Antero Resources Corporation (AR) Q3 2015 Earnings Report, Transcript and Summary

Good day. And welcome to the Antero Resources Third Quarter 2015 Earnings Conference Call and Webcast. All participants will be in listen-only mode. [Operator Instructions] After today’s presentation, there will be an opportunity to ask questions. [Operator Instructions] Please note, this event is being recorded. I would now like to turn the conference over to Mr. Michael Kennedy, Vice President of Finance and Director of Investor Relations. Please go ahead.

Thank you for joining us for Antero’s third quarter 2015 investor conference call. We will spend a few minutes going through the financial and operational highlights and then we’ll open it up for Q&A. I would also like to direct you to the homepage of our website at www.anteroresources.com, where we have provided a separate earnings call presentation that will be reviewed during today’s call. Before we start our comments, I’d like to first remind you that during this call, Antero management will make forward-looking statements. Such statements are based on our current judgments, regarding factors that will impact the future performance of Antero and are subject to a number of risks and uncertainties, many of which are beyond Antero’s control. Actual outcomes and results could materially differ from what is expressed, implied or forecast in such statements. 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 the call today. In my comments I am going to highlight some of the key achievements from our third quarter 2015 results, discuss our peer leading EBITDAX, EBITDAX margins and price realizations, and review the dropdown of our water business from Antero Resources to Antero Midstream. Paul will then discuss operational highlights from the quarter, provide an update on the regional gathering line expected to be in place online in December of this year. Review current well costs and expectations moving forward and provide further commentary on our preliminary 2016 development plans. On the production front, we had another outstanding quarter, setting record quarterly production levels passing the 1.5 Bcfe a day quarterly production mark for the first time in our history. Liquids production during the quarter averaged over 52,000 barrels a day and made up nearly 21% of our production stream and that’s C3+ NGL, of course, plus condensate. Both the overall production growth and liquids production growth were driven by outstanding results in our Utica operations, where we placed 25 wells online during the quarter. Utica net production increased over 120 million cubic feet a day equivalent to an average of 365 million cubic feet a day equivalent, including liquids production of 19,250 barrels a day for the quarter. During the quarter, we once again realized peer leading EBITDAX and EBITDAX margins and price realizations driven by our record production, attractive firm transportation portfolio, significant hedge, hedge book and reduced operating cost, which I’ll touch on shortly. As outlined on slide two of our earnings call presentation, titled Antero Outperformance. We achieved an EBITDAX margin of $1.97 per Mcfe, with $291 million of consolidated EBITDAX. As you can see on the top half of that page, page two, over the last five quarters we have consistently achieved peer leading EBITDAX margins among our peer group. We have outperformed the average peer group EBITDAX margin by more than 70% in third quarter alone. Pointing you to the bottom half of the page, we generated the same level of EBITDAX during the third quarter of this year as we did the prior year quarter, despite more than a 50% drop in oil prices and 30% drop in gas prices. This compares favorably to the peer group, which generated on average 42% less EBITDAX compared to the prior year quarter. This was the second consecutive quarter that we generated a the highest EBITDAX among our Appalachian peers and we had over $75 million higher EBITDAX than our next closest peer. These financial results truly demonstrate the sustainability of Antero’s business model. These strong EBITDAX results was primarily driven by our record production, attractive firm transport portfolio, which enables us to take our gas to more favorably priced markets and our substantial hedge book of course. Turning you to Slide #3 of our earnings presentation, titled 3Q 2015 Natural Gas and NGL Realizations, you can see that our natural gas realizations during the third quarter was $2.32 per Mcf before hedging and $3.99 per Mcf after hedging, that’s on the upper left portion of that graph. The before hedging price in yellow represented a $0.45 differential to the NYMEX price for the quarter. This was 25% higher than the peer group median on pre-hedged prices and 62% higher than the peer group median including hedge settlements. We sold 68% of our gas during the quarter at favorably priced indices, including TCO, NYMEX and Chicago, and expect that percentage to grow to 95% in 2016. On the NGL front, we realized $12.08 per barrel before hedging and $16.47 per barrel after hedging. Similar to our realized gas pricing, our NGL pricing was more than double the peer group average on pre-hedge prices and almost triple the peer group average when you include hedge settlements. We expect this outperformance to continue as we are 100% hedged on propane in 2016 and gain access to international markets in 2017 through our Mariner East II capacity. On the not hedging front, we again generated substantial realized hedge gains of $206 million or $1.49 per Mcfe during the quarter. As you can see on Slide #4 of our earnings call presentation, titled Hedging Integral to the Business Model, this represented the 26 out of the last 27 quarters since 2009 that we realized a hedge gain, generating over $1.5 billion in cash revenues over that timeframe. As we’ve discussed on past calls, hedging is not just complementary to our business model but integral to our success and long-term development plans. We sell a significant portion of our production in fall and it’s a simple as that. The shale revolutionize has changed the dynamics of the oil and gas industry. Given our significant low-cost resource position in what we believe is one of the most attractive shale plays in North America. It is imperative that we are able to lock in attractive rates of return through our substantial hedge book and diversify the firm transport portfolio. We now have 3.1 Tcfe hedge going forward, at an average price of $3.93 per MMBtu, which equates to a $2.8 billion mark-to-market value, as of September 30th of this year. As highlighted on Slide #5 of our earnings presentation, titled insulated from 2016 commodity price volatility, we are nearly 100% hedged on our preliminary target 2016 production range, at $3.94 per Mcfe. The only components of our production stream that are unhedged at this time are the C4 Plus NGL products and our condensate production. Given the significant hedge position, we could experience $30 oil and $2 natural gas throughout the year and only lose approximately 3% of our expected EBITDA, based on current strip pricing. You can see that in the middle of the page, lower part -- middle of the page on the graph. So needless to say, we feel very good about our 2016 development plans. Before I highlight some of the key quarterly financial results, I want to discuss the dropdown of our water business from Antero Resources to Antero Midstream that occurred in late September, as well as highlight the recent increase to our borrowing base, which was completed earlier this week. First on the dropdown, Antero Midstream acquired the entire water business from Antero Resources for $1.05 billion, with AR receiving $794 million in cash, and 11 million common units in MLP, plus two potential earn-out payments of $125 million each, due at the end of 2019 and 2020, if certain delivered volume thresholds are met. We are very excited to complete this transaction and believe it was well structured by the AR and AM independent committees, resulting in a win-win for all the parties involved. From the AR side, the transaction enabled us to substantially de-lever our balance sheet through the $794 million cash payment received. And we increased our holdings in AM by 11 million units, retaining 66% interest in MLP. Additionally, the earn-out payments provide another incentive for long-term AR growth. On the credit facility front, despite the significant decline in commodity prices over the last year, our borrowing base increased by 12.5% to $4.5 billion, which was driven both by our PDP reserve growth and by the increase in the value of our hedge position. We are only --we are one of only a handful of companies in the E&P space with a borrowing base over $500 million that has increased its borrowing base thus far during this re-determination season. On the heels of the credit facility commitment increase in the spring, we think this really speaks to the productivity of our assets, quality of our reserves and resiliency of our business model. As outlined on Slide #6, titled strong balance sheet and financial flexibility, you can see in the top left fourth quadrant that, as a result of the water drop, Antero Resources liquid non-E&P assets of $5.5 billion exceed total debt of $3.9 billion by over $1.5 billion. So the non-liquid E&P assets are the commodity derivatives and the equity ownership in AM. To emphasize the point, while we have no plans to do so, we could repay all debt, and have over $1 billion in cash on the balance sheet, if we chose to monetize our liquid non-E&P assets. This relationship is quite extraordinary relative to our peers in the industry today. In the bottom left quadrant, AR has nearly $3 billion of credit facility liquidity on a standalone basis, as of September 30, and approximately $4 billion on a consolidated basis. Rounding out my comments for today, let’s touch on the quarterly consolidated financial results. Antero Resources adjusted net revenue increased 12% from the prior-year quarter to $570 million per unit. Production expenses were $1.32 per Mcfe, which is an 18% decrease from the prior-year quarter and well below our full-year 2015 guidance range of $1.50 to $1 60 per Mcfe. Driven by lower production tax expenses stemming from lower commodity prices, a reduction in estimated property taxes as well as reduced fuel cost due to lower commodity prices. Our production expenses include leased operating, gathering, compression, processing and transportation cost as well as production tax. Our per unit net marketing expense for the quarter were $0.19 per Mcfe, also below our 2015 guidance range of $0.20 to $0.30 per Mcfe, primarily as a result of our increased Utica equity production volumes flowing on our Chicago-directed firm transportation portfolio, thereby reducing unused capacity on this firm transport. Our G&A expense for the quarter was $0.26 per Mcfe, a 10% decrease from the third quarter of 2014, and within our guidance range of $0.23 to $0.27 per Mcfe, excluding non-cash stock compensation expense. EBITDAX for the third quarter was $291 million, in line with last year’s third quarter, despite a 32% reduction in NYMEX natural gas prices and a 53% reduction in oil prices. Lastly, during the quarter, we spent $341 million on drilling completion, $39 million for land, and $20 million for water projects. Driven by our strong financial position and significant hedge book, we believe we are well positioned to continue executing our development plan for many years to come. With that, I will turn it over to Paul for his comments.

Thanks, Glen. In my comments today, I am going to further discuss operational highlights from the quarter, provide an update on the in-service timing of the regional gathering pipeline that we’ve discussed on past calls and its impact to Antero’s bottom line. I’ll review current well costs and expectations moving forward. And I’ll provide additional commentary over our preliminary 2016 production growth targets. First, let me provide some additional color as it relates to some of our key operational highlights from the quarter, particularly in the Utica. As Glen mentioned earlier, we completed and placed online 25 wells in the Utica during the quarter. And this represented over 80% of the wells that we placed online during the quarter and over 26% of all Utica wells that we’ve put to sales since the beginning of 2013. So it was a very productive quarter in the Utica. The Utica activity is what really drove both our overall production growth, and more specifically our liquids production growth, with an average liquids content from these 25 wells of 33% in ethane rejection. With all that being said, we also completed the driest, most down-dip Utica pad by Antero to date, the so-called Laura Ditch pad. Even under a flow-back management program, these wells had an impressive combined average 30 day rate of 64 million cubic feet equivalent per day, with average flowing casing pressure of 3,400 pounds per well for the 30 days. As a reminder, through our attractive firm transport portfolio, we are able to sell our Utica gas volumes to the Chicago market, and the Michigan market, which historically trade at a premium to NYMEX pricing. Driven by the attractive, Chicago and Michigan pricing, along with the BTU upgrade we receive on our gas from rejecting ethane and leaving it in the gas stream, we realized a $0.26 per Mcf premium to NYMEX during the quarter on our Utica gas sales, an outcome we are very pleased with. In West Virginia, we completed six Marcellus wells during the quarter, with an average lateral length of approximately 10,300 feet, and an average stage length of approximately 200 feet. Slide #7 details the drilling and casing of our first West Virginia Utica shale well in Tyler County earlier this month, at a total vertical depth of 11,400 feet, and a lateral length of more than the 6,600 feet. We are currently beginning completions activity on this well. Once the well is completed, we will produce into our rich gas infrastructure, in order to assess its performance and the appropriate pace of development, once the Energy Transfer Rover Pipeline is placed into service, and goes right near this area in 2017. As it relates to drilling and completion costs, we continue to be very encouraged by what we are seeing today. We have reduced well costs in both the Marcellus and Utica by 16% and 18% respectively, as compared to 2014 costs. In the Marcellus, approximately 50% of the savings are from service cost reductions and 50% are from operational efficiencies. In the Utica, approximately 65% of the well cost savings are from service cost reductions and 35% are from operational efficiencies. Year to date, we have averaged $0.90 per Mcfe of development costs, including about $1.2 million per well of road, pad and facilities costs. On the service cost side of things, it’s important to point out that many of our drill rigs and frac crews today are still under legacy contracts. When these contracts roll off and we are able to re-contract at spot market rates, we expect to achieve further savings on well costs of approximately 10% to 12%. As you can see on Slide #8, titled high return locations drive value creation, these additional savings will result in increases to our rate of drilling economics of approximately 10 to 15 rate of return points. Moving on to the regional gathering pipeline, I want to provide everyone with a status update of the project and discuss the impact of the pipeline, and what it will have on our bottom-line cash flow. Based on the current status of the project today, we expect the pipeline to be placed into service into early December of this year. To help understand what this means for Antero, I’ll refer you to Slide #9, entitled projected incremental EBITDA from regional gathering pipeline in the service. As you see on the map, on the right side of the page, once the pipeline is operational, this will enable us to shift all Marcellus production that would otherwise flow north to Dominion South and TETCO M2 pricing. Instead, move it down the regional gathering pipeline, which will enable us to receive TCO and NYMEX -based pricing. Based on the preliminary 2016 targeted development plan, this results in a 650,000 MMBtu per day shift in volumes in 2016 from the inferior markets to the superior markets. As outlined on the top of the map, you can see the spread between Dominion South and NYMEX is a $1.04 per MMBtu, and the spread between TETCO M2 and NYMEX is $0.96 per MMBtu based on current 2016 strip pricing. Additionally, as shown in the table on the left side of the page, by shifting the 650,000 MMBtu s a day away from Dominion South and TETCO M2 pricing in 2016, and selling it instead at NYMEX and TCO, primarily through contracted firm sales, we will realize incremental revenue of more than $160 million based on strip pricing as of September 30th. After incorporating the additional demand and variable costs associated with the regional gathering line, we will wind up with just over $125 million in incremental EBITDA in 2016, as a result of gaining access to this regional gathering pipeline. Before wrapping up, I’d like to briefly touch on our 2016 preliminary production growth target. We continue to receive questions about this growth target, so I first wanted to make a couple of clarifications. The 25% to 30% production growth we have highlighted is growth relative to our 2015 production guidance of 1.4 Bcfe per day. While we are trending towards finishing this year above the 1.4 Bcfe per day guidance, we want to make sure everyone understands that 2016 target is still based on percentages above our 2015 guidance. As we mentioned on our last earnings call, we feel very comfortable with our 2016 production growth target given our inventory of drilled but uncompleted wells, our top-tier firm transport and hedge book that insulates us from virtually all commodity price scenarios, and the continued well cost reductions we are seeing today and expect to achieve in the future. While we understand that we cannot ignore the challenging commodity environment we face today, we feel that we positioned the business to succeed and deliver value to our shareholders for many years ahead. With that, I will now turn the call over to the operator for questions.

[Operator Instructions] The first question comes from Neal Dingmann of SunTrust. Please go ahead. : Hey, guys. Good morning. This is Will for Neal. Nice quarter. First question, looking at your kind of talking about the ‘16 growth target, how do you guys see activity shifting in the current environment between dry gas, wet, or focusing on the dry gas Utica in West Virginia or in Ohio?

We continue to see good rates of return in our rich Marcellus, but we also like to dry. So I think we will see that there will be a shift in the Utica to little dryer and still about the same BTU levels in the Marcellus. We will juggle back and forth the emphasis based on regional takeaway. So it may be a little more capital spending and a little more drilling over on the Marcellus side, with the regional gathering line that we just described. And then as we wait for more pipe to come into the Utica and some of our firm transport on ETC Rover will come online we expect at the end of 2016. And so until then, midway through the year we’ll start to fill up our Rex capacity and perhaps will use other people’s capacity beyond what we have. So there will be a little bit of juggling, but getting a little dryer in the Utica and staying about the same BTU in the Marcellus. : Okay. Thank you. And then on -- you talked about Stonewall quite a bit, can you help us get a better idea of what the net cost is for you all to move gas on that system?

Yeah, I think it’s in the $0.20 range, let’s say, is probably a good estimate there. : Okay. Thanks.

All right. Are there any other questions?

Okay. The next question comes from Holly Stewart of Howard Weil. Please go ahead.

Good morning, gentlemen.

Hi, Holly.

First question, maybe just on the West Virginia dry gas Utica well, is there a plan to flow test that well, or are you just going to flow it under a restricted rate?

Just flow is under restricted rates. So we have of course a frac design. Let me back up and say we are pleased with the way that the drilling went. We’ve got a lot experience in drilling deep, high pressured wells. We have used an extra big rig, extra big high pressure stack on it, so really didn’t see any difficulties in getting the well down and cased, so feel good about that. And so we will be fracking it over the next month or so, and the plan is to use combination of resin coated and ceramic proppant and we’ve got our design. So we will frac it. We will flow it back under restricted rate. We definitely don’t want to suffer any flowback of proppant or crushing. So we will keep it somewhat restricted. And so it will probably be a little bit of time before we begin to see decline in it. We know from certain offset wells we could open it up. We’ve had lot of big wells in our time in both plays. And in any of them, you can open it up and get an impressive marquee flow rate, but I think we will restrict it in that 15 million or 20 million a day range.

Great. Thank you. And then I guess, Glen, care to share the ASE on the wall?

I think this one has a little bit more science to it in that we went to straight down first, drilled the pilot portion, so we could see the Utica Point Pleasant in the vertical sense. So we did high resolution logs, we did pressure tests, sidewalk cores and so on. So we could fully understand it and also make sure which exact zone we wanted to go sideways in. So that cost a little extra to come back up and then kick off and go sideways, but I think this will be around $15 million roughly all in and can we get development wells, a few million dollars less than that, that might be possible.

Okay. Great. Thank you. And then I guess the final one on the West Virginia dry Utica, is there any intention in 2016 to allocate additional capital there?

It’s possible. It might be a little early. I think we don’t expect the Rover line that comes down to Sherwood to come in until mid ‘17. So until then, any dry gas that we develop would come, we would probably send through our rich gas system and not the end of the world that we would be sending dry gas through the Sherwood processing complex. There may be some other alternatives, Eureka Hunter and so on that possibly would connect us more directly without going through plan, but we’d have to let those considerations unfold.

Got it. And last one for me, just on maybe the M&A landscape. It sounds like there’s a lot of asset packages out there. Just curious to get you guys take and then curious if you’d be an active buyer in this market?

Well, there are good packages, good properties, don’t think you’ll see us buying a company, that’s really not what we do. We’ve added so much value just by base leasing. So if there are some leasehold that would appeal to us we might approach it that way.

Thank you, guys.

Thank you.

The next question comes from Brian Gamble of Simmons & Company. Please go ahead.

Good morning, guys and good quarter.

Good morning.

Morning. First wanted to chat on the production, you mentioned the production growth for next year, wanted to focus a little bit more short-term, if I may, to start, I think last quarter, you talked about the expectation in Q3 might be a slight down tick and then we see an uptick in Q4, obviously, outperform that in Q3, anything that shifted? Should we still expect Q4 to be a slight uptick in the production arena?

Yeah. I think, Q4 will be pretty flattish. We accelerated some completions in the Utica just due to great performance out in the field. I think that’s probably would drove the outperformance in the third quarter. So I would not expect to being uptick in the fourth -- in the overall net basis.

Great. And then when you talk about the production growth, appreciate the clarification and its also 1.4 guidance. When you mentioned the ducts are part of that plan and I think, maybe the moderation of some of those duct as we go through the year, exactly kind of walk me through that? What is based into that? How many ducts to get to that 25% to 30% are you expecting to drawdown during 2016 and maybe if you wanted to touch on the total CapEx level that you’re forecasting with the net growth range that might be helpful, as well as any true-ups on that from the last time you talked about it?

Yeah. As part of that, you’ll see 50 to 60 uncompleted wells get completed starting around year end most likely. We’re seeing continued improvement in frac cost from the cost that we’re seeing out there and so we’re looking to started on that, I don’t think we’ll do them all in a couple of months, we’ll spread them out throughout the year. So I think you’d see us running probably eight or nine frac crews throughout the year, next year to work that duct portfolio if you will. And then as far as capital, it’s been a moving target to our favor, of course, which has been terrific and I think relative to what we said a few months ago in the last quarterly call. We’d expect to see our drilling completion capital sort of inline with this year’s actual numbers. So we don’t expect to see an increase there and maybe a slight decrease in order to hit that kind of production growth for next year.

Great. And then on the NGL side, you seem to have at least some moderation in the down tick that we’ve seen throughout 2015 from a realization standpoint? Any reason to believe that we’re getting any better as we walk into the winter, I mean, theoretically, seasonally, we should, anything out of the ordinary that helps that as we walk into 2016?

No. Not out of the ordinary. I think you’d say, well as the near-term drilling subsides a little bit in Appalachia that will back-off and the volume and the volume increase. There is a little bit of export that will now go on with Mariner I with ranges volumes to export out of market, so in a sense draining the surplus a little bit. So between a little bit decline in drilling and a little bit of export can the Northeast markets improved, it’s possible. I think the next year to drop really is at the end of ‘16 when Mariner II opens, because that has a lot of export capacity possibilities. As the market knows, as many know, we have firm capacity on Mariner East II of 50,000 barrels a day and move propane, butane through that, as well as 11,500 of barrels a day of ethane. But there are possibilities for overflow and moving more volumes out of Marcus Hook through Mariner II for us and for other parties and so will that help draining the bath tub and the surplus beginning in really in ‘17. That would be when that happens because Mariner East isn’t expected to come on until end of ‘16. But that’s where we’re looking for some short intermediate term improvements in prices on the liquids.

Great. Appreciate that Paul.

Sure.

The next question comes from Kevin MacCurdy of Heikkinen Energy Advisors. Please go ahead.

Can you guys detail how much new firm transportation and firm sales you have coming online in 2016 and what kind of flexibility you have in filling or potentially releasing any of that incremental capacity?

Yeah. Let us pullout some schedules here, Kevin. Just to start out while we’re dating that up, of course, you always have flexibility in releasing capacity. There are bulletin boards for each pipe and so you can release for any period of time you want and you put it on the bulletin board and people did on it and of course, it’s either they’re bidding a discount to your cost or a premium depending on the spreads across the pipe and how scarce it is and so that’s certainly possible. I think another thing I want to add is, if looking into rear view mirror, yes, we’ve been paying for open space on some pipe, the pipe grows and our production grows, of course. But there are some pretty good examples, for example, our Rex capacity where we have been paying the past number of months on open capacity on Rex, buying other peoples gas to offset the transport. But by first quarter, second quarter of this year, all of our Rex capacity for example is full and we’ll be out there looking at the other opportunities to flow gas out of the Utica. So it’s a moving target that what is open space today fills up pretty rapidly with the pace of growth that we have on, let see. So as to a chart and how much firm capacity we have. Today we have 2.6 Bcf a day and through the course of cal 16, we’ll move up to about 3.8 Bcf a day. And quite a bit of that capacity is precious, in that we can buy distressed gas in the TETCO M2 pool and the Dominion South pool and move it through some of that transport and pick up a pretty good spread. So there’s a very active program here at Antero to -- certainly to fill our unused capacity, and to trade through it and buy third-party gas and do everything that we can to offset our transportation costs.

And you can see that chart on page 34 on the website presentation for AR. You can see the page Paul is referring to.

Great. Thanks for the clarity.

Thank you.

[Operator Instruction] The next question comes from Dan Guffey of Stifel. Please go ahead.

Good morning, guys. Congratulations on a good quarter. Just looking, you guys highlighted drilling your driest Ohio Utica well. Was that in your 40,000 net acres that’s the dry gas portion or was that just west of that mark? And then I guess, is that 40,000 dry portion of Ohio Utica in your 2016 plans or is infrastructure still not built out enough, as you move to the East?

I’d have to look at the map, but I am going to say that Laura Ditch is right on the border. It’s roughly in the 40,000 acres of dry gas that -- yes, it’s borderline. It’s at around 1,130 BTU. We are looking at a map here, Dan. So it’s on the up-dip edge of the 40,000 acres of dry-ish gas that doesn’t need processing. And so yeah, infrastructure is coming along. We will be able to produce a lot of those dry pads. But as I just mentioned in the answer to that last question, we will be filling up our Rex by first or second quarter with completing the wells that are underway right now. And so the infrastructure will lead into other people’s transport, as well as TETCO. And so that’s why the emphasis will be, move over and drill a little bit more Marcellus during cal 16.

Okay. Thanks for the color. And then can you talk about maybe your appetite and if you’ve had any discussions regarding the Pennsylvania acreage swap and/or sale?

Our appetite? It’s extremely good acreage and there’s drilling all around this. Rice, EQT, others surround us. So it is very good. We have just a couple of wells that we drilled years ago there before we shifted our focus to West Virginia. They had very high -- the metrics we look at of course are EURs and Bcf per thousands. We did those completions in the old style, 400-foot plus stage lengths and still had very good wells. So know it’s highly prospective, well blocked up, good term on it. So would we trade or sell? It’s possible. But there is no movement underway right now to do that. It’s in good shape and we are patient. So we may get to drilling it as the regional gathering lines come in. There’s a way to actually move that gas south to the same destination that our West Virginia Marcellus gas goes. So definitely has value there that can come to the better markets beginning in a month.

Okay. And I guess last one for me. And I think I know the answer, but I’ll ask anyway. You guys -- obviously you have highlighted you guys have one of most comprehensive hedge books in the entire industry. And I know this would go against any kind of business philosophy that you guys have, but is there a price where you would monetize any portion of your hedges, particularly when you look out to 2020, 2021, or any of those later dated hedges that are extremely valuable at the current strip?

Yeah, I think we would say, never say never, but I think we will probably give you the answer you’re expecting Dan which is, we just haven’t done that before. We just keep it simple. We’ve only done straight swaps, no collars or three-ways or anything, and we’ve left those in place. When you look back in history, those that have yanked their insurance policy so to speak, when they yanked their hedges, sometimes they -- mostly they live to regret it. So I think we are probably going to keep them in place

Yes, I think a lot of analysts incorrectly look at our hedge book as just a financial position, a trading position. We’ve never taken any hedges off. That’s why I made the comment earlier that you should really look at our hedges as a forward sale. I mean, we are just selling our production forward where we like the prices and we tend to go out further than most other producers. And we’re reaping the benefits of that today in a down market.

Thanks for all the detail, guys. And congrats on a good quarter.

Thank you.

The next question comes from Jeoffrey Lambujon of Tudor, Pickering, Holt & Company. Please go ahead.

Good morning. I appreciate the color on the optionality of fill volumes, or I guess excess capacity next year with third party gas. Is there any more detail you can provide in terms of much excess capacity, I guess mitigation you are targeting next year? I know it’s price dependant, but any advantage or thoughts around expectations would be helpful.

Yeah, we will guide to that when we come out with guidance later, but I don’t think we are really prepared to give you guidance on that today, but we think it’s all very manageable.

All right. Thank you.

Thanks.

This concludes our question-and-answer session. I would now like to turn the conference back over to Mr. Kennedy for closing remarks.

Thank you for participating on our call today. If you have any further questions, please feel free to reach out to us. Thanks again.