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Kinder Morgan Inc
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Welcome to the Quarterly Earnings Conference Call. At this time, all parties are in a listen-only mode, until the question-and-answer session of today’s conference. [Operator Instructions] I would like to inform all parties that today’s conference is being recorded. If you have any objections, you may disconnect at this time.
I will now turn the call over to Mr. Rich Kinder, Executive Chairman of Kinder Morgan. Thank you. You may begin.
Thank you, Denise. Before we begin, I’d like to remind you, as I always do, that KMI’s earnings release today and this call include forward-looking statements within the meaning of the Private Securities Litigation Reform Act of 1995 and the Securities and Exchange Act of 1934 as well as certain non-GAAP financial measures.
Before making any investment decisions, we strongly encourage you to read our full disclosures on forward-looking statements and use of non-GAAP financial measures set forth at the end of our earnings release as well as review our latest filings with the SEC for important material assumptions, expectations and risk factors that may cause actual results to differ materially from those anticipated and described in such forward-looking statements.
As I do -- always do on these calls, let me talk briefly about our financial strategy at Kinder Morgan with specific focus on our dividend policy. Ours is a conservative philosophy, and we believe that is appropriate, particularly in our industry and especially in these unprecedented times. As Steve, Kim and the team will describe, while we face headwinds, we are addressing our challenges. Our cash flow remains strong, even in this environment. We are covering our dividend and all expansion CapEx from that cash flow.
Now, let me talk about our dividend. July 2017, when we were paying an annual dividend of $0.50, we said we expected to increase that dividend $0.80 in 2018 to $1 in 2019 to $1.25 in 2020. We met those expectations in both 2018 and 2019 and we have the financial wherewithal to meet the $1.25 in target in 2020 with significant coverage. That said, in unprecedented times like these, the wise choice in the opinion of our management and our Board is to preserve flexibility and balance sheet capacity. Consequently, we are not increasing the dividend to the $1.25 we projected, under far different circumstances in 2017. Nevertheless, as a sign of our confidence in the strength of our business and the security of our cash flows, we are increasing the dividend to $1.05 annualized, a 5% increase. Doing so, we believe we have struck the proper balance between maintaining balance sheet strength and returning value to our shareholders, which remains a primary objective of our Company. We remain committed to increasing the dividend to $1.25 annualized. Assuming a return to normal economic activity, we would expect to make that determination when the Board meets in January 2021 to determine the dividend for the fourth quarter of 2020.
And with that, I’ll turn it over to Steve.
All right. Thanks, Rich.
I’ll give you an overview of our business, including the coronavirus response and impacts, and turn it over to our President, Kim Dang to cover the outlook and the segment updates. Our CFO, David Michels will take you through the financials. And then, we’ll take your questions, as usual.
I’ll begin on a grateful note. I’m glad that we strengthened our balance sheet, reducing debt by about $10 billion since the third quarter of 2015. I’m grateful we completed the KML sale in December of 2019 and converted the proceeds to cash at an attractive time. I’m glad we hedged crude early in the year. I’m glad that we have a disciplined approach to capital investment and that we operate our business with -- operate with a business model that insulates us from some of the worst of the current double impact on energy markets right now. I’m grateful for the way we run our business and for the culture of our workforce. All of these things have made us strong for the current storm.
In times like these, it’s especially important to keep your priorities and principles in mind. Our priorities are, number one, to keep our employees safe; and two, to keep our businesses running. We operate infrastructure that is essential to businesses and communities across the country. We need to keep our assets running and we have. To protect our employees, we instituted telecommuting, which has worked astonishingly well, by the way, and made changes in our field operations to enable our coworkers to do their work while maintaining appropriate physical distance. In a few cases where distancing is not possible, we are enhancing our PPE requirements. It’s working. All of our assets are running and we are keeping our coworkers safe.
Our financial principles remain the same. First, maintaining a strong balance sheet. Even with our revised estimate, we are consistent with our approximately 4.5 times debt-to-EBITDA target. We believe the dividend decision made today was a wise one.
Second, we are maintaining our capital discipline through our return criteria, a good track record of execution and by self funding our investments. On that front, we evaluated all of our 2020 expansion capital projects and reduced CapEx by about $700 million for 2020 or 30%, in response to the changing conditions in our markets. We still have $1.7 billion of expansion capital in 2020 on good project investments.
Finally, we are returning value to our shareholders with a 5% year-over-year dividend increase to $1.05 annualized and the commitment to get to $1.25 when market conditions recover. As Rich said, we think that holding off on a larger increase and leaving our balance sheet stronger, but still showing an increase in our dividend, strikes the right balance, strong balance sheet, capital discipline and returning value to shareholders. Those are the principles we operate by even in or perhaps especially in times like these.
Here’s what we’re seeing in our businesses. Natural gas transportation and storage remains relatively strong, and transport volumes are up year-over-year. Over time, we’re going to see some shifting from associated gas to dry gas. But we have assets that serve both. Refined products volumes are coming down in a way we’ve never seen before. This impacts us in several ways. Our refined Products Pipelines are common carrier pipelines. So, we get paid a fee on the actual throughput. Historically, throughput varied only slightly, usually growing 1% or so a year.
Lower throughput translates into lower revenues until we start to see recovery in the economy. In our Terminals business, most of our revenue comes from MWCs, monthly warehouse charges, but ancillary services, blending for example, are more throughput-driven. So, we see some deterioration there. This is partially offset by increased demand for previously unleased capacity. Almost every tank we have is now under contract.
On refined products volumes specifically, we believe this is not a permanent change. It’s temporary. There are all kinds of views about how long is temporary and when we will get to the other side, but we will get there.
For gathering and processing assets, we’ll be negatively impacted by reduced producer activity. We are seeing increased interest, however, in our Haynesville assets, but that will take some time to ramp up.
Overall, reduced producer activity negatively impacts this part of our business. As a reminder, gathering and processing, when you put the gas portion of it together with the products portion is only about 10% of our budgeted segment EBDA.
Finally, in our CO2 business, commodity prices are an obvious negative. However, we did a lot of hedging earlier in the year. And as you can see in the updated sensitivities page that we included in this quarter’s earnings package, our exposure to oil price changes is reduced going forward. We’re focused on our free cash flow. And our capital reductions for 2020 in this segment are expected to offset the distributable cash flow decline for 2020 in the segment.
The outlook numbers Kim will take you through are based on a bottoms-up reforecast we worked on with each of our business units and corporate staff. That review focused on margin impacts and cost savings opportunities. We also fully reviewed our capital expenditures, as I mentioned. It’s challenging to give guidance in uncertain times like these. We think we addressed that challenge by giving you our estimate and also giving you estimated sensitivities.
And with that, I’ll turn it over to Kim.
Okay. Thanks Steve.
Let me mention quickly a few stats for the quarter and how those have changed more recently. And then, I’ll spend most of the time on our outlook for the balance of the year and the assumptions underlying that outlook.
For the quarter, our natural gas transport volumes were up 8% or 3.1 Bcf a day. As we progress through April, we continue to see strength in these volumes. Let me remind you though that on our transport pipe, most of our volumes are under take-or-pay contract. So, to the extent that we do see a drop-off in volumes in the future, we would not be impacted.
Our gathering volumes are down 2% in the quarter. The decline -- or actually, they’re up 2% in the quarter. The declines in the dry gas basins were slightly more than offset by an increase in the volumes in the associated plays. However, we are seeing volume reductions in the associated plays in April, and we expect more in May.
Petroleum product demand was flat for the quarter. It was positive in January and February, and then we saw an 8% decline in March. Currently, we’re seeing about a 40% to 45% reduction in refined products volumes, which will impact both, our Products Pipeline and our Terminals segment.
Crude and condensate volumes were up 9% in the quarter, and unlike petroleum products, stayed strong in March. But, they are coming off in April and we expect more degradation in May. For the full year, we’re projecting to come in about 8% below budget on the EBITDA and about 10% below budget on DCF. So, we’re projecting roughly $7 billion in EBITDA and roughly $4.6 billion in DCF.
We’ve reduced expansion CapEx, as Steve mentioned, by approximately $700 million or almost 30%. So, the reduction in DCF is more than offset by a reduction in CapEx, resulting in DCF less CapEx that is approximately $200 million better than our budget. We currently expect to end the year at 4.6 times debt to EBITDA.
Now, let me break down 8% variance on EBITDA into six buckets, to help everyone understand. The first bucket is lower commodity prices, and this is all commodities, are expected to have a little less than 2% impact. We’re assuming an oil price of about $30 per barrel on average for the balance of the year. And our sensitivity to oil, as Steve mentioned, has been reduced. There’s about 1.7 million per dollar change in the price per barrel. So there’s not much sensitivity here, given the hedges we have in place.
The second bucket, lower natural gas gathering and processing volumes, also projected to have an impact of a little less than 2%. For Q2 through Q4, we’re assuming about a 12% volume reduction. But, there’s lots of variations between the assets, depending on which basin they serve. For example, on some of our assets, we project well over a 30% decline in volumes, while on other assets we expect a much smaller decline.
Overall, on natural gas G&P assets, our assumptions result in approximately 20% reduction in EBITDA versus our budget for the year. And one of the primary reasons for the discrepancy between the volume decline and the EBITDA decline is that we are projecting greater volume declines on our higher margin assets.
The third bucket, lower refined products volumes, expect that to impact us a little less than 2%. This takes into account the impact on both, our Products Pipelines segment and our Terminals segment. Here what we’re assuming in our outlook is an 18% to 20% reduction in volumes versus our budget for the balance of the year with a 40% to 45% reduction in Q2, decreasing to 10% to 12% in Q3 and 5% to 6% in Q2 and Q4. These three buckets, commodity prices, natural gas gathering and refined products at a little less than 2% each, account for roughly 5.5% of the 8% variance.
The fourth bucket, lower crude and condensate volumes, expected to have an impact of about 0.7% of EBITDA. We’re assuming a 19% reduction in volumes Q2 through Q4 versus our budget. These numbers include the impact on both, our gathering systems and our pipeline transport volumes.
The last two buckets, lower capitalized overhead, which is a result of the decrease in capital spending and lower CO2 volumes, together account for about a 1% variance.
And we mentioned that as we determined the impact on EBITDA, we have taken into account and netted out of the numbers that I mentioned, about $80 million in OpEx and cost savings, some of which is fuel and power that is directly related to the lower volume.
So, that covers the most significant pieces in the EBITDA forecast and largely explains the 8%.
On the positive side, we’ve got about a $100 million in savings between lower interest expense and lower sustaining CapEx. So, the 8% reduction in EBITDA less the savings on interest expense and sustaining CapEx roughly gets you to the 10% impact on EBITDA.
Now, we’re operating in a highly uncertain and changing environment. It’s difficult to know how quickly economic activity may normalize. So, in table 8 of the press release, we have provided you with sensitivities around the biggest moving pieces of our forecast. And that is so that, as things change, you can calculate the impact on our forecast.
And with that, I’ll turn it over to David Michels.
Thank you, Kim.
First, I’d like to recognize our accountants, our financial planners, our tax department, our Investor Relations and everyone else who had a hand in Kinder Morgan’s closing and reporting processes this quarter. We’ve been working remotely since March 16th and in that time, we’ve successfully closed the quarter, effectively performed our control procedures and prepared a detailed full-year forecast update, sensitivities to that forecast as well as significant supporting analysis. And despite all of that extra work and all of the extra challenges, we met our close and reporting schedule. And that’s a result of the resolve and the commitment of our coworkers. So, great work.
Moving onto the quarter. As you -- current events had a negative impact on our expected net income, EBITDA and DCF. However, with the identified capital expenditure reductions, we expect to be able to fully fund our cash needs, including our capital expenditures and dividends with our distributable cash flow. Additionally, we have an undrawn $4 billion credit facility to provide ample liquidity, even considering our upcoming maturities. We have about $950 million of debt maturing in September, another $1.9 billion maturing in the first quarter of next year, plus, despite significant current market turmoil, the investment grade debt capital markets have generally remained open and have been available to us.
Furthermore, even with the forecasted EBITDA change, we currently project a year-end debt-to-EBITDA level of 4.6 times from our budget of 4.3, but still consistent with our long-term leverage target of around 4.5. However, despite our ample liquidity, relatively insulated business and overall financial health, we believe it’s prudent not to increase our dividend by 25%, as previously expected. So, we are declaring a dividend of $0.2625 per share, which is a $1.05 annualized or a 5% increase from last quarter, but below our budget of $0.1325 per share or $1.25 per share annualized.
Now, moving onto the earnings performance for the first quarter of 2020, compared to the first quarter of last year. Revenues were down $323 million, driven in part by lower natural gas prices versus Q1 of 2019. The lower natural gas prices also drove a decline in the associated cost of sales of $285 million. As a reminder, given the way that we contract, particularly in our Texas Intrastates business, gross margin is a better indicator of our performance than the revenue alone. And this is a good illustration of that. Additionally, Q1 2020 [Technical Difficulty] sale of our KML and U.S. portion of our Cochin pipeline, which collectively contribute about [Technical Difficulty] of EBDA in the first quarter of 2019.
We have a loss on impairments and divestitures of $971 million this quarter, and that includes a $350 million impairment on our oil and gas producing assets in our CO2 segment as well as [Technical Difficulty] million impairment of goodwill associated with that same segment. Those impairments were [Technical Difficulty] sharp decline [Technical Difficulty] that we experienced during the quarter. Largely driven by the impairments, we had a net loss attributable to KMI of $306 million for the quarter. Our adjusted earnings, which is our non-GAAP term for net income adjusted for certain items, were down $300 million compared to the first quarter of 2019 -- $30 million compared to the first quarter of 2019. Adjusted earnings per share was $0.24 for the quarter, down $0.01 from Q1 of 2019.
Moving on to DCF performance. Natural gas was down 2% for the quarter. Unfavorable impacts there include our sale of Cochin, TGP being down due to 501-G impacts and a milder winter than expected last year and lower gathering and processing contributions at KinderHawk, North Texas and Oklahoma. Partially offsetting those were contributions from the Elba Island liquefaction and Gulf Coast Express projects.
Products was down 7%, driven by oil price impacts on our crude and condensate assets. Terminals was 14%, mostly due to the sale of KML and the Canadian terminals. CO2 [ph] was down 7%, driven by lower CO2 and oil volumes, partially offset by higher realized oil prices.
Our G&A and corporate charges were both lower by $18 million due to lower non-cash pension expenses and the benefit from the sale of KML, partially offset by lower capitalized overhead. Our JV DD&A and non-controlling interests, there were $19 million of deductions between those two and those are explained mainly by our partner sharing in the Elba Island greater contributions. And that explains the main changes in adjusted EBITDA, which was 5% lower than Q1 2019.
Total DCF of $1,261 million is down $110 million or 8%. DCF per share is $0.55 per share, down $0.05 from last year. To summarize the DCF impacts, we had pricing and volume impacts on the [Technical Difficulty] of about $7 million weather and 501-G impacts on TGP was another $27 million with greater sustaining capital of $26 million, greater pension contributions of $18 million and the KML sale impact on our DCF by about $18 million. The sale impacted the segments by 74, but had offsets in interest G&A and NCI. Those items were partially offset by the net contributions of Elba Liquefaction and GCX projects, which contributed about $52 million. And that gets to 107 of the 110 change.
Now, adding a little bit to what Kim provided for the full year 2020 guidance, I’ll provide some by segments. Natural Gas segment is projected to be down 4% from planned for the full year, driven by lower gathering and processing activity levels. Products is expected to be down about 17%, driven by lower refined product volumes, lower crude pipeline volumes and unfavorable price impacts. Our Terminals segment is projected to be down 5%, driven by lower throughput. And while that segment is largely take-or-pay, as Steve mentioned, we do have lower ancillary service revenues. Truck rack revenues and both businesses impacted by lower throughput. CO2s is expected to be down 16%, driven by lower oil and NGL price, lower CO2 and oil production volumes as well.
G&A, our lower capital spend leads to lower capitalized overhead, but partially offset by non-GAAP pension income and cost savings.
So, that provides the main items driving our EBITDA 8% lower by segment. Kim mentioned our new table 8. And I would also like to note that while we don’t foresee this as a material risk at this point, as our as our assets generally provide critical infrastructure services, we may be exposed to potential credit default events. We do not forecast any potential impacts. So, if experienced, we could see further pressure on the forecast.
I’d also like to draw your attention to a supplemental slide deck that has been posted to our website. That provides more information on the assumptions for the year, as well as some helpful information on our assets, customers and contract mix.
Finishing up with the balance sheet. We ended the quarter at 4.3 times debt to EBITDA, which is consistent with where we were at the year-end. With the 8% EBITDA impact, we expect that to increase to 4.6, as I mentioned, by year-end. And I think the current events underscore just how important it is to have reduced our debt by nearly $10 billion since 2015.
Our net debt ended the quarter $32,560 million, down about $470 million from the year-end. To reconcile that change, we had $1.261 billion DCF. We received proceeds from the sale of Pembina shares of $900 million. We had a growth capital and JV contributions of about $500 million in the quarter. We paid dividends of about $570 million. We paid taxes for some deferred Trans Mountain sale taxes, as well as some taxes on the Pembina share sales of about a $160 million. We bought back $50 million worth of KMI shares. And we had a working capital use, mainly interest payments, bonus, property tax payments in the quarter of about [Technical Difficulty] million. And that gets you close to the $469 million change in net debt for the quarter.
With that I’ll turn it back to Steve.
All right. Thanks, David. And Denise, we will now open it up for questions. And as we have been doing for the past several quarters here, we ask that you hold your questions to one and one follow-up. And then, if you’ve more, get back into queue and we will get back to you. Denise?
Thank you. We will begin the question-and-answer session. [Operator Instructions] And our first question today comes from Jean Ann Salisbury with Bernstein. Your line is now open.
Hi, guys. On the contracting of the terminal capacity to get up to a 100%, did you only contract that space for one year or will that extra cash flow persist for longer? And I just wanted to clarify that’s already in the new guidance.
Yes, it’s already in the new guidance, and we contracted for a variety of terms. And John Schlosser, why don’t you elaborate on that?
Sure. It was anywhere from one, two years. We started off the quarter at 2.3 million barrels of available capacity. And as we stand today, we’re down to 727,000, and most of those are very small chemical tanks. Well, we expect that to continue to shrink as the month goes on and get closer to zero as we finish out the quarter -- or the month. Excuse me.
Okay. That makes sense. And that was also a third party as we shouldn’t expect to see exciting marketing earnings from the contango from KMI, right?
All third party.
Okay. Thank you. And then, can you -- the CO2 business is obviously kind of the most exposed to oil price. Can you give us a sense of what the minimum amount of CapEx going forward would be to kind of keep that business intact over the next few years?
Yes. Again, we invest our CapEx in the CO2 business based on the returns that it produces. In other words, there’s revenue associated with the oil that comes with the capital that we invest. And we look at that and we stress test the pricing through that oil and we determine whether or not it meets our hurdle criteria. Obviously, those prices have come down. That’s why we’ve taken about $130 million of CapEx out. So, we’re not investing to try to keep it flat. What we invest in is based on the incremental economics of those investments.
We’ve been holding to a relatively small decline rate with the CapEx that we’ve been investing. We would expect that decline rate obviously to increase a bit, remains to be seen exactly, but increase a bit with us pulling capital away from that business. But again, we invest the capital based on the incremental economics that we get.
Our CO2 lifting -- our lifting cost for most of our investments right now is about $20. And that includes a CO2 price at a market price for CO2, not what it costs us to produce that CO2, which is much lower. And so, we look at our production, make sure that it makes sense to continue to produce it. And as I mentioned, we have that substantial portion of it hedged.
The next question comes from Shneur Gershuni with UBS. Your line is open.
Hi. Good afternoon, everyone. I appreciate the tough environment that everyone is in terms of trying to put together guidance and to appreciate the sensitivities that you’ve put out today. I was just wondering if we can focus on the refined product business for a second here. When I look at your Q2 assumptions for 40% to 45% reduction from budget for refined products and terminals, can you provide a little bit of color around the inputs that went into those assumptions? Is that what you’re experiencing today and you’re carrying it through to the end of the quarter, or is there some relationship to refinery utilization that we should be watching? I’m just trying to understand what signposts we should be looking at when thinking about the volumes, as it runs through the refined product segment as things unfold in this difficult environment?
Yes. Good question. And so, we did this at a fairly high level, as you heard from Kim. We sort of did it quarter-by-quarter -- we did do it quarter-by-quarter. And it was based on a current, and I mean, current as in current month kind of activity that we’re seeing on our assets, and also discussions with our customers that we had both in the products and in the terminals business. And so, that informed the assumptions that we use. Now, having said that, it’s a bit of guesswork right now for everyone. But, we made the best informed judgment we could based on the data that was available to us. And then again gave you some sensitivity, so that you could adjust it based on different assumptions if you have them. But, I think it was fairly informed based on actual experience for early at least in the second quarter, but also conversations with customers. Kim, anything you want to elaborate on there?
I think that covers it.
Okay.
And for a follow-up question, I think, we appreciate the prudence around the dividend increase being only to 5% versus 25%. Definitely, I appreciate the comments about that you have the ability to actually pay it out of cash flows if you chose to do it and you’re looking to revisit in the fourth quarter of this year. Just wondering if the balance of 2020 turns out better than you’re currently budgeting, would you be open to returning cash flow to shareholders via buybacks as an alternative means to returning shares under the existing -- returning cash flows under the existing buyback program?
I’ll try to answer that. Again, our anticipation is that we want to go to the $1.25 when normal -- when the economy is normalized. And we think there is an excellent chance that will happen by the fourth quarter. That’s why we put it in the way we did. I don’t think we are -- while I would never say never, it’s not our intention to do significant additional buybacks this year. But again, we’ll watch the whole situation very carefully. I think, as Steve has said, these are really unprecedented times. We’re just trying to be very conservative and very protective of the strength of our balance sheet and provide all the flexibility we can for the Company.
The next question comes from Jeremy Tonet with JPM. Your line is open.
Hi. Good afternoon. I just want to start off with the proceedings before the Texas Railroad Commission here. And in the event that there is action to prorate production, would you be able to kind of walk us through what that would mean for KMI, the EUR, CO2 business, the nat gas pipes? Would this invoke some type of forced majeure on taker-or-pays? I realize this is highly unusual situation and question, but just wanted to see what you guys’ thoughts were.
Yes. So, we’ve evaluated our force majeure provisions. And while there’s some -- there is some variability in them. If you look at our tariffs on the interstate natural gas transportation business in particular, which is a big -- obviously a big chunk of our overall business, force majeure events do not excuse obligation to pay. And so, even if something technically qualified as a force majeure, and I’m not saying that this would, but even if it did under our interstate tariffs, it wouldn’t be a force majeure on the obligation to pay.
Now, in terms of whether they’ll actually go ahead with this, and how it will look when it happens and how it would be different from what’s going to happen anyway with people taking the right economic steps, based on the price signals that they’re getting in the market, I think that’s anybody’s guess. But, at least when it comes to our transportation tariffs, we think we’re fairly well insulated there.
When it comes to CO2 production, I’ll ask Jesse to supplement anything that he sees there. But, I mean, we’re reacting to price signals too as we expect others are and would expect in the event, and again, I don’t think it’s very likely but in the event they did put in some kind of proration, I think we can we can comply with it and probably would be complying with it just in the normal course, if that’s what price is telling us. Jesse, anything you want to add to that?
Yes. I think you’ve covered it there from the production side. Just on the takeaway from that perspective, we do not have minimum volume commitments. So, our takeaway contracts would not be affected by the proration.
And you talked about in the G&P that there’s declines in certain basins. I was just wondering if you could walk us through a bit more detail what you’re seeing in the various basins and where actual shutting happening or any more color you could provide on what’s happening on the ground right now?
Okay. Tom, I’ll ask you to elaborate on that.
Yes. I mean, it’s very early days. And I think we’re seeing this probably real time starting now and more so I think as we get into May that all the associated gas plays are going to be primarily where we see this. Some Permian volumes will be declining or coming off. We think clearly the Bakken will be impacted as well. Those are probably the two biggest areas that we’re seeing. Now, the other side of the coin, I think as we progress through the year, we’re already getting some inbound inquiries about incremental activity in our dry gas basin part of the network, Haynesville particularly. So, I think we’ll see some potential offset in those areas maybe late this year, early next year.
The next question comes from Colton Bean with Tudor, Pickering, Holt & Company.
So, just to follow up on the question there around the EUR business. Steve, I think, you mentioned that lifting cost is around $20 a barrel. To the extent that -- acknowledging that you guys may not have or you have integrated economics on the CO2, if you were to see a price that drops below even those integrated economics, is there any ability to defer production and settle your hedges on a financial basis or even purchase in basin, if physical volumes are needed?
Yes. There is the ability to turn down production and just collect on the hedges. We have a customer on the other end of those contracts. So, we would be judicious about that, but there is some flexibility to do that.
And then, just following up on the CapEx side of things. I think, you all noted that you had taken out about $700 million in 2020, quite a bit more than I think CO2 could account for it. So, could you just frame for us, within the other segment, what the moving pieces were there?
Yes. And on the -- oh, go ahead, Kim.
Go ahead.
Yes. So, if you look at the slide deck that David referred to, on page five, we break that out for you. And so, in natural gas, for example, we pulled down CapEx by about 460. A lot of that is in either removed or deferred G&P investments. In products, it is about $90 million. And that’s really -- a lot of that is coming from some reduction in the crude or the gathering business that is part of that segment.
In Terminals, there was a few project deferrals in there. And then, CO2, about 130 that I mentioned -- Terminals was 30, by the way, I don’t know if I said that. CO2, about 130, most of that is project deferrals into a different -- until we see a different price environment. Kim, anything you want to add to that?
No
Okay. All right.
The next question is from Spiro Dounis with Credit Suisse. Your line is open.
Hey. Good after, everyone. Glad to hear you’re all doing well. Just a higher level question, if you’ll entertain. I guess, we’ve all been through a few cycles at this point. So, I would certainly appreciate your point of view on this. And just around the downturn, does this one feel different in terms of its lasting impact on the sector? Rich, I know, you mentioned getting back to normal by fourth quarter, but got to think at least on the supply side, maybe there’s a lasting impact here. And just more broadly, what you think KMI needs to do to adapt? I don’t want to lead you too much. But, do you see yourselves pivoting back towards dry gas basins here or shifting your strategy in any sort of meaningful way?
I’ll start and ask Rich to add to this. I mean, this is certainly different, unprecedented when you put the combination of the two things, the OPEC Plus falling apart on March 6th, together with COVID crushing demand. And I think you have to look at those two things separately in terms of duration. On COVID, again, it’s still anyone’s guess, but it is -- it’s a virus. Virus tends to be temporary, even if it comes back, it will still be a temporary phenomenon. And we would expect demand to return to normal for refined products, for example. And as Kim mentioned, we’re not really seeing much degradation yet in our natural gas demand and natural gas throughput. When you look at the OPEC Plus situation, if -- even with a return to normal economic activity, if the coalition, if you will, doesn’t hold together and the market is forced to balance on just fundamentals of supply and demand, that could take longer or that could be a more lasting impact, which would have an impact on the shales and the near term, additional gathering and production investment that we would otherwise have planned to make. That could last longer, unless a deal is put together in a better economic environment than what we’re experiencing today.
On your point about being able to pivot to dry gas plays, we do have that ability. If you think about our assets, our natural gas assets, we serve dry gas plays like the Marcellus, Utica from a transmission standpoint and storage standpoint with our Tennessee Gas Pipeline system. We serve the Haynesville, as Tom mentioned. And we’ve got plenty of room to grow to the extent the dry gas market -- or to the extent that the gas market comes back into balance with a reliance less on associated gas volumes, and more on dry gas volume.
Rich, anything else you want to add about cycles?
No. I think, you’ve covered it, Steve. I agree.
And then, just to circle back on the CapEx reductions. I guess, what percentage of the total CapEx cut would you say -- or CapEx reduction would say is an actual cut versus natural deferral? I can see obviously the backlog there is down about I think $300 million or so since the fourth quarter, but I know there’s a lot of moving pieces in there. So, just help understand what you guys have actually trimmed out on a permanent basis here?
Yes. So, that’s hard to say, right? Because, it depends on if there’s a recovery in commodity prices and when that occurs. And that’s what would drive back in more CapEx on G&P for example, and on CO2. And so, you kind of have to ask yourself, what do you believe about that? We’ve talked about it as a management team, and this is -- definitely goes in the category of forward-looking statement, because nobody knows for sure right now. But, we’re below the $2 billion to $3 billion threshold, obviously, at 1.7 for this year. And our best guests, and it is just a guess at this point, is we’re going to run below that $2 billion to $3 billion range, as we look ahead to 2021 as well, barring some real big turnaround. And it would be awhile before we get back to kind of that 2 to 3 range. And it would require, I think, as I said, some return in producer activity, driven by a better commodity price environment.
The next question is from Gabe Moreen with Mizuho. Your line is now open.
Good afternoon, everyone. A quick question on I guess the language around exposure to credit default events. Maybe I could just drill down, and I don’t mean to sort of fish for negatives here at all. But any discussions you’re having with customers around areas of concern there, maybe some surprises you’ve seen in portfolio and portfolio in terms of customers, maybe approaching you for, maybe some lead contractually? I’m just curious whether that was based on specific current customer discussions or generic legal language?
Well, it is a fairly generic comment, but let me tell you how we look at credit, Gabe. We look at it -- on our Monday meetings, it’s the second topic we cover every Monday, and we go through and we evaluate it customer by customer who has some difficulty, has there been a credit downgrade, what are the outstanding receivables, et cetera, et cetera. But we also look at and we seek collateral and we call them collateral where we have the rights to do so. And we also look at what is the underlying value of the capacity that that particular customer is holding, and to what extent, in a worst case scenario, will they still need that capacity in order to be able to get their product to market and therefore unlikely to reject the contract. So, we try to take all of those things into account.
Now, there’s no good analogy to the current year. There just isn’t. But, if we look at something that was similar in terms of impact on the producers segment, we go back to 2016. Our bankruptcy defaults in 2016 amounted to about $10 million. Now, this is -- for all the reasons I said before, it is a worse year than that, but we have those mitigations that I mentioned. It’s also a little bit difficult to call your shots on who you think is going to tip over or not tip over. Maybe they do a debt restructuring instead, et cetera, et cetera. And that’s why it’s very hard for us to project it. But I think it was appropriate for David to mention it because we don’t have it in our revised forecast.
I appreciate that. Thanks, Steve. And then, as a follow-up to that on PHP. Can you talk about how capital contributions from your JV partners work? What were to happen if maybe let’s say in the unlikely scenario a capital contribution from a JV partner would not come through? And then, I guess also would you be willing to talk about what the credit rating is for that one producer on the pipe that I think holds 20% of the project?
Tom, I’m going to ask you to answer that. I’m not familiar with how dilution works and that sort of thing under the agreements. Do you know?
Yes. Actually, I don’t off the top of my head, Steve.
Okay. Anthony, do you have any insight to offer on the capital calls? I mean, they’ve all been going well, but any other insights.
No. Obviously, they have been going well. And there is support for credit, support for the shipper, the equity owners that are non-investment grade or unrelated, to the extent they did not put in a contribution as we have support.
Credit support for the capital contribution?
Right.
The next question comes from Michael Lapides with Goldman Sachs. Your line is open.
Hey, guys. Thank you all for taking my questions. The first one is on the refined products business, which is your 40% plus demand downtick in the second quarter. When you look at your refined products pipeline system relative to kind of the broader United States system as a whole, is there something about your system in particular where you think it could be better or worse than kind of the broader nation or do you think yours is a good proxy for what’s happening in the broader U.S.?
Yes. So, Michael, I won’t try to speak for others, but think about the markets we serve, right? The SFPP system is our largest system. It serves California. It serves Arizona. If you think about our plantation pipeline system, that really serves the Mid Atlantic. Its point of terminus is the national airport near Washington DC. And so, you’re talking about Southeast to Mid Atlantic markets there. And the other system is our CFPL system, which serves Tampa and Central Florida. And so, you can think about differences in demand and differences in response to this virus and how that’s playing out in different places. You can also think about how it’s playing out and which will be likely to recover earlier. And, I’ll just ask you to make your own assumptions about that rather than me trying to speculate for other people’s pipelines.
Got it. Thank you for that. And then, one other one looking at slide 12 and kind of the commentary about your customer base and their credit ratings. Just curious, have you all looked at the 76% or so that the outlined as being investment grade? And how many of those are on credit outlook, negative watches? Meaning, we’re seeing lots of fallen angels in the energy credit world these days. And I’m just curious how many -- or what percent of that -- what portion of that 76% you think might be migrating from investment grade to high yield?
Okay. Yes. So, the 76% is investment grade as well as substantial credit support, and the other thing we identified is, our estimate of approximately 1% exposure on our budgeted net revenues from those who are B minus or below. And so, those are kind of the fence posts we put out there. I don’t know the proportion of that 76% that is on negative outlook. I will ask Anthony if you happen to know.
I think most of that already has been incorporated into the update. I think, there’s probably a small, very small percentage that on negative outlook. But generally to the extent they’re on negative outlook and they get dropped from investment grade to non-investment grade, it would trigger a right for us to draw on collateral, but it’s a relatively small percentage.
The next question comes from Ujjwal Pradhan. Your line is open. Ujjwal is with Bank of America. Thank you.
First one for me, regarding options for crude oil storage within your asset platform. Are there any options that you’re exploring to provide additional storage capacity, given the shortage recently? And do you have -- 16 Jones Act tankers with over 5 million now of potential capacity. Can you comment if all of that is contracted out or if there’s a possibility of using that capacity?
Yes. I’ll take the last part of that first. It is all under contract on the Jones Act capacity. And John will elaborate on this. But, there is a reluctance to -- and it’s under our customer’s control. Right? It’s under our customer’s control. And it’s mostly clean products, as I mentioned, and there is a reluctance to convert those to dirty products, where we don’t already have them in dirty products service, dirty being crude I mean, and because of cleaning costs et cetera. But John, anything you want to add to that?
You’re correct. Two-thirds is in clean, it won’t be converted back to crude, and the other is just the economics on the smaller MR sized vessels for storage doesn’t make sense from our customer standpoint.
And then, on the crude storage, I mean, again, it makes sense for our refined products assets to be in refined product service. That’s where most of our tankage is. And as John pointed out, it is filling up rapidly. On the crude side, we do have some limited storage capability in our CO2 business as well as in our products pipeline business, but it’s not -- it’s not particularly material.
And as a follow-up, after the Keystone pipeline ruling in Montana last week, I saw there were few headlines raising questions about potential challenge to bring in highway permits as well. Can you comment on the potential legal challenge there?
Yes, sure. We are aware of the decision, obviously. It is not stopping us from continuing our construction at this point. I’ll just say that it’s hard to imagine that that decision applies outside of the project that that decision was related to, particularly when you think about the implications of all of the various projects that are operating under Nationwide Permit 12 from the Army Corps, and all the jobs that are at stake et cetera. It’s hard to imagine that as a country we would send those people home during times like this. So, look, we wouldn’t expect this decision to stop our construction on PHP. And an important fact there is that we already have -- we have an existing authorization, a verification under nationwide rule 12 that applies to PHP.
The next question is from Pearce Hammond with Simmons Energy. Your line is open.
Picking up on Spiro’s earlier question. During this downturn, are there opportunities to strengthen the Company and make it even better enterprise coming out of the downturn? And if so, what are some of those steps or opportunities that you could take?
Yes. As I said at the beginning of my remarks, I think we took a lot of really important steps over the last several years to make our Company stronger. Certainly, what we’re doing, continuing to operate and operate well and operate the way we have been. It has been -- it strengthens our organization. In terms of further strengthening the balance sheet, we are following the capital allocation priorities that Rich outlined and that I outlined. And we do feel comfortable with our current leverage metric in terms of supporting the rating that we have. And we stay in close contact with the rating agencies and believe that they agree with that. We’ll always look for opportunities to get stronger. But, I think we’ve done a really good job of getting to where we are right now.
Thank you, Steve.
The next question is from Tristan Richardson with SunTrust. Your line is open.
Hey, guys. Good afternoon. Just a quick follow-up to an earlier question on what you guys are seeing in midstream. With respect to the revised expectations there, conceptually, can you talk about how much of the revision is due to either expected shut-ins of existing production or versus previously expected volume growth that is just now no longer expected to materialize?
Yes. So, I think, what we tried to do, as I said before, was we looked closely at what our current activity levels were, but also had conversations with our customers to try to understand what they were seeing coming. And look just -- that’s going to be an evolving situation. Shut-ins will be the right solution for certain wells for a certain period of time.
But, I think, there’ll be instances where there’s a prioritization going on. And some of our customers even pointed out that they may drill other wells and shut in other ones that are not as economic, because high GOR, water handling costs, all kinds of things. So, there is a whole variety of considerations that will go into that. But I think, doing this quarter-by-quarter, I think we captured at least our best guess and informed by what our customers are telling us that the deep negative that we’re seeing right now, as well as what we expect that to average out to for the quarter. Kim, any additional detail there?
No, I think you covered it.
Okay.
Thanks. And just second, on the cost saving side, Kim, you talked about the $80 million in operating cost savings and $100 million in lower interest costs? I think, you mentioned capitalized overhead. But, do you guys see any further opportunity on the G&A side?
Kim, go ahead.
Yes. I mean, in these numbers, we’ve taken into account G&A savings, things have come from not traveling, things like that. So, we have tried to take into account G&A savings. The $100 million, just so you know was -- half of that about is on interest and then half of that on sustaining CapEx. So, that $100 million was a combination of interest and sustaining CapEx. But, we did take into account G&A savings in the $80 million.
And the other thing I would add there is we continue to look for opportunities to save costs without compromising the safety and integrity of our assets. One phenomenon that we’re really just on the front end of, and we’ve seen -- we’ve reflected some of this, but I suspect we haven’t reflected all of it yet, is that as we’re going out to our vendors and service providers, we’re getting good cost reductions, and we’re really on kind of the front end of that. People are anxious to do business with us. They’re anxious to have work wherever they can at this point. And Jesse and his team in CO2 for example, they’re in the early part of their cycle at getting those sort of price and term concessions from the people who provide services to us. And so, I think that can lead to additional capital and OpEx savings as we progress on. But, obviously there are negatives on the other side as there are with any forecasts. But, I think that is one thing I would point to.
Yes. And Steve, you know, the other thing our forecast mentioned is that we’ve assumed that a lot of work just gets pushed to later in the year and that we can get basically double the work done in certain cases. And so, there is the potential that we have, other things move out of the year that we just haven’t been able to project at this point.
The next question is from Danilo Juvane with BMO Capital. Your line is now open.
Thank you. I really have a follow-up on guidance. To the extent that it was informed by conversations with your customers, how confident are you that you’ll be able to hit updated numbers? And could you see further revisions to your leverage objectives as well as your dividend growth target for the year?
Kim, do you want to take the first stab at that?
How confident are we in these numbers? Look, we did a bottoms-up review. We involved all of our business units. We tried to get in all the data that we could from what we were seeing from our customers. And so, we took our best stab at it. But, as I said earlier, it is a highly uncertain market. And so, we don’t know if those judgments are going to prove to be correct. And so, that’s why we have given people, one, clarity into the judgments we made about how much we were taking down volumes; and then, further provided a sensitivity. So, to the extent that volumes end up worse than what we are projecting or better than what we are projecting, people can adjust our numbers in the future.
The next question comes from Becca Followill with U.S. Capital Advisors. Your line is open.
Good afternoon. First, thanks for the level of detail. I know how difficult this is to put together. And it’s really very helpful. Second, on CO2 business, there is huge uncertainty. We don’t know how prices are going to shake out. You guys are pretty heavily hedged for this year, but not as much for next year. Can you talk about what shut-ins would mean for that business in terms of how durable is the field? If you do shut it in, would it take additional capital to bring it back? Can you just curtail it back and then bring it up to kind of ease things or just kind of bigger picture on CO2?
Sure. And I’ll ask Jesse to supplement this. But, we’re not talking about shutting in fields. There may be some turndown here and there, depending on the price signals we’re seeing in the cash market, as we talked about earlier. But for example, in our three smaller fields, we’re looking at, instead of introducing a new CO2 in those fields, just recapturing the CO2 that comes out with our oil production and recycling it in those fields. So, it’s not about shutting it down. It’s more about dialing it back and under the current market environment, not introducing new CO2 into it. But, Jesse, why don’t you comment further on that?
That’s a good summary there, Steve. But, I think where we are, Becca is, we’re obviously high grading the production in each field and optimizing the highest cost production, highest gas to oil ratio. So, we’ve taken steps to curtail that production. Each field is different, different reservoirs, different wellbore, diagram. So, where you have pumps, there’s obviously some risk that you have to pull those, if you restart. But, from a material perspective, we think that most of the production will come back with a very little capital required. You will have some instances where you have to work over a well and restimulate it to get it going. But right now, we’re just high-grading production and getting the most profitable barrels to market.
Thank you. And then, what basis differential are you guys assuming for the rest of the year?
Jesse, do you want to answer that as well? Are you talking about Mid-Cush?
Yes.
Go ahead Jesse. We hedge that...
Yes. With respect to Mid-Cush, we are virtually 100% hedged there at a positive $0.14. So, we’ve taken that risk off the table.
Thank you. And there are no other questions at this time.
Thank you very much. And have a good evening. Stay safe and stay healthy. Thank you.
This does conclude today’s conference call. Thank you for participating, and you may disconnect at this time. Speakers, allow a moment of silence and standby for your post conference.