Kinder Morgan, Inc (NYSE:KMI) Q2 2020 Earnings Conference Call July 22, 2020 4:30 PM ET
Richard Kinder - Executive Chairman
Steven Kean - Chief Executive Officer
Kimberly Allen Dang - President
David Michels - Vice President and Chief Financial Officer
John Schlosser - President, Terminals
Tom Martin - President, Natural Gas Pipelines
James Holland - President, Products Pipelines
Conference Call Participants
Jeremy Tonet - JPMorgan
Colton Bean - Tudor, Pickering, Holt & Co.
Shneur Gershuni - UBS
Spiro Dounis - Credit Suisse
Ujjwal Pradhan - Bank of America Merrill Lynch
Tristan Richardson - SunTrust Robinson Humphrey Inc
Keith Stanley - Wolfe Research, LLC
Pearce Hammond - Simmons Energy
Michael Lapides - Goldman Sachs
Christine Cho - Barclays Capital
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. [Operator Instructions] I would like to inform all parties that today’s conference is being recorded. If you have any objection, you may disconnect at this time.
I will now turn the call over to Mr. Rich Kinder, Executive Chairman of Kinder Morgan. Thank you.
Thank you, Denise. As usual, before we begin, 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 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.
Now, as I always do on these calls, let me talk briefly about our financial strategy at Kinder Morgan. To say that these are unprecedented times for the American economy is an understatement and particularly for the energy business. We faced the continued impact of COVID-19, together with the negative effect that virus has had on worldwide demand for most of the products we move through our pipelines and handle at our terminals.
So the question is, what should our financial strategy be in the face of these black swan events? Actually, in our judgment, the response is pretty similar to the approach we’ve been using for the last few years. We will continue to prioritize returning value to our shareholders, while maintaining a solid investment-grade balance sheet.
Specific to our balance sheet, we are fortunate to have paid down approximately $10 billion in debt since 2015. We’re also fortunate to have assets that throw off substantial cash flow, even under adverse circumstances. We need to live within that cash flow by funding all dividends and expansion CapEx from those internal – from these internally generated funds. We’re doing that today and expect to accumulate cash in excess of our dividends and our CapEx, even in the challenging year of 2020.
As previously announced, we reduced our expected expansion budget by about 30% this year and are also reducing our operating expenses and sustaining CapEx, which Steve and Kim will talk about in just a few minutes. We’ve raised our dividend payout and expect to do more in that regard when normal economic conditions return.
Looking beyond 2020, we believe we are operating in a maturing business segment and that our opportunities for viable expansion projects will likely be significantly less than we have experienced over the last several years. If that expectation proves accurate, they will probably reduce our growth potential, but will allow us to husband [ph] significant cash flow that we can use to increase our dividend, pay down debt and/or buy back shares under the right conditions.
Our goal is to be disciplined in every respect. That means being very careful in high grading potential capital expansion expenditures and keeping a focus on operating our assets in the most efficient way possible.
Now, most investors we talk with, whether generally positive or not on the KMI story, believe that given our size, attractive assets and relatively strong balance sheet, we will be a long-term survivor. With that in view, they see us as a potential consolidator in the midstream area.
Let me say that while we would never rule out a potential M&A transaction, we will not undertake such action to the detriment of our balance sheet. Beyond that, it would have to be accretive to our distributable cash flow.
One final thought. In unsettled times like these, the famous quote of Mark Twain comes to mind. He said, “It’s difficult to make predictions, particularly about the future.” That said, I believe in this kind of environment, staying power and maintaining a long-term outlook are keys to long-term success and the delivery of real value to our shareholders.
And with that, I’ll turn it over to Steve.
All right. Thanks, Rich. I’ll give you an overview of our business, including the coronavirus situation. I’ll give you an update on our Permian Highway Pipeline project. I’ll also provide some color on the organizational announcement that we’re making today. Then I’ll turn it over to Kim Dang to cover the outlook and segment updates. And then our CFO, David Michels, will take you through the financials, then we’ll take your questions.
In times like these, it’s especially important for us to keep our priorities and principles in mind. Our priorities throughout the COVID response has been to keep our employees safe and to keep our businesses running. We operate infrastructure that is essential to businesses and communities across the country. We need to keep our assets running and we have.
To protect our employees, we instituted telecommuting for our offices and that’s worked astonishingly well. We also made changes in our field operations to enable our coworkers to do their work, while maintaining appropriate physical distance. In a few cases where distancing was not possible, we enhanced our PPE requirements. It’s working, all of our assets are running, and we’re keeping our coworkers safe while they are at work.
Community spread has continued and it’s affecting us, particularly in our Houston area locations. But telecommuting and the other precautions we are taking have allowed us to maintain effective, safe, reliable operations, while largely keeping our coworkers from contracting or spreading the virus while at work.
Our financial principles remain the same. First, maintaining a strong balance sheet. Second, we are maintaining our capital discipline through our return criteria, a good track record of execution and by self-funding our investments. On that front, we evaluated all of our 2020 expansion capital projects and reduced CapEx by about $660 million from our 2020 budget in response to the changing conditions in our markets.
We still have over $1.7 billion of expansion capital in 2020 on good project investments and a backlog of $2.9 billion, 71% of which is a natural gas. We’re also maintaining cost discipline. We now stand at nearly $170 million of expense in sustaining capital costs savings for 2020, including deferrals, up from $125 million that we reported to you in April.
The result of this work on our capital budget and our costs is that our projected DCF less discretionary capital spend has actually improved versus our plan, notwithstanding the pandemic and notwithstanding the degradation to our forecast which more than offset the degradation to our forecast with spending 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. Strong balance sheet, capital and cost discipline and returning value to shareholders, those are the principles we continue to operate by.
We continue to make very good progress on our Permian Highway Pipeline project, which is supported by long-term contracts with a take-or-pay structure. Construction is proceeding very well. And we are now nearly 80% mechanically complete on the pipeline, actually, 79% as of this morning, and we’re 97% complete on our mainline compression. We still expect to be fully in service in early 2021.
Permitting delays preconstruction and some additional land acquisition and river crossing costs have impacted returns, but we are still looking at a strong double-digit unlevered after-tax return on this project.
Our team has continued to overcome obstacles and the number of remaining obstacles has shrunk considerably, particularly in light of the Supreme Court decision to stay the injunction against the Army Corps Nationwide Rule 12 permitting process, but also as a result of adjustments the team has made in routing and construction.
The other topic I want to touch on is the organizational changes that we made today. James Holland has been appointed Chief Operating Officer reporting to Kim. James has a long successful history at Kinder Morgan, including most recently as President of our Products Pipeline Group.
We asked James to take on the leadership of our ongoing ESG and operational excellence initiatives. Also, we have asked James to lead our examination of cost effective changes in our organizational structure. Our management team is in the midst of an effort to determine how we operate and is considering centralizing certain functions in order to be more efficient and effective.
We are already an efficient and lean organization. But we are always looking to do better, especially in today’s challenging environment. We believe that cost effectiveness is one of the keys to long-term success in our sector. 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 the budget together.
The management team is committed to these objectives, and James will help make us – make sure that we meet them. We expect to conclude this review concurrent with the preparation of our 2021 budget.
We also announced Dax Sanders will take over as President of our Products Pipeline Group. Dax has had a long successful career here, too, has been first Chair on our acquisition and divestiture activity for over the last seven years. More than being the corporate development guy though, Dax has also been a key player in every significant strategic decision we have made.
Now, he will bring his skills and experience to bear on leading a business unit and working with a great team in our Products Pipeline segment. Kevin Grahmann will take over Dax’s role in corporate development, and he will do a great job. We won’t miss a beat.
And with that, I’ll turn it over to Kim.
Kimberly Allen Dang
Okay. Thanks, Steve. I’ll go through a review of each of the business segments, as well as a high-level summary of our current full-year forecast. So first, starting with the business units and natural gas.
Natural gas transport volumes were up about 3%, or approximately 940,000 dekatherms per day versus the second quarter of 2019. That was driven by GCX, which went into service last September; TGP, due to increased LNG deliveries; CIG, due to heating demand and DJ Basin production; and volumes on our Texas intrastate due to demand growth.
Physical deliveries to LNG facilities off of our pipelines were up over 900 per day versus Q2 2019, but they were down significantly versus the first quarter of this year. Exports to Mexico were flat in the second quarter when compared to the second quarter of 2019. Deliveries to power plants were up about 6%, driven by coal switching and warmer weather. And LDC demand on our system was down approximately 7%. Industrial demand was relatively flat.
Our gathering volumes were down about 8% in the quarter compared to the second quarter of 2019. They were down 9% compared to Q1 of this year. KinderHawk, which serves the Haynesville and the – and our Oklahoma assets were down due to the lack of drilling and the decline in existing wells. Volumes on our Hiland system, which is in the Bakken, were down due to production shut-ins.
In general, what we’re seeing in the Eagle Ford and the Bakken is that volumes bottomed out in May and June, respectively, with some increase in volumes thereafter, as producers started to bring back shut-in production. In the Haynesville, which did not have the shut-ins we saw in the associated plays, we expect continued volume decline this year due to the lack of drilling. However, we continue to have conversations with producers about incremental volumes in 2021, given the current natural gas price curve.
In our Products Pipelines segment, refined products volumes were down about 31% for the quarter versus the second quarter of 2019 as a result of the pandemic and about the same percentage versus plan. So that’s slightly better than the 40% that we projected for the second quarter and our Q1 call.
Volumes versus our budget were down over 40% in April, and then we saw recovery in May and again in June. And so in June, they were down about 24% versus our budget. Currently, volumes in our Products Pipeline are down roughly 15% and that’s really depending on the market.
Crude and condensate volumes were down about 26% in the quarter. Here, we saw the largest decline in May versus April for refined products, with the weakness largely carrying into June. These volumes were weaker in Q2 than what we projected for you in our Q1 call, largely offsetting the better refined products volumes. In July, we started to see some recoveries as producers have brought some shut-in production back online with a recovery in oil price.
In terminals, we experienced declines in our refined product throughput of about 24%. So slightly better than what we saw in our Products Pipeline, and that’s just driven by the different markets that we serve. However, the financial impact of the volume decline is more moderate in this segment, given the primarily take-or-pay contract structure.
One bright spot in the midst of the pandemic has been the demand for tankage. Currently, we have approximately 99% of our tankage under contract. In CO2, oil production was down approximately 13%. Over 20% of that reduction was associated with production curtailments that we instituted when prices dropped below about $20 a barrel.
With improved prices, we’ve restarted the majority of that production without operational issues or impacts to the reservoir. CO2 volumes were down about 31% in the quarter. Overall, CO2 demand in Southwest Colorado is at a level that we haven’t seen since 2004. However, we expect to see some rebound as oil prices improve.
For the full-year, we’re projecting to come in slightly below the guidance we gave you in the first quarter of approximately 8% below budget on EBITDA and approximately 10% below budget on DCF.
A number of you are going to ask on the follow-up calls what slightly means? So right now, we estimate we’re about 9% and 11%, respectively, on EBITDA and DCF. But that implies much more accuracy and specificity than what we really have in these highly uncertain times and thus our guidance of slightly below.
The slight deterioration that we’ve seen since the first quarter has all been in midstream natural gas due to the lower gathering volumes in the Bakken, the Haynesville and Eagle Ford. Producer bankruptcies and softer market fundamentals impacting our Texas Intrastate business.
Our forecast for refined product demand for the balance of the year assumes volumes are down 11% to 12% in Q3 and 5% in Q4 versus our budget, and that’s largely unchanged from what we projected for you in our first quarter call.
For natural gas gathering volumes, we’re projecting volumes for the second-half of the year, on average, to be relatively flat versus what we saw in the second quarter. This equates to down approximately 12% versus the second-half of 2019 and down approximately 20% versus our budget for the second-half of the year. This is a change from what we projected in Q1. And as I mentioned previously, one of the drivers of our slightly lower guidance.
We’ve continued to look for expense reductions to offset the volume and price impacts that we can realize without sacrificing safety or compliance. Incorporated in our guidance is the $170 million of cost savings between OpEx, G&A and sustaining CapEx that Steve mentioned in his comments.
We’re now projecting that year-end debt-to-EBITDA will round up to 4.7 times due to the EBITDA deterioration. We continue to operate in a highly uncertain and changing environment. It is difficult to predict what will happen. Certainly, at the time we announced our Q1 earnings, no one was predicting the COVID outbreak that we’ve seen – that we’re seeing in Texas, Florida, Arizona and California.
As we did last quarter, Table 8 of the press release provides you with sensitivities around the biggest moving pieces of our forecast, so that if things change, you can calculate the impact on our business.
And with that, I’ll turn it over to David Michels.
All right. Thank you, Kim. So now, as we’re all aware, this year’s events have had a negative impact on our EBITDA and on our DCF. But as was previously mentioned, we’ve identified capital expenditure reductions, which more than offset the DCF reduction. And so we expect to fully fund all of our cash needs, including our capital expenditures and our dividends within our distributable cash flow.
We also have $950 million of debt maturing in September and another $1.9 billion maturing in the first quarter of next year. But with that said, we had over $500 million of cash on the balance sheet at the second quarter – at the end of the second quarter and an undrawn $4 billion credit facility. So we have ample liquidity, even accounting for our debt maturities.
Now, moving on to the quarter, we’re declaring a dividend of $0.2625 per share, or $1.05 annualized flat with last quarter. Revenues were down $654 million from the second quarter of 2019, driven in part by lower natural gas prices this quarter versus last year’s quarter. And those lower natural gas prices also drove a decline in associated cost of sales of $336 million. So gross margin, revenue less cost of sales was down $318 million, which is a better indicator of our performance relative to revenue alone.
The loss on impairments and divestitures of $1.005 billion includes $1 billion impairment of our natural gas midstream business, which was driven by a sharp – the sharp decline that we all saw in natural gas production activity impacting several of our natural gas midstream assets. Due largely to that impairment, our net loss attributable to KMI was $637 million for the quarter.
Adjusted earnings, which is our non-GAAP term for net income adjusted for certain items, and that certain items this quarter is comprised mainly of that impairment just discussed.
Our adjusted earnings were $381 million, down $112 million compared to the second quarter of 2019. Adjusted earnings per share was $0.17 for the quarter, which is down $0.05 from the prior period.
Moving on to distributable cash flow performance. Natural Gas segment was down $55 million for the quarter. The sale of Cochin drove most – more than half of that lower contribution. Additionally, various gathering and processing systems experienced lower activity and our Tennessee Gas Pipe was down due to 501-G impacts and mild weather. Partially offsetting those were contributions from – greater contributions from Elba Liquefaction and Gulf Coast Express projects.
Products was down $80 million, driven by lower refined product volume, as well as lower crude and condensate volume. Terminals was down $61 million. This was also partially driven by the sale of KML, as well as lower refined product, coal and steel volumes.
CO2 segment was down $28 million, driven by lower CO2 and oil volumes, partially offset by cost savings. Our general and administrative and corporate charges were higher by $5 million due to lower capitalized overhead, partially offset by some lower non-cash pension expenses, as well as the sale of KML.
JV, DD&A and NCI, this $20 million of reductions are explained mainly by our partner sharing in the Elba Liquefaction’s greater contributions. And that explains the main changes in adjusted EBITDA, which was $249 million, or 14% lower than the second quarter of last year.
Interest expense was lower by $59 million, driven by lower floating rates benefiting our interest rate swaps, as well as a lower overall debt balance, partially offset by lower capitalized interest. Recall we used the proceeds from our KML and Cochin sales to reduce debt.
Cash taxes lower by $46 million due to deferred tax payments at Citrus, Plantation, a deferral of our Texas margin tax and the sale of KML, which was a taxpaying entity. Those deferrals are only to later in 2020. For the full-year, cash taxes are in line with our budget.
Sustaining capital was $31 million lower versus Q2 of 2019, and total DCF of $1.001 billion is down $127 million, or 11%. DCF per share was $0.44 per share, down $0.06 from last year.
So to summarize the distributable cash flow impacts, segments were down $224 million. We had lower capitalized overhead of $24 million. Greater cash pension contributions of $18 million, partially offset by lower interest, taxes and sustaining capital of $135 million, and that gets you just over $130 million of the $127 million change.
Moving on to the balance sheet. We ended the quarter at 4.5 times debt-to-EBITDA, up from the 4.3 times we had last quarter and at year-end 2019. Our net debt ended the quarter at $32.4 billion, which is down $622 million from year-end and $153 million lower than last quarter. As Rich mentioned, but it’s worth pointing out again, our net debt has now declined by about $10 billion since the third quarter of 2015.
So to reconcile the quarter change in net debt, we generated just over $1 billion of DCF. We paid out $600 million of dividends. We spent $500 million on growth capital and JV contributions, and we generated $250 million of working capital source of cash. And that explains the majority of the $153 million change for the quarter.
Reconciling from year-end, the lower – $622 million of lower net debt, we generated $2.262 billion of distributable cash flow. We received a little more than $900 million from the Pembina share sale. We paid out $1.17 billion of dividends. We spent $1 billion on growth capital and contributions to JVs. We we paid $160 million of taxes on deferred Trans Mountain and Pembina share sales. We bought back $50 million of KMI shares and we had $150 million use of working capital changes, and that explains the majority of the $622 million.
Finally, as Kim mentioned, there’s still plenty of uncertainty for the remainder of the year. So as we did last quarter, we’ve provided a table with sensitivities to some of those assumptions that remain uncertain, so you guys can model accordingly. Also, consistent with last quarter, we posted a supplemental slide deck to our website, which provides some helpful information on our assets, customers and contract mix.
With that, I’ll turn it back to Steve.
All right. Thank you. And I’ll remind everybody that as a courtesy to all the callers, we’ll limit the questions per person to one question with one follow-up. But if you have additional unanswered questions, get back in the queue and we will get back around to you.
So with that, Denise, if you would open it up for questions.
Thank you. [Operator Instructions] And our first question comes from Jeremy Tonet with JPMorgan. Your line is open.
Thanks for taking my question. Just want to start off on the CapEx comments, I think, that you began the call with here. I’m just wondering if you could provide any more color, I guess, what you think of sustaining rate of CapEx would be kind of in 2021 or plus. Just trying to get a feel there for what the opportunity set is and how you think about that versus free cash flow and type of returns you can get? I think, the EBITDA multiple that you guys quoted this quarter was 5.8 versus 5.6 in the past. So just trying to see how this all fits together?
Yes. So we had previously talked about being in the range and we’ve been in this range for about 10 years of $2 billion to $3 billion a year of capital expansion opportunities that would manifest, that we would pursue and get along our system because of the network we have and because of the broader dynamics in U.S. energy.
Certainly, what we’ve seen this year with everything that’s happened, both in energy and in broader markets, is those opportunities reduced. And so we’ve been very disciplined and reacted quickly to what we saw there and we took a substantial amount of capital out. And so we’re now sitting this year at $1.7 billion.
And so, Jeremy, we don’t know where that number is going to be. But I think, if you look at, let’s call it the next few years kind of outlook as it looks from standing here today, that number looks like it doesn’t get to the $2 billion to $3 billion. In fact, it looks like it hangs around the level we’re seeing in 2020, maybe a little less.
And so – but the way we’ll generate that capital investment opportunities is the same way we always have, which is we’ll go look for investment opportunities that are attractive to our shareholders, but we’ll have a high hurdle on it, particularly in this day and time. What – if you’re trying to build linear infrastructure, you have to have margin of safety in any investment that you’re thinking about making.
So we’ll have a high hurdle rate, give ourselves substantial headroom and margin for safety above our weighted average cost of capital. It’s got to be something we’re confident we can deliver, get permitted, et cetera, on time and on budget.
And as Rich mentioned at the very beginning, it’s an increasingly more difficult time to get linear infrastructure built. And so all of that goes into, I think, guiding you to a forward view on expansion capital that’s below what our historical run rate has been.
And I would add consistent with what Steve is saying that, of course, as I said at the beginning, it cuts both ways, but it certainly helps us in terms of looking at our cash flow. If you just think of producing $4.5 billion of distributable cash flow and then take out $1.5 billion, you’re left with $3 billion. The dividends at the current rate are a little less than $2.5 billion. So you have several hundred million dollars in that very rough pro forma, several hundred million dollars of cash flow above self-funding of the dividend and all of the expansion CapEx.
And the objective of self-funding is one of the reasons that led us back really starting in several years ago to elevate our return criteria.
That’s very helpful. Maybe picking up on that last point, Rich, the several hundred million of free cash flow you talked about there. You see that leverage kind of stepped up a little bit versus what you guys had thought about before. And just want to confirm there’s no need for equity or anything like that. You guys are still in good standings with the agencies here.
And as you think about where to put those several hundred million, it seems like leverage – deleveraging would be kind of a top priority versus buybacks or other options. Just wondering if you could update us on deleveraging buybacks and how that all kind of fits together…?
Well, as we said, we continue to have maintaining a strong balance sheet is one of our top priority. So we certainly won’t do anything to imperil that. And we think that have – living within our means and generating excess cash flow every year is a real positive in the long range outlook for a strong credit profile.
The next question comes from Colton Bean with Tudor, Pickering, Holt & Company. Your line is open.
Good afternoon. So maybe just a follow-up on the leverage side of things. You noted the expectation for a more mature U.S. energy landscape on the other side of this. And I think we’ve heard some comments from the upstream community, indicating that growth is likely to be structurally lower, even if we were to return to that $50 to $60 barrel world. So as you evaluate financial policy in that environment, any updated thoughts on that 4.5 times debt-to-EBITDA target?
We still think that the around 4.5 times is appropriate for our business and leaves us in solid investment-grade territory. And so we continue to see that as our longer-term objective, that’s not changed by what we’re seeing.
What we will be adjusting is what we were just talking about, which is, as we go out and look at capital opportunities – capital investment opportunities, we do expect those to be less, and that is driven in part by what our upstream customers are thinking about doing.
We got a great network and we’ve got good debottlenecking expansions and other things. We have a $2.9 billion backlog. But as I said, running at the $2.5 billion to $3 billion range is not what we’re expecting or foreseeing for the next several years…
…because of that reduced activity.
Understood. And just with some of the moving pieces right now on Bakken takeaway, it seems like this is a scenario where you see a materially wider differential. I think, you’ve noted recently that HH is less contracted than some of your other assets. How do you think about the opportunities that in the event that based on the takeaway becomes a constraint?
Yes. So we have seen increased activity and interest in HH. Our volumes were up this month versus last month. That is a function of, I think, really two things, concerns about takeaway, but also for reasons of priority of access to HH, people do want to maintain their history on the system. So we continue to see barrels that might have otherwise gone someplace else, they’re continuing to come our way.
And so that’s a – that’s one effect of people’s concern around the DAPL situation. And we do see the same thing that you’re saying, which is we could see differentials expand the WTI in the Bakken if there is a shutdown.
I – we don’t have any special insight into that, that seems to me like a relatively unlikely result in the end. Obviously, it’s stayed right now, but it’s not – there’s no decision on the merits on it, it was just a stay, so that it could be considered without causing undue harm or disruption in the market.
The other impact from DAPL is, it is one of the outlets on our Hiland crude gathering system. And so our customers want to continue to have that outlet in addition to HH and we want them to have that outlet. So they continue to move those volumes on our system. So we don’t have any interest in seeing a shutdown. It’s a bad broader message for pipeline infrastructure, but also for our business, particularly on the gathering side.
The next question comes from Shneur Gershuni with UBS. Your line is open.
Hi, good afternoon, everyone. Happy to hear everyone is safe and well and congrats on the promotions. Maybe the – to start up a follow-up on Colton and Jeremy’s question on the CapEx side. Given the difficult legal landscape right now, given the fact that the E&Ps are talking about free cash flow positive and keeping their CapEx down.
Is – you’d mentioned in one of your responses about hanging out kind of where you’re at right now on growth capital. But is there a scenario where 2021, or maybe in 2022, where growth CapEx could be as low as $1 billion?
We’re close, yes. We’re close.
We’re close. Okay. And maybe as a follow-up question, your language around the guidance of slightly lower than 10% in terms of EBITDA. You also mentioned some green shoots as well, too. I was wondering if you can expand on them. And if nothing changes, where you’re seeing things right here? Is it fair to say that your outlook for considering a dividend increase during the fourth quarter board meeting is effectively unchanged at this point right now?
We’re not changing anything from what we said in April. It is something that we’ll take up with all the facts in front of us when we get together in January as we normally do to consider the fourth quarter dividend. So no real update, that’s still our perspective on it. And, Kim, I’ll ask you to comment on some of the green shoots.
Kimberly Allen Dang
Yes. I think – and we’ve tried to – I think, we have incorporated the green shoots into the the guidance forecasts that we gave you. We saw a little bit better petroleum product demand in May and June than what we expected, but we have improvement built into that forecast for the balance of the year.
We’ve seen more leasing of our tanks on the – in the terminal side. But we also built that into our forecast for the balance of the year. And in terms of the volumes on the G&P side, we’ve seen some increase in volumes in July. And as I said a while go, I think, our perspective on the balance of the year is that we’re kind of flat to the second quarter.
The next question comes from Spiro Dounis with Credit Suisse. Your line is open.
Hey, afternoon, everyone. Just wanted to maybe ask about 2021. And I think 2020, we’re all fair to say that it might go down as a bit of an anomaly when we look back on it. And so just thinking about returning to normal and maybe what the earnings ability the company looks like, obviously, took off about $600 million from the budget from the start of the year. Some of that, obviously, is going to have a lasting impact.
But just how are you thinking about a return to normal 2021? How much of that $600 million comes back? And how do you think about some of the offsetting factors between just the base business decline outside of COVID versus some of the growth projects coming online next year like Permian Express?
Yes. So really, there is still a lot of uncertainty. As we pointed out multiple times here, we go through a pretty detailed budget review that takes a look at what – how markets are shaping up and looks at everything commercially and also looks at our costs on a bottoms-up basis as well. That’s going to be an enhanced review on the cost side this year. And it’s just hard to say right now.
Now we can observe the same macro factors that you have and some of this ties back to what we discussed on the capital side of things, which is the producer community is in a different situation even than what it was in, in 2016.
There’s not as much capital available to it. There’s a lot more emphasis on free cash flow that tends to – that would tend to dampen what expectations would be for U.S. energy production. And we’ve kind of got to make up for what we lost this year before you begin to see it grow again.
And so I think this – the overall – everything that’s happened in energy has kind of pushed the return to growth out a couple of years. And who knows beyond that, right? And so, I think, generally speaking, the opportunity to deploy additional capital or deploy capital at our historic levels, as we’ve said several times now, it’s just not likely at this point from our perspective.
So we think we’re going to be looking at a lower expansion capital spend, and that has pluses, but also minuses. Meaning that, there’s EBITDA at the good return that we set as a hurdle for our investment decisions. That means that there’s an EBITDA that we would have normally expected to get that we’re not going to get if we’re not deploying capital at higher levels.
But really, I go back to the beginning, which is we go through a pretty detailed process in setting our 2021 plan. And we’re not really in a position to start commenting about 2021 yet.
Yes, there’s a couple of answer right now. Appreciate you taking a swing at it. Second, Steve, maybe for you as well. You mentioned the new initiative to further streamline operations. It sounds very early stages, but just curious how you think about the timing of when that would actually start showing up in earnings when we start seeing those savings? And does this review contemplate divesting or maybe even shutting down some underperforming assets?
I would call that latter thing that’s a separate consideration. Meaning, we do look at divestiture – the divestitures from time to time where they make sense. So we think the asset is more – somebody is willing to pay more for it than we think it’s worth. But those I think we’ve done a lot of that already and we’re kind of – we’re down to fairly small pieces there. The exercise, your question about when would that show up in earnings? It would show up in 2021.
The next question is from Ujjwal Pradhan with Bank of America. Your line is open.
Good afternoon, everyone. Thanks for taking my question. First one from me on M&A and the growth of commentary. Rich, thanks for your thoughts on the topic in your prepared remarks. Just wanted to get your thoughts on, given the trough valuation for midstream assets in today’s market, the smaller size of your growth backlog and challenges in building new assets that you have pointed out. If you were to pursue M&A, what asset or geography would be of interest?
We don’t do it that way, and I’ll reiterate what Rich said. I mean, we’ve been – we’ve worked very hard to get our balance sheet where it is. And doing something that hurts the balance sheet, hurts the balance sheet metrics is really not something that we’re interested in. And so we’re going to be – we’re going to jealously guard that. And then also, we would need to see good value in terms of DCF per share accretion as a result.
What we look at as we evaluate those things is, is it in a business that we are comfortable operating that we have – that we understand and where we believe that we can bring some considerable value to it either in terms of costs? Well, certainly, in terms of cost synergies, but also in terms of other strategic synergies, whether those are capital or pieces of the business that we could put together and make better and then you’ve got to find something that’s transactable.
And so there’s – there are a number of screens that have to clear. And so you can’t predict it, and we’ve said that for years now. People have been projecting consolidation in our sector for, I don’t know, six or seven years, something like that. I mean, people think it’s more right now, but we’ve been thinking that it’s right for a while. So those things remain just very hard to call. It’s something that we’re interested in, but it’s got to meet those criteria that we laid out.
Thanks for that, Steve. And maybe a follow-up to that, again, on the topic of M&A. Would you be able to discuss the latest strategic rationale that KMI has been owning and operating the CO2 business with a CNP profile? We saw a renewed interest in this area, given the major independent deal announced earlier this week. So really, the question is do you have interest in monetizing that business? And what would be the right bid for that segment?
I could say just generally that, of course, we’re in the business of maximizing value for our shareholders. So we are always open to considering options there, but I’ll put some context on it for you. I mean, that is a business that is a niche for us. It’s something that we know how to do and how to run.
And Jesse and his team have done really a magnificent job looking hard at the capital and have actually improved the free cash flow coming from that business unit versus what was in the budget with everything that’s happened. And so as a result of cost savings and also capital, either deferrals or reductions, they’ve just done a great job. So I feel like we know what we’re doing in that niche business.
The other consideration or the other element of context to consider is that, it’s a bit of a unique business, right? Enhanced oil recovery, a lot of that is about having the pipeline infrastructure owning the CO2, which we do, knowing what to do with it when you put it in the ground. It’s not a shale play or conventional play.
And so I think just naturally, that tends to limit the market. But look, we do what’s in our shareholders’ best interest. This is a business that we can handle well in terms of its overall part of the Kinder Morgan picture. The EOR part of that business is now and you’ll see this in the updated investor presentation slides posted on the website is now at 3% of our segment EBITDA. So I think that’s the full story there.
Up next is Tristan Richardson with SunTrust. Your line is open.
Good afternoon, guys. Thanks for all the data points on what you’re seeing in refined products towards the end of the quarter and even more recently. Can you talk a little bit about what assets or geographies are sort of leading that demand rebound? And any sort of what areas remain challenged?
Yes. I’m going to ask John Schlosser. He has assets really around the country to take a stab at that. It is different by geography as you imply. Go ahead, John.
Sure. Our Midwest rack facilities are actually up slightly 1% above plan. Our Northeast racks are down 10% to plan, and our Gulf Coast assets – rack assets are down 10% to plan.
Kimberly Allen Dang
And then what we’re seeing on the West Coast, I think, on the Products Pipelines is more like 15% and then also in some places in the Southeast is probably around 15%, both of those in Products Pipelines.
That’s great. Thank you. And just a follow-up from a previous question on the review on streamlining or centralizing some functions. I may have missed this, but you could – is there an order of magnitude of efficiency gains or quantitative cost saves you guys are targeting here?
But we’re going to approach this with kind of a blank sheet of paper, and we’re going to get everything we can out of that process. Looking internally, our organizational structure and thinking of changes to our traditional business unit centric structure is not something we’ve done before. So the outcome of this process is unknown.
So we don’t have a specific target in mind other than we’re going to do the work. We’re going to examine it deeply, do the work from the bottoms-up, and we’re going to make our primary criteria here, what’s the thing that’s going to get us the most efficiency and the most cost savings.
We’re going to look at our outside expenditures. We’re going to look at our organization. We’re going to do what we need to do to deal with the challenging times that we’re in. But because it is kind of a brand-new look at things, there’s not a way to quantify it.
Now, of course, we’ve identified already $170 millions of savings as we’ve all mentioned, so far projected for this year, about $100 million of that is – just a little over $100 million of that is we believe as permanent or recurring, with the balance of it being deferrals that ultimately we will have to spend on – particularly on the sustaining capital side.
The other thing that we’ll have as a clear objective here is the way we put our budgets together, is we make sure that we adequately budget for safety and compliance in our assets. And so we will adhere to that principle, along with adhering to the principle that we’re going to get as much out of this process as we reasonably can. But because it’s unpredictable, we haven’t set a number.
Great. Thank you guys very much.
The next question is from Keith Stanley with Wolfe Research. Your line is open.
Hi. Good afternoon, and thanks for all the transparency. I just wanted to follow-up on how you’re thinking about the dividend. The language in the press releases is still pretty strong on being committed to $1.25. So can you give more color on the criteria you’re looking at to raise it to that level potentially by year-end? Is it just refined products volumes going back to normal? Do you need to see midstream and other businesses start recovering?
And then on the balance sheet, is there a leverage threshold around that. For example, if you were at 4.7 times next year, would that still be an environment where you could do that large of a dividend step up?
Well, let me just say that, I think, Steve alluded to this earlier that we haven’t changed anything from the first quarter. We said at that time, we would see how the year played out. And when we return to normalcy, we – our long-term intention is to take that dividend up to the $1.25 target.
That said, as I said, it’s almost very difficult to predict what’s going to happen between now and then. But we tried to be very careful with the language in the earnings release, and sort of enumerating the factors that we’re going to consider. But the thing – the real thinking is to ascertain whether we have a return to normal economic conditions.
And one of the advantages of making this decision at the January Board meeting is, by that time, we will have had full access to a detailed 2021 budget. Our Board will be able to look at that and decide in view of that budget, looking ahead, what makes the most sense.
We’re clearly very cognizant of our debt-to-EBITDA ratio. We want to maintain a strong balance sheet. We’re very happy we can self-fund all of our expansion CapEx and the dividend. And we want two things for certain. We want adequate coverage of that dividend. And we want to make damn certain that once we do a dividend increase, that dividend increase is permanent, and that we’re not retracting that at some later date.
So those are the factors that will go into it. And right now, this is a very complicated world. It’s unprecedented, it’s unpredictable. And we’ll just see where we get by next January. We should know a lot more about that time.
Understood. Thank you.
Up next is Pearce Hammond with Simmons Energy. Your line is open.
Good afternoon, and thanks for taking my questions. My first question is, what are the key final milestones to bring the Permian Highway Pipeline online in early 2021?
Yes. So it’s really – it’s the construction, which, as I said, is well in progress. There is an endangered species Migratory Bird window that reopens for our construction. So we have one of our spreads. We’re standing at, like 87% cleared. And we’re kind of standing by until we get to August 1, and we’re free to clear the remainder. And we should be able to do that based on our experience today. We should be able to do that effectively and with adequate mitigation of impacts to the oak trees, et cetera.
So that’s one. We’ve got a couple of river crossings to complete. Those are all underway. There is one reroute that we’re doing around a river crossing. And that process is also well underway. And so we think we see a pretty clear line of sight. Now there is litigation around this pipeline.
As we said, again, we’re very encouraged that the Supreme Court stayed the injunction of all Nationwide 12 permits for oil and gas projects, the decision that came out of the Montana Court. That removes – that – it didn’t cause us to stop construction, but it removes a lot of uncertainty around the legal aspects of this, the sustainability of Nationwide Rule 12. And so we’re grateful to see that.
The other thing I would point out in that regard is the Nationwide 12 permit is something we need for certain construction activities. And we have found a number of measures. That’s why I alluded to the team’s work, certain construction measures that will allow us to avoid impacting waters of the U.S. and to reduce the number of crossings of navigable waters that we need to do.
So we’ve taken some steps and some actions on our own in order to strengthen our position. Nationwide Rule 12 is something we need, as I said, for certain construction activities. It’s not what we need to operate. So we’ll get this work done. We believe we’ll get this work done. We’ll be up and running and put it in service for our customers at the end of – or at the very beginning of 2021.
Thanks, Steve, for that comprehensive answer. And then my follow-up is with the Dominion sale of their gas transmission assets to Berkshire Hathaway, do you expect other utilities to do the same as the convergence theme from years ago gets unwound? And do you expect to see some attractive assets potentially for sale because of this trend?
Yes. That’s a – that is hard to no, of course, and we don’t speak for the utilities on what they do with their assets. We were – we viewed the transaction as a nice affirmation from a obviously a smart investor on the underlying value of midstream businesses. And that’s the main takeaway that we took from it.
Hard to project whether there will be assets that come on the market or interest in unwinding the convergence as you called it. But certainly, if the – if assets that meet all of those criteria that we’ve been talking about throughout this call were to come on, we would certainly take a look at them.
The next question comes from Michael Lapides with Goldman Sachs. Your line is open.
Hey, guys, thank you for taking my question. I’ll ask two, and they’re pretty basic. One, any initial thoughts on the FERC’s comments on the indexation process? Obviously, this would impact the refined Products Pipelines business. Just curious for your thoughts after the first put out the initial data.
And then the other thing on the TGP growth project into New York, can you just talk about what permitting is required, especially at the state level, given New York’s not always the easiest place to permit in any – anything?
Okay. Yes. Well, so starting with the FERC adder, so they came out with a proposed for comment and the industry is commenting on it has commented on it of 0.09 versus the adder of 1.23 that we have today. There are a couple of things that we would observe about that.
I mean, one is that they kind of combined in there the impact of the tax allowance. We are a taxpaying entity unlike an MLP as a C-Corp and have been for a while. We would like them to separate that out.
So that we can be more specific about how the index adder should affect us specifically. And there’s some other subtleties too like, the particular composition of companies that they use. They use if you want, the middle 80%, if you will, versus the middle 50%.
We think that there’s some room and we are commenting to get them to consider that adder a little more carefully and at a minimum separate the text component out. So that hopefully, we can take advantage of our current status in that regard.
On the New York expansion, we are – I’m going to ask Tom to comment on any more specifics. But we are serving New York, the facilities that we’re building in – are in New Jersey on land that we’ve acquired. And so we think we have a good situation there in terms of being able to get this project properly permitted.
But, Tom, any other color you want to add there?
Yes. I mean, there’s really nothing unique. And I think the point – the primary point you made is the key one, Steve. And that is this New Jersey and we own the right away. And so there’s really nothing unique there from a permitting perspective that we need to do locally.
Got it. Thank you, guys. Much appreciated.
The next is from Christine Cho with Barclays. Your line is open.
Good evening. Thank you for taking my questions. Can I start with – can you remind us when you don’t have to pay cash taxes until? And in the event, the corporate tax rate does go back up if there is a change in administration, let’s call it, close to the 35% level. Should we think that, that timeline gets accelerated, especially if the CapEx levels continue to trend below your $2 billion to $3 billion target range?
Right. So we are not expecting to be a cash taxpayer until beyond 2026. And what I would say about that, Christine, is refining that further, there’s a lot of moving parts and assumptions that go into that. But from how we look at things right now, we think that, that statement of beyond 2026, we still – we have some cushion in there, even if we were to – so we could absorb I don’t know what tax increase would be, but I mean, we have some capacity, some cushion to be able to absorb a change in tax policy with that guidance. So we’re still saying beyond 2026 and actually, there’s some cushion there.
Okay. And also, if CapEx continues to trend lower?
Yes. We’re doing that with our kind of revised perspective on CapEx.
Okay. Okay. And then I appreciate your comments about like the volume activity on HH. Can you just remind us what would need to be done if you wanted to expand HH pipeline capacity on your system? And how long any of that would take? I feel like in the past, I’ve seen you guys out with open season for incremental capacity. But I just didn’t know if you would actually have to build a pipe or if it could be done with pumping, et cetera?
Yes. You’re right about that and good memory, as always, Christine. We do have an expansion. It is a pump station expansion. So it doesn’t involve overland construction. And we can add, James, I think, it’s like 15. How many…
Oh, I’m sorry, 35 – 35,000 barrels with a pump station expansion.
Oh, and the timeframe?
Kimberly Allen Dang
12 to 18 months.
12 to 18, yes. Thanks, Kim.
The next question is from Shneur Gershuni with UBS. Your line is open.
Hi, just a quick follow-up question. In the event tax rates went up. When we went through the whole 501-G process, it was because tax rates went down. So would there be a scenario where your tariffs would then go up and you’d be able to apply to increase tariffs? I’m just kind of curious if we kind of get a hold of the entire 501-G process that we saw, I guess, two years ago?
Yes, we’d like to be able to get that back. I mean, the way – but the way we operate our pipelines is we operate them on a fairly low-cost of service basis. We do our best to keep our customer satisfied and do our best to stay out of rate cases. So it would be not a common situation certainly for us to find ourselves in a position where we would be filing for a rate increase.
But look, we’ve got regulatory teams, rate-making teams that, that look at those dynamics closely for us. And if the opportunity presented itself, we’d certainly pursue it. But our main approach is, just keep our customers happy. Give them a good quality of service. Give them some flexibility that they want, and try to stay away from Washington.
All right, perfect. Thank you for that. Very good follow-up.
And there are no other questions at this time.
Okay. Thank you, Denise, and thanks to all of you for joining us on the call and have a good evening and stay safe and healthy. Thank you.
Thank you. And that does conclude today’s conference. Thank you for participating. You may disconnect at this time. Speakers allow a moment of silence and standby for your post-conference.