Welcome to the quarterly earnings conference call. At this time, all participants are in a listen-only mode until the question and answer session of today's conference. At that time, you may press star one 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 would now like to turn the conference over to Mr. Rich Kinder, Executive Chairman of Kinder Morgan. Thank you. You may begin.
Thank you, Sheila. Before we begin, as I always do, I'd like to remind you 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 disclosure 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. Let me begin by saying that over the last several quarters, I've started these calls with a review of our financial philosophy and strategy at Kinder Morgan.
I went back and looked at what I've said over the last few quarters, and the message has been very consistent, and it is this: We generate significant amounts of cash, and we'll use that cash to fund our expansion CapEx needs, pay our dividends, and to keep our balance sheet strong, and occasionally on an opportunistic basis to repurchase shares. We will use a disciplined approach to approving any new projects, and that's exactly what we're doing, even in this challenging year of 2020, which I believe shows the resilience and strength of our collection of midstream assets. Now, as we look beyond this year, we can't predict with any accuracy what the future will bring in terms of a return to normalcy for our economy and our lifestyle.
We are confident that KMI will continue to generate strong cash well in excess of our expansion CapEx needs and the funding of our current dividend. That will allow us to maintain a strong balance sheet and return significant additional cash to our shareholders through increased dividends and/or share repurchases. If the results and outlook are that positive, why is that not reflected in our stock price? I'm certainly no expert on that subject, but it appears that many investors are not committing any funds to the energy business without any consideration of the unique characteristics of our midstream sector. We are not climate change deniers, and we recognize the growing momentum of renewables in America's energy mix. That said, there is a long runway for the products we handle, particularly natural gas.
For a clear-eyed examination of the role of fossil fuels in the energy transition, I recommend everyone read the excellent new book, "The New Map," by Pulitzer Prize winner Daniel Yergin. In it, he details in specific terms the need for oil and particularly natural gas in the coming decades and indicates the importance of existing energy infrastructure like ours. Now, beyond the present use of our assets, our extensive pipeline infrastructure can play an important role in facilitating many of the changes being advocated to lessen global emissions. To name just three examples, if green hydrogen becomes a reality, we can move some amount of it through our pipes. If refiners produce renewable diesel, we can transport that through our product pipelines. If CCUS advances, we have more experience in moving CO2 and injecting it underground than virtually any other company in America.
In short, to paraphrase Mark Twain, the rumors of our death are greatly exaggerated. With that, I'll turn it over to Steve.
Thank you, Rich. I'll give you an overview of our business and then 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. Our financial principles remain the same, maintaining a strong balance sheet. We're 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 $680 million from our 2020 budget for almost 30%. That was in response to the changing conditions in our markets. We still have over $1.7 billion of expansion capital in 2020 on good returning project investments. We're also maintaining cost discipline.
We now stand at about $188 million of expense and sustaining capital cost savings for 2020, including deferrals. About $118 million of that is permanent savings, we believe. The result of this work on our capital budget and our costs is that our projected DCF less discretionary capital spend is actually improved versus our plan by about $135 million to our 2020 plan and about $600 million versus our 2019 actuals. All that notwithstanding the pandemic. We more than offset the degradation to our DCF forecast with spending and capital investment cuts in 2020. Finally, we are returning value to shareholders with the 5% year-over-year dividend increase to a $1.05 annualized, providing an increased but well-covered dividend. The strong balance sheet capital and cost discipline and returning value to our shareholders. You'll note that we omitted the reference to getting to a $1.25 dividend that we projected back in 2017.
Omitting the $1.25 is not backing away from further dividend increases. We remain committed to paying a healthy, well-covered dividend. It's simply wise, we believe, to preserve flexibility to return value to shareholders in the best way possible for shareholders, especially in light of a share price that shows an 8%+ yield on a well-covered dividend. We will review dividend policy with the board following completion of our 2021 budget process. We have accomplished some important work so far during 2020, which I believe will lead to long-term distinction for our company. First, as Kim will cover, we've been successful in advancing our Permian Highway Pipeline project under very difficult circumstances, including local opposition, legal and permit challenges, and by the way, a global pandemic, too.
We're distinguishing ourselves and demonstrating to our customers and partners our ability to get projects done in difficult conditions. Second, we are already an efficient operator, but we are getting more efficient and more cost-effective. We believe that is one of the keys to success in our business for the long term. As I mentioned last quarter, our management team is in the midst of an effort to examine how we are organized and how we operate. We are centralizing certain functions in order to be more efficient and effective, and we are making appropriate changes to how we manage and how we are staffed, and I believe that we will achieve substantial savings. Additionally, as always, we'll be evaluating costs and revenues as part of our annual budget process, which we're also in the midst of right now.
We'll bring those two efforts to a close in the coming weeks and incorporate the results into our 2021 guidance. It's essential to be cost-effective while also maintaining our commitment to safe and compliant operations. That's embedded in our values, our culture, and in how we put our budget together. The management team is committed to these objectives too, and that commitment is also critical to our long-term success. Third, we'll soon be publishing our ESG Report. We have incorporated ESG reporting and risk management into our existing management processes. The report will explain how. In the meantime, Sustainalytics has ranked us number one in our sector for how we manage ESG risk. These things are all important to our long-term success, and we have advanced the ball significantly on all three in 2020. What have we been doing during the pandemic?
We're completing a major, new, fully contracted natural gas pipeline in the face of opposition. We're expanding our gas network in Texas and have expanded our terminal capabilities in the Houston Ship Channel. We've reduced costs and capital expenditures, actually increasing our cash flow after CapEx for the year. We continue to advance the ball on ESG, and we're also completing organizational restructuring at the same time. All this while keeping all of our assets running safely, reliably, and efficiently and continuing to originate new business. I'm grateful for the quality of our people and the strength of our culture, two things we probably don't emphasize enough. One more thing. There's a lot of discussion around our sector right now about ongoing energy transition, and I'd like to make a few points about how we participate.
First, we and many objective experts, as Rich mentioned, believe that natural gas is essential to meeting the world's energy needs and meeting climate objectives as it has here in the U.S. U.S. natural gas will play a significant role, and our assets are well-positioned to benefit from that opportunity. More important to us is the value of what we specifically do, which is less about providing the commodity itself and more about providing the transportation and storage capacity for deliverability. The value of that increases for the power sector as more intermittent resources are relied on for power generation. Natural gas is clean, affordable, reliable, and pipelines deliver that commodity by the safest, most efficient, most environmentally sound means.
We'll continue to look for additional ways to benefit from the long-term energy transition, including the role of our infrastructure in firming intermittent renewable resources, which is what I just mentioned. Our marketing of our low methane emissions performance as responsibly produced and transported natural gas. That's a good synergy between our ESG performance that's lowering our methane emissions overall and our commercial opportunities. We're distinguishing ourselves as an environmentally responsible provider, and increasingly that matters to our customers. Further down the road, there may be hydrogen blending opportunities in our natural gas pipelines, and if the incentives are adequate, captured man-made CO2 to be transported on our CO2 pipelines and used for EOR. We'll also continue to evaluate other opportunities in the renewable sector that as always will be very disciplined. The G in ESG is critically important, and we won't forget about that.
We believe the winners in our sector will have strong balance sheets, low-cost operations that are safe and environmentally sound, and the ability to get things done in difficult circumstances. As always, we will evolve to meet the challenges and opportunities we face. With that, I'll turn it over to Kim.
Great. Thanks, Steve. Today I'm going to go through a review of each of our business segments as well as a high-level summary of the full-year forecast. First, starting with the Natural Gas segment, transport volumes were down about 2% or approximately 575,000 Dth per day versus the third quarter of 2019. That was driven primarily by low LNG demand, competition from Canadian deliveries, and low Rockies production. These declines were partially offset by a full quarter of volumes on our GCX pipeline that went into service last year. Physical deliveries to LNG facilities off our pipelines were down about 700,000 Dth a day versus the third quarter of 2019. They were also down versus the second quarter of this year. We have seen a recovery in those volumes, and current volumes are nearing pre-pandemic levels. Exports to Mexico were very strong in the quarter.
They were up 500 a day when compared to the third quarter of 2019, and over 650 per day versus the second quarter of this year. Deliveries to power plants were up 5%, driven by coal switching and warmer weather. Our gathering volumes were down about 13% in the quarter compared to the second quarter of 2019. For gathering volumes, I think the more informative comparison in the current environment is versus the second quarter of 2020. Compared to the second quarter, volumes were down about 4%. KinderHawk, which serves the Haynesville, was down due to lack of drilling and decline in existing wells. However, we're still expecting, based on conversations with customers in the forward curve on natural gas prices, to see new drilling in the Haynesville in 2021.
The bright spot in the quarter was volumes on our Hiland system in the Bakken, which were up approximately 30% versus the second quarter of this year. On our natural gas projects, we completed Elba during the quarter. The facility is now fully in service. On PHP, we're now about 97% mechanically complete. We expect to be fully in service in early 2021. On our Products Pipelines Segment, refined products volumes were down about 16% for the quarter versus the third quarter of 2019 as a result of the continued pandemic impact. The 16% compares to about a 14% reduction the EIA shows for the third quarter. Our volumes are slightly worse than the EIA. That's primarily because jet fuel, as a percentage of our total volumes, is greater than it is for the EIA mix.
For each month in the quarter, we did see an improvement in volumes over the prior month. For October, we're currently expecting volumes to be off approximately 13% versus the prior year. The 13% is comprised of road fuels off about 5% and jet fuel approaching off 50%. Crude and condensate volumes were down about 17% in the quarter versus 2019, but improved by about 11% over the second quarter. In terminals, we experienced decline in our refined products throughput of about 22%, but here the impact of lower volumes is mitigated by the fixed take-or-pay contracts that we have. For those of you who are trying to read through to demand, I would point out that the percentage is significantly impacted by imports in the Northeast than exports in the Gulf Coast.
If you look at our rack facilities, which is probably a better gauge of what's happening with demand, they were off about 11% in the quarter. Our liquids utilization percentage, which is a more accurate predictor of the health of this business, given the structure of our contracts, remains high at about 96%. If you exclude tanks out of service for required inspection, utilization is 98%. The bulk side of our business, which accounts for roughly 20% of the terminal segment earnings, was impacted by weakness in coal and petroleum coke volumes. In CO2, oil production was down approximately 12%, and CO2 sales volumes were down approximately 33%. However, lower OpEx and help on oil prices more than offset the lower volumes. Our team's done a tremendous job of adjusting to the current reality. They've achieved cost savings both on the OpEx and the capital side.
Therefore, free cash flow from this segment is expected to be better than budget and better than 2019. For the full year, our guidance remains the same as we gave you last quarter. We expect to be below plan by slightly more than 8% on EBITDA and slightly more than 10% on DCF. Embedded in this guidance is over $187 million in cost savings between G&A, OpEx, and sustaining CapEx. To give you a better sense of what we are projecting on fourth quarter volumes, for refined products within the Products Pipelines segment, we're estimating volumes to be off about 10% versus the prior year. On crude and condensate volumes, we're estimating volumes to increase by approximately 5% versus what we saw in the third quarter.
On natural gas gathering volumes, we're expecting volumes in the 4th quarter to be essentially flat with what we saw in the 3rd. On debt to EBITDA, we're expecting to finish the year at approximately 4.6x debt to EBITDA, so slightly better on this metric than what we told you last quarter. With that, I'll turn it over to David Michels.
All right. Thank you, Kim. Today, we're declaring a dividend of $0.2625 per share or $1.05 annualized, which is flat with last quarter. For our quarterly performance, our revenues were down $295 million from the third quarter of 2019, driven in part by lower natural gas prices in Q3 of this year versus Q3 of last year. Those lower natural gas prices also drove a decline in associated cost of sales of $107 million, which partially offset the lower revenues. Net income attributable to KMI was $455 million for the quarter, 10% down from the third quarter of 2019. Our adjusted earnings is a bit higher at $485 million, down 5% from the third quarter of 2019. Adjusted earnings per share was $0.21 for the quarter, down $0.01 from the prior period. Moving on to DCF performance for the third quarter.
The natural gas segment was down $8 million, with lower contributions driven by our sale of our Cochin Pipeline, along with lower volumes on our South Texas and KinderHawk gathering and processing systems, partially offset by contributions from Elba Liquefaction and Gulf Coast Express projects coming online. Our product segment was down $67 million, driven by lower refined products volumes as well as lower crude and condensate contributions, mainly due to demand impacts from the pandemic, as well as lower oil prices. Our terminal segment was down $49 million, driven mostly by the sale of KML and the terminals associated with that business, as well as the lower refined products, coal, steel, and petcoke volumes.
Our CO2 segment was up $5 million due to lower operating costs and improved year-over-year realized pricing, given improved Midland Cushing hedges, more than offsetting the lower CO2 demand and lower produced crude oil in that segment. The G&A and corporate charges were lower by $18 million, driven by lower non-cash pension expenses, the sale of KML, as well as cost savings. The JV, DD&A, and non-controlling interest items combined show a $24 million reduction, driven mainly by our partner at Elba Liquefaction sharing in greater contributions from that facility. That brings us to adjusted EBITDA of $125 million, or 7% lower than the third quarter of 2019. Below EBITDA, interest expense was $61 million favorable versus last year, driven by lower floating rates benefiting our interest rate swaps, as well as lower debt balance, partially offset by lower capitalized interest.
Our cash taxes were higher in the third quarter by $37 million due to deferred payments at Citrus Corp. And our Texas margin tax from the second quarter of 2020 into the third quarter. For the full year, cash taxes are fairly close to our budget. The main driver behind our other item, favorable $34 million, was a change in the schedule of our contributions to our pension plan. In 2019, we made the entire annual contribution to our pension plan in the third quarter. This year we began making quarterly contributions. Overall, we expect to contribute $10 million more in 2020 versus 2019 to our pension plan. Total DCF of $1.085 billion is down 5% from the third quarter of last year. Our DCF per share of $0.48 is down $0.02 from last year.
On the balance sheet, the end of the quarter at 4.6x debt to EBITDA and expect to end the year at the same level, which is up slightly from last quarter of 4.5x and up from 4.3x at year-end 2019. During the quarter, we had a very nice capital markets execution. In August, we issued $750 million of 10-year senior notes with a 2% coupon and $500 million of 30-year senior notes with a 3.25% coupon, and those were the lowest ever achieved 10-year and 30-year coupons associated with those 10 and 30 year issuances, respectively, for KMI. The issuances also further bolstered our already strong liquidity position as those proceeds more than covered the amount of debt maturing in the quarter. At the end of the quarter, we had an undrawn $4 billion credit facility and over $600 million of cash on hand.
Our net debt ended the quarter at $32.6 billion, down $433 million from year-end and up $189 million versus last quarter. To reconcile the quarter changes, we generated $1.085 billion in distributable cash flow. We spent $600 million on dividends, $400 million on growth CapEx and JV contributions, and had a $270 million working capital use. That gets you mostly to the $189 million change for the quarter. For the change from year-end, we've generated $3.347 billion of distributable cash flow. We brought in $900 million from the Pembina share sale in the first quarter. We paid out dividends of $1.77 billion. We've spent $1.4 billion on growth capital and JV contributions. We've spent $235 million on taxes associated with the Trans Mountain and Pembina share sales. We've bought back $50 million of KMI shares. We've had $360 million of working capital use, mostly interest expense paid.
That explains the majority of the $433 million reduction in net debt from year-end. With that, I'll turn it back to Steve.
Okay. Thanks, David. Sheila, we'll open it up to questions, and I'll remind you as we've done in the past, that as a courtesy to all callers, we're going to ask that you limit your questions to one question per person with one follow-up. However, if you do have additional unanswered questions, get back in the queue and we will come back around to you. Okay, Sheila?
Thank you. We will now begin the question and answer session. To ask a question, please press star one. If you need to withdraw your question, press star two. Again, to ask a question, please press star one. Our first question comes from Jeremy Tonet with JPMorgan. Your line is open.
Good afternoon.
Hi, good afternoon. Thanks for having me. Maybe just starting off with a high-level question here on the pace of recovery. It's obviously difficult to tell here, but just wondering what your thoughts are. If you look at the G&P segment, I'm wondering what you could tell us as far as what type of activity you're seeing in the quarter and how you think that might recover over the next couple of quarters, and a similar question on the product demand side. What are you seeing now, and when do you think it's possible to get towards pre-COVID levels? Just trying to get a better feel for how this could unfold over the next couple of quarters here.
Okay. Yeah, fair enough. Broadly, as you heard from the numbers that Kim went through, we're continuing to see month-over-month improvements on the refined products side of things. Things bounced back up big in the second quarter. In the third quarter it's been more gradual. We're still seeing month-over-month improvements. It's gradual. Right? I think we don't have any special insight into how quickly people will return to driving. They're certainly starting to. Diesel volumes have remained fairly strong. Jet is, I think most people would say, and I think we would say, that jet is likely to lag. Its impact on us is relatively smaller than what its volume impact is. About 12% of what we handle in our refined products business is jet. It only comes down to about 8% of the EBITDA for those segments.
For KMI overall, it's about I'm sorry, 12% of refined products, 3.5% of the combined refined products and terminal segments on EBITDA contributions, so 1% for KMI overall. That's the whole of jet volume. 12% of the total volumes, but only 8% of the EBITDA. Okay? On G&P, so gradual recovery there. On G&P, as Kim said, when we look at the change versus last quarter, it's a much smaller change than what it was on a year-over-year basis. There, I think we saw a big comeback in the Bakken, for example. I think the Eagle Ford will probably continue to lag.
The Haynesville is also lagging, but we expect that that's going to start turning around because we do need to produce natural gas in the United States, and if we're not going to produce it to meet demand, if we're not going to produce it in associated gas plays, it's going to come from the dry gas plays, and the Haynesville is well positioned for that. Our assets are well positioned on the dry gas plays from an interstate standpoint on TGP for the Marcellus and Utica, and from a gathering standpoint for the Haynesville, and very capital-efficient increases in production that we can achieve there. Look, it's a bit of a mixed bag across the G&P landscape, but that's directionally how I would size it up.
That's very helpful. Thanks. Maybe just turning to California and energy transition, as you guys talked about before. In California, we see the internal combustion engine phase-out plans and see greater penetration from EV and biodiesel. Just putting it all together, thinking about this, refineries potentially closing there, how does this impact KMI? Or more importantly, how does KMI, I guess respond to this going forward?
Yeah, there are pluses and minuses. I'll start with the plus side. As refineries convert to generate more renewable diesel, we can handle renewable diesel in our pipelines. We can handle it in our storage tanks. We think there may be opportunities for us to develop in our Products Pipelines segments and additional facilities to handle increases in renewable diesel that come out of the developments in California. In California, it is heavily subsidized, and so it will make sense for people to make those investments, and we're looking for ways that we could participate. I think just broadly, there are some things that we have to pay attention to in terms of being able to track renewable content, which becomes more challenging once we get over the 5% level. We can adapt and adjust to that.
I think the easy way to think about it is renewable diesel looks like regular diesel when it's in our pipes and tanks. On the negative side, certainly we've seen the announcement about the intent to phase out or really eliminate internal combustion engine sales in new cars in California. A couple points that I would make that kind of mitigate that. One is not all of our volumes on our SFPP system move to serve California markets. Some of it moves to serve Arizona as well as serving Nevada, both in the Las Vegas and Reno markets. The other thing is it takes a while. We're talking about between now and 2035. It takes about 10-12 years to roll over the vehicle fleet, et cetera. There are a number of things that really mitigate that impact for us on the refined product side.
Got it. Thank you.
Thank you. Our next question comes from Ujjwal Pradhan with Bank of America. Your line is open.
Good afternoon. Good afternoon, everyone. Thanks for taking my question. On M&A, Steve, we have seen a wave of upstream M&A recently, and midstream sector appears to be primed for it as well, with recent headlines around certain G&P companies exploring sale. If a deal were to satisfy your criteria for leverage and DCF accretion, which area of business would KMI prioritize pursuing M&A in?
Again, you said that really key point there, which is it has to meet the criteria, and that includes meeting balance sheet criteria, as well as being a business that I think generally that we're already in and that we're confident we can operate and that we can bring some additional synergies to. We can always bring cost synergies, we believe. We are an efficient operator, but we have to find other things that we can do. I think there are two parts of this. Certainly the activity that's going on in E&P right now, I think that's a good thing for the sector, and I think indirectly, therefore, a good thing for midstream in the sense that you're getting stronger, more well-capitalized players with plans to continue to develop.
They're doing it in a way that doesn't harm the entity going forward by paying too big of a premium, for example, et cetera. In midstream, we continue to keep our eye on relative valuations with all those criteria that I mentioned, and we're going to be very conservative and very disciplined about our participation there. The other thing I think we'll begin to see more of, but it's on the sidelines right now, is asset packages coming on the market. There's a lot of those evaluations, I think, were put on hold back in March and April, and do think that we'll start to see a little bit more activity there. We're in that information flow, and if we find something that's attractive, as we did on a fairly small scale at the end of last year, we'll look to act on those.
Not yet really seeing it in midstream, but we think there may be some asset sales that come online later in the process here. Kevin, anything that you want to add to that?
No, I think you covered it all very well, Steve.
Yeah. Thank you.
Got it. Thanks for that, Steve. Second question on traditional thoughts on shareholder return here. How are you weighing buyback versus distribution growth? Question here is, given that distributions have not been rewarded recently, would you say that buybacks may be a better option than your current intention to raise distributions to the $1.25 per share level?
Yeah. I think both Rich and I covered it at the beginning. We're looking at what the best way is to return excess cash to shareholders, maintain a strong balance sheet, invest in projects at good returns that are well above our cost of capital, et cetera. You're right. In the current environment, a security that's yielding over 8%, certainly that's the case. However, we're going to be thoughtful about this. Our Board will be thoughtful about it when they deliberate on it and make the decision. Just because dividends are out of favor now doesn't mean we shouldn't be paying them and shouldn't be increasing them.
We think that that's a very valuable and reliable and steady way to return excess cash to our shareholders, and we believe that the market from time to time appreciates that, and from time to time it doesn't, and I don't think we can make our decisions based on what is currently prioritized. Clearly, by saying what we said in the release, we're giving ourselves flexibility, which I think is, as I said, is a very wise thing for us to do in a time like this.
Got it. Thank you, Steve. I'll jump back on the queue.
Thank you. Next, we will hear from Colton Bean with Tudor, Pickering, Holt & Co. Your line is open.
Good afternoon. Appreciate the prepared remarks around energy transition and potential opportunities for the KMI asset base. Coming at it from a slightly different angle, can you speak to your philosophy on capital structure in the context of transition?
Capital structure in what sense?
Mostly thinking here in terms of the balance sheet and whether is leverage the appropriate metric. Is there some consideration of ratable debt requirement?
Oh, I-
Really just trying to understand, whether it's 2030 or 2060, if there is some sort of timeline out there, how you evaluate that when you look at the balance sheet.
Yeah. No, I understand. Look, we still believe, Anthony can weigh in on this as well. We still believe that the rating agencies believe that we are appropriately rated at BBB flat at the around four and a half times. When you look at our whole business mix. I'll make a little bit of a broader point here. I'm not the expert that you all are in other sectors. In my casual observation of it's funny to me that in our sector, when we talk in terms of 2040, 2050, 2060, there aren't many businesses out there right now that can really be thinking in terms of that length of time for them to be in business and doing things that they're doing today.
I think there's no pressure there to do something different on the four and a half times when you think about that runway and when you think about the quality of our assets and the diversity of our cash flows and the length of our contract terms, the increasing irreplaceability of our assets, if you will. The harder it is to build new infrastructure, the flip side of that is that the existing infrastructure, which we happen to have a lot of becomes more valuable, all things being equal. I guess the short answer is no.
Got it. Appreciate that. On the Rockies pipeline network, you mentioned some producer optimism in the Haynesville, just getting the move in the strip here. Could you characterize recent conversations around the Rockies region and whether your thoughts on recontracting potential have shifted at all?
I'll ask Tom Martin to speak to that. Tom?
Yeah. I think clearly we're seeing less development activity in the Rockies than we were seeing probably a year ago. That certainly will have an impact of excess capacity in that market. I think we have valued that in the past appropriately. I don't see that as a material change to us overall. Clearly, things that we've known about that are on the recontracting cliff such as Ruby, things of that nature, we've considered that in our long-term plan, and I don't see that really being impacted by the current change.
Yeah. I just appreciate that.
Thank you. Our next question comes from Jean Ann Salisbury with Bernstein. Your line is open.
Hi. Good afternoon. We're expected to have too much gas takeaway out of the Permian next year when PHP and Whistler start. Can you remind us how much of your existing gas takeaway there is under take-or-pay? If we should expect significant cannibalization when PHP starts next year?
The vast majority of it is under reservation fee-based contracts. That's really EPNG and NGPL and the Hill Country pipeline, which is a smaller intrastate pipeline than the two new ones that we're building. It's mostly reservation fee or take-or-pay base. I think that the one impact that we'll see or that we've started to see is that with less constraint, there's less of the short-term business that we were doing and getting nice rates for. It does have some impact, not to the base as much as to some of the upside opportunities that we had been seeing. There'll be some impact at the margin there. Tom, anything else you want to add to that?
No, you covered it, Steve. Thank you.
Okay, thanks. Just one more about energy transition. In a scenario where 2035 utilities gas demand drops significantly, but to your point earlier, they still need very high availability of gas to cover peak daily demand. How would you see contract structures with utilities on gas pipelines changing, if at all? Do you think they'll have to kind of keep contracting their maximum daily quantities or pay you the same or pay you less? If you could just talk a little bit about how contracts you think would change in that environment.
Yeah, we think that within the existing tariff structures that we have that largely we can accommodate that environment. I'll ask Tom to add any color here that he wants to. For example, if you need the gas deliverability for three hours every day, but you don't need it for 24 hours a day, it doesn't have to be sold that way. We can sell it on a long-term basis at max rate or at a negotiated rate. People pay to have the capacity available when they need to call on it. That might mean that utilization goes down, but as somebody who contracts for and charges for our services based on the reservation of the capacity itself, we think that we can, and we have successfully worked through that and gotten renewals on good terms with our customers, including in California.
We've sold capacity to merchants, et cetera, who are holding it on the same idea. They can capture the upside on a spike, for example, but we can parlay it into term contracting. We are looking at are there new service structures that we should be considering that would be more attuned to variable demand from power generators, and we may have some ideas there, and we may make some proposals there, including on the storage front. I think we can manage within the structure we have. Tom?
Yeah, I think that's right, Steve. We are starting to see some variable type services being contracted out west. The long and short of it is we're getting really good value on our capacity, whether it's sold on a 24-hour basis and used less and/or selling variable services to meet that growing need, really, of capacity to backstop renewables.
Got it. You do have examples where the maximum daily quantity is much higher than the utilization, but utilities can still pay you through that contract structure.
Yeah, we do have some of those services that we sell out west.
Cool. That's all for me. Thank you.
Okay.
Thank you. Our next question will come from Shneur Gershuni with UBS. Your line is open.
Hi, good afternoon, everyone. Just wanted to come back to one of the earlier questions. Unfortunately, I have to use your question on this, but just with respect to the commentary around buybacks and the dividend. Maybe I'm paraphrasing a little bit, but you added buybacks officially to your press release, which I didn't really see last time. You've talked about the increased flexibility. Is the right way for us to think about this on a go-forward basis that you definitely are focused on flexibility, you see where the yield is today, and is it fair to conclude that you're basically looking at an option where you maybe increase the dividend at a smaller rate, but that you look to pair return of capital needs to shareholders via using buybacks? It could sort of be a twin announcement in January rather than specifically around the dividend.
Is that the right way for us to be thinking about that as one of the options you're considering?
Yeah, two things. One is that, again, we will complete our budget process and talk to the Board about how to look at dividend policy for 2021. Yeah, as I said earlier, Shneur, we are by talking about buybacks, and of course, we have been talking about buybacks for a while. We have used about 575 of the Board-authorized $2 billion of capacity, and we did a little bit earlier this year, for example. That is not a new message. I think what is new is that we are emphasizing the flexibility by not specifically talking about $1.25 and a timeframe on $1.25. The answer is yes on retaining flexibility, and that is what we are trying to get across today.
Perfect. Maybe as a follow-up question, I realize it's a little early to be talking about guidance given you're still in your budgeting process. On the last call, there was some discussion around CapEx potentially being as low as $1 billion for growth CapEx. You also made further emphasis on reducing costs. I believe Kim sort of addressed that in the prepared remarks as well too. How have things evolved in your thinking since the second quarter? Do you see deeper cuts on the horizon? Just any color that you can provide on how you're thinking directionally on both operating costs from where we sit today, as well as the discussion on CapEx from the last call where the $1 billion came up.
Yeah. We are in the middle of our process right now, but I think one thing that has emerged fairly clearly, and I don't think it's all that surprising, but we talked about being at the low end of the range, or I'm sorry, below the historical range of $2 billion-$3 billion and responded, yes, when you asked maybe as little as $1 billion. I think that's shaping up to be a pretty good assumption for 2021 because we can kind of see that. We can sort of see the projects slate from here, and that kind of low $1 billion range looks reasonable. Everything else that you mentioned is really getting worked through right now.
I mentioned the cost savings evaluation that we've done, and in parallel, we've been working on our budget and really are getting into the thick of that as we review our business unit budgets in the coming weeks here. All that's going to have to get folded together, and it's a little more complicated than it's been in past years, as you might expect because of that. Still expect we're going to be able to give you guidance. It might not be on the exact anniversary of when we did it last year, but we still think we can pull those together and give you some indication.
Perfect. Really appreciate the color that you provided. I'll jump back in the queue to ask my remaining renewable natural gas question.
Okay.
Thank you. Our next question will come from Spiro Dounis with Credit Suisse. Your line is open.
Hey, afternoon, everyone. Steve, curious as you go through the budget process here and go through all the assets with a fine-tooth comb again, getting out of the Analyst Day. Has the downturn changed the way you think about some of your assets and whether or not they're still core to the business? Just curious if anything's sort of been permanently shifted lower and thinking about certain assets maybe still carrying their weight from a free cash flow perspective. Does that present any disposition candidates now that maybe you didn't think about earlier in the year?
Yeah, you're going to kind of hear a repeat of the way we've talked about this before. I think we did obviously our Canadian divestitures for a variety of reasons. You saw that. Most of what we've been doing since then has been relatively small and kind of pruning to align things. John Schlosser and his team have done a great job over the years of sort of migrating us more toward refined products hubs and a little bit away from these kind of islands in bulk terminal assets. We still have some very good bulk terminal assets. I think we've done a good job of kind of pruning.
I'll say the other thing that we always say, which is we are a shareholder-driven company, and if values appear and they're worthwhile and our shareholders are going to be better off on the other side of the transaction than they were on their way in, then we will consider it. We are a shareholder-driven company, and so even if it's a business that we like, if the value is really strong and robust we'll consider those things too.
Okay. Fair enough. Sounds like pretty consistent there. If I could just get you to opine on the natural gas price outlook in 2021. I know it's not a major driver for you, but just given your position on both the supply side and demand side, seems like you have a pretty unique view here. I guess as we head into next year, obviously there's supply constraints in the associated gas basins. I imagine on demand side, we're not going to have the same sort of LNG cancellations that we saw this year, that's sort of moving the other direction. Curious, just given where the price level is now above $3, could that actually get tighter from here? Are you seeing enough, I guess, resiliency in the gas basins and maybe a recovery in the Haynesville to sort of offset that on the supply side?
Yeah. Supply is drifting down because of the associated gas plays and demand is going up. I'm not a commodities trader, but that looks like it's going to drive prices higher, and of course, that's what we're beginning to see. I think the other phenomenon, though, that has to be factored in there is that I think that there is a bit of a lag in reflex time or response time here in terms of making the switch from associated gas to the dry gas plays. I mean, people are getting their plans together, and we've had good conversations with our customers, et cetera. I think you're probably right. We are the swing supplier from a global LNG standpoint, but I think earlier this year was unusual in terms of the level of cancellations. I think LNG has been going back up.
I think Tom, they're to like 7.8 Bcf a day now, which is kind of in line with where it was pre-COVID, and we've got some additional facilities that are coming on that are going to drive demand further. Something's got to come in and fill that in, and it seems like that's lagging a little bit. A lot's been reflected in the price already. It seems like there could be still some volatility and maybe some continued upward pressure. Tom, anything else you want to point to that you observe?
No. I think you covered it all. I mean, it is a need for dry gas development. That doesn't happen overnight. I think the demand signals for 2021 look good. We could see things fairly tight, I think at least the first half of 2021. Probably drawing down storage levels lower certainly than we have in recent times to help fill some of that. We really need to see response from the producer community for the second half of 2021 and beyond.
And just to point out-
Great. Go ahead.
It doesn't as directly affect us as it does the producer segment. We do benefit from some volatility and people's need to have storage and pull on storage or we'll get some benefit out of that, I think, derivatively.
Perfect. Thanks for the call, guys. Be well.
Thank you. Our next question will come from Tristan Richardson with Truist Securities. Your line is open.
Hey, good afternoon. Just a quick one, a follow-up on the whole energy transition topic. You mentioned in your prepared remarks that you guys do and have evaluated more kind of renewable-oriented projects. Can you talk about return hurdles? Are projects that could conceivably make sense for KMI competitive with traditional midstream projects, or do the acceptable return metrics look different just because this is a different opportunity set with a different growth profile?
Yeah. The returns are lower and lower than what we would see in a midstream investment. The argument is that there's so much capital available for those opportunities that the cost of capital is lower, and ultimately reflected too in the equity cost of capital for companies that are directly in that business. I don't see us gambling on an uplift in our overall equity value because we start to make some investments in solar panels or windows. I think we're going to, as I said, continue to be very disciplined. We've got a lot to work with in terms of what Tom and his team can do to complement renewable generation. As I mentioned, marketing the fact that we are a very low emission, methane emissions source of supply and transportation service.
Things like that don't require us to compromise on returns for our shareholders, but still nevertheless allow us to participate, and I think participate in a meaningful way. Other things are Dax and his team, as I mentioned, they are looking hard at renewable diesel opportunities, and I think we can see returns in those businesses that are nice and very consistent with, in some cases, maybe at the high end of some of the returns that we would get in our midstream business. John Schlosser is looking at the same thing in his business, his refined product terminaling business. I think we're looking to participate in a way that doesn't compromise on our return criteria.
Very helpful. Just one last one on the buyback topic, and I think the word flexibility's been used a lot this afternoon, and seems like that's where the emphasis is. I think there's been some prescription out there in a lower growth environment that a buyback program should be programmatic. I think that would actually probably take away from that flexibility. Is that a fair way to think about y'all's opinion on a programmatic type of buyback plan?
Yeah. Our view really hasn't changed on that. Opportunistic is the operative term, and that's the way we've administered the authorization that the Board has already put in place, and we would expect that to continue that approach, be opportunistic in our purchases.
Thank you guys very much.
Thank you. Our next question comes from Pearce Hammond with Simmons Energy. Your line is open.
Good afternoon. Thanks for taking my questions. Steve, how should we think about 2021 adjusted EBITDA? What do you see as the high level puts and takes around next year's outlook for Kinder Morgan?
I don't have one for you until we finish the budget process. Look, this is something I think it happens every call that's the third quarter call. Which is we report on the quarter, and people are naturally turning their attention to the year ahead, and so are we, but we're not done yet. I think we'll save that until we finish that work, and then we'll let people know where we think we're coming out.
Okay, understand. Thank you, Steve. Following up on an earlier question from one of the analysts about E&P, M&A and kind of the big wave that we've seen, do you think that that big wave ultimately places pressure on the midstream sector to consolidate, or does that not play a role?
I don't think it really plays a role. I think that it will proceed on its own course. People have been pointing out really for seven or eight years now that there are probably too many midstream energy companies to actually serve the market need, and therefore there should be some consolidation. It really hasn't happened in a material way other than the kind of internal consolidation, if you will, MLPs and GPs combining and those sorts of things. There's still a rationale for it, is what I'd say. I'd point to all the factors I talked about in answering the earlier question as the things that need to come together in order for it to make sense to us to act on, particularly in these times. The particularly in these times point is that there's still a lot of uncertainty out there.
I mean, we're not on the other side of the downturn to U.S. energy, not on the other side of the virus certainly yet. I think there remains a fair degree of uncertainty out there.
Thank you.
Thank you. Next, we will hear from Michael Lapides with Goldman Sachs. Your line is open.
Hey, guys. Thank you for taking my question. Real easy one here. There's a lot of smaller E&Ps and a few larger ones that are in distress, financial distress. Can you talk about kind of your broad exposure to them and how much in the way of either contract rejection risk or simply contract renegotiation risk presents itself when you're going through the planning process and thinking about 2021 and beyond?
Okay. Yeah, a few things on that. For us, we believe we provide essential services to these producers. Generally we have some insulation from contract rejection to the extent that they, and that'll vary from basin to basin. Okay? If they're going to continue to produce, they need to continue to get their product to market. We're there providing important services for their ability to do that. That always enters into the rejection affirmation discussions. We've got, I'd say, balance. If you look now at where we are, probably less than 1% on a revenue basis exposed in 2020 to B- and below. Still running like 75% of our revenues. This is revenues from customers that are above, I think it's 5 million is the threshold we use. Might be 10.
Anyway, our customers, 75% are investment grade or have provided substantial credit support. We have experienced about $40 million credit hit from producer bankruptcies for 2020. Again, I think we have a number of things that we can do that help insulate us, including calling for adequate credit support, including having assets that provide services that are needed, whether it's by the company or the debtor in possession.
Got it. Thank you, guys. Thank you, Steve. Much appreciated.
Thank you. Our next question will come from Elvira Scotto with RBC Capital Markets. Your line is open.
Hey, good afternoon, everyone. Thanks for answering all the questions. I have a couple of follow-ups. On the upstream M&A, I know you mentioned that, in a way, as more upstreams merge, it's a benefit having larger, better capitalized customers. Do you think that this also would benefit the larger, more integrated midstream companies that can provide more services or have a bigger footprint? Do you think that actually works to your benefit?
That it works to the upstream consolidation working to the benefit of the integrated?
Yeah, the larger midstream companies with larger asset footprints. Yeah.
Yeah. I think I mentioned this earlier, but I think it is good overall, not just for that sector, but for ours as well, that we're getting producer combinations out there that are producing healthy companies that intend to continue to produce oil and natural gas and are coming out in good shape from those transactions, or would emerge from the other side of those transactions in good shape. I think that's always helpful. Now, I think it's a question of how quickly do they form their new drilling plans and all of that sort of thing. I think it's a healthy thing overall for the energy business and at least derivatively for our sector.
Got it. Okay. Just one follow-up on the energy transition question. You mentioned the ability to use your existing assets, and you talked about hydrogen and the ability to use your existing gas pipelines. Natural gas pipelines can transport, I think, anywhere from 5%-15% hydrogen blend without really much modification. What would be required to transport more hydrogen?
Okay. Kim, do you want to take a shot at that one?
Sure. I think the issue with transporting more hydrogen, Elvira, is embrittlement of pipes. It can cause cracking in certain types of steel. On the compressors, the issue is certain compressors. Generally, compressors that are manufactured within the last 20 years, roughly, can generally handle hydrogen blends that are 10% or less. Compressors that are older than that may require some upgrades even to handle the 0%- 10%. Again, just like on the pipeline embrittlement of the compressor stations handling, current compressor stations probably cannot handle a greater blend than the 10% without some modification.
The only thing I'd add to that, Elvira, is that we have to look at or think about the downstream end uses as well. Which power plants can take what levels of hydrogen? The industrial uses, et cetera. You start to challenge the downstream end uses as well.
Got it. Great. Thanks very much.
Thank you. Our next question comes from Shneur Gershuni with UBS. Your line is open.
Hi, good afternoon, guys. Just a follow-up question here. The early part of the call with energy transition questions were a lot about the challenges. Elvira asked a great question on the hydrogen side. I was wondering about something that I think is more closer to home right now or more in the realm of our predictable timeframe. Specifically on renewable natural gas. Wondering if you can talk about whether it's something you're already participating in and something where you see a growth opportunity right now, and being able to utilize your existing footprint to take advantage of it.
Kim, go ahead.
Okay, sure. Shneur, renewable natural gas right now is a relatively small market. It's probably about 100 million cubic feet a day. The potential issues are that typically the supply sources, which are landfills, dairy farms, wastewater treatment plants, those types of things, you can only get a small supply from those sources. It's also very expensive. The cost estimates I've seen on it are $15-$30 per Dth. Those are the issues that would have to be overcome. It is certainly something that we're looking at and that can be shipped on our pipelines.
We are transporting a little bit today. To your question about doing it today, it's very small. Kim, you might also talk about, on the other hand, the size, and how we define it for responsible natural gas.
Yeah. Responsible natural gas right now, in 2019, net supply was probably 11 Bcf a day, and so roughly 11% of the U.S. supply. The way we think about it is, that's gas that is produced, processed, transported with a commitment to reduce methane emissions to less than 1% by 2025. We're part of a group, obviously, that has made that commitment. The less than 1%, midstream has an allocation of that less than 1%, and the midstream allocation is 0.31. We are well below that 0.31% and have been for a couple of years. We have had some customers talk to us about responsible natural gas. These customers are marketing gas to international customers. It has been important to them and important to their customers.
I think we haven't seen a large acceptance of responsibly sourced gas, but we've had more recent conversations on this, and it seems like it could be gaining in importance.
Cool. Really appreciate the update on it. Thank you, guys.
Thank you.
Thank you. Our next question will come from Ujjwal Pradhan with Bank of America. Your line is open.
Thanks for taking my follow-up here. Just a quick one on Permian Highway. It appears the pipeline's progress, based on the completion level, it could be placed early into service next year. If you are able to do so in early January, do the contracts kick in right away?
Yeah, they kick in after we have done our commissioning work, which is a gradual and somewhat unpredictable process. I mean, it's a big pipe. We got a lot of compressor stations on it. We got to make sure everything works, et cetera. We would expect to be in service and have those contracts go into effect, as we said, in early 2021.
Got it. That's it for me. Thank you.
Thank you. We are showing no further questions at this time.
All right. Thank you very much. We appreciate your attendance.
Thanks all.
Thank you. That does conclude today's conference. Thank you again for your participation. You may disconnect at this time.