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. 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 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. In July 2017, when we were paying an annual dividend of $0.50, we said we expected to increase that dividend to $0.80 in 2018, to $1 in 2019, and 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 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 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 a 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 while 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 EBITDA. 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.

Thank you, Steve. I want to quickly highlight some statistics for the quarter and how they've changed recently. After that, I will focus on our outlook for the rest of the year and the assumptions behind it. For the quarter, our natural gas transport volumes increased by 8%, or 3.1 Bcf a day. As we move through April, these volumes continue to show strength. However, it's important to note that most of our transport volumes are under take-or-pay contracts, so any future volume drop-off won't affect us. Our gathering volumes decreased by 2% this quarter, but actually increased by 2% overall. The declines in dry gas basins have been slightly offset by increased volumes in associated plays. Nevertheless, we are witnessing volume reductions in the associated plays this April, and we anticipate more in May. Petroleum product demand remained flat for the quarter; it was positive in January and February but saw an 8% drop in March. Currently, we are observing a 40% to 45% reduction in refined product volumes, which will affect both our Products Pipeline and Terminals segments. Crude and condensate volumes rose by 9% this quarter and remained strong in March, although they are declining in April, with further degradation expected in May. For the full year, we project to be approximately 8% below budget for EBITDA and about 10% below budget for DCF, estimating around $7 billion in EBITDA and approximately $4.6 billion in DCF. We have cut expansion capital expenditures by around $700 million, nearly 30%. This decrease in DCF is more than compensated for by the reduction in CapEx, resulting in DCF minus CapEx being around $200 million better than our budget. We expect to finish the year with a debt to EBITDA ratio of 4.6 times. Now, let me break down the 8% EBITDA variance into six categories for clarity. The first category is lower commodity prices, which are expected to impact us by just under 2%. We're assuming an average oil price of about $30 per barrel for the remainder of the year, and our sensitivity to price changes has decreased significantly, with about $1.7 million in EBITDA impact per dollar change in oil price due to our hedges. The second category involves lower natural gas gathering and processing volumes, also projected to have an impact of just under 2%. We anticipate about a 12% reduction in volumes from Q2 through Q4. However, this varies across different assets based on the basins they serve, with some expecting declines over 30% while others may see smaller reductions. Overall, our assumptions lead to an approximate 20% decrease in EBITDA from our natural gas gathering and processing assets compared to our budget. One main reason for the discrepancy between the volume and EBITDA declines is that we're seeing larger volume declines on higher-margin assets. The third category is lower refined product volumes, which we expect to impact us by just under 2% as well. In our outlook, we're estimating an 18% to 20% decrease in volumes versus our budget through the remainder of the year, with a 40% to 45% drop in Q2, decreasing to 10% to 12% in Q3, and 5% to 6% in Q4. These three categories—commodity prices, natural gas gathering, and refined products—contributing less than 2% each, account for about 5.5% of the 8% variance. The fourth category, lower crude and condensate volumes, is expected to impact us by about 0.7% of EBITDA, with a projected 19% decline in volumes from Q2 through Q4, including both gathering and pipeline transport volume impacts. The last two categories, lower capitalized overhead due to decreased capital spending and lower CO2 volumes, together represent about a 1% variance. We factored in around $80 million in operating and cost savings into our EBITDA assessment, some of which stems from lower fuel and power costs directly linked to reduced volumes. This summarizes the key elements of our EBITDA forecast and helps explain the 8% variance. On a positive note, we anticipate around $100 million in savings from lower interest expenses and reduced sustaining capital expenditures. Consequently, the 8% reduction in EBITDA, less the savings from interest and sustaining CapEx, approximates a 10% impact on EBITDA. We are operating in a highly uncertain and dynamic environment, making it tough to gauge how quickly economic activity might return to normal. Therefore, in the press release's table 8, we've provided sensitivities regarding the major variables in our forecast, allowing you to calculate the impacts as circumstances evolve. With that, I’ll hand 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. 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 $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 included the sale of our KML and U.S. portion of our Cochin pipeline, which collectively contributed about $50 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 CO2 segment as well as a $621 million impairment of goodwill associated with that same segment. Those impairments were due to the sharp decline in crude prices 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 $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 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's share in the Elba Island's 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 earnings of about $7 million, weather and 501-G impacts on TGP were 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. The Natural Gas segment is projected to be down 4% from planned for the full year, driven by lower gathering and processing activity levels. Products are 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. CO2 is expected to be down 16%, driven by lower oil and NGL prices and 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 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 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 $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. 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 the queue and we will get back to you. Denise?

Thank you. We will begin the question-and-answer session. 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 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 to two years. We started the quarter with 2.3 million barrels of available capacity. Currently, we're down to 727,000, most of which consists of small chemical tanks. We anticipate that this will continue to decrease throughout the month, approaching zero as we complete the month.

Okay. That makes sense. And that was also a third party, so we shouldn’t expect to see exciting marketing earnings from the contango from KMI, right?

All third party.

Thank you. Can you provide an estimate of the minimum capital expenditure required to maintain the CO2 business over the next few years, considering its sensitivity to oil prices?

We invest our capital expenditures in the CO2 business based on the returns it generates. This means there is revenue linked to the oil associated with the capital we invest. We evaluate that and stress test the pricing through the oil to see if it meets our criteria. Prices have fallen, which is why we've reduced our CapEx by about $130 million. We are not investing to maintain a flat output; our investments depend on the additional economics they provide. We have managed to maintain a relatively low decline rate with our CapEx. We expect that decline rate to rise slightly, but it remains uncertain, especially with less capital being allocated to that business. Our capital investment is driven by the additional economics we achieve. Our CO2 lifting cost for the majority of our current investments is around $20, which factors in the market price for CO2, not our production cost of it, which is significantly lower. We assess our production to ensure it makes sense to continue, and as I noted, we have hedged a substantial portion of it.

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 I 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, that's a good question. We approached this at a high level, as Kim indicated, breaking it down quarter-by-quarter. This was based on current month activity we observed concerning our assets and discussions we had with our customers in both the products and terminals business. These factors informed our assumptions. That said, there is some uncertainty for everyone right now. However, we made the best judgment we could based on the available data. We also provided some sensitivity so you could adjust according to different assumptions you might have. I believe our insights were quite informed by actual experiences, particularly in early second quarter, along with customer conversations. Kim, do you have anything further to add on this?

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 buyback program?

I’ll try to answer that. Our expectation is to reach $1.25 when the economy stabilizes, and we believe there is a good chance this could happen by the fourth quarter. That’s why we positioned it this way. While it's not our intention to conduct significant additional buybacks this year, we will monitor the situation closely. As Steve mentioned, these are truly unprecedented times. We are being conservative and protective of our balance sheet while providing flexibility 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 force majeure on take-or-pays? I realize this is highly unusual situation and question, but just wanted to see what you guys’ thoughts were.

We have assessed our force majeure provisions, and while there is some variability in them, our tariffs in the interstate natural gas transportation sector, which constitutes a significant part of our overall business, maintain that force majeure events do not exempt the obligation to pay. Thus, even if an event could technically qualify as a force majeure, which I’m not indicating will happen, it would not relieve the obligation to pay under our interstate tariffs. Regarding the potential actions and their implications, how they will unfold, and how they may differ from typical economic responses based on market price signals is uncertain. However, concerning our transportation tariffs, we believe we are relatively protected. As for CO2 production, I'll ask Jesse to provide any additional insights he may have. We are also responding to price signals, just as we assume others are, and in the unlikely event of a proration implementation, we believe we can comply and likely would be in alignment with it based on what the prices indicate. Jesse, do you have anything to add?

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.

To follow up on the question regarding the EUR business, Steve, you mentioned that the lifting cost is about $20 a barrel. If the price were to fall below the integrated economics, is there a possibility to defer production and settle your hedges financially or even purchase in-basin if physical volumes are required?

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. Please go ahead, Kim.

Go ahead.

Yes. If you refer to the slide deck that David mentioned, on page five, we provide a breakdown. In natural gas, we reduced CapEx by approximately 460, mainly due to either removed or deferred gathering and processing investments. In products, the reduction is around $90 million, largely from decreased activity in the crude or gathering business within that segment. There were several project deferrals in Terminals as well. Additionally, CO2 saw a reduction of about 130, with Terminals accounting for 30 of that. Most of the CO2 reduction is due to project deferrals until there is a more favorable price environment. Kim, do you want to add anything?

No.

Okay. All right.

The next question is from Spiro Dounis with Credit Suisse. Your line is open.

Hey. Good afternoon, 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. This situation is certainly different and unprecedented, combining the collapse of OPEC Plus on March 6th with COVID significantly reducing demand. It’s important to consider these two factors separately regarding their duration. As for COVID, it's still uncertain, but being a virus, it's expected to be temporary; even if it resurfaces, it will likely remain a short-term issue. We anticipate that demand for refined products will eventually return to normal. Additionally, as Kim pointed out, we haven’t yet seen much decline in our natural gas demand or throughput. Regarding the OPEC Plus dynamics, even if economic activity returns to normal, if the coalition does not remain intact and the market must realign based solely on supply and demand fundamentals, the impact could be longer-lasting, affecting shale operations and our near-term plans for gathering and production investment. This situation could persist unless a more favorable deal is reached compared to our current economic environment. Concerning your question about pivoting to dry gas plays, we are equipped for that. Our natural gas assets support dry gas regions like the Marcellus and Utica through our Tennessee Gas Pipeline system, and we also serve the Haynesville, as Tom mentioned. We have ample capacity to expand as the gas market stabilizes, shifting reliance from associated gas volumes to dry gas volumes. Rich, do you have anything else to add about cycles?

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

Could you clarify what percentage of the total CapEx reduction is an actual cut versus a natural deferral? I understand that the backlog has decreased by about $300 million since the fourth quarter, but I recognize there are many factors involved. Please help me understand what permanent reductions have been made.

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 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 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?

We consider credit during our Monday meetings, where it's the second topic we discuss. We evaluate each customer facing difficulties, such as credit downgrades or outstanding receivables. We also seek collateral when we have the rights to do so and assess the underlying value of the capacity held by each customer. We consider how critical that capacity is for getting their product to market and how likely they are to reject the contract in a worst-case scenario. We take all of these factors into account. There's no good comparison to this year, but if we look back to 2016, our bankruptcy defaults then totaled about $10 million. This year is worse due to several reasons, but we have mitigation strategies in place. It is also challenging to predict which customers might fail, as they may opt for debt restructuring instead. That's why making projections is difficult. However, I think it was important for David to bring it up since we haven't included 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.

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.

Thank you for that. I wanted to ask about slide 12 and the information regarding your customer base and their credit ratings. Have you examined the approximately 76% identified as investment grade? I'm interested in how many of those are currently under credit watch with negative outlooks. We are noticing a trend of fallen angels in the energy credit sector lately. What percentage of that 76% do you think might transition 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 is 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.

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 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 address the last part first. Everything is under contract concerning the Jones Act capacity. John will provide more details on this. However, there is a hesitation, as it is ultimately the customer's decision. Most of the products involved are clean, and there's a reluctance to switch those to dirty products, especially where we don’t already have dirty products in service, due to cleaning costs, among other reasons. John, do you have anything to add?

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.

Regarding crude storage, it is logical for our refined products assets to focus on refined product service, as that is where most of our tank storage is located. As John mentioned, it is filling up quickly. We do have some limited storage capacity on the crude side within our CO2 business and products pipeline, but it is not significant.

And as a follow-up, after the Keystone pipeline ruling in Montana last week, I saw there were few headlines raising questions about potential challenges to bring in highway permits as well. Can you comment on the potential legal challenge there?

Yes, we are aware of the decision and it is not hindering our construction efforts at this time. It's difficult to believe that this decision would apply beyond the specific project it pertains to, especially considering the numerous projects operating under Nationwide Permit 12 from the Army Corps and the jobs that depend on them. It seems unlikely that we would send those workers home during such times. Therefore, we do not anticipate this decision will impact our construction on PHP. Importantly, we already have an existing authorization and verification under Nationwide Rule 12 that pertains to PHP.

The next question comes 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 has been strengthening 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. 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. We examined our current activity levels and spoke with our customers to understand their perspectives on future trends. This situation will continue to evolve. Some wells may need to be shut in temporarily. However, there may be cases where prioritization occurs, leading some customers to drill new wells while shutting in less economic ones due to factors like high gas-to-oil ratios and water handling costs. Many factors will influence these decisions. We have attempted to estimate our projections for this quarter based on our customers' feedback and the negative trends we are currently observing. Kim, do you have any further details to add?

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 that 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.

We are continuously seeking ways to reduce costs without affecting the safety and integrity of our assets. One trend we are just beginning to experience is that we are receiving strong cost reductions from our vendors and service providers. Businesses are eager to collaborate with us, and many are seeking opportunities to secure work at this time. For instance, Jesse and his team in CO2 are just starting to negotiate better prices and terms with the service providers. I believe this could lead to further savings in both capital and operating expenses as we move forward. Of course, there are potential downsides to consider with any projections, but this is a positive aspect worth highlighting.

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 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 targets 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 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 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 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. 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.