Kinder Morgan Inc - Class P (KMI) — Q4 2016 Earnings Call Transcript

Okay. Thank you, Jay and welcome to our quarterly call. Before we begin, as always, I would like to remind you that today’s earnings release and this call includes forward-looking statements within the meaning of the Private Securities Litigation Reform Act of 1935 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. Before turning to Steve Kean, our CEO and Kim Dang, our CFO for an update on our operational and financial performance, let me just start the call by reiterating our strategy at Kinder Morgan. We’re all about creating value for our shareholders. To accomplish that goal, we’ve worked diligently in 2016 to strengthen our balance sheet, and we did. We also achieved financial performance consistent with the guidance we’ve been giving since our first-quarter call in April 2016. We expect that the strengthening of the balance sheet will continue in 2017. We also expect that when we finish our work on joint ventures and as we work through the backlog, we will be producing cash well in excess of our investment needs. While we have alternatives in using that cash to deliver value to shareholders, our current thinking remains that the best way to deliver that value is through substantially increasing our dividend. We expect to update you on that in the later part of this year when we announce our dividend policy for 2018. Steve?

Ken will provide a detailed overview of our fourth quarter and full-year performance. I will concentrate on three key themes regarding our performance that will impact 2017 and beyond: the initiative to strengthen our balance sheet, progress on our growth projects, and positive signs in the sector. First, we closed the year ahead of our target with a debt to EBITDA ratio of 5.3 times, following several joint ventures and divestitures throughout the year. Our 2017 plans will maintain this progress, including exploring joint ventures or an IPO for the Trans Mountain expansion, both of which are attractive options with strong interest. We will further develop these alternatives this quarter to ensure we choose the one that offers the best value and other critical terms. We believe bringing in other investors for Trans Mountain, which now accounts for roughly half of our backlog, is the best decision for our shareholders and the project itself. We factored in our ending debt metric of 5.4 times for 2017 without considering any additional contributions from interested investors in the project, allowing us some room for improvement as the year progresses. Overall, we surpassed our 2016 goals and aim to exceed our targets for 2017 as well. Second, regarding our projects' progress, our backlog currently stands at $12 billion, down from $13 billion last quarter. We activated nearly $800 million worth of projects in the last quarter and approximately $1.8 billion over the entire year. We accounted for $200 million in project removals this quarter and a total of $4.6 billion removed over the year. These removals were often due to regulatory issues, but primarily we aimed to accelerate our progress by focusing our capital on higher-return projects. We saved $50 million in costs during the last quarter, which aligns with our backlog adjustments. In the quarter, we also made $167 million in new investments, totaling $740 million for the whole year. Many of these decisions stemmed from our strategic evaluation of investments in CO2, which involved eliminating some projects and introducing new ones. To summarize, we refined our backlog to bolster our balance sheet and direct our capital toward the highest-return opportunities, exactly as we outlined. In 2016, we improved our balance sheet, progressed on our projects, identified new high-return endeavors, closed the year with DCF and EBITDA results consistent with our projections since April, covered our dividend and capital expenditure needs without needing to tap capital markets, and we expect to continue this momentum into 2017. It's also notable that we monitored counter-party credit risk this year and haven't experienced a revenue-impacting default since early April. This was a priority for us, and we have managed to maintain this stability throughout the year, despite initial challenges in the first quarter due to bankruptcies among some of our coal customers. Moving on to the future, market recovery is beginning to emerge in the sectors we serve. In natural gas, North American Gas remains the preferred long-term energy source to meet both domestic and growing international energy needs, with growth driven by increased coal demand from power plants; in 2016 gas surpassed coal’s share of power demand for the first time. Additionally, we have a 75% market share in exports to Mexico, and LNG exports are ramping up on the Gulf Coast, with overall production expected to reach a capacity limit of between 8 Bcf and 9 Bcf once current projects are completed. Demand from the Gulf Coast's petrochemical and industrial sectors is promising as well. In the fourth quarter, we saw positive signs, including record-setting days on two of our larger systems. The resurgence of price volatility has been advantageous for our storage business, benefiting both 2016 and 2017. We secured about half a Bcf of new natural gas capacity sign-ups, with the total reaching 8.7 Bcf over the past three years. Although gathered volumes were lower on our system, the resurgence of drilling rigs in the Eagle Ford and Haynesville, along with steady gathering rates in the Bakken, provide optimism for our gas gathering volumes. Notably, our gas business constitutes around 55% of our segment earnings, with gathering and processing accounting for roughly 20% of that figure. In North American crude, we have seen encouraging signs as rig counts increased significantly over the past six months, and U.S. production grew in the last quarter. Producers are successfully reducing their breakeven costs in the Eagle Ford, which faced significant challenges during the downturn. Acreage is transitioning from capital-constrained owners to new entities that we expect will enhance productivity. We anticipate volumes in the Eagle Ford, for both gas and oil, will likely decline in the first half of 2017 before stabilizing and beginning to grow later in the year. Refined products have maintained stability, with pipelines remaining the most cost-effective method for transporting products from refineries to market, and we hold the largest position in refined product pipelines. Moreover, our terminal assets are strategically positioned, with about 80% of our segment earnings attributed to liquids, predominantly from refined products. Specifically, our location in Houston puts us in an excellent position to capitalize on demand and export growth in refined products. Regarding NGLs, even though the NGL processing segment is minor within our network, we expect notable growth as upcoming petrochemical projects reach completion in the next one to two years. Overall, the long-term outlook for North American energy is positive, and our strategic endeavors are well-placed to benefit from this recovery. Lastly, I want to provide updates on our two largest projects, Trans Mountain and Elba. Trans Mountain reached two critical achievements in December of 2016 and January of 2017. On December 2, we received a Certificate of Public Convenience and Necessity from the Canadian government. Recently, British Columbia's Premier Clark confirmed that we have fulfilled her five specified conditions for heavy oil pipelines in B.C. The B.C. government has also issued its environmental order, approving the project under certain conditions. These advancements are crucial for enabling Canadian producers to access global markets and are part of a comprehensive set of announcements from federal and provincial governments designed to address environmental, climate, and First Nations concerns. The expansion is essential as Canadian oil sands production continues to grow, albeit at a slower rate compared to two years ago, while pipeline capacity remains limited. We are confident that most of our shippers desire the capacity they currently hold, with some potentially seeking even more. Other interested customers are available, should capacity become accessible. This project has made significant headway since our last update. Here are our next steps: we’re finalizing our cost estimates for the shippers, which we plan to deliver in early February. Following that, there will be a 30-day review period for the shippers, and we expect to reach a final investment decision by late Q1 or early Q2. During this time, we’ll also be seeking additional investors through either a joint venture or an IPO, as previously mentioned. The next few months will be busy for our largest projects. As for Elba, construction is underway, and we are receiving timely notices to proceed from FERC under the certificate obtained last June. We have a 20-year contract with Shell for this project, which now has both Free Trade Agreement and non-FTA export authorization. We have a solid EPC contract, and we see it as a good candidate for a joint venture that could attract strong investor interest. While we aren't obligated to pursue a joint venture, we believe it is a favorable candidate and are optimistic about finalizing something soon. Now, I’ll hand it over to our Chief Financial Officer and our newest board member, Kim Dang.

Thanks, Steve. Today, we’re declaring a dividend of $0.125 per share, consistent with our budget. I'm going to take you through all the numbers as usual. But I don’t think you’re going to find any surprises in our results. As adjusted EBITDA, GCF, and net debt to adjusted EBITDA are all consistent with the guidance that we have provided since April updated for the SNG transaction. Starting with the preliminary GAAP income statement, you will see that revenues are down and costs of sales have increased, resulting in about a $457 million reduction in gross margins. As I've told you many quarters, we do not believe that changes in revenue, or revenue itself, are a good predictor of our performance. However, when revenues are down, we generally see a reduction in our cost of sales, which more than offsets the reduction in revenues as we have some businesses where revenues and expense fluctuate with commodity prices, but margin generally does not. That did not hold true this quarter, so let me explain. Both revenues and cost of sales are impacted by non-cash, non-recurring accounting entries, which we call certain items. Certain items contributed $237 million to the quarter-over-quarter gross margin reduction, with the largest being an approximately $200 million in revenue that we recorded in the fourth quarter of 2015 related to a pipeline contract buyout. Adjusting for these certain items, gross margin would have been down $220 million. The largest contributor to this decrease is the sale of 50% interest in SNG. As a result of the sale, we no longer consolidate SNG's revenues or cost of sales. But it's fair to report our 50% interest in net income further down the income statement as equity earnings. Keep in mind also that SNG did not have significant cost of sales. The impact of deconsolidated SNG was approximately a $134 million reduction in gross margin for the quarter, leaving a reduction in gross margin of about $86 million, which I think is more consistent with how we would view our results. The main drivers of the remaining gross margin reduction are consistent with those that I'll cover for you on DCF in a moment. Net income available for common shareholders in the quarter was $170 million or $0.08 per share versus a loss of $721 million or a loss per share of $0.32 in the fourth quarter of the prior year, resulting in an increase of $891 million or $0.40 a share. Now, before everyone celebrates a 125% increase in our earnings, let me give you the numbers adjusted for certain items. Net income available to common shareholders before certain items was $410 million versus the adjusted number in 2015 of $463 million, down $53 million or 11%. EPS before certain items was $0.18, down $0.03 versus the fourth quarter of 2016. Certain items in the fourth quarter of this year were an expense of $239 million. The largest of which was a $250 million non-cash impairment of our investment in Ruby. Although the majority of Ruby's capacity is contracted until 2021, the impairment was driven by delay and expected West Coast natural gas demand to be on that timeframe. Certain items in 2015 were a net expense of $1.2 billion, also driven primarily by non-cash impairments. Let's turn to the second page of financials now, which shows our DCF for the quarter and year-to-date, and is reconciled to our GAAP numbers in the earnings release. DCF is the primary financial measure on which management judges its performance. As I mentioned in my opening remarks, our 2016 performance is consistent with the guidance provided since April, updated for the SNG transaction. DCF and adjusted EBITDA are approximately 4% below our budget, and net debt to adjusted EBITDA is 5.3 times. We generated total DCF for the quarter of $1.147 billion versus $1.233 billion for the comparable period in 2015, down $86 million or 7%. There are a lot of moving parts, but if you want a very simple explanation, the segments are down $123 million, primarily due to reduction in our natural gas and CO2 segments as a result of the 50% SNG sale and lower realized oil prices. Interest expense was reduced by $41 million versus the fourth quarter of the prior year, as we used the proceeds from the SNG transaction to repay debt. These two items, the change in the segment and the change in interest expense, net to a change of $82 million or approximately 95% of the DCF change. DCF per share of $0.51 versus $0.55 for the fourth quarter of the prior year, down $0.04. Almost all of which is associated with the DCF earnings I just walked you through. $0.51 in DCF per share results in $867 million of excess distributable cash flow above our $0.125 dividend for the quarter. For the full year, DCF per share was $2.2, resulting in almost $3.4 billion excess distributable cash flow above our dividend. Now, let me give you a little more detail on the segment performance. The natural gas segment is down $114 million, largely due to the sale of SNG. Increased contribution from TGP expansion projects placed in service largely offsets lower midstream volumes. CO2 decreased by approximately $54 million due to lower oil prices and approximately 8% lower production. As Steve mentioned, the lower production was partially driven by project deferrals and reallocating capital to higher return projects with slower production response. The Terminals segment was up $39 million or 15%, driven by increased contributions from our Jones Act tankers and our joint venture with BP. Products was up 19%, impacted by higher volumes on KMCC and Double H pipes, and favorable performance in our Transmix business. And KMC was down about $5 million due to timing above it. Versus our budget, as I previously mentioned, adjusted EBITDA was about 4% below budget, largely as a result of the partial sale of SNG, lower gas midstream and natural gas volumes in our natural gas segment, full bankruptcy impact, and reduced liquid throughput and ancillaries in our Terminal segment, lower crude and condensate volumes in our products segment. The individual segments ended up very consistent with the guidance we gave you in the prior quarter. DCF was down approximately 4% with the negative variance on adjusted EBITDA somewhat offset by reduced interest and sustaining CapEx. With that, I’ll move to the balance sheet. On the balance sheet, you will see total assets down about $3.8 billion. A huge driver of the reduction in assets was the scale of SNG, and you can see that coming through primarily in the plant, property, and equipment line and the reduction in goodwill. Net debt, we ended the quarter at $38.16 billion. That translates into net debt to adjusted EBITDA of 5.3 times, as I’ve previously mentioned, consistent with the guidance we gave you. For the year, debt is decreased by $3.064 billion and for the quarter we had a reduction in debt of $1.088 billion. And so let me reconcile that for you. In the quarter, $1.088 billion reduction in debt, we had $1.147 billion of DCF. We had about $627 million in expansion CapEx, acquisitions, and contributions to equity investments. We had divestiture proceeds of $77 million, plus $776 million of the SNG divestiture proceeds. We had placed in escrow on September 30th to pay down debt on October 1. So those proceeds were released from escrow. And then we paid a dividend of $279 million. Working capital and other items were a small source of cash. For the year, the reduction in debt of $3.064 billion, DCF was $4.511 billion. Expansion CapEx, acquisitions, and contributions to equity investments were a use of cash of $3.06 billion. Now, that number is a little bit different from the number you saw in the press release and that’s because this is a cash number and the number in the press release is an accrual number. We’ve got divestiture proceeds of $2.94 billion, and the biggest piece of that was SNG. SNG, we got $1.4 billion in cash and then also $1.2 billion that was deconsolidated. The other contributors to divestiture proceeds, we sold our Parkway pipeline for $142 million. We got a promote on Utopia, and then we've got some proceeds on some small terminal sales. Dividends for the year were $1.12 billion, and then working capital and other items was a use of cash of about $210 million. And that's a whole laundry list of things, including the Maple payments that we paid on the debt that we repaid in conjunction with the SNG transaction, timing on distributions from JVs, margin that went out the door, working capital used on AP and AR, offset by positive working capital on property tax. So, with that, I'll turn it back to Rich.

Okay, thank you. And Jay, we're willing to take questions now.

So, congrats on the TMX milestones, I got a quick question here though. So I know, I'm still waiting for FID, and you guys were thinking about what the final cost number will be. But could you just talk a little bit about that in the context of the 6.7 times spill-over with multiple you referred to when talking about the project backlog? And just generally, how I should be thinking about the return on this project?

The return on the project is quite impressive. If you consider our overall backlog multiple being around 6.5 times EBITDA, it’s somewhat better than that. However, it’s important to remember that there is ongoing capital expenditure for this project, which means it doesn't directly correlate to an IRR. Still, it remains an attractive project with strong returns. Regardless of the specific investment for this project, we earn based on that investment once we finalize the costs.

And then could you give a quick update on Utopia, as well? I know the press release referenced progress made on the right of way. But how should I be thinking about that?

So actually this call last quarter we had just gotten an order from one of the courts in Ohio, finding that Utopia did not have eminent domain in that particular jurisdiction. We’ve since had mixed results, meaning that some have found eminent domain rights, common career status, and public utility status in the eminent domain. But we can't wait for all of that to resolve itself. So Ron McClain and his team put together a strategy to go pursue the right of way, notwithstanding whatever the courts decide. And they've made very good progress on that. And so I think the way to think about it is we believe we're going to get it done, and we've acquired a substantial amount of the right of way, and we believe we're going to complete it.

And last one from me. Can you guys talk a little bit more about this small but looks like new JV with EnLink? And what the genesis for this project and strategic venture is?

Yes, so we have a position in the scoop/stack area that came as part of the Hiland acquisition, and some acreage dedications there, commitments there. And we looked for the most, the best, returning opportunity to get that system built out. And essentially because there's additional processing capacity in the area, we were able to come up with a much better project from an NPV standpoint, than if we had laid down pipe and built the brand new processing facility. So it turns out better for shareholders. We utilized some under-utilized capacity that our partner had, and end up with the better results for our customers and shareholders.

I have a couple of quick questions. Following up on the TMX topic, could you discuss what we should expect regarding the potential promote? I remember that Utopia had around a 20% promote, but current trading values for Canadian pipelines seem to be much higher than that. Is there a possibility of seeing a promote that exceeds 20%? I would appreciate any insights you could provide on how this might work.

Well, no. We specifically have not given specific guidance on that, because frankly we don’t want to set a marker out there. We want to run a process and test that value. But we don’t want potential counter parties to see a number out there that they feel like if I hit that then I’m done. And so, we think it’s best for our shareholders, best for the project overall, if we just run the process. But we can say that the interest has been very strong from potential JV partners, and also strong interest in an IPO as an alternative.

And as a follow-up question, in your prepared remarks, Steve, you talked about green shoots. What I think about the contracted nature of many of your assets in terms of some MBCs and fee-based and so forth. I was wondering if you can talk about if these green shoots do continue, where we can potentially see a positive revision to your EBITDA guidance for 2017?

What might influence our guidance will be discussed in detail during next week's call. One area where we've observed some value that has made a difference is the return of value to our storage assets, which I believe will exceed our 2017 plan. This is a positive development. Additionally, we might see similar potential in the throughput of our products pipeline and at our terminal facilities. Next week, we will provide an insightful look at what we believe are the key drivers for our business in 2017.

And the final follow up and I suspect this is the next week answer as well too. But you put out the return marker of 6.7 times, excluding CO2 projects. I was wondering if you can remind us what the target was for CO2 related projects, and how much of the backlog is represented by CO2 these days.

We have established a minimum unlevered after-tax return of 15% for CO2 projects, and the recently approved projects significantly exceed that threshold. We are currently focused on identifying high-return projects and stress testing them under various oil price scenarios. This minimum return serves as our baseline. The total CO2 in our backlog amounts to $1.4 billion out of the $12 billion total.

Let's explore a few questions related to LNG. Regarding the potential for an Elba joint venture, what metrics will you use to assess its viability? Is it based on a return threshold, a de-leveraging metric, EBITDA, or perhaps a combination of these factors?

Well, the reason for considering a JV on Elba is to address the balance sheet. So we of course take into account what the impact is going to be on our leverage metric. But it's really a function of return. Now, it's the value that we get for someone buying in and participating in the project.

The Southwest Louisiana supply project, is that tied to the Cameron online date, or is that contractual February 18th?

No, it is tied to the first in service on that project.

But it looks like there's the potential you get your part done before them, I guess. And then just very simplistically, on CO2 projects north of 15% return, and I assume that that's for crude pricing, correct?

Yes, we look at it on a strip, but then we also look at it with the sensitivity off of that strip to make sure that to look at what an NPV '15 breakeven price would need to be. So, we look at the pricing in a couple of different ways.

Okay, that’s all. Thanks…

There's always the potential if there's downside risk in the pricing where we still have a nice return in economic project works.

It's been an enabler that Trump is supportive of Keystone. I'm just wondering what impact, if any, that has on the potential of Trans Mountain shippers, and maybe they're willing just to pay?

So, we don't think that it has much impact. We think that there're some significant advances to the Trans Mountain project. Of course it is under contract with shippers. And it is these projects that we believe is in the lead, and gets people to tide-water where they can access a world market price. And so there's a strong interest in it, and that strong interest has continued after Trump's election and after his comments on Keystone.

And also on Trans Mountain, the Canadian dollar has fallen pretty significantly since you've started the Trans Mountain process. I think that’s also true. But I just want to make sure that both the CapEx and the tariffs are in Canadian dollars, so there’s not really any forex impact either way?

So, we’ve carried the CapEx in our backlog in U.S. dollars. But yes, the tariff is in Canadian dollars, and the CapEx that gets communicated to our customers will be in Canadian dollars as well.

So just in terms of return, there is not really forex exposure?

No.

Okay, thank you. And then…

Most of the spend is in Canadian dollars.

Right.

Okay, thank you. And then last one is, you noted that figures in the gas volumes were down because of Texas intrastate due to declining Eagle Ford. I am just wondering how much room there is for Permian gas growth to offset this, or if you’re kind of near your max for Permian gas lift?

On the Intrastate?

Yes.

Yes. We are fairly full of intrastate rate system of what we can see from the Permian. As Steve said earlier, I think we are approaching a bottom in the Eagle Ford volumes to expect those to flatten out towards the middle of the year and more likely with oil later in 2017.

And Permian volume, I mean the intrastate aside for a moment, Permian volume growth does tend to drive good value on our EPNG assets.

A couple of quick questions. The first, within Products Pipes, on that segment, exiting Q4 and I realize, we will get more details on this next Wednesday, but exiting Q4, were you guys more optimistic about the incremental uplift on NGL volumes and margins or possibly what KMCC and Double H could do as capacity utilization improves into the first quarter?

Ron, do you want to…

Well, what we are seeing recently is strong volumes in Q4 and in January and we expect that to fall off a little bit, but I think we expect KMCC volumes to return as Tom said, rest of the year, and should drill.

I am just trying to get a sense of the expected pull-through and kind of how that segment ultimately shakes up for year-over-year performance thinking about the quarters, but I know we are getting to that on Wednesday, so we can defer till then. If I could just switch quickly over to CO2, within that 8% lower reported production estimate or actual, outside of those project deferrals and that reallocation of capital, the projects, production response that you guys discussed, was there anything from a legacy organic field decline perspective that caught your attention, maybe pattern conformance or anything that we should be looking out for?

I think, look, there is a natural decline associated with those fields and we continue to work for ways to offset those declines, and historically we have been able to do that. And we are looking at and we will go over this next week as well looking for some opportunities to flatten out again or potentially even grow that production with some new opportunities in those fields. I guess, I wouldn’t say that there was anything unexpected in what we saw in our results there.

Okay. And then, last question from me. Kim, just a quick housekeeping one on that $215 million impairment on the equity investment in Ruby, recognizing obviously the non-cash nature of it, can you quantify for us maybe the magnitude and timing shift of that West Coast natural gas demand that drove the impairment to be recognized? I am just trying to get a sense of the drivers behind it.

Sure. It probably moved out three to four years.

How are you guys thinking about some of the legal challenges to the Trans Mountain project, just your thoughts there on where you expect to be challenged, how you are feeling about the legal case and over what timeline we should expect some of these challenges to play out?

Okay. Yes, several parts to that answer. So, one is legal challenges have already been filed. Most of the legal challenges to date related to the project have resulted positively for the project continuing. And a big part of that, I think, is due to the fact that the Canadian government provincially and federally has taken a long time, a lot of care, and gathered a lot of information, and attached a lot of conditions and engaged in a lot of consultation to make the orders that they ultimately issued very strong and hard to overturn on appeal. So, it was a lot of good work building the record and listening to, responding to, and putting in place the appropriate conditions to deal with the legitimate concerns that have been raised. Our view of the appeals, and we’ll be filling our responses today or shortly to those that have already been filled is that they are unlikely to succeed on the merits on appeal and that given the much higher standard for something like an injunction for example, they are unlikely to succeed in getting something that actually stops the project. So, I think the credit goes to our team up there, but certainly the government engaging in such a thorough process ultimately makes those orders very strong.

Great. So, you sound pretty confident there. One follow-up, just any more color on the merits when you are considering a JV partner for the project relative to an IPO of the Canadian business, just how you are weighing what some of the positives and negatives would be of each option? And then also how do we think about the timing of when you would look to do a sell down, is it soon after FID or would you wait a little while on this?

Let's start with the timing. We would anticipate doing something with the FID or shortly thereafter. And as far as timing is concerned, I think that that will give you an idea. There is a lot of pros and cons between the JVs and IPO; and we can get into more detail perhaps next week on that. But I think the real salient point is that both are very good potential alternatives. And we think we're going to have the ability to make a selection between the good and the better. So, we think that it's going to be a decision that benefits our shareholders for the long run.

Quick question, once you are done with the balance sheet repair, are you still planning on financing half of ongoing growth CapEx that is separate from JV partners in the debt markets and the rest sub operating cash flow?

I believe that's a solid overview. We will assess the situation as we move ahead. Our preference is to strengthen our balance sheet, and we feel we are getting closer to achieving that. We expect to see positive outcomes from joint ventures throughout this year that will contribute to this goal. Once we reach that point, we will maintain our balance sheet and manage the debt to EBITDA ratio without needing to issue new equity unless we choose to. We plan to use excess funds beyond our dividend payouts to finance the equity portion of our capital expenditures. Although we are evaluating all potential projects for the future, the Trans Mountain project is an example of a significant initiative that we're pursuing. Once we navigate through the challenging stages, we anticipate that our capital expenditure levels will decrease. We will continue to seek growth opportunities, but our capital expenditures will be lower.

On that note, it didn’t sound like there was maybe much added in terms of new project origination in the fourth quarter. How comfortable are you given the positive signs already discussed that maybe would just start to move over the next couple of years back towards that $2 billion to $3 billion in annual project origination?

Yes, and that could happen. I mean, like we’ve always said, we will continue to look for good higher returning projects. We believe that is the best way to deliver values who invested in good, high returning projects. But I think our current view is that we are likely to generate cash as these projects come on. We are likely to generate cash in excess of those equity portion of those investment opportunities. And in those circumstances, we believe the best way to return value to shareholders is within an increasing dividend.

Understood, yes. If you are only having to cover half of that, your operating cash, so you definitely have a lot free.

That’s right.

So, last question, any update, I suppose that you might touch on some specifics on the segments next week but any update about prospects for contracting remaining unhedged Jones Act tankers?

Yes. Currently, I believe everything that’s on the water is under charter.

11 of the 16 are under long-term contracts. That have some exposure, the total exposure for next year to our budget is $2.9 million or 0.2% of our total budget for 2017.

0.29% for the total budget.

I understand. So, regarding the exposure, what is yet to be delivered that is meaningful?

Well, in sum, our existing charter terminations as well as ships roll off of charter. And look, I think we’ve been very active in re-chartering vessels as charter expirations come up, and I think have been pretty successful in what is no doubt a down market and making sure that our ships have charters even if it’s at a reduced rate. And that will continue to be our goal through the year. I think also, we would hope that we and the other large vessel companies would be able to take a little business from the ATB market and I think we are beginning to see; we are competing for that business as well. We’re starting to see that.

I wanted to circle back a question on Ruby. So, there was a write down on Ruby this quarter. I think if I’m not mistaken, MEP was written down last quarter. Are there any expectations of additional write downs on a going forward basis perhaps?

I think carrying value on Fayetteville is like a $100 million. So, it’s got a relatively low carrying value. We have to assess our assets every quarter and to make sure that we’re carrying them at the right value. I don’t see significant risk of impairments going forward but we will have to make that assessment based on market conditions at the end of every quarter.

Got it. And the last question for me, most of my questions have been asked. What was the CO2 CapEx spend this past quarter?

I don’t think we have a quarterly number for you.

Just want to go back to TMX here and just want to clarify, do you see any situation where you would go to loan with this project or at this point you feel you have a lot of certainty with regards to the JV or IPO options, if you’re pretty certain that that would happen at this point?

It’s the latter, it’s the latter. I mean, that’s an option to us but I’d say, as I said at the very beginning, we think that syndicating this is the right answer overall. And we think that the interest level is high enough and strong enough for whichever route that we take that we’re going to be successful in that syndication.

Great, thanks. And then, could you just walk us through what you think might be the optimal amount to monetize at this point and how you kind of think about gives and takes there?

It varies so much depending on the structure that’s pursued and it’s a broad enough range that I can’t really give you a specific answer there.

Okay, great. And then just a housekeeping one there, what was the last number for the CapEx spend there; how current is that?

We have been carrying it at 5.4. When you see it in our backlog, it’s sitting there at U.S. $5.4, and if you convert that at the current exchange rate, it’s about U.S. $6.

And when was that last updated?

We’ve carried that same number for a while and what’s happened is just by kind of happenstance the FX rates have changed; it stayed reasonably closely in line, so we haven’t updated U.S dollar number since the beginning of the project for our U.S. investors. But it was done at a time when the loonie and the dollar were at par.

Okay, not material cost or anything that’s changed much. And then just one last and as far as shipper contracts, is everything set there, is there any deadlines where things go past certain time frames that that could be changed or anything like that?

No, to be clear on the earlier question, costs have changed, costs have changed and what we’re in the process of doing now, is communicating that final cost estimate to shippers, which we expect to have prepared and delivered to them in early February. That’s the current thinking. And then, there is a 30-day period of shipper review where they examine the underlying cost because once that cost is set, that is the investment; that is what we earn on. So, there'll be a review process over the 30 subsequent days after we give them the final cost estimate.

Great, and all the shippers are fully committed; are there any kind of drop-dead dates where contracts should reopen or anything like that?

If the costs exceed a certain level, then there is an opportunity for customers to reconsider their position and turn their capacity back. But as I said at the beginning, there's enough interest from current shippers potentially in expanding their position as well as from other potential customers who are not currently shippers wanting to come in, that we remain very confident that capacity gets placed at the level it is today.

That makes a lot of sense, and I would expect there to be very high demand. Also, I have one last question regarding the ongoing industry consolidation. It seems smaller players are starting to consolidate, and that trend is picking up speed. I'm curious how you view Kinder Morgan's role in that context moving forward and if there is an opportunity to accelerate deleveraging through an all-equity deal.

We continue to look in that market, continue to look for those opportunities. We do, and implied in your question, we're looking at DCF accretion but we are also looking at leverage improvement as well. That narrows the field frankly, that narrows the field, but we continue to look actively in that market for opportunities.

John, how are you doing?

Doing good, Rich, and congrats on the approvals on Trans Mountain.

Thank you. We think they're very significant.

Just a couple of clarifications, can you share with us or remind us how much has been spent on Trans Mountain development to date? And then in terms of the cost overruns or if there's cost overruns, it sounds like the way things are structured with the shippers that they would in terms of what they would pay on the shipping cost, they in fact bear a portion or all or maybe if you can share if there's cost overruns how that works?

So, starting with the first question, it's roughly CAD$600 million gross and so there's also, remember, we have part of our development costs are covered; it's over a 10-year period but they're covered under our what we call our firm 50 dock charges. So, years ago, we signed up shippers to give them access to firms based across our existing Westridge dock and those proceeds go toward the deferring of development costs and over the life of that, those charges is about CAD$250 to CAD$255 million. So, you have to net that off and those don't all come in the same time that we're doing development. As I said some of it can come over time but it's CAD$600 million gross. And then that’s a firm 50 off of that. On how the cost structure works, once the final cost estimate is delivered and we proceed toward project execution, there are two categories of costs. There's a set of uncapped costs, and those are costs where if there is an overrun, then that overrun would be to the projects accounts. Then there is a set of uncapped costs. And those overruns, if there are any, those overruns would be added to the investments in the project, and we would earn on those. So, it’s not just flow through; it becomes part of the investment and we earn on it. And those tend to be, as you’d expect, the most predictable elements of the build. They apply to things like steel costs, which are not going to be an issue, aboriginal consultation, ultimate consultation and accommodation costs and two particular parts of the build that are likely to be difficult and unpredictable when we’re forecasting it. Having said all that, what we’re delivering to shippers will be P95. So, we feel like with all the work that’s been done, we have narrowed the estimates, both on capped and uncapped costs to a very, very narrow level. And at a 95% probability, meaning a 95% probability that would come in at or under the number that we deliver. So, we think we’ve done a lot of work to make sure we have our arms around what the cost risks are there, and are taking them into account in the final cost estimates.

Okay. And just to help about what percentage is capped and what percent is uncapped?

I don’t have that information right now; most of it will be capped. However, I don’t have the exact percentage of the uncapped portion. The majority of the costs will indeed fall under the capped category.

Okay. That’s really helpful. So, it sounds like there is some kind of a sharing on the uncapped and then the capped, that’s basically predictable costs that are locked in. So that’s the idea, correct?

Well, yes, and on the uncapped, to be clear on that too, there is a possibility since these are the more unpredictable category of costs that they come in lower. And if they come in lower, the shippers get the benefit of that lower cost as well.

Just rolls into the tolls, John. If it comes in higher on the uncapped portion, the tolls increase; it comes in lower, then tolls decrease.

Okay. That makes sense. And then, just on the schedule, I think the last schedule you shared with us was fourth quarter 2019 or end of 2019 start-up. Is that factoring in any expected litigation, how should we think about that?

We still view the project and services the end of 2019; so, really think of 2020 as being when the revenue starts to arrive. And the schedule we’re building takes into account what we think we’re going to encounter include the need to deal with litigation as obviously.

Okay, great. And then, the other thing I just wanted to touch on briefly was just every now and again, we hear these rumors flying around about the sale of the KMI E&P business. You had some discussion last year; it sounds like we hearing some rumors fly again. We’ve always thought about it that you would sell down, if it could be effectively balance sheet accretive, otherwise you wouldn’t do it. Any other comments you could share with us in that regard?

We don't discuss transaction activities like that. However, I can share that we continue to view that business favorably, as we have discussed in previous quarters and conferences. We achieve good returns in that area and have developed specific expertise, particularly in the EOR, midstream, and transportation aspects. We've moved forward into EOR because we possess a scarce and essential resource, which is CO2, vital for extracting certain oil barrels from the ground, and we've learned how to leverage that. We're pleased to maintain this business. As a shareholder-focused company, we are open to any opportunities that could enhance shareholder value, including the potential sale of an asset, as evidenced by our actions this year. Nonetheless, we genuinely value this business and aren't compelled to take action regarding it. Additionally, any considerations around a disposition, along with the points you raised, include the possibility that it could be DCF dilutive. We also weigh whether the multiple uplift on remaining cash flows would justify the transaction, ensuring that our investors would be better positioned the following day. This is a significant constraint in our decision-making process.

Thanks a lot. A couple of segment questions. One is back on CO2, is the 8% decline something that is given your current spending and projects timing, is that 8% something we should assume for the next few quarters or is it something that accelerates or even declines?

The way we invest in that business is not based on a decline rate or offsetting a decline rate or holding a decline rate, we’re reversing it. It’s really based on individual projects and whether the incremental oil that’s produced for that capital is going to pay us a handsome enough return for us to make that investment. So, that’s the way we do it. And we don’t plan for it, can’t forecast for you a targeted decline rate or a targeted level of production. We address the project opportunities as they come forward and fund the ones that make economic sense.

And that being said, we will go through the 2017 budget next week, and I think you will see in there that the 2017 production is relatively flat versus 2016. And then to answer the question that was asked earlier about the CapEx for the fourth quarter on CO2, it was $73 million.

Thanks for that. The other question I had left was on the Natural Gas Pipeline segment, just trying to understand a lot of moving parts there. But if you took SNG out of both years or both fourth quarters, what would be the comparison?

If you take SNG out of both fourth quarters?

My impression is it’s partly in 2015 but below somewhere in 2016. I just wanted to clarify the change, the rate of change there.

The underlying business in SNG is relatively flat.

Okay.

The underlying business of SNG is clear. Year-to-date, I believe the sale has not significantly impacted the segment. It's important to note the distinction between the segment and our plan of slightly over $100 million. For the Company, the overall impact is much smaller because certain general and administrative expenses are eliminated, and there are reductions in sustaining capital.

Interest.

Most of my questions have been asked, but I have one clarification. When examining the Natural Gas Pipeline segment, it appears that TGP and NGPL experienced a good year-over-year increase while other pipelines were relatively unchanged. Could you discuss the type of increase you're observing in NGPL and TGP in terms of flows or cash contributions?

Yes, I believe that TGP is largely driven by projects. Looking at the fundamental prospects for those systems, TGP continues to increase in value. The revival of growth in the Marcellus and Utica regions will further enhance that. It is also benefiting from the expansion of market demand in Mexico, the growth of LNG markets, and the power sector, where it has recorded impressive data this year. Similarly, SNG is performing very well, and NGPL is also gaining from increased volumes coming in from REX, particularly from REX West, which is again tied to the Marcellus-Utica region, along with support from Sabine Pass at the lower end of the system and some additional power demand and growth in Mexico. Overall, I see all three of those systems performing well and supported by strong underlying fundamentals.

Any update on re-contracting for some of the contracts rolling off on NGPL?

Contracts going off on NGPL, generally the re-contracting is done…

I mean some of our bigger customers who actually have long-term commitments as long as 10 years, but the regular tenure on some of the more traditional LAC customers are every three years and we still think that will add better rates than in some instances than we’ve seen in the past. And there seems a bigger interest in the projects that we're working on NGPL as well. So, I think the prospects are very good for all the reasons that Steve just mentioned as far as the drivers.

Okay, Thank you very much. We appreciate you all sticking with us for a pretty long call, and have a good evening.