Battalion Oil Corp (BATL) 2014 Q3 法說會逐字稿

Good day, ladies and gentlemen, and welcome to the Halcon Resources Q3 2014 Earnings Conference Call. At this time all participants are in a listen-only mode. Later we will conduct a question-and-answer session, and instructions will follow at that time.

(Operator Instructions)

As a reminder, this conference call is being recorded. I would now like to introduce your host for today's conference call, Mr. Floyd Wilson, Chairman and Chief Executive Officer. Sir, you may begin.

Okay. Thanks, operator. Good morning, everybody. Thanks for joining. This conference call contains forward-looking statements. For a detailed description of our disclaimer, see our earnings release issued yesterday afternoon and posted on our website. I hope you all enjoyed that hold music; I thought it was pretty good.

We achieved record levels of production in the first half of this year, and we did it again in the third quarter. 3Q production of over 43,500 barrels a day was another record, despite selling approximately 3,700 BOE per day in the second quarter. On a pro forma basis we grew production 8% quarter over quarter.

In response to currently low crude prices and currently high service costs, we've decided to not employ five rigs that we had prior planned to employ next year. We'll run six rigs getting started here, and see how the year unfolds. We will still grow production 15% to 20% year over year, and we'll spend about $750 million. As I mentioned, we will remain flexible to increase or decrease that capital program for 2015.

While we are substantially hedged for next year, we are in that uncomfortable space where crude prices have declined dramatically, while service costs remain at an all-time high. Of course the flip side to that is that efficiencies are at an all-time high as well, so it's not a black hole by any means, but they are out of sync.

As has happened many times during my time in the business, our sales and our great partners on the service side of the industry will react accordingly to changing conditions and reach a comfortable space. As you all know, we need each other.

Both of our core plays are profitable at today's prices, or even lower. Our expectation is to run six rigs across our portfolio in 2015, and we will spend meaningfully less than what we had planned to spend next year. We'll grow production, as I mentioned, 15% to 20%; 100% driven by our Williston Basin and El Halcon assets. Again, we're very flexible during the year. We're hedged, and we've got a great hedge position that Mark will go over with you.

Up in the Williston Basin, we averaged three rigs during the quarter. We'll keep three rigs running this quarter. We're making new highs all the time, and efficiencies are increasing. We're in pad drilling, simultaneous operations, and completion modifications are ongoing in the Fort Berthold area. We have seen IP rate for wells put on line during the quarter improve by approximately 15% to just under 3,000 BOE per day. The average 30-day rate also improved.

We also drilled and completed two wells in Williams County during the quarter from an existing pad. These wells were spaced 880 feet apart, with completed well costs less than $8.5 million each. It's a significant cost improvement for that area.

The primary driver for the lower completed well cost was frac cost. We pumped 100% sand as opposed to resin-coated sand and lightweight ceramic, and that cut about $1 million off that. We're going to wait and watch those results.

Many others in the field are doing similar type frac jobs. On average, all the wells -- all the operated wells we put on line in the Williston Basin during the third quarter are out-performing our type curves for each area.

For the past quarter, actually over the early part of this year and through today, we've been testing a modified or hybrid slick-water completion design, in an effort to further decrease our completed well cost, and the results thus far are encouraging. The idea is to pump the hybrid jobs at a similar rate, 60, 70 barrels per minute, a similar rate as a regular slick-water completion, using the same amount of proppant but to use less water.

Down in the Fort Berthold area we have to source the water right off the Fort Berthold Indian reservation, and it's quite expensive. The savings is approximately $300,000 to $400,000 per well, and we've had some great results, as I mentioned.

Down-spacing tests continue in the Williston Basin across the industry, and certainly for us. Our current development plans are to proceed with spacing wells at either 660 feet or 880 feet apart, depending on where we are in the basin.

Another note, we continue to make progress to expedite pipeline construction and increase gas capture. As a result, we were able to reduce the amount of gas we flare in the Williston Basin by 50% during the third quarter alone. We're flaring about 25% of our gas today.

It's a huge improvement and there's more to come. Up in that area, in summary we continue to focus on improving economics by lowering completed well cost in the basin, without impacting production rates or URs. We're quite pleased with what's going on up there so far.

Switching over to El Halcon, this is a great play. We continue to make progress here every single quarter. I guess we might have drilled maybe 80 wells by now. Not all of them are on line, of course, maybe 85 by now. We operated an average of three rigs during the quarter, and plan to keep the same number of rigs this quarter.

Average IPs of the wells put on line during the quarter was 878 BOE per day. That's a 9% improvement over the previous quarter -- over the second quarter. Average 30-day rate of 726 was a 17% improvement quarter over quarter.

On average, the wells put on line during the third quarter are out-performing our 452 MBOE type curve. In fact, 12 of the last 14 wells we put on line are out-performing. Most all the recent wells we've drilled are out-performing that type curve.

We remain focused on identifying ways to reduce completed well costs while increasing performance. Drill inefficiencies are ongoing. Average spud to TD for the three string wells we drilled in El Halcon during the third quarter was 14.3 days. It's fewer days for less than three strings, but that's an improvement on three string wells of about 30% when compared to the prior quarter.

We're still trying to identify the most economic completed lateral length. We have certain restrictions at times based on the leash shapes.

We're targeting 7,000- to 8,000-foot laterals where the unit configuration allows. We have several wells being drilled or planned to be drilled this quarter that will be over 9,000 feet.

This play has really bloomed. I think there's more than 25 rigs running the play, and there's a lot of good information coming out of it. Our current drilling program is designed to capture leases and hold acreage over the next 12 to 18 months.

We'll get that done. Once we can go to development mode and pad drilling, completed well costs are expected to decline by up to $1 million per well.

Important to reiterate that our entire 100,000-acre position has been de-risked. We're surrounded by other great companies drilling good wells. It's important to note that we identified what we believe to be the core of the play prior to leasing acreage. Results continue to validate our belief that the play is expansive, and our acreage is very good.

Tuscaloosa Marine Shale -- I'm going to do my darndest to make sure that people understand that we are highly confident, and we like the play. There's a lot of oil there; but it's an early-stage development project. The core of the play has plenty of commercial locations.

However, it is currently a relatively high-cost play; and with currently low crude prices we will not be devoting a significant portion of our resources to TMS in the near term. We don't have any lease issues we care about.

Our efforts are focused on our two core plays, which provide all of our current production, almost all of our current production, and all of our projected production growth in the future. We ran two rigs during the third quarter, participated in six wells; three operated, three non-op.

These six wells had an average lateral length, both op and non-op, of 6,150 feet, and achieved an average initial production rate of approximately 1,165 BOE per day, 89% oil. 30-day rate for those same six wells was 895 BOE per day. These are right in line with some attractive estimates.

I'll leave Charles to mention specifics on the Blackstone minerals, the SD Smith and the [Fastow]. These are wells that we operated during the quarter. I'll also ask Charles to comment -- we just brought a well on the Shuck Row, and it's one of the better wells in the play.

The industry continues to make progress in this emerging play. Drill days are coming down on a regular basis, and completion recipes are evolving to become more effective, all of which will translate into more consistent results.

Having said that, the TMS is certainly more susceptible to low oil prices than our other crude plays, due to the higher well costs. A tempered approach to drilling in this play in the near term is warranted.

Keep in mind we're still in the early stages of developing this play, and our growth for 2015 will be driven by the Williston Basin and El Halcon. Mark, you got a few comments to make?

Yes. Thank you, Floyd. We ended the quarter with solid liquidity position of approximately $815 million. Our borrowing base was increased during Q3 to $1.05 billion, from $700 million in conjunction with our regular fall re-determination.

This increase was driven by positive results from the ongoing drilling program in both the Williston Basin as well as El Halcon. Production for the quarter averaged right at 43,600 barrels of oil equivalent per day, which was above street estimates, as well as the mid-point of our guidance. For the full year 2014, we expect to come in towards the high end of previously published guidance of 40,000 to 42,000 BOE a day, which again is going to be driven by the operational results in the two core areas.

On the cost side, LOE and work-over expense came in at $8.45 per BOE in the third quarter, which does represent about a 26% improvement compared to the same quarter of last year. After adjusting for some selected items, cash G&A expense for the quarter was $6.07 per BOE, which is about a 25% improvement compared to last year.

Taxes other than income was $7.12, and gathering and other expenses came in at $1.86 per BOE for the quarter. Cash G&A is not forecasted to come in under the low end of our $7 to $9 guidance range for 2014. All other expenditure guidance is projected to be within previously published ranges for the year.

With regard to D&C, CapEx on the second-quarter call, we had mentioned we expected D&C to trend up in Q3, and then back down in the fourth quarter. This hasn't changed.

We spent $322 million on D&C during the third quarter, and expect D&C CapEx to decrease in the fourth. Taking into consideration the Apollo TMS financing of $150 million, we expect to spend an additional $75 million in D&C for the full year, in addition to the previously published guidance of $950 million.

Improved drilling and completion efficiencies in the Bakken are the primary reason for the increased D&C spending this year, as we're drilling and completing wells in that play faster than initially forecasted. I'll also point out the additional capital invested in D&C will be reflected in higher than initially projected production levels, as well.

You'll also note from a review of the Q, there hasn't been any significant amount of money expended on leasing acquisitions, seismic, and infrastructure in the third quarter. We expect the same in the fourth quarter.

There's recently been a lot of discussion around pressure on oil prices, so I think it's worth reminding investors and analysts that we are well hedged for 2015, as Floyd had touched on. Our systematic and consistent approach to hedging over the past few years has resulted in more than 31,000 barrels of oil a day of production hedged at right around $87 a barrel for 2015. We're also meaningfully hedged in 2016, with about 16,500 barrels of oil hedged, at a price right under $90 a barrel.

Our hedge profile compares favorably to that of our peers, and allows us to execute on our 2015 drilling activities. Having said this, as Floyd had mentioned, we are dialing back our drilling for 2015 in an effort to reduce our cash flow out-spend. We have included a detailed look at our current hedge portfolio in the earnings release that was published yesterday afternoon. With that, I'll turn it back over to you, Floyd.

Thanks, Mark. Charles Cusack, our COO, is on the line I know. Charles, do you have a few comments to make?

Yes, I'll just address the operations and the TMS briefly. Basically, we're drilling our ninth and tenth wells right now. We continue to have drilling improvements, and we're feeling very confident in the way we're drilling the wells, evidenced by our recently drilled Creek Cottage West well, drilled to over 21,000 feet in 26 days. We're really getting that recipe down on that side.

On the completion side we have five wells that are now flowing. We've had more of a learning curve on that side. Had a couple hiccups. We under-stimulated our first well. It came in decent rate, but it's going to be an under-performer because of being under-stimulated. Then we fracked into some small faults in another well, possibly two of them. We've learned you need to be near 2-D seismic lines, and that a 3-D seismic will probably critical to the TMS going forward.

Our fourth well is close to a type curve well; then our fifth well that we just brought on the Shuck Row is our best well to date. It's still cleaning up, but we have a projected 24-hour rate that over the next few hours that will get it to well over a thousand barrels a day. 1,066 is our estimate, and 800 to 1,000 cubic feet a day. That would be a 1,276 BOE per day, including NGLs and minus the shrink.

In addition, we just finished pumping the George Martins frac. That's 25 stages that all pump really well. That's the furthest well completed yet to date in Wilkinson County, so it's a step-out well, helping to help delineate the acreage. We have four more wells that will be coming on line over the next two months.

In addition, other industry has 12 additional wells. That's a lot of data in the next two months. I'll also mention we're drilling our first well over in Tangipahoa, so you're 50 miles across. We're very confident. The oil's in place.

We're getting more and more consistent, and we're very confident in our type curve still. You're just going to see more and more results further evidence of that.

Thanks, Charles. Really the punch line for today's call is that we continue to execute and we hit our numbers, and we'll hit them in the future. Our two core plays are going to provide all of our growth for 2015.

We are taking a conservative approach at this time, remain flexible. Be prepared to change our course if we feel it's appropriate. Operator, we're ready for questions, if there are any.

Thank you.

(Operator Instructions)

Our first question comes from Jason Wangler from Wunderlich Securities.

Hey, good morning. Curious with the TMS with the Apollo deal, I think previously you guys have said that the next kind of tranche of their decision is coming up here at the end of the year. Have you got any indication of what the plans are there, and maybe some color on that?

Yes, listen. There's no color. It's not coming up at the end of the year. We still have funds there. As we've noted, we're going to slow the drilling down, and let the results from our next four wells and the industry's next 12 wells kind of guide us. We don't have any decision point at this moment.

Okay. In general there with what you talked about with pulling back on the rig side, can you just maybe talk about what your contracts look like on those rigs?

We have no issues, Jason. We have no issues whatsoever with contracts on rigs. We employ the kind of rigs that we can use at El Halcon or the TMS. We're perfectly content to slow down a bit and let results guide us over the next quarter or so.

Okay, great. Thank you, I'll turn it back.

Thank you. Our next question comes from Steve Berman from Canaccord Genuity.

Good morning. Floyd, where do you see the six rigs deployed in 2015 at this point between the Williston and the El Halcon?

Okay, not to get too granular, but about half and half. We can move that around if we choose to, but about half and half.

Then the TMS, do you think you'll still participate on a non-op side, because you seem to have a decent number of non-op wells going on?

Yes, of course we will. We're getting some great wells, and some great data that way. But Steve, we are not a TMS Company. It's a development stage, a development play in an early stage. We own some nice acreage in the middle of it. We've got plenty of things to do in our other areas. We are hopeful that will turn into a core area for us, but right now with oil prices where they are and service costs where they are, we've elected to slow down there.

Understood. One for Mark. Relative to the $750 million to $800 million D&C guidance for next year, what do you see as total CapEx when you add in capitalized interest and G&A and leasing and seismic and all that good stuff? What's the total range looking like now?

A place holder in your model for right now, probably $100 million.

So add $100 million to the $750 million to $800 million?

Yes, that will include capitalized interest in G&A and things of that nature.

Okay. All right, thanks guys.

Thank you. Our next question comes from Neal Dingmann from SunTrust.

Good morning, guys. Floyd, obviously on your Bakken and El Halcon, where you showed about the IP and the 30-day rates that continue to improve materially sequentially, just two questions there. One, between those two plays, what type of pay-backs are you looking? I'm assuming the Fort Berthold, it's got to be very quick there. Secondly, can those IPs and 30-day rates continue to improve on the magnitude that we just saw in the third quarter?

As far as continued improvement, I would say it's certainly feasible. We've had much fewer below-average wells than in the past, and we project even fewer below-average wells in the future. That would drive our average upward. We're not really projecting -- we're using our current plan to make our projections. Improvements would be on top of that.

Now there's hardly anything, maybe even in the US but certainly in our portfolio, that compares -- that has as good a pay-out as the really large wells in the Williston Basin. But outside of that Fort Berthold area, El Halcon wells compete very nicely with other wells in the Williston Basin. We have a nice balance there. A lot of inventory in all these areas, but if we're only going to run six rigs, we're basically extending our inventory in these very commercial areas.

Understood. Lastly, certainly understanding you're not a TMS Company at this point, are there certain costs or service costs that could decline enough to bring you back to that play in the nearer term, or is it just quite simply a matter of today comparing the economics that are to your -- obviously to the outstanding returns you have in the other two plays?

Well, you're always about today, right? We are comparing those returns. We have plenty of lease term in all of our areas, or they are HBP'd. We're not letting that drive us. It's really the relationship of expected cost reductions to current oil prices that has us a bit conservative. The strip has dropped. The five-year strip has dropped dramatically over the last three months or so. Costs are coming down, and fewer what I call train wrecks on wells across the industry will bring costs down. Then just experience will bring cost down.

If we hit our model up there, or over there in the TMS, and get the costs down, those wells will compete with everything else we have, except the best part of the Williston Basin. Now they're not competitive today. We have no lease issues. We're a two-core-play Company at this moment, and we can grow for several years being a two-core-play Company; but we have high hopes and expectations for that play.

Floyd, is there a certain oil price that you see, if we went back to $85 or $90 where the activity would go back up to those 11 rigs, or is it more still just a matter of the combination of the oil price with the service cost?

It's a combination of oil price and service cost. Certainly we would have a better feeling about everything with a bit higher oil prices, but we can't plan for that, and we wouldn't change our program overnight. If we made some changes in the future it would be after a hard look at expected cash flows and benefits from spending more money. Actually, I believe a Company that can spend $750 million and grow 15% or 20% is in a class by itself.

Got you. Okay, thank you.

Our next question comes from James Spicer from Wells Fargo.

Hi, good morning. Given the slowing pace of drilling in the TMS for 2015, how long is the initial $150-million funding from Apollo going to last? Where does that take you through? Can you comment on how much incremental capital you guys are putting in there next year?

Very little capital is going in there next year. As I said, we're going to take the first quarter and review all of our own flow-backs and all the industry's flow-backs, and decide and then review where prices have gone after this many months, and take a hard look. We still have money. We don't report those numbers exactly, but we still have funds available from the JV, and we've got a great partner there. We will work cooperatively there, and try to achieve a good result for all of us.

Okay, great. Then it looked like your natural gas price differentials widened out meaningfully during the quarter. Just wondering if you could comment around that?

Mark, correct me if I'm wrong, but I believe it was 100% driven by additional gas capture in the Williston Basin. As you know, Williston Basin gas differentials are higher than most areas of the country. Is that fair, Mark, or wrong?

Yes, that's fair, Floyd. We did draw down to -- for Q3 overall Company, we dropped down to about 88%. You are accurate, Floyd, that was mainly driven up in the Bakken area.

When we think about next year, we should think about the differentials staying at similar levels, since you're capturing more of that gas?

Well, the differences aren't driven by just us. It's driven by supply and demand and transportation costs, so it's hard to say. We do have a long history up there of achieving between 80% and 85% and 92% or so of NYMEX. Mark said we were at 88% this quarter. You've got to get this flaring in hand and get it reduced to zero. All of us up there are working on that really hard, and we're all making great strides. The differential increases, but there's less money being burned in flare stacks and basically thrown away. On a cash basis, we're making more money there than we did before, but the price for that commodity is less.

Yes, I understand. Thanks a lot, guys.

Thank you. Our next question comes from Ron Mills from Johnson Rice.

Good morning, Floyd. Question -- just among the Bakken, if you look at your three rigs, are you going to concentrate those rigs down on the reservation, or given what some of these recent results in Williams County do you think you'll be moving between the two? In Williams, how do you break down your acreage?

It's a pretty big position going from northwest to southeast, and I think you've had some better results in southeast. How do you look at your drilling plans up there?

We have all that laid out, and our projections for this year are dependent on what we have laid out, but we can move it around. I won't say it's half and half, but it's something about like that. We've got a large area of Williams County.

We basically have several type curves up there. As you pointed out, the southeast part of our acreage holdings are just as good as the things to the south on the Indian reservation. It moves outward from basically -- these are round numbers, a 700,000 barrel type curve to 600,000 to 500,000 to 400,000.

And a 400,000 barrel type curves are less attractive and we have no plan on drilling any of those anytime in the next couple of years. Unless prices are quite a bit higher. But we don't have to, it's all HBP'd.

I don't know if that's responsive, but we haven't like put a map out and said well this is the good part and this is the medium part and this is the part that we need higher prices. But we've got plenty of inventory for a while to rotate along.

The important thing to note about it, up there it's a bit more shallow. So far, the less expensive frac jobs are working great. We can complete a well up there for a couple million dollars less than down to the south.

Is that -- does that also take into account the southeast part of Williams County? It still does cost $1 million to $2 million less?

Yes.

Okay. I think Williams County is for the most part HBP'd. How is your lease status on the reservation?

We are substantially HBP everywhere. We are in pad drilling. We're HBP. There might be a few acres way up to the northwest that we just don't care about, but I think most of those are either already gone or HBP'd anyway. Substantially, we are HBP'd there.

Similar question in El Halcon. I think you're drilling more lease capture wells there, albeit on a position that has been de-risked by you and others. How does your lease status look in El Halcon to lead to potential pad development at some point?

We think we can be in full pad development within two years, two to three rigs. We'll hold all the acreage within 18 months or so, maybe a little less, maybe a little bit more. We have some areas with culture there, and it takes more planning.

Sometimes you just have to gut up and drill more wells off of one pad, so you stay out of the culture's way as best as you can. For instance on the Texas A&M campus. We'd hate to interrupt another football game, or something.

Great. I think Charles mentioned in addition to your remaining wells to bring on line in the TMS, there were 12 industry wells coming on line. Are those industry wells that you have an interest in, or just industry wells that are expected to commence production?

Industry wells. I believe we have an interest in half of them. But that's an estimate on my part. We're in such a good data-sharing mode with the other fine operators in that play that at this moment to me, a result whether or not we have an interest is just as important; because it is an early-stage play.

If there's only been, I don't know, 50 wells drilled in the modern TMS days, and probably no more than 30 of those have even been flowed yet, or 35, I don't know. But it's just so early.

We've got a great group of operators there that are sharing information. No one is competing for acreage. It's working out really well there. We think it's -- to me it doesn't really matter if we have an interest or not.

Do you know when you stop drilling -- or when you take the two rigs out, once you get these 10 wells done, about how much of that initial HK TMS capital will have been spent?

There will still be some left over. I don't have an exact number for that. Of course, when we stop drilling we still have wells to frac and facilities to put on, and all that kind of stuff, and there's plenty of money for all that.

What's important to us is making sure that we're making progress on costs in the play, and on understanding obstacles -- as Charles was saying, faults and things of that nature, underlying Tuscaloosa Marine sands that are water-bearing sometimes. Sometimes they're close to the Tuscaloosa Marine Shale base. We're trying to figure all that stuff out.

This is so like every other play that we've been in. It's just these wells are a little bit more money, but following the same pattern. Drill days are going down.

People are understanding where to put the laterals and where not to. People are thinking really hard about obstacles. There's some natural fracturing in this play that can help or can hurt at times. It's really an exciting thing to be in such a large oil reservoir and have such a big acreage position, and not have to do anything about it any time soon.

Most of our leases are three plus two, so we have plenty of -- and they're very inexpensive to buy the extra two, so hardly any money there. We're really in a great position to ease back, watch prices, watch cost, review data, and then set a course.

Great. Thank you, Floyd.

Thank you. Our next question comes from Sean Sneeden from Oppenheimer.

Good morning. Thank you for taking the questions. Mark or Floyd, as you think about next year's budget, how comfortable are you guys out-spending cash flows here to achieve production growth? For instance, is there a minimum amount of liquidity that you want to maintain as you exit next year, or maybe can you talk about how you're thinking about that?

I'll let Mark speak in specifics if he has any specifics, but we are very liquid right now. The small out-spend that you might project is well in hand at this time.

We're never comfortable with out-spending, but these shale plays require that by everybody in the industry, not just us. We've decided to cut back on the out-spend dramatically for next year.

Of course we cut back on projected EBITDA, as well. We're trying to keep all that in mind, and run a responsible program that still has a nice growth component. Mark, anything to add to that?

No, I would just simply say that while there is going to be an out-spend next year, we've obviously dialed back spending, and we're looking to reduce that. It will be meaningfully less of an out-spend than in prior years. With the liquidity that we have on the balance sheet, the Company is set up well to execute. Also, it's even further suited to do it when you take the hedge position into consideration.

Certainly I appreciate that. When you think about -- obviously you guys have been on a nice trajectory in terms of de-leveraging the balance sheet, given all the production growth. Has the current commodity price environment or your current plans changed your thought process in terms of where you'd like to get your leverage profile to?

Our overriding plan and instinct has been to reduce leverage. There's only a few ways to do that. The old fashioned way, you grow production and revenue, so that's our basic idea here.

Now we're in a spot where even though we're hedged, prices are down and costs are still high, and perhaps even rising at times. We're just -- we just have to respond to that in a responsible way, and we think we're doing that.

Thanks. Last one from me -- Floyd, or maybe even Charles. Can you remind me what your ball park PDP declines are right now?

Charles, do you have that in mind?

I don't.

Look, it's probably about 30%, but I don't really have that number on the tip of my tongue.

That's probably a good estimate.

Okay, great.

Keep in mind that a 20% growth for next year, you have to replace that 30%, and then grow net-net another 20%. We think we can do that with a relatively small budget.

Great, that's helpful. Thank you very much.

Our next question comes from Jeff Robertson from Barclays.

Thanks. Floyd, can you talk at all yet about how some of that out-performance you've seen in the Bakken and El Halcon would reflect on year-end reserves, and how all that got incorporated into the borrowing base increase yield for the fall?

Yes, and Mark please add in if there's something. But as you may remember, we had a very substantial borrowing base increase at the last re-determination this fall. It went from $700 million to $1.05 billion.

That's basically a consortium of 15 or 20 banks with outside engineers determining that. That's got to be a signal to what we're going to have in terms of reserve growth for 2014.

We've had a great year. It's just -- we're going to have a really good year in terms of reserve growth and cost reductions and production growth. In terms of what goes on, there won't be a re-determination until next spring. I don't know anything about that at this moment. Do you, Mark?

No, we'll see what it holds, but we obviously expect to continue to see an increase in the borrowing base. It's the cheapest form of capital we have, so we'll continue to work with the commercial banks to grow it as we can.

Mark, were there any changes in the pricing on the borrowing -- on the credit facility?

No, there were no changes on the pricing grid.

Okay, thank you.

Thank you. Ladies and gentlemen, that does conclude our question-and-answer session for today's call. I would now like to turn the call back over to Floyd Wilson for any closing remarks.

Well, I have no remarks except to say if we forgot something or weren't responsive just give us a call. We're drilling ahead as we always do.

We're going to have a great year this year, and we're projecting a really good year next. Thanks for dialing in.

Ladies and gentlemen, thank you for participating in today's conference. This does conclude the program, and you may all disconnect. Everyone have a wonderful day.