Lonestar Resources US's (LONE) CEO Frank Bracken on Q4 2016 Results - Earnings Call Transcript

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Lonestar Resources US, Inc. (NASDAQ:LONE) Q4 2016 Earnings Conference Call March 23, 2017 5:00 PM ET

Executives

Frank D. Bracken III - CEO

Doug Banister - CFO

Analysts

Ron Mills - Johnson Rice

John White - ROTH Capital

Steve Berman - Canaccord Genuity

Irene Haas - Wunderlich

Matt Heckler - Logan Asset Management

Operator

Ladies and gentlemen, thank you for standing by. Welcome to the Lonestar Resources’ Fourth Quarter and Year-End 2016 Financial Results Conference Call. At this time, all participants are in a listen-only mode. There will be a question-and-answer session following our presentation, and instructions will be given at that time. Please note this conference call is being recorded, today, 23rd day of March 2017.

I would now like to turn the conference over to your host, Frank D. Bracken III, Chief Executive Officer. Please go ahead.

Frank D. Bracken III

Good afternoon and thanks for joining us. With me today from Lonestar are Barry Schneider, Doug Banister, as well as conference regulars Tom Olle and Chase Booth. Before I get started, I want to direct you to the cautionary note regarding forward-looking statements, the Safe Harbor and disclaimer on Page 2 of the conference call slides.

Now please turn to Page 3 for my opening remarks. During the fourth quarter, the company was primarily focused on balance sheet improvements and therefore no new Eagle Ford shales were completed during the third or fourth quarter of 2016. Consequently, the company experienced a 23% decrease in net oil and gas production to 4,560 Boe a day during the fourth quarter compared to 5,921 barrels a day during the third quarter.

Two principal factors were responsible for this decline. First, the company completed the sale of its Conventional assets during the quarter. Those assets contributed 436 barrels equivalent a day during the third quarter. Secondly, as I mentioned, we had not completed any Eagle Ford shale wells since the second quarter when we completed 2 gross 0.9 net weeks at Cyclone.

While we didn’t complete any new Eagle Ford wells in the quarter, we did accomplish a lot with the balance sheet cutting long-term debt by 34% or over $107 million. Incrementally, at year-end 2016, we had $68.5 million available on our revolver and about 6 million in cash.

With the balance sheet improvement and Lonestar commenced its drilling completion program for 2017. After having completed only 5 gross 3.8 net wells in the first half of '16, Lonestar plans to bring 11 to 12 net wells on during 2017. The 2017 program is underway.

We’ve brought on 3.0 gross 2.9 net extended reach wells at Burns Ranch in the first quarter. And with these wells on line, production has regained upward momentum with estimated March 2017 production averaging 5,500 Boe a day, up 21% from the fourth quarter.

On this slide we’ve laid out our remaining drilling plans for the year and I would note that we reiterate our $62 million to $72 million capital budget with up to $10 million allocated for leasehold acquisitions. And that we genuinely believe that we’ve adequately accounted for service cost inflation in this budget and it’s the same budget we took on our roadshow.

A couple of under comments on our drilling program. There’s a chance that we’ll drill 11 not 12 wells but based on our ability to redistribute capital toward longer lateral, we could drill the same number of perforated feet with the right 11 wells that we would have originally completed with 12 wells. That’s not yet our plan but very well could be as we continue to ration cash. This would save us a little money.

The other consideration that I would mention is that while we have presented a schedule here with wells at Horned Frog and Beall Ranch, these properties are either HPP [ph] entirely or close to it and we might redirect capital towards nearly acquired projects. Even with those variables, we forecast that 4Q '17 production will represent a 65% to 85% increase over 4Q '16 results, which sets us up for a very, very big 2018.

Lastly, I think probably most importantly to what I’m going to discuss today, I’m pleased to announce that Lonestar has entered into a series of transactions in the Eagle Ford shale which continue our track record of cost efficient growth in our reserves and drilling inventory. Lonestar has reached a series of agreement to acquire interest in a total of 2,565 gross 1,921 net acres in Gonzales and La Salle Counties for a total cost of $9.1 million.

There’s actually some current production associated with these assets or at least one of these assets. The net average is about 147 Boe a day right now, almost all oil. These properties were acquired in classic Lonestar form in what we call hand-to-hand combat through a combination of purchase of working interests in HPP properties, farm-in agreements and dozens of primary term lease acquisitions.

These acquisitions represent a combination of increased working interests in Lonestar-operated production in Gonzales County, the acquisition of undeveloped leasehold that’s contiguous to the company's Cyclone asset also in Gonzales County, as well as the acquisition of additional leasehold just north of the company’s Horned Frog asset in LaSalle County.

In aggregate, this leasehold increases our drilling inventory by up to 28 gross locations in well-established portions of the play. All of these locations are extended reach ranging from 7,000 feet to 10,000 feet and materially bolster our extended reach inventory.

Additionally, the company's internally generated reserve estimates forecast proved and probable reserves associated with the properties of 6.7 million Boe of which 400,000 Boe was PDP. At current NYMEX strip, these proved and probable reserves have PV-10 of $54 million. That’s over $2 a share.

These deals represent an excellent start to 2017 representing a 15% increment to proved reserves and as I said PV-10 additions exceeding $2 a share. Looking forward, I continue to be positive about Lonestar’s current pipeline of similar organic growth projects which should provide meaningful baseline growth in reserves and value while we continue to pursue larger scale acquisitions.

I plan to give you a thorough update on operations and open up the call for any detailed questions, but right now I’m going to turn the call over to our CFO, Doug Banister, to review some key financial highlights.

Doug Banister

Thank you, Frank. All of the information I will review today is contained in our fourth quarter press release or is depicted on Slide 4 of our conference call slides. Lonestar completed no new Eagle Ford shale wells during the fourth quarter of '16 and consequently reported a 23% decrease in total company production in the fourth quarter of 2016.

Fourth quarter 2016 volumes of 4,560 Boe per day consisted of 2,457 barrels of oil per day; 984 barrels of NGLs per day; and 6,717 Mcf of natural gas per day. The company’s production mix for the fourth quarter of 2016 was 75% liquid hydrocarbons.

For the 12 months ended 2016, the company produced 5,899 Boe per day. And as Frank mentioned earlier, our drilling program has kicked in and March 2017 production has climbed up to 5,500 Boe per day.

As I’ve said, Lonestar has been highly focused on balance sheet improvement. Since our last conference call following the public offering to 13.8 billion shares of our common stock, Lonestar used net proceeds to repay 21.0 million of our 12% second lien notes, 49 million of our revolving credit facility while also retiring the 2.1 million Seaport repurchase facility.

At year-end, long-term debt totaled 212.3 million comprised of 43.5 million of revolving credit facility, 17 million of second lien senior notes and 151.8 million of eight and three quarters senior unsecured notes. Importantly, since June 30, we reduced debt by $107.2 million from $319.5 million to $212.3 million. At year-end, we also had 68.5 million availability on our revolver.

Crude oil hedging continues to be an important part of Lonestar’s strategy. We believe crude oil hedging provides increased visibility to cash flow streams and associated liquidity in the current crude oil price environment and augments the company’s borrowing base. We’ve really batten down the hatch for 2017.

Our 2017 crude oil hedge position coverage is currently 2,877 barrels of oil per day at an average strike price of $53.77 per barrel. These hedges provided the company price protection for between 70% to 75% of our 2017 oil production.

Additionally, we have a strong hedge book protecting our 2017 natural gas production covering 7,000 MMBTU per day at a price of $3.36. We’ve also hedged a healthy portion of our 2018 crude oil production with NYMEX swaps totaling approximately 2,500 barrels of oil per day at an average strike price of $55.33 per barrel.

I will now turn the call back over to Frank for additional comments.

Frank D. Bracken III

Thanks, Doug. As we try to do each quarter, we try to provide some topical commentary that’s intended to give you some insights about how we’re positioning the company as well as give you detail results from the business. While the fourth quarter did not see any new wells brought on stream in typical Lonestar fashion, we continue to block and tackle across the company.

I’ll now refer you to Slide 5 to give you an update on our Cyclone properties. Most Lonestar continues to operate at Cyclone 9 and 10 wells which were placed on stream on May 12, 2016, those wells were completed with an average perforated interval of 6,685 feet and Lonestar held a 42% working interest in those wells.

These wells were fracture simulated under our Schlumberger JV with an average proppant concentration of over 1,500 pounds per foot utilizing BroadBand diverters, which allowed us to frac on 300-foot stage spacing, twice the footage spacing that we would have had to incur had BroadBand not been implemented.

Number 9 well has produced over 84,000 barrels in 315 days while the number 10 well has produced over 87,000 barrels in the same time period. We’re extremely pleased with the results of these wells.

I’ll refer you to the bottom half of the slide to demonstrate this performance. In the Cyclone area, we’re challenged by lack of Eagle Ford thickness and pressure and also overlying depletion in the Austin Chalk. However, our results which are depicted in the bottom right panel demonstrate that our technical team was up to the challenge.

To demonstrate how Lonestar’s results compare to other wells in the area, we selected 16 wells that were in the closest to our Cyclone wells at average lateral depth ranging from 8,000 feet to 9,100 feet. Six of these wells were deeper than Cyclone depicted in green; five were at the same depth depicted in blue and five were shallow depths depicted in red. The location of these offsets are shown in the map on the bottom left quadrant of Slide 5 and color coated as I’ve described.

Now on to performance. The cum versus time met graph that we show for our wells demonstrates that the Cyclone 9 and 10 have actually outperformed wells at similar depths by 154% and actually outperformed every single well that is deeper than Cyclone, save one. That’s an EOG well. That’s about 400 feet deeper than our well and was produced pretty aggressively in the first year.

Our Cyclone story represents classic value Lonestar value creation. At year-end 2016, Lonestar had released 2,656 net acres in Cyclone and more than a dozen transactions. This acreage is expected to accommodate 26 additional laterals with average lateral lengths exceeding 8,100 feet. The entire purchase price for this leasehold was $3.1 million or right at $100,000 per location.

And based on the results of the 9 and 10, Lonestar’s third-party engineers booked 3.1 million Boe of proved reserves with PV-10 of $42.5 million at strip prices and additional 5.5 million Boe of probable reserves which had PV-10 of $65.5 million at strip prices. That strip PV-10 is roughly to $5 for Lonestar’s share and we think we can repeat this success in the transactions that we’ve consummated to-date and similars like it.

In 2017, we’ve continued to build mass in the Cyclone area. Since January 1, 2017, we’ve acquired an additional 526 net acres which are contiguous to the company’s current leasehold. There were acquired at a whopping cost of $700,000 and increased the number of drilling locations at Cyclone from 26 to 33.

The company's internal reserve estimates for the newly- acquired interests are over 2 million barrels of oil equivalent. Lonestar plans to get on this acreage quickly. We plan to drill two 2-well pads, commencing in April. The 4 and the 5 have been permitted with planned TD's of 19,100 feet, indicating planned perforated intervals of 10,000 feet. We will have an 86.5% working interest in those wells.

Lonestar plans to file permits next week on the Cyclone 26 and 27 and you can see the location of those wells in the map on the top right-hand quadrant with planned TD's of 18,000 feet, indicating planned perforated intervals of 9,000 feet. We’ll have a 100% working interest in those wells.

At the nearby Harvey Johnson lease, Lonestar holds a 50% working interest and operates six Eagle Ford shale wells that were accessed via farm-in in 2014. Just recently, Lonestar executed a definitive agreement to purchase an additional 33.5% working interest in the Eagle Ford shale unit for $7.6 million. The acquisition adds an estimated 133 barrels a day of oil and 81 Mcf a day of gas or 147 Boe per day, as indicated by March production.

The acquisition also includes a 33.5% working interest in the 967 acre unit, half of which is undeveloped. Proved developed producing reserves associated with the transaction are about 400,000 barrels, almost all oil. More significant additional reserve potential exists in the undeveloped leasehold, which can accommodate 8 additional laterals when pooled with offsetting acreage.

I’ll now turn you to Page 6 to update you on the progress we’ve made with Burns Ranch wells that we’ve drilled and completed in the fourth quarter. On January 5, Lonestar completed completion operations on the Burns Ranch Eagle Ford 8, 9 and 10 wells with lateral lengths of approximately 9,620; 9,440; and 8,460 feet, respectively. These wells were drilled to an average measured depth of 18,007 feet and were drilled from spud to TD in an average of just over 13 days, nearly twice as fast as our last batch.

Lonestar conducted a series of tests with these wells designed to establish best practices for the full scale development of the property. All of our generation 4 and generation 5 stages were engineered and positioned with information we garnered for thru-bit laterals and all three wells utilized BroadBand diverters which allowed Lonestar to reset stage spacing at 300 foot increments as compared to 247 foot spacing on Gen 3 wells drilled in 2015 reducing the number of frac stages and associated costs.

However, Lonestar also wanted to test higher proppant concentrations on the new set of wells. And as a control to the pilot, we pumped 1,500 pounds per foot on the number 8 well which is very similar to our older generation 3 wells. Because we pumped 300 foot non-geometric BroadBand stages here, we labeled that number 8 well a Gen 4 completion. It’s a bit in-betweener [ph].

As a variable in our pilot test, we pumped proppant concentrations exceeding 2,000 pounds per foot on the 9 and 10 wells, which is the highest in the company’s history. We disclosed the actual details of the 30-day test for the new wells in our press release and I’ll refer you to that document for those details.

While we only have 68 days of production results from the Gen 4 and Gen 5 wells, we’re extremely pleased particularly with the results of our Gen 5 wells. First, I’ll refer you to Figure 1. To-date, our Gen 5 wells have outperformed our Gen 3 and 4 wells by 8% on an absolute basis. However, that really doesn’t tell the story of the technical performance of the Gen 5 wells based on how we’re choosing to produce these wells.

When examining frac efficiency and reservoir performance, our technical team isn’t just focused on the initial rates we report in our press release but rather much more focused on maximizing ultimate oil recoveries over the life of the well. And we believe inducing a rapid drawdown in the near-wellbore area will inhibit the flow of oil under the wellbore and the result of increase in GOR also removes energy rapidly away from the reservoir impairing future recoveries.

Consequently, we’ve been highly focused on maintaining lower gas to oil ratios in our Gen 5 wells as we believe the rapid increase in GOR that we experienced in our Gen 3 wells ultimately impaired our OURs [ph]. As a result, we’ve been much more stringent in our choke management techniques on our Gen 4 and Gen 5 wells and Figure 2 demonstrates that we’ve regulated our GOR in our Gen 5 wells keeping it very stable here for well over the last 50 days right around 1,000 SCF per barrel. By contrast, at 30,000 barrels of oil recovered on our Gen 3 wells, the GOR was at 1,500 and rapidly climbed to over 2,000.

Figure 3 provides one set of technical parameters that give us some extremely positive indications of how our Gen 5 well designs are positively influencing our recoveries. Figure 3 plots cum oil recoveries versus pressure drawdown between our Gen 3, 4 and 5 wells and the results and differences are really striking. At 30% pressure drawdown, the Gen 3 wells shown in red had recovered 15,900 barrels. By contrast, our Gen 5 wells shown in blue achieved 30,000 barrels of well recovery with the same 30% pressure drawdown, an improvement of 89%.

We believe the results to-date are the result of increased effectiveness of the Gen 5 completions in contracting additional reservoir rock volume via a more complex fracture volume in the same fracture half-length, resulting in better frac efficiency and drainage efficiency. We’ll continue to update you on this important development in well performance on future calls.

I’ll now refer you to Slide 7. We’ve updated our leasehold map and highlighted the acquired properties we discussed today in blue. But I’d like to make two important points before I turn the call over to questions. First, I’d like to call your attention to our third acquisition which is a new leasehold we’ve acquired near Horned Frog.

During the first quarter of 2017, Lonestar reached agreements to acquire working interests in 1,426 gross and 1,071 net acres in a block just north of the company's Horned Frog property. This leasehold was assembled in our classic hand-to-hand combat style. The position was assembled via more than a dozen primary term leases and a farm-in agreement, and was acquired at a total cost of less than $1 million.

Depending on ultimate spacing, which could range from 500 to 700 foot per well, the lease block will accommodate 7 to 11 extended reach laterals ranging from 7,400 to 10,000 feet in length. The company's internal reserve estimates for the newly-acquired interest at Horned Frog are 4.3 million Boe. New wells on this property have a reasonably good chance of taking the place of our scheduled Horned Frog wells as that block is already HPP.

I’d like to conclude the call by saying that 2016 was a really transformational year for Lonestar. We moved the company’s listing to the NASDAQ. We sold off our non-core conventional assets. We completed our first U.S. stock offering that provided capital to fix the balance sheet and restart our Eagle Ford shale development program; but most importantly, reduced long-term debt by $107 million in the last six months of the year.

We anticipate increasing production sequentially in each quarter of 2017 by drilling extended reach laterals in our inventory. Already in 2017, we’ve entered into a series of transactions that increase our reserves and drilling inventory and provide additional growth opportunities for the company.

You can see those additions on the map in Slide 8. There are in our core areas where we’ve already demonstrated technical excellence and I feel really good about our ability to replicate this kind of organic leasehold and reserve growth that we achieved in the first quarter and remaining part of 2017 again. That would generate 25% to 30% reserve growth at very low costs. With this excellent start to the year, we think the company’s extremely well positioned to generate growth and shareholder value in 2017 and beyond.

This concludes our prepared remarks. And I’ll now turn the call back over to the moderator for your questions.

Question-and-Answer Session

Operator

Thank you. Ladies and gentlemen, we will now begin the question-and-answer session. [Operator Instructions]. We will now take our first question from Ron Mills with Johnson Rice. Your line is open. Please go ahead.

Ron Mills

Good afternoon, Frank. A couple of questions. One on the acreage additions and congrats on adding the 2,000 acres. When you look at the first quarter and look at the opportunity sets that are out there around your existing areas, in your hand-to-hand combat, is that the kind of pace that you would hope to be able to continue to work on? And can you provide some color in terms of what the current A&D market looks like out there in terms of some potential packages in areas that you may be interested in?

Frank D. Bracken III

Sure. So we really have a three-pronged approach to this. And I can tell you that these three transactions, the one half and – one we got done in 45 days. The other two have taken us six to nine months to get done. So the timing on these things has always – we have a desire to do it. We know what we can pay. Bringing the horse to water sometimes take a long time. But I would tell you that the inventory similar sorts of organic growth potential is larger in the immediate pipeline than what we’ve closed today both in terms of acreage and reserve value. I wish I can predict timing on it. So I won’t necessarily commit to the notion that we’ll replicate this again in the second quarter. I sure like to think I can do it. I will say in aggregated magnitude the things that we have that we’re in negotiations on are larger than what we’ve closed. And I think we got a good handicap shot at getting that done. When you can create value like this – look, this is hard work. It takes a lot of time from a lot of people in our organization. But we think it creates probably the best value you can create. You’re creating something material out of little crumbs, if you will. The confidence in our ability to continue to execute this strategy and grow kind of 20% to 30% a year with this mechanism gives us the ability to be pretty picky about the way we go about acquisitions. And I think you can think about our strategy as being kind of as follows. These little organic deals are crumbs. The next thing we want to do is take off some slices of pie to grow the company. More often than not we think those slices of pie will be unsolicited offers into other companies for some or all their assets. We’re in active discussions on a number of those kind of things and those are not huge deals, but very incremental to the company. We increase our odds by doing these kind of unsolicited offers. Competition is always tough. And then I think you’re getting ready based on what I hear in the A&D market to see kind of a floodgate open in the Eagle Ford in I’d call it the 75 million to 500 million size class. So there’s a real continuum in terms of size of the growth available to us and we’ll sit here and eat our little crumbs and hopefully knock off a slice of pie or two during the year. And longer term, hope to position ourselves for pieces of bigger deals.

Ron Mills

Great. And then you referenced with the Burns Ranch wells, you referenced the March production level of 5,500 and kind of 65% to 85% growth fourth quarter-to-fourth quarter. I’m just curious about how the cadence of that sequential growth might look in terms of – do you have an internal sense as to a completion schedule and just want to make sure that employs the kind of choke management program you’re using?

Frank D. Bracken III

Yes, so the answer to the second question is absolutely. It’s very specific to being disciplined about the way we produce these wells. We’ve got a fairly good completion and on stream schedule set on Page 3 that ought to give you some sense for the tenure of that program. And I would tell you this that one of the issues with a really small company is a few wells really change the production profile pretty rapidly. Similarly said, a 30-day delay in getting frac through there and getting wells on will have a similar ripple effect through the production. And what I would tell you is we’ve talked about a 4Q exit rate because we’re confident that over the course of the year we get this program on and we have a fairly predictable exit rate based on having that program completed. The nuances – I would just tell you that I think investors are going to – have to be patient with us in terms of the magnitude of quarterly growth. We’re going to grow every quarter. We try to give you a decent sense of where we’re going to bring wells on and when. It will vacillate. But I think if you keep an eye on the big picture it’s we’re going to grow production a hell of a lot over a course of four quarters and we’re going to keep bringing these little acquisitions in. They’re going to add up and set the stage for 20%, 30% reserve growth as a baseline in 2017.

Ron Mills

Great. I’ll let someone else jump in and jump back in to ask a couple of modeling questions. Thanks.

Operator

Our next question comes from the line of John White with ROTH Capital. Your line is open. Please go ahead.

John White

Good afternoon, guys. Thanks for taking my call. Again on the 1,920 net acres in Gonzales and La Salle County, maybe I’m missing something but my back of the envelope valuation numbers just show that is insanely cheap. Can you give us some color? Is it the distress situation or --?

Frank D. Bracken III

No. So if you kind of generally think about it, I’d allocate about $7 million for the producing asset and the rest for the – if you’re going to start to do the math on that, I think that’s back of the envelope but I think it’s a pretty good starting point.

John White

That’s what I did.

Frank D. Bracken III

None of these were distress. These were situations where we go into an area, we identify reserve opportunity and we recognize that the leasehold is really broken up. And no individual piece of that has any value. But when you work hard and roll up your sleeve and aggregate it into drillable blocks that you can drill long laterals on, you kind of create – there’s an alchemy effect to it. You create a lot more of the part of the sum than the parts you worked.

John White

Okay. So it’s a lot of small tracks that would require a lot of land man hours?

Frank D. Bracken III

In the primary term leasehold, in the farm-out, there were over 20 different entities who we’ve engaged in contractual relationships with.

John White

Yes, that’s a lot of negotiations. And I guess I missed it but was there a fourth quarter 2017 exit rate mentioned?

Frank D. Bracken III

We pointed the growth of 65% to 85%. I’ll do the math for you. It’s 7,500 to 8,500 barrels a day.

John White

All right. Well, good luck on that and thanks for taking the call.

Frank D. Bracken III

Thanks, John.

Operator

Our next question comes from the line of Mike Kelly with Lonestar Resources [ph]. Your line is open. Please go ahead.

Unidentified Analyst

Hi, Frank. Didn’t know I joined your team yet but --

Frank D. Bracken III

I hadn’t noticed that either yet, but we’re glad to hear from you.

Unidentified Analyst

Anyways, curious of what the average project return would be on these wells, the 28 gross locations you’ve picked up? I’ve always appreciated how you guys have force ranked [ph] to your undeveloped inventory based on project returns. Maybe do you take the average you talked about as top quartile, average, how do you think about it?

Frank D. Bracken III

I would tell you that they’re all meaty and/or better.

Unidentified Analyst

Okay, great.

Frank D. Bracken III

It’s almost definition, Mike. If you’re drilling wells that are among the longest in the company then generally speaking we’re doing a lot of that in the oil window, they’re going to be among your best returns.

Unidentified Analyst

Okay, solid. That’s great. And curious just on January and February where you were in March production, how you look on volumes in gen and fab in Q1?

Frank D. Bracken III

I think we’ve adequately guided each of you a good number to expect for the quarter. We’ll try to not get that granular on the calls. But I think you’ve spoken to Chase. You know what the fourth quarter was. You know that March was the high month. So there’s room in between there. From what we’ve seen you’re very much in line with our expectations for the first quarter.

Unidentified Analyst

Okay. All right, good to know. Thanks. And then just from a strategic standpoint, crude has pulled back here. Inventory continues to build with pushbacks. It looks something [indiscernible] on crude but low 40s. How has that kind of changed your strategy for the year?

Frank D. Bracken III

I think some of the things that we’re able to do which are really unique, first and foremost we’ve protected ourselves to a very high degree on crude oil and gas prices with the hedges we have in place. They protect – let’s just call it a nice round number, 75% of our oil and gas volumes for the year at prices that are substantially higher than those that you’ve mentioned. So we really only have about 25% of our production exposed to commodity prices. That means that volatility and cash flow should be narrowed as well. We do have – by design we never get too far out of over our skies in terms of drilling and our HPP obligations as well. We’ve designed the thing to have no short-term expirations on any of our engineered locations. So if we had to dial things back a little bit, we would. I think our initial solution will be, hey, we’ve got so many long laterals, maybe we drill 11 – we can drill 11 wells not 12 and maintain the same number of lateral feet, because we can shuffle some capital toward 10,000 foot laterals. So that’s the way to maybe trim the budget a little bit if you need to. So we have that available to us to do if we want to. But we’ll monitor as the year goes on. But this is an important year for us in terms of establishing a trajectory on production and I think we’ve more than adequately price-protected ourselves, I would like to think better than most. And we’ll monitor it but we don’t have any guns to our head if we – if the wheels fell off in the third or fourth quarter, we might slow down a little bit and maybe we spend more money on acquisitions. I think the silver lining is, is we’re in this business for years not quarters and softening in prices should actually improve the acquisition environment.

Unidentified Analyst

Absolutely. All right, I’ll hand it back. Thanks, Frank.

Operator

Our next question comes from the line of Steve Berman with Canaccord Genuity. Your line is open. Please go ahead.

Steve Berman

Thank you. And thanks Frank for the details as always. First question is the Burns Ranch 8, 9, 10, what was the average drill and complete cost for those? And then on a going forward and also the balance of the year, have you built in any cost inflation into your CapEx guidance for those wells?

Frank D. Bracken III

So the Burns Ranch wells look like they’re going to be turned to the tanks for about $5.7 million. I would tell you this that the currently quoted cost of service is across the board, whether it’s pipe, whether it’s fracture stimulation, et cetera. And by the way I think those are the two leading sources of inflation out there right now. We’ve got current cost in our budget for the year. We thought it would be a good idea to not think that things were going to stay as soft as they were last year in a pretty tough environment. And so we built a lot of that into our budget already. So the inflation you’ve heard about, it’s in our budget already.

Steve Berman

Got it. And maybe a couple of questions for Doug. I didn’t see it in here but do you have an average share count for Q4 '16? And also just wondering why there was such a big income tax expense in Q4 relative to the pre-tax loss?

Doug Banister

During Q4 of 2016 as part of the 13.8 million shares that we sold and closed on December 22, there’s a Section 382 tax limitation that kicks in when you change out the ownership of your company greater than 50%. And obviously we sold – having gross proceeds close to $80 million, we actually sold more than the market cap at that time. So there is a Section 382 limitation that we undertook with our auditors and their tax people, which had us write-off. It goes into more detail in the tax footnote of the K that you can read, but basically we wrote off around 140 million in NOLs and it limits our ability to use some NOLs in the future. But we’ve got about 60 million in NOLs that are available to us for future operations.

Steve Berman

All right. And do you have that average share count for us?

Doug Banister

The average share count, I don’t have it off the top of head. I do know that we had 21.8 out at the end of the year and it came out very late. So the average share count is probably in the low 8 million because of the 13.8 coming in so late.

Steve Berman

All right. Thanks. I’ll turn it back.

Operator

[Operator Instructions]. We do have a question from the line of Irene Haas with Wunderlich. Your line is open. Please go ahead.

Irene Haas

Yes. So can I ask another question on the tax? If you didn’t have this interesting twist, what would your tax rate be for fourth quarter? And secondarily, could we have a little color on sort of lease operating expenses for 2017? That would be very helpful on a per barrel basis.

Frank D. Bracken III

Let me answer the second one first. So Barry and the guys have done a tremendous job of lowering the absolute level of operating cost field but that actual process was really undertaken kind of between the September and December timeframe and doesn’t really show up in the fourth quarter. Also bear in mind that when you’re our size, when you take your accruals, you take everything you have an invoice for and you book it in the year-end. So there’s probably a little bit of – there’s some inflation in there that ordinarily wouldn’t be there. We also are operating with the smallest number of barrels that we’ll produce and a lot of our cost our fixed. So I think if you did that math, you’re at $8.34 of Boe in the fourth quarter, we’d expect that number to be between $6.50 and $7 in the first half and get right around down about 5 as we really ramp volumes by the fourth quarter. That ought to give you – if you work the math out, that ought to give you about $6 Boe number for the calendar year.

Irene Haas

Okay. And then if you didn’t have that special 382 tax limitation deal, what would your tax treatment look like in fourth quarter?

Doug Banister

I do not have an answer for you at the moment. I can get your name and number and give you a call back and let you know. But that’s not a number I have at the moment.

Irene Haas

Okay, we can take this offline. Thank you.

Doug Banister

Okay.

Operator

Our next question comes from the line of Matt Heckler with Logan Asset Management. Your line is open. Please go ahead.

Matt Heckler

Hi, guys. I wondered if you could just give us an update on what your current liquidity looks like as of today?

Doug Banister

At the end of the year, it was 68.5 million on the revolver.

Matt Heckler

And how do you look today, as of the call?

Doug Banister

A little less than that. We’re not really in the business of disclosing interim numbers like that, but clearly you’re early in the year where you’re kicking off the program, you’re going to incur a kick start to CapEx.

Matt Heckler

Okay. Thank you.

Operator

Our next question comes from the line of Jay Sherman with Lincoln Financial [ph]. Your line is open. Please go ahead.

Unidentified Analyst

Hi. I appreciate the call. I’m just wondering what’s your plan for becoming profitable and what your free cash flow is going to be looking like this year or there won’t be free cash flow?

Frank D. Bracken III

Cash flow breakeven in terms of being self-sufficient in terms of your funding capabilities I think should be the target of every oil and gas company and certainly isn’t ours. I think that’s something that we achieve as we stated in some of our recent documentation right around the end of the year. We have a fixed G&A base, we paid off a lot of debt, we’ve got a fairly fixed interest expense burden and when production gets depressed by lack of activity, that’s going to pressure profitability. But as we ramp up volumes, we should become net income positive. That’s assuming prices don’t just completely fall out of bed. But we ought to get to net income positive by the fourth quarter of this year for sure.

Unidentified Analyst

What if the prices don’t cooperate?

Frank D. Bracken III

I’d say it will still be a lot closer to breakeven but I don’t know what price you have in mind.

Unidentified Analyst

There’s been no talk about profitability on the call, which is why I’m prompting the question.

Frank D. Bracken III

I guess I would tell you we’re mainly focused on returns. We think building asset value is the thing that grows shareholder wealth. There’s a lot of accounting mumbo jumbo that goes into your next income calculation. Some of those things we have good control of and some we don’t. But undoubtedly so with cash flow self-sufficiency I think comes profitability. But a lot of this has to just do with scale. There’s an asset base there that needs to be developed. As you apply capital to that asset base, you generate a level of productivity that is more representative of expand to your asset base. So a lot of this is just scale for us. It’s getting the production back ramp and amortizing what are generally fixed cost over a much larger number of barrels and Mcf.

Unidentified Analyst

Thank you.

Operator

Our next question comes from the line of Jeff Patrick with Northland Capital [ph]. Your line is open. Please go ahead.

Unidentified Analyst

Hi, guys. Hi, Frank.

Frank D. Bracken III

Hi, Jeff.

Unidentified Analyst

Hi. So I think you correctly put the caveat out there that small companies are super sensitive to delays and I think the investor base or the investors in the impeded day are concerned about tightness in frac crudes and all that good stuff. But is it fair to say because of your Schlumberger agreement that it’s going to be at least through 2017 more predictable for you or as that agreement rolls off, which I think it does in this year, does that change in midyear? So I’m just curious kind of how you guys are thinking about that?

Frank D. Bracken III

So I would like to think that – there’s layers to that question, it’s a great question. First, let me say that we’ve got frac slots through our Cyclone wells already set in stone with Schlumberger. When I say set in stone, they can still wiggle but we’re on the schedule with the dedicated crew. And one of the things that attracts Schlumberger to doing – that incentive Schlumberger to be on time for us is we’re not just doing the – we’re not doing slick water jobs which are very low margin jobs for them and burn up their equipment. We’re doing pretty complex jobs and those jobs use their BroadBand pills, they use their J-mix [ph]. They use a lot of the bells and whistles. So those jobs tend to be more profitable for them I think in some respects than a lot of our competitors. And I think lastly there’s a very strong technical alliance and relationship between the two companies. So I think all those factors give us for our size an advantage over somebody who doesn’t have those relationships and the kind of jobs that we’re pumping. We’re doing a lot of – we’re not just fracking with Schlumberger, we’re running logs with them. We’re using some of their BHA to do [indiscernible] gamma ray in certain areas. There’s a number of silos at Schlumberger that all year long that we’ll utilize. So I think we get [indiscernible] a little bit different light or at least I’d hope so.

Unidentified Analyst

Yes. Based on early results, it seems like it’d be safe to say that you’re happy with the relationship, so we don’t have to expect that midyear you’re looking elsewhere.

Frank D. Bracken III

We have a great relationship with them. We’re believers in a number of the technologies that we’re employing. And I think frankly our people are value added into that process. We hold our own there. So we’re very pleased with it and the assets we have today. I think you’ll see us continue to use a number of these processes to try to drive down the number of stages we pump and improve the results that we generate.

Unidentified Analyst

Okay, good. Thanks, guys. Good luck going here.

Frank D. Bracken III

Thank you, Jeff.

Operator

We do have a follow-up question from the line of Ron Mills with Johnson Rice. Please go ahead.

Ron Mills

And this is the last one, this is for Doug. Just on the fourth quarter on the interest expense line, can you walk through some of the components there? Were there some kind of one-time charges associated with some of those debt repurchases, because given your debt outstanding, I just want to make sure my forward-looking interest expense of kind of 4.5 million or 5 million a quarter is more the run rate?

Doug Banister

There were some issues in regards to the interest expense and the repurchase of the bonds and things that we had to write off some deferred financial costs associated with those that roll through the interest expense line. But the answer is 4.5 or a little north is a good number to use.

Ron Mills

Okay, great. Thank you.

Operator

Thank you. Frank, we have no further questions in the queue.

Frank D. Bracken III

Great. Thanks for your questions and thanks for your time. We think we’re off to a great start both in terms of our production results and our acquisition strategy being successful. And we look forward to sharing more success with you on the next call.

Operator

Ladies and gentlemen, this concludes the Lonestar Resources fourth quarter and year-end 2016 financial results conference call. Thank you for joining us today. You may now disconnect your lines.

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