Kinder Morgan, Inc.

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. At any time, you may press star 1 on your phone to ask a question. 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 released today and this call include forward-looking statements within the meeting of the Private Securities Litigation Reform Act of 1995 and the Securities 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 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 faced 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 50 cents, we said we expected to increase that dividend 80 cents in 2018 to $1 in 2019 to $1.25 in 2020. Met those expectations in both 2018 and 2019, and we have the financial wherewithal to meet the $1.25 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 four 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. In 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 Michaels, 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 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 the 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 now 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. Refined products pipelines are common carrier pipelines, so we get paid a fee on the actual throughput. Historically, throughput varied only slightly, usually growing a percent 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 unleashed capacity. Almost every tank we have is now under contract. On refined products volume 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. Our gathering and processing assets will be negatively impacted by reduced producer activity. We are seeing increased interest, however, in our Hainesville 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 early 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 this 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 address 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 contracts. 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 – actually, they're up 2% in the quarter. The decline in the dry gas basins were slightly more than offset by an increase in the volumes in the associated place. 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 are seeing about a 40% to 45% reduction in refined product volumes, which will impact both our product pipeline and our terminal segments. 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 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 the 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. is 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, is 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 GMP 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 product volumes, expect that to impact us a little less than 2%. This takes into account the impact on both our product pipeline segment and our terminal segment. Here what we're assuming in our outlook is an 18% to 20% reduction in volume 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 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, is 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. Let me mention that as we determined the impacts 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 volumes. So that covers the most significant pieces in the EBITDA forecast and largely explains the 8%. On the positive side, we've got about $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 Michaels.

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 Kendra Morgan's close and reporting process 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. It's a great work. Moving on to the quarter, the current events have 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 expenditure and dividends, with our distributable cash flow. Additionally, we have an undrawn $4 billion credit facility that provides 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 forecast EBITDA change, we currently project a year-end debt 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 $1.05 annualized, or a 5% increase from last quarter, but below our budget of $1.1325 per share or $1.25 per share annualized. Now, moving on to 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 intrastate business, this margin is a better indicator of our performance than revenue alone, and this is a good illustration of that. The 2021-20 flex sale of our KML and U.S. portion of our coaching pipeline, which collectively contributed about $74 million of EBITDA 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 C2 segment, as well as a $600 million impairment of goodwill associated with that same segment. Those impairments were driven by the sharp decline that we experienced during the quarter. Laws are 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 501G impacts and a milder winter than expected last year, and lower gathering and processing contributions at Kinderhawk, North Texas, and Oklahoma, partially offsetting those for 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 down 14% mostly due to the sale of KML in the Canadian terminals. T2 was down 7% driven by lower CO2 and oil volumes, partially offset by higher realized oil prices. Our GNA and corporate charges were 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 JVDD&A and non-controlling interests, there were 19 million of reductions between those two, and those are explained mainly by our partner sharing in the Echo Island greater contributions. And that explains the main changes in adjusted EBITDA, which was 5% lower than Q1 2019. Total DCF of $1,261,000,000 is down $110,000,000 or 8%. DCF per share is $0.55 per share, down $0.05 from last year. To summarize the DCF impacts, we had price and volume impacts on the segments of about $70 million. Weather and 501 impacts on TGP was another $27 million. It's greater sustaining capital of $26 million. greater pension contributions of $18 million, and the KML sale impacted 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 you 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 segment. Natural gas segment is projected to be down 4% from plan 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 bulk business that's impacted by lower throughput. CO2 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-cap 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 assets generally provide critical infrastructure services, we may be exposed to potential credit default events. We did not forecast any of those 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 pact, 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 $32,560,000,000, down about $470,000,000 from year end. To reconcile that change, we had $1.261 billion of DCF. We received proceeds from the sale of Pemina shares of $900 million. We had growth capital and JV contributions of about $500 million in the quarter. We picked dividends of about $570 million. We paid taxes for some deferred Trans Mountain sale taxes, as well as some taxes on the Pemina share sales of about $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 $400 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, do one and one follow-up, and then if you've got more, get back in the queue and we will get back to you. Denise.

Thank you. We want to begin a question and answer session. If you would like to ask a question, please press star 1, update your phone, and record your name clearly. Your name is required to introduce your question. And our first question today comes from Jeanann Salisbury with Bernstein. Your line is open.

Hi, guys. On the contracting of the terminal capacity to get up to 100%, did you only contract that space for one year, or will that extra cash flow persist for longer? And 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 Slosher, why don't you elaborate on that? Sure. It was anywhere from one to 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 all to third parties. We shouldn't expect to see exciting marketing earnings from the Contango or 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?

Yeah, 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 for 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 to keep it flat. What we invest in is based on the incremental economics of those investments. You know, 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 did. 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 a substantial portion of it hedged.

The next question comes from Sarah. Shunir Gershuni with UBS. Your line is open.

Hi. Good afternoon, everyone. Appreciate the tough environment that everyone is in in terms of trying to put together a guidance and do appreciate the sensitivities that you put out today. I was just wondering if we can focus on the refined product business for a second here. Sure. You know, 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 you know, the volumes as it runs through the refined product segment as things unfold in this difficult environment?

Yeah, 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 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, you know, 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 5% versus 25%. And, you know, definitely 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 by a buyback as an alternative means to returning shares under the existing, returning cash flows under the existing buyback program?

Yeah, so you're a... I'll try to answer that. Go ahead. again, our anticipation is that we want to go to the dollar and a quarter when normal, when the economy is normalized. And we think there's 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, 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, and 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 Tonette 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 EOR, CO2 business, and that gas pipes? Would this invoke some type of force majeure on take or pays? I realize this is a highly unusual situation in question, but just wanted to... see what you guys' thoughts were.

Yeah, so we've evaluated our force majeure provisions and while there is some variability in them, if you look at our tariffs on the interstate natural gas transportation business in particular, which is 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 a 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?

Yeah, I think you've covered it there from the production side. Just on the takeaway, from that perspective, we do not have minimum volume of commitment, so our takeaway contracts would not be affected by the probation.

That's very helpful. Thanks. And You talked about in the GMP 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, where are actual shut-ins 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.

Yeah, 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, you know, where we see this. You know, 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. You know, 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 space and part of the network in Hainesville 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 and Company.

Good afternoon. Just to follow up on the question there around the EOR business, Steve, I think you mentioned that lifting costs around $20 a barrel. To the extent that, you know, acknowledging that you guys may not have or you have integrated economics on the CO2, if you were to see a price that dropped below, even though it's 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?

Yeah, there is the ability to turn down production and just collect on the hedges. You know, 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.

Got it. 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. So can you just frame for us within the other segments what some of the moving pieces were there?

Yeah, and on the – oh, go ahead, Kim. Go ahead. Yeah, 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 was 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. and terminals, there was a few project deferrals in there, and then CO2 at the 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 until we see a different price environment. Kim, anything you want to add to that? No. All right.

The next question is from Sphero Dunas with Credit Suisse. Your line is open.

Hey, afternoon, everyone. Glad to hear you're all doing well. Just a higher-level question, if you'll entertain. I guess you've all been through a few cycles at this point, so we 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 do you think KMI needs to do to adapt? I don't want to leave you too much, but do you see yourself 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 the OPEC plus situation, you know, if, if, 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. 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, you know, 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 Hainesville, as Tom mentioned, and we've got plenty of room to grow to the extent that the gas market comes back into balance with a reliance less on associated gas volumes and more on dry gas volumes. Rich, anything else you want to add about cycles?

No, I think you've covered it, Steve. I agree.

Perfect. I really appreciate the color there. 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 you say is an actual cut versus an actual deferral? I can see, obviously, the backlog there is down about, I think, $300 million or so since this fourth quarter, but I know there's a lot of moving pieces in there. So just self-understand what you guys have actually trimmed out on a kind of permanent basis here.

Yeah, 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 GNP, for example, and on CO2. And so you kind of have to ask yourself, what do you believe about that? You know, we've talked about it as a management team, and this definitely goes in the category of forward-looking statement because nobody knows for sure right now. But, you know, we're below the $2 billion to $3 billion threshold, obviously, at 1.7 for this year. And our best guess, and it is just a guess at this point, is we're going to run below that $2 to $3 billion range as we look ahead to 2021 as well, barring some real big turnaround. And it would be a while 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 Maureen with Mizuho. Your line is open.

Hi, good afternoon, everyone. Quick questions 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 in terms of customers? maybe approaching you for maybe some contractually. I'm just curious whether that was based on specific current customer discussions or generic legal language.

Well, it was a fairly generic comment, but let me tell you how we look at credit, Dave. We look at it on our Monday meetings. It's the second topic we cover every Monday. And we go through and we've evaluated customer by customer, You know, 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 on 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 producer 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?

Yeah, 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 credit support for the equity owners that are non-investment grade or unrated. So to the extent they did not put in their contribution, we have support.

Credit support for the capital contribution.

Correct.

The next question comes from Michael Lapidus with Goldman Sachs. Your line is open.

Hey, guys. Thank you all for taking my questions. The first one's on the refined product business, which is when you're 40% plus demand down take in the second quarter, when you look at your refined product 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.?

Yeah, 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, and 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, D.C. 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 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 you 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. Yeah, 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- 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 very small percentage that's 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 Ujwal Pradhan. Your line is open. Ujwal is with Bank of America. Thank you.

Good afternoon, everyone. Thanks for taking my question, and thanks for all the updated guidance and budget sensitivities. First one for me regarding options for storage within your asset platform, are there, Any options that you're currently exploring to provide additional storage capacity given the shortage recently? And, you know, do you have 16 drone tank anchors with over 5 million barrel of potential capacity? Can you comment if all of that is contracted out or if there's a possibility of using that capacity?

Yeah, 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 product service, dirty being crude, I mean, 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 particularly material.

Got it. Thanks for that. And as a follow-up, after the Keystone Pipeline drilling in Montana last week, I saw there were a few headlines raising questions about potential challenge to Permian Highway. permits as well. Can you comment on the potential legal challenge there?

Yeah, sure. We're aware of the decision, obviously. It is not stopping us from continuing our construction at this point. You know, 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 you know, 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 of verification under nationwide rule 12 that applies to PHP.

The next question is from Pierce Hammond with Simmons Energy. Your line is open.

Yeah, good afternoon and thanks for taking my question. Picking up on Spiro's earlier question. During this downturn, are there opportunities to strengthen the company and make it an even better enterprise coming out of the downturn? And if so, what are some of those steps or opportunities that you could take?

Yeah, 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, has been it strengthens our organization. You know, 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 Kristen 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 the 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, you know, previously expected volume growth that is just now no longer expected to materialize?

Yeah. So, um, uh, you know, I think what we tried to do, as I said before, was, um, 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, that's going to be an evolving situation. You know, shut-ins will be the right solution for certain wells for a certain period of time, but I think there will 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 are 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, the deep negative that we're seeing right now as well as what we expect that to average out for the quarter. Kim, any additional detail there?

No, I think you covered it.

Thanks. And just a second, on the cost savings side, Kim, you talked about the $80 million in operating cost savings and $100 million in lower interest costs. And I think you mentioned capitalized overhead, but do you guys see any further opportunity on the G&A side? Kim, go ahead.

Yeah. I mean, in these numbers, we've taken into account G&A savings, you know, things that have come from not traveling, things like that. So we have tried to take into account G&A savings. And the $100 million, just so you know, was half of that about is on interest and then half of that's 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, you know, 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 forecast, but I think that is one thing I would point to.

Yeah, and Steve, you know, the other thing I'd forecast mention 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.

True. Helpful. Thank you guys very much.

The next question is from Danilo Giovanni with BMO Capital. Your line is 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 the 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? Well, 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 were projecting or better than what we were projecting, people can adjust our numbers in the future.

Thank you for that. That was my only question.

The next question comes from Becca Followell with U.S. Capital Advisors. Your line is open.

Good afternoon. First, thanks for this level of detail. I know how difficult this is to put together, and it's really very helpful. Second, on the 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 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 ratios, so we've taken steps to curtail that production. Each field is different, different reservoirs, different wellbore diagrams, so where you have pumps, there's obviously some risk that you have to pull those if you restart, but From a material perspective, you know, we think that most of the production will come back with very little capital required. You will have some instances where you have to work over a well and it's kind of re-stimulated 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, you want to answer that as well? Are you talking about mid-cush?

Yeah.

Go ahead, Jesse. We hedged that.

Yeah, with respect to mid-tush, we are virtually 100% hedged there at a positive 14 cents. 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 stand by for your post-conference.