Antero Resources Corporation

Greetings and welcome to the Antero Resources second quarter 2019 earnings call. At this time, all participants are in a listen-only mode. A brief question and answer session will follow the formal presentation. If anyone should require operator assistance during the conference, press star zero on your telephone keypad. As a reminder, this conference is being recorded. It is now my pleasure to introduce our host, Michael Kennedy, Senior Vice President of Finance. Thank you. You may begin.

Thank you for joining us for NTERO's second quarter 2019 investor conference call. We'll spend a few minutes going through the financial and operational 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.nteroresources.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 like to first 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 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 measure. Joining me on the call today are Paul Rady, Chairman and CEO, and Glenn Warren, President and CFO. I will now turn the call over to Paul.

Thanks, Mike. Thank you to everyone for listening to the call today. In my comments, I'm going to spend some time talking about our long-term strategy and focus on our recently announced well cost and operating cost savings initiatives. I'll provide detail on savings we've achieved to date and highlight the key items that will reduce costs further towards our target. Glenn will then highlight our second quarter financial achievements, including the premium NGL price realizations following our first full quarter with Mariner East II in service. He will conclude by discussing our expanded hedge position through 2022 and our capital spending outlook. I'd like to start by discussing our long-term strategy. We remain focused on maximizing our ability to generate free cash flow on a sustained basis. As we look at our five-year development plan today, The best way to deliver maximum free cash flow on a sustainable basis is to grow production in the near term to fill our firm transportation commitments while we have attractive natural gas hedges in place. At current commodity strip prices, we forecast funding this growth primarily through cash flow from operations, and the water earn-out payment of $125 million expected in Cal 20. This allows us to preserve our strong balance sheet. Once we grow into our firm transport and essentially eliminate net marketing expense in 2022, we are well positioned to be more flexible with our development plan and generate significant free cash flow. To provide some complex context, if we elect to just maintain year-end 2021 forecast production of approximately four BCF equivalent per day, the capital required to do so would be less than $900 million. This would result in our ability to generate free cash flow of over $400 million in Cal 22, even at today's commodity strip prices, or over a 30% free cash flow yield. As opposed to downshifting to maintenance capex today and delivering one year of free cash flow with unfilled pipeline commitments remaining, our strategy positions us to deliver long-term sustained free cash flow generation. Now, let's turn to our well-cost savings initiatives. Regardless of commodity price cycles, we remain committed to maximizing value. Over the last several quarters, we undertook an internal review of every expense associated with our well costs with the goal of materially reducing costs to maximize returns. Let's turn to slide number three, titled Targeted Marcellus Well Cost Reductions. Please note that all these numbers assume a lateral length of 12,000 feet. We are targeting a reduction in well costs of 10% to 14% on a per lateral foot basis or approximately $1.2 to $1.7 million per well by 2020 compared to our 2019 budgeted costs. On a dollar per foot basis, this translates into a reduction from 2019 budgeted costs of $0.97 million per 1,000 feet to a target of $0.83 million to $0.87 million per 1,000 feet. This is expected to be reached by the beginning of Cal 20. These savings have come or will come from a combination of water savings initiatives service cost deflation, and continued efficiency gains. Meeting our target will position us at the low end of the cost curve among our Appalachian peer group. Now let's take a step back and talk about what we've already achieved to date. Following the waterfall on the page, we begin with our January 19 well cost at $0.97 million per thousand feet, that was assumed in our budget. Through the first half of the year, we've already achieved savings of approximately $500,000 per well, which brings us to our current AFE with second half 2019 well costs estimated at $0.93 million per thousand feet. This progress was the driver behind lowering our 2019 CAPEX guidance back in May without any change to our planned activity. We're very proud of our team's ability to deliver on this target significantly ahead of schedule. This achievement reflects both continued operational efficiency gains and service cost deflation that was realized during the first half of 2019. From our current AFE of $0.93 million per thousand feet of lateral, we expect well cost to decline further to the range of $0.83 to $0.87 million per thousand feet by Cal 20. These additional savings are expected to come primarily from our water savings initiatives, both on enhanced flow back water management and completion optimization. Now let's take a closer look at our major components of our well cost savings. We talked about the timing of well cost savings. but I wanted to provide a breakdown of the magnitude of each category. On slide number four, titled Cost Reduction Initiatives Breakdown, you can see the breakdown by category, assuming the midpoint of our targeted well cost reductions of $1.2 to $1.7 million. We are targeting approximately $800,000 per well in well cost reductions from more efficient flowback and produced water management, as well as optimized completion design. On the flowback and produced water side, we expect to reduce costs through a combination of, first, polishing and blending the water to reuse in completions, secondly, repurposing portions of our existing fresh water system to transport the water, and three, constructing additional water pipeline infrastructure. Historically, we've used third-party trucking companies to transport our flowback and produced water at a cost of between $6 and $9 per barrel. Over the last 12 months, we have paid nearly $160 million to third-party trucking companies. This situation provides Antero with a significant opportunity for improvement and for material savings on a per-barrel basis. while also expanding the scope of the flowback and produced water services business for Antero Midstream. On the water used for completions, earlier this year we began performing pilots across our acreage to test and analyze the optimal completion design to maximize returns. After successful pilots using mostly 100-mesh propane, we now plan to reduce water used in completions from a range of 40 to 45 barrels per foot down to 35 to 38 barrels per foot in a new cost-efficient completion design. The completion design optimizes both fracture length, driven by water usage, and reservoir conductivity, which is driven by the type and amount of propant, in the most cost-effective manner. We have not seen any evidence of degradation in either production or EURs in all of our piloting, and we do not expect it going forward. The second component of our Well Cost Savings Initiative is service cost deflation and efficiency gains. An often overlooked byproduct of lower commodity prices and reduced industry activity is a deflationary service cost environment. Service costs go down. This is especially true in the Appalachian Basin, where producers have lowered capital programs while also continuing to realize efficiency improvements. Given that Antero has remained one of the more resilient producers in the basin through all cycles, we've maintained excellent relationships with our vendors. In early 2019, we began working with our vendor partners to find areas to reduce expenses. The result of these extensive conversations was a meaningful reduction in total vendor costs. Further savings will come from last mile sand sourcing logistics and an additional sand contract that was recently finalized with a premier sand supplier. On the efficiency gains, as we have highlighted during many of our earnings calls, our team's operational efficiency gains continue to surpass expectations. Slide number five, titled Marcellus Drilling and Completion Efficiencies, highlights the many advancements that we achieved during the second quarter of 2019. During the quarter, we averaged 5,470 feet of lateral drill per day. That's approximately one mile, a little over a mile every single day, 20% improvement from our 2018 average. In addition, We achieved what we believe is a world record, again, by drilling a total of 9,650 feet of lateral in one day, which we're extremely proud of. Completion stages per day averaged 5.7 stages per day, an increase from the 5.2 stages per day average in 2018. We continue to drill longer laterals. During the quarter, we were able to drill our longest Marcellus lateral ever at 16,279 feet sideways. These efficiency gains, combined with service cost deflation, are expected to reduce well costs by approximately $650,000 per well, assuming the midpoint of the target range. The enhanced produced water management will also reduce lease operating expenses. Let me clarify how we talk about water in terms of well cost and LOE. When we complete a well, after perforating and stimulating it, we flow the well back and begin to recover the water as we turn it in line. We categorize the first 90 days as flow back water, and the cost to truck and recycle it is capitalized as part of the well cost. After 90 days, we account for the well, the water, as produced water, and the cost to truck and recycle it is considered LOE. So let me talk a little bit more about LOE, lease operating expenses. In the first half of 2019, produced water costs represented approximately 80% of total LOE. Assuming Antero Midstream provides the new expanded produced water services, we expect LOE to be reduced by at least 20% in Cal 20 compared to Cal 19 budgeted costs. This equates to savings of at least $50 million on an annualized basis. Slide number six, titled Appalachian Pier Marcellus Well Cost Comparison, provides a snapshot of our Appalachian Pier well costs and future targets. Keep in mind that there is a variance among producers as to what costs are captured in capitalized well costs versus LOE, but the trends are useful. As you can see, our new well cost target will move us from an average ranking to becoming one of the lowest cost producers in the lowest cost natural gas basin in the world. While we recognize that some of these cost initiatives have not been fully realized to date, we are already seeing results from the company's focus on costs, as we achieved the lowest capital spending quarter in our history at $303 million for the quarter. Over the last 12 months, our drilling and completion capex was $1.55 billion, which delivered 700 million cubic feet equivalent of production growth. This was accomplished while spending near cash flow levels, highlighting the attractive capital efficiency of our asset base, Going forward, we anticipate a quarterly D&C CapEx run rate approximately in line with this second quarter spend in the $300 million to $325 million range. In summary, we will continue to prioritize maximizing value through an intense focus on costs. The reduction in well costs is expected to deliver 2019 drilling and completion capital at the low end of our guidance range. and lead to a lower DNC capital target of $1.2 to $1.3 billion in Cal 20. The decline in capital spend during Cal 20 is despite a similar number of well completions to 2019, but actually with a 19% increase in total lateral footage completed next year due to longer laterals. With that, I'm going to turn it over to Glenn for his comments.