APA Corporation (APA) — Q3 2021 Earnings Call Transcript

Good morning. And thank you for joining us on APA Corporation Third Quarter 2021 Financial and Operational Results Conference Call. We will begin the call with an overview by CEO and President John Christmann. Steve Riney, Executive Vice President and CFO, will then provide further color on our results and 2021 outlook. Also on the call and available to answer questions are Dave Pursell, Executive Vice President of Development. Tracy Henderson, Senior Vice President of Exploration, and Clay Bretches, Executive Vice President of Operations. Our prepared remarks will be approximately 18 minutes in length, with the remainder of the hour allotted for Q&A. In conjunction with yesterday's press release, I hope you've had the opportunity to review our 3rd quarter financial and operational supplement, which can be found on our Investor Relations website. Please note that we may discuss certain non-GAAP financial measures. A reconciliation of the differences between these non-GAAP financial measures and the most directly comparable GAAP financial measures can be found in the supplemental information provided on our website. Consistent with previous reporting practices, adjusted production numbers cited in today's call are adjusted to exclude non-controlling interest in Egypt and Egypt tax barrels. Finally, I would like to remind everyone that today's discussion will contain forward-looking estimates and assumptions based on our current views and reasonable expectations. However, a number of factors could cause actual results to differ materially from what we discussed today. A full disclaimer is located with the supplemental information on our website. And with that, I will turn the call over to John.

Good morning and thank you for joining us. Our top priority coming into 2021 was to continue strengthening the balance sheet through debt reduction. With the significant recent strides in that regard and a favorable outlook for continued free cash flow generation, we are in a position today to announce some material changes to our capital investment plans and use of free cash flow. First, we're moving toward a capital budget that will sustain or slightly grow global production volumes. This is being accomplished through a gradual ramp in activity over the next few quarters primarily in Egypt where we are anticipating PSC modernization terms will be approved by year-end, but also in the onshore U.S. Second, we're committing to a significant increase in cash return to shareholders. While a stronger commodity price environment has accelerated progress on the balance sheet, it is the quality and cash flow generating capacity of our core operating areas that are enabling our new capital return framework. We have a substantial inventory of quality drilling opportunities throughout our portfolio. In addition to Egypt, which now has the deepest inventory in more than a decade, we also have significant potential in our onshore U.S. portfolio, primarily in the Southern Midland Basin, Alpine High, and Austin Chalk. In this price environment, there are many compelling drilling opportunities that should be funded and we anticipate adding a fourth onshore U.S. rig in 2022. With regard to our new capital return framework, we are committed to returning a minimum of 60% of our free cash flow to shareholders. This begins with our base dividend, which in September we announced would increase to an annualized rate of $0.25 per share. Yesterday, we announced a doubling of that rate to $0.50 per share. In early October, we took the more significant step of initiating a share repurchase program. Through October 31st, we have repurchased 14.7 million shares and expect to continue returning capital in this manner through the Fourth Quarter and into 2022. Our commitment is to return at least 60% of free cash flow to shareholders and we will exceed this amount in the current quarter. We believe that APA currently offers one of the highest free cash flow yields in our peer group, and that this framework could deliver us an attractive and highly competitive return to our shareholders. Turning now to the third quarter results highlights. Through a combination of strong commodity prices, capital and cost discipline and good well performance, we generated nearly $1.2 billion of adjusted EBITDA, making it our strongest quarter of the year thus far. We anticipate the fourth quarter will be even stronger. U.S. production exceeded guidance in the third quarter and we continue to see good performance in the Permian oil plays, Alpine High, and the Austin Chalk. Internationally, production was a bit below guidance as we experienced some extended maintenance turnarounds and compressor outages in the North Sea and lower volumes in Egypt associated with the impact of strengthening oil prices on our production sharing contracts. We expect gross production in both the UK and Egypt will increase in the fourth quarter. In the U.S. we placed a total of 10 wells online during the quarter. This included 9 wells in the Southern Midland Basin, 3 of which were 3 miles in length. At Alpine High, no new wells were placed on production during the quarter. But performance from this year's DUC completions, as well as the underlying base production volumes continue to exceed expectations. In the East Texas Austin Chalk, we drilled three operated wells earlier this year, two of which are on production. We've recently added a third rig in the U.S., which will be used to continue the delineation of our Austin Chalk acreage position. We have now gathered a substantial amount of data in this play that indicates returns will compete with other quality portfolio opportunities. Turning to international operations. In Egypt, gross production has begun to turn higher, putting us on a good trajectory as we enter 2022. In anticipation of modernized PSC terms, we recently increased our rig count to 11. We will likely add more rigs in 2022 as modernized terms would return Egypt to being the most attractive investment opportunity within our portfolio. In the North Sea, we continue to operate 1 floating rig in 1 platform crude. As expected, production was up modestly in the third quarter compared to the second quarter as we continued to work through both planned and unplanned maintenance downtime. On the drilling front, we recently TD'd the store to development well, which we plan to place online in January. While one of the primary objectives in this well was wet, we encountered more than 300 feet of net pay and other targets, which we're projecting will IP around 20 million cubic feet per day of gas and 2500 barrels per day of condensate. Our 59% working interest in this well provides good leverage to what should be robust North Sea natural gas and condensate prices over the coming months. In Block 58 offshore Suriname, our partner Total is currently running 2 rigs, one of which is conducting a flow test at Sahakara Sal and the other is drilling the Bond Bonnie exploration well in the Northern portion of the block. These operations are still ongoing and the data we collect will help inform the next steps in the Block 58 appraisal and exploration programs. On Block 53, we are finalizing plans for our next exploration well location with partners Petronas and Septa. The Noble Jerry D'Souza drillship is scheduled to commence drilling this well in the first quarter. The plan is to drill one well in Block 53 in 2022, but we have an option on the drillship for two additional wells if warranted. Before closing, I want to comment on the charge we took this quarter related to the Gulf of Mexico properties we sold to Fieldwood in 2013. Since Fieldwood emerged from bankruptcy in August, we have independently assessed the situation and have elected to book the contingent liability that you saw in our press release. In closing, I'd like to make a few remarks about the progress we're making on the ESG front. We recently announced that we have eliminated all routine flaring in U.S. operations. This was an ambitious goal that we set at the beginning of the year and achieved 3 months ahead of schedule. Additionally, through the end of the third quarter, flaring intensity in the U.S. was only 0.38%, significantly below our target of less than 1%. Our global safety performance has also been strong. We have delivered a 35% improvement in our total recordable incident rate compared to this time last year. We have also progressed a number of important initiatives that foster diversity and inclusion within the organization and that enhance the health and well-being of our employees. In October, we published our 2021 sustainability report, which I hope you will review for a more in-depth look at our ESG philosophy, performance, initiatives, and success stories. Finally, we are in the process of establishing some very rigorous short, medium and long-term ESG goals, which will include further efforts on GHG and methane emissions and we look forward to discussing these in the near future. And with that, I will turn the call over to Steve Riney, who will provide additional details on our third quarter results and outlook.

Thank you, John. In my prepared remarks this morning, I will make some additional comments on our third quarter performance, provide a bit more color on the field-related contingent liability, review aspects of our midstream's recently announced combination with EagleClaw and provide some more context around our free cash flow outlook and capital framework. As noted in our news release yesterday, under Generally Accepted Accounting Principles, APA Corporation reported a third quarter 2021 consolidated loss of $113 million or $0.30 per diluted common share. These results include a number of items that are outside of core earnings, excluding the impacts of the Fieldwood related contingent liability, a loss on extinguishment of debt, a charge for tax-related valuation allowance, and some other smaller items, adjusted net income for the third quarter was $372 million or $0.98 per share. Most of our financial results were in line with or better than guidance this quarter. Upstream capital investment was considerably below guidance, primarily due to the timing of infrastructure spending in Egypt and lower exploration costs in Suriname. Our teams have done a good job holding the line on capital and LOE despite service cost inflation. And we expect these will finish the year at or below our original 2021 guidance. G&A was also below guidance this quarter, mostly due to the timing of some costs which we now expect to be incurred in the fourth quarter. I would like to provide a bit more color now on the Fieldwood ARO situation. Through Fieldwood's most recent bankruptcy process, we had to rely on third-party estimates of the remaining net abandonment obligations related to our legacy properties. Since Fieldwood emerged from bankruptcy in August, we have conducted our own evaluations. Based on that work, it appears the combination of the various financial security packages and the anticipated future net cash flows from the properties will not be sufficient to fund all of the remaining abandonment obligations. Accounting rules require that the entire undiscounted contingent obligation and the offsetting undiscounted value of the financial security will be brought onto our books. These are recorded independently as a liability and an asset without netting them against one another. Accordingly, in the third quarter, we brought onto our books the anticipated net ARO obligation of $1.2 billion. We also recorded the offsetting value of the financial security in the amount of $740 million. As a reminder, the financial security includes a funded abandonment trust, letters of credit, and surety bonds. As abandonment activity occurs, it will be funded first by the free cash flows currently being generated by the legacy properties. To the extent these cash flows are insufficient, Apache Corporation will be required to fund the activity and will be reimbursed through the financial security. Only after the operating cash flows and financial security packages are fully depleted, will Apache Corporation be obligated to fund the activity without a source of reimbursement. The undiscounted net liability is $446 million and we anticipate it will be at least 2026 before Apache incurs costs in excess of the available financial security. A few weeks ago, our majority-owned midstream company, Altus, announced that it will combine with the parent company of EagleClaw Midstream, to form the largest integrated midstream company in the Delaware Basin. We considered a wide range of strategic options for Altus for more than a year. Ultimately, we determined that this transaction would allow all Altus shareholders to reposition equity holdings into a pro forma company with the best combination of scale, synergies, asset quality, and attractive growth opportunities. The transaction would also preserve the $6 per share annual cash dividend for the public shareholders and provide near-term optionality for APA to monetize a meaningful portion of our current position. Such a secondary sale would benefit the combined company by improving the public float. It would also provide APA with cash flow, a portion of which would be deployed into Alpine High activity, thereby enhancing dedicated sources of revenue for the company. Reducing our ownership interest in Altus to a minority position provides a number of benefits for APA as well, including simplification of our financial reporting, increased comparability with our upstream-only peers, and improved leverage metrics upon deconsolidation of $1.3 billion of debt and preferred equity as of September 30th. As we proceed towards closing, which is anticipated in the first quarter of 2022, we will provide further detail around the accounting treatment and the financial statement impacts of this transaction. With respect to portfolio management more generally, as we build the capital investment program to a level capable of sustaining or slightly growing production, you will see increasing activity in our core asset areas, primarily in the U.S. onshore and in Egypt. This will demonstrate both the quality and running room in our core assets, as well as the need for a more accelerated pace of non-core asset divestments. As part of that, in 2022, we anticipate a minimum of $500 million of further non-core U.S. onshore asset divestments. I'd like to close by reiterating some of John's comments regarding APA's free cash flow generation capacity and its anticipated uses. As always there can be some confusion around a term like free cash flow. So we want to be clear what it means at APA. You will find our definition of free cash flow in our financial and operational supplement, which we published with every quarterly earnings report. In the fourth quarter of this year at current strip pricing, we expect to generate free cash flow in excess of $600 million, which would result in full-year 2021 free cash flow of around $2 billion. Under our new capital return framework, a minimum of 60% of this free cash flow would go to ordinary dividends and share repurchases. And as John indicated, we expect to exceed this 60% framework in the current quarter. Looking ahead to next year, we currently contemplate a capital budget of around $1.5 billion. This would consist of roughly $1.3 billion for development and $200 million for exploration and appraisal activities, mostly in Suriname. As we've indicated, we believe the planned level of activity would put our global total BOE production on a sustaining to slightly growing long-term trajectory. This excludes any future production contribution from Suriname. The near-term allocation of capital would likely be biased towards increasing oil production, which would offset declining gas and NGL production. That said, the commodity price environment is very active, and we have considerable flexibility within our portfolio to redirect capital as appropriate. Based on this investment level, we anticipate free cash flow in 2022 would again be in the neighborhood of $2 billion prior to any benefits of Egypt PSC modernization. Finally, I would like to caveat all of this with, as is customary, the final plan for 2022 will be reviewed in the fourth quarter call in February. And with that, I will turn the call over to the operator for Q&A.

Well thanks. Good morning everybody. Just checking, John, can you hear me okay? I'm finding it difficult?

Yes, Good morning Doug.

Some companies can give me some problems. John, I'm going to start with Egypt if I may. I'm sure you saw the report we put out a month or so ago. One of your smaller peers has been a little bit more transparent on the potential changes in terms from the PSC modernization. So one of those conceptually, you could walk us through how you see the moving parts as it relates to increased profit oil and in particular, the potential for legacy stranded capital cost recovery. If you could put some maybe a range of potential impacts on your assuming similar terms applied.

Well, Doug, it's a great question. And you know, from our perspective, we are the largest onshore producer in Egypt. You've hit on some of the key points. We've made the decision not to give more color on that until it's finalized. I will tell you that the modernized PSC has recently been approved by the cabinet and it has moved on to Parliament. So we're getting close and we expect everything's on track for a year-end approval. But in terms of any more color, you've done a good piece of work out there. And I'll let Steve comment on a couple of things.

Doug, I want to add that based on your analysis, it's clear you have a solid understanding of how the PSCs function. Although we haven't specified the exact amount, I can confirm that the backlog will be recovered over a five-year period on a quarterly basis. This backlog will be included in the overall costs for recovery. To summarize, this is all subject to the 40% limit on cost recovery barrels. The key advantage, as you pointed out in your report, is that by consolidating these costs into a single category for recovery, we avoid stranded costs in smaller categories, which will help us recover this backlog, especially in the current pricing environment.

Steve, I know you don't want to give specifics, but in my note I did suggest the potential of the impact could be several $100 million across. Would you push back on that or give some affirmation that we're in the ballpark?

Yeah, Doug. I think I need to be really careful about that. So I think we won't comment on it at this point in time.

Okay. I understand. Let me move on very quickly to my second question, which is understandably Suriname. You've got a well test, I guess you drilled out the fox about 3.5 weeks ago. John, I guess I'm a little surprised that you're not ready to give us some updates there or on Bonboni, where our guys on the ground are suggesting that you'd already in the formation era. So I'm just wondering if you can offer any color around those 2 pieces of potential news flow that we expect, I guess in the coming months, now we get there. Thank you.

Great question. I'll address Sahakara Sal South first. Number 1 you can appreciate that there's multiple phases of a flow test that you go through and sometimes even more important than the flow period is the buildup and the pressure response and all of those things. So it's early. I will just tell you to save your question. I'm not in a position to reveal anything on it today, but hold your question and we'll be able to respond in the near future. So as returning to Bonboni? Yes, Total’s got two rigs, the developers of Sahakara South. The value in is at Bonboni I will remind everybody it's a 45 kilometer step-out to the North. It is a key well. And I think the prospectivity up there will inform the Northern portion of the block, as well as have some implications on Block 53. So once again, I'm not in a position to provide any update but I would just say stay tuned, right? So, and we'll be in a position to update you when we can.

Awesome, thanks so much, guys.

Hello, John. Great update on the shareholder return. I wanted to add one thing regarding that. What are your thoughts on choosing between a variable dividend and a buyback? Your stock seems quite undervalued to me, so I’m curious how you view these two options.

Neal, I guess I'll start out and just on the framework, I'll just give a few comments here. It really should not come as a surprise that anybody that's engaged with us over the last several years when we've been on the road and in our meeting. Stephen and I have been really clear that a quality EMP needs to have a strong balance sheet. You need to have a sustaining low growth profile. Multiple years of inventory, but not too many years of inventory. And we should be throwing off the majority of our free cash flow to shareholders. We've had a lot of work to do. The volatile pricing environment has at times impacted. But we're in a position where we're finally here. If you look at the framework, we believe you want to do a nice mix. You need a competitive dividend. We're not big fans of the variable dividend in terms of how that works. And I think with where our share price is, especially today is as cheap as it is, that that would be the primary means of how we'd look at it. Steve, any more specifics you want to provide?

Thank you for the question about the variable dividend. It's important to provide some context regarding the framework we've introduced today. John presented the historical background accurately. If we reflect on the industry, it hasn't been long since the focus was solely on growth with minimal returns to shareholders. Recently, we've shifted towards moderated growth ambitions and are beginning to implement returns frameworks. The current challenge is determining the appropriate return framework, and I believe the industry is still in the early stages of that process. Right now, returns frameworks are trending toward a percentage of free cash flow, which seems promising. The ranges vary widely, from 25% to 75%, and I expect we'll find a comfortable spot within that range. For APA specifically, it's moving toward about 50%. We've made significant strides in strengthening our capital structure with the debt tender this fall, which was entirely focused on reducing debt. While more work remains on our balance sheet, we still aim to achieve an investment-grade status, which may take some time. It's important to recognize the significance of shareholders as well, so we must balance returns to them with ongoing improvements to the balance sheet. The industry has opted for a 50% return rate, while we have selected 60%, which we believe represents the right balance. Our portfolio is strong and diversified, sustaining free cash flow for many years. Keep in mind, free cash flow—the basis for return distribution—is calculated after capital expenditures. We continue to enhance the balance sheet, with up to 40% available for other uses, including debt reduction. In the near term, we have a preference for dividends and buybacks. Additionally, we discussed the potential acceleration of non-core asset sales, which could provide funds to both strengthen the balance sheet and increase returns to shareholders. We feel confident in maintaining the 60% level. As John mentioned, we currently aren't fans of variable dividends, but we will keep an eye on how the market responds moving forward. Generally, the variable dividend should be a smaller component of our strategy. For now, we're focused on buybacks because we believe our share price is undervalued. We've been trading at a free cash flow yield greater than 25%, one of the highest among our peers, and we believe the market hasn't fully recognized our cash flow generating capabilities. We need to address this discrepancy. While we’ll strive for a competitive ordinary dividend yield compared to other exploration and production companies and the broader market, we see the current typical yield of about 2% as insufficient. We'll look to establish a balance regarding our financial strength and the price points involved, including discussions about mid-cycle prices. We are committed to increasing the dividend but will do so carefully, especially considering that we significantly cut the dividend by 90% just 18 months ago, which was difficult. We want to ensure we do not find ourselves in a similar situation again. I hope this provides a lot of insight into our returns framework.

No, I appreciate what you said about the total return and the share buybacks. I have a quick follow-up, John. What are your thoughts on the future of near-term and medium-term Alpine High activity, especially considering the strong natural gas prices following the Altus deal and the Schneider long-term supply contract agreement that seems to be coming to fruition? Given all that, could you share your thoughts on Alpine High?

When you look at our U.S. program, we've got 2 rigs in the southern Midland Basin. We picked up another 1 that's in the Chalk now. We've indicated we will be adding another rig, probably in the middle of next year, which will put us to 3 that will go to Permian. And quite frankly, then we envision those rigs working those assets in tandem. We're in pad drilling. You will be seeing those move. And what the time it takes on the unconventional side to mobilize a rig, drill pads, and see production. Your short-term windows are benefiting from those right now at Alpine High with the docks that we did earlier, right? So I think you're going to see our very well thought out efficient capital program in the U.S., where we're moving those rigs around those places based on how we've laid the inventory out in the infrastructure, so we can maximize those returns. But there is a portion of the Altus piece if we sell down shares that we do put in there, but it will all fit into our framework. So it's nice to have quality inventory and options because then we can just really plan it out and be thoughtful, but you'll see activity across our Permian next year in a very thoughtful way.

Got it. Thank you all so much for the time.

You bet. Thank you, Neal.

Yeah. Good morning, buddy. See what the next steps would be at the issue with both appraisals. There are just lack of reservoir quality sands as you stepped out. Did you just step out too far in the edge so you need to move back towards the discoveries with the next appraisals or is it more complicated than that?

Mike, it's a good question. I will tell you that it was a big step out. We know it looked a little different in terms of the signature. So we knew there was more risk to it. But there is work to do at Cadcassie, in closer. But I think from the priorities, it will all be put into is your working across all the discoveries and the appraisal program. We're integrating data. We've prioritized for the appraisal there things that you would be what I'll call lower GOR black oil that you could potentially fast-track. And so we're working those in a queue based on the learnings; we've integrated everything in. Some of that will come to one of the reasons why crab to go is the next exploration well. It's in the neighborhood and we like the way it looks. So I think it's all part of an integrated plan.

Okay. Helpful. And maybe just to follow-up on Neal's question. Can you talk about that decision to put the third rig in the Chalk versus the Midland or Alpine High? And Steve mentioned a plan to add a fourth rig next year. Any early preview on where that might land? I guess, any possibility of going beyond four rigs, and then U.S. next year?

Yes. This is David Pursell, good question. So remember on the Chalk we talked about drilling a handful of wells in our Brazos County acreage position. One, because we're trying to maintain optionality. We've had significant experience a bit to the West and the Washington County area and we had a decent acreage position put together and wanted to hold it together and we liked what we've seen so far. It's consistent with the geology we've seen in Washington County in well results. And so we really just want to leverage that experience. We liked what we saw and felt like it was time to put a rig there and continue to progress that position. The thing to remember is it's near infrastructure. There's a lot of pipe infrastructure in the area. It's less than a 100 miles from Houston Ship Channel. So we're getting Henry Hub pricing and LLS pricing for the crude. The GORs are a little bit higher than what you typically see in the Permian. So there's a little bit of a gas component too, which we like in these markets. So for us it was a pretty easy decision on the Chalk. The extra rig we talked about, the incremental rig in the middle of 2022. I think it's important to point out, first of all, as we think about adding another rig, it's harder to stand up a rig quickly, it's a couple of quarters from the time you make that decision till the time you're turning to the right just because of long lead items in supply chain issues, and to make sure that we have everything we need to keep that rig running. I think John highlighted that there is a lot to do in the Permian. We have two rigs in the Southern Midland Basin. We have a lot of development inventory that we're not getting to, which includes Alpine High and we have a lot of good opportunities for that rig and we'll post John those in February that you can imagine Alpine would be on that list of places we'd be looking to drill next year.

And to be clear, there will be no fifth rig in the onshore U.S. next year.

Thanks, guys.

Thank you, Mike.

Good morning, all. Just a question following up on the Austin Chalk and the Alpine High, how do you think longer-term about the balance of gas-directed drilling versus oil-directed drilling, any thoughts there?

I think the strength of our diverse portfolio allows us to be flexible. The answer really hinges on how the commodity markets will perform. Currently, the crude market looks promising, and our gas market is showing signs of improvement as well. We hope to see the later part of the gas curve strengthen slightly from now. With our diverse portfolio, both in the Permian and globally, we have the flexibility to adapt and capitalize on global commodity markets. We'll continue to monitor the forward curve on gas closely.

Okay perfectly clear. We're traveling the globe, can you talk about inflation and sort of what's you're baking in domestically, where you might be seeing something a bit higher versus maybe some of the international assets? What's baked into that sort of capex guide in terms of inflation?

Yes, Bob, you look today and this is the commodities, right? I mean steel is up, where we've got fuel. Your power costs, your people costs, but it's really steel and people, is how we frame it. And we have factored some of that into that capital number, as we look at our programs. And then we try to get ahead on the purchases. And so, if you get into the middle of '22, it is baked into our capital numbers.

Any difference domestically versus internationally? And is there a number you'd hazard to throw out?

No. I think you can easily reach the 15-20% figure, and sometimes even higher, although there isn't a significant difference between the two. The advantage of places like Egypt is that there's less competition for rig additions, making it easier to acquire rigs there compared to the U.S. For context, in 2014 we were operating 28 rigs in Egypt, so we aren't going to a level that requires us to bring in new equipment. Do you have any additional specifics, Dave?

The only thing I'd add is if you think about the type of drilling that we did in Egypt, its vertical wells. It's more commodity drilling compared to what we're doing in the Permian where a lot of the well cost is really on the completion side. So just less I think John hit it, there's less inflation in Egypt and Astra just because of the type of wells that we tend to drill day in and day out.

I would also mention, Bob, that some of the targeted divestments have impacted our higher water cuts. In Basin Platform properties, we are consuming more energy and moving more fluids, which are positively influencing our numbers in regard to our targets. We are being very strategic about our portfolio and taking all of these factors into account.

Great, that makes sense. Thanks much.

Hi guys. Just wanted to follow up on the stock buyback program here. I guess, high level you guys talked about roughly I guess $2 billion of free cash flow. There's some dividend here, but 60% to the buyback I mean, that certainly could imply North of a billion dollars on the buyback. And just in our math, that's certainly seems to be a very large percentage of your shares outstanding currently approaching 15%, upwards of that maybe in one year or next year. Just wanted to get a sense of do you guys think that a number that size is roughly correct and is it feasible to buy back that much stock?

Well, if the share price stays roughly where it is, and that'll be the outcome, yes. And if oil prices stay where they are.

Right. Okay. And then just wanted to follow-up on the Austin Chalk here. So obviously, it's like this point you've dedicated rig. In your slide deck you talked about one well result looked very strong. Presumably there's probably more than that in terms of results that maybe you guys have seen out there. I was hoping maybe you could give us a little bit more color in terms of inventory of aerial extent of where you guys have drilled. Is there an acreage number you think is a sweet spot out there for you that, would give you just a number of years of inventory and maybe just more color about what that rig is doing. Is it all development work? Is there going to be a mix of some exploration in there? Can you maybe just provide a little bit more color about what the run rig is doing and what you've seen so far?

One comment from me is, not only do we have the operated rig, but we're also amount up on some of Magnolia's operations, so there's quite a bit of data. Dave, I'll let you jumped in.

That's a good question. Regarding the Brazos County area, we haven't discussed the specifics yet, but we are conducting additional delineation work to assess the potential size of the resource. From what we see, there is definitely over five years of development work available in this location. We are utilizing a lot of the knowledge we've gained from our operations in Washington County, and as John mentioned, we also have a substantial non-operating position. We'll keep it at that.

Okay. Thanks, guys.

Hi, guys. Thanks for taking my questions.

You bet, John.

I wanted to follow up on Alpine High. A couple of quarters ago, I didn't think we would have multiple questions about it, but clearly a lot has changed. When I consider the developments at Alpine High and the impact of gas and NGL prices, along with the recent Altus - EagleClaw deal that made those processing and gathering rigs significantly more appealing, I know that you have also worked on wider spacing than you typically do there. I’m curious if it's likely that the fourth rig will be deployed at Alpine High, and if there's a plan to update us on the economic model for Alpine High, as it has been quite some time since we last reviewed it.

Yes, John, this is Dave. We look for that as we get into 2022 and really kind of hone in on where that additional rigs are going to focus. But you're right. I mean, it's not just gas price and cost structure. We've done some things on performance, on some of the docks with spacing as well as its frac design and some of those wells are in the public domain and the results are very, very good and certainly exceeded our expectations. So there's a number of factors that would drive us to really focus on Alpine as well as some of the other opportunities out there.

Okay. And then just the follow-up question on Egypt. So if I heard you right, John, it sounded like the 11 rigs was going to go higher post the modernization, getting completed if I heard that right. And obviously it's been a while since we've been at this sort of an activity set. So Egypt until at least Suriname gets to a point where it's at first oil, Egypt becomes the growth driver for the company. And I guess I'm just curious when we think historically has been an 8 rig program or so would try and keep production roughly flat if we go 11 rigs plus. Is it a double-digit type growing asset just I guess any additional color how you're thinking about Egypt.

We've been gradually increasing our operations. We started the year with around 5 rigs, then moved to 8, and now we are at 11. The plan is to increase further. I don't foresee a return to our previous levels in the mid-20 range. However, we are poised to make a turnaround. We have been slightly under-investing in Egypt for several years, and we intend to change that trajectory, which aligns with Egypt's interests as well as ours.

Got it. Thanks. I appreciate it.

Thank you.

Actually, John just asked my 2 questions, but I'll ask one more. The asset retirement liability being put back to you with those Gulf of Mexico assets, does Fieldwood continue to operate there and do you have any input on what they do there?

No. Those assets came out of Fieldwood, so the legacy Fieldwood Company is now a Company called Quarter North. And they don't own the old Fieldwood assets that Apache had sold to them. Those came out and went into an interview that we now call Tom Shelf. There is a person that's contract managing those assets because there are assets that are still producing. But the contract today is in place with Quarter North, the old Fieldwood organization to operate those assets for us, and we will continue to evaluate whether that's the best long-term situation.

Is there any consideration for taking over operations there? Or would it be more sensible to operate it yourself given the liabilities involved?

We need to consult our legal team regarding whether we can operate those assets. There are some concerns about our ability to do so, and I don't believe we would take over the operations at this moment. The assets have a significant inventory from Fieldwood, with many currently undergoing abandonment and a smaller number still generating free cash flow. We've recorded a net liability of $1.2 billion on our balance sheet, which reflects the gross abandonment obligation minus the free cash flows expected from those assets during their remaining lifespan. Additionally, we have listed $740 million on the asset side as financial security to cover those abandonment obligations. This results in a net liability of around $450 million, which we won't begin to fund until 2026 at the earliest, with potential costs extending over the next 5 to 6 years. The present value of all costs today is approximately $250 million. We had to report an undiscounted figure of $450 million. I should also mention that we only gained access to the raw data for this analysis in August and have been thoroughly investigating the abandonment costs since then. Our second focus was assessing the operating assets and cash flow from the producing properties. Lastly, we looked into capital investment opportunities, as these assets have potential for recompletion and other investments. While we targeted high-priority opportunities, we believe there are additional options available to lower operating costs and improve investments that we have yet to explore. We will monitor these prospects in the coming quarters, which could potentially reduce the $450 million liability over time, thus decreasing its present value.

Thanks for the detail on that, Steve. One more. You'd mentioned Steve, that the divestitures you plan next year. I know you guys don't want to give detail on that, but I'm just curious. Can you speak broadly as to what assets might be put in that divestiture bucket or I'm assuming they are on the domestic side and outside of your 3 core areas or were core interception?

Mike actually, we sold some Central Basin Platform properties earlier this year that were higher costs, higher water cut, later life in the country for having a portfolio for a long long time. What I call some of the legacy. You can anticipate more of those types of assets is probably what would make sense.

Yeah. Okay. Very good. Thank you, guys.

Thank you.

Hey everyone. I apologize for coming back again, but I have a few things I need clarification on. My first question is regarding the buyback. I think I missed a comment, so I'll ask this: Considering potential disposals and the cash flow impacts we've already discussed regarding the Egyptian situation, is there a limit to how aggressive you plan to be with the buybacks in absolute terms?

No.

Okay. Simple enough. My focus is.

So just to get a bit of color on that, Doug, I think again, I think our shares are trading at a pretty meaningful discount today. They have improved over the last month or so and that no doubt as part of the purpose of the buyback. But we believe there's still trading at a meaningful discount relative to the price environment we find ourselves in. And we just think that's, for long-term shareholders, that's one of the better investment opportunities we can make, so we'll continue doing that. As long as the free cash flow holds up. So that's why we say it's a minimum of 60%.

Steve, the 5-1/4 million, does that go to the balance sheet or does that go to buybacks as well, because that's not technically operating cash flow?

Yes, we will not make any commitments regarding the buybacks or how the other 40% of free cash flow from the disposal proceeds will be allocated, as we will address that when the time comes. This could be used to strengthen our balance sheet, increase buybacks, or accelerate dividend payments. We also have several upcoming initiatives, including the modernization in Egypt. We have many opportunities ahead of us.

I don't want to labor the point but credit agencies, do they have a view on the buyback, have you run this past them to get their opinion?

We haven't spoken to them yet, but we will be speaking with them shortly.

Okay. And my last one.

We will reassure them of the same thing that we've talked about here today. We're still going to have plenty of free cash flow to do further balance sheet improvements and from asset disposals, if we need to do that and if we feel like that's the best thing to do at the point in time.

Thank you. My follow-up is a real quick one for clarification. Cheniere is your contract kicking in pari- passu with their 3rd Corpus Christi development, which is not even FID-ed yet. My understanding was that that contract to become effective middle of next year. Can you just offer some clarification on the timing? And maybe what you would expect that the ultimate tooling costs to be for you guys.

Yes, I can certainly comment on the first part of that. Our contract is, while it was in the context of FID in another project, it's not contractually tied to any project. And so it's just a contract that starts in 2023 and runs for 15 years. A 140 million cubic feet a day, and Cheniere has an option to bring that forward one year to start it in mid 2022, July of 2022. And we were waiting to see if they will exercise that option.

Alright, thanks folks.

Thank you. And before ending today's call, I'd like to leave you with the three following points. First, we're taking prudent and appropriate steps now to increase our capital investment to a level that will enable us to sustain production on a global basis for many years. Our portfolio offers considerable depth and flexibility to do this efficiently. Second, we're generating substantial free cash flow in this environment, which we currently estimate will be around $2 billion for the full-year 2021 and again in 2022. And lastly, we are committed to returning a minimum of 60% of our free cash flow via dividends and share buybacks. And we're demonstrating our commitment to this process right now in the Fourth Quarter. Thank you for participating in our call today. Operator, I'll turn it over to you.