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Good day everyone and welcome to the Magellan Midstream Partners Fourth Quarter 2017 Earnings Results Conference Call. Today's conference is being recorded. At this time, I would like to turn the conference over to Mike Mears, President and Chief Executive Officer. Please go ahead.
Good afternoon and thank you for joining us today to discuss Magellan’s fourth quarter financial results and our outlook for 2018. 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 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.
We’re pleased to report our 2017 with strong operating and financial results delivering quarterly records to refined products transportation volumes, crude transportation volumes and distributable cash flow and solidifying 2017 as another record year for Magellan. In addition, we increased our cash distributions by 8% for the year, while generating a healthy 1.25 times average which resulted in more than $200 million of access cash available to invest in Magellan’s business.
I’ll now hand the call over to our CFO, Aaron Milford, to review Magellan’s fourth quarter financial results in more detail. Then I’ll be back to discuss our guidance for the New Year and our expansion project before opening the call to your questions.
Thank you, Mike. I would like to remind the audience that we'll be making references to certain non-GAAP financial metrics, including operating margin and distributable cash flow. We believe these metrics are useful for investors in evaluating our performance. We’ve included exhibits to our earnings release that reconcile these metrics to their nearest GAAP measure.
Earlier this morning, we reported fourth quarter net income of $237.9 million, or $1.04 per unit on a diluted basis, which was higher than the $213.3 million or $0.93 per diluted unit reported for the fourth quarter of 2016. Excluding the impact of mark-to-market commodity activity in the current quarter, adjusted diluted earnings per unit of $1.19 exceeded our guidance of $1.15 provided back in November of last year.
For the year, we reported the net income of $869.5 million in 2017 compared to $802.8 million for 2016. Distributable cash flow of $308.3 million in the fourth quarter of 2017 was $31 million higher and the $277.2 million reported in the fourth quarter of 2016. For the year, we reported $1.02 billion of distributable cash flow which was in line with our annual guidance provided back in November of 2017 and $73.9 million higher than our 2016 results. Both the quarterly and annual results represent record distributable cash flow performance for Magellan.
As expected, we ended the year on a strong note, and we were able to overcome the effect of Hurricane Harvey and meet or exceed the financial guidance we have provided. For the fourth quarter, Hurricane Harvey negatively impacted diluted net income by about $8 million and distributable cash flow by approximately $10 million.
For the year, net income was negatively impacted by approximately $15 million and distributable cash flow was negatively impacted by approximately $20 million. As we discussed after the third quarter of last year, our marine segment bore the brunt of this event through loss and increase spending. As we look forward, we don’t expect any materially lingering effects from Harvey in 2018 once we take into account our expectations for insurance recoveries.
I will now move to discussion of our segment operating margin performance for the quarter. Our refined product segment generated $216.2 million of operating margin in the fourth quarter of 2017 which was $24.8 million higher in the fourth quarter of 2016. Transportation internals revenues were almost $25 million in the 2016 quarter as well.
In total, our gasoline volumes were up by about 9% and our distil volumes were up by 16%, which equates an aggregate to an 11% volume increase compared to the fourth quarter of 2016. These increases were primarily driven by increased volume in Texas with distilled demand in West Texas due to increased drilling activity being particularly notable.
Our average rate per barrel decreased in the fourth quarter 2017 compared to the 2016 quarter as a result of lower tariffs received to a shorter home business in South Texas which offset the impact of our overall average tariff increase of 3% in July of 2017.
Operating expenses decreased $13 million compared to the fourth quarter of 2016 mostly due to favorable outages and lower environmental accruals which were offset by higher maintenance spending and higher personnel cost.
Product margin in the fourth quarter decreased by approximately $12 million compared to the fourth quarter of 2016 partly as a result of other period unrealized losses associated with our hedging program. Our cash margin which takes into account when we physically sell product and is normalized for unrealized gains and losses was also below last year’s per quarter primarily due to higher butane costs.
These same blending margins in the fourth quarter were approximately $0.30 per gallon compared to margins of $0.35 per gallon in the fourth quarter of 2016. For the year, the refined products segment contributed almost 50% to total operating margin for the company.
Moving now to our crude oil segment, this segment generated operated margin of $141.8 million in the fourth quarter 2017. This represents a $30 million increase compared to the fourth quarter 2016 and was another quarterly record for the segment.
Transportation internals revenues increased by $24 million compared to the fourth quarter of 2016 primarily as a result of contributions from the - and the record crude oil transportation volumes. During the quarter, Longhorn volumes averaged 265,000 barrels per day and our volumes in the Houston distributions system were up substantially in the quarter.
As a result of higher Houston distribution system volumes which move at a substantially lower rate than our Longhorn pipeline barrels, the average rate for barrel declined compared to the fourth quarter of 2016. Fourth quarter 2017 operating expenses increased $8.6 million compared to the 2016 quarter as a result of higher operating expenses associated with the condensate splitter, higher maintenance spending as well as higher personnel cost.
Equity earnings from the crude oil related joint ventures increased by $16.7 million compared to the fourth quarter of 2016. This increase resulted primarily from higher earnings related to our BridgeTex and Saddlehorn joint ventures. BridgeTex volumes average almost 350,000 barrels per day during the fourth quarter of 2017, which was about 125,000 barrels per day higher in the same period in 2016.
Higher quarterly volumes was result of additional shipments related to our reasonably activated Eaglebine origin and spot volumes being shipped in response to wider market differentials between West Texas and Houston during the quarter. For the year, BridgeTex’s volume average almost 270,000 barrels per day compared to about 215,000 barrels per day in 2016.
Saddlehorn volumes were approximately 75,000 barrels per day during the fourth quarter of 2017 as a result of increased condensate barrels shipped under a newly established splitter as well as a step up in committed volumes. For the year Saddlehorn averaged just over 50,000 barrels per day in 2017 compared to around 40,000 barrels per day in 2016.
Product margin for the crude oil segment was negative $3.3 million or $2.9 million lower than the fourth quarter of 2016. This negative product margin resulted primarily from changes in the value -- market value of nine expositions used to hedge our over expositions as well as increased transportation charges. For the year our crude oil segment contributed about a third of total company operating margin.
Finishing up my discussion of our segment performance, our marine segment operating margin was $9 million lower in the fourth quarter 2017 compared to the fourth quarter of 2016. Transportation and terminals revenues were $4.9 million lower in the fourth quarter versus the 2016 quarter primarily as a result of impacts from Hurricane Harvey. Expenses were $3.8 million higher also primarily related to our Hurricane Harvey response and related environmental accruals. For the year, our marine segment contributed about 8% to total company operating margin.
Now moving to other net income variances to 2016, our G&A expenses $8.5 million higher in the fourth quarter of 2017 compared to the fourth quarter of 2016 primarily resulting from higher headcount and higher bonus and long-term incentive expenses. Depreciation and amortization expense was up by $6.5 million for the quarter as a result of assets being placed into service.
Net interest expense increased by $5.6 million due to lower capitalized interest in the current quarter compared to the fourth quarter of 2016 as well as higher average debt balance as we continue to fund our various growth projects. Our weighted average interest rate fell to 4.8% in the current quarter from 4.9% in the fourth of 2016. Other expenses were slightly higher than the fourth quarter of 2016.
Moving onto a discussion regarding our balance sheet and liquidity position, our outstanding debt balance was $4.6 billion at year end 2017, with no borrowings outstanding under our commercial paper program. We also had a cash balance of $176 million at December 31st as a result of our bond offering in the fourth quarter of 2017.
Our net debt to EBITDA ratio at December 31, 2017 was approximately 3.3 times. We continue to maintain $1 billion credit facility which also supports our commercial paper program. We do have any borrowings outstanding under this facility at year end 2017. We also continue to maintain a $750 after market equity program and we do not issue any units during the quarter and not issued any units since putting the program in place.
As we stated in the past, the ATM is a tool we plan to use to manage our leverage ratio to approach our four times limit. As has been the case for some time, given our current economic estimates we believe we can fund our current state of growth projects without needing to issue any equity, but we do expect our leverage ratio to continue to rise closer to our 4 times target as we fund our growth projects throughout 2018.
I will now turn the call back over to Mike to discuss our forward guidance and our growth projects currently underway.
Thanks, Aaron. Earlier today, we announced DCF guidance of $1.05 billion for 2018, our plan is to increase distribution by 8% again in 2018 consistent with previous guidance resulting in coverage of about 1.2 times for the year. To help you better understand our 2018 DCF guidance, we generally like you to walk you through the key assumption we use to create our projections for the New Year to give you a better feel for how we see the year playing out.
Starting with our refining products segment, we expect base refined products volume to remain relatively flat between the years especially in light of record demand in 2017. Adding on incremental shipments, we expect around our Texas City assets and a new connection we made in El Paso, we project total refined products volumes to increase by about 7% in 2018. The other key component for our refined products pipeline just the average tariffs recharge.
As you know, the current FERC indexation methodology is based on the change in the producer price index plus 1.23%. The preliminary change in PPI for 2017 is an increase of 3.2% which will result in almost the 4.5% tariff increase for those markets that follows the index. Even though roughly 40% of our refined product system is subject to indexation, we expect to increase tariffs in all of our refined products markets by FERC index on July 1, 2018.
For modeling purposes, please keep in mind that our point-to-point pipeline movement haven’t impact on the average rates that you see on our operating statistics. Even though, we intend to rate tariffs almost 4.5% in mid 2018, our overall rate per barrel is expected to be remain flat between period since the majority of projected incremental throughput is anticipated to be shorter haul movements in the Texas City in the El Paso areas which move at a lower tariff rate.
The other key assumption is significantly impact to refined product segment is the commodity price environment, especially as it results to butane blending activities. We have about one-half of our expected 2018 butane blending sales volume hedged at this point with virtually all of our spring blending margin locked in and we generally used the forward commodity price curve to forecast the expected margin for our un-hedged volumes.
The average blending margins in 2017 were compressed compared to recent years primarily due to the strength in butane pricing, which is unfavorable to our butane blending activities since we purchase butane to blend. We average blending margins of around $0.35 per gallon during 2017 and expect margins close to $0.30 per gallon in 2018, which would be add historically low margin for Magellan.
The 2018 margin estimate is based on hedges locked in for approximately one-half of our expected volumes and also using a late December forward price curve for un-hedged volumes. Any important in the actual margin the second half of the year is upside to our current guidance.
Moving to our crude oil segment, we expect shipments on our Longhorn pipeline to be similar to 2017 levels at 260,000 barrels per day get into 2018 with no spot shipments. As you are aware, our Longhorn contracts are set to expire in the fall of 2018. We remain in active discussions with shippers regarding potential new rates upon re-contracting.
Although, we remain confident demand for space to Longhorn strong, as we’ve discussed for a while now the pricing environment for term commitments is very competitive, and so our 2018 projections assume a Longhorn rates will be lower upon re-contracting in the fourth quarter of 2018.
For our Houston distribution system, we expect to see increased volume in the new year primarily related to more volume coming into our East Houston facility from BridgeTex and Houston in our increased takeaway capacity now that are recently constructed East Houston to how the avenue pipeline is operational.
As a reminder, even though the Houston distribution system makes up about one half of the crude oil transportation volumes we report, the average tariff on the Houston distribution system is significantly lower than the Longhorn tariff at approximately $0.30 per barrel.
Combining these pieces, we expect our wholly owned crude oil transportation volumes to increase about 10% in 2018 again driven by higher Houston distribution volumes that move in the lower rate.
Moving on to BridgeTex, as you know we have recently expanded capacity of that pipeline from 300,00 barrels a day to 400,000 barrels with a further expansion to 440,000 barrels per day in progress and expect to be operational in early 2019. BridgeTex conducted two open seasons recently to secure commitments to utilize the newly created space.
Considering these new commitments, our 2018 projections assume BridgeTex’s volumes average around 315,000 barrels per day in 2018 which is slightly above summative volume level. For comparison, we move closer to 270,000 barrels a day in 2017 with the 17 results including about 15% spot shipments as the system benefitted from a favorable crude differential between Midland and Houston during the latter part of the year.
The current market differentials do not support a spot barrel movement. So our guidance assumes no spot volumes for BridgeTex or Longhorn in 2018, we see upside to our guidance of approximately $30 million if these differentials turn favorable once again and the available space is utilized for spot barrels on both BridgeTex and Longhorn.
Contributions from the Saddlehorn pipeline are expected to increase during 2018 due to the ramp in committed volumes. As you may recall committed volumes increased to 60,000 barrels a day temporarily in 2017 and step up again to 70,000 barrels a day in September 2018, which is modeled into our ’18 projections. Although, Saddlehorn moved to small amount of condensate during 2017 under recently filed lower incentive rates, we have not built those continued movements into our forecast at this time.
We expect our condensate split to be operating in line with contracted throughput levels for 2018 which will be a first full year benefit from this asset. As a reminder, the split is supported by a long-term take or pay agreement that is expected to generate a seven times multiple during the initial contract term.
Regarding maintenance capital, we’ve spent approximately $90 million during 2017 which is a reasonable estimate again in 2018. Although you know we see a line item for the capital component of our integrity program, Magellan spends considerable time and effort each year to ensure the integrity of our assets. On a combined basis considering capital and expense, we expect to spend almost $250 million on maintenance and integrity work for the entire company during 2018.
So, that summarizes the key assumptions build into our projections resulting in DCF of approximately 1.05 billion in 2018. Reaffirming our state of goals, 8% annual distribution growth for 2018 we still expect to generate a healthy coverage level of 1.2 times with approximately $165 million of excess cash flow for the year.
I am sure you’ve also noticed that we’ve provided our view of 2019 and 2020 as well in this morning’s release. We have continued to hear from our long-term investors the strong distribution coverage remains important to them especially considering the performance of the energy markets and MLP space over the last few years, as a result we intent to manage our business in a way that maintains a coverage ratio of 1.2 times for the foreseeable future.
Based on our internal forecast, we currently expect annual DCF growth in the range of 5% to 8% for both 2019 and 2020. To maintain 1.2 times coverage, Magellan tends to manage distribution growth consistent with our expectation for DCF growth for those periods, which would imply annual distribution growth in the range of 5% to 8% for 2019 and 2020 as well with excess cash in $175 million to $200 million range each year to reinvest in the business.
With regards to expansion capital, we spent more than $540 million on organic growth construction projects during 2017. Based on the projects currently under construction, we expect to spend $900 million in 2018 with an additional $375 million in 2019 to complete the projects now in progress.
We spoke in detail last quarter about the newer and large scale projects that were kicked off during the latter half of 2017. Most notably our Pasadena marine terminal joint venture with Valero our pipeline projects to construct a crude pipeline from Wink to Crane, Texas and refined product pipeline from East Houston to Hearne, Texas.
We continue to make progress on these projects which are still in the early stages of construction and make up the bulk of the future spending. Specific to Pasadena, construction is underway with the first 1 million barrels of storage expected to be operational in early 2019 and the remaining 4 million barrels of storage projected to come online in early 2020.
For the Wink and Hearne pipelines we are in the process of permitting, route work and pipe procurement, both pipes expected to be operational in mid 2019. We also increased our total spending estimates by about $60 million for a number of new smaller projects which include reactivation of a jet fuel pipeline George Bush Intercontinental Airport in Houston, additional butane blending opportunities and enhancements to a number of our terminals around the country.
We recently replaced our new 24 inch crude oil life from East Houston to Holland Avenue into service which will significantly increase the capacity of our Houston distribution system out of East Houston. We are also nearing the finish line for the second phase of our Seabrook Logistics joint venture with 1.7 million barrels of crude oil storage in connectivity to our Houston distribution system to be completed in mid 2018.
We are also continuing to make significant progress on addition of new dock capacity at our Galena Park marine terminal which is expected to be fully operational by late 2018. As you can see, we continue to make progress on completing expansion projects and lots of new opportunities for future growth. And more importantly, these projects are strategic in nature and commissioned at attractive returns most recently in the eight times multiple range.
We also continue to evaluate other potential expansion opportunities still totaling well in excess of $500 million with future projects under consideration in each of our business lines. Among many other possibilities these opportunities include further build out of our Pasadena joint venture additional crude oil infrastructure investments in West Texas in Corpus Christi and significant refined products pipeline expansion opportunities.
We currently -- we currently an open season in progress for proposed pipeline delivered crude oil and condensate from the Permian and Eagle Ford Basins to Corpus Christi in Houston. Potential shippers have expressed significant interest and we just extended the open fees in another month to March 1, to provide the potential shippers in additional times, time to finalize the commitment.
We have significant incremental services to offer a conjunction with the proposed pipeline including a Suezmax stock expansion at Seabrook Logistics significant. incremental stories and dark capabilities and Corpus Christi in permits and land for an additional 50,000 barrel day condensate at Corpus Christi.
On the topic of acquisitions, we remain active in analyzing the opportunities available on our space as always price and risk profile are key considerations and Magellan intends to maintain its disciplined approach when evaluating not only potential acquisition opportunities. but also construction projects. Our preference continues to be to pursue opportunities to expand our asset portfolio with fee based activities and long-term committed volumes from credit worthy counterparty.
That now concludes our prepared remarks, so operator we can open it up for questions.
Thank you. [Operator Instructions] We’ll our first question from Theresa Chen from Barclays.
Mike, I wanted to follow up on some of your comments related to 2018 DCF guidance particularly related to Longhorn. You mentioned that we should be expecting a lower tariff versus what I believe today at an average of quarter end. We heard also extensive comments from different market participants about the competition on out there, and some tariff for new leap post projects as lowest as $1.50 or so. I was wondering, if you could just give us sense or range of what you actually expect to Longhorn tariff to be. Are we really expecting something as wide as like a $0.75 delta from where you are today?
Well, thanks for the question. I mean we have been actively discussing in the last few days how much the exposure we would provide with regards to re-contracting the Longhorn. Unfortunately, we’re not prepare to give a range at this point and it’s primarily because we’re right in the midst of those negotiations with multiple parties and it is a very competitive market.
And so, unfortunately I can’t narrow that down for you any further at this point. I -- we have an expected range that we believe we’re going to be re-contracting, we build that lower range into our guidance not only in 2018 but also in 2019 and 2020. And, but unfortunately I need it to thorough on giving you more specifics on the range of those rates at this point.
Okay. Understand. In terms of the guidance further out to 5% to 8% growth. Can you talk to us about what would be the drivers of delta between the lower and higher ends? Is it very commodity driven differentials butane blending et cetera? Or is it more related to start up and return multiples on projects coming online?
It’s related -- there’s two big components that drive that range. One is commodity margins, as I mentioned, in 2018, we’re expecting historically low commodity margins for our butane blending activities and if you look at out in 2019 and 2020, there’s some marginal improvement there, but we're still at very low historical rate. And so there’s certainly upside associated with that. The lower end of our range is kind of tied to what the current curve suggest, which are pretty -- as I said historically low margin. The other component is the spot volumes on our crude oil pipeline and in our forecast, we've assumed that even out in 2019 and 2020. So there’s significant upside there. But at the lower end of our guidance assumes that we don't have any spot movements on our crude pipes.
And lastly would you mind just providing some additional color on the future phases of Pasadena and Seabrook Logistics? As you stand now, where are those discussions? And how are you seeing demand shapeup?
Well, with regards to Pasadena, we’re already in active discussions with a number of parties for further expansion of Pasadena. Just as a reminder, we can build another 5 million barrels of storage there and 3 additional docks. The expectations for increased refined product exports are very strong. So there's interest in the capabilities of Pasadena. So those discussions are underway. On Seabrook, our next phase of expansion would include additional storage, actually at Seabrook, but also at Suezmax dock. Progress on that project has been moving pretty rapidly and I would hope that we'll have something to announce more definitive on that in the near future.
And we’ll take our next question from Jeremy Tonet with JP Morgan.
I want to touch base on the guidance to start off and just want to see going out to 2020, it seems like it might be a little bit further guidance later dated than maybe what you had provided in the past and was wondering any thoughts behind that? And also just kind of when you’re thinking about the guidance, it feels like the coverage ratio is kind of the -- it determines what happens to the outputs more, the growth of the DCF at that point. I’m just wondering how you think about how much capital or growth CapEx you'll have over the next few years that kind of is the other Variable, I guess, to drive that? And if it becomes more or less, how that could influence your guide or later-dated growth rate?
Well with regards to going out for guidance through 2020, I mean, you're right that's typically longer than we've done in the past. We felt that it was important to do this time and we're not necessarily trying to set a precedent here, but if you look at the growth in DCF between 2018 and 2017, it’s slightly below at least in our at the lower end of our forecast for guidance, it's below what our historical growth has been.
And we view 2018 as somewhat of a GAAP year, we’ve got significant growth projects coming in line in 2019 and 2020. And so we felt that that it was important to signal that '18 is not an indicator of the long-term growth of the company that the growth prospects are still strong. So we felt it was appropriate to give guidance for ‘20 in addition to ‘19 at this time.
With regards to the 1.2 times coverage, we feel -- we've historically talked about being comfortable going down the 1.1 times coverage. Quite frankly, we think our business is healthy at 1.1 times coverage, but we also think that it is prudent to maintain a higher coverage and trend more towards a self-funding model than a full distribution of available cash flow. So, we are going to target 1.2 times at least for the foreseeable future.
Clearly and if you look at the projects we are constructing right now and the projects that we have in our backlog, we feel confident at this point that those can be funded primarily with debt. And if something significant were to change with regards to that, we would reevaluate that with regards to whether or not this recent coverage needs to be modified to more self fund rather than issue equity. But at this point in time we think the 1.2 times coverage is healthy and that’s what our expectation would be over the next three years.
And just want to go back to Longhorn and expand a little bit more on that with the re-contracting. And it seems like the competitive situation with new pipe center in the market, but also seems like production is still growing rapidly in the basin and considerably you could have some capacity tightness especially as the year progresses and into year-end '18. So I was just wondering how you weigh these different factors into your thoughts on timing, the re-contracting doing it sooner versus later, if it will get tighter as the year goes on.
Well, if you’ve known us for any length of time, we are rather conservative company and we would prefer committed contracting rather than be exposed to the market. And so, we would err as we’re doing in this case, to re-contract at rates that are secured for term commitments rather than be exposed to whatever the differential is at any point in time was spot tariffs.
And so that’s our preference, I mean you are absolutely right, that if the production continues to grow as it has been and its projected to be that there could be tightness in the market in the next couple of years; however, we tend to prefer longer term contracts at fixed rates then to try to maximize short-term profits.
I will say though that even with re-contracting Longhorn we have spot space on Longhorn and we have significant spot space on BridgeTex. So, if the market does tighten and the differentials widen, then we will benefit from that even with our re-contracting Longhorn strategy.
And just last one I guess. As far as -- there is a lot of Permian takeaway projects being proposed right now, some of them moving forward. Just wondering how you guys think about it from a macro bubble. How much -- how many pipes are needed, how much new capacity is a room for kind of three pipes moving forward right now or anything you can provide as far as the in-house views as far takeaway needs over the next few years with Permian?
Well, I mean first of all, I think it’s safe to say that we would not build a pipe out of the Permian in this environment without long-term commitment that would support the economics. So, that’s the reality in the short-term, if you look at long-term, and if you get out five plus years from now -- there is certainly are bullish production forecast for the Permian that would support more than two pipelines going forward.
So, that’s kind of the view as if you can get something that is long-term committed with an attractive return now. You’re still exposed to the long-term growth of the Permian, but everyone is existing assets and new assets. But again the Permian Basin looks like it's going to be very strong for some time. And in our view, if you go out that far into the future that the long-term risk is not -- I should say the long-term production forecast would support the proposed pipes that are being built.
And we’ll go next to Mirek Zak with Citigroup.
Looking at your $500 million plus project opportunities, can you guys speak to how you’ve seen the return makeup of those opportunities change over the past year or so, and kind of how that’s looking in your perspective further out maybe going for 2018 to 2020?
Well, I would not say that the return characteristics have change significantly, I mean the returns of the projects we’re pursuing in general -- we've historically quoted six times to eight times range. They're quite frankly more of the upper end of that range. But they’re not typically outside of that range.
If you look at the Permian Basin for instance, and the very competitive nature there, the rates that are being proposed are significantly lower than the pipelines that we’re build five years ago. That just means to more need more volume, I mean this project are not going to get build unless you have higher volume commitment than you needed five years ago. But the returns on those projects at least the one that we’re considering are still in the same ballpark as projects we’ve approved in the past.
Obviously, Longhorn and outlier there, outlier was a uniquely advantageous project for us and had a very, very low multiple, which I would say as an outlier. But if you look at our standard investments, the projects we’re looking at in the Permian now still are hitting those thresholds. They’re deep more difficult to get with regard to securing commitments because you need more volume, but we think we’re going to be able to get that across the gold line.
And so when you speak of those projects that you haven’t officially announced or sanction yet that all generating need your return rate hurdles. And also on top of that how often do you see that opportunities that sort of replenish itself?
Well, our goal is to hit our internal return threshold before we sanction the project. So that's – and we believe we're going to be able to do that with regards to our pipeline development out of the basin. As far as that opportunity set replenishing itself. That's a tough question to answer. It's not -- it’s unlikely that we're going to continue to see the need for a long haul pipeline out of the Permian forever
So we need to look elsewhere for growth which we've been able to do it with the diversified business. I would just point to our track record, we've historically said that we have over $500 million backlog in our development pipeline and we've been able to execute and bring projects across the goal line that are sufficient to maintain our growth, and when I look at our backlog at this point, we still feel that -- we still feel confident we're going to be able to do that in the future.
We’ll go next to David Amoss with Heikkinen Energy.
Just a couple of questions and I apologize for staying on the Permian, but if you guys have a forecast for the basin, the exit rate in 2018 would be really helpful for us? And then I guess the follow-up questions are, the $30 million worth of upside that you have in DCF with some spot volumes on those pipelines. How much spot are you assuming and for how long? And what would that be on an annualized basis in 19?
Well, I think, the upper end of that range is assuming that we essentially fill up Longhorn, which only has 10% of its space available for spot shipments. And then BridgeTex with spot shipments recognizing again that we only own half of BridgeTex, that are -- that $30 million would represent basically filling that up for the year. Now that -- that's just those two items. There's upside opportunities in other areas, commodity margins can improve, we can see continued strong growth in refined product demand. There’s a number of other areas that we have opportunity for upside. Those are probably the two most notable and those two alone can get us to that $30 million number. But it would be significantly utilizing the available spot capacity to get $30 million just from those two items.
And then any comments on your own internal production forecast that corresponds to the guidance you put out today?
Well, I can tell you we don't generate our own internal forecast. We use everyone’s and kind of make a judgment as to which ones are the most reasonable. So I don’t have an exit number to give you right now, unfortunately. So, I don't have that number for you.
Okay, thanks. And then one last one just if you could comment on what's driving the higher butane costs recently and how you see that playing out over the next couple of years?
Well, if you look at history, I think the biggest driver in the strength of butane pricing is availability to export significant quantities of butane. So we think that the markets adjusted to that. If you look at it forward curves, long-term, butane pricing versus gasoline pricing, we expect to see some widening, not significant, but some widening over the three year period. So we think we are at a low point.
And so the driver there is really going to be what’s the U.S. domestic growth in production for butane, which we believe to continue to be strong versus what’s the international demand for butane going to be, and we think that it’s -- there’s some probability when you look at those expectations that you would see butane prices not strengthening any better than where they are at right now. That’s only one part of the curve. The other part of the curve is gasoline pricing.
And with the forward crude oil forecast right now, we don’t see significant strengthening in gasoline prices. So that’s why we’ve built our guidance around a relatively flat margin over the three year time period.
We’ll go next to Danilo Juvane with BMO Capital Markets.
Thanks and good afternoon everyone. Just a quick follow-up, I know you can’t reveal what the re-contracted tariff that you have at Longhorn is embedded in guidance. But within the distribution growth spread that you outlined the 5% to 8%. Can you at least say where that re-contracted that you have in forecast is, is it at the low end of your expectations, is it at midpoint, or the high end?
Well the -- I would say that at the 5% to 8% assumes what I would consider probably the low end of our expectations on re-contracting. But you have to understand that’s not a variable, we want it’s done, it’s done. Once we set those rates which we are going to know here in the next few months as we re-contract, they are fixed, they will be fixed over the three year timeframe.
So we will be in a much better position three months from now or six months now we’d be more firm on what that distribution DCF growth looks like in ‘19 and ‘20. But right now we are assuming fairly low rates on being re-contracted. When I say fairly low, again I am not trying to give any percentage here.
They are lower than what the current rates are and they are consistent with the competitive market. But I hope you can appreciate that in the midst of renegotiating this in a highly competitive market we need to be a little sensitive on what we disclose with regards to what kind of rates we’re talking about.
And we’ll go next to Lin Shen with Hite.
So you just mentioned that Longhorn will be re-contracted for a fixed carry for three years contracted. I guess I’m going to ask that do you think three year is going to be a new normal for contract renegotiations for the crude pipelines and maybe also some kind of expectation for Permian contract life.
Well to be clear and if I gave you this impression I apologize, but I did not intend to say that we were signing three year contracts on Longhorn. I mean what I was talking about was our three year DCF guidance period and we would expect Longhorn to be contracted during that period. The term of the contracts are under negotiation, they’re not necessarily set at for three years with this point.
Okay. Got it. And also I think for 2018 your plan to finance mostly your CapEx is debt and also when I think about your long-term DCF coverage of 1.2 and also self funding being. How should we be think about your that EBITDA leverage for 2019, 2020?
Well, as we’ve said for a long time, our targeted maximum leverage ratio is around four times. So, as we look at 2018, we think we can fund what we have on the play right now and what we see over the next few years, what we’re currently constructing to fund that with debt and internally retain cash book and stay consistent with our maximum target. So, that’s what I would mention.
Going forward, we’re going to live within that four times limit, we think we can do that and fund everything with debt. We’re going to be caveat from a land or really big project we may have to revisit how we fund that, but at the end of the day the goal will be to maintain the balance sheet, maintain our leverage ratio at a healthy level. And we’re maintaining a one-two coverage ratio for the foreseeable future. We’ll pretty much be the right level for us to balance that.
And currently do you expect to your leverage going to be lower next year 2019?
No, leverage will continue to creep up throughout this year in 2018. So, currently we’re around 3.3 times debt-to-EBITDA at the end of 2017. We expect that leverage ratio to gradually increase throughout 2018 as we fund our growth closer to the four times level. And then once we get to our target, we’ll be our target.
We’ll go next to Jeremy Tonet with JP Morgan.
Hi. Just sort of a follow up question with regard to, do you incur that you have with the FERC, and if there is any update that you could provide us there as far as how that has progressed?
I don’t have any updates other than what you can read publicly. All the information I had is what’s been publicly filed. So, that’s I don’t have an update.
We will go next to Jerren Holder with Goldman Sachs.
So, I guess one of your recent presentations just talking about some doc opportunities in the Corpus Christi area or it looks like you have the opportunity to build for docs, assuming you were to get contracts and what not. Just how soon potentially that could you bring that potential project into service?
Well, our land in Corpus is actually fairly ideally situated right on the shift channel there for development. But it has nothing other than this at this point. So, it’s from a commissioning point to operations you’re probably looking at as a two year kind of timeframe.
Okay. And in terms of the CapEx for the four docs, I guess you need storage as well and maybe some other pipelines itself. I would imagine that not included in your $500 million of opportunities your factoring in then?
Well, remember we're in excess of $500 million.
Okay
And yes that would be in the category of potential projects that would be in the backlog. And just to give you a sense, I won't quote for you an actual capital cost, but the scope of it that the capabilities we have with the land would include four docks and up to 10 million barrels of storage. So that should give you kind of the sense what kind of capital opportunity is there.
I mean, is it fair like if we use the Seabrook sort of economics here you’re working on now, we can sort of use that as a better gauge in terms of that equivalent of what it could cost for that that type of project?
Sure.
Okay.
That would be a reasonable benchmark.
And we’ll go next to James Carreker with US Advisors.
Hi, I just wonder if you had any concerns about the new federal tax rate and the potential to over earn on your refined product pipelines or even your crude oil pipelines.
Well, we don't have any concerns with regard to that for two reasons. One, it's primarily an issue on the refined products system as opposed to the crude oil systems, most of the crude oil systems are contracted rates and so, it’s a little more complicated there, but on the refined products system which is really where the focus should be with regards to the tax change, again 60% of our markets are market based.
So they're not subject to cost of service regulation. The other 40% is subject to the index, the index is -- the current index is set to be in place for the next three years. So that should be pretty stable. But just when you look at Magellan system overall, if you look at our regulatory filings with regards to our cost of service estimates, we are under earning.
And if you take those same regulatory filings and you bring the tax allowance down to zero, which is not the case, but just to show an extreme case, if you took the tax allowance down to zero, we're still under earning. So we don't think we've got much exposure to the tax law change in our regulated rates.
And there are currently no more questions in the queue.
All right, well, thank you for your time today and we appreciate everyone's continued interest in Magellan. Talk to you later.
And this does conclude today’s call. Thank you for your participation. You may now disconnect.