金德摩根 (KMI) 2016 Q3 法說會逐字稿

Thank you for standing by and welcome to the quarterly earnings conference call.

(Operator Instructions)

Today's conference is being recorded. If you have any objections, you may disconnect at this time. Now, I'd like to turn the call over to Mr. Rich Kinder, the Executive Chairman at Kinder Morgan. Sir, you may begin.

Thank you, May, and welcome to the Kinder Morgan third-quarter investor call. As usual, before we begin, 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 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 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 I turn it over to our CEO, Steve Kean, and our CFO, Kim Dang, let me make a couple of brief comments, one, more industrywide in nature, and the other specific to KMI. Let's start with the industrywide thought.

We continue to be bullish on the prospects for North American energy, especially natural gas. And as the largest midstream management company in North America, we believe we are well-positioned in our existing businesses, and with our backlog of growth projects. Fossil fuels, and especially natural gas, which has now surpassed coal as the primary fuel source for power generation in the US, are going to be needed for a long, long time.

I would add that natural gas is a key in reducing CO2 emissions in America. For example, despite a substantial increase in electric generation over the levels of 1993, the CO2 emissions from electric generation in 2015 were flat for those in 1993, largely as a result of the increased use of natural gas to generate that electricity. So natural gas is playing a major role in reducing emissions.

But, there have been recent controversies, as you all know, surrounding new pipeline projects, and I would like to offer my perspective. First, to the extent it becomes difficult to build new infrastructure, that tends to make existing pipeline networks more valuable, and we obviously have a tremendous existing network. Second, while the protesters tend to get the headlines, it is still possible to build out new infrastructure. This quarter, for example, we completed an expansion on our Texas gas pipeline network.

Third, and maybe most importantly, I think, is to distinguish the permitting environment, both geographically and jurisdictionally. There's a big difference, for example between state-permitted projects, where eminent domain is a function of state law, and a federally certificated natural gas project. Ultimately, we realize that the environment is changing, and we're adapting by building those changing circumstances into how we budget and plan our projects.

Now to the comments specific to Kinder Morgan. During the third quarter, we substantially reduced our debt, and this positions us for long-term value creation. We're now ahead of our plan for 2016 year-end leverage and as the Chairman and largest shareholder of the Company, I'm very pleased with the progress we're making toward achieving our targeted leverage level of around 5 times net debt to adjusted EBITDA.

This will put us in a position to deliver substantial value to our shareholders, through dividend increases, share repurchases, attractive growth projects, or further debt reduction. Now, because we get so many questions regarding these alternatives, let me expand a bit on this subject. Our current view leans toward increasing the dividend substantially, while maintaining both greater coverage than in the past, and a stronger balance sheet.

That said, we will obviously make the best economic decision at the time we reach that point. We can't give you exact timing on when we will reach our target, because there are numerous factors involved. But as I said, the message today is we are pleased with the progress to date.

With that, I'll turn it over to Steve.

Okay, thanks Rich.

I will update on capital projects and counterparty credit, and then hit on some segment highlights and trends. On the capital update, two of our larger projects, first on Trans Mountain, on that expansion, I'll start with the fundamentals.

We consistently hear from producers in Canada, and some refiners in the Northwest US, that they are counting on this project to get built. Production is expected to continue growing, even though it is at a slower rate on the oil sands, and takeaway capacity projects continue to lag the demand. Oil prices have hurt the oil sands, no question, but from the perspective of our expansion, the supply and demand fundamentals for new takeaway capacity are good.

We're nearing the end of the federal review process right now. We have our NEB recommendation finding the project to be in the public interest, and the Federal Government has undertaking its further consultation process, with the objective of a final decision in December of this year. We've made great progress with communities along the route, and have agreements with the majority of the most directly-affected First Nations bands. We're actively engaged with the BC government on the satisfaction of their five conditions.

Finally, I will note that we do believe that this project would make a very good candidate for bringing in other investors, through a joint venture or other structure. It is an attractive project economically, and there is substantial interest in it.

We believe that the project needs to ripen through the review processes that are nearing a conclusion now, but following those reviews, assuming the outcomes are favorable, or if the outcomes are favorable, we would look to syndicate this investment. We have got a lot of options here, including self funding, so we're not committing to any one approach, but we do think it is worth exploring the options at the right time.

On Elba, we have our 7C certificate from FERC. We got that in June, but the news is, that we have received now, our first significant notices to proceed from FERC just this week, and that is the authorization that follows the 7C that takes our implementation plan, and it gives us permission to go forward with construction. We and Shell, our customer, are prepared for us to begin construction, starting the first of November.

With respect to the rest of our projects, we've been talking for several quarters now about high grading the backlog, and making sure that we're attending to our balance sheet, and also ensuring that we grow value through investments at attractive returns that we can fund out of the cash flow that we generate. That is, without needing to access the capital markets. This quarter, our backlog stands at $13 billion; that is down from $13.5 billion last quarter.

We believe it is an attractive slate of projects, projected 6.5 times CapEx to EBITDA multiple. 87% of the backlog is for fee-based projects in our pipelines and terminals businesses. The changes from that $13.5 billion to the $13 billion, we put $600 million worth of projects into service during the quarter, including bringing on the intrastate Texas gas crossover project, that is in support of LNG in Mexico markets, taking delivery of two Jones Act vessels, which are under charter, completing two smaller liquids terminal expansions, and we completed Phase 1 of our Tall Cotton Enhanced Oil Recovery project.

So $600 million went into service, we added a little over $200 million of projects in the quarter, $130 million of that in gas, and $75 million in CO2, where we continue to see good returns, even at current prices. If you look at the year-to-date numbers, we've added a little under $600 million, about $575 million in new projects. That has been, the backlog has been coming down, so that has been, those editions have been more than offset by projects going into service, and project cancellations earlier in the year.

Overall, I think what this shows you is we have been successful in doing what we set out to do. We have high-graded the backlog to strengthen our balance sheet, and enabled the funding of our growth projects without needing to access capital markets, while continuing to add projects where we find them at attractive returns.

Turning to customer credit, we have a broad, diverse customer base, with overall very good credit quality. We continue our extreme focus throughout our commercial and corporate organizations, active monitoring, calling for collateral, et cetera. And we have seen some stabilization in counterparty credit as our producer customers have been actively addressing their issues over the last few quarters.

So, in the past quarter, we were not impacted by any customer defaults. We had one customer file for bankruptcy, and the reorganized entity continued to contract with us. So no impact from customer defaults in the third quarter.

Now turning to the segment for some highlights and trends there, starting with the GAAP measures, GAAP segment earnings were down $211 million for the quarter, compared to the third quarter of 2015, primarily due to higher impairments in this quarter, compared to the same quarter last year. Those were primarily comprised of a $350 million non-cash impairment on our MVP investment, driven by the expectation of future lower contract rates, and an approximately $84 million loss associated with partial sale of SNG.

If you look at segment earnings before DD&A in certain items, which is how we measure our performance, we are down $33 million, or 2% quarter to quarter. CO2 is down $53 million year over year due to the lower prices, $62 a barrel realized versus $74 in the third quarter of last year, and lower production. Nevertheless, we expect CO2 to make plan, due to some improvement versus our plan price, and good performance on cost savings by that segment.

Compared to the same quarter last year, gas is down 2%, while terminals and products are up 22% and 7% respectively. Overall we think again that the quarter's performance demonstrates the resiliency of our cash flows, even in difficult commodity price environments.

Focusing on some of the broad trends affecting our business, first in natural gas, we're seeing the demand-side developments that we anticipated. On our systems specifically, we're benefiting from increased demand for gas in the power sector, increased exports to Mexico, and now for the first time, increases due to LNG exports. On Kinder Morgan pipelines, power driven gas demand was up 9% 3Q to 3Q, from 6.5 BCF last year, 7 BCF this quarter. On a macro basis, gas is now overtaking coal, as Rich mentioned, as a fuel source for power generation.

Mexico export demand on our pipelines grew by 6% year over year for the quarter, and is up 15% on an comparable year-to-date number. We reached an average volume of 2.8 BCF a day for the quarter, about 75% of total exports to Mexico. We're in the early days of LNG export driven demand, but even with the Sabine Pass outage in the last two weeks of the quarter, we experienced about 350 a day of LNG demand on our systems, and much more to come there, we believe.

Most of our $4 billion of backlog projects in the gas sector are directed at those three market trends, plus one more, and that is the reversal projects on our TGP system, to move more Marcellus and Utica gas to the South. Natural gas, which is by far our segment, is an 80/20 story, with approximately 80% of the budget segment earnings before DD&A attributable to transportation and storage, which benefits from the trends I just discussed, and the other 20% in gathering and processing.

Our gathered volumes are down 17% to 18% year over year, as a result of declines in the Eagle Ford, Oklahoma, and the Bakken. Our Bakken midstream financial performance is up year over year, and up versus plan, primarily due to contract restructuring earlier in the year. But overall, this business outside of the take or pay commitments that we have, is dependent upon the recovery in those basins as gas demand grows and oil prices and therefore drilling recovers.

We continue to believe that the need for natural gas transportation and storage capacity will grow, as the demand trends that I talked about continue. And in the longer term, the gathering volumes flatten and turn up when we ultimately see recovery in the gas supply basins that we serve.

In products pipelines, we're getting the benefit year over year of higher volumes. Refined products volumes are up 3% quarter to quarter and year over year, and well above the growth in the EIA national numbers. Our crude and condensate volumes are up 6% year over year. Our NGL volumes are down 1%, primarily due to a petrochemical plant turnaround by one of our customers.

In terminals, we're seeing the benefit of new liquids capacity coming online, and increased utilization of that expanded capacity. So more capacity online and higher overall utilization.

We also took delivery of two additional Jones Act vessels, which are under contract. Overall, the liquids portion of our terminals businesses over 75% of the segment earnings before DD&A before certain items, and the increased utilization we're seeing and the expansions we're bringing on are positives for that long-term outlook.

With respect to the Jones Act vessels, we see medium-term market weakness there, we benefit from having charters in place for the vast majority of our vessels, and we have a modern fuel-efficient fleet that should be very competitive. But we expect some over capacity in the market for the medium term, which will affect new charter rates and renewal rates until the overall US fleet is right-sized from a capacity standpoint.

On the bulk side, we're down slightly year over year, primarily again attributable to the coal business. In CO2, we had lower volumes year over year for the quarter, down 5%, with SACROC and Yates down year over year. Katz, Goldsmith, and Tall Cotton up year over year, but below our plan.

We also had strong NGL production in the segment, a record quarter in fact, just slightly higher than last year. We also approved some EOR development projects during the quarter, and continue to find attractive return projects in this segment.

With that, I'll turn it over to Kim for the financials.

Thanks Steve. Today we're declaring a dividend of $0.125 per share, consistent with our budget and the guidance we gave you in December of last year. First, turning to the preliminary GAAP income statement, you will see that similar to the first two quarters of this year, revenues in the quarter are down significantly. As I say many quarters, we believe that revenue, or the changes in revenue are not necessarily a good indicator of our performance.

We have some businesses where revenues and expenses fluctuate with commodity prices, but margin generally does not, which is why you also see a partially offsetting variance in cost of sales. In addition, both revenues and cost of sales can be impacted by non-cash sporadic accounting entries for certain items. The largest impact of the certain items on changes in revenues and cost of sales relates to the unrealized CO2 mark to market and hedge ineffectiveness impact on our change in revenues, which accounts for almost 40% of the $377 million change in revenues in the quarter.

We had a net loss in the quarter of $227 million, and a loss per share of $0.10, versus income of $186 million, and earnings per share of $0.08 in the third quarter of last year, a reduction of $413 million and $0.18 a share. Now, let me talk about what is driving that loss.

We recorded a $230 million non-cash after-tax, and that is why that number is little different from what Steve said, because this is after-tax, impairment on our MEP investment, driven by our expectations of lower future transportation contract rates, and approximately a $350 million after-tax loss associated with the SNG transaction, most of which is non-cash book tax expense. For those of you who are interested in how we can have such a large book tax expense on a relatively modest book loss, when you would ordinarily expect a book tax benefit, I will be happy to explain later, but I'm not going to bore everybody with all the details at this point.

Together, these two charges result in a net expense of $580 million, and are the primary drivers of our $570 million in certain items for the quarter. Net income before certain items was a positive $343 million. The adjusted number in 2015 was $345 million, or down $2 million, essentially flat. EPS, excluding certain items, was $0.15, or down a penny versus the third quarter of 2015. So essentially flat, when excluding certain items.

Now let's turn to the second page of the financials, 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. We generated total DCF for the quarter of $1.081 billion versus $1.129 billion for the comparable period in 2015, down $48 million, or 4%.

There are a lot of moving parts, but if you want a very simple explanation, it boils down to CO2 being down $53 million, primarily on lower commodity prices. But to take you through a more granular analysis, the segments were down by $33 million, or 2%. As I previously mentioned, CO2 decreased $53 million and natural gas decreased about $18 million, with offsets -- those two segments were offset by increases in all of our other segments, with the largest dollar increase from the other segments coming from our terminals segment.

The natural gas segment would have been slightly positive if you exclude the impact of the SNG sale, which we sold a 50% interest in, on September 1 of this year. Adding back an $11 million change in JV DD&A, which primary reflects our increased interest in NGPL that we acquired in the fourth quarter of 2015, we add that back to the segment -- the segment's down $33 million, the assets are really down about $22 million.

This $22 million decrease was partially offset by a $12 million benefit, i.e., lower expense when you combine G&A and interest expense. $19 million in increased cash taxes, which is primarily driven by the fact that Citrus fully utilized its NOLs in 2015, is largely offset by an $18 million decrease in sustaining CapEx, a lot of which is cost savings. Netting out the $39 million increase in preferred stock dividends, you get to a DCF variance of $50 million versus the $48 million shown on the page.

DCF per share was $0.48 in the quarter versus $0.51 for the third quarter of last year, or down $0.03 per share, with about $0.02 associated with the DCF variance I just walked you through, and about a penny due to the additional shares that were issued during 2015 to finance our growth projects, and maintain our balance sheet. $0.48 in DCF per share results in $801 million in excess distributable cash flow above our $0.125 dividend per the quarter. And year to date, we have generated approximately $2.5 billion of excess distributable forecast flow above our dividend.

Now let me give you some details on our expected performance for the full year, versus budget. Natural gas pipelines was expected to be approximately 5% below its budget, due to the SNG transaction, lower volumes in our midstream group, and a delay on our EEC SNG pipeline expansion in service, as a result of a delay in receiving our FERC certificate.

If you exclude the impact of the sale of the 50% interest in SNG, we would have expected natural gas to be about 2% below its budget, so on an apples to apples basis, the 2% is consistent with what we told you last quarter, for the natural gas pipeline segment. CO2 is expected to end the year on its budget, consistent with the guidance we gave you last quarter. Some price help and cost savings are offsetting the lower-than-expected oil and CO2 volumes.

We currently expect terminals to end the year about 5% below its budget, that is slightly more than the 4% we discussed last quarter. The overall variance is due to the impact of the coal bankruptcies and lower throughput and ancillaries on some of our liquids terminals, versus what we had budgeted. Actually, throughput on our liquids terminals year to year, when you compare it to 2015, is actually up. It is just slightly lower than what we expected in our budget.

We currently expect products to end the year approximately 5% below its budget, consistent with the guidance we gave you last quarter, primarily due to lower crude and condensate volumes on KMCC, Double H and Double Eagle, lower throughput on KMST, and lower rates on our SFP pipeline, and as a result of the lost income due to the sale of Parkway. Consistent with last quarter, we are projecting KMC to be essentially on its budget. With respect to other items, interest, cash taxes, G&A and sustaining, on a combined basis for those items, we're expecting to come in lower than budget.

Or said another way, they are expected to be a favorable variance, primarily as a result of lower interest and sustaining CapEx. Interest is expected to be approximately 4% below its budget. About half of this variance, or over half of the variance is associated with a lower balance, as a result of the SNG transaction, with the remaining variance driven primarily by lower rates. Sustaining CapEx is also expected to be approximately 4% lower than budget.

Let me conclude with two overall financial points. On an apples-to-apples basis, our full-year guidance has not changed from the updated guidance we gave you last quarter, when you exclude the impact from the 50% sale of SNG. We continue to expect that adjusted EBITDA will be about 3% below budget, and DCF will be approximately 4% below budget.

When you adjust for the four-month impact of the 50% SNG sale, so not on an apples-to-apples basis with what we gave you last quarter, we expect EBITDA to be approximately 4% below budget, but DCF will also be approximately 4% below budget. DCF doesn't change versus SNG transaction versus no SNG transaction, given the interest rate savings. And 4% doesn't change, given the interest rate savings, offset from the impact of the lost SNG EBITDA, because we used all the proceeds from this transaction to reduce debt.

And the second point is that we expect to end the year at 5.3 times debt to EBITDA, which is also consistent with what we told you in the second-quarter call. The 5.3 is down from our budget guidance of 5.5 times, largely as a result of the SNG transaction.

With that, I will move to the balance sheet. When you look at total assets on the balance sheet, total assets are down $2.5 billion, and that is largely driven by the sale of the 50% interest in SNG. We ended the quarter with net debt of $39.25 billion, which is down $1.976 billion from the end of last year, and down $2.073 billion from the second quarter.

We ended the quarter at 5.3 times debt to EBITDA, and as I said, that is where we would expect to end the year. The 5.3 times is down from the 5.6 times, where we ended last year. Now, to reconcile the change in debt for you, for the quarter, as I said, debt is down 2.073 billion. We generated DCF of $1.08 billion.

We spent about $550 million in expansion CapEx acquisitions and contributions to equity investments. We paid $280 million in dividends. We had proceeds from divestitures of about $1.43 billion, with the biggest being the SNG transaction.

We also deconsolidated about $1.2 billion in debt, as a result of the SNG transaction. And we also took $803 million of the cash that we received from that transaction, and it is sitting in restricted cash, so in other current assets on our balance sheet, and we used that to pay debt on October 1. So that debt was not paid down as of 9/30, but has subsequently been paid down.

Then we had $9 million of working capital and other items that was a use of cash. Year to date, the change in debt, $1.976 billion. So we've reduced debt by just under $2 billion. We generated DCF of $3.36 billion.

We had expansions, acquisitions, and contributions to equity investments of $2.43 billion. We had -- we paid dividends of $839 million. We had proceeds from divestitures of $1.65 billion.

We deconsolidated $1.2 billion of SNG debt. We placed $800 million again into escrow, which is shown in restricted cash, or other current assets on our balance sheet. Again, we used to pay down debt on October 1. Then we add working capital and other items, that was a use of cash of about $168 million. That gets you to the $1.976 billion reduction in debt. With that, I will turn it back over to Rich.

Okay. Thank you, Kim, and with that, May, we will open the lines for questions.

(Operator Instructions)

Kristina Kazarian, Deutsche Bank.

Steve, appreciated the project updates. A couple of quick clarifications. On Utopia, any color on the judge's denial of your use of eminent domain, and maybe could you talk about what this means for that project? And then on, Elba appreciate the November 1 date, but can you just remind me, am I still going through the rehearing process, and what does that mean for that project going forward?

Okay. I will start with Utopia. We had a Wood County judge who, in interpreting the eminent domain statute, interpreted that our pipeline didn't qualify for eminent domain. We are appealing that, in fact, we filed the appeal last week. It is inconsistent with what other decisions, including appellate decisions, that have been made in the state. We think we are ultimately going to prevail on appeal there.

There maybe some other decisions that come out of Wood County that will be consistent with that, but we expect ultimately to prevail on appeal. We are in the process of evaluating what that means. We're two-thirds of the way through applying right-of-way already, separate and apart from what happened with that decision. So this is fairly recent news, and so, we're sitting down and strategizing about how to go forward with the acquisition of the remaining right-of-way, and what our legal strategy is going to be, et cetera. That's what that decision was about, that's where we are in the project, in terms of acquiring right-of-way and what we plan to do in terms of -- what we have already done in terms of appeal.

On the Elba project, yes, we have we have reached agreement with Shell to proceed without the rehearing having been finalized, so we're ready to go. Our customers are ready to go, we're ready to go. We have our 7(c) already, as I mentioned, we have the notice to proceed, which gives us the authority to go forward with construction, even without a final order on rehearing. We're proceeding, starting up November 1.

Perfect. Thanks and just a quick follow-up from me, too. Rich mentioned the changing regulatory headwinds. Do you think there's a possibility for a change in tides to the positive here? What could be a driver for that? And if we don't see a change, what could be some that ways you adjust when thinking about new projects going forward?

I'll start with the latter part first, and Rich mentioned this. On the adjustments, what we need to do is, and we been doing for months now, is evaluating our project opportunities, and having discussions with our customers, that attempt to price and schedule into our projects what is no doubt an enhanced regulatory burden for getting those projects through the permitting and approval process. We have to make the appropriate adjustments.

In terms of what can turn that around, again, this varies from place to place. We have built our Texas pipeline over the summer effectively, and it's -- you have to go place by place and commodity by commodity to sort this out. But the bottom line is, you need to fully take into account, we need to fully take into account, the additional length and requirements that will be placed on the permitting process. It's not that the whole world needs to change, this is a case-by-case consideration that you need to make.

The other thing that can change the whole dynamic is I think increasingly people will realize, those who don't already, that a big part of the answer to reduced CO2 emissions and cleaner power generation, and compliance with a clean power plan, and things like that, is enhanced -- is additional natural gas, and you don't get the additional natural gas without the additional gas infrastructure. So I think that's a driver that could potentially change some of that dynamic.

Sounds great. And Kim, thanks for the walk as well.

Jeremy Tonet, JPMorgan.

Jeremy?

Jeremy check your mute function.

We'll move to the next question. Christine Cho, Barclays.

I wanted to touch upon Elba. Regarding the rehearing, how should we think about expectations for this asset to be put into a JV? Do you want the final FERC order? Are you in talks with parties and just waiting for that, or have talks cooled now, just because it is not as urgent with leverage coming in better than your target for year-end?

Christine, we have talked, we have put Elba in as a placeholder, where we showed everyone our capital expenditure plans, and everything at the beginning of the year. A placeholder as a JV. We don't have to JV Elba. I think it is a very amenable -- it is very amenable to a joint venture, it is a standalone asset investment, at least when it comes to the liquefaction facilities, and it is attractive, it's under a 20-year contract with Shell.

We've got the ability to self fund that or to JV it, but it is an attractive JV candidate, but again, we are not in a position where we have to do anything in particular with it. But we continue to explore options to JV assets, and that is one of the big variables, and what our plans are, and how quickly we get to where we want to go, and Elba is certainly on the list of things that we can consider.

I don't think the rehearing really bears on it that much, one way or the other. I think, in the context of FERC 7(c)s, it is often, it's traditional for you get the 7(c), and you start construction when you get the notice to proceed, without waiting for the rehearing. In this case, I would say we've got an extremely tight, extremely well-reasoned, extremely thorough 7(c). They took extra time to get it out. And so we think it is going to withstand any rehearing or appeal, and so we're going to go ahead and get started.

Okay. Great. That was helpful.

Then moving over to Trans Mountain, I know we've got a couple of months before we hear from the Canadian government on this project, and I know earlier in the remarks, you said you were open to JVs. But how do you think about project financing this project? Or would terms that usually come with project financing immediately rule that out? And by terms, I mean anything that would restrict how much cash you could pay out from the asset. Just curious as to how you think about that option.

I think we will figure out what the structure is going to be first, in terms of -- is it going to be a JV candidate? Is it not going to be a JV candidate, and what's the timing of it going forward? And then we will figure out what the exact financing plan would be. But, I wouldn't anticipate that we would put in structures that would make it difficult for us to get the cash out of the asset.

And would you say would lean towards having the asset be off balance sheet, or that's an afterthought?

If you're asking -- I think that the way -- we would have to look at it both ways. Both having the leverage on our balance sheet and not having it on our balance sheet, just to make sure that we are in an okay place, even if the leverage was on our balance sheet.

Okay, great. And then last one for me. Over the third quarter, we saw a big M&A announcement between two of your peers, and then talks of another buyer trying to pick the interest of another company. Just curious as to what your view on the landscape is for M&A in the US and in Canada, and do you think we're finally going to see corporate M&A deals get done with everyone trying to fill in the holes of their portfolio? And it also being increasingly more difficult to build an infrastructure, like you said earlier, Rich. Or do you think it's just more fact specific?

It's always pretty fact specific or situation specific. We continue to look for the opportunities, but in addition to being accretive to DCF, it needs to be accretive so leverage metrics. We have to work from that standpoint, so it's a little bit more difficult to get through the screens. But I think ultimately, there's going to be consolidation in the sector. You look at the numbers, and you look at how many players are out there, and we would expect ultimately to be a participant in that.

Great. Thank you.

Brian Gamble, Simmons & Company.

Follow up on the M&A discussion, while we've got it. I think the C Corp for C Corp is a tough one to get through, lots of moving pieces, with any combination that you may try to put together. But when you about individual assets, and Steve, you mentioned essentially the deleveraging event, given the assets that you have in place today, are there assets that if they were a deleveraging event in totality, you would consider divesting them? And of course, I'm speaking specifically about CO2, but is getting something north of the leverage multiple enough to make an asset that isn't quite as core to your competencies a sellable item?

There are unique considerations that surround every one. As we've shown through making progress this year on our leverage metrics, we have considered non-core asset sales. We had a few of those, and the big transaction of course was SNG, and that was a bit unique circumstances. We're not generally in the business of selling cash flowing pipeline assets, but in that particular case, we had partner who was bringing value, securing the asset, but also bringing incremental investment opportunities to the project, so it made a lot of sense for us to go ahead and do that.

With respect to CO2 specifically, we like that business. It is a good business. We invest and get good returns on that business. It's a niche for us. We are not out chasing E&P and shale and offshore and things like that.

We have CO2, which is a scarce commodity, and have the infrastructure to get it delivered to EOR fields where it is the only thing that can free up oil, and we've integrated forward into enhanced oil recovery. We've got expertise there, and we think we're good at it. So we like that business, and we're happy to keep running it.

If you think about your question in terms of a transaction or a potential transaction, we are shareholder directed company, and if there is a transaction to be done that will improve overall value for our shareholders, we are absolutely going to consider it, and do it if it makes sense. The considerations around CO2 specifically is that it will probably be slightly dilutive or somewhat dilutive, and then the question would have to be, is the multiple expansion that you get on the remaining EBITDA of the remaining business, and the yield contraction on DCF that you get by having a better portfolio, or a more stable portfolio of remaining businesses, enough to offset that and produce real shareholder value?

Certainly there are theoretical numbers in which that would work. So, again, we are a shareholder directed company. We're going to do the things that are going to make sense, and create value for our shareholders.

On the shareholder comment, do you think there's enough shareholder support of the sale of that asset to make it a more, make the hurdle easier to jump over, knowing that shareholders support that type of decision?

I think it's about the numbers for us. And it's about what's going to make economic sense. As I said, what will the dilution be, and what will a multiple increase need to be, to more than offset that? So at the other side of it, a shareholder is better off. That is the calculation we make.

Great, and that last question for me. Rich, you mentioned as part of the opening remarks, essentially first priority for increased cash flow would be after of course you get to your debt metrics, as I think you put it, a significant increase in the dividend over time. Clarify one thing for me. Are we getting to 5 times before contemplating that, or are we having visibility to get to 5 times before that is a contemplation?

I think we've always said we wanted to get to around 5 times before we increase the dividend, and that is still our target. But again, I think it's important that we've got so many questions about this, we elected to lay out a little more detail on it. Our game plan, again, we would reserve the right to see what the facts on the ground are when we get to that point, but our game plan would be, we obviously have a lot of firepower, a lot of free cash flow.

And to the extent we can substantially increase the dividend, while still maintaining an adequate of coverage ratio, and by that, I would mean that we would be able to fund the equity portion of our going rate of capital expenditures. We don't know exactly what that is, but we look back and you take out the pigs going through the boa constrictor like Trans Mountain, for example, and you're in that $2 billion, $2.5 billion, $3 billion, in that range.

And if you say once our balance sheet is where we want it, we're going to finance half of that out of the retained cash, and half of that back in the debt markets at that point in time. Then you see your way clear to having a very nice dividend, but with very nice coverage, and maintaining a strong balance sheet. And that is really the trifecta that we are looking for, and I think -- just look at this year, and I think Jim emphasized this, we're right consistent, absent the SNG transaction, with where we told you in April, and where we told you in July, we were going to be.

That leads to DCF of about $2 per share for this year, and we are paying out a $0.50 dividend. That is a whale of a spread between the two. But at some point, when we get this balance sheet the way we want it, we're going to be able to take that dividend up substantially, and still have adequate coverage. We're not going back to having $0.05 of coverage or something like that, because we would like to cover our portion of the equity portion, of a normalized CapEx program.

Appreciate the color, Rich.

Brandon Blossman, Tudor, Pickering.

Let's start with Trans Mountain, again. Steve, you were pretty clear, or I would say very clear on your messaging, around JV potential for Trans Mountain. I guess one question is, has anything changed quarter over quarter, that caused you to be more clear about that messaging? Was it counterparty interest, or has this been the plan all along?

We talked about it, an answer to a question, I think, on the last call, so it's consistent with it to that point. But we're getting closer now to some decision point and resolution, and yes, there has been interest in the project, as you would expect. And so, it's just a little bit of ripening here, ripening in the process and our thinking. There is a little ripening left to go, in terms of getting some of these -- getting the clarity on the regulatory front, which again, appears to be getting closer.

Okay. And probably as expected, the project screens are almost screens for a JV partner here. As you think about and prioritize or rank potential partners, and project promotes that accrue back to your part of the development, and this is a big open question, but how do you think through that process in terms of what you would like to see, in terms of getting paid for your development work here, in terms of reducing your capital requirements in 2017, 2018, and early 2019, and being able to return to getting cash back to shareholders? How do you balance all those pieces of that equation conceptually?

Those are all three benefits, right? And agree with those, but we're really not foreclosing -- we have a lot of options, in addition to having a good interest in it. We've got a lot of options on how to proceed, and a fair amount of work to do to figure out what the best option is. So we're keeping those options open and not really ready to refine that any further for you right now.

Okay. Fair enough. But probably just knowing the potential there, and the opportunity to create some real value nearer-term, rather than longer term. Okay.

I will leave that one to rest. Another broad question, surprises about 12 months ago from the rating agencies. How have those conversations evolved over the last 12 months, in terms of just level of comfort on the other side of the table, as you continue to have those conversations with the rating agencies?

Sure. If you think about where we were 12 months ago, and where we are today, 12 months ago, we were at 5.6 times debt to EBITDA, and we had -- we were paying out substantially all of our cash flow in the form of dividends. Today we are at 5.3 times, and we are paying out a very small portion of our cash flow in terms of dividends, and so I think we are in very good shape in our current rating.

Okay. Understood. Thank you, Kim. And then last question for me, the MEP write-down, what triggered that process, or that consideration?

We just had some interest from various shippers, and potentially looking at contracts. When the contracts on MEP have expired, or will expire, and based on those conversations, we felt like that the rates that we might get when the contracts expire don't support the carrying value of where we have that asset.

Great. Understood. Thank you very much.

Jean Ann Salisbury, Bernstein.

Just a couple quick ones from me. So we've had a nice run in crude price recently, and services costs have down a lot this year. At these new lower services costs, can you give a range of oil price at which you would be able to book new crude reserves at a level that approximates replacing production? I assume that number has actually got much better from last year.

Jesse, do you want to answer?

I think we have added projects throughout the year, so as prices improve, I'd say we're adding reserves today.

Okay. Do have a sense of if you wanted to actually replace 100% of your production this year, what prices would have to be, or even a range?

We don't look at it that way. The way we look at it is, we look at a discrete project by project, and we look at the returns on the projects, that the CO2 group brings forward. And if those returns clear our hurdle, and the minimum amount of capital is 15% unlevered after-tax right now, and if they clear that hurdle, then we generally proceed with it, and if they don't clear that hurdle, at a minimum, then generally we aren't pursuing those projects.

Okay. Understand. Thank you. Then my second question, exports to Mexico, as you noted, have grown massively 3.3 BCFE, and I believe that you mentioned that the majority of that moved on Kindle Morgan pipelines. There are a bunch of new Mexico export pipes, I think, 3 BCFE coming on in the first half of next year. Will that have a material impact on your physical flows or segment EBITDA?

I think that given where our assets are positioned overall, growth in Mexico, export volumes are going to benefit us. Even if other people are building pipelines. An example of that would be the MEP pipeline that went into service, what, two years ago or so? And we deliver a substantial amount of gas into that pipeline.

And the reason for that is we have the infrastructure in Texas, we have infrastructure on EPNG from West Texas through Arizona. So it's part of a larger grid, and our piece of that grid is well positioned to benefit from the pulling into Mexico that is happening, and increasing volumes over the years. So even if it is not us constructing in-country pipe, which we haven't gotten comfortable with from a risk-reward standpoint, the increase in demand and the hooking it up increasingly to US supply sources is going to benefit our system, overall. Transport as well as storage and as well on the intrastate side, sales.

And I think this sounds like a broken record, but we've said it time and time again. This is one more demonstration of the strength that is inherent in having the pipeline network on the natural gas side that we have, which expands all of the producing that arises, and interconnects with virtually every other pipeline system in America, and that's going to pay dividends for many years to come.

Thanks. That is really helpful. And lastly, are we close to contract minimums on gas gathering? So another thing, if Eagle Ford production continues to decline, there actually won't be much impact on Kinder Morgan?

We have got roughly -- I don't think I can answer that question exactly, but we've got 30% of what we call our gathering and processing that's under take-or-pay contracts. But without looking at it contract by contract, I couldn't tell you whether -- wait, short answer is, if there is continued decline, then we're not at the bottom. There would be a continued decline in our revenues. But we do have some floor in our revenue, because we got this 30% of the contracts are take-or-pay.

Great. Thanks. That's all for me.

Danilo Juvane, BMO Capital Markets.

Most of my questions have been hit. I did have one very quick follow-up on Eagle Ford. Volumes was, gathering volumes in general. You mentioned last quarter that you signed some incentive agreements that hopefully would have gotten some volumes in your system. Was that supposed to be imminent here, or is that something you expect to be reflected in your volumes over time?

We have successfully increased our market share from where we were sitting in the first and second quarters, and those incentive contracts were a big part of that. So, we have, if you will, restored the market share that we had at the end of 2015, back to where we were. But we're still in the Eagle Ford, it's a market share of a declining overall base. And so the declines still come, but I think the program that Tom and his team initiated was successful in taking our market share back up.

Got you. And with respect to the issues that you had with MEP, are you seeing anything similar for other pipelines within your system?

We have other pipes that are what you call it, basis pipes, FEP is another example. And so pipes that are point to point, that had long-term contracts that underwrote them when they were expanded, as those contracts roll off and basis has come in, that would present the same phenomenon.

Do you have magnitude of what the revenue impact rate, impact could be going forward here?

The FEP, it's not, let me, is not a revenue issue, in terms of what the shippers are paying us, because those are take-or-pay contracts, and I think the contracts go through 2019 or 2020 on FEP. I think it would just be, as we figure out where we think exactly the market is, whether you have a non-cash impairment on those assets. So the customers are still paying, in fact, the largest customer on FEP is Southwestern. They've actually put a rig or two back into the Fayetteville, and their credit situation, I think, has improved dramatically over the last few months.

Thanks for the color. Last question for me, is the CO2 CapEx still trending at about $50 million or so? Quarterly?

Yes we had, it's up a little bit from where we were, I think we were at about $210 million for the year. We're now about $249 million or $250 million. Yes, $250 million.

Got you. Okay. Thank you, that's it for me.

Ted Durbin, Goldman Sachs.

Coming back to Trans Mountain here. Maybe you can give us a little bit of a preview on this Ministerial Panel's report? I think it's due November 1, and how that will impact the December decision? And then also an update on the BC process, meeting the five conditions in particular? I think revenue sharing is one of the big ones there.

Yes, so there were a couple of, if you will, additional federal processes. One was a federal consultation process where the federal government was directly out consulting with First Nations and communities. The one that you are specifically referring to is, there was a panel of three people appointed to go out and hear from the community up and down the right-of-way, and gather data, or gather perspectives that hadn't been picked up in the NEB proceeding.

That process has wrapped up in terms of the hearing, and as you pointed out, there is a report that is due. It's a report that is cataloging, at least as I understand it, everything that the group of three heard, while they were talking to people in the communities, along the rights-of-way. The federal -- so those things feed into the federal decision, the order in council that comes out of the federal government, which is still scheduled for December 20. So I don't know of anything, Ted, that is inconsistent with the December 20 date. Certainly nothing that is associated with those two processes. We still expect to see on or before December 20, a final order in Council.

Then, the other part of my question, it was a long one on the British Columbia process, meeting the five conditions?

We have been engaged with British Columbia on the five conditions. I think it has been constructive and productive engagement. We don't have anything final there.

The other process that is going on in British Columbia is the EA order that they are going to issue around the same time as the federal decision. And at least in our thinking, we're assuming that is in January. That's not going to be in December, that's going to be in January. And so, I think what we're aiming for is to have the British Columbia conditions, as well as that environmental order, resolved and complete early next year.

Okay, great. And then I know you have been back and forth with the contractors. Just any updates on the cost side and overall project returns, still in line with what you had originally budgeted?

Project returns are still in line. We're still working on the costs with the contractors. We have made very good progress, I would say, but we're not final yet, and we're still -- as you know, a complicated project. There's still work to be done there, but I think we've made good progress.

Okay. I'll leave it at that. Thank you.

Shneur Gershuni, UBS.

I just wanted to confirm your response to one of the earlier questions, I think it was Brian's question about retained distributable cash flow. I just want to make sure I understood it correctly. If, let's say, you're at a run rate, just using round numbers here, about $4.5 billion of distributable cash flow, and I think if I heard you correctly, you had talked about potentially holding back about $2 billion of that of that retained DCF to fund the equity portion of a normalized growth CapEx budget.

No, you didn't hear me correctly. What I said was, we would hold back, and certainly we would expect that $4.5 billion run rate today to increase, as new projects come online. But what I said was, we would hold back the amount necessary to fund the equity portion of a normalized CapEx expenditure for the year. So for example, we would think, and that would depend on what projects you have. We would think historically there has been between $2 billion and $3 billion per year.

So if you pick the midpoint of that as $2.5 billion, you would be withholding $1.25 billion out of that $4.5 billion or $5 billion of distributable cash flow. So, it is not the whole thing, because once we get to the level of -- the appropriate level of debt, we would intend to go back to financing half equity, half debt. But the difference is we would not contemplate putting out new equity, we would be using retained cash flow from operations to fund the quote-unquote equity portion of that. Does that answer your question now?

Yes, I think we're actually on the same page. So if I do my math correctly, that means it is a very significant increase in the dividend from where you are today, which I think is running at about $1.1 billion or $1.2 billion. Am I thinking about that correctly, and it corresponds with your whale of a difference comment earlier?

Yes that would be, of course, a significant difference, right.

Okay. Cool. Second question, and I know that you've been asked this many different ways, but I realize the Company has make considerable progress of getting down to your stated goal of 5 times net debt to EBITDA. Two questions in one here.

Has that leverage goal impacted your ability to consider some growth projects? And then secondly, given all the questions about returning to a higher level of dividends, is the Board considering any options to accelerate the pace to this 5 times leverage goal, either through equity or preferred issuances? Or even asset sales, or is the Board comfortable with the pace where you're at, and you'll get there when you expect to get there?

Okay. So, let me answer, and I think my answer to the first will address the answer to the second question, which is the reason that we decreased the dividend primarily a year ago, had to do with inefficient capital markets, and not wanting to fund expansion CapEx in a market that wasn't rationally pricing debt and equity securities. I think the debt market has changed, the equity market is still significantly different from where we were 12 months ago, 18 months ago. So, we are funding our CapEx program.

So in my mind, what we are constrained by, we do want to improve the balance sheet, and that is a goal that we have. But what we're doing is we are living within our cash flow, meaning that we want to be able to fund our CapEx and our dividend from our cash flow. And so that is the constraint, and so, because we have a limited amount of capital, that is why we have the hurdle rate set at 15% unlevered after-tax IRR for projects.

I fully anticipate that over time, as the CapEx comes down, and also as the balance sheet improves, that we would relax that standard. I don't know exactly what that number is going to be today, but it would be something less than the 15%. It probably won't be back at the 8% unlevered after-tax that we previously used for a hurdle rate, but we will have to make the assessment, when that time comes.

And so, you're comfortable with the pace that you're at, or would you consider options to accelerate getting there?

If you mean assuming equity, we're not an equity issuer at these prices.

That was why -- that we're living within cash flow, given where the current equity prices are.

But look, we are going as fast as we can. If can find ways to go faster, we will. We're working on this all the time, as you might imagine. But it's just a question -- the particular method that you identified, as distinguished from attractive joint ventures for example, and other ways of accelerating us getting there, that approach that is issuing equity, is not attractive at today's prices.

Okay. Fair enough. And one final question. We have seen a spike in global coal prices recently, and I know you had some challenges at your terminals over the last two years. Has there been any inquiries, or increased inquiries in terms of folks wanting to ship out coal in bulk out of the US? Or is it still too early to see the benefit from the recent increases that we have seen in coal prices globally?

We saw actually a 13% uptick last quarter in our coal volumes, mostly on the export side. Now, on a US basis, exports were down 11.8%. That is just a drop in the bucket. We're still down 30% on a year-over-year basis. The prices we've seen, some price compression.

Volumes did spike up, but we don't anticipate that going significantly higher. The forecast for this year is still tracking at about 59 million tons of export, and that is comparable to 74 million tons last year. It's not projected a lot higher than that. So we've got some ground to make up.

All right. Thank you very much.

Darren Horowitz, Raymond James.

Thank you, Rich, I hope you and the team are doing well. I will be quick. Rich, you and Steve mentioned the permitting challenges, and obviously the Connecticut expansion of TGP comes to mind. I'm just thinking systemically, what impact do you think these permitting challenges are going to have specifically on the Northeast gas market, when you reconcile the amount of market pipe capacity versus what you said you expect, Marcellus and Utica production growth expectations to be. Do you think it's a rescaling marketed pipe or a combination of pipes? And I'm most interested to know your thoughts on maybe some basis differential expectations, more pressure at Dawn hub, but most importantly how you capitalize on it, through scaling up TGP?

Okay. A lot loaded in there, but basically I think our view, it is very hard to get big new builds done Into New England or into the Northeast, and we have seen that not only with the NED, which we talked about the first quarter and discontinued, but also with recent rulings, that I think verified that decision. It's making it harder to get things done on a mega-scale, call it.

We have continued to engage with our customers on smaller scale projects, and we'll continue to pursue those. I think from the perspective of right now, today, it is hard to get new significant gas infrastructure built into New England, and that would tend to increase the basis differentials between what is already the lowest price gas at Dominion South, call it, and the New England market, which is just a few -- the highest priced in North America and just a few hundred miles away. So, barring some improvement in that overall permitting environment, I think it's difficult to do those, but we will keep looking for the smaller projects to do.

The other thing, I think New England is a perfect example of what Rich said at the very beginning, which is that it does tend to make existing -- the existing network more valuable. The thing I would add, and let Tom throw whatever he wants, but the TGP system is a system that is continuing to produce project opportunities for us. A lot of our backlog on TGP -- a lot of our backlog in gas is on TGP. It's the biggest home for it outside of the Elba project right now.

And, what a lot of that project capital is directed at now, is getting the gas, as you know Darren, south from the Marcellus and Utica to the new market, the new market area, which is now the Gulf Coast of the United States. And we are proceeding along very well with those. We're building on our existing footprint.

That again goes to the need to make distinctions between projects out there and infrastructure projects. Building off of your existing footprint, adding compression, maybe laying some parallel pipe, things like that. That created a different -- that is a different -- in a federally certificated process, that is a different context in which to be doing your project expansions. So I think you will see basis widen into new England or to the Northeast, and I think we'll find plenty of things to invest in, and are finding plenty of things to invest in on TGP, to get that gas someplace else.

Thank you.

Jeremy Tonet, JPMorgan.

You're back on.

Sorry about that. Thanks for taking me. Going back to TMX here, I was just wondering if you could help me think through some things here, as far as, if there is any target as far as what the right ownership would be for this. And when you're talking about the JV here, is this just the expansion, or the expansion of the existing pipe? What it comes back to is, when I'm thinking, I'm trying to model 5 times debt to EBITDA, the spend on TMX, and the drag associated with when the cash flows materialize, there's a pretty big variable in that equation. So I'm just wondering if you could help me think through that.

A number of things in there, but I think -- the project is hard to separate from the underlying asset, to answer the simplest one of your questions there. On the approach on what the ownership percentage would be and more of the details, I will go back to the earlier answer which is, we have a lot of options and we're going to pursued the most valuable one because the easiest way I can characterize it and we don't have to do anything, which is a great position to begin. But we are going to evaluate it.

Got you, that's helpful. And then if I heard you correctly, let me know if I'm wrong, as far as when in the regulatory process it might make sense to proceed with the JV if the terms makes sense. It is earlier next year when you see if things progress as scheduled, that could kind of come to fruition at that point?

That's a good point to be looking at it, when we see the regulatory clarity. Because I think investors would like to see that too, and so I think that's a reasonable point for us to be examining it.

Got you. Thanks for that. That's it for me.

Craig Shere, Tuohy Brothers,

Good afternoon.

Good afternoon, takes for taking the extended call here. So a couple of questions here, one, Rich, you commented about the historical annual run rate, call it about $2.5 billion a year. I know we have some [taking the Python] issues with Trans Mountain and other such items that may be JV'd. But my question is, as we think about lowering the hurdle rate for new projects from 15% perhaps to the very low double digits, do you see the capacity in this current market to really fill in for that kind of ongoing investment opportunity when year to date you've only filled in $575 million?

Well I think again, we would just have to look at what the environment is at that particular point in time and these things do vary from year to year. But we look back over several years and it's our thought at this time, and again, it's a preliminary outlook, as I stressed, but that that annual burn rate, if you will, of expansion CapEx Is something in the range we talked about. And that's what we would want to use as providing enough coverage to pay for the quote unquote equity portion of that burn rate. And I think under almost any scenario that leaves a lot of money to pay dividends, but we'll just look at the effects of circumstances when we reach that point.

Understood. Is there any color about how much you've left on the table because it didn't meet your hurdle rate because of the significant balance sheet management that has really helped a lot in the last two, three, four quarters? Any kind of color on you've already left on the table because of that discipline, that maybe when, in better market, might be there in the future?

I don't know that we left anything on the table, Craig. We did elevate our return hurdle criteria, but we have continued to say, look, if there is something that our business units thinks makes sense, we've got a good customer, good counter-party credit, long-term contracts, confidence around execution et cetera, we want to bring it in and talk about it. And we continue to see those come forward. I think the one place that we took a close look at was CO2 and certainly in the oil price environment we saw earlier in the year, we took projects off the table and now we're adding those back as we see oil prices recover.

So, are there some things that we've might have been able to do if we were in an 8% world that we're not doing we're in a 15% world? Then yes, maybe so. But I think what we're talking about in the longer term is return hurdles that we will relax off of the 15%, as Kim said, and I think given the network that we have, we'll still find those opportunities off of our network and we're finding some of them still today.

Understood. And on MEP, was there some specific ongoing revenue or EBITDA drag or reduction expected apart from the one-time non-cash writedown?

You're asking if we've had any changes on the underlying contracts at MEP, no. There have been no underlying changes. This is based on -- the impairment is largely based on, informed by discussions with customers of rates that we can get when contracts expire.

Understood. And on the Jones Act Tankers, any more color you could provide there on your comments about the size or duration of the moves? I think you still have American Liberty and American Pride yet to contract -- is that correct? An any update about charters rolling over the next couple of years.

We have two ships that are not yet constructed and those are the only two of the 14 are currently not chartered. The only two of the 16 that are not currently chartered. Everything else is -- there is one that's under a shorter-term charter that is rolling into a long-term charter. Everything a charter. We do have some coming off in one or two in 2017 -- three in 2017.

We're having a real strong year there. We're up $12 million on the base, mostly due to a less [op higher] and higher rates, and then the expansions are another [25.7]. If you look going forward, the risk it really is -- we've got 11 that are under long-term agreement and then five that could be impacted at some point or another, it's about 15% of the total earnings for that group.

That's very good color. Thank you. And then on -- there was the question about Trans Mountain costs, I just want to confirm, historically you all have said that if we bumped up against that upper limit of what the off-takers were required to accept in Canadian dollars, if we punch through that, that there was still a significant shipper interest and if conditions were that you punch through that a little bit, the expectation would be plenty of still interest and you wouldn't be too worried about that. Is that still the case that whatever comes, you're going to do your best to keep costs down but the shipper interest is there?

There's good strong shipper interest including outside of the current shippers. And so yes, we still believe that. Now having said that, we are working very hard to keep our overall costs down and to be within the cap, and we're making good progress. But yes, we do believe that there's strong enough -- there is strong shipper interest outside of the existing shippers.

Great. And last question for me. It's a bigger picture, but the industry -- don't even want to call it industry, but the activism out there that's made it difficult to put on new projects has also start impacting existing projects on occasion and that's called into question what kind of ongoing costs that are for surveillance and security. Can you comment on those trends and any issues impacting the industry?

I think it's the same general comment which is we have to take all of those kinds of things into account in scheduling and costing our projects. And it includes additional public outreach, it also includes taking into account security measures that may be needed. So, it's about adapting to that new environment and that's what we are actively doing.

Okay. Thank you very much.

Becca Followill, US Capital Advisors.

Afternoon, Becca.

Afternoon. Three questions for you, one on Utopia, back to that, do you have a timing on the appeal and in how many counties have you sued the landowners?

The timing on the appeal, we've asked for an expedited appeal, so we're waiting to see if that is granted and then they'd have to set a schedule. And so I don't have a specific answer on that, but it would be months. It would be months to get the appeal ultimately resolved. And Ron, in terms the number of counties where we've got condemnation suits, it's probably nearly every county (multiple speakers).

Several of the counties and we -- and as typical of all of our projects, we try to avoid use of eminent domain. We negotiate with respect with landowners and as Steve and Rich indicated, we're about 65% just through gaining easements without any eminent domain. We continue to work the effort while we appeal this one county effort and what happens in other counties, that remains to be seen.

So other judges of course have ruled this other way on this.

There have been counties that have ruled the opposite direction?

Correct.

In Ohio?

And including at the appellate level.

Was the appellate level, was it on surveying or was it on eminent domain?

It was on eminent domain.

Okay, are there different districts that you have to go through if a different county rules, or is it all in one district and which district is it?

It's a county by county. This is a county court system, state county court system in each county in then there are appellate districts and then ultimately the Ohio Supreme Court.

But you're appealing to a district court?

We're appealing to the Court of Appeals.

Court of Appeals, okay. But you know which district?

I don't know what the number is.

Thank you, I'll track it down. Second, on the timing to finalize the cost of the Trans Mountain expansion, I would assume you would have to have that in hand before you could do a JV?

Yes, and we have to -- I don't remember the exact timeframe, but we do deliver it to the shippers following the receipt of acceptable approvals. So there's some relatively short window of time within which to deliver that.

So that would also be in January then?

It's the six that -- Ron informs it's the sixth district Court of Appeals. What was your other question, Becca?

So it would be January then on timing (multiple speakers).

Let's say first-quarter.

Okay. And then finally on Yates, it seemed like a fairly big sequential tick down in production there. Was anything unusual that was going on?

A couple things. We deferred a couple of projects earlier in the year and then we had a power outage in the quarter that significantly affected the field. But nothing major beyond those (inaudible).

And how much did the power outage affect the field in terms of production? Can you quantify?

I'd have to get back to you on that.

Okay. Great, thank you guys.

Chris Sighinolfi, Jefferies.

Good afternoon.

Hey Rich, appreciate the time tonight. Just on a couple of clarification questions, to start a model question, Kim, I think I heard you say in your prepared remarks that the full year sustaining CapEx would be within 4% of the initial budget. Just wondering, I think the original budget was [570], [574], so I was just looking at the final page of your release tonight. I just wanted to figure out the reconciliation of that comment, if I heard you correctly or not and then the [455] listed in the last page. Just what I should be using, what is the number?

The original budget was [574] and we'll be within 4% of that number.

Of that number, okay. Okay.

4% better, in other words (multiple speakers).

Yes, yes, no I understood. There's a lot of improvement you guys have made there. I knew it was going to be under, I just didn't know that [455] spoke to a larger magnitude. So I'll follow up, maybe with David about what this table represents, but I just wanted to clarify for our model what the number should be. Second question for me, oil curves moved up significantly since the last call, curious if any additional hedging activity had taken place and if you could maybe give me just a quick rundown on where you stand?

Sure, on the hedges, and this is 2017, we've got -- I'm going to give you barrels now because I think that is easier for everybody's model than giving you percentages. And so on barrels, we've got 24,400 barrels hedged for 2017, 13,700 for 2018, 6,100 for 2019 and 2,300 for 2020. And the 2017 barrels that are just gave you include roughly 1,700 barrels of NGLs. And to give you the prices that go along with that, 2017 is $62, 2018 is $66, 2019 is $58, and 2020 is $51.

Perfect. Super helpful.

In the prices include the NGL volumes.

Right. Okay. And the final question for me, Kim, is just a lot of questions on TMX, obviously I appreciate the color on the project, procedural pass, potential for partners. I just -- as it relates to your historical cadence around guidance, just given that's normally early December and a lot of this seems like it will be decided either late December or late January, just what we should be expecting from you, if anything different than normal.

In terms of getting guidance later in the year with all the moving parts in the first quarter --

Precisely, yes.

So we haven't even started going through our budget process for 2017, so we normally decide if, when and how to guide when we're deeper, actually when we're completed with that process. So I don't have an answer for you yet, Chris.

Okay. Thanks for the time, guys.

Thanks.

Faisel Khan, Citigroup

Hello Faisel, how are you this afternoon?

Hello, thanks, good evening. In terms of the TMX again, can the negotiations with your contractors extend beyond the end of the year, or are you expecting that to be done by end of the year?

I would expect there will be stuff being negotiated with the contractors all the way along through the project, frankly. But the bulk of it will be done by the time we communicate to the customers obviously, so early next year.

Okay. And then the increased contribution that you guys talked about the quarter from the Hiland Midstream assets, what exactly is that associated with? Was that associated with higher volumes, or was there something else going on (multiple speakers)?

It was shifting contracts from commodity sensitive contract structures where we were getting a percentage of proceeds, to locking in the fee and giving the producer the commodity upside. So the producer was happy with the commodity upside and we were happy to lock-in and secure a stable cash flow.

Okay and that caused an increase in the EBITDA for the quarter?

It did, yes. For the year too.

Got it. And then the hedges, Kim, that you described on the call right now, are those hedge amounts for next year -- those look like a little bit lower than what you would normally be at this time of year in terms of percentage of volume basis.

We are within our hedging program.

Okay, okay and the tax expense you talked about for SNG, is that just related to the deferred tax assets for the entire company, or is that just a reflection of a change in the DTA for you guys?

No, it's a reflection of the fact that we don't book deferred taxes on nondeductible goodwill.

Okay. Okay. That make sense, that's all I had guys. Thanks.

John Edwards, Credit Suisse.

Hello Jonathan, how are you doing?

Doing good, I'll try to keep this really brief. Can you remind us on Trans Mountain with that CapEx cap is and then if you could remind us how much you've invested in Trans Mountain to date?

It's CAD6.8 billion is the cap amount and by the end of the year, will be a little under CAD600 million invested, but keep in mind that there is -- Canadian, but keep in mind that's a gross number and we collect what we call firm 50 fees, this is firm capacity across the dock, and there's $250 million worth of firm 50 fees that go to offset that development cost. So the net number and now, that doesn't all match up in time, that is extended over a 10 year period. But $250 million worth of development costs is funded through the firm 50 fees.

And then beyond that, as of course we've explained before, we have commitments from the shippers for a portion of this in the event that the project would not go forward. So it's not like all of this is on our nickel. I think Steve's has explained that in the past.

Okay, so if it doesn't go forward, approximately what percentage basically (multiple speakers)?

It varies depending on the reason, but it is generally no less than 80% is borne by the shippers.

Okay. That's helpful. And then the December 20, do you expect that to be -- is that literally a go, no-go or is there some other decision that could come out of that?

It's a decision and we don't know if it is going to have additional conditions or affirm the NEB's existing 157 conditions or so. But it will be -- it is expected to be, as for example in the Northern Gateway case, the order in council is a definitive decision about whether they view the project as being in the public convenience and necessity. So will be definitive from that standpoint, we would expect. Unless there's something very different here, we would expect them to make that determination definitively.

Okay. So that becomes effectively becomes the go, no-go, is the public (multiple speakers)?

I'm not clear on what you mean by go, no-go.

I mean you get a decision -- does that mean, for example if they did not find it is in the public -- it's not a project found in the interest of the public for convenience and necessity, would you in effect, at that point have to cancel the project? Now if they find you'll get a certificate of public convenience and necessity, but they add some conditions, I'm presuming then that project, for all practical purposes, definitely goes forward. That's what I'm trying to figure out.

So, on the going forward decision, there are the other elements that I spoke to, we've got to get the BC resolution, go through the final contractor and customer communications, all of which we expect to happen fairly shortly after the federal order. The federal order could be a range of things. Naturally think we've made a very case and we think we've done better even than past applications in terms of meeting the requirements that the government has laid out, so we're certainly advocating for and expecting we'll find a determination that it is in the public convenience and necessity.

But it could also have additional conditions and we would have to examine those conditions are what impact the have on the project. And to your point, yes, they could determine that it is not. And then would have to decide what our next steps were from that point.

Okay. And then to switching over to the JV possibilities, given that the customers are effectively funding a portion of this on a JV, would they be eligible to participate in any, say, markup on that -- how much sharing would go on with the customers?

No, there is no sharing on that. But we're also, again, not being specific about who might want to be a participant if, if, again, this is an if, if we pursued a JV.

Okay. So I'm presuming -- would be fair to presume that there is a fair number of the customers that would want to be -- (multiple speakers)?

I wouldn't lean into that, John. I think that they're generally in different businesses than owning pipelines, if you look at the slate of customers, I'm just not precluding any potential option there.

Okay that's really helpful. That's it for me. Thank you so much.

Sunil Sibal, Seaport Global Securities.

Hello, good afternoon guys and thanks for all of the clarifications. Just a couple of quick ones for me. Trying to think six to18 months ahead, you got your leverage to below 5 times, and the rate of dividends to higher levels. How should we think about leverage from that point going forward? Because presumably, you're looking to finance some of the future projects with additional debt. Is there a target kind of [leverage] that you will still be aiming for, especially considering that you might get credit for that capital spend for future leverage?

We've been targeting about 5 times leverage as a decision point. When we get to that point, we will, as Rich said, we will look at the dividend, we will look at whether we want to pay down additional debt and we will look at what we think the right long-term run rate is for the business, whether it is the 5 times or whether it is something improved from there. And so, I think in terms of, you can expect it would be at 5 times or potentially better depending on what decision we make when we get to that point.

Okay. Thanks for that, and then just one clarification with regard to your interstate pipelines. I was wondering what kind of interest you are seeing on some of the recontracting for those pipelines. I think NGPL especially had some contracts which were coming up for renewal, any color on that?

Yes, I would say overall we've had good interest and good rates. Our contract [tender] really has increased over the course of the year. And the right way to think about NGPL is that it touches all the major demand and supply areas that are engaged in the market right now, whether it be LNG, whether it be Mexico exports, whether it be petrochemical growth in the Gulf Coast, whether it be certainly Marcellus Utica and even the Permian, we're seeing some action out west as well. So good prospects along NGPL.

Thanks, guys.

Okay. Thank you all very much. Have a good evening. I know everybody's going to scurry home to watch the big debate tonight. You should be reading your Kinder Morgan information instead. (laughter) Thank you and have a good evening.

Again, and that concludes today's conference. Thank you for participating. You may now disconnect.