Boardwalk Pipeline Partners' (BWP) CEO Stanley Horton on Q2 2014 Results - Earnings Call Transcript

Aug. 4.14 | About: Boardwalk Pipeline (BWP)

Boardwalk Pipeline Partners, LP (NYSE:BWP)

Q2 2014 Results Earnings Conference Call

August 04, 2014, 09:00 AM ET

Executives

Molly Ladd Whitaker - Director of IR and Corporate Communications

Stanley Horton - CEO and President

Jamie Buskill - SVP, CFO and Chief Administrative Officer

Analysts

Brian Lasky - Morgan Stanley

Jeremy Tonet - JPMorgan

Darren Horowitz - Raymond James

John Edwards - Crédit Suisse

Christine Cho - Barclays Capital

Elvira Scotto - RBC Capital Markets

Faisel Khan - Citigroup

Operator

Good day, ladies and gentlemen and welcome to the Second Quarter 2014 Boardwalk Pipeline Partners Earnings Conference Call. My name is Kane, I will be your operator for today. At this time all participants are in listen-only mode. Later we will conduct a question-and-answer session. (Operator Instructions). As a reminder this conference is being recorded for replay purposes.

I would now like to turn the conference over to your host for today, Ms. Molly Ladd Whitaker, Director of Investor Relations and Corporate Communications. Please proceed.

Molly Ladd Whitaker

Thank you, Kane. Good morning, everyone and welcome to the second quarter 2014 earnings call for Boardwalk Pipeline Partners, LP. I’m pleased to be joined today by Mr. Stan Horton, our President and CEO; and Mr. Jamie Buskill, our CFO.

If you would like a copy of the earnings release associated with this call please download it from our website at www.bwpmlp.com. Following our prepared remarks this morning we will turn the call over for your questions.

We would like to remind you that this conference call will include the use of statements that are forward-looking in nature. Statements in this earnings call related to matters that are not historical facts are forward-looking statements. These statements are based on management's beliefs and assumptions using currently available information and expectations. Actual results achieved by the company may differ materially from those projected in any forward-looking statements. The company expressly disclaims any obligation to update or revise any forward-looking statements made during this call.

I’ll also like to remind you that during this call today we may discuss certain non-GAAP financial measures, such as adjusted EBITDA and distributable cash flow. With regard to such financial measures please refer to our earnings release for reconciliation to the most comparable GAAP measures.

Now I would like to turn the call over to Stan Horton.

Stanley Horton

Thank you, Molly, and good morning, everyone. I hope you've had a chance to review the press release we issued this morning. In addition to reporting earnings we also announced a quarterly distribution of $0.10 per unit or $0.40 annualized.

I am going to provide a commercial update and then Jamie will discuss the financial results for the quarter. During the second quarter we made good progress on adding new firm load to our natural gas pipeline network. The majority of this new demand utilizes mainline capacity termed back in prior periods or expected to expire in the near future. However, considering the lead times need for regulatory approvals and construction many of these projects will not begin generating revenues for another two to three years.

Our Southeast market expansion project is currently being constructed and is proceeding as planned. We expect the project to go into service in the fourth quarter of this year. This project increases Boardwalk’s ability to transport natural gas supplies to growing areas of demand in the Southeast region in the United States, including industrial and power generation markets in Mississippi, Alabama and Florida. This approximately 550,000 MMBtu a day project is fully contracted with long term firm agreements.

Two previously announced projects for deliveries to new gas-powered power plants have been recently completed or near completion. In June we placed into service the second phase of our project that serves a new gas-powered power plant in North Texas where we have firm commitment to deliver approximately 125,000 MMBtu a day.

In a prior earnings call we announced a long term contract with Kentucky Utilities to serve their Cane Rune combined cycle power plant with a firm commitment of approximately 105,000 MMBtu a day. I am pleased to report that the targeted in service date is on schedule for the fourth quarter of this year. Serving this plant will utilize existing mainline capacity and require minimum capital.

During the quarter we made progress on new several new in-use delivery opportunities. We recently executed a 11 year firm transportation agreement to serve a new industrial plant in Louisiana with approximately 100,000 MMBtu a day volume commitment and a first quarter 2016 targeted in-service date. We also recently executed our five year firm and no-notice service agreements to serve a new gas-powered power plant in Indiana with approximately 105,000 MMBtu a day volume commitment and a second quarter 2017 targeted in-service date. Minimal capital will be required to serve each of these plants.

In addition we recently completed a successful open season for a project that would provide gas deliveries from Perryville exchange to the Louisiana river corridor area. We have executed a long term preceding agreement with an industrial end-user for 80,000 MMBtu a day of firm transportation service, subject to the customer receiving a final investment decision on the plant. The anticipated service commencement date for this project is in 2018 and capital costs are expected to be minimum.

We also recently completed a binding open season for the Western Kentucky Market Lateral Project. This Lateral would consist of approximately 90 miles of pipeline and provide up to 230,000 MMBtu a day of deliveries to a proposed plant in Kentucky. The end service date for the project is targeted for the third quarter of 2016 subject to regulatory approvals and is expected to cost approximately $80 million. In order to attain the gas supplies needed to feed this proposed lateral mainline capacity on Texas Gas will be contracted and utilized as well.

Now I will provide an update on the Texas Gas North-to-South conversation project, which once completed will give Texas Gas bi-directional flow capabilities adding valuable optionality to the Texas Gas system.

Our Ohio-to-Louisiana access project announced two quarters ago will provide long term firm natural gas transportation primarily from Lebanon, Ohio to delivery markets primarily in Louisiana. We have executed preceding agreements for approximately 625,000 MMBtu a day with a weighted average contract life of 13 years. It will cost approximately $115 million with a first half 2016 targeted in-service date subject to regulatory approval. The majority of this capacity will be used to serve in newest markets such as LNG exports, LDC and industry markets which are either directly or indirectly connected to our pipeline system.

Last quarter we also announced the Northern Supply Access project which would add more North-to-South flow capabilities to Texas Gas. We have executed firm preceding agreements for 130,000 MMBtu a day of capacity associated with the Northern Supply Access project subject to Board and regulatory approvals. The majority of these volumes are expected to deliver into the proposed Southern Indiana market lateral and additional capital project design to serve new industrials in the area consisting of a 30 mile pipeline with a capacity of 166,000 MMBtu a day. This project is supported by firm preceding agreements with a weighted average contract life of 20 years also subject to Board and regulatory approvals.

CapEx combined is estimated at $100 million and we expect both projects will go into service in mid-2016. An open season for the remaining capacity associated with the Northern Supply Access project just concluded on July 28. In the open season we offered up to 584,000 MMBtu a day of north-to-south capacity with the second quarter 2017 targeted in-service date. We are still evaluating the results of the open season and will provide more details on the outcome once the analysis is complete.

Now an update on the Flag City Processing Plant in South Texas. That plant has been in service for approximately a year now and we have seen plant utilization increase as the Eagle Ford Shale play continues to ramp up. I am pleased to announce that we contracted for an additional 30 million cubic feet a day of firm gathering and processing capacity in our Flag City processing plant in South Texas under a five year agreement this quarter. Boardwalk will spend approximately $14 million to construct a lateral to this new customer which is expected to go in to service in the first quarter of 2015. With this new agreement in place the Flag City plant is now 70% contracted on a firm basis and we continue to process additional volumes on an interruptible basis as well.

Highlighting the continued demand for liquid services in Louisiana, last quarter I mentioned that we were engaged in discussions with customers looking to build large scale ethane crackers in Louisiana and that we had executed long-term firm agreements with one of these customers Sasol for ethane and naphthalene transportation storage services contingent on their ethane cracker receiving a final investment decision. This project is expected to cost approximately $145 million and is anticipated to go in service in the second half of 2017.

Now I'd like to discuss our current storage fundamentals. This past winter we experienced demand for loaning services due to wide fluctuations in price. The extremely cold winter this fast heating season resulted in low storage balances and a NYMEX curve went backwardated and as we anticipated demand for parking and storing services has been very weak. We are starting to see some improvement but the natural gas time spreads are still somewhat compressed. Weather and production trends will continue to have a big impact on these spreads.

In conclusion, as I have illustrated today we are seeing an increased interest for our pipeline capacity and are working diligently to transform our assets to serve ever-changing marketplace. Many of the projects we are working on are repurposing existing capacity for new uses. The projects I just mentioned today represent approximately two billion cubic feet a day of demand for our natural gas pipeline system.

I am encouraged by the amount of deal flow we are seeing and feel our assets are well positioned. A supply push from the Northeast is occurring as Marcellus and Utica production is ramping up and needs to find additional market outlets. At the same time an offsetting demand pull has emerged. Our [inaudible] is located near many potential new power generation, industrial and LNG export facilities. These end use markets value flexible and reliable transportation and storage services and value supply optionality, all of which we are capable of providing.

Now let me turn the call over to Jamie to review the results of the quarter.

Jamie Buskill

Thank you, Stan and good morning everyone. We reported operating revenues of $293 million for the quarter, an increase of $5 million or 2%. Our revenues were favorably impacted from the recent completion of growth projects and colder than normal weather during the earlier part of the quarter. The increase was offset by lower storage revenues and lower transportation revenues related to firm contract renewals due to the negative market fundamentals we have previously discussed. Our natural gas transportation volumes for the quarter were 596 TBTU compared to 567 TBTU transported in the second quarter of 2013. We transported eight million barrels of NGLs in the second quarter of 2014 compared to 10 million barrels in the second quarter of 2013, a decrease of 20% due to third party facility outages.

We reported operating expenses of $197 million for the quarter, an increase of $90 million or 11%. The 2013 period was favorably impacted by gains of $17 million related to storage base gas sales which lowered operating expenses in the previous year. Adjusted EBITDA for the quarter was $167 million, a decrease of $12 million or 6% from $179 million for the comparable period in 2013. Net income attributable to controlling interest for the quarter was $57 million, a decrease of $14 million or 19% from $71 million for the comparable period last year. Both adjusted EBITDA and net income were impacted by the items previously discussed.

We generated $124 million of distributable cash flow for the quarter, a decrease of $25 million, or 17% from the $149 million generated in the second quarter of 2013. We invested $74 million in our growth projects for the quarter and have invested $124 million year-to-date and plan to invest approximately $330 million in total for the year.

In the second quarter we spent 23 million in maintenance CapEx and have spent $39 million year-to-date and plan to spend between $90 million to $100 million in total for the year. In addition in the third quarter we plan to spend approximately $15 million in base gas purchases for operational purposes. We expect to finance our 2014 growth capital expenditures from cash flows generated from operations utilizing the available capacity under our revolving credit facility and borrowings under our new subordinated debt agreement.

Boardwalk and a subsidiary of Loews Corporation have entered into a 10 year $300 million subordinated debt agreement under which Boardwalk has the right to borrow at any time until December 31, 2015. The initial interest rate will be 5.75% which is fixed until May 2018. To-date we have not borrowed under this arrangement. This agreement further underscores Loews support for Boardwalk. As of June 30th we had $100 million borrowed under our revolver.

In summary we are pleased with our financial results from the first half of 2014. But just as a reminder the third quarter historically tends to be our lowest performing quarter due to the seasonal nature of our revenues and maintenance activities. We are not revising the 2014 distributable cash flow guidance that was provided earlier this year.

That concludes my remarks and I will now turn the call over to the operator for questions.

Question-and-Answer Session

Operator

(Operator Instructions). Your first question comes from the line of Brian Lasky from Morgan Stanley. Please proceed.

Brian Lasky - Morgan Stanley

Good morning everyone.

Jamie Buskill

Good morning

Stanley Horton

Good morning.

Brian Lasky - Morgan Stanley

I was curious whether you could just quantify the impact of weather on this quarter’s results. I think last quarter you said there was kind of an $18 million to $19 million impact. What was the equivalent this quarter?

Jamie Buskill

It’s not smaller. It’s just actually a few millions dollar this quarter. Where you saw a part of that was as Stan mentioned we were able to do parks, because of the backwardated market and if you know this our park and lending was up about $2 million for the quarter. That was the biggest driver.

Brian Lasky - Morgan Stanley

Got it. If you could I think earlier this year you guys guided, your [run way] is down from transportation storage having a $40 million range from contract rollovers. It seems even excluding some of the weather impacts and other things that you are trending well above that. Could you just kind of update us on your thoughts around the re-contracting front?

Jamie Buskill

Yes. The annualized impact from the contract renewals we said would be approximately $40 million. One thing I will caution on that, some of the bigger contracts that expire actually happened in the second-half of the year. So that’s probably driving some of the results differences between the first half and second half but that’s kind of still where the range is approximately $40 million.

Brian Lasky - Morgan Stanley

All right. Got it, that makes sense. That’s all I had. Thank you.

Jamie Buskill

Thank you.

Operator

Your next question comes from the line of Jeremy Tonet from JP Morgan. Please proceed.

Jeremy Tonet - JPMorgan

Good morning, congratulations on the strong quarter.

Jamie Buskill

Thank you.

Jeremy Tonet - JPMorgan

I was just wondering if you could help us out, when you provided the guidance at the beginning of the year, how did these results stack-up versus your plan, could you share anything on that.

Jamie Buskill

No, we really talk to the year. I mean we did see a strong start to the year but the thing I would like to point out and focusing on the remainder of the year, first off, we did have the colder than normal weather. So it’s hard to predict what weather will be but you have to assume it’s probably going to more on the normal weather tend. Stan mentioned the story to markets right, now very challenging and then as I just mentioned on the previous question some of our contract renewals actually happened, our explorations happened in the second half of the year.

And also as I said on the call we are buying about 15 million of base gas sales. Now that’s in the third quarter. We’ll leave it up to you as to whether you include that or exclude it from the distributable cash number. So those are something affecting the year. But yes, the first half of the year was little stronger than we expected because of the colder weather primarily.

Jeremy Tonet - JPMorgan

Got you, thanks. And I was just wondering, it seems like there is a bunch of projects out there than you -- Stan you ran through, that was very helpful. And I was wondering if you might be able to provide us any color on what the economics might look like for these projects. It seems that you said there’s minimal capital requirements. So it seems like these projects could be nicely accretive and given that some of the binding open seasons have been completed at this point just wondering if you could share any thoughts on that with us.

Stanley Horton

Yeah, the guidance that I have being giving people on these projects is that you ought to be thinking about in the aggregate. I mean we are a regulated pipeline and overtime we are going to earn a regulated rate of return on these projects in the aggregate. So when I tell people that they are not to look at these projects on a case by case basis I mean a project that has minimum capital that gives us a hundred thousand MMTBtu a day of new incremental load. I mean if you calculated the return on the incremental capital it’s huge but that’s not really the way things work because we have got embedded capital on our existing pipeline system.

So what I tell people is these are good sound regulated rate of return projects when you look at them in the aggregate.

Jeremy Tonet - JPMorgan

Okay, fair enough. And I was just wondering it might be a little bit earlier at this point but there was some commentary in some releases there about supply header for an LNG facility in Gulf South. I was just wondering if you might be able to share any color there?

Stanley Horton

No, not really. We continue to talk to all of the LNG facilities and sometimes early in these discussions for regulatory reasons we have to post things on our electronic bulletin board but discussions that we are having with people that have advanced to the point where we have preceding agreements or expecting to have preceding agreements in the very near future we like to talk about. Those that have not advanced to that stage, we’d rather not talk about.

Jeremy Tonet - JPMorgan

Fair enough. And then just one last one for me if I could. I was wondering if you might be able to comment on the Lebanon to TGT Zone 1 differentials and how that has impacted demand for North or South service. Seems like they spend some substantial changes there over time, just wondering if you might be able to comment there.

Stanley Horton

Well, what I think people are looking at is longer-term, I think what they are looking at is longer-term where the demand is going to be and how they can physically move gas north to south. These are 15 and 20 year transportation agreements that people are looking at. So short-term pricing needs, do they impact it? Yes, somewhat but not as much when you are talking about 15 and 20 year commitments that people are looking.

As I said there is a supply push. Supply has got to come out of Marcellus-Utica. The big demand is along the Gulf Coast Area and people are just looking for the most economic means to be able to get there. So I think we are right in the hunt on everything that we are doing there.

Jeremy Tonet - JPMorgan

That’s it for me. Thank you very much.

Stanley Horton

Thank you.

Operator

Your next question comes from the line of Darren Horowitz from Raymond James. Please proceed.

Darren Horowitz - Raymond James

Good morning guys. A couple of quick questions for me, Stan, when you start thinking about additional downstream Gulf Coast demand and further opportunities to lever your Gulf South Line beyond the Southeast market expansion kind of beyond the opportunity for LNG export, where do you see the biggest opportunity? Is it a ship channel focus, or maybe further east through Bad Rouge or is there just so much more industrial and power generation and possibly PetChem and export opportunities that that’s where the big infrastructure push is going to end up?

Stanley Horton

I would say this and I won’t talk about any specific projects, I haven’t talk about today. But I’m -- as I said I am very, very encourage by the low profile that we are seeing from Texas all the way over to the Florida Panhandle and that’s where our Gulf South system is located. So it’s not one particular area. I mean we're seeing a great interest all the way down from South Texas to the Florida Panhandle. So I am very encouraged as I said in my comments.

Darren Horowitz - Raymond James

Okay, and then with regard to the Sulphur and Choctaw facilities that you talked about, can you just remind me you how much of capacity there is available for possible NGL storage and maybe some downstream or multi-directional optionality through a header system and how much more incremental CapEx do you think it would take in order to get those specific facilities up to where you can have greater vertical integration moving product downstream?

Stanley Horton

You are asking me questions about numbers I don't have in front of me, but I would say this, I mean we got a lot of capability to expand in that area to meet additional projects like the Sasol project that we announced. I just don't have the specific numbers in front of me but I'll be glad to have Alistair or Molly try to get those to you.

Darren Horowitz - Raymond James

Okay. And then last question, just with regard to your commentary, specifically around the Flag City Processing Plant. Based on the contract mix and the opportunity for upside there on an interruptible basis at what level of capacity utilization do you start thinking about possibly an expansion?

Stanley Horton

Well, what you’d love to be able to do is close out one position and then start another plant. I wouldn't say we would have to be a 100% closed out. We are all the time talking to producers in that area. About a second plant -- at the site of Flag City we’ve got the ability to put two more trains. So it's not so much just closing out our position on the first one and it's how much can we get contracted on the second one. I don't want to build the spec plant that's kind of not what we do, but if we could enough market demand to put a floor of our returns on the second plant we’d certainly look at that and that's what we are talking with producers about.

Darren Horowitz - Raymond James

Thank you.

Operator

Your next question comes from the line of John Edwards from Crédit Suisse. Please proceed.

John Edwards - Crédit Suisse

Hi. Good morning everybody and congrats on another good quarter. Just Stan, I mean you've gone through a number of contract wins here and you've indicated in your comments you are pretty optimistic. So I am just curious in terms of contract wins versus plan how would you view that?

Stanley Horton

Well, our plan is an internal document, so we don't really contrast things against our plan externally. Just let me go back and say that I am very pleased with the deal flow. We talked about the deals today during my discussion that I think our deals that are either in-house or just subject to regulatory approval or FID of the parties. They are not the only discussions that we have going on but they are the only discussions that we like to talk about.

We're pretty consistent that we don't talk about deals before they are deals. But just suffice it to say to that I am encouraged about the deal flow, I mean I am. There is a great deal of market demand that’s building up our around pipeline system and we're pleased and we think we're going to get our share of that demand.

John Edwards - Crédit Suisse

Okay, that's helpful. So just following that then in terms of deal flow versus contract roll-off, I mean at this point are you expecting your deal flow to more than offset your future contract roll-offs?

Stanley Horton

One of the things that we are starting to see and it's -- Jamie and I wrestle with how to talk about new contracts and contract roll-offs and renewals and trying to segregate those into the buckets that we've been segregating them, because in a lot of cases some of this new deal flow is using contract capacity that has been term backed in previous years and maybe be unused for short-term firm transport where there's been capacity term back in previous years. So we’re wrestling with how to start presenting that to the invest community to where there’s a better understanding about what's going on. I think probably in the future we'll try to start talking about this on a net basis.

What everyone is used to is talking about the buckets that we have been talking about but it’s getting, as I said, more difficult to be able to do that as we are rolling over contracts, we are re-contracting space, that’s been termed back in prior periods. We are re-contracting space that we anticipate that might be termed back in future periods. So it’s really on a net basis that we ought to start talking about this and we’ll increasingly start doing that as we move forward.

John Edwards - Crédit Suisse

Okay. So maybe if I could ask it another way are you expecting the capacity utilization to at least, that sounds you are expecting it to at least hold steady more or less going forward if not maybe perhaps even increasing a bit. Is that maybe the right way to think about it or..?

Jamie Buskill

John, we can provide guidance beyond what we provided already. But as Stan mentioned a lot of project we are talking about does exactly what he says, but a lot of these don’t come out on for another two or three years. So just keep that in mind.

John Edwards - Crédit Suisse

Okay, fair enough. And you were talking about on the base gas, you are going to leave it up to us whether to include it or exclude it from DCF. I am just curious how you guys are going to account for it?

Jamie Buskill

We’ll show it on the -- we anticipate showing it as coming out of DCF. Basically it will be a reduction in DCF but even with that we still anticipate -- are still comfortable with our guidance that we provided at the beginning for the year.

John Edwards - Crédit Suisse

Okay.

Stanley Horton

Yeah, I think when we sold gas we included it in DCF.

John Edwards - Crédit Suisse

That’s right.

Stanley Horton

So we don’t want to be buying gas and not include in DCF, we are being consistent.

Jamie Buskill

Yeah, we show the pieces and we will kind of leave up to you guys to decide how -- whether you want to include it or not.

John Edwards - Crédit Suisse

Okay, then I missed your -- I think you gave out the expected CapEx now for the year. Can you just repeat that?

Jamie Buskill

Yeah, the growth capital for the year is approximately $330 million, maintenance capital is $90 million to $100 million and then we did $15 million of gas, base gas purchases.

John Edwards - Crédit Suisse

Okay, great. That’s all I have, thank you very much.

Operator

Your next question comes from the line of Christine Cho from Barclays. Please proceed.

Christine Cho - Barclays Capital

All of the north to south service you have announced does it include utilization of the 26 inch line that you recently were thinking about converting for Bluegrass?

Stanley Horton

Know as I have I think I have stated before, there is an aggregate amount of gas that on a north to south flow if we would get to, we would need the 26 inch to remain in natural gas service. With the Ohio-to-Louisiana project in the 130,000, the northern axis that I talked about, that is still below what we would need. We got to be able to ascertain the demand from the recent open season that concluded.

If that number gets above or about 350,000 decatherms a day then we would have to make a decision, because anything over that we would need that 26 inch to remain in natural gas service. So that’s kind of a key number for us.

Christine Cho - Barclays Capital

So 350,000 decatherms over what, the Northern Supply Access project was going to be or including?

Stanley Horton

No, if you take the 625 a day on the -- our first project the Ohio-to-Louisiana project the 130,000 that we had on the lateral, on the Northern Axis Supply Project that I talked about and then add 350,000 to that, that’s kind of the number that we can receive up in the north and transport down in the Louisiana without needing the 26 inch line. Any volumes in addition to that we would need the 26 inch line to stay in service.

Christine Cho - Barclays Capital

And I mean assuming that you get this extra 350,000 decatherms a day contracted I mean when do you anticipate making a decision on what do you want to do with that 26 inch line?

Stanley Horton

Well as soon as we have decisions that we have to make on the gas, commensurate with that we would in effect be making a decision on the 26 inch. So I think as we said, we’ll know where we are on the Northern Access Project probably by the end of the month. So it's kind of that time frame that if the [range] were above 350 we’d have make a decision on the pipeline project. If they are below 350 then we have more time to make that call.

Christine Cho - Barclays Capital

Okay, great. And then you talked about a number of projects being minimal in CapEx collectively when you add all of these small projects how much is the total ball park, is that less than $30 million or $50 million? I am just trying to get a gauge of what your definition of minimal capital?

Jamie Buskill

So if you look at all the project excluding the southeast which goes in service this year but if you add up all the capital spend that Stan mentioned on those projects it's about $450 million, and again that excludes the Southeast expansion.

Christine Cho - Barclays Capital

Okay, and then I think you have some debt maturing in 2015 on Texas Gas and Gulf South, have you guys decided if you are going to be refinancing that or…?

Jamie Buskill

I can't provide guidance on our financing plans. We do have collectively $525 million of debt that expires between those two companies, but I can't provide any guidance at this point.

Christine Cho - Barclays Capital

Okay. Thank you. That's it from me.

Operator

Your next question comes from the line of Elvira Scotto from RBC Capital Markets. Please proceed.

Elvira Scotto - RBC Capital Markets

Hi. Good morning. Just one question from me, you talked a lot about the expansions on Texas Gas transmission and Gulf South. I was wondering if you can provide maybe your thoughts on opportunities around Gulf Crossing especially given its location and the potential growth coming out of the SCOOP?

Stanley Horton

Yeah, I'd be glad to. I mean there is a lot of growth coming out of the Oklahoma region and the SCOOP play, stack play and others. We continue to monitor that. We continue to have discussions with producers, nothing imminent nothing that I can talk about in the way of projects. But it’s certainly our hope that those volumes continue to grow because they're good volumes that could be transported down Gulf Crossing in the years ahead. So we have a lot of interest in it and continue to monitor it and work with those producers.

Elvira Scotto - RBC Capital Markets

That's great. Thank you.

Operator

Your next question comes from the line of Faisel Khan from Citigroup. Please proceed.

Faisel Khan - Citigroup

Hello

Stanley Horton

Yes.

Faisel Khan - Citigroup

Oh, sorry I didn't recognize the name. It's Faisel Khan from Citigroup, so I guess I’ve a new name now. But I just had a couple of questions on the north to south capacities you guys were just talking about. So just adding the 625 to 130 and 350, sort of you gets you to in that sort of BCF a day base. So anything above that you are saying you need to sort of -- if you can clarify your statements around that, that will be great.

Stanley Horton

Yeah. As I said, anything over about 350,000 MMBtu a day associated with the open season that we just concluded would necessitate that we leave the 26 inch line, that we had and are proposing to abandon for the Bluegrass project it would necessitate that, that line stay in natural gas service to be able to effectuate the deliveries to Louisiana. So that's kind of the volume that takes you over the top, the remaining capacity would be not sufficient to do that. You would need the 26 inch line to remain in gas service. That help?

Faisel Khan - Citigroup

Okay, assuming that -- yeah, it does. Assuming that 26 inch remains in service, what's the capacity total north-south we can get out of that line?

Stanley Horton

Again the 584 that we offered up in the Northern Supply Access open season, we offered up that 584 because that was the maximum capacity that we could let move on Texas Gas north-to-south on a fully compressed Texas Gas system. So when we ran the open season we decided instead of trying to pick a number and pick a project that we would just offer up the total amount of capacity that we could handle with a fully compressed system and then see what the market demand was for additional capacity at this point in time.

Faisel Khan - Citigroup

Okay.

Stanley Horton

So that’s I mean that’s where that number came from. It wasn’t a specific project number. It was just kind of the maximum capacity that we could add to the system on a north to south flow and to do that you need the 26 inch line service.

Faisel Khan - Citigroup

So on a fully compressed basis north to south is the 625, 130 and 584, is that…?

Stanley Horton

That’s correct. You’ve got it?

Faisel Khan - Citigroup

Okay, and there is no other way to add additional capacity unless you were?

Stanley Horton

There is, I mean we can start looping the system. But the first thing that we wanted to do was to offer our capacity on a fully compressed system and after you pass that hurdle then you can start looking at the next hurdle and the next hurdle is looping the system and of course when you start looping the system, I mean you can -- the capacity is not infinite but it’s just how much loops do you want to put in and what are the economics associated with that?

Faisel Khan - Citigroup

So I assume this time 584 a day is, I mean if you look around the market today that’s got to be some of the cheapest capacity on a north-south basis, is that a fair statement or…?

Stanley Horton

You know there is a lot of projects being offered up there and a lot of projects that are going to different markets, whether it be the Florida market, the Carolina markets or markets up in Canada or markets back in the Gulf Coast. So it’s hard to just to kind of compare rates because in some cases people are getting down to the Gulf Coast and the other thing is where they are getting to the Gulf Coast and is there additional third party transport that has to occur once they get to a point to get to a market. So it’s not just what is our capacity versus our rate versus somebody else. It’s our rate, our market where do they get to, how much incremental fees to get to the market that they are ultimately trying to get to. So it’s unfortunately it’s just not that simple.

Faisel Khan - Citigroup

Okay, if I look sort of beyond this 584 data and is it -- I mean have you even -- does it make sense to start having those conversations with the customers right now?

Stanley Horton

Well, no, I tend to take things one step at a time I have 40 years. Once we get the 584 contracted we can start turning our attention something that’s bigger than that. But 584,000 MMTBtu a day is big volume coming on top of the volume that we have already subscribed. Let us try to handle that one before we turn our attention to a bigger looping project.

Faisel Khan - Citigroup

Okay, and is there any reason to think that, that 584 a day would be and the cost would be any different than the 625 you guys have outlined before?

Stanley Horton

Yeah, I mean you know the 625, I would say, one of the reasons that we offered that up, it’s a $115 million for the 625. I think we gave some guidance that the 584 on a capital basis would be more expensive than the 625. I don’t know what the project is going to be right now I don’t know whether the project would occur all at once or in increments or what, so I just really can’t give any guidance of what the capital cost could be.

Faisel Khan - Citigroup

Okay, thanks. I appreciate the time and interest in my questions.

Operator

Your next question comes from the line of John Edwards from Crédit Suisse. Please proceed.

John Edwards - Crédit Suisse

Yeah, just to follow up Faisel’s question, so on the 584 that you have put out there I guess that’s the capacity where you have just, I guess concluded the open season and you are going to I guess at the end of the month have a better idea of how much of that will subscribed and at that point you will be able to -- that will be the decision point on the extra 26 inch, whether that stays in gas service or not, just to clarify is that correct?

Stanley Horton

Yeah, that’s correct. But also let me clarify this. I would expect that when we analyzed the bids, that the bids would kind of fall into three buckets. Those that we are able to get absolute firm agreements on and people want us to proceed on regulatory fillings to serve their load, those that may have certain contingencies in the bid and that they’ll need to work out their contingencies before that would become a binding contract, and then those who have a strong interest but aren’t will to yet put their name on the contract. So the 584 as I said could be one project. It could be a series of projects that would go into service over a two to three year period. We just don’t know right now.

John Edwards - Crédit Suisse

Okay, that’s really helpful. Okay, thank you.

Operator

Ladies and gentlemen, that concludes our question-and-answer session. I will now turn the call back to Molly Ladd Whitaker for your closing remarks.

Molly Ladd Whitaker

Once again, we’d like to thank you for joining us this morning and for your continued interest in Boardwalk Pipeline Partners. As a reminder an online replay of this call is available on our website at www.bwpmlp.com. This concludes today’s conference call. Thank you and have a great day.

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