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Cimarex Energy Co (XEC)
Q3Â 2020 Earnings Call
Nov 5, 2020, 11:00 a.m. ET
Contents:
- Prepared Remarks
- Questions and Answers
- Call Participants
Prepared Remarks:
Operator
Good morning, and welcome to the Cimarex Third Quarter 2020 Earnings Conference Call. [Operator Instructions]
I would now like to turn the conference over to Karen Acierno. Please go ahead.
Karen Acierno -- Vice President of Investor Relations
Good morning, everyone, and welcome to our third quarter 2020 earnings conference call. An updated presentation was posted to our website yesterday afternoon. We may reference that presentation on our call today. Just a reminder, our discussion will contain forward-looking statements. A number of actions could cause actual results to differ materially from what we discussed. You should read our disclosures on forward-looking statements in our news release and in our latest 10-Q, which was filed yesterday, for the risk factors associated with our business. So our prepared remarks today will begin with an overview from our CEO, Tom Jorden, followed by a few comments from Cimarex SVP and CFO, Mark Burford; Blake Sirgo, VP of Operations, will then provide a brief operational cost update. [Operator Instructions]
So with that, I'll turn the call over to Tom.
Thomas E. Jorden -- President and Chief Executive Officer
Thank you, Karen, and thank you to all who are joining us this morning. I'll briefly discuss our financial and operating results for Q3, our go-forward outlook and update you on the ongoing prgress we're making on ESG issues. I'll finish with our perspective on the changing landscape of mergers and acquisitions and their impact on Cimarex's future. First, a brief recap of our financial and operational results. We had a very good third quarter in the midst of the most challenging macro environment in our company's history. Our oil production averaged 71,600 barrels per day, which was in line with our guidance. Our total production averaged 249,000 barrels of oil equivalent per day at the high end of our guidance. We generated $139 million of free cash after our dividend and finished the quarter with $273 million cash on hand. We are on track to finish the year having generated well over $200 million of free cash flow after our dividend with an excess of $300 million cash on hand at year-end. Given the year we face, this is an extraordinary achievement and reflects the adaptability, determination and grit of our organization. We expect our total 2020 capex to be within our revised guidance of $600 million. As if any of us needed a reminder of how the year has changed, let me remind you that our initial capital guidance for 2020 was $1.25 billion to $1.35 billion. The word volatility seems inadequate to describe the market conditions we faced in 2020. We are looking forward to New Year's eve and putting 2020 behind us. We continue to achieve meaningful cost reductions in all categories, including capex, LOE and G&A. Blake and Mark will comment on our cost reductions as well as the operational and organizational improvements that will allow us to sustain many of these cost reductions. We are a better company owing to the challenges we have faced in 2020. As we look ahead into 2021 and beyond, we are highly confident that we can sustain our top-tier financial and organizational results. With our fourth quarter completion cadence, we will have significant momentum as we enter Q1 2021.
Although we have not finalized 2021 full year guidance, we do look into the first quarter and expect high single-digit oil volume growth over Q4 2020. We will enter 2021 very well-positioned. Financial performance has little meaning if it's not sustainable. The sustainability of our financial performance is underpinned by our asset quality and ability to continuously improve our cost structure, margins and capital efficiency. Slide six illustrates the ongoing progress we are making in lowering our cash expenses per BOE. Mark will cover this in more detail. Slides 10 and 11 speak to our asset quality, and the steps we have recently taken to improve our capital efficiency. We have a deep inventory of high-quality locations that will drive our performance over time. At a $40 oil price, we have more than a 20-year inventory of locations that generate greater than 1.5 PVI 10. We guide our investment decisions through a dual lens that considers both rate of return and PVI 10. This 20-year inventory does not fully capture the new landing zones that we're testing and delineating, these results will further backstop our ability to sustain and potentially improve our financial performance. We look forward to discussing these exciting results with you in the future. Now a few comments on the tremendous progress we have made on the environmental front. This year, we adopted aggressive corporate goals to reduce our methane intensity and reduce flaring. Thus far, our organization has crushed these goals. Our target for methane intensity, defined as volume of fugitive methane divided by gross operated gas production, was an intensity rate target of 0.245%. We are on track to achieve a 2020 methane intensity rate of 0.200%. On to flaring. In 2019, we flared 1.9% of our Permian gas production. Our stretch goal for 2020 was 0.96% of Permian flaring, a 50% reduction from 2019. We are on track to achieve a 2020 Permian flare rate of 0.95%. How have we done this? The answer is simple; organizational focus and commitment, creative engineering, smart use of data analytics and adoption of emerging innovative technology.
Slide 13 highlights some of the technology we have deployed, which includes ongoing aerial surveillance, an amazingly effective ground-based radar technology and the adoption of true tankless facility design. We have also adopted an aggressive optical gas imaging inspection regimen that far exceeds federal and state requirements. Regardless of the outcome of the presidential contest, our industry will face increasing challenges in winning back our investors through consistent financial results and delivering our products with a low-carbon production footprint. Going forward, we may face a more difficult regulatory framework and will certainly face more stringent reporting requirements. Cimarex is ready for the challenge, and we look forward to continuing our momentum into 2021 and beyond. Finally, let me comment on the recent rash of mergers and acquisitions within our sector. Each of the announced deals is unique in its own right and stands alone on its prospective merits. We do not offer an opinion on any particular transaction. I would, however, like to comment on the viewpoint that scale is essential for success and that consolidation is inevitable. As we grade Cimarex's performance, whether it be financial, operational or environmental, we grade Cimarex on our ability to be excellent on all fronts. We are committed to be top tier on every meaningful metric, and we will not use size as an excuse for subpar performance, period. We will compete with all companies in our sector, big and small. We will be measured by the excellence of our results, not our scale. Cimarex has consistently delivered top-tier financial results. We are an organization that has demonstrated operational excellence, has a history and a passion for continuous improvement, and we have assets that can support our aggressive goals over time. We can and will be an industry leader on ESG issues. We have a terrific balance sheet and the wherewithal and discipline to preserve it and improve it. We offer the investors significant exposure to upside in oil, gas and natural gas liquid prices. With a few of our peers now gone, Cimarex is uniquely positioned within our market cap range to offer quality, repeatability and sustainability.
Any suggestion that we are not investable is simply nonsense. To be fair, there are parts of our business where scale is important. Lowering operating costs through proper management of midstream infrastructure is one; significant continuity of acreage for long lateral development and not fromproject size is another. As we pivot to resource harvest mode, the scale and development projects can have a significant impact on the ability to capture the lowest per unit cost structure. This is particularly true in the ability to take full advantage of the savings offered by simul fracs, facility optimization and the long-term benefits of electrification. Our current program has sufficient scale to capture the overwhelming majority of these efficiencies. Additionally, throughout our history, we have chosen to further leverage our scale by entering into smart joint ventures with outstanding partners. Our joint development agreement with Chevron and Culberson County is one such example. As we go forward, we will explore similar opportunities, preserve our nimbleness and capitalize on smartly crafted relationships. If the size of the company were the controlling variable for success, multinational majors would dominate U.S. resource plays. Our focus is on excellence, not size. Our goal has always been to build a great company. If our Board of Directors were to become convinced that we could build a better company through a merger, we would jump at the opportunity. But make no mistake about it, Cimarex is not one of the last kids on the playground waiting to be picked for a team. We have had many opportunities to merge, but we remain independent because our Board has determined that independence is the best strategic choice at this time. As we go forward, we will consider any option that furthers our goal of building a great company and builds value for our shareholders. I cannot recall a time in my life, and there were so many people around me telling me exactly what the future will look like. They have been wrong before, and they will be wrong now. Cimarex has the capability and flexibility to deal with an uncertain future. Until then, we will show up each and every day and compete.
With that, I'll turn the call over to Mark for a rundown on our financial progress.
Mark Burford -- Senior Vice President and Chief Financial Officer
Thank you, Tom. Good morning, everyone. I'll provide some details on our third quarter financial results and outlook. Our total cash operating costs comprised of LOE, transportation, production taxes and G&A, and the third quarter totaled $7.26 per BOE. We project our total cash operating cost per unit to decrease approximately 13% in 2020 as compared to the 2018 and 2019 average. Year-to-date total 2020 G&A expense included severance cost of $31 million from staff reductions to align the organization to the prevailing macro environment and expected lower activity levels. On a per unit basis, severance in 2020 is adding approximately $0.34 per BOE to our cost. On a go-forward basis, these adjustments result in reducing future cash overhead expenditures by $40 million to $50 million. Adjusted cash flow from operations for the first nine months of 2020 totaled $688 million, and we generated $182 million of free cash flow after the dividend. In the third quarter, we had $139 million of free cash flow after dividend, of which we received cash settlements of $14 million this quarter from our hedges. And year-to-date, we received $121 million. We exited third quarter with $273 million in cash on hand and no borrowings on our $1.25 billion revolving credit facility. This quarter, we also added a Fitch rating, at a corporate family rating, at BBB and a stable outlook. S&P retained their BBB minus rating and now had us at a stable outlook, and Moody remains at BAA three with a stable outlook. Our projected 2020 capital remains unchanged at $600 million. We now expect to have 15.5 net wells brought on in the fourth quarter. This is about 5.5 wells from our previous forecast as a result of operational efficiencies, which brought well forward from January 2021 by one to two weeks, which are now projected to come on at the very end of 2020. Fourth quarter 2020 production volumes are expected to average 215,000 to 235,000 barrels equivalent per day, with oil volumes expected to average 62,500 to 68,500 barrels of oil per day. We have strong momentum heading into '21, with the assumption of drilling and completion activity. With our strong underlying asset base and cost structure, we are in a great position to generate free cash flow in excess of our growing dividend at $35 WTI oil and $250 Henry Hub gas. The flat to modestly increasing production. At higher prices, we expect to significantly have higher free cash flow with a clear goal of having more than sufficient funds to retire $750 million 2024 notes, which is our nearest maturity.
With that, I'll turn the call over to Blake.
Blake Sirgo -- Vice President of Operations
Thanks, Mark. The third quarter marked our return to activity with four rigs and two frac crews now running in the Permian. Structural changes and incremental operational efficiencies have caused our costs to continue to decline. We expect this trend to continue. While market rates for services are leveling out, we are seeing continued cost reductions driven by efficiency gains in our operations. As such, our go-forward D&C cost per lateral foot has decreased from $800 to $900 per foot to $800 to $850 per foot. To provide some detail, our year-to-date 2020 average drilling feet per day is up 31% from 2019 levels, a result of increased pad drilling and offline cementing. A great example of this is our count fleet development in Culberson County, where a new 2-mile Wolfcamp A well drilled to TD in 10.3 days, a new company record. Improvement continues on the completion side as well with our 2020 year-to-date average completed feet per day of 21% from our 2019 average. When we combine these D&C efficiencies with additional operational cost savings, such as co mingling surface facilities and reducing flowback costs, the result pushes total cost per lateral foot to the low end of the go-forward range across all programs. As always, when we report $1 per foot, we are including all capital costs associated to bring that well online, including drilling, completion, facilities and flowback. Q3 lifting costs came in at $2.70 per BOE, which is down 20% from Q3 2019 and down 22% from Q1 2020 before the pandemic hit. We estimate 65% of these LOE reductions since Q1 2020 are structural and will be sustained. These structural changes include reductions in contract labor, implementation of new maintenance programs and field efficiencies gained through automation. Our cost structure is a critical component to ensuring Cimarex delivers strong free cash flow, and our ops teams are up to the challenge. We are pushing efficiencies and innovating across our entire value chain, which will continue to drive down our costs as we move forward.
With that, we'll turn it over for questions.
Questions and Answers:
Operator
[Operator Instructions] Our first question comes from Arun Jayaram of JPMorgan. Please proceed
Arun Jayaram -- JPMorgan -- Analyst
Good morning, Tom & Team, was wondering if you could elaborate on the inventory comment that you mentioned in your prepared remarks. I think I heard you said you had 20 years of inventory, call it as a 1.5 times PVI ratio. So is that just assuming flattish activity, but maybe give us a little bit more meat on the bone in terms of what you've done here to estimate your go-forward inventory?
Thomas E. Jorden -- President and Chief Executive Officer
Good morning, Arun, I appreciate that question. What I should have said that 20 years is at a current investment rate. Obviously, as investment rate increases, inventory decreases, but that's also -- we -- I said in my remarks, we use a combination of rate of return and PVI 10 and that's kind of a new language that you've heard us externally speak. We started emphasizing PVI 10 about 1.5 years ago, in addition to rate of return. If I were to speak loosely on rate of return, that is an inventory at $40 oil that generates, give or take, a 50% IRR or better. If we lower -- if our cost structure changes or we look at lower rates of return, certainly, our inventory increases, but that's kind of where we decide to draw the line to communicate it externally. That is, though, in direct answer to your question, that's at our current investment rate and that does not include additional adds that some of our new landing zones are developing, but we view those as high grading rather than necessarily extending, but that -- hopefully, I've answered your question.
Mark Burford -- Senior Vice President and Chief Financial Officer
Just to clarify to you, that price deck you used, the PVI 10 was a result using a $35 to $40 price deck, too. So the PVI 10 cut off of 1.5 is that using a $35 to $40 price deck at $250 gas and 40% NGLs is the price deck we used for that cutoff.
Arun Jayaram -- JPMorgan -- Analyst
Got it. Got it. My follow-up is I wanted to see Tom and team, if you could talk about slide 11, you had been for pretty clear about plans to relax spacing, and I wanted to see if you could give us some thoughts on the count fleet development And a couple of thoughts that come to our mind is it looks like you're now looking to land the lateral in the XY zone versus before just a little bit below that, again, in the Upper Wolfcamp, and you are using wider spacing. So maybe talk about some of the learnings and some of the implications to well productivity on a go-forward basis?
Thomas E. Jorden -- President and Chief Executive Officer
No, thank you for that follow up, Arun. Referring to slide 11. It's one petroleum system, and the critical question that we ask ourselves is, are there frac barriers or our hydraulic fracture networks freely passing from one stratigraphic zone to another. And then the upper Wolfcamp and that XY, that is one petroleum system. So what you see there is we've added a few landing zones, move them up to the XY that gives us a little more vertical separation, but this is really just an outcome of a lot of years of collecting data. What we've observed is that we did see -- we talked about this in past calls, the last call, in particular, that our 2019 program really did observe quite a bit of well interference in that Upper Wolfcamp. The upper Wolfcamp and which includes the XY, is a highly permeable rock system compared to others and so the drainage is well beyond the fracture tip. And that was a big learning for us in 2019. And as we experimented, we found that we can drill fewer wells and have very modest impact on complete recovery out of that section. And so in the case you have in front of you, we're spending 30% less capital on wells. I mean, that doesn't include facilities. So I'm doing a little bit of arm waving there, but 30% less capital and generating more net present value, the relax spacing not only is more capital efficient, it actually creates more value than the higher spacing. And that's something Cimarex has learned. I think it's something that the industry either has learned or is learning that you really have to look at those incremental wells and not just the total project rate of return because the total project rate of return is going to look great on both the left and right side of that slide. It's if you go from well seven through 10, was that incremental capital well-invested or should you've taken that capital and put in a different project, and that's the lesson we've learned, and that's the point of slide 11.
Arun Jayaram -- JPMorgan -- Analyst
Okay. Thanks a lot.
Operator
And our next question comes from Gabe Daoud of Cowen. [Operator Instructions] Please proceed.
Gabe Daoud -- Cowen -- Analyst
Good morning, everyone. I appreciate all the prepared remarks so far. Tom, I guess for 2021, your expectation of flat to slightly up oil volumes on similar capex. Are there any further capital efficiency improvements embedded in that outlook, whether on the cost side or perhaps on the productivity side, particularly as your relaxing spacing in the Wolfcamp, as you noted?
Thomas E. Jorden -- President and Chief Executive Officer
No, we model where we are today. So we generally, as we go forward, we don't project what we haven't achieved. So that said, current -- what we're seeing is current capital efficiency and current costs, but Mark, I'm going to invite you to comment on that?
Mark Burford -- Senior Vice President and Chief Financial Officer
No, that's correct, Tom. And we're using our current leading edge costs that we would be looking at into '21, Gabe. And then further on the efficiencies on productivity, we are -- as we discussed, as Tom discussed, with the relaxed spacing, we do have all those sort of measures built into our forecast as well.
Gabe Daoud -- Cowen -- Analyst
Thanks. That's helpful. Then I guess just as a follow-up, you guys had kind of noted that through 2024, you'll use free cash flow to pay down debt, and particularly the 2024 notes. And I guess, on our numbers, as we look through to 2024, it would appear that free cash flow generation post the dividend would be more than enough to cover the '24 notes while also still growing the dividend? And Mark, I guess, in your prepared remarks, you did characterize the dividend as growing. So I guess, the question is, should we anticipate annual increases in the dividend through 2024? And I guess, to what extent would the magnitude look like? Thank you.
Mark Burford -- Senior Vice President and Chief Financial Officer
Sure, Gabe. Yes, we do have expectations to grow our regular dividend. We're going to make sure that growth, that dividend is very manageable. So we're looking at a measure of it relative to our cash flow at flat price cases as well and probably target something in the -- around 10% of our cash flow for our regular dividend and to the extent we have free cash flow publicly on that, Gabe, that we'll have to make decisions on that. We're discussing with the Board with variable dividends and other options. But again, the first priorities right now are our debt repayment and making sure we have sufficient cash there. And then secondly, again, that some measured growth in our regular dividend, make sure it's very sustainable.
Gabe Daoud -- Cowen -- Analyst
Awesome. Thanks, Mark. Thanks, Gabe.
Operator
And our next question is going to come from Jeanine Wai of Barclays. Jeanine, please proceed.
Jeanine Wai -- Barclays -- Analyst
Hi, good morning. This is Jeanine Wai. My first question is for you, Tom. Maybe if we could go back to your comments on size, and you mentioned that Cimarex is capturing the overwhelming majority of efficiencies at your current scale, but that you're open to exploring opportunities to partner in order to capture maybe additional efficiencies on top of that. So I just wanted to kind of dig into that comment a little bit. Is that more related on the opportunity side to things on the midstream? Or is that more of a -- is there more opportunity to capture additional efficiencies on the upstream side?
Thomas E. Jorden -- President and Chief Executive Officer
Well, yes. Jeanine, I'll use the Chevron joint development agreement in Culberson County as a good example. There we can share in midstream costs, gathering and compression. And our operating costs are, I think, basin leading low because of the efficiency of our midstream there and our ability to optimize that midstream and that flows into a whole set of good outcomes, not only cost, but our flaring is also very, very low in Culberson County because we control our own destiny at every point of that value chain. Saltwater disposal is another very important benefit where we've built our own saltwater disposal network. And not only does that allow us tremendous flexibility and savings and disposal, but it also has introduced tremendous cost savings on water sourcing because we use at times, 100% of our water for recycling. It also is just absolute project size because we're partnered with an outstanding partner and we're 50-50. The projects are bigger, and we can have longer laterals. We can take advantage of zipper fracs. We haven't moved to some fraction in Culberson County yet, but I think we may. And then something else that's coming here in the fourth quarter that we haven't talked about publicly, but I'll mention now, is we have a real push on electrification. And we'll be experimenting with something that we think is really important, and that's an electric frac crew that's taking power off our owned and operated electric grid and that's the smart way to do this. Towing a turbine around on dirt roads is a really bad idea. And we have some of our own experience that tells us why it's a bad idea. It's much more elegant solution if you can get that electrical crew or electrical drilling rig to take power from your own electrical grid. So these are all things that add up. Some of them are big-ticket items, some of them are small items, but they are benefits of scale. And we think there are other opportunities in the basin to replicate what we've done in Culberson County.
Jeanine Wai -- Barclays -- Analyst
Okay. Great. Thank you. And then maybe a little more detailed question, if I may. Cimarex continues to pull forward wells given good efficiencies. Previously, I think the commentary was that given the lag and timing and all of that production would start to turn and grow in December. So we just wanted to check in to see if that's still the new case given the new completion schedule? And maybe if you had any comments on the exit rate, that might be helpful for us to frame the growth in Q1?
Mark Burford -- Senior Vice President and Chief Financial Officer
Yes, Janine, yes, we have some additional wells that are moving up from '21 into the last part of 2020 with 5.5 net wells, but those are coming on very end of the year, which does position us well into the first quarter. And as Tom stated, in the first quarter, we do see our oil volumes growing at high single digits, so into the first quarter.
Jeanine Wai -- Barclays -- Analyst
Okay. Thank you very much.
Operator
Our next question is going to come from Neal Dingmann of SunTrust Securities.
Neal Dingmann -- SunTrust Securities -- Analyst
Tom, could you and John, maybe talk about how you just see the baseline decline progressing? It seems to me you're holding production quite nice with limited activity. So just wondering your thoughts there?
Thomas E. Jorden -- President and Chief Executive Officer
Well, base decline is always a hurdle to overcome. And then we do have a very young, profitable asset base, and that does lead to decline. But Mark, why don't you handle the detail there?
Mark Burford -- Senior Vice President and Chief Financial Officer
Yes, sure, Neal. That is obviously something we are challenged. Our production teams are always challenged to make sure we're doing everything we can to defend the base, as we call it, with operational activities to maintain that base, but that is something every E&P faces in trying to maintain that base production.
Neal Dingmann -- SunTrust Securities -- Analyst
Okay. And then just one follow-up on the prior call, you had talked about likely. I think it was sometime in early, potentially, '21, getting a bit more active on operated Anadarko activity. Could you talk about your thoughts returning to that play more on the operational side?
Thomas E. Jorden -- President and Chief Executive Officer
Well, we're still looking at our 2021 program. We haven't finalized it, but we're kind of where we were last quarter. We do have a project or two on that oily room in the Anadarko based on some wells that we brought online, over the last year, 1.5 years. We have outstanding returns on those wells. I mean they really -- if we choose to do this Anadarko project, which I believe we will, it's -- if we rank our opportunities companywide, it's top 10. I mean it really competes with Delaware Basin on all measures. We like the project. We like the returns, but I'll just say we're right where we've been in the past. We're talking about something that the high side would be 10% or 15% of our capital. And again, I wave my arms when I say that because we're still finalizing 2021 capital. It will be a small program, but it competes on all measures, heads up.
Neal Dingmann -- SunTrust Securities -- Analyst
Very good. Thanks, Tom. Thanks, Mark.
Operator
Our next question comes from Josh Silverstein of Wolfe Research. Josh, please proceed.
Josh Silverstein -- Wolfe Research -- Analyst
Yes,thanks. Good morning. Tom, I appreciate the comments on M&A. It sounds like you've been involved in multiple conversations recently. I just want to see if those were both on the divestiture and the potentially the acquisition side. And what is the main pushback from the Board? You said right now, is that not the right time, just because of where the stock price is or just the right combination that it doesn't make sense to do a deal?
Thomas E. Jorden -- President and Chief Executive Officer
Well, I'm going to restate your question, Neil. Look, we've said in the past, and I'll say again now, there have been lots of conversations going on throughout 2020, CEO and CEO phone calls, and that comes as no surprise to anybody. And so yes, we've had opportunity to have conversations, and we've looked at both sides of it. We've looked at mergers, we've looked at an opportunity to acquire, but the big restatement, I'll make is you said, pushback from the Board. Our Board is highly focused on creating value over the long haul. Our Board is also very aligned with the executive team in having a long-term framework and viewing things through a patient lens. And there's been some good commentary on this through some calls, and you pay attention to them as we do. We're in a cyclic business. And I think that we need to be very, very careful making decisions in the downside of the cycle. Now I don't -- that doesn't mean it's a bad idea and careful doesn't mean don't do it, but careful means careful. I'll come back to what I said in my closing, everybody thinks they know what the future looks like. And yet, there are some very constructive voices out there that think that natural gas and oil prices are well poised for a rebound. We haven't slammed any doors. And I want to be clear on that. Our -- we have tremendous flexibility for any option available to us, but our Board has decided for now, given what we have considered that our current position is right where we want to be. Mark, do you want to add anything to that?
Mark Burford -- Senior Vice President and Chief Financial Officer
Yes. No, I don't think there's much I could add, Tom. It just comes down the value proposition. Our Board is recognizing looking out for the best things our shareholders. And if we can make a better company and create more value through something like that, management and the Board be very -- pursue that very hard. Right now, with our asset base and the quality of our balance sheet and the exposure we have on a go-forward basis at the current point, we think we can create more value for our shareholders as a stand-alone. But that again, as Tom said, we continue to be monitoring what's the best company we can build.
Josh Silverstein -- Wolfe Research -- Analyst
Got it. I appreciate those comments there and clarifications. Second question I just wanted to ask was the 50 wells planned through 2023 on federal acreage, it kind of nicely lines up with the 50 permits that are either approved or in progress. I'm just curious on the development plan, do you guys intend to actually speed up the development? Or is it actually kind of even around 10 wells over the next five years, given the current backlog and permits that you have?
Thomas E. Jorden -- President and Chief Executive Officer
Well, we have -- we've talked about the 50 or so permits over the next few years. We actually hold -- we think by year-end, we're going to have 168 permits, and we do have the ability to accelerate. We've recently been looking at an acceleration plan that would give us the opportunity to bring a lot of New Mexico value forward. But right now, we're going to watch and wait. I'm hopeful that New Mexico development is going to be proceeding a pace, but we are ready. If we decide we want to accelerate, we would redirect capital to New Mexico, and we have the projects lined up, we have the permits and there are great opportunities.
Josh Silverstein -- Wolfe Research -- Analyst
Okay. Thanks, Tom.
Thomas E. Jorden -- President and Chief Executive Officer
Sure.
Operator
[Operator Instructions] Our next question comes from John Abbott of Bank of America. John, please proceed.
John Abbott -- Bank of America -- Analyst
Good morning. I'm on for Doug Leggate this morning. I just wanted to go back to the commentary around the 20-year inventory. I just want to make sure that I get clarification. Is that all Permian or does that include some Anadarko? And then how does that sort of change -- you talked around $35 to $45, the inventory sounds like it's based at $40. What is the impact of oil prices, it's $5 lower as far as the extent of that inventory? Is it reduced by maybe a quarter? How should we think about that?
Thomas E. Jorden -- President and Chief Executive Officer
Well, I can tell you exactly. At $35, $250 gas price, it's about a 15-year at 1.5 PVI 10, and it goes to $20 at a $40 oil price. It includes Anadarko and Permian, although it's overwhelmingly driven by the Permian. That's -- and again, that has a very high economic cutoff. 1.5 PVI 10 is a fairly steep cutoff. If we lower our cutoff, it just adds to that. And again, I don't want to communicate how we see inventory incorrectly. We see inventory is giving us tremendous flexibility for near year financial returns. A deep inventory means a deep flexibility to high grade. And so we really like to have a deep inventory because that means we have a high degree of confidence that over the next three- to five-year window, we can achieve outstanding financial returns.
John Abbott -- Bank of America -- Analyst
I appreciate it. And then just for the follow-up question here. It's going to be on the Mid-Con. Going back to the commentary that you could spend potentially 10% to 50% of your budget next year, and that's sort of loan rock area. You've increased your spacing of wells in the Permian, you've made progress on costs in the Permian. If you did go back to the Mid-Con, you went to loan rock area, I mean, should we be thinking that spacing would increase? And also, what do you think is the ability to drive down cost lower than per lateral foot?
Thomas E. Jorden -- President and Chief Executive Officer
Well, that's a very active -- the spacing question in the Anadarko is a very active debate internally. I will say that based on our data, we don't think we need to relax spacing in Anadarko. We -- again, I said in the Permian, the challenge is that we're draining a reservoir well beyond our fracture tip. That's typically not the case in the Anadarko, particularly I'm speaking about Woodford Shale. In the Woodford shale, your drainage area is more or less, at least in the early economic life of the well, it's combined to your -- it's restricted to your fracture area. So we've not seen the degree of notable interference in Anadarko that we experienced in that Upper Wolfcamp. That said, there's a little bit of better be safe than sorry floating around here. So I suspect that we may relax our spacing in the Anadarko likely. I mean, not to the degree to which we talked about in the Upper Wolfcamp, but we -- I would expect we're probably going to relax it very modestly.
John Abbott -- Bank of America -- Analyst
Thank you very much.
Operator
[Operator Instructions] I do not see any further questions at this time. This concludes the question-and-answer session. I would now like to turn the conference back over to management for any closing remarks.
Thomas E. Jorden -- President and Chief Executive Officer
Well, thank you all for your questions this morning. Really look forward to getting back to work, getting back to a serious momentum. Hopefully, we've been clear with what we can and will deliver. And hopefully, we've been very clear with you that we have tremendous flexibility on all fronts. So thank you for your questions, and I'll wish you a happy New Year now. Thank you.
Mark Burford -- Senior Vice President and Chief Financial Officer
Thank you, everyone.
Operator
[Operator Closing Remarks]
Duration: 43 minutes
Call participants:
Karen Acierno -- Vice President of Investor Relations
Thomas E. Jorden -- President and Chief Executive Officer
Mark Burford -- Senior Vice President and Chief Financial Officer
Blake Sirgo -- Vice President of Operations
Arun Jayaram -- JPMorgan -- Analyst
Gabe Daoud -- Cowen -- Analyst
Jeanine Wai -- Barclays -- Analyst
Neal Dingmann -- SunTrust Securities -- Analyst
Josh Silverstein -- Wolfe Research -- Analyst
John Abbott -- Bank of America -- Analyst
