Antero Resources Corporation (NYSE:AR) Q1 2016 Earnings Conference Call April 28, 2016 11:00 AM ET
Michael Kennedy - Senior Vice President, Finance and Chief Financial Officer, Antero Midstream Partners LP
Glen Warren - President and Chief Financial Officer
Paul Rady - Chairman and Chief Executive Officer
Neal Dingmann - SunTrust Robinson Humphrey
Phillip Jungwirth - BMO Capital Markets
Brian Singer - Goldman Sachs
James Sullivan - Alembic Global Advisors
Ben Wyatt - Stephens Inc
Good morning and welcome to the Antero Resources First Quarter 2016 Earnings Conference Call. All participants will be in listen-only mode. [Operator Instructions] Please also note, this event is being recorded.
I would now like to turn the conference over to Michael Kennedy, Senior Vice President of Finance and Investor Relations. Please go ahead, sir.
Thank you for joining us for Antero’s first quarter 2016 investor conference call. I’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 Home Page 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 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 will now turn the call over to Glen.
Thank you, Mike, and thank you to everyone for listening to the call today. In my comments, I’m going to highlight our first quarter financial results, including price realizations and EBITDAX margins, and then touch on the capital markets activity during the quarter, as well as our financial flexibility. Paul will then highlight the significant operational improvements we achieved during the quarter, including service cost reductions and operational efficiency gains that continue to drive down our overall development costs, and finally, discuss the operational flexibility of Antero.
During our comments, both Paul and I will periodically refer you to a handful of slides that are located in a separate conference call presentation on the Home Page of our website titled, First-Quarter 2016 Earnings Call Presentation. This is separate from our Monthly Investor Presentation, also located on our website. So please make sure that you’re reviewing the correct slide deck during the call.
Let’s begin with some of the key highlights from the quarter, as we had another tremendous quarter, both operationally and financially. Production averaged a record 1.758 Bcfe per day for the quarter, including over 68,000 barrels a day of liquids. This outperformance during the quarter, combined with the continued operational efficiencies we are seeing today enabled us to increase production guidance for the year to 1.75 Bcfe per day, while still maintaining our $1.3 billion drilling and completion budget.
The liquids production during the quarter included approximately 12,000 barrels a day of ethane, which was a significant increase from the 2,179 barrels a day of ethane we recovered in the prior quarter. As this was the first full quarter following the installation of a de-ethanizer facility at the Sherwood complex in December of last year. While we are only recovering approximately 12,000 barrels a day of ethane today, the de-ethanizer does provide capacity to recover 40,000 barrels a day of ethane at the Sherwood facility, providing us with the ability to significantly increase ethane production in the event that ethane prices continue their recent upward trajectory and local economic support recovery.
Moving onto realize pricing during the quarter, despite the continued downward pressure on commodity prices, we realized all end pricing at $4.14 per Mcfe, including NGLs oil and hedges, which was a $2.05 premium to the Nymex average during the quarter. The ability to realize prices at a premium to Nymex was a function of our industry-leading hedge book, along with our diversified firm transportation portfolio allowing us to sell approximately 99% of our natural gas production at favorable price indices, an improvement from 83% in the fourth quarter. In fact, we sold our natural gas at a $0.01 differential to Nymex on average for the quarter before hedges.
As you can see on Slide 2, entitled Hedge Strategy Produces Consistent Results and Stability, we realized a hedge settlement gain of $324 million during the quarter, or $2.03 per Mcfe. Since 2009, we have consistently realized quarterly hedge gains, including 28 of the last 29 quarters.
Looking ahead as of March 31, we had 3.6 Tcfe hedged at an average price of $3.71 per Mcfe, resulting in projected hedge gains of $3.1 billion through 2022. This strategy of selling production forward has allowed us to lock an attractive returns and provides us with stability by maintaining momentum via prudent growth through the downturn. This is especially important in an environment, where our peers are forced to scale back to preserve capital.
To further discuss our firm transportation portfolio, I will refer you to Slide 3, titled Projected Incremental EBITDA from Stonewall. This quarter represented the first full quarter that we had access to the Stonewall pipeline, which enabled us to sell approximately 99% of our natural gas production at favorable priced indices, as I mentioned earlier.
As you can see on the map on the right-hand side of the page, Stonewall allowed us to shift all Marcellus production that was otherwise flowing north to Dominion South and TETCO M2 pricing down Stonewall, enabling us to exceed favorably priced TCO at Nymex-based pricing. Based on 2016 guidance, this will result in a 650,000 million Btu per day shift in volumes in 2016, and an incremental $126 million in EBITDA, as you see at the lower left-hand side of the page. Bolstered by the previously mentioned hedge gains coupled with the price realization improvements, we generated $355 million in consolidated EBITDAX during the quarter.
As you can see on Slide #4, titled Highest EBITDAX and Margin Among Peers, despite a decline in Nymex gas and oil prices of 30% and 32%, respectively, AR’s EBITDAX was essentially unchanged year-over-year. This translated into EBITDAX margin of $2.03 per Mcfe for the quarter, which we expect be the highest among our peers during the quarter, once again, as we continue to benefit from our hedge book and FTE portfolio.
Before moving onto our 2016 development plan and balance sheet, I wanted to touch on net marketing expenses. During the quarter, we generated $99 million in marketing revenue, along with marketing expenses of $138 million. The largest component of marketing expense was demand charges associated with unutilized capacity and third-party gas purchases.
During the first quarter, we purchased and sold approximately 540 million cubic feet a day of third-party gas, utilizing excess capacity on the Tennessee Gas Pipeline and capturing an average spread of $0.43 per Mcf. Net marketing expense was in line with expectations at $39 million, or $0.24 per Mcfe. As previously discussed, beginning July 1, 2016, and continuing until the Rover Pipeline is placed in service, or December 31, 2018, whichever is later, the third-party is assuming our ANR Pipeline capacity costs.
Looking to the second-half of 2016, we expect to see a reduction in net marketing expense as a result of the ANR Pipeline costs being covered by a third-party. Said another way, we expect net marketing expense to be more front-half weighted this year with first-half 2016 marketing expenses making up approximately 65% of the total net marketing expenses for 2016.
To touch on our differentiation versus our peers, Slide #5, titled Continued Measured Growth, illustrates our leading position for growing, both production and cash flow. Additionally, looking at the bottom-half of the page, you can see that our leverage at year-end 2015 was 3.7 times, which is at a level we feel comfortable allowing the balance sheet to flex in a severe commodity price downturn.
Based on 2016 consensus estimates, our leverage by year-end 2016 is expected to be essentially unchanged, due to the production and cash flow growth I just discussed. This is a key differentiator versus some of our peers, who continue to see declining cash flow leading to increasing leverage for the current commodity price environment.
With that being said, we would ultimately like to see leverage in the two times range, assuming a more normalized commodity price environment over the long-term. Now that we have covered the ability of the balance sheet to support the growth at AR, I want to further expand on the current development plan by highlighting the operational flexibility we built into the program to react to commodity price changes over the next few years.
Directing you to Slide #6, titled Low Maintenance Capital Provides Flexibility and Upside, you can see that we could spend just $275 million of drilling and completion capital to maintain production at 2015 levels of approximately 1.5 Bcfe a day, obviously, we’re ahead of that today. Building upon that maintenance capital, you will note that we could also achieve 17% year-over-year net production growth for 2016, while only spending $675 million in total significantly below the projected hedge revenues in 2016 of over $1 billion, and that’s the red line on the left side.
However, in order to continue momentum heading into 2017, out 2016 D&C budget includes an additional $625 million that will contribute to the 2017 growth target of 20%, which we feel very confident about given the continued capital efficiency, flexible DUC inventory, and volume so far at attractive prices.
Looking ahead to 2017, our maintenance capital needed to generate production levels similar to 2016 would be just $500 million, and that’s the yellow box, almost $100 million below the projected hedge revenues in 2017. The remaining capital to achieve 20% year-over-year growth in 2016 would be an additional $375 million, or $875 million in total, and that’s the top of the green bar, and an additional capital invested with continued growth momentum into 2017 – into 2018, excuse me. So about half of the capital for maintenance and this year’s growth and half for next year’s growth. Now that we’ve established the ranges in capital spending that allow us to maintain production, or continue our momentum to thrive as prices recover.
Let’s move onto Slide #7, titled Flexibility and Upside. First and foremost, we have kept our lean workforce intact throughout the commodity downturn, which provides us the ability to quickly react to changes in commodity prices. For example, we were running 21 rigs in early 2015, with essentially the same workforce, or three times the amount of rigs planned for 2016. On the Midstream front, we benefit from having an in-house Midstream provider, Antero Midstream, which can quickly adapt to changes in development plans to avoid gathering compression bottlenecks that could materialize with third-party Midstream providers.
Our substantial inventory with over 3,600 remaining 3P locations and the demonstrated ability to efficiently develop the resource provides significant leverage upside as commodity prices recover. Said another way, while our peer leading hedge book totals 3.6 Tcfe and provides a significant downside protection from commodity prices, the upside is truly in the 37.1 Tcfe 3P base, and the fact that, we are well-positioned to develop it. It’s also worth noting that our hedge prices of $3.57 and $3.91 per Mcfe in 2017 and 2018 are 20% and 30% above current Nymex natural gas price – pricing in those years, respectively.
Moving onto the capital markets for the quarter, we completed an underwritten secondary offering of $8 million AM units for net proceeds of approximately $178 million. In essence, this transaction was monetizing a portion of the roughly 12 million AM units AR received, as partial consideration for the water dropdown that AR had not originally anticipated owning, but took part – took as part of the transaction, given the challenging environment, and that was in September of 2015.
We continue to see tremendous value in the Midstream business, which bodes some of the highest distribution growth in distributable cash flow coverage ratios in the entire MLP space. Pro forma for the offering, we still own approximately 62% of Antero Midstream.
To quickly discuss balance sheet and liquidity, despite the continued decline in commodity prices, our borrowing base under was reaffirmed at $4.5 billion this spring. As you can see on Slide #8, titled 2016 Borrowing Base Reaffirmed, Antero was one of only five public E&P companies with a borrowing base greater than $1 billion that did not receive a reduction in borrowing base in a redetermination season this spring so far. And one of only two BB rated public E&P companies that reaffirmed its borrowing base. The reaffirmation of the borrowing base is a direct result of the significant PDP reserve growth and significant value of our hedge position.
As of March 31, 2016, we had over $3 billion of availability under our credit facility and over $3.5 billion of available consolidated liquidity. Additionally, we maintained stable debt and leverage levels from year-end 2015. Looking forward, we expect to continue delivering top tier production growth with 17% year-over-year growth guided to in 2016 and 20% growth targeted for 2017.
With that, I’ll turn it over to Paul for his comments.
Thanks, Glen. In my comments today, I’m going to discuss well costs and operational improvements we’ve seen during the first quarter, including highlighting several new Antero records that we have set. I will finish with a review of our well economics, which illustrates the benefit of deploying capital to generate strong rates of return.
First, let’s discuss the significant improvements in well costs that we are seeing. As illustrated on Slide #9, titled Proven Track Record of Well Cost Reductions, current well costs in the Marcellus have declined to $0.95 million per 1,000 feet of lateral, or a 32% decline compared to the fourth quarter of 2014.
As you can see on the bottom of the slide, we’ve seen similar success in the Utica with well costs totaling $1.14 million per 1,000 feet of lateral, or a 29% decline compared to the fourth quarter of 2014. Not only did the first quarter 2016 well costs represent significant reductions compared to the end of 2014, the Marcellus and Utica well costs represented a 17% and 13% reduction respectively compared to well costs assumed in our year-end 2015 reserves. The reduction in well cost is driven primarily by reduced service costs as legacy contracts continue to roll off and we begin to realize lower spot rates, as well as a number of operational efficiencies.
Let me talk about those operational efficiencies. If you’ll move to Slide 10 and that’s a slide called Continuous Operating Improvement. Drilling days during the first quarter in the Marcellus were reduced from 24 days in 2015 to 21 days. And stages completed per day increased from 3.5 stages per day in the prior year to 3.8 stages per day more recently.
In the Utica, Drilling Days during the first quarter decreased from 31 days in 2015 to 24 days and stages completed per day increased from 3.7 stages per day in the prior year to 4.4 stages per day.
Additionally, during the quarter, we set two new company records. First, we recently drilled and cased the longest lateral in company history at over 14,000 feet sideways. And second, we drilled 5,291 feet of lateral in a 24 hour period, over a mile. In fact, all of our top 10 Drilling Days in the Marcellus since we began in the play have occurred in the first quarter of 2016.
In addition to the drilling and well cost improvements, as you can see the blue box at the bottom of the slide, during the first quarter of 2016, we attained a wellhead EUR per 1,000 feet of 2.0 Bcf in the Marcellus Shale and 1.6 Bcf in the Utica Shale.
By fine-tuning proppant sizes and modifying the profit mix, we’ve increased prop and placement to over 98% over the last six months, that’s been a real focus of ours to make sure we got the jobs fully off. While the recent results are very encouraging, we have yet to see the additional improvements from new completion techniques that I’m going to discuss next.
We intend to keep our eye on type curves and economics shown at the 2015 EURs of 1.7 Bcf per 1,000 feet in the Marcellus and 1.6 Bcf per 1,000 feet for the time being until we see more results. So that’s our current type curves, and our current economics that we’re sticking with for the time being 1.7 Bcf per 1,000 in the Marcellus, 1.6 Bcf per 1,000 in the Utica, for the time being. In addition to the improvements just discussed, we recently began pilot testing additional proppant loading and fluid designs in order to improve recoveries in proppant placement.
As shown on Slide #11 entitled, Marcellus Proppant Placement, we’ve increased proppant loading by approximately 25% versus our previous design and by fine tuning the proppant mesh sizes and utilizing 25% more water in completions. We’ve also been able to hold proppant placement at over 98%.
While based on a small population, the pilot tests on our 2015 vintage wells in our highly rich gas area have responded quite well to the increased proppant loading and placement, exhibiting initial EURs that are 20% to 30% higher than adjacent wells.
Let me move onto Slide #12. That’s entitled Marcellus Improvements are Driving Value Creation. This slide is a scatter plot of EURs for all of our 251 Antero Marcellus SSL wells completed since 2014. As a reminder, SSL is shorter stage length, generally 200 foot stage length instead of longer stage length.
First of all, you’ll see that there’s a strong correlation between lateral length of the well and the EUR with no degradation in EURs as we complete wells in the 10,000 foot to 11,300 foot range. We’ve completed 33 wells now that are greater than 10,000 feet in lateral length with EURs averaging just over 2.0 Bcf equivalent per 1,000 feet, just like the EURs for laterals less than 10,000 feet.
We have 47 wells in the completion queue today in the 100,000 foot to 14,000 foot lateral length range. This is an important point, as longer laterals improve well economics by spreading the fixed vertical and surface costs over a larger reserve base.
Secondly, the orange diamonds represent EURs for wells completed in the first quarter of 2016, and you can see that they are all on or above the 2.0 Bcf equivalent per 1,000 foot type curve, averaging 2.3 Bcf equivalent per 1,000 feet. Importantly, this out performance did not yet include the impact of our recent completion modifications to higher proppant loading of 1,500 pounds per foot and water utilization of 39 barrels per foot. 2016 will be an interesting year as we begin to see the results of these larger completions in the Marcellus.
Now before we move onto the Q&A, I’d like to touch on well economics and the potential upside from the increased EURs that I previously discussed. Slide #13 entitled Marcellus Upside Potential, illustrates the impact of improving EURs per 1,000 feet from 1.7 Bcf to 2.0 Bcf in the highly rich gas and highly rich gas/condensate windows seen on wells completed in the first quarter with at least 30 days of production.
As you can see, the increase in recoveries translates into attractive 45% rates of return on a pre-tax basis in the highly-rich gas/condensate areas and 30% rates of return in the highly-rich gas areas, assuming a March 31, 2016 strip pricing or increases of 10% and 6% respectively.
Additionally, these locations have very attractive breakeven prices. In the highly rich gas/condensate area, where we have over 600 locations, the breakeven price is $1.40 per MMBtu on NYMEX gas pricing. In the highly rich gas area, where we have almost 1,000 locations, the breakeven price is $2.05 per MMBtu on NYMEX gas pricing. It’s also worth pointing out that the well costs that are baked into the returns include $1.2 million for road, pad and production facilities, and both the demand and variable costs of the firm transportation are also included.
In summary, our first quarter was an outstanding quarter on the operational front, and while we are very pleased with the results, we expect to continue making further progress on improving well costs and returns as we move forward.
With that, I will now turn the call over to the operator for questions.
Thank you. We will now begin the question-and-answer session. [Operator Instructions] Our first question comes from Neal Dingmann of SunTrust. Please go ahead.
Good morning, guys. To say – Paul, just a question towards the end of your commentary you talked about obviously the 10,000 foot wells. Looking at the maps, and I just want to make sure I’m correct on this. It looks like you’ve always had a pretty contiguous position both in the Marcellus and Utica. I guess I’m just trying to think percentage wise is – the majority of your acreage, are you able to do these 10,000 foot laterals? And if so, is that the plan to continue to certainly go after more of these?
Yes, the plan is to go after more. Our acreage position right now is very continuous and contiguous, and I think we averaged 9,500 feet roughly on our average laterals. But to get to that average that means we’ll have plenty of them that will be above 10,000 as well as some that are in the 7,000 or 8,000 range. So yes, we definitely will have a subset of our total that will be well above 10,000 feet.
Okay. And then just lastly I guess the plan for the – assuming prices stay around the same area, I think you’ve got now the one Utica and several Marcellus rigs. Given almost – I’m just a bit surprised, any thoughts about either reallocating, going a little more aggressively in the Utica versus the Marcellus or maybe going to – if you could why the sort of the one versus the seven given the economics?
Yes, we certainly like our Utica play very much and the well results, but there’s a certain circumstance that it’s important for people to know, and that is we are – all we have on the Rex westbound lateral is 600 million cubit feet a day of firm transport, and that lateral is running full.
They’ve filed for an expansion, that’s been approved, but it won’t become available until the middle of 2017. And so until that time we’re capped out at 600 million a day, and so that’s pretty much where we are right now. So the one rig in the Utica will keep us right there at 600 million a day.
The relief that we are expecting is energy transfers Rover Pipeline, and that will come to the Seneca area by mid 2017. So when that comes we’ll have as much as 800 million a day of additional takeaway on Rover that ties to our Midwest and our Gulf markets. So that’s why we’ve reallocated capital over to the Marcellus side for the next year or 15 months is to just ride that constraint.
Makes sense, and then just lastly if I could, you’ve already certainly got a big acreage position. Just, Paul any thoughts that you might have on just M&A deals you’re seeing? Any thoughts about – how aggressively are you looking at anything?
Well, we’re certainly have – as good a handle as anybody on ownership throughout the trend. We’ve got more than 300 lease brokers that are – have worked the court houses. And so we really know who’s out there, and we continue to add on a base leasing basis and also we buy selected acreage from such players as Magnum Hunter that we announced last year.
So I think you’ll see selective transactions where we’ll – we will buy acreage in slightly larger blocks, and then continue to pick up our at least 500 acres a week just through base leasing, filling in and expanding.
Makes sense, thank you all.
And our next question comes from Phillip Jungwirth of BMO Capital Markets. Pleas go ahead.
Yes, good morning.
Kinder had commented on a mutual agreement to the inter statement of Broad Run Expansion Project. And was just hoping you could provide any color from Antero’s view on the reasoning behind the deferral? As we look at your future FT portfolio, are there any other additions that could be deferred?
Yes, so that’s right. Our TGP, we’ll have the right to expand that from 590 million a day to 790 million a day, and so Kinder and Antero agreed that that would be put off until mid 2018, and so that’s the plan. There are other projects out there. We’re not pushing for any delays. The FT that we stepped into we will fill most of it by 2019. So we’ll see how some of these things come about, but yes, there’s no negotiation going onto for us trying to delay any projects.
Okay, great. And then you had mentioned reducing your stake in the LP units of Antero Midstream, which was the first time since IPO. So two questions, one, how important is it to maintain over 50% ownership of the LP? And then two, if ownership were to drop below 50%, would AM still be consolidated by Antero Resources?
Yes, if ownership dropped below 50%, we would continue to consolidate because sort of common affiliates. But – so that’s not a particular trigger point. But we’re very happy with our ownership there. We see lots of appreciation upside. This transaction was really meant to kind of complete the transaction from last September when the market was tough.
It’s still tough on the MLP side in general, but it was difficult then. We did a pipe transaction for about half of the AM equity that we wanted to put away, and this transaction took care of most of the other half of that transaction. So that was really the plan there as opposed to kind of a methodical sell down of AM, that is not the plan right now.
Okay, great. And then Antero certainly has a very valuable hedge book. And I know the question has been asked on your willingness to unwind this, but specifically as it relates to 2017 where supply, demand fundamentals do seem to be improving, it looks like you’re over 100% hedged at least on projected dry gas volumes. So curious as to your willingness to roll some of the 2017 hedges into later periods such as 2019, 2020, 2021 where you did add hedges in the quarter?
Yes that’s a good question. So we have virtually never unwound hedges. So the track record of those that who have materially unwound them has not been so great. And so we consider that our protection, but that’s right. We have a lot of flexibility, if we are slightly over hedged in a certain year, well as we get close and we look at our projections – the projections change from time to time from year-to-year. So you never know whether by the time we get close to that year whether we will be over hedged or not, but you’re right. We can also through spread trades move the hedges back and forth, and so move them to further out years. It’s pretty simple and pretty liquid market to move some of those volumes out to later years, if we wanted to.
And our next question comes from Brian Singer of Goldman Sachs. Please go ahead.
Thank you. Good morning.
Good morning, Brian.
I recognized you haven’t made any official changes to your tight curve, but can you talk to – with the efficiencies that you are seeing and an expectations for further efficiencies? How would is that all this would change your strategy regarding what price you would need to see to accelerate activity? What price at which you would want to sign new contracts for take away? I know in the very near-term we are kind of talking about delays, but sign new long-term contracts for takeaway and how low of a price longer-term you would feel comfortable hedging?
So, in terms of tight curves, I think we can say we are encouraged by our results over the last year and the improvements, but we are pretty conservative. And so it’s going to take with our reserve engineering group probably a year anyway of many wells demonstrating an uptick before we would change the tight curve. But certainly better results means that one can develop at lower prices, if we wanted to. We are not really looking to sign on for anymore FT at this point. We’ve got a number of projects that are coming on and we project that we will fill them in due course through calendar 2019, we will be pretty full.
I think rather than sign contracts with new projects, the new projects generally are quite a bit more expensive than the ones that we have now, because they’re new builds, whereas a lot of ours were either reversals, first of all, back hauls, then reversals where the molecules flow in a different direction, or compression projects.
So that’s when lot of our – that’s why we have such a low FT relative to new builds. And so what would we do if we needed more capacity even to accelerate beyond what we have now? Odds are that there are a number of more distressed parties that have signed onto plenty of future projects that are in distress and probably won’t be using their capacity.
So it’s always a first alternative would be to look at what’s called release capacity, where you sublet their capacity. And if they do it in a formal way, it’s put out on a bulletin board and sometimes those are discounted pretty heavily. Sometimes it’s a premium, but if pipes are under filled and we needed more, then we would look to be able to use somebody else’s space at a discounted rate. That would probably be the first direction we would go.
Got it. And then the hedging side of things, then if you’ve got – if your break-evens increasingly moving below $2, and I don’t know whether that’s how you think about it on a corporate level, or a well level, I mean, do you start to have more comfort with a long-term gas price of $3, or lower and hedging at those levels?
Well, the way we look at hedging right now, we are fortunate that we have such a substantial hedge position. So we are fully hedged in 2016 and 2017 and more than 80% hedged in 2018 and 2019. So we feel very secure. We also have hedges out in the 2020, 2021, and 2022 area, but we have the luxury right now of just watching. And we’ve been watching for a while now for several months and have seen the curves moving up.
So we’re not really looking to jump anytime soon at locking in more. The lowest hedges we have put in place in many years have been in the $2.75 range. And so is that an ideal price? No. If you asked us today, where do we think longer-term gas prices are going to be, somewhere in that $2.75 to $3.50, or even $3.75 range. So we might be looking towards those. I think we can develop that quite a bit lower prices than they have. But that – and withstand those, but we’re looking for higher prices and we’re extremely well protected over the next four years.
So I don’t think you will see us going – CAL 17 right now is hovering right at about $3, and I don’t think anytime soon we will be going and hedging below that. I think we are looking for higher prices yet and probably on the outer part of the curve. CAL 22 this morning was $3.40, so you can see we are inching up toward that $3.50 range and we will be looking towards the outer part of the curve, but not necessarily real soon.
Got it. And then I guess lastly, I think you mentioned early on or in one of your presentations the balance sheet doesn’t get incrementally more leverage potentially the opposite as you go about your growth strategy. But can you talk about interest levels beyond letting that play out in deleveraging, particularly from material asset sales or equity at the apparent level?
Yes, I think all we can say on that front is stable leverage this year and we expect to drive that down over time. So the nice thing is, we’re in a very opportunistic position, where we don’t have to do anything right now. We have a great hedge position, as Paul said, fully hedged, fully sold out essentially on our gas over the next two years, and most of our propane over the next two years, so we’re in good shape there. We can be optimistic. And then I think you’ve probably heard the guidance that over time we want to drive that down well under three times leverage.
Great. Thank you.
Thank you very much.
And our next question comes from James Sullivan of Alembic Global Advisors. Please go ahead.
Hey, good morning, guys.
Could you guys comment just very quickly. We know there’s lots of talk about last quarter, but on your kind of evolving ethane and geo-marketing strategy for incremental volumes. I know, obviously, you have got ATEX and the Mariner East and so on. But how do you guys see that market developing, number one.
And number two, I know would it seem like an out there question six months ago, but has there been any talk on ATEX capacity expansion yet, or do you think the appetite is greater for kind of nearer-in markets like Sarnia and so on?
Yes, so the ethane market certainly is improving. Why is that? Well it’s in part, people are foreseeing over the next couple of years the petro chem demand in the U.S., as well as exports becoming a reality in the arbed [ph] places like Northwest Europe are positive.
So you can see more and more interest in that. I haven’t heard any talk yet of ATEX expansion. It’s still probably running 50% to 60% full. And so, yes, maybe one would explore, if we were looking for more FT, would it be Mariner East, or more of ATEX, but unexpanded or the local markets, as you say, there’s still three cracker projects that are out there, ethane cracker projects in Appalachia that have not gone FID.
And certainly, as if things got healthier, then we would definitely look at those and pursue those a little bit more. We would be supportive of those, so we would look locally. But yes there has been a lot of positive dynamic. If you look at gas value of ethane right now, it’s in the mid to high-teens, whereas the futures market you’re seeing 2017 and 2018 now in the $0.26 to $0.28. So there’s definitely a premium developing beyond gas value for ethane and so the market is definitely seeing shortages and more demand.
Great, thanks for the color, guys. And do you have any commentary I know we’ve already touched on it once today, but on the Rover timeline? I know it’s been delayed and you guys are probably just working with the ET timeline, which is mid 2017, but do you have any commentary on that or on the kind of chatter about it getting downsized, number one?
And then on the other hand, given your guys reservation on that, I know you talk about keeping the one rig running in Utica just to fill Rex until that starts up. Would you guys – how long do you think you guys would need to fill it your capacity on there? I know that’s kind of a loosey-goosey question, because capital is your constraint, but – or maybe said another way, how much would it cost to sell it and would you guys ramp ahead of time to try to absorb the capacity?
Yes so, we do have discussions with Energy Transfer. They have been very good at updating us on their progress. We do believe their timetable of having Rover in place by mid-2017. There’s some interesting photographs out there now of their staging yard in Massillon, Ohio and they have got over 400 miles of 42 inch pipes that are there in the staging area, and that would build out in a large segment of Rover from Claring to Defiance plus a couple of legs.
I think they’re going to phase it in but, I’m not sure what they’ve said. So not sure whether it’s full bore at 3 plus Bcf a day or something less than that. But we are certainly happy to get our FT on Rover. We have 800 million a day contracted with them and the way our projections look right now. It will take on the order of a year to a year and a half, for us to be able to fill that out of the Marcellus. There maybe, as we gain more confidence that that truly is the timetable.
We may begin to put rigs back to work in 2017, getting ready to ramp up into the new Rover capacity. It takes a while to of course drill out pads, and then frack them and get ready for production. So let’s say in early 2017, if we’re convinced that it’s coming in mid-2017, you could see us put more rigs back to work in the Utica.
Okay, guys. Thanks so much.
And our next question comes from Ben Wyatt, of Stephens. Please go ahead.
Hey, good morning, guys. Just quick question on Slide 10 here, you have some information here just kind of on rigs and crews? And just curious if you guys could give us any color on how you see that shaking out maybe over the next couple of years, kind of that ratio of rigs to crews? And then your thoughts around, if you were to ramp in 2017 and 2018, any tightness on the oilfield services side considering the downturn?
Yes, of course everyone is following the rig count and a whole lot of rigs have been laid down. The rigs that have been laid down in Appalachia are dry stacked in Appalachia, so they haven’t left the region. But definitely the crews have been downsized. So it’s probably easier to ramp things up and pull rigs out of stacking and those are more readily available than the crews.
But we would expect as the industry begins to ramp up – back up that probably the most experienced crews would be called back first. So I don’t think we’d have to go through the cycle of very green hands like you see when there were 1,600 plus rigs running and the last crews were extremely green.
So probably could attract the experienced crews. We have not seen any pressure on oilfield services that still we’re seeing, there’s plenty of services being available on the spot rate, both on drilling rates for the kinds of rigs we like and the stage costs on – with who we think are competent frack companies. That those have gone down quite a bit and we don’t see any upward pressure at all.
Very good, that was it from me. Thanks, guys.
And our next question is a follow-up from James Sullivan, of Alembic Global Advisors. Please go ahead.
Thank you, guys. Thanks for letting me on one more time, real quick I just wanted to clarify, I think you had said this, but in your maintenance and growth capital assumptions on Slide 6 of the presentations, are you guys using your 2015 F&D per Mcfe numbers or are you using them for the Q1 2016 numbers, which are the lower ones?
We’re using sort of year end assumptions around reserves per well and the production that comes from those wells. So there is upside to those production forecasts if we continue to see 2 Bcfe per 1,000 or 2 Bcf per 1,000 at the wellhead or greater over time. So you do see some production upside there with the same dollar spending.
Great, thanks. And then just last one here. On the 10,000 foot lateral slide and this may be me reading a little too much into your graphic here, but it looks like there’s a little bit more dispersion from the mean in the well results as you go out past 10,000 feet. Is that just noise or do you think it has anything to do with the relative difficulty of landing and zone when you go out that long? And where does the risk/reward kind of become unattractive for the super-long laterals?
Well James, yes this is a new slide. And so I don’t think we would attribute any greater range of outcomes, only that it’s newer. I think we have quite a bit of confidence that we can stay in zone for 10,000 feet or we just as we score proppant placement. We also score staying within zone and it’s in the high 90’s percent. I think we’re in good shape there. We are fortunate that we are in an area where there is virtually no folding or faulting. And so it’s readily defined and we get better all the time.
So I see your point that that oval it looks a little bit bigger. I’m not sure if you got rid of the oval where you can see much more dispersion, maybe there’s more dispersion there or difference to the upside that I see more points off north of the curve than south. But it’s a good question, but we’re not really seeing it that way that it gets more risky going out that far.
All right, great. Thanks, guys very much.
And this concludes the question-and-answer session. I’d like to turn the conference back over to management for any closing remarks.
Thank you for joining us on our conference call today, and please feel free to reach out to us if you have any further questions. Thanks again.
And thank you, sir. Today’s conference has now concluded, and we thank you all for attending today’s presentation. You may disconnect and have a wonderful day.
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