Greetings, and welcome to the Antero midstream third quarter 2020 earnings conference call. At this time, all participants are in listen-only mode. A question-and-answer session will follow the formal presentation. If anyone should require operator assistance, please press star zero on your telephone keypad. As a reminder, this conference is being recorded. It's now my pleasure to turn the call over to Michael Kennedy, Chief Financial Officer. Please go ahead, sir.
Thank you for joining us for Antero Midstream's third 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'd 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'll turn the call over to Paul.
Thanks, Mike. I'd like to start by highlighting the progress AR has made on its asset sale program in 2020, beginning on slide number three, titled AR Asset Sale, Refinancing and Debt Repurchase Update. To date, AR has executed $751 million of asset sales, achieving the bottom end of its $750 million-$1 billion asset sale target. These transactions have allowed AR to reduce its near-term maturities by $1.3 billion since initiating the asset sale program in the fourth quarter of 2019 and positions AR to repay its 2021 and 2022 maturities. AR continues to monitor various asset sale markets, and any additional proceeds will be used for further debt reduction. The current natural gas and NGL fundamentals continue to look encouraging as we head into 2021, as Dave Cannelongo will discuss in his comments.
This further supports upside to AR's free cash flow profile, driven by the scale AR has achieved over the last several years. To put it in perspective, as the second-largest NGL producer in the U.S., every $5 per barrel change in C3+ NGL prices improves AR's annual cash flow profile by over $225 million. On the natural gas side, AR is 100% hedged in 2021, but the improving gas strip increases AR's underlying value and opportunity set. Now let's turn to slide number four, titled AR Firm Transportation Provides Stability. The red line in the chart represents the Appalachian basis differential, which has averaged $0.82 below NYMEX going back to 2014. AR's premium FT, firm transportation, has delivered a $0.05 discount to NYMEX over that same timeframe.
It is also worth noting that since AR has had access to its entire FT portfolio in 2018, it has been able to realize a $0.06 premium to NYMEX to date. During the third quarter, this benefit was even more pronounced as Appalachian basis differentials blew out and regional prices traded at $1.50 below NYMEX. As depicted on the slide, AR's FT portfolio provides pricing stability and production flow assurance, de-risking AR's business model. It effectively provides an insurance policy that protects physical gas flow and allows AR to hedge liquid NYMEX Henry Hub prices. This has allowed AR to avoid shut-ins and curtailments experienced by other peers in Appalachia, and in turn, it drives stability and reliability for AM's revenue stream. Lastly, I would like to briefly discuss AM's corporate sustainability report, which highlights our outstanding environmental, social and governance or ESG performance on slide number five.
Since its inception, Antero Midstream has been committed to environmental excellence, and our greenhouse gas intensity is one of the lowest in the industry. Our methane leak loss rate of 0.017% in 2019 was significantly below the ONE Future industry and sector targets of 1% and 0.28%, respectively. Looking forward, we believe natural gas will be key to the energy transition in the coming decades as a complement to renewable energy growth. As one of the largest natural gas gathering and processing midstream companies in the U.S., we are well-positioned to maintain our peer-leading ESG position while striving to improve our metrics even further through our 2025 environmental targets. On the governance front, in 2019, Antero Midstream transitioned away from the MLP structure to a full C-corp structure, significantly enhancing shareholder rights and improving corporate governance.
Our board is comprised of a majority of independent directors, and our compensation plans are based on metrics aligned with shareholder value, including return on invested capital, leverage, ESG metrics, and per share cash flow growth. With that, I'll turn it over to Dave Cannelongo.
Thanks, Paul. Let's turn to slide number six and begin by adding some color on the NGL and LPG macro environment. In the aftermath of the March OPEC Plus price war and the COVID-19 pandemic, the resulting decline in rig and completion crew activity in oil-focused shale basins has set up expectations of a prolonged period of depressed U.S. oil production. Thus far, that is what has materialized: a decline flattening of oil production, which has resulted in a decrease in associated NGL production from the oil-focused plays. The chart on the left-hand side of the slide illustrates that U.S. NGL supply forecasts have declined by 1.1 million barrels per day since the beginning of this year. We believe it may take three to four years for U.S. NGL production to return to pre-COVID-19 levels.
The chart on the right-hand side of the slide highlights the expected surplus of LPG export capacity along the Gulf Coast. Since the start of the shale revolution, we have enjoyed only a handful of periods when ample export capacity has been available. Looking forward, plentiful dock capacity will allow the U.S. to fully access the international markets on a sustained basis, resulting in U.S. Mont Belvieu prices closely linked to international markets. While Antero has enjoyed unrestricted access to these international markets through our Mariner East commitment for nearly two years now, this fundamental change on the U.S. Gulf Coast will benefit Antero's share of NGL production that is sold domestically and linked to Mont Belvieu 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 resilient petrochemical and residential commercial markets during this pandemic. Here we illustrate the outperformance of Mont Belvieu C3+ pricing relative to WTI in 2020. On the right, we see the continued outperformance in propane relative to Brent at the Far East Index or FEI, which is the benchmark in Asia. What we've witnessed is that demand for LPG in key Asian markets during the third quarter has actually increased year-over-year, and that the strength of NGLs witnessed early in the pandemic was not temporary.
Looking beyond the resilient residential and commercial demand, the relative preference of gasoline in the global transportation fuels market during this pandemic has also been favorable for NGL pricing on a relative basis to oil. Gasoline has been less affected than distillates, which have seen inventories increase significantly due to the more pronounced and prolonged decline in jet fuel demand. Resulting weak distillate demand has led to reduced refinery runs in the U.S. and globally, which in turn has lowered the production of refinery LPG and other gasoline blend components such as naphtha. Ultimately, these downstream trends have been even further supportive of blending butanes and C5+ into the gasoline pool.
In addition, the relatively tighter supply and demand dynamics for naphtha has a knock-on effect for LPG, as there is some competition between naphtha and LPG for use as a feedstock in select steam crackers in Europe and in Asia. Overall, we believe that global market dynamics are constructive for NGL prices at a minimum in the near to midterm timeframe. Turning to slide number eight, titled NGL Pricing Outlook, the chart illustrates the value that some third-party analytical teams, including the Citi commodities team shown here, continue to place on NGLs in 2021 and beyond, based on their bottoms-up global supply-demand models.
Behind many of these forecasts is the realization that if oil was to stay range-bound throughout 2021 at $40 a barrel-$45 a barrel, the world will simply not be able to supply enough hydrocarbons in the subsequent years to meet demand in a post-pandemic environment, which undoubtedly will result in higher prices.
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. Realized Northeast differentials continue to improve year-over-year, with more and more volume shipping out of the basin on the Mariner East system, as Energy Transfer has added incremental capacity since initially placing Mariner East two in service. With the Northeast LPG supply potentially at its peak here in 2020, we ultimately expect Northeast differentials to Mont Belvieu to strengthen even further in coming years. With that, I will turn it over to Mike.
Thanks, Dave. I'll begin my AM comments with third 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 3.1 BCF per day in the third quarter, which represents a 13% increase from the prior year quarter. Compression volumes during the quarter averaged 2.8 BCF per day, a 16% increase compared to the prior year. AM added 120 million per day compressor station in the Marcellus, and compression capacity was 90% utilized during the third quarter of 2020. Our 50/50 joint venture gross processing volumes averaged 1.5 BCF per day, a 43% increase compared to the prior year quarter. Processing capacity was over 100% utilized during the third quarter. JV gross fractionation volumes averaged 39,000 barrels per day, a 22% increase from the prior year.
JV fractionation capacity was 98% utilized during the quarter. Freshwater delivery volumes averaged 111,000 barrels per day, a 21% decrease from the prior year quarter, driven by lower completion activity by Antero Resources. Freshwater delivery volumes were ahead of expectations during the third quarter, driven by an acceleration of completions as AR averaged a company record 8.5 completion stages per day. This pulled incremental stages into the third quarter, originally scheduled for the fourth quarter, and as a result, we expect a reduction in freshwater delivery volumes in the fourth quarter. Moving on to financial results. Adjusted EBITDA for the third quarter was $229 million, a 5% increase compared to the prior year quarter. Distributable cash flow for the third quarter was $189 million, resulting in a DCF coverage ratio of 1.3 times.
Capital expenditures during the quarter were $37 million, a 77% decrease compared to the third quarter of 2019. During the third quarter, we generated a company record $158 million of free cash flow before return of capital, compared to just $23 million in the prior year quarter. Moving on to the balance sheet and liquidity. As of September 30th, 2020, Antero Midstream had $1.19 billion drawn on its $2.13 billion revolving credit facility, resulting in approximately $950 million of liquidity. AM's total debt and leverage were both flat quarter-over-quarter at $3.1 billion and 3.7 times respectively. I'll finish my comments on slide number 11, titled AM Updated Guidance Summary. As depicted on the slide, we have taken significant steps to reduce capital investments by over $100 million compared to our original budget, a 34% decrease.
Driven by throughput exceeding expectations and operating expense reduction achieved to date, we increased our adjusted EBITDA guidance from the previous range of $800 million-$815 million to $835 million-$845 million. These two factors have driven a $90 million or 23% increase in our free cash flow guidance in 2020 at the midpoint of the revised guidance range of $485 million-$495 million. In addition, we are currently trending towards the higher end of our return on invested capital target of 14%-16%. Our just-in-time capital investment philosophy has positioned us to quickly adapt to changes in AR's development plan and avoid being overbuilt on midstream infrastructure. All of these achievements would not be possible without the hard work and dedication from all of our employees who safely delivered another exceptional operational quarter. With that, operator, we are ready to take questions.
Thank you. We'll now be conducting your question- and- answer session. If you'd like to be placed in the question queue, please press star one on your telephone keypad. A confirmation tone will indicate your line is in the question queue. You may press star two if you'd like to remove your question from the queue. For participants using speaker equipment, it may be necessary to pick up your handset before pressing star one. One moment, please, while we poll for questions. Our first question today is coming from Jeremy Tonet from JP Morgan. Your line is now live.
Hey, good morning, guys. This is James on for Jeremy. I guess just starting off with 2021 and understand it's early to provide any numbers there, but I guess just given the revised guidance for 2020, and what that assumes for 4Q, would it be fair to assume that 4Q might be a good annualized run rate for 2021, just assuming Antero's stepping down activity here?
No. It would be, at least on the revenue side, probably okay. Antero Midstream had a couple expense items in 2020 that will not repeat in 2021, and that's specifically around the Clearwater facility. It remains to be seen, but the rebates step up in 2021, the threshold levels. Some of those may or may not be achieved, whereas in the 2020 timeframe and in fourth quarter, we expect those to be achieved. EBITDA should be higher than that kind of fourth quarter run rate.
Got it. Just shifting to kind of the debt profile here. It seems like it's been trending a little bit high in the past few quarters. Can you just talk to me about what you expect in terms of the pace of de-leveraging next year? I know you guys have mentioned you're comfortable within this kind of 3x-4x range, but just wanted to see if, given the free cash flow inflection, if you can see that leverage ticking lower next year.
Yeah, I don't know what you're referring on the second and third quarter. We actually paid down a little bit in the second quarter. In the third quarter, we only increased leverage by $30 million, and that's because we have our interest expense of actual cash interest paid occurs in March and September of every year for $60 million versus an interest expense of $30. We actually had free cash flow above the return of capital this quarter. I think it was 147, about $10 million worth. That's the first time. No, we expect leverage to be flat. When we look at the models going forward, we don't add any absolute leverage. It stays flat. With EBITDA ticking up a little bit, that 3.7 times trends a bit lower, but kind of stays in the mid threes level.
Got it. If one more, if I can, just more of a macro one. Obviously, given the takeaway of the basin, you have the Atlantic Coast cancellation, there's MVP hurdles remaining. I guess, just looking out next year, what's really the impact if maybe MVP is delayed on the AM business?
For me, I think that would be encouraging for AR. Obviously, AR has the firm transport already in place to deliver its production to the premium price markets, so any widening in basis does not affect them from a production flow assurance, from a throughput in the AM systems. It would probably allow AR to have lower marketing expense, which would improve just their overall financial profile.
Got it. Thanks. That's it for me.
Yeah. Thanks, James.
Thank you. Our next question today is coming from John Mackay from Goldman Sachs. Your line is now live.
Hey, everyone. Good morning. Thanks for the time. Just wanted to circle back on two of those, actually, just ask in a little bit different way. The 2020 guidance implies a bit of a step down for 4Q 2020. I understand that AR production's going to step back a little bit, but is there anything else moving there? Maybe a one-off on either side?
One thing is, I mentioned it in my comments, you probably about have half the completion activity that we had in the second and third quarter on the water. When you look at that way, I think the water EBITDA for this quarter was in between $30 million and $35 million. Half of that would suggest next quarter's water EBITDA would be $15 million-$17 million. That's part of the primary step down. Then you do have a little bit lower, about 100 million a day lower volumes of throughput. Those two in combination gets you to that implied EBITDA, kind of at the midpoint in the fourth quarter of $195 million-$200 million.
Great. That's helpful. Thank you. My follow-up's actually, so didn't use the buyback this quarter, but could you guys just share how you think about using the buyback going forward and whether or not you might consider increasing leverage even just temporarily to buy back shares?
Yeah, no, we wouldn't consider increasing leverage to buy back shares. We still have $150 million available to us. We're just opportunistic around that. We definitely take into account our leverage and do not want to increase our leverage for buybacks.
All right. That's it for me. Thank you.
Thank you, John.
Thank you. Our next question today is coming from Gregg Brody from Bank of America. Your line is now live.
Hi, guys. Just a clarification on the midstream fee incentive, which was hit this quarter, which I guess you paid AR. Do you expect that to occur in the fourth quarter as well?
Yes.
You do. That's in the numbers. There's no delay in that. If it was in the third quarter that happened, you paid AR in the third quarter for it? Did you actually pay the fourth?
I think it's one month away. We paid them in October.
October. Okay. All right. That's it for me. Thanks for the time.
Thanks, Greg.
Thank you. Our next question today is coming from Sunil Sibal from Seaport Global Securities. Your line is now live.
Yes. Hi. Good morning, guys.
Hi, Sunil.
Thanks for taking my question. First question was related to the NGL volumes that you processed with your JV. Seems like there was a pretty decent pickup sequentially in that number. Is that anything to do with how you're recovering NGLs? Because the process volumes were up 6%, but the NGL flows seems like were up more. Just trying to understand that.
No, nothing different. That was just from the production growth at AR and it being focused on a heavy liquids window of the Marcellus.
Okay. Then on the consolidation front, obviously the E&P sector is seeing some consolidation effort. I was curious what your views are around consolidation in the midstream side. I think in the past, you guys have talked about growing third-party business. I was wondering if you could frame for us any opportunities or how do you see that playing out?
No, we're still focused on the organic business. We definitely keep our eyes open for opportunities. I don't think there's anything near term. We'll keep evaluating anything that comes up in the basin. We generally have shied away from situations where we buy into gathering driven by another producer. That's not really been of interest. It's been more looking at downstream opportunities.
Got it. Thanks.
Thank you.
Thank you, Sunil. Thank you. We've reached the end of our question- and- answer session. I'd like to turn the floor back over to Michael Kennedy for any further closing comments.
I want to thank everyone for participating in our conference call today. If there are any further questions, please feel free to reach out to us. Thanks again.
Thank you. That does conclude today's teleconference. You may disconnect your line at this time and have a wonderful day. We thank you for your participation today.