May 2, 2013
Executives
Michael N. Mears - Chairman of Magellan GP LLC, Chief Executive Officer of Magellan GP LLC, President of Magellan GP LLC and Chief Operating Officer of Magellan Gp LLC John D.
Chandler - Chief Financial Officer of Magellan Gp Llc, Principal Accounting Office of Magellan Gp Llc, Senior Vice President of Magellan Gp Llc and Treasurer of Magellan Gp Llc
Analysts
Edward Rowe Brian J. Zarahn - Barclays Capital, Research Division Steven C.
Sherowski - Goldman Sachs Group Inc., Research Division Sharon Lui - Wells Fargo Securities, LLC, Research Division John Edwards - Crédit Suisse AG, Research Division James Jampel Connie Hsu - Morningstar Inc., Research Division Norman Kramer John K. Tysseland - Citigroup Inc, Research Division Elvira Scotto - RBC Capital Markets, LLC, Research Division Ketul Sakhpara - TPH Asset Management, LLC
Operator
Good day, and welcome to the Magellan Midstream Partners First Quarter 2013 Earnings Results Conference Call. Today's conference is being recorded.
At this time, I'd like to turn the conference over to Mr. Mike Mears, President and Chief Executive Officer.
Please go ahead, sir.
Michael N. Mears
All right, thank you. Good afternoon, and thank you for joining us today to discuss Magellan's first quarter financial results and our outlook for the rest of 2013.
Before we get started, 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 in forming your own opinions about Magellan's future performance. As mentioned in our earnings release this morning, Magellan is off to a solid start to 2013.
Our refined products pipeline performed well during the first quarter, delivering more volumes and generating higher product gains than we initially expected for the period. Further, we continue to make significant progress on our expansion capital projects that I'll discuss shortly.
But for now, I'll hand the call over to our CFO, John Chandler, to discuss our first quarter results in more detail.
John D. Chandler
Thanks, Mike. Before I begin discussing specific business unit performance, I want to mention that I will be commenting on the non-GAAP measure operating margin, which is simply operating profit before G&A expenses and depreciation and amortizations.
A reconciliation of operating margin to operating profit was included in our earnings release this morning. Management believes that investors benefit from this information because it gets to the heart of evaluating the economic success of the partnership's core operations.
As noted in our press release this morning, we reported net income of $113 million this quarter versus net income of $93.5 million in the first quarter of 2012. In all fairness though, the first quarter of 2012 was significantly impacted by out-of-period hedge activity, where the first quarter of 2012 was negatively impacted by $16.3 million of out-of-period losses, while the first quarter of 2013 benefited by $4.9 million from out-of-period hedge gains.
So if you factor out the out-of-period activity, net income between periods was comparable. Details reflecting the out-of-period activity can be found on our distributable cash flow reconciliation to net income, which can be found attached to our earnings release this morning.
Also of note, this is the first quarter that we reported our results in our reorganized reporting segments, which was an effort we undertook, in part, to reflect the increasing importance of crude oil activities to our business. A full history of resegmented quarterly data back to 2009 can be found on an 8-K that we filed with the SEC on March 12.
In addition, on April 30, we filed an 8-K restating certain sections of our 2012 10-K, to reflect both data and business narratives in the new segment format. As is usual, I'll go through the operating margin performance of each of our business lines then discuss variances in depreciation, G&A and interest to come to an overall explanation of the variance in net income.
So first, let's look at operating margin, which was up $30.8 million versus the same period last year, or actually up $9.6 million when you exclude out-of-period hedge activity. On refined product segment saw operating margin increase $34.7 million versus the same period last year, going from $125.4 million to $160.2 million this period.
Out-of-period hedges explain $21.2 million of this variance. Therefore, all other activities for the pipeline segment netted to an aggregate increase of $13.5 million.
Of that, our transportation and terminals revenues were $7.7 million more than the same period last year. This increase can almost entirely be described by increased tariff revenues on our refined products pipeline as a result of higher shipment volumes and higher tariff rates.
Our refined product shipment volumes for the period was 10.7 million barrels or about 13% more than the same period last year. Now a big portion of this increased volume came from our South Texas pipeline system, where volume shipped at a much lower average tariff rate, the tariff is in the $0.20 per barrel range.
In fact, if you break out the South Texas system, where volumes increased 7.6 million barrels, that leaves a 3.1 million barrel or 4% volume increase on the remainder of our systems. The South Texas pipeline system increased, in large part, due to the initiation of a volume incentive program in September 2012.
If you exclude the South Texas volumes, gasoline volumes increased 3% and distillate volumes increased 7% on the remainder of our systems. Distillate demand has been strong in West Texas, with the abundance of drilling activity; while gasoline demand has been strong, in part, due to having lower gasoline inventories coming into the first quarter of 2013 versus the first quarter of 2012, and also due to a project completed last year that allows us to periodically reverse a segment of our refined products pipeline between Southern Oklahoma and Dallas, Texas.
With the flexibility to reverse our system and the additional pipeline storage capacity that our reversal brought to our shippers, Mid-Continent refiners were able to keep their production and shipments higher. That is important because weak gasoline demand has traditionally been an issue for refiners in the first quarter due to the reduced driving activity during this part of the year.
On the tariff side, refined products tariff rates for the period went from $1.197 per barrel last year to $1.136 per barrel this year or a 5% decrease. As mentioned with the volumes, we shipped significantly more volume on our South Texas system, which ships at a more lower average tariff rate, again, around $0.20 per barrel.
Therefore, if you factor that system out, the tariffs on the remainder of our pipeline systems increased to $1.34 per barrel versus $1.32 per barrel last year or an approximate 2% increase in tariff rates. Obviously, a major contributor to this variance is the fact the we raised rates on July 1, 2012, in all of our markets by approximately 8.6%, with those increases offset somewhat by both short-haul tariffs, as Mid-Continent refiners maintained high creek runs during the first quarter of 2013, resulting in shorter haul shipments, as well as growth in inventory on our pipeline system during first quarter of 2013.
And when that happens, that tends to reduce our tariff rates. Product margins from our commodity-related activities for the refined product segment increased $16.1 million versus the first quarter of 2012, going from $25 million last year to $41.1 million this quarter.
Again, these results are heavily impacted by out-of-period hedge losses in the first quarter of 2012 and out-of-period hedge gains in the first quarter of 2013. If you factor these out, again, they -- representing about $21.2 million of these variance, our operating margin for commodity-related activities actually decreased by $5.1 million versus the same period last year.
You can arrive at this number by taking the product margin from our operating margin reconciliation sheet attached to our earnings release this morning and make the adjustments identified as commodity-related adjustments on the DCF Reconciliation page. Lower butane blending profits explained most of this variance, where we saw both lower margins and lower volumes versus the same period last year.
Volumes were down largely due to timing, as storage in our pipeline system this year allowed us to carry more barrels in the second quarter than last year, with the second quarter typically providing higher gasoline prices. Margins were down somewhat due to reduced gasoline prices versus the same period last year.
This is for our refined product segment. We're $10.9 million less than the same period last year.
The decrease in expense is primarily due to more favorable product gains, due to the benefit of inventory reevaluation given the increased commodity prices this quarter versus year-end prices, and higher net barrels gained on the pipeline this quarter, which can be attributed in part to more barrels moving through our pipeline systems. And to a lesser extent, our reduced expenses can be explained by lower environmental accruals where, during the first quarter of 2012, we had a larger environment accrual related to a pipe flange leak that occurred at one of our terminals in Minnesota.
Now going to our crude oil segment. Operating margin for the crude oil segment was down $1.3 million or about 5% versus the same quarter last year, with higher revenues being more than offset by higher expenses.
Transportation and terminals revenues for the crude oil segment were $2 million more than the same period last year, with the majority of that increase coming from incremental tariff revenues on our Houston area crude oil distribution system and additional revenues from leasing once idled or underutilized components of our refined products pipeline systems in crude service now. Transportation volumes increased 1 million barrels or about 7% while tariffs increased 13%.
Our crude oil average storage utilization only slightly increased between periods, due primarily to the reactivation of some idle tankage at our Cushing terminal. On the terminal expenses, they were $6 million more than the same period last year, in part, due to lower pipeline loss allowance gains and higher integrity work.
The lower loss allowance gains were a result of lower throughput activity at our Cushing terminal, from which we're allowed to collect a loss allowance, as well as a change in our tariff structure on our Houston area distribution system that reduced the amount of loss allowance we collect as part of the tariff. Integrity expenses increased, in part, due to tank work at Cushing, which was planned and part of the normal maintenance cycles for these tanks.
And finally, affiliate management revenue increased $3 million dollars for the crude segment due to fees being collected for construction management on BridgeTex, as well as management fees earned from our operation of the Osage pipeline JV. Now going to marine storage.
Our operating margin for marine storage segment was down by $2.6 million or about 9% versus the same quarter last year, primarily due to an increase in operating expenses and lower product margins. Transportation and terminals revenues for the terminal segment were essentially unchanged between periods, with new tankage at higher average rates, offsetting storage tanks taken out of service for maintenance.
For the period, our average lease storage utilization declined 1.4 million barrels for the quarter, going from 24.1 million barrels per month leased for the first quarter of 2012 to 22.7 million barrels leased for this quarter. Of this change, we had about 0.5 million barrels of new storage come online during the quarter, mostly at Galena Park, Texas, offset by 1.6 million barrels of tankage taken out of service for maintenance, and about 300,000 barrels of tankage going on lease, mostly from our Wilmington, Delaware terminal.
Net product margins for the marine storage segment was $1.9 million less than the same period last year, largely due to timing on transmix sales at our Galena Park terminal and a catch-up accrual in the current period for historical measurement losses at Galena Park. In terminal expenses, we're $1.7 million more than the same period last year, largely due to an insurance reimbursement of about $2 million received in the first quarter of 2012 related to historical hurricane damage that served to reduce expenses in the 2012 period.
Finally, affiliate management fee revenues, as well as equity earnings, are up for the marine terminal segment due to our Texas Frontera tankage JV at our Galena Park terminal. Therefore, in summary, those are the reasons operating margin for the quarter increased $30.8 million going from $178.1 million last year to $208.9 million this quarter.
Now stepping down to net income. Depreciation was up $4.8 million due to capital additions, as well as a catch-up entry for contract amortizations related to our South Cushing acquisition -- tankage acquisition in 2011.
G&A expenses, the G&A expenses were up $6.3 million due in part to higher equity-based incentive compensation accruals resulting from strong financial results for Magellan, and incremental costs for equity awards and deferred director equity compensation given our growing unit price. In addition, G&A costs are up, in part, related to incremental costs associated with construction management services provided to some of our JV arrangements, as well as additional personnel costs related to our growth projects.
And interest expense, net of interest income and capital interest, was essentially unchanged, with the cost of additional borrowings outstanding being offset by more capitalized interest associated with our numerous growth capital projects. During the first quarter of 2013, we had about $240 million in additional average borrowings outstanding versus the first quarter of 2012, resulting from the fact that in November 2012, we've proactively issued $250 million in debt to take advantage of the low rate environment and pre-fund future expansion capital.
As of the end of the first quarter of 2013, we still have $221 million in cash on our balance sheet and had no borrowings outstanding on our revolver. Furthermore, all of our interest is currently at fixed rates, at an average realized rate of about 5.3%, including hedges, with no debt swapped to floating.
Therefore, in total, MMP's net income increased $19.5 million, going from $93.5 million in the first quarter of 2012 to $113 million in the first quarter of 2013. On a final note, our leverage metrics include $2.4 billion in debt outstanding at the end of the first quarter 2013, and then after reducing for cash of $221 million, we have net debt of $2.1 billion, resulting in a net debt-to-EBITDA ratio of about 3x for the last 12 months.
And it would be slightly less than that if you pro forma it for our Longhorn cash flows now that, that reversal is in service. Finally, as of the end of the first quarter of 2013, our $800 million revolver has $0 outstanding.
I'll now turn the call back over to Mike to discuss capital projects and DCF guidance for the remainder of 2013. Mike?
Michael N. Mears
Thanks, John. Looking ahead to the rest of 2013, we have increased our DCF guidance by $10 million to a new annual record of $580 million for 2013.
The new guidance incorporates the favorable items benefiting our first quarter results, as well as higher margin expectations for our butane blending activities, primarily resulting from butane prices that are below historical levels. At this point, we have hedged approximately 20% of the remainder of our projected 2013 blending volumes.
And to be clear, our new DCF guidance does not yet include benefits from our pending pipeline acquisition. Related to our growth construction projects, I am pleased with the progress we are making to bring these assets online safely, on time and on budget.
Specifically related to our Longhorn pipeline project, we began delivering crude oil to the Houston market beginning mid-April, and expect our delivery rate to average approximately 90,000 barrels a day from mid-April through the second quarter, ramping up to its full 225,000-barrel per day capacity in the third quarter of 2013. This capacity ramp up relates to completing additional pump stations in crude oil storage at Crane in East Houston.
As a reminder, the Longhorn pipeline is fully committed, but we have allocated 10% of the capacity for spot shippers, which has been well received by the market. We continue to analyze the opportunity to increase the pipeline capacity to a greater level than 225,000 barrels a day.
While the scope is still being defined for this potential project, we believe we could add another 50,000 barrels per day, increasing the capacity of the Longhorn pipeline up to 275,000 barrels per day for an additional $80 million, based on preliminary estimates. Understanding that speed of execution is imperative, we expect to make a decision on this project within the next few months.
We will provide more details on the timing of this potential expansion once we have further defined the scope and have made the decision to proceed. For now, this project remains in our bucket of potential projects we are assessing, that well exceeds $500 million in total.
We also continue to make progress on our BridgeTex joint venture, which will also deliver Permian crude oil to the Houston market. We still target an operational date of mid-2014, with right-of-way permitting and tank construction activities in full swing at this point.
Our Double Eagle joint venture is currently in the process of filling the condensate pipeline for initial deliveries from Three Rivers to our Corpus Christi terminal, with full operation expected in the third quarter of 2013 once the Western leg from Gordondale becomes operational. Since our last earnings call, we announced an agreement to acquire 800 miles of refined products pipeline, primarily located in Wyoming, Colorado and New Mexico.
These pipelines are a natural extension of our existing refined products distribution system and provide new markets for Magellan to serve. At this point, we are awaiting regulatory approvals, so we cannot say for certain when this acquisition will close.
However, we remain hopeful we can close soon. Based on the growth projects underway, we currently expect to spend $900 million during 2013, with another $320 million spent in 2014 to complete these projects.
The 2013 estimate includes more than $120 million we spent during the first quarter and $190 million for our pending pipeline acquisition. So as you can see, Magellan is generating positive momentum with the performance of our base assets and the progress of our growth projects.
If these favorable business trends continue and our growth projects are placed into service as we currently expect, there is potential upside to the 10% annual distribution growth we have initially targeted for 2013. In fact, you may have noticed in the earnings release that we now indicate a target of at least 10% annual distribution growth for 2013, and we will continue to fine-tune this target as we make more progress on our expansion projects in the coming months.
Further, we also remain committed to our goal of raising 2014 annual distributions by at least 10% over the actual distributions paid in 2013. Operator, that concludes our prepared remarks, so we now can open the call for questions.
Operator
[Operator Instructions] And our first question will come from Edward Rowe with Raymond James.
Edward Rowe
Could you guys provide some thoughts around the competitive landscape in the Permian? In other words, do you believe there's enough pipeline takeaway capacity with Longhorn, and potentially BridgeTex, versus production estimates right now?
Michael N. Mears
Well, I think if you look at the most recent production forecast, and I'm talking forecasts that go out 5 to 8 years, it would suggest that there is not enough takeaway capacity currently, with -- currently, with projects being currently built. So number one, we don't think that the market's overbuilt; and number two, we think that there's the potential for increased takeaway capacity over time.
The situation's not urgent at the moment. This production is forecast to grow over time.
We also expect to see some displacement of crude oil that's currently moving from West Texas to Cushing, which is serving our refineries in the Mid-Continent, to see that displaced or pushed back into West Texas that will also create the need for more capacity to the Gulf. So we think there's upside potential for more capacity.
That's one of the reasons why we're looking at expanding our Longhorn system.
Edward Rowe
Okay, very good. Second question, with the amount of condensate production that's being forecasted out of the Eagle Ford, are you seeing increased opportunities to really leverage your footprint around your terminals and so forth, to provide the producers more access for the takeaway of the condensate?
Michael N. Mears
We are -- we're looking at a number of things in the Eagle Ford. Our primary focus right now is to put Double Eagle into service and to secure additional volumes on Double Eagle.
If you remember, Double Eagle has commitments that are about 50% of the capacity of the pipeline. And now that we are on the verge of putting that line into service, the interest has ramped up for shippers looking for space on that system to get condensate to the Gulf Coast.
So that's our primary focus at the moment.
Edward Rowe
Okay. And last and final question, in terms of the butane, with butane prices falling dramatically, do you see any effects on the RINs on the business with butane blending going forward?
And also in addition, do you see any opportunity to leverage what potentially could be a butane oversupply situation in the market?
Michael N. Mears
Well, certainly, I mean, for the second half of your question, the fact that there's a current and projected growing overhang of butane in the market is a favorable situation for our butane blending business. And that's one of the reasons why we expect strong margins this year, and we haven't really done forecasts beyond that, but it appears to be a long-term favorable trend with regards to the blending business to have an oversupply of butane.
[Technical Difficulty]
Michael N. Mears
I'm not sure why I got cut off, but with regards to RINs, I was mentioning that we are an obligated party with regards to RINs, and so we either have to produce those through blending ethanol or we have to buy those in the open market. We don't blend ethanol and so we acquire RINs.
And as of right now, in 2013, we have acquired all the RINs we need for the year. So we're not exposed to RINs this year.
But obviously, with the trend that RINs are moving in, it's a concern and it would impact, if the trend continues, our margins on blending. We're looking at a number of things to mitigate that.
We typically buy RINs in advance. We're looking at the possibility to do some blending, biodiesel for instance, to produce our own RINs.
We're looking at ways to try to mitigate that expense. But it will be part of the cost of business of doing butane blending going forward.
Operator
And now we'll take our next question from Brian Zarahn from Barclays.
Brian J. Zarahn - Barclays Capital, Research Division
Just looking at the quarter, your both refined product and crude volumes were up year-over-year but they were down quarter-over-quarter. Can you talk about the sequential volume decline?
Was it more refinery outages, or were there some other variables behind that?
Michael N. Mears
Typically, with regards to refined products, the first quarter is seasonally the low period on shipments. Gasoline demand is lower.
Diesel demand is lower, with the -- in the agricultural sector not being a peak period in the first quarter. That's the primary drivers.
There's nothing unique that's happening there other than seasonal differences.
Brian J. Zarahn - Barclays Capital, Research Division
And then on the crude side?
Michael N. Mears
On the crude side, hold on a second here. Let me look at my -- we'll get back to you with an answer on that.
There's nothing that jumps to mind that stands out for any kind of systematic decrease in crude volumes, so we'll get back to you with more details on what's happening there or what happened there in the first quarter.
Brian J. Zarahn - Barclays Capital, Research Division
And then for your outlook...
Michael N. Mears
I should highlight -- I was going to lead into that, on the outlook. Our expectations on our crude oil system and what's -- all you're seeing really in the first quarter in the crude oil volumes is crude oil that we moved through our distribution system in the Houston Ship Channel.
You're not seeing any volume yet there from the Longhorn ramp up, since that didn't start until the second quarter. So if we just talk about the distribution system in Houston, we expect that volume to ramp up going forward.
As more Eagle Ford barrels come into the market, as more barrels come in from our Longhorn System into the market, we expect that the volume on the distribution system to grow over time.
Brian J. Zarahn - Barclays Capital, Research Division
Okay. And then on the crude oil segment, the -- it looks like on the operating expense side, because we have some limited data on a quarterly basis, assumed to be a lot of moving parts.
What's a good way to think about operating expenses as a percent of revenues for that business?
Michael N. Mears
Yes, I think we need to get back to you on that, too. I think -- we don't typically look at operating expenses as a percent of revenue, as a measure that we track.
John D. Chandler
Plus as we move forward, you're going to see a growing, obviously, a growing presence from our Longhorn profitability, the shipments on Longhorn pipeline system, which will change that materially, so I don't think anything we would give you historically, which is largely based around Cushing storage, is going to be meaningful going forward with the large growth in the Longhorn Pipeline system and the volume [indiscernible]
Brian J. Zarahn - Barclays Capital, Research Division
Okay. I was talking about Longhorn.
On the expansion, would that be done through adding additional pump stations? I thought that was -- the 225,000 was the maximum capacity.
Can you talk about how you would increase capacity by 50,000 barrels a day or more?
Michael N. Mears
Well, there's a number of components to doing that. The biggest components are putting -- changing out the pumps at existing pump stations or changing out the pump elements at existing pump stations for higher flow rates.
And then also using drag reducer to increase the throughput on the line. The scope is still being defined.
We may or may not need an additional pump station. That's part of the scope process that's underway.
We do need additional tankage to handle the incremental flow, and there may be some things we need to do with regards to environmental permits, with regards to the pipeline. That's why I mentioned that $80 million number is somewhat loose at this point, because we're still nailing down the scope.
But I will -- one thing I should point out, too, with regards to that expansion is that it is a higher cost expansion on an operating cost basis, too, and it's something to think about when your model this forward. The incremental barrels will have a higher operating cost to move, because we will have higher power costs and we will have drag reducer costs that we don't have today.
But once we have the scope on that finalized, and I should say once we've actually approved proceeding with the project, we'll provide many more details on that.
Brian J. Zarahn - Barclays Capital, Research Division
And last one for me on Longhorn. When -- can you give a little more color as to when in the third quarter you expect the pipe to have full capacity?
Michael N. Mears
Well, that's a number -- I'd like to give you a precise date. It's the nature of any construction project that it's hard to nail down a precise date when there's a lot of moving parts.
I wouldn't say, at this point in time, our expectation is to be late in the third quarter, but we will do our best to get it up and running as fast as we can.
Operator
And next we'll go to Steven Sherowski from Goldman Sachs.
Steven C. Sherowski - Goldman Sachs Group Inc., Research Division
On a potential Longhorn expansion, I realize you haven't decided whether or not you're going to go through on this, but how long do you think it would take to add that capacity if you do decide to go through with this project?
Michael N. Mears
Well, a lot of that depends on the scope. I mean, for instance, do we need to put in an additional pump or not?
But I think the fact that we need to build additional storage in order to accommodate the increased throughput, typically, that's a 12- to 18-month type of construction period for new storage. So I think once we make the decision to go, that's the timeframe we'd be looking at.
Steven C. Sherowski - Goldman Sachs Group Inc., Research Division
Okay. And I may have missed this before, but the $200 million delta between your 2013 CapEx guidance this quarter versus last quarter, what's the difference there or projects rather?
Michael N. Mears
The biggest piece of that is the acquisition, the refined products assets from Plains.
Steven C. Sherowski - Goldman Sachs Group Inc., Research Division
Okay. And what is the multiple on that acquisition?
Michael N. Mears
We haven't given a multiple on the acquisition. All we've stated is that it's going to be immediately accretive, but we haven't quoted a multiple.
Steven C. Sherowski - Goldman Sachs Group Inc., Research Division
Okay. And I know one of your competitors had mentioned a potential -- couple of new build pipelines that would compete with the pipelines that you're planning to acquire.
Would you mind just talking about that? I mean, are those realistic threats or do you see these pipelines being built?
Or is there a need for these pipelines to be built?
Michael N. Mears
Well, I think we're aware of who you're referring to. And clearly, when another party publicly talks about building a pipeline, it's something we want to pay attention to.
It would be our intent to serve that customer to the best of our ability after we acquired these assets, such that another pipeline wouldn't be necessary. That's something that we'll have to continue to manage going forward.
Obviously, we can't do anything about that at this point, since we haven't closed on the assets. But once we do, that would obviously be a key focus of ours.
Operator
Our next question will come from Sharon Lui from Wells Fargo.
Sharon Lui - Wells Fargo Securities, LLC, Research Division
Just wondering if you have any early indications of whether the uncommitted capacity in Longhorn would be filled and whether this would be, I guess, a main driver for your decision to increase the distribution above that 10% target?
Michael N. Mears
Well, to the first part of your question, we -- the commitments on Longhorn were significantly in excess of the 225,000 barrel a day capacity. The uncommitted shipments, at this point, are really just the 10% that we've reserved for spot shippers.
And the way that works is we make it available for spot shippers. If spot shippers don't dominate into that space, then it just reverts back to the committed shippers.
And so we're certain the pipeline will be full at all times at this point. Now I will say that in the initial stages of start up, we've made that 10% available for spot shippers and the demand has been overwhelming to access that uncommitted space.
So that's one of the drivers behind our interest to expand. I think that it's important to realize and to reemphasize that, again, our commitments are far in excess of our capacity and in fact, our commitments are in excess of our potential expanded capacity.
So we don't view, at least during the term of those contracts, that there's any risk with regards to the expansion. Beyond the life of those contracts, again, going back to the first question earlier, we project the need for capacity and the need for potentially incremental capacity out of the Permian is going to grow.
And so we have a high level of confidence that even after the expiration of the contracts, the demand for those -- that movement is going to be there.
Sharon Lui - Wells Fargo Securities, LLC, Research Division
Okay. And just to remind us, the 3x EBITDA multiple, that's just assuming based on the commitments, is that correct?
Michael N. Mears
That is -- well, that's assuming the pipeline is full at the committed contract tariffs.
Sharon Lui - Wells Fargo Securities, LLC, Research Division
Okay. So I guess talking about the potential increase in your distribution above that 10% range, are you still looking for, I guess, excess coverage of that $75 million?
Or do you think you're going to be in excess of that number this year?
Michael N. Mears
Well, we'll make that determination when we decide what we're going to do with the distribution. I will tell you that the fundamentals of us building up to that $75 million excess cash level haven't changed.
And whether or not that's the exact amount that we will target for this year is yet to be discussed. But I think if you do the math on our current DCF forecast and what our distributions are, you can see that there's some room between a 10% growth rate and that $75 million level.
I'm not saying that we'll take it all the way down to $75 million, but I think that should give you some boundaries as to what we would be evaluating as we go forward. And again, I want to reemphasize that all of that is dependent upon the execution on our growth projects.
I think generically, that's true, but in this case, it's even more true for us, because the Longhorn ramp up is such a significant project with regards our cash flow projections for the year that our ability to go above 10% is very dependent on the success of the timing of our expansion. I shouldn't say, our expansion, but the timing of coming to the full 225,000 barrels a day.
Sharon Lui - Wells Fargo Securities, LLC, Research Division
So it sounds like the, I guess, the decision in terms of the distribution growth rate might be made in the fourth quarter when that ramp up is completed?
Michael N. Mears
Well, clearly, we haven't decided when we will do it. I don't -- that's not necessarily true, though.
I mean, I think as we get closer to the third quarter, or we get through the end of the second quarter, we're going to have more information on the progress on the expansion. And we're not necessarily saying that the full 225,000 barrels a day has to be in service and performing before we make that decision, but we certainly have to have a much higher level of comfort that it's going to stay on schedule before we make that decision.
So that could happen at any time between now and the fourth quarter.
Sharon Lui - Wells Fargo Securities, LLC, Research Division
Okay, that's helpful. And I guess going back to the pending pipeline acquisition from Plains, maybe if you could just talk about whether, I guess, the main merit is market diversification or do you actually anticipate potential synergies with your existing assets or some organic growth opportunities tied to those assets?
Michael N. Mears
Well, if you look at that acquisition, the way -- if nothing changes with regards to movements on that system -- on those systems, that's the basis for us stating that it's immediately accretive. So we don't need to drive incremental barrels through that system, or we do not need to implement organic projects on those systems in order for it to be accretive.
Now that's not to say that, that won't be our goal. I mean, clearly, we're interested in driving more business through those assets, and perhaps driving longer-haul barrels through our system, our existing system, to serve those markets that don't serve those markets today, and so those are all upsides.
In addition to that, there are organic projects that we'll be pursuing after the acquisition also.
Operator
And next, we will take John Edwards from Credit Suisse.
John Edwards - Crédit Suisse AG, Research Division
Could you just talk a little bit -- okay, a couple of questions about the expansion. On the 50,000 expansion, you mentioned that there were spot shipments that are going to be -- or I guess there was subscriptions much higher than the 225,000.
So are you looking at something further, a higher level of barrel capacity in the future, beyond this 50,000?
Michael N. Mears
No, we're not. I mean, not because we don't think there may not be demand for it, but once we get to 275,000, we really have maxed out the hydraulic capacity of the pipe.
So we wouldn't be looking at a second expansion of Longhorn beyond 275,000.
John Edwards - Crédit Suisse AG, Research Division
Okay, all right. And then with that 275,000, would you also be looking at reserving at that level, around 10%, for spot?
Michael N. Mears
Yes.
John Edwards - Crédit Suisse AG, Research Division
Okay. And then could you remind us, on the tariff, what you're able to charge on spot shipments, is it about -- is it higher than what you can charge on the committed shipments?
Michael N. Mears
It is higher than what we'd charge on the committed shipments, and this is an approximate number. But out spot tariff is right around $3.50 a barrel, and that's quite a bit higher than our committed tariffs.
John Edwards - Crédit Suisse AG, Research Division
Okay. So with the expansion, would you be looking to -- is it possible that you would have that as being a greater level than the 10% spot, or just in all, at the 275,000, you'd still have about 10% spot shipments?
Michael N. Mears
We would expect have 10% spot shipments at 275,000.
John Edwards - Crédit Suisse AG, Research Division
Okay. And then just to clarify, so the $900 million CapEx, that does -- for 2013, that does include the acquisition, correct?
Michael N. Mears
That's correct, that's correct.
John Edwards - Crédit Suisse AG, Research Division
Okay. And then just remind us again, when does that close or when is it expected to close?
Michael N. Mears
Well, we're in the filing period with the FTC on it as we speak. And as soon as we can get through that process, we should be able to close very quickly at the completion of that process.
And unfortunately, I can't give you any more details on the timing of the completion of the FTC process. That's, quite frankly, what we're waiting for.
John Edwards - Crédit Suisse AG, Research Division
Would a reasonable assumption be by the end of the second quarter that you should be through that? Is that reasonable, just for modeling purposes?
Michael N. Mears
I hate to give a projection like that when it's completely outside of our control. So I hesitate to give any prediction on the completion of that process.
Operator
Our next question will come from James Jampel with HITE.
James Jampel
Most of my questions have been answered. If you could just address what you saw in the refined products system that you're purchasing from Plains.
What can you guys do with that system that Plains could not?
Michael N. Mears
Well, I think if you look at a map of that system, you can see that those pipes are situated at the end of long-haul pipes on our system. So I mean, just to give you an example of something that we can do.
If you look at Albuquerque market right now, we have a pipeline that runs from Houston to El Paso. The system we're buying runs from El Paso to Albuquerque.
To the extent that we can create a more competitive market in Albuquerque for a Houston-sourced barrel, then that generates a long-haul shipment on our system to get to the Albuquerque market. So we've essentially converted a short-haul shipment into a long-haul shipment, which is a significant financial upside to having those 2 systems operate together.
So I mean, that's a simple example of where you can essentially acquire a system that extends your system and create more long-haul movements, at the same time, you're making the market more competitive.
James Jampel
Do you guys connect to the Rocky Mountain system?
Michael N. Mears
We don't today, but it's very close to us. We have a line that runs into Denver, and those systems are not physically connected today, but they could be.
James Jampel
Do you have any estimate of synergies or extra revenue that the combination could bring on?
Michael N. Mears
We haven't provided any of that publicly, no.
Operator
And we'll now take Connie Hsu from Morningstar as our next question.
Connie Hsu - Morningstar Inc., Research Division
Most of my questions have been answered as well, but just one quick balance sheet question. With the acquisition cost of $190 million, the additional funding in addition to the remaining growth spending for the year, are you still planning to finance all this through cash and debt with no equity issues for the year?
John D. Chandler
Yes, we still have -- first of all, again, we ended the quarter with $220 million in cash and, yes, we still have significant capacity to do debt financing this year beyond the amounts we're even talking about here.
Connie Hsu - Morningstar Inc., Research Division
Okay, great. And have you disclosed the capacity on the 2 pipeline systems that will be acquired from Plains?
Michael N. Mears
We haven't disclosed the capacity on the systems. They're 8-inch and 6-inch pipeline systems, so that should give you a range of what their capacities are, but I don't have those off the top of my head.
Operator
And we'll now go to Norman Kramer with Kramer Investments.
Norman Kramer
One of your competitors announced on their call that they were looking into or planning to build a butane export facility. And I was wondering how that -- if that comes to be, how that might impact your blending business.
Michael N. Mears
Well, without knowing the specifics of what that proposed project is -- I mean, what I would tell you generically is that anything that causes butane prices to be depressed is favorable for the business, and anything causes butane prices to increase is unfavorable for the business, and that's just a generic statement. Clearly, if there was large-scale export capabilities for butane, that, that would be -- put a positive angle on butane prices, and that wouldn't be necessarily directionally favorable for the blending business.
I should highlight though that we've been doing the blending business for many, many years through a variety of environments with regards to gasoline pricing and butane pricing, and it's been a very profitable and sustainable business through all of those periods. So I don't think that one should view that the creation of butane exporting capability as having a material negative effect on our blending business.
Operator
John Tysseland from Citi has our next question.
John K. Tysseland - Citigroup Inc, Research Division
I just have a general markets question. As the Longhorn ramps up, do you have a view on how that might impact storage margins in Cushing as barrels start flowing directly to the Coast versus Oklahoma?
Michael N. Mears
Well, our view on Cushing has remained pretty similar through this whole process. The demand for storage in Cushing is not going to go away.
I mean, clearly, redirecting barrels, that potentially could go to Cushing, to the Gulf is directionally the wrong direction for Cushing storage. But on the other hand, you got significant new production coming into Cushing from other sources.
You've got more Canadian barrels coming in, projected to come in, you've got more Mississippi Lime production coming in to Cushing. Cushing is going to continue to be a hub for crude oil storage and distribution for the foreseeable future, and so we don't anticipate, for as far as we can see, deterioration in the storage margins in Cushing.
John K. Tysseland - Citigroup Inc, Research Division
Is there any indication from customers that you can see today, I mean, in terms of the length of contract preference that they have today versus, call it a year or 2 ago?
Michael N. Mears
In Cushing?
John K. Tysseland - Citigroup Inc, Research Division
Yes.
Michael N. Mears
We're somewhat in a unique situation in Cushing, that we're relatively new. And the contracts we have in Cushing have either -- our initial contacts are still in their initial term or contracts have defined renewals that are being exercised.
So we haven't actually been in the market to renew those contracts and we're not actively looking to build any new storage in Cushing. So I can't really comment on the precise state of the market right now, if we were to go out and do that.
My sense is though is it hasn't changed dramatically, that you're still talking the same typical kind of terms with regards to new storage contracts. But I don't have any direct knowledge to support that, since we haven't been actively looking to renew contracts or sign new contracts in Cushing for a little -- for quite some time.
John K. Tysseland - Citigroup Inc, Research Division
That's helpful. And then last question, on the butane blending business, do you actively hold any inventory or do you take advantage of inventories to where you can take advantage of this seasonal aspect of butane prices relative to crude oil and gasoline prices?
Michael N. Mears
Absolutely. We buy a significant portion of our butane at this time of the year, when butane prices are their lowest.
We don't own any butane storage ourselves, but we lease quite a bit of storage around the Mid-Continent and in Houston. I should say, we own some storage in Houston, but for the most part, we lease storage and we physically buy it and hedge gasoline forward in the month we anticipate blending to lock in the margin.
Operator
Our next question will come from Elvira Scotto from RBC Capital Markets.
Elvira Scotto - RBC Capital Markets, LLC, Research Division
On the $500 million backlog of potential projects, is that still primarily crude-related or are these projects now more balanced?
Michael N. Mears
No, they're still primarily crude-related. In fact, we go through that exercise each quarter to kind of calculate that percentage, and about 80% of that backlog is crude oil related.
Elvira Scotto - RBC Capital Markets, LLC, Research Division
Okay. And are you looking at any potential to expand refined products' export capability?
Michael N. Mears
We look at that, yes. That is -- I mean, clearly, I mean, the need to export refined products is projected to grow.
And we are actively -- and we have facilities today to do that. We're actively looking at ways to expand those facilities and grow outside those fence lines to expand those capabilities also.
Elvira Scotto - RBC Capital Markets, LLC, Research Division
Okay, great. And then do you still see any opportunity to repurpose any of your existing assets or pipelines?
Michael N. Mears
There's a handful of smaller projects we're looking at, primarily around Cushing, that would repurpose underutilized or idle products lines, but nothing more significant than that at this point in time.
Operator
And next we'll go to Ketul Sakhpara from TPH Asset Management.
Ketul Sakhpara - TPH Asset Management, LLC
Can you give us an idea about how contracted the 2 pipelines that you're acquiring, how contracted they are, if they are, and what is the average length of the contracts?
Michael N. Mears
You mean on the acquisition of the products lines?
Ketul Sakhpara - TPH Asset Management, LLC
The acquisition, exactly.
Michael N. Mears
Yes. Well, those pipelines are not contracted.
Those pipelines operate similar to our existing refined product pipes and really similar to most refined products pipes that are out there. Those pipelines have been around for quite some time.
They serve specific demand center cities along our routes and it's a demand-driven system. And so most refined product systems in that situation do not have long-term take-or-pay contacts for -- most of them don't have it at all, and when they do, there's a small percentage of the shipments.
So there are none on these assets. They are truly demand-driven refined products pipes.
Ketul Sakhpara - TPH Asset Management, LLC
And the charges that you can charge on that -- on those pipelines, they're also mostly demand-driven or you have a cap and then you charge something below that?
Michael N. Mears
I'm not sure I understand the question.
Ketul Sakhpara - TPH Asset Management, LLC
So the shipping charges for products on those pipelines, are those charges mostly demand-driven or you have a cap on the charges that you can charge and then you charge somewhere between 0 and that cap?
Michael N. Mears
Well, those pipelines are regulated pipelines and typically, regulated pipelines, and these would also fall to that category, are you have stable tariff rates and they're increased each year by an index that the FERC establishes. And so that's the typical process for setting rates on products pipelines.
Operator
And we have no further questions in the queue at this time. I'd like to turn the call back over to Mr.
Mears for any additional or closing remarks.
Michael N. Mears
Well, thank you for your time today. We're pleased with our start to 2013 and even more pleased with the progress on our expansion projects.
We appreciate your interest in Magellan, and we'll talk to you next quarter. Thank you.
Operator
That does conclude our conference for today. Thank you for your participation.
You may now disconnect.