Aug 1, 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
Steven C. Sherowski - Goldman Sachs Group Inc., Research Division Brian J.
Zarahn - Barclays Capital, Research Division Darren Horowitz - Raymond James & Associates, Inc., Research Division Connie Hsu - Morningstar Inc., Research Division John Edwards - Crédit Suisse AG, Research Division James Jampel Louis Shamie Sigi Tang
Operator
Good day, everyone, and welcome to the Magellan Midstream Partners Second Quarter 2013 Earnings Results Conference Call. This call is being recorded.
And at this time, for opening remarks and introductions, I'd like to turn the call over to the President and Chief Executive, Mr. Mike Mears.
Please go ahead, sir.
Michael N. Mears
Good afternoon, and thank you for joining us today to discuss Magellan's second 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 and form your own opinions about Magellan's future performance.
As you can tell from our earnings announcement this morning, 2013 is shaping up to be a better year than initially expected for Magellan. Last week, we added more color to our distribution goals, increasing our targets to 16% distribution growth for 2013 and 15% distribution growth for 2014.
The increased 2013 distribution guidance is attributable to strong financial results so far this year, as well as improved DCF expectations for the full year of 2013. Further, progress on the development of our significant expansion capital projects has provided us enough confidence in our future cash flow growth to also raise our 2014 distribution guidance.
I'll hand the call over to our CFO, John Chandler, to discuss our second quarter results in more detail, then I'll be back to discuss our outlook for the remainder of 2013 and the status of our expansion capital projects.
John D. Chandler
Thanks, Mike. Before I begin discussing specific business unit performance, I do 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 this information, because it gets at the heart of evaluating the economic success of the partnership's core operation.
As noted in our press release this morning, we reported net income of $153.6 million this quarter versus net income of $137.8 million for the second quarter of 2012 or a $15.8 million increase. However, of note, both periods did benefit from significant favorable items.
And if you'd normalize those items out, our net income actually increased more like $25 million versus the second quarter of 2012 instead of the $15.8 million I just mentioned. Specifically, during this quarter, we benefited from a $10.6 million reversal of a previous operating expense accrual for excess emissions dating back to 2008 at our Houston area terminals.
We originally put these accruals on in 2012, when it was believed that the EPA would assess retroactive fees back to 2008 for these excess emissions. The Texas Commission on Environmental Quality, the agency responsible for collecting these fees, recently implemented a rule to collect fees that does not require retroactive collections prior to 2012, and as a result, we reversed this accrual.
The 2012 period benefited from an incremental $19.6 million in mark-to-market impact for out-of-period hedges. Now details reflecting these out-of-period activities can be found on our distributable cash flow reconciliation to net income, which can be found attached to our earnings release this morning.
Now moving on to the segments. Each of our segments produced higher results than the previous period, driven by higher volumes and higher rates on our refined products and crude pipeline systems.
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. This comes to an overall explanation of the variance in net income.
But, first, let's look at operating margin, which was up $27.7 million versus the same period last year. Our refined product segment's operating margin increased $800,000 versus the same period last year, going from $177 million to $177.8 million this period.
This segment's performance, however, was actually quite a bit higher, if you exclude the out-of-period hedge activity, which benefited the second quarter 2012 by $19.6 million. Stepping through our segment.
Our transportation and terminals revenues were $15.1 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 tariff rates.
That's not to say that volumes did not increase. Our refined product shipment volume for the period was 3.2 million barrels or about 3% more than the same period last year.
However, almost this entire increase came from our Texas City refined products pipeline assets. Because we earn only a small tariff on these shipments and it's in an approximately $0.20 per barrel range, this contributed only slightly to our increased revenues.
On the remainder of our systems, diesel shipments increased, but those were offset by lower LPG shipments. And our gasoline shipments between periods were essentially unchanged.
So again, tariff rate increases were the most significant driver of our revenue variance. And to that point, our average tariff rate increased by $0.10 per barrel this quarter or 7.6%, going from a $1.27 per barrel last year to $1.37 per barrel this quarter.
Obviously, a major contributor to this variance is the fact that we raised rates on July 1, 2012 in all of our markets by approximately 8.6%. Now moving to product margins.
Our commodity-related activities for the refined product segment decreased $14 million versus the second quarter of 2012 going from $55.9 million last year to $41.9 million this quarter. Again, these results are heavily impacted by out-of-period hedge gains in the second quarter of 2012.
If you factor out the out-of-period items, again, representing $19.6 million, our operating margin from our commodity-related activities actually increased $5.6 million this quarter versus the same period last year. You can arrive at this number by taking the product margin from our Operating Margin Reconciliation page and make the adjustments identified as commodity-related adjustments on our DCF Reconciliation Page, both of which are attached to our press release this morning.
Generating this $5.6 million additional income were driven by higher butane blending profits, and they explain most of this variance, where we saw significantly higher margins, offset somewhat by slightly lower volumes. Volumes were down largely just due to timing.
Margins were higher due to butane costs that are significantly cheaper relative to gasoline this year, a product we believe about the recent decoupling of butane prices to gasoline, given the significant increases in natural gas liquids production in the United States. Somewhat offsetting the increase in butane profits were lower fractionation profits and the lower Longhorn buy-sell profits, where in the second quarter of 2012, we were still buying, shipping and selling refined products on the Longhorn Pipeline System, which, of course, we no longer do now that, that system is in crude service.
On operating expenses. Our refined product segment expenses were $400,000 more than the same period last year.
The increase in expense was primarily due to higher property taxes and higher power costs, which were mostly offset by the reduction of previous excess emission expense accruals at our East Houston terminal, which totaled $3.6 million. Now again, you may recall, I mentioned that $10.6 million total reversal led to this expense, but that remaining $7 million expense reversal occurred in our marine terminal segment, which I'll talk about more in a moment.
Obviously, both power cost and property tax increases on this pipeline segment are a direct result of the increases of profitability and the increase in shipment volumes we're experiencing in the pipeline segment. Now moving to our crude oil segment.
Our operating margin for the crude oil segment was up $17.7 million or approximately 78% versus the same quarter last year, as Longhorn shipment volumes have been ramping up. Transportation and terminals revenues for the segment was $18.6 million more than the same period last year.
Nearly 80% of this increase can be attributed to the incremental revenues coming from our Longhorn Pipeline System, where the pipeline began shipment services in second quarter of this year. The remaining increases came from incremental terminal revenue at our Corpus Christi, Texas terminal.
Double Eagle condensate volumes have began flowing into our Corpus Christi terminal, and from higher revenues from our Houston area distribution system as volumes increased, in part, due to incremental usage of this Pipeline System by Houston area as refiners running more domestic crude oil. Pipeline shipment volume for this segment increased 10.9 million barrels versus the same period last year.
6.8 million of that increase came from our Longhorn Pipeline System, and 4.1 million of that increase came from our Houston area distribution system. The average tariff realized for our crude oil system increased from $0.30 per barrel in the second quarter of 2012 to $0.77 per barrel in the second quarter of 2013.
This increase in rate is primarily because the growth of the Longhorn shipment volumes, which ship at a much higher average rate than our Houston area distribution system. Quarter-to-quarter, the average realized on Longhorn shipments was $2.19 per barrel versus $0.32 per barrel on our Houston area distribution system.
On our crude segment expenses, they were $2.5 million more than the same period last year, with increases in compensation and other operating costs related to the ramp up of the Longhorn Pipeline System, being offset by higher product gains, which also benefited from the ramp up of the Longhorn Pipeline System. And finally, affiliate management revenue increased $3 million due to fees being collected for construction management on BridgeTex as well as management fees earned form operating the Osage pipeline joint venture.
Now to our marine segment. Our operating margin for the marine storage segment was up $9.1 million or about 38% versus the same quarter last year, significantly, as a result of a decrease in operating expenses as a result of the reduction of previous a excess emission accrual, which benefited this segment by $7 million this quarter.
Terminal revenues were essentially unchanged between periods, with new tankage at higher average rates, offsetting storage taken out of service mainly for maintenance. For the period, our average lease storage utilization declined 1.4 million barrels for the quarter, going from 24.2 million barrels per month leased for the second quarter of 2012 to 22.8 million barrels leased this quarter.
Of this change, we had 900,000 barrels of new storage that came online, mostly at Galena Park, Texas, offset by 1.8 million barrels of tankage taken out of service for maintenance and 500,000 barrels of storage going unleased mostly from our Wilmington, Delaware terminal. Net product margin for the marine storage segment was about 500,000 more than the same period last year, largely due to the timing on transmix sales at our Galena Park terminal.
And our terminal expenses were $7.6 million less of the same period last year, again, largely due to the reduction of previous excess emission accruals at our Galena Park Texas terminal, which contributed $7 million in expense reduction this quarter. And finally, an affiliate management fee revenue as well as equity earnings for the segment are up due to our Texas Frontera joint venture at our Galena Park terminal.
Therefore, in summary, those are the reasons operating margin for the quarter increased $27.7 million. Now stepping down to net income.
Depreciation was up $2.7 million due to capital additions. G&A expenses were up $7.8 million, due in part to higher bonus and equity-based incentive compensation accruals, resulting from strong financial results from Magellan and incremental costs for equity awards and deferred director equity compensation, given our growing unit price.
And also, G&A costs are up, in part, related to the incremental costs associated with construction and management services provided to some of our JV arrangements as well as additional personnel costs related to our growth. Finally, interest expense net of interest income and capitalized interest was essentially unchanged between periods, with the cost of additional borrowings outstanding being offset by more capitalized interest associated with our numerous growth capital projects.
During the second quarter of 2013, we had $250 million in additional average borrowings outstanding, resulting from the fact that in November 2012, we 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 second quarter, we still have $119 million in cash on the balance sheet and have no borrowings outstanding on the revolver.
Furthermore, all of our interest is currently fixed at an average realized rate of 5.3%, including hedges, with no debt that is swapped to floating. Therefore, in total, MMP's net income increased $15.8 million going from $137.8 million for the second quarter of 2012 to $153.6 million this quarter.
Our leverage metrics include $2.4 billion of debt outstanding at the end of the second quarter of this year. And after reducing for cash of $119 million, we have net debt of $2.2 billion, resulting in a net debt to EBITDA ratio of about 3x for the last 12 months.
And, obviously, it would be slightly less if you pro forma in the Longhorn cash flow now that, that pipe is in service, which were allowed to do under our credit facilities. And, finally, as of the end of the second quarter of 2013, again, our $800 million revolver has 0 borrowings outstanding.
As a final note, we are happy to say that S&P affirmed our strong credit metrics yesterday by taking us up off a positive review and increasing our corporate rating to BBB+. We remain on a positive outlook with Moody's.
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 $50 million to a new annual record of $630 million.
This new guidance incorporates favorable items benefiting our results so far this year, as well as higher-margin expectations from our butane blending activities, primarily resulting from butane prices that continue to be well below historical levels. At this point, we have hedged approximately 85% of the remainder of our projected 2013 blending volumes.
So most of that margin should be locked in from a DCF standpoint. Our new 16% annual distribution growth target for 2013 will require close to $495 million to pay cash distributions to our limited partners.
This works out to about a 1.3x distribution coverage for 2013. And to be sure we're all on the same page in how we're thinking about that growth, 16% growth is a true annual calculation over the roughly $1.88 per unit we paid related to 2012, which yields approximately $2.18 per unit targeted for 2013 results.
Right now we're thinking about that payment stream as a $0.025 increase per quarter for the remainder of the year. And I'll mention again that we have also increased our 2014 distribution target to 15% annual growth over the $2.18 targeted for 2013.
We continue to receive a number of questions about renewable identification numbers or RINs, so I'd like to speak to that issue. As a reminder, because of our blending butane activities, we are deemed to be an obligated party under the Renewable Fuel Standard.
Although we blend ethanol for our customers at our terminals for a fee, we do not own or blend ethanol for our own account and thus, don't take title over RINs. So instead, we purchase RINs to meet this obligation in the open market.
100% of our projected 2013 RIN requirements were purchased either last year or earlier this year, so we have no future price exposure for 2013 RINs. Due to the volatility in RIN prices, it is Magellan's policy to buy a future RIN, at the same time we hedge future blending volumes, such that our total margin for hedge volumes is fixed.
As a result, we are now buying RINs for 2014, as we begin to hedge our butane blending activity next year. As you know, RIN costs are much higher than they have been historically, but even with these higher costs, we continue to see very attractive blending margins because of the low butane pricing environment as well as relatively high gasoline prices.
At this point, we have hedged about 25% of our projected 2014 blending volumes. And since the commodity margin environment continues to be strong, I would like to also address our current views on distribution coverage.
We have mentioned in the past that we believe that Magellan should maintain an amount of annual excess cash to provide adequate breathing room for risk factors related to the sustainability of our DCF. Historically, we have mentioned that we felt about $75 million per year was sufficient, primarily, as a safety factor related to commodities.
The determination of an appropriate excess cash coverage is a point-in-time calculation based on current operating environment and the impact that environment may have on our DCF. Given the high blending margins we are currently seeing and the resulting increase in DCF, we believe an excess cash amount of $125 million per year is more appropriate at this time.
We plan to use those excess cash flows to continue to reinvest in the business, and we'll continue to reassess our excess cash flow amount in the future. And as a reminder, although we are benefiting from the current commodity environment, we continue to generate the vast majority of our financial results from our fee-based transportation and terminal activities.
For 2013, we still expect these fee-based activities to comprise around 80% of our operating margin. One of the main factors impacting our future growth is progress we are making on our expansion projects.
To date, I'm very pleased with the strides we have made for each of our key projects, with the projects that have been put into service so far this year, coming on safely and on budget. Related to our Longhorn Pipeline project, we began delivering crude oil to the Houston market beginning in mid-April and as expected delivered approximately 90,000 barrels per day from mid-April through the second quarter.
Looking ahead to the next page of this project, we expect to average approximately 120,000 barrels per day during the third quarter, reaching full capacity of 225,000 barrels per day by the end of September. During the months of August and and September, we expect to bring additional tankage into service to facilitate the pipeline movements and to add pump stations along the pipeline to bring us up to the higher pumping capacity.
Further, we expect additional supply from third-party pipelines to come online at the Longhorn origin, allowing us to reach these higher throughput levels over the coming months. As a reminder, the Longhorn Pipeline is fully committed, but we have set aside 10% of the space for spot shippers.
If there are no spot customers interested in shipping for whatever reason, our committed shippers will fill the entire capacity of the pipeline. We are also making good progress on our BridgeTex joint venture, which will also deliver Permian crude oil to the Houston market and continue to target an operational date of mid-2014.
At this point, we have made significant progress on right-of-way acquisition and permitting, and tank construction and pipe production are currently underway. Our Double Eagle joint venture also became operational during the second quarter and is now making condensate deliveries from the newly constructed truck unloading facility at Three Rivers,Texas to our Corpus Christi terminal.
The remaining pipeline segment from Carbondale, Texas should be operational in September. The Double Eagle Pipeline is capable of transporting 100,000 barrels a day of condensate, which we continue to believe is a competitive advantage for this system since it's not batched with other projects -- products.
While this project is supported by long-term customer commitments, we have space available for additional shippers and continue to see significant interest from the market to ship on this pipeline as we get closer to the date Double Eagle system will be fully operational. We also purchased the Texas and New Mexico portion of our previously announced Refined Products pipeline acquisition on July 1.
As a reminder, this 250-mile pipeline delivers refined products from El Paso to the Albuquerque market and also from the refinery in El Paso to the U.S. border with Mexico.
This pipeline is a natural extension of our infrastructure, with the refined products line to Albuquerque already connected to our existing pipeline system that delivers product into El Paso. At this point, we are still awaiting regulatory approval of the Rocky Mountain Pipeline System that we also agreed to purchase a few months back and remain optimistic we will be able to close on this system later this year.
Based on the growth projects underway, we currently expect to spend $900 million during 2013 with another $320 million spend in 2014 to complete these projects. The 2013 estimate includes almost $250 million we spent during the first half of the year as well as the $190 million combined for the pipeline we acquired in July and the pending Rocky Mountain portion of that pipeline acquisition.
Even though we have included the pending Rocky Mountain pipeline acquisition in our expansion capital estimate, we have not yet included this acquisition in our 2013 DCF guidance, nor have we assumed this acquisition occurs in order to meet our forward distribution growth guidance. We also continue to evaluate well over $500 million worth of potential opportunities.
One of these projects is a potential refined products pipeline from our Fort Smith, Arkansas terminal to the terminals in Little Rock, Arkansas. This opportunity exists due to changes in the supply and demand patterns in the Mid-Continent.
Our proposed pipeline will allow customers in the Little Rock market to source products from the Gulf Coast, which has been a primary source of product for the market in the past, as well as from refiners in Oklahoma and Kansas, which have not had access to this market in the past. We are currently discussing this project with potential shippers and anticipate conducting an Open Season later in the third quarter.
Results of the Open Season will be assessed to determine if there's enough interest for us to proceed with the project. We also announced a potential project a few weeks ago for the development of a deep water storage and handling facility in the Houston Gulf Coast for crude oil, refined products and ethanol.
We are working with Vopak on this opportunity due to the synergies between Vopak's land availability and extensive worldwide storage capabilities and our comprehensive refined product and crude oil pipeline connectivity in the Houston Gulf Coast region. We are in the process of discussing this project with potential customers to determine if sufficient industry support can be secured to proceed.
We continue to develop the opportunity to increase pipeline capacity of Longhorn by an additional 50,000 barrels per day. We are in the process of assessing the final regulatory issues, but at this point, the project has a high probability of proceeding.
The capital for this project is still estimated to be no more than $80 million, with the majority of this capital to be spent on additional storage at East Houston and the Longhorn origin and for further capacity expansion of our Houston area distribution system. If we proceed, the regulatory required work and hydraulic expansion could be complete as early as the first quarter of 2014.
However, our ability to use the full amount of the capacity increase may be limited until the incremental storage is completed near the end of 2014. At this point, we have not included the Longhorn expansion project or any of our other potential organic growth projects in our expansion capital estimates, our 2013 DCF guidance or our distribution growth guidance.
So as you can tell, Magellan remains active in delivering growth for our investors by diligently placing our current growth projects into service and by exploring the best opportunities for us to satisfy the energy industry's growing infrastructure needs, which will most likely produce our next wave of growth opportunities. That concludes our prepared comments, and so I will now turn it over for questions.
Operator
[Operator Instructions] And we'll take the first question from Steve Sherowski with Goldman Sachs.
Steven C. Sherowski - Goldman Sachs Group Inc., Research Division
I'm just trying to get a sense of what's the biggest difference between your beginning of the year outlook and what you're currently seeing, and to provide you with a degree of comfort to increase your distribution guidance?
Michael N. Mears
Well, I think when we started the year, we had not yet started up Longhorn, and so there was still some uncertainty as to the start date for Longhorn. That's probably the biggest factor, with regards to our comfort on our guidance for the year.
I think when we entered the year, we also did not have as much of our commodity business hedged as we do now. So we've got a much higher of level comfort as to what those margins are going to be for the year, so that's what gave us -- in addition to the strong performance from a volume and tariff standpoint that we've seen year-to-date with regards to our refined products business.
So that's what gave us the comfort for 2013. If you advance then into 2014, it's really the progress with the BridgeTex system that's giving us incremental comfort to increase that -- the guidance for 2014, that we haven't had any problems maintaining our schedule in BridgeTex.
Steven C. Sherowski - Goldman Sachs Group Inc., Research Division
Okay. And just a quick follow-up.
What are you seeing in the storage market currently? I know that -- and I think no more than 15% to 20% of your storage assets reprice over the next or on an annual basis.
But what's the difference you're seeing in the fees that you can get between Gulf Coast and perhaps East Coast and even Cushing?
Michael N. Mears
Right. When we talk about -- when we look at storage, obviously, it's very location-specific.
In the East Coast, we've got a soft market. New Haven is under a very long-term contract.
That's not coming up for renewal anytime soon, so we didn't talk about that. But when you talk about the Gulf Coast, Galena Park, in particular, where most of those contracts are turning over that you mentioned.
The market, still, very strong. In fact, we're expecting our rates to -- well, actually, if you looked at our rates, they've increased about 5% year-over-year this year versus last year at Galena Park for the storage we've rolled over.
And the market for refined products storage at Galena Park, it still remains strong. If you look at our average rates, our average rates in our Marine terminals is about $0.40 $0.45 a barrel.
And the current market for refined products storage on the margin is $0.55 to $0.60 a barrel. So there's additional opportunity as contracts roll over, depending on what the rate is in those specific contracts.
But in total, our average rate at the marine facilities is below the current market, so we would expect that to continue to improve as contracts roll over.
Operator
And we'll go to Brian Zarahn with Barclays.
Brian J. Zarahn - Barclays Capital, Research Division
On the -- John went through the numbers a little quickly. Can you just reiterate the contribution of Longhorn and the Houston distribution system in the second quarter in terms of driving crude operating margin growth?
Michael N. Mears
Hold on a second, while we grab those. I can tell you that Longhorn volumes and growth on the Houston distribution system are a significant majority of the growth in the quarter.
John D. Chandler
Just to give you that breakdown again. On transportation revenues in the crude oil segment, they were up $18 million.
Actually, revenues in sales were up $18.6 million, about 80% of that was Longhorn. And the other 20% came from a combination of what we saw at Corpus Christi from the Double Eagle Pipeline and incremental revenues from our Houston area distribution system, so 80% of that increase is Longhorn.
On the expense side, I think I'd mentioned the accrued expenses were about $2.5 million. I think, you could say most of that's Longhorn-related.
So, hopefully, that gives you a feel for that. And I would put it around $15 million from revenue or so from Longhorn and about $2.5 million to $3 million on [indiscernible].
Brian J. Zarahn - Barclays Capital, Research Division
On the expansion of Longhorn, are you pretty comfortable with that $18 million cost estimate? Or is there actually room, potentially, for it to come down?
Michael N. Mears
I think there's room for it to come down. As I mentioned $80 million is a not-to-exceed number that we're looking at right now.
The scope of what we need to do is somewhat determined by what the regulatory requirements are going to be. And that still in a state of flux, to some extent, we've estimated that on what we think is the high side for what we may need to do there.
And so we think that $80 million is the high end of the range.
Brian J. Zarahn - Barclays Capital, Research Division
And then turning to your ship channel storage JV, can you give a little color as to would this be -- in terms of product mix, is it more refined products or crude? Any potential range of capacity that you're looking at.
Michael N. Mears
Well, we haven't gone into this joint venture with a preconceived notion on a mix between refined products and crude oil, but we have the advantage of having a significant distribution and pipeline connectivity optionality for either one to connect into these facilities. We're really assessing what the market need is for either one.
And if 100% of the market need for that facility is refined products, then that's the direction we'll go. And if 100% of it's for crude oil, then we'll go that direction too.
There's significant interest for both, so I would expect it to be a mix of those 2. But we're still early in the process of having discussions with customers, so we haven't tried to define that any further than that.
Brian J. Zarahn - Barclays Capital, Research Division
And then final one for me. On the Rocky Mountain pipeline acquisition, it seems like the regulatory approval's taking a little bit longer.
Is this your typical D.C. time?
Or is there something else that is taking a little longer to review?
Michael N. Mears
We are in the second request process with the FTC, which I think the time required to go through a second request is typical from what we're seeing right now. So you shouldn't read anything more to that other than, clearly, when the FTC does a second request, they want to look at it deeper than they would, just on initial review, so that process is ongoing.
But we're still very optimistic that we're going to have a favorable conclusion.
Operator
And we'll go to Darren Horowitz with Raymond James.
Darren Horowitz - Raymond James & Associates, Inc., Research Division
Mike, appreciate the color on the RINs. And at this point, I realize that you guys have only hedged about 25% of your projected 2014 butane for blending.
But given where the cost of butane is today and the current cost of the RINs on what's locked in, can you just give us a rough sense year-over-year for how the blending margins stand to look in 2014 relative to this year?
Michael N. Mears
Well, I think our blending margins for 2014, at least the 25% we've hedged, are consistent with what we're seeing in the fourth quarter. So they're still extremely strong.
So the guidance we've given -- the increase in guidance we've given for 2013 ,which is a significant portion of that increase is due to improved margins in the fourth quarter on our blending. Those margins are spilling over into 2014, and we're seeing similar high margins in the first quarter.
And when we say 25%, that's 25% for the year. Most of that hedging's done for the first quarter.
And we've got -- I don't know what the number is, but it's a very high percentage for the first quarter that rolls into 25% for the year. So that's what we're hedging right now, and those margins are consistent with the fourth quarter.
Darren Horowitz - Raymond James & Associates, Inc., Research Division
Okay. Yes, I appreciate that.
That makes sense. And then switching gears to the Double Eagle JV.
I'm just curious, is 100% of that capacity booked now?
Michael N. Mears
It is not. I mean, we still only have a commitment that ramps up to 50,000 barrels a day, but we are having active discussions with a number of other parties who are interested in the incremental space.
Darren Horowitz - Raymond James & Associates, Inc., Research Division
Okay. And as you think, at the terminal point of that, how do you start to think of that as volume ramps, possibly the opportunity for additional storage beyond the 500,000 barrels that you have at Corpus or maybe even expanding the barge dock and offloading capabilities?
Michael N. Mears
All of that is under evaluation. Double Eagle, itself, can be expanded to a higher capacity than 100,000 barrels a day.
So we've got multiple expansion steps there. We can expand the pipe.
Obviously, that's a joint venture with Kinder, so that would need to be a joint decision. But some of the parties we're talking to and some of the opportunities we're looking at both involve expansion of, or the addition of additional storage in Corpus.
Operator
And we'll go to Connie Hsu with Morningstar.
Connie Hsu - Morningstar Inc., Research Division
I just have a couple of questions, again, on the Houston Deepwater storage joint venture. Do you have any estimates on the cost of the investment yet?
And then on the rail access, will this new project entail building a new rail facility to enable this? Or will you be connecting to existing local facilities?
Michael N. Mears
Well, we haven't given the cost estimates yet on the joint venture, simply because we haven't determined yet what the market interest is for storage. I mean, obviously, this facility is scalable.
There's a certain level of minimum storage we would need to make a project economical and scalable from there. We haven't disclosed any of those numbers yet, while we are in the process of talking to customers.
With regards to the rail, we would be constructing a new unit train offloading facility at the location. It would -- I mean, obviously, that would be connected to local railroads coming in, but it would be a new unloading facility owned by the joint venture.
Connie Hsu - Morningstar Inc., Research Division
Okay. And then just on the Double Eagle condensate line again, has the pace of getting commitments been roughly in line with your expectations?
Michael N. Mears
Well, I don't know that we set out a specific target for our expectation. We've only been in operation now for a few months.
It was our expectation that once we were in operation, the interest level would ramp up, and that it has. We're seeing shipments today, truck barrels, and just as a reminder, I mean, today, we're taking these truck barrels at Three Rivers and shipping those to Corpus, since we don't have lateral lines completed yet.
We're shipping barrels for noncommitted parties today, so we're shipping more today than we have under the committed contracts. And we're expecting that to grow.
So we're very pleased with that even though -- and I think we've said all along that it's not -- it's possible that at the end of the day, we're shipping -- the only committed volumes we'll have are the commitments we have, but then we'd have sizable volume shipping under spot tariffs. And as we've started the project up, we've got volume shipping at spot tariffs.
So I would say that it's really progressing kind of as we expected so far.
Operator
Next is John Edwards with Credit Suisse.
John Edwards - Crédit Suisse AG, Research Division
Just following up on the Double Eagle expansion. So just you're going through the rundown on what, in terms of your distribution growth guidance for next year -- what's included and what isn't.
And so is the Double Eagle expansion, that's not in your thoughts for next year or is? In other words you've got this 50,000 commitment, you can go to 100,000.
I just want to -- that's what I'm trying to get an idea of, how much you're counting on that?
Michael N. Mears
Yes. We are not counting on an expansion of Double Eagle to meet our growth targets for next year.
We're -- I mean, all we've modeled into our forward plans right now to support the growth that we've announced is -- what our base commitment levels are. And then what we're expecting to see from spot barrels from what we've heard from interested parties right now.
We're not building any expansion of the system at this point.
John Edwards - Crédit Suisse AG, Research Division
And you're not looking for any -- so no more ramp up of beyond the 50,000 initial committed barrels?
Michael N. Mears
We may be expecting some marginal spot barrels in our forecast going forward, but they're not significant enough to change our distribution growth target if they don't happen. Those are rather modest on what we've built in.
The large projects that we're looking to, the large shippers that we're talking to, that potentially bring big blocks of volume to Double Eagle are not modeled into our forward forecast right now.
John Edwards - Crédit Suisse AG, Research Division
Okay, great. That's helpful.
I guess, the other question I have is in terms of, for the last several quarters you've indicated that you have $500 million or more in terms of opportunity set under evaluation. And I'm just wondering what kind of changes, if any, are you seeing in the types of assets or opportunities that are available?
Michael N. Mears
Well, I can tell you that the majority of those projects and, in fact, I think, we probably talked about, 75% of those projects in that excess $500 million category are crude oil related. That percentage may not be 100% accurate any longer, since we are evaluating this new pipeline to Little Rock, which is a refined products pipe, which is a pretty sizable project, which is new to the list in the last quarter.
But even with that, I mean, the majority of projects that we're looking at are crude oil related
John Edwards - Crédit Suisse AG, Research Division
Okay, that's helpful. And then in terms of when you say $500 million or more, are you saying the opportunity set, I mean, is about the same, or is it continuing to rise?
Michael N. Mears
Well, but the reason we say more than $500 million without giving a more precise number is, because it moves around quite a bit. We're looking at a lot of projects.
Some projects have higher probability of occurring than others. And that list is constantly changing.
So rather than giving out a number that is up one quarter and down the next quarter, we try not to do that. We just try to indicate that it's more than $500 million.
I can tell you right now...
John Edwards - Crédit Suisse AG, Research Division
Trajectory. I'm just looking for the general trajectory.
That's all.
Michael N. Mears
Right. I'd say it's going up.
We have a long list of things on our project list for quite some time, so it's sizable to begin with, but I'd say it's trending up. It's not probably dramatically trending up versus where we've been, but it's been large to begin with, but the trend is positive.
John Edwards - Crédit Suisse AG, Research Division
Okay. And then, lastly, the Longhorn in terms of the ramp, is that progressing as expected?
Or is it a little bit ahead of schedule? If you could comment on that.
Michael N. Mears
It's progressing as expected. We've said all along that it was going to be late third quarter before we got to full capacity, and that's consistent with where we are today.
Operator
Next is Matt Niblack with HITE.
James Jampel
It's actually James Jampel with HITE. Could you talk a little bit about how backwardation in the crude and refined products markets affects Magellan if at all?
And can you comment currently? And if it were to persist?
Michael N. Mears
Well, I mean, if you just talk at a point in time, for example, right now, we've got crude oil and refined products under contract. I think, probably on the refined products side, we've been through numerous cycles of backwardation and contango in the refined products market.
And consistently, our refined products storage on our pipeline that we lease out and the storage at Galena Park have maintained their value through those periods. And the primary reason for that is that storage is used by our customers, not just for playing the market structure.
It's used for a number of things, blending opportunities in basis differentials. And so we've seen continued strength in those markets.
We're pursuing, as we speak, even though we're in a backwardated market -- we're pursuing additional refined products storage opportunities around our pipeline system, where our customers have significant interest in supporting. So refined product market that really doesn't have a big impact on us.
On the crude oil market, I think one can argue that in a contango market in crude oil that could impact the value storage at Cushing. At this point in time, with all of our contracts at Cushing are in place.
We don't have anything renewing in the next couple of years. And so there's really no impact to us on horizon.
We'll have to assess that risk down the road, when those contracts are up for renewal, but those are quite some years out before we have to address that, and who knows what the market structure will be at that time.
James Jampel
Can you elaborate a little bit more about what's going on in New Haven?
Michael N. Mears
Well, New Haven, in particular, is a location that's under a very long-term contract. It's in the neighborhood of 10 years out on the life of that contract, so -- we don't have any short-term exposure in New Haven.
You may have been asking about Wilmington. Wilmington is a location where the market's been soft.
We have a contract there -- that for a large portion of facility that still has quite some length on it. But storage that has been turned back -- or that has come up for renewal recently has been turned back.
It's primarily dark oil storage and the market in the Northeast for dark oil storage has changed dramatically with the refinery changes in the market. And so there's been some weakness in the Willington market.
That weakness has been for quite some time. It hasn't -- it's not something that's just now showing up at our earnings.
It's been there for maybe 1 year or 18 months. So we're evaluating some options there.
We're evaluating, converting the dark oil storage to light products. We're looking at some other things to make those tanks that are currently not used more valuable, given the current situation in the Northeast.
But right now, that market for dark oil is pretty soft. But that's one -- Wilmington is not -- I mean, it's just one facility.
Obviously, it's not, by any stretch our largest facility in our marine segment, and we're not seeing that softness anywhere else.
James Jampel
You mentioned that in New Haven that the market was softer?
Michael N. Mears
If I said that, I misstated, I mean -- what I meant was the northeast. which for us is Wilmington and New Haven.
Wilmington is where we've seen the softening, simply because we've have contacts come up for renewal. New Haven, again, I mean, it's a long-term contract there, so we really haven't tested the market recently because of the length of contract.
Operator
At this time, there's one name remaining on the roster. [Operator Instructions] And we'll take the next question from Brett Riley with Zimmer Partners.
Louis Shamie
Actually, it's Louis Shamie also from Zimmer Partners. Just a question about the refined products pipes.
You saw rates -- the average tariff there. Volumes were more or less flat with, I guess, the previous quarter, but volume -- the average tariff was up about 20% sequentially.
Can you talk a little bit about what's driving that and kind of how sustainable these changes are?
Michael N. Mears
Well, first of all, I would comment and say that you just look at the components of the refined products volumes. We had strength in diesel volumes and weakness in LPG volumes.
In the LPG volumes, that weakness was really related to the refinery turnaround, and those are low tariff movements. And so if you exclude that, and if you just look at gasoline and diesel fuel, we actually had an increase in volumes.
As far as the drivers for that, again, we continue to see very strong demand in Texas. The diesel volumes we moved to Odessa, really, related to all the activity that's happening in the Permian is one component of that.
We think that's sustainable and perhaps growing. We did see some refinery turnarounds in Mid-Continent, which don't necessarily -- to some extent, they drive incremental volume, since those refinery racks are not operating at full capacity, while they're on turnaround, so that drives some volume and also drives longer haul shipments in our system.
So those items, one can say those are onetime items, and they are, but refineries have turnarounds all the time. So they're repeatable, they just don't repeat every quarter.
Louis Shamie
So whereas kind of in Q1, your average haul was a bit shorter than it usually is. Q2, just because of market dynamics, you were able to get some more long haul.
And that kind of...
Michael N. Mears
I think that's an accurate statement.
Operator
And we do have a question from Sigi Tang with BAM Funds.
Sigi Tang
This is Sigi from BAM. Just curious, first, on your Longhorn expansion.
What kind of rates should we be looking at for this additional 50,000 barrel a day?
Michael N. Mears
Well, the tariffs on that volume will be the same as what we're shipping today. The contracted tariffs will be the same, and the spot tariffs will be the same.
The operating cost on that incremental expansion will be quite a bit higher. We're -- obviously, as we're pushing more through the pipe, the incremental power cost and workover [ph] costs are going to be higher.
We haven't, I think, publicly quantified that. But I think as we get further along and we've nailed down the scope and exactly what we need to do will provide some more guidance on that.
But it's going to be lower than what -- the incremental margin's lower than what the base volumes are even though the tariff's the same due to the cost. But we will -- I think in a future call, we'll probably get more guidance on what that margin will be, once we're certain were going to proceed.
Sigi Tang
Got it. And in terms of your backlog of new projects, should I think is more like a crude-focused?
Or is it going to be more like refined products-focused? Is it going to be like more pipeline or more terminals?
Like, just give us some direction on that.
Michael N. Mears
Yes, just -- I mean, again, we publicly said about 75% of that backlog is crude oil-related and they're pipeline and storage projects both. So those are the primary components of that.
Operator
And there are no other questions. I'd like to turn it back over to Mike Mears for any additional or closing remarks.
Michael N. Mears
All right. Well, I want to thank, everyone, for your time today.
We're optimistic about our ability to continue our consistent growth. And we appreciate your continued interest and support of Magellan.
Have a good afternoon.
Operator
Thank you very much. That does conclude our conference for today.
I'd like to thank, everyone, for your participation, and you may now disconnect.