Good day, and welcome to the Antero Resources second quarter 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 a 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 second 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 would also like to direct you to the homepage of our website at www.anteroresources.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 measures. Before I turn it over to Paul, I also quickly want to provide a brief update on the review of potential measures to enhance Antero's valuation. As we have mentioned, a special committee of independent directors of our board, in conjunction with legal and financial advisors, is conducting this review and working with the special committees of Antero Midstream and Antero Midstream GP boards and their advisors. The special committees are exploring the full range of options to create long-term value for the stakeholders of all three entities, which is a complex process and remains ongoing.
While substantial progress has been made by the special committees, as we stated previously, there's no definitive timetable for completion of this evaluation. There can be no assurances that any initiatives will be announced or completed in the future as a result of this review. We hope to be in a position to give you an update before the end of the third quarter. As you can understand, we will not be able to address any questions related to this review or discuss it further during today's call. Joining me on the call today are Paul Rady, Chairman and CEO, and Glen Warren, President and CFO. I will now turn the call over to Paul.
Thank you, Mike, and thank you to everyone for listening to the call today. In my comments, I'm going to highlight our operational execution during the quarter and provide an update on the 2018 completion schedule. Glen will highlight several significant second quarter financial achievements and updates to our 2018 guidance. Let's begin by discussing the efficiency improvements we made during the quarter. Once again, Antero set new quarterly operational records during the second quarter. Looking at slide number three, titled Drilling and Completion Efficiencies, starting on the top left portion of the slide, in the Marcellus, we held our average drilling days flat at 12 days, and in the Utica, flat at 20 days, despite the continued trend of increasing our average lateral length, as seen on the lower left portion of the slide.
During the quarter, we drilled the longest lateral drilled to date in West Virginia at 15,100 feet sideways. Completion stages per day in the Marcellus averaged 5.0 stages per day during the second quarter, including a company record of 5.5 stages per day in the month of April. The trend continues with 6.5 stages per day completed overall on average in late July. This compares to 4.6 stages per day average in 2017. In the Utica, we completed 5.4 stages per day on average, an increase from 5.1 stages per day on average during the first quarter. These improvements are reducing well cost and are ahead of our current budget, which assumes 4.5 completion stages per day.
As a result of this improvement, we plan to release two completion crews during the second half of 2018, as wells are being completed at a quicker pace than the initial development plan. The decision to drop these crews also reflects our commitment to maintaining capital discipline, as full-year capital spend guidance remains unchanged. The quicker pace of the development plan will result in 65-75 wells being turned to sales during the third quarter, with an average lateral length of approximately 9,500 feet. We recently placed into service our largest pad to date in the Marcellus at 14 wells which follows two recent 12-well pads turned to sales in the second quarter. As we continue to increase our pad size and lateral lengths, while making strides in drilling days and stages per day, we expect to achieve further efficiencies.
We also recently achieved our first remote completion, where we located completion crews and equipment on a separate pad from the well pad, enabling improved logistics for completions operations. In the coming quarters, we will conduct our first concurrent operations where we drill wells at one end of a large pad while we complete wells at the other end of the pad, thereby getting to first production much quicker on these eight-14 well pads. Turning to well costs, earlier this year there was considerable concern over service cost inflation. Given the continued efficiency gains by the industry and the constraints that are occurring in the Permian, service costs have recently softened.
Additionally, we continue to assess various self-sourcing sand options, which, as the largest component of our well costs, has the potential to save us upwards of $500,000 per well over the long term once we fully implement it. Despite this operational momentum, we are experiencing some production curtailments due to tightness in the local crude trucking takeaway market. Our crude buyers have been challenged to secure adequate numbers of licensed truck drivers and trucks to move our growing crude production. We expect these curtailments to be temporary in nature, as we have recently executed direct agreements with additional companies for additional trucking capacity. The additional capacity will enable us to lift existing curtailments, as well as to move the 100,000-barrel plus crude inventory that has built up over the last couple of months.
Currently, there is approximately 100 million cubic feet equivalent per day of production that's under curtailment, including 4,000 barrels a day of NGLs and 2,000 barrels a day of crude oil. With trucking capacity expected to match oil production beginning in September, we anticipate that the production curtailment will be alleviated by the fourth quarter of 2018. In the Utica, five horizontal Ohio wells were placed to sales during the second quarter with an average lateral length of 15,900 feet. Antero also set a new company record for the Utica, drilling nearly 5,200 lateral feet in a 24-hour period. Additionally, the 10 Ohio dry Utica wells that were completed at the end of 2017 continue to show strong results, producing 200 million cubic feet a day flat over the first 150 days before exhibiting natural decline.
While we remain excited about the Ohio Utica, we have shifted our second half 2018 development plan to more economic liquids-rich locations in the Marcellus due to the continued strength in liquids pricing. Our current five-year plan does include the resumption of drilling and completion activity in the Ohio Utica in 2019. To briefly touch on our 2018 well completion plan. We remain on track to complete approximately 145 wells this year, with an average lateral length of 9,700 feet. Due to efficiencies, our completions outpaced our production facilities and tie-in line dates, resulting in capital spend in the second quarter that preceded the production benefit that we will see in the third quarter. As a result, we anticipate a reduction in Antero's quarterly run rate capital spend during the third and fourth quarters of this year.
Nonetheless, our development plan is forecast to result in strong fourth quarter production, providing momentum into 2019. With that, I will turn it over to Glenn for his comments.
Thank you, Paul. Good morning. Let me begin with our key financial achievements from the quarter and provide color on the changes to guidance we outlined in our press release issued yesterday afternoon. During the second quarter, net production averaged a record 2.52 Bcfe per day, delivering 15% year-over-year growth and 6% sequential growth, including a record 113,600 barrels a day of liquids. Liquids increased 10% sequentially, reflecting a continued emphasis on developing our liquids-rich acreage. Liquids production included 6,900 barrels a day of oil, 70,500 barrels a day of C3+ NGLs, and 36,200 barrels a day of ethane. During the second quarter, Antero's realized natural gas price was $2.83 per Mcf before hedges, representing a $0.03 per Mcf premium to the average NYMEX Henry Hub price. This marks the 16th consecutive quarter that we have delivered pre-hedged natural gas realizations at a premium to Henry Hub.
During the first half of 2018, Antero's average natural gas price realizations resulted in a $0.09 per Mcf premium to NYMEX before hedges. Highlighting the continued benefits from our strategically advantaged firm transportation portfolio. During the third quarter, we also anticipate Rover Phase Two capacity to be placed into service, which will unlock optionality to reach the favorably priced Chicago and Gulf Coast markets with either Marcellus or Utica Gas, further reducing our exposure to local markets. As a result, we are raising our full-year realized natural gas price guidance from a range of $0.00-$0.05 per Mcf premium to NYMEX to a range of $0.05-$0.10 per Mcf premium to NYMEX before hedges. Slide number four captures the favorable shift in geographic exposure that we anticipate in the second half of 2018.
As shown on the chart at the top half of the page, we expect a decrease of 5% of our gas being sold in local markets and an 8% increase in Midwest and Gulf Coast markets combined. As a result, approximately 97% of our gas is expected to be sold into premium markets, enabling us to maintain the exceptional natural gas price realizations we achieved during the first half of the year. Moving on to liquids pricing during the quarter. We realized an unhedged C3+ NGL price of $34.81 per barrel, representing a 44% increase from the prior year quarter. While NGL prices did not keep up with the rise in WTI prices during the quarter, averaging just 51% of NYMEX WTI on an absolute basis, NGL prices remained consistent on a dollar-per-barrel basis with our guidance early this year.
For the full-year, we are reducing our full-year 2018 guidance for C3+ NGL prices as a percentage of WTI from a range of 62.5%-67.5% down to a range of 57.5%-62.5% due to the delayed in-service date of Mariner East 2 pipeline. For additional context, if ME2 had been online during the second quarter of this year, we would have received a $4 per barrel uplift on our C3+ realized pricing, which speaks to the significant benefit of this project, particularly in the summer months when NGL differentials are typically wider. We currently forecast ME2 to be operational during the fourth quarter of 2018. We also recognize that there is a potential for it to be in service before that, as they are currently working on repurposing existing product pipeline to move volumes prior to the final regulatory approval and construction completion of ME2.
This is only about a five-mile segment of ME2. As shown on slide number five, propane fundamentals remain strong with days of supply at the lowest level in five years and inventory 12% below the five-year average. Further, as illustrated on slide number six, based on strip pricing through the balance of 2018, tightening inventories and increased exports are expected to result in improvement in C2+ pricing through year-end this year. It is important to note that despite reducing the percentage range relative to WTI, the implied absolute C3+ NGL price based on our updated guidance reflects an increase of $1.20 per barrel at the midpoint relative to our January guidance. The outlook for the second half 2018 ethane pricing also looks positive with recent increases in Mont Belvieu prices.
If ethane remains economically attractive, we have upside to recover volumes during the second half of 2018, up to an average of 45,000-50,000 barrels per day. To quantify the pricing impact, a $0.05 increase per gallon in Mont Belvieu ethane pricing would result in $10 million-$15 million in incremental cash flow during the second half of 2018 to Antero. As you can see on slide number seven, entitled "Leader in Leveraged NGL Prices," Antero is a top three NGL producer and was the number one NGL producer in the U.S. in the second quarter based on numbers released to date. In conjunction with the Mariner East 2 pipeline delay, we are also lowering our full-year cash cost guidance for 2018 from a range of $2.10-$2.20 per Mcfe on a standalone basis down to $2.05-$2.15 per Mcfe.
Net marketing expense guidance for 2018 is unchanged at $0.10-$0.125 per Mcfe, with the second quarter as expected, reflecting the high point of the year. We expect net marketing expense to trend lower over the second half of this year as production increases and we begin flowing volumes on the Rover Phase Two Sherwood Lateral. Now I'd like to briefly touch on our financial highlights for the quarter. Antero led its peer group once again in realized pricing, as you can see on slide number eight, titled "The Leader in All-in Realized Pricing in Appalachia." Antero generated standalone adjusted EBITDAX of $335 million, a 25% increase over the year-ago period. Standalone adjusted operating cash flow was $279 million, 36% higher than the year-ago period, driven primarily by higher natural gas production and favorable liquids prices.
As forecasted, we anticipate a return to free cash flow in the fourth quarter of this year, an inflection point for free cash flow that we expect to be sustained throughout 2019. Slide number nine highlights our historical consistency in being a peer leader when comparing standalone EBITDAX margin to our Appalachian peer group. Our integrated strategy has positioned Antero as a leader in EBITDAX margin for the past five
half years. This outperformance and consistency is a direct result of AR's industry-leading liquids exposure, firm transportation portfolio to attractive markets, our hedge portfolio, and integrated midstream business. As a reminder, we are the only U.S. producer that is 100% hedged on expected natural gas production for the remainder of 2018 and all of 2019, and we're hedged at $3.50 per MMBtu. In summary, we continue to differentiate ourselves by executing on our long-term strategy. We remain committed to creating value for our shareholders by focusing on our extensive liquids-rich inventory and delivering on our long-term targets, including a declining leverage profile to the low twos by year-end this year, as shown on slide number 10.
As shown on slide number 11, titled Antero Profile to Drive Multiple Expansion, this momentum will place Antero in an elite group of just six E&P companies that have scale, double-digit production growth, low leverage, and generate free cash flow, all of whom trade at a premium multiple valuation relative to Antero. With that, I'll turn the call over to the operator for Q&A, for questions.
Okay, thank you. We will now begin the question and answer session. To ask a question, you may press star then one on your touchtone phone. If you're using a speakerphone, please pick up your handset before pressing the keys. If at any time your question has been addressed and you would like to withdraw your question, please press star then two. The first question comes from Subash Chandra with Guggenheim. Please go ahead.
Yeah, thanks. Good morning. Question on the Utica for you, Paul. I think Glenn concluded his comments talking about liquids rich, et cetera. I get it's in your five-year plan, do you need to reinitiate activity in the Utica at all? Or do you think you can bypass it through more active Marcellus development?
Yeah, I think the latter. I think we have it penciled in for next year, but we're always judging these things based on gas prices and liquids prices. There's no obligation to go over to the Ohio Utica side. No leases to save, for example. We have flexibility there.
Okay. Are there sort of hooks in the Utica asset that would keep it in the portfolio, or could it be deemed as non-core if you don't need to develop it?
Well, we like the inventory, and it still gives us a respectable rate of return. There are no hooks that would say it's sacred, but it fits in our plan for now.
Okay, got it. The efficiencies you talked about, just curious if that was really correlated to the larger pads in the quarter, or are these efficiencies durable if you go to smaller pads? If you drill regardless of pad size?
I think it's both. The larger pads definitely helps, but even for same size pads, we're getting faster and faster.
Correct. A final one for me. The midstream expenditures at the AR level, facilities, gathering, et cetera, what is the outlook for that in the second half? Is it also front-end loaded?
No, the actual midstream facilities are not. That's actually borne by Antero Midstream. They're responsible for putting in all those facilities. That's more straight line across all the quarters.
Okay, thanks.
Thanks, Subash.
Thank you.
Okay, the next question comes from Jane Trotsenko with Stifel. Please go ahead.
Good morning. Looking at slide four, your Midwest exposure will increase from 16% during the first half of 2018 to 23% during the second half of 2018. With each Rover and Nexus pipelines coming online and then increasing Canadian natural gas production that also targets the Midwest market, how do you think the regional supply-demand dynamics will evolve with this growing gas competition? If you think that Marcellus gas will be able to push out Canadian gas supplies?
Yeah. Yes, the reason that more gas is going to go to the Midwest is because the Sherwood Lateral portion of the Rover project will finally reach Sherwood processing plant. We'll move more volume in that direction towards Chicago, MichCon, the Midwest. Yeah, that's what we've seen so far this year, is that Marcellus Utica gas is cost-advantaged, it is pushing gas. Midcontinent gas is not coming to Chicago, nor Rockies gas nearly as much, or to Dawn over in Ontario. The Northeast gas is pushing back and displacing gas from Canada, from the Rockies, and from the Midcontinent, I think it'll continue.
Thanks. My second question. You have several pipeline projects coming online over the second half of 2018 and early 2019. Could you please remind us the thought process behind which pipelines are going to be filled first?
We do have several pipes coming on. I mentioned the Sherwood Lateral, that's an important one for us. We have three projects with TECO, Columbia. There's the eastbound WV line, which goes over to the Washington-Baltimore area. There's westbound WV that connects with our Tennessee to the Gulf. Then there is MXP, which is an important project for us that goes right through the heart of our acreage. We project to be filling all of those over the next 15 months or so. We do look on a best net back basis on a day-to-day basis, our marketing group does. We also judge third-party marketing opportunities on a day-to-day basis. We move anywhere from 300 to 600 million a day, recently, of third-party gas, where we collect a margin of between $0.30 and $0.60.
We juggle all that, we weigh all that to see what our best net back is going to be and where the opportunities are for filling the remainder with third-party gas until we fill it with our own, which is the longer-term plan.
That's it for me. Thank you so much.
Thank you.
Thank you.
Okay, again, if you have a question, please press star, then one. Okay, the next question comes from Sean Sneeden with Guggenheim. Please go ahead.
Hi, thank you for taking the questions.
Hi, Sean.
Maybe just on ethane. I think you guys studied the potential recovery of, I think, up to 45 a day. What's the threshold on price where it starts to make sense for you guys to start recovering more?
Yeah. The broad answer would be in the low $0.30 range to the mid to high $0.30 range. What we're balancing is the local gas value as well. We have the option to leave the ethane in the stream and collect the gas value of the ethane on an MMBtu basis. As regional gas prices change, that also dictates. That's why there's a range there around what the ethane price is, because we can choose to leave it in the stream, or we can choose to recover it. That's the broad answer, is anywhere from, say, $0.31-$0.36 is the threshold for where we can elect to recover it and make a profit.
We have actually capitalized on that a bit recently, incrementally recovering about 7,000 barrels a day in July and in August over what we had planned to recover, just to capitalize on some high pricing in the high $0.30 range per gallon.
Great. That's helpful. Just lastly for me, a bunch of your bonds are currently callable. How do you think about potentially trying to refinance some of the front-end maturities? Is that something that begins to make sense? Or is that something that you need to or you have a preference to wait until you get to investment grade?
No, we're always opportunistic, that's something we continually watch, we haven't seen any of them move to the point where we felt like we could execute a bond deal that made sense from an NPV standpoint to pay the premium to call the bond. We watch that continually, and I think you'll see us do some of that over time over the coming quarters.
Great. Thanks so much, guys.
Yeah. Thanks, Sean.
Okay, the next question comes from Glenn Greenberg with Brave Warrior. Please go ahead.
Good morning, Glenn, and good morning, Paul.
Hi, Glenn.
Earlier this year, there were special committees formed, I guess, to discuss the structure of the general partnership and the stream assets and AR exploration company. I'm wondering what's become of those discussions. What was the objective behind having them and the special committees being formed, and where did your deliberations take you to this point?
Well, the deliberations continue, Glenn. It's serious discussions. They're very deliberate, and the special committees move carefully to make sure that all bases are covered. Each special committee has advisors, legal and financial. The big picture has been simplification. I think the market has looked and seen which could be combined with which, and what levers could be pulled, and so that's been out there, but that's all we can say. Of course, no guarantee that anything will happen. Serious discussions continue to happen.
Good. Thank you.
Okay. Again, if you have a question, please press star, then one. Again, if you have a question, please press star, then one. Okay. I have a question from Kevin MacCurdy with Heikkinen Energy Advisors. Please go ahead.
Hey, guys. I saw that you mentioned that you are dropping two frac crews in the Appalachian region. I'm wondering what this means for future well costs and if maybe we could see some lower CapEx in the future if operations are more efficient.
Well, the delta really there that you're looking for is just more stages per day, rather than the number of frac crews. We needed fewer frac crews because we front-end loaded our completions partly this year. Also because of that increase, that was really driven partly because of the rate of increase. We had budgeted 4.5 stages per day, and now we've seen 5.5 and even 6.5 in late July. We just needed fewer crews. For every increase in stages per day on a well, you pick up $90,000-$100,000 of well cost savings. That's the magnitude. If we can average 5.5, say, the rest of the year, we'll save almost $100,000 per well.
Will you add back crews for next year, or is this the four crews will be enough to execute your 2019 plan?
No, I think we'll be adding back, and we'll make a judgment call as to how many and when. As Glenn said, it is an efficiency factor, we'll see what our current state of affairs is at the end of the year or in the fourth quarter and how many stages we can accomplish per day, and make a judgment call there. As we get faster and faster, these crews can accomplish more in a shorter amount of time. The way the contracts are structured, there is a price break. They are covering their base load equipment, as they get more stages off, they make more money, the price per stage goes down.
All right. Thanks for the clarity.
Yeah. Thank you.
Okay, this concludes our question and answer session. I would like to turn the conference back over to Mr. Michael Kennedy for any closing remarks.
Thank you for joining us on today's conference call. If you have any further questions, please feel free to contact us. Thanks again.
The conference has now concluded. Thank you for attending today's presentation. You may now disconnect.