Good morning, and welcome to Centennial Resource Development's Conference Call to discuss its Second Quarter 2020 Earnings. Today's call is being recorded. A replay of the call will be accessible until August 18, 2020, by dialing 855 859-two thousand and fifty six and entering the conference ID number 7,031, 059 or by visiting Centennial's website at www.cdevinc.com. At this time, I will turn the call over to Hays Mabry, Centennial's Director of Investor Relations, for some opening remarks. Please go ahead.
Thank you, Rebecca, and thank you all for joining us on the company's Q2 earnings call. Presenting on the call today are Sean Smith, our Chief Executive Officer George Glyphis, our Chief Financial Officer and Matt Garrison, our Chief Operating Officer. Yesterday, August 3, we filed a Form 8 ks with an earnings release reporting 2nd quarter earnings results for the company and operational results for our subsidiary, Centennial Resource Production LLC. We also posted an earnings presentation to our website that we will reference during today's call. You can find the presentation on our website homepage or under Presentations at www.cedevinc.com.
I would like to note that many of the comments during this earnings call are forward looking statements that involve risks and uncertainties that could affect our actual results and plans. Many of these risks are beyond our control and are discussed in more detail in the Risk Factors and the Forward Looking Statements sections of our filings with the SEC, including our Form 10 Q for the quarter ended June 30, 2020, which was also filed with the SEC yesterday. Although we believe the expectations expressed are based on reasonable assumptions, they are not guarantees of future performance, and actual results or developments may differ materially. We may also refer to non GAAP financial measures that help facilitate comparisons across periods and with our peers. For any non GAAP measure we use, a reconciliation to the nearest corresponding GAAP measure can be found in our earnings release or presentation, which are both available on our website.
With that, I will turn the call over to Sean Smith, our CEO.
Thank you, Hays. The past 6 months have certainly been a challenging time for the entire E and P industry, including Centennial. In March, we witnessed an unprecedented increase in global supply from OPEC plus members amid a global pandemic, which had already significantly weakened near term demand. These events, in part, have caused oil prices to move significantly lower and caused widespread shut ins by the industry during the Q2. With this in mind, I'd like to start off today's call by quickly reviewing Centennial's response to recent global events that have transpired over the past several months and is outlined on Slide 4 of today's presentation.
We reacted decisively in order to protect the balance sheet and manage liquidity. In May, we announced plans to temporarily suspend all drilling and completion activity, while materially reducing our full year capital budget by 60%. As a result of low realized prices, we voluntarily curtailed approximately 20% of our May production in order to protect field level cash flow and economics. The production team used our in house data analytics tool to quickly evaluate well economics to determine which well should be shut in based off actual netbacks and operating costs for each individual well in the field over this time. In early June and as oil prices increased, we brought back essentially all of our shut in volumes with virtually no incremental costs or associated workover expense.
As discussed on the previous earnings call, we also took several steps in order to significantly reduce our cost structure and debt outstanding. During the Q2, we made the tough but necessary decision to reduce the size of our workforce in order to better align the company's organizational structure given the current commodity price environment and subsequent activity levels. This also included reduction in salaries across all company employees, with the largest reductions being taken at the senior management and Board levels. Additionally, we executed a successful debt exchange offer, which reduced our total debt outstanding by $127,000,000 and lowered future interest expense. It is important to note, we have not been standing idle during this lower commodity price environment.
We've taken this opportunity to completely review our operational procedures and practices searching for any incremental cost savings or efficiencies. While George and Matt will provide more details on this shortly, I am confident that Centennial will emerge from this downturn with expanded operating margins and structurally lower well cost, which will continue to benefit the company going forward. With that, I will turn the call over to George to review the financials before providing some closing remarks. George?
Thank you, Sean. I'll first review our Q2 financial results and then discuss the debt exchange, capital structure, liquidity hedge position and 2020 guidance. Turning to our financials on Slide 11 of the earnings presentation. Net oil production for the Q2 averaged approximately 37,400 barrels per day, which was down 13% over the prior year period and represents a 10% decrease from Q1. Production was impacted by the voluntary curtailment of approximately 20% of May volumes and the significant reduction in completion activity during Average net oil equivalent production totaled 68,245 barrels per day, which was down 10% from the prior year period and represents a 5% reduction from Q1.
Total equivalent production declined less than oil production because we had less flush contributions from new wells, which typically yield a higher oil cut, and we flared fewer volumes in Q2 compared to Q1. Revenues totaled approximately 90,000,000, which was a 53% decrease compared to Q1, primarily as a result of the significant decline in oil and NGL price realizations and lower production. Excluding the impact of basis hedges, Centennial's Q2 realizations were 77% of WTI or $21.47 per barrel compared to $45.14 in Q1. Lower oil realizations as a percentage of WTI were primarily driven by a negative CMA roll adjustment, particularly during the month of May. Lastly, NGL prices were down 46 percent to $7.72 per barrel compared to 14.30 in Q1.
Turning to costs, despite the decline in production volumes, unit costs continue to look good relative to our expectations. LOE per barrel decreased by 17% from Q1 to $4.16 primarily as a result of lower workover expense as well as continued reduction in equipment rentals and electricity. Matt will provide further details on LOE shortly. Cash G and A for Q2 was $2.21 per barrel overall, but was $1.75 when adjusted for severance costs, primarily associated with our recent workforce reduction. DD and A decreased by 3% to $14.98 per barrel.
And lastly GP and T expense increased 7% to $2.78 per barrel in part because of a significant reduction in Feet monetizations relative to prior quarters. In Q2, we recorded GAAP net income attributable to our Class A common stock of approximately $5,000,000 Adjusted EBITDAX totaled $24,000,000 down from approximately $113,000,000 in Q1 due to lower commodity prices and production volumes, which were partially offset by reduced operating costs. Shifting to CapEx, during Q2, we ran essentially 0 drilling rigs and did not spud any wells. In April, we completed 4 gross wells compared to 22 completions during the prior quarter. As a result of lower activity and continued cost reductions, Q2 D and C CapEx was 21,000,000 compared to approximately 147,000,000 in Q1.
As Matt will describe shortly, our D and C cost per well have declined quite significantly as a result of internal initiatives to improve efficiencies as well as overall service market conditions. Facilities and infrastructure capital totaled approximately 6,500,000 compared to 25,000,000 during Q1 due to the lower level of completion activity in Q2 and fewer infrastructure needs. We also incurred approximately $100,000 in land capital. Despite the de minimis land spend, we anticipate maintaining our acreage position as a result of recent swaps and trades executed by our land team. Overall, Centennial incurred approximately 28,000,000 Slide 8, As we addressed briefly on the last quarterly call, in April, we launched a debt exchange that provided all bondholders the opportunity to exchange their senior unsecured notes into 2nd lien notes at a significant premium to the then prevailing market price.
The objective of the exchange was to reduce our total senior unsecured debt amounts into lower interest expense. On May 22, we completed the exchange in which holders of 254,000,000 of senior unsecured notes across both the 2026 2027 tranches tendered and exchanged their bonds for 127 of new 8% second lien notes due in 2025. The net effect of the exchange was a reduction to our senior notes of $127,000,000 and we are pleased to have closed the transaction during a very turbulent period in the markets. On Slide 9, we summarize our capital structure and liquidity position. At the end of the quarter, we had 370,000,000 of borrowings on our revolving credit facility.
During the quarter, we borrowed 135,000,000 on the facility, which was an unusually high amount relative to previous quarters, particularly in light of the minimal capital spend during the Q2. The increased level of borrowings was primarily related to working capital changes, including a significant reduction of our accounts payables and accrued capital expenditure line items. This occurred because 2nd quarter working capital needs were still reflective of higher levels of activity from Q1 and because incoming cash for the quarter was lower due to the deteriorating commodity prices coupled with lower production. I would note that we do not anticipate anything remotely near this level of borrowings in subsequent quarters. In fact, based upon anticipated capital spending levels for the second half of the year, which you can reference on Slide 10 of the presentation, we expect that expenditures will be funded through operating cash flow based upon current strip and our hedge position.
As of June 30, Centennial had total liquidity of approximately $300,000,000 which is based upon the $700,000,000 borrowing base adjusted for the $32,000,000 availability blocker, dollars 370,000,000 of outstanding borrowings, dollars 8,000,000 of letters of credit outstanding and approximately $7,000,000 of cash. Given that we don't anticipate a significant level of borrowing going forward, we expect that our liquidity position will remain quite sufficient for future activity. Finally, at June 30, Centennial's 1st lien debt to LTM EBITDAX was 0.9 times, net debt to LTM EBITDAX was 2.6 times and net debt to book capitalization was 29%. I'll remind you that the leverage covenant currently applicable in our credit agreement is 1st lien debt to LTM EBITDAX, which currently has a maximum threshold of 2.75 times providing plenty of cushion. The amendment to our leverage covenant which was completed concurrently with the debt exchange significantly enhances our financial flexibility going forward.
Turning to hedging on Slide 13. As a result of the Q2 hedges that we established in March as oil markets were rapidly deteriorating, we incurred a hedging loss of approximately 7,000,000 during Q2. At the time, we also entered into similar hedges in Q3 and will likely incur even more significant hedge losses during the Q3. At the time, we made the prudent decision to implement these hedges in order to protect the company against further downside risk in the event that oil prices remained at severely depressed levels for a prolonged period of time. Subsequently, we have initiated a more systematic hedging program to protect future cash flows, which is more representative of what you'll see in the future.
Going forward, we plan to hedge a portion of our production with the goal of covering certain corporate costs such as G and A, interest and exploration expenses, while also retaining exposure to potential upside in prices. With this philosophy in mind, we recently entered into fixed price WTI swaps for the Q4 of this year covering 13,000 barrels per day at an average price of $38.89 Additionally, we have costless collars in place for Q4 covering 2,000 barrels per day at a floor of 39 and a cap of $44.50 We anticipate continuing to add to our hedge program for future volumes with a primary focus on 2021. I'd now like to touch on our updated 2020 corporate guidance on Slide 12. As you'll recall, we had largely suspended guidance with the exception of CapEx back in late March as a result of the precipitous decline in oil prices and our concomitant reduction in activity. We are now able to reissue full year guidance given that prices have stabilized to some degree and the potential for future shut ins has been drastically reduced.
As oil prices have recovered from record lows, we have commenced the completion of 5 DUCs in New Mexico and assuming strip pricing, we plan to add 1 operated rig in the Q4. Currently, we expect this rig will commence drilling in Reeves County before moving to New Mexico late in the year or it is likely to remain. We expect the completion activity to generate midpoint oil of 35,500 barrels per day for the year. You'll also note that oil as a percentage of total production is expected to be approximately 54%, which is not surprising given the lack of flush production from new wells as compared to prior periods. Given these planned activity levels, we estimate total capital expenditures for the year of 240,000,000 to 270,000,000 which represents a $10,000,000 reduction at the midpoint compared to our previous guidance.
As you can see back on Slide 10, total CapEx incurred during the first half of twenty twenty represents approximately 80% of our updated full year budget and was largely driven by our 5 rig drilling program at the beginning of the year. This implies a much lower spend in the second half of the year compared to the first, which will, as I mentioned, is expected to result in cash flow neutrality for the balance of the year. To wrap up, I hope you've come away with a sense for the tangible progress we've made on a number of fronts during the quarter. We materially reduced our cost structure, particularly with regards to G and A and LOE costs. We were able to reduce our total debt amount of senior notes outstanding by 127,000,000 while lowering future interest expense.
And finally, we've instituted a hedging program providing protection from downside commodity risks. Ultimately, all of these actions have better positioned future. And with that, I'll turn the call over to Matt to review operations.
Thank you, George. During challenging times such as present, we have been more focused than ever on reducing what costs we can control across every single discipline in the company. As many of you know, from last quarter's call, Centennial has implemented a number of projects in the field, focused on reducing LOE costs. And I'm pleased to share with you the progress we've made as well as detail the positive financial impacts that they've had. As you can see on Slide 5, we reduced 2nd quarter LOE per unit by 17% compared to last quarter, representing our 3rd consecutive quarter of declining LOE per unit.
Even more impressive is the fact we've been able to continue to reduce our LOE in a declining production environment. Looked at a slightly different way, total LOE decreased $16,500,000 from the Q3 of 2019, even though we added over 50 wells since that time. This considerable savings has been driven by the execution from our operations staff on a number of different fronts. Earlier this year, we completed Phase 1 of our company owned electric substation in Reeves County. Upon initial startup, we were immediately able to reduce the number of generators from approximately 135 to 50 as seen on Slide 6.
The savings on rentals from this is obvious, but the more reliable and consistent form of power manifests itself in significant reductions in downtime, which directly impacts the bottom line. Additionally, we expect phases 2 and 3 of our electric substation to be operational during the Q4 of this year, further reducing our reliance on generators and having a direct impact on our go forward LOE cost. Staying on Slide 6, you can see our transition to gas lift has been a very significant effort by our production and fields teams. At this time last year, roughly half of our wells were reliant on ESP as the primary form of artificial lift and only 20% utilized gas lift. By Q2 of 2020, we had added roughly 100 incremental wells to the field and only a third of the total wells remained on ESP, while 40% utilized gas lift.
This is key because gas lift is inherently more reliable when compared to ESPs. The increased reliability of our artificial lift program has resulted in a more stable production base with lower downtime. We've also seen our failure rates for the artificial lift drop by 34% this year compared to 2019, resulting in less workover expense. We will continue to utilize gas lift across our assets wherever possible. Our team has also continued to optimize our saltwater disposal system in Reeves County.
Year to date, we've realized significant reduction in disposal costs through the removal of generators at our SWD sites. In addition, costly trucking of produced water has virtually stopped as 97% of our water is now on pipeline. Combined, these efforts have reduced our per barrel disposal costs on our operated system by 35% compared to last year, adding continued downward pressure to LOE and further increasing the value of our SWD system to Centennial. While this is just an update of a few of our larger cost savings initiatives, we've continued to pursue smaller items such as equipment purchases that are at historically low prices. With prices as low as they are in many cases, purchasing equipment rather than renting just makes good business sense.
Additionally, we continue to scrutinize and bid out all of our service providers for better pricing. Turning to well costs, I'd like to detail some of the continued improvements that we're seeing in D and C costs, which are seen on Slide 7. We've seen a material and steady decline in our D and C costs, which have been driven by both higher efficiencies as well as structural cost reductions. Beginning with drilling, year to date, we've reduced our spud to rig release cycle times by 25% to just over 18 days on average compared to last year. And while we are proud of these improvements overall, we believe there is still plenty of room to realize lower costs and greater efficiencies.
We have taken full advantage of our drilling hiatus to focus on every single aspect of our drilling program from pad construction through the rig release, carefully evaluating every aspect of the operation. When we resume activity, it will be a very different look for us. Since much of these changes are attributable to our new Centennial 2.0 culture and a much more streamlined approach to our cost structure, we believe the majority of these lower costs will be permanent and not necessarily tied to potential service cost inflation a rising oil price environment. On the completion side, we continue to be impressed by what our team is accomplishing. Compared to last year, we increased our average stages pumped per day year to date by roughly 35% to over 8 stages per day.
Put another way, we have increased the total lateral footage completed per day from 13.50 feet in 2019 to 1700 feet per day in 2020. With this team's track record of success, we feel confident about maintaining that high level of performance when activity resumes. While we've also benefited from overall service our water recycling efforts are starting to play a bigger role this year in our completion cost reduction. For a quick background, in 2019, we implemented a water recycling program with an initial focus on our New Mexico operations. Last year, we recycled and reused over 3,000,000 barrels of flowback and produced water in New Mexico.
After successful implementation in the Northern Delaware, earlier this year, Centennial initiated those same solutions for our Texas operations. Water recycling reduces both fresh water consumption and produced water disposal volumes, which not only lowers our overall completion cost and positively impacts LOE, but also is important from an ESG perspective. Year to date, we have recycled 72% 31% of flowback volumes in New Mexico and Texas, respectively, and plan to continue to increase our use of recycled water with the goal of using recycled water whenever practical. To sum it up, Centennial is not the same company we have been in the past. Our hard times that we've endured have forced us to look at every single piece of our business and consider ways that we could do it better.
The fruits of this labor can be seen in the graph at the top of Slide 7, where overall we've reduced our year to date total well costs by approximately 25% compared to early 2019. As a reminder, since operators report these figures several different ways, I would point out that the well costs we provide are fully burdened, inclusive of drilling, completions, facilities and flowback costs. More importantly, we believe a large portion of these savings are more structural in nature. Said another way, based on current strip prices, along with the expected oilfield service environment, we believe that we'll be able to further reduce all in D and C costs to approximately $900 per lateral foot, assuming our average of 7,500 foot lateral lengths when activity resumes later this year, with the goal of even further reductions to the sub-nine hundred dollars per foot range in 2021. Before I pass it back to Sean, I want to touch on our exposure to federal leasehold, as I know that this is a topic as of late.
Out of our roughly 80,000 net acre position, spanning both the Northern and Southern Delaware Basins, Centennial only has 4,000 net acres or approximately 5% located on federal lands, all in Lea County, New Mexico. Though our federal land leases only represent a small portion of our total land position, we continue to be proactive about building permit inventory such that we always have multiple years of permitted drilling locations. And with that, I'll turn it over to Sean for closing remarks.
Thanks, Matt. Having made some significant cost improvements in the business over the past several months, I trust you can understand why we're excited to resume activity during the second half of the year. This is an important first step in order to moderate current declines and provide momentum heading into 2021. I'm confident that we'll be able to carry forward the cost reductions you've heard highlighted on today's call. Therefore, it is key to understand that our future growth as a company will be supported by: 1, expanded margins, specifically pertaining to future LOE and G and A costs and 2, materially lower well costs.
Finally, one positive outcome which has resulted from our reduction in activity is the significant shallowing of our corporate decline rate. As I mentioned during last quarter's call, our corporate oil decline rate was 45% to 50% at the end of March. Including our planned activity during the second half of this year, we expect this metric to improve to the low 30% range by the end of this year. This represents a significant reduction and will have multiple benefits. The resetting of our corporate decline rate will provide a shallower base production wedge for us to restart activity, helping us eventually return to modest production growth in the future.
Before we go to Q and A, I'd like to leave you with 5 key takeaways from this morning's call. 1, we've significantly lowered our D and C costs, thus driving capital efficiency, and there's still more room for improvement, as Matt mentioned. 2, we've enhanced our margins as a result of recent cost initiatives and optimization of our asset base, particularly to LOE and G and A. 3, our corporate decline rate will be materially lower than previous years, providing us with solid footing headed into 2021. 4, we've reduced the total principal amount of debt outstanding and lowered future interest expense as a result of the debt exchange and 5, finally, we expect to essentially be cash flow neutral for the remainder of this year, helping us manage liquidity while resuming activity.
In closing, all of the above will provide a solid base for Centennial underpinned by a materially lower cost structure. And let's not lose sight of the fact that we have very high quality assets and an outstanding technical team to sustain and drive the future value of the company. With these tailwinds at our back, we're excited to return to a modest level of activity as we close out 2020 and head into 2021. Thanks for listening. And now we'll head to Q and A.
Thank you. The question and answer session will be conducted electronically. And our first question comes from the line of Scott Hanold with RBC Capital Markets.
Thank you. I guess my first question would be, what is the plan going forward? I mean, obviously, you guys had taken off all activity when prices got low and are starting to resume now. But as you look forward, what strategically do you want to do? Is the goal to reduce gross debt, to reduce leverage matrix to a certain point to maintain production.
If you can give us some line of sight on how you think about that? And when you do start activity on a more consistent basis going forward, is it going to be more weighed to the New Mexico area or to Texas?
Sure, Scott. I appreciate the question there. And I certainly understand the desire for everybody to get a look at 2021. As we all know, the back half of this year is going to be a lot of changes and a lot can happen between now and when we start talking about our full guidance for next year with elections coming up. We've got the vaccines relative to the pandemic.
We'll see how that affects the global economy and then ultimately supply demand dynamics. And so all of that weighs into how we're looking at next year. And we have never given forward looking guidance this early in the prior year. So that's not something we're going to do today. But from a managing of the company perspective, take into account that we've totally reset the company from our corporate decline rate, our cost structure, our balance sheet and we've really positioned ourselves to respond to however commodity prices look going into next year.
I think we've done a very good job of that. And the fact that we're cash flow neutral the back half of the year really just shows kind of how we've restructured the business. So while we don't give forward looking guidance, I think what can be said is that we are going to balance both the capital spend, returning to some level of activity, while at the same time managing our leverage profile. So it will be a combination of the 2 is how we are managing our business going forward. I know that's not the maintenance CapEx type of number that people are looking for, but that's how we are going to manage our business for the back half of the year and how we look at going into 2021.
Okay. Yes, I know I understand the challenges with that. I appreciate that color. And I guess my follow-up.
Yes, it was really let me just address that before you can ask one more follow-up is Texas, Mexico. I think that George had mentioned that maybe the rig is going to start off in Texas and then move to New Mexico. That is the plan. We've got just we've got some very attractive leases there that we'd like to get to in Texas that compete very favorably with our returns in New Mexico. So we're going to go hit a 2 well pad there, assuming we have a rig stand up in the Q4.
And then that rig will immediately move to New Mexico where it will be in development mode on our New Mexico assets. So that's kind of our plan of activity and how we plan on attacking it at the end of this year going into 1st part of next.
Okay, understand. And then my follow-up question is, obviously, the big transaction, Chevron, Noble, could have some implications on your acreage. I know Noble is very intermixed with your acreage profile. Could you remind us how between yourselves and Noble, how much of that acreage is from a development strategy is somewhat contiguous or are you planning just to kind of go your separate ways or is there some push and pulls with Chevron now, maybe taking control of that land?
I would say, there is not going to be any material push and pulls with Noble and Chevron going forward. We operate the majority, I mean, nearly all of our position. And so we control our own destiny and won't get pulled into any material non opposition with a new operator down there. I think we're in a very favorable position. They are more adjacent to us than intermixed with us.
So look forward to seeing what kind of development plan that Chevron has in order for that area, but don't think that it will impact any of our operations.
Appreciate it. Thanks.
Your next question comes from the line of Neal Dingmann with Truist Securities.
Sean, maybe a question for you and Matt. You kind of hit the clip, but I know you mentioned just a second ago, Scott, your upcoming pad will be a 2 well pad. Now, Lisa, my question, sort of given your spend outlook that you talked about, George talked about, that we can go to 'twenty one
sort of a 2 parter one.
Based on that, is the thought with pad design to do more just sort of 2 wells or 3 wells pads? And if so, can you get the cost initiatives audit by doing these smaller pads?
Neal, you were breaking up during that question, but I think I got it all. You're really talking about pad size and cost capital efficiency associated with our average pad size. And can we continue that going forward, I think is what you were getting to. So that's what I'm going to answer now. And if that doesn't cover it, we can try to get in, but
that's it. That's it.
Going forward, we do plan on kind of 2, 3 and 4 well pad sizes. I think that's consistent with what we've done in the past. I think the efficiencies that we've seen, efficiencies that we've seen in Q1 and even getting into late last year we'll continue those efficiencies plus the continued improvement, as Matt had mentioned. So I don't think we'll have anything lost from by going from 5 rigs to now ramping back to 1 rig and then eventually more as we go into the future. Maybe Matt, I'll turn I'll let our COO address anything that I may have missed there.
But go ahead, Matt.
I think fundamentally what Sean said is correct with regard to our desire to drill more wells on a pad, kind of our sweet spot is somewhere around 3 wells per pad, maybe a 4th well. But just by the way we operate, typically we target 2 and 3 well pads kind of on average. That being said, anytime you're standing up a rig and starting over, there's going to be just some level of efficiency from when you were running multiple rigs for months months on end, you're going to lose a little bit of some of those efficiencies as you just start to pick up activity again. So I wouldn't expect right off the bat that we hit our stride on the very first well out the gate. I think it's going to take some familiarity with the people in the field and some communication and oversight from our guys in the office.
And then I think we'll hit our stride pretty quickly because we do have lofty expectations for efficiencies on a go forward basis.
Okay. Good to see. And one additional for George if I could. Just on the hedges, you were in kind of a different situation when you earlier this year added those 2nd and third quarter hedges, Mike thought. Or I guess your thoughts into 'twenty one, you'll be in a much better position, both cash and operations wise.
So again, would it just be more opportunistically add hedges or I was wondering George how you think about it?
Yes.
I think, Neil, the way we're thinking about the hedges, as I said in my remarks is, we think about it in terms of covering big chunk of our corporate costs, whether they be G and A or interest. And we're going to do that primarily through swaps and to some extent, costless collars. And in addition to that, in a more normalized kind of operating environment, part of the philosophy is, you put some hedges in place to protect your cash flow, so that you can support your capital program and your overall activity levels, so you aren't whipsawing the number of rigs you have out or the number of completion crews. The other thing to think about is how those hedges might impact your borrowing base. And so there is a thought to making sure that we're kind of optimizing and enhancing our borrowing base levels going forward.
We also want to we've recognized that we're in the depths of a new world here with the global economy and that our view is over time as the economy improves that oil prices will go up. So we do want to give our investors some upside exposure as well. So, there's a bit of a balance there. What I'd say as well is, if the strategy is evolving, it's obviously something that's new to the company. And I think you can differentiate between what we did in Q2 and Q3 versus what we've done in Q4 and what we plan to do going forward.
So, we don't have specific targets, timing that we've put in place for we're going to hedge X percent of volumes, but that's something that we're working on internally and collecting our thoughts on as we go. But bottom line is, we will be much more active from a hedging standpoint to mitigate the risks associated with the oil price environment.
Thanks guys. Good details.
Your next question comes from the line of Leo Mariani from KeyBanc.
Just wanted to kind of get a little bit more color on the activity restart here. You certainly go into the 1 rig case. Just kind of wanted to get a sense, is that a level of activity you feel pretty comfortable at? It's sort of $40 You guys had mentioned potentially adding some other rigs into the future. Is it really just kind of governed by cash flow?
Is the plan going forward just to do your best to kind of spend within cash flow? Just trying to kind of get a sense of what the governors are on future activity changes at CEDEV?
Sure. Thanks, Leo, for the question. And I do feel comfortable that we will be adding likely adding a rig in the Q4, obviously, depending on what commodity prices are doing. I think it's still a volatile market. It has settled a bit.
As we've all seen, it seems like $40 is a bit of a floor at least recently, and that's a good sign that there is support for that price and above. I think as we mentioned in the prepared remarks, assuming strip price, which is essentially $40 slightly increasing in the outward years, that supports at least a modest level of activity. So, should prices change one way or the other dramatically, we may pivot from that. But I feel very comfortable that that's what we're going to see towards the back half of the year. We haven't given what a rig cadence would look like for next year, but assuming prices continue to improve and we think over time they will, as those prices continue to see upward momentum and support looked for us to add additional activity.
That being said, that will all be balanced with our leverage being forefront in our mind. We want to position the company such that we don't get too far out over our skis from a leverage perspective. And so balancing between the 2 will be what we are doing going forward.
Okay. That's helpful. And I guess just following up on the leverage, obviously, you guys had a successful debt exchange here recently. Just trying to get a sense if there's other future initiatives at the company to reduce debt. You guys talked about spending within cash flow in the second half of the year.
Obviously, that kind of more maintains debt. Are there other things that you guys might be looking at, whether it's future debt exchanges or other initiatives to potentially kind of reduce that debt over the next couple of years?
Sure. Yes, good question. We'll always be looking for opportunity to lower our leverage profile if there are options to do so that are accretive to our metrics. As you recall, we were looking at an STBD sale earlier in the year and which would have materially changed our balance sheet. That did not go through, as we all know, but the benefits of that is that keeping that asset helped push our LOE costs further down.
So there are good things to that. So we are we always are looking at strategic sales of non core assets and we'll continue to do that. If we're able to put a package together again of non core assets that we think we can get fair value for that will be accretive to our metrics that will help delever the company, then we'll consider that going forward. Okay. Thank you.
Thanks, Leo.
Your next question comes from the line of Will Thompson from Barclays.
Hey, good morning. I appreciate the detailed look under the hood and on the cost initiatives. It clearly seems like this is more structural in nature. But I want to ask, one of the slides indicate that Centennial is in active negotiation with service providers. Can you just give us a little sense on how those conversations are going and whether price concessions would be upside to the 2021 cost impact versus what you're kind of baking in for second half of twenty twenty?
Sure. Yes, this is Matt. I'll go ahead and start trying to field that question. We provided on Slide 7 a bit of historical look at our performance back to 2018 really from the spud to rig release as well as our completion stages per day, really kind of deliberately to show a bit of a track record of really more of the structural efficiency gains with regard to our overall costs. And if you think about this company's activity, the majority of our activity was in in fact, almost all of our activity was in Q1 and it stopped abruptly in Q2 as George alluded to in his portion of the script.
And so with the exception of some minor spillover with regard to a few completions that were done in the 1st couple of weeks of Q2, dominantly the costs that were reflective on that Slide 7 were indicative of more structural changes. The negotiations with service company providers, obviously without tipping too much, we feel very good about there being some additional upside potential there to realize some cost savings on top of that. We, of course, consider those kinds of things in a go forward look at our business. But for the purposes of planning and for the purposes of kind of just sticking to the fundamentals of blocking and tackling, we really like to focus on the things that we can control and the things that we can change with our teams. Does that help you?
Yes. That's good color. Thank you, Matt. And then I guess as my follow-up, just to clarify on the base decline, the improvement from to low 30s, is that on a BOE basis? And if it is, I mean, how much delta would it be for oil?
And then maybe to manage expectations in context of the full year production guidance, is it fair to assume 4Q will be below 3Q levels? Just want to understand sort of the cadence in light of the 5 DUCs being completed this quarter?
Yes, I appreciate the question there. It's Will. And thank you for acknowledging that we've given out some increased level of detail in this. That's intentional. We're trying to be more helpful for folks to get a better look at the company and how we operate structurally going forward.
Relative to the corporate decline, those numbers I quoted were on a BO basis. And so I feel good about that is the controlling entity, I guess, if you will, or commodity for the company. And so that's how we kind of think about things. We don't give quarterly guidance. And so that's not something I think I'm going to weigh in on.
I think if you draw a line from where we stand today to our midpoint of our guidance, it will give you a good feel for how we're thinking of things. So I think that's the level of detail we can kind of provide from a quarterly basis.
Okay. Thank you, guys.
Thanks, Will.
Your next question comes from Doug MacIntosh with Johnson Rice.
Good morning, Sean.
Good morning.
Just
had a quick question kind of around the OpEx side. You guys have made some pretty impressive improvements and like you said, despite volumes kind of coming down. That being said, it does look like based on the full year guidance, OE comes up a little bit in the back half of the year. What's the driver there? And then to get to the midpoint, it looks like levels are around $5 Is that a good number to think about going forward as well?
Sure. I'll take it. I'll touch on that. And if I missed anything, then Matt can jump in. I think if you look at the back half of the year, obviously, our activity level has slowed.
And so our production will then also continue to decline a little bit. We've added a little bit of activity in the fact that we've got some DUCs that we are currently completing and we plan on starting up a rig in the Q4, but that's not going to be fully enough activity to offset the decline. So from a unit cost perspective, you may have some increase in LOE, but from a total dollar number, we're still working on decreases.
Right. Okay. Thanks. And most of my other questions were answered, so appreciate
it. Great. Thanks, Don.
At this time, we have no further questions. This does conclude today's conference call. You may disconnect at this time.