EnLink Midstream LLC (ENLC) 2016 Q4 法說會逐字稿

Ladies and gentlemen, thank you for standing by. Welcome to the EnLink Midstream fourth-quarter and full-year 2016 earnings call. All participants will be in a listen-only mode.

(Operator Instructions)

After today's presentation that will be an opportunity to ask questions.

(Operator Instructions).

Please note that this call is being recorded today, Wednesday, February 15, 2017, at 10.00 a.m. Eastern Time. I would now like to turn the meeting over to Kate Walsh, Vice President of Investor Relations.

Please go ahead.

Thank you.

Good morning, everyone. Thank you for joining us today to discuss EnLink Midstream's 2016 results and 2017 outlook. Participating on the call today are Barry Davis, Chairman and Chief Executive Officer; Mike Garberding, President and Chief Financial Officer; Steve Hoppe, President of the Gas Gathering, Processing and Transportation Business; Mac Hummel, President of the Natural Gas Liquids, Crude and Condensate Business; and Ben Lamb, Executive Vice President of Corporate Development.

As you saw, we issued our earnings release yesterday and plan to file our Form 10K with the SEC later today. To accompany today's call, we have posted the earnings release and the operations report to the Investor Relations portion of our website. Shortly after today's call will also make available a webcast replay of this call on our website.

I will remind you that any statements made about the future, including our expectations or predictions, should be considered forward-looking statements within the meaning of the Federal Securities laws. Forward-looking statements are subject to a number of assumptions and uncertainties that may cause our actual results to differ materially from those expressed in these statements. We undertake no obligation to update or revise any forward-looking statements.

We will discuss certain non-GAAP financial measures. You will find definitions of these measures, as well as reconciliations of these non-GAAP measures to comparable GAAP measures, in our earnings release. We encourage you to review the cautionary statements and other disclosures made in our SEC filings, specifically those under the heading Risk Factors. The structure of the call will be to start with brief prepared remarks and then leave the majority of the call open for a question-and-answer period.

With that, I would now like to turn the call over to Barry Davis.

Thank you, Kate.

Good morning, everyone. Thank you all for joining us today. I am extremely proud of our team and the accomplishments we achieved during the challenging commodity environment we found ourselves in this past year.

Crude oil prices a year ago were hovering around $26 per barrel. In response, our team focused and executed our plan. As a result, we are strong and opportunity rich as we begin to now see strength in the industry.

At ENLK, we delivered approximately 14% growth in adjusted EBITDA and distributable cash flow from 2015 to 2016. While maintaining investment-grade credit metrics and achieving a solid distribution coverage ratio of 1.03 times for the year. We exceeded the midpoint of our adjusted EBITDA guidance range, which is a testament to the strength of our business model.

ENLC, our general partner, delivered approximately $202 million of cash available for distribution and achieved a strong coverage ratio of 1.09 times for 2016, with coverage expected to continue to strengthen in 2017 and 2018. ENLC experienced solid cash flow contributions and tax benefits from its strategic investment in our Central Oklahoma growth platform, translating into additional value for unitholders.

The strength of our business gives us the opportunity to evaluate distribution growth presumption at both ENLK and ENLC. We believe distribution growth could resume in 2018 based on our investment-grade leverage metrics, distribution coverage targets in the range of 1.1 times to 1.2 times, and a more stable commodity environment. We're also evaluating resuming distribution growth at ENLC, in advance of ENLK, as we expect a faster build of coverage at ENLC.

We currently see great value from our corporate structure having separately traded GP and MLP entities. We believe it affords us imported financial flexibility and transactional advantages. Corporate simplification is an active topic these days. Our position remains that we like our structure, and we don't have to solve the same problems as some of our peers. We just entered the high splits for incentive distribution rights, with around 10% currently going to the GP.

We project limited cash taxes at the GP, with the expectation of paying around $5 million in cash taxes at the ENLC level for each of 2017, 2018 and 2019. We don't need to cut distributions, as our coverage has remained strong and is growing. Finally, we believe our focus should be on executing organic expansion in our core growth basins.

This year, we have a large-scale projects in progress, such as bringing Chisholm II and III online in the stack; expanding Lobo II in the Delaware; completing Phase 2 of our greater Chickadee crude oil gathering system in the Midland Basin; and putting the Ascension Pipeline in service in Louisiana. We are in the best basins and are committed to growing, with our strong producer base, across our entire platform. That is where our focus is today.

I'd like to now take a few minutes and update you on our core growth areas. The activity and results we see in Central Oklahoma are really exciting. Producers are accelerating investments and sharpening focus in the stack as development results continue to exceed expectations. We are progressing well with building out additional processing capacity to handle the increasing gas volumes. We expect Chisholm II's 200 million cubic feet a day capacity to be operational in early second quarter. Once Chisholm II and III are in service, we will have approximately 1 billion cubic feet a day of processing capacity in the region.

As producers capture efficiencies by transitioning to multi-well pad drilling from single-well development, we believe that our volume growth in Oklahoma will be erratic, or sawtooth, during the year rather than a steady upward trend. The predominance of volume growth is expected during the second half of 2017, as drilled and uncompleted wells and new wells drilled in the first half are tied in and start flowing volumes through our system. We're on track to bring Chisholm III's 200 million cubic feet a day online during the fourth quarter of 2017, and are evaluating the next suite of expansion options available to us. Our conviction in Central Oklahoma is growing day by day.

Turning now to the Delaware Basin, we are also experiencing exciting progress on our footprint in this high-growth basin. We recently added to the depth of our commercial portfolio by finding a new contract with a large investment-grade producer who is very active in the area. We are expecting associated volume uplift to accelerate the next phase of our Lobo system build out. We are expanding our gas processing capacity in the area by 60 million cubic feet a day, bringing Lobo II to 120 million cubic feet a day.

The additional capacity is expected to be online in the second quarter, and our total processing capacity in the Basin will be 155 million per day. This new long-term contract is fee-based and has associated volume commitments but no dedicated acreage. Without associated dedicated acreage you won't see rigs related to this contract in our quarterly rig count update. But there are several rigs active in this producer's development area.

We expect the volume commitments associated with this new contract to utilize the majority of the 60 million cubic feet a day expansion. Our Midland Basin operations are well-positioned for the gas and crude volume growth we're expecting in 2017. We strategically invested in additional gas processing capacity during 2016 by bringing the Riptide plant online. We expect to see utilization of our assets steadily ramp throughout the year.

We will also be bringing Phase 2 of our greater Chickadee crude oil gathering system online later this quarter and are expecting meaningful volume growth on this system during the year. Our Louisiana assets could not be positioned any better. A franchise gas and NGL platform in the growing Gulf Coast demand corridor.

On the gas side of the business, we conservatively estimate slow, steady growth, as it is tough to predict power generation demand driven by weather and interruptible demand driven by LNG and other end users. For liquids, we are excited about linking supply from the tailgate of Chisholm II to demand on our Cajun-Sibon system. We're forecasting that our Cajun-Sibon Pipeline will be at maximum capacity in the second quarter of this year.

We are also expecting the uplift in volumes to benefit our entire NGL system in Louisiana. As I mentioned before, we are bringing online our Ascension NGL Pipeline in the second quarter. We expect to leverage additional bolt-on growth once that line is in service.

Finally, I want to touch on our anchor position in the Barnett Shale. Devon announced that they are allocating capital of approximately $50 million to their North Texas operation, and are investing in both their refrac program and their drilling program, with an expectation of drilling 5 to 10 new wells. We are encouraged to see Devon's renewed investment in the area and are optimistic that modern completion techniques could lead to further development of our dedicated acreage sooner than anticipated.

However, we are operating in a mature basin that has seen limited investment activity over the past year or more. During 2016, we experienced gathering volume declines of around 8%, slightly more than forecasted. We continue to work with Devon on optimization programs and pressure reductions.

During 2017, we estimate gathering and transportation declines will be around 10% when normalized for the sale of the North Texas Pipeline. We do believe this will improve over time, as Devon again increases capital in the Barnett and we have minimum buying commitments in place that provide strong cash flow support.

To sum it all up, we continue to execute on the plan we laid out: strong balance sheet, best basins, right platform, top customers. The strength we built in 2016 positions us well for 2017 and beyond. We continue to capitalize on growth opportunities and execute on long-term expansions across our platform, creating unitholder value for years to come.

With that, I will turn it over to Mike.

Thanks, Barry.

Good morning, everyone.

As Barry highlighted, EnLink delivered strong results this year, achieving adjusted EBITDA net to ENLK of $775 million for the year, which represents over 14% growth from 2015. We exceeded adjusted EBITDA guidance for the third year in a row and continue to build a strong scorecard of executing on the plan we laid out. We are committed to maintaining our strong investment-grade balance sheet, preserving ample liquidity, and creating stable cash flows that support and grow our distribution.

We took deliberate steps during 2016 to ensure that we met our goals. First, we executed on nearly $1.2 billion in equity during 2016. This includes our preferred and ENLC units issued for Tall Oak acquisition and our ENLK ATM issuances during the year. We ended a very tough year with debt to EBITDA of 3.7 times, a very solid place to be from a balance sheet perspective.

Second, we executed on issuing senior notes in July with an all-in interest rate of 4.85%, which was at the lowest point of the 10-year treasury for the year. This helped to position us with consolidated liquidity of $1.6 billion at the end of the year.

Third, we executed on a joint venture with NGP to ensure we had a strategic partner with focused capital to quickly grow the business. We gained access to $400 million in capital commitments that allowed us to finish out our initial Delaware build, as well as deepening relationships with a large investment-grade customer. Finally, we announced the sale of non-core assets for $275 million and are reinvesting in our core basins, Central Oklahoma and the Permian.

We did all this to ensure we maintained the strength of our balance sheet despite very volatile capital markets. This also puts us in a position where we do not have to rely upon marketed equity transactions for 2017 equity funding, which provides great financial flexibility. Our current financial plan has us issuing equity under the ATM, consistent with the pace in the second half of 2016, as well as finalizing asset sales we have discussed.

As Barry mentioned, we believe we not only have assets positioned in the core of the core of the best basins, but we also have the right business model to execute on our growth opportunities. We believe this solidly comes together in 2018.

A couple of items that we highlighted in 2017 guidance were the exit rate ENLK adjusted EBITDA and distribution growth. The exit rate adjusted EBITDA should highlight the earnings growth of these assets and the business model. Our 2017 guidance projects an adjusted EBITDA exit rate of $925 million to $950 million, a 20% increase versus 2016 adjusted EBITDA.

We signaled that the majority of growth will be levered towards the second half of 2017, with an expectation that the first quarter will be somewhat flat through the fourth quarter of 2017. However, we believe this growth gives us the opportunity to consider growing distributions at ENLK during 2018 and potentially growing distributions at ENLC prior to ENLK.

I will now turn the call back over to Barry for his concluding remarks.

Barry?

Think you, Mike.

We are excited about the year ahead. We have a lot to execute on and a lot to accomplish. We have superior quality assets in premier US basins and long-term contracts with top-tier producers who are focused on growth.

We believe the activity we're seeing today is sufficient to drive the growth we expect. We have a team whose hearts and minds are fully engaged, who come to work each day with a strong sense of ownership and purpose, all keys to continuing to pave a successful path ahead.

With that, Operator, you may open the lines for questions.

Take you, Sir. We will now begin the question-and-answer session.

(Operator Instructions)

At this time we will pause momentarily to assemble our roster. The first question comes today from T.J. Schultz with RBC Capital Markets. Please go ahead.

Great. Thanks. First looking beyond Chisholm Three, when you think about that next suite of expansion options, what are the kind of current thoughts on keeping potential processing additions in-basin versus the potential for Oklahoma express and then any color on potential expansion or extensions into Cajun-Sibon?

The morning, T.J. This is Barry, and I will ask Ben to respond to that.

Hello, T.J. It is Ben. First let's take a step back and just talk about where we are in central Oklahoma. As you said, looking beyond Chisholm Three, but first I just want to remind everyone that Chisholm Two is under construction right now, looking to go in service here very shortly. Chisholm Three coming right behind that toward the end of the year.

Previously we had guided you to think about the need for a processing expansion every 12 to 18 month if present trends continue. Right now present trends are continuing. We don't see anything different today than when we provided that general guidance.

Now, as to the next step on processing capacity in Oklahoma, it could take a couple of forms. It could take the form of additional capacity there in the state, it could take the form of Oklahoma express and doing the processing in North Texas. What we do have is conviction that we will continue to need add processing capacity.

What we like today is perfect clarity on the downstream markets that would determine where that processing capacity should be. At times it has looked like Oklahoma express was the best answer. At times it has looks like in state processing was the best answer, and right now we have a very dynamic market on the residue gas side in particular, and we will need to see a little bit more clarity before we can make that determination. Fortunately I think we are going to have that clarity before we need to make a decision which is probably later this year.

On the Cajun-Sibon question, maybe I will start and I'll ask Mac to add. You know, the great news is we are going to fill Cajun-Sibon with Chisholm liquids. The question that we have before us is exactly how we get those liquids to Cajun-Sibon.

We control enough supply to construct an NGL pipeline if that is what we choose to do. Something that we are working through right now is trying to determine whether that is the best answer, whether the best answer is a partnership with others, or whether the best answer is just using third party infrastructure that is very attractively priced. We will have to stack up all of our options and make sure that we choose the one that competes the best both financially and strategically.

T.J., this is Mac. Ben, I think you did a great job answering the question. I would just add that I think central Oklahoma is a great demonstration of the capability that we've built and the capability that we are continuing to build to link our upstream businesses with our downstream businesses so that we get multiple touches on that molecule and give us additional opportunities to add margin.

Got it. Thanks. That is helpful. And just moving to the Delaware JV contemplates $800 million of committed capital so again just looking ahead, in this case after Lobo II, just any color on the next targets. Are you looking at where acquisitions knowing matador is still holding some extreme or is there enough organically to do it around your current footprint?

Hey, T.J., it is Ben again. I will start and Steve may want to add on. Our priority is focusing on the execution of what we have in the Delaware. It is organic growth as the first priority.

Having said that, there are a lot of assets in the Delaware that could come available for sale. We've seen some transaction activity already this year in that regard.

We are always involved in M&A activity. We're always looking at opportunities to add to the positions that we have in ways that make us better, but we will be disciplined about it. If we take that step it will only be because we feel real conviction that an acquisition makes us better.

T.J., this is Steve. You know, when you look at the opportunities that we've got in front of us right now, the first opportunity is the expansion that we've got up to Lobo II plant. It is a $60 million a day plant and we've already started work on expanding that to $120 million a day.

In addition to that there are a number of pipeline expansions that we're working on off of our gathering system. You recall the gathering system was recently put into service at the end of this year and that was actually three months early. We had planned on the end of the first quarter.

We are already in a great position to expand off of the gathering system and we've got an opportunity as volumes grow that the next bolt on would be a third plant in the area. We see a lot of opportunity for rapid growth in the area. We see drilling and prices improving that could give us the market to drive that opportunity and we're preparing for it today.

Great. Thanks. Just last one for me, Barry, you touched on the GP LP structure. Just if you could expand on some ways you want to leverage the flexibility that the structure gives you.

Is this something you would want to transact more at the ENLC level to utilize that currency or is the comment really that since the GP take is not a big hindrance to your cost of capital right now you just don't even address it or adjust the structure now but maybe something to consider later?

Yes, TJ. Consistent with what I said earlier, we don't think we have a problem first of all with the cost of capital burden or tax burden at the general partner. We've done some very creative and strategic things to address that so we like our structure, we believe that it does in fact offer us some of financing flexibility as we look at transactions.

Just to remind you, we've used it in two of the largest transactions, the combination of ENLC and ENLK in two of the largest transactions that we've done in the creation of in link first of all, and then in central Oklahoma asset acquisition that we did. So that is an example of where we think it really affords us some flexibility. Not predicting, but certainly just acknowledging the optionality that we have.

And let me just lastly say, we do believe there is a lifecycle to the GP MLP structure, and everyone has to evaluate that in time and we will stay very much on top of it. If there is something there that needs to be done, we will certainly be proactive.

Great. Thanks, Barry.

Thank you. Our next question will come from Jeremy Timaeus, JPMorgan. Please go ahead.

Morning, Jeremy.

This is actually (inaudible) on for Jeremy. I have a couple of quick questions for you guys, the first on Tall Oak EBITDA. So EMLC share of $9 million for 2016 this kind of translates toward $55 million for the year on EBITDA which falls slightly below your $75 million to $85 million guidance. I just want to check if I am missing anything here or if I'm reading this right.

This is Mike. There is a good question. There are other items in there. There's some dollars and the related to the joint venture we have out of the Delaware so you are generally in the number.

I would say where we guided for the central Oklahoma acquisition was around $70 million. Your numbers, if you just gross it out by the 16% gets you around the $55 million if you do it on the net number in there. I would say we are generally around that more around the $60 million number.

Where the focus is again is the growth we see moving into 2017 and then ultimately 2018 because of where the producers are from a development standpoint and the key for that is really the conviction we have around the guidance both for 2017 and exit rate into 2018.

Mike, I will add on one thought. I know it is easiest to conceptualize our business as all being inside little boxes so there is a central Oklahoma acquisition box that we talked about and put an EBITDA number out there associated with it. But the reality is that if that asset has been integrated into our broader central Oklahoma business we had our 400 million cubic feet a day Kana plant, and of the things we did last year was off-load volumes from the central Oklahoma systems we acquired on to our legacy cadence system.

So when we do that, some of the margin moves out of the acquired entity and into the legacy entity. So just looking at the ENLC financials and doing a gross up doesn't tell the whole story of the acquisition.

Got you. That's helpful, and one more question on following up with MBC sold off in the Barnett. Can we see the run out or someone to step up for the flag contact expedition like some of your peers have similar kind of support so any comments there or --

This is Mike again. I will start and pass it to Steve.

If you go to what Barry talked about in the script on the Barnett, that is the key is really is us working hand-in-hand with Devon on the Barnett and you can see that ultimately through two things. One, you can see that from a Devon perspective on bringing money back to the drill bit, and two, you can see it from a healing perspective on the pressure reduction and optimization working hand-in-hand with Devon from an efficiency standpoint.

Steve can walk you through what those ultimately mean both to us and to Devon.

This is Steve. On the MBCs, in 2016 on the Devon-based contracts -- and this is both North Texas and Oklahoma, we made $37 million in MBC payments. In 2017 we're projecting about a $20 million increase to that. But keep in mind one of the things that we see is the Oklahoma volumes will further be supported by development in the Cana-Woodford group so we do not see that being an issue going forward long-term.

In North Texas, I want to really stress that we are going to be very determined to find better than apron off case in Barnett. We are going to continue working with Devon and other producers to reduce declines. We want to improve well head net backs that's going to incentives, encourage and support new development.

We are going to continue to pursue consolidation opportunities and connect new supplies to our system, and we've been very successful in our operations' optimizations. In fact, we've reduced O&M costs $20 million in 2017 compared to 2015. We have a lot of things that we're working on and focused on to continue to have North Texas be a good and stable cash flow to our business and I think we have been very successful in that effort.

Steve, I think that as well said and this is Barry I want to add to that or emphasize that it is a joint effort between us and Devon. We are working collaboratively to determine a positive future for the Barnett and I think the $50 million of investment they are making this year is in that direction.

We have not had a modern type curve, a modern well drilled in the Barnett for now two or three years and so part of what they are doing is to determine really where it fits in their portfolio as well as hopefully it will be helpful to other operators in the Barnett Shale to see what can be done. We have seen some positive developments in other plays like the Haynesville for example that has really resulted in a resurgence in that area.

The expectation is that you will see returns on wells drilled in the Barnett today north of 20%. How far north will be determined by the success of the wells we are drilling.

So again, emphasizing what Steve said, we are determined to find a better forecast for the Barnett Shale and be on the MBCs to really close that gap there. Stay tuned and we will try to keep you posted on that as it develops.

Thanks, guys. That is helpful color. That is it for me.

Thank you.

The next question will come from Mirek Zak of Citigroup. Please go ahead.

Good morning, everyone. Just a couple of quick ones for me. The first one being on the NGL side, I was just curios what potential opportunities you see on the NGL side out of the Permians. Is that only on the pricing side or if and where you might see additional opportunities around NGLs there?

Mirek, this is Mac Hummel. Thanks for the question. I think the primary opportunity we see for increased NGLs from the NGL side of the business out of our Permian area is that we can funnel those volumes into our Cajun-Sibon facility, so like we talked about with central Oklahoma and the linking opportunity we've got there, we've got the opportunity to link some of that NGL growth that we see out of the Permian into our Cajun-Sibon facilities over time and really touch that molecule again multiple times in our margin each time we do.

Okay, great, and secondly, in Oklahoma, at what point do you think crude production there could be substantial enough to warrant any additional infrastructure investment on your part of what type of opportunity set that might look like?

Yes, Eric, it is Ben. Let me start. I think it is later this year. The economics of crude oil gathering are such that it's hard to make it work for single wells being drilled by themselves in delineation mode. It is much easier to make it work in competitive with trucking when you have multi well pads being developed.

Something that we have seen late last year and certainly so far in the first quarter is a transition to pad drilling by more of our customers sooner than we expected. Devon, for instance, in their operations report highlights their showboat development later this year which is 15 to 20 wells in a single drilling unit developing three Miramak horizons. If you go and look at what Newfield said two days ago at the Credit Suisse conference they talked about up to 30 wells per drilling unit and I have a gun barrel diagram showing 12 Miramak wells in the same section.

Just today I know we have one producer who is operating four rigs in the same drilling unit, four rigs all lined up on the north side of the road. It's that kind of development that makes it possible to go and make a crude gathering system work and it is something we're working on with multiple producers and I expect we will have some progress on that later this year.

Is any of that in your guidance at this point?

Mirek, this is Mike. It is not.

Okay. Thank you very much. That is all for me.

Think you, Mirek.

The next question will come from Robert Balsamo with FBR. Please go ahead.

Hey, good morning.

Good morning, Robert.

Just some clarification in the crude and condensate segment showing some good volume growth year-over-year, but obviously the segment profit per barrel falling off, is that just the newer assets generating lower margin? Can you talk a little bit about that dynamic?

Yes, Robert, this is Mac. What you see in the growth in the crude and condensate business is primarily oriented toward West Texas growth around Chickadee system as well as growth on the supply and marketing side and so if you're taking the barrel counts and trying to do just in easy margin calculation, I think that's really somewhat misleading in terms of what the business is doing there.

The way the Chickadee business is structured is that those barrels are purchased by us and sold into Chickadee and sold by us out of Chickadee and so from a crude and condensate segment perspective we are touching those barrels twice if you will. We are touching them on the supply and marketing side and we are touching them on the pipeline terra side.

That's good clarification, thank you. And I was wondering if you could just address the Louisiana, the gas gathering process, obviously some headwinds there moving into 2017 continuing declines. Anything you are seeing there, any potential flattening of those declines are in activity that is worth addressing at this point?

Yes, Robert, this is Mac again. On the gas side of the business in Louisiana we continue to talk about the fact that we have what is the premier asset footprint in the state. When you look at what we have been able to do in terms of integrating those systems together and utilizing storage and the capability that brings, it has been significant.

You might have seen as you look through the operations quarterly report we've had a record year of volumes in Louisiana in 2016. That record year was greatly benefited by a significant volume of interruptible business. That interruptible business was largely pointed at the power market and through our Sabine pipeline Henry hub facilities.

When it came time to provide guidance for 2017 we just did not feel comfortable including all of those volumes in our number for 2017. I feel really good about our ability to compete with those. I feel real good about our ability to win those and what I'm happy to say is that if you look at the short window into 2017 we already have, our volume performance to date in 2017 looks very much like our volume performance on average in 2016.

That is great. That upside is not included in the guidance?

That is correct.

Great, and then just a follow-up on the previous question let's see you mentioned the reduced O&M costs in 2017 by $20 million kind of offsetting some potential headwinds from MBC's rolling off. Could you elaborate on those O&M costs, kind of savings there are, if that is sustainable? Obviously I assume it is, but where it is coming from?

This is Steve and those are the cost reductions we have seen over the last two years so 2017 is coming in $20 million lower than our 2015 numbers and it's just general O&M costs for the system wide. Things like compression rental expenses and things like that. (multiple speakers)

Great. That is it for me. Thank you.

Think you, Robert.

(Operator Instructions).

The next question will come from Matt Niblack with HITE. Please go ahead.

Think you.

Hi, Matt.

Good morning and congratulations on the great performance here. Just wanted to clarify the Barnett refrac and development program, because I was looking through Devan's operations report and it seemed a little hazy in that report of that timing and whether or not that was something that was approved versus being explored, but your remark at the beginning suggested maybe that had been approved.

Forgive me if I missed something there, but what's the status and the timing on that kind of redevelopment program in the Barnett?

This is Steve, Matt, and as of now we don't have specific schedule that Devon's got in their plans. I know that they got a number of things that are working on and trying to establish that schedule and it's refracs, it's work overs on wells and it's possibly drilling 5 to 10 new wells so we're going to continue to work with them to the year and help support that program, but we don't have specific schedule as of today.

Okay, but the expectation is that is something that will get started this year or we're still waiting for certain commodity environment not yet realized?

No, I think we are expected to see that this year. I don't think it is necessarily driven by pricing.

Okay --

Matt, I think it was clear that it is in their 2017 capital plan. They allow in that capital and be done.

Got it, so is the goal here to slow declines or is the goal here to get to flat or to grow? What is there operating objective?

I think their operating objective is the same as ours is to revitalize that basin and to apply, as Barry said, new drilling techniques and learn how those new techniques and new programs can help support the basin and where it falls in their portfolio.

Okay, so in terms of the degree to which declines are arrested or reversed, that is to be determined?

That is correct, Matt. We have not seen a statement out of Devon of a specific target as far as flat or growing volumes out of the Barnett at this point. I think they are very much in a exploring opportunities mode at this time.

It is Ben. Let's not lose sight of the big picture, and Barry touched on it earlier. There really isn't an instance where a truly modern drilling and completion technique has been applied to the best acreage in the Barnett. When you think about resource redevelopment, Barry gave the example of the Haynesville.

The Haynesville like the Barnett was designed with frac 1.0. Well now we're on frac 5.0, and I think it is an open question what happens when you apply frac 5.0 to the Barnett. That is what we're going to find out. It will be exciting to see.

The other piece of that real quick is the refrac of getting the cost down to $700,000 per well. That is a very cost-effective way for them to go back in and re-complete all of their older wells and their portfolio is large. Two ways we're coming about that.

I appreciate the color. I know it's not your most exciting asset, but it is important for the model so thanks for the discussion there.

Thank you, Matt, and we're looking forward to the future and it possibly being one of the most exciting as you are.

(Operator Instructions).

The next question is from Sharon Lui with Wells Fargo. Please go ahead.

Hi. Good morning.

Good morning, Sharon.

Just if you could provide some more details on the recent contract for the Lobo II whether there is a step up in those volume commitments and if you can potentially see a potential expansion of Lobo?

Yes, Sharon, this is Steve. There was a step up in volume commitments with the recent contract, and where we are at today as we alluded to earlier we just put in Lobo II in service, that added 60 million a day that plant came online in December. We are already working on the expansion of that Lobo II, which is another 60 million a day that would take the Lobo to plant up to 120 million a day. When you combine that with our Lobo I plant that gets us to 155 million.

You look at our current forecast towards the end of this year we would expect that we hit those volumes and be at that full capacity so we are now in the next few months looking at what we are going to need to do as far as planning and timing for our third plant and we definitely see a lot of additional opportunity out there beyond just the contract that we signed today. We've got a number of deals that we are on the verge of completing and a number of new opportunities that are coming up as prices improve.

We are very encouraged by what we are seeing in the Delaware. In fact, I will mention that in January we saw volumes through our Delaware system approaching 60 million a day so we are definitely starting to see a lot of gas start to accumulate up there and it is a very positive outcome that we are expecting this year.

Okay, great, and also I guess there is a potential to expand Riptide, I believe, can you maybe talk about the potential timing and capital requirements for that expansion?

Yes, riptide, this is Steve again, and riptide we just completed last year and that was the expansion in the Midland basin. With that expansion it takes our Midland basin and processing capacity to 400 million a day. As you look at the growth that we are projecting in the Midland basin it will run between 20% and 30% a year over the next few years.

It is a good stable, consistently growing asset. We really like the position we have in the basin, in the floor, and in fact I will note that when you saw the low prices Barry in his comments stated, a year ago we saw $26 oil. We still had rigs operating in the Midland basin at $26 oil and we got even our operating at $50 today, so we seen a lot of good, slow development in that area that is consistent with our plan.

When you look at the timing of that, we think we are well-positioned for the next few years with our existing processing capacity and we don't anticipate meeting and expansion within the next two years, but we are chasing some opportunities that could be very large that may drive an expansion. Our next expansion phase for Riptide would add 100 million to capacity and what cost us in the neighborhood of about $30 million. Very economical when you look at what you see for processing plants and processing capacity.

Great. Thank you.

Thank you, Sharon.

Ladies and gentlemen, this concludes our question-and-answer session. I would like to turn the conference back to Barry Davis for any closing remarks.

Thank you, Chad, and thank you again to all of you who joined in today's call. We look forward to updating you on our first quarter result in May and hope you have a great day, and again, thank you for your support. Goodbye.

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