Michael Kennedy - VP, Finance & IR Glen Warren - President & CFO Paul Rady - Chairman & CEO

Neal Dingmann - SunTrust Robinson Humphrey Jeoffrey Lambujon - Tudor, Pickering, Holt and company Dan Guffey - Stifel Nicolaus Holly Stewart - Howard Weil

Thank you for joining us for Antero second quarter 2015 investor conference call. We will spend a few minutes going to the financial and operational highlights and then we will 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 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 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.

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 Glen.

Thanks, Mike and thank you to everyone for listening to our call today. In my comments are going to highlight some of the key achievements from the second quarter 2015 results.

Discuss our expectations for the remainder of the year and provide color around our preliminary year-over-year net production growth target of 25% to 30% for 2016. Paul, will then highlight service cost reductions and operational efficiencies that we have achieved year-to-date outlined in Tower County, West Virginia, bolt on acreage acquisition we completed during the quarter and touch on our first Utica dry gas exploratory well that we spud in West Virginia earlier this week.

On the production front, we had another outstanding quarter producing 1.484 Bcf per day net which was above expectations and in-line with the record quarterly production level achieved in the first quarter of 2015. Liquids production averaged almost 46,000 barrels a day for the quarter and made up 18% of the production stream.

As we look ahead to the remainder of the year, we expect a slight decline in production during the third quarter driven by the deferral of 50 completions in the Marcellus into 2016 but expect to ramp up in completion of production during the fourth quarter as we head into 2016. As a reminder, we're referring the completion of 50 Marcellus well until the new regional gathering pipeline is in service expected by the end of the fourth quarter of this year.

Once the pipeline is operational we expect an approximate $0.80 per Mcf improvement in gas pricing relative to Dominion South and Tedco M2 pricing resulting in approximately $150 million of incremental EBITDA during 2016. As you can see on Page 1 of the earnings call presentation, hopefully you've had a chance to pull it up, title that completion deferrals 2016 production impact, the 50 Marcellus deferred completions are expected to add over 350 million cubic feet of gross well head production by the middle of next year at the peak.

These deferrals along with our cost reduction efforts allow us to target year over year 2016 net production growth of 25% to 30% with only a modest increase in our drilling completion capital budget relative to our 2015 budget. Moving onto our hedge book during the quarter we once again generated significant realized hedge gains of $196 million or $1.45 per Mcfe.

As you can see on Page 2 of our earnings call presentation titled, hedging Antero business model, this represented the 25th out of the 26 quarters since 2009 that we realized hedge gain generating over 1.3 billion in cash hedge gains over that timeframe. The extensive hedge we became elated is performing exactly as we intended providing significant cash flow protection during the low commodity price environment.

As we say in the heading of the page, hedging as much is complementary but integral to our business model and long-term development plans. In fact, during the second quarter alone we added a net 409 Bcf of natural gas hedge positions of the out years despite rolling off 160 Bcf of maturing natural gas hedges in the quarter.

We have the 2.8 Tcfe hedge going forward an average price of $4.08 per Mcfe which equates to a $2 billion mark-to-market value as of June 30 of this year. Moving onto slide 3 of our earnings presentation titled, 2016 hedges insulate from commodity price volatility for slide 3, for 2016 we're significantly hedged on our targeted natural gas production in C3 plus NGL production with 90% to 94% of the production range hedged at $4.02 per Mcfe for 2016.

With such a large percentage of our expected production hedged in 2016 we could experience the $5 oil and $2 natural gas throughout the year and only lose approximate 9% of our expected EBITDA based on current strip pricing, you can see that at the table at the bottom, so I'm picking the midpoint in the table at the bottom. This inflation around commodity price fluctuations provides us the clarity on 2016 prices was one of the primary considerations when gaining comfort on refining our 2016 production growth targets.

They give us comfort in rolling those numbers out -- those targets out midyear. While local price differentials for gas and NGLs and in Appalachia continue to be pressured we believe that our, in addition to hedges just discussed, we're well-positioned through our diversified firm transport portfolio will enable us to continue delivering attractive price realizations and netbacks even in the current low commodity price environment.

First to touch on EGL pricing I'll direct you to page number 4 of our earnings call presentation and that's titled, NGL exports and netbacks step up by fourth-quarter 2016. On this slide we'll illustrate the uptick in realized pricing and netbacks we expect to achieve once we gain access to our firm commitment on Mariner East II which is currently planned to be placed in service in the fourth quarter of 2016.

As you can see the bottom left table we have a base commitment of 61,500 a day on Marnier East 2 that's consistent 11,500 barrels a day of ethane, 35,000 barrels a day of propane and 15,000 barrels a day of butane. In addition to this base commitment, we also have doubling rights on our propane and butane commitments which would bring our total commitments on Mariner East II to 112,000 barrels a day.

As relates to the potential value uplift I'll direct you to the black dotted box on the center left side of the page and the blue outlined box on the bottom right-hand side of the page. As you can see from these tables assuming NGL strip pricing at both Mont Belvieu [ph] and Northwest Europe for August, so these are current spot prices in current shipping rates for each perspective area, our commitment on Mariner East 2 will enable us to realize an uptick of $0.14 per gallon for propane and $0.12 per gallon for butane if it were in place today.

So if you apply this uptick to our full base commitment volume for propane and butane the 50,000 barrels I mentioned earlier, our access to Mariner East II would result in incremental EBITDA of over $100,000,000 on an annual basis. Further, as more new vessels are built and delivered shipping rates are expected to decline in 2016 which would add significantly to that incremental EBITDA figure.

To mitigate additional NGL pricing pressure before ME2 is placed in service, we've entered into significant propane hedges for both the remainder of this year and 2016 as well. For the remainder of 2015 we've hedged $22,000 a day propane at $0.62 per gallon which is $0.20 per gallon higher than Mont Belvieu August 15 propane strip prices.

For 2016 we've hedged 30,000 barrels a day of propane at $0.59 per gallon which is $0.12 per gallon higher than current 2016 propane strip pricing. Rounding out my comments for today let's touch on quarterly consolidated financial results.

Antero adjusted net revenue increased 32% from prior year quarter to $575 million for the second quarter this year. Per unit production expenses were $1.45 per Mcfe which is below our full-year 2015 guidance range of $1.50 to $1.60 and that's primarily due to lower production tax expense stemming from lower commodity prices.

On our production expenses [indiscernible] include lease operating expense gathering compression processing transportation cost and production tax all in. Our per unit net marketing expenses for the quarter were $0.22 per Mcfe as expected with certain portions of our firm transport portfolio being placed in service in April of this year.

Our G&A expense for the quarter was an attractive $0.23 per Mcfe which is at the low-end of guidance of $0.23 to $0.27 per Mcfe excluding non-cash stock compensation expense. EBITDAX for the second quarter was $268 million in line with last year's second quarter despite a 43% reduction in NYMEX natural gas prices and 44% reduction in oil prices.

We reported adjusted net income for the quarter of $17 million or $0.06 per share. Lastly during the quarter we spent $440 million on drilling and completion cost, $46 million on land, $12 million for water projects and $34 million for a bolt-on acreage acquisition in Tower County West Virginia.

Year-to-date we spent approximately $1 billion on drilling and completion capital or approximately 60% of our budget for the year, this is in line with our drilling completion schedule which is more heavily weighted to the first half of the year as we reduced our rig count from 21 rigs in January to 10 currently. We've completed about 60% of our planned completions for the year in the first half of this year.

Driven by our diversified FT portfolio we sold approximately 62% of our natural gas production at favorable price indices well as natural gas price before hedging of $2.20 per Mcf or $0.44 per Mcf less than the average NYMEX natural gas price for the quarter, so there's your differential. After hedging we sold our natural gas from $3.86 per Mcf which represents a premium to NYMEX of $1.22 per Mcf.

Additionally we sold our NGLs at a realized price of $16.29 per barrel or approximately 28% of the average WTI oil price for the period. Note that these are C3+ barrels with all ethane left in the gas stream.

After hedging we sold our NGLs at a realized price of $19.51 per barrel or approximately 34% of the average daily WTI oil price for the period. Importantly when including the value of tick associated with hedges our liquids production we received $3.85 per Mcfe or an incremental $1.21 per Mcfe increase to our realized gas equivalent prices compared to the average NYMEX for the quarter.

From a leverage and liquidity standpoint we're well-positioned in the current commodity price environment to continue executing on our development plan for many years ahead. On a consolidated basis we had $3.5 billion of available liquidity and just under $4.4 billion of net debt as of June 30.

Which represents net debt to trailing 12 month EBITDA of 3.5 times. As you can see on page 5; title, strong balance sheet and financial flexibility, we feel comfortable allowing our balance sheet to flex during these leverage levels during soft commodity price environments.

Particularly considering the $2 billion mark-to-market value or hedge book the $2.9 billion of midstream value held in our -- through our 70% interest in [indiscernible] mid-stream and expected proceeds from the drop-down transaction of our integrated water business. That puts you in the $6 billion neighborhood of non-E&P fairly liquid assets that we hold at the company relative to the $4.4 billion of net debt.

When putting all this together results in liquid non-NPS that's well in excess of the debt plus over $3 billion of liquidity which positions Antero well for the future. So in concept we could monetize all the non-A&P assets ended up with $1.5 billion in cash using those numbers.

We have no plans to do so except as to the water drop-down but it puts us in a very competitive position relative to our peers. Before I turn it over to Paul, I like to provided brief recap on Antero's current operations and discuss our outlook going forward.

I'll direct you to the page number 6 in the deck titled, Antero's Best position to weather the storm. There are many points that I would like to touch on.

While commodity price continues to see pressure our focus remains on operations and other factors under our control. As it relates to capital spending we reduced our 2015 capital budget by 49% for 2014 and expect only a modest increase in 2016.

As just mentioned, we feel very comfortable with our current leverage level in this commodity price environment given our various liquid non-E&P assets, including our large in the money hedge book, Antero Midstream ownership and expected proceeds from the water drop-down and that's covered in the upper right portion of that page. On the NGL pricing front, the next box down, we're 100% hedged on propane for the remainder of 2015 and 2016 and gain access to Mairner's 2 in the fourth quarter of 2016, enabling higher NGL [indiscernible] based on current strip pricing.

While industry well economics continue to be challenged, now down to the third box, we managed to reduce our well cost by 15% to 20% so far this year and are generating rates return in the range of 25% to 50% looking at our drilling plans for the remainder of the year. Upon gaining access to the regional gathering pipeline we discussed earlier, we will receive stronger netback pricing in our gas production resulting in $150 million of incremental cash flow when that comes online.

We have control of our own destiny as it relates to take-away capacity and infrastructure build out through our low-cost firm transport portfolio and ownership of Antero Midstream. To sum it up, we believe we're well positioned to succeed the current commodity priced storm and continue executing on our organic growth program, to develop significant value for shareholders for many years to come.

With that, I will turn it over to Paul for his comments.

Thanks, Glen. In my comments today I'm going to provide more detail around the well cost reductions we've achieved to date, provide an overview of the bolt-on acreage acquisition we completed during the quarter, discuss our Utica dry gas test well in Tyler County, West Virginia that we spud earlier this week and finally touch on the potential integrated water business drop-down to Antero Midstream.

First let me discuss our well costs. As Glenn mentioned and as illustrated on slide 7, entitled AR well cost reductions; we have reduced well cost in both the Marcellus and Utica by 16% and 18% respectively as compared to 2014 cost.

Approximately half of the savings in the Marcellus are from service cost reductions and the other half are from operational efficiencies. We averaged 22 drilling days per well for a 9,000 foot lateral which is an improvement of seven days versus the 2014 Marcellus average of 29 drilling days per well.

Similarly on the completion side of things, we were able to increase the completed number of stages per day by over 25%; to 3.9 stages per day during the second quarter which of course, decreases overall completion cost per stage. The reduction in drilling days and increasing completed stages per day, in turn reduces our daily rental cost for tools and other spread cost which amplifies the overall cost reductions.

In the Utica approximately 65% of the well cost savings are from service cost reductions and 35% are from operational efficiencies. Similar to the Marcellus we improved the number of drilling days per well from 34 days in 2014 to 30 days in the second quarter of 2015 for a 9000-foot lateral and increase the completed stages per day by 34% over the 2014 development program to 4.3 stages per day.

We have also captured additional savings opportunities including lower cement, mud and cutting disposal cost as well as the operational efficiencies previously discussed. Now, shifting to the recent acreage acquisition of approximately 4400 net acres with both Marcellus Shale and Utica Shale potential, the acreage was acquired were approximately $34 million and is located in the core of the Marcellus Shale, liquids rich window in Tyler County, West Virginia directly adjacent to Antero's existing acreage.

And addition to Marcellus Shale rights, the acquired acreage also includes Utica Shale rights it is in very close proximity to the Stewart Windland [ph] well which was drilled by one of our peers as highlighted on slide 8 entitled; Antero's first Utica dry gas well. And this Stewart Windland well had an additional -- initial 24 hour rate of 46.5 million cubic feet a day or 8.8 million cubic feet per day per thousand foot of lateral which is the fourth highest announced initial production rate per thousand feet of lateral for a Utica Shale dry gas well.

On the acquired acreage we have identified 83 gross drilling locations in the Marcellus highly Rich gas condensate regime that are either impacted through increased working interest or longer laterals or added as completely new locations and another 67 Utica Shale locations with 392 Bcfe of net 3P Marcellus reserves and 308 Bcf of net Utica resource respectively. Importantly, we expect these well locations to generate 30% to 40% rates of return at current strip pricing.

Note that the well cost assumed in order to estimate our rates of return are all in, including $1.2 million of allocated pad, road and facilities costs. To further expand on our thoughts around Utica Shale dry gas potential we recently spud our first Utica Shale dry gas well in Tyler County West Virginia, near the acquired acreage I just discussed.

And expect to have initial results in the fourth quarter. Referring you again to slide number 8, this well as targeted the Point Pleasant high-pressure, high porosity dry gas fairway, on Antero's 181,000 net acre position which includes approximately 1900 gross locations and 12.5 to 16 Tcf of net resource, not currently booked as 3P reserves.

And addition to our Point Pleasant exposure in northern West Virginia, we also have exposure to Point Pleasant dry gas potential in Ohio with 43,000 net acres, including approximately 289 gross locations in 2.4 Tcf of 3P reserves. Moving to ongoing developments on the midstream side, I'm sure many of you are aware we received a favorable private letter ruling on our integrated water business in May of this year and we started the process toward a potential drop-down transaction of the water business from Antero Resources into Antero Midstream.

The benefits of this potential transaction is twofold; first, the potential capital infusion into AR and the deleveraging of ARs balance sheet coupled with capacity to finance future water infrastructure CapEx at Antero Midstream; and second, the value uplift from the tax efficient MLP structure. As you know, we have an approximate 70% interest in Antero Midstream or roughly $3 billion in value based on AM's current unit price as of today.

So we participate directly in the growth and the value creation of the MLP. While we cannot go into specifics regarding timing or evaluation of a drop-down since the process is still ongoing, we can disclose that Antero Midstream has exercised its option to purchase this water business and negotiations are ongoing between the two independent boards and their respective financial advisors.

When we arrive at to the Q&A portion of this call please be aware that we would not be able to answer any questions regarding the valuation and timing of any potential transaction. We had another outstanding quarter operationally, including bringing on the most productive ourselves well in the company's history, located in the liquids Rich portion of our acreage that queued 2.7 Bcf equivalent in its first 120 days and the production was 30% liquids.

This operational success resulted in net production exceeding our expectations for yet another quarter and we made significant improvements in cost reductions. While we cannot ignore the challenging commodity environment we face today, we feel that we have positioned the business to weather the storm, given our low finding and development cost, significant commodity hedge position, financial flexibility and diverse take away optionality to favorable markets.

With that, I will now turn the call over to the operator for questions.

With the recent success we obviously [indiscernible] other guys in Southwest PA your thoughts about perhaps expediting some of the drilling, you obviously have a sizable amount of acres there yourselves, your thoughts about either drilling that or just redirecting some of your drilling efforts?

We're certainly following the activities of all of our peers in the play and, you are right, they are pretty impressive flow rates. So our view right now is to drill at least one well ourselves and learn more about the technique, more about the well cost and then produce the well and see what the decline curve actually is.

We're still in learning mode so it is still uncertain as to what the economics will be, but with good results and it is quite possible that we will do more.

What is your -- do you have take-away in that area, is that any issue?

We can move the gas through our Rich gas system and that's what we're going to do with our first well is move the dry gas through so we have capacity. It is not as efficient, but it is the best direction to go to send it through the plant and then to better markets.

Further on down the road, by the end of next year, then Rover will be operational or mid 17 and so we will be able to move gas in the Northwest direction. So better take away situation in about a year and a half.

In the meantime, we can move it to our infrastructure to the better markets but it is not quite as efficient but certainly better than going to Dominion South or TETCO M2.

Just last question on -- you talked I think in the press release about the component [indiscernible] expense that was attributable to the underutilized [indiscernible] pipeline capacity. Just your thoughts on that going forward, will that continue to be about the same as far as what's underutilized or how will you think about that?

We will continue to see some cost there. We certainly try to mitigate those costs each quarter by using the capacity in capturing differentials where we can or buy and selling gas.

So it is a little bit of a wild card but we will continue to see that until we fill the capacity which by 2017, those numbers start to get pretty minimized relative to the overall cash flow and revenues of the company. But it will continue to be an issue for the next year and a half which we think that's a fair price to pay for a position that bills toward 4.8 Bcf a day.

And I think our demand charge on that whole position average I think we disclosed in 2016 is about $0.33 then it bills in the high $0.30 per demand charges by 2018, 2019 when all of that is online. Very reasonable cost of transport so we were early mover and you pay a little bit of a price on that certainly during a commodity downturn where you scale back a bit, but we think it is certainly a fair trade.

Just first on in Q2 production, you mentioned your Marcellus well to date as the best Marcellus well to date for you guys. Anything else contribute to the beat that could be expected to continue going forward maybe better than expected decline rates?

Anything on the timing of completion? Just anything of that nature?

Well we certainly try to be conservative in our outlook so we hope that we can exceed expectations going forward. But it really is a situational thing quarter by quarter as to where you have constraints here and there and pipeline downtime and that type of thing.

But we're optimistic and feel good about our guidance.

Just given the run rate so far, how does that jive with what the current full-year guidance and then previous guidance for April through December being about at the 1.4 Bcfe a day level at the midpoint? How does this change that if at all or are you still sticking to that number?

We do expect net production to be down a bit in the third quarter, so we still feel good about that 1.4 Bcfe a day number for the year. And, like I said, we're optimistic that we will exceed that and that's one of the guidance is 40% plus production growth for the year.

And last question for me looking into 2016, you guys have laid out the well cost, but could you provide more color on assumptions going into that preliminary 25% to 30% target for next year in terms of rig activity, capital allocation and efficiencies that kind of go in to that assumption?

Yes, we're baking our efficiencies into our thinking for next year's budget and that's why we have the comment there that modest increase in what does that mean for this year's budget. It is probably in the 5% to 15% range, something like that depending on where we end up on that production target spectrum for next year.

But we have baked those efficiencies into that and the well cost reductions so far. We do think all of that continues, it is not static, so hopefully that will actually improve by the time we get to 2016.

In 2013 you guys began utilizing the SSLs and saw a nice bump in recoveries and then you subsequently increased your Marcellus URs per 1000 lateral foot near year end 2013. Over the past 18 months, those UR per 1000 foot estimates have been essentially stable.

I'm curious, could you guys provide any detail if you see any changes you are making in your completion design and if you see any potential uplifts for higher incremental recoveries on your West Virginia acreage?

The company never reaches perfection where all these tweaking our completion designs but we have pretty well settled on the SSL, the shorter stage length. As we're now we've got some pilots that have been going on for at least the last six months, have a little bit shorter, but we continue to watch production and see if we can optimize further.

But feel pretty good about where we're now.

Okay. You guys have been one of the most aggressive in building your acreage foothold throughout the basin.

I guess can you discuss how many additional large-scale opportunities that are currently on your radar?

We still have a very active leasing program. We're pleased that we have seen the lease cost go down quite a bit during this downturn, but we have lots of things on our radar, both big and small.

We focus on where we see, of course, the best potential geologically and in terms of results and we factor take away and those things into. So have a lot of things that are going on, but I think the best value right now is the base leasing that we continue to do.

And then last one for me. I guess with commodity prices headwinds persisting, could you guys anticipate you could see any borrowing base reductions on your upcoming October redetermination or should the increase in PDP offset any of the commodity price decreases?

I don't think we're in that category in the box of seeing a step down in our borrowing base. We would expect it to be neutral to up with added quarters.

We did that determination off of year-end reserves so that was the $4 billion borrowing base. So we will be looking at three quarters of additional PDPs less production, so we feel pretty good about that being neutral to positive step up and actual borrowing base and whether or not we choose to use all that, that's another matter.

But we're very solid there and certainly the hedge book helps buffer that and we continue to add hedges and that buffers that situation.

Quickly, Paul I think last quarter you mentioned you still give the edge to liquids development just that we've been under continued NGL pressure, just curious if you had an update on your thoughts there?

We continue to look at that. We have shifted a little bit over in our Utica fairway a little bit toward drier side, feel good about that where it is more of a known entity.

We know the decline curves and the well cost and, after we drilled this deeper Utica test in the Marcellus, we will certainly weigh that against liquids. So still subject to rethinking it, but for the time being, we still see that our best well economics are in the liquids fairway in the Marcellus.

Okay, great and then maybe kind of sticking with the Utica activity. I think most of your Utica completions were set the second half of the year.

Can you help us better forecast the division I guess between 3Q in 4Q with the Utica completions?

Yes, I think a good measure would be probably 75% of our completions in the Utica are happening in a second half of year, Holly. So it is very much back-end loaded where you have the opposite phenomena in the Marcellus where it is flip the other side.

Any help between 3Q and 4Q?

Between the two plays, when you balance it out, they're fairly equivalent in terms of number of completions expected each quarter. You see more of the production show up in the fourth quarter, hence the bit of a step down in production expected in the third quarter.

And then maybe a last one just on some help with modeling for NGL pricing. Is there a way to think about the discount that the basins receiving right now on NGLs?

Just maybe a rule of thumb or something?

It's certainly volatile and I think it is going to be hard to predict here for the next year or so for us until we get into the Mariner East and the International market. But we do expect to see improvement seasonally as you go into the fall/winter months.

We're optimistic about that. But it is difficult to predict and we have our forecast out there of 30% to 35% of WTI for the year.

But that's taking into account quite a bit of volatility from quarter to quarter. Second quarter expected to be soft and it was.

And third quarter similar with improvement in the fourth quarter, seasonally.

Thank you for joining us on today's conference call. If you have any further questions please feel free to contact us.

Thanks again. Goodbye.