EQT Corp (EQT) 2017 Q1 法說會逐字稿

Greetings, and welcome to the EQT Corporation First Quarter 2017 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, sir.

You may begin.

Thanks, Christine.

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

With me today are Steve Schlotterbeck, President and Chief Executive Officer; Rob McNally, Senior Vice President and Chief Financial Officer; David Schlosser, Senior Vice President and President of Exploration and Production; and Lisa Hyland, Senior Vice President and President of Midstream.

This call will be replayed for a 7-day period beginning at approximately 1:30 p.m.

Eastern Time today.

The telephone number for the replay is (201) 612-7415, with a confirmation code of 136-50780.

The call will also be replayed for 7 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 a.m.

today, which requires that we take the last question at 11:20 a.m.

The dial-in number for that call is (201) 689-7817.

In a moment, Rob will summarize EQT's first quarter 2017 results, and Dave will give a brief operational update, followed by comments by Steve.

Following their prepared remarks, Steve, Rob, Dave and Lisa will be available to answer your questions.

I'd 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 Risk Factors in the EQT's Form 10-K for the year ended December 31, 2016, 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.

With that, I'd like to turn the call over to Rob McNally.

Thank you, Pat, and good morning, everybody.

Before reviewing first quarter results, I want to highlight our recent acreage acquisitions.

During the quarter, we completed 2 acquisitions adding 67,400 core Marcellus acres for $652 million, funded with cash on hand.

We've been very active consolidating our acreage position in our Marcellus core, increasing our position by over 222,000 net acres, which represents the most Marcellus acres acquired by a single producer since 2015.

On the pricing side, we have seen significant improvement throughout our various markets.

The average realized price, including cash settled derivatives, was $3.50 per Mcfe, a 33% increase compared to the $2.63 realized in the first quarter of last year.

The stronger pricing environment was also reflected in our average differential for the quarter, which was negative $0.13 per m. This is a $0.54 improvement from the fourth quarter of 2016 and a $0.09 improvement from the first quarter of 2016.

The improved pricing also highlights the value of our diversified firm capacity portfolio, which provides significant takeaway capacity to premium markets.

During the quarter, additional contracted capacity and higher utilization of this capacity to move our gas to these markets resulted in both higher realized price and higher transportation cost for the quarter compared to our guidance.

We expect continued improvement to our realized price as incremental pipeline projects come online, including the MVP pipeline, which will provide access to the premium Southeast market.

As you'll see in our updated slide deck, we expect our basis to improve from negative $0.25 in 2017 to negative $0.13 in 2019, based on forward pricing at our markets.

I'll now provide a brief overview of the first quarter results.

As you read in the press release this morning, EQT announced first quarter 2017 adjusted earnings per diluted share of $0.43 compared to $0.05 in the first quarter of 2016.

Adjusted operating cash flow attributable to EQT increased to $322 million as compared to $217 million in the first quarter of 2016.

As a reminder, EQT Midstream Partners and EQT GP Holdings' results are consolidated in EQT Corporation's results.

EQT recorded $86.7 million of net income attributable to noncontrolling interest in the first quarter of 2017 compared to $82.7 million in the first quarter of 2016.

Starting with production results.

Production sales volume of 190 Bcfe for the first quarter was 6% higher than the first quarter of 2016, which was on the low end of our guidance as we completed fewer wells than we had planned for the first quarter.

As discussed, the realized price, including cash held derivatives, was $3.50 per Mcfe, a 33% increase compared to the $2.63 in the first quarter of last year.

Operating revenues totaled $828.7 million for the first quarter of 2017, which was $345 million higher than the first quarter of 2016.

Total operating expenses at EQT Production were $571.2 million or 17% higher quarter-over-quarter.

Transmission expenses were $43.4 million higher due to volumes moved by Rockies Express Pipeline and Ohio Valley Connector.

We were paying for some REX capacity last year, but since we were unable to physically move our produced gas to REX in the first quarter of 2016, we used that capacity for marketing.

When we use pipeline capacity for marketing, we net the cost of the transportation against the recoveries realized.

The cost of the pipeline capacity used to move our produced gas is recognized as an operating expense.

The increased transportation expense this quarter was largely due to us using more of our own transportation capacity to move our gas, driving higher transportation cost and higher realized prices.

Processing expenses were $16.7 million higher, consistent with higher wet gas volumes.

Production taxes were $6.2 million higher as a result of better pricing.

Gathering expenses and DD&A were all higher, consistent with production growth.

Excluding a legal charge of $5 million, SG&A was essentially flat, while lease operating expense, excluding production taxes, were $1.6 million lower.

Moving on to midstream, EQT gathering income was $73.6 million, $1 million higher than the first quarter of 2016 on increased gathering revenues, partly offset by increased operating expenses.

Total operating expenses were $28.7 million or $3.3 million in 2016 (sic - see press release, "a $3.3 million increase ").

Looking at EQT Transmission, operating income was $71.5 million, 11% higher than the first quarter of 2016.

Operating revenues were $13.3 million higher over first quarter 2016, primarily due to EQT's firm commitment on the OVC, or Ohio Valley Connector, which was placed into service on October 1, 2016.

Operating expenses were $29.6 million or $6.3 million higher than the same quarter of 2016.

And then finally, our stated liquidity update.

We closed the quarter in a great liquidity position with 0 net short-term debt outstanding under EQT's $1.5 billion unsecured revolver and about $857 million of cash in the balance sheet, which excludes EQM.

We currently forecast about $1.3 billion of operating cash flow for 2017 at EQT, which includes approximately $200 million of distributions to EQT from EQGP.

So we are fully capable of funding our roughly $1.5 billion 2017 CapEx forecast, excluding EQM and EQGP, with that expected operating cash flow as well as the current cash we have on hand.

Okay, with that, I will turn the call over to David.

Thanks, Rob, and good morning, everyone.

For those of you that I have not met, I am David Schlosser, and I was appointed President of EQT's Production business unit in March of this year.

I've been with EQT for 10 years and have been employed in the oil and gas industry for about 29 years, with the majority of my time spent on the operations side.

I most recently managed the engineering, geology and planning functions for EQT Production, and I have been involved with the growth and expansion of EQT's Marcellus and Utica development program since inception.

I will now make some comments about the quarter.

As Rob mentioned, our sales volume for the first quarter was at the low end of guidance at 190 Bcfe.

This was primarily driven by completing 0 wells in plan, as we did not add frac crews as quickly as anticipated due to the tighter-than-expected market.

We are, however, reiterating our full year guidance and have additional frac crews scheduled to come on at the beginning of June, at which time we expect to quickly get back on track with our 2017 turn-in-line schedule.

Our business plan also anticipated sales volumes to be flat Q2 versus Q1.

We are now projecting Q2 sales volume between 190 and 195 Bcfe.

Our 2017 growth will be back-end loaded as we expected, and we will exit 2017 at approximately 2.6 Bcf per day.

As you saw on today's news release, we recently increased our EUR estimates for our core Marcellus by 14% to 2.4 Bcfe per thousand foot.

This reflects enhancements to our standard frac design, which among other things, increase the sand and water per foot of pay.

We continue to experiment with even larger frac jobs, which we expect will increase the effectiveness and efficiency of the fracs.

At this point, however, it is too early to know if the economics will be improved, because as you may expect, with bigger jobs come higher costs as well as impact to lateral spacing.

We are confident in our technologies and methodology, and we'll provide update as our progress continues.

On the last call, Michael Hall asked about our well results in the dry Marcellus window in West Virginia.

We currently have only 10 wells producing in Marion in eastern Wetzel County, but our preliminary EUR estimate for this area is 2.4 Bcfe per 1,000 foot, which is consistent with our average EUR for our core development area.

We are very encouraged by this productivity.

Finally, an update on our Utica program.

As we've indicated during previous calls, we continue to work in understanding the reservoir and improving costs and have decided to not share individual well results as we move along.

We have completed the Big 177 well in Wetzel County, West Virginia, and it is online.

Our 2017 plan calls for drilling 7 wells, and we are currently drilling the Moore well in Greene County, PA, and should have that well online in the second quarter.

After we TD the Moore, we will move the rig to Armstrong County, Pennsylvania, to drill the next Utica well.

With these test wells, we are getting a better understanding of the production mechanisms, recoveries and the economics of Utica, which was our overall goal of the 2017 program.

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

Thanks, David.

Good morning, everyone, and thank you for joining us.

With this being my first call as CEO, I want to take a few minutes to comment on my strategy for EQT.

I've been on the management team for many years and have been an active participant in shaping and implementing our strategy, so in many ways, it is a continuation of the strategy that EQT has been successfully executing.

The one thing I'm most proud of as a member of the management team is EQT's history of focusing on creating shareholder value.

From our large share buyback program in the early 2000s, the sale of our LDC business in 2013 to our creation of EQM and EQGP and our current consolidation efforts, EQT has always focused on creating long-term shareholder value.

I assure you that I will continue to focus on doing what is best for the long-term benefit of our shareholders.

We are blessed to have an outstanding set of assets in one of the largest and most economic natural gas basins in the world.

We are already the largest gas producer in the Marcellus and the fourth largest in the U.S. We also have the largest midstream business in the Appalachian Basin.

There are tremendous synergies between the 2 businesses that we have leveraged for the benefit of EQT, EQM and EQGP investors.

As you probably know, I believe there are significant benefits to consolidation in our core development areas.

Over the past decade, we've made tremendous advances in operating efficiencies by focusing on finding ways to improve how we drill and complete our wells.

These improvements have dramatically lowered the per-unit cost of the gas we develop.

Unfortunately, these improved techniques are easily transferred between producers and the advantages gained are short lived, as other producers adopt the same best practices.

So while our development and operating costs have improved dramatically, the economic value added has not increased in concert as the supply of gas increased, pushing gas prices down.

The next wave of efficiencies will come from consolidation of the scattered acreage positions in Appalachia.

This consolidation will drive longer laterals, more wells per pad, improved water and operating logistics and more efficient gathering and transmission pipelines.

These advantages will be more difficult to replicate and the consolidators will hold a competitive advantage that will yield higher returns for their shareholders.

I think further consolidation within the Marcellus core is the best path to creating a sustained competitive advantage, increasing shareholder value.

To date, we've been very successful implementing this strategy and we are beginning to see the value creation from it.

We've added over 220,000 core Marcellus acres since the beginning of 2016.

Our focus is on adjacent acres to what we already own and has facilitated an increase in average lateral length of our Marcellus wells from 5,900 feet in 2015 to over 8,000 feet in 2017.

As you can see in our slides, at a constant $2.50 local gas price, adding 2,000 lateral feet increases returns from 39% to 52%.

As we continue to consolidate, I think it is realistic for us to get to a point where we are drilling 10,000-foot laterals, increasing returns at the same gas price to 62%.

Our midstream business also benefits from our consolidation efforts.

By increasing our inventory, the runway for midstream investments supporting production gets longer.

This opens the door to build gathering systems and makes MVP expansion and interstate pipes further south more likely.

As we implement initiatives to strategically expand our footprint and drive stronger returns, we remain squarely focused on innovation throughout our operations.

I am proud of our culture of innovation at EQT, and we are focused on leveraging that to continue to improve safety, reduce operating costs and improve returns on our investments.

In my opinion, the commodity price cycles are here to stay and we need to be profitable throughout the cycle.

Our continued focus on innovation will enable us to achieve these objectives.

I thank you for your continued support as shareholders of EQT, and I'll now hand the call over to Pat Kane.

Thanks, Steve.

Christine, you could open the call to questions.

(Operator Instructions) Our first question comes from the line of Phillip Jungwirth with BMO.

How dependent is the 15% to 20% growth target through 28 -- 2018 to 2020 on the targeted in-service date for Mountain Valley?

And realizing you're still on schedule today, but if timing were to slip by, say, 6 months, would this alter growth plans at all?

Or would you just anticipate selling more gas to [M2] and having lower realizations in transportation costs?

Yes, Phillip, I don't think the timing of MVP, although I will reiterate, we still expect to be on target for an end of '18 turn in line.

But if delays would happen, I wouldn't expect it would affect our growth rate at all.

I think you nailed it.

It would affect our netbacks in that time period, from end of '18 until turn in line.

A little bit we would sell more gas locally, but -- which shouldn't affect our growth rates at all.

Okay, and then just following up on that, the Mountain Valley delivery point, as you guys note, is trading at NYMEX or really a premium to NYMEX.

Wondering if you have any expectations for basis once Mountain Valley comes online and an additional 2 Bcf a day of gas is sold there?

Yes, Phil, I think -- so we, obviously, expect there to be an impact once we deliver that kind of gas to that point.

And there are a range of estimates from various services that are out there.

I think our best view is something close to parity with NYMEX is what we're expecting, perhaps a few cents below NYMEX.

But there are some services that think it could continue to trade at a premium.

So I think we're trying to take a bit of a pessimistic view and hope it ends up better than we expect.

Okay, great.

And then, one of your Appalachia peers recently entered into a processing joint venture as it looks to expand its wet gas capacity and then -- almost half of your undeveloped Marcellus locations are wet gas.

So just 2 questions, one, if you could just speak to your current processing capacity and utilization?

And then two, would you look to expand this and is a joint venture an option?

Yes, so if I think -- so we saw that announcement, and I thought that was actually a pretty brilliant move on their part.

With our recent consolidation efforts focused on -- not necessarily focused on, but ended up being more wet gas and as we reconfigure our future development plans to take advantage of those acquisitions, we are now forecasting to be wetter than we otherwise were.

And I think as a result, now as we look out in the future, we think we probably have enough scale to consider opportunities like that.

Probably not necessarily going into it on our own, but something maybe similar to the deal that you described, where we enter into a joint venture to provide some investment opportunities for EQM.

Our next question comes from the line of Arun Jayaram with JPMorgan.

I was wondering if you could provide a little bit more color around the frac crews.

And just -- it sounds like you had some challenges in getting some startups, just maybe give us a sense of how many crews do you have deployed today?

And what will happen as we think about the back half, I think, you cited maybe some additional crews around midyear?

Yes, this is David.

So the story is, I think, as you know we had reduced activity in 2016, as we began the ramp up in late 2016 and early '17.

We discussed -- we chose to be selective about who our service providers would be and we were trying to pair the right mix of quality and price and the market tightened up I think, as everybody knows, quicker than we expected, driven a lot by Permian activity.

But so we've been running 2 to 3 crews in the first quarter.

We think by June, we'll be at 6, ramping up to 7 sometime in the third or fourth quarter and that's how we'll finish out the year.

But like I said, we made a conscious decision not just to jump at the first deal that was out there, and we're a bit selective and we'll be ramping up by mid-year.

And Arun, one more bit of color on that.

Our contracts with our frac suppliers had penalty clauses that if they decided to leave, they would owe us some money, similar to the kind of contracts we've had with drilling companies, where during the downturn, we elected to pay the penalties and released the rigs.

A couple of our frac contractors decided to pay us the penalties to take their frac crews to jobs that were more profitable.

So we will get some penalty fees, but that, obviously, is far less than the value of having the wells fracked on the schedule that we would have liked.

But that said, I think we feel good that by the beginning of June, we will have enough frac crews running to confidently tell you that we're going to make our full year guidance, which obviously then projects a pretty dramatic increase in production in the second half of '17.

And you guys cited, is it a 2.6 Bcfe per day kind of exit rate?

Is that what you're calling for the year-end exit rate?

Or more of a fourth quarter kind of average?

Yes, it's pretty much a fourth quarter average.

To the 2.6 Bcfe?

Yes.

Okay, great.

And just going back to the addition of the frac crews, can you comment on any greater inflationary pressure that you're seeing as you're ramping out and what looks to be a much tighter services kind of environment?

Yes, well, certainly, we did see inflation and we've built that in to our numbers.

I think when we issued this new IR presentation, it was built on a 15% service price increase.

So we've built in what we think we are seeing and what we are going to see for the remainder of the year.

So it's in our numbers now and hopefully, we're past the worst of it.

This is Rob.

I think that the frac pricing is probably going to be up more than that 15%, but that's offset some by actually declines on the drilling side because we had some older rig contracts with high prices that rolled off.

So that's kind of a blended number across all the services.

Fair enough.

And my final question, just looking at the cost structure on a cash cost per-unit basis, you did kind of raise the guide by about $0.07.

A lot of that was kind of on the third-party gathering and processing side.

Could you just talk about what drove that?

And maybe some opportunities on a go-forward basis to take those costs down over time?

I think a big part of that is the processing costs because of the acquisitions that we've done and the mix of wet and dry gas has gotten a bit wetter for us.

And so processing costs go up, but then, so do realizations.

And some of it is also due to transportation, where we're using more of our capacity to transport our gas as opposed to using it for marketing purposes, which again also it increases transportation cost, but also increases realizations.

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

Steve, maybe big picture, you talked quite a bit about this consolidation being the strategy.

How should we be thinking about this kind of second half of the year?

And then maybe think -- maybe thinking through the funding of that?

Yes, Holly.

I think we expected to continue to do similar types of deals as we've been doing.

So the small- to medium-sized asset deals are, by far the most likely and most available.

And I think we're -- we continue to be pretty optimistic that there will be a deal flow throughout the year.

So attractive asset packages that fit very well with our strategy.

And I think for now, the bulk of that could be paid for with cash on hand.

There -- when you look at the maps, there are some obvious kind of merger type -- not necessarily opportunities, but things where you put bigger packages together and really kind of change the landscape.

Those obviously are much more difficult to do, much more unlikely.

And if something like that were to come about, we'd have to take a hard look at how we would finance something like that.

But I think, for now the short term -- the strategy in the short term is to focus on the asset deals, because we think we can get some of those done and we can finance those with available cash.

Perfect.

And then maybe more of a micro question, and I think you've answered it with the frac crews, but just trying to bridge the gap between the 2Q production guide and then you guys had a pretty big DUC number at the end of 1Q.

So I'm assuming that, that's just timing of these frac crews coming back online and then are coming back?

And then maybe kind of thinking about the 1Q DUC number this year versus the 1Q '16 DUC number.

Can you break down kind of the acquisition wells that you had in there versus kind of pure EQT?

Holly, this is David.

I don't know if I have the Q1 off the top of my head.

But I know in the Q, the current quarter, there's 35 DUCs in there from the latest acquisition.

So of the 183, 35 of those are stone DUCs.

Okay.

And then just the 2Q production guide to the DUC count, I'm assuming that's just kind of related to this -- the timing of the frac crews?

Yes, it certainly is.

Our next question comes from the line of Neal Dingmann with SunTrust.

Two questions, Steve, the first one is just -- when you look at the co-development of both the Marcellus and Upper Devonian, I mean, again, I know you've had some pretty great -- really nice slides out earlier, the basin just shows how that increases on a per acre basis.

Could you address that?

I mean, for the quarter, I think you had 20 Marcellus, 19 Upper Devonian.

Is that a split that we should continue to see?

And are you sort of sticking by that because of this upside with the co-development?

If you could just talk about that, perhaps for the remainder of the year and into '18?

Yes, Neal, certainly we continue to feel very strongly about the economics of co-development in that particular area of Upper Devonian that we specify in our investor presentation where because of the geology and the results that we have in that area, it's pretty clear to us that it is the right economic decision.

Outside of that box, it doesn't make sense to codevelop, even though in some of the areas, there is good Upper Devonian potential.

It's just okay to wait, to drill those wells until much later.

Regarding the current balance, it's a hard question to answer, Neal, because of the consolidation we've done.

We are currently kind of incorporating the new acreage and redoing our development plans to focus on making the best investments we can.

So that's shifting around our focus a little bit from a certain areas into other areas and we haven't really finished that.

So it's a bit tough to answer that, and I'll just mention that maybe I'm getting a little off track here, but one other factor that's ongoing that can affect how we allocate capital between our development areas is around something called joint development and cotenancy in West Virginia.

We've talked about it a few times over the years.

It is some legislative fixes to the old antiquated oil and gas wells in West Virginia that we and the industry have been trying to get updated for quite a while now.

It remains in flux.

We're hopeful there'll be a special session this summer, where it gets brought up again.

And the outcome of that could potentially have impacts on how we allocate our capital across that development area.

So that's a long-winded answer to tell you that it's in flux and I can't give you a good number right now.

One thing to keep in mind on that is we've only got Upper Devonian that we want to develop on about 20% of the core Marcellus acreage.

So within the long run, that's probably a ratio that you'd see, but in any short period of time, the mix can be meaningfully different.

And then just real quick, I don't want to beat this one to death.

The other part is we are still playing a bit of catch up from the cut back in early 2016, where we had cut back some of the co-development potential Upper Devonian wells that now the clock is ticking on those, because of the nature of the co-development.

So right now we're in a bit of a catch-up mode, but that should be concluding here pretty quickly.

Okay.

And then just one last one, Steve, on the consolidation I remember speaking to you before, you mentioned about having to repermit or doing some additional permitting on that versus what maybe had already been done with the previous owners.

How -- is that still the case?

How is that coming along?

Anything you could mention on that?

Yes, that is still the case, and that will continue to be the case as we bring in new acreage because the whole reason for the acquisitions is to extend the laterals, and if we have the opportunity to do that, even if we permitted a well shorter, we want to go back and repermit it to get of the economic advantages.

So that does build in a bit of a delay in some cases, but that's something that we plan for and really the delay this quarter is driven far more by the frac crew availability than any issues around that.

We had properly planned and accounted for having to repermit as we added acreage.

Our next question comes from the line of Brian Singer with Goldman Sachs.

Going back to the op cost points with looking at the first quarter relative to annual guidance, it would appear the first quarter came in above where you've raised the annual guidance to.

Can you just give us a little bit more color, I know you don't have the quarterly guidance, but a little bit more sense of the moving pieces and the trajectory as we go through the year?

Yes, I think, big picture, what you see is that the volumes are going to increase significantly in the second half of the year, and so the per-unit cost on a number of line items will start to come down.

I think that's the big picture answer to what we'd expect to see on a per-unit basis.

Got it.

Which would mean that essentially then if you're flat in the second quarter, you'd see the bulk of those decreases coming in the second half, if you're flat (inaudible)?

Yes, that's correct.

Okay.

And then going back to the M&A point, 2 questions there.

You mentioned earlier you could do what you think might be available with cash on hand.

While the cash may be there, what's your tolerance for higher leverage that would likely result?

And then, do you see any relationship between scale and the ability to retain frac crews, lower services costs, et cetera?

Maybe I'll answer the first part of that question and I'll let Steve or Dave answer the second part.

Yes, it is important to us to maintain an investment-grade balance sheet.

There's a number of reasons that we've articulated in the past.

And so we will be cognizant of that when we think about how we would fund any future acquisitions.

We do have both debt capacity and equity markets available.

And so if the acquisitions make sense, we will be able to fund them and we'll manage the debt-to-equity mix to keep -- to be sure that we stay on the right side of the rating agencies.

Okay, Brian, could you repeat the second part of your question?

Yes, I guess I'm trying to see and that probably isn't just there.

If there's any read across from the nonaffiliate and the frac crews to stay in the area to some of the scale that you're looking for.

Do you see the ability to further lower cost and increase efficiencies and retain frac crews from the type of scale and the M&A that you're looking to do?

Yes, I think -- so I think, the issue around the frac crews is a temporary phenomenon.

A lot of equipment, a lot of crews were shut down during the downturn and this rebound is happening fairly quickly and as you know, really quickly in the Permian.

A lot of the equipment and crews are (technical difficulty) between basins.

So we're seeing a lot of that, but I think, over time, and I think fairly quickly, the service companies will recommission a lot of equipment and rehire a lot of the hands that were let go.

So I think there's a time period here where the demand is outstripping the supply, but that will equalize going forward.

So I think, I don't see any real long-term concerns around that and certainly, not related to our consolidation efforts.

I think, consolidation only improves the efficiency of all of that activity, means we can get more done with less crews as we consolidate.

Mr. Kane, we have no further questions at this time.

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

Thank you, Christine, and thank you all for participating.

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.