Apache Corporation (NASDAQ:APA) Q1 2021 Earnings Conference Call May 6, 2021 11:00 AM ET
Gary Clark - VP of IR
John Christmann - CEO, President
Stephen Riney - Executive VP & CFO
Clay Bretches - EVP of Operations
David Pursell - EVP of Development
Conference Call Participants
John Freeman - Raymond James
Doug Leggate - Bank of America
Michael Scialla - Stifel
Jeanine Wai - Barclays
Charles Meade - Johnson Rice
Gail Nicholson - Stephens
Paul Cheng - Scotiabank
Leo Mariani - KeyBanc
Neal Dingmann - Truist Securities
Good day. And thank you for standing by. And welcome to the APA First Quarter 2021 Earnings Announcement Webcast Conference Call. At this time, all participants are in a listen-only mode. After the speaker’s presentation, there will be a question-and-answer session. [Operator Instructions] Please be advised that today's conference is being recorded. [Operator Instructions]
I would now like to hand the conference over to Mr. Gary Clark, Vice President for Investor Relations. Sir, please go ahead.
Good morning. And thank you for joining us on APA Corporation's first 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. Clay Bretches, Executive Vice President of Operations; and Dave Pursell, Executive Vice President, Development, will also be available on the call to answer questions. Our prepared remarks will be approximately 15 minutes in length with the remainder of the hour allotted for Q&A.
In conjunction with yesterday's press release, I hope you have had the opportunity to review our first quarter financial and operational supplement, which can be found on our Investor Relations website at investor.apacorp.com.
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.
This quarter, we have also introduced the term free cash flow, which is defined on page 20 in the glossary of our supplement. 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'd like to remind everyone that today's discussions 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 discuss today. A full disclaimer is located with the supplemental information on our website.
And with that, I'll turn the call over to John.
Good morning, and thank you for joining us today. In my prepared remarks, I will review APA Corporation's first quarter results and discuss our 2021 priorities. Despite some significant weather-related challenges, we delivered a strong first quarter. Specifically, our free cash flow generation was over $500 million. We performed well relative to our production and cost expectations, and our safety performance was excellent.
Our total adjusted production exceeded guidance as Permian oil and gas volumes benefited from a faster-than-expected recovery from the February storm impacts. This more than offset lower international adjusted volumes resulting from the impact of higher oil prices on our Egypt PSC cost recovery barrels and some extended operational downtime in the North Sea.
Upstream capital investment and LOE were considerably below guidance for the quarter. Together with strong price realizations, these factors contributed to an exceptional quarter of free cash flow generation, all of which is being designated for debt reduction. Looking ahead, the full year guidance we provided in February is unchanged, and we are clearly off to a good start.
Turning now to operations in the United States. We reactivated a rig in the Permian Basin, which was previously on standby and picked up one additional rig to drill a 4-well program in the Austin Chalk play of Texas in Brazos and Washington counties. We placed 22 wells online in the Permian, including two at Alpine High. Roughly 5,000 BOEs per day of lower-margin Permian production remains shut in at the end of the first quarter. We are very pleased with the early results and combined with the recovery from Winter Storm Uri are expecting a significant increase in second and third quarter production.
On Tuesday, we announced an agreement in principle with the Ministry of Petroleum and the Egyptian General Petroleum Company to modernize the terms of our current production sharing contracts, which is the result of a process that has been underway for more than one year. The agreement is comprehensive, and when ratified by parliament, will result in increased activity, capital investment and oil-focused production growth over the next several years.
Currently, we are running a five-rig program in Egypt and continue to build quality inventory across our expanded acreage footprint. In the first quarter, we had another significant oil discovery at our Hadid prospect, the details of which are in our financial and operational supplement.
We are projecting Egypt gross production will bottom in the second quarter and trend up in the second half of the year. Debottlenecking of certain pipelines of facilities and the addition of compression capacity will enable us to connect roughly 35 wells in the second half of the year compared to only 20 wells during the first half.
These and other 2021 guidance items do not include any potential changes associated with the pending PSC modernization, which we look forward to updating after the agreement is formally approved.
In the North Sea, we have been operating one floating rig and one platform rig crew for just over a year. At this pace, we are capable of delivering annual production in the range of 55,000 to 60,000 BOE per day for the next several years. In 2021, we anticipate North Sea volumes will be a bit lower as we experienced unplanned compressor downtime in the 40s field during the first quarter and will incur extended pipeline downtime and platform maintenance turnarounds during the second and third quarters. Following this, however, we expect a sharp rebound in production during the fourth quarter 2021.
In January, we announced a discovery at our fourth exploration well in Suriname. An appraisal plan for this well, Keskesi is forthcoming. Total has now fully assumed operatorship of Block 58 and is running two rigs in the vicinity of the Sapakara discovery. Both rigs are capable of appraisal and exploration drilling, which provides ultimate flexibility as we execute our programs. We look forward to providing updates as appropriate in the future.
Next, I would like to review our priorities for 2021, which we outlined previously on our February conference call. First, we are budgeting conservatively and focusing on free cash flow generation and debt reduction. This year, our reinvestment rate is currently tracking below 50%.
Second, we are aggressively managing our cost structure, and we'll continue to do so regardless of the oil price environment. Third, we are preserving optionality within our portfolio, which will enable us to either develop or possibly monetize certain assets at the appropriate time.
Fourth, we are advancing the exploration and appraisal programs in Suriname and are now beginning to benefit from our joint venture carry agreement, which is a very efficient funding source for our differential long-term opportunity in Block 58.
Fifth, we are continuing to focus on value creation through organic exploration. We recently announced the hiring of Tracey Henderson to lead our exploration team, which concludes an extensive search that began prior to the COVID-19 pandemic. Tracey's experience and expertise are a great fit for the existing APA portfolio and we look forward to her leadership on future exploration strategy and ventures.
And lastly, we are advancing ESG initiatives that are relevant, impactful and core to our business. Broadly defined these fall into three areas of emphasis, air, water, and communities and people. In 2021, we have established goals that address routine flaring, freshwater consumption and diversity and inclusion programs. These goals are linked to the annual incentive compensation of not just management, but all employees. We made excellent progress in each of these areas during the first quarter and I look forward to discussing them further as we progress these efforts through the year.
In closing, I would like to thank all of our employees across the globe for their hard work in the first quarter And in particular, our field personnel and contractors on the front lines that did an excellent job of safely navigating global pandemic protocols as well as some very extreme weather events.
During the historic freeze in Texas, our teams worked around the clock to maintain and restore the hydrocarbon production systems that are vitally important to ensuring the safety and well-being of people and communities during events such as this.
And with that, I will turn the call over to Steve Riney, who will provide additional details on the first quarter and our 2021 outlook.
Thanks, John. As noted in our news release issued yesterday, under generally accepted accounting principles, APA Corporation reported first quarter 2021 consolidated net income of $388 million or $1.02 per diluted common share. These results include items that are outside of core earnings, the most significant of which is a $43 million valuation allowance adjustment for deferred taxes in the quarter. Excluding this and other smaller items, the adjusted net income was $346 million or $0.91 per share.
We had a very good first quarter with most financial results being in line or better than our previous guidance. Notable exceptions were North Sea production, which John addressed; and G&A expense, which was $83 million. While underlying spend was in line with our guidance of around $75 million, additional charges were recognized for the mark-to-market impact on certain stock compensation programs.
First quarter results were significantly influenced by U.S. natural gas pricing volatility associated with Winter Storm Uri. The impacts of the storm appear in several places on the income statement. So let me take you through most of the significant items. Since it determines the reporting of results, I'll first remind everyone of how we handle Permian Basin gas production.
We sell all of our gas production in basin, and then manage our long-haul transport obligations separately. We optimize those obligations through the purchase, transport and sale of gas from various receipt points in the Permian Basin and in the Gulf Coast areas.
Our common practice as we contract for the purchase and sale of gas is to maintain a relatively balanced exposure between gas daily and first-of-month pricing. As the end of January approach, we had a portfolio of purchase and sales contracts that were heavily skewed to February first-of-month pricing.
As we commonly do when this is the case, we use financial contracts to rebalance that exposure closer to 50-50. So given the unusually high gas price spike that occurred in mid-February, this impacted first quarter reporting of results in three ways: first, our underlying sales contracts for produced gas determine the reporting of revenue and realizations. Since approximately half of our underlying sales contracts for February production were at gas daily pricing, you will see a significant increase in both natural gas revenues on the income statement and in the average realized price for U.S. gas for the quarter.
Second, our underlying contracts also determine the reporting of revenues and costs associated with our activities to purchase, transport and sell gas to fulfill our transportation obligations. The results of these activities appear in the lines entitled, Purchased Oil and Gas Sales and Purchased Oil and Gas Costs on our P&L. Combined, we incurred a loss of $54 million on that activity in the first quarter, which includes the cost of the transport and the fuel associated with that transport.
In a normal quarter, given current differentials, we would expect this loss to be in the $25 million to $35 million range. For the first quarter, this loss was compounded by a volume imbalance in our underlying purchase and sale contracts, which resulted in more gas purchased at the higher February daily prices and more sales at the lower first-of-month pricing.
Finally, since we used the financial swap to rebalance our underlying contract portfolio, a good portion of the price spike benefit appears in the $158 million derivative instrument gain on the income statement. If our underlying contract portfolio had been more balanced in the first place, we would not have used the derivative contract, and we would not have this gain. Instead, we would have reported higher gas revenues and a lower loss on sales of purchased gas. I know I went through that quickly, and it can be confusing. If you have further questions, please call Gary's team and they can take you through it in further detail.
Free cash flow was also strong in the first quarter, exceeding $500 million. That cash is being used for debt reduction, initially, through the pay down of our revolver. Excluding the consolidated effects of Altus Midstream, we reduced net debt by $339 million in the quarter, mostly through the retention of cash. If the current price environment holds up, we anticipate at least $1 billion of net debt reduction in 2021.
Turning now to some additional comments around our 2021 outlook. Our full year 2021 production, capital, LOE and G&A guidance all remain unchanged. Assuming the recently announced PSC modernization in Egypt proceeds on course, we anticipate adding some capital activity in Egypt for the second half of 2021. We will update our guidance for Egypt as we proceed through that approval process.
We have also expanded our guidance to include the anticipated effects of purchasing and selling gas in the U.S. to fulfill our transport obligations, which I discussed previously. Lastly, for the remainder of the year, we expect our U.S. natural gas realizations will closely approximate Waha and El Paso Permian pricing. You will find all of our current guidance items in the financial and operational supplement.
In closing, we look forward to a very strong year of free cash flow generation of at least $1 billion. This should take us a good bit of the way toward our previously mentioned leverage target of around 1.5 times debt-to-EBITDA under a mid-cycle pricing scenario.
You should understand, however, that our more relevant objective is to return to investment-grade credit status. To that end, we will continue to budget conservatively, focus on costs, free cash flow generation and debt reduction and maintain close contact with the rating agencies to ensure that we are taking the appropriate steps to achieve that goal in a timely manner.
And with that, I will turn the call over to the operator for Q&A.
Thank you [Operator Instructions] Our first question comes from the line of John Freeman from Raymond James. Sir, your line is open.
Good morning, guys.
Good morning, John.
The first question I had was just on what Steve said there at the end about potentially looking when the new PSC has done in Egypt about adding some additional capital and activity in the second half of '21 in Egypt. And obviously, that's consistent with what you've said in the past, John, about eventually wanting to get the U.S. and Egypt, and 2022 and beyond is sort of more of a maintenance level activity at the least.
And so I know in the past, the sort of the commentary around Egypt had been from the five rigs you're currently running, probably wanting to get to at least a couple of rigs more to at least get to that maintenance level. So until told otherwise by you all, is that a fair assumption to assume that, that's kind of where you want to get to in Egypt for the - by year-end?
Yeah. I'll make a few comments on - just in general on Egypt, and then I'll have Dave step in a little bit in terms of just rig count and things. But I think what you've seen is, finally, we can get out in the public about a real important step in the process that we've been working through and modernizing our PSCs in Egypt.
This is something that we started really prior to the COVID-19 pandemic. But I will tell you, we've been negotiating in good faith and in earnest with Egypt since -- for more than a year. And we're at a point today where after working with the Minister of Petroleum as well as EGPC, we were able to announce this on Tuesday. It's really a framework that sets the future for Egypt. We've been clear not to touch guidance this year. We've now had to go through the approval process, and there are some steps to go through the parliamentary process and ultimately get things ratified, and then we'll be able to talk more about it.
But as we go through the year, we will be picking up some activity. There's just a lot of projects in Egypt that had been - become non-competitive because of the terms of the PSC, and this is really going to open up some projects that we're ready to fund. I think this is going to be a win-win for both the country of Egypt and Apache, and it's going to really put us on a much stronger than just maintenance curve for Egypt. So Dave, I'll let you jump in and add a little bit more to that.
Yeah. Thanks. Let's step back. And I think, John, you had - you framed your question on what we've said before around wanting to maintain the business. So let's think about maintenance capital. So right now, we're going to spend this year roughly around -- these are going to be round numbers - $900 million of development capital. And that's -- and in that mode, production's in a modest decline.
So we think about two places we'd want to flex capital to arrest that decline, that would be in the U.S. in the Permian Basin, primarily, and in Egypt. If you think about a rig line, we've talked about needing potentially a full rig line or a partial rig line in addition to the two we'll have in the second half of this year in the Permian to sustain production and then more rigs in Egypt. And we've talked about seven to eight rigs needed to sustain or maintain production there.
And so if you think about a rig line in the Permian and a handful of rigs in Egypt, that puts you roughly $200 million incremental dollars. So our maintenance capital is about $1.1 billion. And the key here is we're not talking about material growth, but we're talking about maintaining production. And that gives us some optionality in the portfolio to where we want to add that capital to maintain our global production. And so that frames the maintenance capital, and I'll throw it over to Steve to add some more color on that.
Yeah. So we entered, I think, good context for this is that we entered the year as people will recall, it seems like years ago, but ended this year with a plan that was based on $45 WTI, and it had a - as Dave called it, the development capital, the $900 million of development capital, if we just set aside Suriname, was about a 60% reinvestment rate. And at current strip, that same amount of capital is less than a 40% reinvestment rate.
So clearly, this is not a reinvestment rate that's going to sustain, and it's not a maintenance level of capital spending. And so we've got a continued slight decline in production volumes. And we've talked about this in the past, that the #1 priority coming into the year when it still looked like a pretty difficult year was that we needed to get debt paid down. We needed to get the balance sheet strengthened an we needed to star the process and that was the most important financial priority.
But it is prudent [ph] to spend at of maintenance capital level and maintain the production volume going forward and we probably need somewhere in the neighbourhood of $100 million to $200 million more development capital in order to get into that neighbourhood.
And with price where they are, and if they hold up, I think we’re likely to start increasing capital in the second half in order to get that point and most of that is Dave outlined is going to be in the Permian and Egypt, especially Egypt with the modernization efforts as that proceeds and gets the final approval.
And I just want to echo on that. The issue there was the old structure of the PSCs and how they work. These were very old vintage PSC structures. And it has nothing to do with the fact that Egypt actually has some very highly economic opportunities in quite a bit of them and just needed the PSC structure that enabled the capital investment in that.
And I'll just echo once again John's point that none of this is in our guidance. It's not in the capital for guidance nor is it in the production volume or anything else for guidance. And just to reinforce what Dave said, I'd ask that we please don't throw us into the bucket of growthers [ph] because this is not an aggressive growth spending plan. This is just about a prudent step towards getting to at least a maintenance level of capital spending.
I appreciate that. That makes a lot of sense. Just the follow-up related sort of tied to that is I see what sort of the activity has been in Suriname onto the first half of the year were Total made the decision to focus more on appraisal here in the first half of the year as opposed to immediately taking that second rig up to Bonboni for the exploration program.
And I guess we'll just wait to see when we ultimately get up to Bonboni. But at the very least, it seems like just given that you are on the hook for 12.5% on appraisal versus 50% on exploration, it seems like that created a little bit of slack in the budget, unless I'm reading too much into it.
There's at least a little slack because just by definition, it seems like your Suriname on budget from where you started the year is probably a touch lower just given the -- a little bit more of a skew toward appraisal versus exploration at least through the first half of the year.
Yes. And I guess, John, we look at the Suriname budget, we really haven't touched that, right? I mean it's just a timing thing. Bonboni will be the next exploration well. We're obviously anxious to go drill it. And it is 45 kilometers to the north, so it's -- to give you an idea just the scale and scope. So we aren't shifting dollars there, consuming any of that. We've left the Suriname budget kind of where it is. That's just a kind of timing. And quite frankly, we had a pretty good idea what their cadence was going to be as we entered this year anyways.
Great. Well, I appreciate it, guys.
Thank you. Our next question comes from the line of Doug Leggate from Bank of America. Sir, your line is open.
Thank you. Good morning, everybody. I'm afraid I'm going to pound John a little bit on Egypt, just to round out the last John's questions. Steve, I wonder - I know you're going to give us details later on, but I just wonder if I could touch on a couple of aspects of why this could be a big deal for you guys. I think it's 10 years since we published our primer on this, believe it or not. The cost pool, the potential for extension and the implications of that seismic shoot you've been doing, particularly over the oil play in the Western Desert, can you offer any - can you quantify perhaps what no ring fencing can do to the cost recovery or the cost that you have outstanding there and whether you would get an extension on those concessions as part of this agreement?
No, I mean, Doug, great question. And you'll have to just wait until we get things finally approved for us to really dive in and give any - a lot of details on it. But I'll just say, we - stepping back, it's a holistic approach. This is something that will be good for Egypt. We've looked at things very carefully. This has been a process that has been very lengthy and very thorough and very comprehensive.
And it really is in line with the minister's objective of modernizing the oilfield in Egypt. And I think it's going to have some benefits that's going to enable us to direct more dollars into the drilling programs and into the volumes, which are going to generate more revenue.
And so we've got a deep inventory. We're seeing good early results off of the seismic with the Hadid announcement that we had this - within the supplement this go-around. So we're excited about Egypt. And quite frankly, this really puts us in a position where we can fund some projects that are ready to go.
Forgive me for getting technical on this, John, but I just want to make sure you understand my question. Do you have isolated cost recovery pools that you couldn't recover because they were ring-fenced?
And I'm just trying to understand if you could - your share of production could go up sort of overnight as a consequence of being able to tap into those cost recovery pools without any incremental capital
I fully understood your question. I'll just say again, I can't get into a lot of details until we close. But this is going to be a win-win for both us and Egypt, and it's going to let us put more dollars in the ground and raise out investments. Steve, do you want to?
Yes. I'd just say, Doug, we applaud and respect the effort. We just can't get into details because it's still got quite a bit of process to go. But we've made a major milestone here with the agreement in principle, and so we're on our way.
And I'd just like to reiterate, Egypt is a fantastic country to do business in and it's got some of the best underlying opportunity in our entire portfolio and long legs on that inventory as we're proving with the seismic and some of the activity going on, on the exploration side.
And all we're accomplishing with this is the -- is getting rid of an old, outdated PSC structure that created artificial barriers, to being able to access some of that really attractive opportunity. We'll give a lot more details as we get closer to this.
Okay. I don't want to hold the call guys. That was actually my first question. My second one, I won't go to Suriname this time, but I'd like to ask you, Steve, about free cash flow. Look, obviously, $500 million adjusting for working capital, $1 billion for the year that current. There is some something not adding up there.
I just wonder if you could just frame for us what you think the scale of the more than $1 billion could look like. And more importantly, in a relatively complex portfolio in some people's view, what's the longevity, ex Suriname, of sustaining that free cash flow from the current portfolio? And I'll leave it at that. Thanks.
Yes. Great, Doug. And I think that I was probably a bit too understated in my prepared remarks. And the point of that was really just to highlight where we've gotten to in one quarter from the plan that we laid out to all of you in February.
Our original plan, as I said, we report at $45 WTI. It had somewhere around $350 million of free cash flow. And the point of the - of my prepared remarks was to just indicate that it's over $1 billion now. And maybe I could do a little bit better than that and say that at the current strip, it will be well over $1 billion.
We - the only thing I would say about that, though, is we don't give guidance on free cash flow. We haven't done that in the past. And I don't want to start that process on an iterative basis at this point, mainly because there are so many different measures out there of what people call free cash flow. And we've defined what ours is, so we're very clear about that. But we're going to continue not to give guidance on it.
And the second thing I would say is, if I go back to my comments earlier around maintenance capital, on the -- if you just set Suriname aside, we're somewhere -- and yet, we continue to invest $200 million in Suriname, you only need about 100 -- somewhere between $100 million and $200 million more to get to a maintenance level of capital on the development side.
So we're not far from that. And then -- and so that's what your difference is, it requires $100 million to $200 million more in order to sustainably access this, what I would call well over $1 billion of free cash flow, in this price environment for an extended period of time. And I think what we've shared in the past is that we certainly are confident we can do that for five to 10 years, and we're always looking for opportunities to be able to do that for an extended period of time beyond that.
Steve, that's really helpful. I mean Suriname's in the stock [ph] for free, and I appreciate the answer.
Thanks for the question. Gave me the opportunity to be a little less conservative on the free cash flow.
That’s appreciated, guys. Thanks so much.
Thank you, Doug.
Thank you. Our next question comes from the line of Michael Scialla from Stifel. Sir, your line is open.
Thanks. Good morning, everybody. John, you mentioned in your prepared remarks about potential non-core sales. I just wanted to see if you could talk about that anymore, maybe what assets might be included there and how far along in the process are you. Is there a formal data room planned for that? Or where are you in that process?
Mike, thanks for the question. Yes, we typically wait to talk about portfolio transactions and things after we've announced them and so forth. So -- but I don't think it's a big secret. We've had a pretty small package in the Permian that's in the market. It's non-core, some higher cost waterflood-type stuff that we may be in a position to transact on, we'll see.
We're kind of working through that now. I think the point is we've got the rig running in the chalk. We're open to looking at what we will and will not be investing in. And as we make progress on things like modernization in Egypt, it's a continual process for us. So a lot of key things going on, but we're open and always looking at various things with the portfolio.
Okay. Thanks. And I wanted to ask on Suriname, just kind of a follow-up on the deeper test at Keskesi. You ran into the pressuring issues before you could test the Neocomian. I think you said in your release, it nevertheless helped validate your geologic model. I just want to see if you could add any color on that and what you saw in that process.
Well, with Keskesi, there were a couple of things that happened there that I think were key. Number one, we got down below the unconformity. I think, number -- and proved that we had charge in hydrocarbons. I mean, that's obviously why we had to stop. And then the other key fact that was important was at that depth, we proved that we could have quality reservoir in those carbonates. And so -- and it also was very, very rich hydrocarbon, not just a dry gas.
So we're encouraged by that. It's a prospect and a play that's going to need to be tested. But it's also going to take a different well design than what we had. We were very close to getting down to the first target. There were two targets that we're going after. But we had to call it early and we did.
But that's something we'll be working with our partner, Total, on to come back with an exploration well that will test those Neocomian targets at a later date, because both of us were encouraged by what we had seen leading up to getting very close to the first target.
Great. Thanks, John,
Thank you. Our next question comes from the line of Jeanine Wai from Barclays. Ma’am you line is open.
Hi. Good morning, everyone. Thanks for taking our questions.
Good morning, Jeanine.
Good morning. Thanks for the time. Maybe just two quick ones on the balance sheet. Can you talk about the medium-term plan for adjusting the balance sheet? You've got a ton of free cash flow on the horizon, so there's a lot of options there. Do you intend to retire debt as it comes due? Or are there opportunities to retire or further refinance at lower rates earlier?
Yeah. Jeanine, so this is Steve. Yes, we've talked about the fact that we are -- we've talked externally about -- we're targeting at least getting down to 1.5 times debt to EBITDA. We may need to move lower than that. Certainly, the direction things have been moving in general over time. We believe something at or below that number is going to be what's required to get back to investment grade.
And as I said in my prepared remarks, that's ultimately the real underlying goal, is to get back to investment grade, and we're going to do whatever it takes to do that. We're clearly making some tremendous progress this year by our estimation at the current strip. We'll have net debt-to-EBITDA down to approaching 2, about 2.1 times debt-to-EBITDA at the end of this year. Even if you adjusted that to -- well, what would happen if we were in a $55 price environment for 2022, we'd still only be slightly higher than the 2.1, maybe 2.2 or 2.3. So it doesn't move up considerably.
So we're - we've made tremendous progress or will make tremendous progress this year if prices hold up. As far as how we're going to do that, we haven't gotten into the details of exactly how we're going to do that. But it obviously has to result in paying off some of the bonds historically. What we've generally said is we're going to do it the same way we've done it in the past.
We've done combinations of open market repurchases. We've done 10b5-1s. We've done tender offers, refinances, and we will do all of the above. I don't believe -- at this point in time, I don't believe you'll see a material amount of refinances going forward until we get to -- back to investment grade. We've got about a little over $335 million of debt maturing in the next couple of years, and that will just be paid down as it matures.
And so maybe following up on, so the ultimate goal is to get back to investment-grade. How do you view that versus more meaningfully increasing the dividend? Or are those two things kind of mutually exclusive? Or do you think you can do both of them the same time?
Yes. I - obviously, both of those are important. I think we have to get the balance sheet in order and get debt down and get at least at a minimum, get back closer to a point where we think achieve investment grade before we start looking at the dividend again.
And as we've discussed before and I think we've talked with you specifically about it, we look at debt paydown as a return to shareholders because every dollar of debt that we can get off the balance sheet today will add more than $1 to the market cap of the company, we believe, because we think that the debt level is actually weighing on the share price.
And so while it's not the same as a dividend and we recognize that, it does benefit shareholders directly with debt paydown. And we haven't made any specific plans as to what we're going to do. We've got quite a bit still to accomplish on the debt paydown effort.
We - as I said, we'll accomplish quite a bit of that, hopefully, this year. We'll need to do more of it in 2022. And at an appropriate time, we'll reconsider whether we need to bring the dividend back or whether we want to start bringing the dividend back and we'll certainly hold out the option that we could start looking at the dividend prior to actually getting investment grade. That is clearly an option for us.
Thank you for all the detail. I appreciate it.
Thank you, Our next question comes from the line of Charles Meade from Johnson Rice. Sir, your line is open.
Good morning, John to you and the rest of your team there.
Good morning, Charles.
I wondered if I could go back to Egypt and just ask a question -- I think I know the answer. But in principle -- I recognize you can't talk about the details yet. But in principle, are we talking about that there's some opportunities that are obvious to you and obvious to Egypt, but it's also obvious to Egypt that you're not pursuing them because of the -- maybe some oil price thresholds that are quite low in those PSCs, and so that's the win for them? Do I have the right framework?
Yes. I'll just say that there were some projects that the PSC was making them less competitive, right? And by modernizing the PSCs, there's projects that move up the queue that we can fund, and we'll be looking forward to fund. So there's no doubt it's a critical step. And this is not -- it's not uncommon. You got to understand these PSCs, we've been in Egypt for over 2.5 decades now. A lot of these fields have been operated since the mid-90s. And so stepping back and going through this, this is just the evolution that's required in an oilfield, right? So.
Yes. That's right. I imagine if you'd ask the people who had written them, if they were going to stand for all time, they would have said absolutely no. But If I can ask the second question about -- you mentioned in your prepared remarks and you guys put out a press release about bringing Tracey Henderson on to head up our your exploration. So she has some experience drilling offshore Suriname.
And I wonder if you could just talk a little bit about more -- a little more about where you see her getting rubber to the road or really helping your process both in near term and the long term. I know that you're still the operator of Block 53, if I'm not mistaken. So that's one obvious place in the near term. But can you talk a little bit about how you expect her to fit in and contribute?
Well, I mean, I think it's all about building the executive leadership team that we want for long term. And Tracey brings a wealth of experience and a wonderful skill set. She's worked in small publicly traded companies, so she understands where they had to explore for a living. I think she'll bring a lot of expertise, a lot of experience. She's built exploration teams. I think we've got a lot of key pieces here that she'll be able to come in and hit the ground running and work with, and a portfolio that fits a lot of her expertise. So she was absolutely our #1 candidate, and we're thrilled to ever join us.
Thank you for that color John.
Thank you. Our next question comes from the line of Gail Nicholson from Stephens. Ma’am your line is open.
Good morning. We came in slightly below guide for 1Q. Can you talk about the drivers here and the ability to replicate any of those 1Q savings going forward?
Yeah, Gail, this is Clay Bretches. And with regard to the LOE, it was just a masterful performance by our operations folks in the field. They did a great job. They understood the task that was at hand. Last year, we went through some significant cost-cutting exercises. We identified the areas where we could cut cost. We knew that those needed to be sustainable, especially when we were looking at commodity prices in 2020.
So we had an all-hands-on-deck approach to this. There was a lot of bottoms-up initiatives that led to this LOE reduction. It wasn't short term. It wasn't just deferral of expenditures, maintenance, et cetera. There was some of that, but it wasn't significant. The big issues here in LOE reduction had to do with those initiatives that took place.
If you take a look at where we had the most significant reductions, it was in the Permian. A lot of that had to do with the wells that we shut-in. We have a lot of wells that are what we call frequent flyers, wells that go down a lot. We took those out of service, and those are still shut-in because they cost us a lot of money and they're not economic to run.
Furthermore, a lot of our waterflood properties that just weren't providing the economics, we went through and looked at these on a well-by-well, field-by-field basis, there's a lot of water that's not being injected right now because it's really expensive to inject that water. We still have approximately 300,000 barrels a day of water that we don't inject, which saves us a lot on electricity, a lot on maintenance, a lot on personnel overall. So in general, it's just the approach that we took. We want to maintain that.
That's something that we talk about as an operations group on a regular basis. How do we maintain this low LOE profile as we go forward? In light of the fact that commodity prices are increasing, we do have concern about inflation and service costs.
So we focus on making sure that we keep that LOE down, continue to strive to find initiatives that are going to keep the LOE down and flat in light of the fact that we know that there's going to be some inflationary pressures going forward. So really, again, just kudos to our operations team for getting us to where we are and maintaining those levels.
Okay. I appreciate the clarity. And then just moving kind of on the ESG front. In regards to carbon capture, some of your North Sea peers are looking at carbon capture projects. Are you in the process of potentially doing anything in that vein? And/or do you see any potential for carbon capture of projects on your North Sea portfolio?
Yes. Gail, on the ESG front, we've emphasized there's really three areas. I mean we're focused on air, water, communities and people, right? And I think the key for us, too, is we're focused on near-term projects that we can do that can make an impact. And I think the area we're focused on right now mainly is flaring And in the -- basically in the U.S., where we're committed to eliminating our routine flaring by year-end this year as well as delivering less than 1% flaring intensity.
So key goals there. We're looking at things in the North Sea. But as far as right now, the near-term things, we're looking at some of the low-hanging fruit that we can get after. I don't know if, Clay, you want to add anything on the carbon side in the North Sea.
No. Just what you said, obviously, there's a price on carbon in the North Sea, which creates opportunities. Anytime you have a price on carbon, that creates some economic incentives to study carbon capture. So we will take a look at that anywhere that we see a price on carbon. It is something that we were paying attention to in the North Sea. But like John said, what we're focused on right now from an ESG standpoint are those areas that we have control and which are going to be impactful for Apache. So the really big initiative for us from an ESG standpoint is to end our routine flaring in the U.S. onshore by the end of 2021.
And we think this is really significant. You hear a lot of ESG claims out there that talk about some type of initiative that's aimed at 2030, 2040, 2050. What we're doing is saying we're going to end routine flaring by the end of this year. And we think that's really significant. And it represents a significant commitment by Apache to do the right thing and to produce responsibly. And we've shown that over and over.
If you take a look at the investment that we have made in midstream solutions to make sure that we were performing responsibly, not only with Altus Midstream with those gathering and processing assets that we have in the Delaware Basin, but also our significant investment in the Gulf Coast Express pipeline, Permian Highway pipeline. Both of those are moving over four billion cubic feet of natural gas out of the Permian Basin that not only serves Apache, but it serves a basin in general.
Getting that gas out of there and creating opportunities for others to get gas that otherwise would be flared out of the basin. So we've put a lot of investment in those pipes. We've put a lot of commitment in terms of firm transportation to anchor those pipes. So we feel like we're really doing a lot that impacts the gas flaring and ESG initiatives in real time.’
Great. Thank you. Great quarter, looking for the back half of the year.
Thank you. Our next question comes from the line of Paul Cheng from Scotiabank. Sir, your line is open.
Thank you. Good morning, guys.
Good morning, Paul.
Can I just get some maybe your intention for Egypt and Permian over the next several years. I mean we know that you -- most likely than not, that probably going to raise the activity level to into the sustaining level for those two areas. But over the next several years that are we going to trying to maintain them flat or that you were trying to grow a bit. And is that in any shape or form tied to your debt reduction target for that? How that decision-making or that type process is going to be? That's the first question.
The second question is certainly, Total have indicated they will sanction the first development this year coming on stream in 2025. Any kind of color you can provide that which discovery is going to be target and whether that you will be doing similar to what Exxon did in these are one using a smaller ship sort of as an early production system, trying to learn the rest of -- learn the whole operation before you go to the [indiscernible] operation. Thank you
Well, thanks. Two good questions. I'd say, first of all, when we look at the portfolio, we've said for 2021, not to touch guidance or anything right now. So modernization in Egypt is going to have a big impact for us. It is going to enable us to put Egypt back on a track where we can grow those volumes, and I think it's going to be very beneficial. I think in Permian, we've got one rig running today. We're planning to pick up a second rig midyear.
As David has said, we need to grab another rig there to kind of maintain our Permian volumes, and that would be an objective of ours But I think as we look going forward beyond that, we don't see trying to ramp up to a big activity pace and try to grow aggressively, that we think we want a modified moderate investment pace where we're investing very wisely and very -- making very capital -- efficient use of that capital.
Your question on Suriname, clearly, we're underway with -- as Total as operator. They've got two rigs running in the vicinity of the Sapakara discovery. We have not put out any time lines, and I don't see a anything magical about when you need the FID a project. I think the key for us is doing the appraisal work collecting the data, so we can ultimately FID a project. There's lots of optionality.
You are very likely looking at potential FPSOs like what's been done next door, but it's just really premature to get into anything there. I don't see anything magical about a year-end time line to make a first oil 2025. I think that could easily slide into next year and still make that type of time frame. So we're not pressing for any hurdle there. You want to do the work, you want to do it right, and then you want to be in a position to FID the projects when you're ready to FID the projects.
John, can I just go back into the first question that you said you're not going to increase the activity and trying to have a major growth. Is that a function to your debt reduction target that -- because you haven't reached that yet? Or that is just because you think the world doesn't need more oil even though the commodity price is strong.
No, I think -- Paul, I think in the short term, it's a function of needed debt reduction. But I think longer term, it's just in the -- it's part of the function of more cash flow for shareholders. And we've been in a position for quite some time that growth was not an objective that was worth chasing in and of itself. And that this business needs to be something that's returning cash to investors.
We need to get the balance sheet fixed first in order to do that. As I mentioned earlier, we think reducing debt is a return to shareholders, just a different type. But longer term, when we get debt where it needs to be, we're not going to be looking for double-digit growth, but we're going to be returning cash to investors.
And Steve, I just want to -- reaffirm that. I think earlier, you guys said that you're going to add a rig in Egypt. That's not included in the current budget. And same as that for Permian, if you're trying to maintain as a flat production. So if we're going to do those, then that means that your overall capex for this year is going to be higher than $1.1 billion, right?
Yes. Let us be clear one more time maybe. We are not changing our guidance at this point in time. We just said that if prices hold up and we continue to make progress on the Egypt modernization, we may be looking at some further capital spending or capital activity in the second half of the year. If we were committed to doing that, we would be looking at contracting rigs and we would be telling you we're changing guidance, but we're not doing that right now.
Okay, perfect. Thank you.
Thank you. Our next question comes from the line of Leo Mariani from KeyBanc. Sir, your line is open.
Yeah. Hey, guys. I just wanted to follow up a little bit on Egypt here. In terms of the Hadid discovery, can you maybe just give us a little bit more color around that? Is this something that rose out of the new concessions and new seismic that you folks shot? When do you see first production from that potential discovery here? And then additionally, do you think that this discovery unlocked a bunch of other drilling opportunities for you late this year and into 2022?
Yes, Leo, great question. It is a result of the new seismic. It was 2013 when we shot our last vintage, and then we started shooting this new seismic in really the '18, '19 still shooting process out there. It's given us more clarity where we can see things that are more subtle, and we're starting to move really from just drilling big bumps to things that have a stratigraphic element to them.
This is a trend where it sets up multiple wells within the discovery area, but it also sets up very similar-looking prospects that look much like it. So it really gives you some insight into the lens we have now and the opportunity that we know sits out there that we now can start to crystallize as we continue to drill more wells off of the new seismic and refine that process. So on timing, I don't have that for you today. I can let - I think Clay can jump in on that on - actually on the Hadid well.
Yes. So Leo, this is Clay Bretches. And on the timing for the Hadid we're laying pipeline right now, and we're making sure that we have a pipeline that is sized for -- appropriately for the Hadid, but also for growth opportunities, just like what John said, based on follow-on wells in and around Hadid. And that pipeline is being laid right now and should be in service in the fourth quarter of this year.
Okay. That's helpful. I just want to jump over to the North Sea here. You guys certainly had some unplanned downtime in the first quarter, but you're also saying there's going to be -- it sounds like some more of that in the second quarter and then maybe some normal planned turnarounds in the third quarter.
Could you give us a little bit color on how you see North Sea volumes progressing? Would you expect second quarter to go down further or would be more flat with first quarter?
And then just kind of what's the cadence into third quarter? Is it down further? And I think you guys were saying that fourth quarter production should be up a lot. Just wanted to understand the cadence in the next few quarters.
Yes. I mean, it's all planned activity. Second and third quarter were, from the get-go, planned. It's pretty heavy maintenance periods. We were unable to do some of it last year, so they're going to be a little heavier this year. And then you're going to have a really strong rebound in Q4 as we bring everything back online.
So I think the -- our guidance for the year is -- we reiterated that. And I don't know, Dave, is there anything else on shape or anything for Qs two and three for North Sea.
Yes. Just to reiterate what John said. The TARs [ph] in the second and third quarter, probably a little larger than normal because they were abbreviated last year because of COVID issues. So we'll see second and third quarter impacts, rough order of magnitude, those are kind of in the 6,500 barrel BOE per day range expected through the quarter for second and third quarter just on those impacts, and we'll see a rebound in the fourth quarter. So again, as John said, no change to guidance.
Okay, thank you.
Thank you. Our last question comes from the line of Neal Dingmann from Truist Securities. Sir, your line is open.
Thanks for squeezing me in guys. Just my last question, I don't know if there's anything about this, but I'm just wondering. We've seen a nice run continue not only in oil, but in gas. Any thoughts on potential incremental activity in Alpine this year or early next?
Yes. Neal, this is Dave Pursell. From an activity standpoint, we have five DUCs that we're completing as we speak. We completed two earlier in the year. We're going to evaluate the performance of those. But given where oil prices are, and we've got -- as we've talked about on this call, we have a constrained capital budget with oil in the 60s, it's hard for Alpine to compete with oilier capital in the Permian and in Egypt. So our view is let's evaluate the performance of the DUCs and then we'll decide or evaluate potential third-party capital.
Sure. Makes a lot of sense. And then just lastly, quickly, are you seeing any just OFS, whether cost inflation, not only domestically, but I'm just curious, internationally, do you see much over on the two plays?
Yes. On well capital, so far, the answer is no. We would - we're looking for it. We'd anticipate it. We're looking at steel to see if we see inflation on the OCTG side of it. I think where we're feeling the inflation, and Clay talked about it on the LOE stuff, your basic operating chemicals and diesel costs. So we're seeing a little more real-time inflation on the -- at the LOE level and less at the capex level right now.
Very helpful. Thanks again for squeezing me in.
Thank you. There are no further questions in queue. I will now turn the call back to John Christmann. Sir, please go ahead.
Thank you. I'd like to leave you with the following parting thoughts. Delivery was very good in the first quarter, and we have reiterated our full year guidance. Commodity prices continue to be constructive, and we have clear visibility into at least $1 billion in free cash flow this year. We are seeing the benefits of our diversified portfolio as increasing volumes in the Permian over the next two quarters will more than offset the seasonal planned maintenance downtime in the North Sea. Activity will also be picking up in Egypt as we move into the back half of the year. We have successfully transitioned operatorship on Block 58 to our partner, Total, with two rigs conducting very active appraisal and exploration programs for 2021. We look forward to updating you on our continued progress throughout the year. That concludes our call today.
This concludes today's conference call. Thank you for participating. You may now disconnect.