EQT Corp (EQT) 2016 Q3 法說會逐字稿

Welcome to the EQT Corporation third-quarter earnings conference call.

(Operator Instructions)

As a reminder, this conference is being recorded.

It is now my pleasure to introduce your host, Patrick Kane, Chief Investor Relations Officer.

Thank you, you may begin.

Thanks, Christine.

Good morning, everyone, and thank you for participating in EQT Corporation's conference call.

With me today are Dave Porges, Chief Executive Officer; Steven Schlotterbeck, President of EQT and President of Exploration and Production; Randy Crawford Senior Vice President of EQT and President of Midstream and Commercial; Robert McNally, Senior Vice President and Chief Financial Officer.

This call will be replayed for a seven-day period beginning at approximately 1:30 pm Eastern time today.

The telephone number for the replay is 201-612-7415.

The confirmation code is 136-376-97.

The call will also be replayed for seven days on our website.

To remind you, the results of EQT Midstream Partners ticker, EQM, and EQT GP Holdings, ticker EQGP, are consolidated in EQT's results.

Earlier this morning, there was a separate joint press release issued by EQM and EQGP.

The partnerships will have a joint earnings conference call at 11:30 today, which requires that we take the last question at 11:20.

The dial-in number for that call, if you're interested, in 201-689-7817.

In a moment, Rob will summarize EQT's third-quarter 2016 results.

Dave will discuss his retirement announcement, and finally, Steve will give a brief operational update.

Following the prepared remarks, Dave, Steve, Randy, Rob will all be available to answer your questions.

I would like to remind you that today's call may contain forward-looking statements.

You can find factors that could cause the Company's actual results to differ materially from these forward-looking statements, listed in today's press release under -- and under Risk Factors in EQT's Form 10-K for the year ended December 31, 2015, as updated by any subsequent Form 10-Qs which are on file at the SEC and available on our website.

Today's call may also contain certain non-GAAP financial measures.

Please refer to this morning's press release for important disclosures regarding such measures, including reconciliations to the most comparable GAAP financial measure.

I would now like to turn the call over to Rob McNally.

Thanks, Pat.

Before reviewing third quarter results, I want to highlight our recent Statoil Acreage acquisitions.

As a reminder, on May 6, we completed an approximately $800 million common stock offering.

At the time, a portion of the proceeds were used to fund the approximately $412 million Statoil acquisition, with remaining proceeds to be used for another acquisition of similar size.

On Tuesday, we announced acquisition of approximately 60,000 net Marcellus acres, which also includes 39,300 net Utica acres, for $683 million.

These acquisitions are consistent with the equity raised and we'll pay for using those proceeds plus the proceeds from the latest drop-down to EQM.

The signing of the recently announced acquisitions, combined with the Statoil acquisition and a few smaller deals and leasing activity during the year, bring year to date in committed investment and undeveloped acreage to approximately $1.2 billion and represent the most Marcellus under contract for acquisition by a single producer this year.

These investments are consistent with our consolidation strategy and create value through purchasing undeveloped acreage while minimizing the amount paid for flowing production, which tends to be value neutral.

This year alone, for every one acre developed, 19 acres have been acquired.

Our core Marcellus acreage has increased by 143,000 net acres, or 55%, and our undeveloped location inventory has increased to almost 3,700 locations.

Much of this acreage is contiguous with EQT's existing development area.

Therefore, the lateral lengths of 190 existing EQT locations can now be extended from approximately 3,000 feet to 6,000 feet on average, and a flat $2.50 realized gas price see IRRs on these wells increase from approximately 9% to 37%.

Effective October 1, EQT completed the final drop of Midstream assets to EQT Midstream Partners for $275 million.

The drop included the Allegheny Valley Connector, a transmission and storage system, along with several Marcellus gathering systems.

The sale did not include a small gathering system that is currently being evaluated for potential sale, which would bring total proceeds above $300 million.

As a reminder, the [Sheerin] Gathering System will be folded into EQT Production and Midstream results will solely reflect the results of EQT Midstream Partners, which will still be consolidated into EQT Corporation's results.

I will now give a brief overview of the quarter.

As you read in the press release this morning, EQT announced third-quarter 2016 adjusted loss of $0.26 per diluted share, which represents a $0.06 per share decline from adjusted EPS in the third quarter of 2015.

Adjusted operating cash flow, attributable to EQT, increased by $19.3 million to $167.7 million for the quarter.

EQT Midstream Partner and EQT GP Holdings' results are consolidated in EQT Corporation's results.

EQT recorded a $78.1 million of net income, attributable to non-controlling interests in the third quarter of 2016.

We currently forecast $320 million of net income attributable to non-controlling interest for the full-year of 2016, assuming the midpoint of EQM's guidance.

The operational story for the third quarter was strong volume growth and a low commodity price environment.

We had another very solid operational quarter, including record produced natural gas sales and record volumes at Midstream.

The third quarter was very straightforward so I'll keep my remarks fairly brief.

EQT production continued to grow sales of produced natural gas.

Production sales volume of 196 Bcfe, which included 3.5 Bcfe from the Statoil acquisition and the recently completed quarter was 26% higher than the third quarter of 2015.

The lower average realized price more than offset the volume growth.

The average realized price of EQT Production was $2.20 per Mcfe compared to $2.55 in the third quarter of last year.

You will find a detailed components of the price differences in the table in this morning's press release.

Net marketing service revenues totaled $5.3 million in the third quarter of 2016, which is relatively flat for the same period last year.

Total operating expenses at EQT Production were $524.6 million, or $49.7 million higher quarter over quarter.

DD&A, gathering, transmission and processing expenses were all higher, consistent with the significant production growth, although production taxes and exploration expense were lower for the quarter.

Moving on to the Midstream results in the third quarter.

Operating income was $132.7 million, up 17% over the third quarter of 2015.

Operating revenue was $214.3 million, $15.8 million higher than the third quarter of 2015, as a results of higher Marcellus volumes.

Total operating expenses at Midstream were $81.6 million, $4 million lower over the same period last year.

On a per unit basis, gathering and compression expenses were down 17% as a result of higher volumes.

And finally, our standard liquidity update.

We closed the quarter in great shape, with zero short-term debt outstanding under EQT's $1.5 billion unsecured revolver and $1.8 billion of cash on the balance sheet, which excludes cash on hand at EQM or EQGP.

Pro forma for the acquisitions I mentioned earlier and for the funds received from the drop to EQM, the cash balance would have been approximately $1.35 billion.

We currently forecast approximately $750 million of operating cash flow for 2016 at EQT, which includes about $150 million of distributions from EQGP.

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

Great.

Thank you, Rob.

I only have one topic in my remarks.

I was going to talk about the Cubs but Pat Kane discouraged me from doing so.

So my only topic today pertains to my announcement of my intention to retire as CEO early next year and transition at that time to the role of Executive Chairman.

It has been my honor to serve as an Executive Officer of EQT Corporation for nearly 19 years, including being CEO since early 2010.

When my tenure as CEO began, EQT was already a well-run shareholder value-focused Company.

However, it did seem important to elevate the importance of our financial strategy for a period of time and that was a central focus of my tenure.

During these nearly seven years as CEO, we have created additional value via the creation of two new public entities, several new transactions between EQT and those entities, sales of non-core assets and acquisition of assets complementary to our core business.

We also raised sufficient capital to fund our value of accretive growth, and maintain a strong credit position through a very difficult time in our industry.

Along the way, we made a variety of commitments to our investors and I believe that the recently announced Midstream drop and Upstream acquisitions honor the commitments that we made.

That said, while financial strategy will always be important, it no longer needs to have the outsized roll-head during much of my time as CEO.

In a sense, therefore, I believe that my work here is done.

On a personal side, as many of you are aware, I do have a variety of other interests, with my family being first amongst them, but various not-for-profit endeavors also being increasingly important to me.

Even as we have achieved much of what I set out to accomplish as CEO, these other interests and priorities have exerted an increasing tug on my thoughts and energies as I look to make a difference in other ways.

Putting that another way, as much as I have enjoyed the past 19 years and is proud as I am at what we have accomplished at EQT, there are other things that I want to do with my life that are tough to do when one is a full-time executive at a publicly-traded company.

So no matter which way one looks at it, this is a good time to hand over the reins.

Steve Schlotterbeck is well-suited to be the next Chief Executive Officer.

His pairing of strong, analytical skills, with a nurturing of a culture of innovation are just what the Company needs as it moves into the next phase of value creations.

These recent value accretive acquisitions are a clear example of his leadership as are the combination of operational focus and scientific and technological innovation that he has brought to our Company-wide focus on creating shareholder value.

I am confident he will do well and investors will do well with him at the helm.

Finally, I have actually enjoyed most of my interactions with investors and analysts.

Thank you for your support and insights over the years and with that, I will turn it over to Steve.

Thank you, Dave.

Good morning, everyone.

I want to start by saying what a great honor it has been to be chosen to succeed Dave as CEO of EQT Corporation.

And I am humbled to be entrusted with the responsibility to lead this great organization forward.

EQT's future is bright, thanks to the transformative leadership of Dave Porges.

His vision, financial acumen and leadership abilities have fundamentally changed EQT, positioning us at the forefront of energy development and keeping us well-positioned to face future challenges and opportunities for years to come.

EQT has endured one of the industry's most challenging periods of cyclical uncertainty, primarily because of our stringent focus on cost, our strong balance sheet and our uniquely integrated business structure.

The combination of our outstanding Upstream and Midstream assets, together with strong financial management and operational nimbleness, will enable us to continue creating and delivering value for EQT shareholders.

Maybe the most important reason I am so confident in EQT's future is the strong and dedicated leadership of our Board and executive team and the continued commitment of the most talented employees in industry.

This is an exciting time to be a part of this Company and this industry and I'm excited to be a part of it.

Now let's continue with the review of our recent core Marcellus acreage acquisitions and our current thoughts on our deep Utica program.

Starting with our Marcellus acreage acquisitions, as Rob mentioned, we announced the acquisition of an additional 60,000 core Marcellus acres this week.

Year to date, we have added 143,000 core acres, including 63,000 from Statoil and 20,000 through smaller deals and leasing efforts during the year.

More importantly, is that since 2013, we've added 230,000 core Marcellus acres.

We have completed 477 wells over the same time period, developing 44,000 acres.

The net result is an increase in our core undeveloped acreage of 186,000 net acres, for roughly 1,950 net incremental locations.

We have heard some of the rumors recently about inventory constraints at EQT.

Simply put, we are not inventory constrained.

We will continue to fill in gaps and look at bolt-on acquisitions but with this week's acquisitions, we have achieved our near-term acreage acquisition goals.

Moving to the deep Utica.

We continue to make progress on our deep Utica testing efforts.

We are becoming more confident that we will achieve a combination of lower costs with higher EUR per foot that will result in similar, if not better, economics to our core Marcellus economics.

As we mentioned last quarter, we have already lowered cost down nearly to our target range of $12 million to $13 million per well.

Based on our progress, we think that we will reach our target range soon.

We have also seen an improvement in productivity from changes we have made to our frac design on the last two wells.

Given our well cost expectations, we think we need between 3 Bcf and 3.5 Bcf per 1,000 feet of pay to achieve returns which are competitive with our Marcellus opportunities.

We are not there yet but we aren't far off and are certainly encouraged by our progress.

Our current thinking is that you should expect a one rig deep Utica program in 2017, drilling between six and eight wells.

We believe this level of drilling will allow us to achieve our cost and productivity objectives as well as begin delineation of the economic extent of the deep Utica, with the goal of establishing a deep Utica development program in 2018.

As far as progress reports, we believe it's in our shareholders' best interests not to share specifics of our techniques or results, as we are currently the only Company investing in the deep Utica.

Before moving into development mode, we need to ensure that we can effectively move the gas so we've been working closely with our Midstream Group on gathering system designs.

Based on pressures and the production profile of the deep Utica, our initial estimate is that per-unit gathering costs for deep Utica would be about half that of the Marcellus.

In summary, we continue to make solid progress on both the cost and recovery efforts and we are encouraged that the deep Utica can compete with or surpass our core Marcellus economics in the near future.

I will now hand the call over to Pat.

Thank you, Steve.

This concludes the comments portion of the call.

Christine, would you please open the call up for questions?

(Operator Instructions)

Holly Stewart, Scotia Howard Weil.

Let me give my -- be the first to give my shout out to Dave.

Dave, very many accomplishments over certainly my 12 years in covering the stock.

I'm not sure another company has changed in so many ways, so a much deserved retirement.

Thank you.

Maybe starting off, Steve, you were running through that fast.

Can you give me the -- you said one rig may be dedicated next year.

What was the amount of wells drilled?

6 to 8 wells with that one rig.

Okay, great.

And then maybe just following up on the three acquisitions that we've talked about for 2016, I know there is some midstream contracts that you are working through on the Statoil deal, but can you maybe just talk to us about how you're thinking of development there and maybe priorities in terms of those properties?

I think in terms of how we will develop that, we will incorporate that acreage into our land process and we will allocate capital based on the best returns available, starting in our 2017 plan, which we will talk about in December.

But I will say, one of the main drivers behind all of these acquisitions is our desire to extend laterals, and part of that then requires us to go re-permit a lot of the existing locations to take advantage of those synergies.

So there is a bit of a delay before we get immediate benefits from the acquisitions.

So it will probably be mid-2017 before a significant portion of our development program is incorporating the new acreage.

But we don't want to drill short laterals when we can take a few months and go back and re-permit and get the better economics.

So you will start to see benefits from the acquisitions next year, but it will probably be the back half of the year before we really get full speed ahead.

Great, that's helpful.

And then maybe just one last one for me: It looks like this is the first time you guys have stripped out the ethane volumes, maybe just a little color here.

Has there been a shift in strategy on extracting ethane or how should we be thinking about that?

Good morning, Holly.

This is Randy.

As I have said in the past with respect to ethane, we are opportunistic in extracting ethane.

To the extent that the opportunity presents itself that we can extract the ethane and sell it above the methane pricing, we are taking that opportunity, and we have 10,000 barrels a day of capacity that allow us that.

So we broke that out to demonstrate that.

Okay, so don't necessarily think about this as a go-forward?

It's a one-off quarterly opportunity?

Well, no.

It is basically on market conditions.

So as we extracted the higher BTU gas, to the extent that it's in EQT's best interest to extract the ethane and sell it into the capacity, we will do that.

Otherwise, we will sell it for methane prices, and the market has, with the improvement in ethane recently, it has been a core part of our Business to go ahead and extract the ethane to increase value to the shareholder.

Holly, I would just add that this capacity, the 10,000-barrel capacity Randy mentioned, came on in the second quarter.

Perfect, thank you.

Understood, thanks, guys.

Brian Singer, Goldman Sachs.

Dave, congrats on your retirement, and, Steve, congratulations on your new role here.

The press release referenced the transition towards more operational drivers from financial drivers.

I wanted to see if perhaps in that context Steve could discuss perspective on the importance of integration?

And, Steve, how you view leverage versus liquidity versus outspending cash flow at the E&P and midstream level?

First, on the integration, at the current time, we think we generate significant benefits from the ability to work -- the two businesses working together.

I think we do have a view that over the long term, the benefits received from that versus the benefits of separation might be outweighed by separation.

But I think, certainly in the short term, we continue to think that the combination of the two businesses makes the most sense for our shareholders.

The second question around leverage and liquidity and outspend, I think, as you've seen through this downturn, we appreciate the value of a strong balance sheet.

We have historically, I think it's really a legacy from our utility days, but we have been an investment grade-rated company.

I think we continue to view that as valuable.

So I think you'll see continued focus on keeping our balance sheet strong.

I think we have a number of levers available to us to fund and outspend, if we think that's the prudent path forward, particularly the -- our large stake in EQGP is available to us to sell down to fund an outspend.

But I would say, generally speaking, to grow at competitive rates does typically require a bit of an outspend.

So I would think that is likely in the future, but it all depends on what we think the economics of our opportunities are.

So I think I will leave it at that.

That's great, and very helpful.

My second question is also somewhat strategic.

A year ago and maybe eight months ago, we had a lot of questions on the potential for EQT to expand in Appalachia, and you've done a couple of acquisitions that you've referred to here.

And I wondered whether you think you are at the asset and size and scope that you think is reasonable going forward?

Or whether we should expect that you will continue to be active in considering further consolidation opportunities in the basin, and if so, what that scenario -- what that looks like, what that market looks like?

Well, I think there's two ways to answer that.

First, as it pertains to size and scope, I think we feel very comfortable where we are at.

We have a very deep inventory and the ability to grow at competitive rates for quite some time.

So I think we're not going to be driven by a desire just to gain scale.

That said, one of the biggest value-creating opportunities we see in Appalachia is the efficiencies we get from drilling longer laterals.

So the acquisitions we've done to date are designed to allow us to drill longer laterals and get those efficiencies and drive the unit cost down.

And to the extent that opportunities become available that fit our acreage well and allow us to gain those synergies, I think we will continue to be interested.

Subject to the comments I just made about liquidity and balance sheet strength, we're not going to stick our neck out to do that.

But if there are opportunities to continue to put large blocks of acreage together to allow us to drill longer laterals, then we would be interested in taking a look.

Great, thank you very much.

Arun Jayaram, JPMorgan.

Congratulations to you both.

I wanted to start off perhaps, Steve, in talking about the acquisitions.

Obviously, it appears that one of the drivers was just increasing the ability to drill longer laterals, and we did note that this quarter your laterals were, at least on the Marcellus side, were pushing close to 9,000 feet.

But from a geological basis, can you talk about the quality of this acreage relative to your current core in terms of gas in place?

Thoughts on potential EURs and how does this acreage that you've added in this deal, plus the Statoil deal, compare to what you have previously?

Well, I think, yes, we are very happy with the quality of the acreage in all three of these deals.

Specifically, Statoil and Trans Energy are West Virginia-focused or all in West Virginia, all very connected to the acreage we already have in Wetzel and Marion Counties, and Tyler County, and we think very consistent with the results we have seen down there.

Specifically because I think I had seen a question or two about Marion County, I think there has been less drilling there and some of the competitor results may be -- are a little bit less than a little bit further to the West.

I can tell you, we turned in line six wells in Marion County in April of this year, and all six are exceeding our tight curve for northern West Virginia.

So I don't know if that is a result of the acreage we have, and the Trans Energy acreage is directly connected to the acreage where those wells were, or if it's different completion techniques or exactly why.

But as a result, we are very encouraged by that portion of Marion County, which I would imagine is probably where, if you were going to speculate on the acreage, that would be where the concerns might be.

From the data we have, we are very excited about it.

Just from a lease expiration standpoint, could these deals cause you to maybe run faster a little bit just to make sure that you lock up the acres, or how does that influence your plans in 2017 and 2018?

I think in 2017 and 2018, it will have very little influence.

The vast majority of the acreage we got that's not held by production doesn't have expirations until 2019 and beyond, which is one reason we like these -- very little near-term expirations.

I would say if it does affect our development plan, it won't probably -- that factor won't drive the pace.

It might drive the -- how we select locations.

So we might have a preference for pads that hold acreage versus pads that are already held.

I think the pace will be driven more by economics and our liquidity position.

Okay.

If I could sneak in one more, just on the Utica program, it sounds like the last two wells that you have completed have maybe improved your bias or your thoughts around the deep Utica.

I think ceramics, we're seeing, may be -- on the previous calls, it may be an enabler.

But can you just talk a little bit about what has changed the improving well productivity, but maybe a little bit about what's improved in terms of the overall deep Utica program versus your prior call or two?

As I said, we don't want to give out any specifics on what we're doing, since right now we're -- I think we're the only Company -- perhaps one other is investing a little bit in the deep Utica.

But the one factor we have talked about in the past that I will comment on is the type of proppant.

We started with ceramics.

We had a view that maybe sand would work, and at the time would be significantly cheaper than ceramics.

We switched over.

Those next couple of wells were significant underperformers from the Scotts Run, and then we switched back to ceramics for the last couple of wells and they were significantly better than the wells with sand.

And each subsequent -- those two wells have gotten us much closer to the target recoveries that we think we need.

So I think ceramic does play a big role.

Our current plan is to use ceramics for all wells in the future; and fortunately, we have also been able to cut the costs of the ceramics basically in half from the first well, so that also helped on the economic side.

Beyond that, I will say we have been doing a lot of technical work on our drilling and completion techniques.

The typical stuff you would think about, types of sand, loading schedules, pump rates, targeting in the reservoir, all that kind of stuff.

And I think as we drill wells and learn more, just as we saw in the Marcellus, we're seeing continuous improvement.

That is one of the reasons we want to spend the next year basically doing one well at a time, so we can try new techniques, learn from them, apply them to the next well and not get too far over our skis.

But we do think with another six or eight wells, we will be in a position where I think we'll -- I am confident we will have the costs where they need to be.

I'm pretty confident that the recoveries will get into that range that we think we need, and hopefully we will also have a chance to delineate the extent of the economic area of the Utica.

Okay, that's very helpful, thank you, Scott.

Dan Guffey, Stifel.

I'll echo my congratulations.

I'm just curious, other operators in West Virginia have been touting productivity gains from completion optimizations.

Have you even discussed elevated type curves?

I'm just wondering if you can talk about how your West Virginia Marcellus completions are evolving?

And should we expect to see a change in the average per-foot productivity or an increase in the type curves across that core area, and if any of these gains could influence your 2017 guidance?

Yes and no.

The one thing I will say is we recently adopted a new standard frac design that uses considerably more proppant per foot.

Based on some very early tests and a lot of reservoir modeling, we do expect this new technique to yield higher NPV per acre and per well.

We probably won't increase our type curve until we have sufficient production history from a number of wells to confirm the results.

And we just started that in a broader way two or three months ago.

So it will take quite a few more months before we have wells online with production history.

So if it plays out the way we expect, we would expect an increase in the type curve, but I don't think it's going to happen in the next couple of quarters.

Okay.

Is that just in West Virginia or are you seeing anything in Southwest PA as well?

That is actually in both areas.

Across our whole core position, we are adopting a technique with more sand.

Okay, great.

And then, it looks like firm transportation volumes are obviously increasing to the Midwest, and it looks like that's going to continue to grow throughout most of 2017.

Just curious what types of increase in transportation should we expect to see into 2017?

I'm sorry.

You were talking about how much transportation and additional capacity that we have?

Correct, yes.

It looks like additional volume is moving into the Midwest.

With the completion of the OVC, we now have additional assets, as you know.

We'll be moving up to about 650 million a day over the next few months; and depending on the market conditions, could move even more going forward.

Should we expect to see a per-unit increase in transportation expense moving forward as those volumes increase?

Those volumes and those capacity commitments are fixed in nature, so essentially you will see that, but net, in terms of realized prices, we should see an increase in our realized price.

In fact, from an EQT perspective, we're taking action to ensure that we're building the pipelines to get higher realized price.

The transportation cost per unit, but net realized prices should be increasing, obviously.

Okay, great.

And then one last one on efficiencies.

I see you guys are running three top-hole rigs and three Marcellus rigs.

Just wondering if you can discuss any efficiency gains made over the last year, and then currently how many wells per year can a single horizontal rig drill with the top-hole rig running ahead of it?

First, on the efficiencies, just a couple of stats.

Year-to-date 2016 versus 2015 actual data on a dollar per 1,000 foot of pay, we have seen about an 18% improvement.

So from $1,100 -- a little over $1,100 per foot to a little over $900 per foot in 2016.

Our current thinking as we're starting to put together a business plan for 2017 is that we should expect to see a further reduction in that cost or further improvement in efficiencies.

A lot of that will be driven by longer laterals that we expect to be able to drill in 2017.

And on the number of wells per rig top-set, I actually don't have that number.

I would guess it's probably 20?

If we top set them, we could drill 20 wells with a big rig per year.

Okay, thanks for all the color, guys.

Neal Dingmann, SunTrust.

Congrats.

Steve, just one general question here.

Obviously, now when you look at that core rectangle that you guys always break out when you include now all this additional great acreage you picked up, how much variation do you see in returns?

You have a pretty big swath there from all the way from Allegheny down to Doddridge?

I'm just wondering in broad terms if you assume somewhat similar D&C techniques, how much do you anticipate the returns that are in there?

Neal, we actually see very little variability in the bulk of that rectangle.

One little exception potentially is once you get north of Pittsburgh, you will see the rectangle goes up there into southern Butler County and Armstrong County.

Those returns are not quite as high, and we're not really focused drilling up there, but there is consolidation opportunities potentially, with long enough laterals, they can be competitive.

But with that exception, the returns are pretty equivalent.

We get a little of the liquids benefit in the majority of West Virginia that we don't get in Pennsylvania, and that tends to offset a small productivity advantage that Greene County, Pennsylvania, has.

And then, Steve, just lastly, how much different completion design, maybe besides the 10,000 foot lateral you said you'd prefer on most as far as sand and different things you're using there on these Marcellus.

Is there much variability there?

No, our design actually has become more standardized across that core area than I would have expected.

It varies a little bit, but not a whole lot.

Thank you.

We have no further questions at this time.

I would now like to turn the floor back over to Management for closing comments.

Thank you, everybody, for participating, and we will see you on the next call in February.

Ladies and gentlemen, this does conclude today's teleconference.

You may disconnect your lines at this time.

Thank you for your participation and have a wonderful day.