Northern Oil and Gas Inc (NOG) 2013 Q3 法說會逐字稿

Good day, and welcome to the Northern Oil & Gas Inc third-quarter 2013 earnings conference call. Today's conference is being recorded. At this time, I would like to turn the conference over to Michael Reger. Please go ahead, sir.

Thank you, Rochelle. Good morning, ladies and gentlemen. This is Mike. We are happy to welcome you to the third-quarter 2013 earnings call for Northern Oil & Gas. With me today is Tom Stoelk, our Chief Financial Officer, who will discuss our financial highlights from the third quarter.

Before we begin this morning's call, you should be aware that certain statements made during the call may contain forward-looking statements that are based on management's expectations, estimates, projections, and assumptions, and that involve certain risks and uncertainties. We encourage you to review the various risk factors relating to our business, which are available in our annual report on form 10-K for the fiscal year ended December 31, 2012 and other reports we have filed with the SEC.

These forward-looking statements relate to our future plans, objectives, expectations, and intentions. Our actual results could differ materially from those contemplated by these statements, partially as a result of the various assumptions relied upon in making such statements.

During this conference call, we will also make references to certain non-GAAP financial measures. Reconciliations of these non-GAAP financial measures to the applicable GAAP measures can be found in the earnings release that we issued last night.

As we mentioned in our earnings release last night, Northern third quarter 2013 production was 1.2 million barrels of oil equivalent, or 13,049 barrels of oil equivalent per day, a 20% sequential increase over the second quarter. We added 147 gross, 12.1 net, wells to production in the third quarter, bringing our total producing well count to 1,585 gross, 133.5 net, wells as of September 30.

The level of joining activity in the basin was strong throughout the third quarter, primarily driven by favorable weather and pad drilling efficiencies. Our backlog of wells, either drilling or awaiting completion, expanded to 260 gross, 18.8 net, wells as of September 30.

Robust activity levels continued into the fourth quarter as we added 65 gross, 4.6 net, wells to production during the month of October. We spud another 60 gross 3.3, net wells during the month as well, leaving our drilling and awaiting completion list at 255 gross, 17.4 net, wells in process as of October 31. The October completion activity gives us a really nice start to the fourth quarter, and hopefully a strong finish to the year.

Due to the sequential production growth and well productivity we experienced during the third quarter and our strong start to the fourth quarter, we are raising our assumptions to an estimated 37 to 39 net well additions for the year, and estimated 2013 total production of 4.4 million to 4.5 million barrels of oil equivalent. If weather cooperates and completion activity remains robust in November and December, we could be at the higher end of that range.

Acreage acquisitions picked up slightly in the quarter as we acquired almost 7,400 net editors at an average cost of just under $1,500 per acre. This brings our current acreage position to approximately 187,000 net acres in the core of the play at the end of the third quarter. We will continue to be disciplined in our acreage acquisition strategy, seeing only high-quality, non-operated, near-term drilling opportunities.

As mentioned in our press release last night, on October 16 Northern began repurchasing shares under our existing share buyback authorization. During the third quarter, we purchase just over 2 million shares at an average cost of $12.82 per share. This represented just over 3% of the Company's stock.

The decision to buy back shares was initiated for a couple of reasons. First, Northern's liquidity position has never been stronger. The borrowing base under our 13-bank revolving credit facility was increased to $450 million during the third quarter.

Capital expenditures have been more predictable, and per-well costs have been trending down. Aside from McKenzie County where the wells are bit more expensive due to depth and completion designs, most of the well costs we are seeing are closer to $8.5 million or less.

Also, we have mitigated futures cash flow volatility by increasing our oil hedges to maintain a strong liquidity position. In addition, the market's valuation of Northern versus the value of our asset base had become, in our opinion, dislocated.

Our Board, the rest of the management team, and I have concluded, after careful consideration, that it was the appropriate time to act. At approximately $13 per share, it was cheaper to buy our own high-grade acreage position, current production, reserves, and future drilling inventory than it was to buy most of the deals we are seeing in the marketplace.

Overall, the third quarter was very exciting for Northern as activity levels improved as compared to the first half of the year, and our sequential production growth resumed. We are encouraged by the level of activity in October, and the inventory of wells that should come on before year-end.

We are in a great position to continue to execute our business plan into 2014 and beyond. We will continue to seek high-quality acreage opportunities, develop our extensive drilling inventory, expand our liquidity position, and explore additional ways to maximize shareholder value. With that, I'm going to turn the call over to Tom Stoelk, our Chief Financial Officer, to discuss our financial highlights from the third quarter.

Thanks, Mike. We reported GAAP net income of $1.7 million, or $0.03 per diluted share, for the third quarter 2013. Excluding the effects of non-cash loss on derivative instruments, we reported adjusted net income of $20 million or $0.32 per diluted share.

Adjusted EBITDA for the third quarter was $74.6 million, bringing total adjusted EBITDA for the first nine months of 2013 to $196.3 million, which is a 22% increase compared to the first nine months of 2012. In the third quarter of 2013, oil, natural gas and NGL sales, excluding the effect of settled derivatives, increased 33% compared to the third quarter of 2012, and that was driven by a 16% increase in production and a 15% increase in realized pricing, excluding the impact of settled derivatives.

Our average realized price, including all cash derivative settlements during the third quarter of 2013, was $82.58 per Boe. That was roughly 4% higher than the $79.38 per Boe realized in third quarter of 2012. Our higher average realized price in the third quarter of 2013 as compared to the same period 2012 was driven by higher average oil prices, offset by the effect of losses on settled derivatives.

Oil differentials during the third quarter of 2013 was $9.04 per barrel as compared to $10.18 per barrel in the third quarter of 2012. During the third quarter of 2013, we had a non-cash mark-to-market derivative loss of approximately $29.4 million. That compares to a $22.3 million loss in third quarter of 2012. The non-cash loss relates to oil volumes hedged in future periods at prices less than the forward futures market on September 30, 2013.

Production expenses were $11.5 million in the third quarter 2013. That compared to $8.7 million in third quarter of 2012. On a per-unit basis, production expenses increased to $9.56 per Boe in the third quarter of 2013 compared to $8.42 per Boe in the third quarter of 2012. The year-over-year increase in 2013 was really driven by higher water hauling and disposal costs and workover expenses.

Our production taxes totaled $9.9 million in the third quarter of 2013. That compares to $8.1 million in the third quarter of 2012. As a percentage of oil and gas revenues, production taxes were down slightly to 9.3% in the third quarter of 2013.

General and administrative expense was $4.2 million for the third quarter of 2013. That compared to $9.5 million for the third quarter of 2012. On a per unit basis, general administrative costs during the third quarter of 2013 were $3.47 per Boe.

Excluding the $4.9 million severance charge from last year, our G&A expenses dropped 9% in the third quarter of 2013 compared to the same period in 2012. So, we've been able to contain our overhead costs while continuing to grow our business.

Depletion, depreciation and amortization, and accretion was $32.1 million in the third quarter 2013. That compares to a $28.1 million in the third quarter of 2012. Completion expense, which is the largest component of our DD&A, averaged $26.66 per Boe in the third quarter of 2013 compared to $26.93 in the third quarter of 2012.

The provision for income taxes was $1 million in the third quarter of 2013 compared to $213,000 in the third quarter of 2012. The effective tax rate during the third quarter was 37.6%. The year-over-year decrease in our effective tax rate reflects a decrease in the corporate income tax rate in North Dakota.

During the third quarter of 2013, capital spending totaled approximately $117.5 million, which puts our nine month capital spend of $319.5 million. Our total capital expending for the first nine months is broken down as follows.

Drilling and completion costs, including capitalized workover, expenses was $280 million. We spent $22.6 million on acreage and related activities, and another $16.9 million on other capital expenditures.

As we mentioned in our earnings release, during the third quarter of 2013 we placed 147 gross, 12.1 net, wells into production, which brings our year-to-date producing well additions as of September 30 to 358 gross, 27.3 net, wells. If we hit the top end of the completed well range Mike mentioned earlier, we will have added approximately 39 net producing wells by the end of the year. Assuming our drilling and completion costs per net well is $9 million, which is the weighted average AFE cost for our wells in process on September 30, we incur a total of approximately $351 million of drilling and completion costs related to the producing well additions in 2013.

Please keep in mind that our actual CapEx spending will be impacted by the expenditure levels on our backlog of wells in process at the end of the year. We entered 2013 with a backlog of approximately 12.4 net wells in process, which has increased to 18.8 net wells on September 30.

At September 30, 2013 we had incurred approximately $64 million of drilling and completion costs related to our in-process wells at that date. Given our slight pick-up in acreage acquisitions during the third quarter, our full-year acreage CapEx will probably be closer to $30 million, and I'd estimate that other capitalized expenditures will remain unchanged at our previous estimate of $30 million.

As Mike mentioned in conjunction with the comments about share repurchases, we increased our hedge position in order to protect our liquidity, increase the predictability of our cash flow, and to help maintain a strong financial position. Currently, we have hedged approximately 11,200 barrels of oil per day in the fourth quarter of 2013.

Approximately 52% of the fourth quarter hedging is done with costless collars with an average floor price of $90 per barrel and an average ceiling price of $104 per barrel. In 2014, we hedged -- we have hedged approximately 10,900 barrels of oil per day. The majority of our 2014 hedges are crude oil swaps at an average price of $90.46 per barrel.

In 2015 we have hedged approximately 7400 barrels of oil per day. The majority of our 2015 hedges are crude oil swaps at an average price of $89.03 per barrel.

At September 30, 2013, our revolving credit facility at $45 million drawn on a $450 million borrowing base. With strong third-quarter growth, our net debt-to-adjusted EBITDA was 2 times on a trailing 12-month basis and 1.8 times at an annualized the third quarter. While we have ample liquidity under our revolver to fund our development, or our future development, we also remain focused on maintaining a strong balance sheet. At this time, I will turn the call over for Q&A to Rochelle. If you would please give the instructions for Q&A.

(Operator Instructions)

Scott Hanold with RBC.

Mike, you had mentioned that you all are looking at other opportunities to advance -- enhance shareholder value outside -- I'm assuming that means outside of the share buyback. So, kind of have embedded two questions.

First, what would those other opportunities entail? Can you give us some color on that? The second question is it on the stock buyback, what is your view at this point? Was that a one-time sort of transaction you did, or could we see this happen again?

Thanks, Scott. As far as the stock buyback goes, obviously we won't be mentioning our specific plans ahead of time, and we will report any of the stock buybacks at the end of the quarter. Having said that, as you know, we make decisions on a daily basis on well proposals and acreage acquisition opportunities. So our capital allocation decisions are somewhat fluid.

The first part of question that was additional ways to maximize shareholder value, and I think we will continue as a management team, and the Board will continue to analyze other opportunities, royalty trust or MLP, additional stock buybacks, et cetera. We will continue to analyze those opportunities, potentially strategic asset sales; however, our leverage is relatively low compared to our peers at under 2 times debt-to-EBITDA.

So we are not in any need to make any asset sales. But we are always reviewing those opportunities and all the options we have.

Okay, and that's some good color, thanks. Then my second question would be on the acreage acquisitions. You made a pretty nice chunk of acquisitions this quarter.

Can you give us a little color on what changed this quarter to really ramp to that up, and where that stuff was that? Also, I guess over the last couple of years, we've seen some larger operators sell some non-op interest, and recently another one has indicated that they are looking to selling some Montreal non-operated interest. Just remind us at this point what your appetite for some of these bigger deals?

I think the strength of our balance sheet and our liquidity position gives us the ability to weigh these new deals we are seeing. The new one this week with Oasis divesting their Montreal non-op, that's a very interesting opportunity.

We are going to run that one out, just like we run all of these opportunities through our acquisition teams. But we really do stay focused on what we do best at Northern and the niche -- and really the business model that we invented, which is acquiring and being the clearinghouse for acquiring these non-operated strategic interests that are about to be drilled.

From an organic standpoint, we continue to be very active on the ground. We have, over time, acquired a few packages that were larger. We are looking at a few packages that are a bit larger.

We will continue to look at opportunities that are big, like the Oasis package, which is similar to the EOG package from about 1.5 years. But really where we picked up the acreage in the third quarter, to answer your question, is basically across the board throughout North Dakota, spread across the counties where we have really strong presence are already.

We have added additional acreage in Montreal, McKenzie, Dunn, Richland County, et cetera. So we will continue to just pick away at the core acreage that we continue to see, especially as it relates to the near-term drilling opportunities.

Okay. If I could follow up with that really quickly on sort of the pick-up in your core bread-and-butter acquisitions. Is something changing in the basin right now?

Early on, obviously, you got in there early and you were able to be very successful. Then it slowed down a little bit. Is there something, another cycle occurring in the Williston at this point where maybe there's some more smaller non-op stuff coming available for you all?

There is a lot of activity right now that we are seeing from an acreage standpoint that interesting to us. One thing that might be creating this is that with pad drilling, you start to see well proposals go out, not just for one well but for, in some cases, four or eight wells.

That may create liquidity issues for others, or CapEx issues for others, where Northern, given the strength of our balance sheet and our liquidity position, we may have the it opportunity to acquire that interest from some of the smaller folks in the basin. So we have started to see more deals, and we believe the main catalyst is from pad drilling.

Okay. That's great. Thanks, guys.

Jason Wangler with Wunderlich Securities.

Just curious on the hedging, obviously jumping it up. Is that about to the limit of your credit facility? Or is there any more room there?

There's some more room, effectively. Most of that room would be out in 215, 216 area.

I should have specified, I was thinking 14 because it looks like some pretty nice numbers there. And then just, obviously with the 7,400 you picked up last quarter and your comment there on the pad drilling, as far as seeing that, do you think we are in the early stages of that still? Or do you think that a lot of it's kind of being picked up, and do you see maybe, without asking too much about 2014, do see a land budget that is still going to be able to let you really start -- keep acquiring acreage in the core?

I think we are just starting to get going here with pad drilling. I think a majority of the units that we are participating in are on pads with at least two wells, but in most cases four. I think -- I really think we're just getting going here with this particular opportunity we are seeing from an acreage standpoint.

That's great. Thank you.

Peter Kissel with Howard Weil.

Congrats on a good quarter. Mike, you alluded to this a little bit in your prepared remarks, but just looking at your fourth-quarter assumptions, it looks fairly conservative. Particularly that you are coming out of the gate so strong with 4.6 net wells in October.

I just was wondering if you wouldn't mind clarifying to make sure that it has nothing to do with timing of completions in November or December. It's much more just a function of playing it conservative, with the risk of some potential early winter weather.

Pete, thanks. The big issue for us, as a non-op, we really -- we get to take a really hard look at our existing in-process list, and that's really strong right now at close to 18 net wells. I think right around 255 gross wells that are actively drilling, or completing or awaiting completion.

So we have a pretty good bead on what's happening. As you know, what happens in the first month of the quarter is more beneficial than what happens in the last month of any given quarter. So we are really encouraged by the fact that October was strong.

It really does come down to weather. If completions continue to be strong in November and December, we think we are going to be at the higher end of those ranges that we mentioned.

It's not in effect of just being conservative. We just truly don't know what the weather is going to be like in late November and December. Fingers crossed that it's favorable, because it's been pretty good so far.

Got you. Thanks, Mike. Maybe taking a bit of a step further here. Looking at the first half of 2014 or so, how should we look at, outside of weather of course, but how should we look at the smoothness of the growth trajectory?

Is there any sort of quarter you see coming up in the first two quarters or so that has more pad drilling or less pad drilling that may create more lumpiness in the mix? Or is a little too early to tell?

It's too early to tell. I would say that given the pad drilling phenomenon, that's actually a benefit to Northern. Because with roughly 252, 260 gross wells that are actively drilling or completing or waiting completion, that is somewhat of a smoothing effect for us.

We are not sitting on one pad waiting for production to come on at some point in the future. We are completing big pads today. We were completing big pads last week and we will again next week.

So it's kind of a smoothing effect for us, just given the sheer number of wells that we are participating in. Really again, the key is, if we have favorable weather conditions in the first quarter, it will be a lot more smooth than it was in 2013, where our operating partners and Northern both said, we thought the first half would be flat and then we thought we would ramp into the second half.

And it looks like all of our partners, now that they reported third quarter, and Northern as well, that all happen kind of as expected. So, we are just -- fingers crossed for favorable weather. That's the big issue in the Willisron is just kind of getting equipment moved around.

Thanks, Mike. Much appreciated.

Ryan Oatman with SunTrust.

We've seen some operators really focused on driving down costs while It seems like others have taken a different approach and are adding a little bit to the cost to try some new completions to improve productivity. I was just wondering if you could speak broad strokes as to where you see costs moving across the basin? Do see guys more focus on kind of driving down the costs? Or more focused on improving the potential productivity?

I think you get the best of both worlds here. You start to see costs continue to come down across the board. In addition, as a lot of you have seen over the last few months, new completion techniques really have been utilized to improve the recovery of the oil in place.

We don't necessarily see that as a broad cost increase issue. We think that costs are going to continue to come down, really because it isn't a completion -- it isn't a major completion redesign, it's just a techniques change. So, we are excited to see the costs continue to come down, and we think that the costs will come down and the completions will be more effective as we go here with the additional sand.

You are referring to the bigger completions where they are adding more sand with cemented liners and plug-in perf, and we are starting to see some really amazing results from that. We've seen a lot come out of it EOG especially. They've been the most vocal about it, and they were one of the first to utilize this new technique, if you will.

So we were in a lot of those new wells. So we got to see in real-time and it was really exciting for us. But we continue to see costs come down, basically across-the-board and with every operator.

You do see the productivity gains that some of these operators are talking about between these new wells with the new designs and the offsets?

Yes, it's really strong. Especially with EOG. They've started to talk about some of their results that we've participated in. So EURs appear to be moving up with this new design, and with EURs, so goes IRRs. So we are really encouraged.

Right. Absolutely. Then kind of a tactical question that was touched on a little bit earlier regarding hedging in the backwardation of the curve. How do you think about being opportunistic with your hedging? And how do you balance between, say, a swap and a collar? What are your thoughts on hedging strategy?

Well, it just really depends on what the market looks like. There's been some backwardation over the last few months. The curves flattened materially, as you've seen, which would kind of put collars more in play.

But really, $90 is an important level for us. We've been fortunate to put on a pretty significant hedge book through the end of 2015 at $90 a barrel, or approximately $90.

The fourth quarter is particularly exciting. We've got a majority of our hedges that have $90 floors with $104 ceilings. So that's going to be a positive for the remainder of the year. But we will continue to add to 2015 hedges. $90 is a really good level for us, and we've been able to, and fortunate to be able to put on a pretty big book there at $90.

That's great. I will hop back in the queue. Thanks, Mike.

Jared Lewis with Northland Securities.

Back to the acreage. You added 7,400 just on the held-by-production in North Dakota has been holding steady around that 70%. Can you just talk about that a little bit? Just why that really hasn't moved that much?

It's really just kind of a wash. We have -- we had about, I think, just right around 3,000 acres expire during the quarter and we added about 7,400 acres.

So it was a really strong quarter for us from an acreage acquisitions standpoint. The new acreage we acquired, that will all, or for the most part, be held by production in, we think, the fairly near term. So that number should start moving up.

The big driver of our held-by-production percentage will be as we start to increase activity in Richland County, where really, if you take Richland County out of the equation, we have are pretty substantial HPP position. But we have a fairly substantial area of mutual interest in that Big Sky play we have with Slawson.

We've got one rig running over there right now. They will continue to bounce around and hold acreage, and hold the stuff that we really want to hold. We think our percentage should start moving up here pretty materially.

Great. Just kind of a follow-up on that. Given, I assume, the stuff that is expiring is kind of away from the core and the stuff you are adding is tighter. Does that change the overall working interest at all?

It really hasn't changed the working interest at all. Primarily, the expirations we are seeing are in Richland County. This is acreage we bought alongside Slawson that -- at very favorable cost. So our primary expirations in the third quarter and the fourth quarter are from Richland County, in that area.

Slawson is going to drill with stuff that is going to have the highest IRR first. It's a pretty big slug of acreage. We've got about 25,000 acres over there, south of [Zone Cooley]. Slawson is getting to the best stuff.

The expiration pressure is in Richland County. We are -- over in North Dakota, we are getting after that. The activity is really brisk.

One more quick one, if you don't mind. Are you seeing, just with the pad drilling, a lengthening from when you get AFE to when you start seeing cash flowing? Or just what are you seeing with that, with kind of the aspect of pad drilling?

Well, I think the key is just when you spud a well, and it is the first well on a four-well pad, the first well obviously is going to have a longer drill-to-complete cycle time, but the last well will be a lot tighter.

So we think that our average is going to be fairly stable at kind of 90 to 120 days. You take weather out, it's going to be at the lower end of that range. You factor weather in, it's going to be at the higher end of that range. But generally speaking, it's spud to spud.

So drilling time to total depth, that's decreasing, which is positive. Then spud-to-sales overall will decrease when the weather is better, and widen out a little bit towards the 120 range when weather is less favorable during the winter months. Generally, it's a positive.

Excellent. Thank you.

Marshall Carver with Heikkinen Energy Advisors.

A couple questions. One on the expense guidance. Do have any -- it looks like 3Q came in fairly predictably. Any tweaks on from 3Q to 4Q that we should think about?

Not really, Marshall. I think that LOE per Boe probably in the $9.50 range, similar to what you saw in Q3, production taxes a percentage of oil and gas, probably 9.4%, 9.5%, somewhere in there.

You can see our G&A was running about $4.2 million for the quarter. On a nine-month basis, we are tickled, we're $12 million. So probably around $4.2 million, $4.3 million wouldn't be a bad number there. You've seen our production guidance. So we announced in the earnings release and talked about in the script. Not a whole lot of tweakary, I don't think.

Great. Thank you. Did you all do a reserve report along with the bank redetermination? Just wondering if you have a feel -- I know you are drilling in better areas this year. You have a feel (multiple speakers) EURs per (multiple speakers).

Marshall, to answer your question on the reserve report. The majority of our lending is supported by our PDP production. So we get after real hard our PDP reserves on a midyear, but we don't do a whole lot of work around the PUD because it's just a smaller component of it.

So, we didn't do a -- we didn't really do a full-blown reserve estimate, to answer your question. We do see some growth, some pretty strong growth, I think, when we come up with our year-end reserves. But to answer your question, we didn't do a full-blown one at midyear.

Okay. Thank you. That's all for me.

Adam Wright with RBC Capital Markets.

Just a quick one for Tom. Can you help me just check my forecast or estimate on what your RP capacity is currently?

We didn't hear that. Adam, on what?

Your restrict did payment capacity?

I'm sorry. Yes, ( inaudible) Roughly around, I think, $60 billion, a little -- right around that neighborhood.

Okay. That's great for me. Thank you.

Ravi Kamath with Global Hunter.

Good quarter. Couple questions. One on the, I think you said that AFC on the work in process was $9 million. It seems like I recall on the last quarter that was more like $8.8 million. Just wondering if you could kind of reconcile that, and I think you talked about maybe getting to $8.5 million. Just if you could talk about that a little bit, please?

Really it is driven by the mix of where those wells are at. When you take a look at our wells in processes at the end of quarter of 18.8, about one-third of those wells are in McKenzie County.

So that's driving that weighted average up. It's McKenzie County wells are roughly, on average about $9.9 million on a weighted-average basis.

If you'd exclude the McKenzie County wells, kind of the rest of that inventory, or rather the other two-thirds of the drilling in process wells have a weighted-average weighted average cost of rougher around $8.5 million. What you are seeing is a higher mix of wells in process in a really good county, being McKenzie, with higher well cost kind of driving that weighted average up.

Understood. Then with regards to acreage explorations, can you sort of give us a ballpark number for Q4 of 2013, and also if you have the numbers for 2014, and maybe how much of that you expect to directly hold?

Right. I would say, this is Mike. I would say that our expirations in the fourth quarter will be similar to the third quarter. So fairly immaterial. Kind of think under 3,000 acres. Hopefully, we put up another good quarter from acquisition opportunities that we are seeing in the field.

Okay. Last one for me. Just wanted to get an update on Richland County activity and recent results. Anything, (inaudible) well cost, anything you can share on results in Richland County? Thank you.

The one thing that we've seen Slawson do over the last year or so is use dual laterals with, I guess you would call them dual short laterals, which has been very encouraging to us. The first test well was called the Archer where they drilled the well in the corner of the section and then drilled 5000-foot laterals, one north and south, one east and west along the section line.

Once both wells -- both laterals were fracked and brought online, we were seeing those well costs in the neighborhood of $7.5 million for a dual lateral, and each lateral seemed to be consistent with the production of the single short laterals that we were drilling adjacent. So cost have come down.

we see EURs across the board up there. But really good internal rates of return on some of these new wells we've been drilling right in the heart of Big Sky.

Okay. Great. Thanks, guys.

There are no further questions. I would like to turn the call back over to Mr. Reger for any additional or closing remarks.

Great. Thanks everyone for your participation in this call. Rochelle, will you give the replay information to the group? We look forward to seeing everybody soon and sharing our results with you from the fourth quarter in the new year. Have a great day.

Thank you. That will conclude today's call. The replay does start November 8 at 1 PM Central time and runs through November 22nd at 1.00 PM central time.

The dial-in numbers 719-457-0820 or 888-203-1112. Thank you. You now may disconnect.