Lilis Energy, Inc. (LLEX) CEO Ron Ormand on Q1 2019 Results - Earnings Call Transcript

About: Lilis Energy, Inc. (LLEX)
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Earning Call Audio

Lilis Energy, Inc. (NYSEMKT:LLEX) Q1 2019 Earnings Conference Call May 10, 2019 11:00 AM ET

Company Participants

Joe Daches - President & CFO

Ron Ormand - Chairman & CEO

Jim Denny - EVP, Production & Operations

Conference Call Participants

Neil Dingmann - SunTrust

Ronald Mills - Johnson Rice


Good morning, and welcome to the Lilis Energy First Quarter 2019 Financial Results and Corporate Update Conference Call. All participants will be in listen-only mode. [Operator Instructions] Please note, this event is being recorded.

I would now like to turn the conference over to Joe Daches, President and CFO. Please go ahead.

Joe Daches

Thank you. Good morning and thank you for joining Lilis Energy's conference call. Today, Lilis management will discuss financial results for the quarter ended March 31, 2019, and will provide an update on corporate developments along with second quarter 2019 outlook and guidance. After the market closed yesterday, we released our financial and operating results. If you have not yet reviewed our earnings release, please visit our Investor Center at the company's website,

Our remarks today may contain forward-looking statements. Such statements are subject to a number of assumptions, risks and uncertainties, many of which are beyond the control of the company. Participants are cautioned that any such statements are not guarantees of future performance and the actual results or developments may differ materially from those projected in the forward-looking statements. Please see our earnings release for a discussion on these statements and associated risks. We also refer to certain non-GAAP measures, so please, see these reconciliations within the earnings release.

Joining me today is our Chairman and CEO, Ron Ormand; Jim Denny, EVP of Production and Operations; Saurabh Devarjan [ph], Chief Technical Officer; and Wobbe Ploegsma, Vice President of Capital Markets and Investor Relations. During this call, we will review the results for the first quarter of 2019 and then discuss outlook and guidance for the second quarter of 2019.

I will now turn the call over to our Chairman and CEO, Mr. Ron Ormand.

Ron Ormand

Thanks, Joe and good morning everyone. Welcome to our first quarter 2019 earnings call and corporate update.

Before we start, I would encourage everyone to please review our earnings presentation posted at our website for additional details and other operational updates. First, I'd like to thank all Lilis employees for their hard work as we continue to make strides in growing our asset and production base. I would like to start this call by stating that despite weather conditions and third-party midstream issues, we still made our stated production guidance for the first quarter. We continue to make significant progress on all of our strategic goals.

During the first quarter of 2019, we unfortunately experience continued natural gas production efficiencies from our third-party midstream partner which negatively impacted production. Our outlook and guidance will continue to be focused on oil and liquids mixes as approximately 90% of our cash flow is derived from oil and NGLs. I would like to now go over our first quarter 2019 highlights and then provide a brief overview of our second quarter 2019 outlook and guidance.

First quarter 2019 highlights include the following: the company had 6 DUCs at the year-end 2018. Of those 6 the company has brought on the Oso #1H during the first quarter of 2019 and completed the Haley #1H and the Haley #2H in early April. Our Northeast Axis well has recently fracked, and is currently prepping for flowback. Prep [ph] completions doing the first and second quarter are expected to significantly benefit future quarters in 2019 as production ramp-up timing coincides with uplifts and realized pricing and substantial margin enhancements. In addition, compared to March 31, 2018, we've increased our proved reserves by 298% to approximately $44 million Boe with 68% consisting of liquids, 51% oil, and 17% natural gas liquids at March 31, 2019.

As mentioned on our last earnings call, during the first quarter we improved our capital structure through the exchange of our previously outstanding second-linked term loan which was significantly decreased our indebtedness in any near-term prepayments of debt.

Now, I'd like to give a quick operational update. During the first quarter of 2019, the company strategically opted to frontload a portion of its 2019 capital expenditure budget, strategy is designed to maximize associated production revenues in upcoming quarters as timing coincides with significant uplifts and realized pricing and other margin enhancement, including realized LOE costs. Several wells that accounted for significant capital spend during first quarter of 2019 have begun flowing to production, including the Oso and two Haley wells. Haley #1H and the Haley #2H began flowing to sales on June 6, 2019, and the North East Axis has finished completion and commencing flowback with the North West Axis scheduled for later this month.

The Haley #1H recorded an IP24-hour rate of 1,422 Boe per day; 1,124 Bo per day, which is 90% liquids and 79% oil, with 317 Boe per day per 1,000 lateral feet. The Haley #2H, recorded an IP24-hour of 1,048 Boe per day and 639 Bo per day; this is 81% liquids and 61% oil or 234 Boe per 1,000 lateral feet. We're extremely pleased with the results of these two wells, which both exceeded IP rates for 1 mile wells and Haley #1H exceeded our 1.5 mile target IP24-hour rate. We experienced significant margin improvements as realized pricing from contracts and reduced SWD costs. Second half of 2019 should bring even better pricing realization compared to WTI along with continued benefits from our SWD contracts.

Our quarter-over-quarter production was flat to slightly positive on a Boe basis, which we believe speaks to the quality of our existing production base when considering only one well, the Oso, was bottom-lined at the tail end of the first quarter. We're optimistic about the continuing growth in production and cash flow in the second quarter, and especially in the third quarter when all our DUCs are online with increase realized pricing commencing July 1, 2019. Thus we expect to see very meaningful sequential increases in our EBITDAX in the second and third quarters of 2019.

Capital spending in Q2 2019 will be focused on completing the remaining DUCS, including the two Kudu wells, which we've just recently completed drilling. We're trying to see the production and revenue continue to improve as DUCs that are turned to sales, management continues to evaluate and closely monitor our capital program with the goal of continued improvement of CapEx returns in second quarter of 2019. We have made significant technical advancements in the 3rd Bone Spring and choke management, resulting improved production rates on previous new wells, as recently demonstrated in the Haley wells.

We continue to target cash flow neutrality in second half of the year under a one-rig program. However, we're seriously evaluating the second-rig in the back half of the year as our fundamentals and technology continue to improve. We've also added depth in our technical team with the addition of Saurabh Devarajan [ph] our Chief Technical Officer, and Chris Cantrell, Senior Vice President of Planning & Engineering. We expect to add additional personnel to our operations team, including senior personnel to position the company, to expand our operational program.

I'd now like to turn it over to Saurabh [ph] to give additional review and update.

Unidentified Company Representative

Thank you, Ron. I would like to go over a few technical updates, starting with two of our well results in the Bone Spring, which we are very excited about.

First, the Tiger #3H, which is a 1.5 mile, 3rd Bone Spring well, that started production in October 2018. In about six months, the Tiger has produced nearly 95,000 barrels of oil, which is actually not very far behind our 1.5 mile Wolfcamp type curve performance, with the lowered D&C cost and the shorter cycle times factored in, we determined that the Bone Spring development well has an IRR that's similar to our Wolfcamp.

Second, the AG Hill #2H well targeted a shallower 2nd Bone Spring landing zone; this well was drilled in the eastern part of the acreage. So while it had first production in August 2018, this well was shut in for about three months post the initial flow back, pending midstream takeaway. The AG Hill #2H was put back on production towards end of last year and continues to impress with its performance. Most recently, for a couple of months the well stayed very flat at an old rate of about 400 to 500 Boe per day. Just to be noted, the AG Hill #2H is a short lateral but performance-wise is close to the Tiger #3H ,which was a 1.5 mile well. Our current 1.5 mile Bone Spring type curve, is based on the Tiger #3H which means a future AG Hill #2H which means of future AG Hill #2H type well, build at 1.5 mile length, has the potential to be even better than our current one Spring type curve.

Offset operators have targeted similar intervals in the Bone Spring with success; so this truly has potential to be a regional play and not just a localized target. But for physically speaking, we definitely see these zones of interest present with very good reservoir properties across our acreage. While this is a small sample set, we will continue to monitor performance and collect data on the Bone Spring targets that we have identified. So far, we're happy with what we're seeing and believe the Bone Spring will be a significant part of our long-term development plans.

The other item we get asked about is the well spacing; so wanted to address that next as best as we can. We drilled our first spacing test on the 2 Haley Wolfcamp A wells; the Haley #1H and #2H are spaced about 600-feet laterally. Landing zones are vertically offset by about 150-feet. Wells were zipper fracked [ph] in April of this year, and we realized efficiencies on the operation side were not running into any issues. So far, as Ron mentioned, we're very pleased with the flowback from both the wells and continue to monitor the data. In addition, we also continue to monitor results from spacing tests offsetting us to the South and West in Texas. We've seen several examples of 660-feet spacing tests in the Wolfcamp A and the Wolfcamp B, south of us that are very encouraging. Notably, we've also seen a 330-feet staggered spacing test that has generated compelling oil volumes at the pad level while recognizing it's hard to dig into individual well with the public data.

Another near-term value driver that we're seeing are some of the recent prolific 1.5 miles and the 2 miles wells immediately offsetting our acreage in New Mexico. These long laterals significantly exceed our current Wolfcamp type curve and we are excited for the potential in that area as well, going forward. I also want to talk about our recent data from new choke management and flowback strategies. We've been involved in data swaps with offset operators, have been studying the results of different flowback methodologies from various landing zones. Including our own wells, we have a dataset of over 75 wells that we have used to develop a flowback thesis to optimize NPV without sacrificing EUR or future value. As a first test of this thesis, we've deployed a more aggressive flowback on the two Hayley wells that were mentioned earlier. So far the results have been very encouraging on the Hayley's, which has given us the data support to try a similar approach on the upcoming Kudu Wolfcamp B wells. While we're cautious to consider individual geology and nature of fluids before applying these learnings across the field, we strongly believe that we are on the right path to maximize NPV in each well without harming future performance or EUR.

To summarize, we have opened up a transformational new play in the Bone Springs, which we believe is present across our acreage position and has the potential to be a significant part of our development strategy going forward. We are modifying our flowback strategy based on our own learnings and operated wells and supplemented by data from offset operators with the aim of maximizing NPV. This also dovetails with tweaks and optimizations that we are considering, currently implementing on the completion side. Lastly, we have drilled our first Wolfcamp A spacing test in the Hayley's and are very encouraged by results so far. Combined with the LOE realizations and pricing up less that Ron and Joe have discussed, we believe we are well-positioned to execute technically on all the above items and to generate compelling economic returns on future wells.

And now I'll turn the call back to Joe.

Joe Daches

Thank you, sir. I'd like to review our 2019 financial highlights, second quarter and year-end guidance along with providing a brief update on midstream. Despite adverse weather conditions and midstream inefficiencies, we increased our net sales production volumes by 75% to 6,058 Boe per day, including a 52% increase in crude oil production to 3,530 Boe day for the quarter ended March 31, 2019. We also recognize realized oil pricing equal to 84% of WTI during the quarter, including realized pricing of 93% of WTI during the month of March, resulting in approximately $16.50 per barrel benefit within our realized prices of oil during the month. Our commodity mix was 72% liquids, including 58% crude for the course. Revenue from oil, natural gas and NGL was $17.7 million versus $14.4 million for the same quarter in 2018, which was a 23% increase. This increase was primarily attributable to increased sales volumes at which was partially offset by a 14-hour decrease in commodity prices compared to the prior year.

Beginning March, 1; Lilis realized crude prices significantly improved due to a combination of reduction in crude transportation costs and realized Gulf Coast crude pricing through FD contracts. Lilis realized oil price increased over 40% compared to January driven by strong Gulf Coast pricing. Realized pricing of 93% of WTI in March, resulted in approximately $16.50 per barrel or over 40% improvement from January, and these substantial enhancements and profit margins are expected to increase throughout 2019.

Our recurring production costs decreased from $10.08 per Boe in 2018 to $7.26 per Boe in 2019. This decrease in production costs resulted from lower SWD costs, as well as lower overhead costs per Boe produced. We expect continued improvement in our Boe metrics with our projected increases in production. We reduced our total GAAP G&A expense by approximately $1 million or 8% quarter-over-quarter to $9.7 million for the quarter ended March 31, 2019, and on a Boe basis, our recurring G&A per Boe was reduced to $6.58 per Boe in Q1 2019 compared to $14.54 for the same period in the prior year.

Adjusted EBITDAX during the quarter ended March 31, 2019 with $6.5 million compared to $4.5 million during the same period in 2018, this is an increase of 45%. This increase was primarily driven by increased revenue resulting from higher production volumes and realized pricing contracts, as well as lower operating expenses per Boe during 2019. Total CapEx during the first quarter was $33.4 million. D&C capital expenditures during the quarter were $24.5 million, which primarily consisted of DUC expenditures of $19 million, and an additional $5.5 million in 2019 drilling program expenditures. The additional $8.9 million relates to non-recurring expenditures from work overs, facility expansions, the path for pilot tests, as well as freshwater sourcing wells.

Now to move on to 2019 outlook. Our outlook provides for a flexible development that provides the company optionality with respect to adjusting capital spending based on changing market conditions and our strategic objectives. This plan provides for positive growth and production in 2019 while maintaining low leverage. We are projecting second quarter 2019 oil productions to range from 3.6 to 3.8 MBoe/d and NGLs to range from 800 to 1000 barrels a day with our liquid mix accounting for approximately 70% to 75% of our total production. We expect to realize crude pricing to be between 90% to 95% of WTI, and CapEx to be between $15 million to $20 million. We expect to see recurring lease operating expenses to remain between 7 and 7.50 per Boe for the second quarter of 2019 with increasing improvement throughout 2019 in the Boe metrics.

For the full year, we've increased our CapEx budget from $50 million to $60 million to $67 million. We've also increased our full year top-line oil production from 4.6 MBoe/d to 4.8 MBoe/d.

Before we open the call for questions, I'd like to take a moment to provide a brief update on third-party midstream operations. We've recently begun to see positive results from our third-party midstream provider resulting in a significant improvement in runtime. These improvements are correlated to the completion of many operational and mechanical improvements made to the gathering, treating and processing midstream facilities. We continue to independently evaluate a number of these field-treating options to improve production. And we are cautiously optimistic about our progress, and we will continue working on and observing these solutions, improvements and efficiency.

I want to conclude by saying that we have taken significant steps to position the company to maximize the value of our assets with a much more favorable balance sheet. I'm confident of the value of the assets, and the future of our company.

And with, that I'd like to open up the call for questions.

Question-and-Answer Session


[Operator Instructions] Our first question comes from Neil Dingmann with SunTrust. Please go ahead.

Neil Dingmann

Maybe, Ron, a question for you or Jim. It sounds like - I'm just wondering geologically and geographically now, do you all think you've sort of delineated now everything; it sounds to me like you have based on what - you know, Saurabh [ph] and Ron, what you were talking about - but just could you comment about the program as how is it looks the rest of this year and going to next year? Is it more of just kind of now development mode, if you would?

Ron Ormand

Now, I'll let Saurabh [ph] comment a little bit on our technical side of it but I would say that in terms of our delineation mode, what we're doing now is really focusing on the most profitable benches, we're really not looking to do further delineation during 2019. Having said that, we've done a substantial amount of that delineation already; so we don't see a need to do substantial delineation in 2019. I think we've got that somewhere between five and six good benches now that we can look to including the more recent very favorable results we're seeing with the Bone Springs, which we will incorporate more into our future development program.

And then we also still have the New Mexico acreage where we haven't moved up to yet with permits, which we believe could be exceeding our current Wolfcamp type curve in Texas based upon the offset results we've seen up there. So, we have plenty of good inventory without doing further delineation. However, we have delineated substantial amount already of our acreage, but it's not the say that we don't have additional potential within other benches in the acreage. Saurabh [ph], you want to add anything?

Unidentified Company Representative

No. Just as Ron said, Neil, we've got 30-plus wells, we've got a lot of datasets, we're doing data swaps with offset operators. So, I think we have learned a significant amount in the area. So we're understanding things like oil production, the IPs, the response to flowback, and all that; so I think we've got a great handle on what the technical dataset looks like.

Ron Ormand

Yes, I would say one of the things we've done is some of the non-recurring CapEx was related to their panther pilot well on the east and also some seismic data; so that we have data, both, over in the east and now we're looking at seismic data up in the New Mexico area before we commenced drilling there. So there is some front-end loaded information that we have as we move forward.

Neil Dingmann

At least been a good point, Ron, and at least my second question is as far as; I've come about adding a second rig, I agree. It seems like you all have shown you can certainly, if choose, stay with one rig or within free cash flow or go ahead and grow. It seems to me to - I don't know, I'm just kind of curious on how you all think about creating the more shareholder values that today potentially adding that second rig, given you wouldn't see a huge increase in costs and such around that.

Ron Ormand

Again, that's something we're very carefully evaluating. There are number of factors involved with that and in terms of making sure fundamentals like oil pricing. We obviously have the benefits in the second half of the pricing. We have this fishy [ph] take away, we'd like to get to the New Mexico, although that may be later in the year to be honest just because of permitting but we have with the delineation of the Bone Spring, that could be an area that we could drill quicker bringing cash flow on a much faster basis because it's a shorter-term cycle and bring more forward more NPV and IRR. I think we will be making a decision on that in the very near future, but given some of the technical data, the fundamentals, our results, and also our - what we see coming up really in the second and third quarter in terms of our EBITDAX ramp is quite significant. And so, that kind of also help support us in terms of what we can do on a go forward basis.

We're going to see a good benefit of what we've done in the first quarter in the second quarter, but the third quarter is where we're going to really see the production uplift. And I think we'll see at least a doubling of EBITDAX assuming current prices as we get through the third quarter, and potentially in the second quarter. So, with the margins, and the production, and the cash flow; it positions us to do that. We would like - we're still sticking with our one rig program, but we're evaluating that on what's the best way to bring the value forward for the company.

Neil Dingmann

No, it makes sense. And what do you think about - what do you and Joe think about hedging side, you could do start ramping that up with the research, if it hedges with that or not necessarily?

Ron Ormand

We're very well hedged right now, but we would have additional hedges put in place. So we are hedged up to about 60% of our actual production, it's 80% of our PDP, okay. So we're very well hedged, mostly callers; but yes, we would look to do that as well. That would probably entail moving some more hedges in '20 where we have less hedges because a lot of that production would come on towards the end of the fourth quarter.


Our next question comes from a Ronald Mills with Johnson Rice. Please go ahead.

Ronald Mills

Good morning. A quick question; I have a little follow-up on what Neil was just asking. As you noodle-through potentially looking to add a second rig - and he talked a little bit about what that also does, not just to growth second to third quarter or even that would be a longer updated outlook, but - what that does in terms of the balance sheet and kind of leveraged position? And how you weigh growth and kind of accelerated deleveraging versus standing pat at the one rig program?

Ron Ormand

Well, I think I'm going to let Joe handle that but if we look at our one rig program, our leverage is just - it's coming down quite substantially. We are mindful of maintaining a very - much more conservative leverage position as we move forward. So, I think there are liquidity events, as well as not just leverage, including cash flow that can support the expansion of our activities. Joe, do you want to talk about that?

Joe Daches

Yes. Thanks, Ron. Hey, Ron. How are you doing? I think the one rig scenario and the cash neutrality that's expected in the second half of the year puts us in a scenario that we're less than 2 times levered for sure. And it progressively gets better and like an inverted wedge on each of the progressive quarters throughout the year. We're very mindful of leverage and indebtedness and making sure we're doing the right things, and what we have right in front of us is our redetermination of our borrowing basis scheduled to happen in the month of June. We feel pretty good about what's going on and in all things that would support advancing up all to another set. And as Ron mentioned, we've got a handful of liquidity enhancement items in front of them, some are significant, some are less than right; but the reality of it is, we're - if we bring in a second rig, we want to make damn sure that we don't start pushing the needle the wrong way on leverage.

We will continue our disciplined approach to making sure that our leverage does not get out of whack. I mean, I don't know how else to say each other than just to be straight up honest on that one. If we bring a second rig in we would be very careful as to how much CapEx we spend in the current year and what that production and what the resulting cash flows are. I think we all would recognize that bringing a second rig on in the second half of the year, that 2020 would be the big benefactors, would really benefit from that second rig program and that's very interesting to us as well.

Jim Denny

I think also as you look at the growth of the company and with the cash flow, with the growth coming in, if you're not looking about any elevated leverage from that because we're going to have benefits coming back; it might be in the short-term but in the long-term, it may actually bring our leverage down.

Ronald Mills

Okay. And just want to follow-up on that, in terms of the liquidity in enhancing - in enhancement opportunities; I saw in the Q you mentioned potential sale of some royalties, you also have some non-core assets sales; I mean you're getting a better handle on the various zones and across your acreage position. What kind of - I guess, how much or what are you looking to accomplish or how much liquidity can you can you bring in? And what are the primary assets that you're talking about it in those royalties and non-core sales?

Ron Ormand

I think it's - I don't think it's something we can then comment on in terms of specifics. I'll say this, you know, we're not looking to - we want to make sure that what we sell lives us with a very meaningful position, certainly not impacting the working interest that we've worked hard to get ourselves back up to, okay. So, it would be obviously in areas where we have drilled for we have higher working interest; so we're not impacting the overall economic. It wouldn't be you know a huge number but it's certainly a meaningful number for us if we chose to go that direction, okay. So we have to look at that, we have a water asset that we have talked a lot about, water - fresh water sourcing. We're putting data together on that, we've got close to 100,000 barrels, up 50,000 barrels today and we can ramp up to about 100,000 barrels of fresh water. And this was part of the non-recurring costs we had in the first quarter, drilling those fresh water wells but that also is a business that can be monetized and we didn't start out that way but it really - because of the need for fresh water and some cost advantages that we have, we're going to look to either monetize or JV that business.

I wouldn't - I don't know that will be a near-term event, but certainly I wouldn't start within the next six months. It gives us - we have some strategic advantages and it's become a valuable asset, it's not really recognized in the company right now but obviously want to monetize it, it would help me.

Ronald Mills

Right. And then when I - given the tight curve data and the relative returns in which - in terms of EUR is pretty similar, the IRR is pretty similar as well with the Wolfcamp. When you think about it longer term, how do you think about potential allocation between the Wolfcamp and in the Bone Springs or do you potentially think you move to a co-development of both zones? And how much of that would be driven by - kind of infrastructure needs or capacity situations?

Ron Ormand

I think we look at each independently but we do look at it - I would say as a dual program where I'd more incorporated from what we have today, may not be 50/50, okay; but I'd certainly say it's a larger portion of all we would be doing and what would be doing is drilling primarily pad wells, okay. So we can have a rig drilling two wells in the Bone Spring, two wells in the Wolfcamp, okay; we just did that. And that's the way that we can more efficiently develop the asset and focus on two different zones and then frac them simultaneously. So that's something we've looked at very closely. As we look at a longer term plan, we will move more towards that certainly as we get into probably second half of this year and certainly into 2020 where almost all of our drilling would be on at least two-well pads, and it could be focusing the Bone Springs or the Wolfcamp or it could be Mexico which would be - New Mexico has Bone Springs and Wolfcamp; initial target, there is probably a Wolfcamp A.

Ronald Mills

And then lastly, New Mexico you talk about you know - it take - it's a little bit further down the road because of permitting. When do you think you'll kind of get a little bit more active up there, given some of the exciting offset results. I guess, I don't - I'm not as clear on New Mexico regulatory process versus Texas. So you know curious when you kind of pulled in more wells there to complement with what you're doing and Texas, that's it.

Ron Ormand

Well, it's a BLM, right, so it's a federal lease as opposed to a private lease. So, when you're going to drill on our BLM lease. You have - you know the advantage is you have a good royalty rate and then in a long-term, you have to have the drilling permits. We do think we will hear something about that by the third quarter, so it's just a matter of how quickly we can get up there but that's - we've got set back obviously with the government shutdown because that's part of the federal government to BLM but they do prioritize drilling, and when you have time commitments on your drilling leases and obviously they get revenue from it at the state level. So it is a process but we're well down the road, we have something like 13 to 15 permits in process, including I would say 5 or 6 in that Marlin block right now. So we can't - we're on a continuing process of permitting so that we'll have an inventory permits, not that we're going to drill all those wells but you know, it could be for us or someone else in the future but it's in with a primary focus on our Marlin area and Hog area, down below where we can draw long laterals. That's the process that helps [ph].


Our next question comes from Gerald [ph] with Stifel. Please go ahead.

Unidentified Analyst

Good Morning. I just had a quick question about some of the non-recurring expenses from the quarter; specifically could you go in a little more detail about the Panther pilot well, as well as the SCADA system production monitoring that you guys are using? Thanks.

Ron Ormand

Jim, you want to tell him about the Panther?

Jim Denny

The Panther is our most eastern most test. It's deep holloway through the Wolfcamp B test, we've logged it full log suites, we've taken rotary course and the number of the formations, and we're using that to tie into our seismic and also to better evaluate the east side. So it was an expensive project that really wasn't intended to generate revenue so - and it represents a very large portion of the not very spend in the first quarter. We also have some facility and Infrastructure upgrades, and then we'll drill some fresh water wells as Ron had mentioned. So that's the bulk of it right there. Now, with the admin [ph], the SCADA system is an electronic system whereby the gauges don't have to go up on the tanks, we got tank levels, we've got alarms, we can see pressures; so we can better monitor our production on a day-by-day basis, by well-by-well basis, and it also ties into our Soft Creek lease automatic testing transfer system, it should be coming online in the next few months.

Ron Ormand

Well, a lot of that is infrastructure-related with the water and our oil and gathering, and then the Panther well.

Jim Denny

We've spent about $2.5 million on an 8-inch [ph] basis on the pilot. Call it $0.5 million or $600,000 or so on the SCADA. There is - you know, it's sort of de minimis amounts all kind of rolled in there. I don't have all the exact details, happy to follow back up with you again for those two amounts, it's about $2.5 million or $1.5 million for SCADA.


This concludes the question-and-answer session. I would like to turn the conference back over to Ron Ormond, Chairman and CEO; for any closing remarks.

Ron Ormand

Well, thank you everyone for attending this morning. I think I want you to stress the acceleration of our D&C CapEx is going to really impact second quarter but really more the third quarter. And that - some of the notes I've seen have not necessarily, and - looked at in terms of what that may do. But again, significant bump in our production from where we are today, significant bump in our EBITDAX because of the contracts that we have. And we are currently tracking our guidance well in the second quarter, and we want to make sure that we're putting out numbers that were well within and above. So we're very pleased with where our operations are today, and we look for a very good second quarter and an excellent third quarter.

So with that, I'd like to end up and say thank you very much, and I'll be available for any questions or follow-up if anybody needs it. Thank you.


The conference has now concluded. Thank you for attending today's presentation. You may now disconnect.