Greetings, welcome to the Antero Midstream second quarter 2020 earnings conference call. At this time, all participants are in a listen-only mode. A question and answer session will follow the formal presentation. If anyone should require operator assistance during the conference, please press star zero on your telephone keypad. Please note that this conference is being recorded. I will now turn the conference over to our host, Michael Kennedy, Chief Financial Officer. Thank you, sir. You may begin.
Thank you for joining us for Antero Midstream's second quarter 2020 investor conference call. We'll spend a few minutes going through the financial and operating highlights, and then we'll open it up for Q&A. I would 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 David Cannelongo, the Vice President of Liquids Marketing and Transportation. With that, I'll turn the call over to Paul.
Thanks, Michael. I'd like to start by discussing AR's asset sale program, which continues to improve AR's liquidity position and will allow it to repurchase debt at attractive discounts to par. Slide three, titled AR Asset Sale Program Update, details the progress that AR has made to date on its $750 million-$1 billion asset sale program. During the fourth quarter of 2019, AR commenced its asset sale program with the sale of AM shares to AM for $100 million. Despite the ongoing COVID-19 pandemic, AR was able to execute a $402 million overriding royalty interest sale in the second quarter of 2020, including $300 million of upfront proceeds and $102 million of contingent payments. In July, AR monetized excess 2021 natural gas hedges for proceeds of $29 million. This brings AR's total completed asset sales to $531 million.
These asset sales have allowed AR to reduce total debt by approximately $365 million since commencing the asset sale program in the fourth quarter of 2019. In addition, AR is in active discussions for further asset sales, and we remain confident that we can achieve the $750 million-$1 billion asset sale target in 2020. We believe this positions AR to repay its 2021 and 2022 maturities and significantly de-risks the Antero complex. Before moving on to AR's liquidity position, I want to briefly touch on AR's hedge position pro forma for the recent monetization on slide number four, titled Enhanced Natural Gas Hedge Position. In the second half of 2020, AR is 94% hedged on natural gas production at a price of $2.87 per MMBTU. Due to the overriding royalty interest sale, AR was previously over-hedged on its 2021 natural gas production.
As a result, AR monetized 100 BBtu per day of excess, quote-unquote "hedges" above its 2021 natural gas production for a gain of $29 million. These proceeds were used to continue repurchasing debt at attractive discounts to par. Pro forma for the monetization, AR is approximately 100% hedged on its 2021 natural gas production at $2.77 per MMBTU. AR was also active in the second quarter and added 620 BBtu a day to its 2022 natural gas hedge position, which now stands at 1,300 BBtu a day. This is consistent hedging and allows AR to maintain a stable development program. Slide number five, titled 'Substantial Liquidity Enhancements at AR,' shows the liquidity impact of the asset sale program and significant drilling and completion capital savings achieved to date.
First, as a reminder, AR's borrowing base under its credit facility was confirmed at $2.85 billion in April, well in excess of lender commitments of $2.64 billion. As of June 30, 2020, AR had approximately $1 billion of liquidity, which is depicted on the dark green bar on the left-hand side of the page. Based on today's strip prices, AR's development plan is expected to generate $200 million of free cash flow in the second half of 2020, further improving its liquidity position. This ability to generate free cash flow is driven by the significant capital savings and improvement in NGL prices in the second half of 2020, which David Cannelongo will discuss in his comments.
Assuming execution of the remaining sales at the high end of AR's targeted asset sale program of $469 million, AR would have $1.7 billion of liquidity at year-end 2020, prior to any further bond repurchases. This is more than sufficient to repay both the 2021 and 2022 maturities, which have a total par value of $1.26 billion and market value of $1.04 billion. With that, let me turn it over to David Cannelongo, our Vice President of Liquids Marketing and Transportation.
Thanks, Paul. Let's turn to slide number six and begin by discussing the NGL macro environment. The effects of COVID-19 on oil and transportation fuel demand and the resulting decline in rig and completion crew activity in oil-focused shale basins has set up expectations of a prolonged period of depressed US oil production. More notably, this backdrop results in depressed associated NGL production relative to the volumes that were being produced and fractionated just prior to the onset of COVID-19 around the world. The chart on the left-hand side of the slide illustrates that NGL supply forecasts have declined by over 1 million barrels a day since the beginning of this year.
Further, it highlights that it may take several years for US NGL production to return to pre-COVID-19 levels, as the momentum of production declines from the dramatic slowdown in US shale activity over the last four months plays out. The chart on the right-hand side of the slide highlights that sufficient export capacity along the Gulf Coast has helped clear the domestic market and tightened Mont Belvieu pricing to international pricing. Turning to slide number seven, titled "NGL Price Recovery Expected," we can see that the strength of NGL markets relative to WTI and Brent has continued to stay elevated as a result of more resilient petrochemical and residential commercial markets during this pandemic. Here we illustrate the outperformance of Mont Belvieu propane relative to WTI in 2020.
On the right, we see a similar outperformance in propane relative to Brent at the Far East Index, or FEI, which is the benchmark in Asia. This is important as Antero has exposure to not only domestic NGL markets, but also international destination pricing through our export access on the Mariner East system. While the fundamental backdrop for NGL prices is set up for improved pricing as we head into next year, the limited liquidity in the futures markets for such products does not always reflect the anticipated value further out the curve. Put another way, there is typically very little correlation between the future strip and the out-years in the ultimate physical price.
Slide number eight, titled "NGL Pricing Outlook," illustrates the value that some third-party analytical teams, including the Citibank commodities team shown here, are placing on NGLs in 2021 and beyond based on their bottoms-up global supply-demand models. Looking more closely at the Northeast takeaway capacity, slide number nine, titled "Northeast LPG Supply and Demand," highlights the reason for a tightening of the Northeast differentials to Mont Belvieu for LPG that has resulted from the Mariner East project. The increase in takeaway capacity out of the Marcus Hook terminal through Mariner East led to markedly improved in-basin pricing relative to Mont Belvieu. Marcus Hook has the capacity to evacuate in excess of 225,000 barrels per day of LPG from the basin through exports, helping support Northeast domestic LPG prices.
The anticipated final completion of the Mariner East 2 pipeline system this winter, taking ME2 capacity to 275,000 barrels a day, will create ample capacity to export Northeast NGL production for the next several years, and we anticipate in-basin differentials to remain tight to Mont Belvieu going forward. With that, I will turn it over to Michael.
Thank you, David. I'll begin my AM comments with second quarter operational results beginning on slide number 10, titled "Year-over-Year Midstream Throughput.
Starting in the top left portion of the page. Low pressure gathering volumes were 2.9 Bcf per day in the second quarter, which represents an 8% increase from the prior year quarter. Compression volumes during the quarter averaged 2.7 Bcf per day, a 13% increase compared to the prior year. During the second quarter, AM placed online a new Marcellus compressor station, adding 240 million per day of capacity and supporting the compression volume growth in the quarter. AR's compression capacity was 91% utilized during the second quarter of 2020. Our 50/50 joint venture gross processing volumes averaged 1.4 Bcf per day, a 42% increase compared to the prior year quarter. Processing capacity was 100% utilized during the quarter. JV gross fractionation volumes averaged 33,000 barrels per day, a 22% increase from the prior year.
Freshwater delivery volumes averaged 102,000 barrels per day, a 16% decrease from the prior-year quarter. The reduction in freshwater delivery volumes is driven by AR moving to one to two completion crews during the quarter, as we discussed on our first quarter conference call. AR is currently operating two completion crews on Antero Midstream dedicated acreage. Moving on to financial results. Adjusted EBITDA for the second quarter was $201 million, a 2% decrease compared to the prior-year quarter. During the quarter, Antero Midstream only received two monthly joint venture distributions compared to three monthly distributions received in prior quarters, resulting in a $7 million reduction in adjusted EBITDA. Distributable cash flow for the second quarter was $152 million, resulting in a DCF coverage ratio of one times.
Capital expenditures during the quarter were $59 million, a 63% decrease compared to the second quarter of 2019. During the second quarter, we generated a company record, $108 million of free cash flow before return of capital, compared to just $15 million last year. Moving on to the balance sheet and liquidity. As of June 30th, 2020, Antero Midstream had $1.16 billion drawn on its $2.13 billion revolving credit facility, resulting in approximately $1 billion of liquidity. AM's total debt was flat quarter-over-quarter at $3.1 billion as a result of the improved free cash flow profile, as well as receiving $39 million of the $55 million cash tax reimbursement under the CARES Act.
Looking ahead to the back half of 2020, we expect capital expenditures to continue to decline, driving increasing free cash flow before return of capital. As a result, we expect AM's total debt to remain relatively flat at $3.1 billion for the remainder of 2020. I'll finish my comments on slide number one titled Inflection Point of Generating Free Cash Flow. This slide depicts just how far we've come since our IPO in 2014, where we outspend cash flows by approximately $600 million before return of capital. In 2020, we are now at the point of harvesting those five years of capital discipline investments and leveraging our core gathering, processing, and water infrastructure.
We have stayed true to our discipline capital investment philosophy and not made any extensive acquisitions or investments in downstream opportunities that did not meet our return thresholds or tied up capital in long lead time capital projects. Our just-in-time capital investment philosophy and capital discipline has allowed us to reduce our capital budget by over $100 million in 2020 and target $445 million-$475 million in free cash flow before return of capital. This continued downward momentum in capital spend and our stable fixed fee earnings allows AM to maintain a strong and flexible balance sheet. I'd like to finish the call by thanking all of our employees who safely delivered an exceptional operational quarter with no material curtailments despite all of the ongoing uncertainty and challenges surrounding the COVID-19 pandemic. With that operator, we are ready to take questions.
Thank you. Ladies and gentlemen, at this time, we will conduct our question and answer session. If you would like to ask a question, please press star one on your telephone keypad. A confirmation tone will indicate that your line is in the question queue. You may press star followed by the number two if you would like to remove your question from the queue. For participants using speaker equipment, it may be necessary to pick up your handset before pressing the star keys. Our first question comes from Jeremy Tonet with J.P. Morgan. Please state your question.
Hi, good morning.
Hi, Jeremy.
Just want to start off with capital allocation philosophy, if I could. It seems like even if the third JV payment for the quarter came through, the coverage on the distribution would have been pretty tight this quarter. Just wondering, when it comes to return of capital philosophy, paying a 22% yield versus increasing share repurchases or paying down debt. Just want to see what goes into this distribution level as opposed to reducing it to pursue one of those other avenues. It seems like it could be more accretive to buy back units at this point.
Jeremy, we stated our coverage ratio kind of range from the start in 2014. It's around 1.1 times. If you did do that $7 million, you would've been at that 1.1 time. The quarter was well within our expectations and our philosophy on paying the dividend. The other thing that influences that is when you look at our free cash flow, plus that tax payment, there was no leverage added during the quarter. The return of capital and the dividend was within our free cash flow. We look at that as well. We look at our capital budget too. It's just in time. There's no long lead time, and it's decreasing. That free cash flow increases over the next couple of quarters. That will support the dividend payments. You look at our leverage.
Of course, we're in the mid 3x, very strong balance sheet compared to our peers. All of those factors go into when we determine the dividend, and we're comfortable with the level that it was at.
Got it. Yeah. Just in terms of the absolute level of yield, the 22% seems a bit high there. I just didn't know if there was a certain level of accretion that could be achieved on repurchases where it might make sense to pivot in that direction or if that goes into your thought process in any way.
No. We expect the equity to perform better over time and that yield to come down to match the dividend. It was a volatile quarter and obviously, there was some weakness in the whole industry. I don't think that yield is reflective of the true underlying fundamentals of the business.
Got it. Thanks for taking my question.
Thanks, Jeremy.
Thank you. Just a reminder, to ask a question, press star one. We'll pause for a couple of moments to pull for questions. Once again, to ask a question, press star one. Our next question comes from Holly Stewart with Scotia Howard Weil. Please state your question.
Good morning, gentlemen. Maybe just one or two from me. Michael, it looks like the processing capacity was 100% utilized during the quarter. Could you just remind us of the schedule there?
Yeah. Smithsburg 1 is the next plant. Sherwood's at capacity with 13 plants, that was at 100% capacity. Smithburg 1 is almost entirely complete, that should come on either later this year or into 2021. With that said, AR is kind of at a maintenance capital. They produced around 3.5 Bcfe a day in the second quarter, there's not much growth going forward. Sherwood right now has the ability to handle. It's flowing at above nameplate, still has the ability to handle the volumes.
Okay, great. Maybe one for Paul or Glen, just we saw the take-in transaction earlier in the week with CNX and CNX Midstream. Just kind of curious your thoughts there.
I think same here. We share the curiosity. It will be interesting to watch that transaction. We certainly looked at a combination of AR and AM when we went through the simplification in 2018. As you recall, that was a lengthy process with lots of different outcomes analyzed, the decision was made for Antero really to separate the governance and convert AM from an MLP into a C corp. Our situation is not really analogous to that. We will watch the CNX situation, like we said, with curiosity. Further, AM is just a much bigger midstream business relative to AR upstream, compared to CNX and CNX Midstream. Curious situation. Be interesting to watch.
Yeah, maybe the vice versa. AM taking in AR.
It's actually our idea.
It's all I had. Thanks, guys.
Yeah. Thanks, Holly.
Our next question comes from Ned Baramoff with Wells Fargo. Please state your question.
Hi. Thanks for taking the question. A two-part one on the JV distribution. First, could you maybe talk about the reason for only two monthly distributions being received by AM? Second, it seems the distributions for the two months were $19 million, which would imply $nine and a half per month, while you quantified the impact to EBITDA for the third month to be about $7 million. If you could just talk about the step-down in monthly distributions from the JV.
It's just simply a timing issue. We only book them when we actually get paid, received. We only received two. One of these quarters down the road, obviously, there'll be a catch-up payment when we receive four. That was just hard to predict. On the $19 million versus the $7 million, it's generally around that $21 million a quarter for the three months. When we budgeted it, we budgeted it at $7 million a month. That $7 million probably was where the volumes were at right now, in excess of where we had forecast. Probably would've been more around that $9 million- $10 million. When we just highlight the $7 million, that was actually what was in the forecast.
Got it. That's helpful. Maybe just switching gears on your supply-demand analysis of the North American gas market. Maybe could you just talk about your view on the development of the Haynesville as opposed to the Northeast to fill in the supply reduction from declining production in most other basins?
Well, I think we've seen the decline in Haynesville. I think the latest numbers I saw was 13 Bcf a day. It went to under 11 Bcf a day out of the Haynesville in just the last few months. What is the reason for that? Don't know. We look at the Haynesville as not quite as economic as really the very premium gas basins like Appalachia. Is it just a capital allocation issue? We're following it as well, and we do see it's been a puzzle, I think, to many in the industry as to how the Haynesville has stayed so high. I don't know the exact answer, but I think it probably doesn't surprise industry that much that it's declining relative to some of the other gas places.
Got you. Last one for me, if I may. Are there any updates on the litigation with Veolia that you could share?
There are no updates, no.
Okay, thanks. That's all I had. Thank you.
Thank you. Thanks, Ned.
Our next question comes from Sunil Sibal with Seaport Global Securities. Please state your question.
Yes. Hi, good morning, guys, and thanks for all the clarity. I just wanted to go back to the slide nine in your deck where you talked about the infrastructure build-out and the differentials between, say, Northeast and Mont Belvieu. It seems like second quarter there were a few probably one-time items, and then the regional demand is probably also weak this quarter. In addition to the new infrastructure which you talked about, the pipe and the capacity being expanded, are there other factors that you think would lead to tightening of the Belvieu to the Northeast spread?
Sunil, that's really the primary driver. I mean, the Northeast, its infancy was always at a premium to Belvieu when the market was short NGLs for refinery gasoline blending for the butanes and pentanes, and then propane for the res/com market. Appalachia's grown so much now that we've really needed the export outlet to drain the bath, as you've heard us say numerous times. That's really been the key driver, and the arbs that'll be received out of Mariner East will play a role on what the floor is back in the basin.
We kind of predicted this slide has been shown for some time before Mariner East came online, and now we've witnessed the results over the last year and a half, and it's very much met our expectations of what it was going to do to the floor price in the basin once that was debottlenecked.
I've got it. Could you remind us on the transport side, you obviously have capacity on Mariner East. In terms of locking in the Far East or the European prices, do you have contracts on the shipping side also?
We have indexed sales to the Far East Index and to Northwest Europe, but we have not ourselves actually chartered the vessel. We are predominantly selling FOB, the Marcus Hook dock, but at either a Mont Belvieu ARA or FEI linked price. When you sell versus international index, you can somewhat imply what your shipping cost was and the price that you sold the dock at.
Okay. Got it. One kind of broader question on the leverage and that dividend coverage philosophy. It seems like, I think in the past you've articulated 1.1x-1.2x kind of dividend coverage is where you're comfortable with, and leverage also 3.5x-4x. Obviously you're staying within those kind of broader parameters, at the same time de-risking the overall AR complex or Antero complex. Should we think about you kind of revisiting those parameters at some point of time? Obviously, if we execute on AR kind of debt reduction strategy, considering that the midstream industry overall is kind of moved beyond those kind of numbers and kind of pointing to more conservative parameters on those two criteria.
Yeah, nothing at this time. I think the midstream industry is trying to get down to where our balance sheet already is at, in the mid threes. I do see some of those coverage ratios going higher for other midstream providers, but that's generally because they may have long-term capital projects or other kind of calls on their cash that Antero Midstream doesn't have. Right now we're comfortable in those ranges that you mentioned.
Okay, got it. Thanks.
Thanks, Sunil.
There are no further questions at this time. I'll turn it back to management for closing remarks. Thank you.
I'd like to thank everyone for participating in today's conference call. If you have any further questions, please feel free to reach out to us. Thanks again.
Thank you. This concludes today's call. All parties may disconnect. Have a good day.