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Ladies and gentlemen, thank you for standing by and welcome to the Magellan Midstream Partners' Fourth Quarter 2018 Earnings Results Conference Call. During the presentation, all participants will be in listen-only mode. Afterwards, we will conduct a question-and-answer session. [Operator Instructions] As a reminder, this conference is being recorded today Thursday January 31, 2019.
Now, it's my pleasure to turn the call over to Mike Mears, Chief Executive Officer. Please go ahead, sir.
Great, thank you. Good afternoon and thank you for joining us today to discuss Magellan's fourth quarter financial results and our outlook for 2019. 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, but actual outcomes could be materially different.
You should review the risks factors and other information discussed in our filings with the SEC and form your own opinions about Magellan's future performance. Despite the volatility in the energy space over the last year, Magellan's business fundamental have remaining strong and I'm please report, we generated record, distributable cash flow for 2018. Further, we grew our annual cash distributions in line with our 8% goal, while maintaining distribution coverage at a solid 1.26 times for the year.
You may notice in today's earnings that we have decided discontinued operation of our ammonia pipeline system later this year. And recognize and impairment associated with this decision in the fourth quarter. This system has been generating low operating margins for some time now and with the prospects of declining in anhydrous ammonia supply and continued high operating costs. Future operation of the system was not likely to be profitable.
I'll now turn 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 as well as the status of our larger expansion projects, before opening the call to your questions.
Thank you, Mike. During my comments today, I will be making references to certain non-GAAP financial metrics including operating margin and distributable cash flow. We've included exhibits to our earnings release to reconcile these metrics to the nearest GAAP measure.
Earlier this morning we reported fourth quarter net income of $314.1 million or $1.37 per unit on a diluted basis, which was higher than the $237.9 million or $1.04 per unit on a diluted basis reported for the fourth quarter of 2017. Excluding the impact of mark-to-market features contract activity in the current quarter, adjusted diluted earnings per unit was $1.03.
As discussed in the earnings release this morning and as Mike mentioned a moment ago, we've decided to begin the process of decommissioning our ammonia pipeline system which resulted in a $49.1 million impairment charge in the fourth quarter. Adjusted further for this impairment, our diluted earnings would have been $1.24 per unit and in line with the guidance we had previously provided.
First quarter distributable cash flow was $302.4 million compared to $308.3 million in the fourth quarter of 2017. DCF in the quarter was negatively impacted by approximately $9 million related to ammonia decommissioning costs as well as an additional $9 million related to our decision to write-off certain expenses to-date related to our previously announced Delaware Basin crude pipeline and planed fractionator in Frost, Texas.
For the year, 2018 was a very successful year. As Mike already mentioned, we set a record for distributable cash flow of $1.11 billion. Much of this outperformance was driven by higher crude oil pipeline volumes due to wide Permian to Houston market differential. But our refined product segment which still produces a majority of our distributable cash flow also performed very well setting an annual volume record. While in Marine segment was a state contributor to our overall performance.
I will now move to a brief discussion of the fourth quarter operating margin performance for each of our business segments. Our refined product segment generated $349.3 million of operating margin in the fourth quarter of 2018 compared to $216.2 million for the same period in 2017, an increase of $133.1 million. Much of this increase can be attributed to the favorable impact of unrealized mark-to-market gains, recognized on exchange traded futures contracts used to hedge our commodity related activities.
In periods when commodity product prices fall dramatically within a quarter which is what we experienced during the fourth quarter of 2018, we typically see larger mark-to-market gains related to our hedges, which we normalize out to only reflect realized activity in our calculations of distributed cash flow for a given period.
Transportation and terminal revenues increased $13.3 million compared to the fourth quarter of 2017 due to higher average tariff rates. In aggregate, volumes declined 2% compared to the fourth quarter of 2017 but it's important to put this in perspective. This overall decrease in volume is due to lower shipments on our South Texas system which moves at lower rates and as a supply driven portion of our system in the Houston area that has little relationship to how much volume we ultimately move on our higher tariff long-haul refined products pipeline systems
Within the core demand driven portions of our system in Texas in the Mid-Continent, volumes increased 2% compared to the fourth quarter of 2017 with gasoline being basically flat and distillate demand driving growth especially in our West Texas market.
Operating expenses were $17.7 million higher than the fourth quarter of 2018 compared to the 2017 quarter. Maintenance costs increased $12 million between periods due to the timing of work completed. We also wrote off three million dollars of project costs related to the previously planned Frost fractionator, as I mentioned earlier. Finally, personnel costs were higher as well.
Commodity margin increased by $125.5 million compared to the fourth quarter of 2017 due to non-cash unrealized gains related to our hedging program as mentioned a moment ago. Our cash product margin for the quarter was higher than the 2017 quarter due to higher realized butane blending net margins. Butane blending volumes declined between periods due to refinery turnarounds during the quarter.
Equity earnings from our Powder Springs joint venture increased compared to the 2017 period due to higher margins and volumes. For our crude oil segment current operating margin of $129.8 million was $12 million lower than the fourth quarter of 2017.
Transportation and terminal revenue increased by $11.9 million due to fees earned from new storage and ancillary services associated with storage capacity the Magellan leases from our joint venture, Seabrook Logistics and uses to offer storage and throughput services to our customer. We also earn higher revenue from our condensate splitter in Corpus Christi.
Revenue from crude oil pipeline movements was essentially flat compared to the 2017 quarter due to higher volumes being offset by lower average tariff rates. Volumes were 25% higher compared to the 2017 quarter with increased volumes on the Houston distribution system being the primary reason for the increase between periods the spot shipments on Longhorn also increased.
The average tariff rate declined due to a higher proportion of volumes on our Houston distribution system would earn a considerably lower tariff rate compared to Longhorn as well as lower average committed tariff rates on Longhorn which became effective in the fourth quarter of 2018.
Operating expenses were $25.3 million higher than the 2017 period. This increase resulted from higher fees paid to Seabrook Logistics for storage and services which Magellan utilized to then provide services to our customers. We also recognized $9 million of expenses related to the partial write-off of project costs for the Delaware crude oil pipeline project and the retirement of certain inactive tanks and our fishing terminal. Environmental remediation accruals also increased between periods and product gains were less favorable.
For the quarter, volumes in our Longhorn pipeline averaged about 275,000 barrels per day. While our equity earnings from our various crude oil joint ventures decreased $4.4 million compared to the fourth quarter of 2017, our joint ventures continue to perform well. The period over-period-decline results from a bit of an apples-to-oranges comparison to the fourth quarter of last year due to our sale of a portion of our interest in BridgeTex, which closed at the end of the third quarter of 2018.
After this transaction, the fourth quarter of 2018 would have been higher than last year's quarter due to higher spot and committed volumes on both, BridgeTex and Saddlehorn as well as higher storage and ancillary revenues generated by Seakbrook Logistics as a result of this most recent expansion and export capabilities coming online in the third quarter of 2018.
BridgeTex volumes averaged almost 415,000 barrels per day during the fourth quarter of 2018. Saddlehorn pipeline averaged nearly 100,000 barrels per day during the fourth quarter, as a result of the scheduled step up in commitment levels as well as additional volumes received due to recent joint tariff arrangements put in place to originate volumes into Saddlehorn from the broader Rocky Mountain crude oil market.
Moving now to the marine segment. The marine segment generated $30.7 million of operating margin in the fourth quarter of 2018 an increase of $4.6 million from the fourth quarter of 2017. Some of the revenue increase due to higher utilization compared to the 2017 quarter due to the 2017 period being negatively impacted by higher levels of out of service tank maintenance in part due to damage from hurricane Harvey.
Now moving to other net income variances the last year's quarter. Our G&A expenses were slightly higher as a result of higher personnel cost associated with higher headcount, and incentive compensation. Depreciation amortization and impairment expense increased as a result of new assets being placed into service as well as the $49.1 million impairment charge related to our ammonia system mentioned earlier.
Interest expense was $4 million lower than the fourth quarter of 2017 due to lower average outstanding debt balance. Our average interest rate of 4.8% was unchanged between periods.
I will now move to a discussion regarding our balance sheet and liquidity position. Including the current portion of the long term debt, we have $4.3 billion of long term debt outstanding as of December 31, 2018 and we had no outstanding commercial paper borrowings. Further, we had $218.3 million of unrestricted cash on hand at the end of the quarter.
Our leverage ratio was approximately 2.3 times debt to EBITDA as calculated according to our credit facility agreement. The current period leverage ratio was positively impacted by the BridgeTex transaction completed in the third quarter of 2018 as the proceeds were initially used to pay down debt as well as the gain being included in EBITDA for compliance purposes, if the pro forma of the impacts of this transaction, our leverage ratio would have been around three times.
As we continue to fund our current expansion capital program, we expect this ratio to remain below our longstanding maximum target leverage ratio of four times. Further we don’t expect to issue any equity through our current funding needs, and planned to fund our needs we're raising debt and using excess cash flow.
Accordingly, we issued $500 million of third year bonds in early January. This issuance along with cash on hand will be used initially to redeem the $550 million of 6.55% notes that were coming due in July of 2019. We also continue to maintain a credit facility totaling $1 billion which also back stops our commercial paper program.
I will now turn the call back over to Mike, to discuss 2019 guidance as well as our more significant growth project currently underway.
Thank you, Aaron. Earlier today, we announced DCF guidance of 1.14 billion for 2019. Our plan is to increase annual distributions by 5% for 2019, which is consistent with our previous guidance. Healthy distribution covers remains primary importance to us and we intend to maintain annual distribution covers at least 1.2 times for the foreseeable future.
As has become customary, we generally like to provide you with the key or substance we use to build up our projections for the New Year. So you have a better feel for how we see 2019 playing out. Starting with our refined product statement, we expect based refined product volume to remain relatively flat between years. Especially in light of record shipments in 2018 with the benefit of growth project we expect total refined products pipeline shipments to increase by nearly 5% in 2019.
These growth projects include more short-haul movements from both the new connection at El Paso added in mid-2018, as well as volume move to our new Pasadena joint venture Marine terminal that just became operational this month. And of course, our new East Houston to Hearne pipeline is expected to add volume once placed into service in mid-2019. The other key metric for refined product pipeline system is the average tariff we collect.
As you know, the current FERC indexation methodology is calculated as a change in the producer price index plus 1.23%. Based on the preliminary change in PPI for 2018, we expect the tariff increase to be about 4% for those markets that follow the index. Well, only roughly 40% of our refined product system is subject the indexation. We expect to increase tariffs in all of our refined products markets by the 4% FERC index on July 1, 2019.
For modeling purposes, please keep in mind there a point-to-point pipeline movements have an impact on the average rate that you see in our operating statistic. Even though, we intend to raise tariff by 4% in mid-2019, our overall rate for barrel is expected to remain relatively flat between periods such as significant portion of the projected incremental throughput is anticipated to be from short-haul movements as mentioned earlier, which move at a lower tariff rate.
The other key assumption significantly impacts refined product segment is a commodity price environment especially as it relates to our butane blending activities. We have about 1.5 of our expected 2019 butane blending sales volume hedged at this point with virtually all of our springs blending margin locked in.
We generally use the forward commodity price curve to forecast expected margin for any un-hedged volumes. We averaged plenty margins of around $0.40 per gallon during 2018 and expect margins to be similar in 2019. The 2019 margin estimate is based on hedges locked in for approximately 1.5 of our expected volumes and in early January forward curve for the un-hedged volume.
Moving to our crude oil segment, we expect shipments on a long-haul pipeline to average 260,000 barrels a day in 2019, which is less than 270,000 barrels a day move in 2018. Much of the 2018 period benefited from spot barrels due to the favorable pricing differential between the Permian Basin and Houston.
While these differentials are currently still favorable, they can be unpredictable and it has started to shrink considerably of late. As a result, we have assumed that spot barrel move on long-haul during the first quarter of 2019 only, with volumes moving closer to minimum commitments for the remainder of the year.
In addition, the average tariff of Longhorn is expected to be lower than 2018 as well due to the new contracts that became effective during the fourth quarter of 2018. As a reminder, following the recent contracts and the rules, the new average committed rate for Longhorn is roughly $2 per barrel with an average remaining contract life of five years.
For our Houston distribution system, we expect to see volumes to climb consistent with our assumption as spot barrels will not move beyond the first quarter of 2019. Even though, the Houston distribution system makes at more than 50% of the crude oil or transportation volume we report, the average tariff on the Houston distribution system is significantly lower than Longhorn at about $0.20 per barrel, so variances in volume generally will not have a material impact to DCF.
Combining these pieces, the overall approval tariffs for a wholly owned pipelined is expected to decline about a 5% primarily due to a full year of the lower average Longhorn committed rate to became effective in the fourth quarter of 2018.
Moving on the BridgeTex. As you know, we have recently expanded the capacity to 440,000 barrels per day. However, we use an average run rate of 425,000 barrels per day for forecasting purposes due to throughput variations resulting from different product rates and routine line maintenance.
Like Longhorn, we're forecasting in our based guidance spot shipments from BridgeTex move during the first quarter only. As a result, our 2019 projections as soon BridgeTex volumes to average around 350,000 barrels a day in 2019. For comparison, we moved 318,000 barrels a day in 2018 which benefited from spot ship as much as the year.
The Saddlehorn Pipeline is expected to move about 110,000 barrels per day during 2019 based on 70,000 barrels a day as committed volume as well as incremental volume from new joint tariffs, we recently put into place with a joining pipeline system to access more barrels from the DJ and Powder River basins.
We currently have 190,000 barrels per day of total capacity available on Saddlehorn and may very well be in a position to use all of that space in the near future. As a result, we're currently considering a further expansion of the Saddlehorn pipeline to add up to 100,000 barrels a day of additional space over the next year or two.
Concerning maintenance capital, we spent nearly $90 million during 2018 and expect the number to be closer to $95 million in 2009. Although you only see a line item for the capital component of our integrity program, Magellan spent significant time and effort each year to ensure the safety and reliability of our assets. Considering those capital and expense, we expect to spend about $230 million on maintenance and integrity work in 2019.
So those are the key building blocks us from our projections, resulting in DCF of approximately $1.14 billion in 2019. With our stated goal of 5% annual distribution growth for 2019, we expect to generate a healthy coverage ratio of 1.2 times, with more than $200 million of excess cash flow generating to reinvest in the business this year.
As mentioned earlier, our current DCF projections to simplify shipments continue on the Longhorn and BridgeTex pipelines during the first quarter of 2019 only. If spot shipments were to continue throughout the year, our DCS could increase up to $1.2 billion for 2019. At this time, we do not intend to provide financial guidance beyond 2019. However, we can reiterate our intention to target distribution coverage and at least 1.2 times for the foreseeable future.
With regard to expansion capital, we spent nearly $640 million on organic growth construction projects starting 2018. Based on the progress of expansion projects currently underway, we expect to spend $1.3 billion in 2019 with an additional $400 million in 2020, to complete the project now in progress. Specific to the Pasadena refined products terminal, we've placed the initial 1 million barrels of storage and related docs into service earlier this month.
We continue to make significant progress on the next phase of Pasadena which is comprised of 4 million barrels of storage with an additional dock expected to come online by the end of 2019. Discussions with a number of industry participants continuing for additional infrastructure for this new facility and we remain optimistic about future expansions to Pasadena.
Significant progress continues on $1 billion of construction projects for new refined products pipelines in the State of Texas. Construction is underway for our East Houston to Hearne pipeline that is expected to be operational in mid 2019.
Significant activity is also underway for our West Texas refined products pipeline expansion with right-of-way work in pipe steel production in process. Construction is expected to commence in mid 2019 with the West Texas expansion target to be operational in mid 2020.
As Aaron mentioned, in an effort to be more capital efficient, we are no longer pursuing our Delaware Basin crude oil pipeline from Wink to Crane on a standalone basis and are actively evaluating a lower cost solution that will meet the needs of our shippers.
The PGC joint venture pipelines deliver crude oil from the Permian Basin to the Gulf Coast region continues to advance with additional interest from new potential shippers. Concurrently, discussions are continuing with Exxon and Plains to assess the potential of a project combination.
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, potential project under development include expansion of the Saddlehorn Pipeline system as I mentioned earlier as well as the crude oil pipeline from Cushing to Houston.
The open season for this proposed Voyager pipeline was just extended to the end of March. Significant interest has been expressed from potential shippers especially those planning to reach Voyager from connecting carriers. However as is often the case, they need additional time to finalize their commitments across multiple pipelines.
We remain optimistic about these opportunities as well as a host of other projects that are earlier phases of analysis. While the project we assess come in all shapes and sizes, we remain committed to our capital discipline and continue to target an EBITDA multiple of 6 to 8 times for new investments.
That now concludes our prepared remarks. So operator, we’re now ready to turn the call over for questions.
[Operator instructions] And our first question comes from the line of Spiro Dounis with Credit Suisse. Please go ahead.
Just want to start up on CapEx, specifically on 2020, and how to think about backfilling that? And so when we think about it, what you think we expect to expect to see some of that $500 million or excess of $500 million convert in this 2020 CapEx, if you just give us a sense of what are some of the gaining issues, preventing some of these larger projects from being included?
Well, I think the simple answer is, all of those potential projects are in various states of negotiations to secure contract. So without going through the list of potential projects in detail, I'd say there are some projects that are closer to being initiated and rolling into that capital pool and there are some that are further away. So I don’t really have a breakdown on the timing. I would expect as the year goes you will be seeing us increased expansion capital forecast for 2020, but I don't have a schedule of exactly when that's going to happen.
Okay, no worries. And just with respect to distribution growth around 5%. I think like you said consistent with what you said in the past to maybe at the lower end of that 5% to 8% range. So just curious, what sort of driving you there? Is that a function of funding all this growth like you said? Or does that also relate to kind of what's going on in the market and maybe growth not being rewarded the way it used to?
Well, I think there is a little bit of all of that in there. I mean if you go through our assumption for 2019, we have taken a fairly conservative approach in our view with regards to guidance. Most notably, making building into our guidance no spot movement in our accrual pipes after the first quarter. Consistent -- with all consistent with that, we should probably be at the lower range of our distribution growth. And there are some elements of not getting paid for that came into that decision, but there is more of an element of that continuing to strengthen our balance sheet and keep higher levels of coverage.
And our next question is from Gabe Moreen with Mizuho. Please go ahead.
Mike, can you talk a little bit about, I think, walking a little bit away from the 2020 guide of 5% to 8% DCF growth that you gave back in November? Is it just Permian spreads coming in a bit more in dynamic, getting a bit more competitive of it sooner? Or are there any factors there that other factors beyond I guess crude oil prices and commodity prices also coming in since back you reported in November?
We spent a lot of time internally as to whether we should give 2020 guidance or not. And primarily under the concern that the market might take it as a negative, we're not intending report to be a negative. There are simply so many variables that for 2020 that are very hard to predict that we felt that wasn't prudent for us to put guidance out there. Those variables include, I mean a major component of those variable is what the Permian spread is going to be after many of these new-build types come into service later this year. That's just one variable.
You also have a wide range of commodity forecast that are out in the market, which directly affects our blending margins. And we also have another round of long-horn re-contracting that's going to occur into 2020. So, there is enough variables there that we didn't feel that was prudent for us to lock in or reaffirm 2020 guidance. But I don’t want that to mean that there is not reasonable assumptions within those variables that provide for very healthy growth in 2020, we don't feel this point to get comfortable giving guidance to that.
And then maybe if I can ask another two short ones. One is on the Plains' joint venture pipeline and partnering with your project. Should we read anything to their announcement earlier this week about FIDing it? Or is it just negotiations continue and hopefully something gets announced there in terms of combining the projects?
Well, I don't want to comment on reading anything in their FID. I mean, I think their FID stands on itself. What I can say in and of course, I can't say much about this other than to affirm that we are continuing discussions with them and they are proceeding. But that's really all I can say at this point.
Okay. And last one for me is this on the ammonia pipe, any thoughts to -- or feasibility to repurposing that pine in any shape or fashion?
We've looked at repurposing the ammonia system numerous times over the years. And the fundamental problem with the ammonia system is the maintenance capital and expense, the forecasted forward maintenance capital expense on that pipe really make it an economics to put it into any service. And so, there's really no option to do that.
And the next question is from Keith Stanley with Wolfe Research. Please go ahead.
Just looking at the 2019 DCF guidance, it's more like 3% growth year-over-year. Can you just talk about some of the drivers versus when you were previously talking to 5% to 8% growth year-over-year in 2019 that have changed?
Well, we've had a couple of things change. I think we had been up until recently making the assumptions that spot volumes are long-haul crude oil price will continue beyond the first quarter. Given the volatility in the market we've seen recently, we've changed that assumption. And so, clearly if you added quarter or two to our numbers, we will be probably in the previous guidance was given. And there's still a reasonable change that will happen. But again, given our conservative nature, we've not put that in our current guidance.
I think the other thing I'd highlight to is just from a simple math standpoint, that when we gave that guidance. We had, we exceeded our expectations for 2018. And so, if you're looking at a year-over-year improvement, you're starting with a base higher than what we had, what we were anticipating when we gave that guidance. I think the other component too here I think that, that we should highlight is that between the guidance we gave back in November versus today. We've had a significant decline in commodity prices, which impacts our blending business. So I think it's those things are really the primary compound of the change.
And on the ammonia business, can you say how much EBITDA and DCF is contributed I guess in 2018? Or is expected to contribute in 2019? Is there anything material at all that that's in your numbers from that business?
It's not material. I can tell you, I looked at the last three year average and it was less, I mean, the operating DCS impact of the ammonia system over the last three years was less than $3 million a year.
Next question is from Theresa Chen with Barclays. Please go ahead.
I wanted to follow up on your crude project activity in the Permian. So in regards to the cancellation of the Wink to Crane project as a standalone entity, does this mean that it could potentially become part of the PGC project? And at this point, what do you think the probability is that Longhorn line moves forward?
With regards to the Wink to Crane, we are still actively looking at a capital investment and capacity between Wink to Crane, but it'd not be as a standalone pipeline. And that's probably all I can say about that at this moment. And it would be a much, much lower capital investments and it would be a much more efficient way for us to source barrels into Longhorn for our customers. So that's actively being developed. Does I answer the question?
In the probability that the PGC project moves forward at this point?
We're actively progressing with PGC and continue in the process of acquiring right away and pursuing the project on a standalone basis. It's, we are still very interested in combining the project with Exxon and Plains. And so that is moderating that process a little bit, but we are still proceeding full steam ahead.
Do you have a timeline of when those discussions can be concluded the combination of the two projects?
It's bad business to try to forecast timing on negotiations. I can tell you that speaking for PGC, we would want to complete these as fast as we can. And we're operating under that scenario, but I can't really give you a prediction is when that's going to be included.
Okay. Just looking at the reiteration of your topic for 2019 and 2020 and books like your portion for that project is still included. Is that the case?
That's correct.
Okay. And then on BridgeTex, can you just remind us how much spot capacity is available? I guess like here post the final expansion taking you to 425?
I'm not sure I have that number on top of my head. Hold on that, I've got some folks here is doing the math for me, about 115,000 barrels a day.
Okay. And then what is the throughput on the system so far this quarter?
Was the throughput on BridgeTex this quarter?
Yes.
Are you talking about in the first quarter for the fourth quarter last year?
The first 31 days of 2019.
I'm not prepared to give you that number at this point.
Okay. No worries. Do you have your cash product margin for fourth quarter '18 and define product segment?
The cash margin for the refined product segment?
The product margin related to butane friendly.
You mean need for blending.
Yes.
For the year, it's around $0.40 a gallon. For the fourth quarter it was around $0.55 a gallon.
And our next question is from Jeremy Tonet with JP Morgan. Please go ahead.
Just want to come back to the 1.2 times coverage that you guys have been referencing before here. Is that just a number where it doesn't up pertain DCF in that kind of fit your equity needs for a year if you're spending 400 to 500 a year? Or is this -- how also that also I guess the distribution growth plan, if you're having a CapEx year, if you're spending a lot in the near term you know could it pick up after or you're looking to kind of manage to a steady growth rate? Just wondering, if you could kind of help us think through the process there?
So, when we think about our coverage ratio we're trying to make sure that is at a level that we’re properly funding our CapEx and also reflects to some extent how we see where we are in a particular business cycle. You may recall many years ago when we had very high commodity margins we actually allowed our coverage ratio to take up to almost 1.5 times for a while.
So, it is a combination of our spending needs along with where we are in a particular business cycle that helps to offset for any short term period of time what our coverage ratio targets would be. We feel long-term at least for the foreseeable future at least 1.2 is as a good place for us to be, but it could be higher than that during periods of time.
And I think the past you guys have discussed possible pipe connectivity between Houston and Corpus, any updated thoughts that you could provide there?
I don’t have an update. I can tell you we’re still working on it, but I don’t have an update.
One last one for me, guys. Just wondering, you talked at the Analyst Day at bit and if you had any updates thoughts with regards to the possibility of converting to C-Corp, if you kind of see limitations in the MLP space, it seems like you kind of hit up against index max's there and if that plays into your thought process?
We keep the idea of converting to a C-Corp on under evaluation all the time. From our perspective, just making sure we’re doing our jobs appropriately that something we need to keep our eye on, so we do. The reality of it is given we don’t need to raise any equity. We can fund our growth with excess cash flow and raising debt. We feel like we have what I would consider a really powerful option here. And when you combined that option with the data that we see which is arguably not very conclusive that if you were to convert to a C-Corp that you necessarily see a valuation benefit from that.
And if you take that uncertainty, that’s the real motivator of converting and trying to get additional demand from your units and increase the price for that with a broader investor base. We understand that, but we have to believe that against the fact that when we convert for us it would -- not for us for everybody it's permanent. You don’t get to rewind the clock. So when you looking at having to make a very permanent and impactful decision, over the long-term and just propose that with the uncertainty of whether you’ll benefit from it, to us that means you need to be cautious and patience, which is steps that we’re taking.
And the next question is from Jerren Holder with Goldman Sachs. Please go ahead.
Maybe starting with the Delaware Basin project that you guys canceled. I noticed CapEx guidance necessarily changed. Was there something else added to the backlog? Or how should we think about what was factored in for guidance for CapEx there?
Well, I mean our actual total capital spending did change. What's misleading is if you look at our guidance for '19 and '20, it's consistent with what we were previously guiding. But if you look at '18, we significantly underspent our guidance for '18. So that's really where you see the variance.
And then at what point in time, do you think the buyback program -- unit buyback program can make sense for Magellan?
Well, buyback program is something that we consider and we're not in a position to do that today. We think that we've got better usage of our capital at this point to deploy on the growth projects we have in front of us. So we're not planning on a buyback. If we reach the point in time, where I guess one of two things, we either build more excess cash and we have valuation on our equity that we think that's a good usage of cash to buyback our units then we would consider at that time. But we will consider it at that time, but we're not in that environment at this point.
And the next question is from Dennis Coleman with Merrill Lynch. Please go ahead.
Wonder if I might just try one on PCG again. In terms of the discussions between you and the Plains-Exxon Group, can you talk about what's being negotiated? Obviously, it has to be win-win for both, and what they came out with seemed to identify a certain path? I mean, is it right of way or where the pipeline might go volumes? Anything you might be able to talk about there would be helpful.
Well, as much as I've like to I can't unfortunately. Now, I like to do is tell you that we are in discussions. But hopefully you can appreciate, there is multiple parties sitting around the table in these discussion. And the confidentiality is important to a lot of those parties including ourselves. And so that's all I can say at this point.
Okay, but give us a shot there, thank you. I guess maybe just on the Voyager announcement and the extension of the open season. How should we interpret the extension out to the late March date?
I think you should that interpret that as the normal course of events. It's a very competitive market. And parties that are interested or considering commitments often times ask for more times. And that's how you should interpret it. The caveat I'll add to that though is that, until we have commitments, we don't have a project. And so -- but we wouldn't be extending it, if we didn't think that there was a significant likelihood that we can get those commitments.
And then, one just a little bit more detailed, if I can. On the adjustments to DCF that you talked about the 9 million for ammonia and 9 million for the other projects, just where exactly is that coming through the income statement. Is that in the DDNA line, it looks like that's probably where it is?
Where you will see the adjustments, so if you talk about the ammonia, the $9 million is a subset of the $49.1 million total impairment charge. So that's where you'll see it on the income statement. And then on this other $9 million, where you'll see those coming through are in the operating expenses of the particular segment, for instance, for the fraction area. You'll see that coming through other refined products operating expenses. And then for the Wink to Crane, you'll see that coming through the crude oil segment operating expenses.
And the next question is from Shneur Gershuni with UBS. Go ahead.
Sort of beat on the whole PGC Pipeline again, but I do have slightly different questions. In the past you've talked about having enough commitments to move forward. Are you able to give us some color around the credit quality of the customers that have committed? And are they binding or the still evaluating other projects?
They are binding commitments and say and the credit, I mean, there's a range of credit there, but generally it's a strong credit.
You said something in, I believe in your prepared remarks about how customers are evaluating other projects as well to. Did I miss here that or was that correct?
What I said and I think you did miss here that is that we are talking through incremental potential shippers on the PGC in addition to the commitments we already have.
So, the one that you have in place right now are strong credit quality customers?
Yes.
With respect to the shutdown of the ammonia pipeline, I believe you said to a previous question that, it was less than $3 million a year in DCF. But you'd also mentioned in one of your other responses that part of the issue with repurchasing at, I believe, it was the Gabe's question. As you mentioned that, it was really about the maintenance CapEx with so high on it. Can you give us some color on the maintenance CapEx for this pipe -- for the ammonia pipeline? And does that impact your expectations for maintenance CapEx on a go forward basis?
Well, I mean how to parse through question there. It is true that the maintenance capital and expense costs are significantly higher on the ammonia system than really any other pipe we've got. And a lot of that forward forecasting. So when we look at -- so another way of saying that, our historical costs of at high, but our future costs are expected to be even higher than that. So we -- back to your question exactly how much maintenance capital was, I think we spent -- I'm trying to look at some notes here.
Our total cost, I'm sorry, I don't have all that information, right in front of me. So I'm trying to find it. Our total asset integrity, our expense cost and our capital cost on average historically is probably in the just ball parking an average here. I'd say $10 million a year range on the system. And when I look out to 2020 and beyond that number was forecast to go up significantly.
Okay, that makes sense, very final question.
I was going to say, sorry for bouncing around on you like that, but I was trying to find all that information.
Yes, that's totally appreciated. Just a couple more clarification. With respect to Saddlehorn, you've talked about potentially 100 of expansion. Would that be 100% on Saddlehorn or would that be in combination with Grand Mesa that’s a NGL?
It would be 100% on Saddlehorn.
And so, it's a 100% your capacity.
Correct.
And then just to clarify the results that you're actually reported to that. The adjusted EBITDA number that was in the press release, did that include the, we'll call it one-time or lumpy items with the write-offs in it and so the number was actually higher on a clean basis? Or was the adjusted EBITDA number to green number?
The adjusted EBITDA number includes the write-offs we talked about today. The only thing that it doesn't show up in there is the again on BridgeTex which we exclude for DCF purposes, but the other write-off items we talked about is in that number.
So clean number will infect be higher then?
Yes.
And the next question is from Elvira Scotto with RBC Capital Markets. Please go ahead.
Just a couple of clarification questions. So, with the write-off that you've discussed today, all else equal, OpEx for crude oil and refined products, should actually be lower kind of going forward for modeling purposes. Is that correct?
Yes.
And then again, I just wanted to clarify that last question the adjusted EBITDA number of $374 million, you're saying does it include $49 million of impairment or have you excluded that?
Let me try and be clear, that number does not include the $49.1 million. It does include $9 million of that $49.1 million related to ammonia. It also…
It's helpful.
Yes, I apologize if I wasn't clear. It also includes the amount we wrote-off related to Frost, and it also includes the amount of wrote-off related to the Cushing tanks and then also the Wink to Crane line. So, the only thing that's not reflected in there is essentially the noncash portion balance of the ammonia write-off.
And then as you think about the Voyager Pipeline and how competitive that building pipe from Cushing down to the Golf Coast? Is there any opportunity for Voyager to combine with any other competing pipeline similar to the discussions that you’re having on PCG?
I’d say our mentality and our focus here at Magellan is always to be capital efficient when an opportunity to be capital efficient is available. So that is available we would be open to considering it.
And then just the last one for me is, do you have any updates in the past you talked about potential exports facility capable of alluding VLCCs at Harbour Island, Corpus Christi. Do you have any update you know you’re still at the project any update there would be helpful.
Yes, really, all I can say at this point, we’re looking at that, we’re also looking at other options, it’s a very dynamic environment. And we’re looking at a number of things, but we don’t have any updates on any of at this point.
And gentlemen, those are all the questions we have for today, and I’ll now turn it over back to you for any closing remarks.
All right, well thank you for your time today and thank you for your interest in Magellan. Hope you have a good afternoon.
And ladies and gentlemen that does conclude our call for today. We thank you for your participation, everyone. Have a great rest of your day and you may disconnect your lines.