Kinder Morgan Inc - Class P (KMI) — Q1 2016 Earnings Call Transcript

Okay, thank you, Shaun, and welcome to the KMI first quarter investor call. Before we begin, I would like to remind you that today’s earnings release 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. We encourage you to read our full disclosure 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 a list of risk factors that may cause actual results to differ materially from those in such forward-looking statements. I’ll start the call and before I turn it over to our CEO, Steve Kean, and our CFO, Kim Dang, I’d like to give you a quick overview of our strategy at KMI. The first point I would make is that this quarter’s results again demonstrate that we remain a strong generator of cash even in these chaotic times for the energy sector. Second, as we’ve said previously and at our meeting in January, we do not anticipate any requirement to access the equity markets for the foreseeable future. We also do not see any requirement to access the debt markets for the foreseeable future, except for rollovers in years subsequent to 2016. We’ve again reduced our expansion CapEx, Steve will take you through that, for 2016 and we expect that trend to continue in subsequent years through both high-grading our projects and entering into selective joint ventures. We expect to fund the necessary CapEx out of our cash flow and continue to improve our debt to EBITDA ratio, thereby preserving and strengthening our investment-grade balance sheet. As our cash flow achieves those objectives, funding our CapEx and strengthening our balance sheet, we will obviously have excess cash which we will then use to either raise our dividend, purchase our shares, or for new projects and/or acquisitions, but only if they are solidly accretive to our distributable cash flow per share. And with that, I’ll turn it over to Steve.

Okay, thanks Rich. I’m going to hit on three topics before giving you some segment highlights for the quarter. First, an update to our capital projects and our expected growth spend for 2016, an update on our outlook for the balance of 2016 and some thoughts on our counterparty credit risk. With respect to the capital update, we announced today a reduction in our project backlog of $4.1 billion, so from $18.2 billion down to $14.1 billion. The two biggest adjustments are the removal of the Palmetto Pipeline project, which is a reduction of $550 million and the market portion of the NED project, which is a reduction of $3.1 billion. With respect to NED, we worked very hard; this is our Northeast Direct project, that would have served the New England market. We worked very hard to get customer commitments on the project. And while many of our LDC customers did sign up, we did not receive enough contractual commitments from electric customers to make the project viable. So we will fulfill our obligation to consult with our customers over the next 30 days or so, but this project is not economic, so we’re removing it from the backlog. In both cases, NED and Palmetto, based on all the facts, we believe this is the right outcome for our investors. To be specific, the return on the NED project at the level of commitments that we have would be less than 6% unlevered after tax. That’s clearly not viable and we are far better off having that cash available for other uses, whether that’s continued and even accelerated deleveraging, other investment opportunities or returning value to shareholders. We value our New England customers and continue to believe along with many others that additional capacity is needed in the region, but we’ll have to look for other ways to serve some part of those needs. We didn’t get there on this one and the action we’re taking is undeniably the right call for our investors. On the Palmetto pipeline, essentially the Georgia legislature prevented us from getting eminent domain and also prevented us from getting other state permits. We were making good progress with land acquisition even without eminent domain, but we needed other permits which Georgia has now put a moratorium on. We needed environmental permits, for example, which they’ve now put a moratorium on until mid-2017. So as a result, we are not moving forward with Palmetto. We had some other small adjustments to the backlog, including putting about $160 million worth of projects in service during the quarter. We had some cost changes which netted to a reduction of $254 million in the overall backlog and we had some other scope additions and removals which essentially offset each other. Looking at the bigger picture on our capital project spend, we continue to high-grade our capital investments to ensure that we’re securing our investment grade credit metrics and maximizing the returns we get for the capital that we do deploy. We’re aiming to reduce spend, improve returns, and selectively joint venture projects where that makes sense. We’ve reduced our expected 2016 spend by an additional $400 million to $2.9 billion. So that compares to the $3.3 billion that we projected in January for 2016, which in turn was $900 million down from the $4.2 billion that we projected in our preliminary 2016 guidance, which we sent out last December. So we’ve continued to work through our backlog and high-grade where we’re spending our capital. With respect to joint ventures, we’d be pursuing these where they made sense that is where we could share the capital spending obligation on a particular project with a third party, get paid a reasonable value for having originated the opportunity, et cetera. But the summary is that the process is going well and we currently expect to achieve the results that we built into our plan. We’re also taking care to not be dependent on any one transaction. These processes can be unpredictable and we will be in a position to back away from a given transaction if acceptable value does not materialize. Overall, as we complete projects and further high grade the backlog, we will free up cash that we can use to reduce debt, return cash to investors in the form of buybacks and dividends or invest in attractive projects or acquisitions or some combination of those. Now for the 2016 outlook update, we have looked at the potential impacts for the remainder of 2016 due to continued weakness in the sector. We now estimate on a full-year basis for 2016 a negative impact of about 3% to the EBITDA that we showed in January. But because of our ongoing efforts to high grade our capital spend and to pursue the joint ventures where it makes sense, we expect to meet our investment grade credit metrics, notwithstanding the 3% reduction. That 3% EBITDA reduction translates into a 4% reduction in DCF. As the year goes on, we will try to mitigate that negative, but we are not assuming in this outlook any dramatic turnaround for our producer customers by the end of the year as some analysts have predicted. Now, we’re not happy about any negative to plan, but I think when you put this in the context of the dramatic production declines particularly in the Eagle Ford, which is down 28% on oil from its peak and 15% on gas, and credit weaknesses, our business is really diversified and insulated from the full brunt of the weakness in the producing sector. So here are the two main contributors. A little under half of the deterioration is attributable to lower Eagle Ford volumes and those flow through both our midstream group in the gas business unit and also in our products group. And again this is all comparing to our original outlook, so this is not a year over year look. This is versus our January outlook that we presented at the conference. So a little over half attributable to the Eagle Ford; another 20% is attributable to the coal customer bankruptcies. So there are a lot of other pieces and Kim will take you through some additional details, but those are the two big chunks contributing to the degradation in the forecast. While the current year outlook for North American energy production is experiencing weakness, we’re still bullish on the longer term. We believe that we’ll continue to see more of our North American energy needs met by North American energy production that will grow our exports; we’ve already been growing refined products and natural gas to Mexico. I think we’ll continue to see growth in natural gas and natural gas liquids exports. And those long-term trends are good for North American energy midstream companies like Kinder Morgan. Okay, the third general topic is counterparty credit. We’ve been monitoring counterparty credit very closely, but beyond monitoring, we’ve been taking action, have been calling on collateral, putting other credit support arrangements in place. A few points about our particular circumstances. Given our diverse business mix, we’ve got a very broad and diverse customer base. We’ve got producer customers, of course, but we also have integrated energy companies, gas and electric utilities and industrial users of our services. We’re not exposed to any single sector, commodity or service. That diversifies our exposure, which reduces our risk. Our top 25 customers constitute 44% of our revenue. And of that revenue, 85% is investment grade. Of our total revenue, about 75% is investment grade or has substantial credit support, and 86% is rated B or better. In our business, real exposure is more complicated than simply looking at our customers’ rating. In many cases, the rights our customers hold are valuable to third parties or essential to the revenue-generating activities of those customers and therefore will be needed on an ongoing basis by the customer or, in the worst case, the debtor in possession in bankruptcy or a subsequent purchaser. We analyze all of those factors and mitigation to get to our credit concern list. Our identified credit concern list amounts to about 5% of revenue and about half of that is mitigated by credit support or the underlying resale value of the capacity that the customers hold. And those numbers, that 5% and that half of five percent include Peabody, the Peabody bankruptcy which we’re now reflecting, so the going forward number is less than that. Looking at the first quarter 2016 to Q1 of 2015, the overall summary is this. On an earnings before DD&A and certain items basis, three of our five business units grew year over year. Gas was up 4%; products pipelines were up 17%; terminals were up 2%; Kinder Morgan Canada would have been up year over year but for the effect of a weakening Canadian dollar; and CO2 was down 21% as a result of lower commodity prices and some lower production. On natural gas pipelines, we had very strong performance on TGP and the contributions from our Highland midstream acquisition. So we split the Highland acquisition between our midstream business unit in gas and our products pipelines for the Double H pipeline. Contributions from really strong performance on TGP and the contribution from our Highland midstream acquisition that we made in the first quarter of last year and those two things more than offset weakness in our other midstream assets and in our western pipelines. The midstream weakness is largely gathering and processing in the Eagle Ford, and on a year-over-year basis, gathering in the Haynesville. Looking at the bigger picture on our capital project spend, we continue to high-grade our capital investments to ensure that we’re securing our investment-grade credit metrics and maximizing the returns we get for the capital that we do deploy. We’re aiming to reduce spend, improve returns, and selectively joint venture projects where that makes sense. We’ve reduced our expected 2016 spend by an additional $400 million to $2.9 billion. So that compares to the $3.3 billion that we projected in January for 2016, which in turn was $900 million down from the $4.2 billion that we projected in our preliminary 2016 guidance, which we sent out last December. So we’ve continued to work through our backlog and high-grade where we’re spending our capital. With respect to joint ventures, as we discussed at the January conference, we’d be pursuing these where they made sense, that is where we could share the capital spending obligation on a particular project with a third party, get paid a reasonable value for having originated the opportunity, et cetera. The process is going well and we currently expect to achieve the results that we built into our plan. We’re also taking care to not be dependent on any one transaction. Overall, as we complete projects and further high-grade the backlog, as Rich mentioned, we will free up cash that we can use to reduce debt, return cash to investors in the form of buybacks and dividends or invest in attractive projects or acquisitions or some combination of those. Now for the 2016 outlook update, we have looked at the potential impacts for the remainder of 2016 due to continued weakness in the sector. We now estimate on a full-year basis for 2016 a negative impact of about 3% to the EBITDA that we showed in January. But because of our ongoing efforts to high-grade our capital spend and to pursue the joint ventures where it makes sense, we expect to meet our investment grade credit metrics, notwithstanding the 3% reduction. That 3% EBITDA reduction translates into a 4% reduction in DCF. As the year goes on, we will try to mitigate that negative, but we are not assuming in this outlook any dramatic turnaround for our producer customers by the end of the year as some analysts have predicted. Now, we’re not happy about any negative to plan, but I think when you put this in the context of the dramatic production declines particularly in the Eagle Ford, which is down 28% on oil from its peak and 15% on gas, our business is really diversified and insulated from the full brunt of the weakness in the producing sector. So here are the two main contributors. A little under half of the deterioration is attributable to lower Eagle Ford volumes and those flow through both our midstream group in the gas business unit and also in our products group. Another 20% is attributable to the coal customer bankruptcies. So there are a lot of other pieces and Kim will take you through some additional details, but those are the two big chunks contributing to the degradation in the forecast. So while the current year outlook for North American energy production is experiencing weakness, we’re still bullish on the longer term.

Okay, thanks, Steve. Today, we’re declaring a dividend of $0.125 per share. That’s consistent with our budget and the guidance we gave you in December of last year. But most importantly, we generated $954 million of DCF in excess of our dividend, which as Steve and Rich pointed out insulates us from the challenging capital markets and significantly enhances our credit profile. Let me explain what I mean when we say significantly enhances our credit profile. If you compare our coverage ratio and that’s DCF divided by the dividend, in the first quarter of last year which was 1.2 times versus the 4.4 times in the first quarter of this year, we have significantly more retained cash flow, approximately $750 million and therefore we have no capital markets risk to getting equity raised. In addition, our previous funding policy was to fund our expansion CapEx 50% equity and 50% debt. Now, we’re using 100% retained cash flow and therefore our balance metrics will improve more quickly than under our prior funding model. Before we get to DCF, let me point out a couple of things on a GAAP income statement. You will see that revenues, net income available to common shareholders and earnings per share are down. As I say many quarters, we do not believe that these measures or changes in these measures are necessarily a good predictor of our performance. We have some businesses where revenues and expenses fluctuate with commodity prices, but margin generally does not. In addition, these numbers can be impacted by non-cash nonrecurring accounting issues or what we call certain items. If you look at revenues, revenues are down $402 million or 11%. However, if you strip out the certain items, with the primary certain item impacting revenues being the CO2 and the mark to market on our other hedges, revenues would be down $316 million. When you compare that $316 million to the $359 million reduction in the cost of goods sold, gross margin is actually up. That’s largely because we have some businesses where both revenues and expenses fluctuate with commodity prices. With respect to net income, if you strip out the certain items, net income before certain items was $446 million compared to $445 million for the same period in 2015 or essentially flat. EPS before certain items was $0.18 versus the $0.12 you see on the page for the first quarter of 2016 compared to $0.20 in the first quarter of 2015. The segments were up by $28 million as Steve mentioned or 1%, with the increases in natural gas and products which combined for an increase of $85 million, slightly offsetting the $58 million reduction in CO2, driven largely by lower crude price. DCF per share in the quarter was $0.55 versus $0.58 for the first quarter of last year. DCF per share was down slightly due to the additional shares we issued during 2015 to finance our growth projects and maintain our balance sheet. Therefore, despite an almost 30% decline in commodity prices versus the first quarter of last year, our performance was relatively flat and we believe that this demonstrates the resiliency of our cash flows generated by a large diversified platform of primarily fee-based assets.

I was just wondering if you could walk through the guidance reduction, what the different drivers are for that, just one more time for us that would be helpful.

I’ll start with the two big pieces and then Kim has some additional detail. About just a little under half of it, a little under 50% of the reduction is attributable to lower Eagle Ford volumes than what we had in the plan. So I talked about volumes being up year over year, but versus what we had in the plan, we had lower Eagle Ford volumes. That impact is on our Eagle Ford gathering system, our TK header line and the processing facility. It’s also volumes that we’re entering into our Texas Intrastate system that we expected to be able to move on that system and collect transport fees. The other place where we have exposure to Eagle Ford volumes is in our products pipelines where we have the KMCC pipeline and the splitter. We expected the splitter in our plan to run a little bit above its contract minimums. We have good contracts with good protection there. It’s running at the minimums, which are pretty good. I mean, it’s a pretty high percentage of the capacity of the facility, but we had budgeted a little bit more there. And KMCC, we expect we’re now going to start to see some volumetric decline on that. Another 20% is attributable to the coal company bankruptcy. Those are the two very big pieces.

And then regarding the decision to take NED off now versus later, can you just walk through the timing and the reasoning behind it?

Look, we gave it our all on NED. We pursued customers hard, we pursued approvals hard. In the end, the customer commitments just weren’t there. Now, that makes the project uneconomic not surprisingly and that’s why I wanted to specify the return for you. It’s apparent, it’s objectively apparent that the project is not economically viable at that customer sign-up level. We have one significant prospective customer who determined to put their volume someplace else and that was a significant negative for the project. That’s how we got to that decision in the time we’re talking about now, but I want to underscore again from an investor standpoint, in light of that return, we are a lot better off with that $3.1 billion back in our pockets and being put to some other use. The project wasn’t going to produce the return that would be required to make it viable because, again, the contracts weren’t there. I think if you look through the rest of the backlog, my guess is we’ll find some bits and pieces here and there that will either save some money on or may change the timing a little bit. I still think those are high probability projects though and ones that we want to build out and do and they contribute to our DCF per share growth that we’re aiming to achieve by building it out.

And just to underscore the average, the year one EBITDA multiple on the projects in the backlog excluding CO2, as we said on CO2, we look at the project at the time we enter into, I mean, it’s a forward curve at that time and we target at least a 15% unlevered after tax return. But on the non-CO2 projects, the average year one multiple, EBITDA multiple is 6.7 times.

One last question if I could, just curious how you guys think about growth now with the backlog standing at $14 billion, the size of the entity as it is right now, what type of EBITDA growth do you guys see yourself being able to achieve? Is there anything different than what you guys have communicated historically?

One very simple way to look at it is take the 6.7 multiple off of $14.1 billion and divide that by the number of shares outstanding and you can see what that works out to be. And it’s $0.70, $0.75 per share.

If you exclude the CO2 from the $14.1 billion, you will arrive at approximately $1.8 billion, with nearly $175 million being incremental to 2016.

First question just a follow up on the discussion on CapEx, when I look at it for 2016, you’ve now revised it lower again, which I guess is good in this environment. You also mentioned some improvements on costs, are you able to beat up your contractors a little bit further to improve returns?

It’s a mix of things. We had some spend for NED in there, but we don’t really have construction spend for NED in 2016. That would not have been a huge component of the $3.1 billion and Palmetto was primarily a land acquisition and maybe the start of construction. So it was not just those; we got cost reductions; we had other projects that we moved. We also made some JV assumptions as well.

We have one project, the timing has moved out on.

The cost reductions, is that something that we can see more on a go forward basis?

We have seen some improvement in returns partly because we made scope refinements and other cost reductions that are more market-oriented; it’s costing less to do things now than it did in the more heated environment and we’ve also added customers to some of our expansions. One example I’m thinking of is on our Texas Intrastate. In other words, even within an individual project, we’re trying to march returns up by doing those three things: optimizing scope, reducing cost, and adding revenue. On Trans Mountain, we are engaged actively with the BC government on those. The BC government is also going to be conducting an environmental review under their provincial process. We expect that both of those things will be concluded within the same timeframe of the federal process, maybe not the same day, but within the same general timeframe. We have this project in the backlog and we are aiming for a 2019 completion, end of 2019 completion.

We generated total DCF for the quarter of $1.233 billion versus the $1.242 billion for the comparable period in 2015. Therefore, total DCF was down approximately $9 million, essentially flat between the two periods.

We expect natural gas pipelines to come in approximately 2% below its budget, primarily as a result of lower volumes, mainly in the Eagle Ford. The other factor impacting our natural gas for the full year is the delay on EEC, SNG pipeline expansion project as a result of the FERC certificate being about three months later than we anticipated.

The $28 million increase in the segment was offset by a $39 million increase in our preferred stock dividends. If you remember, we issued preferred stock in the fourth quarter of last year. Now, there are other moving parts, but if you take the $28 million from the segments offset by the $39 million, that gives you a decrease of $11 million versus a decrease in DCF that I mentioned of $9 million.

I wanted to start on the NED project. When you mentioned the commitment level is not enough from the electric customers, was there any single reason that you can point to as kind of the biggest reason for non-commitment?

I’m not sure I want to get into that customer’s particular thinking. I think that the main thing from our standpoint is we needed additional sign up. The processes up there just have not fully formed in a way that will allow the electric generation load that needs firm natural gas infrastructure on a long-term basis to get approved.

And then on the impact to the 2016 outlook, could you touch on why you think those Eagle Ford volumes are lower? Is it lower activity level in the basin or are you seeing lower contribution from existing wells?

It’s really lower activity. The rig count there is 40% below what we were looking at and thinking about in October. That doesn’t mean it can’t come back at some point, there’s oil window, there’s an NGL window and all this is associated production, the gas that’s coming out is associated gas. But I think that takes commodity price recovery for people to come back and start deploying rigs and completing wells.

It’s a nationwide phenomenon. I think we gave figures at the start which you might get again, the decline built in oil. Oil was down 28% from its peak, gas 15%.

I understand the stance on funding CapEx through cash flows, but with the recent strength in the credit markets, is there any reason you don’t consider tapping the debt markets that have about $3 billion you have maturing in 2017?

We’ll continue to watch the market and if we think it makes sense we may do that at some point. But obviously we don’t need to.

I think that we don’t need to, but we have the ability to if it looks advisable.

With regard to this common theme of being focused on return for equity holders, what is the quantitative target on leverage that you’re looking to achieve before you consider enhancing that equity value and also your preference between share buybacks, dividend increases or maybe a balance between both?

We remain consistent with what we said previously that as we promised the rating agencies we will be in the range of 5.5 going down to 5 times debt to EBITDA and we would anticipate achieving the bottom end of that range on a going forward basis. We’ll look at it. If it makes the most sense to buy back shares at that time, we will buy them back. I can tell you if the prices are where it is today, $19, we would buy it back.

From my mind, it makes sense on those removals. But when I’m taking that lower backlog now and thinking about looking longer term towards 2017, do I now have a line of sight on getting to that maybe in 2017 timeframe or am I thinking a little too ahead of myself there?

We’ll just see how everything comes together. But certainly, we’re getting closer to getting to that happy sun meadow where we can afford to make those choices.

And then my next question is, can you just touch on what you guys are seeing on your side in terms of contract negotiations? Are you finding any pushback?

Interestingly, we’re kind of in a net positive right now on the contract renegotiation front. We went through a process in our Highland midstream assets that enabled us to hook up more production out there and that was advantageous to the producers as well as to us. We fixed our fees and took commodity exposure off and the producer wanted that, wanted to have the commodity upside. But the bottom line for us is we improved our position on a 2016 basis and improved our fee recoveries on those renegotiated contracts.

The negative variance on G&A is driven by lower capitalized overhead as a result of the lower expansion capital that Steve mentioned and interest expense is expected to be lower than budget due to lower LIBOR rates.

At this time, Shaun, we will take questions that people may have.