Mike Kennedy - Vice President, Finance Paul Rady - Chairman, Chief Executive Officer Glen Warren Jr. - President, Chief Financial Officer, Secretary

Neal Dingmann - SunTrust David Beard - Iberia

Thank you for joining us for Antero's fourth quarter 2013 investor conference call. We will spend a few minutes going through 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 updated our company presentation for our fourth quarter 2013 results. Before we start our comments, I would 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.

Joining me on the call today are Paul Rady, Chairman and CEO and Glen Warren, President and CFO. I would now turn the call over to Glen.

Thanks Mike. And thank you to everyone for joining us today for the call.

Fourth quarter 2013, net daily production increased quite dramatically to $678 million cubic feet equivalent per day on a net basis that was up 115% year-over-year and 20% sequentially. The production included approximately 11,200 barrels a day of liquids that's up 42% sequentially and really up from nil the prior year because our first processing came online in late 2012.

So a very dramatic step-up there at 11,200 barrels a day in the quarter. This liquids growth was achieved despite couple of delays, we had two major delays in compression facilities – new compression facilities in the Utica, and then we disclosed just recently that that first compressor session came on in late January in the second –should come on now by the end of the quarter, early in the second quarter.

We sold our natural gas during the quarter at $0.19 per Mcf premium to NYMEX and that's very important relative to some of the disclosures that you have seen by some of the operators in the play taking quite a hit to NYMEX. So we have been well-positioned in that respect and part of that is the fact that we are selling higher BTU gas at the tailgate of our plants.

We are fortunate to be in the Southwester core of the Marcellus in Northwestern West Virginia. And that allows us to sell majority of our gas at the TCO index price, at least historically.

TCO traded at a $0.04 that's $0.04 per Mcf discount to NYMEX for the quarter for the fourth quarter, but our gas sold at a premium due to the high BTU content, as I mentioned. We are currently in ethane rejection, so we get a nice pick-up from leaving ethane in the gas stream, which raises the BTU at the tailgate of the processing facility.

We also received attractive prices for our NGL barrel. And just a reminder, our NGL barrel currently is C3+ so leaving ethane in the gas stream.

This results in a much more valuable barrel evidenced by our subsiding $56 per barrel for our product in the fourth quarter and that approximates 58% of WTI oil for the quarter, so that ties back to the guidance that we have out there in the 53% to 57% range for 2014. We realized $54 million or $0.87 per Mcf during the quarter from our hedges.

When you combine our premium value natural gas and liquids projection with our hedge position, our average gas equivalent price was $5.26 per Mcfe. For the past four years, our realized gas equivalent price after hedges has averaged $5.20 per Mcfe.

That represents about 40% premium to the average NYMEX price over that period, so quite a significant premium through hedging in our liquids. This premium relationship should continue in the 2014 due to increase in our liquids volumes relative to the total gas volumes and the recent strength in the NGL market.

We estimate that the increase from 2014 strip over the past couple of months has increased our forecasted EBITDAX for 2014 by about $100 million. While the winter weather in the Northeast has been quite severe and challenging for our people in operations, we don't see any impact on our production outlook.

We had certainly baked in some risk in there. So we are right on track in terms of our production that's not to say we didn't have disruptions, we certainly had daily disruptions particularly in January, it was quite difficult conditions for our people.

But, we kept things on track. Further despite various market dislocations from a gas perspective for the first two months of 2014, we estimate our gas price utilization before the impact of hedges have been at the high-end of our 2014 guidance, which is zero to $0.10 per Mcf premium to NYMEX.

So we have been at the high-end of that so far this year. We have been very well-served once again by being located primarily in West Virginia and Ohio, and focusing a large portion of our gas sales at the TICO index in Appalachia.

Additionally, Antero's elected to revise the treatment of our ATEX ethane pipeline commitment, which just began – those payments just began in January this year. We are going to include that fee as a component of cash production expense for 2014.

Previously in our guidance, when we prepared our guidance for 2014, we considered the fee has a reduction in the NGL sales price, so we have netted against the NGL sales price. And that results in a lower assumed Y-grade C3+ price as a percentage of WTI.

So as a result, we are updating our 2014 guidance, and you saw that in the press release. For NGL price realizations, previously they were 52% of WTI and now our guidance is 53% to 57% of WTI.

So we are increasing our cash production expense from the $1.40 to $1.50 range previously to $1.50 to $1.60 to count for that movement of the cost, there is no real impact on earnings or a cash flow, we just wanted to get that straight. From a cash operating cost perspective, production expenses were $1.52 per Mcfe for the fourth quarter.

As a reminder, our production expenses include lease, operating, gathering, compression, processing, transportation, and production tax. So it's an all in cash number.

Our G&A expense for the quarter declined quite significantly by 34% from the prior year quarter to $0.31 per Mcfe. Please note that we expensed 100% of our G&A expenditures, so we actually have one of the lowest cost structures in the industry.

We are not capitalizing G&A. From a margin standpoint, we are also at the top of the natural gas industry.

We realized revenue on a gas equivalent basis, as I mentioned it $5.26 per Mcfe, and had operating costs including all of our G&A of $1.83 per Mcfe. And that calculates to an EBITDAX margin of $3.43 per Mcfe in the quarter.

We believe, we have the highest price realizations in EBITDAX margins per unit among our peer group in Appalachia. When you factor in, we have approximately $1 per Mcfe development cost or capital cost per unit that results in a full cycle cost of under $3 when you add in the cash operating cost.

So you can easily see our projects are getting or generating very high rates of return. EBITDAX for the quarter was $215 million, which is 149% higher than the prior year's quarter, an 18% higher than the third quarter of 2013, so sequentially.

Development capital was $510 million for the quarter, in addition, we spent $200 million in infrastructure projects including freshwater distribution infrastructure and $100 million on acreage adding about 17,000 core Marcellus and Utica net acres during the fourth quarter. We outlined our hedge position in the release as of the release date with a total of approximately 1.3 Tcfe hedge at an average index price of $4.62 per MMBtu, and $96.54 per barrel through 2019, so that's a bit of an update from the year end hedging that you see in the 10-K.

As you will know, a substantial amount of the hedges are at the indices where we sell our product. So we tied much of our financial hedging to our firm transportation physical deliveries.

In an early release, we also provided guidance for 2014, the guidance we provided since the completion of an IPO of our midstream subsidiary during the year. We filed our initial S1 related to that potential transaction during the first week of February, so we are on track to meet that assumption and that was disclosed that was announced previously.

It is important to note as we decided to take on the majority of our midstream infrastructure, it is required to meet our prolific development program in order to capture value for our stakeholders on the midstream portion of our business while capitalizing on a lower cost of capital for that business. This decision resulted in $600 million of capital budget for Antero midstream and that's higher than we would have budgeted, if we had simply engaged third parties to build out infrastructure, which we have done more of historically.

So we are doing more of that midstream build out ourselves going forward, as the message. And hence the $600 million budget for this year for midstream.

The 2014 guidance that we issued in January forecast average annual net production to increase by approximately 75% to 85% and that's to the 925 million cubic feet equivalent per day to 975 million cubic feet equivalent per day level on a net basis. This outlook includes significant liquids volume, the highest level in our history at 24,000 to 26,000 barrels per day or about 16% of our production stream this year, last year that number was only about 7% of our production stream, so quite dramatic growth in liquids proportion.

This growth is generated from a developmental capital program of $1.8 billion for the year. We also planned to continue consolidate in the play to release all the acquisitions and we budgeted $200 million for that leasehold effort in 2014.

From a capital perspective, Antero was highly active during the fourth quarter of 2014. During the quarter, we completed our highly successful IPO, which resulted in proceeds of the company of $1.6 billion, which we used to repay debt.

We also issued during the quarter, $1 billion of senior notes at five and three-eights coupon and that lowered our weighted average interest cost on our term debt by almost 200 basis points to 5.8% average for the term debt. We had debt of $2.1 billion at year end, which included about $300 million drawn on our $1.5 billion of floating rate credit facility.

That's the commitment level of the borrowing base is actually $2 billion. Based on the fourth quarter's annualized EBITDAX, we were 2.5x on debt to EBITDAX basis and we project this to improve significantly through the year particularly with the proceeds from the MLP IPO.

We also have plenty of liquidity as our current borrowing base is $2 billion based on our mid-year 2013 reserves, so those reserves were done back of 630 reserves of that borrowing base. So we will be redoing that again here in the spring.

So that's a long nine-month period between borrowing base redeterminations. With the tremendous increase in proved developed reserves achieved in the second half of 2013, 1.4 Tcfe grew from June 30, 2013 to year end to 2.0 Tcfe, we expect our borrowing base to materially increase in that second quarter redetermination.

To summarize the quarter from a financial perspective, we have tremendous growth with excellent cash margins and returns with strong visibility. And we expect these results to continue well into the future.

We are able to secure the capital needed to fund continued momentum so we are in a great position. With that, I will turn it over to Paul for his comments.

Thanks Glen. In my comments today I'm going to address a couple of our recent developments.

Glen has already covered the financials and the 2014 guidance, so I'm going to focus on our year end 2013 reserves and Q4 operational update. We had excellent reserve growth during the year, our proved reserves increased 78% during the year to 7.6 Tcfe although only 23% of our total 450,000 net acres had proved reserves associated with it at year end 2013.

So we do have a lot of growth ahead of us. All sources finding and development costs, including acreage costs were $0.58 per Mcfe and we had development costs of $1.14 per Mcfe, both of these costs are best-in-class for the industry and when compared to the 339 per Mcfe EBITDAX margin Glen talked about a little bit earlier, we generated results that are best in class recycle ratios.

Marcellus shale accounted for 95% of our proved reserve volumes, but the remainder attributed to the Utica shale. We were able to add 3.7 Tcf equivalent of proved reserves to increase the total proved reserves to 7.2 Tcfe in the Marcellus this year.

And importantly 1.1 Tcfe of that addition was in the proved developed category as we completed some 113 wells in the Marcellus during the year. Just to talk about the percentages for a moment, we are now at 27% PDP out of total proved, up from 22% last year.

When you look at the 1.1 Tcfe of PDP addition on those 113 wells, that computes to an EUR per well up 10.6 Bcf that we drilled during the year or 1.5 Bcf per 1000 feet of lateral. Now although that's prolific EUR per well and very respectable results, during the year, we shifted over to shorter stage length, SSLs and that has improved our recoveries, so we were able to upgrade our type curve by 18% for wells that have been completed with the SSLs and that's moved this from the 1.5 up to 1.73 Bcf per 1000 feet of lateral.

Early in the process of capturing these SSL results, and so we have only booked 14% that is 91 locations out of our 665 Marcellus proved undeveloped locations, so just 14% have been booked incorporating SSL type curve. Though we expect to materially increase that percentage, those numbers of locations by the end of 2014, and take into account more SSL results.

In the Utica shale, we have only classified approximately 400 Bcf equivalent as proved reserves across our core leasehold position of 106,000 net acres. We have 19 proved developed locations, but only have 21 proved undeveloped locations booked at year end.

We expect this to materially grow by year-end 2014 as we are running 5 rigs, and we plan on completing 41 wells in the play in the Utica during the year. We have four type curve regimes in the play that range from dry gas on the east, which is below 1100 BTU, the highly rich condensate, which is between 1250 and 1300 BTU.

We were able to raise the EURs for three of the four regimes with the highly rich gas regime topping the list with an incredible 20.5 Bcfe, EUR per location. These are monster wells with rates of return above 150% assuming year end prices.

We also lowered a highly rich condensate EUR over on the far west side of the fairway. But due to a tight condensate production, it still achieves in excess of 125% rate of return, again, at year-end prices.

Based on Antero's successful drilling results to-date as well as those of other operators in the vicinity of Antero's leasehold, the company believes that a substantial portion of its Marcellus and Utica shale acreage will be added to proved reserves over time as more wells are drilled. However, due to SEC requirements, we have classified the vast majority approximately 77% of that acreage as probable or possible reserves.

We had year end 3P reserves of 35 Tcf equivalent, 62% increase over year end 2012 3P reserves, which were 21.6 Tcf equivalent 3P. The 62% increase in 3P reserves was driven by the addition of 51,000 net acres in the core Marcellus, and 28,000 net acres in the core Utica in 2013, and also through implementation of our SSL completions.

We were able to convert approximately 58% of our 3P undeveloped locations through the SSL type curve in the Marcellus; again, with continued success you should see that percentage increase to close to 100%. The Marcellus comprised the majority of our 3P reserves as it had 25 Tcfe at year end.

Importantly 97% of Antero's 25 Tcfe of 3P reserves in the Marcellus were classified as proved and probable that is 2P reflecting the delineation work we and industry have performed and that's the low risk nature of the Marcellus reserves. The Utica shale comprised 5.8 Tcfe of the 3P reserves.

As I highlighted earlier, we've only booked approximately 6% of this as proved, so we have a lot of growth ahead of us. There are also, we also have developments in 2014 that could increase the overall size of the resource.

In addition to our active leasing program, we have two density pilots in the Utica to be drilled this year. We will be testing a 500 foot and 750 foot inter-lateral distance pilot in the Utica and remember everything is planned right now on 1,000 foot inter-lateral distance.

So if these pilots are successful that could increase our current 759 identified locations and could increase the total 3P reserves because currently as I say our locations are out in that 1,000 foot inter-lateral distance an exciting opportunity and one that we and the industry have high hopes for. Now, on to the fourth quarter operational update.

During the fourth quarter, we added a rig in the Utica, which brought our total rig count to 20 rigs in the Appalachian Basin along with an average of four frac spreads that either drilled or completed some 25 wells. However, we were only able to put to sales 19 wells due to some compression delays which I'll discuss in a minute.

This firmly places us as the most active operator in the Appalachian Basin, and we have the highest growth trajectory with a triple digit continuous annual growth rate for at least – for the last four years and projected growth in 2014 of 75% to 85%. In the Marcellus, we continued to be the most active operator with 15 rigs and six frac spreads currently working for us including two fully dedicated crews.

We just increased our frac fleet to six as we have 65 wells now in various stages of drilling and completing process, so we have a significant backlog primarily due to pad drilling. We expect to add one additional frac fleet in the next month and maintain that frac fleet count until the backlog returns to more normal levels, which should be by mid year 2014.

Let me talk about SSLs for a minute. Antero transition to shorter stage length completions on virtually all of its Marcellus wells during the fourth quarter of 2013.

While the wells utilizing SSL completions has limited production history, we are encouraged by the results. We have completed and placed online 22 Marcellus wells utilizing SSL completions that have 30 days of production history, and the rate of improvement over our non-SSL type curve has been 31%.

Of those 22 wells that have been online for at least 120 days and that improvement continues to hold up as they are up 27% over non-SSL type curves. We're working with a range of 25% to 30% improvement and the average well cost for these wells have been only 12% higher.

As mentioned earlier based on these results, we've instituted an SSL type curve that is 18% higher than the prior type curve it will continue to monitor the results the potential for an increased SSL type curve going forward. Now shifting to the Utica, we are running five rigs in the play as we added the fifth rig during the fourth quarter as I mentioned, and we put online during the quarter only one well as we had delays in two third-party compressor stations that were scheduled to come on online during the quarter.

We had six wells that were dependent on those compressor stations to be brought online so they were deferred until late January of this year. When placed online these six wells had an average 24 hour initial production rate of 27 million cubic feet equivalent a day, and without the delay in the two compressor stations would have contributed to an average liquid production rate above our fourth quarter 2013 guidance.

The testament to our diversity across the Appalachian Basin, and our understanding of various risks across the play that we were able to still able to deliver above the mid-point of our total production guidance despite these delays. We also provided 30-day rates for our first 11 Utica core wells in ethane rejection.

Despite producing in a high pressure environment due to no compression availability, the wells still had an average 30-day rate of 15 million cubic feet equivalent a day assuming ethane rejection. As a comparison, this is approximately 35% higher than 30-day rates on our SSL wells in the Marcellus and we all know about the explosive growth of the Marcellus.

As mentioned earlier, we now have 120 million a day compression station in service, or the operating environment has become more favorable. The second 120 million a day compressor station I'm talking about in the Utica is now expected to be completed late in the first quarter of 2014 and the third 100 million a day compressor station should be online this summer.

These three compressor stations have a combined capacity of 340 million a day along with three condensate stabilization facilities that have a combined capacity of 16,000 barrels a day. All of these facilities are fully dedicated to Antero.

From a processing perspective, we will be able to accommodate our development program. As the Seneca processing facility is online, we currently have access to 250 million cubic feet a day of capacity, which increases to 600 million a day of capacity by early next year.

In addition to all the positive momentum we are building in the liquids portion of the Utica there have also been some recent encouraging industry wells in the dry gas area where we originally identified 950 potential drilling locations on our West Virginia and Pennsylvania Marcellus acreage with 5 Tcf of net resource. We're currently reassessing the resource potential based on the new data points these new industry wells and we do plan to drill a Utica dry gas well ourselves in West Virginia in the second half of 2014.

In summary, we remain the most active operator in Appalachia, and we have the highest growth rate in the combined place. We continue to have excellent well results in both the Marcellus and Utica, and we'll continue to build out as a midstream infrastructure and continue to increase our leasehold position.

Our assets contain one of the largest, if not the largest liquids exposure in the core of the core in those plays. We're excited for 2014.

And with that operator, we are now ready to take questions.

Good morning, guys, say going to Paul, just a question obviously great news about all the capacity coming on with Seneca, just wondering based on all that capacity coming on your thoughts, is that just enough to handle the – sort of the current plan with the five rigs running, or is there anticipation of may be perhaps adding some rigs there. Just want to know what you're planning out.

Yes. Neal, hi, there is a plan to continue to add rigs and I think over the next several years you'll see us grow that rig count to five rigs to eight or nine rigs, anyway over the next several years.

Okay. And then around the same area in Utica what's the status these days, I know for a little while you had a bit of compression issue didn't seem to be much of an impact these days your thoughts on the – going on the compression?

In Utica the -- yes, we are getting fairly full up again here during the month of March coming month, but we're expecting that second compressor stations to come on either end of March or early April. So we feel like it should match pretty well and then we have a third station that should come on this summer getting us up to that full capacity.

And of course, we have further stations planned out into the future later in the year, but those are the three critical ones and one is on now so that's good news.

Okay. And then Paul, you mentioned about perhaps drilling a dry gas Utica well in that, I guess West Virginia or PA area second half this year, your thoughts if that's successful would that sort of change your thoughts about drilling those up or you will just kind of because of how positive economics the Marcellus is will you sort of stay the course there?

Probably more of the later, Neal. So it will be in West Virginia, and we have some 130,000 acres of deep rights under our Marcellus position over that we think our perspective for the deep Utica for the dry gas play.

So I think it remains to be seen just how strong it is and whether it can compete with Marcellus rich and Utica rich, if it can then we may change our minds. But right now we're expecting to be still good rates of return for the deep Utica drive, but not as strong as the liquid.

So if it works out the way we would expect then well we'll just have to see, but probably the liquid side will still take preference.

Okay. And then lastly, just on the Marcellus pretty evident, how economic these returns are.

Are you still toying with expanding some laterals, I know there are some others around you that have done 9,000, 10,000 foot laterals in some of these Marcellus areas? Your thoughts on maybe just the frac and lateral design there?

Yes. I guess that we probably drilled the longest in the Marcellus as well the Utica.

We've gone out changing the subject slightly but to 11,600 feet in the Utica and to about 10,800 in the Marcellus and have a lot planned in that range. So we feel pretty good going out to roughly 11,000 feet in the Marcellus, have a fair amount of those scheduled.

And the ones that we'd done so far that are above 10,000 are good results we're not seeing that we can't frac the toes or anything like that. So its, we've got a pretty elaborate design of all the units already in place and pads that have been available, so that governs to some extent the length of our laterals, but I don't think we'd hesitate going out into that 10,000 foot range as the need arises.

Okay. Very good.

Great results guys.

Thank you.

Good morning, gentlemen. Would you care to share any exit rates of production this year, so far this year?

Good morning, David. No, we're going to stay away from that for now just stay with our guidance.

I absolutely understand. And how about timing of all the wells behind pipe whether they will be all tied in this quarter or next quarter can you give me any color there?

Yes. I think 80 something wells that we have that are in various stages of development some of those are just drilling with the current rig count 20 rigs.

So the vast majority of those will be on by the end of the second quarter, but we're pad drilling and up to four or five wells on a pad, so some of that takes quite a bit of time. So it depends on what stage you're in with each one so.

Okay. No, that's helpful.

And lastly, could you give us some color on, I know you've given total guidance on liquids but maybe the mix from liquids out of the Marcellus and the Utica and how we should expect that to shift over time?

Yes. The liquids certainly see a higher percentage in the Utica.

So we're tending to drill on average more richer wells that tend to yield more liquids. But, I think a good kind of mix overall is kind of 85, 15 between NGLs and oil as a company.

Okay. That's helpful.

I appreciate the time. Thank you.

Thank you.

Sure. This concludes our conference call.

And I want to thank everyone for participating in it. And if there are any further questions please feel free to contact us.

Thanks again.