Laredo Petroleum Inc (LPI) Q4 2018 Earnings Conference Call Transcript
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Laredo Petroleum Inc (NYSE: LPI)
Q4 2018 Earnings Conference Call
Feb. 14, 2019, 8:30 a.m. ET
Contents:
Prepared Remarks
Questions and Answers
Call Participants
Prepared Remarks:
Operator
Good day ladies and gentlemen and welcome to Laredo Petroleum Incorporated Fourth Quarter and Year-End 2018 Earnings Conference Call. My name is Mark and I'll be your head operator for today. (Operator Instructions) As a reminder, this conference is being recorded for replay purposes.
It is now my pleasure to introduce Mr. Ron Hagood, Vice President, Investor Relations. You may proceed, sir.
Ronald L. Hagood -- Vice President, Investor Relations
Thank you and good morning. Joining me today are Randy Foutch, Chairman and Chief Executive Officer; Rick Buterbaugh, Executive Vice President and Chief Financial Officer; Karen Chandler, Senior Vice President and Chief Operations Officer; and Jason Greenwald, Vice President, Reservoir Engineering; 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 these forward-looking statements for a variety of reasons, many of which are beyond our control. In addition, we'll 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 yesterday's news release. Yesterday afternoon, the company issued a news release and presentation detailing its financial and operating results for fourth quarter and full-year 2018. We will refer to the presentation by page during today's call. If you do not have a copy of this news release or presentation, 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.
Randy A. Foutch -- Chairman & Chief Executive Officer
Thanks Ron. Good morning and thank you for joining Laredo's fourth quarter and full-year 2018 earnings conference call. 2018 was a successful year for Laredo by many measures. We grew total production by 17%, increased the value of our proved reserves by 19% and maintained a strong balance sheet. Our operational expertise continued to drive drilling and completion efficiencies, keeping well costs in check. And our previous investments in field infrastructure helped keep operational costs low as we delivered our 10th consecutive quarter of unit LOE below $4.
Moving forward, the company is well positioned for 2019 which will be a transitional year for Laredo. As we talked about last quarter, we are executing a shift in our strategy committing to align capital expenditures with operating cash flow by adjusting activity as needed and focusing our development plans on wider well spacing to drive improvements and returns and capital efficiency versus 2018 development, which was focused on inventory expansion and net asset value accretion.
As we execute this shift, we are significantly reducing our drilling and completion cadence, exhibiting capital discipline by cutting our expected spending by approximately 45% versus 2018. We are able to accomplish this as we have an 88% of our acreage held by production and we've avoided long-term service contracts. Slowing operations in 2019 is expected to produce both short and long-term advantages for the company. Namely, we anticipate that we will operate within cash flow for a full-year 2019 at a WTI strip price deck of $54 per barrel and Henry Hub strip of $2.90 per million cubic feet of natural gas.
Additionally, we believe slowing development will begin to moderate both our whole and total production corporate decline rates, ultimately reducing our maintenance capital levels. Once we have executed this plan in 2019, we anticipate being able to keep annual oil production flat in 2020 and 2021 from fourth quarter 2019 levels of approximately 23,000 barrels of oil per day, grow reserves and live within cash flow in the mid-50s environment not including any additional savings. As we've always done, we plan to adjust our workforce staffing levels and absolute G&A expense regularly as we adjust operational activities to operate within cash flow with these savings expected to be in the second half of 2019.
Upside to our cash flow assumptions can be realized through increased commodity prices, reduced service costs or better-than-anticipated well productivity versus our revised type curve among other means. We feel that sustained oil prices in the mid-50s per barrel range could precipitate further service cost reductions. Should additional cash flow be realized, we have the option of utilizing the excess cash flow for numerous purposes including to pay down debt, repurchase stock or complete additional wells.
To conclude, we have made an excellent start implementing this strategic shift we need to execute to drive shareholder value in a capital-disciplined fashion. We have shifted our development program to wider spacing to focus on increasing returns and capital efficiencies. We are exhibiting capital discipline with our 2019 budget that aligns capital expenditures and cash flow. And we expect further reductions in our controllable costs as we reduce G&A as our operational activity slows.
I will now turn the call over to Karen for an operations update.
T. Karen Chandler -- Senior Vice President & Chief Operating Officer
Thank you, Randy. To start off, I'm going to walk through some of our reserves data including PDP decline rates and our new type curve. Turning to slide 5, you can see the updates to our reserves as of year-end 2018. As part of our ongoing reserves estimation process, for our year-end 2018 reserves estimation, we incorporated additional production data to reflect the higher gas content and steeper oil declines on our historical wells and the negative effects on oil production from tighter spacing on our recent wells.
This additional production history has led to more particular forecast, including specific B factors for both developed and undeveloped locations. The result of these changes were negative revisions to oil reserves and positive revisions to natural gas and NGL reserves, with no meaningful change to oil EUR on a BOE basis. In conjunction with this process, we also revised our type curve which you can see on slide 6. Here, we are showing a comparison over the first five years of the life of the well for the revised and historic type curves.
A few points that are important to note. First, while over the 50-year life of the well, there was an approximate 27% decrease in the oil EUR, there's only a 6% decrease in first year oil production and only an approximate 15% decrease over the first five years of the well's life. Second, in the revised type curve, the total recoveries increased 12% in the first year and 13% in the first five years. This dynamic drives very similar rates of return for the previous and revised type curves. In addition to changes related to decline rates, the productivity assumptions of the revised type curve are based on assumptions for infill locations in some of our most highly developed areas and on productivity assumptions for areas and landing points that in some cases have limited data. Slide 7 and 8 show Laredo's corporate decline rates for total production and oil respectively.
As it relates to oil decline rates, we expect this rate to moderate over the next few years as higher decline, tightly spaced wells drilled in 2017 and 2018 get older and as fewer new wells are brought on at a slower development pace. Slide 9 demonstrates the oil decline projected for the tightly spaced wells that we drilled the past couple of years. Compared to both the previous and revised type curves, first year oil production is not significantly lower.
However, it is in the subsequent years that the higher decline rates become more pronounced. In total, for years 2 through 5, oil production for tightly spaced wells is expected to be approximately 30% lower than that for the revised type curve. There are couple of important implications that result from this dynamic. First, I mentioned previously that we expect our corporate oil decline rate to moderate as the tightly spaced wells get older. The negative impact of the reduced oil productivity will begin to lessen as we move through time. And I will note this impact is already factored into the corporate oil decline rates we show on slide 8.
The second important implication of this is the positive inflection point in oil productivity that should emerge as we finish completing tightly spaced wells and begin to complete widely spaced wells later in the second quarter of 2019. The revised type curve expectations for oil production within the first five years are approximately 20% higher for widely spaced wells than the current expectations for the tightly spaced wells.
Turning now to operations. As Randy explained earlier, we have shifted our strategy to operating within cash flow. To accomplish this goal, with strip pricing of approximately $54 per barrel WTI, we will be adjusting our activity levels in 2019. At the beginning of the fourth quarter of 2018, we were operating four rigs and two completion crews.
Turning to Slide 11. We illustrate our planned progression of drilling and completion activity levels by quarter in 2019 for three different potential commodity prices, including strip pricing in both above and below strip pricing. This optionality of drilling and completion cadence is achievable in large part due to Laredo's strategy of maintaining operational flexibility through high working interest and minimal drilling requirements. We have also traditionally signed service contracts of a year or less.
And as you can see on Slide 11, we will be moving to operating one rig by the second half of 2019. We were able to make this adjustment without paying any early termination penalties because of how we structured our rig contracts. We are currently operating two completion crews and our completion activity in 2019 will be front loaded. At the strip pricing scenario, we expect to complete 36 gross wells, 32 of which we expect to be completed in the first half of 2019. In the second half of 2019, we plan to adjust the number of completions to align with cash flow. Should prices move down, we expect to complete a minimum of 28 gross wells and then we will have the flexibility to drop to zero completion crews.
Conversely, we can keep a completion crew longer and complete more wells, should additional cash flow be generated. Using current strip and service costs, we expect activity levels in subsequent years to approximate the two rig, one crew average for 2019. Like 2019, we would expect to front load completions activity to work down docks built in the previous year.
On Slide 12, you can see the breakdown of our capital program at strip pricing. Once again stressing the program will be adjusted based on cash flow generation. The company's focus on efficiencies and controllable costs can provide upside to our cash generation capabilities. On Slide 13, you can see one example of how much more efficient we had become year in, year out since 2014. Should we be able to continue to make gains beyond what are illustrated in this chart, we have the potential to continue to reduce our capital well cost. We have factored into our 2019 budget actual completion cost savings we have negotiated at the beginning of the year, but we believe there are more opportunities for savings if oil prices remain at these levels.
Slide 14 illustrates the continuous progress we have made on controllable cash costs. LOE has been driven down in large part by the benefits of our prior investments in infrastructure. And as Randy mentioned, we expect to make further progress on G&A expense as we align our activity and staffing levels.
I will now pass the call over to Rick for our financial update.
Richard C. Buterbaugh -- Executive Vice President & Chief Financial Officer
Thank you Karen and good morning. Fourth quarter and full-year 2018 statement of operations and cash flows were included in our press release issued yesterday. We expect to file our Annual Report on Form 10-K later this afternoon. Although fairly self-explanatory, there are a couple of items in the cost and price realization categories that fell outside of our previous fourth quarter guidance where some explanation may be helpful. Depletion, depreciation and amortization or DD&A in the fourth quarter of 2018 was $9.29 per barrel of oil equivalent compared to our guidance of $9. This metric is primarily driven by depletion which typically represent slightly more than 90% of the company's total DD&A.
As you know, depletion is derived from period production, total reserves and the undepleted base in our full cost pool. For Laredo, that calculated rate is very representative of our depletion costs for proved developed reserves since we booked minimal PUDs and we do not carry a large unevaluated property balance which is excluded from the depletion calculation. Annual drilling activity during the year provides additional knowledge that assists in evaluating properties, resulting in the continuous movement of unevaluated property cost into our full cost pool. Similar to prior years, in 2018, we transferred a net $45 million equivalent to about 25% of our unevaluated property costs at year-end 2017 into our full cost pool.
This results in only about 5% of our total assets being classified as unevaluated at year-end 2018. Karen has discussed the changes in our reserves at year-end, but as a reminder only about 9% of our proved reserves are undeveloped. And those undeveloped reserves represent about six months of development activities. You will recall that beginning in 2015, we significantly reduced our booking of undeveloped locations to enable us the maximum flexibility to drill our most appropriate locations and at the proper cadence, while staying true to the SEC guidelines. The other outlier in our guidance was our natural gas price realizations which were 17% of the Henry Hub benchmark, well below our initial expectation of 40% of Henry Hub. This is simply a function of the mood in the WAHA basis and how we derive the guidance amounts.
At the time, we provided guidance for fourth quarter 2018 natural gas realizations. We incorporated one month of actual WAHA basis and we used two months of strip prices. At that time, November and December 2018 WAHA basis were forecasted at a negative $1.47 and a negative $1.20 respectively. Actual pricing for November and December of 2018 were a negative $1.74 and a negative $4.58 respectively. For all of our price realization guidance, this dynamic applies.
We use any actuals to date and forecast based upon the appropriate product strip. Looking to the future, our 2019 budget is based on the primary premise of balancing development activity expenditures with operating cash flow on an annual basis. Using benchmark strip pricing of approximately $54 per barrel for oil and $2.90 per million cubic feet of natural gas, we believe that this translates into a capital program of approximately $365 million for the year of which about 82% is for drilling and completion activities. Unlike past years, this activity will create a limited inventory of uncompleted wells.
This program coupled with our high HBP percentage, a reduced PUD booking strategy and limited long-term contracts on rigs and crudes provide added flexibility that enables us to make investment adjustments that balance operating activity with cash flow. A substantial portion of our completions will occur in the first half of 2019. Consequently, we do expect to incur an outspend in the first quarter. We then anticipate to be approximately cash flow neutral in the second quarter and then generate enough free cash flow in the second half of 2019 to balance spending and cash flow for the full year.
The key component of this budget flexibility is the structure of our hedging program. The structure of this program protects the company from a large downward mood in the price of oil while we retain all of the upside if oil prices increase. We have hedged approximately 90% of our anticipated oil production in 2019 and approximately 90% of those hedges are puts with an average strike price of $47.45, not including premiums paid or deferred.
In summary, we are committed to targeting cash flow neutrality for full-year 2019 and we believe we have the operational and financial flexibility to achieve that as we continue to focus on controllable cash costs. We have a solid financial structure with significant liquidity to capitalize on appropriate opportunities. We have a consistent hedging program to protect our anticipated cash flows and we have no debt due for three years, all of which provides a strong foundation for the company.
Operator, at this time would you please open the lines for any questions?
Questions and Answers:
Operator
(Operator Instructions) Our first question comes from the line of Brian Singer of Goldman Sachs. Your line is now open.
Brian Singer -- Goldman Sachs -- Analyst
Thank you, good morning.
Randy A. Foutch -- Chairman & Chief Executive Officer
Hi Brian.
Brian Singer -- Goldman Sachs -- Analyst
Two questions with regards to the new type curve and the timing of the more widely spaced wells. As you slow activity in CapEx in the second half, can you just to give us or remind us what your expectations are for how many widely spaced walls would come online by quarter over the course of the year? It seems like that's disproportionately 3Q and 4Q or maybe 2Q, 3Q or 4Q?
Randy A. Foutch -- Chairman & Chief Executive Officer
I think I'll let Karen give you -- Karen or Dan, but it's -- we came in through the end of 2018 with the number wells in process. And so we'll work off that inventory and then start to wider spacing.
T. Karen Chandler -- Senior Vice President & Chief Operating Officer
So, the well count numbers as we're coming in through first quarter of 2019, that's kind of in transition time. We've got 15 wells that we will be finishing at completion-wise in this quarter. And then as we roll into second quarter, then we move toward the wider-spaced wells as we kind of finish up at least in the current plan those completion activities. So that would be the remainder of the wells after the 15 --
Brian Singer -- Goldman Sachs -- Analyst
Got it. Okay. And then my follow-up is, do you have -- what's the longest history if all that you have wider-spaced walls online, or will these be the first ones you're testing? And I kind of asked to see if what you're saying on slide 9 is it's really the second year where you'll see the differentiation in terms of a lower decline rate relative to the tightly spaced wells, when we would start to see that evidence? Is that more of a late 2020 type event, or will you be seeing results from any wells that you may have in the hopper that you already have online?
Randy A. Foutch -- Chairman & Chief Executive Officer
Brian, we said for a long time that production history matters and we never lied. As you know, claiming lots of early on information is being relevant. We've had some different landing points and so and so forth. But Jason, do you want to address specifically?
Jason R. Greenwald -- Vice President, Reservoir Engineering
Yes, sure. Hi, this is Jason. In terms of how much production history we've got on wider-spaced wells, the answer is several years. So going back into 2016 in particular, those were significantly consistent with what we're planning to do on a going-forward basis. So that's the production history that we've got going at least back to 2016.
Brian Singer -- Goldman Sachs -- Analyst
Got it, thank you.
Operator
Thank you. And our next question comes from Derrick Whitfield with Stifel. Your line is now open.
Derrick Whitfield -- Stifel -- Analyst
Thanks, good morning all.
Randy A. Foutch -- Chairman & Chief Executive Officer
Good morning, Derrick.
Derrick Whitfield -- Stifel -- Analyst
And I'll pick up on Brian's question and perhaps ask this for either Randy or Karen. But based on Karen's earlier comments, is it possible that your revised type curve is overly punitive in light of your broad D&C optimization efforts since 2016?
Randy A. Foutch -- Chairman & Chief Executive Officer
You know, we've tried to play middle-of-the-road and not be -- and not push the data one way or another. I think we've tried to be completely straightforward and get the conclusions that the data gives us at the time. Obviously when you look at the curves, some of this data took two years to three years to materialize. That doesn't mean there's not perhaps upside. But where we are today, this is how we see it.
Derrick Whitfield -- Stifel -- Analyst
Understood. And then if I think about the PowerPoint and discussion, most of it has been focused on the productivity of your new type curve. Could you speak to the current expected cost of these wells and what tweaks you plan to test in low-density development that could improve the cost side of the equation?
Randy A. Foutch -- Chairman & Chief Executive Officer
Yes, I will let Karen give you the exact numbers, but we kind of took the same approach on cost. We are using as we have always done. We did see some, perhaps some softening in service costs that we know is there that came about in the last couple of months. We used that because that was factual. We have not projected additional service costs in any of our numbers. But Karen, do you want to --?
T. Karen Chandler -- Senior Vice President & Chief Operating Officer
Yes. So we've continued through the last quarter, a couple of quarters to see some improvement, again continuation of drilling completion efficiencies and then also some service costs reduction and working hard with our service providers to look at the overall cost structure. We've seen saving $200,000 (ph) trimmed off in the last quarter. So, continuing to make good progress there on well costs. As we continue to kind of look at the broader spacing, we continue to look at completions optimization around sand volumes, water volumes, optimization and others. So there's certainly still potential to keep working on the well costs. We have made good progress and we expect that to continue. There may be more service cost depending on commodity price, and we'll continue to work that.
Derrick Whitfield -- Stifel -- Analyst
Very helpful. Thanks guys.
Operator
Thank you. And our next question comes from Joe Allman of Baird. Your line is now open.
Joseph Allman -- Baird -- Analyst
Thank you. My first question is could you respond to the 13-D that SailingStone filed this morning? And the way I see it SailingStone is suggesting four things. So, the first thing would be lower G&A to the tune of like 50% lower. Second would be focus on return on capital while prioritizing free cash flow and return of capital. Third thing is a reasonable business plan with management compensation aligned with that plan. And the fourth thing would be pursuing strategic alternatives.
Randy A. Foutch -- Chairman & Chief Executive Officer
Joe, SailingStone Capital has been a longtime shareholder. They did file a 13-D this morning. And we engage in lots of communication with our shareholders and we value their input. And I think I'll just stop there.
Joseph Allman -- Baird -- Analyst
Got you. Okay. My follow-up question is in terms of the spacing plan, where ultimately do you expect to go to? I know in one of your slides, you are showing kind of any of the optimization and then the rate of return optimization. Are you moving toward the rate of return optimization or are you moving toward the NAV optimization?
Randy A. Foutch -- Chairman & Chief Executive Officer
We announced, Joe, in the third quarter call that while we had spent a fair amount of time and effort trying to really maximize the NAV over the inventory that we had, we felt like that has added substantial inventory. We recognized and then talked about it for a while that there were some degradation in reserves and productivity. But we announced in the third quarter that we were not going to continue focusing on NAV that we were going to go for broader spacing and drill just better rate of return wells. And that's what this strategy shift for us is all about.
Joseph Allman -- Baird -- Analyst
Got you. And just to clarify on that one. So I know originally, Randy, I think the NAV approach would have had potentially like 32 wells per section or 24 wells per section. And right now, your ROR optimization is looking at four wells to eight wells. So are you actually moving to four wells to eight wells per section overall?
Randy A. Foutch -- Chairman & Chief Executive Officer
Yes. I think that's directionally where we're going. There are some zones that probably lend themselves to eight wells, but I think directionally that's what you should think about.
Joseph Allman -- Baird -- Analyst
Great. Very helpful. Thanks and Happy Valentine's Day.
Randy A. Foutch -- Chairman & Chief Executive Officer
Thank you.
Operator
Thank you. And our next question comes from Richard Tullis of Capital One. Your line is now open.
Richard Tullis -- Capital One Securities -- Analyst
Hi, Thanks. Good morning everyone.
Randy A. Foutch -- Chairman & Chief Executive Officer
Good morning, Richard.
Richard Tullis -- Capital One Securities -- Analyst
Randy, looking out to 2020, 2021, I know you mentioned you would likely be able to keep oil flat with the 2019 exit rate. What specific DNC CapEx would be associated with that, and what sort of oil price would you be thinking about for those two years for the associated budget?
Randy A. Foutch -- Chairman & Chief Executive Officer
We used, I think we said that we just kind of used strip pricing going out in those years. And that basically makes D&C cost relatively flat the next couple of years. I think there's some, again I referenced the fact that there's some things that could be enhancements of that including pricing, including reduction in service costs, including better performance on the type curves, but we're basically using the strip prices. And you know, I think the message is that the 2020 program the way we modeled is about the same as the 2019 program.
Richard Tullis -- Capital One Securities -- Analyst
Okay, that's helpful. And then secondly, what's the rough split between zones for the 2019 drilling program?
Randy A. Foutch -- Chairman & Chief Executive Officer
The 2019 drilling program, 2020 is going to be about flat. We're focusing pretty much on the Upper and Middle. As we've said a lot, we have a lot of client inventory, we have a lot of inventory. I think 2020 is probably a little more weighted toward the middle Wolfcamp, but it's going to be Upper and Middle.
Richard Tullis -- Capital One Securities -- Analyst
All right. Thanks so much. I will jump back in the queue.
Randy A. Foutch -- Chairman & Chief Executive Officer
Thank you.
Operator
Thank you. And our next question comes from the line of Noel Parks of Coker & Palmer. Your line is now open.
Randy A. Foutch -- Chairman & Chief Executive Officer
Good morning.
Operator
Moving on, our next question comes from the line of Kashy Harrison of Simmons Energy. Your line is now open.
Kashy Harrison -- Simmons Energy -- Analyst
Good morning everyone Thanks for taking my questions.
Randy A. Foutch -- Chairman & Chief Executive Officer
Good morning.
Kashy Harrison -- Simmons Energy -- Analyst
So in the prepared remarks and the press release last night, you highlighted anticipated corporate cost reductions in the second half of 2019. So either for Randy or Rick, I was just wondering if you could give us a sense of what you're planning in terms of G&A reductions on a dollar basis?
Richard C. Buterbaugh -- Executive Vice President & Chief Financial Officer
Kashy, this is Rick. Similar to what you saw in 2015 when we saw a significant drop in commodity price at the end of 2014, we modified our operating programs, significantly dropped the amount of activity. The cuts that you would be seeing in 2019 I think are going to be appropriate relative to the rig activity that we do. We're going to balance that with the timing of when that activity takes place. If we see, as Randy talked about, changes in commodity prices or service costs that changes our cash flow, we may modify the rig activity and completions along with that which drives a lot of the G&A cost associated with that.
Kashy Harrison -- Simmons Energy -- Analyst
Got you. And then I guess maybe my follow up, my second question and this one might be for Karen or for Jason. But I was wondering if you could just walk us through the ultimate gap in understanding between the actual results and the expected results on the historical wells, which include the appropriate spacing? So why do we employ a higher B-factor initially, and what was missed in the initial analysis that ultimately resulted in a lower B-factor?
Randy A. Foutch -- Chairman & Chief Executive Officer
I'll take a first crack at that. And as we tried to show in the deck is that where we saw definitive production history was in a couple of outyears. They tracked pretty close initially, and I think that was really the eye-opener. And in the 2018 drilling, where we drilled pretty tight spacing thinking that was the NAV inventory approach, we saw those results much quicker. Jason, do you want to --?
Jason R. Greenwald -- Vice President, Reservoir Engineering
Yes. I guess the thing I would emphasize is the additional production data that we've been talking about for quite some time. And to pick up on what Randy is talking about, with the denser spacing kind of in the more recent drilling, that was having us take just a little bit harder look at more broadly at all of the production data that we had to come up with our current interpretation.
Kashy Harrison -- Simmons Energy -- Analyst
I guess what I was trying to understand more so was on the -- I guess we had a higher B-factor because we thought we were going to get a higher terminal oil production curve, and even on these new wells, these new wells should be, in theory, would be comparable to the wider-spaced wells in the past. So really what I'm trying to get at is, is our understanding of longer-term production in shale evolving? Just I mean, that's really where I'm more or so going with this. Are we just overestimating the recoveries in the Midland Basin right now?
Randy A. Foutch -- Chairman & Chief Executive Officer
I don't want to -- I think I can speak a lot about our properties. And on page 6, I think that is our forward-looking curve, that's our understanding. And we've said -- and this is interesting I think to us is that we've said for years that as this production ages, it will get gassier. And in fact, we showed slides in which we had our GOR increasing out over five years. Now, what we've done is we've taken a forward-looking curve and pushed that out, and that's on I think page 6, kind of gives you where we think we are today.
Kashy Harrison -- Simmons Energy -- Analyst
Okay. That's it from me. Thank you.
Randy A. Foutch -- Chairman & Chief Executive Officer
Thank you.
Operator
And our next question comes from Sameer Panjwani of Tudor Pickering Holt. Your line is now open.
Sameer Panjwani -- Tudor Pickering Holt -- Analyst
Hi guys, good morning.
Randy A. Foutch -- Chairman & Chief Executive Officer
Good morning.
Sameer Panjwani -- Tudor Pickering Holt -- Analyst
So I think it's been a while since we've gotten an inventory update. So, could you share us some thoughts regarding remaining locations between the Upper and Middle Wolfcamp, assuming the new four wells to eight wells per section spacing design, maybe low-end and high-end to correlate the difference of potential spacing?
Randy A. Foutch -- Chairman & Chief Executive Officer
Yes. And that's a good question, appreciate that.
Jason R. Greenwald -- Vice President, Reservoir Engineering
So this is Jason. On the total inventory figures, the figures that we have talked about in the recent past are 1,600 total locations and those figures in total that hasn't -- our current spacing and developments approach haven't changed those figures.
Sameer Panjwani -- Tudor Pickering Holt -- Analyst
Okay. And to clarify, that's just between the Upper and Middle Wolfcamp?
Jason R. Greenwald -- Vice President, Reservoir Engineering
No. That's all zones. And so that is 1,600. Just to make sure that that's clear, that's eight locations per section, that's 1,320 co-development.
Sameer Panjwani -- Tudor Pickering Holt -- Analyst
Okay great. And then circling back to the type curve conversation, just trying to reconcile the difference between the oil cut in your type curve, up 31% and in your reserves up 26%. The reason I asked this is I think this is the second time in recent memory that oil cut has been adjusted. So I'm just trying to get a sense of your comfort level with the go-forward curve relative to kind of what the reserves are saying?
Randy A. Foutch -- Chairman & Chief Executive Officer
Rick, do you want to --?
Richard C. Buterbaugh -- Executive Vice President & Chief Financial Officer
Keep in mind that the reserves are the remaining reserves. It does not include the production at the early life of those wells. And we've got wells included there that were drilled back in 2008 and 2009. So what you're seeing in the type curve is from day one of a new well which is going to be higher. And as you saw on page 6 that oil tends to be more front-end loaded. And so you produced off some of the oil that's in the reserves. Since we do not book a large amount and really just a minimal amount of PUDs, you don't receive the benefit of a lot of PUD bookings in the total oil amount in the reserves.
Sameer Panjwani -- Tudor Pickering Holt -- Analyst
Okay. That makes sense. So, essentially your PUD oil cut would be in line with your type curve?
Richard C. Buterbaugh -- Executive Vice President & Chief Financial Officer
Yes.
Randy A. Foutch -- Chairman & Chief Executive Officer
Yes.
Sameer Panjwani -- Tudor Pickering Holt -- Analyst
Okay, thank you.
Operator
Thank you. And our next question comes from the line of Gregg Brody of Bank of America. Your line is now open.
Randy A. Foutch -- Chairman & Chief Executive Officer
Good morning, Gregg.
Gregg Brody -- Bank of America -- Analyst
Good morning guys. You mentioned the 2020 spend would be similar on the D&C side to 2019. Did you -- can you provide some guidance on what the infrastructure spend might look like as part of that?
Randy A. Foutch -- Chairman & Chief Executive Officer
I think Rick's got better numbers, but effectively the 2020 is reduced. We have said now for a couple years that our infrastructure spend is basically behind us, but you always have to set tanks and things and time lines. So there is some infrastructure spend. And that infrastructure spend that we have in the past, again to repeat himself, has led to us to really have very, very efficient operations and very efficient LOE. I think 2020 will be somewhat similar to 2019.
Richard C. Buterbaugh -- Executive Vice President & Chief Financial Officer
And then in the following years, I would expect to see it begin to come down. That would be -- 2019 and 2020 will be some expansion into newer areas, some of the acreage that was acquired where we would be expanding some of our existing corridors. So as Randy said, 2019 and 2020, I would expect the infrastructure to be very similar and then begin dropping again.
Gregg Brody -- Bank of America -- Analyst
I appreciate all the detail here today. I'm just curious about how you're thinking about managing your credit profile as you navigate commodity prices and what you do with excess cash flow? Maybe you can give us an update there, that would be helpful.
Richard C. Buterbaugh -- Executive Vice President & Chief Financial Officer
Yes, on the credit side, as you are aware, we have two outstanding loan-term note issued. There's $800 million associated with that, none of which is due prior to 2022. We do have our revolving credit facility which has $1.3 billion borrowing base, of which we've drawn about $200 million, little over $200 million on that. The fact that we are dedicated to operating within cash flows, I would not expect to see any meaningful change in that line. And so, with the amount of liquidity that we have, the fact that there is no long-term debt due for three years, we are well below any covenant tests within that credit facility. So we're very, very comfortable with where we're at today even in a fluctuating commodity price environment.
Gregg Brody -- Bank of America -- Analyst
I appreciate all that. What I meant more specifically was are you targeting a leverage target through your plan here? How are you thinking about those types of metrics?
Richard C. Buterbaugh -- Executive Vice President & Chief Financial Officer
We've always looked at that, made sure that we had plenty of flexibility. And even at times when our -- on a net debt to either trailing or projected EBITDA was moving up, we had a lot of flexibility of how we could deal with it. As you saw when we divested of our interest in Medallion and reduced the debt significantly, we think we still have much of that flexibility. But over the outlook for a multi-year outlook, we would be targeting, really around 2. You may see it move up and be opportunistic to 2.5 times, but certainly stay below that. As I mentioned in my comments, you will see little bit of an outspend in the first quarter of 2019. And so, we would expect to fund that off of our credit facility, but then repay that over the remainder of 2019 such that we would stay at a very similar level to what you see now.
Gregg Brody -- Bank of America -- Analyst
Got it. And you don't expect the borrowing base to change as a result of the reserve revisions?
Richard C. Buterbaugh -- Executive Vice President & Chief Financial Officer
The borrowing base is really based upon the value of our reserves. As you saw, the value has actually gone up versus year-end 2017. Since that value is primarily associated with proved developed reserves, that's going to be the primary focus associated with the credit facility. Now, the borrowing base is always going to be determined based upon kind of overriding commodity prices at the time that the group is looking at that. And so, I think that's going to be very dependent upon what is the price deck that the bank group would use. But at the $1.3 billion base that was really set and approved last fall, there is still cushion to go above that. We chose not to go really push that, and are very comfortable with that. Now, even if it comes down, we would still have more than adequate liquidity given the programs that we are looking at.
Randy A. Foutch -- Chairman & Chief Executive Officer
And Gregg, keep in mind Rick went over our hedging, where on the crude, we are floored at 47-something and we get all the upside on that. And that is comforting to us because it does protect to a significant degree our cash flow and line of credit at least through 2019.
Gregg Brody -- Bank of America -- Analyst
Great. And then just one follow-up. You gave the 2020 oil production expectations and sort of how it's going to stay flat. Could you give some insight into how we should think about gas and NGLs in terms of growth?
Richard C. Buterbaugh -- Executive Vice President & Chief Financial Officer
On a run rate versus our exit in 2019, we expect to see fairly similar on a BOE basis. I don't have with me the breakdown between gas and NGLs, but on a BOE basis, that we would again stay pretty flat 2020. There's always going to be some variability on those amounts on a quarter-to-quarter basis which is going to be driven by the number of completions that are coming on and when those completions come on in the quarter as we've always talked about. But on average, we expect that to be very similar and basically flat.
Gregg Brody -- Bank of America -- Analyst
Great, thank you for the time guys. I appreciate it.
Randy A. Foutch -- Chairman & Chief Executive Officer
Thank you.
Operator
Thank you. And our next question comes from Noel Parks of Coker & Palmer. Your line is now open.
Randy A. Foutch -- Chairman & Chief Executive Officer
Good morning, Noel.
Noel Parks -- Coker & Palmer -- Analyst
Hi, sorry about that. I didn't get off mute fast enough last time. One thing at this point in your development, has the issue of choke management pretty much been resolved, or is that the thing you are still looking at when bringing wells online?
Randy A. Foutch -- Chairman & Chief Executive Officer
We spent a fair amount of time on doing that and we saw some results that were positive. I think in general what we saw was that after some period of time, and it was dependent a little bit quite frankly on spacing, they reverted back to the mean. So we still have -- I didn't really address it in my remarks, but we still think we've got efficiencies on the production side, on the completion side, on the drilling side. And I think the flow back process, we're still looking at. I don't know that we're going to do choke management across the board in any way.
Noel Parks -- Coker & Palmer -- Analyst
Okay, great. Just wondering when you're talking about service costs having seen some improvement, I was wondering specifically, you know, as you kind of decide where you're heading with the rig count, when you are talking with your rig vendors, was there a lot of flexibility? Did they sort of come to the table looking to bargain as far as what you might get for day rates that you held onto them, a couple of the rigs?
Randy A. Foutch -- Chairman & Chief Executive Officer
It's interesting and that we've had long relationships. And I think there's a lot of dialogue between Laredo and our service providers, not just on rigs but on pressure pumping, on all parts of that. And so I think we've been pretty forthright in explaining where we are and where we're headed. And their job is to take care of their shareholders. So there's a pretty healthy debate that goes on almost continually. I think Karen --
Noel Parks -- Coker & Palmer -- Analyst
Okay.
Randy A. Foutch -- Chairman & Chief Executive Officer
It not a -- we do bid out a fair amount of activity, but that's not a point in time, that's just process that goes on almost continually.
T. Karen Chandler -- Senior Vice President & Chief Operating Officer
One of the, as Randy said, we've -- here, obviously being very clear about what our strategy is for 2019 to operate within cash flow. So, the discussions we are having with our service providers are very much geared toward that. The more savings we can get, the more activity potentially. And so, that's just a very ongoing dialogue that we're working hard to have really across all of our services.
Noel Parks -- Coker & Palmer -- Analyst
Okay, great. And just one last thing. There's a brief mentioned a minute ago about the credit line. Do you happen to recall what the last borrowing base redetermination, what the price deck was? What was the new stand on the banks?
Randy A. Foutch -- Chairman & Chief Executive Officer
Each bank within the group is going to use their own individual price tag. That's going to be in, the last round in the fall. Appears to be in the range of $50 to $55.
Noel Parks -- Coker & Palmer -- Analyst
Okay. They had not gotten as aggressive as sort of the strip we saw at the time, in other words.
Randy A. Foutch -- Chairman & Chief Executive Officer
Exactly, I'm not going to speak for the banks on what they used because each bank is going to use their own.
Noel Parks -- Coker & Palmer -- Analyst
Okay, fair enough. Thanks.
Operator
And I am not showing any further questions at this time. I would now like to turn the call back to Ron Hagood for closing remarks.
Ronald L. Hagood -- Vice President, Investor Relations
Thank you very much for joining us today. We appreciate your interest in Laredo, and have a good morning.
Operator
Ladies and gentlemen, thank you for participating in today's conference. This does conclude the program and you may all disconnect. Everyone, have a great day.
Duration: 55 minutes
Call participants:
Ronald L. Hagood -- Vice President, Investor Relations
Randy A. Foutch -- Chairman & Chief Executive Officer
T. Karen Chandler -- Senior Vice President & Chief Operating Officer
Richard C. Buterbaugh -- Executive Vice President & Chief Financial Officer
Brian Singer -- Goldman Sachs -- Analyst
Jason R. Greenwald -- Vice President, Reservoir Engineering
Derrick Whitfield -- Stifel -- Analyst
Joseph Allman -- Baird -- Analyst
Richard Tullis -- Capital One Securities -- Analyst
Kashy Harrison -- Simmons Energy -- Analyst
Sameer Panjwani -- Tudor Pickering Holt -- Analyst
Gregg Brody -- Bank of America -- Analyst
Noel Parks -- Coker & Palmer -- Analyst
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