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Magellan Midstream Partners LP (NYSE:MMP)
Q4 2019 Earnings Call
Jan 30, 2020, 1:30 p.m. ET

Contents:

  • Prepared Remarks
  • Questions and Answers
  • Call Participants

Prepared Remarks:

Operator

Greetings everyone, and welcome to the Magellan Midstream Partners Fourth Quarter Earnings Conference Call. [Operator Instructions] Afterwards, we will have a question-and-answer session. [Operator Instructions] As a reminder, this conference call is being recorded today, Thursday, January 30th, 2020.

It is my pleasure now to turn the conference over to Mike Mears, Chief Executive Officer. Please go ahead, sir.

Michael N. Mears -- Chairman, President and Chief Executive Officer

Good afternoon, and thank you for joining us today to discuss Magellan's fourth quarter financial results and our outlook for 2020. I must 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 risk factors and other information discussed in our filings with the SEC and form your own opinions about Magellan's future performance.

Before we discuss earnings, you may have noticed that we announced last week our intention to sell three of our marine terminals for $250 million. This transaction was a result of a continuous evaluation of our existing assets. We are always looking for ways to optimize our portfolio and the divestiture of assets outside our strategic footprint is an important element of our capital discipline. We believe the price is attractive with these three locations contributing cash flow in 2019 of less than $20 million on a combined basis.

As part of that same news release, we also announced our board has authorized us to repurchase units on an opportunistic basis. And I will discuss our intentions around this new buyback plan a little later in the call.

Turning to financial results for 2019, Magellan closed out the year with another strong quarter, generating record DCF for both the quarter and the year. Annual distribution coverage was higher than usual for our company at 1.4 times generating nearly $370 million of excess cash flow. Our CFO, Jeff Holman will now review Magellan's fourth quarter financial results in more detail then I'll be back to discuss the status of our larger expansion projects, our guidance for the year and how we think about capital allocation before opening the call to your questions.

Jeff L. Holman -- Senior Vice President, Chief Financial Officer and Treasurer

Thank you, Mike. Before I begin please note that I will be making references to certain non-GAAP financial metrics, including operating margin and distributable cash flow. We have included exhibits to our earnings release that reconcile these metrics to their nearest GAAP measures. Earlier this morning we reported fourth quarter 2019 net income of $286.4 million or $1.25 per unit on a diluted basis compared to $314.1 million or $1.37 per diluted unit in fourth quarter 2018. Excluding the impact of mark-to-market activity, fourth quarter 2019 adjusted diluted earnings per unit was $1.31, which exceeded our guidance for the quarter of $1.13. Distributable cash flow for the quarter was $357.8 million, $55.4 million higher than fourth quarter, 2018, driven primarily by strong results from both our refined products and crude oil segments.

I will now discuss the performance of each of our segments in turn starting with our refined product segment. Refined products generated $264.9 million of operating margin in 4Q '19 compared to $349.3 million in the prior year period. As noted in our earnings release, the lower 2019 figure primarily reflects the impact of mark-to-market adjustments for hedge positions related to the partnership's commodity-related activities.

Excluding these adjustments, operating margin for the segment increased approximately $16 million over the 2018 period. Transportation and terminals revenue for the segment increased $2.8 million. Refined products transportation rates increased primarily as a result of the mid-year tariff escalation of 4.3% while volumes increased largely due to our East Houston-to-Hearne project, which came online in late third quarter of 2019. These higher revenues were mostly offset by the absence of ammonia revenues following the termination of the ammonia service in second half 2019.

For the year, total refined products volumes increased approximately 1%. Base volumes across our system declined slightly, beating the volume contributions from growth projects. I'll note that if you look at our total shipments by product for the full year 2019, which includes volumes from growth projects, gasoline appears to have decreased a little over 2%. However, most of the decrease in gasoline volumes occurred in the South Texas portion of our system, which as we've noted previously experiences more volatility in both product mix and overall demand and which has significantly lower tariffs than most of our system, such that variations on this portion of our system have relatively low impact on our overall revenues.

Excluding both this portion of our system and growth projects, base gasoline volumes decreased approximately 1% in 2019 while base distillate volumes were essentially flat. Operating expenses for the refined products segment were $10.7 million lower in the current period, primarily due to lower integrity spending as a result of the timing of maintenance work as well as lower asset retirements, partially offset by lower product gains, which reduced operating expenses.

Product margin decreased $93.9 million compared to 4Q '18, primarily due to higher unrealized gains in 2018 on futures contracts used to hedge future product sales. Excluding these out of period items, product margin for the refined products segment increased approximately $7 million, primarily as a result of higher sales volume in the current period from our butane blending activities.

Moving now to our crude oil segment, fourth quarter operating margin of $151.3 million was $21.5 million higher than fourth quarter of 2018. Crude oil transportation and terminals revenue increased $7.4 million primarily due to higher storage utilization and higher ancillary revenues. Our crude oil transportation volumes also increased in the current period with most of the increase resulting from higher volumes in our Houston distribution system.

As we have seen throughout 2019, the increase in Houston distribution volumes which move at lower rates than longer haul Longhorn shipments contributed to the decline in the average rate we reported for our wholly owned crude oil pipelines. Lower spot volumes on Longhorn in fourth quarter '19 also contributed to the decrease in average rate between periods. Volumes on Longhorn were slightly lower in the current period at approximately 275,000 barrels per day versus about 280,000 barrels per day in fourth quarter 2018.

As anticipated, lower price differentials between Midland and Houston resulted in our not receiving any spot nomination during the recent quarter. However, some of the resulting available space were used by our committed shippers and some was used by our own marketing affiliate. As a reminder, revenues from those marketing activities are reflected as product sales in our consolidated income statement.

Beginning this quarter, we have included the volumes associated with our affiliate marketing activities in the operating statistics quoted in the financial schedules that accompany our earnings release. Operating expenses for the crude oil segment decreased $15.6 million, primarily due to lower asset writedowns in the 2019 period as well as lower integrity spending and lower environmental accruals. Crude oil equity earnings decreased slightly between periods, as lower contributions from BridgeTex offset higher Saddlehorn earnings.

Saddlehorn equity earnings were higher, primarily as a result of new commitments received in connection with the expansion of the Saddlehorn pipeline. Saddlehorn volumes averaged approximately 180,000 barrels per day in the quarter compared to approximately 100,000 barrels per day in the prior year period. Higher average BridgeTex volumes of approximately 425,000 barrels per day compared to approximately 415,000 barrels per day in fourth quarter '18 were offset by lower average BridgeTex rates. As the lower Midland to Houston differential already mentioned discouraged movements at the posted spot tariff and the resulting available space was filled with volumes shipped pursuant to other tariff arrangements.

Finally, to wrap up the discussion of our performance by segment, our marine segment generated $32.9 million of operating margin, an increase of about $2.3 million over the 2018 period. Revenues were $1.4 million higher, primarily due to increased ancillary revenues at Galena Park, slightly offset by lower rates on storage contract renewals, particularly at Wilmington. Equity earnings for the marine segment increased approximately $1 million as a result of higher earnings at our Pasadena joint venture while commodity margin for the segment increased $1.8 million. These increases were partially offset by higher tank integrity spending and higher operating taxes.

Moving now to other variances to last year's quarter, depreciation, amortization and impairment expense decreased $38.2 million between periods, primarily because the 2018 period included the impairment of the ammonia pipeline system, while G&A expense was essentially unchanged between periods. Net interest expense was $3.5 million higher in the current quarter due to higher average debt outstanding as a result of borrowings made to finance our growth projects, partially offset by a lower average interest rate.

Our weighted average rate was approximately 4.6% during the fourth quarter and our average debt outstanding was $4.8 billion. As of December 31st, 2019, the face value of long-term debt outstanding was $4.75 billion and we had $58 million of cash on hand.

[Indecipherable] balance sheet metrics and liquidity, our leverage ratio for compliance purposes was approximately 2.8 times at the end of 2019. Our expectation that we will fund all of our forecasted growth projects with retained excess cash flow and debt while staying well within our long-standing 4 times leverage limit remains unchanged. In light of our significant available liquidity and lower growth capital forecast, we recently terminated our $500 million 364 day credit facility.

In addition, we allowed the shelf registration for our at-the-market equity issuance program to expire and renewed as we consider it unlikely that we will need such a program in the next several years. We continue to maintain our multi-year credit facility with capacity of $1 billion, which is currently undrawn.

I will now turn the call back over to Mike to discuss guidance for 2020.

Michael N. Mears -- Chairman, President and Chief Executive Officer

Thanks, Jeff. Turning to our outlook for the new year, we announced DCF guidance of $1.2 billion for 2020. While lower than our DCF generation in 2019, you may recall that our '19 results significantly exceeded initial expectations for the year. These positive variances included significantly more crude transportation revenues than expected due to the favorable Permian differential for most of the year and more favorable butane blending margins than expected, both of which have now retreated closer to our original expectations.

In addition, 2019 also benefited from material one-time insurance recoveries and a one-time gain on the sale of our ownership in the discontinued Wink to Crane pipeline project. As usual, I'll now walk you through the building blocks we used for our 2020 projection, so you still have a better feel for how we are thinking about the new year.

Starting with our refined products segment, we expect base refined products volume to remain relatively flat between years. Similar to our base business in 2019 and further emphasizing the stable nature of our refined products pipeline systems. With the upcoming benefit of recent growth projects that expand our Texas capabilities, we expect total refined products pipeline shipments to increase closer to 10% in 2020. These growth projects include a mix of short-haul movements from our new East Houston-to-Hearne pipeline that began operations in late 2019, as well as our West Texas expansion that represents the higher tariff movement once placed into service in mid-2020.

In addition to volume, the average tariff rate for our refined products pipeline system is an important component to model this segment. The tariff adjustment to occur on July 1st, 2020 is the fifth and final year to use the current FERC index, which is based on the change in the PPI plus 1.23%. The preliminary change in PPI for 2019 is less than 1%, resulting in an index rate adjustment of right at 2% for the 40% of our markets that follow the index. However, the remaining 60% of our refined markets are not subject to the index methodology because they are either intrastate movements or deemed to be competitive by the FERC.

As a result, we can adjust rates in these markets as competitive forces allow. Our commercial team is analyzing each of the relevant markets at this time, but we generally intend to increase rates in our competitive markets by 3% to 4% in mid-2020 similar to our historical approach. For modeling purposes, please keep in mind that our point to point pipeline movements have an impact on the average rates that you see in our operating statistics. Even though we intend to raise tariffs, an average of around 3% in mid-2020, our overall rate per barrel is expected to remain relatively flat between periods. This is because a significant portion of the projected incremental throughput is expected to come from shorter haul movements that ship at a lower tariff rate.

Because this is the final year for the FERC's current index, the FERC will be working to determine what the appropriate index will be for the next five-year period beginning 2021. As soon as the FERC Form 6s are filled with the various refined products and crude oil pipelines in the late spring of this year, the cost data from those filings will be compiled and used by the FERC to set the index for the next five years. As usual, the pipeline industry will be taking a very active role in this process to continue educating the Commission about the index and how it impacts our industry, especially in light of continued turnover at the agency.

At this time, there is no new information to report on how they plan to incorporate the MLP income tax allowance change from two years ago into the new index calculations. But we don't believe it will have a material impact based on our internal evaluation that we publicly shared at our 2018 Analyst Day. The other key assumption that significantly impacts our refined products segment is the commodity price environment, especially as it relates to our butane blending activities. We have about one half of our expected 2020 butane blending sales volume hedged at this point with virtually all of our spring blending margin locked in.

We generally use the forward commodity price curve to forecast the expected margin for any unhedged volumes. Based on final results blending margins ended up averaging around $0.60 per gallon during 2019. Of note, this was the best margin we've seen in four years, primarily due to the lower butane pricing environment that favorably impacted our blending profits. Considering the hedges locked for approximately half of our total expected volume and a mid-January forward curve for the remaining unhedged volume, we currently expect average blending margin of $0.50 per gallon for 2020.

Moving to our crude oil segment, we'll set the stage by reminding you that the pricing differential between the Permian Basin in Houston is not expected to be sufficient to encourage spot shipments on either Longhorn and BridgeTex pipelines in 2020 or the next few years after that for that matter. As a reminder, both systems benefited from spot shipments from much of 2019, resulting in greater volume at a much higher spot tariff rate of around $4 per barrel and we do not expect that to reoccur in 2020.

Addressing Longhorn first, we are pleased to advise we have made substantial progress on recontracting the Longhorn capacity that was set to expire in the fall of 2020. As a reminder, approximately half of the commitments at Longhorn or about 130,000 barrels per day elected to renegotiate new long-term agreements back in late 2018 when the initial contracts expired. Those new contracts had an average life of about eight years at that time. So, closer to seven years at this point.

Shippers representing the remaining 50% of the volume chose a two-year extension, which is set to expire in late 2020. We have been actively negotiating with potential shippers for some time to fill that space with our preference being to have longer-term agreements even if that requires accepting marginally lower rates for long-term cash flow certainty. To that end, we are pleased to have recently signed a new 10-year take-or-pay commitment with a quality counterparty that substantially reduces our recontracting risk. The volume commitment in this new agreement ramps up over the next few years. As a result Magellan's marketing affiliate will step in to facilitate inter-stage shipments and we have secured multi-year fixed differential agreements with third parties to backstop our affiliate shipments to bridge the gap during the ramp-up period.

The portion of our marketing affiliate shipments that are back-stopped by third parties are considered in our analysis as committed volume on Longhorn. The bottom line is that we are making excellent progress to term up capacity on Longhorn with this new long-term agreement, taking substantial risk off the table. Specific to 2020, Magellan expects total committed volume to average approximately 230,000 barrels a day on Longhorn. Based on commitments secured to date, committed volume on Longhorn over the next five years is expected to average nearly 200,000 barrels per day.

We remain in active negotiations to secure additional commitments to lock in the remaining uncommitted space, both short term and long term. And based on these discussions and the projected forward differentials, we expect Longhorn to be essentially full in 2020. As expected, the average tariff for Longhorn going forward will be lower than 2019 as a result of the new committed volume and affiliate marketing agreements.

We are not disclosing the differentials that have been agreed to with third parties within our marketing affiliate, which equates to about 40,000 barrels per day of the 230,000 barrels a day of committed volumes in 2020. Excluding those affiliate shipments and based on the current status of contract renewals, the all-in average committed rate for the approximately 190,000 barrels per day of third-party committed shipments for Longhorn in 2020 is expected to be roughly a $1.95 per barrel with the current average remaining contract life of seven years. Negotiations continue for the remaining uncommitted space and we will provide updates on future average committed rates once the recontracting process has run its course.

Moving on to BridgeTex, we expect shipments to average approximately 400,000 barrels a day during 2020 compared to nearly 430,000 barrels a day in 2019. Again, the differential is such that spot shipments are not motivated to move between the Permian and Houston. As a reminder, commitments take up approximately 80% of the pipeline's capacity with an average remaining life of five years and BridgeTex has taken proactive measures to incur additional movements in this environment for the use of incentive tariff rates.

The Saddlehorn pipeline is expected to move more than 180,000 barrels per day during 2020. Due to new commitments received in conjunction with the pipeline expansion, there is currently in process and expected to come online in late 2020. Once the expansion is complete, Saddlehorn will be capable of transporting 290,000 barrels per day with effectively three-fourths of this full capacity secured with new long-term commitments for seven years.

Switching to the marine terminal segment, we expect phase two of the Pasadena expansion to be operational during the new year, which will be partially offset by the pending sale of three of our marine terminals that we've indicated contributed cash results of less than $20 million in 2019 on a combined basis.

Concerning maintenance capital, we spent a little over $95 million during 2019 and expect to spend a similar amount again in 2020. Magellan spent significant time and effort each year to ensure the safety and reliability of our assets. And considering both capital and expense, we expect to spend more than $240 million in total on maintenance and integrity work in 2020. So, in summary, those are the key assumptions we have used to build up to our 2020 DCF guidance of $1.2 billion.

Turning now to distribution growth, managing our business in a prudent manner for the long-term benefit of our investors remains our top priority. While our business has continued to perform very well and demand for our services remained strong, our outperformance in 2019, as was mentioned earlier, was driven in part by favorable conditions for our crude oil business that we do not think are likely to persist. In light of this, we plan to increase annual distributions by 3% for 2020, which we believe is more in line with our inherent long-term growth profile in a low expansion capital environment. We plan to achieve this goal with the $0.0075 quarterly increments, consistent with our 2019 approach.

With DCF of $1.2 billion and 3% annual distribution growth targeted for 2020, we expect to generate distribution coverage of 1.25 times, which results in more than $240 million of excess cash flow that can be used to reinvest in the business or otherwise create additional value for our investors.

At this time, we do not intend to provide financial guidance beyond 2020, however, based on continued investor feedback that higher distribution coverage remains of high importance to them, especially in light of the volatility within the energy space, we intend to target distribution coverage above 1.2 times for the foreseeable future. While we continue to evaluate well in excess of $500 million of potential organic growth projects that would create incremental value for our investors, the reality is that we will most likely be in a lower capital spending environment over the next few years. So, I'd like to spend a few moments discussing our capital allocation strategy.

Our first priority will continue to be to invest in attractive high quality growth projects. In saying that Magellan remains committed to our long-standing approach to capital discipline and only plan to move forward on new opportunities if they meet or exceed our targeted 6 times to 8 times EBITDA multiple threshold and they are appropriately adjusted for risk and long-term sustainability of cash flows. To the extent opportunities of this nature are indeed lower especially in light of the current competitive environment, we believe that excess cash flow can be returned to investors utilizing other tools including unit repurchase program or special distributions.

As announced last week, our board has authorized us to repurchase up to $750 million of units over the next three years. To clarify, we do not deem this to be a defined program with a set schedule but rather intend to use the plan opportunistically -- to opportunistically purchase units from time to time. In addition, we also believe that payment of a special distribution while not talked about much in the midstream space could make a lot of sense as well, returning cash to investors immediately in a very tax-efficient way.

I know that a number of you have been curious to know if we have a formulaic approach in mind for when each of these levers could be pulled. The short answer is no, we do not have a formulaic approach. What we do intend to do is engage in a point in time analysis using a deliberate long-term value focused approach, taking into account our outlook for capital spending, our liquidity and leverage and our leverage position at the time and our valuation. The bottom line is that we remain focused on maximizing value for our investors and our employees with a number of attractive tools available to us, including capital projects, a buyback program and potential special distributions to opportunistically increase value to our unitholders.

That now concludes our prepared remarks. So, operator, we can open up for questions.

Questions and Answers:

Operator

Thank you very much. [Operator Instructions] And our first question comes from the line of Jeremy Tonet with J.P. Morgan. Please go ahead.

Joe Martoglio -- J.P. Morgan -- Analyst

Hi, this is Joe on for Jeremy. I wanted to start off with asset sales and it kind of seems like the recent asset sales you completed were kind of non-core to the business. Are there any other assets you have in mind where that kind of represent stuff out of your footprint? And can you talk about I guess maybe kind of valuations you're seeing and kind of things you would explore there?

Michael N. Mears -- Chairman, President and Chief Executive Officer

Well, I'm not going to talk about any specific assets we may or may not be looking at. But right now I can tell you that we routinely evaluate our portfolio and make determinations as to whether or not there is portions of our business that may be have higher value elsewhere. Probably not going to comment more on that specifically. I will say though as a reminder that we do -- that we are likely to sale a -- sell a portion of our Saddlehorn pipeline later this year. As you recall, third-party as an option to purchase that and our expectations are they will exercise that and do that. So, that is likely upcoming. And just as a point of reference that reduction of income from that sale is embedded in our plan.

Joe Martoglio -- J.P. Morgan -- Analyst

Okay. That's helpful. And then I also wanted to dig in a little more on the buybacks, you mentioned both a special distribution and a buyback. I wanted to see if any scenario mix one of those situations more likely than the other and kind of you also had kind of an intrinsic value in your head where you would kind of accelerate buybacks or other things for execution?

Michael N. Mears -- Chairman, President and Chief Executive Officer

Well, valuation in our mind is an important element of determining whether we buy back units or issue a special distribution, but evaluation analysis [Phonetic], this is always a point in time calculation. And so we don't have a number out there that's what's going to trigger this. And even if we did, we probably wouldn't be talking about it. But -- so, that's how the process is going to go. I mean, when we reach a point where we feel like something is actionable one way or another then we'll make a value judgment as to what we think the best return of value is to our unitholders, whether it's a buyback or special distribution and make a decision at that time.

Joe Martoglio -- J.P. Morgan -- Analyst

That's helpful. Thank you. That's all from me.

Michael N. Mears -- Chairman, President and Chief Executive Officer

Thanks.

Operator

And our next question comes from Tristan Richardson with SunTrust. Please go ahead.

Tristan Richardson -- SunTrust -- Analyst

Good afternoon, guys. Just a question, can you just talk about commodity related activities...

Michael N. Mears -- Chairman, President and Chief Executive Officer

We can't hear you. Can you speak up or get closer to...

Tristan Richardson -- SunTrust -- Analyst

Apologies, is this better?

Michael N. Mears -- Chairman, President and Chief Executive Officer

Much better.

Tristan Richardson -- SunTrust -- Analyst

Sorry about that. And just with respect to your commodity related activities contributing less than 15% of the operating margin, does that include activities by the marketing affiliate in the crude business and/or the marketing affiliate activities that are backstopped by third parties, just kind of curious about that 15% or less than 15% number.

Michael N. Mears -- Chairman, President and Chief Executive Officer

Well, historically, we've quoted that really just based on our blending business. I don't know if we've run the math on that to determine whether that's...

Jeff L. Holman -- Senior Vice President, Chief Financial Officer and Treasurer

We have and it's probably still under 15%, but we need to run it, and that's what exactly that ends up being will depend a little bit on how the year goes as well. But that number we quoted was not specifically designed to incorporate the marketing activities.

Tristan Richardson -- SunTrust -- Analyst

Very helpful. Thanks. That's in our mind. Thank you.

Operator

And our next question comes from Shneur Gershuni with UBS. Please go ahead.

Shneur Gershuni -- UBS -- Analyst

Hi, good afternoon, everyone.

Michael N. Mears -- Chairman, President and Chief Executive Officer

Good afternoon.

Shneur Gershuni -- UBS -- Analyst

I was wondering maybe we can start off on the buybacks that again, just kind of want to understand philosophically how you're thinking about it, you have slowed your distribution growth rate, obviously you're trying to match up, how you see things with your business in targeting a higher coverage ratio? When I think about the authorization just like the simple math right now you can eliminate effectively 5% to 6% of your units outstanding, which would then allow you to recycle that capital back into or save the distributions into a higher growth rate. Is the idea that we should be thinking about it is that you'd like to target kind of the same type of growth rate longer term where you had been previously is just it's going to be now in a form of buybacks and a lower distribution growth rate, could we see something like a 5% increase in total return of capital to unitholders 3% by distribution and let's say 2% via buyback, just kind of wondering how you're sort of thinking about it philosophically without giving us the price or anything of the sort?

Michael N. Mears -- Chairman, President and Chief Executive Officer

Well, I think, we don't think of it that way, I think, the math may work out that way and I haven't run the math. So, I don't know, but it may work out that way. I mean, if you assume that we have no capital projects and we use all of our excess cash flow to pay a distribution or buyback equity, clearly, that would work out to a higher total return than just the normal distribution growth rate, but that's not the way we're thinking about it.

I mean, again, our first preference is to find good projects to invest in. And so the buybacks and the special distributions are the alternative of that. And we really think about is just the most efficient way to return value to the shareholders, not really trying to target any kind of specific return. So, that's the way we're looking at it.

Shneur Gershuni -- UBS -- Analyst

Okay. Fair enough. Two more follow-up questions, just -- thank you for all the color that you gave about the Longhorn recontracting and so forth. I was wondering if you can sort of talk about the difference in the rates you're getting for a term today kind of on the incremental versus the last round of recontracting, I think you did early last year, are the -- is it -- is the rate fairly similar to where it was when you first had the Longhorn contracts roll and you did the blend and extend when you sort of think about the new rates. Is it lower today kind of similar and so forth?

And then secondly, where you see the market in terms of getting spot volumes which had been a surprise in most of the quarters throughout last year that you hadn't guide to, just wondering if there is opportunity for that or we should never think of the -- be thinking about spot at all this year?

Michael N. Mears -- Chairman, President and Chief Executive Officer

The contract rates in today's environment, if you want any kind of term are less than they were a year and a half ago. So, they are directionally down, so I'll try to provide a whole lot more color on that. But you're talking rates that I'm going to give you extreme bounds here, but or -- $1.10 to $1.50 a barrel is kind of the range that you can get the market today for any kind of term. Now, there is exceptions to that based on other conditions, but that's kind of the market range right now. And then it can change in a week or in a month given the dynamic nature of new pipelines starting up. And when they're going to start up add and what's happening with the current production forecast. So, that's a point in time kind of analysis.

With regards to your second question on, I think it was, is there any opportunity for spot shipments this year, which I mean technically speaking a spot shipment the way we think of it would be a third-party who is willing to pay the posted tariff which on our pipes is about $4 a barrel, and I'd say the probability of that happening this year is zero. I'd love to be wrong on that, but just based on where the market is today and the new capacity coming online. That's extremely unlikely to happen. And so movements in that space are going to need to be done, but through an affiliate transaction at different rates.

Shneur Gershuni -- UBS -- Analyst

Okay. Fair enough. And one last question, has there been any discussion, I'm sure you get this question all the time about C-Corp conversion and so forth, but has the board sort of engaged any advisors or taking a deeper look at the question whether it's either to think about it from a C-Corp perspective or even to consider a REIT, which seems to be the latest trend that people are talking about or everybody still comfortable with where the structure currently is today?

Michael N. Mears -- Chairman, President and Chief Executive Officer

Well, we frequently evaluate a C-Corp conversion, we frequently have discussions with our board about C-Corp conversion. And we -- it's not something where we've analyzed once and put on the shelf, it's an ongoing process. And our position today is the same as it's been for quite some time is if you -- in our view, if you do a long-term present value of our current tax-efficient structure versus a C-Corp structure which is ultimately going to pay taxes at some point. There is a higher value to remain the way we are. There is still the question of perhaps you can get a higher valuation today if you convert to a C-Corp. I know there's a lot of analysis on that. We're not 100% convinced that there is a long-term increase in value. We already trade at a premium value, so it's unclear to us that we would get any kind of significant pop right out of the gate, but even if we did we also manage the business for the long term. And so the question remains is would we still be trading at a similar multiple in the future if we're paying cash taxes versus what today when we're not paying cash taxes. And so we evaluate all of that with regards to our determination. And as of right now we're not intending to convert to C-Corp.

Shneur Gershuni -- UBS -- Analyst

If I can sort of follow up on that for a second there. Completely understand the argument about from a tax perspective, but just looking at your own guidance where you're expecting a slower distribution growth rate -- distributable cash flow rate and so forth, kind of a more mature capex environment, does the REIT structure not makes sense, because you would not be in a taxable situation and you'd be able to distribute your cash flow under the REIT structure just given kind of the majority of where you are in the capex phase?

Jeff L. Holman -- Senior Vice President, Chief Financial Officer and Treasurer

This is Jeff. The restructure is interesting but our appreciation of that is that the qualifications for rents would not fit with a large proportion of our business model. Tariffs that are not subject to monitor commitments probably are not rents and that makes it very complicated for us to consider a REIT restructure without multiple securities.

Michael N. Mears -- Chairman, President and Chief Executive Officer

And maybe just more clarity on that, the majority of shipments on our refined product pipeline are not done under a contract, they're done only under a posted tariff. And we don't believe that revenue from a posted tariff would qualify under a REIT structure if there is no contract, term contract associated with it.

Shneur Gershuni -- UBS -- Analyst

Got it. Okay. That makes sense. And appreciate the clarification. Thank you very much, guys. And enjoy the rest of the day.

Michael N. Mears -- Chairman, President and Chief Executive Officer

Thank you.

Operator

And our next question comes from Keith Stanley with Wolfe Research. Please go ahead.

Keith Stanley -- Wolfe Research -- Analyst

Hi, good afternoon. You talked at the start about how you beat the initial 2019 guidance really very significantly with crude spreads and butane blending probably some other things, I imagine. When you're looking at this year are there areas where you would say, you feel like you've maybe been conservative or have opportunities to perform better than the guidance in 2020? And I'm just thinking, whether it's tariff increases you haven't done yet in competitive areas or timing of growth projects, cost control, anything along those lines where you might have opportunities.

Michael N. Mears -- Chairman, President and Chief Executive Officer

Let me answer that question in just a second, because I do want to highlight, I know there's been a lot of, I think, focus on our guidance this year versus the actual performance in 2019. Let me just address that for a second, then I'll get back to your question. If you recall, our initial guidance in 2019 was $1.4 billion -- $1.14 billion. So, we beat our guidance, initial guidance by almost $150 million last year. There were a number of things that were associated with that. But so now we wind up with almost a $1.3 billion level of DCF performance last year and $1.2 billion of DCF guidance this year.

I want to highlight a couple of things relative to that. First of all, if I look at the material changes between '19 and '20 obviously one of the biggest of those if not the biggest of those is the change in crude oil, what the income we're going to make based on the reduced tariff and the reduced margins on the crude oil business. So, that's one item. The other item that's a variance is the sale of our marine terminals and the pending potential sale of Saddlehorn, portion of Saddlehorn. The other change is a decline in blending, butane blending margins for 2019 versus the forecast for 2020.

And the fourth one is a material variation. We had significant insurance recoveries in 2019. And we also had a significant gain on the sale of our Wink to Crane assets. If I add those all up together, just those items, it's a variance from 2019 to 2020 of almost $170 million of DCF. So, that's our starting point is to take those out and then build a DCF for 2020 from that. And as our DCF for 2020 significantly above 2019 minus those amounts, I want to start with that because I think it's important to point out what those material variances are.

Now, to your question where is there upside? Well, there's -- the upsides are in some extent in those areas. If the Permian to Houston differential is better than what the forward curve suggests then that's an upside. If blending margins improve from where they are right now that's a potential upside, I think that's one that's pretty real given we're in low $50 crude environment depending on what's your view is, what's going to happen to crude oil for the rest of the year. There is a potential for upside there.

Those are probably the two biggest pieces of upside. We do, we are focused and have initiated cost-control measures. We're very early on in the process there. It's difficult to tell how much of an impact that's going to have in 2020. But we expect it's going to have some impact. And hopefully, it's going to have more impact in future years. So, those are I think probably some of the most notable upsides, and of course, with refined products business, there is probably not a lot of upside on tariff, but we could be surprised on volume as we go through the year.

Keith Stanley -- Wolfe Research -- Analyst

That's a really helpful answer. Follow-up, quick question, just how discussions gone on a more capital-efficient version of Voyager Cushing to Houston pipe, have you made progress since the last quarter on that?

Michael N. Mears -- Chairman, President and Chief Executive Officer

We've made progress, but not enough progress to announce that we've -- we're starting the project. I will say that there is interest, there is significant interest in this project. We're still working with our partners on it. As I've mentioned before, the scale and size of this project are not -- is not the same as some of the other projects out there really only depends on one or two key shippers to make a commitment. Those shippers are still actively talking to us. However, they are very patient, and so we're being patient. We have not built any of that into our forward models. And that's just one project, we have other projects that may be very attractive and have very solid returns that we're working on.

Yeah, we're going to see how those play out too, but to be clear, we're not counting on any of those to happen. I mean, we're planning for a very low capital environment going forward. We think we have inherent growth in our business even in the absence of spending capital. And until these projects happen that's how we're going to manage our business.

Keith Stanley -- Wolfe Research -- Analyst

Thank you very much.

Operator

And our next question comes from Vikram Bagri with Jefferies. Please go ahead.

Vikram Bagri -- Jefferies -- Analyst

Good afternoon, everyone. I wanted to touch on operating expenses, they were lower than what we expected, I think, they were lower than what was baked into the consensus. I think, you mentioned lower integrity spending on crude pipes and several other smaller factors. Does that mean there will be some catch-up spending in 2020 on crude pipes, one. And two, I think, Mike, you just mentioned that there are some cost control measures that you're working on. I was wondering how impactful these measures can be in 2020 and going forward, and how should we think about opex in the 2021 and years beyond?

Michael N. Mears -- Chairman, President and Chief Executive Officer

Well, I can tell you, I mean there is a little bit of catch-up in 2020. It's already in our guidance. I don't know if I'd call it material. With regards to the cost control efforts, our expectations for 2020 are fairly modest and we're going to be putting some bounds around what we expect we can do in the years to come. I mean there is a chance and I think a reasonable chance that we can capture some meaningful cost reduction in our business over the next three years and we've really -- we're just starting to focus on that. If you're in a high-growth environment, which we've been in for the last number of years, the organization tends to focus on that. If you pivot to a low-growth environment, it gives the organization time to focus on efficiency. So, we're going to take advantage of that.

Vikram Bagri -- Jefferies -- Analyst

And these -- as a follow-up, and the source of these cost control measures is that automation, a new technology, where is -- what's the -- I was trying to understand what the source is? Thank you.

Michael N. Mears -- Chairman, President and Chief Executive Officer

Yeah, it's all of those and more. It's efficiency and processes, it's potential automation processes. There is a range of things that we're going to be evaluating and investigating that could capture some significant savings.

Vikram Bagri -- Jefferies -- Analyst

That's all I had. Thanks.

Operator

Our next question comes from David Amoss with Heikkinen Energy Advisors. Please go ahead.

David Amoss -- Heikkinen Energy Advisors -- Analyst

Hey, Mike, I just wanted to spend a quick minute, making sure that I understand the commentary on Longhorn volumes correctly. If I remember properly, two years ago you had half of your commitments extend at term and the other half exercised their two-year option. And so, are those two-year options still good through September of this year and can you use that assumption to get to the volume guidance that you gave earlier?

Michael N. Mears -- Chairman, President and Chief Executive Officer

I'm hesitating as it's a very complicated answer to that question. The best I can tell you is just to reiterate, and we try to go out of our way to explain this in my notes, but for 2020 when we close to 230,000 barrels a day of committed volume, again, a portion of that and you can gather from this that contracts have been restructured, but a portion of that which is 190,000 barrels a day is third-party commitments, that's the average volume for the year from third-party commitments. And then 40,000 barrels a day is the average volume that our affiliate is going to ship that supported by third-party commitments, but it will show up as affiliate shipments which adds up to the 230,000.

And our expectation is that our affiliate will ship more than that, it's not committed, but will more than that to fill the pipeline. That's probably the best clarity I can give you without going into a lot of details on specific contracts and specific structures.

David Amoss -- Heikkinen Energy Advisors -- Analyst

Okay. That's helpful. Thanks. And then just to follow-up, you said that the current rate for term is the $1.10 to $1.50 obviously a wide range there. Are you trying to recontract at that level or are you waiting for a higher price. I guess, the remaining option would be that it's just hard to put together that many barrels at the term, right?

Michael N. Mears -- Chairman, President and Chief Executive Officer

No, we're not waiting for a higher price. If you look at the forward curve, the differential it's going downward and not improving for quite some time. So, we're not waiting for a higher price. And the long-term agreement we just signed we've been working on that for quite some time. I mean, it's -- they get a -- in our view, they get a 10-year agreement from a credit-worthy party in this market and a substantial volume. We haven't disclosed the volume, but substantial volume. We feel very good about that, because it -- we're going to have some ups and downs during the ramp-up period over the next couple of years, but for the long term this creates, it takes a lot of risk off the table for a long term.

David Amoss -- Heikkinen Energy Advisors -- Analyst

Thank you. I appreciate the clarity.

Operator

Our next question is from Derek Walker, Bank of America. Please go ahead.

Derek Walker -- Bank of America -- Analyst

Hi, good afternoon, guys. Thanks for the time today.

Michael N. Mears -- Chairman, President and Chief Executive Officer

Yeah.

Derek Walker -- Bank of America -- Analyst

Most of my question have been answered, but maybe just a couple touch up questions, you mentioned in guidance it also includes the portion of Saddlehorn and there's obviously been a lot of commentary already around just the balance of special distribution and buybacks and -- but there is no formula but it's just sort of point in time evaluations, but should we think about that point in time evaluation sort of at the time or in and around the potential Saddlehorn sale. So, sort of more of a year-end event as far as how 2020 might unfold?

Michael N. Mears -- Chairman, President and Chief Executive Officer

I wouldn't characterize it that way. I'd say, there is a couple of things that occurring here, as I've told to you there Voyager and other projects are still under development and there is going to be a period in time here where we need some clarity on whether those projects are going to materialize or not. So, that's one factor into the timing of this. It probably makes sense for us to wait until we have certainty of closing on the marine assets, we haven't closed on those yet.

So, there's a number of issues here that we're juggling before we make a decision to do either one of those. It's not driven by Saddlehorn, it's possible we could something before the Saddlehorn transaction and it's possible that there will be after that or it's possible that we'll find good projects to invest in and we will do either one. So, I know that's kind of goal all around the question, but that's where we sit at the moment.

Derek Walker -- Bank of America -- Analyst

Appreciate it. That's helpful. And then maybe just a quick high-level one, you talked about the FERC indexing process a little bit that the Form 6 is there sort of in the spring time frame and they will use that to make an assessment. Do you kind of see that ramping up at the end of this year or is it sort of early next year and sort of process and you talked about the turnover. And do you see yourself engaging more this year as far as making sure that they are well informed as far as how you want that process to unfold?

Michael N. Mears -- Chairman, President and Chief Executive Officer

Well, the expectation is that a decision is issued before the end of the year. There is no mandate for that and it could bleed into next year, but our expectation is before the end of the year. And, yes, the industry will be very engaged with the Commission in this process through the course of the year.

Derek Walker -- Bank of America -- Analyst

Okay. Thank you. Appreciate it.

Michael N. Mears -- Chairman, President and Chief Executive Officer

Sure.

Operator

And our last question comes from Spiro Dounis. Please go ahead.

Spiro Dounis -- Credit Suisse -- Analyst

Hey, everyone. Thanks for squeezing me in. Two quick ones here, first one the special dividends, just any thoughts around maybe a profit-sharing mechanism that maybe could result in more multiple expansion for the stock that also reward shareholders for maybe sticking with you over time as opposed to a one-time payment. I guess, we've always do the special dividends that potential wouldn't really expand the multiple much and doesn't reward loyalty, just curious how you're thinking about the mechanics around that?

Michael N. Mears -- Chairman, President and Chief Executive Officer

Well, we haven't really thought about profit sharing mechanism for two reasons, I guess, one is either a buyback or a special dividend is dependent what our actual expansion capital spending is which can fluctuate. And I understand, perhaps you could adjust the profit sharing calculation based on how much you're spending on capital. But it can be highly volatile, I mean, you could see it as it is for us now. We spent $1 billion last year and we're spending $400 million this year. And they can be volatile.

And I guess the second piece is how that would work with the option to buyback units because there may be periods in time where it doesn't make sense to use our profit to pay a distribution and we'd rather use it to buyback units. So, we haven't given that. But I'm not going to sit here and say we won't ever think about that, but it hasn't been top of mind to date.

Spiro Dounis -- Credit Suisse -- Analyst

Okay. I understood. Last one from me, just in the $500-million-plus expansion backlog, how would you characterize where these projects are in their development, just generally speaking, and maybe what they look like, just trying to get a sense if either crude products or crude product oriented on the brownfield, greenfield and maybe just any sense on if they are kind of more demand pool or supply push-type projects?

Michael N. Mears -- Chairman, President and Chief Executive Officer

I wish I could give you a short answer on that. I mean the truth is, it's in crude oil and refined products and it's brownfield and greenfield. And some of these projects are fairly mature and some of them are. But I'd caution even a fairly project doesn't mean it gets done. I can't overemphasize how focused we are being disciplined though. I mean, I think we showed a track record of being able to walk away from projects when we don't think they meet our return thresholds and our risk profile. And that hasn't changed. And it makes it tougher to get projects done, but I think that's what the market wants right now, is that kind of discipline. So, there is no guarantee on any of these projects, but on the other hand if a project meets all of those criteria, that's still the best place to deploy capital.

Spiro Dounis -- Credit Suisse -- Analyst

Got it. Thanks for the time today gentlemen.

Michael N. Mears -- Chairman, President and Chief Executive Officer

Sure. Thank you.

Operator

And Mr. Mears, I'll now turn the call back over to you for closing remarks.

Michael N. Mears -- Chairman, President and Chief Executive Officer

All right, well, thank you everyone for your time today and we appreciate your continued interest in Magellan. Have a good afternoon.

Operator

[Operator Closing Remarks]

Duration: 61 minutes

Call participants:

Michael N. Mears -- Chairman, President and Chief Executive Officer

Jeff L. Holman -- Senior Vice President, Chief Financial Officer and Treasurer

Joe Martoglio -- J.P. Morgan -- Analyst

Tristan Richardson -- SunTrust -- Analyst

Shneur Gershuni -- UBS -- Analyst

Keith Stanley -- Wolfe Research -- Analyst

Vikram Bagri -- Jefferies -- Analyst

David Amoss -- Heikkinen Energy Advisors -- Analyst

Derek Walker -- Bank of America -- Analyst

Spiro Dounis -- Credit Suisse -- Analyst

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