually, Greene County, where we have a number of wells that are constrained.

It's in Southern -- Eastern -- Southeast Greene County.

This system could ultimately add about 15 million a day of capacity, but it also is going to require an upgrade to our meter station there.

And so this capacity won't be available to us all by the end of the month here.

It's going to have to be -- there's going to have to be an additional upgrade to the meter station that -- where this gas is delivered.

There are all kinds of -- these kinds of projects are out there.

And, unfortunately for us, with the -- some of the permitting required us to do, when I say us, really, Laurel Mountain, to do some studies with respect to endangered species.

This is relatively routine.

Atlas Energy deals with this all the time when we're permitting wells.

It's just Laurel Mountain got started a little bit late in its permitting, and we got caught.

Okay.

And then, as you go through the year, is there some other looping projects that will allow you to bring on the other 26 wells?

Or I guess referring to a prior question, is there any need to get some of the Header System up and running to meet your new target for 2010?

I think our target is based on what we feel confident very conservatively that we can accomplish.

In addition to the looping situation we described, we have two other looping situations that we expect to have in place before the end of the year.

We've had processing plants where we've raised the safety standards as we've increasingly emphasized that aspect of the Business, and that meant that we had to slow the projects down and in a couple of cases take processing plants out of operation.

We're returning them.

There's a lot that's going on.

There's a lot that we're doing.

And we're trying to be as conservative as possible in projecting the forward situation.

I think that you all will be pleasantly surprised, much more likely that you'll be pleasantly surprised and that you'll be unpleasantly surprised by the speed with which we deal with this constraint.

Okay.

And so then in terms of progression, I guess as you look into the second quarter in terms of where production is right now, can you kind of give us a sense of where it is right now?

Are you looking at quarter over quarter somewhat flat sequentially and then starting to ramp it up a little bit in the third quarter as that -- the Brown Looping project is complete?

I think if you start with the actual results for the first quarter and anticipate gradual increases through the year, you won't be far off and if we can do better, I won't be surprised.

In terms of your drilling program, you mentioned you're adjusting your drilling program around some of these constraints.

When you sort of think about the 26 wells that you're drilling, are really those the wells that will be moving around and then say the other -- the residual wells you're drilling that may not get tied in because of infrastructure constraints, are they going to kind of be put into the areas where you think are most prospective at this point?

Well, absolutely.

We're -- when you look at a system that is probably 45 to 50 miles north to south and 25 to 30 miles east to west, you can't make one general statement about the whole system.

It depends on where you are, how wells are declining in certain areas.

So, I think, I'm confirming what I think you're suggesting, is that we are moving our program around to the extent possible to try to capture that incremental capacity on our legacy system and where we think it's highly likely there will be loop projects actually constructed this year.

And quite frankly, it's caused to us delay a couple of our completions and if you heard what I talked about, if you heard my turn-on schedule that I discussed, you recognize it's a little back end loaded here.

So, if we get some of that capacity available to us sooner than we are conservatively projecting, and as Ed mentioned, we're working hard on that with our partners at Williams, then we can maybe increase or accelerate the turn-ins.

But, that's how we see it.

Okay.

And one last question.

On the Collingwood.

Outside of the Encana well that was announced today, that I think they mentioned came on at 2.5 million a day.

What do you all know about that in terms of prior penetration?

And, from my understanding, it's not quite as much of a blanket up in Michigan, as it's a little bit spotty here and there.

But, if you can give us any color around that, that would be great.

Well, first of all, there have been quite a few penetration of this because it sits right above the Trenton, which some people have tested, and it also sits above the Prairie du Chien, which is an old play in Michigan.

So, there is actually quite a bit of well control, although no one has tried to complete a well until Encana did into this Collingwood.

We're very aware of where this formation is prospected.

It pretty much follows the deep Michigan rift that runs up along the Northwestern side of Northern Michigan.

Serendipity has it that we are extremely well positioned because one of most prospective areas is Antrim county, where we're the dominant acreage holder.

And we identified this and we've been watching what Encana was doing over the last several months and we became convinced that this could be a legitimate play.

There was very good shows in those penetrations that I talked about earlier.

And I think what's going to unlock this play is this Colling -- the recognition that the Collingwood has very high measured porosities.

So, we've got this all mapped.

And as Ed mentioned, we really initiated a leasing program a little over a month ago.

Unfortunately for us, the prices ran up really fast.

We participated in the state lease sale earlier this week, but, quite frankly, didn't buy much.

We felt like those prices were way over what we were comfortable with, but with a position of 115,000 acres, 70,000 net to us, we're sitting pretty good.

Okay.

And then I guess, so part of the Collingwood I guess, is it a shale with some interbedded limestone in it?

Is that the way the reservoir looks, the formation looks to you all?

It might be more of a limestone with interbedded shales in it with a utica on top.

And we think that the utica charged up this lime shale, if you want to call it, and we think that it was -- it also generated gas itself.

What's interesting here, and I think it may be driving a lot of the industry's great interest, is we would expect this to be a fairly rich gas stream and we ought to see some pretty darn good recoveries out of the -- out of this Collingwood.

Michigan is a great state to be an oil and gas producer.

There's a very significant natural gas market there.

Michigan is by far the largest storage state in the United States and there's quite a bit of refinery complex in the Port Huron area and right across the border in Canada area.

So, there's a real market for the condensate and the NGLs that we might produce, and of course, there's plenty of market for any ramp-up in natural gas.

As the largest producer in Michigan, we're well aware of how the infrastructure works, and again, as I said, we have a very nice position and we're going to be drilling some wells here in the next several months.

Do we know on the well that was completed in there how much liquids contribution and condensate contribution there was?

Yes, we do.

But, I might let Encana make those statements.

Okay, did you have an interest in that well?

No, we don't.

Okay.

Alright, thanks.

You're welcome.

Your next question comes from the line of Jack Aydin with KeyBanc.

Hi, guys.

Hi, Jack.

Most of the questions that I wanted to ask have been asked, but let me go at it this way.

You were talking about reaching sometime in the second quarter next year Appalachian production to 85 million, 95 million.

You're already producing about 45.2 million.

Could you explain to me, based on the drilling backlog and everything, is that basically going to be more or less Marcellus production, you're backing out the conventional production?

How do you arrive at that number in a way?

Well, first of all, it's a relatively conservative forecast.

Especially as we ramp into 2010, as we've mentioned.

But, Jack, rough numbers are Marcellus production right now is about 60 million to 65 million a day.

And our total gross production is about -- I'm talking gross numbers here, is about 115 million to 120 million a day right now and all of that incremental growth will be Marcellus.

Do you run it by wells?

How many wells do you think --

The production forecast is driven by our turn-ins.

Obviously, our engineered decline on existing wells plus turn-ins, when we anticipate that well will be turned in, so it's a well by well analysis.

And one of the things we have to judge is from some hydraulic engineering and testing and analysis how much of that production into the system will actually get to the market.

Now, once we have this Header System up and running, it's going to be darn close, if not at 100%.

But, right now what happens when we turn in these higher pressure wells, Jack, we back off our legacy production, which needs to operate at much lower pressures.

That's why it's so important we're able to get this new system built.

Our legacy system was very handy, Jack, we were able to use it to the delineate our acreage position, which was very beneficial to us.

But, we always knew this was not the system for a large scale Marcellus development program.

We've got to have a new Header System, and that's what we're building.

On Laurel Mountain, is there a penalty for not -- the group not meeting their timetable in getting Header System on line?

There are penalties, Jack.

The penalties really revolve around completion -- in-service completion dates, and if Laurel Mountain were to miss these in-service completion dates there would be penalties and potentially a release of our dedication.

Okay.

You care to -- okay.

We anticipate that Laurel Mountain will meet its projected in-service dates.

Thanks a lot.

Jack, I have not -- I'm not sweating the completion dates.

The thing that we're struggling with here is some of these loop projects that we were counting on looks like they've been delayed.

So, it's really a timing issue.

But, I don't really think that we're going to have an issue getting the new Header System completed by the date that we had anticipated.

Appreciate it, thank you.

Thank you, Jack.

Your next question comes from the line of Marshall Carver with Capital One.

Hi, Marshall.

Yes, good morning to you.

Couple questions.

Do you have the specific timing of your Collingwood test?

Will we get news on that in the next quarter conference call or is it more like the end of 2010?

I think it's more at the end of this year, Marshall.

We're staking wells right now.

I think that for us to have any information on our own tests would be later this year.

Okay, that's helpful.

And do you have estimates on how much those wells will probably cost?

Well, it really depends.

The Utica/Collingwood , the depth dips from north to south.

The Encana well, I think, was at about 9,000 feet of vertical depth.

Some of our acreage to the north of that is more in the 6,500-foot range.

Depends on where we actually drill those wells.

I just think that for right now I would estimate that we're in the $4 million to $5 million range.

That's a total guess, by the way,

Thank you.

Based on sort of analogous situations.

But, Marshall, bear in mind that we have a major operation in Michigan already and our Michigan-based crews also operate in Indiana.

So, once again, we have the advantage of having infrastructure, of having the personnel.

These companies that the newspaper alluded to, the outside companies coming in, will have the same problem that they've had in Pennsylvania.

Namely, we have the staff, we have the infrastructure, and therefore, we have a big advantage.

Now, of course, standing at this point, probably we would not look upon it as a big negative if a year or a year and a half from now it happens that the results from the Collingwood are so fantastic that it overwhelms our existing system.

We're already starting to give preliminary thought to how we can enhance that infrastructure, although it's very, very early in this situation.

So, there are a lot of similarities here to the Marcellus situation, although obviously Marcellus opportunity comes probably once in a lifetime for the whole world and so I'm not anticipating that Michigan will be quite what Marcellus is.

But, there are striking similarities and we have the same striking advantages in Michigan that we had in Pennsylvania.

So, it's very gratifying, and of course, we all know it'll be very challenging.

Right, thank you.

One more question.

Did you throw out a -- put out a CapEx number for this year?

We had provided a CapEx number last quarter where we estimated CapEx for the year would be around 260, 265.

We're adjusting that number.

We have adjusted that number, but we haven't firmed it up yet based on all that is developing in the Business that we've talked about today.

But, having said that, inclusive of the acquisition of the Burkland/Boyer acreage, which we announced a number of weeks ago, netting that against the drilling carry that that we'll receive this year from our joint venture partner and factoring in a couple of other elements, including potentially adding a Collingwood well or two to the mix, and adding potentially to some of the lease expense that we'll incur to complete units and expand our units in Appalachia, I would say net of all of that activity, our CapEx budget, we are anticipating that our CapEx budget will be reduced from the 260 to 265 level to something closer to the 215 to 225 level after factoring in all those elements.

So, that's 215 to 225, which includes acreage costs?

That includes acreage costs, but excludes the Burkland/Boyer acreage acquisition.

It was about $115 million The 215 to 225 relates to the original 260 guidance.

It was 115 net to us.

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

Good morning, hi.

Trying to understand, on the permitting issues, sounds like they only affect the looping projects and not the main Header System.

Is that -- am I understanding that correctly?

And if so, why is that the case?

I wouldn't assume that.

It's just that the construction of the looping system was always -- most of that was always going to take place later in the year.

So it's just a timing -- I guess what I'm getting at is there any --

The first construction was really going to be on these looping projects and the large compressor station where -- that we're going to deliver into in terms of the Header System, and the hope was that that construction would have already began and that we would have capacities available to us in the next 30 to 60 days.

And we have experienced permitting delays that are going push those projects back, but the main Header System construction wasn't really going to start anyway for a couple of months.

Okay, so I guess once you get these permitting issues behind you that clear the way for the looping projects, are there any more potential permitting issues that could affect the bulk of the project?

We certainly don't foresee any.

And even the existing permitting situation, in some respects, was a concatenation of circumstances that we don't think will recur in the future.

Okay, thanks.

In terms of the backlog of wells that you'll there, are you going to go ahead and complete those or do you just drill them and shut them in?

Or what do you do there?

There may be a few wells that we go ahead and drill, complete, and flow back and then shut in and season, as we've talk about in the past.

There may be a few wells like that.

But, generally speaking, we will hod back completions until we know there's a capacity available.

Okay, and you mentioned the nice rates you're seeing in your dry gas area.

What kind of rates were you seeing on the -- I know it's a big part of the acreage, but in terms of the wet gas wells, are you seeing similar declines there?

Or are they any different?

Well, first of all, they're really good wells.

And I think that the value in the liquid is real and attractive, but we do see steeper declines in that area.

But, don't forget the overwhelming percentage of our acreage is in the dry window.

Right.

Can you venture a guess on an average EUR for the wet area yet, or is it too early?

I'd rather not.

Okay.

And then any update on the closed loop water system?

That's progressing ahead.

We actually are testing right now -- the one thing we wanted to do was test this on an actual horizontal well.

We've done a lot of testing in the field on vertical wells and we're doing that as we speak.

And we fully expect by the end of the year to have a system where we're using 100% of our water.

Okay, great.

And in terms of the Collingwood, that 4.5 million you threw out, Rich, that was for a horizontal, right?

I'm wondering, are you planning on drilling horizontally right away or are you going to try vertical first?

I think that we'll probably go right to horizontal.

Okay.

We definitely think it's a horizontal play.

Okay.

And is it overpressured like the Marcellus, or how do the pressures compare to -- sounds like you are going to have to have the same sort of infrastructure issues there.

I'm assuming it's over pressured also.

Well, actually, I'm not -- we're not sure.

In fact, we wouldn't be surprised if it's normally pressured, but I think we need to get a well and a formation before we make any strong predictions there.

The one thing about Michigan, and the infrastructure is always an issue, but Michigan, because of the substantial amount of pipeline that works already through Michigan, and MichCon has a very substantial -- which is a subsidiary of DTE, has a substantial, I'm going to call it a gathering system, but it's really just trunk lines, out into the old producing areas in Michigan.

We probably are not going to have as great a challenge in Michigan as we have in Pennsylvania.

Okay.

From a construction standpoint.

There's a plant, there's an existing plant, natural gas processing plant, with about 400 million a day of capacity in and around our acreage already.

I think right now they're only processing about, from what I understand, about 50 million a day.

So, there's a lot of unused excess capacity in Michigan, as Michigan production has declined.

From formations like the [Nagin Reeve] and the Prairie du Chien, and even the Antrim itself has been declining as an industry over the last couple years.

Your next question comes from the line of Ray Deacon with Pritchard Capital.

Hi, Rich.

I was wondering if I could ask you what the 30-day rate looks like on a 6 Bcf well?

30-day rate?

Well, good question.

Let me just look at this real quick.

I would put it in the neighborhood of around -- I'm adding some numbers up here, in the neighborhood of around 4.5 million a day.

Okay.

Great.

I was just curious about, can you talk in general about deliverability versus production, say by the end of this year?

If you had the infrastructure in place that you are going to get by the middle of 2011, what do you think your productive capability could be in Appalachia?

Well, in terms of daily production?

Yes, exactly.

I was just -- you had mentioned at one point, I recall kind of what you thought an average rig in the Marcellus could add, drilling for a year, and my recollection, I thought you said around 17, 18 million a day.

Is that fair?

What one -- help me out again.

One rig?

Right, just run one rig for a year and try to measure how much production that could add.

Well, I think if you want to take a fairly conservative estimate, I think one rig could drill one -- excuse me, about 15 wells, one horizontal rig using top hole rigs ahead of it could drill 15 wells per year.

Is that what you are asking?

Exactly.

And so the, sort of by the end of the year, how much production would that one rig add, I guess?

Would you have --

I'd have to do that math.

I'd have to do that math.

We can work with you on that off-line, if you want.

Okay, cool.

And I guess, just you're -- when do you -- I guess you're kind of moving around this year, given the transportation constraints and kind of, where is the bulk of the activity going to be this year?

Is it primarily Western Fayette, or will you have a lot of wells in Greene and Washington also?

And Westmoreland County.

We will be drilling very actively at -- really in all parts of the -- of our core area there.

Got it.

We have had very, very stout results in all three of those counties, and also Eastern Washington County.

Okay.

And is that dry gas, or that's a wet gas area?

Dry gas.

Dry gas.

Okay.

Got it.

So the efficiencies -- the efficiencies you gain will be primarily next year trying to get down to 3.8 million, once you're on pads, probably by the end of next year?

Is that fair?

That's very fair.

We do start drilling -- we are starting to drill pad -- more concentrated pad wells at the end of this year in anticipation of the system being available within months after that.

So, we're not waiting until next year.

But, where you really start to get the substantial production increases in concentrated areas will be more in the first half of next year, but we're going to be beginning to drill our concentrated pad wells in 2010.

Okay, got it.

Great.

Thank you very much.

Thank you, Ray.

Your next question comes from the line of Lee Cooperman with ATLS Energy.

Yes, hi.

Thanks.

You paint the picture of great optimism.

I can't read a research report out of Wall Street that doesn't have a price objective with at least a five handle on it.

You did a brilliant deal with Reliance, which really has them largely fund your CapEx.

What's the prospect with the stock selling very low levels relative to the underlying asset value of the company, assuming we don't get a further collapse in the price of gas, of taking some of that cash flow that we have and reducing the equity base at a time now when there's great uncertainty in the market and people don't seem to believe what we've got?

One way of funding that is whether we could sell and/or spin out the partnership business, which is not really central to what we do.

Let me start with one of the last things you said, the reference to people apparently don't believe that we have what we have.

Our feeling is very much to the contrary.

Not that they don't believe, that the stock is not reflecting it.

In other words, everybody out there has got some big price objective on the stock, and the stock will, of course, because of the market, is selling at the low end of this trading range and quite some time.

It wasn't a question, I don't believe.

The market doesn't believe.

You got a lot of adherence, a lot believers except for the lowness of the market.

Is Mr.

Market creating an opportunity for us, given the unique nature of your joint venture with Reliance, where you'll be building up a lot of free cash flow since they're funding the development costs?

That's the only --

We will watch the market very closely, and we will try to take advantage.

Let me give you an example.

There are six analysts have a buy on the stock and the average price objective is $52.50, and we're down $2 this morning to $30.90.

And given the unique nature of your joint venture, whether buying a $1 bill for $0.60 might be one of the strategies that you can incorporate.

Just a thought.

No, that's absolutely right.

Your next question comes from the line of Wayne Cooperman with Cobalt Capital.

Hi, guys.

Apologize if there's redundance here, but I had to get off for a few minutes.

First, on Michigan, I know it's early, but do you have any plans for drilling that?

Is that going to be on your own account, in a joint venture with a partnership program?

Can you elaborate on that?

We will definitely be taking advantage of the availability of the very favorable partnership arrangements relative to Michigan, whether we also will drill for our own account remains to be determined.

We certainly have the capital capacity to drill for our own account.

Right.

Secondly, would you -- you just quickly after closing the Reliance transaction, you bought more acreage.

Could we expect, or are you looking to increase acreage more on the JV, or was that sort of a one-off opportunity?

It was a unique opportunity, but we think there are other equally strategic opportunities.

We're looking for them.

Our understanding with Reliance looks to an expansion and, quite possibly a massive expansion of that situation.

With Reliance's support, we can do a lot more.

But, we're not into growth for the sake of growth.

We're into growth for the sake of strategic advantage.

And as far as the pipeline issue, which is clearly being viewed relatively unfavorably today, can you -- A, how do we know that the high pressure system will be done by Q2 2011?

Obviously, you never know everything definitively, but how much confidence do we have?

And once that's finished does that basically alleviate all of the take-away capacity issues?

And B, I guess between now and then, what can we do to get more gas out of the ground?

Although, I'm not sure that we should be in a rush to get it out of the ground anyway at current prices, to the extent we could get it out -- it's still there, and we can get it out at a better price later?

That's an excellent point.

The completion of the Header System will more than alleviate all of our constraints.

It will give us extraordinary excess capacity far into the future, and as we indicated, that system itself is being built to be expansible to over a billion cubic feet per day.

We are taking, as we indicated throughout the presentation, a number of steps to alleviate the constraint, and we're quite optimistic that we will have a great deal of success.

Your forecast now assumes you don't have have any success, or is that -- I'm just curious.

I won't say it anticipates no success, but as Rich indicated, it's extremely conservative.

And how do we know, though, that the high pressure system will be done on time?

I mean, do they have all the permits they need?

I assume you are not -- you're doing this kind of on the same right of way that your existing pipelines are so you don't need to buy all the land and do all the heavy lifting.

We definitely were able to use some of our right of ways, but not all of them, Wayne, because the diameters that we're installing are going to be so much greater, some of our right of ways were diameter constrained.

But that being said, really Laurel Mountain is, I think, well ahead on the right of way front, and on permitting, they've already filed permits for the entire Header System and are working through that right now.

So, at this point, I think we are on schedule and feel confident that this Header System will be completed by the second quarter of 2011.

And it comes on in stages?

Ladies and gentlemen, this concludes the question-and-answer session for today's call.

I will now turn the call over to management for any closing remarks.

Thank you very much.

We're hopeful that at next call, instead of continuing to be speaking about constraints, we'll be delivering information that will indicate that our facilities are increasingly capable of taking on additional gas.

The other excellent elements that we discussed we anticipate will continue to occur and, as we suggested, we're especially excited by what's happening in Michigan.

Thank you all.

Ladies and gentlemen, thank you so much for your participation in today's conference.

This concludes our presentation.

And you may now disconnect.

Have a wonderful day.