Antero Resources Corp (AR) 2017 Q1 法說會逐字稿

Good morning, and welcome to the Antero Resources First Quarter 2017 Earnings Conference Call. (Operator Instructions) Please also note, this event is being recorded. I would now like to turn the conference over to Mr. Michael Kennedy. Please go ahead.

Thank you for joining us for Antero's First Quarter 2017 Investor Conference Call. We'll spend a few minutes going through the financial and operational highlights, and then we'll open it up for Q&A. I would also like to direct you to the homepage of our website at www.anteroresources.com, where we've 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 forecasted 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 Paul.

Thank you, Mike, and thank you to everyone for listening to the call today. In my comments, I'm going to discuss productivity gains that we continue to achieve through our advanced completions, highlight a couple of notable pads that were recently placed to sales and provide updates on key infrastructure projects that influence our development plan going forward. Glen will then highlight our first quarter financial results and discuss our peer-leading, liquids-rich position and development plan, which provides us with a material uplift on our realized pricing. Finally, Glen will conclude with a summary on the operational flexibility and integrated business strategy at Antero and how this provides us with tremendous long-term operational visibility.

Let's begin with discussing the operational momentum that has continued at Antero over the last few years. As illustrated on Slide #2, entitled Marcellus Completion Evolution, the main chart shows the evolution of Antero's completions over the last few years and the productivity gains we've achieved during this time. As you can see on the bottom left of the graph, the dark green diamonds represent wells completed with our legacy completion design using 1,250 pounds or less of proppant per foot and 32 barrels of water per foot, on average. These 2015 completions support the 1.7 Bcf per 1,000 feet type curve at which the majority of our reserves are currently booked. Moving up and to the right, the red diamonds represent wells completed with 1,500 pounds per foot of proppant and 34 barrels per foot of water, essentially the recipe that we've used in 2016. As outlined on the insert graph at the top left of this slide, many of these wells now have over a year of production history and continue to support a 2.0 Bcf per 1,000 type curve. Then towards the end of 2016 and the beginning of this year, we began testing higher proppant loads ranging from 1,750 to 2,500 pounds per foot. At this time, we are very encouraged by the higher intensity completions and will continue to analyze the results from these completions as it relates to EURs and overall well economics.

Now, directing you to Slide #3, entitled Recent Marcellus Well Results, I'd like to provide some more color around some of the encouraging results I just mentioned. The first pad I'll highlight is a 4-well Marcellus pad located in the southern portion of our rich gas area in West Virginia. This pad is significant as it was one of the first pads completed with 2,500 pounds of proppant per foot. The 4 wells have an initial average wellhead EUR of 2.2 Bcf per 1,000 feet of lateral and an average processed EUR of 2.5 Bcfe per 1,000 feet of lateral, assuming full ethane rejection. What's most notable about this pad is the fact that it is located outside of our high-graded core areas. To the extent we continue to see encouraging results in this area, it is likely that the red and orange high-graded core outlines could be extended. The other pad I'll touch on from this slide is a 4-well pad completed in our highly rich gas regime in the Marcellus. The 4 wells on this pad have an average lateral length of 10,000 feet, an average wellhead EUR of 2.4 Bcf per 1,000 feet of lateral and an average processed EUR of 2.9 Bcfe per 1,000 feet of lateral, assuming full ethane rejection. In addition to the advanced productivity from these pads, the other key takeaway from this slide is the continued downward trend in finding and development costs. As highlighted in yellow on each pad, F&D costs are trending as low as $0.35 per Mcfe.

Now turning your attention to Slide #4, entitled Improving Marcellus Returns. When you combine these increased productivity gains with Antero's long laterals, you can really see the material impact on well economics and value creation for shareholders. Note at the bottom of the page, you can see that we've -- we have over 1,800 drilling -- undrilled locations at the 1,200 to 1,300-plus BTU regimes, and we continue to add to our core drilling inventory, as you can see on Slide #5, titled A Leading Consolidator in Appalachia. We've added 113,000 net acres to our core Marcellus and Utica positions since the beginning of 2016, including 32,000 net acres, thus far, in 2017.

Next, I wanted to provide an update on a couple of the long-haul infrastructure projects and how the projects impact our overall development plan. In early February of this year, Energy Transfer received FERC approval to proceed with the construction of the Rover pipeline. Energy Transfer has reiterated its plans to place Rover into service in the third quarter of 2017 with Phase 1 expected to come online in July of 2017 and Phase 2 expected to come online in November of 2017. As a reminder, we are in anchor shipper on Rover with an 800,000 MMBtu per day firm commitment. Phase 1 of the project will connect our Utica assets to the Midwest and Gulf Coast through the Seneca processing facility in Ohio, and Phase 2 will connect our Marcellus assets to the Midwest and Gulf Coast markets through the Sherwood processing facility in West Virginia. A number of Utica locations are currently in the process of being completed in anticipation of the Rover phase 1 startup. Once phase 2 is placed in service, connecting the Sherwood facility with Rover, we will likely fill Rover with Marcellus gas while our Utica production continues to grow into the capacity. Rover will then deliver our Marcellus and Utica gas to either the Midwest markets or onto our ANR south firm transport that delivers to the Gulf Coast. Given the optionality that we've built through our drilling inventory, development plan and firm transport portfolio, we feel comfortable in our ability to adapt to a number of different pipeline in-service timing scenarios and deliver on our long-term growth targets.

Shifting to liquid infrastructure. I'd like to discuss a couple of announcements during the quarter that enhance Antero Resources' long-term development plans. In February of this year, construction on the Mariner East 2 pipeline began, and it is expected to be operational in the fourth quarter of 2017. As illustrated on Slide #6, titled NGL Infrastructure Buildout in the Northeast, Mariner East 2 will transport NGLs from the Marcellus and Utica to the Marcus Hook export facility. We are an anchor shipper on Mariner East 2 with a 61,000 barrel per day commitment, which is comprised of 11,500 barrels of ethane, 35,000 barrels a day of propane and 15,000 barrels a day of butane. This is an important project for Antero, as it will allow us to export our growing liquids production to international markets and receive Mont Belvieu-plus pricing at the terminal. When you combine our Mariner East 2 commitment with our 20,000 barrel a day ethane firm transportation contract on the ATEX pipeline and our 30,000-barrel a day ethane supply agreement to the Shell ethane cracker, we have committed to overall NGL takeaway capacity or firm sales of 111,500 barrels a day.

In addition to the Mariner East 2 announcement, we also committed to 2 more processing plants at the Sherwood facility called plants #10 and 11 during this past quarter. This secures an additional 400 million cubic feet a day of processing capacity to support our liquids-rich production. Antero had already previously committed to Sherwood plants 8 and 9, which are expected to be in service in the third quarter of '17 and the first quarter of '18, respectively, and then plants 10 and 11 are scheduled for the third and fourth quarters of 2018. As a reminder, Antero Midstream owns a 50% interest in Sherwood plants 7 through 11 as well as 6 future plants at a to-be-determined location through its 50-50 joint venture with MarkWest Energy. The joint venture is significant to Antero Resources for 2 reasons: first, it improves our downstream visibility into processing fractionation and liquids transportation; and secondly, Antero participates in the upside from the value creations at Antero Midstream through its $0.59 -- 59% limited partner ownership.

In summary, these NGL infrastructure projects provide us with significant diversification of end markets and visibility on our growth plans. Glen will go into more detail on the pricing uplift that we anticipate from our liquids-rich development plans, but it should be evident the tremendous value we see in a diversified development plan, targeting both natural gas and liquids production going forward.

With that, I'll turn it over to Glen for his comments.

Thank you, Paul. In my comments today, I will highlight our first quarter financial results, including price realizations and EBITDAX margins, further discuss Antero's liquids-rich development plan, realized pricing uplift and conclude with a summary of our integrated business plan and how it positions us for success in both the near-term and long-term outlook.

Let's first look at some of the key highlights from the quarter. Production averaged a record 2.144 Bcfe a day for the quarter, including a record 99,000 barrels a day of liquids. The liquids production during the quarter consisted of over 7,000 barrels a day of oil and approximately 92,000 barrels a day of NGLs, representing a 45% increase from the prior year quarter and a 14% increase sequentially, as we remain the largest NGL producer in Appalachia. The outperformance we've seen over the quarter, most notably around liquids production, plays a prominent role in our long-term strategy as it boosts our production and price realizations, which I will expand on in just a minute. In fact, Antero was also the largest producer in Appalachia in the first quarter on a gas-equivalent basis at 2.144 Bcfe a day.

Moving on to realized pricing during the quarter. We had another outstanding quarter for both realized gas and liquids pricing. We realized a $0.03 premium to NYMEX Henry Hub or $3.35 per Mcf before hedges on our gas production during the quarter. That's dry gas only. This is the third quarter in a row that we've realized a premium to NYMEX prices. Even with local indices beginning to tighten, our extensive firm transport portfolio still proves to be a valuable asset to Antero, enabling us to continue moving our gas to the most favorable markets and consistently achieving a premium to NYMEX. We realized a natural gas hedge gain of $75 million during the quarter or $0.54 per Mcf. Moving forward, we believe our firm transportation and hedge book will continue to be competitive advantages for us, as uncertainty in the natural gas market's likely to continue.

As illustrated on Slide #7, titled Largest Gas Hedge Position in U.S. E&P, for the remainder of 2017, we are 100% hedged on our expected gas-equivalent production of $3.47 per MMBtu and 96% hedged on our targeted gas production in 2018 at $3.91 per MMBtu. Through the end of the decade, we are 84% hedged versus target gas production at $3.72 per MMBtu, which is a $0.72 per MMBtu premium to the current strip. Staying on the hedge topic, our hedge book is what really allowed us to continue our activity through the persistent commodity price downturn dating back to late 2014.

Since the first quarter of last year, Antero has grown production 22% from the first quarter of 2016 compared to its peer group that grew production approximately 8% on average over that time period. As we said at the time, by maintaining a considerable level of activity through the downturn, we were able to lock in more favorable terms on service contracts and keep the very best crews in place. We've also limited the ability for crews to walk away upon a ramp in activity by leveraging our ongoing working relationships. From the service provider perspective, they place a lot of value in operators like Antero, as we fit nicely into their portfolio of clients that can continue development activity through the market ups and downs. This has, of course, proved to be very meaningful as we see a number of peers that are finding it difficult to line up necessary crews to meet their ramp in development activity. At the end of the day, it's all about delivering shareholder value, and that's very difficult to accomplish when there's a lack of certainty around development plans.

As it relates to liquids, we realized an unhedged oil price of $41.96 per barrel and an unhedged C3+ NGL price of $29.52 per barrel during the quarter or 57% of NYMEX WTI, which is above the high end of our recently updated 2017 guidance of 50% to 55%. The improvement in C3+ NGL realized pricing was driven primarily by the strengthening of Mont Belvieu pricing relative to WTI with local differentials improving as well. For oil sales, we recently entered into new 6-month contracts effective April 1 of this year that will result in an improved average differentials to NYMEX WTI of $5.50 to $6 per barrel.

Moving on to our EBITDAX for the quarter. We generated $365 million in consolidated EBITDAX, a 3% increase from the prior year quarter. Our EBITDAX margin was $1.64 per Mcfe after adjusting for the noncontrolling interest in Antero Midstream. When you compare this to our Marcellus F&D cost of approximately $0.45 per Mcfe for the quarter, you can see the attractiveness of our development plan and the unlevered recycle ratios of approximately 4x, which we're able to generate.

As outlined on Slide #8, titled 2017 Guidance and Long-term Outlook, all of this translates into our ability to grow production by 20% to 25% in 2017 to 2.2 Bcfe a day while targeting annual production growth of 20% to 22% thereafter through the year 2020. Our integrated business plan will enable us to achieve this growth while maintaining a drilling and completion budget within consolidated cash flow from operations through 2020 while also shrinking our leverage to the mid-2s range by the end of 2018.

The ability to maintain these production growth levels, while also deleveraging, speaks our integrated business strategy that includes best quality rock, firm transport to favorable price indices, owning our midstream business, selling gas forward at fixed prices and the highest exposure to liquids pricing upside in Appalachia. Antero is now the most integrated natural gas and NGL producer in the U.S.

Continuing on the liquids topic. I wanted to provide a few thoughts as it relates to our substantial core liquids-rich position in Appalachia and why Antero is focused on a liquids-rich development plan going forward. As you can see on Slide #9, titled Largest Core Drilling Inventory in Appalachia, Antero has the largest core drilling inventory in Appalachia with 3,502 undrilled locations. Roughly 75% of these locations are liquids-rich and as outlined in the pie chart on the slide. That's the green portion of the bars. Antero holds 43% of the undrilled core liquids-rich locations in Appalachia. This significant liquids-rich inventory enables us to achieve tremendous growth in our liquids production with significant exposure to liquids pricing upside and, as I will touch on later, a material uplift to our realized gas prices.

On Slide #10, entitled Rapidly Growing NGL Production, we have increased our NGL production at a compounded annual growth rate of 93% since 2014, and expect to grow to around 150,000 barrels per day by 2020. This expected growth provides us with tremendous leverage and visibility as it relates to the NGL infrastructure build-out in the Northeast, and you're seeing that come to fruition with the recently announced joint venture between Antero Midstream and MPLX that Paul discussed earlier.

To provide further color on liquids pricing upside, I'll refer you to Slide #11, titled Liquids Pricing Upgrade in the Marcellus. The key takeaway from this slide is the fact that even in a $2.75 gas price environment, that's NYMEX, we can still generate around $4 per Mcfe of realized pricing on an unhedged equivalent basis, assuming $55 to $65 oil prices. With F&D costs now down in the $0.40 per Mcfe range, we are generating unlevered cash margins that yield unlevered recycle ratios in the 4x range. And that's assuming total cash cost, including G&A, interest expense, minority interest, of about $2.25 per Mcfe.

On the left-hand side of the chart, you can see the assumed realization of a dry gas producer at 1,050 BTU gas. Assuming a $2.75 per MMBtu NYMEX gas price, the dry gas producer would realize a $2.89 per Mcf gas price as a result of the small MBtu upgrade. At 1,250 BTU, which is right down the fairway of our rich gas Marcellus inventory, we will generally pick up $1 to $1.50 per Mcf, assuming a range of $55 to $75 from NYMEX WTI oil over the long term. Some of that is condensate, as you can see on the slide, but most of it's from the NGL stream, which averages about 1.9 gallons per Mcf in the 1,250 BTU area. So that's a nice pickup that we achieve from our liquids-rich production stream.

Before I finish up, I wanted to discuss how the integrated business platform we built at Antero positions the company for both near- and long-term success. This platform starts with a substantial amount of core drilling inventory in one of the lowest-cost basins in the U.S. Through this inventory, we were able to build a sustainable development program that will deliver attractive growth for multiple decades in a capital-efficient manner. The company's industry-leading hedge book provides us with firm pricing on our product while the firm transportation portfolio ensures we are able to send our gas to the best-priced markets. As a liquids-rich producer, we not only realize a BTU upgrade through our gas price realizations, but we also partake in the liquids price upgrade.

And finally, our 59% ownership in Antero Midstream provides us with both leverage and visibility into the infrastructure build-out in the northeast while allowing us to participate in the value creation at AM as they build out the downstream value chain.

Before we take any questions, I would like to point out that for security [and law] reasons, we will be limited in our ability to discuss the AMGP IPO that occurred last week.

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

(Operator Instructions) Our first question comes from Neal Dingmann from SunTrust.

Paul, for -- I guess for yourself or one of the guys there. Just wondering, has the recent improvement, certainly, notable improvement we've seen in Appalachian NGLs, has that changed how you think about potential drilling plans for the latter part of this year or -- I should say the second half of this year, given just the improvement we've seen? Or is the plan still pretty much in place?

Yes. The plan is pretty much in place. Most of what we're drilling is quite rich, and so we'll be able to take advantage of improving liquids prices. But steady as she goes. We don't see any reason to change the plan.

Okay. And then just lastly, it seems now you're certainly much more in development mode and costs are reflecting that. What is -- when I look now at the plans for the remainder of the year, but the -- you mentioned a couple of 4-well pads, what is sort of your optimal pad design when you look at that for -- going forward in this developmental mode?

Well, optimal is a -- the more laterals, the better. We're going to average 9 laterals per pad this year. So that's pretty good. It could increase a little bit more, probably 10, maybe 12 wells would be the most we've experienced and seen out there. So we're happy in that 10-ish range. That gives us 5 north-directed, 5 south-directed, and that works well, works well for efficiencies on rigs and also zipper fracs.

Our next question comes from Holly Stewart of Scotia Howard Weil.

It looks like we may have lost Holly. We can come back around to Holly later.

My apologies. It looks like we have James Sullivan of Atlantic Global Advisors (sic) [Alembic Global Advisors].

Just want to step back for a minute here, taking the longer view on your hedge book here. As your gas production base gets bigger, do you see there having to be a philosophical shift in any way in the percentage of hedge coverage you guys would like to have in any given year? Is there a size issue, or can you just comment on that a little bit?

Yes. As we get larger and larger, it takes more work to hedge 100%. So we'll play that by ear going forward. The most we've been able to -- well, I don't know about able to, but the most we've put in place is 2 plus Bcf a day of hedging. And can we keep pace as our production climbs? Probably, but it does take some effort. So we're watching on that, and we'll see. We may be less than 100% hedged in the future, but we'll just play it by ear and see how liquid the futures markets are.

Okay, great. So just want to switch gears real quick, talk about that added acreage you guys disclosed there. I think you added some in Southern Doddridge County. You also talked about of the highlight pad down there also getting closer to the 2.2 Bcf per 1,000 feet kind of core cut-off range there. Obviously, I assume those 2 dynamics are related a little bit. Can you talk about how extensive or how much the one, what you were seeing on the drilling side was playing into what you guys are doing on the acreage side?

Well, the good news is that the drilling is playing in quite well to what we're doing on the acreage side. We continue to add to block up. We've got a number of key outposts that we key off of that tell us the geology is going to be good where we're taking leases. So our view of how it's going to turn out is being proved up as we drill. So everything that we're adding in terms of acreage is pretty well-defined and disciplined and really will lead to more development in the development program. We're not doing any wildcat outposts, obviously. Everything we have, I think, probably close to 100% success rate. So we're -- we add acreage, but the development plan is proving where we're adding the acreage at.

Our next question comes from Holly Stewart of Scotia Howard Weil.

Great, okay. Can we maybe talk just about NGL realizations? Was there anything different maybe you saw in the market this quarter, things that you guys did differently? I mean, you're nicely above where the guidance is on realizations for the full year.

Holly, I think it was primarily just tighter differentials in the Northeast. So I'd say NGL growth in the Northeast has flattened, and you've seen less demand for railcars for oil. So we've seen the pricing come down and good strong prices in the Northeast. So I think it's just tight differentials for propane, particularly. For the heaviers, we've entered into some side contracts, so to speak, we talked about that in the past, where those marketers have found better markets than going into the sort of Northeast pools. So I think it's a combination of all that.

Okay, great, helpful. And then maybe just any commentary you can give on the quarterly cadence. I mean, I -- the 1Q production number was, I think, nicely above the Street. And so just kind of thinking through the 2017 guidance and kind of how the quarters might roll through that.

Yes. I think you'll see gradual growth over the next quarter or so. And then we're a bit more back-end loaded, like some of the peers this year, with more of our completions coming in the second half of the year. Probably over 60% of the completions are in the second half of the year.

Okay, that's helpful. And then maybe one more final one, if I could. Just on the ethane, you had probably peaked. It looks like you had a very strong ethane quarter. You're producing above your capacity on ATEX. So let me see, you're selling into the market using MarkWest. Or how should we think about you guys getting that -- those ethane volumes to market?

Yes. We continue to increase our ethane recovery, just to keep pace, to keep our residue gas from being too rich. And so we've got a number of side deals with buyers in different directions. And so besides in other directions than ATEX, we have sales deals to sell some of our ethane to other buyers.

Our next question comes from Carlos Newall of Raymond James.

Building on the ethane discussion, ethane sales continue to come in higher than expected. Going forward, how should we think about the composition of the average NGL barrel? Should we stick with the partial C2 recovery mix provided back in 2Q '16, suggesting about 25% ethane? Or should we adjust ethane higher?

Yes. The 25% ethane's approximately what it was for this quarter. I believe we had 72,000 barrels of -- approximately 70,000 barrels of NGLs C3+ and the 25,000 barrels of ethane. So that's a good proxy for going forward.

All right. That's very helpful. And also, could you provide an update on a projected firm transport utilization? And also, what component of excess transport is currently unmarketable? And any color on that would be helpful.

Well, we certainly have some good firm transport coming. It's just -- it's debatable as to when it comes online. Is it July, August, September, in that time frame? And I'm talking about the Rover pipeline. So we do have some capacity coming. But keep in mind that Phase 2 of that should follow only 3 months or so later. And when Phase 2 comes, then Rover will be connected to our Marcellus production into Sherwood. So Rover we're likely to fill fairly quickly because we can utilize that from both areas.

Our next question comes from David Tameron of Wells Fargo.

Just building on the last question. What is your outlook at this -- as you start thinking about ethane injection? How do you see that? Or how do you those prices I guess plays out over the next couple of years?

Well, the ethane economics right now are such that it's centered to leave the ethane (technical difficulty) if we are just looking at, say, gas value at TCO. And so what we recover is what we need to recover in order to not get our stream too rich. But the outlook would be that we need ethane prices at least in the low $0.30 range to make ethane recovery more economic.

Okay. That's helpful. And then if I just think about your firm transport, obviously, it's -- your whole portfolio obviously has allowed you to get to where you needed to get, combined with the hedges. Going forward, as we start thinking about the ramp in the Marcellus and the pipelines, how much -- there's probably less value tomorrow than there was, right, yesterday. But how should we think about that? And how do you think about just that value of that firm transport portfolio, say, 2 years down the road?

Yes. So today the, differentials are shrinking down south and Tetco M2 relative to some of the other indices, and that's because there's more distressed gas out of those pools is being bought to fill producers', shippers' available capacity in some of the new projects, so tightening differentials. We still have a couple -- several more projects to come on between now and the end of '19, those being Columbias, the Mountaineers, the Gulf Xpresses and so on. But we project, for Antero alone, that we'll be -- those will come on and then we fill them relatively quickly, within 1 to 2 years. So with our growth plans, we definitely need the FT that we've signed up for.

I think a number of people are looking at rig counts and trying to judge whether there's going to be available capacity, available FT longer term, for people to move into unused space or whether the pipes are going to fill up. There's been a couple of newer twists, newer developments, a couple of projects that are utility pole projects. One is to the Southeast, Atlantic Coast Pipeline, with the Southeast utilities backing that one, and they want to buy in the Marcellus pool at the beginning of their pipes. So that's a situation where producers are not being asked to sign up, but instead, there are -- there's a sales point directly in the heart of our acreage. The second one is Nexus going to the Northwest, a similar situation, utility pole. So we're watching the environment. We know that we'll be moving quite a bit more gas, but will it be us that sponsors the project or signs up, or will it be doing longer-term deals into utility pole projects? And so we've got a number of years to judge how that all unfolds.

(Operator Instructions) Our next question comes from Brian Singer of Goldman Sachs.

You talked a bit earlier in your prepared remarks on the acquisitions that you've made into Southwest PA, and you also mentioned the core position that you put together. To the degree that you now have the largest core drilling opportunity in Appalachia, as you described, is there the need for consolidation from here? And is the opportunity set as attractive as it has been, from your perspective, over the last year or so?

The opportunity set is still attractive. We favor more the A&D side than the M&A side. And so we're able to -- basically saying we're able to work with other companies, other peers, that have acreage that they're willing to sell that's not strategic for them. So still see good things coming along. And so it is still a good environment for a consolidation. Maybe it'll shrink in size in its more smaller tracks. And there's more efficiency consolidation going on, where trades are being made between the various players, the various competitors, both in the Marcellus and the Utica.

Great. And then my follow-up is the progressive transportation costs. You have the guidance out there for operating expense for the year, but I wonder if you could give us a little more color on how the transportation -- unit transposition costs should evolve between now and '18, with and without -- or before and after Rover.

Yes. I think our range out there is, I think, 7.5% to 12 -- I'm sorry, $0.075 to $0.125 per AM. And I think we'll just have to evaluate as Rover comes on, when it comes on and how we utilize that as to how that gets adjusted, if it gets adjusted, as we go throughout the year. But I think longer-term, we expect that to be in that range or below. And then eventually, it evaporates by the time we get out to 2020 or so because we're starting to fill all of that capacity. So we feel very good about our capacity, as we said earlier. We fill it all up by the year 2021, based on our growth plans. So we'll be looking for what's next, whether it's taking out some of the firm that's being -- some of the pipe that's being built out there right now. There's some available. There may be some that becomes available, or potentially longer term, maybe there needs to be another project that we could be involved with. So we're looking, certainly 3, 4, 5 years out on that.

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

Thank you for participating in our conference call today. If you have any follow-up questions, please feel free to contact us. Thanks again.

The conference has now concluded. Thank you for attending today's presentation. You may now disconnect.