BP Midstream Partners LP (BPMP) Q4 2018 Results Earnings Conference Call February 28, 2019 10:00 AM ET
Brian Sullivan - VP, IR
Rip Zinsmeister - CEO
Craig Coburn - CFO
Conference Call Participants
Jeremy Tonet - JPMorgan
Derek Walker - Bank of America
Good morning everyone and welcome to the BP Midstream Partners 4Q 2018 Results Conference Call and Webcast. [Operator Instructions] Please also note today's event is being recorded.
At this time, I'd like to turn the conference call over to Mr. Brian Sullivan, Vice President of Investor Relations. Sir please go ahead.
Welcome to BP Midstream Partners Fourth Quarter and Full Year 2018 Results Presentation. I'm Brian Sullivan, Vice President of Investor Relations; and I'm here today with our Chief Executive Officer, Rip Zinsmeister; and Chief Financial Officer, Craig Coburn.
Before we begin, I would like to draw your attention to our cautionary statement. During today's presentation, we will make forward-looking statements that refer to our estimates, plans and expectations. Actual results and outcomes could differ materially due to factors we note on this slide and in our SEC filings. We will also refer to non-GAAP financial measures. Please refer to our SEC filings and supplemental information in this presentation for important disclosures related to these measures. These documents are also available on our website.
And now over to Rip.
Thanks Brian. Good morning, everyone, and thank you for joining our call today.
Almost a year ago, Craig, Brian and I welcomed you to our first results presentation. Today, we report on our first full year of operations, a highly successful year for us in which we've built a track record of strong operational and financial performance, exceeding the forecast we gave at the time of our initial public offering.
We delivered full year cash available for distribution of $144 million, which was at the top-end of our guidance range and our portfolio of high-quality assets continues to perform very well. We consistently raised our distribution each quarter delivering mid-teens distribution growth to unitholders in 2018 in line with the target we outlined to unitholders at IPO.
And we successfully completed our first dropdown, a transaction that was immediately accretive to unitholders and enhanced portfolio diversification and balanced our onshore and offshore cash flows. All of this was achieved against the backdrop of a challenging equity capital market for MLPs, evolving investor sentiment towards MLP structures and governance and volatility in the energy market more broadly.
Our success over the past year is a testament to the quality of our asset portfolio and its ability to generate stable, predictable cash flows with minimal impact from fluctuations in energy commodity markets.
The organic growth potential of our onshore and offshore assets whether through the growth and processing of advantaged feedstock or commercial optimization programs at BP's Whiting Refinery or production growth from new projects and technology advancements in the offshore Gulf of Mexico Deepwater, and perhaps most importantly, having a strong supportive sponsor in BP, which underpins the robustness and flexibility of our sponsored MLP model.
We are watching closely and learning from the evolution of the MLP 1.0 to 2.0 environment. Given we are very early in our life cycle, we have the advantage of being able to wait and see positioning us to optimize our capital structure in a way that is fair and equitable to all. For now, we will maintain a continued laser focus on our performance delivery.
We will capitalize on our visible organic growth potential. We will pursue dropdowns subject to market conditions that are accretive to unitholders with assets that further strengthen our already high-quality portfolio.
And we will continue to listen to our investors. We hear loud and clear the market's biases against IDRs while we have not even reached the first threshold for IDRs to kick in, and we will address this at an appropriate time.
To our agenda for today. I'll begin the presentation with a review of the highlights from 2018. Craig will then take you through the details of the fourth quarter and full year results and remind you of our 2019 guidance and our financial frame. We are not changing our 2019 guidance or our financial frame through 2020.
It's no coincidence that we showed a picture of BP's Mad Dog facility, which is located offshore Deepwater Gulf of Mexico as our opening slide today. In fact, you'll see several images of BP's operated offshore Deepwater Gulf of Mexico projects as well as images of BP's Whiting Refinery scattered throughout our presentation today. That's because I plan to spend some time today updating you on our growing confidence in the organic growth potential of our onshore and offshore pipeline assets.
Investors frequently ask us about the offshore Deepwater Gulf of Mexico in particular. And today we will spend some time sharing our insights with you on this area of our business. I'll conclude our presentation this morning by summarizing our key messages regarding asset dropdowns and distribution growth. Craig and I will then be ready to take your questions.
Firstly, to the highlights from the year. 2018 was a year in which we demonstrated the attractiveness of our investment proposition. At IPO, we laid out to investors our proposition to deliver unitholders consistent top tier distribution growth, specifically mid-teens per unit annual distribution growth through 2020 by combining organic growth opportunities and strategic acquisitions of assets from BP. We delivered on all elements of this proposition last year and we expect to repeat that delivery in 2019.
In our first full year of operation, we've built a track record of strong, reliable and predictable operations and financial performance. We consistently raised our distribution per unit and delivered cash available for distribution above IPO forecast levels.
In the fourth quarter, our gross pipeline throughput volumes were 6% higher compared to the fourth quarter of 2017 on a pro forma asset basis, driven by offshore pipelines after adjusting for the impact of the Ursa pipeline, which was included in our first drop. This organic throughput growth was achieved even with maintenance at the Whiting Refinery and apportionment on the Enbridge main line in the fourth quarter of 2018.
We also successfully completed our first asset acquisition from BP confirming our ability to execute attractive dropdowns. We delivered a transaction that was not only accretive, but also added stable cash flows from high-quality assets with well-established customers and assets with meaningful future growth potential.
It clearly show the strength of our sponsored MLP model having a strong supportive sponsor in BP. The scale and depth of BP's Midstream value chain assets provides us with access to a significant inventory of high-quality dropdown assets for many years to come.
In January of this year, the Board of Directors of the general partner declared an increased quarterly cash distribution of $0.3015 per unit for the fourth quarter of 2018. This distribution was paid on February 14th, and with this increase, we delivered our unitholders around 15% distribution growth in 2018 right in line with our target.
During the first half of 2018, we completed an important step in demonstrating our commitment to responsible corporate governance by filling the last of three Independent Board positions with the appointment of Michele Joy as an Independent Director. Michele joined our two other Independent Directors, Walter Clements and Bob Malone, who were appointed to the Board in 2017.
And finally, with our 2018 dropdown, we are set up to deliver mid-teens distribution growth through 2019 from the embedded organic growth potential of our portfolio. This provides us with a great deal of flexibility on the timing of a potential drop in 2019 subject to market conditions, which would underpin mid-teens distribution growth in 2020.
So in summary, we achieved what we said we were going to do. We have now established real momentum in our business and plan to carry that forward into 2019. This slide visually shows the track record we established last year.
The graph on the left shows our adjusted EBITDA consistently exceeded our IPO forecast. Similarly, the graph in the middle shows we grew our cash available for distribution consistently throughout the year, also exceeding IPO forecast.
And finally, the graph on the right shows, we grew our distribution each quarter delivering unitholders around 15% distribution growth through 2018. Importantly, in doing so, we maintained a distribution coverage ratio within our target range of 1.1 times to 1.2 times, calculated on a full year basis. This is a powerful visualization of the solid track record we have now established.
On that note, let me now hand over to Craig.
Thanks Rip. Good morning, everyone. We delivered another solid set of results from the fourth quarter establishing a track record of strong operational and financial performance for our first full year of operation.
First, to our operational results. Our fourth quarter total pipeline growth throughput was around 1.6 million barrels of oil equivalent per day, higher than the third quarter as previously guided reflecting a full quarter contribution from the Ursa pipeline, which was included in our 2018 asset drop.
Throughput on this pipeline was approximately 100,000 barrels per day during the fourth quarter and higher volumes on Proteus and Endymion, following the start up of Thunder Horse Northwest Expansion project in mid-October. This was offset by lower throughput on the BP2 pipeline as a result of maintenance at Whiting continuing into the fourth quarter as planned and ongoing apportionment of Enbridge mainline. Apportionment averaged around 45% during the quarter.
Reminder that we have minimum volume commitment arrangements in place with BP with respect to throughput on our onshore pipelines mitigating the impact to our cash available for distribution from maintenance and apportionment. And lower throughput on the Mars pipeline, driven by temporary production impacts caused by well performance issues.
Fourth quarter average revenue per barrel on a portfolio basis was broadly flat compared to the third quarter. On a full year basis, the average revenue per barrel was consistent with 2017 calculated on a like-for-like basis, which was consistent with our guidance.
Looking ahead, we expect pipeline gross throughput in the first quarter of 2019 to be slightly lower than the fourth quarter of 2018 reflecting significantly lower volumes on Proteus and Endymion, due to turnaround and maintenance activities at Thunder Horse and the concurrent connection of the Mattox pipeline at South Pass Block 89.
This decrease will be partially offset by higher throughput on BP2 pipeline following the completion of maintenance at Whiting in the fourth quarter and slightly lower apportionment expected on the Enbridge mainline and higher throughput on the Diamondback pipeline reflecting favorable diluent demand seasonality during the winter months.
Moving to our financial results. We finished the year strong with fourth quarter cash available for distribution of $41 million, bringing our full year cash available for distribution to $144 million. This was at the top-end of our forecast range consistent with the guidance we gave during our third quarter results.
Net income attributable to the Partnership for the fourth quarter was $37 million, higher than the third quarter as expected, largely reflecting a full quarter's contribution from the assets we acquired on October 1st, 2018 and the higher volumes from Proteus and Endymion offshore pipelines.
Revenues related to our wholly owned assets, which include our three onshore pipelines, were $3 million lower compared to the third quarter reflecting lower fixed loss allowance revenue on BP2 attributable to lower realizations during the quarter.
And in the third quarter of 2018, we recognized deficiency revenue related to the first half of 2018 in addition to deficiency revenue related to the third quarter. In the fourth quarter, we only recognized deficiency revenue related to the fourth quarter.
In the fourth quarter, we recognized $4.1 million of deficiency revenue under the throughput and deficiency agreements. This was primarily due to lower throughput on BP2 and Diamondback as a result of the expected maintenance at Whiting and apportionment on the Enbridge mainline that occurred in the quarter.
During the quarter, we incurred transaction cost of approximately $1.3 million related to our 2018 asset drop compared to $1 million in the third quarter. No additional costs relating to this transaction are expected in 2019.
Income from equity method investments before adjusting for non-controlling interest was higher in the quarter benefiting from a full quarter's contribution from our interest in Ursa and KM-Phoenix joint ventures that were acquired as part of the 2018 asset drop and higher throughput volumes from Proteus and Endymion pipelines.
This was partially offset by a lower contribution from the Mars pipeline attributable to slightly lower volumes compared to the third quarter driven by temporary production impacts caused by well performance issues.
Net interest expense was $4 million in the fourth quarter reflecting the use of our revolving credit facility to fund the asset drop in 2018. In our calculation of cash available for distribution, we reserved cash during the fourth quarter to make this interest payment at the end of the first quarter of 2019.
Adjusted EBITDA attributable to the Partnership was $43 million for the quarter and $149 million for the full year. On a full year basis, our distribution coverage ratio was 1.2 times, which is in line with our guidance of 1.1 times to 1.2 times.
Looking forward to the first quarter of 2019, we expect cash available for distribution to be lower than the fourth quarter consistent with lower dividends from Mardi Gras, primarily reflecting the significantly lower volumes on Proteus and Endymion due to the scheduled maintenance activities on Thunder Horse during the quarter and the concurrent tie-in of the Mattox pipeline, somewhat expected to be offset by lower maintenance spending in the period and the absence of transaction costs related to the 2018 acquisition.
Turning now to our financial frame. We laid out guidance for 2019 and through 2020 in a lot of detail during our third quarter results call, so we will not cover that again today. The guidance we gave last quarter is unchanged.
The key takeaways for you are; we expect our full year cash available for distribution to be in the range of $160 million to $170 million this year. We continue to target mid-teens per unit annual distribution growth through 2020.
The embedded organic growth potential of our existing portfolio is sufficient to deliver mid-teens distribution growth in 2019 without the need to do a drop providing us with the flexibility on the timing of our next dropdown, subject to market conditions. Rip will cover our 2019 dropdown expectations later in this presentation. Finally, we expect to roll forward our financial frame beyond 2020 later this year.
With that, I will hand back to Rip.
I would now like to update you on the organic growth potential of our asset portfolio. It is an exciting area of focus for us, as we believe, it offers significant upside potential with minimal capital expenditure by the Partnership. I'll start with a high-level overview and then we'll look at this in more detail.
We see visible organic growth opportunities in both our onshore and offshore pipelines. Our onshore pipelines are strategically located and highly integrated with BP's Whiting Refinery, the largest refinery in BP's global refining portfolio. We've included a list of our onshore pipeline assets in the supplementary information section of this presentation.
They play a critical role in maintaining the supply of crude oil to and moving refined products and diluent from the Whiting Refinery. Organic growth is expected to be achieved as BP progresses its key programs of reliability, efficiency, advantaged feedstock and commercial optimization at the Whiting Refinery.
In 2018, for the second consecutive year, refining availability, a measure of operating efficiency at the Whiting Refinery, was sustained at the highest level in more than 10 years. BP is progressing towards processing more than 350,000 barrels per day of Canadian heavy crude at Whiting by 2020 and this is expected to benefit throughput on our BP2 pipeline. Commercial optimization efforts may provide further upside to the movement of refined products and diluent from the refinery.
Our offshore pipelines link BP and third-party producers offshore Deepwater Gulf of Mexico, crude oil and natural gas production to Gulf Coast refining and processing markets providing offtake solutions for much of BP's world-class Deepwater Gulf of Mexico assets.
We have included a list of our offshore pipeline assets in the supplementary information section of this presentation. In most cases, our offshore pipelines are the most economic route for the producers to get their product to market and production from offshore fields is dedicated for life of lease, which may extend for multiple decades.
The Gulf of Mexico Deepwater is an attractive high-margin region for BP and other third-party producers and the hopper of opportunities, both new projects and opportunities around existing hubs continues to grow.
For example, new technology has unlocked an additional 1 billion barrels of oil in place gross at the BP-operated Thunder Horse facility and a further 400 million barrels of oil in place gross at the BP-operated Atlantis facility. We expect our offshore pipelines to benefit from increased throughput from already announced new projects as well as the growing hopper of opportunities in this region.
Let's now look at each of these organic growth areas in more detail. Firstly, let me talk a little about BP's Whiting Refinery and how BP's refining plans underpin organic growth in our onshore pipelines, particularly BP2. Whiting is currently the largest refinery in the U.S. Midwest and BP's largest in terms of refining capacity and one of the most complex refineries in BP's portfolio. It has a nameplate refining capacity of 430,000 barrels per day.
Our onshore pipelines, BP2, Diamondback and River Rouge, are strategically located and highly integrated with Whiting. Whiting depends on BP2 as its primary pipeline for delivery of Canadian heavy crude. Although, this pipeline also has the ability to ship a wide variety of crude oil types ranging from light sweet to heavy sour as the need arises.
Whiting is uniquely positioned to leverage its advantaged location and refinery configuration to capture and process discounted Canadian heavy crude feedstock. The refinery forms an essential part of BP's northern tier refining strategy in the U.S. Its location advantage and its feedstock flexibility enables BP to optimize a crude slate depending on relative crude differentials, an important capability to take advantage of market opportunities as they arise.
Given its proximity to Canadian crude supply, it enjoys a transportation cost advantage relative to U.S. Gulf Coast refineries. In the integration between the refinery and BP's supply and trading business, provides the ability to procure feedstocks at very competitive prices adding significant value.
In 2013, BP finished a multi-billion dollar, multi-year modernization project at Whiting that increased its heavy crude processing capability to take advantage of growing supplies of heavy Canadian crude. BP intends to expand the processing of heavy crude towards 350,000 barrels per day by 2020, a significant increase over the average heavy crude volumes processed at the refinery in 2018.
It is this strategy to increase the amount of advantaged feedstock processed at Whiting over the next few years relative to total throughput process that underpins the potential for future throughput growth on BP2.
Said another way, we expect that as Whiting increases its stock diet of heavy crude over the next several years, this should lead to increased throughput on BP2. Importantly BP2's capacity was expanded from approximately 240,000 barrels per day to 475,000 barrels per day to accommodate this growth. That means organic growth on BP2 to take advantage of BP's planned expansion requires minimal capital expenditure by the Partnership.
Finally, substantially all of our aggregate revenues from our onshore pipelines are supported by commercial agreements with BP that include minimum volume commitments through 2020. For BP2, the minimum volume commitments increased from 303,000 barrels per day in 2018 to 310,000 barrels per day this year and to 320,000 barrels per day in 2020 consistent with BP's intention to expand the processing of heavy crude at the refinery over the same period. The quality of operating information we have about Whiting from BP provides us with confidence that this organic growth on BP2 can be delivered.
You may have noticed that crude throughput on BP2 in 2018 was lower than the minimum volume commitment. In large part, this was due to the scheduled maintenance activity at Whiting Refinery during the third and fourth quarters and apportionment on Enbridge's mainline.
Now to offshore Deepwater Gulf of Mexico. Much attention is given to onshore production, particularly in the Permian Basin, however, offshore Deepwater Gulf of Mexico is a highly attractive region experiencing significant capital investment and production growth. For BPMP unitholders, it offers strong organic growth potential across our offshore pipeline network well into at least the middle part of the next decade.
During our IPO roadshows, as well as last year, I mentioned that we were bullish on the potential growth from this region. Since then, the continued development in the Gulf along with new BP and industry FID announcements and technology advancements has only reinforced our conviction and confidence on this growth potential.
With the rise of shale oil in the U.S., we're often asked whether offshore deepwater projects are competitive. For producers, offshore Deepwater Gulf of Mexico is a high margin competitive business. Let me explain why.
First, the region has an attractive tax and royalty fiscal regime, which acts as an incentive for producers to invest in offshore deepwater projects and to develop and produce these resources. Second, offshore fields are generally characterized by higher production rates and lower decline rates compared to onshore light-type development projects.
Third, production from offshore deepwater projects once online is largely resilient to fluctuations in oil and gas prices. Producers make long-term capital investments in offshore deepwater projects that have production profiles that span multiple decades.
Projects are evaluated and optimized for many years in advance of making a final investment decision testing their resilience to a wide range of resource recovery and oil and gas price scenarios. These are projects that once commissioned and brought online are not turned on and off on a whim.
Producers strive to operate offshore deepwater projects with high plant availability and consistent production notwithstanding fluctuations in the commodity price environment. That's a very different production profile for many onshore producers who ramp up and ramp down activity depending on the oil and gas price. That distinction is important as it provides us with a stable, dedicated throughput source for our offshore pipelines subject to scheduled turnaround and maintenance activity.
And fourth, since the oil price collapse of 2014, offshore deepwater producers have reset their capital and operating cost basis. BP's Gulf of Mexico unit production costs are down 40% leveraging standardization, simplification efforts, new technologies and agile ways of working.
Advances in seismic technologies and subsea tieback distances are making it possible to access new resources from existing infrastructure. All of these elements make offshore deepwater projects in the Gulf, both Greenfield and Brownfield highly desirable offering attractive returns and low breakeven prices.
We continue to see a lot of exploration and development activity in offshore deepwater fields in the Gulf with major projects starting up as early as this year as well as recently sanctioned projects providing continued development activity through into the next decade. We see even greater visibility to this growth compared to last year. Let me explain why.
BP is currently the top oil producer in the Gulf. Its net production in the Gulf of Mexico has increased by more than 60% rising from less than 200,000 barrels of oil equivalent per day in 2013 to more than 300,000 barrels today. BP is also one of the largest leaseholders in the Gulf with acreage in about 200 lease blocks. BP sees its net production growing to around 400,000 barrels of oil equivalent per day through the middle of the next decade.
This growth will be supported by recent project start-ups including Thunder Horse Northwest and South expansions and the Thunder Horse water injection project as well as the addition of a second platform Argos at the Mad Dog field, which is scheduled to come online in late 2021.
Future potential development at BP's offshore fields in the Gulf include the recently sanctioned Atlantis Phase 3 project, Atlantis Phase 4 and 5, and further developments at Thunder Horse and Mad Dog. All of these developments could contribute to production from facilities that connect to our offshore pipeline network.
And there's a lot of resource still to be produced from offshore Deepwater Gulf of Mexico. For BP, its offshore deepwater fields are a young resource base with only 12% of net hydrocarbons in place produced.
For example, the BP-operated Mad Dog field has gross estimated hydrocarbons initially in place of around 4.5 billion barrels of oil equivalent. As at the end of 2017, only 4% of this resource had been recovered through production.
BP-operated Thunder Horse field has gross estimated hydrocarbons in place of around 3.9 billion barrels of oil equivalent with only 10% recovered at the end of 2017. And the Atlantis field has gross estimated hydrocarbons in place of around 3 billion barrels of oil equivalent with only 11% recovered.
But as you can see, there are many years of production remaining to fully capture the recoverable resources. That will provide dedicated throughput volumes on our offshore pipeline network for many years.
Other producers are also developing new projects or have recently started up new projects that transport volumes via our offshore pipeline network. For example, Shell is currently developing the Appomattox project with production expected to start in 2019.
The Mattox pipeline will transport volumes from Appomattox and connect into the Proteus pipeline. Endymion pipeline, which originates downstream of Proteus will also benefit from additional volumes from Appomattox. Shell also has a string of adjacent Norphlet discoveries and see these as attractive tiebacks to Appomattox.
In April last year, Shell announced the final investment decision for the Vito project, which has the potential to transport additional volumes via the Mars pipeline. Several recent deepwater project startups, the Hess-operated Stampede project and the Chevron-operated Big Foot project transport volumes via the Amberjack pipeline, which connects into the Mars pipeline.
And finally, exploration and evolving infrastructure-led exploration opportunities offer further growth upside. All of this underpins our confidence in the near-term and long-term growth of offshore deepwater in the Gulf of Mexico. And for us our offshore pipeline assets are uniquely positioned to capture this future growth.
This slide shows an illustration of our offshore pipeline network as well as some of the next wave of growth opportunities. The math is not to scale and is not intended to include an exhaustive list of all future opportunities. However, it should provide you with an insight into the significant amount of future development activity that's possible in the offshore Deepwater Gulf of Mexico and importantly the future throughput volume growth potential for our offshore pipelines.
Let me explain why our offshore pipelines are uniquely positioned to capture this growth. First, our offshore pipeline network is sized to accommodate BP and third-party future growth opportunities. In most cases, the pipelines were designed, not only to meet the needs of the original BP-operated projects, but also to accommodate new connections for growing production.
As we have highlighted, commencing with our IPO, there's future throughput growth expected with a minimal capital spend by the Partnership. While at the same time, additional opportunities may arise, which could provide the opportunity for commercial investment by the Partnership. The approach to investment in new opportunities will be assessed on an individual basis.
Second, cost and permitting challenges associated with building new pipelines along with access to the Louisiana Offshore Oil Port or LOOP should make our pipelines the first choice and the most economic route to market for producers located in our catchment areas.
Third, our location advantage means that the Mars and Mardi Gras pipeline feed into the PADD 3 refining market, which represents approximately 50% of the total North American refining capacity.
Fourth, shippers are generally required to dedicate production from fields to the pipelines for the life of applicable lease, ensuring production is shipped via our pipelines. Volumes are shipped under fee base and FERC tariffs depending on the pipeline.
And last, our offshore pipeline network is located or connected to pipeline servicing high-growth catchment areas such as Green Canyon, Walker Ridge, Mississippi Canyon and Desoto Canyon. There's a lot of activity going on in these catchment areas.
Several new discoveries have been recently announced and new technologies and ways of working are unlocking new barrels around existing infrastructure in these catchment areas.
They're also enabling resources to be brought to market faster. For example, BP recently announced that at its Thunder Horse project, it applied new seismic techniques like ocean bottom nodes, full waveform inversion and new ways of working, unlocking an additional 1 billion barrels of oil in place gross and unlocked an additional 400 million barrels of oil in place gross around its Atlantis facility.
BP's project teams have also been using agile ways of working and challenging themselves to bring new subsea tiebacks online quicker resulting in a step change improvement in project cycle time. These are referred to as fast-paced tiebacks and tieback businesses are growing due to innovative new flow assurance designs.
So putting all this together into what it means for BPMP organic growth potential, we have a high degree of confidence in the growth of offshore Deepwater Gulf of Mexico within the operating radius of our pipeline assets. The quality of production and operating information we have about existing offshore projects as well as visibility to future growth prospects from our sponsored BP, underpins our confidence.
And as I mentioned earlier, access to this information is a key benefit of our sponsored MLP model. Although we've not formally extended guidance for growth beyond 2020, there is clear visibility to continued organic growth in the offshore to the early part of the next decade.
Finally, let me touch on asset dropdowns on our distribution growth. Our message regarding dropdowns and distribution growth is clear and consistent. We laid this out in detail on our third quarter results call, but let me recap.
Regarding dropdowns, the embedded organic growth potential of our existing portfolio is expected to be sufficient to deliver mid-teens per unit annual distribution growth through 2019 providing us with a great deal of flexibility on the timing of a potential dropdown in 2019.
If we choose to do a dropdown in 2019, it would set us up early to deliver mid-teens per unit distribution growth through 2020. While our expectation is to continue targeting one dropdown per year, we know equity market conditions are tough. We will keep listening to the investor community and dialoguing with our sponsor with the dropdown in 2019 being subject to market conditions.
We expect our next dropdown to include an asset or assets from the bottom two tiers of our dropdown inventory pyramid. That includes downstream pipelines and other midstream assets in BP's U.S. fields and trading business. Our next dropdown could be at least the size of the 2018 dropdown although this is subject to change as the asset mix is progressed depending on market conditions.
We will remain flexible regarding financing to achieve the optimal financing mix given the market environment. We remain committed to targeting investment-grade credit metrics and a balanced capital structure while pursuing our growth strategy.
Our investment proposition to unitholders remains the same, to deliver you consistent top-tier distribution growth. Through 2020, we remain committed to targeting mid-teens per unit annual distribution growth. And ask Craig mentioned earlier, we expect to provide greater visibility beyond 2020 with the roll forward of our financial frame later this year.
So in closing, let me leave you with the following messages. We are delivering on what we said we were going to do and we're doing better than we initially envisaged. Our asset portfolio is high-quality and continues to consistently perform very well.
In a volatile energy market, our cash flows are stable and predictable with minimal exposure to commodity price fluctuations. In fact a $5 per barrel change in commodity price would have changed revenue by only around $1 million for the year ended December 31st, 2018. We have visible organic growth opportunities across our asset portfolio, both onshore and offshore and it's a hopper that just keeps improving.
The scale of our sponsor's midstream value chain assets provides us with access to an inventory of high-quality dropdown assets for many years. In 2018, their inventory pool grew even larger such as with BP's acquisition of BHP's onshore assets in the Permian, Eagle Ford and Haynesville, and more recently, its investment in Portland's retail joint venture, which included a product pipeline and terminal.
The benefits of our sponsored MLP model differentiates us whether it's the superior quality of information to value dropdown assets, the high-quality of information to manage the assets once dropped or our ability to work with BP to derisk assets prior to dropdown, mitigating capital spend following acquisition. These are benefits that cannot be replicated in a merchant model.
We're already thinking about the migration to MLP 2.0 and what it means for an MLP like ours that is very early in its life cycle. We are conscious of the transition that BPMP may need to make over time subject to market conditions as well as the market's biases towards IDRs.
As I've said, we'll address this in a proactive and pragmatic manner at an appropriate time. We believe we offer all investors a differentiated investment proposition underpinned by a strong supportive sponsor in BP, a sponsor that is committed to our growth strategy and our success. Thank you for listening.
Craig and I are now ready to take your questions.
[Operator Instructions] Our first question today comes from Jeremy Tonet from JPMorgan. Please go ahead with your question.
Thanks for all the information today, that was helpful on the outlook for the Gulf there. Just want to come back to the 2019 guidance and you talked about 1Q '19, some of gives and takes there, and I was just wondering as we look past 1Q, are there any other notable turnarounds or maintenance activities in the Gulf or onshore that we should be thinking about when we're modeling out the year?
So thanks for the question. I'll get - Rip. I'll get Craig's input as well. So in a weird way, 1Q you can think about kind of EBITDA actually exhibiting a bit of an investment cycle because basically we had to turn off Proteus and Endymion for the entire month of February, so that's quote-unquote, the bad news.
The good news is we've tied in the Mattox pipeline and did a workover on Thunder Horse and Mattox connects to Appomattox. So basically that's why our cash flows are back-end loaded because a brand new field is coming into production and setting product down the Mattox pipeline and Proteus and Endymion.
So that's the principal driver of a deduct in 1Q and also why you see better support in Q3 and Q4 because of new production. And I'll have Craig comment on turnarounds.
Right. And so I would say, building on what Rip said, our EBITDA profile does build and it's back-end loaded because of those reasons as well as additional volumes, I mean, the additional volumes coming on Proteus and Endymion as the Mattox pipeline hooks in. We also have additional volumes, a full year of Ursa and coming into play for the full year.
We're not aware of any major issues on the pipes, but we have normal shutdowns and maintenance, normal maintenance, not shutdowns, going on and going off through the quarters, but that's built into our guidance of $160 million to $170 million.
And just want to address kind of a broader question. We're often asked, there are some other sponsors out there that folded in their MLP in, so we're often asked the question on that. I mean, it seems like you've laid out a very detailed plan for the MLP here. But just wondering how you respond to that when you guys get that questions? And understanding the point, you talked about being early in the life cycle for the IDRs. But it seems like given the market that's like here, maybe there's an opportunity to kind of even get ahead of things here and eliminate the IDRs now - very early now and build some goodwill and kind of build off an opportunity there. Just wondering how you think about those two points.
Funnily enough, you're the first guy to ask it, so I don't have a ready response of - you know, 10 people have asked me this and I have a - my canned, well-practiced response. I understood why Valero folded theirs in, as an example, right, as well as Dominion. Dominion basically had a massive change in their top line due to FERC actions.
So structurally and strategically, their MLP didn't make any sense. BP, the sponsor is certainly watching the market looking at the yields and trying to figure out, is this a waiting game for the retail investor to come back, and is the retail investor coming back?
As you would expect, we have relationships with all manner of very sophisticated investment banks including yours, and I get - half the sentiment says, this is a good business, be patient it's gone through cycles before, and the other half is anxious, I'd say, is a fair statement. We're taking a view that kind of year-in, year-out, you have market windows as you always get an equity capital markets and cycles that you need to prepare to go-to-market if the window is attractive. That's our approach for 2019 and that's about all I can comment on at this point in time.
I guess, I would add that we are early in the cycle here and there's benefits to that, right? So we're watching what others are doing and we're learning from others. And I think we're only 15 months from our IPO. There may be some advantages to go in early on IDRs on the foot side of that. It's always helpful to watch and wait and see what others do and see how things play out.
So I think we are positioned well for 2019 with our drop last year and we have the opportunity here to focus on the 2019 results and delivering on that and seeing how the markets evolve over 2019.
Our next question comes from Dennis Coleman from Bank of America. Please go ahead with your question.
This is Derek Walker on for Dennis. Maybe just a quick one on BP2. Can you just talk a little bit about how you see the cadence of the volumes throughout 2019? I think at IPO, there was an expectation for 337,000 barrels per day, but given kind of where volumes are today, 18% less than MVCs. Sort of how do you see that kind of ramping throughout the year just given maintenance and some of the apportionment that you mentioned?
As I look at performance in Q1, BP is pretty proud of our supply and trading team. We have exceeded MVCs kind of week to week, but apportionment does dominate the frame. So I'm looking at BP2 as really delivering MVC volumes and not much more than that on average this year whereas previously we would've thought you would exceed that given the machine in the plant is running very well.
And basically, we're paying more to get our barrels shipped a longer distance and coming up BP1 to supply the refinery because of apportionment.
I would just add that 310,000 is the volumes we're expecting and we have the MVC behind our revenues for BP2. They're pretty ratable throughout the year. There's no major scheduled shutdowns that are out there. And as Rip said, I think the major thing here is apportionment. The refinery is running well, it came out of the turnaround and then it's running well.
So we've had a few minor issues with the weather. In January, as you now, we had some extreme cold. But for the most part, the biggest issue is how much heavy can we get down BP2 from - through apportionment. The trading organization is pretty good at getting additional barrels on top of what we get apportioned. And then - but we are protected by the MVC, so we know we will get the 310,000 of revenues in 2019.
And then maybe just a question, it's a little derivative from Jeremy's question, just around the dropdowns in 2019. You mentioned there is flexibility here, you can hit your targets without a drop. But I guess, how are you thinking about the priority, is it no drop, is it doing something similar to last year, doing 50-50 debt equity? Is it doing just a smaller size acquisition, which is debt, any color sort of how you're thinking the priority there?
Well, it's - honestly speaking, it's hard to run a dropdown MLP, and say, well we're not really interested in doing drops, right? I mean, that's kind of - it's not exactly a raison d'etre. Hitting the numbers, running the business, that's job 1, and we've demonstrated that in 2018. We feel very good about 2019.
And unfortunately given where capital markets are, we're more or less stuck being opportunistic in terms of, will the market provide an attractive window in which the finance to drop.
If you talk in terms of back office, we're doing all the work to support a drop. And then the timing thereof will be a function of how attractive the markets are. We are not inclined to do another 100% debt-financed drop. That would stretch the capital frame and actually would take some forbearance from the sponsor.
So that's not a game where we're interested in. Nonetheless, per my comments, we're always interested in optimizing the capital structure. I get ridiculous volume of inbounds from interested - kind of private capital interested in more of the exotic flavors in the cap structure and so far we haven't pulled that lever or advanced that in any meaningful way.
I think one other thing to point out, I mean, we - referring back to Rip's comments around the inbounds on private capital, just a little market context here, we are looking interestingly at the delta between the multiples private capital was willing to pay for assets that are stable, consistent cash flows like ours and where the market is today.
And our own opinion is the smart money is smart and the market needs to readjust a bit here in terms of the flows. But that is what it is. That's our view. But it is an interesting sort of dynamic to point out. As I'm sure, you've all observed very well yourselves.
And ladies and gentlemen, at this time, showing no additional questions, I'd like to turn the conference call back over to Rip Zinsmeister for any closing remarks.
Well, firstly, I want to thank the audience for their patience. It was probably a longer call than certainly our own track record in history. We thought it was important certainly and we thank our existing investors who have encouraged us to talk about the Gulf to the market because we do see that as distinctive. I've been bullish on it from day one, continue to be very bullish. There's a wave of production coming our way, which will benefit our unitholders and our business. And in closing, I just want to encourage, if any has any follow-on questions, our Investor Relations group is here to help you.
Okay. Take care. Everybody, have a great day.
Ladies and gentlemen, that will conclude today's conference call. We do thank you for attending today's presentation. You may now disconnect your lines.