Antero Resources Corporation

Good day, and welcome to the Intero Resources fourth quarter and year-end 2018 earnings conference call and webcast. All participants will be in listen-only mode. Should you need assistance, please signal a conference specialist by pressing the star key followed by zero. After today's presentation, there will be an opportunity to ask questions. To ask a question, you may press star, then one on your touch-tone phone. To withdraw your question, please press star, then two. Please note, this event is being recorded. I would now like to turn the conference over to Mr. Michael Kennedy, Vice President of Finance and Head of Investor Relations. Please go ahead.

Thank you for joining us for Antero's fourth quarter 2018 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'd also like to direct you to the homepage of our new website at www.enteroresources.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, Entero Management will make forward-looking statements. Such statements are based on our current judgments regarding factors that will impact the future performance of Entero and are subject to a number of risks and uncertainties, many of which are beyond Ontario'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, and Glenn Warren, President and CFO. I will now turn the call over to Paul.

Thanks, Mike, and thank you to everyone for listening to the call today. In my comments, I'm going to review our 2018 development activity, including the cost efficiencies we have achieved and discuss our recently announced 2019 capital budget and flexible long-term development outlook. Glenn will then highlight our fourth quarter and full-year financial achievements and discuss the expected change in financial reporting to deconsolidate Antero Midstream from AR following the simplification. Glenn will also touch on our 2018 approved reserves and provide some additional color around our long-term outlook and firm transportation portfolio. Let's begin by discussing the efficiency improvements we made during the quarter and throughout 2018. Once again, Antero set new operational records during the fourth quarter. Looking at slide number four, titled Drilling and Completion Efficiencies During the Fourth Quarter, completion stages per day in the Marcellus set another company record for a full quarter, averaging 5.7 stages per day. For the full year of 2018, completion stages per day in the Marcellus averaged 5.2 stages per day, which was an increase of one full stage per day from the 2017 average of 4.2 stages per day. Looking at our 2019 budget, we are assuming 5.2 stages per day, so this is certainly an area we think we can outperform, resulting in additional well-cost savings. To provide some detail on these savings, an increase of one additional stage per day would result in about $200,000 of savings per well. Moving on to some of our recent operational results, during the fourth quarter we turned to sales several outstanding Marcellus liquids-rich pads. One particular pad was a 10-well pad with an average lateral length of 9,700 feet and an average BTU of 1,230 feet. This pad produced approximately 195 million cubic feet equivalent per day during the first 60 days, or 19.5 million cubic feet equivalent per day per well. The liquids rate on this pad was nearly 10,100 barrels a day during the first 60 days, consisting of 1,400 barrels of oil, 5,700 barrels a day of C3 plus NGLs, and 3,000 barrels a day of recovered ethane, representing about a 25% ethane recovery. Another strong data point from the quarter was from a well we completed in our highest BTU regime that was drilled with a lateral length of nearly 15,100 feet. This well produced a 60-day rate of nearly 29 million cubic feet equivalent per day, including approximately 2,100 barrels of total liquids. As we enter 2019, we like where we are, positioned from both a scale and commodity diversification standpoint. As illustrated on slide number five, titled Antero's Balanced Position on the Commodity Spectrum, we are the largest NGL producer in the U.S. and the fifth largest natural gas producer. This scale across both commodities provides us with the ability to manage through commodity price volatility and prosper with any increase in either commodity. Intero holds 40% of the core, undrilled, liquids-rich locations in Appalachia, over 2.5 times more than the closest competitor by our analysis. This extensive liquid inventory is a clear competitive advantage. Now let's turn to our 2019 development plan and long-term outlook, which we announced on January 8th. We are expecting annual production growth during 2019 in the range of 16% to 20% while spending within cash flow. Slide number six, titled Disciplined Long-Term Development Plan, highlights our production growth through 2023 under multiple commodity price scenarios ranging from $50 to $65 per barrel, WTI, and $2.85 to $3.15 per mm BTU, NYMEX, natural gas pricing. The important takeaway here is that Antero will remain flexible depending on the commodity price outlook. We will remain disciplined, spending within cash flow in a low case, but have the ability to prudently grow production to maximize free cash flow if commodity prices improve. ultimately delivering an appropriate mix of return of capital to shareholders and further delivery. To provide some more details on capital and our well costs, I'll point you to slide number seven, entitled Path to 2019 Well Cost Efficiencies. On this page, you can see a bridge from our standalone Marcellus well cost when we entered 2018 to our target in 2019 for a 12,000-foot lateral. Entering 2018, our standalone Marcellus budgeted well costs were $950 per foot. As oil prices rose throughout the year, the well costs were impacted by 6% inflationary costs, primarily related to increases in water hauling costs and production facility expenses. We were able to primarily offset the inflation in 2018 with reduced sand costs through self-sourcing and overall completion costs through a 25% increase in stages per day and renegotiated contracts. Our 2019 target of $930 per foot assumes savings from additional sand self-sourcing contracts, a further increase in stage efficiencies, and optimized water handling, as well as improvements at the Clearwater facility. Further, we expect the DNC capital cost reductions by multiple public operators to date to lead to deflationary pressure on service and material costs. All that being said, it's important to point out that our 2019 budget does not assume any of these additional operational or deflationary savings I just mentioned. I would also like to mention that these standalone well costs include all pad and facilities costs and all flowback water costs. which our peers may not include in their reported well costs. We remain focused on efficient capital spending in 2019, which will benefit from certain capital expenditures made during the fourth quarter of this last year of 2018. In particular, with better construction weather conditions than we typically see in the latter part of the year, We invested $78 million for pads, roads, and facilities in the fourth quarter, and we now have 18 pads that are in progress and plan to be turned to sales in 2019 and 2020. Additionally, as we discussed at our Analyst Day in early 2018, we've transitioned to primarily building our pads today on larger footprints. The larger footprints allow us to be more capital efficient as we are able to operate under different scenarios, such as drilling and completing pads concurrently or continuing to produce from wells on one side of a pad while drilling or completing wells on the other side of the pad. This ultimately results in a meaningful reduction in cycle times from stud to first sales and results in better alignment between capital spending and cash flow. Looking ahead to 2019, as a result of the focused spending on pad infrastructure and equipment in 2018, we expect to be at the low end of our previously announced drilling and completion capital budget of $1.3 to $1.45 billion on a standalone basis and $1.1 to $1.25 billion on a consolidated basis. Turning to slide number eight, titled Mariner East 2 Uplift, we're excited to have ME2 now in service. February represented the first month that we nominated our committed volume of 50,000 barrels a day of propane and butane at the Marcus Hook docks. Based on our contracts in place and current market pricing, we expect to receive a premium to Mount Bellevue pricing of at least 5 cents a gallon at the dock. As illustrated on this slide, this translates into an uplift of about $2 to $4 a barrel when compared to railing to the Mount Bellevue or Conway markets. It's also important to note that in addition to the $2 to $4 per barrel uplift on a net back basis, The price received for the volume shipped on ME2 will reflect the price at the dock, and the ME2 costs will be recorded as a transportation expense. If you think about the 52% of WTI realized pricing in the fourth quarter for our C3 plus NGLs, The shift in sales point related to ME2 volume alone would have resulted in about a 7% pickup in realized pricing relative to WTI. When you include the uplift, that adds another 2% to 4% on a percent of WTI basis or north of 60% WTI. We like the position... We are now in as the largest NGL producer in the U.S. with significant exposure in the international market out of Marcus Hook. In summary, we had a strong year in 2018, reducing our financial leverage to 2.2 times, and we grew production nearly 900 million cubic feet equivalent per day over the last 12 months to over 3 BCF equivalent a day. And also, another accomplishment is that we announced the simplification of our midstream organization. Entering 2019, we now have significant scale, product diversification, and a strong balance sheet to manage through commodity price volatility. Our long-term strategy centers on prudent capital deployment, continued focus on full cycle rates of return, and generating free cash flow, all while maintaining a strong balance sheet. With that, I will turn it over to Glenn for his comments.