Vital Energy Inc (VTLE) 2015 Q1 法說會逐字稿

Good day, ladies and gentlemen, and welcome to the Laredo Petroleum quarterly 2015 earnings conference call. My name is Nicole, and I will be your operator for today. At this time, all participants are in a listen-only mode. We will be conducting a question-and-answer session at the financial and operations report. As a reminder, this conference is being recorded for replay purposes.

It is now my pleasure to introduce Mr. Ron Hagood, Director of Investor Relations. You may begin, sir.

Thank you, and good morning. Joining me today are Randy Foutch, Chairman and Chief Executive Officer; Jay Still, President and Chief Operating Officer; Dan Schooley, Senior Vice President, Midstream and Marketing; and Rick Buterbaugh, Executive Vice President and Chief Financial Officer; as well as additional members of our management team.

Before we begin this morning, let me remind you that during today's call we will be making forward-looking statements. These statements -- including those describing our beliefs, goals, expectations, forecasts, and assumptions -- are intended to be covered by the Safe Harbor provisions of the Private Securities Litigation Reform Act of 1995. The Company's actual results may differ from those forward-looking statements for a variety of reasons, many of which are beyond our control. In addition, we will be making reference to adjusted net income and adjusted EBITDA, which are non-GAAP financial measures. Reconciliations of GAAP net income to these non-GAAP financial measures are included in today's news release.

Beginning January 1, 2015, Laredo began reporting production and proved reserves on a three-stream basis. In the news release issued this morning, financial and operating results and well results have been reported on a three-stream basis. In the 10-Q issued this morning, first-quarter 2015 results are reported on a three-stream basis, but reported first-quarter 2014 results are on a two-stream basis. The conversion of production and unit cost data for 2014 from two-stream to three-stream has been provided in the appendix of the updated corporate presentation released this morning.

In the news release and in comments on this call, volume-based comparisons between 2014 and 2015 are made, 2014 results have been converted to a comparable three-stream figure.

Earlier this morning, the Company issued a news release detailing its financial and operating results for the fourth quarter of 2014. If you do not have a copy of this news release, you may access it on the Company's website at www.LaredoPetro.com.

I will now turn the call over to Randy Foutch, Chairman and Chief Executive Officer.

Thanks, Ron, and good morning. Thank you for joining Laredo's first-quarter 2015 earnings conference call.

In the first quarter, the Company continued to benefit from its full field development strategy for its high-quality contiguous acreage position in the Midland Basin. We achieved Company record production of 47,487 BOE per day and now expect production in 2015 to grow between 13% and 16% from 2014.

Infrastructure investments, our focus on drilling efficiency, and reductions in service costs have enabled us to reduce estimated capital cost for horizontal wells both for those drilled on single-well pads as well as those on multi-well pads. As we realize the lower capital costs and drill a higher percentage of more capital-efficient 10,000-foot laterals, returns rivaling those at the higher oil prices during 2014 are possible. Additionally, we expect any further acceleration of development drilling to be focused on our production corridors and executed on multi-well pads targeting the highest-return zones.

We continue to make investments in our production corridor during the quarter, with a focus on water gathering and distribution infrastructure in the Reagan North corridor. This infrastructure is now operational and has been tied into the JE Cox-Blanco corridor to maximize completion and production efficiencies for the 12 horizontal wells we plan to simultaneously complete on the corridor during the second quarter.

The effectiveness of the production corridor system is further amplified by the ability to link corridors to maximize our operational capabilities. Jay will expand upon this in his operational review.

The extensive database the Company has assembled since we began drilling wells on our leasehold is being integrated into our Earth Model to identify optimal landing points for horizontal wells and steer the lateral into the most productive rock intervals. The Earth Model is expected to be especially useful in optimizing well performance and recoveries when landing and drilling stacked lateral targets.

The Medallion pipeline, in which we have a 49% equity ownership, became fully operational in the first quarter. During the first quarter of 2015, the Medallion system transported approximately 7,000 barrels of oil per day. In the second quarter of 2015, it is expected the system will transport at least 40,000 barrels of oil per day, more than half of which is expected to be third-party volumes.

Financially, the Company is well positioned for the current commodity price environment, as exemplified by our recent borrowing base increase, which Rick will cover in the financial overview.

We have a strong hedge position for the next three years to protect a significant portion of our revenue stream. We have strengthened our balance sheet, and that enables the Company to appropriately respond as margins continue to improve.

I will now hand the call over to Jay for a detailed operational review.

Thank you, Randy. During the first quarter of 2015, we achieved Company record production of 47,487 barrels of oil equivalent per day. The adverse weather we experienced this year had minimal impact on our production in the first quarter because of the focused improvements we've made to our infrastructure and operations following the 2013 ice storms in Midland. By consolidating decentralized wellhead compressors into large centralized compressor facilities, we reduced the impact of power outages and production downtime. We continue to get more of our oil production gathered on pipe, which reduces trucking delays caused by inclement weather. Today we have approximately 40% of our crude oil production being gathered on pipe.

We completed 11 horizontal wells in our 4 initially targeted zones consisting of 2 in the upper Wolfcamp, 2 in the middle Wolfcamp, 3 in the lower Wolfcamp, and 4 in the Cline shale. As demonstrated in the production data charts contained in this morning's earnings press release, production data continues to support the type curves we have established for each of these four zones. We have managed our completion schedule for 2015 to focus on efficiency gains by utilizing dedicated completion crews and to take advantage of service cost reductions as they have declined over the first quarter.

In the second quarter of 2015, we expect to complete approximately 20 gross horizontal wells, 12 of which are planned as concurrent completions in the JE Cox-Blanco production corridor. The drilling and completion of these horizontal wells represents the continued refinement of our full-field development plan for our Permian-Garden City acreage. The 12 horizontal wells were drilled as two stacked laterals into what we believe are the two best Wolfcamp targets in this development area. With two rigs working side by side drilling in adjacent lanes along the production corridor, we improve drilling, completion, and production efficiencies and expect to recognize significant efficiencies in water handling, production takeaway, and centralized gas lift.

We can effectively manage the 3 million barrels of water required for completions in less than 30 days, and all flow backwater can be moved on pipe directly to be recycled or to a saltwater disposal well, thus eliminating trucking expense.

Additionally, after extensive analysis of the impact of completing new wells around existing producing wells, we have instituted a completion plan that we believe will minimize the frac impact to nearby wells. We expect to utilize this development model for future horizontal wells drilled as back laterals for production corridors.

As we previously stated when we announced our 2015 capital budget, as we have realized reduced costs to drill and complete wells, whether to then adjust our expected drilling activities we have reduced our capital budget from $525 million to $475 million to continue our original 2015 drilling plan. We now expect horizontal wells drilled on a single-well pad to range from $6.3 million to $6.9 million and horizontal wells drilled on multi-well pads to range from $5.9 million to $6.5 million.

Capital cost reductions on single-well pads incorporate service cost savings as well as efficiencies from our best composite well program that we have reduced drilling times for all zones. [Multi-well] pad comparable costs also incorporate the savings from the tremendous efficiencies intrinsic to drilling wells without rig moves, new pad construction, and completion activities.

As costs come down and capital efficiencies on drilling on multi-well pads with longer laterals are incorporated, rates return on horizontal wells have the potential to rival those previously achieved at higher oil prices. Laredo is well positioned with our production corridors in contiguous acreage positions to continue to drive operational efficiencies and increase activities as appropriate.

I would now like to turn to call over to Dan to discuss our marketing midstream efforts.

Thank you, Jay. As Jay mentioned, the Company's investments in infrastructure to create production corridors provided tangible benefits in the first quarter by mitigating the production impact of severe winter weather. In the first quarter of 2015, LMS crude gathering systems transported approximately 40% of the Company's gross oil production versus none of the production in the first quarter of 2014. As the JE Cox-Blanco wells begin production, the expectation is that LMS crude gathering systems will transport approximately 50% of the Company's gross crude oil volumes. Additionally, LMS gas gathering systems transport approximately 50% of the Company's gross natural gas volumes, up from 36% of the gross gas net natural gas volumes in the first quarter of 2014.

As opposed to the first quarter of 2014, where the Company was utilizing wellhead compression for gas lift operations, we replaced these compressors with centralized facilities which are more reliable and are equipped with backup power systems. The Company's investments in three centralized compressor stations have enabled Laredo to put 26% of its wells on a more cost-effective and reliable centralized compression by the end of the first quarter of 2015. It is anticipated that 45% of the Company's wells would be on centralized compression by the second quarter of 2015.

As of January 1, 2015, Laredo reports production on a three-stream basis and consequently is giving pricing guidance for NGL realizations as well as oil and natural gas. In the first quarter of 2015, Laredo's crude oil price realizations as a percentage of WTI were approximately 86%, slightly better in both second quarter first and second quarter 2015 guidance of 85%.

Several dynamics affect the price we receive for our oil. We have contracts to pay us the higher of the Gulf Coast or Midland markets. This means that as the LLS Midland spread widens, our price realizations benefit and, conversely, are not as strong as the spread narrows. We believe that the optionality embedded in our marketing contracts is of long-term benefit, and we are particularly encouraged by the development of the new WTI Houston index, which we believe will benefit Permian producers like Laredo with access to the Magellan-East Houston terminal.

Our crude oil price realizations are also impacted by fixed-fee transportation, which becomes the larger portion of the price as WTI declines. However, we are also connecting more of our crude oil to our gathering systems, which reduce the overall transportation costs by $0.95 a barrel, partially offsetting the impact of the other fixed transportation fees that affect our realized price. The net effect of these factors is illustrated by the reduction in oil price realizations as a percentage of WTI from 93% in the first quarter of 2014 to 86% in the first quarter of 2015. Similarly, the Company's natural gas processing contracts are based on product prices at Mont Belvieu, Texas, which tend to move in conjunction with WTI. Here, the transportation and fractionation fees are only moderately variable and did not move in equal proportion to the NGL prices, and thus represent a higher percentage of WTI at lower prices.

Our realized price incorporates these fees. Alternatively, the producer could incorporate these fees into LOE. While there are many possible contractual arrangements between producer and plant operator, the majority of Laredo's contracts are classified as a percent of proceeds, wherein the processor retains a certain percent of the proceeds as compensation for processing services. This payment to the processor is incorporated into our realized pricing. Alternatively, a producer could realize a higher price and incorporate the percent-of-proceeds payment into lower volumes for NGL and residue gas.

For comparison, in the first quarter of 2014 on a two-stream basis, our realized natural gas price was 142% of Henry Hub. If reported on a three-stream basis, the realized natural gas price would have been 81% of Henry Hub, and the realized NGL price would have been 33% of WTI.

In the first quarter of 2015, the realized natural gas price was 72% of Henry Hub, and realized NGL price was 27.5% of WTI. It's important to note that there have been no material changes to the pricing provisions of our processing contracts. The lower realized prices relative to their benchmarks has been a function of the dynamics noted above.

As we discussed, LMS is a 49% owner of the Medallion pipeline system that has commenced commercial operations in the first quarter of this year. Average throughput for March 2015 was approximately 16,500 barrels of oil per day. And current May dominations on the pipeline exceed 40,000 barrels a day, over half of which is third-party barrels. The initial pipeline was approximately 88 miles in length and traversed through Laredo's acreage in northern Reagan County and Glasscock County for delivery to the Colorado City hub in Scurry County, Texas. Today, the system extends over 230 miles in four counties with over 100,000 net acres of third-party acreage dedicated to the system.

I would now like to turn the call over to Rick to review our financial results and outlook.

Thank you, Dan, and good morning. As stated in our news release this morning, Laredo reported first-quarter 2015 adjusted net income of $4.4 million, or $0.03 per diluted share, and adjusted EBITDA of approximately $119 million. Production volumes for the first quarter totaled approximately 4.3 million barrels of oil equivalent, a 47% increase from the equivalent three-stream volumes in first-quarter 2014. Even with these increased volumes, total first-quarter 2015 sales for oil, natural gas liquids, and natural gas declined to approximately $118 million due to lower product pricing. This was predominantly associated with a 55% decrease in realized oil prices from $91.78 per barrel in the first quarter of 2014 to $41.73 per barrel in the first quarter of this year. However, our effective oil price for the quarter was actually $69.51 per barrel, or 67% higher than the reported amount, due to the benefit of our strong hedge positions.

The Company has made considerable progress reducing unit cash operating expenses. Unit cash costs for the first quarter of 2015 were $14.07 per BOE, an decrease of approximately 30% from the prior quarter of $20.06 per BOE on a comparable three-stream basis. Reflected in this figure this figure are savings from the closing of our Dallas office and our workforce reduction of approximately 75 employees that was announced in January of this year. A non-recurring charge of approximately $6 million was recorded as a restructuring expense and not included in cash G&A expenses. Depletion, depreciation, and amortization expense of $16.83 per BOE was approximately $2.40 per BOE lower than the midpoint of our prior expectations. The decrease is primarily due to reduced drilling and completion costs that we have now achieved, as Jay detailed.

These demonstrated lower costs reduce our future development costs and lower the total depletable base, which is part of our DD&A calculation DD&A calculation.

Inventory evaluation at lower cost or market for crude oil line fill and materials and supplies resulted in a small impairment expense of less than $11 million in the quarter. The combination of drilling efficiencies and demonstrated reductions in drilling and completion costs has reduced our 2015 expected capital expenditures to $475 million while maintaining the same activity levels. This includes effectively operating the equivalent of 2.5 horizontal rigs and 1.5 vertical rigs during 2015, as well as the carryover of approximately 20 additional completions from 2014 drilling activities.

These carryover activities represent approximately $85 million of expected capital expenditures in 2015. In the first quarter of this year, approximately $40 million of our capital expenditures were associated with work that was begun in 2014.

As Randy mentioned, we have increased our projected annual production growth into the range of 13% to 16% from our 2014 levels. During the second half of this year, the combination of anticipated production, which is underpinned by our strong hedge position, and coupled with our reduced cost structure and lower interest expense, is expected to balance anticipated cash flow with capital expenditures.

As a reminder, Laredo utilizes commodity derivatives to reduce the variability of its anticipated cash flow due to fluctuations in commodity prices. We actively monitor our hedging program and use a combination of puts, swaps, and collars -- none of which are three-way collars -- to hedge a portion of our anticipated production. Details of our hedge positions which run through 2017 are outlined in today's news release.

Starting at the beginning of this year, Laredo has voluntarily begun segment reporting for our wholly owned subsidiary, Laredo Midstream Services, or LMS. The first-quarter 2015 Form 10-Q that was filed earlier this morning includes this information beginning on page 27. I would like to point out that some of the items of note in this presentation.

First are the line items for sales of purchased oil and cost of purchase oil. These items are primarily related to our 10,000 barrels of oil per day delivery commitment to the BridgeTex pipeline.

Secondly is the income [we have] lost from our equity method investee. This reflects the revenue and expenses related to LMS's 49% ownership interest in the Medallion pipeline system. During the first quarter of 2015, the system commenced commercial operations. However, revenues were limited, and they were more than offset by expenses which were primarily made up of depreciation of the pipeline assets. However, we do expect that revenues will continue to increase throughout 2015.

Lastly, I would like to comment on midstream service items and the corresponding inter-company eliminations. The revenue from services provided by LMS to Laredo are basically offset by inter-company eliminations due to Laredo's high working interest in our properties. The difference is primarily the result of third-party revenue paid to transport oil and natural gas on our gathering systems.

In early March, the Company called the entire $550 million of 9.5% notes that were due in 2019. The notes were fully retired in April of this year, and therefore they are presented on our March 31 balance sheet as short-term debt.

On Monday of this week, our 18-member bank group completed the regular semi-annual redetermination of the Company's senior secured credit facility. The significant increase in the quantity and quality of our proved reserves, coupled with our strong hedge position, was recognized even in the current reduced-price environment. As a result, lenders increased the Company's borrowing base to $1.25 billion. Discussions that we have had with our lenders has given us confidence that this borrowing base will continue to be supported through the fall redetermination even at current commodity prices. With this increased borrowing base, the Company has elected a commitment level of $1 billion. This results in current liquidity of approximately $950 million.

At this time, operator, will you please open the lines for any questions?

(Operator Instructions) Brian Gamble, Simmons & Company.

Good quarter. Good job on the cost side. I wanted to touch on that, if I may, for a minute. The both single- and multi-well pad costs look good. As far as the reduction is concerned from either where we were in the fourth quarter or from full-year 2014 averages, is there any way to break out what piece of that is due to cost concessions from service providers and what piece of that is due to efficiencies that you guys have been able to implement?

I think Jay may have better numbers. But I think the important thing is we started talking -- this is Randy; I'm sorry, Brian. We started talking well over 18 months ago or so that we were starting to see some real efficiencies in our drilling -- efficiencies in our completions. And we talked about our best well in 2012 was our average well in 2013, and 2013's best well was the composite well was our average going forward.

So we are seeing some pretty meaningful efficiencies that we think are the result of not only paying attention and good operations, but just the fact that the way we have set up with contiguous acreage and our ability to drill these. We've stated that we've seen somewhere around maybe as much as 20% or so for the year in terms of actual cost reductions. And so I think it's pretty much a combination of those two. But we started seeing the capital efficiencies in terms of how we were operating materialize well before service costs started running down.

Brian, I would characterize it in 2014 as demand really started increasing, pretty much able to keep our drilling completion costs flat primarily from the improvements we made and efficiencies on the drilling side versus completion cost inflation. So just from our Cline wells, we were able to reduce the drilling days about 25%. But the drilling is about 40% of your total well costs. So in total, we are seeing about a 20% reduction in our drilling completion costs, and I would say probably 7% of that is -- 7% to 10% of that is actually efficiencies in our remainder of service costs -- round numbers.

That's great, for future planning purposes. And then as far as kind of the language in the release -- and maybe I'm reading too much into this, but it sounded like a potential transaction maybe may be less likely now than it was three months ago. I know the balance sheet has changed considerably, and kudos to you guys for getting that done. But anything that the, I guess we'll call it, inflation in current oil prices and the $60 curve for the back half of the year, does that change the thinking at all, Randy, as to how what a deal with look like and/or the number of people that potentially would be interested?

Brian, I think we stated clearly all along that we really kind of had three goals that we wanted to accomplish. And if we couldn't get those three goals, we didn't think it would be in the best interest of shareholders. And those three goals (technical difficulty) again to somehow or another put additional CapEx to work on our acreage that wasn't our capital and accelerate spending on the area that we have. We stated that we had 3,200 locations ready to go in which we are the operator with a 90% working interest.

So our first goal was to start working on that inventory. The second goal was to increase cash flow and EBITDA sooner rather than later. We felt like that was pretty critical. The third one, which was stated all along as might be the hardest goal, was to make sure that we didn't do a deal that in any way changed the pristine nature of the Company or our acreage in terms of having lots of side joint venture drilling funds and transactions that one would have to look at.

So the Company received pretty significant interest regarding those type of opportunities. We've not reached any terms that we think would be beneficial to shareholders in terms of meeting those three goals. Further pursuit may occur, but I don't think we can do more than say that no assurances of any discussions or transactions will occur.

Sounds good. Appreciate the detail, Randy.

David Tameron, Wells Fargo.

Good morning. If I just think about the cost structure, obviously some good improvements thus far. Can you talk about where you think we are at as far as obviously some more efficiency gains coming? But as far as just overall costs, where would you expect them to trend? I know oil price dictates part of that. But if oil is at $60, let's say, where would you expect the cost to trend in the second half of the year?

I think we have publicly and internally stated that for a while that in our experience once there's this period of confusion where commodity prices and margins and service costs are adjusting, and then once that's kind of behind us, we have a little bit of stability going forward. But I think there is still some pressure on service costs. I don't know how much more of that we will see. But as commodity prices improve, I think historically service costs have been slower to adjust upwards, historically.

So we continue to work -- we like our service providers. They understand that we have decades of drilling. They want to be with us. When this thing stabilizes and turns around, we want to be with them. So I think there is still some pressure on service costs. I don't think we are going to see another 20% or 30%. Jay, do you want to --

We still have -- it's supply-demand works. You've got a 47% decrease and -- rig count in the Permian Basin, there's an over-supply of a lot of services. We're being offered some tremendous discounts on a lot of services, but quality is also suffering as well. So we pay very close attention to make sure we get quality service. But I do think costs will continue to come down, but I'm not thinking we are going to see another 30% drop in the second half of this year.

Okay. And Jay or Randy, along those lines, obviously discounts are being offered. Have you guys changed your philosophy at all as far as -- I know Randy, in the past you have never really locked in or been hesitant to lock in some long-term service contracts. Anything you are seeing out there that would change that? I know it's always been a handshake agreement, but can you address that?

We've stated in the past we have never really wanted to have long-term contracts. We feel like having flexibility was pretty important to us. We have signed some one-year-or-less service contracts. Our view is that even today that we are probably better off preserving flexibility and having less service costs under contract than we are to have more.

Okay. That's fair. And then in the Wolfcamp -- when I look at those -- how much data do you have on the 10,000-foot laterals? How many days of production at this point?

We've got pretty significant production data on some of our earlier 10,000-foot laterals. We've got about 400 days on a few of them. I think we showed in our analyst day type curves as the EURs on the wells that we had significant days on. So we had 6 wells that went into our upper Wolfcamp type curve, and those have over 300 days of production.

Yes, that's where I was going. It looked like just that upper Wolfcamp cume -- average cume production per well came down a little bit from 45 or whatever it was in there before -- 44. Can you -- is there anything driving that down? Is that just statistical numbers, or can you talk about that? It looks like the recent add in production was a little lower than on a per-well basis.

We show that, I think, on page 18 of the current presentation, with our lateral type curves and the number of wells and the number of frac stages and -- pushed out to 10,000-foot laterals. And in the release -- Jay, do you want to --

What I was looking at is that 88 in that table you show versus the 90 prior.

Oh. I see -- when we are talking about the 180 days?

Yes. It just looked like those upper Wolfcamp wells, the averages came down a little bit. Right when you do the math and back out, per-well averages, it looked like it came down a little bit. I was just wondering if there was anything specific driving that or if it was just noise in the numbers.

No (multiple speakers) are type curves we continually throw all the wells that oscillate around the mean into our type curves. That's why we really look at long-term data to see where we are going. And you know this that's 365 wells have been on for over a year -- continue to support the type curve, and that's just a manifestation of statistics.

Okay. That's all I got. Thanks.

Brian Singer.

Just one question -- when you think about a scenario if oil prices kind of stay where they are, how would you think about what you would need to see in the key milestones from a balance sheet cost and CapEx cash flow balance perspective for how you think about your trajectory? What would your rig count look like if these prices hold? And how would that change if you did get a joint venture done?

Just on the joint venture side, if we do a joint venture and it accomplishes those three goals, then our view is that it's potentially something pretty good for shareholders. But we are not in any way speculating what a joint venture or a drilling fund or any kind of a transaction like that would look at.

We were pleased with response we had, but we were very, very specific in that anything we did there would need to accomplish those three goals. We are actually -- as Rick and I both stated -- we are pretty pleased with our financial capability in terms of increased borrowing base and the way we view our entire balance sheet. Rick, do you want to talk?

Brian, we certainly have changed our balance sheet. We've positioned the Company to have the flexibility to take advantage of opportunities as they come about. We've talked about the large inventory of projects that we have in place. We certainly want to bring that forward as quickly as possible, but we also want to ensure that we are making solid investments. And so, as we see stability to the margins it's not just increasing commodity prices. It's a combination of the commodity price and the service cost and outlook going forward as far as is this the right time to -- when is the right time to bring in additional activities and start to do that.

We do not want to put ourselves in a position that stresses the balance sheet. We've seen commodity prices in the past that come down in the similar cycle that we are experiencing today. And it takes a while to come back. Prices can stay down lower for a longer period, and we want to be prepared to be able to handle that period so that the large inventory of projects that we have identified will be realized.

And so I guess to follow-up, then, is the price environment today if we just assume today's prices hold and today's costs hold, is that then -- are your returns then consistent with increasing activity if you see that stability? And when you talk about you don't want to stress the balance sheet when we think about an upper limit, what is the limiting factor on how quickly you can accelerate it? Is it based on a leverage requirement? A CapEx cash flow balance requirement? What is it that you look to?

Brian, I'll let Rick follow up. But the point that we've been making internally and externally is that -- again, when you talk about having 3,200 locations in which we operate and have a 90% working interest, those are ready to go. High quality backed up with all the data you need. And there may be another several thousand -- I think we talked about that on page 8 in the slide deck.

I think there's clearly a need for us at some point, when we see margins stabilize, to be very concerned about how we view that long, long decades of inventory. We are seeing that with our capital efficiencies. We are seeing with the cost reductions that we are starting to get back to the same type of margins that we saw during earlier 2014 when prices were much higher. So the 50-, 60-year -- 40-, 70-year inventory is something that we are going to have to pay a lot of attention to for years to come.

We've talked a little bit, Brian, about the fact that we do have a large inventory and capabilities with our contiguous acreage position to drill longer 10,000-foot laterals. We are seeing encouraging results with the longer run time from those longer laterals that gives us confidence that we can drill those within the margins that we are seeing today that could rival the returns that we are were achieving last year. I think we want to see a little more stability in those margins before we really ramp up activities associated with that.

Financially, we feel that we are in very good position to be able to do that. Our debt to EBITDA is very comfortable. And especially given the lower commodity prices, I think most companies and certainly we are a little more comfortable at a higher level in a low-price environment than we would have been or were in the past in a $90 to $100 price environment. But we are not going to run activities based upon hope or expectations of commodity price increases. We are going to base it upon what we are seeing today.

Thank you.

(Operator Instructions) Ipsit Mohanty, GMP Securities.

Thank you. I just wanted to see the fact that you are already getting good reduction in well costs, and you guided with something lower when you start multi-pad development. I'm assuming that given the focus here in 2015 will be HPP and doing single-well pads. Do you see these costs being realized more in 2016 than 2015? The 5.9 to 6.5 range?

I think we're anticipating that we need to see a little bit of -- before we would feel comfortable talking about 2016 -- we haven't talked about any real 2016 guidance -- I think our view is that we like the way that the margins are heading directionally. We are encouraged very much. We like the way the service companies have been very proactive in approaching us in terms of reducing cost. But there is obviously still a little bit of stabilization that we need to see on what our ultimate margin is. And we are still a long ways from talking about 2016.

As we move forward -- you're right -- the 2015 program is really focused more on acreage holding, which is going to involve more one-off type drilling. We've talked about in the past that as we get through 2015 and 2016, we have more flexibility on our CDC requirements, where more and more of our acreage becomes held. We are always going to have CDC drilling requirements, but it gives us a little more flexibility to drill along our corridors even in a lower activity level than we have in 2015. So, yes, we would expect to see those costs trending down going forward, keeping everything else consistent into that 5.9 to 6.5 range.

Appreciate that. And I know that you really don't want to make much of 2016 right now; it's too early. But the way you managed your balance sheet very nicely -- and now you've done a great job the last couple of months bringing it to where it is right now. But maybe your outlook is now you are drilling -- you are going to drill within cash flows. Is that the mindset now for the future years, for 2016? As well, is that going to be a very key criteria that you would look at as you start priming up 2016, drilling within cash flows that is?

We have always -- recently or last several years been stating that we want to be able to self fund a greater and greater percent of our capital expenditures. We had intentionally outspend by a significant amount both in 2012 and in 2014 specifically to gain data and understanding of our acreage, how it was going to -- what was going to be the most efficient way to go about the development. So we did spacing tests both horizontally and vertically. We tested multiple zones, the 4 initial zones that we have targeted for full development as well as tested some other zones, which we think we needed to do to understand how do we plan the development over this contiguous acreage position to make sure that we are efficiently extracting the maximum value of the entire asset.

And so with that, we did outspend in those years. We do want to spend much closer within cash flow in the future. But an asset like this in the right price environment, we are willing to add debt. I think our overall leverage position, though, will continue to come down.

Got you. Great. Thank you.

Richard Tullis, Capital One Securities.

Just two quick questions, Rick or Randy. I'm not sure if you provided an update on the canyon information. You had the one well that you talked about at the analyst day and then I guess a second well that was getting close to completion at that time. Any updates there?

Jay, do you want to --

Sure. One well we've had on for a couple of months now is actually doing slightly better -- about 11% better than our Cline type curve. It is a bit more gassy than the Cline. The second canyon well, we are in the progress of completing it right now.

Okay. And then just lastly, I know at the analyst meeting you also had mentioned about 70% of your core production -- excuse me, your core acreage held by production. Going forward, do you risk losing any substantial portion of that remaining 30% with, say, the current 5-rig program extended out into next year?

No. The interesting thing to us is that we've talked about for years that other operators are now actually bringing additional zones to bear besides the ones that we started off with. And, Richard, as you know, we kind of started drilling in this area first. And I think our plan back a couple of years ago was evolving to the point to where we felt like we wanted to keep as much of the acreage together. We knew that there was going to be additional zones. And there were some announcements made this morning and yesterday about some zones that probably impact our acreage; we are fully expecting that.

So our plan for a number of years has been to -- let's make sure that we keep the acreage together until we get data to decide exactly what we want to do with it. I think obviously on an 80-mile-long trend there will be some acreage that is more important than others. But I think you should expect that most of the acreage we are going to keep together because we think it is valuable.

Thanks, Randy. Appreciate it.

Thank you. And I'm showing no further questions at this time. I'd like to turn the call over to Mr. Hagood for any closing remarks.

We just wanted to thank everybody for joining us for our first-quarter 2015 conference call. Operator, you may now disconnect.

Ladies and gentlemen, thank you for participating in today's conference. That does conclude today's program. You may now disconnect. Have a great day, everyone.