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Antero Midstream Corp
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Greetings and welcome to the Antero Midstream First Quarter 2020 Earnings Conference Call and Webcast. [Operator Instructions] Please note that this conference is being recorded. I will now turn the conference over to our host, Michael Kennedy, Senior Vice President of Finance and Chief Financial Officer for Antero Midstream. Thank you. You may begin.
Thank you for joining us for Antero Midstream’s first quarter 2020 investor conference call. We will spend a few minutes going through the financial and operating highlights and then we will open it up for Q&A. I’d also like to direct you to the homepage of our website at www.anteromidstream.com where we have provided a separate earnings call presentation that will be reviewed during today’s call.
Before we start our comments, I would first like to remind you that during this call Antero management will make forward-looking statements. Such statements are based on our current judgments regarding factors that will impact the future performance of Antero Resources and Antero Midstream and are subject to a number of risks and uncertainties many of which are beyond Antero’s control. Actual outcomes and results could materially differ from what is expressed, implied or forecast in such statements. Today’s call may also contain certain non-GAAP financial measures. Please refer to our earnings press release for important disclosures regarding such measures including reconciliations to the most comparable GAAP financial measures.
Joining me on the call today are Paul Rady, Chairman and CEO of Antero Resources and Antero Midstream; Glen Warren, President and CFO of Antero Resources and President of Antero Midstream; and Dave Cannelongo, Vice President of Liquids Marketing and Transportation.
With that, I will turn the call over to Paul.
Thanks Mike. I would like to start by discussing the updated development plans and capital budgets at Antero Resources and Antero Midstream. On to Slide #3 titled flexible and just-in-time capital budget, the left hand side of the page illustrates AR’s drilling and completion capital budgets which have remained flexible based on commodity prices and targeting free cash flow. In March, AR announced a reduction of its drilling and completion capital budget from $1.15 billion to $1.0 billion as a result of achieving D&C capital cost savings ahead of schedule. These savings were driven by flow-back water savings and increased efficiencies such as daily drilling footage improvements and an increase in completion stages per day. This allowed AR to maintain a D&C capital budget that approximated free cash flow even after the initial decline in commodity prices.
In order to maintain its financial profile and liquidity, AR has further reduced its D&C capital budget to $750 million in response to the unprecedented demand impacts from the global COVID-19 pandemic and oil price war. This reduction was driven primarily by the deferral of 20 well completions from 2020 into 2021. Importantly, given the visibility AM has into AR’s development plans, AM has quickly adapted to these changes and lowered its capital budget from an original budget of $300 million to $325 million in February to a range of $215 million to $240 million today. Our updated capital budget represents a 27% reduction from our original capital budget and a 65% reduction compared to 2019 capital expenditures.
Looking ahead, should natural gas prices continue to strengthen, AR has 4 dry gas Utica pads that are development-ready and can be feathered in to the 2021 drilling program. These dry gas pads require very little additional capital investment from AM and are located nearby existing infrastructure with excess capacity. This development plan visibility and pure-play Appalachian focus is a competitive advantage compared to midstream gathering and processing companies that have a multitude of producers across various basins. Our coordinated planning with AR reduces uncertainty, particularly in today’s environment and allows AM to have a more stable financial policy that benefits our shareholders.
Slide 4 titled significant liquidity enhancements illustrates the recent liquidity developments at AR. First, AR’s borrowing base under its credit facility was confirmed at $2.85 billion, well in excess of lender commitments of $2.64 billion. As a result, AR had over $1 billion of liquidity under its $2.64 billion credit facility as of March 31, 2020, which is shown on the dark green bar on the left hand side of the page. AR’s updated development plan is expected to generate a $175 million of free cash flow in 2020 further improving its liquidity position. Assuming execution of the remaining sales under AR’s targeted asset sale program of $900 million, AR would have over $2.1 billion in liquidity at year end 2020 prior to any further bond repurchases.
Over the last two quarters, AR has taken a proactive approach to debt reduction repurchasing $608 million of notional senior unsecured debt at a 20% weighted average discount reducing total debt by $120 million. The par value of the remaining 2021’s plus 2022 maturities is $1.491 billion. The market value of the remaining 2021 and ‘22 senior notes net of what has been repurchased today is shown on the right hand side of the page and totals $1.104 billion. As you can see, due to its broad range of assets and natural gas rather than oil focus, AR should be well positioned with sufficient capacity to repay its near-term maturities. In addition, continues to focus on asset sales, cost reductions and other opportunities to enhance this liquidity position.
Before turning the call over to Dave, I would like to briefly walk through AR’s updated hedge position on Slide #5 titled enhanced natural gas hedge position. AR has continued its consistent hedging program and taken advantage of the natural pricing strength on the back end of the curve. During the first quarter, AR added 688 MMBtus a day of gas hedges at an average price of $2.48 per MMBtu. As depicted on the slide, AR is 94% hedged on its expected 2020 natural gas production and 100% hedged on its expected natural gas production in 2021. In addition, we expect AR to continue to proactively hedge volumes in cal ‘22 and beyond as prices continue to improve.
In addition, Antero is 100% hedged on its 2020 oil and C5+ production at an oil price equivalent of $55.63 per barrel. Dave will discuss the Northeast storage situation and impacts from COVID-19 on the NGL and condensate markets, but these hedges provide significant price protection for AR’s liquids production. This consistent approach to hedging drives development plans stability across commodity price cycles, which in turn benefits AM.
With that, I will turn the call over to Dave.
Thank you, Paul. I’ll begin by providing an update on in-basin condensate market dynamics. The COVID-19 pandemic and the nationwide stay-at-home order have severely impacted demand for transportation fuels, resulting in a dramatic decline in refinery runs. We have in turn witnessed a reduction in purchases of Appalachian oil condensate from the traditional buyers in the basin. Prior to the COVID-19 pandemic, Antero had developed a diverse set of buyers and sales points, as well as off site storage capacity. Since then, we have expanded our customer base and nearly doubled our in-basin storage capacity. To date, AR has not had to shut-in or curtail any production as a result of storage constraints.
We are confident today that we have the firm sales and storage in place to produce our wells at full capacity at least through the summer. Due to the proactive steps taken at Antero to secure additional oil storage and sales, we expect that regional and national demand will be restored to a great extent before we would see any significant impacts to our production. Importantly, AR is 100% hedged on its oil and pentane production, the two products most impacted by COVID-19 demand disruption at an average price of $55.63 per barrel. There is still uncertainty about how long stay-at-home mandates will remain in place and therefore reduced demand, but we are set up to weather the storm with minimal impact to our production for a prolonged period.
Now let’s turn to Slide 6 and discuss the NGL macro environment. The COVID-19 pandemic has not impacted global demand for NGL products nearly as much as it has impacted demand for transportation fuels derived from oil. The restarted economic activity in Asia, coupled with lower LPG production from refineries in the U.S. and abroad, has led to strengthening prices for LPG on a relative basis to WTI as shown on the left-hand side of the page. NGL prices have decoupled from WTI prices, highlighting the inelastic global NGL demand from petrochemicals and residential commercial markets, further supported by government subsidies in countries like India. This is particularly evident as the C3+ NGL percent of WTI ratio has nearly doubled since February and the strengthening has occurred during the shoulder season when NGL prices are historically the weakest. The right-hand side of the page illustrates Asia propane prices, which have already bottomed and continue to recover as economic activity resumes.
Importantly, Antero was well positioned with its access to international markets through Mariner East 2, where we have not seen any impacts on our ability to export LPGs. As a reminder, Antero has the ability to adjust our cargo destinations based on the most favorably priced markets which has included taking advantage of strengthening prices in Asia. LPG prices in Europe have been slower to recover as economic activity has yet to return in a meaningful way and storage levels remain elevated. Consequently, Antero is targeting Asia destinations with our discretionary cargoes. Meanwhile, AR has hedged essentially all of its projected 2020 propane exports to Europe at $0.55 per gallon, net of shipping or 37% above current strip prices.
Moving to the supply side of the equation on Slide 7, the expected decline in North American oil production is anticipated to result in a significant reduction in associated NGL production. Everyone is familiar with the associated gas story, that is gas production associated with oil production, but the impact of the decline in associated NGLs is expected to be even more pronounced as we move into next year. This rollover in NGL supply results in sufficient LPG export capacity for the foreseeable future that has historically constrained U.S. NGL pricing and production as illustrated on the right-hand side of the page. We expect this to result in a strengthening of domestic NGL prices toward Brent-linked international prices over time.
For several years now, the U.S. has been critical to global LPG markets, responsible most recently for supplying well in excess of 50% of the world’s waterborne LPG imports and growing. In our most recent NGL fundamentals analysis updated last quarter, the U.S. was needed to provide an incremental 445,000 barrels per day of LPG to world markets by 2022 to satisfy global growth driven by the residential, commercial and petrochemical markets. With both U.S. and OPEC+ NGL production anticipated to be in decline over this timeframe, the backdrop for NGLs begin to look similar for the scenario we saw play out for 2017 and 2018 resulting in strong NGL prices precipitated by a period of low oil prices and declining U.S. production.
With that, I will turn it over to Mike.
Thank you, Dave. I will begin my AM comments with first quarter operational results beginning on Slide #8 titled year-over-year midstream throughput. Starting on the top left portion of the page, low-pressure gathering volumes were 2.7 Bcf per day in the first quarter, which represents a 6% increase from the prior year quarter. Compression volumes during the quarter averaged 2.5 Bcf per day, a 12% increase compared to the prior year. Our 50-50 joint venture gross processing volumes averaged 1.3 Bcf per day a 33% increase compared to the prior year quarter. Processing capacity was 95% utilized during the quarter. JV gross fractionation volumes averaged 33,000 barrels per day, a 50% increase from the prior year and freshwater delivery volumes averaged 183,000 barrels per day, a 20% increase over the prior year quarter.
During the first quarter, AR averaged over 7 completion stages per day which was ahead of budget and resulted in stages originally scheduled for the second quarter to shift into the first quarter. As a result, we expect the reduction in completion activity combined with the schedule shift to result in the decreasing freshwater delivery volumes in the second quarter of 2020.
Moving on to financial results, adjusted EBITDA for the first quarter was $217 million, a 7% increase compared to the prior year quarter. Distributable cash flow for the fourth quarter was $164 million resulting in a DCF coverage ratio of 1.1x. Capital expenditures during the quarter were $80 million, a 56% decrease compared to the first quarter of 2019. During the first quarter, we generated $99 million of free cash flow before dividends compared to an outspend of $2 million last year. As depicted on Slide #9, AM has reached an inflection point of generating free cash flow in 2020 as we leverage our existing midstream infrastructure. Free cash flow generated in the first quarter places us on track to achieve our increased free cash flow guidance of $420 million to $450 million for the full year 2020.
Moving on to balance sheet and liquidity on Slide #10, as of March 31, 2020, Antero Midstream had $1.17 billion drawn on its $2.13 billion revolving credit facility resulting in approximately $1 billion of liquidity. Additionally, AM’s net debt to LTM adjusted EBITDA was 3.7x at quarter end. Importantly, AM’s nearest senior note maturity isn’t until 2024 and it has an attractive term debt structure over the next several years.
I will finish my comments on Slide #11 that summarizes the guidance we announced yesterday. AM is well-positioned to adapt to the uncertainties in today’s environment, with leverage over a turn lower than the peer average and approximately $1 billion of liquidity. Further, we have $420 million to $450 million of free cash flow before return on capital, which gives us tremendous flexibility. Paul mentioned we have the benefit of real-time information from our primary customer, which allows us to quickly adjust our capital program and be one of the most capital efficient midstream companies in the industry.
As a result, we have taken over $85 million out of our 2020 capital budget alone and will continue to flex our capital budget up or down in response to AR’s development plans. Antero Midstream does not have any long cycle time projects that result in an inflexible capital budget. And as a result, our leverage is expected to stay in the mid to high 3x range. These capital budget reductions more than offset the change in our adjusted EBITDA guidance which resulted in an improved free cash flow profile by $35 million at the midpoint or 9% improvement. Unlike a lot of GP&T peers, AM is not facing declining throughput and uncertainty from oil shale plays. Further, we have not had any operational or throughput issues to-date as a result of COVID-19, but we continue to monitor our guidance and capital budget and ensure we maintain our financial strength and flexibility.
In summary, we continue to be pragmatic and diligent in response to the current uncertainty driven by the COVID-19 pandemic. And I’d like to thank all of our employees for their dedication during these unprecedented times. With that, operator, we are ready to take questions.
Thank you. [Operator Instructions] Our first question comes from Kyle May with Capital One Securities. Please state your question.
Good morning. I’d like to start with the…
Hi, Kyle.
The fresh water side of the business. You talked about 20 well completions will be pushed into next year. Can you talk about your expectations for wells that would be serviced with fresh water in the second quarter of this year and then kind of the cadence for the balance of the year?
Yes. Obviously, when we service the fresh water that’s ahead of the completions, so on AR’s call we talked about how we did 25 wells completed in the first quarter and about 45 in the second. So a lot of that water was pushed into the first quarter, so the water does come down. Looking ahead into the second half of the year, AR is going to complete approximately 30 to 35 wells. So the second quarter will be down from that. So we’ve got about 35 to 40 wells in the first quarter and it goes down to about 20 in the second.
Got it. Okay, that’s helpful. And then also on the Antero Resources call, it sounded like you were leaning towards a maintenance mode for 2021. If that plays out as expected, what kind of CapEx which would you need at Antero Midstream to support that level of activity?
Yes. Looking out, the CapEx this year is $215 million to $240 million, the average is about $200 million, and ‘21 is kind of where we’re at. Our CapEx continues to decline and also hopefully we can work that down from there. But about $200 million is our estimate.
Got it. And the last one, if I can. Previously you have talked about doing more water recycling in the field after you idle to Clearwater Facility. Can you give us an update on this program and how we should think about the mix of activity between infield recycling and outsourcing to third-party for the balance of the year?
Well, our infield recycling has been very successful. Our goal is 100% recycling. We’ve hit that a number of times, but typically we are anywhere from one-third up to 60% flow back water. Our teams – water teams have made great efficiency improvements. So that’s going along real well. And we feel very good about the path that we’re on.
Okay, that’s helpful. That’s all from me. Thank you.
Thank you. Our next question comes from Tarek Hamid with JPMorgan. Please state your question.
Good morning. I wanted to ask quickly about how you’re thinking about the balance sheet right now, given both for puts and takes on CapEx as well as the distribution. You’ve talked about the 3 to 4 times leverage ratio as kind of being your target. You’re certainly within there now. Is it sort of fair to say, that remains the target?
Yes. No, we feel good about it. Like I mentioned, we are at 3.7x and we see that kind of a level that we sustain over the next couple of years.
Alright. And I guess as you think about your liquidity currently, obviously you’re a little bit drawn on the revolver now, sort of, how do you think about the right number of liquidity at AM to run the business on a go forward basis, kind of, given all the uncertainty?
Yes. We have $1 billion. That’s ample liquidity. We don’t really draw much on the credit facility on a go-forward basis. We have evened out that maintenance capital for AR, we have continued EBITDA growth into 2021 and our capital continue to decline. So you really don’t draw much going forward. So having $1 billion liquidity plus or minus feels good.
Got it. And then just last one from me, as you think about just the return of capital, sort of, how do you balance distributions versus share repurchases? Obviously, you’ve used a lot the last 12 months. And just wanted to get a sense of how you are thinking about that mix going forward?
Yes. We have about $150 million left on our repurchase program. Obviously, where the equities are at right now, it’s attractive to us. So that’s why you saw us being active in the first quarter. I would think, we would continue to be active on that going forward to kind of similar levels that we had in the first quarter. So we like buying back shares at these prices.
Got it. That’s it from me. Thank you very much.
Thanks, Tarek.
Our next question comes from Sunil Sibal with Seaport Global Securities. Please state your question.
Yes. Hi, good morning, guys.
Hi, Sunil.
And thanks for all the clarity. I just had one quick question. So when we look at the guidance that you’ve given versus what you reported in Q1, so it seems like you will have some headwinds in for the remainder of the year. Is that all primarily driven by the water segment and completion activities there or are there other – any other factors which are driving that?
No, it’s just the water. The throughput is as expected. AR’s guidance is the same for 2020. So it’s really just a deferral of those 20 wells completions since obviously it would have been completed with our water system in 2020 being deferred into ‘21.
Okay. And the fact that you did much higher completions in the Q1 kind of pulled in some of the revenues forward?
That’s right, yes.
Got it. And then one on the capital allocation kind of framework, so if the conditions you know were to deteriorate in terms of commodity pricing etcetera, or reflect on AR’s plants, I was wondering, is 4x kind of leverage the max that you let it run to, before you take a hard look at returning cash to shareholders or how should you think about or how should we think about that variability in the leverage versus your goals of returning cash to shareholders? Thanks.
Yes, it’s not a max of our financial policies to go up 4x. It’s hard for me to even envision a case where it goes higher than that. I think you’ve seen how flexible the capital at AM is. So if AR’s capital is less, then AM is going to have much less capital as well. So being fixed fee have acreage dedication. It’s a very stable business. So – and that just-in-time portion and not having any inflexible capital really bodes well for AM. So I just – I don’t really see how it could go above 4x, but our financial policy is to not exceed that. But we’re in good shape.
Okay, thanks.
Thanks, Sunil.
Thank you. Our next question comes from Jeremy Tonet with JPMorgan. Please state your question.
Hey, Jeremy.
Hey, good morning guys. This is James on for Jeremy. If I could just start with maybe the incentive fee program I think when you guys released that back in December, that was kind of built around an 8% to 10%. Production growth from Antero on that – it seems to be – have changed with the message this morning. Can you share any updated thoughts there?
Yes, no, it’s working well. We designed that in the summer for incentive growth for AR and as you know, the first 6 months at 2.7 Bcf per day in the low pressure and AR was able to deliver 2,717, so they hit that plan and there is growth from AR in the second and third quarter. So we do see them achieving those growth incentive fees in the first three quarters. So we have that $36 million rebate in our guidance. So it’s working as planned. I think we’ll see how the year progresses and where the volumes go. They could potentially hit the fourth, but that’s yet to be seen, but right now it’s working as planned.
Got it. Thanks. And then similar to the same question, but looking at the 2021, the broader implications there for Antero Midstream, given the maintenance mode scenario that you guys are running at AR, directionally, where should we think about – given the situation is fluid and there’s a lot of moving pieces, but directionally where should we think about Antero Midstream’s outlook there?
No, it’s good. As I mentioned, our EBITDA is still growing. You are still – even maintenance capital you’re still growing on AM dedicated lands. So our EBITDA is still growing in 2021, couple of percent. So, definitely, it’s come down from the high-single-digits to low-single-digits, but still growing and then our capital continues to decline, so, I see, actually, capital next year lower than 2020. So that free cash flow profile is actually increases in ‘21. So it looks good for AM.
Great, thanks. That’s helpful. I appreciate the color.
Thank you.
Our next question comes from Gregg Brody with Bank of America. Please state your question.
Hey, Gregg.
Hey, guys. Good to talk to you again. So, you mentioned the refund from AM – AM would pay to AR, how is that going to flow through just the financial statements? How should we think about that?
It’s just a $12 million reduction in the fees. So it will be – you wouldn’t see it, we’ll just have $12 million less of LP revenue.
Okay, and then that would – so for on the AR side it would just be a lower cost.
Right. It’s just lower in TP and T-line item.
Got it. And you also mentioned – I didn’t jump into this on the credit facility, but since you’ve been talking about AR for quite a bit, what – there is some flexibility, it sounds like you’ve mentioned in the press release, and if you look through the amendment, you can see there is flexibility for sales. How – for certain sales, how do you design the credit facility changes to allow for sales? What’s – how much can you actually sell without liquidity on the AR facility coming down?
Yes, I will – first thing to note is when you think about the asset sales, it’s the borrowing base impact. It’s not the actual proceeds. And if you can imagine, the price decks that the banks use, there wasn’t really much on development – on developed value – pipe value. So not only do we have flexibility in those baskets that you’re referring to quite a bit, but it’s really around the borrowing base amounts. So that provides us a lot of cushion. And then the fact that we’re $210 million above the actual credit facility amount of $2.85 billion to $2.64 billion obviously is a cushion that we can capitalize on as well. So we have quite a lot of leeway and have been able to do the asset sales without impacting liquidity.
Got it. So, you didn’t take the assets and merge from the borrowing base.
No. Those were already existing asset buckets. They were just – we put in a mechanism that not only asset sales, now we can offset it with any further hedging or further PDP wells that come on over that same timeframe. So there is an interesting mechanism there that nets those values from the hedges in the PDP wells against any asset sales. So that was a nice improvement.
And I noticed, I think the value of AM is in that as well.
Right.
Is that.
Deconsolidated. It’s our first credit facility that’s deconsolidated. So AM’s shares are pledged underneath that credit facility. So any sale would count as an asset sale.
Got it. And then, you’ve – I think you’ve – there is some, in both press releases there is mention of evaluating your return to shareholders through dividends and share repurchases. It seems like what we’ve talked about on this call is you’re comfortable with your leveraging your liquidity. So are you thinking about that today, potentially changing your return to shareholders or was that just a general statement that you’re making just as a part of the – what you’re just telling investors could happen, but not necessarily a near term.
I think you hit it on the first part. We feel good about our position. We’re out with our liquidity and balance sheet and knowing our sponsors plan. And so we-which is kind of impressive that AM can actually provide guidance when most are withdrawing their guidance. So we’re in good shape and we feel good about it. But with that said, we are kind of in un-chartered territory around this COVID-19. We think we have a lot of visibility in our plans, but we just wanted to flag that there’s obviously a lot of uncertainty in the market. So, like we always do, we sit down with the Board every quarter and assess where we’re at and we’ll do the same this next July and we’ll know a lot more then. But right now we feel good about it.
And last question for you. The Clearwater facility, I know there’s a lot going on right now in the world and I’m curious if there is any developments on potentially capturing some value from that.
No, we don’t have anything. I think you saw update, we are in litigation with and we’ll pursue that vigorously, but outside of that, which has been shutdown and we shouldn’t really have any more facility expenses with that, maybe a couple of million for the remaining 9 months. So, that should really tail off which will help the profile as well.
Got it. Well, thanks for giving us all your time over the last two calls guys. I appreciate it.
Yes.
Thanks, Gregg.
Our next question comes from Ned Baramov with Wells Fargo. Please state your question.
Hi and thanks for taking the question. Could you maybe elaborate a little bit more on the joint effort by AR and AM to mitigate NGL storage capacity issues in the Northeast? Maybe if you can talk about some of the initiatives you are pursuing to ensure that you have ample storage capacity after this summer?
Yes, good question. So, we have our storage in the field level at the pads in the compressor stations and alike. We also – Antero Resources has been able to market its volume at other locations along the Ohio Valley on the river. And so we have had positions in facilities along that corridor there and have been able to secure capacity at those facilities. That’s really it for the oil piece on the NGL side. There has really been no challenges to really speak of around moving NGLs over here over the last couple of months. There is a significant amount of storage capacity at Marcus Hook, some several million barrels of propane as well as some underground storage on top of that, but vessels continue to come to that facility given some of the geographical advantages they have. And so, we have seen no new challenges on the NGL front or a reason to go out and secure additional NGL storage capacity at this time.
That’s helpful. Thank you. And then maybe just a housekeeping item, could you quantify the percent of revenues that are derived under minimum volume commitment contracts, which I believe relate to the high-pressure gathering and compression assets?
Yes, I don’t have a number for you like you mentioned its 70%, 75% for compression and high-pressure and then it’s also 70% on the processing JV. So and those were for compression and high-pressure for projects after post the IPO. So it’s not quite that much, but those are the MVCs we have and we don’t have many MVC volumes at all, yes.
Got it. That’s all I had. Thank you.
Thank you.
Our next question comes from Ethan Bellamy with Baird. Please state your question.
Hey, guys. Good morning. Just had a few for you. Is there a bogey at AR in terms of asset monetization or down to ‘21s or to ‘22s where AM would be in a position to pay a more sustainable yield?
We have a $900 million bogey at AR, but that doesn’t really influence the yield at all for AM. AM is looking at the underlying fundamentals of cash flows, but AR does have a $900 million at the top end of their range, which is not needed at all really for ‘21s and ‘22s. It’s just generally to get the leverage down into the low 2x.
So keeping the distribution at the dividend to AM where it is would imply you think that stock price ought to double or triple from here then to make it more reasonable cost of equity?
Yes, we don’t really look at the markets for that, but that’s for you to say, I think Ethan, but I like the way you are thinking.
Okay. Have you seen any international LNG buyers or middlemen trying to bottom the shale market here?
No. We have our firm sales at Cove Point, at Sabine Pass and at Freeport. And those we have not seen what you are talking about, the cargoes sale as per the schedule, the buyers are there. So, I have not seen any hesitation or interruption in the planned schedule.
And I think that you guys are probably good in the short-term on all the permitting work for infrastructure, particularly with the slowdown, but do you anticipate any sort of medium or long-term problems with the Army Corp Engineers for permitting issues?
No, not at all. We have a really good relationship with the permitting regulatory agencies, both on the federal and the state level. We, like all of oil and gas in West Virginia and Ohio, are considered essential in the context of COVID-19. But we’re also just important as an activity base, an employment base, a tax base. And so they are important to us. We are important to them and we haven’t seen any permitting slowdowns or hang-ups.
And last question, do you guys have any insight on the timing of the cracker where you are the anchor shipper?
Nothing that we could say at this time.
Okay. Thanks, guys. Good luck.
Thank you.
Our next question comes from Chris Tillett with Barclays. Please state your question.
Hey, guys. Good morning. I guess the first from me would be, can you just provide a quick update on the build-out at Smithburg, given what looks like now a possibility for entering maintenance mode in 2020 and beyond?
Yes. We have two plants planned. The first one comes on agenda this year and the second one, next year.
Okay, but nothing beyond that. I mean, I know that at one point, you had said there is possible I think up to 6, but at the moment nothing beyond those 2 at this point?
Not over the next couple of years, that’s right.
Okay. Okay, thank you. And then maybe more of an AR question. Gas prices have improved pretty materially here over the last month or so. If things continue to look better through the remainder of this year and into next year, do you think from an AR perspective, they might look to take advantage of that and produce more or is it a situation in which maybe you are happy with your production plans and would just harvest some of the cash flow to repair the balance sheet?
Yes, I think the latter. We’re quite capital disciplined and don’t plan to flex with the move in commodity prices and certainly not the next year or two.
Okay, that’s it for me then. Thanks, guys.
Thank you.
Thanks, Chris.
Ladies and gentlemen, that is all the questions that we have for today. I’ll turn it back to Michael Kennedy for closing remarks. Thank you.
Thank you for listening to our first quarter conference call. If you have any further questions, please feel free to reach out to us. Thanks again.
Thank you. This concludes today’s conference. All parties may disconnect. Have a great day.