RRC
#I think if you look at where we are for 2017, we are well hedged, we're comfortable with our plan and will move forward.
And then I think if you look into 2018, there are several thoughts there.
One is there's multiple ways to win, even if gas is a little lower, we are closer to strip, we see differentials that could even improve beyond what we have in there, NGL pricing and netbacks could be better.
Cost structure and efficiencies, I think, will get better.
I think when you look across 2017, 2018, we're in good shape, and I still think if you look out far enough, and you take into account incremental gas, that demand is coming, and account for base decline that has to be overcome, there's a story brewing for gas.
And last but not least, I'd add in, with gas prices where they are for people that aren't hedged or even what some people are saying oil prices may fall back in the second half of the year, you actually lower prices in 2017 might help 2018, even though the strip doesn't reflect that right now
Yes, this is <UNK> <UNK>, I'll take that.
We think that the ethane markets, both domestically and globally, are improving.
There are several crackers coming online in the Gulf Coast in mid to late 2018 and coming into 2019.
Those stocks are high right now, we feel like the several hundred thousand barrels a day demand that's represented in those crackers that is coming online will more than offset the supply that's available there.
Also propane with the ME 2 project that we're involved in and the propane that we're flowing through and putting on boats to the global markets is really flowing through currently into our improved NGL prices you see, and we see global propane demand increasing PDH plants in China, the energy use for propane in Japan.
So, we see over the next several years propane demand increasing, as well.
I'll tack onto that, <UNK>, and <UNK> said ME 2, but we are actually in ME 1, right.
Didn't want to confuse anybody there, but with the great contracts we have on Mariner East [LON], on Mariner West and ATEX, and the improving markets that <UNK> was just referring to, we're pretty well set up.
Our goal all along for years has been to have a diverse set of outlets and a diverse set of pricing scenarios, I think we are finally beginning to see how that is serving us really, really well.
What's important, it is going to offer us a ton of optionality going forward, so we can set back and wait and see what Mariner East Phase 2 is going to look like, or Mariner East 2X, and the Shell cracker, and all these others things.
We've got lots of opportunities going forward, and I think that's going to be a unique story for us, since we were so early on in these other projects.
The good news is we have optionality there as you look forward, so there's good things happening in Louisiana, and of course, with the pricing that's a big advantage and all that, but there's good things happening up in the Marcellus, too.
You're seeing a lot of improvements, longer laterals, better netbacks, new transportation agreements kicking in, so we will continue to look at that as we go forward and turn that knob to where we think it's optimum for any one particular year or time.
Maybe flip the other way, <UNK>.
The other thing I'd say is we have a really big acreage position, and we have the ability, back to <UNK>'s question too, it's really a big blocky position.
If somebody says otherwise, that's fake news, to use that term.
So, we have the ability to drill long, and what you're saying is, too, again, as we try to be very thoughtful methodical scientific data-driven, so we're drilling some 15,000-foot wells as we speak.
We have some 10,000 wells wet 10,000-foot wet wells, like <UNK> said, that are phenomenal.
So, we will look at where that optimum is, it's probably a little early to say where it is, it's longer than we are, so we will continue to march out, but we'll step out like we are with 15,000-foot wells, so we can see what that data looks like.
And then, again, dial it to where we think is optimum as we move forward with time, but that will drive increasing efficiencies.
Or you could have an old well out there that's butting up against that lease, so there's some of that in there, but we have a lot of wells where we can drill longer laterals on.
That plays in our earlier state, so you'd be spending a lot of R&D dollars to try to unlock it, when, like <UNK> said, we have got a lot of, a much higher probability, stronger economic wells to drill, instead.
But there'd be a lot of value to it.
(Multiple speakers) We hold all those [lease] rights, by the way.
It's captured.
That's a great question, <UNK>.
And back to what we said is those wells really they're east and west of Vernon, they are more like Vernon, so you have got instead of Terryville, you have one Upper Red, down there you got three Upper Red, and Terryville you've got one Lower Red there, you've got three Lower Reds and all these laterals are just in one of those six zones.
Did we pick the optimum zone, did we optimally drill and complete it.
You can go on and on, that's why there's tremendous upside, we're excited about the 400 Bcf per section, the high pressure, the thicker interval, and which of those six laterals is best ultimately that we develop, who knows.
Four of six or five of six or two of six, so there's a lot of upside and a lot of potential there, so it gives us optionality, we just want to be very thoughtful how we go forward.
And like <UNK> said, he talked about all the types of data we are gathering to help understand that.
Thank you
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