Northern Oil and Gas Inc (NOG) 2014 Q2 法說會逐字稿

Good day and welcome to the Northern Oil & Gas second-quarter 2014 earnings conference call. Today's conference is being recorded.

At this time, I'd like to turn the conference over to Mr. Michael Reger. Please go ahead, sir.

Thanks, Eric. Good morning, everyone. This is Mike. We are happy to welcome you to the 2014 second-quarter earnings call for Northern Oil & Gas. With me today is Tom Stoelk, our Chief Financial Officer, who will discuss some of our financial highlights from the second quarter.

Before we begin this morning's call, you should be aware that certain statements made during this 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 10K for the year ended December 31, 2013, 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, including adjusted net income and adjusted EBITDA. Reconciliation of these non-GAAP financial measures to the applicable GAAP measures can be found in the earnings release that we issued last night.

Now that we have the disclosures out of the way, I will start by saying, by all accounts, the second quarter was a great quarter for Northern. Conditions in the field were better than expected, and well productivity continued to improve. We talked last quarter about the breakdown of our wells in process by county. So it should be no surprise that, of the wells brought online during the second quarter, over 90% of them were in the core counties of Mountrail, McKenzie, Williams, and Dunn. We expect that trend to continue, given that our wells in process at the end of the quarter continue to be dominated by those same four core counties, which account for 91% of the current wells in process at the end of the quarter.

Second-quarter production was up 17% over the first quarter of 2014, and up 41% year over year, to approximately 15,400 barrels of oil equivalent per day. We placed into production 14.4 net wells, which brings our total producing well count to 2,037 gross or 165.2 net wells. Activity on our acreage remains very robust as we spud an additional 190 gross or 13.4 net wells during the quarter. If you include the wells in process at the end of the second quarter, Northern has now participated in a total of 2,335 gross wells, which is approximately 20% of the Bakken and Three Forks wells drilled since 2006.

As we begin the third quarter, July got us off to a very solid start. We completed four net wells, and spud another four point net wells, increasing our wells in process list further to 313 gross or 23.9 net wells as of July 31. Based on our strong second-quarter results and the quality and size of the in-process well list, we are raising our 2014 production guidance to an increase of 20% to 25% over 2013 levels.

Let me take a moment to talk about capital allocation as well. Every day we take a hard look at our capital allocation opportunities, whether it's new acreage, well proposals and AFEs, or repurchasing our own stock. Over the past year, we have taken a more disciplined approach to our capital allocation decisions, and we believe that this is showing in our most recent results. For example, we are pleased to be able to raise our 2014 production guidance without changing our expectations for the year's net well additions, which we still expect to be approximately 44 net wells added. We continue to participate in some of the best projects in the basin, and we will continue to evaluate opportunities and allocate our capital to the highest rates of return while avoiding projects that do not meet our strict internal threshold.

We remain committed to our effective and efficient business model, and we will continue to look for ways to grow the asset base and further improve capital efficiency and returns.

With that, I'm going to turn the call over to Tom Stoelk, our Chief Financial Officer, to discuss the financial highlights for the second quarter.

Thanks, Mike.

The second quarter we reported a net loss on a GAAP basis of $4.4 million, or a loss of $0.07 per diluted share. The loss was due to a non-cash loss on the mark to market of our derivative instruments. Our adjusted net income, which excludes the net impact of that non-cash mark to market loss, was $17.3 million, or $0.29 per diluted share. Our adjusted EBITDA for the second quarter totaled $81.4 million, which was up 40% as compared to the same period last year and up 24% on a sequential quarterly basis.

During the second quarter, our total production volumes were approximately 1.4 million BOE, or averaged 15,396 BOE per day, which was up 41% as compared to the same period last year. On a sequential quarterly basis, production volumes increased 17%.

The strength of the overall financial results of this quarter was clearly driven by our increased production levels. One factor that certainly made a big difference in this quarter's production was the fact that nearly half the completed well additions that occurred during the quarter occurred during that first month. During the second quarter, we added 14.4 net wells to production, with 6.7 of those occurring in April, which in turn provided a strong start to the quarter.

Oil and gas sales reached $121.2 million during the second quarter, which was a 52% increase as compared to the same period a year ago. Our average oil price differential to NYMEX WTI benchmark was $12.25 per barrel in the second quarter of 2014, as compared to $5.32 per barrel in the second quarter 2013 and $13.42 per barrel last quarter. Our realized price per barrel of oil equivalent, after reflecting our settled derivative transactions, was $78.45 per BOE in the second quarter of 2014. That realized price was 4% higher than last quarter and 2% lower when compared to the second quarter of last year.

As a result of oil price derivative activities, Northern incurred a net cash settlement loss of $11.2 million in the second quarter of 2014, compared to a loss of $499,000 in the second quarter 2013. As a result of forward oil price changes, our mark to market derivative gains and losses resulted in a non-cash loss of $35.3 million in the second quarter of 2014, compared to a non-cash gain of $17 million in the second quarter of 2013.

Production expenses increased $1.4 million during the second quarter of 2014 as compared to last quarter and reached $13 million. On a per unit basis, the average production expense decreased by $0.46 per BOE from the first quarter to $9.30. We are currently estimating that production expenses on a per unit basis will range between $9 and $9.50 per BOE during the second half of 2014.

We pay production taxes based on the amount of oil and gas natural sales before the impact of settled derivatives. Production taxes totaled $12.2 million in the second quarter of 2014, or approximately 10.1% as a percentage of oil and gas sales, which was the same percentage experienced last quarter and compares to 9.5% in the second quarter of 2013. The Company's production tax rate is trended slightly higher due to the decreased waiting of oil revenues on wells receiving tax exceptions for a certain period of time. Upon expiration of the production tax exemptions in North Dakota, that rate will increase to the standard 11.5% statutory rate. As the mix in our production base changes, we expect our average production tax rate as a percentage of oil and gas sales will continue to trend higher throughout 2014, likely averaging in the mid-10% range during our remainder of the year.

General administrative expense was $4 million for the second quarter of 2014, which was essentially flat when compared to last quarter in the second quarter of last year. On a per unit basis, our general administrative expense per BOE was $2.84 per BOE in the second quarter of 2014, which was $0.50 lower than last quarter and $1.11 lower than the second quarter of 2013.

Depletion, depreciation, and amortization was $42.2 million in the second quarter of 2014 or $30.13 per BOE, which compares to $26 million in the second quarter of 2013 or $26.79 on a BOE basis. The depletion rate per BOE of $30.02 was determined based on our year-end reserve report, and we expect that to remain at that level until we update our reserves, likely not until the fourth quarter of this year.

During the second quarter of 2014, our capital expenditures totaled $155.6 million. The breakdown is as follows: approximately $137.3 million of drilling and completion capital, which includes capitalized workover expense; $16.5 million on acreage and other acquisition activities in the Williston Basin, and $1.8 million of capitalized interest and other capitalized cost. Our first half drilling and completion capital expenditures include approximately $59 million of spending attributable to the increase in the number of our wells in process. We ended the quarter with 23.5 net wells in process, which is an 8.3 net well increase from the number of wells in process at the end of the year.

The average completed well cost for the 19 net wells placed in the production during the first half of 2014 was approximately $9.5 million per well. The newer completion technologies using plug-and-perf and some increased profit usage have slightly increased our well cost estimates. Perhaps more importantly, these methodologies appear to be increasing production levels. As a result of the well cost increases, we're raising our drilling and completion capital expenditure guidance by approximately 5%.

Turning to liquidity, as of June 30, 2014, we had $198 million drawn on our revolving credit facility, which has a borrowing base of $500 million, leaving us with $302 million of borrowing availability under the revolver, with approximately $14.3 million in cash at quarter end. The Company had available liquidity of approximately $316.3 million. Including our senior notes, our total indebtedness at the end of the second quarter was approximately $707 million, and the ratio of our long-term debt to trailing fourth quarters adjusted EBITDA was 2.4 times. We believe we have more than enough liquidity to handle our current backlog oils in process, and we expect our cash flow to continue throughout to keep us in strong financial position.

We continue to layer in hedges opportunistically as the market warrants to increase the predictability of our cash flow and help maintain a strong financial position. For the remainder of 2014, we currently have hedged approximately 10,500 barrels of oil per day using swaps at an average price of just under $90 per barrel, and approximately 650 barrels of oil per day using costless collars, having average floor of $90 and an average ceiling price of $99.05 per barrel. In 2015, we have hedged approximately 10,850 barrels of oil per day, an average swap price of approximately $89.43. For the first half of 2016, we have hedged approximately 5,000 barrels a day at an average swap price of approximately $90 per barrel.

At this time, we're going to turn the call over to the operator for Q&A. Aaron, if you could please issue the instructions.

(Operator Instructions)

And we will go first to Scott Hanold with RBC Capital Markets.

Thanks, good morning, guys. Congratulations on the quarter. I have a couple quick questions, first one maybe for Mike and then a follow up for Tom.

First on production and guidance, Mike. It looks like it you all stand still, from where you were in the second quarter, you can get pretty well into your full-year guidance at this point.

Is that a little bit of conservatism? Is there going to be a little bit of ebb and flow in the 3Q and 4Q? I know it can be tough to gauge quarterly production, but if you can give us a little color on that, that would be great.

Yes, I think the way we're looking at this is that we are very comfortable with 20%. But we look forward into the second half of the year.

We are factoring the potential of a rough fourth quarter from a weather standpoint. So we just want to be conservative there.

If we continue to have a, the same momentum we saw coming out of the second quarter, and carry through to the end of the year, we will likely be at the high end of that range or better. So we're going to be conservative at this point because we don't know what the weather is going to look like in the fourth quarter, but we feel pretty good about the year as it is shaking out.

Okay. So you guys can't predict weather yet. All right. Got it.

I mean that's good. That make sense. Looks like things are going pretty well.

On the second one, on the CapEx increase about 5%. Tom, I think this has been discussed in a variety of ways on different calls.

But when you look at the first half spending, for the drilling on completion and that full-year guidance that you set out in addition to the 5%, it looks like there is little bit of -- it looks like it's going to be running a little bit higher. Can you square the circle for that up for us?

Sure. As I mentioned in the earlier remarks, our capital and spending included an increase for approximately $59 million that was attributable to the investments made in the wells in process as of June 30. That increase in the number of wells was driving the overall increase on capital spending. And I'm going to walk you through some computation that I hope will clarify.

The bottom line is that our in process inventory has stayed at the same levels that you're in our capital spending would've been $59 million lower or approximately [$213 million], which would've put us in the midpoint of the beginning of the year guidance. We finished the second quarter with 23.5 net wells that were drilling and awaiting completion, which is an increase of 8.3 net wells from the beginning of the year. Not only did the number of net wells in process inventory increase, but also the percentage of completion on those wells increased from year-end to June 30.

At December 31, we had 15.2 net wells that were approximately 40% complete, so we ended 2013 with a net investment in our in-process inventory of approximately 6.1 net wells. And I derived that number by multiplying the 15.2 net wells that were in process times the percentage of the completion amount of 40% to arrive at 6.1.

At June 30, the number of net wells that were in process were 23.5, and as far as the percentage complete, they were approximately 53% complete as of that date. So we ended the quarter with a net investment at the end of June of approximately 12.5 net wells, which is derived by taking the 23.5 net wells times the 53% estimated completion percentage.

Now, if you take the net investment in our in process inventory at the end of June, which is 12.5, and you subtract the 6.1 net wells that we had coming in at the first of the year, you're going to arrive or derive the increase in our investment in the wells that were drilling are awaiting completion that occurred in during the year. And that net increase is about 6.4 net wells.

Now, the weighted average cost of our in process inventory at June 30 was approximately $9.2 million per net well, so if you multiplied the $9.2 million times a 6.4 net well increase, that occurred during 2014, you're going to arrive at that $59 million estimate. If our in process inventory had stayed exactly the same as the year-end levels, and a percentage completion was the same, as I mentioned, we would spend $59 million less and our CapEx would've been in the midpoint of our beginning of the year guidance. If that helps.

Yes, no, that's a lot of good data. Certainly taken into some numbers, but I appreciate the color.

Sure. Thanks.

We will go next to Steve Berman with Canaccord.

Good morning, guys. Mike, your second-quarter production beat the Street by about 1500 BOE a day.

I was wondering if you could just give us a general idea of how much of that was from better conditions out there versus your operators drilling bigger and better wells. Just the general idea there.

I think generally, over the last year, we started to see a material improvement in the quality of wells being drilled across the basin. You also should factor in for Northern, just the percentage of wells that we are adding to completion that are in the four core counties, which continues to improve as we go on.

As I mentioned in my remarks that over 90% of the wells that are currently in process are in those four core counties with a current awaiting especially to Mountrail County. So you are going to see some bigger wells of the more net wells that we've added.

Of the additional net was we added, we're seeing some of the stronger wells come on. But I think one of the biggest factors in the second quarter was just that we really did have a really good momentum from a completion standpoint.

So we were able to add 14.4 net wells during the quarter, and the second quarter can be challenging. And in 2014 here, the second quarter was not challenging. So we have great momentum going into the second half of the year. July got off to a great start.

And the quality of the wells in process and the age of the wells on the drilling and completion lists or the in process list as Tom just mentioned in his answer to Scott was that age is advancing. So looks like we will have really good completion momentum in the third quarter as well.

So that just gives you a little color. We saw little bit of everything. But I think the number one key to watch for Northern and our -- and the winner for us going into the second half is the number of net wells in those four core counties and the completion momentum of that B&C list. So we are excited.

Okay. My other question, Mike, is there's some new rules in North Dakota particularly thinking about the gas flaring rules that have gone into effect. And just your general thoughts there as how you view your operators and in with a whole bunch of companies up there, how they are handling this and going forward here.

Sure. We are taking a really hard look at what we are going to be participating in here going forward. I think one of the advantages that we have is just given the sheer volume or the sheer number of wells that we have that are participating in those four core counties.

It's going to be really important for us and really is important for us especially because the majority of infrastructure is in the four core counties. The wells that we are going to be adding and the wells we have added of recent that have real strong flush production, they are all going to be tied and into that GAAP infrastructure. So we don't see any material effect going forward.

Great. Thanks, Mike.

Thank you.

We will take our next question from Peter Kissel with Howard Weil.

Hey, guys. Congrats on a good quarter and thanks for taking my questions. I guess just one right off the bat looking at the outlook which I know you touched on a little bit here, but looking at the third and fourth quarters.

Is there any particular period that you see where there could be some lumpiness to the completions? Or I guess maybe a better way of asking it is, is there any higher working interest, pads or wells that you are exposed to coming up over the next few months that could skew production higher or lower by quarter?

I think it's going to be fairly smooth here. If you look at the numbers we put out for July 31, we had a strong completion list in July. We completed four net wells and spud another 4.4 in July.

Just the sheer number of wells, gross number of wells, I think it was 300 or 313 gross wells were in process at the end of July. It looks like given the age of that B&C list as Tom was mentioning again, it looks like they should all come on pretty ratably, which gives us a lot of confidence when it comes to our new guidance.

So any quarter can be lumpy, severe weather can affect the logistics in the field in any one month, but usually, the third quarter's our best quarter from a weather standpoint every year. And then the fourth quarter can be good as well. So it looks like it could be fairly smooth throughout the rest of the year.

Okay. Thanks Mike. I guess my next question is for Tom.

When you think about debt levels, you no doubt have plenty of liquidity in the form of borrowing base availability. So no issues there. But I'm just curious to see if there's any particular level of debt or coverage ratio that you look at that dictates your comfort level?

Well, I think speaking personally, I'm comfortable with our debt levels now. I think that for us because we continue to grow that I would like to see our debt to trailing four quarters EBITDA not peek into the 3 times very far.

3.1, 3.2 might be I'd start to get a little bit of concern with respect to it. Not overly concerned, but I be concerned. But that's probably metric I will look at quite a bit with respect to that.

And I think we are actually here in really good shape with respect to availability and the growth in the reserve base. And as Mike mentioned in all, we are pretty excited about what we are seeing happening in the field where our drilling opportunities are for the second half of this year. And then when you add on to it, the impact of some of the newer completion methodologies that are being adopted in the field, so we are in pretty good shape, I think.

All right. Great. Thanks, guys.

(Operator Instructions)

We will go next to Phillip Johnson with Capital One.

Hey, guys. Thanks. Just to clarify on the CapEx accounting. If we back off the $59 million in accruals off the $270 that you reported for CapEx for the first half of the year, it's roughly $210 million. Is that the actual amount of cash that you spent on CapEx in the first half of the year?

No, you have to -- it includes accruals. So effectively, our cash spend is a different amount than that. We had an accrual for drilling and completing wells at the end of December, and we have a related accrual at the end of June. It's just we estimate the percentage complete on the wells based on when it was spud and then based on the drilling reports and the status of the wells, make certain cost estimates for items that are incurred in our view. But we haven't been billed by the operators at that point in time.

Right, --

So you can really draw cash in that number and relate them.

Okay. So is there an actual estimate of what you spent on cash in the first half of the year?

Yes, I don't have that in front of me. My guess is that that would be about $40 million or $50 million lower. But I would have to put pencil to it.

Okay. And then just on the 5% increase in CapEx, does that assume that well cost continue to run at about $9.4 million or is it assumed that they continue to creep higher on a weighted average basis?

It assumes that they tend to creep higher. Our in process list will move around a little bit. At the end of June it was an average will cost of $9.2 million; at the end of July it had actually dropped into the $9 million levels.

So we try to use our crystal ball a little bit and forecast where that development activity's going to be and the timing of those completions. But I think for the year, it will probably average about $9.3 million, somewhere in that range.

Okay. Great. Thanks.

Yep.

Scott Hanold, RBC Capital Markets.

Hey, guys. Just a follow-up on the acreage you all picked up. It was a pretty big chunk, almost 7000 net this quarter. Can you give a little color on that?

Was it one or two big chunks or was it, you're picking up a few hundred here, a few hundred there. Just seems like a pretty nice size addition, and if we can get some color on the location of all core acquisitions for the most part?

Yes, for the most part it was some of the, our typical wheelhouse type activity where we were picking up smaller 80 to 200-acre transactions subject to well proposals where we are buying AFEs. As you know, that's the power of our franchise that we really do see the majority of activity in the field and we get to analyze a lot of these well proposals. And we picked up a lot of them in the second quarter.

So it wasn't a big lumpy, I don't think there was a single big lumpy transaction in there. it was all just a bunch of our typical, hundred acre type stuff.

That's pretty impressive increase, and do you sense that, with, and I know you talked about with operators moving back into the core that some of the smaller acreage holders, working interest holders I should say are, I guess for lack of a better term, getting run over a little bit by big AFEs they can't handle, so you can step in there. Is that what is happening or is there something else?

No, that's exactly it. I mentioned that on several of the previous calls.

So if you take a typical well proposal that someone might receive that may or may not be able to participate in that well, if they have 10% interest in a $9 million well, they will get a cash call for 900,000. The current state of development in the Williston is that every pad is going to have approximately 4 wells on it.

So instead of that land man or lease broker or whomever it might be receiving a well proposal and cash call for $900,000, there will be four well proposals and cash calls in that same FedEx envelope. So they will get a bill for $3.6 million in that particular example.

So we are seeing a lot of activity just because of the pace of development in the field has been increasing. You can see that from some of our spud numbers from the first half. So we are seeing a lot of edge there where just given the size of our balance sheet, we are able to stand in there and continue to make a market for those types of opportunities.

Okay. Great. And then one other question, too, and taking a look at the well that you know have recently been completed and stuff in your in process or in your inventory right now.

I mean, do you all have a sense on how much of that is actually using new completion design? Is that something you all have visibility, on or is it just tough to know?

We are starting to get more and more visibility on it. I would say that no one operator has moved exclusively to that.

We are seeing different areas, identified as new test areas for the new slick water and increase prop and completion, so I guess I will take the opportunity to say that like every one of our operators is trying. And so that's the most exciting part about what were seeing. Everyone over operators when they tried it, have found that it's been an improvement to our general returns and general EURs.

The other interesting thing that I figured we might get in one of the questions was the lower benches of the Three Forks activity. If you will indulge me, I will take your question and run with it here.

One of the of the things that were seeing that's really interesting is lower benches of the Three Forks in and around southern Mountrail. We saw some really nice Whiting Wells, really nice Oasis wells, and then Slawson drilled a handful of lower bench test on the Peninsula in southern Mountrail County. And that is very material to us because we haven't really accounted for a lot of lower bench reserves.

So this is starting to delineate really nicely, and that's probably the most exciting thing that I'm watching as we progress into the second half of the year because these wells, some of these wells, there's an Oasis well in Mountrail County that is amazing. Slawson's lower bench wells are in several cases better than the first bench Three Forks, so we are particularly encouraged about the delineation of the lower benches. So I figured I would get that in the Q&A, so thanks for the follow-up questions, Scott.

No worries. That's good color. And I think you all, in your roughly 1300 remaining well inventory net inventory, you assume what, 10 wells per 1280. Is that five in he Bakken, five Three Forks, the lower branches are going to add to that number?

Yes, I think that's the way we will model it generally; however, each area is different. We are seeing some operators talking about seven to nine in the middle Bakken, four to seven in the first bench or the upper Three Forks.

And then I think they are generally, some of our operating partners you can see from some of their slide decks, they are estimating three to five in the lower benches. But the way we are going to model it now is five to the Bakken and five to the Three Forks. That the conservative way to look at it from an inventory standpoint.

Understood. And then I could just tack on a little bit to my question. Slawson is a big operator of yours. Have they done slick waters and remind me, do they do plug and perf or do they do sliding sleeves?

Up until recently, they had been are primarily in the 36 to 40 state sliding sleeve from a completion design. The results have been good, obviously, because some of the better rocks in the Williston there and southern Mountrail County.

We have tried several wells with the increased prop and the increased or new completion designs. We have seen the results of those.

There is one particular set of data that I have seen where it appeared that the 30 day rate was approximately 30% higher than the other wells that were sliding sleeve around it. So I think what we need to do now and I'm pretty sure what Slawson is doing at this point is breaking out the calculator trying to determine returns versus additional cost or EURS versus additional cost.

So it appears the additional cost will be worth it. We are encouraged by the new data.

That's just plug and perf. That's not even using slick water, is that right?

No they are using the big fracks where they are tripling the amount of sand they are putting in the well water.

Okay. Great. Thanks.

Thank you, Scott.

We will go next to Blaise Angelico with IBERIA Capital Partners.

Hey, guys. Just a quick follow-up here regarding the Bakken and Three Forks. If you look at tour wells in process, you give us a better idea of the number percentage of which wells of Bakken versus Three Forks and lower Three Forks?

I would say the vast majority are Bakken. I would say a hand wave that I would say 70% to 80% are middle Bakken and the balance being Three Forks at any given time.

We are seeing a couple dozen wells that are testing the lower benches. So it's pretty exciting.

But if you look at a total DNC list for us, the end of July it was over 300 wells, so we get to see a lot of data. But I would say 70% to 80%, probably closely to 80% is middle Bakken.

Thanks, guys. Appreciate it.

Thanks, Blaise.

We got next to Marshall Carver with Heikkinen Energy Advisors.

Yes, good morning and thank you for the clarification on the CapEx in the call. That was very helpful. I had one question. The lower bench Three Forks that are you said were so successful in around your Mountrail acreage, how many acres do you have in that sweet spot there?

I think if you look at the total Mountrail County position, it is approximately 30,000 acres last I checked. And I would say is probably half in the South and half in the north, and so I would say that some the Mountrail County right in the core there is at least 15,000 acres, just to hand wave it.

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

Marshall, this is Brandon. I just wanted to clarify one more thing because I saw your note this morning on the percentage of the CapEx.

And so to carry on a little bit with Tom's math, just for you for your note, that if you look at those first-half completions of about 19 wells, with the math Tom gave you that we pay for basically an additional 6.4 net wells, that gets you to about 25.4 wells that we have paid for which is ironically about 58% of our expected 44 net wells for the year. If you look at the drilling and capital budget that we have laid out, that spend of $240 million include some work over cost in there of about $1 million a month.

That gets you to about $234 million of DNC capital. If you take a slight increase we had in the DNC capital, budget that $234 million of the $410 million DNC budget total for the year is about 57%.

So again, just to reemphasized Tom's math earlier, we are exactly on pace with the amount of capital we spent year to date as well as the number of wells that we pay for year to date. So I hope that helps. Aaron, I think with that we will cut it off, Mike.

Thanks, everybody. Thanks for your interest in Northern. Aaron will give you the replay information. We look forward to talking to you all next quarter.

This does conclude today's conference. We thank you for your participation.