Tyler Lewis - CONSOL Energy, Inc. Nicholas J. DeIuliis - CONSOL Energy, Inc. David Michael Khani - CONSOL Energy, Inc. Timothy C. Dugan - CONSOL Energy, Inc..

Joseph Allman - FBR Capital Markets & Co. Holly Barrett Stewart - Scotia Howard Weil Neal D. Dingmann - SunTrust Robinson Humphrey, Inc..

Ladies and gentlemen, thank you for standing by and welcome to the CONSOL Energy's First Quarter 2017 Earnings Results Conference Call. As a reminder, today's call is being record. I would now like to turn the conference over to the Vice President of Investor Relations, Tyler Lewis..

Thanks, Nick, and good morning to everybody. Welcome to CONSOL Energy's first quarter conference call. We have in our room today Nick DeIuliis, our President and CEO; Dave Khani, our Chief Financial Officer; and Tim Dugan, our Chief Operating Officer.

Today, we will be discussing our first quarter results, and we've posted an updated slide presentation to our website.

As a reminder, any forward-looking statements we make or comments about future expectations are subject to business risks, which we've laid out for you in our press release today, as well as in our previous Securities and Exchange Commission filings. We'll begin our call today with prepared remarks by Nick, followed by Dave and then Tim.

And then, we will open the call up for Q&A. With that, let me turn the call over to you, Nick..

Well, thanks, Tyler, and good morning, everybody. Highlighted in the morning's press release, there were three important and critical achievements that developed this quarter. Now the first one was from an operations standpoint.

And if you look at our operational performance, cycle times have been dramatically reduced, capital efficiency is up, and the type curves have been further optimized in some of our fields. All of these items have contributed to 2017 and 2018 production guidance increasing. So, for 2017, we're increasing guidance to 420 to 440 Bcf.

And for 2018, we're increasing guidance to 490 to 520 Bcf. Those both compare to the prior guidance numbers of 415 Bcf for 2017 and 485 Bcf for 208. And we did that without increasing our previously announced 2017 and 2018 capital plans. So, that's a really significant achievement and, of course, a driver of our NAV per share.

Now the second development was that we monetized over $100 million in non-core E&P assets to-date so far this year. We expect to be over halfway to the high-end of our $400 million to $600 million asset sales target by the end of the second quarter. So we got off to a good start there.

And then the third development that was significant, we generated approximately $100 million in organic free cash flow in the first quarter that excludes asset sales, and we used the organic free cash flow to pay down debt at a discount and further reduce interest expense. So these are three very important achievements.

They're fundamental drivers, as we continue to pursue our strategic goals in 2017 and beyond. And taking a step back, beyond these critical achievements so far this year, we'd like to add how a unique situation for the Appalachian Basin, perhaps for all of E&P, is unfolding with CONSOL Energy.

We have over the past five quarters, were currently in early 2017 and we will continue in the future to be a company who exercises a disciplined capital allocation philosophy across a premier asset base, and we're doing it in a way where we deliver the best of both worlds. That's production growth and free cash flow generation.

We delivered both in a big way throughout 2016, we did so again in the first quarter of this year and we expect to continue to do so throughout the remainder of 2017 and 2018. That's a unique trait in Appalachia and it's a characteristic that creates all kinds of opportunity across a range of options to grow the intrinsic value for our ownership.

Now I'm going to let Tim Dugan cover more of the specifics regarding the operational achievements and the exciting things that we continue to see there, along with the improvements in type curve optimizations.

So, in the meantime, I want to spend the remainder of the time I have with you on the second and third developments that I mentioned for the quarter. Over the years, our monetization program has seen tremendous success and that's been illustrated by CONSOL being the beneficiary of billions of dollars worth of proceeds.

The majority of those asset sales historically have been co-related and have netted the company over $5 billion since 2012. This quarter, however, highlighted a step-change in what we began and when we began monetizing non-core E&P assets.

Why is the step-change important? Well, I'll remind you, as we discussed in the past, one of the most significant benefits of the Marcellus joint venture dissolution, which wrapped up in the fourth quarter of last year, was the fact that the separation gave CONSOL 100% control of our future development pace, as well strategic control of our assets to include divestitures.

As such, the ability to divest acreage that falls outside our 10-year plan, that becomes a lot easier. We recently closed on three transactions, which in aggregate total approximately $108 million. Since two of those transactions closed after the end of the first quarter, we've only received about $16 million of those proceeds as of March 31.

In addition to those initial proceeds, we expect to receive around $92 million in the second quarter. Now, on top of those initial asset sales, we've got a handful more in process.

Another potential asset package, which is currently in the held-for-sale category in our SEC guidelines highlighted in our 10-Q that's going to be filed, is the plan to sell 12 producing wells, 15 DUCs, and roughly 15,500 net developed and undeveloped acres in Doddridge and Wetzel Counties in West Virginia.

I don't want to go into the specifics beyond that, but it's important to highlight that with the sales that have closed to-date, along with those that are currently in process, we think we have the momentum to reach our target of $400 million to $600 million in 2017 for asset sales, in addition to reaching a halfway point to the high-end of the guidance range by the end of the second quarter.

That third development I mentioned that we generated around $100 million in organic free cash flow, again, that excludes asset sale proceeds and we used that free cash flow to pay down debt at a discount. It's important for a couple of reasons. First, yet again, we generated organic free cash flow from continuing operations.

Second, we continue to execute on further reducing debt to reduce our leverage targets. And last but not least, with proceeds coming in from closed asset sales, we expect the second quarter will be even better than the first quarter in terms of de-levering.

With continued organic free cash flow generation and proceeds from asset sales, we're expecting that our total company leverage ratio will decline to the low 2xs by year-end. Since a strong leverage ratio allows us to execute the separation of our coal and E&P businesses, let me provide a brief general update on the separation front.

Now, as we said before, we're running a dual process in parallel to maximize the outcome. Now the first process is an outright sale and the second process is a spin transaction. We've retained Credit Suisse and Bank of America Merrill Lynch to assist with these processes.

We're pleased with the level of interest the sale process has generated from strategic buyers as well as financial sponsors to-date. But also we're pleased with the progress we're making with the preparations for a spin-off.

Now we don't have a timetable for the completion of the sale process or the spin process, but as we said previously, we expect to complete the separation in 2017.

Beyond that, I really don't want to get into many details, other than it really is going to boil down to selecting the path that optimizes the best NAV per share opportunity for the shareholders. To briefly summarize and foreshadow some of the key themes you'll hear from Dave Khani and Tim Dugan in a minute. Production is up. Capital is flat.

Asset sales are on track. Our hedge program protects us from future volatility. And year-over-year, our quarterly costs are lower, even though production was down slightly because of tight in-line scheduling. We've got a low-risk plan that will yield significant growth over the next two years.

And at the same time, we don't expect any inflationary pressures for service costs due to contracted frac crews, along with expected efficiency improvements that Tim's going to talk about. In short, everything is falling into place as we continue on the path of separating and continuing to transform the company.

This all leads to the topic of capital allocation, something that you've heard us speak about for a handful of quarters now. All the arrows that are pointing up for CONSOL will create opportunities for important capital allocation decisions in the coming months.

From a development standpoint, we continue to evaluate and drill our highest-rate-of-return areas first. These decisions continue to evolve, especially given our continued success in the dry Utica. Tim's going to talk about that in some greater detail.

On a corporate level, we remain focused on using free cash flow to further reduce debt to get our leverage ratio down to the low-2xs 2017. And following the company reaching this target, along with the separation of our coal and E&P businesses, we're going to be in a position where we can then pivot to a number of potential options.

If we feel we're still trading at a significant discount or NAV per share, and we certainly believe that today, a share repurchase program is an option. We could plow funds into the drill bit or we could look at M&A acreage opportunities.

Whichever way we go, we're going to look at this in an opportunistic fashion and not a prescriptive one, and our decision ultimately depends on where we see the highest rate of return and NAV per share impact. So, stay tuned on that front, much more to come this year. With that, now I'm going to turn it over to Dave Khani..

Can we grow production meaningfully? And do we have the outlets to sell it at a reasonable margin, despite not having an extremely large FT book? Shifting to the results for the quarter and highlighted on slide 18, CONSOL reported adjusted income and EBITDA from continuing operations of $38 million or $0.17 per diluted share and $217 million, respectively.

On a GAAP basis, the company reported net loss from continuing operations of $39 million, attributable to CONSOL shareholders, primarily reflecting $138 million impairment related to the sale of Knox and Coalfield assets, the $25 million unrealized gain on commodity derivatives, and $5 million in various non-recurring fees.

As we monetize assets and streamline our company, we will continue to experience gains and losses. We would expect to realize gains on the next set of asset sales. Let's move over to guidance.

We're increasing our EBITDA guidance for 2017 by 7% over the February earnings release, driven by higher production and improved basis outlook, partially offset by moderately higher operating costs and some higher post-retirement costs. In the first quarter, we beat most of our internal forecasted items, including production.

As a result, we've raised guidance. On the production front, the only point I will make is that our production increase is tied to improved recycling ratios and capital yields that Nick highlighted, as well as an improvement in our PUD conversion costs. Now let's talk about operating costs, which increased in the quarter.

Our per unit LOE continues to tick down by about $0.04, but our gathering, processing and transportation costs increased about $0.10 as a result of higher percentage of gas getting processed resulting from the JV dissolution, and two one-time catch-up items from our Ohio wet Utica and our CONE fees.

Moving forward, we expect to see a sharp reduction to operating costs over the next two years, as we expect to bring on more dry gas production. Our dry Utica operating costs are materially lower than our Marcellus, and it is the single biggest driver in reducing our cash operating costs.

Couple this with significant expected decreases to Utica D&C costs, which Tim will touch on, drive higher rates of return than our Marcellus. This is why we were much more bullish than our peers on the dry Utica. We expect dry Utica volumes to jump about sevenfold by the fourth quarter of 2017. Now let's talk about coal.

CNXC reported its first quarter earnings last night and posted strong results beside another mild winter. CONSOL is increasing its 2017 coal sales guidance to a range of 25.6 million to 27.6 million tons from what was 26 million tons previously.

The increase in sales guidance is supported by higher natural gas prices and more normal coal inventory levels, which has helped improve demand from domestic power plant customers. Based on the updated guidance range, an approximately 95% of 2017 sales are uncontracted and 65% of 2018 sales are contracted.

With regard to the met coal kicker, CONSOL conservatively forecasts around $15 million to $20 million in EBITDA associated with the 2017 Buchanan royalty. We raised the bottom end of the previous guidance since we see strong benchmark met pricing and our royalty continues to remain in the mine.

Over the past two quarters, we have captured approximately $15 million. Now turning over to the macro front. We remain confident in favorable supply and demand conditions for 2017 and into 2018. On slide 15, we showed evidence that the market is under-supplied, which could be as much as 3 Bcf per day.

Normalizing for heating degree days, storage withdrawals were stronger than expected, leaving inventory at average levels. Couple this with higher demand and relatively flat first half of 2017 Appalachian production, creates a more bullish outlook heading into 2018.

We were also encouraged by the recent progress in major pipeline projects, including Rover, as highlighted on slide 16. As we stated recently, we expect basis to continue to contract longer-term and average around $0.10 to $0.15 or in line with the variable cost of transportation out in the basin.

We have improved our open natural gas basis outlook for 2017-2018 by around $0.28 per Mcf, driven primarily by shifting gas away from certain higher-basin differential areas, along with securing favorable firm sales contracts. Now let's talk about marketing and hedging.

We take a portfolio approach to market our E&P products given the high risk of over-production that causes one method of shipment to come in and out of favor. This means we will use existing low-cost FT, along with other operators' existing FT and firm sales or physical sales, and then supplement with a hedge book.

This enables us to be flexible on how much and where we produce, which is very important with the disruption of the dry Utica coming into play. We do not want stranded high-cost FT. We've recently put greater emphasis on physical sales, which cover and lock-in prices in often premium and illiquid markets.

This aspect represents about 11% of our forward-marketing book. In the first quarter specifically, CONSOL completed two large volume contracts on the East Tennessee system. The pricing structures for these deals provide value above pool sales on Columbia Gas Transmission, where much of the gas flowed prior to certain system enhancements.

Furthermore, both deals utilize customers' firm transformation capacity at no cost to CONSOL, thereby allowing CONSOL to forego the renewal of certain of its firm transportation obligations on the East Tennessee system. Now, while we are confident in micro dynamics, going forward we continue to de-risk revenues with our systematic hedge program.

In the first quarter, CONSOL added NYMEX of gas hedges of 153.7 Bcf for 2018 to 2021 and 253.5 Bcf of basis hedges for 2017 to 2021. As shown on slide 11, approximately 74% of our guided 2017 production is completely hedged on both NYMEX and basis.

We're also more than 50% hedged for 2018 and we were able to lock-in some favorable rates during our recent run-up in both NYMEX and basis. Let's talk about the balance sheet leverage and liquidity.

After surpassing our 18-month free cash flow plan at the end of 2016 and executing on our de-leveraging plan for this year, our balance sheet repair is nearly complete. This enables the optionality to use free cash flow to include things like stock repurchases, asset purchases, as well as increased drilling.

All of our efforts to lock-in revenue and increase margins helped drive our number one capital allocation initiative so far for reducing leverage. To that end, we debt repurchased about $100 million of the 2022 bonds in the first quarter at an average price of $98.54.

This debt repurchase was done with all organic free cash flow and we also generated $117 million in total free cash flow. At the same time, CONSOL was able to maintain liquid of roughly about $2 million, similar to year-end levels.

Based on expected organic free cash flow and the current estimate of asset sales of the year and our tax refund, we expect to reach our target leverage ratio before year-end. In summary, we continue to focus on further strengthening an already strong balance sheet. We remain committed to making prudent capital allocation decisions.

And our goal is to finalize the coal and E&P separation in 2017. Once we split, we will continue to differentiate ourselves by being able to grow and generate free cash flow. As Nick stated, 2017 will be year two in this regard. With that, I'll turn it over to Tim..

7 dry Utica wells in Monroe County, Ohio and two Marcellus wells in Washington County, PA. For one of the Marcellus wells, our team achieved an Appalachian Marcellus drilling record of 7,380 feet drilled in a 24-hour period on our Morris 30B well in Washington County, PA.

In the quarter, drilling efficiency, or days per 1,000-foot of lateral, improved 18% compared to 2016, helping reduce our cost per lateral foot by 11%.

In Monroe County, Ohio, the dry Utica wells averaged approximately 9,900 lateral feet while averaging 21.5 drilling days per well, compared to 24 drilling days per well during the fourth quarter of 2016.

At the current pace, a single rig could drill 16 dry Utica shale wells per year with 10,000-foot laterals, which is a 14% improvement compared to the fourth quarter of 2016.

Drilling costs for the dry Utica in Monroe County have dropped from $384 per lateral foot in the fourth quarter of 2016 to $351 per lateral foot this quarter, and we expect further improvement in future costs.

When you include completion costs, which have increased some due to design changes in proppant loading and proppant type, our Monroe County dry Utica well costs are now around $9 million for a 9,000-foot lateral, which compares to $9.6 million just eight wells ago.

We recently TD-ed the Aikens 5M, our first offset to the Gaut 4H well in Westmoreland County, PA in the deep dry Utica. From a drilling standpoint, we have successfully drilled the Aikens well in a fraction of the time it took to drill the Gaut well. Specifically, it took us 38 days to TD the Aikens well, compared to 167 days to drill the Gaut well.

Previously, we had stated that it would take us five wells to seven wells to get our costs under $15 million. With the improvements seen on the current well and assuming completion operations go as planned, there's a clear path to a sub-$12.5 million deep dry Utica well in the next two wells. Again, this highlights our tremendous rate of change.

Results like this are likely to accelerate our shifting focus from the Marcellus to the dry Utica, fast-tracking the Utica development planning process and its infrastructure build-out options.

Shifting to completion activity, we utilized 3 frac crews in the quarter and finished completion operations in Allegheny County, Pennsylvania on the ACAA1 pad, which contains six Marcellus wells as well as one Burkett and one Rhinestreet well.

Our model-based frac design optimization and improved logistics resulted in the company fracking on average 1,245 feet per day, compared to 800 feet per day in 2016. Operating at this pace with pads drilled and ready to frac, our frac crew can frac 46 Marcellus wells per year with an average lateral length of 8,000 feet.

Total completion cost for the eight Marcellus wells fracked in the first quarter were $348 per lateral foot, which is flat to our unit costs for 2016 Marcellus completions and a 6% increase from the last wells fracked in 2016, which were in the third quarter.

While we continue to see excellent production response from increased proppant loading and pumping nearly 600,000 pounds of proppant per stage, we are still able to offset service cost increases through gains and operational efficiencies.

On peak days, we were able to frac 11 stages per day, with many days exceeding 10 stages per day, and unloading 130 sand trucks in a 24-hour period. Three of the Marcellus wells returned in line in the quarter, with the remaining five wells carrying over into the second quarter. Now, shifting to production.

Our quarterly production was 95 Bcfe or an average daily production of 1.056 Bcf per day. This is a quarter-over-quarter decline from the fourth quarter, which was 101.3 Bcfe or average daily production of 1.101 Bcf per day.

Even though Marcellus volumes increased during the quarter, we saw a decline in our Utica production, which was the main driver of the overall production decline in the quarter. Now, this is important.

If you remember, last quarter, I laid out a development cadence for the year and said that we didn't expect any new wells to be turned in line until the very end of March or early April, and that the Monroe County wells would not come online until the end of May.

So the decline in the quarter is not unexpected and is driven by natural declines and the timing of when wells are getting turned in line. However, the decline was slightly accentuated due to some temporary shut-ins.

Specifically, we temporarily shut-in a flowing Monroe County pad in order to frac an adjacent well and we temporarily shut-in the Gaut well to install tubing.

That said, we expect volumes to grow year-over-year in 2017 and the Utica production to continue to become a larger percentage of the production mix, sooner rather than later, as Monroe County gets further developed and the results from the Aikens pushes us further into the deep dry Utica development.

I'd like to spend the remaining time talking about how we further refined our production protocol and how it will result in increased production in 2017 and 2018 at the same capital levels we announced last quarter.

There are two specific fields where we have adjusted our production protocol; one is the Morris Field, which is Marcellus production in Greene County, PA; and the other is our dry Utica Switz Field in Monroe County, Ohio.

You can see an illustration on slide 8 highlighting the change that we continue to refine how we are flowing back our wells, which ultimately is changing the shape of the type curve. We have been advocates of flowing the wells back under constrained conditions for a longer period of time.

So this is nothing new, but more so a modification due to a breakthrough in our understanding of reservoir compressibility tailored to specific geologic areas. Further production improvements are being driven by optimizing stage lengths, diversion techniques, and proppant loading.

For the Monroe County Switz wells, we've also optimized inter-lateral spacing. All of these modifications have resulted in a substantial production forecast increase, while spending no additional dollars from the previously announced capital budgets for 2017 and 2018 of $555 million and $600 million, respectively.

So how have all the cycle time improvements in production optimization changes impacted capital intensity moving forward? If we think in terms of maintenance and production capital to hold production flat, we expect it to further improve.

More specifically, at our December Analyst Day, we talked about maintenance capital being $250 million to $300 million to hold 395 Bcfe flat. With some of the improvements and optimization changes that we've made, maintenance and production capital is near the low-end of that range at $265 million to hold 395 Bcfe flat.

With that, I'll turn it back over to Tyler..

Thanks, Tim. This concludes our prepared remarks.

Nick, can you please open the line up for questions at this time?.

Certainly. The first question today comes from the line of Joe Allman with FBR. Please go ahead..

Thank you, operator. Good morning, everybody..

Morning..

Morning..

Do you have any comments on CONE in light of the NBL upstream asset sale announcement this morning? Do you have any preferential rights there and would you have an interest in buying NBL's interest if it were available? And is there any value impact on CONE based on this change in ownership?.

Joe, I think that looking at it as an owner in CONE, the announcement today should be viewed as a bullish indicator.

And the reason we say that is that, call it, roughly half of the acreage dedication that sits there at CONE today is changed ownership and it's now in the hands of someone that I'm assuming has plans to develop it, and CONE is looking forward to working with a new customer.

So, from a growth perspective and what that means for distributions and whatnot, I think that's positive news. Beyond that, really can't comment other than what you've read and I've read out there in the public space..

Okay. Very helpful. Thank you..

You're welcome..

Your next question comes from the line of Holly Stewart with Scotia Howard Weil..

Good morning, gentlemen. Maybe the first question, just strategically. Nick, you listed kind of all the strategic options, the three strategic options, that you're looking at. And then, Dave, I think you hit on the kind of hitting the leverage targets of 2.5 times.

Should we expect some of these levers to start being pulled before or after your decision of separation? Or how do we think about the two being linked?.

I think the ability to allocate capital across either increased activity set on the E&P side or share count reduction, additional debt reduction or acreage acquisition, really doesn't so much come down to what and when we decide to do with splitting the two segments of coal and E&P.

I think it's more driven by getting that leverage ratio down to the mid- to the low-2xs. And that should be, again, something that happens sooner within 2017 as opposed to later..

Yeah. And I would just add that the coal separation can only enhance probably our flexibility..

Perfect. Thank you. And then I don't know if Don would take this one, but just on the marketing portfolio, you mentioned some of the stuff that you'd done on East Tennessee. Just some color there in terms of letting the FT roll-off those sales contracts that you've done.

I'm assuming that looks like the pie has shifted a little bit maybe due to that East Tennessee firm transport.

And then maybe an additional one to that, where does NEXUS kind of fall into those pie numbers for 2017, 2018?.

Well, Holly, we've got, with the NEXUS, it looks like there's potentially a delay there, although they're still saying it will be in service by the end of 2017, but looking more and more like there will be a delay. And we do have a bit of our FT on NEXUS. But we continue to push for a balanced FT book that keeps our costs down.

We've been able to release some capacity that we no longer need and move it off the books. But we'll continue working down that path to keep the FT under that $0.30 target that we've laid out over the last several quarters..

I think it's our ability to be able to sculpt the transportation aspect and where we ship our gas, without having to have a very rigid FT aspect of it. We allow the existing FT owner to be able to optimize his own book as opposed to us trying to fill in a whole bunch of production.

So it just allows us then to not have stranded FT or open FT, and enable an existing FTR to be able to make a win-win between both sides..

Okay.

So, maybe just to make sure we understand, you've essentially released some FT on East Tennessee, but you've entered into some firm sales contracts on that same line?.

Correct..

Got it. Okay. Thanks, guys..

You're welcome..

And we will go to the line of Neal Dingmann with SunTrust..

Morning, guys. Nick, I think a question maybe for you or David, just real quick on the asset sales.

Did that include any of the – or maybe for David, any of the existing minerals? And if not, any change in plans for the minerals that are associated with all those leases in Appalachia?.

Yes. One of the asset sales does has some fee in there as well, yes, so which enhanced the value that we we're getting. And as far as the second question, are we looking to do anything on our fee mineral position in general, which is fairly large, I'd just say, if we do, we'll announce it if we do something..

Okay. And then maybe a question for Tim, just on that slide, Tim, that slide 8 you referred to, I really like those, obviously, those revised type curves are flattening and showing the production hanging on earlier.

With that, I mean, does that change your EUR estimate? I didn't notice if it has, but it certainly appears those curves by flattening or improving, would that mean that your EURs would improve or have improved as well?.

Right now, we haven't changed the EURs on those wells. We've changed the shape of the curve by holding production flat for a longer period of time and have adjusted the decline, the B factor, on our decline, once the wells start to decline. So we have not changed the EURs at this point..

Okay. And then, just one last one on that slide, the following slide, slide 9, when you talked about on the Gaut, kind of installing the tubing.

I guess my question is just more broadly, Tim, when you guys look at some of these wells, like the Gaut or some of these other existing ones, are there going to be continuing to be a number of things like installed tubing or things like that that you can do to continue to boost that line pressure? It's certainly a noticeable increase on this one.

So I'm just wondering are there other things like that that we should assume you can do for a relatively minimal expense going forward..

Well, the tubing install, it's an expected, anticipated and managed step. We watch our critical velocities and ability to unload the wells and keep the gas flowing, and install the tubing when it's appropriate. But, obviously, there's opportunities to put wells on compression and things like that where we can continue to manage the pressure drawdown..

Very good. Thanks, guys..

Thank you..

We do have a follow-up question from Holly Stewart..

Hey, guys.

Just maybe one more because you lay out the turned in lines in 2018 was just a little bit more to the Utica? But I guess, what do you need to see to make this a bigger shift in 2018 towards the Utica?.

Well, I think that's really being driven by results, Holly. As I said, we just TD-ed the Aikens well, which is an offset to the Gaut, and so far everything up in that area has met our expectations. And as more and more results come in, we will continue our push towards the Utica.

We're laying out additional wells and we're working on our development plans as we move forward. So I think just continued results as we've seen and continued push to get more wells drilled and turned in line..

All right. Thanks, guys..

With that, speakers, there are no further questions in queue..

Okay. Great. Thank you everyone for joining us this morning. We look forward to speaking with you again next quarter. Thank you..

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The numbers again are 1-800-475-6701 and the access code is 406259. International callers may use 320-365-3844. That does conclude our conference for today, we thank you for your participation. Thank you for using the AT&T Executive Teleconference Service. You may now disconnect..