Kinder Morgan Inc - Class P (KMI) — Q3 2020 Earnings Call Transcript

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 disclosures on forward-looking statements and the 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 look back and reflected on 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. But 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 share repurchases. So 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. Now, 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 and 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 a certain amount of it through our pipes. If refiners produce renewable diesel, we can transport that through our product pipelines. And 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. And with that, I'll turn it over to Steve.

All right, thank you, Rich. So I'll give you an overview of our business and then turn it over to our President, Kim Dang, to cover the outward and segment updates. Our CFO, David Michels, will take you through the financials. And then we'll take three questions. Our financial principles remain the same, maintaining a strong balance sheet, maintaining our capital discipline through our return criteria, a good track record of execution and 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, a cut of 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 costs is that our projected DCF less discretionary capital spend has actually improved, versus our plan by about $135 million 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 a 5% year-over-year dividend increase to $1.05 annualized, providing an increased but well-covered dividend. So 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 $1.45 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 is yielding over 8% on a well-covered dividend. We will review dividend policy with the Board following the 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. I believe that we will achieve substantial savings. Additionally, as always, we will be evaluating costs and revenues as part of our annual budget process, which we are 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 will 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 advanced the ball significantly on all three in 2020. So 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 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, 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 the ongoing energy transition, and I'd like to make a few points about how we participate. First, we and many objective experts, as Richard mentioned, believe that natural gas is essential to meeting the world's energy needs and 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 or deliverability. The value of that increases for the power sector as more intermittent resources are relied upon 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, as 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, 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 manmade 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 is always our approach to be very disciplined. The G in ESG is critically important, and we won't forget about that. We believe that winners in our sector will have strong balance sheets, low-cost operations that are safe, environmentally sound, and the ability to get things done in difficult circumstances. As always, we'll evolve to meet the challenges and opportunities we face. And with that, I'll turn it over to Kim.

Okay. 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. So first, starting with the natural gas segment, transport volumes were down about 2% or approximately 575,000 dekatherms per day versus the third quarter of 2019. That was driven primarily by lower LNG demand, competition from Canadian deliveries, and lower 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 dekatherms a day versus the third quarter of 2019. They were also down versus the second quarter of this year. However, 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, and they were up 500 a day 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. So compared to the second quarter, volumes were down about 4%. KinderHawk, which serves the Haynesville was down due to lack of drilling and the decline in existing wells; however, we're still expecting based on conversations with customers and a 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 Highland system and the Bakken, which were up approximately 30% versus the second quarter of this year. On our natural gas projects, we completed our Elba facility during the quarter, and it is now fully in service. On PHP, we're now about 97% mechanically complete, and we expect to be fully in service in early 2021. On the product pipeline 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 that the EIA shows for the third quarter. So our volumes are slightly worse than the EIA and that's primarily because jet fuel is 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 are 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 a 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. But 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 and 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 liquid utilization percentage, which is a more accurate predictor of the health of this business given the structure of our contracts, remains tight at about 96%. If you exclude tanks out of service for the 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 the CO2 oil production sector, we saw a decrease of 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 has done a tremendous job of adjusting to the current reality; they've achieved cost savings both on the OpEx and capital side. They've reevaluated and cut capital projects that didn't meet our return criteria, and 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 planned 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're projecting on fourth quarter volumes, for refined products within the products pipeline 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. And on natural gas gathering volumes, we're expecting volumes in the fourth quarter to be essentially flat with what we saw in the third. And debt to EBITDA, we're expecting to finish the year at approximately 4.6x debt to EBITDA, slightly better on this metric than what we told you last quarter. And with that, I'll turn it over to David Michels.

Great. Thank you, Kim. Today we're declaring a dividend of $1.26, 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. And 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 $1.21 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 lower refined products, coal, steel, and pet coke 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 plantation and 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 other item, the main driver behind our other item, favorable $34 million, was the 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, and 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 was down 5% from the third quarter of last year, and our DCF per share of $0.48 is down $0.02 from last year. On the balance sheet, we ended 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 at 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, which were the lowest ever achieved 10-year and 30-year issuances coupons associated with those 10 and 30-year issuances respectively for KMI. The issuance also further bolstered our already strong liquidity position as those proceeds more than covered the amount of debt maturing in the quarter. So 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 compared to last quarter. To reconcile the quarter changes, we generated $1.085 billion of distributable cash flow, spent $600 million in dividends, $400 million on growth CapEx and JV contributions, and had a $270 million working capital use, which accounts for the majority of the $189 million change from year-end. We generated $3.347 billion of distributable cash flow, brought in $900 million from the Pembina share sale in the first quarter, paid out dividends of $1.77 billion, spent $1.4 billion on growth capital and JV contributions, spent $235 million on taxes associated with the Transmountain and Pembina share sales, bought back $50 million of KMI shares, and had $360 million of working capital used, mostly interest expense paid, which explains the majority of the $433 million reduction in net debt from year-end. And with that, I will turn it back to Steve.

Okay. Thanks, David. So Sheila, we'll open it up to questions. And I'll remind you that, as we've done in the past, as a courtesy to all callers, we ask that you limit your questions to one question per person with one follow-up. However, if you do have additional unanswered questions, please get back in the queue, and we will come back around to you. Okay, Sheila?

To start off, can you provide an overview of the recovery pace? It's challenging to gauge, but I'm curious about your insights. In the G&P segment, what kind of activity are you witnessing this quarter, and how do you foresee its recovery in the upcoming quarters? Additionally, regarding product demand, when do you believe we might return to pre-COVID levels? I'm trying to understand how this situation might evolve in the next few quarters.

Okay, yes, fair enough. I mean, 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 bumped back up big in the second quarter, and in the third quarter, it's been more gradual, but we're still seeing month-over-month improvements. I think we don't have any special insight into how quickly people will return to driving or certainly starting to see diesel volumes has remained fairly strong. Jet, I think most people would say, and I think we would say, that jet is likely to lag. But its impact on us is relatively smaller than what its volume impact is. So about 12% of what we handle in our refined products business is jet, but it only comes down to about 8% of the EBITDA for those segments. And then, for KMI overall, it's about 12% of refined products, 3.5% of the combined refined products and terminal segments on EBITDA contribution. So 1% for KMI overall; that’s the whole of object volume. So 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. And there, I think the recovery is going to be, 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's going to start turning around because we do need to produce natural gas in the United States. If we're not going to produce it to meet demand, if we're not going to produce it and associated gas plays, it's going to come from the dry gas plays, and the Haynesville is well-positioned for that and 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. So look, it's a bit of a mixed bag across the G&P landscape, but that's directionally how we have sized it up.

That's very helpful. Thanks. And 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 a greater penetration from EV and biodiesel. And just putting all that together, thinking about these refineries potentially closing there. How does this impact KMI or more importantly, how does KMI, I guess, respond to this going forward?

Yes. So 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 pipeline 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 can participate. So I mean, 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, but we can adapt and adjust to that. But 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 really eliminate internal combustion engine sales in new cars in California. A couple points that I would make that mitigate that. One is not all of our volumes on our SFPP system serve the California market. Some of it moves to serve Arizona, as well as serving Nevada, both in the Las Vegas and Reno markets. And the other thing is, it takes a while; we'll talk about between now and 2035. It takes about 10 to 12 years to roll over the vehicle fleet, et cetera. So there are a number of things that really mitigate that impact for us on the refined product side.

Firstly, on M&A, Steve, we know we have seen a wave of upstream M&A recently, and the midstream sector appears to be primed for it as well, with recent headlines around certain G&P companies exploring sells. If a deal were to satisfy your criteria for leverage in DCF accretion, which area of business would KMI prioritize pursuing M&A again?

I'll give you a really key point there, which is it has to meet the criteria that includes meeting balance sheet criteria, as well as being a business that I think generally we're already in and that we're confident can operate. We can bring some additional synergies in. We can always bring cost synergies; we believe we are an efficient operator, but we have to find other things that we can do. Look, I think there are two parts to 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, I think, and they're doing it in a way that doesn't harm the entity going forward. I think too big of a premium, for example, et cetera. In midstream, we continue to keep our eye on relative valuations with all those criteria I mentioned earlier. 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 kind of 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 are 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 will look to act on those. So not yet; we're really seeing it in midstream. But we think there may be some asset sales that come online later in the process here.

Got it. Thanks for that, Steve. And second question on additional thoughts on shareholder return here? How are you weighing buyback versus distribution growth? 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?

Yes. 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, and invest in projects that are good returns and well above our cost of capital, et cetera. And you're right; I mean in the current environment with a security that's yielding over 8%, certainly, that's the case. However, we're going to be thoughtful about this, and 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 or shouldn't be increasing. We think that that's a very valuable, reliable, and steady way to return excess cash to our shareholders. And we believe that the market from time to time appreciates that, and at times, it doesn't. And I don't think we can make our decisions based on what is currently prioritized. But clearly, by saying what we said in the release, we're giving ourselves flexibility, which I think is a very wise thing for us to do in a time like this.

Appreciate the prepared remarks around energy transition and potential opportunities for the KMI asset base. Coming in from a slightly different angle, can you speak to your philosophy on capital structure in the context of transition?

Capital structure and in what sense?

Mostly thinking here in terms of the balance sheet and whether leverage is the appropriate metric. Is there some consideration of rating? Really just trying to understand, if there is, 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?

Yes. No, I understand. Look, we still believe, and Anthony can weigh in on this as well, that the rating agencies believe that we are appropriately rated at BBB flat around 4.5x 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. But in my casual observation of it, it's funny to me that in our sector, when we talk about 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. And so I think there's no pressure there to do something different on 4.5x when you think about that runway and the quality of our assets, the diversity of our cash flows, and the length of our contract terms. The increasing irreplaceability of our assets, if you will, I mean, the harder it is to build new infrastructure, the flipside of that is that the existing infrastructure, which we haven't had a lot of, becomes more valuable, all things being equal. And so I guess the short answer is no.

Appreciate that. And then on the Rockies pipeline network, you mentioned some producer optimism in the Haynesville just given the moving strip here. Could you characterize recent conversations around the Rockies region, and whether that your thoughts on recontracting potential have shifted at all?

I'll ask Tom Martin to speak to that. Tom?

Yes. I mean, I think clearly, we're seeing less development activity in the Rockies than we were seeing probably a year ago. And so that certainly will have an impact on having excess capacity in that market. But I mean, I think we have valued that, I think in the past, appropriately, and so I don't see that as a material change for us overall. Clearly, things that we've known about that are on the big contracting 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.

So 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, and if we should expect significant cannibalization when PHP starts next year?

The vast majority of it is under reservation fee-based contracts. So that's really EPMG and NGPL and the hill country pipeline, which is a smaller intrastate pipeline than the two new ones that we're building. So it's mostly reservation fee or take-or-pay based. I mean, I think that the one impact that we'll see, or that we started to see, is that with less constraints, there's less of the short-term business that we were doing and getting nice rates for. So it does have some impact, not to the base as much as to some of the upside opportunities that we have been seeing; so it'll be some impact at the margin there.

No. You covered it, Steve. Thank you.

Thanks. And then just one more about energy transition. So in a scenario where 2035 utility of gas demand drops significantly but to your point earlier, they still need very high availability of gas to cover a peak daily demand. How would you see contract structures with utilities and gas pipelines changing, if at all? Do you think they'll have to keep contracting their maximum daily quantities or pay you the same or pay less? If you could just talk a little bit about how you think contracts would change in that environment?

We believe that our current tariff structures can effectively accommodate the changing environment. For instance, if a customer requires power or gas delivery for three hours each day rather than around the clock, we can offer it on a long-term basis at the maximum rate or an agreed rate. Customers are willing to pay for capacity when they need it, even if overall utilization decreases. We have successfully renewed contracts on favorable terms with our clients, including those in California. We've also sold capacity to merchants who operate under similar principles, allowing them to benefit from spikes in demand while we secure term contracts. We are currently exploring new service structures that better align with the variable demand from power generators and may introduce some proposals, particularly regarding storage, but we are confident we can operate effectively within our existing framework.

I think that's right, Steve. I mean, I do; we are starting to see some variable type services being contracted out west. But 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.

Just wanted to come back to one of the earlier questions, unfortunate to use the question on this, but just with respect to the commentary around buybacks and the dividend. Maybe I'm paraphrasing here a little bit here, but you added buybacks efficiently 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're definitely 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 may increase the dividend at a smaller rate but that you look to pair return of capital needs to shareholders via using buybacks? And so it could 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?

Two things: one is that, again, we'll complete our budget process and talk to the Board about how to look at dividend policy for 2021. But yes, as I said, we are by talking about buybacks, and of course, we've been talking about buybacks for a while. We've utilized about $575 of board authorized $2 billion of capacity; we did a little bit earlier this year, for example. So that's not a new message. I think what's new is that we are emphasizing the flexibility by not specifically talking about $1.25 in a timeframe on $1.25. So the answer is yes on retaining flexibility, and that is what we're trying to get across today.

Perfect. And 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. But on the last call, there was some discussion around CapEx potentially being as low as a billion dollars for growth CapEx. You also made further emphasis on reducing costs, and I believe you can address 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 both on the horizon? Just any color that you can provide and 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 billion dollars came up?

Yes. So 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, I'm sorry, below the historical range of $2 billion to $3 billion. When you responded, yes, when you ask maybe as little as a 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 late from here. And so 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 in the thick of that as we review our business unit budgets in the coming weeks here. And so all that is 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. But still expect we're going to be able to give you some 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. I really appreciate the color that you provided. And I'll jump back in the queue to ask about a minute renewable natural gas question.

Steve, curious, did 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 of the business? Just curious if anything's sort of been permanently shifted lower, and thinking about certain assets maybe still carrying our 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?

You get to kind of hear a repeat of the way we've talked about this before, but we did our 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 migrating us more toward refined product hubs and a little bit away from these kind of islands, and both terminal assets have seen some very, very good bulk terminal assets. But I think we've done a good job of pruning. And then, I'll say the other thing that we always say, which is we are a shareholder-driven company. If values appear, they are worthwhile, and our shareholders are going to be better off on the other side of the transaction than they were on the way in, then we will consider it. We are a shareholder-driven company. And so even if it's a business that relies on getting the value is really strong and robust. We'll consider those things too.

Okay, fair enough and we'll get pretty consistent there. If I could just get your thoughts on natural gas prices, I realize it's not a major driver for you, but just giving you a position on both the supply side and demand side seems like you'd have a pretty unique view here. And I guess, as we enter next year, obviously, there's supply constraints and 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, and so that's sort of moving the other direction. Just given where the price outlook is now above three, could that actually get tighter from here? Are you seeing enough, I guess, resiliency in the gas basins, maybe a recovery to sort of offset that on the supply side?

So supply is drifting down because of the associated gas plays, and demand is going up. And 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 don't 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. The people are getting their plans together, and we've had good conversations with customers, etc. But I think you're probably right, we are the swing supplier from the 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, and I think, Tom, it's 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 online 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 has been reflected in the price already. But it seems like there could still be 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. And that doesn't happen overnight. I think the demand signals for 2021 look good. And so, we could see things fairly tight, at least in the first half of ‘21, probably drawing down storage levels lower than we have in recent times to help fill some of that. And then, we really need to see response from the producer community for the second half of ‘21 and beyond.

It doesn't directly affect us as it does the producer segment. But we do benefit from some volatility in people's need to have storage and supporting for full storage, or we'll get some benefit out of that I think derivatively.

Just a quick one, 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, or 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?

Yes. So the returns are lower and lower than what we would see in midstream investments. And the argument is that there's so much capital available for those opportunities that the cost of capital is lower and ultimately reflected to 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 windmills. 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 emission source of supply and transportation service. So things like that don't require us to compromise on returns for our shareholders, but still, nevertheless, allow us to participate. I think participate in a meaningful way. The other things are Jack and his team, as I mentioned, they are looking hard at the renewable diesel opportunities. And I think we can look, we can see returns in those businesses that are nice and very consistent with and in some cases may be at the high end as 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 terminal business. But I think we're looking to participate in a way that doesn't compromise on our return criteria.

Very helpful. And then one last one on the buyback topic and the word flexibility has been used a lot this afternoon. And it 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 your opinion on a programmatic type of buyback plan?

Our view really hasn't changed on that. Opportunistic is the operative term. And that's the way we've administered the program that's already in, that program that's in place, but the authorization that the Board has already put in place, and we would expect that to continue that approach to be opportunistic in our purchases.

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 that I think happens at 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. So I think we'll save that until we finish that work. Then, we'll let people know where we think we're coming out.

Okay. I understand. Thank you, Steve. And then 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. But it really hasn't happened in a material way other than the kind of internal consolidation, if you will, animal feed and GT is combining those sorts of things. But there's still a rationale for it is what I'd say. I point to all the factors I talked about in the earlier question as the things that need to come together for us to make sense to us to act on particularly in these times. The point is that there's still a lot of uncertainty out there. We're not on the other side of the downturn to U.S. energy, not on the other side of the virus yet. I think there remains a fair degree of uncertainty out there.

Real easy one here, there's a lot of smaller E&Ps seeing 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 contract renegotiation risk presents itself when you're going through the planning process and thinking about 2021 and beyond?

We believe we provide essential services to these producers, which generally gives us some protection from contract rejections, although this can differ by region. If producers intend to keep producing, they need to ensure their products reach the market, and we play a vital role in that process. This consideration always factors into discussions about contract rejections. In 2020, we faced around $40 million in credit losses due to producer bankruptcies. However, we have several strategies to mitigate this risk, such as requiring adequate credit support and having assets that deliver necessary services, whether to our company or to debtors in possession.

I have a couple of follow-ups. On the upstream M&A, I know you mentioned that in a way as more upstream merges it’s a benefit having larger, better-capitalized customers? What are your thoughts on? Do you think that this also would benefit the larger and more integrated midstream companies that can provide more services or have a bigger footprint? Do you think that that actually works to your benefit?

Yes. 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 the company emerged 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 the new drilling plans and all of that sort of thing, but I think it's a healthy thing overall, for the energy business and at least derivatively for our chapter.

Got it. Okay. And then just one follow up on the energy transition question. You mentioned the ability to use your existing assets. You talked about hydrogen and the ability to use your existing gas pipelines. Natural gas pipelines can transport anywhere from 5% to 15% hydrogen blend without really much modification. What would it be required to transport more hydrogen?

The challenge with transporting more hydrogen is the risk of embrittlement in the pipes, which can lead to cracking in certain types of steel. As for compressors, those produced within the last 20 years are typically capable of handling hydrogen blends of 10% or less. However, older compressors might need some upgrades to manage even blends ranging from 0% to 10%. Furthermore, existing compressor stations likely cannot accommodate blends greater than 10% without modifications.

The only thing I would add is that we need to consider the downstream end users as well, such as which power plants can accommodate varying levels of hydrogen. The industrial applications also raise questions for downstream end users.

Thanks for taking my call again. Just a quick one on Permian highway. It appears the pipeline's progress based on the completion level. It could be placed earlier into service next year. So if you're able to do so, in early Jan, do the contracts kick in right away?

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've got a lot of compressor stations on it, we got to make sure everything works, etc. But we would expect to be in service and have those contracts go into effect as we said in early 2021.

All right. Thank you very much. We appreciate your attendance.

Thanks all.