May 6, 2014
Executives
Michael N. Mears - Chairman of Magellan GP LLC, Chief Executive Officer of Magellan GP LLC and President of Magellan GP LLC Michael P.
Osborne - Chief Financial Officer of Magellan GP LLC and Senior Vice President of Finance & Accounting - Magellan GP LLC Paula Farrell -
Analysts
Edward Rowe John D. Edwards - Crédit Suisse AG, Research Division Norman Kramer Steven C.
Sherowski - Goldman Sachs Group Inc., Research Division Brian J. Zarahn - Barclays Capital, Research Division Elvira Scotto - RBC Capital Markets, LLC, Research Division Stephen Tabb - Tocqueville Asset Management LP Stanley Ross Payne - Wells Fargo Securities, LLC, Research Division Sharon Lui - Wells Fargo Securities, LLC, Research Division
Operator
Good day, and welcome to the Magellan Midstream Partners First Quarter 2014 Earnings Results Conference Call. Today's conference is being recorded.
At this time, I would like to turn the conference over to Mr. Mike Mears, Chief Executive Officer and President.
Please go ahead, sir.
Michael N. Mears
All right, thank you, and thank you for joining us today. I would like to start by thanking those of you that attended our recent Analyst Day.
We hope you received some valuable detail about our current businesses and growth projects, and found the event to be a useful -- good use of your time. Before we dive into our earnings, I'll remind you that management will be making forward-looking statements as defined by the SEC.
Such statements are based on our current judgments regarding some of the factors that could impact the future performance of Magellan. You should review the risk factors and other information discussed in our filings with the SEC and form your own opinions about Magellan's future performance.
As announced this morning, we kicked off 2014 with exceptional strength, generating quarterly financial records during the first quarter of 2014. Not only did we significantly exceed our financial results from a year ago, including a year-over-year DCF increase of 104%, but we also beat our quarterly EPU guidance due to stronger-than-expected volumes and rates for our refined products and crude oil pipelines, more favorable product overages on our pipeline systems, and the sale of additional volumes from our butane-blending activities, in part due to higher gasoline demand, which provides us more opportunities to blend.
I'll hand the call over to our new CFO, Mike Osborne, to discuss our first quarter results in more detail, then I'll be back to discuss our outlook for the rest of 2014 and the status of our expansion capital projects.
Michael P. Osborne
Thanks, Mike. Before I begin, I want to mention I will be commenting on the non-GAAP measure operating margin.
A reconciliation of operating margin to operating profit was included in our earnings release this morning. Management believes that investors benefit from this information as it's a tool we use in evaluating the economic success of the partnership's core operations.
We reported record net income for the quarter of $242.6 million compared to net income of $113 million in the first quarter of 2013, or an increase of approximately $130 million. Net income per unit increased from $0.50 to $1.07, also a record.
While each of our segments produced higher results than the prior year period, both the refined products and crude segments recorded significant increases over the prior year period and were key drivers of the overall increase. Total operating margin for the quarter was $347.5 million compared to $208.9 million for the first quarter of 2013.
Our refined products operating margin increased from $255 million -- from $160.2 million or a $94.8 million increase, with the transportation and terminals margin increasing $40 million and the product margin component increasing $54.8 million. On the transportation and terminals margin, this benefited from both increased volumes shipped and higher tariffs.
The volumes shipped increased almost 12% to 103.8 million barrels in the 2014 quarter from 93 million barrels in 2013. Excluding acquisitions and the short-haul movements on our South Texas system, our historical pipeline system benefited from a 10% higher volumes due to strong demand for refined products in regions that it operates.
In part due to the seasonal reversal of a portion of our Oklahoma system to deliver product into Texas, the start-up of our recently constructed pipeline from El Paso to a locomotive fueling facility in New Mexico and shipments to a new connection to a third-party pipeline that serves markets outside of our core areas. Overall, our average tariff increased $0.22 per barrel from approximately $1.14 to $1.36.
The increase primarily resulted from longer haul movements on our historical pipeline system to meet the strong demand, a slight decrease in volumes on our South Texas system, which has lower rates, and the 2013 4.6% midyear tariff adjustment. The high revenues were slightly offset by higher operating expenses, which were attributable to operating costs related to the pipeline systems acquired in 2013, higher property taxes, power expenses and personnel costs, and those were offset by higher product overages.
The product margin component increased in refined products segment was primarily attributable to butane-blending activities. The product margins benefited from both lower cost of butane and higher volumes.
The higher volumes were attributable to selling additional volumes that were carried over from 2013 blending activities that were in inventory at year end and then additional increased blending during the quarter due to blending opportunities resulting from higher product demand. The crude segment increased to $63.3 million from $22.7 million or a $40.6 million increase in operating margin.
The primary drivers of this were Longhorn, which began operation in mid-April 2013, and then also higher pipeline volumes on the Houston crude oil distribution system. Longhorn averaged approximately 200,000 barrels per day during the quarter, and our average tariff was approximately $2.15 per barrel.
Increased operating expenses on the segment were primarily attributable to costs related to the operation of Longhorn, and those were partially offset by favorable product overages. On the marine storage segment, operating margin increased from $25.3 million to $28.4 million for a 12% increase.
This was driven by storage fees from newly constructed tanks placed into service at our Galena Park terminal, as well as lower maintenance expenses during the period. Stepping down from operating margin to net income.
We experienced slightly higher depreciation due to higher property balances. We had higher G&A costs due to increased personnel costs, primarily.
And then our net interest cost, inclusive of capitalized interest, was up slightly as well due to higher average debt balances. We ended the quarter with cash and equivalents of $196.6 million, and our total debt balance of $2.9 billion.
During the quarter, we issued an additional $250 million of our 5.15% notes due in October 2043. The notes were issued 103% of par to yield 4.95 to maturity.
At the end of the quarter, we had no borrowings on our $1 billion revolving credit facility. And our debt to EBITDA computed on a rolling 4-quarter basis was 2.8 to 1, and that calculation considers the cash on hand on the balance sheet, so it's a net-debt calculation.
All of our interest is currently at a fixed rate. However, we do have the June maturity of our 2014 notes, and we anticipate, at least initially, refinancing those on our new commercial paper program.
I'll now turn it back over to Mike to discuss capital projects and DCF guidance for the remainder of 2014.
Michael N. Mears
Thanks, Mike. Considering our strong start to 2014 and looking ahead for the rest of the year, we have increased our DCF guidance by $80 million to $810 million.
The increased guidance primarily incorporates the favorable items that benefited our first quarter results. Even though we had many positives with regards to volumes, rates and blending margins in the first quarter, we have not materially changed our underlying business assumptions for the remainder of the year at this point.
On the distribution front, we raised our quarterly cash distribution to $0.6125 per unit, which puts us on a ratable trajectory to reach our goal of 20% annual distribution growth for 2014. By increasing our DCF guidance to $810 million, we now expect 2014 distribution coverage of about 1.35x, which would equate to excess cash of over $200 million for the year.
Even though this is more than the $125 million excess cash target that we have mentioned in the past, we still believe $125 million is a reasonable long-term target. And we remain committed to our goal of increasing cash distributions by 20% for 2014 and 15% for 2015.
In the meantime, we plan to use our excess cash to fund our expansion growth projects. Magellan continues to benefit from a tremendous period of growth, and we are making significant progress on our current expansion projects.
We have been increasing crude oil volumes on our Longhorn Pipeline, averaging 2,000 barrels per day during the first quarter of 2014. And we now have received regulatory approval to increase Longhorn's capacity to 275,000 barrels per day and expect to average about 240,000 barrels per day during the second quarter and in the 250,000-barrel a day range during the second half of the year.
We are also nearing start-up of our largest construction project to date, the BridgeTex pipeline. As you know, BridgeTex is our joint venture with Occidental Petroleum to deliver crude oil from the Permian Basin to the Houston Gulf refinery region.
We are nearing completion of tank and pipeline work, and expect to begin initial line fill during late second quarter, with pipeline deliveries to the Houston area expected during mid-third quarter. The project remains within budget with around 90% of the project costs committed at this point.
Based on the timing of start-up and the timing of related cash distribution payments from the joint venture to Magellan, we expect to see the first real financial benefit of BridgeTex beginning with 2015 results. We have also recently announced 2 additional expansion projects to drive Magellan's future growth.
The first one entails building a 50,000-barrel-a-day condensate splitter at our Corpus Christi terminal. As we've discussed in the past, Corpus Christi is an ideal location for a condensate splitter due to the close proximity to the condensate-rich Eagle Ford shale, as well as it being the termination point of our Double Eagle joint venture pipeline.
The splitter is fully supported by a long-term take-or-pay commitment, which is expected to generate an average EBITDA multiple of 6x. We expect to spend approximately $250 million on this project, with about 1/3 of that related to the actual splitter.
The remaining 2/3 of the capital will be spent on storage, and additional terminal and dock improvements to our Corpus Christi facility. We have submitted all of the air permits and expect them to be approved in early 2015, which will allow us to begin construction at that time.
At this point, we expect to complete construction, begin operations of the condensate splitter during the second half of 2016. The second large-scale project we just announced yesterday, which relates to our Little Rock refined products pipeline.
As we've discussed in the past, we received sufficient commitments from our Open Season process, but needed to finalize the scope of the project. We just announced that we have entered into an agreement with a subsidiary of Spectra Energy Partners to utilize an existing 160-mile pipeline for a portion of the route.
And with this step complete, we are proceeding with the Little Rock project. Magellan will construct 2 new sections of pipeline.
First, from our Fort Smith terminal to connect to the existing pipe at the origin end. And two, from the existing pipe into the Little Rock area on the destination end.
We expect to spend $150 million on this project, which also includes enhancements to our existing refined products pipeline system to accommodate the increased volumes to this market. We are very excited about this project, which will provide the Little Rock market with more refined product supply options.
Through this extension, shippers will, for the first time, have access to supplies from refiners in the Mid-Continent. Our system will also provide access to Gulf Coast refiners, so that suppliers of fuel to the Little Rock market will be able to optimize their supply requirements through a single pipeline system.
Subject to regulatory and other approvals, we expect the Little Rock pipeline to be operational in early 2016 and to generate an 8x EBITDA multiple, based on committed volume, with upside potential beyond that. Based on the expansion projects we currently have under construction, we expect to spend $700 million during 2014, with an additional spending of $325 million in 2015 and $75 million in 2016 to complete the projects now in process.
We continue to have a strong balance sheet and do not anticipate the need for any equity issuances to fund our growth for the foreseeable future. We also continue to evaluate well in excess of $500 million worth of potential opportunities that are still in the development phase.
The exact list of opportunities moves around quite a bit, which is the nature of project development, but we continue to see a large number of attractive projects out there, some of them quite large in scale that we continue to develop. And while we continue to see potential growth opportunities in all aspects of our business, the majority of opportunities are still in the crude oil infrastructure space.
We also remain active in evaluating a number of acquisition opportunities that are on the market. We intend to maintain our disciplined approach to acquisitions, especially with the significant number of organic growth opportunities we continue to assess, which generally provide a much more attractive return for our investors.
And that concludes my prepared remarks. So operator, we can now turn it over for questions.
Operator
[Operator Instructions] We'll take our first question from Edward Rowe with Raymond James.
Edward Rowe
We're hearing from a number of producers on earnings calls that there's a growing proportion of crude production coming out of the Permian that's actually condensate. And with BridgeTex being a little bit closer to the New Mexico kind of North area, are you seeing any producers discuss opportunities for you guys to build separate infrastructure for condensate?
Michael N. Mears
We haven't had any discussions with producers at this time to construct anything specifically for condensate. We have seen, for lack of a better term, lightening of the crude that we're seeing on Longhorn.
In fact we just, in the last month or 2, changed the spec, with all of our shippers' consent, on Longhorn to accept lighter crude. But at this point, we are not actively looking at any separate infrastructure in the Permian for condensate removal.
Edward Rowe
Okay. And a couple of more questions.
With the differentials between Midland and Cushing WTI being pretty volatile, how are you guys balancing whether or not to get more long-term commitments versus capturing upside from spot shipments on BridgeTex?
Michael N. Mears
Well, that's an ongoing evaluation. And I can tell you at this point in time, it continues to be ongoing.
We -- given the nature of our business, I think we generally prefer to have commitments versus not having commitments. I mean, volatility is nice in the market, but everybody knows that can change pretty rapidly, and our business model would generally prefer to have commitments.
But that being said, the difference in tariff between a spot tariff and a committed tariff are quite different. And so really, all I can tell you at this point is that evaluation continues.
Edward Rowe
Okay. And lastly, in terms of the product margins and the refined products space, I guess butane blendings, when we were looking at spot margins, we didn't really see any blowout in spreads.
And at the same time, using kind of a seasonal spread analysis, we saw some marginal improvement. Can you share with us any more details on how the uplift from butane blending attributed to the upside to margins in the space?
Michael N. Mears
Well, I think, I mean there's really 3 components to that. One is, we saw continued strong gasoline prices in the Mid-Continent through the first quarter.
Secondly, butane prices have been depressed and continue to be depressed, likely due to the strong production of butane. I think another significant factor we saw was a, I shouldn't probably use the word collapse, but a significant reduction in the basis differential in the Mid-Continent versus what we've seen perhaps in the past 2 years, particularly in the winter.
So all 3 of those things really contributed to a strong blending environment. I will say even though I don't have any evidence to prove this scientifically, if you look at what we did in the first quarter, I mean, we moved a significant number of barrels south into Texas.
We moved a significant number of barrels out of the Mid-Continent into a third-party pipeline to take to different markets. If you compare that versus a few years ago, we've, in effect, created or debottlenecked, to some extent, the situation that occurs in the winter in the Mid-Continent with regard to gasoline supply.
We think that, that may have had some effect on the basis differential not collapsing or not getting as wide as it historically has and it also gave us more blending opportunities. Last year, we filled up on gasoline in the winter and we actually had to stop blending activities for a period of time because we were full on gasoline.
We didn't have that problem this year. We were able to clear enough barrels out of the system, so that we didn't fill up all of our storage and we were able to blend throughout the first quarter.
Operator
Our next question comes from John Edwards with Credit Suisse.
John D. Edwards - Crédit Suisse AG, Research Division
Just kind of extending Eddie's questions. So you've basically held guidance to what you've -- for the rest of the year, versus what you did before.
And so I'm just curious if what you're seeing in the butane market, you got pretty good margins and so on. And obviously, I understand it is seasonal, but I mean, do you think you're going to have some additional opportunities there and maybe you could talk little bit about that versus why not push the guidance up a little higher, I guess?
Michael N. Mears
Well, I guess the short answer to that is, we saw a very strong quarter. And we prefer to give conservative guidance versus aggressive guidance.
And so as we looked at that, we -- there were some timing issues with regards to sales we did in the first quarter that benefited the first quarter that when we look at margins into the fourth quarter, we expect those margins to be strong enough to offset the timing differences with regard to increased first quarter sales. So that really allowed -- the benefit there really allowed us to feel comfortable keeping all of the gains in the first quarter from blending in the forecast.
But beyond that, we just would prefer, at this point in time, to not provide an aggressive forecast. I would agree that there is certainly some potential upside with regards to blending margins.
However, given our history and our preference for a conservative forecast, we've chosen not to model that into our forecast at this point.
John D. Edwards - Crédit Suisse AG, Research Division
Okay, that's helpful. And then on your expansion projects, at Analyst Day, you gave us a slide where it showed a 20% pipeline expansion, 60% crude, 10% refined storage, 10% terminal expansions.
What's the breakout now, with the Little Rock project now going from potential expansion to actual expansion?
Michael N. Mears
Hold on a second. I'm trying to get that information.
The chart I'm looking at now, all -- why don't you answer the question, Paula, I'm going to read the chart [ph].
Paula Farrell
Okay. John, that component, at this point in time, is really closer to 5% versus the 20%, now that Little Rock has come out of it.
John D. Edwards - Crédit Suisse AG, Research Division
Okay. And then the rest of the percentages are?
Well, basically, just Little Rock came out, and then that component becomes 5% and then the other, not a lot of change in the other expansion potentials?
Paula Farrell
That's right.
Operator
Our next question comes from Norman Kramer with Kramer Investments.
Norman Kramer
I too had a question about the butane blending. Do you have -- could you give us some color?
Do you have some type of a longer-term outlook on the potential for butane-blending profits remaining such a significant piece going into the future, say, in the 3- to 5-year term, now that we seem to be seeing more producers and shippers talking about butane export? Do you have any thoughts on that?
Michael N. Mears
Well, I mean, first, I'd say we're probably not the best experts on forecasting commodity prices. But certainly, to the extent that you have significant butane exports that that's going to have a positive effect on butane prices and have a negative effect on margins.
However, our view is, if you look at the next 3 to 5 years, that we would expect blending margins to be, I mean, set aside the first quarter of this year as kind of an exceptional period for a second. But if you just look at the last 2 to 3 years, I mean, our expectations are those blending margins are going to remain strong, maybe a little bit less aggressive than what we've seen with the potential for butane prices to come up, and also for the potential for gasoline prices to come down.
Now if you look at the forward curves on crude oil, they would suggest you -- if you can believe a forward curve, that prices of crude oil and gasoline will be lower in the future than they are today. And so therefore, you would expect some tightening of that margin.
And so I mean, we wouldn't be surprised to see those margins not nearly as strong over the next couple of years. But I wouldn't characterize it as a collapse in the margin.
I mean, I think we're talking relatively small percentages in drops in the margin. And offsetting that, we've been continuing to improve the amount or increase the amount we've been able to blend, the efficiency of our blending that should offset some of that, if it were to occur.
Of course, those were just based on forward curves. But we wouldn't be surprised to see slightly lower margins in the future than what we've seen the past couple of years.
Norman Kramer
Okay. And I had one other question, too.
At the Analyst Meeting, you had talked about the possibility of building a second splitter at Corpus Christi and that you had sufficient room to do so, and do you have any update on that? Has there been any discussions, is there any near-term potential there?
Michael N. Mears
We don't have an update. I mean, we are in discussions, but we don't have an update beyond that.
Operator
Our next question comes from Steve Sherowski with Goldman Sachs.
Steven C. Sherowski - Goldman Sachs Group Inc., Research Division
Not to beat a dead horse on this butane-blending topic, but in your internal models, what type of butane exports do you assume just over the next couple of years? How do you see the growth trajectory?
Michael N. Mears
Well, we -- I mean, we don't model it down to that level. I mean, really, when we're looking at our 3-year forecast, which is really all we go out when we're doing forecasting, and we look at those margins, we're really looking at -- we are using the forward curve.
We're using a NYMEX crude curve or a gasoline curve with an assumed basis differential back to the group, and then a Belvieu butane curve. And so we're more or less relying on the market, in those forward curves, to make those estimations for us with regards to what they think the pricing will be.
Steven C. Sherowski - Goldman Sachs Group Inc., Research Division
Okay. And if I could just have a quick follow-up.
What are you seeing in the M&A market right now? How would you just characterize it?
And what type of deals are you being presented with? Are they more on the crude side or the products side or somewhere else?
Michael N. Mears
Well, I'd say there is a number of things that are in the market and they are across the board. There are crude assets, there is products assets, there's NGL assets and there's a wide range of things out there, varying from 100% fee-based, all the way up to assets that have quite a bit of commodity risk.
I would also say right now that from what we're seeing and what you guys can probably see on the announced deals, we think the multiples are still pretty high, and which is probably one of the main reasons why you haven't seen us transact anything recently. A number of the assets that are on the market we're interested in.
It's just we're not willing to pay the high multiples.
Operator
[Operator Instructions] Next question comes from Brian Zarahn with Barclays.
Brian J. Zarahn - Barclays Capital, Research Division
On the Little Rock project, can you talk a little bit about the contract you have with Spectra in terms of its length and sort of what needs to be done on their end to have the pipe ready for you in 2016?
Michael N. Mears
Well, the length of the contract, I'll just tell you, it's a very long-term contract. It's -- I'll probably just leave it at that.
It's long enough for us to be comfortable making the investments to connect it to our system. Obviously it is a natural gas line, inspector needs to go through the abandonment process, which they've initiated.
And then with regards to the actual work that needs to be done on the pipe, it's rather standard stuff, replacing some valves and that sort of thing. If I'm not mistaken, this line at one point in its former life was a -- oh, I was incorrect, I was thinking of a different system.
This line, it will require a, like I said, just some valves and some pump stations. And, but other than that, that the work is pretty routine on the pipe itself.
Brian J. Zarahn - Barclays Capital, Research Division
Okay. And then on the -- just to confirm the identified project, CapEx is now $1.1 billion with the addition of the Little Rock project?
Michael N. Mears
That's correct.
Brian J. Zarahn - Barclays Capital, Research Division
Okay. I know you commented on the other splitter that's potentially under evaluation, any just general updates on the other projects that you're looking at?
Michael N. Mears
Well, I don't -- we don't have any updates really on anything to announce at this point. Again, we've got a significant number of projects we're developing.
As I've mentioned in my notes, some of those are quite sizable and they're advancing, but we don't have any updates on anything specifically right now.
Brian J. Zarahn - Barclays Capital, Research Division
And last one for me. What was the expansion CapEx in the first quarter?
Michael N. Mears
Hold on a second.
Paula Farrell
$184 million.
Operator
[Operator Instructions] We'll take our next question from Elvira Scotto with RBC Capital Markets.
Elvira Scotto - RBC Capital Markets, LLC, Research Division
Just one question for me. If the rest of the year shakes out sort of better than expectations, how do you balance between sort of what you think you can pay out in the form of distribution versus what you will retain to reinvest?
Michael N. Mears
Well, it seems to be the hot topic of the past month, we've been asked that question quite a bit. At this point in time, we're sticking with the 20% growth guidance for this year, distribution growth of 15% for next year.
Clearly, if the excess cash reaches a high enough level, we would need to revisit that. That doesn't necessarily mean we would change that guidance.
The benefits of increasing short-term distribution growth versus long-term stability, I think, is one that we're in the process of reevaluating what's the right view on that. So I don't have an answer for you on that question, other than just to reaffirm what our current guidance is.
Elvira Scotto - RBC Capital Markets, LLC, Research Division
Okay, great. And then on the -- actually, I do have one other question.
On that backlog of projects, that over $500 million. I mean, these are projects, you said primarily crude, still within sort of that, you're looking at projects that would give you that typical 6x to 8x EBITDA return?
Michael N. Mears
That's correct.
Operator
We'll take our next question from Steve Tabb with Tocqueville Asset Management.
Stephen Tabb - Tocqueville Asset Management LP
This is more of a generalized question. I read and hear so much about the Permian Basin and how many additional rigs and how many additional wells they're drilling.
And my little understanding, most of those wells are comparatively long-lived wells. So overall, what is your view toward your ability to expand your investments in that area?
Michael N. Mears
Well, I think, I mean, first of all, if you look at the long-haul pipeline takeaway capacity from the Permian. It's our view, at least at this point in time, based on the current production forecasts that if -- or I should say, when all of the pipelines that are being built that have been announced are actually completed that there will be adequate takeaway capacity from the Permian Basin to match the production growth.
So at this point in time, we're not envisioning any additional long-haul takeaway capacity from the Gulf. We are, however, looking at opportunities to expand our reach on the origin ends of our pipelines in the Permian Basin and also to expand our capabilities at the destination end, in the market for connectivity to refineries and storage in those markets.
Stephen Tabb - Tocqueville Asset Management LP
All right. Now I have an altogether different question.
You say, you mentioned that through your budgeting and planning, mostly on a 3-year basis, but your pipelines and your other investments are meant to last and are lasting a lot longer. Do you review any of your -- or do you review your fixed property investments for a possibly faster write-offs or impairments at all?
To what extent is that examined each year?
Michael N. Mears
Well, I mean, first of all, to make it clear, I mean, you're right, we do have long-lived assets. When I mentioned we have a 3-year planning cycle, I mean that's really a process of determining what our cash flow expectations over the next 3 years are.
When we are making investment decisions, we clearly look at the life of the asset in our investment decisions to determine whether or not those are good investments. With regards to impairment analysis, we do, do that and it's a process that takes place on a routine basis.
It's a process that takes place, in some cases, on an ad hoc basis if something materially has changed in the cash flow of a particular asset. So yes, that is a process that we engage in pretty regularly.
Stephen Tabb - Tocqueville Asset Management LP
Have there been any impairment charges at all over the last few years?
Michael N. Mears
Nothing material.
Operator
[Operator Instructions] We'll take our next question from Ross Payne with Wells Fargo.
Stanley Ross Payne - Wells Fargo Securities, LLC, Research Division
Yes. I was just wondering if I could get a little more specific debt number from the 2.9.
I just wanted to kind of finalize my model.
Michael P. Osborne
Ross, what's -- I'm not sure I understand the question.
Stanley Ross Payne - Wells Fargo Securities, LLC, Research Division
Can you give us a little more specific debt number. I'm sure it's rounded to 2.9, but I'm just curious what -- do you have an exact number?
Michael P. Osborne
Okay, yes. 2.94 would be what you'll see on the balance sheet.
But in terms of the actual maturity number, it is 2.9.
Operator
Our next question comes from Sharon Lui with Wells Fargo.
Sharon Lui - Wells Fargo Securities, LLC, Research Division
Just a follow-up question on the Little Rock project. Given that you have a contract with Spectra, what's the potential return for that project?
Michael N. Mears
What we've stated is it's an 8x multiple on the committed volumes. I will mention, though -- we're not going to disclose the committed volumes, but we will say they're significantly less than the market and they're also significantly less than the capacity of the pipeline.
So there is upside to that 8x multiple. The 8x is based just on the committed amount.
Sharon Lui - Wells Fargo Securities, LLC, Research Division
Okay. And in terms of the current volumes flowing on that pipe, is there a risk in terms of the FERC abandonment process?
Michael N. Mears
Well, that's a question probably better oriented to Spectra. But it's -- they have initiated the process and they -- I think, it's fair to say that they characterized the risk as very, very low, that they won't have a successful abandonment.
Sharon Lui - Wells Fargo Securities, LLC, Research Division
Okay. And typically, when would they receive a decision from FERC?
Is it a 12- to 18-month process or...
Michael N. Mears
It's our understanding, at least on this piece of pipe, it's an 8- to 12-month process.
Operator
[Operator Instructions] It appears we have no further questions in queue. At this time, I'd like to turn the conference back over to Mr.
Mears for any closing or additional remarks.
Michael N. Mears
All right, well, thank you for your time today. We are off to a great start in 2014, and we stay focused on seeking additional growth opportunities.
So we appreciate your continued interest and have a great day.
Operator
Thank you. That does conclude today's conference.
Thank you for your participation.